Shell Canada Research Articles

ZCL signs deal with Shell Canada

ZCL signs deal with Shell Canada

Gas field planning tool

AbstractGas Field Planning Tool (GFPT) was developed in 1990 by the Shell Group of Companies to fill the need for a tool for gas field planning and development using deterministic subsurface and surface models. Main initiators were Shell Canada, NAM (the Netherlands), Shell Expro (UK) and BSP (Shell Brunei), as these companies are major gas producers.Shell Companies now have several years experience with using the GFPT. Application ranges from simple single field models to corporate-level models with a large number of gas reservoirs and wells. Shell companies now using GFPT models are Shell Expro (UK), BSP (Brunei), SSB (Malaysia), Shell Canada, SPDC (Nigeria), SDA (Australia), Woodside (Australia), PDO (Oman), NAM (the Netherlands), New Business Development (e.g. Lunar Project) and in future also Shell Egypt.NAM currently has a GFPT model for the Anjum field in Friesland and for the Ten Arlo field in the north of Holland.GFPT is currently being migrated to an HFPT (Hydrocarbon Field Planning Tool), which can also be used for planning of condensate, oil and water developments and for control of hydrocarbon compositions in the network using PVT de-lumping at the well head (e.g. for LNG plants) and optimisation techniques (linear, non-linear or based on bean-back lists).

A Laboratory Study on Near-Miscible CO2 Injection in Steelman Reservoir

Abstract Miscible flooding is considered unsuitable for some reservoirs in southeast Saskatchewan because of high C)2 minimum miscibility pressure or operating pressure constraints. Therefore, the effectiveness of near-miscible C)2 injection was assessed for the Steelman reservoir in a laboratory study. The minimum miscibility pressures (MMP) were estimated for Steelman reservoir fluids with pure C)2 and C)2-hydrocarbon gas mixtures, the partially flashed reservoir fluids and the dead oils with pure C)2. The results of MMP studies demonstrated (1) addition of ethane or propane can reduce C)2 MMP greatly; and (2) achieving a miscible C)2 flood in the Steelman reservoir could be possible at a lower operating pressure than the measured C)2 MMP, by partially depleting the reservoir. Asphaltene flocculation tests showed that, after the onset point, flocculation increased linearly with gas concentration, but that the presence of brine had a negligible effect. Three tertiary C)2 coreflood tests were conducted with Steelman reservoir fluids at the reservoir temperature. These results showed that the microscopic displacement efficiency during the C)2 injection stage improved with the operating pressure in the near-miscible region, but no dramatic change in oil recovery was observed with a change in operating pressure. Introduction The Steelman pool, located about 200 km southeast of Regina, Saskatchewan, was discovered in 1954. Covering approximately 370 km2, the field was estimated to contain over 134 million m3 of light oil in the Frobisher and Midale beds located at a depth of about 1,400 m. Most of the reservoirs in the Midale beds, which contain about 83﹪ of the reserves of the pool, have been under waterflood for over 20 years and have nearly reached the estimated production limit by primary and waterflood(1). For achieving additional oil recovery and consequent financial benefits, the development of tertiary enhanced oil recovery (EOR) techniques, such as C)2 flooding, is essential. Miscible C)2 flooding is a proven enhanced oil recovery technique(2). Over the last decade, C)2 injection has become the leading EOR process for light oil(3). In Canada, the industry interest in C)2 flooding is evidenced by Shell Canada's C)2 pilot tests(4, 5), a miscible C)2 flood at Joffre field in Alberta(6), and the implementation of PanCanadian's Weyburn C)2 injection project(7). Additional field applications are expected to be initiated in southeast Saskatchewan and other regions when C)2 sources are available. Miscible C)2 displacement offers the greatest oil recovery potential, but it can only be achieved at a pressure greater than a certain minimum referred to as the minimum miscibility pressure (MMP). The effect of solution gas on the development of miscibility is not well understood, as is reflected by the lack of a consensus in the literature. Rathmell et al.(8) found that C)2 MMP is related to the volatile and intermediate fractions of the oil. Yelling and Metcalfe(9) found from their experimental study that, for a saturated reservoir oil, areal variation in gas-oil ratio (GOR) will result in an areal variation in the C)2 MMP. They pointed out that the C)2 MMP determined for a pilot area may not apply to the rest of the field.

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).

Asphaltene Deposition in Electrical-Submersible-Pump Applications

This article is a synopsis of paper SPE 56662, "Asphaltene-Deposition Problems in the Oil Industry With Focus on Electrical-Submersible-Pump Applications," W. A. Limanowka, SPE, Centrilift, Baker Hughes Canada Co., M.J. Voytechek, SPE, Shell Canada Ltd., and Renata E. Limanowka, Northern Alberta Inst. of Technology, originally presented at the 1999 SPE Annual Technical Conference and Exhibition, Houston, 3-6 October.

Stimulation of Horizontal Wells In Shell Canada Limited

Abstract The design and results of stimulation treatments in Shell Canada's horizontal wells to 1993 are discussed. Shell Canada's experience with horizontal wells started in 1988 with three wells drilled in the Midale Field, Saskatchewan. Application of horizontal technology grew and over 20 new horizontal wells or reentries were drilled in Shell's oil and gas fields during 1993. Horizontal drilling continued to be a major part of the subsurface capital program in subsequent years. The stimulation techniques used on the carbonate reservoirs of those horizontals varied dependent on well type, field characteristics and economics. The first horizontal well at Midale was cased, selectively perforated, and acidized. Most subsequent horizontal wells were, however, completed openhole. Shortcomings in the stimulation technology and efforts undertaken to improve stimulation results are discussed. Introduction Effective stimulation of horizontal wells presented some new challenges. The main challenges were:Identification of the hydrocarbon bearing and potentially productive intervals along the horizontal wellbore;Effective placement and diversion of acid to ensure the treatment of all productive intervals along the horizontal wellbore;Identification of the nature and magnitude of the damage to be removed. Shell Canada made extensive use of coiled tubing to stimulate its horizontal wells. This was due to coiled tubing's (CT) proven ability to be run to the end of the horizontal section and withdrawn while pumping/jetting acid and other treatment fluids across the zones of interest. Economides(1) had provided guidelines on acid treatment volumes per unit length of horizontal section, pump rates and withdrawal rates for CT to ensure effective treatment across the horizontal sections. Because of the difficulties experienced in removing damage from some horizontal wells using acids and the increased water production that was sometimes experienced, underbalanced drilling was identified as a means to minimize drilling damage(2). Underbalanced drilling was subsequently employed in Midale and Harmattan East. Whilst underbalanced drilling did provide benefits in certain settings, the incremental cost to drill underbalanced vs. effective stimulation later to remove damage was an important consideration. Stimulation of Midale Horizontal Wells Horizontal wells in the Midale oil field, located in SE Saskatchewan, presented unique challenges in stimulation design. This was due to the binary nature of the reservoir geology and to the maturity of the waterflood. The Midale formation from which hydrocarbons are produced is composed of a dolostone, commonly called the Marly, overlying a limestone, called the Vuggy. Imprinted on this geology is a fracture network trending southwest- northeast. Because of the higher porosity and more plastic nature of the dolostone, the Marly tends to be less fractured than the underlying Vuggy. While it might be anticipated that this fracture network would provide extensive communication between Marly and Vuggy, thin and laterally extensive barriers of tight limestone exist through out the field. The foregoing geologic factors greatly influenced the waterflood response of the Midale Unit. The field was developed on an 80-acre inverted 9-spot pattern, with a variety of infill wells for accelerated production.

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.

UTF Project Status Update, May 1997

Abstract The Underground Test Facility (UTF) is producing from three tunnel drilled 500 m long horizontal well pairs which have produced effectively at their peak rates and reached recoveries of almost 55% OOIP. Two new pairs of 750 m and 300 m horizontal wells have been drilled from the surface and were started up in April 1996. Start-up performance and well control methods have been successful. Another 750 m horizontal well pair is to be drilled from surface in the spring of 1997 and started up in the fall of 1997. Its purpose is to test methods of operating a well pair next to a depleted reservoir without losing steam to it. Net revenue from the UTF Project has funded the costs of adding three surface well pairs and related plant facilities since September 1994. The UTF Project is owned by AOSTRA with nine industry participants, including Gibson Petroleum Company Limited who was appointed Project Operator in October 1995. Introduction This is the third in a series of papers presenting the development status of the Steam Assisted Gravity Drainage (SAGD) process at the Underground Test Facility (UTF) situated 70 km northwest of Fort McMurray, Alberta (Figure 1.1). The first paper(1), presented in 1991, covered the initiation of the UTF Project from 1984 to May 1991. It discussed the rationale for starting the UTF, the basic SAGD process, the facilities (shaft, tunnels, underground drill rig, Phase B plant), the results of the three Phase A well pairs, and the drilling and design of the three Phase B well pairs which had not yet started up. The second Paper(2) reviewed the start-up and performance of the three Phase B well pairs and facilities which had produced 500,000 barrels of bitumen at that time, May, 1994. It also discussed the economics of a potential 30,000 bpd commercial SAGD recovery project. The current paper looks at the continuing performance of the Phase B wells and facilities which have produced over 2,400,000 barrels of bitumen; the design and April 1996 start-up of two pairs of SAGD wells drilled from the surface (Phase D) which have produced over 170,000 barrels of bitumen; the design of a third surface well pair to be drilled in the spring of 1997 to test the methods of placing and operating a new well pair next to a depleted reservoir without adverse effects; the features of a produced water recycle plant scheduled for start-up in the fall of 1997; and concludes with a brief discussion of some commercial aspects related to the economics of the SAGD process at the UTF and the marketing of bitumen. The UTF Project is currently owned by the Alberta Oil Sands Technology and Research Authority (AOSTRA) and funded jointly by AOSTRA (25%) and nine industry participants (8 113% each). In addition to Gibson, the industry participants are: Amoco Canada Petroleum Company Limited, Chevron Canada Resources Limited, China National Petroleum Co. (Canada) Ltd., Imperial Oil Resources, Japex Oil Sands Limited, Petro-Canada, Shell Canada Limited, and Suncor Inc.

Long-Stroke Pumping System for Multilateral Thermal Wells

This article is a synopsis of paper SPE 54115, "Long-Stroke Pumping System at Shell Canada's Peace River Multilateral Thermal Wells," by Mirko J. Zatka, Shell Canada Ltd., originally presented at the 1999 SPE International Thermal Operations and Heavy Oil Symposium, Bakersfield, California, 17-19 March.

Production Casing Performance In a Thermal Field

Abstract High temperature steaming of wells can cause plastic yielding of the production casing. However, when properly designed and installed these casing strings will last the full life of a thermal project. Inferior designs or installations can cause significant well problems ranging from wellhead growth and settling to buckled or parted casing. Since 1979, Shell Canada limited has been operating a thermal project in the Peace River/Cadotte Lake area. Steam injection temperatures have been as high as 335 ° C, but only two of the 286 steamed wells have incurred thermal induced casing failures. Three additional casing failures were caused by corrosion. Some 10 to 15 other wells have experienced wellhead settling (casing contraction). Several wellheads have gone down 25 to 50 cm, requiring wellhead and piping modifications but casing integrity has been maintained. This paper discusses the casing and cement designs used historically, field observations and explanations for the casing "shrinking" phenomena and the field testing of K-55 grade casing. Shell Canada Limited's current design utilizes K-55 premium connection casing with class G thermal 1,880 kg/m3 and 1,400 kg/m3 weight cements. Introduction Shell Canada Limited has operated a steam injection project at Peace River since 1979. The production zone is an unconsolidated sandstone of the Lower Cretaceous Gething formation. This bitumen reservoir is 550 m from surface with an average pay thickness of 25 m. The bitumen gravity is 8 - 10 ° API with a viscosity at reservoir conditions of 200 Pa.s. The bitumen saturation decreases with depth in the zone. At bitumen saturations below 65%, the water phase is mobile and allows steam injection below fracture pressures. Most, but not all the wells drilled have a mobile bottom water layer. The primary recovery process has been a pattern steam drive. Dedicated injection wells were utilized, however all wells were initially steamed and produced to establish bitumen mobility and communication between wells. In 1993, four horizontal wells were drilled to evaluate the Enhanced Steam Assisted Gravity Drainage Process (ESAGD). Since then, 25 horizontal wells have been drilled for ESAGD or cyclic steaming bitumen recovery. All of these wells have used K-55 casing with premium connections. Casing designs have varied from NM-80 LT&C, L-80 VAM, L-80 OBTC (oversize buttress threaded and coupled), and most recently K-55 NS-CC premium connection. Between 1979 and 1997, there were five casing failures at the Peace River complex. One was a buckled casing string, another was a parted connection and the remaining three were due to corrosion. Ten to 15 wells have had casing "contraction," causing the wellhead to settle 10 to 50 cm. The casing/wellhead movement is not a failure but can impose additional operating expenses and difficulty. In general, the casing performance has been satisfactory, as the above failures can be explained and continued reliability from the existing casing strings is anticipated. Casing Design An understanding of the stresses imposed on the casing during thermal operations is needed to properly design the casing and evaluate its performance.

Emerging Technologies For SAGD Drilling And Production

Abstract SAGD, as originally conceived, consists of two parallel horizontal wells, one drilled directly above the other. Steam is injected into the upper well, forming a steam chamber. The heavy oil or bitumen is heated, reducing its viscosity, then drains by gravity, along with the condensed steam, to the lower well. Several other variants exist, including vertical injectors, and single well SAGD. Conventional, aggressive, heavy oil production methods have been labeled "poor reservoir management." In general, 80% of the reservoir energy is expended to produce 20% of the oil in the reservoir. "80/20 Rule"(1). SAGD stands out as an enticing and economically viable development method for operators holding heavy oil and tar sand properties worldwide, even in the current climate of lower heavy oil prices. Recoveries of 55 to 80% OOIP are possible, compared with 5 to 15% for conventional recovery methods, and 18 to 30% for enhanced thermal recovery methods. SAGD production rates of 200 to 1,400 bbl/day have been recorded compared with 0 to 100 bbl/day for non-thermal recovery in the same fields. Both factors combine to achieve production cost reductions of 30% or more. Drilling and completion costs generally run around 20% of the total cost of the project. "SAGD is very, very profitable when applied in the right reservoir." The challenge for SAGD technology lies in finding the right reservoir. This challenge holds true whether SAGD technology is applied to undeveloped areas of the reservoir, or when SAGD is used to clean out oil left behind by less efficient recovery processes. SAGD History 1978 - Imperial Oil drilled the first Hz SAGD well in Canada at Cold Lake. 1987 - AOSTRA lead the way in proving out the concept of twin well SAGD by drilling three 50 m SAGD pairs from a horizontal mine tunnel at the UTF site near Fort McMurray. 1993 - Surface drilled SAGD well pairs. Two well pairs were drilled for Shell Canada at Peace River, and one for Amoco at Wolf Lake. 1995 - First commercial scale SAGD project. CS, now Pan Canadian Resources, drilled and completed three well pairs at Senlac, Saskatchewan. 1998 - Sperry Sun Drilling Services has successfully drilled 44 SAGD well pairs worldwide to date. Technological Advances With conventional SAGD, large quantities of steam are required for production. By injecting approximately 1% of a noncondensable gas, along with the steam, steam requirements are drastically reduced.Laboratory experiments indicate a reduction in steam requirements on the order of 25% (2). An industry funded research project is currently underway involving eight companies and GravDrain Inc. Drilling and Production Issues With cold production of heavy oil, 1,000 m horizontal sections are common and multilateral wells with up to 8,000 m of horizontal section exist. However, with SAGD, horizontal lengths of more than 500 m have proven difficult to manage for two reasons. If product lifting cannot keep up with production, SAGD efficiencies are drastically reduced because hot water, being less viscous than oil, is produced preferentially. Second, establishing a uniform steam chamber in pairs longer than 500 m has proven difficult.

A Modern Example of Short-Cycle-Time Development

This article is a synopsis of paper SPE 38824, "Simonette Beaverhill Lake A&B Pools: A Modern Example of Short-Cycle-Time Development," by T.J. Moynihan, SPE, Chevron Canada Resources; J.C. Fryters, Chevron Petroleum Technology Co.; and P. Chernik, SPE, Shell Canada Ltd., originally presented at the 1997 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 5-8 October.

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.

Data Model for Drilling Information and its Application

As computing technology has evolved, so have the demands placed by the user community on the functions it provides. The expectations of software used in drilling operations are changing from a convenient way of producing the daily drilling report, to acquiring drilling data for use in engineering analysis programs. This data is expected to provide insight into an increasing array of complicated engineering operations questions. There are a number of commercial morning reporting systems in use throughout the industry. However, after collecting many years worth of drilling data, the engineer is finding that their morning reporting system cannot easily provide the answers to some very basic questions. Many providers of drilling information systems have built their applications founded on daily wellsite operations, using the latest Graphical User Interfaces (GUIs) to ensure their case of use. The data model is usually an afterthought, and is generally time rather than activity based. In some cases, the data model is used as a tool to further the system`s {open_quotes}user-friendliness{close_quotes}. This robs the application of its versatility in performing even some of the most fundamental analysis of the data. To date, neither POSC (Petrotechnical Open Systems Corporation) nor the PPDM (Public Petroleum Data Model)more » have initiated studies to develop a drilling data model. The authors will present a data model that was used as a basis for Shell Canada`s (SCan) Drilling Information System. The provision of a sound data model, that accurately reflects the fundamental data used by drilling (or other operations), is paramount to the success of any information system. Without it, the utilization of engineering operations analysis tools for optimization would be extremely difficult.« less

Assessing The Risk Of Wellbore Instability In Horizontal And Inclined Wells

Abstract Wellbore instability can lead to expensive operational problems during the drilling, completion and production of horizontal and inclined wells. This paper reviews the direct and indirect symptoms of wellbore instability, its root causes, and various empirical and deterministic modelling approaches to predicting the risk of hole collapse or convergence. In general, linear elastic models that are only concerned with stability at the wellbore wall often give overly pessimistic predictions. An alternative approach, using the extent of the "yielded" zone around an unstable wellbore and the kinematics of rock detachment, is proposed for practical risk assessments. A case history for an open hole completed horizontal well in a limestone reservoir under high drawdown is described. General guidelines for conducting field-oriented stability assessments conclude the paper. Introduction Wellbore instability during the drilling, evaluation, completion and production phases of a well has become an increasingly important concern for many operators applying horizontal well technology. Traditional conservative completion methods for vertical wells are being challenged as operators attempt to reduce well costs and still derive the improved productivity and access to hydrocarbon reserves offered by horizontal wells. More recent horizontal well innovations include the use of underbalanced drilling techniques(l), slimhole completions, side track or re-entry wells with open hole build sections(2,3), and multiple laterals from a single vertical or horizontal wellbore(4). In applying these new technologies, there are often issues posed during the well planning stage where the risk of hole collapse in the short or long term must be addressed. In many cases, the selection of an optimal strategy to prevent or mitigate the risk of wellbore collapse might compromise one or more of the following other elements of the overall well design: the rate of penetration; the risk of differential sticking; drilled cuttings and mud disposal options; hole cleaning abilities; hole size, and consequently the completion and stimulation options available; formation damage risk; stimulation requirements; the ability to log the hole; and the selection of surface sand handling facilities (where sand production is anticipated). In many cases there may be insufficient experience with a given reservoir and the desired completion, hence the prior performance of vertical wells cannot be used, by itself, to guide the well design. This paper reviews the symptoms of wellbore instability and its fundamental causes. Published approaches to wellbore stability prediction will be described, particularly those which address the most common problems faced in developing normally to slightly under pressured oil and gas fields. Emphasis is placed on techniques and conditions applicable to Western Canada where there has been a rapid pace of horizontal well development, particularly with re-entry wells. Predictive techniques applicable to build, inclined or horizontal sections of a well, during the drilling, completion and subsequent production phases, will then be described. Selected case histories from the literature are cited and an example of a wellbore stability prediction for Shell Canada's first horizontal open hole completion is described. This paper will not review all the wellbore stability models which have been developed for vertical wells.

Enhanced Steam-assisted Gravity Drainage: A New Horizontal Well Recovery Process For Peace River, Canada

Abstract A new horizontal well recovery process, developed for application in the Peace River tar sands of Alberta, Canada, has shown sufficient technical and economic potential to warrant a field test which commenced operations in November 1993. The new process is an enhanced version of the steam assisted gravity drainage(1,2) (SAGD) process which is currently being field tested by Alberta Oil Sands Technology and Research Authority (AOSTRA) together with a consortium of industry members at the Underground Test Facility (UTF) located in northern Alberta(3–5). The SAGD well configuration, which consists of two parallel and superposed horizontal wells, with continuous steam injection occurring in the upper well and liquid and gas production from the lower well, is also utilized in the Enhanced Steam Assisted Gravity Drainage (ESAGD) process. A performance enhancement to the SAGD process is obtained through the application of a small pressure differential between adjacent pattern steam chambers. The gentle "steam drive," which occurs once sufficient bitumen mobility has been obtained between steam chambers, is observed to be tolerant of reservoir heterogeneities. Additional benefits include accelerated steam zone growth and bitumen production, up to 50% improvement in ultimate recovery efficiency, and no impairment to the thermal efficiency relative to the SAGO process. The surface access 'ESAGD field test currently underway in Peace River is described. The Peace River oil sands are 10caEed in northwestern Alberta (Figure I). Following the oil sand deposit discovery in 1949, Shell Canada began testing a variety of in situ recovery processes, including steam soak tests in 1962. steam drive and in situ combustion testing in 1965–66, followed by steam injectivity and productivity tests in 1973–74(6,7). A 31-well pilot (Peace River In Situ Pilot - PRlSP; see Figure 2) began operations in 1979, testing the pressure cycle steam drive process(7–9). Pilot operations ended in 1992 at a cumulative recovery efficiency of 65% and cumulative oil steam ratio of 0.25. In 1986, Shell Canada commenced operations in [he Peace River Expansion Project (PREP). the only commercial project in [he Peace River oil sands, with a target production of 1,600 m3/day of bitumen from 163 producers(10). The need to improve production economics by reducing production costs was the motivation behind the Peace River horizontal well study, which began in early 1991. The use of horizontal wells in a pattern steam drive was shown via numerical simulation to result in poor recovery and thermal efficiency due 10 poor steam conformance. This led to the numerical simulation study of SAGD (1,2). SAGD without any performance enhancements did not appear to yield the desired performance uplift in Peace River. Further study ultimately led to the development of the ESAGD process. Geological Description The Peace River oil sand deposit covers an area of approximately 6,200 square kilometres and contains some 12 billion cubic metres of bitumen. The productive horizon is found in the Bullhead member of the Cretaceous Bluesky/Gething zone at an average depth of 600 m, and is geologically equivalent to the shallower. productive McMurray sands in Northeastern Alberta(11).

Identification of a simulated Shell distillation column using time series analysis methods

Abstract This paper presents details of a multivariate time series identification of the simulated Shell distillation column described in the introductory paper by Cott. The approach applied here involves the use of time series identification techniques and may be considered as representative of the system identification procedures adopted by Shell Canada for quadratic dynamic matrix control (QDMC) applications. Results indicate that techniques of time series analysis are very flexible and capable of producing satisfactory step response models under both low and high signal to noise conditions.

A Statistical Analysis Of The Early Peace River Thermal Project Performance

Abstract A statistical correlation of well performance indices with geology is described for the steam soak phase of the Peace River Expansion Project (PREP), a thermal recovery project operated by Shell Canada Ltd. As expected from a confirmed, permeability-dominated steam underride through a basal lean bitumen zone, well performance correlates only with geology of the lean zone, and not at all with that of the overlying rich bitumen zone during this stage. However, the existence of extensive cross-correlations among the geological parameters, which in at least one instance has introduced a spurious correlation for calendar day oil rate, suggests that log analysis techniques need to be optimized in studies of this kind. In additionto the conventionally calculated bulk fraction shale volume Vsh)from logs, the introduction of other shale parameters is advantageous, and is discussed. Introduction In recent years there has been a growing interest in statistical studies of oil well performance indicators. Apart from the most common analyses, dictated by the need to reduce large data sets to some manageable size, statistical correlations of productiondata against geological parameters might be used to test theories of reservoir depletion that are provided by modelling. This work is intended to test a depletion theory, with the use of public data from the thermal Peace River Expansion Project (PREP), operated by Shell Canada Ltd. in northwestern Alberta. The PREP Project Shell Canada Ltd. has been operating the Peace River Expansion Project since 1986, following a very successful pilot which, as of October 1989, has recovered 53% of oil-in-place by a pressure cycle steam drive process(1). The project recovers bitumen from the 30 m thick Bluesky/Gething sands which have a thin basal zone of relatively low oil saturation (50% of pore volume) and high permeability. This lean pay zone, varying in thickness from 0.3 m to 7 m, allows injection of stream at high rates below fracture pressure in all but eight wells. All wells are perforated in this zone, except in Pads 12 and 15, where shale in the basal zone forced perforation in the rich zone, Thus, a permeability-dominated steam underride(2) permits heating or the richer zone from below(3). The operating strategy and facilities at the Peace River project have been described on several occasions(4–8); in essence it consists of alternating periods of high steam injection and low production rates (pressure-up) with periods of low or no steam injecrion and high production rates (blowdown). Figure 1 shows the well patterns at the Shell Peace River Project. To the west lies the original well cluster of the pilot (PRISP) project, consisting of seven inverted seven spots, Four clusters of thirteen patterns each represent the expansion project which will be considered in this paper. The small irregular "Multisoaks" pattern remains from a previous cyclic steam pattern. While the three eastern wells of this pattern have been incorporated into cluster A, they will be excluded owing to their prior operations history.

New Bentonite Extension Test Provides A Better Gel Quality Evaluation

Abstract A bentonite extension (BEXT) lest has been developed as a bentonite quality control procedure. Unlike the API bentonite quality control test, the HEXT test will differentiate between poorer and better grades of bentonitic ores. The BEXT lest generates an ultimate yield point for a bentonite based upon that bentonite's maximum extendability in fresh water. Beneficiating polymers commercially added to bentonite samples do not affect ultimate yield point values. Bentonite samples with ultimate yield paints greater than 30 pascals are shown to produce fresh water bentonite muds with acceptable rheological properties. Poorer quality bentonites having ultimate yield points of less than 16 pascals do not give adequate yield points or gel values. Data presented from the BEXT test correlates closely to western Canadian drilling performance. Field data demonstrate that faster drilling rates and fewer hole problems have been realized when good quality bentonites, as specified by the BEXT test, have been used. A review of case histories for foothills wells indicates better hole cleaning and improved suspension properties have been observed when poorer quality bentonites were replaced by better quality gels. Drilling costs have been significantly reduced when better quality bentonites are used for fresh water drilling operations. Introduction Improved hole cleaning and suspension characteristics or drilling fluids have commonly been associated with reduced drilling problems. This is especially true when fresh water systems normally associated with significant hole washouts are used. Most of Shell Canada's rheological problems in recent years have been associated with poor quality bentonite. Therefore, a quality control program was initiated ror bentonitic clays to reduce drilling problems and mud costs in the field. This paper discusses testing procedures as well as field results for fresh water drilling fluids. Gel/XC polymer costs have been reduced by at least 37% in areas where the program has been implemented. Bentonite Quality Most bentonitic days used in the drilling industry have beneficiating agents added during milling operations. .Although the agents have qualified interior clays to API specifications, problems meeting our rheological specifications in the field have been observed where poor quality bentonite has been used(1). With additions of poor quality bentonite minimal increases in yield point and initial gels have been observed, while methylene blue test values, plastic viscosity, gel progression and % sounds increase significantly making the drilling fluid more susceptible to contamination as well as more costly. In contrast, with higher quality bentonite additions both yield point and initial gel values improve significantly. The current approved use of extending polymers to upgrade bentonite has led to concern about true bentonite quality(2). A new method to ensure bentonite quality is required to replace the current API procedure. Alternate quality procedures for bentonite have been proposed, however, none of these methods quantitatively measure raw bentonite quality(3,4). Bentonite Extension Text (BEXT Test) The BEXT test was developed to quantitatively measure bentonite quality. This procedure measures the maximum yield potential of bentonite samples for a standard bentonite extender Alcomer 1773.

Separation Scheme For Cleaning Up Oily Waste

Abstract It is well known that heavy oil and oil sands thermal recovery operations produce oil-laden solids and sludges which are difficult to treat and to dispose of safely. The oil-laden sediments and sludges, which commonly accumulate in oil field produced fluids separators and treaters and at the bottom of storage tanks, are usually not readily amenable to conventional methods of treatment and disposal. Such materials, commonly called produced so/ids, typically consist of oily sand, precipitates and emulsified oil and water. The nature of produced solids at Shell Canada '5 steam-enhanced heavy oil recovery facility at Peace River is described; and the development of a new process for treating produced solids that allows removal, and recovery, of hydrocarbons associated with the solids and thereby assists in the safe disposal of the residual solids is discussed. The process comprises mainly feed conditioning, hydrocarbon removal and recovery, and water removal steps. The basic concepts of the process may also be applicable to oily waste other than produced solids such as soil contaminated in an oil spill or from oil storage or refinery operations. Introduction In the production and treatment of crude oils, especially in heavy oil and oil sands thermal recovery operations, the generation of oily produced solids waste is a well known problem and poses difficulties in the treatment of produced fluids and in disposal of the solids. Based on industry surveys(l), the annual volume of oily produced solids, excluding untreatable slop oils and spill debris, at Canadian heavy oil operations approaches 50 000 m3. In comparison, the volume of produced sand, tank bottoms, separator sludges and associated solids in the United States is in the order of 200 000 m3 (more than half in California)(2). Due to their appreciable hydrocarbon and brine contents and their physical nature, produced solids are not readily amenable to conventional methods of treatment and disposal and can represent a significant loss in crude oil production. In many cases, produced solids are combined with slop oils and spill debris and stored in on-site "ecology pits". Such oily mixtures have been utilized for road dust suppression and in the preparation of road surfacing material(3). Studies on land farming methods for disposal of oily waste sludges suggest that this concept may be possible but major changes in soil properties could adversely influence end use of the land(4,5). Previously, numerous methods have been investigated for recovery of oil from produced solids including thermal retorting by the AOSTRA Taciuk Process(6,7), use of coal(8) solvent extraction and mechanical means(9). An oily sand cleaning system, consisting of a set of hydrocyclones for removal of oil and water and a dewatering screen for removal of additional water is reported(10). Incineration methods may also be an attractive option for decontaminating the solids and energy recovery. Injection of a slurry of the oily produced solids and water into an underground formation has been demonstrated to be a viable option but successful injection is greatly affected by the characteristics of the produced solids and the disposal formation selected(11).