PRISM :: Browsing by Author "Chen, Zhangxin"

Browsing by Author "Chen, Zhangxin"

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Open Access
A Galerkin Finite Element Method for Numerical Solutions of the Modified Regularized Long Wave Equation
(2014-06-19) Mei, Liquan; Gao, Yali; Chen, Zhangxin
A Galerkin method for a modified regularized long wave equation is studied using finite elements in space, the Crank-Nicolson scheme, and the Runge-Kutta scheme in time. In addition, an extrapolation technique is used to transform a nonlinear system into a linear system in order to improve the time accuracy of this method. A Fourier stability analysis for the method is shown to be marginally stable. Three invariants of motion are investigated. Numerical experiments are presented to check the theoretical study of this method.
Open Access
A linear, stabilized, non-spatial iterative, partitioned time stepping method for the nonlinear Navier–Stokes/Navier–Stokes interaction model
(2019-07-03) Li, Jian; Huang, Pengzhan; Su, Jian; Chen, Zhangxin
Abstract In this paper, a linear, stabilized, non-spatial iterative, partitioned time stepping method is developed and studied for the nonlinear Navier–Stokes/Navier–Stokes interaction. A backward Euler scheme is utilized for the temporal discretization while a linear Oseen scheme for the trilinear term is used to affect the spatial discretization approximated by the equal order elements. Therefore, we only solve a linear Stokes problem without spatial iterative per time step for each individual domain. Then, the method exploits properties of the Navier–Stokes/Navier–Stokes system to establish the stability and convergence by rigorous analysis. Finally, numerical experiments are presented to show the performance of the proposed method.
Open Access
A Stabilized Mixed Finite Element Method for Single-Phase Compressible Flow
(2011-01-23) Zhang, Liyun; Chen, Zhangxin
We present and study a stabilized mixed finite elementmethod for single-phase compressible flow through porous media. Thismethod is based on a pressure projection stabilization method for multiple-dimensional incompressible flow problems by using the lowest equal-orderpair for velocity and pressure (i.e., the pair). An optimal error estimate in divergence norm for the velocity and suboptimal error estimatesin the -norm for both velocity and pressure are obtained. Numericalresults are given in support of the developed theory.
Open Access
Analysis of the Influence of Different Fracture Network Structures on the Production of Shale Gas Reservoirs
(2020-12-15) Yue, Ming; Huang, Xiaohe; He, Fanmin; Yang, Lianzhi; Zhu, Weiyao; Chen, Zhangxin
Volume fracturing is a key technology in developing unconventional gas reservoirs that contain nano/micron pores. Different fracture structures exert significantly different effects on shale gas production, and a fracture structure can be learned only in a later part of detection. On the basis of a multiscale gas seepage model considering diffusion, slippage, and desorption effects, a three-dimensional finite element algorithm is developed. Two finite element models for different fracture structures for a shale gas reservoir in the Sichuan Basin are established and studied under the condition of equal fracture volumes. One is a tree-like fracture, and the other is a lattice-like fracture. Their effects on the production of a fracture network structure are studied. Numerical results show that under the same condition of equal volumes, the production of the tree-like fracture is higher than that of the lattice-like fracture in the early development period because the angle between fracture branches and the flow direction plays an important role in the seepage of shale gas. In the middle and later periods, owing to a low flow rate, the production of the two structures is nearly similar. Finally, the lattice-like fracture model is regarded as an example to analyze the factors of shale properties that influence shale gas production. The analysis shows that gas production increases along with the diffusion coefficient and matrix permeability. The increase in permeability leads to a larger increase in production, but the decrease in permeability leads to a smaller decrease in production, indicating that the contribution of shale gas production is mainly fracture. The findings of this study can help better understand the influence of different shapes of fractures on the production in a shale gas reservoir.
Open Access
Analytical Modeling of Steam Injection and Steam-Solvent Co-Injection for Bitumen and Heavy Oil Recovery with Parallel Horizontal Wells
(2019-04-30) Keshavarz, Mohsen; Chen, Zhangxin; Harding, Thomas Grant; Chen, Zhangxin; Harding, Thomas Grant; Gates, Ian Donald; Maini, B. B.; Lines, Larry R.; Das, Swapan K.
Steam-assisted gravity drainage (SAGD) is recognized as one of the most promising techniques for the commercial in situ recovery of bitumen reserves. The process, however, is energy intensive and is economically challenged in thin and low-quality reservoirs. Years of small-scale testing have shown that adding small amounts of hydrocarbon solvents to steam can yield large gains in oil output and reduced emissions over the conventional SAGD (Rassenfoss, 2012). The process has been referred to with different names in industry and academia such as expanding solvent-SAGD (ES-SAGD), solvent aided/assisted-SAGD (SA-SAGD), SAGD+TM, solvent aided process (SAP) and so on. High costs of solvents compared to bitumen requires their optimized use. The numerical simulation complexities and run times can make the filed-scale optimization exercise extremely costly. Therefore, analytical models can play an important role for such a purpose and to increase the confidence in performance forecasting. This dissertation starts with a review of the primary analytical models available for SAGD and co-injection and discussion on their limitations. Then, a new universal modelling approach is proposed that is applicable to the both processes. The breakthrough in the modelling approach is the robust coupling of mass balance, energy balance and fluid flow in porous media. This approach solves the heat and mass transfer problems at the stationary base of the steam chamber where the drainage to the producer happens. Combining material balance and Darcy’s Law, it then estimates the bitumen production rate and chamber shape. Then, energy balance is incorporated to estimate the steam requirements. In addition, the new modeling approach closes the material balance on all the components which allows for the estimation of solvent requirements for a particular set of key performance indicators. The developed model is intended to be simple enough for practical applications. After validation against numerical simulation results, its application to history-matching, forward prediction, pre-screening and uncertainty analysis is demonstrated through a number of field case studies.
Open Access
Application of In-situ Upgrading in Naturally Fractured Reservoirs
(2021-01-22) Duran Armas, Jose Luis; Pereira-Almao, Pedro R.; Maini, B. B.; Aguilera, Roberto F.; Chen, Zhangxin; Mehta, Sudarshan A. Raj; Oldenburg, Thomas B. P.; Dalaï, Ajaỳ Kumar
The persisting low oil price and the need for more environmentally-friendly energy sources have driven the latest development of new technologies for the sector and, in particular, for heavy oil exploitation. Among those technologies, In-Situ Upgrading Technology (ISUT) offers downhole processing, leaving undesired products underground, enhanced oil recovery and reducing the upgrading cost. ISUT is a thermal recovery process that uses hot fluid to transport catalytic nanoparticles, creating a reactor around the wellbore. Supporting the pilot test of ISUT, planned for the Aguacate field at the central Gulf Coast region of Mexico, this thesis focus on reinforcing many technical aspects for that pilot test. A kinetic model was developed for the Aguacate heavy oil and its vacuum residue at reservoir conditions. Ten sets of temperature and residence time, similar to those used for mild hydrocracking processes but in the presence of a carbonate rock core. Moreover, five pseudo components were assigned to model the reaction inside the porous carbonate medium. These results were all utilized to create the kinetic model specific for this pilot test. The products' characterization showed moderate temperatures and longer residence times improve product quality, translating into preferred temperatures below 350 oC with longer residence times. The used set-up for the kinetic analysis replicated the reservoir environment, using a matrix and a fracture where the fluid could flow. This work confirmed the catalytic hydrogenation process in ISUT by measuring molecular markers' conversion into other organic products, indicating limits of catalyst concentration to avoid adverse effects that may result in excess paraffinic compounds, eventually risking their precipitation subsequent operating instabilities in the media. Lastly, the hydrogen consumption in the ISUT process was studied using ten experimental conditions to create a statistical model to predict the hydrogen consumed in the process. The model showed that hydrogen consumption is linear vs. temperature and reaction time.
Open Access
Application of Polymer and Nanomaterials for Improving Heavy Oil Recovery
(2019-09-10) Aliabadian, Ehsan; Sundararaj, Uttandaraman; Chen, Zhangxin; Maini, B. B.; Dong, Mingzhe; Lines, Larry R.; Mohanty, Kishore K.
Booming population growth and economic activity have contributed significantly to an increased demand for energy in the last few decades, specifically in Canada. A major source of energy is oil extracted from underground petroleum reservoirs. Utilizing current technology and equipment, only a small portion of oil can be produced and recovered. Steam-assisted gravity drainage (SAGD), used as a common technique to produce heavy oil in Canada (specifically in oil sands reservoirs), requires a lot of energy and negatively impacts the environment. Using environmentally friendly and cost-effective techniques instead of or combined with SAGD improves the extraction of oil from Canadian oil reservoirs. Reservoir pressure, which is a driving force for pushing oil toward production wells, reduces drastically in the early stages of oil production from underground resources. This leads to a significant decrease in oil production rate. To solve this problem, enhanced oil recovery (EOR) methods inject water, gas, or chemical solutions to maintain reservoir pressure. When water is injected (water flooding) into heavy oil reservoirs, it cannot push the viscous oil smoothly because of water’s lower viscosity as compared to oil. As a result, injected water tends to bypass the pores containing trapped oil and the flooding becomes inefficient. To overcome this problem, one method adds polymers to the injected water. The addition of polymers leads to a more uniform flooding by increasing the viscosity of the injected fluid. Unfortunately, this approach suffers seriously from degradation of polymers at high temperatures and precipitation of polymers due to interaction with ions like sodium and calcium in brine. To solve these problems, the addition of nanomaterials to a polymer solution is highly recommended. The main focus of this PhD dissertation is to evaluate the effect of surface chemistry and geometry of nanomaterial on creation of a network with large polymer molecules. In addition, to mimic the large deformations in converging and diverging pores in porous media, linear and nonlinear rheology were employed to characterize the mechanical and flow behaviors of these hybrid dispersions. Sandpacks were used as the porous media to simulate oil reservoirs. Different hybrid dispersions were injected into sandpacks and the yield of recovered oil was reported. Results of this work can pave the way for use of polymer/nanomaterial solutions for heavy oil recovery. This study also demonstrated that large deformation oscillatory shear tests can be employed to distinguish flow behavior of hybrid systems. It was also shown that interaction between polymer and nanomaterial affects network structure and, consequently, oil recovery. Furthermore, size of nanomaterial compared to pore size distribution of porous media is a significant parameter that should be considered. The outcomes of this study could be helpful in improving heavy oil recovery in thin oil formations such as the Cardium, Montney, and Ostracod formations. These formations are too thin to utilize processes like steam-assisted gravity drainage and solvent vapor extraction, making this technique significant for increasing oil recovery in Canadian heavy oil reservoirs.
Open Access
Asphaltene Mesoscale Aggregation Behavior in Organic Solvents
(2019-01-10) Ahmadi, Mohammad; Abedi, Jalal; Hassanzadeh, Hassan; Chen, Zhangxin; Ponnurangam, Sathish; Sanati-Nezhad, Amir; Torabi, Farshid
Asphaltenes have received significant attention over the past decade, primarily because of their complex self-assembly behavior that results in their aggregation and deposition either in the reservoir formation or the production facilities. The aggregation and deposition of asphaltenes causes severe problems in both upstream and downstream sectors of the petroleum industry. For this reason, significant effort has been expended in shedding light on the basic molecular and colloidal properties of asphaltenes to identify the key parameters controlling their stability in the crude oil mixture. Molecular simulations provided invaluable information on the main molecular mechanisms leading to the asphaltene aggregation and also the principal intermolecular forces governing this process. However, the high computational cost of these simulation approaches did not allow the scientists to fully produce the aggregation behavior of asphaltenes in the past. In this work, we aimed at studying the asphaltene self-assembly behavior at mesoscales wherein the primary colloidal particles portray the asphaltene nanoaggregates. The Brownian dynamics (BD) simulations have been utilized to investigate the aggregation behavior of asphaltenes in different solvent environments at various volume fractions of asphaltene nanoaggregates under no- and simple shear-flow conditions. The BD simulations enabled us to access significantly larger length and time scales compared to the molecular simulations resulting in complete reproduction of asphaltene aggregation hierarchy. The effects of asphaltene volume fraction, solvent quality, and the shear rate on the kinetics of aggregation, the internal structure of the formed aggregates, and the self-diffusion coefficients of asphaltenes were also discussed.
Open Access
Assessment and Improvement of Underground Coal Gasification Modelling
(2018-12-13) Jiang, Liangliang; Chen, Zhangxin; Farouq-Ali, S. M.; Abedi, Jalal; Jeje, Ayodeji A.; Gao, Yang; Gupta, Subodh C.
Underground coal gasification (UCG) is a process to convert coal in-situ into combustible synthetic gas (syngas). Oxidant is brought downhole through an injector for coal combustion and gasification while resulting syngas is extracted from a producer. UCG offers a better way to exploit coal resources over conventional mining with smaller environmental footprint. It has gained considerable attention in emerging economies, e.g., China and India, which are coal-rich nations and have an ever-increasing energy demand. As a complex coal thermal recovery process involving multi-physics and kinetics, knowledge gaps remain before UCG reaches large-scale commercial implementation. To enhance knowledge, this work applies a modified simulation tool to model certain important aspects of UCG, i.e., assessing critically the use of a reservoir simulator to model UCG, exploring the theory of a prior linking method of reverse combustion, studying the role of coal cleats in governing fluid flow and heat transport with regard to aquifer contamination, and investigating the progressive changes in coal pores associated with UCG. Additional modelling efforts were made to explore an extended practical importance of UCG. The prospect of applying UCG to mobilize contiguous heavy oil is studied and the feasibility of linking UCG with carbon storage and sequestration is examined.
Open Access
Characterizing Supercritical Methane Adsorption on Shale by a Multi-site Model
(2018-12-13) Wu, Zhe; Chen, Zhangxin; Azaiez, Jalel; Aguilera, Roberto F.
Shale gas, mainly consisting of adsorbed gas and free gas, has served a critical role of supplying the growing global natural gas demand in the past decades. Considering that the adsorbed methane has contributed up to 80% of the total gas in place (GIP), understanding the methane adsorption behaviours is imperative to an accurate estimation of total GIP. Historically, the single-site Langmuir-Gibbs model, with the assumption of a homogeneous surface, is commonly applied to estimate the adsorbed gas amount. However, this assumption cannot depict the methane adsorption characteristics due to various compositions and pore sizes of shales. In this work, a multi-site model integrating the energetic heterogeneity in adsorption is derived, which is also successfully validated with a series of measured adsorption isotherms in experimental conditions. Applying the proposed multi-site model for estimating GIP in shales can achieve more accurate results compared with using the traditionally single-site model. Furthermore, shale reservoir properties, such as reservoir porosity, a geothermal gradient, as well as a pressure gradient have been investigated and shown to affect the GIP.
Open Access
Experimental Analysis of Displacement Characteristics and Production Potential for Marginal Resources in Highly Developed Reservoirs
(2020-11-17) Liu, Chang; Chen, Zhangxin; Maini, B. B.; Pereira-Almao, Pedro R.
Waterflooding has become a common method for improving oil recovery in conventional oil reservoirs all over the world. Indeed, because most of the earlier exploited oilfields with large reserves have entered a development stage where high water cuts are present, new replacement resources are crucial so that conventional oilfield development will continue to meet increasing worldwide energy demands. The term – a marginal resource refers to those layers that have resource identification but cannot meet the criteria to be considered true reserves under the U.S Securities and Exchange Commission (SEC) standards. In this research, the properties and displacement characteristic are experimentally investigated and huge amounts of data, which was provided by CNPC, is analyzed to show the feasibility of economic production of marginal resources. First, a property data collection was analyzed, which can be used to have basic understanding of marginal resources. 104 cores are selected to finish six experiments to get more understanding about the uniqueness of properties. CT test results provided by CNPC are also analyzed to realize a correlation between clay mineral content and production efficiency. Finally, the feasibility of production is shown by a previous development test result. The test and analysis results show that compared to reserves layers, a marginal resource has abundant clay mineral, whose average is 5.5%, which results in a more water-wet rock and more formation damage during a displacement process. On the other hand, its producible oil amount is less than those from conventional sand reservoirs layers. A combined development plan passing a CNPC economy audit shows that the marginal resource can be economically produced.
Open Access
Experimental and Numerical Modelling of Hybrid Steam In-Situ Upgrading Process for Immobile Oil
(2020-09-08) Wills Lopez, Violeta Carolina; Pereira-Almao, Pedro R.; Chen, Zhangxin; Maini, B. B.; Mehta, Sudarshan A. Raj; Salahub, Dennis R.; Ovalles, César
The Canadian oil sands constitute the third largest accumulation of oil in the world. Various in situ recovery technologies are applied to extract the bitumen, most of them rely on steam injection which requires a large amount of energy while releasing a considerable amount of carbon dioxide. Because the bitumen produced from the Oil Sands is not pipeline transportable at surface conditions, it is necessary to improve its characteristics by lowering the viscosity and increasing the API gravity. An integrated concept for recovering and upgrading is presented by the In-Situ Upgrading Technology (ISUT), which partially replaces the injection of steam with a hot catalytic mixture that includes the heaviest fraction of the bitumen and hydrogen. ISUT is an alternative option for enhancing the recovery and upgrading the oil in the reservoir to produce a synthetic crude oil that meets the pipeline requirements reducing costs, environmental emissions, while eliminating diluent. In this work, a version of ISUT, which involves steam and hot nano-fluid injection, was evaluated by performing experiments in a vacuum insulated core-holder with a well arrangement similar to SAGD using the typical Athabasca reservoir properties and operating conditions of 450psig, 350⁰C and 8 hours of reaction-residence time. In-situ upgrading was assessed by performing comprehensive analyses such as viscosity, API gravity, simulated distillation, micro carbon residue, sulphur, and stability (P-value) of the products plus detailed characterization of the porous media after running the experiments. The main results indicated that the injection of the hot catalytic mixture enhanced the bitumen recovery and upgrading of the Athabasca vacuum residue. The occurrence of hydrogenation reactions allowed the production of upgraded products while coke formation was avoided.
Open Access
Experimental and Numerical Studies of Foamy Oil Displacement Mechanisms in Heavy Oil Reservoirs
(2019-04-25) Wang, Danling; Chen, Zhangxin; Moore, Robert Gordon Gord; Chen, Shengnan
Foamy oil behavior has proven effective for heavy oil recovery and typically generates as pressure depletes in the first recovery stage. It possesses a low gas-oil ratio, maintains reservoir pressure and leads to high production recovery. Because the energy exhausts at the end of the first recovery stage, a significant amount of heavy oil remains underground. Therefore, the research objective is to develop a feasible gas injection process for foamy oil generation by understanding the generation mechanisms between gas and heavy oil. In the research, the mechanisms of foamy oil generation are experimentally investigated and the gas injection process is optimized. First, a vertical visible slab model is built, which can observe foamy oil generated in a gas flow channel. Gas injection tests are conducted afterwards. The strategy is optimized by identifying key parameters including gas injection type, gas injection rate, gas injection pressure and contact time. The model and our experiments reveal the mechanisms of foamy oil generation: the gas slowly reacts with the heavy oil at the contact surface and the generated foamy oil is stripped away with continuous gas injection. The highest oil recovery factor of 37.36% can be obtained by injecting gas at the rate of 2.0 ml/min, under 4.5 MPa, and using a contact time of 4 hours. The injected gas is mixed with 30% CH4 (methane) and 70% CO2 (carbon dioxide). Numerical simulation is also employed to validate the feasibility of the gas injection method for generating foamy oil and enhancing recovery in heavy oil reservoirs.
Open Access
Fracture Height Propagation in Tight Reservoirs Using the Finite Element Method
(2021-01-26) Cai, Jiujie; Chen, Shengnan; Chen, Zhangxin; Gates, Ian Donald; Wong, Ron Chik Kwong; Zhang, Yin
In recent years, multi-stage hydraulic fracturing technology is widely applied in oil/gas industry all over the world as a successful treatment, especially in tight and shale reservoirs. The induced fracture geometries directly affect the post-stimulation production and economic profitability of the project and accurately predicting the fracture properties is quite important. In addition to fracture length and conductivity, fracture height is another critical parameter of the hydraulic fracturing treatments in the unconventional tight/shale formations. Multiple transverse fractures are usually created along the horizontal wells, where the mechanisms of fracture-height-containment can be complicated under conditions such as interactions with the natural fractures, as well as adjacent hydraulic fractures. In addition, the directions of the bounding layers may not be parallel with that of horizontal wells. Traditional fracture propagation models applied in industry do not include all the aforementioned factors comprehensively. This research targets to study the mechanisms of hydraulic fracture propagation, focusing on the fracture-height-containment in the scenarios of multiple fractures along the horizontal wells. Firstly, a two-dimensional numerical model is proposed to analyze the methodology of single fracture height propagation via the finite element method. Then, an analytical model is built to understand the mechanisms of the fracture height containment considering inclined bounding layers. Modeling results suggested that for the closely spaced multiple fractures which are growing simultaneously, the critical fluid pressure becomes larger, implying that the fracture height propagation is more difficult under such scenario. Fracture height propagates more easily when bounding layer inclination angle increases. Thirdly, a three-dimensional numerical model with cohesive method on the fracture height propagation is used to analyze the multiple fracture interactions and the effective fracture height and width in tight reservoirs. The influence of stress shadow and stress difference on effective fracture height has been investigated and results show that the interaction from adjacent fracture becomes more significant when fracture spacing is small. Fluid injection rate is also an important influencing factor on the hydraulic fracture width especially when flow rate is low. When stress shadow effect is strong, the interior fractures can hardly propagate, and the majority of the fluid volume goes into the exterior fractures.
Open Access
Geochemical Modeling of Oil-Brine-Rock Interactions during Brine-Dependent and Brine-CO2 Recovery Technique in Carbonate Petroleum Reservoirs
(2019-04-24) Awolayo, Adedapo Noah; Sarma, Helmanta Kumar; Nghiem, Long X.; Gates, Ian Donald; Dong, Mingzhe; Lines, Larry R.; Chen, Zhangxin; Kam, Seungihl
The brine-dependent recovery process involves the tweaking of the ionic composition and strength of the injected water compared to the initial in-situ brine to improve oil production. The recovery process has seen much global research efforts in the past two decades because of its benefits over other oil recovery methods. In recent years, several studies, ranging from laboratory coreflood experiments to field trials, admit to the potential of recovering additional oil in sandstone and carbonate reservoirs and has been well-explored on two frontlines, namely, brine dilution and compositional variation. However, many challenges have saddled the recovery process, such as disputes over the fundamental chemical mechanisms; difficulty with construction of a representative model to give reliable interpretation and prediction of the process, and these necessitate applicable solution. Therefore, this study explores the formulation of theory based on experimentally-observed behavior to couple equations of multicomponent transport and geochemical reactions. Mechanisms such as dispersion/diffusion, advection, instantaneous equilibrium reactions, and non-equilibrium rate-controlled reactions are captured in the construction of the numerical models. The DLVO theory of surface forces was also applied to rationalize potential determining ion interactions and to evaluate the contribution of each force component to the wettability change in the oil-brine-rock system and the characteristic oil recovery improvement. The model was applied to interpret recently-published results on the different approaches that have been explored in the application of brine-dependent recovery process in carbonate reservoir rocks. The focus being that identifying the dominant mechanisms responsible for the observed improved recovery will help substantiate the field application of the process. The study demonstrates that injected brines, containing potential determining ions depleted in NaCl, are more effective at improving recovery when it, and wettability alteration is much more pronounced at high temperatures. It was also illustrated that potential determining ion concentrations play a more significant role as compared to brine salinity reduction. The magnitude of the contribution of the electrostatic force to sustaining a stable water film increases with decreasing ionic strength, either through reduction of NaCl, Ca2+ or brine dilution, or increasing SO42- concentration. Mineral dissolution/precipitation is necessary for the pursuit of re-establishing equilibrium and should not be ignored in modelling different mineralogical carbonate rocks. The derived optimized thermodynamic parameters are demonstrated to be widely applicable. Although chalk and limestone differ by surface area and reactivity, the same thermodynamic parameters are applicable in modeling the recovery process in their respective reservoir rocks. There is a significant increase in relative injectivity for brine-CO2 recovery mainly due to more exposure to a higher amount of CO2-saturated-brine
Open Access
Geological Realization Rankings for Steam-Assisted Gravity Drainage (SAGD) Reservoir Dynamic Modeling
(2018-12-11) Tamer, Mohamed Rajab; Chen, Zhangxin; Elmabrouk, Saber Kh; Dong, Mingzhe; Husein, Maen M.
Geological realizations are generated using geological and petrophysical properties to capture the range of possible geologic variability presented in the reservoir under development. Reservoir dynamic modelling or reservoir simulation is typically conducted to identify the range of uncertainties in the geological realizations through fluid rates, volumes and recovery factors. Conducting dynamic SAGD reservoir simulation for all stochastic geological realizations for ranking is not viable in practice due to excessive amounts of computer time required especially when modelling a thermal process like SAGD. This thesis presents a novel approach that uses the geological realization characteristics including permeability, porosity, initial water saturation and block volumes to rank equal probable SAGD geological realizations in order to classify high, medium, and low performing SAGD realizations prior to SAGD simulation. This research work introduces five statistical averaging techniques, and then examines the coefficient of determination between the five statistical averaging ranking measures and the SAGD reservoir performance forecast of the SAGD geological realizations. These techniques encompass Permeability Mean (PM), Permeability Harmonic Mean (PHM), Block-Volume Permeability Harmonic Mean (BVPHM), Pore-Volume Permeability Harmonic Mean (PVPHM), and Bitumen-In Place Volume Permeability Harmonic Mean (BIPVPHM). To validate the five statistical ranking measures, nine generic SAGD realizations involving a shale slab of two different model grid dimensions and a number of seventy SAGD geostatistical realizations are examined. This research work also investigates ranking the SAGD geological realizations throughout the life of SAGD operations by comparing the coefficient of the determination between the ranking results and performance of SAGD geological realizations over 10 years of SAGD operations. The results indicate that the PM ranking technique can be used to explain the forecast of the SAGD performance of the generic geological realizations at early SAGD time up to 81% at most, whereas the PVPHM ranking technique can be used to explain the SAGD performance of the tested SAGD geostatistical geological realizations up to 74% at most. The introduced techniques can be included in a commercial dynamic reservoir package to re-process SAGD geostatistical geological realizations prior to conducting SAGD reservoir simulation studies on a selected group of the SAGD geological realizations for further reservoir simulation rankings.
Open Access
Impact of Water Saturation on Gas Storage in Clay-rich Shale
(2020-09-22) Zhu, Lihua; Chen, Zhangxin; Sundararaj, Uttandaraman
For shale gas reservoirs, to evaluate the total gas-in-place (GIP) requires us to estimate the adsorbed gas amount accurately because the adsorbed gas generally constitutes 40%-85% of the total GIPs. However, under geologic conditions, water saturations always exist in shale reservoirs, which largely decreases the natural gas adsorption capability of shale, thus affecting the reliability of shale gas resources evaluation. In this thesis, we have built a mathematical model for calculations about gas adsorption in shale clay in different water environments, where the Langmuir adsorption equation is adopted for the gas-liquid interaction between methane and dry clay surface, and the Gibbs equation is used to characterize the gas-liquid interaction between methane and an adsorbed water film. Through our calculation, with the water saturation in a 4-nm slit pore being 20%, methane adsorption capacity is decreased by 55.4%, compared with dry conditions; when the water saturation in a 4-nm capillary is 36%, methane adsorption capacity is decreased by 80%. This proposed model is then extended to porous media which follows the log-normal pore size distribution (PSD). Based on the results, we have found that the shapes and sizes of nanopores in shale can affect the moisture distribution features and gas adsorption capability. Influences of water on methane adsorption capability mainly acts as (i) an adsorbed water film in large pores decreases the affinity between methane and pore-walls; (ii) capillary water totally blocks some small pores and makes them loose abilities to adsorb methane. When the water saturation of the slit-pore porous media reaches 43%, with the 2-nm slit pores blocked by water, the gas adsorption capability declines by 50% compared with dry conditions. When the water saturation of the capillary porous media arrives at 45%, with the 3-nm slit pores blocked by moisture, the methane adsorption capacity is deceased by 70% compared with dry conditions.
Open Access
Instabilities of Nanofluid Flow Displacements in Porous Media
(2019-04-08) Dastvareh, Behnam; Azaiez, Jalel; Chen, Zhangxin; Gates, Ian Donald
The interface of two approaching fluids in porous media becomes unstable at strong enough flow rates when the viscosity of the displacing fluid is less than that of the displaced one. This phenomenon is studied to address the effect of nanoparticles (NPs) dispersed in the displacing fluid assumed fully miscible with the displaced one. The problem is first studied under isothermal conditions. The effects of the NP-induced additional properties such as the viscosity of the nanofluid, the Brownian diffusivity and the NP deposition are addressed on both the flow instability and the flow configuration. It was found that NPs attenuate the instability of an initially unstable flow, but this effect is mitigated in the presence of NP deposition. Moreover, the Brownian diffusivity was found to have a destabilizing effect, but it cannot make an initially stable system unstable. The study is then extended to include the thermal effects. This leads to the emergence of a new NP transport phenomenon known as thermophoresis in which NPs migrate in opposite direction of the temperature gradient. This effect is addressed in connection with other properties. Specifically, depending on whether a hot fluid is displacing a cold one or vice versa, the competition between the two transport mechanics, Brownian motion and thermophoresis, is found to lead to different trends in terms of the flow configuration and instability. Next, the catalytic roles of NPs on the flow and instability are investigated for approaching reactive fluids. The study is conducted under both isothermal and non-isothermal conditions resulting from the heat of the reaction. A new set of conditions is introduced to predict the instability of the isothermal case based on the species mobility ratios, which then leads to six different flow configurations. Finally, the coupled effects of the heat of reaction and thermophoresis on the flow configuration and the amount of chemical products are addressed.
Open Access
Investigation on effects of water-shale interaction on acoustic characteristics of organic-rich shale in Ordos Basin, China
(2024-07-26) Zhuang, Yan; Liu, Xiangjun; Chen, Zhangxin; Liang, Lixi; Zhang, Shifeng; Xiong, Jian; Zhang, Tiantian
Abstract The water-shale interaction affect the shale structure, leading to wellbore instability and increasing drilling costs. The extent of structural changes within the shale can be determined non-destructively by analyzing its acoustic characteristics. Experiments were conducted to investigate the acoustic properties of shale from the Yanchang Formation in the Ordos Basin before and after exposure to brines of varying types, soaking times, and salinities. The study investigated the effects of brine type, soaking time, and salinity on shale’s acoustic properties, including changes in acoustic wave propagation speed, P/S wave velocity ratio, and both time-domain and frequency-domain amplitudes. The results indicate that although the type of brine has a limited impact on the water-shale interaction, KCl exhibits a significant inhibitory effect. However, the soaking time and the brine salinity have a significant impact on the acoustic properties of shale. As the soaking time increases, the decrease in wave velocity increases, the P/S wave velocity ratio increases, and the decrease in time-domain amplitude increases. The amplitude of the main frequency in the frequency domain signal also decreases with the increase of reaction time, which is consistent with the analysis results of the time domain signal. As the salinity of brine increases, the decrease in wave velocity decreases, the P/S wave velocity ratio decreases, and the decrease in time-domain amplitude decreases. The amplitude of the main frequency in the frequency domain signal also decreases with the increase of brine salinity, which is consistent with the analysis results of the time domain signal. This work establishes the relationship between water-shale interaction and acoustic characteristics, which can quantitatively evaluate the degree of interaction between water and shale without damaging shale. Furthermore, this research provides new insights and guidance for predicting drilling collapse cycles and optimizing drilling fluid compositions.
Open Access
Machine learning-based models for predicting permeability impairment due to scale deposition
(2020-07-02) Ahmadi, Mohammadali; Chen, Zhangxin
Abstract Water injection is one of the robust techniques to maintain the reservoir pressure and produce trapped oil from oil reservoirs and improve an oil recovery factor. However, incompatibility between injected water and reservoir water causes an unflavored issue named “scale deposition.” Owing to the deposited scales, effective permeability of a reservoir reduced, and pore throats might be plugged. To determine formation damage owing to scale deposition during a water injection process, two well-known machine learning methods, least squares support vector machine (LSSVM) and artificial neural network (ANN), are employed in the present paper. To improve the performance of the LSSVM method, a metaheuristic optimization algorithm, genetic algorithm (GA), is used. The constructed LSSVM model is examined using real formation damage data samples experimentally measured, which was reported in the literature. According to the obtained outputs of the above models, LSSVM has a high performance based on the correlation coefficient, and infinitesimal uncertainty based on a relative error between the model predictions and the corresponding actual data samples was less than 15%. Outcomes from this study indicate the useful application of the LSSVM approach in the prediction of permeability reduction due to scale deposition, and it can lead to a better and more reliable understanding of formation damage effects through water flooding without expensive laboratory measurements.