McMurray Formation Research Articles

Artificial Lift-A Major Unresolved Issue for SAGD

Abstract Lower-pressure SAGD may be required because of thief zones, or to improve the SOR, emissions, and water use. Simple 3D simulation examples representing real-world conditions illustrate the need for low steam-trap subcool values. A low mixed subcool value is needed to minimize local subcool values along the well pair and maximize steam chamber development. Lower pressures magnify the need for low subcool values. For low mixed subcool values, there is zero or very low liquid head available above a bottomhole pump. However, a high average head is required, much higher than the minimum head, due to SAGD flow instabilities. Using typical field values, a simple analysis shows that a standard bottomhole pump configuration cannot provide low subcool values for lower steam chamber pressures. A lift system designed to provide low subcool values at lower pressures is a two-stage lift system called ELift. This was used at Gulf's Surmont SAGD pilot for three years. A simulation example of the two-stage lift system is provided showing excellent conditioning of fluids prior to the pump inlet. This allows the use of standard pumps, and extends pump service life, in addition to providing the benefits of lower-pressure operation and improved recovery performance with low mixed subcool values. Introduction Steam-assisted gravity drainage (SAGD) is now used in large commercial operations as well as pilot operations. However, one of the major issues that has not yet been resolved is the issue of artificial lift for lower-pressure SAGD operations. The main focus of this paper is to summarize why lower-pressure SAGD is important, describe the impact of steam-trap control and unstable SAGD flow on artificial lift requirements, and describe a lift system which, in principle, meets the requirements for SAGD lift at lower pressures. Reasons for Lower-Pressure SAGD Operations Lower-pressure SAGD may be required because of the presence of thief zones. Associated gas sands and/or water sands in the upper part of the McMurray formation are common features of the Athabasca oil sand deposit, and may constitute thief zones to SAGD operations. The upper gas and water sands are generally under-pressured at virgin conditions, and gas production operations have further lowered the pressure. When SAGD steam chambers achieve hydraulic communication with associated thief zones, the pressure in the steam chamber must be close to that in the overlying thief zone, and artificial lift will generally be required. There is extensive information on this topic from several gas/bitumen hearings and in decision reports by the Alberta Energy and Utilities Board(1). Even when thief zones are absent, lower-pressure SAGD may be required to improve the steam-oil ratio (SOR). Reduced SOR provides savings in natural gas consumption, reduced emissions per unit of production (specific to Kyoto regulations), and reduced usage of valued water resources. Because reduced SOR also reduces water handling requirements, it provides important savings in the separation and water-recycle facilities. A SAGD plant is mainly designed with regard to steam-generation/water-handling capacity. Once a plant is built, with relatively minor modifications it will provide increased oil rates as the SOR declines.

Characterizing sediment sources and natural hydrocarbon inputs in the lower Athabasca River, Canada

The Athabasca River drains an area of 160 000 km2 in northern Alberta, Canada, with much of the lower basin underlain by oil-sand deposits. The oil sands occur primarily in the McMurray Formation of the Cretaceous Period, with outcrops evident along the banks of the Athabasca River, as well as the lower portions of several tributaries. Since the oil sands represent a natural diffuse source of hydrocarbons to the aquatic environment, understanding the nature and extent of sediment-bound hydrocarbon contaminants in the context of the sediment regime of the Athabasca River is important. Described are fluvial geomorphic characteristics of the lower Athabasca River, which provide a basis for assessing sediment-bound hydrocarbon contaminants. Suspended sediment derived from main stem and tributary sources between Fort McMurray and Embarras account for 1.2 Mt, or 18%, of the mean annual load of the Athabasca River. Of this load, approximately 53% of the sediment input originated from tributaries, the remainder from main-stem sources. The majority of sediment contributed along the main stem occurs in the vicinity of Embarras, well downstream of oil-sand sources. Natural oil-sand sediment contributions are likely much less than 3% of the annual load downstream of Fort McMurray. Key words: sediment, fluvial geomorphology, oil sands, hydrocarbons, polycyclic aromatic hydrocarbon (PAH), contaminants, environmental monitoring, Athabasca River.

Seismic modeling of fluvial-estuarine deposits in the Athabasca oil sands using ray-tracing techniques, Steepbank River area, northeastern Alberta

ABSTRACT Most of the bitumen ressources in the Athabasca oil sands area are contained in fluvial and estuarine channel deposits of the Lower Cretaceous McMurray Formation. Stratigraphic sections were measured along a 5 km stretch of the Steepbank River, north of Fort McMurray, near the Suncor Steepbank Mine. We have identified at least four channel complexes based on stratal bounding surfaces, arrangement of exposed lithofacies, and consistent paleoflow patterns. The lower part of each channel complex contains medium to large-scale, trough crossbedded sandstone, exhibiting high porosity and permeability. These sandstones were deposited in channel axes and are the highest-grade bitumen deposits in the study area. Overlying inclined beds (sandy or muddy inclined heterolithic stratification) downlap on the lower sandy beds and were deposited in estuarine point bars, but the permeability and bitumen saturation of these strata are considerably lower. Nearby wells contain cored and logged intervals that are similar to exposed outcrops in the riverbank. For the outcrop sections, artificial sonic logs were constructed by comparison with sonic curves from these nearby wells, but the curves were modified to reflect differences in thickness and mud content at the exposure. Three structural-stratigraphic cross-sections and ray-tracing techniques were used to construct seismic models. These models compare favourably with four high-quality, industry-acquired seismic lines from the Clarke Creek ExxonMobil lease area, about 20 km southeast of the Steepbank River outcrops. The deposits at Steepbank are thus similar in scale and geometry to those in the Clarke Creek area. The Clarke Creek channel complexes are very well imaged on the seismic profiles, and our seismic modeling indicates that high-resolution seismic data are necessary to image these channels. 1 Present Address: Alberta Energy and Utilities Board, 640 - 5 Avenue SW, Calgary, AB T2P 3G4 End_Page 178------------------------

Mapping of the McMurray Formation for SAGD

Abstract The McMurray formation in north-eastern Alberta contains a substantial fraction of the world's currently identified oil resources. The areal extent of the deposit is in the order of 300 km north-south and 100 km east-west. It has been estimated(1) that over 40 billion barrels (6.35 × 109 m3) are potentially recoverable with steam assisted gravity drainage (SAGD) from dual well pairs. This is in addition to the substantial reserves already accessible from surface mining operations in locations with minimal overburden. The success of potential SAGD projects is greatly dependent upon the proper identification of regions with adequate pay, limited shale barriers, and controllable bottom water and/or top gas/water. The fluvial/estuarine nature of the formation greatly limits the predictability of trends when viewed in a local context. However, when regional behaviour is coupled with geostatistical techniques, an improved understanding of these critical parameters is possible. This paper applies a computerized log analysis technique to obtain the porosity, oil saturation and permeability from the McMurray formation utilizing digitized logs. Additional analysis is performed to obtain regions of effective net pay and other performance indices. This information is then presented through the use of regional mapping with a geostatistical approach. Introduction The Athabasca tar sand deposit is located in the northeast corner of Alberta, Canada. The major accumulation within this deposit is contained within the McMurray formation of early Cretaceous age. By various estimates, the OOIP of the McMurray formation exceeds 120 e09 m3 (750 billion bbls)(2). The commercial extraction projects currently operational in this region are based on surface mining techniques. However, only a small fraction of the resource is suitable for mining operations(2). The vast majority of the region is covered by overburden deposits that exceed any currently economic surface mining technique. These more deeply buried regions may prove to be amenable to the steam assisted gravity drainage (SAGD) process or some variant(3). Several pilot/demonstration plants have shown promising results with this technology, originally developed by the Alberta Oil Sands Technology Research Authority (AOSTRA) for the underground test facility (UTF)(4). The intention of this paper is to provide an overview of some of the computerized mapping techniques that are applicable to determining the extent of the possible SAGD resource in the McMurray formation. Reservoir Requirements for SAGD The SAGD process consists of a pair of parallel horizontal wells with a 3 8 m vertical separation. During normal operation, steam is injected into the upper/injection well, while oil and steam condensate are produced from the lower/production well. The energy transferred from the condensing steam heats the formation, greatly lowering the viscosity of the oil. This enables the oil to flow via gravity to the underlying production well. The process appears to be quite robust from a theoretical perspective. The two principal governing factors, conduction heat transfer into the cold reservoir and gravity flow of fluid to the production well, are only moderately influenced by many reservoir characteristics. A number of previous studies have explored the theoretical range of applicability of the SAGD process to generic heavy oil reservoirs(5, 6).

ABSTRACT: Application of Sedimentology and Ichnology for Facies Delineation and Reservoir Characterization of the McMurray Formation, Alberta, Canada

ABSTRACT: Application of Sedimentology and Ichnology for Facies Delineation and Reservoir Characterization of the McMurray Formation, Alberta, Canada

ABSTRACT: Ichnofossil Evidence from the Estuarine Facies of the McMurray Formation, northeast Alberta: Facies Interpretation and Possible Production Enhancement

ABSTRACT: Ichnofossil Evidence from the Estuarine Facies of the McMurray Formation, northeast Alberta: Facies Interpretation and Possible Production Enhancement

Numerical Simulation Study of a Well In the JACOS Hangingstone Steam Pilot Project Near Fort McMurray

Abstract This paper presents a numerical simulation study of a well in a pilot project which has 13 steam stimulation wells in an oil sand reservoir near Fort McMurray. Steam injection commenced May 1, 1990 as a joint project by Petro-Canada, Imperial Oil Resources, Canadian Occidental Petroleum Ltd. and Japan Canada Oil Sands (JACOS). A special emphasis has been made on the energy distribution around the subject well. Many thermocouples have been installed in the wellbore outside of the casing and three temperature observation wells have been drilled at 12 m distances from the well. A numerical history match was conducted when the well completed its seventh cycle of production. The bottom-hole temperature, bottom-hole pressure, fluid production of each phase and temperature profile at the observation wells were used as history match parameters. The simulation results indicate that a failure zone was mainly created in the top of the upper McMurray formation which overlies the target oil zone during the first two cycles. The location of this failure zone gradually shifted downwards as the cycles progressed. The failure zone developed mainly in the lower part of the Upper McMurray formation during the third and fourth cycles, and in the top of the Lower McMurray formation, the target oil zone, during the fifth and sixth cycles. This downward change in the location of the failure zone caused a gradual improvement in oil production by cycle. To achieve a history match of all field observations, a good representation of the failure zone is an essential requirement. The Sand Deformation module interfaced with CMG's STARS model was used in this study. It was discovered that all of the field observations could not be matched simultaneously without this special version of the model. Introduction The Hangingstone Steam Pilot utilizes a cyclic steam stimulation (CSS) process to extract bitumen from the Athabasca oil sands. The bitumen viscosity at reservoir condition is over 1,000,000 mPa.s and will not flow naturally. Petro-Canada initially operated the CSS Pilot project near Fort McMurray from 1985 to April 1992 as a joint venture of Petro- Canada, Canadian Occidental Petroleum Ltd., Imperial Oil Resources, and Japan Canada Oil Sands Ltd. (JACOS), known as the PCEJ Group. Then JACOS subsequently took over the project. The project initially consisted of three single well steam stimulation tests. One of the interesting results of the single well tests was that oil production progressively improved with time. The mechanism of this behaviour was not clearly understood at that time. A thirteen multiwell pilot test commenced on May 1990 based on the results of the single well tests. A unique feature of the multiwell project is that three temperature observation wells were drilled at a distance of 12 m from well C2 in an equilateral triangle around the well. The temperature response in these wells has helped monitor heat and fluid movement in the reservoir. In addition to this, 20 thermocouples have been installed in well C2 outside of the casing at 1 – 2 m intervals within the target formation.

Geology-based conditional simulation in the Athabasca oil sands deposit, Alberta, Canada

The Athabasca oil sands deposit, Alberta, Canada, is one of the largest known hydrocarbon accumulations. The efficient exploitation of this deposit, as well as other oil sand accumulations throughout the world, is based onin situ recovery and surface mining methods. Quantitative modeling of deposit heterogeneity provides a valuable engineering tool. In the present study, conditional simulation was used to model oil-saturated zones in part of the Athabasca deposit. This technique generates equiprobable models of thein situ variability of essential deposit attributes that honor the available data and their spatial statistics. The application of the technique is based on the delineation of geologically homogeneous zones within the host McMurray Formation, their statistical validity, and the integration of geological interpretations. The geological framework is developed, and subsequently, high resolution conditionally simulated models of three identified hydrocarbon-bearing zones are generated, in terms of the zone boundaries and the percent weight of oil saturation. These models serve as “what-if” tools for risk assessment and future planning.

オイルサンド油層に対するｃｙｃｌｉｃ ｓｔｅａｍ ｓｔｉｍｕｌａｔｉｏｎ法を用いた回収テストのヒストリー・マッチ実施例

The successful performance of the CSS (Cyclic Steam Stimulation) process at the PCEJ Pilot is largely dependent on the fracture configurations in the oil sands, McMurray Formation. From a simulation point of view, the key is how well such fracture configurations can be described in a simulation model. This study concludes that the coupling of a reservoir simulator (THERM, version 2.4, SSI) to a fracture simulator (TARSIM, version 2.4, Simtech) can be used to successfully describe the recovery mechanism of the CSS process at the PCEJ Pilot. Based on the Fixed Fracture Concept, the output from the TARSIM model such as fracture lengths and failure zone widths, were used as inputs for the THERM model. Within the fracture grids, fractures were expressed by increasing both the horizontal and the vertical transmissibilities. Fracture initiation and propagations were expressed as porosity increases when grid pressures reached the 7, 000kPa fracturing pressure determined from field study. By using the above approach, a good overall history match for the PCEJ Pilot Project was accomplished.

Impact of Upper McMurray Formation Marine Oil Sands on dragline mining at the Syncrude Canada Limited open pit mine : McKenna, G T; List, B R Proc 2nd International Symposium on Mine Planning and Equipment Selection, Calgary, 7–9 November 1990P363–371. Publ Rotterdam: A A Balkema, 1990

Impact of Upper McMurray Formation Marine Oil Sands on dragline mining at the Syncrude Canada Limited open pit mine : McKenna, G T; List, B R Proc 2nd International Symposium on Mine Planning and Equipment Selection, Calgary, 7–9 November 1990P363–371. Publ Rotterdam: A A Balkema, 1990

Detailed Reservoir Characterization Based on Outcrop Analogs: Lower Cretaceous McMurray Formation, Northeast Alberta

Detailed Reservoir Characterization Based on Outcrop Analogs: Lower Cretaceous McMurray Formation, Northeast Alberta

Reservoir geological modelling of the McMurray Formation, Alberta

Reservoir geological modelling of the McMurray Formation, Alberta

Sedimentology of McMurray Formation channel-fill deposits

Sedimentology of McMurray Formation channel-fill deposits

Lithological Discrimination and Correlation in Oil Sands Using Rock Magnetic Properties

The Lower Cretaceous McMurray Formation, which contains most of the bitumen reserves of the Athabasca oil sands, comprises uncemented quartz sands with siltstone, shale, and local ironstones. The sequential fluvial, estuarine, and marine depositional environments of the McMurray drainage basin have resulted in the complex juxtaposition of differing lithofacies. Horizontal continuity of lithofacies is limited. Sand body geometries are many and varied. Prediction of sand body geometry has important economic applications; a strong positive correlation exists between sand facies and oil grade. An investigation of the magnetic property variations in specimens from five closely adjacent boreholes within the McMurray Formation has shown that it is possible to: (1) document objective magnetic property parameters to differentiate distinct lithological units; (2) use these same magnetic parameters to establish between borehole lithostratigraphic correlations; and (3) to show that the magnitude of some magnetic parameters bears a direct relationship to the oil content of a lithology.

Channel-fills in the McMurray formation: their recognition, delineation, and impact at the Syncrude mine : CIM Bulletin V82, N928, Aug 1989, P67–74

The Lower Cretaceous McMurray Formation contains the bitumen reserves of the Syncrude Mine in northeastern Alberta. The Syncrude Base Mine area consists of estuarine sediments with channel-fill sediments. A detailed knowledge of the distribution of these beds is very important in assessing the risk of mine highwall instability

Reservoir Characterization for Chevron's HASDrive Field Trial, Athabasca Oil Sands Area, Northeastern Alberta, Canada: ABSTRACT

Chevron is currently field testing an in-situ thermal recovery process termed Heated Annulus SteamDrive (HASDrive) on the Lower Cretaceous Athabasca tar sand deposit at the Alberta Oil Sands Technology Research Authority (AOSTRA) Underground Test Facility (UTF) site. The HASDrive process applies heat through a subsurface horizontal pipe to the base of the bitumen-rich reservoir sands of the McMurray Formation. A vertical steam-injection well aids in mobilization of the heavy crude and sweeps hydrocarbons toward a horizontal subsurface producing well. To evaluate the HASDrive technology, a geologic model was developed to predict the distribution and geometry of reservoir sands and intervening shales. Core studies indicated deposition took place in an estuarine environment, with sands representing tidal channel deposits and shales relating to tidal flat sedimentation. A thorough program of conventional and special core analysis was done on samples from five wells. Special core analysis consisted of miscibly cleaning samples prior to determination of brine permeability. Vertical and horizontal permeability were determined for massive to cross-bedded sandstone as well as four types of shale-bearing sandstone. Of these four, thin shale beds and shale breccia were more effective in reducing permeability and may form barriers to fluid flow. Thin discontinuous shale laminae ormore » shaly wisps merely impede flow. Interactive workstation programs used core and log data petrophysical parameters as input to build a simulator grid of 2,600 blocks in 10 layers to represent a field trial area of approximately 2,000 m{sup 2}. Potential barriers capable of preventing or reducing the flow rate were identified, incorporated into the model, and treated as dimensionless shales (i.e., shaly beds with negligible thickness). The simulator model was then used to the match history of field trial fluid production.« less

Fracture Geometries Consistent With Ttiltmeter Data And Pressure And Tracer Communication In The Glisp 1-1 Stimulation

Abstract The Gregoire Lake In-situ Steam Pilot (GLISP) in the Athabasca tar sands, includes three producing u:ells surrounding an injection well. The authors modeled tiltmeter records of the fracturing treatment of the central injection well, and pressure and tracer communication from the central injection well to the producing wells, and investigated how these analyses support various fracture geometry scenarios. Several different fracture geometry scenarios have been examined. Theorencal surface tiltmeter vectors for these scenarios are compared with observed vectors. Also, theoretical time delays based on propagation of pressure transients and tracer material have been predicted for these scenarios, and compared with observed delays. The results of these comparisons are expressed in the form of a "range" of fracture geometries that are most consistent with measured tiltmeter data in the field, and pressure and tracer time delays in the three production wells. Interpretations within this range include complex fracture systems with one or two fracture components rising steeply from tire base of the McMurray Formation into the overlying depleted zone. Dominant horizontal fracturing does not appear to occur. Introduction The Gregoire Lake In-Situ Steam Pilot (GLISP), in the Athabasca tar sands, includes three producing wells, P-l, P-2, and P-3 surrounding an injection well, I-1 (Fig. la). On February 5, 1987, the injection well I-1 was fractured with about 114 m3 (30 000 gallons) of linear gel without proppant, to communicate with the producing wells. The cased well was fractured through notches near the bottom of the McMurray Formation. Profiles of bottomhole treating pressure and rate are shown in Figure 1b. A wide variety of diagnostic information has been evaluated in regard to the geometry of the induced fracture by MacKenzie, et al. (1). Several different fracture geometries are ranked, in order, according to how consistent they are with these data. The most probable fracture geometry is a U-shaped fracture, or variations of this generic shape, such as a non-symmetric U-shaped fracture, an L-shaped fracture, or an elongated bowlshaped fracture. The goal of this paper is to examine how consistent are three totally independent diagnostic observations of fracturing (tiltmeters and pressure, tracer communication). Delays in pressure transient peaks at the three production wells varied from 1.1 to 3.6 hours (from beginning of fracture). Hot water and tracers were injected after the treatment to assess communication with the other wells in the pilot The time to maximum tracer at the producing wells was 3 to 6 days. Several different fracture geometries scenarios have been examined. Using an in-house code, theoretical surface tilt meter vectors for these scenarios are compared with observed vectors. Also, theoretical time delays based on propagation of pressure transient and tracer material have been predicted for these scenarios, and compared with observed delays. The results of this analysis are expressed in the form of a "range" of fracture geometries that are most consistent with these data.

Modeling and Mapping of Geology and Hydrocarbon Content of the McMurray Formation, in Northern Alberta: ABSTRACT

Complex stratigraphy and depositional facies of the McMurray Formation requires special attention and understanding prior to modeling and mapping. This requirement is due to the extreme lateral and vertical variations of the lithofacies of the McMurray Formation. The bitumen content of the McMurray Formation is of epigenetic nature. The oil saturation is a function of physical characteristics of the reservoir rock such as porosity and permeability. These characteristics vary based on the lithology and depositional facies. To map the detail geology and oil content of the McMurray Formation in the area under investigation, the formation was divided into five distinct correlatable units based on its regional depositional environment. These units from top to bottom are Marine, Upper Peritidal, Fluvial-Lacustrine, Lower Peritidal, and Continental. Each unit was further divided into a number of subunits based on its lithology and specific depositional facies. The thickness, bitumen content, fine, solid and water content of each subunit were modeled and used for reserve calculation and mine planning. Modeling and mapping was done based on variable block modeling concept. This concept, unlike conventional block modeling technique, takes detail geology into consideration, therefore allowing determination of the exact location of ore and waste units.

Fracture Stimulation In The Glisp Tar Sands Pilot-Case History

Abstract This paper reviews fracture stimulation of the McMurray formation in the Gregoire Lake In Situ Steam Pilot Project (GLISP), in northeastern Alberta. The purpose of the stimulations was to effect interwell communication between the injection and production wells prior to steam injection. In situ stresses measured at shallow reservoir depths, indicated a possibilityfor horizontal fractures, a very desirable prerequisite/or the potential success of the experimental pilot. Analyses of data collected during and following the final fracture stimulation in the pilot area on the I-I central injection well (i.e. tiltmeter data, bottomhole pressures, temperature profiles, tracer surveys, production response, laboratory experience, field observations) and fracture theory indicate that a very complex fracture geometry resulted with both horizontal and vertical components. These data were used to address an array of nine possible fracture geometries to determine the more probable fracture configurations). Interwell communication by hydraulic fracturing was achieved over short distances but not over the full well spacing of the pilot. Introduction Amoco Canada Petroleum Company Ltd., Petro-Canada, Inc., and the Alberta Oil Sands Technology and Research Authority (AOSTRA) are participants in an in situ experimental recovery pilot to investigate the feasibility of producing the heavy oil reserves in the McMurray formation in the Gregoire Lake area of the Athabasca tar sands deposit. This pilot known asthe Gregoire Lake In-Situ Steam Pilot or "GLISP" is located as shown in Figure 1. The pilot area, shown in Figure 2, was selected on the stratigraphy seen in the C-l abandoned core hole as being the preferred lithology in the general area. Three confirmation wells (D-l, D-2 and P-l) were drilled. Log evaluation indicated that the P-l well had the most suitable reservoir properties and therefore it was selected as the central injection well for the pilot. One observation well (O-1) was drilled and three producing wells were planned to be drilled triangularly spaced around this injection well (see original pilot configuration, Fig. 2). Drilling the three production wells was deferred pending the possible fracture stimulation of the central injection well. In addition, a tiltmeter survey was planned to monitor fracture evolution and better define the optimum locations for the wells. Injectivity tests run on the three confirmation wells indicated that fracturing would be required to accomplish communication between wells. Concurrent with the injectivity tests, in situ stress tests were also conducted to obtain fracture design data. The majority of these stress tests indicated closure pressures approximating the overburden pressure. In some tests there was also evidence of a much lower closure pressure. These data suggested the strong possibility of a horizontal fracture which would be preferred for the pilot. However, there was the distinct possibility of a vertical fracture, or more likely, a complex fracture geometry with both horizontal and vertical components. The P-l central injector was fracture stimulated through perforations at the base of the McMurray formation.

Sedimentology of McMurray Formation at HASDrive Site of AOSTRA Underground Test Facility, Northeastern Alberta, Canada: ABSTRACT

Sedimentology of McMurray Formation at HASDrive Site of AOSTRA Underground Test Facility, Northeastern Alberta, Canada: ABSTRACT