PanCanadian Petroleum Research Articles

Full Spectrum

Sally Zinke is an outstanding geophysicist who has left an indelible mark on SEG with her many achievements. Most notably, she is the only woman to date who has served as President of our Society. Zinke received a B.S. in geology and geophysics from the University of Wisconsin–Madison, an M.S. in geophysics from Pennsylvania State University, and midway through her career completed the executive M.B.A. program at the University of Denver with an emphasis in finance. She has worked for a major oil company, Mobil Oil; a large independent, PanCanadian Petroleum; was a faculty member at the University of Texas Bureau of Economic Geology; worked as a consultant on many exploration-related projects; and most recently was director of exploration/director of new ventures for Ultra Petroleum. Throughout that time, she has been a volunteer in her local SEG section, the Denver Geophysical Society, and has served on numerous SEG committees and several Executive Committees. While President in 2000–2001, Zinke, along with her Executive Committee, developed a Strategic Plan to take SEG into the 21st century. She also ably handled the 9/11 interruption of the SEG Annual Meeting in San Antonio, Texas. Through all of this, Zinke was a single mom, and as she claims, “My greatest success is my 22-year old daughter — I built an intelligent, strong, yet compassionate woman.”

JointPPandPSseismic inversion

We present a case history of joint inversion of PP and PS reflection seismic data using a weighted stacking technique. Our example comes from Blackfoot Field, owned and operated by PanCanadian Petroleum, in southeastern Alberta, Canada. The exploration target at Blackfoot is a Lower Cretaceous channel system approximately 1.4 km deep (Figure 1). Figure 1. The Glauconitic channel system at Blackfoot Oil Field, Alberta, is a sequence of sand and shale filled valleys incised into Lower Cretaceous and Mississippian carbonates. The Blackfoot interpretation has an upper and lower channel that are prospective and separated by a nonporous lithic channel. These Glauconitic channels, with sand or shale fill, are found throughout the region, and, as there were many episodes of channel formation, can be stacked on top of one another. At Blackfoot, the channel interval is about 40 m thick and 100 m wide. There tends to be good porosity in an upper channel and a lower channel that are separated by a tight, lithic channel. The upper channel, where present, is usually gas-prone, while the lower channel is generally oil-prone. When the pore fluid in the channel sands is a compressible hydrocarbon instead of incompressible water, the bulk compressibility is reduced and this modifies the signature of seismic reflection data. Because pressure waves and shear waves sense different rock and pore-fluid properties, joint use of PP and PS data can provide superior lithologic discrimination. The conversion of one elastic wave, either P or S , into another upon reflection or transmission at an interface is described by the Zoeppritz equations. These equations are algebraically quite complex and it is not practical to reproduce them here. Instead, we will present useful concepts and approximate forms. (We invite the reader to visit our Web site, http://www.crewes.org, and interactively examine the equations using our …

Weyburn CO2 Miscible Flood Conceptual Design and Risk Assessment

Abstract For the three years leading up to the end of 1995, a multidisciplinary project team evaluated the business opportunity of injecting carbon dioxide into a portion of the Weyburn Unit to improve recovery. As with any project of this magnitude, a comprehensive analysis of the opportunities and risks in the project had to be clearly defined and evaluated. A risk assessment using a Monte Carlo simulation approach was undertaken to combine the technical with the non-technical issues associated with the project in order to define the full cycle opportunities and risks. The risk assessment process was used to optimize the project configuration, to focus the team on key issues, and to find ways to mitigate the risks inherent in the project. Key uncertainties impacting the range in expected project returns appeared in the areas of commodity prices, reservoir performance, costs and fiscal terms. The risk assessment process and conceptual development plan, incorporating studies and analysis completed up to the end of 1995, is the subject of this paper. Introduction The Weyburn Unit, covering an area approximately 180 km2, is approximately 130 km southeast of Regina, Saskatchewan (Figure 1). The Unit is operated by PanCanadian Petroleum Limited on behalf of the working interest ownership. The field was discovered in 1955 and produced under primary depletion until an inverted nine spot waterflood was implemented in 1964. Production at the end of 1995 averaged 3,150 m3/d of medium sour crude from 650 oil producers, of which 90 were horizontal wells. At that time, it was postulated that more than 116 ? 106m3 of oil was expected to remain in the reservoir after the completion of waterflood operations, or 65% of the original 178 ? 106m3 in place. This large remaining oil in place represented a very attractive target for an enhanced recovery process. The Midale beds of the Weyburn field were deposited on a shallow carbonate shelf in the Williston basin. The reservoir is uniformly divided into the upper Marly, a chalky inter-tidal dolo-stone with limestone interbeds, and a lower Vuggy zone, a heterogeneous and highly fractured sub-tidal limestone. A more complete reservoir characterization was discussed by Elsayed et al.(1) FIGURE 1: Weyburn unit outline. (Available in full paper) FIGURE 2: Risk analysis is the centerpiece of a risk management process. (Available in full paper) An analogy to the Weyburn field can be drawn from the Midale Unit, situated just east of the Weyburn field. Shell Canada Ltd., the operator of the Unit, implemented a CO2 injection pilot in 1984 which was completed in 1988. Due to encouraging results from the pilot(2), Shell implemented a "CO2 demonstration project, " an eight pattern flood in 1991 which was designed to improve oil recovery from the area and provide technical and economic data to further assess full scale development potential. This flood is still in progress. Input data forming the basis of this assessment incorporated some of the Midale information as well as opinions from internal experts, industry consultants and other analogous CO2 floods in the Permian Basin(3).

Laboratory Investigation of Weyburn CO2 Miscible Flooding

Abstract Weyburn reservoir, located in southeast Saskatchewan and operated by PanCanadian Petroleum Ltd., has reached its economic limit of production by waterflooding. The reservoir is a target for tertiary CO2 miscible flooding to enhance oil recovery and extend its production life. A comprehensive study has been conducted by the Saskatchewan Research Council and PanCanadian to assess the suitability of the process for Weyburn. This paper presents a technical evaluation of CO2 near-miscible injection for Weyburn reservoir. This is based on laboratory studies conducted with three Weyburn oils collected from different regions of the reservoir. These studies included:measurement of minimum miscibility pressure for the reconstituted reservoir fluids for pure and impure CO2,determination of PVT properties for reservoir fluid-CO2 mixtures, andassessment of recovery behavior from uniquely designed laboratory core-flood tests representing the permeability contrast of the reservoir. The studies indicated that the CO2 minimum miscibility pressure for the Weyburn reservoir oils varied from about 11.5 to 14.5 MPa, indicating suitability for CO2 miscible flooding. PVT data generated for the three Weyburn reservoir fluid-CO2 mixtures showed that viscosity reduction and oil swelling by CO2 also contributed to oil recovery. A slight manipulation of the measured PVT properties of the mixtures made it possible to obtain single property curves for the three Weyburn oils. This feature can be used to estimate the PVT behavior for any Weyburn oil from the reservoir. Core-flood studies showed that CO2 injected into the Vuggy zone could rise to the upper Marly zone and help enhance oil recovery. A separate simulation and modelling study conducted by PanCanadian Petroleum Ltd. satisfactorily matched the experimental PVT properties, MMP values and recovery mechanism suggested by the core-flood behaviour. Introduction The total oil reserves of Saskatchewan are estimated at over 3 billion m3 of initial oil-in-place (IOIP). The light and medium oil reserves contribute approximately 1.6 billion m3 IOIP(1). Over 10﹪ of the light and medium reserves, or 178 million m3 IOIP, are held in Weyburn reservoir. The Weyburn field is located approximately 130 km southeast of Regina in Saskatchewan and covers over 180 km2 of production area. The field was discovered in 1955 and PanCanadian Petroleum (PCP) Ltd. is the major operator. It has over 627 producing wells and 162 water injection wells on approximately 24 ha spacing(2). The oil production from the Weyburn field comes from Midale beds of the Mississippian Charles Formation in the Williston Basin at a depth of 1,310 to 1,500 m. The field was produced by primary depletion for about nine years until 1964. Waterflood was started thereafter using a nine-spot pattern. In 1985, to optimize the waterflood performance, both horizontal and vertical infill drilling programs were initiated. The combined oil recovery by primary and secondary production was approximately 28﹪ IOIP by 1994. Waterflooding has almost reached its economic limit for the Weyburn reservoir. The ultimate conventional recovery is expected to be 31﹪ IOIP, leaving a large target for tertiary recovery techniques(3). A similar situation exists for the majority of Saskatchewan's light and medium reservoirs(1,4).

Reduction of Surface Casing Vent Leaks In Viking/Kinsella, Alberta Using Improved Drilling And Cementing Techniques

Abstract Surface casing vent leaks (SCVLs), subsequent to production casing cementation, became a serious concern in the Viking/Kinsella area. The gas sand formations responsible for the SCVLs were relatively shallow, low temperature, and overpressured. Drilling angled wells from pad locations increased the possibilities of SCVLs due to the difficulty in obtaining a good primary cement job. Conventional drilling and cementing practices did not prove effective in reliably preventing environmental liabilities were incurred. PanCanadian Petroleum Ltd. Has implemented a number of drilling and cementing "good practices" to reduce SCVL incidents. The changes in drilling and cementing practices and materials have resulted in a significant reduction in the number and severity of SCVLs. Introduction The main objective of a successful primary cementing operation is the complete displacement of drilling fluids and solids from the drilled hole/casing annulus with a competent cement slurry designed for area specific concerns. Industry research and experience has shown that even a properly designed cement slurry cannot provide an effective hydraulic seal if contaminated with drilling fluids or solids, or if a channel through the cement exists. Drilling practices have an impact on the quality of the wellbore to be cemented, as well. This paper addresses the changes in drilling practices and cement design established to eliminate surface casing vent leaks (SCVLs) at the PanCanadian Viking/Kinsella development project. Background The Viking/Kinsella field is located 20 km northeast of Viking, Alberta, in TWP 47 RGE 9 W4M. PanCanadian's wells in this field historically suffer from poor zonal isolation and high frequency of SCVLs. A SCVL is defined as any measurable flow or pressure build up of gas, water or hydrocarbon liquid on a vent on the surface casing bowl(1). This paper specifically refers to SCVLs from gas sources. The source formations (Figure 1). PanCanadian set a goal to eliminate all SCVLs in an effort to reduce well lifecycle cost in the area. PanCanadian utilizes slant well pad drilling in the Viking/Kinsella area to reduce:Capital costs when compared to directional drillingOperating costs; maintain fewer leases and facilitiesWell production operating costsEnvironmental impact by minimizing surface land requirements A typical well configuration consists of: Equations (available in full paper) The operational issues that were addressed in the drilling and cementing of the slant wells in the Viking/Kinsella are:Complete removal of drilled solids from hole,Optimal casing centralization, andOptimal slurry design Mechanical Considerations Numerous cementing techniques have been considered throughout the industry to combat SVCLs, all with limited success. They include:Applying additional pump pressure from surface to compensate for hydrostatic losses due to slurry gelation,Placing a fast setting cement at surface and "pancake" squeezing a slower setting slurry into the gas zone, orInflating an external casing packer at the surface casing shoe to provide a mechanical barrier to gas flow.

Unlocking Manitoba's Oil And Gas Potential

Abstract In the early 1990s oil and gas exploration and development in Manitoba decreased dramatically. Between 1989 - 1991, only six geophysical programs were run. By the end of 1991 the amount of Crown land under disposition had dropped to 25,800 ha, a 12 year low. In 1992, only 28 wells were drilled in the province. In 1993 Manitoba Energy and Mines recognized that simply providing a stable and competitive fiscal regime was not enough to attract new companies and new investment to Manitoba. A more aggressive approach was need to encourageExploration activity, in particular targeting under-explored pre-Mississippian formationsThe application of new technologies, i.e., horizontal drilling and 3D seismicRecompletions and workovers of existing wells and optimization of existing waterflood projects The culmination of our efforts was the introduction of the Petroleum Exploration Assistance Program (PEAP) in November 1995. PEAP provides assistance to companies exploring for oil and gas in Manitoba. The program provides funding of up to 20% of eligible expenditures to a maximum of $200,000 per company in any fiscal year. PEAP funding has been approved at $1 million a year for three years. PEAP in combination with Manitoba's Drilling Incentive Program (MDIP) and other competitive advantages has resulted in a tremendous increase in oil and gas activity in the province. Crown land under disposition has more than quadrupled to 113,566 ha. Over 1,900 km of seismic was run in 1996, more than in the previous seven years combined. A total of 57 wells were drilled last year of which 28 or 49% were exploratory including 15 pre-Mississippian tests. This paper outlines the initiatives of Manitoba Energy and Mines to attract oil and gas investment to Manitoba and the competitive advantages enjoyed by operators in the province. A brief overview of Manitoba's geology provides a framework for a summary of oil and gas activity in the province. Included is a description of PEAP and MDIP. A comparison of Crown royalty, production tax and petroleum incentives between Manitoba and Saskatchewan is provided to illustrate the attractiveness of investment in Manitoba. Introduction The mission of Manitoba Energy and Mines, Petroleum and Energy Branch is to foster investment in the sustainable development of Manitoba's petroleum resources. The Branch believes there is the potential for substantial ongoing exploration in Manitoba. The Branch also recognizes that there is tremendous competition for capital investment and, to quote David Tuer, President and CEO of PanCanadian Petroleum, "capital knows no borders"(1). The Branch has a four-prong strategy to provide the best business climate in Canada for oil and gas investment:Develop easy to understand workable regulations, policies and proceduresDevelop and disseminate resource informationEnsure Manitoba's petroleum fiscal regime is effective and CompetitiveWork to achieve a high level of awareness of our competitive Advantages The first step in development of workable regulations was completed in 1994 when Manitoba's new Oil and Gas Act was proclaimed.

Weyburn CO2 Miscible Flood Conceptual Design and Risk Assessment

Abstract For the three years leading up to the end of 1995, a multi-disciplinary project team evaluated the business opportunity of injecting carbon dioxide into a portion of the Weyburn Unit to improve recovery. As with any project of this magnitude, a comprehensive analysis of the opportunities and risks in the project had to be clearly defined and evaluated. A risk assessment using a Monte Carlo simulation approach was undertaken to combine the technical with the non-technical issues associated with the project in order to define the full cycle opportunities and risks. The risk assessment process was used to optimize the project configuration, to focus the team on key issues, and to find ways to mitigate the risks inherent in the project. Key uncertainties impacting the range in expected project returns appeared in the areas of commodity prices, reservoir performance, costs and fiscal terms. The risk assessment process and conceptual development plan, incorporating studies and analysis completed up to the end of 1995, is the subject of this paper. Introduction The Weyburn Unit, covering an area approximately 180 km2, is approximately 130 km southeast of Regina, Saskatchewan (Figure 1). The Unit is operated by PanCanadian Petroleum Limited on behalf of the working interest ownership. The field was discovered in 1955 and produced under primary depletion until an inverted nine spot waterflood was implemented in 1964. Production at the end of 1995 averaged 3,150 m3/d of medium-sour crude from 650 oil producers, of which 90 were horizontal wells. At that time, it was postulated that more than 116 ??106m3 of oil was expected to remain in the reservoir after the completion of waterflood operations, or 65% of the original 178 ??106m3 in place. This large remaining oil in place represented a very attractive target for an enhanced recovery process. The Midale beds of the Weyburn field were deposited on a shallow carbonate shelf in the Williston basin. The reservoir is uniformly divided into the upper Marly, a chalky inter-tidal dolostone with limestone interbeds, and a lower Vuggy zone, a heterogeneous and highly fractured subtidal limestone. A more complete reservoir characterization was discussed by Elsayed et al.(1) An analogy to the Weyburn field can be drawn from the Midale Unit, situated just east of the Weyburn field. Shell Canada Ltd., the operator of the Unit, implemented a CO2 injection pilot in 1984 which was completed in 1988. Due to encouraging results from the pilot(2), Shell implemented a " CO2 demonstration project," an eight pattern flood in 1991 which was designed to improve oil recovery from the area and provide technical and economic data to further assess full scale development potential. This flood is still in progress. Input data forming the basis of this assessment incorporated some of the Midale information as well as opinions from internal experts, industry consultants and other analogous CO2 floods in the Permian Basin(3). Traditional Evaluation Process Traditional engineering, design, and estimating methodology sets out a logical step-by-step process which leads through the project life cycle.

Selecting a Rodless Lift System for a Highly Deviated Wellbore

This article is a synopsis of paper SPE 53958, "Selecting the Appropriate Rodless-PC Lift System for a Highly Deviated Wellbore," by R.C. Chachula, SPE, PanCanadian Petroleum Ltd., and J.S. Mann, SPE, Reda Pump Co., originally presented at the 1999 SPE Latin American and Caribbean Petroleum Engineering Conference, Caracas, 21-23 April.

Depth imaging by elastic wavefields—wherePmeetsS

In November 1997 the CREWES Project at the University of Calgary, with assistance from Boyd Petro‐Search Consultants and PanCanadian Petroleum, recorded a unique, high‐resolution 3-C, 2-D seismic survey at the PanCanadian‐owned Blackfoot Field some 50–55 km east of Calgary, Alberta, Canada. The producing formation is a Lower Cretaceous, cemented, glauconitic sand deposited as incised channel‐fill sediment above the Mississippian carbonates. The sandstone is about 1500 m below surface. Its thickness ranges up to 45 m. Average porosity is near 18%. Cumulative production throughout southern Alberta exceeds 200 million bls oil and 400 billion ft3 gas.

An Integrated Approach to Project Management, Wainwright West Project

This article is a synopsis of paper SPE 49064, "An Integrated Approach to Project Management, Wainwright West Project," by Mohamud Zaver, SPE, PanCanadian Petroleum Ltd., prepared for the 1998 SPE Annual Technical Conference and Exhibition, New Orleans, 27-30 September.

Desanding System for Downhole Oil/Water Separation: Field Trial

This article is a synopsis of paper SPE 49053, "Field Trial of the First Desanding System for Downhole Oil/Water Separation in a Heavy-Oil Application," by T.L. Danyluk, SPE, and R.C. Chachula, SPE, PanCanadian Petroleum Ltd., and S.C. Solanki, SPE, C-FER Technologies Inc., originally prepared for the 1998 SPE Annual Technical Conference and Exhibition, New Orleans, 27-30 September.

Dolomitization and Neomorphism of Mississippian (Visean) Upper Debolt Formation, Blueberry Field, Northeastern British Columbia: Geologic, Petrologic,  and Chemical Evidence

Petrographic, chemical, and isotopic studies of the Mississippian (Visean) upper Debolt Formation in the Blueberry field, British Columbia, Canada, reveal that dolomitization was the result of several diagenetic events and that neomorphic alteration of these dolomites significantly modified their original chemical signatures. These studies also demonstrate how tectonics play an important role in controlling and modifying reservoir dolomites in the area. Petrographic investigations have documented two early dolomite phases, (1) early matrix dolomite and (2) pervasive dolomite, and two later generations, (3) coarse cement and (4) pseudomorphic replacement of crinoids. Early matrix dolomite occurs as small (average 25 µm) subhedral to euhedral crystals that replace the matrix of carbonate mudstones, wackestones, and packstones. Petrographic evidence suggests that early matrix dolomite had a relatively early, precompaction origin, possibly from marine fluids. However, geochemical evidence indicates that later fluids have altered their original geochemical signatures. ©Copyright 1997. The American Association of Petroleum Geologists. All rights reserved.1Manuscript received February 1, 1996; revised manuscript received August 16, 1996; final acceptance January 19, 1997. 2Department of Earth Sciences, University of Windsor, Windsor, Ontario, Canada N9B 3P4. Present address: Chauvco Resources, Ltd., 2900, 255-5th Avenue S.W., Calgary, Alberta T2P 3G6 Canada. 3Department of Earth Sciences, University of Windsor, Windsor, Ontario, Canada N9B 3P4. This research was supported by individual operating grants from Canada's Natural Sciences and Engineering Research Council (NSERC) awarded to I. S. Al-Aasm and additional funding from PanCanadian Petroleum Resources Limited, and Suncor Inc. S. Durocher acknowledges support from an Ontario Graduate Scholarship. S. Brame (Talisman Energy), L. Williams (Phillips Petroleum Resources, Ltd.), G. Burrowes and I. Mcllreath (PanCanadian Petroleum Ltd.), and J. Packard (Rhomb Carbonate Consulting Ltd.) are thanked for the valuable information, insights, and ideas for tackling the complexities of the Blueberry field. Thanks are also due to J. Veizer (University of Bochum and University of Ottawa) for strontium isotope analysis. An earlier version of this paper benefited from critical reviews by M. Malone (Texas A&M University), C. Viau (Shell Canada, Ltd), S. Schutter, J. Dravis (Dravis Interest Inc.), and an anonymous reviewer.

Continuous Improvement: A "Win ... Win" Process

Abstract Implementing a Continuous Improvement (CI) process within PanCanadian's oil and gas production operations might have been a simple assignment if one were not also trying to caprure the hearts and imaginations of the people in a changing work environment. Meeting the challenge is resulting in big payoffs to both the organization and its people. This paper discusses the plan used within the Company's Production Division to successfully introduce the CI process. A brief insight is provided on the process philosophy, with emphasis placed on the planning, training and coaching used to launchhe process. Also reviewed at length are the impediments to change and the challenges faced when changing ::m organization's culture. In a CI work environment, the supervisor's traditional role changes from one of monitoring and controlling [0 one of inspiring motivating and leading people by communicating a clear vision_ Employees at all levels in the work environment are organized into teams and armed with a good working knowledge of the problem-solving tools which allow them to pursue and implement improvement initiatives. The outcome of the process is an ongoing "win ... win" situation for both the Company and its people. Employees are gainingore trust, eliminating job irritants and enjoying their work more in a team environment. The Company is winning through increased production improved safety and reduced operating expenses, thanks to the many innovative ideas which the employees have implemented. Introduction In a rapidly changing business climate, Darwin's theory of survival holds equally true for corporations. It's not necessarily the big and strong who will ultimately survive but those who adapt the fastest to changing conditions. With long-term survival acting as a catalyst. PanCanadian Petroleum Limited. In the spring of 1990 embarked on changing its culture. The Company wanted to become less rigid by breaking down its structure and empowering mployees to react quickly to potential business opportunities. To achieve the transformation. TeamPro Services Ltd., an Alberta company specializing in CI implementations, was hired to assist PanCanadian line management in developing a new operating philosophy and implementation plan. The initial mandate was to involve the entire Production Division. There are a total of 480 employees within the Production Division, of which 405 are located in five field production districts. A resident Production Superintendent Supervises each district and reports to one of three Production Managers in Calgary. The majority of the production accounting work is done in the head office, which also provides most of the engineering support for the field operations. However, there are two or more engineers in each district reporting to Calgary-based Engineering Supervisors. The CI process which was launched in June 1990, has had a significant impact on how the Company does its business. The intent of this paper is to briefly describe the CI concepts and philosophy adopted by the Production Division, followed by a major discussion of the implementation plan with highlights of what worked well and what could be improved in similar situations.

Experience With Fireflooding In Countess 'B' Pool, Alberta Reservoir Aspects

Abstract This paper discusses the reservoir aspects of the Countess ‘B’ Fireflood Pilot Project in southeastern Alberta. The Countess 'B J Pool is a Glauconitic channel sandstone and has been under waterflood since 1973. The fireflood pilot was initiated in 1983 and the operation is expected to continue until 1991. This 16 ha inverted five-spot includes one injector and four producers. The pilot was designed to determine the level of incremental recovery that could be achieved from the process application and to obtain operating experience from a reservoir containing 28 ° API oil. An extensive program of well testing and fluid analysis has been conducted to identify and evaluate the pilot performance. The Countess ‘B’ Fireflood Pilot has broken new ground in a number of ways. Results suggest that a waterflooded light oil reservoir can be fireflooded successfully. A mineralogical examination of a post-combustion core indicates that firefront temperature in this pool is 300 °C to 400 °C and oil is effectively displaced. To the end of 1988, the cumulative burned volume represented 20% of the pilot volume. To date the pilot has achieved most of its objectives and will likely achieve the remaining objectives prior to its termination in 1991. Introduction The Countess Upper Mannville ‘B’ Pool is located in Township 19, Range 16W4M, approximately 20 km west of the town of Brooks. Alberta (Fig. I). This pool is part of the Countess Latham trend and was discovered in 1965. The pool is operated by PanCanadian Petroleum Limited and jointly owned (50%) with LL&E Canada Ltd. The pool is currently in the later stages of waterflood. Extensive engineering and laboratory studies conducted on the Countess ‘B’ Pool during the period 1978–80 concluded that fireflooding application is feasible. A pilot project commenced in January 1983 in Part II of the Countess ‘B’ Pool to evaluate the fireflood process and is expected to continue until 1991. Reservoir In the Countess ‘B’ Pool, oil production is from a series of southeast/northwest trending channel sands. These sands are elongate and narrow with a length of up to 5 km and a width ranging from 300 m to 1500 m. Thickness varies from 1 m to 12 m. Based on lithology and stratigraphic position, the sandstones of the Countess ‘B’ Pool are part of the "'Glauconitic" of the Upper Mannville Group. Part II of the Countess "B' Pool, as shown in Figure 2, is the largest of these sands. Following are the average reservoir properties of Pan II:depth 1080mgross pay thickness 8 mporosity 25%permeability 800 mDinitial oil saturation78%initial reservoir pressure 9.6 MPareservoir temperature 38 °Coil gravity28 °C APIoil Viscosity @ reservoir conditions 6 cpinitial formation volume factor 1.124 The Glauconitic sandstones of the Countess ‘B’ Pool are generally fine- to medium-grained, moderately well sorted and composed of quartz and chert with minor feldspar and decrial clay. Cementation is mainly by authigenic clays, including kaolinite and to a lesser degree illite.

Application Of Fluid Analyses To The Operation Of An In Situ Combustion Pilot

Abstract This paper reports the interpretation of the results from an extensive field fluids monitoring program which supported the operation of the Petro-Canada/ AOSTRA heavy oil in situ combustion pilot at Kinsella, Alberta. Produced gas analyses are discussed in terms of confirmation of reservoir ignition, monitoring the progress and efficiency of the burn, safety considerations and the extent of air propagation in the reservoir. Fireflood indicators in the produced water indicated the proximity of the/ire with respect to individual wells, as well as providing insights into the chemical processes occurring during combustion. Changes in oil composition indicated which wells were most influenced by low temperature oxidation, distillation and thermal cracking of the oil. An over-all assessment of the data, in conjunction with operational parameters, demonstrated that fireflood indicators in the produced fluids can be used over the entire pilot operation to monitor the advance of the fire/rant and to estimate the location of the fire with respect to production wells. Introduction Steam-based thermal recovery strategies have found widespread application. However, some shallow reservoirs with a thin net pay zone and containing viscous oil are currently best exploited using an in situ combustion process. Operators such as Pan Canadian Petroleum(1). Amoco(2). Husky (3), General American Oils(4), and Petro-Canada(5) have reported on the complexities of operating fireflood projects in Alberta. The Kinsella Heavy Oil In Situ Combustion Project (KHOPD) was a joint venture between Petro-Canada Resources and the Alberta Oil Sands Technology and Research Authority (AOSTRA). The pilot site was located approximately ZOO kmsoutheast of Edmonton, Alberta (Fig. I). The air pattern originallyonsisted of four air injection wells (BI-I, BI-2. BI-3 and I-4), five production wells (BP-1, BP-2, BP-3, BP-4 and BP-5) and three observation wells (BO-I, BO-2 and BO-3). The air attern was subsequently modified with the addition of three production wells (BP-6, BP-7 and BP-8) and two observation wells (BO-4 and BO-5). The four wells BP-I, BP-6, BP-7 and BP-8 essentially yielded an inverted five-spot around the air injector BI-4 (Fig. 2). The produced fluid compositions from three additional wells (AP-2, AP-4 and AP-5), located some distance from the air pattern (Fig. 2), were also monitored. Dry combustion was carried out at KHOP-D for approximately two years. The wet combustion phase commenced in August 1983 with intermittent water injection into BI-4 for the purpose of scavenging heat from the burned zone and transmitting this heat(in the form of steam) to the oil bank in front of the combustion zone. To assist with the operation of this pilot, in understanding the reservoir behaviour and in the design of subsequent projects, an extensive fluids analysis program was establishedto monitor the composition of the produced fluids. Regular sampling and analysis of produced gas, oil and water from as many as eleven production wells continued for approximately 3 and a half years. Gas and water samples were generally analyzed on a weekly basis, while oil samples were analyzed twice per month. Indications that the firefront was approaching a particular well often necessitated more frequent analysis.

An Early Proterozoic VGP From an Oriented Drillcore Into the Precambrian Basement of Southern Alberta

SUMMARY We report paleomagnetic results for 25 samples from a fully-oriented PanCanadian Petroleum drillcore which penetrated the Precambrian basement of southern Alberta at a depth of 2550 m. Samples were taken at approximately 1 m intervals over a 7 m section of core. Intensities of natural remanent magnetization (NRM) were 0.5-14 A m-' over the section, which consists mainly of granodiorite, with one short granite interval. X-ray and Curie temperature data indicated magnetite as the only important NRM carrier. Most of the NRM was an intense, steeply-inclined drilling remanence, with coercivities <20 mT and distributed low-to-intermediate unblocking temperatures. After magnetic cleaning, a weak but stable primary NRM with high coercivities and high unblocking temperatures was isolated, with D = 157, I = +52 (k = 118, mg5 = 3, N = 20). The corresponding virtual geomagnetic pole (VGP) is 4S, 93W (dp = 3, dm = 4), which falls on the North American apparent polar wander path around 1850 Ma. The basement of this part of Alberta is probably an extension of the Churchill Structural Province of the Laurentian Shield.

Optimized Drilling Through Use Of Downnhole Motors

Abstract It has been established that rate of penetration (ROP) is directly related to rotational speed (RPM) of the drill bit in most formations. The Wembley area of northwest Alberta shows a proportionate increase in drilling rate with increases in rotary speed. Pan Canadian Petroleum Ltd. (PCP) optimized bit RPM by supplementing the rig's rotary capability with downhole motors. This paper will summarize the results of using downhole motors to Increase penetration rates in the Wembley field and will provide the drilling plan which PanCanadian uses to optimize vertical drilling with downhole motors. Introduction The relationship for soft and medium soft formations, between rate of penetration and rotational speed has been established as(1): (1) R = KWN a where: R = Rate of penetration K = Lithology factor N = Rotary speed W = Weight on bit a = exponent (equal to 1 for Wembley) For Wembley area this equation may be reduced to: (2) R = constant ( N ) Although the constant includes the bit weight, which is a variable, by drill off tests and manufacturer's recommendations bit weight has been optimized at a relatively constant value between 18 000 and 20 000 daN. Equation (2) suggests the rate of penetration can be enhanced through rotary speed increases. Factors which place an upper limit on rotary speed include:Drill string limitations.Drilling rig limitations on rotary speed.Drill bit limitations.Mechanical hole erosion.Casing wear. Drill string limitations include resonant vibration, joint strength, wear due to erosion and cyclic bending fatigue. Contractors limit rotary speed to 150 RPM or less and will not warrant the operational integrity of the string at higher rotary speeds. An excellent reference paper has been prepared by D. Dareing of Maurer Engineering Inc. (Ref. SPE 11228). Therefore most conventional drilling rigs are limited to rotary speeds of 150 RPM. Chain drive rotary tables are in common use and are usually coupled from the drawworks power take-off directly to the rotary drive pinion. Due to substructure space limitations it is not often possible to include a transmission on the rotary table. Chain sprockets also tend to be fixed by rotary torque requirements and chain speed limits. Torque tubes and electric drive rotaries have added flexibility to available RPM but these systems are not always available. Retrofit on existing rigs cannot be economically justified unless a long-term rig commitment is possible. Drill bit manufacturer's suggest RPM limits for their products but recent developments in premium sealed bearings have allowed greater flexibility. Also, insert bits have been improved in the bonding of carbide teeth to the cone matrix, allowing higher rotary speeds. Casing wear is a concern to all operators and, in some cases, optimum drilling performance has been sacrificed to limit wear. Non-rotating stabilizers have been used successfully but, again, stabilizer wear increases substantially when the drill string is rotated above 100 RPM.

1985 CSEG/CGU National Convention

The Canadian Society of Exploration Geophysicists (CSEG) and the Canadian Geophysical Union (CGU) held their first joint national meeting in Calgary, Canada, May 7–10, 1985. As the CSEG represents primarily the oil exploration side of geophysics and the CGU represents mainly the academic side, both groups felt that a joint convention would broaden their perspectives. Some 1750 delegates and over 100 students registered for the meeting. The Convention Committee was chaired by Ian Baker (Atlantis Resources Ltd.), and CGU was represented by Peter Savage (Pan Canadian Petroleum Ltd.). The Technical Committee was chaired by John Peirce (Petro‐Canada Inc.) for CGU and Graham Millington (Canadian Superior Oil Ltd.) for CSEG

Application Of Foam Cements In Alberta

Abstract The demand for light-weight cement in areas of low-strength formations has led to the increased use of foamed cement in PanCanadian's wells. Foamed cementing involves mixing surfactant upstream of the cement pumper and injecting nitrogen into the pumper discharge line, with a foam generator installed downstream. The "constant foam density method" was used. It involves increasing uniformly the nitrogen/cement ratio, to establish a constant slurry density of the cement column. In most wells cemented to surface a nitrogen-free cap of 100 m to 200 m of lead cement was maintained above the foam, to prevent nitrogen from breaking out to surface. Although exhibiting relatively high strengths and reasonably low permeabilities, the foamed cement was used only as a filler cement. All the zones of interest were covered by a pad of neat tail-in cement. Recent field tests by PanCanadian confirmed that foamed cementing is only slightly more expensive than conventional cement jobs but less costly and involving less mechanical risk than multi-stage jobs. At the same time, it can be considerably less expensive than glass or ceramic microspheres cementing. Introduction During the last year, PanCanadian Petroleum used foamed cement slurries in primary cementing on a total of 11 wells (Fig. 1) located in areas where traditionally two-stage jobs were used: southeast Alberta, Grande Prairie and Lindbergh. Conventional filler cements which meet compressive strength regulations, as pozzolan-cement, gel-cement and pozzolan-cement- gel, are often too dense for the weaker formations, resulting in lost circulation while cementing. The use of lightweight fillers (perlite, gilsonite) or of water extending additives which allow increased water ratios (bentonite, diatomaceous earth, silicate extenders, etc.) give little strength satisfaction at slurry densities below 1 400 kg/m). In the province of Alberta, ERCB Regulations for cement fillers require a compressive strength of at least 3 500 kPa after curing for 48 hours at the temperature of the uppermost potential hydrocarbon-bearing zone. Other effective methods of overcoming cement problems in wells having low fracture gradient formations are multi-stage cementing, or the addition of high-strength microspheres (HSMS). The first method involves some mechanical risks related to the actuation of the stage tool. The use of HSMS is simple and secure, but considerably more expensive. PanCanadian's foam cementing field tests included a wide depth range (from 615 m KB in Lindbergh to 2 238 m KB in Wembley) as well as individualized slurry design and operational procedures. Operationally, it has been found that foam cementing is relatively straightforward and can be done with standard equipment and no special personnel. When properly designed and conducted, if the planned foamed slurry downhole densities are not lower than 1 000 kg/m3, a foamed cement operation can be as effective and successful as any other conventional cementing job. The foam quality and stability are very sensitive to even some small changes (in the field) of slurry parameters and/or in operational procedures. During the cement operation neat (unfoamed) cement slurry density being warranted, the proper and continuous monitoring of cement slurry pump rate, nitrogen delivery rate, and surfactant/foam stabilizer injection rate, is crucial for a successful job.

A Preliminary Numerical Simulation Study of In-situ Combustion In a Cold Lake Oil Sands Reservoir

Introduction The thermal models of the Computer Modelling Group were used in a preliminary study of the behaviour of in-situ combustion fallowing steam stimulation in a Cold Lake oil sand reservoir. The study was performed in order to enhance operations of the BP/Partners Marguerite Lake Phase A Project. Chemical reaction parameters for the simulations were obtained by matching laboratory combustion tube experiments. History matching of field steam stimulation data was not performed in this study but rather temperature and fluid saturation distributions following steam stimulation were estimated using analytical techniques. One- and two-dimensional, cross-sectional simulations were carried out to study the effects of the amount of initial reservoir preheating and the vertical reservoir permeability distribution on ignition and maintenance of combustion. Both dry and wet forward combustion runs were performed. It was found that the size of the cold zone between wells following steam stimulation has a significant effect on the performance of combustion drive, as does the existence of a high-permeability zone in the reservoir. Expected oil production" rates, air-oil ratios. etc., are presented for this process. Introduction BP Exploration Canada Limited is currently operating a pilot project in the Cold Lake oil sands to investigate the recovery of bitumen using a sequential steam-stimulation and in-situ combustion drive process. The Marguerite Lake Project, Phase A, is located as shown in Figure 1. The project is funded by BP Exploration Canada Limited and its partners: the Alberta Oil Sands Technology and Research Authority (AOSTRA), Hudson"s Bay Oil and Gas Company Limited and Pan Canadian Petroleum Limited. In-situ combustion experiments began at the Phase A site in November 1979 following sixteen months of steam stimulation operations. (In this project, it was necessary to fracture the formation in order to obtain adequate injectivity.) A number of one- and two-dimensional numerical simulations were performed to investigate ignition and maintenance of combustion in the reservoir following steam stimulation. It was also desired to obtain estimates of air injectivities, combustion temperatures, production rates, oil recoveries and heat breakthrough times at the producing wells. Steam stimulation data from the Phase A project have not been history matched and many of the required input parameters for the model have been estimated rather than measured. For these reasons, the results of the study should be considered as qualitative only. Model Input Data Appendix A contains a listing of some of the physical property data input to the model. Much of the data were obtained from an earlier study conducted by Finbow and Koop (Ref. 1), Laboratory combustion tube data were history matched using CMG"s one-dimensional in-situ combustion tube simulator COMB, described in Reference 2. One dry and one wet forward combustion tube experiment were matched. Figure 2 shows an example of temperature profile matching at a time close to the end of the wet combustion tube run. The history-matching parameters employed for the combustion tube experiment simulations were the kinetic parameters of cracking and high-temperature burning reactions and the phase equilibrium constants.