Well Test Analysis: Wells Producing by Solution Gas Drive

1976 ◽  
Vol 16 (04) ◽  
pp. 196-208 ◽  
Author(s):  
R. Raghavan
Keyword(s):  
Porous Media ◽  
Multiphase Flow ◽  
Relative Permeability ◽  
Oil And Gas ◽  
Function Concept ◽  
Permeability Characteristics ◽  
Fluid Properties ◽  
Diffusivity Equation ◽  
Gas Drive ◽  
Solution Gas

Abstract Drawdown and buildup data in a homogeneous, uniform, closed, cylindrical reservoir containing oil and gas and producing by solution gas drive at a constant surface oil rate were investigated. The well was assumed to be located at the center of the reservoir. Gravity effects were not included. Though the reservoir systems studied were assumed to be homogeneous, the effect of a damaged region in the vicinity of the wellbore was examined. Recently, alternate expressions for describing multiphase flow through porous media have been presented. These expressions incorporate changes presented. These expressions incorporate changes in effective permeability and fluid properties (formation volume factor, viscosity, gas solubility) with pressure by means of a pseudopressure function. The validity of applying the pseudopressure-function concept to drawdown and pseudopressure-function concept to drawdown and buildup testing for multiphase-flow situations was investigated. The pseudopressure function for analyzing drawdown behavior is calculated difrerently from that required to analyze buildup data. Consequently, two pseudopressure functions are required for analysis of well behavior in multiphase-flow systems. Dimensionless groups are used to extend the results to other situations having different permeabilities, spacing, reservoir thickness, well permeabilities, spacing, reservoir thickness, well radii, porosity, etc., provided the PVT relations and relative-permeability characteristics are identical to those used in this study. The pseudopressure-function concept used to analyze pseudopressure-function concept used to analyze drawdown and buildup behavior extends the applicability of the results to a wide range of PVT relations and relative-permeability characteristics. Introduction During the past 30 years, more than 300 publications have considered various problems publications have considered various problems pertaining to well behavior. Except for a few (about pertaining to well behavior. Except for a few (about 10), most papers examining transient pressure behavior assume that the fluids in the reservoir obey the diffusivity equation. This implies the use of a single-phase, slightly compressible fluid. The reason for the popularity of this approach is twofold:(1)the ease with which the diffusivity equation can be solved for a wide variety of problems, and(2)the demonstration by some problems, and(2)the demonstration by some workers that, for some multiphase-flow situations, single-phase flow results may be used provided appropriate modifications are made. The necessary modifications are summarized in Ref. 1. The main objective of this study is to present a method for rigorously incorporating changes in fluid properties and relative-permeability effects in the properties and relative-permeability effects in the analysis of pressure data when two phases of oil and gas are flowing. This should enable the engineer to calculate the absolute formation permeability rather than the effective permeability to each of the flowing phases. This method is based on an idea suggested by Fetkovich, who proposed that if an expression similar to the real gas pseudopressure is defined, then equations describing pseudopressure is defined, then equations describing simultaneous flow of oil and gas through porous media may be simplified considerably. The validity of the equations and methods for calculating the pseudopressure function, however, was not presented pseudopressure function, however, was not presented by Fetkovich. LITERATURE REVIEW AND THEORETICAL CONSIDERATIONS General equations of motion describing multiphase flow in porous media have been known since 1936. These equations, and the assumptions involved in deriving them, are discussed thoroughly in the literature and will not be considered here. Equations for two-phase flow were first solved by Muskat and Meres for a few special cases. Evinger and Muskat studied the effect of multiphase flow on the productivity index of a well and examined the steady radial flow of oil and gas in a porous medium. Under conditions of steady radial porous medium. Under conditions of steady radial flow the oil flow rate is given by (1) SPEJ P. 196

Pressure Transient Analysis of a Vertically Fractured Well Produced by Solution Gas Drive

1977 ◽  
Vol 17 (05) ◽  
pp. 369-376 ◽  
Author(s):  
R. Raghavan
Keyword(s):  
Oil And Gas ◽  
Function Concept ◽  
Pressure Function ◽  
Pressure Transient ◽  
Permeability Characteristics ◽  
Solution Gas Drive ◽  
Fluid Properties ◽  
Gas Drive ◽  
Fractured Well ◽  
Solution Gas

Abstract Pressure transient data were investigated in a homogeneous and uniform reservoir containing oil and gas and producing at a constant surface oil rate by solution gas drive by means of a vertically fractured well. The well is assumed to be located at the center of a closed-square drainage area. Gravity effects were not included. To my best knowledge, this is the first study ort the pressure transient behavior of a vertically fractured well producing by solution gas drive. producing by solution gas drive. A recent paper presented a new method for analyzing pressure data in wells producing by solution gas drive. The method incorporates changes in effective permeability and fluid properties (formation volume factor, viscosity, and gas solubility) with pressure by means of a pseudo-pressure function however, it dealt exclusively pseudo-pressure function however, it dealt exclusively with plane radial flow. This paper presents the application of that new technique to vertically fractured wells. Dimensionless groups are used throughout to extend the results to other situations having different permeabilities, spacing, reservoir thickness, porosity, etc, provided the PVT relations and relative-permeability characteristics are identical to those used in this study. The pseudo-pressure function concept used to analyze pseudo-pressure function concept used to analyze drawdown and buildup behavior extends the applicability of the results to a wide range of PVT relations and relative-permeability characteristics. Introduction In recent years, the analysis of pressure data of fractured wells has received considerable attention. However, most of this work is related to single-phase flow. An examination of the literature indicated that no rigorous study has been made regarding the pressure behavior of a vertically fractured well producing by solution gas drive. The first objective of this paper is to discuss the transient floe, behavior of the system described above. The second objective is to demonstrate the applicability of a recent technique for determining absolute formation permeability when two phases (oil and gas) are flowing simultaneously. This technique is based on using a pseudo-pressure function that rigorously incorporates changes in permeability with saturation and fluid properties permeability with saturation and fluid properties with pressure. It will be shown that, by using the procedure suggested here, better estimates of procedure suggested here, better estimates of fracture length also can be obtained. LITERATURE REVIEW General equations of motion describing multiphase flow in porous media are well known and will not be discussed here. A summary of the work in this area as if pertains to well test analysis is presented in Ref. 5. This section briefly reviews only the computation of an integral (henceforth called the pseudo-pressure function), which was used in Ref. pseudo-pressure function), which was used in Ref. 5 to analyze drawdown and buildup. In a recent paper, Fetkovich suggested that if the pseudo-pressure function, m (p), given by: (1) is used, then transient, pseudo-steady-state and steady-state multiphase flow through porous media may be described by simple expressions similar to that for the flow of a slightly compressible fluid. For example, Fetkovich suggested that for transient radial flow one can express the flow rate as (2) where to is the dimensionless time given by (3) In Eq. 2, s' represents the skin effect that, in general, includes the effects of damage in the vicinity of the wellbore, as well as a skin effect caused by the development of a gas saturation. SPEJ P. 369

scholarly journals A Fractal Model for Predicting the Relative Permeability of Rough-Walled Fractures

2021 ◽  
Vol 2021 ◽  
pp. 1-10
Author(s):  
Zuyang Ye ◽  
Wang Luo ◽  
Shibing Huang ◽  
Yuting Chen ◽  
Aiping Cheng
Keyword(s):  
Porous Media ◽  
Multiphase Flow ◽  
Relative Permeability ◽  
Fractal Model ◽  
Numerical Results ◽  
Flow Paths ◽  
Capillary Model ◽  
Lognormal Distributions ◽  
Fractal Characteristics ◽  
Aperture Distribution

The relative permeability and saturation relationships through fractures are fundamental for modeling multiphase flow in underground geological fractured formations. In contrast to the traditional straight capillary model from porous media, the realistic flow paths in rough-walled fractures are tortuous. In this study, a fractal relationship between relative permeability and saturation of rough-walled fractures is proposed associated with the fractal characteristics of tortuous parallel capillary plates, which can be generalized to several existing models. Based on the consideration that the aperture distribution of rough-walled fracture can be represented by Gaussian and lognormal distributions, aperture-based expressions between relative permeability and saturation are explicitly derived. The developed relationships are validated by the experimental observations on Gaussian distributed fractures and numerical results on lognormal distributed fractures, respectively.

A NEW RELATIVE PERMEABILITY MODEL OF UNSATURATED POROUS MEDIA BASED ON FRACTAL THEORY

Fractals ◽  
2020 ◽  
Vol 28 (01) ◽  
pp. 2050002
Author(s):  
KE CHEN ◽  
HE CHEN ◽  
PENG XU
Keyword(s):  
Experimental Data ◽  
Porous Media ◽  
Fractal Dimension ◽  
Multiphase Flow ◽  
Relative Permeability ◽  
Volume Fraction ◽  
Fractal Model ◽  
Accurate Estimation ◽  
Unsaturated Porous Media ◽  
Flow Through

The multiphase flow through unsaturated porous media and accurate estimation of relative permeability are significant for oil and gas reservoir, grounder water resource and chemical engineering, etc. A new fractal model is developed for the multiphase flow through unsaturated porous media, where multiscale pore structure is characterized by fractal scaling law and the trapped water in the pores is taken into account. And the analytical expression for relative permeability is derived accordingly. The relationships between the relative permeability and capillary head as well as saturation are determined. The proposed model is validated by comparison with 14 sets of experimental data, which indicates that the fractal model agrees well with experimental data. It has been found that the proposed fractal model shows evident advantages compared with BC-B model and VG-M model, especially for the porous media with fine content and texture. Further calculations show that water permeability decreases as the fractal dimension increases under fixed saturation because the cumulative volume fraction of small pores increases with the increment of the fractal dimension. The present fractal model for the relative permeability may be helpful to understand the multiphase flow through unsaturated porous media.

scholarly journals Relative Permeability Characteristics During Carbon Capture and Sequestration Process in Low-Permeable Reservoirs

Materials ◽  
2020 ◽  
Vol 13 (4) ◽  
pp. 990
Author(s):  
Mingxing Bai ◽  
Lu Liu ◽  
Chengli Li ◽  
Kaoping Song
Keyword(s):  
Relative Permeability ◽  
Carbon Capture ◽  
Oil And Gas ◽  
Co2 Flooding ◽  
Two Phase ◽  
Permeability Characteristics ◽  
Gas Recovery ◽  
Miscible Flooding ◽  
Relative Permeability Curves ◽  
Carbon Dioxide Co2

The injection of carbon dioxide (CO2) in low-permeable reservoirs can not only mitigate the greenhouse effect on the environment, but also enhance oil and gas recovery (EOR). For numerical simulation work of this process, relative permeability can help predict the capacity for the flow of CO2 throughout the life of the reservoir, and reflect the changes induced by the injected CO2. In this paper, the experimental methods and empirical correlations to determine relative permeability are reviewed and discussed. Specifically, for a low-permeable reservoir in China, a core displacement experiment is performed for both natural and artificial low-permeable cores to study the relative permeability characteristics. The results show that for immiscible CO2 flooding, when considering the threshold pressure and gas slippage, the relative permeability decreases to some extent, and the relative permeability of oil/water does not reduce as much as that of CO2. In miscible flooding, the curves have different shapes for cores with a different permeability. By comparing the relative permeability curves under immiscible and miscible CO2 flooding, it is found that the two-phase span of miscible flooding is wider, and the relative permeability at the gas endpoint becomes larger.

scholarly journals Emerging Advances in Petrophysics: Porous Media Characterization and Modeling of Multiphase Flow

Energies ◽  
2019 ◽  
Vol 12 (2) ◽  
pp. 282 ◽  
Author(s):  
Jianchao Cai ◽  
Shuyu Sun ◽  
Ali Habibi ◽  
Zhien Zhang
Keyword(s):  
Porous Media ◽  
Multiphase Flow ◽  
Oil And Gas ◽  
Reservoir Characterization ◽  
Experimental Studies ◽  
Flow Modeling ◽  
Special Issue ◽  
Fractal Approach ◽  
Unconventional Resources ◽  
Oil And Gas Resources

With the ongoing exploration and development of oil and gas resources all around the world, applications of petrophysical methods in natural porous media have attracted great attention. This special issue collects a series of recent studies focused on the application of different petrophysical methods in reservoir characterization, especially for unconventional resources. Wide-ranging topics covered in the introduction include experimental studies, numerical modeling (fractal approach), and multiphase flow modeling/simulations.

Multiphase-Flow and Reactive-Transport Validation Studies at the Pore Scale by Use of Lattice Boltzmann Computer Simulations

SPE Journal ◽  
2017 ◽  
Vol 22 (03) ◽  
pp. 940-949 ◽  
Author(s):  
Edo S. Boek ◽  
Ioannis Zacharoudiou ◽  
Farrel Gray ◽  
Saurabh M. Shah ◽  
John P. Crawshaw ◽  
...  
Keyword(s):  
Porous Media ◽  
Multiphase Flow ◽  
Capillary Pressure ◽  
Computer Simulations ◽  
Relative Permeability ◽  
Lattice Boltzmann ◽  
Reactive Transport ◽  
Pore Space ◽  
Processing Unit ◽  
Space Images

Summary We describe the recent development of lattice Boltzmann (LB) and particle-tracing computer simulations to study flow and reactive transport in porous media. First, we measure both flow and solute transport directly on pore-space images obtained from micro-computed-tomography (CT) scanning. We consider rocks with increasing degree of heterogeneity: a bead pack, Bentheimer sandstone, and Portland carbonate. We predict probability distributions for molecular displacements and find excellent agreement with pulsed-field-gradient (PFG) -nuclear-magnetic-resonance (NMR) experiments. Second, we validate our LB model for multiphase flow by calculating capillary filling and capillary pressure in model porous media. Then, we extend our models to realistic 3D pore-space images and observe the calculated capillary pressure curve in Bentheimer sandstone to be in agreement with the experiment. A process-based algorithm is introduced to determine the distribution of wetting and nonwetting phases in the pore space, as a starting point for relative permeability calculations. The Bentheimer relative permeability curves for both drainage and imbibition are found to be in good agreement with experimental data. Third, we show the speedup of a graphics-processing-unit (GPU) algorithm for large-scale LB calculations, offering greatly enhanced computing performance in comparison with central-processing-unit (CPU) calculations. Finally, we propose a hybrid method to calculate reactive transport on pore-space images by use of the GPU code. We calculate the dissolution of a porous medium and observe agreement with the experiment. The LB method is a powerful tool for calculating flow and reactive transport directly on pore-space images of rock.

An Alternate Method to API RP 14E for Predicting Solids Erosion in Multiphase Flow

2000 ◽  
Vol 122 (3) ◽  
pp. 115-122 ◽  
Author(s):  
Brenton S. McLaury ◽  
Siamack A. Shirazi
Keyword(s):  
Multiphase Flow ◽  
Production Rate ◽  
Oil And Gas ◽  
Gas Production ◽  
American Petroleum Institute ◽  
Sand Production ◽  
Threshold Velocity ◽  
Oil And Gas Production ◽  
Sand Erosion ◽  
Fluid Properties

One commonly used method for determining oil and gas production velocities is to limit production rates based on the American Petroleum Institute Recommended Practice 14E (API RP 14E). This guideline contains an equation to calculate an “erosional” or a threshold velocity, presumably a flow velocity that is safe to operate. The equation only considers one factor, the density of the medium, and does not consider many other factors that can contribute to erosion in multiphase flow pipelines. Thus, factors such as fluid properties, flow geometry, type of metal, sand production rate and size distribution, and flow composition are not accounted for. In the present paper, a method is presented that has been developed with the goal of improving the procedure by accounting for many of the physical variables including fluid properties, sand production rate and size, and flowstream composition that affect sand erosion. The results from the model are compared with several experimental results provided in the literature. Additionally, the method is applied to calculate threshold flowstream velocities for sand erosion and the results are compared with API RP 14E. The results indicate that the form of the equation that is provided by the API RP 14E is not suitable for predicting a production flowstream velocity when sand is present. [S0195-0738(00)00203-X]

An Experimental Investigation of Viscous-Oil Recovery Efficiency as a Function of Voidage-Replacement Ratio

SPE Journal ◽  
2016 ◽  
Vol 21 (04) ◽  
pp. 1236-1253 ◽  
Author(s):  
Tae Wook Kim ◽  
E.. Vittoratos ◽  
A. R. Kovscek
Keyword(s):  
Relative Permeability ◽  
Oil Recovery ◽  
Crude Oils ◽  
Replacement Ratio ◽  
Two Phase ◽  
Foamy Oil ◽  
Three Phase ◽  
Solution Gas Drive ◽  
Gas Drive ◽  
Solution Gas

Summary Recovery processes with a voidage-replacement ratio (VRR) (VRR = injected volume/produced volume) of unity rely solely on viscous forces to displace oil, whereas a VRR of zero relies on solution-gas drive. Activating a solution-gas-drive mechanism in combination with waterflooding with periods of VRR less than unity (VRR < 1) may be optimal for recovery. Laboratory evidence suggests that recovery for VRR < 1 is enhanced by emulsion flow and foamy (i.e., bubbly) crude oil at pressures under bubblepoint for some crude oils. This paper investigates the effect of VRR for two crude oils referred to as A1 (88 cp and 6.2 wt% asphaltene) and A2 (600 cp and 2.5 wt% asphaltene) in a sandpack system (18-in. length and 2-in. diameter). The crude oils are characterized with viscosity, asphaltene fraction, and acid/base numbers. A high-pressure experimental sandpack system (1 darcy and Swi = 0) was used to conduct experiments with VRRs of 1.0, 0.7, and 0 for both oils. During waterflood experiments, we controlled and monitored the rate of fluid injection and production to obtain well-characterized VRR. On the basis of the production ratio of fluids, the gas/oil and /water relative permeabilities were estimated under two-phase-flow conditions. For a VRR of zero, the gas relative permeability of both oils exhibited extremely low values (10−6−10−4) caused by internal gas drive. Waterfloods with VRR < 1 displayed encouraging recovery results. In particular, the final oil recovery with VRR = 0.7 [66.2% original oil in place (OOIP)] is more than 15% greater than that with VRR = 1 (55.6% OOIP) with A1 crude oil. Recovery for A2 with VRR = 0.7 (60.5% OOIP) was identical to the sum of oil recovery for solution-gas drive (19.1% OOIP) plus waterflooding (40.1% OOIP). An in-line viewing cell permitted inspection of produced fluid morphology. For A1 and VRR = 0.7, produced oil was emulsified, and gas was dispersed as bubbles, as expected for a foamy oil. For A2 and VRR < 1, foamy oil was not clearly observed in the viewing cell. In all cases, the water cut of VRR = 1 is clearly greater than that of VRR = 0.7. Finally, three-phase relative permeability was explored on the basis of the experimentally determined two-phase oil/water and liquid/gas relative permeability curves. Well-known algorithms for three-phase relative permeability, however, did not result in good history matches to the experimental data. Numerical simulations matched the experimental recovery vs. production time acceptably after modification of the measured krg and krow relationships. A concave shape for oil relative permeability that is suggestive of emulsified oil in situ was noted for both systems. The degree of agreement with experimental data is sensitive to the details of gas (gas/oil system) and oil (oil/water system) mobility.

A New Model to Obtain Representative Field Relative Permeability for Reservoirs Produced under Solution Gas Drive

2005 ◽  
Vol 8 (04) ◽  
pp. 348-356 ◽  
Author(s):  
Fabrice Bauget ◽  
Patrick Egermann ◽  
Roland Lenormand
Keyword(s):  
Relative Permeability ◽  
History Matching ◽  
Phase Transfer ◽  
Bubble Nucleation ◽  
Relative Permeabilities ◽  
Solution Gas Drive ◽  
Reservoir Conditions ◽  
Depletion Rate ◽  
Gas Drive ◽  
Solution Gas

Summary Relative permeability curves (kr) control production and are of primary importance for any type of recovery process. In the case of production by displacement (waterflood or gasflood), the kr curves obtained in the laboratory can be used in numerical simulators to predict hydrocarbon recovery (after upscaling to account for heterogeneity). In the case of reservoirs produced under solution-gas drive (depressurized field, foamy oils), the experiments conducted in the laboratory depend on the depletion rate and cannot be used directly for reservoir simulations. We have developed a novel approach for calculating representative field relative permeabilities. This new method is based on a physical model that takes into account the various mechanisms of the process: bubble nucleation(pre-existing bubbles model), phase transfer (volumetric transfer function), and gas displacement (bubble flow). In our model, we have identified a few"invariant" parameters that are not sensitive to depletion rate and are specific to the rock/fluid system (mainly the pre-existing bubble-size distribution and a proportionality coefficient relating gas and oil velocity for the dispersed-phase regime). These invariant parameters are determined by history matching one experiment at a given depletion rate. The calibrated model is then used to generate synthetic data at any depletion rate, especially at very low depletion rates representative of the reservoir conditions. Relative permeabilities are derived from these"numerical" experiments in the same way as they are from real experiments. The calculated kr is finally used in commercial reservoir simulators. We have tested our model by using several series of published experiments with light and heavy oils. After adjusting the invariant parameters on one or two experiments, we are able to predict other experiments performed at different depletion rates with very good accuracy. Finally, we present an example of determination of relative permeabilities at reservoir depletion rates. Introduction In the case of conventional recovery processes (waterflooding and gasflooding), experiments that are conducted in the laboratory can mimic the conditions that prevail in the reservoir. Hence, the kr data derived from these experiments can be used in a practically straightforward manner for field-simulation purposes (upscaling is often needed to account for heterogeneities). The problem is more complicated for recovery by solution-gas drive. In this case, the laboratory experiments fail in reproducing the reservoir conditions. In reservoirs, the depletion rates are at least several times lower than what can be obtained in the laboratory. Because the depletion rate controls the gas topology (bubble density), the diffusion of gas from solution (out of equilibrium), and the gas displacement (dispersed flow), it also dramatically affects the shape of the kr curves. Therefore, the depletion experiments cannot be used to derive field kr data directly.

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