bluuebunny/crossref_metadata_2025 huggingface dataset:
Improved Pressure Response Representation and Reduction of Numerical Dispersion Effects in Reservoir Simulation
Authors: Laprea-Bigott Marcelo , Morse Richard A.
Published: December 2007

A study has been made of the effects of numerical dispersion in reservoir simulation. A one-dimensional two-phase (water-oil) numerical model has been used in this investigation.

Instead of the regular single-point upstream transmissibilities, a new technique is proposed which consists of keeping track of the position of the displacement front, and using an interblock pseudo transmissibility. It is shown that a very significant reduction of the numerical dispersion of flood fronts and much improved representation of pressure history are obtained when using these modifications.

The applicability and effectiveness of this technique is illustrated by comparisons of numerical examples with theoretical and data published in the literature. The method proposed in this study can be implemented in any finite-difference reservoir simulator without much reprogramming effort, provided the displacement process to be simulated can be described by the Buckley-Leverett theory.
Analytical Modeling of Oil Recovery by Steam Injection: Part II. Asymptotic and Approximate Solutions
Authors: Yortsos Yanis C. , Gavalas George R.
Published: December 2007

This article studies the development of asymptotic and approximate solutions for the growth of the steam zone in steam injection processes in one-dimensional reservoirs at constant injection rates. These solutions are generally derived by using integral balances which include heat losses to the surroundings and the hot liquid zone. In this way, the effects of preheating, caused by heat transport in the hot liquid zone ahead of the steam front are fully accounted.

At the beginning of injection the advance of the front is well described by the Marx-Langenheim model, provided that the injection rates are sufficiently high. At longer times deviations occur and a criterion is developed, in terms of a single heat transfer dimensionless parameter R, that defines the time interval of applicability of the Marx-Langenheim model. The asymptotic behavior at large times depends solely on a dimensionless parameter A, defined as the ratio of the latent to the total heat injected. It is shown that the final dimensionless expression does not depend on R (i.e., on the injection rates), although the time taken to reach the asymptotic state is significantly influenced by R.

An approximate analytical solution that reduces to the respective asymptotic expressions at small and large times is obtained under conditions of high injection rates (R ≫ 1). The solution is shown to give a better approximation to the steam zone rate of growth for intermediate and large times than the approximate expressions developed by Marx and Langenheim3, Mandl and Volek4, and Myhill and Stegemeier5. For a wider range of operating conditions (including low injection rates), i.e., for R between 1 and ∞, an approximate numerical solution based on a quasi-steady state approximation is presented. The proposed solution requiring very modest computation is expected to give reliable results under a variety of operating conditions.
Modeling of Filter Cake Buildup Under Dynamic-Static Conditions
Authors: Ershaghi Iraj , Azari Mehdi
Published: December 2007

A method is discussed whereby the numerical solution of equations describing the filtration process of drilling fluid may be used for prediction of cake buildup and filtrate volume into a given zone. The data required for the simulation study include estimation of cake permeability during the dynamic phase, filtrate viscosity, cake compressibility and porosity, and pressure differential against the formation.

Application of the technique allows sensitivity analysis of important parameters controlling the filtration process in a given operation. Furthermore, estimation of invasion radius may be made in advance for determination of optimum timing for logging and improvements in log interpretations. This will allow the design of the best mud composition for a given application.
The Coal Bed Methane Potential of the Raton Basin, Colorado
Authors: Tremain Carol M.
Published: December 2007

In order to determine the coal bed methane potential of the Raton basin, Colorado Geological Survey personnel studied the geography, the geology, the history of oil and gas exploration, and the coal resources and past production in the Raton coal region. Data gathered during study of the above disciplines, along with direct measurements of the coals’ gas content, can be used to estimate the methane potential of the Raton basin.
Perspective on Devonian Shale Gas Exploration
Authors: Dean Claude S.
Published: December 2007

Since fractured reservoirs are essential to production, exploration rationales specific to the Devonian shale unconventional gas resource are characterized by a geologic fracture creating mechanism. One such predicts intense fracturing in the shale wherever proximally associated with the major thrust faults of the Appalachian overthrust belt. Gruy Federal No. 1 Grainger Co. (DOE EGSP-TN9), a U.S. Department of Energy (DOE)-funded rank wildcat located in Grainger County, TN, successfully tested that rationale. The well penetrated the Saltville Thrust Fault (stratigraphic throw: over 10,000 feet) and encountered the Devonian-Mississippian Chattanooga Shale in the lower plate. The shale proved to be 720 feet thick, of which 480 feet or 67% was anomalously radioactive (25 API above shale base line). Two hundred twenty (220) feet of core was recovered from the most highly radioactive (organic rich) intervals and a full suite of wireline logs was run. Widespread and locally intense fracturing in the shale, especially in the organic sections, observed in the core and evidenced by the logs vindicates the exploration rationale. The well will be hydraulically fractured and tested to evaluate production potential.
The Unique Methane Gas Deposit in Lake Kivu (Central Africa) - Stratification, Dynamics, Genesis and Development
Authors: Tietze Klaus
Published: December 2007

Lake Kivu, situated in Central Africa, contains a scientific and economic peculiarity: 63.109 m3 of methane at STP are dissolved in the deep part of this lake. The gas is held in the water by a special density stratification. The lake has recently been systematically explored during a German research expedition. With help of the results of the expedition and theoretical exploitation models the basis for development of this unique methane deposit has been created.
Influence of Coalbed Characteristics and Geology on Methane Drainage
Authors: Finfinger Gerald L. , Prosser Leonard J. , Cervik Joseph
Published: December 2007

Methane drainage in advance of mining using horizontal holes continues to expand. Interpretation of coalbed characteristics and geology in relation to drilling procedures and gas flows will provide additional information for further development of this technique. A study conducted in the Pittsburgh coal-bed at Bethlehem Mines Corp., Marianna mine 58, showed the effect of coalbed discontinuities, such as clay veins and sandstone channels, on drilling of horizontal boreholes and on gas flows. It has shown the need to adapt drilling techniques to the varying degrees of hardness encountered within the same coalbed.
Drilling Long Horizontal Coalbed Methane Drainage Holes from a Directional Surface Borehole
Authors: Diamond William P. , Oyler David C.
Published: December 2007

Three primary horizontal methane drainage holes totaling 2,428.4 meters (7,967 feet) have been completed in the Pittsburgh coalbed from a directional surface borehole. Directional control and sidetracking techniques developed during the project increased the horizontal drilling rate from 24.4 meters (80 feet) per day initially to 64.9 meters (213 feet) per day on the third horizontal hole. Drilling data indicate that horizontal holes can be drilled substantially longer than the maximum 977 meters (3,207 feet) achieved.
Effect of Laboratory Core Cleaning on Water-Oil Relative Permeability
Authors: Jennings H.Y.
Published: December 2007

Predictions of reservoir performance are usually based on laboratory measurements of core properties. Laboratory measurements, for example of oil recovery by waterflooding, are in turn related to the wettability of the rock surface. This has been shown by recent papers in the petroleum literature on the subject of wettability. Data have already been presented by this laboratory which show that wettability determines the shape of the water-oil relative permeability curves for a given porous medium. Thus, ideally, laboratory measurements should be made on cores which have the same wettability as the reservoir rock. This paper presents results of laboratory relative permeability measurements on oil field cores. Measurements were made in the water-oil system using the dynamic or "Penn State" relative permeability method. Saturations were obtained by using a radioactive oil soluble compound. Data were obtained on cores as taken from the field in an unextracted condition. Measurements were then made on the same cores after toluene extraction.

A comparison of the relative permeability vs saturation curves obtained from the core samples before and after extraction showed a measurable change in the curves, but the changes were small and not due to significant changes in wettability. It can be concluded that the laboratory procedure of core cleaning with toluene extraction and subsequent handling during core analysis does not significantly change the relative permeability characteristics from those of the core material at the start of the core analysis operation. This conclusion is based on data from cores that were preferentially water-wet, cores that were preferentially oil-wet, and cores that were of intermediate wettability.

Introduction

Reservoir rocks are porous media with high specific surface area and exceedingly fine pore structure. It is not difficult to understand why a knowledge of the surface properties of reservoir rocks is fundamental to an understanding of how fluids flow in such porous media. The molecular processes that occur on the surface of the reservoir minerals and at the fluid interfaces have been shown to be a dominating factor when considering the recovery of oil from porous media. Intensive research is being conducted by most oil field research laboratories in an to evaluate qualitatively and quantitatively the role of wettability. The activity in this field can be verified by noting the number of recent publications and patents dealing with the subject of "wettability". Prior to these recent articles, only a meager amount of wettability data was available in the petroleum literature. These articles show that wettability can materially affect predictions concerning the volume of oil-in-place, and controls to a great degree the relative success of completion methods and several recovery processes.
Emulsion Characteristics Associated With An Alkaline Water Flooding Process
Authors: Chang Mun-Sik M. , Wasan Darsh T.
Published: December 2007

This paper presents the results of an investigation of emulsions containing an acidic crude oil from Wilmington Field, California, and sodium hydroxide/sodium orthosilicate solutions. The effect of alkaline water formulation on emulsion characteristics was determined.

The characteristics of emulsions were evaluated as a function of salinity, alkali type, and alkali concentrations in the aqueous phase. Emulsion stability, as defined by the coalescence rate of oil droplets in water-external emulsions, was determined as a function of salinity and alkali type. Shear viscosity measurements were made for both the oil-external and water external emulsions formed as a result of crude oil/alkaline water interaction. When the emulsions were oil-external, the degree of incorporation of water by the oil was measured in terms of oil phase volume swelling. The effect of divalent ions on shear viscosity and phase volume swelling were also evaluated.

The results indicate that there is some optimum salinity in the aqueous phase which needs to be maintained to minimize the problems associated with viscous emulsions. Also the emulsions formed with sodium hydroxide are different from those formed with sodium orthosilicate, especially in the presence of divalent ion salts, so that different salinities are required to minimize the shear viscosity of emulsions for the two systems.
Improving Cement Bond in the Rocky Mountain Area by the Use of Spacer, Wash, and Thixotropic Cement
Authors: Waremburg Philip A. , Kirksey James M. , Bannister Charles E.
Published: December 2007

Extensive results from field tests in the Rocky Mountain area show how cement bonding may be improved through the use of a spacer, wash, and thixotropic cement. These results are the culmination of nearly three years field work undertaken to determine what factors affect bonding and what methods or materials could be used to consistently improve the cement-to-pipe and cement-to-formation bond.

This paper discusses the recognized conditions associated with poor cement bonding and the materials that were used alone and in combination to improve cement bonding. Bond logs and other data are presented to show the results obtained through the use of a spacer, wash, and thixotropic cement. Other techniques used to improve cement jobs are briefly discussed.
Foamed Hydrocarbon Stimulation Water Sensitive Formations
Authors: Holcomb David L. , Callaway Ralph E. , Curry Lynn L.
Published: December 2007

A system of synergistically combining fluorocarbon and hydrocarbon surfactants has been developed to provide specific foaming agents which will function effectively in various hydrocarbon media. The uses of these agents are potentially tremendous in foam fracturing, paraffin and heavy hydrocarbon removal, hydrocarbon/water hydrostatic head removal, and foamed drilling operations.

Development and research of three specific foaming agents in three different condensates will be reviewed to correlate data necessary to optimize foaming agent selection.

The hydrocarbon media that can be foamed are virtually unlimited and include kerosene, diesel, condensate, aromatic solvents, crude oil and water/condensate combinations.

This technique provides a new alternative for completion and stimulation in areas where formation sensitivity to water must be considered.
Petroleum Vaporization Recovery by High Pressure Gas Injection
Authors: Barney C.L.
Published: December 2007

This paper presents a method for estimating recovery and performance under a program of high pressure gas injection in volatile oil reservoir under vaporization conditions. A discussion or the equations and data needed to make the estimates is given with a description of how these data are obtained. A description of vaporization phenomena during the recovery process is also given.

The "vaporization process as a means of recovery in volatile oil reservoirs" is defined as a pressure maintenance program, whereby gas is injected into the oil column of a reservoir under high pressure, resulting in oil production by miscible displacement and absorption. The vaporization recovery process is a relatively new concept in oil reservoirs even though a similar process has been used for years in condensate reservoirs. When carried out under proper conditions, the program is expected to yield very high oil recovery.

The recovery method is developed by using an injected gas reservoir oil phase diagram and certain volumetric balance equations. A volumetric balance of various reservoir fluids is maintained by simultaneously solving sweep efficiency of the respective fluids. A sample calculation is included.

Introduction

In 1951, Atlantic initiated a high pressure gas injection project in its Block 31 field in West Texas. Although current comparative recovery data are not available from this project, it is known to be performing successfully. Atlantic has continued to pioneer the high pressure, miscible gas injection theory of production as evidenced by papers starting in 1950.

Even though the vaporization process of hydrocarbon recovery has been used for many years in condensate reservoirs, it is a relatively new concept in oil reservoirs. As is true in condensate reservoirs, very high recovery is expected when the process is applied to oil reservoirs.
Wave Theory and Free-Surfaces - A Study of the Motion of Oil Reservoir Fluids
Authors: Rowan G.
Published: December 2007

This paper deals with the time-varying solutions of free-surface problems in porous media as an extension of the steady-state theory developed by M. King Hubbert. Examination of the equations shows that a marked similarity exists between these and those of the linear exact wave theory for the propagation of a disturbance at the interface of two superposed fluids. This purely formal analogy is extended so that solutions in hydrodynamic theory may be transformed quite simply to give solutions to similar problems in porous media.

The auxiliary problem in water wave theory, namely the shallow water problem, is next considered. The resulting equation is found to exhibit a similar analogy to the Boussinesq equation or the Dupuit-Forchheimer theory of ground-water flow.

On the basis of these analogies and the relationship between the theories of deep and shallow water waves, an analysis is made of the errors involved in the Dupuit approximation. A discussion on the application of the Dupuit approximation to model experiments indicates the importance of the size of the model on the interpretation of results. A method is suggested for analysing gravity flow problems by means of a combination of the Dupuit theory and the more exact theory.

Introduction

This paper is concerned with the study of the motion of an interface separating immiscible liquids of different density and viscosity in a porous medium. It is assumed that the flow of the fluids in question is governed by Darcy's law and that the presence of an interface is due to complete segregation under the action of gravitational forces. Hence in a multi-fluid system, whenever gravitational effects are of importance, interface or free-surface problems naturally present themselves.

Strictly speaking, the term "free-surface" is usually applied to the hypothetical surface of demarcation between air and water in ground water studies. However, it is a convenient description and is applied quite generally to surfaces of separation as defined above, thus avoiding any confusion with the interfacial phenomena studied in capillarity theory.
Coal Conversion Plans and Plants in the United States
Authors: Fedde Paul A. , Hagerman Robert L.
Published: December 2007

Just a few years ago energy analysts were projecting U.S. energy requirements to be 150 quads (1 quad = 1015 Btu) by the year 2000. The rapid rise in energy costs, particularly petroleum derived fuels, since 1973 has resulted in the spending of millions of dollars by industry and individuals to increase the efficiency of energy utilization in the U.S. This trend toward energy conservation has become so apparent that recent estimates of U.S. energy requirements for the year 2000 have been lowered, and now range between 95 quads and 120 quads.

Coal usage which was 770 million tons in 1979 (15 quads) is projected to be approximately 40 quads in 2000 (see Table 1), a 150% increase. Coal, which supplied 18% of the U.S. energy requirements in 1979, is estimated to supply about 37% of the U.S. energy in the year 2000. This huge increase in coal consumption is needed if the U.S. is to meet its goal of two million barrels of oil equivalent energy from coal conversion and shale oil plants by the mid 1990's.

Table 2 is my estimate of the contribution of substitute fuels to U.S. energy requirements in 2000. To supply 7.5 quads of substitute fuels will require building five 100,000 bbl/dy oil shale plants, twenty 100,000 bbl/dy coal liquids plants and twenty-eight 250 MMCFD coal gasification plants in a period of just 20 years. The capital cost of these plants in today's dollars is in excess of $175 billion. Most of the coal conversion plants produce both gaseous and liquid product streams so it will not be possible to classify the plants as simply as stated above. The proposed Texas Eastern-Texas Gas Sasol type plant for example will produce the equivalent of 56,000 barrels of oil per day but 44% of the plant output, on a Btu basis, will be pipeline quality gas.
Application of the Centrifugal Model to the Study of Reservoir Behavior
Authors: Goodwin R.J. , Massey D.G. , Crawford Paul B.
Published: December 2007

A centrifugal reservoir model has been constructed for studying solution gas-drive phenomena. The model has been used to study the effect of oil properties, well location and producing rate on the recovery of oil from a solution-gas-drive reservoir. Gravity segregation effects were minimized by the slow rotation of the model about a horizontal axis. The studies were conducted on a synthetic porous media having a permeability of less than 10 md; the bubble point of the crude oil ranged from a few hundred to over 2,000 psi; connate water was present.

It was found that the crude oil properties had a very large effect on the total oil recovery. The effect of well spacing and rate of production is presented. It was found that for the conditions of the test the well spacing and production rate may have an effect on the oil recovery depending on the reservoir system and producing technique.

Introduction

In 1952 the Texas Petroleum Research Committee initiated a research project to study criteria for determining the most efficient rate of producing an oil reservoir. A large number of articles bearing directly on this subject have appeared in the literature. Three recent reports on this subject have included literature reviews so a review is not repeated here. Field data have been used, model studies made, and certain mathematical techniques have been used to estimate the effect of reservoir rock and fluid properties, rate of production and well spacing on solution gas-drive performance.

Following the review of the literature it was decided that a laboratory model would be built in which one could simulate a solution gas-drive reservoir so that one could determine experimentally the effect of production rate, well spacing, and fluid and reservoir properties on oil recoveries.

Small parts of reservoirs have been built in various shapes and sizes to represent reservoir conditions; however, gravitational effects in the actual reservoir and the part of a reservoir used in the laboratory may not be the same. The overall effects of gravity in either an actual reservoir or a part of a reservoir used in the laboratory are not well defined.
A Systematic Approach to the Relative Permeability Problem in Reservoir Simulation
Authors: Molina Nelson N.
Published: December 2007

Direct experimental determination of three-phase relative permeability data is extremely difficult. For this reason, numerical models describing multiphase flow in petroleum reservoirs determine three-phase relative permeability functions using two sets of the more easily measured two-phase data, i.e., water-oil and gas-oil displacement systems. However, because of the wide range of scattering of the laboratory-measured two-phase relative permeability data, it is usually very difficult to determine a representative average function whether by reservoir layers (different lithologies) or reservoir regions (several facies or reservoir units). It follows that our greatest need today in the area of reservoir simulation is a quick, relatively inexpensive procedure to match reservoir performance data based on adjustments of representative relative permeability functions assigned on a permeability distribution basis. A systematic approach to this problem is discussed in this study.

Fluid saturation and relative permeability values corresponding to the beginning, intersection, and end points of the displacement process were correlated as a logarithmic function of air permeability to determine initial saturation functions for each rock type (regions with identical capillary pressure and relative permeability properties). This procedure proved to be useful for water-oil and gas-oil systems of carbonate and sandstone reservoirs. The so determined saturation functions were curve fitted using exponential equations as starting points during the history match phase. Subsequently, the shapes of the relative permeability curves were adjusted by changing the exponents of the fitting equations in order to match WOR and/or GOR production history. This procedure assumes no mass diffusion and isothermal reservoir conditions. This approach has been successfully applied to match reservoir production history of different oil fields of the world, even when adverse mobility ratio conditions were present in stratified reservoirs.

The following are included: typical fluid saturation and relative permeability correlations as a logarithmic function of air permeability, relative permeability fitting equations, and applications to match the observed performance of selected case histories.
Compositional Variations within a Hydrocarbon Column due to Gravity
Authors: Schulte A. M.
Published: December 2007

Gravity forces may generate and stabilise variations in composition along the hydrocarbon column in thick reservoirs. From the condition of thermodynamic equilibrium in a hydrocarbon column in the field of gravity one may determine with an equation of state the variations in composition with depth. The developed calculational procedure uses the Soave and Peng-Robinson equation of state. Results are shown for various hydrocarbon systems. Aromatics content, overall pressure and the introduction of binary interaction coefficients in the equation of state are seen to have strong influence on the predictions of gravity segregation. Observed compositional variations and corresponding variations in bubble points/dew points as well as the occurrence of natural miscibility between cap gas and reservoir oil can be explained.
Adsorption and Interfacial Tension Dynamics of Surfactants in Porous Media
Authors: Ramirez W. Fred , Friedman Francois , Denoyelle Ludovic C. , Shuler Pat J.
Published: December 2007

The objective of this work is an understanding of the dynamic mechanisms associated with the adsorption of surfactants on porous media and the dynamics associated with the lowering of the interfacial tension between oil and a surfactant solution.

Most studies on surfactant adsorption have assumed that the adsorption mechanism occurs rapidly as compared with convection and dispersion. Trogus et al. (1977) have proposed a kinetic model which at equilibrium yields the Langmuir isotherm. Results of using this model have shown that the kinetic rate constant increases with an increase in phase velocity. An explanation for this variation is to postulate separate mass transfer and kinetic adsorption mechanisms. A new model is proposed and tested which consists of the solute moving to the rock-fluid interface by a mass transfer mechanism and then adsorbing to the rock via a kinetic mechanism. The mass transfer rate constant has been evaluated and correlated as a function of phase velocity. The correlation obtained for Berea sandstone and Triton X-100 (non-ionic) surfactant is in good agreement with existing mass transfer correlations for packed-bed reactors, indicating the validity of our mass transfer model for describing the transport of surfactant through porous media.

Using a spinning drop tensiometer, the dynamic response of the interfacial tension between n-decane, and a brine solution of Texas No. 1 surfactant or TRS 10–80 surfactant was obtained. A kinetic adsorption/ desorption rate model for the dynamic behavior was developed. At high surfactant concentrations the normal interfacial tension decrease stops abruptly at a specific plateau value. This plateau breakpoint seems to be due to an abrupt phase change at the interface which prevents the continued adsorption of surfactant monomer molecules. The breakpoint disappears at low surfactant concentrations allowing a normal equilibrium condition to be reached. An increase in surfactant concentration increases the interfacial tension dynamic response rate. Close to the optimal salinity the dynamic behavior is slow with Texas No. 1 and fast with TRS 10–80. We have linked these observations to the Van der Waals energy of desorption and the Gouy surface potential of the double layer.
Determination of Fissure Volume and Block Size in Fractured Reservoirs by Type-Curve Analysis
Authors: Bourdet Dominique , Gringarten Alain C.
Published: December 2007

A new type-curve is presented for analyzing wells with wellbore storage and skin in double porosity systems. This type-curve applies to damaged, acidized, and fractured wells in fissured reservoirs. In addition to the usual well and reservoir parameters (permeability, skin, wellbore storage constant and length of the fracture intersecting the well), analysis yields characteristic parameters that can provide quantitative information on the volume of fissures and the size of porous blocks in the reservoir. These, in classical methods, could only be obtained if semilog radial flow were present at both early and late times, (thus yielding two characteristic parallel semi-log straight lines on a Horner plot), a condition that is seldom satisfied in practice.

The analysis method presented in the paper is illustrated with actual field examples from several different fissured reservoirs.
Techniques for Fully Implicit Reservoir Simulation
Authors: Au Anthony D. K. , Behie Alda , Rubin Barry , Vinsorne Kaz
Published: December 2007

This paper summarizes the methods that have been used to develop fully implicit and highly implicit reservoir simulators.

The techniques developed emphasize simplicity and clarity. The governing equations, written in fully implicit form are treated as functions. These coupled nonlinear functions are solved by Newtonian iteration, the derivatives of the Jacobian matrix being evaluated numerically. A procedure is described for the efficient evaluation of the Jacobian.

A technique is presented for avoiding variable substitution in variable bubble point problems. This is accomplished by means of a novel pseudo solution gas formulation.

An efficient method for including two-point upstream into fully implicit simulators, without increasing the Jacobian bandwidth, is described. The scheme is based on a fully implicit upstream mobility plus an explicit correction term derived from the two-point mobility formulation. In addition a new method called centralized upstream is given. The new method has less truncation error then two-point upstream, and is little more difficult to implement.

A modified Crank-Nicholson method is described for reducing the time truncation error associated with large time steps in implicit models. The modified version does not exhibit the usual stability problems associated with the Crank-Nicholson method on nonlinear problems.

A section on well models shows how a simple enhancement of conventional well models can be used to account for the position of a well within a grid block. It is also shown how to introduce a multiblock well completion into an implicit simulator without destroying the block-banded form of the Jacobian, or without increasing the bandwidth.

An efficient iterative solution method is described for the sparse block-structured Jacobians. The method extends the SIP factorization to block form and uses minimizations and orthogonalizations to accelerate the convergence rate.

Several applications and examples are provided. A water coning example is included to show the stability and convergence characteristics of the Newtonian iteration. A vertical cross-section oil resaturation problem with variable bubble point is used to illustrate the pseudo solution gas formulation. The modified Crank-Nicholson method is applied to a one-dimensional Buckley-Leverett type problem.
Evaluation of Procedures and Instrumentation Available for Time-Temperature Stability Studies of Crosslinked Fluids
Authors: Conway Michael W. , Pauls Richard W. , Harris Lawrence E.
Published: December 2007

The rheological characterization of crosslinked fracturing fluids, even at ambient conditions, has proven to be a very difficult task. Because no unique Theological parameters exist for time-shear dependent fluids, the utility of n’ and K’ data gathered on these fluids depends entirely on the validity of the methodology used to prepare and evaluate the fluids. Since the prediction of fracture geometry and proppant placement is highly dependent on the n’ and K’ values used, it is imperative that the rheo-logical parameters are representative of the fluid that is used in the field.

Present methods used to prepare cross-linked fluids for rheological characterization will be discussed. Criteria useful in evaluating laboratory procedures will be presented.

Only a limited amount of instrumentation is available for measuring the rheological properties of fluids at temperatures greater than 212°F (100°C). The inherent limitations of the available equipment will be reviewed and data showing the effect of procedural variations will be presented. Procedures aimed at providing time-temperature stability data will also be presented.
Visual Logging for Inspection and Troubleshooting
Authors: Davis Ken E. , Fleniken John A.
Published: December 2007

The waterwell industry has been using submergible television cameras for years to aid them in casing inspections and troubleshooting wells. Their success ratio has been outstanding but the oil industry and others have only had limited success. The reason is usually the lack of clarity in the drilling or work-over fluid. Displacement of these fluids is generally affected by fluid density, fluid velocity, temperature and the size pipe in which the displacement is being made. This large number of variables indirectly affects water clarity in that you must displace the dirty drilling or completion fluid before a television camera can be used. Field tests have been conducted on the effects of these variables and the results offer suggestions for the solution of these associated problems. Downhole pictures are presented showing the effects of the aforementioned variables as well as unique failures of casing and the positions of various types of lost equipment. Some open hole logging is also presented.
Short Term Pressure Build-Up Analysis in Vertically Fractured Wells, Constant Rate and Variable Rate Cases
Authors: Beardall Terence J.
Published: December 2007

Empirical approximation equations to the uniform flux and finite conductivity vertically fractured well models are presented. The equations are of similar form and can be superposed to derive a wide range of analysis techniques analagous to those for radial flow. In this paper, both constant rate and variable rate build-up cases are discussed. New plotting methods are derived which extend the normal Horner radial flow straight line back to much earlier shut-in times. The techniques are particularly useful in the analysis of short term pressure build-ups, which do not reach pseudo-radial flow.
Analysis of Vertical Fracture Length and Non-Darcy Flow Coefficient Using Variable Rate Tests
Authors: Pascal H. , Quillian Ronald G. , Kingston D. J.
Published: December 2007

In this investigation, a new method is presented for predicting both the non-Darcy flow coefficient and vertical fracture length based upon single-point, variable flow drawdown tests of shallow, low permeability gas reservoirs. The mathematical model simultaneously incorporates the effects of non-Darcy flow and variable rate expressed as a continuous function of time, thus providing a corrected pressure-drawdown versus time relationship.

Pascal and Quillian1 described a method of analyzing variable flow tests where rate variation, usually declining during the test, is considered a continuous function of time. Solutions proposed in the foregoing article offered credible values for permeability and skin when matched with well production histories. Pascal, Quillian and Kingston have now expanded upon the basic concepts presented under reference 1 to provide solutions for vertical fracture length and the non-Darcy flow coefficient, using single-point variable flow data, resulting in a comprehensive model for analyzing transient pressure behavior.

A correlation between the non-Darcy flow coefficient and permeability is also proposed.

In low permeability gas reservoirs, the effects of variable (declining) rate become less apparent as flow time is extended. Conversely, the influence of non-Darcy flow becomes more dominant with increasing flow time.

The model is illustrated using several field from hydraulically fractured gas wells in a low permeability reservoir.
Inclusion of Radial Flow in Use of Permeability Distribution in Waterflood Calculations
Authors: Ache Paul S.
Published: December 2007

In 1949, William E. Stiles presented an article entitled, "Use of Permeability Distribution in Water Flood Calculations" in which he outlined a method for prediction of water flood performance. In the method Stiles derived equations which were based upon the assumption that the direction of fluid flow from an injection well was in a linear direction. These equations were mathematically derived by a statistical presentation of permeability data.

This paper introduces to the method the fact that initially the direction of fluid flow from an injection well is radial and then continues to treat the direction of flow in three distinct periods. The first is radial flow; the second is a period of transistion from radial to linear flow; and the third is after reservoir fill-up when it is assumed that linear flow conditions do predominate. Equations are then derived for the radial flow period which express water cut and the commensurate fraction of water flood oil recovered in terms of dimensionless permeability. Additional modifications are also suggested in application to field performance.
New Steel Alloy and Certification Procedure for High Pressure Wellheads
Authors: Burley J. D. , Greer J. B. , Royer C. P.
Published: December 2007

Deep, abnormal-pressure, sour gas well development has resulted in the investigation of alternate alloys for use in high-pressure wellhead equipment. Evaluation of more traditional alloys produced results that were considered to be deficient for thick-wall, high-pressure equipment. This paper describes laboratory evaluations of a chromium-one percent molybdenum low alloy steel family that provides more uniform throughwall physical properties and manufacturing experience with this alloy for a high-pressure wellhead application. Also described is a certification procedure that more closely approximates the metallurgical structure and physical properties for large, thick-wall, high-pressure equipment.
New Instrumentation for Managing Sand-Problem Prone Fields
Authors: Stuivenwold P. A. , Mast H.
Published: December 2007

Sand influx in oil and gas wells may cause serious erosion problems and result in substantial deferment in production. Tools have been developed for continuously monitoring sand production both at surface and downhole. These tools are applicable in dry and wet gas and single-phase liquid. They are now being applied in field operations. A prototype sand detector for multi-phase flow has been developed and successfully tested in the field.
An Automatic Timestep Selection Scheme for Reservoir Simulation
Authors: Jensen Ole K.
Published: December 2007

The literature concerning timestep selectors is reviewed with discussion of applications to reservoir simulation.

A first order predictor-corrector method is applied to automatically select the time-step size in a finite difference steam injection reservoir simulator. The step size is estimated from the first neglected term in the series expansion; and a set of rules is developed for accepting new step sizes. Comparisons are made with a commonly used method which limits the time step based on the linear extrapolation of maximum changes of key variables. The comparisons show reductions in the number of time step used; easier usage and to some degree elimination of rapidly oscillating timestep.
Three Dimensional Permeability Measurements
Authors: Morita Nobuo , Gray K. E.
Published: December 2007

This paper provides theory and experimental procedures to calculate principal permeabilities and directions from data obtained with a whole core type permeameter which has radial and axial flow measurement capabilities with two openings attached to cylindrical curved surface. The conventional plug method to determine anisotropic permeability was also modified to improve its accuracy; plug number and sample spacing were rigorously designed using error sensitivity numbers.

To check the validity of the apparatus, experiments were run using anisotropic Berea sandstone.
Foamed Acid Stimulation: Success in the Illinois and Michigan Basins
Authors: Ford William G. F. , Burkleca Lee F. , Squire Kenneth A.
Published: December 2007

Foamed acid has been used successfully in the stimulation of oil and gas wells in the Illinois and Michigan basins. Advantages derived from the use of foamed acid in fracture acidizing treatments are presented. Results have shown that foamed acid outperformed conventional acid as a means of increasing production when used in fracture acidizing treatments. This paper discusses various aspects of job design and summarizes treatment results.
Analysis of an Extended Well Test to Identify Connectivity between Adjacent Compartments in a North Sea Reservoir
Authors: Gringarten A. C.
Published: December 2007

The paper demonstrates the usefulness of extended well tests and advanced interpretation techniques to complement seismic information with an example from a North Sea reservoir. This reservoir is heavily faulted but seismic indicated that the faults were discontinuous, thus suggesting good communication between the various parts of the reservoir. To verify this, tests were run on the two wells already drilled: an extended four month test on a vertical well, followed by a four and a half month shut-in; and a conventional test on a horizontal well. The extended test was analyzed in both the conventional way (one flow period at a time) and by deconvolution of the entire pressure and rate histories. The combination of the interpretations of the tests on both wells allowed to delineate compartments in the reservoir, to assess their connectivity and to correct the seismic information.

The paper illustrates the difficulty of interpreting data in the conventional way, as most interpretable flow periods are short (200 hours maximum) compared to the length of the test and individually may be misleading, as derivative shapes tend to be dominated by features reflecting the way log derivatives are calculated rather than by the geology. It is shown that deconvolution is free from these limitations and provides a much clearer picture of the well behavior.
Innovative Knowledge-Driven Approach for Shared Earth Model Building
Authors: Rainaud J.-F. , Perrin M. , Bertrand Y.
Published: December 2007

During the last four years, the Institut Français du Pétrole (IFP) has tried to meet the present-day need for oil companies to produce large amounts of 3D geological models that can be updated, extended, modified or rebuilt by any potential user (Shared Earth Models = SEM) by setting up a co-operation with a few French academic research teams.

This multidisciplinary group comprises geologists, reservoir engineers, computer scientists and mathematicians. The all over goal of the co-operation is promoting innovative solutions for an easier production of 3D hydrocarbon reservoir models and for the sharing of the building process and of the results over the net. The work of the group is based on the belief that this challenge can be faced by substituting to the current data-driven modeling approach a knowledge driven approach [J.F. Rainaud & al; 2004]. This means that the geological surfaces included in a geological model should not be considered as geometrical or graphic items but as true geological objects. The topology of the surface assemblage is then no longer an intrinsic feature of 3D model but it can instead be deduced from geological properties attached to the geological surfaces themselves (nature of the surface: stratigraphic limit / fault, geological position: intersecting / unconformable / on-lap).

The objective of the paper is to present how we use geological knowledge, classical surface representations and well bore information to build, populate, and automatically update complex geological and reservoir models based on common geological constraints. One of the most interesting features of this approach for reservoir engineering is the capacity to embed this automatic consistent modeling of the geological and reservoir grid into a complete loop of history matching. The all over proposed medology is illustrated by examples emphasizing various results already obtained
Efficient Wellbore Cement Sheath Design Using the SRC (System Response Curve) Method
Authors: Fourmaintraux D. , Bois A.-P. , Franco C. , Fraboulet B. , Brossollet P.
Published: December 2007

Inter-zonal flow of fluids behind cemented casings has plagued the EP industry for years. This has led to the development of many models, but there is still a need for a unified and practical method to design cement sheaths.

Three leakage categories can be distinguished depending on the physical state of the cement when leakage occurs, and this paper focuses on modeling cement sheaths while in solid state (CSSS). It shows first that predictive simulations are not very efficient, even if tremendous improvements have been made the past ten years. Then, a new modeling method (inspired from the Convergence-Confinement Method for designing of tunnel supports) is introduced, the SRC (System Response curve) method, that simplifies CSSS modeling. Using a case of history, where SRC method has been used to help in designing a well, the paper highlights the importance of pore pressure and shrinkage in predictive cement-sheath modeling.