bluuebunny/crossref_metadata_2025 huggingface dataset:
Successful Deployment of Thermal Simulation Technology to Field Office
Authors: Hong K. C. , Cook G. W.
Published: December 2007

We successfully deployed thermal simulation technology to a field office to enable the staff responsible for operating steamfloods to conduct on-site studies of their projects. The success was attributed to a number of factors, including (1) placement of a simulation expert in the field office, (2) formation of a thermal modeling focus group, (3) introduction of simulation software on PC's, (4) increased speed and memory of desktop PC's, and (5) designation of reservoir heat management as a key job responsibility for thermal engineers. Field engineers now routinely use this technology to evaluate investment decisions and development alternatives, manage steamflood reservoirs, and optimize project operations.

Field engineers have carried out many simulation studies by use of the desktop technology. Examples include (1) optimizing slim-hole injector-injector spacing and injector-horizontal producer spacing in a dipping reservoir, (2) fine-tuning water and steam injection periods in a fieldwide application of the water-alternating-steam process, and (3) evaluating the economic potential of heavy oil, trough reservoirs. These studies have resulted in adding value to heavy oil assets by reducing operating costs or increasing reserves.
A Reservoir Study of the Friendswood Field
Authors: Blair E.A. , Enquist B.R. , Good L.W. , Walton E.C.
Published: December 2007

To temporarily stop migration of oil into the original gas cap, the existing gas injection project in this Texas Gulf Coast field was expanded. For the purpose, water turned out to be a more efficient displacing medium than gas. By unitizing the field and then injecting 80,000 barrels of water a day, oil migration can be stopped and 55 million more barrels of oil will be recovered.

Introduction

The Friendswood field (sometimes referred to as Webster) was discovered by Humble in 1937. It is located on the upper Texas Gulf Coast immediately south of Houston (Fig. 1), and has productive sands originally encompassing more than 4,100 acres. Approximately 215 wells were required to fully develop the field to 20-acre spacing. The sands are very prolific and the average well exhibits a productivity index of approximately 29 B/D per psi productivity index of approximately 29 B/D per psi drawdown. Cumulative Frio sand oil production has been 310 million bbl, and reservoir pressure has dropped only 340 psi since discovery. Principal production has been from upper Frio sands of Miocene age. Although prorated together, these sands have been divided into 17 members for reservoir control purposes. A small amount of oil (2 million bbl) has been produced from the Marginulina sands, which lie just above the Frio. The field contains several fault systems, and, because of fault juxtaposition, communication occurs between some of the sand members. Several studies, resulting in MER hearings, workover programs, and a gas injection program, have been conducted in the past. For the study discussed here, those past programs were reviewed and additional necessary programs were determined. Current fluid contacts for each sand member were ascertained on the basis of conventional neutron logs, pulsed neutron logs, induction electric logs, and well production histories. Oil and gas volumes were then production histories. Oil and gas volumes were then mapped for original and current conditions. Material balance and unsteady-state water influx calculations were used to match past reservoir behavior and to predict future performance. predict future performance.

JPT

P. 685
Scaleup of Reservoir-Model Relative Permeability With a Global Method
Authors: Li Dachang , Cullick A. S. , Lake Larry W.
Published: December 2007

Geoscientists and engineers commonly build geologic or geostatis-tical reservoir models that contain more than 106 grid cells. For flow simulation, the number of grid cells must be reduced by a factor of 10 or more. Such scaling up necessarily involves a loss of information that must be restored through the use of effective or pseudorelative permeabilities. This paper describes an approach to generate such functions that, when combined with global absolute permeability scaleup,1 offers a significant improvement over existing "dynamic pseudo" methods that require extensive fine-grid simulation and that are very sensitive to flow conditions.1

The method builds on previous work to scale up absolute permeability through a global technique that minimizes the loss of permeability variance and the spatial correlation in an unequally sized grid system. This paper shows that, when the residual permeability following global absolute permeability scaleup is spatially uncorrected, the velocity of a fluid-displacement shock front correlates with a well-defined universal heterogeneity number that is related to the permeability distribution. The paper presents an analytic computation of the pseudo as a superposition of the shock velocities for the residual field, found from a table look-up, and the fine-grid field when the fine-grid relative permeabilities (usually based on measured relative permeabilities) have the same normalized form. The method is then generalized to multiple functional forms of fine-grid-cell relative permeabilities with new relative permeability and capillary pressure averaging methods. The procedure eliminates the need for fine-scale simulation and is equally applicable to geologic deterministic or stochastic models.

The paper describes the technique in detail and demonstrates the procedure with one two-dimensional (2D) and one three-dimensional (3D) reservoir model waterflood simulation. In the latter case, the number of cells is reduced from 23,600 (fine scale) to 4,000 (coarse scale) with very little change in the water breakthrough and water-cut behavior.
Building Extensible Interactive Applications - A Case Study
Authors: Frost Robert , Diserens Michael , Williams Glyn
Published: December 2007

We use the development of an interactive program, which analyzes the results of experiments on rock samples and uses these results realistically in reservoir simulation, to illustrate various software engineering techniques. These techniques promote portability, flexibility, and fast application development through the reuse of existing software components. We describe guidelines for achieving compiler and windowing system independence, along with the benefits of using an object-oriented software architecture.

A software module called the Calculator provides extendibility to the user by controlled exposure of internal program variables.
Factors Affecting Liquid-Liquid Relative Permeabilities of a Consolidated Porous Medium
Authors: Lefebvre du Prey E.J.
Published: December 2007

Many laboratory displacement tests have been performed to study factors affecting relative performed to study factors affecting relative permeability curves, residual saturations, and shape permeability curves, residual saturations, and shape of recovery curves. Three sintered artificial porous materials and pure fluid mixtures have been used for this systematic study.

The factors were interfacial tension, the viscosity and the velocity of the fluids (in the dimensionless group σ/µv), the wettability, and the viscosity ratio. The results can be used as guidelines for research on recovery processes.

Introduction

Waterflooding is by far the most common secondary recovery technique. Several processes (polymer injection, surfactant injection, hot water injection, etc.) attempt to improve sweep efficiency by affecting some of the factors involved in the displacement process. For orienting research on these processes, process. For orienting research on these processes, a good knowledge of how these parameters affect local displacement efficiency and over-all sweep efficiency in the reservoir is required.

We present here an attempt to understand the effects of such parameters:

(1) at the microscopic level on the shape of relative permeability curves and the values of final saturations obtained by flooding, and

(2) at the macroscopic level, on the behavior of one-dimensional displacement.

Effects of the morphology of the porous medium were not included in this study. We mainly examined the effects of fluid properties on fluid displacement in only three specific porous media. These three artificial sintered media were made of Teflon, stainless steel and alumina. For the following reasons they were very well suited to the systematic investigation undertaken:

(1) they are homogeneous and so the results are not subject to macroscopic heterogeneity effects;

(2) they are identical in the same series, thus permitting the results to be compared from one experiment to another

(3) their constant and well-defined chemical composition makes it possible to perform wettability measurements outside the porous medium;

(4) they are consolidated like most of reservoir rocks;

(5) they have good mechanical properties and so can be washed successively without being altered and

(6) the three media used correspond to three possible cases of wettability, i.e., Teflon is strongly oil-wet, alumina is strongly water wet, and stainless steel may have intermediate wettability depending on the fluids considered.

Some of our results reported here (concerning experiments with Teflon at a viscosity ratio of one) were presented earlier.
A Relationship Between Pore Structure and Residual Oil Saturation in Tertiary Surfactant Floods
Authors: Dullien F.A.L. , Dhawan G.K. , Gurak Nur , Babjak L.
Published: December 2007

Photomicrography and mercury porosimetry have been used jointly to determine the pore-size distributions of various sandstone samples. The two curves differed drastically from each other for all samples.

Two unconsolidated packs consisting of uniform 250u glass beads and mixed 44-250u beads, respectively, as well as the sinters prepared from them, were also investigated.

An index, D, measuring the difficulty of recovering waterflood residuals in tertiary surfactant floods has been constructed from the two different porosimetry curves. Reasonably good correlation porosimetry curves. Reasonably good correlation bas been obtained between D and residual oil saturations found in tertiary surfactant floods.

Introduction

This paper presents our first results in a continuing study of pore structure and oil recovery.

The problem of how pore structure might influence oil recovery has been discussed by several authors. There is, however, no known method whereby one could rank various porous media (e.g., different sandstones) on the basis of pore structure in the order of decreasing amounts of expected residual oil saturations assuming identical conditions of flooding (identical oil, water, wetting and pressure gradient for the various sands. In this pressure gradient for the various sands. In this work we have taken an initial step toward this ideal objective. The prime target of the treatment has been the problem of correlating the extent of recovery of waterflood residuals by tertiary surfactant floods with the pore structure. The degree of difficulty presented by the pore structure in the way of recovering the isolated oil masses left behind by a waterflood has been expressed in the form of an index that is calculated from a mercury porosimetry and a photomicrographic pore-size distribution curve obtained on the sample. pore-size distribution curve obtained on the sample. The degree of correlation obtained amounts to a promising start in the case of tertiary surfactant promising start in the case of tertiary surfactant floods, and there also appears to be some correlation between the residual oil saturations found in the waterfloods and the pore structure.

In this paper we are considering only the case of water-wet formations and moderate viscosity ratios.
Fracture Dimensions in Frac&pack Stimulation
Authors: Fan Yong , Economides M. J.
Published: December 2007

A model is introduced to predict dynamic fracture dimensions in frac&pack stimulation. Design aspects of the two-in-one step treatment techniques, required by soft and high-permeability reservoirs are discussed. A pressure-dependent leakoff model, based on the transient flow of a non-Newtonian fluid displacing a reservoir fluid has been developed and incorporated with fracture mechanics concepts to simulate the entire process of frac&pack treatments including fracture propagation, inflation, proppant packing, and closure. Results obtained in this study indicate the considerable difference between traditional fracturing and frac&pack treatments. In the latter, fracture length is much less important than fracture conductivity. This work shows how to terminate the fracture growth at the appropriate time, and how to design frac&packs resulting in fracture widths several times larger than those for traditional fracturing.
Computing Pressure Distributions in Wedges
Authors: Chen Chih-Cheng , Raghavan Rajagopal
Published: December 2007

Pressure distributions for wells in wedge-type systems are derived in terms of the Laplace transformation Characteristics of responses are discussed and computational issues are addressed. The algorithm given here is a practical tool for analyzing flows in wedge-type systems and may be incorporated immediately into existing software packages. Existing solutions, in the petroleum-engineering literature, for pressure distributions in wedges are a subset of the solution given here.
Measurement of Aperture and Multiphase Flow in Fractures With NMR Imaging
Authors: Kumar Arun T. A. , Majors Paul , Rossen William
Published: December 2007

Nuclear magnetic resonance imaging (NMRI) techniques were used for the measurement of the spatial distribution of apertures and two-phase fluid distributions in rock fractures. Rock models of known apertures were used to validate the NMRI technique. NMRI aperture values were in good agreement with nominal and hydraulic aperture values. The fracture signal in porous rock was isolated by NMR spin-spin relaxation times. Areal distributions of oil and water in an immiscible fracture flow were resolved on the basis of their NMR spin-lattice relaxation times.
Radiotracers in Gas-Liquid Transportation Problems-A Field Case
Authors: McLeod W.R. , Rhodes D.F. , Day J.J.
Published: December 2007

Presented here are the results of a field program to develop and Presented here are the results of a field program to develop and evaluate radiotracer techniques for simultaneously measuring linear velocities of the individual phases of a multiphase stream. The flow properties monitored were used to compare experimental two-phase pressure drops with values predicted by techniques currently used pressure drops with values predicted by techniques currently used in design work.

Introduction

Numerous studies have been published on the transportation of gas-liquid mixtures through pipelines. However, the range of applicability pipelines. However, the range of applicability of most of the methods suggested for describing two-phase flow is generally limited to the conditions under which the investigations were performed. This shortcoming can be attributed performed. This shortcoming can be attributed either to improper design and instrumentation of the experiments or to departure of the analytic models, upon which the correlations are based, from the physical model or both. Therefore, further research in two-phase flow is needed to obtain more meaningful data for the solution of gas-liquid transportation problems.

A prerequisite to understanding two-phase flow in a pipe is an adequate knowledge of the interrelationship between the velocities of the individual phases, individual densities, the gas volume fraction and the gas weight fraction. It is very difficult, however, to measure the relative velocities of the individual phases. In addition, the method most commonly used in the past to obtain the vapor volume fraction was very unsatisfactory. It constituted isolating a portion of the pipe by means of quick-closing valves, and subsequently measuring the actual quantity of liquid present. The volume fraction of vapor obtained in this manner was an average value over the length of the test section, so the effect of geometrical changes on density of the two-phase mixture could not be accurately determined. These are serious shortcomings of previous investigations of two-phase flow.

In recent years a technique that has become more common for measuring fluid flow involves the use of radioactivity. This technique now offers easy and accurate means of measuring the linear velocity of each individual phase (radioactive tracer survey), and both the density and void fraction (gamma-ray attenuation). The method reported here to determine linear phase velocities is the Isotope Velocity method; a slug of radioactive material is injected rapidly into the flowing stream, and the transit time of the radionuclide between positions of known detector separation is measured. The accuracy of such a flow measurement depends upon the strength of the gamma rays emitted by the chosen isotope, accurate knowledge of the internal dimensions of the pipe, detector sensitivity and velocity profile.

JPT

P. 939
A Study of Displacements in Microscopic Capillaries
Authors: Templeton Charles C.
Published: December 2007

Any explanation of the nature of multiphase fluid flow through porous media must ultimately involve a knowledge of the mechanism of such flow through the individual pores of the medium. To provide quantitative information of the latter type, a study was made of gas-liquid and liquid-liquid displacements in single uniform Pyrex capillaries with diameters as small as 4 microns.

Quantitative observation of air-liquid displacements with zero contact angle indicates the adequacy of a model based on Poiseuille's Law and the independence of capillary pressure and interfacial velocity. Consequently, this work discounts previous claims that flow is abnormally retarded in very small capillaries.

For the displacement of a very viscous oil by water in a capillary initially filled with water, flow is faster than predicted by the above model. This behavior is probably due to the existence of a thin annular film of water between, the oil column and the capillary wall as postulated by Yuster.

Introduction

The need for experimental observation of the microscopic nature of multiphase fluid flow, to further the understanding of the results of macroscopic flow investigations, has been previously recognized. Chatenever and Calhoun in connection with the API Project 47B have extensively studied the flow of fluids through layers of glass or lucite spheres between glass or lucite plates.

Lowman prepared an interesting film concerning flow in a single capillary, using an apparatus which made a moving interface appear stationary in the field of a microscope.

The purpose of the present investigation was to determine what contribution might be made to this field by comprehensive quantitative observation of gas-liquid and liquid-liquid displacements in single capillaries of uniform, very small diameter. The techniques used are similar to those of Lowman but incorporate improvements necessary for quantitative work. Quantitative observations must begin with fluids of simple chemical composition to provide a basis for analyzing the more complex behavior that may be expected with natural reservoir fluids. However, some qualitative observations on systems involving crude oils are presented.
Low Surfactant Concentration Enhanced Waterflooding
Authors: Wellington Scott L. , Richardson Edwin A.
Published: December 2007

A new gradient scaled flooding test procedure indicated that oil is mobilized by the leading edge of the surfactant dispersion curve where the concentration is low, 1 to 10 ppm. Underoptimum, highly interfacially active blends of anionic and cationic surfactants were formulated to take advantage of the displacement mechanism. Essentially all the initial or residual crude oil was removed from shaly sand packs using approximately 0.4 percent surfactant with less than 0.1 pore volume loss.
Thermally Induced Fractures: A Field-Proven Analytical Model
Authors: Detienne J-L. , Creusot Max , Kessler Nicolas , Sahuquet Bernard , Bergerot J-L.
Published: December 2007

Thermally induced fracturing (TIF) during water injection is a well-established phenomenon. TIF modeling implies solving equations simultaneously that conventional petroleum engineering applications deal with separately. Combining these equations leads to very complex computer programs. This has led to the need for a simple model, which we present in this paper. Coupling analytical expressions representing each of these phenomena, rather than the basic physical equations, has led to a computer program that can be run on a modern desk-top computer. This program has successfully matched the daily wellhead pressure and injection rate during a period of 3 to 5 years for injection wells in complex sandstone/dolomite reservoirs. The model can be used for injection-well monitoring as well as in a predictive mode when planning new water-injection projects. The algorithm is sufficiently simple to be implemented in a conventional reservoir simulator.
Recovery of Gas Condensate by Nitrogen Injection Compared With Methane Injection
Authors: Sänger Peter , Hagoort Jacques
Published: December 2007

Methane injection or gas cycling is the recovery process of choice for gas-condensate reservoirs. For economic reasons, however, this process can often not be implemented. An alternative injection gas may be nitrogen, which is relatively cheap and available everywhere. Nitrogen, however, causes stronger liquid drop-out in the mixing zone between the gas condensate and the injected gas, which could reduce recovery.

This paper presents the results of slim-tube experiments and numerical simulations of the displacement of a model gas condensate at reservoir conditions by both nitrogen and methane. The gas condensate used is a three-component hydrocarbon system representative of a North Sea reservoir. The phase behavior and physical properties of mixtures of the gas condensate and injection gas were calculated with an equation of state tuned by some selected pressure/volume/temperature (PVT) experiments.

The main conclusion of this study is that the displacement of gas condensate by both nitrogen and methane is a developed miscible process, which results in high condensate recoveries. The recovery is adversely affected by dispersion; nitrogen is more sensitive to this than methane.
Theoretical Aspects of Emulsification in Porous Media
Authors: Raghavan R. , Marsden S.S.
Published: December 2007

A theoretical analysis of the mechanism of emulsification in porous media is presented. As an initial step in the investigation of the dispersion of one liquid in another, the hydrodynamic stability of a liquid layer surrounded by two other liquids is studied by the application of perturbation methods. Criteria for the hydrodynamic stability of the liquid layer are developed and the critical condition at which the instability occurs is predicted. Any disturbance of the interface is amplified, and, finally, jets of one liquid shoot out into the other phase. The radius of the droplets, as well as the phase. The radius of the droplets, as well as the number of droplets, formed are then determined.

The analysis presented pays due care to the viscometric aspects of the dispersion of one fluid into another. The mechanism oil emulsification proposed is based on the hypothesis that viscosity proposed is based on the hypothesis that viscosity differences between displaced and displacing liquids can lead to emulsion formation.

Introduction

A considerable amount of the world's crude oil is produced in the form of stable emulsions. These produced in the form of stable emulsions. These must be broken down into their two constituents, crude oil and brine, before sale and transportation of the former and disposal of the latter. The application of new recovery methods such as thermal simulation and surfactant flooding has, in many cases, accentuated the problem of emulsion formation. This, together with the introduction of new recovery methods using emulsions or emulsion floods, has led to considerable interest in both the generation and the flow of emulsions. Since there is sound evidence that emulsions are generated in some instances while liquids are flowing in porous media, we have investigated some of the viscometric aspects of emulsification by considering the hydrodynamic stability of liquid-liquid interfaces in porous media. porous media.
The Statfjord Satellites: Challenges and Experiences During Development and Production Startup
Authors: Malmin P. C.
Published: December 2007

Production from the Statfjord Øst field was started up as planned and the project was completed within the overall budget. This paper reviews the handling of the more significant problems that were encountered during the development phase and gives a summary of the initial experiences after production startup.

After a description of the Statfjord satellite fields, the paper gives a résumé of the major tasks encountered during the development of these fields. The extensive modifications to the Statfjord C platform required by this project were performed while the platform was producing at its maximum capacity. Manning level and control of hot-work were two major issues in this context. In addition, the project team was able to add the necessary subsea equipment to ensure timely startup of gas production at Sleipner to the scope of the project. Two areas of environmental concern are described: (1) the reduction of flaring during well testing and (2) the containment of CO2 emissions as power consumption on the platform was increased.

Production from the two fields started in September 1994 and January 1995, respectively. After an initial running-in phase of a few weeks, production was very stable. The final challenge to overcome to start production was the need to get an agreement to reduce the continuous high production at Statfjord C to provide processing capacity for the Statfjord satellites.
Prediction of Gas Hydrate Formation Conditions in Aqueous Solutions of Single and Mixed Electrolytes
Authors: Zuo You-Xiang , Stenby Erling H.
Published: December 2007

In this paper, the extended Patel-Teja equation of state1 was modified to describe non-ideality of the liquid phase containing water and electrolytes accurately. The modified Patel-Teja equation of state (MPT EOS) was utilized to develop a predictive method for gas hydrate equilibria. The new method employs the Barkan and Sheinin hydrate model2 for the description of the hydrate phase, the original Patel-Teja equation of state3 for the vapor phase fugacities, and the MPT EOS (instead of the activity coefficient model) for the activity of water in the aqueous phase. The new method has successfully predicted the gas hydrate formation conditions in aqueous solutions of single and mixed electrolytes. The agreement between experimental data and predictions was found to be excellent.
A Contribution to Electrical Log Interpretation in Shaly Sands
Authors: Poupon A. , Loy M.E. , Tixier M.P.
Published: December 2007

Simple qualitative methods are explained for identifying those shaly sands in a well that are most likely to contain oil. A need for more precise measurement of the variables that enter shaly sand analysis is indicated. Field examples are given to illustrate the methods.

A theoretical discussion of the quantitative interpretation of shaly sands is given as a basis for discussion and as a guide for the future. While not generally capable of practical application at the present time because of the lack of sufficient accuracy of the electric log data, these methods may become more feasible in the future as the result of the improved logging methods now being introduced.

Introduction

Experience has shown that for porous formations containing only a negligible amount of clayey material, reliable information on the fluid saturation and porosity of the reservoir rocks can usually be derived from the electrical logs. The interpretation is based on empirical formulae relating the true resistivity of a porous formation to its lithologic character, to the resistivity of the interstitial water, and to the proportions of water and hydrocarbons in the pores. If the resistivity of the interstitial water is not known, its approximate value can be derived from the SP curve. The porosity can usually be determined to a good approximation from a MicroLog, or a MicroLaterolog.

When the reservoir rocks contain an appreciable percentage of clayey material, an additional factor is introduced into the analysis. In a clean formation, the matrix is an electrical insulator, so that the ability of the formation to conduct current is due only to the conductivity of the electrolytes in the pores; in a shaly formation, the shale constitutes a part of the rock matrix able to conduct current, and influences the resistivity of the formation.
Use of the Finite-Element Method in the Solution of Diffusion-Convection Equations
Authors: Shum Y.M.
Published: December 2007

A variational principle can be applied to the transient heat conduction equation with heat-flux boundary conditions. The finite-element method is employed to reduce the continuous spatial solution into a finite number of time-dependent unknowns. From previous work, it was demonstrated that the method can readily be applied to solve problems involving either linear or nonlinear boundary conditions, or both. In this paper, with a slight modification of the solution technique, the finite-element method is shown to be applicable to diffusion-convection equations. Consideration is given to a one-dimensional transport problem with dispersion in porous media. Results using the finite-element method are compared with several standard finite-difference numerical solutions. The finite-element method is shown to yield satisfactory solutions.

Introduction

The problem of finding suitable numerical approximations for equations describing the transport of heat (or mass) by conduction (or diffusion) and convection simultaneously has been of interest for some time. Equations of this type, which will be called diffusion-convection equations, arise in describing many diverse physical processes. Of particular interest to petroleum engineers is the classical equation describing the process by which one miscible fluid displaces another in a one-dimensional porous medium. Many authors have presented numerical solutions to this rather simple presented numerical solutions to this rather simple diffusion-convection problem using standard finite-difference methods, method of characteristics, and variational methods.

In this paper another numerical method is employed. A finite-element method in conjunction with a variational principle for transient heat conduction analysis is briefly reviewed. It is appropriate here to mention the recent successful application of the finite-element method to solve transient heat conduction problems involving either linear, nonlinear, or both boundary conditions. The finite-element method was also applied to transient flow in porous media in a recent paper by Javandel and Witherspoon. Prime references for the method are the papers by Gurtin and Wilson and Nickell. With a slight modification of the solution procedure for treating the convective term as a source term in the transient heat conduction equation, the method can readily be used to obtain numerical solutions of the diffusion-convection equation. Consideration is given to a one-dimensional mass transport problem with dispersion in a porous medium. Results using the finite-element method yield satisfactory solutions comparable with those reported in the literature.
Innovations in Handling and Processing Unconsolidated Cores
Authors: McCollough C.N.
Published: December 2007

Introduction

Techniques and equipment have been developed for preserving the integrity, of cores from unconsolidated preserving the integrity, of cores from unconsolidated sand reservoirs. New procedures are employed for coring, for removing the cores from the core barrel and handling them at the well site, and for preparing them for sampling in the core processing laboratory and preserving them for future use. The analytical laboratory methods used for drilling plugs with liquid nitrogen and mounting them in triaxially loaded holders are similar to those already reported and will not be discussed here.

The goal of the new techniques is to obtain essentially undisturbed samples in order to determine in the laboratory, under simulated in-situ conditions, such parameters as porosity, permeability, relative permeability, and formation factor, and to establish permeability, and formation factor, and to establish more precise geological and petrophysical relationships from cores.

The need for better data has arisen primarily from the large number of supplemental recovery projects in shallow sand reservoirs in California and elsewhere. These projects created a need for accurate reservoir data not critical during primary depletion. A majority of the shallow oil sands are unconsolidated and there is little or no cohesive strength in the fabric. Frequently when cores are recovered the better quality reservoir rock ends up as piles of sand in the core tray, and only the poorer rock with enough clay or cementation to bind it together can be sampled for laboratory analysis.

P. 1191
Combined Free and Forced Convection in Porous Media
Authors: Combarnous Michel A. , Bia Paul
Published: December 2007

An experimental study of thermal convection in a horizontal porous layer bounded by isothermal planes has been performed with and without a mean flow of the saturating fluid phase. The temperature distribution and heat transfer resulting from convection have been determined.

The theoretical criterion for the onset of convection (Rayleigh number NRa > 4p2) has been verified. For low values of NRa (< 260) a regular pattern of convective cells has been observed which may be motionless or moving depending on the experimental conditions. For NRa values higher than 260, another convective state has been found that is mainly unstable.

Numerical computations have been worked out that confirm the experimental results on the heat transfer and size of convective cells.

Introduction

Thermal convective currents may exist in a porous medium when the vertical component of the temperature gradient runs in the same direction as the gravity vector. Such a configuration is possible in some cases during a real in-situ combustion test4 or during hot fluid injection. A general understanding of convection is also of interest for analyzing the abnormal temperature gradients sometimes observed in oil and gas reservoirs.22

From the phenomenological standpoint a distinction must be made between the natural or free convection occurring in a closed volume and the mixed or combined free and forced convection arising when there is a mean flow of the fluid phase.

Natural convection in porous media has been the subject of numerous experimental attempts to determine a convection criterion, e.g., by using a linear theory,1,2,9 and to measure the mean heat transfer.3,7 Numerical studies8,10,15,19,20 have also been made, and their results are not always in good agreement with experimental observations. However, no thorough study of mixed convection has been made except for a theoretical analysis of the convection onset criterion5 and some qualitative experimental observations.4

This paper presents some findings concerning both the natural and mixed convection of an incompressible fluid in a homogeneous horizontal porous layer bounded by two parallel impervious isothermal surfaces. The temperature for the cooler upper surface is T1 and that of the lower surface is T2=T1+?T.
The Effect of Interfacial Films on the Displacement of Oil by Water Porous Media
Authors: Bourgoyne A.T. , Caudle B.H. , Kimbler O.K.
Published: December 2007

Many crude oils contain surface active compounds that will collect at an oil-water interface to form a rigid film. Since interfacial forces are important in the displacement of oil by water in reservoir rock, the presence of rigid films in the reservoir could alter the recoverable oil by water invasion. Experimental work in water-wet Porous media indicates that the presence of interfacial films decrease the amount of recoverable oil in highly heterogeneous porous medial but usually has no effect in nearly homogeneous systems.

Introduction

It is generally accepted today that petroleum is derived from sedimentary organic matter. Meinschein, working with several soils and recent marine deposits, found that nonhydrocarbon organic compounds, similar to compounds found in living things, made up about 80 percent of the extracted organic material. Porphyrins, percent of the extracted organic material. Porphyrins, amino acids, and sulfur compounds were the main constituents found. Amino acids are the basic units of protein and, as such, are an essential part of all organisms. Erdman shows several possible reactions for the conversion of amino acids and carbohydrates to the common low molecular weight hydrocarbons. Baker, as well as Hodgson and Hitchon, gives evidence that complex natural organic compounds act as "solubilizers" to allow the movement of hydrocarbons by ground water from the source bed to the reservoir. Trace amounts of soluble polar organic compounds are usually found in reservoir water. Thus, the high molecular weight surface active material found in crude oils (such as the porphyrinmetal complexes, esters, ketones, aldehydes, porphyrinmetal complexes, esters, ketones, aldehydes, carboxylic acids and organic nitrogen compounds) are probably remnants of the organic matter from which the crude oil originated.

With many crudes, the presence of significant quantities of surface active material can result in the formation of a rigid film at an oil-water interface. If the interfacial area is reduced, the film will often wrinkle, indicating the formation of a solid membrane. The presence of film material has an important effect in the formation and stability of oilfield emulsions, and in the deposition of paraffin in oilfield equipment. Fig. 1 is a paraffin in oilfield equipment. Fig. 1 is a photograph taken during a microscopic examination photograph taken during a microscopic examination of film material obtained after breaking a water-in-oil emulsion. Shown in the photograph are ruptured film sacs that once stabilized two droplets of water in the emulsion.

Interfacial forces are important in the displacement of oil by water in reservoir rock, and the presence of rigid Elms could alter these forces. Since much of the available laboratory data on the displacement of oil by water in porous media was obtained using relatively pure water and oil, the effect of rigid films should be known if we are to apply these data to reservoir systems.
Concerning the Calculation of Inflow Performance of Wells Producing from Solution Gas Drive Reservoirs
Authors: Standing M.B.
Published: December 2007

Estimating probable flow rates of wells producing from solution gas drive reservoirs is a problem frequently encountered by petroleum engineers. One approach to an answer involves the simultaneous solution of the well's inflow performance relationship (IPR) and the rate-dependent pressure losses in the well tubing, surface flow lines, and chokes. Nind covers very nicely several graphical methods of accomplishing the simultaneous solution. This note presents relationships that can be used to obtain IPR presents relationships that can be used to obtain IPR curves applicable to bounded solution gas drive reservoirs in which the average reservoir pressure is less than the reservoir fluid bubble-point pressure. Vogel's dimensionless IPR equation is the basis for the development. An example illustrates how future IPR curves can be developed from a current productivity index value.

Vogel developed a general dimensionless relationship for wells producing under conditions outlined above and under pseudosteady-state conditions given by Eq. 1.

(1) = 1 - 0 .2 - 0 .8 ,

where

qo = stock-tank oil producing rate, B/D pwf = wellbore flowing pressure, psi pwf = wellbore flowing pressure, psip = average reservoir pressure, psi p = average reservoir pressure, psi qo max = maximum rate the well would producefor conditions of pwf = 0.

Eq. 1 can be rearranged to

= ...............(2)

The productivity index of a well is defined by

(3) J =

Substitution of Eq. 3 into Eq. 2 yields

(4) J =

Physical conditions inherent in Eq. 4 are that reservoir Physical conditions inherent in Eq. 4 are that reservoir gas and oil saturations, as well as reservoir pressure, vary with distance away from the wellbore, and that the well's skin factor is zero.

Let us now consider the situation in which fluid saturations are the same everywhere in the reservoir. This is analogous to a "zero drawdown" situation. Let J* be the well's productivity index under these conditions. Mathematically,

(5) lim J J* =

Applying the limit conditions to Eq. 4 yields

(6) J* =

P. 1141
Polywater and Reservoir Engineering
Authors: Davidson L.B.
Published: December 2007

Research by Deryagin and Fedyakin during the last decade showed that a solid surface can influence the properties of an adjacent liquid to depths on the order properties of an adjacent liquid to depths on the order of a micron. In particular they found that viscosity increases substantially near the solid-liquid interface.

In many porous materials pore throats on the order of a few microns are quite common. Consequently, "wall effects" may significantly alter viscosity of fluid flowing through such materials and it becomes important to determine how seriously current models of flow in porous media are affected by this phenomenon. phenomenon. As a simple illustration of the role played by "wall effects," consider flow through a single capillary of radius r. Assume that the viscosity at the center of the tube has a constant value, and near the tube wall a constant value . The viscosity changes fromto at the radial position us. The "permeability" of the tube is defined for a Newtonian fluid by:

=, .........................(1)

where eff is an effective viscosity for flow through the tube. If there were no "wall effect" eff would equal .

To measure the single-tube "permeability" it is customary to carry out flow tests at constant pressure drop, p, and to compute "permeability" using the viscosity of the bulk fluid, . Let this computer "permeability" be denoted as k calc. Then

= .......................(2)

Now, let

Xr = and X = .

Then it is not difficult to show that for a Newtonian fluid

(3) 4 = X + (1 − X )Xr

The deviation between the calculated and effective values is a linear function of the ratio X . The slope of the line tends to zero as Xr increases. As a particular example, suppose Xr = 0.5 and the viscosity particular example, suppose Xr = 0.5 and the viscosity is twice as large as the usual value . Then the calculated "permeability" of the tube is equal to 53.1 percent of the effective value. percent of the effective value. This simple example shows that the near-surface structuring of liquid could significantly influence flow behavior in porous materials. Whether or not this is actually true depends on the depth of the liquid structuring, the magnitude of changes in fluid properties resulting from the structuring, and the percent of area available to flow that is affected by structuring. The last factor is determined by the pore-size distribution of the system.

P. 1263
Predicting Pore Compressibility of Reservoir Rock
Authors: Marek B.L.
Published: December 2007

The effective pressure in a reservoir is characterized by two sets of stress conditionsthe stress condition at the time the reservoir is discovered and the stress condition existing during the pressure decline period due to production of reservoir fluids. Since correlations of pore compressibility presented in literature may have been obtained by several different types of laboratory testing procedures, a technique of converting these various procedures to a reference set of stress conditions is required for reservoir evaluation.

With the method presented here we can quickly interpret results of various pore compressibility measurements regardless of the testing procedure used.

The limits of effective stress at the time of discovery of the reservoir, according to van der Knapp, can be described by the equations:

effective stress = = ( )

for "passive" earth pressure condition, and

effective stress =

for "active" earth pressure condition. In these equations:Pz = overburden pressure, psipi = initial pore fluid pressure, psi= pore fluid stress, psi= mean external stress, psiA, B = constants related to the Mohr failure diagram

van der Knapp suggests that the "passive" stress condition exists at initial reservoir conditions and further chooses values of A and B that lead to ( - ) = 5/9 (Pz - Pi). However, on the basis of fracture gradient data, it seems more reasonable to assume values of A and B for consolidated sandstones, limestones and dolomites that give a value of ( - ) = (Pz, - Pi).

P. 340
Decline-Curve Analysis
Authors: Gentry Robert W.
Published: December 2007

This paper explains a simple and effective method for graphically solving all three types of production decline. The three types of declines are:

exponential hyperbolic, and harmonic.

The mathematical development of these curves was by Arps.

Decline curves are one of the most extensively used forms of data analysis employed in the evaluation of oil properties. Often future production is extrapolated as a straight line on semilog paper (exponential or constant-percentage decline) because this type of decline is the easiest to handle mathematically and graphical. This is done irrespective of the fact that several investigators have reported that this type of decline is rare and that actual oil production usually follows a hyperbolic decline. production usually follows a hyperbolic decline. However, the hyperbolic decline is difficult to analyze mathematically or graphically. The most recent method utilizes transparencies, as proposed by Slider.

The method outlined below greatly simplifies the solution and extrapolation of decline curves. The first four columns of Table 1 list the rate:time and cumulative-production:rate relationships as developed by Arps. The equations are all solutions of the differential equation D = Kq = - (dq/dt)/q. In each instance two unknowns must be calculated from the two relationships. They are the decline exponent n and the initial decline rate Di. The third unknown, qi, can be obtained from the production history of the well. First. the rate:time relationship is manipulated to solve for the value of Dit in terms of the ratio (qi/qt). These relationships are shown in Column 5 of Table 1. Next, the rate:time relationship is solved for Di, and this value of Di is substituted into the cumulative-production:rate relationship. This relationship is then solved for the value of Qt/(qit) in terms of (qi/qt), These relationships are shown in Column 6 of Table 1. Two graphs can then be constructed by selecting a value for n and then substituting values of (qi/qt into the relationships. A curve on each graph for the selected value of n will be produced. This can be done for any desired number of n values from 0 n 1. (See Figs. 1 and 2.) These curves can then be used to analyze and extrapolate decline curves from actual production history.

P. 38