Greater Edmonton Area Bitumen Upgrader Supply Chain Study

Greater Edmonton Area
Bitumen Upgrader Supply Chain Study
PREPARED FOR:
PREPARED BY:
COLT ENGINEERING CORPORATION
EDMONTON, ALBERTA
March 31, 2007
This document represents work done by Colt Engineering Corporation (Colt) performed to recognize engineering principles and
practices. The work is based upon the project scope and design information as described herein and as provided by the Owner. Any
representations in this document are furnished for general information only and are not in any way guaranteed or warranted by Colt or its
sub-consultants or on behalf of the Owner or their respective employees. None of the above named parties or individuals shall be liable,
in negligence or otherwise, for any reliance which may be placed by any other party upon any representations contained herein.
TABLE OF CONTENTS
1. Executive Summary…………………………………………………………………………….. 1
2. Background and Objectives……………………………………………………………………7
2.1 Need for Alberta Based Bitumen Upgraders
2.2 Greater Edmonton Area Upgraders
2.3 Study Objectives
3. Methodology………………………………………………………………………………….....12
3.1 Type of Process Units Encountered in Bitumen Upgrading
4. Upgrader Data Sources…………………………………………………………………..…….13
4.1 Petro-Canada Edmonton Refinery – Refinery Conversion Project
4.2 BA Energy Heartland Upgrader
4.3 Scotford Upgrader Expansion Project
4.4 Synenco/SinoCanada Northern Lights Upgrader
4.5 Petro-Canada/UTS/TeckCominco Fort Hills Upgrader
4.6 Northwest Upgrading
4.7 North American Upgrading
4.8 Total SA and “Other” Upgrader
5. Estimated Costs of the Proposed Upgrading Facilities……………………………….....18
6. Conclusion…………………………………………………………………………………….....21
7. Appendices………………………………………………………………………………….…....22
1.EXECUTIVE SUMMARY
Background
Alberta is currently producing more than 1 million barrels per day (bpd) of bitumen from the oil sands and has
the potential to reach 3.5 million bpd by 2020. This creates an opportunity for further bitumen upgrading in
Alberta to maximize the value of the resource.
Presently, Alberta upgrades most of the bitumen it produces into a higher valued synthetic crude oil in the
Greater Edmonton Area (GEA) near Fort Saskatchewan (Shell Canada) and in the Fort McMurray region (Suncor
and Syncrude). The Province’s upgrading capacity is about 800 thousand barrels per day and is expected to
increase to over 2.5 million barrels per day by 2020. The additional upgrading capacity will come from significant
expansions of existing facilities as well as the construction of newly planned projects in the GEA. The GEA is
home to 1.1 million citizens and comprises the City of Edmonton and its 22 surrounding municipalities.
Greater Edmonton Area
The planned increase in upgrading capacity creates significant challenges to the region’s oil and gas industry
as it procures equipment and services from across the globe. However, these supply chain challenges also
create long-term economic opportunities for the GEA – and Alberta more broadly – in attracting manufacturing
and service companies to the region. These companies will have the opportunity to assist in the design,
construction, and maintenance of these facilities. In many instances, their proximity to the proposed plant sites
has the potential to lower capital costs. In addition, planned upgrading will create extended opportunities for
service and supply companies throughout the life of the upgrading facilities.
The upgrading capacity growth in the GEA represents a very significant opportunity for suppliers to this
market. The list of potential upgraders is constantly evolving, as existing and new proponents advance the
development of their plans for new or expanded facilities. At the time of writing this report (March 2007) there
are six upgrader projects under development (engineering and construction) and several more under serious
consideration (front-end engineering). Construction of these GEA upgrader projects would result in a regional
bitumen throughput capacity of 1.5 million barrels per day, 60% of the expected total capacity in the province.
The construction of all phases of the projects would involve investment in the range of C$40 billion to
$70 billion between 2008 and 2015.
In addition to the significant capital investment in these projects, the GEA also stands to benefit from providing
ongoing supply and services to operate, maintain and upgrade these facilities. The typical annual operating
(excluding feedstocks) and maintenance costs average 2 to 3 percent of the installed cost of a facility
(approximately C$1.5 billion to $2.0 billion) and annual sustaining capital costs are averaging 2 percent
(C$1 billion to $1.5 billion) of the installed cost of each facility. These benefits to supporting service industries
would be sustained over the estimated 30 to 50 year life of a facility. The types of materials, equipment and
services that will be required during the operating phase of the facilities closely resemble those required during
the construction execution phase.
There is a need to understand the overall impact of this level of growth and to provide the necessary policy and
infrastructure support to assist industry in meeting this investment challenge. To this end, Edmonton Economic
Development Corporation (EEDC) and Alberta Employment, Immigration and Industry (AEII) commissioned this
study to provide an overview of the growing bitumen upgrading industry in the GEA for use in the formulation
of policies and initiatives to promote the development of the equipment and service industry and identify
infrastructure requirements to enable planning. The information will provide an awareness of the size, type
and timing of business opportunities arising either directly or indirectly from the bitumen upgrading industry.
This study is the first of a two-phase process to identify the service opportunities for Alberta. The main objective
for phase one is to identify and document existing and proposed upgrading facilities and the individual
processes and equipment and services that these facilities will require for construction and maintenance.
Following this, a separate study will analyze the current manufacturing, equipment and support services found
in Alberta and determine the “gaps” that exist in industrial manufacturing and services. These “gaps” could be
the basis for further investment attraction for businesses needed to supply the upgrader developments.
Study Findings
Information for this study was obtained from publicly available reports and qualified assumptions to develop
profiles of the type and quantity of supply and services that would be required by the proposed GEA upgraders.
Below is a listing of the upgrader projects (data is current March 2007) included in the analysis. The projects
included were those likely to be built between 2007 and 2015.
Table 1:
Greater Edmonton Upgraders and their Current Status
Upgrader
Current Status
Petro-Canada Refinery
Mid 2008 Start-up
BA Energy
3Q 2008 Start-up
Shell Scotford
Nov. 1, 2006 – AOSP Expansion 1 to proceed Planned Start-up 2010 (more phases announced)
Northwest Upgrading
EUB Submission Feb. 2006 – Detailed Eng. underway
Planned Start-up 2010
Synenco/SinoCanada
EUB Submission Sept. 2006 – Planned Start-up 2010/2011
Petro-Canada/UTS
EUB Submission Dec. 2006 – Project Sanction 2008
Planned Start-up 2012
Total SA
Project Timelines to be Confirmed
North American Oil Sands
Project Timelines to be Confirmed
Other*
Project Timelines to be Confirmed
* “Other” refers to an assumption that at least one additional upgrader currently under discussion will be announced during this timeline.
Preliminary process configurations listed in public disclosure documents for each project were used to identify
the types of Process Units and Offsites & Utilities required. These include:
Process Units
• Diluent Recovery
• Vacuum
• Deasphalt
• Coking
• Hydrocracking
• Hydrotreating
• Gas Recovery Unit
• Gas Sweetening Units
• Sulphur Recovery
• Hydrogen Production
• Sour Water Stripping
• Coke Gasification
Offsites and Utilities
• Electrical Distribution
• Cooling Water
• Flare System
• Fuel Gas
• Effluent Treating
• Boiler / Power
• Control Rooms (I/C)
• Buildings
• Interconnecting Pipelines
• Tank Farm
• Blending / Loading Racks
• Plant Air
Based on this information and the reported timelines of the upgraders identified, annual expected equipment
orders were projected to 2014. The results show that between 2007 and 2014 (when procurement for the
proposed projects would be completed), total orders for major equipment to support the upgraders are
significant. Some examples of major equipment totals and the range of costs of these types of equipment
are shown below. A more complete list of equipment and bulk requirements is provided in this report.
Table 2:
Equipment Requirements and Details
Major Class
Equipment
Quantity
Range of Cost
of One Item
Equipment
Delivery
Lead
Times
Total
Low
($,000)
High
($,000)
(months)
Buildings
Buildings between
100m³ and 1000m³
136
1,000
2,000
12
Buildings
Buildings larger than 1000m³
170
2,000 10,000 18
Buildings
Buildings less than 100m³
85
20 400 6
Buildings
Control Room
17
2,000 5,000 18
Compressors
Centrifugal
113
200 3,000 12
Compressors
Fan/Blower
360
20 200 6
Compressors
Reciprocating
25
150 3,000 12
Flare
Flare Derrek
17
1,000 3,000 12
Flare
Flare Line/Tip
51
500 2,500 12
Heat Exchangers
Air Cooled
829
150 1,500 9
Heat Exchangers
Boilers
58
3,000 5,000 12
Heat Exchangers
Carbon Steel (Shell/Tube)
2371
150 400 9
Heat Exchangers
Cooling Tower (per cell)
85
500 1,000 9
Heat Exchangers
Fired Heater
290
700 8,000 12
Heat Exchangers
HP Alloy (Shell/Tube)
546
1,500 3,000 24
Heat Exchangers
LP Alloy (Shell/Tube)
697
50 400 18
Heat Exchangers
Process Steam Generator
233
150 300 9
Power
Electric Motors
5099
5
500 6
Pressure Vessels
Bullet
17
500 1,000 9
Pressure Vessels
Horizontal Separator
952
100 1,000 12
Pressure Vessels
Packed Tower
88
200 2,000 12
Pressure Vessels
Sphere
17
500 2,000 18
Pressure Vessels
Trayed Tower
387
200
2,000 12
Pressure Vessels
Vertical Separator
1513
100 1,000 12
Pumps
HP Multistage Centrifugal
295
500
2,000 18
Pumps
LP/MP Centrifugal
4309
20 500 9
Pumps
Positive Displacement
315
10
500 9
Reactors
Coke Drums
16
2,000 5,000 18
Reactors
HP Alloy
204
1,000 10,000 24
Reactors
Sulphur Plant
90
100 500 12
Chart continues on next page
Table 2:
Equipment Requirements and Details
(Continued from previous page)
Major Class
Equipment
Quantity
Range of Cost
of One Item
Equipment
Delivery
Lead
Times
Total
Low
($,000)
(months)
High
($,000)
Steam Turbines
Steam Turbines
318
50 500 9
Tanks
Large > 50 kbbl
255
300 5,000 12
Tanks
Medium > 10 kbbl < 50 kbbl
51
50 300 9
Tanks
Small < 10 kbbl
192
10 50 6
BulkType
BulkSubType
Total
Analyzers
Analyzer
Control Valves
Control Valves
Flow Instruments
FIC Local
Flow Instruments
Flow Instruments
233
100
300
1-4
17581
10
100
1-4
17
1
10
1-4
FIT DP Elec.
8184
1.5
3
1-4
FIT DP Pneu.
628
1.5
3
1-4
Flow Instruments
Flow Switch
290
1.5
3
1-4
Flow Instruments
Rotameter
170
1.5
3
1-4
Level Instruments
Level Controller Pneu.
85
1.5
3
1-4
Level Instruments
Level Gauge
6414
0.5
2
1-4
Level Instruments
Level Switch
932
1.5
3
1-4
Level Instruments
Level Tape
498
1.5
3
1-4
Level Instruments
Level Transmitter Elec.
3239
1.5
3
1-4
Orifice Plates
Orifice Plate
8886
0.1
1
1-4
Pressure Instruments
DP Gauge
431
1.5
3
1-4
Pressure Instruments
DP Transmitter
1789
1.5
3
1-4
Pressure Instruments
Local PIC
Pressure Instruments
Pressure Gauge
Pressure Instruments
Pressure Instruments
233
1.5
3
1-4
11771
0.25
0.5
1-4
Pressure Switch
2250
1.5
3
1-4
Pressure Transmitter
3773
1
3
1-4
Regulating Valves
Regulating Valves
1055
0.5
2
1-4
Rupture Discs
Rupture Discs
16
0.25
0.5
1-4
Safety Valves
Safety Valves
13851
2
15
1-4
Solenoids
Solenoid
3425
0.25
0.5
1-4
Temperature Instruments
BS IR
523
1
2
1-4
Temperature Instruments
Local TI Gauge
18680
0.1
0.25
1-4
Temperature Instruments
Local TIC Loop
360
1.5
3
1-4
Temperature Instruments
Temperature Switch
1685
1
2
1-4
Temperature Instruments
Temperature Transmitter
17481
1.5
3
1-4
Temperature Instruments
Testwell
11140
0.2
0.5
1-4
Temperature Instruments
Thermowell
38206
0.2
0.5
1-4
The values for other bulk items were estimated based on the average cost of an upgrading facility.
Current estimates for the cost of an upgrader range from C$30,000 to $50,000 per barrel per day of capacity.
This equates to C$40 billion to $70 billion of total installed cost to complete all proposed phases of these
projects. Industry data on the breakdown of cost by equipment, bulk items and labour for upgrader/refinery
facilities are available. For example, generally 13 percent of total installed cost is attributed to the piping
required to construct such facilities. Similarly, 2 percent of total installed cost is for structural steel. Using these
percentages, the final estimated supply requirements are in the range of C$5.5 billion to $9 billion for pipe and
C$0.9 billion to $1.5 billion for structural steel. The magnitude of supply opportunities for these projects is large
and forthcoming.
However, it must be noted that the equipment quantities in this study are estimates and should not be
considered final totals. The timing of each project is subject to change due to investment decisions, regulatory
approvals and market forces, such as the availability of labour, material and equipment. In addition, this
work does not consider supply requirements for the bitumen production facilities, pipelines and terminals,
downstream integration opportunities and other infrastructure required to support these facilities. This work
does, however, provide a basis for assessing the capacity and capability of the supply chain to meet the
specific opportunity of upgraders in the GEA.
Conclusion
The construction of bitumen upgraders presents a substantial economic opportunity for the GEA, both in the
initial development period and during the operating life of the projects. Based on the cost estimates found in this
study, it is apparent that the base procurement demands of the upgraders during the construction years of 2008
to 2015 would amount to between C$18.8 billion and $32.9 billion, excluding pipeline investment. Furthermore,
the demand for supplies, services and capital upgrades could very easily exceed $100 billion over the 30 to 50
year life expectancy of these plants. Such a level of sustained economic activity will generate significant supply
responsibilities and all parties would do well to engage in supply chain planning and development.
The growth in the GEA due to bitumen upgrader development also provides an opportunity for Alberta to
expand its existing heavy industrial manufacturing base, generating both direct and indirect economic benefits
from oil sands developments. Given the size of the developments, there is significant opportunity to leverage
off this demand to grow a world-class heavy industrial manufacturing hub.
2.BACKGROUND AND OBJECTIVES
A sharp increase in global oil prices in the last decade provided the economic impetus for a significant
expansion in oil sands bitumen production in northern Alberta. Several industry organizations expect bitumen
production to reach anywhere between 3 to 4 million barrels per day by 2020. The figure below provides an
estimate by the Alberta Government for Alberta’s total crude oil production (conventional and oil sands) to
2020. The capital investment required to exploit this resource makes this sector one of the largest investors
in Canada with a large employment impact and significant tax and royalty revenues to various governments.
Alberta Supply of Crude Oil and Equivalent
Alberta Supply of Crude Oil and Equivalent
4000
Forecast
3600
Thousand Barrels Per Day
3200
2800
Non-upgraded Bitumen
2400
2000
Synthetic Crude Oil
1600
1200
800
Pentanes
Heavy
Light/Medium
400
0
1996
1998
2000
2002
2004
2006
2008
2010
2012
2014
2016
2018
2020
Source: AEUB 1996 to 2015; AEII 2015 to 2020
Source: AEUB 1996 to 2015; AEII 2015 to 2020
2.1 Need for Alberta Based Bitumen Upgraders
Bitumen is a semi-solid, degraded form of oil that does not flow at normal temperatures and pressures,
making it difficult and expensive to extract. Technologies utilized to extract the bitumen include open pit mining
operations and insitu (thermal recovery) techniques.
To render bitumen capable of being transported it must be blended with a diluent of lighter hydrocarbon liquids,
traditionally condensates. Diluted bitumen can then be converted into a lighter synthetic crude oil (SCO)
through bitumen upgrading processes or refined directly into petroleum products by specialized refineries.
Most North American refineries can currently handle only 10 percent to 15 percent of their input coming
from bitumen sources, but conversion projects are occurring to increase refining capabilities to handle these
heavier supplies.
The two original oil sands mining plants (Suncor and Syncrude) near Fort McMurray utilize upgrading facilities
located at their production sites to convert bitumen into SCO. Integration of bitumen production and upgrading
at a common site has a number of practical advantages from an energy efficiency and water utilization
perspective. Construction and operating costs in the Fort McMurray area have recently inflated considerably
as operators and constructors in the region compete for available personnel and services. This has caused
considerable cost impact in executing these on-site upgraders and has resulted in more consideration being
given to the upgrading at locations farther from the production sites.
The Greater Edmonton Area (GEA), with its population in excess of one million residents, affords a location
that is still relatively close (300 to 500 km) to the bitumen producing areas and offers the supply base,
construction workforce and infrastructure to improve the cost effectiveness of building and operating bitumen
upgrading facilities. In addition, upgraders in this area accrue the cost, sales and feedstock availability benefits
of synergies with existing facilities in the area where hydrogen production, utilities, pipelines, other upgrading,
refining and petrochemical projects currently exist.
Supply of the required equipment, materials and services to construct, operate, maintain and sustain new
upgrading facilities represents a significant increase in business activity for the Edmonton area economy.
Interested parties in the GEA recognized a need to understand the overall impact of this level of growth,
and to provide the necessary policy and infrastructure support to assist industry in meeting this investment
challenge. To this end, Edmonton Economic Development Corporation (EEDC) and Alberta Employment,
Immigration and Industry (AEII) commissioned this study to provide awareness of the size, type and timing of
business opportunities arising. The study utilized publicly available information and qualified assumptions to
develop profiles of the type and quantity of supply and services that would be required by the proposed GEA
upgraders.
2.2 Greater Edmonton Area Upgraders
The list of upgraders proposed for the GEA continues to evolve as bitumen producers and merchant upgraders
develop their plan for these facilities. At the time of writing this report (March 2007), the following (Table 3) list
of proponents are considered likely to proceed with the construction of GEA upgrading facilities between 2007
and 2015.
Table 3:
Greater Edmonton Upgraders and their Current Status
Greater Edmonton Upgraders
Current Status
Petro-Canada Refinery
Mid 2008 Start-up
BA Energy
3Q 2008 Start-up
Shell Scotford
Nov. 1, 2006 – AOSP Expansion 1 to proceed Planned Start-up 2010 (more phases announced)
Northwest Upgrading
EUB Submission Feb. 2006 – Detailed Eng. underway
Planned Start-up 2010
Synenco/SinoCanada
EUB Submission Sept. 2006 – Planned Start-up 2010/2011
Petro-Canada/UTS
EUB Submission Dec. 2006 – Project Sanction 2008
Planned Start-up 2012
Total SA
Project Timelines to be Confirmed
North American Oil Sands
Project Timelines to be Confirmed
Other*
Project Timelines to be Confirmed
* “Other” refers to an assumption that at least one additional upgrader currently under discussion will be announced during this timeline.
Each of these operators has published plans for their phasing of the execution of these developments. Table 2
illustrates the throughput of each developmental phase.
Table 4:
Throughput and Timing for Each Phase of GEA Upgrader Development
Company
Facility
Phase
Onstream
by
Incrimental
Capacity
(KBBL/Day)
Petro Canada
Edmonton Refinery
RCP Project
2008
85
BA Energy
Heartland Upgrader
Phase 1
2008
54.4
Phase 2
2010
54.4
Shell/Chevron/
Western Oil Sand
Scotford Upgrader
Phase 3
2012
54.4
De-bottleneck
2008
45
Synenco/
SinoCanada
Northern Lights Upgrader
Expansion
2010
90
Phase 1
2010
50
Phase 2
2012
50
Upgrading
Phase 1
2010
50
Phase 2
2012
50
Petro Canada/
UTS/Teck
Sturgeon Upgrader
Phase 3
2015
50
Phase 1
2011
170
North American Oil Sands Ft. Sask Area Upgrader
Phase 2
2015
230
Phase 1
2011
80
Phase 2
2015
80
Total SA
Phase 1
2011
50
Phase 2
2013
50
Another Upgrader
Phase 1
2011
50
Phase 2
2013
50
Redwater
Ft Sask
Ft Sask
10
2.3 Study Objectives
The objective of this study was to prepare high-level estimates of the quantity counts for major equipment
and bulks required to construct the above listed facilities. This information would be useful in identifying supply
requirements and gaps in local production. The tool used to develop these estimates is in a form that allows
for some “what-if” scenario development that would test the impact on quantities/time for project/phase
schedule changes and for additions/deletions of upgraders or phased expansion of a given upgrader.
There are a number of components in the facility lifecycle cost, but in general these can be broken into
three main cost categories:
1.The Capital Cost (CAPEX) for the installation of the facility
2.The Annual Operating and Maintenance Cost for the operation of the facility
(typically 2-3% of the CAPEX in current dollars)
3.Sustaining Capital over the plant’s lifecycle
(annual costs typically 2% of CAPEX in current dollars)
This study focused its efforts on establishing the quantities for components used in the initial capital cost.
Operating and maintenance, and sustaining capital were dealt with as factors of the initial capital cost.
It is important to note that it is beyond the scope of this project to size the major equipment and bulks.
Each upgrader and their individual units will be engineered for purpose and the final flow sheet, equipment
list, and sizing of equipment will be the outcome of engineering work by the operator, the selected process
technology licensors and the appointed engineering procurement and construction.
11
3. METHODOLOGY
The quantification of major equipment and bulks prior to completion of the engineering of these facilities is an
educated estimate and is based on a minimal amount of available information. There is considerable difference
in the processing schemes that have been announced by the upgrader proponents. Therefore, the estimates
need to consider the choice of processing scheme in arriving at the quantity counts.
Upgrader operators have provided block flow diagrams that illustrate the types of processing units proposed
for their facilities in their public disclosure documents. Generally the types of processes used are common to
the bitumen upgrading and petroleum refining industry. Therefore, generic flowsheets provide a reasonable
“first guess” as to the equipment types and numbers found in each process unit. Variants of each type are
also available from process technology licensors and these have a great similarity in the equipment types and
counts. Colt Engineering has experience in working with a great number of process licensors and existing
bitumen upgrader (and refinery) processes. The general industry knowledge gained from this exposure formed
the basis much of the detail for this study.
3.1 Type of Process Units Encountered in Bitumen Upgrading
The types of processes used in bitumen upgraders can be broken into two major categories: Processing Units
and Offsites & Utilities. Processing units are those units directly involved in the conversion and separation of
bitumen into higher quality material. Offsites & Utilities are the processes, equipment, and facilities that support
the operation of the processing units. The type of processing units and offsites & utilities found in the GEA
upgrader public disclosure documents include:
Processing Units
•
Diluent Recovery
•
Vacuum
•
Deasphalt
•
Coking
•
Hydrocracking
•
Hydrotreating
•
Gas Recovery Unit
•
Gas Sweetening Units
•
Sulphur Recovery
•
Hydrogen Production
•
Sour Water Stripping
•
Coke Gasification
Offsites & Utilities
•
Electrical Distribution
•
Cooling water
•
Flare System
•
Fuel Gas
•
Effluent Treating
•
Boiler / Power
•
Control Rooms (I/C)
•
Buildings
•
Interconnecting Pipes
•
Tank Farm
•
Blending/Loading Racks
•
Plant Air
12
4.UPGRADER INFORMATION DATA SOURCES
The data for the process configuration of each upgrader was obtained from public disclosure documents that
many of the upgrader proponents have filed for regulatory approval, stakeholder consultation, or from public
presentations made by these companies. Each upgrader proponent has unique requirements, which drive the
considerable variations in the configuration of each of these proposed facilities.
In most cases a block flow process diagram was supplied. These describe in general terms the types of
processes and how they will be configured to make up the entire upgrading facility. The flow scheme and
corresponding equipment lists for each type of process were developed based on generic flowsheets obtained
from process technology licensors and these were supplemented with additional process engineering
experience based on Colt Engineering’s work in a number of bitumen upgraders and refineries that process
bitumen-based feedstocks.
In addition to the processing units, each facility will require both utility and offsite facilities to support the
operation of the processing units, maintenance and administration functions at each facility. The offsites and
utility systems at each facility are expected to be quite similar in makeup at each upgrader and simplified
generic flowsheets for each system were assumed.
The following is a brief summary of the information obtained for each of the GEA upgrader projects.
4.1 Petro-Canada Edmonton Refinery- Refinery Conversion Project
The Petro-Canada Refinery Conversion Project (RCP) was added to the list of GEA upgraders since the
objective of the project is to replace the feedstock from the existing 85,000 barrels per day (bpd) of conventional
oil with a feedstock that is comprised of a combination of sour synthetic crude oil and diluted bitumen/heavy oil.
When onstream in 2008, this will result in a 135,000 bpd feed based entirely on bitumen derived feedstocks.
The RCP involves the replacement of the existing process units: crude unit, vacuum unit, delayed coker, amine
unit, sulphur plant and sour water stripping. In addition, a number of units were revamped and offsites and
utilities added. For this study only the equipment in the new process units were included in the equipment count.
4.2 BA Energy Heartland Upgrader
BA Energy’s Heartland Upgrader is the first “merchant upgrader” to be built in Alberta. Value Creation, the owner
of BA Energy and the developer of the proprietary technology used in this upgrader, believes the simplified
process system used will dramatically reduce the capital and operating costs of producing SCO. BA expects
the first 54,400 bpd phase of the upgrader to be onstream in 2008. The project will have three phases to bring
upgrading capacity to over 150,000 bpd (assumed to be three parallel trains).
13
The process uses a proprietary solvent deasphalting process (ADC) to recover the lighter hydrocarbons
from bitumen, followed by a proprietary pyrolysis technology to upgrade the deasphalted oil residue and
simultaneously remove sulphur from the pyrolysis products.
4.3 Scotford Upgrader Expansion Project
Shell Canada is moving forward with the 135,000 bpd debottleneck and expansion of the Scotford Upgrader
(with partners Chevron Canada and Western Oil Sands). It estimated that it will be onstream in 2010.
The Scotford Upgrader Expansion Project will involve:
•
debottlenecking the existing upgrader facilities
•
adding a third bitumen processing train with a nominal capacity of 90,000 bpd of bitumen feed
The third bitumen processing train will be similar to the existing upgrader processing trains and will incorporate
the following major components:
•
atmospheric and vacuum (A&V) distillation unit
•
residue hydroconversion (RHC) unit with an integrated hydrotreater (IHT)
•
solvent deasphalting (SDA) unit
•
supporting process units for hydrogen manufacturing and sulphur recovery
•
supporting utility systems and offsites, such as steam, electrical power, fuel
•
gas, water, flare, blending, storage and rail facilities
The third processing train will be integrated into the operation of the existing upgrader and will use and build
on existing utilities and infrastructure, where possible.
14
4.4 Synenco/SinoCanada Northern Lights Upgrader
Synenco proposes to build in two phases a 100,000 bpd upgrader to process bitumen from its mining/extraction
complex north of Fort McMurray. The project will use carbon rejection and hydrogen addition to produce high
quality SCO.
Process Flow Diagram
4.5 Petro-Canada/UTS/TeckCominco Fort Hills Upgrader
The bitumen-processing capacity of the Fort Hills Upgrader Project will be 165,000 bpd during the first phase.
In subsequent phases, capacity will be expanded to reach 340,000 bpd. The first phase will utilize standard
carbon rejection and hydrogen addition technologies (as shown in the diagram below). Phase two may
incorporate solvent deasphalting and asphaltene gasification.
15
4.6 Northwest Upgrading
Northwest is the second “merchant upgrader” proposed for the GEA. This facility will be built in two phases
based on the principle of hydrogen addition as shown in the flow sheet below. The first phase is expected to
come online in 2010. This upgrader will be one of the first facilities in Alberta to utilize gasification technology.
Source: Individual Company Investor Publications
16
4.7 North American Oil Sands
North American is proposing to build their upgrader on land they own in the Fort Saskatchewan area.
Their proposed development is as follows
Capacity
Phase 1: 76,000 bpd of bitumen, proposed to startup in 2012
Phase 2: Increase capacity up to 220,000 bpd, proposed to startup in 2015
Configuration
Phase 1: coking / hydro-treating
Phase 2: coking / hydro-processing / coke gasification
The process configuration of this facility is anticipated to be as follows:
4.8 Total SA and “Other” Upgrader
Total SA has made known its intention to consider building an Edmonton area bitumen upgrader. As yet there
are no regulatory applications filed. Other proponents are considering Edmonton area upgrading facilities.
For the purposes of this study it was assumed that at least one other project would emerge between 2007
and 2015. It was also assumed that the configuration of these upgraders would be carbon rejection with
hydrotreating to produce a SCO.
17
5.ESTIMATED COSTS OF THE PROPOSED UPGRADING FACILITIES
GEA bitumen upgraders have provided estimates of their capital costs to bring these facilities onstream.
A summary of the data recently (March 2007) presented by the Alberta Industrial Heartland Association
is as follows:
Table 5:
Upgrader Cost Estimates
Proponent
Throughput bpd
Cost $/bbl
(billions)
BA Energy
163,000
$ 1.8
11,042
Northwest Upgrading
150,000
$ 2.0
16,000
Fort Hills
165,000
$ 6.0
36,363
Shell
135,000
$ 5.0
41,481
Synenco
100,000
$ 3.6
36,000
North American
165,000
$ 4.0
24,242
85,000
$ 4.1
48,235
963,000
$ 27.5
28,556
Petro-Canada RCP
Sum Total
18
Table 6:
Upgrader Cost Breakdowns
Typical Upgrader/Refinery Cost Breakdowns
Component Cost Ranges
Percentage of
total installed cost
Low Range based on
$40 billion in CAPEX
Low Range based on
$70 billion in CAPEX
Equipment
heaters
2
0.800
1.400
heat exchangers
5
2.000
3.500
vessels
7
2.800
4.900
pumps
7
2.800
4.900
compressors
1
0.400
0.700
mechanical equipment
1
0.400
0.700
structural steel
2
0.800
1.400
piping
13
5.200
9.100
electrical
5
2.000
3.500
instruments and controls
2
0.800
1.400
insulation/paint
2
0.800
1.400
Total
47
18.800
32.900
Bulks
Processing Units
Based on the information available for each proposed upgrader, a list of all the types of processing units that
would be employed was developed. These include units that convert bitumen into synthetic crude oil and the
supporting utility and offsite facilities that are needed to maintain operations.
A process flow sheet for each process and utility unit listed above was obtained from process technology
licensors and some were available based on Colt Engineering working experience with units of these types.
A summary of the quantity of major equipment for each type of process is provided on the table below.
19
20
Positive Displacement
HP Alloy
Coke Drums
Sulphur Plant
Trayed Tower
Packed Tower
Horizontal Separator
Reactors
Vessels
0
Amine
4
0
2
0
0
0
3
9
0
Coking
5
0
3
0
2
0
0
43
0
Diluent
Recovery
1
0
2
0
0
0
3
21
0
Gas
Recovery
7
4
5
0
0
0
0
33
0
1
8
5
0
0
0
0
21
3
Mild
Hydrocracking
21
0
5
0
0
2
2
13
0
Hydrogen
& PSA
4
4
0
0
0
0
4
7
7
Light gas oil
Hydrotreater
15
0
3
0
0
4
0
9
2
Naphtha
Hydrtreating
1
0
1
0
0
3
0
4
4
Residue
Hydrocracking
28
0
5
0
0
2
7
33
LP Alloy (Shell/Tube)
Carbon Steel (Shell/Tube)
Air Cooled
Plate/Frame
Hairpin
Fired Heater
Cooling Tower
Boilers
Fan/Blower
Reciprocating
Screw
Axial
Large (>50KBBL)
Intermediate
(10KBBL> >50KBBL)
Small (<50KBBL)
Tanks
Total
Centrifugal
Compressor
34
1
0
0
0
0
0
0
0
88
3
0
0
0
0
0
0
1
80
2
0
0
0
0
0
2
0
115
0
0
0
0
0
0
0
1
5
0
2
0
0
18
36
0
0
0
0
4
0
9
14
0
4
0
0
0
14
0
12
87
0
0
0
0
0
0
0
96
0
0
0
0
2
0
1
13
3
0
0
1
0
0
4
16
0
1
0
3
0
2
0
0
4
14
0
21
5
0
0
1
0
0
0
0
2
11
0
0
Heat Exchangers HP Alloy (Shell/Tube)
81
6
0
0
0
0
3
4
0
1
1
0
2
0
0
0
8
2
12
107
0
0
0
0
0
0
4
1
2
0
4
0
0
18
11
0
21
41
2
0
0
0
0
0
0
1
2
0
1
0
0
4
6
0
10
6
130
0
0
0
0
0
0
0
2
4
0
3
0
0
0
21
0
0
0
1
2
14
0
Solvent
Deashpalt
1
0
69
2
0
0
0
0
0
0
0
4
0
2
0
0
3
14
49
0
0
0
0
0
0
0
0
0
2
0
0
0
22
0
0
3
0
Sour Water
Stripping
5
0
2
0
0
0
0
17
1
0
0
6
0
0
3
14
0
Sulfur
Recovery
with Tail Gas
33
0
0
0
0
0
0
0
0
0
0
0
0
0
4
4
0
0
65
3
0
0
0
0
0
6
0
0
0
4
0
0
2
1
18
0
2
1
7
4
0
2
2
0
0
4
3
19
2
Heavy gas oil
Hydrotreater
Vertical Separator
2
7
7
3
7
14
23
8
4
15
10
HP Multistage Centrifugal
LP/MP Centrifugal
Pumps
Description
Unit
Gasification
Process Unit Major Equipment Quantities by Unit
Table 7:
95
0
0
0
0
0
0
5
0
0
0
2
0
0
3
24
2
0
19
4
0
2
0
0
0
5
29
0
Vacuum
6.CONCLUSION
The construction of bitumen upgraders presents a substantial economic opportunity for the GEA, both in the
initial development period and during the operating life of the projects. Based on the cost estimates found in
this study, it is apparent that the base procurement demands of the upgraders during the construction years
of 2008 to 2015 would amount to between C$18.8 billion and $32.9 billion, excluding pipeline investment.
Furthermore, the demand for supplies, services and capital upgrades could very easily exceed $100 billion
over the 30 to 50 year life expectancy of these plants. Such a level of sustained economic activity will
generate significant supply responsibilities and all parties would do well to engage in supply chain planning
and development.
The growth in the GEA due to bitumen upgrader development also provides an opportunity for Alberta to
expand its existing heavy industrial manufacturing base, generating both direct and indirect economic benefits
from oil sands developments. Given the size of the developments, there is significant opportunity to leverage
off this demand to grow a world-class heavy industrial manufacturing hub.
21
7.APPENDICES
Appendix A:
Control Valves
Bulk Class
Bulk Item
Total
Year
Control Valves
Control Valves
914
2007
Control Valves
Control Valves
2327
2009
Control Valves
Control Valves
2669
2010
Control Valves
Control Valves
2512
2011
Control Valves
Control Valves
2250
2012
Control Valves
Control Valves
2635
2013
Control Valves
Control Valves
4274
2014
22
Appendix B:
Flow Instruments
Bulk Class
Bulk Item
Year
Total
Flow Instruments
FIC Local
2007
1
Flow Instruments
FIC Local
2009
2
Flow Instruments
FIC Local
2010
3
Flow Instruments
FIC Local
2011
2
Flow Instruments
FIC Local
2012
2
Flow Instruments
FIC Local
2013
3
Flow Instruments
FIC Local
2014
4
Flow Instruments
FIT DP Elec.
2007
423
Flow Instruments
FIT DP Elec.
2009
1048
Flow Instruments
FIT DP Elec.
2010
1244
Flow Instruments
FIT DP Elec.
2011
1191
Flow Instruments
FIT DP Elec.
2012
1022
Flow Instruments
FIT DP Elec.
2013
1234
Flow Instruments
FIT DP Elec.
2014
2022
Flow Instruments
FIT DP Pneu.
2007
11
Flow Instruments
FIT DP Pneu.
2009
69
Flow Instruments
FIT DP Pneu.
2010
92
Flow Instruments
FIT DP Pneu.
2011
113
Flow Instruments
FIT DP Pneu.
2012
70
Flow Instruments
FIT DP Pneu.
2013
92
Flow Instruments
FIT DP Pneu.
2014
181
Flow Instruments
Flow Switch
2007
15
Flow Instruments
Flow Switch
2009
38
Flow Instruments
Flow Switch
2010
44
Flow Instruments
Flow Switch
2011
38
Flow Instruments
Flow Switch
2012
40
Flow Instruments
Flow Switch
2013
44
Flow Instruments
Flow Switch
2014
71
Flow Instruments
Rotameter
2007
10
Flow Instruments
Rotameter
2009
20
Flow Instruments
Rotameter
2010
30
Flow Instruments
Rotameter
2011
20
Flow Instruments
Rotameter
2012
20
Flow Instruments
Rotameter
2013
30
Flow Instruments
Rotameter
2014
40
Appendix C:
Analyzers
Bulk Class
Bulk Item
Total
Year
Analyzers
Analyzer
7
2007
Analyzers
Analyzer
30
2009
Analyzers
Analyzer
35
2010
Analyzers
Analyzer
37
2011
Analyzers
Analyzer
28
2012
Analyzers
Analyzer
34
2013
Analyzers
Analyzer
62
2014
Appendix D:
Level Instruments
Bulk Class
Bulk Item
Year
Total
Level Instruments
Level Controller Pneu.
2007
5
Level Instruments
Level Controller Pneu.
2009
10
Level Instruments
Level Controller Pneu.
2010
15
Level Instruments
Level Controller Pneu.
2011
10
Level Instruments
Level Controller Pneu.
2012
10
Level Instruments
Level Controller Pneu.
2013
15
Level Instruments
Level Controller Pneu.
2014
20
Level Instruments
Level Gauge
2007
292
Level Instruments
Level Gauge
2009
942
Level Instruments
Level Gauge
2010
948
Level Instruments
Level Gauge
2011
966
Level Instruments
Level Gauge
2012
820
Level Instruments
Level Gauge
2013
918
Level Instruments
Level Gauge
2014
1528
Level Instruments
Level Switch
2007
28
Level Instruments
Level Switch
2009
120
Level Instruments
Level Switch
2010
140
Level Instruments
Level Switch
2011
148
Level Instruments
Level Switch
2012
112
Level Instruments
Level Switch
2013
136
Level Instruments
Level Switch
2014
248
Level Instruments
Level Tape
2007
31
Level Instruments
Level Tape
2009
56
Level Instruments
Level Tape
2010
83
Level Instruments
Level Tape
2011
63
Level Instruments
Level Tape
2012
74
Level Instruments
Level Tape
2013
77
Level Instruments
Level Tape
2014
114
Level Instruments
Level Transmitter Elec.
2007
150
Level Instruments
Level Transmitter Elec.
2009
471
Level Instruments
Level Transmitter Elec.
2010
478
Level Instruments
Level Transmitter Elec.
2011
487
Level Instruments
Level Transmitter Elec.
2012
418
Level Instruments
Level Transmitter Elec.
2013
463
Level Instruments
Level Transmitter Elec.
2014
772
Appendix E:
Orifice Plates
Bulk Class
Bulk Item
Total
Year
Orifice Plates
Orifice Plate
443
2007
Orifice Plates
Orifice Plate
1127
2009
Orifice Plates
Orifice Plate
1348
2010
Orifice Plates
Orifice Plate
1307
2011
Orifice Plates
Orifice Plate
1106
2012
Orifice Plates
Orifice Plate
1339
2013
Orifice Plates
Orifice Plate
2216
2014
Appendix F:
Pressure Instruments
Bulk Class
Bulk Item
Total
Year
Pressure Instruments
DP Gauge
2007
25
Pressure Instruments
DP Gauge
2009
57
Pressure Instruments
DP Gauge
2010
67
Pressure Instruments
DP Gauge
2011
58
Pressure Instruments
DP Gauge
2012
54
Pressure Instruments
DP Gauge
2013
67
Pressure Instruments
DP Gauge
2014
103
Pressure Instruments
DP Transmitter
2007
81
Pressure Instruments
DP Transmitter
2009
233
Pressure Instruments
DP Transmitter
2010
277
Pressure Instruments
DP Transmitter
2011
270
Pressure Instruments
DP Transmitter
2012
218
Pressure Instruments
DP Transmitter
2013
269
Pressure Instruments
DP Transmitter
2014
441
Pressure Instruments
Local PIC
2007
7
Pressure Instruments
Local PIC
2009
30
Pressure Instruments
Local PIC
2010
35
Pressure Instruments
Local PIC
2011
37
Pressure Instruments
Local PIC
2012
28
Pressure Instruments
Local PIC
2013
34
Pressure Instruments
Local PIC
2014
62
Pressure Instruments
Pressure Gauge
2007
651
Pressure Instruments
Pressure Gauge
2009
1586
Pressure Instruments
Pressure Gauge
2010
1786
Pressure Instruments
Pressure Gauge
2011
1649
Pressure Instruments
Pressure Gauge
2012
1520
Pressure Instruments
Pressure Gauge
2013
1767
Pressure Instruments
Pressure Gauge
2014
2812
Pressure Instruments
Pressure Switch
2007
103
Pressure Instruments
Pressure Switch
2009
296
Pressure Instruments
Pressure Switch
2010
346
Pressure Instruments
Pressure Switch
2011
327
Pressure Instruments
Pressure Switch
2012
280
Pressure Instruments
Pressure Switch
2013
339
Pressure Instruments
Pressure Switch
2014
559
Chart continues on next page
Appendix F:
Pressure Instruments (Continued from previous page)
Bulk Class
Bulk Item
Year
Total
Pressure Instruments
Pressure Transmitter
2007
149
Pressure Instruments
Pressure Transmitter
2009
484
Pressure Instruments
Pressure Transmitter
2010
574
Pressure Instruments
Pressure Transmitter
2011
576
Pressure Instruments
Pressure Transmitter
2012
472
Pressure Instruments
Pressure Transmitter
2013
559
Pressure Instruments
Pressure Transmitter
2014
959
Bulk Class
Bulk Item
Total
Year
Regulating Valves
Regulating Valves
55
2007
Regulating Valves
Regulating Valves
128
2009
Regulating Valves
Regulating Valves
168
2010
Regulating Valves
Regulating Valves
142
2011
Regulating Valves
Regulating Valves
146
2012
Regulating Valves
Regulating Valves
161
2013
Regulating Valves
Regulating Valves
255
2014
Appendix G:
Regulating Valves
Appendix H:
Safety Valves
Bulk Class
Bulk Item
Total
Year
Safety Valves
Safety Valves
766
2007
Safety Valves
Safety Valves
2008
Safety Valves
Safety Valves
1895
2009
Safety Valves
Safety Valves
2100
2010
Safety Valves
Safety Valves
1941
2011
Safety Valves
Safety Valves
1820
2012
Safety Valves
Safety Valves
2068
2013
Safety Valves
Safety Valves
3261
2014
Bulk Class
Bulk Item
Year
Total
Solenoids
Solenoid
2007
127
Solenoids
Solenoid
2009
444
Solenoids
Solenoid
2010
519
Solenoids
Solenoid
2011
523
Solenoids
Solenoid
2012
416
Solenoids
Solenoid
2013
508
Solenoids
Solenoid
2014
888
Appendix I:
Solenoids
Appendix J:
Temperature Instruments
Bulk Class
Bulk Item
Year
Total
Temperature Instruments
BS IR
2007
22
Temperature Instruments
BS IR
2009
68
Temperature Instruments
BS IR
2010
79
Temperature Instruments
BS IR
2011
75
Temperature Instruments
BS IR
2012
68
Temperature Instruments
BS IR
2013
78
Temperature Instruments
BS IR
2014
133
Temperature Instruments
Local TI Gauge
2007
1019
Temperature Instruments
Local TI Gauge
2009
2531
Temperature Instruments
Local TI Gauge
2010
2849
Temperature Instruments
Local TI Gauge
2011
2626
Temperature Instruments
Local TI Gauge
2012
2456
Temperature Instruments
Local TI Gauge
2013
2794
Temperature Instruments
Local TI Gauge
2014
4405
Temperature Instruments
Local TIC Loop
2007
21
Temperature Instruments
Local TIC Loop
2009
46
Temperature Instruments
Local TIC Loop
2010
53
Temperature Instruments
Local TIC Loop
2011
46
Temperature Instruments
Local TIC Loop
2012
54
Temperature Instruments
Local TIC Loop
2013
54
Temperature Instruments
Local TIC Loop
2014
86
Temperature Instruments
Temperature Switch
2007
80
Temperature Instruments
Temperature Switch
2009
224
Temperature Instruments
Temperature Switch
2010
261
Temperature Instruments
Temperature Switch
2011
240
Temperature Instruments
Temperature Switch
2012
218
Temperature Instruments
Temperature Switch
2013
253
Temperature Instruments
Temperature Switch
2014
409
Temperature Instruments
Temperature Transmitter
2007
964
Temperature Instruments
Temperature Transmitter
2009
2226
Temperature Instruments
Temperature Transmitter
2010
2699
Temperature Instruments
Temperature Transmitter
2011
2411
Temperature Instruments
Temperature Transmitter
2012
2288
Temperature Instruments
Temperature Transmitter
2013
2658
Temperature Instruments
Temperature Transmitter
2014
4235
Chart continues on next page
Appendix J:
Temperature Instruments (Continued from previous page)
Bulk Class
Bulk Item
Year
Total
Temperature Instruments
Testwell
2007
662
Temperature Instruments
Testwell
2009
1380
Temperature Instruments
Testwell
2010
1750
Temperature Instruments
Testwell
2011
1461
Temperature Instruments
Testwell
2012
1508
Temperature Instruments
Testwell
2013
1733
Temperature Instruments
Testwell
2014
2646
Temperature Instruments
Thermowell
2007
2084
Temperature Instruments
Thermowell
2009
5027
Temperature Instruments
Thermowell
2010
5862
Temperature Instruments
Thermowell
2011
5323
Temperature Instruments
Thermowell
2012
5016
Temperature Instruments
Thermowell
2013
5759
Temperature Instruments
Thermowell
2014
9135
Appendix K:
Heat Exchangers
Major Type
Equipment
Year
Number
Heat Exchangers
Air Cooled
2007
45
Heat Exchangers
Air Cooled
2009
87
Heat Exchangers
Air Cooled
2010
135
Heat Exchangers
Air Cooled
2011
98
Heat Exchangers
Air Cooled
2012
124
Heat Exchangers
Air Cooled
2013
134
Heat Exchangers
Air Cooled
2014
206
Heat Exchangers
Boilers
2007
5
Heat Exchangers
Boilers
2009
4
Heat Exchangers
Boilers
2010
9
Heat Exchangers
Boilers
2011
7
Heat Exchangers
Boilers
2012
10
Heat Exchangers
Boilers
2013
9
Heat Exchangers
Boilers
2014
14
Heat Exchangers
Carbon Steel (Shell/Tube)
2007
152
Heat Exchangers
Carbon Steel (Shell/Tube)
2009
309
Heat Exchangers
Carbon Steel (Shell/Tube)
2010
364
Heat Exchangers
Carbon Steel (Shell/Tube)
2011
312
Heat Exchangers
Carbon Steel (Shell/Tube)
2012
296
Heat Exchangers
Carbon Steel (Shell/Tube)
2013
375
Heat Exchangers
Carbon Steel (Shell/Tube)
2014
563
Heat Exchangers
Cooling Tower
2007
5
Heat Exchangers
Cooling Tower
2009
10
Heat Exchangers
Cooling Tower
2010
15
Heat Exchangers
Cooling Tower
2011
10
Heat Exchangers
Cooling Tower
2012
10
Heat Exchangers
Cooling Tower
2013
15
Heat Exchangers
Cooling Tower
2014
20
Heat Exchangers
Fired Heater
2007
15
Heat Exchangers
Fired Heater
2009
38
Heat Exchangers
Fired Heater
2010
44
Heat Exchangers
Fired Heater
2011
38
Heat Exchangers
Fired Heater
2012
40
Heat Exchangers
Fired Heater
2013
44
Heat Exchangers
Fired Heater
2014
71
Chart continues on next page
Appendix K:
Heat Exchangers (Continued from previous page)
Major Type
Equipment
Year
Number
Heat Exchangers
HP Alloy (Shell/Tube)
2007
10
Heat Exchangers
HP Alloy (Shell/Tube)
2009
66
Heat Exchangers
HP Alloy (Shell/Tube)
2010
88
Heat Exchangers
HP Alloy (Shell/Tube)
2011
79
Heat Exchangers
HP Alloy (Shell/Tube)
2012
92
Heat Exchangers
HP Alloy (Shell/Tube)
2013
76
Heat Exchangers
HP Alloy (Shell/Tube)
2014
135
Heat Exchangers
LP Alloy (Shell/Tube)
2007
64
Heat Exchangers
LP Alloy (Shell/Tube)
2009
87
Heat Exchangers
LP Alloy (Shell/Tube)
2010
108
Heat Exchangers
LP Alloy (Shell/Tube)
2011
89
Heat Exchangers
LP Alloy (Shell/Tube)
2012
90
Heat Exchangers
LP Alloy (Shell/Tube)
2013
108
Heat Exchangers
LP Alloy (Shell/Tube)
2014
151
Heat Exchangers
Process Steam Generator
2007
7
Heat Exchangers
Process Steam Generator
2009
30
Heat Exchangers
Process Steam Generator
2010
35
Heat Exchangers
Process Steam Generator
2011
37
Heat Exchangers
Process Steam Generator
2012
28
Heat Exchangers
Process Steam Generator
2013
34
Heat Exchangers
Process Steam Generator
2014
62
Appendix L:
Power
Major Type
Equipment
Number
Year
Power
Electric Motors
310
2007
Power
Electric Motors
657
2009
Power
Electric Motors
772
2010
Power
Electric Motors
704
2011
Power
Electric Motors
662
2012
Power
Electric Motors
772
2013
Power
Electric Motors
1222
2014
Appendix M:
Pumps
Major Type
Equipment
Year
Number
Pumps
HP Multistage Centrifugal
2007
9
Pumps
HP Multistage Centrifugal
2009
39
Pumps
HP Multistage Centrifugal
2010
45
Pumps
HP Multistage Centrifugal
2011
43
Pumps
HP Multistage Centrifugal
2012
44
Pumps
HP Multistage Centrifugal
2013
41
Pumps
HP Multistage Centrifugal
2014
74
Pumps
LP/MP Centrifugal
2007
273
Pumps
LP/MP Centrifugal
2009
542
Pumps
LP/MP Centrifugal
2010
658
Pumps
LP/MP Centrifugal
2011
593
Pumps
LP/MP Centrifugal
2012
546
Pumps
LP/MP Centrifugal
2013
663
Pumps
LP/MP Centrifugal
2014
1034
Pumps
Positive Displacement
2007
18
Pumps
Positive Displacement
2009
52
Pumps
Positive Displacement
2010
40
Pumps
Positive Displacement
2011
47
Pumps
Positive Displacement
2012
42
Pumps
Positive Displacement
2013
41
Pumps
Positive Displacement
2014
75
Appendix N:
Pressure Vessels
Major Type
Equipment
Year
Number
Pressure Vessels
Bullet
2007
1
Pressure Vessels
Bullet
2009
2
Pressure Vessels
Bullet
2010
3
Pressure Vessels
Bullet
2011
2
Pressure Vessels
Bullet
2012
2
Pressure Vessels
Bullet
2013
3
Pressure Vessels
Bullet
2014
4
Pressure Vessels
Horizontal Separator
2007
38
Pressure Vessels
Horizontal Separator
2009
161
Pressure Vessels
Horizontal Separator
2010
140
Pressure Vessels
Horizontal Separator
2011
142
Pressure Vessels
Horizontal Separator
2012
110
Pressure Vessels
Horizontal Separator
2013
135
Pressure Vessels
Horizontal Separator
2014
226
Pressure Vessels
Packed Tower
2007
4
Pressure Vessels
Packed Tower
2009
12
Pressure Vessels
Packed Tower
2010
16
Pressure Vessels
Packed Tower
2011
12
Pressure Vessels
Packed Tower
2012
16
Pressure Vessels
Packed Tower
2013
12
Pressure Vessels
Packed Tower
2014
16
Pressure Vessels
Sphere
2007
1
Pressure Vessels
Sphere
2009
2
Pressure Vessels
Sphere
2010
3
Pressure Vessels
Sphere
2011
2
Pressure Vessels
Sphere
2012
2
Pressure Vessels
Sphere
2013
3
Pressure Vessels
Sphere
2014
4
Pressure Vessels
Trayed Tower
2007
21
Pressure Vessels
Trayed Tower
2009
53
Pressure Vessels
Trayed Tower
2010
59
Pressure Vessels
Trayed Tower
2011
57
Pressure Vessels
Trayed Tower
2012
44
Pressure Vessels
Trayed Tower
2013
59
Pressure Vessels
Trayed Tower
2014
94
Chart continues on next page
Appendix N:
Pressure Vessels (Continued from previous page)
Major Type
Equipment
Year
Number
Pressure Vessels
Vertical Separator
2007
74
Pressure Vessels
Vertical Separator
2009
211
Pressure Vessels
Vertical Separator
2010
218
Pressure Vessels
Vertical Separator
2011
231
Pressure Vessels
Vertical Separator
2012
208
Pressure Vessels
Vertical Separator
2013
213
Pressure Vessels
Vertical Separator
2014
358
Major Type
Equipment
Year
Number
Reactors
Coke Drums
2007
2
Reactors
Coke Drums
2010
2
Reactors
Coke Drums
2011
2
Reactors
Coke Drums
2012
4
Reactors
Coke Drums
2013
2
Reactors
Coke Drums
2014
4
Reactors
HP Alloy
2007
3
Reactors
HP Alloy
2009
23
Reactors
HP Alloy
2010
30
Reactors
HP Alloy
2011
37
Reactors
HP Alloy
2012
22
Reactors
HP Alloy
2013
30
Reactors
HP Alloy
2014
59
Reactors
Sulphur Plant
2007
6
Reactors
Sulphur Plant
2009
12
Reactors
Sulphur Plant
2010
12
Reactors
Sulphur Plant
2011
12
Reactors
Sulphur Plant
2012
12
Reactors
Sulphur Plant
2013
12
Reactors
Sulphur Plant
2014
24
Appendix O:
Reactors
Appendix P:
Steam Turbines
Major Type
Equipment
Number
Year
Steam Turbines
Steam Turbines
18
2007
Steam Turbines
Steam Turbines
42
2009
Steam Turbines
Steam Turbines
48
2010
Steam Turbines
Steam Turbines
44
2011
Steam Turbines
Steam Turbines
42
2012
Steam Turbines
Steam Turbines
48
2013
Steam Turbines
Steam Turbines
76
2014
Appendix Q:
Tanks
Major Type
Equipment
Year
Number
Tanks
Large > 50 kbbl
2007
15
Tanks
Large > 50 kbbl
2009
30
Tanks
Large > 50 kbbl
2010
45
Tanks
Large > 50 kbbl
2011
30
Tanks
Large > 50 kbbl
2012
30
Tanks
Large > 50 kbbl
2013
45
Tanks
Large > 50 kbbl
2014
60
Tanks
Medium > 10 kbbl < 50 kbbl
2007
3
Tanks
Medium > 10 kbbl < 50 kbbl
2009
6
Tanks
Medium > 10 kbbl < 50 kbbl
2010
9
Tanks
Medium > 10 kbbl < 50 kbbl
2011
6
Tanks
Medium > 10 kbbl < 50 kbbl
2012
6
Tanks
Medium > 10 kbbl < 50 kbbl
2013
9
Tanks
Medium > 10 kbbl < 50 kbbl
2014
12
Tanks
Small < 10 kbbl
2007
13
Tanks
Small < 10 kbbl
2009
20
Tanks
Small < 10 kbbl
2010
29
Tanks
Small < 10 kbbl
2011
27
Tanks
Small < 10 kbbl
2012
38
Tanks
Small < 10 kbbl
2013
23
Tanks
Small < 10 kbbl
2014
42
Appendix R:
Compressors
Major Type
Equipment
Year
Number
Compressors
Centrifugal
2007
7
Compressors
Centrifugal
2009
15
Compressors
Centrifugal
2010
19
Compressors
Centrifugal
2011
14
Compressors
Centrifugal
2012
12
Compressors
Centrifugal
2013
19
Compressors
Centrifugal
2014
27
Compressors
Fan/Blower
2007
21
Compressors
Fan/Blower
2009
46
Compressors
Fan/Blower
2010
53
Compressors
Fan/Blower
2011
46
Compressors
Fan/Blower
2012
54
Compressors
Fan/Blower
2013
54
Compressors
Fan/Blower
2014
86
Compressors
Reciprocating
2009
5
Compressors
Reciprocating
2010
5
Compressors
Reciprocating
2011
5
Compressors
Reciprocating
2012
6
Compressors
Reciprocating
2013
2
Compressors
Reciprocating
2014
2
Appendix S:
Flare
Major Type
Equipment
Number
Year
Flare
Flare Derrek
1
2007
Flare
Flare Derrek
2
2009
Flare
Flare Derrek
3
2010
Flare
Flare Derrek
2
2011
Flare
Flare Derrek
2
2012
Flare
Flare Derrek
3
2013
Flare
Flare Derrek
4
2014
Flare
Flare Line/Tip
3
2007
Flare
Flare Line/Tip
6
2009
Flare
Flare Line/Tip
9
2010
Flare
Flare Line/Tip
6
2011
Flare
Flare Line/Tip
6
2012
Flare
Flare Line/Tip
9
2013
Flare
Flare Line/Tip
12
2014