PLAINS CO2 REDUCTION (PCOR) PARTNERSHIP 

(PHASE II) –ZAMA FIELD VALIDATION TEST 

REGIONAL TECHNOLOGY IMPLEMENTATION 

PLAN 

Task 3 – Deliverable D52 

Prepared for: 

Andrea McNemar 

U.S. Department of Energy 

National Energy Technology Laboratory 

3610 Collins Ferry Road 

PO Box 880, MS P03D 

Morgantown, WV 26507-0880 Prepared by: 

 

Cooperative Agreement No. DE-FC26-05NT42592 Steven A. Smith 

James A. Sorensen 

Edward N. Steadman 

John A. Harju 

Energy & Environmental Research Center 

University of North Dakota 

15 North 23rd Street, Stop 9018 

Grand Forks, ND 58202-9018 

Bill Jackson 

Doug Nimchuk 

Apache Canada, Ltd. 

No. 1000, 700 9th Avenue Southwest 

CALGARY, AB T2P 3V4 

CANADA 

 

 Lyle Burke 

RPS Energy 

800 5th Avenue Southwest, Suite 1400 

CALGARY, AB T2P 3T6 

CANADA 

2010-EERC-05-03 September 2009 

Approved
DOE DISCLAIMER

 This report was prepared as an account of work sponsored by an agency of the United 

States Government. Neither the United States Government, nor any agency thereof, nor any of 

their employees makes any warranty, express or implied, or assumes any legal liability or 

responsibility for the accuracy, completeness, or usefulness of any information, apparatus, 

product, or process disclosed or represents that its use would not infringe privately owned rights. 

Reference herein to any specific commercial product, process, or service by trade name, 

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recommendation, or favoring by the United States Government or any agency thereof. The views 

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States Government or any agency thereof. 

 This report is available to the public from the National Technical Information Service, U.S. 

Department of Commerce, 5285 Port Royal Road, Springfield, VA 22161; phone orders 

accepted at (703) 487-4650. 

EERC DISCLAIMER

 LEGAL NOTICE This research report was prepared by the Energy & Environmental 

Research Center (EERC), an agency of the University of North Dakota, as an account of work 

sponsored by the U.S. Department of Energy (DOE). Because of the research nature of the work 

performed, neither the EERC nor any of its employees makes any warranty, express or implied, 

or assumes any legal liability or responsibility for the accuracy, completeness, or usefulness of 

any information, apparatus, product, or process disclosed or represents that its use would not 

infringe privately owned rights. Reference herein to any specific commercial product, process, or 

service by trade name, trademark, manufacturer, or otherwise does not necessarily constitute or 

imply its endorsement or recommendation by the EERC. 

ACKNOWLEDGMENTS 

 This report was made possible through the collaborative contributions and efforts of 

numerous groups from throughout the United States and Canada. We gratefully acknowledge the 

individuals who provided the backbone information upon which this report is based, specifically, 

Pat McLellan, Mathias Grobe, Stefan Bachu, David Ryan, Bill Reynen, Dave Nakles, and Rob 

Lavoie. We also acknowledge the PCOR Partnership partners for their valuable efforts in 

providing much of the information used for this report. We extend our appreciation to the various 

federal, state, and private organizations and university groups for their cooperation in our search 

for data. A number of individuals at the Energy & Environmental Research Center provided 

valuable support for this effort. 
i 

TABLE OF CONTENTS 

LIST OF FIGURES ........................................................................................................................ ii 

LIST OF TABLES ......................................................................................................................... iii 

EXECUTIVE SUMMARY ........................................................................................................... iv 

INTRODUCTION .......................................................................................................................... 1 

 Philosophical Approach ........................................................................................................ 4 

 Technical Approach .............................................................................................................. 5 

BACKGROUND ............................................................................................................................ 7 

 Zama Location and General Geological Setting ................................................................... 7 

 Overview of the Zama Oil Field, Keg River F Pool Operational History ............................ 7 

 Overview of the Zama Gas-Processing Plant ...................................................................... 10 

MVA PROGRAM ........................................................................................................................ 12 

 Regulatory Process .............................................................................................................. 13 

 Data Reconnaissance and Integration.................................................................................. 14 

 Baseline Geological and Hydrogeological Characterization............................................... 14 

 Rock Lithology, Mineralogy, and Composition of Formation Fluids ................................. 19 

 Baseline Reservoir Conditions ............................................................................................ 21 

 Mechanical Rock Properties ................................................................................................ 22

 Geochemical Interactions Between Acid Gas and Reservoir/Seal Rocks ........................... 23 

 Wellbore Integrity and Leakage Potential ........................................................................... 25 

 Tracer and Pressure Monitoring Programs .......................................................................... 26 

 

INJECTION PROGRAM ............................................................................................................. 28 

 Capture and Infrastructure at Zama ..................................................................................... 28 

 Well Preparation and Maintenance ..................................................................................... 29 

 Acid Gas Injection ............................................................................................................... 31 

 EOR Operations .................................................................................................................. 34 

 Determination of CO2 Storage Capacity ............................................................................. 36 

KEY OBSERVATIONS, CHALLENGES, AND LESSONS LEARNED .................................. 37 

 Suitability of Pinnacle Reefs for Acid Gas Injection and Long-Term CCS ....................... 37 

 Relative Mobility and Fate of CO2 and H2S Within Carbonate Reservoirs ........................ 38 

 Effects of Acid Gas on Wellbores and Surface Infrastructure ............................................ 39 

 The Use of Pressure Data and Tracers to Detect Leakage .................................................. 39 

 Nontraditional Economic Components ............................................................................... 40 

Continued . . . 
ii 

TABLE OF CONTENTS (continued) 

REFERENCES ............................................................................................................................. 41 

AN OVERVIEW OF ALBERTA REGULATORY AND PERMITTING 

SUBMITTALS .............................................................................................................. Appendix A 

TABLE OF MVA TECHNIQUES AND APPLICATIONS ......................................... Appendix B 

LIST OF FIGURES 

1 Location of the PCOR Partnership–Apache Canada acid gas storage field 

 validation test in the Zama Field of Alberta .......................................................................... 3

2 Monitoring activities at Zama, focused on assessing the potential for leakage out of the 

 reservoir through the cap rock, wellbores, and spillpoint at the base of the structure .......... 6

3 Map view of Zama showing the F Pool in relation to the gas plant ..................................... 8

4 Flooded areas of the Zama Field ........................................................................................... 9

5 AGS diagrammatic cross section of the Zama area .............................................................. 9

6 Oil production well in the Keg River F Pool of the Zama oil field ..................................... 11

7 Apache Canada Zama gas plant and oil production facility ................................................ 12

 

8 AGS northeast Alberta stratigraphic and hydrostratigraphic section .................................. 15

9 AGS Zama geological and hydrogeological study area ...................................................... 16

10 AGS Zama Keg River cross section .................................................................................... 18

11 Cross section of the Zama subbasin showing regional structural architecture.................... 18

12 Simplified paleogeography of the Keg River carbonate from basin-scale assessment ....... 19

13 AGI geomechanical workflow ............................................................................................ 22

14 Pressure-monitoring MVA program ................................................................................... 27

15 Operation to clear a plugged flowline ................................................................................. 29 

Continued . . . 
iii 

LIST OF FIGURES (continued) 

16 Example of raw logging data and interpretation showing casing deformation ................... 32

17 Monthly F Pool injection history – volume and mass ......................................................... 32

18 Keg River F Pool oil production and acid gas injection profiles ........................................ 33

19 Cumulative F Pool injected volumes and mass of acid gas ................................................ 33

20 F Pool–mass of CO2 stored ................................................................................................. 34

21 Zama Keg River F Pool EOR scheme as of May 2009 ....................................................... 35

22 Keg River F Pool volumetric estimation of OOIP and subsequent production 

 prediction ............................................................................................................................. 36

LIST OF TABLES 

1 F Pool Cumulative Recoveries to November 2003 ............................................................. 10 

2 F Pool Initial Conditions ..................................................................................................... 11 
iv 

PLAINS CO2 REDUCTION (PCOR) PARTNERSHIP (PHASE II) –ZAMA FIELD 

VALIDATION TEST REGIONAL TECHNOLOGY IMPLEMENTATION PLAN

Steven A. Smith, Energy & Environmental Research Center 

James A. Sorensen, Energy & Environmental Research Center 

Edward N. Steadman, Energy & Environmental Research Center 

John A. Harju, Energy & Environmental Research Center 

Bill Jackson, Apache Canada, Ltd. 

Doug Nimchuk, Apache Canada, Ltd. 

Lyle Burke, RPS Energy 

September 2009

EXECUTIVE SUMMARY 

 A comprehensive, monitoring, verification, and accounting (MVA) plan is critical to the 

success of any geological carbon sequestration project utilized as a method of reducing carbon 

dioxide (CO2) emissions to the atmosphere. From October 2005 through September 2009, the 

Zama oil field in northwestern Alberta, Canada, has been the site of acid gas (approximately 

70% CO2 and 30% hydrogen sulphide [H2S]) injection for the simultaneous purpose of enhanced 

oil recovery (EOR), H2S disposal, and sequestration of CO2. The Plains CO2 Reduction (PCOR) 

Partnership has conducted MVA activities at the site throughout this period, while Apache 

Canada Ltd. has undertaken the injection and hydrocarbon recovery processes. This project has 

been conducted as part of the U.S. Department of Energy (DOE) National Energy Technology 

Laboratory (NETL) Regional Carbon Sequestration Partnership Program and has been 

recognized by the Carbon Sequestration Leadership Forum as being uniquely able to fill 

technological gaps with regard to geological storage of CO2. 

 One of the primary purposes of the PCOR Partnership Phase II Program is to develop a 

Regional Technology Implementation Plan (RTIP) based on the experiences and results 

generated at Zama. The purpose of the RTIP is to provide technical guidance on approaches for 

conducting baseline surveys, MVA, and assessing the overall success of injecting CO2-rich acid 

gas into deep carbonate oil reservoirs for the purpose of simultaneous CO2 storage and EOR. The 

RTIP presents a series of key observations, insights, and recommendations, based on the 

experiences at Zama, that are intended to be broadly applicable to the injection of acid gas for 

simultaneous CO2 storage and EOR operations at locations throughout the United States, 

Canada, and even the world. 
v 

 Acid gas has been obtained as a by-product of oil production in the Zama Field and 

subsequent fluid separation process at the on-site facilities. During the separation process, oil and 

gas are sent to market while acid gas is redirected back to the field for utilization in EOR 

operations. Previously, CO2 was vented to the atmosphere and sulfur was separated from the H2S 

and stockpiled in solid form on-site. This project has enabled the simultaneous beneficial use of 

each of these processing by-products and effective mitigation of two environmental concerns. 

 The Zama project has been designed to address the issue of monitoring CO2 sequestration 

at EOR sites, in this case utilizing H2S-rich acid gas as the sweep mechanism, in a cost-effective 

and reliable manner. The primary issues that were addressed include 1) determination of CO2

and/or H2S leakage, or lack thereof, from the pinnacle; 2) development of reliable predictions 

regarding the long-term fate of injected acid gas; and 3) generation of data sets that will support 

the development and monetization of carbon credits associated with the geologic sequestration of 

CO2 at the Zama oil field. 

 To address these issues, a variety of research activities have been conducted at multiple 

scales of investigation in an effort to fully understand the ultimate fate of the injected gas. 

Geological, geomechanical, geochemical, and engineering work has been used to fully describe 

the injection zone and adjacent strata in an effort to predict the long-term storage potential of this 

site. Through these activities, confidence in the ability of the Zama oil field to provide long-term 

containment of injected gas has been achieved. While this project has been focused on one of the 

hundreds of pinnacles that exist in the Zama Field, many of the results obtained can be applied 

not only to additional pinnacles in the Alberta Basin, but to similar structures throughout the 

world. 

 Monitoring the site has been achieved primarily through fluid sampling and pressure 

monitoring in both the target pinnacle reef and overlying strata. A gas-phase perfluorocarbon 

tracer, designed to mimic the injected gas, has been used in an effort to identify any leakage into 

overlying stratigraphic horizons. Pressure is also being measured at the injection zone and 

overlying productive zones to ensure 1) overpressurization of the target is not occurring and 

causing undue stress on the overlying cap rock that could potentially lead to failure and 

2) leakage along wellbore pathways is not occurring. Certifying the integrity of the system has 

been a critical focus area, with tests being completed on the cap rock and injection zone to 

determine the nature of potential geochemical and geomechanical changes that may occur as a 

result of acid gas exposure under supercritical pressures and temperatures. 

 Geological investigation was focused on the reservoir, local, and regional (subbasinal) 

scales. Results of these investigations indicate that natural leakage from this system is unlikely 

and regional flow is extremely slow, on the order of thousands to tens of thousands of years to 

migrate out of the basin. The potential for leakage through existing wellbores was also evaluated 

and found to be very low. Geomechanical evaluations, including 3D modeling, were completed 

on the injection zone and adjacent stratigraphy. This series of tests confirm that the geological 

structures that are being utilized are excellent candidates for sequestration. The cap rock is 

considered to be extremely stable, has extremely low permeability, and is not likely to fracture 

when subjected to injection pressures well beyond the maximum allowed. Geochemical 

modeling aids in the understanding of the long-term fate of acid gas injected into carbonate 
vi 

rocks. Evaluations of the Zama system indicate that the impact of mineralization on the overall 

storage capacity of the system is negligible and will occur very slowly over geological time 

scales. 

 Continuous injection has taken place at a depth of 4900 feet into the carbonate pinnacle 

reef structure since December 2006. As of September 30, 2009, approximately 58,000 tons of 

acid gas had been injected into the pinnacle reef, of which approximately 40,000 tons was CO2. 

Incremental oil production from the pinnacle reef over the course of the project, as of 

September 30, 2009, was approximately 25,000 barrels. 

 Project results indicated that a robust, yet practical, MVA program can be developed. 

Given the proper geologic setting, MVA activities can be relatively inexpensive and not 

adversely affect commercial EOR operations. 
1 

PLAINS CO2 REDUCTION (PCOR) PARTNERSHIP (PHASE II) –ZAMA FIELD 

VALIDATION TEST REGIONAL TECHNOLOGY IMPLEMENTATION PLAN

Steven A. Smith, Energy & Environmental Research Center 

James A. Sorensen, Energy & Environmental Research Center 

Edward N. Steadman, Energy & Environmental Research Center 

John A. Harju, Energy & Environmental Research Center 

Bill Jackson, Apache Canada, Ltd. 

Doug Nimchuk, Apache Canada, Ltd. 

Lyle Burke, RPS Energy 

September 2009

INTRODUCTION 

 In recent years, the management of carbon dioxide (CO2) emissions from large industrial 

point sources has been identified as a potential means to mitigate global climate change. Efforts 

to reduce CO2 emissions now are a significant focus for all energy production and use 

stakeholders, including the general public, governments, industry, regulators, and 

environmentalists. Many large industrial CO2 emission sources produce a gas stream that 

includes constituents other than CO2. This is particularly true of natural gas-processing plants, 

which can have significant quantities of hydrogen sulfide (H2S) mixed within their CO2 stream. 

Such gas mixtures are commonly referred to as “acid gas” or “sour CO2” streams. While many 

laboratory- and field-based research projects have focused on technical and economic issues 

associated with the management of CO2, relatively few have focused on the unique issues related 

to the management of acid gas, which is far more toxic and corrosive than pure CO2. 

 Carbon capture and storage (CCS) in geological media have been identified as important 

mechanisms for reducing anthropogenic CO2 emissions currently vented to the atmosphere. 

Several means for geological storage of CO2 are available, such as in depleted oil and gas 

reservoirs, deep saline formations, CO2 flood enhanced oil recovery (EOR) operations, and 

enhanced coalbed methane recovery. These same geological formations may also be amenable to 

the large-scale storage of acid gas. Activities to improve understanding and develop technologies 

and approaches for CO2 and acid gas capture; transportation; storage; and monitoring, 

verification, and accounting (MVA) have been, and continue to be, conducted. The goals of such 

activities are to determine the technical and economic viability of CO2 and acid gas storage and 

to support the deployment of large demonstrations and, ultimately, commercial-scale projects. 
2 

 The capture of acid gas from raw natural gas production streams has been economically 

conducted throughout the world for decades, largely through the use of amine-based acid gas 

removal technologies in gas-processing plants (Skinner and others, 1995; Sorensen and others, 

1996). Similarly, the transportation of high concentrations of acid gas through pipelines has also 

been safely and cost-effectively conducted for decades, especially in western Canada where a 

network of thousands of wells and gathering lines have produced and moved trillions of cubic 

feet of methane and acid gas throughout Alberta and British Columbia for several decades 

(Sorensen and others, 1996). The technical and economic challenges associated with the 

injection of CO2 and acid gas into geological formations are also fairly well understood, as CO2

injection for EOR has been applied at many locations since the 1970s and the injection of acid 

gas for disposal purposes has been conducted in Alberta since the 1980s. However, unlike 

capture, transportation, and injection, the long-term permanent storage of acid gas for the 

mitigation of greenhouse gas emissions and the MVA required for such storage projects are in 

the early stages of technology development and implementation and are, therefore, less 

understood. 

 In particular, MVA activities are critical components of geological acid gas storage 

projects for two key reasons. First, the public must be assured that geological storage of CO2 and 

acid gas is a safe operation. Second, emerging carbon credit-trading markets need assurance that 

credits are properly assigned, traded, and accounted for. Integrated geological and 

hydrogeological characterization, modelling and simulation, geomechanical testing, and 

geochemical sampling and analysis programs are technologies that can facilitate documentation 

of the movement of the injected gases and detect any potential leakage from the storage unit. 

 The Energy & Environmental Research Center (EERC), through the Plains CO2 Reduction 

(PCOR) Partnership, one of the U.S. Department of Energy (DOE) National Energy Technology 

Laboratory’s Regional Carbon Sequestration Partnerships, is working with Apache Canada Ltd. 

to conduct a program of primarily field-based activities that will support and validate the safe 

and cost-effective injection of acid gas into selected reservoirs of the Zama oil field for the 

simultaneous purposes of acid gas disposal, CO2 storage, and EOR. The reservoirs in the Zama 

oil field exist in the form of isolated, porous, and permeable pinnacle reefs (carbonate rocks) 

which are sealed by a thick layer of essentially impermeable anhydrite. The capture, 

transportation, and injection processes and subsequent hydrocarbon recovery operations are 

being carried out by Apache Canada at its oil field and natural gas-processing plant locations 

near Zama, Alberta, Canada (Figure 1). The role of the PCOR Partnership is to conduct MVA 

activities at a specific location/reservoir (referred to as the “F Pool”) within the Zama oil field. 

The MVA activities have been designed in such a way as to be cost-effective, cause minimal 

disruption to ongoing oil production activities, and yet provide critical data on the behavior and 

fate of the injected acid gas mixture within the reservoir. 

 The MVA, acid gas production, and EOR activities at the Zama oil field that are 

considered to be part of Phase II of the PCOR Partnership Program were conducted from 

October 2005 through July 2009. One of the primary purposes of the PCOR Partnership Phase II 

Program is to develop a Regional Technology Implementation Plan (RTIP) for each of the 

Phase II field-based CCS demonstrations. In the case of the Phase II activities at Zama, the 

purpose of the RTIP is to provide technical guidance on approaches for conducting baseline
3 

Figure 1. Location of the PCOR Partnership–Apache Canada acid gas storage field validation 

test in the Zama Field of Alberta. 

surveys, MVA, and assessing the overall success of injecting CO2-rich acid gas into deep 

carbonate oil reservoirs for the purpose of simultaneous CO2 storage and EOR. The RTIP is not 

intended to be a detailed accounting of the numerous activities conducted at Zama and their 

results over the course of the project. Instead, the RTIP presents a series of key observations, 

insights, and recommendations, based on the experiences at Zama, that are intended to be 

broadly applicable to the injection of acid gas for simultaneous CO2 storage and EOR operations 

at locations throughout the United States, Canada, and even the world. The PCOR Partnership 

Phase II Zama project was designed with the following goals in mind: 

• To demonstrate that the capture and injection of an acid gas stream into properly

 characterized and carefully selected underground reservoirs is feasible and safe within

 existing industry and regulatory standards. 

• To design, implement, and demonstrate cost-effective MVA strategies for verifying and 

 validating the containment integrity of the target reservoirs. 

• To demonstrate that highly concentrated acid gas (in this case, 30% H2S and 70% CO2) 

 can be successfully used for EOR operations in a type of geological feature (carbonate 

 pinnacle reefs) that had previously been untested with respect to acid gas-based EOR. 
4 

 Philosophical Approach 

 There is a broad range of technologies and approaches that can be and, in some cases, have 

been applied to CO2 storage projects of various scales around the world. Early geological storage 

research and demonstration projects deployed MVA strategies that were developed based on a 

lack of knowledge about the effectiveness and utility of many of the applied technologies. The 

absence of knowledge required early projects to gather as much data as possible using a wide 

variety of techniques. In particular, a desire to “see” the plume of injected CO2 led to a strong 

emphasis on the use of geophysical data, especially 3-D and 4-D seismic, to monitor the plume. 

While the use of geophysically based approaches and techniques in early projects yielded 

valuable results that are essential to the development of geological storage as a CO2 mitigation 

strategy, their high costs of deployment and often limited ability to identify CO2 in many 

geologic settings may render them as being the exception rather than the rule when it comes to 

developing practical MVA plans for future projects. If the implementation of CCS is to occur on 

a large enough scale to mitigate global climate change, then economics must be secondary only 

to health and safety considerations at the earliest stages of project development. At the same 

time, a detailed understanding and effective demonstration of the technical feasibility with 

respect to injectivity, capacity, containment, and overall safety is essential for all stakeholders to 

buy into the concept of large-scale CO2 and/or acid gas injection. This is the context within 

which a philosophical approach was developed, which was then applied to the PCOR Partnership 

Phase II Program. 

 It is expected that, in many cases, EOR projects and depleted oil and gas pools will provide 

the most favorable locations for long-term CO2 storage from both a technical and economic 

standpoint. From a technical perspective, such sites benefit from a relative wealth of previously 

generated, readily available subsurface characterization and reservoir production and injection 

data. These data provide critical, invaluable insight regarding the long-term prospects for 

technically feasible and safe injection and storage of CO2, and in this case, acid gas. From an 

economic perspective, hydrocarbon reservoirs (and especially those that are suitable for EOR 

projects) are attractive because the use of existing infrastructure can lower the start-up costs of a 

project, while the production of incremental oil can be used to offset the costs of capital, 

operations, and maintenance and, ultimately, bring profitability to the project. The use of 

established hydrocarbon reservoirs also benefits from the fact that a regulatory framework 

already exists for permitting many, if not all, of the surface and subsurface operations that will be 

necessary to conduct a project. 

 The philosophical approach of the PCOR Partnership toward the design, implementation, 

and operation of the MVA plan and associated project activities was to: 

• Maximize the use of previously generated data on the geological, geochemical, and 

 geomechanical characteristics of the formation into which acid gas was to be injected 

 (target injection zone) and the overlying low-permeability rock formations that would 

 serve as seals. 
5 

• Minimize, as much as possible, the need to obtain data beyond that which is already 

 collected by the operator as part of the “normal” or “standard” operation of an EOR or 

 acid gas disposal project. 

 For those elements of the MVA plan that required the use of new or nonstandard testing or 

technologies in the field, those elements would be designed in close consultation with the field 

managers and operators to ensure that disruption of normal oil field operations was minimized. 

 The application of these fundamental guiding principles to the planning and operation of 

the Zama project ensured that the goal of demonstrating the economic feasibility of acid gas 

injection for simultaneous EOR and CO2 storage under “real world” technical and economic 

constraints could be achieved. That being said, the PCOR Partnership and Apache Canada 

recognized the value of developing previously unavailable fundamental data sets that could 

provide new understanding of CCS and guide the direction of future CCS research. With that in 

mind, the PCOR Partnership sought and, when appropriate, acted on opportunities to costeffectively conduct additional activities that were of a more research-oriented nature and which 

would not typically be part of future nonresearch EOR and/or CCS projects. 

 Technical Approach 

 For purposes of discussion in the context of this report, the technical aspects of the PCOR 

Partnership Phase II–Apache Canada project at Zama generally can be thought of as falling into 

two categories: 1) the MVA program and 2) the injection program. These categories are not 

necessarily independent of each other, with some activities and data sets being common between 

the two categories. However, for the sake of effective discussion in the context of the RTIP, they 

are presented in this report in relatively independent sections, with categorization based largely 

on what was deemed to be the primary purpose of each activity. 

 The purpose of the MVA program is to 1) provide a set of baseline conditions upon 

which the effects of the project can be compared to data gathered during and after injection 

operations; 2) generate data sets that demonstrate the security of the injection program from the 

perspectives of containment and safety; and 3) establish a technical framework for the creation 

and ultimate monetization of carbon credits associated with reduction of emissions and the 

geological storage of CO2 at Zama. MVA program activities that resulted in the determination of 

baseline conditions include geological and hydrogeological characterization at various scales, 

characterization of the F pool reservoir, determination of geomechanical and geochemical 

properties of key rocks in the reservoir/seal system, and evaluation of wellbore integrity issues. 

Field-based elements of the MVA program include the introduction of a tracer and data 

collection (i.e., formation fluid sampling and analysis, reservoir dynamics monitoring) from the 

injection, production, and monitoring wells. Other key elements of the MVA program include 

documentation of the permitting process and regulatory framework for the project, determination 

of material balance based on the collected field data, and a modeling-based study of historical 

and new reservoir pressure data in an effort to maximize the use of pressure data as a means of 

early identification of leakage. Generally speaking, monitoring activities are focused on the nearreservoir environment, including monitoring for leakage through cap rock, wellbore leakage, and 

spillpoint breach (Figure 2). 
6 

Figure 2. Monitoring activities at Zama, focused on assessing the potential for leakage out of the 

reservoir through the cap rock, wellbores, and spillpoint at the base of the structure. 

 The purpose of the injection program is to 1) ensure the cost-effective injection of acid gas 

from the Zama gas-processing plant into the Zama F Pool reservoir; 2) facilitate the production 

of incremental oil from the F Pool reservoir; and 3) support the documentation of effective CO2

storage in the F Pool. Key aspects of the injection program include the capture and infrastructure 

elements of the project, well preparation and maintenance activities, and acid gas injection and 

EOR operations. 

 The PCOR Partnership Phase II–Apache Canada project at Zama was conducted by a 

multidisciplinary team of engineers, scientists, regulators, and management personnel. The 

management team for the project included representatives from Apache Canada and the EERC. 

The primary technical team comprised technical professionals from Apache Canada, the EERC, 

the Alberta Energy and Utilities Board (AEUB), the Alberta Geological Survey (AGS), RPS 

Energy, Schlumberger Oilfield Services, and Advanced Geotechnology Inc. Effective, frequent 

communication between all team members was critical to the timely, cost-effective design and 

implementation of all project activities. To facilitate communication and the appropriate sharing 

of project data, conference calls were held on at least a quarterly, often monthly, and sometimes 

weekly basis. A password-protected file transfer portal (FTP) site was established for the easy 

sharing of documents and data between members of the technical team. Integration of activities 

in a cross-disciplinary manner facilitated efficient implementation of project plans. Such 

integration, while effective from a project management and budget standpoint, sometimes 

blurred the lines between the various elements of the program, which further underscored the 

need for frequent, diligent reporting of activities and results and thoughtful, interpretive 

discussion between team members. 
7 

BACKGROUND 

 Zama Location and General Geological Setting 

 The Zama oil field is located at 59° latitude in the extreme northwestern corner of the 

province of Alberta, approximately 875 km (550 miles) northwest of Edmonton, as shown in 

Figure 1. The gas plant is situated within the boundaries of the oil field and is approximately 

1 km west of the F Pool injection site (Figure 3). The field covers an area of about 2000 km2

(500,000 acres) in an area known geographically as the Fort Nelson Lowland. The Fort Nelson 

Lowland plain is characterized by boreal forest, extensive bogs, fens, muskeg, surface water 

accumulations, ox bow lakes, and meandering water courses. The area is subject to typical 

northern latitude interior plains weather patterns, including severe cold winter temperatures and 

summer thawing, which turns most of the flat country into very wet marshland, as illustrated in 

Figure 4. 

 From a geologic perspective, the Zama area is located in the Zama subbasin which, in turn, 

is in the northwest portion of the Alberta Basin. The F Pool is one of hundreds of pinnacle reef 

structures that comprise the oil reservoirs of the Zama oil field. Pinnacle reefs at Zama are steepsided, moundlike carbonate structures in the Keg River Formation, having an average size of 

40 acres at the base and 400 ft in height. The depth from surface to the pinnacles is typically 

4900 ft. The reefs are typically dolomitized, with variable porosity (average 10%) and 

permeability. The pinnacle reefs are encased laterally and vertically by essentially impermeable 

anhydrites and underlain by a brine-saturated formation. Figure 5 presents a cartoon 

representation of the general structure, in cross-section view, of the pinnacle reefs and their 

relationship to overlying seals, aquifers, and hydrocarbon reservoirs. The stratigraphic and 

structural isolation of the pinnacles, their adequate porosity and permeability, and the close 

proximity to an anthropogenic source make them suitable candidates for conducting a CO2

sequestration technology validation test. Beyond Alberta, similar pinnacles are known to occur in 

the Saskatchewan and North Dakota portions of the Williston Basin as well as in the Michigan 

Basin. 

 Overview of the Zama Oil Field, Keg River F Pool Operational History 

 The Keg River F Pool began producing oil in 1967. The well produced 170,750 m3

(1.1 MMbbl) of oil over a 20-year period. In late 1986, oil production was discontinued, and the 

well was completed as a saltwater disposal well in October 1987. Water injection operations 

were suspended in October 1991, with a cumulative water injection of about 1.8 MMbbl 

(287,500 m3

). In 1992, an attempt at secondary oil production was unsuccessful, with little 

incremental oil being produced. The waterflooding of small pinnacles, such as the Zama Keg 

River F Pool, was found to be challenging because of their small size and heterogeneity with 

respect to porosity and permeability. 

 In June 1997, the well completion in the Keg River Formation was abandoned, and the 

well was recompleted as a gas well in the Slave Point Formation (referred to as the Slave Point 

FFF Pool). The gas completion watered out and was suspended in November 2006. This 

completion (Slave Point FFF) is suspended at surface (meaning it no longer produces gas but has 

not been completely shut in) and, as a result of this project, is now utilized as a monitoring well
8 

Figure 3. Map view of Zama showing the F Pool (shaded in yellow) in relation to the gas plant. 
9 

Figure 4. Flooded areas of the Zama Field. Specialized transportation required to navigate the 

muskeg that dominates the area. 

 

Figure 5. AGS diagrammatic cross section of the Zama area. Light green areas of the Keg River 

reefs represent accumulations of oil. Red areas represent accumulations of natural gas. Blue 

areas represent permeable brine water-saturated zones. 

for potential wellbore leakage of gas injected into the Keg River F Pool. A second well was 

drilled into the Keg River F Pool in January 2002 and encountered oil at the top and center of the 
10 

F Pool pinnacle. It was completed as an open hole and placed in production in March 2002. 

Production was suspended in early 2004 after producing just 5438 m3

 (34,220 bbl) of oil. 

 In July 2004, following project planning, including reservoir, geological evaluations, and 

economic evaluations, Apache made an application to the Energy Resources Conservation Board 

(ERCB) to conduct an acid gas miscible flood. Petroleum engineering studies and lab work were 

also carried out in support of this application, including well and reservoir review, miscibility 

studies, statistical analysis of oil compositions in the area, and estimates of miscible flood 

efficiency. The original ERCB approval stipulated operational limits for the F Pool EOR scheme, 

some of which were altered following the application and approval process to allow for changes 

in the acid gas miscibility pressure. 

 A third F Pool production well was drilled in September 2004. The well was placed in 

production in August 2005. Perforated low in the formation, it was a poor producer, with a 

cumulative oil production of about 75 m3 (470 bbl) between August 2005 and May 2006. This 

well was then utilized to draw water off the lower portion of the pinnacle to lower the average 

reservoir pressure down to the original ERCB-approved range beginning in November 2006. 

This objective was accomplished by May 2006 but injection was not started until December 

2006. By that time, injection of acid gas into other pinnacle reefs (pools) in the Zama Field had 

already begun, and the Zama Keg River F Pool became the third pool in the Zama oil field to be 

placed on acid gas EOR. Tables 1 and 2 present the cumulative oil production history of the 

Zama Keg River F Pool and its preinjection reservoir conditions, respectively. Figure 6 depicts a 

producing oil well in the F pool. 

 Overview of the Zama Gas-Processing Plant 

 The Zama gas plant is owned and operated by Apache Canada. The plant currently 

generates about 7.5 million cubic feet per day (7.5 MMcf/day, 210,000 m3

/day) of acid gas 

consisting of 20% to 40% H2S and 60% to 80% CO2. This amounts to a total of about 273 metric 

tons/day of CO2 and 84 metric tons/day of H2S. The Zama gas plant and oil production facility 

(Figure 7) was modified to accommodate the acid gas EOR/CCS project. Following these 

modifications, the Zama gas plant consists of the following process elements: 

• Production gathering system 

• Conventional oil and gas processing, sales, and shipping 

• Conventional gas compression 

• Acid gas compression and injection 

• Gas recycle stream 

 Table 1. F Pool Cumulative Recoveries to November 2003 

Oil 1,107,512 bbl 176,100 m3

Gas 533,604,614 ft3 15,110,000 m3

Water 405,647 bbl 64,500 m3

Water Injection 2,304,329 bbl 366,400 m3

 
11 

 Table 2. F Pool Initial Conditions 

Plan Type Keg River Pinnacle Reef 

Initial Reservoir Pressure 2095 psi (14,447 kPa) 

Reservoir Temperature 160°F (71°C) 

Initial Water Saturation 15% (from logs) 

Porosity 10% (from logs) 

Initial Gas Oil Ratio 52 m3/m3

Initial Formation Volume Factor 1.183 r vol/std vol 

Bubble Point Pressure 1275 psi (8791 kPa) 

API1

 Gravity 35.2 API 

Calculated OOIP2 2.2 million bbl 

344,000 m3 (volumetric using 3-D seismic data) 

Calculated OOIP 3.5 million bbl 

557,000 m3

 (material balance) 1 American Petroleum Institute. 2 Original oil in place. 

Figure 6. Oil production well in the Keg River F Pool of the Zama oil field. 
12 

Figure 7. Apache Canada Zama gas plant and oil production facility. 

 Prior to the EOR/CCS demonstration project, the acid gas stream from the Zama gasprocessing plant was processed through a Claus sulfur recovery unit to produce solid elemental 

sulfur, which was then stored until market conditions would allow its sale; CO2 was vented to the 

atmosphere during these plant operations. A very significantly sized storage site within the 

Apache Zama production facility was required to house this by-product of the gas-processing 

operations. The remainder of the acid gas stream processed was injected for disposal in the Keg 

River Formation via acid gas disposal wells. 

 The injection of the acid gas for the EOR project permitted the shutdown of the Claus unit, 

and the gas plant was reconfigured to inject the entire acid gas stream into the Keg River EOR 

pools. The elimination of the sulfur production and storage is a major environmental benefit in 

addition to the simultaneous elimination of the CO2 venting (64,000 tons per year). 

 The current Zama natural gas operation has resulted in significant reduction of the 

operating costs that were associated with the sulfur plant. Further revenue could result if EOR is 

feasible using miscible acid gas flooding. This value-added approach could be used to manage 

CO2-rich acid gas streams at many of the more than 1300 gas-processing plants in North 

America as well as others worldwide. 

MVA PROGRAM 

The goal for the PCOR Partnership MVA activities at the Zama site was to establish the 

integrity of the Zama pinnacle reefs for CO2–H2S storage. This was accomplished by carrying 

out the following activities: 
13 

• Going through the regulatory process 

• Data reconnaissance and integration 

• Baseline geology and hydrogeology characterization 

• Rock mineralogy and composition of formation water determination 

• Mechanical rock properties and stress regime evaluation 

• Assessment of geochemical interactions between formation and injected fluids and 

 reservoir rock and cap rock 

• Assessment of wellbore integrity and leakage potential 

 Regulatory Process 

 While the regulatory process for any given acid gas injection project, whether it be for 

EOR, CCS, or both, will vary depending on the jurisdiction within which the project is operated, 

it is instructive to briefly summarize the process that Apache Canada went through for the 

project at Zama. As operator, Apache Canada is committed to developing the Zama acid gas 

injection EOR and CCS project in a manner that complies with all current Alberta ERCB oil and 

gas regulations. Well completions, facility and gathering system modifications, and reservoir 

engineering practices were all conducted within industry-recommended practices (IRP), 

including the practices and standards of API and the National Association of Corrosion 

Engineers. In many cases, these standards and practices are consistent with regulatory 

requirements and guidelines, although it is important that this be determined definitively by the 

operator early in the planning stages for any CCS project. 

 To convert an oil field to an acid gas injection process in Alberta, a formal application 

must be made to the Resource Applications Department of the EUB (ERCB) under 

Section 26(1)(a) of the Oil and Gas Conservation Act (Alberta Oil and Gas Conservation Act, 

2009). Specifically, EUB Directive 65 (Energy Resources Conservation Board, 2009) must be 

followed. It is then required to file a separate application for each pool, which references the 

original application approval. Also required is Directive 51 (Energy Resources Conservation 

Board, 1994), compliance planning for injection wells, and a site-specific Emergency Response 

Plan (ERP) (Energy Resources Conservation Board, 2008). Wellhead components must meet 

product specification level (PSL) III requirements according to API Standard 6C. 

 Because of the site-specific nature of the application for the F Pool acid gas injection, a full 

presentation of the elements of that application is beyond the scope of this discussion. The 

complete application and subsequent amendments submitted by Apache Canada for the F Pool 

acid gas injection scheme are included as Appendix A of this report. In addition to this main 

application, a holding application under ERCB Directive 065 was also required to be able to 

place more than one production well within a 1⁄4 section drill spacing unit. The original 

application provided a project challenge in that the first pool approval for the Z3Z pool was 
14 

received 388 days after submission; this was twice the expected length of time and significantly 

delayed project start-up. 

 

 Data Reconnaissance and Integration 

 Efficient data acquisition, evaluation, and integration through the use of data management 

tools are crucial early steps in the establishment of baseline conditions. Data reconnaissance and 

integration activities for the Zama project included the following: 

• Well/reservoir information of the pertinent formations. 

• Data on drilling, completion, and stimulation/workover of key wells in the area. 

• Digital production/injection history of key wells. 

• Geological and geophysical information on the key formations in the study area, 

 including formation isopach and depth maps, interpreted seismic data, hydrogeological 

 characteristics, etc. 

• Reservoir engineering data on injection zone characterization and acid gas 

 injection/monitoring schemes. 

 Baseline Geological and Hydrogeological Characterization 

 Identifying and characterizing the geological setting and hydrogeological regime at an acid 

gas–CO2 injection site is important to understand possible migration pathways and the effect the 

flow of formation water may have on the spread of the injected gas. The Devonian Keg River 

Formation and its associated pinnacle reefs are part of the Keg River saline aquifer system. 

Several aquifer systems (Figure 8) are present in the sedimentary succession overlying the Keg 

River Formation: 1) the Devonian Sulphur Point saline aquifer; 2) the Devonian Slave Point 

saline aquifer; 3) the Upper Devonian saline aquifer system, which includes carbonates of the 

Winterburn and Wabamun Groups; and 4) isolated sand aquifers in the shales of the Lower 

Cretaceous Fort St. John Group (Bluesky and Paddy Formations). The following information 

was collected as part of the Zama characterization activities and should be a part of any 

characterization program for a CCS project: 

• Hydrostratigraphic delineation 

• Aquifer and aquitard geometry and thickness 

• Rock properties relevant to the flow of formation waters and injected acid gas such as 

 porosity and absolute and relative permeability 

• Geothermal regime 

• Pressure regime 
15 

Figure 8. AGS northeast Alberta stratigraphic and hydrostratigraphic section. 

• Direction and strength of formation water flow 

 A model of the flow-driving processes and mechanisms in the region and strata of interest 

were developed from those data that help in understanding the effect of natural flow on flow 

paths in the aquifer intervals of the Zama study area and outside, in case of leakage, and also of 

the effect of injection on the Keg River saline aquifer system. The results of the modeling 

showed that barring major leakage through a wellbore, the current and planned acid gas injection 

at Zama will have minimal impact on the hydrogeologic regime of any of the Devonian Aquifer 

systems in the area. The study also showed that even if injected acid gas were to make its way 

into any of the Devonian Aquifer systems, the direction and strength of formation water flow in 

those systems are such that it would take thousands of years for the acid gas to migrate to any 

formation outcrop. These results are a key component to demonstrating long-term containment 

of the injected acid gas and safety. 
16 

 The geology and hydrogeology characterization work was carried out at four different 

scales (Figure 9): 

• Reservoir scale 

• Local scale 

• Regional or subbasin scale 

• Basin scale 

 Work at the reservoir scale focused on the Zama F oil pool and the immediately 

underlying and overlying confining units: Lower Keg River Formation limestone and Muskeg 

Formation anhydrite. This, the smallest of scales, provides insight into predicting the immediate 

and early near-term effects of the injection operations. This is the most detailed portion of the 

baseline characterization and will be the most frequently updated over the course of any injection 

program. This is because data generated over the course of the injection, such as history 

matching injection and production curves, will provide new insight regarding the characteristics 

of the reservoir. 

Figure 9. AGS Zama geological and hydrogeological study area. The triangle represents the local 

(or field) scale, the square represents the regional scale, and the black outline around the Alberta 

Basin represents the basin scale. The reservoir scale, which is the F Pool pinnacle reef, is too 

small to be represented on this map. 
17 

 Work at the local scale covered areally the Zama F Pool and a few adjacent pinnacle reefs 

and, stratigraphically, the entire sedimentary succession from the basement to the surface. This 

scale generally includes the oil field within which the individual pool is a part. As with work 

done at the reservoir scale, work at the local scale can be used to predict near-term (months to 

years) effects of injection. These data can typically be updated on a relatively frequent basis as 

data from injection or production activity in wells in this area will typically be generated 

according to a schedule similar to the target reservoir. 

 

 Work at the regional, or subbasin scale, focused on evaluating relevant data and 

information from the basement to the surface over the entire Zama oil field/subbasin. This scale 

generally is defined according to the geological setting of the area within which the local scale 

area sits, but is generally much larger than the local scale (up to several hundred square miles). 

Examples typically include large structural features such as subbasins, but could also be defined 

by the extent of a particular formation of interest whose areal extent is not necessarily defined by 

a structural feature. Evaluations at this scale can provide insight that is useful in predicting the 

medium- to long-term (decades to hundreds of years) effects of large-scale injection operations, 

particularly if multiple projects are planned. 

 Work at the basin scale was primarily conducted with respect to large-scale 

hydrogeological characteristics. Basin-scale studies of aquifer system dynamics (flow, 

temperature, salinity, hydraulic head, etc.) will provide insight regarding the very long-term 

(hundreds to thousands of years) effects of large-scale CO2 or acid gas injection. This is also the 

scale at which multiple large-scale injection projects should be evaluated. 

 At the reservoir and local scales, a geological model of the strata associated with the 

Middle Devonian Keg River Formation at the F Pool EOR site was generated to evaluate 

reservoir geometry and internal architecture. The Keg River pinnacle reef reservoirs are confined 

above by 70 m of Muskeg/Prairie Formation evaporites and underlain by the Lower Keg River 

carbonate platform, which consists of tight lime–mudstone and a slightly porous limestone. The 

carbonates are also underlain by about 70 m of Chinchaga Formation evaporites. The 

overlying/surrounding cap rock was also evaluated, as well as the underlying aquifer that 

provides reservoir support in places. Information about the geology of the reservoir and 

confining strata (e.g., structural setting, stratigraphy, general lithology; thickness; and areal 

extent) were collected, processed, and interpreted for the local-scale area. 

 At the regional scale, the geology, stratigraphy, and lithology were evaluated, delineated, 

and described for the entire sedimentary succession from the base of the Middle Devonian Elk 

Point Group (lower confining unit) to the surface (Lower Cretaceous Fort St. John Group and 

Quaternary drift) for the Zama subbasin (Figure 8). In addition, the structural elements in the 

area, from the basement to the surface, were investigated to identify any possibly existing faults 

and/or fractures that would allow migration of reservoir and injected fluids. On this basis, a 

geological model (Figures 10–12) of the entire sedimentary succession was built, with particular 

attention given to the strata overlying the Keg River injection interval. 
18 

Figure 10. AGS Zama Keg River cross section. 

Figure 11. Cross section of the Zama subbasin showing regional structural architecture. The 

texture seen in the cutaway is the result of individual pinnacle reef structures sitting on the Keg 

River platform. 
19 

Figure 12. Simplified paleogeography of the Keg River carbonate from basin-scale assessment. 

 Rock Lithology, Mineralogy, and Composition of Formation Fluids 

 

 Data regarding key properties of the reservoir rocks and fluids are critical to 1) determining 

the feasibility of a potential injection location for large-scale CCS and 2) predicting the short-, 

medium-, and long-term effects of injection on the reservoir. Because the Zama project was 

conducted in an oil field that has been operating for several decades, a tremendous amount of 

lithology, mineralogy, and formation fluid baseline characterization data had been generated 

long before the acid gas injection project was planned. This made the drilling of an exploration 

well at Zama unnecessary. However, projects that are planned to be conducted in areas that are 

underexplored and less understood, such as in a saline formation, should include the drilling of 

an exploratory well as an early part of the characterization process. Exploration wells can 

provide project planners with a variety of data that are critical to establishing the efficacy of 

large- scale injection and storage at a given site. These data are an excellent means of providing 

support to a variety of preinjection modeling activities, including the development of static 

petrophysical models, site-specific geomechanical and geochemical modeling, and simulations 

of injection and plume transport and fate. An exploration well characterization program should 

include the following elements: 
20 

• Collection of core and cuttings 

− Cuttings should be collected at regularly spaced intervals (5 m is typical industry 

practice) from surface to total depth of the well. Cuttings provide information on the 

lithology of the site, including the depth and thickness of such key intervals as 

potential injection zones, seals, and aquifers that need to be protected. 

− At a minimum, core should be collected from the primary target injection zone. If 

possible, core samples of the primary seal should also be collected, although it is 

worth noting that some shales that can serve as perfectly competent seals may not 

yield good core samples because of their friable nature. The collection of core from 

secondary target injection zones and seals should also be considered. It is also worth 

noting that the collection of core samples should be supervised by wellsite geologists 

and drillers who have experience drilling in the local area. Knowledgeable geologists 

and drillers will have a keen understanding of the typical depths and thicknesses at 

which specific formations and zones within formations are likely to occur in a given 

area, which is information that is critical to the successful collection of core samples. 

− Core samples should be collected and preserved to allow for detailed description and 

testing. Core tests should include a variety of mineralogic, physical, and 

geomechanical parameters, including relative permeability of acid gas and brine and 

dynamic and static compressibility, among others. 

• Collection of formation fluids and fluid testing 

− Collection of downhole reservoir fluid samples, preservation at reservoir pressure, 

and subsequent analysis will yield invaluable data regarding the geochemical regime 

of the target injection zone. Geochemical analyses should include specific gravity, 

salinity, resistivity, total dissolved solids, anions, cations, organic acids, metals, and 

gas analyses (including hydrocarbons). 

• Collection of open hole geophysical logs 

− A suite of open hole logs should be run that includes, at a minimum, density, 

neutron, caliper, dipole sonic, and a microimaging tool. These logs will provide key 

rock property data including porosity, resistivity, general lithology and, to a lesser 

extent, permeability. Other specialized geophysical logs can be used to determine the 

saturation of various phases (e.g., gas, brine, and oil) within a reservoir and other 

useful reservoir properties. 

• Cement bond and casing integrity logging 

− Cement bond and casing integrity logs will demonstrate the integrity of the casing 

and cement of the exploration wells and provide crucial data that will support the 

development of casing and cementing scheme designs for future injection and 

monitoring wells in the area. 
21 

• Application of drill stem tests (DSTs) 

− DSTs should be run in all zones within the well that are being considered as potential 

injection zones. A DST will provide information on the type and basic characteristics 

of fluid in the zone being evaluated and the rates at which those fluids can be 

produced, which yields important information on the injectivity of the formation. 

Pressure data from a DST can be used to calculate formation pressure, permeability, 

and the amount of formation damage incurred by the drilling and completion of the 

well (Hyne, 1991). 

• Pressure transient analyses 

− A pressure transient test in a single well can be used to evaluate pressure variations 

in the target formation as a function of time. The pressure transient test is used to 

qualitatively identify the parameters that control injection such as formation 

permeability and thickness, skin effect, static reservoir pressure, and reservoir 

boundaries and limits. Types of pressure transient tests include drawdown, buildup, 

and falloff tests (Hyne, 1991). Analyses will support injection design and pressure 

buildup/falloff prediction. 

• Initiation and completion of mini-frac tests 

− A mini-frac is a small fracturing treatment used to acquire data that will confirm the 

predicted response of the interval being tested to increases in pressure. The mini-frac 

procedure provides key design data from the parameters associated with the injection 

of fluids and the subsequent pressure decline (Schlumberger Oilfield Glossary, 

2009). In the case of a CCS project, current regulatory principles typically preclude 

injection that goes beyond a preset reservoir pressure threshold. The purpose of the 

pressure threshold is to minimize the risk of injection-induced fracturing of both the 

reservoir and the overlying seal rock. It is recommended that, at a minimum, a minifrac test be conducted on the primary seal formation. These data can be used to 

evaluate the competency of potential sealing formations and provide quantitative 

measurements that support the determination of an appropriate injection pressure 

limit that is based on site-specific data rather than generalized rules of thumb. 

 Baseline Reservoir Conditions 

 Oil production commenced in November 1967. A summary of cumulative recoveries is 

shown in Table 2. During the 1990s, the F Pool was shut in. This resulted in reservoir pressure 

being recharged as a result of water injection activities in nearby Keg River Formation locations. 

Current reservoir pressure is assumed to be in the vicinity of 2466 psi (17,000 kPa) at the 

reservoir datum depth, based on a measurement taken in December 2004. Reservoir pressure was 

reduced a further 2 MPa (to 15,000 kPa) between July 2005 and February 2006 to comply with 

EUB requirements before initiating acid gas injection. 
22 

 Mechanical Rock Properties 

The goal of the geomechanical characterization program is to establish the geomechanical 

properties of the key sink and seal formations and the stress regime in the area to assess the 

mechanical integrity of the system and potential for rock fracturing. An in-depth review of the 

stress regime and structural features in the Zama F Pool reservoir was conducted to identify 

structures such as faults or fractures. Zama project activities included a variety of laboratory and 

field-based investigations. Laboratory-based activities using core samples of Keg River reservoir 

rock and Muskeg anhydrite cap rock collected from the original F Pool well drilled in 1967 

included compression tests to determine rock strength, static and dynamic elastic properties, 

compressibility, and stress-dependent permeability; and sonic tests to determine compressional 

and shear wave velocities. Field-based activities included in situ stress orientation and magnitude 

analysis, including log-based analysis of rock mechanical properties such as dynamic elastic 

properties and stress regime. Regional minimum stress orientation was determined using 

borehole breakout data from a number of wells in the Zama area. Analytical work also included 

using the laboratory and field-based data to correlate static-to-dynamic elastic properties, 

conduct geomechanical simulations, and assess overall reservoir and cap rock integrity. 

Figure 13 illustrates the workflow for geomechanical studies that was used by Advanced 

Geotechnology Inc. (AGI) on the Zama acid gas injection project. 

Figure 13. AGI geomechanical workflow. 
23 

The results of the Zama geomechanical studies have been presented in detail in Smith and 

others (2008) and their presentation here is beyond the scope of this report. However, some key 

results are worth noting. The peak strength data indicate that both the reservoir rock and the cap 

rock are relatively strong carbonate rocks and are very strong when compared to sedimentary 

rocks such as sandstones. The single Keg River dolomite sample exhibited a compressive 

strength of 24.6 kpsi (168.5 MPa) with a relatively stiff Youngs Modulus of 6193 kpsi 

(42.7 GPa). The Muskeg cap rock samples, whether dolomite or anhydrite, showed sample 

variability but, in general, were about equal to or significantly greater in strength than the more 

porous reservoir rock. When combined with data from laboratory pore entry mercury injection 

pressure tests and mechanical stress testing on similar area cores, plus log analyses and drilling 

reports, there is strong evidence that the thick 200- to 300-ft (60- to 90-m) Muskeg Formation 

dolomite/anhydrite sequences provide a competent, dense, essentially impermeable cap rock 

above the Keg River pinnacles. The data show that these rocks can sustain high stresses without 

experiencing significant deformations and that failure of the cap rock should not occur under 

normal operating conditions. The data further suggest that the F Pool pinnacle integrity far 

exceeds the current ERCB EOR pressure limit, and it could be proposed that once the EOR 

recovery is completed, additional CO2 and/or acid gas volumes could be stored within this 

pinnacle by increasing the allowable storage pressure beyond the original reservoir pressure. 

 Geochemical Interactions Between Acid Gas and Reservoir/Seal Rocks 

 Understanding the geochemical interactions between injected fluids (i.e., CO2 and/or acid 

gas) is critical to predicting both the effects of such injection on reservoir and seal rocks and the 

ultimate fate of the injected gases. The geochemistry-related activities that were conducted as 

part of the Zama project were focused on gathering relevant mineralogy and geochemistry data 

and assessing, through the use of geochemical modeling, the interaction between the injected 

gas, the reservoir fluids, and the rocks. The goals of these activities were to determine 1) the 

potential amount of CO2 and/or H2S that may be stored through mineral precipitation and 2) the 

effects of mineral precipitation on permeability and injectivity. The specific elements of a 

geochemistry evaluation for any given CCS project will be site-specific, depending on the nature 

of the rocks, formation fluids, and injection stream that will be involved. However, in general, 

geochemistry evaluations for CCS projects should include detailed analytical data on mineralogy 

from core or cuttings of the injection target zones and associated cap rocks being considered, 

rock property data such as porosity and permeability, and detailed data on the chemical 

characteristics of both the formation fluids and the injection stream. Mineral compositions can be 

obtained by scanning electron microscopy (SEM), x-ray diffraction (XRD), and x-ray 

fluorescence (XRF) techniques. Fluid chemistry data can be obtained from the analysis of 

samples of formation fluids, preferably samples that were collected and preserved at reservoir 

pressure. The mineral and fluid compositional data can then be used to perform geochemical 

modeling to assess the long-term fate of acid gas in the subsurface. A wide variety of 

geochemical evaluation activities were conducted for the Zama project, and a full presentation of 

all of those activities and results is beyond the scope of this document. However, some of the 

activities and their results are notable and are described below. 

 The Alberta Research Council (ARC) performed numerical simulations to examine the 

behavior of the CO2 and H2S components of the acid gas after injection into a depleted reservoir. 
24 

The reservoir and process conditions were based on the conditions associated with injection into 

the Slave Point Formation in the Zama Field. The composition of the acid gas was assumed to be 

70% CO2 and 30% H2S, and the temperature and pressure of the reservoir were assumed to be 

50°C and 14 MPa. The reservoir mineralogy was identified as calcite, quartz, and dolomite, with 

trace amounts of clays. In addition, there is an appreciable amount of iron within the carbonate 

minerals. The modeling was performed using the reservoir simulator GEMTM (Computer 

Modelling Group), which has the capacity to model the flow of fluids and reactions between 

minerals and aqueous fluids. 

 The modeling results demonstrate that the leading edge of the acid gas plume will become 

enriched in CO2. This observation is in agreement with recently reported field, lab, and modeling 

results (Talman and Perkins, 2009). The enrichment is due, at least in part, to the preferential 

absorption of H2S into the aqueous phase. However, in the presence of reactive iron-bearing 

minerals, other processes can lead to the separation of the two gases. As the acid gas plume 

reacts with the carbonate minerals, significant amounts of iron and bicarbonate are added to the 

water. This iron rapidly precipitates as an iron sulfide when H2S is present in the gas phase. The 

iron sulfide precipitation produces a significant amount of acid; this acid drives much of the 

bicarbonate out of aqueous solution, leading to further CO2 enrichment in the gas plume. 

 Numerical modeling simulations were also conducted as part of the ARC geochemistry 

work. Simulations were run for 200 years following acid gas injection. The numerical results 

indicate that significant concentration gradients may remain in the reservoir at the end of this 

time. Dense, CO2/H2S-rich gas compositions will exist at the bottom of the reservoir, with 

primarily methane-rich gases existing near the top. This behavior was found to be sensitive to the 

choice of the diffusion coefficients that are used in the model. 

 These modeling results demonstrate that the behavior of injected acid gas can be 

significantly affected by the presence of reactive iron minerals in the reservoir. Furthermore, 

these results indicate that the vertical variations in the gas-phase composition may be significant, 

so that the upper reaches of a storage reservoir may not be significantly affected by the injection 

(Talman and Perkins, 2009). 

 The Zama geochemistry evaluations also examined the relationships between geochemical 

interactions and effects on permeability of reservoir and seal rocks. Examination of the literature 

shows that certain natural CO2 reservoirs have experienced a defined (and measurable) natural 

leakage rate (Le Guen and others, 2008; Zhaowen and others, 2005). While it is expected that the 

very low permeability of the Muskeg cap rock will contain the injected CO2 and other acid gas 

components, it is also known that capillary fluid entry and/or interfacial fluid tension (IFT) will 

allow some restricted fluid to imbibe into the cap rock. It is possible that, in some cases, there 

will be low levels of sustained diffusion into the cap rock in direct contact with the reservoir. 

While it seems clear that existing natural micro-fractures or flaws in the cap rock are of more 

concern, this IFT-related issue has generated a significant volume of technical literature and was 

examined in the context of acid gas injection at Zama. 

 Aqueous acid gas mixtures do typically have lower IFT pressures than the hydrocarbons 

that were originally trapped by the cap rock (Nelson and others, 2005; Oldenburg and others, 

2002; Ostrowski and Ulker, 2008). Therefore, it may be optimistic to assume a reservoir that 
25 

successfully contained hydrocarbon reserves (or even high-purity CO2) over geologic time will 

automatically contain 100% of the aqueous fluid mixtures with lower interfacial tensions such as 

CO2 in brine or CO2 and H2S mixtures in brine. It must be recognized that this leakage 

mechanism is rock-, pressure-, temperature- and fluid-dependent, and the variability of CO2–

brine IFT pressures for brines of differing salinity is well documented (Li and others, 2005; 

Zhaowen and others, 2005). 

 CO2–brine IFT decreases with increasing pressure, while increasing temperature and brine 

salinity have the opposite effect. Specific data on H2S–water and CO2–H2S IFT have recently 

been reported (Shah and others, 2008) in which the H2S–brine system acts in a similar manner 

but at a much lower capillary entry pressure than the CO2–brine solution. The H2S–water IFT is 

30% to 40% lower than that of the CO2–water IFT. However, for both systems, the IFT is much 

lower than the in situ hydrocarbon IFT that originally provided the trapping mechanism for the 

hydrocarbons against the cap rock layer. Thus, additional laboratory IFT studies are suggested to 

further investigate aqueous H2S and aqueous CO2–H2S mixtures. 

 In conclusion, these studies suggest that containment of acid gas in a geological reservoir 

setting may be affected by the capillary properties of the acid gas–brine solution in relation to the 

capillary pore entry pressure of the brine-saturated cap rock system. In particular, the studies 

suggest that the maximum reservoir pressure to avoid acid gas imbibition into the cap rock may 

be lower than current pressure limits derived from mechanical stress testing. The designated 

maximum operating reservoir pressure will be pool-specific. If a lower maximum reservoir 

pressure limit is necessary, the estimates for storage capacity in each reservoir will require 

review. The impact on the gas miscibility with the reservoir oil and the EOR project will also 

need to be reviewed. 

 Wellbore Integrity and Leakage Potential 

 Wellbores constitute a critical element with regard to the disposal and storage of acid gas 

and CO2 because they may provide a leakage pathway. It is not possible to determine the “exact” 

state of all wellbores; consequently, the approach that was used in the Zama project, and which is 

recommended for use in areas with a large number of existing wellbores, was to combine both 

“real” field data and analytical or numerical simulations to quantify processes associated with the 

hydraulic integrity of the wells. Statistical well geometry and performance data within the Zama 

field and surrounding regions were compiled from available databases. A database of projectspecific well data was constructed from detailed review and synthesis of available well file 

information. In a limited number of cases, data were available from old wellbores where cement 

samples had been taken to evaluate their stability in the long term. Based on this information, 

probabilistic assessments of wellbore integrity issues under the conditions of acid gas and CO2

injection and long-term buoyancy-driven forces were evaluated. 

For the Zama project, a review of the integrity of the casing cement, and completion of the 

new acid gas EOR/CCS wells drilled into the F Pool as part of the project was conducted and led 

to the following conclusions: 

• Overall Well Assessment – The integrity of the current wells is good, with no leaks to 

 date and a minimal to moderate probability of seepage or leaks, with the possible 
26 

 exception of the original 1967 well completion. This well was recognized as having the 

 greatest chance of seepage early in Phase II of the project based on its age and cement 

 quality, as well as the fact that it is plugged back to the Slave Point FFF completion 

 with a series of internal packer/bridge plugs that are capped with cement. As a result, 

 this well was proposed as the site for a gas-soluble tracer study. 

• Casing/Cement Integrity Assessment – No casing inspection logs were located for any 

 of the four wells in the F Pool. Nevertheless, there is minimal potential for leakage 

 from the three wells completed since 2004; however, the original well, which was 

 drilled in 1967, has the potential to allow leakage because of a very low production 

 casing cement top. The other three wells have surface casing cemented at or near 

 surface and should have minimal chance of a surface casing vent flow or shallow 

 seepage to groundwater. 

• Completion Integrity Assessment – The review of the tubing strings and downhole 

 completion equipment utilized in the F Pool wells revealed that all of the wells have 

 standard L-80 tubing above the packers and should be monitored for corrosion. 

 Typically, this is done by pressure testing the annulus to ensure that there is no 

 communication with the tubing. The three newest wells utilize corrosion-resistant 

 Incoloy packers, profiles, and on–off tools from the packer down, along with SM-222 

 coating of the tubing joints below the packer. Two of the production strings also utilize 

 complex multiple packer assemblies to allow for tracking of the EOR flood interface. 

 This has the potential to provide good data regarding the sweep and recovery efficiency 

 but also carries some risk due to the numerous potential leak paths in the completions. 

 Tracer and Pressure-Monitoring Programs 

 One of the primary concerns with any CO2 or acid gas injection project is leakage of the 

injected gas from the target reservoir through the cap rock and into an overlying zone of high 

porosity and permeability. At Zama, this concern was addressed by using an existing well that is 

completed in the Slave Point FFF Pool, which lies directly over the Keg River F Pool pinnacle 

reef, as a monitoring well. Specifically, the Slave Point FFF Pool well was used to collect Slave 

Point Formation fluid samples that were analyzed for a tracer that was injected into the Keg 

River F Pool. The monitoring well was also used to monitor for changes in Slave Point FFF Pool 

pressure that might be indicative of acid gas leakage into the Slave Point Formation. The concept 

for the pressure-monitoring program was that close examination of historical pressure data from 

the Slave Point FFF Pool well and comparison of those data with pressure data collected during 

the Zama acid gas EOR and CCS project could provide insight regarding the potential use of 

pressure data as a low-cost monitoring technique. 

 A gas-soluble, fluorocarbon-based chemical tracer compound (5.5 kg of Core Labs IGT1100) was injected into the Keg River F Pool in February 2008. Other naturally occurring 

compounds, such as CO2 or H2S with unique isotopic fingerprints, were considered and, in some 

geological settings, may be appropriate and more cost-effective. However, the presence of large 

amounts of naturally occurring CO2 and H2S throughout the Devonian-age rocks of northwestern 

Alberta, including the Keg River and Slave Point Formations, combined with the complicated 
27 

history of acid gas production and disposal in the Zama area led the technical team to 

recommend the use of a proprietary synthetic fluorocarbon-based tracer compound. Initial gas 

sampling was performed on the Slave Point Pool in April 2008. A further gas-sampling operation 

was conducted on December 20, 2008. No tracer has been detected in any of the gas samples to 

date, although the scheduled mid-2009 samples have not yet been collected as a result of 

personnel and budget restrictions. The on-site tracer-sampling program is complicated by the fact 

that the Slave Point well “watered out” and no longer flows gas. Sampling from a flowing well 

would be much simpler and less expensive. 

 The pressure-monitoring program at Zama consisted of monitoring of the reservoir 

pressures of both the Keg River F Pool at 2175 psi (±15,000 kPa) and the Slave Point FFF Pool 

at roughly 870 psi (3000 kPa). These pressures were monitored on the same 6-month schedule as 

the collection of the tracer samples based on the premise that if the wellbore allows leakage, it 

will eventually be detected by an increase in the lower-pressure Slave Point completion. The last 

two Slave Point FFF pressures indicate a small 29-psi (200-kPa) increase in pressure (Figure 14). 

At this point, it cannot be determined if this is a result of two different gauge readings, water 

influx, an increase of pressure due to the arrival of a pressure front being generated by the Keg 

River F Pool injection, or seepage of acid gas from the Keg River F Pool into the Slave Point 

FFF Pool. More pressure data are required before the source of any pressure change can be 

attributed to any of these or any other causes. 

 Appendix B shows the techniques employed over the course of the project to monitor the 

effects of acid gas injection at the Zama Field demonstration site. The baseline state of each of 

these parameters was determined as described above. 

Figure 14. Pressure-monitoring MVA program. 
28 

INJECTION PROGRAM 

 The injection program for the Zama EOR and CCS project was designed, implemented, 

and operated by Apache Canada according to regulatory guidelines established by the Alberta 

ERCB. The purpose of the injection program is to 1) cost-effectively capture, transport, and 

inject acid gas from the Zama gas-processing plant into the Zama F Pool reservoir; 

2) facilitate the production of incremental oil from the F Pool reservoir; and 3) support the 

documentation of effective CO2 storage in the F Pool. Over the course of the Zama EOR and 

CCS project, a variety of site-specific design and operational challenges were identified and 

addressed to varying degrees of success. A detailed discussion of the site-specific issues is 

beyond the scope of this report. Rather, as an RTIP, this report will focus on the components of 

the Zama Keg River F Pool acid gas injection program that may be more broadly applicable 

across North America. Key aspects of the Zama injection program that this RTIP will address 

include the capture and infrastructure elements of the project, well preparation and maintenance 

activities, acid gas injection and EOR operations, and determination of CO2 storage capacity. 

 Capture and Infrastructure at Zama 

 The Zama gas-processing plant handles all of the production taken from the field and 

prepares it for sales to the market. Originally, the solution gas produced from Keg River oil pools 

contained approximately 5% CO2 and 3% H2S. The Zama gas-processing plant also processes 

nonassociated gas from the field, which contains approximately 13% H2S and 8% CO2. Finally, 

an amine-based acid gas removal (AGR) system generates an effluent stream that is 

approximately 4% methane, 66% CO2, and 30% H2S. The effluent acid gas exits the AGR 

system in the gas plant at essentially atmospheric pressure. Using a corrosion-resistant 

compressor, the acid gas is compressed to the appropriate pressure for injection. Additional acid 

gas is stripped from oil produced through EOR activities at a separator tank, compressed, and 

commingled with the previously discussed stream. It is this gas stream that is injected as the acid 

gas miscible flood solvent. The acid gas stream is transported from the gas plant to the injection 

site through a pipeline made of corrosion-resistant steel. 

 It is worth noting that several site-specific operational challenges were identified over the 

course of operating the acid gas EOR/CCS facility. While a detailed description and discussion 

of these issues is beyond the scope of this report, of particular importance to the operation of the 

Zama injection project were: 

1. Optimization of perforation zones within each pinnacle reef. 

2. Optimization of gas injection rates. 

3. Plugging/freezing of flow lines and wells due to hydrates, wax, and asphaltene 

 precipitation (wax-stabilized hydrates). 

 Any or all of these items may represent operating challenges to any EOR/CCS operating 

facility and have the potential to result in increased engineering work as well as increased 

operating costs. Optimization of the perforation zones and gas injection rates will be entirely 

site-specific, and the degree of difficulty in determining the optimal conditions will be largely 
29 

dependent on the degree of heterogeneity within the target reservoir. The plugging/freezing 

issues that were encountered over the course of the Zama project may be an issue wherever a 

combination of oil characteristics and cold climate conditions may be found. Figure 15 shows a 

picture of a plugged flow line. If this occurs, the plug can rarely be cleared without excavation of 

the flow line, as shown. At Zama, Apache Canada has had to insulate lines and use a 

combination of heat and chemicals to economically resolve these problems. However, it is 

important to note that, as was the case at Zama, none of these challenges are entirely new to the 

oil and gas industry and, given time and thoughtful consideration, all of them are manageable 

and do not threaten the commercial use of acid gas injection for EOR or as a viable CCS 

strategy. 

 Well Preparation and Maintenance 

CCS project operators and related stakeholders generally agree that the ability of new and 

existing wellbores to reliably contain CO2 is of upmost importance. The main reasons for this 

include validation of storage volumes and related CO2 storage credits, minimizing MVA 

operations, and to gain public confidence. The collective documentation of the required design 

features for new and old wells is commonly termed a basis of design (BoD). The BoD 

establishes a clear understanding of the required well functional and performance specifications, 

life span, injection fluid and corrosion specifications, reservoir characterization, completion 

configuration, corrosion and integrity-monitoring plan, barrier and safety systems, and welloperating and maintenance schedule. Some of the key considerations that went into the 

development of the BoD are discussed below. 

 The basis of oil and gas industry well design for CO2 injection and storage stems from 

long-established practices developed to inject associated CO2, H2S, acid gas, saline brine, and 

waste fluids within a wide variety of reservoirs since the mid-1900s. Among these fluids, acid 

gas (H2S + CO2 + SO2) has the highest potential for wellbore corrosion and health, safety, and 

environmental (HSE) damage as H2S can cause sudden deadly respiratory arrest. Dry CO2 alone 

Figure 15. Operation to clear a plugged flowline. 
30 

is minimally corrosive, but wet CO2 (mixed with saline brine) can be very corrosive and 

represents a significant challenge to petroleum industry standards. Fortunately, preventing and 

mitigating leakage of petrochemical and petroleum fluids is a long-standing objective of the oil 

and gas industry. 

 Despite the challenges presented above, the injection of CO2 and acid gas is a relatively 

common practice that has been used for decades in North America. North American CO2

injection has roots within the Permian Basin of West Texas, with the use of CO2 for EOR. The 

first known project was started by Chevron in Scurry County, Texas, in January 1972. Since 

then, CO2-based EOR has been conducted on a large scale throughout the world, including 

several large oil fields in West Texas, Saskatchewan, and Alberta. In the Western Canadian 

Sedimentary Basin, acid gas injection experience is similar to that of CO2. Some moderately sour 

gas injection has been under way since the late 1970s as part of pressure maintenance schemes 

for selected oil fields. In 1989, the injection of acid gas for the purpose of outright disposal 

began when Chevron installed the first acid gas compression and injection operation at Acheson, 

Alberta (Royan and Wichert, 1997). This industry activity has led to the current status whereby 

the materials and procedures to drill and complete a well for the production or injection of CO2, 

H2S, and/or acid gas mixtures are very well defined by regulations, standards, and IRPs. 

The selection of corrosion-resistant materials for well completions is critical to the longterm operation and maintenance of an acid gas EOR and/or CCS project. Manufacturer-supplied 

guides can provide useful insight to the selection of corrosion-resistant alloy (CRA) steel based 

on the exposure to CO2 and H2S at different temperatures. While guides such as this are useful, it 

is important to note that economics and practical considerations must also be factored into the 

final design. For instance, exclusive use of a simplified manufacturer’s guide would lead one to 

assume that there should be considerable use of high-cost chrome- and nickel-based alloys. 

However, as a result of the significant incremental costs for CRA pipe, most CO2 and acid gas 

applications have turned to the use of low-alloy carbon steel protected by coatings or linings for 

casing and tubing applications. In some circumstances, a well design will utilize one or two 

joints of CRA casing within critical wellbore sections such as casing over the reservoir zone 

where repeated reseating of a production packer may be required. Smaller equipment items such 

as packers, flow control devices, and subsurface safety valves are also often constructed of 

nickel-based alloys as it is more difficult to protect all of the wetted and working surfaces of 

these items with coatings. This approach has been applied successfully to the design of acid gas 

injection and sour gas production wells throughout North America as well as at Zama. 

 The use of corrosion-resistant cements is also a critical component to maintaining wellbore 

integrity. On balance, the most recent work strongly indicates that properly designed portlandbased oil well cements are very CO2-resistant (Crow and others, 2008). Duguid (2008) provides 

a good summary of recent experimental work and concludes that a well-cemented well with good 

zonal isolation will be safe for 30,000 to 700,000 years. These publications consistently show 

that CO2 and brine mixtures do change the texture and mineralogy of portland oil well cements, 

but that the changes do not significantly reduce the hydraulic seal afforded by the cement sheath. 
31 

 Well preparation activities at Zama included conducting a variety of tests to determine the 

integrity of the existing F Pool wells. The integrity of new or old wells is easily verified with 

modern downhole logging tools, including mechanical caliper tools, electromagnetic tools, and 

acoustic resonance tools. An example of the types of data used to evaluate wellbore integrity is 

shown in Figure 16. Any existing field or area proposed for CO2 storage must include an 

evaluation of the ages and wellbore integrity of existing wells as part of the local risk evaluation. 

Even very old oil field wells have been shown to provide reliable well integrity for CO2 injection 

and storage. 

 Acid Gas Injection 

 The injection of acid gas into the Zama Keg River F Pool pinnacle reef was initiated in 

December 2006. Injection continued well into 2009, with some interruption for well 

maintenance, and Apache Canada plans call for continued injection beyond 2010. Some of the 

more important statistics for the period of operation between December 2006 and May 2009 are 

summarized below. 

 During the 30 months between December 2006 and August 2009, approximately 2500 

metric tons/month of acid gas was injected into the Keg River F Pool (1850 metric tons of CO2

and 650 metric tons of H2S). The injection was at an average depth of 1455 m, which was the top 

of the Keg River Pool pinnacle reef. These injection rates were designed to maintain the 

prescribed miscible pressure range and maintain a stable displacement. The average daily acid 

gas injection rate throughout 2009 has been approximately 1.4 MMscf (50 × 103m3/d). Through 

August 30, 2009, the cumulative amount of gas injected into the F Pool was 1) 40,160 metric 

tons of acid gas, 2) 29,720 metric tons of CO2, and 3) 9640 metric tons of H2S. After adjustment 

for the reproduced mass, the net stored CO2 and H2S in the F Pool is 16,050 and 5807 metric 

tons, respectively. 

 The acid gas injection and production histories for the period of December 2006 through 

May 2009 are shown in Figures 17 and 18. During this 30-month period, injection rates have 

varied to either maintain pressure in the F Pool or conduct well maintenance activities. The longterm average injection rate is roughly 2500 metric tons per month. Daily averages were 

approximately 60.8 metric tons of CO2 and 21 metric tons of H2S. 

 Over the entire 4-year life of the F Pool project (December 2006 to December 2010), 

between 40,000 and 60,000 metric tons of acid gas will be injected. Prior to decommissioning at 

the end of the EOR program, some of the stored acid gas volume may be produced back for 

injection into one or more of the other EOR/storage pools. This ability to “bank” and reuse the 

acid gas is seen as a distinct advantage for supplying injection gas to multiple EOR/storage pools 

in the area. However, the net volume of acid gas expected to be permanently retained in the F 

Pool upon completion of the EOR project (approximately 2019) is in excess of 40,000 metric 

tons. Figure 19 presents the cumulative injected and stored F Pool mass and volumes to May 30, 

2009. Figure 20 details the net stored CO2 mass. 
32 

Figure 16. Example of raw logging data and interpretation showing casing deformation (courtesy 

of Baker Hughes). 

Figure 17. Monthly F Pool injection history – volume and mass. 
33 

Figure 18. Keg River F Pool oil production and acid gas injection profiles. 

Figure 19. Cumulative F Pool injected volumes and mass of acid gas. 
34 

Figure 20. F Pool–mass of CO2 stored. 

 EOR Operations 

 As part of Apache Canada’s plans to conduct a new phase of oil recovery operations in the 

Zama oil field, a new production well was drilled into the F Pool in September 2004. The well, 

referred to as Production Well 1, was placed in production in August 2005. The well was 

perforated low in the formation and, unfortunately, was a poor producer, with a cumulative oil 

production of only about 75 m3 (470 bbls) between August 2005 and May 2006. In order to 

prepare the F Pool reservoir for acid gas injection and EOR, this well was then utilized to draw 

water from the lower portion of the pinnacle to lower the average reservoir pressure down to the 

original ERCB-approved range. This objective was accomplished by November 2006, but 

injection was not started until December 2006 when the Zama Keg River F Pool became the 

third pool in the Zama oil field to be placed on acid gas EOR. 

 By December 2007, acid gas injection had been conducted for a year but oil production 

had not yet begun. Apache Canada reconsidered the production strategy in the F Pool, resulting 

in plans to conduct a workover on Production Well 1 and to drill an entirely new well, 

Production Well 2, into the F Pool. A workover of Production Well 1 was completed in June 

2008, and Production Well 2, the fourth and newest well in the F Pool, was drilled in August 

2008. Some additional oil was produced as a result of these actions. Specifically, the workover of 

Production Well 1 yielded 350 m3

 (2200 bbl) of oil, with the cumulative oil production from the 

beginning of EOR totaling roughly 430 m3 (2700 bbl). The newest well in the pool, with only the 

upper set of perforations open to production, produced 8900 bbl of oil during the first 3 months. 

The configuration of the final F Pool EOR scheme is shown in Figure 21. 
35 

Figure 21. Zama Keg River F Pool EOR scheme as of May 2009. 

 Historically, the F Pool had declined in production to an uneconomical rate. Through a 

modeling study conducted by the University of Regina in 2005, it was determined that injection 

of acid gas for EOR could revive this pinnacle and return it to an economically viable producer. 

As of June 2009, there has been minimal incremental oil production from the F Pool as a result 

of the acid gas injection, as it appears the project is still in the dewatering and displacement 

phase. Acid gas injection at the top of the structure is being balanced by high water-cut 

production from the bottom of the structure to develop and maintain stability of the miscible 

sweep. Water is being displaced in a gravity-stable, top-down manner. While the oil bank has not 

yet reached the main production perforations in Production Well 1, it has reached the producing 

interval in Production Well 2. 

 Prior to the EOR project, the OOIP in the Keg River F Pool was estimated to be 

approximately 3914 Mbbl. It should be noted that revised estimates using updated reservoir 

models now estimate the total volume to be approximately 5000 Mbbl. The volume of oil 

recovered during the three stages of oil recovery are as follows: 1073 Mbbl (27%) were 

recovered during primary production, 35 Mbbl (1%) during secondary production (water 

flooding), and an anticipated 588 Mbbl (15%) to be produced during tertiary recovery associated 

with acid gas injection. Roughly 57% (2218 Mbbl) of the OOIP is currently estimated to be 

unrecoverable by current methods (Figure 22). 
36 

Figure 22. Keg River F Pool volumetric estimation of OOIP and subsequent production 

prediction. 

 Determination of CO2 Storage Capacity 

Through August 30, 2009, the cumulative amount of gas injected into the F Pool was 

1) 40,160 metric tons of acid gas; 2) 29,720 metric tons of CO2; and 3) 9640 metric tons of H2S. 

After adjustment for the reproduced mass, the net stored CO2 and H2S in the F Pool is 16,050 

and 5807 metric tons, respectively. 

 As described above, it is anticipated that over the entire 4-year life of the F Pool project 

(December 2006 to December 2010), between 40,000 and 60,000 metric tons of acid gas will be 

injected. It is also anticipated that some of the stored acid gas volume may be produced back to 

surface for injection into one or more of the other EOR/storage pools that exist in the Zama oil 

field. This ability to “bank” and reuse the acid gas is seen as possibly being necessary for 

supplying injection gas to multiple EOR/storage pools in the area, as the output of acid gas from 

the Zama gas plant is not considered to be large enough to meet all of Apache Canada’s EOR 

goals for the Zama oil field. However, the net volume of acid gas expected to be permanently 

retained in the F Pool upon completion of the EOR project is in excess of 40,000 metric tons. 

While this value is not of the scale of many commercial projects, it should be noted that there are 

currently more than 800 pinnacles of this type producing from the Zama Field. When taking 

these additional pinnacles into consideration, the field becomes a significant site for CCS 

activities. 

New reservoir-modeling efforts were conducted to estimate the ultimate CO2 storage 

capacity of the Zama Keg River F Pool pinnacle reef and predict the fate of the injected acid gas. 

Specifically, conventional material balance models of the reservoir had to be updated with 

compositional pressure–volume–temperature to allow for evaluating original black oil fluids (oil, 
37 

gas, water) along with the acid gas. However, models with and without this upgrade provided 

successful pressure history matches by including a very weak aquifer that only has a small 

impact during the shut-in period. This observation was consistent with the level of pressurization 

that occurred in the F Pool after primary oil recovery operations and water injection activities 

ceased in 1992 and also supports the conclusion that there is only a minimal chance that the acid 

gas will be displaced under the spill point at the base of the F Pool. 

 Furthermore, it was concluded that the reservoir material balance provides an acceptable 

reproduction of the Keg River pool production history. Specifically, the compositional model 

allows for reliable predictions of pool performance and response and, based on the allowable 

operating pressure, validates the F Pool volume and EOR potential and establishes available acid 

gas storage volumes. It also validates that the F Pool has minimal connectivity to the underlying 

Lower Keg River Aquifer, indicating that the pool will pressure up prior to forcing any 

significant volume of acid gas below the pinnacle spill points. 

KEY OBSERVATIONS, CHALLENGES, AND LESSONS LEARNED 

 As described above, the PCOR Partnership’s Phase II activities at Zama combined a 

wealth of historical information with newly generated laboratory- and field-based data to develop 

a broad range of previously unavailable insights regarding the injection of acid gas for EOR and 

CCS. These insights can provide stakeholders and planners of future similar projects with the 

ability to make informed decisions for a variety of design elements. Project-critical technical 

areas for which information was compiled for this RTIP include baseline geological and 

hydrogeological characterization, wellbore integrity issues, determination and implications of 

geomechanical properties of reservoir and seal rocks, expectations for geochemical interactions, 

prediction of near- and long-term effects and fate of the injected gases, and design and operation 

of wells and surface infrastructure in the presence of high concentrations of acid gas. Some of 

the key observations, challenges, and lessons learned over the course of the Zama acid gas 

injection project are briefly summarized below. 

 Suitability of Pinnacle Reefs for Acid Gas Injection and Long-Term CCS 

 Based on the available data, the geological studies concluded that the injection of acid gas 

into the pinnacle reefs of the Zama Keg River Formation is a safe operation. The acid gas will be 

confined to the injection horizon by the reef structures that originally trapped the oil and gas. 

There is minimal potential for acid gas leakage through faults and fractures in the Zama area or 

for acid gas migration to shallower strata, potable groundwater, or to the surface as a result of 

flow through naturally occurring permeability streaks or flow paths. 

 The strength of the reservoir and cap rock formations, as determined by the geomechanical 

and geochemical evaluations, combined with the closed architecture of the pinnacle structure and 

the very conservative maximum operating pressures leave little possibility of lateral migration 

outside of the reef structures. Further, the results of the regional hydrogeological study indicates 

that any potential dispersion beyond the individual pinnacle spill points into the regional aquifer 

would still result in storage occurring before the plume had traveled a significant distance, e.g., 
38 

the maximum velocity of the formation water is sufficiently slow that it would take as mush as 

800,000 years for a fluid molecule to reach a Keg River Formation outcrop. 

 When combined with data from laboratory pore entry mercury injection pressure tests and 

mechanical stress testing on similar area cores, as well as log analyses and drilling reports, there 

is strong evidence that the thick (200 ft [60 m] to 300 ft [90 m]) Muskeg Formation 

dolomite/anhydrite sequences provide a competent, dense, and essentially impermeable cap rock 

above the Keg River pinnacles. These data suggest that the F Pool pinnacle integrity far exceeds 

the current ERCB EOR pressure limit, and it could be proposed that following the completion of 

the EOR recovery, additional CO2 and/or acid gas volumes could be stored within this pinnacle 

by increasing the allowable storage pressure beyond the original reservoir pressure. 

 There are currently known to be over 800 pinnacle reefs in the Zama subbasin of the 

Western Canadian Sedimentary Basin. There are also known to be hundreds of similar pinnacle 

reefs that occur in the Williston Basin, Michigan Basin, and Illinois Basin, just to name a few. 

The geological and hydrogeological studies conducted at Zama provide supporting 

documentation that pinnacle reefs can be suitable and even excellent sites for CCS. 

 Relative Mobility and Fate of CO2 and H2S Within Carbonate Reservoirs 

 One set of questions that were identified early in the Zama project was whether or not the 

primary constituents of the acid gas stream would undergo separation within the reservoir, and if 

it did occur, what the magnitude and timing of that separation would be. The results of 

geochemical modeling conducted that used the geochemical and mineralogical properties of the 

F Pool reservoir indicated that the leading edge of the acid gas plume will become enriched in 

CO2. This observation was in agreement with the results of field- and laboratory-based analytical 

activities and other modeling efforts. The enrichment is due, at least in part, to the preferential 

absorption of H2S into the aqueous phase. However, in the presence of reactive iron-bearing 

minerals, other processes can lead to the separation of the two gases. As the acid gas plume 

reacts with the carbonate minerals, significant amounts of iron and bicarbonate are added to the 

water. This iron rapidly precipitates as an iron sulfide when H2S is present in the gas phase. The 

iron sulfide precipitation produces a significant amount of acid; this acid drives much of the 

bicarbonate out of aqueous solution, leading to further CO2 enrichment in the gas plume. 

 Additional transport studies suggest that containment of the acid gas in a geological 

reservoir may be affected by the capillary properties of the acid gas–brine solution in relation to 

the capillary pore entry pressure of the brine-saturated cap rock system. In particular, the studies 

suggest that the maximum reservoir pressure limitation to avoid acid gas leakage through, or 

imbibition into, the cap rock may be lower than current pressure limits derived from mechanical 

stress testing. The designated maximum operating reservoir pressure will be pool-specific. If a 

lower maximum reservoir pressure limit is necessary, the estimates for storage capacity in each 

reservoir will require review. The impact on the gas miscibility with the reservoir oil and the 

EOR project will also need to be reviewed. 
39 

 The results of the acid gas mobility and fate investigations conducted as part of the Zama 

project may be directly applicable not only to the hundreds of similar pinnacles in the Zama 

subbasin, but to acid gas injection projects in carbonate rock formations in general. 

 Effects of Acid Gas on Wellbores and Surface Infrastructure 

 The selection of corrosion-resistant materials for well completions and surface 

infrastructure is critical to the long-term operation and maintenance of an acid gas EOR and/or 

CCS project. Because of the higher costs of such materials, the judicious application of 

corrosion-resistant materials in the design of wells and surface facilities is required to maintain 

the proper balance of performance versus cost. For instance, as a result of the significant 

incremental costs for CRA pipe, most CO2 and acid gas applications have effectively used lowalloy carbon steel protected by coatings or linings for casing and tubing applications. In some 

circumstances, it may also be appropriate to utilize one or two joints of CRA casing within 

critical wellbore sections rather than throughout the entire length of the well. Smaller equipment 

items such as packers, flow control devices, and subsurface safety valves are also often 

constructed of nickel-based alloys, as it is more difficult to protect all of the wetted and working 

surfaces of these items with coatings. This approach has been applied successfully to the design 

of acid gas injection and sour gas production wells at Zama and, in most cases, can be broadly 

applied to similar injection schemes wherever they may be planned. 

The use of corrosion-resistant cements is also a critical component to maintaining 

wellbore integrity. In general, recent literature suggests that properly designed portland-based oil 

well cements are very CO2 resistant. In fact, the results of experimental work presented by 

Duguid conclude that a properly cemented well with good zonal isolation will be safe for 30,000 

to 700,000 years. The literature also consistently shows that while CO2 and brine mixtures do 

change the texture and mineralogy of portland cements used in oil wells, those changes do not 

significantly reduce the hydraulic seal afforded by the cement sheath. 

 A review of the integrity of the casing cement and completion of the acid gas EOR/CCS 

wells in the F Pool indicated that the integrity of the current wells is good. With respect to the 

infrastructure at Zama, some site-specific challenges were encountered, most notably the 

plugging of flowlines with asphaltines and waxes, particularly during the winter months. These 

problems were successfully addressed by Apache Canada through the combined use of heated 

and/or insulated flowlines and the introduction of chemical additives to prevent the coagulation 

of those materials. It is important to note that none of the operational challenges at Zama are new 

to the oil and gas industry and, given time and thoughtful consideration, all of them are 

manageable and should not threaten the commercial use of acid gas injection for EOR or as a 

viable CCS strategy. 

 The Use of Pressure Data and Tracers to Detect Leakage 

 One of the goals of the Zama project was to minimize any disruption to normal 

commercial oil field operations. One way to achieve this goal was to look for ways to maximize 

the use of data sets that are routinely gathered over the course of oil field operations. Pressure 

data, both from the preinjection history of the F-Pool and from the injection phase of the project, 

were identified as one possible way of identifying the leakage of acid gas from the pinnacle reef 
40 

into an overlying formation. Another technique that would cause minimal disruption to normal 

operations was to do a one-time injection of a unique tracer compound into the acid gas stream 

early on during the injection phase and then monitor for that tracer in the various production and 

monitoring wells as part of periodic sampling and analysis events. In the case of the Zama F 

Pool, an existing gas production well that was completed into the overlying Slave Point 

Formation was selected to serve as a monitoring well for both the pressure measurements and 

tracer analyses. 

 With respect to the tracer monitoring, a gas-soluble chemical tracer compound (5.5 kg of 

Core Labs IGT-1100) was injected into the Keg River F Pool in February 2008. The collection 

and analysis of fluid samples from the Slave Point FFF Pool for the tracer was conducted on a 

6-month schedule. No tracer has been detected in any of the gas samples to date. 

 Historical and current pressure data were gathered for both the Keg River F Pool and the 

overlying Slave Point FFF Pool. During the Zama injection project, initial pressure testing was 

performed on the Slave Point FFF Pool in April 2008. A further pressure survey and gassampling operation was conducted on December 20, 2008. The historical data combined with the 

new data allowed for a comparison of the Keg River F Pool and Slave Point FFF pressure 

histories and indicate a small 29-psi (200-kPa) increase in pressure in the last two Slave Point 

FFF Pool measurements. At this point, it cannot be determined if this is a result of two different 

gauge readings, water influx, or an increase of pressure due to seepage. More pressure data are 

required before the source of any pressure change can be attributed to any of these or any other 

causes. 

 Generally speaking, the results of the tracer and pressure-monitoring activities at Zama 

indicate that both techniques hold considerable promise for application as useful, noninvasive, 

cost-effective elements of an MVA plan. 

 Nontraditional Economic Components 

 One of the primary goals of the Zama project, especially with respect to MVA, was to 

establish a basis for the creation and eventual monetization of carbon credits associated with the 

CCS component of the project. The MVA activities conducted at Zama were designed to yield 

data that would demonstrate 1) the containment of the injected CO2, 2) the mass of CO2 stored, 

and 3) the long-term safety of the project with respect to human health and the environment. The 

MVA data generated over the course of the Zama project have certainly provided a technically 

robust, detailed accounting of all three of these aspects. Unfortunately, robust carbon credittrading markets for credits associated with geological storage of CO2 have been very slow to 

develop and, to date, the Zama project does not have any carbon credits associated with it. 

 While carbon credits have not yet been established for the Zama project, it is worth noting 

that the acid gas injection program has yielded tax credits for Apache Canada. To encourage the 

development of a CCS industry in Alberta, the provincial government, through the Alberta 

Department of Energy, has instituted a Royalty Credit Program (Alberta Department of Energy, 

2005). This program offers a royalty reduction to companies that use CO2 in EOR operations and 

that meet certain qualification criteria. Apache Canada has qualified for this tax credit, and 
41 

royalty relief is currently being awarded for the G2G Pool in the Zama oil field. Applications for 

the F and NNN Pools at Zama have been submitted but have not yet been awarded. 

REFERENCES 

Alberta Department of Energy, 2005, www.energy.gov.ab.ca/Oil/766.asp (accessed August 

2009). 

Alberta Oil and Gas Conservation Act, 2009, www.eub.gov.ab.ca/bbs/requirements/actsregs/ 

ogc_act.pdf (accessed August 2009). 

Crow, W., Williams, B.D., Carey, B., Celia, M., and Gasda, S., 2008, Wellbore integrity of a 

natural CO2 producer: Presented at the 7th Annual Conference on Carbon Capture and 

Sequestration, Pittsburgh, Pennsylvania, May 5–8, 2008. 

Duguid, A., 2008, An estimate of the time to degrade the cement sheath in a well exposed to 

carbonated brine, in Proceedings of the 9th International Conference on Greenhouse Gas 

Control Technologies: Washington, D.C., November 16–20, 2008. 

Energy Resources Conservation Board, 1994, Directive 051: Injection and disposal wells – well 

classifications, completions, logging, and testing requirements, www.ercb.ca/docs/ 

documents/directives/Directive051.pdf (accessed August 2009). 

Energy Resources Conservation Board, 2008, Directive 071: Emergency preparedness and 

response requirements for the petroleum industry, www.ercb.ca/portal/server.pt/ 

gateway/PTARGS_0_0_313_248_0_43/http%3B/ercbContent/publishedcontent/publish/ercb_

home/industry_zone/rules__regulations__requirements/directves/directive071.aspx (accessed 

August 2009). 

Energy Resources Conservation Board, 2009, Directive 065: Resources applications for 

conventional oil and gas reservoirs, www.ercb.ca/docs/documents/directives/Directive065. 

pdf (accessed August 2009). 

Hyne, N.J., Dictionary of petroleum exploration, drilling & production, Pennwell Books, 1991. 

Le Guen, Y., Le Gouevec, J., Chammas, R., Gerard, B., and Poupard, O., Oxand S.A.; Van Der 

Beken, A., and Jammes, L., 2008, Schlumberger Carbon Services, CO2 Storage – Managing 

the risk associated with well leakage over long timescales, in 2008 SPE Asia Pacific Oil & 

Gas Conference and Exhibition: Perth, Australia, October 20–22, 2008, SPE Paper 

no. 116424. 

Li, S., Dong, M., Li, Z., Huang, S., Qing, H., and Nickel, E., 2005, Gas breakthrough pressure 

for hydrocarbon reservoir seal rocks: implications for the security of long-term CO2 storage in 

the Weyburn Field: Geofluids, v. 5, no. 4, p. 326–334. 
42 

Li, Z., Dong, M., Li, S., and Huang, S., 2005, CO2 storage in depleted oil and gas reservoirs—

caprock characterization and storage capacity: Science Direct Energy Conversion and 

Management 2005. 

Nelson, C.R., Evans, J.M., Sorensen, J.A., Steadman, E.N., Harju, J.A., 2005, Factors affecting 

the potential for CO2 leakage from geologic sinks: Grand Forks, North Dakota, Energy & 

Environmental Research Center, October 2005. 

Oldenburg, C.M., Unger, A.J.A, Hepple, R.P., and Jordan, P.D., 2002, On leakage and seepage 

from geologic carbon storage sites: Earth Sciences Division, Ernest Orlando Lawrence 

Berkley National Laboratory, Berkley, California, June 2002. 

Ostrowski, L., and Ulker, B., 2008, Minimizing risk of gas escape in gas storage by in-situ 

measurement of gas threshold pressure and optimized completion solutions, in 2008 SPE 

Europe/EAGE Annual Conference and Exhibition: Rome, Italy, June 9–12, 2008, SPE Paper 

no. 113509. 

Royan, T., and Wichert, E., 1997, Acid gas injection eliminates sulfur recovery expense: Oil & 

Gas Journal, April 28, 1997. 

Schlumberger Oilfield Glossary, 2009, www.glossary.oilfield.slb.com/ (accessed September 

2009). 

Shah, V., Broseta, D., Mouronval, G., and Montel, F., 2008, Water/acid gas interfacial tensions 

and their impact on acid gas geological storage: International Journal of Greenhouse Gas 

Control, v. 2, 2008, p. 594–604. 

Skinner, F.D., McIntush, K.E., and Murff, M.C., 1995, Amine-based gas sweetening and claus 

sulfur recovery process chemistry and waste stream survey: Gas Research Institute Topical 

Report, December 1995. 

Smith, S.A., McLellan, P., Hawkes, C., Steadman, E.N., and Harju, J.A., 2008, Geomechanical 

testing and modeling of reservoir and cap rock integrity in an acid gas EOR/sequestration 

project, Zama, Alberta, Canada, in Proceedings of the 9th International Conference on 

Greenhouse Gas Control Technologies: Washington, D.C., November 16–20, 2008. 

Sorensen, J.A., Fraley, R.H., Gallagher, J.R., and Schmit, C.R., 1996, Background report on 

subsurface environmental issues relating to natural gas sweetening and dehydration 

operations: Gas Research Institute Topical Report, March 1996. 

Talman, S., and Perkins, E., 2009, Geochemical modeling of acid gas injection with reference to 

the Zama 08-33-115-6W6 well: Edmonton, Alberta, Canada, Alberta Research Council 

Carbon Energy Management, 67 p. 
APPENDIX A 

AN OVERVIEW OF ALBERTA REGULATORY 

AND PERMITTING SUBMITTALS
A-1 

Table A-1. Historical and Proposed ERCB F Pool Approval Conditions 

ERCB EOR Approval No. 10328A: Approval Specifics Summary – Original Conditions 

2) For the purposes of this approval, “miscible fluid” means gas that contains: 

a) A mixture of at least 0.97 mole fraction of H2S and CO2, with the remainder 

composed of other natural gas components. 

b) A H2S content not less than 0.25 mole fraction and not more than 0.40 mole fraction 

at any time. 

c) An average H2S content not less than 0.32 mole fraction based on a 3-month rolling 

average. 

5) The Operator shall conduct injection, to that part of the subject pool referred to in 

Appendix A, in accordance with the following requirements: 

a) Production, without injection, shall initially occur until the average reservoir pressure 

is between 14,450 kPa(g) and 13,700 kPa(g). Miscible fluid shall then be injected in 

sufficient volumes to maintain the average reservoir pressure between 13,700 kPa(g) 

and 14,450 kPa(g). 

b) Wellhead injection pressure shall not exceed 8000 kPa(g) at any time. 

c) The representative composition of the injected miscible fluid shall be determined on a 

biweekly basis, and the representative composition of the produced gas shall be 

determined on a monthly basis. 

ERCB EOR Approval No. 10328A: Approval Specifics Summary – Amendment 1 

2) For the purposes of this approval, “miscible fluid” means gas that contains: 

a) A mixture of at least 0.97 mole fraction of H2S and CO2, with the remainder 

composed of other natural gas components. 

b) A H2S content not less than 0.20 mole fraction and not more than 0.40 mole fraction 

at any time. 

c) An average H2S content not less than 0.23 mole fraction based on a 3-month rolling 

average. 

5) The Operator shall conduct injection, to that part of the subject pool referred to in 

Appendix A, in accordance with the following requirements: 

a) Production, without injection, shall initially occur until the average reservoir pressure 

is between 15,500 kPa(g) and 14,000 kPa(g). Miscible fluid shall then be injected in 

sufficient volumes to maintain the average reservoir pressure between 14,000 kPa(g) 

and 15,500 kPa(g). 

b) Wellhead injection pressure shall not exceed 8000 kPa(g) at any time. 

c) The representative composition of the injected miscible fluid shall be determined on a 

biweekly basis, and the representative composition of the produced gas shall be 

determined on a monthly basis. 

ERCB EOR Approval No. 10328A: Approval Specifics Summary – Amendment 2 

2) For the purposes of this approval, “miscible fluid” means gas mixture with the following 

physical properties: 

a) A minimum cumulative pseudo-critical temperature (cumulative from start of acid 

gas injection) of 310 K. 

b) A H2S content not more than 0.40 mole fraction at any time. 

c) A methane content not more than 0.11 mole fraction based on a 3-month rolling 

average. 

Continued . . . 
A-2 

Table A-1. Historical and Proposed ERCB F Pool Approval Conditions (continued) 

ERCB EOR Approval No. 10328A: Approval Specifics Summary – Amendment 2 

5) The Operator shall conduct injection, to that part of the subject pool referred to in 

Appendix A, in accordance with the following requirements: 

a) Production, without injection, shall initially occur until the average reservoir pressure 

is between 16,500 kPa(g) and 14,500 kPa(g). Miscible fluid shall then be injected in 

sufficient volumes to maintain the average reservoir pressure between 14,500 kPa(g) 

and 16,500 kPa(g). 

b) Wellhead injection pressure shall not exceed 8000 kPa(g) at any time. 

c) The representative composition of the injected miscible fluid and the representative 

composition of the produced gas shall be determined on a monthly basis. 
July 31, 2004 

Alberta Energy and Utilities Board 

Resource Applications Group 

640 – 5th Ave. S.W. 

Calgary, AB 

T2P 3G4 

Attention: Cheryl Adolf 

Resources Applications Group 

RE: Zama – Keg River F Pool – Enhanced Oil Recovery Scheme Application 

______________________________________________________________________ 

Apache Canada Ltd. (“Apache”) requests approval to implement an Enhance Oil 

Recovery (EOR) Miscible Flood project in the subject pool in accordance with Section 

26(1)(a) of the Oil and Gas Conservation Act. 

This application will discuss Apache’s plans to implement a series of EOR miscible flood 

schemes in selected pinnacles in the Zama area but the attached document will focus 

primarily on the subject pool for approval. Separate applications will be submitted for 

each pool to eventually be included in the overall project. 

The content of the attached document was written in compliance with the EUB 

Application Guide 65. A Guide 51 application for the injection well associated with this 

project will follow at a later date. 

We look forward to further discussion concerning this project. If you have any further 

information requirements related to this application please contact either Rob Lavoie, 

303-8584 or Doug Nimchuk, 261-1271. 

Yours Truly, 

Mike Thorson 

Reservoir Engineering Manager – Apache Canada Ltd. 
APPLICATION 

BY 

APACHE CANADA LTD. 

RESOURCE APPLICATION FOR APPROVAL 

TO IMPLEMENT AN ENHANCED OIL 

RECOVERY SCHEME 

IN THE 

ZAMA KEG RIVER F POOL 

USING ACID GAS AS A MISCIBLE 

FLOODING SOLVENT 

EUB GUIDE 65 SCHEDULE 1 AND 

SUPPORTING DOCUMENTATION 

MARCH 31, 2003 
Page 1 

Table of Contents

Definitions 

Background 

(Submission in accordance w/Section 26(1)(a) of the Oil and Gas Conservation Act) 

Guide 65 Schedule 1 

Zama Acid Gas Miscible Flood Development Plan Overview 

Supporting Documentation 

1. Project Location 

2. Previous Approvals for Zama Keg River F Pool 

3. Pool Order Number and Mapping of Pool Outline 

4. Geological Description 

5. Reservoir Production Performance History 

5.1. Reservoir Characterization 

5.1.1. Initial Conditions 

5.1.2. Summary of Reservoir Fluid PVT Studies Conducted 

5.1.3. Petrophysical Interpretations 

5.2. Production Performance and Pressure History 

5.3. Current Estimated Conditions 

5.4. Current Estimated Reservoir Pressures 

6. Proposed Production and Injection Wells 

7. Reservoir Development Plan 

7.1. Proposed Acid Gas Injection Plans (Acid Gas Source and Composition) 

7.1.1. Solvent Source Selection 

7.1.2. Transportation 

7.1.3. Injection Start-up Date and Proposed Injection Rate 

7.2. Minimum Miscibility Pressure Estimations and Laboratory Analysis 

7.3. Estimated Miscible Flood Sweep Efficiency 

7.4. Critical Injection Rate Analysis 

7.5. Performance Forecast Methodology – By Analogue Method 

7.6. Material Balance Derived Forecasts of Reservoir Pressure and Fluid Contact 

Movement 

8. Reserves Summary 

8.1. Initial Oil in Place 

8.2. Current Cumulative Recovery and Remaining Oil in Place 

8.3. Estimated Enhanced Oil Recovery Performance 

8.3.1. Production and Injection Forecasts 

8.3.2. Solvent Breakthrough Forecast 

8.4. Ultimate Expected Recovery Efficiency 

9. Guide 51 Compliance Plans 

10. Notifications and Safety Plans 

References 
Page 2 

List of Tables

1 Core Data from Zama Keg River F Pool - Well 4-36-116-6W6 

2 PVT Data and Material Balance Calculations 

4 Petrophysical Interpretations of Electronic Logs 

5 Pressure versus Cumulative Production Volumes - Keg River F Pool 

6 Acid Gas Injection - Gravity Stable Rate Calculations for the ZKR F Pool 

7 Performance Prediction for Early Breakthrough of Acid Gas - Zama KR F Pool 

8 Performance Prediction for Late Breakthrough of Acid Gas - Zama KR F Pool 

List of Figures

1 Map of the Zama Area and The Location of the Zama Gas Plant 

2 EUB G-Order for the F Pool 

3 Aerial Seismic Map of Proposed Zama Acid Gas Injection EOR Project 

4 Net Pay Isopach of the Zama Keg River F Pool 

5 Structure Contour Map of the Zama Keg River F Pool 

6 Annotated Cross-Section of the Zama Keg River F Pool 

7 Zama Core Air Permeability – Phi versus K-Vertical 

8 Zama Core Air Permeability – Phi versus K-Max 

9 Zama Core Air Permeability – Phi versus K-Horizontal 

10 Pressure and Production History for Zama Keg River F Pool 

11 MMP Correlations for Zama/Shekilie Areas 

12 Current vs Original Reservoir Pressures for EOR Candidates Near Zama Gas Plant 

13a All Rainbow Keg River Pools, Recovery Efficiency vs HCPVinj of Hydrocarbon Gas 

13b Waterflooded Rainbow Keg River Pools, Recovery Efficiency vs HCPVinj of Hydrocarbon Gas 

13c Not Waterflooded Rainbow Keg River Pools, Recovery Efficiency vs HCPVinj of Hydrocarbon Gas 

13d No Outliers Not Waterflooded Rainbow Keg River Pools, Recovery Efficiency vs HCPVinj of Hydrocarbon Gas 

14a Analytical Model for Zama Keg River Acid Gas Miscible Flood - Recovery Profile - Late Breakthrough 

14b Analytical Model for Zama Keg River Acid Gas Miscible Flood - Breakthrough Profile - Late Breakthrough 

15a Analytical Model for Zama Keg River Acid Gas Miscible Flood - Recovery Profile - Early Breakthrough 

15b Analytical Model for Zama Keg River Acid Gas Miscible Flood - Breakthrough Profile - Early Breakthrough 

16a Zama Keg River F Pool Recovery Rate Forecast 

16b Zama Keg River F Pool Recovery Rate Forecast 

17 Material Balance Analysis for the Zama Keg River F Pool 

Appendices

1. Measurement of CO2 and CO2 + H2S MMP for Zama Oil 
Page 3 

Definitions

CO2 Carbon Dioxide 

EOS Equation of State 

GOR Gas Oil Ratio 

GHG Green House Gas 

H2S Hydrogen Sulphide 

HCPV Hydrocarbon Pore Volume 

HCPVI Hydrocarbon Pore Volume Injected 

MMP Minimum Miscibility Pressure 

OGIP Original Gas In Place 

OOIP Original Oil In Place 

PVT Pressure Volume Temperature relationships for reservoir fluids 

RGIP Remaining Gas In Place 

ROIP Remaining Oil In Place 

VRR Voidage Replacement Ratio 

WAG Water Alternate Gas Injection Scheme 
Page 4 

Background 

Over the past three years Apache has invested significant resources into the acquisition 

and subsequent development of the Zama oil fields of North Western Alberta. Apache is 

in the process of implementing numerous waterfloods in separate oil pools consisting of 

relatively small Devonian Keg River pinnacles with significant vertical relief. 

Waterflooding and miscible flooding of these pinnacles has, in the past, proven to be a 

challenge for the operators in this region due to the small size and high degree of 

reservoir heterogeneity associated with these pools. 

This document is written for the Resource Applications department of the EUB and is in 

accordance with Section 26(1)(a) of the Oil and Gas Conservation Act. It outlines the 

plans to conduct an acid gas miscible flood in the subject pool and is one of a series of 

applications Apache plans to submit for similar pools in the area if economic 

performance justifies this. 

Although economics are not discussed in the attached support documentation for the 

EUB Guide 65, the number of pools Apache will apply enhanced recovery schemes to 

will depend on the economic outcome of the first series of pools and the availability of 

both Federal and Provincial incentives connected with the Canadian commitment to 

reduction in the intensity of Green House Gas (GHG) emissions. 

Zama Acid Gas Miscible Flood Development Plan Overview 

The Zama gas plant is currently owned and operated by Apache Canada Ltd. The plant 

currently generates about 175 e3

m3/day of acid gas consisting of 20 to 40% H2S and 80 to 

60% CO2. This amounts to a total of about 220 Tonnes/day of CO2 and 80 Tonnes/day of 

H2S. A portion of this effluent is currently processed through a Claus unit to generate 

elemental sulfur and sent to a sulfur block. The rest is injected into the Keg River 

formation using nearby acid gas injection wells. 

The Zama Acid Gas Miscible Flood Project proposes to re-configure the Zama Gas Plant 

to inject the entire acid gas stream into nearby Keg River formation pinnacles. This will 

permit the use of all acid gas handled at Zama as a miscible fluid and permit the shut 

down of the Claus unit and eliminate the further accumulation of elemental sulfur in the 

block. 

An estimated initial volume of 175 e3

m3/day of acid gas is expected to be available for 

enhanced oil recovery use in the area. Apache has identified nine (9) candidate pools 

within 6 km of the Zama Gas Plant which could benefit from acid gas miscible flooding. 

The initial acid gas supply would be adequate to begin flooding four (4) pools. 

Subsequent breakthrough of acid gas solvent would then be recycled into additional 

candidate pools in the area. Apache estimates there could be adequate acid gas volumes 

over the next 4 to 5 years to flood an additional five (5) pools. Since acid gas produced 

with the incremental oil is conserved for recycle, it is estimated that the number of pools 

that can be added to the project would increase by about one to two pools per year. The 
Page 5 

initial nine pool scheme is estimated to have the potential to contribute an enhanced oil 

recovery reserve of 509 e3

m3 (3.0 million barrels). Over a period of 16 years, 1 

megatonne of CO2 could be sequestered by this single project consisting of 9 pinnacles. 

Although there are over 600 of these pinnacles in the larger Zama area, if this project 

proves economic, the potential to further expand the project to an additional 80 to 100 

pinnacles could exist. 

Please refer to Figure 1 for a map of the Zama Area indicating the location of the Zama 

Gas Plant and the candidate pools. 
Page 6 

Supporting Documentation 

1. Project Location 

The larger project area of all currently planned acid gas miscible flood pools is shown in 

Figure 1. The Zama Keg River F pool (F Pool) location is highlighted in Figure 1. The 

EUB G-Order boundaries for the F Pool are provided as Figure 2. 

2. Previous Approvals for Zama Keg River F Pool 

In September of 1987 the EUB approved a produced water disposal scheme for this pool 

(Board Approval No. 5471, for Application No. 871257). 

3. Pool Order Number and Mapping of Pool Outline 

The EUB G-Order boundaries for the F Pool are provided as Figure 2. The Zama Keg 

River F Pool Order number is: POOL ORDER: 997 788006 2001-10-01

4. Geological Description 

In the Zama-Virgo oilfields the Middle Devonian Keg River Pinnacles are the primary oil 

producers in the area. These pinnacles were formed in a lagoon partially surrounded by 

banks and fronted by the Presqu’ile barrier to the west. There are over 400 pinnacles that 

have been discovered to date in the basin. The average size of a pinnacle is 16 ha at the 

base and 120m in height (approx. the size of dome stadium). The reef facies consists of 

common Devonian reef building organisms like tabular and bulbous stromatoporoids and 

tabulate corals. The reef is typically dolomitized with variable porosity and permeability. 

Principle rock types include wackestone, packstone, floatstone and rudstone. Porosity 

types range from intercrystalline to microfracture with varying degrees of alteration due 

to secondary leaching and dolomitization. Large vugs (greater than 5 cm) are not 

uncommon but can be partially occluded by calcite and anhydrite overgrowths and/or 

bitumen. Porosity and permeability both decrease to the tops of the reef because there 

was less fauna developed in the basin due to a restricted water conditions at the end of the 

Upper Keg River time. The reefs are sealed by impervious anhydrite of the Muskeg 

formation. Underlying the reefs is the Lower Keg River platform which is a tight lime 

mudstone and is the lower hydraulic seal. Reefs that display pressure support from an 

active water drive occur where the lower portion of the pinnacle is continuous below the 

spill point. This connects the oil pool to a large volume of porous, water-bearing Upper 

Keg River located radially beyond the reef. The original oil-water contact provides the 

maximum acid gas storage limits. There are also many pinnacles that are isolated reefs 

and have no aquifer support. 

The Zama member of the Muskeg formation caps all the Upper Keg River reefs in the 

basin. In a reef crestal position it is a laminated dolomite with abundant reef building 

organisms and is often a continuous reservoir with the Keg River. In the flank position 

the Zama grades into a less porous alagal laminated mudstone and is separated from the 
Page 7 

Keg River by a middle anhydrite. Above the Zama member the Muskeg formation ranges 

in thickness between 60 and 90m and is the cap rock for the underlying reefs. 

The Keg River reefs are good reservoirs as they contain a high percentage of good to very 

good permeability. However significant variations can occur both vertically and laterally. 

These reefs are good candidates for CO2 miscible flooding as they are compact and 

contained reservoirs with oil pays up to 100m in thickness. 

The pinnacles are easily identified on 3D seismic and can be reliably mapped. An aerial 

view of the 3D seismic interpretation of the entire Zama Acid Gas Miscible Flood Project 

is provided as Figure 3. 

A net pay isopach map of the Zama Keg River F pool is provided as Figure 4. The two 

existing well locations are provided on this map. A structure contour map is also 

provided as Figure 5 and the location of the initial oil-water contact is noted. An 

annotated log cross-section is provided as Figure 6. 

5. Reservoir Production Performance History 

5.1. Reservoir Characterization 

The F Pool was discovered in 1967 and brought on production in February of that year. 

A PVT sample was taken in October of 1967 by The Hudson’s Bay Oil and Gas 

Company Limited and analyzed by Core Laboratories in November of 1967 (Reference 

1). The original reservoir pressure was recorded as 14,447 kPa (2095 psig) at datum 

depth of -1098.6 m MSL. 

By November of 1968, special core analysis was conducted on core samples taken during 

drilling of the 11-25 well (Reference 2). Routine core analysis was performed on the 8-

13-116-6W6 discovery well and a summary of parameters derived for this work is 

provided as Table 1.

5.1.1. Initial Conditions 

Play Type Keg River Pinnacle Reef 

Initial Reservoir Pressure 14,447 kPa 

Reservoir Temperature 71 C 

Initial Water Saturation 15% (from logs) 

Porosity 10% (from logs) 

Initial Gas Oil Ratio 52 m3/m3 

Initial Formation Volume Fac. 1.183 r vol/stdvol 

Bubble Point Pressure 8,791 kPa 

API Gravity 35.2 API 

Calculated OOIP 344 e3

m3 (Volumetric using 3D Seismic Data) 

Calculated OOIP 557 e3

m3 (Material Balance, see discussion below) 
Page 8 

5.1.2. Summary of Reservoir Fluid PVT Studies Conducted 

One routine PVT analysis was conduced on the 08-13-116-6W6 discovery well, see 

Reference 1). Table 2 and 3 provide the Differential and Flash Corrected PVT data 

respectively used in material balance analysis for this pool. 

5.1.3. Petrophysical Interpretations 

Routine and special core analysis tests were conducted on cores taken from the discovery 

well 11-25-116-6W6, Reference 2. Waterflood coreflood experiments indicated a 

residual oil saturation of 30% to 50% for high permeability (100+ md) to low 

permeability (6 md and less) rock respectively. 

The range of typical Zama Keg River core measured air permeabilities are shown in 

Figures 7 through 9. These figures illustrate the air permeability distribution with 

increasing scale on the x-axis. It is evident that most of the permeability clusters in the 

100 md region but there is a substantial degree of heterogeneity represented. 

Petrophysical interpretations of wireline logs are provided as Table 4. 

5.2. Production Performance and Pressure History 

Oil production commenced November, 1967. Cumulative oil production to date for this 

pool is 176.2 e3

m3 or 51% of the OOIP calculated via volumetric analysis. Based on the 

material balance analysis the cumulative oil recovery would represent only 32% of the 

OOIP. A plot of the production performance for the pool is provided as Figure 10. 

Historic reservoir pressure is also illustrated on Figure 10. It is evident from this plot that 

reservoir pressures depleted with primary production through to the end of the 1980’s. 

During 10 years of shut-in through the 1990’s reservoir pressure recharged to the 

surrounding aquifer system pressure or has been recharged as a result of water injection 

activities in nearby Keg River formations. Current reservoir pressure is assumed to be in 

the vicinity of 24,000 kPa at the reservoir datum depth based on a measurement taken in 

February of 2002. Since this date, a significant amount of production was withdrawn 

from the reservoir which may have resulted in a 5 mPa pressure depletion. Moreover, 

there is some uncertainty concerning the validity of the pressure taken in 2002. A 

pressure measurement is needed to verify the reservoir’s current pressure prior to 

commencing the acid gas miscible flood operations. 

Cumulative production of oil, water, and gas, and the pressure history at reservoir datum 

are provided as Table 5. 
Page 9 

5.3. Current Estimated Conditions 

Original Oil In Place calculations performed both volumetrically and by material 

balance are given below: 

Calculated OOIP 344 e3

m3 (Volumetric using 3D Seismic Data) 

Calculated OOIP 557 e3m3 (Material Balance, see discussion below) 

Cumulative recoveries to November 2003: 

Oil 176.1 e3

m3

Gas 15.11 e6m3

Water 64.5 e3m3

Water Injection 366.4 e3m3

5.4. Current Estimated Reservoir Pressures 

A recent pressure measurement (02/19/2002) indicates that recharge has taken place in 

this reservoir to a pressure of 23,975 kPa at Datum Depth. 

6. Proposed Production and Injection Wells 

Two wells were drilled into the F pool: 

100/01-13-116-6W6 - This well is proposed to be the future injector 

 100/08-13-116-6W6 – This well is currently believed to require too much down 

hole revisions for re-use. Plans are being made to drill a new well for production 

from this enhanced oil recover project. 

7. Reservoir Development Plan 

7.1. Proposed Acid Gas Injection Plans (Acid Gas Source and Composition) 

7.1.1. Solvent Source Selection 

The CO2/H2S source is from Apache’s own operation of the three (3) Zama Gas Plants 

located at 13-12-116-6 W6M. These three plants have a total of four (4) amine trains 

which produce a source of 70 to 80% CO2 for the project. Effluent from Plant 1 is 

currently being processed into elemental sulphur and stored in a block near the plant. 

Acid gas from the other two plants is compressed for injection into the 

00/02-02-117-6W6 acid gas disposal well. Apache proposes to use the gas being injected 

into this disposal well as the miscible flood solvent used for this enhanced oil recovery 

schemes at Zama. The composition of effluent from these two plants is provided in the 

following table: 
Page 10 

Plant 

Acid Gas 

Rate, e3m3/day 

CO2, 

Mole 

%

CO2+H2S 

Rate, 

e3m3/day 

CO2 

Rate, 

e3m3/day 

H2S 

Rate, 

e3m3/day 

2 46 76 46 35 11 

3 75 77 75 58 17 

Blended Comp. 77% 23% 

Total, e3m3/day 121 93 28 

Total, Tonnes/day 210 170 40 

Mega Tonnes/Year 0.1 0.01 

Mega Tonnes over 16 

Year LIfe 1.0 0.24 

Only a portion of the above volumes will be injected into the F pool with the remainder 

being injected into an additional two pools in the vicinity of the Zama gas plant (the 

subject of two additional companion applications, Reference 7 and 8). 

7.1.2. Transportation 

Figure 1 identifies the location of the pipelines required to transport acid gas from the 

Zama Gas Plant to the candidate pools. Apache proposes to utilize either existing 

pipelines if they are suitable or new pipelines for this purpose. 

7.1.3. Injection Start-up Date and Proposed Injection Rate 

Installation of necessary separation and compression equipment will take place over the 

spring and summer of 2004. Solvent injection is planned to commence as early as 

October or November of 2004. 

Solvent injection rate depends on both the critical rate for stable advancement of the 

flood front (see section 7.4 below), and the maximum rate possible at a voidage 

replacement ratio of 1.0. Historic maximum production rate for the Zama Keg River F 

pool was in the order of 130 m3 day of oil. Although a maximum injection rate of 94 

reservoir m3 day of solvent is calculated as the gravity stable critical rate, it may not be 

possible to sustain this rate given the maximum production rate possible from the single 

production well on the structure. Apache plans to inject solvent with no production until 

the minimum miscibility pressure (MMP) is achieved if necessary (see section 7.2). 

Once the MMP is reached, production will commence and a voidage replacement rate of 

1.0 will be maintained. The timing of the date of first production will depend on 

monitoring of reservoir pressure at the proposed production well. 

7.2. Minimum Miscibility Pressure Estimations and Laboratory Analysis 

During the fall of 2003, fluids were sampled from the 02/11-25-116-6W6 well (and also 

the 00/8-13-116-6W6 well of the Zama Keg River F Pool) and shipped to the PTRC in 

Regina for analysis (Reference 3, and Appendix 1). These separator gas and oil samples 
Page 11 

were recombined to achieve the bubble point reported by the original PVT sample 

analysis done for the pool (Reference 1). 

A rising bubble apparatus was used to measure the minimum miscibility pressure of the 

recombined oil with pure carbon dioxide and a gas mixture composed of 20 mol% 

hydrogen sulfide in carbon dioxide. The CO2 MMP for the 8-13 well’s reservoir oil was 

19.9 MPa. Addition of 20 mol% H2S to the CO2 had the effect of reducing the MMP to 

16.6 MPa. Some evidence of solids participation was noted in the experiments. 

In addition to this laboratory analysis, a statistical analysis of oil compositions in the 

Zama area was conducted and the Alston correlation for MMP estimations (Reference 4) 

was used to predict the MMP values prior to completing the lab analysis. Use of the 

Alston correlation requires the availability of a detailed reservoir fluid analysis including 

compositional analysis. Over a hundred detailed fluid analysis studies have been 

conduced on pools in the Zama area but only a few of these were conducted on the pools 

selected as candidates. 

To arrive at an MMP for each of the candidate pools, MMP’s were calculated based on 

Alston’s correlation for each of the pools that had detailed fluid analysis, Figure 11, and a 

statistical correlation of these MMP’s was arrived at using only API gravity and reservoir 

temperature. Figure 11 shows the calculated MMP values for pure CO2 as a solvent and 

for a mixture of 33% H2S/67% CO2. Using these correlations of MMP along with the 

API gravity and reservoir temperature for pools that did not have detailed PVT analysis, 

an MMP value was calculated for each of the nine miscible flood candidates near the 

Zama gas plant. Figure 12 provides the calculated MMP values for a number of pools in 

the target area for both the pure CO2 and H2S/CO2 mixture solvents. Also shown in 

Figure 12 is the original reservoir pressure and the most recent pressure measurement 

available to Apache. As can be seen in Figure 12, some of these candidate pools may 

require further pressure support depending on results of more recently acquired pressure 

surveys (some recharge is anticipated over time). 

The laboratory measured MMP values from the PTRC for two pools sampled are plotted 

on Figure 12 showing that the correlation is reasonably consistent with the lab analysis 

results. Figure 12 shows the MMP values predicted by correlations for the F Pool to be 

about 17 MPa for a 33% H2S, 67% CO2 mixture and about 20 MPa for pure CO2.

7.3. Estimated Miscible Flood Sweep Efficiency 

Based on the F pool’s current cumulative oil recovery of 176.2 e3m3 of oil, and assuming 

volumetric interpretations of seismic data are correct, a volumetric sweep efficiency of 

72.5% has been achieved to date using the following equation: 















  =

oi

oi orw

WF

Vol

S

S S

RE E
Page 12 

Where: 

Evol - Volumetric sweep efficiency at the end of waterflood 

REwf - Current water drive recovery efficiency 

Soi - Initial oil saturation, (85%) 

Sorw - Residual oil saturation to water drive, (35%) 

Assuming that the residual oil in the swept zone is 35% based on a conservative estimate 

from special core studies, Reference 2, and assuming that the residual oil saturation in a 

solvent swept region of the reservoir will be about 5%, our expectation of the ultimate 

recovery efficiency is given by the following equation: 

Where: 

Sor_acid_gas - Residual oil saturation to acid gas drive, (assume 5%) 

Ultimate_REAcid_Gas_Flood - Ultimate recovery efficiency at the end of the acid gas 

flood. 

Given the above estimates of residual oil saturations and the excellent sweep efficiency 

that has already been achieved in this pool, a estimate of the incremental recovery 

efficiency with a further 75% discounting for the possibility of poorer performance under 

an acid gas drive scheme is about 12.8%. 

7.4. Critical Injection Rate Analysis 

The maximum acid gas injection rate is an important design issues for miscible flooding 

in the Keg River pinnacle reefs. A gravity stable flood which moves an oil bank 

vertically down through the reef is the current miscible flooding concept for the Zama 

Keg River pinnacles. As was the case for the Rainbow Keg River systems, there is a 

potential problem with gravity stability which depends on the rate of gas injection. 

Injecting at too high a rate will induce viscous fingers through the oil column and 

towards the production perforations of the producing well. 

To mitigate gravity instability, it is necessary to calculate a rate at which vertical 

injection will maintain a gravity stable flood front moving downward through the 

pinnacle. (Dake, Reference 5) published a gravity stability analysis involving the 

following calculations: 

Where: 

Vol

oi

oi or acid gas

Acid Gas Flood E

S

S S

Ultimate _ RE * _ _

_ _ 













  =

( 1)

4.9 10 sin 4 '



	 =



M

x kk A

q

g

rg

crit μ

 
Page 13 

qcrit - Maximum rate at which injection of acid gas will be stable for moving a fluid 

column vertically downward through a residual oil column, rb/day 

k - Absolute reservoir permeability, md 

krg - Relative permeability end-point to gas, dimensionless 

A - Effective cross-sectional area being pushed downward by the injected gas, ft2

	 - Specific gravity difference between the oil zone and the injected gas zone, 

relative to water density 

 - Angle of elevation of the reservoir, in the case of vertical drive downward 

through the Keg River Pinnacles, this is 90 degrees 

μ g - Viscosity of the injection gas at reservoir conditions, acid gas, cp 

M - Mobility ratio between injected gas and the oil zone defined as: 

Where: 

kro - End-point relative permeability to oil 

μ o - Oil viscosity at reservoir conditions 

A set of example calculations are provided as Table 6. The critical rate is highly 

dependent on, among those items listed above, the effective cross-sectional area exposed 

to the injected gas that is pushing the oil bank vertically downward. A larger effective 

area will result in a higher critical rate. Given that the Zama pinnacles are highly 

heterogeneous and that injection is occurring at a single injection site, it is difficult to 

predict this value. Further reservoir modeling will need to be performed to improve 

Apache’s understanding of this relationship. 

Apache proposes to operate the F pool acid gas miscible flood at a maximum critical rate 

of 100 rm3

/day which translates to an injection rate at standard conditions of as high as 50 

e

3

m3/day of acid gas injection or 90 tonnes/day of acid gas injection. It is possible that 

this rate will exceed the true stable rate. If this is the case, Apache is considering the use 

of a technique which has been tried for the Rainbow Keg River field involving cyclic 

injection and shut-in of production to stabilize the flood front, Reference 6. If cyclic 

injection is necessary to stabilize the flood front, additional pinnacles will need to be 

identified for the project in order to utilize all of the available acid gas from the Zama 

Plant site. 

7.5. Performance Forecast Methodology – By Analogue Method 

Significant effort towards reservoir modeling of the Zama Keg River pinnacle 

performance under a miscible flooding scheme will be necessary to both predict 

performance and to monitor performance of the currently proposed pilot project. 

Compositional or pseudo-compositional numerical simulation would be required for this. 

Although history matching efforts towards this are currently underway, numerical 

ro o

rg g

k

k

M

μ

μ

'

'

=
Page 14 

predictions of miscible flood performance have not yet been completed. The University 

of Regina has been commissioned to conduct this simulation research. Moreover, the 

accuracy of performance predictions using a numerical simulator for such a 

heterogeneous reservoir system may be questionable until actual miscible flood 

performance data is available for history matching purposes. 

Given a practical need to estimate miscible flood performance for the project, a 

preliminary performance assessment was conducted using the historical performance of 

the Rainbow Keg River reef oil pools south of the Zama field. The Rainbow Keg River 

reefs have been undergoing hydrocarbon miscible flooding since the early 1960’s. Some 

of these pools are in late stages of mature miscible flooding with over 1.5 hydrocarbon 

pore volumes of solvent injected. Unfortunately, many of these pools were never 

waterflooded before initiating the miscible flood. This complicates their use as an 

analogue for the Zama Keg River pools which were produced either through natural or 

artificial waterflood drive. Figure 13a provides a conformance plot for all solvent 

flooded Rainbow Keg River pools. Figure 13b breaks out those pools which had solvent 

injection beginning after significant waterflood recovery had been achieved thereby 

representing more direct analogues for the Zama Keg River planned miscible flood 

schemes. Performance of the Keg River pools were modeled against the behavior 

illustrated in Figure 13b. Figure 14a and 14c provides the recovery efficiency versus 

hydrocarbon pore volume relationships, for both early and late solvent breakthrough 

cases respectively, used in our preliminary screening study. Figure 14b and 14d provides 

an estimate of the solvent breakthrough behavior expected, for both early and late solvent 

breakthrough cases respectively – also modeled against the Rainbow Keg River miscible 

flood behavior. 

As can be seen in Figures 14a and 14b Apache has modified the expected recovery 

performance for the late breakthrough cases for the Zama acid gas flood relative to the 

Rainbow Keg River analogues. Apache believes that a different completion strategy that 

involves perforating the production wells at a lower point in the reef relative to the gas 

injection level could result in a delayed gas breakthrough performance compared to that 

observed in the Rainbow Keg River analogues. Apache has, however, uses the direct 

analogue curves as a worst case scenario (Figures 14b and 14d) for breakthrough which is 

accompanied by an accelerated oil recovery profile but is discounted by 50% for poorer 

sweep efficiency rather than 75% as discussed in section 7.3 (the sweep efficiency 

discussion). 

Oil recovery rate profiles for both the early and later breakthrough cases are shown in 

Figures 15a and 15b for both the early and late acid gas breakthrough cases respectively. 

The late breakthrough achieves an incremental recovery of 19.8% while the early 

breakthrough case achieves an ultimate incremental recovery of 13%. Both cases involve 

a significant amount of recycling of injected acid gas. 

Operation of the candidate pools at a reservoir pressure near or above the MMP is 

assumed to be possible. Acid gas injection it self will be used to pressurize the F pool to 

be near or above the 16.6 MPa required for miscibility as estimated using Apache Canada 
Page 15 

Ltd’s estimation from MMP correlations. Based on a pressure measurement taken in the 

F pool in November of 2001, current reservoir pressure at the datum depth is 23,975 kPa. 

Tabulations of the expected oil, water, and gas, production as well as solvent injection 

and breakthrough rates for both the early and late breakthrough cases are provided as 

Tables 7 and 8 respectively. Figures 16a and 16b are provided to illustrate the forecasted 

oil rates for these two sensitivity cases. 

7.6. Material Balance Analysis of Original Oil in Place 

A material balance analysis of the original oil in place was possible using the early 

production data and pressure measurement take for the Zama Keg River F pool. Figure 

17 shows the result of this material balance and indicates an Original Oil in Place value 

of 556.5 e3m3 (3.5 mmbbl oil). However, due to the possible interconnectivity of this 

pools with both other pinnacles in the region, material balance analysis is complicated 

and would require additional analysis that considers inter-pool connectivities. 

8. Reserves Summary 

8.1. Initial Oil in Place 

The most reliable Initial Oil in Place analysis method for the F pool is the volumetric 

analysis due to complications with communicating reservoirs in the vicinity of this pool 

as discussed above. This volumetrically assessed Original Oil in Place value is: 344 e3

m3

oil (2.166 mmbbl oil). 

8.2. Current Cumulative Recovery and Remaining Oil in Place 

The current cumulative recovery of oil from this pool is 176 e3m3 or 51.2% of the OOIP 

calculated via volumetric analysis. Based on the volumetrically determined Initial Oil in 

Place this leaves a Remaining Oil in Place of 168 e3m3.

8.3. Estimated Enhanced Oil Recovery Performance 

The estimated incremental recovery performance predictions indicate the possibility for 

incremental recoveries of between 8.5% and 12.8%, amounting to incremental production 

of between 29 to 44 e3

m3 of enhanced oil recovery. There is no further waterflood or 

primary production potential in this pool. 

8.3.1. Production and Injection Forecasts 

Tables 7 and 8 and Figure 16a and 16b provide the range of possible production 

performance expected for this enhanced oil recovery scheme given conditions where 

breakthrough occurs early or late respectively. 
Page 16 

8.3.2. Solvent Breakthrough Forecast 

Tables 7 and 8 provide the range of possible acid gas breakthrough performance expected 

for this pool under this enhanced oil recovery scheme given conditions where acid gas 

breakthrough occurs early or late respectively. 

8.4. Ultimate Expected Recovery Efficiency 

The ultimate recovery efficiency for the life of the F pool could therefore be increased 

from the current value of 51.2% to a range of 59.7% to 64% of the original oil in place. 

This relatively good performance is predicted on the basis of relatively good sweep 

efficiency achieved by the natural water drive which was supplemented by some artificial 

water injection. 

9. Guide 51 Compliance Plans 

A Guide 51 submission for the planned 00/01-13-116-6W6 acid gas injection well will be 

submitted once this well has been completed for acid gas injection service. 

10. Notifications and Safety Plans 

All individuals who are impacted by the zone of possible acid gas emission will be 

notified. Apache will forward these responses to the EUB once they are available. Site 

specific emergency response plans will be compiled and submitted for approval by the 

EUB. 
Page 17 

References 

1. Core Laboratories Inc. “Reservoir Fluid Study – HB Zama N 8-13-116-6W6M”, 

File No. RFL 4706., November 27, 1967. 

2. Core Laboratories, Inc. “Special Core Analysis Study – Zama Field” SCAL – 

6894, Novebmer 4, 1968. 

3. Selim Sayegh, Bart Schnell, Sam Huang, “Measurement of CO2 and CO2+H2S

MMP for Zama Oils”, Petroleum Technology Research Centre, February 2004. 

Also provided as Appendix I of this document. 

4. R.B. Alston, etal, “CO2 Minimum Miscibility Pressure: A Correlation for Impure 

CO2 Streams and Live Oil Systems”, Society of Petroleum Engineers Journal, 

April 1985. 

5. L.P. Dake, “Fundamentals of Reservoir Engineering”, Elsevier, 1978, Page 389. 

6. I. Adamache, et al, “The Effect of Cyclic Flow Interruptions on the Performance 

of Vertically Directed Miscible Floods”, SPE 22935, 66th Annual Technical 

Conference and Exhibition of the SPE held in Dalas, TX, October 6-9, 1991. 

7. Apache Canada Ltd, “Resource Application for Approval to Implement an 

Enhanced Oil Recovery Scheme in the Zama Keg River G2G Pool Using Acid 

Gas as a Miscible Flooding Solvent”, March 2004. 

8. Apache Canada Ltd, “Resource Application for Approval to Implement an 

Enhanced Oil Recovery Scheme in the Zama Keg River NNN Pool Using Acid 

Gas as a Miscible Flooding Solvent”, March 2004. 
Table 1 (1 of 1)

Core Sample

No. feet

Depth, 

Top of 

Sample, 

m

Depth, 

Bottom

of 

Sample, 

m

Length of 

Sample, 

m K Max K Vertical

Perm 

Meters, 

md.m

Porosity, 

%

Porosity 

meters

m

89 4901 1493.8 1494.1 0.3 3.75 0.35 1.0 5.9 0.016

90 4901.9 1494.1 1494.5 0.4 12.6 8.25 5.4 11.6 0.049

91 4903.3 1494.5 1494.9 0.3 41.8 2.06 14.0 7.2 0.024

92 4904.4 1494.9 1495.2 0.3 1.55 1.38 0.5 7.1 0.024

93 4905.5 1495.2 1495.6 0.4 4.01 3.01 1.5 6.6 0.024

94 4906.7 1495.6 1495.9 0.4 16.3 3.25 6.0 8.5 0.031

95 4907.9 1495.9 1496.2 0.3 0.0 7 0.019

96 4908.8 1496.2 1496.6 0.4 1510 0.0 13.3 0.049

97 4910 1496.6 1496.8 0.2 19.7 4.46 4.8 6.9 0.017

98 4910.8 1496.8 1497.0 0.2 62.8 1.75 9.6 5.4 0.008

99 4911.3 1497.0 1497.2 0.2 12.3 7.4 3.0 11.6 0.028

100 4912.1 1497.2 1497.4 0.2 8.08 0.0 7.7 0.016

101 4912.8 1497.4 1497.7 0.2 8280 6.58 2019.0 9.6 0.023

102 4913.6 1497.7 1498.0 0.4 0.37 0.0 6.8 0.025

103 4914.8 1498.0 1498.3 0.3 26.5 2.03 8.1 9.3 0.028

104 4915.8 1498.3 1498.6 0.3 106 2.61 29.1 15.2 0.042

105 4916.7 1498.6 1498.8 0.2 0.94 0.0 17.9 0.033

106 4917.3 1498.8 1499.0 0.2 2.52 0.07 0.6 11.2 0.027

107 4918.1 1499.0 1499.4 0.3 0.04 0.01 0.0 3.6 0.012

108 4919.2 1499.4 1499.7 0.4 1.66 0.7 0.6 3.9 0.014

109 4920.4 1499.7 1500.0 0.2 0.37 0.0 1.4 0.003

110 4921.2 1500.0 1500.2 0.2 6.43 1.71 1.6 4.5 0.011

111 4922 1500.2 1500.4 0.2 4.28 0.0 10.7 0.020

112 4922.6 1500.4 1500.6 0.2 2.71 0.48 0.6 1.6 0.003

113 4923.3 1500.6 1500.9 0.3 6.55 0.01 2.0 2.7 0.008

114 4924.3 1500.9 1501.2 0.3 1.3 0.38 0.4 2.2 0.007

115 4925.3 1501.2 1501.6 0.3 0.74 0.01 0.2 2.7 0.009

116 4926.4 1501.6 1502.0 0.4 0.0 3.4 0.015

117 4927.8 1502.0 1502.4 0.4 0.1 0.01 0.0 5.5 0.022

- 4929.1 1502.4

118 4934 1503.9 1504.1 0.2 0.23 0.08 0.1 4.1 0.010

119 4934.8 1504.1 1504.4 0.2 0.04 0.08 0.0 2.3 0.006

120 4935.6 1504.4 1504.6 0.2 0.11 0.15 0.0 4.8 0.012

121 4936.4 1504.6 1504.9 0.2 0.08 0.04 0.0 2.5 0.006

122 4937.2 1504.9 1505.1 0.2 0.08 0.08 0.0 4.5 0.011

123 4938 1505.1 1505.3 0.2 0.08 0.04 0.0 2.8 0.007

- 4938.8 1505.3

124 4943.7 1506.8 1507.2 0.4 3360 1990 1229.0 22.5 0.082

125 4944.9 1507.2 1507.4 0.2 0.0 18 0.033

- 4945.5 1507.4

126 4946.2 1507.6 1507.9 0.3 336 159 92.2 14.5 0.040

127 4947.1 1507.9 1508.1 0.2 188 39.6 45.8 12.2 0.030

128 4947.9 1508.1 1508.3 0.2 2600 770 554.7 23.6 0.050

129 4948.6 1508.3 1508.6 0.2 0.0 3 0.007

130 4949.4 1508.6 1508.8 0.2 231 37.7 42.2 11.8 0.022

- 4950 1508.8

131 4951 1509.1 1509.3 0.3 3.17 0.0 13.1 0.036

132 4951.9 1509.3 1509.6 0.2 244 157 52.1 8.3 0.018

133 4952.6 1509.6 1509.8 0.2 10400 0.0 21.6 0.046

134 4953.3 1509.8 1510.0 0.3 1500 0.0 20.5 0.056

135 4954.2 1510.0 1510.3 0.2 424 0.0 16.7 0.041

136 4955 1510.3 1510.5 0.2 168 69.3 35.8 12.6 0.027

137 4955.7 1510.5 1510.6 0.2 17.6 0.0 14.5 0.022

138 4956.2 1510.6 1510.9 0.2 228 152 48.6 13.6 0.029

139 4956.9 1510.9 1511.2 0.3 338 30.5 103.0 10.1 0.031

140 4957.9 1511.2 1511.4 0.2 1100 90.3 234.7 9.7 0.021

141 4958.6 1511.4 1511.6 0.2 1130 464 275.5 13.3 0.032

142 4959.4 1511.6 1511.8 0.2 27.1 39.6 5.8 9.3 0.020

143 4960.1 1511.8 1512.1 0.2 9.57 3.72 2.3 6 0.015

144 4960.9 1512.1 1512.5 0.5 354 189 161.8 11.3 0.052

145 4962.4 1512.5 1512.8 0.2 141 22 34.4 5.5 0.013

146 4963.2 1512.8 1513.1 0.3 7.5 0.023

- 4964.2 1513.1

147 4975 1516.4 1516.7 0.3 504 159 169.0 8.8 0.030

148 4976.1 1516.7 1517.0 0.3 52.8 0.0 16.4 0.050

149 4977.1 1517.0 1517.3 0.3 0.0 25.5 0.078

150 4978.1 1517.3 1517.6 0.3 5290 0.0 8.2 0.025

151 4979.1 1517.6 1517.9 0.3 833 0.0 15.8 0.048

152 4980.1 1517.9 1518.2 0.3 2.44 0.0 11.4 0.031

153 4981 1518.2 1518.6 0.4 0.7 0.52 0.3 1.6 0.006

154 4982.3 1518.6 1519.0 0.4 4.31 1.38 1.6 4 0.015

155 4983.5 1519.0 1519.4 0.4 5150 5.88 2197.6 9.6 0.041

156 4984.9 1519.4 1519.7 0.3 0.1 0.0 4.8 0.013

157 4985.8 1519.7 1519.9 0.2 30.7 2.89 7.5 4.6 0.011

158 4986.6 1519.9 1520.4 0.5 53.2 14 27.6 1.7 0.009

159 4988.3 1520.4 1521.1 0.6 0.44 0.01 0.3 1.1 0.007

160 4990.4 1521.1 1521.6 0.5 7.49 11.3 3.9 2.8 0.015

161 4992.1 1521.6 1522.1 0.5 40.3 21.5 20.9 1.8 0.009

162 4993.8 1522.1 1522.5 0.4 0.12 0.01 0.0 1 0.004

163 4995 1522.5 1522.9 0.5 0.08 0.01 0.0 1.4 0.006

164 4996.5 1522.9 1523.4 0.5 1.06 0.25 0.5 2.5 0.011

165 4998 1523.4 1523.8 0.5 44.7 21.5 20.4 3 0.014

166 4999.5 1523.8 1524.2 0.3 2.27 2.88 0.8 2.2 0.007

167 5000.6 1524.2 1524.6 0.4 1830 176 725.1 8.1 0.032

168 5001.9 1524.6 1524.9 0.3 10.8 3.27 3.0 3.5 0.010

169 5002.8 1524.9 1525.2 0.4 0.0 9 0.036

170 5004.1 1525.2 1525.4 0.2 0.0 11.3 0.021

171 5004.7 1525.4 1525.7 0.2 0.0 16.9 0.041

172 5005.5 1525.7 1526.1 0.4 32.8 0.0 11.3 0.045

173 5006.8 1526.1 1526.4 0.4 344 0.0 12.2 0.045

174 5008 1526.4 1526.7 0.3 69.1 0.0 10.1 0.028

175 5008.9 1526.7 1527.1 0.4 1.52 0.0 3.7 0.014

- 5010.1 1527.1

176 5012 1527.7 1527.8 0.2 0.0 30 0.055

177 5012.6 1527.8 1528.2 0.4 65.6 0.56 24.0 5.3 0.019

178 5013.8 1528.2 1528.4 0.2 9.56 0.0 8 0.017

179 5014.5 1528.4 1528.7 0.3 93.1 49.6 25.5 5.6 0.015

180 5015.4 1528.7 1529.1 0.4 0.0 14.9 0.054

181 5016.6 1529.1 1529.4 0.3 6.33 6.38 1.9 2.9 0.009

182 5017.6 1529.4 1529.6 0.3 11.7 16.4 3.2 3.6 0.010

183 5018.5 1529.6 1529.9 0.2 18.4 8.39 4.5 2.9 0.007

184 5019.3 1529.9 1530.2 0.3 9800 321 2688.3 9.5 0.026

185 5020.2 1530.2 1530.4 0.3 0.0 10.5 0.029

186 5021.1 1530.4 1530.6 0.2 55.8 98.4 11.9 6.8 0.015

187 5021.8 1530.6 1531.0 0.3 149 130 50.0 6.5 0.022

188 5022.9 1531.0 1531.3 0.3 33 13.9 11.1 6 0.020

189 5024 1531.3 1531.7 0.3 393 509 131.8 7 0.023

190 5025.1 1531.7 1531.9 0.2 19.9 6.56 4.9 4.3 0.010

191 5025.9 1531.9 1532.0 0.2 125 5.25 19.1 6.9 0.011

192 5026.4 1532.0 1532.3 0.2 71.8 52.8 15.3 8.4 0.018

193 5027.1 1532.3 1532.4 0.2 28.8 0.0 16.3 0.030

194 5027.7 1532.4 1532.6 0.2 13.5 0.1 2.1 4.5 0.007

195 5028.2 1532.6 1532.9 0.3 27.5 6 8.4 3.4 0.010

196 5029.2 1532.9 1533.2 0.3 21.4 0.0 3.5 0.011

197 5030.2 1533.2 1533.5 0.3 1610 10.6 490.7 10.1 0.031

198 5031.2 1533.5 1533.9 0.4 81.1 27.5 29.7 10.1 0.037

198b 5032.4 1533.9 1534.3 0.4 81.1 27.5 32.1 10.1 0.040

199 5033.7 1534.3 1534.6 0.3 12800 1460 3901.4 14.1 0.043

200 5034.7 1534.6 1534.9 0.3 2000 165 548.6 11.5 0.032

201 5035.6 1534.9 1535.2 0.3 874 20.5 266.4 7.3 0.022

202 5036.6 1535.2 1535.4 0.3 385 69 105.6 10 0.027

203 5037.5 1535.4 1535.7 0.3 556 0.0 14.4 0.044

- 5038.5 1535.7

Total 34.5 16581.1

Average 0.30 693.2 276.9 144.2 8.6 0.0

Length Wgtd Ave. 0.32 480.1 228.1 8.1

Std Deviation 0.087546 2101.883 1172.197 531.2566 5.697966 0.015583

Variance 0.007664 4417910 1374046 282233.5 32.46682 0.000243

Kv/Kh Ratio 0.40 Average 

Kv/Kh Ratio 0.47 Length Wgtd Ave.

Core Data from: Zama Keg River F Pool - Well 8-13-116-6W6
Table 2

Differential Liberation PVT Data

Differential Liberation Well

0

Tres Pressure Bubble Pt. Soln GOR Oil FVF Visc

(deg F) (kPag) (kPag) (m3/m3) (resVol/Vol) (cp)

71.1 34475 8791 1.174 1.68

71.1 31028 8791 1.178

71.1 30338 8791 1.61

71.1 27580 8791 1.182

71.1 26201 8791 1.54

71.1 24133 8791 1.187

71.1 22064 8791 1.47

71.1 20685 8791 1.191

71.1 17927 8791 1.41

71.1 17238 8791 1.196

71.1 13790 8791 1.201 1.34

71.1 12411 8791 1.203

71.1 11722 8791 1.204

71.1 11032 8791 1.205

71.1 10343 8791 1.206 1.28

71.1 9653 8791 1.207

71.1 8964 8791 1.208

71.1 8791 8791 58 1.209 1.26

71.1 8729 8791

71.1 8667 8791

71.1 8550 8791

71.1 8329 8791

71.1 7943 8791 54 1.201

71.1 7929 8791 1.29

71.1 7343 8791

71.1 7102 8791 1.34

71.1 7081 8791 51 1.192

71.1 6771 8791

71.1 6206 8791 46 1.183 1.41

71.1 6095 8791

71.1 5413 8791

71.1 5357 8791 42 1.173

71.1 5309 8791 1.47

71.1 4723 8791

71.1 4496 8791 38 1.163

71.1 4482 8791 1.56

71.1 4103 8791

71.1 3585 8791 33 1.152 1.66

71.1 3516 8791

71.1 3117 8791

71.1 2758 8791 30 1.142 1.76

71.1 2427 8791

71.1 1875 8791

71.1 1862 8791 1.89

71.1 1841 8791 23 1.129

71.1 1324 8791

71.1 1034 8791 2.04

71.1 1000 8791 17 1.114

71.1 552 8791 2.22

71.1 531 8791 13 1.101

71.1 0 8791 1.046 2.64

8-13-116-6W6

Page 1
Table 3

Flash Corrected PVT Data

GOR

Adjusted PVT data Separator Flash Conditionpsig kPa m3/m3

First Stage Flash from 8791 to 552 at 42.2

Second Stage Flash at from 552 0 at 8.2

Total Flash GOR 50.3 m3/m3 50.3

Flash FVF 1.2074 rvol/svol

Tres Pressure Bubble Pt.Soln GOR Oil FVF Visc

(deg C) kPa kPa m3/m3 (rvol/svol) (cp)

71.1 34475 8791 50.3 1.1492 1.24

71.1 31028 8791 50.3 1.1530

71.1 30338 8791 50.3 1.19

71.1 27580 8791 50.3 1.1572

71.1 26201 8791 50.3 1.17

71.1 24133 8791 50.3 1.1615

71.1 22064 8791 50.3 1.14

71.1 20685 8791 50.3 1.1658

71.1 17927 8791 50.3 1.33

71.1 17238 8791 50.3 1.1702

71.1 13790 8791 50.3 1.1753 1.53

71.1 12411 8791 50.3 1.1774

71.1 11722 8791 50.3 1.1785

71.1 11032 8791 50.3 1.1795

71.1 10343 8791 50.3 1.1805

71.1 9653 8791 50.3 1.1817

71.1 8964 8791 50.3 1.1828

71.1 8791 8791 50.3 1.1830 Bubble Point

71.1 8729 8791

71.1 8667 8791

71.1 8550 8791

71.1 8329 8791

71.1 7943 8791 46.5 1.1752

71.1 7929 8791 1.19

71.1 7343 8791

71.1 7102 8791 1.17

71.1 7081 8791 42.9 1.1664

71.1 6771 8791

71.1 6206 8791 38.5 1.1576 1.22

71.1 6095 8791

71.1 5413 8791

71.1 5357 8791 34.5 1.1478

71.1 5309 8791 1.64

71.1 4723 8791

71.1 4496 8791 30.0 1.1380

71.1 4482 8791

71.1 4103 8791

71.1 3585 8791 25.4 1.1272

71.1 3516 8791

71.1 3117 8791

71.1 2758 8791 22.8 1.1174

71.1 2427 8791

71.1 1875 8791

71.1 1862 8791

71.1 1841 8791 15.6 1.1047

71.1 1324 8791

71.1 1034 8791

71.1 1000 8791 9.9 1.0900

71.1 552 8791

71.1 531 8791 5.8 1.0773

71.1 0 8791 1.0235
Figure 16b

EOR Oil Rate

Keg River F Recovery Profile - Late Breakthrough

0.05.0

10.0

15.0

20.0

25.0

30.0

2004 2006 2008 2010 2012 2014 

Oil Rate, bbl/day
Table 4 (2 of 2)

Keg River Reef:

Zama Member/Keg River (N-D porosity)

Data was accepted into the Net Pay Summary if the following criteria were met.

Analysis Porosity............... greater than or equal .030 and less than or equal 1.000Analysis Sw..................... greater than or equal .000 and less than or equal .400Volume of Shale................. greater than or equal .000 and less than or equal .300

UWI Location Top Base Cum. PhiH Cum. Hyd. Cum. H Cum. kH 

Pore Vol. meters 

100081311606W60100/ 08-13-116- W6 1467 1477 1.358 1.172 9.3 0 100081311606W60100/ 08-13-116- W6 1477 1490 0.928 0.728 9.9 0 100081311606W60100/ 08-13-116- W6 1490 1502 0.168 0.123 2.1 0 100081311606W60100/ 08-13-116- W6 1502 1512 1.905 1.68 9.5 0 100081311606W60100/ 08-13-116- W6 1512 1520 0.428 0.361 2.7 0 100081311606W60100/ 08-13-116- W6 1533 1540 0.769 0.601 5 0 

The Keg River formation was from 1502 meters to the base of the logs (1551.0 meters KB)

section (from 1502.0 –1517.5 meters) had a large difference between the average porosities 

density and the neutron-acoustic (up to 5.8%). The density log is reading abnormally high a

potential rugose borehole conditions (no caliper run over this section), which could be caus

fractures and/or vugs. The core porosity matches reasonably well with the neutron-acoustic 

are sections that have a poor fit (see plots).
Table 5

SUMMARY OF RESERVOIR OFF-TAKE, VOLUMETRIC and MATERIAL BALANCE CALCULATIONSAnalysis of Current Bubble Pointfrom Remaining Oil and Gas in the

Reservoir

Original Solution GOR (from PVT report) 284 scf/bbl 50.3 m3/m3

OOIP Volumetric 2.166 mmbbl 0.34 Mm3

OOIP Material Balance 3.665 mmbbl 0.58 Mm3

OGIP(solution gas) Volumetric 615 mmscf 17.3 Mm3

OGIP(solution gas) Matatial Balance 1041 mmscf 29.3 Mm3

Cum Gas Prod 536.53 mmscf 15.1 Mm3

Cum Oil Prod 1.10817 mmbbl 0.18 Mm3

Cum GOR 484.16 scf/bbl 85.8 m3/m3

Remaining Gas Volumetric 79 mmscf 2.2 Mm3

Remaining Gas Mat Balance 504 mmscf 14.2 Mm3

Remaining Oil Volumetric 1.06 mmbbl 0.17 Mm3

Remaining Oil Mat Balance 2.56 mmbbl 0.41 Mm3

Rem GOR Volumetric 74.32 scf/bbl 13.2 m3/m3

Rem GOR Mat balance 197.25 scf/bbl 35.0 m3/m3

Current Sat Pressure using Volumetrics 213 psi 1469 kPa from Flash Corrected PVT T

Current Sat Pressure using Mat Balance 763 psi 5261 kPa from Flash Corrected PVT T

Lowest Pressure Measured Pressure 551 psi 3800 kPa

Original Sat Pressure PVT 1275 psi 8791 kPa

Imperial Metric



0

20406080

100120140160

Jan-67 Jun-72 Dec-77 Jun-83 Nov-88 May-94 

Rate (m3/d)

Daily Fluid PROD m3/d DAILY OIL PROD m3/dDAILY WTR INJECTION m3/d /10 GOR m3/m3 x 10Pressure Survey Survey Date

Figure 10. Pool Pressure and Production History
Rising Bubble Apparatus MMP for H2S and CO2 Injection Ga

Zama Keg River F Pool - 1-13-116-6W6M

8

1012141618202224

0 5 10 Mo1l5% H 20 25 3

2S in CO2 Injection Gas

MMP (MPa)

Original DepleteDeplete
Figure 14a

Figure 14b

Analytical Model Based

on

Rainbow Keg River Miscible Flood - Late Breakthrough

Figure 14a and 14b

Rainbow Keg River Miscible Hydrocabon Flood 

Dimensionlesss Recovery Profile Model

0.00

0.20

0.40

0.60

0.80

1.00

1.20

0.00 0.20 0.40 0.60 0.80 1.00 1.20 1.40 1.60

HCPV Inj.

P

erc

ent Incre

m

ental

R

e

c

o

v

ery

%

Rainbow Keg River Miscible Hydrocabon Flood 

Breakthrough Gas Profile

0.00

0.20

0.40

0.60

0.80

1.00

1.20

0.00 0.20 0.40 0.60 0.80 1.00 1.20 1.40 1.60

HCPV Inj.

Pro

d/Inj G

a

s

R

atio
Figure 15a

Figure 15b

Analytical Model Based

on

Rainbow Keg River Miscible Flood - Early Breakthrough

Figure 15a and 15b

Rainbow Keg River Miscible Hydrocabon Flood 

Dimensionlesss Recovery Profile Model

0.00

0.20

0.40

0.60

0.80

1.00

1.20

0.00 0.20 0.40 0.60 0.80 1.00 1.20 1.40 1.60

HCPV Inj.

P

erc

ent Incre

m

ental

R

e

c

o

v

ery

%

Rainbow Keg River Miscible Hydrocabon Flood 

Breakthrough Gas Profile

0.00

0.20

0.40

0.60

0.80

1.00

1.20

0.00 0.20 0.40 0.60 0.80 1.00 1.20 1.40 1.60

HCPV Inj.

Pro

d/Inj G

a

s

R

atio
Figure 16a

EOR Oil Rate

Keg River F Recovery Profile - Early Breakthrough

02468

101214

2004 2006 2008 2010 2012 2014 

Oil Rate, m3/day
Figure 16b

EOR Oil Rate

Keg River F Recovery Profile - Late Breakthrough

0.05.0

10.0

15.0

20.0

25.0

30.0

2004 2006 2008 2010 2012 2014 

Oil Rate, bbl/day
Guide 65 -Schedule 1 

Resources Applications

1: REGISTRATION 

Month 08 Day 09 Year 2004 Applicant’s File Number 01-13-116-6W6 

EUB USE ONLY 

 Registration Number: Registration Date: Month Day Year 

Company Name Apache Canada Ltd. Company Code OJL8 

Contact Person (N/A )

Nimchuk Doug 

 Last Name First Name 

Telephone 403-261-1271 Fax 403-261-1273 

E-Mail Address Doug.nimchuk@apachecorp.com 

Consultant (N/A )

CalPetra Research and Consulting Inc. AOP2 

 Company Name Consultant Code

Consultant Contact Person Lavoie Robert G. 

Last Name First Name 

Telephone (403) 862-9798 Fax (403) 261-1273 

E-Mail Address Rob.lavoie@apachecorp.com 

2: BASIC INFORMATION REQUIREMENTS 

1. Field, Strike Area, and Pool 

 Field code No./Name Strike Area Name Pool code No./Name 

0997 / Zama Zama 0788006 / Keg River F 

2. What is the ownership basis on which you make this application? 

100% owner and operator of the subject pool 

3. Have you completed the notification requirements? Yes No 

4a. Do you need EUB assistance to complete the notification requirements? Yes No If yes, please supply details.

Apache has issued notifications to applicable land owners. Apache will forward all correspondence related to 

these notices to the EUB. Although notifications are required, injection wells DO NOT have critical sour status until injection commences. 

4b. Are there outstanding concerns? Yes No 

5. Does your injectant contain hydrogen sulphide (H2S)? Yes No 

5a. If Yes, is a new emergency response plan (ERP) needed, or does an existing ERP need updating? Yes No 

5b. If No, state why not 

5c. If Yes, supply details The updated ERP will be provided to the EUB concerning acid gas injection proposed for this project 

(continued) 

Guide 65-Schedule 1-2000-06 

Alberta Energy and Utilities Board 640 5 Avenue SW Calgary, Alberta T2P 3G4
Guide 65 -Schedule 1, page 2 Company Name Apache Canada Ltd. 

5d. Have you conducted notification for ERP purposes to all potentially affected parties? Yes No 

5e. If Yes, are there any outstanding concerns? 

No. 

6. Are you applying to amend an existing approval or order? Yes No 

6a. If Yes, what is the existing approval or order number? 

6b. Is the name of the approval holder current? Yes No 

3: TYPE OF APPLICATIONS

1. What types of resources applications are you submitting at this time? 

UNIT 1 - EQUITY UNIT 2 - CONSERVATION 

Rateable Take (1.1) Enhanced Recovery Scheme (2.1) 

Common Purchaser (1.2) Enhanced Oil Recovery Project (2.2) 

Common Carrier (1.3) Enhanced Recovery Recognition 

Common Processor (1.4) Good Production Practice (2.3) 

Common Pooling (1.5) Concurrent Production (2.4) 

Special Spacing (1.6) Pool Delineation and Ultimate Reserves (2.5) 

UNIT 3 - PRODUCTION CONTROL UNIT 4 - DISPOSAL/STORAGE 

Commingled Production (3.1) Disposal (Class I-IV (4.1) 

Good Production Practice (Primary Depletion Pool) (3.2.2) Acid Gas Disposal (4.2) 

Gas-Oil Ratio Penalty Relief (3.2.3) Underground Gas Storage (4.3) 

Special Maximum Rate Limitation (3.2.4) 

Gas Allowable (3.3) 

UNIT 5 - CORPORATE CHANGES 

Change in Name of Approval Holder (5.1) 

Change of Holder of Approval (5.2) 

4: FUTURE APPLICATIONS

1. Do you plan to submit subsequent applications associated with the present applications to the EUB within six months? 

 Yes No 

2. If Yes, state what types and when you plan to submit these applications. 

The Guide 51applications for this Enhanced Recovery Scheme will be submitted as soon as the wells have been completed for injection 

service. 

Note: Remember to file three copies of the application package, including Schedule 1, unless otherwise specified in individual units of this guide. 

SUBMIT APPLICATIONS TO:

Alberta Energy and Utilities Board 

Resources Applications Group 

640 - 5 Avenue SW 

Calgary, Alberta T2P 3G4 

Alberta Energy and Utilities Board 640 5 Avenue SW Calgary, Alberta T2P 3G4 
(403) 261-1200 

FAX (403) 263-1200 

SUITE 1000 / 700 – 9th AVENUE S.W. / CALGARY, ALBERTA, CANADA T2P 3V4 

November 9, 2004 

Alberta Energy and Utilities Board 

Resource Applications Group 

640 – 5th Ave. S.W. 

Calgary, AB 

T2P 3G4 

Attention: Joe McIntosh 

Resources Applications Group 

RE: Zama – Keg River F Pool – Enhanced Oil Recovery Scheme Application 

 Addendum – Reservoir Abandonment Plans 

 Application No. 1356043 

______________________________________________________________________ 

Apache Canada Ltd. (“Apache”) has recently requested approval to implement an Enhance Oil Recovery (EOR) 

Miscible Flood project in the subject pool. During the review of Apache’s application a question was raised 

regarding the pressure at which this pool (and other similar pools) will be abandoned. 

Background Information

Apache’s latest pressure measurement conducted for the 01-13-116-6W6M well at reservoir datum is 16,225 

kPa. This pressure is 1,672 kPa above the earliest pressure measurement (original reservoir pressure) of 14,553 

kPa taken on February 28, 1967, prior to start of production. 

As can be seen in Table 1 and Figure 1, the minimum miscibility pressure for the planned acid gas miscible 

flood, as measured in a Rising Bubble Apparatus (RBA) at the Saskatchewan Research Council (SRC), ranges 

from 13.4 to 19.9 MPa for H2S concentrations ranging from 40% down to 0% respectively (the balance being 

CO2). 

The planned injectant acid gas H2S composition is anticipated to range between a minimum of 25% and 

maximum of 40% with an average of 32% H2S. However, due to the presence of methane and nitrogen 

impurities in the plant effluent (1.2% C1 and 1.2% N2), it is likely that the MMP will be about 800 to 1,000 kPa 

higher than for pure H2S and CO2 components. Given a worst case scenario of an average 25% H2S solvent 

injection stream, the MMP would be 15.8 MPa plus a contingency for impurities of 1,000 MPa. Therefore the 

required MMP with a safety factor is 16.8 MPa or 17,000 mPa as was suggested in the subject Guide 65 

Application. Apache seeks to operate this pool at a pressure of 17.5 MPa to ensure miscibility is achieved even 

at the lowest range of H2S composition. 
2004-11-09 F Pool Addendum Pressure Discussion Page 2 of 2 Created on 11/9/2004 4:00 PM 

Given that the reservoir pressure is currently below this target, acid gas will be injected with no (or low) 

production until the desired reservoir pressure has been achieved. Once the 17.5 MPa target range is achieved, 

a voidage replacement of 1.0 will be maintained until the end of the flood. The flood is currently anticipated to 

require about 8 to 10 years to reach its economic limit. When the economic limit for the F Pool is reached, acid 

gas will be diverted to other prospective acid gas miscible flood pools in the area. 

Abandonment Pressure Question

Given the discussion above, Apache wishes to maintain a target pressure regime of 17.5 MPa for the F Pool. 

Apache is committed to de-pressurizing this pool to an acceptable pressure level upon reaching the 

economic limit of the miscible flood, and given continued future concerns over H2S containment in this pool. 

In order to define a specific time commitment for this, Apache commits to blow down of the pool if no 

production is taken from the F pool production well (0/08-13-116-6W6) over a period of 3 years. This will be 

done by either continued production of acid gas (with re-injection in a disposal well or other miscible flood 

project) or continued production of high water-cut fluids until the reservoir pressure is reduced to an acceptable 

level as determined by the EUB. 

We look forward to further discussion concerning this project. If you have any further information 

requirements related to this application please contact either Rob Lavoie, 303-8584 or Doug Nimchuk, 261-

1271. 

Yours Truly, 

Mike Thorson 

Manager, Reservoir Engineeing – Apache Canada Ltd. 
Table 1: Summary of RBA MMP Measurements of Apache-Zama Recombined Oil with CO2 + H2S

Mixtures 

Recombined Oil Sample Well 1-13-116-6 W6M 11-25-116-6 W6M 

Temperature (°C) 71 76 

Injection Gas Composition (% H2S)* MMP (MPa) MMP (MPa) 

0 19.9 21.3 

20 16.6 19.0 

40 13.4 16.9 

* Balance is CO2

Figure 1: Rising Bubble Apparatus MMP for H2S + CO2 Injection Gas Mixtures with Zama 

Recombined Oils

10

12

14

16

18

20

22

0 10 20 30 40

Mol% H2S in CO2 Injection Gas

MMP (MPa)

1-13-116-6 W6M

11-25-116-6 W6M
(403) 261-1200 

FAX (403) 263-1200 

SUITE 1000 / 700 – 9th AVENUE S.W. / CALGARY, ALBERTA, CANADA T2P 3V4 

December 9, 2004 

Alberta Energy and Utilities Board 

Resource Applications Group 

640 – 5th Ave. S.W. 

Calgary, AB 

T2P 3G4 

Attention: Joe McIntosh 

Resources Applications Group 

RE: Zama – Keg River F Pool – Enhanced Oil Recovery Scheme Application 

 Additional Information Request of December 9, 2004 

 Guide 65 Application No. 1356043

______________________________________________________________________ 

Apache Canada Ltd. (“Apache”) has recently requested approval to implement an Enhance Oil Recovery (EOR) 

Miscible Flood project in the subject pool, Resource Application No. 1356043. This addendum addresses a 

request for further information by the EUB, dated December 9, 2004. This letter will be referred to as the 

Information Request (IR) letter. Each requested information item will be referred to by the numbering in the 

IR. 

IR 1:

As was indicated in our previous addendum letter of November 9, 2004, Apache remains committed to depressuring the F Pool at the end of the productive life of the current applied for scheme. Given that two wells 

currently exist for this pool, either one of these wells could be used for the purpose of de-pressuring the pool 

after wells have been suspended for a 3 year period. Apache will weigh the merits of conducting the depressuring earlier (than the 3 year wait discussed above) if there is a risk that wells may need re-drilling. The 

need for additional wells or re-working of existing wells to achieve the desired de-pressure operation will be 

assessed at that time. However, Apache commits to de-pressuring the reservoir to the original reservoir 

pressure of 14,553 kPa at the conclusion of the scheme in the timing stated above using the most appropriate 

method available at that time. 

Further to this discussion is the issue of managing the location of the residual oil column. Apache will monitor 

the situation and take action to prevent movement of the oil column to a position below the original oil-water 

contact. It would not be in Apache’s best interest to allow this kind of movement to take place since any 

mobile oil remaining in the residual oil column would become inaccessible to be produced through the 

existing well completion. 
2004-12-09 Further F Pool EUB Information Request Response Letter Page 2 of 2 Created on 12/9/2004 2:20 PM 

Based on 3-D seismic interpretations, the location of the structural spill point below the original oil water 

contact of 1131 mSS is 1230 mSS which provides 99 meters of possible movement of the oil-water contact 

before over-filling would occur. As stated above, it would not be in Apache’s best interest to allow 

displacement of a remaining oil column to a depth this far below the original oil-water contact and Apache 

would not allow this to occur. Apache will be monitoring the residual location of the oil column and ensuring 

that the reservoir pressure balance between the gas cap and the oil zone are not such that this kind of over 

displacement would occur. 

IR 2:

ERP notifications and approvals for the 00/01-13 and 02/01-13 wells are currently in process. Land 

notifications have been issued for these wells but delays in locating the area liaisons have delayed receiving the 

required notification approvals. Once these have been obtained the EPR applications will be sent to the EUB 

for approval. The primary wellhead components are PSL III compliant as required for critical sour gas wells. 

All documentation to this effect has or will be submitted as part of Apache’s critical sour gas well application 

process. 

The new EPR approval for injection and production lines will allow for up to 60% H2S at a surface pressure of 

14,890 kPa. Again, these EPR approvals are waiting on area liaison notification approvals. Please refer to 

Attachment 1 for pipeline and facility licensing information pertaining to maximum operating pressure and 

maximum H2S content. 

IR 3:

As for IR2, ERP approvals are in progress for both the 00/01-13 and 02/01-13 wells. Apache will have these 

ERP documents into the EUB before the year end. 

Yours Sincerely, 

Mike Thorson 

Manager, Reservoir Engineering – Apache Canada Ltd. 
MADE at the City of Calgary, in the 

Province of Alberta, on 

ALBERTA ENERGY AND UTILITIES BOARD 

Approval No. 10328 Page 1 of 5 

ENHANCED OIL RECOVERY 

Approval No. 10328 

The Alberta Energy and Utilities Board, pursuant to the Oil and Gas Conservation Act, chapter 

O-6 of the Revised Statutes of Alberta, 2000, orders as follows: 

1) The scheme of Apache Canada Ltd. (hereinafter called “the Operator”) for enhanced 

recovery of oil by miscible displacement using hydrogen sulphide (H2S) and carbon dioxide

(CO2) injection in that part of the Zama Keg River F Pool outlined in Appendix A of the 

approval, as described in 

a) Application No. 1356043, 

is approved, subject to the terms and conditions herein contained. 

2) For the purposes of this approval “miscible fluid” means gas that contains: 

a) a mixture of at least 0.970 mole fraction of H2S and CO2, with the remainder composed 

of other natural gas components, 

b) an H2S content not less than 0.25 mole fraction and not more than 0.40 mole fraction at 

any time, and 

c) an average H2S content not less than 0.32 mole fraction based on a 3 month rolling 

average. 

3) The miscible fluid, as identified in clause 2, is to be injected into the subject pool through the 

well(s) with the following unique identifier(s): 

Class III 

00/01-13-116-06W6/0 

 The class of fluid is described in EUB Guide 51. 

4) The injection of miscible fluid may commence in the well(s) referred to in clause 3 once the 

EUB has confirmed in writing that EUB Guide 51 requirements have been met. 

5) The Operator shall conduct injection, to that part of the subject pool referred to in Appendix

A, in accordance with the following requirements: 

 

18th day of August 2005.
http://www.eub.gov.ab.ca

August 18, 2005 

Doug Nimchuk 

Apache Canada Ltd.

Suite 1000, 700 – 9 Avenue SW 

Calgary AB T2P 3V4 

Dear Mr. Nimchuk: 

ZAMA KEG RIVER F POOL 

ENHANCED OIL RECOVERY SCHEME 

APPLICATION NO. 1356043 

APPROVAL NO. 10328 

The Alberta Energy and Utilities Board (EUB) has considered your application, dated July 31, 

2004, and related submissions requesting approval to implement a new scheme for enhanced oil

recovery by miscible displacement using hydrogen sulphide and carbon dioxide in the Zama Keg 

River F Pool. Your application has been granted subject to the conditions detailed in Approval 

No. 10328, which is enclosed for this purpose. 

The EUB will defer recognizing any enhanced recovery reserves for this scheme until actual 

scheme performance indicates that such reserves are being recovered. In this regard, the annual 

performance review presentations for the scheme required as part of the subject approval and in 

accordance with EUB IL 96-02: Progress Report Requirements for Miscible Flood Schemes will 

be or particular interest in determining the success of acid gas injection in recovering incremental 

reserves in this particular reservoir situation. 

Questions on this matter should be directed to Joe McIntosh at 297-8415. 

Yours truly, 

Tom Byrnes, P. Eng. 

Staff Reservoir Engineering Specialist 

Resources Applications 

JM 

Enclosure 
Approval No. 10328 Page 2 of 5 

a) production, without injection, shall initially occur until the average reservoir pressure is 

between 14 450 kiloPascals (gauge) and 13 700 kiloPascals(gauge). Miscible fluid shall 

then be injected in sufficient volumes to maintain the average reservoir pressure between 

13 700 kiloPascals (gauge) and 14 450 kiloPascals (gauge), 

b) the reservoir pressure shall be monitored by conducting a bottomhole pressure test every 

6 months, with the first test commencing by February 1, 2006, 

c) wellhead injection pressure shall not exceed 8 000 kiloPascals (gauge) at any time, 

d) the injection well shall be monitored in accordance with EUB IL 94-2 and subsequent 

amendments, 

e) the representative composition of the injected miscible fluid shall be determined on a 

bi-weekly basis, and the representative composition of the produced gas shall be 

determined on a monthly basis, 

f) once miscible fluid injection begins, the Slave Point Formation in the 00/08-13-116-

06W6 well shall be monitored for H2S and CO2 by collecting fluid samples from the 

perforated Slave Point interval in this well on a bi-monthly basis and analyzing these 

samples for H2S and CO2 content. If there is any indication of increased H2S or CO2 

contents, the Operator shall immediately inform the EUB Resources Applications Group, 

g) the pressure in the tubing/casing annulus of the injection well shall be monitored on a 

daily basis. The Operator shall immediately inform the EUB Operations Group if a tubing, 

casing, or packer failure is suspected, or if any H2S or CO2 is detected at the injection 

well’s surface casing vent, 

h) packer isolation tests at the injection well shall be conducted on an annual basis and the

results submitted electronically to the EUB by September 1 of each year, and appropriate 

corrosion protection shall be implemented, 

f) injection operations shall be suspended immediately if any operational equipment, 

monitoring equipment, or safety devices fail that would compromise environmental 

protection or the safe operation of the scheme, 

g) if acid gas breakthrough occurs before any appreciable oil is produced from the Keg 

River formation in the 03/01-13-116-06W6 well, the Operator shall immediately inform 

the EUB Resources Applications Group and provide the details of its plans for modifying 

scheme operations and making the corresponding amendments to this approval, 

h) the abandonment of any well, whether an injector or producer, shall not proceed until the

Operator has applied and received approval for its abandonment program from the EUB

Operations Group, 

6) The Operator shall be subject to the two-part reporting process for miscible floods outlined in 

EUB IL 96-2: Progress Report Requirements for Miscible Flood Schemes. In addition to the 
Approval No. 10328 Page 3 of 5 

base reporting requirements specified in IL 96-2, the following annual data submission 

requirements shall apply: 

a) a summary of all workovers done on the injection and producing wells including, but not 

limited to, the reason for the workovers and the results of the workovers, 

b) a discussion of changes in equipment and operations, 

c) a discussion of changes in the performance of the scheme including, but not limited to, 

identification of problems, remedial action taken, and results of remedial action on 

scheme performance, 

d) a discussion of the overall performance of the scheme, including where the injected 

miscible fluid may have swept the reservoir and to what extent an oil bank may have 

formed, 

e) results and evaluation of all monitoring done during the reporting period including but 

not limited to: pressure surveys, corrosion protection, fluid analyses, logs and any other 

data collected that would help in determining the success of the scheme, 

f) a table(s) showing the following injection data for each month of the reporting period: 

i) mole fraction of H2S in the injected miscible fluid, 

ii) mole fraction of CO2 in the injected miscible fluid, 

iii) three month rolling average mole fraction of H2S in the injected miscible fluid, 

iv) volume of H2S injected at standard conditions, 

v) volume of CO2 injected at standard conditions, 

vi) volume of miscible fluid injected at standard conditions, 

vii) formation volume factor of miscible fluid injected, 

viii) volume of miscible fluid injected at reservoir conditions, 

ix) hours on injection, 

x) average daily miscible fluid injection rate at standard conditions, 

xi) maximum wellhead injection pressure (MWHIP), 

xii) corresponding wellhead injection temperature when MWHIP was measured, 

xiii) average wellhead injection pressure, and 

xiv) average wellhead injection temperature, 

g) a table(s) showing the following production data for each month of the reporting period, 

with free gas defined as the produced gas exclusive of any solution gas from the 

produced oil: 

i) average producing oil rate at standard conditions, 

ii) volume of oil produced at standard conditions, 

iii) formation volume factor of oil produced, 

iv) volume of oil produced at reservoir conditions, 

v) average producing gas rate at standard conditions, 

vi) volume of gas produced at standard conditions, 
Approval No. 10328 Page 4 of 5 

vii) calculated volume of free gas produced at standard conditions, 

viii) average composition of gas produced, 

ix) calculated average composition of free gas produced, 

x) formation volume factor of free gas produced, 

xi) volume of free gas produced at reservoir conditions, 

xii) average producing water rate at standard conditions, 

xiii) volume of water produced at standard conditions, 

xiv) formation volume factor of water produced, 

xv) volume of water produced at reservoir conditions, 

xvi) average producing gas/oil ratio at standard conditions, and 

xvii) average producing water/oil ratio at standard conditions, 

h) a table showing the following voidage calculation data at reservoir conditions for each 

month of the reporting period: 

i) volume of miscible fluid injected, 

ii) volume of oil produced, 

iii) volume of free gas produced, 

iv) volume of water produced, and 

v) estimated, or actual measured, average reservoir pressure, 

i) a table showing the calculated net tonnes of sulphur and carbon dioxide injected into the 

pool by the scheme on a monthly and cumulative basis, and 

j) a plot showing the following monthly average data at standard conditions versus time: 

i) miscible fluid injection rate, 

ii) producing oil rate, 

iii) producing gas rate, 

iv) producing water rate, 

v) producing gas/oil ratio, and 

vi) producing water/oil ratio, 

with the plot displaying the scheme on an ongoing basis and not just for the reporting 

period. 

END OF DOCUMENT 
Approval No. 10328 Page 5 of 5 

R.6W.6M. 

T.116 
DIRECTIVE 065 AMENDMENT APPLICATION 

FOR 

ACID GAS ENHANCED RECOVERY SCHEME 

IN 

ZAMA KEG RIVER F POOL 

APPROVAL No. 10328A 

Prepared by: 

Apache Canada Ltd. 

October 2007 
Directive 065 Approval 10328A Amendment Application – 

Zama Keg River F Pool Acid Gas Miscible ER 

Table of Contents 

1 General........................................................................................................................ 1 

1.1 Proposed Acid Gas Enhanced Recovery Scheme Amendment .......................... 1 

1.2 Current Approval Specifics ................................................................................ 1 

1.3 Proposed Amendment Specifics ......................................................................... 2 

2 Basic Data ................................................................................................................... 2 

2.1 Approval Area..................................................................................................... 2 

2.2 Pool Reserves and Recovery............................................................................... 2 

3 Proposed Amendment Details..................................................................................... 3 

3.1 Background......................................................................................................... 3 

3.2 Changes to Solvent Composition........................................................................ 4 

3.3 Implication to Miscibility ................................................................................... 4 

3.4 Expected Range of Solvent Composition ........................................................... 4 

3.5 Equation of State Calibration.............................................................................. 5 

3.6 Implication to Minimum Miscibility Pressure.................................................... 5 

3.7 Minimum Miscibility Pressure and Pseudo Critical Temperature...................... 5 

3.8 Operating Pressure & Formation Fracture Pressure ........................................... 6 

3.9 Cap Rock Integrity.............................................................................................. 7 

3.10 Other Changes to Ascertain Solvent Composition ............................................. 8 

4 Safety .......................................................................................................................... 8 

5 References................................................................................................................... 8 
Directive 065 Approval 10328A Amendment Application – 

Zama Keg River F Pool Acid Gas Miscible ER 

List of Tables 

1. Reservoir Parameters, Zama Keg River F pool 

2. Performance Prediction for Early and Late Breakthrough of Acid Gas - Zama Keg 

River F Pool

3. Acid Gas Solvent Composition - Best Case for Miscibility 

4. Acid Gas Solvent Composition - Existing Operating Conditions 

5. Acid Gas Solvent Composition - Worst Case for Miscibility 

List of Figures

1. Approval Area Map 

2. Zama Keg River F Recovery Rate Forecast Early and Late Breakthrough Cases 

3. Zama Keg River G2G Pool Production & Injection History Plot 

4. Zama Keg River Z3Z Pool Production & Injection History Plot 

5. Zama Acid Gas ER Injection/Production Pipeline Map 

6. Zama Acid Gas ER Facility Structure Diagram 

7. Hydrocarbon Content Plot in Acid Gas Solvent Stream Flowing North of the Zama 

Gas Plant 

8. Hydrocarbon Content Plot in Acid Gas Solvent Stream Flowing South of the Zama 

Gas Plant 

9. Plot of Slim Tube Recovery and EOS Matches of Zama Keg River F Pool Oil 

10. Slim Tube Recovery Prediction Plot of Zama Keg River F Pool Oil 

11. Plot of Solvent Gas Compositional Effects on Minimum Miscibility Pressure of 

Zama Keg River F Oil 

12. Pseudo Critical Temperature Plot for Acid Gas Stream Flowing North of Zama 

Complex 

13. Pseudo Critical Temperature Plot for Acid Gas Stream Flowing South of Zama 

Complex 

14. Step Rate Injectivity Tests Comparison Plot 
Directive 065 Approval 10328A Amendment Application – 

Zama Keg River F Pool Acid Gas Miscible ER 

Page 1 of 8

1 General 

1.1 Proposed Acid Gas Enhanced Recovery Scheme Amendment 

In accordance with Section 39(1)(a) of the Oil and Gas Conservation Act, Apache 

Canada Ltd. (“the Operator”), the operator of Enhanced Oil Recovery Approval 

No. 10328A, hereby applies to amend the approval for the following changes to the 

specified operating conditions: 

a) the composition of the solvent acid gas 

b) the average operating pressure of the miscible flood 

c) the frequency of injected miscible fluid sampling 

1.2 Current Approval Specifics 

Enhanced Oil Recovery Approval No. 10328A specifies the following Clauses: 

2) For the purposes of this approval “miscible fluid” means gas that contains: 

a) a mixture of at least 0.970 mole fraction of H2S and CO2, with the 

reminder composed of other natural gas components, 

b) an H2S content not less than 0.20 mole fraction and not more than 0.40 

mole fraction at any time, and 

c) an average H2S content not less than 0.23 mole fraction based on a 3 

month rolling average. 

5) The Operator shall conduct injection, to that part of the subject pool referred 

to in Appendix A, in accordance with the following requirements: 

a) production, without injection, shall initially occur until the average 

reservoir pressure is between 15500 kiloPascals (gauge) and 14000 

kiloPascals (gauge). Miscible fluid shall then be injected in sufficient 

volumes to maintain the average reservoir pressure between 14000 

kiloPascals (gauge) and 15500 kiloPascals (gauge), 

c) wellhead injection pressure shall not exceed 8000 kiloPascals (gauge) at 

any time. 

e) the representative composition of the injected miscible fluid shall be 

determined on a bi-weekly basis, and the representative composition of the 

produced gas shall be determined on a monthly basis. 
Directive 065 Approval 10328A Amendment Application – 

Zama Keg River F Pool Acid Gas Miscible ER 

Page 2 of 8

1.3 Proposed Amendment Specifics 

The Operator proposes the following changes to the Clauses: 

2) For the purposes of this approval “miscible fluid” means a gas mixture with 

the following physical properties: 

a) a minimum cumulative pseudo critical temperature (cumulative from 

start of acid gas injection) of 310o K, 

b) a H2S content not more than 0.40 mole fraction at any time.

c) A methane content not more than 0.11 mole fraction based on a 3 month 

rolling average 

5) The miscible fluid injected to that part of the subject pool outlined in 

Appendix A 

a) Production, without injection, shall initially occur until the average 

reservoir pressure is between 16500 kiloPascals (gauge) and 14500

kiloPascals (gauge). Miscible fluid shall then be injected in sufficient 

volumes to maintain the average reservoir pressure between 14500

kiloPascals (gauge) and 16500 kiloPascals (gauge), 

c) wellhead injection pressure shall not exceed 8 000 kiloPascals (gauge) at 

any time. 

d) the representative composition of the injected miscible fluid and the 

representative composition of produced gas shall be determined on a 

monthly basis. 

2 Basic Data 

2.1 Approval Area 

The Approval No. 10328A covers the entire Zama Keg River F Pool which is in the 

SE/4 of Section 13-116-06W6. This amendment is not seeking any changes to the 

original approval area. A map showing the pool boundary, the approval area and 

the notification area can be found in Figure 1. 

2.2 Pool Reserves and Recovery 

The Operator is not proposing any changes to the original oil-in-place (OOIP) or 

incremental recovery estimates in this amendment application. The following table 

summarizes the various recoveries and factors as stated in the original enhanced 

recovery application: 
Directive 065 Approval 10328A Amendment Application – 

Zama Keg River F Pool Acid Gas Miscible ER 

Page 3 of 8

Source of OOIP EUB Apache 

OOIP Estimate (103m3) 546.0 344.0 

Current Oil Recovery (103m3) 176.3 176.3 

Current Oil Recovery Factor (%) 32.3 51.2 

Incremental Miscible Recovery 

Estimate (103m3) 29.2 to 44.0 

Incremental Miscible Recovery 

Estimate (%) 8.5 to 12.8 

A tabulation of reservoir parameters is provided as Table 1 while reserves and 

production forecasts are provided as Table 2 and Figure 2. 

3 Proposed Amendment Details 

3.1 Background 

Apache is currently operating a total of 5 acid gas miscible flood schemes and one 

acid gas disposal well. The production responses of the Operator’s first two acid 

gas enhanced recovery (ER) schemes, Zama Keg River G2G and Zama Keg River 

Z3Z Pools, have exceeded our expectation and predictions. Figures 3 and 4 show 

the production/injection histories of the two pools respectively. While this is a 

good news story, it does have some unexpected implications to other acid gas 

miscible floods that will be using the associated solution gas stream from these 

existing ER schemes as part of the solvent. 

In order to understand the issues, one has to understand the production facilities. 

Production from the pools with ER is sent to a high pressure separator at the Zama 

processing complex through dedicated high pressure production flow lines. The 

associated solution gas is separated from the oil and is sent into the acid gas stream 

from Plant #2 to become the solvent for re-injection into other pools with miscible 

ER schemes. Figure 5 is a map of the facilities, wells, flow lines, pools and their 

spatial relations of one to another. Figure 6 is a diagram showing only the pools 

with miscible ER schemes and how they are connected to the central facilities. The 

blue dash rectangle in the center of the diagram represents the Zama processing 

complex. Even though the diagram is not drawn to scale, the pools identified north 

of the complex are indeed to the north of it. Likewise, the pools drawn to the south 

of the complex are located south of the processing facilities. 

In 2006, acid gas from Plant #3 was used as solvent to the ER schemes to the south 

of the complex while acid gas from Plant #2 was combined with the associated 
Directive 065 Approval 10328A Amendment Application – 

Zama Keg River F Pool Acid Gas Miscible ER 

Page 4 of 8

solution gas from the high pressure separator to become solvent for ER schemes to 

the north of the complex. 

3.2 Changes to Solvent Composition 

Figure 7 shows the hydrocarbon content in the acid gas solvent stream used for 

injection into the ER schemes to the north of the Zama complex. It consisted of the 

acid gas from Plant #2 and the associated solution gas from Zama Keg River G2G 

Pool and Zama Keg River Z3Z Pool. There was a definite up trend with 

hydrocarbon exceeding 3% for approximately half of year. Figure 8 shows the 

hydrocarbon content in the acid gas solvent stream used for injection into the ER 

schemes to the south of the Zama complex. The solvent is strictly acid gas from 

Plant #3. The plot shows that the hydrocarbon content to be essentially flat 

throughout 2006 and below 3%. Besides a slight variation in hydrocarbon content 

of acid gas between Plant #2 and Plant #3, the only other difference between the 

solvent stream going north of the plant and the stream going south was the 

associated solution gas from the high pressure separator. 

3.3 Implication to Miscibility 

As more acid gas ER schemes start to show production responses, a larger volume 

of associated solution gas is expected and the hydrocarbon content of the combined 

injection stream may continue to increase as the proportion of the associated 

solution gas increases. This increase in hydrocarbon content in the solvent would 

affect the conditions in which miscibility with reservoir oil could be achieved. 

Apache has conducted an extensive study on the effect using an Equation of State 

(EOS) model. 

3.4 Expected Range of Solvent Composition 

Tables 3, 4 and 5 tabulate a range of expected solvent compositions that were used 

in the EOS study. The tables show the blending of acid gas stream from a plant at 

the complex with an associated solution gas stream at different blending ratios. 

Both the composition of the plant gas and the solution gas streams vary in each 

case. 

Table 3 shows a scenario of the blending of a plant gas and a solution gas with the 

lowest hydrocarbon content. The blending ratio is bracketed by the plant gas at the 

one end and the recycle solution gas at the other. Four other blending ratios of 

plant gas and recycle gas were used for the intermediate ranges: 5:1, 3:1, 1:1 and 

0.6:1. The resulting compositions are listed in blue. 

Table 4 shows the resulting composition of a scenario of blending an average plant 

gas and recycle gas composition in 2006. 
Directive 065 Approval 10328A Amendment Application – 

Zama Keg River F Pool Acid Gas Miscible ER 

Page 5 of 8

Table 5 shows the resulting composition of blending a plant gas with the lowest 

H2S content and a recycle gas with the highest hydrocarbon content, consisting of 

very high methane composition. This represents possibly the worst case scenario 

for miscibility. 

The EOS study, therefore, examined solvent compositions ranging from having 

40% H2S and 0.5% hydrocarbon on one end to 23% H2S and 16% hydrocarbon (all 

methane) on the other. 

3.5 Equation of State Calibration 

Apache has invested significant effort into modeling Zama reservoir oil with an 

EOS model. This EOS was used to predict miscibility. Before any prediction was 

made, the EOS model was tuned on the characterization of enhanced recovery lab 

studies from Zama Keg River F, Zama Keg River G2G and Zama Keg River NNN 

Pools. Figure 9 shows the lab result of a slim tube recovery using an acid gas blend 

and oil from Zama Keg River NNN Pool. It also shows the prediction of an 

uncharacterized EOS and one of a characterized EOS. The characterized EOS 

recovery prediction virtually matches that of the lab result. 

3.6 Implication to Minimum Miscibility Pressure 

Figure 10 shows the result of simulated slim tube experiments with an acid gas that 

consists of 23% H2S, 75.75% CO2, 1% C1 and 0.25% N2. This acid gas 

composition represents the lowest H2S composition going forward from the Zama 

gas plants. The figure shows the result with original oil and depleted oil. The 

results show a range of minimum miscibility pressures (MMP) from 12,500 to 

17,000 kPa. The two EOS models represent the range of uncertainty in the binary 

interaction coefficients used in PVT matches. 

3.7 Minimum Miscibility Pressure and Pseudo Critical Temperature 

Additional simulated slim tube studies were done with the different solvent 

compositions as detailed in Tables 3, 4 and 5. The result is presented in Figure 11 

where MMP is plotted against the Pseudo Critical Temperatures (Tpc) of each of the 

solvents. The plot illustrates the relationship between MMP and the Tpc of the acid 

gas solvents. 

Instead of showing the result of all the blends of plant gas and solution gas, Figure 

11 shows all the cases of each of the three scenarios. This study uses a recombined 

original oil with a bubble point (Pb) of 8,890 kPa. 
Directive 065 Approval 10328A Amendment Application – 

Zama Keg River F Pool Acid Gas Miscible ER 

Page 6 of 8

The green shaded area in Figure 11 shows the currently proposed amendment 

request operating pressure range of 14,000 to 15,500 kPa for the Zama Keg River F 

Pool ER scheme that is currently before the board. The blue shaded area in the 

figure shows the range of Tpc (314.0 to 326.8 oK) of the acid gas solvent injected 

into the scheme in 2006. 

The EOS study clearly shows that the currently approved operating pressure range 

is inadequate to achieve miscibility for solvents with higher expected hydrocarbon 

content. Similarly, should the hydrocarbon content in the solvent increase beyond 

the level seen in 2006, the Tpc of the acid gas solvents is expected to be lower. 

Apache’s estimate of the lowest quality acid gas solvent over the life of the ER 

project to be consisted of 23% H2S, 60.5% CO2, 11.4% C1, 0.2% N2 and 2.9% 

intermediate hydrocarbons which has a Tpc of 310 oK. A solvent with this character 

would achieve miscibility with the Zama Keg River F recombined original oil at an 

operating pressure range of 14,500 to 16,500 kPa. 

Figures 12 and 13 show the Tpc of the acid gas solvent available for ER schemes 

north of the Zama complex and south of the Zama complex respectively in 2006. 

3.8 Operating Pressure & Formation Fracture Pressure 

The proposed operating pressure range of 14,500 to 16,500 kPa is above the 

original reservoir pressure of 14,447 kPa. Apache presents the step-rate injectivity 

test results from three Zama Keg River wells nearby: 00/11-25-116-06W6, 00/02-

02-117-06W6 and 00/01-13-116-06W6 in Figure 14. None of the step-rate result 

shows a change of slope. Therefore, no formation fracture pressure was observed. 

The highest observed wellhead injection pressure in these tests was 12,000 kPa. At 

a nominal depth of 1,500 mKB and an injected fluid density of 1,100 kg/m3, the 

bottomhole pressure is approximately 28,000 kPa. The Directive 051 allows 90% 

of the fracture or the highest observed pressure, whichever is less, we can, 

therefore, inject at a maximum downhole pressure of 25,200 kPa. The minimum 

wellhead pressure that will produce a downhole pressure of 25,200 will occur when 

the tubing contains the densest fluid. This will occur when the injection gas stream 

is made up of 100% plant gas. Therefore, with an average acid gas solvent density 

of 907 kg/m3

, this maximum downhole pressure translates into a maximum 

wellhead pressure of 12,265 kPa. The current Directive 051 approved maximum 

wellhead injection pressure is 8,000 kPa. An amendment to the D 51 Maximum 

Well Head Pressure will be made to match this proposed D 65 amendment. 
Directive 065 Approval 10328A Amendment Application – 

Zama Keg River F Pool Acid Gas Miscible ER 

Page 7 of 8

3.9 Cap Rock Integrity 

In order to ensure there is containment of the acid gas solvent within the Keg River 

reef, Apache undertook a study of the competency of the cap rock. The study used 

mercury injection to measure the capillary pressure in core plugs from the Keg 

River cap rock which was then used to determine the threshold entry pressure 

(Reference 1). Using mercury (the non-wetting phase) to displace air (the wetting 

phase); the 5 core plugs yielded threshold pressures ranging from 82,400 to 

308,900 kPa with an average value of 157,000 kPa. The calculated permeability to 

air ranges from 1.59 10-9 to 7.95 10-9 millidarcy (md) and gave a harmonic average 

permeability of 3.7 10-9 md. Based on this harmonic average permeability, the 

mercury threshold pressure was calculated to be 215,955 kPa. 

Where: 

Threshold_Press - Threshold Pressure 

IFT - Interfacial Tension 

Θ - Contact Angle 

Acid_Gas - Acid Gas displacing Brine 

Mercury - Mercury displacing Air 

The equation above is used to calculate the threshold pressure of the cap rock with 

acid gas displacing brine. 

Based on a measured IFT of 38 dynes/cm for the CO2-brine interface, the threshold 

pressure for CO2 was determined to be 22,400 kPa. The lab was unable to measure 

the contact angle and the IFT for the acid gas (H2S/CO2) solvent. The presence of 

H2S is expected to result in a slightly lower IFT based on the higher solubility of 

H2S in brine. An IFT of 30 dynes/cm is assumed for the solvent gas and the 

adjusted threshold pressure to acid gas is 17,700 kPa. This is the pressure 

differential required at the cap rock interface to initiate flow. 

Since the average reservoir pressure is approximately 15,000 kPa and the threshold 

pressure is about 17,700 kPa, a pressure of approximately 32,700 kPa would be 

required to initiate flow. The actual flow rate would be dependant on the effective 

permeability through the thick low permeability cap rock layer, the viscosity of the 

acid gas, and the actual differential pressure for flow. 

With a maximum permissible bottomhole injection pressure of 23,400 kPa (90% of 

fracture extension pressure) and based on a formation fracture gradient of 18 

kPa/m, the solvent acid gas will be contained by the cap rock. 

( )

( ) ⎟

⎟

⎠

⎞

⎜

⎜

⎝

⎛

× Θ

× Θ =

mercury mercury

acid gas acid gas

Acid Gas mercury IFT

IFT

Threshold Press Threshold Press

cos

cos _ _ _ _

_
Directive 065 Approval 10328A Amendment Application – 

Zama Keg River F Pool Acid Gas Miscible ER 

Page 8 of 8

3.10 Other Changes to Ascertain Solvent Composition 

As detailed in Section 3.1, the associated solution gas from the high pressure 

separator can currently be combined only with the acid gas from Plant #2 as solvent 

for the ER schemes to the north of the Zama complex. In order to increase 

operating flexibility to control solvent composition, Apache intends to make 

changes to the injection flow lines such that the associated solution gas from the 

high pressure separator can be diverted to be combined with acid gas from Plant #3 

as shown in Figure 6. 

4 Safety 

Although the Operator proposes to operate the enhanced recovery scheme at a target 

average reservoir pressure between 14,500 to 16,500 kPa, Apache is committed to 

de-pressurize the pool pressure back down to the original reservoir pressure of 

14,447 kPa upon reaching the economic limit of the miscible flood. Apache 

proposes to start pool de-pressurization within three years of suspension of the 

miscible flood by either one or both of the following: 

1. production of acid gas from the top of the reef with re-injection into an acid 

gas disposal well or into other miscible flood enhanced recovery schemes 

2. production of high watercut reservoir fluid from the base of the pinnacle reef 

5 References 

1. Core Laboratories, “Advanced Rock Properties Study for Pennzoil Canada Inc. – Coenerco Zama 06-04-116-6W6M”, for Pennzoil Canada Inc., April 27, 1995, File 

Number: 52132-95-1017 
Directive 065 Approval 10328A Amendment Application – 

Zama Keg River F Pool Acid Gas Miscible ER 

Tables 
RESERVOIR PARAMETERS 

Pool: Zama Keg River F Pool 

Reservoir Parameters 

Pi, Reservoir Pressure (initial) 14,447 kPag EUB Reserves 

Database 

P, Reservoir Pressure (current) 15,838 kPag September 2004 Static 

Gradient Test 

T, Reservoir Temperature 71.1 oC Reservoir Fluid Study 

Boi, Oil Formation Volume Factor (initial) 1.183 Res. m3/m3 Reservoir Fluid Study 

Bo, Oil Formation Volume Factor (current) 1.172 Res. m3/m3 Calculated 

Bg, Gas Formation Volume Factor (current) N/A Res. m3/m3 Reservoir Fluid Study 

Rs, Solution Gas Oil Ratio (initial) 50.3 m3/m3 Reservoir Fluid Study 

Rs, Solution Gas Oil Ratio (current) 13.2 m3/m3 Calculated 

Porosity 10% Well Logs 

Initial Water Saturation 15% Well Logs 

API Gravity 35.2 API Reservoir Fluid Study 

Table 1
Zama Keg River F Recovery Rate Forecast 

Early and Late Breakthrough Cases

Zama Keg River F Production Forecast - Early Break Through Case

Pool ZKR F Producer 00/01-13-116-06W6/00

OOIP 344 e3m3 Injector 03/01-13-116-06W6/00

HCPV 413 e3rm3

Inj. Rate 30.2 e3m3/day

Acid Gas Eg 0.32 e3m3/rm3

Rs 52.0 m3/m3

Ult. EOR% 8.5%

Solution Prod.

Injection Incremental Year Year Gas Gas

Rate Cum. Inj Cum Inj. Cum Net Cum HCPVinj Rec Oil Rate Water Rate Rate Rate

Year e3m3/day e3m3 res m3 Inj, e3m3 Recy, e3m3 Frac. Frac. m3/day m3/day e3m3/day e3m3/day

2006 30.2 11025 34818 10731.0 293.9 0.08 0.0169 15.93 95.4 0.8 10.3

2007 30.2 22050 69636 21436.4 613.4 0.17 0.0338 15.93 79.5 0.8 20.6

2008 30.2 33075 104454 24126.7 8948.0 0.25 0.0451 10.68 79.5 0.6 25.1

2009 30.2 44100 139272 34513.9 9585.6 0.34 0.0527 7.19 79.5 0.4 26.6

2010 30.2 55124 174090 44844.9 10279.5 0.42 0.0607 7.56 79.5 0.4 28.6

2011 30.2 66149 208908 55465.7 10683.6 0.51 0.0665 5.43 79.5 0.3 29.6

2012 30.2 77174 243726 66718.6 10455.6 0.59 0.0699 3.25 79.5 0.2 28.8

2013 30.2 88199 278544 77678.9 10520.1 0.67 0.0720 2.00 79.5 0.1 28.9

2014 30.2 99224 313362 88669.0 10555.0 0.76 0.0737 1.52 79.5 0.1 29.0

2015 30.2 110249 348180 99598.2 10650.7 0.84 0.0752 1.43 79.5 0.1 29.3

2016 30.2 121274 382999 110448.1 10825.6 0.93 0.0773 2.00 79.5 0.1 29.8

2017 30.2 132299 417817 121310.3 10988.3 1.01 0.0793 1.93 79.5 0.1 30.2

2018 30.2 143323 452635 132326.9 10996.6 1.10 0.0809 1.49 79.5 0.1 30.2

2019 30.2 154348 487453 143351.8 10996.6 1.18 0.0825 1.49 79.5 0.1 30.2

2020 30.2 165373 522271 154364.3 11008.9 1.26 0.0834 0.84 79.5 0.0 30.2

2021 30.2 176398 557089 165385.3 11012.9 1.35 0.0840 0.63 79.5 0.0 30.2

2022 30.2 187423 591907 176410.2 11012.9 1.43 0.0847 0.63 79.5 0.0 30.2

2023 30.2 198448 626725 187435 11012.9 1.52 0.0854 0.63 79.5 0.0 30.2

Zama Keg River F Production Forecast - Late Break Through Case

Pool ZKR F Producer 00/01-13-116-06W6/00

OOIP 344 e3m3 Injector 03/01-13-116-06W6/00

HCPV 413 e3rm3

Inj. Rate 30.2 e3m3/day

Acid Gas Eg 0.32 e3m3/rm3

Rs 52.0 m3/m3

Ult. EOR% 12.8%

Solution Prod.

Injection Incremental Year Year Gas Gas

Rate Cum. Inj Cum Inj. Cum Net Cum HCPVinj Rec Oil Rate Water Rate Rate Rate

Year e3m3/day e3m3 res m3 Inj, e3m3 Recy, e3m3 Frac. Frac. m3/day m3/day e3m3/day e3m3/day

2006 30.2 11025 34818 10879 146 0.08 0.001 0.76 95.4 0.0 4.7

2007 30.2 22050 69636 21757 293 0.17 0.002 0.76 94.6 0.0 9.5

2008 30.2 33075 104454 27727 5348 0.25 0.014 11.99 83.4 0.6 15.3

2009 30.2 44100 139272 37977 6123 0.34 0.048 31.60 63.8 1.6 18.4

2010 30.2 55124 174090 47692 7433 0.42 0.070 21.28 63.8 1.1 21.5

2011 30.2 66149 208908 57683 8467 0.51 0.088 16.28 63.8 0.8 24.0

2012 30.2 77174 243726 68076 9098 0.59 0.098 9.45 63.8 0.5 25.4

2013 30.2 88199 278544 78301 9898 0.67 0.104 5.79 63.8 0.3 27.4

2014 30.2 99224 313362 88867 10357 0.76 0.108 4.45 63.8 0.2 28.6

2015 30.2 110249 348180 99647 10602 0.84 0.113 4.01 63.8 0.2 29.3

2016 30.2 121274 382999 110467 10807 0.93 0.116 2.99 63.8 0.2 29.8

2017 30.2 132299 417817 121329 10970 1.01 0.119 2.89 63.8 0.2 30.2

2018 30.2 143323 452635 132341 10982 1.10 0.121 2.24 63.8 0.1 30.2

2019 30.2 154348 487453 143366 10982 1.18 0.124 2.24 63.8 0.1 30.2

2020 30.2 165373 522271 154372 11001 1.26 0.125 1.26 63.8 0.1 30.2

2021 30.2 176398 557089 165391 11007 1.35 0.126 0.95 63.8 0.0 30.2

2022 30.2 187423 591907 176416 11007 1.43 0.127 0.95 63.8 0.0 30.2

2023 30.2 198448 626725 187441 11007 1.52 0.128 0.95 63.8 0.0 30.2

Table 2
Zama Keg River F Pool

Acid Gas EOR Approval No. 10328A Amendment

Stream 1 Stream 2

Plant Gas Recycled Gas Gas Plant 5:1 3:1 1:1 0.6:1 Recycle

N2 0.16% 0.21% 0.16% 0.17% 0.17% 0.18% 0.19% 0.21%H2S 40.00% 40.00% 40.00% 40.00% 40.00% 40.00% 40.00% 40.00%CO2 59.34% 50.69% 59.34% 57.90% 57.18% 55.02% 53.93% 50.69%C1 0.50% 4.90% 0.50% 1.23% 1.60% 2.70% 3.25% 4.90%C2 0.00% 1.70% 0.00% 0.28% 0.43% 0.85% 1.06% 1.70%C3 0.00% 1.30% 0.00% 0.22% 0.33% 0.65% 0.81% 1.30%i-C4 0.00% 0.20% 0.00% 0.03% 0.05% 0.10% 0.13% 0.20%n-C4 0.00% 0.40% 0.00% 0.07% 0.10% 0.20% 0.25% 0.40%i-C5 0.00% 0.20% 0.00% 0.03% 0.05% 0.10% 0.13% 0.20%n-C5 0.00% 0.20% 0.00% 0.03% 0.05% 0.10% 0.13% 0.20%C6+ 0.00% 0.20% 0.00% 0.03% 0.05% 0.10% 0.13% 0.20%Total HC 0.50% 9.10% 0.50% 1.93% 2.65% 4.80% 5.88% 9.10%

Best Case for Miscibility (Lowest C1 in Recycle stream gas analysis (Z3Z Aug 11 2006), 40% H2S)

Component

End Streams (Simulated Injection Gas Compositions)

Table 3
Zama Keg River RRR Pool

Acid Gas EOR Approval No. 105551 Amendment

Stream 1 Stream 2

Plant Gas Recycled Gas Gas Plant 5:1 3:1 1:1 0.6:1 Recycle Max HC1

N2 0.16% 0.21% 0.16% 0.17% 0.17% 0.19% 0.19% 0.21% 0.21%H2S 31.46% 23.88% 31.46% 30.20% 29.56% 27.67% 26.72% 23.88% 23.00%CO2 67.83% 63.51% 67.83% 67.11% 66.75% 65.67% 65.13% 63.51% 60.55%C1 0.49% 7.56% 0.49% 1.66% 2.25% 4.02% 4.90% 7.56% 11.40%C2 0.02% 1.88% 0.02% 0.33% 0.48% 0.95% 1.18% 1.88% 1.88%C3 0.02% 1.31% 0.02% 0.23% 0.34% 0.66% 0.82% 1.31% 1.31%i-C4 0.00% 0.23% 0.00% 0.04% 0.06% 0.12% 0.15% 0.23% 0.23%n-C4 0.01% 0.59% 0.01% 0.10% 0.15% 0.30% 0.37% 0.59% 0.59%i-C5 0.01% 0.32% 0.01% 0.06% 0.08% 0.16% 0.20% 0.32% 0.32%n-C5 0.01% 0.35% 0.01% 0.07% 0.10% 0.18% 0.23% 0.35% 0.35%C6+ 0.01% 0.16% 0.01% 0.04% 0.05% 0.09% 0.10% 0.16% 0.16%Total HC 0.56% 12.40% 0.56% 2.53% 3.52% 6.48% 7.96% 12.40% 16.24%

1

Component

 One final run was made with a composition having a Tcp = 310K

Existing Operating Conditions (Average Recycle Gas and Plant Gas for 2006)

End Streams (Simulated Injection Gas Compositions)

Table 4
Zama Keg River F Pool

Acid Gas EOR Approval No. 10328A Amendment

Stream 1 Stream 2

Plant Gas Recycled Gas Gas Plant 5:1 3:1 1:1 0.6:1 Recycle

N2 0.50% 0.50% 0.50% 0.50% 0.50% 0.50% 0.50% 0.50%H2S 23.00% 23.00% 23.00% 23.00% 23.00% 23.00% 23.00% 23.00%CO2 75.94% 60.50% 75.94% 73.37% 72.08% 68.22% 66.29% 60.50%C1 0.49% 16.00% 0.49% 3.07% 4.36% 8.24% 10.18% 16.00%C2 0.02% 0.00% 0.02% 0.02% 0.01% 0.01% 0.01% 0.00%C3 0.02% 0.00% 0.02% 0.01% 0.01% 0.01% 0.01% 0.00%i-C4 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00%n-C4 0.01% 0.00% 0.01% 0.01% 0.00% 0.00% 0.00% 0.00%i-C5 0.01% 0.00% 0.01% 0.01% 0.00% 0.00% 0.00% 0.00%n-C5 0.01% 0.00% 0.01% 0.01% 0.01% 0.00% 0.00% 0.00%C6+ 0.01% 0.00% 0.01% 0.01% 0.01% 0.01% 0.00% 0.00%Total HC 0.56% 16.00% 0.56% 3.13% 4.42% 8.28% 10.21% 16.00%

Worst Case for Miscibility (Highest C1 in Recycle Stream Gas Analysis (Theoretical), 23% H2S)

Component

End Streams (Simulated Injection Compositions)

Table 5
Directive 065 Approval 10328A Amendment Application – 

Zama Keg River F Pool Acid Gas Miscible ER 

Figures
ACL ZAMA 1-13-116-6 Acid GAS Disposal

ACL 102 ZAMA 1-13-116-6 Pumping OIL

800 m

Zama Keg River F

Pool & ER Approval

T116

R5W6 R6 Apache Canada Ltd

Zama Keg River F Pool

Pool Boundary &

ER Approval No. 10328A

Licensed to : Apache Canada Ltd

By : Date : 2007/06/28

Scale = 1:25000 Project : zama eor scheme

0 0.5 1 1.50 0.5 1

Kilometres

Miles

FG AOZ D&A D&C PO

AGZ AO SO AZN PG

SG AK AG WI FO

AWI AKO ARO CMM ARE

AWD LCT WD GD SWI

ARG DRN CLI PTG SWD

AKG J&A SL

WELL SYMBOLS

Figure 1
Zama Keg River F Recovery Rate Forecast 

Early and Late Breakthrough Cases 

EOR Oil Rate

Zama Keg River F Pool - Early Breakthrough Case

0.0

2.0

4.0

6.0

8.0

10.0

12.0

14.0

16.0

18.0

2004 2006 2008 2010 2012 2014 2016 2018 2020 2022 2024

Oil Rate, m3/day

EOR Oil Rate

Zama Keg River F Pool - Late Breakthrough Case

0.0

5.0

10.0

15.0

20.0

25.0

30.0

35.0

2004 2006 2008 2010 2012 2014 2016 2018 2020 2022 2024

Oil Rate, m3/day

Figure 2
Friday, May 25, 2007, 09:32 AM

Time (years)

1968 2008 72 76 80 84 88 92 96 00 04

0

0

0

0

1

0

0

0

1

0

0

1

0

1

PRD Monthly FLD 3 m

0

0

0

0

1

0

0

0

1

0

0

1

0

1

PRD Monthly OIL 3 m

00

00

1

00

01

0

01

01

INJ Monthly Acid Gas 3 m3 x10 PRD Cum OIL 135,076.1 3 m

PRD Cum WTR 91,483.8 3 m

Data As Of:

WellCount:

2007-03 (AB)2/2

ZAMA KEG RIVER G2G POOL

PRODUCTION/INJECTION 1968-03

2007-03

From:

To:

Figure 3
Friday, May 25, 2007, 09:29 AM

Time (years)

1969 2008 73 77 81 85 89 93 97 01 05

0

0

0

0

1

0

0

0

1

0

0

1

0

1

PRD Monthly FLD 3 m

0

0

0

0

1

0

0

0

1

0

0

1

0

1

PRD Monthly OIL 3 m

00

00

1

00

01

0

01

01

INJ Monthly Acid Gas 3 m3 x10 PRD Cum OIL 170,757.9 3 m

PRD Cum WTR 17,847.2 3 m

Data As Of:

WellCount:

2007-03 (AB)2/2

ZAMA KEG RIVER Z3Z POOL

PRODUCTION/INJECTION 1969-11

2007-02

From:

To:

Figure 4
Figure 5

02-02

ZKR UND

(KEG RIVER BANK)

100/02-02 DIS.

04-36 I ZKR NNN

102/04-36 INJ.

100/04-36 PROD.

11-25 I ZKR G2G

100/11-25 PROD.

102/11-25 INJ.

01-13 I ZKR F

100/01-13 INJ.

103/01-13 PROD.

BATTERY 12

PLANT 1

PLANT 2

PLANT 3

05-34 / 04-34

ZKR Z3Z I 100/05-34 INJ.

100/04-34 PROD.

09-33

ZSP K

100/09-33 (DH) DIS.

 08-33 (S)

14-32 I ZKR RRR

100/14-32 PROD.

100/14-32 (DH) INJ.

 11-32 (S)

Zama EOR System Map

Phases I, II, & III

P:\APACHE\ZAMA\06200 EOR Field P&IDs\Map\Zama EOR System Map - Rev 7.pdf

2006-MM-DD

Inset Map:

LEGEND:

Acid Gas Injection Line - Proposed

Acid Gas Injection Line - Existing

Acid Gas Injection Line - Proposed Re-Use of Existing

Production Line - Proposed

Production Line - Existing

Production Line - Proposed Re-Use of Existing

Injection Well Riser

Production Well Plant / Battery 12

Disposal Well
Figure 6
Zama Keg River F Pool

Acid Gas EOR Approval No. 10328A Amendment

Acid Gas Injection Composition

Flowing North of Zama Gas Plant

5.0%0.0%

10.0%

Jan 0- 6 Feb 0- 6 Mar 0- 6 Apr 0- 6May 0- 6 Jun 0- 6 Ju -l 06Aug 0- 6Sep 0- 6 Oct 0- 6 Nov 0- 6 Dec 0- 6 Jan 0- 7

Date

Mole %

HCCum HC

3% Maximum HC Limit

Figure 7
Zama Keg River F Pool

Acid Gas EOR Approval No. 10328A Amendment

Acid Gas Injection Composition

Flowing South of Zama Gas Plant

5.0%0.0%

10.0%

Jan 0- 6 Feb 0- 6 Mar 0- 6 Apr 0- 6 May 0- 6 Jun 0- 6 Ju -l 06 Aug 0- 6 Sep 0- 6 Oct 0- 6 Nov 0- 6 Dec 0- 6 Jan 0- 7

Date

Mole %

HCCum HC

3% Maximum HC Limit

Figure 8
Zama Keg River F Pool

Acid Gas EOR Approval No. 10328A Amendment

Figure 9
Zama Keg River F Pool

Acid Gas EOR Approval No. 10328A Amendment

Figure 10
Zama Keg River F Pool

Acid Gas EOR Approval No. 10328A Amendment

Solvent Gas Compositional Effects on Minimim Misscibility Pressure

Apache F Keg River Pool

86420

1816141210

295 300 305 310 315 320 325 330 335

Solvent Gas Pseudo Critical Tempurature, K

bility Pressure, MPa Est'd Minimum Misci

Worst Case for Miscibility (Highest C1 in recycle stream gas analysis (theoretical), 23% H2S)Best Case for Miscibility (Lowest C1 in Recycle stream gas analysis (Z3Z Aug 11 2006), 40% H2S)Existing Operating Conditions (ave recycle gas and plant gas for 2006)

Currently Approved operating pressure range

North Line average pseudo critical temp range

Average operating range

HC 

16.0

%

HC 

10.2% HC 

8.3%

HC 

4.4% HC 

3.1% 

HC 

0.6% 

HC 

12.4% HC 

8.0% 

HC 

6.5% HC 

3.5% 

HC 

2.5% 

HC 

0.6% 

HC 9.1%

5.9

4.8

2.7 

1.9% 

HC 0.5% 

HC 

16.2% 

Figure 11
Zama Keg River F Pool

Acid Gas EOR Approval No. 10328A Amendment

Injection Gas Pseudo Temperature

for North Line - Acid Gas EOR Scheme

370.0360.0350.0340.0330.0320.0310.0300.0

Jan 0- 6Feb 0- 6Mar 0- 6 Apr 0- 6May 0- 6 Jun 0- 6 Ju -l 06Aug 0- 6Sep 0- 6 Oct 0- 6Nov 0- 6Dec 0- 6 Jan 0- 7

Date

Temp, K

Injection Gas Pseudo Temp, K

Figure 12
Zama Keg River F Pool

Acid Gas EOR Approval No. 10328A Amendment

Injection Gas Pseudo Temperature

for South Line - Acid Gas EOR Scheme

370.0360.0350.0340.0330.0320.0310.0300.0

Jan 0- 6 Feb 0- 6 Mar 0- 6 Apr 0- 6 May 0- 6 Jun 0- 6 Ju -l 06 Aug 0- 6 Sep 0- 6 Oct 0- 6 Nov 0- 6 Dec 0- 6 Jan 0- 7

Date

Pseudo Temp, K

Injection Gas Pseudo Temp

Figure 13
Zama Keg River F Pool

Acid Gas EOR Approval No. 10328A Amendment

STEP RATE INJECTIVITY TESTS 02-02-117-06W6, 01-13-116-06W6 & 11-25-116-06W6

0

8,0006,0004,0002,000

14,00012,00010,000

0 0.2 0.4 0.6 0.8 1 1.2 1.4 1.6

INJECTION RATE m3/min

WELLHEAD PRESSURE kPa

02-02-117-06W6 Acid Gas Disposal01-13-116-06W6 F Pool11-25-116-06W6 G2G Pool

Figure 14
APPENDIX B 

TABLE OF MVA TECHNIQUES AND 

APPLICATIONS
Data Application 

Well-Specific Data Baseline geology – hydrogeology – reservoir characterization – seal 

characterization - static modeling – dynamic modeling 

Downhole (geophysical) Logs Rock properties – reservoir characterization – seal characterization – stati

and dynamic modeling 

Spontaneous Potential Rock properties – geochemistry – water resistivity Resistivity and Microresistivity Rock properties – reservoir characterization – geochemistry – water and o

saturation 

Resistivity Imaging Rock properties – lithology characterization – geomechanical properties – 

fracture and fault detection – reservoir anisotropy 

Sonic Imaging Rock properties – lithology characterization – geomechanical properties – 

fracture characterization – stress analysis and stability 

Sonic – Open Hole Rock properties – sonic porosity – geomechanical properties – 3D rock 

mechanics – permeability estimates – pore pressure 

Sonic – Cased Hole Wellbore integrity – cement bond identification – cement bond quality – 

hydraulic isolation determination 

Ultrasonic – Cased Hole Wellbore integrity – cement bond identification – cement bond quality – 

hydraulic isolation determination – well damage and corrosion 

Spectral Gamma Ray Rock properties – lithology characterization – facies definition Nuclear Porosity Rock properties – neutron porosity – density porosity – bulk density – 

lithologic characterization – geomechanical properties – gas ID 

Nuclear Spectroscopy Rock properties – lithologic characterization – geochemical stratitgraphy Magnetic Resonance Rock properties – lithologic characterization – permeability – effective 

porosity – irreducible water saturation – hydrocarbon ID 

Caliper – Open Hole Rock properties – borehole rugosity Caliper – Cased Hole Wellbore integrity – casing damage Flow Characterization Geochemical characterization – reservoir characterization – volumetric 

flow rates – injectivity – wellbore integrity 

B-1
Data Application 

Drill Stem Tests Reservoir characterization – permeability – formation pressure – injectivit

– formation damage due to drilling 

Pressure Transient Analyses Reservoir characterization – permeability – formation pressure – injectivit

– formation damage due to drilling 

Mini-Frac Tests Reservoir characterization – seal characterization – geomechanical 

properties – rock competency 

Pressure/Temperature Geochemical characterization – reservoir characterization – wellbore 

integrity 

Tiltmeters Geomechanical characterization – reservoir characterization Seismic Imaging (vertical seismic  profiles) 

Reservoir characterization – permeability – injectivity – geomechanical 

properties – geochemistry 

Drilling Records Wellbore integrity – reservoir characterization Well Completion Records Wellbore integrity – reservoir characterization – simulation modeling Well Stimulation Records Wellbore integrity – reservoir characterization – simulation modeling – 

geomechanical properties 

Well Workover Records Wellbore integrity – reservoir characterization Production Records (oil, gas,  water) Reservoir characterization – injectivity – simulation modeling Injection Records (gas, water) Reservoir characterization – injectivity – simulation modeling Cuttings Collection and Analysis Lithology characterization – reservoir characterization – seal 

characterization – geochemistry 

Core Collection and Analysis Lithology characterization – reservoir characterization – seal 

characterization – permeability – geomechanical properties – geochemistr

Rock-Specific Data (from  core/cuttings)

Baseline geology – reservoir characterization – seal characterization – 

geochemistry – static modeling – dynamic modeling 

B-2
Data Application 

Mineralogy and Lithology  Analyses 

Reservoir characterization – seal characterization – geochemical propertie

– geomechanical properties – static and dynamic modeling 

X-Ray Diffraction (XRD) Mineralogy – chemical composition – geochemical modeling X-Ray Flourescence (XRF) Mineralogy – chemical composition – geochemical modeling Scanning Electron Microprobe  (SEM) 

Mineralogy – chemical composition – microstructure – geomechanical 

properties – geochemical modeling 

CT Scan Porosity – permeability – microstructure – geomechanical properties Geomechanical Analyses Geomechanical properties – permeability – failure threshold pressure – 

elastic and strength properties – geomechanical modeling 

Static and Dynamic Elastic Testing Geomechanical properties – elastic and strength properties – 

geomechanical modeling 

Young’s Modulus Geomechanical properties – stiffness Poisson’s Ratio Geomechanical properties – strain characterization – geomechanical 

modeling 

Permeability Analyses Permeability – injectivity – dynamic modeling Standard Core Plug Permeability Permeability – single-phase (oil, gas, or water) permeability – injectivity Relative Permeability Tests Permeability – multiphase (oil–gas–water) permeability – injectivity Pore Entry Mercury Injection Test Permeability – pore distribution – pore geometry – capillary pore pressure Probe Permeameter Test Permeability – air permeability – injectivity Reservoir Fluid Data Baseline geology – hydrogeology – geochemistry – static and dynamic 

modeling 

Gas-to-Oil Ratio Geochemistry – dynamic modeling Water Chemical Composition Geochemistry – dynamic modeling Water Specific Gravity Geochemistry – dynamic modeling Salinity Geochemistry – dynamic modeling Resistivity Geochemistry – dynamic modeling Gas Composition Geochemistry – dynamic modeling 

B-3
Data Application 

Oil Gravity Geochemistry – dynamic modeling Viscosity Geochemistry – dynamic modeling Salt Content Geochemistry – dynamic modeling Reservoir Data Baseline geology – hydrogeology – geochemistry – geomechanical 

properties – static and dynamic modeling 

Lithology Geology – static and dynamic modeling Average Depth to Top of Pay Geology – static and dynamic modeling Datum (ft or m) (mean sea level) Geology – static and dynamic modeling Minimum Depth Geology – static and dynamic modeling Maximum Depth Geology – static and dynamic modeling Average Pay Thickness Geology – static and dynamic modeling Average Porosity Geology – static and dynamic modeling Secondary Porosity Geology – static and dynamic modeling Average Permeabilty Geology – static and dynamic modeling Maximum Permeability Geology – static and dynamic modeling Minimum Permeabilty Geology – static and dynamic modeling Average Initial Water Saturation,  % Geology – static and dynamic modeling – geochemistry Average Reservoir Temperature Geology – static and dynamic modeling – geochemistry – geomechanical 

properties 

Initial Reservoir Pressure Geology – static and dynamic modeling – geochemistry – geomechanical 

properties 

Current Reservoir Pressure Geology – static and dynamic modeling – geochemistry – geomechanical 

properties 

Bubble Point Geology – static and dynamic modeling – geochemistry Residual Oil/Gas, % Geology – static and dynamic modeling – geochemistry Formation Volume Factor at  Reservoir Pressure Geology – static and dynamic modeling 

B-4
Data Application 

Oil Formation Volume Factor at  Bubble Point Geology – static and dynamic modeling Original Oil in Place Geology – static and dynamic modeling Thickness of Closure Geology – static and dynamic modeling Primary Drive Mechanism Geology – static and dynamic modeling Initial Gas-to-Oil Ratio Geology – static and dynamic modeling – geochemistry Current Gas-to-Oil Ratio Geology – static and dynamic modeling – geochemistry Geophysical Survey Data Geology – structural architecture – geomechanical characterization – 

reservoir characterization 

2D Seismic Surveys Geology – structural architecture – geomechanical characterization – 

reservoir characterization 

3D Seismic Surveys Geology – structural architecture – geomechanical characterization – 

reservoir characterization 

Crosswell Seismic Profiling Geology – structural architecture – geomechanical characterization – 

reservoir characterization 

Crosswell Microseismic Profiling Geology – structural architecture – geomechanical characterization – 

reservoir characterization 

Gravimetric Surveys Geology – structural architecture – geomechanical characterization – 

reservoir characterization 

Interferometric Synthetic Aperture  Radar (InSAR) 

Geology – structural architecture – geomechanical characterization – 

reservoir characterization 

Magnetic Anomoly Surveys Geology – structural architecture – geomechanical characterization – 

reservoir characterization 

Microseismic Array Surveys Geology – structural architecture – geomechanical characterization – 

reservoir characterization 

Tiltmeter Array Surveys Geology – structural architecture – geomechanical characterization – 

reservoir characterization 

B-5