Extrapolation of Laboratory Measured Black Oil and Solution Gas Fluid Properties for Variable Bubblepoint Simulation

1999 ◽  
Author(s):  
W.D. McCain ◽  
J.P. Spivey
Keyword(s):  
Black Oil ◽  
Fluid Properties ◽  
Solution Gas

A Generalized Compositional Approach for Reservoir Simulation

1983 ◽  
Vol 23 (05) ◽  
pp. 727-742 ◽  
Author(s):  
Larry C. Young ◽  
Robert E. Stephenson
Keyword(s):  
Enhanced Recovery ◽  
Gas Condensate ◽  
Reservoir Modeling ◽  
Pressure Equation ◽  
Compositional Modeling ◽  
Fluid Property ◽  
Black Oil ◽  
Fluid Properties ◽  
Newton Raphson ◽  
Raphson Method

A procedure for solving compositional model equations is described. The procedure is based on the Newton Raphson iteration method. The equations and unknowns in the algorithm are ordered in such a way that different fluid property correlations can be accommodated leadily. Three different correlations have been implemented with the method. These include simplified correlations as well as a Redlich-Kwong equation of state (EOS). The example problems considered area conventional waterflood problem,displacement of oil by CO, andthe displacement of a gas condensate by nitrogen. These examples illustrate the utility of the different fluid-property correlations. The computing times reported are at least as low as for other methods that are specialized for a narrower class of problems. Introduction Black-oil models are used to study conventional recovery techniques in reservoirs for which fluid properties can be expressed as a function of pressure and bubble-point pressure. Compositional models are used when either the pressure. Compositional models are used when either the in-place or injected fluid causes fluid properties to be dependent on composition also. Examples of problems generally requiring compositional models are primary production or injection processes (such as primary production or injection processes (such as nitrogen injection) into gas condensate and volatile oil reservoirs and (2) enhanced recovery from oil reservoirs by CO or enriched gas injection. With deeper drilling, the frequency of gas condensate and volatile oil reservoir discoveries is increasing. The drive to increase domestic oil production has increased the importance of enhanced recovery by gas injection. These two factors suggest an increased need for compositional reservoir modeling. Conventional reservoir modeling is also likely to remain important for some time. In the past, two separate simulators have been developed and maintained for studying these two classes of problems. This result was dictated by the fact that compositional models have generally required substantially greater computing time than black-oil models. This paper describes a compositional modeling approach paper describes a compositional modeling approach useful for simulating both black-oil and compositional problems. The approach is based on the use of explicit problems. The approach is based on the use of explicit flow coefficients. For compositional modeling, two basic methods of solution have been proposed. We call these methods "Newton-Raphson" and "non-Newton-Raphson" methods. These methods differ in the manner in which a pressure equation is formed. In the Newton-Raphson method the iterative technique specifies how the pressure equation is formed. In the non-Newton-Raphson method, the composition dependence of certain ten-ns is neglected to form the pressure equation. With the non-Newton-Raphson pressure equation. With the non-Newton-Raphson methods, three to eight iterations have been reported per time step. Our experience with the Newton-Raphson method indicates that one to three iterations per tune step normally is sufficient. In the present study a Newton-Raphson iteration sequence is used. The calculations are organized in a manner which is both efficient and for which different fluid property descriptions can be accommodated readily. Early compositional simulators were based on K-values that were expressed as a function of pressure and convergence pressure. A number of potential difficulties are inherent in this approach. More recently, cubic equations of state such as the Redlich-Kwong, or Peng-Robinson appear to be more popular for the correlation Peng-Robinson appear to be more popular for the correlation of fluid properties. SPEJ p. 727

Characterization of a Carbonate Reservoir With Pressure-Transient Tests and Production Logs: Tengiz Field, Kazakhstan

2001 ◽  
Vol 4 (04) ◽  
pp. 250-259
Author(s):  
K.T. Chambers ◽  
W.S. Hallager ◽  
C.S. Kabir ◽  
R.A. Garber
Keyword(s):  
Flow Behavior ◽  
Carbonate Reservoir ◽  
Dual Porosity ◽  
Rate Data ◽  
Pressure Data ◽  
Pressure Transient ◽  
Reservoir Flow ◽  
Black Oil ◽  
Fluid Properties ◽  
Tengiz Field

Summary The combination of pressure-transient and production-log (PL) analyses has proved valuable in characterizing reservoir flow behavior in the giant Tengiz field. Among the important findings is the absence of clear dual-porosity flow. This observation contradicts an earlier interpretation that the reservoir contains a well-connected, natural fracture network. Fracturing and other secondary porosity mechanisms play a role in enhancing matrix permeability, but their impact is insufficient to cause dual-porosity flow behavior to develop. Flow profiles measured with production logs consistently show several thin (10 to 30 ft) zones dominating well deliverability over the thick (up to 1,040 ft) perforation intervals at Tengiz. A comparison of PL results and core descriptions reveals a good correlation between high deliverability zones and probable exposure surfaces in the carbonate reservoir. Contrary to earlier postulations, results obtained from pressure-transient and PL data at Tengiz do not support rate-sensitive productivity indices (PI's). Inclusion of rate variations in reconciling buildup and drawdown test results addressed this issue. We developed wellbore hydraulic models and calibrated them with PL data for extending PI results to wells that do not have measured values. A simplified equation-of-state (EOS) fluid description was an important component of the models because the available black-oil fluid correlations do not provide reliable results for the 47°API volatile Tengiz oil. Clear trends in reservoir quality emerge from the PI results. Introduction A plethora of publications exists on transient testing. However, only a few papers address the issue of combining multidisciplinary data to understand reservoir flow behavior (Refs. 1 through 4 are worthy of note). We used a synergistic approach by combining geology, petrophysics, transient tests, PL's, and wellbore-flow modeling to characterize the reservoir flow behavior in the Tengiz field. Understanding this flow behavior is crucial to formulating guidelines for reservoir management. Permeability estimation from pressure-transient data is sensitive to the effective reservoir thickness contributing to flow. Unfortunately, difficulties associated with the calibration of old openhole logs, sparse core coverage, and a major diagenetic overprint of solid bitumen combine to limit the identification of an effective reservoir at Tengiz based on openhole log data alone. Consequently, PL's have been used to identify an effective reservoir in terms of its flow potential. A limitation of production logs is that they only measure fluid entering the wellbore and are not necessarily indicative of flow in the reservoir away from the well. Pressure data from buildup and drawdown tests, on the other hand, provide insights into flow behavior both near the well and farther into the reservoir. The combination of pressure-transient analysis using simultaneous downhole pressure and flow-rate data along with measured production profiles provides an opportunity to reconcile near-wellbore and in-situ flow behavior. Expansion of reservoir fluids along with formation compaction provides the current drive mechanism at Tengiz because the reservoir is undersaturated by over 8,000 psia. As the field is produced, reservoir stresses will increase in response to pressure decreases.5 Increased stresses can significantly reduce permeability if natural fractures provide the primary flow capacity in the reservoir. Wells producing at high drawdowns provide an opportunity to investigate the pressure sensitivity of fractures within the near-wellbore region. Early interpretations of pressure-transient tests at Tengiz uncovered a significant discrepancy between buildup and drawdown permeability, despite efforts to carefully control flow rates during the tests. Drawdown permeabilities typically exceeded the buildup results by 20 to 50%. Although this finding appears counterintuitive to the expectation that drawdowns (that is, higher stresses) would lead to lower permeability, it indicated a possible stress dependence on well deliverability. The method proposed by Kabir6 to reconcile differences between drawdown and buildup results proved useful in addressing this issue. The opportunities to collect PL and downhole pressure data at Tengiz are limited by mechanical conditions in some wells and by the requirement to meet the processing capacity of the oil and gas plant. On the other hand, accurate wellhead-pressure and flow-rate data are routinely available. Wellbore hydraulic calculations provide a basis for calculating flowing bottomhole pressures (FBHP's) with the available surface data. Calculated FBHP's can be combined with available reservoir pressure data to determine PI's for wells lacking bottomhole measurements. The ability to compute accurate fluid properties is critical in applying this approach. Unfortunately, the black-oil correlations routinely used in wellbore hydraulic calculations7–9 do not provide reliable results for the volatile Tengiz oil. We obtained good agreement between laboratory measurements of fluid properties and calculated values using a simplified EOS.10 Surface and bottomhole data collected during PL operations provide a basis for validating wellbore hydraulic calculations. Networks of natural fractures can dominate the producing behavior of carbonate reservoirs such as Tengiz. Early identification of fractured reservoir behavior is critical to the successful development of these types of reservoirs.11 We present an approach for resolving reservoir flow behavior by combining production profiles, pressure-transient tests, and wellbore hydraulic calculations. Furthermore, we discuss the PL procedures developed to allow acquisition of the data required for all three types of analyses in a single logging run. Field examples from Tengiz highlight the usefulness of this approach.

Applications of the Coefficient of Isothermal Compressibility to Various Reservoir Situations With New Correlations for Each Situation

2007 ◽  
Vol 10 (01) ◽  
pp. 43-49 ◽  
Author(s):  
John Paul Spivey ◽  
Peter P. Valko ◽  
William D. McCain
Keyword(s):  
Isothermal Compressibility ◽  
Pressure Range ◽  
Laboratory Data ◽  
Material Balance ◽  
Weighted Average ◽  
Correlation Equation ◽  
Reservoir Pressure ◽  
Integral Sign ◽  
Black Oil ◽  
Fluid Properties

Summary The coefficient of isothermal compressibility (oil compressibility) is defined as the fractional change of oil volume per unit change in pressure. Though the oil compressibility so defined frequently appears in the partial-differential equations describing fluid flow in porous media, it is rarely used in this form in practical engineering calculations. Instead, oil compressibility is usually assumed to be constant, allowing the defining equation to be integrated over some pressure range of interest. Thus, the oil compressibility in the resulting equations should be regarded as a weighted average value over the pressure range of integration. The three distinct applications for oil compressibility in reservoir engineering are (1) instantaneous or tangent values from the defining equation, (2) extension of fluid properties from values at the bubblepoint pressure to higher pressures of interest, and (3) material-balance calculations that require values starting at initial reservoir pressure. Each of these three applications requires a different approach to calculating oil compressibility from laboratory data and in developing correlations. The differences among the values required in these three applications can be as great as 25%. Most published correlations do not indicate the particular application to which the proposed correlation applies. A correlation equation for oil compressibility has been developed using more than 3,500 lines of data from 369 laboratory studies. This correlation equation gives the average compressibility between the bubblepoint pressure and some higher pressure of interest. Equations to calculate appropriate values of compressibility for the other two applications are presented. Introduction The equation defining the coefficient of isothermal compressibility at pressures above the bubblepoint pressure is rather simple:(Equation 1) However, in application the situation becomes somewhat complex. Usually the equation is integrated by separating variables:(Equation 2) Moving oil compressibility outside the integral sign requires the assumption that it is constant. Because it is not constant, the use of this equation requires a value of oil compressibility that is a pressure-weighted average across the pressure range used in the calculations. There are three applications for oil compressibility in reservoir engineering:The defining equation, for which the oil compressibility should be calculated as a single value at the pressure of interest, often used in pressure-transient analysis.The extension of fluid properties from correlations starting at the bubblepoint pressure to pressures above the bubblepoint pressure. This application is also used in black-oil reservoir simulation.The use of oil compressibility in black-oil material-balance equations in which the starting point is the initial reservoir pressure. Values of oil compressibility should be calculated from laboratory data with these applications in mind. Most published correlations for oil compressibility do not indicate the particular situation to which the correlation applies, although values calculated for these three applications can differ significantly. For example, Fig. 1 gives values of oil compressibility calculated with the constant-composition-expansion data from a widely available black-oil laboratory report (Reservoir Fluid Study 1988). Two things are readily apparent. First, coefficients of isothermal compressibility are not constant as pressure changes. Second, the three applications require values that differ by up to 25%.

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

A Pseudobubblepoint Model and Its Simulation for Foamy Oil in Porous Media

SPE Journal ◽  
2014 ◽  
Vol 20 (02) ◽  
pp. 239-247 ◽  
Author(s):  
Zhangxin Chen ◽  
Jian Sun ◽  
Ruihe Wang ◽  
Xiaodong Wu
Keyword(s):  
Porous Media ◽  
Oil Recovery ◽  
Field Performance ◽  
Foamy Oil ◽  
Pvt Data ◽  
Fluid Properties ◽  
Usual Equilibrium ◽  
Solution Gas ◽  
Lower Production ◽  
Better Than

Summary This is the second paper of a series in which we study heavy oil in porous media. The first paper dealt with an experimental study (Wang et al. 2008), whereas a mathematical and simulation study is presented here. The research program stems from the need to predict the field performance of a class of heavy-foamy-oil reservoirs. These reservoirs show a better-than-expected primary performance: lower production gas/oil ratios (GORs), higher-than-expected production rates, and higher oil recovery. A mechanism used to account for the observed performance is that the liberated solution gas is entrained in the oil when the reservoir pressure falls below the thermodynamic equilibrium bubblepoint pressure. The presence of entrained gas increases the effective compressibility of the oil phase and prevents gas from becoming a free phase. Hence, the foamy oil behaves as if it had a pseudobubblepoint pressure below the usual equilibrium bubblepoint pressure. This paper describes a pseudobubblepoint model and a methodology that can be used to compute foamy-oil fluid properties from conventional laboratory pressure/volume/temperature (PVT) data. The techniques developed are then used to study foamy oil in the Orinoco belt, Venezuela. The present mathematical model is validated by comparing numerical and experimental results.

A Method for Handling Spatially Varying Fluid Properties in a Simulation Model for a Fissured Reservoir

1970 ◽  
Vol 10 (01) ◽  
pp. 25-32
Author(s):  
W.P. Sibley
Keyword(s):  
Simulation Model ◽  
Oil Recovery ◽  
Horizontal Plane ◽  
Gas Oil ◽  
Pvt Properties ◽  
Engineering Studies ◽  
Fluid Properties ◽  
Recovery Mechanisms ◽  
Gas Drive ◽  
Solution Gas

Abstract The high relief, fractured carbonate reservoirs of the Asmari formation in Iran have extremely thick oil columns, with a large vertical change of reservoir temperature. This large change results in a significant effect on reservoir fluid properties. In contrast, there is a remarkable uniformity of PVT properties on a horizontal plane. Therefore, to properties on a horizontal plane. Therefore, to obtain meaningful results from reservoir engineering studies, PVT properties must be carefully weighted vertically. Intensive study of the known oil recovery mechanisms within these highly fissured systems resulted in a sophisticated reservoir simulation model. The model is programmed to include these recovery processes, which occur essentially in horizontal layers or zones. It also includes a technique for volumetrically weighting the large vertical variation of the PVT data. A description of this weighting process is the primary purpose of this paper. Introduction Oilfield structures found in Iran have been described as very long, high relief, assymmetrical anticlines that contain unusually thick oil columns (see Fig. 1). The oil reservoirs generally are capped with large primary gas accumulations and are often affected by natural water drive. Producing formations include the Asmari, Bangestan, and Khami carbonates, with the Asmari being by far the most common and prolific. Although some Asmari reservoirs have been discovered that contain sandstones interbedded within the limestones and dolomites, most reservoirs in Iran contain the bulk of the oil in compact carbonates that have been contorted and highly fractured during structural deformation. The resulting anticlinal oil accumulations are produced mainly from complex fracture systems, which apparently exist quite uniformly throughout the dense matrix. Study of surface rocks, cores and well producibility show that well developed fissure producibility show that well developed fissure systems are responsible for the excellent fluid communication. Because the fissures contain relatively little oil, maintenance of such prolific rates is dependent upon rate of oil replenishment from the adjacent matrix. The various productive mechanisms determine the rate of replenishment and duration. RESERVOIR AND MODEL CONSIDERATIONS Engineering studies of the fissured Iranian reservoirs have led to a mathematical model that is even more sophisticated than an earlier one. Many complex features have been included in the current model, making it a useful aid for advising management. The model consists of a master digital computer program that encompasses 54 subprograms and runs on any of the IBM 7040, 7090 and 360/65 computers. The known oil recovery mechanisms included in the model are based on consideration of practical oil recovery observations. For example, oil recovery from the expanding gas cap is predicted by using recognized gravity drainage formations, but if necessary, retrograde condensation recovery from the gas cap can also be included. Fluid and rock expansion, solution gas drive, and water displacement are also included, and vary according to the reservoir in question. But the manner in which gas production differs from what is usually observed in a solution gas drive must be known to include a proper simulation of behavior. Experience has shown that the producing gas-oil ratio continues to decline during the entire producing life of a well unless the proximity of the gas cap results in gas coning, at which time the well is shut in. Material balance calculations show that the initial gas-oil separation singe actually occurs in the reservoir, with the fissure system readily enabling the liberated gas to segregate toward the gas cap. SPEJ P. 25

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

Sign in / Sign up

Export Citation Format

Share Document