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.
Chen, Mingjun (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | Kang, Yili (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | Chen, Zhangxin (University of Calgary) | Wu, Keliu (University of Calgary)
Shale gas production results from a series of multi-gas transport mechanisms over a wide range of pore sizes. Also, it depends on a real gas effect, a sorption layer effect and an effective stress sensitivity. Therefore, a model unifying all these factors is important to accurately evaluate multiscale gas flow capacity during production. Laboratory measurements and modelling techniques are combined in this work to propose a unified model for real shale gas flow behavior. First, pore structure of shale is deeply analyzed. Second, a weighted contribution of each mechanism to the total gas flux is established. Finally, a unified model is proposed considering a real gas effect, a sorption layer effect and an effective stress sensitivity. In order to validate this model, steady state flow experiments in shale cores are conducted. Also, methane adsorption experiments and effective stress experiments are applied to quantitatively find the effects of adsorption and poromechanical behavior on gas flow, which are used in the model parameters. Then this model is used to evaluate gas transfer capability of a shale gas reservoir over multiple pore sizes. It is shown that the dominant gas transport mechanism is different in different scale of pores/fractures. Moreover, the results show that the contribution of each flow mechanism changes obviously with a different pressure as the pore hydraulic radius ranges from 10-100nm. Then the effects of gas-solid properties, pore structure and temperature-pressure conditions on shale gas flow capacity with the pore sizes of ranging from 10-100nm are deeply analyzed, respectively. Finally, a specific methodology on evaluating multiscale gas flow capacity in shale is proposed considering gas-solid properties, a volume proportion of a pore hydraulic radius from 10-100nm and reservoir temperature-pressure conditions. This work systematically investigates shale gas flow behavior through a unified model and provides an alternative workflow for evaluating capacity of multiscale shale gas flow.
Dang, Cuong (Computer Modelling Group Ltd) | Nghiem, Long (Computer Modelling Group Ltd) | Nguyen, Ngoc (University of Calgary) | Chen, Zhangxin (University of Calgary) | Yang, Chaodong (Computer Modelling Group Ltd) | Bae, Wisup (Sejong University)
This paper presents recent advances in the subject of modeling and optimization of ASP (Alkaline, Surfactant and Polymer) flooding with: (1) a critical review of the state-of-the-art development of ASP flooding; (2) an efficient and accurate novel approach for ASP modeling for robust simulation of chemical processes in conjunction with oil, gas, and water flash calculations using an equation of state (EOS) simulator; (3) systematic validation of the new modeling approach with laboratory studies; (4) evaluation of a hybrid Low Salinity ASP recovery process; and (5) robust optimization of ASP field-scale design under geological uncertainties.
We used a new approach that can model the behavior of the surfactant-oil-water-microemulsion system based on solubility data. In the Type III system, the emulsion is distributed judiciously between the oil and water phases without the need to introduce a third liquid phase. This model captures most of the important physical and chemical phenomena in the ASP process. The model was then validated with numerous coreflooding experiments conducted by different research institutes as well as with a specialized chemical flood simulator. The newly proposed model is tested using different injection schemes and chemical formulations including negative salinity gradient, non-negative salinity gradient, and a series of benchmark coreflooding experiments. Excellent agreements between the model and the experiments in terms of oil recovery and pressure drop were achieved for all corefloods. In addition, the model was also proven to be highly consistent with both UTCHEM-EQBATCH and UTCHEM-IPHREEQC. More importantly, previous results obtained without the explicit modeling of Type III indicated that the recovery factor deviates significantly from the experimental data, whereas the pseudo two-phase approach in this paper gives an excellent match in all cases. This model has also been successfully applied to match the recovery of Alkaline-CoSolvent-Polymer flooding, which is a promising recovery approach.
We investigated the potential of hybrid low salinity ASP flooding in which Low Salinity Waterflooding (LSW) was implemented in secondary production and followed by ASP flooding. This approach can provide a superior performance compared to the conventional chemical flooding because it provides better oil recovery in the secondary stage and promotes the synergy between low salinity environment and ASP slugs. Finally, the proposed robust optimization workflow helps to increasea project NPV and significantly reduces the uncertainty range associated with geology.
Zhan, Jie (University of Calgary) | Yuan, Qingwang (University of Regina) | Fogwill, Allan (Canadian Energy Research Institute) | Cai, Hua (CNOOC Ltd.-Shanghai) | Hejazi, Hossein (University of Calgary) | Chen, Zhangxin (University of Calgary) | Cheng, Shiqing (China University of Petroleum-Beijing)
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. With the progress of understanding the nature of shale reservoirs, we find that some shale methane is stored as an adsorbed phase on surfaces of organic carbon. Meanwhile, laboratory and theoretical calculations indicate that organic-rich shale adsorbs CO2 preferentially over CH4. 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 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 this model, 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. A Langmuir isotherm model is used for CH4 and the multilayer sorption gas model, a BET model, is implemented for CO2. In addition, a mixing rule is introduced to deal with the CH4-CO2 competitive adsorption phenomenon.
In the paper, an integrated methodology is provided to investigate the CO2 sequestration process. Simulation results indicate that a shale gas reservoir is an ideal target for the CO2 sequestration. Even with the reservoir pressure maintenance due to the injection of CO2, the reservoir productivity is not enhanced. Hydraulic fracking which creates freeways for gas flow is the key to improve the reservoir performance. 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. In addition, we cannot ignore the contribution of slip flow and diffusion to the reservoir performance. Based on the methodology provided in this paper, we can easily deal with the apparent permeability effect using a commercial simulator platform.
Wang, Kun (Department of Chemical and Petroleum Engineering, University of Calgary) | Liu, Hui (Department of Chemical and Petroleum Engineering, University of Calgary) | Luo, Jia (Department of Chemical and Petroleum Engineering, University of Calgary) | Chen, Zhangxin (Department of Chemical and Petroleum Engineering, University of Calgary)
Unconventional petroleum reservoirs, such as shale gas and tight oil reservoirs, have changed the entire energy equation in the world. An accurate and efficient reservoir simulator is essential for the development and management of these reservoirs and the optimization of their production schedules. However, the gas storage and transport mechanisms in ultra-tight matrix, including gas adsorption/desorption, non-Darcy flow, and surface diffusion, are different from those in conventional petroleum reservoirs. In addition, hydraulic fracturing techniques are often required to achieve their economical production, which leads to existence of complex fracture networks in the unconventional reservoirs. These features of unconventional reservoirs make their accurate numerical simulations a big challenge. In this paper, we develop a simulator for fractured unconventional reservoirs, which takes the specific gas storage and transport mechanisms into consideration, employs a multiple interacting continua (MINC) model to handle well connected natural fractures, utilizes an embedded discrete fracture model to simulate large-scale disconnected hydraulic fractures, and uses a coupled model to efficiently describe multi-scale fractures with irregular geometries. To reduce the computational time, parallel computing techniques are also employed, with which large-scale reservoir simulation cases can be finished in practical time. From the numerical experiments, we can see that reasonable physical phenomena is captured and accurate predictions are performed by this simulator.
Yang, Min (University of Calgary) | Harding, Thomas G. (Nexen Energy ULC) | Chen, Zhangxin (University of Calgary) | Yu, Kuizheng (University of Calgary) | Liu, Hui (University of Calgary) | Yang, Bo (University of Calgary) | He, Ruijian (University of Calgary)
Steam injection is a widely used thermal technology to recover heavy oil and oil sands resources, while high operating costs have made it vulnerable to low crude oil prices. In-Situ Combustion (ISC) provides an alternative to steam injection with the advantage of low operating costs and high energy efficiency. Hybrid steam and ISC has great potential in oil sands recovery because it combines the advantages of both steam injection and ISC. Before design of this hybrid process, it is important to understand the displacement mechanisms during this hybrid process.
In this study, numerical simulation has been performed to investigate the performance of co-injection of an air and steam process at the experimental scale. A three-dimensional radial numerical model has been developed using CMG STARS to simulate a steam flood test and a combustion tube test. The co-injection of enriched air and steam was performed after a period of hot water flooding in the combustion tube test. Simulated temperature profiles and combustion front velocities were matched with experimental measured results, indicating that the high temeprautre oxidation (HTO) reactions were captured in the simulation. In order to understand displacement mechnisms, simulation results obtained from both tests have been compared and analyzed, including temperature profiles, a steam front velocity, residual oil saturation, and oil recovery.
It is found that co-injection of steam and enriched air has the potential to improve oil recovery. An ultimate recovery factor of around 90% is achieved for the co-injection of the steam and enriched air process, while the recovery factor is around 60% for the steam flooding test. This is because ISC is able to recover residual oil left behind by the steam flooding. However, steam still plays a dominant role in displacement of bitumen. The steam front propagates faster than the combustion front. Also, the steam front travels faster with the presence of the combustion front, indicating that the combustion front behaves as a heat source for steam front propagation. This work greatly increases the understanding of displacement mechanisms in a hybrid steam and combustion process.
Liu, Hui (University of Calgary) | Wang, Kun (University of Calgary) | Yang, Bo (University of Calgary) | Yang, Min (University of Calgary) | He, Ruijian (University of Calgary) | Shen, Lihua (University of Calgary) | Zhong, He (University of Calgary) | Chen, Zhangxin (University of Calgary)
New reservoir simulators designed for parallel computers enable us to overcome performance limitations of workstations and personal computers and to simulate large-scale reservoir models with billions of grid cells. With development of parallel reservoir simulators, more complex physics and detailed models can be studied. The key to design efficient parallel reservoir simulators is not to improve the performance of individual CPUs drastically but to utilize the aggregation of computing power of all requested nodes through high speed networks. An ideal scenario is that when the number of MPI processors is doubled, the running time of parallel reservoir simulators is reduced by half. In real simulation, numerical difficulties and performance problems appear when the number of MPI processors grows due to the deteriorating linear solver efficiency and increasing communication overhead, which are determined by a grid distribution.
The goal of load balancing (grid partitioning) is to minimize overall computations and to make sure that all MPI processors have a similar workload. Geometric methods divide a grid by using a location of cells while topological methods work with connectivity of cells, which is generally described as a graph. The geometric methods are much faster than the topological methods. This paper introduces a Hilbert space-filling curve method. A space-filling curve is a continuous curve and defines a map between a onedimensional space and a multi-dimensional space. A Hilbert space-filling curve is one special space-filling curve discovered by Hilbert and has many useful characteristics, such as good locality, which means that two objects that are close to each other in a multi-dimensional space are also close to each other in a one dimensional space. This property can model communications in grid-based parallel applications. The idea of the Hilbert space-filling curve method is to map a computational domain into a one-dimensional space, partition the one-dimensional space to certain intervals, and assign all cells in a same interval to a MPI processor. To implement a dynamic load balancing method, we need a mapping kernel that converts high-dimensional coordinates to a scalar value, and an efficient one-dimensional partitioning module that divides a one-dimensional space and makes sure that all intervals have a similar workload.
The Hilbert space-filling curve method is compared with other load balancing methods, such as the K-way method from ParMETIS and other geometric methods from Zoltan. The results show that our Hilbert space-filling curve is much faster than graph methods. It also has good partition quality. This method has been applied to reservoir models with billions of grid cells and linear scalability has been obtained on many parallel computing systems.
In the petroleum industry, accurately estimating wellbore heat loss in thermal recovery processes remains a critical problem. One difficulty lies in simulating heat transfer and fluid dynamics within wellbore annuli. A literature survey shows that the state-of-the-art thermal wellbore simulators use empirical correlations to calculate the heat loss through wellbore annuli. As more sophisticated wells have been drilled, there is a growing need for a more detailed wellbore annulus heat transfer model. In this study, a 2D transient mathematical model is proposed for the conjugate natural convection and radiation within wellbore annuli. The governing equations consist of a continuity equation, a vorticity transfer equation, an energy transport equation and a radiative transfer equation (RTE). A finite volume approach with a second-order upwinding scheme is implemented for discretization. Newton-Raphson iterations are deployed for linearization. The algorithm is validated by consistence in simulation results compared with benchmark numerical solutions with the Rayleigh number up to 107. Parameters such as an aspect ratio, a radius ratio and a conduction-to-radiation coefficient are examined. A case study on vacuum insulated tubing heat transfer using Marlin Well A-6 data demonstrates the merits of the developed program by the consistence of simulation results compared with field measurements.
Steam assisted gravity drainage (SAGD) is recognized as a profitable and stable approach to address the exploitation of heavy oil and oil sand resources. However, the efficiency of SAGD, a close relative of a sufficiently-expanded and uniformly-developed steam chamber, tends to be deteriorated by quick steam movement and high heterogeneity. Chemical additives and foam assisted SAGD (CAFA-SAGD) is a strategy proposed on this account. This study aims to analyze the mechanisms and phenomena involved.
The injection of chemical additives to promote in-situ foam generation reduces gas relative permeability by slow-moving and stagnant bubbles trapping. Also, lamella resists bubbles flow and increases apparent gas viscosity. The restriction of steam mobility thus favors a sufficiently-expanded steam chamber and the nitrogen co-injected to stabilize bubbles works as a separator between steam and overburden to reduce heat loss. Simultaneously, the interfacial tension reduction due to surfactants injection at a water/oil interface may influence phase behavior, which further leads to the solubilisation of residual oil. CAFA-SAGD is thus likely to increase heat efficiency and add oil output.
A homogeneous model is built to analyze CAFA-SAGD considering foam generation by snap-off and leave-behind, foam trapping in a porous medium and foam coalescence due to both the lack of surfactants and capillary suction. Besides, with the analysis of foam wall slip phenomena, a comprehensive foam property model is coupled to analyze shear thinning rheology and calculate lamella viscosity as a function of gas saturation and gas velocity. In addition, the influences generated by surfactant injection should be added. This study also develops an analytical FA-SAGD model based on Butler's finger rising model (1987) to show foam's effects on a steam chamber growth rate and shape. We derive the FA-SAGD model accounting for the retarded steam movement with higher steam viscosity and lower gas relative permeability. The foam viscosity is calculated as a function of gas saturation and a gas rate, and the modification of gas relative permeability is reflected with a higher gas residual saturation according to Bertin et al.'s foam property model (1998). After comparing, validating, and discussing the developed model against the SAGD model, we find that foam injection contributes to high production efficiency with less steam consumption. A lower steam mobility generated by stronger foam is more likely to have a lower SOR (steam-oil ratio).
The results agree well with the published high-temperature steam foam experiments and pilot tests. Strong bubbles accumulate along the boundary of a steam chamber to restrict steam movement, while weak foam fills inside the chamber to enhance steam trap, contributing to a higher oil recovery factor and lower SOR.