bluuebunny/crossref_metadata_2025_split huggingface dataset:
Flow of a Power-Law Fluid in an Eccentric Annulus
Authors: Uner Deniz , Ozgen Canan , Tosun Ismall 
Published: December 2007

Summary
An eccentric annulus is modeled as a slit of variable height, and the volumetric flow rate of a power-law fluid in an eccentric annulus is compared with that in a concentric annulus for a given pressure drop. The results indicate an increase in the volumetric flow rate as the inner pipe is displaced from a concentric position. The effect of the eccentricity ratio on the volumetric flow rate becomes predominant, especially when the power-law index, n, is small.
A Method to Determine Semipermeabilities by Steady Rates
Authors: Gao Cheng-tal 
Published: December 2007

Summary
The formation properties for individual layers of a multilayer reservoir are necessary for numerical simulation and tertiary process. Several multilayer well testing methods have been developed to estimate permeability-thickness product, kh, and skin factor, s, for individual layers. This paper gives an analytical method to calculate the vertical permeabilities of low-permeability intercalations between production layers in an n-layered reservoir with kh, s, and the steady flow rate of each layer when all layers produce together with a common wellbore pressure and a constant total rate.
Heat Transfer in Hydraulic Fracturing
Authors: Meyer Bruce R. 
Published: December 2007

Summary
An analytical heat transfer model is presented for the combined convection along a vertical fracture with conduction and convection in the reservoir. The model couples the energy (heat transfer) and fracture propagation equations resulting in a closed-form, dimensionless-temperature integral solution.
Major model enhancements include incorporation of (1) a finite film coefficient, (2) time-dependent fracture temperature for calculating the instantaneous heat flux, (3) energy storage in the fracture, and (4) coupled energy and fracture propagation equations. The introduction of a power-law Nusselt number to determine the convection-film coefficient is also new and unique.
The influence of fluid leakoff and a finite convection-film coefficient as heat-reduction mechanisms is discussed. The effect of energy storage and a time-dependent fracture temperature on the heat transfer rate is also illustrated. Finally, simulation studies illustrating the effect of heat transfer on fracture propagation characteristics are presented.
New Laboratory Tests Evaluate the Effectiveness of Gilsonite Resin as a Borehole Stabilizer
Authors: Davis Neal , Tooman Clyde E. 
Published: December 2007

Summary
Gilsonite® resin is a naturally occurring, mined carbonaceous material classified as an asphaltite. For many years, Gilsonite has been used in drilling fluids as an additive to assist in borehole stabilization. It has been well documented that this material works efficiently to minimize hole collapse in unstable shale sections. However, because Gilsonite is an asphaltite with a high-temperature softening point, duplication of its mending action in laboratory tests conducted at ambient temperatures and low pressures has been difficult.
New laboratory techniques have been developed only recently to evaluate Gilsonite under simulated downhole conditions. With innovative procedures and a newly built downhole simulation cell (DSC), we tested Gilsonite under temperatures and pressures similar to drilling conditions in which the product would normally be used. These tests indicate that borehole enlargement was minimized by use of Gilsonite while substantial enlargement was measured when the same drilling-fluid system was used without Gilsonite.
Another new test procedure was developed to discriminate between various types of Gilsonite products and to determine the most effective product under different temperature and pressure environments. This procedure made use of a high-temperature, high-pressure (HTHP) fluid-loss cell with Berea cores as a filtering medium. Scanning-electron-microscope (SEM) examination of the test cores from both testing procedures provided insight into the mechanisms of how Gilsonite provides stability under downhole conditions. Field data from wells drilled in widely different geological environments support the conclusions reached from laboratory tests.
Prediction of Layer Lengths From Layer Heights for Reservoir Simulations: A Statistical Analysis of Outcrop Data
Authors: Kossack Charles A. 
Published: December 2007

Summary
This paper describes an attempt to determine the relationship between a geological layer's height and width from published data on outcrops. Data from 11 outcrops are included in the study. A statistical analysis is performed on the highly variable data. The results show some interesting trends, but the basic conclusion is that more data of higher quality are needed from the geological community before correlations such as those shown can be used.

Introduction
History matching reservoir performance or predicting future oil recovery with a numerical reservoir simulator requires a detailed description of the porous medium. The data available from the actual oil reservoir consist of the logs and cores taken from the sparsely drilled wells. In general, we know very little about the variations in the porous media between wells. To fill this information void, geologists have been studying outcrops of rock formations that have depositional environments similar to the oil reservoirs being studied. Because the outcrop data gathered are only a small sample of the total set of rock formation data, a statistical approach must be used when one applies the outcrop results to the oil-bearing formation.
Recently, researcher in the petroleum industry and in universities have been studying the effects of permeability variations and layering on oil recovery. The conclusions, at this point, are that an accurate reservoir description for use in reservoir simulators should contain the best estimate of the formation layer's thickness, length, and mean permeabilities, and the variation of permeability within the layer. One would ultimately like to be able to predict, in a statistical way, all the important formation properties between wells from core and log data, the geological analysis of the depositional environment, and the outcrop studies. This paper describes a small step toward achieving that goal. The results of published outcrop studies are analyzed statistically and compared.
JPT
P. 867^
Solutions of Heat-and Fluid-Flow Problems in Naturally Fractured Reservoirs: Part 2—Fluid-Flow Problems
Authors: Satman A. 
Published: December 2007

SummaryThis paper, the second of two concerning the solution of heat-and fluid-flow problems in naturally fractured reservoirs, covers solutions of fluid-flow problems in naturally fractured reservoirs.The pressure transients occurring in a naturally fractured reservoir as a result of a constant production (or injection) rate are analyzed. The reservoir systems considered include an infinite and a finite system. Exact solutions and new approximate solutions for drawdown and interference tests are given. These approximate solutions are easy to use for designing and analyzing well test data. Type curves for analyzing pressure data are developed. The model is applied to drawdown and interference field data to illustrate the method of analysis and the applicability of the model.
Kepiting Field Production/Storage Barge - Design, Installation, and Operation
Authors: Carl Albert C. , Satar Sanussi , Liles Stephen P. 
Published: December 2007

Summary
The Kepiting field is located in 295 ft [90 m] of water in the Natuna Sea, Indonesia. Development of this two-well field required innovative planning andinvolved unique designs of producing systems. The plan includes seafloor wellstied back to a spread-anchored, purpose-built, oil-process and -storage barge. The barge is designed to handle four producing wells and to process 10,000 B/D[1590 m3/d] well fluid and 10 million scf/D [283 × 100 std m3/d] gas. Excessgas beyond barge-fuel needs and artificial-lift requirements is flared on thebarge. Heated oil storage for 53,000 bbl [8430 m3] is available. Processedcrude is transported from the barge to a floating export terminal by a shuttletanker. Kepiting field was operated profitably from Oct. 27, 1986, to Aug. 8,1989, at which time the wells were plugged and the tieback risers disconnected. The production barge currently is operating at the Ikan Pari field, 50 nauticalmiles [80 km] northeast. This paper discusses the design and construction ofthe barge and the operating philosophy and experience.

Discussion

Project Implementation.
The Kepiting field development work-its oil wells, riser system, and the FPSO-was awarded on a basic concept. Bids includeddetailed engineering, from which the final design requirements would evolve. Front-end engineering showed that the proposed systems or their alternativeswould work. As the engineering work progressed and new information (oftenproprietary) became available, changes, alternatives, and details wereselectively included that improved cost-effectiveness or safety aspects(personnel, environmental, and use of resources). The project flow chart isshown in Fig. 3. Major work areas defined were (1) well completion, (2) trees, (3) flexible risers, (4) an FPSO with a shuttle tanker, and (5) a wirelinere-entry system.
This complex project required close coordination to bring thesystems together at the right time. This paper focuses on one aspect of theproject, the design and implementation of the FPSO.

Contracting and Construction.
When we decided to adopt a spread-moored FPSO, we knew that a new build would be required. We chose to lease the FPSO (on abare-boat type of charter) and its companion shuttle tanker (on a timecharter). Therefore, a request for tender was issued for a single-source leasecontract that included detailed design and supply of the FPSO, supply of asuitably equipped shuttle tanker, installing and anchoring the FPSO, startupand 45-day acceptance testing, and identification and procurement of a 2-yearsupply of spare parts. The bid package contained barge hull drawings, processflowsheets, process and instrument drawings (P and ID's), electrical one-linedrawings, specification sheets for equipment identified on the P and ID's, andan instrument index.

JPT
P. 480⁁
Development and Application of the Controlled-Freeze-Zone Process
Authors: Haut R. C. , Denton R. D. , Thomas E. R. 
Published: December 2007

Summary
The controlled-freeze-zone (CFZ) process is a cryogenic distillation technique for separating CO2 and heavier compounds from methane (C1). This paper describes how the process controls the freezing and melting of CO2 in a specially designed section of an otherwise conventional distillation tower. In addition to describing the process, this paper compares the CFZ process to other gas-treating processes, discusses pilot-plant operational results, and gives examples of potential CFZ applications. The CFZ process is a simple, cost-effective method to process gas streams containing CO2 using proven facilities, equipment, and control philosophies and has been demonstrated through the operation of a large-scale pilot plant.
Simplified GERG Virial Equation for Field Use
Authors: Jaeschke Manfred , Audibert Serge , van Caneghem Patricia , Humphreys A. E. , Janssen-van Rosmalen Renée , Pellei Quinto , Schouten J. A. , Michels J. P. J. 
Published: December 2007

Summary
A GERG (Groupe Européen de Recherches Gazières) equation of state (EOS) is presented to calculate the compressibility factor of natural gases. The equation, which does not require detailed gas analysis, can predict the compressibility factor when three of the four following gas properties are known: the gross calorific value, the relative density, and the mole fractions of N2 and CO2. The new equation, known as the SGERG-88 virial equation, is based on ideas presented in an earlier study. The new equation, however, applies to wider ranges of temperature and pressure and can be applied to gases containing hydrogen if the mole fraction of the hydrogen is known. The equation was tested on natural gases purchased, transported, and marketed by the European gas companies. Excellent agreement between computed and experimental compressibility factors was found. This difference is, in most cases (94% of the data points), less than 0.1% in the temperature range of 265 to 335 K and for pressures up to 12 MPa.
Analysis of Pressure-Falloff Tests Following Cold-Water Injection
Authors: Bratvold Reldar B. , Horne Roland N. 
Published: December 2007

SummaryThis paper presents generalized procedures to interpret pressure injection and falloff data following cold-water injection into a hot-oil reservoir. The relative permeability characteristics of the porous medium are accounted for, as is the temperature dependence of the fluid mobilities. It is shown that the saturation and temperature gradients have significant effects on the pressure data for both the injection and falloff periods. The matching of field data to type curves generated from analytical solutions provides estimates of the temperature-dependent mobilities of the flooded and uninvaded regions. The solutions also may be used to provide estimates of the size of the invaded region, the distance to the temperature discontinuity, heat capacities, and wellbore-storage and skin effects.
The Prediction of Volumes, Compressibilities and Thermal Expansion Coefficients of Hydrocarbon Mixtures
Authors: Avasthi Surjit M. , Kennedy Harvey T. 
Published: December 2007

Abstract
An equation developed for gaseous hydrocarbon mixtures predicts molal volumes with an average absolute deviation of 0.73 percent when applied to 264 natural gas and condensate systems including 2,043 PVT points. Another equation developed for liquid hydrocarbon mixtures predicts molal volumes with an average absolute deviation of 1.12 percent when applied to 346 crude oil systems including 1,759 PVT points. Both equations require composition of the mixture to be expressed as mole fraction of methane through heptanes-plus, hydrogen sulfide, nitrogen and carbon dioxide, together with the characteristics of the heptanes-plus fraction in addition to the temperature and pressure. The equations cover wide ranges of the variables involved, and their accuracy is considerably better Than that of other available methods.
The equations were differentiated to allow calculation of the coefficients of isothermal compressibility and isobaric thermal expansion. (In this paper the coefficient of isothermal compressibility and the coefficient of isobaric thermal expansion will be expressed as compressibility and thermal expansion coefficient, respectively.) Equations to calculate these quantities are presented.

Introduction
Calculations of reservoir performance for petroleum reservoirs require accurate knowledge of the volumetric behavior of hydrocarbon mixtures, both liquid and gaseous. Compressibilities are required in transient fluid flow problems, and thermal expansion coefficients are important in thermal methods of production.
An accurate laboratory investigation of the PVT behavior of each reservoir fluid encountered would be costly and time consuming. For this reason various correlations for predicting fluid properties have been developed and recorded and recent literature. Correlations have been presented in the form of graphs, tables and equations. Since an increasing number of studies are being conducted with the aid of electronic computers, recent efforts have been directed toward development of correlations suitable for computer programming. Application of computers permits the use of more complex correlations which otherwise are not feasible. Moreover, methods for predicting reservoir performance, particularly those based on the compositional material balance, depend upon the capability of accurately expressing the molal volumes and other fluid properties as functions of pressure, temperature and composition.
The coefficient of isothermal compressibility c is defined by(1)
and can be computed from the slope of isothermal specific volume curve for each pressure. The compressibility is a point function and has the dimension of reciprocal pressure.
The coefficient of isobaric thermal expansion beta is defined as(2)
It is a point function and has the dimension of reciprocal temperature. The thermal expansion coefficient can be obtained from the slope of an isobaric specific volume curve for any temperature.
SPEJ
P. 95ˆ
A Field Application of Pulse-Testing for Detailed Reservoir Description
Authors: McKinley R.M. , Vela Saul , Carlton L.A. 
Published: December 2007

Abstract
Johnson et al. have described a new well-testing technique that measures formation flow properties between wells. The technique, called pulse-testing, requires a sequence of rate changes in the flow at one well and measurement of the resulting pressure changes at an adjacent well with a very sensitive differential pressure gauge.
This paper describes an extensive application of the technique in a producing oil field. Pulse-tests on 28 of 45 possible well pairs in the field provided a picture of the areal distribution of reservoir hydraulic diffusivity, transmissibility and storage. The primary objective in presenting these data is to demonstrate the potential of the method for reservoir description. A second objective is to show in three ways the qualitative and quantitative accuracy of reservoir parameters determined from pulse-tests:pulse-test data show a nonuniformity in the field, closely correlating with the oil-water distribution as given by production data;pulse-test values for permeability are comparable with core values, andperhaps most important, the field responds to a conventional interference test in the manner in which pulse-test data predict it should.

Introduction
The pulse-testing technique by Johnson et al. is an ideal source of data for purposes of reservoir description, for it provides a measurement of formation storage S = phi ch, hydraulic diffusivity eta = k/phi c mu and transmissibility T kh/mu between wells.
This paper describes an application of this method in a producing oil field. Results were analyzed to give numerical values for the parameters eta, T and S. These values were compared with oil-water production data (for the effect of fluid saturation), with core data and with data from an interference test.
The reservoir in which the pulse-test survey was run is the result of a structural trap formed by a fault along the east side of a north-south trending anticline. A down-structure aquifer provides a natural flank water drive for the pool. The producing formation is a dolomitic limestone having mainly vugular permeability; the formation oil has a gravity of 29 degrees API with negligible dissolved gas. The field contains 19 wells, all on pump, arranged on 40-acre spacing along the top of the anticline.
Fig. 1 shows the location of all these wells except two at the south end of the field. The dashed line on the righthand side of the figure represents the approximate location of the fault with respect to well positions.

Pulse-Test Survey and Analysis of Data
A pulse-test requires a pulsing well and a responding well.
JPT
P. 313ˆ
Computation and Interpretation of Capillary Pressure From a Centrifuge
Authors: Skuse Brian , Flroozabadi Abbas , Ramey Henry J. 
Published: December 2007

SummaryCentrifuge capillary pressure measurements usually are conducted at atmospheric air pressure. In such measurements, any capillary pressure exceeding atmospheric pressure requires a negative pressure in the wetting phase. Experiments were conducted to examine the effect of air pressure on air/brine capillary pressure. First, drainage capillary pressure curves were determined for six low-permeability core samples under atmospheric pressure. Then, drainage capillary pressure curves were determined at an elevated air pressure of 112 psia [0.77 MPa] for the same samples. The two capillary pressure curves for each core sample generally are in close agreement. Both measurements reported in this paper and data from the literature indicate stable behavior for the wetting phase under negative pressure conditions.
Prediction of Sulfate Scaling Tendency in Oilfield Operations
Authors: Yuan M. D. , Todd A. C. 
Published: December 2007

Summary
This paper presents a model for predicting the scaling tendencies of barium, strontium, and calcium sulfates resulting from the mixing of injected and formation waters and from temperature and pressure effects. The model also predicts competitive simultaneous coprecipitation of BaSO4, CaSO4, and SrSO4, where sulfate is the common ion, reflecting the precipitation of more than one sulfate mineral. The supersaturations and amounts of precipitation of the sulfates are calculated from their solubilities, which in turn are calculated by the Pitzer equation for electrolyte ion activity coefficients.
In-Situ Stress Tests and Acoustic Logs Determine Mechanical Properties and Stress Profiles in the Devonian Shales
Authors: Gatens J. M. , Harrison C. W. , Lancaster D. E. , Guidry F. K. 
Published: December 2007

SummaryThe in-situ stress contrast between a reservoir rock and the surrounding formations is important to the design and analysis of hydraulic fracture treatments. The stress contrast between layers controls the fracture's vertical (height) growth, which in turn affects the fracture length and width. As part of the Gas Research Inst.'s (GRI's) Comprehensive Study Well (CSW) program in the Devonian shales of the Appalachian basin, we measured in-situ stresses directly and used these values to calibrate acoustic log measurements to develop stress profiles across the Devonian shales. This discusses the measurement and interpretation of in-situ stresses, the use of acoustic logs to determine mechanical properties and a more complete stress profile, and the practical use of the stress profile in fracture-treatment design and analysis.In-situ stresses were measured directly throughout the Devonian shale interval with both openhole and cased-hole stress tests, conducted with nitrogen, a specially designed downhole shut-in tool, and a downhole quartz pressure gauge with surface readout. The paper describes the procedure used and presents interpreted stress-test results from two CSW's. Full-waveform acoustic tools were run to define elastic properties of the Devonian shales. These properties also were determined under both static and dynamic conditions from whole-core plugs taken in the shales. Logs were calibrated to core-measured values, and then elastic properties determined from the logs were used to compute an in-situ-stress profile, which was calibrated against field measurements of in-situ stresses. Finally, we discuss how these data are used to design and analyze hydraulic fracture treatments in CSW's.
Reservoir-Fluid Property Correlations—State of the Art
Authors: McCain W. D. 
Published: December 2007

Summary
This paper presents correlations to determine reservoir-fluid properties from field data. The best available correlations were selected by comparison with a data base of hundreds of reservoir-fluid studies of samples representing all areas of the free world involved in active petroleum exploitation from 1980 to 1986. Also, correlations of formation-water properties are given.