Showing papers by "George J. Moridis published in 2021"

Coupled Flow/Geomechanics Modeling of Interfracture Water Injection To Enhance Oil Recovery in Tight Reservoirs

Abstract: Unconventional tight reservoirs that are typically characterized by low permeability and low porosity have contributed significantly to the global hydrocarbon production in recent years. Although hydraulic fracturing, along with horizontal well drilling, enables the economic development of such reservoirs, the production rate often declines sharply and results in low primary hydrocarbon recovery. The application of enhanced-oil-recovery (EOR) techniques in tight reservoirs has received much interest. In this study, the feasibility and efficiency of interfracture water injection to enhance oil recovery in multistage fractured tight oil reservoirs are analyzed through an efficient coupled flow/geomechanics model with an embedded discrete-fracture model (EDFM). A combined finite-volume/finite-element scheme is used to discretize the governing equations for flow and geomechanics, and the coupled problem is solved sequentially using a fixed-stress splitting algorithm. A basic numerical model consisting of a 15-stage fractured horizontal well is constructed using the petrophysical and geomechanical properties of a tight oil formation in Ordos Basin, China. Fractures indexed with even numbers are switched into injecting fractures when the production rate has dropped to less than a certain threshold. The improvement of oil recovery is analyzed by comparing the production profiles with and without water injection. In this coupled model, the fracture closure/opening during production/injection is considered according to the constitutive relations between fracture aperture and effective normal stress acting on the fracture faces. The poromechanical response of matrix is modeled by the Biot (1941) theory. The effects of fracture spacing, injection rate, and the presence of a natural-fracture network on oil-recovery enhancement are discussed through sensitivity analysis. The main mechanisms of interfracture water injection for enhancing oil recovery are waterflooding and reservoir-pressure maintenance. Small fracture spacing tends to reduce the oil recovery because of fracture interference and a limited drainage area; therefore, the primary depletion stage is shortened as the fracture spacing is reduced. The influence of interfracture water injection is more pronounced with smaller fracture spacing because the pressure-transient responses near the producing fractures are more dramatic considering the close proximity between the injecting fracture and the producing fracture. Although a higher injection rate results in higher oil recovery, the injectivity in low-permeability reservoirs limits the maximum-allowable injection rate. When secondary (natural)-fracture networks are considered, neighboring hydraulic fractures can be connected to one another via the secondary fractures, particularly if the interfracture spacing is small. Water can break through in the producing fractures quickly, which could also lead to high water cut and suboptimal oil-recovery performance. This study tests the feasibility and efficiency of interfracture injection to enhance tight oil recovery. The results indicate that interfracture injection can be a promising EOR technique for tight oil reservoirs, which sheds lights on future completion strategies and production design in tight reservoirs.

Hydraulic-Fracture-Width Inversion Using Low-Frequency Distributed-Acoustic-Sensing Strain Data—Part I: Algorithm and Sensitivity Analysis

Abstract: Low-frequency distributed-acoustic-sensing (LF-DAS) data, which can be treated as linear-scaled strain variations, have been used recently to monitor hydraulic-fracturing treatments. Forward geomechanical modeling has been the subject of recent research efforts to better interpret the observed signatures of field LF-DAS data. To the best of our knowledge, there is no study that attempts to quantitatively characterize fracture geometries by directly inverting the LF-DAS strain data. In this study, we propose an inversion algorithm, in which the strains monitored by LF-DAS along an offset well are related to the fracture widths through a Green function. A 3D displacement-discontinuity method is used to construct the Green function. The least-squares method is first used to solve the linear system of equations. Regularization might be needed to stabilize the underdetermined system. Then, Markov-chain Monte Carlo (MCMC) simulations are conducted to generate fracture-width samples from the target distribution of LF-DAS strain data and to quantify uncertainties associated with the inverted widths. The inversion results obtained by the least-squares method are nonunique, heavily depending on the a priori regularization information. Regardless of the additional constraints imposed on the linear system, the inverted fracture width at the monitor-well location is always consistent with the true value because the LF-DAS data show a dominant sensitivity of fracture width near the monitor well. MCMC simulation results confirm that the LF-DAS strain data can only impose constraints on fracture segments near the monitor well. Moreover, the average value of the inverted widths in the vicinity of the monitor well is usually the same as the width right at the monitor well, except for the very early time after fracture hit when there are sharp width variations near the fracture tip. Therefore, it is efficient to use a single width for each fracture during the inversion process. The presented algorithm is successfully applied to invert the width evolution near the monitor well as a function of injection time. The results of this study demonstrate how much information can be obtained with high confidence from the inversion of LF-DAS strain data, which is beneficial for future use of LF-DAS data. The accurate estimation of fracture width at the monitor well can be used to calibrate hydraulic-fracturing models, improve the design of completion parameters such as proppant size, and provide the possibility of characterizing the whole fracture geometry with additional information or assumptions.

Fracture-Hit Detection Using LF-DAS Signals Measured during Multifracture Propagation in Unconventional Reservoirs

Abstract: Low-frequency distributed acoustic sensing (LF-DAS) data are a powerful attribute to detect fracture hits and characterize fracture geometry during multistage hydraulic fracturing treatments in unconventional reservoirs. The DAS data in low-frequency bands linearly correlate with strain and strain rate induced by dynamic fracture propagation. Due to the complexity of multiple-fracture propagation in unconventional reservoirs, the measured signals from different wells exhibit various characteristics. Mechanisms causing the differences are not well understood, which makes the interpretation of real LF-DAS data and detection of fracture hits very challenging. Hence, it is necessary to relate the observed strain/strain-rate signatures to specific fracture patterns based on the physical model of rock deformation during fracture propagation and to quantitatively characterize signatures surrounding fracture hits. In this study, we have applied our in-house fracture propagation model to simulate simultaneous multiple-fracture propagation as well as fracture-induced strain and strain-rate responses along an offset monitor well. Then a general guideline for fracture-hit detection is proposed based on quantitative analysis of strain/strain-rate responses during multiple-fracture propagation. Finally, a set of field examples are presented to demonstrate the potential of LF-DAS data on hydraulic fracturing monitoring. During multiple-fracture propagation, a “heart-shaped” zone with positive strain rates may be identified for each fracture before the fracture hit. Immediately after the fracture encounters the monitor well, part of the fiber within the fracture path keeps being extended, while the fiber sections off the path become compressed. Three 1D features along the channel (location) axis are designed to detect fracture hits. The features are maximum strain rate, the summation of strain rates, and summation of strain-rate amplitudes. Channels with fracture hits usually exhibit significant peak values of the three features. However, the characteristic signatures can be less detectable when the gauge length is close to the cluster spacing. Connections between fracture-hit locations and cluster perforations clearly reflect the fracture propagation direction. The field examples illustrate the complexity of real LF-DAS signals and demonstrate the adequacy of the proposed guideline for fracture-hit detection with multicluster completion. The fractures propagate nearly perpendicular to the horizontal wellbore in this unconventional shale formation. In addition, four to five fractures out of eight perforation clusters can propagate 396.24 m (1,300 ft) and hit the monitor well, and the “heel-biased” fracture pattern is observed (fractures that do not hit the monitor well are usually close to the toe side). Fracturing fluid leaking off into the previous stage can also be diagnosed, which could negatively affect the completion efficiency.

Hydraulic-Fracture-Width Inversion Using Low-Frequency Distributed-Acoustic-Sensing Strain Data Part II: Extension for Multifracture and Field Application

Abstract: Low-frequency distributed-acoustic-sensing (LF-DAS) strain data are direct measurements of in-situ rock deformation during hydraulic-fracturing treatments. In addition to monitoring fracture propagation and identifying fracture hits, quantitative strain measurements of LF-DAS provide opportunities to quantify fracture geometries. Recently, we proposed a Green’s function–based algorithm for the inversion of LF-DAS strain data (Liu et al. 2020b) that shows an accurate estimation of fracture width near the monitor well with single-cluster completions. However, multicluster completions with tighter cluster spacings are more commonly adopted in recent completion designs. One main challenge in the inversion of LF-DAS strain data under such circumstances is that strain measurements at fracture-hit locations by LF-DAS are not reliable, which makes the individual contribution of each fracture to the measured strain data indistinguishable. In this study, we first extended the inversion algorithm to handle multiple fractures, investigated the uncertainties of the inversion results, and proposed possible mitigation to the challenges raised by completion designs and field data acquisition through a synthetic case study. Ideally, there are available data on both sides of each fracture so that the inverted width of each fracture can be obtained with a negligible error. In reality, the strain data are usually limited, providing less constraint on the width of individual fracture. Nevertheless, the inversion results provide an accurate estimation of the width summation of all fractures. To evaluate the individual fracture width, a time-dependent constraint is added to the inversion algorithm. We assume that the width at the current timestep is dependent on the width at the previous step and the width variation between the two timesteps. The width variation can be roughly estimated from LF-DASstrain-rate data at the fracture-hit location. This extra constraint helps to improve the inversion performance. Finally, a field example is presented. We show the width summation of all fractures and the width of each individual fracture as a function of treatment time. The time-dependent width profiles show consistent trends with the LF-DASstrain-rate data. The calculated strains from the inverted model match well with the LF-DAS measured strain data. The findings demonstrate the potential of LF-DAS data for quantitative hydraulic-fracture characterization and provide insights on better use of LF-DAS data. The direct information on fracture width helps to calibrate fracturing models and optimize the completion designs.

A New Modeling Framework for Multi-Scale Simulation of Hydraulic Fracturing and Production from Unconventional Reservoirs

Abstract: This paper describes a new modeling framework for microscopic to reservoir-scale simulations of hydraulic fracturing and production. The approach builds upon a fusion of two existing high-performance simulators for reservoir-scale behavior: the GEOS code for hydromechanical evolution during stimulation and the TOUGH+ code for multi-phase flow during production. The reservoir-scale simulations are informed by experimental and modeling studies at the laboratory scale to incorporate important micro-scale mechanical processes and chemical reactions occurring within the fractures, the shale matrix, and at the fracture-fluid interfaces. These processes include, among others, changes in stimulated fracture permeability as a result of proppant behavior rearrangement or embedment, or mineral scale precipitation within pores and microfractures, at µm to cm scales. In our new modeling framework, such micro-scale testing and modeling provides upscaled hydromechanical parameters for the reservoir scale models. We are currently testing the new modeling framework using field data and core samples from the Hydraulic Fracturing Field Test (HFTS), a recent field-based joint research experiment with intense monitoring of hydraulic fracturing and shale production in the Wolfcamp Formation in the Permian Basin (USA). Below, we present our approach coupling the reservoir simulators GEOS and TOUGH+ informed by upscaled parameters from micro-scale experiments and modeling. We provide a brief overview of the HFTS and the available field data, and then discuss the ongoing application of our new workflow to the HFTS data set.

Evaluation of the Effectiveness of Continuous Gas Displacement for EOR in Hydraulically Fractured Shale Reservoirs

Abstract: The main objective of this study is to analyze and describe quantitatively the effectiveness of continuous gas displacement as an enhanced oil recovery (EOR) process to increase production from multifractured shale oil reservoirs. The study uses CH4 continuously injected through horizontal wells parallel to the production wells as the displacement agent and investigates the effects of various attributes of the matrix and of the induced and natural fracture systems. This numerical simulation study focuses on the analysis of the 3D minimum repeatable element (stencil/domain) that can describe a hydraulically fractured shale reservoir under production. The stencil is discretized using a very fine (millimeter-scale) grid. We compare the solutions to a reference case that involves simple depressurization-induced production (i.e., without a gas drive). We monitor continuously (a) the rate and composition of the production stream and (b) the spatial distributions of pressure, temperature, phase saturations, and relative permeabilities. The results of the study indicate that a continuous CH4-based displacement that begins at the onset of production does not appear to be an effective EOR method for hydraulically fractured shale oil reservoirs over a 5-year period in reservoirs in which natural or induced fractures in the undisturbed reservoir and/or in the stimulated reservoir volume (SRV) can be adequately described by a single-medium porosity and permeability. Under these conditions in a system with typical Bakken or Eagle Ford matrix and fracture attributes, continuous CH4 injection by means of a horizontal well parallel to the production well causes a reduction in water production and an (expected) increase in gas production but does not lead to any significant increase in oil production. This is attributed to (a) the limited penetration of the injected gas into the ultralow-k formation, (b) the dissolution of the injected gas into the oil, and (c) its early arrival at the hydraulic fracture (HF; thus, short circuiting the EOR process by bypassing the bulk of the matrix), in addition to (d) the increase in the pressure of the HF and the consequent reduction in the driving force of production and the resulting flow. Under the conditions of this study, these observations hold true for domains with and without an SRV over a wide range of matrix permeabilities and for different lengths and positions (relative to the HF) of the gas injection wells.

Transformational-Decomposition-Method-Based Semianalytical Solutions of the 3D Problem of Oil Production from Shale Reservoirs

Abstract: The primary objective of this study is to develop fast analytical and/or semianalytical (A/SA) solutions for the problem of liquid flow/production and pressure interference in multifractured systems between parallel horizontal wells in ultralow-permeability reservoirs. We propose a new A/SA method that reduces the 3D flow equation into either a simple algebraic equation or an ordinary differential equation (ODE) in a multitransformed space, the inversion of which yields solutions at any point in space and time.In the proposed transformational decomposition method (TDM), a general, fully linearized form of the 3D partial-differential equation (PDE) describing low-compressibility liquid flow through porous and fractured media is subjected first to Laplace transforms (LTs) to eliminate time, and then to successive finite cosine transforms (FCTs) that eliminate either all three dimensions, yielding a simple algebraic equation, or two dimensions, yielding an ODE in space only. Inversion of the solutions of the multitransformed space equations provides solutions that are analytical in space and semianalytical in time. The TDM completely eliminates the need for time and space discretization, thus dramatically reducing the input-data requirements and long execution times of numerical simulations.The Fortran 95 code for the TDM solutions requires limited inputs and is easy to use. Because of the linearity requirements of the Laplace transformation of the underlying PDE, the TDM is only rigorously applicable at greater than the bubblepoint pressure. Using 3D stencils (the minimum repeatable elements in the horizontal well and hydraulically fractured system) as the basis of our study, solutions over extended production times were obtained for a range of isotropic and anisotropic matrix and fracture properties, constant and time-variable production regimes (rates or bottomhole pressures), combinations of stimulated reservoir volume (SRV) and non-SRV subdomains, variable hydraulic-fracture (HF) dimensions, and inner and boundary (toe and heel) stencils.The results were compared with analytical solutions (available for simple problems and domain geometries), as well as with numerical solutions from a widely used, fully implicit 3D simulator that involves very fine discretization of a 3D domain comprising more than 356,000 elements. The TDM solutions were shown to be in excellent agreement with the reference analytical and/or numerical solutions, while requiring a fraction of the memory and execution times of the latter because of the elimination of the need for time and space discretization.The TDM is an entirely new approach for the analysis of low-compressibility liquid flow and pressure interference in hydraulically fractured ultralow-permeability reservoirs. The TDM solutions have the potential to provide a reliable and fast tool to identify the dominant mechanisms and factors controlling the system behavior and can act as the basis for a rapid initial parameter identification in a history-matching process for possible further refinement using full numerical modeling at less than the bubblepoint pressure.

The Partial Transformational Decomposition Method for a Hybrid Analytical/Numerical Solution of the 3D Gas-Flow Problem in a Hydraulically Fractured Ultralow-Permeability Reservoir

Abstract: The analysis of gas production from fractured ultralow-permeability (ULP) reservoirs is most often accomplished using numerical simulation, which requires large 3D grids, many inputs, and typically long execution times. We propose a new hybrid analytical/numerical method that reduces the 3D equation of gas flow into either a simple ordinary-differential equation (ODE) in time or a 1D partial-differential equation (PDE) in space and time without compromising the strong nonlinearity of the gas-flow relation, thus vastly decreasing the size of the simulation problem and the execution time. We first expand the concept of pseudopressure of Al-Hussainy et al. (1966) to account for the pressure dependence of permeability and Klinkenberg effects, and we also expand the corresponding gas-flow equation to account for Langmuir sorption. In the proposed hybrid partial transformational decomposition method (TDM) (PTDM), successive finite cosine transforms (FCTs) are applied to the expanded, pseudopressure-based 3D diffusivity equation of gas flow, leading to the elimination of the corresponding physical dimensions. For production under a constant- or time-variable rate (q) regime, three levels of FCTs yield a first-order ODE in time. For production under a constant- or time-variable pressure (pwf) regime, two levels of FCTs lead to a 1D second-order PDE in space and time. The fully implicit numerical solutions for the FCT-based equations in the multitransformed spaces are inverted, providing solutions that are analytical in 2D or 3D and account for the nonlinearity of gas flow. The PTDM solution was coded in a FORTRAN95 program that used the Laplace-transform (LT) analytical solution for the q-problem and a finite-difference method for the pwf problem in their respective multitransformed spaces. Using a 3D stencil (the minimum repeatable element in the horizontal well and hydraulically fractured system), solutions over an extended production time and a substantial pressure drop were obtained for a range of isotropic and anisotropic matrix and fracture properties, constant and time-variable Q and pwf production schemes, combinations of stimulated-reservoir-volume (SRV) and non-SRV subdomains, sorbing and nonsorbing gases of different compositions and at different temperatures, Klinkenberg effects, and the dependence of matrix permeability on porosity. The limits of applicability of PTDM were also explored. The results were compared with the numerical solutions from a widely used, fully implicit 3D simulator that involved a finely discretized (high-definition) 3D domain involving 220,000 elements and show that the PTDM solutions can provide accurate results for long times for large well drawdowns even under challenging conditions. Of the two versions of PTDM, the PTD-1D was by far the better option and its solutions were shown to be in very good agreement with the full numerical solutions, while requiring a fraction of the memory and orders-of-magnitude lower execution times because these solutions require discretization of only the time domain and a single axis (instead of three). The PTD-0D method was slower than PTD-1D (but still much faster than the numerical solution), and although its solutions were accurate for t < 6 months, these solutions deteriorated beyond that point. The PTDM is an entirely new approach to the analysis of gas flow in hydraulically fractured ULP reservoirs. The PTDM solutions preserve the strong nonlinearity of the gas-flow equation and are analytical in 2D or 3D. This being a semianalytical approach, it needs very limited input data and requires computer storage and computational times that are orders-of-magnitude smaller than those in conventional (numerical) simulators because its discretization is limited to time and (possibly) a single spatial dimension.

Quantitative Hydraulic-Fracture Geometry Characterization with LF-DAS Strain Data: Numerical Analysis and Field Applications

Abstract: Low-frequency distributed acoustic sensing (LF-DAS) has been used for hydraulic fracture monitoring and characterization. Large amounts of DAS data have been acquired across different formations. The low-frequency components of DAS data are highly sensitive to mechanical strain changes. Forward geomechanical modeling has been the focus of current research efforts to better understand the LF-DAS signals. Moreover, LF-DAS provides the opportunity to quantify fracture geometry. Recently, Liu et al. (2020a;2020b) proposed an inversion algorithm to estimate hydraulic fracture width using LF-DAS data measured during multifracture propagation. The LF-DAS strain data is linked to the fracture widths through a forward model developed based on the Displacement Discontinuity Method (DDM). In this study, we firstly investigated the impacts of fracture height on the inversion results through a numerical case with a four-cluster completion design. Then we discussed how to estimate the fracture height based on the inversion results. Finally, we applied the inversion algorithm to two field examples. The inverted widths are not sensitive to the fracture height. In the synthetic case, the maximum relative error is less than 10% even when the fracture height is two times of the true value. After obtaining the fracture width, the fracture height can be estimated by matching the true strain data under various heights with a strong smooth weight. The error between the calculated strain and true strain decreases as the height is getting close to the true value. In the two field examples, the temporal evolutions of both width summation of all fractures and the width of each fracture show consistent behaviors with the field LF-DAS measurements. The calculated strain data from the forward model matches well with the field LF-DAS strain data. The results demonstrate the robustness and accuracy of the proposed inversion algorithm.

JFTS+H: A Julia-Based Parallel Simulator for the Description of the Coupled flow, Thermal and Geochemical Processes in Hydrate-Bearing Geologic Media

Abstract: The objectives of this study are to develop (a) the Julia Flow and Transport Simulator (JFTS), a serial and parallel, high performance non-isothermal, multi-phase, multi-component general simulator of flow and transport through porous/fractured media, and (b) an associated module that describes quantitatively the Equation-of-State (EOS) of the complete H2O+CH4 system by covering all combinations of phase coexistence that are possible in geologic media and including all the regions of the phase diagram that involve CH4-hydrates. The resulting simulator (hereafter referred to as the JFTS+H code) can describe all possible scenarios of hydrate occurrence, dissociation and formation/evolution and is to be used for the investigation of problems of (a) gas production from natural CH4-hydrate accumulations in geologic media, as well as for (b) the analysis of any laboratory experiments involving CH4-hydrates. As indicated by the JFTS name, this simulator is written in the Julia programming language and its parallelization is based on the Message Passing Interface (MPI) approach. The JFTS+H simulator is a fully-implicit, Jacobian-based compositional simulator that describes the accumulation, flow and transport of heat, and up to four mass components (H2O, CH4, CH4-hydrate and a water-soluble inhibitor) distributed among four possible phases (aqueous, gas, hydrate, and ice) in complex 3D geologic systems. The dissociation and formation of CH4-hydrates can be described using either an equilibrium or a kinetic model. The automatic derivate capability of Julia greatly simplifies and enhances the Jacobian computations. The MPI Interface (Blaise, 2019) is implemented in all components of the code, and the METIS library (Karypis, 2013) is used for the domain decomposition needed for the effective parallelization of the solution of the Jacobian matrix equation that is accomplished using the LIS library (Nishida, 2010) of parallel Conjugate Gradient solvers for large systems of simultaneous linear equations. The JFTS+H code can model the fluid flow, thermal and geochemical processes associated with the formation and dissociation of CH4-hydrates in geological media, either in laboratory or in natural hydrate accumulations. This code can simulate any combination of the three possible gas hydrate dissociation methods (depressurization, thermal stimulation, and inhibitor effects), and computes all associated parameters describing the system behavior. The JFTS+H results show very good agreement with solutions of standard reference problems, and of large 2D and 3D problems obtained from another well-established and widely used numerical simulator. The code exploits the speed, computational efficiency and low memory requirements of the Julia programming language. The parallel architecture of JFTS+H addresses the persistent problem of very large computational demands in serial hydrate simulations by using multiple processors to reduce the overall execution time and achieve scalable speedups. The code minimizes communications between processors and maximizes computations within the same computational node, which has important consequences (especially when coupled with the automatic derivative capabilities of Julia) on performance in the development of the Jacobian matrix. An optimal LIS solver is recommended for this type of problem after evaluating different options. This approach provides both speedup and computational efficiency results when different numbers of processors are called in the solution process. This work is believed to be the first application of Julia (a new, highly efficient language designed for demanding scientific computations) to create a simulator for flow and transport in porous media. JFTS+H is a fast, robust parallel simulator that uses the most recent scientific advances to account for all known processes in a dynamic hydrate system and works seamlessly on any computational platform (from laptop computers to workstations, to clusters and supercomputers with thousands of processors).