Abstract Currently, large-scale commercial in-situ recovery of bitumen from oil sands reservoirs is done by thermal gravity drainage oil sands recovery processes such as cyclic steam stimulation (CSS) and steam-assisted gravity drainage (SAGD). In these processes, steam is injected into the formation, which then heats bitumen until it is sufficiently mobile enough to be moved to the production well. The key goal of these processes is controlled and targeted steam delivery, really heat delivery, to the reservoir, and thus, both heat transfer and consequent bitumen mobilization are key controls on the performance of the processes. Here, we describe conductive and convective heat transfer at the edge of steam chambers and oil mobilization just beyond the edge of the chamber. The results demonstrate the complex interplay between heat transfer and oil mobilization: heat transfer controls the temperature profile beyond the edge of the steam chamber, which sets the oil viscosity profile, which in turn controls bitumen mobilization. Relative permeability, geomechanics, and geologic heterogeneity make the phenomena more complex. The discussion suggests that self-corrective robust recovery processes or dynamic well interventions such as smart wells that yield uniform steam chambers are required to ensure efficient heat transfer and oil mobilization.

Abstract On May 18, 2006, a surface steam release incident occurred at the Total E&P Canada Ltd. (referred to here as “Total”) Joslyn Creek steam-assisted gravity drainage operation in northeastern Alberta, approximately 60 km (37 mi) north of Fort McMurray. No injuries or loss of life, consequences to wildlife, and public impacts occurred. The Energy Resources Conservation Board (ERCB) staff conducted a nearly 3-yr multidisciplinary investigation into the conditions that resulted in the incident. This analysis included independent geologic and engineering investigation as well as an extensive review of the material of Total submitted to the ERCB. The report of Total included detailed seismic imaging and extensive monitoring and modeling programs and has been released to the public on the ERCB Web site. This chapter gives the highlights of some of the main engineering factors, with detailed emphasis on geologic considerations related to this incident. Given ongoing caprock integrity concerns associated with the hydraulic fracturing in the subsurface to initiate production, these findings will have relevance to other shallow in-situ thermal and non-thermal operations around the world, including in-situ bitumen and extra-heavy-oil deposits and unconventional commodities such as tight oil development.

Abstract Outcrops and subsurface investigations emphasize that the main bitumen reservoirs of the McMurray Formation are large point-bar deposits. Sedimentological studies performed on these reservoir objects have shown that tidal currents occurred in the meandering paleo-river system. These tidal inputs increased reservoir heterogeneities primarily because of successive mud decantation periods and the many reactivation or erosion surfaces. Five main reservoir heterogeneities have been described on Steepbank River outcrops: mud accumulation during channel abandonment, mud drapes along accretion surfaces that are downward interfingered into cleaner sands, flood-plain deposits on top of the point bar, reactivation surfaces typically associated with mud-clast deposits, and mud-clast breccias accumulated at the base of the channel. At the same time, five main facies have been emphasized on these studied tide-influenced point bars: mud-clast breccias, cross-stratified sands, slightly heterolithic rippled sands, highly heterolithic burrowed sands, and thick mudstones. For each of these facies, petrophysical properties have been established, enabling their application as rock types for the Steepbank River outcrop modeling. This deterministic method of modeling, improved by light detection and ranging (LiDAR) data, used truncated Gaussian simulations constrained by the proportion cube, sedimentological logs corresponding to hard data, and adequate variograms. The resulting facies and heterogeneity distributions conform closely to the outcrop reality, lending support for the modeling method.

Abstract Traditionally, in-situ oil sands operators use the simple approach of placing steam-assisted gravity drainage (SAGD) well pairs as close to the base of pay as possible, with the expectation that the effects of reservoir heterogeneity will be mitigated by the use of longer well pairs. It has been proven, however, that the geometry associated with the top and base of the SAGD pay interval and the distribution of reservoir lithofacies within the pay interval have a significant impact on SAGD performance. This chapter proposes that optimal well placement and selective completion strategies can more effectively address reservoir heterogeneity issues, provided that a three-dimensional (3-D) model of the SAGD reservoir and an ultimately fuller understanding of the evolution of the steam chamber over time exist. By applying strong scientific principles and consistent SAGD strategies, top operators have demonstrated that improved reservoir performance is possible, evidenced by higher production rates, lower steam-oil ratios, and maximized recoverable reserves.

Introduction Steam-assisted gravity drainage (SAGD) method is a heavy-oil in situ recovery technique used for bitumen production of the Athabasca Oil Sands, where bitumen reserves from oil sands are estimated at 173 billion barrels (Alberta Energy and Utilities Board, 2008). The typical configuration of the SAGD includes two horizontal wells of 750 m in length and vertically separated by 5 m, in which the upper well is used for steam injection to increase the mobility of the bitumen and the lower well is for bitumen production. Feasible bitumen recovery from oil sands by SAGD is limited within the lateral perpendicular distance of approximately 50 m from the horizontal well pairs. Therefore, profitably viable bitumen production performance requires that the SAGD well pair location be at thick reservoir sands. The complexity of facies distribution in the target formation requires effort in understanding detailed distribution of the reservoir sands. A deterministically constructed geologic model was visualized to better understand 3D distribution of the reservoir sands in the study area (Takahashi et al., 2006). Because lateral continuity of the lithologic facies in the area of interest is shorter than typical interwell distance, the deterministically predicted facies distribution leaves inherent uncertainty in terms of the bitumen production forecasting. The reservoir sand facies can contain impermeable thin mudstone layers and impermeable mudstone clasts. Previous works including Schmitt (2004) and Takahashi et al. (2006) often refer to the thin mudstone layers adversely affecting the growth of the steam chamber during the SAGD process and consequent bitumen production performance. Although the mudstone clasts have not been often discussed in regard to the impact on the bitumen production performance, our field operation has experienced unexpectedly lowered bitumen production from the reservoir containing the mudstone clasts.

Introduction Heavy oil and bitumen constitute the largest easily accessible remaining hydrocarbon deposits in the world, with the greatest potential resources found in Canada, Venezuela, and the former Soviet Union. There are many ways to produce these assets, starting with surface mining of the shallow oil sands to various in situ recovery methods. Heavy oil can sometimes be produced cold, whereas bitumen requires heating or injection of solvents to be mobilized. Cold production of heavy oil may or may not be successfully monitored by electromagnetic surveys (EM), depending on the recovery technique. Slow drainage by pumping the oil is no different from other oil production in terms of EM and should hence be successful, but for the process known as cold heavy-oil production with sand (CHOPS), it is unclear whether this can be successfully monitored by EM because the recovery rate is only 10% and most of the oil and sand is produced from so-called “wormholes,” which affect only restricted parts of the reservoir.

Abstract Petroleum reservoirs are heterogeneous and, therefore, uncertain. Heterogeneity and uncertainty are important for reservoir management. The transfer of geologic uncertainty through process performance is commonly achieved with flow simulation; however, full physics flow simulation requires significant professional and computer time. A proxy model tuned to the specific recovery process provides a means to quickly predict performance uncertainty caused by multiple geologic models and uncertain operating conditions. A limited number of flow simulation runs are used to calibrate the proxy, then calculations proceed quickly. The classical response surface approach is also illustrated. Details are given to the application of proxy models to the steam-assisted gravity drainage process. A proxy model based on the Butler steam-assisted gravity drainage theory is developed to predict the oil flow rate, cumulative oil production, and cumulative steam injection profiles during the rising and spreading steam chamber periods of a steam-assisted gravity drainage well pair. A synthetic example shows the efficiency of the methodology in terms of computation time and predictability. Investment decisions follow an information cycle that starts with acquisition, processing, and interpretation of subsurface data, creating the information needed to construct geostatistical models used to assess reservoir performance using criteria such as the number and type of wells. Different field development scenarios are considered, and decision criteria are applied to select and implement the optimum production scheme. Once wells are drilled and production starts, more information is available for optimizing decisions. The decisions made early in a reservoir life cycle are perhaps the most important, and they have to be made with limited information. Generating multiple geostatistical realizations to represent the state of uncertainty related to the actual reservoir properties is becoming common ( Deutsch and Journel, 1998 ). The available well data early in reservoir development sample less than one-trillionth of the reservoir. Seismic data provide more extensive data coverage but at a larger scale and with less precision related to reservoir facies, porosity, and permeability. The uncertainty is large; however, 100 or fewer realizations are commonly considered adequate to permit assessment of resources at 10, 50, and 90% confidence levels.

Introduction The goal of any operator involved in heavy oil whether flowing or not is to maximize production and minimize costs. With the rapid growth of projects in oil sands, the SAGD process has become commonplace. Although widespread, SAGD is still a relatively new process and operators are discovering that developing an adequate steam chamber requires careful planning. An integral part of this planning process is detailed characterization of the reservoir. With the current operating experience, it is apparent that relatively small features in the reservoir, once thought to be of little or no concern, have been a major impediment or permanent barrier to steam chamber development. The lack of steam chamber growth or inconsistent growth along the horizontal wells is a major contributor to underperforming wells. Therefore, upfront reservoir characterization and the identification of baffles and barriers to steam growth are critical to the process. This chapter details how operators are utilizing crosswell seismic imaging to increase reservoir knowledge and plan SAGD well pair placement and assess overall performance of the steam injection process. Background Heavy oil is characterized by an American Petroleum Institute (API) gravity of less than 22.3°. Bitumen at 8–10° API will not flow at normal reservoir conditions. The API gravity of the oil in the reservoir predicates the production methods. Various production methods are now being used in heavy-oil reservoirs. They range from cold heavy-oil production with sand (CHOPS), cyclic steam injection (CSS), steam-assisted gravity drainage (SAGD), steam-assisted gas push (SAGP), vapor extraction (VAPEX), fire flood, and Toe-to-Heel Air Injection (THAI TM ). With the exception of CHOPS and VAPEX, the other methods rely on heat to mobilize the oil. In the case of fire flood and THAI, heat is generated internal to the reservoir by active combustion, and the other methods rely on steam injected from the surface. It is these processes that will be focused on here.

Abstract – Thermal – some information – cyclic and steam drive – steam assisted gravity drainage – Miscible – limited information – Waterflood – only one paper with a section devoted to sweep efficiency – Low drawdown – Low fluid production per unit well length – Less sand control problem – High sweep efficiency – Infill producers – Large contact area – High injectivity – Injectivity problems will be reduced