Bitumen Reservoirs Research Articles

Proof of Sinian Reservoir Bitumen in Sichuan Basin as Oil Cracking Cause

In order to reveal the cause of the largely distributing bitumen in Sinian reservoirs of Sichuan Basin, geochemical characteristics of the bitumen have been studied. From its microscopic optical characteristics, large proportion of the solid bitumen was found as cavity-filling. What’s more, the steroid and terpenoid biomarkers of the bitumen in the reservoir distribute normally, and 25-norhopane standing for degradation and washing function hasn’t been detected. Last but not least, condition of crude oil cracking was also possessed, as from the thermal evolution history of Sinian stratum of Sichuan. All of the above suggested that the bitumen was caused by oil cracking in the reservoir.

Practical process design for in situ gasification of bitumen

The province of Alberta, Canada hosts an estimated 170 billion barrels of crude bitumen reserves in the Athabasca, Cold Lake and Peace River deposits. These reserves are commercially recovered through surface mining or in situ recovery methods. Most of the produced bitumen is converted in surface upgraders to synthetic crude oil (SCO), a 31–33°API oil product. Next, SCO is converted to transportation fuels, lubricants and petrochemicals in conventional refineries and petrochemical industries. In situ recovery or mining as well as bitumen upgrading and refining are energy intensive processes that generate huge volumes of acid gas, consume massive volumes of water, and are costly. Bitumen upgrading requires hydrogen, and currently most of it is produced by steam reforming of methane. Alternatively, hydrogen can be generated by in situ gasification of bitumen. In situ gasification of oil sands is potentially more energy efficient with reduced emission to atmosphere since acid gases are sequestered to some extent in the reservoir. Also, water usage is lowered and heavy metals and sulfur compounds in the bitumen tend to remain downhole since the main product is gas. The objective of this research was to understand and optimize hydrogen generation by in situ gasification from bitumen reservoirs. The central idea was to recover energy from the reservoir in the form of hydrogen and bitumen. In situ combustion has been attempted in the field, in a pilot run at Marguerite Lake. In this pilot, the produced gas contained up to 20mole percent of hydrogen. In the current study, the Marguerite Lake Phase A main-pattern in situ combustion pilot was history-matched as a basis to understand a field-operated recovery process where in situ gasification reactions occur. Based on Marguerite Lake in situ combustion pilot observations, a new in situ bitumen gasification process, based on a Steam-Assisted Gravity Drainage (SAGD) well configuration, was designed and compared with conventional SAGD on the basis of energy investment, emission to atmosphere and water usage. The results show that the amount of energy produced per unit of energy invested for the in situ gasification process was greater than the steam alone recovery process with less than half the water usage. The cyclic injection of steam and oxygen as compared to steam injection alone can permit design of oil-alone to oil+syngas production processes.

A Comparative Field-Scale Simulation Study on Feasibility of SAGD and ES-SAGD Processes in Naturally Fractured Bitumen Reservoirs

Thermal processes are widely applied in heavy oil and bitumen reservoirs. Steam-Assisted Gravity Drainage (SAGD) and Expanding Solvent-SAGD (ES-SAGD) are the two most promising techniques for production of heavy oil and bitumen reservoirs. The feasibility and efficiency of the aforementioned processes have been studied extensively for sandstone reservoirs. As there are some naturally fractured heavy oil resources in the world similar thorough studies are necessary to find out the applicability of these processes in these types of reservoirs. In this work several numerical simulations have been performed to investigate the feasibility of these methods in naturally fractured reservoirs (NFR). Dual permeability option was applied in this study. This work tries to cover the effect of several parameters such as reservoir thickness, fracture permeability, matrix permeability, fracture spacing, steam quality and oil viscosity on SAGD and ES-SAGD processes. Results have elucidated that basically both methods are efficient and economically applicable in naturally fractured reservoirs. Recovery factor and cumulative steam-oil ratio (CSOR) were economical parameters to evaluate the performance of processes. However, in some cases net amount of injected energy and oil production rate were considered for evaluation too. Generally ES-SAGD had better performance based on the recovery factor, CSOR, oil production rate and net amount of injected energy. Effect of solvent type and concentration were studied for ES-SAGD process only. For this purpose, pentane, hexane and heptane were selected. Pentane displayed better performance in earlier periods of production; however the heavier solvents showed better recovery performance at later times.

Understanding the Heat-Transfer Mechanism in the Steam-Assisted Gravity-Drainage (SAGD) Process and Comparing the Conduction and Convection Flux in Bitumen Reservoirs

Summary SAGD is one successful thermal recovery technique applied in the Athabasca and Peace River reservoirs in central and northern Alberta, Canada. In SAGD, steam is injected into a horizontal injection well and is forced outward, losing its latent heat when it comes into contact with the cold bitumen at the edge of a depletion chamber. As a consequence, the viscosity of the bitumen falls several orders of magnitude, its mobility rises several orders of magnitude, and then it flows under gravity toward a horizontal production well located several meters below and parallel to the injection well. Heat-transfer mechanisms are pivotal to the SAGD process. Though heat energy is transferred from steam to reservoir by conduction and convection, heat transfer by convection is not considered in the classic SAGD mathematical models such as Butler?s. Researchers such as Butler and Stephens (1981), Reis (1992), Akin (2005), Liang (2005), Nukhaev et al. (2006), and Azad and Chalaturnyk (2010) considered conduction from steam to cold reservoir to be the only heat-transfer component. However, because the heat capacity of water is typically two to five times that of bitumen, convection caused by the mobile condensate flow in the reservoir may contradict these studies. Farouq-Ali (1997) was the first to criticize the assumption that there is only a thermal conduction mechanism in the SAGD process. He pointed out that with so much condensate flowing, convection would be expected to be the dominant heat-transfer mechanism, which can be plausible at high temperatures. In response, Edmunds (1999a) stated that on the basis of the associated change in enthalpy, the heat transfer into a cold reservoir because of convection is probably less than 5% of that because of conduction. Ito (1999) challenged Edmunds (1999a) statement, on the basis of Ito and Suzuki (1996, 1999) and Ito et al. (1998), pointing out that "this number, 5%; i.e., ratio between convection to conduction presented by Edmunds (1999a) is unrealistically low, (and) it should be in the range of 50%. This study examined the relative roles of convective and conductive heat transfer at the edge of SAGD steam chambers. In summary, the mathematical model developed in this study considered both conduction and convection, and the resultant output from the model is reasonably consistent with published field data. This study supports the idea that although convection can dominate near the chamber edge in high-water-saturation reservoirs, in bitumen-rich reservoirs, its contribution to heat transfer is less than 1% and can be neglected.

Understanding the Heat-Transfer Mechanism in the Steam-Assisted Gravity-Drainage (SAGD) Process and Comparing the Conduction and Convection Flux in Bitumen Reservoirs

Summary SAGD is one successful thermal recovery technique applied in the Athabasca and Peace River reservoirs in central and northern Alberta, Canada. In SAGD, steam is injected into a horizontal injection well and is forced outward, losing its latent heat when it comes into contact with the cold bitumen at the edge of a depletion chamber. As a consequence, the viscosity of the bitumen falls several orders of magnitude, its mobility rises several orders of magnitude, and then it flows under gravity toward a horizontal production well located several meters below and parallel to the injection well. Heat-transfer mechanisms are pivotal to the SAGD process. Though heat energy is transferred from steam to reservoir by conduction and convection, heat transfer by convection is not considered in the classic SAGD mathematical models such as Butler's. Researchers such as Butler and Stephens (1981), Reis (1992), Akin (2005), Liang (2005), Nukhaev et al. (2006), and Azad and Chalaturnyk (2010) considered conduction from steam to cold reservoir to be the only heat-transfer component. However, because the heat capacity of water is typically two to five times that of bitumen, convection caused by the mobile condensate flow in the reservoir may contradict these studies. Farouq-Ali (1997) was the first to criticize the assumption that there is only a thermal conduction mechanism in the SAGD process. He pointed out that with so much condensate flowing, convection would be expected to be the dominant heat-transfer mechanism, which can be plausible at high temperatures. In response, Edmunds (1999a) stated that on the basis of the associated change in enthalpy, the heat transfer into a cold reservoir because of convection is probably less than 5% of that because of conduction. Ito (1999) challenged Edmunds (1999a) statement, on the basis of Ito and Suzuki (1996, 1999) and Ito et al. (1998), pointing out that “this number, 5%; i.e., ratio between convection to conduction presented by Edmunds (1999a) is unrealistically low, (and) it should be in the range of 50%.” This study examined the relative roles of convective and conductive heat transfer at the edge of SAGD steam chambers. In summary, the mathematical model developed in this study considered both conduction and convection, and the resultant output from the model is reasonably consistent with published field data. This study supports the idea that although convection can dominate near the chamber edge in high-water-saturation reservoirs, in bitumen-rich reservoirs, its contribution to heat transfer is less than 1% and can be neglected.

The Effect of Geometrical Properties of Reservoir Shale Barriers on the Performance of Steam-assisted Gravity Drainage (SAGD)

Many bitumen reservoirs contain shale layers of varying thickness, lateral extent, and frequency. These shale layers, depending on their size, vertical and horizontal locations, and continuity throughout the reservoir, may act as a flow barrier and severely reduce vertical permeability of the pay zone and slow down the steam-assisted gravity drainage steam chamber development. Therefore, to improve productivity in these reservoirs, understanding of the effects of reservoir heterogeneities has become necessary. This work presents numerical investigation of the effects of shale barriers on steam-assisted gravity drainage performance when applied to produce mobile heavy oil. The most concern of the work is upon how different geometrical properties of these shale barriers, such as vertical and horizontal position, density, discontinuity, and dispersion through the reservoir, affect the steam-assisted gravity drainage performance and steam chamber development in above wells region. Simulation results showed that the performance of steam-assisted gravity drainage is lower in the case of presence of continued shale layers, their longer extension, and their higher density (number of shale layers per unit volume). As the vertical distance between the continued shale layer and injector decreases, the recovery factor will be less. Distribution scheme of the layers also affected the recovery performance and production rates, since higher was the produced oil in the case of scattered layers as compared to the case of stacked shale layers on top of each other. It was found that the effect of the aforementioned parameters on the ultimate oil recovery factor and production rates was less in the case of presence of discontinuities in the shale barriers.

Monitoring of SAGD Steam-Chamber Conformance by Using White-Noise-Reflection Processes

Summary Thermal stimulation of bitumen in oil-sands reservoirs is a critical requirement for the success of steam-based recovery processes such as steam-assisted gravity drainage (SAGD). If the bitumen is not heated, it remains at its original viscosity, often in the millions of centipoise and, thus, is not mobilized so that it cannot be moved to a production well. All oil-sands reservoirs are heterogeneous, both with respect to geology and fluid composition, and, thus, conformance of steam in the reservoir is not uniform. At present, real-time monitoring of the steam-conformance zone in the reservoir is not possible, and, thus, the spatial distribution of heat delivery to the reservoir is uncertain. In this research, a new method for detecting heterogeneity and monitoring steam chambers has been developed and tested by detailed thermal/acoustic reservoir simulation. Here, a thermal fluid-flow simulator was one-way coupled to a wave-propagation simulator (information passed is density alone) to evaluate the potential of identifying rock and fluid discontinuities during a SAGD operation with coded white-noise-reflection processes. Digital communication systems use coded white-noise processes to make advantageous use of unexpected reflections from environmental heterogeneities. The proposed theory and subsequent simulations reveal that it is possible to resolve the edge of the SAGD steam chamber and to image the heterogeneity within the reservoir as it evolves with white-noise-reflection methods. The properties of the signals described provide an opportunity for property detection at lower power levels and higher frequencies than traditional seismic methods. Furthermore, the signals are such that the noise from recovery processes and the native reservoir environment do not interfere with the detection methods, allowing for the monitoring method to be used concurrently with the recovery process.

Experimental and numerical study of initial water mobility in bitumen reservoirs and its effect on SAGD

Interstitial water in a water-wet bitumen reservoir can form a continuous water network, which allows reservoir water to flow throughout the reservoir. A primary objective of the paper was to develop an experimental method to measure the water effective permeability of the continuous water network in an unconventional oil–water system. In experiments, semi-permeable membranes were installed at the production end of sandpacks to create a stationary oil phase condition. Experimental results showed that the water phase could flow under low permeability at initial water saturations. A cylindrical capillary tube model was developed to analyze experimental results and it showed that different wetting film thicknesses inside a porous medium could alter the overall effective permeability under the same initial water saturation. In the case study, different reservoir simulation operations were performed to compare influences of initial water movement. It was concluded that, under a small amount of initial water movement across the boundary, the pressure profiles and flow patterns of reservoir water changed.

Geochemical characterization of solid bitumen (migrabitumen) in the Jurassic sandstone reservoir of the Tut Field, Shushan Basin, northern Western Desert of Egypt

Abstract Asphaltene-rich solid bitumen was identified within the pore spaces of the Middle Jurassic Khatatba sandstone reservoir in the Tut Field, Shoushan Basin, Egypt. Despite good reservoir properties have been detected, the solid bitumen forms barriers in the reservoir, which prevents economic petroleum production. Petrographical and organic geochemical techniques were applied in order to characterize the source rock of the bitumen and its formation mechanisms. Organic geochemical results confirm the presence of actively migrating non-biodegraded hydrocarbons within the Khatatba sandstones. Biomarker data suggest that the solid bitumen originated from a marine shale source rock that was deposited in mildly anoxic to suboxic conditions. Biomarker oil-source rock correlation with the organic‐rich sediments of the Khatatba Formation indicates that the shale and coaly shale within the Khatatba Formation are an effective source rock in the area. The natural deasphalting is the predominant mechanism for the formation of the asphaltene rich solid bitumen in the Khatatba sandstones. Adsorption of asphaltenes onto authigenic kaolinite played a major role in the fixation of bitumen. Furthermore, gas deasphalting caused by gas injection may have contributed to a phase change in the reservoir fluid and deposition of solid bitumen. The injected gas is generated from Khatatba Type III kerogen or older source rocks in the Shoushan Basin during the mature stage of hydrocarbon generation.

Monitoring of SAGD Process: Seismic Interpretation of Ray+Born Synthetic 4D Data

The objective of this study is to evaluate which production information can be deduced from a 4D seismic survey during the Steam-Assisted Gravity Drainage (SAGD) recovery process. Superimposed on reservoir heterogeneities of geological origin, many factors interact during thermal production of heavy oil and bitumen reservoirs, which complicate the interpretation of 4D seismic data: changes in oil viscosity, in fluid saturations, in pore pressure and so on. This study is based on the real Hangingstone field case of the McMurray formation in the Athabasca region (Canada). In previous works, an initial static model (geology, petroacoustic and geomechanical) has been constructed and a thermal production of heavy oil with two coupled fluid-flow and geomechanical models has been simulated. Seismic parameters (density, compression velocity and shear velocity) of the saturated rocks have then been computed from mechanical and reservoir parameters at several stages of the production. A repeated acquisition survey is modelled at different stages of SAGD production. This is performed using a 3D seismic modelling approach. To focus on the reflections generated within the reservoir zone, a target-oriented modelling is chosen. It is based on the ray+Born approach which permits to compute the P-wave elastic response by correctly handling the seismic amplitudes as a function of source-receiver offset. Real incoherent noise is added to the zero-phase synthetic data to produce a more realistic result. The noise-free and the noisy synthetic data are processed to get stacked and time migrated images. A simple processing workflow leads to image the steam chamber development, in particular its V-shape in radial section, and to observe time-lapse in the reservoir zone. An interpretation work is then carried out. Some seismic attributes like RMS values of amplitude changes between stages, energy, time differences of reservoir bottom between stages, etc. are computed from the synthetic (noise-free and noisy) seismic data. Some of these attributes prove to be robust to the noise and to show some production effect. Possible trends between these attributes and the modelled reservoir/geomechanical properties (lithofacies, pressure, temperature, steam saturation, etc.) are also evaluated. Finally, geobodies are extracted from the seismic attributes.

Technology Focus: Heavy Oil (March 2012)

Technology Focus The rapid growth in interest and in development activities related to unconventional oil and gas resources, including heavy oil, is clearly evident throughout the industry. One outcome has been a tremendous increase in the number of SPE papers written this past year on various topics associated with development and recovery optimization of heavy-oil reservoirs. Another is that petroleum-engineering departments at many more universities worldwide are actively engaged in teaching courses and performing research related directly to viscous- and/or heavy-oil recovery. One topic in particular has gained more attention: development and application of enhanced thermal-recovery methods that use various solvents as a means to improve recovery and to reduce operating costs significantly relative to conventional thermal projects. Continued knowledge development in this subject area through a combination of reservoir-scale physics and chemical-process analysis, simulation-capability advancement, laboratory testing, and field-piloting work is needed to enable operators to design and implement these methods effectively and commercially, especially for viable development of thinner, lower-quality heavy-oil reservoirs. One synopsis paper and a reading paper were selected to provide further insights regarding the potential and the challenges associated with the use of solvent-recovery techniques in such applications. The other papers were chosen to illustrate the variety and significance of the challenges operators may encounter in assessing and/or pursuing the development of heavy-oil reservoirs under different settings and conditions. These include various problems that had to be dealt with during testing of a heavy-oil well in an offshore location; the many planning issues, design tradeoffs, and performance considerations associated with the sequencing and conversion of a heavy-oil-field development from cold to hot production; the difficulties experienced in planning and conducting pilot operations in a high-viscosity oil field overlain by thick permafrost in the Russian Arctic; and the ability to achieve adequate recovery with steaming of fractured carbonate reservoirs. Recent literature also describes several interesting technology developments, modeling studies, and field-trial activities related to the use of in-situ combustion and electrical-heating methods as alternative heavy-oil-recovery techniques. Several additional papers present results from investigations of CO2 injection into heavy-oil or bitumen reservoirs to achieve both improved oil recovery and greenhouse-gas sequestration, while many others describe new developments and/or field experiences involving waterflooding and polymer flooding of heavy-oil reservoirs. The many papers written on these topics can be sourced through OnePetro. Recommended additional reading at OnePetro: www.onepetro.org. SPE 146671 A Semianalytical Approach for Estimating Optimal Solvent Use in a Solvent-Aided SAGD Process by Subodh Gupta, SPE, Cenovus Energy, et al. SPE 149917 Approaches to Development of High-Viscosity Oil Fields in Arctic Conditions by Example of the Russkoe Field by I. Edelman, OJSC TNK-BP Management, et al. SPE 150692 A New Perspective on Tracking Energy Transfer in SAGD Derived From 3D Numerical Field-Scale Simulations by C.C Ezeuko, SPE, University of Calgary, et al. SPE 144524 Recovery Mechanism of Steam Injection in a Carbonate Reservoir by Guo-Qing Tang, SPE, Chevron, et al. SPE 148966 Analysis of the First CHOPS Pilot for Heavy-Oil Production in Kuwait by Tirtharenu Sanyal, Kuwait Oil Company, et al. SPE 148917 Effect of Methane Coinjection in SAGD—Analytical and Simulation Study by Jyotsna Sharma, SPE, University of Calgary, et al.

Viscosity and other rheological properties of bitumen from the Upper Devonian Grosmont reservoir, Alberta, Canada

Viscosity is directly related to the mobility and quality of hydrocarbons in reservoirs, and its distribution is commonly heterogeneous. Therefore, viscosity has a great impact on the exploitation of heavy oil and bitumen reservoirs. Previous studies showed that viscosity measurements are problematic and are often inconsistent mainly because of the challenges of sample preparation and lack of a standard procedure for measuring viscosity in the oil and gas industry. This study aims to improve the characterization of reservoir viscosity by understanding the rheological properties of bitumen using bitumen samples from the Upper Devonian Grosmont reservoir, Alberta, Canada. This study shows that Grosmont bitumen is essentially a non-Newtonian fluid, exhibiting a distinctive shear-thinning behavior at low temperatures of less than 40C. With increasing temperature, however, the bitumen changes from a non-Newtonian fluid to a Newtonian fluid. At low temperatures, the viscosity variations can be divided into four stages. A standard viscosity called zero-shear viscosity is obtained from the viscosity variations and can be used throughout the reservoir as characteristic viscosity for Grosmont bitumen. The viscosity distribution in the Grosmont reservoir is complex and appears to be stratigraphically related. Bitumen samples from formation boundaries tend to have higher viscosities, suggesting more severe biodegradation at these locations. Possible causes for the observed patterns in the Grosmont include (1) oil-water contacts migrating up and down over time; (2) oil migration and/or biodegradation controlled by aquitards that divide the reservoir into hydrostratigraphically separated units; and (3) differences in microbial activity, that is, aerobic versus anaerobic, possibly controlled by the level of oxygenation over time.

DESIGN OF THE INJECTION STRATEGY IN EXPANDING-SOLVENT STEAM-ASSISTED GRAVITY DRAINAGE

Steam-Assisted Gravity Drainage is effective at extracting oil from heavy oil and bitumen reservoirs. However, steam generation by natural gas combustion can render the process uneconomic. It has been suggested that addition of injected solvents improves oil rates or at least maintains similar oil rates with reduced steam. This is the basis of the Expanding Solvent - Steam Assisted Gravity Drainage process. The central idea is that steam plus solvent is better than steam alone to recover heavy oil and bitumen. In this research, the steam and solvent injection strategy is designed by optimizing the cumulative steam-oil ratio by using simulated annealing and a commercial reservoir simulator.

Geochemical characteristics and origin of reservoir bitumens from Well Zhong 1 in the Katake Uplift, Tarim Basin

The source of marine crude oils from Tarim Basin is still disputed. However, research on the reservoir bitumens may provide a piece of new evidence to elucidate oil source. Geochemical characteristics of reservoir bitumens from different strata from Well Zhong 1 in the Katake Uplift were discussed here in detail. Pr/Ph ratios of reservoir bitumen from Well Zhong 1 range from 1. 14 to 1. 39, CPI ratios from 1.01 to 1.08, which indicates no odd-even predominance of normal alkanes, with OEP ratios ranging from 0.98 to 1.05. The contents of gammacerane and C28 sterane of reservoir bitumen from Well Zhong 1 are low, while dibenzothiophene series are abundant. Sterane isomerization maturity parameter and Ts/(Ts+Tm) ratio indicate that the reservoir bitumen from Well Zhong1 is mature to highly mature. Based on the differences in biomarker distribution, it is concluded that reservoir bitumen from Well Zhong 1, of which molecular parameters are contrary to those in Cambrian oil from Well Tadong 2, originated from the Upper Ordovician source rocks.

The Influence of Salt Concentration in Injected Water on Low-Frequency Electrical-Heating-Assisted Bitumen Recovery

Summary Steam injection is often not a good alternative for oil recovery from shallow bitumen reservoirs. For instance, the thin caprock creates the danger of steam breakthrough. For deeper reservoirs, the heat losses from injection wells may be prohibitive. A technology that may be better suited is oil recovery aided by low-frequency electrical heating of the reservoir. This technology, well known for environmental remedial applications, has been field tried recently, yielding promising results. The process uses electric conductivity of connate water to propagate an alternating current between electrodes, inducing the Joule heating of the reservoir. An associated problem is the appearance of hot spots around the electrodes that may be relieved by water circulation. However, the water circulation may have a significant effect on the heating process because the electric conductivity of the circulated water depends on its salt content. To find out the influence of salt concentration on process efficiency, we have studied the process of salt-water recirculation around an electrode using numerical simulation. The physical properties and operational data for Athabasca bitumen have been collected from the literature. The model built with Computer Modelling Group's STARS simulator and tested first with available analytical solutions has been validated, and the proper choice of the underlying grid and numerical tuning parameters has been verified. The process was also simulated at field scale for a common pattern of electrodes and production wells. The salt penetrated into the reservoir, far beyond the major water-circulation zone around the electrodes. This process increases the electric conductivity in a large region between electrodes, which improves the heating of the reservoir. The single-electrode simulation studies using different tools yielded similar results for a simple problem. More-complex (and more-realistic) field-scale simulations show that adding salt enhances the oil production. In practice, an upper concentration limit may be given by corrosion problems at the electrodes. The reservoir simulation of bitumen recovery assisted by low-frequency heating is a challenging multiphysics problem. The understanding of the influence of salt concentration on the circulated water provided by this work is an important key in process-design considerations.

Potential for hydrogen generation from in situ combustion of Athabasca bitumen

The volume of heavy oil and bitumen in Alberta, Canada is estimated to be about 1.7 trillion barrels. The majority of the produced heavy oil and bitumen in Alberta is converted in surface upgraders to synthetic crude oil, a crude oil with API gravity typically between 31 and 33° API, which in turn can be converted to fuel, lubricant, and petrochemical products in standard refineries. To upgrade bitumen requires hydrogen. In current practice, much of this hydrogen is generated from catalytic steam reforming of methane together with the water–gas shift reaction. This means that heavy oil and bitumen upgrading, as is currently done, requires large amounts of natural gas to generate hydrogen. The potential for in situ generation of hydrogen by gasification of bitumen reservoirs offers an attractive alternative which can also have both economic and environmental benefits. For example, hydrogen generated from bitumen gasification can also be used for in situ upgrading as well as feedstock for ammonia and other chemicals. The water–gas shift reaction also generates carbon dioxide which could be potentially sequestered in an in situ gasification process so that emissions to the atmosphere are reduced. This technology provides a potential clean method to produce fuel and feedstock material from bitumen, a relatively “dirty” fuel and feedstock oil, in addition to more energy efficient ways of extracting in situ heavy oils. However, to design in situ bitumen gasification processes requires a reaction model that provides a reasonable representation of the gasification reactions. Here, a new kinetic model is developed to examine the potential for hydrogen generation from Athabasca bitumen. The kinetic model consists of thermal cracking, oxidation/combustion, hydrogen generation and hydrogen consumption reactions. A comparison of the simulation results and experimental data from the published literature reveal that the new model can predict hydrogen generation from gasification of methane, Athabasca bitumen, and coke.

Stability of the edge of a SAGD steam chamber in a bitumen reservoir

Steam-Assisted Gravity Drainage (SAGD) is a key in-situ recovery process being used today to extract oil from bitumen reservoirs. In SAGD, an oil-depleted chamber of steam grows within the oil sands formation along a pair of horizontal wells and heats bitumen-laden oil sands at its edge. The viscosity of bitumen drops by up to five orders of magnitude when heated to above 200 °C and mobilized bitumen at the chamber edge flows under gravity to a production well located at the base of the chamber. If the steam chamber does not grow uniformly along the wellpair, then bitumen recovery is less than ideal. To raise the thermal efficiency, and consequently the economics, of the process, efficient heat transfer from chamber to the oil sands must occur and the chamber must grow uniformly along the entire length of the wellpair. If steam fingers develop at the edge of the chamber, then the heat transfer area enlarges and raises the thermal efficiency of the process since more heat is directed to the oil sands. In this research, the stability of the interface between the steam chamber and oil sands is examined by using linear stability theory. The results show that the stability is controlled by the difference between the energy content-weighted Darcy–Rayleigh numbers of the steam/water phases (displacing fluid) and the oil phase (displaced fluid). Also, the results show that at typical SAGD steam saturation temperatures, the chamber edge is unstable providing the steam quality at the edge exceeds about 50%.

Geochemical characterization of solid bitumen in the Chesterian (Mississippian) sandstone reservoir of the Hitch field, southwest Kansas

Solid bitumen was identified within the Mississippian Chester sandstone reservoir in the Hitch field, southwest Kansas. The adjacent Etzold field has similar reservoir properties but lacks solid bitumen, although the Hitch and Etzold fields were thought to be in pressure communication and have common source rocks. Hitch and Etzold crude oils and core extracts were characterized geochemically to gain a better understanding of the reservoir-filling history and geological and geochemical controls on solid bitumen formation in the Hitch reservoir. Based on a variety of geochemical characteristics, we propose that the Hitch and Etzold oils are mixtures derived from Ordovician and Late Devonian–early Mississippian (Woodford Shale) source rocks. The solid bitumen in the Hitch reservoir probably results from mixing of oils having different geochemical compositions, which filled the reservoir over an extended period. No evidence of severe biodegradation or thermal alteration is observed. A reservoir-filling scenario is proposed in an effort to explain why the Hitch oils are geochemically more heterogeneous than Etzold oils. Furthermore, gas de-asphalting and regional pressure drops as a result of post-Laramide orogeny may have contributed to a phase change in the reservoir fluid and deposition of solid materials by disturbance of thermodynamic equilibrium. The major significance of this study is related to improving our knowledge on the occurrence of the presence of solid bitumen in reservoirs that can introduce barriers into the reservoir, complicating waterflood operations and leading to erroneous oil-in-place calculations and subsequently lower than expected oil recovery.

Organic geochemical and fluid inclusion evidence for filling stages of natural gas and bitumen in volcanic reservoir of Changling faulted depression, southeastern Songliao basin

Recently, volcanic gas reservoirs in Yaoyingtai (腰英台) and Daerhan (达尔罕) tectonic belts in Changling (长岭) faulted depression of southeastern Songliao (松辽) basin have been discovered. Based on the compositions and isotopic values, the natural gas is characterized by high content of methane, low content of C2 +, and C1/C1–5 beyond 0.95. Also, the natural gas contains nonhydrocarbons including carbon dioxide with the content from 20% to 40% and minor amount of N2. Combined with the isotopic values, the natural gas is generated by humic kerogen and coal-derived type, but in Daerhan, the natural gas is probably mixed by oil type gas. From the measurement of lithology and fluid inclusions in volcanic rocks, the bitumen, liquid hydrocarbon, and gas hydrocarbon inclusions are present. Through the analysis of the single gas inclusion in volcanic reservoir, the content of carbon dioxide is low, so the carbon dioxide and hydrocarbon gas of the reservoirs are not accumulated at the same time. In addition, minor amount of bitumen in the reservoirs is formed by thermal evolution of the crude oils sourced from the Yingcheng (842557CE) Formation mudstones through the characterizations of the biomarkers. The distribution of homogenization temperatures presents two peaks, one with the liquid hydrocarbon filling stage, and the other with gas filling stage. However, in Daerhan tectonic belt, the second peak is gas and carbon dioxide mixed filling period probably. Combined with the homogenization temperatures of salt water inclusions, the oil and gas filling period is from Qingshankou (青山口) Formation to Nenjiang (嫩江) Formation in the research area. During the charging period, minor amount of inorganic carbon dioxide filled into the trap, but plenty of inorganic carbon dioxide from the end of Sifangtai (四方台) to Eogene periods was related with the structural movement.

Modelling of 4D Seismic Data for the Monitoring of Steam Chamber Growth During the SAGD Process

Summary This paper presents an integrated workflow for the interpretation of 4D seismic data to monitor steam chamber growth during the steam-assisted gravity drainage recovery process (SAGD). Superimposed on reservoir heterogeneities of geological origin, many factors interact during thermal production of heavy oil and bitumen reservoirs, which complicate the interpretation of 4D seismic data: changes in oil viscosity, fluid saturations, pore pressure, and so on. The workflow is based on the generation of a geological model inspired by a real field case of the McMurray formation in the Athabasca region. The approach consists of three steps: the construction of an initial static model, the simulation of thermal production of heavy oil with two coupled fluid-flow and geomechanical models and the production of synthetic seismic maps at different stages of steam injection. The distribution of geological facies is simulated on a fine grid using a geostatistical approach, which honours all available well data. The reservoir's geomechanical and elastic properties are characterized by logs and literature at an initial stage before the start of production. Production scenarios are run to obtain pore pressure, temperature, steam and oil saturations on a detailed reservoir grid around a well pair at several stages of production. Direct coupling with a geomechanical model produces volumetric strain and mean effective stress maps as additional properties. These physical parameters are used to compute new seismic velocities and density for each stage of production according to Hertz and Gassmann formulas. Reflectivity is then computed, and a new synthetic seismic image of the reservoir is generated for each stage of production. The impacts of heterogeneities, production conditions and reservoir properties are evaluated for several simulation scenarios from the beginning of steam injection to 3 years of production. Results show that short-term seismic monitoring can help in anticipating early changes in steam injection strategy. In return, long-term periods allow the behaviour of the steam chamber to be monitored laterally and in the upper part of the reservoir. This study demonstrates the added value of 4D seismic data in the context of steam-assisted heavy oil production.