Yang, Bin (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | You, Lijun (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | Kang, Yili (Engineering and Technology Research Institute, Southwest Oil & Gas Field Company, PetroChina) | Chen, Zhangxin (Department of Chemical and Petroleum Engineering, University of Calgary) | Yang, Jian (Engineering and Technology Research Institute, Southwest Oil & Gas Field Company, PetroChina) | Han, Huifen (Engineering and Technology Research Institute, Southwest Oil & Gas Field Company, PetroChina) | Wang, Liang (Engineering and Technology Research Institute, Southwest Oil & Gas Field Company, PetroChina)
In shale gas reservoirs, the fluid imbibition was quite common during well drilling and stimulation, and it also related with engineering designs such as the borehole instability control and hydraulic fracturing operation, which fluid spontaneous imbibition into shales became a hot issues. In current fluid imbibition models, the pore shape was usually assumed to be circular tube, whereas scanning electron microscope (SEM) images analysis showed that the pore shapes in shale derived a lot from the ideal circular pores. One of the approaches to correct the deviation between the pore shapes and the ideal circular pores was to introduce a pore shape factor into the imbibition model. This paper provided a model to calculate the shape factors for specific geometric pores, and then based on the shape and proportion analyses of the inorganic and organic pores in shale, a comprehensive pore shape factor can be obtained. For tested two shale samples, the comprehensive pore shape factor was 0.54 and 0.61. Taking the values into the fluid imbibition model, it showed that the predicted curves accord quite well with the experimental data, and if the pore shape factors were ignored, there would present an overestimation of 37.0% and 27.9%, respectively. It seemed that calculating the pore shape factor accurately and involving it in the imbibition model would be very essential when dealing with the experimental fluid imbibition data or conducted field fluid imbibition volume predictions.
The in-situ steam based technology is still the main exploitation method for bitumen and heavy oil resources all over the world. But most of the steam-based processes (e.g., cyclic steam stimulation, steam drive and steam assisted gravity drainage) in heavy oilfields have entered into anexhaustion stage. Considering the long-lasting steam-rock interaction, how to further enhance the heavy oil recovery in the post-steam injection era is currently challenging the EOR (enhanced oil recovery) techniques. In this paper, we present a comprehensive review of the EOR processes in the post steam injection era both in experimental and field cases. Specifically, the paper presents an overview on the recovery mechanisms and field performance of thermal EOR processes by reservoir lithology (sandstone and carbonate formations) and offshore versus onshore oilfields. Typical processes include thein-situ combustion process, the thermal/-solvent process, the thermal-NCG (non-condensable gas, e.g., N2, flue gas and air) process, and the thermal-chemical (e.g., polymer, surfactant, gel and foam) process. Some new in-situ upgrading processes are also involved in this work. Furthermore, this review also presents the current operations and future trends on some heavy oil EOR projects in Canada, Venezuela, USA and China.
This review showsthat the offshore heavy oilfields will be the future exploitation focus. Moreover, currently several steam-based projects and thermal-NCG projects have been operated in Emeraude Field in Congo and Bohai Bay in China. A growing trend is also found for the in-situ combustion technique and solvent assisted process both in offshore and onshore heavy oil fields, such as the EOR projects in North America, North Sea, Bohai Bay and Xinjiang. The multicomponent thermal fluids injection process in offshore and the thermal-CO2and thermal-chemical (surfactant, foam) processes in onshore heavy oil reservoirs are some of the opportunities identified for the next decade based on preliminary evaluations and proposed or ongoing pilot projects. Furthermore, the new processes of in-situ catalytic upgrading (e.g., addition of catalyst, steam-nanoparticles), electromagnetic heating and electro-thermal dynamic stripping (ETDSP) and some improvement processes on a wellbore configuration (FCD) have also gained more and more attention. In addition, there are some newly proposed recovery techniques that are still limitedto the laboratory scale with needs for further investigations. In such a time of low oil prices, cost optimization will be the top concerns of all the oil companies in the world. This critical review will help to identify the next challenges and opportunities in the EOR potential of bitumen and heavy oil production in the post steam injection era.
Dang, Cuong (Computer Modelling Group Ltd.) | Nghiem, Long (Computer Modelling Group Ltd.) | Nguyen, Ngoc (University of Calgary) | Yang, Chaodong (Computer Modelling Group Ltd.) | Mirzabozorg, Arash (Computer Modelling Group Ltd.) | Li, Heng (Computer Modelling Group Ltd.) | Chen, Zhangxin (University of Calgary)
Many attempts have been made to understand, design, and optimize a chemical flooding process; however, the current low oil price environment makes its implementation very challenging from an economics point of view. Recently, CoSolvent Assisted Chemical Flooding (CACF) has been considered as a promising approach to reduce the cost of surfactant-based recovery methods, especially in heavy oil reservoirs. More importantly, recent studies indicated that CACF can be efficiently applied at relatively low temperature, i.e., without the need of steam injection. This helps reduce for the cost of steam generation and injection, and the associated greenhouse gas effects. This paper presents a new development in modeling CACF using an Equation-of-State (EOS) compositional reservoir simulator.
We used a new approach to model the behavior of the oil-water-microemulsion system based on solubility data without modeling type III microemulsion explicitly. The results showed an excellent agreement with numerous chemical coreflooding data and are in agreement with a chemical floodingresearch simulator. The new development presented includes the effects of cosolvent on rheological properties and phase behavior of microemulsion in the CACF process, particularly microemulsion viscosity and interfacial tension.
The proposed model showed good agreement with four published CACF coreflood experiments in which surfactant was not used in alkali and polymer chemical slugs. This model efficiently captures the complex chemical reactionsoccurring in the CACF process, i.e., generation of in-situ soap based on reactions between alkali and a rich acid component in heavy crude oil. The model provides consistent results with laboratory coreflood data at different operating temperatures, which is very important for heavy oil reservoirs. The ultimate recovery factor by CACF coreflooding is about 97%, similar to ASP (Alkali, Surfactant and Polymer) coreflooding, but without the need of surfactant injection.
An expression is analytically presented for the shear dispersion, or Taylor (1953) and Aris (1956) dispersion, of a solute transporting in a coupled system, which consists of a matrix and a rough-walled fracture. To derive a shear-dispersion coefficient in a fracture with rough and porous walls, the continuities of solute concentrations and their fluxes are imposed at the fracture walls. The dispersion coefficient for the coupled system is obtained as a function of the Péclet number and relative roughness, where the latter parameter is defined as the ratio of the maximum height of the roughness to the minimum half-aperture of the fracture. Several models for fracture-roughness geometry, including periodically and randomly shaped roughness models, are applied to study the effect of fracture-aperture variation on dispersion. The dispersion coefficient for all rough-walled fractures identifies three different regions in terms of the degree of relative roughness. The results show that for small values of the relative roughness (0 < ε ≤ 0.1), the dispersion coefficient is at maximum for bell-shaped geometry and at minimum for triangular-shaped and randomly shaped geometries. When the relative roughness is within 0.1 < ε < 10, the dispersion is observed to be at maximum for rectangular-walled and at minimum for triangular-walled fractures. The results also reveal that for high values of the relative roughness (ε ≥ 10), the dispersion is higher for bell-shaped roughness, whereas the triangular-walled fracture results in the lowest dispersion. It is found that for all roughness geometries an increase in either the Péclet number or relative roughness leads to an increase in the dispersion.
Zhan, Jie (University of Calgary) | Soo, Eric (Texas A&M University) | Fogwill, Allan (Canadian Energy Research Institute) | Cheng, Shiqing (China University of Petroleum) | Cai, Hua (CNOOC Ltd.) | Zhang, Kai (University of Calgary) | Chen, Zhangxin (University of Calgary)
The application of horizontal well drilling coupled with the multistage fracturing technology enables commercial development of shale gas formations, which launches the energy revolution from conventional resources to unconventional resources. Some of the shale reservoirs, particularly the Eagle Ford shale, contain a wide range of hydrocarbon fluids covering from low GOR black oil and volatile oil to the rich and lean gas-condensate. With the progress of understanding the nature of shale reservoirs, we find that some hydrocarbons are stored as an adsorbed phase on surfaces of organic carbon. Meanwhile, laboratory and theoretical calculations indicate that CO2 has significantly greater sorption capability compared with some lighter hydrocarbons like CH4 and C2H6. Shale gas reservoirs are recently becoming the promising underground target for CO2 sequestration. In the paper, systematic numerical simulations will be implemented to investigate the feasibility of CO2 sequestration in Eagle Ford liquid-rich shale gas reservoirs and quantify the associated uncertainties.
First, a multi-continua porous medium model will be set up to present the matrix, nature fractures and hydraulic fractures in shale gas reservoirs. Based on the Eagle Ford gas condensate data, 14 components will be simulated in the compositional model. Meanwhile, we will investigate a three-stage flow mechanism which includes convective gas flow mainly in fractures, dispersive gas transport in macro pores and multi-component sorption phenomenon in micro pores. To deal with this complicated three-stage flow mechanism simultaneously, analytical apparent permeability which includes slip flow and Knudsen diffusion will be incorporated into a commercial simulator CMG-GEM. In addition, multicomponent adsorption/desorption lab data will be included in the model. A mixing rule is introduced to deal with the competitive adsorption phenomenon between the different components.
In the paper, an integrated methodology is provided to investigate the CO2 sequestration process. Simulation results indicate that the Eagle Ford liquid-rich shale gas reservoir is an ideal target for the CO2 sequestration. To some extent, the average reservoir pressure is maintained due to injection of CO2. But most of the pressure is trapped around an injector due to the tight formation. That is why the reservoir productivity is enhanced by the injection process. But the increment is very small. Hydraulic fracking which creates freeways for gas flow is the key to improve the reservoir performance. The pressure maintenance around the injector reduces the effect of the liquid blockage, which is a good sign to implement the cyclic inert gas injection to reduce the effect of the liquid blockage and enhance the reservoir performance ultimately. The multicomponent desorption/adsorption is a very important feature in a shale gas reservoir, which should be fully harnessed to benefit the CO2 sequestration process. Meanwhile, the multicomponent desorption/adsorption process will increase the condensate production, which will lead to severer liquid blockage. In addition, it will limit the gas production. Furthermore, we cannot ignore the contribution of slip flow and diffusion to the reservoir performance during the sequestration process. Based on the methodology provided in this paper, we can easily deal with the apparent permeability effect based on a commercial simulator platform.
Zhan, Jie (University of Calgary) | Soo, Eric (Texas A&M University) | Fogwill, Allan (Canadian Energy Research Institute) | Cheng, Shiqing (China University of Petroleum) | Cai, Hua (CNOOC Ltd.) | He, Ruijian (University of Calgary) | Chen, Zhangxin (University of Calgary)
The gas flow in shale matrix is of great research interest for optimizing shale gas development. Due to a nano-scale pore radius, the gas flow in the shale matrix may fall in flow regimes which include viscous flow, slip flow and Knudsen diffusion. On top of that, gas adsorption/desorption and stress-sensitivity are some other important phenomena in shale. In this paper, we introduce an integrated multi-scale numerical simulation scheme to depict the above phenomena which is crucial for the shale gas development.
Instead of Darcy's equation, we implement the apparent permeability in the reservoir-scale continuity equation to depict the gas flow (viscous flow, slip flow and Knudsen diffusion) in shale matrix. A Langmuir adsorption/desorption term is included in the reservoir-scale continuity equation as a generation term. To ensure the real-time desorption and adsorption equilibrium with gas production, an iterative mass balance check of pore wall surfaces (pore scale) is introduced. At each time step, the pore-scale and reservoir-scale mass balance should be satisfied simultaneously in each grid block. On top of that, the lab data of a Bakken reservoir which provides a relationship between a matrix pore radius reduction and the effective stress is integrated into the two-way coupling geomechanical process to simulate a stresssensitive shale formation.
This methodology examines the influence of each mechanism for the shale gas flow in the matrix. Instead of conventional pressure-independent Darcy permeability, the apparent permeability increases with the development of a shale gas reservoir. With the gas adsorption/desorption, the reservoir pressure is maintained via the supply of released gas from nano-scale pore wall surfaces. With the consideration of geomechanics, the apparent permeability is decreased due to the compaction of nano-scale pore radii, which leads to the maintenance of reservoir pressure. Due to the difference of compaction magnitude for each grid block, geomechanics create additional heterogeneity for a nano-pore network in shale matrix, which we should pay more attention to.
A novel integrated multi-scale methodology is introduced to examine the crucial phenomena in the shale matrix, which simultaneously takes into account the influence of flow regimes, gas adsorption/desorption and stress-sensitivity. An effective way is provided to quantify the above effects for the transient gas flow in shale matrix.
Nguyen, Ngoc T. B. (University of Calgary) | Dang, Cuong T. Q. (Computer Modeling Group Ltd.) | Yang, Chaodong (Computer Modeling Group Ltd.) | Nghiem, Long X. (Computer Modeling Group Ltd.) | Chen, Zhangxin (University of Calgary)
Steam Assisted Gravity Drainage (SAGD) has been widely applied to unlock hydrocarbon resources in oil sands reservoirs. This method uses steam, which is generated at the surface, to heat a formation and create a steam chamber around an injector. Past studies have indicated that reservoir heterogeneity is one of the crucial factors that directly affectthe performance of the SAGD process. This paper presents an innovative integrated modeling approach for evaluating, assisted history matching, and production forecasting of the SAGD process with the presence of a complex shale barrier system in oil sands reservoirs.
As SAGD is a strongly geological dependent recovery process and, unfortunately, there are many uncertainties associated with reservoir geology in reality. Therefore, it requires generating a large number of geological realizations to capture the critical effects of geology, especially with the presence of shale barriers, in history matching and field development planning of the SAGD process. To quantify the impact and improve the quality of history matching compared with the traditional method, an efficient integrated workflow has been developed in which geological information generated from a geological modeling package is automatically updated for a reservoir simulator and controlled by an intelligent optimizer in a big-loop modeling approach.
A detailed workflow on the integrated modeling approach that includes shale barriers for a typical oil sands reservoir is described in the first section of this paper. Shale bodies are geostatistically distributed in the geological models. A comprehensive parametric study was conducted with numerous geological realizations to identify the critical role of shale barriers in SAGD performance including shale geometry, shale length and thickness, shale distribution and proportions. Then the Bayesian algorithm with a Proxy-based Acceptance-Rejection sampling method is employed for assisted history matching of SAGD production profiles. With the presence of complex shale barriers, it requires simultaneous updating of both geological and reservoir engineering parameters. Using the proposed approach, the global history matching errors were drastically reduced in all production wells. Validation results indicate that the integrated modeling approach effectively helps to update the properties and distribution of shale barriers to find the closest geological distribution compared to the true solution. Finally, an ensemble of the best-matched simulation models is used to perform a probabilistic forecasting to capture the uncertainties in future production profiles.
Not limited to history matching ofthe SAGD process, the proposed approach can be also applied to different complex problems such as robust optimization for various recovery methods from conventional to unconventional reservoirs.
Hybrid steam and in-situ combustion recovery processes have shown advantages over pure steam injection for recovery of oil sands resources, particularly with respect to reducing costs and lowering requirement for water and natural gas. However, it has been very challenging to predict field performance of hybrid steam and combustion processes with a reasonable degree of confidence. Usually, a combustion front has a thickness of only a few inches and high resolution grids are required to capture the steep temperature, saturation and fluid composition gradients in the vicinity of the combustion front. Using high resolution, fine grids to improve accuracy of simulation requires excessive computation time and, therefore, may be impractical for field scale modelling. It is important to have a robust simulation tool to accurately predict reservoir performance without compromising the computational efficiency.
In this work, numerical modeling of a hybrid steam and combustion recovery process was performed in a typical Athabasca oil sands reservoir. A comprehensive new reaction kinetics model derived from laboratory results was incorporated to represent the complex chemical reactions in the combustion process. The hybrid recovery process utilized oxygen enriched air co-injection after several years of SAGD operation. In the numerical model, safe limits were set on producing well temperature and oxygen content of produced fluids. The initial grid size in the numerical model was at the centimeter scale resulting in large run time, and thus, in order to improve the computational efficiency, a dynamic gridding feature was applied. Parameters for controlling the creation of a dynamic grid and subsequently reverting back to the coarse grid have been examined in order to properly trigger the dynamic gridding feature in the model. Once the optimized dynamic gridding parameters were determined, several different well configurations were investigated. Comparisons were made between SAGD and hybrid steam/combustion processes in terms of cumulative water (steam) injection, cumulative oil production, and a steam-oil ratio.
By comparing the simulation results from the fine grid model and the dynamic gridding model, it has been found that the temperature gradient is the best criterion to use for controlling dynamic gridding compared to fluid saturation and/or composition criteria. The threshold value for the temperature criterion was determined to be 35°C. The model locates the fine grids in close proximity to the combustion front where the temperature and fluid saturation gradients are the steepest and it places the coarse grid blocks elsewhere in the model. Comparisons are made between the computation time and the accuracy of the simulation and these demonstrate that dynamic grid amalgamation reduces the computation time significantly while maintaining reasonable computation accuracy of simulation. Compared with SAGD, the hybrid steam/in-situ combustion process reduced cumulative water usage (steam injection) by 20% to 27%, while the cumulative oil production remained the same.
This paper provides a workflow for modelling of hybrid steam and combustion processes. Also, it is expected that this work will provide insights for field design of these hybrid thermal recovery processes.
Zhan, Jie (University of Calgary) | Lu, Jing (The Petroleum Institute) | Fogwill, Allan (Canadian Energy Research Institute) | Ulovich, Ivan (University of Calgary) | Cao, Jili Paul (University of Calgary) | He, Ruijian (University of Calgary) | Chen, Zhangxin (University of Calgary)
The application of horizontal well drilling coupled with the multistage fracturing technology enables commercial development of shale gas formations. To optimize the shale gas development, the transient gas flow in a shale formation is of great research interest. Due to anano-scale pore radius, the gas flow in shale matrix may fall in flow regimes which include viscous flow, slip flow and Knudsen diffusion. On top of that, gas adsorption/desorption and stress-sensitivity are some other important phenomena in shales. In this paper, we introduce a novel numerical simulation scheme to depict the above phenomena and predict the gas production from a multi-stage fractured horizontal well, which is crucial for the shale gas development.
Instead of Darcy's equation, we implement the apparent permeability in the continuity equation to depict the gas flow (viscous flow, slip flow and Knudsen diffusion) in shale matrix. An adsorption/desorption term is included in the continuity equation as an accumulation term. A sink which is based on Peaceman's well model is placed at the center of the fracture cell. Uniform fluid flow from matrix to fractures is assumed. Only viscous flow is considered in the fractures and the permeability of the fractures doesnot change with pressure. The model is validated via comparing with an infinity-conductivity fracture model. Moreover, the lab data of Eagle Ford shale which provides the relationship between matrix permeability and the effective stress is integrated into the two-way coupling geomechanical process to simulate a stress-sensitive shale formation. Furthermore, the Langmuir and BET models will be compared to investigate the detailed adsorption/desorption process.
This methodology examines the influence of each mechanism for the transient shale gas flow. Instead of conventional pressure-independent Darcy permeability, the apparent permeability increases with the development of a shale gas reservoir, which leads to higher productivity. With the gas adsorption/desorption, the reservoir pressure is maintained via the supply of released gas from nano-scale pore wall surfaces, which also leads to higher gas production. In addition, it yields a 5% difference for the cumulative production for one yearbetween the Langmuir and BET models. With the consideration of geomechanics, the apparent permeability is decreased due to the compaction of nano-scale pores, which leads to a decrease in productivity. Due to the difference of compaction magnitude for each grid block, geomechanics creates additional heterogeneity for anano-pore network in a shale formation, which we should pay more attention to.
A novel methodology is introduced to examine the crucial phenomena in a shale formation, which simultaneously takes into account the influence of flow regimes, gas adsorption/desorption and stresssensitivity. On top of that, the productivity of a multi-stage fractured horizontal well is quantified. We provide an effective way to quantify the above effects for the transient gas flow in shale formations.
Zhan, Jie (University of Calgary) | Han, Yifu (University of Oklahoma) | Fogwill, Allan (Canadian Energy Research Institute) | Wang, Kongjie (China University of Geosciences) | Hejazi, Hossein (University of Calgary) | He, Ruijian (University of Calgary) | Chen, Zhangxin (University of Calgary)
The gas flow in shale matrix is of great research interest for optimizing shale gas reservoir development. Due to a nano-scale pore radius, the gas flow in the shale matrix may fall in flow regimes which include viscous flow, slip flow and Knudsen diffusion. On top of that, the adsorbed and free gas is stored in nano-scale organic pores. The gas molecules are attached as a monolayer to pore walls to form a film of gas which is the thickness of the adsorbed layer. When a reservoir is depleted, the attached gas molecules will be released so that the radius of organic pores in which the free gas flows is changeable. Thus a sorption-dependent radius will be introduced to the apparent permeability which represents the flow regimes. Stress sensitivity will also be investigated via a two-way coupling geomechanics process. In this paper, we introduce a novel integrated numerical simulation scheme to quantify the above phenomena which is crucial for the shale gas reservoir development.
Instead of Darcy's equation, we implement the sorption-dependent apparent permeability in the continuity equation to depict the gas flow (viscous flow, slip flow and Knudsen diffusion) in shale matrix. The methodology which was developed by Vasina et al. and validated through comparing with molecular simulation will be implemented to determine the thickness of an adsorbed layer at each time step. The Langmuir adsorption/desorption term is included in the continuity equation as an accumulation term. In addition, lab data for a Bakken reservoir which provides a relationship between a matrix pore radius reduction and the effective stress is integrated into the two-way coupling geomechanical process to simulate a stress-sensitive shale formation.
This methodology examines the influence of each mechanism for the shale gas flow in the matrix. Overall, the sorption-dependent apparent permeability is smaller than the sorption-independent apparent permeability, which leads to the pressure maintenance for the sorption-dependent apparent permeability case. The sorption-dependent apparent permeability will lead to additional heterogeneity. The apparent permeability near a wellbore is bigger than the one far away from the wellbore, which causes the pressure transmit more easily around the production side. With the consideration of geomechanics, the apparent permeability is decreased due to the compaction of a nano-scale pore radius, which leads to the maintenance of reservoir pressure. Due to the difference of compaction magnitude for each grid block, geomechanics also creates additional heterogeneity for a nano-pore network in shale matrix, which we should pay more attention to.
The sorption-dependent radius is incorporated into the apparent permeability model to depict the sorption-dependent apparent permeability of shale matrix. We provide a novel integrated methodology to quantify the crucial transient phenomena in the shale matrix, which includes flow regimes, gas adsorption/desorption and stress sensitivity.