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Results
Abstract Unconventional reservoirs exhibit ultra-low matrix permeability, typically in the order of nano-Darcies. To produce hydrocarbons from these reservoirs economically, hydraulically-fractured horizontal wells are commonly used. During production and reservoir depletion, the permeability changes due to decrease in pore pressure and the subsequent increase in effective stress. Similarly, conductivity (kfwf) of the hydraulic fractures could also change under closure stress. The reservoir simulation models used in the industry may consider such variations in transport as a function of stress using mechanistic stress-dependent permeability models, however analytical models used extensively in the industry may not consider such variability. Further, these analytical models often consider production occurring under constant bottom hole pressure (BHP) condition. In this paper, we tested the accuracy of such an analytical model, also known as Aโk plot, in rate transient analysis (RTA). The Aโk plot is used to estimate the effective hydraulic fracture surface area A of the well's hydraulic fractures contributing to production. Hence, it is used to measure quality of the well's completion and the extent of its stimulated draining volume. In measuring the quality, however, it is assumed that the matrix has an average permeability k that stays constant during the production. This may be a reasonable assumption for some of the tight gas formations but shale formations have stress-dependent quantities with impact on gas transport such as the matrix permeability, fracture permeability, and fracture width. Hence, ideally these quantities should be treated dynamically during the RTA analysis. For the study we used a single-well reservoir flow simulation model including a horizontal well with exactly known effective fracture surface area. The reservoir, completion parameters and the fluid properties are taken from an independent study on a shale gas well's production-rate history-matching, optimization, and forecasting. The history-matching of this study used the bottom hole pressure history of one year and a half of gas production under natural flow conditions (no artificial lift). The calibration included reservoir and hydraulic fracture permeability values changing as a function of mechanical stresses induced dynamically by the withdrawal of the fluids. Using the forward simulation results, we showed that the Aโk plot works for wells with infinite conductivity hydraulic fractures and for production under static conditions, i.e., constant permeability for the matrix and constant conductivity for the fractures. However, the plot yields significant error in the calculated fracture surface area (larger than 40%) when we consider dynamic matrix and fracture permeability conditions. The error in the estimated fracture surface area is greater in the presence of dynamic fracture conductivity under closure stress, compared to dynamic matrix permeability under overburden stress. Furthermore, the error in calculated area is more pronounced in ultra-low permeability formations and for the wells with finite (and limited) conductivity hydraulic fractures. The error in the estimated area is also significant, when the well experiences a non-constant BHP. We propose a modified RTA method to consider these dynamic conditions in order to minimize the errors in the calculated area. As part of the modification, we propose a simple weighted-averaging of the permeability to use in the RTA analysis. This approach correctly recovers the area under 1-3% accuracy for any dimensionless fracture conductivity (CfD) condition and stress dynamic matrix permeability. Interestingly, the results show that the fractures can control flow not only during fracture linear flow and bi-linear flow but also during the formation linear flow regime.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.75)
Abstract Hydraulic fracture conductivity (wfkf) is a critical parameter in completion design of horizontal shale wells. Field evidence and laboratory investigations suggest that these fractures could have finite conductivity values that are influenced by the fracture closure stresses developing during production. Consequently, the fracture conductivity decreases as a function of production time. Currently no field test exists that can capture the dynamic behavior of the conductivity. Bilinear flow analysis (ยผ-slope flow regime) is a common rate-transient-analysis (RTA) technique that uses the first few days of production data to obtain a conductivity value averaged over time for all the fractures of the well. But it does not consider the stress-sensitivity of the production. In this paper, using forward simulation of flow and production from a hydraulically fractured shale gas well with a stress-sensitive (dynamic) permeability field, we show that the error associated with the averaging of the dynamic behavior of the fracture conductivity could be large. We re-visit bilinear flow theory and modify the RTA method for the presence of stress-sensitive hydraulic fracture conductivity. Now the ยผ-slope analysis gives an average of the dynamic fracture conductivity, which could be lower than the initial conductivity. The work shows the need to extend the analysis to formation linear-flow and boundary dominated flow regimes. Introduction Bilinear flow occurs in shale gas wells, as a manifestation of linear flow in both matrix and fracture simultaneously. The duration of this flow regime spans the first few days of production, typically after the fracture linear flow regime, when flowback of the injected fracturing fluid occurs, preceding the widely-observed half-slope formation linear flow regime. Its signature on a log-log diagnostic plot is ยผ slope on pressure and radial derivative plots and zero-slope on the linear derivative plot (Clarkson and Beierle 2010) The interpretation of fracture linear and bilinear flows can aid us in obtaining a fracture conductivity averaged for all the fractures of the well.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.99)
- (5 more...)
Summary Fluid storage capacity measurements of core plugs in the laboratory consider pore volume as a function of effective stress. The latter is equal to applied confining pressure โ n รโapplied pore pressure. However, the results are often reported as a function of difference in the applied pressures, because the effective stress coefficient (n) is an unknown. This creates confusion during the interpretation of laboratory data and leads to added uncertainties in the analysis of the storage capacity of the samples under in-situ conditions. In this paper, we present a new laboratory method that allows simultaneous prediction of the sample pore volume, the coefficient of isothermal pore compressibility, and the effective stress coefficient. These quantities are necessary to predict the fluid storage as a function of effective stress. The method requires two stages of gas (helium) uptake by the sample under confining pressure and pore pressure and measures pressure-volume data. Confining pressure is always kept larger than the equilibrium pore pressure, but their values at each stage are changed arbitrarily. The analysis is simple and includes simultaneous solutions of two algebraic equations including the measured pressure-volumedata. The model is validated by taking the reference pore volume near zero stress. The reference volume predicted matches with that measured independently using the standard helium porosimeter. For sandstone, shale, and carbonate samples, the estimated pore compressibility is, on average, 10โpsi. The effective stress coefficient is higher than unity and is a linear function of the ratio of the applied pressure values. We present a new graphical method that predicts the Biot coefficient (ฮฑ) of the rock sample, a fundamental quantity used during the strain calculations that indicates the tendency of the rock to deform volumetrically. A new fundamental rule is found between the applied pressure difference and the effective stress: ฯe/ฮฑ = pcโโโpp. Interestingly, the predicted Biot coefficient values for the shale samples show values between 0.46 and 1.0. This indicates that features of the shale sample, such as mineral variability, fine-scale lamination, and fissility, come into play during the fluid storage measurements.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.96)
Abstract Methane hydrate is formed in a sand pack that undergoes cooling-heating cycles over a range of temperature. Five cycles are designed so that hysteresis can be observed in the sand pack. Each cycle has a different melting temperature which leads to varying intensity of temperature relaxation effect on the hysteresis. Evidence of hysteresis is observed in three separate temperature readings of thermocouples. Formation of hydrates is dependent on the thermal cooling rate of the sand pack, and the melting temperature of the previous cycle. A temperature increase is observed in the whole system, and this increase is driven by temperature peaks indicating significant hydrate formation near the thermocouples. These peaks have important effects on the whole system. By comparing each cycle's temperature peaks, hysteresis is clearly observed at the temperature readings of the short thermocouple. The same hysteresis pattern follows for the location of the temperature peaks. When significant hydrate formation occurs in the sand pack, a steepening of the pressure decline is observed, indicating a rapid loss of free gas in the system. The pattern that is observed in the temperature peaks is also identified in the pressure profiles, thus linking the gas saturation to hydrate formation. The time derivative of pressure corroborates these findings. A new model is proposed for the prediction of secondary hydrate formation time as a function of the melting temperature the porous medium experienced.
Thermally-Induced Secondary Fracture Development in Shale Formations During Hydraulic Fracture Water Invasion and Clay Swelling
Eveline, Vena F. (PERTAMINA, Jakarta, Indonesia) | Santos, Laura P. (Texas A&M University, College Station, Texas) | Akkutlu, I. Yucel (Texas A&M University, College Station, Texas)
Abstract Current trends in shale gas industry require an advanced-level understanding of fracturing water invasion into formation and the subsequent water-shale interactions. Previously, we studied osmosis and clay swelling effects on the permeability of the shale formation. Shale, with an average 50% clay content, could hold large cation-exchange-capacity and significantly improved membrane efficiency, which may promote swelling and changes in the stress. In addition, large temperature-gradient effects due to cold water contacting the formation has not been investigated in detail. A new geomechanically-coupled reservoir flow simulator is developed, which accounts for cold freshwater imbibition, osmosis and clay-swelling effects on the formation permeability under stress. The model includes aqueous and gaseous phases with three components: water, gas and salt. Governing geomechanical equation includes pore-pressure as well as temperature gradients. Volumetric strain (porosity changes) is calculated as a function of the mean normal stress, pore pressure and temperature. Imbibition occurs in water-wet inorganic part of the matrix, in the micro-cracks. Osmosis and clay swelling effects develop when the imbibed water in the micro-cracks interacts with the saline water in clay pores, which acts as a semi-permeable membrane to the water and experiences pore (osmotic) pressure changes and swelling of the clay in the formation. The effect of temperature is pronounced early during the shut-in when imbibition of cold water takes place rapidly. Cold water introduces a low-stress region near the fracture due to thermal expansion effect and pore pressure buildup. We used a criterion and discuss the potential for fracturing. It is anticipated that the fracturing develops during forced imbibition of cold water given that a large difference exists between the injected water and the formation temperatures.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Mineral > Silicate > Phyllosilicate (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
Abstract Fluid storage capacity measurements of core-plugs in the laboratory considers pore-volume as a function of effective stress. The latter is equal to (Applied Confining Pressure) โ (Effective Stress Coefficient) x (Applied Pore Pressure). However, results are often reported as a function of difference in the applied pressures, because the coefficient is unknown and depends on the sample. This creates confusion during the interpretation of laboratory data and leads to added uncertainties in the analysis of storage capacity. In this paper we present a new laboratory method that allows simultaneous prediction of the sample pore volume, coefficient of isothermal pore compressibility, and the stress coefficient. These quantities are necessary to predict the fluid storage as a function of effective stress. The method requires two stages of gas (helium) uptake by the sample under confining pressure and pore pressure and measures pressure-volume data. Confining pressure is always kept larger than the equilibrium pore-pressure but their values at each stage are changed arbitrarily. The method considers gas leakage adjustments at high pore pressure. The analysis is simple and includes simultaneous solutions of two algebraic equations including the measured pressure-volume data. The model is validated by taking the reference pore volume near zero stress. The reference volume predicted matches with that measured independently using the standard helium porosimeter. For sandstone and shale, the pore compressibility is on average 10 psi and the effective stress coefficient is slightly higher than 1. The effective stress coefficient in isotropic elastic porous materials is known as the Biot coefficient and the value we predict indicates the relationship between the bulk and grain volume moduli. Interestingly the effective stress coefficient predicted using shale samples rich in clays and organic matter is slightly higher than for sandstone. This indicates that other features of the sample such as fine-scale texture (laminations, and anisotropy, etc.) could come into play during the fluid storage measurements.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.73)
Abstract Capillary end effect develops in tight gas and shale formations near hydraulic fractures during flow back of the fracturing treatment water and extends into the natural gas production period. In this study, a new multi-phase reservoir flow simulation model is used to understand the role the capillary end effect plays on the removal of the water from the formation and on the gas production. The reservoir model has a matrix pore structure mainly consisting of a network of micro-fractures and cracks under stress. The model simulates water-gas flow in this network with a capillary discontinuity at the hydraulic fracture-matrix interface. The simulation results show that the capillary end effect cause significant formation damage during the flow back and production period by holding the water volume and saturation near the fracture at higher levels than that based on only the spontaneous imbibition of water. The effect makes water less mobile, or trapped, in the formation during the flow-back and tends to block gas flow during the production. The stress change effects during the production are relatively less important. We showed that the capillary end effect cannot be removed completely but can be reduced significantly by controlling the wellbore flowing pressure and by altering the formation wettability. Introduction Hydraulic fracturing is a well stimulation technique for improved natural gas production from tight gas and shale formations. However, the implementation of the technique brings in new formation damage considerations. During the fracturing treatment, a large volume of water is pumped with proppants into the well. The injected water at high pressure applies the downhole force necessary for the fracture initiation and growth into the formation. Following the treatment, the well is flowed back. Only a small fraction of the injected water can be recovered, however, during the flow-back and natural gas production (Cheng, 2012). A large portion of the water is left behind in the fractures as residual water. Several studies argued that during the treatment forced imbibition of the fracturing water into the water-wet clayey portion of the formation as another reason for the fracturing fluid loss (Bennion and Thomas, 2005; Shaoul et al., 2011, Cheng, 2012; Eveline et al., 2017). The injected water lost to the formation creates a region of high water saturation which may lead to liquid blocking near the fracture during the gas production (Shaoul et al., 2011) and to clay swelling (Scott et al., 2007; Eveline et al., 2017). These studies have previously showed the potential flow impairment mechanisms in tight gas and shale formations and discussed to a certain extent that they may influence a well's performance during production. However, these studies did not consider the existence of capillary end effect (CEE). In ultra-low permeability formations, such as tight gas and shale, the sizes of the pores and cracks contributing to the transport of fluids are significantly reduced. Hence, once the fresh fracturing water invades, the formation experiences large gas-water capillary pressure. Consequently, the two-phase flow dynamics during the flow-back could be controlled by capillary forces. In the presence of strong capillarity, the capillary discontinuity at the fracture-matrix interface will retain the injected water within the formation. This retention could cause high levels of immobile water saturation near the fracture and significantly amplify the liquid blocking in the formation.
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (0.66)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
Abstract Shale gas wells exhibit formation linear flow, which is in most cases the only transient flow regime available for engineering analysis. Production Rate Transient Analysis (RTA) methods have been developed to analyze the transient flow into shale gas well. These methods often assume homogeneous reservoir properties and neglect the dynamic nature of the formation. In shale gas reservoirs, however, the properties could change; in particular, the permeability due to stress-dependence of the formation and non-Darcian effects. In this work, a theoretical study is conducted to show the range of errors on the predicted total fracture surface area caused by the constant permeability assumption. The study proposes a modified RTA model, which accounts for dynamic permeability to eliminate the error in calculated area. Results from the sensitivity analysis show that the error on surface area calculation ranges from 1% โ 323% due to the constant permeability assumption. The total fracture surface area calculation is most sensitive to the geomechanical (stress-sensitive) parameters, which affect the permeability in the region away from fractures. Results show that the error in area is reduced when the initial value of the dynamic permeability is large. Sorption parameters are the second most influential category affecting the surface area calculation. Molecular diffusion of the adsorbed and free gas molecules enhance permeability near the fractures, wherein the slightest variations in dynamic permeability can cause the error in area to change significantly. For these parameters, higher permeability near the fractures translates to higher error in area.
- North America > United States > Texas (1.00)
- Europe (0.93)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
Abstract Much work has been done to demonstrate an economical impact of various fluid transport mechanisms on the long term behavior of shale gas production. These studies were elementary level and focused on identifying a dominant mechanism of production. They did not consider, however, the interaction of the fractures with the shale matrices in detail. In the near wellbore environment the fracture is the crucial component of transport, whereas the matrix is the place for storage. In this paper, using a new in-house reservoir flow simulator, we introduce the nature of this interaction and show that the transport in the tight matrix can be induced by carefully designing the well completions and by operating under the optimum production conditions. The simulator accounts for a hydraulic fracture coupled to shale matrix with an anistropic apparent permeability field, which is stress-sensitive and includes the effects of molecular transport phenomena. The fracture has a dynamic conductivity with a simple nonlinear deformation rule reflecting proppant embedment effect on the conductivity. Using a sector model, we predict short-term cumulative production trends. The results indicate that design of horizontal wells with multiple fractures should take into account the geomechanical and diffusional resistances associated with the gas transport in the matrices. Further, in-series nature of the production indicates that changes in fracture conductivity beyond its threshold value has negligible effect on the production trends. Therefore, production optimization efforts should instead focus to considerations to improve the flow rates in the matrix.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
Abstract Measured permeability of an organic-rich shale sample vary significantly with applied laboratory conditions, such as the confining pressure, temperature and the measurement fluid type. This indicates that the measured quantity is influenced by several mechanisms that add complexity to the measurement. The complexity is mainly due to stress dependence of the matrix permeability. Also, it is due to the fact that organic-rich shale holds significant volumes of fluids in sorbed (adsorbed, dissolved) states, sorption can also influence the permeability through its own storage and transport mechanisms. The stress-dependence and sorption effects on permeability could develop under the reservoir conditions and influence the production, although we currently do not have a predictive permeability model that considers their co-existence. In this work this is accomplished by considering that the shale matrix consists of multiple continua with organic and inorganic pores. Stress-dependency of the permeability comes along with slit-shape inorganic pores, whereas the sorption effects are associated with nano-scale organic capillaries. A simple conceptual flow model with an apparent shale permeability is developed that couples the molecular transport effects of the sorbed phase with the stress-dependence of the inorganic matrix. Sensitivity analysis on the new permeability model shows that the stress-dependence of the overall transport is significant at high pore pressure, when the effective stress is relatively low. Diffusive molecular transport of the sorbed phase becomes important as the stress gets larger and, hence, the inorganic pores close. The constructed apparent permeability versus pore pressure curves show the dominance of the molecular transport as permeability improvement characterized by appearance of a minimum permeability value at the intermediate values of the pressure. The new permeability model can be used easily in history-matching a well performance and optimizing its production.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)