# PLAINS CO 2 

# 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 G overnment, 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, trademark, manufacturer, or otherwise does not n ecessarily constitute or imply its endorsement, recommendation, or favoring by the United States G overnment or any agency thereof. The views and opinions of authors expressed herein do not necessarily state or reflect those of the United States Government or any agency thereof.

This report is available to the public from the National Techni cal Information Service, U.S. Department of Commerce, 5285 Port Royal Road, Springf ield, VA 22161; phone orders accepted at (703) 487-4650.

EERC DISCLAIMER

LEGAL NOTICE This research report wa s prepared by the Energy & Environmental Research Center (EERC), an agency of the Univ ersity 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 empl oyees 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 di sclosed or represents that its use would not infringe privately owned rights. Reference herein to any specif ic 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 co llaborative contributions and efforts of numerous groups from throughout the United States and Canada. We grat efully acknowledge the individuals who provided the back bone information upon which this report is based, specifically, Pat McLellan, Mathias Grobe, Stef an Bachu, David Ryan, Bill Reynen, Dave Nakles, and Rob Lavoie. We also acknowledge the PCOR Partners hip partners for their valuable efforts in providing much of the information used for this report. We extend our appr eciation to the various federal, state, and private organizations and unive rsity groups for their cooperation in our search

for data. A number of individua ls 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 ........................................................................................................... i v

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 Operat ional History ............................ 7 Overview of the Zama Gas-Processing Plant ...................................................................... 10

MVA PROGRAM ................................................................................................................... ..... 12 Regulatory Process ........................................................................................................... ... 13

Data Reconnaissanc e and Integration.................................................................................. 14 Baseline Geological and Hydroge ological Characterization............................................... 14 Rock Lithology, Mineralogy, and Com position of Formation Fluids ................................. 19

Baseline Reservoir Conditions ............................................................................................ 21 Mechanical Rock Properties ................................................................................................ 22

Geochemical Interactions Between Ac id 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 CO 2 

### 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 CO 2 

### and H 2 

### S 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 .............................................................................................................. Appen dix A

TABLE OF MVA TECHNIQUES AND A PPLICATIONS ......................................... Appendix B

LIST OF FIGURES

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

validation test in the Za ma Field of Alberta .......................................................................... 3

2 Monitoring activities at Zama, focused on asse ssing the potential fo r leakage out of the reservoir through the cap rock, wellbores, and spillpoint at th e 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 productio n facility ................................................ 12

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

9 AGS Zama geological and hydr ogeological study area ...................................................... 16

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

11 Cross section of the Zama subbasin show ing 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 interp retation showing casing deformation ................... 32

17 Monthly F Pool injection hi story – volume and mass ......................................................... 32

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

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

20 F Pool–mass of CO 2 

### stored ................................................................................................. 34

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

22 Keg River F Pool volumetric estima tion of OOIP and subsequent production prediction ................................................................................................................... .......... 36

LIST OF TABLES

1 F Pool Cumulative Recove ries to November 2003 ............................................................. 10

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

### iv PLAINS CO 2 

### REDUCTION (PCOR) PARTNERSHIP (PHASE II) –ZAMA FIELD

VALIDATION TEST REGIONAL TECH NOLOGY IMPLEMENTATION PLAN

Steven A. Smith, Energy & Environmental Research Center James A. Sorensen, Energy & E nvironmental Research Center Edward N. Steadman, Energy & En vironmental 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, a nd accounting (MVA) plan is critical to the success of any geological carbon sequestration project utilized as a method of reducing carbon dioxide (CO 2 

### ) emissions to the atmosphere. From October 2005 through September 2009, the

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

70% CO 2 

### and 30% hydrogen sulphide [H 2 

### S]) injection for the simulta neous purpose of enhanced oil recovery (EOR), H 2 

### S disposal, and sequestration of CO 2 

### . The Plains CO 2 

### Reduction (PCOR) Partnership has conducted MVA ac tivities at the site throughout this period, while Apache Canada Ltd. has undertaken the injection and hy drocarbon recovery proce sses. This project has been conducted as part of the U.S. Departme nt of Energy (DOE) National Energy Technology Laboratory (NETL) Regional Ca rbon 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 CO 2



### .

One of the primary purposes of the PCOR Partnership Phase II Program is to develop a Regional Technology Implementation Plan (RTI P) based on the expe riences and results generated at Zama. The purpose of the RTIP is to provide technical guidance on approaches for conducting baseline surveys, MVA, and a ssessing the overall success of injecting CO 2 

### -rich acid gas into deep carbonate oil reservoi rs for the purpose of simultaneous CO 2 

### 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 br oadly applicable to the injection of acid gas for

simultaneous CO 2 

### storage and EOR operations at loca tions throughout the United States, Canada, and even the world.

### v Acid gas has been obtained as a by-produc t 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 redir ected back to the field for utilization in EOR operations. Previously, CO 2 

### was vented to the atmosphere and sulfur was separated from the H 2 

### S and stockpiled in solid form on-site. This project has enabled the simultane ous beneficial use of each of these processing by-products and effec tive mitigation of two environmental concerns.

The Zama project has been designed to address the issue of monitoring CO 2 

### sequestration at EOR sites, in this case utilizing H 2 

### S-rich acid gas as the sweep mechanism, in a cost-effective and reliable manner. The primary issues that were addressed include 1) determination of CO 2 

### and/or H 2 

### S leakage, or lack thereof, from the pinn acle; 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

CO 2 

### 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 un derstand the ultimate fate of the injected gas. Geological, geomechanical, geochemical, and engin eering work has been used to fully describe the injection zone and adjacent stra ta in an effort to predict the long-term storage potential of this site. Through these activities, conf idence 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 Fi eld, many of the results obtained can be applied not only to additional pinnacles in the Alberta Basin, but to si milar structures throughout the

world.

Monitoring the site has been achieved pr imarily through fluid sampling and pressure monitoring in both the target pinnacle reef an d 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 hor izons. Pressure is also being meas ured 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 th at could potentially lead to failure and 2) leakage along wellbore pathways is not occurri ng. Certifying the integrity of the system has been a critical focus area, with tests being co mpleted on the cap rock and injection zone to determine the nature of potential geochemical a nd geomechanical changes that may occur as a result of acid gas exposure under superc ritical pressures and temperatures.

Geological investigation was focused on the reservoir, local, and regional (subbasinal) scales. Results of these investigations indicate th at 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 th rough existing wellbores was also evaluated and found to be very low. Geomechanical eval uations, including 3D modeling, were completed on the injection zone and adjacent stratigraphy. This series of test s confirm that the geological structures that are being util ized are excellent candidates fo r sequestration. The cap rock is considered to be extremely stable, has extremel y low permeability, and is not likely to fracture when subjected to injection pressures we ll beyond the maximum allowed. Geochemical modeling aids in the understand ing of the long-term fate of acid gas injected into carbonate

### vi rocks. Evaluations of the Zama system indicate th at 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 take n 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 in to the pinnacle reef, of whic h approximately 40,000 tons was CO 2



### . 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, ye t practical, MVA program can be developed. Given the proper geologic setting, MVA activit ies can be relatively inexpensive and not adversely affect commercial EOR operations.

### 1 PLAINS CO 2 

### REDUCTION (PCOR) PARTNERSHIP (PHASE II) –ZAMA FIELD

VALIDATION TEST REGIONAL TECH NOLOGY IMPLEMENTATION PLAN

Steven A. Smith, Energy & Environmental Research Center James A. Sorensen, Energy & E nvironmental Research Center Edward N. Steadman, Energy & En vironmental 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 (CO 2 

### ) emissions from large industrial point sources has been identified as a potential means to mitigate global climate change. Efforts

to reduce CO 2 

### emissions now are a significant fo cus for all energy production and use stakeholders, including the general public , governments, industry, regulators, and environmentalists. Many large industrial CO 2 

### emission sources produce a gas stream that

includes constituents other than CO 2 

### . This is particularly true of natural gas-processing plants, which can have significant quantities of hydrogen sulfide (H 2 

### S) mixed within their CO 2 

### stream. Such gas mixtures are commonly refe rred to as “acid gas” or “sour CO 2 

### ” streams. While many laboratory- and field-based rese arch projects have focused on technical and economic issues associated with the management of CO 2 

### , relatively few have focused on the unique issues related to the management of acid gas, which is far more toxic and corrosive than pure CO 2



### .

Carbon capture and storage (CCS ) in geological media have b een identified as important mechanisms for reducing anthropogenic CO 2 

### emissions currently vented to the atmosphere. Several means for geological storage of CO 2 

### are available, such as in depleted oil and gas reservoirs, deep saline formations, CO 2 

### flood enhanced oil recove ry (EOR) operations, and enhanced coalbed methane recovery. These same ge ological formations may also be amenable to the large-scale storage of acid gas. Activities to imp rove understanding and develop technologies and approaches for CO 2 

### and acid gas capture; transporta tion; storage; and monitoring, verification, and accounting (MVA) have been, and continue to be, conducted. The goals of such

activities are to determine the tech nical and economic viability of CO 2 

### and acid gas storage and to support the deployment of larg e 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-pro cessing plants (Skinner and others , 1995; Sorensen and others, 1996). Similarly, the transportation of high concentr ations 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 a nd gathering lines have produced and moved trillions of cubic feet of methane and acid gas throughout Albe rta and British Columbia for several decades (Sorensen and others, 1996). The technical a nd economic challenges associated with the injection of CO 2 

### and acid gas into geological formations are also fairly well understood, as CO 2 

### injection for EOR has been applied at many loca tions 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 M VA required for such storage projects are in the early stages of technology development a nd implementation and are, therefore, less

understood.

In particular, MVA activities are critical components of geologi cal acid gas storage projects for two key reasons. Firs t, the public must be assured that geological storage of CO 2 

### and acid gas is a safe operation. Second, emerging car bon credit-trading markets need assurance that credits are properly assigned, traded, and accounted for. Integrated geological and hydrogeological characterization, modelling a nd simulation, geomechanical testing, and geochemical sampling and analysis programs are t echnologies that can f acilitate documentation of the movement of the injected gases and dete ct any potential leakage from the storage unit.

The Energy & Environmental Research Center (EERC), through the Plains CO 2 

### Reduction (PCOR) Partnership, one of the U.S. Departme nt of Energy (DOE) National Energy Technology Laboratory’s Regional Carbon Seques tration Partnerships, is worki ng with Apache Canada Ltd. to conduct a program of primarily field-based ac tivities 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, CO 2 

### 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 esse ntially impermeable anhydrite. The capture, transportation, and injection pr ocesses and subsequent hydro carbon recovery operations are being carried out by Apache Canada at its oil fi eld and natural gas-processing plant locations near Zama, Alberta, Canada (Figure 1). The ro le 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 act ivities, and yet provide critic al data on the behavior and fate of the injected acid gas mi xture within the reservoir.

The MVA, acid gas production, and EOR activ ities 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. On e 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 pr ovide technical guid ance on approaches for conducting baseline

### 3 Figure 1. Location of the PCOR Partnership–Apa che Canada acid gas st orage field validation

test in the Zama Field of Alberta.

surveys, MVA, and assessing the overall success of injecting CO 2 

### -rich acid gas into deep carbonate oil reservoirs for the purpose of simultaneous CO 2 

### storage and EOR. The RTIP is not

intended to be a detaile d accounting of the numerous activiti es conducted at Zama and their results over the course of the pr oject. Instead, the RTIP presents a series of key observations, insights, and recommendations, based on the experiences at Za ma, that are intended to be broadly applicable to the injec tion of acid gas for simultaneous CO 2 

### 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 inject ion of an acid gas stream into properly characterized and carefully se lected underground reservoirs is feasible and safe within existing industry and regulatory standards.

• To design, implement, and demonstrate cost-e ffective MVA strategies for verifying and validating the containment integr ity of the target reservoirs.

• To demonstrate that highly concentrated acid gas (in this case, 30% H 2 

### S and 70% CO 2 

### ) can be successfully used for EOR operations in a type of geologi cal feature (carbonate pinnacle reefs) that had prev iously been untested with respect to acid gas-based EOR.

### 4 Philosophical Approach

There is a broad range of technologies and appr oaches that can be and, in some cases, have been applied to CO 2 

### storage projects of various scales ar ound the world. Early geological storage research and demonstration proj ects deployed MVA stra tegies that were developed based on a lack of knowledge about the effectiveness and u tility 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 CO 2 

### 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 technique s in early projects yielded valuable results that are essential to the development of geological storage as a CO 2 

### mitigation strategy, their high costs of deployment and often limited abil ity to identify CO 2 

### in many geologic settings may render them as being the exception rather th an the rule when it comes to developing practical MVA pl ans for future projects. If the imple mentation 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 earli est stages of project development. At the same time, a detailed understanding and effective dem onstration of the techni cal feasibility with respect to injectivity, capacity, containment, and ove rall safety is essential for all stakeholders to buy into the concept of large-scale CO 2 

### and/or acid gas injection. This is the context within which a philosophical approach was developed, whic h was then applied to the PCOR Partnership Phase II Program.

It is expected that, in many cases, EOR proj ects and depleted oil a nd gas pools will provide the most favorable locations for long-term CO 2 

### storage from both a technical and economic standpoint. From a technical perspe ctive, such sites benefit from a relative wealth of previously generated, readily available subsurface characte rization 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 CO 2 

### , and in this case, acid gas. From an economic perspective, hydrocarbon reservoirs (and especially t hose that are suitable for EOR projects) are attractive because the use of existing infrastructure can lowe r 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, br ing 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 Pa rtnership toward the design, implementation, and operation of the MVA plan and a ssociated project activities was to:

• Maximize the use of previously generated data on the geological, geochemical, and geomechanical characteristics of the forma tion 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 “nor mal” or “standard” ope ration of an EOR or acid gas disposal project.

For those elements of the MVA plan that requ ired 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 disrupti on 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 dem onstrating the economic feasibility of acid gas injection for simultaneous EOR and CO 2 

### storage under “real world” technical and economic constraints could be achieved. That being sa id, the PCOR Partnership and Apache Canada recognized the value of developing previously unavailable fundamental data sets that could provide new understanding of CCS a nd 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 activi ties that were of a more res earch-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 ca n be thought of as falling into two categories: 1) the MVA program and 2) th e injection program. These categories are not necessarily independent of each ot her, with some activities and data sets being common between the two categories. However, for the sake of effe ctive discussion in the context of the RTIP, they are presented in this report in relatively indepe ndent 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 du ring and after injection operations; 2) generate data sets that demonstrat e 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 ca rbon credits associated with reduction of emissions and the geological storage of CO 2 

### at Zama. MVA program activities that resulted in the determination of baseline conditions include geol ogical and hydrogeolog ical characterization at various scales, characterization of the F pool reservoir, dete rmination of geomechanical and geochemical properties of key rocks in the reservoir/seal sy stem, and evaluation of wellbore integrity issues. Field-based elements of the MVA program in clude the introduction of a tracer and data collection (i.e., formation fluid sampling and anal ysis, 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 ac tivities 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) fa cilitate the production of incremental oil from the F Pool reservoir; and 3) support the documentation of effective CO 2 

### storage in the F Pool. Key aspects of the injectio n program include the capt ure and infrastructure elements of the project, well preparation and ma intenance activities, and acid gas injection and EOR operations.

The PCOR Partnership Phase II–Apache Ca nada project at Zama was conducted by a multidisciplinary team of engineers, scientis ts, regulators, and management personnel. The management team for the project included repr esentatives 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 Adva nced Geotechnology Inc. Effective, frequent

communication between all team members was crit ical 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 projec t management and budget standpoint, sometimes

blurred the lines between the va rious elements of the program, which further underscored the need for frequent, diligent reporting of activiti es 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° latit ude 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 b oundaries of the oil fiel d and is approximately 1 km west of the F Pool inje ction site (Figure 3). The fiel d covers an area of about 2000 km 2


### (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 wate r 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 count ry into very wet marshl and, 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 th e Zama oil field. Pinnacle reefs at Zama are steepsided, moundlike carbonate structur es 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, w ith variable porosity (average 10%) and permeability. The pinnacle reefs are encased latera lly and vertically by essentially impermeable anhydrites and underlain by a brine-saturate d formation. Figure 5 presents a cartoon representation of the gene ral structure, in cros s-section view, of the pinnacle reefs and their relationship to overlying seals, aquifers, an d 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 CO 2 

### sequestration technology validati on 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 produci ng oil in 1967. The well produced 170,750 m 3


### (1.1 MMbbl) of oil over a 20-year period. In la te 1986, oil production was discontinued, and the well was completed as a saltwa ter disposal well in October 1987. Water injection operations were suspended in October 1991, with a cu mulative water injection of about 1.8 MMbbl (287,500 m 3 

### ). 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 becaus e of their small size and heterogeneity with respect to porosity and permeability.

In June 1997, the well completion in th e 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 su rface (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 (s haded in yellow) in rela tion to the gas plant.

### 9 Figure 4. Flooded areas of the Zama Field. Specialized tr ansportation 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 brin e 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 oi l at the top and center of the

### 10 F Pool pinnacle. It was completed as an ope n hole and placed in production in March 2002. Production was suspended in earl y 2004 after producing just 5438 m 3 

### (34,220 bbl) of oil.

In July 2004, following project planning, includ ing reservoir, geologi cal evaluations, and economic evaluations, Apache made an applicati on to the Energy Resources Conservation Board (ERCB) to conduct an acid gas miscible flood. Pe troleum engineering studi es and lab work were also carried out in support of this applicati on, including well and reser voir review, miscibility studies, statistical analysis of oil compositions in the area, and estimates of miscible flood efficiency. The original ERCB approval stipulatedoperational limits for the F Pool EOR scheme, some of which were altered following the applic ation 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 m 3 

### (470 bbl) between August 2005 and May 2006. This

well was then utilized to draw water off the lo wer portion of the pinnacle to lower the average reservoir pressure down to the original E RCB-approved range beginn ing in November 2006. This objective was accomplished by May 2006 but injection was not started until December 2006. By that time, injection of ac id gas into other pi nnacle reefs (pools) in the Zama Field had already begun, and the Zama Keg River F Pool becam e 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 opera ted by Apache Canada. The plant currently generates about 7.5 million cubic feet per day (7.5 MMcf/day, 210,000 m 3 

### /day) of acid gas consisting of 20% to 40% H 2 

### S and 60% to 80% CO 2 

### . This amounts to a tota l of about 273 metric tons/day of CO 2 

### and 84 metric tons/day of H 2 

### S. The Zama gas plant an d oil production facility (Figure 7) was modified to accommodate the acid gas EOR/CCS project. Following these modifications, the Zama gas plant consis ts of the following process elements:

• Production gathering system

• Conventional oil and gas pro cessing, 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 m 3



### Gas 533,604,614 ft 3 

### 15,110,000 m 3



### Water 405,647 bbl 64,500 m 3


### Water Injection 2,304,329 bbl 366,400 m 3

### 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 m 3 

### /m 3



### Initial Formation Volume Factor 1.183 r vol/std vol

Bubble Point Pressure 1275 psi (8791 kPa)

API 1 

### Gravity 35.2 API

Calculated OOIP 2 

### 2.2 million bbl
344,000 m 3 

### (volumetric using 3-D seismic data)

Calculated OOIP 3.5 million bbl 557,000 m 3 

### (material balance)

1 American Petroleum Institute.

2 Original oil in place.



### Figure 6. Oil production well in the Keg Ri ver 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 su lfur recovery unit to produce solid elemental sulfur, which was then stored until mark et conditions would allow its sale; CO 2 

### 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 ac id 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 ga s stream into the Keg River EOR pools. The elimination of the sulfur production a nd storage is a major environmental benefit in

addition to the simultaneous elimination of the CO 2 

### venting (64,000 tons per year).

The current Zama natural gas operation ha s resulted in signifi cant reduction of the operating costs that were associated with the sulf ur plant. Further revenue could result if EOR is feasible using miscible acid gas flooding. This value-added appro ach could be used to manage

CO 2 

### -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 CO 2 

### –H 2 

### S storage. This was accomplished by carrying out the following activities:

### 13 • Going through the regulatory process

• Data reconnaissance and integration

• Baseline geology and hydroge ology characterization

• Rock mineralogy and composition of formation water determination

• Mechanical rock properties a nd stress regime evaluation

• Assessment of geochemical interactions between formation and injected fluids and reservoir rock and cap rock

• Assessment of wellbore integr ity and leakage potential

Regulatory Process

While the regulatory process for any given ac id gas injection proj ect, whether it be for EOR, CCS, or both, will vary depending on the ju risdiction within which the project is operated, it is instructive to briefly summarize the pr ocess 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 ga thering system modifications, and reservoir engineering practices were all conducted w ithin industry-recommended practices (IRP), including the practices and standards of AP I and the National Asso ciation of Corrosion Engineers. In many cases, these standards and practices are consistent with regulatory requirements and guidelines, although it is importan t 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 injec tion 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 Conservati on Act (Alberta Oil and Gas Conservation Act, 2009). Specifically, EUB Directive 65 (Energy Res ources Conservation Bo ard, 2009) must be followed. It is then required to file a separa te application for each pool, which references the original application approval. Also required is Directive 51 (Energy Resources Conservation Board, 1994), compliance planning for injection we lls, and a site-specific Emergency Response Plan (ERP) (Energy Resources Conservation Board, 2008). Wellhead components must meet product specification level (PSL) III require ments according to API Standard 6C.

Because of the site-specific nature of the app lication for the F Pool aci d gas injection, a full presentation of the elements of that applicat ion is beyond the scope of this discussion. The complete application and subsequent amendmen ts 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 a pplication 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 ch allenge in that the first pool approval for the Z3Z pool was

### 14 received 388 days after submission; this was twice the exp ected length of time and significantly delayed project start-up.

Data Reconnaissance and Integration

Efficient data acquisition, evaluation, and inte gration through the use of data management tools are crucial early steps in the establishment of baseline c onditions. Data reconnaissance and integration activities for the Zama project included the following:

• Well/reservoir information of the pertinent formations.

• Data on drilling, completion, and stimulati on/workover of key we lls in the area.

• Digital production/injecti on history of key wells.

• Geological and geophysical in formation on the key forma tions 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 characterizi ng the geological setting and hydr ogeological regime at an acid gas–CO 2 

### injection site is important to understand po ssible 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 Poin t saline aquifer; 2) th e Devonian Slave Point saline aquifer; 3) the Upper De vonian saline aquifer system, wh ich 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 characteri zation activities and shoul d 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 form ation waters and injected acid gas such as porosity and absolute and relative permeability

• Geothermal regime

• Pressure regime

### 15 Figure 8. AGS northeast Alberta stratigra phic and hydrostratig raphic section.

• Direction and strength of formation water flow

A model of the flow-driving processes and mech anisms in the region and strata of interest were developed from those data that help in un derstanding the effect of natural flow on flow paths in the aquifer intervals of the Zama study ar ea 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 leakag e through a wellbore, the current and planned acid gas injection at Zama will have minimal impact on the hydroge ologic regime of any of the Devonian Aquifer systems in the area. The study also showed that ev en if injected acid gas were to make its way into any of the Devonian Aquifer systems, the dire ction and strength of fo rmation water flow in those systems are such that it would take thousa nds of years for the acid gas to migrate to any formation outcrop. These results are a key compone nt to demonstrating long-term containment of the injected acid gas and safety.

### 16 The geology and hydrogeology ch aracterization work was carri ed 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 confinin g units: Lower Keg River Form ation limestone and Muskeg Formation anhydrite. This, the smallest of scales , provides insight into predicting the immediate and early near-term effects of th e injection operations. This is th e 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 th e course of the injection, such as history matching injection and production curves, will provi de 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 re presents the regional scale, and the black outline around the Alberta

Basin represents the basin scale. The reservoir sc ale, 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 succe ssion from the basement to the surface. This scale generally includes the oil field within whic h the individual pool is a part. As with work done at the reservoir scale, work at the local sc ale can be used to predict near-term (months to years) effects of injection. These data can typi cally 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 ove r 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 generall y much larger than the local scale (up to several hundred square miles). Examples typically include large structural featur es such as subbasins, bu t 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 year s) effects of large-scal e injection operations, particularly if multiple projects are planned.

Work at the basin scale was primarily conducted with resp ect to large-scale hydrogeological characteristics. Basin-scale studies of aqui fer system dynamics (flow, temperature, salinity, hydraulic head, etc.) will provide insight regarding the very long-term (hundreds to thousands of year s) effects of large-scale CO 2 

### 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 Form ation at the F Pool EOR site was generated to evaluate reservoir geometry and internal architecture. The Keg River pinnacle reef re servoirs are confined above by 70 m of Muskeg/Prairie Formation eva porites 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 evalua ted, as well as the underlying aquifer that provides reservoir support in places. Informa tion about the geology of the reservoir and confining strata (e.g., structural setting, stratigraphy, general lithology; thickness; and areal extent) were collected, pr ocessed, and interpreted fo r the local-scale area.

At the regional scale, the geology, stratigraphy, and lithology were evaluated, delineated, and described for the entire sedimentary successi on from the base of the Middle Devonian Elk Point Group (lower confining unit) to the su rface (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 inve stigated to identify any possibly existing faults and/or fractures that would allow migration of re servoir and injected fluids. On this basis, a geological model (Figures 10–12) of the entire se dimentary 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 sh owing regional structural architecture. The texture seen in the cutaway is the result of indi vidual pinnacle reef struct ures sitting on the Keg River platform.

### 19 Figure 12. Simplified paleogeography of the Keg Ri ver carbonate from basin-scale assessment.

Rock Lithology, Mineralogy, and Co mposition 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 fo r 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 operati ng 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 pla nned. 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 sa line formation, should in clude 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 preinject ion modeling activities, includi ng the development of static petrophysical models, site-specific geomechani cal and geochemical modeling, and simulations of injection and plume transport and fate. An exploration well character ization program should include the following elements:

### 20 • Collection of co re and cuttings

− Cuttings should be collected at regularly spaced intervals (5 m is typical industry practice) from surface to total depth of th e 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 fr om 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 fr iable nature. The collection of core from secondary target inject ion zones and seals shoul d also be considered . It is also worth noting that the collection of core samples should be superv ised by wellsite geologists and drillers who have experi ence drilling in the local ar ea. 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 preser ved to allow for detailed description and testing. Core tests should include a va riety 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 sample s, 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 (incl uding 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 soni c, and a microimaging tool. These logs will provide key rock property data including porosity, resi stivity, general lithol ogy and, to a lesser extent, permeability. Other specialized geophysic al 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 pr ovide crucial data that will support the development of casing and cementing sche me 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 c onsidered 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 t hose fluids can be produced, which yields important informatio n 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 tr ansient 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 us ed to acquire data that will confirm the predicted response of the interval being test ed to increases in pressure. The mini-frac procedure provides key design data from the pa rameters associated with the injection of fluids and the subsequent pressure decline (Schlumberger Oilfield Glossary, 2009). In the case of a CCS pr oject, current regulatory pr inciples typically preclude injection that goes beyond a pr eset 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 reco mmended 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 se aling formations and provide quantitative measurements that support the determinati on of an appropriate injection pressure limit that is based on site-specific data ra ther 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 wa ter injection activities in near by 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 ini tiating 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 syst em and potential for ro ck fracturing. An in-d epth 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 pr oject activities included a variety of laboratory and field-based investigations. Laborat ory-based activities using core samples of Keg River reservoir rock and Muskeg anhydrite cap rock collected from the origin al F Pool well drilled in 1967 included compression tests to determine rock stre ngth, 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. Re gional minimum stress orientation was determined using

borehole breakout data from a numb er 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 Za ma 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 beyo nd the scope of this repo rt. However, some key results are worth noting. The peak strength data i ndicate that both the rese rvoir rock and the cap rock are relatively strong carbonate rocks and ar e 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 re latively stiff Youngs Modulus of 6193 kpsi (42.7 GPa). The Muskeg cap rock samples, whet her 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 si milar area cores, plus lo g analyses and drilling reports, there is strong evidence that the thick 2 00- 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 th at these rocks can sust ain high stresses without experiencing significant deformations and that failure of the cap ro ck should not occur under normal operating conditions. The data further s uggest 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 CO 2 

### and/or acid gas volumes coul d be stored within this pinnacle by increasing the allowa ble storage pressure beyond the original reservoir pressure.

Geochemical Interactions Between Acid Gas and Reservoir/Seal Rocks

Understanding the geochemical interacti ons between injected fluids (i.e., CO 2 

### and/or acid gas) is critical to predicting bot h the effects of such injection on reservoir and seal rocks and the ultimate fate of the injected gases. The geoche mistry-related activities that were conducted as part of the Zama project were focused on gather ing relevant mineralogy and geochemistry data and assessing, through the use of geochemical m odeling, 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 CO 2 

### and/or H 2 

### S 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 gi ven CCS project will be site-spe cific, depending on the nature of the rocks, formation fluids, a nd injection stream that will be involved. However, in general, geochemistry evaluations for CCS projects should include detailed analytic al 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 th e injection stream. Mineral compositions can be obtained by scanning electr on microscopy (SEM), x-ray diffraction (XRD), and x-ray fluorescence (XRF) techniques. Fluid chemistry da ta 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 proj ect, and a full presentation of

all of those activities an d results is beyond the sc ope of this document. However, some of the

activities and their results are not able and are described below.

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

behavior of the CO 2 

### and H 2 

### S components of the acid gas after in jection 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% CO 2 

### and 30% H 2 

### S, and the temperature and pressure of the reservoir were assumed to be 50°C and 14 MPa. The reservoir mineralogy was id entified as calcite, quartz, and dolomite, with trace amounts of clays. In addi tion, there is an appr eciable amount of iron within the carbonate minerals. The modeling was performed using the reservoir simulator GEMTM (Computer Modelling Group), which has the capacity to mode l the flow of fluids and reactions between minerals and aqueous fluids.

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

enriched in CO 2 

### . 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 H 2 

### S 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 minera ls, significant amounts of iron a nd bicarbonate are added to the water. This iron rapidly precipitates as an iron sulfide when H 2 

### S is present in the gas phase. The iron sulfide precipitation produces a significant amount of acid; th is acid drives much of the bicarbonate out of aqueous so lution, leading to further CO 2 

### enrichment in the gas plume.

Numerical modeling simulations were also co nducted as part of the ARC geochemistry work. Simulations were run for 200 years followi ng acid gas injection. The numerical results indicate that significant concentr ation gradients may remain in th e reservoir at the end of this time. Dense, CO 2 

### /H 2 

### S-rich gas compositions will exist at the bottom of the reservoir, with primarily methane-rich gases exis ting 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 th e behavior of injected acid gas can be significantly affected by the presence of reactive iron minerals in the re servoir. Furthermore,

these results indicate that the ve rtical variations in the gas-ph ase 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 ex amined the relationships between geochemical interactions and effects on permeability of reservoir and seal rocks. Examination of the literature

shows that certain natural CO 2 

### reservoirs have e xperienced 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 CO 2 

### and other acid gas components, it is also known that capillary fluid entry and/or inte rfacial fluid tension (IFT) will

allow some restricted fluid to imbibe into the ca p 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-fr actures or flaws in the cap rock are of more concern, this IFT-related issue ha s 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 re serves (or even high-purity CO 2 

### ) over geologic time will automatically contain 100% of the aqueous fluid mixtures with lowe r interfacial tensions such as

CO 2 

### in brine or CO 2 

### and H 2 

### S mixtures in brine. It must be recognized that this leakage mechanism is rock-, pressure-, temperature- and fl uid-dependent, and th e variability of CO 2



### – brine IFT pressures for brines of differing salinity is well documented (Li and others, 2005; Zhaowen and others, 2005).

CO 2 

### –brine IFT decreases with increasing pressu re, while increasing temperature and brine salinity have the opposite e ffect. Specific data on H 2 

### S–water and CO 2 

### –H 2 

### S IFT have recently been reported (Shah and othe rs, 2008) in which the H 2 

### S–brine system acts in a similar manner but at a much lower capillary entry pressure than the CO 2 

### –brine solution. The H 2 

### S–water IFT is

30% to 40% lower than that of the CO 2 

### –water IFT. However, for both systems, the IFT is much lower than the in situ hydrocarbon IFT that orig inally provided the tr apping mechanism for the hydrocarbons against the cap rock layer. Thus, add itional laboratory IFT studies are suggested to further investigate aqueous H 2 

### S and aqueous CO 2 

### –H 2 

### S mixtures.

In conclusion, these studies suggest that co ntainment of acid gas in a geological reservoir setting may be affected by the capi llary properties of the acid gas–brine solution in relation to the capillary pore entry pressure of the brine-satura ted 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 mechani cal stress testing. The designated maximum operating reservoir pres sure will be pool-specific. If a lower maximum reservoir pressure limit is necessary, the estimates for st orage 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 re gard to the disposal and storage of acid gas

and CO 2 

### because they may provide a leakage pathway. It is not possible to determine the “exact” state of all wellbores; c onsequently, the approach that was used in the Zama project, and which is recommended for use in areas with a large numb er of existing wellbores, was to combine both “real” field data and analytical or numerical simulations to quantif y processes associated with the hydraulic integrity of the wells. St atistical well geometry and perf ormance data within the Zama field and surrounding regions were compiled from available databa ses. A database of projectspecific well data was constructed from detaile d 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 stabi lity in the long term. Based on this information, probabilistic assessments of well bore integrity issues under the conditions of acid gas and CO 2 

### injection and long-term buoyancy-dr iven forces were evaluated.

For the Zama project, a review of the integr ity 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 we lls 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 completi on. 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 pl ugs that are capped with cement. As a result, this well was proposed as the si te 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 po tential to allow l eakage 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 revi ew of the tubing strings and downhole completion equipment utilized in the F Pool wells revealed that al l of the wells have standard L-80 tubing above the packer s 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 utiliz e corrosion-resistant Incoloy packers, profiles, and on–off tool s 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 allo w 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 CO 2 

### or acid gas injection project is leakage of the injected gas from the target re servoir 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. Specif ically, 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 l eakage into the Slave Poin t 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 t hose 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 CO 2 

### or H 2 

### S 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 CO 2 

### and H 2 

### S throughout the Devonian-age rocks of northwestern Alberta, including the Keg River and Slave Poin t Formations, combined with the complicated

### 27 history of acid gas production an d disposal in the Zama area led the technical team to recommend the use of a proprieta ry 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 b een detected in any of the gas samples to date, although the scheduled mid-2009 samples have not yet been collect ed as a result of personnel and budget restrictions. Th e on-site trace r-sampling program is complicated by the fact

that the Slave Point well “water ed 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 pr emise 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-ps i (200-kPa) increase in pressure (Figure 14). At this point, it cannot be determined if this is a result of two differe nt gauge readings, water influx, an increase of pressure due to the arriva l 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 th ese 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 de monstration 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 regul atory 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-processi ng 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 CO 2 

### storage in the F Pool. Over the course of the Zama EOR and CCS project, a variety of site-s pecific design and ope rational 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 RT IP, this report will fo cus on the components of the Zama Keg River F Pool acid gas injection pr ogram 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 EO R operations, and determination of CO 2 

### 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% CO 2 

### and 3% H 2 

### S. The Zama gas-processing plant also processes nonassociated gas from the field, wh ich contains approximately 13% H 2 

### S and 8% CO 2 

### . Finally, an amine-based acid gas removal (AGR) system generates an effluent stream that is approximately 4% methane, 66% CO 2 

### , and 30% H 2 

### S. 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 appr opriate pressure for in jection. Additional acid gas is stripped from oil produced through EOR activities at a separator tank, compressed, and commingled with the previously disc ussed 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-specifi c operational challenges we re identified over the course of operating the acid gas EOR/CCS fac ility. 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 zone s 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 ope rating challenges to any EOR/CCS operating facility and have the potential to result in increased engineer ing work as well as increased operating costs. Optimization of th e perforation zones and gas inje ction rates will be entirely site-specific, and the degree of difficulty in de termining 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 characterist ics 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 economi cally resolve these probl ems. However, it is important to note that, as was th e case at Zama, none of these ch allenges are entirely new to the oil and gas industry and, given time and thoughtfu l consideration, all of them are manageable

and do not threaten the commercial use of aci d gas injection for EOR or as a viable CCS

strategy.

Well Preparation and Maintenance

CCS project operators and relate d stakeholders generally agree that the ability of new and existing wellbores to reliably contain CO 2 

### is of upmost importance. The main reasons for this

include validation of stor age volumes and related CO 2 

### storage credits, minimizing MVA operations, and to gain public confidence. The co llective 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, reser voir characterization, completion configuration, corrosion and integrity-monitoring plan, barrier and safety systems, and welloperating and maintenance schedule. Some of th e key considerations that went into the development of the BoD are discussed below.

The basis of oil and ga s industry well design for CO 2 

### injection and storage stems from long-established practices devel oped to inject associated CO 2 

### , H 2 

### S, acid gas, saline brine, and waste fluids within a wide variety of reser voirs since the mid-1900s. Among these fluids, acid gas (H 2 

### S + CO 2 

### + SO 2 

### ) has the highest potential for wellbor e corrosion and health, safety, and environmental (HSE) damage as H 2 

### S can cause sudden deadly respiratory arrest. Dry CO 2 

### alone

Figure 15. Operation to cl ear a plugged flowline.

### 30 is minimally corrosive, but wet CO 2 

### (mixed with saline brine) can be very corrosive and represents a significant challenge to petroleum industry standard s. 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 CO 2 

### and acid gas is a relatively common practice that has been used for decades in North America. North American CO 2 

### injection has roots within the Permian Ba sin of West Texas, with the use of CO 2 

### for EOR. The first known project was started by Chevron in Scurry County, Texas, in January 1972. Since then, CO 2 

### -based EOR has been conducte d on a large scale through out the world, including several large oil fields in West Texas, Saskat chewan, and Alberta. In the Western Canadian Sedimentary Basin, acid gas injection e xperience is similar to that of CO 2 

### . 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 comp lete a well for the produc tion or injection of CO 2 

### , H 2 

### S, and/or acid gas mixtures are very well de fined by regulations, standards, and IRPs.

The selection of corrosion-resist ant materials for well completi ons is critical to the longterm operation and maintenance of an acid ga s 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 CO 2 

### and H 2 

### S at different temperatures. While gu ides such as this are useful, it is important to note that economics and practical c onsiderations must also be factored into the final design. For instance, exclusive use of a si mplified manufacturer’s gui de 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 CO 2 

### and acid gas applications have turned to the use of low-alloy carbon steel pr otected by coatings or linings for casing and tubing applications. In some circum stances, a well design will utilize one or two joints of CRA casing within critical wellbore s ections 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 through out 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 st rongly indicates that prop erly designed portlandbased oil well cements are very CO 2 

### -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 CO 2 

### and brine mixtures do change the texture and mineralogy of portland oil well cements, but that the changes do not signifi cantly reduce the hydraulic seal afforded by the cement sheath.

### 31 Well preparation activities at Zama included co nducting a variety of tests to determine the integrity of the existing F Pool wells. The integr ity of new or old wells is easily verified with modern downhole logging tools, in cluding mechanical caliper tool s, electromagnetic tools, and acoustic resonance tools. An example of the types of data used to evaluate wellbore integrity is shown in Figure 16. Any existin g field or area proposed for CO 2 

### storage must include an evaluation of the ages and wellbore integrity of exis ting wells as part of the local risk evaluation. Even very old oil field wells have been s hown to provide reliable well integrity for CO 2 

### 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 fo r 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 wa s injected into the Keg River F Pool (1850 metric tons of CO 2 

### and 650 metric tons of H 2 

### S). The injection was at an averag e depth of 1455 m, which was the top of the Keg River Pool pinnacle reef. These in jection 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 × 10 3 

### m 3 

### /d). Through August 30, 2009, the cumulative amount of gas inject ed into the F Pool was 1) 40,160 metric tons of acid gas, 2) 29,720 metric tons of CO 2 

### , and 3) 9640 metric tons of H 2 

### S. After adjustment for the reproduced mass, the net stored CO 2 

### and H 2 

### S in the F Pool is 16,050 and 5807 metric tons, respectively.

The acid gas injection and pr oduction histories for the peri od of December 2006 through May 2009 are shown in Figures 17 and 18. During this 30-month period, in jection rates have varied to either maintain pressure in the F P ool or conduct well maintenance activities. The longterm average injection rate is roughly 2500 me tric tons per month. Daily averages were approximately 60.8 metric tons of CO 2 

### and 21 metric tons of H 2 

### S.

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 w ill be injected. Prior to decommissioning at the end of the EOR program, some of the stor ed acid gas volume may be produced back for injection into one or more of the other EOR/stor age pools. This ability to “bank” and reuse the acid gas is seen as a distinct advantage for s upplying injection gas to multiple EOR/storage pools in the area. However, the net vo lume of acid gas expected to be permanently retained in the F Pool upon completion of the EOR project (appr oximately 2019) is in excess of 40,000 metric tons. Figure 19 presents the cumu lative injected and stored F Pool mass and volumes to May 30, 2009. Figure 20 details the net stored CO 2 

### mass.

### 32 Figure 16. Example of raw logging data and interp retation showing casing deformation (courtesy of Baker Hughes).

Figure 17. Monthly F Pool injectio n history – volume and mass.

### 33 Figure 18. Keg River F Pool oil producti on and acid gas injection profiles.

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

### 34 Figure 20. F Pool–mass of CO 2 

### 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, unfortunate ly, was a poor producer, with a cumulative oil production of only about 75 m 3 

### (470 bbls) between August 2005 and May 2006. In order to prepare the F Pool reservoir for ac id gas injection and EOR, this well was then utilized to draw water from the lower portion of the pinnacle to lo wer the average reservoir pressure down to the original ERCB-approved range. This objec tive was accomplished by November 2006, but injection was not started until December 2006 wh en 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 th e production strategy in the F Pool, resulting in plans to conduct a workover on Production We ll 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 m 3 

### (2200 bbl) of oil, with the cu mulative oil production from the beginning of EOR totaling roughly 430 m 3 

### (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 Regi na 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 incremen tal 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 th e top of the structure is bei ng balanced by high water-cut production from the bottom of the structure to deve lop and maintain stability of the miscible sweep. Water is being di splaced in a gravity

- stable, top-down manner. Wh ile 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 th e Keg River F Pool was estimated to be approximately 3914 Mbbl. It should be noted th at revised estimates using updated reservoir

models now estimate the tota l volume to be approximately 5000 Mbbl. The volume of oil recovered during the three stag es 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. Roughl y 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 estim ation of OOIP and subsequent production prediction.

Determination of CO 2 

### Storage Capacity

Through August 30, 2009, the cumulative amount of gas injected into the F Pool was 1) 40,160 metric tons of acid ga s; 2) 29,720 metric tons of CO 2 

### ; and 3) 9640 metric tons of H 2 

### S. After adjustment for the repr oduced mass, the net stored CO 2 

### and H 2 

### S 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 ga s volume may be produced back to surface for injection into one or more of the ot her 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 pool s 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 vol ume of acid gas expected to be permanently retained in the F Pool upon completion of the EOR project is in exce ss of 40,000 metric tons.

While this value is not of the sc ale of many commercial projects, it should be noted that there are currently more than 800 pinnacl es 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 CO 2 

### storage capacity of the Zama Keg River F P ool 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 withou t this upgrade provided successful pressure history matches by including a very weak aquifer th at only has a small impact during the shut-in period. Th is observation was consistent w ith 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 rese rvoir material balance provides an acceptable reproduction of the Keg River pool production history. Specifically, the compositional model allows for reliable predictions of pool perfor mance 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 valid ates that the F Pool has mini mal 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 Partnershi p’s Phase II activities at Zama combined a wealth of historical information with newly gene rated 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 st akeholders and planners of fu ture similar projects with the ability to make informed decisions for a variet y of design elements. Proj ect-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 ro cks, 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 l earned over the course of the Zama acid gas injection project are briefly summarized below.

Suitability of Pinnacle Reefs for Ac id Gas Injection and Long-Term CCS

Based on the available data, the geological stud ies 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 stru ctures that originally trapped the oil and gas. There is minimal potential for acid gas leakage th rough faults and fractures in the Zama area or for acid gas migration to shallowe r strata, potable groundwater, or to the surface as a result of flow through naturally occurring perm eability streaks or flow paths.

The strength of the reservoir and cap rock formations, as determined by the geomechanical and geochemical evaluations, combined with the cl osed architecture of th e pinnacle structure and the very conservative maximum op erating pressures leave little po ssibility of lateral migration

outside of the reef structures. Further, the results of the regi onal hydrogeological study indicates that any potential dispersion beyond the individual pinnacle spill points into the regional aquifer would still result in storage o ccurring before the plume had trav eled a significant distance, e.g.,

### 38 the maximum velocity of the formation water is su fficiently 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 po re entry mercury injection pressure tests and mechanical stress testing on similar area cores, as well as log analyses a nd drilling reports, there is strong evidence that the thick (200 ft [6 0 m] to 300 ft [90 m]) Muskeg Formation dolomite/anhydrite sequences provid e a competent, dense, and essentially impermeable cap rock above the Keg River pinnacles. These data suggest that the F Pool pinnacl e integrity far exceeds the current ERCB EOR pressu re limit, and it could be proposed that following the completion of the EOR recovery, additional CO 2 

### 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 suit able and even excellent sites for CCS.

Relative Mobility and Fate of CO 2 

### and H 2 

### S 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 geoc hemical and mineralogical properties of the F Pool reservoir indicated that the leading edge of the acid gas plume will become enriched in

CO 2 

### . This observation was in agreement with the results of field- and laboratory-based analytical activities and other modeling efforts. The enrichment is due, at leas t in part, to the preferential absorption of H 2 

### S 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 minera ls, significant amounts of iron a nd bicarbonate are added to the water. This iron rapidly precipitates as an iron sulfide when H 2 

### S is present in the gas phase. The iron sulfide precipitation produces a significant amount of acid; th is acid drives much of the bicarbonate out of aqueous so lution, leading to further CO 2 

### enrichment in the gas plume.

Additional transport studies suggest that co ntainment 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 pr essure 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 ma ximum operating reservoir pressure will be pool-specific. If a lower maximum reservoir pressure limit is necessa ry, 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 appli cable not only to the hundreds of similar pinnacles in the Zama subbasin, but to acid gas injec tion projects in carbonate rock formations in general.

Effects of Acid Gas on Wellb ores 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 su ch materials, the judicious application of corrosion-resistant materials in the design of wells and surface facilities is required to maintain the proper balance of performan ce versus cost. For instance, as a result of the significant incremental costs for CRA pipe, most CO 2 

### and acid gas applications have effectively used lowalloy carbon steel protecte d 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 en tire 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 coat ings. 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 scheme s 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 de signed portland-based oil well cements are very CO 2 

### 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 CO 2 

### and brine mixtures do change the texture and mineral ogy of portland cements used in oi l 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 th e 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 th e introduction of chemical additi ves to prevent the coagulation of those materials. It is important to note that no ne of the operational challenges at Zama are new to the oil and gas industry and, given time a nd thoughtful consideration, all of them are manageable and should not threat en 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 wa s 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 hist ory 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 uni que 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 peri odic sampling and analysis events. In the case of the Zama F Pool, an existing gas producti on well that was completed in to the overlying Slave Point

Formation was selected to serve as a monitori ng well for both the pressure measurements and tracer analyses.

With respect to the tracer monitoring, a gas-soluble ch emical tracer compound (5.5 kg of Core Labs IGT-1100) was injected into the Ke g River F Pool in February 2008. The collection and analysis of fluid samples from the Slav e 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 inj ection project, initial pressure testing was performed on the Slave Point FFF Pool in Apr il 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-ps i (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 pr essure due to seepage. More pressure data are required before the source of any pr essure change can be attributed to any of these or any other

causes.

Generally speaking, the results of the trace r and pressure-monitori ng activities at Zama indicate that both techniques hol d considerable promise for app lication 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 m onetization 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) th e containment of the injected CO 2 

### , 2) the mass of CO 2 

### 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 a ll three of these aspects. Unfo rtunately, robust carbon credittrading markets for credits associated with geological storage of CO 2 

### 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 establ ished for the Zama projec t, it is worth noting that the acid gas injection progr am has yielded tax credits for Apache Canada. To encourage the development of a CCS industry in Alberta, the provincial governme nt, through the Alberta Department of Energy, has instituted a Royalty Cr edit Program (Alberta Department of Energy, 2005). This program offers a royalty reduction to companies that use CO 2 

### in EOR operations and that meet certain qualification criteria. Apache Canada has qualified fo r 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 s ubmitted but have not yet been awarded.

REFERENCES

Alberta Department of Energy, 2005, www.ener gy.gov.ab.ca/Oil/766.asp (accessed August 2009).

Alberta Oil and Gas Conserva tion 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 CO 2 

### producer: Presented at the 7th A nnual Conference on Carbon Capture and Sequestration, Pittsburgh, Pennsylvania, May 5–8, 2008.

Duguid, A., 2008, An estimate of the time to degr ade the cement sheath in a well exposed to carbonated brine, in Proceedings of the 9th Intern ational Conference on Greenhouse Gas Control Technologies: Washi ngton, D.C., November 16–20, 2008.

Energy Resources Conservation Board, 1994, Directive 051: Injection a nd disposal wells – well classifications, completions , logging, and testing requ irements, www.ercb.ca/docs/ documents/directives/Directive051.pdf (accessed August 2009).

Energy Resources Conservation Board, 2008, Di rective 071: Emergency preparedness and response requirements for the petroleu m industry, www.ercb.ca/portal/server.pt/ gateway/PTARGS_0_0_313_248_0_43/http%3B/ercbC ontent/publishedcontent/publish/ercb_ home/industry_zone/rules__regula tions__requirements/directves/ directive071.aspx (accessed August 2009).

Energy Resources Conservation Board, 2009, Di rective 065: Resources applications for conventional oil and gas reservoirs, www.erc b.ca/docs/documents/directives/Directive065. pdf (accessed August 2009).

Hyne, N.J., Dictionary of petroleum expl oration, drilling & produc tion, Pennwell Books, 1991.

Le Guen, Y., Le Gouevec, J., Chammas, R., Ge rard, B., and Poupard, O., Oxand S.A.; Van Der Beken, A., and Jammes, L., 2008, Sc hlumberger Carbon Services, CO 2 

### 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 th e security of long-term CO 2 

### storage in the Weyburn Field: Geofluids, v. 5, no. 4, p. 326–334.

### 42 Li, Z., Dong, M., Li, S., and Huang, S., 2005, CO 2 

### storage in depleted oil and gas reservoirs— caprock characterization and storage capacity: Science Di rect Energy Conversion and Management 2005.

Nelson, C.R., Evans, J.M., Sorensen, J.A., St eadman, E.N., Harju, J.A., 2005, Factors affecting the potential for CO 2 

### leakage from geologic sinks: Gr and 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 Sc iences Division, Ernest Orlando Lawrence Berkley National Laboratory, Berkley, California, June 2002.

Ostrowski, L., and Ulker, B., 2008, Minimizing ri sk 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 Exhibiti on: Rome, Italy, June 9–12, 2008, SPE Paper

no. 113509.

Royan, T., and Wichert, E., 1997, Acid gas injecti on eliminates sulfur r ecovery expense: Oil & Gas Journal, April 28, 1997.

Schlumberger Oilfield Glossary, 2009, www.glo ssary.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 ge ological storage: Internationa l 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 st ream survey: Gas Research Institute Topical Report, December 1995.

Smith, S.A., McLellan, P., Hawkes, C., Steadma n, E.N., and Harju, J.A., 2008, Geomechanical testing and modeling of reser voir and cap rock integrity in an acid gas EOR/sequestration project, Zama, Alberta, Canada, in Proceedin gs 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 Instit ute Topical Report, March 1996.

Talman, S., and Perkins, E., 2009, Geochemical mode ling of acid gas injection with reference to the Zama 08-33-115-6W6 well: Edmonton, Albert a, 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 Speci fics Summary – Original Conditions 2) For the purposes of this approval, “m iscible fluid” means gas that contains: a) A mixture of at least 0.97 mole fraction of H 2 

### S and CO 2 

### , with the remainder composed of other natural gas components. b) A H 2 

### S content not less than 0.25 mole fracti on and not more than 0.40 mole fraction at any time. c) An average H 2 

### S content not less than 0.32 mole fr action based on a 3-month rolling

average. 5) The Operator shall conduct in jection, to that part of th e subject pool referred to in Appendix A, in accordance with the following requirements: a) Production, without injec tion, shall initially o ccur until the average reservoir pressure is between 14,450 kPa(g) and 13,700 kPa(g). Misc ible fluid shall then be injected in

sufficient volumes to mainta in the average rese rvoir pressure be tween 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, “m iscible fluid” means gas that contains: a) A mixture of at least 0.97 mole fraction of H 2 

### S and CO 2 

### , with the remainder composed of other natural gas components. b) A H 2 

### S content not less than 0.20 mole fracti on and not more than 0.40 mole fraction at any time. c) An average H 2 

### S content not less than 0.23 mole fr action based on a 3-month rolling

average. 5) The Operator shall conduct in jection, to that part of th e subject pool referred to in Appendix A, in accordance with the following requirements: a) Production, without injec tion, shall initially o ccur until the average reservoir pressure is between 15,500 kPa(g) and 14,000 kPa(g). Misc ible fluid shall then be injected in

sufficient volumes to mainta in the average rese rvoir pressure be tween 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, “miscibl e fluid” means gas mixture with the following physical properties: a) A minimum cumulative pseudo-critical temp erature (cumulative from start of acid gas injection) of 310 K. b) A H 2 

### S 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 Pr oposed ERCB F Pool Approval Conditions (continued) ERCB EOR Approval No. 10328A: Approval Specifics Summary – Amendment 2 5) The Operator shall conduct in jection, to that part of th e subject pool referred to in Appendix A, in accordance with the following requirements: a) Production, without injec tion, shall initially o ccur until the average reservoir pressure is between 16,500 kPa(g) and 14,500 kPa(g). Misc ible fluid shall then be injected in

sufficient volumes to mainta in the average rese rvoir pressure be tween 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 inject ed 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 – 5 th 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, 2003Page 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

ReferencesPage 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 CO 2 and CO 2 + H 2 S MMP for Zama OilPage 3 

# Definitions

CO 2 Carbon Dioxide EOS Equation of State

GOR Gas Oil Ratio

GHG Green House Gas

H 2 S 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 SchemePage 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 e 3 m 3 /day of acid gas consisting of 20 to 40% H 2 S and 80 to

60% CO 2

. This amounts to a total of about 220 Tonnes/day of CO 2 and 80 Tonnes/day of

H 2 S. 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 e 3 m 3 /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. ThePage 5 initial nine pool scheme is estimated to have the potential to contribute an enhanced oil recovery reserve of 509 e 3 m 3 (3.0 million barrels). Over a period of 16 years, 1 megatonne of CO 2 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 thePage 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 e 3 m 3 (Volumetric using 3D Seismic Data)

Calculated OOIP 557 e 3 m 3 (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 e 3 m 3 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 e 3 m 3 (Volumetric using 3D Seismic Data)

Calculated OOIP 557 e 3 m 3 (Material Balance, see discussion below)

Cumulative recoveries to November 2003:

Oil 176.1 e 3 m 3

Gas 15.11 e 6 m 3

Water 64.5 e 3 m 3
Water Injection 366.4 e 3 m 3

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 CO 2 /H 2 S 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% CO 2 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 m 3 day of oil. Although a maximum injection rate of 94

reservoir m 3 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 samplesPage 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% H 2 S, 67% CO 2 mixture and about 20 MPa for pure CO 2

.

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 orw o i WF
Vol

S S S RE EPage 12 Where:

E vol - Volumetric sweep efficiency at the end of waterflood

RE wf - Current water drive recovery efficiency

S oi - Initial oil saturation, (85%)

S

orw - 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:

S
or

_ acid_gas - Residual oil saturation to acid gas drive, (assume 5%) Ultimate_RE Acid_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 gas

a cid o r o i

Flood G as A cid E S S S RE U

ltimate *

_ _ _

_ _      



=

) 1 ( sin 1 0 9

. 4 ' 4

 = 

M A k

k x q

g rg

crit μPage 13 q crit - 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

k

rg - Relative permeability end-point to gas, dimensionless

A

- Effective cross-sectional area being pushed downward by the injected gas, ft 2

- 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

g μ

- Viscosity of the injection gas at reservoir conditions, acid gas, cp

M

- Mobility ratio between injected gas and the oil zone defined as:

Where:

k

ro - End-point relative permeability to oil

o μ

- 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 rm 3 /day which translates to an injection rate at standard conditions of as high as 50

e 3 m 3 /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 o r o g r 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 CanadaPage 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 e 3 m 3
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 e 3 m 3 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 e 3 m 3

.

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 e 3 m 3 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 CO 2 and CO 2 +H 2 S MMP for Zama Oils”, Petroleum Technology Research Centre, February 2004. Also provided as Appendix I of this document.

4. R.B. Alston, etal, “CO 2 Minimum Miscibility Pressure: A Correlation for Impure

CO 2 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, 66 th 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)

C ore Sample

No. feet D epth, Top of

S ample,

m Depth,

B ottom

of

S ample,

m Length of

S ample,

m K Max K Vertical Perm

M eters,

md.m P orosity,

% Porosity

m eters

m

89 4901 1493.8 1494.1 0.3 3.75 0.35 1.0 5.9 0.016

9 0 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

9 2 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

9 5 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

9 7 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

9 9 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

1 01 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

1 03 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

1 05 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

1 07 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

1 09 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

1 11 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

1 13 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

1 18 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

1 20 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

1 22 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

1 24 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

1 26 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

1 28 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

1 30 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

1 46 4963.2 1512.8 1513.1 0.3 7.5 0.023

- 4964.2 1513.1

1 47 4975 1516.4 1516.7 0.3 504 159 169.0 8.8 0.030

1 48 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

1 68 5001.9 1524.6 1524.9 0.3 10.8 3.27 3.0 3.5 0.010

1 69 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 V isc (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 Conditio n psig 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 1.0235Figure16bEOROilRateKegRiverFRecoveryProfile-LateBreakthrough0.05.010.015.020.025.030.0200420062008201020122014201620182020

Oil Rate, bbl/dayTable4(2of2)KegRiverReef:ZamaMember/KegRiver(N-Dporosity)DatawasacceptedintotheNetPaySummaryifthefollowingcriteriaweremet.AnalysisPorosity...............greaterthanorequal.030andlessthanorequal1.000AnalysisSw.....................greaterthanorequal.000andlessthanorequal.400VolumeofShale.................greaterthanorequal.000andlessthanorequal.300UWILocationTopBaseCum.PhiHCum.Hyd.Cum.HCum.kHAverageAvg.WaterPoreVol.metersPorositySaturation100081311606W60100/08-13-116-W6146714771.3581.1729.300.1460.137100081311606W60100/08-13-116-W6147714900.9280.7289.900.0940.215100081311606W60100/08-13-116-W6149015020.1680.1232.100.080.265100081311606W60100/08-13-116-W6150215121.9051.689.500.2010.118100081311606W60100/08-13-116-W6151215200.4280.3612.700.1590.158100081311606W60100/08-13-116-W6153315400.7690.601500.1540.219TheKegRiverformationwasfrom1502meterstothebaseofthelogs(1551.0metersKB).Theuppersection(from1502.0–1517.5meters)hadalargedifferencebetweentheaverageporositiesoftheneutrondensityandtheneutron-acoustic(upto5.8%).Thedensitylogisreadingabnormallyhighandthisisduetopotentialrugoseboreholeconditions(nocaliperrunoverthissection),whichcouldbecausedbymicrofracturesand/orvugs.Thecoreporositymatchesreasonablywellwiththeneutron-acousticporositybuttherearesectionsthathaveapoorfit(seeplots).Table5SUMMARYOFRESERVOIROFF-TAKE,VOLUMETRICandMATERIALBALANCECALCULATIONSAnalysisofCurrentBubblePointfromRemainingOilandGasintheReservoirOriginalSolutionGOR(fromPVTreport)284scf/bbl50.3m3/m3OOIPVolumetric2.166mmbbl0.34Mm3OOIPMaterialBalance3.665mmbbl0.58Mm3OGIP(solutiongas)Volumetric615mmscf17.3Mm3OGIP(solutiongas)MatatialBalance1041mmscf29.3Mm3CumGasProd536.53mmscf15.1Mm3CumOilProd1.10817mmbbl0.18Mm3CumGOR484.16scf/bbl85.8m3/m3RemainingGasVolumetric79mmscf2.2Mm3RemainingGasMatBalance504mmscf14.2Mm3RemainingOilVolumetric1.06mmbbl0.17Mm3RemainingOilMatBalance2.56mmbbl0.41Mm3RemGORVolumetric74.32scf/bbl13.2m3/m3RemGORMatbalance197.25scf/bbl35.0m3/m3CurrentSatPressureusingVolumetrics213psi1469kPafromFlashCorrectedPVTTable,thisvalueisimpossibleCurrentSatPressureusingMatBalance763psi5261kPafromFlashCorrectedPVTTableLowestPressureMeasuredPressure551psi3800kPaOriginalSatPressurePVT1275psi8791kPaImperialMetricApacheCanadaLtd.WaterfloodEnhancedRecoveryZamaKegRiverFPoolMarch2003Page#020406080100120140160Jan-67Jun-72Dec-77Jun-83Nov-88May-94Nov-99May-05

Rate (m3/d)05,00010,00015,00020,00025,00030,000 Datum Pressure (kPaa) & GOR (m3/m3) x 10DailyFluidPRODm3/dDAILYOILPRODm3/dDAILYWTRINJECTIONm3/d/10GORm3/m3x10PressureSurveySurveyDateOil175,663m3Gas15,144e3m3Wtr59,898m3WtrInj366,424m3Figure10.PoolPressureandProductionHistoryRisingBubbleApparatusMMPforH2SandCO2InjectionGasZamaKegRiverFPool-1-13-116-6W6M810121416182022240510152025303540Mol%H2SinCO2InjectionGas

MMP (MPa)81012141618202224OriginalBP8.9MPaDepletedBP6.9MPaDepletedBP4.9MPaFigure 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.PercentIncrementalRecovery%

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.Prod/InjGasRatioFigure 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.PercentIncrementalRecovery%

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.Prod/InjGasRatioFigure16aEOROilRateKegRiverFRecoveryProfile-EarlyBreakthrough02468101214200420062008201020122014201620182020

Oil Rate, m3/dayFigure16bEOROilRateKegRiverFRecoveryProfile-LateBreakthrough0.05.010.015.020.025.030.0200420062008201020122014201620182020

Oil Rate, bbl/dayGuide 65 -Schedule 1 Resources Applications

1: REGISTRATION

Month 08 Day 09 Year 2004 Applicant’s File Number 01-13-116-6W6

E UB 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 (H 2 S)? 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 3G4Guide 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 – 9 th AVENUE S.W. / CALGARY, ALBERTA, CANADA T2P 3V4

November 9, 2004

Alberta Energy and Utilities Board Resource Applications Group

640 – 5 th 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 H 2 S concentrations ranging from 40% down to 0% respectively (the balance being

CO 2 ).

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% H 2 S. However, due to the presence of methane and nitrogen impurities in the plant effluent (1.2% C 1 and 1.2% N 2 ), it is likely that the MMP will be about 800 to 1,000 kPa higher than for pure H 2 S and CO 2 components. Given a worst case scenario of an average 25% H 2 S 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 H 2 S 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 H 2 S 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 CO 2 + H 2 S

Mixtures

Recombined Oil Sample Well 1-13-116-6 W6M 11-25-116-6 W6M Temperature ( ° C) 71 76

Injection Gas Composition (% H 2 S)* MMP (MPa) MMP (MPa)

0 19.9 21.3

20 16.6 19.0

40 13.4 16.9

* Balance is CO 2

Figure 1: Rising Bubble Apparatus MMP for H 2 S + CO 2 Injection Gas Mixtures with Zama

Recombined Oils 10 12 14 16 18 20 22

0 10 20 30 40

Mol% H 2 S in CO 2 Injection Gas MMP (MPa)

1-13-116-6 W6M

11-25-116-6 W6M(403) 261-1200 FAX (403) 263-1200 SUITE 1000 / 700 – 9 th AVENUE S.W. / CALGARY, ALBERTA, CANADA T2P 3V4

December 9, 2004

Alberta Energy and Utilities Board Resource Applications Group

640 – 5 th 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 poolafter 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% H 2 S 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.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 applic ation, 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 Za ma 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 th is regard, the annual performance review presentations for the scheme required as part of the s ubject 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

EnclosureApproval No. 10328 Page 2 of 5



### a) production, without injection, shall initially occur until the average reservoir pr essure is between 14 450 kiloPascals (gauge) and 13 700 kiloPascals(gauge). Miscible fluid shal l 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 eve ry 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 determine d 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 thes e 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 Applicati ons 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 i f 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, a nd 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 modifyin g 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 f loods outlined in EUB IL 96-2: Progress Report Requirements for Miscible Flood Schemes. In addition to theApproval No. 10328 Page 3 of 5



### base reporting requirements specified in IL 96-2, the following annual data submi ssion 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 injecte d 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 oth er 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 pe riod:

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 peri od, 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 e ach 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 DOCUMENTApproval 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 2007Directive 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 Minimu m Miscibility Pressure.................................................... 5

3.7 Minimum Miscibility Pressure a nd 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................................................................................................................... 8Directive 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 Produc tion & Injection History Plot

4. Zama Keg River Z3Z Pool Produc tion & 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 Eff ects 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 PlotDirective 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 th e Oil and Gas Conservation Act, Apache Canada Ltd. (“the Operator”), the operato r of Enhanced Oil Recovery Approval No. 10328A, hereby applies to amend the a pproval 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 H 2 

### S and CO 2 

### , with the reminder composed of other natural gas components,

b) an H 2 

### S content not less than 0.20 mole fraction and not more than 0.40 mole fraction at any time, and

c) an average H 2 

### S 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 sh all 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 H 2 

### S 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 sh all 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 Za ma 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 showi ng 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 (10 3 

### m 3 

### ) 546.0 344.0 Current Oil Recovery (10 3 

### m 3 

### ) 176.3 176.3 Current Oil Recovery Factor (%) 32.3 51.2 Incremental Miscible Recovery Estimate (10 3 

### m 3 

### ) 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 unexpect ed implications to other acid gas miscible floods that will be using the a ssociated 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 ar e 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 dr awn 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 associatedDirective 065 Approval 10328A Amendment Application – Zama Keg River F Pool Acid Gas Miscible ER Page 4 of 8 

### solution gas from the high pressure separato r 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 st ream 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 hydro carbon content to be essentially flat throughout 2006 and below 3%. Besides a s light 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 incr ease 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 th e 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 ble nding of acid gas stream from a plant at the complex with an associated solution ga s stream at different blending ratios. Both the composition of the plant gas a nd 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 ra tio is bracketed by the plant gas at the one end and the recycle solution gas at th e 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

H 2 

### S content and a recycle gas with the hi ghest hydrocarbon content, consisting of very high methane composition. This repr esents possibly the worst case scenario for miscibility.

The EOS study, therefore, examined so lvent compositions ranging from having

40% H 2 

### S and 0.5% hydrocarbon on one end to 23% H 2 

### S 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 char acterization 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 s lim 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 charact erized 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% H 2 

### S, 75.75% CO 2 

### , 1% C 1 

### and 0.25% N 2 

### . This acid gas composition represents the lowest H 2 

### S 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 mi scibility pressures (MMP) from 12,500 to 17,000 kPa. The two EOS models represent th e range of uncertainty in the binary

interaction coefficients used in PVT matches.

3.7 Minimum Miscibility Pressure a nd Pseudo Critical Temperature

Additional simulated slim tube studies were done with the different solvent compositions as detailed in Tables 3, 4 a nd 5. The result is presented in Figure 11 where MMP is plotted against th e Pseudo Critical Temperatures (T pc 

### ) of each of the solvents. The plot illustrates the relationship between MMP and the T pc 

### of the acid gas solvents.

Instead of showing the result of all the bl ends 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 (P b 

### ) 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 s hows 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 T pc 

### (314.0 to 326.8 oK) of the aci d gas solvent injected

into the scheme in 2006.

The EOS study clearly shows that the curre ntly approved operating pressure range is inadequate to achieve miscibility for solvents with higher expected hydrocarbon content. Similarly, should the hydrocar bon content in the solvent increase beyond the level seen in 2006, the T pc 

### 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% H2 S, 60.5% CO2, 11.4% C1, 0.2% N2 and 2.9% intermediate hydrocarbons which has a T pc 

### 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 T pc 

### 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 pre ssure in these tests was 12,000 kPa. At a nominal depth of 1,500 mKB and an injected fluid density of 1,100 kg/m 3 

### , 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 dow nhole 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/m 3 

### , 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 competen cy 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-we tting phase) to displace air (the wetting phase); the 5 core plugs yielded th reshold pressures ranging from 82,400 to 308,900 kPa with an average value of 157,000 kP a. 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 CO 2 

### -brine interface, the threshold pressure for CO 2 

### was determined to be 22,400 kPa. The lab was unable to measure the contact angle and the IFT for the acid gas (H 2 

### S/CO 2 

### ) solvent. The presence of

H 2 

### S is expected to result in a slightly lower IFT based on the higher solubility of

H 2 

### S 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 gas acid gas acid

mercury Gas Acid 

### IFT IFT Press Threshold Press Threshold

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 w ith the acid gas from Plant #2 as solvent

for the ER schemes to the north of th e 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 w ithin 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 th e reef with re-injection into an acid gas disposal well or into other miscible flood enhanced recovery schemes

2. production of high watercut reservoir flui d from the base of the pinnacle reef



### 5 References

1. Core Laboratories, “Advanced Rock Proper ties Study for Pennzoil Canada Inc. – Coenerco Zama 06-04-116-6W6M”, for Pennzoil Canada Inc., April 27, 1995, File

Number: 52132-95-1017Directive 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. m 3 

### /m 3 

### Reservoir Fluid Study

Bo, Oil Formation Volume F actor (current) 1.172 Res. m 3 

### /m 3 

### Calculated

Bg, Gas Formation Volume F actor (current) N/A Res. m 3 

### /m 3 

### Reservoir Fluid Study

Rs, Solution Gas Oil Ratio (initial) 50.3 m 3 

### /m 3 

### Reservoir Fluid Study

Rs, Solution Gas Oil Ratio (current) 13.2 m 3 

### /m 3 

### Calculated

Porosity 10% Well Logs

Initial Water Saturation 15% Well Logs

API Gravity 35.2 API Reservoir Fluid StudyZama 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 30.2Zama Keg River F PoolAcid Gas EOR Approval No. 10328AAmendmentStream 1 Stream 2Plant Gas Recycled GasGas Plant 5:1 3:1 1:1 0.6:1 RecycleN2 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 HC0.50% 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)ComponentEnd Streams (Simulated Injection Gas Compositions)Zama Keg River RRR PoolAcid Gas EOR Approval No. 105551 AmendmentStream 1 Stream 2Plant Gas Recycled GasGas Plant 5:1 3:1 1:1 0.6:1 RecycleMax HC1N2 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 HC0.56% 12.40%0.56% 2.53% 3.52% 6.48% 7.96% 12.40% 16.24%1One final run was made with a composition having a Tcp = 310KComponentExisting Operating Conditions (Average Recycle Gas and Plant Gas for 2006)End Streams (Simulated Injection Gas Compositions)Zama Keg River F PoolAcid Gas EOR Approval No. 10328AAmendmentStream 1 Stream 2Plant Gas Recycled GasGas Plant 5:1 3:1 1:1 0.6:1 RecycleN2 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 HC0.56% 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)ComponentEnd Streams (Simulated Injection Compositions)Directive 065 Approval 10328A Amendment Application – Zama Keg River F Pool Acid Gas Miscible ER 

# FiguresACL ZAMA 1-13-116-6 Acid GAS DisposalACL 102 ZAMA 1-13-116-6 Pumping OIL

8 0 0 mZama Keg River FPool & ER ApprovalT116R5W6R6Apache Canada LtdZama Keg River F PoolPool Boundary &ER Approval No. 10328ALicensed to : Apache Canada LtdBy :Date : 2007/06/28Scale = 1:25000Project : zama eor scheme0 0.511.50 0.5 1KilometresMilesFGAOZD&AD&CPOAGZAOSOAZNPGSGAKAGWIFOAWIAKOAROCMMAREAWDLCTWDGDSWIARGDRNCLIPTGSWDAKGJ&ASLWELL SYMBOLS

### 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 2024Oil 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 2024Oil Rate, m3/dayFriday, May 25, 2007, 09:32 AMTime (years)19682008727680848892960004

1 0 1 0 0 1 0 0 0 1 0 0 0 0PRD Monthly FLD3m

1 0 1 0 0 1 0 0 0 1 0 0 0 0PRD Monthly OIL3m 1 0 1 0 0 1 0 0 0 1 0 0 0 0INJ Monthly Acid Gas3m3x10PRD Cum OIL 135,076.13mPRD Cum WTR 91,483.83mData As Of:WellCount:2007-03 (AB)2/2ZAMA KEG RIVER G2G POOLPRODUCTION/INJECTION1968-032007-03From:To:Friday, May 25, 2007, 09:29 AMTime (years)19692008737781858993970105

1 0 1 0 0 1 0 0 0 1 0 0 0 0PRD Monthly FLD3m

1 0 1 0 0 1 0 0 0 1 0 0 0 0PRD Monthly OIL3m 1 0 1 0 0 1 0 0 0 1 0 0 0 0INJ Monthly Acid Gas3m3x10PRD Cum OIL 170,757.93mPRD Cum WTR 17,847.23mData As Of:WellCount:2007-03 (AB)2/2ZAMA KEG RIVER Z3Z POOLPRODUCTION/INJECTION1969-112007-02From:To: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

I nset 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 WellZama Keg River F PoolAcid Gas EOR Approval No. 10328AAmendmentAcid Gas Injection CompositionFlowing North of Zama Gas Plant0.0%5.0%10.0%

J a n - 0 6 F e b - 0 6 M a r - 0 6 A p r - 0 6 M a y - 0 6 J u n - 0 6 J u l - 0 6 A u g - 0 6 S e p - 0 6 O ct - 0 6 N o v - 0 6 D e c - 0 6 J a n - 0 7Date

Mole %HCCum HC3% Maximum HC LimitZama Keg River F PoolAcid Gas EOR Approval No. 10328AAmendmentAcid Gas Injection CompositionFlowing South of Zama Gas Plant0.0%5.0%10.0%

J a n - 0 6 F e b - 0 6 M a r - 0 6 A p r - 0 6 M a y - 0 6 J u n - 0 6 J u l - 0 6 A u g - 0 6 S e p - 0 6 O ct - 0 6 N o v - 0 6 D e c - 0 6 J a n - 0 7Date

Mole %HCCum HC3% Maximum HC LimitZama Keg River F PoolAcid Gas EOR Approval No. 10328AAmendmentZama Keg River F PoolAcid Gas EOR Approval No. 10328AAmendmentZama Keg River F PoolAcid Gas EOR Approval No. 10328A AmendmentSolvent Gas Compositional Effects on Minimim Misscibility PressureApache F Keg River Pool024681012141618295 300 305 310 315 320 325 330 335Solvent Gas Pseudo Critical Tempurature, K

Est'd Minimum Misci bility Pressure, MPaWorst 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 rangeNorth Line average pseudo critical temp rangeAverage operating rangeHC16.0%HC10.2%HC8.3%HC4.4%HC3.1%HC0.6%HC12.4%HC8.0%HC6.5%HC3.5%HC2.5%HC0.6%HC9.1%5.94.82.71.9%HC 0.5%HC16.2%Zama Keg River F PoolAcid Gas EOR Approval No. 10328AAmendmentInjection Gas Pseudo Temperaturefor North Line - Acid Gas EOR Scheme300.0310.0320.0330.0340.0350.0360.0370.0

J a n - 0 6 F e b - 0 6 M a r - 0 6 A p r - 0 6 M a y - 0 6 J u n - 0 6 J u l - 0 6 A u g - 0 6 S e p - 0 6 O ct - 0 6 N o v - 0 6 D e c - 0 6 J a n - 0 7Date

Temp, KInjection Gas Pseudo Temp, KZama Keg River F PoolAcid Gas EOR Approval No. 10328AAmendmentInjection Gas Pseudo Temperaturefor South Line - Acid Gas EOR Scheme300.0310.0320.0330.0340.0350.0360.0370.0

J a n - 0 6 F e b - 0 6 M a r - 0 6 A p r - 0 6 M a y - 0 6 J u n - 0 6 J u l - 0 6 A u g - 0 6 S e p - 0 6 O ct - 0 6 N o v - 0 6 D e c - 0 6 J a n - 0 7Date

Pseudo Temp, KInjection Gas Pseudo TempZama Keg River F PoolAcid Gas EOR Approval No. 10328AAmendmentSTEP RATE INJECTIVITY TESTS 02-02-117-06W6, 01-13-116-06W6 & 11-25-116-06W602,0004,0006,0008,00010,00012,00014,0000 0.2 0.4 0.6 0.8 1 1.2 1.4 1.6INJECTION RATE m3/min

WELLHEAD PRESSURE kPa02-02-117-06W6 Acid Gas Disposal01-13-116-06W6 F Pool11-25-116-06W6 G2G Pool

# APPENDIX B

TABLE OF MVA TECHNIQUES AND

APPLICATIONSData ApplicationUsed at Zama forMVAWell-Specific Data Baseline geology – hydrogeology – reservoir characterization – sealcharacterization - staticmodeling – dynamic modelingYesDownhole (geophysical) Logs Rock properties – reservoir characterization – sealcharacterization – staticand dynamic modelingYesSpontaneous Potential Rock properties –geochemistry – water resistivity YesResistivity and Microresistivity Rock properties – reservoir characterization – geochemistry – water and oilsaturationYesResistivity Imaging Rock properties – lithology characterization – geomechanical properties –fracture and fault detection – reservoir anisotropyYesSonic Imaging Rock properties – lithology characterization – geomechanical properties –fracture characterization – stress analysis and stabilityNoSonic – Open Hole Rock properties – sonic porosity – geomechanical properties – 3D rockmechanics – permeability estimates – pore pressureYesSonic – Cased Hole Wellbore integrity – cement bond identification – cement bond quality –hydraulic isolation determinationNoUltrasonic – Cased Hole Wellbore integrity– cement bond identification – cement bond quality –hydraulic isolation determination – well damage and corrosionNoSpectral Gamma Ray Rock properties – lithology characterization – facies definition YesNuclear Porosity Rock properties – neutronporosity – density porosity – bulk density –lithologic characterization – geomechanical properties – gas IDYesNuclear Spectroscopy Rock properties – lithologiccharacterization – geochemical stratitgraphy NoMagnetic Resonance Rock properties – lithologic characterization – permeability – effectiveporosity – irreducible water saturation – hydrocarbon IDNoCaliper – Open Hole Rock properties – borehole rugosity YesCaliper – Cased Hole Wellbore integrity – casing damage NoFlow Characterization Geochemical characterization – reservoir characterization – volumetricflow rates – injectivity – wellbore integrityNoContinued . . .



### B-1Data ApplicationUsed at Zama forMVADrill Stem Tests Reservoir characterization – permeability – formation pressure – injectivity– formation damage due to drillingYesPressure Transient Analyses Reservoir characterization – permeability – formation pressure – injectivity– formation damage due to drillingYesMini-Frac Tests Reservoir characterization– seal characterization – geomechanicalproperties – rock competencyYesPressure/Temperature Geochemical characterization – reservoir characterization – wellboreintegrityYesTiltmeters Geomechanical characterization – reservoir characterization NoSeismic Imaging (vertical seismicprofiles)Reservoir characterization – permeability – injectivity – geomechanicalproperties – geochemistryNoDrilling RecordsWellbore integrity – reservoir characterizationYesWell Completion RecordsWellbore integrity – reservoir characterization – simulation modelingYesWell Stimulation Records Wellbore integrity – reservoir characterization– simulation modeling –geomechanical propertiesYesWell Workover RecordsWellbore integrity – reservoir characterizationYesProduction Records (oil, gas,water) Reservoir characterization – injectivity – simulation modelingYesInjection Records (gas, water)Reservoir characterization – injectivity – simulation modelingYesCuttings Collection and Analysis Lithology characterization – reservoir characterization – sealcharacterization – geochemistryYesCore Collection and Analysis Lithology characterization – reservoir characterization – sealcharacterization – permeability – geomechanical properties – geochemistryYesRock-Specific Data (fromcore/cuttings)Baseline geology – reservoir characterization – seal characterization –geochemistry – static modeling – dynamic modelingYesContinued . . .



### B-2Data ApplicationUsed at Zama forMVAMineralogy and LithologyAnalysesReservoir characterization – seal characterization – geochemical properties– geomechanical properties – static and dynamic modelingYesX-Ray Diffraction (XRD) Mineralogy – chemical composition – geochemical modeling YesX-Ray Flourescence (XRF) Mineralogy – chemical composition – geochemical modeling YesScanning Electron Microprobe(SEM)Mineralogy – chemical composition –microstructure – geomechanicalproperties – geochemical modelingYesCT Scan Porosity – permeability – microstructure – geomechanical properties NoGeomechanical Analyses Geomechanical properties – permeability – failure threshold pressure –elastic and strength properties – geomechanical modelingYesStatic and Dynamic Elastic Testing Geomechanicalproperties – elastic and strength properties –geomechanical modelingYesYoung’s Modulus Geomechanical properties – stiffness YesPoisson’s Ratio Geomechanical properties– strain characterization – geomechanicalmodelingYesPermeability AnalysesPermeability – injectivity – dynamic modelingYesStandard Core Plug Permeability Permeability – single-phase (oil, gas, or water) permeability – injectivity YesRelative Permeability Tests Permeability – multiphase (oil–gas–water) permeability – injectivity NoPore Entry Mercury Injection Test Permeability – pore distribution – pore geometry – capillary pore pressure YesProbe Permeameter Test Permeability – air permeability – injectivity NoReservoir Fluid Data Baseline geology – hydrogeology – geochemistry – static and dynamicmodelingYesGas-to-Oil Ratio Geochemistry – dynamic modeling YesWater Chemical Composition Geochemistry – dynamic modeling YesWater Specific Gravity Geochemistry – dynamic modeling YesSalinity Geochemistry – dynamic modeling YesResistivity Geochemistry – dynamic modeling YesGas Composition Geochemistry – dynamic modeling YesContinued . . .



### B-3Data ApplicationUsed at Zama forMVAOil Gravity Geochemistry – dynamic modeling YesViscosity Geochemistry – dynamic modeling YesSalt Content Geochemistry – dynamic modeling YesReservoir Data Baseline geology – hydrogeology – geochemistry – geomechanicalproperties – static and dynamic modelingYesLithology Geology – static and dynamic modeling YesAverage Depth to Top of Pay Geology– static and dynamic modeling YesDatum (ft or m) (mean sea level) Geology – static and dynamic modeling YesMinimum Depth Geology – staticand dynamic modeling YesMaximum Depth Geology – staticand dynamic modeling YesAverage Pay Thickness Geology – static and dynamic modeling YesAverage Porosity Geology – static and dynamic modeling YesSecondary Porosity Geology – static and dynamic modeling YesAverage Permeabilty Geology – static and dynamic modeling YesMaximum Permeability Geology – static and dynamic modeling YesMinimum Permeabilty Geology – static and dynamic modeling YesAverage Initial Water Saturation,% Geology – static and dynamic modeling – geochemistryYesAverage Reservoir Temperature Geology – static and dynamic modeling – geochemistry – geomechanicalpropertiesYesInitial Reservoir Pressure Geology – static anddynamic modeling – geochemistry – geomechanicalpropertiesYesCurrent Reservoir Pressure Geology – static anddynamic modeling – geochemistry – geomechanicalpropertiesYesBubble Point Geology – static and dynamic modeling – geochemistry YesResidual Oil/Gas, % Geology – static and dynamic modeling – geochemistry YesFormation Volume Factor atReservoir Pressure Geology– static and dynamic modelingYesContinued . . .



### B-4Data ApplicationUsed at Zama forMVAOil Formation Volume Factor atBubble Point Geology – static and dynamic modelingYesOriginal Oil in Place Geology –static and dynamic modeling YesThickness of Closure Geology – static and dynamic modeling YesPrimary Drive Mechanism Geology –static and dynamic modeling YesInitial Gas-to-Oil Ratio Geology – staticand dynamic modeling – geochemistry YesCurrent Gas-to-Oil Ratio Geology – staticand dynamic modeling – geochemistry YesGeophysical Survey Data Geology – structural architecture – geomechanical characterization –reservoir characterizationNo2D Seismic Surveys Geology – structural architecture – geomechanical characterization –reservoir characterizationNo3D Seismic Surveys Geology – structural architecture – geomechanical characterization –reservoir characterizationNoCrosswell Seismic Profiling Geology – structuralarchitecture – geomechanical characterization –reservoir characterizationNoCrosswell Microseismic Profiling Geology – structuralarchitecture – geomechanical characterization –reservoir characterizationNoGravimetric Surveys Geology – structural architecture – geomechanical characterization –reservoir characterizationNoInterferometric Synthetic ApertureRadar (InSAR)Geology – structural architecture –geomechanical characterization –reservoir characterizationNoMagnetic Anomoly Surveys Geology – structural architecture – geomechanical characterization –reservoir characterizationNoMicroseismic Array Surveys Geology – structuralarchitecture – geomechanical characterization –reservoir characterizationNoTiltmeter Array Surveys Geology – structural architecture – geomechanical characterization –reservoir characterizationNo



### B-5