Browsing by Subject "Naturally fractured reservoirs"

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Development of an efficient embedded discrete fracture model for 3D compositional reservoir simulation in fractured reservoirs
(2013-08) Moinfar, Ali, 1984-; Sepehrnoori, Kamy, 1951-; Johns, Russell T.
Naturally fractured reservoirs (NFRs) hold a significant amount of the world's hydrocarbon reserves. Compared to conventional reservoirs, NFRs exhibit a higher degree of heterogeneity and complexity created by fractures. The importance of fractures in production of oil and gas is not limited to naturally fractured reservoirs. The economic exploitation of unconventional reservoirs, which is increasingly a major source of short- and long-term energy in the United States, hinges in part on effective stimulation of low-permeability rock through multi-stage hydraulic fracturing of horizontal wells. Accurate modeling and simulation of fractured media is still challenging owing to permeability anisotropies and contrasts. Non-physical abstractions inherent in conventional dual porosity and dual permeability models make these methods inadequate for solving different fluid-flow problems in fractured reservoirs. Also, recent approaches for discrete fracture modeling may require large computational times and hence the oil industry has not widely used such approaches, even though they give more accurate representations of fractured reservoirs than dual continuum models. We developed an embedded discrete fracture model (EDFM) for an in-house fully-implicit compositional reservoir simulator. EDFM borrows the dual-medium concept from conventional dual continuum models and also incorporates the effect of each fracture explicitly. In contrast to dual continuum models, fractures have arbitrary orientations and can be oblique or vertical, honoring the complexity and heterogeneity of a typical fractured reservoir. EDFM employs a structured grid to remediate challenges associated with unstructured gridding required for other discrete fracture models. Also, the EDFM approach can be easily incorporated in existing finite difference reservoir simulators. The accuracy of the EDFM approach was confirmed by comparing the results with analytical solutions and fine-grid, explicit-fracture simulations. Comparison of our results using the EDFM approach with fine-grid simulations showed that accurate results can be achieved using moderate grid refinements. This was further verified in a mesh sensitivity study that the EDFM approach with moderate grid refinement can obtain a converged solution. Hence, EDFM offers a computationally-efficient approach for simulating fluid flow in NFRs. Furthermore, several case studies presented in this study demonstrate the applicability, robustness, and efficiency of the EDFM approach for modeling fluid flow in fractured porous media. Another advantage of EDFM is its extensibility for various applications by incorporating different physics in the model. In order to examine the effect of pressure-dependent fracture properties on production, we incorporated the dynamic behavior of fractures into EDFM by employing empirical fracture deformation models. Our simulations showed that fracture deformation, caused by effective stress changes, substantially affects pressure depletion and hydrocarbon recovery. Based on the examples presented in this study, implementation of fracture geomechanical effects in EDFM did not degrade the computational performance of EDFM. Many unconventional reservoirs comprise well-developed natural fracture networks with multiple orientations and complex hydraulic fracture patterns suggested by microseismic data. We developed a coupled dual continuum and discrete fracture model to efficiently simulate production from these reservoirs. Large-scale hydraulic fractures were modeled explicitly using the EDFM approach and numerous small-scale natural fractures were modeled using a dual continuum approach. The transport parameters for dual continuum modeling of numerous natural fractures were derived by upscaling the EDFM equations. Comparison of the results using the coupled model with that of using the EDFM approach to represent all natural and hydraulic fractures explicitly showed that reasonably accurate results can be obtained at much lower computational cost by using the coupled approach with moderate grid refinements.
Foam assisted surfactant-gas flooding in naturally fractured carbonate reservoirs
(2018-01-26) Aygol, Hayrettin; Sepehrnoori, Kamy, 1951-; Lashgari, Hamid Reza
In naturally fractured reservoirs, water flood performance and efficiency for oil recovery is usually limited by capillary forces. Wettability and interfacial tension (IFT) between oil and water phases are essential factors that limit the potential for oil production in naturally fractured reservoirs. The permeability of such reservoirs is in range of 1~20 md (majority of carbonate reservoirs) with the matrix wettability preferentially oil-wet to mixed-wet. Hence, water and/or gas flood performances are not efficient due to the tendency of water or gas flow through fractures. Surfactants are used to reduce IFT between oil and water, alter the wettability of matrix to proficiently water-wet, and generate in-situ foam as a drive and for mobility control. Spontaneous imbibition between the fractures and the matrix is achieved by both wettability alteration and ultra-low interfacial tensions. Experimental studies show that co-injection or alternate injection of surfactant solution and gas are very promising to mobilize and solubilize the remaining oil. In this study, we overview to provide a technical background and review the literature extensively in order to understand surfactant flooding and foam performance in porous media. Results show that surfactants are induced to matrix through fractures not only by spontaneous imbibition, but also by foam that diverts surfactant solutions into low permeability matrix. The finding results by several authors in lab-scale indicate that surfactant type, foam properties, capillary pressure properties corresponding to different wetting states, and oil-water interfacial tension are crucial factors that significantly impact the efficiency of such processes. In general, summary of this work shows that foam plays a dominant role as a drive to displace the oil in matrix when capillary forces are not strong to retain the oil in presence of surfactants. Although there is very restricted work that claim foam efficiency in presence of oil, mobilized oils are displaced and moved toward fractures as pure oil bank (oil phase). Some laboratory measurements and simulation study reveal with both core and reservoir scales that such process provides great sweep efficiency and recover a significant amount of remaining oil from the matrix to fracture.
Geostatistical Characterization of Naturally Fractured Reservoirs
(2004-05) Liu, Xiao Huan; Srinivasan, Sanjay
Natural fractures are commonly observed in many major reservoirs worldwide and contribute significantly to worldwide oil production. Characterization of fractures is necessary in order to make accurate forecast of reservoir performance. However, fracture reservoir characterization is not easy due to insufficient information generally derived from cores and logs. The main characterization tools are geological classification, geomechanical characterization, pattern recognition and stochastic simulation. Geological classification is based on analysis of paleo-stress conditions in the reservoir at the time of fracturing. Geomechanical characterization is based on utilization of the plausible stress state of the reservoir in order to predict the distribution and orientations of fractures. The disadvantage of this tool is the models are largely deterministic (i.e. uncertainty of fracture propagation might not be captured). Fracture patterns can also be classified using the information obtained from outcrop. Although some information supplementary to cores and logs can be obtained from outcrop and used to classify patterns in detail, environmental factors such as weathering would constrain the inference & application of outcrop patterns to model target reservoir. Besides, the extent to which the outcrop is analogous to the target reservoir is difficult to ascertain a priori. The stochastic simulation approach is based on application of some statistical interpolation algorithm such as kriging or cokriging that can be used to obtain estimates of necessary conditional distributions from which fracture patterns can be sampled. Since it does not consider any geomechanical criteria for fracture pattern generation, the model based on stochastic simulation is not physical. Therefore integration of the information derived from more realistically deterministic geomechanical models is necessary to develop physically realistic stochastic fracture models. This is a primary focus of this research. The spatial distribution of fractures in a reservoir affects the displacement of fluids and the prediction of future performance. Realistic characterization of fractured reservoirs requires quantification and classification of fracture patterns on the basis of the underlying geological characteristics and developing reservoir modeling algorithms that can integrate connectivity (multiple point) based statistics related to fracture patterns. Developing a methodology for summarizing the characteristics of fracture networks based on multiple point connectivity characteristics derived from analog models and all other available reservoir specific data in the form of well information, conditioning reservoir models, geomechanical models and seismic areal proportion maps is the primary objective of the research.
Implementation of a Dual Porosity Model in a Chemical Flooding Simulator
(1999-08) Aldejain, Abdulaziz A; Miller, Mark A; Sepehrnoori, Kamy
Naturally fractured reservoirs occur worldwide and constitute an important reservoir type. The main feature that distinguishes naturally fractured reservoirs from conventional reservoirs is the presence of fractures. These fractures offer permeability enhancement. However, most of the porosity, and therefore the oil, still exists in the matrix blocks between fractures, thus requiring the oil to be transferred into the fracture network before it can be recovered. Recovery by water imbibition derived by capillary forces offers an excellent means of expelling the oil from matrix blocks and into fractures. However, this mechanism leaves behind significant amounts of oil in the matrix block in the form of residual oil. Reducing the residual oil saturation in the matrix blocks could thus lead to a higher oil recovery. One method to accomplish this is through the use of surfactants. Numerical simulation of this process offers a means to better understand and evaluate the application of surfactants in naturally fractured reservoirs. This goal has been accomplished by taking advantage of an existing simulator, UTCHEM. UTCHEM is a 3D, multicomponent, multiphase, compositional, finite-difference simulator. Dual porosity modeling has been implemented in UTCHEM to accommodate simulation of naturally fractured reservoirs. This implementation is accomplished by adding source/sink terms to the fracture network equations to account for the matrix/fracture flow transfer for each matrix gridblock. The matrix blocks are discretized into subgrids to offer better transient flow description. The matrix-block equations are further decoupled from the fracture equations to minimize coding. In addition to the capability of handling surfactant applications in naturally fractured reservoirs, the simulator has many other applications. Tracer studies and the use of tracers in characterization of naturally fractured reservoirs, the use of polymers and the feasibility of such use in waterflooding of naturally fractured reservoirs, and the use of biodegradation processes in oil-spill cleanup are a few of the features available. The simulator has been verified against an analytical solution to a single phase, single-fracture tracer diffusion problem. The solution of a quarter-five-spot waterflood problem using ECLIPSE, a commercial reservoir simulator, has also been compared with the solution using UTCHEM to the same problem. Finally, the simulator has been used to study the effects of the use of polymers and surfactants to improve oil recovery.
An Investigation of Countercurrent Imbibition Recovery in Naturally Fractured Reservoirs With Experimental Analysis and Analytical Modeling
(1997-12) Cil, Murat; Miller, Mark A; Reis, John C
Naturally fractured reservoirs occur worldwide containing potentially economic and strategic fluids such as gas, oil and water. Modeling of naturally fractured reservoirs has advanced considerably because of the desire to increase the recovery from naturally fractured oil reservoirs and to exploit the vast storage capacity of naturally fractured formations for underground disposal of nuclear wastes. Countercurrent expulsion of oil from matrix blocks to the surrounding fractures by capillary imbibition of water is one of the more important fluid flow mechanisms in naturally fractured reservoirs. Transfer functions are essential for dual porosity simulators to characterize the countercurrent fluid flow between matrix blocks and surrounding fractures. The primary objectives of this study are: 1) to conduct experimental studies with single matrix blocks to better understand the general characteristics of countercurrent imbibition, and 2) to develop a comprehensive analytical matrix/fracture transfer function. New experimental methods for cleaning laboratory cores, establishing initial water saturation in odd shaped rocks and obtaining a transparent epoxy seal on core pieces to observe imbibition fronts have been developed to examine the general characteristics of countercurrent imbibition in single matrix blocks. A new analytical model (matrix/fracture transfer function) capable of modeling 1D, 2D and 3D countercurrent imbibition flow inside single matrix blocks has been derived. Imbibition characteristics are identified by analyzing the results of experimental data. The examined characteristics are: 1) types of imbibition and recovery trends, 2) flux and transition time, 3) imbibition front and average saturation, 4) effect of core size and shape, 5) effect of temperature, 6) effect of initial water saturation, 7) reproducibility, and 8) long term recovery. Based on the identified characteristics, solution proce~ures are developed to use with the new analytical model for recovery predictions. Results indicate that some imbibition parameters stay the same regardless of the geometry of the matrix block and imbibition type. The concept of an equivalent dimensionless distance is shown to reduce the number solution steps by combining the two periods of countercurrent imbibition under one set of equations. This greatly simplifies the analyses of countercurrent imbibition recovery with the new model. An apparent relative permeability concept shows that relative permeabilities are independent of temperature, and the change of imbibition with temperature is primarily due to the change of fluid viscosity and interfacial tension. The results in this study can easily be incorporated into a dual porosity simulator for multiphase fluid flow in naturally fractured reservoirs.
Modeling chemical EOR processes using IMPEC and fully IMPLICIT reservoir simulators
(2009-08) Fathi Najafabadi, Nariman; Delshad, Mojdeh; Sepehrnoori, Kamy, 1951-
As easy target reservoirs are depleted around the world, the need for intelligent enhanced oil recovery (EOR) methods increases. The first part of this work is focused on modeling aspects of novel chemical EOR methods for naturally fractured reservoirs (NFR) involving wettability modification towards more water wet conditions. The wettability of preferentially oil wet carbonates can be modified to more water wet conditions using alkali and/or surfactant solutions. This helps the oil production by increasing the rate of spontaneous imbibition of water from fractures into the matrix. This novel method cannot be successfully implemented in the field unless all of the mechanisms involved in this process are fully understood. A wettability alteration model is developed and implemented in the chemical flooding simulator, UTCHEM. A combination of laboratory experimental results and modeling is then used to understand the mechanisms involved in this process and their relative importance. The second part of this work is focused on modeling surfactant/polymer floods using a fully implicit scheme. A fully implicit chemical flooding module with comprehensive oil/brine/surfactant phase behavior is developed and implemented in general purpose adaptive simulator, GPAS. GPAS is a fully implicit, parallel EOS compositional reservoir simulator developed at The University of Texas at Austin. The developed chemical flooding module is then validated against UTCHEM.
New Dual Porosity Thermal Simulator for Steam Injection in Naturally Fractured Reservoirs
(1997-05) Liang, Zhiyue; Miller, Mark A; Sepehrnoori, Kamy
A distinguishing characteristic of naturally fractured reservoirs is that fractures have high permeability with very small pore volume while the matrix blocks between fractures have low permeability with large pore volume. Because of the extreme differences in properties between the two media, fluids tend to channel through fractures to production wells, leaving much oil behind in relatively low-permeability matrix blocks, typically resulting in very low oil recoveries. One method proposed to increase recovery from naturally fractured reservoirs is steam injection. Heat transfer, imbibition, gas generation, and other mechanisms have the potential to expel fluids from matrix blocks at sufficient rates and in sufficient quantities to be feasible. The objective of this study is to develop an accurate 3D three-phase dual porosity thermal simulator to study steam injection processes in naturally fractured reservoirs. A new dual porosity thermal simulator, UTDUTHM, has been developed for modeling steamflooding in naturally fractured reservoirs. An implicit algorithm is used to solve the equations for the combined fracture/matrix system. The new simulator can model reservoirs with vertical fractures, horizontal fractures and their combination by appropriate subgridding of matrix blocks. The new simulator can also handle gas generation in the matrix, a capability not found in other simulators. A new set of correlating equations for saturated steam/water properties has also been developed for inclusion in the simulator. These correlations are better than those previously reported in terms of accuracy, continuity, range of applicability, and simplicity. The new simulator is verified by test runs against a commercial simulator, STARS, and a research simulator, UTDUAL. Excellent agreement is achieved. The procedure for implementing a dual porosity model was also implemented into UTCHEM, a chemical flooding simulator developed at The University of Texas at Austin. This implementation shows that the method can easily extend an existing single porosity simulator to a dual porosity simulator with very few changes to the existing code.
Optimization of chemical enhanced oil recovery methods for naturally fractured carbonate reservoirs
(2022-02-24) Mejia, Miguel, M.S. in Engineering; Pope, G. A.; Balhoff, Matthew T.; Mohanty, Kishore K; Johnston, Keith P; Pyrcz, Michael J
Carbonate oil reservoirs are important energy sources, accounting for over 60% of the world’s oil reserves. Recovering oil from these reservoirs is challenging, especially if they are naturally fractured. Waterflooding is inefficient because water flows through the highly permeable fractures and bypasses the rock matrix, where most of the oil is stored. Mixed-wettability, low matrix permeability, and large heterogeneities also make secondary oil recovery challenging. Chemical enhanced oil recovery with alkali, surfactants, and polymer addresses some of these challenges. Surfactants can lower the interfacial tension to decrease the residual oil saturation. Polymer increases the viscosity of the injected water, improving the microscopic and macroscopic sweep efficiency. This research involves the optimization of some chemical flooding methods for naturally fractured carbonates. Coreflood experiments and the UTCHEM reservoir simulator were used to investigate alkali-surfactant flooding in fractured Texas Cream limestone cores. A decrease in fracture mobility caused by viscous phase trapping in the fracture was identified as the main reason for the high observed oil recoveries. Due to the uncertain properties of the viscous phase trapped in the fracture, polyethylene oxide (PEO) polymer was investigated for mobility control. Coreflood experiments demonstrated the viability for using PEO in 18 mD cores. PEO significantly improved oil recovery in a fractured core. The viscosity and cloud point of the PEO were systematically investigated. The polymer concentration, temperature, salinity and hardness were varied, and several additives were added to potentially increase the range of conditions for which PEO could be applied to EOR. Methyl-urea, urea, and ethanol were identified as additives to increase the cloud point and viscosity of PEO. Finally, machine learning models including support vector machine, random forest, and neural network models were trained to predict the aqueous stability of surfactant solutions and phase behavior of microemulsions. A large database of over 600 phase behavior experiments and over 800 aqueous stability experiments was used to train the models. The models may be used to guide the process of selection of surfactants that produce sufficiently high solubilization ratios.
Simulation of Interwell Gas Tracer Test in Naturally Fractured Reservoirs
(2005-08) Gholamreza, Garmeh; Pope, Gary A.; Sepehrnoori, Kamy
The main objective of this research was to investigate the gas tracer test in naturally fractured reservoirs and compare the dual porosity and discrete fracture models for the gas tracer test. The method of moments was used to estimate the average oil saturation and swept pore volume in naturally fractured reservoir gas tracer tests. It was used to estimate mobile oil saturation for a case of uniform residual oil saturation in the matrix and fracture, and for a case of different residual oil saturation in the matrix and fracture from total concentration of the produced tracer. Results verify that the method of moments is a fast, simple, and accurate method of estimating the oil saturation in fractured reservoirs. The gas tracer test in naturally fractured reservoirs was simulated for the dual porosity and discrete fracture models and results were compared. Results of the ECLIPSE simulator were compared with the IMEX simulator for the dual porosity and discrete fracture models. The comparison demonstrates that the discrete facture model has properties of the dual porosity model and the reality of a fractured reservoir. In addition, the effect of dimensionless groups in the dual porosity and discrete fracture models were studied. The effect of dimensionless parameters in the fracture tracer transport was analyzed and the equilibrium condition of the gas tracer's transport between the matrix and fracture was obtained.