Recent Publications
All SPE papers are property of the Society of Petroleum Engineering and .pdf files can be obtain from their website.
Selection by Year: 2003 | 2004 | 2005 | 2006 | 2007
2007
IPTC 11778: A Critical Review for Proper Use of Water-Oil-Gas Transfer Functions in Dual-Porosity Naturally Fractured Reservoirs – Part II. M. Al-Kobaisi, H. Kazemi, B. Ramirez, E. Ozkan, and S. Atan. This paper was prepared for presentation at the International Petroleum Technology Conference held in Dubai, U.A.E., 4–6 December 2007.
Abstract: This paper is Part II of SPE 109821. In Part I, we discussed the viability of the use of simple transfer functions to accurately account for fluid exchange resulting from capillary, gravity and diffusion mass transfer for immiscible flow between fracture and matrix in dual-porosity numerical models. Here we will show additional information on several relevant topics, which include (1) flow of a low concentration, water-soluble surfactant in the fracture and the extent to which the surfactant is transported into the matrix, (2) an adjustment to the transfer function to account for the early slow mass transfer into matrix before the invading fluid establishes full connectivity with the matrix, and (3) an analytical approximation to the differential equation of mass transfer from a fracture to the matrix and a method of solution to predict oil drainage performance. Numerical experiments involving single-porosity, fine-grid simulation of immiscible oil recovery from a typical matrix block by water, gas, or surfactant-augmented water in an adjacent fracture were performed. Results emphasize the viability of the transfer function formulations and their accuracy in quantifying the interaction of capillary and gravity forces to produce oil depending on the wettability of the matrix. For miscible flow the fracture-matrix mass transfer is less complicated because the interfacial tension between solvent and oil is zero; nevertheless, gravity contrast between solvent in the fracture and oil in the matrix creates convective mass transfer and drainage of the oil.
IPTC 11781: Pressure-Transient Performances of Hydraulically Fractured Horizontal Wells in Locally and Globally Naturally Fractured Formations. F. Medeiros, B. Kurtoglu, E. Ozkan, and H. Kazemi. This paper was prepared for presentation at the International Petroleum Technology Conference held in Dubai, U.A.E., 4–6 December 2007.
Abstract: This paper presents a discussion of diagnostic pressure and pressure-derivative plots for hydraulically fractured horizontal wells in locally and globally fractured formations. The discussions are based on pressure-transient responses generated by using a semi-analytical, heterogeneous reservoir simulator. Pressure-transient characteristics are discussed and documented. Performances of horizontal wells with longitudinal and transverse fractures are compared. It is shown that global and local natural fractures display distinct pressure transient characteristics and, hence, significantly influence well performance. In general, conductive, interconnected natural fractures dominate the pressure-transient characteristics of horizontal wells in tight formations even in the presence of hydraulic fractures. Furthermore, the results also indicate that if the reservoir is naturally fractured, hydraulic fracturing might not improve productivity significantly, unless large hydraulic fracture conductivities can be achieved. Finally, if there is a significant contrast between the effective permeabilities of local natural fractures and surrounding homogeneous reservoir, it might be possible to estimate the volume of the naturally fractured region.
SPE 110848: Analysis of Production Data From Hydraulically Fractured Horizontal Wells in Tight, Heterogeneous Formations. F. Medeiros, B. Kurtoglu, E. Ozkan, and H. Kazemi. Presented at the SPE Annual Technical Conference and Exhibition in Anaheim California, 11-14 November 2007
Abstract: This paper discusses the analysis of production data from hydraulically fractured horizontal wells in tight, heterogeneous formations. We consider horizontal wells with longitudinal and transverse hydraulic fractures, which might be surrounded by a region with natural fractures. These well-reservoir configurations are of interest in many unconventional reservoirs, including tight-gas sands and shale-oil or gas formations. A semi-analytical model that can incorporate the key features of reservoir heterogeneity and the details of hydraulic fracture and wellbore flow is used to compute production decline. Production decline characteristics are presented in terms of transient productivity index. Computation of transient productivity index from field data and the analysis of production decline by transient productivity index are explained. Example applications of production data analysis for fractured horizontal wells in tight, heterogeneous formations are presented.
SPE 109821: A Critical Review for Proper Use of Water/Oil/Gas Transfer Functions in Dual-Porosity Naturally Fractured Reservoirs—Part I. B. Ramirez, H. Kazemi, M. Al-Kobaisi, E. Ozkan, and S. Atan. Presented at the SPE Annual Technical Conference and Exhibition in Anaheim California, 11-14 November 2007
Abstract: Accurate calculation of multi-phase fluid transfer between the fracture and matrix in naturally fractured reservoirs is a crucial issue. In this paper, we will present the viability of the use of simple transfer functions to accurately account for fluid exchange resulting from capillary, gravity and diffusion mass transfer for immiscible flow between fracture and matrix in dual-porosity numerical models. The transfer functions are designed for sugar-cube or match-stick idealizations of matrix blocks.
The study relies on numerical experiments involving fine-grid simulation of oil recovery from a typical matrix block by water or gas in an adjacent fracture. The fine-grid results for water-oil and gas-oil systems were compared with results obtained with transfer functions. Both in water and gas injection, the simulations emphasize the interaction of capillary and gravity forces to produce oil depending on the wettability of the matrix.
In gas injection, the thermodynamic phase-equilibrium, aided by gravity-capillary interaction and to a lesser extent by molecular diffusion, is a major contributor to interphase mass transfer. For miscible flow the fracture-matrix mass transfer is less complicated because there is no capillary forces associated with solvent and oil; nevertheless, gravity contrast between solvent in the fracture and oil in the matrix creates convective mass transfer and drainage of oil.
Using the transfer functions presented in this paper, fracture and matrix flow calculations can be decoupled and solved sequentially–reducing the complexity of the computation. Furthermore, the transfer function equations can be used independently to calculate oil recovery from a matrix block.
SPE 109295: Non-Darcy Flow Effects in Dual-Porosity, Dual-Permeability, Naturally Fractured Gas Condensate Reservoirs. B. Ramirez, H. Kazemi, E. Ozkan, and M. Al-Matrook. Presented at the SPE Annual Technical Conference and Exhibition in Anaheim California, 11-14 November 2007
Abstract: This paper addresses the retrograde condensation behavior in natural fractures and in the near wellbore region of a naturally fractured reservoir (NFR). The study includes the combined effect of non-Darcy flow in presence of retrograde condensation and wellbore damage on pressure transient analysis of naturally fractured reservoirs. A single well compositional model was constructed and used to evaluate both the early-time and late-time characteristics of the pressure transient data.
In naturally fractured reservoirs the high velocity region could be substantially beyond the near wellbore region because of the narrowness of the fractures. To assess this situation, draw-down, build-up and multi-rate tests were simulated in rich gas and lean gas condensate reservoirs. It was concluded that the gas condensation in the near wellbore region significantly increases the calculated skin factor beyond the physical damage.
SPE 108110: Productivity and Drainage Area of Fractured Horizontal Wells in Tight Gas Reservoirs. F. Medeiros, E Ozkan, and H. Kazemi. Presented at the 2007 Rocky Mountain Oil & Gas Technology Symposium in Denver, CO, 16-18 April 2007.
Abstract: This paper discusses the performance and productivity of fractured horizontal wells in heterogeneous, tight-gas formations. Production characteristics and flow regimes of unfractured and fractured horizontal wells are documented. The results show that if hydraulic fracturing affects stress distribution to create or rejuvenate natural fractures around the well, productivity of the system is significantly increased. Unless there is significant contrast between the conductivities of the hydraulic and natural fractures, hydraulic fractures may not significantly contribute to the productivity. For extremely tight formations, effective drainage area may be limited to the naturally fractured region around the well and the hydraulic fractures. It is also shown that very long transient flow periods govern the productivity and economics of fractured horizontal wells in tight formations. The results of this study are also applicable to oil production from fractured shale.
SPE 104581: Transient Behavior of Multilateral Wells in Numerical Models: A Hybrid Analytical-Numerical Approach. C. Aguilar, E. Ozkan, H. Kazemi, M. Al-Kobaisi, and B. Ramirez. Presented at the 15th SPE Middle East Oil & Gas Show and Conference held in Bahrain International Exhibition Centre, Kingdom of Bahrain, 11-14 March 2007.
Abstract: This paper presents an extension of transient well index approach to simulate pressure transient behavior of multilateral wells. This approach uses an analytical solution for the well index at early times and switches to the numerical well index at late times. The use of the transient well index eliminates the need for excessive grid refinement around the well. In this paper, we have improved the accuracy of the transient well index approach and have provided for a flexible and easily implementable approach to place multilaterals in conventional, Cartesian-grid reservoir models.
SPE 104580: Verification and Proper Use of Water/Oil Transfer Function for Dual-Porosity and Dual-Permeability Reservoirs. A. Balogun, H. Kazemi, E. Ozkan, M. Al-Kobaisi, and B. Ramirez Presented at the 15th SPE Middle East Oil & Gas Show and Conference held in Bahrain International Exhibition Centre, Kingdom of Bahrain, 11-14 March 2007.
Abstract: Accurate calculation of multi-phase fluid transfer between the fracture and matrix in naturally fractured reservoirs is a very crucial issue. In this paper, we will present the viability of the use of a simple transfer function to accurately account for fluid exchange resulting from capillary and gravity forces between fracture and matrix in dual-porosity and dual-permeability numerical models. With this approach, fracture and matrix flow calculations can be decoupled and solved sequentially, improving the speed and ease of computation. In fact, the transfer function equations can be easily used to calculate the expected oil recovery from a matrix block of any dimension without the use of a simulator or oil recovery correlations.
The study was accomplished by conducting fine-grid simulation of a typical matrix block and comparing the results with those obtained with the use of a simple transfer function for a water-oil system. This study was similar to a previous study (Alkandari, 2002) we had conducted for a gas-oil system.
The transfer functions of this paper are specifically for the sugar-cube idealization of a matrix block, which can be extended to simulation of a match-stick idealization in reservoir modeling. The basic data required are: matrix capillary pressure curves, densities of the flowing fluids, and matrix block dimensions.
2006
SPE 101987: Effects of Formation Damage and High-Velocity Flow on the Productivity of Slotted-Liner Completed Horizontal Wells. Y. Tang, T. Yildiz, E. Ozkan, and M. Kelkar. Presented at the 2006 International Oil & Gas Conference and Exhibition in China held in Beijing, China, 5-7 December 2006.
Abstract: Slotted-liner is a relatively simple and cost-effective well completion technique for horizontal wells. However, fluid flow into a slotted-liner completion is quite complicated due to three dimensional flow convergence around slots and limited open-to-flow areas. Furthermore, the compounded effects of formation damage and non-Darcy flow on the fluid flow towards slotted-liners must be considered in well completion design process.
This paper presents a comprehensive semi-analytical model for estimating the productivity of horizontal wells completed with slotted liners. The semi-analytical model is obtained by coupling the reservoir flow and wellbore flow equations. The model includes the additional pressure drops due to mechanical skin and non-Darcy effect. Additionally, the model could handle non-uniform flux, non-uniform skin distribution, and selective completion with blank pipes. Both oil well and gas wells are evaluated. For gas wells, the standard pseudo-functions are used. Detailed discussion of the effects of formation damage and non-Darcy flow is provided.
Results indicate that the productivity reduction because of formation damage is more significant for slotted-liner completion than the openhole completion due to increased pressure drop with flow convergence in the region with reduced permeability. Control of drilling damage ratio is more important than control of drilling damage radius. High slot density with low phasing angle helps to reduce the non-Darcy flow effect.
SPE 84378: Pressure-Transient Responses of Horizontal and Curved Wells in Anticlines and Domes. N. Al-Mohannadi, E. Ozkan, and H. Kazemi. Presented at the 2003 SPE Annual Technical Conference and Exhibition, Denver, 5-8 October, and revised for publication. Paper peer approved 5 November 2006.
Abstract: This paper presents a discussion of the pressure-transient responses of horizontal wells in anticlinal structures and curved and undulating wells in slab reservoirs. It confirms that, in the absence of a gas cap, conventional horizontal-well models may be used to approximate the flow characteristics of the systems in which the trajectory of the well does not conform to the curvature of the producing structure. If a gas cap is present, however, the unconformity of the well trajectory and producing layer manifests itself, especially on derivative characteristics when the gas saturation increases around the well. In general, the most significant deviations from the conventional horizontal-well behavior are observed during the buildup periods following long drawdowns. In these cases, the pressure-transient analysis is complicated and requires detailed numerical modeling of the well trajectory and reservoir geometry in the vertical plane.
SPE 102834: A Semianalytical, Pressure-Transient Model for Horizontal and Multilateral Wells in Composite, Layered, and Compartmentalized Reservoirs. F. Medeiros Jr., E. Ozkan, and H. Kazemi. Presented at the SPE Annual Technical Conference and Exhibition, 24-27 September 2006, San Antonio, Texas, USA
Abstract: This paper presents a semianalytical model for the pressure-transient analysis of horizontal wells in composite, layered, and compartmentalized reservoirs. The model divides the reservoir into blocks that represent locally homogeneous substructures of the reservoir and couples the analytical, pressure-transient solutions at the block boundaries. This approach is consistent with the averaging effect of pressure transients and provides an alternative to full numerical modeling of horizontal-well pressure-transient responses in heterogeneous formations. The model can also be generalized for multiple wells of different geometry including multiple laterals.
SPE 90623: Combined Effect of Non-Darcy Flow and Formation Damage on Gas-Well Performance of Dual-Porosity and Dual-Permeability Reservoirs. C. Pereira Tavares, H. Kazemi, and E. Ozkan. Presented at the 2004 Annual Technical Conference and Exhibition, Houston, TX, 26-29 September, and revised for publication. Paper peer approved 31 July 2006.
Abstract: This paper addresses the combined effect of formation damage and non-Darcy flow in naturally fractured reservoirs using simplified analytical solutions and a 2D numerical simulator. Pressure drawdown, buildup, and isochronal tests simulated in this work indicate that, despite high fracture permeability, skin damage may accentuate the non-Darcy flow effect and drastically influence pressure-transient characteristics of low-pressure, naturally fractured reservoirs. In high-pressure reservoirs, this effect is significant only at high rates. Non-Darcy flow does not usually mask the typical pressure-transient characteristics of dual-porosity and dual-permeability reservoirs, but the conventional interpretation of the early-time data may lead to erroneous results. If the exponent, n, of the isochronal tests approaches 0.5 while the matrix permeability is low and flow rate is rather high, this would indicate the predominance of fracture flow. Under these conditions, small contributions from skin damage may greatly reduce gas-well performance in naturally fractured reservoirs.
Paper 2006-162: Pressure-Transient-Analysis of Horizontal Wells with Transverse, Finite-Conductivity Fractures. M. Al-Kobaisi, E. Ozkan, H. Kazemi, and B. Ramirz. Presented at the Petroleum Society’s 7th Canadian International Petroleum Conference (57th Annual Technical Meeting) Calgary, Alberta Canada, 13-15 June 2006.
Abstract: This paper discusses the analysis of pressure-transient responses of horizontal wells intercepting finite-conductivity transverse fractures. We use a hybrid, numerical-analytical model to simulate the impact of the fracture properties on the early-time flow regimes and pressure transient characteristics of fractured horizontal wells. It is shown that the fractured geometry and well location strongly influence the flow convergence in a horizontal-well fracture and lead to early-time flow regimes different from vertical-well fractures. Accordingly, appropriate pressure-transient models and analysis procedures should be used to determine fracture properties. We present straight-line analysis equations for radial-linear and pseudo-bilinear flow regimes for circular and rectangular fractures, respectively. We also bring the conventional fracture half-length and conductivity concepts into perspective and question the assumption that the properties estimated from pressure transient test of horizontal-well may be taken as effective properties when fractures are not rectangular. We show that flow convergence toward the wellbore may increase non-Darcy flow within the fracture. If the additional pressure drop because of flow choking and non-Darcy flow is not taken into account, pressure-transient test indicate smaller effective conductivity or fracture size. Because this additional pressure-drop is flow rate dependent, the estimated effective fracture properties are not useful for performance prediction purposes.
SPE 92040: A Hybrid Numerical/Analytical Model of a Finite-Conductivity Vertical Fracture Intercepted by a Horizontal Well. M. Al-Kobaisi, E. Ozkan, and H. Kazemi. Presented at the 2004 SPE international Petroleum Conference in Puebla, Mexico, 7-9 November, and revised for publication. Paper peer approved 17 May 2006.
Abstract: This paper presents a hybrid numerical/analytical model for the pressure-transient response of a finite-conductivity fracture intercepted by a horizontal well. The model dynamically couples a numerical fracture model with an analytical reservoir model. This approach allows us to include finer details of the fracture characteristics while keeping the computational work manageable. For example, the fracture may have irregular shape, nonuniform width, and variable conductivity, and the well may not intersect the fracture at its geometric center.
In this paper, we use the hybrid model to investigate the effects of fracture properties on the pressure-transient characteristics of a single, finite-conductivity horizontal-well fracture. The single horizontal-well-fracture model can be extended easily to multiply fractured horizontal wells by superposition. The model also can be used to compute the pseudoskin caused by the effects of nonideal fracture geometry, variable conductivity, and flow choking around the wellbore and to investigate the influence of fracture properties on the performance of horizontal wells.
2005
SPE 77534: Effects of Formation Damage and High-Velocity Flow on the Productivity of Perforated Horizontal Wells. Y. Tang, T. Yildiz, E. Ozkan, and M. Kelkar. Presented at the 202 SPE Annual Technical Conference and Exhibition, San Antonio, TX, 29 September – 2 October and revised for publication. Paper peer approved 24 May 2005.
Abstract: A comprehensive semianalytical model has been built to investigate the effects of drilling and perforating damage and high-velocity flow on the performance of perforated horizontal wells. The model incorporates the additional pressure drop caused by formation damage and high-velocity flow into a semianalytical coupled wellbore/reservoir model. The reservoir model considers the details of flow in the vicinity of the wellbore, including 3D convergent flow into individual perforations, flow through the damaged zone around the wellbore and the crushed zone around the perforation tunnels, and non-Darcy flow in the near-wellbore region. The wellbore flow model includes the effect of frictional pressure drop. Both oil and gas wells are considered.
The expressions provided in this paper for additional pressure losses caused by perforating damage, drilling damage, and high-velocity flow can be used to optimize perforating parameters and decompose the total skin into its components (perforation pseudoskin, damage skin, and non-Darcy skin).
SPE 84292: Analysis of Interference Tests with Horizontal Wells. M. Al-Khamis, E. Ozkan, and R. Raghavan. Presented at the 2003 SPE Annual Technical Conference and Exhibition, Denver, 5-8 October, and revised for publication. Paper peer approved 24 May 2005.
Abstract: One of the common assumptions in horizontal-well interference-test analysis is to ignore fluid flow in and out of the horizontal observation well and represent it by a point. In some cases, the active well is also approximated by a vertical line source. Using a semianalytical model, this paper answers three fundamental questions:
• What is the critical distance between the wells to represent the horizontal observation well by an observation point?
• Where should the observation point be placed along the horizontal well?
• Under what conditions may the active well be approximated by a vertical line source and the exponential integral solution be used to analyze observation-well responses?
Two correlations are presented to simplify the analysis of horizontal-well interference tests. Example applications are presented, and error bounds are documented.
SPE 93296: Interpretation of Skin Effect from Pressure Transient Tests in Horizontal Wells. A.M. Al-Otaibi, and E. Ozkan. Presented at the 14th SPE Middle East Oil & Gas Show and Conference in Bahrain International Exhibition Centre, Bahrain, 12-15 March 2005.
Abstract: Most horizontal wells have non-uniform distribution of skin along their lengths and this creates a challenging problem in the interpretation of their pressure-transient responses. The theory indicates that the rigorous incorporation of non-uniform skin distribution into horizontal well pressure-transient models requires the knowledge of not only the skin distribution but also the flow rate distribution into the horizontal well from the reservoir. Because this information is not normally available to the analyst, standard pressure interpretation techniques and tools assume uniform distribution of skin with the expectation that the estimates would correspond to some average of the skin distribution. The question that has not been adequately addressed in the literature is the physical meaning of the skin estimates from different pressure-transient analysis tools in common use. Because this question has not been adequately addressed, purely geometrical interpretations of the skin estimates have been proposed to calculate horizontal well productivities and develop flow models.
In this paper, we generate synthetic pressure-transient responses for different non-uniform skin distributions along a horizontal well and analyze these responses by using the conventional tools that assume uniform distribution of skin. Skin estimates from well-test interpretation are then compared with the known skin distributions.
The findings of this study are practical and important. First, the pressure drop caused by skin depends on the flow regimes if the skin distribution is non-uniform. Because the models used in commercial software assume the same additional pressure drop due to skin, the regression analysis can only match one of the flow periods for a constant skin value. To interpret the meaning of this skin estimate, we used the semi-log analysis techniques and demonstrated what type of average the estimated skin represents for different flow regimes and different skin distributions. For most cases, the estimates of skin from early-time radial flow analysis represent the arithmetic average of the skin distribution which may be useful for stimulation decisions. The skin estimate from the pseudo-radial flow period corresponds to the skin pressure drop at the heel of the horizontal well, which represents the additional pressure drop to be considered in the productivity calculations. We demonstrate that the geometric interpretation of the non-uniform skin effect proposed in the literature is inaccurate and leads to significant errors in the calculation of horizontal well productivity.
S. Atan, E. Ozkan, and H. Kazemi. Numerical Simulation of Multiphase Flow in Multiscale Heterogeneous Reservoirs Using Multimesh Computing Methodology. 2005.
Abstract: Despite the improvements in recovery from complex reservoirs, on the average, two-thirds of the original oil in place will be left behind. To improve the recovery further, successful reservoir monitoring and accurate modeling of fluid movement are essential. Reservoir monitoring requires building reservoir models that integrate various scales of data; typically geostatistical, seismic, saturation, and pressure/rate measurements. The common simulation approach is to treat all physical processes governing the fluid motion on the same spatial and temporal scale. This requires rescaling of the data to a convenient scale for simulation purposes. However, the upscaled properties, whether it is based on geostatistics or dynamic measurements from flow test, in general, do not provide satisfactory answers for simulation of complex, heterogeneous reservoirs. To accurately account for heterogeneity, multimillion grid simulators may be required, but this brings us to the question of practicality and may not be the correct recourse to deal with data-scale problems. An alternative is to develop reservoir models that use the natural scales of convective flow and pressure diffusion in an integrated computational scheme, known as multimesh computing methodology. In multimesh computation, the first step is to solve the pressure equation on the coarse grid, which is composed of several fine-grid cells per coarse grid cell. The second step is to compute the flow velocities at the boundaries of the coarse grid cells based on the pressure solution and interpolated onto the fine grid cells. Finally, the phase saturation is computed for each fine grid. In general, we solve the convective component flow problem on a fine-grid scale, as small as what geocellular models are. Consequently, we can obtain very accurate tracking of fluid movement in the reservoir reflecting the heterogeneity of the reservoir accurately.
SPE 93294: Dual-Mesh Simulation of Reservoir Heterogeneity in Single- and Dual- Porosity Problems. S. Atan, M. Al-Matrook, H. Kazemi, E. Ozkan, and M. Gardner. Presented at the 2005 Reservoir Simulation Symposium in Houston, TX, 31 January – 2 February 2005.
Abstract: This paper presents dual-mesh computing in simulation of reservoir heterogeneities in single- and dual-porosity reservoirs. The dual-mesh approach provides a great tool for computing displacement processes and saturation distribution on the same fine-grid as the underlying geological models and is also extremely powerful in simulation of naturally fractured, dual-porosity reservoirs. This approach may even be used for the fine-scale computations in compositional modeling of petroleum reservoirs. In principle, the dual-mesh computing surpasses the benefits of streamline simulation both in single and dual-porosity problems. Several convincing examples are presented to illustrate the broad applications. The reasons for the accuracy and efficacy of the dual-mesh computing are also explained.
SPE 93053: Multilevel Fracture Network Modeling of Naturally Fractured Reservoirs. H. Kazemi, S. Atan, M. Al-Matrook, J. Dreier, and E. Ozkan. Presented at the 2005 Reservoir Simulation Symposium in Houston, TX, 21 January 2005 – 2 February 2005
Abstract: This paper provides a review of common approaches for simulation of naturally fractured reservoirs and a new model formulation that is more amenable to the utilization of detailed geologic information from deterministic models, multipoint statistical simulations (MPS), and discrete fracture network (DFN) models. Unlike the common dual-porosity and dual-permeability models, the new model considers flow in several sets of fractures (that is, micro, macro, and mega fracture levels) and the wells can intercept any class of fractures. Matrix flow is also included in the formulation. A dual-mesh-computing algorithm is used to capture the major orientation of fractures in the flow network. The algorithm consists of the conventional five-point discretization for the coarse grid and a special nine-point discretization scheme for the fine grid. The size of the coefficient matrix for the discretization scheme can be reduced because of the dominance of vertical flow drainage in fractured reservoirs.
2004
SPE 91940: Dynamic Behavior of Discrete Fracture Network (DFN) Models. H. Araujo, P. Lacentre, T. Zapata, A. Del Monte, F. Dzelalija, J. Gilman, H. Meng, H. Kazemi, and E. Ozkan. Presented at the 2004 SPE international Petroleum Conference in Puebla, Mexico, 8-9 November 2004
Abstract: This work shows that discrete fracture network modeling is very desirable for the characterization of naturally fractured reservoirs but it is only a highly subjective starting point. Thus, calibration against short and long term pressure transient tests is most crucial. This paper shows how the dynamic behavior of a discrete fracture network model of Margarita gas field compared against pressure transient measurements in a sidetrack delineation-well. The performance comparison of a very fine-grid reservoir model, which included the discrete fracture network information, versus a much coarser upscaled grid model is also documented.
SPE 92039: New Analytical Pressure-Transient Models to Detect and Characterize Reservoirs with Multiple Fracture Systems. J. Dreier, E. Ozkan, and H. Kazemi. Presented at the SPE international Petroleum Conference Held in Puebla, Mexico, 7-9 November 2004.
Abstract: This paper presents two new pressure-transient models for naturally fractured reservoirs. The analytical models consider flow in a quadruple-porosity system that consists of a triple-fracture network with a single-matrix system. The models are used to investigate the pressure-transient characteristics of quadruple-porosity systems. They can also be used to detect, characterize, and simulate naturally fractured reservoirs with quadruple-porosity characteristics. It is shown that the fracture interconnectivity can be determined from pressure-transient tests if the combined fracture storativity is sufficiently large and the matrix contribution can be unambiguously isolated. Regression analysis of pressure-transient tests in naturally fractured reservoir with quadruple-porosity behavior is also discussed. It is demonstrated that the standard regression techniques are very sensitive to the scatter of the pressure vs. time data.
SPE 89880: Streamline Simulation of Countercurrent Water-Oil and Gas-Oil Flow in Naturally Fractured Dual-Porosity Reservoirs. J. Moreno, H. Kazemi, and J. R. Gilman. Presented at the SPE Annual Technical Conference and Exhibition in Houston, TX, 26-29 September 2004.
Abstract: The flow of hydrocarbons in naturally fractured reservoirs is a very complex process involving the interaction of reservoir fluids with two distinct porous media. Accurate simulation of the physics of flow and fast execution of the resulting complex numerical code is fundamental in developing a viable tool for reservoir development and management. This paper addresses this issue by developing and evaluating a basic 3-D streamline reservoir simulator for counter-current water-oil flow in naturally fractured dual-porosity reservoirs. The concept is readily extended to counter-current gas-oil gravity drainage in such reservoirs.
In the water-oil case, the counter-current flow of water and oil between the fracture and matrix media is generally attributed to water imbibition process. However, in oil-wet or mixed-wet rocks, the water imbibition could be non-existent, small, or strongly saturation-dependent. In these cases, given the right conditions, gravity potential can enhance oil drainage. These physical concepts are included in the simulator.
In the gas-oil case, the capillary forces generally resist the gravity potential; thus, preventing counter-current flow of oil and gas. With proper placement of gas-oil contact in the fractures, the gravity potential can overcome the capillary resistance to invoke gas-oil gravity drainage. We will demonstrate how such a formulation can be included a dual-porosity streamline simulator.
In the simulator, we apply an incompressible flow assumption to the fracture network in order to solve the 3-D water-oil displacement problem using a set of 1-D streamlines. Simple, but realistic, transfer functions, handle the matrix-fracture counter-current flow. These transfer functions depend on fracture-matrix relative permeability and capillary pressure functions, as well as the local gravity potential. A simpler, but perhaps more realistic, form of the transfer function is determined experimentally as a scaleable fractional oil recovery curve versus an appropriate dimensionless time. The transfer functions include other conventional reservoir properties such as permeability, porosity, and shape factor.
The simulator was used to model several water-oil displacement test cases and the results were compared with Eclipse 100 dual-porosity model results. The comparisons were favorable and the differences in results were consistent with the difference in the simulation approach.
We believe the streamline simulation of dual-porosity reservoirs could become an important tool for evaluating and managing fractured dual-porosity reservoirs. Because of the efficiency of the formulation, larger, more realistic geologic models can be modeled as compared to conventional simulators. For instance, simulating the frontal advance of the gas-oil contact in fractures, to invoke gravity drainage without gas breakthrough, can be accurately and efficiently handled using the formulation described here. Similarly, the breakthrough of water in fracture channels can be accurately simulated for very complex geologic models.
2003
SPE 84294: Estimation of Storativity Ratio in a Layered Reservoir with Crossflow. N. M. Al-Ajmi, H. Kazemi, and E. Ozkan. Presented at the SPE Annual Technical Conference and Exhibition held in Denver, CO, 5-8 October 2003.
Abstract: This paper presents a practical method to estimate the storativity ratio of a layered reservoir with cross-flow from pressure transient data. The method uses an analytically derived formula for the storativity ratio in terms of the separation between the two semi-log straight lines on pressure versus log-time plot. Knowing the storativity ratio from a well test, individual layer properties may be estimated if the layer flow rates are available from production logs. Demonstrations of the method to estimate the storativity ratio and individual layer properties are presented by examples. Comparison of the results with those obtained from the existing techniques is also provided to highlight the accuracy of the proposed technique.