Various attempts have been made to model flow in shale gas systems. However, there is currently little consensus regarding the impact of molecular and Knudsen diffusion on flow behavior over time in ...such systems. Direct measurement or model-based estimation of matrix permeability for these “ultra-tight” reservoirs has proven unreliable. The composition of gas produced from tight gas and shale gas reservoirs varies with time for a variety of reasons. The cause of flowing gas compositional change typically cited is selective desorption of gases from the surface of the kerogen in the case of shale. However, other drivers for gas fractionation are important when pore throat dimensions are small enough. Pore throat diameters on the order of molecular mean free path lengths will create non-Darcy flow conditions, where permeability becomes a strong function of pressure. At the low permeabilities found in shale gas systems, the dusty-gas model for flow should be used, which couples diffusion to advective flow. In this study we implement the dusty-gas model into a fluid flow modeling tool based on the TOUGH+ family of codes. We examine the effects of Knudsen diffusion on gas composition in ultra-tight rock. We show that for very small average pore throat diameters, lighter gases are preferentially produced at concentrations significantly higher than in situ conditions. Furthermore, we illustrate a methodology which uses measurements of gas composition to more uniquely determine the permeability of tight reservoirs. We also describe how gas composition measurement could be used to identify flow boundaries in these reservoir systems. We discuss how new measurement techniques and data collection practices should be implemented in order to take advantage of this method. Our contributions include a new, fit-for-purpose numerical model based on the TOUGH+ code capable of characterizing transport effects including permeability adjustment and diffusion in micro- and nano-scale porous media.
The behavior of fluids in confined spaces is important in several research fields, including the oil and gas industry, because of the importance of confined hydrocarbons in unconventional shale ...reservoirs. A large percentage of the hydrocarbons are contained in nanoscale shale pores, and as a result, interactions between fluid molecules and the pore walls become significant to the fluid behavior and cause deviations of the fluid properties from bulk properties. In this work, classical molecular dynamics (MD) simulations and grand canonical Monte Carlo (GCMC) simulations are performed to model kerogen pores in shale reservoirs and their effect on adsorption selectivity and phase equilibria of hydrocarbon mixtures in a wide range of temperatures and pressures. A slit pore made of graphite walls is used to represent the basic unit where a fluid may be stored in shale reservoirs. The separation between graphite layers is varied to observe the effect of confinement on the adsorption selectivity and phase equilibrium of methane–ethane mixtures. Results from GCMC and MD simulations show that ethane is preferred over methane in the confined system. Moreover, most fluid molecules in the confined system tend to be adsorbed on the pore walls instead of remaining in the gas phase. Preferential interactions between the fluid molecules and the pore walls induce changes in the phase diagram in the confined system. Results from GCMC simulations show shifts with respect to the bulk pressure–composition phase diagram that becomes more pronounced as the pore size decreases.
As part of an effort to identify suitable targets for a planned long-term field test, we investigate by means of numerical simulation the gas production potential from unit D, a stratigraphically ...bounded (Class 3) permafrost-associated hydrate occurrence penetrated in the BPXA-DOE-USGS Mount Elbert Gas Hydrate Stratigraphic Test Well on North Slope, Alaska. This shallow, low-pressure deposit has high porosities (ϕ = 0.4), high intrinsic permeabilities (
k = 10
−12 m
2) and high hydrate saturations (
S
H = 0.65). It has a low temperature (
T = 2.3–2.6 °C) because of its proximity to the overlying permafrost. The simulation results indicate that vertical wells operating at a constant bottomhole pressure would produce at very low rates for a very long period. Horizontal wells increase gas production by almost two orders of magnitude, but production remains low. Sensitivity analysis indicates that the initial deposit temperature is by the far the most important factor determining production performance (and the most effective criterion for target selection) because it controls the sensible heat available to fuel dissociation. Thus, a 1 °C increase in temperature is sufficient to increase the production rate by a factor of almost 8. Production also increases with a decreasing hydrate saturation (because of a larger effective permeability for a given
k), and is favored (to a lesser extent) by anisotropy.
In this paper, we evaluate the gas production potential of disperse, low-saturation (
S
H
<
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-
S
H hydrate-bearing sediments subject to depressurization-induced dissociation over a 10-year production period. We investigate the sensitivity of items (a)–(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-
S
H 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.
This work develops a model and rapid simulation strategy for the electrically-driven dissociation (unlocking) of subsurface gas hydrates. There are two schools of thought, as to how electrical fields ...can dissociate gas hydrates:
Case 1: gas hydrates are dissociated (unlocked) by an appropriate intensity and frequency of the electric field,
Case 2: gas hydrates are dissociated by an appropriate level of Joule heating.
In either case, one must resolve the thermoelectric fields within a heterogeneous medium consisting of encapsulated gas hydrates in a interstitial material. Accordingly, the objective of this work is to develop an easy-to-calibrate model and rapid simulation strategy to guide the delivery of an appropriate current and electrical field, as well as an appropriate level of Joule heating. The approach utilizes a coupled system of equations based on: (1) an electrical-flow submodel, (2) a thermal field evolution submodel, (3) a thermoelectric and frequency-dependent attenuation and (4) a spatio-temporal Finite-Difference Time Domain (FDTD) discretization of the coupled field equations. The model can be rapidly computed and allows analysts to vary parameters quickly, which facilitates the potential use of Machine Learning paradigms for data-model calibration. Numerical studies are provided to illustrate the behavior of the model.
Geologic reservoirs containing gas hydrate occur beneath permafrost environments and within marine continental slope sediments, representing a potentially vast natural gas source. Numerical ...simulators provide scientists and engineers with tools for understanding how production efficiency depends on the numerous, interdependent (coupled) processes associated with potential production strategies for these gas hydrate reservoirs. Confidence in the modeling and forecasting abilities of these gas hydrate reservoir simulators (GHRSs) grows with successful comparisons against laboratory and field test results, but such results are rare, particularly in natural settings. The hydrate community recognized another approach to building confidence in the GHRS: comparing simulation results between independently developed and executed computer codes on structured problems specifically tailored to the interdependent processes relevant for gas hydrate-bearing systems. The United States Department of Energy, National Energy Technology Laboratory, (DOE/NETL), sponsored the first international gas hydrate code comparison study, IGHCCS1, in the early 2000s. IGHCCS1 focused on coupled thermal and hydrologic processes associated with producing gas hydrates from geologic reservoirs via depressurization and thermal stimulation. Subsequently, GHRSs have advanced to model more complex production technologies and incorporate geomechanical processes into the existing framework of coupled thermal and hydrologic modeling.
This paper contributes to the validation of these recent GHRS developments by providing results from a second GHRS code comparison study, IGHCCS2, also sponsored by DOE/NETL. IGHCCS2 includes participants from an international collection of universities, research institutes, industry, national laboratories, and national geologic surveys. Study participants developed a series of five benchmark problems principally involving gas hydrate processes with geomechanical components. The five problems range from simple geometries with analytical solutions to a representation of the world's first offshore production test of methane hydrates, which was conducted with the depressurization method off the coast of Japan. To identify strengths and limitations in the various GHRSs, study participants submitted solutions for the benchmark problems and discussed differing results via teleconferences. The GHRSs evolved over the course of IGHCCS2 as researchers modified their simulators to reflect new insights, lessons learned, and suggested performance enhancements. The five benchmark problems, final sample solutions, and lessons learned that are presented here document the study outcomes and serve as a reference guide for developing and testing gas hydrate reservoir simulators.
•Code comparisons build confidence in simulators to model interdependent processes.•International hydrate reservoir simulators are compared over five complex problems.•Geomechanical processes significantly impact response of gas hydrate reservoirs.•Simulators yielded comparable results, however many differences are noted.•Equivalent constitutive models are required to achieve agreement across simulators.
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.
Following the results from the open-hole formation pressure response test in the BPXA-DOE-USGS Mount Elbert Gas Hydrate Stratigraphic Test Well (Mount Elbert well) using Schlumberger's Modular ...Dynamics Formation Tester (MDT) wireline tool, the International Methane Hydrate Reservoir Simulator Code Comparison project performed long-term reservoir simulations on three different model reservoirs. These descriptions were based on 1) the Mount Elbert gas hydrate accumulation as delineated by an extensive history-matching exercise, 2) an estimation of the hydrate accumulation near the Prudhoe Bay L-pad, and 3) a reservoir that would be down-dip of the Prudhoe Bay L-pad and therefore warmer and deeper. All of these simulations were based, in part, on the results of the MDT results from the Mount Elbert Well. The comparison group's consensus value for the initial permeability of the hydrate-filled reservoir (
k = 0.12 mD) and the permeability model based on the MDT history match were used as the basis for subsequent simulations on the three regional scenarios. The simulation results of the five different simulation codes, CMG STARS, HydrateResSim, MH-21 HYDRES, STOMP-HYD, and TOUGH+HYDRATE exhibit good qualitative agreement and the variability of potential methane production rates from gas hydrate reservoirs is illustrated. As expected, the predicted methane production rate increased with increasing
in situ reservoir temperature; however, a significant delay in the onset of rapid hydrate dissociation is observed for a cold, homogeneous reservoir and it is found to be repeatable. The inclusion of reservoir heterogeneity in the description of this cold reservoir is shown to eliminate this delayed production. Overall, simulations utilized detailed information collected across the Mount Elbert reservoir either obtained or determined from geophysical well logs, including thickness (37 ft), porosity (35%), hydrate saturation (65%), intrinsic permeability (1000 mD), pore water salinity (5 ppt), and formation temperature (3.3–3.9 °C). This paper presents the approach and results of extrapolating regional forward production modeling from history-matching efforts on the results from a single well test.
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