bluuebunny/crossref_metadata_2025 huggingface dataset:
Olympic Pool Water Flood
Authors: Stiles W.E.
Published: December 2007

The Olympic pool is located some 12 miles northeast of the city of Wewoka, in Hughes and Okfuskee counties, Okla.

The field was discovered in July 1935. Subsequent rapid development on 10-acre spacing proved 3,500 acres productive in the Senora sand, which is found at an average depth of 1,800 ft. Primary production was by solution gas drive mechanism. By 1940, 14 years after discovery, the field had produced almost 14 million bbl of oil and then was in the stripper stage.

In that year, a pilot water flood was started which in less than one year of injection proved the floodability of the Senora sand. Additional waterflood development followed, and by 1954 the entire field was being operated under a pattern water flood.

A water supply source of some 100,000 B/D of capacity was found and developed after the original source of supply, although sufficient in quantity, proved highly corrosive. The problems encountered in developing, treating and injecting this volume of water are presented.

Production and injection history to Jan. 1, 1956, is presented to show the magnitude of the results being obtained, and the comparison of recoveries under water flood to recoveries under primary operation.

Introduction

The performance thus far of the Olympic pool water flood is a testimonial for "patterned" development, modern engineering techniques, and cooperation between operators in waterflooding operations. These factors, together with favorable reservoir conditions, have contributed significantly to the high efficiency being obtained. One of the largest projects in operation, the Olympic pool water flood probably holds the record for the highest daily rate of oil production, some 15,000 bbl. By the end of 1955, seven years after the start of pilot flood operations, more oil had been produced by water flood than was produced in 14 years of primary production.
Rheology of Gels Used for Conformance Control in Fractures
Authors: Liu Jin , Seright R. S.
Published: December 2007

This paper investigates whether gel behavior in rheometers correlates with that examined during extrusion through fractures. Although qualitative similarities were noted, the pressure gradients during gel extrusion through fractures were substantially greater than the values expected from rheological measurements. Also, the pressure gradient for gel extrusion through fractures varied in an unexpected manner with fracture width.
Verification of a Complete Pore Network Simulator of Drainage and Imbibition
Authors: Patzek Tad W.
Published: December 2007

Relative-permeability and capillary-pressure functions define how much oil can be recovered and at what rate. These functions, in turn, depend critically on the geometry and topology of the pore space, on the physical characteristics of the rock grains and the fluids, and on the conditions imposed by the recovery process. Therefore, imaging and characterizing the rock samples and the fluids can add crucial insight into the mechanisms that control field-scale oil recovery. When the fundamental equations of immiscible flow in the imaged samples are solved, one can elucidate how relative-permeability and capillary-pressure functions depend on wettability, interfacial tension, and the interplay among viscous, capillary and gravitational forces. This paper summarizes the development of a complete quasistatic pore-network simulator of two-phase flow, "ANetSim," and its validation against Statoil's state-of-the-art proprietary simulator. Most equations presented in this paper are new; therefore, repetition of the published Statoil results is kept to a minimum. In particular, the hydraulic conductance correlations in two-phase flow and the model of cooperative pore-body filling are new. ANetSim has been implemented in MATLAB® and it can run on any platform. Three-dimensional, disordered networks with complex pore geometry have been used to calculate primary-drainage and secondary-imbibition capillary pressures and relative permeabilities. The results presented here agree well with the Statoil simulations and experiments.
Asymptotic Analytical Solutions for Imbibition Waterfloods in Fractured Reservoirs
Authors: Civan Faruk , Rasmussen Maurice L.
Published: December 2007

A generalized methodology is presented that obtains analytical solutions for imbibition waterfloods in naturally fractured oil reservoirs undergoing multistep matrix-to-fracture transfer processes. The phenomenological representation of the oil transfer from matrix to fracture is based on a three-exponential matrix-to-fracture transfer function, the necessity for which is seen by examination of experimental data. The resulting integrodifferential equation is converted to a fourth-order partial differential equation, linearized by invoking the unit endpoint mobility-ratio approximation, and then solved analytically by asymptotic means. It is shown that the asymptotic-approximation approach significantly reduces the complexity of the solution process and yields adequate solutions for long-time evaluation of waterfloods in naturally fractured reservoirs. The solution is not only computationally advantageous, but it also provides a physically meaningful interpretation of the propagation speed and diffusive spreading of the progressing wave front, which could not be readily obtained from the usual type of solution methods, such as the direct application and inversion of the Laplace transformation.
Integration of Partial Differential Equation for Transient Radial Flow of Gas-Condensate Fluids in Porous Structures
Authors: Eilerts C.K. , Sumner E.F. , Potts N.L.
Published: December 2007

The second-order, nonlinear, partial-differential equation representing the transient radial flow of gas-condensate fluids in reservoirs has been integrated by using finite-difference equations and electronic computers. Effect was given to pressure-dependent permeability, viscosity, and compressibility and to distance-dependent permeability. The influence of a second-degree velocity term in the Darcy equation was investigated. Implicit methods were used and practical, convergent solutions were obtained with material balance to less than 6 x 10 for recovery of one-half the reserve at constant flow rate. Integration results provide the productive period of a reservoir for a given constant rate and the fraction of the fluid initially in place that can be recovered in that period. The properties of a lean and a rich fluid are represented in a set of integrations designed to demonstrate the effect of different constant-recovery rates and significant variables emphasized one at a time.

Introduction

A method is needed for computing the availability or reserve of a gas in a formation, making use of all technical and engineering information that is pertinent. As a step in this direction, a program for computing transient linear flow was developed that utilizes principles of earlier finite-difference computing for a similar purpose and gives effect to significant pressure- and distance-dependent properties of reservoirs and their contents. The present paper pertains to transient, radial flow of gas-condensate fluids. In the partial-differential equation of flow, effect is given to the variables viscosity and compressibility, and also to permeability. Included in the study is the quadratic form of the Darcy equation of flow that has been the subject of field tests and that has been applied to a gas with constant properties in transient flow computing. Inclusion in the differential equation of variable coefficients to represent properties greatly complicates the higher derivatives of the equation. Because it was impractical to make a required improvement in certain of the finite-difference derivatives by Taylor-series expansion, five-term derivatives were used in the implicit computing. Related methods were developed that can improve general facility in manipulating finite-difference equations.

BASIC EQUATIONS

PARTIAL DIFFERENTIAL EQUATION

The basic partial differential equation for transient radial flow in the direction of decreasing radius is

(1)

where r radius, Lv = apparent velocity along radius, L/tp = density, M/L3t = time, tphi = porosity, dimensionless.

In this equation, only the porosity is regarded constant. The density is

(2)

where p = pressure, m/LtM = molecular weight of fluid, mT = constant temperature of fluid, Tz(p)= pressure- dependent compressibilityfactor, dimensionlessR = gas constant, mL2/t2T.

SPEJ

P. 141ˆ
Burst-Induced Stresses in Cemented Wellbores
Authors: Fleckenstein W. W. , Eustes A. W. , Miller M. G.
Published: December 2007

This paper presents the results of a finite element study of the resistance to burst pressure. Results from the 2D model quantify the effects of various mechanical properties of cement on a cemented wellbore. Comparison of the predicted stresses with experimental results demonstrated that ductile cement is far less likely to crack radially from high internal burst pressures than a brittle cement. It is demonstrated that the in-situ formation stresses acting on the cemented wellbore greatly affect the burst resistance of the cemented wellbore.

The industry acknowledges that there is an increase in the burst resistance of cemented pipe vs. uncemented pipe; but the effects of cement and formation mechanical properties, and in-situ stresses are not well understood. This paper presents the results of a finite element study of the resistance of casing to internal burst pressure under a variety of conditions. This will provide for better design understanding of the stress conditions developed in casing under burst loading.

2D stress-distribution model results are presented in graphical and tabular format for a variety of geometrical and mechanical material properties of formations, cement slurries, and casing combinations.

A better understanding of the true stress profile in cemented pipe allows for less expensive decisions concerning casing design parameters and safety-factor criteria. Applications using the burst resistance of the cemented pipe as a system as opposed to using the burst resistance of free pipe can include deeper drilling with thinnerwalled pipe, smaller rigs, and better casing integrity decisions for refracturing candidates.
Petroleum Reservoir Simulation Coupling Fluid Flow and Geomechanics
Authors: Gutierrez M. , Lewis R. W. , Masters I.
Published: December 2007

This paper presents a discussion of the issues related to the interaction between rock deformation and multiphase fluid flow behavior in hydrocarbon reservoirs. Pore-pressure and temperature changes resulting from production and fluid injection can induce rock deformations, which should be accounted for in reservoir modeling. Deformation can affect the permeability and pore compressibility of the reservoir rock. In turn, the pore pressures will vary owing to changes in the pore volume. This paper presents the formulation of Biot's equations for multiphase fluid flow in deformable porous media. Based on this formulation, it is argued that rock deformation and multiphase fluid flow are fully coupled processes that should be accounted for simultaneously, and can only be decoupled for predefined simple loading conditions. In general, it is shown that reservoir simulators neglect or simplify important geomechanical aspects that can impact reservoir productivity. This is attributed to the fact that the only rock mechanical parameter involved in reservoir simulations is pore compressibility. This parameter is shown to be insufficient in representing aspects of rock behavior such as stress-path dependency and dilatancy, which require a full tensorial constitutive relation. Furthermore, the pore-pressure changes caused by the applied loads from nonpay rock and the influence of nonpay rock on reservoir deformability cannot be accounted for simply by adjusting the pore compressibility.
Screening and Coreflood Testing of Gel Foams To Control Excessive Gas Production in Oil Wells
Authors: Wassmuth F. R. , Hodgins L. A. , Schramm L. L. , Kutay S. M.
Published: December 2007

Polymer-enhanced foam and gel-foam formulations were screened and tested for their injectability and gas-blocking ability in Berea sandstone cores and carbonate packs (in the presence and absence of oil at 85°C). Gel foams, with suitable gelation delay, were propagated through packed cores in a similar manner as polymer-enhanced foams (PEF's). However, the gas-blocking ability of cured gel foam was far superior to that of PEF. The gel foam blocked gas flow completely, even in the presence of oil, and a significant pressure differential had to be exceeded before the gas could channel through the gel foam and flow through the core.
A General Single-Phase Wellbore/Reservoir Coupling Model for Multilateral Wells
Authors: Ouyang Liang-Biao , Aziz Khalid
Published: December 2007

A general single-phase flow model that rigorously couples flow in the reservoir with flow in the wellbore is presented. The model can be applied to a parallelepiped drainage domain consisting of any number of wells containing any number of laterals of arbitrary configurations. The fluid is assumed to be slightly compressible, and gravity head is included. Reservoir inflow for the entire time period (from early transient to late pseudosteady state) is handled in the coupling model by integrating the instantaneous point source/sink solution over both time and space. Pressure drop along any lateral in the well system is the sum of three components: wall friction, gravity, and acceleration owing to wall inflow or outflow. Effects of wall mass transfer on wall friction and kinetic energy change are taken into account.

A computer package has been developed and used to perform a series of sensitivity studies that lead to several important and interesting observations. The coupling model may be applied to determine well productivity, well index for multiphase flow simulation, wellbore pressure profile, and wellbore inflow or outflow distribution for any time in the well's production/injection life.
Tenth SPE Comparative Solution Project: A Comparison of Upscaling Techniques
Authors: Christie M. A. , Blunt M. J.
Published: December 2007

This paper presents the results of the 10th SPE Comparative Solution Project on Upscaling. Two problems were chosen. The first problem was a small 2D gas-injection problem, chosen so that the fine grid could be computed easily and both upscaling and pseudoization methods could be used. The second problem was a waterflood of a large geostatistical model, chosen so that it was hard (though not impossible) to compute the true fine-grid solution. Nine participants provided results for one or both problems.
A New Efficient Averaging Technique for Scaleup of Multimillion-Cell Geologic Models
Authors: Li D. , Beckner B. , Kumar A.
Published: December 2007

Increased resolution in reservoir characterization is driving the need for efficient and accurate upscaling techniques for reservoir simulation, on which reservoir performance prediction relies. Unfortunately, the existing averaging methods (i.e., harmonic, arithmetic, power law, geometric, or a combination of harmonic and arithmetic methods) are only applicable under the circumstances of perfectly layered or perfectly random heterogeneity distributions, which are rarely seen in realistic reservoir descriptions. This paper presents a new averaging method that improves these upscaling averaging methods for realistic reservoirs and can substitute for the orders-of-magnitude slower direct-simulation methods, such as pressure-solver techniques. The new averaging method first calculates the upper and lower bounds of the effective properties based on the nature of geology and then employs a new correlation, scaling, and rotation technique to estimate the effective properties for the upscaled grid. The approach not only preserves the accuracy of the time-consuming simulation methods but also retains the speed of the traditional averaging methods.

Five real sandstone and carbonate reservoir geologic models (three of which are multimillion-cell models) from Africa, North America, and South America were employed as benchmarks and working data sets to develop and validate the new technique. The technique has the advantage of handling the more irregular geometries [i.e., pinchouts, faults, and flexible simulation grids such as the Perpendicular Bisection (PEBI) grid].
Mechanistic Modeling of Two-Phase Flow in Deviated Wells
Authors: Kaya A. S. , Sarica C. , Brill J. P.
Published: December 2007

A mechanistic model was developed to predict flow pattern and flow characteristics such as pressure drop and liquid holdup in vertical and deviated wells. The model includes five flow patterns: bubbly, dispersed-bubble, slug, churn, and annular flows.

Flow-pattern prediction incorporates the transition models proposed by Barnea1 (or Taitel et al.2) for dispersed-bubble flow, Ansari et al.3 for annular flow, Tengesdal et al.4 for churn flow, and a new bubbly-flow transition model. For each predicted flow pattern, a separate hydrodynamic mechanistic model is proposed. A new hydrodynamic model for bubbly flow has been developed, and the Chokshi5 slug-flow model has been modified significantly. The Tengesdal et al. and Ansari et al. models have been adopted for churn and annular flows, respectively.

The model is evaluated with a well databank of 2,052 cases covering a broad range of field data. Pressure drop predictions with the model are also compared with those using the Ansari et al., Chokshi, Hasan and Kabir,6 and Tengesdal7 mechanistic models, and the Aziz et al.8 and Hagedorn and Brown9 correlations. The results of the comparison study show that the proposed mechanistic model performs the best and agrees with the data.
Design and Installation of a Sand-Separation and -Handling System for a Gulf of Mexico Oil Production Facility
Authors: Rawlins C. H. , Wang I. I.
Published: December 2007

A comprehensive system for the separation and handling of sand from produced fluids was designed and installed on a facility in the Gulf of Mexico. This system involves two multicone desander systems, one on the water outlet and one on the oil outlet of a low-pressure separator, to provide separation of sand from produced fluids. The separated solids are collected, dewatered, and transported to a unique, simple-solids handling system designed for complete fluid containment and safe handling. The focus of this paper is to present the design of the separation and handling system and to discuss the various challenges encountered during and after commissioning. The topics covered include desander operation (pressure drop and separation), slurry discharge from the desander, dewatering of slurry, recycling of fluids, and transport of the collected solids from platform to shore.
Material Balance Above the Bubble Point
Authors: Hobson G.D. , Mrosovsky I.
Published: December 2007

Material balance relationships for expansion-type reservoirs above the bubble point have been discussed in recent years by H. N. Hall and M. F. Hawkins, Jr. The former drew attention to the effects of rock compressibility, and the latter to the effects of the compressibility of any interstitial water. Hawkins derived a general relationship which took note of oil, water and rock compressibilities, and then by assuming first, the absence of interstitial water and secondly, no effects due to interstitial water or rock compressibility, obtained relationships symbolically of the same form as those previously derived directly by Hall.

Hawkins defined his terms clearly, and noted an approximation, due to the omission of a term involving the product of two compressibilities, made in reaching his final equation. There is, however, possible ambiguity with regard to Hall's written definition of the oil production term. One interpretation would mean that the produced oil and initial oil-in-place, if both required as stock tank barrels, would be obtained by using different formation volume factors in the conversion in order to satisfy the conditions implicit in Hall's formulae. The other would involve an approximation which, if used, was not stated. In both Hall's and Hawkins' studies the effect of the approximation or inconsistency is very slight. Nevertheless, it may be justifiable to give a somewhat more consistent derivation, since the complexity of the final relationships is not thereby greatly increased.
The Responsibility of Geologists and Petroleum Engineers in Meeting Exploration Demands in the Future
Authors: Halbouty Michel T.
Published: December 2007

The oil industry should be preparing right now for the high future demands of petroleum products, even though there are adequate reserves to handle present demand. Engineers and geologists, in particular, should cooperate and strive to use data at hand to increase tile efficiency of methods of finding new oil. Several important areas of cooperation are discussed and examples are given of instances in which such cooperation led to significant discoveries. Broader responsibilities of engineers and geologists are also pointed out.

Introduction

In 1962, the United States produced 3.02 billion bbl of crude oil and natural gas liquids. This is the first time that total liquid hydrocarbon production has exceeded 3 billion bbl. In 1962, the United States also set a new record for natural gas by producing 13.7 trillion cu ft. At this rate of production, this country will have consumed its proven reserves of 38.7 billion bbl of liquid hydrocarbons in 12 1/2 years and its proven reserves of 273.8 trillion cu ft of gas in 20 years. Annual demand, however, is increasing at an established rate of 2 1/2 to 3 1/2 per cent/year for oil and 4 1/2 to 5 per cent/year for gas. Therefore, in order to maintain an adequate reserve position during the next 10 years, the United States must find 45 billion bbl of oil and 275 trillion cu ft of gas. In short, the petroleum industry's geologists and engineers must find and produce more oil and gas in the foreseeable future than has ever been produced in an equivalent previous period. In view of this challenge, one can only conclude that the basic law of supply and demand on which this country's economy is, or has been, based promises a bright future for the industry.

This rosy glow in the early morning sky is viewed at the moment, however, by an industry which is in a deep valley full of dark shadows. At a time when all signs point to an ever increasing demand for new reserves and greater productive capacity, the industry finds itself with more products to sell than present consumers can use. In addition, there is the problem of the loss of investment capital as a result of the continuing threat of increasing federal control. The sum of these two factors equals a reduction in exploration and production which is revealed by declining activity over the last 10 years.

Industry Reaction

Fig. 1 presents a brief resume of exploration and development in the United States since 1953. Geophysical activity is down 50 per cent from a high of 8,240 crew months in 1955 to a low of 4,231 crew months in 1962. Exploratory drilling is down 33 per cent from a peak of 16,207 wells in 1956 to 10,797 wells in 1962. Finally, as the inevitable result of a decline in exploration, development drilling has dropped 16 per cent from a high of 42,000 wells in 1956 to 35,408 in 1962.

JPT

P. 239ˆ
Oil Recovery by Gravity Drainage
Authors: Hagoort J.
Published: December 2007

Recent observations have indicated surprisingly high oil recoveries for gravity drainage. This has prompted us to reexamine gravity drainage as an oil recovery process. It is shown that oil relative permeability is a key factor. For accurate measurement of this oil relative permeability, we have developed a new method based on centrifugal gas/oil displacement in small cores. Several oil relative permeabilities for various rock types are presented. These relative permeabilities confirm that gravity drainage in water-wet, connate-water-bearing reservoirs can be very effective for oil-recovery.
Computer Simulation of Two Nuclear Well Logging Methods
Authors: Smith Harry D. , Schultz Ward E.
Published: December 2007

Monte Carlo techniques have been used to simulate the response of a multiwindow natural gamma ray spectral log to varying borehole conditions and to investigate the potential of a porosity logging concept using a ratio of fast to epithermal neutrons.
Effect of Stratification on Relative Permeability
Authors: Corey A.T. , Rathjens C.H.
Published: December 2007

Introduction

Although the oil industry has been aware of the directional variability of permeability in porous rock, the directional variability of relative permeability has been largely ignored. Yet it is apparent that such an effect must be present in a system in which the distribution of oil and gas within the porous matrix is controlled by capillary forces.

It is easy to visualize a rock composed of layers of fine and coarse material such that gas flow across the bedding planes would take place only after the average oil saturation had been reduced to a very low value. The fine layers, because of their greater capillarity, would remain saturated and act as barriers to the flow of gas after the coarse layers had been desaturated. Flow of gas parallel to the bedding planes would obviously take place at a much greater liquid saturation.

Without more complete information concerning the geology of a reservoir than is generally available, it is not possible to predict exactly how such phenomena would affect the over-all performance of an oil field. It is possible, however, to predict qualitatively the effect of stratification on relative permeability measurements made on laboratory cores.

In this investigation the effect of stratification was studied analytically by assuming that two porous materials with different capillary pressure-desaturation curves (but identical relative permeability curves) were in contact and in capillary equilibrium. As a qualitative check on the analytical results, cores having various degrees of visible stratification were used for relative permeability measurements made with fluids flowing both parallel and perpendicular to the bedding planes. A quantitative check was considered impractical because of the difficulty of devising models in which two materials of predetermined properties could be joined without the plane of contact becoming a discontinuity.

Theoretical Considerations and Assumptions

The assumption of capillary equilibrium in an oil-gas system implies that the difference in pressure between oil and gas is everywhere the same.
A Coupled Model for Three-Phase Capillary Pressure and Relative Permeability
Authors: Hustad Odd Steve
Published: December 2007

A fully coupled formulation for three-phase capillary pressure and relative permeability is presented. The formulation incorporates hysteresis and miscibility on both capillary pressure and relative permeability, simultaneously. Consistency is ensured for all three two-phase boundary conditions through the use of two-phase data and the application of normalized saturations.

Simulation examples of water-alternating-gas (WAG) injection are demonstrated using water-, mixed-, and oil-wet capillary pressure and relative permeability curves, both exhibiting hysteresis. The examples represent typical core-flooding scales in the centimeter to meter range. Discussions and illustrations are given demonstrating the importance of the functional dependency and the extrapolation of two-phase capillary pressure values to three-phase flow properties.
Simulation and Performance Prediction of a Large-Scale Surfactant/Polymer Project
Authors: Lake Larry W. , Johnston James R. , Stegemeier George L.
Published: December 2007

This paper presents a performance prediction technique for the response of a large-scale chemical flood. The technique involves the sequential use of a detailed finite difference simulator and a streamtube program. Although approximate, the technique avoids the difficulties usually associated with the independent use of either simulator.
Sensitivity Analysis of Hole Cleaning Parameters in Directional Wells
Authors: Li Jeff , Walker Scott
Published: December 2007

In this study, 600 tests were conducted and a new computer program was developed for the prediction of cuttings transport in the multiphase system (gas+liquid+cuttings). The sensitivity of cuttings bed height with respect to liquid/gas volume flow rate ratio, in-situ liquid velocity, rate of penetration (ROP), inclination angle, and circulation fluid properties was conducted. The hole-cleaning time with both circulation mode and wiper trip is also discussed. The results from the sensitivity analysis presented in this paper indicate, first, that the fraction of the circulation liquid has a significant impact on the cuttings transport in underbalanced drilling with gasified fluids; second, that among different variables, the in-situ liquid velocity is the most important variable for cuttings transport; and, finally, the hole-cleaning time decreases nonlinearly with increasing fluid circulation rate.
Compositional Grading—Theory and Practice
Authors: Høier Lars , Whitson Curtis H.
Published: December 2007

This paper quantifies the potential variation in composition and pressure/volume/temperature (PVT) properties with depth owing to gravity, chemical, and thermal forces. A wide range of reservoir fluid systems has been studied using all of the known published models for thermal diffusion in the nonisothermal mass-transport problem.

Previous studies dealing with the combined effects of gravity and vertical thermal gradients on compositional grading have been either (1) of a theoretical nature, without examples from reservoir fluid systems, or (2) proposing one particular thermal-diffusion model, usually for a specific reservoir, without comparing the results with other thermal-diffusion models.

We give a short review of gravity/nonisothermal models published to date. In particular, we show quantitative differences in the various models for a wide range of reservoir fluid systems. Solution algorithms and numerical stability problems are discussed for the nonisothermal models that require numerical discretization, unlike the exact analytical solution of the isothermal gradient problem.

We discuss the problems related to fluid initialization in reservoir models of complex fluid systems. This involves the synthesis of measured sample data and theoretical models. Specific recommendations are given for interpolation and extrapolation of vertical compositional gradients. The importance of dewpoint on the estimation of a gas/oil contact (GOC) is emphasized, particularly for newly discovered reservoirs in which only gas samples are available and the reservoirs are near-saturated.

Finally, we present two field case histories—one in which the isothermal gravity/chemical equilibrium model describes measured compositional gradients in a reservoir grading continuously from a rich gas condensate to a volatile oil, and another example in which the isothermal model is grossly inconsistent with measured data and convection or thermal diffusion has apparently resulted in a more-or-less constant composition over a vertical column of some 5,000 ft.
Critical Point and Saturation Pressure Calculations for Multipoint Systems
Authors: Baker Lee E. , Luks Kraemer D.
Published: December 2007

Calculation of fluid properties and phase equilibria is important as a general reservoir engineering tool and for simulation of the carbon dioxide or rich gas multiple-contact-miscibility (MCM) mechanisms. Of particular interest in such simulations is the near-critical region, through which the compositional path must go in an MCM process.

This paper describes two mathematical techniques that enhance the utility of an equation of state for phase equilibrium calculations. The first is an improved method of estimating starting parameters (pressure and phase compositions) for the iterative saturation pressure (bubble-point or dew-point) solution of the equation of state. Techniques previously have been presented for carrying out this iterative solution; however, the previously described procedure for obtaining initial parameter values was not satisfactory in all cases. The improved method utilizes the equation of state to estimate the parameter values. Since the same equation then is used to calculate the saturation pressure, the method is self-consistent and results in improved reliability.

The second development is the use of the equation of state to calculate directly the critical point of a fluid mixture, based on the rigorous thermodynamic criteria set forth by Gibbs. 1 The paper presents an iterative method for solving the highly nonlinear equations. Methods of obtaining initial estimates of the critical temperature and pressure also are presented.

The techniques described are illustrated with reference to a modified version of the Redlich-Kwong equation of state (R-K EOS); however, they are applicable to other equations of state. They have been used successfully for a wide variety of reservoir fluid systems, from a simple binary to complex reservoir oils.
Impact of Research on Oil Recovery
Authors: Sherborne John E. , McEwen C.R.
Published: December 2007

Introduction

Production research, as it exists today, is a product of the past 25 years. That it is an important part of the oil business at the present time can be indicated by its scope. Twenty-five years ago the number of individuals performing production research could almost be counted on the fingers of one's hands; today it is estimated there are several thousand people working in production research. During the past five years, a number of multi-million dollar production research laboratories have been built and many sizeable additions have been made in the production research facilities of practically all the major oil companies. It is estimated that there is currently being spent on production research something over $20 million annually exclusive of research on oil finding.

The impact of production research on the recovery of petroleum can be considered in three parts. The first of these is the tremendous body of knowledge which has resulted from production research. The second has been the change in our concepts regarding the occurrence and recovery of petroleum and thereby the change in our operating procedures which has been brought about. The third has been the improvement in our ability to quantitatively evaluate various recovery procedures so that the optimum one can be chosen at an early time in the history of the oil field.

It would be difficult indeed to give credit to the very many individuals who have contributed by their research efforts to our knowledge concerning recovery processes. A number of review papers covering the major contributions have appeared from time to time in the literature. Some of the more recent of these are noted in the bibliography. For details of the contributions made with respect to increasing our knowledge, the reader is referred to these papers and to the selected items in the bibliography of this paper.

Rather than produce another such review, we should like to discuss the impact of production research on recovery by citing some specific examples of how our concepts have changed and how our ability to evaluate recovery processes has improved.
Improved Integrated Reservoir Interpretation Using Gas While Drilling Data
Authors: Kandel D. , Quagliaroli R. , Segalini G. , Barraud B.
Published: December 2007

The acquisition of gas in mud data while drilling for geological surveillance and safety is an almost universal practice. This source of data is only rarely used for formation evaluation because of the widely accepted presumption that it is unreliable and unrepresentative. Recent developments in the mud-logging industry to improve gas data acquisition and analysis have led to the availability of better quality data.

Within a joint Elf/Eni-Agip Div. research program, a new interpretation method has been developed following the comprehensive analysis and interpretation of gas data from a wide range of wells covering different types of geological, petroleum, and drilling environments.

The results, validated by correlation and comparison with other data such as logs, well tests, and pressure/volume temperature (PVT) data, enable us to characterize lithological changes; porosity variations and permeability barriers; seal depth, thickness, and efficiency; gas diffusion or leakage; gas/oil and hydrocarbon/water contacts; vertical changes in fluid over a thick monolayer pay zone; vertical fluid differentiation in multilayer intervals; and biodegradation.

The comparison of surface gas, PVT, and geochemistry data clearly confirms the consistency between the drilling gas data (gas shows) and the corresponding reservoir fluid composition.

The near real-time availability, at no extra acquisition cost, of such data has led to:

The optimization of future well operations (such as logging and testing). A better integration of while-drilling data to the well evaluation process. Asignificant improvement in both early formation evaluation and reservoir studies, especially for the following applications, in which traditional log analysis often remains inconclusive: Very-low-porosity reservoirs. Thin beds. Dynamic barriers and seal efficiency. Low-resistivity pay. Light hydrocarbons.

Examples show gas while drilling (GWD) wellsite quicklook interpretations with simple lithological and fluid interpretations, as well as more complex reservoir and fluid characterization applications in varied geographical and geological contexts; both demonstrate how GWD data are integrated with more standard data sets.
A Novel Approach for Reservoir Forecasting Under Uncertainty
Authors: Mishra S. , Choudhary M. K. , Datta-Gupta A.
Published: December 2007

This paper presents a novel approach for developing statistical estimates of uncertainty in reservoir performance from a limited number of simulations. The methodology involves ranking and weighting the full suite of geostatistical models on the basis of a surrogate performance measure, then estimating the mean/variance of the desired performance measure by using a weighted average of simulation results from a few selected realizations. The streamline time-of-flight-based volumetric sweep efficiency is used as the surrogate performance measure to rank geostatistical models, and their weights are determined from a moment-matching algorithm.
Improvements to Reservoir Material-Balance Methods
Authors: Pletcher J. L.
Published: December 2007

Experience with material-balance data sets from the field and from simulation has revealed some procedures that can be used to improve analysis of both oil and gas reservoirs:

Failure to account for a weak waterdrive can result in significant material-balance errors. The assertion of previous authors that weak waterdrive exhibits a negative slope on the Cole (gas) and Campbell (oil) plots has been confirmed. A weak waterdrive is much more unambiguous on these plots than on commonly used plots, such as the p/z plot for gas. A modified version of the Cole plot is proposed to account for formation compressibility. The reservoir drive indices are a useful tool for determining the correctness of the material-balance solution because they must sum to unity. The drive indices should never be normalized to sum to unity because this obscures their usefulness and leads to a false sense of security. A modified version of the Roach plot (for gas) is proposed that improves interpretation in some waterdrive situations. Material balance has not been replaced by reservoir simulation; rather, it is complementary to simulation and can provide valuable insights to reservoir performance that cannot be obtained by simulation.
Slowing Production Decline and Extending the Economic Life of an Oil Field: New MEOR Technology
Authors: Brown L. R. , Vadie A. A. , Stephens J. O.
Published: December 2007

This project demonstrated the effectiveness of a microbial permeability profile modification (MPPM) technology for enhancing oil recovery by adding nitrogenous and phosphorus-containing nutrients to the injection water of a conventional waterflooding operation. The MPPM technology extended the economic life of the field by 60 to 137 months, with an expected recovery of 63 600 to 95 400 m3 (400,000 to 600,000 bbl) of additional oil. Chemical changes in the composition of the produced fluids proved the presence of oil from unswept areas of the reservoir. Proof of microbial involvement was shown by increased numbers of microbes in cores of wells drilled within the field 22 months after nutrient injection began.
Selective Plugging of Injection Wells by In Situ Reactions
Authors: Hower Wayne F. , Ramos Joe
Published: December 2007

Introduction

Petroleum engineers have long realized that producing horizons are not homogeneous. Severe permeability variations have been proven through core analysis and electrical surveys. After obtaining initial flush production through waterflooding, operators have shown concern about the distribution of water in the zone being flooded. At first, the efficiency of most floods was often an unknown factor. But efforts were soon directed toward the development of a method of accurately determining the distribution of flood water. Initial attempts to obtain necessary data were frequently very time-consuming and depended upon a uniform hole size for accurate information. Since many wells that were undergoing flooding operations had been shot, data of this type were inaccurate and misleading.

Early Research

In the early spring of 1951, a research project was instigated to develop a method of effectively treating water injection wells to greatly reduce the permeability of the above described thief zones. It was soon realized that it would be extremely difficult, if not impractical, to hope to be able to actually equalize the permeability of the entire horizon. Past research and field applications reported singular success when the surface of the formation was selectively plugged. There is adequate proof that additional oil was recovered as the result of these treatments and the process was a definite contribution to the industry.

The procedure had two major drawbacks, however. One being that where there are no horizontal bedding planes to isolate the selectively plugged zone and where the vertical permeability is relatively high, the injection water quickly goes around the surface plug and again enters the zone of highest permeability. The other is that an injection well will develop a formation pressure which will cause a back flow of formation fluids when water injection is stopped. Such a back flow normally washes away the surface plugging chemicals and thus reopens the offending zone so that it may accept flood water again.
Development and Application of an In-Situ Combustion Reservoir Simulator
Authors: Youngren Gary K.
Published: December 2007

This paper describes a three-dimensional, three-phase in-situ combustion reservoir simulator that rigorously models fluid flow, heat transfer, and vaporization/condensation. It has five components: water, oxygen, nonvolatile oil, and two arbitrary volatile components. The volatile components partition between the oil and gas phases. The physical mechanisms modeled, the comprehensive mathematical solution method employed, and four applications of the simulator are presented. The applications demonstrate that the simulator can be used to interpret laboratory results and predict the effects of reservoir characteristics and operating strategy on field performance.
New View on Continuous-Removal Liquids From Gas Wells
Authors: Li M. , Li S. L. , Sun L. T.
Published: December 2007

The paper adopts the view that the liquid droplets entrained in gas wells tend to be flat and deduces new formulas for the continuous removal of liquids from gas wells. The results calculated from the formulas are smaller than those of Turner et al. However, the predicted results are in accord with the practical production performance of China's gas wells with liquids. The paper also gives the simple forms of these formulas and shows the load-up and near load-up production performance as well as unloaded gas wells through the wellhead, producing performance figures.
A Method for Predicting Oil Recovery by Steamflooding Including the Effects of Distillation and Gravity Override
Authors: Rhee Shie W. , Doscher Todd M.
Published: December 2007

This paper describes a semianalytical method for calculating oil recovery by steamflooding. It accounts for effects of steam distillation and gravity overlay of steam. First, the equations for the heat balance and the configuration of the steam/liquid interface1 are solved simultaneously to predict the volume of the overall heated zone and the volume and shape of the steam zone. Second, the approximate enthalpy and material balances are combined with the thermodynamics of differential vaporization to derive a fully compositional method for calculating the volume and composition of steam-distilled hydrocarbons. Finally, the results of the foregoing are combined with a fluid flow model, similar to Higgins and Leighton's2 cell model for waterflood analysis to calculate oil recovery.

This semianalytical method can account for almost all the important recovery mechanisms involved in steamflooding with relatively small computation time. Good agreement has been obtained between available experimental data and calculations carried out in accord with this analysis.
A Laboratory Study of Low-Permeability Gas Sands
Authors: Jones F.O. , Owens W.W.
Published: December 2007

Routine permeabilities of tight gas sands are shown to be greater than under reservoir conditions, often by more than a hundred-fold, because of the great relief of stress, absence of connate water, and increased gas slippage. Correlations are presented that can be used to estimate in-situ permeability from routine data.

Introduction

Yearly compilations of U.S. oil and gas reserves by the American Gas Assn.1 show that U.S. gas reserves reached a maximum in 1967 of nearly 290 Tcf (8×1012 m3). With the exception of the year 1970 when Prudhoe Bay reserves were added, gas reserves have declined at a near-constant rate of 10 Tcf (2.8×1011 m3) per year since then. To help moderate or reverse this trend, the industry is extending its exploration and development efforts to include horizons with permeabilities in about the same range as common cement - i.e., microdarcies. The design of stimulation treatments to achieve commercial rates of production and reliable assessment of potential reserves in such low-permeability rocks demands accurate knowledge of their permeability, porosity, and flow properties. Though meager, there is sufficient information already available in the literature to suggest that some of the flow properties of these rocks differ markedly from those of more permeable rocks and, thus, require closer study.

Results of several different studies of the properties of low-permeability gas-producing horizons have been published previously. A study by Thomas and Ward2 showed that the permeability of cores from the Pictured Cliffs and Fort Union formations were affected significantly by confining pressure. Porosities, however, were not altered greatly. They also reported that the presence of a simulated connate water saturation (about 500(0) reduced gas permeabilities to only 10% to 20% of the specific gas permeability. Vairogs et al.3 concluded that very low-permeability rocks are affected by stress to a greater degree than those having higher levels of permeability. This agreed with results reported earlier by McLatchie et al.4

Tannich5 mathematically studied liquid removal from fractured gas wells in low-permeability horizons and concluded that in very low-permeability rocks, cleanup times could be extensive but that permanent formation damage was not likely. The study, however, provided no measured experimental data of the flow properties of low-permeability rocks.