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Djebbar Tiab

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Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the SPE Permian Basin Oil and Gas Recovery Conference, May 15–17, 2001

Paper Number: SPE-70035-MS

Abstract

Abstract Numerous waterflooding projects are under way throughout the world for increased recovery. Water injection tests of oil zones are frequently undertaken during the planning phase of waterfloods. Analysis of the bottomhole pressure data recorded during these tests not only provides similar information to that obtained from production tests concerning the well and the reservoir characteristics but also allows the mobility ratio between the injected and resident fluids to be determined. Conventionally, pressure fall-off test data is analyzed using semilog plot of bottomhole pressure versus time. This paper is the extension of the Tiab's Direct Synthesis Technique 10–15 to pressure injection and Fall-off tests in water injection wells. Direct synthesis is a transient pressure analysis technique 10–15 , which uses log-log plot of pressure and pressure derivative vs. time. Thus, different straight line portions indicating different flow regions are directly analyzed. Direct synthesis is very useful in conditions of short and early time pressure data missing tests. It also verifies the results since it uses more than one equation for the estimation of reservoir parameters such as permeability, wellbore storage coefficient, and skin factor. Finally, field examples of pressure falloff analysis are presented to illustrate use the direct synthesis and results are compared with those from type curves and conventional semilog analysis. Introduction Traditionally water flood schemes have been implemented later in the life of the field following primary depletion. Now, such schemes are often considered during the initial development of a field. The economic viability of many fields depends upon successful implementation of water injection at early stage. Injection tests are, therefore, performed on appraisal wells drilled prior to the decision to develop the field. These tests are designed to assess both the efficiency of the filtration equipment and the injection characteristics of the formation. Operational and the cost considerations dictate that the maximum possible information be derived from these tests, which may be few hours of duration. Analysis of the pressure Falloff and injectivity tests has been discussed at considerable length in the literature. The pressure buildup during injection period, however, has received relatively little attention. The main reason is that falloff tests match to the pressure buildup test in production wells, which is easy to analyze. Furthermore, the injectivity test is mathematically difficult to handle due to moving boundary, the flood front.

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the SPE Permian Basin Oil and Gas Recovery Conference, May 15–17, 2001

Paper Number: SPE-70062-MS

Abstract

Abstract Hydraulic fracturing has generally been limited to relatively low-permeability reservoirs. In recent years, the use of hydraulic fracturing has expanded significantly to high permeability reservoirs. The objectives of fracturing low permeability reservoirs and high permeability reservoirs are different and defined by reservoir parameters. The estimation of reservoir permeability, a variable of great importance in hydraulic fracturing design is frequently unknown because candidate wells either do not flow or a pretreatment pressure transient test is required. Consequently, Nolte has introduced a new method for adding after-closure fracturing analysis to the pretreatment calibration testing sequence that defines fracture geometry and fluid loss characteristics. The exhibition of the radial flow is ensured by conducting a specialized calibration test called mini-fall test. The derivations by Nolte, based on the theory of impulse test and principle of superposition, allow the identification of radial flow and thus the determination of reservoir transmissibility and reservoir pressure. This study presents a review of the after-closure radial flow analysis. A modified method is proposed to complete the Nolte's method for the determination of the reservoir transmissibility and reservoir pressure based on the pressure derivative. The application of the modified method is demonstrated on actual field data from calibration tests performed on several oil and gas wells. The reservoir parameters determined with this method are verified by comparison with results obtained from buildup tests. Introduction Hydraulic fracturing has been recognized to be an effective means for enhancing well productivity and recoverable reserves, especially for low permeability reservoirs, by reducing the resistance to flow area between the wellbore and formation. The appropriate fracturing treatment for a given well has been hard to design because of the numerous variables involved. The use of inaccurate reservoir variables to design treatments may lead to poor production estimates. In wells that are to be hydraulically fractured, minifracture treatment, called also calibration test, frequently is performed to determine parameters needed for the stimulation design. It is generally performed without proppant and therefore, retains negligible conductivity when it closes. Fracture pressure analysis was pioneered by Nolte 1,2 . The basic principles are analogous to those for pressure analysis of transient fluid in the reservoir. Both provide a means to interpret complex phenomena occurring underground by analyzing the pressure response resulting from fluid movement in rock formation. The analysis of fracturing pressure, during injection, during closing and after closure period, provide powerful tools for understanding and improving the fracture process. Advances in minifracture analysis techniques have provided methods for determination of fracturing treatment design parameters such as leak-off, fracture dimensions, fluid efficiency, closure pressure and reservoir parameters. These parameters can then be used to determine the pad volume required, best fluid loss additives to be used, and most importantly, to achieve the optimum fracturing treatment design. Fig. 1 shows a typical history of the calibration test from the beginning of pumping until the reservoir disturbance from the fracture decays back to the initial reservoir pressure. Fracturing pressures during each stage of fracture evolution (i.e. growth, closing and after-closure) provide complementary information pertinent to the fracture design process. Therefore, Fracturing pressure analysis may be reduced to three distinct types of analysis.

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the SPE Permian Basin Oil and Gas Recovery Conference, May 15–17, 2001

Paper Number: SPE-70017-MS

Abstract

Abstract This paper investigates the effect of higher concentrations (0–100%) of CO 2 , H 2 S, and N 2 on natural gas well deliverability, reserve estimation, and pressure test analysis quantitatively. Physical properties of natural gases such as viscosity and compressibility are corrected according to the concentrations of the contaminant gases such as CO 2 , N 2 , and H 2 S present in it. These contaminant gases have profound impact on pressure test analysis. The Carr et al 1 viscosity correction chart allows adjusting the viscosity up to 15% concentration of these contaminant gases. However, Wichert and Aziz 2 compressibility correction chart allows up to 80% concentration of the CO 2 and H 2 S. Tiab 3 developed an analytical method to estimate pseudopressure function for 0–100% combined-concentration of CO 2 , H 2 S, and N 2 . His pseudopressure was first re-plotted to simplify the procedure and then it was used to analyze the deliverability, pressure tests, and decline curves quantitatively. The analysis was performed with Carr et al 1 viscosity correction chart, pure CO 2 properties, and then with Tiab's corrected pseudopressure. Pure CO 2 properties were used due to the fact that the sample data has 98.256% CO 2 . During this study it was observed that the compressibility factor has a little effect on analysis since it is a volume-related property. Viscosity, however, has the largest effect on the analysis since pressure is transmitted through the fluid in the porous media and viscosity works against it. It was also observed that the numerical method of calculating pseudopressure function introduced successive error in the analysis. Number of pressure data points also contributed to theerrorinnumericalintegrationofthepseudo-pressure function. Analysis of field as well as simulated examples resulted an absolute error range of 13–75% in the permeability estimation in pressure tests, 77% in deliverability tests, and 20–95% with pressure derivative. Error in AOF was observed as 15% and as high as 32 % in reserve estimation. Introduction The High energy (Temperature and Pressure) environment and the presence of Oxygen rich compound turned many of the hydrocarbon reservoirs into CO 2 rich reservoirs. Such reservoirs usually are of low commercial value due to higher concentration of sour gases. Fig.1 shows the existence of CO 2 rich reservoirs in United States. Texas, New Mexico, Colorado, Mississippi, Wyoming, and Utah are the states with abundance of this natural resource. Two major consumers of CO 2 are the Chemical and Petroleum industries. Due to its miscibility in both water and oil, CO 2 has found its niche in EOR operations of miscible flooding. However, the potential for CO 2 flooding and its other application will be significant if it is found in enough quantity. Thus, its use and production as a natural resource requires the development of engineering techniques to analyze such reservoirs effectively.

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the SPE Permian Basin Oil and Gas Recovery Conference, May 15–17, 2001

Paper Number: SPE-70036-MS

Abstract

Abstract The analysis of oil production data using decline curves is a modeling and forecasting technique. Actual production rate and time data are history matched to a theoretical model using specialized graphs known as type curves. This study begins with a review of the previously developed decline curve construction and analysis methods. It consists of reproducing Arps-Fetkovich type curves and the derivative type curves for advanced decline curve analysis. A Program was developed to generate the dimensionless rate-pressure and time data necessary to construct Fetkovich type curves. Combining the analytical solution derivative for transient flow based on numerical analysis, and the empirical solution derivative for boundary dominated flow develops the derivative type curves. The type curves is used to identify the transient versus depletion stages and to estimate reservoir parameters and future decline paths. Field production data are generally difficult to match with the type curve for this reason a Universal Fitting Equation is proposed as an alternative to manual type curve matching. This equation combines both Arp's empirical equation and Fetkovich analytical solutions. It equation offer the following advantages: Fitting with the equation is more precise than type curve matching to obtain reservoir dimensionless radius reD, Arp's exponent b, matching points q/q Dd , and t Dd /t. The real production data can be fitted directly by the equation without using smoothing techniques. The radial and pseudosteady state regions are determined automatically and easily from fitting. Some production data that were insufficient to be analyzed with manual type-curve matching can be interpreted with the Fitting Equation. This procedure has been applied to some Real field data from Hassi Messaoud field cases and it has given significant results. Introduction Decline curves are the most common means of forecasting production and estimating the value of oil and gas wells. The earliest literature refers to a mathematical decline analysis approach presented by Arnold and Anderson in 1908. Arps developed the standard exponential, hyperbolic and harmonic decline equations in 1944. In 1973, Fetkovich 2 proposed a dimensionless rate-time type curve for decline curve analysis of wells producing at constant bottom-hole pressure. These type curves combined analytical solutions to the flow equations in the transient region and empirical decline curve equations in the pseudo-steady state region. This approach to decline curve analysis, known commonly referred to as "advanced decline curve analysis", has become widely used as a tool for formation evaluation and reserves estimation. In 1980, Fetkovich 2 demonstrated that decline curve analysis not only has a solid fundamental base but also provides a tool with more diagnostic power than had been previously suspected. Fetkovich 2 constructed log-log type curves, which combine all these equations developed by Arps 1 with the analytical constant pressure infinite and finite reservoir solutions. He showed that log-log type curves could be analyzed by the type curve matching technique. The uses of pressure derivatives in well test interpretation was introduced by Tiab 3 in 1975 and Bourdet et al. developed the use of derivative type curves for transient well test analysis in 1983. By multiplying the pressure derivative by the time, (or equivalently, by taking the derivative of pressure with respect to the natural log time), they were able to display both the pressure and the pressure derivative type curve on a single set of axes.

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the SPE Permian Basin Oil and Gas Recovery Conference, May 15–17, 2001

Paper Number: SPE-70012-MS

Abstract

Abstract In heterogeneous reservoirs like Hassi Messaoud, the exact interwell location of each reservoir sandstone body can not be in most cases easily located, and the potential of drilling unsuccessful production wells is usually present. In this situation a reservoir characterization model with usable uncertainties is needed. Conventional modeling techniques fail to quantify heterogeneities in lateral direction, however horiontal well data appear to compensate for this lack of information, providing some knowledge about variability of reservoir parameters, using data recorded along the horizontal drainhole of horizontal wells, hence providing adequate measurements of reservoir properties in the interwell locations. In this study a petrophysical model was generated for the north east area of Hassi Messaoud field comprising four horizontal wells. The generated models of porosity permeability and shale distribution were in agreement with Hassi Messaoud braided fluvial depositional model. The facies lateral variations have confirmed the nonuniform depletion throughout this sector of the field, which has led to its zonation. Once the reservoir characterization was complete, the generated model was validated using a full-field model of North East area, that involves history match of each well individually. Introduction For each target reservoir, many geostatistical realizations can be generated by integrating seismic, sedimentology, geology, and petrophisical data with their respective uncertainties captured by these models. Traditionally, reservoir description has been interpolated at the inter well locations, using simple algorithms, which fails to capture the true geological complexity and therefore results in ineffective prediction. To address this failure in the traditional route, one needs to consider using tools which allow the user to represent more accurately the range of plausible geological cases. Stochastic modeling techniques are used to construct detailed geological description using structural information, diagenetic and depositional models, reservoir stratigraphy, log and core data, and fault and fracture information. In most cases, adequate measurements of reservoir properties are not available to evaluate inter well variability at small scales. Information about lateral variations of reservoir parameters comes from horizontal wells or seismic data. Log data from horizontal wells have been used to improve inter well reservoir characterization, identify fractures and lateral variation of facies. Stochastic reservoir modeling is becoming commonly used tool to describe reservoir heterogeneities. It involves the generation of images of the reservoir lithofacies and rock properties that ideally, would honor all available data (Core measurements, well logs, seismic and geological interpretations, analog outcrops, well test interpretations, etc). Certain information, like production data or effective properties derived from well tests, can not be easily incorporated into the reservoir model. Almost always, a stochastic reservoir modeling exercise will involve a hybrid technique combining the best features of a number of available algorithms. Simulated annealing is an algorithm initially developed for the solution of combinatoin optimization problems. Generally, conventional modeling techniques fail to capture the true geological complexity of the reservoir in the lateral direction due to the lack of data in unsampled zones. In most field cases, only vertical well data representing a small fraction of the reservoir are available to describe the spatial distribution of reservoir properties. Horizontal wells, however, have emerged to quantify heterogeneities in the lateral direction because of their extended reach.

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the SPE Permian Basin Oil and Gas Recovery Conference, May 15–17, 2001

Paper Number: SPE-70013-MS

Abstract

Abstract This study investigates the effect of horizontal wellbore hydraulics on the early time dynamic behavior of horizontal wells. A finite conductivity model has been developed to couple infinite-conductivity horizontal well model based on uniform flux solution and finite conductivity wellbore hydraulic model. A sensitivity study is presented to show: The effect of horizontal well conductivity on production distribution along the wellbore at different time-steps, including early time radial flow, intermediate time linear flow and late time radial flow. The effect of wellbore length on the magnitude of wellbore-pressure drop under different values of Horizontal Well Conductivity, CH D , and Reynolds number, N Re . The effect of pipe roughness, Rp. The effect Reynolds number at the downstream end of the well, N Re . The new finite conductivity model is evaluated by setting a computer programs using Mathlab programming. The programs can include any friction factor correlation and production scheme. Type curves, of dimensionless pressure and pressure derivative versus dimensionless time, are obtained for different values of horizontal well conductivity and Reynolds number. These sets of curve can be used for type curve matching techniques. Correlations of the additional pressure drop due to finite conductivity solution over infinite conductivity solution, ?P D (t D ), are presented for different values of dimensionless well length, L D , horizontal well dimensionless conductivity, CH D , Reynolds number, Re, and pipe roughness, Rp. Introduction The magnitude of wellbore pressure drop has been considered negligibly small in order to satisfy the infinite conductivity and uniform flux idealization. However in some circumstances the pressure drop in the horizontal wellbore can have an effect on the horizontal well behavior. This is supported by the numerous studies incorporating the effect of pressure drop in horizontal well models. In practice, some pressure drop from the tip of a horizontal well to the producing end is needed to maintain fluid flow within the wellbore. As a result, the downstream end of the horizontal well will be subjected to a lower pressure than the upstream end. Hence, for better understanding of horizontal well behavior, a good estimate of the pressure drop within the horizontal portion of the well is needed. This estimation can help reservoir engineers in optimizing an individual completion and/or optimizing the depletion plan for a reservoir. The major reason for drilling a horizontal well is to produce with a higher flow rate at a lower reservoir pressure drawdown. Frictional pressure losses could be comparable to the pressure drop within the reservoir. In such a case, drilling a longer horizontal well may not enhance the productivity. In this study, a semi-analytical model is developed and a sensitivity study is performed on the parameters affecting finite conductivity pressure solution. Literature Review The intensive theoretical studies of horizontal wells over the last two decades have shown that the incorporation of horizontal wellbore hydraulics into the horizontal well model is a challenging issue. This section will review the relevant literature concerning the effect of hydraulics on horizontal well performance. Dikken 1 was the first to incorporate the effect of frictional wellbore pressure drop in horizontal well productivity. His basic assumption is that the productivity index per unit length of horizontal well is constant. He developed a second order differential equation to determine the wellbore flow rate at any location in the wellbore. He then solved analytically the differential equation for the case of infinite wellbore length and numerically for the actual case. Novy 7 extended Dikkin's 1 work to gas wells. Landman 8 and Halvorson 9 presented analytical solution to the non-linear differential equation. However, both of their solutions were limited to special cases.

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the SPE Permian Basin Oil and Gas Recovery Conference, May 15–17, 2001

Paper Number: SPE-70021-MS

Abstract

Abstract Oil recovery by miscible gas injection process has been a topic of research, development, and field testing for more than 40 years. There is still some disagreement in the interpretation of laboratory, field-test data and selection of predictive methods. Field experiments, however, have disclosed a number of problems with hydrocarbon miscible flooding that limit the oil recovery and diminish the economic attractiveness of these processes. Due to the fact that there is no generalized engineering method or model that adequately accounts for all the factors, each model tends to emphasize one or more aspects of the displacement while neglecting other aspects for the sake of tractability. A parametric study is done, using a 3-D, compositional numerical simulator "VIP" in order to design the model and analyze the results and performance of miscible gas injection in Hassi Berkine South field. A 9-component PR EOS was used to describe the phase behavior using IMPES formulation. The process of simulation study to design and optimize the full field model included the following steps: Start with a basic run, used as a reference case. 2) Compare the base case (miscible gas injection) with water injection process. 3) Consider the phase behavior effect. 4) The reservoir description effect. 5) Vertical sweep out. 6) Partial recovery of miscible flood. 7) Influence of grid variation. A cross sectional model was used to represent the simulation domain that covered about 5000 ft 2 in area and 100 ft in thickness. All the runs consisted of two wells, penetrating the entire layers, the injector in the first cell and the producer in the last one. From the results it has been concluded that the use of horizontal well data has compensated for lack of information about reservoir heterogeneity in lateral direction of the interwell locations. Introduction The term, "miscible fluid displacement", is defined as any oil-recovery displacement process, where there exists an absence of a phase boundary or interface between the displaced and the displacing fluids. Since there is no interface, consequently no IFT between the displacing fluid (i.e., the capillary number becomes infinite) and residual oil saturation can be reduced to it lowest possible value. Field testing and supporting laboratory research disclosed a number of problems with hydrocarbon miscible flooding that act to limit oil recovery and diminish the economic attractiveness of the process. For miscible displacement, to be a competitive process for a given reservoir, several conditions must be satisfied, because the incremental oil recovery is determined largely by reservoir properties and fluid characteristic (heterogeneity, fluids mobility, miscible sweepout, gravity stabilization, viscous fingering, etc.) Many researchers have worked on the reservoir engineering aspects of miscible flood design and performance. Important factors that need to be considered and carefully evaluated whether potentially take place. As yet, there is no generalized engineering method or model that adequately accounts for all factors which usually need to be considered. Each predictive method tends to emphasize one or more aspects of the miscible displacement, while neglecting other aspects for the sake of tractability. For this reason, a good understanding of basic miscible flood principles is required. Theory review For the discussion of predictive methods, we have to review some of the important factors that usually need to be evaluated in the design of the miscible flood performance.

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the SPE Permian Basin Oil and Gas Recovery Conference, March 23–26, 1998

Paper Number: SPE-39803-MS

Abstract

Abstract Reservoir evaluation of shaly formations has long been a difficult task. This in turn makes seeking enhanced reservoir description of shaly sand reservoirs much more difficult. This study develops four models and a systematic technique which incorporate conventional log-derived data to identify shale type and hydraulic flow units in shaly sand reservoirs. The four models were derived using available shale models: laminated shale, dispersed shale for low and high shaly formations, total shale, and the Waxman-Smits (W-S) "Cation Exchange Capacity" model. It is found that these four models possess common features in that each flow unit in any shaly sand reservoir can be represented by a straight line on a log- log plot of the "Shaly Reservoir Quality Index" (SRQI) versus porosity. This straight line representing the flow unit yields a unique slope that equal: [1.7 + (m/2)] for laminated shale, [1.7] for dispersed shale, [1.7 + (m/2)] for total shale model, and (1.7+m) for Waxman-Smits model. In addition, each flow unit has a characteristic intercept at (= 1.0 which is equal to the "Shaly Flow Unit Factor" (SFUF). This study also includes how to apply these models in order to define the shale type and identify different flow units constituting the shaly sand reservoir. These shaly sand models were validated using a simulated well-log data. The new models, in combination with the technique proposed in this study, represent an effective tool for an enhanced reservoir description of shaly sand reservoirs. In addition, it provides an economical technique due to its inherent use of conventional well log-derived data P. 427

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the SPE Permian Basin Oil and Gas Recovery Conference, March 23–26, 1998

Paper Number: SPE-39810-MS

Abstract

Abstract The purpose of this study is to develop new models capable of providing better description of the reservoir through the use of the concept of Reservoir Quality Index (RQI) combined with the available permeability models appearing in the literature. Six enhanced reservoir characterization models have been developed that incorporate core and/or conventional well-logging derived-data to identify hydraulic (flow) units. Two models are developed based on equation of Nuclear Magnetic Resonance (NMR) to identify flow units using core data. In addition, three flow unit models are developed based on Timur, Wyllie and Rose, and a generalized permeability equations. The sixth model is developed using Jorgensen permeability equation. It is found that each flow unit can be represented by a straight line on a log-log plot of the RQI versus porosity,, or versus the parameter()depending upon the permeability equation used. The straight line (representing the flow unit) yields various unique slopes for the different models. This depends upon the porosity exponent that appeared in the permeability equation. In addition, each flow unit model possesses a characteristic intercept on the NMR Decay time- # log-log plot, or on the RQI- # log-log plot, or on RQI() log- log plot. The new flow unit models are validated by using actual and simulated data. Use of the new models in combination with the systematic technique developed, 2. Is correlative and mappable at the interwell scale; represents effctive tools for enhancing reservoir characterization. P. 505

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the Permian Basin Oil and Gas Recovery Conference, March 27–29, 1996

Paper Number: SPE-35163-MS

Abstract

Abstract A new, alternative method, referred to as "direct synthesis", is proposed for interpretation of pressure tests in naturally fractured reservoirs. Direct synthesis utilizes the characteristic intersection points and slopes of various straight lines from a log-log plot of pressure and pressure derivative data. Values of these points are linked directly to the exact, analytical solutions to obtain reservoir or well parameters. The direct synthesis method offers the following advantages: accurate results from using the analytical equations to calculate reservoir parameters, independent verification is frequently possible from a third unique point, and useful information is obtained when not all flow regimes are observed, as a direct result of the additional characteristic values developed by the method. Application of this technique is presented for single-well pressure tests in an infinite-acting naturally fractured reservoir with pseudosteady state interporosity flow, including the effects of wellbore storage and skin. New analytical and empirical expressions were developed as a result of this work. These expressions are an integral part of the technique, providing the desired accuracy and versatility. Several field examples are given to clarify the technique and also illustrate the accuracy of the method. When possible, a comparative analysis with other methods is included. Background The basic equations for flow in naturally fractured reservoirs of dual porosity were originally formulated by Barenblatt, et al. Using continuum mechanics, the rock and flow parameters of the two media, fractures and matrix, are defined at each mathematical point. The transfer of fluid between the two media is maintained in a source function, where the flow is assumed to be pseudosteady state in the matrix system. Warren and Root used this approach to develop a comprehensive and applicable solution to pressure drawdown or buildup tests in a dual porosity, naturally fractured reservoir. From their work several flow regimes could be identified from semilog analysis. In chronological order there exist an early time, straight line representing fracture depletion only, a transition period when the matrix contribution to flow is dominant, and a late time, straight line which corresponds to the time when the entire reservoir produces as an equivalent homogenous reservoir. This late time, semilog straight line is parallel to the first straightline.

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the Permian Basin Oil and Gas Recovery Conference, March 16–18, 1994

Paper Number: SPE-27716-MS

Abstract

Abstract Unexpected early waterflood breakthrough in a high matrix porosity, Pennsylvanian age sandstone reservoir, indicated the possible presence of a high directional permeability fracture flow system superimposed on the matrix flow system. A simulation study was initiated to study this problem. Simulation history matching results showed that the fractures exhibited high directional permeability but low storage capacity relative to the matrix portion of the reservoir. A low fracture intensity index was calculated. This low storage capacity fracture system supports the hypothesis that the fracture system resulted from previous stimulation treatments rather than from an extensive naturally occurring fracture system. The recognition and quantification of this new model led to significant improvements in field production practices, well alignments, ultimate oil recovery and production forecasting. Introduction Reservoir simulation was performed on a Pennsylvanian age fractured sandstone oil reservoir. The approximately 30 well field had produced about 700 MBO in seven years of primary production. A single vertical layer system was used since the sandstone, with log calculated porosity averaging 15%, exhibits good vertical homogeneity (Figure 1). Initial waterflooding, utilizing a near 5 spot pattern, was interrupted after only one month of injection when early water breakthrough was encountered in wells along lines east and west of the injection wells. A series of well tests and tracer surveys indicated that the early break through was caused by an unexpected east-west trending fracture system. P. 775^