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Collaborating Authors
Chen, Zhangxin John
Investment Strategy of CO2-EOR in China: Analysis Based on Real Option Approach
Bi, Jianfei (China University of Petroleum, Beijing 102249, China) | Li, Jing (China University of Petroleum, Beijing 102249, China) | Chen, Zhangxin John (University of Calgary, Alberta T2N1N4, Canada) | Gao, Yanling (China University of Petroleum, Beijing 102249, China) | Liu, Yishan (China University of Petroleum, Beijing 102249, China) | Wu, Keliu (China University of Petroleum, Beijing 102249, China) | Dong, Xiaohu (China University of Petroleum, Beijing 102249, China) | Feng, Dong (China University of Petroleum, Beijing 102249, China) | Zhang, Shengting (China University of Petroleum, Beijing 102249, China)
Abstract As the most potential Carbon Capture, Utilization, and Storage (CCUS) technology, CO2-enhanced oil recovery (CO2-EOR) can both improve oil recovery and relieve the pressure of reducing CO2 emission. However, CO2-EOR projects have not been substantially deployed in China due to the significant investment and high uncertainties of technology, market, and policy. Therefore, identifying potential bottlenecks, and developing effective investment strategies are of great necessity at present. In this work, a real option approach combined with reservoir simulation technologies is proposed, which can investigate the optimal deployment timing and the investment value of the CO2-EOR projects. Meanwhile, a sensitivity analysis is conducted to examine the effects of different uncertainties. The results show that real option approach is suitable for the evaluation of CO2-EOR projects because it can fully take the flexibility of investment time into account. And it is found that under the current investment environment, it is difficult for China to deploy CO2-EOR projects on a large scale before 2030. High oil prices, low CO2 purchase prices, and transportation of CO2 by pipeline can bring forward the investment time and increase the investment value. Besides, government subsidies and technological progress are also favorable for the deployment of the project. Compared with technological progress, the effect of subsidies is more obvious, while it should be noted that huge subsidies will bring a financial burden to the government. In a word to launch CO2-EOR projects earlier and make it play a more important role in China's carbon emission reduction, a compound strategy should be made based on consideration of all these influencing factors.
- Asia > China (1.00)
- North America > United States (0.94)
- Asia > China > Jilin > Songliao Basin > Daqingzijing Field (0.99)
- North America > United States > Louisiana > China Field (0.97)
Modelling the Apparent Viscosity of Water Confined in Nanoporous Shale: Effect of the Fluid/Pore-Wall Interaction
Li, Jing (China University of Petroleum, Beijing & University of Calgary) | Chen, Zhangxin John (China University of Petroleum, Beijing & University of Calgary) | Lei, Zhengdong (Research Institute of Petroleum Exploration and Development) | Gao, Yan (Research Institute of Petroleum Exploration and Development) | Yang, Sheng (University of Calgary) | Wu, Wei (University of Calgary) | Zhang, Linyang (University of Calgary) | Yu, Xinran (University of Calgary) | Feng, Dong (China University of Petroleum, Beijing) | Bi, Jianfei (China University of Petroleum, Beijing) | Wu, Keliu (China University of Petroleum, Beijing)
Abstract The viscosity of nanoconfined fluid is a crucial parameter for evaluating the flow back of the fracturing fluid in unconventional reservoirs. Generally, the viscosity is an intrinsic property defined as the internal friction among fluid molecule themselves. However, the effect of the fluid/pore-wall interaction on the viscosity of fluid at the nanoscale becomes significant. Due to this strong confinement, two abnormal flow behaviors have been discovered, including an extremely high water-flow rate in hydrophobic nanotubes and an extremely slow capillary filling rate in hydrophilic nanochannels. Thus, understanding such contradictory hydrodynamics is helpful to estimate the flow performance of fracturing liquid in both organic pores and inorganic pores of shales. In this work, a concept of apparent viscosity of nanoconfined fluid is proposed, where the activation energies (indicating the energy barrier needed to be overcome for fluid motion) caused by both the fluid/ fluid interaction and fluid/pore-wall interaction are modeled. For the case with only fluid/fluid interaction, the apparent viscosity reduces to the bulk-phase viscosity, and this traditional case has been well studied. Thus, we mainly focus on the additional interaction energy caused by the pore walls during the motion of water molecules. To solve this problem, the fluid/pore-wall interaction, including an intermolecular term, an electrostatic term and a structural term, is considered to modify the Eyring's viscosity theory. Due to a repulsion term (e.g., the structural force) and an attraction term (e.g., the intermolecular force and the electrostatic force) both introduced in the surface interaction, the integrated interaction energy of fluid and pore-wall can be either positive or negative, which depends on the relative value of repulsion and attraction controlled by the pore-wall wettability. Finally, the contact angle of the pore surface is calculated by a DLVO theory (describing gas/water/solid interactions) related to the fluid/pore-wall interaction properties. The continuous viscosity profile of fluid confined inside nanochannels with different wettability and size can be directly obtained by the proposed method. Result shows that: (i) the presence of the pore-wall significantly influences the apparent viscosity of fluid. For a strongly hydrophilic channel with the contact angle approaching to zero, the average viscosity of first layer (assuming the monolayer thickness is 0.35 nm) can be 3โผ4 times higher than that of the bulk phase; whereas for a strongly hydrophobic case, the first-layer viscosity is about 2โผ3 times lower. Thus water molecules with the extremely high-viscosity close to the hydrophilic wall can be regarded as a sticking layer as the immobile state, and those with the low-viscosity near the hydrophobic wall can be regarded as the rare-density vapor due to the surface depletion effect. (ii) The average viscosity of the confined fluid is a function not only of the wettability but also of the confinement. When the pore dimension decreases to serval nanometers, the portion of water molecules in the interface region increases relative to the total water molecules present in entire nanopores, and the average viscosity is dominated by the apparent viscosity of fluids near the wall. Besides, (iii) it is worth noting that the effect of pore wall on the apparent viscosity reduces sharply, the apparent viscosity approaches to the bulk-phase viscosity when the fluid-wall distance is about 0.7-1.2 nm, corresponding to two or three molecular layers. In this work, the viscosity of the nanoconfined fluid has been successfully modeled by considering both the fluid-fluid interaction and the fluid-wall interaction. We try to pave a path for characterizing the water flow behavior in both hydrophilic and hydrophobic nanopores, and further guide to simulate the imbibition characteristic or the flowback performance of the fracturing liquid in shale gas/oil reservoirs.
- Research Report > New Finding (0.48)
- Research Report > Experimental Study (0.34)
- Geology > Mineral (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.91)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
Methane Transport through Nanoporous Shale with Sub-Irreducible Water Saturation
Li, Jing (China University of Petroleum) | Li, Xiangfang (China University of Petroleum) | Wu, Keliu (University of Calgary) | Chen, Zhangxin John (University of Calgary) | Wang, Kun (University of Calgary) | Zhong, Minglu (The University of Hong Kong) | Bai, Zhijun (Powerchina Zhongnan Engineering Corporation Limited)
Abstract Characteristics of gas transport in nanopores are topics of great interest for evaluation of unconventional reservoirs. The apparent permeability model for single-phase gas flow has been extensively investigated. Few models, however, have been established for the gas transport in gas/liquid two-phase flow condition. Unfortunately, initial water always exists under reservoir condition. Although it is regarded as immobile state, the impact of which on gas flow capacity should not be simply neglected. In this work, firstly, the state of sub-irreducible water saturation in unconventional reservoirs have been carefully investigated, and the thickness of thin film bound on inorganic pore surface (e.g. clay or quartz) has been quantified. Subsequently, by considering the impact of the water film on the effective hydraulic diameter, gas slip-flow model is established. Noting that the gas phase in moist conditions is mainly composed of both methane and vapor rather than single-component methane. Thus, the methane-vapor binary gas state equation has been introduced to describe the real gas effect under high pressure and temperature condition. Our proposed model has been directly verified by the laboratory tests, and the gas relative permeability in different cases with varying Knudsen numbers has been computed. To our surprise, the calculated relative permeability curves for gas transport in narrow pores demonstrate as convex shape, which indicates that the influence of water on gas flow weakens as the increase of irreducible water saturation. This phenomenon become obvious especially in large Knudsen number condition. In fact, as the increase of Knudsen number, the gas slippage becomes significant and the relative impact of pre-adsorbed water reduces. For a typical tight gas reservoir with initial water saturation of 30%, the effective permeability for gas transport will reduce about 15%~30%, which depends on the Knudsen number for gas transport. Therefore, neglecting the effect of two-phase interaction might overestimate the gas deliverability.
- Europe (0.67)
- North America > United States > Texas (0.46)
- North America > United States > Pennsylvania (0.28)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.46)
Abstract Steam-Assisted Gravity Drainage (SAGD) is a widely used thermal recovery technique in western Canada. Use of numerical simulators, although successful in history-matching and performance prediction of the process, is extremely time consuming for field-scale optimization purposes. Therefore, analytical and semi-analytical models are desirable tools for quick field-wide performance forecast. The first theoretical study of SAGD was conducted by Butler et al. (1981). An elegant analytical model was developed to estimate the oil production rate of a laterally spreading steam chamber, assuming a steady-state mode of thermal conduction beyond the advancing steam front. This model has been the basis for all other SAGD analytical/semi-analytical studies. The model was later modified by Butler and Stephens (1981) and Butler (1985) to overcome the shortcomings of the steady-state heat transfer assumption. The majority of the analytical models of SAGD to date, assume that steam chamber has reached the over-burden from the start of the process and that it can only grow sideways. In real applications, however, steam chamber will rise vertically during its early stages of development. Therefore, these models are not capable of capturing the physics of the vertical growth phase adequately and their estimations of the oil production rate and steam oil ratio (SOR) may be questionable. A uniform steam chamber development during the vertical growth is crucial to an efficient SAGD process during the rest of the project's lifetime. Therefore, it is important to have a reliable estimation of the performance of this phase. In this work, the unsteady-state SAGD model of Butler (1985) has been modified to include the vertical growth phase. Darcy's law and material balance were combined to estimate the oil production rate and steam chamber growth. Energy balance was then used to estimate SOR. Validation of the estimations for oil production rate, steam chamber shape and SOR from this new model against the results of fine-scale numerical simulation indicates that the model has successfully captured the primary physics of the vertical growth phase. The model also predicts a more accurate in-situ distribution of thermal energy and SOR compared to the original model of Butler (1985). A closed form solution is possible for oil production rate, chamber height and SOR under some simplifying assumptions during the vertical growth phase; however, a numerical approach is required beyond this phase. The mathematics are simple enough to allow coding with simple computer programs to yield quick realistic field-scale performance predictions.
- Overview > Innovation (0.68)
- Research Report > New Finding (0.47)
Modeling the Diffusion Controlled Swelling and Determination of Molecular Diffusion Coefficient in Propane-Bitumen System Using a Front Tracking Moving Boundary Technique
Etminan, S. Reza (Alberta Innovates Technology Futures (AITF)) | Maini, Brij B. (University of Calgary) | Chen, Zhangxin John (University of Calgary)
Abstract Accurate estimation of molecular diffusion coefficient is necessary for the design and modeling of solvent-assisted recovery techniques for exploitation of heavy oil and bitumen resources. Several studies on molecular diffusion measurement have been conducted using various pure gaseous solvents but there are very few diffusivity measurements available for the propane-bitumen system. The scarcity of these data is due to the complexities arising in the modeling of dissolution of propane in bitumen. These include high solubility of propane in bitumen and subsequently, dramatic volume change of the diluted oil, drastic reduction of bitumen viscosity during dilution and the possibility of asphaltene precipitation. In this work, a rigorous numerical model is developed to model the diffusivity of propane in bitumen based on real data. This model accounts for bitumen solution density change (swelling) as a result of dilution. A front-tracking moving boundary algorithm and numerical procedure is proposed which accounts for volume change of each grid at each time step. Those grids which experience diffusive flux, change sizes based on non-ideal mixing data available from measurement of solution density versus concentration. Finally, the Levenberg-Marquartd method was applied to estimate the propane diffusion coefficient based on laboratory measured gas-oil interface movement. A constant-pressure diffusion measurement experimental technique was used to measure mass of gas dissolved and solution height change in a propane-bitumen diffusion experiment at 413.7kPa (60 psia) and 827 kPa (120 psia) both in 24ยฐC. The experimental results show that the "no-swelling" simplifying assumption often used in diffusion measurement modeling studies, cannot be generalized to all gaseous solvents because based on our experiments, the bitumen solution volume can be increased by 50% due to propane dissolution. The estimated diffusion coefficient is compared with the results of other mathematical techniques available in the literature. It is shown that the no-swelling simplifying assumption used in unidirectional modeling of gas diffusion in bitumen leads to estimation of erroneous parameters when propane is the gas and oil density and oil volume change is neglected.
- North America > Canada (0.28)
- North America > United States (0.28)
Abstract Among of the new inventions on thermal recovery, Fast-SAGD was introduced as the next generation of SAGD with greater amounts of bitumen and lower injected steam. However, there are still many suspicions about the successful of this technology such as the incremental bitumen recovery of Fast-SAGD is from the SAGD production well or combined with the offset well? It is very difficult to conclude that Fast-SAGD is better than conventional SAGD when numerical simulation of two processes was conducted in different well pattern as well the amount of operated well. This paper presented a comparative evaluation between conventional SAGD and Fast-SAGD in three typical formations (McMurray, Clearwater, and Bluesky) of Alberta's Oil Sand. Three reservoir models with over one hundred numerical simulations under various operation conditions were developed to achieve the most unprejudiced comparison between two recovery processes. The simulation results proved that significantly recoverable bitumen was originally produced from offset well in Fast-SAGD system and leads to higher recovery factor. But, there is only slight increase in cumulative oil recovery when two processes were performed in same pattern with similar number of production wells. The result also indicated that the difference of 10kPa between steam injection pressure and reservoir pressure in literature is not enough for both SAGD and Fast-SAGD operations. And then, this study presented a numerical investigation for evaluating the potential applicability of Fast-SAGD recovery process under complex reservoir conditions such as shale barriers, thief zones with bottom and/or top water layers, overlying gas cap and fracture systems in Clearwater formation.
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.39)
- North America > Canada > Alberta > Athabasca Oil Sands > Western Canada Sedimentary Basin > Alberta Basin > McMurray Formation (0.99)
- North America > United States > Montana > Western Canada Sedimentary Basin > Alberta Basin (0.96)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Bluesky Formation (0.94)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Clearwater Formation (0.93)
Abstract Reservoir simulation for a full field heterogeneous model with millions of grid blocks demands significant computational time so improving the computational efficiency becomes crucial in designing a reservoir simulator. Graphics Processing Unit (GPU), a new high-profile parallel processor with hundreds of microprocessors, stands out in parallel simulation because of its efficient power utilization and high computational efficiency. Also, its cost is relatively low, making large-scale parallel reservoir simulation possible for most of desktop users. In this paper several GPU-based parallel preconditoners, in conjunction with a new GPU-based GMRES algorithm, are proposed and coupled with an in-house black-oil simulator to speedup reservoir simulation. In particular, massively parallel ILU preconditioners (ILU(0), ILUT, block ILU(0), block ILUT), which are usually regarded as data dependence and highly sequential preconditioners, are developed on GPUs. In the numerical experiments performed, the SPE 10 problem, a 3D heterogeneous benchmark model with over one million grid blocks, is selected to test the speedup of our GPU solver and preconditioners. On the state-of-the-art CPU and GPU platform, the new GPU implementation can achieve a speedup of over eight times in solving linear systems arising from this SPE 10 problem compared with the CPU based serial solver. Moreover, our GPU solver is successfully coupled with the in-house black-oil simulator to test the performance of the whole parallel simulation process, with a speedup of about six times. The excellent speedup and accurate results demonstrate that the GPU-based parallel linear solver and preconditioners have the great potential in parallel reservoir simulation.
- Information Technology > Hardware (1.00)
- Information Technology > Graphics (1.00)
Abstract Overlying top water and gas thief zones have a detrimental effect on the Steam-Assisted Gravity Drainage (SAGD) recovery process since steam penetrates into these zones which results in great heat loss. Due to the presence of these top thief zones, recovering bitumen by the SAGD process has become challenging for the Athabasca oil sands. Numerical simulations, laboratory experiments and field production data have demonstrated that oil production tends to decrease as the depletion of top gas occurs; also, heat loss to the overlying thief zone will be more significant when a top water zone is present. Indeed, SAGD is a coupled geomechanical, thermal and fluid flow problem because continuous steam injection changes reservoir pore pressure and temperature, which can alter the effective stress in-situ. Therefore, to represent the physics of thermal flow and soil geomechanics, a coupled geomechanical simulation that solves the flow and stress equation simultaneously in the reservoir is crucial for modeling the SAGD process. The objective of this paper is to construct a 3D geostatistical model for the Surmont pilot and implement coupled geomechanical modeling for the SAGD process aiming at investigating the impact of dilation and thermal expansion on the surface subsidence and bitumen recovery. Reasonable history match of oil and water rates has been achieved and steam chamber profiles have been conformed to the field data from the observation wells. An Expanding Solvent Steam-Assisted Gravity Drainage (ES-SAGD) process has been investigated on a full field-based heterogeneous simulation model using an optimal solvent mixture. Finally, geomechanical effects on the ES-SAGD process are investigated through an iterative coupling approach. Introduction The negative impacts of top water and gas cap on SAGD performance have been previously presented and discussed in the literature (Good et al. 1997; Nasr et al. 2000; Law et al. 2000). Both experimental and simulation approaches were conducted to determine SAGD steam chamber growth in the presence of a top thief zone. It was observed that the overlying top water and gas thief zones have a detrimental effect on the Steam Assisted Gravity Drainage (SAGD) recovery process since steam penetrates into these zones and results in great heat loss (AEUB, 1998). Thermal SAGD simulations models have been constructed and successfully matched using the computer assisted history-matching approach. The optimization strategies have been proposed in terms of the operating pressure and subcool control. Furthermore, ES-SAGD possibilities have been investigated using different solvent mixture co-injected with steam. Through a sensitivity study, an optimal solvent mixture has been proposed for this case with a top thief zone. SAGD is a coupled geomechanical, thermal and fluid flow problem because continuous steam injection changes reservoir pore pressure and temperature, which can alter the effective stress in-situ. Dilation behavior associated with volumetric strains is triggered by the continuous steam injection, which causes the increase of porosity and permeability. Therefore, the fluid flow behavior must be coupled to the geomechanical behavior of the oil sands. Investigating the interaction between the cap rock integrity, dilation and thermal expansion under the continuous steam injection is the motivation of this study. ES-SAGD Investigation ES-SAGD is the co-injection of small amount solvent additive with steam in the SAGD process. Solvent will condensate at the boundary of the steam chamber and diffuse into bitumen, which will reduce the oil viscosity, yield the higher oil drainage and reduce the amount of steam required.
- North America > United States (1.00)
- North America > Canada > Alberta > Athabasca Oil Sands (0.84)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > Canada > Alberta > Athabasca Oil Sands > Western Canada Sedimentary Basin > Alberta Basin > Surmont Field (0.99)
- North America > Canada > Alberta > Athabasca Oil Sands > Western Canada Sedimentary Basin > Alberta Basin > McMurray Formation (0.99)
- North America > Canada > Alberta > Athabasca Oil Sands > Western Canada Sedimentary Basin > Alberta Basin > Hangingstone Oil Sands Project (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Cold Lake Oil Sands Project > Clearwater Formation (0.98)
Abstract Molecular diffusion coefficient is an important parameter in modeling mass-transfer based reservoir processes. However, experimentally measured diffusivities for heavy oil systems are relatively scarce and no standardized method exists for measurements of this important parameter. The available measurement techniques are tedious, expensive and often not very reliable. There is an obvious need for developing improved methods for measuring diffusivity of gases in heavy oils. It is well known that as a gas dissolves into heavy oil, the oil viscosity drops considerably and this affects the diffusivity. The objective of this work is to measure the diffusivity of highly soluble gaseous solvents in heavy oils at different concentration levels. We have developed a modified pressure decay method that maintains constant concentration at the gas-liquid interface and measures the amount of gas transferred to the liquid as a function of time. An analytical solution has been developed for finding diffusion coefficient and the equilibrium solubility of gas in the oil at the test pressure. To study the concentration dependence of diffusivity, a stepwise increase in pressure is used starting from a low pressure. Through this stepwise procedure, a diffusion coefficient is measured for each gas saturation pressure (concentration), going from low pressure to near gas dew point pressure in 5 to 6 steps. The bitumen height in our cell is updated at each pressure to account for bitumen swelling. Propane was used as vapor solvents and diffusion cell was kept at constant temperature. Introduction Efficient recovery of heavy oil and bitumen is still very challenging and remains an issue in ongoing researches all around the world. Thermal recovery methods, which rely on heat for viscosity reduction, are generally accepted as viable and several steam based projects have been successful, especially in Canada. Using light hydrocarbon solvents can provide similar viscosity reduction and is potentially more efficient in so-called challenging reservoirs where thermal methods do not work. In comparison with thermal methods, solvent based processes are more environmentally friendly and require no fresh water resources. Moreover, using CO2 as a major component in the injected solvent helps in reduction of Green House Gases by sequestering CO2 emissions. Keeping that in mind, reliable measurements of molecular diffusion coefficient are required for designing solvent-based recovery processes in heavy oil reservoirs. Accurately knowing the diffusion coefficient and its variation with process conditions would also improve the predictions of compositional reservoir simulators. Unlike heat conductivity or viscosity in the analogous transport phenomena, measurements of mass diffusivity of gases in liquids are more difficult and no standardized procedures for such measurements exist. Several experimental and mathematical methods have been introduced to characterize this key parameter. The ratio between the local flux and the local gradient in the concentration is defined as diffusion coefficient 1 which controls the rate of dissolution in a diffusion process. There are two other parameters, which are equally important in controlling the overall rate of diffusion process. First is the solubility of the gas in the liquid and the second is the mass transfer coefficient on the gas side of the gas-liquid interface. Solubility value or saturation concentration is the maximum or eventual amount of gas that can be dissolved into the liquid phase. The mass transfer coefficient is defined as a proportionality constant that relates the rate of mass transfer to difference between the bulk gas phase concentration and the concentration at the interface 2. When the gas phase is a pure component, this constant reflects the existence of a resistance to mass-transfer at the interface which makes the interface concentration smaller than the equilibrium concentration. In absence of such resistance, the concentration at the interface exposed to a pure component gas would be equilibrium concentration determined by the solubility of the gas at the test conditions.
- North America > Canada > Alberta (0.28)
- North America > United States > Oklahoma (0.28)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Abstract Perhaps the most important unconstrained aspect of petroleum systems analysis concerns the charging and emplacement of petroleum to a structure or prospect. Petroleum charge rates, leakage, and spill control petroleum residence time in a reservoir, which is fundamental for prediction of biodegration rates, seal integrity (failure), and oil quality, all of which are affected by fluid mixing processes. While forward models can estimate plausible charge rates based on thermal histories, there are no field data proxies for the charge rates that are necessary to constrain migration and charge models. To solve this problem, we are coupling high resolution, full physics reservoir simulation protocols to full 4D basin models such that gradients in petroleum compositions from models and from chemical analysis can be used to constrain charges rates. This new generation of hybrid reservoir simulator/basin models necessitates rapid high resolution fluid mixing solvers and multicomponent fluids. This paper deals with the development of compositional fluid mixing simulators that can be coupled with basin modeling. These simulators will enable the forward simulation of detailed reservoir charging and fluid property evolution, coupling the effects of advection, diffusion, gravity segregation, and biodegration to predict the development of compositional gradients in petroleum columns that can be used to constrain reservoir charging and alteration processes. In this paper the effects of advection, diffusion, and gravity segregation are particularly studied. The traditional simulator for solving the isothermal gravity/chemical equilibrium problem is deduced as a special example of the simulators presented here. Numerical experiments to show these effects are given. Introduction Tremendous efforts have been devoted to modeling compositional variations under the force of gravity in hydrocarbon reservoirs in the past 30 years. Whitson and Belery (1994) gave a historical survey on the development of methods used to investigate gravity segregation. The formulation for computing the compositional variations under gravity for an isothermal system was first given by Gibbs (1876). Gibbs' formulation states that the total potential of each component is constant. In the 1930s, based on this formulation, Muskat (1930) and Sage and Lacey (1938) reported preliminary results in modeling these variations. Schulte (1980) appeared to be the first person to solve for compositional variations using a practical method. Numerous studies on the subject of modeling the compositional variations have appeared since then; see the bibliographies in Whitson-Belery (1994). A major conclusion from these studies is that the gravitational force has a significant effect on these variations. The chemical equilibrium constraint of Gibbs holds only for an isothermal system. For nonisothermal systems, this constraint is no longer valid because of nonzero entropy production. Furthermore, transience is not solved using Gibbs' formulation so there is no driving force. Finally, the effects of advection and diffusion must be taken into account.
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Fluid modeling, equations of state (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (0.67)