Mature Fields Solutions

Transcription

MATURE FIELDS
MATURE FIELDS
s o l u t i o n s
Solving challenges.™
>Why
Section Title
Choose
Halliburton as a Mature Asset Partner
• A dynamic Health, Safety, Environment, and Service Quality philosophy
permeates all of Halliburton’s work from the top management down. Our
ethics, enforced throughout the company, state that every person is responsible not only for his or her own personal safety but also that of the people
who work around them. All employees are empowered with Stop Work
Authority, compelling any unsafe work to cease until a resolution is created.
fewer plugs to drill out, reduced overall completion time and more complex
networks to be built through the biodegradable BioVert® diverting agent.
• Halliburton also offers a unique gas separator technology, known as
Q-MAX™ Bypass, that separates the free gas to allow centrifugal pump to
reliably maintain continuous operation in EPS wells.
• Comprehensive training and competency of all employees is enforced
throughout the organization. Compliance with applicable laws and regulations is mandatory.
• The innovative Enhanced QuikRig® coiled-tubing system is designed with
the well-control package preassembled on a mast, improving operational
efficiency, reducing rig-up time, and creating a safer rigsite environment for
well intervention.
• Fifteen (15) state-of-the-art research and development centers are located
around the world. These centers enable closer collaboration with the customer
to identify and categorize specific mature asset optimization problems and
deliver project-specific answers to any challenges that may arise.
• Water management is essential to mature asset economic success.
Halliburton leads the industry in provision of cost-effective water management technologies, such as:
• Groundbreaking mature asset oil and gas solutions help enable recovery of
remaining and bypassed reserves that were not previously economic. Using
a holistic approach, integrating reservoir understanding and combining the
latest improvements in refracturing, microseismic, well configurations and
production systems will optimally energize mature reservoirs.
• The FlexRite® Multibranch Inflow Control (MIC) system is an innovative
multilateral junction and completion system allowing a multilateral well to
be completed with sand screens, swellable packers, Inflow Control Devices
(ICDs) and Interval Control Valves (ICVs) to help maximize oil production
from each multilateral leg using one trip in the hole.
• By combining unique diversion technologies and pumping processes in the
AccessFrac® service, operators are able to maintain long-term production. Each perforation cluster is treated, which enables longer treatment intervals,
– Halliburton’s Swellpacker® system provide effective water management
in a range of applications. They swell up to 200%, sealing the annulus
around the pipe to achieve effective zonal isolation and inhibit water flow.
– The effects of paraffin, asphaltene (tar) and scale deposition from oil and
water flow inhibit production. Halliburton’s extensive range of paraffin,
asphaltene and scale inhibitor and removal chemicals make quick work of
deposition mitigation and/or clean up by application of the “right type” of
chemical and at the “right time”. Through technical advances such as these, Halliburton is committed to
delivering safe, reliable, and efficient solutions that bring “bottom-line” value
to the mature asset operator within a holistic framework that leverages all its
areas of expertise.
Halliburton is committed to delivering safe, reliable, and efficient solutions that bring “bottom-line value”
to the oil and gas stakeholder.
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Commitment
> Why Choose Halliburton>asHalliburton
a Mature Asset
Partner
Since the advent of the modern oil and gas age,
our industry has produced some one trillion
barrels of oil worldwide. The vast majority of
the fields that produced that oil are now mature,
with significantly reduced production and
aging equipment. But, far from being decrepit
assets, these mature fields offer one of our most
important opportunities to develop oil and gas
resources to meet future energy demands.
The bulk of these future assets in mature
developments reside in two forms. The first is
oil and gas that was known but not accessed
due to our previous inability to produce them
economically. The second are those reserves that
were accessed but could not be produced due to
technology limitations that resulted in recovery
rates of oil in place of less than 20 percent.
The result is, in current estimates, a remaining
producible resource base of at least an additional
one trillion barrels in mature assets. It is vital to
the global economy that these mature reserves
be developed. To accomplish this will require
a multi-faceted technology campaign, one that
Halliburton is committed to pursue.
Development and deployment of new technology to
improve production from previously produced
reserves, which will have immediate impact, is
the first order of business in the quest to maximize the value of mature assets. Halliburton
has committed its resources to these technologies,
resulting in significant improvements in artificial
lift, especially in electric submersible pumps
and linear lift. Important advances have also
been made in accessing more of the reservoir,
or re-accessing the reservoir, through improved
fracture and well stimulation technologies.
These technologies, in turn, allow the producer
to take advantage of our advances in recovery
mechanisms and conformance which make
more oil and gas available for production at the
wellbore interface.
In the longer term, optimized reservoir
performance will result in the highest EURs in
mature fields. Here, we have worked diligently
to optimize reservoir management. Through
our holistic framework that encompasses our
consulting and project management expertise to
ground breaking enhanced oil recovery technology,
we stand ready to optimize your reservoir for
maximum productivity from existing pay zones.
And, when new opportunities present themselves
in the form of new pay zones in mature fields,
look to Halliburton’s proven ability to image those
resources behind pipe and install the latest technology to make them economic or to re-engineer the
field where pockets of the reservoir may not have
an avenue to get to surface.
As in all developments, well integrity is key.
This is especially true in mature fields where
existing wellbores may have integrity issues due
to extended wear or age. Halliburton’s expertise
can turn an integrity-impaired liability into an
Dave Lesar
Chairman, President and CEO, Halliburton
asset with cutting edge technologies such as
Wellock™. And when the time comes, as it must
in the life of any mature asset, to abandon wells,
the same technology that ensures producing well
integrity can be used to successfully and safely
abandon a well.
There is a world of potential remaining in
mature assets. Halliburton has the drive,
commitment and technology to maximize that
potential. It is the Halliburton promise.
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Table of Contents
Why Choose Halliburton as a Mature Field Partner. . .......................... 2
Halliburton Commitment.............................................................. 3
Health, Safety, Environment, and Service Quality Excellence............... 5
Global Mature Fields.................................................................. 6
Consulting and Project Management - Realizing the Full Potential
from Mature Fields. . .................................................................. 10
Innovation Delivery................................................................... 19
Value-Added Procurement and Logistics. . ...................................... 23
Immediate Impact and Production Sustainability.. ............................ 26
Bypassed Zones and New Pay Zones That May Have Been Missed..... 96
Field Re-engineering Considerations........................................... 107
Waterflood and EOR Management.............................................. 112
Optimizing Infield Drilling and Evaluation. . .................................... 123
Safe and Compliant Well Abandonment....................................... 163
> Health, Safety, Environment, and Service Quality Excellence
Health, Safety,
Environment, and
Service Quality
Excellence
Effective health, safety, environmental,
and service quality processes permeate
Halliburton’s global business and provide the
foundation that makes its broad range of services efficient, effective, and safe. Halliburton
believes firmly that zero HSE incidents is an
attainable goal company-wide and reaching
that objective requires a methodical approach
to continuous improvement of all HSE and
SQ systems. Many of our geographic and
product lines have demonstrated that zero
HSE incidents are achievable over the past
few years and our continuous improvement in
injury rates and service quality is noticeable.
The following principles guide Halliburton’s
global operations:
• HSE incidents are preventable.
• Leadership and management commitment
are fundamental.
• HSE performance is each individual’s
responsibility.
• Compliance with applicable laws and regulations is mandatory.
• Working safely and protecting the environment are conditions of employment.
• Stop any task or operation if a concern or
question regarding an HSE risk exists.
Halliburton’s deep-rooted HSE tenets place
particular emphasis on continual training
to instill a high level of competency in all its
employees, as well as providing all personnel
full stop-work authorization should they
recognize any unsafe activity. Specifically,
Halliburton’s guiding HSE principals are:
• Ensure training and competency of the
workforce. Halliburton HSE training gives
employees the skills and knowledge to
perform their jobs safely and competently.
The training prepares the employees to
recognize hazards, prioritize risk, assign
controls to reduce risk to an acceptable
level, and to understand internal and
external reporting requirements. It also
provides a basic knowledge of the applicable
regulatory requirements and emergency
response procedures. Also, workers are
tested in various offshore and onshore jobs
to meet certain competencies required for
the specific job.
• Encourage employees to communicate
and address risk. Employees are expected
to observe each other’s HSE performance
and to Stop Work when necessary. All
employees or contractor personnel who
observe an unsafe action or condition have
an obligation to intervene by taking one or
more of the following actions:
• Communicate concerns directly to the
persons involved.
• Correct the condition or situation.
• Relay the concern to the appropriate supervisor or customer representative.
• Stop Work (within the scope of responsibility)
if clear and present danger exists.
Through careful analyses, five critical focus
areas have been identified that present the
biggest risk for HSE, process safety, and
service quality incidents. When conducting
operations in any of these areas, extra attention and absolute adherence to the processes
are focused upon. Also, emphasis is put on
weather condition and the factor it plays on
human performance while working.
• Barriers – Physical measures (such as
packers, plugs, BOPs, surface valves, barrier fluids, i.e., drilling or cement fluids)
that prevent unwanted gas or oil from
flowing into the annulus or tubing from the
formation and traveling to the surface
• Hydrocarbons to the Surface – Flow of gas
or oil to the surface such as well testing or
well cleanup operations
• Trapped Pressures – Equipment (i.e., discharge iron, lab machinery, BOPs,
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> Health, Safety, Environment, and Service Quality Excellence
cement heads, swages, pipelines, hoses,
tanks, or silos) in which a release of pressure could occur
• Well Collision – The potential for collision
while drilling with a producing or existing
wellbore
• Radiation and Explosives – Any surface
activities concerning a radioactive source
or explosive material
Halliburton also is at the forefront of regulatory compliance with products and
execution practices that meet or exceed federal and state governmental regulations
and help reduce HSE concerns. The worldwide regulatory environment is composed
of numerous federal and state regulatory
bodies, each issuing regulations for HSE and
operations. For example, U.S. Federal offshore
HSE and operational regulations are complex
and very extensive. While it is beyond the
capacity of this publication to list and/or discuss all Federal regulatory mandates related to
offshore and onshore operation, basically they
can be broken down into two types: Safety
and Environmental Systems (SEMS) and
mandatory regulations. The regulatory environment in the Gulf of Mexico is overseen by no less than five Federal government agencies. The SEMS II final rule,
also known as the Workplace Safety Rule,
provides requirements for employee training,
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empowering field-level personnel with safety
management decisions and strengthening
auditing procedures by requiring them to be
completed by independent third parties.
In addition, a number of quasi-official bodies,
such as the American Petroleum Institute, Det Norsk Veritas, and the American Bureau
of Shipping, issue standards for recommended
practices offshore and onshore; many of
these standards are subsequently adopted by
federal and state regulatory bodies. Once the
applicable federal, state, and local regulations
have been identified, Halliburton complies
accordingly.
Fig. 1. Safety rules and federal/state regulations are adhered to in working in mature
fields. Also, personnel have Stop Work authority should they identify anything that might
cause an incident. Specialized protective gear
is used working offshore and onshore.
> Global Mature Fields
Global Mature
Fields
Recent reports project that global population
will increase by 2 billion people, from 7 to 9
billion, by 2040. Even with significant gains
in energy efficiency, a 35% increase in worldwide energy demand, led by China and India,
will be required to meet basic needs and to
improve living standards (Fig. 1). Increasing
population, urbanization, and efforts to improve living standards worldwide are
driving rising demand for energy.
ExxonMobil estimates that 60% of this rising
energy demand will be met through supplies
of oil and gas. Oil will remain the largest
fuel source with natural gas surpassing coal
as the second largest fuel source. The global
demand for oil is projected to increase 25%
by 2040 and the demand for natural gas by
65%. However, consumption is outpacing the
addition of new reserves and both the number
and size of new discoveries are decreasing.
Advancements in science and technology
have resulted in the discovery and development of new sources of oil and gas, like shale
and deepwater formations. Large, affordable
supplies of clean-burning natural gas are
projected to be available through 2040—much
of the demand for natural gas is for generation
of electricity.
While unconventional sources will play an
increasing role in meeting energy demand, most
of the increased demand for hydrocarbons will
be met by extracting additional production
from existing, i.e., mature, fields, where large
percentages of the known hydrocarbon reserves
remain in place. Recent studies estimate that
hydrocarbon production from these fields will
account for more than one-half of the global
energy mix for at least the next 20 years. A field
is considered “mature” when overall primary
production has peaked and is on the decline.
The situation may also result from improper
development of the field, e.g., application of the
wrong well spacing or completion method.
Billions of people
2000
Operators today face a four-fold challenge:
the need to improve returns from their assets;
mitigate the decline of new, major/giant field
discoveries; maximize recovery; and operate
efficiently. Unlike today’s prospective basins
with potentially large hydrocarbon reserves,
which typically require large and often
high-risk investments for uncertain payouts,
mature fields are more predictable (less risky),
both in terms of production and dollars.
The great advantages of mature fields are the
large volumes of remaining hydrocarbons
(reserves) that have already been identified
through drilling, testing, pressure data and
historical production. The data accumulated
Quaddrillion BTUs
2020
* Mexico and Turkey included in key growth
2040
2000
2020
2040
* Mexico and Turkey included in key growth
Fig. 1. Growth in global population (left) and energy demand 2010-2040 (right) (ExxonMobil).
ExxonMobil, 2014
“The Outlook for Energy: A View to 2040”
over years of exploration, development and
production are used to generate reservoir
models that result in very low risk for drilling
new infill wells and recompletions in existing wells.
Mature fields, many in the secondary or tertiary production phases, account for over
70% of the world’s oil and gas production. The
average recovery factor is 70% for gas and 35%
for oil. Even lower recovery rates are common
due to geological characteristics, resource
constraints, or operational inefficiencies from
old technology. Reservoir heterogeneity is
the single most important reason for low oil
recovery, early breakthrough, and excess water
production. In the U.S. an estimated 80% of
the total number of oil wells are now classified
as “marginal.” Increasing ultimate recovery in
mature fields may involve extending the peak
production period of the field or flattening
the decline curve through the application of
secondary, improved, and enhanced recovery
methods. Boosting the recovery factor of the
world’s oil fields by just 1% would cover two
to three years of worldwide consumption at
current rates.
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"Developments and Challenges of Mature
Oil Fields,” S. Bannerjee, Shell"
SPE The Way Ahead, 9(3), 2013
"The Appeal of Mature Fields,” T.B. Willis,
Chevron"
Extending the productive life of mature fields
has two aspects: improving well productivity
and improving field productivity (Fig. 2).
Achieving these objectives involves addressing
a number of specific challenges, such as old
equipment and infrastructure, and excessive
water production. Water can be a problem,
because mature fields produce far more
water than oil, raising potential environmental
issues. Advancements in technology play a key
role in extending the life of mature fields by
continually improving the field economics. In
addition to improving facilities and applying
secondary, tertiary, and enhanced recovery
methods, such as injection of water, gas,
steam, or chemicals, new seismic, reservoir
modeling, and advanced logging technologies
improve identification of bypassed pay, horizontal and multilateral drilling and geosteering technologies enable accurate placement
of infill wells on smaller spacing, and greater
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exposure of the reservoir, and advanced completion and stimulation technologies optimize
production. In many aging reservoirs the
best solution may be remediation, i.e., special
technologies to clean and re-energize existing
completions and producing intervals, and
limit the entry of water and solids into the
wellbore. These technologies are essential to
identifying additional reserves, for accurate
placement of the wellbore to recover those
reserves, and for optimizing production. By
combining extended-reach or lateral boreholes with advanced multistage stimulation
technology, more of the reservoir can be
Primary Recovery
"Mature Oil Fields: Preventing Decline,”
I. Munisteri, BP; and Maxim Kotenev,
Robertson CGG"
exposed and the number and placement of the
completion zones can be optimized.
Every producing reservoir has a life cycle
(Fig. 2). The primary phase is characterized
by the recovery of hydrocarbons by natural
mechanism, such as its pressure—this period
is marked by a relatively rapid decline in
Secondary Recovery
Improved Recovery
Thousand barrels per day
Enhanced Recovery
Vertical Infills
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n-6
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5
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0
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0
n-9
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5
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5
n-0
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0
n-1
Ja
Fig. 2. Graphs illustrating how the productive life of mature fields can be extended by advances in
improved (IOR) and enhanced (EOR) recovery technologies. (a) Theoretical plot showing the application
sequence of EOR and IOR technologies. (b) Production history of the Weyburn Unit in western Canada
showing how the productive life of the field has been extended (Cenovus Energy).
Oil Recovery
Primary Recovery
Natural Flow
Artifical Lift
Generally Less
Than 30%
Secondary Recovery
IOR
30% - 50%
Waterflooding
Pressure Maintenance
EOR
Tertiary Recovery
Thermal
Steam
Hot Water
Combustion
Gas Injection Chemical
CO2
Hydrocarbon
Nitrogen/Flue
Alkall
Surfactant
Polymer
>50% and
Up to 80 + %
Other
Microbial
Acoustic
Electromagnetic
Fig. 3. Definition of terms used in extending the productive life of a mature field (modified from
SPE 84908).
the initial high volume of production. The
secondary recovery phase includes the use of
basic techniques such as injecting water into
the reservoir or using artificial lift to generate
additional hydrocarbon flow and manage pressure. Secondary recovery activities have
long been an industry standard. The improved
recovery phase increases the sweep factors
of the reservoir by drilling and completing
smart infill wells, revamping facilities, and
redesigning waterflood schemes. The enhanced
recovery phase uses techniques such as gas,
steam, or chemical injection and development
of new facilities to recover more oil from the
reservoir (Fig. 3).
SPE 84908
"The Alphabet Soup of IOR, EOR, and AOR:
Effective Communication Requires a Definition
of Terms,” G.J. Stosur, Consultant; J.R. Hite,
Business Fundamentals Group, N.F. Carnahan,
Carnahan Corporaiton; K. Miller, Consultant,
presented at the 2003 SPE International Improved
Oil Recovery Conference in Asia Pacific, October
20-21, Kuala Lumpur, Malaysia"
Halliburton is successfully challenging the
conventional thinking that improve and
enhanced recovery activities are too costly
and ineffective to be justified. Halliburton’s
Consulting & Project Management team provides the expertise and works with our clients
in a collaborative environment to provide
customized and comprehensive field solutions
to maximize the value of their mature fields.
Our innovative technologies, software, and
methodologies are proving that revitalization
activities can be economical, while increasing
ultimate recovery by an average of 20% or more.
/9
> Consulting and Project Management - Realizing the Full Potential from Mature Fields
Consulting and
Project Management
- Realizing the Full
Potential from Your
Mature Fields
Maximize recovery is the goal in any mature
field. In the past, operators shifted resources
elsewhere once the “easy oil” was found and
produced. With advances in new technology,
getting as much as possible from existing
assets is becoming more and more feasible.
Mature fields require more careful planning,
especially during the reassessment phase, in
order to identify producible reserves that were
previously missed or thought unobtainable.
Applying the correct methods and technologies
is key in redefining the value of these hidden
assets. The combination of options for
revitalizing a mature field (Fig. 1) generates
hundreds of scenarios—the challenge is identifying the optimal combination in a
timely manner.
Halliburton Consulting’s team of over 350
professionals can help a client achieve greater
insight into a mature field and can apply
customized solutions to maximize its value.
Halliburton can collaborate with a client’s
in-house asset team to provide comprehensive
and innovative solutions or manage an entire
/ 10
project. A field assessment may include reinterpretation of existing seismic data to identify
unknown seismic attributes, studying the
complex geomechanical stresses influencing
production, or modeling various scenarios to
arrive at a plan that best addresses and meets
the client’s objectives. Determining whether
a potential re-engineering or operational
improvement scenario can be profitable is a
critical decision in mature-field exploitation.
Halliburton Consulting provides the cross discipline capability needed to help
improve the performance of declining assets.
Consulting specialists at Halliburton combine
the most reliable, proven and value-added
technologies and services with industry
best practices and procedures to prolong
field life and maximize the value of mature
fields. They also have access to technical
product-service-line specialists and support
personnel. Halliburton’s comprehensive
solutions include:
• Complete Asset Management via our group of
650 industry-leading consultants and project
managers
• Entire Field Optimization via specialized
mature-field drilling and formation-
evaluation services. That is, enhanced reservoir drainage via optimized infill well patterns,
architecture, and visualization.
• Individual Well Optimization via artificial lift,
production chemicals, conformance chemistry,
production hardware, and a fully integrated
well-intervention capability
• Well Abandonment Designs and Execution via
integrated services consisting of, but not limited to, logging, pipe recovery, and
cementing.
OPTIONS
Exploitation
Well
Spacing
Well
Geometry
500 m
Vertical
Steam
S1
S2
Sn
Water
Polymer
ASP
300 m
Horizontal
100 m
Slant
Artifical
Lift
Surface
Installation
None
Available
Injection Plant
BCP
ESP
Gas Lift
Fig. 1. How to find the optimal combination in a timely manner.
Marketing
Strategy
One
Segregation
New
Injection Plant
Split Fluids
Also, Halliburton has
a systematic
approach,the
asProductivity
illustrated below
upgrade
a Mature Field.
Framework
for Extending
Life ofto
Mature
Fields
Time
Frame
Issues
Capabilities
Solution Process
Benefits
Client
• Increased
production and
recovery
• Fix
underperforming
wells
Well
Productivity
• Address artificial
lift, unwanted fluids
and sanding
challenges
Collaboration
Review
Well Data
Prioritize
Interventions
• Devise well
abandonment
strategy
Collaboration
Evaluate
Constraints
• Timely EOR
implementation
Review Models
and
Design Plan
Collaboration
Field Productivity
• Reduced
downtime and
lost production
• Optimized
Exploitation
Client
Diagnose
Potential and
Economics
• Reduced OPEX
• Close HSE issues
Well Productivity
• Identify remaining
reserves
• Develop infill
drilling program
Execute
Interventions
Collaboration
• Improve remaining
reserves
Field
Productivity
Develop
Solutions
Execute
Programs
• Increased
reserves
• Enhanced
recovery
• Efficient
Abandonment
Fig. 2. Frame work for extending the productivity life of mature fields.
Project Experience
In addition to seasoned professionals and
innovative technologies, Halliburton also has
years of worldwide experience in oilfield management that can help operators maximize
recovery from mature fields in a cost-effective
and timely manner.
Landmark’s real-time monitoring, surveillance and integrated modeling and analysis solutions allow operators to visualize and
understand their mature fields and enable early
detection and analysis of production anomalies.
Obtaining this information in real-time allows
prompt action to limit production declines or
interruptions. Landmark’s software solutions
for reassessment and planning allow the client
to realize the full potential from mature fields.
Software portfolios include:
Reservoir Characterization Software for the Life
of the Field
- ProMAX® 4D - Image seismic response to
changes in the reservoir over time. Isolate
changes in the reservoir from acquisition
noise and signature in multiple vintage
seismic data.
- DecisionSpace® Geophysics/Geology
Leverage prestack seismic attributes to monitor
pressure and saturation differences over time;
model and predict pressure/saturation curves to
predict 4D effects
- GeoProbe® – Mulltivolume/multivintage
interpretation
- DecisionSpace® Earth Modeling – Property
modeling through life of the field
- OpenWorks® - Managing massive amounts
of mutiple vintages of 4D seismic data,
interpretations, and reservoir models. Mature Field Production Optimization Software
- WRM - Well Review Management, for
ranking and selecting wells with production problems.
- CasingSeatTM - Example of planning
new injection or production wells. Well
design from the perspective of borehole
size and selection of casing type.
Calculation cost-effectiveness based on
historical data.
- StressCheckTM - Maintain mechanical
integrity
- WellCatTM (for intelligent wells) Analysis of temperature and stress
- WellCostTM - Predictive AFE cost and
drilling time. It has both deterministic
/ 11
Extensive experience in mature field optimization
- AssetConnectTM Enterprise SoftwareSupports scalable and seamless
connection of technical workflows across
organizational domains and geographic
locations. Enabling distributed execution
with centralized model management,
AssetConnect Enterprise software helps
ensure consistency and automation of
workflows resulting in a more efficient and
cost effective production environment.
Halliburton Locations
Mature Field
Other
Fig. 3. Halliburton is actively consulting in many mature fields and our service centers are near by to
carry out the activities.
and stochastic methods with connection
to EDMTM software.
- NETool Software – Near-wellbore
completions analysis.
TM - OpenWells® Mobile - Workover and
intervention analysis
Asset Management
- Nexus® reservoir simulation software Enables more robust, accurate, and faster
reservoir simulation via simultaneous
modeling of the total asset: multiple
reservoirs, multiple wells, and a common
/ 12
subsurface-surface-economic models, stochastic analysis for quantifying uncertainty
and risk, considers a very large number
of scenarios, integrated decisions, and
reduces the planning cycle.
surface facilities network.
- SurfNet™ post-processor software - An
easy-to-use, graphical tool that interfaces
with Nexus® simulation software for
analysis of well and surface-facility data.
SurfNet software allows engineers to
visualize and analyze the production and
injection systems of one or an entire group
of reservoirs at any level of detail, including perforations, wellbore equipment and
the detailed surface facility model.
- DMSTM – Decision Management
System – Offers automatic coupling of
SPE 110250
“How Integrated Field Studies Help Asset Teams
Make Optimal Field Development Decisions,”
L. Saputelli, L. Lujan, L. Garibaldi, J. Smyth,
A. Ungredda, J. Rodriguez and A.S. Cullick,
Halliburton, presented at the 2008 SPE Western
Regional and Pacific Section AAPG Joint
Meeting, March 31-April 2, Bakersfield, California
SPE 124203
“Simulations of Field Development Planning
Help Improve Economics of Heavy-Oil Project,”
D. Teotico, L. Schauerte, and J. Griffith,
Shell; G. Schottle, and R. Mehl, Halliburton,
presented at the 2009 SPE Annual Technical
Conference and Exhibition, October 4-7, New
Orleans, Louisiana
Case STUDY:
Multidisciplinary Well Planning Technology Reduces Cycle Times by up to 80%
A global independent operator was seeking a
solution to help it rapidly ramp up development in the Montney Shale. Existing manual
methods of well planning proved too slow and cumbersome; previously it took 180 days to complete just 2 planning iterations for 10 pads with 80 horizontal wellbores,
targeting 3 to 4 zones in each well. The
slow pace of the planning cycle was making
it difficult to keep up with an ambitious
drilling schedule that involved hundreds of
horizontal wellbores. The operator needed
to improve efficiency without slowing
asset teams down. The operator invited
Landmark to conduct two pilot studies
in the Montney asset, using Landmark’s
collaborative DecisionSpace® Well Planning
software technology. Automated scenario
planning, visualization, and optimization
tools in DecisionSpace Well Planning software enabled the operator to plan the
entire field up front, review well and pad
plans in 3D, and reach consensus rapidly.
In each pilot study the planning cycles were
reduced drastically. The first pilot took
just 15 days to plan the same 80 wells, but
completed 30 to 40 planning iterations,
which dramatically improved reservoir
Fig. 4. Using DecisionSpace® Well Planning software, an operator planned hundreds of wells with
stacked, horizontal wellbores targeting 3 or 4 zones each in the Montney Shale.
optimization. The second pilot reduced the
well planning cycle by as much as 80% and
saved an estimated $4.5 million USD in the
first phase of operations. To avoid interference problems in areas with active drilling
and completion operations the operator
needed to ensure that frac crews remained
at least 1,000 m away from drilling rigs. An
the operator linked DecisionSpace Well
Planning with its own scheduling software,
thereby streamlining the process of mapping
crew locations each month. The company
subsequently purchased six DecisionSpace
software licenses, potentially saving the
operator millions of dollars.
/ 13
Case STUDY:
Landmark/Client Team Prepares Integrated Conceptual Development Plan in Eight Weeks
The newly organized offshore division of a national oil company
faced an urgent and fixed deadline to perform a thorough review of
an existing field development plan for two offshore gas fields in two
months with a focus on generating economically viable alternatives
that could ensure first production by 2010. They needed to provide
documentation necessary to obtain exploitation permits and accelerate time to first production. However, because of significant
changes in partner relationships and the operator’s internal organization, much of the original documentation was no longer
available. What remained was a single “most likely” scenario, but
little remained of the rationale behind it or any alternative scenarios that had been evaluated. Other objectives included efficiently
recovering 70% of the original gas in place in 20 years without
environmental impact, while addressing social development issues
in the region.
Due to the complexity and urgency of the challenge the operator
teamed with Landmark’s Consulting and Services group to conduct
a detailed front-end loading (FEL) study for rapid field development
planning using an integrated Landmark suite that included AssetView™ software and other DecisionSpace® applications, Decision Management System™ (DMS™), Nexus®, and FieldPlan®
DMS™ software. Front-End Loading is a formal three-step methodology for capital project planning that improves project definition
up front and increases the probability of business success by avoiding uneconomic investments and forestalling costly changes
during project execution. Landmark formed a multidisciplinary
team of 14 consultants from around the world, giving each special-
/ 14
ist a ‘mirror’ collaborator in the operator’s organization. A vital
component of the FEL methodology involves pulling together all
the domain experts to brainstorm input parameters for integrated
modeling and planning decisions at the very earliest stage. The joint
Landmark/operator team met twice daily in a dedicated collaboration environment with access to all the technology and held
frequent reviews with high-level decision makers.
The project was completed on schedule. In just eight weeks, the joint
Landmark/client team thoroughly reviewed all viable exploitation
scenarios for the two strategically important offshore gas fields and
presented a fully integrated conceptual development plan that met
all project objectives. The team identified more than 200 potential
well locations based on reservoir quality. Using dynamic modeling of the reservoirs, surface facilities and economics, it identified
16 optimum locations that could save $80 million USD in drilling
costs, while boosting production by 30%. In addition, the integrated
approach improved collaboration among the operator’s departments, many of which had not worked together like this before.
Management was so impressed with the people, processes, and tools,
it decided to license the full suite of Landmark technologies used in
the study, and Landmark consultants participate in planning for two
other gas fields in the area. The joint Landmark/operator team met
twice daily in a dedicated collaboration environment with access to
all the technology and held frequent reviews with high-level decision makers. The colaboration ended in major results.
Case STuDY:
Optimized Development in an
Economically Marginal Reservoir
In an unconventional reservoir development,
well costs represent the largest component
of the capital budget. After having a
collision and difficulty planning the lazy
S shape of thewells and hitting multiple
targets, the customer needed a different
solution. To further complicate matters,
there were endangered cacti that precluded
a pad. Permit changes required by pad
drilling and close-target spacing (10 to
20 acre) were slowing down the drilling
process. Halliburton Consulting used
optimized collaborative well planning to prepare multiple scenarios and to optimize existing pads. Multiple scenarios
were run that included changes in spacing, use of existing pads, and changes in
pad configuration. The resulting optimal
scenario provided savings of $30,000
USD per well (in drilling days). A total
saving of more than $200 million USD
could be realized if the customer chose to
continue to develop the field with up to
6,000 wells.
Case STUDY:
Mature Field Optimization
The client was seeking to improve contributions from an underperforming asset through
interpretation of existing and new data and identification of unswept reserves. The project consisted of integrated surface-subsurface studies of three fields and involved
close collaboration between Halliburton and the client to ensure knowledge transfer. The work involved interpretation of multiple 3D seismic datasets, geological evaluation
of >500 wells, evaluation of 50 reservoirs, and dynamic full-field simulation of 20 reservoirs. The project identified new development opportunities—18 of 19 of the
drilled wells were successes—and suggested revisions to the existing perforation and
waterflood programs.
Case STuDY:
Mature Field Revitalization Increases Reserves by 700%
A major operator in the Gulf of Mexico had a 31-year old field with 60+ wells. Production
had declined to 8% of peak production. The client had requested a field/well abandonment program. An integrated Halliburton‐Landmark‐client team conducted a last-stage
field review to apply “fresh eyes” and to identify new technology that could to add value.
The team performed QA/QC of the available data and a detailed evaluation that included
reprocessing existing seismic data, establishing reservoir-seismic correlations using neural
networks and statistical techniques. New structural and depositional geologic models
were created. The reservoir study identified a new play; booked significant bypassed
reserves (324 Bcf gas), increasing reserves by 700%; and improved production by 800%.
As a result of the added value that accrued from the Halliburton-lead field evaluation the
asset went from “worst to first” in the client’s GOM portfolio.
/ 15
Case Study:
Case STUDY:
Waterflood Optimization Plan
EOR Screening, Ranking and Pilot
Visualization Case Study: Front-End
Planning for Future Success
A South American operator holding almost all reserves of a large mature heavy-oil (17.4° API
crude) field, where 900 million of the estimated 11,116 million barrels OOIP had already been
produced, requested a revitalization plan within a very short, 2 to 3 month, timeframe. The
objective was to maximize NPV by optimizing volumetric swept efficiency in Module V of
LL-03 Field using numerical algorithms and stochastic analysis. Halliburton put together a multidisciplinary consulting team that developed an innovative approach to complete the objectives in a timely manner under
challenging working conditions and limited resources. The large volume of data and the substantial computational time required for simulating complex scenarios made generation of
long-term production forecast simulations impractical for this study. Instead, this study used
a numerical algorithm that drastically reduced the time and number of realizations required
to define an optimum asset production forecast. These gains were achieved by focusing on short-time span optimization stages, beginning with the first years of the drilling
campaign when the greatest value would be added. The technique was sequential, progressing
to the next independent stage until the production forecast lifecycle reached diminishing
returns. The study focused on increasing short-term production over the initial five-year
drilling campaign. Overall, three simulation stages were evaluated in this case, cumulative productions Np in the first five years, in addition to a fourth stage maximized net
present value (NPV) by deciding well type (i.e., injector-producer), location of the wellsite,
drilling sequence, and water injection rate. A total of 880 scenarios were generated using the
constraint of existing infrastructure systems. The reservoir exploitation plan was redesigned
and included plans for a number of new producer and injector wells, well locations, the
drilling sequence, and water-injection rates. Optimization resulted in increased cumulative oil
production and NPV values between 300 and 400% over the base case.
/ 16
The operator of a heavy-oil field with
very low recovery rates wanted to begin
planning an enhanced oil recovery project to improve short- and longterm productivity. The client sought
Halliburton’s expertise to screen and rank
applicable EOR methods for the field
and to propose a pilot and full-field visualization plan for the most appropriate
EOR method. Four potential areas of the
field were screened for 17 commercial
IOR/EOR methods using commercial
software, subject matter expert input and
analog studies. Homogeneous numerical
models were used to conduct forecasting
for feasible EOR methods. The forecasts
and risk analysis were used to determine
the best exploitation method. An area
was selected, and a deployment scheme
and operational criteria were used to
visualize a pilot and full-field execution
plan. An increase in incremental oil production of 1.5 million barrels was forecast
for 18 wells..
Case STuDY:
Case STUDY:
Mature Offshore Field Revitalization by Secondary and Tertiary Recovery
Polymer Flooding Pilot Assessment
A South American operator had a field
with 80% of the hydrocarbon resources still
in place, but the current pressure was 1/3
the original. The client wanted to evaluate
waterflooding as a potential method for
increasing short-term production and
extending reservoir life. A numerical
and stochastic analysis was conducted to
maximize Net Present Value by optimizing
the volumetric sweep efficiency in a sector
of the field. A multidisciplinary consulting
A South American operator was conducting a pilot test targeting 12%
incremental oil recovery. After injecting
an 0.12 PV, no incremental production
was detected. The lack of a comprehensive subsurface surveillance and
monitoring plan (SSMP) precluded a reliable assessment and control definition.
The scope of the project was to propose
objectives, identify uncertainties and
risks and establish successful criteria as
the basis for aligning the pilot project’s
SSMP plan. An on-site consultant
accomplished data gathering and data
interpretation, calculations and test
design. The results demonstrated (1) the
convenience of continuing the polymer
injection, (2) the strengths and weaknesses of the SSMP, (3) technologies to
improve capture of reservoir-related
polymer flooding data were visualized,
and (4) by elaborating and proposing
a new road map, the decision-making
process for the polymer pilot project
was improved.
team identified uncertainties and risks in
the waterflooding project deployment, tested multiple hypotheses, and estimated the
optimized value. The new plan quantified
the planned investment of $100 million
USD, demonstrated that the original waterflooding scenario provided only a marginal
return on investment, and estimated that
an extended waterflooding plan comblined
with chemical EOR would yield a potential
increase of 300% NPV.
OTC 22517
SPE 145070
“Reserves Estimation Uncertainty in a
Mature Naturally-Fractured Carbonate Field
Located in Latin America,” G.V. Riveros,
L. Saputelli, Hess Corp.; J. Patino, and A.
Chacon, Halliburton, and R. Solis, Qatar
Petroleum, presented at the 2011 Offshore
Technology Conference Basil, October 4-6,
Rio de Janeiro, Brazil
“Coupled Surface/Subsurface Simulation
of an Offshore K2 Field,” W. Dobbs, B.
Browning, Anadarko; J. Killough and
A. Kumar, Halliburton, presented at the
2011 SPE Reservoir Characterization and
Simulation Conference and Exhibition,
October, 9-11, Abu Dhabi, UAE
IPTC 14253
“Leveraging Emerging Technologies to Increase Production from Unconventional Reservoirs: Case Study
of India,” Y.K. Choudary, SumitBhat, and A. Kumar, Halliburton, presented at the 2012 International
Petroleum Technology Conference, February 7-9, Bankok, Thailand
/ 17
Case STUDY:
A Major Operator and Landmark Consulting & Services Revitalize a 30-Year Old Field in the Gulf of Mexico
Discovered in 1966, an offshore Gulf of Mexico field had produced
approximately 1 Tcf of natural gas by the mid-1990s. However,
production had dropped to about 15 MMcfg/D, which was
approaching the economic threshold and due to poor financial
performance the field was designated a noncore asset. The
field contained multiple pay zones and the operator decided to
re-evaluate the field’s remaining potential rather than divest the
property. A 10-year old speculative 3D seismic survey over the area
was available. To supplement internal limited manpower and to
introduce new and evolving technologies into this mature field, the
operator approached Landmark’s consulting group and formed an
integrated asset team for the project. During the initial assessment,
the team reprocessed the existing 3D seismic—the original data
had been post-stack processed—using more-advanced algorithms
(Kirchhoff prestack time migration) to validate proposed locations
and determine if additional reservoirs could be developed. The
higher quality of the reprocessed data enabled the team to accurately
image another fault, roughly parallel to the main field fault, forming
a previously hidden fault block in which three productive pay
zones were identified. AVO analysis on the far-offset volume, using
prestack gathers, allowed them to quickly scan the dataset for solid
/ 18
leads, many of which turned into drillable prospects. One new fault
block contained 107 Bcf of gas. In one case, in-depth analysis helped
the team avoid drilling an unnecessary and expensive well, saving $3
million USD in operational costs.
Application of two new and evolving drilling and completion technologies also contributed to success in this mature Gulf of Mexico
field. The team decided to set expandable casing above the depleted
sands—the first use of this technology in the Gulf of Mexico. The
well started with a conventional hole, 7-5/8 × 8-5/8 in. expandable
liner was set above the depleted sands, the mud weight was reduced,
and the well drilled out with an 8-1/2 in. borehole; reducing drilling
dollars without sacrificing the optimal hole size at TD. Thru-Tubing
FracPac™ treatment—normally a recompletion procedure for lowrate wells—was employed as a primary completion technique for
high-rate wells, reducing costs and improving field economics—one
well produced 20 MMcf/D. During the five-year project 18 wells
were drilled, 17 of which were commercially successful and production increased by more than 800%, to approximately 180 MMcf/D
(Fig. 3). Revitalization returned this mature asset to among the
operator's best producing properties in the Gulf.
> Innovation Delivery
Innovation Delivery
Strategically Positioned Technology Centers
To support its dominate position in mature asset production optimization and redevelopment worldwide, Halliburton has significantly
increased its technology investment. Over
the past three years, several “state of the art”
technology centers have opened globally, with
more on the way. This investment positions
Halliburton closer to the customers, opening the
door for better understanding of their challenges
and collaboration on in-depth solutions to
realize full value from mature assets. No matter
where the client may be having a technical challenge, Halliburton has the capability to deliver
the innovation to solve that challenge.
Halliburton Houston Technology Center Halliburton’s primary technology center in
Houston continually attracts global clients
seeking assistance in solving their specific
challenges. The 215,000 sq ft (19,974 sq m)
Houston Technology Center officially opened
in 2012 and is now home to 550 innovators
focusing on fluids and chemicals, sensor
physics, rock mechanics, and electronics that
are primarily organized into five product
service line solutions’ providers as well as some
integrated asset solutions.
The Houston Technology Center clearly
reflects the critical importance of Health,
Fig. 1. Halliburton's Strategically Positioned Technology Centers.
/ 19
Safety and Environmental (HSE) excellence
throughout Halliburton. The building is
built to the exacting “Leadership in Energy
and Environmental Design” (LEED) Silver
standards, making it cutting edge in energy
efficiency. The flooring of each room indicates
the specific personal protection equipment
(PPE), employees should use in that area. The
layout of the facility includes numerous huddle
rooms and conference rooms which help foster
an open office environment that encourages
inter-disciplinary collaboration. While the
eight primary areas house the very latest R&D
tools, the Houston Technology Center is less
about laboratory instruments and more about
the solutions being developed and delivered to customers.
Fig. 2. Halliburton Houston Technology Center.
Halliburton Brazil Technology Center In 2013, Halliburton opened its Brazil
Technology Center at the Federal University of
Rio de Janeiro UFRJ) Technology Park, located
/ 20
Fig. 3. Halliburton Brazil Technology Center.
at the do Fundao, Rio de Janeiro. The 7,062 sq
m (76,015 sq ft) technology center includes
specialized laboratories, a collaboration room,
a testing area and conference and training
centers in a collaborative setting. While this
lab is primarily focused on Deepwater, it will
be used for solutions generation for all types of
hydrocarbon development projects.
Halliburton Pune Technology Center As the global energy industry evolves, it
encounters new challenges that require
innovative solutions, particularly in the Eastern
Hemisphere. Meeting these challenges is the
mission of the engineers and scientists at the
new Halliburton Technology Centre (HTC)
in Pune, India. As Halliburton’s Fluids Center
of Excellence, HTC-Pune supports the key
technology areas of Fluids Chemistry &
Engineering, Fluids Delivery Systems and Reservoir Knowledge. Housed in the 66,000 sq ft Pune facility is a broad range of
research, development and support activity.
HTC Pune has teams and laboratories
dedicated to Cementing, Production
Enhancement, Drilling Fluid Systems and
Drilling. The team is committed to delivering
consistent quality service in accordance
with ISO 9001:2008 requirements. Working
in collaboration with other Halliburton
Technology Centers, further expands the lab’s
capabilities and opens virtually unlimited
problem-solving possibilities.
Fig. 4. Pune Facility.
Fig. 5. Pune Technology Laboratories.
Halliburton Singapore Technology Center To assist clients in the optimization of Asia
Pacific mature assets, Halliburton Completions
Tools (HCT) laid the groundwork for the
2014 unveiling of a new Technology Center
in Singapore. The new Singapore facility is
similar to the Carrollton Texas Technology
Center that focuses on specific markets, such
as mature fields and shale assets. The new
center complements the HCT Singapore
manufacturing facility that opened in 2013.
The combination of the technology and
manufacturing center enhances Halliburton’s
capacity to serve the entire Eastern Hemisphere,
Fig. 6. Halliburton Singapore Manufacturing
and Technology Center - East.
Fig. 7. Halliburton Singapore Manufacturing and
Technology Center - North.
particularly the Asia Pacific area, and enables
the rapid delivery of solutions to area clients.
The Halliburton Advanced Perforating
Flow Laboratory The current industry standard is to evaluate
perforating charge performance in a cement
target as documented in API 19B Section
I Perforator System Testing. However, a
perforating charge penetration in cement
does not necessarily translate into actual
penetration in hydrocarbon-bearing reservoir
rock. Accordingly, the more in-depth API
Section IV test can provide realistic flow
performance data, validating the effectiveness
of a perforator’s penetration in a porous media.
With Halliburton’s Jet Research Center’s (JRC)
leading-edge evaluation techniques, reservoir
inflow from a perforation tunnel optimization
can be carried out for specific well conditions.
Many of these tests have been tailored
specifically for an operator’s requirement
to help better understand actual downhole
conditions and the perforating system
performance. The Alvarado, Texas laboratory’s
capabilities allow Halliburton to provide real
answers to how a perforating system performs
under actual reservoir conditions, accounting
for overburden stress, reservoir pore pressure,
wellbore pressure, and reservoir and wellbore
response at reservoir temperatures. By doing
so, the lab enables reservoir and completion
Fig. 8. Advanced Perforating Flow Laboratory at
Halliburton’s Jet Research Center in Alvarado, TX.
engineers to more accurately appraise a well’s
performance and can be used as a tool to
identify the optimum solution to connect the
wellbore and reservoir. The facility includes
three newly designed test vessels:
• The new 50,000-psi ultrahigh-pressure test
vessel is the only one in the world that is
capable of simulating in-situ conditions with
remarkable accuracy of supplying 50,000-psi
overburden, 40,000-psi wellbore, and
40,000-psi reservoir pressure.
• The new cantilevered cell capabilities are
25,000-psi overburden, 20,000-psi pore
pressure, and 20,000-psi wellbore. A Section
IV test can be performed by rotating the
cell to any angle desired and determine the
effects, if any. This ability is unique to the
industry.
/ 21
• The third vessel’s capabilities are 25,000-psi
overburden, 20,000-psi pore pressure, and
20,000-psi wellbore, with high-temperature
capabilities up to 400°F (204°C).
The lab also includes a dedicated in-house
Computed Tomography (CT) scanner to
provide high-resolution 3D imaging of the
perforation tunnels. In addition, the images
provide definitive perforation geometry.
Software enhancements developed in the
medical industry are being implemented
for better understanding of the crushed
zone and identification of metal debris left
in the perforation tunnel. The CT scan is a
standard part of the work flow for charge
performance evaluation and improvement. The
technological advancements of the perforation
lab represent a significant innovation in
developing reservoir solutions in mature assets.
Case STUDY:
Formation-Specific Charge Development: Dominator® Charge Gives 21% Greater
Penetration in Challenging North Sea Field
A major operator asked Halliburton to help improve project economics by optimizing the
industry-leading 33⁄8-in., 6-spf, 25-gm gun system for an application in a marginal gas-
condensate field in the North Sea. To meet specific field needs, charges were tailored to specific in-situ rock characteristics and reservoir conditions. In this particular situation, high
jet-tip speed and an extra burst of power in the trailing elements were added to give deeper
penetration and to create perforation-tunnel geometry conducive to complete tunnel cleanup for the operator’s specific underbalance condition.
These Dominator® shaped charges were developed at the Halliburton Advanced Perforating
Flow Laboratory by firing perforating charges into real rock under simulated downhole
conditions that included rock effective stress, wellbore underbalance, and rock pore
pressure. By analyzing post-shot results from the testing program, it was possible to rapidly
develop a charge with favorable jet characteristics. Using the perforation flow laboratory
in the design process also avoided the pitfalls associated with translating data from surface
concrete targets to productivity estimations in downhole reservoirs.
/ 22
Fig. 9. The Dominator® Charge demonstrated
a 21% increase in rock penetration and a
12% productivity increase over benchmark
conventional charges.
Acoustic Test Facility - Only One of Two in
the World The characterization of wireline logging tools is
essential to verify and validate tool response, and
ensure superior service quality. Consequently,
Halliburton’s Wireline and Perforating product
service line made the decision to build its own
acoustic test facility—one of only two in the world. Previously, acoustic testing was dependent
on third parties, which was a significant
disadvantage. Recognizing that cement
slurries can be designed to meet the precise
specifications required for the characterization
of sonic tools, the Wireline and Perforating team
and Halliburton’s Cementing Product Service
Line (PSL) came together in a joint collaboration
to design and construct the unique Acoustic Test
Facility at the Houston Technology Center.
> Value Added Procurement and Logistics
Value Added
Procurement and
Logistics
Fig. 10. This Acoustic Test Facility enables
Wireline & Perforating and Sperry to deliver
appreciably enhanced service quality across
the formation evaluation services.
Mature Field Winning Innovations:
2012 Spotlight on Technology OTC Award
EquiFlow® Autonomous Inflow Control Device
2012 Hart’s MEA Awards
EquiFlow® Autonomous Inflow Control Device
CleanStream® Service
2012 World Oil Awards
RockOn® Surfactants
Russia RAO/CIS Conference
WellLock® Resin
In mature asset optimization and redevelopment, procurement and logistics are critical
to ensure sufficient materials are available and
on location at the right time, thus avoiding
non-productive time and keeping logistics costs
within limits that are absolutely necessary. In its
continuing efforts to acquire secure and adequate supplies long-term, Halliburton
sources materials from diverse vendors
throughout the world, which also helps support
the local economies where the work is being
conducted. A detailed worldwide vendor
management process and system has been
developed to help guarantee adherence to
specific technical specifications and HSE standards on every single product that Halliburton
delivers to its customers. Halliburton Global
Procurement and Logistics provides customers
with the unparalleled speed, reliability and
visibility needed to deliver efficiently in often
adverse conditions (Fig. 1).
Procurement and Materials
Halliburton’s Procurement and Materials
organization has employees worldwide
who are responsible for (1) developing and
maintaining strategic supplier relationships that
deliver long-term value to internal and external
Speed
Reliability
Visibility
Fig. 1. Halliburton Value-Added Procurement
& Logistics System Mission.
customers, (2) effectively managing the commodities purchased on a global basis, and (3)
delivering materials, equipment, and services
across the company. Halliburton uses its global
network, policies, and common work practices
to deliver goods and services at the right time,
and in the right place, while serving as a leader
in safety and quality excellence.
Global Field Procurement and Materials
comprises eight regions that are under the
direction of regional and country Procurement
and Materials managers. Strategic supplier
relationships are developed and maintained to
assure delivery of equipment and services.
Wherever possible, Halliburton seeks to
maximize its use of local suppliers within
countries where doing so will not compromise
job delivery performance. These strategic
supplier relationships allow Halliburton to effectively manage the purchase of commodities
/ 23
on a global basis, thus bringing long-term
value to internal and external customers
alike. Halliburton’s Global Sourcing team
has personnel located in five strategic areas
globally who are responsible for leading global
sourcing efforts; assuring adequate and timely
supply of all goods and services; maximizing
opportunities from global supply sources;
and maintaining assurances of the repeatability of product quality and global suppliers’
reliability of delivering high-quality products. Halliburton promotes opportunities for diverse
suppliers, including minorities, women, and
small business enterprises, to participate in the
procurement process. Halliburton has created
a broad supplier registration portal for current
and potential U.S. suppliers. Certification
in this program means that a supplier meets
minimal recognized standards of ownership,
management and control by minority, women
or other designated groups.
Within Performance Management, eProcurement
is responsible for supplier relationship management, technology platforms allow electronic
business transactions between Halliburton and
its key suppliers, and continuous improvement
through efficient use of buying channels. Global
Logistics is the industry leader in Supply-Chain
Management capabilities with security of supply
and in house manufacturing capability being
strategic differentiators in the oil field service
arena. Halliburton takes a multifaceted approach
to continuity of supply that is strengthened by
the collaborative relationships developed with
strategic suppliers. In the United States, as other
countries optimizing production in mature assets,
the logistics of delivering supplies are becoming
larger and more complex.
Fig. 2. Halliburton integrated Transportation Management System (tms) flow of information.
/ 24
The ability to deliver products to the job
site consistently and reliably—whether large
volume shipments of bulk materials or smaller
shipments of specialty products—is critical.
Combining superior rail, transfer and trucking
capabilities provides Halliburton the flexibility
to respond quickly to changing job requirements. Also, Halliburton is the only service
company in the industry that builds its own
equipment, e.g., for hydraulic fracturing, coiled
tubing, and slickline. Therefore, it controls its
manufacturing schedules to provide flexibility.
Halliburton knows the performance of the
equipment in the field and can make immediate improvements and rapidly deliver them to
the field without long time delays.
Logistics
With a presence in more than 87 countries,
Halliburton Logistics averages one million
moves per year. With logistics-related costs representing between 10 and 15% of an operator’s
total job outlay, getting logistics right means
that materials and personnel are on the ground
ready to start a job, on time. Conversely, getting
logistics wrong means costly nonproductive
time. Halliburton’s Global Logistics organization focuses on speed, reliability and visibility:
• Speed – A strategic network that allows
materials to be moved around the globe in a
rapid and efficient manner.
• Reliability – A global footprint, combined
with high standards of compliance, personnel and providers results in consistent and
reliable moves.
• Visibility – The ability to see where a
shipment is at any given point in the move
and identify the cost of each of those points,
provides information that is critical to an
operator’s ability to plan a job and maintain
the correct inventory to avoid added cost and
rig downtime.
Achieving these goals is made possible through
a standardized approach that involves a
strategic network, highly professional people,
advanced systems, comprehensive capabilities, project management and compliance.
Halliburton’s team members are present on
both ends of a move to guarantee effective
logistics execution. Logistics professionals
successfully complete the Halliburton
Global Logistics Educational Program. Key
performance indicators (KPIs) are set for all
performance areas and used to monitor the
performance of the logistics organization
to ensure service quality. More importantly,
Halliburton adheres to first-world standards
for ethics and strictly follows the U.S. Foreign
Practices Act, the U.K.’s Anti-Bribery Law, and
all local regulations that apply. Third-party
participants, including freight forwarders
and brokers, are also held to these standards.
Halliburton controls adherence to its standards
and efficiency processes. Halliburton’s logistics
personnel are trained in project-management
processes. Logistics personnel are experienced
in both startups and in establishing presences
in emerging frontier countries. These capabilities and experience allow for preplanning
to meet potential challenges that might arise
during a move.
A dedicated professional is assigned to each
project to handle every part of the move,
from startup to delivery. This professional has
oversight and accountability for the project.
Project managers coordinate with the operator’s
logistics team and every person involved with
the project. Halliburton Global Logistics has
capabilities for handling different types of
moves for a wide range of finished products
and offers an array of services. These services
can be ocean scheduled, air consolidated, air
direct, “in-country” rail and land transport
moves, or a combination of several. Halliburton
has the capability and infrastructure to move
oversized and time-sensitive items, as well as
hazardous and chemical supplies anytime and
anywhere in the world in a safe manner, while
maintaining regulatory compliance.
Halliburton transports a wide range of materials, such as proppants, bentonite, barite, lignite,
cement, and other commodities over land.
Consequently, an integrated transportation
Halliburton Manufacturing, Procurement
and Logistics Value Proposition
Halliburton’s strategic manufacturing,
procurement and logistics network can
handle all types of moves using ocean
scheduled, air consolidated, air direct,
“in-country” rail and land transport moves.
Superior rail, transfer and trucking
capabilities can respond quickly to changing
requirements of a job. Ships and railcars
carry bulk supplies to central points, trucks
take equipment and supplies to the specific
wellsites. This reduces the highway traffic
and infrastructure damage that occurs with
a total trucking system. Increased visibility
provided by advanced logistics management
and transportation management systems
allows monitoring and immediate tracking of
goods moving through the strategic network.
These capabilities lead to better decisions
and more accurate forecasts, which in turn
result in greater efficiency, less NPT, and
lower costs to the customer.
American Shipper
“Controlled Logistics: Halliburton turns
freight transport, compliance into “selling
point” in company” C. Gillis, Halliburton,
April, 2012, 8-11
/ 25
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> Immediate Impact and Production Sustainability
management system, TMS, delivers a complete monitoring and tracking system for
ground transportation that provides direct
communication between shippers and carriers
and also increases visibility with regard to rail
and trucks. TMS allows employees to know
where loads are at any point in time and enables them to make better sourcing
decisions and monitor and manage carrier
performance for greater efficiency and
execution. In the United States, optimization
and development of mature assets require a
significant amount of logistics.TMS streamlines this logistical challenge, allowing Supply
Chain to electronically plan and execute loads
through third party carriers, while keeping
track of who performed a particular job and
when it was completed. TMS benefits include
planning, execution, trade compliance,
carrier connectivity, payment simplification
and truck-load visibility. For example,
Halliburton’s proppant volume has tripled
over the last two years and TMS has enabled
significant reductions in truck wait time's
providing a direct savings to the customer.
Immediate Impact
and Production
Sustainability
Myriad factors, singularly or in combination,
can restrict optimum recovery from a
mature well, from loss of permeability, to
total pressure depletion, to high water-cut
and everything in between. Consequently,
realizing maximum value from an aging asset
means pinpointing the specific cause/s of
declining or totally blocked flow and taking
the appropriate remediation steps to restore
production.
That is why the Halliburton multidisciplinary
approach, using state-of-the-art technologies
applied holistically, has become the industry
choice for sustaining production in declining,
older wells. Halliburton has solutions to meet
the most daunting production challenges,
including mechanical and chemical artificial
lift systems for pressure-depleted reservoirs,
tailored production chemicals to remediate
flow-blocking H2S and iron sulfides, new
generation sand and produced water control
technologies and the most advanced coiled
tubing and associated intervention systems.
All these are applied seamlessly to help operators receive maximum value for their aging
offshore or onshore asset. Field-Wide Real-Time Operations
With increasing computing power, numerical
and empirical models have gradually become
more commonplace to describe reservoir, well,
and surface network behavior. Optimization
workflows, such as gas-lift optimization, flow
assurance, and real-time drilling, have encouraged the need for asset-wide integrated
production optimization. Model-based
methods combined with real-time data are
increasingly used to monitor, optimize, and
control the field more efficiently, proactively,
and remotely. Real-time decision centers for
drilling and production are gaining popularity to provide collaboration and
integrated operations environments. The
digital oilfield provides integrated operations
to measure, model, and control the oil and
gas field assets, enabling decisions to be made
effectively and consistently by the right people
at the right time. A comprehensive integrated
production-optimization strategy can
maximize reservoir recovery and ultimately
increase return on investment.
Today, mature fields typically employ field-wide monitoring or surveillance
programs to optimize productivity. These
monitoring projects generate large volumes
real-time production-related data from
intelligent downhole sensors (e.g., DTS,
pressure and temperature gauges, DCS/
Fig. 1. A classification of production-related data.
SCADA systems), from well tests and interventions in existing wells, and from drilling
new infill wells (Fig. 1). Most data have a
focused project-level value and a broader asset-level value and can be further categorized
according to life cycle stage. The acquisition
and interpretation of these data in real time
is key to managing them effectively and
understanding the role they play in higher
order workflows and value chains. At a project
level, the original data sources have separately
evolved to address specific needs of the
producers. In most cases, there is a movement
of the project-level data to the asset level; in
some cases asset-level data may return to the
project level to serve as reference data. Using
digital oilfield techniques including integrated
workflows increases operational efficiency
through (a) reductions in time spent on data
acquisition and validation, (b) collaborative
decision-making with key stakeholders, (c)
minimization of time between decision to
execution by means of operations support services, and (e) prompt re-evaluation of optimization initiatives soon after implementation.
Halliburton WellDynamics SmartWell® system technology offers products and services
designed specifically to remotely control and
monitor targeted reservoir zones without
intervention. Remote configuration of wells
optimizes production without costly well
intervention. Services range from reservoir
engineering studies to advanced completion
design, zonal isolation and flow control, reservoir monitoring, and surface digital infrastructure solutions. A SmartWell completion
system optimizes production by collecting,
transmitting, and analyzing completion,
production, and reservoir data, allowing
remote selective zonal control. Selective zonal
control enables effective management of
water injection, gas and water breakthrough,
and individual zone productivity thereby
helping to increase reservoir efficiency and
ultimate recovery. The ability to produce
multiple reservoirs through a single wellbore
reduces the number of wells required for field
development, thereby lowering drilling and
completion costs. Managing water through
remote zonal control reduces the size and
complexity of surface handling facilities. Flow
control solutions include interval control
valves (ICV), lubricator valves (LV), packers,
and downhole control systems. Permanent
monitoring solutions include downhole
gauges and flowmeters. Digital infrastructure
solutions include a supervisory control and
/ 27
data acquisitions system (SCADA) designed
for manual, automatic, and integrated
operation and electrohydraulic control and
monitoring systems. Optical fiber solutions
include distributed temperature sensing
(DTS) tools and software.
SmartWell systems allow operators to identify
anomalies in production and make necessary
adjustments in real time to minimize the
production decline. In cases where remote
adjustment of fluid flow, ESP settings and
frequency, or gas lift is insufficient to restore
declining production levels, the system identifies the wells and zones where more complex
intervention may be required.
Landmark’s DecisionSpace® Desktop software
Case STUDY:
Real-Time Surveillance Optimizes Production at East Blanco Field
The Rocky Mountain operator of the East Blanco field, an important gas field in the San
Juan Basin, New Mexico, found that relying on spreadsheets for production monitoring was
(a) inhibiting knowledge transfer, (b) difficult and time-consuming to maintain, and (c) making it challenging to monitor hundreds of wells and quickly identify significant variances, or (d) making it difficult to predict reservoir performance using traditional
tools and techniques. The operator installed a real-time electronic data collection system
in the field, implemented Landmark’s DSS™ (Dynamic Surveillance System™) software and
linked to the ARIES™ application for monthly production data and OpenWells® database for
drilling and completion data using Engineer’s Data Model™ (EDM) software. The El Blanco
Field has about 150 wells, 250 completions, and a complex gas-gathering system roughly
22 miles long from N to S. The operator uses DSS software for (1) day-to-day production
monitoring, to identify, which wells have dropped in production and which have increased
(Fig. 2), enabling the wells with problems to be addressed as rapidly as possible, and (2) as
a reservoir engineering tool, to better understand and predict performance from specific
wells, selected areas, or the entire field. The enhanced ability to monitor production
volumes in near real time, optimize well performance, minimize lost production, and
better predict reservoir performance to guide drilling and completion activity enabled the
operator to quickly identify problems delivering 50% of the gas from new wells to the sales
point, enabling timely corrective action.
/ 28
provides a unified visualization, interpretation
and modeling workspace where asset teams
can collaborate more effectively to evaluate
and develop assets. The software provides a
multiuser environment and integration across
multidomain data types (geology, geophysics
and reservoir modeling) and workflows on an
enterprise-scalable data-management foundation. Geologists, geophysicists and reservoir engineers share a common
1D/2D/3D visualization and interpretation
workspace with real-time visual connectivity
between seismic, well log, GIS and hydraulic
fracture-treatment data. Decisions can be
made in the context of all available multidisciplinary data and with the benefit of insight
from the entire asset team. Model scenarios
are stored in OpenWorks® database, ensuring
data integrity and access by multiple users.
Halliburton Real-Time Centers (RTCs) allow
subject matter experts to (1) collaborate and
work concurrently on multiple wells located in
different parts of the world, (2) minimize HSE
issues by reducing the number of staff needed
on site, and (3) decrease the time required to
make the right decisions by facilitating collaboration in real-time. They also provide an environment for experienced people to train and
mentor the rising generation and speed their
development to facilitate knowledge transfer, a
key issue to our industry. Halliburton has built
SPE 111990
“Real Time Operations in Asset Performance
Workflows,” A. Garcia, G. Mijares, J.
Rodriguez, S. Sankaran, and L. Saputelli,
Halliburton, presented at the 2008 SPE
Intelligent Energy Conference and Exhibition,
February 25-27, Amsterdam, The Netherlands
SPE 115367
“Implementing i-field Initiatives in a Deepwater
Green Field, Offshore Nigeria,” O.S. Adeyemi,
S.G. Shryock, Chevron; S. Sankaran,
Halliburton; O. Hostad, StatoilHydro; and J.
Gontijo, Petrobras, presented at the 2008 SPE
Annual Technical Conference and Exhibition,
September 21-24, Denver, Colorado
Fig. 2. The operator's engineers use DSSTM software daily to visualize electronic meter data in order
to monitor production and identify potential problems. Left: wellhead pressures (red = higher, yellow =
lower). Right: production rates (size = volume, red = decrease, green = increase). Bottom: hourly meter
readings over 9 months (brown = eff. gas in Mcf/D, blue = water, green = cum. gas in MMcf).
over one hundred Real-Time Centers (RTCs)
around the globe. About half of these were
constructed for national and international oil
companies and are usually manned by our experts, as well as our clients. The rest were built
as internal RTC “hubs” for our own service
quality and operational excellence control and
are fully staffed by Halliburton personnel and
support wells within their respective regions.
SPE 127517
“Methodology for Oil Production-Loss Control
in a Digital Oilfield Implementation,” A. Garcia,
L. Machado, G. Singh, D. Martins, Halliburton;
P.S. de Sousa, and M. Herdeiro, Petrobras,
presented at the 2010 SPE Intelligent Energy
Conference and Exhibition, March 23-25,
Utrecht, The Netherlands
Fully adaptable to the needs and conditions of
a particular location, RTCs can integrate all
aspects of a project, from prospect generation
/ 29
SPE 127691
SPE 138316
SPE 150455
“Realizing Value from Implementing i-field™ in
Agbami—a Deepwater Greenfield in an Offshore
Nigeria Development,” S. Sankaran, A. Awasthi,
Halliburton; M. Olise, D. Meinert, Chevron, SPE
Economics & Management, 2011
“Monitoring and Optimizing Oil Fields by a
Real-Time Production Operation (RTPO) System,”
T. Dutra, L. Machado, M. Rodriguez, I. Almeida,
Halliburton; B. Montanha, M. Manzali, M.
Dinis, L. Carbone, M.F. de Souza, and M.
Herdeiro, Petrobras, presented at the 2010 SPE
Latin American and Caribbean Petroleum
Engineering Conference, December 1-3, Lima, Peru
“Enabling Agile and Responsive Workflow
Automation: A Hydraulic Fracture Design Case
Study,” M. Strobel, G. Carvajal, M. Szatny, C. Peries, Halliburton, presented at the 2012 SPE
Intelligent Energy International, March 27-29,
Utrecht, The Netherlands
SPE 130205
“Holistic Automated Workflows for Reservoir and
Production Optimization,” G. Carvajal, M. Toro,
M. Szatny, G. Robinson, J. Estrada, Halliburton,
presented at the 2010 SPE EUROPEC/EAGE
Annual Conference and Exhibition, June 14-17,
Barcelona, Spain
SPE 132983
“Enhanced Reservoir Scenarios Management
Workflow,” A. Garcia, J. Rebeschini, D. Martins,
C. Vieira, Halliburton; F. Nunes, E. da Silva, and
M. Herdeiro, Petrobras, presented at the 2010
SPE Asia Pacific Oil and Gas Conference and
Exhibition, October 18-20, Brisbane, Australia
/ 30
SPE 138436
“Integrated Optimization System for Short-Term
Production Operations Analysis,” J. Rebeschini,
A. Garcia, A. Lima, S. Purwar, Halliburton; L.
Carbone, M. Dinis, and M. Herdeiro, Petrobras,
presented at the 2010 SPE Latin American and
Caribbean Petroleum Engineering Conference,
December 1-3, Lima, Peru
SPE 152234
“Workflow Automation (WFA) for the Integrated
Production Operations in the Macuspana Field,”
C. Cruz Villanueva, C. Tapia, A. Calatayud, M.
Benumea, Pemex; A. Garcia, V.H. Hernandez,
J.A. Balcazar, T. Lotar, S. Purwar, and J.
Rodriguez, Halliburton, presented at the 2012
Engineering Conference, April 16-19, Mexico City, Mexico
SPE 152330
SPE 143730
“Transforming Operations with Real-Time
Production Optimization and Reservoir
Management: Case History Offshore Angola,”
J. Paulo, D.A. Taylor, O. Isichei, M. King,
Chevron; G. Singh, Halliburton, presented at
the 2011 SPE Digital Energy Conference and
Exhibition, April 19-21, The Woodlands, Texas
“Enhance Platform Integrity by a Real-Time
Equipment Monitoring Workflow,” L. Machado,
M. Costa, Halliburton; S. Correa, E. Regina,
and M. Herdeiro, Petrobras, presented at the
2012 Latin American and Caribbean Petroleum
Engineering Conference, April 16-18, Mexico
City, Mexico
to well planning, drilling, evaluation, optimization, field delineation, reservoir modeling
and production enhancement. As operations
expand and move increasingly to offshore and
other challenging environments, the real-time
feedback available in these centers provide
the ability to monitor rig and downhole
operations remotely while fostering efficient
collaboration among team members and
experts around the world—without the need
to travel to remote or dangerous locations—
improving safety, helping reduce costs and,
ultimately, enabling our customers to make
better decisions.
An example of the RTC capability is RTS™
Reservoir Testing Studio which features the
Halliburton proprietary ExactFrac® Services
and FasTest® analysis service techniques as well
as conventional Horner (radial) and spherical
time plot well test routines. The RTS studio is
designed to work with the Halliburton InSite®
real-time data management and distribution
system. The InSite Anywhere® service option
provides real-time access to RTS analysis plots,
from anywhere and at anytime, with an internet
connection. A report generator compiles the
pressure transient analysis into reports that
contain summary tables, gradient plots, and
the analysis plots. The summary tables can be
exported to Microsoft Excel® spreadsheets or
Microsoft Word® tables.
SPE 108291
“Optimization of Deepwater Drilling With
Real-time Operations,” W. Hamed, ShellEgypt; and A. Bassem, M. Gamal, S. Nafie,
M. Oraby, and A. Waheed, Halliburton,
presented at the 2007 SPE/IADC Middle East
Drilling and Technology Conference and
Exhibition, October 22-24, Cairo, Egypt
SPE 97059
Fig. 3. Real Time Center in Calgary, Alberta,
Canada. Geoscientists and engineers are
able to visualize, analyze, and interpret
reservoir and drilling data in real time.
“Evolution of Real-Time Drilling Operations:
From Concept and Value Justification to Global
Implementation,” E. Van Oort, Shell E&P
Americas; R. Rosso, Halliburton; and J. CabelloMontero, Shell E&P Technology, presented at
the 2005 SPE Annual Technical Conference and
Exhibition, October 9-12, Dallas, Texas
SPE 111990
“Real Time Operations in Asset Performance
Workflows,” A. Garcia, S. Sankaran, G. Mijares,
J. Rodriguez, and L. Saputelli, Halliburton,
presented at the 2008 Intelligent Energy
Conference and Exhibition, February 25-27,
Amsterdam, The Netherlands
Fig. 4. Halliburton Real-Time Center (RTC)
reservoir and drilling data in real time.
/ 31
Case STUDY:
Real-Time Geosteering Delivers Precise Horizontal Wellbore Placement in Canadian Heavy Oil Sands
An operator in the Primrose heavy-oil field in northern Alberta,
Canada, requires steam injection for several months through
horizontal wellbores placed low in the reservoir. The operator drills
wells from pads with 16 horizontal wellbores each: eight each in
opposite directions, with lateral sections approximately 1,200 m
long. At a depth of 450 m in the Clearwater formation, producing
sands lie over shale, sometimes with a thin layer of nonproducing or
muddy sand in between. To land as close as possible to the bottom
of the producing sands, the wells target the base of the reservoir
with a maximum 1 m clearance. In the past, use of conventional
gamma-ray data to detect the reservoir bottom was unsuccessful,
and "tagging the shale" to characterize the reservoir was inaccurate
and inefficient, often resulting in a stuck bit or increased wellbore
tortuosity that would position part of the production section in nonproducing rock. With 6 to 10 of the 16 wells per pad sidetracked
at least once, the operator sought to reduce tagging and improve
wellbore positioning. Sperry Drilling provided a collaborative approach in which geoscientists and engineers worked together at
the Calgary RTC (Fig. 3). The StrataSteer® geosteering and modeling
software allowed the team to visualize, analyze and interpret reservoir and drilling data in real time, constantly updating petrophysical
models and refining the reservoir characterization for more accurate
wellbore placement. Because the data can be viewed at the RTC in
real time from any location, remote operation would help increase
safety by reducing the number of people required on location.
Based on the LWD responses predicted, drilling engineers, geologists and directional well planners then designed well and pad plans
/ 32
for optimal reservoir drainage. Geosteering was conducted with
Sperry gamma-ray and resistivity sensors and data transmission was
provided by the ZoomXM™ electromagnetic telemetry (EMT) system. During drilling, the EMT transmitted downhole data from
the LWD tools back to surface on the rig and to the RTC, where
experts continually compared actual against predicted log responses
to update the model and identify new drilling targets for the directional driller at the rig. Penetration rates through the
Clearwater sand approach 200 to 400 m/h and geosteering must
respond rapidly. Over time, as the accuracy of wellbore placement
increased, the penetration rate doubled to > 300 m/h. The resulting
55 geosteered wells were drilled with zero sidetracks, straighter
wellbores, and precise wellbore placement within 0.5 to 1 m of the
reservoir base. The producible reservoir was increased by an estimated 5 to 10%. Using the shared earth model, engineers can now
complete a well plan in just a few days that previously took 4 to 6
weeks to complete. Geosteering in the Primrose field resulted in an
average drilling cost reduction of 13% per well, partly due to faster
drilling speeds and time saved by avoiding the shale. In addition, the
resulting smoother well trajectories reduced drilling costs and will
maximize steam contact with the reservoir. A straighter wellbore
requires fewer wiper trips, creates easier liner and casing runs, and
speeds other drilling operations. As a result, the number of days in
the horizontal section fell from 4.25 to 3.6, and drilling time declined 40% in some wells. In addition, the cost of a wellsite
geologist was eliminated. The company planned to use Sperry’s RTC
approach on similar properties east of Primrose field.
Case STUDY:
Real-time Center Optimizes Geosteering Efforts to Maximize Exposure in Extremely
Thin Middle East Clastic Reservoir
A Middle East operator drilling through complex shale and sand formations required
accurate and high-quality real-time information to navigate to a very thin (1 m) sandstone
target zone sandwiched between two shale zones and where the dip changes rapidly within
a short vertical section and commonly thins out. Planning and executing operations
through a RTC (Fig. 4), Sperry Drilling services implemented the ADT® applied drilling
technology drilling optimization service to guide performance of a Geo-Pilot® rotary
steerable system and triple-combo logging-while-drilling (LWD) suite using StrataSteer®
3D geosteering service. With the ADT service, Sperry Drilling was able to create a team
focused on the customer objectives, integrating real-time LWD monitoring and engineering support combined with geosteering and petrophysical support. The ADT service
provided prewell, real-time, and post-well support from two separate locations: Real-time
geosteering specialists were located at the customer’s location, and real-time monitoring
and intervention for LWD and ADT optimization services were conducted from the
RTC. This arrangement enabled the Sperry Drilling geosteering specialists to maintain
constant communication, and effectively linked the Sperry geologists with customer
geologists. Sperry Drilling geosteering specialists used geosignals from the InSite ADR
sensor to identify vertical and lateral changes in reservoir thickness, continuously refining
the wellbore trajectory for precise wellbore placement within the target zone. Sperry
Drilling’s experienced StrataSteer service specialists helped the customer achieve very high
reservoir contact in the thin sandstone formation, placing the wellbore within the narrow
target with maximum 100% reservoir contact. With this success, application of the ADR
azimuthal deep resistivity sensor and the RTC have now become requirements in this field.
SPE 163696
“Maximizing the Value of Real-Time Operations
for Diagnostic and Optimization at the Right
Time,” A. Al-Jasmi, H.K. Goel, A. Al-Abbasi, and
H. Nasr, Kuwait Oil Company; and G. Velasquez,
G.A. Carvajal, A.S. Cullick, J.A. Rodriguez, and
M. Scott, Halliburton, presented at the 2013
SPE Digital Energy Conference and Exhibition,
March 5-7, The Woodlands, TX, USA
OTC 20921
“Visualization and Collaboration: Keys to Optimal
Platform Placement,” J. Cristancho, R. Peters,
Halliburton; W. Denham, D. Algu, P. Daley,
and C. Njoku, Shell E&P, presented at the 2010
Offshore Technology Conference, May 306,
Houston, Texas
SPE 122855
“The Promise and Challenges of Digital Oilfield
Solutions—Lessons Learned From Global
Implementations and Future Directions,”
S. Sankaran, J. Lugo, A. Awasthi, and G. Mijares,
Halliburton, presented at the 2009 SPE Digital
Energy Conference and Exhibition, April 7-8,
Houston, Texas
/ 33
SPE 128522
SPE 166695
SPE 167397
“Overcoming Uncertainties Through Advanced
Real-Time Wellbore Positioning in Kuwait:
A Success Story,” S. Jumah, K. Saleh, H.
Al-Mayyan, F. Al-Mudairis, Kuwait Oil
Company; D. Hawkins, H. Al-Abri, P. Martinez,
Halliburton Sperry Drilling, presented at the
2010 SPE North Africa Technical Conference
and Exhibition, February 14-17, Cairo, Egypt
“Using Real-Time Operations Interventions
in a Drilling and Subsurface Collaborative
Environment,” T. Fayzullin, Lukoil; P. Kowalchuk,
T. Goebel, and A. Shopeju, Halliburton, presented at the 2013 SPE/IADC Middle East Drilling
Technology Conference and Exhibition, October
7-9, Dubai, United Arab Emirates
“Maximizing the Value of Real-Time Operations
for Diagnostic and Optimization at the Right Time
(KwIDF Project),” A. Al-Jasmi, H.K. Goel, A. Al-Abbasi, and H. Nasr, Kuwait Oil Company;
and G. Velasquez, G.A. Carvajal, A.S. Cullick*,
J.A. Rodriguez, and M. Scott, Halliburton,
presented at the 2013 SPE Middle East Intelligent
Energy Conference and Exhibition, October
28-30, Dubai, United Arab Emirates
SPE 143757
“Barriers to the Implementation of Real-Time
Operations Strategy,” C. Crawley, Chevron; and A.
Rizvi, Halliburton, presented at the 2011 Brasil
Offshore Conference and Exhibition, June 14-17,
Macae, Brazil
SPE 163697
“A Surveillance "Smart Flow" for Intelligent
Digital Production Operations,” A. Al-Jasmi,
H.K. Goel and H. Nasr, Kuwait Oil Company;
and G.A. Carvajal, D.W. Johnson, A.S. Cullick*,
J.A. Rodriguez, G. Moricca, G. Velasquez, M.
Villamizar and M. Querales, Halliburton, 2013
March 5-7, The Woodlands, Texas
/ 34
SPE 167273
“Effective Well Management in Sabriyah
Intelligent Digital Oilfield,” M. A-R. Jamal, M.
Al-Mufarej, M. Al-Mutawa, E. Anthony, and
C. Hom, Kuwait Oil Company; S. Singh, G.
Moricca, and J. Kain, Halliburton; L. Saputelli,
Frontender Corporation (formerly with
Halliburton), presented at the 2013 SPE Kuwait
Oil and Gas Show and Conference, October
7-10, Mishref, Kuwait
OTC 24358
“Optimized Well Path Planning Decisions in
Real-time Monitoring Operations,” C. Falcone,
C. Born, J. Lonardelli, and O. Nunes, Petrobras;
W. Ney, Halliburton, presented at the 2013OTC
Brasil, October 29-31, Rio de Janeiro, Brazil
SPE 141598
SPE 167327
“Value Generated Through Automated Workflows
Using Digital Oilfield Concepts: Case Study,”
B.A. Al-Enezi, M. Al-Mufarej and E.R. Anthony,
Kuwait Oil Company; G. Moricca, J. Kain,
Halliburton, and L. Saputelli, Frontender
Corporation (formerly with Halliburton), presented at the 2013 SPE Kuwait Oil and Gas Show
and Conference, October 7-10, Mishref, Kuwait
“Case-Based Reasoning: Predicting Real-Time
Drilling Problems and Improving Drilling
Performance,” H. Raja, Halliburton Energy
Services, Frode Somo and M.L. Vinther,
Verdande Technology, presented at the
2011 SPE Middle East Oil and Gas Show and
Conference, September 25-28, Manama, Bahrain
Diagnosing the Reservoir
Understanding well performance is key to
optimizing production and ultimate recovery
from mature fields. One of the most important
key elements on determining the overall reservoir performance is the bottomhole pressure.
Halliburton offers a number of sophisticated
tools, in addition to worldwide, real-time data
management capabilities, that measure and
interpret well performance parameters such as
bottomhole pressure build and drawdown and
turn that data into actionable information to
enhance the performance of your mature asset.
This can be done through intervention pressure
gauges to get the exact pressure along with rapid
telemetry transmission or though new surface
technology requiring no intervention to get the
downhole pressure by measuring the surface
pressure with analyses obtaining the downhole
reservoir pressure.
communicating with the unit and a program for
converting the acquired wellhead pressure data
to bottomhole conditions and generating the
necessary plots for reservoir analysis.
Quartz-type transducers provide distinct
advantages in pressure resolution, data frequency,
stability in changing temperature conditions that
are essential in the application of surface pressure
data for pressure transient analysis. The design
of the SPIDR internal pressure transducer, a
shear-mode, dual quartz-crystal resonator whose
frequency changes with pressure, is the basis
for SPIDR system's accuracy. This transducer
is extremely rugged, accurate and repeatable,
making it well suited for oilfield applications.
The transducer uses a second quartz crystal for
temperature compensation ensuring the pressure
data are unaffected by temperature changes in the
Reservoir Evaluations from the Surface
The Self-Powered Intelligent-Data Retriever
(SPIDR®) unit is a surface well-testing system
that detects subtle pressure changes over a short
period of time (Fig. 5). It was developed as a
nonintervention alternative to using downhole
pressure gauges for well testing and thereby
eliminates the high risk and expense of running
gauges downhole. The SPIDR system includes
software for programming, downloading and
Fig. 5. SPIDR® Self-Power Intelligent-Data Retriever.
/ 35
Case STUDY:
DFITTM Tool-Derived Frac Parameters
Help Operators Select Completion
A major South Texas operator used the
SPIDR system to perform work for Wilcox
wells to specifically determine permeability
ahead of the scheduled frac date. A common
problem in the Wilcox is that permeability
obtained from drilling logs is often inaccurate, resulting in stimulation expenditures
that don’t provide an economic rate of
return. The DFIT tool can provide the operator with empirically derived permeability
numbers that will help make the decision
if a particular zone should be fractured or
not. In one specific instance, the operator
chose not to fracture a zone, which resulted
in an approximate savings of $500,000 USD.
These savings were then spent to stimulate
more productive payzones to achieve an
economic well.
well and its surroundings. The accuracy of the
surface transducer can be verified before, during,
and after each test, and the transducer is not subjected to the temperatures and stresses of a trip
downhole. Digital data eliminate errors in reading
mechanical pressure-bomb recorders. The SPIDR
system can also monitor two external transducers,
greatly expanding the utility of the system by
allowing simultaneous monitoring of other
process variables, such as, flow rate, temperature
and pressure. External transducers are suitable
/ 36
for sour service and are available in several ranges
with an accuracy of ±- 0.2% and can be located
several feet away. The results obtained from the
SPIDR system are equal to or superior to those
from testing with downhole gauges, without the
many risks and costs of downhole testing.
The SPIDR system memory has a maximum
capacity of > 9 million samples. A single sample
includes date, time, sample number, pressure
from the internal transducer, and readings from
the external transducers.
Subsurface Evaluation
Data acquisition is one of the most important
objectives during a reservoir management well
testing operation. The well-test data acquisition
system must be reliable, provide accurate
measurements and provide information that
is easily accessible to customers. Halliburton
offers a line of robust gauges with proven
track records for reliability all designed to
meet a variety of customer needs. Continued
innovation and technological advancement
has led to development of a newer generation
of highly reliable tools that require less power,
employ larger memory capacity, and have
higher resolution and increased stability in high
temperatures, resulting in consistent, accurate
measurement of reservoir parameters.
The SmartLog™ permanent downhole gauge
system (Fig. 2) allows an operator to monitor
production status in real time throughout the
life of an asset, allowing for critical adjustments
as needed to optimize reservoir and production
management when downhole conditions
change. Piezoresistive-gauge technology
provides accurate, repeatable, reliable, and
economical downhole pressure, temperature
and vibration measurements. In addition to
production monitoring, the real-time data provided by these gauges are also used to
optimize commingled zones, identify communication between wells, and to plan well
placement. The specifications for the SmartLog
gauge are provided in Table 1. Based on testing,
the estimated target reliability for the SmartLog
system is approximately 90% for five years at
110°C operating environment.
DynaMem® electronic memory gauges are
available in three series of gauges depending
on the type of sensor: Quartz, sapphire, and
piezoresistive. They are designed for both shortterm and long-term monitoring requirements,
including well testing, well simulation, completions diagnostics, slickline and coiled-tubing
operations. The gauges come in standard sizes
and a miniature version that maintains the
same standard as larger gauges (Tables 2 to
4). The gauges require very little maintenance
and are easily calibrated. These robust gauges
have proven reliable in the toughest of oilfield
environments, including sour service.
A side-pocket mandrel gauge is available for use
in flowing gas-lift wells. Similar to the electronic
memory gauges, these also have a large memory
capacity and low power consumption. They are
used in long-term monitoring of flowing wells
with no tubing restriction, in frac monitoring
and production testing. Please refer to your
Halliburton representative for more details on
the gauges.
The Halliburton through-tubing, retrievable
High-Expansion Gauge Hanger (Fig. 7) allows
memory gauges, fluid samplers, and other
downhole devices to be securely anchored in
the wellbore at the reservoir depth while using
conventional slickline methods for setting and
retrieving. The slim design allows it to be deployed through smaller completion tubing
and restrictions to be set in liners/casings with a larger ID.
Calibrated Pressure Range
Atmospheric–5,000 psi
Pressure Accurancy (%FS)
<0.1
Pressure Resolution (psi/sec)
<0.05
Pressure Drift at Maximum
Pressure and Temperature (%FS/yr)
<0.1
Maximum Operating Pressure
6000 psi
Calibrated Temperature Range
Ambient - 125˚ C
Temperature Accuracy (˚C)
<0.5
Operating Temperature Range
-20˚C to 125˚C
Vibration Sensing ±-17g axis accelerometer
Table 1. SmartLog Gauage
The benefits of the High-Expansion Gauge
Hanger include:
• Soft set with Halliburton’s nonexplosive
Downhole Power Unit (DPU® Downhole
Power Unit) tool
• Slickline retrievable
• Can be run on slickline, e-line, or coiled
tubing
• Reliability and design based on proven
Fig. 6. The slim (0.88 in. OD) SmartLog™ gauge housing and chassis.
/ 37
through-tubing bridge-plug technology
• Easily field redressable
Bottomhole to Surface Data Communication
• Streamlined design
maximizes flow area
The DynaLink® telemetry system (Fig. 8)
provides reliable, real-time, wireless bi-directional communication that helps reduce the
cost of operations and enhances the economic
value of the reservoir. The telemetry system
uses acoustic energy transmitted through the
tubing or wireline to allow flexible access to
downhole sensors to provide critical and accurate real-time data that are used to
monitor or evaluate the reservoir thus enabling
better and faster decisions in drillstem
testing, pressure and temperature monitoring,
sand-control, sampling, or stimulation applications. Strategically placed repeaters boost the
signal periodically to overcome signal attenuation with depth and a backup memory gauge
provides redundant capabilities. At surface, a
wireless station receives and transmits the data.
The system is rated to 20,000 psi (137.9 MPa)
and 302°F (150°C).
• Minimal restrictions
increase quality of
data collected while
flowing or injecting.
The hanger is full-
featured, providing:
• Slow controlled,
soft set for equal
force distribution,
self-centralizing
• A greater flow area
than other hangers in
the industry
• Debris- and
scale-tolerant
• Optimum bidirectional slip contact
allowing high load
capacity
Fig. 7. HighExpansion Gauge
Hanger
• Slip design that optimizes setting force and
minimizes damage to tubing
/ 38
• The ability to be set in multiple-weight
casings, one size for multiple-weight casings.
A simple modular design reduces operational complexity, allowing versatility and
performing the job with wireline if necessary.
The DynaLink system's bidirectional communication capability allows it to be used to
actuate downhole tools including tester and
circulating valves, bottomhole samplers, and
transmission control protocol (TCP). The
DynaLink system is capable of transmitting
data across Halliburton annulus-operated
downhole tester valves in drillstem testing
(DST) applications, or can be hung-off on
wireline in bottomhole pressure survey
applications. For pressure and temperature
monitoring, a dual memory gauge allows
redundancy capability. The compact size
allows for increased application flexibility in
drillstem testing, fracturing, coiled tubing,
and sand-control operations, and also allows
for ease of transportation.
Case STUDY:
Downhole pressure gauges deployed
using high-expansion gauge carrier
and retrieved.
At a customer’s location, a set of bottomhole
pressure gauges attached to the Halliburton
4.5-in. high-expansion gauge hanger was
set using a slickline DPU® Downhole Power
Unit tool at 11,970 ft (3,649 m). The gauges
were put through a series of production
tests over a 22-day period up to: 4,485 psi
(30.9 MPa) flowing pressure, 29.7 MMcf/D
on a 38/64 in. choke with 3.8% CO2. After
all the tests were concluded, Halliburton
slickline was deployed to the location,
which pulled the gauges without trouble,
and the bottomhole pressure gauges were
downloaded.
Whether data are acquired in the subsurface
or at the wellhead, the data and the initial interpretation must be integrated and analyzed
with other well data to fully understand production parameters and optimize well output.
Using powerful HalLink® satellite communications technology to bridge the distance between
people and data, Real-Time Operations brings
well-test data directly to the experts, enabling
Halliburton and the client to monitor and
analyze a well test in real time without traveling to the wellsite. This means not only faster
communication of vital information from the
wellsite to support personnel, but also faster
solutions for unplanned events.
SPE 77701
“Gas/Condensate and Oil Well Testing–From
the Surface,” C. Fair, Data Retrieval Corp.; B.
Cook, Nexen Petroleum U.S.A., Inc.; T. Brighton,
BG-Group, M. Redman, and S. Newman, Data
Retrieval Corp., presented at the 2002 SPE
September 29-October 2, San Antonio, Texas
Mechanical and Chemical Lift Solutions
that Keep Mature Wells Flowing
Fig. 8. DynaLink® Telemetry System
At some point, pressure depletions in nearly all
wells will require some form of artificial lift to
keep production flowing at value-added rates.
This universal certainty requires the eventual
installation and application of artificial lift
solutions, such as electrical submersible
pumps (ESP), where long-term durability and
reliability are prerequisites for helping continue
to realize maximum value of a mature asset.
Halliburton offers the industry’s most robust
and high performing suite of ESPs and associated motors, and protectors, all engineered,
manufactured and tested to deliver unmatched
reliable service life. Unlike conventional ESPs,
Halliburton’s pumping units are differentiated
by their capacity to handle gas. Halliburton
ESPs are engineered, manufactured and tested
to deliver long service life with accessories
available to increase resistance to abrasion
or corrosion. Extra high-torque shafts are
available for all models. For the centrifugal ESP
suite, the number of stages determines the total
amount of lift provided and motor horsepower
required, allowing pump customization to deliver the most effective performance with the
least operating cost.
Optional instrumentation is available on
all Halliburton advanced ESPs, allowing
remote monitoring and transmission of well
and pump performance data to the surface
control box, and/or to a Web client, if desired,
equipment operation can be maintained at
peak efficiency and well performance can be
optimized.
Unique to Halliburton’s ESP line of artificial
lift solutions is the Q-MAX™ gas bypass,
which is engineered to increase pump
life with a modular design that promotes
efficiency and long-term reliability. Q-MAX
gas bypass minimizes damage by eliminating
the harsh conditions that pumps must endure
/ 39
when gas is handled ineffectively and expands
the operating window for gassy wells.
The sustained feed of the Q-MAX gas bypass
keeps the pump primed with liquid so it
can boost without
surging or pumping
off, even in wells
with a high gas void
fraction (GVF). This
design not only
extends pump life,
but also reduces
intervention costs.
By preventing
gas from entering
the pump, the
Q-Max gas bypass
lengthens pump life
and increases well
productivity, while
Fig. 9. Q-Max™ Gas
reducing intervenBypass
tion costs. Its uniform performance
envelope means less downtime, less electrical
power consumption, and more hydrocarbon production. The unique and robust design
protects the pump, allowing it to operate
trouble free for extended periods.
As most onshore wells employ rod-pumps
for artificial lift, Halliburton provides the
cost-effective MaxiStroke™ surface pumping
/ 40
unit that essentially pays benefits with every
stroke (Fig. 10). The MaxiStroke real-time
adjustable, ultra-long, variable-speed stroke
self-adjusts to dynamic fluid levels in the well
to optimize well performance. The integrated
pump-off controller software automatically
senses downhole conditions and changing load
levels, and, accordingly, adjusts unit speed to
maintain optimum fluid levels.
The MaxiStroke unit helps reduce operating
costs from the day of installation and is the ideal
option for more mature wellsites in built-up or
environmentally sensitive areas. The small footprint of the MaxiStroke unit requires no
large cement pad and most units can be transported to location on a standard flatbed truck.
The exceptional long strokes of MaxiStroke
unit helps reduce rod fatigue as well as rod and
tubing wear, which pays off in fewer interventions and associated downtime. If downhole
maintenance is required, the MaxiStroke XLS
unit model can be set back quickly and easily
to maximize safety and workflow efficiency.
In addition, over time conventional lift
systems face myriad operational challenges,
primarily centered on mechanical wear,
corrosion, pump failures, as well as overall
inefficient pumping. To directly address
inefficient pumping and mechanical wear,
Halliburton changed the face of rob pump
Fig. 10. MaxiStroke™ - XLS (Extra Long Stroke
unit model)
Case STUDY:
ESP-Q-MAX Combo Gas Bypass Increases Well Drawdown, Hikes Gas Production
A West Texas operator requested
Halliburton install an electrical submersible pump (ESP) in a well that was
previously produced by gas lift because it had a Gas Oil Ratio (GOR) of 2,280, which
was far too high for conventional ESP use.
Along with high GOR, the well conditions
included:
• Static BHP: 1300 psi (13.1 MPa)
• BHT: 150°F (88°C)
• Total Fluid Volume: 735 BFPD
• Water Volume:450 BWPD
• Gas Volume: 650 Mcf/D
• Oil Volume: 735 BOPD
design with its advanced Linear Lift System
(LLS). An innovative and footprint-reducing
pump jack design, the LLS features the same
downhole equipment as a conventional rod
pump system, essentially consisting of tubing,
rods, and a pump. The difference is in the
surface equipment, which is smaller, has an
automatic pump-off controller and a self-adjusting, ultra-long variable speed stroke.
The operator wanted to increase well
drawdown and stimulate gas production by
installing an ESP, but was concerned that
high GOR would create gas-lock conditions and inhibit normal pump operations.
Realizing the limitations of traditional
rotary gas separators (RGS) in such high
GOR wells, Halliburton proposed the use
of a Q-MAX Gas Bypass (GBP) as the gas
separation device in the ESP configuration. After 12 months of operation, the ESP-Q-MAX combination gas bypass had
increased and sustained gas volume to
1,168 Mcf/D along with a 2% increase in
incremental oil volume to 291 BOPD and
higher total fluid volume of 854 BFPD.
The performance recorded aggregate sales
increases of more than $164,250.
These characteristics have several potential
advantages over the traditional pump jack and
rod pump installation, including:
• More efficient pumping
• Reduced rod and tubing mechanical wear
• Decreased environmental impact
The integrated pump-off controller software
automatically senses downhole conditions and
changing fluid levels. The pump-off controller
then adjusts the unit speed to maintain optimum fluid levels, thus preventing pumpoff and reducing the effects of fluid pound on
the rod string. These innovations minimize
rod and tubing wear and pump failures, thus
promoting more efficient pumping conditions.
The benefits of these operational advantages
are increased daily production with reduced
downtime.
As a cost-effective alternative for operators
wishing to delay the capital costs of mechanical
lift, Multi-Chem
offers the Foam
Assisted Lift
(FAL) solutions
to help maintain
the critical
velocity needed
to carry liquids
to the surface
in wells where
production
pressures are not
high enough to
remove produced
fluids. FAL
solutions reduce
the density of
Fig. 11. Linear Lift System
surface-mounted unit
liquids in the
/ 41
well, allowing gas pressure from the reservoir
to flow hydrocarbon and stabilizing production
by preventing fluids from accumulating and
causing liquid loading.
Using Multi-Chem’s proprietary FAL modeling
software, subject matter specialists perform
a complete system survey and recommend a
customized solution that can be formulated
with compatible chemistries for corrosion
protection, scale control, hydrate control, or
paraffin and asphaltene control, providing
maximum benefit from a single injection point. Specialists test chemical FAL products to
ensure the proper chemistry to unload the well
quickly, minimizing production losses. After
applying the solution, Multi-Chem’s expert
team continues to monitor well performance
and recommend any program modifications
that will ensure sustained production flow.
The customized FAL products are formulated
based on specific conditions of the application,
such as colder climates, high temperature
reservoir conditions, high TDS brines and high
condensate wells. For deepwater artificial lift
applications, Multi-Chem offers umbilical-
certified FAL products. The FAL products can
be applied in batch treatments, either through continuous injection down the backside of
wells, or via a capillary string.
/ 42
Customized Remedial Chemical Solutions
to Sustain Production with Supporting
Accessories
As fields mature, a proliferation of restrictions,
such as corrosion, paraffin, H2S and iron
oxide solids, hinder the ability to optimize
reservoir contact and maximize production. Production chemicals represent the front line
of defense in keeping production flowing and
increasing the life of the well. However, to be
truly effective, chemical remediation solutions
must be formulated precisely to meet distinct
reservoir characteristics.
Multi-Chem, a Halliburton service, has long
been recognized as the premier provider of
production chemical solutions that strike a
healthy balance between performance and environmental stewardship. Multi-Chem offers
a full suite of production-sustaining additives,
including corrosion inhibitors, defoamers,
oxygen and H2S scavengers, surfactants, and
scale inhibitors, among others. In developing
a tailored solution, Muli-Chem’s production
chemical specialists examine core samples to
ensure the formulation perfectly matches the
formation characteristics. In essence, MultiChem creates a new technology for each and
every application.
That reservoir-specific approach is clearly
reflected in Multi-Chem’s award-winning
Customized RockOn® surfactants that
consistently demonstrate higher initial
production rates and greater ultimate recovery at lower overall well costs. Specifically
formulated based on core-sample testing,
each RockOn® surfactant solution is custom-tailored to take into account the unique
reservoir characteristics, with options to fit
specific environmental requirements. By
optimizing RockOn surfactant usage rates,
Multi-Chem production chemical specialists
also help minimize costs, while optimal
interaction with a broad range of API gravity
oils increases fluid mobility to improve lift
efficiency and extend pump life. Fig. 12. Using proprietary FAL modeling
software, subject matter specialists perform a
complete system survey and can recommend
a custom designed solution that can be
formulated with compatible chemistries for
corrosion protection, scale control, hydrate
control, or paraffin and asphaltene control.
AWARD
RockOn Surfactants won the 2013 World Oil
Best Production Chemicals award
RockOn surfactants are designed to increase
the radial penetration of the frac jobs, providing access to more of the reservoir and trapped
oil. RockOn surfactant chemistry elongates the
oil droplets trapped in small pore spaces, allowing the oil to move through the small
pore throats, enabling more oil to be produced
that otherwise would remain behind the pipe.
Over time, the buildup of hazardous hydrogen
sulfide (H2S) and iron sulfide in producing
wells, pipelines and tubular surfaces severely
restricts production and the continuing
economic vitality of the mature asset. MultiChem’s response to that prevalent problem is
its AcroClear® acrolein-based H2S scavenger
and iron sulfide dissolver that consistently
outperforms conventional chemical solutions. AcroClear dissolver delivers highly effective
removal of iron sulfide in production and injection wells, repairing near-wellbore
damage caused by iron sulfide deposits and
previous acid-jobs. It is also effective in removing iron sulfide-based deposits on pipelines or
tubular surfaces, exposing the surface area for
an effective corrosion-inhibitor application.
AcroClear H2S scavenger and iron sulfide dissolver is water- and oil-soluble, allowing
it to penetrate oily coatings on iron sulfide
particles, clarify black water and rid discharge
of surface-sheening iron sulfide solids. Unlike
acid or THPS treatments, AcroClear dissolver is
non-corrosive and does not change the system
pH, nor is it affected by iron concentrations.
The highly reactive dissolver works completely,
irreversibly and quickly, which is extremely
important when retention time is an issue.
Administered only by Multi-Chem’s specially
trained Certified AcroClear Technical Specialists
(CATS), AcroClear treatments are at much lower
rates than other specialty chemicals, providing a
cost-effective dissolver with a very short half life,
reducing its environmental impact. Complementing AcroClear treatments is
the Multi-Chem H2S scavenger and iron
sulfide dissolver tank that incorporates a
satellite-based temperature monitoring system
to detect any polymerization or contamination
of the product. In the event of a temperature
excursion, the GPS transmitter immediately
notifies key Multi-Chem response personnel.
The rugged AcroClear H2S scavenger and iron
sulfide dissolver field tanks are built to meet
extremely high quality standards.
Fig. 13. Trapped oil droplet before RockOn
surfactant is added.
Fig. 14. After RockOn surfactant is added, oil
droplet is deformed and able to move with
water and through the formation.
For onshore applications, Multi-Chem
developed its suite of Low Dosage Hydrate
Inhibitors (LDHI) to effectively control
hydrates to maintain well, flowline and
pipeline integrity while reducing total costs.
As its name implies, the LDHI require lower,
and more cost effective, dosage rates than
conventional methanol or glycol-based
inhibitors. The LDHI has been a proven an
ideal solution to preventing hydrate plugs that
can create complete blockages, enhancing HSE
/ 43
of highly advanced rocking cells, specially
designed to withstand corrosive gases. The
system provides an opportunity to better simulate actual flow conditions, reducing risks
of plugged lines and stimulates actual field
conditions-onshore, offshore or subsea.
As with nearly all oil and gas development
and production operations, enhancing production from mature and depleted reservoirs
also must comply with ever-tightening environmental restrictions. These regulations also
mandate that production chemical treatments
come with reduced environmental impact.
Fig. 15. Sulfide Controller Tank.
performance by reducing chemical storage and
handling hazards associated with the thermodynamic inhibitors.
The chemical specialists that make up Multi-Chem’s Flow Assurance Engineers
first perform an extensive system survey to
determine the type of inhibitor best suited for
the specific application and provide a cost-
effective LDHI program to reduce the risks of
plugged lines and system failures associated
with hydrates. The team uses state-of-the-art
monitoring and modeling software to design
and implement the right solution to maintain
flow at optimal levels. Offering best-in-class
technology, Multi-Chem continues to
/ 44
introduce innovative technologies and applications for LDHI solutions, including:
At the core of the Multi-Chem portfolio are
its all-inclusive NaturalLine® environmentally
conscious products and solutions, which
offer a chemical alternative tailored for
• Anti-Agglomerate (AA) inhibitors that prevents hydrates from adhering to each
other by keeping hydrate crystals in a slurry
that can be flushed out with remaining fluids
• Kinetic Hydrate Inhibitors (KHI) that
prevents hydrates from forming for a period
of time—or holds them static for a period of
time. If the residence time of the fluids in a
pipe is shorter than the hold time, no hydrates form
For testing and assessing LDHI, Multi-Chem
has developed a first-of-its-kind system
Fig. 16. Low Dosage Hydrate Inhibitors (LDHI)
from Multi-Chem effectively control hydrates
to maintain well, flowline and pipeline integrity
while lowering total costs.
Case STUDY:
Case STUDY:
Case STUDY:
LDHI Eliminates Methanol to Control
Hydrates, Cuts Costs
AcroClear® Dissolver Cleans Water
Tanks, Saves LA Operator $36,500/Month
Biocide Treatment Removes Arsenic,
Makes Oil Saleable
The oil producer was consuming
significant volumes of methanol to
control hydrates in the tubing which
formed above a downhole choke. After
a survey, Multi-Chem replaced the
methanol with its MC MX 892-5 LDHI
at an initial injection rate of 320 litres/
day. Optimization of the chemistry was
undertaken every two days and once a
reduction of 60% was reached the rates
were slowed to once per week to ensure no reoccurrence of hydrate depositions.
Eventually a 70% reduction was reached
at 100 L/D. Before application of the
LDHI solution, the operator was using
320 litres/day of methanol, which if
reduced below 250 L/D, would cause
the well to plug off within two to three
days. By reducing the rate with LDHI,
the operator saved $1,572/month and
experienced no further problems with
hydrate formations. By reducing the
chemicals required at the location, the
operator realized additional cuts in freight costs.
An operator in central Louisiana was
experiencing increases in the discharge
pressures of the water transfer lines
throughout the field. These increases
reduced the amount of disposal water
that could be transferred from several
tank batteries in the field to the saltwater
disposal (SWD) system via water transfer
pumps. The operator had to rely on
trucking to transfer the water from various locations in the field to the SWD
system at an average cost of $1,200/day or
approximately $36,500/month. A Multi
Chem analysis identified the problem with
the 400-bbl tank batteries as high iron
sulfide depositions. Afterwards, the tanks
were treated with AcroClear dissolver at
1.5% volume based on the water levels and,
once treated, the operator circulated the
tanks for 24 hours. Afterwards the water
was able to be transferred from the tanks
batteries to the SWD system without the
use of water transfer trucks. The application of AcroClear dissolver eliminated the
need for water truck transfers in the field
saving the customer $36,500/month in
trucking cost.
A Wyoming producer was experiencing
arsenic in the oil production from its
gas wells at high enough levels that the
refineries were rejecting the crude. The
wells were producing 300 BOPD, which
the operator was unable to sell. Moreover,
production was flowing into a 30,000-bbl
stock tank that had accumulated more
than 10,000 bbl of unsold oil. Accordingly,
the operator had no choice but to truck
the oil to a different and receptive
refinery. Owing to the additional costs,
the producer contacted Multi-Chem
for a solution. Prior to Multi-Chem’s
involvement, the producer was selling its oil at $50/bbl, but after treatment with
the MC B-8501 biocide, the arsenic was
removed from 6,000 bbl that were sold
at $90/bbl, amounting to $540,000. After
subtracting the $50,400 chemical costs,
the operator realized a $489,600 profit.
By using MC B-8501, the producer was
able to resume going to the refinery with
the oil.
/ 45
Case STUDY:
Case STUDY:
Case STUDY:
Tailored Corrosion Treatment Slashes
Well Costs
Paraffin Treatment Increase Oil
Production from Zero to 200 BOPD
Tailored Treatment Eliminates Scale,
Corrosion Production Restrictions
A major US operator was producing in a
field that historically was very corrosive,
forcing many companies to install
chrome tubing in their wells. Owing to high CO2 and H2S concentrations that
resulted in tubing failures, the operator
had spent approximately $250,000/well
in workover costs. Since chrome tubing
is an expensive solution, the operator
contacted Multi-Chem for an alternative
and effective corrosion inhibitor
program. After surveying the field and
system, Multi-Chem developed a new,
application-specific, formulation for its
MC MX 725-6 corrosion inhibitor that
was applied on these wells some seven
years ago. MC MX 725-6 has proven
to be extremely effective, resulting in
zero failures on hundreds of wells. In
addition, Multi-Chem continues to
monitor the iron and manganese counts
and trends as part of the corrosion
programs. After Multi-Chem applied its
MC MX 725-6 corrosion inhibitor and
the corresponding monitoring program,
the operator was able to eliminate the use
of chrome tubing and reduce operating
and maintenance costs dramatically.
/ 46
An operator in the Rocky Mountains was
experiencing a buildup of paraffin in the
tubing and flowline of one of its wells,
resulting in:
• Slow plunger runs
• Zero oil production and no return on
the investment
• Fouled equipment and location
• Plugging and high pressures
Multi-Chem analyzed the situation and
recommended a tailored MC P-3039
paraffin inhibitor treatment. After the
application, production increased from
zero to 200 BOPD of 38.35 API gravity
crude that sells for roughly $105/bbl.
After subtracting the $613/day chemical
costs, the operator realized net revenue
of $20,387/day.
In San Juan County, California, an operator producing gas from the Fruitland Coal
formation experienced mineral scale
(calcium carbonate and barium sulfate)
deposition on the downhole equipment.
Accordingly, pump life was reduced while
the likelihood of under-deposit corrosion
increased, thus raising operating and
maintenance expense, and reducing
production. After a thorough analysis,
Multi-Chem customized a robust scale
dissolving treatment program that began
with the MC MX 5-1961 inhibitor to
remove existing scale deposits. After the
clean out, to combat the severe scaling
tendencies of the water in the wells, Multi-Chem proposed use of the proprietary MC S-2425 scale inhibitor. As part
of the comprehensive treatment program
tailored for this application, Multi-Chem
then applied the MC C-6252 corrosion
inhibitor, designed to be adsorbed onto
metallic surfaces. After treatment for a
year and half, the wells have not encountered a scale or corrosion-induced failure,
and have realized an increase in production and a reduction in costs. Without this
program, the BHA typically would have
scaled off in about three months.
each application. With its NaturalLine suite,
Multi-Chem collaborates closely with operators
to develop environmentally responsible
alternatives to all their mature field production
challenges, including the treatment of flowback
and produced water.
For each application, Multi-Chem’s
experienced team of technical specialists
will evaluate the production or fracturing
challenge and recommend the most effective
products and solutions to meet the operator’s
production and environmental objectives. All recommended products receive a ranking
based upon carefully selected environmental
and health-based criteria. This information is provided to the operator along with the
pertinent technical and cost performance
information. The product can then be independently evaluated and selected based on
criteria that best demonstrate a commitment
to environmental stewardship, while also
meeting operational needs.
The system to place the chemical at the optimum
location is critical as well to ensure no active
waste of the chemical. The Halliburton
CheckStream® system is a downhole chemical
injection system redundant check valve
installed and protected by an industry-
standard mandrel chassis. The CheckStream
system provides precise wellbore chemistry
management, optimizing flow assurance and
Fig. 17. CheckStream® system One-Piece Mandrel
enhancing production. The dual-redundant
check valve allows delivery of chemical fluids
to the wellbore while simultaneously preventing wellbore fluids and gas from entering
the control line and migrating to the surface.
The system optimizes flow assurance and
production performance and helps reduce
costly intervention.
The Halliburton Checkstream system is included
in completions where chemicals are needed to
be injected downhole to prevent:
• Scale
• Asphaltenes
• Emulsions
• Hydrates
• Foaming
• Paraffin
• Stress Corrosion
• Cracking Corrosion
Features of the CheckStream system include the
following:
• Subsea, platform and land applications
• Dual redundant checks (hard and soft seats)
• Field-installable burst disc with selectable ranges
• Variable cracking pressures available
/ 47
• Wide range of flow from 0.02 to 10 gal/min
• Industry-proven FMJ testable dual metal
-to-metal seal connectors
• High pressure and temperature (HPHT)
ratings of 15,000 psi differential and 200°C for
HPHT applications
• Configurable for multipoint, single control
line injection applications
• Extensive qualification testing performed to
achieve highest reliability
As they age, many wells tend to lose permeability, thereby restricting flow and delivering
less than optimal production rates. For years,
acidizing has been one of the most commonly
used solutions for enlarging void spaces to
maximize reservoir contact to both restore
and increase production. • Welded pup-joint-nipple mandrel is designed for use in low pressure, shallow set,
nondeviated well applications
Halliburton offers a comprehensive suite of
custom-blended carbonate and sandstone
acid-stimulation systems and processes designed to restore declining flow and promote long-term production increases. Of course, optimum results from any of
the various Halliburton formulations and
procedures depend largely on a thorough
understanding of formation mineralogy.
Before an acid-stimulation program commences, Halliburton’s STIM2001™ simulator
evaluates the origins of lost production in one
or a series of wells, and afterwards ranks the
examined wells on the basis of delivering the
best value for each stimulation dollar spent.
The overall mechanical system includes
double check valves, line and cable protectors,
multispooling units for installation of different
chemical cables and pumping units. The system
has gone through many system qualification
tests, including Norwegian testing.
The STIM2001 software can determine the
wells’ skin value, the damage mechanisms in
play, applicable remedies, and the ideal production rate. It can guide fluid selection,
recommend fluid diversion programs,
simulate fluid flows in both sandstone and
The mandrel includes a profile for burst disc
installation. Two types of chemical injection
mandrels are available.
• Deep-set nipple mandrel features a one-piece machined design for use in mature deepwater or critical applications. The
deep-set nipple mandrel utilizes the same
design criteria as the permanent downhole
gauge mandrel
/ 48
Innovative Acidizing Solutions to
Stimulate the Wellbore
carbonates (including worm holing), and
automatically generate reports based upon
single-entry data.
Halliburton offers a wide variety of matrix
acidizing treatments to improve connectivity
near the wellbore region. The innovative
formulations include the new generation
KelaStimSM service, which delivers highly
effective acid stimulation of carbonate or
mixed carbonate/sandstone formations with
the chelant remaining stable up to 400°F.
In addition to its high temperature stability,
the KelaStim system can be used in any
acid-sensitive environment as its chemical
composition promotes rapid biodegradation,
making it more environmentally friendly than
typical acid treatments. What’s more, compared to highly acidic
fluids, like high-strength HCl or formic/
acetic acid blends, the KelaStim system can be
used to stimulate a carbonate formation and
remove damage from the formation with less
risk of rock deconsolidation, which can lead
to wellbore collapse, especially in horizontal
intervals. The fluid system also eliminates
some of the flush stages, thus reducing treatment complexity. The versatile KelaStimSM service fluid also
can be used to remove nonclay damage from
the formation conductive
farther from the wellbore. Combined with design
and placement, these acid
systems are proven effective
in extending well life in the
most complex of fracture
and matrix acidizing
treatments.
The Sandstone 2000
hydrofluoric acid (HF) acid
systems simplify acidizing
with all components designed into the formulaFig. 18. The StimWatch monitoring service comes with iView™ analysis
tion to address the variables
software for real time temperature monitoring.
and problems that once
plagued conventional HF
gravel-pack completions with less risk of
acid treatments. When mineralogy and the
damaging the particulates. It is fully comnature of the damage are uncertain, Sandstone
patible and can be used with HCl, acetic and
2000 system provides maximum dissolving
formic acid blends and tailored for specific
power without secondary precipitation.
applications such as scale removal, pickling,
Compared to standard HF systems, Sandstone
matrix acidizing, or filter-cake removal
2000 system exhibits far less tendency to
applications.
unconsolidate sandstone formations. The portfolio of formation-specific acid treatments include the Carbonate 20/20™ and the
Sandstone 2000™ acidizing systems. Carbonate
20/20 acid systems come with the utmost in
expert personnel, analytical/diagnostic tools,
products, and processes to place the right
fluid across the carbonate formation to leave
Halliburton’s acidizing solutions also use new
generation diverters, like the Guidon AGSSM
acid guidance system that uses a hydrophobically modified polymer to effectively divert
acid away from water-producing zones. The
agent is placed in alternating stages with the
acid throughout the entire treatment.
The effectiveness of an acidizing program also
can be monitored in real-time with Pinnacle’s
StimWatch® stimulation monitoring service
that uses distributed temperature sensing
(DTS) to monitor both acid and fracturing
treatments to observe stimulation fluid entry
points into the formation.
Case STUDY:
StimWatch® Service-Inspired
Adjustments Enhance Stimulation
Effectiveness
A California operator wanted to perform
a stimulation for an underperforming
well that was perforated in multiple
sand and shale horizons. Halliburton
recommended a multistage sandstone
acid treatment with diverter. In order to
understand the performance of the diverter and monitor treatment of all zones,
a retrievable FiberWatch® DTS fiber optic
service was included as part of the acid
stimulation. The StimWatch monitoring
service allowed the operator to view the
placement of the acid treatment in real
time as well as making instantaneous
changes in the stage size and pump-rate.
The initial diverter on this particular job
was not effective and was replaced with
an alternative diverter to successfully
stimulate the entire interval. This improved the effectiveness of the stimulation treatment.
/ 49
As part of Pinnacle’s innovative FiberWatch®
service, which comprises a portfolio of fiber-optic and distributive sensing technologies,
StimWatch service gives operators a vehicle
for monitoring the treatment in real-time and
quickly makes any modifications needed to
optimize the results. By tracking temperature
throughout the wellbore, StimWatch service
indicates the velocity and depth of a fluid,
indicating which zones are being effectively
treated.
Well Interventions
Intervention and workover operations represent
one of the industry’s most expensive and risky
operations, especially in mature and challenging
applications. Any offshore or onshore intervention that can be carried out safely without
requiring a high-cost rig can enhance the overall
economic profile of the asset considerably. Befitting its solution-focused approach,
Halliburton has developed the industry’s most
advanced coiled-tubing and wireline-deployed
intervention solutions, fiber-optic monitoring and highly cost-effective electric and slickline
interventions with associated video monitoring. In addition, Halliburton provides systems
for distinct applications, such as a solution for
setting and retrieving tools in power-limited
well sites and a fast, value-added approach for
identifying stuck-pipe depth.
/ 50
Coiled Tubing Interventions - Reducing Costs,
Enhancing Productivity
As they age or otherwise encounter production-restricting blockages, horizontal wells
pose distinctive remediation challenges. In
mature and often complex horizontal well
trajectories, shutting off high water cut and
sand production, removing scale and other
obstructions and improving near-wellbore
conductivity has proven largely ineffective,
and extremely costly, with conventional rig
interventions.
More and more mature wells are being
re-designed as horizontal to achieve more
recovery from the fields. Halliburton has
long been recognized for its industry-leading
advancements that have contributed to the
rapid emergence of coiled tubing as the
predominate mechanism for horizontal
intervention. Halliburton’s pacesetting innovations in coiled tubing and other
rigless well interventions have been shown to
significantly improve production rates and
completion efficiency, reduce mechanical
risk and extend the economic lives of mature
field wells. Continuing that trend, Boots &
Coots, a Halliburton service, ushered in a
new generation of coiled tubing technology
with its Enhanced QuikRig® system, which
is designed with the well control package
preassembled on a mast, thereby enabling
faster rig-up, improved operational efficiency
and safer operation.
Compared to standard units, the three-
component Enhanced QuikRig coiled tubing
system includes a specially-designed and
larger-capacity reel trailer, a higher-capacity
injector rated up to 125,000 lb, an auxiliary
mast unit housing the well control package
and power pack and a new dedicated 60
to 80-ton boom truck crane (Fig. 19). The
preassembled well-control package enables
the system to rig-up in half the time required
of a conventional coiled tubing unit.
The Enhanced QuikRig® system is ideal
for nearly all conventional coiled-tubing
applications in both mature and emerging
fields. However, its large-capacity well-control
stack of up to a 5-1/8 in. 15K rating and
its capacity to contain a full milling BHA
in the riser stack, makes the new system
especially well-suited for frac-plug mill-outs.
In addition, the versatile Enhanced QuikRig
system also can accommodate all standard
V95 Enhanced QuikRig unit reels and V95K
injectors in applications requiring lower pull
capacities.
The specially designed control panel enables
the coiled-tubing operator to define and label
up to six individual BOP control functions.
the fluid top and optimize the quantity of
injected product, effectively reducing costs.
CoilComm monitoring capabilities include
distributed fiber sensing technologies such as
distributed temperature sensing (DTS) and
distributed acoustic sensing (DAS) (Fig. 21).
With the uniquely engineered CoilComm
service, the optical fiber can be installed inside various coiled-tubing sizes depending
on wellbore requirements. Deploying
fiber-optic sensing technologies in coiled
tubing is a more efficient and economical
method for continuous real-time monitoring
of horizontal well conditions.
Fig. 19. Enhanced QuikRig® - New designed coiled tubing system for Mature Fields limit unit has specialized horizontal shale and well capabilities.
The panel also facilitates the operation of up to
three remote-operated, Lo Torc® control valves.
Moreover, coiled tubing also has emerged
as a cost-effective deployment alternative
to the permanent casing-conveyed, or
tractor-conveyed options for placing well
performance monitoring technology all of
which can be expensive, limited, and risky. Boots & Coots and Pinnacle have further
maximized the efficiency and value of coiled
tubing- conveyed well monitoring with the
new generation CoilCommSM real-time fiber
optics monitoring service to help enhance
well-production performances and the success
rates of interventions. In addition, the real-time
capability of the QuikRig reel trailer fully supports the new CoilComm fiber-optic service.
With CoilComm services, operators have
single-trip access to accurate depth correlation,
temperature and pressure profiles to identify
which zones are benefitting from a stimulation
treatment and which are being bypassed. For jetting and underbalanced operations,
CoilComm service allows operators to measure
In addition, optimizing the effectiveness of
matrix treatments to remove production blocking paraffin, scale and asphaltene deposits from the near-wellbore area, perforations
and screens, as well as remediate cement
and perforation damages, have long been a
challenging proposition. Complementing its
coiled tubing and hydraulic workover expertise, Boots & Coots developed the Pulsonix®
TFA tuned frequency aptitude process,
designed around proven fluidic oscillator
technology. Pulsonix TFA enables better
control when matching fluid rates to the most
desirable frequency and amplitude of the
pressure pulses based on the requirements of
the application. The Pulsonix TFA service is
/ 51
bbl/min allows precise matching of the BHA
and maximizing the flow capacity benefits
of a wide range of coiled tubing and jointed
pipe sizes. Unprecedented mass flow rates
provide stronger pulse amplitude providing
enhanced near-wellbore action, while side and
bottom ports enable direct impingement on
perforations. Pulsonix TFA penetrates deep
into fractures to clean up gel, emulsions and
crosslinkers and enhances the placement and
effectiveness of treatment fluids.
SPE 164434
“Wellbore Asphaltene Cleanout Using a new
Solvent Formulation in a Horizontal Openhole
Oil Producer in Carbonate Reservoir of North
Ghawar Field -Scripting a Success Story,”
Alejandro Chacon, Alexys Jose Gonzalez and
Ernesto Bustamante, Halliburton; S. Murtaza,
A.A. Al-Ruwaily, A.A. Taqi, and S.S. Qahtani,
Saudi Aramco, presented at 18th Middle East
Oil & Gas Show and Conference (MEOS), Mar
10 - 13, 2013, Manama, Bahrain
In addition, the new generation solution:
• Stimulates high-permeability formations
Fig. 20. Pulsonix TFA pressure waves propagate
spherically from the tool and can remove many
types of near-wellbore damage through cyclic
loading.
• Treats perforation and wellbore with gravel
packing and frac packing
• Places fines consolidation chemicals
excellent for a wide variety of horizontal and
vertical wells, both open and cased hole.
• Facilitates gravel pack repair to remove
chemical and fines plugging
The wide range of fluid rates from 0.50 to 40
• Enhances conductivity
SPE 153779
Fig. 21. CoilCommSM FiberOptics.
/ 52
“Water Injector Matrix Acidizing: Evaluation
of Tools Deployed on Coiled Tubing Used for
Placement,” Rakesh Trehan and Norman Jones,
Halliburton; Vincent Meraz-Mata, Vintage
Production California, LLC, presented at
2012 SPE Western North American Regional
Meeting, March 19-23, Bakersfield, CA
SPE 163891
“Successful Case Histories for the Next
Generation 3D CFD-Derived Fluidic Oscillator,”
Robert Howard and Ismael Martinez, Boots
& Coots; Tim Hunter, Halliburton, presented
at 2013 SPE/ICoTA Coiled Tubing & Well
Intervention Conference & Exhibition, March
26-27, The Woodlands, TX
SPE 131551
“A Successful Application of Near-Wellbore
Stimulation using Fluidic-Oscillation Technique in
North Africa Oil Field,” K. Kritsanaphak, S. Tirichine, and M. Kammourieh, Halliburton,
presented at the 2010 CPS/SPE International Oil
& Gas Conference and Exhibition in China, June
8-10, Beijing, China
• Removes fill from open hole or casing
• Optimizes injection profiles
Multiconveyance Intervention, Video
Monitoring Solutions
Obviously, when production from a mature
well declines, it takes profits with it. As such,
the faster production sustaining intervention
can be deployed, the faster flow and revenue
can be restored. The stakes rise appreciably
in complex HPHT, mature and similarly
challenging wells where operators typically
use electric line to run an evaluation tool
with real-time data gathering capabilities.
After the data are evaluated, the operator may
choose to switch to slickline to quickly run
the necessary mechanical tools to improve
well performance. Accordingly, the most-effective and time-saving option is to have both
conveyance methods on-site and ready to run.
As the world’s premier slickline company,
as well as the developer of industry-leading
cased hole and perforating technologies,
Halliburton offers an entire line of conveyance-flexible tools that include industry-leading technologies for measurement, perforating
and intervention. In addition, Halliburton’s
sophisticated combo-unit delivers a truly
integrated suite of slickline and electric line
solutions that deliver the same high-quality
data in both real time and memory mode and
help operators improve process efficiency and
asset value. One of the key differentiators to
Halliburton’s e-line and slickline solutions is
rapid deployment to reduce NPT, intervention
costs and get production back on line as
quickly as possible.
Halliburton’s electric line and slickline
services enable a wide variety of integrated
project-critical services, ranging from logging
operations that can help operators make decisions about how to get the most out of each
well, to the maintenance services that actually
get the well to optimum performance. The
Fig. 23. The TMD-3DTM service provides complete
formation evaluation for porosity and gas
saturation in complex casing completions.
Fig. 22. With conveyance flexibility is an
important part of the Halliburton eline and
slickline service delivery. Virtually any service
can be provided on all conveyance methods.
e-line and slickline solutions, for instance,
accommodate Halliburton’s suite of formation
evaluation tools, which takes in a portfolio
of specialized evaluation tools, including the
TMD-3DTM tool, a 3-detector pulsed-neutron
Sigma service (Fig. 23) that delivers conventional 2-detector measurements as well as
advanced tight gas detection. The companion
RMT EliteTM tool provides industry-leading
carbon and oxygen (C/O) logging, oil saturation in unknown salinity waters, multiphase
saturation for flood monitoring, and shale gas
reservoir evaluation.
/ 53
Case StUDY:
Evaluation of corrosion in outer
casing strings done by XaminerTM
Electromagnetic Corrosion Tool (ECT)
Until recently, accurately evaluating corrosion in outer casing strings required
operators to pull tubing. Using new
technology, Halliburton verified corrosion through various casing strings in
hundreds of Middle Eastern well without
the need for workovers. A large Middle
Eastern operator with thousands of wells
is using Halliburton’s new Xaminer™
Electromagnetic Corrosion Tool (ECT) to
validate and prioritize the need for remedial operations. This will save the operator
millions of dollars by avoiding the need to
pull tubing in wells that may not yet need
intervention. With the help of this tool,
the operator has started a campaign to
monitor corrosion advance through well
productive life, and to program future well
interventions. The company credits ETC
with helping them operate more efficiently
and avoid potential environmental issues.
The e-line and slickline solutions also offer
Halliburton’s suite of reservoir evaluation and
monitoring tools that feature advanced pulsed
neutron logging tools to provide leading evaluation to enable the right economic decisions about the productive life of the well. / 54
The e-line and slickline tools available also
include:
including pressure, temperature, X-Y
caliper and inclinometer
• Cement and casing evaluation tools to
verify well integrity, which includes the multifinger caliper that provides the best
well-integrity services on a single trip,
saving rig time and delivering solutions
more efficiently.
• Correlation tools, encompassing gamma
ray, casing collar locator
• Production Logging Tools for vertical, deviated and horizontal well paths that offer
equipment for both memory and electric
line production logging.
• Flow-rate measurement comprising
continuous flowmeters, basket flowmeters,
fullbore flowmeters and spinner array tools
• Fluid identification and flow composition
for measuring gas holdup, capacitance
water holdup, radioactive fluid density,
differential pressure density, resistance
array and capacitance array
• Flow condition and well diagnostics,
Fig. 24. T op of wire and tool
To further reduce the personnel required, as well
as NPT and intervention costs, Halliburton’s
e-line and slickline solutions can be delivered
in an innovative combo configuration, fully
customized to allow operators to get the most
out of both technologies in a single unit. Combo
e-line-slickline units can be tailored for any
application or environmental condition.
Of course, knowing precisely what is occurring
downhole, in real time, during an intervention
to sustain production is critical. Halliburton’s
solutions include a full suite of downhole video
camera technologies, including the companion
Slickline Memory Camera that gives operators
an up-close look of what is taking place in
the well, as it is taking place. This advanced
imaging service literally allows operators to
Partially open crown
Fully closed crown valve
“see” borehole conditions as they develop to
fully understand what is going on downhole.
Validating these downhole conditions can help
expedite the best course of action, increasing
the likelihood of a successful intervention
while reducing your overall risks and associated
costs. Capable of taking 1,000 pictures per run,
the Slickline Memory Camera can be run on
slickline or coiled tubing, and being less than 2
feet (0.61 m) in length, makes it easily portable
and ideal for rig ups with height restrictions.
The Slickline Memory Camera is a viable
option for mechanical inspections, such
as parted tubing/corrosion/ obstructions/
restrictions, fishing operations, gas lift and
surface-controlled subsurface safety valve
(SCSSV) inspection , scale and organic buildup
survey, corrosion inspections and, particularly
in mature wells, identifying points of hydrocarbon entry in high water-cut wellbores.
Halliburton's Downhole Camera Services also
include the EyeDeal™ Camera System that
provides high-resolution images to eliminate
guesswork from a range of diagnostic test and
troubleshooting operations. Applications of the
EyeDeal Camera System include quality assurance inspection, gas entry, water entry, fishing
operations, casing and perforation inspection,
and general problem identification. When
attached to Halliburton’s Fiber-Optic system,
the EyeDeal camera offers a continuous-feed
image with excellent screen resolution in
depths of 14,000 ft. and pressures of 10,000 psi
and temperatures of 250°F.
Interventionless Solutions
Eliminating the need to intervene in a well
by removing the tree and running workover
tubing into it results in both lower costs and
increased safety when identifying and solving
downhole problems. Interventionless activities
generally take two forms—assessment of
well integrity and productive capacity and
installation of technical solutions to solve any
problems identified in either area.
Halliburton’s suite of wireline-run well
assessment technologies include cutting-edge
analytical tools, such as:
• Fast Circumferential Acoustic Scanning Tool
(FASTCASTTM Tool) is up to five times faster
than other third party tools and accurately delivers 100% circumferential coverage in casing sizes up to 20 in. diameter. High-resolution
cement and casing data are recorded
simultaneously to save even more time. The
flexible FASTCAST scanning tool allows
programmable shots per scan to provide the
best measurement solution to match the need.
• Halliburton’s new ECT can detect mechanical integrity issues through multiple casing
strings. It enables detection of corrosion in
outer casing without removing inner tubing
and can show where potential problems are
located both vertically and radially in the
well. The ECT can be used at regular intervals without pulling tubing. It’s now easy
to detect how much corrosion has reduced
the wall thickness of the second casing and
whether the third is affected, too. This helps
avoid needless work. The operator can now
understand the advance of corrosion in
each well and can precisely predict when
to perform workovers. This well integrity
monitoring plan enables them to budget
and schedule interventions to maximize the
efficiency and safety of a workover program.
• Reservoir management requires timely
information. We offer an understanding of
production dynamics to enable decisions
that optimize production and mitigate risk.
Halliburton's RMT Elite™ logging system is
crucial in estimating the reserves remaining
in a reservoir. It can also be useful in locating
missed pay zones. The RMT Elite™ logging
system accurately evaluates performance of
reservoirs over time without requiring that
tubing be pulled from wells. Despite its slim
design, this pulsed neutron logging system
achieves results and resolutions that previously were available only with large-diameter
carbon-oxygen (C/O) systems. The system’s
modular hardware gives operators flexibility
/ 55
to simultaneously measure CO, sigma and
water-flow.
Once problems have been identified in wells,
Halliburton next generation interventionless
capabilities allow the operator to introduce
solutions in a cost effective, safe and environmentally sound manner as illustrated in the
examples below.
• Very often, mature wells can be recompleted
with excellent results. One key to successful
recompletion is maximum perforation
penetration. The MaxForce® line of
super-deep penetrating charges is our latest
breakthrough. This combination means
unsurpassed production performance. The
deeper penetration of MaxForce charges:
- Increases productivity
- Penetrates past any near-wellbore damage
- Potentially intersects more natural fractures.
Charges are manufactured with the highest levels of quality assurance and are also
randomly tested to ensure consistent charge
performance and reliability.
Fig. 25. C
ement Inspection Up to Five Times Faster. The FASTCAST™ scanning tool system.
/ 56
• In all assets, and particularly in mature assets,
proppant flowback has been an issue for the
industry and can result in a significant loss
of fracture conductivity and lower overall
productivity in the well. Damaged equipment
and cleanout services add to the cost of
the well and lower the economic return.
Additionally, cleaning the wellbore does not
prevent recurrence of proppant flowback and
must be repeated several times. Being able to
halt or minimize proppant flowback can be
crucial in making a mature asset profitable.
Proppant flowback can damage equipment and
restrict hydrocarbon production and can require frequent workovers to clean the wellbore.
Halliburton’s PropStop® ABC service provides
proppant flowback control in a safer and easier
to use system.
• Provides cohesion between proppant grains
without damaging permeability or conductivity of proppant pack
• Helps maintain highly conductive fractures
and long-term productivity
• High-strength consolidation can be achieved
with small amounts of material
• Helps eliminate many health and safety
hazards
• High flash point makes system easier to
manage
• Easy cleanup, no special solvents required on
location for equipment cleaning
• Can be applied using bullheading or coiled
tubing
• Enables treating long intervals; foam acts as a
resin extender and is self-diverting.
Solution for Setting, Pulling Tools in
Power-Limited Situations
In remote locations, the setting or retrieving
of bridge plugs, monolocks, packers and other
downhole appliances often is hampered by
the limited availability or total lack of electrical power for downhole tools. Halliburton
resolved that issue with its electromechanical
DPU® Downhole Power Unit that provides an
alternative to jointed-pipe intervention to generate high setting force for setting or retrieving
downhole tools without the use of explosives.
A gear motor operates a linear drive to generate
gradual, controlled, axial compressive or tensile
force to optimize the setting of the slips and
sealing elements of monobore nippleless locks,
packers and bridge plugs. The DPU® Downhole
Power Unit operates at higher temperatures
and pressures than previous power-delivery
technologies—pressures and temperature up
to 30,000 psi and 400°F (204°C), respectively,
and delivers up to 100,000 lbf setting force—for
reliable operation in extreme downhole
conditions, such as, deep or high-temperature
environments. The DPU® Downhole Power
Unit tools also provide real-time monitoring,
display, and recording of the setting operation—the setting force, stroke length and the
rate at which forces are being applied—which
allows remotely based completion engineers to
monitor the plug/packer setting operations in
a collaborative environment where workflows
of model, measure, and optimize are used.
Eliminating the use of explosives helps improve
safety, logistics, and
reliability.
The DPU® Downhole
Power Unit is available
in both slickline and
electric line versions—
the slickline version
uses batteries to
provide the energy to
the motor and timing
circuits—and can be
run on third-party
e-lines, thus allowing
immediate deployment
to any rig, anywhere.
Cost-effective solution
for locating stuck
pipe depth
Fig. 26. Schematic of
Whether trying to free
the DPU®-I Downhole
differentially stuck pipe
Power Unit tool.
during infill drilling
or extracting salvageable tubulars during well
abandonment, isolating the exact depth at
which the pipe is stuck can be an expensive
/ 57
Case StUDY:
Downhole Power Unit saves $1.5
million in Gulf of Mexico
The DPU® Downhole Power Unit tool
was used in the Gulf of Mexico to set
a sump packer deeper than 30,980 ft
(>9445 m). The e-line rig-up/rig-down
time was 8 hr and 20 min, compared to
the more than 40 hrs that would be been
required for a jointed-pipe intervention. Consequently, the operator saved more
than one and a half days of rig time at
a spread cost of $1 million/day. These
improvements in operational efficiencies
netted the operator more than $1.5
million USD in savings.
SPE 123943
“New Family of Setting Tools for Ultra Deep and
High Temperature Well Conditions,” C. Kessler, J.
Hill, E. Shook, R. Housden, Halliburton; and E.V.
Collum, (Walter Oil & Gas), presented at the 2009
SPE Annual Technical Conference and Exhibition,
October 4-7 October, New Orleans, Louisiana
/ 58
SPE 125446
SPE 154421
“Plug Setting Aid Retooled for Up-Hole Down-Dip
Plug Back Application Enables Pin Point Slurry
Placement in Complex Up-Dip Wellbore,” H. Rogers,
D. Winslow and P. Boddy, Halliburton, presented
at the 2009 SPE/IADC Middle East Drilling
Technology Conference and Exhibition, October
26-28, Manama, Bahrain
“Slickline-Conveyed Eletromechanical Tool
Utilization in Deepwater Gulf of Mexico,”
B. Gary, Halliburton; J. Schlechtweg, Shell; J.
Clemens, Halliburton, and J. Garrett, Shell,
presented at the 2012 SPE.IcoTA Coiled
Tubing and Well Intervention Conference and
Exhibition, March27-28, The Woodlands, Texas
SPE 128123
“Case Histories of a New Family of Setting Tools for
Ultra Deep and High Temperature Well Conditions,”
C. Kessler, J. Hill, and R. Housden Halliburton,
presented at the 2010 North Africa Technical
Conference and Exhibition, February 14-17, Cairo,
Egypt
SPE 119907
“Case Histories of a New Wireline Logging Tool
for Determination of Free Point in Support
of Drilling and Pipe Recovery Operations,” C.
Kessler, D. Dorffer, D. Crawford, R. DeHart,
and J. Weiser, Halliburton, presented at the
2009 SPE/IADC Drilling Conference and
Exhibition, March 17-19, Amsterdam, The
Netherlands
SPE 143209
“Game-Changing Technology Developments for
Improving Operational Efficiencies in Deepwater
Well Completions,” C. Kessler, J. Hill, and T. Earl, Halliburton, presented at the 2011 Brasil
Offshore Conference and Exhibition, June 1417, Macaé, Brazil
OTC 20933
“Game Changing Technology Developments
for Safe and Cost Effective Determination of
Free Point in Horizontal and Vertical Wells”
C. Kessler, J. Hill, and J. Weiser, Halliburton,
presented at the 2010 Offshore Technology
Conference, May 3-6, Houston, Texas
and time consuming operation. Conventional
legacy freepoint methodologies typically rely
on numerous stationary strain measurements,
requiring the application of torque or pipe
stretching to try and determine the depth at
which the pipe became stuck.
Halliburton’s HFPT Free Point Indicator
free pipe/stuck pipe recovery service with
associated cutting solutions provides operators
cost-effective determination of freepoint to
expedite pipe recovery. With the Free Point
Indicator tool, two continuous logging passes
are made in a single trip to measure the change
in the magnetostrictive effects of the pipe,
thus providing precise freepoint location. The
down-logging pass records pipe magnetization
with the pipe in a neutral-weight condition; the
up-logging pass records magnetization after
tension or torque has been applied to the pipe
and released, allowing the pipe to return to the
neutral-weight condition.
While applying torque (tension) to the pipe
magnetostrictive properties change, in
sections of stuck pipe that are difficult, if
not impossible, to stretch or torque up, the
magnetization effects remain unchanged.
With the HFPT Free Point Indicator, changes
in the magnetic properties of the drillstring
or casing between the stuck and free pipe are
used to generate a continuous log that shows
the precise depth locations of the freepoint
and stuck points. In contrast to conventional
methods, requiring multiple station measurements with the pipe in tension or torqued, the
HFPT tool requires only a single application
of pipe stretch for a short time between
logging passes, reducing safety risks, NPT,
and operational costs.
The HFPT can be pumped down for
freepoint determination in high-angle or horizontal wells. Correlating the free pipe/stuck
pipe region of the log with other geological,
or petrophysical data can help determine
the root cause of pipe-sticking, such as, key
seating, differential sticking, shale stability,
or hole-cleaning issues. The HFPT tool can
be run in high-strength alloy drillpipe where
slip engagement with legacy tools is often difficult. Real-time operation and 24/7 satellite
communication readily permits the operator
and remotely based pipe-recovery experts
to fully participate in the wellsite plans for
freeing the pipe and the decision process.
Once the HFPT Free Point Indicator has
isolated the depth, or freepoint, of the stuck
pipe, before the operation can continue nearly
all recoveries require safe severing of the
tubulars. Sometimes workovers will require
cutting of tubing or casing to repair the well
integrity. The discussion below provides
some solutions to consider in doing this
work. Halliburton’s response is a wide range
of cost-effective technologies for recovering
stuck downhole tubulars, including jet cutters
in various sizes, lengths and temperature
ratings for a host of applications. The Split
Shot® cutter uses a linear shaped charge to
split tubing and casing collars vertically. The
Drill Collar Severing Tool, a tool of last resort,
uses an explosive collision device to create a
high-energy blast capable of shearing large,
heavyweight drillstrings.
Halliburton also offers alternative high-precision tools. Chemical cutters, available for
applications from coiled tubing to 8 5/8-in.
casing, use chemicals that, when mixed with
an oil/steel wool mixture, create a reaction
that builds pressure and temperature. This
opens the severing head, and the chemical
is expelled, cutting the tubing or casing and making the stuck pipe easier to retrieve.
In addition, unlike many cutting tools on the
market, plasma cutters, such as the MCR X
SPE 147859
“Middle East Case-Study Review of a New
Free-Pipe Log for Stuck-Pipe Determination and
Pipe-Recovery Techniques,” J. Torne (formerly
Halliburton); M. Rourke, B. Derouen, and C.
Kessler, Halliburton, presented at the 2011
Exhibition, September 20-22, Jakarta, Indonesia
/ 59
Radical Cutting Torch (XRT®), cut tubulars
without requiring hazardous and expensive
explosives. The Radial Cutting Torch System,
which ranges from 0.75 to 7 in. (1.9 to 18
cm) OD, is recognized as a highly versatile
pipe-recovery tool, delivering a smooth, nonflared cut that simplifies recovery of the
stuck pipe. The XRT relies on a proprietary
fuel to create a controlled thermal event that
generates plasma with very high temperature
and pressure. The 4.1 flammable solid-fuel
source keeps components radio safe. The proprietary, flammable solid active component of XRT tool allows the tool to be shipped
via commercial airline with delivery time
measured in hours rather than days.
Chemical and Mechanical Water
Management Solutions
The production of unwanted water can
restrict productive well life, while increasing
lifting costs and increasing environmental
issues. In fact, some calculations have upward
of $50 billion being spent annually dealing
with the estimated 220 million bbl/d of
unwanted water produced globally and the
associated problems, such as sand production,
scale and corrosion. The problem is compounded appreciably in mature fields where
approximately 9 barrels of water are produced
for every barrel of oil produced.
/ 60
Fig. 27. E xample of a freepoint log generated by the Halliburton Free Point Indicator Tool
Conformance
Halliburton’s all-inclusive Conformance technology portfolio offers specialized application
software and a variety of chemical treatments
that are applied to reservoirs and boreholes to
help reduce production of unwanted water and
efficiently enhance hydrocarbon recovery and
satisfy a broad range of reservoir management
and environmental objectives. In addition to
the chemical solutions, Halliburton also provides mechanical solutions to head off inflow of
unwanted fluids.
Just as a broad range of causes exist for excess
water production, the Halliburton conformance
package offers a broad variety of solutions
to help mitigate the problems, varying from
in-situ crosslinked water-based polymers, swelling/superabsorbent polymers, relative
permeability modifiers, to cement-type materials. Halliburton conformance solutions have
proved effective in vertical, highly deviated,
and horizontal wellbores, including challenging
completions such as gravel pack, slotted liners,
and openhole completions.
The Conformance portfolio includes field proven chemical technologies for water and
gas shutoff. The activation mechanisms are
divided into sealants, comprising nonselective
treatments and services that fully protect the
hydrocarbon zone, and relative permeability
modifiers, which encompass selective treatments/services and offer the potential for bullheading.
The wide variety of sealants include the
temperature-activated H2Zero® service, a
revolutionary porosity fill sealant that provides
unprecedented capabilities for controlling
unwanted fluid production. Based on an
organically crosslinked polymer that forms a
permanent seal at the formation matrix, the
pacesetting H2Zero® service remains stable in a
wide temperature range of 60° to 400ºF (16 to 204°C). The H2ZeroTM service has been
successfully applied to sandstone, carbonate,
and shale formations requiring a conformance
treatment, solving problems such as water
coning/cresting, high-permeability streaks,
gravel-pack isolation, fracture shutoff, and/
or casing-leak repair. This system has been
successfully tested to withstand a differential
pressure of at least 2,600 psi and is resistant
to acid, CO2, and H2S environments. The
capability of the H2Zero® service to withstand
pressure, workover operations have been
successfully performed in previously treated
wells, including acid stimulation, sand control,
and frac-pack treatments, among others.
When isolation of the water or gas zone is not
an option, the complementary BackStopSM
service, which is designed primarily for water
shutoff, allows the entire wellbore in the selected interval to be filled with the slurry
and squeezed. The BackStop service helps
control unwelcome water production by
introducing an exceptionally capable water
control agent at the shallow part of the
formation around perforation tunnels. Similar
to cement squeezes, BackStop service offers
additional advantages in that it can simply be
jetted out with coiled tubing and longer and
hotter intervals can be treated in one day.
Fig. 28. Common issues like coning and high
perm streaks can be addressed with
H2Zero® service.
/ 61
Used in tandem with the H2Zero® service,
after BackStop treatment is pumped and
squeezed its fluid-loss particles form a
diverting filter cake that uniformly places
the H2Zero polymer at a penetration less than
3 in. into the formation, where after setting
it creates shallow matrix water shutoff. The
(1)
(2)
Case STUDY:
Case STUDY:
Water Cut Slashed, Production
Increased in Older Oman Wells
BackStopSM, H2Zero® Restart Production
Service in High Water-Cut Zone
In the Middle East, an the operator’s
mature wells were sustaining water cut
higher than 96% and included zones with
high permeability contrast. Consequently,
acid diversion would be required during
the cleanup. Halliburton recommended
the Guidon AGS relative permeability
modifier, which effectively diverted the
acid to lower permeability zones. The
selected treatment of the Guidon AGS service eliminated the cleanup stage. After 20
older wells were stimulated, oil production
increased to 1,887 BOPD with 1½ year of
sustained oil production gain and a 1.5%
decrease in water production.
BackStop service also can be used in repairing
casing leaks and sealing off lost circulation zones.
(3)
(4)
Fig. 29. The BackStop service process. (1)
Some perforations produce hydrocarbon and
some produce water. (2) BackStop agent is
bullheaded across all perforations. (3) After
setting up, excess BackStop agent in the
wellbore is washed out. (4) New perforations
are created in non-water-producing zones.
/ 62
In some applications, it is preferable to treat
only the injection wells, and not the producers.
In those cases, the suite of nonselective sealant
solutions includes the CrystalSeal® water conformance control service that places a selected
swellable agent into a permeable zone in an
injection well, using an aqueous solution to swell
the agent. The CrystalSeal agent is a synthetic
polymer capable of absorbing 30 to 400 times its
water weight to seal off unwanted fluid. After 11 years of production, a dual-completed well in the Middle East encountered
96% water cut in lower zone. A production
logging tool (PLT) survey showed the two
middle perforated sections in the zone
produced most of the water and that water
cross flow between these two sections
occurred when the well was closed in.
Isolating the watered-out section in the top
of the lower zone mechanically was not
possible because of the dual completion.
In addition, the 4 ½-in liner prevented a workover to install a cemented completion
inside the existing perforated liner. The
problem interval was 610 ft (186 m) in
length with a bottomhole temperature of
298º F (148 °C). Halliburton applied its
BackStopSM service to achieve a shallow
penetration of the H2Zero agent in the
perforation tunnels. After the BackStop
slurry was bullheaded into the wellbore,
the well was shut in until the slurry set
up. The set-up BackStop agent was then
easily jetted out of the wellbore with coiled
tubing. Following the treatment, a PLT
survey indicated clearly that the squeezed
zone was not contributing to the water production. The zone was re-perforated and
production resumed, virtually water free.
simulator allows data to be interpreted with
unprecedented speed and accuracy. Processes
that once took days to complete now require
just a few hours. Using this state-of-the-art
approach, operators literally can predict the
economic outcome, clearing the way for faster,
smarter and more proactive decisions that can
maximize production and efficiency.
Within the suite of relative permeability
modifiers, one of the key selective treatment
solutions is the WaterWeb® service that uses
unique polymer chemistry to help create
oil-water separation in the reservoir, impeding water flow and enhancing hydrocarbon
flow to the wellbore. With the WaterWeb
service, the resulting improved oil/gas
recovery potential stems from a reduced water
column giving improved natural lift for the
residual oil and/or gas. In addition, it helps
justify prolonged and sustained production by
enhancing reservoir drainage.
The suite of selected treatments also include
the Guidon AGSSM service, a new generation
diverter technology that helps achieve
optimum results from acidizing treatments. Guidon AGS agent adsorbs to the rock where
it provides a highly-effective acid diversion
without gelling or setting up and reduces
permeability to acid with little effect on the
permeability to oil and gas.
Complementing the wide variety of chemical
solutions in the Halliburton Conformance
portfolio is the revolutionary QuikLook®
reservoir simulation service was developed to
optimize both the design and placement of
unwanted fluid shutoff treatments. The multiphase QuikLook software is an advanced 3-D,
four-component, nonisothermal numerical
reservoir simulator. The simulator helps
Mechanically Blocking Unwanted Fluid Inflow
and Enable Production Increase
Fig. 30. CrystalSeal® service treats the
injection wells rather than producing wells,
providing a farther-reaching effect with no
risk of damage to the producers. Available
only from Halliburton, the method entails
placing a swellable agent into a permeable
zone in an injection well and using an
aqueous solution to swell the agent.
design effective well treatments, including
fracturing, conformance and sand control and
is even designed to predict production from
complex wells and reservoirs.
As the only reservoir fluid management
service created specifically for conformance
applications in the oil industry, QuikLook
The migration of unwanted water or gas into
the wellbore of mature fields or a pressure
drop in the tubing can lead to restricted or
uneven production and increase completion costs. Halliburton’s response to this
profit-draining challenge is an engineered
component to the completion string that
reacts to the presence of water or gas in the
surrounding area.
The robust Swellpacker® isolation system
makes it the ideal option for the unique challenges of multizone completions, particularly
in mature wells. Compared to conventional
packer systems, Swellpacker systems provides
a simpler, safer and much more stable solution
for complete and long term zonal isolation.
Swellpacker systems demonstrate their capacity
to cut rig time and reduce costs, all the while
delivering absolute isolation of producing
zones. In some open hole completions,
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0.05
0.1
0.15
0.2
0.25
0.3
0.35
0.4
0.45
0.5
0.55
0.6
0.65
0.7
4000
4010
4020
4030
0
60
40
0
600
0
20
400
200
0
0
Time = 200 Days
Fig. 32. QuikLook® sofware gives both a 2D
and 3D representation of water distribution
inside the reservoir. Issues such as coning or
water channeling can be identified so action
can be taken.
Swellpacker systems may even eliminate
cementing and perforating altogether.
Well-suited to cased or open hole completions, Swellpacker systems is based on the
swelling properties of rubber in hydrocarbons
and/or water. With the ability to swell up to
Fig. 31. The QuikLook® Conformance Simulation Service was developed to optimize the design and
placement of unwanted fluid shutoff treatments. As the only reservoir fluid management service
created specifically for oil industry conformance applications, it allows data to be interpreted with
unprecedented speed and accuracy. Processes that once took days to complete now require just
a few hours. Using this revolutionary approach, you can literally predict the economic outcome,
permitting quicker, smarter, more proactive decisions that maximize production and efficiency.
/ 64
Fig. 33. Swellpacker Isolation System
of dynamic fluid flow, the AICD increases
flow resistance in the presence of water or
SPE 163086
Fig. 34. With Passive ICDs
“Application of ICD Technology for Improvement of
Well’s Productivity and Extension of the Oil Well’s
Life in Samaria Field,” J.H. Ramierez, Pemex; N.E. Saldierna, Halliburton; H.A. Mandujano, and
R.G. Altamirano, Pemex, presented at the 2011
SPE Western Venezuela Section South American
Oil and Gas Congress, October 18-21, Maracibo,
Venezuela
SPE 162471
Fig. 35. With EquiFlow Autonomous Inflow
Control Device (AICD)
200%, it effectively seals the annulus around
the pipe and achieves unprecedented zonal
isolation. Once deployed, the rubber retains
its flexibility, allowing the Swellpacker system
to adapt to shifts in the formation over time
and retain seal integrity.
Another device that controls unwanted
water is the EquiFlow® autonomous inflow
control device (AICD). Using the principals
“Optimization of Inflow Control Device Placement
and Mechanical Conformance Decisions Using a
New Coupled-Well-Intervention Simulator,”
K. Thornton, R. Jorquera, Halliburton; and M.Y.
Soliman, Texas Tech University, presented at
the 2012 Abu Dhabi International Petroleum
Exhibition and Conference, November 11-14, Abu
Dhabi, UAE
gas. Unlike passive inflow control devices
(ICD), the EquiFlow AICD chokes back the
production of unwanted fluid, be it water or
gas, without the need for electrical, hydraulic,
or mechanical intervention. Consequently, the
EquiFlow AICD stimulates and fully controls
production without any moving parts,
intervention from the surface, additional
installation time, or a reduction of internal
pipe diameter.
The EquiFlow® AICD is easy to install and
extremely effective when combined with
zonal isolation systems, such as Halliburton’s
Swellpacker® isolation systems. Installed as
a unit at the end of each screen joint, the
EquiFlow® AICD can be configured for a
specific reservoir, yet it is simple, robust, and
easily combined with all types of sand control screens.
Controlling Formation Sand to Maximize
Production
PropStop® ABC service creates a high-strength
consolidated pack using a small amount of
consolidating material. The reduced material
volume required, as well as its capacity to be
foamed, makes PropStop ABC service more
economical than conventional resin-based
treatments. Since foam is self-diverting,
longer intervals can be treated using a simple
bullheading process, though it also can be
deployed with coiled tubing with enhanced
placement using the Pulsonix® TF tuned
frequency aptitude process, designed around
proven fluidic oscillator technology. The
foamed fluid also increases capillary forces
and provides improved strength development
in a proppant pack.
Over time, the flowback of formation sand and
proppant, especially in poorly consolidated
formations, can severely restrict production
and, in extreme cases, even cause wellbore
/ 65
failure. In addition, the solids build-up can
damage downhole equipment and lead to
costly and frequent cleanup interventions.
Recognizing that an ideal solution is consolidating the near-wellbore region or the
propped fracture by injecting a curable resin
to stabilize the loose material, Halliburton
developed the SandTrap® ABC formation
consolidation service. SandTrap ABC service
enables cost-effective through-tubing
Fig. 36. Proppant flowback control is often necessary to restore production in mature assets. Note
in this photo the eroded tubulars and proppant
on the ground. PropStop® ABC service helps
maximize value while reducing safety hazards
/ 66
conveyance of resin consolidation to help
operators access bypassed reserves and extend
field life. The unique service has been applied
effectively to recomplete sand-producing
intervals or complete untapped pay zones in
existing wells and can be placed with either
through-tubing, coiled tubing or with jointed
tubing and a service packer.
SandTrap ABC service offers operational simplicity with brine and solvent pre-flush stages, a
two-component consolidation fluid and finally
a brine post-flush. The service also relies on
low-viscosity fluids that allow for comparatively
more effective placement into reservoirs with
variable permeability and provides superb
consolidation sands with clay mineral content.
The post-flush displaces the consolidation fluid
to retain pay sand permeability. For wells with
failed gravel packs, SandTrap ABC service can
be used to consolidate the existing gravel pack
and reservoirs and in the problem area to put a
shut-in well back on line.
This new system incorporates a solvent/resin
mixture with novel unique properties that cause
the resin to be deposited as a thin film on the formation and clay surfaces. As the resin is internally
catalyzed, no post-flush treatments are required
to initiate the curing process. Two preflush stages
prepare the formation sand for a high-strength
consolidation and improved permeability
retention. The brine preflush allows the mineral
Case STUDY:
PropStop® ABC Service Achieves
Complete Zone Coverage in Permian
Basin Well
PropStop® ABC service was used as a
preemptive step to avoid production
problems associated with proppant flow
back on a Permian Basin oil well. This was
a challenging well with 25 perforations
spaced over a gross interval of 279 ft. Small
preflush stages commingled with nitrogen
were used to displace the oil from the near
wellbore and to condition the proppant
surfaces for the PropStop ABC service
treatment. The coiled tubing, with the
Pulsonix® TF service, was cycled over the
perforated interval for each of these stages
for enhanced placement. The well was
shut-in long enough for the consolidation
system to cure and afterwards was completed and put on production. Since this
treatment, the well has been producing at
500 BOPD with no proppant production.
surfaces to attract the consolidation fluid so that
a thin, uniform coating of consolidation fluid
coats the formation matrix grains. Connate water
is displaced from the pore spaces to improve
penetration of the treatment into the pores and
subsequent displacement by the post-flush to enhance consolidation strength and permeability
retention.
SPE-69619
Daniel L. Patterson (Halliburton Energy Services,
Inc.), Ian D. Taggart (Shell UK Exploration and
Production), Harald W. Breivik (Statoil Norway),
Gordon Scott (Halliburton Energy Services,
Inc.), Randy Simonds (Halliburton Energy
Services, Inc.), and Rod Falconer (Halliburton
Energy Services, Inc.), Interventionless Production
Packer Setting Technique Reduces Completion
Costs, SPE-69619-MS, SPE Latin American and
25-28 March, Buenos Aires, Argentina, 2001
Case StUDY:
Tagging Proppant Verifies PropStop
ABC Effectiveness
A major operator tested the PropStop
ABC system in a land-based USA
well. To determine the effectiveness
in controlling proppant flowback, the
operator performed a fracture stimulation
treatment using 16/30-mesh sand with a
low-viscosity fracturing fluid, and took no
measures to prevent proppant flowback.
After a few days of controlled flow the
operator tagged proppant built up in the
wellbore. The operator (1) cleaned out the
wellbore, (2) performed a consolidation
treatment using the PropStop ABC
system, (3) turned the well to production
and (4) after several weeks of production,
performed another tag to verify that no
additional proppant or formation material
had been produced. The well is producing
as well as or better than offset wells, has
not seen any additional buildup of solids
in the wellbore, and has flowed back no
measurable amount of proppant.
SPE-137857
Graham William Robb, Ewan Robb and Peter
Inglis (Halliburton), Enhancements To Remotely
Operated Downhole Fluid-Loss Devices Enables
Reliable Operation in Debris Laden Conditions, SPE-137857-MS, SPE Deepwater Drilling
and Completions Conference, 5-6 October,
Galveston, Texas, USA, 2010
SPE-71679
Vimal V. Shah and Neal G. Skinner
(Halliburton Energy Services), A Simple
Acoustic Wave Propagation Model for
Interventionless Well Completions, SPE-71679MS, SPE Annual Technical Conference and
Exhibition, 30 September-3 October, New
Orleans, Louisiana, 2001
SPE-81491
F. Duke Giusti (Halliburton Worldwide,
Ltd.) and Pierre Leschi (TotalFinaElf E&P
Qatar), Innovative Completion Technology
and Contingency Planning Simplify Al-Khalij
Completions and Reduce Installation Costs, SPE-81491-MS, Middle East Oil Show, 9-12
June, Bahrain, 2003
Fig. 37. Mature sand control completions
benefit from using SandTrap ABC
/ 67
Fracturing in Mature Fields
In mature and low-permeability reservoirs,
such as those encountered in unconventional
wells, growing the fracture network and complexity is critical in increasing hydrocarbon
recoveries. Here, enhancing the proppant
distribution is essential to improving access
to a larger area of the reservoir and, in turn,
maximizing drainage and asset value. The
challenge is particularly pronounced in
unconventional plays, which typically reach
their hydrocarbon peak and quickly decline,
hastening the time that they can be labeled
mature assets. Thus, extending their mature
productive life and ultimate recovery is
paramount.
Halliburton’s solution is the multifaceted
AccessFrac ® stimulation service which
delivers unique diversion technologies to
improve proppant distribution, provide deep
reservoir diversion and refrac and revitalize
underperforming wells. It can be integrated
with Pinnacle's optimized hydraulic fracturing and hybrid diagnostic technologies,
to specifically reverse declining production
from unconventional and conventional wells,
taking recovery to the next level. The production enhancement solutions also include
innovative proppant flowback control to
enhance conductivity and to prevent damage
to electrical submersible pumps (ESP) that are
/ 68
part of the artificial-lift completion, this maximized production and minimizes well shut in
time. AccessFrac® CF deep reservoir diversion
service can be incorporated in the stimulation
of infill or pad wells to optimize uniquely
stimulated reservoir area on each well and
to prevent unwanted interference. For refrac
treatments, AccessFrac® RF service can help
you to take control of the wellbore and to
“fill in the gaps" in the fracture network and
immediately increase production and provide
incremental reserves. The advanced diversion
materials used are the industry’s first chemical
OTC 20970
“Development and Field Applications of an
Aqueous-Based Consolidation System for
Remediation of Solids Production,”
Philip Nguyen, Richard Rickman, and Ron
Dusterhoft, Halliburton; Josue Villesca, Gary
Hurst, and Peter Bern, BP, presented at 2010
Offshore Technology Conference, May 3-6,
Houston, TX
SPE 165174
“Effectively Controlling Proppant Flowback to
Maximize Well Production: Lessons Learned from
Argentina,” P.D. Nguyen, J.C. Bonapace, and
G.F. Kruse, Halliburton; L. Solis and D. Daparo,
CAPSA, presented at 2013 SPE European
Formation Damage Conference and Exhibition,
June 5-7, Noordwijk, The Netherlands
diverters with a diverse particle size that are
temporary, self-removing, biodegradable and
SPE 163880
“Successful Application of Aqueous-Based
Formation Consolidation Treatment Introduced
to the North Sea,” R. Bhasker, A.F. Foo-Karna,
Halliburton and I. Foo, Shell,” presented at 2013
SPE/ICoTA Coiled Tubing & Well Intervention
Conference & Exhibition, March 26-27, The
Woodlands, TX
SPE 128025
“Development and Field Applications of an
Aqueous-Based Consolidation System for
Proppant Remedial Treatments,” P.D. Nguyen,
R.D. Rickman, and R.G. Dusterhoft, Halliburton;
J. Villesca, S. Loboguerrero, J. Gracia, and
A. Hansford, BP, presented at 2010 SPE
International Symposium and Exhibition on
Formation Damage Control, Feb. 10—12,
Lafayette, LA
SPE 151002
“Foaming Aqueous-Based Curable Treatment
Fluids Enhances Placement and Consolidation
Performance,” P.D. Nguyen and R.D. Rickman,
Halliburton, presented at 2012 SPE International
Symposium and Exhibition on Formation
Damage Control, Feb. 15-17, Lafayette, LA
capable of withstanding the rigors of fracturing. BioVert® NWB (Near Well Bore) diverting
can effectively bridge at perforations or in the
near-wellbore region of initially stimulated
clusters or openhole intervals. BioVert® CF material is carried deep into the fracture
network where at the tip it provides far-field
diversion to redirect the stimulation energy to
achieve complex fracture development (CF).
Optimizing Down-Spaced Infill Well
Completions to Prevent "Frac Hits" and
Well Interference
Owing to the unprecedented speed of development, many of today’s unconventional resource
plays have already matured and moved into the
longer term developmental drilling and completion strategies. With their ultralow permeability and the short drainage radius of a given
fracture, the reservoirs require more closely
spaced wells to properly drain the reservoir
and boost production rates and incremental
recoveries of hydrocarbons, consequently, infill
drilling, particularly focused on down spacing, has become the most widely used method to
accomplish proper drainage and enhance the
recovery of a field. Aptly designated, down-spacing involves
decreasing the space between wells laterally
to optimize overall economics in terms of
increasing the present value of estimated
future oil and gas revenues while balancing
Fig. 38. The deep reservoir diversion material of AccessFrac CF agent temporarily blocks portions of the
newly created fracture network, thus forcing the fracture to proceed in a direction perpendicular or offset
to the preferential dominate frac direction to create a larger matrix of uniquely stimulated reservoir area.
capital expenditures. In some plays, like the
Eagle Ford shale, operators in their multiwell
pad drilling programs have decreased
downspacing from 160 to 40−60 acres. While
this infill drilling methodology reduces costs
and improves efficiencies, it also comes with
daunting challenges, not the least of which is
well interference. Well-to-well interference,
for instance, can occur when a new infill well
is drilled between two existing wells, thereby
intercepting hydrocarbons flowing toward
those wells and reducing their productivity
and estimated ultimate recoveries (EUR).
One recent engineering study concluded that
/ 69
Fig. 39. As illustrated in a multiwell Haynesville Shale production study
detailed in SPE 167182, AccessFrac CF has helped increase cumulative
production of offset wells.
per-well EUR in the Bakken Shale decreased
in proportion to increased well count, suggesting various levels of interference.
To address the distinct production sustainability
issues with closely spaced wells, Halliburton
developed the AccessFrac® CF deep reservoir
diversion service, which can help mitigate well
interference and provides more optimal fracture networks on infill wells. As a key service
within the innovative AccessFrac family of
diversion technology, AccessFrac CF service is
/ 70
Fig 40. Wells were completed on the same pad offset to a producing parent well. One well used the AccessFrac CF deep reservoir diversion service to prevent a “frac hit” and reduce the chances of well interference.
designed to increase uniquely stimulated areas
of the reservoir and optimize fracture growth in
infill drilling applications. The proprietary deep
reservoir BioVert® CF diverter, is designed to
enhance the development of complex fracture
networks to minimize growth into identified
frac hazards and immediately increase offset
well initial production and help improve
ultimate hydrocarbon recovery. With closely spaced wells, it can become
difficult to get effective stimulation around each
of the later, and equally closely spaced, offset
infill wells. Consequently, during the stimulation
of offset wells the fracture network can preferentially grow in the direction of the partially
drained networks of the originally completed
wells. The so-called “frac hits” come into play
when a well is stimulated in close proximity to
a producing well and the stimulation treatment
reaches or fracs into the producing well, which
usually is shut in prior to the treatment.
AccessFrac® CF agent is designed to stop the
dominate fracture from growing into the
lowered stress environment attributed to the
stimulation and production of the nearby offset
producing wells. The AccessFrac® CF deep
Fig. 41. Artist rendering of an original
horizontal well fracture stimulated creating
a “complex fracture network at each access
point. It is not unusual for the access points to
be 250 to 400 ft apart.
Case STUDY:
Multiwell Haynesville Study Shows AccessFrac® CF Service Elevating Production
A production analysis was performed on a set of wells for one operator in the Haynesville
Shale to demonstrate the impact that deep reservoir diversion can have on increasing offset
well production. The focus group comprised 13 wells stimulated using a deep reservoir diversion material and their production was compared with 54 offset wells across two counties in
East Texas. All of the wells in this analysis were horizontal completions performed between
2009 and 2012. The 8-month cumulative production figures were normalized to proppant
per lateral/ft and averaged for the AccessFrac CF service group and the standard design
group. For further analysis, subsequent wells on a lease were compared directly to quantify
the effects of an already producing parent well nearby—each group representing all the offset
wells within a two-mile radius of a deep reservoir diversion material well. In most cases, the
longest producing well in a given group was also a top performer in terms of gas rate. This
performance behavior is consistent with other parts of the Haynesville shale and suggests as
mentioned above that these early drilled wells benefitted by producing from undisturbed rock
in the early portion of their life. In this group of infill wells below, all had similar completion
dates and were in close proximity to the same parent well. The average production from the
wells incorporating the deep reservoir diversion material into their sand stages was better
than the production from the wells completed with a standard frac design (Fig. 39 and 43).
Case STUDY:
Fig. 42. Artist rendering of the same horizontal
well after it was refraced. The original
complex fracture network is supplemented as
an additional fracture network has developed
from the existing network and NWB conductivity restored. Additionally, new perforation
clusters were added in between the existing
access points to create additional gateways
to the stranded hydrocarbons still in place.
Increased Fracture Complexity Provides Improved Production From Shale Plays
Seventeen operators in seven different formations have used AccessFrac® CF service in
more than 70 multistage wells. These wells have achieved important improvements in
production compared to conventional approaches.
/ 71
reservoir or far field diverter heads off unwanted
fracture growth in one of two methods.
The first approach is to add the deep reservoir
diversion material directly to the sand stages
and attempt to temporarily block portions of the
newly created fracture network, thus forcing the
fracture to proceed in a direction different from
the one already established while also providing
conductivity to those plugged portions since the
diverter is inert and fully degradable with time
and temperature.
A second approach is to add the deep reservoir
diversion material very early in the sand ramp.
This approach can stop a dominate fracture from
forming and extending significantly in the initial
preferential direction of the lower stress of nearby
fracture networks. As such, the deep reservoir
diversion materials provide a temporary blockage
against loss of frac energy and allows it to be redirected to other parts of the reservoir, ultimately creating more complexity, higher production, reduced screen-out risk and improved EUR
for subsequent or infill wells being completed
near previously stimulated, produced wells.
Tailored Re-Frac Solution to Revitalize
Under Performing Wells and Increase
Production
Rapid advancements in horizontal drilling
and multistage fracturing designs have played
a major role in the development of / 72
Case STUDY:
AccessFrac® CF Service Prevents "Frac Hit" and Optimizes Fracture Network Growth
One operator in the Eagle Ford shale had problems previously with offset wells fracing into
nearby producing wells and disturbing production. A four- well pad of new infill wells was to
be completed and all were in close proximity to a long standing producing parent well. The
operator wanted a stimulation design to field trial that hopefully would prevent well interference and possibly reduce the chances of a "frac hit" on the parent well. An AccessFrac
deep reservoir diversion service was applied was applied to the completion design. Its deep
reservoir diversion material can help divert the fracturing energy away from the initial direction of dominate growth, increasing the chance of new areas of the reservoir being
accessed. The deep reservoir diverting material was strategically comingled into portions of
the sand laden fluid stages of the pumping schedule to prevent a dominate fracture growth
into the existing already produced fracture network of the parent well. Ideally this diversion
produces a more complex dense fracture network near the new well being stimulated and
reduces the chance of damaging the producing well nearby. For diagnosing success of the AccessFrac CF treatment, the parent well was equipped with a
pressure monitoring device to determine if a "frac hit" occurs during stimulation of the new
pad wells. The pressure responses indicated that there was no communication during the
stimulation of the multistage well that incorporated AccessFrac CF treatment. However, on
the other offset wells on the same pad that were completed with a standard design, and whose
laterals were further from the parent wells than the AccessFrac CF treated lateral, some level
of interference with the parent well was observed. Additionally, a net pressure analysis was
conducted comparing a sample of the AccessFrac CF well to a sample from the offset wells
using a standard design. The results are illustrated below and demonstrate a more contained,
higher net pressure on the AccessFrac CF treated wells, indicating more ideal fracture geometry was created (Fig. 40). Based on the initial observations it appears a "frac hit" was
avoided by incorporating AccessFrac CF treatment into the completion. With future production history, evidence should emerge to validate the expectation that a higher recovery factor will be present in well with deep reservoir diversion.
It is well documented that both immediate
flow rates and EUR can decline as a result of
“gaps” in the fracture network along the lateral,
meaning that thousands of existing wellbores
in these plays have vast untapped hybrocarbon
reserves in existing perforation clusters that did
not receive effective stimulation. These unproduced or bypassed portions of the reservoir may
be exaggerated further in many wells completed
early in a plays development due to being
understimulated when compared to the more
AccessFrac
450
First (Best 6-mo/Lateral Length)
In addition, logging and shale evaluation studies are showing that there can be significant
variances in rock properties along a horizontal
wellbore or even within an isolated stage in
many of these plays. Low observed cluster
efficiency often leaves areas of the reservoir
ineffectively stimulated with most diagnostic
studies showing an average of only 50 to 60%
of the clusters significantly contributing to
production. Another analysis showed that 80%
of North American shale production comes
from about 20% of the frac stages.
500
Conventional
400
350
AccessFrac average 278.5
300
250
Conventional average 186.3
200
150
100
50
0
1
2
3
4
5
Fig. 43. Haynesville Shale - Cumulative production from wells completed with AccessFrac CF service
compared to wells within a 2-mile radius completed conventionally.
40
35
Sum (9 mo Norm BOE)
unconventional oil and gas fields. In recent
years, production and fracturing design
correlations, production history matching and
advancements in unconventional modeling
have have made dramatic progression along the
learning curve in designing ultra-efficient well
construction, completions and optimizing wellbore construction and stimulation techniques.
AccessFrac
Conventional
30
25
AccessFrac average 278.5
20
15
Conventional average 10.8
10
5
0
Fig. 44. Bakken Formation - Wells fractured using AccessFrac CF service achieve better average
production than wells fractured using conventional approaches.
/ 73
Case STUDY:
AccessFrac® PD Service Helps Avert
Loss of Well and Cuts Completion Time
by More Than 50%
When the 4000 ft lateral cased section of
a well in Eagle Ford shale was deformed
due to tectonic movement, the operator
was unable to run isolation plugs. Unless a
new completion technique was successful,
the operator would probably have to
plug and abandon the well. Halliburton
recommended AccessFrac PD service to
provide isolation between the perf clusters
treated with individual fracturing stages.
During the course of 21 hours of continuous
pumping, 13 frac stages were placed
along the lateral, treating a total of 780
perforations. Plug-setting and drillout time
was eliminated, resulting in cost savings of
approximately $75,000 and the reduction
of completion time to 50% of the time
required by a perf-and-plug procedure.
Pinnacle’s microseismic fracture mapping
shown in (Fig. 46) provided evidence that
effective diversion took place and the well
came on line with an initial production
(IP) equivalent to offset well production.
recent stimulation techniques and perforating
designs.
Because of their unique attributes and based
on radioactive tracer studies, microseismic
/ 74
Fig. 45. Thirteen treatments pumped continuously separated by BioVert® NWB diversion
spacers for isolation.
using only the existing perforations, is yielding
up to 50 to 60% of the original production, this
can be explained by poor cluster efficiency and
stress differences causing varying breakdown
pressures and poor fracture initiation across
the isolated intervals during the initial frac
operations. The success or failure of refracturing
can have large economic and asset implications
for field development and thus are appealing
because treatments involve reusing the existing
wellbore, potentially providing a cost savings of
$2 to 4 million in some North American wells
compared to drilling a new well.
As part of an Integrated Re-Fracturing Solution,
Halliburton developed the AccessFrac® RF
customizable stimulation and diversion design
service. AccessFrac RF service is designed to
Fig. 46. Pinnacles microseismic fracture mapping shows effective diversion taking place
along the wellbore during the treatment.
mapping, fiber optics, tiltmeter, production
logging, and field experience, it appears that
most unconventional multistage horizontal wells
are potential restimulation candidates at some
point in their life, particularly those completed
early in a plays development that are deemed
under-stimulated. In some basins refracing,
Fig. 47. BioVert® NWB’s diverse particle size
provides an effective seal at perforations and
in the NWB region.
Fig. 49. AccessFrac service can be used
to achieve diversion within the fracture
network to create additional fractures and
connect with natural fractures. This results in
increased stimulated reservoir volume.
Fig. 48. AccessFrac service can eliminate the
need for isolation plugs between stages. This
means fewer perforating runs and fewer plugs
to set and drill out. In addition, the AccessFrac
diverter system can help assure all zones
are treated.
“take control of the wellbore” and economically
revitalize underperforming wells. The
advanced refracturing stimulation technique
is aimed at optimizing perforation coverage by
providing prime diversion to breakdown new
or untreated perforation clusters, stimulating
new areas of the reservoir and restoring lost
near wellbore conductivity to existing fractures.
With AccessFrac RF service, Halliburton
combines advanced pumping capabilities
combining biodegradable diversion technology, tailored pumping schedules
and optimized reperforating schemes, can
provide an economical and efficient solution
to stimulate existing ineffectively stimulated
perforation clusters and to breakdown
the newly added clusters to improve the
fracture coverage of the reservoir providing
production uplifts and incremental reserves. It also allows the later use of newly optimized
solutions to the older wellbore.
Integrating Enabling Technologies for
Optimized Fracturing Solution
with tailored pumping schedules to consistently and flexibly deliver effective diverter
concentration and mass to the treatment
interval, while minimizing over-displacement
of previously stimulated clusters. Halliburton’s
on-site technical professionals provide real-time diversion and fracture analysis to-aid
in on-the-fly- decision making with an aim of
optimizing the comprehensive AccessFrac RF
service completion and providing maximum
learning’s for future tailored refacs.
The key to developing innovative fracturing
designs to increase and sustain near-term
production and delay production decline is
the seamless application of technical solutions
to meet the unique demands. The AccessFrac
CF and AccessFrac RF services, as well as the AccessFrac PD service designed to improve
proppant distribution in multizone completions, includes a host of enabling AccessFrac
service technologies applied in an integrated
production-enhancing solution, including:
In addition, the existing wellbores and original completion usually have sufficient
space available to add new perforations between existing access points to gain entry
into potentially untapped portions of the
reservoir. The integrated refracturing design,
• Degradable Diverter System: AccessFrac
service can be applied with a proprietary
biodegradable diverting material in the
near-wellbore region and, when appropriate, within the formation. The material is
the first degradable chemical diverter that
can withstand the rigors of fracturing. The
/ 75
Case STUDY:
AccessFrac® RF Treament Uplifts
Production and Adds Incremental
Reserves
A horizontal Barnett Shale well located in
Wise County, TX was originally stimulated
and brought online in 2004 but by 2010
the production had started to decline. The
operator worked with Halliburton to design
and perform an AccessFrac RF treatment
in October 2010 to attempt to re-establish
conductivity within existing fracture networks
and to add additional access points to the
reservoir. The well had an 1800-ft cased lateral
section and the original perforated interval
spanned roughly 1000-ft of it. The refrac treatment consisted of two stages and optimized
re-perforating with the first stage adding 70%
more perforations across the original interval
and a second stage was performed which
placed 6 new perforation clusters over a unique
300ft previously unstimulated portion of the
lateral. The two stage refrac incorporated a
new stimulation design and placed the same
amount of proppant as the original treatment
but used 46% less fluid. The additional
treatment and redesign was a success providing
a substantial uplift to production with the
post-refrac initial production (IP) being 55% of
the original IP and held well above the original
predicted curve, indicating additional reserves
were accessed. A production history match was
done recently, nearly 4 years after the refrac to
quantify the effect on the estimated ultimate
recovery (EUR) (Fig. 50).
/ 76
Fig. 50. The production rate history match shows a 73% increase to the EUR over the original completion’s estimates. That means +1.07 Bcf in incremental reserves over the producible life of the well, estimated at 30 years.
diverter can be used to create a temporary
blockage that will degrade entirely with
time requiring no special solvents or
additional surface operations. As the new
BioVert® diverting material, often used
in conjunction with AccessFrac service,
has very low HSE hazard ratings, it adds
another layer of environmental protection
for wellsite operations.
• SandWedge® ABC Conductivity
Enhancer: AccessFrac service also can
include SandWedge ABC enhancer to help
achieve and sustain a more conductive
proppant pack. Coating the proppant with
the SandWedge ABC enhancer also is
instrumental in placing proppant pillars to
achieve infinite conductivity in certain formations.
• RockPermSM Service: The RockPermSM
service is a process to select the optimum
surfactant package for a stimulation treatment by evaluating reservoir characteristics
and stimulation fluid components. Specific
focus is placed on minimizing adsorption,
Case STUDY:
AccessFrac® RF Treatment Provides Fast Payout in Haynesville Shale
The candidate well was located in Northwest Louisiana with a ~2,600 ft lateral
targeting the Haynesville formation, and originally completed by Halliburton in
2009 during the early emergence of the play. At that time, operators were actively
experimenting with different stimulation and wellbore construction designs.
Recently, the operator used Halliburton’s AccessFrac RF service to provide
near-wellbore diversion with Halliburton’s unique BioVert® NWB self-degrading,
diverse particle size diverting agent. Its unique design allows for the product
to divert the fracture treatment by bridging off and sealing the near wellbore
area behind the perforations. The original completion consisted of nine stages
conventionally isolated using the traditional perf-and-plug method. This early
completion design showed significant variance from what the operator’s current
treatment resembled, and thus in several aspects the well was deemed to have
been under-stimulated by the operator; both in treatment volumes and cluster
spacing. Prior to completing the AccessFrac RF treatment, 68% more clusters
were added in between the existing stimulated clusters. The refrac completion
consisted of 14 proppant treatments, which were separated by tailored diverter
stages utilizing BioVert NWB agent. The total treatment pumping time was
nearly 28 hours and more than 1.9 million pounds of proppant was successfully
placed (Fig. 51). Halliburton’s Tech Team and on-site Technical Professionals aided in pre-job
planning, real-time diversion and fracture analysis, on-the-fly decision making
and post job analysis to maximize leanings for future refracs. In fact wisdom
collected from prior applications of AccesFrac diverter technology for this
operator on new completions in the play was applied to customize the design and
execution of the refrac treatment. Although, no microseismic or other diagnostic
fracture monitoring was performed, several positive pressure responses were
observed, indicating adequate diversion was occurring. The well’s post refrac IP
was over 60% of the original IP, and is expected to provide a payout period of less
than nine months. Fig. 51. Haynesville Shale AccessFrac® RF service with 68% more
clusters added and 14 proppant-laden stages placing a total of
1.9 million pounds of proppant.
reducing interfacial tension, alter contact angles, increase
understanding of wetting surfaces, and break oil/water
emulsions. These are all attributes necessary to increase
the hydrocarbon production of an asset. It uses laboratory
testing process performed by specially trained technicians
in local area labs. The process selects optimized OilPermTM
Fluid Mobility Modifiers (FMMs) which maximize water
recovery and hydrocarbon production from fracture
stimulated shale reservoirs using Halliburton’s suite of
unconventional-focused technologies including wetting
agents, demulsifiers, solvents and complementary surfactant
mixtures integrated into the reservoir-tailored treatment
fluid formulation. RockPerm service provides a large benefit
in terms of improved fracturing fluid recovery and hydrocarbon fluids production from your reservoirs.
The RockPerm service relies on a natural selection approach
/ 77
Fig. 54. AccessFrac® diversion service technology can
help increase conductive
fracture volume, ensure
all perforations receive
fracturing energy and
create enhanced fracture
complexity and conductivity
for improved hydrocarbon
recovery and long-term
production.
Fig. 52. Conductor® Fracturing Service provides high frequency pulsed proppant
stages to place proppant deeper in the fracture and create infinite conductivity
flow paths. It uses a proven proprietary conductivity enhancing coating agent
that anchors the proppant grains together within the high-density pulses. This
provides more stable conduits around the unique consolidations of the high-density proppant pulses or "pillars" that will hold up better over time. This results
in impoved flow chanels and also enhanced fracture conductivity from the
consolidated pillars. This leads to an environment in the fracture that is resistant
to damage mechanisms and can sustain long-term hydrocarbon influx and flow.
and provides outputs to recommend the optimum surfactant chemistry on a well-by-well basis. The designed testing takes into account
reservoir characteristics and stimulation fluid designs, allowing the
RockPerm Service to deliver the ideal surfactant for each well. The
following methods are used during the evaluation process.
- Water analysis
- Emulsion testing
- Column flow testing
- Compatibility testing
- XRD analysis
• Conductor® Fracturing Service: This proppant pillar fracturing service is
designed to provide infinite acting conductivity for improved production
from liquids producing reservoirs. Proppant is deposited in random pillars
within the fracture using pulsing technology. On-the-fly coating with
SandWedge® enhancer makes the proppantsticky, thus consolidating the
pillars to help maintain
high fracture conducSPE 167182
tivity during the wells
“Hydrocarbon Recovery Boosted by Enhanced
production lifetime.
Fig. 53. Conductor treatment plot showing high frequency pulsed proppant stages and the
incorporation of an AccessFrac PD intra-stage diversion to improve cluster efficiency.
/ 78
Fracturing Technique,” Dave Allison, Jason Bryant,
and Jeremy Butler, Halliburton, presented at SPE
Unconventional Resources Conference-Canada,
Nov. 5–7, Calgary, Alberta, Canada
New Generation Microseismic and
Diagnostic Monitoring Solutions
As fractures propagate during stimulation
pumping stages, microseismic fracture
mapping provides an image of the fractures by
detecting microseisms or micro-earthquakes
triggered by shear slippage on bedding
planes or natural fractures adjacent to the
hydraulic fracture. Pinnacle, the global leader
in mapped fracture treatments, delivers the
maximum amount of both the numbers of
microseismic receivers that can be used and
in the sampling rate that can be obtained,
which translates to optimized microseismic
mapping accuracy and enhanced stimulated
reservoir volume visualization. Pinnacle’s microseismic monitoring solutions
are highly effective in optimizing multiple
stage fracturing treatments and identifying
original fracturing treatments that are candidates for re-frac treatments or by pass areas are
treated effectively.
The Pinnacle Hybrid Tool represents
Halliburton’s optimum microseismic interpretation solution, combining an array of hybrid technologies that comprises a diagnostic
arrangement of downhole tiltmeters and
downhole microseismic receivers positioned
on the same wireline. The array is deployed
with one tiltmeter at each “level” where a
Fig. 55. Pinnacle's Surface Microseismic Imaging results showing microseismic source.
microseismic tool or more-than-one stacked
microseismic tools is placed. The clamp arm
on the microseismic receiver, or receivers,
also serves as the coupling mechanism for
the tiltmeter tool. One other advantage of
this hybrid array is that the tiltmeter tools are
oriented simultaneously with the microseismic
tools. Precise orientation provides additional
data that can be used in the analysis.
stages, Pinnacle developed the revolutionary
ControlFracTM system, the industry’s first
downhole navigation system that delivers
real-time subsurface insight to clear the way for on-the-fly optimization of fracturing
operations. The tightly designed ControlFrac
system integrates AccessFrac, StimWatch
and FracTrackTM system solutions to enhance
reservoir stimulation and maximize asset value.
To help ensure operators are not making needless investments in suboptimal fracturing
Within the ControlFracTM system solution, the
StimWatch technology allows operators to / 79
analyze cluster efficiency or zonal isolation in
real time. This real-time subsurface insight
allows operators to decide whether or not they need to pump AccessFrac diverters to
maximize the number of fracture initiations in
the reservoir, enabling more uniform half-lengths, and hence stimulating more
reservoir. Also, if the microseismic monitoring
service is available, far-field stimulation
response to diversion with AccessFrac diverters
can be validated in real time.
With the ControlFrac system, Pinnacle
employs a host of reservoir monitoring and
fracture diagnostics sensors and techniques
which are employed seamlessly, including:
• Surface Deformation is a monitoring
technique where ground movement, such
as dilation or subsidence, is measured to
identify fracture azimuth and complexity. Pinnacle has used the process to map as deep
as 15,000 ft with surface tilt. The technique
employs three key sensor technologies:
- Tiltmeters are highly sensitive instruments capable of measuring movements
as small as those caused by the pull of the
moon on the earth’s crust
- InSAR or Interferrometric Synthetic
Aperture Radar is a remote sensing technique which uses a space based
satellite to bounce a radar beam off the
/ 80
ground month after month to monitor
movement. This technique has an accuracy of 1 mm. - Differential GPS (DGPS) is a GPS system
which has an accuracy of 1 to 2 mm. Stations are strategically placed in a project area to monitor movement. Usually, the DGPS is supplemented with
InSAR or tilt results.
• Microseismic Monitoring involves offset
well monitoring with an observation well, which is the preferred method, but in some
circumstances monitoring can be conducted
in the treatment well. • Pressure/Temperature Monitoring
involves conventional pressure/temperature gauge installations or distributed
temperature sensing (DTS) measurements with point pressure using the Pinnacle distributed acoustic sensing (DAS) fiber
optic pressure gauge. DTS can be used for
monitoring a cement job and identifying
top of cement within 3 ft; to monitor pumping jobs in real-time to determine whether
zonal isolation equipment is holding or
failing; and once a well goes on production,
generate a virtual injection log for the life of
the well.
Water-Management Services
Halliburton’s H2O ForwardSM service is a
cost-effective oilfield water-management
service that merges engineering, science, and
technology services from several Halliburton
product lines. This new service offers integrated expertise and solutions for water logistics
(source identification), analysis and modeling
of water chemistry, and recycling and reuse
of impaired water sources, i.e., flowback and
produced water. Halliburton has developed (a)
nonchemical technologies that treat flowback
and produced water to allow use in other wells,
and (b) new high-performance fracturing
fluids for slickwater and crosslinked-gel
fracturing treatments that can be used with
100% impaired-water sources containing
total dissolved solids (TDS) concentrations as
high as 300,000 mg/L. By maximizing the use
of impaired (waste stream) water in well completions, the new water-management service
reduces the need for high-quality water in the
unconventional-resource development supply
chain and reduces the toxicity profile, thereby
providing a solution to enable sustainable
development. In addition, it also simplifies
fluid-handling logistics, minimizes trucking
requirements required for transport of water
supply to the wellsite and for wastewater/solid
waste disposal. The overall benefit is a significantly reduced environmental impact from a
mature development.
Halliburton's capabilities in water-processing
technology, fracturing fluid design, and chemical additives include the following innovations:
• CleanSuite™ - delivers mechanical water
treatment and reduced completion fluid
toxicity.
• Multi-Chem® - delivers well completion and
production chemicals
• Universal Fluid Systems - incorporates
impaired water sources into performance
fracturing fluids
SM
The H2O ForwardSM service integrates these
innovations to provide holistic water-management solutions. The environmental and cost
advantages of this service include:
• Eliminates the need for freshwater supplies
• Helps reduce the volume of chemical biocide
needed
• Reduces chemical contamination/toxicity in
water used in oilfield operations.
• Reduces the truck traffic and costs associated
with delivery and removal of wastewater for
disposal.
• Reduces the impact of mature field development on air quality
The water-management workflow (Fig. 56)
consists of defining the water-source options
and the application of the reused water, characterizing the potential source water
(influent) and determining the quality window
for the reused water (effluent), and designing
a practical and cost-effective process to
bridge the gap in quality between the influent
and effluent water. In this scenario, the ions
found within the waters are recycled and the
water-treatment technology and fluid chemistry are adjusted to deliver the desired fluid
properties and successful recycling. The source
water should always subjected to water analysis,
rheology testing, and a pilot test before actual
use in a fluid system because produced water
can be highly variable. This approach eliminates
the need for (a) time-consuming and expensive
water treatments, and (b) disposal of the solid-waste byproduct of the water treatment.
The H2O ForwardSM Water service can be categorized as an operational-expenditure-based
(Opex) water-management solution that
uses transportable technologies that are easily
moved to or removed from the wellsite.
Treating Produced Water On-Site
In re-fracturing, sufficient water and costs
can be a concern. CleanWave® Frac Flowback
Produced Water Treatment service is a cost-
effective and scalable system featuring a mobile
electrocoagulation system that uses electricity
to remove suspended solids, oil, other insoluble
organics, and bacteria from fracture flowback
and produced water (Fig. 57). The CleanWave
Flowback
Produced Natural Brines
Brackish & Seawater
Wastewater
Define
Rouse
Purpose
Determine
Rouse
Qualitiy
Window
Characterize
Source
Options
Design
Process to
Bridge
Source
Quality to
Reuse
Qualtiy
Maximize Well
Productivity while
Minimizing Water
Utilization and
Associated Costs
Fig. 56. Halliburton’s H2O ForwardSM recovery and reuse workflow.
/ 81
service uses electricity, rather than chemicals,
to provide an environmentally focused option
for treating flowback and produced water at
rates up to 20 bbl/min. Specialized pretesting of
the flowback and produced water is performed
using inductively-coupled argon-plasma (ICP)
spectrometry to identify concentrations of
metals in brines, clays and soil samples. When
contaminated water passes through the electrocoagulation cells an electrical charge is induced
in the wastewater using a series of electrodes.
The anodic process releases positively charged
ions that bind onto the negatively charged
colloidal particles in the water destabilizing
the fluid causing suspended solids, heavy
metals, colloids, and some dissolved solids to
a agglomerate and form a sludge layer. At the
same time, gas bubbles produced at the cathode
attach to the coagulated matter causing it to
float to the surface where it is removed by a
surface skimmer. Heavier coagulants sink to
the bottom leaving clean water, suitable for
use in drilling and production operations. A
series of weirs/baffles within the floatation tank
further clarifies the water. Suspended solids not
captured by the separation tank will settle out
in additional downstream settling tanks. Electrical coagulation is a cost-effective method
that (a) reliably removes 99% of the total
suspended solids in the wastewater, including
total petroleum hydrocarbons, divalents and
/ 82
Fig. 57. Drawing of the Halliburton CleanWave service mobile water-treatment system (SPE 153867).
heavy metals, e.g. iron, copper and zirconium
(the presence of certain metals reduces the
effectiveness of friction reducers) (Fig. 58), (b) reduces water turbidity, and (c) reduces
sulfur- and iron-reducing bacteria levels (Fig. 58). However, this system does not
remove dissolved solids (TDS), e.g., salts. Water
treated with CleanWave service can be directly
used for hydraulic fracturing and for water
injection. Removal of the suspended material,
e.g., the heavy metals, helps to prevent system
scaling—thereby reducing or eliminating the
need for cleaning or maintenance—and allows
for water recycling of crosslinked fluids. Recent
studies indicate that fracturing fluids based on
produced water that has undergone electrocoagulation treatment can increase proppant
conductivity by up to 40%, depending on the
source of produced water and the proppant
used. Another benefit of using the clean brine
product of CleanWave treatment is that it may
reduce or avoid the need for clay-stabilization
products. This water treatment maximizes the
use of impaired water sources and minimizes
the costs associated with water procurement,
transportation, and solid-waste disposal.
On location, the CleanWave treatment process
typically consists of the electrical coagulation
unit with a self-contained filtration system,
a chemical trailer used for pH adjustment, a
settling tank, and storage tanks for the influent
to be treated and the treated effluent.
Preventing Biofouling of the Completion
Controlling bacterial growth in fracturing fluids oilfield operations is critical to prevent
scaling, corrosion, and souring (H2S) effects at
the surface and downhole. In addition, excessive growth of aerobic bacteria can also (a) interfere with the polymers used in the fracturing
treatment (particularly crosslinked fluids) causing the fluid to become too thin and ineffective,
Units
and (b) adversely impact production through
biofouling of porosity and production of sour
gas. Typically, chemical biocides are placed in
water tanks to kill any bacteria present before
the water is circulated throughout a production
system (Fig. 59). However, the use of chemical
biocides potentially exposes workers to toxic
chemicals during transport and at the wellsite
and also introduces harmful chemicals into the
flowback and produced water.
CleanStream® service, Halliburton’s ultraviolet
(UV) light control process, uses a mobile
unit capable of effective on-the-fly treatment
of flowback and produced water at rates up
Influent
EC Treated
Effluent
% Reduction
NTU>1,0000.67
99%
Total Suspended Solids
mg/L
49,000
< 4
99%
FOG (non-polar)
mg/L
900
< 5
99%
µg/L6,200 6.9
99%
99%
Turbidity
Copper, Total
Lead, Total
µg/L
Zinc, Total
µg/L19,950 10
Coliforms, Total
#/100mL
270
390,000
< 10
< 100
Fig. 58. Intelligent production focuses in different time span and scales.
99%
99%
SPE 151819
“Water Conservation: Reducing Freshwater
Consumption by Using Produced Water for Base
Fluid in Hydraulic Fracturing–Case Histories in
Argentina,” J. Bonaspace, M. Giglio, Halliburton;
J. Moggia, and A. Krenz, Pan American Energy,
April 16-18, Mexico City, Mexico
SPE 153867
“An Environmental Solution to Help Reduce
Freshwater Demands and Minimize Chemical
Use,” J.E. Bryant, and J. Haggstrom, Halliburton,
presented at the 2012 SPE/EAGE European
Unconventional Resources Conference and
Exhibition, March 20-22, Vienna, Austria
SPE 163824
“Development and Use of High-TDS Recycled
Produced Water for Crosslinked-Gel-Based
Hydraulic Fracturing,” R. LeBas, P. Lord,
Halliburton; D. Luna, XTO Energy Inc.; and T.
Shahan, Halliburton, presented at the 2013 SPE
Hydraulic Fracturing Technology Conference,
February 4-6, The Woodlands, Texas
SPE 165085
“Effects of Total Suspended Solids on Permeability of
Proppant Pack,” X. Ye, N. Tonmukayakul, P. Lord,
and R. LeBas, Halliburton, presented at the 2013
SPE European Formation Damage Conference and
Exhibition, June 5-7, Noordwijk, The Netherlands
/ 83
Fig. 59. Examples demonstrating the capability of the CleanWave water-treatment service to remove suspended solids (a) and suspended petroleum hydrocarbons (b). In each example the water sample before treatment (left) and after final filtration (right) is shown.
Case STUDY:
Case STUDY:
Successful Reuse of Produced Water Preserves City’s
Freshwater Resources
West Texas Operator Uses Treated Produced Water with
no lose in Production
In South America, an operator was seeking to preserve natural freshwater
A recent field trial in the Permian Basin successfully demonstrated the
resources that served as the source of drinking water for a nearby city and
feasibility of using high-TDS produced water as the base fluid in crosslinked-
needed an alternate source of water for its expanding fracturing operations.
gel-based hydraulic fracturing. In this field trial, which involved 7 wells and
Laboratory water analyses of the potential water sources demonstrated that the
97 fracturing stages, 100% of the fracturing fluid base water was produced
chemical formulation of the fracturing fluid and additives could be adjusted to
water with TDS concentrations up to 285,000 mg/L. The produced water was
work with low-salinity produced water from the operator’s waterflood system.
first treated using the CleanWave electrical coagulation service. Comparisons
A methodology was developed to ensure that equipment, tanker trucks, and
with offset wells that had been fractured using 2% KCl as the base fluid indi-
storage tanks were properly treated to handle the produced water and prevent
cated that the wells in this trial were experiencing similar production levels,
bacterial growth. Since 2007, this methodology has resulted in successful com-
i.e., that there was no loss in fracturing-fluid performance accompanying
pletions and the percentage of completions using produced water has gradually
use of high-TDS produced water. The benefits accrued through the use of
increased to 54% through 2010. This, in turn, has resulted in a considerable
produced water and the CleanWave system included a savings of 8 million
reduction in freshwater usage (5.7 million gallons). The operator’s goal was to
gal of fresh water and eliminating 1,400 truck loads of water from offsite, for
use produced water for 100% of its fracturing operations once the necessary
a per well cost savings of $70,000 to $100,000 USD (SPE 163824). infrastructure was in place (SPE 151819) and it is progressing to this goal.
/ 84
to 100 bbl/min. The cellular DNA of bacteria
absorbs the energy from the UV light (254 nm),
as the water flows through the light sources
(Fig. 60) causing damage to their DNA structure, which impairs chromosomal replication,
leaving the bacteria unable to produce proteins
or replicate, thus killing most bacteria. On-site
use of the CleanStream service may reduce or
completely eliminate the need for chemical biocides to treat for aerobic and anaerobic (sulfate
reducing) bacteria.
To obtain a successful decrease in bacteria
levels using UV light, the water must be
effectively dosed with UV light, however, the
high levels of dissolved salts commonly present
in flowback and produced waters can limit the
effectiveness of this method. Specialized pretesting of the influent (flowback and produced
water) must be performed to determine the
suitability and potential flow-rate adjustment
based on the UV-light transmittance of the
water. Depending on the specific conditions,
CleanStream service technology can significantly reduce the need for and use of chemical
biocides. An on-site configuration employing
multiple UV light chambers can increase the
maximum throughput and also provide operational redundancy should one of the chambers
fail. The CleanStream trailer is equipped with
laboratory equipment to perform quality-control checks on the UV disinfection and is easily
integrated with current fracture spread layouts
and is placed between the tanks holding the
water source and the blender (Fig. 61). These
technologies were innovated for the unconventional market but is being more widely used for
any mature field.
World Oil
“UV Light Technology Controls Bacteria while
Reducing Environmental Risks,” K. Kleinwolterink, B. Watson, D. Allison, Halliburton; and M. Sharrock,
EOG Resources, World Oil, 230(12), 2009
SPE 133368
“Nonchemical Bacteria-Control Process,” G. Neal,
K. Kleinwolterink, L. Abney, Halliburton; and L.
Gloe, formerly Halliburton, presented at the 2010
Exhibition, October 18-20, Brisbane, Queensland,
Australia
Fig. 60. Points in the downstream process that can be adversely impacted by bacterial contamination
in produced water.
/ 85
SPE 142217
“Improved Process Provides More Effective
Ultraviolet Light Disinfection of Fracturing Fluids,”
B. Crane, G. Neal, and W. Warren, Halliburton,
presented at the 2011 SPE American E&P Health,
Safety, Security and Environmental Conference,
March 21-23, Houston, Texas
SPE 149445
Fig. 61. CleanStream service UV light (right) disrupts bacterial DNA so they cannot reproduce and
ultimately die off.
®
“Case Study: Challenges Using Ultraviolet Light
to Control Bacteria in Marcellus Completions,” G.
Rodvelt, V. Yeager, Halliburton; and M. Hyatt,
Williams Exploration and Production, presented
at the 2011 SPE Eastern Regional Meeting, August
17-19, Columbus, Ohio
SPE 125665
“UV Light Reduces the Amount of Biocide Required
to Disinfect Water for Fracturing Fluids,” L. Gloe,
and G. Neal, Halliburton, presented at the 2009
SPE Eastern Regional Meeting, September 23-25,
Charleston, West Virginia
Fig. 62. CleanStream® service mobile trailer. The white section contains the laboratory for QC of the
UV process.
SPE 126851
“Ultraviolet Light Disinfection of Fracturing
Fluids,” L. Gloe, G. Neal, and K. Kleinwolterink,
International Conference on Health, Safety and
Environment Conference, April 12-14, Rio de
Janeiro, Brazil
/ 86
Case STUDY:
UV Bacteria Control Achieves 99+% Reduction in Bacteria in the Marcellus
An operator in the Marcellus Shale decided to use the CleanStream service rather than chemical additives
to control the growth of aerobic and anaerobic bacteria in the makeup water used for the fracturing fluid. In
the Marcellus, makeup water is commonly a mixture from a variety of fresh surface and impaired sources
(e.g., rivers, man-made impoundments, public water supplies, coal-mine operations, and flowback fluids),
including 10 to 25% flowback water, for environmental reasons and to reduce disposal costs, and this water
must be treated for bacteria control. The CleanStream UV light treatment was able to reduce aerobic and
anaerobic bacteria colonies in the by about 99.9% the freshwater, which has a UV light transmittance of 75
to 87% at flow rates of 70 to 75 bbl/min. However, the reduction rate in the flowback water samples, which
had a UV light transmittance of 27%, was only 90%. Successful bacteria control using UV light where the
UV light transmittance is <75% requires a lower flow rate through the CleanStream light chambers as the
quality of the influent (the transmittance) must be improved before CleanStream processing. A mixture of
flowback and fresh water with a lower injection rate improved the UV light transmittance to 45% which
brought the bacteria reduction rate back to >99%. During this campaign, approximately 2.5 million gallons
of water for six wells were treated using the CleanStream service, with average bacteria reduction rates of
>99% and reduced environmental risk by 80% (SPE 149445).
Case STUDY:
CleanSuiteTM System Technologies Result in Major Savings on Haynesville Shale Horizontal
A 14-stage Haynesville horizontal shale-gas well had a bottomhole static temperature (BHST) of 340°F. The
fracturing-fluid system that was designed to work only at a maximum temperature of 225°F successfully
placed proppant due to significant formation cool down. More than 4 million gallons of CleanStim® hydraulic
fracturing fluid system, composed solely of ingredients source from the food industry) was used to fracture
stimulate the well and resulted in very economic production of natural gas. The application of the Advanced
Dry-Polymer dry-mixing unit on this job, rather than the common practice of preparing LGC, eliminated
more than 5,000 gallons of hydrocarbon carrier fluid. The CleanStream service treated nearly 4.8 million gallons of water, which saved more than 1,000 gallons of biocide. The reuse of production water, made possible by the CleanWave electrocoagulation service, saved 1 million gallons of fresh water (SPE 153867). Wellbore Integrity Assurance
Optimal and sustained reservoir drainage
from any reservoir requires the wellbore
maintain lifelong reliability to achieve maximum asset value with minimal intervention.
Integrity issues can become more pronounced
in older wells where over time the cement
sheath is adversely subjected to stresses
from formation and pressure changes, or
ever-weakening formations cause the liner
hanger to fail.
To help ensure operators generate the
highest possible return for their mature field
investment for as long as possible, Halliburton
employs a holistic strategy for wellbore
integrity assurance with a portfolio of solutions
employed systematically during planning and
continuing to abandonment. Halliburton’s
wellbore integrity assurance strategy begins
with an customized approach to selecting the
right cement for the specific application, and
continues with new generation lightweight
cements, squeezes and state-of-the-art liner
hanger solutions. In addition, Halliburton
employs the industry’s most advanced technologies to ensure integrity remains a constant
throughout the productive life of the well.
Engineering Integrity at the Onset
A cement design matched for specific wellbore
characteristics and downhole conditions is
/ 87
critical to maintaining integrity. Halliburton response is the iCem® service, a predictive-
analysis software based on computational
fluid dynamics and finite-element analysis.
The iCem software consistently delivers
independently verified simulations of the
slurry during placement. The iCem service
is a scientifcally grounded analytical tool that
helps operators make better decisions faster,
regardless of the asset they are developing.
Accordingly, simulations that once took days to
develop and execute can now be completed in
two to three hours.
Using iCem service, Halliburton evaluates
the effects of variable changes, including mud
displacement, slurry properties, casing/pipe
movement, centralization, fluid volumes, pump
rates, and temperature/pressure differentials.
Three-dimensional models simulate fluid-flow
interaction and displacement phenomena.
Prognostic models simulate fluid-flow
interaction, displacement phenomena, and
stresses in set cement to optimize designs for
primary cementing, a reverse-circulation job,
a balanced plug job, or a post-cementing job
evaluation, while evaluating stresses in the
cement. The iCem service provides predictive
input on material selection and volumes that
help achieve long-term wellbore integrity.
The companion iFacts™ laboratory management system provides engineers immediate / 88
Fig. 63. Cementing engineering analyses tool is comprehensive and goes from drilling fluid displacement
to cement placement.
access to collective data from thousands of
fluid tests. Data centralization promotes
information sharing and collaboration among
the global technical professionals for the
optimization of spacers, flushes, and cement
slurries for specific formations.
systems. This trio works synergistically to
preserve cement integrity, while reducing or
eliminating costly remediation.
In addition, investigations of the root causes
of potential damage in older wellbores led
Halliburton to developed the three-tier
WellLife® III cementing service, comprising
the iCem service for modeling, analysis and
cementing operations design; the nonfoamed
ElastiCem® and LifeCem™ cement systems
and the Swellpacker® isolation system, which
is based on proprietary Swell TechnologyTM
Cementing casing across the highly depleted
zones and weaker formations that characterize
the mature field requires low-density cement
systems capable of reducing the hydrostatic
pressure of the fluid column during cement
placement. Low-density or lightweight cement
systems help achieve the specified top of
cement by avoiding or minimizing the loss of
cement to the formation.
Lightweight Cement Solutions for Unique Mature
Well Challenges
across low-strength water zones or seals off
a microannulus in smaller than a typical
cement particle areas. The Micro Matrix even
provides high compressive strength when the
BHCT is only 40°F, such as those in a subsea
completion and shallow Arctic areas.
Fig. 64. These two 1-in. diameter syringes show
Micro Matrix® cement (on left) has penetrated
20/40 sand while conventional cement (on
right) has bridged. Micro Matrix cement is able
to penetrate openings as small as 0.05 mm or
100 mesh sand.
Halliburton’s comprehensive cementing suite
includes slurries that are light enough to circulate in these challenging applications,
while retaining the ability to withstand downhole conditions. A lightweight cement
can be formulated in one of three ways: water extended, injection of gas (foamed cement),
or by adding low-specific-gravity microspheres or other enhancing additives.
Halliburton’s lightweight slurry portfolio
features the Micro Matrix® cement that
effectively delivers high compressive strength
A major advancement in primary and squeeze
cementing technology, Micro Matrix cement
has been shown to effectively penetrate
and help seal areas normally inaccessible to
conventional oilfield cements. Owing to their
larger particle size, standard cement slurries
are unable to produce more than a skin effect
following a squeeze procedure. Micro Matrix
cement, on the other hand, has been proven
to penetrate small channels, thus helping shut
off undesired water, gas, or steam production.
Micro Matrix cement is microground so the
particle size is 10 or more times smaller than
standard cement, making it particularly
beneficial for remedial cementing where penetration of small cracks is required,
and for wells completed and produced that develop high-permeability streaks resulting in
adverse production economics. Along with remedial applications, the Micro
Matrix cement is ideal for any primary
cementing application requiring a highstrength, lightweight slurry. Furthermore, the
lightweight cement formulation has demonstrated wait on cement (WOC) times reduced
by as much as 50% at low temperature as
compared to premium cement. Micro Matrix
cement expands slightly on hydration and
offers significantly better bonding strength
than typical cement at low temperature. The
Micro Matrix cement is sufficiently versatile, making it compatible with virtually all of
Halliburton's proven cement additives.
Preventing Cement Losses to Maintain Integrity
As with drilling fluids, the partial or complete
loss of cement slurry to the formation during
cementing operations can dramatically
increase NPT and add substantially to the
overall cost of a well. Typical methods of
addressing lost circulation during cementing
operations is with bridging or plugging
material, the use of rapid-set or thixotropic
cement, or with lightweight cement systems.
Within its lightweight cement suite, Halliburton
has formulated low-density slurry solutions
designed specifically to head off losses in depleted zones to protect the long-term integrity
of the mature well. The line includes:
• FracSeal™ low-density cement that can be
designed to handle low-fracture-gradient
wells while maintaining sufficient hydrostatic
pressure to manage pore pressures effectively. FracSeal cement is designed with high-
/ 89
viscosity and expansive forces to help with
hole cleaning and displacement and superior bridging by combining lost-circulation
materials with inherent diverting capabilities
of foam cement. FracSeal cement may be
considered in situations where loss of whole
fluid to the formation is expected and where
foam cement is not available.
• Tuned® Light cement comprises a family of
low-density conventional cements designed
to increase the probability that cement will
circulate up the annulus and not out to the
formation. Tuned Light cement provides superior bridging by combining lost-circulation
material with the inherent diverting properties
of microspheres. Tuned Light cements can
be designed to low slurry densities enabling a
reduction in the equivalent circulating density.
For remedial cementing, Halliburton offers pioneering squeeze solutions that can be
applied at any time during the life of the well.
Depending on the remediation requirement, squeeze-cementing operations can be performed above or below the fracture gradient of the exposed formation.
In addition, Halliburton provides an advanced
line of drillable squeeze packers that are primarily used as cement retainers during remedial
cementing operations.
/ 90
In mature wells, squeeze cementing is commonly used to
• Seal thief or lost-circulation zones
• Repair casing leaks
• Change the water/oil or gas/oil ratio by
shutting off the breakthrough zone
• Abandon a nonproductive or depleted zone
or the entire well
• Modify injection profiles.
Halliburton offers several specifically-
designed squeeze-cementing solutions as part
of Halliburton’s Tuned Cementing Solutions™.
SqueezeCem™ conventional and SqueezeSeal™
foamed cements are designed to form
effective squeeze cement slurries in cased or
openhole intervals.
FineCem™ cement is a fine-particle,
high-surface-area cement blend that can be
used on squeeze jobs where fine-particle
cement blends are required to penetrate
areas previously inaccessible to conventional
cement slurry, such as “tight” casing leaks,
gravel packs, small fractures, channels, or
microannuli. Conventionally, “tight” casing
leaks (the type that bleed off pressure yet
will not accept a continuous injection rate)
usually must be broken down with acid to
increase the leak area so that cement slurry
can enter. However, FineCem cement slurries
can penetrate the small leak much more
easily, and therefore repair it, without prior
breakdown. Wells completed and produced
containing gravel packs typically develop
high-permeability streaks, resulting in steam
or water breakthrough and accompanying
problems associated with either condition.
Standard cement slurries, because of their
greater particle size, are unable to produce
more than a skin effect following squeeze procedures. FineCem cement, however, is able to
penetrate the permeability of the gravel pack
to effectively shut off undesired water, gas, or
steam production. FineCem™ cement slurries
can also be used in slimhole conditions for
production strings.
These tools are available in both poppet valve
and sliding valve types, and include the:
• DrillGun™ Perforating System that provides reliable, quality performance while overall wellsite costs.
• EZ Drill® SVB Squeeze Packer, a robust system engineered to absorb greater tensile
and impact loads as well as greater internal
pressures.
• Fas Drill® Squeeze Packers, which are designed for use in temperatures ranging
from 50 to 250°F (10 to 121°C) and
contains minimal ferrous metal content for
easy drillout.
• Fas Drill® SVB Squeeze Packers, which
are engineered with a stinger-operated
sliding valve that holds pressure from both
directions.
• Primary zonal isolation
Long-Term Liner Hanger Integrity
• Secondary annular
barrier
Any number of industry analysis have shown
that, offshore and onshore, most conventional
liner hangers typically will require some sort
of remediation, that if not addressed, can
lead to serious wellbore stability issues in late
well life. Many of the problems with standard
hangers are liner tops being susceptible to
wellbore debris, as well as ledges, sloughing,
heaving beds and weak formations. • Remediation for annular
pressure buildup or
water / gas breakthrough
Locking In Late Life Well Integrity
• Disposal wells
Casing leaks or microannuli can occur
throughout the life of a well and remediation
typically is both costly and challenging, especially in very narrow annuli or micron-sized fissures.
• Plug and abandonment
Halliburton’s WellLock® resin system readily
penetrates and blocks small casing leaks,
microannuli, or gravel packs without requiring acid cleanups. It provides a gas seal.
The system’s excellent mechanical properties
of high ductility and compressive strengths
up to 18,000 psi, capable of withstanding
pressure differentials up to 100 times more
than required within the wellbore helps to
preserve well integrity.
The mechanical properties of WellLock resin,
including density, elasticity, and strength
can be tailored to meet a variety of wellbore
challenges. Applications include situations
where water or gas leaks need to be prevented
or remediated:
WellLock resin system can
serve as a secondary barrier to a
resilient cement sheath.
When pumped ahead of
cement, WellLock Resin
system deposits a film
on the formation and
outer casing resulting
in dramatic shear bond improvements of the
cement sheath. Unlike a
conventional compressive
Fig. 65. Fas
strength chart for cement
Drill® SVB
where compressive strength
Squeeze
is plotted over time, this
Packera
chart provides data on the mechanical properties of WellLock resin when
serving as a secondary barrier in a downhole
temperature of 162°F (72°C). In these conditions, not only does the resin achieve 12,500 psi, it also remains highly ductile.
To address these long-term integrity issues, Halliburton combined its industry-leading
expandable solid-tubular technology and
cementing expertise to develop the VersaFlex®
liner hanger system. The VersaFlex liner
hanger/packer family consists of an integral
tieback receptacle and expandable solid
hanger body that are bonded to multiple Fig. 66. WellLock resin system can serve as a
secondary barrier to a resilient cement sheath.
/ 91
elastomeric elements. The system provides
both a bidirectional annular seal and all
tensile and compressive load capability.
Unlike conventional liner hangers, the VersaFlex
suite makes for a less complex completion,
reduces potential leak paths and offers
multiple redundant sealing (packer) elements.
Consequently, they eliminate the need for liner- top isolation packers, delivers faster
run-in-hole (RIH) time to reduce rig time while
moving parts improve reliability and fluid flow.
The VersaFlex portfolio includes the:
• VersaFlex® Big Bore System, which is designed specifically for deepwater and
subsea markets and is ideal for complex well
conditions. The VersaFlex Big Bore system
does not require landing in a predetermined
profile, helping to eliminate complications
Case STUDY:
WellLock Seals Casing Leak, Assures
Compliance
The operator was experiencing leaks in aged
casing, making it unable to comply with local
regulations. In addition, the leak was close to
production zone. Halliburton employed the
WellLock resin in a 3.5-bbl bradenhead squeeze,
which effectively isolated the squeeze. With the
leak sealed, the casing passed the pressure test and
successfully met state regulatory requirements.
/ 92
Fig. 67. VersaStim expandable liner hanger system
common to positioning in mudline/casing
wellhead profiles.
• VersaFlex® Breech Lock system increases
compressive load capability of the running
tool allowing operators to reach total
well depth particularly in extended reach
drilling (ERD) wells, while minimizing risks
during liner hanger deployment and setting
operations.
• VersaFlex® High-Torque System, which is
a robust running tool specifically designed
for harsh conditions, is highly effective for
demanding wellbore environments.
• VersaStim™ Expandable Liner Hanger
System represents an optimized configuration for openhole horizontal completions.
Advanced Solutions for Verifying
Long-Term Integrity
As the number of aging oil and gas wells multiple as fields mature, it is necessary to regularly
monitor the integrity of the cement, casing
and tubing, which, during the well’s lifetime,
can deteriorate with prolonged exposure to
corrosive chemical species, such as CO2 and
H2O. In the U.S., many states have enacted
regulations regarding cement inspection in
wells. These regulations may require a detailed
cement-bond logging and casing inspection.
Halliburton ensures long-time integrity with
Fig. 68. This real-time plot from a cased-hole log displays eccentricity, ovality, and relative bearing
in Track 1, casing thickness in Track 2, and regular and amplified amplitude in Track 3. The MicroSeismogram® display is shown in Track 4. The cement bond index and average impedance are
shown in Track 5 while the impedance map is displayed in Track 6. A cement channel (void) is
indicated by the blue shading in the impedance map from X125 to X145 ft.
/ 93
/ 94
a wide range of advanced ultrasonic scanners,
such as the Circumferential Acoustic Scanning
Tool (CASTTM) series, CAST-VTM and CAST-MTM, and FASTCASTTM sensors, that
provides operators valuable data that allow
accurate and precise assessment of cement
and casing integrity. The combination of
Halliburton’s CAST-MTM, and CBL tools and
supporting ACETM software provides data that
are both easy to understand and enables operators to get detailed analyses within minutes.
cement and casing integrity. The larger
CAST-V tool is designed for operation on
conventional 7-conductor wireline in vertical
boreholes. The smaller CAST-M tool is run
on monoconductor electric line in horizontal
boreholes. The FASTCAST tool expands the
capabilities of the CAST-V tool and increases
logging speed by up to five times, significantly
reducing logging time, rig time, and costs.
Both tools can be run in either cased-hole or
imaging mode.
In open hole, the CAST tools provide complete borehole imaging and fracture detection for accurate, precise formation evaluation.
In cased hole, these tools provide simultaneous
ultrasonic cement imaging/evaluation (bond
evaluation) and pipe inspection (casing
thickness and diameter). These sensors provide
a full 360° profile of the borehole that can be
presented in a variety of 2D and 3D imaging
formats. The high-resolution cement and casing evaluation images are oriented with respect
to high side-low side of the wellbore. CAST™
tools also provide a joint-by-joint analysis and
report of internal and external casing defects.
Cased-hole mode provides information about
the casing internal diameter (ID), casing thickness, and acoustic impedance of the material
behind pipe. Image mode is logged at 100%
horizontal coverage with a vertical resolution
of 0.2 in. (60 samples/ft) and provides a highly
detailed image of the interior casing defects.
Pipe thickness and impedance values are not
measured. All three tools are rated to temperatures and pressures of 350°F (176.6 °C) and
20,000 psi (137.9 MPa), respectively. In high
angle or horizontal well conditions, both tools
can be conveyed on drillpipe, tractor, e-coil, or
pumped down.
Combining the CAST-M tool with the CBL-M
cement-bond tool and a multifingered caliper
tool (MFC-M) and using Advanced Cement
Evaluation (ACE™) or Casing Evaluation
(CASE™) data-processing services delivers
precise and high-quality evaluation of both
Meanwhile, casing-inspection logs should be
run based on criteria, such as, well type, fluid
types, pressure, temperature, etc., to calculate
the remaining life of the well. Most conventional
tubular-evaluation tools, including internal
mechanical calipers, electromagnetic and
ultrasonic thickness tools, are satisfactory for the
evaluation of the inner casing, but are unable to
evaluate multiple concentric barriers. Because of
the relatively large diameters and limitations of
current tools, casing inspection typically requires
expensive workovers to pull the inner tubing to
allow inspection of the outer casing.
The 1-11/16-in. diameter of Halliburton's new
Xaminer™ Electromagnetic Corrosion Tool
(ECT) allows measurements in small-diameter
(slim) production tubing. The tool employs
large electromagnetic transmitter and receiver
coils to induce transient or pulsed eddy currents
in the cross section of the tubulars being evaluated and measures the decaying electromagnetic
response generated from the induced signal
with the receiver coils. The resulting signal is
processed to extract quantitative metal thickness
measurements for the tubing and the first
concentric casing.
In certain conditions, it also can qualitatively
characterize corrosion in a third concentric
string. Halliburton has verified corrosion in
hundreds of Middle East wells without the need
for workovers, thereby reducing the customer’s
costs. When combined with multifinger caliper
imaging tools, the condition of both the inner
and outer wall can be determined. Time-lapse
measurements of casing corrosion can provide
a powerful method for evaluating the progression of corrosion in concentric tubulars, before
it reaches the inner production tubing.
All of these innovations work seamlessly to immediately help ensure that wells with
declining production are quickly put back on
line at the highest sustained rates the reservoir
can yield.
SPE 108415
“Cement Bond Evaluation,” E.H. Shook, G.J. Frisch, Halliburton; and T. Lewis, Centurion
Exploration, presented at the 2008 SPE Western
Regional and Pacific Section AAPG Joint Meeting,
March 31-April 2, Bakersfield, California
SPE 145970
“Cement-Bond Evaluation: A Step Change in
Capabilities,” C. Kessler, C. Bonavides, A. Quintero, and J. Hill, Hallburton, presented at
Exhibition, October 30-November 2, Denver,
Colorado, USA
SPE 167028
“Monitoring Well Integrity and Groundwater
Protection with Innovative Logging Practices in
Unconventional Horizontal Wells,” O. Foianini,
and T. Nurhayati, Halliburton, presented at the
2013 SPE Unconventional Resources Conference
and Exhibition-Asia Pacific, November 11-13,
Brisbane, Australia
Case STUDY:
New Casing Corrosion Tool Cuts Costs in Middle East
A Middle East operator holds thousands of producing wells, many dating back to the 1940s. Some of
these wells were recompleted as recently as 2002, and already display symptoms of integrity loss due to
the presence of corrosive fluids such as CO2 and H2S. These conditions result in the need for ongoing
monitoring of the casing integrity of virtually every well. However, the operator found it difficult to
identify wells that needed help the most using conventional tools because they are unable to evaluate
multiple concentric barriers. This limitation meant operators could only determine the extent of corrosion in outer casing strings by performing expensive workovers. With the cost of each workover reaching
approximately $1 million, the operator needed a more efficient way to determine casing corrosion in
outer strings. Halliburton and the customer conducted a field test to assess the integrity of mature wells
completed with small-diameter tubulars in H2S environments. The results showed the tool reliably
quantified metal loss of casing behind the tubing and helped the customer arrive at workable estimates
for the metal's annual rate of loss, thereby making a mitigation strategy possible. The study also showed
increased metal loss in zones of poorly cemented pipe, and little or none in zones with good cement
bonds, which enabled the prioritization of wells for a workover program
SPWLA_2013
“Cement Evaluation Behind Thick-Walled Casing
with Advanced Ultrasonic Pulse-Echo Technology:
Pushing the Limit,” I. Foianini, B. Mandal, and
R. Epstein, Halliburton, presented at the 2013
SPWLA 54th Annual Logging Symposium, June
22-26, New Orleans, Louisiana
SPWLA_2010
IPTC 16997
“Successful Application of a New Electromagnetic
Corrosion Tool for Well Integrity Evaluation in Old
Wells Completed with Reduced Diameter Tubular,”
N. Sethi, N. Guergueb, Halliburton, J. Garcia, K. Yateem, Saudi Aramco; and P. Zhang, Gowell,
presented at the 2013 International Petroleum
Technology Conference, March 26-28, Beijing, China
“A New Monocable Circumferential Acoustic Scanner
Tool (CAST-M) for Cased-Hole and Open-Hole
Applications,” B. Mandal, and A. Quintero, Halliburton,
presented at the 2010 SPWLA 51st Annual Logging
Symposium, June 19-23, Perth, Australia
/ 95
> Bypassed Zones and New Pay Zones That May Have Been Missed
Bypassed Zones
and New Pay Zones
That May Have
Been Missed
Because primary-recovery factors are typically
below 35%, large amounts of oil and gas remain
in mature fields. One of the first challenges
in mature field development is to find the
remaining oil, which occurs as the result
of inefficient displacement (residual oil in
the pores) or poor sweep efficiency during
flooding. When analyzing a mature field, best
practice is to first identify bypassed zones and
determine remaining recoverable fluids. Field
reservoir management is needed to recognize
the number of intervals involved, the age of the
wells and the likelihood of oil being bypassed.
Halliburton’s multidisciplinary approach can
help meet some of the most common mature
field challenges. From accessing bypassed
reserves, to maintaining pressure, to preventing
lost time or premature abandonment,
Halliburton is committed to helping operators
turn their mature fields into profitable ones.
oil saturation (ROS) is very important for
evaluating secondary and tertiary recovery
project economics. Periodic surveillance of
the migration of water or CO2 injected during
flooding is essential to effective flood management, i.e., modifying the injection pattern to
optimize sweep efficiency. Reservoir surveillance can lead to an increased understanding
of aquifer water movement, injected water or
gas movement, injection performance, and
compaction, which allows operators to better
develop existing fields in order to increase
recovery and profitability. Usually, the wells
available for surveillance logging are already
cased and cemented preventing the use of
tradition openhole saturation logging methods,
e.g., resistivity and NMR.
Fluid-saturation evaluation based on cased-hole,
pulsed-neutron inelastic carbon-oxygen (C/O
mode) and neutron capture (sigma mode) is a
proven technology for monitoring ROS, fluid
movement, and to measure flood effectiveness.
Reservoir surveillance using pulsed-neutron
sigma logging has proved extremely valuable
and effective, particularly in areas where there
is a large contrast in capture cross-section
(sigma) between high-salinity formation water
and hydrocarbons, such as Gulf of Mexico.
Carbon-oxygen logging has also proved effective in low-salinity, medium-to-high porosity
oil reservoirs in Indonesia. The latest generation of cased-hole pulsed-neutron tool, the
TMD-3D™ tool, is capable of acquiring sigma
measurements and the RMT-Elite™ Reservoir
Monitoring tool is capable of acquiring both
inelastic and Sigma® measurements, which
allows synergistic reservoir evaluations.
In reservoir monitoring, pulsed-neutron
logging data are compared with the original
openhole logging data or the previous
surveillance survey (time-lapse logging). The
data from pulsed-neutron surveillance logging
are integrated in a dynamic reservoir model
along with other subsurface data, including 4D
seismic, additional openhole logs from new
wells, production data, and injection data in
order to continually optimize recovery. These
results provide a better understanding of
Reservoir Production Evaluation
Reservoir monitoring in mature fields is critical
for developing an effective reservoir-management
strategy. Accurate determination of residual
/ 96
Fig. 1. Schematic of TMD-3DTM tool showing the relative locations of the three detectors from the
pulsed-neutron source.
fluid changes within the reservoirs under the
influence of compaction, water injection and
aquifer movement and the location of bypassed
pay. Additional well-logging sensors such as,
production logs, may be combined with the
pulsed-neutron tools.
The Halliburton TMD-3DTM tool is an advanced though-tubing (1-11/16 in.) 3-detector pulsed-neutron logging instrument
that is primarily used to determine “fluid”
saturations in reservoirs with tubing sizes
smaller than 2-7/8 in. The addition of a third
detector located 10 in. beyond the traditional
detector spacing (TMD-LTM) tool provides a
deeper-reading set of count rates with larger
formation gas response and an additional sigma
measurement, each with reduced environmental effects, which allows greatly improved
determinations of gas saturation (Fig. 1). The
additional detector also provides a cased-hole
“bulk density” measurement that can be used
with the neutron-porosity measurement.
The tool is capable of operating in either silicon
and oxygen activation or capture (sigma)
mode. The traditional thermal-neutron capture
cross-section (sigma) is measured to determine
water saturation in formations with higher
salinities and mid-to-high porosities and monitoring reservoir fluid contacts. The
advanced multi-detector measurements are
SPWLA 2010
SPWLA 2011
“A New Three-Detector 1-11/16-Inch Pulsed
Neutron Tool for Unconventional Reservoirs,”
W. Guo, L. Jacobson, J. Truax, D. Dorffer and
S. Kwong, Halliburton, presented at the 2010
SPWLA 51st Annual Logging Symposium, June
19-23, Perth, Australia
“Advancements In Carbon-Oxygen Surveillance of
the Deepwater Gulf of Mexico Mars Waterflood,”
M. Cuttitta, J. Weiland, Suparman, P. Fox, and
I. Setiadi, presented at the 2011 SPWLA 52nd
Annual Logging Symposium, May 14-18,
Colorado Springs, Colorado
SPWLA 2012
SPWLA 2013
“Uncertainty Analysis for Determining
Petrophysical Parameters with a Multi-Detector
Pulsed Neutron Tool in Unconventional
Reservoirs,” W. Guo, D. Dorffer, S. Roy, L. Jacobson, and D. Durbin, Halliburton, presented at the 2012 SPWLA 53rd Annual Logging
Symposium, June 16-20, Cartagena, Colombia
“PNL application in CO2 and Oil Saturation in
CO2 Flooding Fields,” S. Fnu, Halliburton; Z. Liu
and G. Simmons, Kinder Morgan, presented
at the 2013 SPWLA 54th Annual Logging
Symposium, June 22-26, New Orleans, Louisiana
designed for increased dynamic range and
accuracy for determination of gas saturation
in formations with low porosity and low/unknown salinities. The technology also identifies
bypassed gas in complex completions, estimates
cased-hole porosity and pressure depletion, and
provides basic lithology indicators. This service
can also be used to monitor fluid saturation in
CO2 EOR and in CO2 sequestration, for oxygen
activation to identify water flow inside/outside
casings for conformance, for silicon activation
for gravel-pack evaluation, and for radioactive
tracer detection to assess flood propagation.
Combinations of several measurements are
used to simulate openhole logs, via Chi Modeling® neural-net processing.
The RMT-EliteTM Reservoir Monitoring tool
is a slimhole, dual-detector, pulsed-neutron
spectrometry logging system used for casedhole monitoring of producing reservoirs. The
small diameter (2-1/8 in.) allows access to the
reservoir interval directly through large-diameter tubing (> 2-7/8 in. ID), without having
to kill the well, pull the tubulars, or lose production. The logging tool uses high-density
bismuth germanium oxide (BGO) detectors
to achieve high measurement accuracy and
spectral resolution (256 channels). In a single
pass it can operate in either inelastic carbon/
oxygen (C/O) mode or thermal-neutron
capture (Σ, sigma) mode. In the C/O mode,
/ 97
three measurements record C/O events,
Sigma events and delayed (natural) and
activation events. Carbon/oxygen logging
is used to determine fluid saturations in
freshwater formations and those of unknown
water salinity, reservoir porosity and lithology,
and to identify fluid contacts and bypassed
pay. Oxygen activation can be used to detect
water flow inside or behind casing and a
silicon-activation measurement (acquired
in conjunction with a gamma-ray sensor)
can evaluate gravel packs. Time-lapse C/O
logging is used to monitor fluid movement
and changing conditions in the reservoir,
which are essential for optimizing reservoir
management and hydrocarbon production.
Operating in sigma mode provides all the
measurements normally associated with a
PNC log, allowing determination of fluid
saturations in high-salinity formations (also
gas saturation in freshwater formations).
This mode is optimized for the sigma
measurement and allows for more efficient
detection of high-energy capture gamma rays
with, these data also allow lithologic analysis.
The RMT-Elite™ Reservoir Monitoring tool
offers two to three times higher measurement
resolution than other through-tubing C/O
logging systems and can run continuous
passes in low porosity formations where other
systems can only be run in a stationary mode.
Elemental spectroscopy from capture and
/ 98
inelastic scattering can be used for elemental
and mineralogical analyses and for assessment
of fracture susceptibility. The modular design
allows the RMT-Elite™ Reservoir Monitoring
tool to be combined with a complete string of
production logging tool sensors for detailed
production analysis.
Halliburton’s advanced pulsed-neutron tools
can be deployed in memory mode—on
slickline or coiled tubing—reducing nonproductive time while providing conveyance
flexibility. The Halliburton Memory Pack
(HMP™) tool (Fig. 2) is equipped with specialized engineering safety features, including
timing, temperature, pressure, and mechanical
pressure activation switches to offer multiple
safety barriers for safely deploying the
RMT-Elite™ Reservoir Monitoring tool and
TMD-3DTM tools. The HMP tool has the capability to change logging modes from sigma
to C/O for specialized multiphase saturation
evaluation, which allows planning jobs to
perform multiple applications in a single run
Fig. 2. Halliburton Memory Pack Tool.
into the well. Slickline deployment permits
access to high-pressure wells that may not be
achievable with electric line. The specialized
battery design allows extended logging time
for memory operation, resulting in longer log
intervals.
Sophisticated formation-saturation analysis
and porosity data is available with RMT-EliteTM Reservoir Monitoring tool and
TMD-3DTM tools and Halliburton’s cased-hole
formation evaluation interpretation software
models (Fig. 3), including:
• CarbOxSat™ - Model oil saturation analysis
using C/O measurements
• SigmaSat™ - Model water saturation analysis
using capture cross-section measurements (∑)
• TripleSat™ - Model three-phase oil, gas, and
water saturations using both C/O and ∑
measurements
• Chi Modeling® computation service
SPE 94664
Cased Hole:
Open Hole:
Oh log
Mud log
Core
DST
Well Survey
Fl. Properties
Production
Injected fluid
Rock volumetric
Eff. Porositiy
Tot. Porosity
Vol. sandstone
Vol. limestone
Vol. dolomite
Vol. mineral
Bulk vol. water
Bulk vol. oil
TMD3DTM
Est. total gas
(C02 and N2)
Corrected C02
vol.
RMT-EliteTM
CO mode
Est. Oil vol.
Corrected vol.
RMT-EliteTM/
TMD3DTM
Signa
Est. mix water vol.
and salinity
Observe water and gas
flood pattern
Fig. 3. Example of evaluation workflow for a CO2 flood.
SPE 68713
SPE 88519
“Introduction Experiences of a New High Accuracy
Through-Tubing Pulsed Neutron Reservoir
Management Solution in Asia-Pacific,”
G.A. Simpson, P. Fox, N. Chafai, and J.A. Truax,
Halliburton, presented at the 2001 SPE Asia
Pacific Oil and Gas Conference and Exhibition,
April 17-20, Jakarta, Indonesia
“A Case Study of Carbon-Oxygen Logging
Through Multiple Tubular Strings Offshore
Indonesia: Reservoir Model Verification With
Emphasis of Fluid Contact and Bypass Oil
Identification,” M. Rourke, Halliburton Indonesia;
W.E. Prabowo and S. Winarti, ConocoPhillips
Indonesia Inc., presented at the 2004 SPE Asia
Pacific Oil and Gas Conference and Exhibition,
October 18-20, Perth, Australia
“Maximizing Net Present Value in Mature
Gas Lift Fields” O. Mora, and R.A. Startzman,
Texas A&M University; and L. Saputelli,
Halliburton-Landmark, presented at the 2005
SPE Hydrocarbon Exonomics and Evaluation
Symposium, April 3-5, Dallas, Texas
Formation Testing and Fluid Sampling
The objective of reservoir-fluid sampling is to
collect representative reservoir-fluid samples
using the minimum rig time. The Reservoir
Description Tool (RDTTM) modular, pumpout
wireline formation tester (PWFT) and fluid-sampling system uses multiple technologies
to collect representative reservoir-fluid samples;
reduce sample contamination; provide accurate,
reliable hydrocarbon and fluid typing; deliver
accurate pressure measurements, improved
permeability estimates; and provide high
reliability. A downhole pumping system drives
fluid from the reservoir through the tool past a
series of sensors that measure sample contamination and then into the borehole. Once an
acceptable contamination level is measured, a
sample of the fluid is captured. The Zero Shock
sampling mode is standard for all chambers,
but conventional sampling modes can also be
used (atmospheric and fluid cushioned). The
RDTTM system can monitor up to eight fluid
and formation properties, including: resistivity/
/ 99
capacitance; viscosity; density; bubblepoint;
compressibility; horizontal permeability; vertical
permeability; and anisotropy. The RDT tool
is capable of performing pressure-gradient
testing, permeability anisotropy testing, and PVT
sampling. A variety of test pads (Fig. 4), modules
and configurations are available to meet specific
testing or sampling requirements:
• A dual-port straddle packer section (SPS)
improves straddle-packer sampling performance and reduces sampling time.
• The Magnetic Resonance Imaging
Laboratory (MRILab®) fluid analyzer uses
NMR T1 and T2 fluid characterization at
in-situ conditions to monitor OBM-filtrate
contamination and to provide formation-
fluid identification and fluid properties.
• The new ICE CORESM Fluid Analysis Service has further enhanced the ability of system
to acquire clean reservoir fluid samples and
accurate fluid properties.
“Collecting Single-Phase Retrograde Gas Samples at
Near-Dewpoint Reservoir Pressure in Carbonates
Using a Pump-Out Formation Tester with an Oval
Pad,” C. Jones, and W. Alta, JOB Pertamina-Hess
Jambi Merang; J. Singh, B. Engelman, M. Proett
and B. Pedigo, Halliburton Energy Services,
Conference and Exhibition, November 11-14,
Anaheim, California
• The Zero Shock PVT method (steady-state
pressure, bubblepoint); dual-probe (DPS)
configuration for horizontal mobility and
permeability, kh, and anisotropy, kv/kh.
/ 100
“Fluid Sampling and Interpretation with the
Downhole NMR Fluid Analyzer,” R. Akkurt,
NMRPlus Inc.; C.-M. Fransson, J.M. Witkowsky,
W.M. Langley, Halliburton Energy Services; B.
Sun and A. McCarty, Chevron-Texaco, presented
at the 2004 SPE Annualt Technical Conference
and Exhibition, September 26-29, Houston, Texas
SPE 110831
• An elongated oval-shaped probe/pad
assembly provides the sealing advantages
of a straddle packer, thereby reducing the
drawdown pressure needed to establish flow
in tight or thinly laminated formations and
heterogeneous formations, such as fractured
or vuggy carbonates, where flow comes
from small features, while maintaining the
operational flexibility of a probe.
• A new high-resolution densitometer provides fluid-sample density, water salinity, and fluid compressibility, and quickly,
reliably identifies hydrocarbon and water in
mixed fluid samples.
SPE 90971
SPWLA 2008
Fig. 4. Examples of RDTTM formation-testing
configurations.
“Advances in Fluid Identification Methods Using
a High Resolution Densitometer in a Saudi
Aramco Field,” R. Palmer, A. Santos da Silva, A.A.
Al- Hajari: Saudi Aramco; B. Engelman, T. van
Zuilekom, and M. Proett: Halliburton, presented
Symposium, May 25-28, Edinburgh, Scotland, UK
Case STUDY:
RDTTM Oval Pad Enables Successful Acquisition of Fluid Samples in a Tight Reservoir
In the Asia-Pacific region, reservoir traps are typically stratigraphic and controlled by the
distribution of diagenetic secondary porosity in the low-permeability platform carbonates. The
operator drilled two exploratory wells in a retrograde gas reservoir to evaluate reservoir quality
and hydrocarbon fluid type. The heterogeneous carbonate reservoir is 700 to 1,000 ft thick with
a bottom aquifer drive and pressures near the dewpoint. Collecting and recovering single-phase
retrograde condensate fluid samples was a priority for formation evaluation and for laboratory
PVT analysis, to define a production strategy. Previous attempts to obtain representative samples
in this field were unsuccessful because the pumping drawdown was not maintained above the
dewpoint—allowing liquid condensation to occur in the pore system results in phase separation.
The plan was to keep the drawdown differential pressure at the sand face to 20 psi below the formation pressure to prevent unwanted phase separation (condensation). Extensive prejob planning
was conducted to optimize the tool string to achieve low differential pressure during pumping
and collection of single-phase samples. Based on the anticipated mobility, borehole overbalance
pressure, maximum allowable drawdown pressure, the RDTTM Oval Pad was selected for this
job over dual-probe or straddle-packer configurations because an extensive pressure survey was
planned in this well and straddle packers became fatigued and unusable after a limited number of
pressure tests and their use would require a number of trips. Estimates of flow, while maintaining
a 25-psi pressure differential, were 6 times higher with the Oval Pad, 3.75 cm3/sec, compared to
pinpoint-type probes, measurements of 0.6 cm3/sec. In these reservoirs, small changes in the heavy
carbon content dramatically affect the dewpoint, and preserving sample integrity is critical to the
samples. The MRILab tool section was used for analysis of fluid contamination and fluid typing.
In Well 1, selected data from 39 pressure tests yielded a gas gradient of 0.087 psi/ft. Two RDT
fluid samples were taken at X931 ft. Laboratory analyses demonstrated that the quality of the
samples was comparable to production-log DST bottomhole samples and an equation-of-state
PVT simulation demonstrated that the accuracy of the samples fell within the predetermined
error limits. The RDT Oval Pad configuration satisfied all the operational requirements, successfully acquired an accurate and representative reservoir fluid sample in a low-permeability
and heterogeneous reservoir, and reduced the rig time required for fluid sampling and pressure
testing (SPE 110831).
SPWLA 2008_OO
“The Challenge of Water Sampling with a
Wireline Formation Tester in a Transition Zone,”
N.M. Al-Musharfi, Saudi Aramco; M. Proett,
T. van Zuilekom, B. Engelman, and A. Rabbat:
Halliburton, presented at the 2008 SPWLA
49th Annual Logging Symposium, May 25-28,
Edinburgh, Scotland, UK
SPE 124032
“Improved Accuracy in the Measurement of
Downhole In-Situ Fluid Density,” L. Gao, T. van
Zuilekom, M. Pelletier, M. Proett, and M. Rourke,
Halliburton; and R. Palmer, A. Santos da Silva,
and A.A. Al-Hajari, Saudi Aramco, presented at
Exhibition, October 4-7, New Orleans, Louisiana
SPE 126036
“Improvements in Downhole Fluid Identification by
Combining High Resolution Fluid Density Sensor
Measurements and a New Processing Method:
Cases from a Saudi Aramco Field,” R. Palmer,
A. Silva, and G. Saghiyyah, Saudi Aramco; M.
Rourke, B. Engelman, T. van Zuilekom, and M.
Proett, Halliburton, presented at the 2009 SPE
Saudi Arabia Section Technical Symposium, May
9-11, Al-Khobar, Saudi Arabia
/ 101
SPWLA-2009
“Wireline and While-Drilling Formation-Tester
Sampling with Oval, Focused, and Conventional
Probe Types in the Presence of Water- and OilBase Mud-Filtrate Invasion in Deviated Wells,” A.
Hadibeik, University of Texas at Austin; M. Proett,
Halliburton Energy Services; C. Torres-Verdin,
K. Sepehrnoori, R Angeles, University of Texas
at Austin, presented at the 2009 SPWLA 50th
Annual Logging Symposium, June 21-24, The
Woodlands, Texas
SPE 133405
“Sensitivity of a High-Resolution Fluid-Density
Sensor in Multiphase Flow,” L. Gao, T. van
Zuilekom, M. Pelletier, M. Proett, S. Eyuboglu,
and B. Engelman, Halliburton; and H. Elshahawi
and M. Hows, Shell, presented at the 2010 SPE
September 19-22, Florence, Italy
SPWLA-2010
“Effects of Highly Laminated Reservoirs on the
Performance of Wireline and While-Drilling
Formation-Tester Sampling with Oval, Focused,
and Conventional Probe Types,” H. Hadibeik,
University of Texas; M. Proett, Halliburton;
C. Torres-Verdin, University of Texas; T. van
Zuilekom, B. Engelman, Halliburton; and K.
Sepehrnoori, University of Texas, presented
at the 2010 SPWLA 51st Annual Logging
/ 102
Case STUDY:
Halliburton RDT™ Tool Performs Multiple Functions in Single Downhole Run Helping
Operator Save 30 Hours of Rig Time
A global operator in the Middle East planned to produce from multistage laterals and needed to
know the minimum stresses for better well placement. The operator also planned to eventually
switch some field wells from producers to injectors and needed to know the frac gradient across
the reservoir—this required highly accurate data to determine optimal fracture initiation,
propagation and closure pressures. In place of conventional single-point fracture injections tests
performed at casing set points, Halliburton recommended the Reservoir Description Tool (RDT™)
tester and straddle packers, which can perform microfrac tests at multiple stations, providing accurate data for different zones within the well instead of a single average reading. Halliburton used
simulations to plan the job to cover all possibilities and set up a single toolstring with multiple
pumps and screens to mitigate tool plugging, enabling all testing and sampling to be performed
in a single run and minimizing risk in the openhole environment. The RDT tester has a unique
feedback control system that enables precise control of rates and pressures and also a 50% higher
efficiency than other testers. Halliburton performed two successful microfracs with the RDT/
straddle packer combination, achieved record pressure differentials, collected eight fluid samples,
obtained pressures at 38 points and conducted four pumpouts in a single run. The wireline
methods helped the operator save 30 hours of rig time for a total savings of at least 50% of the cost
of conventional Diagnostic Fracture Initiation Test (DFITSM) analysis. Based on the results, the
operator awarded Halliburton a second job that was completed with the same efficiency, accuracy,
and cost savings.
SPWLA-2010_QQQ
SPE 143084
“Formation Testing Goes Back to the Future,”
M. Proett, D. Welshans, K. Sherrill, J. Wilson, J. House, R. Shokeir, T. Solbakk, Sperry Drilling,
Halliburton, presented at the 2010 SPWLA 51st
Annual Logging Symposium, June 19-23, Perth, Australia
“Enhancing Gas-Reservoir Characterization
by Integrating a Reliable Formation-Testing
Permeability Method into the Workflow,”
J. Hernandez, E. Pacheco, and M.A. Proett,
Halliburton 2011 Brasil Offshore, June 14-17,
Macae, Brazil
SPWLA-2011
“A New Real-Time Contamination Method That
Combines Multiple Sensor Technologies,”
S. Eyuboglu, L. Gao, M. Pelletier, T. van Zuilekom,
and M. Proett, Halliburton, presented at the 2011
SPWLA 52nd Annual Logging Symposium, May
14-18, Colorado Springs, Colorado
SPE 152197
“A New Numerical and Analytical Approach for
Determining Formation Fluid-Sample Cleanup
Behavior Through Multiple Sensor Analysis,”
S. Eyuboglu, M. Proett, L. Gao, W. Sliman, R. Senne, B. Pedigo, and B. Engelman,
Halliburton, presented at the 2012 SPE Latin
America and Caribbean Petroleum Engineering
Conference, April 16-18, Mexico City, Mexico
SPE 164379
“A New Pressure Testing for Low-Mobility
Unconventional Formations: A Synthetic Case
Study Based on Field Data,” H. Hadibeik,
University of Texas at Austin, M. Proett, D. Chen,
S. Eyuboglu, Halliburton Energy Services; C.
Torres-Verdin, and K. Sepehrnoori, University
of Texas at Austin, presented at the 2013 18th
Middle East Oil & Gas Show and Conference,
March 10-13, Manama, Bahrain
Using Multivariate Optical Computing for
Downhole Fluid Analysis
Optimizing production, requires information
on reservoir fluid chemical composition and
fluid behavior to implement a production
plan that takes into account the reservoir-fluid
characteristics and mitigates potential corrosion
and flow assurance problems. Due to the complexity of the chemical constituents comprising
hydrocarbon fluids, accurate detection of these
components typically requires analysis of a large
number of wavelengths over a large spectral region. However, the performance of conventional
downhole optical fluid analyzers and the range
of detectable constituents are band-limited—only
a small fraction of the spectral data is used. In
addition, splitting the optical beam into its wavelength constituents decreases signal-to-noise
ratios (SNR) by orders of magnitude, limiting
the accuracy, sensitivity, and viable ranges of the
answer product.
Halliburton’s new ICE Core™ fluid-analysis
technology is a new downhole optical-sensor
platform designed for use with the Reservoir
Description Tool (RDT™) wireline formation
testing and sampling service that provides
laboratory-quality downhole optical analysis of in-situ reservoir fluids. The ICE Core technology uses a simple and reliable optical
system, multivariate optical computing (MOC),
and integrated computational element sensors
(ICE Core sensors). The ICE Core™ sensor
performs calculations within the multivariate
optical computer. Each ICE Core special
multilayer optical element is encoded with
predesigned information specific to a specific
chemical constituent, such as, methane, ethane,
propane, saturates, aromatics, or water. As reservoir fluids are pumped through a downhole fluid sampler, light is transmitted
through those fluids and sequentially through
a series of ICE Core sensors that rotate past the
light source (Fig. 5). The light intensity emerging from the ICE Core sensor varies with the
presence and proportion of the particular fluid
constituent for which the ICE Core sensor was
designed, providing real-time compositional
analysis of downhole fluids. The wide bandwidth of these optical elements combined with
their intrinsic, high SNR advantage enables laboratory-grade optical analyses downhole.
The compact and passive nature of the ICE
Core sensors results in high reliability. The ICE
Core fluid-analysis technology can analyze
multiple zones downhole, providing (1)
real-time lab results regarding fluid stratification in the reservoir, provides (2) a valuable
backup in case physical samples became lost or
damaged, and (3) allows the operator to make
decisions with a higher degree of confidence.
The current tool configuration is able to accept
up to 20 ICE Core sensors that currently provide concentration levels of methane, ethane,
/ 103
propane, saturate, aromatics, and GOR. ICE
Core sensors for detection of CO2, asphaltenes,
water and water chemistry, resins, and H2S
will be on the market soon. Consult your local
Halliburton wireline representative.
Core Acquisition
Core measurements, especially porosity and
drainage capillary-pressure measurements,
are important for estimating the reservoir
storage characteristics and for calibrating the
well-log-based petrophysical model in order
to optimize the completion. Trip-out time
with a conventional core barrel can be significantly longer than using a wireline-retrievable
system, and may result in a larger volume of
lost gas and fluids. Wireline-retrievable coring
(Latch-Les™ or RockSwift™ wireline-retrievable
coring systems) recovers cores without
tripping the entire drillstring and is ideal for
coring long sections and continuous coring.
Samples taken from whole core are preferred
because they allow all forms of testing—the
types of tests that can be conducted on wireline rotary sidewall (HRSCT™) samples and
drill cuttings are limited, although the data
derived from tests on sidewall cores are also
valuable in shale characterization. The recent
introduction of larger diameter (1.5 x 2.5 in.)
rotary sidewall-coring tools enables more tests
to be run on these samples (Fig. 6). Proper
handling and shipping of core is essential to
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Fig. 5. ICE CoreTM sensor provides real-time compositonal analysis of downhole fluids.
ensuring that laboratory measurements are
representative of in-situ reservoir conditions.
Halliburton’s Xaminer™ CoreVaultTM system,
available for both wireline-retrievable and rotary sidewall cores, is a sealed pressure
vessel that retains all rock and pore fluids
as the core is brought to surface. Subsurface
pressure may be restored through heating of
the pressure vessel during surface laboratory-
controlled fluid and rock transfer procedures.
Static rock mechanical properties can be
determined from well-logging data, i.e.,
crossed-dipole acoustic log data, and then
calibrated to core-analysis stress testing or
diagnostic fracture injection test (DFIT)
results. The DFIT data can come from SPIDR®
Self Powered Intelligent Data Retriever system
discussed earlier in this brochure under the
Individual Well Intervention section. The
orientation of the in-situ stress field along the
projected borehole path, from the surface to
SPE 163289
“Laboratory Quality Optical Analysis in Harsh
Environments,” C. Jones, B. Freese, M. Pelletier,
D. Perkins, D. Chen, J. Shen, and R. Atkinson,
Halliburton, presented at the 2012 Kuwait
International Petroleum Conference and
Exhibition, December 10-12, Kuwait City, Kuwait
Case STUDY:
Real-Time Downhole Fluid Analysis
Provides Laboratory-Quality Results
Recently, a customer used the new ICE
CoreSM fluid-analysis service to accurately
characterize reservoir fluids in-situ in four
deepwater wells offshore East Africa, all of
which contained extremely dry gas. The
average methane concentration obtained
for each well with the ICE Core technology
(97% ±1%) compared very favorably with
the average laboratory analysis (96.600%
± 0.003%). With the data gathered in East
Africa, the customer was able to begin
planning budgets, platforms, tubulars and
treatment facilities faster than ever before.
ICE Core technology is helping accelerate
the customer’s exploration and production
processes by compressing cycle time from
discovery to production (SPE 166415).
SPE 166415
“Field Tests of a New Optical Sensor Based on
Integrated Computational Elements for Downhole
Fluid Analysis,” K.O. Eriksen, Statoil Petroleum;
C. Jones, R. Freese, A. van Zuilekom, L. Gao, D.
Perkins, D. Chen, D. Gascooke, and B. Engelman,
Halliburton, presented at the 2013 SPE Annual
Technical Conference and Exhibition, September
30-October 2, New Orleans, Louisiana
Fig. 6. HRSCT tool showing the rotating carousel that allows increased core
capacity.
/ 105
TD, determines the potential for sloughing
and lost circulation. The magnitude and
orientation of these stresses on core samples it
is best determined from acoustic-anisotropy
analysis using crossed-dipole acoustic logs
(WaveSonic®, QBATSM, or XBATSM services)
or from fracture analysis of borehole images
(XRMITM or OMRITM tools). However, since
many wells lack dipole-acoustic logs and
borehole-image logs, a composite method
for determining rock mechanical properties,
using conventional well logs, was developed and
validated using core, available dipole-sonic log
data and stimulation-treatment pressure-history
matching. Applying this model to the design
of the drill-bits, drilling-fluid, wellbore-trajectory, and stimulation, helps to avoid borehole
stability issues and missing productive pay
zones, thereby reducing NPT and improving
production.
SPWLA 2013
“Field Test of the Integrated Computational
Elements: A New Optical Sensor for Downhole
Fluid Analysis,” C. Jones, L. Gao, D. Perkins, D.
Chen, and D. Gascooke, Halliburton, presented
Symposium, June 22-26, New Orleans, Louisiana
/ 106
SPE 123354
“Calibrated Log Model and Reservoir
Understanding Allows Accurate Prediction of
Production and Improved Hydraulic-Fracturing
Designs,” M. Garcia, M.J. Mullen, and A. James,
Halliburton, presented at the 2009 SPE Rocky
Mountain Petroleum Technology Conference,
April 14-16, Denver, Colorado
SPE 134559
“Integrating Core Data and Wireline
Geochemical Data for Formation Evaluation
and Characterization of Shale Gas Reservoirs,”
J. Quirein, J. Witkowsky, J. Truax, J. Galford,
Halliburton; and D. Spain, and T. Odumosu,
BP America, presented at the 2010 SPE Annual
19-22, Florence, Italy
Case STUDY:
Record-Setting Coring Job in
Colombia’s La Luna Shale
The Halliburton DBS team achieved 91%
recovery during the first RockSwift™ wireline-retrievable coring job on a gas well
in South America. The team, composed
of Baroid, Sperry Drilling (Surface Data
Logging), Wireline and Perforating, Drill
Bits and Services, recovered approximately 2,662 ft (811 m) of the 2,935 ft (895 m)
of full-diameter (3 in.) core that was cut,
despite challenges posed by actual well
conditions differing from the conditions
anticipated in the planning. The operator
pronounced it a record performance for
both the operator and the country and
advised Halliburton that it would be the
preferred service provider on an undetermined number of future projects.
SPE-108139
“A Composite Determination of Mechanical Rock
Properties for Stimulation Design (What to Do
When You Don’t Have a Sonic Log),” M. Mullen, R. Roundtree, Halliburton; and B. Baree Barree
and Associates, presented at the 2007 Rocky
Mountain Oil and Gas Technology Symposium,
April 16-18, Denver, Colorado
SPE 149128
“A New Wireline Rotary Coring Tool: Development
Overview and Experience from the Middle East,”
M. Rourke and J. Torne, Halliburton, presented
at the 2011 SPE/DGS Saudi Arabia Section
Technical Symposium and Exhibition, May 15-18,
Al-Khobar, Saudi Arabia
Field Re-Engineering
Considerations
Revitalizing mature fields involves energizing
the reservoir through a variety of methods: (1) water and polymer flooding; (2) maximizing
flood sweep by optimal placement of injectant
via horizontal wells, and chemical and mechanical (ICD) conformance solutions; (3) enhancing reservoir deliverability through
hydraulic fracturing techniques; and (4) improving artificial-lift systems.
IPTC 17337
“New Technologies for Optimizing Energy-Fluid
Input and Flow Assurance in Mature Assets,”
J.L. Mogollón, T. Lokhandwala, F. Crespo, C. Hein,
S. Rath, and L. Sayavedra, Halliburton, presented
at the 2014 International Petroleum Technology
Conference, January 20-22, Doha, Qatar
technology allows accurate location of structural events (faulting) and time-lapse seismic (4D)
surveys are used to monitor fluid movement
over time (including flood fronts), to reinterpret geological structures, and to quantify
changes in reservoir properties that may occur
over years of production, such as, pore pressure.
Time-lapse seismic data that have been fully
calibrated with well-log information are used
to generate 3D maps that, in turn, enable
quantitative improvement in the reservoir
models used to optimize reservoir management
(i.e., improving flood efficiency). Accurate 3D
and 4D seismic maps facilitate identification
of (a) the locations and the volume of fluid
changes in producing reservoirs, (b) bypassed
pay, (c) areas of breakthrough in enhanced oil
recovery projects, (c) and accurate positioning
of infill wells. Reducing the risks associated
1988 Post-stack Seismic
with drilling and precise placement of new
wells results in fewer nonproductive wells and
improved field economics.
Halliburton offers advanced seismic software
technology for reservoir characterization,
including, 3D and 4D seismic and new
measurement, tomographic, and visualization
techniques:
• ProMAX® 4D - Image the seismic response to
changes in the reservoir over time to isolate
changes in reservoir from acquisition noise
and signature in multiple vintage seismic data. • DecisionSpace® Geophysics/Geology -.Allows
users to leverage prestack seismic attributes to
monitor pressure and saturation differences
over time; and to model and predict pressure/
saturation curves to predict 4D effects. 1998 Reprocessed
Pre-Stacked Seismic
1998 Far Offset Volume
Seismic Reassessment
Improved seismic technology and data processing/reprocessing and analysis/interpretation
techniques can facilitate development and
design of EOR projects in mature oil fields.
Reprocessing older seismic that used post-stack
migration techniques using newer prestack migration techniques can improve the
resolution enabling identification of new fault
blocks and/or bypassed pay (Fig. 1). 3D seismic
Fig. 1. Reprocessing older seismic data using newer methods, i.e., Kirchoff prestack time migration, dramatically improved seismic data quality. The anomaly at right contained more than 100 Bcf of gas.
/ 107
> Field Re-Engineering Considerations
• GeoProbe® - Allows multiple volume/multiple vintage interpretation • DecisionSpace® Earth Modeling - Facilitates
asset modeling through life of field. • OpenWorks® - Manages massive amounts
of multiple vintages of 4D seismic data,
interpretations, and reservoir models.
IPTC 15352
“Examples of 4D Studies from Kuwait,”
A. El-Emam and W. Zahran, Kuwait Oil
Company, presented at the 2012 International
Petroleum Technology Conference, February
7-9, Bangkok, Thailand
IPTC 16910
SPE 109336
“The Marlim Field: Incorporating 4D Seismic in
Reservoir-Management Decisions,” R.M. Oliveira,
Petrobras, Journal of Petroleum Technology,
60(4), 52-53, 107-110, 2008
“Estimating Saturation Changes from 4D Seismic:
a Case Study from Malay Basin,” R. Pathak, and
R. Bakar, Petronas Carigali Sdn Bhd, presented
at the 2013 International Petroleum Technology
Conference, March 26-28, Beijing, China
SPE 122734
IPTC 17047
4D: From Mainstream to Main Street,”
S.A. Levin, Halliburton Energy Services, presented at the 2009 SPE Digital Energy Conference
and Exhibition, April 7-8, Houston, Texas
“Intensive Use of 4D Seismic in Reservoir
Monitoring, Modeling and Management: the
Dalia Case Study,” E. Pluchery, S. Toinet, P. Cruz,
A. Camoin and J. Franco; TOTAL EP ANGOLA,
presented at the 2013 International Petroleum
Technology Conference, March 26-28, Beijing, China
SPE 135007
“4D Reservoir Monitoring and Characterizing
of Marimbá Field, Offshore Brazil,” K.T.P. Lima,
V.M. Reis, and S.R. Malagutti, Petrobras, presented at the 2010 SPE Annual Technical Conference
and Exhibition, September 19-22, Florence, Italy
/ 108
Accurate, Robust, and Fast Simulation of the
Total Asset
Accurate prediction of asset deliverability often
requires modeling of the reservoirs, wells, and
surface facilities as a single integrated system.
This enables the engineer to assess total asset
deliverability from the reservoir through point of
sale. Traditional reservoir modeling approaches
solve surface and subsurface networks separately,
then iterate to convergence. Nexus® reservoir
simulation software enables asset teams to
integrate simulation of multiple reservoirs, with
wells and a common surface facilities network to
model the total asset simultaneously (Fig. 2). This
provides a more robust, more accurate, and faster
Fig. 2. Nexus® reservoir simulation software
integrates, reservoir, well, and surface
facilities to model the total asset.
Fig. 3. The Dynamic Frameworks to Fill® workflow delivers a “step change”in map-making efficiency.
reservoir simulation—Nexus software is an average of five times faster than other commercial
solutions. Nexus reservoir simulation software
works directly with DecisionSpace® reservoir
models, eliminating the need for additional grid
processing prior to a simulation run The software's unique volume balance formulation and
cuts down on iterations without any fine-tuning,
and the unstructured solver dramatically reduces
processing cycles for even the most complex
reservoirs. The tightly coupled network model
is combined with a flexible macro language
that allows changes to the well and network
configuration on-the-fly to quickly predict and
understand asset performance. Nexus software
can predict how facilities sharing across multiple
reservoirs will affect the ultimate performance
of each, and thus eliminate unnecessary facility
upgrades from asset development plans.
Landmark’s DecisionSpace Base module is the
enabling technology for consolidating disparate
applications and workflows into a single
workspace where a shared subsurface model
may be viewed and analyzed. DecisionSpace
software provides the ability to visualize, analyze,
interpret, plan field development and simulate
the surface and subsurface in 1D/2D/3D, which
assist members of an asset team. Well-log
correlations may be validated against seismic
backdrops, earth models may be validated
against well-log data and seismic sections, field
development scenarios may be modeled in
context of the earth model. The ability to easily
access and aggregate all relevant data in context
in a single view improves decision making.
The DecisionSpace module is tightly integrated
with OpenWorks data management software
and includes the Dynamic Frameworks to Fill®
software, which defines how fault and horizon
boundaries relate to one another in a sealed
framework. Data are independently gridded in
the context of individual fault-block domains,
projected into the fault planes, and truncated
(Fig. 3). High-resolution sealed frameworks can
be built quickly using tops, seismic, and conformance technology. The software dynamically
updates the shared framework as interpretations
of new data are made resulting in faster and more
efficient geologic interpretations. The Dynamic
Frameworks to Fill® workflow includes:
• Fault networking, unconformity trimming,
and auto-generation of fault polygons
• Automatic integration of faults and
unconformities
• Interactive horizon clean area and intersection
editing
• Property mapping from interval and log data
and use of framework to define intervals
Presentation-quality maps for all layers and
properties are a byproduct of the sealed framework and can be created in minutes without
manual fault-polygon digitizing and regridding.
/ 109
Studies indicate that as much as 60% of the
initial oil-in-place in an oilfield may remain
after secondary recovery. The EOR market is
large and growing in importance as (a) more
fields move into the mature phase, (b) fewer
new fields are discovered, (c) global demand
for oil continues to increase, (d) oil prices
remain high, and (e) with development of
more efficient and cost-effective EOR methods. Implementation of improved oil recovery
(IOR) and enhanced oil recovery (EOR)
methods can increase the ultimate recovery
factor by 5 to 15%. Substantial production
increases are anticipated over the next 10
years for each of the three primary categories
of EOR: thermal, gas (CO2) and chemical. The
drivers for more EOR-based production are
the global need for oil and the limited supply
available due to declining production and the
low rate of new discoveries. Market dynamics
and drivers are not expected to change
significantly over the next eight years, until
the year 2021.
Global production as a result of EOR techniques doubled over the five years from 2007
to 2011, from 790 to 1,556 million barrels
of oil. Currently 3% of current worldwide
production is now attributable to EOR—by
2021, it is estimated that 46% of worldwide
/ 110
production will be attributable to EOR. The
U.S., Canada, and China are the largest EOR
markets, accounting for 57% of total EORassociated oil production. In the U.S. EOR
expenditures have increased from $20 to $23
billion USD since 2010 and have experienced
an annual growth rate of 7% (Fig. 4).
Gas EOR (carbon dioxide flooding), relies on
the availability of large volumes of low-cost
naturally occurring CO2, and has been limited
primarily to the U.S. where large supplies
of CO2 are available. It accounts for 43% of
global EOR production. In recent year, the
growing movement to reduce CO2 emissions
is resulting in combining carbon capture and
storage (CCS) technologies with CO2 EOR
and is helping to drive the gas EOR market
both in the U.S. and elsewhere. Thermal EOR,
which includes cyclic steam injection and
steam-assisted gravity drainage (SAGD) to
extract oil from heavy-oil reservoirs and oil/
tar sands, accounts for 20% of global EOR
production. Chemical EOR has become more
cost effective and efficient with improvements
in the molecular structures of polymers
Sales ($bn)
Waterflood and EOR Engineering
Justification
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
Year
Fig. 4. Projected expenditures by oil companies on EOR-related projects 2010-2021.
2020
2021
Planned High Price NPV
Unplanned High Price NPV
Planned Exp. Price NPV
Unplanned Exp. Price NPV
25000
Jun-20
Dec-25
Jun-31
Month and Year
SPE 165304
Nov-36
Production Rate (BBL/YR)
Timely decisions are critical in a mature field
because there are often windows of opportunity
to take some action before conditions in the
reservoir decline to a point where value cannot
be recaptured. These scenarios could include if
no action is taken before a reservoir reaches the
bubblepoint pressure, or when an asset team
takes no action before reductions in pressure
cause the precipitation of asphaltenes. Two
elements that can improve rapid and timely
decision making in mature fields include:
NPV (MM$)
and surfactants and a number of large-scale
projects, particularly offshore, are scheduled to
come into operation over the next few years.
• The ability to rapidly forecast production and
recovery increases from the application of
new technologies.
Enhanced oil recovery projects, are strongly
influenced by economics and long-run crude
oil prices. EOR investment decisions are heavily
impacted by (a) the timing of the switch from
primary recovery to waterflooding, and then
(b), the timing of the switch from waterflooding
to tertiary oil recovery (Fig. 5). There are two
Planned EOR
Unplanned EOR
15000
10000
5000
0
• Advanced reservoir and well surveillance
capability combined with the ability to efficiently act upon the insights gained from
the captured well and production reservoir
data.
Primary Production
20000
8/14/2013
10/31/2021
1/17/2030
4/5/2038
Time (Years)
Fig. 5. Starting 3 years earlier an EOR project increases NPV by 29 to 35 %: timely planning and fast
deployment are keys for bigger success.
distinctly different approaches for making EOR
switching decisions: designing EOR up front vs.
implementation as the field matures. The first
approach embraces proactively designing and
executing EOR during the initial development
of a field. The second approach bases switching
decisions on the conditional indicators of the
reservoir, coupled with a view toward the longrun oil price.
/ 111
> Waterflood and EOR Management
Waterflood and
EOR Management
In mature reservoirs secondary recovery
techniques, such as water injection (waterflooding) or artificial-lift technologies, such
as Halliburton electrical submersible pumps,
linear-lift systems, or foam assisted-lift are used
to manage pressure and generate additional
hydrocarbon production. Halliburton works
with operators to review existing data and measure pressure to discover key factors causing
pressure drop and underperformance in your
reservoir. We then identify the right approach
for revitalizing a mature field through application of new technologies, pressure maintenance
schemes, and predicting future performance
using geologic and simulation models.
Optimized full field design
deployment
Optimized pilot design
and execution
Reservoir characterization
and model building
Estimation of value promise
for all EOR-reservoir
sound combination
Fig. 1. Halliburton’s integrated EOR solutions
cover risk estimation and mitigation, probabilistic estimates and optimization by numerical
algorithms.
/ 112
Halliburton offers integrated solutions, covering the entire range of EOR and secondary
recovery, from the appraisal until project
abandonment, which are keys to success.
Water for secondary recovery processes
may require treatment for clarification and
compatibility. Halliburton’s H2O ForwardSM
water-management program is a cost-effective
customer solution that combines chemistry and
innovative, engineered technology to manage
and treat produced water from EOR processes
as well as providing specification-ready water
for such processes. The ability to treat flowback
and produced water or for reuse in service operations can help improve operator profitability and contribute to water conservation.
Halliburton provides the sophisticated understanding necessary to get the most from EOR:
• An integrated approach to the way wells are
planned, drilled, completed, and produced
• Development of “intelligent solutions” that
take a long-term view of the life of the well
• Application of “intelligent well” technology
that facilitates better production management
• EOR specific fluids for pre and post treatment
• Water-management solutions for recycle
and supply of EOR feed water helps provide
better process results
Visiongain
“The Enhanced Oil Recovery (EOR) Market 20132023: Thermal, Gas, and Chemical Production,”
Visiongain (UK), April 25, 2013
SPE 165304
“A Discussion of Different Approaches for Managing
the Timing of EOR Projects,” L. Sayavedra, Jr.,
J.L. Mogollon, M. Boothe, T. Lokhandwala, and
R. Hull, Halliburton, presented at the 2013 SPE
Enhanced Oil Recovery Conference, July 2-4,
Kuala Lumpur, Malaysia
Intelligent Production / Real-Time Flooding
Optimizer
Surveillance in one form or another has been
around the oil and gas industry for many years.
The scope was initially limited to a manual
process using individual engineering and business applications to evaluate a limited number
of wells based either on their value or their
trouble status. At one time, a hardcopy report,
monthly target, production number, downtime,
and operating expenses were adequate for
our needs. Data were gathered by hand and
manually manipulated before presenting them
to operations managers. If a problem was identified, engineers performed an analysis based
on their experience and judgment using the
tools at hand. Because resources were limited,
only the most important wells, or those with
serious problems, could be studied, and even
this examination often lacked depth and many
opportunities to achieve improved performance
and risk reduction were missed or bypassed.
More recently, major improvements in
surveillance, including more engineering and
operations content, have introduced to oil and
gas production. Mature fields have implemented
sophisticated monitoring centers that feed data
into real-time displays, enabling operations staff
to see the status of key measurements. Today,
surveillance includes advanced analytics, expert
systems, and process automation, combining
business or operational intelligence with automated technical calculations. The result is a new
generation of hybrid solutions incorporating
elements of “data-driven” methods, including
management by exception (MBE), business intelligence (BI), and situational awareness (SA) with
“model-driven” techniques, such as model-based
Decision
Frequency
Optimization
Scale
Short - Term
(Monthly)
Zone - Wellbore
- PatternReservoir
decision support (MBDS), advanced process
control (APC), and consequential analysis (CA).
State-of-the-art information technology tools
are used to enable more efficient traditional
processes, build single-purpose workflow applications, and deploy fully automated intelligent
systems using the latest automation, models, and
control systems. The goal of future surveillance
systems should be to replace monitoring wells
against a target, with managing production assets
against their potential in a safe, environmentally
responsible way
Traditional surveillance tools use offline data
that allow users to view, relate, and analyze
reservoir and production data with interactive
base maps/plots with production trends, bubble
plots, diagnostic plots, decline curve analysis,
and type curve analysis. Because resources
were limited, only the most important wells, or
those with serious problems, could be studied,
and even this examination often lacked depth
Optimization
Goals
Predictive Optimization
Advisory with 'Tangible Actions'
Optimized injection settings for:
Medium - Term
(Monthly to quarterly)
• Pattern injection rates
• Maximizing Field Recovery
Optimized production setters for:
• Increasing Production
• Surface chokes (conventional wells)
and Smartwell ICVs
• Reducing Water Production
Near Term Field Development Advisory:
• Identifying opportunity for new wells
and plans.
Fig. 2. Intelligent production focuses on different time spans and scales.
and many opportunities to achieve improved
performance and risk reduction were missed
or bypassed. Today, surveillance means
monitoring in real time to prevent undesired
events by taking the appropriate action to
reduce equipment malfunction/downtime
and nonproductive time (NPT). Integrating
different disciplines to work in a real-time
environment presents considerable challenges
that must be addressed to meet surveillance
requirements for today's production operations. The transformation of raw data into
information is achieved through intelligent,
automated work processes, referred to here as
"smart flows," which assist engineers in their
daily well-surveillance activities, helping make
them more productive and improve decision
making with the ultimate goal of improved
asset performance. Intelligent digital-oilfield
operations include the transfer, monitoring,
visualization, analysis, and interpretation of
real-time data. Enabling this process requires
a significant investment to upgrade surface,
subsurface, and well instrumentation and also
the installation of a sophisticated infrastructure
for data transmission and visualization. Once
upgraded, the system has the capability to
transfer massive quantities of data, converting it
into real information at the right time.
Landmark provides a range of services
that help clients maximize the use of their
/ 113
Case STUDY:
A Major Operator and Landmark Consulting & Services Revitalize a 30-Year Old Field in the Gulf of Mexico
Discovered in 1966, an offshore Gulf of Mexico field had produced
approximately 1 Tcf of natural gas by the mid-1990s. However,
production had dropped to about 15 MMcfg/D, which was
approaching the economic threshold and due to poor financial
performance the field was designated a noncore asset. The
field contained multiple pay zones and the operator decided to
re-evaluate the field’s remaining potential rather than divest the
property. A 10-year old speculative 3D seismic survey over the area
was available. To supplement internal limited manpower and to
introduce new and evolving technologies into this mature field, the
operator approached Landmark’s consulting group and formed an
integrated asset team for the project. During the initial assessment,
the team reprocessed the existing 3D seismic—the original data
had been post-stack processed—using more-advanced algorithms
(Kirchhoff prestack time migration) to validate proposed locations
and determine if additional reservoirs could be developed. The
higher quality of the reprocessed data enabled the team to accurately
image another fault, roughly parallel to the main field fault, forming
a previously hidden fault block in which three productive pay
zones were identified. AVO analysis on the far-offset volume, using
prestack gathers, allowed them to quickly scan the dataset for solid
technology assets. Our consultants deliver
application implementation, deployment,
on-site mentoring, and education programs. In
addition, innovative technologies, key industry
partnerships, and highly experienced domain
experts allow Landmark Services to deliver
solutions that optimize clients’ existing assets
/ 114
leads, many of which turned into drillable prospects. One new fault
block contained 107 Bcf of gas. In one case, in-depth analysis helped
the team avoid drilling an unnecessary and expensive well, saving $3
million USD in operational costs.
Application of two new and evolving drilling and completion technologies also contributed to success in this mature Gulf of Mexico
field. The team decided to set expandable casing above the depleted
sands—the first use of this technology in the Gulf of Mexico. The
well started with a conventional hole, 7-5/8 × 8-5/8 in. expandable
liner was set above the depleted sands, the mud weight was reduced,
and the well drilled out with an 8-1/2 in. borehole; reducing drilling
dollars without sacrificing the optimal hole size at TD. Thru-Tubing
FracPac™ treatment—normally a recompletion procedure for lowrate wells—was employed as a primary completion technique for
high-rate wells, reducing costs and improving field economics—one
well produced 20 MMcf/D. During the five-year project 18 wells
were drilled, 17 of which were commercially successful and production increased by more than 800%, to approximately 180 MMcf/D
(Fig. 3). Revitalization returned this mature asset to among the
operator's best producing properties in the Gulf.
and enable anywhere, anytime collaboration.
These services include intelligent operations
solutions, water management innovations, IT/
data management, and cloud hosting services
to support clients’ national or global workforces
to help in Waterflood and EOR operations.
SPE 139376
“Marlim Field: An Optimization Study on a
Mature Field” D. Bampi, O.J. Acosta, Halliburton,
Carribean Petroleum Engineering Conference,
December 1-3, Lima, Peru
Fig. 3. Collaborative teamwork between an
operator and Landmark’s Consulting &
Services group and the introduction of new
and evolving technologies increased production in a mature GOM field by more than 800%
over five years.
SPE 134586
“Casing Drilling Application with Rotary
Steerable and Triple Combo in New Deviated
Wells in La Cira Infantas Field,” E. Lopez, P.
Bonilla, Occidental de Columbia; A. Castillo,
Halliburton; and J. Rincon,Tesco, presented at
Exhibition, September 19-22, Florence, Italy
Intelligent Completions
A Halliburton SmartWell® completion
system optimizes production by collecting,
transmitting, and analyzing completion,
production, and reservoir data; allowing
remote selective zonal control. Selective zonal
control enables effective management of water
injection, gas and water breakthrough, and
individual zone productivity thereby helping
to increase reservoir efficiency and ultimate
recovery. The ability to produce multiple
reservoirs through a single wellbore reduces the
number of wells required for field development,
thereby lowering drilling and completion costs.
Managing water through remote zonal control
reduces the size and complexity of surface
handling facilities.
Managing Fluids
Flow control solutions include interval control
devices (ICD). Halliburton’s EquiFlow®
autonomous inflow control device (AICD) is
a simple, reliable and cost-effective solution
designed to improve completion performance
and efficiency by delaying the production
of unwanted fluids from high-productivity
zones throughout the length of a horizontal
completion. The EquiFlow AICD uses no
moving parts, does not require intervention
from the surface or downhole orientation and
uses the dynamic properties of the fluid to
direct flow. Using the principals of dynamic
fluid flow, the EquiFlow® AICD increases flow
resistance in the presence of water or gas by
choking back production of unwanted fluid
Case STUDY:
Revitalization of a Mature Middle
East Field Through an Intelligent
Production Project
The operator, was seeking to revitalize
a mature field in the Middle East by
managing the 200+ well field at the asset
level, increasing the recovery factor,
reducing the water cut, reducing NPT.
Collaboration between Halliburton
Consulting & Project Management,
Landmark, WellDynamics, and Pinnacle,
delivered an integrated solution that
consisted of 10 automated collaborative
workflows via the OSP technology
allowing the operator to optimize field
operations. Production increased by 7%
from first well in 2 months; the recovery
factor increased from 8 to 40%, the water
cut decreased from 56 to 20%, NPT
was reduced by 30%, and a 15% overall
improvement was generating a savings of
$30,000 USD/month.
without the need for electrical, hydraulic, or
mechanical intervention, thereby maximizing
oil production. The AICD works like a passive
ICD during oil production but restricts the
production of water and gas at breakthrough
to minimize water and gas cuts dramatically.
The EquiFlow® AICD is easy to install as part of
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the completion string and is highly beneficial
for any well in which production needs to be
balanced over long horizontal reservoirs or in
formations with high permeability variances.
The EquiFlow® AICD is extremely effective
when combined with zonal isolation systems,
such as Halliburton’s Swellpacker® isolation
systems. Installed as a unit at the end of each
screen joint, in unconsolidated reservoirs.
The EquiFlow® AICD can be configured for a
specific reservoir, yet it is simple, robust, and
easily combined with all types of sand-control
screens. Typical applications include wells
experiencing “heel-toe” effects, water or gas
breakthrough, permeability differences, and
water or gas challenges dealing with horizontal
or layered reservoirs.
Listed are some of the waterflood and EOR
papers Halliburton has developed to address
various issues.
SPE 125788
SPE 137133
“Openhole ICD Completion With Fracture
Isolation in a Horizontal Slimhole Well: Case
Study,” D. Young, M. Al-Muraidhef, and P.E.
Smith, Halliburton; and M.Z. Awang, Saudi
Aramco, presented at the 2009 SPE/IADC
Middle East Drilling Technology Conference and
Exhibition, October 26-28, Manama, Bahrain
“Method to Improve Thermal EOR Performance
Using Intelligent Well Technology: Orion SAGD
Field Trial,” H.P. Clark, F.A. Ascanio, C. Van
Kruijsdijk, J.L. Chavarria, M.J. Zatka, W. Williams, A. Yahyai, Shell; J. Shaw, and
M. Bedry, Halliburton, presented at the 2010
Canadian Unconventional Resources &
International Petroleum Conference, October
19-21, Calgary, Alberta, Canada
SPE 126446
“Industry Experience With CO2-Enhanced
Oil Recovery Technology,” R.E. Sweatman,
Halliburton; M.E. Parker, ExxonMobil; and S.L.
Crookshank, American Petroleum Institute, presented at the 2009 SPE International Conference
on CO2 Capture, Storage, and Utilization,
November 2-4, San Diego, California
SPE 137834
“New Approach and Technology for CO2 Flow
Monitoring and Remediation,” R. Sweatman,
Halliburton; S. Marsic and G. McColpin,
Pinnacle – A Halliburton Service, presented at
the 2010 Abu Dhabi International Petroleum
Exhibition & Conference, November 1-4, Abu
Dhabi, UAE
SPE 127072
SPE 120509
“Waterflood Recovery Optimization using
Intelligent Wells and Decision Analysis,”
L. Saputelli, Hess Corporation; K. Ramirez, J. Chegin, and S. Cullick, Halliburton. Presented
at the 2009 SPE Latin American and Caribbean
Petroleum Engineering Conference, May
31-June 3, Cartagena, Colombia
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“North Kuwait Miscible Gas EOR Study,”
M. Al-Ajmi, E. Al-Anzi, H. Al-Anzi, Kuwait Oil
Company; O. Karaoguz, Halliburton; A. Al-Ghadban, B. Baroon, A.A. Al-Dhuwaihi,
B. Al-Otaibi, Kuwait Oil Company, and H. Wigg,
Halliburton, presented at the 2010 SPE EOR
Conference at Oil & Gas West Asia, April 11-13,
Muscat, Oman
SPE 138258
“Advancements in Technology and Process
Approach Reduce Cost and Increase Performance
of CO2 Flow Monitoring and Remediation,” R.E.
Sweatman, Halliburton; S.D. Marsic, and G.R.
McColpin, Pinnacle, presented at the 2010
International Conference on CO2 Capture,
Storage, and Utilization, November 10-12, New Orleans, Louisiana
OTC 21984
SPE 147543
SPE 150071
“Outlook and Technologies for Offshore CO2
EOR/CCS Projects,” R. Sweatman, Halliburton;
S. Crookshank, American Petroleum Institute;
and S. Edman, ConocoPhillips, presented at the
2011 Offshore Technology Conference, May 2-5,
Houston, Texas
“Using a New Intelligent Well Technology
Completions Strategy to Increase Thermal
EOR Recoveries–SAGD Field Trial,” J. Shaw,
and M. Bedry, Halliburton, presented at the
2011 Canadian Unconventional Resources
Conference, November 15-17, Calgary, Alberta,
Canada
“The Future of Surveillance,” M.J. Lochmann,
Halliburton, presented at the 2012 SPE Intelligent
Energy International Conference, March 27-29,
2012, Utrecht, The Netherlands
SPE 140845
“Improvements to Hydrophobically Modified
Water-Soluble Polymer Technology to Extend
the Range of Oilfield Applications,” L. Eoff,
International Symposium on Oilfield Chemistry,
April 11-13, The Woodlands, Texas, USA
SPE 147375
“Comparison of Oil Recovery by Low Salinity
Waterflooding in Secondary and Tertiary Recovery
Modes,” P. Gamage, University of Wyoming (now
with Halliburton) and G. Thyne, University of
Wyoming, presented at the 2011 SPE Annual
Technical Conference and Exhibition, October
30-November 2, Denver, Colorado
SPE 141031
“Carbon Dioxide, Geochemical, and Rateof-Dissolution Simulation for Deep Storage
Environments,” I. Ceyhan, Blade Energy Partners,
Ltd; A. Santra and A.S. Cullick, Halliburton,
presented at the 2011SPE International
Symposium on Oilfield Chemistry, April, 11-13,
The Woodlands, Texas
SPE 147410
“Evaluation of the Effect of Low Salinity
Waterflooding for 26 Fields in Wyoming,”
G. Thyne, and P. Gamage University of Wyoming
Enhanced Oil Recovery Institute, presented at
Exhibitionm October 30-November 2, Denver, Colorado
CMTC 150980
“New Technology for Offshore CO2 Reservoir
Monitoring and Flow Control,” R. Sweatman,
E. Davis, E. Samson, G. McCopin, S. Marsic,
Halliburton, presented at the 2012 Carbon
Management Technology Conference, February
7-9, Orlando, Florida
SPE 164815
“Coupling Reservoir and Well Completion
Simulators for Intelligent Multi-Lateral Wells: Part
1,” G.A. Carvajal, N. Saldierna, M. Querales, K. Thornton, and J. Loiza, Halliburton, presented
at the 2013 EAGE 75th Conference & Exhibition
incorporating SPE EUROPEC, June 10-13,
London, United Kingdom
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SPE 165305
SPE 167327
SPE 167398
“Injection and Production Profile Modification for
Enhanced Oil Recovery: Mechanical or Chemical
Methods?,” A.S. Kim, K.V. Thornton, and M.L.
Boothe, Halliburton, presented at the 2013 SPE
Enhanced Oil Recovery Conference, July 2-4,
Kuala Lumpur, Malaysia
“Value Generated Through Automated Workflows
Using Digital Oilfield Concepts: Case Study,”
B.A. Al-Enezi, M. Al-Mufarej and E. Anthony,
Kuwait Oil Company; G. Moricca, J. Kain, and
L. Saputelli, Halliburton, presented at the 2013
SPE Kuwait Oil and Gas Show and Conference,
October 7-10, Kuwait City, Kuwait
“Automated Workflows to Monitor, Diagnose,
Optimize, and Perform Multi-Scenario Forecasts
of Waterflooding in Low-Permeability Carbonate
Reservoirs (a KwIDF Project),” P. Ranjan, G.A.
Carvajal, H. Khan, R. Vellanki, L. Saputelli, F. Md
Adan, M. Villamizar, S. Knabe, and J.Â Rodriguez,
Halliburton; A. Al-Jasmi, H. Nasr, B. Al-Saad
and A. Pattak, Kuwait Oil Company, presented
at the 2013 SPE Middle East Intelligent Energy
Conference and Exhibition, October 28-30,
Dubai, United Arab Emirates
SPE 166051
“Multi-Objectives Constrained Waterflood
Optimization in Tight Carbonates,” H. Khan,
Halliburton; L.A. Saputelli, Frontender
Corporation; G.A. Carvajal, P. Ranjan, F. Wang,
S.P. Knabe, Halliburton, presented at the 2013
SPE Reservoir Characterisation and Simulation
Conference and Exhibition, September 16-18,
Abu Dhabi, UAE
SPE 166343
“Offshore Polymer/LPS Injectivity Test with Focus
on Operational Feasibility and Near Wellbore
Response in a Heidrun Injector,” O.M. Selle, H. Fischer, D.C. Standnes, I.H. Auflem, A.M. Lambertsen, and P.E. Svela, Statoil;
A. Mebratu, E.B. Gundersen, and I. Melien,
Halliburton, presented at the 2013 SPE Annual
30-October 2, New Orleans, Louisiana
SPE 167393
“Building Neural-Network-Based Models Using
Nodal and Time-Series Analysis for Short-Term
Production Forecasting,” J. Rebeschini, M.
Querales, G.A. Carvajal, M. Villamizar, F. Md
Adnan, J. Rodriguez, and S. Knabe, Halliburton;
F. Rivas, Universidad de Los Andes; L. Saputelli,
Frontender Corp; A. Al-Jasmi, H. Nasr, and H.K.
Goel, Kuwait Oil Company, presented at the 2013
SPE Middle East Intelligent Energy Conference
and Exhibition, October 28-30, Dubai, United
Arab Emirates
As wells and fields mature and undergo secondary and tertiary recovery, proper
reservoir management requires field-wide
surveillance to monitor flood (sweep)
efficiency, periodic re-evaluations of well
performance, and determine and provide the
sources of water production.
Time-lapse seismic (4D) surveys can monitor
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SPE 163082
“Improving Reservoir Monitoring in EOR
Environments Using Microdeformation-Based
Technologies,” S. Marsic, W. Roadarmel, M. Machovoe, and E. Davis, Pinnacle—A
Halliburton Service, presented at the 2011 SPE
Western Venezuela Section South American Oil
and Gas Congress, October 18-21, Maracaibo,
Venezuela
fluid movement over time, including flood
fronts, and are used to help determine sweep
efficiency, identify areas of breakthrough,
information that is need to improve flood efficiency (optimizing reservoir management) and
ultimate recovery. Calibrating the seismic data
to well-logs facilitates quantitative improvement
in reservoir models allowing identification
of bypassed oil and gas and more accurate
A
Yo= 45%
Yw= 55%
A
B
Yo= 40%
Yw= 60%
B
C
Yo= 32%
Yw= 65%
C
D
Yo=
0%
Yw= 100%
D
Fig. 4. In deviated wells, gravity causes separation and stratification of fluid flow into the different phases−lighter fluids move to high side and heavy fluids to low.
Here, Zone D shows very high water holdup, while Zone C shows increasing oil holdup and the beginning of fluid stratification. Depending on the velocity of the flow,
the interface between oil and water may be well defined or irregular. Multiple-sensor tools that provide continuous cross-sectional holdup measurements of all fluid
phases are necessary to ensure reliable measurements in these wells because a single, centered sensor may not “see” each of the fluid phases.
positioning of infill wells. Reducing the risks
associated with accurate placement and drilling
of new wells results in fewer nonproductive wells
and improved field economics.
Microdeformational (tilmeter) monitoring,
which provides high-resolution measurements
of changes in elevations, allows accurate
characterization of ground deformation patterns
that are associated with steam flooding, cyclic
steam stimulation, and steam-assisted gravity
drainage (SAGD), as well as CO2 sequestration
(CCS). Integration of tiltmeter measurements
with other microdeformational measurements,
i.e., InSAR, and differential GPS data, results
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in well-characterized strain measurements that
can be interpreted (via mathematical inversion)
and used to identify and illustrate reservoir-level
changes.
Sweep efficiency is enhanced by conformance
(water control) technology. Production logging
and other methods, such as, permanent
monitoring with fiber-optic sensors, called
distributed temperature sensors (DTS), can
identify variations in injection and production
flows in the perforated zone. When significant
differences are found, conformance technology
is applied to seal or reduce the formation relative
permeability in the perforations and/or the
near-wellbore region with the highest flow rates.
This allows more of the injected fluid to divert
into lower-permeability intervals in the injection
zone. The overall sweep efficiency can be substantially improved by this flow diversion.
In mature fields, optimization of CO2 flood and
tertiary oil recovery demand accurate and consistent formation evaluation in producing wells.
However, the complex well history—including
near-wellbore stimulation and recompletion for
flood injection—often poses challenges to log
interpretation. In particular, resistivity-based
determination of water saturation can be highly
uncertain in heterogeneous carbonate reservoirs
where there can be wide variations in key petrophysical parameters (m, n, Rw). Halliburton’s
new TMD-3DTM slimhole multidetector
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pulsed-neutron tool has been designed to
enhance radial measurement sensitivity and
can derive a calibrated cased-hole porosity
from capture gamma ratios and gas saturation
from the gas-saturation gate tool response. The
particularly valuable in wells where openhole
may not have been run or are unavailable. The
TMD-3DTM tool can accurately identify water or
CO2 breakthrough and monitor changes in water
or CO2 saturation—interpretation of time-lapse
TMD-3DTM tool data can guide conformance
projects designed to improve sweep efficiency.
Production array logging devices, run on e-line
or in memory mode, are used in vertical, highly
deviated and horizontal wells to determine
both the flow profile and source of water or
CO2 influx. In general, data in both the horizontal section and the vertical sections, are important elements in evaluating the performance of horizontal wells and also provide dynamic data for optimization of
reservoir modeling and the determination of
long-term economics and ultimate recoverable
reserves.
Gas holdup is the fraction of the casing
cross-sectional area occupied by gas at a
given depth. Gas holdup estimates are used in
conjunction with estimates of flow velocity to
determine production rates from each zone of
interest. Gas holdup has traditionally been computed from fluid-density measurements;
however, because fluid-density measurements
typically respond to small samples near the
center of the borehole, they may not be representative of the full wellbore. The GHTTM tool
is a slimhole (1-1/16 in.) production-logging
tool that uses a low-energy, nuclear-backscatter technique to obtain fullbore gas-holdup
measurements for determining the volumetric
fraction of gas in horizontal, deviated, and
vertical cased or screened wellbores in all flow
regimes. The tool can detect gas even when
turbulence has distributed or broken the
gas bubbles into sizes so small that they are
undetectable by conventional methods.
Phase segregation occurs in many wells,
particularly highly deviated wells (>60°), but
also in wells with little deviation from vertical.
The lighter fluids move along the high side of
the well and heavier fluids along the low side at
different rates. In these conditions, conventional
center-sampling production logging tools that
measure holdup cannot accurately quantify fluid
distributions and velocities. This can result in
incorrect volume estimates and misdiagnoses of
fluid entry or exit points. The problem is exacerbated in horizontal boreholes with undulating
well paths.
The latest multiphase production array logging
tools have been designed to provide a full
borehole profile. The capacitance array tool
(CATTM) device determines the water, oil, and
gas holdup in the wellbore and the resistivity
array tool (RATTM) device determines the holdup
of hydrocarbons and water. Each of these tools
employs 12 bowspring-mounted microsensors.
The spinner array tool (SATTM) device consists
of six bowspring-mounted microspinners that
enable the measurement of the velocity profile.
These tools provide a detailed examination of
the flowing fluids in all types of wells, including
highly deviated and horizontal wellbores that
is not possible using traditional center-sample
tools. This information is critical to the production engineer for optimization intervention
work, as well as to the reservoir engineer for
updating the reservoir model, to further plan
reservoir-management activities (i.e. waterflood
planning, infill drilling planning, or tertiary-recovery planning).
Halliburton’s Resistance Array Tool (RATTM) system uses a circular array of 12 microsensors
to differentiate between conductive water and
nonconductive hydrocarbons and can detect
very small fast-moving bubbles. These features
allow the tool to deliver a highly accurate,
full-wellbore profile of the volumetric flow rate,
i.e., determination of the water-holdup profile in
wellbores of any deviation from vertical to horizontal and also in any flow regime.
Combined with data from the Spinner Array
Tool (SATTM) and Capacitance Array Tool
(CAT™) systems, the RAT allows quantitative
estimations of the water holdup profile and 3D
imaging, providing more precise information
for reservoir management.
The Capacitance Array Tool (CATTM) tool is a
multiphase holdup tool that identifies fluid phases
in highly deviated and horizontal wells. The tool
uses a circular array of 12 radially distributed
capacitance microsensors placed on flexible
bowsprings that cover the entire diameter of the
wellbore to provide accurate measurements and
images of the entire borehole cross section in
horizontal and deviated wells (Fig. 4). By taking
SPE 165230
“Case History: Monitoring Gas (CO2) Flood in a
Carbonate Reservoir with a New Slim Multidetector
Pulsed Neutron Tool,” K. Kwong, Halliburton;
Z. Liu, Kinder Morgan; W. Guo, L. Jacobson,
Halliburton, presented at the 2013 SPE Enhanced
Oil Recovery Conference, July 2-4, Kuala Lumpur,
Malaysia
SPE 36562
“A New Production Logging Method for Fullbore
Gas Holdup Measurements in Cased Wells”
M.C. Waid, W.P. Madigan, H.D. Smith Jr., and R.B. Vasquez, Halliburton Energy Services,
Conference and Exhibition, 6-9 October, Denver, Colorado
measurements in a single plane across the wellbore, the CAT system measures the capacitance
of the fluid around the sensors. Since each sensor
can distinguish between water, oil and gas, the
holdup around each sensor can be determined.
Variation in response allows the tool to determine
what phase exists at a given region across the
wellbore; sensor response is converted to a phase
holdup. The CAT sensor is run centralized in
the wellbore, where it works seamlessly with
other advanced production logging tools to
provide in-depth fluid phase analysis to facilitate
determinations of gas, oil and water holdups in
both casing and tubing. Once the tool is calibrated
and data are normalized, the curves recorded by
each of the 12 sensors are processed to generate
an image. FloImager™ 3D visualization software
generates interactive 3D images of multiphase
holdup. The results from these analysis packages
allow an operator to understand, modify, and
improve the productivity of a horizontal well.
The Halliburton Spinner Array Tool (SAT™)
system uses six miniature turbines deployed
on bowspring arms for determination of fluid
velocities and direction across the wellbore. The
six miniature turbines use low-friction jeweled
bearings to reduce the mechanical threshold
of the spinner and improve sensitivity to fluid
flow. The tool outputs the direction and speed of
spinner rotation and speed. A relative-bearing
measurement is incorporated to indicate the
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high side of the hole. When used in tandem with
other Halliburton production logging tools and
analysis programs, the SAT sensor can generate
3D visualizations and provide even more
detailed description of downhole fluid flow.
Integrating a full-suite of production logs with a
tubing-evaluation log, pulsed-neutron log, or any
other cased-hole service can provide synergistic
benefits in flow profiling and evaluation of mechanical integrity, or water production because
each tool corroborates the information from the
other tools to provide a better understanding of
downhole events. This extends the life of the field
and improves overall field recovery.
SPE 165275
“Rejuvenating Viscous Oil Reservoirs by Polymer
Injection: Lessons Learned in the Field,”
J.L. Mogollón and T. Lokhandwala, Halliburton,
presented at the 2013 SPE Enhanced Oil Recovery
Conference, July 2-4, Kuala Lumpur, Malaysia
SPE 125028
“Improving the Process of Understanding Multiprobe
Production Logging Tools From the Field to Final
Answer,” G. Frisch, D. Dorffer, and M. Jung,
Halliburton Energy Services; A. Zett and M. Webster, BP Exploration and Production,
Conference and Exhibition, October 4-7, New
Orleans, Louisiana
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SPE 138749
SPE 137202
“Production Logging in Horizontal Wells: Case
Histories from Saudi Arabia Utilizing Different
Deployment and Data Acquisition Methodologies in
Open Hole and Cased Completions,” A.R. Al-Belowi,
M.A. Al-Mudhi, M. Hashem, O.L. Wah, Saudi
Aramco; F. Arevalo, M. Rourke, T. El Gamal,
and J. Torne, Halliburton, presneted at the 2010
Abu Dhabi International Petroleum Exhibition &
Conference November 1-4, Abu Dhabi, UAE
“Intelligent Sensors for Evaluating Reservoir and
Well Profiles in Horizontal Wells: Saudi Arabia
Case Histories,” M.H. Al-Buali, A.A. Dashash,
Saudi Aramco; T. El Gammal, F. Arevalo and J.
Torne, Halliburton, presented at the 2010 Canadian
Unconventional Resources & International
Petroleum Conference, October 19-21, Calgary,
Alberta, Canada
SPE 137205
“Enhancement of PLT Tool Reach in Horizontal
Wells Using Advanced Wireline Tractor,”
M.H. Al-Buali, A.A. Dashash, A. Al-Shehri, Saudi
Aramco; J. Torne, Halliburton; W.K. Hussein,
Aker Solutions, presented at the 2010 Abu Dhabi
International Petroleum Exhibition & Conference,
November 1-4, Abu Dhabi, UAE
SPE 128263
“Evaluating Steam Injection Profile with High
Temperature Memory PLT,” M. Samir, W. Hassan,
Salah Kamal, Scimitar Production Egypt Ltd.; A.
Hassan, M. Draz, and A. Waheed, Halliburton,
presented at the 2010 SPE North Africa Technical
Conference and Exhibition, February 14-17, Cairo, Egypt
SPE 134105
“Flow Profiling and Completion Leak Detection with
Memory Production and Corrosion Logging Tools
in High Profile Gas Condensate Wells: Case History
from Southeastern Bolivia,” I. Foianini, Halliburton,
presented at the 2010 IADC/SPE Asia Pacific
Drilling Technology Conference and Exhibition,
November 1-3, Ho Chi Minh City, Vietnam
SPE 140790
“A Successful Introduction of a New Tools
Configuration and Analysis Method for Production
Logging in Horizontal Wells,” J. Torne, F. Arevalo,
P. Jay, M. Eid, N. Guergeub, and G. Frisch,
Halliburton, presented at the 2011 SPE Middle
East Oil and Gas Show and Conference, September
25-28, Manama, Bahrain
> Optimizing Infill Drilling and Evaluation
Optimizing Infill
Drilling and
Evaluation
Accessing bypassed reserves or evaluating lower
prospective horizons with infill drilling to
increase reservoir exposure and decrease well
spacing with overall objective to reduce costs
can prove tremendously troublesome. In these
formations, fracture gradients and the mud densities required to maintain wellbore stability can
fluctuate considerably, increasing the pressure to
properly plan and execute the drilling operation. In keeping with its holistic approach to maximize
asset value, Halliburton has engineered a full
suite of solutions to optimize infill drilling in
mature and depleted environments. Halliburton
recognizes that understanding the reservoir is
crucial, as is the development of a cost-effective
drilling program for getting the most out of the
mature asset. From new generation solutions to
remove the uncertainties of wellbore placement,
to reducing non-productive time (NPT) in
accessing the target zone, to preventing and
remediating lost circulation. Halliburton has integrated solutions to address the most daunting challenge of constructing wellbores in highly
depleted formations, including:
• Replacing wells via slot recovery on constrained platforms
• Installing an advanced reservoir drainage
multilateral system to minimize the capital
expenditure required to tap marginal reserves
• Using the Evader® gyro measurement-while-drilling (MWD) service to
reduce environmental impact and pad size by
allowing wells to be drilled off a platform or
drillsite pad to reduce the project AFE.
• The StrataSteer® 3D Geosteering service,
along with geosteering specialists, to minimize risk during drilling as well spacing is
reduced
• The DecisionSpace® Desktop software tools
to acquire and analyze well data in real time.
• New generation coring and logging sensors
for advanced formation-evaluation
• Advanced wellsite drill cuttings evaluation
• New generation evaluation technologies
The key to increasing production from
mature fields is identifying new and bypassed
sweetspots and increasing reservoir contact
through optimally placed wells. These objectives are met through advanced formation-evaluation and geosteering technologies. When
infill wells are drilled in new or untested fault
blocks, especially in high-cost environments,
such as offshore and deepwater, in extend an
existing field, a full suite of formation-evaluation technologies, e.g., coring and logging
sensors, should be considered to maximize
reservoir characterization to accurately predict
reservoir quality and producibility.
Reducing Wellbore Placement
Uncertainties
One of the key requirements, as well as one
of the major challenges, in an infill drilling
program is to reach untapped reserves while
avoiding collisions with existing producing
wellbores. Sperry Drilling integrated Survey
Management Services employs a myriad of
new-generation technologies to ensure the
accuracy of survey measurements and reduce
the inherent uncertainties in wellbore position
calculations.
Sperry Drilling's Survey Management Services
uses multistation analysis to improve wellbore
placement, while placing directional sensors
close to the bit and enhances directional
control. The all-inclusive services helps
eliminate correctional trips by detecting and
correcting for operating conditions outside the
specifications, while also minimizing the need
for additional surveys or runs for tool validation. Moreover, Survey Management Services
corrects for magnetic influences of metallic
particles in the drilling fluid and mitigates the
risks associated with high-inclination wells
close to magnetic east and west.
/ 123
Fig. 1. The Sperry Survey Management Service makes corrections for BHA sag, which describes
an error in inclination measurements caused by the flexing of the BHA when resting in an inclined
wellbore.
The Sperry Survey Management portfolio
provides myriad services designed to improve
the accuracy and reduce the uncertainties of
geometric well positioning, including:
• Axial Misalignment (Sag) Correction:
Sperry’s MaxBHA™ drilling optimization
software models sag with greater accuracy
than conventional methods allowing the precise correction of the survey tool inclination to a value that is parallel to the
wellbore axis.
• Multistation Analysis: Processing a series
of surveys allows the survey management
specialist to increase survey accuracy by
estimating the magnitude of axial and cross-
axial biases, cross-axial scale factor influences, and interference on magnetic measurements. It also helps improve accuracy
through the characterization of the specific
/ 124
sensors in use and provides additional quality
assurance checks on the tool performance.
• Dual-Probe Configuration: Two directional sensors may be run within the same
toolstring so two directional surveys are
acquired at the same depth, thus improving
TVD accuracy and quality control, while
providing sensor redundancy that allows the run to continue in the event of a sensor failure.
• Long- or Short-Collar Configurations: Sperry
can provide both long- and short-collar
correction configurations for directional
sensor placement. The short-collar correction
algorithm allows the placement of MWD sensors containing magnetometers closer to the
bit or at the bottom of the MWD tool string.
Thus, a directional sensor can be placed on
top of a mud motor or a rotary steerable tool.
In addition, the Sperry Survey Management
Services delivers magnetic measurements to
determine wellbore azimuth and allow for magnetic field corrections. The total magnetic
field generated at a location has three components: the main field, the crustal field and
the external field. The main field is generated
by the earth’s core, and the orientation of the
main field varies with time. To account for this
secular variation, Sperry utilizes the annually
updated British Geological Survey (BGS)
Global Geomagnetic Model (GGM), a sophisticated model that provides the scalar magnetic
reference values at the drilling location.
The associated IFRSM in-field referencing
service uses a magnetic survey around the
Fig. 2. The IFR in-field referencing service
uses a magnetic survey around the well
site to make corrects for crustal influences
created by magnetic minerals distributed
throughout the earth’s crust that can create
significant localized variation in the total field.
well site to correct for the crustal influences of
the crustal field created by magnetic minerals
distributed throughout the earth’s crust. Once
processed, this data provides accurate reference
information accounting for these localized variations. The IFRSM interpolated in-field
referencing service, developed jointly by
Sperry and the BGS, produces reference values
interpolated from magnetic observatories to
create a virtual observatory at an onshore or
offshore well site. MWD survey data corrected
for main, crustal and external field components
delivers accuracy comparable to that of
high-accuracy north-seeking gyro systems.
The IFR in-field referencing service uses a
magnetic survey around the well site to make
corrects for crustal influences created by
magnetic minerals distributed throughout the
earth’s crust that can create significant localized
variation in the total field.
SPE 128522
“Overcoming Uncertainties through Advanced
Real-Time Wellbore Positioning in Kuwait: A
Success Story,” Don Hawkins, Hakim Al-Abri,
and Pavel Martinez, Halliburton Sperry Drilling; Saud Jumah, Khaled Saleh, Haithem Al-Mayyan
and Fahad Al-Mudairis Kuwait Oil Company,
presented at 2010 SPE North Africa Technical
Conference and Exhibition, Feb. 14-17, Cairo, Egypt
Advanced Solutions for Avoiding Well
Collisions Near Top of Hole
Deviated and/or extended-reach wellbores
drilled from a central pad, platform, or subsea
template provide an efficient method for
optimizing production in high-density infill
drilling. However, in these wells, the close
proximity of the tophole sections requires specialized technology and careful management to
avoid borehole collisions.
Sperry Drilling Evader® MWD gyro service
was developed to help make gyroscopic surveys
faster, safer, more accurate and available in real
time to prevent collisions and avoid financial
losses due to NPT. The service, which is used
in conjunction with Sperry’s current magnetic
directional probes, simultaneously sends up
a magnetic survey and a gyro survey at each
pump cycle, as well as gyrosteering the toolface
orientation. When the tool is clear of magnetic
interference, information is sent to the tool to
shut off the gyro section and continue drilling
with the conventional magnetic MWD system.
The tool’s modular design allows it to be placed
anywhere in the MWD/LWD string, including
on the bottom, to receive directional information as close to the bit as possible
The tool eliminates the need for wireline gyros
to orient or steer the drilling assemblies, saving
considerable rig time and enabling safer operations. The gyro’s accuracy helps assure precise
Case STUDY:
Evader® Service saves nearly $500,000
in drilling platform wells off Malaysia
An operator planned to drill three wells from
the same platform. Halliburton proposed using
Sperry Drilling’s Evader services because the
tool can be added to the BHA before drilling
begins, reducing trip time for the second and
third wells. Based on known tripping costs
involved with replacing a wireline-dependent
gyro assembly with an MWD steerable motor
BHA, the operator decided to try the suggested
solution. The first well was drilled in standard
fashion using Halliburton’s MWD services to
steer the drillstring into place at final depth.
The Evader tool was added to the BHA for
the second well and the crew began drilling
ahead. As planned, the driller was able to
use real-time GWD feedback to steer the bit
while inside the magnetic-interference zone.
After clearing the magnetic-interference zone,
the driller switched to using standard MWD
feedback without having to trip out and back
downhole. This method saved the operator
$195,625 based on trip time and the additional
personnel and equipment it would have
taken to run a wireline gyro survey. The same
method of assembling the BHA was used for
the third well, which was drilled with the same
parameters as the second well, this time saving
an estimated $256,885, for a total estimated
savings of $452,510.
/ 125
slim hole applications as well as complimentary
gamma and resistivity formation evaluation
solutions. Supporting its advanced portfolio of
rotary steerable systems (RSS), Sperry Drilling
offers the high-torque, slim hole SperryDrill®/
GeoForce® XL and XLS series of positive
displacement motors (PDM), engineered to
prevent motor stalling and premature failures. These new generation PDMs represent the most
reliable and powerful motors in the market,
delivering higher torque output and designed
with a rugged mud-lubricated or sealed bearing
assembly. The SperryDrill Series PDM helps
reduce NPT, avoid wellbore collisions and
lower high-angle well costs.
wellbore guidance for collision avoidance and
precise trajectory placement. The tool can be
run with either positive- or negative-pulse
telemetry systems.
Minimizing Infill Drilling Costs
If not addressed precisely, the inherent
challenges of an infill drilling program, not the
least of which include depleted reservoirs and
often close surface proximity to existing wells, can seriously elevate NPT and reduce project
economics considerably.
Halliburton once again has stepped to the
forefront with myriad, high-performance
technologies and solutions, all geared toward
reducing drilling costs and maximizing the
value of clients’ mature assets. Compared to conventional motors, the XL and XLS series deliver 80% more power, 65% higher torque load, 50% increase in
operating differential pressure and a shorter bit-to-bend distance for improved build rates.
The result is longer motor runs, fewer trips
and increased rate of penetration. These high
performance and extremely dependable PDM
consistently demonstrate their capacity to
achieve more than 200 hours downhole.
Cost-Effective Slimhole Re-Entry Drilling,
Evaluation Solutions
Slimhole re-entry drilling is the most economical, and often only viable, means of accelerating
production, increasing field recovery and, at the
end of the day, extending the productive life a
mature onshore or offshore asset. A successful
re-entry drilling and development program
requires precisely accessing and evaluating
the targeted horizon as quickly and safely as
possible.
As an industry pacesetter, Sperry Drilling offers
a wide range of robust, high-speed motors for
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Fig. 3. SperryDrill® motors can be configured
with either conventional power sections (left)
or GeoForce® enhanced power sections
with machined stators (right). Driveshafts are
either box-down or pin-down for use with
FullDrift® extended gauge bits (right).
The GeoForce PDM series also optimizes
Sperry Drilling's Short Radius Drilling System
by helping keep wellbore paths on target with
predictable directional behavior. Short radius
solutions are ideal for depleted or low-pressure
reservoirs where formation pressures are
Sperry Drilling’s formation evaluation solutions
include the EWR®-PHASE 4™ Resistivity
sensors, developed to conduct complete
formation resistivity evaluation in boreholes
as small as 3¾-in. The EWR-PHASE 4 service
utilizes a high-frequency LWD induction resistivity sensor, comprising four radio-frequency
transmitters and a pair of receivers. Measuring
both the phase shift and the attenuation for
each of the four transmitter-receiver spacings
allows for eight different resistivity curves with
differing depths of investigation.
Fig. 4. Short radius drilling with the SperryDrill motor
Transmitters
Receivers
Wear Bands
Fig. 5. The EWR®-PHASE 4TM sensor has four transmitter-receiver spacings.
insufficient to lift fluid above a longer radius
curve. In this challenging application, short radius
drilling solutions allow the well to be landed and
directionally drilled exactly as programmed.
For logging small boreholes, the 3-1/8-in
and 3-5/8-in super-slim tools are suitable for
coiled-tubing drilling, through-tubing rotary
drilling (TTRD) and conventional rotary-drilling applications in borehole diameters as small
as 3¾-in. In addition, the EWR-PHASE 4 tool
has extended transmitter-receiver spacings to
increase the depth of investigation, thereby minimizing the borehole effects intrinsic to
large wellbores.
When the EWR PHASE 4 resistivity sensors
are used for geosteering applications, the
forward modeling capability of the StrataSteer®
3D software provides a synthetic log along
the proposed well path to use as a correlation
“road map”. Vertical resolution enhancement
(VRE) processing corrects for shoulder-bed
and dipping-bed effects, providing curves with
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equipped with a GABI sensor providing
at-bit azimuthal gamma ray and inclination
measurements for improved geosteering and
optimum wellbore placement. The GABI LWD
sensor provides at-bit azimuthal gamma ray
and inclination measurements for improved
geosteering and optimum well placement.
The sensor also produces a borehole image
that can be used to interpret the bed dip and
determine location of an approaching bed. The
GAB sensor can be mounted below the power
section of any SperryDrill PDM, delivering a
powerful tool for drilling long horizontals and
staying in the pay.
Fig. 6. The GABI™ sensor provides azimuthal
gamma ray and inclination surveys right
behind the bit for precise well placement and
increased production.
enhanced vertical resolution. The multiple
resistivity measurements of the EWR-PHASE
4 sensor facilitate the use of various interpretation models for evaluating invaded and anisotropic formations. Moreover, the EWR-PHASE
4 family of wireline-quality, high frequency
LWD induction resistivity sensors is equally
effective in both water and oil-based muds, as
well as air and foam-drilled boreholes.
In some reservoirs, the target zone is easily
recognized using only gamma-ray logs,
which Sperry addresses with its GABI™ motor
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SPE 123859
“Real-Time Decisions with Improved Confidence
Using Azimuthal Deep Resistivity and At-Bit
Gamma Imaging While Drilling,” M. Harris, D. Byrd, M. Archibald, Devon Energy; C. Naupari, M. Bittar, and R. Chemali,
Halliburton, presented at the 2009 Offshore
Europe, September 8-11, Aberdeen, Scotland, UK
SPE 160882
“Anisotropy and True Formation Resistivity
Measurements with a New LWD Resistivity Sensor,”
M. Bittar, H.-H. Wu, S. Li, and M. Bayrakdar,
Halliburton, presented at the 2012 SPE Saudi
Arabia Section Technical Symposium and
Exhibition, April 8-11, Al-Khobar, Saudi Arabia
Geosteering Solutions for Cost-Effective Infill Well
Placement
In accessing bypassed reserves with high-angle
or lateral well paths, precise placement of the
wellbore with the best orientation and with
maximum borehole exposure in the most productive reservoir intervals is key to
optimizing the completion and enhancing asset
economics. As infill well spacing decreases and
more wells are drilled from multiwell platforms
and onshore pads, , accurate well surveying and
placement becomes even more critical.
Sperry has introduced a new-generation suite
of LWD and MWD innovations that help
mitigate many of the hazards in close-contact
infill drilling and makes sure the RSS does not
deviate from the path to the sweetspot. Among
the revolutionary geosteering advances for
mature field redevelopment is the slim-hole
version of the ADR™ azimuthal deep resistivity
sensor that provides a new level of insight into
the reservoir. The ADR is the ideal solution for
optimizing wellbore placement, maximizing
production and extending field life.
The ADR sensor combines a Deep-reading geosteering sensor with a traditional multifrequency compensated resistivity sensor. As such, the
ADR provides over 2,000 unique measurements
for both precise wellbore placement and more
accurate petrophysical analysis, all with a single
CASE STUDY:
CASE STUDY:
Short Radius Drilling Hikes Production in Mature
Malaysia Field
Philippines Debut of Short Radius Drilling Technology Cuts Day
of Drilling Time
The operator of a mature field offshore Malaysia planned a field redevelopment to increase oil production, which would require sidetracks off existing sub-optimally producing wells. The challenges were
to maintain considerable offset from oil/water and gas/water contacts
to avoid early water and gas break through, essential for sustained
clean oil production. The high costs involved with medium radius
horizontal drilling, and the necessity to target bypassed oil, led to the
decision to use Sperry’s innovative short radius drainage technology
that incorporates an articulated PDM to resolve drilling problems
where precise directional control of inclination and hole azimuth is
required. The solution allows unstable or problem formations above
the reservoir to be isolated and a major portion of the curve drilled in
the reservoir section. Real-time tool face orientation and hole direction
while drilling for precise wellbore placement can be determined using
a combination of the steerable downhole motor and articulated MWD
sensors. For this high-dogleg application, a 4¾-in.short radius system
and a 2-7/8-in. drill pipe were used to drill the 6-in drain holes. The drain holes were drilled and successfully achieved build rates up to
100°/30 m (100°/100 ft) with horizontal sections in excess of 250 m
(820 ft) in length. MWD data were transferred in real time to the
onshore base and the InSite Anywhere® service at the client’s office,
facilitating real-time communication and intervention from the client’s
key personnel to control hole trajectory. Since the first application,
more than 100 short-radius wells have been drilled in this field re-development. Up to a nearly threefold increase in production has been
delivered and even some wells that had completely ceased to produce
are now flowing at significant volumes.
The operator’s shallow water well off the Philippines required a sidetrack
after producing hydrocarbons with a high water cut. With the well unable to produce from other zones because of objects left in the borehole
from completion equipment, the client requested Sperry sidetrack the
well from the very top of the reservoir and remain within the reservoir
while drilling away from the water zone until the well reached total
depth (TD). Well geometry indicated that short radius drilling technology, which had never been used in this region, was the only solution
for this challenge. During planning, local Sperry personnel coordinated
with other regions with experience with short radius drilling technology
and simultaneously began deploying the required tools and personnel
in country. The coordinated approach determined that an articulated
motor and MWD sensors was the only way to achieve the short radius
60°/30 m (100 ft) dogleg severity required in the well, although using
slim hole technology to drill the medium hard formation of limestone
and sandstone would present some issues related to drillstring integrity
and BHA dynamics. Therefore, a 4¾-in SperryDrill motor with 2.75°
bent housing was planned to kick off the sidetrack and build inclination
from vertical to 61.5° followed by a SperryDrill motor with 1.5° bent
housing to complete the curve and drill the lateral. The drilling operation was expected to be finished in three days.
As planned, the sidetrack kicked off at 1,633 m (5,357.5 ft) to build
angle with the 2.75° motor, achieving actual dogleg output of 54°/30 m
(100 ft). The second BHA was picked up to soft land the sidetrack. The
74° tangent section was drilled to TD at 1,820 m (5,971 ft). The well remained within the reservoir over the entire187 m (614 ft) sidetrack
that was drilled and finished in just 43 drilling hours, saving the operator
more than a day of rig time.
/ 129
stringers, changes in dip angle and other formation-related issues, the GABI sensor can help
ensure the trajectory is corrected immediately
and the well remains on target.
Determining the optimal borehole orientation
is based on the orientation of the regional
stresses, which is determined from acoustic
data, such as surface 3D seismic (anisotropy
analysis), post-fracture microseismic mapping,
or downhole acoustic logs (WaveSonic® and
XBATSM services and anisotropy analysis). Wells
drilled in directions other than parallel to the
maximum or minimum stress orientation can
lead to complex fracture geometries and injection resistance during the fracturing operation.
Borehole-imaging logs (XRMI™, OMRI™ tools)
can determine whether natural fractures are
open or closed.
Maximizing both infill drilling efficiency and
borehole exposure in the target zone requires
Fig. 7. The unique antenna design makes the
ADR™ tool directionally sensitive so complex
geology and approaching beds can be
accurately mapped.
tool. Deep-reading, directional measurements
provide early warning of approaching bed
boundaries before the target zone is exited,
allowing the operator to keep the wellbore in the
most productive part of the reservoir.
Inclination readings from just behind the bit
contribute to lower wellbore tortuosity, longer
horizontals and more accurate wellbore placement. By providing immediate feedback about
unexpected trajectory changes due to faults,
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Fig. 8. StrataSteer 3D service has proved effective for accurate well placement.
the wellbore remain within the target and
avoid exiting into adjacent formations. The
Sperry wellbore positioning suite includes the
StrataSteer® 3D geosteering service that uses
deep-reading LWD sensors, powerful visualization software and remote operations centers
to deliver accurately placed wellbores in small
pay zone targets. The field-proven StrataSteer
3D service allows operators to increase the percentage of the drilled footage that is in direct
contact with the reservoir. Consequently, more
once-bypassed hydrocarbons are accessed, resulting in improved total asset recovery.
What takes this wellbore-positioning service
beyond the conventional is a combination of
the expertise of the specialists, advanced LWD
sensor technology and a powerful software
model calibrated to the unique response of
these LWD sensors.
Meanwhile, unlike older omnidirectional
sensors that only allow reactive geosteering,
Sperry has introduced a suite of new generation azimuthal sensors (ALD™, InSite
ADR™ , InSite AFR™) that allow proactive
geosteering. In addition, the ZoomXM™ EM
electromagnetic telemetry or mud-pulse
systems transmit the data in real time
from downhole sensors to the surface. EM
telemetry uses two-way low-frequency electromagnetic-wave propagation through the
drillpipe and formations for high-speed data
CASE STUDY:
Real Time Transmission of Mud-Pulse-Telemetry Surveys from Remote
Operations Center
The operator of a gas well in the Haynesville Shale wanted to acquire real-time mud-pulse-
telemetry well surveys without having MWD personnel on location at the rigsite. Remote operations enable the worldwide deployment of expertise and resources more efficiently,
providing the ability to monitor rig operations from afar while fostering efficient collaboration
among team members, improving safety, helping reduce costs and, ultimately, enabling the
customer to make better decisions. To deliver real-time survey data that would enable the
operator to expedite decision making and facilitate precise wellbore placement. Sperry Drilling
monitored the real-time MWD data received at the Remote Operations Center (ROC), and
provided satellite communication to an IP phone in the client’s office and to InSite® systems in
both the client’s office and on the rig floor. Sperry successfully communicated the surveys to
the client from surface to the final survey depth of 7,198 ft (2,194 m) without having personnel
on the rig, saving the client thousands of dollars. Remote operations also alerted the client to
damaging vibration while drilling the top vertical section of the well. Real-time information
allowed the operator to modify the drilling parameters to mitigate the vibration, thereby
avoiding equipment failures and NPT.
transmission to and from the surface. In deep
wells, through- borehole repeaters can be
used to boost signal amplitude where signal
attention is a concern.
In some reservoirs with relatively high clay
content, the most critical aspect of drilling the
horizontals is to ensure that the well path is in
the best rock quality for stimulation. Sperry
ensures as much with its BAT™ sonic tool
with gamma ray as the real-time evaluation
suite, in conjunction with LaserStrat® service,
for gross stratigraphic control. After the well
has been drilled and a completion string run,
cased-hole logging services, e.g., RMT Elite™
tool service, are tied to the sonic and the geochemical data are used to deliver an optimized completion and stimulation
strategy.
/ 131
Case STUDY:
Deep-Reading Azimuthal Resistivity Successfully Places Well in Geologically
Complex Reservoir
The Wilmington Field, which has been producing since 1932, is the largest field in the Los
Angeles basin and the third largest oilfield in the US. The original estimated OOIP for the field
was >10 billion bbl with an estimated ultimate recovery (EUR) of more 3 billion bbl of oil. To-date, seven major producing zones, ranging in age from Lower Pliocene to Upper Miocene,
have produced 2.6 billion bbl and 326 Bcf of associated gas from 6,000 wells. The Wilmington
structure is a northwest-southeast trending, double plunging asymmetric anticline. A series
of transverse, normal faults segment the structure into 10 major productive fault blocks. The
Wilmington productive section has a gross thickness of approximately 3,000 ft and comprises
an aggradational succession of Miocene- and Pliocene-age confined slope deposits prograding
into unconfined basinal-medial to distal-turbidite fan complexes. unconsolidated fine to coarsegrained sandstones. Complexities result in vertical and horizontal stratigraphic controlled
permeability variations that significantly hinder productivity, affect effective waterflooding, but
also result in delineating significant volumes of bypassed recoverable oil.
The optimal positioning of a complex well in a thinly laminated reservoir that has already been
produced required careful planning on the part of the asset team. The objective was to use a
low-angle trajectory to assess the potential for waterflooding in the lower zones of the reservoir
that could negatively affect production. The goal was to determine the relative presence or
absence of water before fully penetrating the lowest zone, which had the highest risk of waterflood. After entry into the lower zone, the resistivity values from the bottom octant of the ADR
tool indicated that water was not present in this lower zone up to the detection limit of the tool.
As drilling continued and the stratigraphic section was traversed, the measurement continued
to indicate the absence of water, enabling the team to confidently drill the section. The use of
the azimuthal ADR tool in a geologically challenging environment enabled the operator to
make proactive decisions about drilling the well in real-time, before events such as waterflood
zones were encountered. In addition, the ability to measure formation resistivity with little
interference from macroanisotropy significantly enhanced the operator’s ability to confidently
determine net pay. The new azimuthal resistivity sensor allows the short-spacing low-frequency
measurement to be qualified for use in water-saturation modeling.
/ 132
SPE 118328
“A New Azimuthal Gamma at Bit Imaging Tool
for Geosteering Thin Reservoirs,” J. Pitcher and R.
Botternell,, Halliburton Energy Services, and J.
Schafer, BXPA, presented at the 2009 SPE/IADC
Drilling Conference and Exhibition, March 17-19,
SPE 128155
“Advances in Geosteering Technology: From Simple
to Complex Solutions,” J. Pitcher, N. Clegg, and C. Burinda, Halliburton; R. Cook and C. Knutson,
Pioneer Natural Resources; M. Scott and T. Løseth, StatoilHydro, presented at the 2010
IADC/SPE Drilling Conference and Exhibition,
February 2-4, New Orleans, Louisiana
SPE 121186
“Case History: A Robust Point-the-Bit Rotary
Steerable System with At-Bit Imaging and 3D
Geosteering Service Integral to Optimal Wellbore
Placement in a Complex Thin Sand Reservoir,”
K.H. Kok, H. Hughes-Jones, E. Chavez,
Halliburton Energy Services; K.A. Abdul Aziz, K.
Yusof, M. Lambert, Newfield Peninsula Malaysia
Inc., presented at the 2009 SPE EUROPEC/EAGE
Annual Conference and Exhibition, June 8-11,
SPE 121894
SPE 132439
SPE 158395
“Azimuthal Wave Resistivity Opens a Window
on the Geology Away from the Wellbore Path,”
R. Chemali, M. Bittar, B. Calleja, D. Hawkins,
and C. Manrique, Halliburton Sperry Drilling
Services, presented at the 2009 EUROPEC/
EAGE Conference and Exhibition, June 8-11,
“Improved Geosteering by Integrating in Real Time
Images From Multiple Depths of Investigation
and Inversion of Azimuthal Resistivity Signals,”
R. Chemali, M. Bittar, .F. Hveding, Min Wu, and
M. Dautel, Halliburton–Sperry Drilling Services,
SPE Reservoir Evaluation & Engineering, 13(2),
172-178, 2010
SPE 128522
“Multilateral and Geosteering Technologies as a
Solution for Optimum Drainage of Heavy Oil of
Thin and Heterolithic Sands in Junín Block of the
Orinoco Oil Belt,” Rondon, P. Alfonzo, A. Bonalde, and W. Garcia, Halliburton; and J. Palermo, J. Ramos, M. Jurado, and C. Brazon,
PDVSA, presented at the 2012 SPE Trinidad and
Tobago Energy Conference and Exhibition, June
11-13, Port of Spain, Trinidad
SPE 143303
“Overcoming Uncertainties Through Advanced
Real-Time Wellbore Positioning in Kuwait: A Success
Story,” D. Hawkins, H. Al-Abri, and P. Martinez,
Halliburton Sperry Drilling; and S. Jumah, K. Saleh, H. Al-Mayyan, and F. Al-Mudairis, Kuwait Oil Company, presented at the 2010 SPE
North Africa Technical Conference and Exhibition,
February 14-17, Cairo, Egypt
“Interpreting Azimuthal Propagation Resistivity:
A Paradigm Shift,” J. Pitcher, M. Bittar, D. Hinz,
Halliburton; C. Knutson, and R. Cook, Pioneer
Natural Resources Company, presented at the
2011 SPE EUROPEC/EAGE Annual Conference
and Exhibition, May 23-26, Vienna, Austria
SPWLA 2010_EEE
“Multi-Sensor Geosteering,” B. Calleja, J. Market, J. Pitcher, and C. Bilby, Halliburton Energy Services,
presented at the 2010 SPWLA 51st Annual Logging
SPE 146732
SPE 153580
“Milestone in Production Using Proactive
Azimuthal Deep-Resistivity Sensor Combined with
Advanced Geosteering Techniques: Tarapoa Block,
Ecuador,” J. Sandoval, M. Guerrero, and C.A. Manrique, Halliburton; and A. Guevara,
Andes Petroleum;, presented at the 2012 SPE
Engineering Conference, April 16-18, Mexico City, Mexico
IPTC 16715
“Real-Time Modeling-While-Drilling for Optimized
Geosteering and Enhanced Horizontal Well
Placement in Thin and Complex Reservoirs,”
K. Saikia, Halliburton, presented at the 2013
International Petroleum Technology Conference,
March 26-28, Beijing, China
SPE 168079
“Field Evaluation of LWD Resistivity Logs in
Highly Deviated and Horizontal Wells in Saudi
Arabia,” M. Bittar, S. Eyuboglu, Y. Tang and B.
Donderici, Halliburton; and P. Anguiano-Rojas
and D.J. Seifert, Saudi Aramco, presented at the
2013 SPE Saudi Arabia Section Annual Technical
Symposium & Exhibition, May 19-22, Khobar,
Saudi Arabia
“Geosteering with Sonic in Conventional and
Unconventional Reservoirs,” J. Pitcher, J. Market,
and D. Hinz, Halliburton, presented at the 2011
October 30-November 2, Denver, Colorado
/ 133
Advanced Rotary Steerable Systems for Hitting the
Target in Depleted Zones with Zero NPT
Drilling infill wells in depleted and unstable
formations, particularly with deviated trajectories, propagate dynamic pressure cycling
and other distinctive downhole problems
that can make it difficult, if not impossible,
to reach bypassed reserves with conventional
assemblies. In addition, mature intervals can
generate extreme levels of vibration, shock and/
or pressure surges that no amount of drilling
parameter adjustments will totally eliminate,
thus escalating NPT.
For slim holes in re-entry and sidetracks,
Sperry introduced its innovative and robust Geo-Pilot® XL rotary steerable system (RSS)
specifically for the increased durability
required for this harsh drilling environment.
Available in the 5200, 7600 and 9600 Series,
the Geo-Pilot XL consistently delivers higher
ROP that reduces trips while ensuring precise
well placement under extreme drilling
conditions. To resist the instantaneous
pressure spikes of depleted or unstable zones,
the Geo-Pilot XL series is equipped with
rotary seals that are able to deliver consistent
sealing of the internal components while
accommodating the off-center rotation of the
drive shaft under elevated temperatures and
dynamic pressure cycling.
/ 134
Unlike conventional RSS designs, the new generation Geo-Pilot system is not only immune to
the stick-slip phenomenon , but also contains
higher-grade materials and other upgraded
subcomponents to resist excessive wearing
caused by prolonged cyclical torque fluctuations. The Geo-Pilot XL is enhanced with the
TEM™ torsional efficiency monitor sensor that
analyzes the variations in rotational speed of
the driveshaft, which is screwed directly to the
drill bit, providing an early warning of the onset
of stick-slip. Drilling parameters can then be
adjusted to reduce or eliminate this damaging bit
phenomenon and maximize drilling efficiency.
In addition, the TEM sensor also improves
drilling performance by providing an excellent
validation of the effectiveness of bit design.
In drilling sidetracks in a mature infill-drilling
campaign, delivering longer and smoother well
trajectories to minimize casing wear has long
been a major challenge. The difficulties are compounded in high-angle
infill wells, especially from multiwell offshore
platforms or onshore pads where communication with adjacent horizontal wells can seriously
reduce reservoir drainage.
Fig. 9. The Geo-Pilot® XL system in three
sizes—5200 Series, 7600 Series and 9600
Series—delivers unprecedented reliability
and speed for tough drilling conditions.
Sperry effectively addressed that issue with its
state-of-the-art Geo-Pilot® Dirigo RSS, which
gives operators all the benefits of point-the-bit
rotary-steerable drilling, with higher build rates than previously possible only with conventional
mud motors. The Geo-Pilot Dirigo RSS opens
the door for achieving higher inclinations
earlier in the well—a particular requirement for
in-fill drilling from multiwell platforms. The
variable deflection point-the-bit RSS provides
maximum ROP while reducing torque and drag
associated with challenging profiles, delivering
a wellbore with low tortuosity. The shorter tool
Fig. 10. Reduce sail angle required in extended-reach drilling, reducing
torque and drag, and facilitating faster, smoother tripping
allows movement of LWD sensors closer to the
bit for improved and faster formation evaluation, critical for horizontal applications.
The ability to provide consistently high build
rates in large hole and soft formations allows
more flexibility in designing wellbore trajectories. The sail angle for extended-reach
Fig. 11. Kick off deeper and land in the reservoir sooner, increasing
reservoir exposure
drilling (ERD) also can be reduced, thus enhancing ERD capabilities and driving access
to reserves from existing platforms and reducing development costs. The variable deflection
point-the-bit RSS provides maximum ROP
while at the same time delivers gun-barrel hole
quality, reducing torque and drag associated
with challenging profiles. In addition, the
reduced profile of the RSS helps improve hole
cleaning and tripping efficiency, while the
shorter tool also allows movement of LWD
sensors closer to the bit for improved and faster
formation evaluation.
/ 135
CASE STUDY:
Geo-Pilot® Dirigo RSS Delivers High Dogleg Solution, Slick Well Path
In a mature field offshore Malaysia, the operator faced the challenge of drilling through a
formation where the overlying soft shale section had made it extremely difficult to achieve
good build rates in the past, and inefficient slide drilling with a motor was commonplace.
Sperry was asked to provide an alternative solution that could consistently achieve a
minimum 6°/100 ft (30 m) build-up rate to deliver a smooth curvature well trajectory from
the platform. This would allow the right step-out to hit reservoir targets while also ensuring
future slickline intervention capability would not compromised by a tortuous well path.
Allowing the drill bit to wander off the centerline of the borehole would result in a spiraled,
or tortuous hole, which is a primary contributor to poor hole quality. Sperry chose its innovative Geo-Pilot Dirigo 9600 series system, the only RSS designed for big holes that can deliver
well profiles previously only possible with motors, but also provide the wellbore quality and
higher ROP of a point-the-bit rotary steerable system.
MaxBHA™ drilling optimization software was used for modeling and designing the BHA.
While the modeled dogleg was 8.34°/100 ft, the actual dogleg produced was 20% higher.
The maximum dogleg after 90 ft (27.5 m) with 100% deflection was 8.55°/100 ft, and if
orientation had continued in the same drilling mode, the dogleg would be in the region of
10°/100 ft. The Geo-Pilot Dirigo system delivered 3,657 ft (1,115 m) at an average ROP of 131
ft/hr (40 m/hr), while building inclination from 36 to 75° at an average build rate of 8.55°/100 ft
The Geo-Pilot Dirigo delivered a smooth wellbore, perfect well trajectory and precise step-out to
intercept the reservoir target. The point-the-bit rotary steerable system was very effective in
all required directional work, thus eliminating the need to combat unwanted BHA directional
walk tendencies while producing a high dogleg. The actual directional wellbore drilled
matched the planned plot line perfectly. The auto cruise mode drilled a very straight section,
with a very slick rotating high dogleg section. The 9-5/8-in. casing was run to bottom
flawlessly.
/ 136
OTC 18975
“RSS Application Shows Higher Offshore Potential
in Onshore Extended Reach Development Wells,”
Ron Handly, Keith Holtzman, Vern Johnson, Sandy Pulley, Halliburton Sperry Drilling
Services; John Dennis and Lee Smith, Halliburton
Security DBS, and Chip Alvord, Brian Noel and
Liz Galiunas, ConocoPhillips Alaska Inc., presented at 2007 Offshore Technology
Conference, April 30l–May 3, Houston, TX
Optimizing MPD to Enable Production of
Hard to Get Reserves
In mature, and often extremely depleted, fields,
one of the operator’s primary infill drilling
challenges is addressing low mud-weight
windows, where constant bottomhole pressure
(BHP) is required to drill the well with minimal
operational problems that can increase NPT.
Managed pressure drilling (MPD) has proven
the most effective option for drilling the
partially or highly depleted zones intrinsic
of mature assets that otherwise could not be
accessed conventionally. However, managing
pressure cycling while drilling or on connections has long been the single biggest challenge
in any MPD application. In response, Sperry developed its GeoBalance®
MPD service that combines the industry’s most
comprehensive suite of pressure optimization
solutions. Through total system and service
integration, GeoBalance MPD optimization
service promotes drilling efficiency and safety
while navigating through complex pressure regimes and unstable formations. Using
minimal overbalanced annular pressure, the
GeoBalance MPD service delivers faster ROP,
reduces fluid loss and reservoir influx and
promotes excellent wellbore integrity.
Fig. 12. GeoBalance® Choke Manifold Skid
Since different levels of mature field reservoir
complexity require different solutions, the
GeoBalance MPD service can be tailored to
meet the level of complexity for each well.
Access to the extensive resources of Halliburton enables Sperry Drilling to offer a fully integrated
package of GeoBalance MPD service capabilities,
from a basic rotating control device-only
service for less stringent requirements to a
premium level incorporating the complete
array of ADT drilling optimization services
and production evaluation services. In depleted
reservoirs, GeoBalance® MPD technologies can
drill, produce and evaluate the reservior. The
GeoBalance system also uses InSite® software as
its database and graphical interface, and all data
available at the field location can be brought into one central depository for data management.
Specific components of the GeoBalance MPD
optimization service include the GeoBalance
Barrier Pill, formulated with robust gel strength
to provide excellent fluid separation in the
wellbore. At the same time, its shear thinning
properties allow it to be easily pumped in place.
As the pill is completely compatible with the
drilling fluid it can be mixed into the active
system when tripping back into the well. The
GeoBalance solution also includes the Rig
Pump Diverter that replaces the backpressure
pump in traditional MPD applications.
The choke manifold skid used in the automated
GeoBalance MPD service regulates the
wellhead pressure, thereby allows precise
control of the bottomhole pressure. Available
in several configurations, all GeoBalance MPD
service choke skids incorporate dual-redundant
chokes available with 1½-, 2- and 3-in. trims
and a bypass line. Using Sperry Drilling Sentry
software, an integrated hydraulic/pneumatic
control panel allows for redundant control of
the system either through manual or remote
system control.
The Sperry MPD
solution includes both low- and high-pressure rotating control
devices (RCD). Both
the low-pressure
RCD 1000 and the
high-pressure RCD
5000 form a positive
seal on the rotating
kelly or drillstring,
allowing for safe flow
diversion from the
Fig. 13. Sperry
Rotating Control
annulus and away
Device
from the rig floor
during either MPD or
underbalanced drilling (UBD) applications.
AADE-13-FTCE-11
“Managed Pressure Drilling—Automation
Techniques for Horizontal Applications,”
C.J. Bernard, Randy Lovorn, Derrick Lewis,
Emad Bakri and Saad Saeed, Halliburton,
presented at 2013 AADE National Technical
Conference and Exhibition, February 26-27, Oklahoma City, OK .
/ 137
New Generation Mature and Infill
Evaluation
Well logging is an integral part of the formation-evaluation phase in infill and mature
wells (Table 1 a-c). Logs are used to identify
and characterize potential reservoir targets,
provide critical information needed to optimize
well placement and completion strategy, and
determine production output of existing wells.
Infill wells can be logged using either wireline
or LWD services, depending on hole deviation
and borehole conditions. In vertical and
moderately deviated wells a wireline service
may provide the most cost-effective option for
data collection.
Advancements in Logging-While-Drilling
Halliburton’s logging-while-drilling (LWD) evaluation services include a triple- or quad-combo
toolstring that includes azimuthally sensitive
gamma-ray sensor (GABI™), resistivity (EWR™,
InSite ADR™ or InSite AFR™), density (ALD™),
neutron-porosity (CTN™) sensors and caliper
(AcoustiCaliper™) services and a mud log.
Azimuthal sensors (AFR, ALD, and GABI
sensors) also provide borehole images and
deep-reading sensors (ADR sensor) detect
approaching bed boundaries to provide
sufficient warning to allow drillers to take
proactive corrective action to help ensure
that the borehole does not exit the reservoir
target zone. An advanced LWD acoustic
/ 138
Vertical Well BHT<350°F
Wireline
LWD
How Used
Openhole - Basic Services
Quad-Combo
Resistivity
Spectral Density
Dual-spaced neutron porosit
Compensated sonic array
MCI™, HFDT™
InSite ADR™, Insite ADF-TT™,
EWR™
Fluid saturation, TOC, anistropy
analysis (ADR-TT)
SDL™
ALD™
Porosity
DSEN™, DSN™-II
BSAT™, Xaminer MPS
CTN™
Porosity, gas identification
QBAT™
Porosity, geomechanical properties
ACRt™ or DLL™, MSFL™,
UltraSlim™ service
Resistivity
Spectral Density
Dual-space neutron
Compensated sonic
Natural gamma ray
SACRt™
SSDL™
SDSN™
SBSAT™
SGR™
Fluid saturation, TOC
Porosity
Clay typing, geosteering, lithology
Spectral natural gamma ray
CSNG™
DGR, ™ DGN™
Lithology, correlation
Natural gamma ray
Azimuthal gamma
ray/inclination
Caliper
Directional survey
NGR™
Included with densityneutron tools
ICT™
GABI™
Clay typing, geosteering, lithology
Advanced Logging Services
IDT™
Compensated array sonic
BSAT™
Crossed-dipole acoustic tool
WaveSonic
®
GABI™/ABG™
AcoustiCaliper™
Geosteering
Borehole geometry, log correction
QBAT™
XBAT™
Porosity, geomechanical properties,
stress-field orientation, anisotropy
analysis
Mineralogy
Elemental analysis
GEM™
LaserStrat®
NMR T1 and T2 analysis;
MRIAN processing
MRIL® Prime, MRIL®-XL
MRIL® WD
Porosity, Permeability, free and
bound water, fluid typing
Borehole imaging
XRMI, ™ OMRI™, CAST-i™
InSite ADR™, InSite
ADR-TT™, InSite AFR™
Borehole imaging
Formation pressure and fluid
samples
RDT™, RDT-MCS, RDT-SPS,
RDT-FSS, RDT-ICS, ICE Core™
GeoTap® IDS
Pressure, permeability, fluid typing
Pulsed-Neutron
RMT-Elite
Releasable Cable Head
RWCH™
LaserStrat Chemostratigraphy
-----
Carbon/oxygen system,
used with Chi Modeling
------
Mineralogy, correlation
Additional services
Mudlog
Eagle™ Gas Extraction
System; DQ 1000™ mass
spectrometer service
Eagle™ Gas Extraction
System; DQ 1000™ mass
spectrometer service
Lithology, gas identification
Table 1a. Recommended Logging and Evaluation Services for Existing and Infill Wells in Mature Fields
logging service, such as, the dipole acoustic
(QBATSM or XBATSM service), is also suggested.
Following completion, wireline devices can be
run in cased hole on pipe (toolpusher logging
service) to obtain elemental concentrations. A
crossed-dipole acoustic log (WaveSonic® tool)
can provide geomechanical parameters and
stress-field orientation.
If the lateral section has been logged using only
minimal evaluation services, a cased-hole option can provide a cost-effective alternative
to horizontal logging. In this scenario, a
wireline pulsed-neutron log (RMT-Elite™
Reservoir Monitoring Tool) and triple combo
are run in the development wells and the data
are evaluated using Chi Modeling® service.
This service uses artificial neural-network processing to create pseudo-openhole logs in the
offsset well intervals where logs are nonexistent
or of extremely poor quality. These combined
services allow generation of a synthetic suite
SPE-94716
“Application of CHI Modeling* Using Pulsed
Neutron to Create Pseudo-Open Hole Logs,”
S. Reed, J. Quirein, J.P. Torne, Halliburton Energy
Services; M. Morales, J. Bernal., and M. Perez
Activo Integral Burgos, PEMEX; and Casares,
M., Northern Region PEMEX, presented at
the 2005 SPE Latin American and Caribbean
Petroleum Conference, June 20-23, Rio de
Janeiro, Brazil
Wireline
LWD
Sidewall Cores
SWC™, RSCT™, Xaminer™
CoreVault™
-----
Conventional (whole) core
Latch-Les™, RockSwift™,
Xaminer™ CoreVault™
-----
Borehole seismic services
Vp/Vs; walkaway VSP, AVO
inversion; overburden interval;
shear-wave anisotropy
-----
How Used
Mineralogy, porosity, permeability,
TOC, kerogen typing, fluid typing,
geomechanical properties, CST
Reservoir delineation, fracture evaluation, reservoir characterization
Cased Hole (e-line, or slickline)
Pulsed neutron
RMT-Elite™, TMD-3D™
Mineralogy, clay typing, fluid
saturations
Neural-network processing
Chi Modeling®
Synthetic openhole triple combo
WaveSonic®
Porosity, geomechanical properties,
stress-field orientation, anisotropy
analysis
Production Logging
CAT™, RAT™, SAT™
Production and water monitoring
Setting services
DPI-I
CBL™, CAST-V™, CAST-M™,
FASTCAST™
Plugs and packer setting
Cement integrity
Casing integrity
MIT™, MTT™, CAST-M
Freepoint tool
FPI™, HFPI™
Cutting services
BO (String Shot), CC, MCR, Jet
Cutter, DCST, Split Shot
Wireline
Cement bond evaluation
Casing inspection (corrosion,
thickness)
Retrieve tubulars upon abandonment
LWD
How Used
Basic Services
Hostile triple combo
Gamma ray
Resistivity
Spectral density
Dual-space neutron porosity
Calipe
Directional Survey
HNGR™
HDIL™, HACRt™, HEDL™
HSDL™
HDSN™
(included with density-neutron tools)
HDIR™
Solar™ Suite
UltraHT-230™
ExtremeHT-200™
ExtremeHT-200™
AcoustiCaliper™
Lithology, correlation
Fluid saturation, TOC
Porosity
Borehole geometry, log correction
Advanced Services
Formation Pressure and fluid
sampling
Borehole imaging
HSFT-II™
Fullwave acoustic
Hostile WaveSonic®
LaserStrat Chemostratigraphy
®
XRMI™
Lithofacies, dip, fracture identification and evaluation
Mineralogy, correlation
Table 1b. Recommended Logging and Evaluation Services for Existing and Infill Wells in Mature Fields
/ 139
Additional Services
Mudlog
Sidewall Cores
Wireline
LWD
How Used
Eagle™ Gas Extraction System; DQ Eagle™ Gas Extraction System; Lithology, gas identification
1000™ mass spectrometer service DQ 1000™ mass spectrometer
service
SWCv™, HRSCT™
Convention (Whole) core
Horizontal Open Hole <350°F
Same as for vertical well <350°F
ALD™ and BAT™
Horizontal Open Hole <350°F
Same as for vertical well <350°F Heat™ Suite II
Hostile WaveSonic®
Solar® Suite
ExtremeHT-200™
UltraHT-230™
ALD™ and BAT™
Cased Hole (e-line, or slickline)
Pulsed neutron
RMT-Elite™, TMD-3D™
Neural-network processing
Chi Modeling®
WaveSonic
®
Mineralogy, clay typing, fluid
saturations
Synthetic openhole triple combo
Porosity, geomechanical properties, stress-field orientation,
anisotropy analysis
Cased Hole Density
Production Logging
Setting services
Cement evaluaton
Freepoint tool
Cutting services
CAT™, RAT™, SAT™
DPI-I
CBL™, RCBL™
FPI™, HFPI™
BO (String Shot), CC, MCR, Jet
Cutter, DCST, Split Shot
Production and water monitoring
Plugs and packer setting
Cement bond evaluation
Retrieve tubulars upon
abandonment
Table 1c. Recommended Logging and Evaluation Services for Existing and Infill Wells in Mature Fields
of openhole triple-combo logs for use in the
petrophysical model.
This combination of services delivers
significant savings in logging costs and rig
/ 140
time, without a loss of log quality. It also offers
a method for acquiring petrophysical data
that minimizes operational risk in situations
where borehole conditions prevent acquisition
of openhole logs. However, for calibration
purposes, this option also requires data from
an openhole triple-combo and cased-hole
pulsed- neutron tool that were run in the
same vertical offset well.
Borehole images provided by azimuthally
sensitive LWD sensors (ALD™, AFR™, and
GABI™ sensors) and high-resolution wireline
imaging devices (XRMI™ and OMRI™ tools)
are used to determine structural dip for stress
analysis, and for fracture identification and
evaluation. They are valuable in drilling and
well placement because they help:
• Identify potential drilling hazards (such as
faults and karst features)
• Determine the optimal orientation for lateral
placement to maximize production
• Identify fractured intervals for completion
• Confirm pressure-dependent leakoff
• Identify thin laminations for fracture
tortuosity.
The presence and orientation of borehole
elongation and breakouts can be combined with
the acoustic-log geomechanical interpretation
to enhance analysis of the in-situ stress field for
developing a completion strategy and making
completion decisions.
Borehole seismic services, e.g., VP/VS attributes,
AVO inversion, overburden, interval, and
shear-wave anisotropy analysis, complement
and improve the accuracy of surface seismic
interpretation. More accurate delineation of
the reservoir reduces well-placement risk;
improved reservoir characterization can
identify reservoir sweetspots; and enhanced
fracture identification and evaluation is central
to optimizing the completion.
SPE 123940
“Deep Electrical Images, Geosignal, and RealTime Inversion Help Guide Steering Decisions,”
R. Chemali, M. Bittar, A. Lotfy, J. Pitcher, and
M. Bayrakdar, Halliburton Sperry Drilling;
D.J. Seifert and S. Al-Dossary, Saudi Aramco,
Conference and Exhibition, Oct. 4-7, New
Orleans, Louisiana
SPWLA 2009
“Multipole Sonic Logging in High-Angle Wells,”
J. Market, and W. Canady, Halliburton, presented
Symposium, June 21-24, The Woodlands, Texas
SPWLA 2010
“Multi-Sensor Geosteering,” B. Calleja, J. Market,
J. Pitcher, and C. Bilby, Halliburton Energy
Services, presented at the 2010 SPWLA 51st
Annual Logging Symposium, June 19-23, Perth, Australia
SPWLA 2010
“Application of High-Resolution LWD Borehole
Images for Reservoir Characterization in
Tectonically and Geologically Complex Reservoirs,”
M. Dautel, R. Chemali, M. Morys, W.E. Hendricks, and D. Hinz, Halliburton; R. Spicer and D. Lund, Oil Search Limited, presented at the 2010 SPWLA 51st Annual
Logging Symposium, June 19-23, Perth, Australia
Wireline Logging Recommendations
As a basic logging suite to provide fluid saturations, porosity, gas identification, and predict
pore pressure ahead of the bit, Halliburton
recommends running a QuadCombo tool
string, comprising resistivity (Xaminer™ MCI,
LOGIQ® ACRt™, DLL™ or MSFL®/MLL™), spectral density (LOGIQ®SDL™), neutron-
porosity (LOGIQ® DSEN-I or DSN™ II), and
compensated acoustic (BSAT™) sensors. A
slimhole (2.35-in. OD) version (UltraSlim™)
tool consisting of resistivity, density, acoustic,
and gamma ray (SACRt, SSDL, SDSN, SBSAT,
and SGR) sensors is also available. The above
recommendation is based on conventional
wells. Please refer to Shale Solutions brochure
for the Mature Shale evaluation components
needed to obtain accurate measurements of
the critical parameters.
This logging suite allows determination of the
critical petrophysical properties (porosity, water
saturation, gas identification, and pore pressure).
In problematic wellbores with poor stability
or that have a high potential for sticking tools,
an electronically activated (rather than tension
activated) wireline release system (RWCH™
Releasable Wireline Cable Head) can improve
wireline tool recovery and avoid risky and costly
fishing jobs. The LaserStrat® wellsite chemostratigraphy service is recommended for gross stratigraphic control in wells where major changes in
lithology and mineralogy are suspected. Mud
logging services are also recommended.
Halliburton also recommends integrating
advanced logging services and processing with
the basic suite to enhance the reservoir characterization that can result in a more
accurate completion design. Advanced services
include:
• Crossed-dipole acoustic log (WaveSonic®
service with geomechanical processing and
anisotropy analysis) for geomechanical properties, fracture identification, and anisotropy
analysis (stress orientation) for designing the
fracture treatment
• Elemental analysis tool (GEM™ tool) for
precise evaluation of complex mineralogy
• NMR service (MRIL®-Prime and MRIANTM T1
and T2 processing analysis) for the determination of pore distribution, identification of effective porosity, and estimation of permeability
/ 141
• Borehole imaging device (XRMITM, OMRITM,
or Cast-VTM, and XRMI image analysis)
for fracture identification and evaluation
(natural or induced, stress orientation, dip
analysis, and facies analysis) to optimize
fracture placement.
In the absence of crossed-dipole acoustic data,
geomechanical properties can be estimated
through a combination of conventional wells
logs. In structurally complex fields, a formation
tester (RDTTM) tool combined with advanced
downhole (ICE CoreTM) fluid and pressure
analysis may be critical to the identification of
bypassed reserves.
In addition, running a cased-hole carbon/
oxygen pulsed-neutron log (RMT-EliteTM
Reservoir Monitoring Tool) together with the
Chi Modeling® service uses the triple-combo
and data from the RMT-EliteTM Reservoir
Monitoring Tool to model (predict) openhole
log measurements and create pseudo-open
hole logs in offset well intervals where logs are
nonexistent or of extremely poor quality.
Elemental analysis, acquired by the openhole
wireline geochemical logging sensor (GEMSM
elemental analysis service) and a casedhole pulsed-neutron sensor (RMT-EliteTM
Reservoir Monitoring Tool), can enhance
identification of clays, complex mineralogy
and lithofacies. The GEM tool provides direct
/ 142
CHISM
Modeling
Input
(Original)
Output
(Synthetic)
Gamma Ray – GR
Intrinsic Sigma – SGIN
Intrinsic near/far ratio – RIN
NPHI
Capture near/far ratio – RTMD
RHOB
Near detector count rate – NTMD
DEEP
RESIS
Far detector count rate – FTMD
Near sigma borehole – SGBN
Interconnection
(Common to all)
Fig. 14. Generation of a synthetic openhole triple-combo logging suite using pulsed-neutron log data
as input to the Chi Modeling neural-network processing
measurements of aluminum and magnesium,
which are very important for determining
clay volume and accurately typing shale
formations. Furthermore, once a model has
been developed, log-derived mineralogy
data can be used to estimate porosity, grain
density, TOC, to identify potential frac barrier
zones, and the best intervals to perforate.
The LaserStrat® service can perform similar
elemental analyses on core or cuttings and
the results can be used to calibrate GEM tool
results and thus, increase confidence in the
log interpretation.
Nuclear magnetic resonance logging is a
valuable tool for porosity, TOC, hydrocarbon
identification and water saturation in mature
reservoirs. The MRIL® Prime, MRIL® XL, and
MRIL-WDTM Magnetic Resonance ImagingTM
Sensor services combined with MRIAN T1 and
T2 processing provide lithology-independent
effective (free-fluid) porosity. Free-fluid porosity is used to quantify the amount of
free gas in the matrix porosity, clay- and
capillary-bound water, bulk gas detection, fluid
typing, fluid contacts, hydrogen-index porosity,
permeability, and viscosity. These results help
identify the formation intervals most likely to
SPE 94716
produce
hydrocarbons.
“Application of Chi Modeling Using Pulsed
Neutron to Create Pseudo-Open Hole Logs,”
S.Reed, J. Quirein,and J.P. Torne,Halliburton
Energy Services; M. Morales, J. Bernal,and M.
Perez,Activo IntegralBurgos, PEMEX; andM.
Casares, Northern Region, PEMEX, presented
at the 2005 SPE Latin American and Caribbean
Petroleum Exhibition and Conference, June 20-23, Rio de Janeiro, Brazil
SPE 103662
“Applications of Artificial Neural Networks
and Dipole Sonic Anisotropy in Low-Porosity,
Naturally Fractured, Complex Lithology
Formations in the Southern Land Region of
México,” G. Escamilla, H. Mesa, B. Ponce, R. Graham, C. Kessler, and J. Murillo,
Halliburton Energy Services; E.O.J. Bueno
and I.C. Pérez, Pemex, presented at 2008 SPE
International Oil Conference and Exhibition,
Aug. 31-Sept. 2, Cancun, Mexico
SPWLA 2009_X
“A New Neutron-Induced Gamma-Ray
Spectroscopy Tool for Geochemical Logging,”
J. Galford, J. Truax, A. Hrametz, and C. Haramboure, Halliburton, presented at the
2009 SPWLA 50th Annual Logging Symposium,
June 21-24, The Woodlands, Texas
SPWLA 2009_T
“Mineralogy Analysis from Pulsed Neutron
Spectrometry Tools,” L. Jacovson, J. Truax, S.
Kwong, and D. Durbin, Halliburton, presented
Symposium, June 21-24, The Woodlands, Texas
SPWLA 2010_IIII
“A Novel Approach to Shale-Gas Evaluation Using
a Cased-Hole Pulsed Neutron Tool,” D. Buller, S. Fnu, S. Kwong, Halliburton; D. Spain, and M. Miller, BP America, presented at the 201
SPWLA 51st Annual Logging Symposium, June
19-23, Perth, Australia
SPE 145709
“Magnetic Resonance Utilization as an
Unconventional Reservoir Permeability Indicator,”
J. Bray, C.H. Smith, S. Ramakrishna, and
E. Menendez, Halliburton; presented at the
2011 SPE Annual Technical Conference and
Exhibition, October 30-November 2, Denver,
Colorado
SPE 158833
“Sensitive New NMR Hybrid T1 Measurements
for Gas Shale, Heavy Oil, and Microporosity
Characterizations,” L. Li and S. Chen,
Halliburton, presented at 2012 SPE Annual
Technical Conference and Exhibition, Oct. 8-10,
San Antonio, Texas
Advanced Wellsite Evaluation
On-site analysis of drill cuttings provides
estimates of gross lithology and mineralogy.
Hallibuton’s new LithoSCANSM service uses a
mobile SEM and energy-dispersive X-ray spectrometers combined with the automated data
acquisition, analysis, and reporting capabilities
of FEI’s QEMSCAN® WellSiteTM tool to quickly classify rock types. Rather than averaging
cuttings matrix properties across an entire sampling interval, the highly detailed analysis
can quantify mineralogy, density, relative
volume, and textural properties, such as quartz
grain size, independently for each lithology
within the given interval providing greater
accuracy, mineralogical detail, and textural
resolution. In addition, the entire sample
collection and preparation time is 25 minutes.
The LaserStrat® service provides high-quality
wellsite determination of mineralogy and TOC
based on elemental concentrations in core and/
or drilling cuttings that can be integrated in the
petrophysical model. Geochemical zonation
increases confidence in picking casing points,
coring points, and recognition of missing or
expanded sedimentary sections. These data
are integrated with other log and core data
in the petrophysical model to determine the
zones with the highest production potential.
In mature reservoirs, these techniques enable
selective perforations in the most productive
/ 143
Case STUDY:
LaserStrat® In-Field Service Helps
Deliver Higher Production in Tight
Oil Wells
The operator in the Eagle Ford play had
experienced disappointing results following
the practice of equally spacing fracture stages
along the length of the lateral and was seeking
detailed reservoir information that would
improve the percentage of fractured intervals
contributing to production and otherwise
optimize the stimulation treatment. Sperry
Drilling services recommended the LaserStrat®
In-Field Service to obtain direct elemental
measurements on drill cuttings along the full
length of the lateral wellbore to construct
a LaserStrat Development Log. This log
provides Redox metal concentration, clay
content, mineralogy, RBI (Relative Brittleness
Index), and gas values. A reservoir analysis
incorporating this information, together with
the results of GR/ChemoGR® analysis and
available mineralogy, and identified a new target within the Eagle Ford shale. With this new
target information from LaserStrat analysis,
the operator was able to optimize positioning
of fracture sleeves and stages over the course
of drilling four wells, resulting in significant
increases in oil and gas production.
areas, rather than even spacing of perforations.
The mineralogical data can also be used to
calibrate log-derived results.
/ 144
Mud logs from existing wells provide indications
of gas shows and the depths at which they were
detected, and also provide flame-ionization
detector readings and chromatographic analysis
of the gas. Mud-logging systems in new wells
(EagleTM Gas Extraction System) acquire
continuous high-quality constant-volume,
constant-temperature mud-gas samples that
are suitable for use in advanced gas analysis
systems (DQ1000SM mass spectrometer service)
and enable reliable predictions of formation
fluid type.
Minimizing Surface Impact While Reducing
Installation Time and Cost
The distinct infill drilling and completion
challenges of highly depleted mature fields
extends to minimizing the surface footprint
of often constricted wellsites. Furthermore, in
aging wellbores especially operators must deal
with often heavy influx of unwanted fluids that
not only increase operational costs, but also restrict the economical drainage of the reservoir.
For mature fields, particularly those produced
through slot-restricted offshore platforms, the
drilling of new infill wellbores to reach untapped
reserves and maintain production may not
be a viable option. As production continues
to decline from aging wellbores, without a
cost-effective solution, the economics of these
wells will take a serious hit. Fig. 15. SperryRite® Multilateral Systems
Maximizing Reservoir Drainage through
Advanced Well Architecture
Halliburton’s holistic solutions to reducing the
costs and minimizing the surface impact of an
infill drilling program includes state-of-the-art
multilateral technologies. These integrated
solutions include an optimized intelligent
completion to increase drainage at the lowest
possible cost and environmental impact.
Multilateral drilling, either with dual- or
multibranch lateral wells, is a viable and
cost-effective solution to achieve economic
viability in mature fields. Halliburton’s new
generation SperryRite® multilateral systems
offer a variety of advanced drainage architectures for new and re-entry wells that enhance
reservoir management and increase production through greater reservoir exposure.
Incremental reserves and production can be
added for a fraction of the cost of conventional wells, while the use of
SPE/IADC 119458
“Multilateral Wells in the Castilla Field of Eastern
Colombia: A Case History of the Guadalupe
Reservoir,” O. Mercado, Ecopetrol; J. Velez, and
S. Fipke, Halliburton, presented at the 2009
SPE/IADC Drilling Conference and Exhibition,
March 17-19, Amsterdam, The Netherlands
multilateral wells reduces the number of
surface locations required and the associated
environmental impact, as well as overall project
costs. SperryRite multilateral systems can be
designed for use in clastic and carbonate or
depleted reservoirs and will accept high-pressure fracturing within each of the laterals.
Meanwhile, bolstering the SperryRite
solutions and delivering even more value to
operators of mature assets was the recent acquisition of widely respected Intelligent
Well Controls Ltd. (IWC) of the UK that
brings an innovative portfolio of MWD–related
SPE 152196
“Multilateral Wells Reduce CAPEX of Offshore,
Subsea Development in Australia's Northwest
Shelf,” B. Lawrence, Apache Energy Ltd.; M. Zimmerman, A. Cuthbert, and S. Fipke,
Halliburton, presented at the 2010 IADC/SPE
Drilling Conference and Exhibition, February 2-4, New Orleans, LA
SPE 128314
SPE 152196
“Multilateral Wells Reduce CAPEX of Offshore,
Subsea Development in Australia's Northwest
Shelf,” B. Lawrence, Apache Energy Ltd.; M. Zimmerman, A. Cuthbert, and S. Fipke,
Halliburton, presented at the 2010 IADC/SPE
Drilling Conference and Exhibition, February
2-4, New Orleans, LA
“Discrete Fracturing of a Deep, Unconventional
Shale Play Using Multilateral Technology,”
D.G. Durst, M. Vento, , G. Tucker, and M. MacDonald, Halliburton Energy Services,
presented at the 2012 SPE Hydraulic Fracturing
Technology Conference, February 6-8, The Woodlands, TX
technologies that further improves the performance and lowers the costs of multilateral systems. Among the IWC
technologies meshed into the SperryRite
multilateral suite is real-time casing-string
orientation that allows Sperry to install
multilateral systems without the need for
additional orienting runs. The state-of-the-art
technology can save operators up to three
runs per isolation junction.
SPE 155532
“Embracing the Challenges—Installation of the
Deepest Level 4 Multilateral Cemented Junction,”
A.W. Hua, T.X. Qing, Y.X. Tong, B.D. Xiang,
Tarim Oilfield Company; C. Ponton and D. Durst, Halliburton, presented at the 2012
IADC/SPE Asia Pacific Drilling Technology
Conference and Exhibition, July 9-11, Tianjin, China
SPE 38494
“Design, Planning, Implementation &
Management of a Multi-Lateral Well on the
BP Forties Field: A North Seas Case History,”
R.D. Jones, J. Rose, P. Lurie, E.D. Hibbert, BP
Exploration Operating Company Ltd.; and P.
Butler, and A. Freeman, Halliburton, presented
at the 1997 Offshore Europe Conference,
September 9-12, Aberdeen, Scotland
/ 145
Meanwhile, bolstering the SperryRite solutions
and delivering even more value to operators
of mature assets was the recent acquisition of
widely respected Intelligent Well Controls Ltd.
(IWC) of the UK that brings an innovative
portfolio of MWD–related technologies that
further improves the performance and lowers
the costs of multilateral systems. important in mature subsea fields. Despite the
advances in multilateral and intelligent completion technologies, in applications where more
than two multilateral junctions were stacked in
a single well, operators were unable to provide
intelligent flow control from each leg, which
is critical for reservoir management. At best,
they could individually control one branch of
a stacked multilateral junction well through a
single ICV, while in the remaining branches
had to be commingled through a shared ICV.
Consequently, when production had to be
throttled back on any of the commingled legs,
production from all the commingled branches,
likewise, had to be cut back. Even worse, if
gas-breakthrough occurred on any of the commingled laterals, all legs had to be shut off.
It goes without saying, but the overriding
objective of multilateral wells is to increase
drainage and optimize slot recovery, especially
Sperry resolved that costly issue with the
FlexRite® Multibranch Inflow Control (MIC)
system, an innovative multilateral junction
SPE 166143
“Multilateral Wells in the Urucu Field of Western
Brazil: Reducing Environmental Impact in the
Amazon.” Mario Vento and Nazildo Batista,
Halliburton Energy Services; Sandro Mendes and
Marcelo Albuquerque, Petrobras, presented at 2013
Sept 30 – October 2, New Orleans, LA
Applications for Mature Fields MLT
Challenge
Solution
Sperry Rite Multilateral System
• Addition of branches to
existing wells on mature assets
• Re-entry to extend the life
expectancy of mature fields.
ReFlexRite® System (Level 5)
• Maintain production without
drilling new wells
• Ability to maintain full functionality with mainbore and lateral
wellbore access.
• Maintain production while
constructing additional
branches
/ 146
• Access more of the reservoir
with the few remaining slots
available.
• Maintain production from an existing
well while adding additional laterals
IsoRite® System (completion system)
• For through-tubing lateral re-entry
access and isolation
and completion solution that allows a multilateral well to be completed with sand screens,
swellable packers, Inflow Control Devices
(ICDs) and Interval Control Valves (ICVs)
to help maximize oil production from each
multilateral leg. The FlexRite MIC is the industry’s first multilateral completion system that
provides sand control at the junction and the
ability to remotely control flow of each individual branch of a multilateral well with three or
more legs, without costly subsea intervention. The new FlexRite MIC multilateral system
incorporates the EquiFlow autonomous inflow
CASE STUDY:
ReFlexRite® System Exposes More
Reservoir; Hikes Production 300%
Needing to expose more reservoir to improve
the economics of its aging producer, the
operator selected the ReFlexRite® multilateral
system to convert an existing single-bore well
to a multilateral well while simultaneously
maintaining production from the original
wellbore. Track-guided milling provided fast
and efficient window cutting, sealed with a
hydraulically isolated TAML Level 5 junction.
With the successful installation of the new
high-strength junction, an additional 5,138
m (16,857 ft) of new reservoir was exposed,
boosting daily production rates more than
300% to 7,550 BOPD.
control device (AICD) to choke off unwanted
fluid inflow and the Halliburton Swellpacker
isolation technologies. Thus, the new FlexRite
MIC multilateral system provides the ability
to deploy a single-trip completion system consisting of multiple, slim hole ICVs,
through stacked TAML level 5 junctions. An
unlimited number of FlexRite MIC junctions
can be installed into a well and remotely
controlled inflow valves can be installed with
each ICV isolated at each junction. Now
production or injection can be managed
and controlled at each individual lateral
totally independent of all other lateral legs.
Water/gas breakthrough can be delayed, and
production can be optimized. It is expected
that implementation of this new technology
development will allow operators to dramatically improve overall recovery rates.
Along with the FlexRite MIC, the highly flexible SperryRite multilateral systems provide re-entry capabilities for full functionality with the main borehole and
access to the lateral branch, thereby allowing
continual development of mature assets. Operators are even able to maintain production as new branches are being constructed. SperryRite encompasses an
extensive and cost-effective technology portfolio for a range of multilateral applications,
including: CASE STUDY:
FlexRite® MIC Effectively Controls Three North Sea Laterals to Hike Oil Production
The North Sea field had primarily been a gas producer with the oil previously deemed uneconomical to produce, owing to the thin oil-bearing layers overlaid by a thick gas cap with limited
slots available. Implementing multilateral technology allowed the operator to successfully exploit
the oil reserves with advanced reservoir drainage architecture. However, with the gas above and
water below, gas-breakthrough eventually occurred and reduced the oil production. In addition,
the formation can produce a significant amount of sand, making it critical for the multilateral
system to provide sand control at the junction. In response, a 10¾-in FlexRite MIC system was
installed from the semisubmersible with three inflow control valves, making it the world’s first
TAML Level 5 multilateral well with remote individual inflow control of three laterals. To date,
all the inflow control devices are operating flawlessly, allowing the operator to increase reservoir
exposure and maximize long-term oil production while providing additional flexibility and
control to reduce and/or delay gas breakthrough that continues to become more unpredictable
on this maturing field. Upon completion of the well, all inflow control valves were opened fully,
but if the need arises, full individual lateral control is now in place to improve control of the
production. With the flexibility of the FlexRite MIC system, the operator has flow control in the
mainbore below the junction for all laterals, allowing for enhanced oil recovery and helping to
increase the well life.
After the success of the first installation, the operator plans to install the FlexRite MIC multilateral solution in all wells in this field with three or more branches and has to date installed the
multilateral system in eight North Sea wells. The operator is also looking for other global applications to use this technology to improve well management with greater flexibility, optimize
production rates and enhance oil recovery.
• Premilled window systems
• Milled exit window systems
• Multilateral completion systems
In addition, all SperryRite premilled window
systems provide proven easy drill-out in new
wells, with no steel debris and less time spent on
cleanouts, further enhancing economic viability.
Sperry Drilling junction solutions between the
main borehole and lateral branch cover the full
/ 147
range of TAML (Technology Advancement for
Multi-Laterals) complexity levels. SperryRite
multilateral systems run the gamut from closely-spaced single, double or triple shortradius window exits with barefoot laterals or
drop liners, to a premier system combining
track-guided window milling and a TAML
Level 5 high-strength junction system with
sand control. MAINBORE
Milled window
The SperryRite suite features the TAML
Level 5 ReFlexRite® System that combines
the precision of the track-guided MillRite®
milled exit multilateral system with the highstrength FlexRite® sealed-junction system for
sand control. The premier ReFlexRite system
provides maximum flexibility for recompletion
of existing wells while maintaining full isolation
and flow-control capabilities from the main bore.
For re-entries and sidetracks, the MillRite®
milled-exit multilateral system offers single-trip
window machining, delivering smooth and
geometrically precise exit windows with
position control that allows for continual lateral
re-entry. The MillRite system incorporates a
special window-milling machine with a latch
coupling anchoring system that permits
the repeatable creation of a near-rectangular
window at a precise depth and azimuth on a
repeatable basis.
/ 148
Washed over
LatchRite®
transition joiny
MillRite®
milling
assembly
Sperry Latch
Coupling with
anchor packer
(for use in
existing wells)
LATERAL BORE
MillRite® Junction
TAML Level 2 or 4
LOWER MAINBORE
Fig. 16. MillRite® Milled Exit Multilateral
System
By controlling the window geometry and position, the versatile MillRite system is especially
beneficial in TAML Level 2 and 4 wells, requiring lateral re-entry and through-tubing
re-entry, and accommodates the installation
of TAML Level 5 completions. The MillRite
system helps to eliminate problems associated
with conventionally milled windows that typically are elliptical and spiraled with no
control over precise depth, orientation or full-gauge section length. The MillRite
windows are machined with an elongated
full-gauge aperture along their entire length
parallel to the axis of the casing. The straight,
longer window geometry eliminates the dogleg
severity problems that are seen when running
lateral liners or tools into the lateral bore
through conventionally milled windows.
SperryRite solutions for mature field multilateral
development also include IsoRite® system, which
provides a completion window system equipped
to accommodate setting of deflectors for lateral
access or isolation sleeves for lateral control.
Moreover, the IsoRite system can be modified
and equipped with a self-locating key and latch
coupling that together allow for installation in
a conventionally milled window at the required
azimuth and depth for a lateral completion operation for through-tubing re-entry access
and isolation. The IsoRite system is designed to
minimize NPT with an enhanced well design.
IsoRite system allows for repeatable lateral
re-entry without having to pull the completion
and its incremental modular design can be used
to upgrade existing junctions. IsoRite systems
also can be stacked in series and used at all
inclinations and azimuths.
Addressing Depleted Zones
Accessing bypassed reserves or exploring new,
underlying horizons in a mature field typically
involves penetrating zones in the formation
that may have been producing for years.
Consequently, reduced pore pressures from
earlier fluid extractions has left the formations
depleted, narrowing the operating window
between the pore pressure and the fracture
pressure. The resulting drilling problems,
usually centered on wellbore instability and can
spawn a number of issues, including stuck pipe
and severe circulation loss, which can not only increase NPT but raises a host of HSE concerns. Halliburton’s integrated approach to addressing
the distinctive issues of drilling depleted
formations begins with a thorough understanding of the geomechanical issues at play
and continues with customized engineered
solutions for controlling low equivalent circulating densities (ECD) and strengthening the
unstable wellbore. If losses do occur, a full suite
of application-specific lost circulation materials
(LCM) is available to head of the most severe
case of lost returns.
Define the
Geological Features:
Stress Field
Bedding
Faulting
Stratigraphy
Lithology
Tectonics
Collect
Rock Properties:
Strength
Elastic Modules
Porosity
Planning the Well:
DESIGN
THE MOST
STABLE
WELL
Est
timate
Ge
eo-pressu
ures:
Poree Pressure Gradient
Oveerburden Gradient
Fraccture Graddient
Sheear Fracture Gradient
Select:
Mudd Densityy
Mudd Chemistry
Well Trajectoory
Casing Depthh
Permeability
Activity
Fig. 17. Planning the well.
Form
mation Evaluatio
on:
Drilling Support:
Images Logs
Coring
MWD, LWD, PWD
Cuttings
Mud Logging Tops
WL Logging
MDT; RFT
RHOB
Leak-O
Off Test
KEEP
THE WELL
STABLE
Goo
od Drilling
Prac
ctices
Pumping Rate
ROP
Well Cleaning
POH and TIH
Deviation Control
Running Casing
Cementing
Bit Selection
Te
esting and
Ca
alibrating:
Caliper
Mud Losses
Adju
usting and
Con
ntrolling:
Mudd Densityy
Mudd Chemistry
Mudd Properties
Well Trajectoory
Casing Depthh
Fig. 18. Drilling support.
/ 149
Understanding Geomechanics Key to
Successful Development of Mature
Reservoirs
In planning an infill drilling program in a
highly depleted field, a thorough understanding of its geomechanics is necessary to ensure
initial and long-term well stability. At well
completion, and especially during fracturing
and stimulation, knowledge of geomechanical
properties such as rock composition and
strength and stress field orientation helps operators avoid costly mistakes by implementing
inappropriate wells and completion designs.
During development, geomechanical programs
have taken planning to a new level, delivering the
industry’s most accurate suite of software that
gives geoscientists and engineers the data they
need to make critical decisions, from determining
whether a reservoir is commercial and, if so, how
it should be developed. The objective is to provide
a strategy that will incorporate the optimum
reliability, safety and efficiency into the plan and
deliver maximum bottom line value.
Geomechanics, likewise, plays a vital role in
analyzing and optimizing production factors,
from initial production to abandonment.
From fracture gradient changes, to sanding,
to compaction and subsidence, Halliburton’s
geomechanical workflow analyzes production
parameters and provides solutions to extend
the life and ultimate recovery of a reservoir.
/ 150
1. Study 4D Seismic Data
ata
2. Determine production induced
d subsidence
3. Build a numerical model
Geometrics
model
Overburden
section
Reservoir
model
Reservoir
section
5. (a) Measured
compare surface
6. Offer solutions to minimize the
negative impact of subsidence
((b) Modeled
subsidence
profiles
4. Obtain compaction and subsidence
Fig. 19. From seismic to production, geomechanics analyses can be used to avoid many problems
across the mature well/field life.
Managing Low ECD to Maintain Well
Integrity While Drilling Depleted Zones
• Reducing NPT, while improving well
integrity
The narrow margin between fracture gradient
and pore pressures intrinsic of depleted zones
in mature assets generate low Equivalent
Circulating Densities (ECD) that if uncontrolled can increase the risks of fracturing
pressure-sensitive formations and induce lost
circulation. • Improving efficiency and cost-effectiveness
Halliburton’s chemical and mechanical Low
ECD Solutions work in synergy to safely,
reliably and efficiently help maximize the value
of a depleted mature asset by:
• Maintaining well control, while avoiding
formation damage
• Tapping into the reservoir safely
Managing Fluid Properties to Resist Sag,
Control ECD
Many of the solutions to low ECD margins
begin with the drilling fluids. In these
environments, unstable fluid rheologies may
lead to NPT and threaten the project success.
For drilling narrow fracture gradient / pore
pressure margins, Halliburton Baroid offers the
BaraECD™ high-performance invert emulsion
drilling fluid and the companion BaraPure™
salt-free version, which are designed to reliably
and cost-effectively maintain ECD control in
narrow drilling window intervals.
The exceptional rheological profile of the
BaraECD drilling fluid system delivers low
viscosity to minimize ECD, while providing
Fig. 20. ECD must remain between the pore
pressure gradient and the fracture gradient to
avoid issues, maintain safe drilling, and successfully drill difficult sections. This profile shows a
depleted zone, where pressure is significantly
lower than surrounding formations.
superb and customized suspension properties
to optimize hole cleaning and resist barite sag,
even during prolonged static periods. The
BaraECD system uses the very latest emulsion
and polymer technology to maintain superb
rheology and robust, yet fragile gels and can
be customized to deliver ECD control based
on temperature requirements, environmental
restrictions and logistic limitations.
The BaraPure high-performance invert
emulsion fluid system provides operators a
salt-free, environmentally sound solution
to oil-based drilling, helping increase
operational efficiency and reduce costs. The
system has replaced the internal, inorganic
salt solution phase with a biodegradable,
hygroscopic internal phase. Using innovative,
stabilizing polymer technology, this system
shows comparable performance to typical
high-performance oil-based systems while
also meeting the world’s most stringent
environmental regulations. While salts are
typically used to lower water activity and increase fluid performance, the BaraPure system has been engineered to exhibit
rheological properties and sag resistance comparable to typical high-performance invert
emulsion systems without the use of chlorides.
The system exhibits tolerance to contaminants
and strong shale stability similar to what is
expected to be seen in oil-based systems.
Fig. 21. This test measures yield point and
suspension properties at very low shear rates.
The BaraECD™ fluid system shows a high
yield point and demonstrates formation of
structure at low shear.
CASE STUDY:
Low-ECD Fluid Solution Avoids Losses
in Depleted GOM Zone
At 5182 m (17,000 ft), the slim-hole high-angle
Gulf of Mexico well encountered a depleted
and permeable zone that was being drilled at
3,000-psi overbalance, elevating the risks of
lost circulation, stuck pipe and well control
issues. The slim hole diameter raised the risks
of elevated ECD, which could not be tolerated
given the 14.8 lb/gal fracture gradient and
13.7 lb/gal surface mud density. Halliburton
responded with its BaraECD Low ECD
fluid solution that allowed the operator to
successfully reach bottom without HSE issues,
indications of sag, mud losses or stuck pipe
while drilling, tripping, logging or running
casing. A safe ECD window was maintained
below the safe 4.8 lb/gal operating window.
/ 151
By removing chlorides from the system,
cuttings can be land farmed in locations where
expensive cuttings treatment services, such as
thermal treatments or cuttings re-injections,
typically have been employed. On-site disposal
can reduce total rig cost by as much as 20% as
well as eliminate the logistical and operational
concerns associated with waste management
equipment. The BaraPure fluid system is ideal
for onshore and freshwater inland locations
operations where environmental regulations
Fig. 22. The VersaFlex® Low ECD system can
provide nearly twice the annular flow area.
thereby allowing for increased flow rates.
/ 152
limit waste management options.
Reducing Stuck Pipe Issues During Liner
Deployment
Excessive pressure drops across the liner top
in tight margins can dramatically hinder the
efficiency, long-term reliability, safety, and
ease of running liner hangers. A key component of Halliburton’s holistic expandable
liner hanger solution, the VersaFlex® Low
ECD system was engineered specifically to
handle low-pressure formations and narrow
fracture gradients. Independent field analysis
routinely verifies the capacity of the system
to reduce pressure drop across the liner top
during circulation and cementing in the well
construction design process.
By using an outer diameter (OD) smaller than
industry-standard, the VersaFlex Low ECD
system reduces pressures within a wide range
of mud densities. The resulting increase in the
bypass area promotes faster trip-in speeds.
This enhanced flow rate helps optimize the cementing process, especially when
integrating its reciprocation and rotation
capability, thus increasing cement integrity.
The VersaFlex Low ECD system also carries
Fig. 23. VersaFlex® ECD System integrated with the SuperFill™ surge reduction system and Protech
CRB® centralizers.
an improved operating envelope without
inner diameter (ID) restrictions.
The high-torque rating of the VersaFlex Low
ECD system permits aggressive reaming
and drill-in capabilities, which are especially
beneficial in sloughing formations, swelling
clays, and cave-ins.
Solution for Reducing Surge During
Casing Run In
Pressure surges restrict the operational efficiency
of running casing through low-ECD zones, reducing running speed and potentially damaging
the formation. Halliburton ‘s SuperFill™ Surge
Reduction System was developed specifically to
help manage surge pressures and enhance runin efficiencies. The SuperFill system provides
reliable self-filling of the fluids into the casing to
minimize the ram effect on the formation caused
by casing running operations. The SuperFill
suite works seamlessly to provide reliable casing
auto-fill to minimize the surge and swab effects
and maximize the running speed into the well.
Complementing the surge reduction system
are the Protech DRB® and Protech CRB®
Centralizers' Service, which help minimize
blade embedment into the formation while
running in. The low friction coefficient helps
minimize the drag forces between the casing
and the formation to enable smoother casing or
liner running operations. The modular blade
design increases the flow area to reduce the
frictional pressure drop across each centralizer
and, in turn, reduce pressure on the formation,
minimizing Low-ECD damaging effects.
Preventing and Remediating Lost Circulation
Lost circulation remains the most troublesome,
and costly, downhole problem while drilling—a
problem that is magnified many times over
during construction of infill wells in heavily
depleted formations. Lost returns elevate the
risks of wellbore instability, packoffs, stuck pipe,
well-control issues, formation damage and even
the inability to complete the well.
Recognizing that preventing or remediating lost
circulation goes well beyond simply pumping
lost circulation material (LCM), Baroid offers
a full portfolio of solutions to selecting and
applying preventative materials to strengthen
the unstable wellbore. Baroid, of course, offers
a comprehensive suite of drilling fluid loss
control additives and LCM to remediate lost
Fig. 24. Predictive DFG™ Software Aids in Product Selection and Treatment Design: Another essential
component of the WellSET treatment is the simulation of actual wellbore conditions. Halliburton DFG™
hydraulics modeling software can predict the equivalent circulating density (ECD) over an interval, calculate
the width of a fracture that may be initiated, and select and design a proper material and particle size
distribution that can efficiently prop and plug that fracture.
/ 153
(1) Calculate Frac Width
(2) Select LCM
(3) Displays Solution
Fig. 25. The Halliburton DFG™ software with DrillAhead® hydraulics module can help predict the
equivalent circulating density (ECD) over an interval in one module, calculate the width of a fracture
that may be initiated, and select and design a proper material and particle size distribution that can
efficiently prop and plug that fracture in a second module. The matchless WellSET® treatment materials are selected from sized resilient graphitic carbon (eg., STEELSEAL® lost circulation material) and
ground marble (eg. BARACARB® 600 bridging agent).
returns once they occur, but stands as an
industry leader in additives and other solutions
for preventing losses from propagating in the
first place.
/ 154
Highlighting the preventive solutions portfolio
is the WellSET® wellbore-stress management
service that combines specially engineered
software and loss prevention material (LPM)
Fig. 26. After being mixed and pumped through
any drill string configuration, an engineered
HYDRO-PLUG® LCM pill is spotted across the
loss zone. Upon its temperature-activated
hydration, HYDRO-PLUG LCM pill forms a competent seal within the source of lost circulation
that eliminates further whole fluid loss.
to strengthen the wellbore to prevent lost
circulation. The service is designed to increase
hoop stress in the near-wellbore region by
placing a specially selected plugging material in
an induced fracture that helps prevent further
pressure and fluid transmission to the fracture
tip, while at the same time widening and
propping the fracture.
• Circulating and static intervals (drilling,
sliding making connections, etc.)
An essential component of the WellSET treatment
is the simulation of actual wellbore conditions,
using the proprietary DFG™ hydraulics modeling
software with the DrillAhead® hydraulics module
with the DrillAhead® hydraulics module. The specially engineered software predicts the ECD
over an interval and goes on calculate the width
of a fracture that may be initiated, and, ultimately,
select and design a proper material and particle-
size distribution (PSD) that can efficiently prop
and plug the fracture. The DFG program is then
able to model the changes in rheological properties resulting from the addition of the specialized
LCM with the modeled changes cycled back to
update the ECD calculations and enhance the
accuracy of the WellSET treatment.
• Fracture generation
The DFG software models key wellbore parameters, including:
• Wellbore geometry
• Hole angle and size
• Drilling mode: sliding, rotating or mixed
• ROP while sliding and/or rotating
• Downhole fluid densities based on dynamic
or static profiles
• Pump rates
• Rotary speeds
• Downhole rheology
• LCM PSD
• Effect of LCM on rheology
The Drill Well On Paper (DWoP) exercise
using the DFG Software with its DrillAhead
Hydraulics Planning Service.
While the type, concentration and PSD of the
LCM are critical factors in controlling lost circulation once it occurs, the particle type generally
is regarded as the most important variable for
obtaining a fracture sealing response in a specific loss zone. Baroid offers an all-inclusive suite of
LCM, specially engineered to promote fracture
sealing in a variety of depleted and loss-prone
formations.
The Baroid offering includes the ultraresilient
SteelSeal® specialty lost circulation particulate
comprising angular, dual composition and
carbon-based particulate additives designed to
compress with an increase in downhole pressures. The compressive property allows SteelSeal to “mold” itself into the fracture, promoting
screen-out. Given downhole pressure fluctuations, the material “rebounds,” thus continuing
to isolate the fracture tip. This property makes
SteelSeal additive one of the most effective lost
circulation materials that is currently available
for both preventing lost circulation, as well as
treating lost circulation after it occurs. SteelSeal
lost circulation material treatments have no
adverse effect on the rheological properties, even
if used in relatively high concentrations.
Besides SteelSeal additive, Baroid’s lost
circulation solutions include the composite
HYDRO-PLUG®, Duo-Squeeze® H and the
Stoppit® LCM. The Duo-Squeeze® H additive
comprises specific materials with a bi-modal PSD in a uniquely engineered concentration,
thus reducing the NPT while mixing the
individual components of the blend. The LCM
works by isolating the tip of the fracture and
sealing it with a unique composition designed
to retain granularity even under high fracture
closure stress.
Baroid also offers the Hydro-Plug LCM, an
engineered, composite solution designed to be
applied as a hesitation squeeze to mitigate partial
to severe drilling fluid loss rates in any nonreservoir formation. It differs from other hesitation squeeze products because the
engineered, composite formulation contains a
specialized hydratable polymer and reaction
retarder to control swelling.
These additives allow for the pill to be easily
pumped through any drillstring, yet still be able
to seal large subterranean apertures after exiting
/ 155
CASE STUDY:
Cuttings Loading
ROP
Duo-Squeeze® Pills Stop Losses, Allow
Lower Zone Evaluation
To evaluate a lower prospective zone, the
operator needed to stop losses in a severely
depleted zone at 10,900 ft, requiring a 16.0-lb/
gal mud density to control the pressure in the
lower sand. Several conventional LCM pills
had been spotted, along with three high-fluidloss squeezes provided by a competitor, as well
as two cement squeezes. The bit was run to
10,900 ft while two 50-bbl Duo-Squeeze® H
LCM pills were prepared. The entire 100-bbl
treatment was spotted in the wellbore. The
bit was pulled to the top of the pill at 6,500 ft,
above the intermediate casing shoe at 9205
ft, and the annulus closed. The pumps were
brought on line slowly. Initially, the pressure
came up to approximately 18.0 lb/gal EMW
and then broke back to 17.2 lb/gal EMW while
squeezing away 50 bbl, or 50%, of the LCM
pill. The pumps were shut down and the pressure monitored for the next four hours, where
a slight rise in pressure was noted, resulting
in a 17.4 lb/gal EMW. The pressure was bled
off and the drillstring run to approximately
10,700 ft. The well was displaced with a 16.0
lb/gal water-based fluid with full returns,
successfully allowing logging evaluation of the
lower production zone.
/ 156
Transport Efficiency
ECD
Fig. 28. The Drill Well On Paper (DWoP) exercise using the DFG Software with its DrillAhead Hydraulics
Planning Service.
the bit. Using a Hydro-Plug LCM pill helps
reduce rig time and operational costs, requiring
no trips out of the hole and no special pumping
or mixing equipment.
designed to increase the toughness of the LCM
in resisting pressure fluctuations, such as swab/
surge pressures or wellbore breathing after the
material has formed a seal.
Like the Duo-Squeeze and Hydro-Plug LCM, Stoppit particulate-based, composite solution
is designed to mitigate partial to severe drilling
fluid loss rates. Compatible with all mud types,
the multimodal composition is designed to provide superior sealing performance in loss zones with severe losses.
StoppitTM works by isolating the tip of the fracture and sealing it with its unique composition
Facilitating the Safe Recovery of Stuck Pipe
Pipe that becomes differentially or mechanically stuck during an infill drilling
program not only increases NPT and costs
exponentially, but poses serious well control
issues. The risks are not restricted entirely
to new wellbore construction, as completion
and intervention operations can experience
tubing, coiled tubing and packer sticking, not
specialized subsea services. And, unlike most companies, Halliburton offers trucks, skids
and specially trained crews dedicated entirely
to delivering expedient and cost-effective pipe
recovery solutions.
Fig. 29. Halliburton’s StimWatch® stimulation monitoring service enables real-time temperature monitoring
of multizone completions to show where pumped fluids are going and how much is entering each interval.
only delaying production, but putting well
integrity in jeopardy. The risks are magnified
when drilling or conducting interventions
through depleted zones, where annulus
pressure exceeds the formation pressure and
can push the pipe against the wall where it
becomes embedded.
The causes of stuck pipe include:
• Key Seat
• Formation Sloughing or Caving
• Casing Collapse
• Junk in the Well
• Cemented Pipe
• Differential Sticking
• Dehydrated Mud
• Blow Out
• Dropped Pipe
Capitalizing on its industry-leading logging expertise and resources, Halliburton Pipe
Recovery Services brings a wide range of
solutions can get operations back on track when
a pipe string becomes stuck. The process begins
with the ultra-advanced Halliburton Free Point
Indicator Tool, which depending on the recovery
method planned, isolates the stuck depth, or freepoint, in but only one or two logging passes. Once the freepoint is determined, Halliburton
delivers the technology and proficiency to facilitate safe and efficient recovery operations, be
it cutting, plugging or punching jobs, including
The Halliburton pipe recovery portfolio
encompasses a wide assortment of cost-effective
technologies, including jet cutters in various
sizes, lengths and temperature ratings for a host
of applications. The Split ShotTM cutter uses a
linear shaped charge to split tubing and casing
collars vertically. The Drill Collar Severing Tool,
a tool of last resort, uses an explosive collision
device to create a high-energy blast capable of
shearing large, heavyweight drillstrings.
Halliburton also offers alternative high-
precision tools. Chemical cutters, available
for applications from coiled tubing to 8-5/8-in.
casing, use chemicals that, when mixed with
an oil/steel wool mixture, create a reaction that
builds pressure and temperature. This opens
the severing head, and the chemical is expelled,
cutting the tubing or casing and making the stuck
pipe easier to retrieve.
In addition, unlike many cutting tools on the
market, plasma cutters, such as the MCR X
Radical Cutting Torch (XRT®) tool, cut tubulars
without requiring hazardous and expensive explosives. The Radial Cutting Torch System,
which ranges from 0.75 to 7 in. (1.9 to 18 cm)
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OD, is recognized as a highly versatile pipe-recovery tool, delivering a smooth, nonflared cut
that simplifies recovery of the stuck pipe. The
XRT tool relies on a proprietary fuel to create a
controlled thermal event that generates plasma
with very high temperature and pressure. The 4.1
flammable solid-fuel source keeps components
radio safe. The proprietary, flammable solid active
component of XRT tool allows the tool to be
shipped via commercial airline with delivery time
measured in hours rather than days.
Most of Halliburton’s pipe recovery tools are
compatible with the RED® (Rig Environment
Detonator), which enhances wellsite safety and
allows uninterrupted rig operations while the
stuck pipe is being extracted. RED products
are certified to contain no primary explosives
and are insensitive to many common electrical
hazards found at the wellsite, including RF
communications, welding and cathodic
protection.
Halliburton pipe-recovery tools compatible
with RED initiators include:
• String Shot Rods
• Jet Cutters
• Drill Collar Severing Tools
• Chemical Cutters
CASE STUDY:
WellSET® Helps Mediterranean Sea Operator Exceed Expected LOT Value and Safely Drill Two Intervals
The operator wanted to secure a dependable leakoff test (LOT) for the
8½-in. interval that would allow it to safely reach target depth, which
required drilling through a weak formation, which ranges from 12.85 to
15.8 lb/gal in equivalent mud weight (EMW). Securing a dependable
LOT would allow the drilling of some 20 ft (6 m) of 6-in. hole to evaluate
the zone where a kick was previously encountered and controlled using
17.5 lb/gal mud. The goal was to prevent the overbalanced kill fluid from
causing lost circulation to the weak formation.
For the 8½-in. interval, Baroid recommended an engineered WellSET®
services treatment using a combination of 5.5 lb/bbl SteelSeal resilient
graphitic LCM and 30.0 lb/gal BaraCarb® 50-micron sized calcium
carbonate to help provide the borehole stress management. The DFG™
hydraulics software would be used to model and calculate the induced
fracture profile experienced when the EMW in the annulus was
increased to the 15.1-lb/gal limit below the LOT value. The annulus was
pressured up to 660 to 200 psi below the expected LOT value—in order
to induce fractures to contain the borehole stress management materials.
The pressure in the annulus was then held constant for 30 min to allow
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time for plugging of the purposely induced fractures. Pressure was
then reduced to zero psi allowing the fractures to close on the WellSET
treatment materials. Based on offset information, the maximum LOT
value achieved previously in this field was 16.5 lb/gal EMW. Application
of the WellSET treatment made it possible to obtain a formation integrity
test (FIT) value of 17.0 lb/gal, which the operators considered adequate to
drill the section safely.
The same integrated solution was applied in the 6-in. section, where the
WellSET treatment was pumped across the open hole and the annulus
was pressured up to 1200 psi using 14.7 lb/gal mud. The annular pressure
was then held constant for 30 min to allow time for plugging the induced
fractures. The pressure was then bled to zero psi, allowing the fractures to
close on the WellSET materials. The formation was pressure tested using
the hesitation method and held 18.92 lb/gal EMW (2340 psi) with no
indication of leak off, which was considered adequate to drill the section
safely. The integrated WellSET treatment saved the operator the cost of
cement squeeze jobs estimated at a minimum of $100,000, including rig
time, services and products required to strengthen the shoe.
Fig. 30. Pipe Recovery Services: Halliburton offers
a wide range of free point indicators, severing
tools and experienced crews to help reduce NPT
and extra costs caused by stuck pipe.
Advanced Infill Drilling Waste Management
Solutions
Onshore and offshore, a considerable percentage
of total drilling fluid costs are consumed with
managing the solid and liquid waste streams
generated at the wellsite to meet ever-tightening
environmental restrictions. Consequently, operators require more cost-effective, HSE acceptable
and reliable solutions for reducing the on-site
footprint, while creating no bottlenecks in the
drilling operation that can result NPT.
The costs and environmental risks are compounded offshore where operators typically
rely on conventional skip-and-ship transport
to collect, handle and move drill cuttings to
onshore treatment and disposal facilities. This
methodology requires multiple crane lifts,
which are well documented as one of the most
hazardous exercises in an offshore operation. Baroid Surface Solutions™ addresses the ever-increasing risks with its innovative Honey Comb
Base (HCB™) drill cuttings bulk storage and
pneumatic handling system. Used in conjunction
with the SuperVac™ cuttings collection and
pumping system, the HCB tank is designed for
the reliable and safer discharge of bulk materials
from pneumatically driven silos.
The HCB tank pneumatically discharges
cuttings from the silo tank and onto a conveying
line that automatically deposits them into
another HCB tank positioned on a supply boat
stationed alongside the rig or platform. From
there, the cuttings are delivered onshore and
disposal takes place—a process that eliminates
the hazards associated with crane lifts and
cuttings boxes. The HCB tank does not rely
on a high-angle conical bottom to ensure mass
flow discharge and can hold approximately 20%
more bulk material in the same footprint as its
conical bottomed counterpart. Accordingly, for
every five conical bottom tanks, the operator
only needs four HCB tanks.
Like cuttings, handling, treating and disposing
of offshore drilling slop, brine/seawater and
wash water is tightly regulated with full compliance an expensive proposition. Halliburton
responded to that challenge with its Offshore
Slop Treatment Unit that uses a combination of
chemical treatment and dissolved air flotation
(DAF) to produce clean water that can either
be discharged directly or reused in pit washing
operations. Depending on the rig or platform,
the Slop Treatment Unit can reduce by as much
as 80% the slop sent onshore for treatment.
The Offshore Slop Treatment Unit can handle all
slop produced on a rig/platform, does not and does not require positioning close to slop tanks
or the pit system and can be placed anywhere
on the rig/platform where space allows for a
20 ft container. Consequently, premium space
can be optimized by positioning the unit in a more remote area, ensuring the full value of the
system is realized.
Prior to discharge, mandated field water analysis is continuously monitored for oil content with the ultrasonic OIW-EX100 oil-inwater monitor designed to operate in hazardous
environments and provide consistent, accurate
and uninterrupted measurements. The OIWEX100, which can be operated and monitored
remotely, processes a truly representative sample
size that enables a consistent and reliable measurement without the need of flow mechanisms,
/ 159
CASE STUDY:
HCBTM, SupaVacTM Combo System Helps UK Operator
Maximize ROP, Eliminate Waste Handling Downtime
Fig. 31. Honey Comb Base (HCB™) Tanks Bulk Storage and Handling of
Drill Cuttings
mechanical mixers or chemical additives.
Baroid also offers its Thermomechanical
Cuttings Cleaner (TCC), which is specially
designed for processing oil-contaminated
cuttings, slop-mud and spent drilling mud. Its
mechanical action is applied directly to the drill
cuttings via hammers that create friction which
causes temperatures to rise above the boiling
points of water and oil. Once these temperatures
are reached, hydrocarbons are removed from the
solids to an acceptable disposal limit (<1% oil on
cuttings). The oil and water vapors that remain
/ 160
In the mature, zero-discharge UK North Sea, the operator required
containment of drill solids generated while drilling the 12¼-in. section
with an oil-based mud (OBM), without requiring cuttings skips. The
raw cuttings were to be stored and transported pneumatically upstream
and into Halliburton HCB tanks onboard the rig prior to being
discharged to 16 HCB tanks located on a supply vessel. From there the
cuttings were to be transported for onshore transfer and treatment. To accomplish this, Baroid Surface Solutions personnel installed two
SupaVac SV-400 cuttings transport units below a 12-in auger and
diverter system. Once the vessel tanks were full, the contents were
taken to an onshore thermal processing plant and blown directly into a
quayside facility. During drilling of the 12¼-in sections, the combined
SupaVac pumping system and HCB system kept pace with drilling rates
of more than 300 ft/hr (91.4 m/h) with transfer rates from the rig to the
supply vessel in excess of 25 tonnes/h. The entire 12-1/4” section could
be contained and transported by vessel directly into the plant for processing with no waiting on weather or delays related to crane operations
or cuttings skips. The operator was able to drill with high penetration
rates and complete the well quickly and safely. During the operation,
the supply vessel also set a UK North Sea record by being alongside for
72 hours during the cuttings transfer operation.
are then fed through the
TCC condensing system
and recovered in the
form of recovered heavy
oil, recovered light oil, and recovered water.
With the exception of strict zero discharge areas, the TCC allows operators meet the
majority of global offshore discharge regulations
and the low <1% oil on cuttings ratio ensures
compliance to any onshore disposal methods.
Consequently, the TCC unit can eliminate
transportation costs, minimize crane lifts
associated with skip and ship operations, and
reduce excessive manual handling, thus improving HSE benefits over other thermal options.
Regardless of the infill-drilling challenge,
Halliburton has the integrated solution to help
ensure all untapped and bypassed reserves are put
into the sales stream.
The Intelligent Way to Complete the
Mature Well
Since typical reservoir optimization methods
are model-based, they are effective only if there
is no reservoir uncertainty involved. However,
in depleted mature fields, especially those being
recompleted with new multilateral branches, ensuring no uncertainties lie in wait is a daunting,
if not improbable, proposition.
Since 1997, Halliburton has been refining what
it then conceived as a new, and more intelligent,
way of completing oil and gas wells to produce
maximum reservoir exposure and drainage.
That concept has since evolved into the
Halliburton SmartWell® intelligent completion
technology, delivering enhanced functionality
through a combination of monitoring and control that helps significantly increase oil recovery,
especially in the face of reservoir uncertainties.
The combination of SmartWell system and
Halliburton’s multilateral technologies enables
maximum drainage of complex reservoirs
with lower well construction costs and higher
long-term asset value. The proven reliability
of SmartWell system technologies consistently
helps operators to cost-effectively deliver some
of the world’s most sophisticated completions.
The technologies intrinsic to tailored SmartWell
completion systems optimize production
without costly well interventions. SmartWell
technology allows operators to collect, transmit
and analyze downhole data; remotely control selected reservoir zones; and maximize reservoir efficiency and profitability by:
• Increasing ultimate recovery with selective
zonal control that enables the effective
management of water injection, gas and water
breakthrough and individual zone productivity.
• Reducing capital expenditure. The ability to
produce from multiple reservoirs through a
single wellbore reduces the number of wells
required for field development, thereby
lowering drilling and completion costs. Size
and complexity of surface handling facilities are
reduced by managing water through remote
zonal control.
• Reducing operating expenditure. Remote
configuration of wells optimizes production
without intervention.
The advanced reservoir management approach that is a SmartWell completion
system remotely monitors wellbore parameters
in real time, and provides remote control of
the inflow or outflow from the reservoir—all
without the need for mechanical intervention.
Fig. 32. Advances over the last decade
have made horizontal drilling a truely viable
field development option. The power of the
SmartWell completion in maximizing reservoir
performance comes with matching the right
completion with the right application to:
• enhance the economics of the project
• provide added wellbore exposure to the
reservoir
• allow the operator to maximize hydrocarbon (oil and gas) production or injection
(water or gas)
• enable better water hydrocarbon
management
A SmartWell system completion consists of some
combination of zonal isolation devices, interval
control devices, downhole control systems,
permanent monitoring systems, surface control
and monitoring systems, distributed-temperature
sensing systems, data acquisition and management software and system accessories. Halliburton left nothing to chance in designing
the components of the state-of-the-art
SmartWell completion system, which include:
• Chemical Injection: Provides operators
precise wellbore chemistry management
designed to help promote flow assurance,
/ 161
optimize production performance and reduce
expensive intervention
• Flow Control: An interval control valve
(ICV) controls the flow of liquid or gas into
(injection mode) or out of (production mode)
a reservoir interval.
• Permanent Downhole Gauges: Quartz crystal transducers provide real-time temperature
and pressure from the reservoir interval.
• Zonal Isolation: Control-line feed-through
retrieval production packers are used to
mechanically isolate the reservoir intervals.
• Splice Subs: Provides flexibility in the completion design by allowing assemblies to be
prebuilt in the shop, thus saving rig time.
• Control Lines: Encapsulated control lines
provide the hydraulic and electric power to
remotely operate the SmartWell system.
For wells requiring gas lift, a SmartWell system with an Auto-Gas Lift (AGL) installation helps a gas cap to increase production from a deeper oil zone. A SmartWell
system incorporating AGL reduces the surface
facilities required and lowers cost compared to
conventional artificial-lift methods. Production
also can be optimized with changing reservoir
conditions without the need for well intervention or workover.
/ 162
SPE 167273
SPE 167352
“Effective Well Management in Sabriyah Intelligent
Digital Oilfield,” M. Abdul-Raheem Jamal, M.
Al-Mufarej, M. Al-Mutawa, E. Anthony, and C.
Hom, Kuwait Oil Company; S. Singh, G. Moricca,
and J. Kain, Halliburton; L. Saputelli, Frontender
Corporation (formerly Halliburton), presented
at the 2013 SPE Kuwait Oil and Gas Show and
Conference, October 7-10, Kuwait City, Kuwait
“Digital Oilfield Technologies Enhance Production
in ESP Wells,” S.A. Al-Mutawa, E. Saleem, and
E. Anthony, Kuwait Oil Company; G. Moricca,
J. Kain, Halliburton; and L. Saputelli Frontender
(formerly Halliburton), presented at the 2013
SPE Kuwait Oil and Gas Show and Conference,
SPE 164813
“Short-Term Production Prediction in Real Time
Using Intelligent Techniques,” A. Al-Jasmi, H.K. Goel,
and H. Nasr, Kuwait Oil Company; M. Querales,
J. Rebeschini, M.A. Villamizar, G.A. Carvajal, and
S. Knabe, Halliburton; F. Rivas, Universidad de los
Andes; and L. Saputelli, Frontender Corporation,
presented at the 2013 EAGE 75th Conference &
Exhibition incorporating SPE EUROPEC, June
10-13, London, United Kingdom
SPE 163697
“A Surveillance "Smart Flow" for Intelligent
Digital Production Operations,” A. Al-Jasmi,
H.K. Goel and H. Nasr, Kuwait Oil Company;
and G.A. Carvajal, D.W. Johnson, A.S. Cullick*,
J.A. Rodriguez, G. Moricca, G. Velasquez, M.
Villamizar and M. Querales, Halliburton, 2013
March 5-7, The Woodlands, Texas
IPTC 17080
“Intelligent Completion Technology Enables
Selective Injection and Production in Mature Field
Offshore South China Sea,” K.H.S. Wee, K. Wood,
and D. Finley, Halliburton, presented at the 2013
International Petroleum Technology Conference,
March 26-28, Beijing, China
SPE 167269
“Best Practices and Lessons Learned after 10 Years
of Digital Oilfield (DOF) Implementations,”
L. Saputelli, Frontender Corporation, C. Bravo,
Halliburton, M. Nikolaou, University of Houston,
C.A. Lopez, BP, R. Cramer, Shell: T. Mochizuki,
and M. Giuseppe, presented at the 2013 SPE
Kuwait Oil and Gas Show and Conference,
>Safe and Compliant Well Abandonment
Safe and Compliant
Well Abandonment
Well abandonment is a natural part of the
oilfield lifecycle. Historically, well productivity
and costs determine when a wellbore is
abandoned or, more specifically, when the
value of production is less than operating
expenses. Today, however, environmental and
regulatory concerns add to this complexity.
Worldwide, governments and legislative authorities are either encouraging or requiring
the industry to seal and permanently take
offline unproductive wells to prevent any
environmental impact. In many cases, the decomissioning of aging wells and infrastructure is treated as standalone projects, rather
than being the responsibility of existing asset
teams with traditional contract models. The
well abandonment contracts are being managed separately with different measurements.
A permanent well-abandonment operation
involves removing the completion or
production string and subsequently setting
the necessary plugs and cement barriers at
specified depths across the producing and
water-bearing zones. These plugs must be
designed and installed as permanent barriers
to assure the well can never cause future problems. In addition, all pipe must be severed
to an agreed upon level below the surface or
seabed with all surface equipment, wellhead
and, if applicable, hardware removed. The
geographic region in which the work is performed has specific plug and abandonment
regulations and each of these orders must be
followed. Regional inspectors must verify that
the work has been conducted according to the
regulations.
The permanent abandonment of nonproductive offshore wells is set to grow exponentially
over the next few years. In the North Sea,
for example, operators have been drilling
and producing for more than three decades,
leaving many reservoirs depleted. In 2013,
authorities estimated that 3,000 wells in the
Norwegian sector alone need to be plugged
and abandoned (P&A).They also estimated
that if five rigs were dedicated to the job full
time, it would take 20 years to P&A all those
wells using conventional milling methods.
Worldwide, an estimated 30,000 offshore wells
will require P&A in the next few years at a
cost that can range from $1.5 to $4 million per
well. Consequently, finding a more efficient
alternative to traditional milling techniques is
a top priority.
Halliburton has developed and continues to
develop new software, tools and techniques
that reduce the cost of abandonment operations, increase efficiency, and adhere to all
regulations, including improving well integrity, securing formations and surface
areas. This work is done safely while
minimizing the impact of the environment.
Halliburton’s worldwide experience can help
operators navigate the often complicated
process of well abandonment, including ensuring full zonal isolation to meet all regulatory stipulations. Solutions are available
to help protect the remaining reserves, safeguard the freshwater sources penetrated by
the wellbore, and prevent surface pollution.
Halliburton’s P&A solutions include full zonal
isolation with cement, sealants, or mechanical
plugging, and pipe-recovery services designed
to allow the use of cost-saving coiled-tubing or
hydraulic-workover-unit technology to pull
tubulars. For areas where power is limited or
nonexistent, tubulars can be retrieved using
Halliburton’s innovative Downhole Power Unit
(DPU). At the end of the day, the operator is
delivered an abandoned well that complies with
all regulatory requirements, including the
pertinent legal location designation.
Designing an Efficient, Cost-Effective
Well Abandonment Program
Halliburton has the proven resources and
experience as a single-source supplier for all
the services needed to optimize well abandonment designs for any mature field. A specially
dedicated project core team will evaluate
and provide solutions for every aspect of
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the targeted well-abandonment project.
Specialists, by discipline, are brought in when
needed to save the operator time reduce P&A
costs, and provide expertise.
This multidisciplinary team, under the direction
of experienced supervisors, reports directly
to operators who have ultimate control of
the project. This cross-functional approach
can be applied to just about any mature-field
abandonment project including fluids,
cementing, as well as coiled tubing, hydraulic
workover, wireline and perforating.
Halliburton offers distinct industry-leading
advantages that are major differentiators in
the plug and abandon arena:
• Proprietary cementing technologies
• The one-trip Hydrawell Hydrawash™
Perforate, Wash and Cement (PWC) system
• Integrated services – Reliable Wireline,
Perforating, Cementing, and Special Tools
• Specialists with extensive Plug and
Abandonment experience based on a multitude of domestic and international P&A projects
Single-Trip Cementing Solution for
Compliant Isolation
Abandoning a well that is no longer productive
represents a major expenditure for operators
/ 164
with no return. The key, therefore, is to reduce
costs as much as possible while still meeting all
governmental requirements.
One of Halliburton’s advanced P&A technologies
is the all-inclusive HydraWash™ system that was
originally conceived as a hydraulic perforating
system, but has since evolved to include tubing-conveyed perforating guns, washing tools, a
cement stinger, and the Swellpacker® equipment.
These tools work in harmony to allow the operator to perforate, clean and place cement into the annulus of an already set casing to seal
Case STUDY:
P&A Team Analyzes Multiwell Projects
The customer needed to plug and abandon
43 wells (platform) in a mature offshore
field that had ceased production within the
previous five years. Halliburton reviewed
10 wells, classified the wells by type and
generated P&A cost-estimate scenarios
by well type for the 43 wells. In another
mature field where production had ceased
within the previous 10 years, Halliburton
reviewed 89 wells, provided a classification
by well type as to whether P&A was
required or remediation could occur
and generated costs for each type of well.
Halliburton reviewed 89 wells, provided
a classification by well type and generated
P&A costs estimates by well type.
off permeable zones, and do so all in a single run.
The HydraWash system greatly increases displacement efficiency by placing cement in a
much more controlled manner. This method
eliminates milling and the removal of cuttings,
leaving the casing intact, thus allowing operators
to re-enter the well to verify cement integrity, saving significant rig time in the process. Cementing
with the HydraWash system creates effective
zonal isolation. The HydraWash system complies
with all Norwegian regulations, which are among
the most stringent in the world. Since its introduction in 2010 it has had a 99.3% success rate.
Solutions for Preventing Leaks,
Ensuring Compliance
In mature fields plug cementing (setting
cement plugs) is used for plugging specific
zones, abandonment of a well by sealing off
selected intervals or a depleted well.
When required, plugs are designated for a
specific place in the well and the challenge is
to place a relatively small amount of cement
slurry above a larger volume of wellbore fluid
or above a formation. As a result, a sound
engineering design that addresses the major
factors affecting plug success is necessary.
Factors include the density and rheology of
both the cement and the wellbore fluid or
formation as well as hole size and hole angle,
including vertical, deviated and horizontal
Case STUDY:
Effective Collaboration Results in Rigless P&A on Unmanned North Sea Installations
The operator planned to decommission 16 mature wells on three platforms in the North Sea that
dated back to the 1970s. These wells ceased production several years ago and needed to be securely plugged to help ensure environmental compliance before the topsides and jacket were removed.
Thus, the major operator needed a safe and cost-effective way to plug and abandon the wells that
would not only meet its own technical and safety standards, but also government requirements.
Most offshore wells in the North Sea are abandoned with the use of a rig for pulling the tubing,
removing casing and milling. To meet the objective for a more cost-effective nonrig P&A method,
while continuing to meet the highest technical and safety requirements, the operator collaborated
with Halliburton to develop and execute the plan that included the use of a support barge and
crane instead of a rig. Collaboration was vital to the success of this operation, which included
weeks of planning at the client’s offices and months on-site. The collaboration involved sending
out joint reports and meeting as one group. Halliburton identified the specific services needed for
this project and cross trained the crew to reduce both personnel requirements and costs. The crew
worked together on all the wells, improving efficiency and ensuring lessons learned were captured
and implemented as the project progressed. Wireline, cement and pumping services were used
to P&A 12 of the 16 wells; the remaining four required more complex methodologies, including
casing removal and the use of alternative pills to hold the cement in place. Crews inserted three
cement barriers that comprised 500 to 1000 ft of cement at the bottom of each hole, in addition to
500 ft of cement at an intermediate depth and 300 ft of cement at the mudline. The result was the
first rigless abandonment of offshore platform wells in the North Sea. Halliburton completed the
successful abandonment of all 16 wells over 305 days, 77 days ahead of schedule and 20% under
budget without any lost time or environmental incidents.
well orientations. The goal is to secure a seal
and leave the top of cement in the location
required to address the reason for the plug in
the first place. Creating an artificial bottom
may be required to effectively spot the
plug. It is essential in these operations that
a competent cement plug is placed the first
time. Properly placing the designed cement
plug helps reduce nonproductive rig time,
minimize wasted material, and mitigate the
need for additional cementing services.
Halliburton offers several specifically-
designed plug-cementing solutions as part of
Halliburton’s Tuned Cementing Solutions™.
PlugCem™ conventional and PlugSeal™
foamed cements are designed to form effective
temporary and permanent abandonment
plugs in cased or openhole intervals.
One of Halliburton’s solutions to the potential
cement shrinkage problem is AbandaCem™
cement slurry that uses Portland cement as its foundation, with additives that reduce hydration shrinkage and form a competent
barrier. The specially formulated AbandaCem
cement slurry also applies a post-set expansion
to provide the barrier assurance that is so
critical to a successful abandonment.
AbandaCem cement has been tested, qualified
and approved for use in the North Sea. The
density of this cement can be tailored to local
pressure conditions with the key capability
of being shrink-compensated. AbandaCem
SPE 148640
“Novel Approach to More Effective Plug and
Abandonment Cementing Techniques,” T.E. Ferg,
H.-J. Lund, Dan Mueller, ConocoPhillips; M.
Myhre, A. Larsen, P. Andersen, HydraWell
Intervention; Gunnar Lende, Halliburton; C.
Hudson, MISwaco Norge AS, C. Prestegaard,
and D. Field, Halliburton, presented at the
2011 SPE Arctic and Extreme Environments
Conference & Exhibition, October 18-20,
Moscow, Russia
/ 165
Case STUDY:
WellLock® Resin Successfully Halts
Fluid Flow
Despite multiple conventional P&A attempts,
bubbles were rising to the surface due to small
leak in the annulus between the 30-in. drive
pipe and the 20-in. conductor pipe. Expensive
rig time continued to accrue because the rig
was unable to move off the well until tests
proved the P&A was successful. Halliburton
recommended application of WellLock® resin
in two operations: a 10 bbl squeeze followed
by placement of a 50 ft resin plug in the 13-3/8
in. casing. After placement of the resin, all gas
flow from the well was successfully halted.
The well was permanently abandoned and the
rig moved off to the next well.
Case STUDY:
WellLock Resin Successfully Seals
Leaking Cement
Costs were mounting for an offshore operator trying to abandon a well. Conventional
decommissioning operations failed to
stop a continuous high-pressure bubble
stream. The low yield-point of Halliburton
WellLock® resin enabled infiltration of the
cement leak. The 3D polymer network not
only resisted gas channeling, it effectively
displaced seawater and wellbore fluids,
achieving a competent plug bond. Testing
after the plug set demonstrated a competent
seal compliant with regulations.
/ 166
cement has been successfully used on hundreds
of wells in the North Sea alone and has proven
to be a revolutionary product that is reliable,
environmentally compliant and cost effective.
Many regulatory bodies now require secondary
barriers and WellLock® resin system provides the
required gas impermeable system. Developed
for intervention to serve as a gas-impermeable
secondary barrier, the WellLock resin system
plays a key role in a successful P&A operation.
WellLock® resin, which is chemically inert and
resistant to acid, forms a high-pressure seal and
can withstand fluid systems impurities in the wellbore. It achieves set state with high bond strength,
enabling it to form a competent hydraulic seal
in an environment where fluids have not been
efficiently displaced. As a secondary barrier to the
primary cement sheath, WellLock resin is ideal
for plug and abandonment, squeeze applications
and microannuli repairs. WellLock resin has been
successfully used offshore in the Gulf of Mexico
and on extensively land in North America,
Latin America and Continental Europe. Current
research efforts are focused on development of
resin systems with low environmental impact for
operations in the North Sea.
After a cement plug has been placed, deployment of Halliburton’s Swellpacker® systems
provide effective zonal isolation needed to
meet the demands and requirements placed on
operators to create safe and competently sealed
wellbores. The Swellpacker tool contains rubber elements that have the capability to
swell up to twice the original installation
size when exposed to hydrocarbon, sealing
the annulus around the pipe. Therefore,
zonal isolation is achieved within a particular
region of the well. The simplicity inherent in
swellable technology systems provides low risk,
specifically-designed solutions that can be used
up and down the wellbore to enhance overall
well integrity. Swellpacker Isolation systems
are able to self heal and can react to changes in
the wellbore over time. These systems also can
remain passive in the cement sheath for years
and activate to maintain a hydraulic seal if a
microannulus occurs as a result of cumulative
stresses from pressure and temperature changes.
The Swellpacker system is chemically bonded
to the basepipe, or is available in a slip-on
version, and includes end rings to protect the
element during the run-in-hole process and
to act as extrusion limiters once the packer
is set. Swellpacker systems can be designed
to optimize the P&A of your well using the
following options:
• Swellpacker Oil Swelling (OS) isolation systems are a blend of polymers that react
and swell when contact is made with
any liquid hydrocarbon. Swellpacker OS
systems can be rated up to 15,000 psi (103.4 MPa) and 390ºF (200ºC).
Case STUDY:
HydraWashTM System Saves Operators Millions In Norway Plug and Abandonment
Operations
Before abandoning a well in the Norwegian sector of the North Sea, environmental regulations
require cementing a 50 m (164 ft) section of casing above and a second 50 m section below each
hydrocarbon-bearing zone. Some operators choose to install additional plugs for added safety.
Because cement must go all the way to the formation, operators used to mill out casing and
remove tons of metal shavings (swarf) before spotting the cement. However, cuttings removal
can damage the BOP and other tools. To avoid damage and ensure safe operation on future jobs,
BOPs had to be dismantled, inspected and repaired at considerable expense. Setting one 50-m
isolation plug using traditional methods used to require 10.5 days and four trips for milling,
clean out, under-reaming and cementing. In addition to being expensive and time-consuming,
this operation prevented re-entry into the wellbore either during the operation or in the future.
The HydraWash system allowed operators to achieve results comparable to the conventional
methods in less than three days and in one run. The HydraWash system perforated, washed and
cemented wells in a single trip, eliminating milling and saving 414 rig days on 67 P&A jobs. By
eliminating the need to mill casing, the HydraWash system saved a major operator in the North
Sea $18 million per well on 50 of the 67 wells.
• Swellpacker Water Swelling (WS) isolation
systems are a blend of polymers that react
and swell when contact is made with water.
Swellpacker WS systems can be rated up
to10,000 psi (68.9 MPa) and 320ºF (160ºC).
Halliburton offers a variety of Swellpacker systems that meet the requirements of
customized well construction or abandonment
plans, from the initial planning stage through
completion, production or abandonment of
the well, and are flexible enough to adapt to the
constantly changing downhole environment.
While stuck pipe often is more aligned with
Complimentary Plug and Abandonment
Technologies, operational issues, once the
reservoir has outlived its productive life, during
well abandonment operations some operators
also want to recover as much casing as possible
for recycling, scrapping or for regulatory compliance. Before the stuck pipe can be
retrieved, Halliburton employs its HFPT Free
Point Indicator service to pinpoint the depth at which pipe is stuck, thus avoiding the time-
consuming and expensive process when using
legacy freepoint methods.
Halliburton also offers the DepthPro® wireless
coiled-tubing collar-locator service that
allows operators to accurately determine the
location of various equipment and points in
the wellbore without using electric line inside
of the coil. This technology is ideal for placing
cement in P&A operations.
In many remote locations, the availability of
electrical power for downhole tools is often
limited, expensive, or nonexistent. This is especially relevant in typical well-decommissioning operations.
Halliburton’s response is the electromechanical
DPU®-I Intelligent Series of downhole power
unit that are equally effective at both retrieving
and setting downhole tools. For cost-intensive
P&A applications, the DPU-I unit provides
an alternative to jointed-pipe intervention to
generate high setting force for pulling tubulars
and other tools without the use of explosives.
Once the pipe has been located and power SPE 54344
“Well Abandonment—A “Best Practices”
Approach Can Reduce Environmental
Risk,” C.H. Kelm and R.R. Faul,
Halliburton Energy Services, presented
at 1999 SPE Asia Pacific Oil and Gas
Conference and Exhibition, April 20-22,
Jakarta, Indonesia
/ 167
provided, Halliburton steps in with its all-inclusive suite of jet cutters, including the
Split ShotTM Cutter that uses a linear shaped
charge to split tubing and casing collars
vertically. Jet cutters that are available in
various sizes, lengths and temperature ratings.
As a tool of last resort, Halliburton also
offers the Drill Collar Severing Tool, which
uses an explosive collision device to create a
high-energy blast capable of shearing large,
heavyweight drillstrings.
Halliburton’s pipe cutting portfolio also includes
optional high-precision tools, like chemical cutters
that are available for applications in sizes from
coiled tubing to 8-5/8 -in. casing. The cutters use
chemicals that when mixed with an oil/steelwool
mixture creates a reaction that builds pressure and
temperature, which opens the severing head and
expels the chemical, cutting the tubing or casing
and making the pipe easier to retrieve
Plasma Cutters, such as the X Radial Cutting
Torch (XRT) system, use proprietary fuel to create
a controlled thermal event that generates plasma
with very high temperature and pressure. A
smooth, nonflared cut is the result and is optimal
for recovering stuck pipe.
Fig. 1. DepthPro® wireless coiled tubing collar
locator service allows operators to accurately
determine the location of various equipment
and points in the wellbore without using
electric line inside of the coil.
/ 168
After the pipe is removed, permanent cement
and mechanical plugs are placed in the well. The
plugging process can take two days to a week,
depending on the number of plugs to be set in
Case STUDY:
EZ Drill SV Squeeze Packer P&A
Procedure Helps Operator Eliminate
One Trip, Reduce Costs
A Gulf Coast operator needed to plug and
abandon a well by setting a plug at the
bottom of a liner and a plug at the top of a
liner—this would normally require two trips
with the drillstring. Halliburton personnel
recommended running one EZ Drill SV
tool at the top of the liner, then bullheading
enough cement to reach the bottom of the
liner to do both jobs at once. The operator
accepted the recommendation and reduced
rig time by eliminating a trip with the
drillstring. The estimated economic value to
the customer was $300,000.
the well. Cement plugs can be set using either
the Halliburton Fas Drill® SVB Straddle Packer,
EZ Drill® SVB Straddle Packer squeeze packers,
packers or plugs that are difficult to drill. Cement
plug materials can be PlugCemTM systems,
AbandaCemTM, specialized cement slurries or
WellLock® resin system.
From operational designs that leave nothing to
chance to the holistic deployment of advanced
technologies, to P&A specialists, Halliburton
takes some of the economic pain out of P&A,
while ensuring full compliance with all pertinent
regulations.
All information contained in this book and any accompanying documentation, including
without limitation, all informational text, photographs, graphics, images, or other materials
(collectively, the “Materials”) as well as all derivative works, may be considered proprietary
or confidential and is owned by Halliburton or other third parties who have licensed their
material to Halliburton. The Materials are protected by trade secret, copyright, trademark,
patent or other U.S. and International intellectual property laws. Any use, reproduction,
dissemination, or distribution by any means, including without limitation, electronic or
mechanical transmission, recording, storage or retrieval, in whole or in part, is strictly
prohibited. The Materials are not to be used in any manner or for any purpose that is unlawful
or which could cause damage, injury or impairment to Halliburton. Halliburton disclaims any
proprietary interest in any Materials other than its own.
Halliburton provides the Materials for informational purposes only and makes no representations about the suitability of the information and no warranties or other assurances as to the
accuracy or completeness of any material contained herein. The Materials are provided “AS
IS” and Halliburton disclaims all warranties and conditions with regard to any information
contained in the Materials. In no event shall Halliburton be held liable for any special, indirect
or consequential damages, whether express, implied or statutory, or fitness for a particular
purpose, and Halliburton shall not be held liable for any technical, editorial, or other errors
or omissions contained in the Materials. Changes and updates may be made periodically to
the Materials.
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© 2014 Halliburton. All Rights Reserved.
/ 171

Mature Fields Solutions

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