bluuebunny/crossref_metadata_2025 huggingface dataset:
Improved Estimation Algorithms for Automated Type-Curve Analysis of Well Tests
Authors: Barua J. , Horne R. N. , Greenstadt J. L. , Lopez L.
Published: December 2007

The analysis of well-test data by automated type-curve match by use of computers is a subject of current interest. Although the automated type-curve-matching technique is often an improvement over conventional methods, there are certain practical problems that occur in its application. Except in the case of a homogeneous reservoir, many reservoir models require the estimation of several parameters. Unless the initial guess is very good, the estimation procedure for many parameters may fail to converge. Even in cases that have only a few parameters, contours of the objective function show that some parameters are inherently ill-defined.

To date, most applications have used the Gauss method or its modifications, such as the Levenberg-Marquardt algorithm. The Newton method should be better suited to the estimation of ill-defined parameters because it uses a search direction that is aligned in the direction of these parameters. This study investigates the application of the Newton method (and an important modification. the Newton-Greenstadt method) to automated well-test analysis. It shows that the added expense of the Newton-Greenstadt method is often justified by the improvement in performance achieved. In many cases, the Newton-Greenstadt procedure converges almost as fast as the Gauss-Marquardt method, yet is more reliable in cases where one (or more important, more than one) parameter is ill-defined.
Study of Subcritical Flow Through Multiple-Orifice Valves
Authors: Surbey D. W. , Kelkar B. G. , Brill J. P.
Published: December 2007

Increased oil and gas production from offshore areas and hostile environments has led to a greater use of multiple- orifice-valve (MOV) wellhead chokes. Unlike conventional wellhead chokes, MOV's can be adjusted to any given choke area while under pressure, allowing wells in remote locations to be controlled from a central site. Data on the behavior of multiphase flow through MOV chokes have not been available in the past. This study investigated high-pressure (400 to 800 psia [2.8 to 5.5 iMPa]), two-phase air/water flow through a 2-in. [5.1-cm] MOV choke. Single-phase air and water data were obtained to determine the valve-sizing coefficient, Cv. A correlating parameter was determined with two-phase data to predict the subcritical two-phase pressure drop. This parameter was found to be a function of the gas/liquid ratio, upstream pressure, and choke opening. A mathematical model based on experimental observations was developed to predict the subcritical pressure drop across the choke for single-phase liquid flow.
Influence off Microporosity on the Evaluation off Hydrocarbon Saturation
Authors: Worthington Paul F. , Pallatt Nadia , Toussaint-Jackson John E.
Published: December 2007

Saturation exponents, determined from electrical measurements on core plugs desaturated with air as the displacing fluid, are influenced by pore size and pore-size distribution. This influence, which manifests itself through the resistivity index, is most pronounced in microporous rocks. Two controlling factors are electrical tortuosity and surface conduction effects, both of which increase as the electrolyte-filled pore volume (PV) is reduced. Theoretical and experimental data have indicated that the saturation exponent can increase or decrease during desaturation, depending on how these factors interrelate. With due caution, the risk of errors in estimates of hydrocarbons in place caused by the use of an inappropriate saturation exponent can be greatly reduced.
Determination of Lithology From Well Logs by Statistical Analysis
Authors: Busch J. M. , Fortney W. G. , Berry L. N.
Published: December 2007

This paper presents a method of predicting lithology by statistical analysis of wireline log measurements with calibration to a core lithology standard. Although an example of the technique applied to the Shublik formation of the Prudhoe Bay area, North Slope, AK, is developed and presented, the method can be applied to any field where some core has been taken. The Shublik, a complex mixture of seven clastic and carbonate rock types, presents a common problem: how can the rock lithology best be identified from wireline logs? During recent work on the reservoir description of the Shublik, it became necessary to answer this question.

A lithology standard must be available to calibrate against during development of a log model of lithology. For the Shublik, the core available provided an excellent sample of the total formation. Using the statistical technique of discriminant analysis, we were able to evaluate a number of log models and to choose the most appropriate one. The final log model chosen for the Shublik formation works quite well and correctly predicts lithology 75% of the time.
Infill Drilling in a Steamflood Operation: Kern River Field
Authors: Restine J. L. , Graves W. G. , Elias R.
Published: December 2007

An infill well program involving 574 wells in previously steamflooded idle reservoirs proved to be economical and increased recovery in some areas from 50 to 58%. These wells were recompleted to zones under active steam drive and showed similar recovery increases in addition to acceleration of reserves. These increases in recovery were attained without additional fuel.
Waterflood Calculations for Multiple Sets of Producing Wells
Authors: Hovanessian S.A.
Published: December 2007

The method of characteristics which reduces the Buckley-Leverett nonlinear, partial differential equation to two first-order, linear differential equations is applied to the solution of a water flood recovery problem for multiple lines of producing wells and one line of injection wells. The application of the method is described by a numerical example, and a brief theoretical background is given. From the results of this study, it is concluded that the cumulative water injected and oil produced are the same for single and multiple sets of producing wells.

Introduction

In this paper, the method of characteristics is applied to the solution of a waterflood recovery problem with multiple lines of producing wells and one line of injection wells. The application of the method to this type of recovery problem considerably simplifies the procedure of obtaining a numerical solution. It differs from the method described by Kern because it eliminates the need for integration in obtaining saturation fronts. In addition, the saturation history at any location within the field is obtained from a single diagram (time vs distance with saturation as a parameter).

The paper includes a brief theory of the method of characteristics and its application to the solution of oil recovery problems. A numerical example is worked out, and the cumulative oil recovery-vs-time curve for a system with multiple sets of producing wells is obtained. This curve is then compared with the recovery curve of a system with only one set of producing wells.

From this study, it is concluded that the cumulative water injected and oil produced are the same for single and multiple lines of producing wells. However, the recovery time is considerably longer for multiple sets of producing wells.
Improved Magnetic Model for Determination of Range and Direction to a Blowout Well
Authors: Jones Douglas L. , Hoehn Gus L. , Kuckes Arthur F.
Published: December 2007

Magnetic logs are commonly used in wild-well kill operations to guide a relief well to a blowout well. Estimates of distance and direction to the blowout well are highly dependent on the assumed magnetic model of the blowout well casing. Theoretical and experimental results show that the magnetic poles of a long magnetized cylinder fit an exponentially distributed model rather than the standard impulsive-pole model. Magnetic techniques for determining range and direction from a relief well to a blowout well are explained, and modifications of these techniques based on the new magnetic model are developed. The techniques presented here can be used during drilling operations with data from most measurement-while-drilling (MWD) tools. Substantial improvements in range estimates are achieved for near- and medium-range targets.
A Management Look at Natural Gas
Authors: Golush W.B.
Published: December 2007

Natural gas is a major factor in the domestic petroleum industry and should command wellhead prices commensurate with its impact on the energy markets. By 1968 gas is predicted to supply 72 per cent of the petroleum energy consumed in those markets where gas and hydrocarbon liquids are in competition with each other. Industry must intensify its exploration efforts to find an annual average of 26 trillion cu ft of gas over the next 10 years. This is needed to back up the predicted 5 per cent annual increase in gas demand. Unit expenditures for finding and developing petroleum hydrocarbons have increased at a faster rate than have unit wellhead revenues per million Btu of combined domestic crude oil and natural gas production. In fact, at constant dollars, unit revenues for combined wellhead production have decreased. Wellhead prices ranging from 18 to 25 cents/Mcf for new gas contracts seem to offer the incentive to explore for and to develop gas reserves. The average wellhead price in 1958 of 11.9 cents/Mcf on all gas must rise to 18 to 20 cents within three years and to 25 cents within 10 years to sustain intensified exploration activities. In addition to firmer prices on new gas commitments, producers must receive higher prices on gas delivered under older contracts. In both cases, Federal regulation of about 65 per cent of the marketed gas production presents a number of uncertainties. Pending an acceptable solution to the regulatory problem, producers should aggressively pursue natural gas activities. Exploration should be concentrated in areas offering the required incentive prices. Sales should be made preferentially into non-jurisdictional markets, or to those interstate markets offering the greatest wellhead revenues.

Introduction

There are some 6,000 producers in the United States who sell significant quantities of natural gas and who are not primarily engaged in the operation of interstate gas pipelines. These "independent producers" sell gas in both interstate and intrastate commerce and are heavily engaged as well in crude-oil finding and development.
New Production Logging Technique for Horizontal Wells
Authors: Joly E. L. , Dormigny A. M. , Catala G. N. , Pincon F. P. , Louis A. J. P.
Published: December 2007

A new technique for running production logs in horizontal wells has been developed. The logging tools attached to a rigid stinger are pumped down a service tubing until they reach the zone to be logged. This paper describes the new technique and the first two case histories, Lacq 91 (France) and Rospo Mare 6 (Italy).
Liquid Holdup in Wet-Gas Pipelines
Authors: Minami K. , Brill J. P.
Published: December 2007

An experimental study of two-phase flow was conducted to investigate liquid holdup in wet-gas pipelines. The liquid-holdup data were obtained by passing spheres through a 1,333-ft [406.3-m] -long, 3.068-in. [77.93-mm] -ID horizontal pipe and measuring the liquid volumes removed. Three different two-phase mixtures were used.

The holdup data were compared with predicted holdup values and were used to evaluate a mechanistic model for stratified flow. None of the methods could accurately predict liquid holdup in this low-holdup region.

Two new empirical liquid-holdup correlations for horizontal flow were proposed. The first is strictly for wet-gas pipelines (0<yL <0.35); the second is for any horizontal pipeline (0< yL<1.0).
Retrieving Stuck Liners, Tubing, Casing, and Drillpipe With Vibratory Resonant Techniques
Authors: Gonzalez Orlando J.
Published: December 2007

This paper discusses the constructive use of resonant power transmission down the axial length of a stuck oilfield tubular for the purpose of extracting the tubular from inadvertent (e.g., stuck drillpipe or tubing) or purposeful (e.g., gravel-packed liners) confinement. Resonant and nonresonant oilfield systems are examined with appropriate field measurements of resonant parameters.
Transverse Dispersion in Slug-Mode Chemical EOR Processes in Stratified Porous Media
Authors: Wheat Michael R. , Dawe Richard A.
Published: December 2007

Transverse dispersion in multilayered media of moderate permeability contrast has been examined experimentally and theoretically. Continuous and slug-mode displacements at unit and nonunit mobility ratios have been conducted in a layered beadpack model with a permeability contrast of approximately 3:1. Layer-width and residence-time effects have been quantified and scaled to core and reservoir dimensions. Transverse dispersion can be significant for reservoirs with layers less than 100 cm [40 in.] thick and core material with layers less than 1 cm [0.4 in.] thick. The data can be used for validating simulation packages written for chemical dispersion.
Patterns of Permeability in Eolian Deposits: Page Sandstone (Jurassic), Northeastern Arizona
Authors: Goggin D. J. , Chandler M. A. , Kocurek G. , Lake L. W.
Published: December 2007

The eolian, Jurassic Page sandstone of northeastern Arizona is marked by a highly ordered heterogeneity. The heterogeneity is expressed by the intricate association of stratification types, which are a direct result of the depositional processes. The dominant stratification types in eolian reservoirs are grainflow, grainfall, and wind-ripple deposits, which form on the lee faces of migrating dunes; interdune deposits, which form between migrating dunes; and extra-erg deposits, which occur sporadically when other depositional environments encroach upon an eolian system. These stratification types each have a unique permeability range, which implies that the fluid migration routes in eolian reservoirs will be dictated by the geometry and types of stratification present.

One of the most important aspects of this study is the correlation of qualitative geologic descriptions with quantitative variables such as permeability. About 2,000 measurements were made with a field minipermeameter on an outcrop of the Page sandstone. These data show that three distinct permeability modes directly relate to the different stratification types.

Permeability exhibits two components of variation: a structural or systematic component and a random or noise component. In this context, the structural component may be correlated to identifiable geologic processes, whereas the random component covers all unexplained variations. These definitions, however, are entirely scale dependent. That is, by decreasing the scale of measurement, structure is revealed in the random variation. This scale dependence is evident in the subject outcrop and, using several statistical tools, we are able to illustrate the "nested" nature of the spatial variation in permeability.
Interpretation of Miscible Displacements in Laboratory Cores
Authors: Bretz Robert E. , Orr Franklin M.
Published: December 2007

Results of stable, first-contact miscible displacements are presented for three San Andres carbonate cores from west Texas and eastern New Mexico. All three cores showed evidence of significant heterogeneity at the core scale. Effluent composition measurements were interpreted with two relatively simple models of mixing during flow in heterogeneous porous media: the Coats-Smith (CS) model, which represents the pore space as flowing and stagnant fractions with mass transfer between them, and a porous sphere (PS) model, which describes flow between an assemblage of porous spheres with diffusive interchange of material in the spheres with fluid flowing past them. Parameters for the two models are reported and compared. Direct measurements of some parameters from thin-sections agreed well with least-error parameters for one sample for which comparisons were possible. PS model fits showed less error than CS model fits.

The form of the PS model is then used to examine how mixing effects change with changes in flow velocity, displacement length, the length scale associated with heterogeneity, and the rate of exchange of material between flowing and stagnant zones. We conclude that for reservoirs with scales of heterogeneity larger than those present in core samples, laboratory core displacements do not provide evidence about mixing behavior at field scale.
Analysis of Heavy-Oil Immiscible CO2 Tertiary Coreflood Data
Authors: Mayer E. H. , Earlougher R. C. , Spivak Allan , Costa Alexander
Published: December 2007

This paper describes the results of a series of tertiary, immiscible, CO2 corefloods of Wilmington field Pliocene reservoir rock containing heavy oil (±14°API [+0.97 g/cm3] and±480 cp [+480 mPa-s]). An initial set of corefloods defined the recovery potential of the CO2 injection, while a series of later tests served to define the process more accurately as applied in the field. In an attempt to understand the displacement mechanism, simulator matching of one of the later, more refined groups of corefloods was performed. The corefloods and simulator work indicate that the incremental recovery is more than can be accounted for by oil-viscosity reduction and crude-oil swelling. The improved performance is attributed to more favorable displacement characteristics and the presence of a free gas saturation in the cores.
In-Situ Combustion in the Lower Hospah Formation, McKinley County, New Mexico
Authors: Struna Stephen M. , Poettmann Fred H.
Published: December 2007

In 1980-81, Tenneco Oil Co. conducted an in-situ combustion pilot test on the Lower Hospah formation of the South Hospah field, McKinley County, NM. Although the reservoir appeared to be an excellent candidate for in-situ combustion, the pilot project recovered only a very small amount of incremental oil and was terminated as a consequence.

To evaluate the pilot test and to determine the reasons for its performance behavior, a reservoir model of the test site was developed from the historical performance of secondary recovery operations in conjunction with available log and core data. The result was a three-layer, four-quadrant model of the test site. The volumetric sweep efficiency of the combustion front was estimated from two interior core holes drilled after the project was terminated. This resulted in a postcombustion model of the test site depicting the vertical sweep of the combustion front.

Stoichiometric relationships were used to evaluate the combustion performance of each layer of the model. The stoichiometric evaluation provided a means to compare quantitatively the postcombustion reservoir model with actual test performance, thus verifying the model. The project failed because the combustion front migrated beneath the oil zone, processing an interval containing low oil saturation and resulting in very large air/oil ratios.
Review of CO2 Flood, Springer "A" Sand, Northeast Purdy Unit, Garvin County, Oklahoma
Authors: Fox Michael J. , Slmlote Vishnu N. , Stark Kelly L. , Brinlee L. D.
Published: December 2007

This paper describes the response of a CO2 flood in the Northeast Purdy Springer "A" Sand Unit in Garvin County, OK. Various aspects of field operations are discussed, including surface handling of the CO2 production stream, measurement and treatment of produced fluids, corrosion and pump problems, effects of high CO2 production seen downhole, and solutions to alleviate these problems. Several patterns in the project have received the full designed CO2 slug size of 30% of initial HCPV. On the basis of individual pattern response, operational and design changes were made to enhance the production performance of the flood area. Results of a time-lapse well-logging program are shown, along with comparisons of injection profiles taken before CO2 injection, during CO2 injection, and during post-CO2 water injection. Production response for several wells is shown and compared. The information and operating philosophy presented is based on operating experience before 1985.
CO2 Diversion With Foam in an Immiscible CO2 Field Project
Authors: Holm L. W. , Garrison William H.
Published: December 2007

A foam emplacement technique was applied through one well in the tar zone of Fault Block V in the Wilmington field to improve the distribution and sweep efficiency of injected CO2. The Long Beach Oil Development Co. is conducting an immiscible CO2/N2 water-alternating-gas (WAG) flood in this waterflooded, heavy-oil reservoir. Laboratory studies showed reduction in CO2/N2 gas mobility and improvement in overall sweep of laboratory cores by the addition of Alipal CD-128 foaming agent during the gasflood.

The field application of the foaming technique was successful in diverting the gas to a previously unswept interval, but subsequent injection of water diluted the foam to the extent that it lost its effectiveness.
Some Considerations in the Pricing of Natural Gas
Authors: Hill Kenneth H.
Published: December 2007

Introduction

In his paper entitled "A Management Look at Natural Gas", W.B. Golush discusses the natural gas industry thoroughly and capably, pointing to the various problems which confront it. The purpose of this article is to offer some additional thoughts, concerning the natural gas producing industry, which relate to the Golush paper.

It should not be construed from anything said herein that wellhead regulation of producer's prices by the FPC is favored. Quite the contrary, for we agree with the author that "the prices paid for natural gas at the wellhead should be set by normal supply-demand relationships".

Transport Costs Restrict Gas Markets

The first point to be made relates to prices paid at the wellhead for natural gas as related to oil and other forms of energy, in particular, on a Btu basis. It is true that natural gas is sold at an average price at the wellhead of about 12/Mcf, or around one-fifth of the equivalent Btu price for crude oil at the wellhead. But, new contracts are now negotiated at 16 to 24/Mcf in Louisiana and Texas. However, the low average price for natural gas relative to its energy value is due mainly to transportation costs to distant markets which, on an energy basis, are roughly five-fold greater than for petroleum. This very great differential in transportation costs seems to be ignored by many recent commentators on the natural gas industry, who deplore the apparent fact that the producer is giving away his gas and that revenues from gas are not carrying their share of exploration. This, at best, is only partially true. For, if natural gas were sold at the wellhead at 55/Mcf, its approximate crude-oil Btu equivalent, it would lose nearly all its market because it would be used only for very local and special uses.

As proof of this, even in California the price of natural gas in the field is at most 35/Mcf, or two-thirds of its estimated Btu basis, and is tied to fuel oil-not crude. Yet these reserves are adjacent to tremendous markets supplied principally from West Texas, some 1,200 miles distant, where the wellhead price averages only 12 to 14/Mcf. New gas contracts in Southern Louisiana, now being made at 20 to 24/Mcf, are probably approaching a level which renders the gas barely competitive with other fuels in New York. So, if prices in the field were to approach an energy basis, the industry would lose such a large proportion of its demand that it would suffer a reduction rather than a gain in revenues.
Peripheral and Line-Drive Water-Injection Projects
Authors: Stephens Fred
Published: December 2007

Introduction

The question of the pattern to be employed is one of the most important considerations necessary to the proper planning of a water-injection project. Before the decision can be made as to what type pattern should be employed, a thorough study of the reservoir parameters must be made. In some reservoirs, it is impractical to employ the five-spot pattern; in others, peripheral or line-drive patterns cannot be used.

Table 1 lists the reservoir data on four waterflooding projects employed in peripheral and the line-drive waterflooding patterns. The results obtained from these projects to date indicate that high sweep efficiencies in water-injection projects can be obtained with a minimum of hazard.

The Sojourner Peripheral Flood

The Sojourner sand unit in Haskell County, Tex., is a waterflooding project which employs the complete peripheral waterflooding pattern (Fig. 1). This waterflooding unit has 57 wells drilled on irregular 40-acre spacing and is completed in the Strawn sand penetrated at approximately 5,100 ft. The average porosity and permeability for this sand are 14 per cent and 12 md, respectively, as determined from 35 complete core analyses. The peripheral pattern was recommended for this project primarily because of the irregular drilling pattern employed.

Because of the depth and the waterflood reserves anticipated, it was impractical to employ in-fill drilling to design a workable five-spot or conventional water-injection pattern. Because of the low natural permeability, however, it was questionable if sufficient water could be injected into the sand to obtain the desired injection rate for an economical floodout time of the reservoir. From calculations using air permeability as a criterion, it originally was estimated that the maximum injection rate per well would be approximately 300 B/D at 1,800-lb surface injection pressure. A pilot water-injection program was initiated in Feb., 1956, into three water-input wells. Results of this pilot indicated that 600 to 900 B/D injection rates were permissable with 600-lb surface injection pressure.
New Sand-Control Filter for Thermal Recovery Wells
Authors: Toma Peter , Livesey Declan , Heidrick Theodore
Published: December 2007

A device was designed to solve a severe case of sand inflow into horizontal wells at the Athabasca Tar Sands pilot plant in Fort McMurray, Alta. The sand problem at this pilot resulted from a combination of three conditions: a fine-grained, cohesionless sand; the cyclic injection of steam; and the production of steam, water, and high-viscosity bitumen. A new type of filter, designed to overcome this problem, has application to the control of solids in wells drilled in a variety of formations producing liquids or gas. It was first designed and tested in the laboratory with a physical simulator; then it was fabricated and tested in vertical wells at the Athabasca pilot plant.
Oilfield Interference in Aquifers of Non-Uniform Properties
Authors: Mortada M.
Published: December 2007

Introduction

Nonsteady-state flow of slightly compressible liquids in porous media of non-uniform properties has been the subject of a number of recent studies. Most of these studies considered one-dimensional flow in systems with cylindrical geometry and with the properties of the porous medium varying with radial distance only.

A. Houpeurt studied the problem in its general form by examining the solutions of the differential equation,

(1)

In Eq. 1, the permeability and the porosity are arbitrary functions of radial distance. Houpeurt concluded that, except for special forms of the functions the problem is not well suited for mathematical treatment, but lends itself to high-speed digital computation.

Carslaw and Jaeger discussed the solution of Eq. 1 for the case in which the permeability varies as a power of the radial distance. P. Albert analytically studied the pseudo steady-state solutions in systems of finite radial extent and non-uniform properties. He also obtained some numerical solutions for non steady-state flow using a high-speed computer. William Hurst examined the interference pressure drop due to a point sink located in an infinite system consisting of two permeability regions in series. In this case, the permeability changed at a radial distance from the point sink.

Interference Between Oil Fields in a Non-Uniform Aquifer

The interference pressure drop for oil fields located in an extensive aquifer of uniform properties is discussed in a number of places in the literature. This work considers the interference pressure drop for oil fields located in a non-uniform extensive aquifer comprising two regions of different properties as shown in Fig. 1.
Solubility and Extraction in Multiple-Contact Miscible Displacements: Comparison of N2 and CO2 Flow Visualization Experiments
Authors: Bahralolom Ibrahim M. , Orr Franklin M.
Published: December 2007

Results of secondary and tertiary displacements of Maljamar crude oil by N2 and CO2 are compared to examine the effects of solubility and extraction on local displacement efficiency. The flow visualization experiments were performed in pore networks etched in glass plates. In those experiments, the much higher solubility of CO2 in the oil caused only marginal improvement in displacement efficiency over that observed for N2, which was much less soluble. At pressures high enough for CO2 to extract hydrocarbons efficiently, however, displacements were much more efficient.

Secondary and tertiary displacements in a more heterogeneous glass model are also compared. In a secondary displacement with high solubility but low extraction, adverse capillary and viscous effects limited the area swept to preferential flow paths. High CO2 solubility did not appear to have significant effects. When water was present in tertiary displacements with efficient extraction and high solubility, combined effects of viscous instability, capillary forces, and heterogeneity sharply reduced sweep efficiency below that observed in secondary displacements in the same model.
A Multiple-Porosity Method for Simulation of Naturally Fractured Petroleum Reservoirs
Authors: Wu Yu-Shu , Pruess Karsten
Published: December 2007

This paper describes the application of the method of "Multiple Interacting Continua" (MINC) to the simulation of oil recovery in naturally fractured reservoirs. A generalization of the double-porosity technique, the MINC method permits a fully transient description of interporosity flow by numerical methods. We present examples to demonstrate the utility of the MINC method for modeling oil-recovery mechanisms by water imbibition and field applications for five-spot waterflooding and water coning problems in fractured reservoirs. All results show that the MINC method provides accurate predictions of the behavior of naturally fractured reservoirs, while requiring only a modest increase in computation work compared with the double-porosity method. The double-porosity method may result in large errors for matrix blocks of low permeability or large size.
Interference Testing of a Two-Layer Commingled Reservoir
Authors: Onur Mustafa , C. Reynolds Albert
Published: December 2007

A two-well system in an infinite-acting, commingled, two-layer reservoir is considered. One well, the active well, is produced at a constant total rate, and the second well, the observation well, is shut in at all times. An analytical solution in Laplace space is presented, and the parametric groups that uniquely determine the pressure and rate solutions are identified. Results regarding crossflow through the observation well are presented. Conditions under which the line-source solution can be used to analyze observation-well pressure data are delineated. Results generally show that the analysis of such pressure data is tenuous unless individual layer flow rates are measured at the active well and the layers are isolated at the observation well, or unless layer flow rates are measured at both wells.
Use of an Ion-Selective Electrode for Determination of Free Chloride Ions in Water-Based Drilling Fluids
Authors: Kaland F. , Hakli U. , Ruoff P.
Published: December 2007

The use of an ion-selective electrode (ISE) for the determination of chloride ions in water-based drilling fluids has several advantages: the measurement is simple, fast, easy to perform, and inexpensive. An ISE can be used for continuous chloride ion logging and allows analysis of colored samples where the traditional API-recommended method is difficult to use.
Pressure Drawdown and Buildup in the Presence of Radial Discontinuities
Authors: Bixel H.C. , Van Poollen H.K.
Published: December 2007

A treatment is given of the transient pressure behavior of a well located at the center of a circular region surrounded by a radial discontinuity. On either side of the discontinuity, the values of permeability, viscosity, compressibility and porosity are uniform but may be different from those on the other side of the discontinuity. The results are obtained by solving a pair of finite difference equations. The numerical solution to these equations is obtained using a digital computer. The results are compared with previously published, approximated analytical solutions to the same problem.

Solutions, presented graphically, show pressure decline for constant rate fluid production. The range of variables studied include dimensionless time from 0.001 to 100 and storage capacity ratio from 0.001 to 1,000. The well behaves as if it were in an infinite reservoir for dimensionless times less than 0.25. Reservoir properties near the well can be estimated in the usual manner.

An overlay technique is used to match an experimental curve with one of the theoretical curves. It is possible to estimate the distance to a discontinuity by substituting the actual time t and the corresponding dimensionless time tD at which a match occurs into the equation a=(0.000264 tkI/tD fI µIcI)1/2, where kI/fIµIcI is the diffusivity near the well, and may be estimated from data taken at early time. Several buildup curves are computed. These curves show that for early shut-in times, correct values for transmissibility are obtained from conventional analysis. However, erroneous values of static reservoir pressure are obtained unless data at large shut-in times are taken.

INTRODUCTION

A mathematical treatment of the transient pressure response of a well located at the center of a region bounded by a circular discontinuity is given. Within a region (Fig. 20) the properties of both the rock and the fluid are considered to be constant on either side of the discontinuity. While these properties are considered constant, they may be different on opposite sides of the discontinuity. A discontinuity of this type could be a fluid-fluid contact or a sudden change in rock characteristics such as thickness, porosity or permeability.

Analytical solutions to this problem are available.1-3 However, they are so involved that they are of little practical use. An approximate solution1 is available but the range of times over which it is valid has not been specified. A numerical solution to a pair of finite difference equations is used to obtain the solution given in this paper.

PREVIOUS WORK

One of the first solutions to the problem was published by William Hurst.1 Hurst considered unsteady-state flow of fluids through two sands in series with different mobilities in each sand. He used Laplace transforms to obtain a solution for a single well located at the center of the circle enclosing the first of the two sands. In this case, the solution for the pressure change in Region I (Fig. 20) is2Equation 1

for r a.
Use of Long-Period Seismometers To Determine Induced Fracture Geometry
Authors: Mauk Frederick J. , Mahrer K. D.
Published: December 2007

A novel technique to determine the geometry of induced hydraulic fractures has been tried at five shallow (305- to 884-m [1,000- to 2,900-ft] depth) stimulation tests since 1983. Long-period (LP) seismometers with peak ground-motion sensitivities in the period range between 10 and 100 seconds were deployed on the surface at distances 115 to 732 m [377 to 2,402 ft] from the treatment wellbores. Identifiable transient waveforms with reproducible site-specific ground-motion polarizations were recorded during four of the five stimulations. Temporal coincidence of these LP waveforms with treatment-related events [e.g., bottomhole pressure (BHP) passing through the formation closure stress] suggested that the signals may contain useful information about the induced fracture. Unsuccessful attempts to simulate the polarization directions as stationary tilts and/or horizontal displacements from the overall expansion of the fracture demonstrated that the source of the signals was not static or quasistatic. An alternative kinematic source model was examined to simulate the waveforms as transient pressure/fracture interactions. Although many observed signal characteristics were consistent with this latter model, considerable doubt regarding the origin of these signals and their usefulness to determine geometry of induced fractures remains. Commercial application of this monitoring technique does not annear to be economicallv feasible.
Analysis of Coalbed Methane Stimulations in the Warrior Basin, Alabama
Authors: Layne Abbie W. , Byrer Charles W.
Published: December 2007

An objective of the U.S. DOE's in-house coalbed methane R&D effort has been to improve coalbed hydraulic fracturing techniques by improving the understanding of stimulation treatments. Current efforts focus on examining data from coal mine excavations to observe stimulation results, conducting Nolte-Smith analyses to characterize fracture behavior, and exercising DOE/METC's stimulation modeling codes. Test Wells DHM-6 and DHM-7, two research degasification wells located in the Oak Grove field, AL, were analyzed in this project. METC's hydraulic fracture models predicted Well DHM-6 coalbed wing lengths 3 to 5% greater than the excavated wing length. This modeling was based on observation of fluid penetration into the shale roof rock and on guidelines derived from the Nolte-Smith method, which indicated vertical propagation into the bounding strata. Results to date indicate that the Nolte-Smith method may provide adequate interpretation of coalbed fracture behavior when the effects of variable injection rates, natural fracture fluid interaction, and the interface effects of coalbed and bounding formations are considered. Further evaluation of hydraulic fracture models that predict the effects of geologic discontinuities on coalbed fracture propagation is recommended. Additionally, a future mine excavation to expose the coalbed roof rock and to assess the extent of vertical fracture propagation is suggested.
Gas-Well Testing in the Presence of Desorption for Coalbed Methane and Devonian Shale
Authors: Bumb A. C. , McKee C. R.
Published: December 2007

Very large potential gas reserves are present in both coalbeds and Devonian shales. In both formation types, long-term gas production is the result of gas desorption from the matrix. Experiments on core samples show that the desorption obeys a Langmuir isotherm.

An approximate analytic solution is derived for single-phase gas flow when gas is present as both free gas and gas adsorbed on the matrix. The solution was verified against a finite-difference solution; the agreement between the two methods is excellent.

The analysis of test data is simplest if the test is conducted at a constant mass flow rate. It is shown that the effect of desorption cannot be detected in production testing; therefore, analysis can be performed to obtain permeability as if the desorption effect is absent. The procedure to obtain desorption parameters is also given. The effect of desorption shows up in an increased compressibility, of the form cg +(αcm/ϕ)+[pscVLpLTz̅/ϕp̅gTsczsc(pL+pL+p̅g)2], which can be much larger than the gas compressibility. The effect of desorption on total production is substantial. When gases are adsorbed, total production over the life of a well can be an order of magnitude higher.
Elastic and Viscoelastic Calculations of Stresses in Sedimentary Basins
Authors: Warpinski Norman R.
Published: December 2007

This study presents a method for estimating the stress state within reservoirs at depth with a time-history approach for both elastic and viscoelastic rock behavior. The model can incorporate changes in pore pressure, temperature gradients, consolidation and diagenesis through time-varying material properties, and varying tectonic episodes. Example calculations are presented for simple cases and for a complete stress history of rocks in the Piceance basin.
A Microcomputer Program for Prediction of Bottomhole Assembly Trajectory
Authors: Birades Michel , Fenoul Robert
Published: December 2007

This paper describes a two-dimensional (2D) static, finite-element microcomputer program capable of quantitatively predicting the inclination behavior of bottomhole assemblies (BHA's). A calculation module that is based on the finite-element method helps account for the forces generated between the components of the BHA and the wellbore wall. This module is used in an automatic iterative process to compute the "equilibrium curve" of the BHA, which gives the future inclination gradient of drilling. The analysis of horizontal wells drilled by Elf Aquitaine demonstrated the role played by the hole-diameter- enlargement/rate-of-penetration (ROP) relation in prediction improvements.
Microcomputer Analysis of Hydraulic Fracture Behavior With a Pseudo-Three-Dimensional Simulator
Authors: Morales R. H.
Published: December 2007

The theory describing a pseudo-three-dimensional (pseudo-3D) hydraulic fracturing model that solves the coupled fluid-flow and elastic-rock-deformation problem associated with a fracture propagating into a zone composed of three or more layers is presented. The fracture is initiated in the center layer. Fracture growth is formulated from the critical-stress-intensity-factor criterion, and fracture width is obtained from plane-strain elasticity solutions. Fluid fronts and proppant settling during fracture closure are tracked during the treatment.

Fracture parameters obtained by this model show excellent agreement (6% maximum difference) with the solution given by a 3D simulator. Also, designs of hydraulic fracturing treatments depicting ways to minimize fracture growth and to optimize proppant distribution are described. The explicit expressions developed for modeling the fracture growth and fracture opening have reduced the complexity of the formulation and the computational effort.
A Viscoelastic Constitutive Model for Determining In-Situ Stress Magnitudes From Anelastic Strain Recovery of Core
Authors: Warpinski N. R. , Teufel L. W.
Published: December 2007

A three-dimensional viscoelastic model is developed to describe the anelastic-strain-recovery (ASR) process. Measured ASR data are curve-fit to the model by a least-squares algorithm, and viscoelastic material properties are calculated. The stress state at depth can then be determined given some additional information. Examples and comparisons with measured stresses are given.
Effects of Capillary Pressure on Coalescence and Phase Mobilities in Foams Flowing Through Porous Media
Authors: Khatib Z. I. , Hirasaki G. J. , Falls A. H.
Published: December 2007

The stability of foam lamellae is limited by capillary pressure. Consequently, as the fractional flow of gas in a foam is raised at a fixed gas velocity, the capillary pressure in a porous medium at first increases and then approaches a characteristic value, here called the "limiting capillary pressure." If the gas fractional flow is increased after the limiting capillary pressure has been attained, coalescence coarsens foam texture, the liquid saturation remains constant, and the relative gas mobility becomes proportional to the ratio of gas-to-liquid fractional flow. The limiting capillary pressure varies with the surfactant formulation, gas velocity, and permeability of the medium.
Static and Dynamic Three-Dimensional Bottomhole Assembly Computer Models
Authors: Birades Michel
Published: December 2007

This paper presents two three-dimensional (3D) mathematical models to predict the directional behavior of bottomhole assemblies (BHA's). The first model describes BHA dynamic, stepwise, transient behavior. Displacements and lateral forces, computed for each step, account for friction against the borehole wall. The second model computes a static BHA equilibrium whereby simplified friction forces are assumed. The static lateral forces are found to be an average of the highly varying ones computed by the dynamic model, but the static computer run is much faster. The static model is therefore used iteratively to compute an oriented dogleg severity that balances lateral forces. This is used to derive the directional behavior of the BHA. Comparison and calibration against real field cases are performed.
Slug-Test Analysis in Double-Porosity Reservoirs
Authors: Grader Abraham S. , Ramey Henry J.
Published: December 2007

The pressure response of a double-porosity reservoir to a slug test in a fully penetrating well with wellbore storage and skin is presented. Pseudosteady-state matrix flow and transient matrix flow with and without matrix skin are considered. Three kinds of type curves are discussed: early-time log-log, intermediate-time semilog, and late-time log-log. Pressure distribution around the active well and the prospects of interference slug testing are considered.

The early-time response of the slug test depends on the presence of wellbore skin; hence, two kinds of early-time type curves are presented. When the active well has wellbore skin, the early-time correlating parameter is the product of the skin and the dimensionless storage, resulting in a new log-log type curve. When wellbore skin is not present, the early-time response is proportional to the square root of time with dimensionless storage as the correlating parameter. The intermediate-time semilog type curves are applicable when wellbore skin is not present, or CDe2S>104. The double-porosity effects are significant in the late-time log-log format, but the flat portion of the pressure response occurs at dimensionless pressures less than 0.01.

The radius of investigation of the slug test in a double-porosity system is also examined with and without wellbore skin at the active well. Interference responses and pressure profiles are presented. Although the presence of wellbore skin reduces the magnitude of the dimensionless pressure responses at observation wells, the detectable radius of investigation does not significantly depend on wellbore skin. Interference slug testing in a double-porosity system requires high-precision pressure-recording tools in the observation wells because the double-porosity effects occur at small dimensionless pressures.

Transient matrix flow without matrix skin reduces the double-porosity effects and limits the use of type curves for determining λ and ω. The slug-test double-porosity effects in a reservoir with transient matrix flow with fracture skin and pseudosteady-state matrix flow are similar.
Effect of Dipping Beds on the Response of Induction Tools
Authors: Anderson Barbara , Safinya Kambiz Ali , Habashy Tarek
Published: December 2007

This paper describes a computer model for studying the effect of dipping beds on the response of induction tools. Simulated tool response in an arbitrary number of dipping beds is obtained from calculations of the magnetic fields of an equivalent magnetic dipole with an axis arbitrarily oriented with respect to the direction of stratification. The effects of the borehole and the invaded zone are neglected to solve the problem in a closed form.

In addition to describing the model, we also study the effect of dip angle on the apparent resistivity and the apparent bed thickness as read by induction tools in several typical logging configurations.
The Quarantine Bay 4RC CO2 WAG Pilot Projects: A Postflood Evaluation
Authors: Hsie J. C. , Stephen Moore J.
Published: December 2007

This paper reviews the design, implementation, and performance of a miscible CO2 water-alternating-gas (WAG) project in a U.S. gulf coast reservoir. The field-test data obtained since the inception of the project in Oct. 1981 are presented, and solutions to such operational problems as downhole corrosion are discussed. Remarkable project response and recovery demonstrated that the CO2 WAG process is technically viable for mobilizing considerable amounts of residual oil from watered-out Miocene reservoirs. A 16.9% recovery of original oil in place (OOIP) was obtained with a CO2 slug size of 18.9% original HCPV. The CO2 requirement was 2.57 Mcf/bbl [458 m3/m3] of oil recovered.