Scale Reservoir Simulation Research Articles

Simulation of CO2 dissolution reactions in saline aquifers using lattice Boltzmann method

CO2 dissolution reactions in saline aquifers during geologic carbon sequestration (GCS) involve multiple physicochemical processes and pose a challenge for both experimental and numerical techniques to capture reactive transport features and complex porous structures. Benefited from advanced models in the lattice Boltzmann (LB) community, namely, multiphase flow LB model and multicomponent transport LB model with chemical reactions, dynamics of CO2-water interfaces, concentration evolution of ions, and heterogeneous and homogeneous reactions could be readily captured by the proposed LB model to characterize CO2 dissolution reactions applicable to far-field applications. This LB model can not only emphasize CO2 dissolution processes at the scale of a few pores but also elaborate on the corresponding controlling mechanisms in porous media during GCS in saline aquifers. LB simulations herein indicate that both diffusion coefficient and reactive interfacial length may change the total concentration gradient at the CO2-water interface to further affect CO2 dissolution reactions. It is also confirmed that CO2 dissolution is a non-equilibrium process, which could not be neglected in reservoir-scale simulations. The effect of reactive interfacial length on CO2 dissolution is negligible due to a narrower range of contact angles in saline aquifers. Influenced by the structural complexity of porous media, the dissolution of CO2 clusters shows a strong heterogeneous characteristic evaluated by the pore size distribution. The evolution of pH in homogeneous reactions is estimated via mass action equations. Besides, the effects of partial pressure, formation temperature, and salinity, as three key factors in the practical application, are thoroughly probed. The high pressure is conducive for sequestration because of its greater sequestration efficiency, but the temperature has both positive and negative impacts on CO2 dissolution trapping and should be carefully evaluated in a certain saline aquifer before the operation. High ion strength would decrease the efficiency of dissolution trapping to some extent.

Experimental and numerical modeling of a novel surfactant flooding: Core scale to reservoir models

This comprehensive study delves into an application of surfactant flooding as a robust enhanced oil recovery (EOR) technique, incorporating both core-scale experiments and reservoir-scale numerical simulations. The research's focal point is to evaluate a novel surfactant's performance in extending oil recovery efficiency within an oil reservoir. The study commences with thorough laboratory experiments at the core scale, illuminating the interplay of fluids within porous media. Transitioning seamlessly to reservoir-scale numerical modeling, the research replicates real-world reservoir conditions. Various well configurations are scrutinized to optimize surfactant flooding strategies for EOR purposes. A key aspect of this analysis is the in-depth examination of the sensitivity of numerical simulations to changes in relative permeability curves during surfactant injection, enabling a robust assessment of the performance of surfactant injection in a broad spectrum of uncertainties. Comparative experiments elucidated the significant influence of a surfactant molecular structure, with aliphatic variants showcasing superior oil displacement efficiency. Moreover, combining surfactant and polymer proved pivotal, enhancing reservoir sweep efficiency and significantly boosting oil recovery. This work establishes a comprehensive framework for evaluating chemical flooding, including surfactant and polymer, as a potent EOR method by bridging the gap between core-scale experiments and reservoir-scale simulations.

CO2 rich cushion gas for hydrogen storage in depleted gas reservoirs: Insight on contact angle and surface tension

Hydrogen storage in porous media (aquifers and depleted reservoirs) is an effective means of achieving large-scale inter-seasonal demand for energy. In particular, the depleted gas reservoir provides substantial storage capacity and additional economic incentives due to the preexistence of the storage infrastructure as well as the requisite reservoir integrity. However, the interfacial phenomenon between the injected hydrogen, the native gas (cushion gas), the formation brine, and the host rocks require further investigation for efficient gas containment. In this study, we conducted a comprehensive examination of the application of CO2 as a cushion gas. Our investigation involved performing contact angle and surface tension experiments using the drop shape analyzer (DSA) 100 equipment. We examined various gas mixtures (H2–CO2 – CH4–N2) under different pressure ranges (500–3000 psi), temperature levels (30, 40, 50, 60, 70 °C), and salinities (2, 5, 10, 15, and 20 wt%).Results indicate that the wettability behavior of the studied gas-mixture compositions remains relatively consistent unless there are changes in the initial wetting state of the rock. The contact angles observed ranged from 29 to 51°, independent of reservoir pressure, temperature, and salinity. The contact angle values increased with higher pressure but decreased with higher temperature. Furthermore, the contact angle was lower for a gas mixture with a lower CO2 fraction compared to a gas mixture with a higher CO2 fraction. Conversely, the gas mixture brine surface tension exhibited a decrease with increasing pressure, temperature, and CO2 fraction. However, it increased with increasing salinity for all gas mixtures. Based on the results obtained from the contact angle and surface tension analysis, mixture 4 emerged as the ideal fraction for designing CO2 cushion gas in terms of both hydrogen storage and withdrawal. These findings present precise and valuable input parameters and data that can be utilized in reservoir-scale simulations to optimize geo-storage in depleted natural gas reservoirs.

Hydrogen storage in depleted gas reservoirs using nitrogen cushion gas: A contact angle and surface tension study

The utilization of depleted natural gas reservoirs is a significant consideration for large-scale hydrogen (H2) storage and production. However, accurate knowledge of cushion gas compositions such as nitrogen (N2), methane (CH4), and carbon dioxide (CO2) is crucial, as they are critical components that affect the rock-fluid interfacial phenomenon, thereby impacting deployment feasibility. Moreover, there are limited reported studies on rock/brine/gas-mixture wettability and gas-mixture/brine surface tension for this type of reservoir. To address this gap, we explore the possibility of using N2 as a cushion gas (in the presence of CH4 and CO2) on a pristine quartz for H2 storage across various pressure (500–3000) psi, temperature (30–70) °C, and salinity (2–20) wt.%. We conducted extensive contact angle (CA) and surface tension (ST) experiments for different gas mixtures (H2–N2–CH4–CO2) to generate relevant data for H2 storage in depleted natural gas reservoirs using drop shape analyzer (DSA 100) equipment. Our findings suggest that the wettability behavior of the gas-mixture compositions studied is likely to remain consistent unless the rock's initial wetting state is altered. The CAs were observed to range between 28 and 46°, regardless of reservoir pressure, temperature, and salinity. It also increased with increasing pressure but decreased with increasing temperature. In addition, CA was lower at a lower N2 fraction (Mix 1–80% H2 – 10% N2 – 5% CH4 –5% CO2) compared to a higher N2 fraction (Mix 4–20% H2 – 70% N2 – 5% CH4 –5% CO2). The ST of the gas-mixture/brine systems declined with increasing (i) pressure, (ii) temperature, and (iii) N2 fraction but increased with increasing salinity for every gas mixture. Based on our investigation, mixtures 2 and 3 with H2 (40–60%) and N2 (30–50%) fractions (at constant 5% CH4 and 5% CO2) were identified as the optimal cushion gas for H2 storage and withdrawal under the studied conditions. The results of this study provide accurate and valuable input parameters and data for reservoir-scale simulations utilized in optimizing geo-storage in depleted natural gas reservoirs.

How pore pressure changes affect stress and strain in fault zones with complex internal structure – Insights from hydromechanical modelling

Faults not only affect the hydraulic regime and the local stress state, but are also prone to reactivation by pore pressure changes, potentially leading to induced seismicity, among others. In the present study, a generic finite element model with a detailed fault zone description including damage zones and a fault core with highly strained rock and fault core lenses of host rock is used to study the stress and strain evolution due to pore pressure changes. Special focus is on the temporal evolution of the effective stresses within the fault zone and the strain partitioning between its various subunits. The coupled hydromechanical simulations comprise five different scenarios covering pore pressure increase due to fluid injection and pore pressure decrease due to fluid production for permeable and semipermeable fault zones as well as different distances between the fault core lenses. Modelling results show that the variable hydromechanical properties of the different fault zone rocks lead to spatially and temporarily highly heterogeneous stress and strain patterns within the fault zone and its surrounding. In particular, substantial stress rotations of up to 45° and differently in the various subunits of the fault zone are found in response to pore pressure changes. Plastic straining as an indication for potential fault reactivation is observed particularly in the injection scenarios. Models provide a template for modifications with respect to fault zone architecture and hydromechanical properties. They can also serve as starting point to define bulk fault zone properties for reservoir-scale simulations which cannot capture the complexities of a fault zone regarding geometry and material distribution.

The potential of hydrogen storage in depleted unconventional gas reservoirs: A multiscale modeling study

Subsurface energy storage in depleted petroleum reservoirs is a promising technique to balance and optimize the utilization of energy resources. In this work, we numerically explore the possibility of storing excessive hydrogen gas in depleted unconventional gas reservoirs. Our study is a multiscale analysis. From the molecular (pore) scale, we investigate the thermodynamics and transport mechanism of the hydrogen gas in the nanopores of the unconventional reservoirs. Then based on the results of the pore scale, we conduct reservoir-scale simulations to quantitatively investigate the preferred cycling pressure, the effective fraction of cushion gas and the amount of storage capacity of unconventional reservoirs. We have discovered that, compared to conventional gas reservoirs, hydrogen stored in unconventional reservoirs maintains higher purity because of the differential adsorption effect of the nanopores. This feature makes depleted unconventional gas reservoirs appealing candidates for underground storage of the hydrogen gas.

Reconciling predicted and observed carbon mineralization in siliciclastic formations

The study of natural CO2 storage reservoirs has demonstrated that carbon mineral trapping is the safest mechanism for subsurface CO2 storage. The slow rate of fluid-rock reactions makes it imperative to use reactive transport simulations as a tool for estimating reservoir scale carbon mineral trapping capacities. However, there is often a disparity in the estimations of carbon mineral trapping capacities determined from reactive transport simulations and recorded in natural CO2 storage reservoirs. This might be due to several factors such as the uncertainty around simulations parameters such as mineral reactive surface areas as well as the neglect of sub-core scale lithological heterogeneity in reservoir scale simulations. This study points to the importance of the latter to reconcile the mismatch. Multiphase reactive transport simulations were run on a cm-scale resolution geological model (CRM) of the Paaratte Formation, Otway Basin (Australia), where mm- to cm-scale lithological heterogeneity is incorporated via upscaled rock parameters. Simulations were also run on a m-scale resolution model (MRM) of the same transect to quantify the difference in the predicted secondary mineral composition due to the incorporation of sub-core scale heterogeneity in reservoir scale simulations. The simulation outcomes for both the models were compared to the data from the Pretty Hill Formation, a natural CO2 storage analogue within the Otway Basin with similar primary mineral composition. The results from the CRM compare well with the secondary carbonate mineralogy of the Pretty Hill Formation. In contrast, the MRM strongly underestimates carbonate mineral formation. The results highlight that the incorporation of mm- to cm-scale lithological interfaces in reservoir scale reactive transport simulations can increase carbon mineralization estimates in siliciclastic formations by 3–6 orders of magnitude as these interfaces are sites for mineral precipitation.

Multiscale numerical simulation of CO2 hydrate storage using machine learning

Carbon capture and storage (CCS) is a technology to reduce significant emissions of carbon dioxide (CO2). CO2 can be stored in sub-seabed aquifers under impermeable layers called caprock. CO2 hydrate forms under the conditions of high pressure and low temperature and it may suppress or block CO2 upwards flow as functioned as a kind of 'caprock'. Therefore, understanding of permeability reduction mechanisms due to hydrate formation is essential for CCS using gas hydrate. This study proposes a novel multiscale numerical method, by which the permeability of hydrate-bearing sediments in reservoir-scale simulations of several hundred meters is estimated using a machine learning technique based on the database of the results of microscopic pore-scale simulations of a couple of hundred μm. Because the permeability reduction is strongly influenced by the characteristics of microscale hydrate distribution, we used two types of neural networks: one is for parameters with regard to the hydrate shape distributed in the pore space and the other is for the permeability reduction due to the hydrate shape. Reservoir-scale simulations were conducted in homogeneous sand sediments using the proposed machine learning model, based on the database of the microscale simulation results, together with existing mathematical permeability models for comparison. The results of the reservoir-scale hydrate distribution using these models were very similar, indicating that the proposed method was validated, while at the same time the difference in the results of the spatial distribution of permeability values, albeit small, suggests the originality of this method.

Numerical Study on Hydraulic Fracture Propagation in a Layered Continental Shale Reservoir

The distribution of beddings varies greatly in shale reservoirs. The influence of beddings on hydraulic fracture propagation has often been studied using simplified geological models, i.e., uniformly distributed bedding models. However, the propagation processes of hydraulic fractures in shale reservoirs with complicated distributed beddings remains unclear. In this research, an outcrop-data-based bedding model of a continental shale formation in the Ordos Basin, China, is built. A mathematical model for fracture propagation is built using the discrete element method and is then verified by a hydraulic fracturing experiment. Reservoir-scale simulations are employed to investigate the influence of geological factors and engineering factors on fracture geometry. The study finds that beddings have significant inhibitory effects on fracture height growth; hydraulic fractures have difficulty in breaking through zones with densely distributed beddings. If a hydraulic fracture encounters a bedding plane with a larger aperture, it is more likely to be captured and expand along the weak interface. High vertical stress difference and a high fluid injection rate can promote the vertical penetration of hydraulic fractures through beddings and activate the bedding system to yield a complex fracture network. Increments in fluid viscosity can increase the resistance of fracture propagation, thereby reducing fracture complexity.

Utilization of a high-temperature depleted gas condensate reservoir for CO2 storage and geothermal heat mining: A case study of the Arun gas reservoir in Indonesia

In this study, field scale reservoir simulations and production history matching are performed to investigate CO2 storage and CO2 heat mining potential in the high-temperature Arun gas condensate reservoir in Indonesia. Our study shows that CO2 injection into the depleted Arun reservoir can produce 51 MMbbl of condensate over 16 years. Afterwards, continuous CO2 injection without any production over 20 years can allow 1.2 Gt of CO2 to be stored by raising the reservoir pressure to the initial value. In addition, subsequent recycling of CO2 can produce substantial amount of geothermal energy for electricity production.Analyses show that at an oil price of $60/bbl, CO2 cost of $30/ton, and a discount rate of 7%, the produced condensate can generate a net present value (NPV) of $1,910 MM. This profit is enough to pay for storing 205 Mt CO2 in two years after condensate recovery. Alternatively, it can be also used to generate 1.1 × 1010 kWh of electricity in seven years through CO2 heat mining. Results, however, are even more encouraging if CO2 cost is zero or negative through CO2 pricing.Furthermore, by applying CO2-enhanced gas recovery (EGR) to all gas condensate reservoirs in Indonesia, we estimate that the low, mid and high values of condensate recovery is 2,100, 2,900 and 3,700 MMbbl, respectively. This, in turn, gives low, mid and high values of 6.6, 7.0 and 7.4 Gt of CO2 storage capacity, respectively. The gas condensate reservoirs have enough capacity to store 45 years of CO2 emission from power and industrial plants in Indonesia if one assumes 45% of the emission is capturable. Additionally, a significant portion of the geothermal resource of 2.06 × 1019 J in the gas condensate reservoirs in Indonesia may be developed by CO2 heat mining after CO2-EGR and CO2 storage.

Characteristics of gas–water flow during gas injection in two-dimensional porous media with a high-permeability zone

A marginal gas injection method was previously proposed based on two-dimensional (2-D) homogeneous porous media, and the feasibility of isolating the oil shale pyrolysis zone from the surrounding hydrological environment had been demonstrated. The gas–water flow characteristics and dynamics during gas injection in 2-D porous media with a high-permeability zone (HPZ) were studied further based on the presence of a HPZ after fracturing oil shale reservoirs. A series of experiments were performed when the gas-injection point was located outside, at the boundary, or inside the HPZ (Case1-3). The HPZ enriched the injected gas, and in Cases 2 and 3, the gas inside the HPZ permeated to the low-permeability zone (LPZ) on both sides, forming two wing tributaries. However, in Case 1, water flowed into the HPZ in the opposite direction. In Cases 2 and 3, the direction of the local pressure gradient on both sides of the HPZ was completely opposite, indicating that the distribution of the pressure field was the direct cause of the gas–water flow characteristics. Therefore, the water-stopping effect of gas injection is primarily reflected in the HPZ. Additionally, the effect was best when the gas-injection point was set at the boundary or inside of the HPZ. These results were verified using reservoir-scale simulations and tests, in which the water yield decreased to ∼ 100 kg/d. Subsequently, we recommended the sites of gas-injection wells for water stopping. All results are expected to provide strategies and theories for dealing with the adverse hydrological environment in large-scale oil shale in situ exploitation.

Dynamic effective permeability of a laminated structure with cross flow in the transient flow process and its application to reservoir simulation

The effective permeability of a laminated structure is an important parameter related to the practical necessity of coarsening of grid blocks in large scale reservoir simulations. Traditional effective permeability derived under steady state flow conditions can cause great errors in the transient flow process due to the great heterogeneity and anisotropy of laminated formations. To handle this error, the unsteady oil flow in the matrix between hydraulic fractures of a laminated system during an oil depletion process is analyzed in this study. Based on material balance, we present an analytical method for calculating the dynamic effective permeability of the laminated structure considering the cross flow between laminae in the transient flow process. The proposed dynamic effective permeability can be used to conduct coarsening of grid blocks and can be incorporated into numerical models for accurate modeling of transient flow in a laminated structure in the reservoir simulation. It is shown that the simulation results using the proposed effective permeability model match well with those from two-dimensional (2D) simulations. Further, the effects of the horizontal permeability, vertical permeability, thickness of the laminae, and the length of the matrix between fractures are studied.

Improving heavy oil production rates in THAI process using wells configured in a staggered line drive (SLD) instead of in a direct line drive (DLD) configuration: detailed simulation investigations

As governments around the world prepare for a transition period to a decarbonised energy and economic future, petroleum is needed to smoothen that transition. Based on the analysis of the International Energy Agency’s 2020 projections, around 770 billion barrels of oil are required to meet demand from now to 2040. However, according to British Petroleum’s Statistical Review of World Energy 2020, as at the end of 2019, the global total reserves of recoverable conventional and unconventional oils is approximately 1734 billion barrels. Out of that, the conventional easy-to-produce light oil accounts for only 30% (i.e. accounts for only 520.2 billion barrels). Therefore, the remaining 249.8 billion barrels of oil needed to satisfy demand up to 2040 must come from unconventional oils, namely heavy oils and bitumen. However, these unconventional resources are very difficult to produce and the current production methods have very high environmental footprints. Consequently, in accordance with climate crisis mitigations, the vast reserves of the virtually unexploited heavy oils and bitumen must be developed using advanced and greener extraction technologies, such as the yet-to-be-fully-understood THAI process which provides partial upgrading of heavy oil/bitumen via in situ combustion. Using validated numerical models which are developed using the CMG’s reservoir thermal simulator, the STARS, which is also used in this study, field scale reservoir simulations of the THAI process were performed with the wells arranged in staggered line drive (SLD) and direct line drive (DLD). Over the 834 days of operating time, the cumulative oil recovery in SLD is 32% of oil originally in place (OOIP) which is equivalent to 26,100 m3 whilst that in DLD is 27% OOIP. This shows that more oil (i.e. an additional 5% OOIP) was cumulatively recovered in SLD compared to in DLD model. It is found that smaller reservoir volume was swept by the combustion front in DLD and thus making the heat-affected reservoir volume smaller than that in SLD model. Furthermore, in DLD, due to the nearness of the injector well to the toe of the horizontal producer (HP) well, oxygen production began much earlier, compared to in the SLD. It is also found that the temperature of the mobile oil zone is higher in the SLD model compared to that in the DLD model. This implies that higher quality oil is produced when the wells are configured in the SLD pattern. Therefore, this first-of-a-kind work has shown that SLD arrangement is far more efficient, safer, and produces higher quality oil than DLD pattern and that actual process engineering designs should use SLD wells configuration.

Contact angle measurement for hydrogen/brine/sandstone system using captive-bubble method relevant for underground hydrogen storage

Subsurface porous formations provide large capacities for underground hydrogen storage (UHS). Successful utilization of these porous reservoirs for UHS depends on accurate quantification of the hydrogen transport characteristics at continuum (macro) scale, specially in contact with other reservoir fluids. Relative-permeability and capillary-pressure curves are among the macro-scale transport characteristics which play crucial roles in quantification of the storage capacity and efficiency. For a given rock sample, these functions can be determined if pore-scale (micro-scale) surface properties, specially contact angles, are known. For hydrogen/brine/rock system, these properties are yet to a large extent unknown. In this study, we characterize the contact angles of hydrogen in contact with brine and Bentheimer and Berea sandstones at various pressure, temperature, and brine salinity using captive-bubble method. The experiments are conducted close to the in-situ conditions, which resulted in water-wet intrinsic contact angles, about 25 to 45 degrees. Moreover, no meaningful correlation was found with changing tested parameters. We monitor the bubbles over time and report the average contact angles with their minimum and maximum variations. Given rock pore structures, using the contact angles reported in this study, one can define relative-permeability and capillary-pressure functions for reservoir-scale simulations and storage optimization.

Implementation of a multi-layer radiation propagation model for simulation of microwave heating in hydrate reservoirs

PurposeThis paper aims to present the implementation of a multi-layer radiation propagation model in simulations of multi-phase flow and heat transfer, for a dissociating methane hydrate reservoir subjected to microwave heating.Design/methodology/approachTo model the induced heterogeneity due to dissociation of hydrates in the reservoir, a multiple homogeneous layer approach, used in food processes modelling, is suggested. The multi-layer model is incorporated in an in-house, multi-phase, multi-component hydrate dissociation simulator based on the finite volume method. The modified simulator is validated with standard experimental results in the literature and subsequently applied to a hydrate reservoir to study the effect of water content and sand dielectric nature on radiation propagation and hydrate dissociation.FindingsThe comparison of the multi-layer model with experimental results show a maximum difference in temperature estimation to be less than 2.5 K. For reservoir scale simulations, three homogeneous layers are observed to be sufficient to model the induced heterogeneity. There is a significant contribution of dielectric properties of sediments and water content of the reservoir in microwave radiation attenuation and overall hydrate dissociation. A high saturation reservoir may not always provide high gas recovery by dissociation of hydrates in the case of microwave heating.Originality/valueThe multi-layer approach to model microwave radiation propagation is introduced and tested for the first time in dissociating hydrate reservoirs. The multi-layer model provides better control over reservoir heterogeneity and interface conditions compared to existing homogeneous models.

New X-Ray Microtomography Setups and Optimal Scan Conditions to Investigate Methane Hydrate-Bearing Sand Microstructure

Abstract Methane hydrates, which are naturally formed at high pressures and low temperatures in marine and permafrost sediments, represent a great potential energy resource but also a considerable geo-hazard and climate change source. Investigating the grain-scale morphology of methane hydrate-bearing sandy sediments is crucial for the interpretation of geophysical data and reservoir-scale simulations in the scope of methane gas production as methane hydrate morphologies and distribution within the porous space significantly impact their macroscopic physical/mechanical properties. X-ray computed tomography (XRCT) and synchrotron X-ray computed tomography (SXRCT) are commonly used to analyze the microstructure of geo-materials. However, methane hydrates exist only at high pressures (up to several megapascals) and low temperatures (a few degrees Celsius). This article describes the development of three experimental setups, which aim at creating methane hydrates in sandy sediment, adapted to XRCT and SXRCT observations. The advantages and drawbacks of each setup are discussed. The discussions focus on the effects of the choice of the system to control temperature and pressure on the quality of images. The obtained results would be useful for future works involving temperature control systems or pressure control systems, or both, adapted to XRCT and SXRCT observations of various geo-materials.

A New Modeling Framework for Multi-Scale Simulation of Hydraulic Fracturing and Production from Unconventional Reservoirs

This paper describes a new modeling framework for microscopic to reservoir-scale simulations of hydraulic fracturing and production. The approach builds upon a fusion of two existing high-performance simulators for reservoir-scale behavior: the GEOS code for hydromechanical evolution during stimulation and the TOUGH+ code for multi-phase flow during production. The reservoir-scale simulations are informed by experimental and modeling studies at the laboratory scale to incorporate important micro-scale mechanical processes and chemical reactions occurring within the fractures, the shale matrix, and at the fracture-fluid interfaces. These processes include, among others, changes in stimulated fracture permeability as a result of proppant behavior rearrangement or embedment, or mineral scale precipitation within pores and microfractures, at µm to cm scales. In our new modeling framework, such micro-scale testing and modeling provides upscaled hydromechanical parameters for the reservoir scale models. We are currently testing the new modeling framework using field data and core samples from the Hydraulic Fracturing Field Test (HFTS), a recent field-based joint research experiment with intense monitoring of hydraulic fracturing and shale production in the Wolfcamp Formation in the Permian Basin (USA). Below, we present our approach coupling the reservoir simulators GEOS and TOUGH+ informed by upscaled parameters from micro-scale experiments and modeling. We provide a brief overview of the HFTS and the available field data, and then discuss the ongoing application of our new workflow to the HFTS data set.

A Multi-Scale Modeling of Confined Fluid: from Nanopore to Unconventional Reservoir Simulation

Tight oil and shale gas reservoirs have a significant part of their pore volume occupied by micro (below 2 nm) and mesopores (between 2 and 50 nm). This kind of environment creates strong interaction forces in the confined fluid with pore walls and then changes dramatically the fluid phase behavior. An important work has therefore to be done on thermodynamic modeling of the confined fluid and on developing upscaling methodology of the pore size distribution for large scale reservoir simulations. Firstly, the comparison between molecular simulation results and commonly used modified equation of state (EOS) in the literature highlighted the model of flash with capillary pressure and critical temperature and pressure shift as the best one to model confined fluid behavior. Then, fine grid matrix/fracture simulations have been built and performed for different pore size distributions. The study has shown that the pore size distribution has an important impact on reservoir production and this impact is highly dependent on the volume fraction of nanopores inside the matrix. Afterwards, coarse grid upscaling models have then been performed on the same synthetic case and compared to the reference fine grid results. The commonly used upscaling methodology of dual porosity model with average pore radius for the pore size distribution is unable to match the fine grid results. A new triple porosity model considering fracture, small pores and large pores with their own capillary pressure and EOS, together with MINC (Multiple Interacting Continua) approach, has shown very good agreement with the reference fine grid results. Finally a large scale stimulated reservoir volume with different pore size distribution inside the matrix has been built using the upscaling method developed here.

Upscaled Anisotropic Methane Hydrate Critical State Model for Turbidite Hydrate‐Bearing Sediments at East Nankai Trough

AbstractTurbidite formation is a common feature of natural hydrate‐bearing sediments that has been observed and reported at several hydrate exploration sites. It is therefore important to incorporate this anisotropic geological feature into the constitutive modeling when evaluating the geomechanical risks involved during hydrate‐based gas production. To date, a number of constitutive models have been proposed to capture the isotropic geomechanical behavior of homogeneous hydrate‐bearing sediments. Since the turbidite formation contains soil layers at a scale much smaller than the size of the numerical element used for reservoir scale simulations, it is necessary to upscale the geomechanical behavior of a layered system to an equivalent anisotropic continuum model by adopting some homogenization techniques. In this study, an anisotropic methane hydrate critical state model is developed by modifying the original isotropic version of Uchida et al. (2012, https://doi.org/10.1029/2011JB008661). The calibration methodology of the anisotropic model parameters for a given set of hydrate heterogeneity and the turbidite formation at the Eastern Nankai Trough is proposed and demonstrated. The upscaled parameters are calibrated by curve fitting the numerically simulated stress‐strain curves of the layered system with the original isotropic constitutive model at the layered scale. Forty‐two sets of model parameters are calibrated from different site element models of this site. They are used to develop empirical correlations between the model parameters and the site input properties within the turbidite formation. This paper presents the details of the new anisotropic constitutive model and the performance of the proposed upscaling procedure for the Eastern Nankai Trough case.

Reservoir simulation with the cubic plus (cross-) association equation of state for water, CO2, hydrocarbons, and tracers

Abstract This work presents an efficient reservoir simulation framework for multicomponent, multiphase, compressible flow, based on the cubic-plus-association (CPA) equation of state (EOS). CPA is an accurate EOS for mixtures that contain non-polar hydrocarbons, self-associating polar water, and cross-associating molecules like methane, ethane, unsaturated hydrocarbons, CO2, and H2S. While CPA is accurate, its mathematical formulation is highly non-linear, resulting in excessive computational costs that have made the EOS unfeasible for large scale reservoir simulations. This work presents algorithms that overcome these bottlenecks and achieve an efficiency comparable to the much simpler cubic EOS approach. The main applications that require such accurate phase behavior modeling are 1) the study of methane leakage from high-pressure production wells and its potential impact on groundwater resources, 2) modeling of geological CO2 sequestration in brine aquifers when one is interested in more than the CO2 and H2O components, e.g. methane, other light hydrocarbons, and various tracers, and 3) enhanced oil recovery by CO2 injection in reservoirs that have previously been waterflooded or contain connate water. We present numerical examples of all those scenarios, extensive validation of the CPA EOS with experimental data, and analyses of the efficiency of our proposed numerical schemes. The accuracy, efficiency, and robustness of the presented phase split computations pave the way to more widespread adoption of CPA in reservoir simulators.