ABSTRACT: The main goal of this research was to investigate the risk of caprock failure due to the SAGDOX process, a hybrid steam and in-situ combustion recovery process for oil sands. A temperature dependency extension to the linear and non-linear constitutive models was developed and implemented in the GEOSIM software. The analysis has shown that there is no increased risk of caprock failure for SAGDOX process compared to SAGD. The study has shown that the overlying Wabiskaw formation experiences shear failure during both SAGD and SAGDOX due to its low initial cohesion, friction angle and proximity to pressure and temperature front, although the failure was mainly driven by pressure propagation. However, Clearwater shale above Wabiskaw can still provide proper zonal isolation to the steam/combustion chamber under SAGDOX operating conditions. Uncertainty in the analysis is due mainly to the sparse nature of geomechanical properties data for the oil sand reservoir and the caprock formations, especially at temperatures over 200 C.
1.1 The SAGDOX process
Nexen Energy ULC (Nexen) has been evaluating SAGDOX - a post SAGD oxidation process (Kerr, 2012; Jonasson and Kerr 2013) - to improve the recovery and project economics of its Long Lake SAGD operation. SAGDOX is meant to be used after several years of SAGD operations when the bitumen between two SAGD well-pairs is mobile. In SAGDOX process (applied to a row of parallel well pairs) oxygen is coinjected with steam in every other SAGD injector well and starts an oxidation process by reacting with residual oil around the injection well. At this point the SAGD production well below the oxygen-steam injector is shut in and steam along with oxygen and combustion gasses fill the steam chamber voidage and push hot bitumen towards the neighbouring SAGD well-pair. The neighbour injection well is also shut-in and could be converted to a producer if need be. Various other well arrangements have been considered including those with vertical injection wells and infill horizontal production wells. Since oxygen is co-injected with steam, very high oxidation temperature of a pure combustion process are not generated as steam carries a large portion of the heat of combustion away from reaction front and temperatures are thereby moderated. Nonetheless, temperatures in the range of 400-600 deg C are expected in the oil sand zone. The high temperature combustion front where the oxidation reactions are active moves away from the oxygen injection wells as the residual oil left behind after steam displacement is consumed. The high temperature reaction zone has a tendency to move upward towards the cap rock under the influence of gravitational forces.
Producing from bitumen reservoirs overlain by gas caps can be a challenging task. The gas cap acts as a thief zone to the injected steam used during oil-recovery operations and hinders the effectiveness of processes such as steam-assisted gravity drainage (SAGD). Moreover, gas production from the gas cap can accentuate the problem even more by further depressurization of the gas zone.
Following a September 2003 ruling by the Alberta Energy Regulator (AER), the oil and gas industry in the province of Alberta, Canada, had approximately 130 million scf/D of sweet gas shut-in to maintain pressure in gas zones in communication with bitumen reservoirs. This decision led to the development of EnCAID (Cenovus' air-injection and -displacement process), a process in which air is injected into a gas-over-bitumen (GOB) zone, and combustion gases are used to displace the remaining formation gas while maintaining the required formation pressure.
An EnCAID pilot was started in June 2006, and preliminary results were reported in 2008. After 8 years of operations, the EnCAID project has not only proved to be effective at recovering natural gas and maintaining reservoir pressure, it has also shown it can heat up the bitumen zone and make the oil more mobile and amenable for production. This led to the development of the air-injection and -displacement for recovery with oil horizontal (AIDROH) process.
The AIDROH process is the second of two distinct stages. First, an air-injection well is drilled and perforated in the gas cap. The well is ignited and air injection is performed to sustain in-situ combustion in the gas zone. This phase is characterized by a radially expanding combustion front, accompanied by conduction heating into the bitumen below. The second stage begins when horizontal wells are drilled in the bitumen zone. The pressure sink caused by drawing down the wells alters the dynamics of the process and creates a pressure drive for the combustion front to push toward the producers in a top-down fashion, taking advantage of the combustion-front displacement and gravity drainage.
In light of the temperature increases observed in the bitumen overlain by the EnCAID project, a horizontal production well was drilled in late 2011 and commenced producing in early 2012. This paper provides an update of the EnCAID pilot results and presents a summary of the technical aspects of the AIDROH project, pilot results, and interpretation of the data gathered to date, such as observation-well temperatures, pre- and post-burn cores, and temperatures along the horizontal producer.
Results indicate that the AIDROH process has the potential to maximize oil production from GOB reservoirs, and efforts continue to be made to optimize its design and operation.
Connacher's first oil sands project, the Pod One facility at Great Divide, has been operational since 2007. The successful SAGD project has produced approximately 7 million barrels of bitumen. During the past three and a half years, the impacts of certain predicted reservoir challenges and opportunities have become apparent.
While the quality of the oil sands in this first phase of Pod One is generally good, Pad 101 South in particular has geological zones that affect SAGD operation. This includes a bitumen lean zone, and a gas cap overlying the main bitumen channel/s. Early field results matched with detailed simulations have shown positive results in maximizing well pair production. For the purposes of this paper a lean bitumen zone differs from an aquifer in two ways. The lean zone is not charged, and is limited in size. The operation is also complicated by the fact the gas bearing zone has been depleted through earlier production.
Connacher's operating practice at Great Divide attempts to achieve a pressure balance between the 3 zones (rich oil sands, lean zone, gas cap) to reduce steam loss and maximize production rates. Reducing the pressure encourages steam chamber development growth horizontally and ensures that steam contacts the highly saturated bitumen areas. How this is achieved with the highest positive impact on well productivity is illustrated with operational data and analysis including the results of simulations that recommended the optimum operating strategies.
Bitumen is too viscous to be produced by conventional recovery methods and significant amounts are too deep to be recovered by mining, necessitating enhanced in-situ oil recovery techniques. The majority of operating and planned in-situ bitumen projects employ thermal techniques to lower the bitumen's viscosity, allowing it to be produced. The viscosity characteristics of the bitumen consequently have a significant effect on production rates and recovery. Bitumen viscosity and chemical composition variation with depth within a single reservoir column has been reported for many heavy oil and oil sand reservoirs in the Western Canadian Sedimentary Basin and elsewhere in the world.
This study investigates, through reservoir simulation, the effects of viscosity variation with depth on the SAGD process and the resulting produced oil characteristics. Oil characteristics, including chemical component and viscosity profiles were built into a variety of reservoir simulation models. The simulation results indicate that the produced oil viscosity and component concentration vary as the steam chamber develops. The trend of the produced oil characteristics is related to the original in-situ profiles of and the reservoir flow barriers. In conjunction with oil rate, surface heave, or other available data, the produced oil characteristics may be used to suggest steam chamber development and the presence of barriers or baffles. The presented approach has potential to become a useful technique for SAGD steam chamber growth monitoring and production optimization.
Oil viscosity and compositional gradients, both areal and vertical have been observed in various fields worldwide1. Differences in physical properties and chemical composition of oil are more significant in heavy oil and oil sands reservoirs2. Recently, more attentions has been paid to heavy oil and oil sands reservoirs in the Western Canadian Sedimentary Basin, where 172.7 billion barrels of bitumen and heavy oil are to be recovered3, mostly through thermal processes, such as CSS (cyclic steam stimulation) and SAGD (steam assisted gravity drainage). Erno et al. found that the viscosity increases towards the bottom of the reservoir for Clearwater B, McMurray, and Wabiskaw formations at Caribou Lake, and Waseca formation at Pikes Peak with up to an order of magnitude difference in the Clearwater B formation. It was suggested that the viscosity variation may affect the performance of CSS, the proposed recovery process for those reservoirs, and should be considered in reservoir characterization and modeling4. Chan et al.5 reported vertical variations of certain chemical compounds in a McMurray Formation corehole in the Athabasca area (re-plotted in Figure 1). They showed that the ratio of diasterane to regular sterane increases from the top to the bottom of the reservoir. Based on the observed baseline of chemical compound distribution, a field application was demonstrated that used the chemical compound concentration from the produced sample to diagnose the CSS performance5.
Oil sands geomechanics plays an important role in the oil sands recovery processes, such as surface mining, cyclic steam stimulation and SAGD, which are widely applied in the development of oil sands resources in Alberta, Canada. Coupled reservoir geomechanical simulation techniques have been developed and used for the design of in situ recovery processes, particularly for SAGD. Thus, a realistic geomechanical model of oil sands material is a critical component in these reservoir geomechanical simulations. This paper presents the development of an oil sands model based on the analysis of laboratory testing results provided by different researchers, including Oldakowski, Samieh and Wong, and Touhidi-Baghni. On the basis of this analysis, 25 numerical experiments were conducted to match these laboratory tests, including the stress paths, as those applied in the laboratory experiments. Consequently, a comprehensive geomechanical model of oil sands material was established based on these numerical experiments. The proposed strain softening model parameters, such as the modulus of elasticity, peak and post-peak friction angle, and dilation angle, can be applied in the coupled reservoir geomechanical simulations of thermal recovery processes, including the SAGD process.
The development technology of oil sands reserves in Alberta, Canada, introduced a series of issues associated with the geomechanical properties of oil sands material. The surface mining technology and in situ recovery processes, such as cyclic steam stimulation (CSS) and steam assisted gravity drainage (SAGD), are both widely applied. Oil sands geomechanics has been studied in these areas, such as the improvement of surface mining efficiency, reservoir deformation regarding in situ thermal recovery, hydraulic fracturing during the cyclic steam stimulation process, and the prediction of in situ recovery performances.
The geomechanical properties of oil sands have been stud\ied extensively since 1970s(1) (2) (3) (4) (5) (6). With increasing experience in sampling and testing, good quality data can be obtained from lab testing. In this paper, the most recent laboratory testing results from Oldakowski(4), Samieh and Wong(5), and Touhidi-Baghini(6), are analyzed and simulated in order to obtain a representative geomechanical model of oil sands material.
Laboratory Testing on Oil Sands
Oldakowski's Lab Tests. Oldakowski(4) conducted a series of triaxial compression tests with different stress paths based on relatively undisturbed oil sands cores to characterize the stress-strain relationships of oil sands material. These oil sands cores were obtained from wells drilled at the AOSTRA Underground Facility Test Phase A site in 1987. In total, 23 oil sands samples were obtained from wells AT3 and AGI4 at two stratigraphic units, E and D, which consist of the richest oil sands at the UTF site.
These effects are easily reproduced with simple 1D column simulations. Solution gas has a material impact on SAGD production rates in general, which explains the need to use arbitrarily low permeabilities when history matching with no gas in the model.
John K. Donnelly* and M. J. Chmilar
Steam Assisted Gravity Drainage (SAGD) is the key to the economic exploitation of over 40 billion barrels (6.35 x 109 m3) of bitumen from the McMurray formation. The SAGD technology has been proven in two stages of piloting and is ready for commercial application. Engineering and economic studies indicate that the SAGD technology can be applied at a unit cost that is substantially below the market price for bitumen which has been at an average often dollars per barrel at the field gate over the last few years.
Based upon the premise that SAGD recovery is feasible throughout the Athabasca area, in reservoirs whose quality equal or exceed that found at the SAGD pilot site, an evaluation study was undertaken. The objective of the study was to map projected bitumen recovery and steam oil ratio as determined for a conceptual commercial SAGD recovery scheme.
The study applied geological and engineering criteria based on current projections of SAGD performance and a conceptual commercial recovery scheme, to analytically derive predictions of cumulative steam oil ratio (CSOR) and bitumen recovery. The study involved evaluating models for estimating SAGD CSOR and bitumen recovery; applying the most suitable model to generate CSOR and bitumen recovery predictions using screened geological data from an Athabasca well data base; then plotting contour lines representing the predicted CSOR and recovery values on a surface map of the Athabasca deposit. The contoured maps outline areas where it is expected that a CSOR of 3.5 m3/m3 or less and a bitumen recovery of greater than 10,000 cubic meters (63,000 barrels) per hectare which is equivalent to an average bitumen production rate of 250 barrels (40 m3) per day over a five year well life from 800 meters long well pairs spaced 90 meters apart.
The maps highlight locations in Athabasca where the best reservoir performance would be expected and delineates the areas which should be studied in detail for commercial application of the SAGD technology.
The petroleum industry has long been interested in potential methods of increasing recovery from oil reservoirs. The energy necessary to produce a satisfactory increase in recovery has been supplied through use of a secondary fluid to displace, heat, and/or dilute the original reserve.
This paper describes a laboratory investigation into the application of electrical energy as a recovery agent in impermeable tar sands. The preliminary study presented has shown that flow continuity can be established and maintained in laboratory tar sand models solely by application of electrical energy. Formation of an electrically carbonized zone of 10 darcies permeability, high oil recovery, moderate thermal-productive requirements, and the production of qualitatively important proportions of electrocarbonization gas have been demonstrated with linear laboratory tar sand models. The size of the permeable channel created was found to be a function of the amount of electrical energy applied. Principal mechanisms responsible for these results have been identified as electrolytic and electronic conduction, electrical resistance heating, viscosity reduction, thermal expansion, and distillation with pyrolysis. Theoretical considerations on the effect of electrolyte content on the over-all resistivity of rock and electrode-earth contact resistance and heating rates arc discussed. Preliminary results of electrogasification and dielectric breakdown experiments with tar sands are mentioned.
Application of thermal energy, as a means of increasing oil recovery from petroleum reservoirs, has received considerable industry interest during the past few years. The problem of producing highly viscous oils and tars presents an even greater challenge because of their tremendous reserve and because thermal recovery by fluid injection methods is not applicable for situations where sufficient flow continuity between wells cannot be established or maintained.
Thermal recovery techniques which have received greatest attention are the injection of air to support underground combustion, the injection of steam, the injection of-hot water, and detonation of thermonuclear devices within oil bearing formations. Use of electrical energy has recently been considered for bottom-hole heating within a single wellbore in order to initiate combustion, or to heat injected or produced fluids. Standard resistance heating elements lowered by conductor cable are usually selected for such purposes. An alternate technique is to utilize the natural earth resistance between two electrodes spaced a considerable distance apart. This technique has been successfully applied to electrocarbonization" experiments with coal and oil shale. However, no recent laboratory work has been reported in application of this technique to the recovery of crude oil from sands.
In the coal and oil shale investigations, the electrocarbonization treatment was found capable of creating a tortuous and permeable fixed-carbon channel, or "electrofracture", through the otherwise impervious strata. Somewhat similar results have been reported by Bill and Davis for oil sands and shales. In their experiments however, dielectric breakdown was used to create the permeable-conductive channel. They also found potential requirements for dielectric breakdown of an oil bearing formation was dependent on electrode spacing which precludes commercial application. On the other hand, electro-linkage - electrocarbonization processes have demonstrated their feasibility by successfully linking through 150 ft of coal with a maximum applied potential of 2,500 v. Total energy requirements for specific electro-thermal applications have been estimated for sands and commercially measured for oil shale.