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1
LIMA, BIANCA FERNANDES. "NATURALLY FRACTURED RESERVOIRS SIMULATION." PONTIFÍCIA UNIVERSIDADE CATÓLICA DO RIO DE JANEIRO, 2013. http://www.maxwell.vrac.puc-rio.br/Busca_etds.php?strSecao=resultado&nrSeq=34826@1.
Full textAbstract:
PONTIFÍCIA UNIVERSIDADE CATÓLICA DO RIO DE JANEIROCONSELHO NACIONAL DE DESENVOLVIMENTO CIENTÍFICO E TECNOLÓGICO
A presença de fraturas naturais em reservatórios de petróleo pode gerar grandes impactos no deslocamento de fluidos em seu interior. Os maiores problemas estão na irregularidade da área varrida pelo fluido injetado, por exemplo, a água, e a antecipação dos breakthroughs, ou seja, a chegada precoce da água aos poços produtores. De modo a analisar o efeito promovido pela presença de fraturas no meio, foram simulados os dois modelos de simulação de fluxo em reservatórios fraturados: o modelo de dupla-porosidade (DP) e o modelo de dupla-porosidade e dupla-permeabilidade (DPDK), bem como outros dois modelos derivados do modelo DP, o modelo de Subdomínios (SD) e o modelo MINC (Multiple Interacting Continua). Também foram realizadas análises paramétricas para compreender o impacto de propriedades, como as permeabilidades tanto da matriz quanto da fratura e o espaçamento das fraturas, no comportamento do fluxo em reservatórios fraturados. A presença de corredores de fraturas (fracture swarms) foi, igualmente, avaliada, assim como seu efeito associado à presença de camadas de altíssima permeabilidade (super-K). Por fim, foi simulado um modelo mais complexo, denominado GTEP, o qual foi construído a partir de uma seção aplicada à simulação de um reservatório carbonático gigante do Oriente Médio, com o intuito de exemplificar a irregularidade da área varrida em reservatórios naturalmente fraturados.
The presence of natural fractures in oil reservoirs can generate major impacts on the fluid displacement inside them. The greatest problems are irregularity in the area swept by the injected fluid, e.g. water, and breakthroughs anticipation, or early arrival of water to the producing wells. In order to analyze the effect of the presence of fractures in the medium, two flow models of fractured reservoirs were constructed: the dual-porosity model (DP) and the dual-porosity and dual permeability model (DPDK), as well as two other models derived from the DP model, Subdomains model (SD) and MINC model (Multiple Interacting Continua). Parametric analyzes were also conducted to comprehend the impact of properties, such as the matrix permeability, the fracture permeability and the fracture spacing, on the flow behavior in fractured reservoirs. The presence of fracture corridors (fracture swarms) was also evaluated in three models, as well as its effect associated with the presence of layers of high permeability, denoted super-K. Finally, a more complex model, called GTEP Field, was simulated, which was constructed from a section applied to the simulation of a giant carbonate reservoir in the Middle East, in order to illustrate the irregularity of the swept area in natural fractured reservoirs.
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Tran, Nam Hong Petroleum Engineering Faculty of Engineering UNSW. "Characterisation and modelling of naturally fractured reservoirs." Awarded by:University of New South Wales. Petroleum Engineering, 2004. http://handle.unsw.edu.au/1959.4/20559.
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Naturally fractured reservoirs are generally extremely complex. The aim of characterisation and modelling of such reservoirs is to construct numerical models of rock and fractures, preparing input data for reliable stimulation and fluid flow simulation analyses. This requires the knowledge of different fracture heterogeneities and their correlations at well locations and inter-well regions. This study addresses the issues of how to integrate different information from various field data sources and construct comprehensive discrete fracture networks for naturally fractured reservoir. The methodology combines several mathematical and artificial intelligent techniques, which include statistics, geostatistics, fuzzy neural network, stochastic simulation and simulated annealing global optimisation. The study has contributed to knowledge in characterisation and modelling of naturally fractured reservoirs in several ways. It has developed: .An effective and data-dependant fracture characterisation procedure. It examines all the conventional reservoir data sources and their roles towards characterisation of different fracture properties. The procedure has the advantage of being both comprehensive and flexible. It is able to integrate all multi-scaled and diverse fracture information from the different data sources. .An improved hybrid stochastic generation algorithm for modelling discrete fracture networks. The stochastic simulation is able to utilise both discrete and continuum fracture information. It could simulate not only complicated distributions for fracture properties (e.g. multimodal circular statistics and non-parametric distributions) but also their correlations. In addition, with the incorporation of artificial fuzzy neural simulation, discrete multifractal geometry of fracture size and fracture density distribution map could be evaluated and modelled. Compared to most of the previous fracture modelling approach, this model is more flexible and comprehensive. .An improved conditional global optimisation model for modelling discrete fracture networks. The hybrid model takes full advantages of the advanced fracture characterisation using geostatistical and fuzzy neural analyses. Discrete fractures are treated individually and yet continuum information could be modelled. Compared to the stochastic simulation approach, this model produces more representative fracture networks. Compared to the conventional optimisation programs, this model is more versatile and contains superior objective function.
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Sobbi, Farhad Aschar. "Well testing of naturally fractured reservoirs." Thesis, Heriot-Watt University, 1988. http://hdl.handle.net/10399/1481.
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CAMIZA, DANILLO DURAN. "SECONDARY RECOVERY IN NATURALLY FRACTURED RESERVOIRS." PONTIFÍCIA UNIVERSIDADE CATÓLICA DO RIO DE JANEIRO, 2015. http://www.maxwell.vrac.puc-rio.br/Busca_etds.php?strSecao=resultado&nrSeq=26967@1.
Full textAbstract:
Todos os reservatórios de petróleo apresentam algum grau de fraturamento.
Muitas vezes, a presença de fraturas afeta de forma significativa o fluxo dos fluidos
nele contidos, seja por incrementarem a permeabilidade do meio, criando caminhos
preferenciais de escoamento, seja por imporem algum tipo de barreira ao fluxo.
Quando submetidos à injeção de água, reservatórios naturalmente fraturados podem
apresentar graves problemas de produção prematura de água e baixíssimas
eficiências de varrido. Os estudos realizados neste trabalho procuraram contribuir
para o melhor entendimento dos processos de recuperação envolvidos na produção
de reservatórios fraturados, bem como o impacto de cada um dos principais
parâmetros que condicionam o fluxo no meio poroso fraturado. Foi realizada, ainda,
uma análise de possíveis estratégias de drenagem para esse tipo de reservatório. Por
fim, foram realizadas simulações para estudar possíveis ganhos da injeção de
emulsão de óleo em água, como método de recuperação, em comparação com a
injeção de água.All oil reservoirs have some degree of fracturing. Often, the presence of fractures affects significantly the flow of the fluids contained in the reservoir, increasing the permeability and creating preferential flow paths or by imposing some barrier to the flow. When subjected to waterflooding, naturally fractured reservoirs may have serious problems like early production of water or very low swept efficiencies. The analyses conducted in this study contemplated the understanding of recovery processes involved in the production of fractured reservoirs and the impact of each of the main parameters that influence the flow in fractured porous media. Also, an analysis of possible draining strategies for this type of reservoir was performed. Finally, simulations were performed to study the possible gains of emulsion injection, as a recovery method, compared with water injection.
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Al, Harbi Mishal H. "Streamline-based production data integration in naturally fractured reservoirs." Texas A&M University, 2003. http://hdl.handle.net/1969.1/2445.
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Streamline-based models have shown great potential in reconciling high resolution
geologic models to production data. In this work we extend the streamline-based
production data integration technique to naturally fractured reservoirs. We use a dualporosity
streamline model for fracture flow simulation by treating the fracture and matrix
as separate continua that are connected through a transfer function. Next, we analytically
compute the sensitivities that define the relationship between the reservoir properties and
the production response in fractured reservoirs. Finally, production data integration is
carried out via the Generalized Travel Time inversion (GTT). We also apply the
streamline-derived sensitivities in conjunction with a dual porosity finite difference
simulator to combine the efficiency of the streamline approach with the versatility of the
finite difference approach. This significantly broadens the applicability of the streamlinebased
approach in terms of incorporating compressibility effects and complex physics.
The number of reservoir parameters to be estimated is commonly orders of magnitude
larger than the observation data, leading to non-uniqueness and uncertainty in reservoir
parameter estimate. Such uncertainty is passed to reservoir response forecast which needs
to be quantified in economic and operational risk analysis. In this work we sample
parameter uncertainty using a new two-stage Markov Chain Monte Carlo (MCMC) that is
very fast and overcomes much of its current limitations. The computational efficiency
comes through a substantial increase in the acceptance rate during MCMC by using a fast
linearized approximation to the flow simulation and the likelihood function, the critical
link between the reservoir model and production data.
The Gradual Deformation Method (GDM) provides a useful framework to preserve
geologic structure. Current dynamic data integration methods using GDM are inefficient
due to the use of numerical sensitivity calculations which limits the method to deforming
two or three models at a time. In this work, we derived streamline-based analytical
sensitivities for the GDM that can be obtained from a single simulation run for any
number of basis models. The new Generalized Travel Time GDM (GTT-GDM) is highly
efficient and achieved a performance close to regular GTT inversion while preserving the
geologic structure.
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Huapaya, Lopez Christian A. "The imbibition process of waterflooding in naturally fractured reservoirs." Texas A&M University, 2003. http://hdl.handle.net/1969.1/1632.
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This thesis presents procedures to properly simulate naturally fractured reservoirs using dual-porosity models.
The main objectives of this work are to: (1) determine if the spontaneous imbibition can be simulated using a two phase CMG simulator and validate it with laboratory experiments in the literature; (2) study the effect of countercurrent imbibition in field scale applications; and (3) develop procedures for using the dual-porosity to simulate fluid displacement in a naturally fractured reservoir.
Reservoir simulation techniques, analytical solutions and numerical simulation for a two phase single and dual-porosity are used to achieve our objectives.
Analysis of a single matrix block with an injector and a producer well connected by a single fracture is analyzed and compared with both two phase single and dual-porosity models.
Procedures for obtaining reliable results when modeling a naturally fractured reservoir with a two phase dual-porosity model are presented and analyzed.
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Tellapaneni, Prasanna Kumar. "Simulation of naturally fractured reservoirs using empirical transfer function." Thesis, Texas A&M University, 2003. http://hdl.handle.net/1969.1/248.
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This research utilizes the imbibition experiments and X-ray tomography results for modeling fluid flow in naturally fractured reservoirs. Conventional dual porosity simulation requires large number of runs to quantify transfer function parameters for history matching purposes. In this study empirical transfer functions (ETF) are derived from imbibition experiments and this allows reduction in the uncertainness in modeling of transfer of fluids from the matrix to the fracture. The application of the ETF approach is applied in two phases. In the first phase, imbibition experiments are numerically solved using the diffusivity equation with different boundary conditions. Usually only the oil recovery in imbibition experiments is matched. But with the advent of X-ray CT, the spatial variation of the saturation can also be computed. The matching of this variation can lead to accurate reservoir characterization. In the second phase, the imbibition derived empirical transfer functions are used in developing a dual porosity reservoir simulator. The results from this study are compared with published results. The study reveals the impact of uncertainty in the transfer function parameters on the flow performance and reduces the computations to obtain transfer function required for dual porosity simulation.
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Rojas, Paico Danny Hubert. "A new procedure for history matching naturally fractured reservoirs /." May be available electronically:, 2008. http://proquest.umi.com/login?COPT=REJTPTU1MTUmSU5UPTAmVkVSPTI=&clientId=12498.
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Shaik, Abdul Ravoof Petroleum Engineering Faculty of Engineering UNSW. "Simulation of stress dependent fluid flow in naturally fractured reservoirs." Publisher:University of New South Wales. Petroleum Engineering, 2008. http://handle.unsw.edu.au/1959.4/43266.
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Naturally fractured reservoirs represent significant portion of the world's oil and gas reserves. In most of the reservoirs, fractures are important contributors to fluid flow. Thus, modeling and simulation of discrete fracture network is essential to assess responses of the reservoirs under stimulation pressure, develop the best hydraulic fracture treatments, carry out feasibility studies, design optimum production methods and improve reservoir potentials. It is also a very complicated process. Natural fractures are by nature highly heterogeneous with different size, orientation and spatial distribution. The complexity is further raised, taking into account the role of matrix, the flow interaction between matrix and fractures, the effect of production-induced stress on fluid flow. Previous works fail to balance sufficient geological complexity and excessive needs of high computational resources. This thesis presents an innovative procedure to simulate stress-dependent fluid flow through discrete fracture network. Three numerical models (tensor, flow and deformation) are developed and coupled iteratively for this purpose. - A tensor model calculates grid based permeability tensor from discrete fracture network model, which includes individual fracture properties such as spatial distribution, length, location and orientation. The tensor model accounts for fluid flow from the matrix to matrix and matrix to fracture. It also includes flow through connected and disconnected fractures. - An unsteady state simulation model investigates fluid flow through the fracture system and gives pressure profile, velocity profile as output. - A dual continuum deformation model studies the reservoir rock deformation and its effects on fluid flow. The geo-mechanic solution is decomposed into matrix and fracture parts that allow calculation of dynamic porosity and permeability separately. The proposed work procedure has been validated to match nicely with analytical results. Furthermore, several case study scenarios are carried out to illustrate how it could help evaluate different aspects of reservoir performance including fracture connectivity, rock deformation, well injectivity and productivity, recovery and even distribution of fluid inside reservoir as a result of rock deformation. The case studies have proven the method to be very efficient in terms computational resources. It also eliminates most of the limitations in the previous models such as handling fracture connectivity, permeability anisotropy and change in effective stress.
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Ahmed, Elfeel Mohamed. "Improved upscaling and reservoir simulation of enhanced oil recovery processes in naturally fractured reservoirs." Thesis, Heriot-Watt University, 2014. http://hdl.handle.net/10399/2755.
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Naturally fractured reservoirs (NFR) contain a significant amount of remaining petroleum reserves and are now considered for Enhanced Oil Recovery (EOR) schemes that involve three-phase flow such as water-alternating-gas (WAG) injection. Accurate numerical simulation of flow in NFR is essential for sound reservoir management decisions to maximise oil recovery and minimise the cost of field development. In this thesis, two important issues related to flow simulation in NFR are investigated. First, a step-wise upscaling approach is developed to evaluate the accuracy of dual porosity models in estimating matrix-fracture transfer duringWAG injection. It was found that the classical dual porosity models generally overestimate recovery from matrix blocks. Hence, a double block model was developed and extended to a multi-rate dual porosity (MRDP). The multi-rate double block model showed significant improvements in matching detailed fine grid simulations of three-phase matrix-fracture transfer. Second, the accuracy of upscaling discrete fracture networks (DFN) is assessed and its impact on history matching was investigated on a real fractured reservoir. A new method to upscale the shape factors needed for MRDP models from DFN is presented. This method is a notable step towards more accurate but still efficient reservoir simulation in NFR.
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Al-Huthali, Ahmed. "Streamline-based simulation of water injection in naturally fractured reservoirs." Texas A&M University, 2003. http://hdl.handle.net/1969.1/410.
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The current streamline formulation is limited to single-porosity systems and is then not suitable for application to naturally fractured reservoirs. Describing the fluid transport in naturally fractured reservoirs has been recognized as a main challenge for simulation engineers due to the complicated physics involved.
In this work, we generalized the streamline-based simulation to describe the fluid transport in naturally fractured reservoirs. We implemented three types of transfer function: the conventional transfer function (CTF), the diffusion transfer function (DTF), and the empirical transfer function (ETF). We showed that these transfer functions can be implemented easily in the current single-porosity streamline codes. These transfer functions have been added as a source term to the transport equation that describes the saturation evolution along the streamlines. We solved this equation numerically for all types of transfer functions. The numerical solution of the continuity equation with DTF and ETF requires discretizing a convolution term. We derived an analytical solution to the saturation equation with ETF in terms of streamline TOF to validate the numerical solution. We obtain an excellent match between the numerical and the analytical solution.
The final stage of our study was to validate our work by comparing our dual-porosity streamline simulator (DPSS) to the commercial dual-porosity simulator, ECLIPSE. The dual-porosity ECLIPSE uses the CTF to describe the interaction between the matrix-blocks and the fracture system. The dual-porosity streamline simulator with CTF showed an excellent match with the dual-porosity ECLIPSE. On the other hand, dual-porosity streamline simulation with DTF and ETF showed a lower recovery than the recovery obtained from the dual-porosity ECLIPSE and the DPSS with CTF. This difference in oil recovery is not due to our formulation, but is related to the theoretical basis on which CTF, DTF, and ETF were derived in the literature. It was beyond the scope of this study to investigate the relative accuracy of each transfer function.
We demonstrate that the DPSS is computationally efficient and ideal for large-scale field application. Also, we showed that the DPSS minimizes numerical smearing and grid orientation effects compared to the dual-porosity ECLIPSE.
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Christoffersen, Kjell R. "High-pressure experiments with application to naturally fractured chalk reservoirs." Doctoral thesis, Norges teknisk-naturvitenskapelige universitet, Institutt for petroleumsteknologi og anvendt geofysikk, 1992. http://urn.kb.se/resolve?urn=urn:nbn:no:ntnu:diva-5290.
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Perez, Garcia Laura Elena. "Integration of well test analysis into naturally fractured reservoir simulation." Texas A&M University, 2005. http://hdl.handle.net/1969.1/3337.
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Naturally fractured reservoirs (NFR) represent an important percentage of the worldwide
hydrocarbon reserves and production. Reservoir simulation is a fundamental technique
in characterizing this type of reservoir. Fracture properties are often not available due to
difficulty to characterize the fracture system.
On the other hand, well test analysis is a well known and widely applied reservoir
characterization technique. Well testing in NFR provides two characteristic parameters,
storativity ratio and interporosity flow coefficient. The storativity ratio is related to
fracture porosity. The interporosity flow coefficient can be linked to shape factor, which
is a function of fracture spacing.
The purpose of this work is to investigate the feasibility of estimating fracture porosity
and fracture spacing from single well test analysis and to evaluate the use of these two
parameters in dual porosity simulation models.
The following assumptions were considered for this research: 1) fracture
compressibility is equal to matrix compressibility; 2) no wellbore storage and skin
effects are present; 3) pressure response is in pseudo-steady state; and 4) there is single
phase flow. Various simulation models were run and build up pressure data from a producer well
was extracted. Well test analysis was performed and the result was compared to the
simulation input data.
The results indicate that the storativity ratio provides a good estimation of the magnitude
of fracture porosity. The interporosity flow coefficient also provides a reasonable
estimate of the magnitude of the shape factor, assuming that matrix permeability is a
known parameter. In addition, pressure tests must exhibit all three flow regimes that
characterizes pressure response in NFR in order to obtain reliable estimations of fracture
porosity and shape factor.
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Bhatia, Kanwaljit S. "Finite element analysis of two phase fluid flow in naturally fractured reservoirs /." The Ohio State University, 1989. http://rave.ohiolink.edu/etdc/view?acc_num=osu1487673114112577.
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Teimoori, Sangani Ahmad Petroleum Engineering Faculty of Engineering UNSW. "Calculation of the effective permeability and simulation of fluid flow in naturally fractured reservoirs." Awarded by:University of New South Wales. School of Petroleum Engineering, 2005. http://handle.unsw.edu.au/1959.4/22408.
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This thesis is aimed to calculate the effective permeability tensor and to simulate the fluid flow in naturally fractured reservoirs. This requires an understanding of the mechanisms of fluid flow in naturally fractured reservoirs and the detailed properties of individual fractures and matrix porous media. This study has been carried out to address the issues and difficulties faced by previous methods; to establish possible answers to minimise the difficulties; and hence, to improve the efficiency of reservoir simulation through the use of properties of individual fractures. The methodology used in this study combines several mathematical and numerical techniques like the boundary element method, periodic boundary conditions, and the control volume mixed finite element method. This study has contributed to knowledge in the calculation of the effective permeability and simulation of fluid flow in naturally fractured reservoirs through the development of two algorithms. The first algorithm calculates the effective permeability tensor by use of properties of arbitrary oriented fractures (location, size and orientation). It includes all multi-scaled fractures and considers the appropriate method of analysis for each type of fracture (short, medium and long). In this study a characterisation module which provides the detail information for individual fractures is incorporated. The effective permeability algorithm accounts for fluid flows in the matrix, between the matrix and the fracture and disconnected fractures on effective permeability. It also accounts for the properties of individual fractures in calculation of the effective permeability tensor. The second algorithm simulates flow of single-phase fluid in naturally fractured reservoirs by use of the effective permeability tensor. This algorithm takes full advantage of the control volume discretisation technique and the mixed finite element method in calculation of pressure and fluid flow velocity in each grid block. It accounts for the continuity of flux between the neighbouring blocks and has the advantage of calculation of fluid velocity and pressure, directly from a system of first order equations (Darcy???s law and conservation of mass???s law). The application of the effective permeability tensor in the second algorithm allows us the simulation of fluid flow in naturally fractured reservoirs with large number of multi-scale fractures. The fluid pressure and velocity distributions obtained from this study are important and can considered for further studies in hydraulic fracturing and production optimization of NFRs.
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Kim, Tae Hyung. "Fracture characterization and estimation of fracture porosity of naturally fractured reservoirs with no matrix porosity using stochastic fractal models." [College Station, Tex. : Texas A&M University, 2007. http://hdl.handle.net/1969.1/ETD-TAMU-2570.
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Huls, Boyd T. "A feasibility study on modeling and prediction of production behavior in naturally fractured shale reservoirs." Morgantown, W. Va. : [West Virginia University Libraries], 2004. https://etd.wvu.edu/etd/controller.jsp?moduleName=documentdata&jsp%5FetdId=3726.
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Thesis (M.S.)--West Virginia University, 2004.Title from document title page. Document formatted into pages; contains viii, 105 p. : ill. (some col.), map. Includes abstract. Includes bibliographical references (p. 96-97).
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Maier, Christine. "Improved simulation of naturally fractured reservoirs using unstructured grids and multi-rate dual-porosity models." Thesis, Heriot-Watt University, 2014. http://hdl.handle.net/10399/2956.
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Naturally Fractured Reservoirs (NFR) hold about half of the world’s remaining oil reserves and are typically very heterogeneous. NFR are also important for many other subsurface engineering applications including (nuclear) waste storage, CO2 sequestration, groundwater aquifers, and geothermal energy extraction. They contain faults, fracture corridors, large fractures but also many small-scale fractures as well as a heterogeneous rock matrix. Multi-phase flow in NFR is strongly influenced by this multi-scale heterogeneity. Therefore, accurate conceptual models that reliably quantify fluid flow in NFR are needed. In this thesis, three important contributions are made towards an improved simulation of multi-phase flow processes in NFR. First, the Implicit Pressure Implicit Saturation (IMPIS) method using unstructured grids was implemented to numerically simulate two-phase flow in a Discrete Fracture and Matrix (DFM) model. Second, a Multi-Rate Dual-Porosity (MRDP) model was developed including fracture-matrix transfer functions that are based on analytical solutions for spontaneous imbibition and gravity drainage. Finally, the two approaches were combined to a DFM-MRDP model. This model represents the multi-scale heterogeneity inherent to NFR more accurately by resolving fluid-flow processes in large-scale fractures directly using the DFM model while accounting for complex matrix heterogeneities when modelling fluid exchange between small-scale fractures and rock matrix using the MRDP model.
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Will, Robert A. "The integration of seismic anisotropy and reservoir performance data for characterization of naturally fractured reservoirs using discrete feature network models." Texas A&M University, 2004. http://hdl.handle.net/1969.1/542.
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This dissertation presents the development of a method for quantitative integration of seismic (elastic) anisotropy attributes with reservoir performance data as an aid in characterization of systems of natural fractures in hydrocarbon reservoirs. This new method incorporates stochastic Discrete Feature Network (DFN) fracture modeling techniques, DFN model based fracture system hydraulic property and elastic anisotropy modeling, and non-linear inversion techniques, to achieve numerical integration of production data and seismic attributes for iterative refinement of initial trend and fracture intensity estimates. Although DFN modeling, flow simulation, and elastic anisotropy modeling are in themselves not new technologies, this dissertation represents the first known attempt to integrate advanced models for production performance and elastic anisotropy in fractured reservoirs using a rigorous mathematical inversion. The following new developments are presented:
. • Forward modeling and sensitivity analysis of the upscaled hydraulic properties of realistic DFN fracture models through use of effective permeability modeling techniques.
. • Forward modeling and sensitivity analysis of azimuthally variant seismic attributes based on the same DFN models.
. • Development of a combined production and seismic data objective function and computation of sensitivity coefficients.
. • Iterative model-based non-linear inversion of DFN fracture model trend and intensity through minimization of the combined objective function.
This new technique is demonstrated on synthetic models with single and multiple fracture sets as well as differing background (host) reservoir hydraulic and elastic properties. Results on these synthetic control models show that, given a well conditioned initial DFN model and good quality field production and seismic observations, the integration procedure results in convergence of both fracture trend and intensity in models with both single and multiple fracture sets. Tests show that for a single fracture set convergence is accelerated when the combined objective function is used as compared to a similar technique using only production data in the objective function. Tests performed on multiple fracture sets show that, without the addition of seismic anisotropy, the model fails to converge. These tests validate the importance of the new process for use in more realistic reservoir models.
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Al, Ghamdi Bander Nasser Ayala H. Luis Felipe. "Analysis of capillary pressure and relative permeability effects on the productivity of naturally fractured gas-condensate reservoirs using compositional simulation." [University Park, Pa.] : Pennsylvania State University, 2009. http://etda.libraries.psu.edu/theses/approved/WorldWideIndex/ETD-4622/index.html.
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Kaul, Sandeep P. "Numerical simulation of two-phase flow in discrete fractures using Rayleigh-Ritz finite element method." Thesis, Texas A&M University, 2003. http://hdl.handle.net/1969.1/373.
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Spontaneous imbibition plays a very important role in the displacement mechanism of non-wetting fluid in naturally fractured reservoirs. We developed a new 2D two-phase finite element numerical model, as available commercial simulators cannot be used to model small-scale experiments with different boundary conditions as well as complex boundary conditions such as fractures and vugs. Starting with the basic equation of fluid flow, we derived the non-linear diffusion saturation equation. This equation cannot be put in weighted-integral weak variational form and hence Rayleigh-Ritz finite element method (FEM) cannot be applied. Traditionally, the way around it is to use higher order interpolation functions and use Galerkin FEM or reduce the differentiability requirement and use Mixed FEM formulation. Other FEM methods can also be used, but iterative nature of those methods makes them unsuitable for solving large-scale field problems. But if we truncate the non-linear terms and decouple the dependent variables, from the spatial as well as the temporal domains of the primary variable to solve them analytically, the non-linear FEM problem reduces to a simple weighted integral form, which can be put into its corresponding weak form. The advantage of using Rayleigh-Ritz method is that it has immediate effect on the computation time required to solve a particular problem apart from incorporating complex boundary conditions. We compared our numerical models with the analytical solution of this diffusion equation. We validated the FDM numerical model using X-Ray Tomography (CT) experimental data from the single-phase spontaneous imbibition experiment, where two simultaneously varying parameters of weight gain and CT water saturation were used and then went ahead and compared the results of FEM model to that of FDM model. A two-phase field size example was taken and results from a commercial simulator were compared to the FEM model to bring out the limitations of this approach.
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Ericok, Ozlen. "Uncertainty Assessment In Reserv Estimation Of A Naturally Fractured Reservoir." Master's thesis, METU, 2004. http://etd.lib.metu.edu.tr/upload/2/12605713/index.pdf.
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ABSTRACT
UNCERTAINTY ASSESSMENT IN RESERVE ESTIMATION OF
A NATURALLY FRACTURED RESERVOIR
ERIÇOK, Ö
zlen M.S., Department of Petroleum and Natural Gas Engineering Supervisor : Prof. Dr. Fevzi GÜ
MRAH December 2004, 169 pages Reservoir performance prediction and reserve estimation depend on various petrophysical parameters which have uncertainties due to available technology. For a proper and economical field development, these parameters must be determined by taking into consideration their uncertainty level and probable data ranges. For implementing uncertainty assessment on estimation of original oil in place (OOIP) of a field, a naturally fractured carbonate field, Field-A, is chosen to work with. Since field information is obtained by drilling and testing wells throughout the field, uncertainty in true ranges of reservoir parameters evolve due to impossibility of drilling every location on an area. This study is based on defining the probability distribution of uncertain variables in reserve estimation and evaluating probable reserve amount by using Monte Carlo simulation method. Probabilistic reserve estimation gives the whole range of probable v original oil in place amount of a field. The results are given by their likelyhood of occurance as P10, P50 and P90 reserves in summary. In the study, Field-A reserves at Southeast of Turkey are estimated by probabilistic methods for three producing zones
Karabogaz Formation, Kbb-C Member of Karababa formation and Derdere Formation. Probability density function of petrophysical parameters are evaluated as inputs in volumetric reserve estimation method and probable reserves are calculated by @Risk software program that is used for implementing Monte Carlo method. Outcomes of the simulation showed that Field-A has P50 reserves as 11.2 MMstb in matrix and 2.0 MMstb in fracture of Karabogaz Formation, 15.7 MMstb in matrix and 3.7 MMstb in fracture of Kbb-C Member and 10.6 MMstb in matrix and 1.6 MMstb in fracture of Derdere Formation. Sensitivity analysis of the inputs showed that matrix porosity, net thickness and fracture porosity are significant in Karabogaz Formation and Kbb-C Member reserve estimation while water saturation and fracture porosity are most significant in estimation of Derdere Formation reserves.
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Bui, Thang Dinh. "Neural network analysis of sparse datasets : an application to the fracture system in folds of the Lisburne Formation, northeastern Alaska /." Texas A&M University, 2004. http://handle.tamu.edu/1969.1/2593.
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Isemin, Isemin Akpabio. "Numerical Simulation of Gas Coning of a Single Well Radial in a Naturally Fractured Reservoir." Thesis, Norges teknisk-naturvitenskapelige universitet, Institutt for petroleumsteknologi og anvendt geofysikk, 2012. http://urn.kb.se/resolve?urn=urn:nbn:no:ntnu:diva-19275.
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Gas coning is the tendency of the gas to drive oil downward in an inverse cone due to the downward movement of gas into the perforations of a producing well thereby reducing oil production and the overall recovery efficiency of the oil reservoir. This work addresses gas coning issues in a naturally fractured reservoir via a numerical simulation approach on a single-well radial cross-section using the ECLIPSE 100 reservoir simulator. Matrix and fracture properties are modelled. Critical rate, breakthrough time and GOR after breakthrough is determined which is used to investigate the effect of matrix and fracture properties on gas coning effective reservoir parameters such as oil flow rate, matrix and fracture porosity, vertical and horizontal matrix and fracture permeability, matrix block size, etc. Results show that reservoir parameters that affect coning include oil flow rate, matrix and fracture porosity, matrix and vertical permeability, anisotropy ratio, perforated interval thickness, density difference and mobility ratio. While matrix block size and fracture spacing have no significant effect on gas coning.
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Abu-Hassoun, Amer H. "Simulation of fluid flow mechanisms in high permeability zones (Super-K) in a giant naturally fractured carbonate reservoir." Thesis, [College Station, Tex. : Texas A&M University, 2007. http://hdl.handle.net/1969.1/ETD-TAMU-1590.
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Fabbri, Heber Agnelo Antonel. "Modeling the effects of natural fractures on the permeability of reservoir rocks /." Bauru, 2019. http://hdl.handle.net/11449/190698.
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Orientador: Osvaldo Luís ManzoliAbstract: This work presents a numerical method based on Discrete Fracture Model (DFM) and the Finite Element Method (FEM), where the fractures are approximated by a reduced model. The flow along and across the fracture is described by a simplified set of equations considering both conductive fractures and barriers. The coupled hydromechanical model is composed of a linear poroelastic Biot medium and a nonlinear model based on damage mechanics for the fractures, which captures the nonlinear normal deformation and shear dilation according to the Barton-Bandis model. Both flow and geomechanical models are approximated using the finite element model. Fractures are explicitly represented by three-node standard finite elements with high aspect ratio (i.e. ratio between the largest and the smallest element dimensions) and appropriate constitutive laws. These interface high aspect ratio elements represent a regularization method which continuously approximate the discontinuous pressure and displacement fields on a narrow material band around the fracture. The complete mathematical formulation is presented together with the algorithm suggested for its numerical implementation. The efficiency of the proposed method is demonstrated through numerical examples, as well as the effects of fractures in the hydraulic properties of porous rocks and its dependency of the stress state.
Resumo: Este trabalho apresenta um método numérico baseado no Modelo de Fratura Discreta (MFD) e no Método dos Elementos Finitos (MEF), onde as fraturas são aproximadas por um modelo reduzido. O fluxo ao longo e através da fratura é descrito por um conjunto simplificado de equações, considerando tanto fraturas condutoras quanto barreiras. O modelo hidromecânico acoplado é composto por um meio poroelástico linear e um modelo não linear para fraturas, baseado na mecânica do dano e que captura a deformação normal não linear e a dilatância ao cisalhamento de acordo com o modelo de Barton-Bandis. Os modelos de fluxo e geomecânico são aproximados usando o método dos elementos finitos. As fraturas são explicitamente representadas por elementos finitos triangulares de três nós com elevada razão de aspecto (isto é, a razão entre a maior e a menor dimensão do elemento) e leis constitutivas apropriadas. Esses elementos de elevada razão de aspecto representam um método de regularização que aproxima de forma contínua os campos de pressão e deslocamento descontínuos em uma estreita faixa material ao redor da fratura. A formulação matemática completa é apresentada juntamente com o algoritmo sugerido para sua implementação numérica. A eficiência do método proposto é demonstrada através de exemplos numéricos, bem como os efeitos de fraturas nas propriedades hidráulicas de rochas porosas e sua dependência do estado de tensão.
Mestre
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Johnson, S. Reed. "Surface and subsurface fault and fracture systems with associated natural gas production in the Lower Mississippian and Upper Devonian, Price Formation, southern West Virginia." Morgantown, W. Va. : [West Virginia University Libraries], 2007. https://eidr.wvu.edu/etd/documentdata.eTD?documentid=4974.
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Thesis (M.S.)--West Virginia University, 2007.Title from document title page. Document formatted into pages; contains vii, 102 p. : ill. (some col.), maps (some col.). Includes abstract. Includes bibliographical references (p. 91-94).
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Mateo, Hernandez Juan Alberto. "Mecanismos de recuperação de oleos pesados durante a injeção de vapor num reservatorio naturalmente fraturado." [s.n.], 2006. http://repositorio.unicamp.br/jspui/handle/REPOSIP/265542.
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Orientador: Osvair Vidal TrevisanDissertação (mestrado) - Universidade Estadual de Campinas, Faculdade de Engenharia Mecanica, Instituto de Geociencias
Made available in DSpace on 2018-08-12T20:49:17Z (GMT). No. of bitstreams: 1 MateoHernandez_JuanAlberto_M.pdf: 12401820 bytes, checksum: 705c41d03544d222731ce816469f47c2 (MD5) Previous issue date: 2006
Resumo: Neste trabalho são investigados os impactos individual e coletivo dos mecanismos de gás em solução, geração de CO2, destilação, embebição capilar e drenagem gravitacional, sobre a recuperação de óleo e gás, durante a injeção continua de vapor num reservatório naturalmente fraturado contendo óleo pesado. A investigação é feita através de simulação numérica dos fenômenos em modelos padrões de reservatórios. Dois modelos numéricos semelhantes são usados para representar o processo de aquecimento da matriz. O primeiro descreve o aquecimento de uma seção horizontal bidimensional de um bloco da matriz circundado por uma fratura na qual circula vapor. O segundo modelo descreve o aquecimento de um bloco de matriz semelhantemente circundado por uma fratura em que circula vapor, porém na direção vertical, visando agregar o efeito da ação da gravidade. Os estudos foram conduzidos para rochas saturadas com óleo vivo. As propriedades da rocha são as de um reservatório carbonático fraturado real e as propriedades dos fluidos se referem também ao mesmo caso real. Alem disso, as condições operacionais adotadas de pressão e temperatura são as observadas no campo, tornando o estudo e suas conclusões como próprias de um estudo de caso. Os resultados mostram que os principais mecanismos de recuperação de óleo da matriz durante o intervalo de aquecimento de 10 anos, foram os mecanismos de gás em solução e de destilação por arraste de vapor. Este último é o mecanismo de maior importância e é responsável pelo melhoramento da qualidade do óleo produzido
Abstract: In this work, the individual and collective impacts of the mechanisms solution gas drive, CO2 generation, steam distillation, capillary imbibition and drainage gravitational, on the oil and gas recovery, were investigated during the steamflooding of a naturally fractured reservoir containing heavy oil. The investigation was performed for standard reservoir models through numeric simulation. Two similar numerical models represent the matrix heating process. The first describes the heating of a horizontal cross-section of a matrix block surrounded by a fracture, in which the steam is flooding. The second model describes the same method of matrix heating, which was represented in the first model, but in the vertical direction, investigating the action of gravity. The studies were performed for a rock saturated with live oil. The rock properties are the same of a real fractured carbonate reservoir and the fluid properties also refer to the same real case. In addition, the adopted field operational parameters (pressure and temperature) refer to field conditions, turning the study and its conclusions as proper of a case study. The results show that the main mechanisms of oil recovery for the matrix block during the heating interval of 10 years were the integrated action of solution gas and steam distillation. The latter is the dominant mechanism and it is responsible for the improvement in the quality of the produced oil
Mestrado
Reservatórios e Gestão
Mestre em Ciências e Engenharia de Petróleo
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Anupam, Ankesh. "Hierarchical modeling of fractures for naturally fractured reservoirs." Thesis, 2010. http://hdl.handle.net/2152/ETD-UT-2010-08-1850.
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Discrete Fracture Networks (DFN) models have long been used to represent heterogeneity associated with fracture networks but all previous approaches have been either in 2D (assuming vertical fractures) or for simple models within a small domain. Realistic representation of DFN on field scale models have been impossible due to two reasons - first because the representation of extremely large number of fractures requires significant computational capability and second, because of the inability to represent fractures on a simulation grid, due to extreme aspect ratio between fracture length and aperture.
This thesis presents a hierarchal approach for fracture modeling and a novel random walker simulation to upscale the fracture permeability. The modeling approach entails developing effective flow characteristics of discrete fractures at micro and macrofracture scales without explicitly representing the fractures on a grid. Separate models were made for micro scale and macro scale fracture distribution with inputs from the seismic data and field observations. A random walker simulation is used that moves walkers along implicit fractures honoring the intersection characteristics of the fracture network. The random walker simulation results are then calibrated against high-resolution flow simulation for some simple fracture representations. The calibration enables us to get an equivalent permeability for a complex fracture network knowing the statistics of the random walkers. These permeabilities are then used as base matrix permeabilities for random walker simulation of flow characteristics of the macro fractures. These are again validated with the simulator to get equivalent upscaled permeability. Several superimposed realizations of micro and macrofracture networks enable us to capture the uncertainty in the network and corresponding uncertainty in permeability field. The advantage of this methodology is that the upscaling process is extremely fast and works on the actual fractures with realistic apertures and yields both the effective permeability of the network as well as the matrix-fracture transfer characteristics.text
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Vicencio, Omar Alan. "Nitrogen injection into naturally fractured reservoirs." Thesis, 2007. http://hdl.handle.net/2152/3061.
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Bansal, Reeshidev 1978. "Seismic characterization of naturally fractured reservoirs." Thesis, 2007. http://hdl.handle.net/2152/3767.
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Many hydrocarbon reservoirs have sufficient porosity but low permeability (for example, tight gas sands and coal beds). However, such reservoirs are often naturally fractured. The fracture patterns in these reservoirs can control flow and transport properties, and therefore, play an important role in drilling production wells. On the scale of seismic wavelengths, closely spaced parallel fractures behave like an anisotropic media, which precludes the response of individual fractures in the seismic data. There are a number of fracture parameters which are needed to fully characterize a fractured reservoir. However, seismic data may reveal only certain fracture parameters and those are fracture orientation, crack density and fracture infill. Most of the widely used fracture characterization methods such as Swave splitting analysis or amplitude vs. offset and azimuth (AVOA) analysis fail to render desired results in laterally varying media. I have conducted a systematic study of the response of fractured reservoirs with laterally varying elastic and fracture properties, and I have developed a scheme to invert for the fracture parameters. I have implemented a 3D finite-difference method to generate multicomponent synthetic seismic data in general anisotropic media. I applied the finite-difference algorithm in both Standard and Rotated Staggered grids. Standard Staggered grid is used for media having symmetry up to orthorhombic (isotropic, transversely isotropic, and orthorhombic), whereas Rotated Staggered grid is implemented for monoclinic and triclinic media. I have also developed an efficient and accurate ray-bending algorithm to compute seismic traveltimes in 3D anisotropic media. AVOA analysis is equivalent to the first-order Born approximation. However, AVOA analysis can be applied only in a laterally uniform medium, whereas the Born-approximation does not pose any restriction on the subsurface structure. I have developed an inversion scheme based on a ray-Born approximation to invert for the fracture parameters. Best results are achieved when both vertical and horizontal components of the seismic data are inverted simultaneously. I have also developed an efficient positivity constraint which forbids the inverted fracture parameters to be negative in value. I have implemented the inversion scheme in the frequency domain and I show, using various numerical examples, that all frequency samples up to the Nyquist are not required to achieve desired inversion results.
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Vicencio, Omar Alan 1966. "Nitrogen injection into naturally fractured reservoirs." 2007. http://hdl.handle.net/2152/13241.
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Tran, Nam Hong. "Characterisation and modelling of naturally fractured reservoirs." 2004. http://www.library.unsw.edu.au/~thesis/adt-NUN/public/adt-NUN20050315.091912/index.html.
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Yi-JieSu and 蘇意傑. "Study of Geomechanical Effects on Fracture Permeability in Naturally Fractured Reservoirs." Thesis, 2012. http://ndltd.ncl.edu.tw/handle/42424164703352268341.
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碩士國立成功大學
資源工程學系碩博士班
100
The purpose of this study was to use an analytical method to study the geomechanical effects on the fracture permeability and pressure response in stress-sensitive naturally fractured reservoirs. The characteristic properties and the approximate expression of the elastic intergral function, which was derived in Jabbari’s theory for stress-sensitive naturally fractured reservoirs, was analyzed and studied. The approximate solution of the bottom-hole pressure for the Jabbari theory was derived. The apparent linear equations for the early time and late time regions were then derived, as well as the equations for the starting time and ending time of the transition region. Based on the equations derived in this study, the estimation procedures for the fracture characteristic parameters and the elastic parameter of stress-sensitive naturally fractured reservoirs were established. A case study was used to validate the derived equations and the estimate procedures. The major results and conclusions obtained from this study are：（1）The approximate pressure solution for stress-sensitive reservoirs was derived. The apprent linear equations for the early time and late time regions were derived to improve the application of Jabbari’s theory in well testing analysis.（2）The equations for estimating the starting time and ending time of the transition regions were derived and can be expressed as:t_Da≅0.157*ω/λ and t_Db≅1.042*1/λ. The criteria used to analyze the the starting time and ending time of the transition regions was the dimensionless pressure of 0.1.（3）The estimation procedures established in this study for analyzing the fracture characteristic parameters and the elastic parameter of stress-sensitive naturally fractured reservoirs were validated from the case study analysis.（4）The pressure drop of stress-sensitive reservoirs was smaller than that of non- stress-sensitive(traditional) reservoirs. The pressure responses were not parallel straight lines in the early time and late time regions in stress-sensitive reservoirs. The formation permeability might be overestimated when traditional well testing analysis is used.
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Moinfar, Ali 1984. "Development of an efficient embedded discrete fracture model for 3D compositional reservoir simulation in fractured reservoirs." 2013. http://hdl.handle.net/2152/21393.
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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.text
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Goudarzi, Ali. "Modeling wettability alteration in naturally fractured carbonate reservoirs." Thesis, 2011. http://hdl.handle.net/2152/ETD-UT-2011-12-4930.
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The demand for energy and new oil reservoirs around the world has increased rapidly while oil recovery from depleted reservoirs has become more difficult. Oil production from fractured carbonate reservoirs by water flooding is often inefficient due to the commonly oil-wet nature of matrix rocks. Chemical enhanced oil recovery (EOR) processes such as surfactant-induced wettability alteration and interfacial tension reduction are required to decrease the residual oil saturation in matrix blocks, leading to incremental oil recovery. However, improvement in recovery will depend on the degree of wettability alteration and interfacial tension (IFT) reduction, which in turn are functions of matrix permeability, fracture intensity, temperature, pressure, and fluid properties. The oil recovery from fractured carbonate reservoirs is frequently considered to be dominated by the spontaneous imbibition mechanism which is a combination of viscous, capillary, and gravity forces.
The primary purpose of this study is to model wettability alteration in the lab scale for both coreflood and imbibition cell tests using the chemical flooding reservoir simulator. The experimental recovery data for fractured carbonate rocks with different petrophysical properties were history-matched with UTCHEM, The University of Texas in-house compositional chemical flooding simulator, using a highly heterogeneous permeability distribution. Extensive simulation work demonstrates the validity and ranges of applicability of upscaled procedures, and also indicates the importance of viscous and capillary forces in larger fields. The results of this work will be useful for designing field-scale chemical EOR processes.text
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Aybar, Umut. "Investigation of analytical models incorporating geomechanical effects on production performance of hydraulically and naturally fractured unconventional reservoirs." Thesis, 2014. http://hdl.handle.net/2152/26452.
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Petroleum and Geosystems EngineeringProduction from unconventional reservoirs became popular in the last decade in the U.S. Promising production results and predictions, as well as improvements in hydraulic fracturing and horizontal drilling technology made unconventional reservoirs economically feasible. Therefore, an effective and efficient reservoir model for unconventional resources became a must. In order to model production from such resources, analytical, semi-analytical, and numerical models have been developed, but analytical models are frequently used due to their practicality, relative simplicity, and also due to limited availability of field data. This research project has been accomplished in two main parts. In the first part, two analytical models for unconventional reservoirs, one with infinite hydraulic fracture conductivity assumption proposed by Patzek et al. (2013), while the other one with finite hydraulic fracture conductivity assumption developed by Ozkan et al. (2011) are compared. Additionally, a commercial reservoir simulator (CMG, IMEX, 2012) is employed to compare the results with the analytical models. Sensitivity study is then performed to identify the critical parameters controlling the production performance of unconventional reservoirs. In the second part, naturally and hydraulically fractured unconventional reservoir is considered. In addition, geomechanical effects on natural and hydraulic fractures are examined. A simple analytical dual porosity model, which represents the natural fractures in unconventional reservoirs, is improved to handle the constant bottom-hole pressure production scenario to identify the production performance differences between the cases with and without geomechanical effects. Finally, geomechanical effects are considered for combined natural and hydraulic fractures, and an evaluation of the circumstances in which the geomechanical effects cause a significant production loss is carried out.
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Abbasi, Asl Yousef. "Simulation study of surfactant transport mechanisms in naturally fractured reservoirs." Thesis, 2010. http://hdl.handle.net/2152/ETD-UT-2010-08-1707.
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Surfactants both change the wettability and lower the interfacial tension by various degrees depending on the type of surfactant and how it interacts with the specific oil. Ultra low IFT means almost zero capillary pressure, which in turn indicates little oil should be produced from capillary imbibition when the surfactant reduces the IFT in naturally fractured oil reservoirs that are mixed-wet or oil-wet.
What is the transport mechanism for the surfactant to get far into the matrix and how does it scale? Molecular diffusion and capillary pressure are much too slow to explain the experimental data. Recent dynamic laboratory data suggest that the process is faster when a pressure gradient is applied compared to static tests. A mechanistic chemical compositional simulator was used to study the effect of pressure gradient on chemical oil recovery from naturally fractured oil reservoirs for several different chemical processes (polymer, surfactant, surfactant-polymer, alkali-surfactant-polymer flooding). The fractures were simulated explicitly by using small gridblocks with fracture properties. Both homogeneous and heterogeneous matrix blocks were simulated. Microemulsion phase behavior and related chemistry and physics were modeled in a manner similar to single porosity reservoirs.
The simulations indicate that even very small pressure gradients (transverse to the flow in the fractures) are highly significant in terms of the chemical transport into the matrix and that increasing the injected fluid viscosity greatly improves the oil recovery. Field scale simulations show that the transverse pressure gradients promote transport of the surfactant into the matrix at a feasible rate even when there is a high contrast between the permeability of the fractures and the matrix. These simulations indicate that injecting a chemical solution that is viscous (because of polymer or foam or microemulsion) and lowers the IFT as well as alters the wettability from mixed-wet to water-wet, produces more oil and produces it faster than static chemical processes. These findings have significant implications for enhanced oil recovery from naturally fractured oil reservoirs and how these processes should be optimized and scaled up from the laboratory to the field.text
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Al, Huthali Ahmed. "Streamline-based simulation of water injection in naturally fractured reservoirs." 2003. http://hdl.handle.net/1969/410.
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Yi-AnChen and 陳怡安. "Transient Pressure Analysis of Stress-Sensitive Naturally Fractured Gas Reservoirs." Thesis, 2015. http://ndltd.ncl.edu.tw/handle/66183063456328790437.
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Lalehrokh, Farshad. "Simulating water tracer test in naturally fractured reservoirs using discrete fracture and dual porosity models." 2005. http://hdl.handle.net/2152/18728.
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A naturally fractured reservoir (NFR) is a reservoir with a connected network of
fractures created by natural processes such as diastrophism and volume shrinkage
(Ordonez et al. 2001). There are two models to simulate this kind of reservoirs: the
discrete fracture model and the dual porosity model. In the dual porosity model, the
matrix blocks occupy the same physical space as the fracture network and are
identical rectangular parallelepipeds with no direct communication between isotropic
and homogeneous matrix blocks. However, each fracture and matrix property is
defined separately in the discrete fracture model.
Another feature of this thesis is tracer testing. In this process, a chemical or
radioactive element is injected to the reservoirs, and then it can be traced using the
devices, which are designed to detect the tracers. Tracer tests have several advantages
such as determining residual oil saturation, identifying barriers or high permeability
zones in reservoirs, and providing the information on flow patterns. Limited number of research studies has been done on performing tracer tests in
naturally fractured reservoirs. Also because there is not enough information about the
advantages and disadvantages of the discrete fracture and the dual porosity models,
researchers and engineers lack the expertise to confidently select either the discrete
fracture or the dual porosity models to simulate the different types of NFRs. In this thesis, we compared the oil and water productions, and tracer concentration
curves in various reservoir conditions, using both the discrete fracture and the dual
porosity models. We used the ECLIPSE, which is a commercial software package in
the area of petroleum industry, to model a naturally fractured reservoir. We
performed a simple waterflooding with two conservative tracers on the reservoirs.
The results presented in each section include the graphs of the oil production rate,
water production rate, and tracer concentration. In addition, we presented the oil
saturation profiles of a cross-section, which includes the production and injection
wells.
The results illustrated that both the discrete fracture and the dual porosity models are
in good agreement, except for a few special cases. Generally, the oil production using
the dual porosity model is more than in the discrete fracture model. The major
disadvantage of the dual porosity model is that the fluid distribution in the matrix
blocks is changing homogenously during the waterflooding period. In other words,
ECLIPSE shows a constant value of the oil and water saturations in each time step for
the matrix blocks. However, the dual porosity model is 3 to 4 times faster than the
discrete fracture model. In the discrete fracture model, the users have complete
control in defining the reservoirs. For example, the fracture aperture, fracture spacing,
and fracture porosities can be set by the user. The disadvantage of this model is that
millions of grid blocks are needed to model a large reservoir with small fracture
spacing.text
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Rijken, Margaretha Catharina Maria. "Modeling naturally fractured reservoirs from experimental rock mechanics to flow simulation /." Thesis, 2005. http://repositories.lib.utexas.edu/bitstream/handle/2152/1708/rijkenm94544.pdf.
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Shafiei, Ali. "Mathematical and Statistical Investigation of Steamflooding in Naturally Fractured Carbonate Heavy Oil Reservoirs." Thesis, 2013. http://hdl.handle.net/10012/7429.
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A significant amount of Viscous Oil (e.g., heavy oil, extra heavy oil, and bitumen) is trapped in Naturally Fractured Carbonate Reservoirs also known as NFCRs. The word VO endowment in NFCRs is estimated at ~ 2 Trillion barrels mostly reported in Canada, the USA, Russia, and the Middle East. To date, contributions to the world daily oil production from this immense energy resource remains negligible mainly due to the lack of appropriate production technologies. Implementation of a VO production technology such as steam injection is expensive (high capital investment), time-consuming, and people-intensive. Hence, before selecting a production technology for detailed economic analysis, use of cursory or broad screening tools or guides is a convenient means of gaining a quick overview of the technical feasibility of the various possible production technologies applied to a particular reservoir. Technical screening tools are only available for the purpose of evaluation of the reservoir performance parameters in oil sands for various thermal VO exploitation technologies such as Steam Assisted Gravity Drainage (SAGD), Cyclic Steam Stimulation (CSS), Horizontal well Cyclic steam Stimulation (HCS), and so on. Nevertheless, such tools are not applicable for VO NFCRs assessment without considerable modifications due to the different nature of these two reservoir types (e.g., presence and effects of fracture network on reservoir behavior, wettability, lithology, fabric, pore structure, and so on) and also different mechanisms of energy and mass transport. Considering the lack of robust and rapid technical reservoir screening tools for the purpose of quick assessment and performance prediction for VO NFCRs under thermal stimulation (e.g., steamflooding), developing such fast and precise tools seems inevitable and desirable.
In this dissertation, an attempt was made to develop new screening tools for the purpose of reservoir performance prediction in VO NFCRs using all the field and laboratory available data on a particular thermal technology (vertical well steamflooding). Considering the complex and heterogeneous nature of the NFCRs, there is great uncertainty associated with the geological nature of the NFCRs such as fracture and porosity distribution in the reservoir which will affect any modeling tasks aiming at modeling of processes involved in thermal VO production from these types of technically difficult and economically unattractive reservoirs. Therefore, several modeling and analyses technqiues were used in order to understand the main parameters controlling the steamflooding process in NFCRs and also cope with the uncertainties associated with the nature of geologic, reservoir and fluid properties data. Thermal geomechanics effects are well-known in VO production from oil sands using thermal technologies such as SAGD and cyclic steam processes. Hence, possible impacts of thermal processes on VO NFCRs performance was studied despite the lack of adequate field data.
This dissertation makes the following contributions to the literature and the oil industry: Two new statistical correlations were developed, introduced, and examined which can be utilized for the purpose of estimation of Cumulative Steam to Oil Ratio (CSOR) and Recovery Factor (RF) as measures of process performance and technical viability during vertical well steamflooding in VO Naturally Fractured Carbonate Reservoirs (NFCRs). The proposed correlations include vital parameters such as in situ fluid and reservoir properties. The data used are taken from experimental studies and also field trials of vertical well steamflooding pilots in viscous oil NFCRs reported in the literature. The error percentage for the proposed correlations is < 10% for the worst case and contains fewer empirical constants compared with existing correlations for oil sands. The interactions between the parameters were also considered. The initial oil saturation and oil viscosity are the most important predictive factors. The proposed correlations successfully predicted steam/oil ratios and recovery factors in two heavy oil NFCRs. These correlations are reported for the first time in the literature for this type of VO reservoirs.
A 3-D mathematical model was developed, presented, and examined in this research work, investigating various parameters and mechanisms affecting VO recovery from NFCRs using vertical well steamflooding. The governing equations are written for the matrix and fractured medium, separately. Uncertainties associated with the shape factor for the communication between the matrix and fracture is eliminated through setting a continuity boundary condition at the interface. Using this boundary condition, the solution method employed differs from the most of the modeling simulations reported in the literature. A Newton-Raphson approach was also used for solving mass and energy balance equations. RF and CSOR were obtained as a function of steam injection rate and temperature and characteristics of the fractured media such as matrix size and permeability. The numerical solution clearly shows that fractures play an important role in better conduction of heat into the matrix part. It was also concluded that the matrix block size and total permeability are the most important parameters affecting the dependent variables involved in steamflooding.
A hybrid Artificial Neural Network model optimized by co-implementation of a Particle Swarm Optimization method (ANN-PSO) was developed, presented, and tested in this research work for the purpose of estimation of the CSOR and RF during vertical well steamflooding in VO NFCRs. The developed PSO-ANN model, conventional ANN models, and statistical correlations were examined using field data. Comparison of the predictions and field data implies superiority of the proposed PSO-ANN model with an absolute average error percentage < 6.5% , a determination coefficient (R2) > 0.98, and Mean Squared Error (MSE) < 0.06, a substantial improvement in comparison with conventional ANN model and empirical correlations for prediction of RF and CSOR. This indicates excellent potential for application of hybrid PSO-ANN models to screen VO NFCRs for steamflooding. This is the first time that the ANN technique has been applied for the purpose of performance prediction of steamflooding in VO NFCRs and also reported in the literature. The predictive PSO-ANN model and statistical correlations have strong potentials to be merged with heavy oil recovery modeling softwares available for thermal methods. This combination is expected to speed up their performance, reduce their uncertainty, and enhance their prediction and modeling capabilities.
An integrated geological-geophysical-geomechanical approach was designed, presented, and applied in the case of a NFCR for the purpose of fracture and in situ stresses characterization in NFCRs. The proposed methodology can be applied for fracture and in situ stresses characterization which is beneficial to various aspects of asset development such as well placement, drilling, production, thermal reservoir modeling incorporating geomechanics effects, technology assessment and so on. A conceptual study was also conducted on geomechanics effects in VO NFCRs during steamflooding which is not yet well understood and still requires further field, laboratory, and theoretical studies. This can be considered as a small step forward in this area identifying positive potential of such knowledge to the design of large scale thermal operations in VO NFCRs.
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Tao, Qingfeng. "Numerical Modeling of Fracture Permeability Change in Naturally Fractured Reservoirs Using a Fully Coupled Displacement Discontinuity Method." 2010. http://hdl.handle.net/1969.1/ETD-TAMU-2010-05-7670.
Full textAbstract:
Fractures are the main flow channels in naturally fractured reservoirs. Therefore
the fracture permeability is a critical parameter to production optimization and reservoir
management. Fluid pressure reduction caused by production induces an increase in
effective stress in naturally fractured reservoirs. The change of effective stress induces
fracture deformation and changes fracture aperture and permeability, which in turn
influences the production. Coupled interactions exist in the fractured reservoir: (i) fluid
pressure change induces matrix deformation and stress change; (ii) matrix deformation
induces fluid volume change and fluid pressure change; (iii) fracture deformation
induces the change of pore pressure and stress in the whole field (the influence
disappears at infinity); (iv) the change of pore pressure and stress at any point has an
influence on the fracture and induces fracture deformation. To model accurately the
influence of pressure reduction on the fracture permeability change in naturally fractured
reservoirs, all of these coupled processes need to be considered. Therefore, in this
dissertation a fully coupled approach is developed to model the influence of production on fracture aperture and permeability by combining a finite difference method to solve
the fluid flow in fractures, a fully coupled displacement discontinuity method to build
the global relation of fracture deformation, and the Barton-Bandis model of fracture
deformation to build the local relation of fracture deformation.
The fully coupled approach is applied to simulate the fracture permeability
change in naturally fracture reservoir under isotropic in situ stress conditions and high
anisotropic in situ stress conditions, respectively. Under isotropic stress conditions, the
fracture aperture and permeability decrease with pressure reduction caused by
production, and the magnitude of the decrease is dependent on the initial effective in situ
stress. Under highly anisotropic stress, the fracture permeability can be enhanced by
production because of shear dilation. The enhancement of fracture permeability will
benefit to the production of oil and gas.
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Shakiba, Mahmood. "Modeling and simulation of fluid flow in naturally and hydraulically fractured reservoirs using embedded discrete fracture model (EDFM)." Thesis, 2014. http://hdl.handle.net/2152/28292.
Full textAbstract:
Modeling and simulation of fluid flow in subsurface fractured systems has been steadily a popular topic in petroleum industry. The huge potential hydrocarbon reserve in naturally and hydraulically fractured reservoirs has been a major stimulant for developments in this field. Although several models have found limited applications in studying fractured reservoirs, still more comprehensive models are required to be applied for practical purposes. A recently developed Embedded Discrete Fracture Model (EDFM) incorporates the advantages of two of the well-known approaches, the dual continuum and the discrete fracture models, to investigate more complex fracture geometries. In EDFM, each fracture is embedded inside the matrix grid and is discretized by the cell boundaries. This approach introduces a robust methodology to represent the fracture planes explicitly in the computational domain. As part of this research, the EDFM was implemented in two of The University of Texas in-house reservoir simulators, UTCOMP and UTGEL. The modified reservoir simulators are capable of modeling and simulation of a broad range of reservoir engineering applications in naturally and hydraulically fractured reservoirs. To validate this work, comparisons were made against a fine-grid simulation and a semi-analytical solution. Also, the results were compared for more complicated fracture geometries with the results obtained from EDFM implementation in the GPAS reservoir simulator. In all the examples, good agreements were observed. To further illustrate the application and capabilities of UTCOMP- and UTGEL-EDFM, a few case studies were presented. First, a synthetic reservoir model with a network of fractures was considered to study the impact of well placement. It was shown that considering the configuration of background fracture networks can significantly improve the well placement design and also maximize the oil recovery. Then, the capillary imbibition effect was investigated for the same reservoir models to display its effect on incremental oil recovery. Furthermore, UTCOMP-EDFM was applied for hydraulic fracturing design where the performances of a simple and a complex fracture networks were evaluated in reservoirs with different rock matrix permeabilities. Accordingly, it was shown that a complex network is an ideal design for a very low permeability reservoir, while a simple network results in higher recovery when the reservoir permeability is moderate. Finally, UTGEL-EDFM was employed to optimize a conformance control process. Different injection timings and different gel concentrations were selected for water-flooding processes and their impact on oil recovery was evaluated henceforth.text
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Alramadhan, Aymen Abduljalil. "Interpretation, Analysis and Design of Inter-well Tracer Tests in Naturally Fractured Reservoirs." Thesis, 2013. http://hdl.handle.net/1969.1/151192.
Full textAbstract:
In order to understand the complex fracture network that controls water movement in Sherrod Area of Spraberry Field in West Texas and to better manage the on-going waterflood performance, a field scale inter-well tracer test was implemented. This test presents the largest inter-well tracer test in naturally fractured reservoirs reported in the industry and includes the injection of 13 different tracers and sampling of 110 producers in an area covering 6533 acres.
Sherrod tracer test generated a total of 598 tracer responses from 51 out of the 110 sampled producers. Tracer responses showed a wide range of velocities from 14 ft/day to ultra-high velocities exceeding 10,000 ft/day with same-day tracer breakthrough. Re-injection of produced water has caused the tracers to be re-injected and added an additional challenge to diagnose and distinguish tracer responses affected by water recycling. Historical performance of the field showed simultaneous water breakthrough of a large number of wells covering entire Sherrod area. This research investigate analytical, numerical, and inversion modeling approaches in order to categorize, history match, and connect tracer responses with water-cut responses with the objective to construct multiple fracture realizations based entirely on water-cut and tracers‟ profiles. In addition, the research highlight best practices in the design of inter-well tracer tests in naturally fractured reservoirs through lessons learned from Sherrod Area.
The large number of tracer responses from Sherrod case presents a case of naturally fractured reservoir characterization entirely based on dynamic data. Results indicates that tracer responses could be categorized based on statistical analysis of tracer recoveries of all pairs of injectors and producers with each category showing distinguishing behavior in tracers‟ movement and breakthrough time. In addition, it showed that tracer and water-cut responses in the field are dominantly controlled by the fracture system revealing minimum information about the matrix system. Numerical simulation studies showed limitation in dual porosity formulation/solvers to model tracer velocities exceeding 2200 ft/day. Inversion modeling using Gradzone Analysis showed that east and north-west of Sherrod have significantly lower pore volume compared to south-west.
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Yadav, Himanshu. "Hydraulic fracturing in naturally fractured reservoirs and the impact of geomechanics on microseismicity." Thesis, 2011. http://hdl.handle.net/2152/ETD-UT-2011-12-4889.
Full textAbstract:
Hydraulic fracturing in tight gas and shale gas reservoirs is an essential stimulation technique for production enhancement. Often, hydraulic fracturing induces fracture patterns that are more complex than the planar geometry that has been assumed in the past models. These complex patterns arise as a result of the presence of planes of weakness, faults and/or natural fractures. In this thesis, two different 3D geomechanical models have been developed to simulate the interaction between the hydraulic fracture and the natural fractures, and to observe the impact of geomechanics on the potential microseismicity in these naturally fractured formations. Several cases were studied to observe the effects of natural fracture geometry, fracturing treatment, mechanical properties of the sealed fractures, etc. on the propagation path of the hydraulic fracture in these formations, and were found to be consistent with past experimental results. Moreover, the effects of several parameters including cohesiveness of the sealed natural fractures, mechanical properties of the formation, treatment parameters, etc. have been studied from the potential microseismicity standpoint. It is shown that the impact of geomechanics on potential microseismicity is significant and can influence the desired fracture spacing. In this thesis, the presented model quantifies the extent of potential microseismic volume (MSV) resulting from hydraulic fracturing in unconventional reservoirs. The model accounts for random geometries of the weak planes (with different dip and strike) observed in the field. The work presented here shows, for the first time, a fracture treatment can be designed to maximize the MSV, when the fractures form a complicated network of fractures, and in turn influence the desired fracture spacing in horizontal wells. Our work shows that by adjusting the fluid rheology and other treatment parameters, the spatial extent of MSV and the desired fracture spacing can be optimized for a given set of shale properties.text
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Wei-ChengJhuang and 莊惟盛. "Study of Transient Pressure Behavior and Radius of Investigation in Naturally Fractured Reservoirs." Thesis, 2011. http://ndltd.ncl.edu.tw/handle/39506149100502072309.
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Zhao, Xueping. "Imaging the Mechanics of Hydraulic Fracturing in Naturally-fractured Reservoirs Using Induced Seismicity and Numerical Modeling." Thesis, 2010. http://hdl.handle.net/1807/32966.
Full textAbstract:
The primary objective of this study is to improve understanding of the mechanics of hydraulic fracturing in naturally-fractured reservoirs. The study focuses on enhancing the interpretation of hydraulic fracture-induced microseismic data using an S-wave Gaussian-beam method and numerical modeling techniques for interpretation. The S-wave Gaussian-beam method was comprehensively calibrated by synthetic and real data sets with different recording networks, and this showed the potential to retrieve additional microseismic data from hydraulic fracturing with linear receiver arrays. This approach could enhance current practice because a large number of induced events in these environments have very strong S-waves with P-wave amplitudes similar, or less than, background noise levels. The numerical study using the distinct element methods PFC2D and PFC3D was used to validate the understanding of the hydraulic fracturing mechanisms induced in laboratory and field fluid treatments in naturally-fractured reservoirs. This was achieved through direct comparison with the results of the geometry of hydraulic fractures and seismic source information (locations, magnitudes, and mechanisms) from both laboratory experiments and field observations. A suite of numerical models with fully-dynamic and hydro-mechanical coupling has been used to examine in detail the interaction between natural and induced fractures with the variations of the differential stresses and the orientations of the pre-fractures, and the relationship between the fluid front, the fracture tip, and the induced seismicity. The numerical results qualitatively agreed with the laboratory and field observations of the geometry of hydraulic fractures, confirmed the possible mechanics of new fracture development and their interactions with natural fractures, and illustrated the possible relationship between the fluid front and the fracture tip. The validated model could therefore help track the potential extent of induced fracturing in naturally-fractured reservoirs and the extent to which it can be detected by a microseismic monitoring array in order to assess the effectiveness of a hydraulic fracturing project.
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Artun, F. Emre Ertekin Turgay Watson Robert W. "Optimized design of cyclic pressure pulsing in naturally fractured reservoirs using neural-network based proxy models." 2008. http://etda.libraries.psu.edu/theses/approved/PSUonlyIndex/ETD-2855/index.html.
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