Substantial amounts of gas are accumulated in tight sand reservoirs in Cooper basin, Australia. This basin has a complex geomechanical stress regime. It is believed that the orientation of the minimum horizontal stress is changing and also there is a stress dependent permeability in this basin. These characteristics have a major impact on the gas recovery from different fields in Cooper basin. It is well known that permeability decreases in sandstone reservoirs when the net confining stress on the rock increases as the gas pressure in the reservoir decreases, so permeability is reduced by gas production. This permeability reduction is more pronounced in tight sand reservoirs due to shear dilation of micro-fractures. In order to model stress dependent permeability, a fully coupled finite element geomechanical reservoir simulations is needed. However, since a large number of data and high computational time is required for this kind of modeling, stress dependent permeability model is a short cut for reservoir simulation. This paper presents an alternative approach of partial coupling of geomechanics and reservoir simulation in which only a finite difference simulator is used with much less computational time and lower cost. In order to prove stress dependent permeability and develop a model, first a three dimensional hydraulic fracture model is constructed based on wire-line logs and mini-frac tests, then the resulting fracture geometry and conductivity are used as input data for dynamic reservoir flow simulation. We found that the reservoir permeability is changing at different time periods during pressure and production history matching. In this paper a stress-permeability relationship was developed by assuming a fully elastic fractured network of flow path to the wellbore in a hydraulically fractured well. Then, this model was tested by a partially coupled geomechanical simulation in Big Lake field in Cooper basin. The results show that our approach has better predictions than when the permeability is assumed to be constant. By this procedure not only the predictions are improved but also the computational time is reduced.

In cemented and cased wells, perforation cluster spacing is optimized based on the type of reservoir fluid, permeability, fracture conductivity, proppant distribution, and associated stresses to place multiple fractures along horizontal wellbores. Specifically, in very low-permeability reservoirs, the requirement for smaller perforation or fracture spacing might not be possible because of the geomechanical interference between fractures. In this case, the commonly used zipper-frac technique can provide a means to create fractures in projects with closer spacing. The benefits of zipper fracs can be maximized by generating proper fracture geometry and properly staggering the perforation/fracture system. This paper reviews and discusses numerical reservoir-modeling results of zipper fracturing that demonstrate the individual or combined effects of the perforation/fracture staggering, comparing these to the fracture length, fracture overlap, fracture conductivity, and/or proppant distribution effects of a conventional completion that does not use the staggered zipper-frac approach. The simulation results are assessed over a wide range of unconventional reservoir permeabilities for both gas and light oil.

Shale swelling during drilling is attributed to osmotic pressure, where low-salinity water enters the shale pores to cause swelling. Low-salinity water injected into high-salinity Bakken formation could similarly enter the matrix pores to displace oil by counter-current flow observed in core experiments. As a result, we believe, low-salinity water can potentially enhance oil recovery from oil-wet Bakken formation. In this paper, we report experimental and numerical modeling studies we conducted to evaluate the potential of low- salinity waterflooding in Bakken. For laboratory experiments, we used horizontal core plugs drilled parallel to the bedding plane. The mathematical included osmotic pressure, gravity and capillary effects. In the mathematical model, the osmotic pressure mass transfer equations were calibrated by matching time-dependent salinities in a published laboratory osmotic pressure experiment. We also modeled oil recovery for a Bakken core using our osmotic pressure mass transport model. The results indicate that osmotic pressure promotes counter-current flow of oil from both the water-wet and oil-wet segments of the core.

As one of the largest unconventional resources in the world, the Bakken petroleum system has approximately 7.4 billion barrels of recoverable oil as estimated by the U.S. Geological Survey in 2013. These resources lie in a 200,000-square-mile area in North America. However, primary recovery rates are low, typically 3%–5%. The use of carbon dioxide (CO 2 ) as an injection fluid may reduce the hydrocarbon viscosities in the reservoir and allow additional trapped oil to be produced. Another benefit of CO 2 injection is to mitigate climate change. In this study, detailed petrophysical and geological field models focusing on the Middle and Lower Members of the Bakken Formation in the Bailey and Grenora areas of western North Dakota were developed based on field characterization, well log interpretation, and laboratory core analysis by scanning electron microscopy, ultraviolet fluorescence, and standard optical microscopy techniques. A fine-scale model with a pair of horizontal wells was extracted from the initial Bailey model to examine the potential effectiveness of CO 2 -based oil recovery techniques. Based on characterization results for the simulation investigation, two three-stage hydraulic fractures were incorporated into the model for CO 2 injection and oil production wells, respectively, as well as the characterized oil properties such as swelling test and minimum miscibility pressure measurement from selected reservoirs. A total of four cases for simulation were designed to enhance oil recovery by CO 2 injection. These cases were run on a single porosity–permeability model to test the basic concepts and later incorporate these results into a dual porosity–permeability model. The results show that CO 2 injection may play a significant role in increasing oil production. Results of this study indicate that production can be enhanced by 43% to 58% compared to cases without CO 2 injection. Since a single-porosity, singlepermeability model was used, relative permeability curves that represent the fractures and matrix were both tested to determine the effects of this variable on the outcome. The results indicated that CO 2 enhanced oil recovery (EOR) is very sensitive to the relative permeability, and that result varied over 100% between the cases. This case study for CO 2 storage in the Bakken Formation provides a basic guideline to address CO 2 -based EOR. Specifically, the efforts provide modeling input for future investigations that could lead to the design and implementation of a possible pilot-scale field test.

Induced fracture complexity maximization, in addition to the primary hydraulic fracture, to improve the recovery efficiency or productivity of gas or liquids in unconventional reservoirs has been accepted and fully implemented by the industry. As a result, stimulation fluids and/or completion strategies have been engineered to maximize induced fracture complexity in many unconventional reservoirs. In typical horizontal completions, induced fracture complexity with sustained conductivity is clearly beneficial for the productivity of nanodarcy (nd) shales, although this might not be a requirement for all unconventional reservoirs, especially tight sands. In some unconventional reservoirs, operators have observed similar productivity in wells with predominantly planar fractures compared to wells that appear to have more complex fractures. This paper, supported by extensive reservoir simulations, aims to develop criteria for situations in which induced fracture complexity and sustained conductivity are required and when they are not. The simulations include a reservoir permeability range of 10 nd to 0.001 md and a complexity or secondary fracture conductivity of 1 to 5 md-ft. The results show that the fracture complexity and sustained conductivity are generally important for reservoir permeabilities lower than 100 nd for gas and 500 nd for liquid-producing reservoirs. Based on these results, an optimized completion strategy is suggested to maximize the productivity or recovery factor (RF) in unconventional gas- and liquid-producing reservoirs.

Liquid-rich shale plays (LRS) in North America have recently gained a lot of attention. Commercialization of these plays is now possible due to new technology, such as multi-fractured horizontal wells (MFHW). Along with such developments, there is an increased requirement to develop consistent reservoir-engineering methods to analyze multi-phase production data in such reservoirs. Large drawdowns required to produce these very low permeability formations complicate production analysis due to condensate drop-out near the wellbore or fracture face. Hydraulically-fractured vertical and horizontal wells completed in tight formations typically exhibit long periods of transient linear flow. This paper discusses a novel production data analysis technique for constant flowing bottomhole pressure (p wf < p dew ) wells producing from fractured LRS reservoirs. Our focus in this work is on cases where the initial reservoir pressure is well above the dew point pressure, as occurs in highly-undersaturated portions of the Eagle Ford Formation. A theoretical basis is developed for analysis of the transient linear flow period for these cases, and the effect of initial pressure on well performance is studied. The governing flow equation is linearized using appropriately defined two- phase pseudopressure and pseudotime functions, where the liquid solution analogy ca n be applied. This approach provides an accurate estimation of the linear flow parameter (x f √k) in multi-phase flow situations. Fine-grid compositional and black oil numerical models are used to validate the results. This work provides a robust analytical framework for production analysis of liquid-rich shale reservoirs as well as practical guidelines for real world applications.

Novel apparatuses have been developed to measure permeability using steady- and unsteady- state methods on nano-Darcy (nD) shale (source rock) using intact cylindrical samples returned to isostatic effective reservoir stress. The steady-state method uses a high pressure dual pump system using supercritical fluids. High pressure supercritical fluids have low viscosity and low compressibility. The effect of low viscosity fluid results in measureable flow rates and the effect of low compressibility fluid minimize unsteady-state transients thereby reducing the amount of time required to achieve steady-state equilibrium. Specially designed and configured pump systems, seals and sleeves reduce leak rates to allow Darcy flow and permeability determination below 1 nD. The unsteady-state method is based upon standard designs but is optimized for small pore volume. In this report we present a summary of over 200 such permeability measurements. Permeability is observed to be dependent on geologic parameters, such as, texture and composition. Stress dependence, with hysteresis, is observed for samples with and without fractures as is rate dependent skin (Forchheimer). An interpretation model where matrix storage feeds a progressively larger fracture network provides a logical basis for a dual-porosity reservoir simulation model. This dual-porosity model is used to understand the influence of reservoir production parameters, such as choke management. An additional observed effect is possibly related to pore collapse and disconnection. Pores associated with organic matter are softer than the surrounding mineral matrix. If these pores have a sufficiently small throat diameter, it is not hard to envision that they easily compact and close under increased effective stress as the result of reservoir depletion. Therefore, organic pore systems can become isolated unlike those of a sponge where fluids remain in pressure communication at all times. The implication of such pore isolation phenomena is that fluid material balance is not preserved during production and can contribute to large production decline rates.

Oil shale, an organic-rich impermeable rock, is an abundant energy resource in the United States. Because few oil shale deposits occur in shallow formations, application of an in-situ process is necessary for thermal decomposition and subsequent oil and gas production. An earlier investigation indicated that cylindrical or planar in-situ electric heaters were more efficient than flowing steam through created fractures. This study investigates the efficiency of oil shale in-situ upgrading by steam flowing in vertical fractures. There are challenges in the through description of in-situ upgrading process because the kerogen decomposition involves of a series of complex and sensitive reactions, and results a large number of fluid and solid products. Expanding the Flow and Transport Simulator (FTSim) developed by Texas A&M University, we developed a fully implicit capability that describes the decomposition of kerogen in the oil shale and the resulting system changes with minimal simplification and assumptions. The decomposition process is represented by 6 kinetic reactions (resulting 10 components and 4 phases), involves coupled processes of mass transport and heat flow, and accurately accounts for phase equilibrium and phase transition thermodynamics. We applied our simulator to find a successful strategy for hydrocarbon production using steam that flows in vertical fractures created by multistage transverse fracturing in a horizontal (MTFH) well. The simulation of simultaneous heating and flowing provides the system change of oil shale reservoir during in-situ upgrading, and it indicates the necessary condition of successful hydrocarbon production from oil shale reservoir.

A practical simulation model is developed and demonstrated with applications for accurate characterization of production rate and pressure behavior with time in shale-gas reservoirs featuring horizontal wells intersected with multi-stages of hydraulic fractures. The model determines the contribution of each fracture stage to the overall production and predicts the pressure changes occurring in the fracture and matrix zones by a compartmental simulation approach. Various flow regimes of drawdown test are investigated for fracture diagnosis with different fracture permeability values to determine the external boundary effect. Our practical mathematical modeling, coupling the wellbore and reservoir hydraulics, is solved numerically by an iterative method to determine the flow rates coming into the horizontal well from multiple hydraulic fractures like the commingled layers intersected by a vertical well. This approach provides a reasonable description of behavior of multiple stages in shale gas reservoirs by considering the alteration of the gas transport properties and the changing apparent permeability under the effect of pore proximity of shale. Various applications of our non-Darcy simulation model demonstrate the importance of the corrections relevant for shale-gas reservoirs compared with the conventional Darcy flow without consideration of such corrections. Commensurate with field observations, when the non-Darcy flow corrections are considered, the cumulative gas production is higher compared with the conventional Darcy flow calculations which impact significantly on fracture and matrix pressure responses and production forecasting.

It is well known that the analysis of production data (Rate Transient Analysis) involves the solution of an inverse problem. We measure the response of the system, typically production rates and flowing pressures, and then proceed to search for the appropriate reservoir model description that created it. Typically, this is accomplished through the minimization of an objective function consisting of the difference between the simulated response and the actual response. In practice, production analysis is complicated by two important problems: 1) The mathematical models (analytical or numerical) that we use to describe well production may not provide an adequate and full description of the true well-completion-reservoir system. This is especially true if the system is complex and asymmetric, as is the case in unconventional plays. And 2) The production response almost certainly contains significant errors and/or disturbances caused by outside influences. This makes the process of error minimization difficult and non-unique. As a result, it is impossible to know whether or not we are obtaining reliable results from production analysis, as there are simply too many unknown variables in the system we are trying to model. The objective of this work is to determine the best procedure for solving the inverse problem of production analysis in a consistent and reliable way, and to quantify just how reliable the results are. We wish to do this in an environment free of complications, such as those identified previously in 1) and 2). To accomplish this, simulated production responses from known models are analyzed, but the full set of model input parameters are withheld; only basic input parameters are provided, such as what would typically be available in practice. Since the "answer key" is available, this study allows us to objectively evaluate and optimize production data analysis best practices.

Production from the gas-condensate window of the liquid-rich shale plays in the US such as Barnett, Marcellus and Eagle Ford, has increased during the past few years. However, there is still a lack of understanding of the flow behavior of gas-condensate in liquid-rich shales when the flowing bottom-hole pressure falls below the dew-point pressure. Condensate dropout below the dew-point pressure leads to variation in the composition of vapor and liquid hydrocarbons. The phase behavior prediction is further complicated by the nanometer-sized pores of the shale formations where fluid-rock interaction could be different than in conventional reservoirs. This work investigated the compositional variation of gas-condensate during flow through Marcellus shale in laboratory coreflooding experiments. During the experiments, a gas-condensate mixture was injected into the core and during the flow, gas samples were collected through ports spaced along the core holder. Then, the gas samples were characterized using gas chromatography for compositional analysis. The results were compared to equivalent experiments in Berea sandstone. The gas-condensate sample used in the coreflooding experiment was collected from the Marcellus liquid-rich region and the experiments were conducted at reservoir pressure and temperature. Prior to conducting the experiments, the permeability of the Marcellus shale core and the Berea sandstone core were characterized using the pressure pulse decay technique and the Darcy flow technique; respectively. Results from this study showed that the gas composition varies along the direction of flow during depletion. The change in gas composition is due to the combination of condensate dropout and relative permeability effects. However, the magnitude of variation in the gas composition across the Marcellus shale core was less than that in the Berea sandstone core. This is an indication that the amount of condensate dropout varies between shale and sandstone for the same fluid system and at similar flowing conditions. Hence, the phase behavior is affected by the additional fluid-rock interaction expected for the shale due to flow through nanometer-sized pores.

Horizontal wells in the tight reservoirs are stimulated using multistage hydraulic fracturing. The fracturing fluid used in this operation is generally water based. A very low percentage of fracturing water is recovered during the flowback operation. Non-recovered water can block the gas flow and damage the reservoir. The water recovery in propped fractures is controlled by microscopic displacement efficiency and fracture areal sweep efficiency. Microscopic displacement efficiency is mainly controlled by capillarity, and has been studied extensively. Areal sweep efficiency during water drainage in propped fractures is controlled by mobility ratio and displacement direction relative to gravity direction, which needs further investigation. This paper reports various fracture drainage experiments to understand the effect of gravity, surface properties, and viscosity on fracture sweep efficiency and total load recovery. A visual cell was built to model a propped fracture. Glass beads were packed in the space between two glass plates, and the pack was then saturated with the fracturing fluid. This simulates the initial conditions before opening the well for flowback. For simulating the water drainage against gravity, representing a fracture element below the horizontal well, the gas was injected at the bottom of the cell. Four sets of experiments were conducted to study the effect of injection pressure, interfacial tension, wettability, and fluid rheology on sweep efficiency and load recovery. Glass beads were chemically treated to alter their wettability from hydrophilic to hydrophobic. For each test, normalized fluid recovery was obtained by measuring the mass of produced fluid and using the material balance. The cell was kept in a dark room in front of a light box, and pictures were taken at regular time intervals. These images were later used to compare the drainage patterns. The results suggest that water recovery in an upward displacement very low mainly due to poor sweep efficiency. Increasing the injection pressure does not improve water recovery. Reducing surface tension and using treated hydrophobic sand improves the sweep efficiency and in turn the load recovery.

Oil production from the unconventional Vaca Muerta play is increasing as a result of a rigorous appraisal and exploitation strategy. Multiple wells have already demonstrated the potential of the Neuquén Basin, however optimization is still ongoing to determine the best practice for completing wells. A stand out difference of the Vaca Muerta play is its thickness (100 m to 450 m), as such a development strategy based solely on vertical wells is being considered in addition to the horizontal well strategy more commonly applied in other shale plays. The thickness of the Vaca Muerta formation creates new challenges and opportunities due to the stratigraphic variation in petrophysical and mechanical properties which can affect fracture effectiveness and well productivity. Completion design, geology and production performance need to be linked. Specifically, the geology of the Vaca Muerta formation, as is the case in most reservoirs, varies significantly more in the vertical direction in comparison to the horizontal direction. With optimum solutions not necessarily being intuitive, numerical simulation is critical as it enables a large number of variables to be analyzed and their individual impact understood and quantified. The objective of this paper is to present the four different approaches that have been used to build numerical models to represent the vertical wells in Vaca Muerta. These are: A single layer model with a planar fracture placed in a zone of improved permeability to represent the Stimulated Rock Volume (SRV) which is then surrounded by undisturbed matrix. A multilayer model with multiple planar fractures placed in an undisturbed matrix. A multilayer model with multiple planar fractures (one per stage), the SRV surrounding the fractures and the undisturbed matrix behind it. A multilayer model, where the SRV is modeled within a dual porosity model. This work shows how these models were constructed, the measurements that were honored and the estimation and justification of values assumed for unknown parameters. The impact of the different methodologies on the time taken and quality of the history match obtained and subsequent forecasts is also discussed. YPF has collected an extensive data set including PLTs, microseismic surveys, downhole pressure gauges, and pressure build ups, which has been used to constrain the numerical models. Building and history matching these models has been challenging but enables conclusions to be made about rock, fluid and completion interaction that cannot be obtained otherwise. The simpler models, have in some cases, enabled rapid estimates to be made for EUR which have subsequently been supported by the results from the more detailed modeling approaches.

Current linear analysis is based upon the tri-linear model, which assumes a continuous and homogeneous porous medium within each flow region. This recent study, however, reveals that a discontinuous stimulated reservoir volume (SRV) is extensively associated with horizontal wells with fewer frac stages and/or within areas with high-stress anisotropic ratio. To characterize such isolated SRV scenarios, three parameters—fracture half-length, SRV permeability, and the half-width for each isolated SRV—must be inferred from the analysis, which creates a difficult challenge for the existing rate transient analysis (RTA) procedure. This paper presents a new RTA methodology and associated diagnostic plots to infer all three parameters simultaneously using the information beyond the linear flow period. The analyzed results illuminate optimizing the number of frac stages and well spacing. The newly developed "beyond linear analysis" procedure has been used successfully to analyze more than 100 Bakken wells with various completion types and frac stages. The resultant RTA-derived statistics have been used for the construction of type curves, well history matching, completion assessments, and optimal well spacing. Almost all the wells with fewer than 20 frac stages show an isolated SRV around each hydraulic fracture; these are good candidates for refrac. Although a high number of frac stages (e.g. >30 stages) will boost the initial production rate (IPR) and more quickly deplete the SRV, it is our conclusion that the estimated ultimate recovery (EUR) is not significantly enhanced beyond a certain number of frac stages. Moreover, both the incremental SRV and flow capacity associated with each additional stage steadily decrease. This suggests that there is an optimum number of frac stages and wells that maximize both the IPR and the EUR of a drilling spacing unit (DSU). This new RTA methodology allows, for the first time, detailed SRV and fracture description. The precise RTA model not only greatly relaxes the dependency on compaction and PVT properties suppression during the history match, but also clarifies the "stress shadow effect" from adjacent stages and the relationship between the shear fracture displacement/dilation and inter- stage intervals.

Permeability estimation from microseismic events has been used in the oil and gas industry for more than a decade. However, some of the geomechanical assumptions associated with this technique may not essentially be representative of the field characteristics. Assumptions of shear failure along faults due to any reservoir pressure perturbation and assumption of random distribution of critical pore pressure in a chosen interval as the shear failure criteria presumably will not be representative of the shear failure criteria for the faults. We propose a new model for seismicity based reservoir characterization based on radial fluid flow in the reservoir and Mohr-Coulomb failure criteria which includes the stress state of the reservoir as well as fault friction coefficient (geomechanical reservoir properties) that were not included in the previously published models. This model relaxes some of the assumptions that were associated with former seismicity based reservoir characterization (SBRC) models. We used microseismic data from German Continental Deep Drilling Project (KTB) to test the validity of our new model. The predicted permeability from our model matches very well with the estimated and measured permeability reported values in the literature for KTB. We then performed sensitivity analyses of the effects of fault friction coefficient on estimated permeability, which showed substantial dependency of estimated permeability on fault friction coefficient. This indicates that the dependency of permeability to reservoir geomechanical properties was ignored in previous SBRC models, which is included in our model.

Gas in tight sand and shale exists in underground reservoirs with microdarcy (µD) or even nanodarcy permeability ranges; these reservoirs are characterized by small pore throats and crack-like interconnections between pores. The size of the pore throats in shale may differ from the size of the saturating fluid molecules by only slightly more than one order of magnitude. The physics of fluid flow in these rocks, with measured permeability in the nanodarcy range, is poorly understood. Knowing the fluid flow behavior in the nano-range channels is of major importance for both simulation studies and calculations of the relative permeability of gas in tight shale gas systems. In this work, a lab-on-chip approach for direct visualization of the fluid flow behavior in nanochannels was developed using an advanced single-molecule imaging system combined with a nano-fluidic chip. Displacements of two-phase flow in 100 nm depth channels were characterized. Specifically, the two-phase gas slippage effect was investigated. Under experimental conditions, the gas slippage factor increased as the water saturation increased. The two-phase flow mechanism in nano-scale channels was proposed and proved by the flow pattern images. The results are crucial for permeability measurement and gas slippage factor determination for unconventional shale gas systems with nano-scale pores.

Although high-frequency fluid production and flowing pressures (hourly or greater) are commonly gathered in multi-fractured horizontal wells (MFHW), this data has rarely been used by industry in a quantitative manner to characterize hydraulic fracture or reservoir parameters and there has been ongoing debate about the usefulness of this data. It is likely that the multi-phase flow nature and the possibility of early data being dominated by wellbore storage have deterred many analysts. This work will expand on the flowback analysis work presented by Clarkson (2012b ). Consistent with that work, our interpretation is that the early flowback data corresponds to wellbore + fracture volume depletion (storage) and it is assumed that fracture storage volume is much greater than wellbore storage. From this flow-regime, bulk permeability (dominated by fracture permeability) and effective fracture half-length can be estimated. However, as pointed out by Clarkson (2012b) there is a large degree of uncertainty in this type of analysis as a result of the number of unknowns which are being adjusted to provide an adequate history match. To better understand the uncertainty and the impact of each parameter, stochastic simulation was used to provide a range of parameter values, which provide an adequate fit of the data, and to determine which parameters have the greatest impact on the match. Stochastic simulation is also used to derive a long-term forecast using parameters derived from flowback analysis. Additional improvements over previous work include the consideration of different fracture geometries, the use of the matchstick model to estimate fracture permeability and additional constraints on relative permeability curve selection. The field cases presented by Clarkson (2012b) for shale gas reservoirs are reanalyzed for proof of concept and demonstration of the developed techniques.

The permeability of unconventional gas/oil reservoirs is a critical control on economic viability of unconventional plays, yet its determination, particularly in ultra-low permeability shale reservoirs, remains a challenge. Some of the difficulties in obtaining accurate permeability measurements in the lab include: recreating in-situ stress and fluid saturation conditions; establishing the appropriate sample size for measurement; correcting for sorption of gases on kerogen and clays; accounting for non-Darcy flow (slippage and diffusion); among many others. Unsteady-state measurements are most popular for establishing permeability in ultra-tight rock; both pressure-decay and pulse-decay decay techniques have been used. Analysis methods for these techniques have been established, but there remain some questions about whether these analysis methods are optimal for establishing permeability. In this work, we investigate the use of pressure- and rate-transient analysis (PTA/RTA) methods to analyze data obtained from a new core plug analysis procedure, designed specifically to extract information (permeability and pore volume) from ultra-low permeability reservoir samples (core plugs). The new analysis procedure calls for analyzing the rate and/or pressure data analogously to larger-scale well-test/production data. During a core plug production test for example, derivative analysis of rate-normalized pseudo-pressure change is first analyzed to determine flow-regimes. For homogenous samples, linear flow is followed by boundary-dominated flow; for this scenario, permeability can be established by noting the end of linear flow and using the distance of investigation calculation to calculate permeability (knowing core length). Permeability can also be established independently from a linear flow (square-root of time) plot. Pore volume can also be established. Analytical simulation is used to verify estimates of permeability and pore volume from RTA/PTA. Our solutions allow complex unconventional gas reservoir behavior to be incorporated, including corrections for adsorbed gas and non-Darcy flow. Our new methodology is tested using various simulated cases which differ due to: 1) reservoir type (single or dual porosity, homogenous or heterogeneous); 2) matrix permeability; 3) analysis type (post injection/falloff production test, or post-injection falloff); 4) adsorption (compressed gas storage only or compressed + adsorbed gas storage); Darcy or non-Darcy flow. In all cases, reasonable estimates of permeability and pore volume were obtained, provided the appropriate corrections are made. We believe this new technique for analyzing core data, and the proposed core testing procedure, will considerably improve on current techniques for establishing permeability and pore volume of unconventional reservoir samples.

During hydraulic fracturing operations in low permeability formations, spontaneous imbibition of fracturing fluid into the rock matrix may be responsible for having a significant impact on the retention of water-based fracturing fluids in the neighborhood of the induced fracture. This may consequently affect the post-frac productivity of the well. However, there is lack of direct quantitative and visual evidence of the extent of retention, evolution of the resulting imbibing fluid front, and how they relate to potential productivity hindrance. In this paper, laboratory experiments have been carefully designed to represent the vicinity of a hydraulic fracture. The evolution of fracturing fluid leak-off is monitored as a function of space and time using X-ray computed tomography (CT). The X-ray CT imaging technique allows us to map saturations at controlled time intervals to monitor the migration of fracturing fluid into the reservoir formation. It is generally expected for low permeability formations to show strong capillary forces due to their small characteristic pore radii, but this driving mechanism is in competition with the low permeability and spatial heterogeneities found in tight gas sands. The relevance of capillarity as a driver of fluid migration and retention in a tight gas sand sample is interpreted visually, quantified and compared with high permeability Berea sandstone in our experiments. It is seen that although these formations demonstrate strong capillarity, the effect can be suppressed by the low permeability of the formation and the heterogeneous nature of the sample. However, saturation values attained during imbibition experiments are comparable to those previously obtained for high permeability samples, which can have significant implications in terms of phase mobilities in the neighborhood of induced fractures. Results from this investigation are expected to provide fundamental insight regarding critical variables affecting the retention and migration of water-based fracturing fluids in the neighborhood of hydraulic fractures, and consequently on the post-frac productivity of the well.

Using lattice-Boltzmann simulation of steady-state gas flow we show that apparent permeability values of nano-scale capillaries could be significantly higher than those predicted by the Klinkenberg slip theory. The difference is due to kinetic effects of gas molecules that have gone through inelastic collisions with the walls on those molecules that make up the bulk fluid in the capillary. The kinetic energy that the bouncing back molecules have and the associated momentum carried to the bulk fluid is not a trivial matter in capillaries with diameter h less than 100nm. It creates a molecular streaming effect that amplifies velocity profile developing across the diameter of capillary. In a sense, it is not only the molecules interacting with the wall that slip but also the bulk fluid, i.e., double slip. The double-slip effect is shown using measured permeability data of a crushed nanoporous material with a uniform pore size (10< h <40 nm) at varying pore pressures. Using the simulation results we propose a modification to the Klinkenberg equation. New double-slip Klinkenberg equation includes a characteristic length scale ( L KE ) that is proportional to the kinetic energy per capillary cross-sectional area of the bouncing-back molecules by the walls. The new length scale of the molecular kinetic effects of nano-capillaries is larger than the mean free path of the molecules. The double-slip Klinkenberg equation reduces to the classical equation for slip flow in large capillaries, i.e., h / L KE >>1, and converges to the absolute permeability value at high pressures. Due to nanoporous nature of coals and organic-rich shales, the double-slip effect is likely to be significant near hydraulic fractures and production wells in depleted reservoirs. The presented theoretical work brings new insights into the measurement of crushed particle permeability using gas uptake or release experiments. Although they are fast low-pressure laboratory measurements, there are widely-recognized uncertainties associated with them. In this paper we show that dramatic variation in the measured permeability is possible due to small changes in the measurement cell pressure. Hence, even when the crushed sample is considered to be representative of the reservoir, the measured permeability may not quantitatively be related to flow under the reservoir conditions. The double-slip permeability concept and the modified Klinkenberg theory eliminate some of the uncertainties associated with the laboratory measurement of permeability and lead to development of new measurement protocols for the unconventional resources industry. A double-slip Klinkenberg chart is developed including the effects of nano-capillaries on the permeability, and two procedures are presented with example calculations on how to use the chart to predict permeability of shale sample from its effective pore size and shape.