Ibrahim Sami Nashawi

Prediction of Water Influx of Edge-Water Drive Reservoirs Using Nonparametric Optimal Transformations

The accurate estimation of water influx into a petroleum reservoir is very important in many reservoir engineering applications, such as material balance calculation, design of pressure maintenance programs, and advanced reservoir simulation studies. These applications have heavily relied on the classical work of van Everdingen and Hurst for finite and infinite edge-water drive reservoirs. However, for both types of water drive reservoirs, the calculation of water influx is not a straight forward task. Table lookup and interpolation between time entries are needed, and furthermore for finite aquifers, interpolation between tables may be also required. The paper presents nonparametric optimal transformations models for the prediction of dimensionless water-influx and dimensionless pressure drop for finite and infinite edge-water drive reservoirs using Graphical Alternating Conditional Expectation (GRACE). In order to achieve maximum efficiency, all the terms involved in the models are used in dimensionless form. GRACE transformations are totally data driven and do not assume any a priori functional form. The results of the various cases are in excellent agreement with the original tables of van Everdingen and Hurst. Introduction Petroleum reservoirs are often surrounded from the edge or the bottom by water aquifers that support the reservoir pressure through water influx. In response to a pressure drop in the petroleum reservoir, the water aquifer reacts to offset, or retard, pressure decline by providing a source of water influx or encroachment. To determine the effect that an aquifer has on the oil and gas production, it is important to estimate the amount of water that has entered into the reservoir from the aquifer. Such calculation is not a simple and risk-free task due to the involvement of many unknown parameters. For instance, aquifer pressure, thickness, permeability, porosity, shape, and areal extent are usually all unknown variables. Furthermore, water aquifer models are classified according to the flow geometry as either edge-water or bottom-water drive (Figures 1 and 2). These models have completely different flow behavior. The type of the water aquifer, its size, properties, and the amount of water that it can deliver into the reservoir for a certain pressure drop during a specific period of time affect the entire production life of the reservoir. A good knowledge of the aquifer properties, specifically the amount of water that it can provide into the reservoir, dictates the production schedule and the development strategies that need to be implemented in order to optimize oil recovery. Many authors have presented different models for estimating the water influx. These models apply to different flow regimes, including steady-state, modified steady-state (Schilthius, 1963), pseudo-steady-state (Hurst, 1943; 1958; Leung, 1986), and unsteady-state (Fetkovitch, 1971; Leung, 1988). van Everdingen and Hurst (1949) presented the most commonly used water-influx model. This model is basically a solution of the radial diffusivity equation; hence, it yields an accurate estimate of water encroachment for practically all flow regimes, provided that the flow geometry is actually radial. van Everdingen and Hurst solutions are for both the constant-terminal-rate case and the constant-terminal-pressure case of finite and infinite edge-water aquifers. Coats (1962) developed a model that takes into consideration the vertical flow of water into the reservoir. However, his model has two major drawbacks: (1) the presented solution is for the constant-terminal-rate case only, which permits the calculation of the pressure from a known water influx rather than the reserve, and (2) the model is only applicable to infinite aquifers and

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.

FLOW PROPERTIES OF WEATHERED CRUDE OILS AND THEIR EMULSIONS

ABSTRACT The present paper proposes the emulsification of weathered crude oils in water as a competitive and cost effective method for reducing their viscosities. Weathered crude oil samples were collected from major Kuwaiti oil lakes. Emulsion preparation involved using, either a nonionic surfactant or alkali, as well as both alkali and fatty acid. The obtained emulsions were characterized by measuring the droplet size distribution of the dispersed phase using optical microscopy. Emulsion stability was also examined in terms of the system breakdown. The rheological properties were measured using a concentric cylinder rotary rheometer. The emulsion rheological behavior has been studied as a function of composition, temperature, and shear rate. A constitutive model was developed to characterize the pseudoplastic behavior of the crude oil and the emulsion systems. The model fitted well the experimental results with a correlation coefficient higher than 95%. Associated with the pseudoplastic behavior, viscoe...

A Depletion Strategy for an Active Bottom-Water Drive Reservoir Using Analytical and Numerical Models—Field Case Study

Water coning is one of the most serious problems encountered in active bottom-water drive reservoir. It increases the cost of production operations, reduces the efficiency of the depletion mechanism, and decreases the overall oil recovery. Therefore, preventive measures to curtail water coning damaging effects should be well delineated at the early stages of reservoir depletion. Production rate, mobility ratio, well completion design, and reservoir anisotropy are few of the major parameters influencing and promoting water coning. The objective of this paper is to develop a depletion strategy for an active bottom-water drive reservoir that would improve oil recovery, reduce water production due to coning, delay water breakthrough time, and pre-identify wells that are candidates to excessive water production. The proposed depletion strategy does not only take into consideration the reservoir conditions, but also the currently available surface production facilities and future development plan. Analytical methods are first used to obtain preliminary estimates of critical production rate and water breakthrough time, then comprehensive numerical investigation of the relevant parameters affecting water coning behavior is conducted using a single well 3D radial reservoir simulation model. DOI: 10.1115/1.3177385

New Approach for Fracture Gradient Prediction Using Nonparametric Optimal Transformations— Field Applications in the Middle East

Abstract Accurate prediction of formation fracture gradient is essential to many petroleum-engineering operations. Proper planning and execution of deep abnormal pressure wells, stimulation treatment, and reservoir exploitation require, among other factors, good estimates of fracture gradient. It has been proven in the literature that most of the available fracture gradient correlations do not provide reliable results when exposed to data away from the geographical region where they were initially developed. A new approach for fracture gradient prediction based on nonparametric optimal transformations is presented. The transformations are totally data driven and do not assume any a priori functional form. The model presents the fracture gradient as a function of pore pressure gradient, rock density, and depth. The data set used in the study consists of more than 21,000 points taken from 16 wells drilled in seven different geologic prospects covering more than 200 mi2. The excellent results obtained from the proposed model establish a new simple tool for fracture gradient calculation that is based on readily accessible parameters. The proposed model is illustrated and validated using several examples from different fields in the Middle East. The results of the various cases confirm that the computed and the measured fracture gradient values are in excellent agreement with an average absolute relative error of 6% and a standard deviation of 0.05 psi/ft.

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.

PREDICTION OF LIQUID VISCOSITY OF PURE ORGANIC COMPOUNDS VIA ARTIFICIAL NEURAL NETWORKS

ABSTRACT Neural network models have been developed to estimate liquid viscosity of pure organic compounds at ambient temperature. These models employ different descriptors as characterizing parameters of the compounds. Three judgement criteria were imposed upon the proposed models: the accuracy of the obtained results, the type and number of the descriptors used as input parameters. The relative importance of the input variables was assessed. In all the cases analyzed, easily accessible properties of the organic compounds have been chosen as input parameters to train the neural network models. The number of the input properties was limited to a minimum without sacrificing the accuracy of the results A set of 110 data points covering a wide variety of organic compounds with a viscosity range of 0.197-19.9 mPa.s was employed in training the neural network models. The validity of the models was tested using 35 data points that were not included in the training set. The obtained results were compared with pre...

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.

Pressure buildup analysis of gas wells with damage and non-Darcy flow effect

This paper presents a technique to analyze pressure buildup test data of gas wells with damage and non-Darcy skin effect. This technique allows the analyst to estimate reservoir permeability and mechanical and rate-dependent skin factors directly by using 2 analysis plots. Formation permeability and rate-dependent skin are obtained from the slope and the intercept of the first plot, respectively, whereas the mechanical skin factor is determined from the intercept of the second plot. In addition, a graphical method to determine the reservoir pressure at infinite shut-in time is proposed. Field and simulated tests are presented to demonstrate the applicability of the technique. The results obtained are compared with new, conventional, and pressure derivative type curve matching techniques.