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Collaborating Authors
Well Completion
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)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
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...)
- 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)
- (2 more...)
Abstract Much work has been done on hydraulic-fracturing as a well stimulation technique but our understanding of formation damage due to fracturing is limited. This is due to inherent complexity of shale-water interactions under subsurface conditions. Damage is triggered by cold and low-salinity water invasion into the formation. Here, we introduce the formation damage mechanisms as a multi-physics/chemistry problem developing in a region near the fracture-matrix interface. Using high-resolution flow simulation models, we investigate the mechanisms and their impact on natural gas production. The simulation model includes geo-mechanically fully coupled non-isothermal multi-component two-phase flow equations that are developed for a multi-scale porous medium representative of the shale formations. We consider the occurrence of formation damage during two consecutive periods: well shut-in period which is considered to begin with the completion of fracturing and extending 1-2 days; followed by water flow-back and gas production period which takes months. During the early shut-in period, cold water invasion leads to thermal contraction of the matrix and reduces the normal mean stress. These changes improve the formation permeability temporarily, they may create secondary fractures, and modify the capillary pressure and saturations in the water invaded zone. These thermal effects are reduced rapidly, however, due to heat supplied by the reservoir. Osmosis pressure and the associated clay swelling cause the formation matrix to absorb fracturing water, reduce the matrix permeability, and amplify the capillary pressure/saturations. In summary, the well goes to the flowback and production with modified near-fracture conditions. During the water flowback the water saturation near the fracture-matrix interface increases; hence, liquid blockage effect on the gas flow becomes larger than that predicted based on the water imbibition during the shut-in only. This is due to capillary-end-effect developing near the interface during the water flow-back, when the fracturing water is displaced by the gas, i.e., drainage. Clay swelling and stress change continue during the withdrawal of the fluids. Consequently, we observe significant impairment in gas production rates. Only a fraction (<20%) of the injected water is ultimately produced back from the shale gas wells; the rest stays in the fractures and invades into the formation. Our simulation work shows that it is mainly the water in the fractures that are produced. The rest stays in the fractures due to relative permeability effects therein, and in the matrix as capillary-bound water due capillary end effect and to clay-swelling.
- North America > United States > Texas (0.28)
- Europe (0.28)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Geological Subdiscipline > Geomechanics (0.96)
- Geology > Mineral (0.93)
- Well Drilling > Formation Damage (1.00)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- (4 more...)
Summary The stress-dependent permeabilities of split shale core plugs from Eagle Ford, Bakken, and Barnett Formation samples are investigated in the presence of microproppants. An analytical permeability model is developed for the investigation, including the interactions between the fracture walls and monolayer microproppants under stress. The model is then used to analyze a series of pressure-pulsedecay measurements of the propped shale samples in the laboratory. The analysis provides the propped-fracture permeability of the samples and predicts a parameter related to the quality of the proppant areal distribution in the fracture. The proppant-placement quality can be used as a measure of success of the delivery of proppants into microfractures and to design stimulation experiments in the laboratory. Introduction Unconventional-oil/gas resources, such as tight gas/oil and resource shale, have low porosity and ultralow permeability. Creating a well-connected complex fracture network is a key component of increasing the permeability and accelerating production. The early era of hydraulic fracturing horizontal wells in unconventional formations was concerned with achieving long fractures with multistage treatments with large cluster spacing. However, recent trends in this type of well completion and stimulation involve fractures that are created in narrower clusters in much closer spacing, targeting larger surface areas. It is argued that the practice of hydraulic fracturing with narrow clusters in close spacing along a lateral wellbore creates fractures with significantly reduced sizes, but in a complex network (Rassenfoss 2017). The creation of a network of fractures includes major operational issues.
- 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...)
Shale Gas Well Production Optimization using Modified RTA Method - Prediction of the Life of a Well
Baek, Seunghwan (Texas A&M University) | Akkutlu, I. Yucel (Texas A&M University) | Lu, Baoping (Sinopec Research Institute for Petroleum Engineering) | Ding, Shidong (Sinopec Research Institute for Petroleum Engineering) | Xia, Wenwu (Harding Shelton Petroleum Engineering & Technology Limited)
Abstract Routine history-matching and reservoir calibration methods for horizontal wells with multiple hydraulic fractures are complex. Calibration of important fracture and matrix quantities is, however, essential to understand the reservoir and estimate the future recoveries. In this paper, we propose a robust method of simulation-based history-matching and reserve prediction by incorporating an analytical solution of production Rate Transient Analysis (RTA) as an added constraint. The analytical solution gives the fracture surface area contributing to the drainage of the fluids from the matrix into the fractures. The surface area obtained from the RTA is the effective area associated with the productionโnot total area. It is the most fundamental and the most significant quantity in the optimization problem. Differential evolution (DE) algorithm and a multi-scale shale gas reservoir flow simulator are used during the optimization. We show that the RTA-based optimization predicts the quantities related to completion design significantly better. Further, we show how the estimated total fracture surface area can be used to measure the hydraulic fracturing quality index, as an indication of the quality of the well completion operation. The most importantly, we predict that the fractures under closure stress begin to close much sooner (100 days) than the prediction without the RTA-based fracture surface area constraint. The deformation continues under constant closure stress for about 20 years, when the fractures are closed nearly completely. This work attempts to use the traditional reservoir optimization technologies to predict not only the reserve but also the life of the unconventional well.
- Asia (1.00)
- Europe (0.68)
- North America > United States > Texas (0.46)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.73)
- North America > Canada > British Columbia > Peace River Field (0.99)
- Asia > China > Sichuan > Sichuan Basin (0.99)
- North America > Canada > Alberta > Smith Field > Am Eagle Et Al Smith 15-7-71-24 Well (0.93)
- North America > Canada > Alberta > Kim Field > Co-Enerco Et Al Peigan 14-26-8-26 Well (0.93)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Production forecasting (1.00)
Abstract This study is based on the premise that most of the trapped hydrocarbons can be produced, if we substitute them with another โacrificialโ fluid that has amplified interactions with organic pore walls, such as CO2. For the presented study, a downhole shale sample is analyzed in the laboratory to predict gas storage properties such as pore-volume, pore compressibility, and gas adsorption capacity. Then a series of pressure pulse decay measurements are performed to delineate transport mechanisms and predict stress-sensitive permeability. These coefficients are obtained as the calibration parameters of a simulation-based optimization for injection and production. Simulation model considers compositional gas flow in a deformable porous media and includes a multi-continuum porosity, with organic and inorganic pores, and micro-fractures. The experimental and simulation results show that most of the injected CO2 is adsorbed in the organic matrix and are not produced back. This is because CO2 molecules have significantly larger adsorption capacity when compared to methane. The strong adsorption of CO2 improves the release of natural gas from kerogen pores. This indicates that the separation of produced CO2 will be a minimal cost. Transport in kerogen has significant pore wall effects, and includes large mass fluxes of the adsorbed molecules by the walls due to surface diffusion. In essence, the adsorbed CO2 molecules significantly influence transport of methane. The results also show core-plug permeability is stress-sensitive due to presence of micro-fractures. Forward simulation results using optimum parameters indicate that closure stress developing near the fractures could significantly control the volume of CO2 injected. This raises operational issues on when to start injecting, and how to inject CO2. Using a simulation study of a production well with single-fracture, we show that fracture closure stress develops rapidly and production rate becomes a slave of the fracture geo-mechanics, e.g., strength of the proppants and the level of proppant embedment.
- Research Report > Experimental Study (0.48)
- Research Report > New Finding (0.34)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.90)
- 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 > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- (3 more...)
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)
- Well Drilling > Formation Damage (1.00)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- (6 more...)
Abstract Water-shale interactions are traditionally perceived as complex phenomena due to reactive nature of shale with water. However, the current trends in shale gas industry requires an advanced-level of understanding of these interactions and their impact on gas production. In this paper we investigate the invasion of fracturing water into the formation and the subsequent water-shale interactions. Objective of this work is to study osmosis and clay swelling effects of the invasion on the formation permeability. For this purpose, a new geomechanically-coupled reservoir flow simulator is developed, which accounts for water imbibition, osmosis and clay swelling effects on the formation permeability under stress. The simulation model considers the formation has a multi-scale pores consisting of microcracks, clay pores and organic pores. Water imbibition occurs in the water-wet inorganic part of the matrix in the microcracks. Osmosis and clay swelling effects develop in the clay pores acting as semi-permeable membrane to the imbibed water and changing the local stress in the formation. The simulation model includes aqueous and gaseous phases with three components: water, gas and salt. The simulation results show that the formation permeability is dynamically affected during the shut-in period by a combination of mechanisms including imbibition, capillarity, diffusion/osmosis, and total stress. Notably, a permeability impairment zone, rather a fracture skin, develops near the fracture. The permeability alteration is due to osmosis-related clay swelling and changing stresses in the formation. The magnitude of the permeability alteration is controlled mainly by the salt concentration difference between the fracturing fluid and the clay-bound water, the clay-membrane efficiency, the clay cation exchange capacity (CEC), the clay porosity, the stress and the duration of the shut-in time. We develop a fracture skin factor that can be used with the single-phase (gas) shale reservoir flow simulators that are typically run in the absence of water invasion at the scale of the stimulated reservoir volume (SRV) and in multidimensional geometries. Currently there is a clear need in the unconventional industry to better-understand and control the hydraulic fracturing fluid-shale interactions. This work is an important milestone considering the complexity of the problem and suggesting that the water chemistry and the formation lithology plays a significant role after the fracturing operations.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Mineral > Silicate > Phyllosilicate (1.00)
- Well Drilling > Formation Damage (1.00)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- (2 more...)
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)
- 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)
- (3 more...)
Abstract This paper describes the stress-dependent permeability of split shale core plugs from Eagle Ford, Bakken, and Barnett formation samples studied in presence of microproppants in microcracks. An analytical permeability model is developed, including the interaction between the fracture walls and monolayer microproppants under stress. The model is then used to analyze a series of pressure pulse decay measurements of the propped shale samples in the laboratory. The analysis provides the propped fracture permeability of the samples and predicts a parameter related to the quality of the proppant areal distribution in the fracture. The proppant placement quality can be used as a measure of success of the delivery of proppants into the fractures and to design stimulation in the laboratory.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.95)
- 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...)