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Collaborating Authors
The Pennsylvania State University
A New Coupled Geomechanical-Chemical Model for CO2 Foam Flooding and Storage in Tight Reservoir
Cai, Mingyu (China University of Petroleum / The Pennsylvania State University) | Su, Yuliang (China University of Petroleum) | Elsworth, Derek (The Pennsylvania State University) | Hao, Yongmao (China University of Petroleum) | Gao, Xiaogang (China University of Petroleum)
Abstract Extensive research indicate that permeability damage caused by stress sensitivity could largely affect the displacement efficiency of CO2 foam. CO2 reaction with in-situ fluid and rock can also notably affects the forming and bursting rates of foam. To our knowledge, no study has fully examined both chemical reactions and mechanical damage effect in the process of CO2 foam flooding. In this work, the reaction kinetics models are used to simulate foam generation, decay, and trap in porous media, among which the relationship between decay reaction rate and permeability is obtained by fitting the results of core displacement experiments. The gas-liquid equilibrium constant (K Value) is used to describe the distribution of CO2 in the gas and liquid phases in a non-ideal mixture. The dissolution and precipitation of minerals by aqueous CO2 and the ion exchange between reservoir fluid and rock surface are also simulated. The Langmuir isothermal equation is applied to calculate the salinity on surfactant adsorption; the Pseudo Dilation Model is applied to simulate formation expansion and compression, and the Barton-Brandis Model is applied to describe the closure of fractures in the dual permeability Model. The new model allows us to examine better the effects of chemical reactions and mechanical damage on the performance of CO2 enhanced oil recovery (EOR) and storage. The results show that compared with water flooding and CO2 flooding, foam flooding benefits from the plugging effect on high permeability areas, and so that achieve higher recovery in strongly heterogeneous dual-porosity reservoirs. However, the high injection pressure of CO2 foam in tight reservoirs may lead to more extensive deformation, which can be improved by surfactant - alternating - gas (SAG) flooding with small slugs. It is also observed that the injected CO2 with foam is stored in a reservoir through kinds of approaches, including residual gas (63.8%), dissolved into oil (31.94%), and dissolved into water (2.88%) and only 1.39% is converted into mineral forms. Under the same gas injection volume, the total storage capacity of CO2 foam flooding is 16.67% higher than that of CO2 flooding. This is because the foam flooding generates a higher sweep area and increases the residual and dissolved gas volumes. This work establishes a chemical-mechanical coupled model to better simulate the complexities of CO2 foam flooding. The outcomes provide new insight into the optimization of CO2 foam flooding designs to maximize oil recovery and CO2 storage in field applications.
- Geology > Mineral (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
Elastodynamic Nonlinear Response of Dry Intact, Fractured and Saturated Rock
Manogharan, P. (The Pennsylvania State University) | Wood, C. (The Pennsylvania State University) | Riviรจre, J. (The Pennsylvania State University) | Elsworth, D. (The Pennsylvania State University) | Marone, C. (The Pennsylvania State University) | Shokouhi, P. (The Pennsylvania State University)
ABSTRACT Nonlinear elastic properties of fractured rocks carry crucial information on fracture features that can be exploited to forecast flow properties, friction constitutive behavior and poromechanical response. We report on a series of experiments designed to compare the nonlinear elastodynamic response of Westerly granite samples under true triaxial stress conditions in three states: dry intact, dry fractured and saturated fractured. We study the effect of fracturing and saturation in modifying the elastodynamic response of the rock. In order to measure the nonlinear elastodynamic response, a dynamic stress perturbation is applied by oscillating the normal stress. Ultrasonic waves transmitted across the fracture are used to monitor the evolution of wave velocity and amplitude before, during and after dynamic stressing. The nonlinearity of the response is evaluated by measuring the stress-dependency of wave velocity, amplitude and recovery rate. As expected, the saturated sample exhibits less nonlinearity than the dry intact and fractured samples due to presence of interstitial fluid and the resulting increased interface stiffness. Conversely, the dry intact rock shows a higher nonlinearity than that for dry fractured. We hypothesize that the fracture significantly reduces the transmission of strain to the half of the sample remote from transmission, thus resulting in a decrease in the measured elastodynamic nonlinearity. 1. INTRODUCTION Nonlinear elastic properties of fractured rock have important implications in managing engineered geothermal systems, waste storage, and unconventional reservoirs. The nonlinear elastodynamic signatures of rock are rich in information on the microscopic characteristics of fracture interfaces, which also govern friction, fluid flow and seismicity. Therefore, understanding the influence of fracturing and interstitial fluid on the elastodynamic response of rock is imperative in predicting its poromechanical properties. Even when macroscopically intact, rocks exhibit strong elastic nonlinearity. This nonlinearity is mainly due to their inherent heterogenous microstructure. The nonlinearity of rocks manifests itself as strain-dependency in the elastic properties, hysteresis and slow dynamics (rate dependent and memory effects). Numerous studies have reported on the nonlinear behavior of rocks using resonance-based methods (Johnson, Zinszner and Rasolofosaon, 1996; Ten Cate and Shankland, 1996; Van Den Abeele et al., 2000; TenCate, 2011; Riviรจre et al., 2015). More recently, dynamic acoustic-elastic testing (DAET) has been used in the laboratory to study the nonlinear elastodynamic behavior of rocks by measuring the strain-dependent variation in elastic ultrasonic wave velocity and amplitude (Renaud et al., 2011; Renaud, Le Bas and Johnson, 2012; G Renaud et al., 2013; G. Renaud et al., 2013). Compared to resonance-based methods, that yield the average nonlinearity of the sample, DAET results are local and comprehensive. Another advantage of DAET is the resemblance of the experimental setup to field-scale processes. In DAET, the nonlinearity is characterized by measuring the change in ultrasonic wave velocity and/or amplitude before, during and after low-frequency perturbations (pump). Rocks are known to exhibit a transient elastic softening phase as a result of applied small-stress perturbations and to recover slowly afterwards (Shokouhi, Riviรจre, Guyer, et al., 2017). Field scale observations also show a decrease in seismic wave velocity in the vicinity of faults during an earthquake and subsequent recovery (Brenguier et al., 2008, 2014; Niu et al., 2008; Sens-Schรถnfelder and Eulenfeld, 2019).
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Structural Geology > Tectonics > Plate Tectonics > Earthquake (0.88)
An Experimental Investigation of the Coupling Between Elastodynamic and Hydraulic Properties of Naturally Fractured Rock at the Laboratory Scale
Shokouhi, P. (The Pennsylvania State University) | Jin, J. (The Pennsylvania State University) | Manogharan, P. (The Pennsylvania State University) | Wood, C. (The Pennsylvania State University) | Riviรจre, J. (The Pennsylvania State University) | Elsworth, D. (The Pennsylvania State University) | Marone, C. (The Pennsylvania State University)
ABSTRACT We report on a series of laboratory experiments designed to simulate local effective stress field fluctuation and its influence on the evolution of permeability and dynamic stiffness in fractured samples of Westerly Granite. L-shaped samples are loaded with tri-axial stresses and fractured in situ. The fracture is subsequently sheared in two 4-mm steps. Oscillatory changes in the local effective stress field are imposed through application of normal stress or pore water pressure oscillations with varying amplitudes and frequencies. Active ultrasonic data (ultrasonic waves transmitted across the fracture) is used to monitor the evolution of wave velocity and attenuation before, during and after dynamic stressing. Throughout the experiment, the evolution of permeability is concurrently measured to determine the relationship between fracture permeability and nonlinear elastodynamic properties (stressdependency of wave velocity and attenuation). Our results to date indicate that relative changes in wave velocity and permeability, due to both normal stress and pore pressure oscillations, are correlated, such that larger drops in wave velocity correspond to larger increases in permeability. Shearing of the fracture reduces the nonlinearity measured during normal stress oscillations for both rock samples. After shearing, the oscillations become generally less effective in enhancing the fracture permeability. 1. MOTIVATION AND BACKGROUND In the context of induced seismicity due to fluid injection, of particular concern are dynamic stresses associated with injection, pumping and transport of supercritical H2Oโ CO2 fluids. These stresses may pose significant risk associated with accelerated deformation, fault reactivation and possible damage to reservoir seals. Regional increases in seismic activity induced by such dynamic stresses have been reported in numerous studies (Healy et al., 1968; Raleigh et al., 1976; Simpson et al., 1988; Davis and Pennington, 1989; Sminchak and Gupta, 2003; Deichmann and Giardini, 2009; Frohlich, 2012; Horton, 2012; Zoback and Gorelick, 2012; Zoback, 2012; Brodsky and Lajoie, 2013; Ellsworth, 2013; Holland, 2013; van der Elst et al., 2013; McNamara et al., 2015; McGarr et al., 2015; Walsh and Zoback, 2015; Weingarten et al., 2015). The recent seismic activity in Ridgecrest California (Ross et al., 2019) and its impact on the community around Los Angeles and local geothermal energy production are stark reminders of the impact earthquakes can have on energy. However, in the context of energy recovery, these dynamic stresses may be beneficial via enhancing permeability. Transient permeability changes caused by dynamic stresses associated with passing seismic waves have been reported at the field scale and also demonstrated in laboratory experiments (Elkhoury et al., 2006; Faoro et al., 2009; Elkhoury et al., 2011; Faoro et al., 2012; Candela et al., 2014, 2015; Carey et al., 2015; Frash et al., 2016; Im et al., 2018; Ishibashi et al., 2018; Zhang et al., 2018; Shi et al., 2018; Ye and Ghassemi, 2018; Shi et al., 2019). These studies show that fluid injection and dynamic stresses combine to produce significant changes in permeability, fault stability and poromechanical properties of rock. Such effects have significant implications for fossil fuel production and geothermal energy.
- North America > United States > Texas (0.46)
- North America > United States > Pennsylvania (0.46)
- North America > United States > California (0.34)
- North America > United States > Oklahoma (0.28)
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (0.68)
- Geology > Structural Geology > Tectonics > Plate Tectonics > Earthquake (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- North America > United States > West Virginia > Appalachian Basin > Utica Shale Formation (0.99)
- North America > United States > Texas > Permian Basin > Cogdell Field > Fuller Sand Formation (0.99)
- North America > United States > Texas > Permian Basin > Cogdell Field > Area Formation (0.99)
- (4 more...)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Faults and fracture characterization (1.00)
Numerical Generation of Stress-Dependent Permeability Curves
Al Balushi, F. (The Pennsylvania State University) | Dahi Taleghani, A. (The Pennsylvania State University)
ABSTRACT In this study, we presented a numerical method to investigate the behavior of absolute permeability changes under various stress conditions using Micro-Computed Tomography (CT) images. To benchmark this method, we implemented this workflow for a Berea sandstone sample. A digital rock model is constructed using CT images and rock deformation under stress is simulated using Finite-Element Analysis. Then, absolute permeability in the deformed rock is computed using Lattice Boltzmann Methods. Since, stress analysis and LBM analyses are time-consuming processes to be implemented for any arbitrary stress conditions, we proposed utilizing the state function method to define permeability as a function of stress invariants. The outcomes of the study show that in poorly consolidated formations, permeability is a strong function of effective stress and decreases nonlinearly as the change in stress invariants becomes more significant. The presented coupled workflow shows some capabilities for predicting absolute permeability for different rock types in different directions. 1. INTRODUCTION Reservoir performance depend to a large extent on its absolute permeability. Permeability is a rock property that defines the rock ability to transmit fluids, which could be affected by several factors including confining pressure, temperature, stress state, and rock microstructure (Fatt and Davis, 1952; Wei et al., 1986; Gavrilenko and Gueguen, 1989; Davis and Davis, 1999; Ghabezloo et al., 2009). An accurate estimation of future productivity and injectivity, quantifying near-wellbore damage, and reservoir simulations are contingent upon understanding permeability changes under different conditions (Bautista and Taleghani, 2017; Bautista and Taleghani, 2018). While there has been speculation in rock mechanics community to relate microfractures' opening or their initiation by shearing as the main attribution for permeability enhancement, in this paper, we look at this problem in absence of microfracture in a digital rock setup to explore such possibility simply due to deformation of pore throat geometries. Reservoir rocks are composed of various-sized grains, pore space, and intergranular material that may be resulting from cementation or overgrowth. The configuration of those components determines the interconnectedness of the pores, which controls the permeability of the rock. Previously, reservoirs were assumed to be static systems (Lorenz, 1999), however, experimental studies and field measurements have revealed that the deliverability of the reservoir varies as a result of stress changes. The porous structure of the rock may alter upon introducing a stress disturbance to the system due to the non-uniform contact between the grains. Because reservoir rocks are non-rigid and exhibit elastic and inelastic properties depending on the constituting grains, which may result in slippage and rotation, change in grainsโ shape, and cracking (Davis and Davis, 1999).
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.52)
Fractional Laplacians viscoacoustic wavefield modeling with k-space-based time-stepping error compensating scheme
Wang, Ning | Zhu, Tieyuan (The Pennsylvania State University) | Zhou, Hui | Chen, Hanming | Zhao, Xuebin | Tian, Yukun
ABSTRACT The spatial derivatives in decoupled fractional Laplacian (DFL) viscoacoustic and viscoelastic wave equations are the mixed-domain Laplacian operators. Using the approximation of the mixed-domain operators, the spatial derivatives can be calculated by using the Fourier pseudospectral (PS) method with barely spatial numerical dispersions, whereas the time derivative is often computed with the finite-difference (FD) method in second-order accuracy (referred to as the FD-PS scheme). The time-stepping errors caused by the FD discretization inevitably introduce the accumulative temporal dispersion during the wavefield extrapolation, especially for a long-time simulation. To eliminate the time-stepping errors, here, we adopted the -space concept in the numerical discretization of the DFL viscoacoustic wave equation. Different from existing -space methods, our -space method for DFL viscoacoustic wave equation contains two correction terms, which were designed to compensate for the time-stepping errors in the dispersion-dominated operator and loss-dominated operator, respectively. Using theoretical analyses and numerical experiments, we determine that our -space approach is superior to the traditional FD-PS scheme mainly in three aspects. First, our approach can effectively compensate for the time-stepping errors. Second, the stability condition is more relaxed, which makes the selection of sampling intervals more flexible. Finally, the -space approach allows us to conduct high-accuracy wavefield extrapolation with larger time steps. These features make our scheme suitable for seismic modeling and imaging problems.
- Asia > China (0.47)
- North America > United States (0.29)
- Geophysics > Seismic Surveying > Seismic Processing (1.00)
- Geophysics > Seismic Surveying > Seismic Modeling > Velocity Modeling (0.46)
Impact of Swelling Area Expansion from the Fracture Wall into the Matrix on the Evolution of Coal Permeability
Zeng, Jie (The University of Western Australia) | Liu, Jishan (The University of Western Australia) | Li, Wai (The University of Western Australia) | Tian, Jianwei (The University of Western Australia) | Leong, Yee-Kwong (The University of Western Australia) | Elsworth, Derek (The Pennsylvania State University) | Guo, Jianchun (Southwest Petroleum University)
Abstract Previous studies have concluded that classical poroelasticity-based permeability models cannot explain why coal permeability changes under the condition of both variable and constant effective stresses. There are two effective stress systems, one for the fracture system and the other for the matrix system. When coal permeability is measured, the effective stress in fractures is thought as constant while that in coal matrices remains changing with time. When gas is injected and reaches a steady state in fractures, the gas diffuses from the fracture wall into the matrix. During this diffusion process, the gas adsorbs onto coal grains. This adsorption results in coal matrix swelling. In this study, we introduce a novel concept of the volumetric ratio, the ratio of the gas-invaded area to the whole matrix area, to quantify the impact of matrix swelling area expansion on the evolution of coal permeability. The gradual matrix pressure increase near fracture walls enhances local swelling. Meanwhile, because the matrix near fracture walls contributes most to local effects, expanding of the gas invaded zone continuously weakens the matrix-fracture unequilibrium and local effects. Finally, the matrix is completely invaded by the injected gas with a new equilibrium state and local effects end. The effective stress in our model can be either constant or time-dependent. A fracture pressure loading function is applied to depict gas injection with time-dependent effective stresses. The modeling results are verified against various experimental data. We find that the evolution of coal permeability from the initial state to the final equilibrium state is a result of the propagation of gas invaded areas from the fracture wall into the matrix. Our model can be utilized to generate a series of coal permeability maps that explain a variety of lab and field observations. 1. Introduction Coal permeability is a crucial parameter that controls methane extraction and carbon dioxide sequestration. It is of interest to both mining and petroleum engineers (Dabbous et al. 1974). Traditional poroelasticity-theory based coal permeability models are developed based on the assumption of evenly swelling or shrinkage of both matrices and fractures (Cui and Bustin 2005; Zhang et al. 2008). And the following bulk and fracture volume change relationships can be obtained (Eqaution)
- Geology > Rock Type > Sedimentary Rock (0.70)
- Geology > Geological Subdiscipline > Geomechanics (0.49)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Coal seam gas (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Gas-injection methods (1.00)
Characterizing Gas Transfer from the Inorganic Matrix and Kerogen to Fracture Networks: A Comprehensive Analytical Modeling Approach
Zeng, Jie (The University of Western Australia) | Liu, Jishan (The University of Western Australia) | Li, Wai (The University of Western Australia) | Li, Lin (The University of Western Australia) | Leong, Yee-Kwong (The University of Western Australia) | Elsworth, Derek (The Pennsylvania State University) | Guo, Jianchun (Southwest Petroleum University)
Abstract An appropriate description of gas transfer from shale matrices to fracture networks is one of the most fundamental issues in shale gas extraction modeling. Existing gas transfer functions can be classified into the following categories: (1) direct single-continuum matrix to fracture transfer; (2) kerogen, inorganic matrix, and fracture series gas transfer; and (3) kerogen to fracture and inorganic matrix to fracture parallel gas transfer. The scanning electron microscope (SEM) images of shale samples reveal the heterogeneous distribution of pure inorganic regions, kerogen and inorganic-matrix interwoven regions, and pure kerogen regions. As fracture networks can penetrate different matrix regions at different locations, the mass transfer between matrices and fractures cannot be comprehensively simulated by any of the above methods. This paper presents a new matrix-fracture transfer function considering type 1: the direct inorganic matrix to fracture network inflow for pure inorganic regions; type 2: the kerogen, inorganic matrix, and fracture series flow for kerogen and inorganic-matrix interwoven regions; type 3: the direct kerogen to fracture network inflow for kerogen-rich regions. The contribution of each type in the transfer function is weighted through the volume percentage of each matrix-region type. Different multi-scale and multi-physics gas flow processes are included in kerogen and inorganic matter respectively. Finally, fluid transfer from fracture networks to hydraulic fractures is coupled through a linear flow system with stimulated reservoir volumes (SRVs). This model has been validated against field data with an excellent agreement. And the degraded model's calculation matches well with that of a published composite linear flow model. Sensitivity analyses indicate that matrix-fracture gas transfer patterns affect certain flow regimes from the matrix-fracture transient regime to the transient regime before the boundary dominant regime. Types 1 and 2 gas transfer mechanisms with direct inorganic matter and secondary fracture connection exhibit lower dimensionless pressure and higher dimensionless rate values. The effects of the organic matter volume fraction and organic-rich reservoir block allocations on well production are also documented. This approach is a general tool for characterizing the gas transfer from shale matrices to fracture networks.
- North America > United States (0.68)
- Asia > China (0.46)
- 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...)
Petrophysical Evaluation of Shale Gas Reservoirs: A Field Case Study of Marcellus Shale
Yildirim, Levent Taylan (The Pennsylvania State University) | Wang, John Yilin (The Pennsylvania State University) | Elsworth, Derek (The Pennsylvania State University)
Abstract Successful petrophysical evaluation and stimulation treatments with horizontal drilling and hydraulic fracturing enable the economic development of shale gas reservoirs. Detailed evaluation of shale gas reservoirs before and after stimulation treatments is a prerequisite to increase efficiency and effectiveness of shale gas development. Determination of organic maturity, porosity and original gas in place remains a challenge using traditional petrophysical models due to the complex pore networks and ultra-low permeability of shale. On the basis of a petrophysical model for shale gas reservoirs (Passey et al., 2010), we propose an integrated approach for petrophysical evaluation using analyses of lithology, porosity, fluid saturation, organic maturity, geomechanical properties and initial gas in place. Our petrophysical model for shale gas reservoirs is partitioned into organic matter, clay and non-clay minerals in the solids, adsorbed and free gas, together with capillary-bound, clay-bound and mobile water in the pore space. Vitrinite reflectance is computed in relation to the level of organic maturity (LOM) and kerogen density. Total organic carbon (TOC) is calculated using the Passey method (Passey et al., 1990). Effective porosity of shale gas reservoirs is calculated from algebraic expressions for solid and fluid fractions of the petrophysical model. Compressional and shear slowness logs are used to evaluate the geomechanical properties. Initial gas in place is calculated from free gas and adsorbed gas with porosity, fluid saturation, areal extent, thickness, adsorbed gas storage and organic matter. The methods are successfully applied to a field case in Marcellus shale. TOC (wt.%) calculated by (sonic-density)/resistivity overlay methods for Marcellus Shale are 9.73% and 6.32%, respectively. TOC correlates directly to porosity and adsorbed gas in place occupied within the organic matter. For Marcellus shale, average density and sonic porosities are 6.25% and 3.46%, respectively. The comparison of Young's modulus and the minimum in-situ stress values between Marcellus shale and adjacent formations are used for the determination of the stimulation interval in the Marcellus Formation. Sonic and density logging suggest 2.22 BCF and 4.10 BCF as technically recoverable reserves with an 8% recovery factor. These results from Marcellus shale provide an improved understanding of economic development of unconventional reservoirs.
- North America > United States > West Virginia (1.00)
- North America > United States > Virginia (1.00)
- North America > United States > Pennsylvania (1.00)
- (3 more...)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.93)
- South America > Colombia > T Formation (0.99)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- (21 more...)
Pore structure characteristics and its effect on adsorption capacity of Niutitang marine shale in Sangzhi block, southern China
Wang, Xinghua (China University of Geosciences (Beijing), The Pennsylvania State University, China University of Geosciences) | Dahi Taleghani, Arash (The Pennsylvania State University) | Ding, Wenlong (China University of Geosciences (Beijing), China University of Geosciences)
Abstract Characteristics of shale pore structures may play an important role in natural gas accumulation and consequently estimating the original gas in place. To determine the pore structure characteristics of Niutitang marine shale in the Sangzhi block, we carried out adsorption-desorption (LP-GA), adsorption (LP-GA), and methane isothermal adsorption on shale samples to reveal the pore size distribution (PSD) and its impact on the adsorption capacity. Results indicate that the Niutitang Shale is in stages of maturity and overmaturity with good organic matter, and they also indicate well-developed interparticle, intraparticle, and organic pores. Quartz and clay are found to be the main minerals, and the high illite content means that the Niutitang Shale is experiencing the later stage of clay mineral transformation. Various-sized shale pores are well-developed, and most of them are narrow and slit-like. For pores with diameters of 2โ300ย nm measured with LP-GA, mesopores (2โ50ย nm) contribute most of the total specific surface area (SSA) and total pore volume (TPV) in comparison to macropores (50โ300ย nm). For micropores () tested by LP-GA, the PSD appears to be multimodal; shale pores of 0.50โ0.90ย nm diameter contribute most of the SSA and TPV. -SSA and -SSA indicate positive correlations with their corresponding TPV. The total organic matter (TOC) has good correlation with the SSA and TPV of micropores. The Langmuir volume positively correlates with the total SSA. Additionally, the TOC content has a good correlation with the Langmuir volume, which is consistent with the observation of well-developed fossils of diatoms and organic pores. As an important source of organic matter, more diatoms mean more organic matter, larger TOC values and quartz content, larger SSA and TPV of micropores, and, of course, stronger shale adsorption capacity. The results provide important guidance for the exploration and development of shale gas existing in the Sangzhi block.
- North America > United States > Texas (0.46)
- Asia > China > Sichuan Province (0.29)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Mineral (1.00)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > United States > Texas > Ardmore - Marieta Basin > Newark East Field > Barnett Shale Formation (0.99)
- Europe > Norway > Norwegian Sea (0.99)
- (5 more...)
Semi-Analytical Analysis of Peak Production Rates in Unconventional, Boundary-Dominated Gas Reservoirs with Adsorptive Storage
Alzaabi, Abdulla (The Pennsylvania State University) | King, Gregory (The Pennsylvania State University)
Abstract The objective of this study was to develop tools to analyze the production profile of unconventional gas reservoirs where adsorption is a dominant storage mechanism. Specifically, the research is focused on analyzing the conditions that affect the time needed to achieve peak gas production rate. To this end, we have successfully derived the analytical expressions for the reservoir pressures at which peak gas production occurs under various operating scenarios. The methodology involves the development of a system of generalized two-phase material balance equations for boundary dominated flow in unconventional gas reservoirs where adsorption is a dominant storage mechanism. The resulting analytical ODEs are then solved numerically (Runge-Kutta) which yields a semi-analytical solution for pressure and saturation versus time. Once the pressure and saturations are determined numerically, gas and water production rates, along with their derivatives, are determined analytically and used to analyze the production profiles. Through the analytical derivatives, reservoir and fluid parameters can be modified to observe their effects on the time to peak gas rate. In this study, three different well specifications were investigated (constant flowing well pressure, constant well drawdown, and constant water production rate) with only two of the three well specifications resulting in a peak gas production rate - no peak gas production rate was observed for the water rate specified wells. Furthermore, the developed semi-analytical model, under appropriate conditions, gives results comparable to numerical reservoir simulator. The paper will discuss conditions at which the material balance results are comparable to full reservoir simulation. Through this research, a new material balance method has been developed that can be presented in different domains (pressure, time, and cumulative produced fluids domains). Also, the novel use of derivatives from the generalized material balance equations was applied in this research to analytically and graphically analyze the production profile. Furthermore, in addition to the peak gas production rate, additional inflection points were observed that have not been reported in the current literature.
- North America > United States > Texas (0.46)
- Asia > Middle East > UAE (0.46)
- North America > United States > Alabama > Tuscaloosa County (0.28)
- North America > United States > Wyoming > Powder River Basin (0.99)
- North America > United States > New Mexico > San Juan Basin > Fruitland Formation (0.99)
- North America > United States > Montana > Powder River Basin (0.99)
- (3 more...)