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We investigated numerical simulation strategies for a long-term test of depressurization-induced gas production from the B1 Sand of Unit B at the Hydrate-01 Stratigraphic Test Well. The main objective of this study was to estimate fluid production rates (with emphasis on water production) under a variety of conditions and production scenarios and contribute new insights to the design and management of the field test. In the first part of the study, we investigated the system response to a three-step depressurization process using two limiting sets of flow properties─the expected maximum and minimum intrinsic and effective permeabilities─for the very heterogeneous reservoir. In the second part, we investigated the effect of the production interval length and placement within the formation relative to the boundaries of the hydrate-bearing unit. The best performing well configuration was used in the third part of the study, which used the most representative subsurface flow properties to investigate the effect of the depressurization strategy on the production performance. The best overall performance (largest gas production with modest water production and a strong response at the observation wells) was obtained with a 10 m-long well situated 3 m below the top of the formation and a three-step depressurization scheme at 15-day intervals to a terminal bottomhole pressure of 2.8 MPa. The overall production performance was enhanced by a faster rate of depressurization. Estimated water production rates in all cases were limited and easily manageable. None of the tested well configurations or depressurization strategies significantly reduced water production without also severely reducing gas production. In all the investigated cases, 95% of the long-term fraction of produced water was replenished by inflows from the boundaries and could not be reduced. These substantial water inflows are an unavoidable feature of HU-B and cannot be easily mitigated by a hydraulic control.

We investigate by means of numerical simulation a planned year-long field test of depressurization-induced production from a permafrost-associated hydrate reservoir on the Alaska North Slope at the site of the recently drilled Hydrate-01 Stratigraphic Test Well. The main objective of this study is to assess quantitatively the impact of temporary interruptions (well shut-ins) on the expected fluid production performance from the B1 Sand of the stratigraphic Unit B during controlled depressurization over different time scales, as well as on other relevant aspects of the system response that have the potential to significantly affect the design of the field test. We consider eight different cases of depressurization, including (a) rapid depressurization over a 60-day period to a terminal bottomhole pressure PWof 2.8 MPa and (b) a slower depressurization rate to a final PWof 0.6 MPa at the end of the year-long production test, in addition to (c) a multi-step depressurization regime and (d) a quasi-linear continuous depressurization strategy. The results of the study indicate that shut-ins obviously reduce gas release and production during and immediately after their occurrence, but their longer-term effects are strongly dependent on the depressurization regime and on the time of observation, covering the entire range of potential outcomes. Shut-ins (a) have a universally strong negative effect when quasi-linear depressurization is involved regardless of the length of the production period, and (b) have a strong positive effect in multi-step depressurization schemes that becomes apparent earlier for large initial pressure drops, but (c) can also appear to have practically no effect for slow stepwise depressurization at the end of the year-long production test. Shut-ins lead to a rapid reformation of hydrates, even to the point of disappearance of a free gas phase in the reservoir. Rapid depressurization regimes lead to early maximum rates of hydrate dissociation and gas production, while the maximum rates occur at the end of the production test for the cases of slower depressurization. Shut-ins do not appear to have a significant impact on water production, as the cessation of production is followed by higher rates production when depressurization resumes. Similarly, (a) the fraction of produced CH4originating from exsolution from the water, (b) the water-to-gas ratio, and (c) the rate of replenishment of produced water by boundary inflows do not appear significantly affected by shut-ins, the effects of which seem to be temporary in the majority of the cases. The study confirmed the superiority of multi-step depressurization methods as the most effective strategies for hydrate dissociation and gas production and showed that two observation wells (located at distances of 30 and 50 m from the production well) are appropriately positioned and both able to capture the P, T, and SGbehavior during the fluid production and shut-ins in any of the eight cases we investigated.

We validate a coupled flow-geomechanics simulator for gas hydrate deposits, named T+MAM, performing two meter-scale laboratory experiments of gas hydrates for production by depressurization, replicating the gas hydrate deposit in the Ulleung Basin, East Sea, South Korea. The first experiment with a sand-only specimen is a 1D 1 m-scale depressurization test based on the excess gas method, which represents the grain coating hydrate growth. On the other hand, the second is a 3D 1.5 m-scale test with the excess water method for a sand–mud alternating layer system, representing the pore filling hydrate growth. We measure production and displacement at the top with different depressurization levels. In particular, the 3D test exhibits high coupling strength of substantial deformation induced by incompressibility of water and high deformability of the specimen. For validation, we match pressure, flow rate, and displacement between the experimental data and numerical results. Thus, we identify that T+MAM is a reliable simulator, which can be applied to fields in both permafrost and deep oceanic hydrate deposits of strongly coupled flow and geomechanics systems. This validation also implies that other coupled simulators based on the same coupling formulation as T+MAM can be validated when individual flow and geomechanics simulators are stable and reliable.

More accurate characterization and prediction of the in-situ distribution of fracturing fluid in fractured reservoirs are needed for enhancing well productivity. In this study, an implicit-sequentially coupled flow/geomechanics simulator incorporating an efficient discrete fracture model is developed to model fluid distribution and recovery performance of ultra-low permeability gas reservoirs. The finite-volume and finite-element methods are used for space discretization of the flow and geomechanics equations, respectively, while the backward Euler method is employed for time discretization. The flow and geomechanics equations are solved sequentially based on fixed-stress splitting. An efficient discrete-fracture model is used to explicitly model the fractured system. Flexible unstructured gridding is employed to model arbitrarily-oriented fractures. The interrelations among pore volume, permeability and geomechanical conditions are considered dynamically using two-way coupled flow and geomechanics computations. The geometry of fracture (networks) due to hydraulic fracturing has significant impacts on the fracturing fluid recovery efficiency and ensuing fluid distribution. Under the same injection volume, the fracturing fluid recovery is higher when the fracture geometry is planar. Fluid recovery is relatively lower whenever natural fractures are activated during fracturing treatments; flowback time is also shortened when complex fracture network with enlarged fracture interface is present. Fracturing fluid in hydraulic fractures may leak off into the natural fractures and subsequently imbibes into the surrounding matrix due to capillarity effects. The fracturing fluid recovery and in-situ fluid distribution are sensitive to the shut-in duration and fracture closure behavior. This study analyzes the coupled flow-geomechanical responses of fractured gas reservoirs during the post-fracturing periods. Understanding the fate of the fracturing fluid can provide insights on, to some extent, the stimulated fracture volume, size of the water invasion zone, and efficiency of the fracturing design. The simulation predictions can also provide more accurate initial reservoir conditions (e.g. distributions of different phases and pressure) for long-term well performance estimation.

The objective of this study is to quantify, by means of numerical simulation, the response of the complex system of gas hydrate accumulations at Site NGHP-02-09, Krishna-Godavari Basin, Indian Ocean, to different production conditions, and to determine the technical feasibility of gas production through depressurization-induced dissociation. The study assesses the suitability of the site for a long-term production test involving a single vertical well, and the long-term potential of the deposit under full-field production using a system of multiple vertical wells. We simulate gas and water flow, estimate the production performance of the accumulation and separately investigate the corresponding geomechanical response of the system. Results indicate that production from Site NGHP-02-09 under the conditions of a long-term field test involving a single vertical well is technically feasible and can yield high gas production rates. However, an inability to fully isolate the water bearing zones results in production that is largely from dissolved gas rather than hydrate dissociation and is thus burdened by excessive water production. Given the estimated physical properties of the reservoir system, Site NGHP-02-09 does not appear to be a promising location for a single-well field test of gas production, but may be a promising production target for full-field production operations using a multi-well system in which exterior wells can mitigate water inflows to allow interior wells to more effectively depressurize the formation and capture methane from gas hydrate dissociation. Geomechanical issues need to be carefully considered as significant displacements are possible, which can be challenging to well construction and stability.

The TOUGH+Millstone simulator has been developed for the analysis of coupled flow, thermal and geomechanical processes associated with the formation and/or dissociation of CH 4-hydrates in geological media. It is composed of two constituent codes: (a) a significantly enhanced version of the TOUGH+Hydrate simulator, v2.0, that accounts for all known flow, physical, thermodynamic and chemical processes associated with the evolution of hydrate-bearing systems and includes the most recent physical properties relationships, coupled seamlessly with (b) Millstone v1.0, a new code that addresses the conceptual, computational and mathematical shortcomings of earlier codes used to describe the geomechanical response of these systems. The capabilities of the TOUGH+Millstone code are demonstrated in the simulation and analysis of the system flow, thermal, and geomechanical behavior during gas production from a realistic complex offshore hydrate deposit. In the third paper of this series, we apply the simulators described in parts 1 and 2 to a problem of gas production from a complex, multilayered system of hydrate-bearing sediments in an oceanic environment. We perform flow simulations of constant-pressure production via a vertical well and compare those results to a coupled flow-geomechanical simulation of the same process. The results demonstrate the importance of fully coupled geomechanics when modeling the evolution of reservoir properties during production.

We investigate the feasibility of production from a layered marine gas hydrate reservoir using the properties and conditions corresponding to the UBGH2-6 site of the Ulleung Basin in the Korean East Sea. The work expands and furthers previous investigations in support of a proposed field test. The target system is location in deep water and consists of 13 m of alternating hydrate-bearing sand and soft mud layers and will be produced using a vertical well. We assess production potential during a 14-day field test, examine sensitivity to heterogeneity in permeability, porosity, and initial hydrate saturation, and assess the geomechanical response of the system to short-term production. Producing gas from the system appears to be technically feasible, however, low production rates and relatively large water production rates are expected during the field test. Expected subsidence and reservoir compaction is limited given the current data and the short timeframes of the production test.

TOUGH + Millstone has been developed for the analysis of coupled flow, thermal and geomechanical processes associated with the formation and/or dissociation of CH4-hydrates in geological media. It is composed of two constituent codes: (a) a significantly enhanced version of the TOUGH + HYDRATE simulator, V2.0, that accounts for all known flow, physical, thermodynamic and chemical processes associated with the behavior of hydrate-bearing systems undergoing changes and includes the most recent advances in the description of the system properties, coupled seamlessly with (b) Millstone V1.0, a new code that addresses the conceptual, computational and mathematical shortcomings of earlier codes used to describe the geomechanical response of these systems. The capabilities of TOUGH + Millstone are demonstrated in the simulation and analysis of the system flow, thermal and geomechanical behavior during gas production from a realistic complex offshore hydrate deposit. In the first paper of this series, we discuss the physics underlying the T + H hydrate simulator, the constitutive relationships describing the physical, chemical (equilibrium and kinetic) and thermal processes, the states of the CH 4+ H 2O system and the sources of critically important data, as well as the mathematical approaches used for the development of the of mass and energy balance equations and their solution. Additionally, we provide verification examples of the hydrate code against numerical results from the simulation of laboratory and field experiments.

The TOUGH+Millstone simulator has been developed for the analysis of coupled flow, thermal and geomechanical processes associated with the formation and/or dissociation of CH 4 hydrates in geological media. It is composed of two constituent codes: (a) a significantly enhanced version of the TOUGH+HYDRATE simulator, v2.0, that accounts for all known flow, physical, thermodynamic and chemical processes associated with the behavior of hydrate-bearing systems undergoing changes and includes the most recent advances in the description of the system properties, coupled seamlessly with (b) Millstone v1.0, a new code that addresses the conceptual, computational and mathematical shortcomings of earlier codes used to describe the geomechanical response of these systems. The capabilities of the TOUGH+Millstone code are demonstrated in the simulation and analysis of the system flow, thermal and geomechanical behavior during gas production from a realistic complex offshore hydrate deposit. In the second part of this series, we describe the Millstone geomechanical simulator. The hydrate-dependent, rate-based poromechanical formulation is presented and solved using a finite element discretization. A novel multimesh coupling scheme is introduced, wherein interpolators are automatically built to transfer data between the finite difference discretization of TOUGH+ and the finite element discretization of Millstone. We provide verification examples against analytic solutions for poroelasticity and a simplified demonstration problem for mechanically induced phase change in a hydrate sediment.

Reaction parameters significantly affect oil production from shales by means of heating and in-situ upgrading. In this study, we perform numerical simulations of two chemical reaction models, which are mainly used in the research of kerogen pyrolysis and subsequent hydrocarbon decomposition in organic-rich porous media. They are the Braun and Burnham model and Wellington model. In these forward numerical simulations, we present the influence of the two reaction models on hydrocarbon production. The Braun and Burnham reaction model shows more vigorous kerogen and subsequent decomposition reactions and more hydrocarbon production than the Wellington model. A local sensitivity analysis identifies the reaction parameters with the highest influence on productivity, and the most sensitive outputs. A data-worth analysis identifies the most valuable observation data to be measured for the best prediction of total hydrocarbon production. We find that the most valuable observation data is the cumulative production of heavy oil in the Braun and Burnham model and of light oil in the Wellington model, respectively. Once we determine the maximum allowable prediction uncertainty and the expected measurement uncertainty, the observation data to be measured for the minimization of prediction uncertainty can be obtained.

We analyze fracture propagation induced by hydraulic fracturing with water injection and examine their detectability with crosswell electromagnetic (EM) geophysical methods. For rigorous 3D coupled flow-geomechanical modeling, we employ a numerical method that can model failure by tensile and shear stresses, dynamic nonlinear permeability, dual continuum approach, and thermo-poro-mechanical effects. From numerical simulation, we find that the fracture propagation is not the same as propagation of the water front, because fracturing is governed by geomechanics whereas water saturation is determined by multiphase flow. At early times, the water front is almost identical to the fracture tip, suggesting that the fracture is mostly filled with the injected water. However, at late times, movement of the water front is retarded compared to fracture propagation, yielding a significant gap between the water front and the fracture top, filled with reservoir gas. During fracture propagation, the coupled flow-geomechanical models are transformed via a rock-physics model into electrical conductivity models. We employ a full 3D finite-element EM geophysical simulator to evaluate the sensitivity of the crosswell EM method to fracture propagation. It is shown that anomalous distribution of electrical conductivity is closely related to the injected water saturation, but not closely related to newly created unsaturated fractures. Our numerical modeling experiments demonstrate that the crosswell EM method can be highly sensitive to electrical conductivity changes that directly indicate the migration pathways of the injected fluid. Accordingly, the EM method can serve as an effective monitoring tool for monitoring the injected fluids during hydraulic fracturing operations.

Grade of oil shale and reaction parameters of in-situ pyrolysis must be identified for the prediction of productivity before actual heating and production. Identification of oil shale grade and reaction parameters depends on laboratory experiments on core samples. However, laboratory-determined parameters can be different from those representing in-situ reservoir conditions. In this study, we use inverse modeling to determine oil shale grade and reaction parameters. The inversions are based on a forward model that simulates heat injection into a well. Temperature at the heating well is affected by a thermal skin effect as a result of a decrease of composite thermal conductivity around the heater due to the decomposition-induced porosity increase. Synthetic observations of heater temperature are generated from a forward simulation. Temperature difference and its derivative are used in synthetic inversions to estimate oil shale grade and parameters of active decomposition reactions with an error below 1%. The proposed methodology of inverse modeling is expected to successfully estimate the oil shale grade and reaction parameters without core sampling and subsequent surface experiments.

The capability to conduct a rapid, near real-time model-based analysis of production data from tight/shale (TS) gas fields is important in determining fracture and matrix properties. Model-based analysis of production can range from simple analytical solutions to complex numerical models. The objective of this study is to develop a simple, Excel-based tool for the analysis of the complex problem of gas production from a fractured TS gas reservoir that is based on a robust model that is faithful to the underlying physics and can provide rapid estimates of the important system parameters. The scientifically robust model used as the basis for this tool is a significant modification and expansion of the bimodal production decline curve of Silin and Kneafsey (2012). The production period is divided into two regimes: an early-time regime before the extent of the stimulated reservoir volume (SRV) is felt, where an analytical similarity solution for gas production rate is obtained, and a late-time regime where the rate can be approximated with an exponential decline or more accurately represented with a numerical integration. Our basic model follows Silin and Kneafsey (2012) and produces the widely observed -½ slope on a log-log plot of early-time production decline curves, while our expanded model generalizes this slope to –n, where 0 < n < 1, to represent non-ideal flow geometries. The expanded model was programmed into an Excel spreadsheet to develop an interactive, user-friendly application for curve matching of well production data to the bimodal curve, from which matrix and fracture properties can be extracted. This tool allows significant insight into the model parameters that control the reservoir behavior and production: the geometry of the hydraulically-induced fracture network, its flow and transport properties, and the optimal operational parameters. This information enables informed choices about future operations, and is valuable in several different ways: (a) to estimate reserves and to predict future production, including expected ultimate recovery and the useful lifetime of the stage or the well; (b) if curve-matching is unsuccessful, to indicate the inadequacy of the mathematical model and the need for more complex numerical model to analyze the system; (c) to verify/validate numerical models, and to identify anomalous behavior or measurement errors in the data. The present approach can be adapted to gas-flow problems in dual-permeability media (hydraulically or naturally fractured) or highly heterogeneous sedimentary rock, as well as to retrograde condensation.

A recent Department of Energy field test on the Alaska North Slope has increased interest in the ability to simulate systems of mixed CO2-CH4 hydrates. However, the physically realistic simulation of mixed-hydrate simulation is not yet a fully solved problem. Limited quantitative laboratory data leads to the use of various ab initio, statistical mechanical, or other mathematic representations of mixed-hydrate phase behavior. Few of these methods are suitable for inclusion in reservoir simulations, particularly for systems with large number of grid elements, 3D systems, or systems with complex geometric configurations. In this work, we present a set of fast parametric relationships describing the thermodynamic properties and phase behavior of a mixed methane-carbon dioxide hydrate system. We use well-known, off-the-shelf hydrate physical properties packages to generate a sufficiently large dataset, select the most convenient and efficient mathematical forms, and fit the data to those forms to create a physical properties package suitable for inclusion in the TOUGH+ family of codes. The mapping of the phase and thermodynamic space reveals the complexity of the mixed-hydrate system and allows understanding of the thermodynamics at a level beyond what much of the existing laboratory data and literature currently offer.

We investigate the productivity and product selectivity of diverse thermal in situ upgrading processes in oil shale reservoirs. In situ upgrading processes applying the ideas of Shell In situ Conversion Process, ExxonMobil Electrofrac, and Texas A&M Steamfrac are simulated by using sector models with the assumption of symmetric patterns. In-house fully functional simulator is used, which has been developed for the kerogen pyrolysis and hydrocarbon production. In the simulation cases, sensitivity analyses to the factors having major influence on the productivity and product selectivity are conducted. The effects of the temperature of vertical heaters, the spacing of hydraulic fractures, and the position of horizontal production wells are analyzed in the applied In situ Conversion Process, Electrofrac, and Steamfrac, respectively. In the applied In situ Conversion Process cases, hydrocarbon production increases with the increasing heater temperature. In the applied Electrofrac cases, hydrocarbon production increases with the increasing spacing of hydraulic fractures, even though longer time period for the process is needed. In the applied Steamfrac cases, the case of production well located at the same depth to the injection well shows the least hydrocarbon production. Among the processes, the applied In situ Conversion Process cases show the highest weight percentage of total hydrocarbon components in the produced fluid, and the applied Electrofrac cases follow it. The applied Steamfrac cases show far lower weight percentage of hydrocarbon production than the other methods. In terms of the mass ratio of produced hydrocarbon to decomposed kerogen, the applied Steamfrac cases show the largest value among the processes by aqueous phase sweeping liquid organic phase, but they also show the huge water oil mass ratio by the continuous injection of hot water. All the applied In situ Conversion Process cases and the Electrofrac case with the short spacing of hydraulic fractures show good heating efficiency by decomposing whole kerogen in the system.

We have studied the hydrocarbon production from oil shale reservoirs filled with diverse initial saturations of fluid phases by implementing numerical simulations of various thermal in-situ upgrading processes. We use our in-house fully functional, fully implicit, and non-isothermal simulator, which describes the in-situ upgrading processes and hydrocarbon recovery by multiphase-multicomponent systems. We have conducted two sets of simulation cases—five-spot well pattern problems and Shell In-situ Conversion Process (ICP) problems. In the five-spot well pattern problems, we have analyzed the effects of initial fluid phase that fills the single-phase reservoir and thermal processes by four cases—electrical heating in the single-phase-aqueous reservoir, electrical heating in the single-phase-gaseous reservoir, hot water injection in the single-phase-aqueous reservoir, and hot CO2 injection in the single-phase-gaseous reservoir. In the ICP problems, we have analyzed the effects of initial saturations of fluid phases that fill two-phase-aqueous-and-gaseous reservoir by three cases—initial aqueous phase saturations of 0.16, 0.44, and 0.72. Through the simulation cases, system response and production behavior including temperature profile, kerogen fraction profile, evolution of effective porosity and absolute permeability, phase production, and product selectivity are analyzed. In the five-spot well pattern problems, it is found that the hot water injection in the aqueous phase reservoir shows the highest total hydrocarbon production, but also shows the highest water-oil-mass-ratio. Productions of phases and components show very different behavior in the cases of electrical heating in the aqueous phase reservoir and the gaseous phase reservoir. In the ICP problems, it is found that the speed of kerogen decomposition is almost identical in the cases, but the production behavior of phases and components is very different. It is found that more liquid organic phase has been produced in the case with the higher initial saturation of aqueous phase by the less production of gaseous phase.

Subterranean structures such as aquifers and depleted gas reservoirs (DGRs) offer a scalable, high-pressure, secure, cost-efficient, and ecologically friendly means of hydrogen (H 2) storage. Underground H 2 storage (UHS) has emerged as a potential solution to alleviate the imbalance between the fluctuating renewable energy generation and the demand for a constant energy supply. Quantifying the recovery efficiency is of paramount importance in the effort toward large-scale UHS. In this numerical simulation study, we employed a high-resolution grid for the discretization of a synthetic (but realistic) heterogeneous anticline intended as a H 2 storage facility, and we assessed the H 2 recovery efficiency, and the purity of produced gas associated with UHS in natural reservoirs involving different pre-existing gases and their quantities. All of these studies included an initial phase of cushion gas injection, followed by 4 cycles of H 2 storage operations composed of injection-idle-withdrawal periods. The simulation results indicated that the H 2 round-trip recovery efficiency R H increased (a) with an increasing number of storage cycles, routinely exceeding 90% and providing evidence of a self-enhancement or self-optimization H 2 recovery mechanism and (b) with an increasing amount of pre-existing gas in the storage zone prior to the H 2 injections — at the end of the 4-cycle test, the highest R H is associated with a DGR with a pre-existing gas consisting of residual CH 4 and additional injected N 2 , and the lowest R H corresponds to an aquifer with no cushion gas. Conversely, the H 2 mass fraction of the produced gas F HQ (a) increased with an increasing number of storage cycles, but (b) decreased rapidly with an increasing amount of pre-existing gas. The presence of a pre-existing gas inevitably leads to severe contamination of the produced H 2 , which never exceeds 40% in the produced gas, can be as low as 4% in early cycles, and cannot be used as a H 2 fuel without gas separation. Aquifer storage without a cushion gas may exhibit the lowest H 2 recovery (about 75% in the long run), but yields practically pure H 2 that does not require further processing before use. A positive conclusion is that, under the conditions of this study, total H 2 losses (including H 2 escaping into the caprock, and inaccessible H 2 dissolved in the aqueous phase of the formation or remaining in the gas storage zone) are limited and manageable, indicating the technical feasibility of geologic H 2 storage. • Discussed the advantages and disadvantages of H 2 storage (UHS) in aquifers and depleted gas reservoirs (DGRs). • Explained reasons for the benefits of cushion gas (CG) or DGRs in UHS performance using material balance theory. • Injecting CG or adding cycles enhances the UHS performance by improving the overall compressibility of reservoirs. • Pre-existing gas improves the H 2 recovery efficiency but leads to the contamination of produced H 2. • Quantified the H 2 loss evolution during a UHS consisting of four injection-idle-withdrawal cycles. [ABSTRACT FROM AUTHOR]

Hydraulic fracturing has been recognized as the necessary well completion technique to achieve economic production from shale gas formation. However, following the fracturing, fluid–wall interactions can form a damaged zone nearby the fracture characterized by strong capillarity and osmosis effects. Here, we present a new reservoir multi-phase flow model which includes these mechanisms to predict formation damage in the aftermath of the fracturing during shut-in and production periods. In the model, the shale matrix is treated as a multi-scale porosity medium including interconnected organic, inorganic slit-shaped, and clay porosity fields. Prior to the fracturing, the matrix holds gas in the organic and the inorganic slit-shaped pores, water with dissolved salt in the inorganic slit-shaped pores and the clay pores. During and after fracturing, imbibition causes water invasion into the matrix, and then, the injected water–clay interaction may lead to clay-swelling pressure development due to osmosis. The swelling pressure gives additional stress to slit-shaped pores and cause permeability reduction in the inorganic matrix. We develop a simulator describing a system of three pores, two phases (aqueous and gaseous phases), and three components (H 2O , CH 4, and salt), including osmosis and clay-swelling effect on the permeability. The simulation of aqueous-phase transport through clay shows that high swelling pressure can occur in clays as function of salt type, salt concentration difference, and clay-membrane efficiency. The new model is used to demonstrate the damage zone characteristics. The simulation of two-phase flow through the shale formation shows that, although fracturing is a rapid process, fluid–wall interactions continue to occur after the fracturing due to imbibition mechanism, which allows water to penetrate into the inorganic pore network and displace the gas in-place near the fracture. This water invasion leads to osmosis effect in the formation, which cause clay swelling and the subsequent permeability reduction. Continuing shale–water interactions during the production period can expand the damage zone further.

We conduct numerical simulations of kerogen pyrolysis by the in situ upgrading process of Steamfrac, which entails the steam or hot-water injection into multistage transverse fractured horizontal well systems, by using a fully functional simulator developed to describe the in situ upgrading process. We first conduct simulation cases of a huff-n-puff method to analyze the sensitivity of temperature distribution of the reservoir to the positions of horizontal wells. Then, we conduct continuous hot-water injection and simultaneous fluid production cases, and analyze the productivity by applying two different irreducible saturations of aqueous phase in the rock matrix.

Hydrocarbon production from unconventional resources and the use of reservoir stimulation techniques, such as hydraulic fracturing, has grown explosively over the last decade. However, concerns have arisen that reservoir stimulation creates significant environmental threats through the creation of permeable pathways connecting the stimulated reservoir with shallower freshwater aquifers, thus resulting in the contamination of potable groundwater by escaping hydrocarbons or other reservoir fluids. This study investigates, by numerical simulation, gas and water transport between a shallow tight-gas reservoir and a shallower overlying freshwater aquifer following hydraulic fracturing operations, if such a connecting pathway has been created. We focus on two general failure scenarios: (1) communication between the reservoir and aquifer via a connecting fracture or fault and (2) communication via a deteriorated, preexisting nearby well. We conclude that the key factors driving short-term transport of gas include high permeability for the connecting pathway and the overall volume of the connecting feature. Production from the reservoir is likely to mitigate release through reduction of available free gas and lowering of reservoir pressure, and not producing may increase the potential for release. We also find that hydrostatic tight-gas reservoirs are unlikely to act as a continuing source of migrating gas, as gas contained within the newly formed hydraulic fracture is the primary source for potential contamination. Such incidents of gas escape are likely to be limited in duration and scope for hydrostatic reservoirs. Reliable field and laboratory data must be acquired to constrain the factors and determine the likelihood of these outcomes.Key pointsShort-term leakage fractured reservoirs requires high-permeability pathways Production strategy affects the likelihood and magnitude of gas release Gas release is likely short-term, without additional driving forces.

We conducted three-dimensional coupled fluid-flow and geomechanical modeling of fault activation and seismicity associated with hydraulic fracturing stimulation of a shale-gas reservoir. We simulated a case in which a horizontal injection well intersects a steeply dipping fault, with hydraulic fracturing channeled within the fault, during a 3-h hydraulic fracturing stage. Consistent with field observations, the simulation results show that shale-gas hydraulic fracturing along faults does not likely induce seismic events that could be felt on the ground surface, but rather results in numerous small microseismic events, as well as aseismic deformations along with the fracture propagation. The calculated seismic moment magnitudes ranged from about -2.0 to 0.5, except for one case assuming a very brittle fault with low residual shear strength, for which the magnitude was 2.3, an event that would likely go unnoticed or might be barely felt by humans at its epicenter. The calculated moment magnitudes showed a dependency on injection depth and fault dip. We attribute such dependency to variation in shear stress on the fault plane and associated variation in stress drop upon reactivation. Our simulations showed that at the end of the 3-h injection, the rupture zone associated with tensile and shear failure extended to a maximum radius of about 200. m from the injection well. The results of this modeling study for steeply dipping faults at 1000 to 2500. m depth is in agreement with earlier studies and field observations showing that it is very unlikely that activation of a fault by shale-gas hydraulic fracturing at great depth (thousands of meters) could cause felt seismicity or create a new flow path (through fault rupture) that could reach shallow groundwater resources.

Gas hydrate deposits were confirmed in the Shenhu Area, the north slope of South China Sea during a drilling expedition in 2007. Hydrate deposits in the area are distributed in disseminated forms in forams-rich clay sediments with permeable overburden and underburden layers. Production of gas from such a type of hydrate deposits is very challenging. In this study, we develop a numerical approach for investigation of gas production strategies by horizontal wells and preliminary estimation of the production potential based on the limited data that are currently available. Numerical models are built to represent the typical hydrate deposits in the area, including the thickness of the Hydrate-Bearing Layer (HBL), hydrate saturation, water depth, temperature at the sea floor, initial thermal gradient and pressure distribution. The models are used to simulate the different production schemes and well designs. In this paper, production strategies of horizontal well system with combination of depressurization and thermal stimulation are investigated through numerical models. Gas production potential from the deposits and effectiveness of the different production methods are evaluated. The simulation results indicate that with current technology, gas production from Shenhu hydrate deposits may not be economically efficient for all the production strategies we have investigated. Copyright 2010, Society of Petroleum Engineers.

Measurements on hydrate-bearing laboratory and field samples are necessary in order to provide realistic bounds on parameters used in numerically modeling the production of natural gas from hydrate-bearing reservoirs. The needed parameters include thermal conductivity, permeability, relative permeability-saturation(s) relationships, and capillary pressure-saturation(s) relationships. We have developed a technique to make hydrate-bearing samples ranging in scale from core plug-size to core-size in the laboratory to facilitate making these measurements. In addition to pressure and temperature measurements, we use x-ray computed tomography scanning to provide high-resolution data providing insights on processes occurring in our samples. Several methods are available to make gas hydrates in the laboratory, and we expect that the method used to make the hydrate will impact the behavior of the hydrate sample, and the parameters measured.

Gas hydrates are solid crystalline compounds in which gas molecules are lodged within the lattices of ice crystals. Vast amounts of CH4 are trapped in gas hydrates, and a significant effort has recently begun to evaluate hydrate deposits as a potential energy source. Class 3 hydrate deposits are characterized by an isolated Hydrate-Bearing Layer (HBL) that is not in contact with any hydrate-free zone of mobile fluids. The base of the HBL in Class 3 deposits may occur within or at the edge of the zone of thermodynamic hydrate stability.In this numerical study of long-term gas production from typical representatives of unfractured Class 3 deposits, we determine that simple thermal stimulation appears to be a slow and inefficient production method. Electrical heating and warm water injection result in very low production rates (4 and 12 MSCFD, respectively) that are orders of magnitude lower than generally acceptable standards of commercial viability of gas production from oceanic reservoirs. However, production from depressurization-based dissociation based on a constant well pressure appears to be a promising approach even in deposits characterized by high hydrate saturations. This approach allows the production of very large volumes of hydrate-originating gas at high rates (>15 MMSCFD, with a long-term average of about 8.1 MMSCFD for the reference case) for long times using conventional technology. Gas production from hydrates is accompanied by a significant production of water. However, unlike conventional gas reservoirs, the water production rate declines with time. The low salinity of the produced water may require care in its disposal. Because of the overwhelming advantage of depressurization-based methods, the sensitivity analysis was not extendedto thermal stimulation methods. The simulation results indicate that depressurization-induced gas production from oceanic Class 3 deposits increases (and the corresponding water to-gas ratio decreases) with increasing hydrate temperature (which defines the hydrate stability), increasing intrinsic permeability of the HBL, and decreasing hydrate saturation although depletion of the hydrate may complicate the picture in the latter case.

In this study we compare the use of kinetic and equilibrium reaction models in the simulation of gas (methane) hydrate behavior in porous media. Our objective is to evaluate through numerical simulation the importance of employing kinetic versus equilibrium reaction models for predicting the response of hydrate-bearing systems to external stimuli, such as changes in pressure and temperature. Specifically, we (1) analyze and compare the responses simulated using both reaction models for natural gas production from hydrates in various settings and for the case of depressurization in a hydrate-bearing core during extraction; and (2) examine the sensitivity to factors such as initial hydrate saturation, hydrate reaction surface area, and numerical discretization. We find that for large-scale systems undergoing thermal stimulation and depressurization, the calculated responses for both reaction models are remarkably similar, though some differences are observed at early times. However, for modeling short-term processes, such as the rapid recovery of a hydrate-bearing core, kinetic limitations can be important, and neglecting them may lead to significant under-prediction of recoverable hydrate. The use of the equilibrium reaction model often appears to be justified and preferred for simulating the behavior of gas hydrates, given that the computational demands for the kinetic reaction model far exceed those for the equilibrium reaction model.

In this study we compare the use of kinetic and equilibrium reaction models in the simulation of gas (methane) hydrate behavior in porous media. Our objective is to evaluate through numerical simulation the importance of employing kinetic versus equilibrium reaction models for predicting the response of hydrate-bearing systems to external stimuli, such as changes in pressure and temperature. Specifically, we (1) analyze and compare the responses simulated using both reaction models for natural gas production from hydrates in various settings and for the case of depressurization in a hydrate-bearing core during extraction; and (2) examine the sensitivity to factors such as initial hydrate saturation, hydrate reaction surface area, and numerical discretization. We find that for large-scale systems undergoing thermal stimulation and depressurization, the calculated responses for both reaction models are remarkably similar, though some differences are observed at early times. However, for modeling short-term processes, such as the rapid recovery of a hydrate-bearing core, kinetic limitations can be important, and neglecting them may lead to significant under-prediction of recoverable hydrate. Assuming validity of the most accurate kinetic reaction model that is currently available, the use of the equilibrium reaction model often appears to be justified and preferred for simulating the behavior of gas hydrates, given that the computational demands for the kinetic reaction model far exceed those for the equilibrium reaction model.

We discuss the range of activities at Lawrence Berkeley National Laboratory in support of gas production from natural hydrates. Investigations of production from the various classes of hydrate deposits by numerical simulation indicate their significant promise as potential energy sources. Laboratory studies are coordinated with the numerical studies and are designed to address knowledge gaps that are important to the prediction of gas production. Our involvement in field tests is also briefly discussed.

In this paper we evaluate the gas production potential of disperse, low-saturation (SH < 0.1) hydrate accumulations in oceanic sediments. Such hydrate-bearing sediments constitute a significant portion of the global hydrate inventory. Using numerical simulation, we estimate (a) the rates of gas production and gas release from hydrate dissociation, (b) the corresponding cumulative volumes of released and produced gas, as well as (c) the water production rate and the mass of produced water from disperse, low-SH hydrate-bearing sediments subject to depressurization-induced dissociation over a 10-year production period. We investigate the sensitivity of items (a) to (c) to the following hydraulic properties, reservoir conditions, and operational parameters: intrinsic permeability, porosity, pressure, temperature, hydrate saturation, and constant pressure at which the production well is kept. The results of this study indicate that, despite wide variations in the aforementioned parameters (covering the entire spectrum of such deposits), gas production is very limited, never exceeding a few thousand cubic meters of gas during the 10-year production period. Such low production volumes are orders of magnitude below commonly accepted standards of economic viability, and are further burdened with very unfavorable gas-to-water ratios. The unequivocal conclusion from this study is that disperse, low-SH hydrate accumulations in oceanic sediments are not promising targets for gas production by means of depressurization-induced dissociation, and resources for early hydrate exploitation should be focused elsewhere.

We determined the composite thermal conductivity (ktheta) of a porous methanehydrate sample (composedof hydrate, water, and methan e gas) as a function of density using iTOUGH2. X-ray computed tomography (CT) was used to visualize and quantify the density changes that occurred during hydrate formation from granular ice. The composite thermal conductivity was estimated and validated by minimizing the differences between the observed and the predicted thermal response using history matching. The estimated density-dependent composite thermal conductivity ranged between 0.25 and 0.58 W/m/K.

In this study we compare the use of kinetic and equilibrium reaction models in the simulation of gas (methane) hydrates in porous media. Our objective is to evaluate through numerical simulation the importance of employing kinetic versus equilibrium reaction models for predicting the response of hydrate-bearing systems to external stimuli, such as changes in pressure and temperature. Specifically, we (1) analyze and compare the responses simulated using both reaction models for production in various geological settings and for the case of depressurization in a core during extraction; and (2) examine the sensitivity to factors such as initial hydrate saturation, hydrate reaction surface area, and numerical discretization. We find that for systems undergoing thermal stimulation and depressurization, the calculated responses for both reaction models are remarkably similar, though some differences are observed at early times. Given these observations, and since the computational demands for the kinetic reaction model far exceed those for the equilibrium reaction model, the use of the equilibrium reaction model often appears to be justified and preferred for simulating the behavior of gas hydrates.

Class 1 hydrate deposits are characterized by a Hy-drate-Bearing Layer (HBL) underlain by a two-phase zone involving mobile gas. Such deposits are further divided to Class 1W (involving water and hydrate in the HBL) and Class 1G (involving gas and hydrate in the HBL). In Class 2 deposits, a mobile water zone underlies the hydrate zone. Methane is the main hydrate-forming gas in natural accumulations. Using TOUGH-FX/HYDRATE to study the depressurization-induced gas production from such deposits, we determine that large volumes of gas could be readily produced at high rates for long times using conventional technology. Dissociation in Class 1W deposits proceeds in distinct stages, but is continuous in Class 1G deposits. Hydrates are shown to contribute significantly to the production rate (up to 65 percent and 75 percent in Class 1W and 1G, respectively) and to the cumulative volume of produced gas (up to 45 percent and 54 percent in Class 1W and 1G, respectively). Large volumes of hydrate-originating CH4 could be produced from Class 2 hydrates, but a relatively long lead time would be needed before gas production (which continuously increases over time) attains a substantial level. The permeability of the confining boundaries plays a significant role in gas production from Class 2 deposits. In general, long-term production is needed to realize the full potential of the very promising Class 1 and Class 2 hydrate deposits.

We use TOUGH+/GasH2O to study the effects of a heat source buried in the Martian permafrost to evaluate the possibility of establishing a wet zone of liquid water, in which terrestrial microorganisms could survive and multiply. Analysis of the problem indicates that (1) only a limited permafrost volume (not exceeding 0.35 m in radius) is affected, (2) a "wet" zone with limited amounts of liquid water de-velops (not exceeding 8 and 0.7 kg for a 250 W and a 62.5 W source, respectively), (3) the wet zone per-sists for a long time, becomes practically stationary after t = 20 sols because of venting into the Martian atmosphere, and its thickness is limited and decreases slowly over time, (4) a "dry" zone (where SG > 0.9) evolves, continues to expand (albeit slowly) with time, but its extent remains limited, and (5) the ice front surrounding the wet zone is self-sharpening. For a range of initial conditions investigated, evolution of the liquid water mass occurs at approximately the same rate, reaches roughly the same maximum, and occurs at about the same time (10 to 20 sols; 1 sol = 24.39 hours).

The relative permeability to fluids in hydrate-bearing sediments is an important parameter for predicting natural gas production from gas hydrate reservoirs. We estimated the relative permeability parameters (van Genuchten alpha and m) in a hydrate-bearing sand by means of inverse modeling, which involved matching water saturation predictions with observations from a controlled waterflood experiment. We used x-ray computed tomography (CT) scanning to determine both the porosity and the hydrate and aqueous phase saturation distributions in the samples. X-ray CT images showed that hydrate and aqueous phase saturations are non-uniform, and that water flow focuses in regions of lower hydrate saturation. The relative permeability parameters were estimated at two locations in each sample. Differences between the estimated parameter sets at the two locations were attributed to heterogeneity in the hydrate saturation. Better estimates of the relative permeability parameters require further refinement of the experimental design, and better description of heterogeneity in the numerical inversions.

We performed a sequence of tests on a partially water-saturated sand sample contained in an x-ray transparent aluminum pressure vessel that is conducive to x-ray computed tomography (CT) observation. These tests were performed to gather data for estimation of thermal properties of the sand/water/gas system and the sand/hydrate/water/gas systems, as well as data to evaluate the kinetic nature of hydrate dissociation. The tests included mild thermal perturbations for the estimation of the thermal properties of the sand/water/gas system, hydrate formation, thermal perturbations with hydrate in the stability zone, hydrate dissociation through thermal stimulation, additional hydrate formation, and hydrate dissociation through depressurization with thermal stimulation. Density changes throughout the sample were observed as a result of hydrate formation and dissociation, and these processes induced capillary pressure changes that altered local water saturation.

The objective of this study is the description of the kinetic dissociation of CH4-hydrates in porous media, and the determination of the corresponding kinetic parameters. Knowledge of the kinetic dissociation behavior of hydrates can play a critical role in the evaluation of gas production potential of gas hydrate accumulations in geologic media. We analyzed data from a sequence of tests of CH4-hydrate dissociation by means of thermal stimulation. These tests had been conducted on sand cores partially saturated with water, hydrate and CH4 gas, and contained in an x-ray-transparent aluminum pressure vessel. The pressure, volume of released gas, and temperature (at several locations within the cores) were measured. To avoid misinterpreting local changes as global processes, x-ray computed tomography scans provided accurate images of the location and movement of the reaction interface during the course of the experiments. Analysis of the data by means of inverse modeling (history matching) provided estimates of the thermal properties and of the kinetic parameters of the hydration reaction in porous media. Comparison of the results from the hydrate-bearing porous media cores to those from pure CH4-hydrate samples provided a measure of the effect of the porous medium on the kinetic reaction. A tentative model of composite thermal conductivity of hydrate-bearing media was also developed.