26842_JOT Winter 2007_e book

Transcription

SaudiAramco Journal Of Technology
A quarterly publication from the Saudi Arabian Oil Company
AN EXPERIMENTAL STUDY OF HOLE
CLEANING UNDER SIMULATED
DOWNHOLE CONDITIONS
see page 2
Saudi Aramco Journal of Technology
CASE HISTORY: APPLICATION OF
COILED TUBING TRACTOR TO
ACID STIMULATE OPEN HOLE
EXTENDED REACH POWER
WATER INJECTOR
WELL
see page 17
WINTER 2007
Elevated temperature and pressure drilling fluids
flow loop, known as Advanced Cuttings Transport
Facility (ACTF) is located at the University of Tulsa, OK
where the experiments were conducted.
On the Cover
An aerial view is shown of a Drilling Rig in
operation. Saudi Aramco currently operates
more than 120 Drilling Rigs. This is the largest
number of Drilling Rigs in operation, not only
in Saudi Aramco’s history, but in any oil
company’s history anywhere.
WINTER 2007
The Saudi Aramco Journal of Technology is published quarterly by the
Saudi Arabian Oil Company, Dhahran, Saudi Arabia, to provide the
company’s scientific and engineering communities a forum for the
exchange of ideas through the presentation of technical information
aimed at advancing knowledge in the hydrocarbon industry.
An Experimental Study of Hole Cleaning Under
Simulated Downhole Conditions
Complete issues of the Journal in PDF format are available on the
Internet at: http://www.saudiaramco.com (click on “publications”).
Case History: Application of Coiled Tubing
Tractor to Acid Stimulate Open Hole Extended
Reach Power Water Injector Well
SUBSCRIPTIONS
Send individual subscription orders, address changes (see page 75) and
related inquiries to:
Saudi Aramco Public Relations Department
JOT Distribution
Box 5000
Dhahran 31311, Saudi Arabia
Fax: +966/3-873-6478
Web site: www.saudiaramco.com
EDITORIAL ADVISORS
Isam A. Al-Bayat, Vice President, Engineering Services
Mohammed S. Al-Gusaier, Vice President, Refining
Abdulla A. Al Naim, Vice President, Exploration
Amin H. Nasser, Vice President, Petroleum Engineering and Development
Zuhair A. Al-Hussain, Executive Director, Drilling and Workover
Saad A. Al-Turaiki, Executive Director, Southern Area Gas Operations
Khaled A. Al-Buraik, Chief Petroleum Engineer
Abdullah M. Al-Ghamdi, Manager, Berri Gas Plant
Khalil A. Al-Shafei, Manager, Materials Planning and Systems
Salahaddin H. Dardeer, Superintendent, Riyadh Refinery Engineering
Abdulmuhsen A. Al-Sunaid, Senior Engineering Consultant,
Environmental Protection
CONTRIBUTIONS
Relevant articles are welcome. Submission guidelines are printed on
the last page. Please address all manuscript and editorial
correspondence to:
EDITOR
William E. Bradshaw
The Saudi Aramco Journal of Technology
Room 2014 East Administration Building
Tel: +966/3-873-5803
E-mail: [email protected]
Unsolicited articles will be returned only when accompanied by a selfaddressed envelope.
Abdallah S. Jum‘ah
President & CEO, Saudi Aramco
2
Dr. Maher M. Shariff, David Nakamura, Dr. Mengjiao Yu
and Dr. Nicholas E. Takach
17
Ayedh M. Al-Shehri, Saad M. Al-Driweesh, Mazen
Al-Omari and Samer Al-Sarakbi
Identifying Sources of Amine Foaming Through
Detailed Troubleshooting Provides More
Feasible Solutions
24
Mater A. Al-Dhafeeri
SmartWell Completion Utilizes Natural
Reservoir Energy to Produce High
Water-Cut and Low Productivity Index Well
in Abqaiq Field
33
Nashi Al-Otaibi, Abdulwafi A. Al-Gamber, Michael
Konopczynski and Suresh Jacob
Shaft Misalignment and Vibration - A Model
41
Dr. Irvin Redmond
New Coating Generations Offer Effective
Solutions for Rehabilitation of Buried Pipelines
52
Dr. Moufaq I. Jafar, Faisal M. Melibari and
Dr. Fikry F. Barouky
Production Optimization Through Utilization
of Innovative Technologies in an Offshore
Field Environment
58
Konstantinos I. Zormpalas, Khalid Al-Omaireen and
Karam Sami Al-Yateem
Crosswell Electromagnetic Tomography in
Haradh Field: Modeling to Measurements
65
Dr. Alberto F. Marsala, Dr. Saleh Al-Ruwaili, Dr.
Shouxiang Mark Ma, Modiu Sanni, Zaki Al-Ali,
Jean-Marc Donadille and Dr. Michael Wilt
Mustafa A. Jalali
Vice President, Saudi Aramco Affairs
Ziyad M. Alshiha
Manager, Public Relations
Production Coordination: Alan Dodd, ASC
Design: Pixel Creative Group, Houston, Texas, U.S.A.
ISSN 1319-2388. © COPYRIGHT 2007 ARAMCO SERVICES COMPANY. ALL RIGHTS RESERVED:
No articles, including art and illustrations, in The Saudi Aramco Journal of Technology, except those from
copyrighted sources, may be reproduced or printed without the written permission of Saudi Aramco. Please
submit requests for permission to reproduce items to the editor.
The Saudi Aramco Journal of Technology gratefully acknowledges the assistance, contribution
and cooperation of numerous operating organizations throughout the company.
SAUDI ARAMCO JOURNAL OF TECHNOLOGY WINTER 2007 1
An Experimental Study of
Hole Cleaning Under
Simulated Downhole
Conditions
Dr. Maher M. Shariff
David Nakamura
Dr. Mengjiao Yu
Dr. Nicholas E. Takach
Dr. Maher M. Shariff received a B.S. in Mechanical
Engineering from Bradley University, IL in 1989, a M.S. in
Mechanical Engineering from Washington University, MO
in 1991, and a Master of Engineering from Vanderbilt
University, TN in 1996. He received a Ph.D. in Mechanical
Engineering with highest honors from Wichita State
University, KS in 2000, in association with the National
Institute for Aviation Research (NIAR). Dr. Shariff’s
dissertation work was in the area of Computational Fluid
Dynamics (CFD). From September 2000 to September
2001, he worked as an Analytical Design Engineer at
Cessna Aircraft Company (a Textron Company) in Wichita,
KS. In September 2001, he joined SABIC Research and
Technology Center in Jubail, Saudi Arabia where he stayed
until February 2003. Then he joined Saudi Aramco’s R&D
Center in February 2003, and is currently working as a
Research Scientist in the R&D Division. His research
interests lie in the areas of drilling and completion fluids as
well as gas/water/oil separation. Dr. Shariff is credited with
more than 10 regional and international publications and
presentations. He is a member of numerous professional
societies; ASME, SPE and ACS. He is currently serving as
the Vice-Chair of the ASME Eastern Saudi Arabia Section.
Dr. Shariff is also a member in a myriad of honor societies,
to name a few, Sigma Xi (Scientific Research), Tau Beta Pi
(Engineering) and Phi Kappa Phi (Academic).
David Nakamura graduated with a B.S. degree in
Petroleum Engineering from the University of Oklahoma,
OK in 1986 and a M.S. degree from the University of
Alaska-Fairbanks, AK in 1996. He worked for
2 SAUDI ARAMCO JOURNAL OF TECHNOLOGY WINTER 2007
Saudi Aramco for 2½ years from 2004-2006 in the Drilling
Technology group. Prior to Saudi Aramco, he worked in
Alaska, Kuwait, Houston, Angola and Azerbaijan. David is
currently working as a Drilling Engineer in Azerbaijan,
offshore in the Caspian Sea. He is a member of the Society
of Petroleum Engineers (SPE).
Dr. Mengjiao Yu is assistant professor of Petroleum
Engineering at the University of Tulsa, OK. He received his
M.S. degree in Electrical and Computer Engineering and his
Ph.D. degree in Petroleum Engineering from the University
of Texas at Austin, TX. Dr. Yu also holds a B.S. degree in
Chemistry and a M.S. degree in Chemical Engineering. Dr.
Yu’s current research interests are in drilling fluids, cuttings
transport, wellbore stability, rheology of fluids, and
petroleum chemistry. He is a member of the Society of
Petroleum Engineers (SPE).
Dr. Nicholas E. Takach is an Associate Professor of
Chemistry at The University of Tulsa, OK. He received his
B.S. degree in Chemistry from California State Polytechnic
University, CA and a Ph.D. in Inorganic Chemistry from
the University of Nevada, NV. Dr. Takach joined TUDRP
in 1996 and became Associate Director in January, 1999.
His research interests include the physico-chemical
properties of drilling and completion fluids, surface and
environmental chemistry applied to the petroleum industry
and thermodynamic modeling of natural gas stability in
ultra-deep reservoirs. Dr. Takach has published in both
chemistry and petroleum-related journals, and has given
presentations in both areas at national and international
conferences. He is a member of the Society of Petroleum
Engineers (SPE) and the American Chemical Society (ACS).
Dr. Takach is also a member of Sigma Xi, the Scientific
Research Honor Society.
ABSTRACT
With increasing measured depths and horizontal
displacements in extended-reach, high-angle wells, hole
cleaning remains one of the major factors affecting cost,
time and quality of directional, horizontal, extended reach
and multilateral oil/gas wells. This study involves
experimental research and theoretical analysis to enhance
cuttings transport capacity in oil and gas well drilling
operations. The effects of drilling fluid rheology, mud
density, temperature, borehole inclination, pipe rotation,
eccentricity, rate of penetration (ROP) and flow rates were
investigated experimentally. Volumetric cuttings
concentration in the test section and frictional pressure
losses were measured during the tests using two nuclear
densitometers and a differential pressure transducer.
A total of 116 experiments were conducted on a full-
scale, Elevated-Pressure Elevated-Temperature Flow Loop
(57.4 ft long, 5.76” x 3.5” annular section) at the
University of Tulsa under controlled experimental
conditions (up to 200 ºF and 2,000 psi). Experimental
results show that drill pipe rotation, temperature and
rheological parameters of the drilling fluids have significant
effects on cuttings transport efficiency. A dimensional
analysis was conducted in this study to develop correlations
that can be used for field applications. A user-friendly
simulator was developed based on the results of the
dimensional analysis and correlations. This simulator can be
used by drilling engineers for design and sensitivity study.
Results from this study can be used to determine critical
conditions for efficient hole cleaning, as well as to optimize
the mud program during the planning and operational
phases of drilling.
INTRODUCTION
As the need for directional and horizontal wells increased,
the interest in cuttings transport problems has shifted from
vertical to inclined and horizontal geometries in the last 20
years. With increasing measured depths and horizontal
displacements in extended reach high angle wells, good hole
cleaning remains one of the major factors affecting cost,
time and quality of directional, horizontal, extended reach
and multilateral oil/gas wells, during both the drilling and
completion phases. It has been recognized for many years
that removal of cuttings from the wellbore during drilling of
highly inclined wells poses special problems. Poor hole
cleaning can result in expensive drilling problems such as a
stuck pipe, lost circulation, slow drilling, high torque and
drag, loose control on density, poor cement jobs, problems
running lower completions, etc. If the situation is not
handled properly, the problem can lead to loss of the well.
Although cuttings transport in horizontal and inclined wells
has been studied for many years, inefficient cleaning of the
wellbore remains one of the most serious problems in
drilling operations.
To address deep gas drilling operations in Saudi Aramco,
continuous hole cleaning problems have been reported
when drilling 83⁄8” and 57⁄8” horizontal holes through
carbonate and sandstone formations. In one well, when
drilling an 83⁄8” hole through the sandstone formation, high
rotational torque was generated due to cuttings bed
buildup. It took approximately five days to drill 519 ft at a
very high cost after the hole was properly cleaned and
torque was reduced.
This study involves experimental research and data analysis
to enhance cuttings transport capacity in oil and gas well
drilling operations. Results from this research will be used to
predict the critical conditions for efficient hole cleaning.
Rheology of Fluid
Much has been written about the role of drilling fluids in
the cuttings transport literature1, 2, 3. These studies and
others debated high viscosity vs. low viscosity and which
rheological parameters are most useful for characterizing
hole cleaning efficiency. Due to the lack of consensus on the
selection of the drilling fluid rheological properties, a
variety of fluids with different rheological parameters and
densities were selected for this study.
Past work1, 2, 3 indicates that the rheological parameters
of the drilling fluid play an important role in controlling
wellbore hydraulics and cuttings transport efficiency.
Therefore, characterization of the fluids in terms of the
rheological parameters is of great importance in this study.
As of now, no single rheology model has been proved to
describe exactly the shear stress-shear rate relationships of
all non-Newtonian fluids over all ranges of shear rate. As a
practical consideration, there are many situations4, 5 where
a different rheology model can be found to approximate the
behavior of an actual fluid (within certain ranges) with
accuracy commensurate with the reproducibility of
measured field data. Among the existing models, some have
gained widespread usage in the oil industry. They are the
Ostwald-de-Walle5 or Power Law Model:
(1)
The Bingham Plastic Model6:
(2)
The Herschel-Buckley or Yield Power Law Model:
(3)
Other models such as the Robertson-Stiff Model have
found applications, specifically in the cementing industry,
and were shown7 to provide a good fit to rheological data.
The Bingham Plastic Model was adopted to characterize
the fluids in this study based on the information provided.
Effect of Density
There are very limited tests conducted in the past to
investigate the effects of drilling fluid density. On the basis
of tests conducted8 it was concluded that, although limited
(in terms of number of experiments conducted), mud weight
has a significant effect on hole cleaning, with or without
pipe rotation. As shown in Fig. 1, we see that at horizontal
conditions, the cuttings weight remaining in the test section
during erosion tests is considerably reduced, as the weight
of the fluid is increased from 7 lb/gal to 13.7 lb/gal.
Cuttings wt (lbs)
remaining in annulus
BACKGROUND
2000
1800
1600
1400
1200
1000
800
600
400
200
0
5
7
9
11
13
15
Mud Weight, lb/gal.
Fig. 1. Cuttings Weight vs. Mud Weights8.
The effects of the mud density were investigated in this
study. Both low density fluids (polymeric fluid and water)
and weighted mud (density increased with barite) were
tested on the full-scale elevated pressure, elevated
temperature flow loop (hereafter referred to as the ACTF
(Advance Cuttings Transport Facility)) to study the effects
of mud density.
Effect of Pipe Rotation
Pipe rotation influences the cuttings bed erosion
significantly9. Results indicate that rotation produces a
velocity profile difference that makes bed erosion easier.
Optimizing the use of rotation can also contribute to an
improvement of drilling efficiency. Sanchez, et al.9, focused
on investigating the effects of drill pipe rotation in hole
cleaning. Their study shows that the effect of drill pipe
rotation is significant and promising enough that it should
not be neglected. Thus to understand the effect of pipe
rotation on the cutting transport efficiency, pipe rotation
was added to the test matrix in this project.
Effect of Temperature
Data collected over the years shows that the drilling fluid
viscosities vary with temperature and pressure. Recent
experiments10 done on cuttings transport by using water as
the test fluid at the University of Tulsa suggest that cuttings
transport is significantly affected by a change in
temperature. Lab experiments also show that the rheology
of drilling fluids changes significantly with temperature.
Due to the change of rheological properties of the drilling
fluids, viscous drag forces applied on drilled cuttings will be
significantly changed. Therefore, effects of temperature on
cuttings transport were considered in this study.
Other Parameters
Borehole inclination angle, rate of penetration (ROP), pipe
eccentricity and flow rates of the drilling fluids were also
considered and tested in this project.
Compressed
Air Tank
Injection
Tower
F1
Metering
Pump
F3
CV5
Air
Compressor
F2
Multiphase Pump
Fracturing Pump
(Mud Pump)
Cooling
Tower
2-inch Pipe
Cooler
3-inch Pipe
Storage
Tank
Heater
Boiler
Mud
Tank
Air Expansion
Tank
V1
DN1
DN2
V3
CV2
Seperation
Tower
CV3
Centrifugal Pump
Annular Section
V3
4-inch Pipe
Fig. 2. Schematic of the ACTF flow loop.
E X P E R I M E N TA L S E C T I O N
Experimental Setup
Fig. 3. ACTF flow loop.
Fig. 4. Centrifugal pump.
This experimental study was conducted at the ACTF flow
loop (Figs. 2 and 3) of the University of Tulsa. The test
facility consists of: 1) pump system, 2) heating and chilling
system, 3) cuttings injection/collection system, 4) piping
system, 5) test section measurement system, 6) storage
tanks, and 7) data acquisition and control systems. A
simplified schematic drawing of the flow loop is shown in
Fig. 2.
The pump system consists of four pumps: a centrifugal, a
triplex (Halliburton), a multiphase (Moyno), and a water
metering pump. The centrifugal pump shown in Fig. 4 takes
water from a 100 bbl holding tank and is used to feed a
water metering pump (200 psi, 100 gpm max). The
discharge pressure from the air compressor has a maximum
Fig. 5. Polymer mixing system.
Fig. 6. Primary tank (Polymer tank).
Fig. 8. Heat exchanger.
Fig. 7. Secondary tank (Water tank).
of 200 psi. Water and air are mixed at the suction side of
the multiphase pump, which then compresses the mixture.
The multiphase pump can provide a maximum differential
pressure of 500 psi. Flow rate is controlled by a control
valve and the multiphase pump rotational speed. Polymeric
solutions were pre-mixed, using the mixing system shown in
Fig. 5 in the 100 bbl primary tank (Fig. 6) and water was
stored in the secondary tank, Fig. 7. After polymer solution
flows through the pipes and annulus, it reaches the section
between the outlet of the 4” pipe and injection tower.
The piping system of the ACTF flow loop consists of: 1)
a 2” pipe, 52.9 ft in length, 2) a 3” pipe, 52.9 ft in length,
3) a 4” pipe, 66.6 ft in length, and 4) an annular section
(5.76” x 3.5”), 57.4 ft in length. On each of the 2” and 3”
pipes, and in the annular section, view ports are installed to
offer online visual observation of flow behavior. Most of
the flow lines are covered with heat insulation material,
which maintains the loop at the desired temperature.
The heating system includes: 1) an indirect-fired natural
Fig. 9. Cuttings injection tank.
gas boiler, 2) an oil circulation tank, 3) two heat
exchangers, Fig. 8, and 4) an automatic control/alarm
system. The test fluid can be heated up to 200 °F.
The cuttings injection and collection systems (Figs. 9 and
10) consist of: 1) an injection tower, 2) a separation (and
collection) tower, 3) a transfer auger to load cuttings into
the injection tower, 4) an injection auger to feed cuttings
into the flow loop, and 5) a weight measurement system.
The injection tower is 22 ft high, and is used to hold
cuttings. The collection (or separation) tower, is 36 ft in
height, and separates fluids from solids. The cuttings are
loaded into the top of the injection tower with a transfer
auger. A motor-driven injection auger is installed at the
bottom of the injection tower in a vertical position. By
turning this auger, cuttings are fed into the 4” pipe, which is
below the injection tower; then the cuttings are carried by
Fig. 12. Data acquisition system.
Fig. 10. Cuttings collection tank.
When steady-state flow is established in the annular section,
the pressure differential in the annulus increases from a
lower value to a higher value and stabilizes, and the pressure
differential in the 4” pipes continues to increase. At that
point, quick-close valves are closed nearly simultaneously. At
the same time, a bypass valve is opened to allow the mixture
to flow directly to the collection tower. This enables a
certain amount of water/cuttings to be trapped in the
annular test section. Two nuclear densitometers measure the
mixture density, which, in turn, can be used to back
calculate the volumetric concentrations of each phase. A
flushing system is installed in the annular section. The
purpose of the flushing line is to measure the weight of
cuttings trapped in the annular section.
Two tanks are included in the ACTF flow loop: one to
hold the polymeric test solution, Fig. 6, and the second to
hold water, Fig. 7, for the tests and for clean up. The
capacity of each tank is 100 bbl. Both tanks are covered
with heat insulation material to minimize heat losses.
A Labview® data acquisition system is installed to
monitor and control tests as shown in Fig. 12.
Preparation of Testing Fluids
Fig. 11. Test section.
water. The weight measurement system consists of load
cells, transducers, and an indicator. At the bottom of the
injection and collection towers, there are three load cells,
installed at 120° apart, to measure the weight of each
tower. The real time readings of the weight can be shown
on the indicators and a computer screen in the control
room. This enables the cuttings injection and collection
rates to be known and controlled.
The annular test section, Fig. 11, has five components: 1)
two-quick closing valves, 2) one bypass valve, 3) two nuclear
densitometers, 4) flushing lines, and 5) an expansion tank.
Two polymers, polyanionic cellulose (PAC) and dispersible
xanthan gum (XCD) were used in this project to control the
rheological parameters, yield point (YP) and plastic viscosity
(PV), of the testing fluids. To prepare the testing fluids, the
polymer mixing tank was first filled with water and heated
to the testing temperature. PAC was dissolved in the water
using a mixer. The amount of PAC was predetermined in the
lab on a small scale. After the PAC was mixed, XCD was
added to adjust the yield point and plastic viscosity. After
adding the polymers, the fluid was agitated for at least 40
minutes for hydration. After the mixing, a sample was taken
from the mixing tank for characterization. Based on the
Testing Parameter
Values
Annular Size
5.76” Casing ID x 3.5” Drill String OD
Rotation (rpm)
0
Eccentricity
Mud Rheology
Fluid Label
Yield Point
20, 40 lb/100 ft2
Plastic Viscosity
10, 20 cP
Density,
(lb/gal)
Plastic
Viscosity, (cP)
Yield Point
(lb/100 ft2)
Fluid A
10
20
8.33
Fluid B
20
40
8.33
Fluid C
20
40
12
80
0.541,” 0.881” offset
Rheological
Parameters
Temperature (ºF)
80, 120, 180
Fluid D
10
20
12
ROP (ft/hr)
15, 20, 30, 40
Water
1
0
8.33
Flow Rate (GPM)
75~250
Table 2. Different fluids used
Density (ppg)
8.3
12
Inclination
(degrees)
90
67
Table 1. Test matrix
measured yield point and plastic viscosity, additional
polymer or water was added to adjust the rheological
parameters to the predetermined values.
High density fluids were prepared in the mixing tank of
an adjoining loop called the Low-Pressure Ambient Pressure
flow loop. Again, polymers were first added to the heated
water and then agitated for at least 40 minutes for
hydration. An Excel® program was developed to calculate
the amount of barite needed for increasing the density of
the testing fluid. Barite was added to the pre-mixed
polymeric fluid to increase the density of the testing fluid to
12 ppg. The weighted fluid was agitated for at least 40
minutes before a sample was taken. A mud balance was
used to make sure the density of the fluid was 12 ppg. Also,
Variable
rheological parameters were measured to make sure the
desired yield point and plastic viscosity were reached.
Below is the generic procedures used to prepare 70 bbls
of testing fluid.
1. Prefill 60.36 bbl heated water to low pressure mixer.
2. Add 44.12 pound mass (lbm) PAC (30/40 rheology)
or 9.8 lbm PAC (10/20 rheology).
3. Add 68.65 lbm XCD (30/40 rheology) or 39.2 lbm
XCD (10/20 rheology).
4. Mix well for 40 minutes.
5. Check the rheology (verify the number before adding
barite).
6. Add 14,173.5 lbm barite (141.7 bags).
7. Mix well for at least 40 minutes.
8. Check the rheology and density.
Characterization of Testing Fluids
A Chandler 35 rotational viscometer (see Fig. 16 in
Symbol
Units
1. Cuttings Volumetric Concentration
Cc
2. Wellbore Diameter
Dimensions
M
L
T
Dimensionless
0
0
0
D
Length
0
1
0
d
Length
0
1
0
Vsl
Length/Time
0
1
-1
5. Hole Angle (Inclination)
θ
Dimensionless
0
0
0
6. Drill Pipe Rotation Speed
Ω
1/Time
0
0
-1
7. Plastic Viscosity
PV
Mass/(Length*Time)
1
-1
-1
8. Yield Point
YP
Mass/(Length)2
1
-1
-2
9. Fluid Density
ρ
Mass/(Length)3
1
-3
0
10. Acceleration due to Gravity
g
Length/(Time)2
0
1
-2
ROP
Length/Time
0
1
-1
e
Length
0
1
0
Tact/Tst
Dimensionless
0
0
0
3. Drill Pipe Diameter
4. Superficial Liquid Velocity, 4Q/Pi
(D2-d2)
11. Injection Rate
12. Eccentricity
13. Tactual/Tstandard (Dimensionless Temperature)
Table 3. Dimensional analysis
Appendix A) was used to measure the rheological
parameters of the testing fluids under ambient temperature
and pressure. A Fann 75 (see Fig. 17 in Appendix A) was
also used in this study to measure the rheological
parameters at high-pressure, high temperature conditions.
Although the Bingham Plastic rheological model was
adopted for this study, the prepared testing fluid was tested
under 1, 2, 3, 6, 10, 20, 30, 60, 100, 200, 300 and 600
rpm and the dial readings were recorded. Yield point and
plastic viscosity were calculated to make sure that desired
rheological parameters were reached.
Test Procedure
The experiments contain the following major steps. The
detailed test procedure can be found in Appendix B.
• Prepare testing fluids.
• Mix polymer.
• Add Barite to increase mud density (when
necessary).
• Circulate fluid through the flow loop and control the
test temperature.
• Inject cuttings at the desired injection rate.
• Wait for the steady-state by monitoring the differential
pressure transducers (DP) and densitometers on the
test section.
• Flush the cuttings and clean up.
Test Matrix
After conducting some pilot tests, the following test matrix
(Table 1) was determined for use in this study for a better
understanding of the hole cleaning process.
R E S U LT S A N D D I S C U S S I O N
Fluid Characterization
As mentioned, fluid characterization was performed to
determine the effects that different rheological parameters
have on cutting transport. As a result of the fluid characterization tests performed using Chandler 35 and Fann 75
viscometers; the following table describes the five different
fluids used in the experiments. Physical properties of the
fluids used are shown in Table 2.
Summary of the Tests Completed on the ACTF Flow Loop
A total of 116 tests were conducted in this study. Table 7 in
Appendix C, shows in detail all the tests conducted in this
project.
Dimensional Analysis
A dimensional analysis was conducted to develop
correlations that can be used to predict the cuttings
volumetric concentration in the annulus based on the
experimental data.
In order to account for the effects of the independent
variables (liquid flow rate, cuttings size, hole angle, fluid
properties, temperature, eccentricity and drill pipe
rotational speed), the following 13 variables, Table 3, are
used in dimensional analysis for cuttings volumetric
concentration. The unit of each variable in terms of the
three basic dimensions (M, L and T) is listed in Table 3.
Dimensional analysis is performed as follows:
Dimensions Involved: [MLT] = 3
No. of Dimensional groups: 13-3 = 10
Terms Used:
1.
2.
3.
4.
(Ratio of equivalent diameter to hydraulic
diameter)
(Equivalent diameter of
annulus)
(Ratio of inner to outer diameter of the
annulus)
(Hydraulic diameter)
Correlations for Cuttings Volumetric Concentration
All experimental results were considered in the dimensional
analysis. The above dimensionless groups indicate all the
parameters that are likely to affect the correlation for
cuttings concentration. This is established by examination
of the experimental results. Correlations for “Polymer” and
“Weighted PAC” (both these terms are used to describe the
fluid types used in the tests) may have to be developed
separately because one model may not be able to
accommodate both fluids.
The effects of flow rate are reflected both in Re and Fr.
Since the yield point, the plastic viscosity and the density of
the fluids were varied for the experiments under study; both
of these dimensionless groups were used in the correlation.
Since the influence of different wellbore/pipe diameter
ratios is not studied here, the dimensionless group π6 was
not included in the correlation.
Since pipe rotation has shown to have a significant effect
on the cuttings concentration, Ta (Taylor number) was
included in the regression analysis. A generalized Taylor
number, Ta, was used for Bingham Plastic fluids as
described in the above Table.
The effect of temperature on the cuttings concentration
was also considered in the dimensional analysis. We first
considered incorporating the effect of temperature by
developing several separate regression models for the effect
of temperature on the rheological parameters of the fluids
transport was incorporated by using the Hedstrom number,
He, in the regression analysis.
The effect of variation of injection rate was incorporated
by Drp, the dimensionless rate of penetration. The
dimensionless rate of penetration is typically represented by
the equation:
0.50
0.45
0.40
Prediction
0.35
0.30
0.25
0.20
(4)
0.15
0.10
0.05
0.00
0.00
0.10
0.20
0.30
0.40
0.50
Observed
Due to the lack of sufficient information, the current
form as shown in the Table 4 was adopted.
The effect of variation in eccentricity is represented by
Decc, dimensionless eccentricity, represented by the equation
shown in Table 4.
Fig. 13. Observed vs. predicted cuttings concentration for polymer solution.
No.
Dimensionless Group
Remarks
35%
30%
π1
Taylor number, Ta
Predicted
25%
π2
20%
Cc
Cuttings Concentration
15%
10%
π3
Hedstrom number, He
π4
Generalized Reynolds
number, Regen
5%
0%
0%
5%
10%
15%
20%
25%
30%
35%
Observed
Fig. 14. Observed vs. predicted cuttings concentration for water.
π5
T(actual)/T(standard)
Temperature Ratio, Tr
π6
d/D
Rd
π7
Froude number, Fr
π8
Dimensionless
Inclination Angle, α
π9
Drp (Dimensionless ROP)
π10
Decc (Dimensionless
Eccentricity)
Table 4. Dimensionless groups
Fig. 15. Cuttings transport simulator.
alone. But this may complicate the analysis of cuttings
transport. Therefore, a temperature ratio, Tr, was used in
the regression analysis.
The effect of the rheological parameters on cuttings
k
b1
b2
b3
b4
39541
-0.914
-0.275
-0.090
-1.093
b5
b6
b7
b8
-1.335
-0.803
0.287
-0.534
Table 5. Parameters for the above model
k
b1
b2
b3
b4
b5
0.062
-1.31
0.157
0.165
0.045
-0.0043
Table 6. Parameters for the above model
Appendix A. Rotational Viscometers used in
this Study
Appendix B. Experimental Procedure Diagram
Preparation Stage
Estimated Time (4 hours)
Check fuel level
Heat water
Mix polymer
Heat polymer
Check the loop and fluid path
Cutting Transport Test
Circulate the fluid
Set the test pressure
Test rheology at steady-state
Set cuttings injection rate
Set pipe rotation speed
Steady-state
Vary flow rate (until pipe is clean)
Stop pipe rotation and cuttings injection
Decrease the pressure slowly
Stop mud pump
Fig. 16. Chandler 35 Viscometer.
Cleaning up the loop and maintenance
Estimated Time (2 hours)
Flush out and drain cuttings from loop and tanks
Rinse loop with water
Fill tanks #1 and #2 with fresh water
Fill fuel tanks of mud pump and compressor
Clean the floor
Check the loop piping and valves
Fig. 17. Fann 75 Viscometer.
The relationship between these dimensionless groups for
cuttings volumetric concentration is expressed as
(5)
A N A LY S I S
An attempt was made to combine all 116 tests together to
obtain one equation. The following equation was adopted to
correlate the experimental data. Using Statistica®, the model
parameters were obtained and are shown Tables 5 and 6.
Overall Correlation for 116 Tests
(6)
Figure 13 shows the comparison between model predictions
with the experimental data using polymer solutions.
Water Test
In the case of water, the He (Hedstrom number), Alpha
Download and backup the data
(Dimensionless Inclination), and the Decc (Dimensionless
Eccentricity) were removed from the analysis since they are
all constant.
The Taylor number (Ta) was modified for water and has
the following form:
(7)
The generalized Reynolds number was also modified for
water and has the following form:
(8)
Using Statistica we obtain:
(9)
Figure 14 shows comparison of experimental data and
Appendix C
Pipe
Flow Rate
Rotation
Inclination
gpm
RPM
0
100
90
TEST
No.
Density
lb/gal
PV, μp
YP,
lb/100 ft2
Temperature
ROP fph
Eccentricity
Cc
1
8.314
10
20
80
30
2
8.314
10
20
80
30
0
200
90
0.881
35%
0.881
14%
3
8.314
10
20
80
30
80
100
90
0.881
6%
4
8.314
10
20
80
30
80
200
90
0.881
2%
5
8.314
10
20
180
30
0
100
90
0.881
11%
6
8.314
10
20
180
30
0
200
90
0.881
4%
7
8.314
10
20
180
30
80
100
90
0.881
15%
8
8.314
10
20
180
30
80
200
90
0.881
0%
9
8.314
20
40
180
30
0
100
90
0.881
20%
10
8.314
20
40
180
30
80
100
90
0.881
15%
11
8.314
20
40
180
30
0
200
90
0.881
0%
12
8.314
20
40
180
30
80
200
90
0.881
0%
13
8.314
20
40
80
30
0
100
90
0.881
30%
14
8.314
20
40
80
30
80
100
90
0.881
9%
15
8.314
20
40
80
30
0
200
90
0.881
0%
16
8.314
20
40
80
30
80
200
90
0.881
0%
17
12
20
40
80
30
0
100
90
0.881
19%
18
12
20
40
80
30
80
100
90
0.881
1%
19
12
20
40
80
30
0
150
90
0.881
5%
20
12
20
40
80
30
80
150
90
0.881
0%
21
12
20
40
180
30
0
100
90
0.881
1%
22
12
20
40
180
30
80
100
90
0.881
0%
23
12
10
20
80
30
0
100
90
0.881
17%
24
12
10
20
80
30
80
100
90
0.881
1%
25
12
10
20
80
30
0
150
90
0.881
8%
26
12
10
20
80
30
80
150
90
0.881
0%
27
12
10
20
180
30
0
100
90
0.881
15%
28
12
10
20
180
30
80
100
90
0.881
1%
29
12
10
20
180
30
0
150
90
0.881
3%
30
12
10
20
180
30
80
150
90
0.881
0%
31
12
20
40
180
30
0
150
90
0.881
1%
32
12
20
40
180
30
80
150
90
0.881
0%
33
8.314
10
20
180
30
0
100
67
0.881
32%
34
8.314
10
20
180
30
0
200
67
0.881
4%
35
8.314
10
20
180
30
80
100
67
0.881
23%
36
8.314
10
20
180
30
80
200
67
0.881
1%
37
8.314
10
20
80
30
0
100
67
0.881
17%
38
8.314
10
20
80
30
80
100
67
0.881
27%
39
8.314
10
20
80
30
0
200
67
0.881
12%
40
8.314
10
20
80
30
80
200
67
0.881
12%
41
8.314
20
40
180
30
0
100
67
0.881
34%
42
8.314
20
40
180
30
80
100
67
0.881
22%
43
8.314
20
40
80
30
0
100
67
0.881
41%
Pipe
Flow Rate
Rotation
Inclination
gpm
RPM
TEST
No.
Density
lb/gal
PV, μp
YP,
lb/100 ft2
Temperature
ROP fph
Eccentricity
Cc
44
8.314
20
40
80
30
80
100
67
0.881
19%
45
8.314
20
40
80
30
0
200
67
0.881
12%
46
8.314
20
40
80
30
47
8.314
20
40
180
30
80
200
67
0.881
1%
0
200
67
0.881
10%
48
8.314
20
40
180
49
12
20
40
80
30
80
200
67
0.881
5%
30
0
100
67
0.881
21%
50
12
20
40
51
12
20
40
80
30
80
100
67
0.881
4%
80
30
0
150
67
0.881
11%
52
12
10
20
80
30
0
100
67
0.881
17%
53
12
54
12
10
20
80
30
0
150
67
0.881
4%
10
20
80
30
80
150
67
0.881
0%
55
56
12
10
20
80
30
80
100
67
0.881
0%
12
10
20
180
30
0
100
67
0.881
22%
57
12
10
20
180
30
0
150
67
0.881
13%
58
12
10
20
180
30
80
100
67
0.881
2%
59
12
10
20
180
30
80
150
67
0.881
0%
60
12
20
40
180
30
0
100
67
0.881
14%
61
12
20
40
180
30
80
100
67
0.881
0%
62
12
20
40
180
30
0
150
67
0.881
4%
63
12
20
40
180
30
80
150
67
0.881
0%
64
8.314
10
20
180
40
0
100
90
0.541
25%
65
8.314
10
20
180
40
0
150
90
0.541
18%
66
8.314
10
20
180
40
0
200
90
0.541
5%
67
8.314
10
20
180
40
0
250
90
0.541
0%
68
8.314
10
20
120
40
0
100
90
0.541
28%
69
8.314
10
20
120
40
0
150
90
0.541
22%
70
8.314
10
20
120
40
0
200
90
0.541
14%
71
8.314
10
20
120
40
0
250
90
0.541
5%
72
8.314
10
20
120
40
80
75
90
0.541
6%
73
8.314
10
20
120
40
80
100
90
0.541
5%
74
8.314
10
20
120
40
80
150
90
0.541
3%
75
8.314
10
20
120
20
80
75
90
0.541
11%
76
8.314
10
20
120
20
80
100
90
0.541
7%
77
8.314
10
20
120
20
80
150
90
0.541
0%
78
8.314
10
20
120
20
0
100
90
0.541
20%
79
8.314
10
20
120
20
0
150
90
0.541
16%
80
8.314
10
20
120
20
0
200
90
0.541
2%
81
8.314
10
20
120
20
0
250
90
0.541
0%
82
12
20
40
180
30
80
150
67
0.881
3%
83
8.33
10
20
180
20
0
100
90
0.541
25%
84
8.33
10
20
180
20
0
150
90
0.541
18%
85
8.33
10
20
180
20
0
200
90
0.541
5%
86
8.33
10
20
180
20
0
250
90
0.541
0%
87
8.33
10
20
80
30
0
150
90
0.881
10%
88
8.33
10
20
80
30
0
200
90
0.881
7%
Pipe
Flow Rate
Rotation
Inclination
gpm
RPM
TEST
No.
Density
lb/gal
PV, μp
YP,
lb/100 ft2
Temperature
ROP fph
Eccentricity
Cc
89
8.33
10
20
80
30
0
100
67
0.881
41%
90
8.33
10
20
80
30
80
100
67
0.881
21%
91
8.33
20
40
80
30
92
8.33
10
20
120
40
0
100
90
0.881
30%
0
100
90
0.881
39%
93
8.33
10
20
120
94
8.33
10
20
120
40
0
150
90
0.881
20%
40
0
200
90
0.881
18%
95
8.33
10
20
180
40
0
100
90
0.881
28%
96
8.33
10
97
8.33
10
20
180
40
0
150
90
0.881
17%
20
180
40
0
200
90
0.881
3%
98
8.33
99
8.33
10
20
180
40
80
100
90
0.881
7%
10
20
180
40
80
150
90
0.881
6%
100
101
8.33
10
20
180
40
80
200
90
0.881
0%
8.314
1
0
180
40
0
100
90
0.541
33%
102
8.314
1
0
180
40
0
150
90
0.541
24%
103
8.314
1
0
180
40
0
200
90
0.541
7%
104
8.314
1
0
180
40
80
100
90
0.541
6%
105
8.314
1
0
180
40
80
150
90
0.541
4%
106
8.314
1
0
180
40
80
200
90
0.541
0%
107
8.314
1
0
120
15
0
100
90
0.541
30%
108
8.314
1
0
120
15
0
150
90
0.541
19%
109
8.314
1
0
120
40
0
100
90
0.541
23%
110
8.314
1
0
120
40
0
150
90
0.541
15%
111
8.314
1
0
120
40
0
200
90
0.541
13%
112
8.314
1
0
120
40
80
100
90
0.541
5%
113
8.314
1
0
120
40
80
150
90
0.541
2%
114
8.314
1
0
120
40
80
200
90
0.541
0%
115
8.314
1
0
180
15
0
100
90
0.541
23%
116
8.314
1
0
180
15
0
200
90
0.541
12%
Table 7. Experimental results
the model predictions for water tests. Good agreement was
achieved.
Development of the Cuttings Transport Simulator
A user-friendly cuttings transport simulator was developed
in this project to help use the correlations obtained from
this study. The simulator was implemented in Visual C++
under a Windows® platform. A sensitivity study can be
conducted using this cuttings transport simulator. Results
can be used for optimization of the drilling operations at
the design stage or on the rig. A screenshot of the simulator
is shown in Fig. 15.
S U M M A RY A N D C O N C L U D I N G R E M A R K S
1. An experimental study on cuttings transport under
simulated downhole conditions was conducted at the
University of Tulsa using the ACTF flow loop.
2. A total of 116 experiments were conducted under well
controlled testing conditions.
3. The effects of drilling fluid rheological parameters, ROP,
temperature, borehole inclination angle, flow rates, pipe
rotation, eccentricity and drilling fluid density on
cuttings transport were studied experimentally.
4. Experimental results show that drill pipe rotation,
temperature and rheological parameters of the drilling
fluids have significant effects on cuttings transport
efficiency.
5. A dimensional analysis was conducted to develop
correlations that can be used for field applications.
6. A user-friendly simulator was developed to help use the
correlations developed in this study. This simulator can be
used by drilling engineers for design and sensitivity study.
7. Critical conditions for efficient hole cleaning can be
determined using the results obtained from this study.
8. The correlations and experimental data provided in this
study are useful for field applications and operation
optimization.
ACKNOWLEDGEMENTS
The authors wish to thank Saudi Aramco for financial and
technical support and the University of Tulsa for providing
the testing facility. The authors also wish to thank the U.S.
Department of Energy and members of Tulsa University
Drilling Research Projects for their financial and technical
support of the construction of the University of Tulsa’s
Advanced Cuttings Transport Facility, which made this
study possible.
REFERENCES
1. Clark, R.K., Bickham, K.L.: “A Mechanistic Model for
Cuttings Transportation,” SPE paper 28306, 69th annual
SPE Technical Conference and Exhibition, New Orleans,
Louisiana, 1994.
2. Rasi, M.: “Hole Cleaning in Large, High-Angle
Wellbores,” IADC/SPE paper 27464 presented at the
IADC/SPE Drilling Conference in Dallas, Texas,
February 15-18, 1994.
3. Luo, Y., Bern, P.A. and Chambers, B.D.: “Flow Rate
Predictions for Cleaning Deviated Wells,” IADC/SPE
paper 23884 presented at the IADC/SPE Drilling
Conference in New Orleans, Louisiana, February 18-21,
1992.
4. Okafor, M.N. and Evers, J.F.: “Experimental
Comparison of Rheology Models for Drilling Fluids,”
SPE paper 24086.
5. Bird, R.B., Stewart, W.E. and Lightfoot, E.N.: “High
Temperature High-Pressure Rheology of Water-Based
Mud,” Transport Phenomena, John Wiley and Sons,
Inc., New York, 1960, p. 11.
6. Bingham, E.C.: “Fluidity and Plasticity,” McGraw-Hill
Book Co., Inc., New York, 1922.
7. Beirute, R.M. and Flumerfelt, R.W.: “Mechanics of the
Displacement Process of Drilling Muds by Cement
Slurries using an Accurate Rheological Model,” SPE
paper 5801, 1977.
8. Eddy, K.: “An Experimental Study of the Effect of Mud
Weight and Drill Pipe Rotation on Cuttings Transport in
Horizontal and Inclined Wells,” University of Tulsa,
Oklahoma, 1996.
on Hole Cleaning during Directional Well Drilling,” SPE
paper, presented at Amsterdam, March 4-6, 1997.
10. Zhu, C., Ph.D. Dissertation: “Cuttings Transport with
Foam in Horizontal Concentric Annulus under
Elevated Pressure and Temperature Conditions,”
University of Tulsa, Oklahoma, 2005.
E X P E R I M E N TA L P R O C E D U R E
The following procedures are to perform experiments on
hole cleaning under simulated downhole conditions using
the ACTF, elevated-temperature, elevated-pressure flow
loop, part of the Tulsa University Drilling Research Project’s
(TUDRP) facilities.
1. Before going to the flow loop
a.
b.
c.
d.
Establish the test matrix data points to be obtained.
Check the current status of the flow loop.
Review test procedures.
Review safety procedures.
2. Check the fuel level in the mud pump to make
sure fuel level is full.
3. Cuttings preparation
a. Sieve the cuttings as required for the upcoming the
experiments.
b. Open the top of the injection tower.
c. Fill the injection tower to 75% of its capacity.
d. Close the top of the injection tower.
4. Fluid preparation
a. Fill tank #1 with water.
b. Heat water to the test temperature while circulating
through the flow loop.
c. Transfer water to the mixing tank.
d. Add and mix polymer as detailed in mud program.
e. During and after the mixing process, take samples and
measure the rheology in the lab using Fann 75 at the test
temperature and pressure, and Chandler 35 at ambient
conditions.
f. Transfer mixed polymer back to tank #1.
g. Heat mixed polymer to the test temperature while
circulating through the flow loop.
5. Rheology test
a. Line up valves to flow through rheology section.
b. Wait for steady state conditions.
c. Record at least two minutes of data at steady-state
conditions.
9. Sanchez, R.A., et al.: “The Effect of Drill Pipe Rotation
d. Increase the flow rate at agreed intervals (LAMINAR
FLOW must be maintained).
e. Return valves to their original position.
f. Take a sample of the liquid from the tank and measure
the rheology using Fann 75 and Chandler 35.
6. Cuttings transport test
a. Increase the flow rate to initial test conditions.
b. Use the Swaco system or Ceramic angle chokes to
control the back pressure to test condition.
c. Wait for steady-state flow rate and pressure conditions.
d. Start the hydraulic pump and auger rotation.
e. Open the cuttings injection valve located at the injection
tower.
f. Pressurize the injection tower.
g. Control the cuttings injection rate at the test rate of
penetration.
h. Wait for steady-state in the annular section.
i. Start pipe rotation at test speed.
j. Wait for steady-state conditions in annular section.
k. Record at least 2 minutes of data at steady-state
conditions.
l. Increase the flow rate by agreed increment.
m. Wait for steady-state conditions in the annular section.
n. Repeat steps k, l and m until annular section is clean.
o. Close the cuttings injection valve and stop the auger
rotation.
p. Take a sample of liquid from the tank and measure the
rheology using Fann 75 and Chandler 35.
q. Turn off the hydraulic pump.
r. Decrease the back pressure slowly.
7. Clean up
a. Flush out all cuttings from the flow loop piping using
water.
b. Rinse and drain tank #1 with water.
c. Rinse the flow loop with hot water.
d. Rinse the flow loop with fresh water.
e. Stop all pumps and return valves to their original
position.
f. Turn off heater.
g. Fill tanks #1 and #2 with fresh water.
h. Fill fuel tanks of mud pump and compressor.
i. Clean the concrete pad of the flow loop.
j. Check the loop piping and valves.
8. Download and backup the data from the
acquisition system.
Case History: Application of
Coiled Tubing Tractor to Acid
Stimulate Open Hole
Extended Reach Power Water
Injector Well
Ayedh M. Al-Shehri
Saad M. Al-Driweesh
Mazen Al-Omari
Samer Al-Sarakbi
Ayedh M. Al-Shehri is a Senior Production Engineer with
the ‘Udhailiyah Production Engineering Division of the
Southern Area Production Engineering Department. He
received a B.S. in Petroleum Engineering from King Fahd
University of Petroleum and Minerals (KFUPM), Saudi
Arabia in 1999. Ayedh has 8 years of oil production
experience in different south Ghawar fields. He is also a
member of the Society of Petroleum Engineers (SPE).
Saad M. Al-Driweesh is a Production Engineering
general supervisor in Saudi Aramco, where he is involved in
gas and oil production engineering, well completion and
stimulation activities. He is mainly interested in the field of
production engineering, production optimization and new
well completion applications. He received a B.S. degree in
Petroleum Engineering from King Fahd University of
Petroleum and Minerals (KFUPM), Saudi Arabia in 1988.
Saad has been working with Saudi Aramco for the past 19
years in areas related to gas and oil production engineering.
Mazen Al-Omari is currently the Operations Manager
for Welltec Middle East. A graduate of Master in Civil
Engineering, he has 16 years experience in the oil field
services industry, mostly in cementing, stimulation, well
intervention and sand control. Mazen has worked in many
countries, including Syria, Turkey, Iran, U.A.E., India,
Pakistan, Indonesia and the USA.
Samer Al-Sarakbi is a General Field Engineer in Schlumberger.
He is involved in coiled tubing and stimulation operations.
Samer’s main interest is in extended reach coiled tubing
applications, downhole tools, carbonate stimulation and water
shut off. He received a B.S. degree in Mechanical
Engineering from Damascus University, Syria, in 2003.
ABSTRACT
With the increasing complexity of well completion, the
rigless intervention work is becoming more challenging.
Conventional techniques are no more adequate to access
long horizontal wells to perform intervention work, such as
acid stimulation, logging, and zonal isolation.
This article will describe the process of using a downhole
coiled tubing (CT) downhole tractor to access a horizontal
open hole (OH) extended reach power water injector (PWI)
well in the Ghawar field, the world’s largest oil field, to
perform a huge matrix acid stimulation job. The volume of
the treatment is considered one of the largest for a PWI and
the first utilization of a CT tractor in the Ghawar field. It
will also review the process of candidate selection, job
design and planning, execution, and results and post job
evaluation. The job set an excellent example of
advancement in intervention technique accessing long
horizontal wells beyond the normal reach of coiled tubing.
In this job, the CT tractor has increased the reach of CT by
54% and a world record of coiled tubing tractored interval
in horizontal OH of more than 5,000 ft was achieved. The
injection rate of the stimulated wells was increased by more
than twofold.
INTRODUCTION
The giant Ghawar field, located in the Eastern Region of
Saudi Arabia, is a carbonate reservoir, more than 200 km
long and 40 km wide with a continuous oil column, Fig. 1.
The production from the field was started in 1951 from the
northern part and thereafter the field was developed toward
the southern tip with the last increment put on stream in
20061.
Fig. 2. Well lateral trajectory.
Reservoir characterizations change along the north-south
lateral with the southern part known for lower reservoir
quality dominated by low permeability fractured formation.
To maximize recovery of oil from this unique reservoir,
peripheral water injection was started in 19662.
As the development reached the southern part of the
Ghawar, the reservoir quality dictated the necessity to
utilize the latest advancement in drilling technology
including long horizontal, maximum reservoir contact
(MRC), real-time geosteering, and I-Field initiatives. These
complex completion wells present a challenge to production
engineers to riglessly access them in order to perform
intervention work to enhance performance or remedy
downhole problems.
Due to tightness of reservoir formation combined with
formation damage, matrix acid stimulation jobs were
deemed necessary to improve injectivity supporting the
reservoir pressure in this part of the field. In extended reach
horizontal wells, bullheading of treatment fluid is not
efficient due to the nature of this fractured reservoir and a
coiled tubing unit (CTU) should be used to provide uniform
distribution of the acid across the horizontal treatment
interval. Field experience indicated that accessibility of a
CTU in horizontal wells is limited due to increased friction
generated when the pipe starts to get helically buckled and
finally reaches a lockup point where the total down acting
forces are no more sufficient to move the CT pipe further in
the well. This limits the capability to distribute the
treatment across the horizontal section.
Different techniques have been used to overcome this
limitation of CT to perform intervention work such as using
large outside diameter (OD) coiled tubing, downhole
vibration tools, and friction reducer chemicals3, 5.
W E L L C O M P L E T I O N A N D H I S T O RY
Fig. 1. 3D map of Ghawar field.
The well was drilled and completed as an extended reach
horizontal OH PWI to a total depth (TD) of 17,716 ft and
Fig. 3. Well completion schematic.
true vertical depth (TVD) of 7,690 ft, Fig. 2. The 61⁄8” OH
was drilled from 8,322 ft to TD. The well was completed
with 7” completion packer and a tail pipe assembly at
7,358 ft with the end of the tail pipe at 8,794 ft, leaving
8,922 ft of horizontally exposed reservoir formation with a
maximum inclination angle of 93°. The average reservoir
porosity is 10%. The objective of this completion is to
cover the anhydrite formation in the 61⁄8” OH below the 7”
liner to the top of the injection formation, Fig. 3. The
decision to set the packer was taken during the drilling
course due to unexpected formation development and
dipping where the setting of the 7” liner was found above
the injection formation leaving the anhydrite formation
exposed.
While the rig was on location, an injectivity test was
conducted at a surface pumping pressure of 1,000 psig
achieving an injection rate of 2.4 barrels per minute
(bbl/min); the rate was considered very low and a clear
indication of formation damage. Performing the acid
stimulation while the rig was on location was not a viable
option; mainly due to safety concerns and the high cost of
rig time; considering the large amount of acid that would be
needed for such treatment.
The well was initially put on injection with an injection
rate of 13,000 barrels of water per day (BWPD) at an
average injection pressure of 2,350 psig. This rate is much
less than the rates of offset wells with even a shorter
horizontal section.
treatment. With bullheading, the acid tends to go to the
least resistance intervals, mostly close to the vertical section
or high permeability streaks; resulting in partial acid
treatment5.
A uniform placement of treatment fluids across the
damaged interval is very essential for the success of the
planned matrix stimulation job.
Chemical diversion and mechanical isolation methods
have been applied with limited effectiveness to distribute the
acid evenly along the horizontal section, especially with
long horizontal wells.
Coiled tubing has been used effectively for acid
displacement in vertical and horizontal wells as a means of
acid placement, where the CT pipe would be run to the end
of the treatment interval and then the acid is pumped across
the formation while pulling out of hole (POOH) or
reciprocating across the treatment interval. This technique
has been also used in combination with chemical diversion
systems, such as foamed viscoelastic diversion, for optimum
acidizing results. In long horizontal and extended reach
wells, this technique application is limited, where CT
usually locks up due to the stacked weight of the CT pipe in
the horizontal section preventing the CT from reaching the
target depth. In such cases, part of the treatment has to be
bullheaded from the lockup point and the rest will be
pumped evenly across the treatment zone while POOH.
Although the maximum available size of the CT during
the job design was only 2”, it was clear from the performed
simulation runs that even bigger OD pipe can not reach the
TD of the well. Simulation runs were also carried out for a
2” CT combined with a vibrational tool and TD would not
be reached.
Review of recent technology advancements to access long
horizontal wells, concluded the CT tractor to be the best
option for reaching MD to displace the treatment fluids.
Although the experience with the CT tractor applications in
OH horizontal wells was very limited, especially with large
acid treatments, it was decided to test this technology to
JOB DESIGN AND PLANNING
Acid Placement Technique
Prior to the acid treatment design, the acid placement
technique into this extended reach PWI was an issue.
Conventional surface pumping through casing, bullheading,
would not give the desired results since diversion of acid
across the damaged interval is a key factor for effective
Fig. 4. Simulation runs for different access techniques.
perform the acid job. Simulation runs were very
encouraging and showed that a 2” CT in combination with
two units of CT tractor can reach TD, Fig. 4.
CT Tractor
The CT tractor is a mechanical device that produces a
concentrated pull force when engaged hydraulically. The CT
tractor is normally made up at the bottom of the CT and is
engaged by pumping a noncorrosive fluid through a
turbine, which acts as a prime mover. A hydraulic pump
then produces the force required to activate a set of wheels
that are hydraulically deployed out of the tool body to
engage the open hole and rotate causing forward
movement. Schematic and typical specifications of the CT
tractor are shown in Fig. 5. Due to the length of the OH
section, a tandem (double) configuration of the CT tractor
was deemed necessary for this operation. This would both
double the force generated as well as double the grip with
the formation allowing it to negotiate reasonable washed
out sections of the OH. Two CT tractors of 31⁄8” size were
planned to be used for this operation with a combined
pulling force of 7,000 lb7.
Acid Treatment Design
The objective of the acid system treatment is to remove the
suspected formation damage and create deep wormholes in
the formation to improve the well’s injectivity. Several acid
systems have been experimented and applied in this part of
the Ghawar field; including plain, diesel emulsified, and
nitrified acid systems. Due to the length of the treatment
interval, volumes of treatment fluids have to be optimized
efficiently without compromising the desired results of the
treatment.
Review of different acid systems applied in the area for
horizontal wells indicated most favorable results were
Fig. 5. Coiled tubing tractor schematic and specifications.
obtained using an acid system consisting of multiple stages
of 20 wt% HCl acid followed by 20 wt% diesel emulsified
acid, then finally followed by foamed viscoelastic
surfactant-based water for diversion4, 6. An engineering
detailed program was prepared for the acid treatment
procedure. The treatment interval was divided into 16
treatment stages of 500 ft each. Below is the general
pumping sequence for each stage:
1. First, the treatment interval has to be washed with
plain 20 wt% HCl for filter-cake clean up and
provide initial wormholes. The main additives to the
plain acid are a corrosion inhibitor, surfactant, and
friction reducer. Plain acid was used at 10 gal/ft,
including additives, resulting in a total acid volume of
77,000 gallons.
2. Plain acid was followed by 20 wt% diesel emulsified
acid at 20 gal/ft with a total of 154,000 gallons for
the 16 treatment stages. The higher concentration of
retarded acid is meant to provide deeper wormholes.
3. To achieve better acid diversion at the end of each
pumping stage, viscoelastic surfactant-based (VES)
water will be used at 10 gal/ft at a total volume of
7,500 gallons.
4. Finally, water over-flush of 10,000 gallons is to be
pumped following the previous 16 treatment stages to
break micelles formed by VES. The over-flush
contained brine water mixed with 3 vol% of mutual
solvent.
The total treatment fluid to be injected in this job is
248,500 gallons; this large acid job is considered one of the
biggest stimulation jobs for any well in the Ghawar field.
Planning and Logistics
The main two parts to plan were the transporting and
mixing of the treatment fluids and the deployment of the
CT and tool string. Also, due to the expected long mixing
and pumping time of corrosive fluids, the safety of
personnel on-site was a concern to ensure safe handling of
chemicals.
Due to the volume significance of the treatment, a total
of 231,000 gal of 20% HCl systems and 17,500 gal of inert
fluids were needed, in addition to the required water to
operate the downhole CT tractor. The main challenges of
material delivering, hauling and mixing were as follows:
• Adequate water and raw acid supply, which was
covered by four water transporters and six raw acid
transporters with a total capacity of 39,000 gal of raw
acid.
• Adequate fluid storage capacity, which was covered by
16 storage tanks with a total storage capacity of
336,000 gal of mixed fluids, Fig. 6.
Fig. 6. Total of 16 500 bbl storage and mixing tanks used to handle the
treatment fluids.
• Mixing all systems on location. This was handled by
the best developed field practices for mixing large
treatment volumes and equipment layout.
As the total length of the designed bottom hole assembly
(BHA) was 48 ft, including the two CT tractor units, and to
avoid the risk associated with high rig up, the pressure
deployment method was used by utilizing a slick line unit.
This method assures the safe deployment of tool strings into
a live well without the use of a long lubricator, longer than
48 ft, and a heavy injector head weight which would
require a large crane and numerous guy wires for stability.
Due to the extensive nature of the operation, safety of
personnel on-site was a concern to all involved parties;
extra safety measures were taken to guarantee safe
execution. A Risk Assessment was conducted to identify
potential hazards throughout the operation to ensure
readiness to handle any safety or operational emergency.
Several safety meetings were held, in both office and on-site,
involving operator and service companies to ensure full
awareness of potential hazards and emergency response
plans.
JOB EXECUTION AND PROCEDURE
The main steps of the job execution were the following:
• Function test and deployment of the tool string in the
well.
• Run the CT tractor 1,000 ft below the tubing end.
• Activate the CT tractor and run to the MD possible.
• Mix and pump the stimulation treatment while pulling
out of the well.
• Un-deploy the tool.
The tool string was deployed in the well taking in
consideration the main risk involved with the snubbing
forces, the pressure control barriers, the CT connector
integrity, the bi-directional strength and the shear capability
of the deployment bar. Successfully, the tool was deployed
in the well keeping two barriers at all times, and following
established best practices and procedures. Deployment
surface equipment mainly consisted of a blowout preventer
Fig. 7. Running in hole and pulling out of hole vs. time.
(BOP) and lubricator for the slick line unit. The deployed
BHA consisted of:
• 2” CT connector
• CT Motor Head Assembly (MHA)
• Circulation sub
• Deployment bar
• Double check valve
• Double ball valve
• Crossover
• Upper CT tractor (Flow Through type)
• Bottom CT tractor (Top Vented type)
The tool was run in the well at an average speed of 45
ft/min while pumping at minimum rate to keep the CT full
with water and conducting the required pull tests until a
9,580 ft depth, where the CT tractor was engaged by
increasing the pumping rate to 1.5 bbl/min. The CT tractor
engagement was confirmed by the reduction in the weight
during the running in the well. The running speed was
adjusted to synchronize the CT and CT tractor movements
at an average run in hole (RIH) speed of 15 ft/min – 20
ft/min.
Between 13,026 ft and 13,148 ft, the CT tractor
encountered a washout; the CT tractor progress was
stopped and the CT could not be run further in the well.
Therefore, the CT tractor was pulled out 100 ft above the
washout area and the running speed increased from 30
ft/min to 40 ft/min trying to create additional inertia for the
pipe to help the CT tractor pass the washout. This
technique was successful and the CT tractor was engaged
with the hole again at 13,148 ft and continued the progress
until reaching 14,770 ft where another washout was
encountered. Three trials were made to POOH and run on
a higher CT speed, but without success, which impeded the
CT from reaching MD and stopped at 14,656 ft. It was
decided to bullhead the first four bottom treatment stages
from the maximum reached depth, 14,656 ft, and the rest
of the treatment will be pumped as per design while POOH,
Fig. 7.
A ball was dropped to open the pumping ports on the
BHA and create a barrier to isolate the internal parts of the
CT tractor from the acid. After 15 hours of mixing of the
first six stages, pumping started and the rest of the
treatment fluid was mixed while pumping. The total
pumping time of the treatment was 52 hours of continuous
pumping at an average pumping rate of 2.0 bbl/min. Once
all acid stages and over-flush were pumped, the tool was
POOH to surface and un-deployment (reverse deployment)
was successfully conducted using the slick line unit. The
whole operation lasted for seven days of around-the-clock
operations.
R E S U LT S A N D J O B E VA L U AT I O N
Injection Gain
Following the successful acid treatment, the well was put
back on injection and the injection potential was effectively
enhanced by more than twofold where the rate increased
from 13,000 BWPD to 28,000 BWPD. This increase in the
injection rate helped to sustain the reservoir pressure in the
area while increasing the oil production target.
Coiled Tubing Tractor Performance
In general, the CT tractor performed very well in this job
although the TD of the well was not reached. Using the CT
tractor increased the reach of the CT in this well by 54%
after tractoring for 5,190 ft in the OH.
The CT tractor could not reach TD mainly due to two
main possible reasons; presence of a washout interval and
the high horizontal friction of CT, making it difficult for the
tool to pull the CT and overcome minimal hole
enlargement. A larger CT tractor could have provided
further reach; however, due to the minimum restriction in
this well of 3.725” it was not applicable.
The inhibition of the CT tractor was an issue, especially
in such a big treatment. In preparation for this job, the
body of the CT tractor was silver coated and extra
protective sleeves were installed, anticipating exposure to
huge amounts of corrosive fluids. This enhancement
provided good protection of the outer body of the CT
tractor, however, minor internal damage was observed on
parts, such as the turbine driving shaft and connection
pipes. This internal damage is a result of having some acid
flowing through the tool body; it is clear that the
circulation sub did not provide full isolation of the CT
tractor.
LESSONS LEARNED
Since this was the first CT tractor job in the Ghawar field,
many lessons were learned. During this job, it was
evidenced that the CT speed can help the CT tractor to pass
washouts in the OH; the inertia force of the CT pushing the
CT tractor can help it to pass through long washouts.
When the CT becomes very long in the horizontal section; it
becomes hard to initiate CT movement when the CT tractor
is stopped by a washout.
The function test for the slick line wire during
deployment and un-deployment is essential. Before opening
the pipe/slip rams the slick line should apply a pull force
equal to the tool weight, 1,000 lb in this case. While testing
the wire for un-deployment the wire was cut at 500 lb
weight.
As some of the internal parts of the CT tractor were
damaged, it is suggested to install a hydraulic valve above
the top CT tractor to ensure complete isolation prior to
pumping the acid; the current configuration is not providing
adequate isolation to protect the internal parts of the CT
tractor from being exposed to corrosive fluids.
S U M M A RY
The operation was successfully completed in one run. The
CT tractor was deployed in the well, engaged at 9,580 ft in
the OH and reached a MD of 14,770 ft. A slick line unit
was used to perform the deployment and un-deployment to
avoid high rig up of the CT injector. At different depths,
while RIH, washout intervals were experienced where the
CT tractor could not give any help to move the CT. In these
situations, the CT string was POOH and RIH again at a
higher speed. This practice was successful in extending the
reach of CT tractor.
A total volume of 248,500 gal of treatment fluids was
pumped to stimulate the well. Objectives of the job was met
with post-acid increase of the injection rate from 13,000
BWPD to 28,000 BWPD.
CONCLUSION
1. A CT tractor can provide an increase of CT reach in
horizontal open hole wells by 54%.
2. CT tractor technology is partially filling the gap between
completion advancement and intervention services.
Enhancement on current tools and development of new
technology is needed to overcome this challenge.
3. Intervention in extended reach wells is both costly and
challenging operationally compared to intervention in
conventional wells.
4. More maintenance is needed for the CT tractor when
used during acid treatment jobs. Availability of handy
spare parts and adequate manpower on-site is essential
for a quick turnaround.
ACKNOWLEDGEMENT
The authors would like to thank Saudi Aramco, Welltec and
Schlumberger for permission to publish and present this
paper.
N O M E N C L AT U R E
BHA
BOP
BWPD
CT
CTU
HCl
MD
MRC
OD
OH
POOH
PWI
RIH
TD
TVD
Bottom Hole Assembly
Blowout Preventer Equipment
Barrels Water per Day
Coiled Tubing
Coiled Tubing Unit
Hydrochloric Acid
Measured Depth, ft
Maximum Reservoir Contact
Outside Diameter, in
Open Hole
Pull Out of Hole
Power Water Injector
Run in Hole
Total Depth, ft
True Vertical Depth, ft
5. Nasr-El-Din, H.A, Aranaout, I.H, Chesson, J.B. and
Cawiezel, K.: “Novel Technique for Improved CT Access
and Stimulation in an Extended Reach Well,” SPE paper
94044 prepared for presentation at SPE/ICoTA Coiled
Tubing Conference and Exhibition, Woodlands, Texas,
April 12-13, 2005.
6. Nasr-El-Din, H.A. and Samuel, M.: “Lessons Learned
from Using Viscoelastic Surfactants in Well Stimulation,”
SPE paper 90383 prepared for presentation at the 2004
SPE Annual Technical Conference and Exhibition,
Houston, Texas, September 26-29, 2004.
7. Omari, M. and Plessing, H.: “Innovation in Coiled
Tubing Tractor Technology Extend the Accessibility of
Coiled Tubing in Horizontal Wells, Allowing Better
Possibilities for Well Intervention,” SPE paper 105225
prepared for presentation at 15th SPE Middle East Oil
Show, Manama, Bahrain, March 11-14, 2007.
REFERENCES
1. Al-Ali, Z.A. and Stenger, B.A.: “A Case History on
Integrated Fracture Modeling in a Giant Field,” SPE
paper 71340 for presentation at the 2001 SPE Annual
Technical Conference and Exhibition, New Orleans,
Louisiana, September 30-October 3, 2001.
2. Bayona, H.J.: “A Review of Well Injectivity Performance
in Saudi Arabia’s Ghawar Field Seawater Injection
Program,” SPE paper 25531 prepared for presentation at
the SPE Middle East Oil Show, Manama, Bahrain, April
3-6, 1993.
3. Blount, C.G., Moony, M.B., Behenna, F.R., Stephens,
R.K. and Smith, R.D.: “Well-Intervention Challenge to
Service Wells that can be Drilled,” SPE paper 100172
prepared for 2006 SPE/ICoTA Coiled Tubing Conference
and Exhibition, Woodlands, Texas, April 4-5, 2006.
4. Harbi, M.I., Al-Dhafeeri, A.M., Al-Rufai, Y.A. and
Mohammed, S.K.: “Evaluation of Acid Treatment
Results for Water Injection Wells in Saudi Arabia,” SPE
paper 101345 prepared for presentation at SPE/IADC
Indian Drilling Technology Conference and Exhibition,
Mumbai, India, October 16-18, 2006.
Identifying Sources of Amine
Foaming Through Detailed
Troubleshooting Provides
More Feasible Solutions
Mater A. Al-Dhafeeri
Mater A. Al-Dhafeeri is a Senior Gas Processing
Engineer working for Saudi Aramco since 1995. He
has worked in most of Saudi Aramco’s gas
processing facilities and NGL areas of the
refineries. Mater received a B.S. degree in Chemical
Engineering from Tulsa University, Tulsa, OK in
1995 and a M.S. degree in Natural Gas Engineering
and Management from the University of Oklahoma,
Norman, OK in 2001.
ABSTRACT
Diglycolamine (DGA) is the most widely used amine sweetening agent in
Saudi Aramco facilities. Similar to other types of amines such as
monoethanolamine (MEA), diethanolamine (DEA) and methyl
diethanolamine (MDEA), foaming is a major concern especially in highpressure (HP) systems. Two case studies revealed that the major cause of
foaming in two different gas processing plants was the high liquid
hydrocarbon entrainment in the sour feed gas.
Focusing on potential causes of the problem and detailed troubleshooting
of amine treatment allowed us to identify the problem and find the most
feasible option to abate the foam or at least reduce its severity.
This article will demonstrate the benefits of proper troubleshooting to
identify the sources of amine foaming in two gas processing facilities at Saudi
Aramco. It will also provide some general information about amine foaming,
causes, symptoms, and troubleshooting guidelines.
FOAMING
Amine solvent foaming has been widely discussed in the gas processing
industry and several pieces of literature address the same problem. Foaming
problems continue to be encountered in amine facilities due to various factors
that induce foaming and lack of operational knowledge to troubleshoot
foaming incidents. Many operational practices regarding foaming problems
are of a reactive type trying to solve what caused such incidents rather than
developing a strategy to track the main sources of foaming and trying to
alleviate them or reduce their impact. High capital loss is reported annually
due to the foaming in amine systems; these could be in the form of
temporarily losing sour gas processing capability, and hence,
reducing sales/fuel gas production, solvent loss, and
violating environmental regulation.
Foaming in any Saudi Aramco treating facility generates
serious revenue loss due to the huge size of the gas
sweetening units treating approximately 7.0 billion standard
cubic feet per day (scfd) of sour gas using the DGA agent.
Continuous anti-foam injection has been the most common
method used in the facilities to suppress foaming. The
utilization of anti-foam injection is well known and
documented throughout the gas processing industry;
however, it is only recommended as a last resort and only
on an intermittent basis. Most of the anti-foams are surface
active and a high dosage could aggravate foaming
problems. Besides, there have been some recent findings
that anti-foam reduces the absorption capacity of CO2 by
40%-55%; however that was based on utilizing MDEA1.
In an effort to reduce the reliance on anti-foams and to
increase operational confidence in the HP amine systems,
the central engineering group of Saudi Aramco in
partnership with field/operation engineering in two Gas
Processing Facilities (Gas Plants) decided to focus on
identifying the sources of foam and eliminate them rather
than trying to suppress the foam.
facilities where most of the current foaming concerns are in
the amine plants that are operating at high-pressures.
Having a low surface tension does not indicate having
stable foam, and hence, a foaming problem. Stability, which
is related to the nature of the surface layer, is the other key
factor of having a foaming concern. Foam stability is
dependent on three main characteristics; elasticity,
gelatinous layer formation, and film drainage4.
• Having higher elasticity, resistance to thinning,
generates lower foaming stability. The major function
of most anti-foam is to increase the solution elasticity
and reduce the foam stability.
• Gelatinous or plastic layer is a surface structure related
to the nature of molecular composition of the aqueous
solution, solutions which are prone to form gelatinous
layers tend to have higher foaming stability4.
Secondary (DEA) and tertiary (MDEA) amines form
this layer easier than primary (MEA and DGA) amines
and therefore, they are more susceptible to foam.
Contaminants, such as amine degradation products,
induce the formation of the gelatinous layer.
• Faster film drainage reduces foam stability. However,
fine particulates, such as iron sulfide, tend to retard
film drainage and increase foam stability.
FOAMING IN AMINE SYSTEMS
FOAM INDUCERS
Foaming is defined as “a result of a mechanical
incorporation of a gas into a liquid, where the liquid film
surrounds a volume of gas creating a bubble2.” Two key
characteristics need to be present in order to have a
foaming concern; solution tendency to foam (the easiness of
a solution to form a foam bubble) and foam stability (foam
resistance to break into the continuous liquid phase). The
higher the foam tendency and stability, the higher the
possibility of having a foaming problem. Surface tension is
the primary indication of foaming tendency. Lower surface
tension leads to more solution susceptibility to foam. The
major source of reducing the surface tension of an amine
solution is solution contamination with surface active
agents which include liquid hydrocarbons. Surface tension is
also affected by operating conditions; higher temperature
and pressure tend to reduce the surface tension.
Temperature has the upper hand in impacting the surface
tension of an aqueous amine solution.
To a lesser extent, higher pressure has a negative impact
on the solution foaming tendency. At higher pressures, the
solubility of liquid hydrocarbons in the amine solution
increases, therefore this changes the surface structure of the
aqueous solution rendering a lower surface tension and
hence increased system tendency to foam3. That is exactly
what has been observed in Saudi Aramco gas processing
Clean uncontaminated amine does not form stable foam.
Amine system foaming is caused by contaminants that are
either introduced to the system through the feed gas, make
up water, and recycled streams or, generated in the system
such as degradation and corrosion products. Listed below
are the most common causes of foaming5-8.
1. Liquid hydrocarbon introduced by sour feed gas is the
primary cause of foaming problems in gas sweetening
plants. Liquids can be introduced as mist entrainment or
carry over, or can be formed inside the column if the
lean amine entering the column is at a lower temperature
than the sour gas dew point. The impact of liquid
hydrocarbon comes from the fact that it is soluble in the
aqueous amine solution and therefore reduces its surface
tension. Secondary and tertiary amines tend to foam in
the presence of liquid hydrocarbons more than primary
amines due to the higher solubility of liquid hydrocarbon
in secondary and tertiary amines. One of the challenges
is the removal of liquid hydrocarbon droplets of aerosol
size. Droplet sizes greater than 3 microns are generally
controllable; however, smaller sizes require careful filterseparator and coalescer design. Some plants were able to
reduce the liquid carry over by installing 0.3 micron
coalescers upstream of the amine absorber columns9.
2. Solid particulate contamination, especially iron sulfide, is
3.
4.
5.
6.
7.
one of the major causes of foaming. Iron sulfides can be
very fine particulates, which are difficult to remove by
conventional mechanical filters, tend to concentrate in
liquid-gas interface and therefore increase the foaming
stability. Iron sulfide is a byproduct of corrosion
activities of hydrogen sulfide and carbon steel piping. It
could be carried over from the sour feed gas, or
generated in the amine solution due to various reasons
such as high solution acid gas loading, high velocities,
and formation of acidic degradation products.
Water soluble surfactants such as corrosion inhibitors,
well treating compounds, and excessive anti-foam agents
tend to dissolve in aqueous solutions and reduce surface
tension. Such contaminants are often much more
problematic than liquid hydrocarbons, if an appreciable
amount exists in the sour gas, due to their higher
solubility in amine solution.
Amine degradation products lead to changes in the
amine solution structure and may increase the foaming
tendency. Degradation products are compounds which
are formed either by the direct reaction of the amine and
constituents in the feed gas (such as CO2, COS, CO, O2
and CS2) or by thermal decomposition of the
amine. Conversion of the amine, irrespective of the
mechanism, represents a loss of active and valuable
amine.
Heat Stable Salts not only tend to reduce the system
sweetening capability, but also increase corrosion and
subsequently increases iron sulfide production and
affects the physical properties of the solution. Corrosion
products and changes in solution properties tend to
increase the foaming tendency and stability. Heat Stable
Salts are not thermally regenerable causing them to
accumulate in the circulating amine solution and
contaminating it. Such heavy salts are products of amine
reaction with other anionic species and/or stronger acidic
components (other than H2S and CO2) which are present
in the sour feed gas.
Oxygen ingress in the feed or the amine solution, even in
ppm levels, leads to the formation of carboxylic acids
that react with amine to form Heat Stable Salts and
therefore increases the system tendency to foam. Positive
pressure is always required to avoid any accidental
oxygen leakage to the system. One area that needs to be
monitored is the amine storage tank that should be
normally protected by an inert gas blanket; commonly
nitrogen blanket gas is used.
Makeup water could be another source of introducing
various contaminants to the system. The main source of
the makeup water is the utility plant where various
chemical additives are introduced to treat it prior to
feeding it to the steam boilers. Such chemicals include
corrosion inhibitors and boiler feed water chemicals.
Demineralized water could provide a very safe source of
makeup.
FOAMING SYMPTOMS
An amine system subjected to foaming exhibits the
following behavior:
• Sudden increase in the column differential pressure is
the first alarming sign of a foaming system. Normally,
amine absorber columns are equipped with differential
pressure cells to monitor system abnormalities. When
the contactor is facing a foaming problem and as the
foam height is increased, the void volume inside the
column is reduced. Reduction in void volume leads to
higher pressure drop.
• Off specification sweet gas due to the loss of some
absorption capacity of amine solution. Foaming
reduces the vapor-liquid contact area, generating a
reduced effective mass transfer zone and thus less acid
gas is picked up by the amine. Most of the gas
processing facilities are equipment with an online
analyzer to detect an H2S concentration in the sweet
gas to avoid producing an off specification sales/fuel
gas. Unexpected high H2S content in the sweet gas
indicates a possible foaming problem in the system.
• Amines carry over to the downstream equipment. This
is a late warning sign of foaming in the column and
could be noticed by some erratic and/or abnormal
levels in the downstream knockout drums.
• Loss or reduction in rich amine flow rate accompanied
with an erratic and/or abnormal level indication in the
absorber column bottom section.
• Abnormal absorber column temperature profile. A
typical temperature profile has a shape of a pregnant
woman, where the bulge (maximum) temperature is in
the lower trays where the main reaction between acid
gas and amine solution takes place, Fig. 1. Normally,
during foaming, the bulge temperature shifts from the
lower trays to the upper trays, especially if foaming
was caused by a contaminated sour gas.
ANTI-FOAM INJECTION
Anti-foam does not eliminate the foaming problem; rather,
it is used to reduce its severity. Most anti-foams tend to
increase the surface layer elasticity allowing it to resist film
thinning7. Once the anti-foam injection is stopped, the
system becomes vulnerable to foaming at anytime due to
the fact that the foam inducing contaminants are still within
the system. Relying solely on anti-foam to avoid foaming
problems leads to contaminants build up in the system, this
will lead to other serious problems such as amine
degradation, solvent losses and corrosion. Excessive antifoam dosage reverses its function and makes it a foam
promoter.
This phenomenon has been clearly demonstrated by
Saudi Aramco Research & Development Center where it
was found that silicon based anti-foam increases its foam
reducing power in a DGA system up to a concentration of
25 ppm and nothing was gained beyond that. At 9,000
ppm, anti-foam begins to stabilize the foam, and therefore
increases the foaming severity10. Another side effect that has
yet to be fully proven for the primary amines is the impact
of anti-foam on the reduction of the mass transfer rate. A
study1 concluded that presence of anti-foam renders lower
diffusion of the acid gases into the amine solution and
therefore, reducing amine absorption capacity. Because of
the above reasons and the extra cost associated with antifoam chemicals, anti-foam should be the last option.
Consequently, preventing contaminants and maintaining a
good quality amine should be the primary target.
CASE STUDIES IN AMINE FOAMING
Foaming in HP gas treatment facilities at Saudi Aramco has
been a concern since their startup. Currently, there are seven
HP treatment trains in Saudi Aramco; five are processing
non-associated sour gas located in the southern area and
two at Berri Gas Plant treating HP offshore associated gas.
Continuous anti-foam is being extensively utilized in the
southern area gas plants. In Berri Gas Plant, anti-foam
injection was subjected to various changes from batch
injection to continuous injection as a reaction to some
foaming incidents where the plant management could not
tolerate any further reduction in gas supply.
The central engineering group decided to tackle the
foaming problem in two locations where there have been
elevated concerns regarding foaming. The main target of the
troubleshooting was to identify the source of foaming
rather than relying on the practice of optimizing the antifoam injection rate. Listed below are the two case studies
with some background on the plants, causes of the
problems, and recommendations to abate foaming or reduce
its severity.
CASE 1: SHEDGUM GAS PLANT (SHGP)
History
Foaming in the HP amine contactor has been a problem
since the startup of the plant. The sour non-associated
Khuff gas was first introduced to the unit in 1991 with the
amine being regenerated in one of the low-pressure (LP) gas
treatment facilities. Maximum throughput attained at that
time was 280 million standard cubic feet per day (MMscfd)
(Design rate is 440 MMscfd). Even at that rate, the system
did not stabilize due to the onset of early foaming
symptoms. Based on the commissioning tests, it was
concluded that foaming in the HP contactor was caused by
some contaminants present in the amine system. Therefore,
activated carbon beds were installed temporarily to remove
dissolved hydrocarbons. After applying three batches of
activated carbon, which were exhausted within 35 days, the
plant was only capable of processing 250 MMscfd of sour
gas. No more activated carbon was added and the system
was dismantled for economical reasons. With the
continuous anti-foam injection of 0.72 ppm, the train was
able to process a maximum sustainable sour gas rate of 460
MMscfd. Since then, the plant has been utilizing continuous
anti-foam. With time, the plant processing capacity has
declined and symptoms of foaming have occurred when the
plant has been operating around the design rate even with
continuous anti-foam injection. Table 1 shows the basic
information about the HP unit.
The team that was formed to resolve the problem
focused on three major areas. Two of them address
potential causes of foaming. The third explores some
possible options to reduce the foaming problems. These
areas are:
• Amine solvent quality
• Sour feed gas pretreatment
• Areas of improvements
Amine Solvent Quality
Amine solution quality is a crucial factor in predicting and
preventing foaming. The first step taken was to check the
lean amine solution quality. Analyses were performed to
show a detailed breakdown of the amine solution
constituents; however, these analyses did not show the
content of either the dissolved hydrocarbon or dissolved
solids, which were expected to be the major cause of
foaming in the plant. The results revealed 15 wt%
degradation products in the solution. The conventional
titration method was showing prior to the detailed analysis
an amine concentration of around 40 wt% - 50 wt%;
however, it was found to be < 34 wt%. Refer to Table 1 for
the complete analyses results.
This is a clear sign that there is a poor amine quality
circulating within the system. The main reason behind this
was the system configuration at that time where a common
regenerator was used for the HP and LP trains.
Hydrocarbons were speculated to be in an appreciable
amount due to the amine filtration system which does not
contain activated carbon beds. Existing filtration consists of
a pre-coat filter (1 micron rating) and a mechanical cotton
fiber filter (5 micron rating) designed to process 10% of the
circulating amine solution. Earlier studies showed that when
activated carbon beds were installed, they were exhausted
in less than 35 days. This indicated that amine was severely
contaminated with dissolved hydrocarbon that was
introduced by the sour feed gas.
Sour Gas Pretreatment
The HP unit is equipped with a slug catcher for removing
bulk liquids and two vertical three phase filter separators
for removing liquid aerosols and solid particulates with
diameters of > 0.5 microns. The filters were equipped with
two separate compartments, 42 filter coalescing elements,
and vane pack. Estimated clean pressure drop (criteria for
replacing the filter element) across the filter separator was
1.25 psi. A HP drop has never been a concern in the plant
since the unit startup. It was concluded that the presence of
solids in the gas phase was not a major concern.
Therefore, we decided to inspect the filter separator for
mechanical damage to the filter elements. Most of the filter
elements were found to be in good mechanical condition
except for three elements that had some cracks that could
have been caused by improper installation and/or damage
during the removal process. Another important issue we
looked at was to verify the liquid loading inside the filter
Fig. 1. Typical contactor temperature profile.
separator. To do that we collected samples from locations
#1 and #2 in Fig. 2. Samples from location #2 were used as
simulation input and the samples from location #1 were
analyzed for liquid loading to confirm the simulation
results. In location #1 we collected the samples from the
vertical segment of the pipeline to have a representative
sample. The collection point was carefully chosen to be as
close as possible to the exit nozzle of the heat exchanger to
minimize liquid settling. Location #2 was used to collect gas
stream samples where the possibility of having liquid is
minimal. This stream was then analyzed and the analyses’
results were used in the simulation to estimate the liquid
formation downstream of the heat exchanger.
A combination of both methods provided a good
representation of the liquid loading. Simulated cases showed
a liquid loading of 320 gpm, while the design rate for each
filter separator was 62 gpm. Liquid loading measured from
location #1 showed liquid loadings varying from as low as
15 gpm to as high as 320 gpm. This indicated that the filter
separators were well under designed for handling the high
liquid loadings; this was mainly due to operating the plant
under an inlet gas composition that is different from the
design.
Areas of Improvement
It was clearly shown that high liquid loading that exceeds
the design of the exiting filter separator is the main cause of
the foaming problem in the facility. Nonetheless, due to the
high capital cost associated with installing additional filter
separators and the commissioning of a new regeneration
system for the HP unit, it was decided to continue using
continuous anti-foam injection as the primary option to
suppress foaming. Several low cost modifications and
operational practices were adapted to improve the unit
performance and reduce the foaming severity. These include:
• Retrofitted perforated liquid surface protection plate
above the maximum liquid level. This will reduce
agitation activities at the liquid surface and also reduce
the liquid carry over rate.
• Modified the level control system to have one
controller for the liquid hydrocarbon and water levels
indistinctively. This will allow faster drainage of the
liquid and reduce carry over.
• Enhanced operational awareness of some of the
important practices; such as routine skimming of
hydrocarbon liquids from the flash drum and the
reflux drum, eliminating the oxygen ingress to the
amine storage facilities, and operating the flash drum
at pressures as low as possible to flash more
hydrocarbons.
Fig. 2. Sample collection locations.
Fig. 3. Berri Gas Plant slug catcher level trend during the November 26
foaming incident.
CASE 2: BERRI GAS PLANT (BGP)
Background
Berri Gas Plant treating an offshore HP sour gas at two
amine treating units were commissioned in 1998 and 2000,
see Table 1. Since their startup, the units were hit by a series
of foaming incidents during the winter season. During each
incident the plant used batch anti-foam to control the
problem; however, after some recent incidents, a continuous
anti-foam injection has been practiced.
The two HP trains use activated carbon beds to treat the
amine solution with upstream and downstream guard
filters. Being surface active, anti-foam usually is adsorbed
by the activated carbon beds and therefore exhausts them
quickly. It was a common practice to have the beds offline
during anti-foam injection. Having the activated carbon
beds offline leads to the dilemma of not having a sink
source for the anti-foam. Continuous anti-foam injection
means continuous build up of the anti-foam agent in the
system that could after some time reverse the functionality
of anti-foam. Continuous anti-foam at Berri Gas Plant has a
more severe impact on the system compared to ShGP in the
previous case study. ShGP is equipped with a pre-coat filter
that acts as a sink for the anti-foam agent.
Our laboratory found that silicon based anti-foam (100
ppm) was completely removed from the amine solution by
one pass through 1” pre-coat filter media. It was estimated
that 70% of the anti-foam was removed by the pre-coat
filter at the plant10. Therefore, identifying the causes of
foaming was imperative to convince the plant management
to stop practicing continuous anti-foam injection. By
reviewing the recent two foaming incidents, foaming
problem in the HP system, its causes, and recommended
remedies are addressed by answering the following
questions:
• What went wrong in the BGP HP amine unit?
• How did we identify the causes?
• What is recommended to alleviate foaming
reoccurrence?
What Went Wrong in BGP HP Amine Unit?
The main cause of the foaming incidents was determined to
be liquid carry over with the sour gas stream mainly as a
result of liquid condensation in the pipeline after an upset
in the offshore gas producing facilities. The upstream
facilities use a refrigeration system to control the
hydrocarbon dew point at approximately 60 °F to condense
heavy hydrocarbons and thus avoid their condensation
along the pipeline. Immediately preceding the last two
foaming incidents, the upstream Gas Compression Plant
(GCP) and the refrigeration systems were shutdown
temporarily. This upset resulted in hydrocarbon
condensation and liquid buildup in the pipeline that was
carried to the BGP slug catcher. Inadequate drainage of the
slug catcher liquid level caused liquid carry over to the HP
contactor.
Fig. 4. Berri Gas Plant slug catcher level trend during the January 18 foaming
incident.
Fig. 6. Offshore gas compression facility outlet flow reading, January 18.
Fig. 7. Amine contactor temperature profile during November 26 foaming incident.
Fig. 5. Offshore gas compression facility outlet flow reading, November 26.
How did we Identify the Causes?
Several indications showed that the cause of foaming was
liquid carry over resulting from an upset in upstream
operation. These indications are listed below:
• High Level Indication in BGP Slug Catcher
There was a sharp increase in the slug catcher level
indicator reading immediately prior to each foaming
incident (Figs. 3 and 4) which is not normal due to the dry
nature of the sour feed gas. The sour gas is considered a dry
gas because of the removal of heavy H/C by the dew point
control unit. It is concluded from this that a rapid increase
in the slug catcher level is very remote except during upsets
in the upstream operation or during pipeline scraping
activities.
• Outage in Upstream Compression Plant
Prior to each of the two recent foaming incidents, there
were upsets in the upstream GCP where gas flow through
the sub-sea pipeline to BGP ceased, Figs. 5 and 6. No flow
into the sub-sea segment of the pipeline and continuous
withdrawal of gas by BGP caused the pipeline pressure to
Fig. 8. Amine contactor temperature profile during January 18 foaming incident.
decrease. Due to the retrograde nature of the gas, pressure
reduction leads to an increase in the gas dew point
temperature11. Therefore, low ambient temperature caused
the stagnant gas to reach the dew point temperature and
resulted in condensation in the pipeline. Looking at the two
foaming incidents, there was a time lag between the
shutdown of GCP and the onset of foaming in the HP
amine system. This is due to the fact that gases travel faster
than the bulk liquids accumulation due to condensation.
Operating Gas Plant Facility
Berri
Shedgum
Sour Gas Rate, MMSCFD
270
440
Hydrogen Sulfide Content, Mol%
2.2
3.2
Carbon Dioxide Content, Mol%
2.8
3.7
Pressure, psig
550
990
2,100
3,400
Process Variables
Amine Circulation Rate, GPM
Lean Amine Solution Analyses
Amine, wt%
39
34
Water, wt%
58
52
Degradation Products, wt%
3
15
Organic Acids, ppmw
50
80
Inorganic Acids, ppmw
15
20
HSS Salt Anions, ppmw
65
100
Lean Loading, mol/mol
0.08
0.07
99
98
Sample Recovery, %
Table 1. Berri and Shedgum Gas Plant data
Gas residence time in the HP gas pipeline is 13-16 hours;
however liquids will travel slower depending on their
quantities. This also explains the time difference in
observing the shutdown impact in the form of foaming
between the two incidents. The November 26 foaming took
place two days after GCP shutdown while the January 18
foaming was observed five days after the shutdown. This is
attributed to longer shutdown duration during the January
18 case that resulted in more liquid condensation and
accumulation.
• Contactor Temperature Profile
The temperature profile inside the contactor during both
foaming incidents showed an increasing trend as we moved
upward in the column, Figs. 7 and 8. The reaction between
amine and sour gas is exothermic and usually the first
contact trays have the highest temperatures. In foaming
systems, major reactions take place at the interface of the
foam due to the hold up of amine by the foam. As the foam
moves upward, the exothermic reaction will move upward
and will be reflected by higher temperatures on the upper
trays. Such a trend appeared during the foaming incidents,
which indicates that sour feed gas has introduced foaming
promoters to the system.
• BGP HP System Operating Experience
Operating experience in BGP HP amine plant showed no
foaming tendencies during summer time. High temperature
is the best environment for inducing foaming as it reduces
the amine surface tension and makes it susceptible to
foaming. Trouble free operation during summer operations
proves that the HP DGA system should be adequate to
handle normal operating conditions during cold weather
seasons if the same sour gas feed quality is maintained.
• Amine Quality
Amine quality has not been a problem in BGP HP DGA.
The plant was able to operate adequately during summer
operations. In addition, the HP amine system is equipped
with the recommended conventional filtration system of
mechanical and activated carbon which are designed to
maintain high amine quality. The good amine quality was
confirmed by detailed analyses as shown in Table 1.
What is Recommended to Alleviate Foaming
Reoccurrence?
Troubleshooting the amine foaming problem and
operational experience revealed that this problem is periodic
and could be controlled without any major modification to
the exiting system. Therefore, it was decided to stop the
continuous anti-foam injection practice. It was found that
the most cost-effective method to abate foaming is to have
better coordination between the upstream facilities and the
gas processing plant. Producing facilities should alarm the
gas plant to take the proper action whenever upsets occur
in any of the following systems: gas refrigeration, gas
dehydration and gas compression. Implementing this
practice will allow gas treatment operations personnel to
take the corrective action of injecting anti-foam (batch) to
the amine solution and closely monitor plant operation. In
addition, added benefits could be attained by installing a
gap action control valve in the slug catcher liquid drainage
system to prevent high liquid build up.
TROUBLESHOOTING GUIDE
Effective troubleshooting of foaming is a vital step in
achieving a resolution to amine foaming. Operations
engineers should be aware of several things in order to
provide effective troubleshooting:
• Understand the foaming concept, symptoms, and
potential causes.
• Check amine quality and treatment methods that
include filtration and/or reclamation.
• Examine sour gas quality and pretreatment equipment.
• Review operation practices of the amine sweetening
plant.
• Respond proactively to the activities in upstream
facilities that have the potential to cause problems in
the amine system.
CONCLUSION
Foaming in amine absorber columns has been a major
concern in HP gas sweetening facilities in Saudi Aramco.
Therefore, continuous anti-foam injection to suppress
foaming has been the most popular remedial method.
Investigation and troubleshooting of the foaming in two
amine sweetening facilities reduced the reliance on the
continuous anti-foam injection at Berri Gas Plant by
identifying the main source of the problem; however,
economics dictated continuing the anti-foam injection at
Shedgum Gas Plant. Both case studies revealed that liquid
hydrocarbon carry over with sour feed gas was the main
foam promoter. A lesson learned from these two cases was
to focus on defining the foaming problem. This allowed a
better understanding of the problems and provided the least
expensive solution to abate the foaming or reduce its
severity.
ACKNOWLEDGEMENTS
This paper was previously published in the Oil & Gas
Journal, August 27, 2007, under the title “Identifying
Sources Key to Detailed Troubleshooting of Amine
Foaming.”
REFERENCES
1. Linga, H., Hinderaker, G. and Tykhelle, B.: “The Effect
of Hydrocarbon Condensate and Anti-foaming Agents
on the Performance of CO2 Absorption with Activated
MDEA,” presented at the 52nd annual Lawrence Reid
Gas Conditioning Conference, Norman, Oklahoma,
February 24-27, 2002.
2. Pauley, C.R., Hashemi, R. and Caothien, S.: “Analysis of
Foaming Mechanisms in Amine Plants,” presented at the
39th annual Lawrence Reid Gas Conditioning
Conference, Norman, Oklahoma, March 6-8, 1989.
3. Al-Ghamdi, A.M.: “Study Underscores Effectiveness of
Anti-foaming Agent in DGA Sweetening Process,” Oil
and Gas Journal, May 20, 2000, pp. 62-69.
4. Pauley, C.R., Hashemi, R. and Caothien, S.: “Ways to
Control Amine Unit Foaming Offered,” Oil and Gas
Journal, December 11, 1989, pp. 67-75.
5. Khull, A. and Nielsen, R., Gas Purification, 5th Edition,
Gulf Publishing Company.
6. Pauley, C.R.: “Face the Facts about Amine Foaming,”
Chemical Engineering Progress, July 1991, pp. 33-38.
7. von Phul, S.A.: “Sweetening Process Foaming and
Abatement,” presented at the 51st annual Lawrence Reid
February 25-28, 2001.
8. von Phul, S.A.: “Sweetening Process Foaming and
Abatement Part II: Case Studies,” poster session in the
52nd annual Lawrence Reid Gas Conditioning
Conference, Norman, Oklahoma, February 24-27, 2002.
9. Khatib, Z.I.: “Reduction of Entrainment of Aerosols in
Gas Streams,” presented at the 47th annual Lawrence
Reid Gas Conditioning Conference, Norman, Oklahoma,
March 2-5, 1997.
10. Harruff, L.G.: “Saudi Arabian Experience with DGA
Units and Related Sulfur Plants,” presented at the 48th
annual Lawrence Reid Gas Conditioning Conference,
Norman, Oklahoma, March 1-4, 1998.
11. Katz, D.L.: “Retrograde Condensate in Natural Gas
Pipelines,” presented at the 23rd annual Lawrence Reid
1973.
SmartWell Completion Utilizes
Natural Reservoir Energy to
Produce High Water-Cut and
Low Productivity Index Well in
Abqaiq Field
Nashi Al-Otaibi
Abdulwafi A. Al-Gamber
Michael Konopczynski
Suresh Jacob
Nashi Al-Otaibi is a Senior Engineer with the Abqaiq
Production Engineering Division of Saudi Aramco’s
Southern Area Production Engineering Department
(APED/SAPED). Nashi holds a B.S. in Petroleum
Engineering from King Fahd University of Petroleum and
Minerals (KFUPM), Saudi Arabia. He has worked in
several petroleum engineering departments within Saudi
Aramco, including production engineering, and reservoir
management and the EXPEC Advance Research Center
(EXPEC ARC). Nashi is an active member with the Society
of Petroleum Engineers (SPE).
Abdulwafi A. Al-Gamber is the Superintendent of the
North Ghawar Well Services Division of the Southern Area
Production Services Department. Previously, he held
supervisory positions in the Abqaiq Production Engineering
Division. Abdulwafi has a B.S. degree in Petroleum
Minerals (KFUPM), Saudi Arabia. He has more than 20
years of experience in production engineering, reservoir
engineering, drilling and workover engineering/operations,
and producing operations.
Michael Konopczynski is the Manager of Reservoir Solutions
and Commercialization at WellDynamics International Ltd.,
where he is responsible for providing petroleum engineering
support for the application of SmartWell technology. Prior
to joining WellDynamics in 2001, Michael was an
employee of Shell Canada Ltd. in a variety of production
engineering and technology roles for close to 20 years.
His assignments with Shell included projects
for steam assisted thermal recovery, CO2 enhanced recovery,
deep sour gas development, and gas-condensate
developments in Canada, the United States and the
Sultanate of Oman.
Suresh Jacob is the Country Manager for WellDynamics
in Saudi Arabia, where he is responsible for the technical
and commercial support for WellDynamics’ operation in the
Kingdom. He has over 10 years experience in well
completion and has worked on several projects comprising
the planning, installation and operation of SmartWell
completions. Suresh received a B.S. in Mechanical
Engineering from the University of Kerala, India in 1993
and a M.S. degree in Petroleum Engineering from the
University of Texas A&M, College Station, TX in 2001.
This application eliminates the need for artificial lift
infrastructure at the surface and operational expenditures.
Using gas cap energy basically is providing free energy.
This article discusses selection criteria of smartwell
application to naturally lift an oil producer by utilizing
energy from an overlying gas cap, completion and operation
experiences and production optimization. Results show the
applicability of natural gas-lift dependent upon standoff
(with respect to the initial gas-oil and water-oil contacts)
and target production rate. It will also address design
considerations for natural gas-lift applications and reports
the operational experience gained in the Abqaiq field with
gas cap gas-lift applications.
INTRODUCTION
ABSTRACT
Reservoir Background
Innovations and smartwell technology applications have
helped overcome the challenges of complex and mature
fields such as the Abqaiq field. This article presents the
application of SmartWell technology in utilizing “free
energy” from an overlying gas cap to produce high watercut and low productivity wells completed in underlying
reservoirs.
The smartwell completion was implemented in the
Abqaiq field to naturally gas lift an intermittent well (a well
which cannot continuously flow to the surface), completed
in the low permeability Hanifa reservoir. The well is drilled
through the gas cap having a 40 ft gas column in the upper
section of the Arab-D reservoir. In this application, the
smartwell completion consists of a surface controlled,
hydraulically operated downhole choke valve that regulates
the gas inflow from the gas cap into the production tubing.
Abqaiq field was the first super giant field developed in
Saudi Arabia. It is located at the North-Eastern tip of the
Ghawar field in the Eastern Province of Saudi Arabia. The
field was discovered in 1940, but full scale development did
not begin until 1946. The field consists of a high relief
south dome and a low relief north dome. The Abqaiq field
produces from two main reservoirs, the Jurassic Arab-D
and Hanifa reservoirs, separated by the 450 ft thick, nonreservoir Jubaila formation. The Arab-D (upper) reservoir is
prolific throughout the whole field with an average
permeability of 400 millidarcies (mD). The Hanifa oil
reservoir (lower) is only present in the South Dome region.
The matrix permeability of this lower reservoir is low (1
mD - 2 mD) with well productivity controlled by near
wellbore fracturing. The oil in the Abqaiq field Arab-D and
Hanifa reservoirs is Arabian Extra Light with an average
API of 37° and Gas Oil Ratio (GOR) of 860 SCF/STB.
First commercial production began in 1946 from ArabD. The field was initially produced in a primary depletion
mode. In the time period from 1954-78, a crestal gas
injection pressure support program was carried out in the
primary Arab-D reservoir at the crest of the high relief
South Dome. Water injection was started from 1956. After
almost 60 years of production, the field watercut is still
very low. Hanifa reservoir production started in 1954.
Reservoir development and production picked up slightly in
1975 with implementation of gravity water injection.
Production from Hanifa was limited and full development
was slow due to the complex behavior of this fractured
reservoir. Vertical communication between the two
reservoirs is evident from production data, and is believed
to be caused by faults and extensive fractures that cut
through Jubaila1, 2. Figure 1 shows the gas cap in the top of
Abqaiq field Arab-D reservoir.
Fig. 1. Abqaiq field map and the gas cap is shown in red.
Hanifa Productivity
The Hanifa oil reservoir is separated from the overlaying
giant Arab-D reservoir by over 450 ft of the Jubaila
formation. These two reservoirs are in pressure-fluid
communication via a network of fractures through Jubaila
impermeable carbonates. This reservoir communication
together with the reservoir heterogeneity of the Hanifa, in
the form of micro-pores and associated fractures, provides a
challenge for reservoir geology and reservoir engineering to
formulate a development plan, involving horizontal
producers, to mitigate reservoir communication and to
efficiently and effectively extract the reserves within the
Abqaiq Hanifa reservoir. The low permeability (1-2 md) of
Hanifa rock adversely impacts the wells productivity index
and injectivity index (PI/II), which causes the Hanifa
producers and injectors that are not in contact with big
fractures to have very low rates1. In the case of the
producers, the wells tend to flow below bubble point
pressure. Moreover, these types of wells usually die at less
than 40% water cut. On the injection side, the tightness of
Hanifa makes it challenging on the flank injectors to
provide adequate pressure support to the crestal producers.
I N C E N T I V E S F O R N AT U R A L G A S L I F T
UTILIZING FREE ENERGY
Fig. 2. Abqaiq Well A completion schematic.
To overcome the challenges of this complex reservoir, Saudi
Aramco has carried out many projects, studies and field
trials for new technologies to achieve the ultimate goal of
enhancing oil recovery. An auto gas lift smartwell
completion system was selected in AB-A as an alternative to
conventional artificial lift methods, like an electric
submersible pump (ESP).
The concept of natural gas lift or auto gas lift has been
discussed by Kumar, et al.3, Glandt described the application
of intelligent wells to natural gas lift4, and others have
described the application and benefits of intelligent well
auto gas lift in the North Sea and in Brunei5, 6. The
smartwell option utilizes the energy from the gas cap to lift
the oil and eliminates the need for artificial lift
infrastructure at the surface. The advantages of smartwells
were the low operating cost and reduction in well
intervention compared to conventional artificial lift
methods like ESP.
CONCEPTUAL DESIGN OF NATURAL GAS LIFT
The design of natural gas lift with smartwell technology is
different from the standard gas lift techniques that inject gas
in the annulus and produce from the tubing through gas lift
valves in side pocket mandrels. In the smartwell design, the
gas from the Arab-D gas cap is produced into the
production tubing to gas lift the oil from the Hanifa
intermittent well. The gas is controlled through a
hydraulically actuated, remotely operated downhole flow
control device. The valve is installed between two packers
to isolate the individual zones along the well path. The
interval control valve enables choking or shutting different
zones according to the well performance like drawdown,
GOR, water cut, etc. The control lines are used to
hydraulically actuate the downhole interval control valve
from the surface. Three conditions must exist to effectively
implement sustainable auto gas lift in a well:
1. The pressure of the gas reservoir must be greater than
the hydrostatic pressure of the column of fluid in the
production tubing (to the depth of gas entry), plus the
line-pack under static conditions, to “kick-off” the
well.
2. The productivity of the gas reservoir must be great
enough to produce sufficient gas for effective lift at
moderate drawdown pressures.
3. The volume of gas reserves associated with the gas
source must be large enough to maintain sufficient
pressure and productivity throughout the life of the
well and under a variety of producing conditions as
the oil zone is depleted and water cut increases.
Fig. 3. Interval control valve.
flow trim to be accurately moved through up to 11
predetermined positions. Accu-Pulse may communicate with
either side of the ICV piston; it may drive the ICV open or
closed. This allows incremental positioning in one
direction8. In this application, the Accu-Pulse module was
placed in the open side so that the valve may be cycled in
incremental positions towards full opening. This
configuration allows the choke to be directly closed from
any open position without having to open any further. By
matching Accu-Pulse with a specific ICV flow trim design,
the system can be optimized for gas injection requirement.
The ICV valve was designed with this in mind and provides
a customizable flow trim element allowing Accu-Pulse and
the valve to be matched to gas lift requirements.
GAS TRIM CHOKE DESIGN
Fig. 4. Accu-Pulse control system.
Figure 2 shows the well completion and the different
downhole components of the smart auto gas lift
completion.
I N T E R N A L C O N T R O L VA LV E ( I C V )
The Interval Control Valve (ICV) was used to control lift gas
from the Arab-D gas cap to the lower Hanifa reservoir. This
ICV has 11 positions, including fully open and fully closed.
The ICV is hydraulically operated from the surface through
¼” control lines. A minimum control line differential
pressure of 250 psi is needed to unlock the metal-to-metal
seal in the choke. This feature prevents inadvertent opening
of the choke by the friction of the fluid. Once unlocked, the
choke can then be fully or partially opened to any position
by applying pressure on the open line. The choke may be
returned to the closed position by applying pressure to the
close line8. The ICV is shown in Fig. 3.
The design process for an auto-gaslift application must
consider the range of possible uncertainties related to
reservoir and well performance throughout the life of the
well. The following key parameters must be considered in
the design process, including the range of values of these
parameters representative of both reservoir uncertainty and
expected changes over the functional life of the well:
1. Gas zone productivity index.
2. Gas zone reservoir pressure (including future
depletion).
3. Gas zone fluid composition.
4. Oil zone reservoir pressure (including future
depletion).
5. Oil zone productivity index.
6. Oil zone fluid composition (particularly water cut and
natural GOR).
The evaluation and design process is based on nodal
analysis to determine the viability and sustainability of the
auto-gaslift application, to establish the optimum
completion geometry (production conduit size), and to
specify the ICV choke Cv profile to provide optimum gas
ACCU-PULSE™ CONTROL SYSTEM
The Accu-Pulse Control System, shown in Fig. 4, is used in
conjunction with the SmartWell Control System to
incrementally open a multi-position ICV. Accu-Pulse
provides incremental movement of a suitable ICV flow trim
by exhausting a predetermined amount of control fluid
from the ICV piston. The capability to recharge and
exhaust the same amount of fluid repeatedly allows the ICV
Fig. 5. Gas lift performance curves.
Fig. 6. Flowing bottom hole pressure.
Fig. 8. CV profile for gas zone chokes.
Fig. 7. Gas zone IPR.
Fig. 9. Types of flow control valve choke trims.
lift controllability over the range of reservoir uncertainties
and changes in future operations7.
The evaluation and analysis process is as follows:
1. Gas lift performance curves (gross flow rate and
flowing bottom-hole pressure vs. lift gas injection rate)
for the oil zone with a fixed flowing tubing head
pressure are generated using nodal analysis
software/wellbore simulator. Curves are generated for
the anticipated range of oil zone productivity indices,
oil zone reservoir pressures, and water cuts, Fig. 5.
From these curves, the lift gas rate resulting in
maximum productivity (minimum flowing bottomhole pressure (FBHP)) and the lift gas rate resulting in
a flowing bottom-hole pressure equivalent to the
minimum desired inflow pressure are identified, Fig. 6.
2. Using the gas lift performance curves, the flowing
production conduit pressure at the point of lift gas
injection is calculated based on tubing outflow
performance as a function of gas injection rate. This
pressure comprises the “downstream” pressure of the
auto gas lift flow control valve.
3. Inflow performance curves for the gas zone are
generated, resulting in gas zone inflow pressure as a
function of flow rate. These pressures comprise the
“upstream” pressure of the auto-gaslift flow control
valve, Fig. 7.
4. At any particular lift gas flow rate, the difference
between the pressure established in Step 3 (gas zone
inflow pressure) and the pressure established in Step 2
(production conduit flowing pressure at gas injection
depth) as a function of lift gas injection rate
constitutes the pressure drop required across the autogaslift control valve. Based on this relationship
between lift gas rate and pressure drop across the
control valve, the Cv profile for the control valve can
be established, Fig. 8, and the physical geometry of
the choke trim can be designed.
5. The process is repeated for the range of reservoir and
productivity parameters expected. Using the optimum
lift gas rates identified in Step 1, the corresponding
flowing bottom-hole pressures for the gas reservoir
are established. The best choke Cv profile which
satisfies the majority of production scenarios and
offers good lift gas control over the range is selected.
Based on well data and choke modeling an equal
percentage type choke was selected for this application.
Figure 9 shows the performance of an equal percentage type
in comparison to the other designs. The ICV in combination
with the Accu-Pulse choking system will provide 11 choke
settings with a flow capability of 0-20 MMscfd through
the choke.
The equal percentage type of choke trim is the best
solution for this type of application because it is well suited
for flow control applications where the entire system
(inflow – outflow) absorbs a large pressure drop as a
function of flow rate. In a reservoir/wellbore system, the
friction pressure drop through the permeable reservoir rock
surrounding the wellbore (inflow), and the friction pressure
drop in the production tubing to surface (outflow) absorb a
large percentage of the controlling pressure drop, hence the
equal percentage type of flow trim is the most applicable
for downhole flow control design.
The other benefit of this design is that it permits a “soft
start” of the lift gas addition, avoiding potential slugging
and inlet separator destabilization, and easing lift gas
optimization for variable well flow conditions.
The hydraulic control lines transmit the hydraulic pressure
necessary to manipulate and control the downhole ICV8.
There are two hydraulic lines connected to the open and
close side of the control valve. The lines are encapsulated in
wear resistant plastic as shown in Fig. 11 and securely
clamped to the outside of the production tubing.
I S O L AT I N G PA C K E R S
S U R FA C E H Y D R A U L I C S Y S T E M
Two HF-1 hydraulically set retrievable packers were used to
isolate the perforated interval of the Arab-D gas cap from the
Hanifa reservoir. The packer is designed for smartwell
applications and has the facility for bypass of electrical and
hydraulic control lines without the requirement for splicing.
The HF-1 packer can be used as both the top production
packer and as one of many lower packers isolating adjacent
zones8. Its design enables all tubing loads to be transmitted to
the casing and prevents movement of the production tubing
and control lines. The HF-1 packer is shown in Fig. 10.
The Surface Hydraulic System is a critical component of
any smartwell completion. The system cleans, pressurizes
and distributes the hydraulic control fluid required to
operate the downhole valve8. A typical hydraulic unit was
used to actuate the downhole ICV. It has a built-in
hydraulic pump and accumulator as well as all required
gauges on the inlet and outlet to monitor and operate the
ICV, Fig. 12.
Fig. 11. Hydraulic control lines encapsulated in wear resistant plastic.
HYDRAULIC CONTROL LINES
WELLHEAD OUTLETS REQUIREMENTS
A special modified tubing hanger and bonnet were used, Fig.
13. This tubing hanger and bonnet were equipped with feed-
Fig. 10. Control lines going through the HF-1 Packer.
Fig. 12. ICV Surface Hydraulic Control unit.
Fig. 14. Well performance before starting natural gas lift.
Fig. 13. Tubing hanger modifications.
through ports for the control lines in the smartwell completion
system and for the subsurface safety valve. The lines were
isolated outside the wellhead using needle valves. The surface
hydraulic panel was connected to the downhole lines to control
the downhole valves and subsurface safety valve.
SELECTION CRITERIA
In most cases, multiple options are evaluated to select the
candidate well. The concept of gas lifting the Hanifa with
the Arab-D gas cap was our primary goal. After evaluating
many options, AB-A was selected because it is located in the
middle of the south dome which has the gas cap on top of
the Arab-D reservoir. The well was drilled and completed as
a highly deviated open hole Hanifa producer in May 1998.
The well was drilled through the Arab-D gas cap, which
was isolated by a 7” liner. The well was put on production
in October 1998 and has been flowing at low bottom-hole
pressure since then. It was an intermittent producer because
it must be shut-in when its FBHP comes close to the bubble
point pressure. The rate of the well has been declining since
it was put on production in October 1998 even after the
stimulation treatment. The decline became more severe
when the well started producing water in September 1999.
well. Diagnostics conducted by the vendor found the control
line damaged below the wellhead. This does not affect the
functioning of the downhole valves and it is fully functional.
WELL PERFORMANCE
Figure 14 shows a plot of the production performance of
the well. The plot shows the rate the well has been declining
since it was put in production in October 1998. The well
was initially producing 4,000 barrels per day (BPD) dry oil
at 50/64” choke. That rate started declining shortly after
the initial production of the well and the well was still dry
at that time. This decline became more severe when the well
started producing water in September 1999. To compensate
for the sharp decline in rate, the choke was gradually
relaxed until it was fully opened in May 2001. The well
was shut-in several times to build up the pressure when the
pressure surveys showed that the well flowing bottom-hole
pressure was close to bubble point pressure. This behavior
continued even after the acid stimulation performed in April
2002 when its productivity index (PI) improved from 1.6
BPD/psi to 5.6 BPD/psi.
The well was worked over in December 2004 to install
the smart completion with natural gas lift. The ICV was
function tested after completion and was found functioning
properly.
The ICV was cycled several times successfully to all
WELL COMPLETION AND SYSTEM
DEPLOYMENT
A 40 ft section of gas cap was perforated in the Arab-D
during the workover to convert to gas lift smartwell. The
two packers straddle the gas cap and the downhole choke
valve was placed in the gas cap to control the gas rate
flowing into the 4½” production tubing. A permanent
monitoring system consisting of a Venturi flow meter and
downhole gauges were installed as part of the completion.
Though these were functional at the time of completion,
they were not working at the time of commissioning the
Fig. 15. Well performance after starting natural gas lift.
positions. After installing and commissioning the ICV
surface hydraulic control system, another function test for
the ICV was conducted and found satisfactory. When the
well tie-in work was completed, the well was unable to
flow. The ICV was opened to help unload the well and
bring it back to production. At ICV position 5, the well was
successfully unloaded and the initial oil production was at
3,700 BPD at 36% water cut on 68/64” choke. Long-term
production rates have averaged approximately 1,700 BPD
with 35% water cut on 43/64” choke. The rate was
optimized after several tests performed at different ICV
positions. During these tests FBHP was monitored to make
sure that the well is flowing at pressure higher than the
bubble point pressure. Production data in Fig. 15 shows
that the smart gas lift completion has enabled the well to
sustain production at higher water cut than before. Figure
15 is a chart showing Well A production using the natural
gas lift option from February 2005 to August 2006.
CONCLUSIONS
Natural gas lift has achieved the objectives to sustain
production from an intermittent well. The natural gas lift
application in Abqaiq Well A has demonstrated the
feasibility and benefit of using intelligent well technology. In
particular, the project has shown that surface controlled
downhole variable flow control valves are beneficial for
control of the gas source zone in applications where there is
a high degree of uncertainty for the production performance
of the oil and gas zones.
ACKNOWLEDGEMENT
The authors would like to thank the management of Saudi
Aramco and WellDynamics for their permission to publish
this paper.
FBHP
Cv
ESP
ICV
BPD
GOR
PDHMS
MMscfd
Flowing Bottom-Hole Pressure
Coefficient of Variation
Electric Submersible Pump
Interval Control Valve
Barrels Per Day
Gas Oil Ratio
Permanent Downhole Monitoring System
Million standard cubic feet per day
REFERENCES
1. Grover Jr., G.A.: “Abqaiq Hanifa Reservoir: Geologic
Attributes Controlling Hydrocarbon Production and
Water Injection,” SPE paper 20607, presented at the SPE
Middle East Oil Technical Conference and Exhibition
held in Bahrain, April 3-6, 1993.
2. Al-Garni, S.A., et al.: “Optimizing Production/Injection
and Accelerating Recovery of Mature Field through
Fracture Simulation Model,” IPTC paper 10433,
presented at the International Petroleum Technology
Conference held in Doha, Qatar, November 21-23,
2005.
3. Kumar, A., Telang, J.K. and De, S.K.: “Innovative
Techniques to Maintain Production from a Problematic
Indian Offshore Field – A Case History,” presented at
the 1999 SPE Latin American and Caribbean Petroleum
Engineering Conference, Caracas, Venezuela, April 2123, 1999.
4. Glandt, C.A.: “Reservoir Aspects of SmartWells,” SPE
paper 81107, presented at the SPE Latin American and
Caribbean Petroleum Engineering Conference, Port-ofSpain, Trinidad, April 27-30, 2003.
5. Betancourt, S., Dahlberg, K., Hovde, O. and Jalali, Y.:
“Natural Gas-Lift: Theory and Practice,” SPE paper
74391 presented at the SPE International Petroleum
Conference and Exhibition, Villahermosa, Mexico,
February 10-12, 2002.
6. Jin, L., Sommerauer, G., Abdul-Rahman, S. and Yong,
Y.C.: “Smart Completion Design with Internal Gas
Lifting Proven Economical for an Oil Development
Project,” SPE paper 92891, presented at the 2005 Asia
Pacific Oil & Gas Conference and Exhibition, Jakarta,
Indonesia, April 5-7, 2005.
7. Konopczynski, M.R. and Ajayi, A.: “Design of
Intelligent Well Downhole Valves for Adjustable Flow
Control,” SPE paper 90664, presented at SPE ATCE
2004, Houston, Texas, September 26-29, 2004.
8. WellDynamics library: “Library_section/pdfs/smartwell
systems,” via (http://www.welldynamics.com).
S I M E T R I C C O N V E R S I O N FA C T O R S
ft x 3.048* E-01
psi x 6.894757 E+00
bbl/d x 1.589873 E-01
in x 2.54* E+01
* Conversion factor is exact
m
kPa
m3/d
mm
Shaft Misalignment and
Vibration - A Model
Dr. Irvin Redmond
Dr. Irvin Redmond re-joined Saudi Aramco in 1998 and
is currently an Engineering Specialist in the Rotating
Equipment Division of Consulting Services Department.
Irvin completed his B.Sc. (with honors) in 1974 and
M.Sc. in Mechanical Engineering in 1981 at Strathclyde
University, Glasgow, later returning to obtain a Ph.D. in
Vibration Control of Rotating Machinery in 1985. Before
joining Saudi Aramco, he worked extensively in the
design, development and troubleshooting of a variety of
rotating equipment. Dr. Redmond has published a
number of technical papers and presented at international
conferences in the field of machinery vibration. He is a
Chartered Engineer (UK) and a corporate member of the
Institution of Mechanical Engineers.
ABSTRACT
Misalignment of coupled rotating machinery shafts is a frequently occurring problem
which can have a substantial influence on equipment reliability. Experience has
shown that diagnosis of misalignment through vibration analysis can be extremely
difficult due in large part to the observed substantial variability in the character of
machinery vibration even when apparently identical alignment states exist.
This article presents the results of a theoretical study on a simple linear
rotordynamic model, capable of simulating the effects of parallel and angular
misalignment across a flexible-element coupling connecting drive and driven rotors.
In contrast to other works the complex system forces and motions are derived by
application of the Lagrange Method without the imposition of specific harmonicexcitation assumptions. The model results confirm that a system having purely linear
properties when subjected to parallel misalignment can exhibit complex multiharmonic vibration response. Support stiffness anisotropy is shown to be an
important parameter in determining the presence and level of first (1X) and secondharmonic (2X) vibration response. Coupling of the lateral-torsional motions is
demonstrated as being key to the production of multi-harmonic system response.
The results provide significant insight into some of the major controlling elements of
the vibration-misalignment relationship in a linear system.
a, b
Shaft dimensions
c
Load torque constant
Cx, Cy,
Ct, Cz
Damping constants (x and y lateral, torsional
and axial)
ft, fz
Dimensionless frequencies (torsional and axial)
g
Gravitational constant
h
Dimension defining mass/inertia location on
shaft
I1, I2
Rotor Polar Moments of Inertia
k1
kx, ky, kt
kz, kc
Dimensionless support stiffness ratio (= kx/ky)
Stiffness constants (x and y lateral and
coupling torsional, axial and angular)
L
Shaft Length
m
r1, r2
t
Ti, TL
Rotor mass
Rotor radii of gyration
Time Time
Input Torque, Load Torque
X1, X2,
Y1, Y2
Shaft linear displacements at bearings 1 and 2
on rotor 2
z
Axial displacement
α
αo
Shaft angular displacement about x axis
Angular misalignment about x’-axis
Shaft angular displacement about y-axis
Angular misalignment about y’-axis
β
βo
δ
ζx, ζy,
ζz, ζt,
Shaft Parallel offset (misalignment)
Damping Ratios (x and y lateral, axial and
torsional)
ψ
φ
θ
Rotor 1 rotational displacement
Rotor 2 rotational displacement
Parallel misalignment reference angle
ωnT,
ωnY,
ωnZ
Natural Frequencies – Torsional, y-Lateral
& Axial
INTRODUCTION
Shaft misalignment has major implications for modern day
rotating equipment reliability. Although effective alignment
techniques have been applied successfully on a wide range
of equipment for some time, deterioration of the alignment
state can frequently occur due to, for example, changes in
equipment operating conditions, foundation settlement and
piping strain1. This situation can lead to the imposition of
excessive forces on the equipment rotating and static
elements, most commonly resulting in bearing or coupling
failure. In extreme circumstances contact between rotating
and stationary components can be expected to occur.
The presence of shaft misalignment can greatly influence
machinery vibration response2. It’s detection through
vibration diagnostics is not a straightforward matter due to
the lack of a clear understanding of the physical mechanism
relating shaft misalignment to vibration. Published work in
this area is extremely limited. For instance, frequent
reference is made to the appearance of a second-harmonic
(2X) vibration component as a possible indication of shaft
misalignment, though there does not appear to be any
definitive work demonstrating analytically how or when
this phenomenon would be expected to occur. Dewell and
Mitchell3 investigated the vibration spectrums produced by
a misaligned flexible disk coupling and showed that (2X)
and (4X) frequency components could be used to detect the
presence of misalignment. Jackson4 described the emergence
of a (2X) vibration component resulting from the nonlinear
properties of oil-film bearings when preloaded due to
misalignment forces. Simon5 modeled misalignment in a
large turbo-machinery and computed the vibration response
based on assumed values for the coupling reaction forces,
the form of which was not disclosed. Xu and Marangoni6, 7
studied, analytically and experimentally, the vibration
response of a misaligned motor-driven system. The coupling
was assumed to exhibit Hooke’s-joint characteristics,
thereby leading to even frequency shaft speed fluctuations
resulting in (2X) rotor response. Sekhar et al.8 and
Arumugam et al.9 predicted multi-harmonic response from
rotordynamic systems subjected to angular and parallel
misalignment by assuming coupling transmitted forces to be
represented by a half-sinusoid function having fundamental
frequency equal to twice the rotational speed. Prabhakar10
applied the same coupling force assumptions and
investigated the transient response of a misaligned rotor
system. They reported success in identifying the presence of
coupling misalignment through the application of wavelet
techniques.
Redmond and Hussain11 analyzed the vibration resulting
from a simple linear rotor model on isotropic supports and
showed the dominant response to be similar to that
resulting from a shaft bow. The predicted vibration
response did not contain any second-harmonic content.
Hussain and Redmond12 extended the model to include
torsional flexibility and demonstrated the influence of
lateral-torsional coupling. Shaft lateral response was shown
to occur at frequencies corresponding to shaft running
speed and torsional natural frequency. No double frequency
response was observed. It is clear from the literature that
the relationship between shaft misalignment and machinery
vibration is still not fully understood. There is a real need
for a simple mathematical misalignment model which
would exhibit the basic characteristics of real rotordynamic
Fig. 1. Flexible Element Coupling a) Schematic, and b) Coupling model.
systems and thereby enable investigation of this common
but complex phenomenon. This article presents such a
model and investigates the influence of a number of system
parameters on the vibration response resulting from
misalignment.
MISALIGNMENT MODEL
Model Requirements
In this article, the main objective is to produce a model
which helps explain the complex misalignment-vibration
relationship in rotordynamic systems. More specifically, the
model is intended to address the mystery of the source of
(2X) vibration, commonly cited as proof of misalignment in
rotating equipment. To gain an understanding of this
unexplained phenomenon it is important that the selected
model be simple in nature to aid in transparency. As a first
step towards this, the system dynamic motions should
preferably be derived without recourse to assumptions of
component (e.g., coupling) nonlinear behavior. With this in
mind, the study presented within is confined to that of a
rotor system having purely linear properties. Only shaft
misalignment is considered and other excitation sources
such as mechanical unbalance are not considered at this
stage. Additionally, axi-symmetry is assumed throughout
the rotating elements.
Coupling Model
The coupling model employed here was selected to reflect
the characteristics commonly attributed to flexible element
couplings, namely radial-rigidity and angular, axial and
torsional flexibility.
The coupling has one articulation point, Fig. 1a. The
shaft ends are considered to be connected by a frictionless
pinned-joint across which a linear rotational spring, kc,
exerts a moment proportional to the relative angular
displacement at the coupling, Fig. 1b. Since axi-symmetry is
assumed, then kc is a constant. The coupling allows for
relative axial and torsional motions of the shafts through
the respective stiffnesses kz and kt. Corresponding axial and
torsional damping is provided by the coefficients Cz and Ct.
Fig. 2. a) Double-rotor misalignment model, and b) Coupling angular offset
schematic.
System Model
The model consists of two coupled rigid rotors as shown in
Fig. 2a. For simplicity, rotor 1, considered the drive rotor, is
restrained by rigid supports while rotor 2 is supported on
flexible damped supports having anisotropic properties. The
model has 5 degrees of freedom. The torsional displacements
of rotor 1 and rotor 2 are defined by ψ and ϕ respectively.
Variables α and β denote the rotational displacements of the
driven end of rotor 2 about the x’ and y’ axes, respectively,
while z represents the axial displacement of rotor 2.
The model is shown in Fig. 2a with parallel
misalignment, δ, greatly exaggerated for clarity purposes. In
these circumstances, the shaft system is initially in an
“unstressed state” before rotation begins. In contrast, when
angular misalignment α0 and β0 is present, rotor 2 supports
will be subjected to an induced preload even before rotation
– it’s value dependent upon the amount of misalignment
and the relative stiffnesses of the coupling and supports.
In the case where the shafts are aligned but coupling
halves are non-concentric with the shafts, the system
response can also be computed considering parallel
misalignment as presented within. When a coupling-half is
mounted on it’s shaft with an angular offset, τ, as in Fig.
2b, then the situation is quite different from conventional
shaft angular misalignment and needs to be accounted for
separately in the system equations. Therefore this angular
offset effect is included in the model equations presented
within.
(7)
Defining the following dimensionless parameters:
(8)
Where
(9)
The dimensionless system matrices become:
Dimensionless Mass matrix:
Derivation of Model Equations
The equations of motion for the coupled system are derived
from application of the Lagrange equations to the system
energy functions.
(10)
Energy Expressions
Dimensionless Damping matrix:
The system generalized coordinate is described by:
(1)
(11)
The system kinetic energy, T, can be written as:
Dimensionless Stiffness matrix:
(2)
The system potential energy, V, can be written as:
(12)
(3)
and the Dimensionless Force Vector is:
where the symbol (‘ ) denotes differentiation with respect to
time.
Nondimensional Equations of Motion
Upon substituting the kinetic and potential energy expressions
into Lagranges’s equation and introducing nonconservative
damping forces from work done considerations, the system
equations of motion may be obtained and nondimensionalized
by dividing through by mω2nyL 2 to give:
(13)
(4)
For clarity purposes, the system excitation force terms in
equation (13) have been separated into static and dynamic
components.
The system equations are clearly nonlinear and the model
degrees of freedom are both statically and dynamically
coupled. It is notable that parallel misalignment
dynamically couples the lateral and torsional system
motions (eqns. 10, 11 and 13) in addition to introducing
static “preload” forces (rows 1 and 2 of eqn. 13). In
contrast, angular misalignment alone provides only static
forcing of shaft lateral motions (rows 1 and 2 of eqn. 13).
Where the dimensionless system generalized displacement,
velocity and acceleration vectors are defined as follows:
(5)
(6)
More importantly, equation (13) very clearly shows that
parallel misalignment produces both first (1X) and second
(2X) harmonic torsional excitation forces. The magnitude
of the fundamental forcing term is proportional to the
support stiffness values while that of the double-frequency
term increases in proportion to the x–y support stiffness
anisotropy, k1. This is a very important feature as most real
rotor systems incorporate bearings whose stiffness increases
with increasing static loading. The equations already show
that the presence of misalignment leads to the imposition of
static bearing or support loading so it is clear that in such
systems increasing the misalignment would produce a
greater static preload thereby augmenting the bearingsupport anisotropy leading to further reinforcement of the
(2X) torsional excitation.
It is evident that the character of the resulting vibration
response, particularly in relation to the presence of (1X) and
(2X) components, will be dependent upon numerous system
parameters, not least the proximity of the system lateral,
torsional and axial natural frequencies to the system main
excitation frequencies. This probably explains the substantial
variability in observed vibration response in apparently
similarly aligned rotating machinery trains. This situation is
even more understandable when one takes into account the
other numerous potential sources of (1X) and (2X) vibration.
Finally, referring to equation (13), the introduction of
coupling angular offset results in lateral excitation of rotor
2 at a frequency corresponding to the fundamental
rotational frequency (1X).
Where
(16), (17)
Therefore, shaft angular misalignment produces only a
static displacement and system vibration does not occur.
Note that rotating-element asymmetry, which can be
present in some systems, has been ignored in this analysis.
Its presence, for example in a disc coupling3, would lead to
oscillatory system motions. The above equations are used to
create Figs. 3a and 3b. These Figures show the influence of
coupling angular stiffness and transmitted torque on rotor 2
displacement when isotropic supports are assumed (k1=1.0)
and α* is set to a realistic value of 0.1. It is seen that at low
coupling stiffness (kc*→ 0) the shafts tend to rotate at a
misalignment angle equal to the original misalignment (α0)
with minimum load transferred to the bearings, while for
high coupling stiffness (kc*→∝) the shafts rotate at a
reduced misalignment angle since the bearings become
preloaded to counter the increased coupling transferred
moment.
The Figures also demonstrate how increasing the
transmitted torque leads to a decrease in the misalignment
angle, Fig. 3a, in the y-z plane but induces misalignment of
the shafts in the orthogonal x-z plane, Fig. 3b, leading to an
increase in the bearing static loading.
A N A LY S I S
Shaft Angular Misalignment Only
The influence of angular misalignment is most easily
demonstrated by simplifying the system dimensionless
equations of motion (eqn. 4) through removal of terms
related to the model axial degree of freedom, z*. Then
consider rotor 2 mass to be concentrated at the right-hand
end of the shaft (h*=1.0) and eliminate parallel
misalignment (θ=0.; p=0) and coupling angular offset (τ=0)
effects. Only the equations related to α and β degrees of
freedom are coupled.
When these equations are combined and the shafts are
assumed to be initially angularly misaligned by an amount
α0 about the x-axis (β0=0) the resulting shaft angular
displacements α and β can be shown to be time-invariant
and are determined from:
(14), (15)
Fig. 3. Influence of Coupling Stiffness, and Transmitted Torque, a)
b)
v’s TL*.
v’s TL* ;
Fig. 4a. β vs. rotor 2 speed.
Fig. 4c. Axial displacement frequency response.
Fig. 4b. Rotor 2 displacement orbits.
Fig. 4d. Support/Coupling load frequency response.
Interestingly, the torque-induced β displacement is seen to
have zero value at zero transmitted torque, TL*and low
values at high torque, but reaches a peak at some
intermediate torque value, in this case at TL*=1. It is
important to note that the introduction of these static
displacements will also lead to the creation of alternating
stresses in the rotating elements.
(h* =0.55). The shaft support configuration remains as
defined above in section 3.1.1 (i.e., a* = 0.1) and gravity,
shaft angular and shaft parallel misalignment effects are
ignored (g* = 0; α0 = 0; β0 = 0; p = 0; θ=0). The
dimensionless drive torque, Ti* is assumed constant at 5.0e5 and the related load torque, TL* is defined by the
square-law relationship TL*= c.φ’*2 where c = 2.22e-5, so
as to provide a nominal rotor 2 dimensionless final running
speed of φ’*=1.5. The dimensionless critical speed in line
with the y-axis, of course, occurs at a frequency
corresponding to φ’*=1.0. System damping parameters are
selected as ζx = ζy = .03; ζz = .01; ζT = .002.
Dimensionless coupling stiffness, kc* = 0.1. The
dimensionless axial and torsional natural frequencies were
chosen as fz = 0.1 and ft = 1.0, respectively. Figures 4a, 4b, 4c
and 4d shows the computed system responses for a range of
Angular Offset Coupling
Considering the case where the coupling is angularly
skewed on the shaft, Fig. 2b, the dimensionless equations of
motion (eqn. 4) are solved numerically using a 4th order
Runge-Kutte algorithm to determine the system transient
and steady-state response. The dimensionless time step is set
at Δt*=.03. For simplicity, the drive rotor inertia is
considered large (r1 = 0.1) compared to the driven rotor (r2
= .01). Rotor 2 mass is assumed to be located at center span
Fig. 5a. Rotor speed transient at startup.
Fig. 5b. System transient torques at startup.
support anisotropy values, k1 = 1.0 to 4.0, when the coupling
skew angle is set at τ = 0.003. In Fig. 4a the β transient
response is presented from startup to full speed. The rotor
angular response β occurs at rotor rotational frequency (1X).
The critical speed in the x-direction increases with increasing
anisotropy parameter k1. The resulting full speed shaft
synchronous displacement orbits (at RH support) are shown
in Fig. 4b. The orbits become elliptical when support
anisotropy is present, i.e., when k1 ≠ 1.0.
When support anisotropy is present, it is seen that shaft
axial motion is also induced, Fig. 4c. In this case the
frequency of vibration corresponds to (2X) rotor rotational
frequency. The vibration is relatively small and results from
the axial inertia forces produced by small axial
displacements linked to rigid-body shaft rotation.
Figure 4d shows the frequency character of the
dimensionless moment loads experienced by the coupling
and rotor 2 flexible supports. The support loads are seen to
Fig. 5c. Steady-state rotor speed spectrum.
Fig. 5d. Rotor steady-state displacement plots.
occur at (1X) shaft rotational frequency. The
nondimensional support load, Mβ*, which occurs in the
direction of the x-axis increases with increasing support
anisotropy while the corresponding orthogonal support load,
Mα*, is not a function of support anisotropy owing to the
definition of k1. Referring to the coupling dimensionless
load, Mc* frequency spectrum, Fig. 4d, it is interesting to
note that when support anisotropy is present the rotating
components experience alternating loading at a frequency
corresponding to (2X) shaft rotational frequency while for
isotropic supports only steady loading is experienced by the
rotating elements.
Shaft Parallel Misalignment Only
The case of parallel misalignment is addressed by analyzing
the model described above for different support anisotropy,
coupling stiffness and misalignment values, through
numerical analysis of equation (4). Figures 5a and 5b show
the transient plots of rotor speed and transmitted torque
Fig. 5e. Steady-state Y2 displacement spectrum.
Fig. 5g. Steady-state axial displacement.
Fig. 5f. Steady-state X2 displacement spectrum.
Fig. 5h. Steady-state support/Cplg forces.
during startup when a steady drive torque, Ti* = 5.e-5, is
applied and isotropic supports are assumed. The parallel
misalignment parameter p is set at .003 and the
dimensionless steady-state rotor speed is chosen as φ’ = 0.5.
The fluctuation in steady-state rotor speed resulting from
parallel misalignment is evident in Fig. 5a. The system is
subjected to an alternating “resistance torque,” Tr* (Fig.
5b) emanating from the parallel offset. This dynamic torque
is balanced, at full speed, by the fluctuating load torque
TL*. These fluctuations are seen to occur at a frequency
corresponding to rotor speed and it’s harmonics, Fig. 5c. Of
particular interest is the presence of a significant secondharmonic response component. This is to be expected since
any (2X) torsional excitation will coincide with the
torsional and y-lateral natural frequencies. It is seen that
increasing the support anisotropy (i.e., increasing k1) has a
marked effect in increasing the magnitude of the (2X) speed
oscillation, due to the proximity of (2X) excitation.
The dimensionless rotor displacements, X2 and Y2, are
computed at the right hand supports of rotor 2 for a range
of support anisotropy values and the results are presented in
Fig. 5d. Circular shaft orbit occurs when the supports have
equal stiffness along the x and y axes. The orbit centers, of
course, do not coincide with the axes origin but take up a
position between this point and the initial offset point
thereby leading to static loading of the supports and
coupling. This is particularly true when the support stiffness
in the x-direction is increased (k1 > 1) where it is evident
that the shaft is then forced to take up a static position
closer to the x-y origin and further from it’s initial position.
In addition, the shaft displacement orbits become less
circular and more distorted as the x-y support stiffnesses
diverge. The influence of support anisotropy on the spectral
content of the shaft displacement responses X2 and Y2 is
demonstrated in Figs. 5e and 5f, respectively. Shaft
displacement response along the y-axis, Y2, occurs at the
fundamental rotor frequency and second-harmonic and is
generally increased with increasing support anisotropy, Fig.
5e. In contrast, displacement X2 also exhibits (3X) response
and, as expected, all frequency components reduce in
magnitude with increasing x-direction support stiffness.
The frequency content of rotor 2 axial vibration response
is displayed in Fig. 5g where it can be seen that, as with the
other model coordinates, axial response is dominated by
fundamental frequency activity along with significant
double-frequency response. All frequency components are
observed to be increased in magnitude when support
anisotropy is augmented. A similar situation exists in
relation to the dynamic support (or bearing) and coupling
forces, Fig. 5h. The support dynamic forces in a direction in
line with the misalignment plane also show a (3X) frequency
component in addition to (1X) and (2X) frequency
responses, at increased k1 values. The coupling experiences
only (1X) dynamic forcing when isotropic supports are
employed. When support anisotropy is introduced (2X),
(3X) and (4X) components are observed to emerge.
Increasing the parallel offset, p, has the effect of increasing
the (1X) and (2X) vibration components as clearly shown in
Fig. 6a and Fig. 6b, where k1 is set at 3. The increased offset
produces a larger alternating resistance torque consisting
mainly of (1X) and (2X) components, as observed in the
steady-state speed waveform shown in Fig. 6c.
This torsional excitation couples through to the lateral
shaft motions to produce the distorted shaft displacement
motion highlighted in Fig. 6d.
The influence of dimensionless coupling angular stiffness,
kc, in the presence of shaft parallel misalignment is clearly
demonstrated in Figs. 7a and 7b. In this case, the support
anisotropy parameter k1 = 3, parallel offset, p =.003 and all
Fig. 6a. Steady-state α v β plots.
Fig. 6c. Shaft Speed vs. Time (k1 = 3.).
Fig. 6b. Shaft angular response, α and β.
Fig. 6d. Rotor steady-state displacement plots.
CONCLUSIONS
Fig. 7a. Shaft Speed vs. Time (k1 = 3).
Fig. 7b. Rotor steady-state displacement plots.
other parameters are as before. As would be expected, the
rotor 2 displacements increase with increasing coupling
stiffness. Referring to Fig. 7a, at low coupling stiffness
values the shaft response is governed more by the support
stiffness due to the enhanced coupling flexibility.
This situation reverses as the coupling stiffness increases
leading to increased transfer of the initial misalignment
across the coupling. In these circumstances Fig. 7b shows
the X2 shaft displacement response to be dominated by
(1X) vibration along with significant (2X) and (3X)
components. All of the frequency components are increased
by increasing coupling stiffness.
In the preceding parallel misalignment analysis the
important system parameters, ft = 1.0 and φ’* = .05, were
deliberately selected with a view to focusing on the
emergence of system (2X) vibration response. More work
will therefore be necessary to investigate system response
for a wider range of controlling parameters.
A simple five degree-of-freedom linear rotor-system model,
consisting of two flexibly-coupled rigid rotors, is presented
to enable assessment of the relationship between shaft
vibration and misalignment. The model is selected to
display some of the important characteristics of present-day
rotating machinery. Anisotropic flexible-damped supports
and coupling torsional and axial flexibility are considered
and the impact of shaft angular and parallel misalignment
investigated.
The resulting system coupled nondimensionalized
equations of motion are shown to be nonlinear in nature.
The individual lateral, axial and torsional responses are
coupled and the relative response magnitudes will depend
upon the degree of coupling and the proximity of the
excitation frequencies with the system natural frequencies.
The equations provide insight to the situation where only
shaft angular misalignment is present and, surprisingly,
demonstrate that in these circumstances system vibration
does not occur. The resulting static displacements lead to
static loading of the supports and dynamic loading of the
rotating elements.
The presence of coupling skew, or rotating angular
misalignment, leads to the introduction of an angular
displacement-forcing function at a frequency corresponding
to the rotor speed.
The system equations show clearly that parallel
misalignment introduces a static displacement in addition to
fundamental-frequency (1X) lateral and torsional excitation
components. A discrete second-harmonic (2X) torsional
excitation term is also evident in the system force vector.
The magnitude of this term is directly proportional to the
support anisotropy and disappears for isotropic supports.
The above effects are demonstrated through numerical
analysis of the equations of motion for a range of model
parameters where it is confirmed that:
• Both angular and parallel misalignment introduce a
static loading, or preload, to the system.
• Angular misalignment alone produces only static
system displacements, in the absence of rotor and
coupling asymmetry. The introduction of transmitted
torque reduces the shaft misalignment angle leading to
greater imposed static forces.
• The presence of an angularly skewed coupling
produces (1X) shaft lateral response when isotropic
supports are employed. The introduction of support
anisotropy leads to (2X) shaft axial response and (2X)
loading of the rotating elements.
• Parallel misalignment alone produces both static and
dynamic, multi-harmonic (i.e., 1X, 2X and 3X) system
responses. The presence of parallel offset introduces
torsional response occurring mainly at fundamental
and second-harmonic frequencies. The resulting speed
oscillations couple through to the system lateral
motions and produce multi-frequency support and
rotating element forces. Parallel misalignment also
induces shaft axial motion which is dominated by (1X)
and (2X) response. Support anisotropy plays a major
role in determining system dynamic response, with
greater divergence of support orthogonal stiffness
values leading to increased dynamic response.
Increasing the parallel offset results in an increase of
the (1X) and (2X) system dynamic response. The
coupling stiffness is very influential in controlling the
system response, as would be expected, so that a
reduction in this parameter leads to reduced dynamic
response, for a given parallel offset.
As far as the author is aware there is nothing in the
literature outlining the relationship between shaft
misalignment and rotor vibration as demonstrated in this
paper, particularly with respect to the importance of
support anisotropy and lateral-torsional coupling in
producing parallel misalignment related (2X) vibration and
the inability of angular misalignment alone to produce shaft
vibration.
The model described within has already been developed
to enable investigation of interaction of shaft misalignment
with mechanical unbalance, nonlinear supports and rotating
element asymmetry. Work is currently underway to expand
the current investigations to assess the influence of these
other “real world” rotordynamic influences.
ACKNOWLEDGEMENTS
The author acknowledges the support of Saudi Aramco,
Saudi Arabia.
REFERENCES
1. Piotrowski, J.: “Shaft Alignment Handbook,” Marcel
Dekker Inc., New York, 2nd Ed., 1995.
2. Piotrowski, J.: “Why Shaft Misalignment Continues to
Befuddle and Undermine Even the Best CBM and ProActive Maintenance Programs,” Proc. of the Predictive
Maintenance Technology National Conference,
Indianapolis, Indiana, 5:18-23, December 3-6, 1996.
4. Jackson, C.: “Considerations in Hot and Cold Alignment
and Couplings,” Proc. 7th Intl. Pump Users Symposium,
Texas A&M University, Texas, 1990, pp. 27-38.
5. Simon, G.: “Prediction of Vibration Behavior of Large
Turbo-Machinery on Elastic Foundations Due to
Unbalance and Coupling Misalignment,” Proc. Instn
Mech Engrs, ImechE, Vol. 206, pp. 29-39, 1992.
6. Xu, M. and Marangoni, R.D.: “Vibration Analysis of a
Motor-Flexible Coupling-Rotor System Subject to
Misalignment and Unbalance, Part I: Theoretical Model
and Analysis,” Journal of Sound and Vibration, Vol.
176(5), pp. 663-679, 1994.
7. Xu, M. and Marangoni, R.D.: “Vibration Analysis of a
Motor-Flexible Coupling-Rotor System Subject to
Misalignment and Unbalance, Part II: Experimental
Validation,” Journal of Sound and Vibration, Vol.
176(5), pp. 663-691, 1994.
8. Sekhar, A.S. and Prabhu, B.S.: “Effects of Coupling
Misalignment on Vibrations of Rotating Machinery,”
Journal of Sound and Vibration, Vol. 185(4), pp. 655671, 1995.
9. Arumugam, S., Swarnamani, S. and Prabhu, B.S.:
“Effects of Coupling Misalignment on the Vibration
Characteristics of a Two Stage Turbine Rotor,” ASME
Design Engineering Technical Conference, Vol. 3, Part B,
1995.
10. Prabhakar, S., Sekhar, A.S. and Mohanty, A.R.:
“Vibration Analysis of a Misaligned Rotor-Coupling
Bearing System Passing Through the Critical Speed,”
Proc. Instn. Mech. Engrs., Vol. 215, Part C, 2001.
11. Redmond, I. and Hussain, K.M.: “Misalignment as a
Source of Vibration in Rotating Shaft Systems,” Proc.
Intl. Model Analysis Conf. (IMAC) XIX, Orlando,
Florida, February 2001.
12. Hussain, K.M. and Redmond, I.: “Dynamic Response
of Two Rotors Connected by Rigid Type Mechanical
Coupling with Parallel Misalignment,” Journal of
Sound and Vibration, Vol. 249(3), pp. 483-498, 2002.
3. Dewell, D.L. and Mitchell, L.D.: “Detection of a
Misaligned Disk Coupling Using Spectrum Analysis,”
Trans. ASME, Journal of Vibration, Acoustics, Stress and
Reliability in Design, Vol. 106, pp. 9-18, January 1984.
New Coating Generations
Offer Effective Solutions for
Rehabilitation of Buried
Pipelines
Dr. Moufaq I. Jafar
Dr. Fikry F. Barouky
Faisal M. Melibari
Dr. Moufaq I. Jafar is a Corrosion Specialist in Saudi
Aramco’s Research and Development Center in Dhahran.
He is an expert in coatings, cathodic protection and
corrosion monitoring. Dr. Jafar has a Ph.D. in Corrosion
Science and Engineering from the University of Manchester
Institute of Science and Technology, Manchester, UK. He
has written over 30 technical papers in the field of
corrosion. Dr. Jafar is a Chartered Engineer (UK), a
Professional Member of the Institute of Corrosion (UK), a
Professional Member of the Institute of Materials, Minerals
and Mining (UK), and a Member of the National
Association of Corrosion Engineers (NACE, USA). He has
served as Vice-chairman and Chairman of NACE, Saudi
Arabian Section.
Dr. Fikry F. Barouky is an Engineering Specialist in
Saudi Aramco’s Consulting Services Department in
Dhahran. He is the Chairman of Saudi Aramco Engineering
Standards Committee for Paints & Coatings. Dr. Barouky
has more than 33 years experience in the materials selection
and corrosion control in the oil and gas industry, power
generation, water desalination, and mining. He received a
Ph.D. in Materials Engineering & Corrosion Science from
Murdoch University, Australia.
Faisal M. Melibari is a Laboratory Technical Specialist in
Saudi Aramco’s Research and Development Center in
Dhahran. He has 15 years of experience in the field of
corrosion and non-metallic materials. Faisal has a B.Sc. in
Chemistry from Surrey University, Guildford, UK. He has
been involved with numerous technical projects in the
field of coatings/non-metallic materials.
Dr. Barouky has written 36 technical papers in the field of
protective coatings and corrosion. He is an active member
of several professional and engineering associations, such as
NACE, SSPC, ACA, Institute of Corrosion and the Institute
of Materials.
Coating
Thickness
Color
System #1
2.6 mm
Light Synthetic polyolefin with
green
PVC wrapping band
System #2
2.0 mm
Black
Rubberized bitumen
with geotextile fabric
Black
A two-component
elastomeric system of
polymer modified
bitumen
ABS T R AC T
System #3
1.6 mm
Description
Saudi Aramco operates thousands of kilometers of buried
pipelines, which require external corrosion protection,
particularly in high water table areas known as “subkha”
(salty) ground. Protective coatings have been the most costeffective passive corrosion control method utilized for the
last five decades as the first line of defense against
corrosion. The use of liquid coatings on new pipelines has
not been successful compared to fusion bonded epoxy (FBE)
in subkha ground. Also, for rehabilitation of buried
pipelines, achieving good surface preparation is still one of
the main factors, which causes premature failures of liquid
coatings. A few years ago, Saudi Aramco started
investigating alternative coating systems that are surface
tolerant and having reliable chemical and mechanical
properties for the external protection of pipelines in subkha
ground. Visco-elastic coatings from different generic
materials have been tested, qualified and successfully used
as stand-alone coatings for external protection of buried
pipelines.
This article presents the results obtained from laboratory
and field testing of three new coating systems. One coating
system has been used in the field for 7 years without
problems, whereas the other coating systems have been
applied in the field for 1 year and are still being evaluated.
Key words: corrosion, visco-elastic coatings, subkha,
pipelines.
Recently two more coatings (systems #2 and #3) were
successfully evaluated in the laboratory and currently being
evaluated in the field. Visco-elastic coatings are non-curable
coatings with self-recovering characteristics. This type of
coating adheres to the steel substrate, with little surface
preparation and allows cold application on under and
above ground facilities. There is no need for priming or
high surface preparation (such as grit blasting to near-white
finish), but the surface must be free of grease, dirt and loose
materials. Coating system #1 comprise of the visco-elastic
coating and a black PVC wrapping band. The corrosion
protection is provided by the “paste” coating, whereas the
PVC wrap is designed to apply pressure on the coating to
enhance its adhesion to the steel substrate and to protect it
from soil stresses.
The two recently evaluated coating systems #2 and #3
are of a different generic type to coating system #1, Table 1.
The two coatings have some properties, which are similar to
those of system #1. These properties include self-recovery,
visco-elasticity and the need for little surface preparation.
All the coatings can be applied manually or with a
wrapping machine.
INTRODUCTION
TEST PROGRAM
Saudi Aramco operates thousands of kilometers of buried
pipelines, which require external corrosion protection,
particularly in subkha ground. The use of liquid epoxy
coatings has not been successful in subkha ground compared
to FBE coatings. Also, for rehabilitation of buried pipelines,
good surface preparation is required and this is costly and
time consuming. Therefore, there is a need for coatings,
which require little surface preparation. Saudi Aramco has
been investigating alternative coating systems for the
external protection of buried pipelines in subkha ground. A
few years ago, Saudi Aramco identified one visco-elastic
coating (system #1), which has been used for the external
protection of pipelines buried in subkha ground.
Table 1. Details of the coating systems
Holiday Detection
A sample of each coating system was placed on a steel panel
and tested in accordance with ASTM G62 to establish the
presence of holidays, using a holiday detector (model
Elcometer 236 Holiday Detector). The tests, which were
carried out at 3,000 volts, showed no holidays in the
coatings.
Impact Resistance
Impact resistance tests were carried out on the coatings to
check the self-recovering characteristics of the coatings. The
tests were performed at two different energy levels of 5 and
10 Joules, at room temperature (~ 23 °C). After testing, the
Coating
5 Joules
(Self-recovery)
10 Joules
(Self-recovery)
System #1
Pass (good)
Pass (good)
System #2
Pass (good)
Pass (good)
System #3
Pass (v. good)
Pass (good)
Table 2. Impact resistance tests and self-recovery
Coating
Self-recovery/Elasticity
System #1
Good
System #2
Good
System #3
Very Good
Fig. 1. Temperature limitation test.
Table 3. Self-recovery/elasticity properties of the coatings
impact areas (dents) were visually examined for damage
and tested using a low voltage (90 Volt) holiday tester. The
three coating systems passed the impact test at 5 Joules and
exhibited good to very good self-recovery of the impact area
(dent disappeared). Each coating was subjected to holiday
testing, and the results were all negative (no holidays in the
coatings). At 10 Joules, the three coating systems passed the
impact resistance test and exhibited good self-recovery. In
all cases, coating system #3 exhibited the quickest recovery,
whereas coating system #2 exhibited the slowest recovery,
which may be due to the presence of the geotextile fabric on
the back of the coating. The results of impact resistance
tests are shown in Table 2.
In addition to the observation of the coatings behavior
after impact resistance testing, a small square sample of each
coating system was pulled from one corner and released to
check its self-recovery/elasticity. The coatings exhibited a
good level of elasticity as summarized in Table 3. Coating
system #3 exhibited the best self-recovery/elasticity.
Chemical Resistance
Small samples (approximately 5 cm2) of the coating systems
were subjected to chemical resistance tests in acidic, neutral
and alkaline solutions. One sample of each coating was
immersed in each of the three solutions (initially pH 3, 7
and 10) at room temperature. The solutions were made up
with deionized water and the pH was adjusted using a
hydrochloric acid (HCl) solution to obtain pH 3, or a
sodium hydroxide (NaOH) solution to obtain pH 10. The
test cells were checked regularly for any change in the
coatings or solutions. After two weeks of immersion in the
test solutions, there was no change in the coating systems or
solution. The pH of the solutions was adjusted to pH 2, pH
7 and pH 12, and the test was continued for another five
months, during which there was no change in the coatings
or solutions.
The three coating systems exhibited good performance in
the three test solutions. The results suggest that the
coatings are chemically stable, which is desirable for longterm corrosion protection. Any coating, in which chemical
reactions take place, would not be stable and would change
its properties/corrosion resistance in the long-term.
Temperature Limitation
The coatings were subjected to temperature limitation tests
to obtain information on the thermal behavior of the
coating and to establish the maximum operating
temperature for each coating.
A sample of each coating system (approximately 5 cm x
8 cm) was placed on a steel panel and weighed before being
placed in an oven initially maintained at 60 °C. The panels
were placed against the wall of the ovens (approximately a
60° angle, Fig. 1) to see if sagging of the coating would take
place at the test temperature. The panels were exposed at
60 °C for 28 days, during which the coatings were
unaffected.
The test temperature was increased to 70 °C and
maintained at this temperature for 90 days (a total of 118
days or 2,832 hours exposure at the two temperatures) to
see the effect of higher temperature on the coatings. The test
panels were examined regularly for any sign of sagging or
increased stickiness/tackiness. At the end of the test period
the panels were visually examined and weighed to see if
Coating
At 60 °C
At 70 °C
% wt. Loss
System #1
No change
Increased tackiness
and stickiness
0.44
System #2
No change
Increased tackiness
and stickiness
0.18
System #3
No change
Increased tackiness
and stickiness
0.29
Table 4. Properties of coatings after heating to 60 °C and 70 °C
Coating
Initial
After 1
Month
After 4
Months
After 8 After 12
Months Months
System
1.75E+11 9.42E+10 7.52E+10 8.40E+10 6.62E+10
#1
System
1.35E+11 7.59E+10 9.70E+10 6.85E+10 6.72E+10
#2
System
1.64E+11 9.63E+10 5.47E+10 5.31E+10 3.26E+10
#3
Table 5. Electrochemical impedance results
Fig. 2. Electrochemical impedance test cell and equipment.
there has been any weight loss. At 70 °C the three coatings
showed some increase in tackiness and stickiness, but no
sign of sagging. The weight loss results from the coatings
were very low, Table 4. The weight loss may be due to loss
of moisture and light (a volatile) ingredient in the coatings.
Upon completion of the temperature limitation test, the
coatings were placed back in the ovens and the temperature
was increased to 80 °C for one week to establish the
maximum operating temperature for the coatings. The three
coatings exhibited increasing stickiness, tackiness and some
sagging.
In summary, the results demonstrated that the maximum
operating temperature for the coatings is 70 °C. Operating
the coatings at a higher temperature would adversely affect
their properties and performance.
after 1 month showed a slight reduction in the electrochemical impedance of the coatings, which may be
attributed to water uptake by the coatings. The reduction in
the electrochemical impedance was very slow with
increasing exposure time. The coatings continued to exhibit
high electrochemical impedance (>1E+10 Ohm-cm2).
Cathodic Disbondment
Cathodic disbondment tests were carried out on the
coatings to obtain information on the performance of the
coatings under cathodic protection condition. Coated
samples were exposed to the test solution (3% NaCl) after
making a 6 mm hole in each coating. A stainless steel tube
was used as the anode and a saturated calomel electrode
was used as a reference electrode. A Solartron 1480
multistat was used to polarize the coated panels to –1.5
Volts for a period of 30 days at room temperature.
Upon completion of the cathodic disbondment test, the
coated panels were subjected to visual examination to
establish the level of cathodic disbondment. The
examination showed that there was no disbondment of the
coatings around the hole, or undercreep corrosion. The
coatings were adherent to the steel substrate and it was
difficult to pull off the coatings from the steel substrate, Fig.
3. The high adhesion helped to prevent undercreep
corrosion and coating disbondment.
Field Trials
An important part of the evaluation of any coating system
in Saudi Aramco is field trials. Coating system #1 has been
applied to several sections of pipelines buried in subkha
ground with a high water table, Fig. 4. The coated sections
were excavated at different intervals and visually inspected
for any sign of coating degradation. Also, windows were
cut in the coating to inspect the steel substrate, Fig. 5. All
Electrochemical Impedance
A computer controlled EG&G Frequency Response
Analyzer (Model 1025) in conjunction with an EG&G
potentiostat/galvanostat (Model 283) were used to conduct
EIS measurements, Fig. 2. The test solution was sodium
chloride (3% by wt). The impedance results obtained from
EIS measurements are summarized in Table 5.
The results showed that the initial impedance for all the
coatings was very high (>1E+11 Ohm-cm2). The results
Fig. 3. Appearance of hole after cathodic disbondment and removal of coating
system #1.
Fig. 4. Excavation of coating system #1.
Fig. 7. Inspection of coating system #2.
Fig. 8. Coating system #3 before backfilling.
Fig. 6. Coating system #2 before backfilling.
the inspected coated pipelines were found to be in good
condition with no sign of degradation, such as change in
color or physical condition after 7 years of burial in subkha
ground. Coating system #1 is currently being used by Saudi
Aramco for coating pipelines operating at temperatures up
to 70 °C.
The two other coating systems (#2 and #3) were applied
last year to a pipeline buried in subkha ground, Figs. 6 to 9.
The coated sections were visually inspected after six
months, and windows were cut in the coatings to inspect
the surface of the pipe. The inspection of system #2 showed
that the coating was damaged at the bottom of the pipe
(around the 6 O’clock position), which led to water ingress
and corrosion of the pipe. The failure appeared to be due to
poor application of the coating in this area, where the
overlap of the coating was inadequate. There was no
corrosion on the pipe surface in other areas where windows
were cut in the coating. For coating system #3, the result of
the visual inspection was better. There was no damage of
the coating at the bottom or other areas of the pipe. There
was good adhesion between the coating and the pipe and
there was no corrosion on the pipe surface in areas where
the window was cut in the coating. The overlap areas were
intact. The field trial is still ongoing.
CONCLUSIONS
The results obtained from the test program have
demonstrated the following:
• The coatings are chemically stable and resistant to a wide
range of pH levels (2-12).
• The coatings have good self-recovering characteristics,
which is important if the coatings are subjected to
damage during installation or due to soil stresses.
• The coatings have excellent electrochemical impedance.
• The coatings have excellent cathodic disbondment
resistance.
• The coatings can be used for the corrosion protection of
pipelines operating at temperatures up to 70 °C.
ACKNOWLEDGEMENT
The authors acknowledge the support of Saudi Aramco and
the help provided by the staff of the R&D Center,
Consulting Service Department and Pipelines Department
during the course of this project.
Production Optimization
Through Utilization of
Innovative Technologies in an
Offshore Field Environment
Konstantinos I. Zormpalas
Khalid Al-Omaireen
Karam Sami Al-Yateem
Konstantinos I. Zormpalas joined Saudi Aramco in July
2006 and has been working with the Safaniya Production
Engineering Unit in NAPED. His focus on the Safaniya
field activities are in production monitoring, well testing,
the performance of wells equipped with Electric
Submersible Pumps (ESP) and a selection of candidate wells
for remedial work to enhance overall production. Prior to
joining Saudi Aramco, he was the Production Engineer of a
field in the Sahara desert in Algeria and worked throughout
the project from the commissioning phase of the Central
Processing Facility for oil and gas, to startup for the first oil
and to full field development. His background includes 15
years of broad production engineering experience in the oil
and gas industry with international postings in eight
countries and four continents.
Khalid Al-Omaireen is the General Supervisor for
Safaniya Production with diverse and deep involvements in
plant operation, plant maintenance, well services and field
services. In 1986, he received his B.S. degree in Petroleum
Engineering from the University of Southwestern
Louisiana, LA. During his career with Saudi Aramco, he
worked as a division head for different plant complexes
that include gas/oil separation, gas compression, seawater
distillation and oil stabilization facilities. In offshore fields,
he has a long experience supporting rig operations and
dealing with offshore barges/boats conducting different
surveillance activities with a focus on improving asset safety
and streamlining.
Karam Sami Al-Yateem graduated with a B.S. degree
in Petroleum Engineering with honors from King Fahd
University of Petroleum and Minerals (KFUPM), Saudi
Arabia in 2005. Karam started as a Production Engineer in
NAPED covering the Safaniya field. Since then he has gone
on several field assignments to various locations onshore
and offshore in the Tanajib area. Currently, Karam works
as a Reservoir Engineer in the Safaniya field for the
Northern Area Reservoir Management Department as a
part of the company’s Professional Development Program.
Author and co-author of several technical papers, Karam
has also worked with the Computational Modeling
Technology Team as a summer student in 2004.
ABSTRACT
Several innovative techniques and practices have been
recently implemented to improve well production
performance in offshore assets in the Arabian Gulf. The
challenges which followed past practices were identified and
intensive work was focused on enhancements to existing
well completions to increase well productivity and prevent
premature water or gas encroachment.
This article describes several innovative concepts
implemented in three major offshore fields in Saudi
Aramco. The methodologies of four technologies which
were tested and implemented in the recent years are
presented. These technologies are the practice of
sidetracking horizontal wells and completed with passive
inflow screens, the use of reservoir gas cap for artificial lift
of oil wells, the Tornado technique for sand fill clean out
and the chemical treatment of wells which endured
formation damage.
All these technologies proved to be successful and their
combined application added value to Saudi Aramco’s
operations. As a result, the production targets for 2006
were met and the positive results obtained from the
implementation of these technologies will lead to the
optimization and improvement of future operational
practices.
BACKGROUND
Saudi Aramco operates three major offshore fields in the
North part of the Arabian Gulf. Horizontal drilling in these
three fields dates back more than a decade. The company
has been prudent in evaluating the technology of drilling
and completing horizontal wells as it has progressed with
time; and constantly improving the designs of horizontal
completions to maximize reservoir recovery. As the number
of horizontal wells increase in the fields, the reservoir sweep
efficiency is improved with time and higher production
rates were accomplished on a per well basis when compared
Fig. 1. Typical sandstone reservoir log section.
Fig. 2. Example of advancement of the OWC.
to vertical producers.
The geology in one of the fields is rather complicated
with the existence of stringer sand bodies which are usually
separated from the main sand by an impermeable shale
break, Fig. 1. The stringer sands were deposited
uncontrollably in the subsurface and pose enormous
challenges in the well placement and deciding on the
direction of the wells when it comes to horizontal drilling.
The three major offshore fields were discovered in the
mid-fifties and have been on production since. Their
(OWC) moves upwards slowly with time due to the strong
aquifer drive in a piston-like movement until producing
zones are swept, Fig. 2. In some areas, the advancement of
the formation water towards the vicinity of the downhole
perforations has as a consequence the increase in water
production. The increasing water cut in the well affects
adversely the production of oil since the well has no longer
sufficient energy to produce naturally and it starts to
produce in an intermittent status.
Horizontal sidetracking is a solution to deal with
problematic wells in terms of their productivity, following a
rigorous and thorough evaluation to select the most
promising candidate wells that would yield the most
optimum results. By sidetracking intermittent wells utilizing
a workover rig in all three offshore fields, the average
production gain from the sidetracked wells in 2006 was 3
thousand barrels of oil per day (MBOPD) per well.
U S E O F PA S S I V E I N F L O W S C R E E N S I N
H O R I Z O N TA L W E L L C O M P L E T I O N S
Fig. 3. Nonuniform inflow profile in a horizontal well.
petrophysical properties are characterized by clean coarse
sands with very good permeability in the range of 3-5
darcies (D). The recovery mechanism is by natural water
drive and in some areas it is complemented by a gas cap
drive. The sandstone reservoirs have pressure support by a
strong water aquifer, which underlay the sand bodies.
In general, the most common type of downhole water
encroachment seen in Saudi Aramco’s offshore fields is
bottom water movement. In this case, the oil water contact
Fig. 4. Internal view of passive inflow screen device.
Saudi Aramco carried out internal appraisals of the
performance of horizontal completions. The evaluation of
production logging campaigns using Production Logging
Tools (PLT) indicated that the implementation of horizontal
wells in the offshore fields demonstrated an excellent sweep
performance of the reservoirs. The studies also identified
that in some horizontal producers, the flow was
predominantly coming from only certain perforations in the
horizontal section or even from a part of single perforated
intervals due to permeability variations or formation damage
during perforation operations. Figure 3 shows a flow profile
of the preferential entry of oil from perforated intervals in
the horizontal section of such a well. This nonuniform
profile often results to premature water breakthrough or gas
Fig. 5. Open hole mechanical packer shown in “Run in hole” position above and “Set” position below.
Fig. 6. Production performance from first candidate horizontal well equipped
with passive inflow screens.
Fig. 8. Inflow profile comparison between horizontal wells with and without
passive inflow screens.
Fig. 7. Even distribution of inflow from first candidate horizontal well
equipped with passive inflow screens.
coning, which directly influences the productivity of the well
and typically leads to its production decline.
Evaluation of new technologies led to the evolution of
the horizontal completion design with targets to achieve a
uniform inflow profile in the horizontal section which will
enhance well productivity and reservoir sweep. Saudi
Aramco introduced the open hole completion combined
with a stand alone premium screen with passive inflow
screens, or otherwise called inflow control devices (ICD).
The implementation of the passive inflow screen technology
in the horizontal section was to prolong well life by
avoiding an uneven flow as seen from the previous example,
thus delaying gas or water breakthrough in horizontal
wells. An additional advantage of the open hole completion
was the overall cost reduction of well drilling mainly due to
rig time savings.
The passive inflow screen system is supposed to
“equalize” the flow and even out the reservoir contribution
along the horizontal section of a well. The passive inflow
screens divert production from toe to heel through a spiral
channel in the horizontal section, Fig. 4. The horizontal
section can be divided in individual compartments with the
use of mechanical open hole packers, which could seal
washouts up to 2.5” higher than the run-in outer diameter
of pipe (OD) of the completion string, Fig. 5. The combined
use of mechanical open hole packers with passive inflow
screens prevents the initiation of an acute channel of gas
from the gas cap above or water from the water aquifer
below the oil rim.
The first pilot installation of the passive inflow system
was in the main sand (Khafji formation) in one of the three
offshore fields in December 2002. The performance of this
well equipped with passive inflow screens is shown in Fig.
Fig. 10. Completion design schematic for natural gas cap lift.
Fig. 9. Flow profile and performance plot of salvaged intermittent well.
6, where the well was put on production in February 2003
with an initial oil rate of 8 MBOPD and it sustained the
production rate with zero water cut until today. After the
installation of the passive inflow screens, a PLT was run
which confirmed the even distribution of inflow in the
horizontal wellbore, Fig. 7. The superiority of the
completion design equipped with passive inflow screens is
evident when this well is compared to two offset wells, also
horizontal producers completed prior to 2002 and without
passive inflow screens, with production rates of less than 5
MBOPD as opposed to 8 MBOPD of the first candidate
well with passive inflow screens, Fig. 8.
Several installations of passive inflow screens followed
the initial pilot run since 2002. As of the end of 2006, there
were 87 passive inflow screen completions in the three
offshore fields. During the 4 years since the first
implementation of the passive inflow screens, the horizontal
wells equipped with this completion design when put on
production, demonstrated an increase between 2-4 MBOPD
compared with nearby horizontal wells which already had
signs of increased water cut or gas oil ratio (GOR).
A distinct advantage of the passive inflow screen system in
the offshore fields of Saudi Aramco is the salvaging of
intermittent flow wells due to increased water production.
Figure 9 shows an example of a conventional vertical
producer which flowed at 1 MBOPD and had reduced
production after water breakthrough. The well was
sidetracked with 50 ft of oil column remaining under the gas
cap and underlain by water. The well was completed with
passive inflow screens in the horizontal section and after it
was put online, it had a stable production of more than 3
MBOPD and with only 5% water cut (WC) as seen in Fig. 9.
N AT U R A L G A S C A P A RT I F I C I A L L I F T
Another innovation which was implemented in the major
offshore fields is the successful integration of natural gas cap
lift with the passive inflow screens. This innovation is again
part of the continued evolution of the horizontal
completions to enhance sweep efficiency or target reservoir
locations partially swept by aquifer water. Coupling the two
technologies together, allowed supplemental energy provided
by the lifting source, in this case the reservoir gas cap, to be
distributed equally in the wellbore through the passive
inflow screens since the best zones along the horizontal
section will not dominate the inflow in the wellbore.
In one of the three fields, the hydrostatic pressure of the
produced fluids with even relatively a low WC range of
below 30% exceeds the production energy of the reservoir
and reduces the well flow. Since there is a gas cap above the
oil zone, a natural gas lift system was used as the energy
source for lifting the oil. The method allows continued
production from the well after the well had stopped or
reduced production, due to water breakthrough.
After review for the best candidate well, the new
completion design was implemented utilizing the combined
concepts, which are the use of passive inflow screens installed
in the oil zone in the reservoir and natural gas lift entry from
the gas cap above. The well is selectively perforated at the gas
cap and allows the gas to flow in the annular space. The gas
is then introduced into the wellbore through an orifice to
assist lifting the column of fluid from the oil zone. Three
choke settings of the orifice downhole can be controlled via
slick line to optimize drawdown and production rates from
the well. This completion design can be seen in Fig. 10. The
success of this completion design in the pilot well paved the
way for workovers in other wells of the field where they
Fig. 11. Intervention jobs breakdown by production gain utilizing a barge
vessel.
would benefit from the existing natural gas cap allowing
higher sustainable production and longer well life.
SAND FILL CLEAN OUT USING TORNADO
TECHNIQUE
The Tornado technique utilizes Coiled Tubing (CT) and a
special jetting nozzle tool for the purpose of sand fill clean
out. While the CT with the jetting tool at the end cleans the
wellbore in the first direct run from debris and sand which
has blocked healthy perforations (penetration stage), the
tool has the ability to invert circulation from its nozzles to
the opposite direction and while pulling out of the hole
with the CT there is a second clean out run which removes
sand that has been re-deposited after the first run (clean out
stage). This technique ensures that unwanted sand which
was not circulated properly and cleaned from the wellbore
during the first run, is now effectively removed especially
from sections of slanted or highly deviated sections of wells
where the gravity is assisting the decantation of sand after
the penetration stage.
A total of 13 wells were cleaned out in 2006 using this
technique to facilitate logging operations and/or for
production increase by cleaning blocked perforations. The
implementation of the Tornado technique resulted in cost
savings of $20,000 per job primarily by eliminating the
chemicals required during previously adopted clean out
operations. The production gain by cleaning perforations in
four wells using the Tornado method in 2006 amounted to
2.75 MBOPD per well. The sand fill clean out on the
remaining nine wells was to facilitate running a PulseNeutron Log (PNL) and it did not attribute to any
production gain.
F O R M AT I O N D A M A G E C H E M I C A L
T R E AT M E N T
Oil wells in the three major offshore fields are subjected to
formation damage during drilling or workover operations
due to calcium carbonate and clay minerals that invade the
pay zone upon well completion. A chemical treatment
process called “Iron Check Pellet” (ICP) was developed and
perfected in Saudi Aramco Research & Development Center
prior to its applicability to the field. It was initially pilot
tested in 2005 for use in wells that had suffered formation
damage and did not flow, or flowed with rates below
expectations. The aim of the ICP chemical treatment was to
restore well potential and directly remove formation
damage caused by drilling fluids while drilling, or by the
use of limestone chips through killing the well during
workover operations. During 2006 and because of the
positive results obtained from the pilot test in 2005, the ICP
treatment technique had a wider use in the offshore fields
and 14 ICP chemical treatment jobs were performed. The
average production gain per well from chemical treatment
amounted to 3.2 MBOPD.
As seen in Fig. 11, the ICP chemical treatment proved to
be the most advantageous when it comes to production gain
among intervention jobs to restore well productivity by
utilizing a barge vessel, as it contributed 44% to the overall
production gain among rigless intervention jobs in 2006.
CONCLUSIONS
1. Iron Check Pellet chemical treatment was the technique
that provided the highest production gain among all
intervention job types by utilizing a barge vessel (rigless
interventions) instead of a workover rig.
2. The availability of proper log data is paramount for the
design of the passive inflow screen system with the
correct horizontal length of compartments and number
of screens per compartment. The decision making of the
proper placement of the passive inflow screens is
facilitated with the acquisition of formation data
utilizing logging while drilling (LWD) formation
evaluation technology.
3. The success realized from the implementation of passive
inflow screens in the three offshore fields will trigger a
new generation of completion systems in Saudi Aramco.
These systems will involve running ICDs, with
mechanical open hole packers, combined with downhole
monitoring systems, in multilateral level 4 completions.
This completion type will be able to exploit more than
one zone (multiple stringer sands), and provide real-time
downhole pressure and temperature monitoring for
individual laterals.
4. During 2006, a total of 17 workovers utilizing rigs and
62 intervention jobs utilizing barge vessels (rigless) were
conducted in Saudi Aramco’s three major offshore fields,
which provided substantial production gains to sustain
overall field productivity and meet the annual targets.
T H E WAY F O RWA R D
The innovative technologies which are presented in this
article have been trial tested and evaluated in the recent
years in Saudi Aramco’s offshore fields and proved to be
very effective in improving sustainable well productivity.
Several of these applications will be perfected for future use
and others have been identified and will be evaluated for
use in the three major offshore fields. The next generation
of completion design with open hole packers in conjunction
with the passive inflow screens will utilize swellable
packers. These packers are made of a solid rubber element
which is capable to expand up to 200% of its original OD
when it comes in contact with reservoir crude. Current
completion designs utilize compartment sizes of 800 ft to
1,000 ft based on open hole log interpretation, whereas the
use of swellable packers could allow individual
compartments every 100 ft in the open hole section. The
increase of the number of compartments created by the
swellable packers along the horizontal section will improve
the system efficiency because the impact on production flow
rates if one or more of the compartments will experience
severe water or gas breakthrough will be minimized.
ACKNOWLEDGEMENTS
The authors acknowledge the support of Saudi Aramco
management for their permission to publish the information
contained in this paper. Our sincere thanks go to
AbdulHameed Aborshaid for his insights and input.
Additionally, the achievements mentioned herein are a
collective effort of several individuals and groups and could
not have materialized without the insight of people who
have a passion for the advancement of technology. Their
direct or indirect contribution to this work is highly
appreciated.
CT
D
ft
GOR
ICD
ICP
OD
PLT
WC
Coil Tubing
Darcy (unit for permeability)
Feet
Gas Oil Ratio
Inflow Control Device
Iron Check Pellet
Outer Diameter of Pipe
Production Logging Tool
Water Cut
Crosswell Electromagnetic
Tomography in Haradh Field:
Modeling to Measurements
Dr. Alberto F. Marsala
Dr. Saleh Al-Ruwaili
Dr. Shouxiang Mark Ma
Modiu Sanni
Zaki Al-Ali
Jean-Marc Donadille
Dr. Michael Wilt
Dr. Alberto F. Marsala has more than 17 years of oil
industry experience and is currently working in Saudi
Aramco’s EXPEC Advanced Research Center (EXPEC
ARC). Previously in Eni and Agip, he covered several
upstream disciplines, including 4D seismic, reservoir
characterization, petrophysics, geomechanics, drilling, and
construction in environmentally sensitive areas. Dr. Marsala
worked in the Technology Planning and R&D committee
of Eni E&P. He was the head of Performance Improvement
of the KCO Joint Venture (Shell, ExxonMobil, Total, and
others) for the development of giant fields in the northern
Caspian Sea. Dr. Marsala, who has authored several
technical papers and international patents, holds a Ph.D. in
Nuclear Physics from the University of Milan, Italy, an
MBA in Quality Management from the University of Pisa,
Italy, and a specialization in Innovation Management. He
served for several years on the Board of Directors of SPE Italian Section and is currently a Quality System Manager
of the European Organization for Quality.
Dr. Saleh Al-Ruwaili is a Petroleum Engineer
specializing in petrophysics and formation evaluation. He
received his B.S. degree in 1989 and a M.S. degree in 1992,
both from King Fahd University of Petroleum and Minerals
(KFUPM), Saudi Arabia. In 1995, Dr. Ruwaili received his
Ph.D. in Computational and Applied Mathematics from
Rice University, Houston, TX. During his 15 years with
Saudi Aramco, he has worked in a number of upstream
areas like reservoir engineering and simulation, reservoir
description, reservoir characterization, reserves assessment
and reservoir engineering technology. Dr. Ruwaili has
filed one patent and authored numerous geoscience and
engineering papers, which were published in international
journals of AAPG, SPWLA and SPE. Currently, he is the
technology champion of the Deep Diagnostics Focus Area
for the Reservoir Engineering Technology Team in the
EXPEC Advanced Research Center (EXPEC ARC).
Dr. Shouxiang Mark Ma is a Petroleum Engineering
Specialist and a Technologist Development Program mentor
at the Petroleum Engineering organization, Saudi Aramco.
Mark received a Ph.D. degree in Petroleum Engineering and
has published more than 30 papers in log/core petrophysics.
Before joining Saudi Aramco in 2000, he worked 20 years
in the industry and academia including PRRC/New Mexico
Tech, WRI/University of Wyoming, and Exxon Production
Research Company. Mark is a member of SPE and SCA.
Modiu Sanni is a Petroleum Engineering Specialist with
the Reservoir Engineering Technology Team (RETT) of the
EXPEC Advanced Research Center (EXPEC ARC). Prior
to joining Saudi Aramco in 2004, Modiu worked for Shell
for approximately 15 years in Nigeria, The Netherlands and
Sultanate of Oman. He has experience in formation
evaluation, reservoir characterization and description,
integrated multidisciplinary field studies, field development
and enhanced oil recovery. Modiu has authored and coauthored papers published in SPE and SPWLA conference
proceedings. He received his B.Sc. in 1987 and a M.Sc. in
1990, both in Mechanical Engineering from the University
of Ibadan, Nigeria.
Zaki Al-Ali holds a M.S. degree in Petroleum
Minerals (KFUPM), Saudi Arabia. He was a Senior
Petroleum Engineer with the Reservoir Simulation Division
before joining ‘Udhailiyah Reservoir Management Division.
Zaki worked for the Ministry of Petroleum and Minerals
for 4 years prior to joining Saudi Aramco in 1987.
Jean-Marc Donadille has been working for 6 years for
Schlumberger in the Paris and Beijing offices. He is
currently a Senior Research Engineer in the Schlumberger
Dhahran Carbonate Research Center in Saudi Arabia. JeanMarc received a joint M.S. degree in 2000 from ENSIMAG
(French Top National School of Computer Science and
Applied Mathematics, Grenoble) and the University of
Waterloo, Ontario, Canada. His interests include modeling
and inversion, electromagnetics, geophysics and
petrophysics.
Dr. Michael Wilt received his B.S. in 1973 and M.S. in
1975 in Geophysics from the University of California,
Riverside, CA. He received his Ph.D. from the University
of California at Berkeley, CA in 1991. Dr. Wilt was
employed as a staff scientist at Lawrence Berkeley
Laboratory between 1977 and 1984 and he was a program
leader at Lawrence Livermore National Laboratory
between 1989 and 1997. In these roles he applied
electrical, electromagnetic (EM) and potential field
methods for oil and geothermal field characterization and
steam flood monitoring. In 1997 Dr. Wilt joined
Electromagnetic Instruments Inc. (EMI) where he led
research and development projects in crosshole EM and
extended induction logging. EMI joined Schlumberger in
2001 and he led the development effort in deep reading
EM technologies, which continues today. He is currently
the Schlumberger Business Development Manager for deep
reading EM technologies in the Middle East and Asia and
he is stationed at the Schlumberger Regional Technology
center in Abu Dhabi.
ABSTRACT
Crosswell electromagnetic (EM) resistivity is emerging as an
intriguing technology for reservoir surveillance. It provides
a cross-sectional resistivity image between two wells and
has the potential to provide fluid distribution at an interwell scale. It can be used for identifying bypassed
hydrocarbons, monitoring macroscopic sweep efficiency,
planning infill drilling, and improving effectiveness of
reservoir simulation. It can be deployed for one-time or
time-lapse surveys.
A crosswell EM technology trial project is being
conducted in an Upper Jurassic carbonate reservoir, at the
Ghawar field in Saudi Arabia, to monitor the movement of
injected water flood front and map the fluid distribution.
The project site is in Ghawar’s southern region, Haradh
field, and consists of three wells in the oil-water contact
zone where peripheral injection water may have produced
an uneven flood front distribution.
Significant drilling and well deepening were required
prior to the deployment of tools in the three-well triangle.
In fact, one new well was drilled and two other wells were
deepened by more than 200 m, so that good volumetric
coverage could be obtained at the oil-water contact zone.
Extensive logs, core and formation tests were also acquired
to provide deterministic saturation profiles at the near
wellbore region. Formation evaluation in the project area
indicates that one of the wells was fully swept while a
second well, some 400 m away, was not.
In July 2007, crosswell EM surveys were acquired across
the three Haradh wells. In spite of the large well
separations, the acquired EM data had good quality, and
good stations repeatability. Preliminary processing has
revealed a structure consistent with the background
structure but a clear image of the oil-water contact is yet
to be made.
INTRODUCTION
The Haradh field is in the southernmost part of the greater
Ghawar field – the largest single oil field in the world, Fig.
1. Arab-D is a 100 m thick, highly prolific, upper Jurassic
reservoir comprising a carbonate sequence of grainstones,
packstones and wackestones1. The original sedimentary
textures have been altered in many places by leaching,
recrystallization, cementation, dolomitization and
fracturing, which have caused a variety of pore types2 to
coexist in Arab-D. Flood-front movement can be uneven in
some parts of the reservoir. Reservoir porosity ranges from
less than 10% at the base to over 30% at the top while
permeability ranges from a few millidarcies to more than
one Darcy.
The Arab-D reservoir in Ghawar has historically been
operated at relatively low depletion rates. Flank water
injection is being carried out to maintain pressure and to
improve sweep efficiency in this reservoir. With current
inter-well spacing, about 1 km, determining fluid
distribution behind the flood front is a key challenge to
maximizing recovery from this reservoir.
Traditional reservoir fluid monitoring techniques, e.g.,
pulsed-neutron logs (PNL) and resistivity logs have
investigation depths ranging from a few inches, for PNL
logs, to about 3 m for the deepest resistivity logs3.
Therefore, they cannot be used effectively for flood-front
monitoring at the inter-well scale.
Of the deeper technologies investigated, the crosswell EM
method seems to have potential value for reservoir
surveillance applications. It has been used in other fields for
reservoir characterization4 and for mapping oil recovery in
thermal enhanced oil recovery (EOR) applications. It has also
been used in time-lapse mode as an indirect means of waterflood monitoring5. We note, however, that these surveys were
acquired at a modest inter-well spacing, < 300 m, which
Fig. 1. Arabian Peninsula and Ghawar field. The area of interest lies in the
southwestern flank of Ghawar, within Haradh.
is not available at the Ghawar field.
Previous trials of 4D seismics at Ghawar have produced
inconclusive results, indicating that the method is not viable
for reservoir surveillance in the Ghawar field. These results
were likely due to the high rigidity of the limestone-dolomite
reservoir rock matrix and the small acoustic impedance
contrast between the pore fluids6 in Ghawar field.
CROSSWELL EM PROJECT
A joint research project between Saudi Aramco and
Schlumberger was initiated to investigate the applicability of
crosswell EM resistivity technology for studying the Arab-D
formation at Ghawar. Haradh field was selected because it
is deemed to be partially invaded by injection water from
nearby injectors. The objective was to evaluate fluid
distribution between wells using crosswell EM resistivity
tomography in combination with a sophisticated suite of
Fig. 2a. Surface location of the project.
Fig. 2b. Relative locations of the three wells for the X-well EM.
Fig. 3a. Resistivity model for a case having water flood, extending up to onefourth of the two-well separation (500 m).
phase it was assumed that a new well, A, could be drilled
and the open hole sections of existing wells B and C could
be used for measurements.
Several scenarios of flood-front movement such as edge
water due to super-K or fracture swarms, bottom water
encroachment, coning, and cusping were modeled (see Figs.
3a and 3b)7. The modeling showed that in almost all cases
the crosswell system would provide adequate signal but the
lateral resolution of images is degraded if the aspect ratio
(vertical logging interval relative to inter-well distance) is
too low. Experimentation with a range of aspect ratios was
conducted and it was found that an aspect ratio of 0.25 or
more is required to achieve reasonable results. In addition,
it was found that measurements need to be made above and
below the reservoir to accomplish plausible results.
To satisfy these requirements, well A was drilled to 200 m
below the reservoir. Additionally, wells B and C were
deepened by approximately 200 m. Consequently, the open
hole intervals for crosswell logging in the three wells
enabled having aspect ratios ranging from 0.3 to 0.65. In
addition, a segment of nonmagnetic (chrome) casing was
used in well A to extend measurements into the section
above the reservoir. Compared to conventional casings,
Fig. 3b. Inversion of synthetic crosswell EM data for the water flood case
shown in Fig. 3a.
wireline logs and formation evaluation tools. These
technologies combined have the potential to monitor
macroscopic sweep efficiency, identify current fluid
contacts, and locate bypassed oil, thus enabling effective
infill-well placement.
PREACQUISITION MODELING
Prior to field acquisition, an extensive search was made to
locate suitable wells at the oil-water contact, Fig. 2a. Once
the site was selected then pre-job forward modeling was
carried out6 to investigate the feasibility of obtaining useful
results from the measurements, with special considerations
to the large well separation and existing completions in
wells B and C to be surveyed, Fig. 2b. During the modeling
Fig. 4. Interpretation of historical well logs in well B.
Fig. 5. Interpretation of historical well logs in well C.
chrome pipe has little effect on EM data. Such nonmagnetic
casing would allow EM measurements to be extended
across a cased section of well A. Otherwise, EM data needs
to be obtained in the open hole with possible risk to well
integrity.
These new drilling and completion activities were
accompanied by coring in well A and logging in the three
wells. Comparing newly acquired logs to the older open
hole suite of logs, it is possible to obtain near-well
formation evaluation in time-lapse mode; see next section.
F O R M AT I O N E VA L U AT I O N
Well B was drilled vertically in 1994; see a composite of
recent and older logs in Fig. 4. Track 1 shows the original
formation resistivity and track 4 the interpreted volumetric
oil and water. A productivity index (PI) test performed in
1996 indicated that the near-wellbore formation was
slightly damaged with a skin of 3. The first production log
(PL) run in 1996 showed that well B was producing dry oil
uniformly from the 100 m reservoir. Water broke through
in 2001. From a PL run in 2003 (track 5), the main oil and
water producing intervals were around 660 ft. Until
recently well B was in production.
Prior to deepening well B, a carbon-oxygen (C-O) log
was run, using reservoir saturation tool (RST™), to
evaluate oil and water distribution near the wellbore8. After
the tubing was removed we ran conventional open hole logs
of triple combo; the resistivity logs are plotted in track 2.
Comparing the 1994 and 2007 resistivity logs indicate that
the invading water has almost reached the top of the
reservoir, track 3. This is consistent with the C-O log
results, track 6.
The 2007 resistivity log was interpreted using the Archie
equation with formation water salinity of 120 ppk total
dissolved salts (TDS); see results in track 6 of Fig. 4. The
2007 results of C-O (shaded blue) and resistivity (yellow
curve) are in good agreement, which is important since the
well data will be used to anchor the crosswell EM results.
A formation tester (FT) job was run and a reservoir fluid
sample was taken at a depth of 652 ft, (track 6). After
pumping out for more than nine hours, this sample had an
85% water cut, indicating that water had reached the top
of the reservoir.
Well C was drilled vertically in 1996; the logs are shown
in Fig. 5. Track 1 shows the original formation resistivity
and track 6 the interpreted volumetric oil and water. A PI
test performed in 1996 indicated that near wellbore
formation was slightly damaged with a skin of 3. Another
PI tested in 1999 indicated more severe formation damage,
with a skin of 9. According to the 1996 PL, the well was
producing dry oil and the reservoir contribution to
production was roughly uniform. Water broke through in
June 1999. From a PL run in May 2001 (track 7), the main
oil producing interval was about 670 ft and water
breakthrough interval was near 672 ft.
Well C was also deepened for the crosswell EM work.
We used this opportunity to acquire a C-O (RST™),
slimhole array induction tool (SAIT™), and conventional
triple combo. The regular array induction tool (AIT™)
resistivity logs are plotted in track 3. The comparison, in
track 4, between the 1996 original resistivity, track 1, and
the 2007 rigless SAIT, track 2, and rig AIT resistivities
indicates that the invading water had reached a depth of
685 ft. The following observations can be drawn from
Fig. 5:
1. Different logging runs may not be on depth. In
average, a 3½ ft depth shift was required to put the
newly acquired logs on depth with the original open
hole logs, track 4.
2. The workover fluid may have deep water invasion
that reduces the AIT™ readings. Depth of invasion
volumetrics are plotted in tracks 4 and 5, respectively.
Using image log calipers, a 2D borehole shape is
constructed in track 1. From Fig. 6, the following
observations can be drawn:
1. The borehole washout (track 1) across the anhydrite
interval, just below casing, is very typical of
anhydrite-water interaction. This enlargement affects
log data quality, especially shallow-depth logs.
2. Track 3 shows water-based mud invasion profile. For
formation evaluation, deep reading logs should be
used.
3. The open hole logs interpretation, using a formation
water salinity of 90 ppk TDS, indicates that the water
front has advanced to about 736 ft (track 5); this is
consistent with FT pressure data and sampling results.
4. Similar to well C, some dry oil was sampled in well A
across the thin oil zone at 844 ft.
5. Comparing reservoir porosity, track 5, and NMR
pore-body size distribution, track 6, higher porosity
rocks (above 760 ft) can have bigger pores.
6. From the static image, track 8, it is obvious that there
Fig. 6. Well logging interpretations for well A.
depends on rock properties and workover operation
practices.
3. After depth shifting, time-lapse porosity logs (track 5)
showed little change from 1996 to 2007.
4. Track 8 shows the C-O results (shaded blue) and the
SAIT™ data (yellow curve) interpreted using Saudi
Aramco best practices of interpreting SAIT™ logs9
and using water salinity of 60 ppk TDS. The C-O and
SAIT™ logs (track 8) are in good agreement.
5. An FT job sampled reservoir fluids. After more than
seven hours of pump-out, the sample at depth 645 ft
contained about 95% oil (5% water cut). Then, after
more than 10 hours of pump-out, for the sample at
depth 692 ft, it showed a water cut of 80%. To our
surprise, some dry oil was sampled across the thin
zone at 821 ft.
Well A was drilled specifically for this crosswell EM
project and this opportunity was utilized to collect cores
across the reservoir. A complete set of logs was also run in
this well, see Fig. 6. Triple combo logs are shown in tracks
1-3, an NMR log in track 6, image logs in tracks 7-8, and
FT in track 5. Logging interpretations for lithology and
Fig. 7. Water volume as fraction of total space on the B-C-A wells section.
Scenario obtained from open hole logs.
is a low porosity, or high resistivity, streak at 730 ft
that may have helped to slow down water
advancement.
FLUID DISTRIBUTION SCENARIO
From the recent formation evaluations discussed, we found
that the near-wellbore conditions in wells A, B and C are
quite variable in spite of their close proximity. In particular,
variations in the fluid level, in the saturation of the various
zones, and in the salinity of the formation water were
observed.
Near-wellbore water saturation was estimated from
recently acquired porosity and resistivity logs using the
Archie equation with water resistivity (Rw) of 0.035 ohmm.
In the following modeling scenarios, the water volume is
considered a fraction of the total space, which equals water
saturation multiplied by porosity:
This quantity is represented for the three wells, in Fig. 7,
by blue color crossing the porosities in the displayed
horizons between wells. Well B has been producing for a
number of years; consequently it shows a large volume of
water in the high porosity section at the upper half of the
reservoir. Well C has also produced for several years; it
shows intermediate water content at the bottom of the highporosity section and low content at the top. In well A, the
water content is low everywhere except at the bottom of the
high-porosity, where it has water in a 3 m zone.
Nonetheless, it is not obvious whether the water in this wet
zone is caused by production in nearby wells or by
peripheral water injection.
In absence of any other inter-well information, the most
plausible way to create scenarios of water distribution
between wells is to interpolate the values at the wells. The
image of Fig. 7 was obtained by interpolating the water
volume fraction computed from eight wells in the area.
Each cell value is an average of the water volume fraction at
nearby wells weighted by the inverse of the distance from
the cell to the nearby well data point. The method accounts
for structural information and reservoir zonation; in
addition it favors horizontal continuity.
Considering the proximity of these wells, this image is
showing surprising variations. Because it is based on
interpolation, rather than measurements, its results are
questionable. For example, it is not clear whether the
continuous path of water leading to Z1-A originates from
Z1-B, Z2-B, or both. Likewise, the extent of the water
present between Z3-B (mainly wet) and Z3-A (dry) is not
well defined. Similar questions about the distribution of the
Fig. 8. Crosswell EM tomography.
water between well A and well C may not be answered with
certainty. It is expected that the resistivity images,
obtainable from crosswell EM surveys, will better define the
inter-well fluids distribution.
CROSSWELL EM TECHNOLOGY
Crosswell EM uses the principles of electromagnetic
induction and tomography to provide an image of the
resistivity distribution between boreholes. Figure 8
illustrates a field application of crosswell EM. Two
boreholes are spaced a distance (x) apart and have a depth
range (z), over which inter-well measurements can be
made. The transmitter (T), placed in the first well,
broadcasts EM signals throughout the medium. At the
second well, the signals are detected using an array of
induction coil (magnetic field) receivers (R). Whenever
possible, the sources and receivers are placed at regularly
spaced intervals below, within, and above the depth range
of interest. The data collected are used to image the
interwell space.
In practice, the adjacent source and receiver stations are
spaced 2% - 5% of the inter-well distance (x). The ideal
measurement range in depth (z) is at least equal, if not
greater, to the well separation such that the aperture (z/x in
Fig. 8.) of the tomographic imaging experiment is equal to
or greater than unity. There have been, however, successful
fit within a specified tolerance for acceptance.
The computational engine that drives the sensitivity and
inversion algorithms is a numerical method that calculates
the electromagnetic fields within a 2D (or 3D) rectangular
grid. A number of these solutions have been developed over
the past 20 years and these will not be described here.
Presently, finite difference algorithm10 is used. It is well
known that the inversion process results in non-unique
models for resistivity maps in the inter-well space
investigated. In practice, this condition is usually managed
by applying the previously known data, e.g., logs,
formation tests, well performance history, and exercising
reasonable model constraints for fitting the data.
C R O S S W E L L E M S U RV E Y I N H A R A D H
Fig. 9. Sample crosswell EM raw data; profile and repeat.
imaging examples where the aperture was much less than
unity; in such cases the problem is usually fairly
constrained. The data set normally constitutes several
thousand measurements, which are interpreted together to
provide the inter-well resistivity map.
Field data is collected using standard wireline logging
conveyance with the source and receiver systems connected
by hardwire. The transmitter tools have an electronics
cartridge and a fairly large antenna, typically 8 cm - 10 cm
in diameter and 4 m - 5 m long. This size is required to
generate a sufficient moment to transmit the signal across
large distances. The receivers can be slimmer but are often
multilevel coil strings; thus they can be quite long.
The acquisition strategy involves fixing the receiver(s) at
a certain depth in one well and acquiring data while the
transmitter sonde is moving continuously in a second well.
After a specified depth interval is logged, the receiver is
moved to a new depth and the process is repeated until the
logging interval is covered by both source and receiver. A
data point usually consists of stacking a monochromatic
sine-wave hundreds or thousands of times. An entire data
set consists of 30-60 separate receiver positions covering the
depth range of interest; therefore using a string of receivers
is essential to manage the data acquisition time. An entire
data set typically requires from 12 to 36 hours depending
on the tools used, well conditions, and well separation.
Field data are interpreted by fitting the measurements to
calculated data from a numerical model, using an inversion
procedure. We begin with a resistivity model, usually
derived from prior knowledge of the field area including
logs, geologic and seismic data. Using this model and a
forward EM code, the inversion calculates the forward EM
response and then adjusts the model parameters, under
certain constraints, until the observed and calculated data
Key challenges facing crosswell EM data acquisition at
Haradh are the large well spacing and the variable
resistivity sections. Although, in theory, EM tomography is
useful at well separations of 1 km or more, this is so far the
largest well separation tried by crosswell EM.
Crosswell EM work in Haradh field was conducted in
July 2007. The three well pair required about seven days
for rig-up and data collection. A sample field profile, Fig.
9, reveals that although the signals were low (as expected),
the data are repeatable. In addition, the background noise
level was found to be very low, which bodes well for
future surveys.
Each of the three surveys consisted of 3,000-4,000
measurements which will be processed jointly to provide the
2D inter-well resistivity maps. In addition to the
tomography data, we also collected background noise data
to evaluate the influence of steel and chrome casing on the
ambient noise.
The next step in the process is to complete the data
inversions and compare the inter-well resistivity maps to the
initial well derived resistivity realizations.
CONCLUSIONS
This initial crosswell EM survey in Saudi Arabia has
produced interesting and useful results. The technique has
demonstrated adequate range and sensitivity for reservoir
monitoring and likely has a bright future in the Kingdom.
We look at this project as an early test of deep diagnostic
technology. The newly acquired crosswell EM surveys and
their interpretations will help in anchoring on effective
reservoir surveillance strategies, which will enhance the
production plans leading to improved recovery.
EM
PNL
PL
PI
C-O
RST™
SAIT™
AIT™
TDS
FT
2D, 3D, 4D
m
n
Rw
Rt
Vwater,frac
φ
Electromagnetic
Pulsed neutron logs
Production log
Productivity index
Carbon-oxygen
Reservoir Saturation Tool
Slimhole Array Induction Tool
Array Induction Tool
Total dissolved salts
Formation tester
2-, 3-, 4-dimensional;
4D is a 3D repeated at different
time (time lapsed)
Archie cementation exponent
Archie saturation exponent
Water resistivity – ohm-m
Formation (true) resistivity – ohm-m
Water volume, fraction of total space –
m3/m3
Porosity - m3/m3
ACKNOWLEDGEMENTS
The authors are thankful to Saudi Aramco and
Schlumberger for their permission to publish this paper.
Special gratitude extended to S. Neaim, N. Afaleg, O.
Ukaegbu, M. Badri and B. Miller for their constant support
to this work. Similar thanks are extended to S. Ghamdi for
the geological description, to R. Akkurt, A. Ibrahim, I.
Ariwodo, M. Zeybek and S. Crary for logging data
acquisition and interpretation, to C. Levesque for the
crosswell EM modeling, to S. Hussain for the Petrel
modeling, and to M. Buali for the wells operations.
REFERENCES
1. Cantrell, D.L., Swart, P.K., Handford, R.C., Hendall,
C.G. and Westphal, H., “Geology and Production
Significance of Dolomite, Arab-D Reservoir Ghawar
Field, Saudi Arabia,” GeoArabia, Vol. 6, No. 1, 2001,
pp. 45-59.
4. Wilt, M.J., Morrison H., Becker A. and Lee, K.: “Cross
Borehole Electromagnetic Induction for Reservoir
Characterization,” SPE paper 23623, 1992.
5. Patzek, T., Wilt, M.J. and Hoversten, G.M.: “Using
Electromagnetics (EM) for Reservoir Characterization
and Waterflood Monitoring,” SPE paper 59529, 2000.
6. Dasgupta, S.N.: “Monitoring Reservoir Fluids Alternatives to 4D Seismic,” 68th Meeting, EAGE,
Expanded Abstracts, E027, 2006.
7. Sanni, M.L., Yeh, N., Afaleg, N.I., Kaabi, A.O., Ma,
S.M., Levesque, C. and Donadille, J.M.:
“Electromagnetic Resistivity Tomography: Pushing the
Limits,” SPE paper 105353, 2007.
8. Kelder, O., Al-Hajari, A., Eyvazzadeh, R., Ma, S.M. and
Al-Behair, A.M.: “Expanding the Operating Envelope of
Carbon-Oxygen Saturation Monitoring Technology,”
IPTC paper 10458, November 2005.
9. Al-Sunbul, A., Ma, S.M., Al-Hajari, A., Srivastava, A.
and Ramamoorthy, R.: “Quantifying Remaining Oil by
Use of Slimhole Resistivity Measurement in Mixed
Salinity Environments – A Pilot Field Test,” SPE paper
97489, International IOR Conference in Asia Pacific,
December 5-6, 2005, and Kuala-Lumpur, Malaysia.
Saudi Aramco Journal of Technology, Winter 2005.
10. Abubakar, A., Habashy, T.M., Druskin, V.L.,
Alumbaugh, D., Zhang, P., Wilt, M.J., Denclara, H.
and Nichols, E.: “A Fast and Rigorous 2.5D Inversion
Algorithm for Crosswell Electromagnetic Data,” 75th
annual International Meeting 2005, SEG, Expanded
Abstracts, 534-537.
S I M E T R I C C O N V E R S I O N FA C T O R S
feet x 3.048* E-01
psi x 6.894757 E+00
bbl/d x 1.589873 E-01
inch x 2.54* E+01
m
kPa
m3/d
mm
* Conversion factor is exact
2. Clarke, E.A.: “Miles to Microns – Analysis of the
Ghawar Arab-D Pore Systems,” Internal Saudi Aramco
Report, 2006.
3. Ma, S.M., Al-Hajari, A.A., Berberian, G. and
Rammamorthy, R.: “Casedhole Reservoir Saturation
Monitoring in Mixed Salinity Environments; A New
Integrated Approach,” SPE paper 92426, 2005.
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