Fuad Qasem

Role of Capillary Imbibition in Partially Fractured Reservoirs

ABSTRACT Capillary imbibition is one of the major recovery mechanisms in naturally fractured reservoirs (NFR) where most of the oil is stored in tight matrices. Most of the imbibition studies of NFR assume uniform distribution of fractures. However, in reality most of NFR are partially fractured with various degrees of fracture intensities. Studies on imbibition phenomena in partially naturally fractured reservoirs (PNFR) are yet to be fully investigated. Thus, this paper investigates the effectiveness of capillary imbibition phenomena for PNFR with various fracture intensities (FI). We define FI as the ratio of fractured portion of the reservoir to total reservoir volume. Moreover, the study shed lights on the effect of water injection rate on the performance of PNFR. In this paper, a random distribution of fractures is assumed to simulate irregularity of fracture network. A dual-porosity/dual-permeability model is used to simulate the water-oil displacement phenomenon. Results show that the FI significantly affects the reservoir performance. Reservoirs with high FI are dominated by counter-current capillary imbibition phenomenon. Conversely, reservoirs with low FI are dominated by co-current capillary imbibition phenomenon. For reservoirs with intermediate FI, both phenomena have a critical role and the recovery is adversely affected.

Detection of pressure buildup data dominated by wellbore phase redistribution effects

Abstract This paper presents a new diagnostic technique that detects the presence of any type of phase redistribution pressure response and determines the true beginning of the semilog straight line for conventional analysis techniques. The method can also be used to predict the end of any wellbore effects. This greatly enhances the conventional analyses and yields more accurate estimation of the reservoir parameters. The technique is based upon existing analytical solutions for radial flow in homogenous reservoirs. The proposed method is simple and straightforward. It does not require manual or automatic type curve matching and it does not use complicated nonlinear optimization or history matching as some other methods necessitate. The applicability and accuracy of the proposed method are demonstrated through the analysis of three simulated cases and two field examples.

Characterizing miscible displacements in heterogeneous reservoirs using the Karhunen-Loéve decomposition

Abstract The article describes the application of the Karhunen–Loéve (K–L) decomposition in characterizing miscible displacements in geostatistically generated permeable media. A large number of simulation runs were performed in several heterogeneous reservoirs, each with different dimensionless scaling groups, and the spatial fluid concentrations were mapped at various times. The heterogeneous permeable media were generated geostatistically using the Matrix Decomposition Method with various degrees of permeability variations and correlation lengths. A finite difference numerical simulator (UTCHEM) has been used for this purpose. Results show that the correlation length and the permeability variation significantly affect the performance of miscible displacements and the transition between gravity-dominated and viscous-dominated displacements. The K–L decomposition was then used to determine an optimum set of eigenfunctions representing the coherent structure of all the simulated data. Results show that these complex patterns arising from a large number of simulation runs can be described by twenty dominant eigenfunctions. From these eigenfunctions and the eigenvalues associated with them, one can in principle predict the results of a simulation run without actually performing the run. These include the prediction of the fluid distribution in time and space as well as the production history curve.

Transient pressure analysis of gas wells producing at constant pressure

Abstract A comprehensive investigation of the validity of applying the constant-pressure liquid solution to transient rate-decline analysis of gas wells is presented. Pseudo-pressure, non-Darcy flow effects, and formation damage are incorporated in the liquid solution theory to simulate actual real gas flow around the wellbore. The investigation shows that for constant-pressure gas production, the conventional semilog plot of the inverse of the dimensionless rate versus the dimensionless time used for liquid solution must be modified to account for high-velocity flow effects. Especially when reservoir permeability is higher than 1 md and the well test is affected by non-Darcy flow and formation damage. In addition, a systematic method for determining formation permeability, mechanical skin factor, and non-Darcy flow coefficient from a single constant-pressure production test also is presented. The working equations are written to allow graphical analysis of the variable rate with time that is analogous to analysis of the constant-rate production test. The procedure is simple and straightforward. It does not require type-curve matching or correlations. The applicability of the proposed method is illustrated using several simulated examples. The input formation permeability varies from 0.1 to 5 md. The ratio of the bottomhole pressure to the initial reservoir pressure ranges from 0.1 to 0.8.

Modeling Inflow Performance Relationships for Wells Producing From Two-Layer Solution-Gas Drive Reservoirs Without Cross-Flow

Abstract Continuous monitoring and accurate anticipation of the present and future performance of the flowing wells and reservoirs constitute the cornerstone elements in the design of optimum field development strategy. It is crucial for the petroleum engineer to possess the appropriate tools that assist in efficiently predicting well behavior, designing artificial lift equipment, forecasting production, and optimizing the entire production system. Inflow performance relationship (IPR) is one of the vital tools required to monitor well performance. Existing inflow performance relationship models are idealistic and mainly designed for homogeneous reservoirs. However, most reservoirs around the world are heterogeneous and composed of layers of different permeabilities. Hence, there is an urgent need for new realistic IPR models that describe the actual reservoir inflow performance behavior more efficiently than the available models. The authors investigate the effects of reservoir heterogeneity on IPR curves for wells producing from two-layer solution-gas drive reservoirs without cross-flow. Furthermore, the results provide the petroleum engineer with two simple yet accurate IPR models for heterogeneous reservoirs. The first model represents the IPR of the well under present flowing conditions, while the second model is used to forecast future well deliverability.

Tracer response in partially fractured reservoirs

ABSTRACT There is considerable interest in the petroleum industry to characterize partially fractured reservoirs and to develop an increased understanding of the physics of fluid flow in these types of reservoirs. This is because fractured reservoirs have different behavior and there exist a large number of these reservoirs that are not fully developed. This paper presents a numerical simulation study that was performed to investigate the effect of rock properties on the tracer response in partially fractured reservoirs using a finite difference numerical simulator. These properties include fracture intensity, fracture porosity and matrix permeability. The functional relationships between these parameters and the calculated effective permeabilities are also investigated. Several images, each with different probability of fracture intensity, were generated randomly. Numerical simulations of single-phase tracer transport were then performed in each of the generated fractured models. Results show that the fracture intensity, fracture porosity and matrix permeability have a significant effect on the tracer response in naturally fractured reservoirs. Depending on the reservoir properties, the results also show that the flow in partially fractured reservoirs can be either matrix-dominated or fracture-dominated. The characteristics of each regime and the conditions for its occurrence are presented.

Inflow performance relationships for layered solution-gas drive reservoir

Inflow performance relationship (IPR) is a very important tool to forecast well performance. Existing IPR models are idealistic since they are developed for homogeneous reservoirs; therefore, they are inappropriate for layered systems. Consequently, there is a need for IPR models that efficiently describe layered reservoir performance. This study investigates the effects of reservoir heterogeneity on IPR for layered solution-gas drive reservoirs. Multiphase flow in both two and multilayer reservoirs was simulated. Both fluid cross flow and no fluid cross flow among layers were considered. A stochastic simulation algorithm was used to generate various permeability realisations among layers. Three geostatistical models using uniform, Gaussian, and bimodal probability distributions were used to grasp optimum match between real reservoir behaviour and simulated data. The generated data were scrutinised to develop two accurate IPR equations. The first equation describes the well behaviour under current flowing conditions, whereas the second equation can be used to forecast future well performance.

Modeling Inflow Performance Relationships for Wells Producing from Multi-Layer Solution-Gas Drive Reservoirs

Optimum field development strategy requires good knowledge of anticipated well performance and future flowing condition variation. This practice involves continuous monitoring of surface facility network, wells, and reservoir. Thus, it is crucial for the petroleum engineer to possess the appropriate tools to efficiently forecast well behavior, design artificial lift equipment and stimulation treatments, forecast production, and improve the entire production system optimization. Inflow performance relationship (IPR) is one of the vital tools required to monitor well performance. Currently used inflow performance relationship models are idealistic in nature, mainly developed for homogeneous reservoirs, and not suitable for multi-layer systems with different permeabilities. Consequently, the available IPR relationships do not provide accurate performance of such reservoirs. Thus, there is an urgent need for new realistic IPR models that describe the actual reservoir inflow performance behavior more efficiently than t he available models. This study investigates the effects of reservoir heterogeneity on IPR curves for wells producing from multi-layer solutiongas drive reservoirs. To achieve the desired objectives a stochastic simulation algorithm known as simulated annealing was used to generate various permeability realizations among the stacked layers. The generated data were then thoroughly scrutinized and two simple yet accurate empirical IPR models were developed for heterogeneous two and multi-layer solutiongas drive reservoirs. Introduction In reservoir studies, Inflow Performance Relationship (IPR) of a well is an essential tool to assess the well performance. It indicates the production behavior of a well and it will assist in determining the feasibility of producing a well. The IPR curve visualizes the relationship between the well’s producing bottomhole pressures and its corresponding production rates under a given reservoir condition. The shape of the curve is influenced by many factors such as the reservoir fluid composition, the existence of well zones, and the behavior of the fluid phases under reservoir flowing conditions. Gilbert introduced IPR curves in 1954 and through the years, these curves had several modifications. In 1968, Vogel introduced a mathematical dimensionless model for wells producing in bounded solution-gas drive reservoirs where the average reservoir pressure is less than the bubble-point pressure. Standing (1970, 1971) introduced a modified version of Vogel’s curve to characterize a well performance for damaged wells and different depletion stages. In 1973, Fetkovich showed that the performance curve for an oil well can be expressed by a more general equation similar to that used for a gas well. His developed equation was found to be valid for tests conducted for a variety of reservoir conditions even when the flowing pressures were well above the bubble-point pressure. Through time, IPR curves have been utilized in different applications in the petroleum industry. Weiss et al. (1981) employed a method of individual zone productivity combined with IPR testing to characterize two prolific offshore oil fields. Later, Brown (1982) combined well-inflow performance with tubing intake curves to prepare pressure/flow rate diagrams in order to properly select the best artificial lift method. Chu and Evans (1983) used a computer-based analysis to find the optimum production design for a naturally flowing water drive wells. They developed a group of graphs that are derived based on the performance of IPR, vertical lift, choke, horizontal flow, and the surface equipments thermodynamics. To eliminate the need for conventional multipoint tests, Mishra and Caudle (1984) developed a new method to calculate the IPR curves for stabilized non-Darcy flow in unfractured gas reservoirs. On the other hand, other studies developed dimensionless IPR curves for fractured gas wells with positive, negative or zero skin effect