bluuebunny/crossref_metadata_2025_split huggingface dataset:
Producer-Engineer-Purchaser... A Case History
Authors: Kubitz John R. , Shearin H.M. 
Published: December 2007

Abstract
Seldom do circumstances present an opportunity to report a complete sequence of management and technological events involving geology, discovery, evaluation, development planning and presentation for sale of products from a major natural gas resource. The Ozona Gas area, Crockett County, Tex., may well represent a classic example of
- geological study and successful interpretation following an offset failure;
- air drilling, limited entry fracturing, and modern completion techniques resulting in a significant reduction in per well costs and increased initial production potentials;
- comprehensive engineering study during and following the use of extensive well testing and fluid sample analyses, special core analysis and radioactive tracing techniques;
- evaluation of reserves based on total effective net productive formation throughout a 70,000-acre area; and
- recommendations for developing dry gas and by-product volumes available for transmission and processing during a 20-year period. All technical and economic data were analyzed and summarized for presentation and use in determining optimum development programs through electronic data processing and computing equipment.
Introduction
The Ozona area is located in Crockett County, in West Texas, about 130 miles southeast of Midland and immediately south and southwest of the town of Ozona (Fig. 1). The first significant well in this area was drilled during late 1939. Subsequent drilling of 14 additional wells failed to discover any sizeable reserves. These wells were all drilled using mud as the drilling fluid, with the exception of one air-drilled hole. All operators overlooked the principal shallow pay zone, the Canyon sand at approximately 6,500 ft, in an effort to establish the deeper Strawn or Ellenburger production. These early wells took up to six months to drill and log with an average drilling time of approximately four months/well. These expensive wells helped Crockett County to become known as the graveyard of the West Texas oil industry. A group, consisting mainly of Delta Drilling Co., Odessa and Tyler, Tex., Johnson and Lindley, Houston, Tex., and Pauley Petroleum Inc., Los Angeles, Calif., entered the area during mid-1961 with the following drilling and development sequence. The initial attempt to establish production in the area appeared to bear out the futility of drilling this area after drilling and suspending the first test during 1961. This well, the Friend No. l, was spudded July 13, 1961 and suspended on Aug. 5, 1961 after finding the Ellenburger too low for commercial production.
JPT
P. 719ˆ
An Implicit Treatment of Upscaling in Numerical Reservoir Simulation
Authors: Guedes S. S. , Schiozer D. J. 
Published: December 2007

Summary
This paper presents a multiscale computational model for multiphase flow that implicitly treats upscaling without using pseudofunctions. The model overcomes some practical difficulties related to use of traditional pseudocurves by executing the upscaling and solution processes in one step and taking into account changes in the numerical model in an adaptive manner.
Removal of Asphalt Deposits by Cosolvent Squeeze: Mechanisms and Screening
Authors: Minssieux Louis 
Published: December 2007

Summary
Performance improvement of usual solvents for asphalt deposits was investigated in an effort to optimize squeeze treatments of formations damaged with asphaltenes. The approach adopted for increasing the solvent power for asphaltenes of such solvents as xylene was to design solvent mixtures with a polarity adjusted to specific chemical features of asphaltenes contained in the crude oil considered. For that purpose, Hansen's theory was used as a guide in defining the composition of cosolvents suitable for asphaltenes. In addition, to increase solvency and to disperse asphaltenes, proper additives were used as a means to create hydrogen bonding with the heteroatoms present in the asphaltene chemical structure or to modify the intermolecular interactions involved in asphaltene aggregation.
Laboratory screening of cosolvents involved four types of tests that were based on the physical/chemical mechanisms deemed predominant in a squeeze operation (i.e., the solvency of asphaltenes, the ability to desorb the asphaltenes adsorbed onto minerals making up the reservoir rock, and the capacity to maintain dispersion of the asphaltenes within the organic phase). Several cosolvents, with a few percent commercial chemicals containing an alcohol or amine functional group in their molecules, were found to exhibit the required properties vs. either solid extracted asphaltenes or well deposits.
The final cosolvent efficiency was checked at reservoir temperature in squeeze experiments carried out in core samples. After a permeability damage occurred during asphaltenic crude oil flow, the remedial effects of squeezes of different cosolvents were evaluated. Several examples illustrate the improvement gained with the designed cosolvents and additives in restoring part of the oil permeability and in reducing the in-situ asphaltene deposition accompanying crude oil flow through core samples.
Upscaling Immiscible Gas Displacements: Quantitative Use of Fine-Grid Flow Data in Grid-Coarsening Schemes
Authors: Darman N. H. , Durlofsky L. J. , Sorbie K. S. , Pickup G. E. 
Published: December 2007

Summary
This paper presents and assesses grid-coarsening schemes based on the quantitative use of fine-scale two-phase-flow information. The basic approach is motivated from a volume-average analysis of the fine-scale saturation equation including gravitational effects. Extensive results for layered systems are presented. We show that coarse-grid simulation error correlates closely with specific subgrid quantities involving higher moments of fine-grid variables, which can be computed from the fine-scale simulations. With formation of a coarse grid that minimizes the appropriate subgrid property, optimal coarse-scale descriptions can be generated. The overall approach is shown to be applicable to coarse-scale descriptions with either rock or pseudorelative permeability curves. The accuracy of the coarse-grid calculations is, however, significantly better when pseudofunctions are used. The method is applied to determine the optimal number and configuration of coarse-grid layers in more general cases and it is shown that coarse-grid results do not always improve as the number of coarse layers is increased.
Compressibility of Natural Gases
Authors: Trube Albert S. 
Published: December 2007

Abstract
The purpose of this paper is to clarify the definition of compressibility and to present a uniform basis upon which instantaneous compressibilities of liquids and gases can be compared. The equations gaverning the instantaneous compressibilities of imperfect gases are derived and the concept of pseudo-reduced compressibility is introduced. Part of the data presented by Brown, Katz et al on compressibility factors for natural gases has been rearranged. A graph of pseudo-reduced compressibility vs pseudo-reduced pressure for various pseudo-reduced temperatures is presented. The need for additional work in relating the compressibilities of liquids and gases is discussed.
This information should be of value to reservoir engineers in making non-steady state performance calculations in gas reservoirs. It should be of further use in pointing the direction for additional research in the nature of liquid and gas compressibilities.

Introduction
With the increasing use of steady and non-steady state well and reservoir data, there is a corresponding increase in the importance of the various factors entering into such calculations. Increasing emphasis is being placed on the necessity for obtaining reasonably accurate estimates of the physical properties of the reservoir fluids well in advance of the more accurate laboratory data.
One such factor is the isothermal coefficient of expansion of the media which are transmitting and attenuating the non-steady state pressure waves. The average isothermal coefficient of expansion, or "compressibility" is a complex function controlled by the physical properties of the formation and the fluids contained therein. The isothermal expansion coefficients for reservoir gases are usually quite variable, in many cases being highly-pressure sensitive. The coefficients for reservoir liquids tend to be pressure sensitive, but not nearly so much as reservoir gases. The coefficients for solids, usually expressed in terms of a "modulus of elasticity" are relatively insensitive to pressure variations within their elastic limits. For this reason, and also because many previous applications have been limited to relatively small pressure ranges, there has been a tendency to ignore the variable nature of isothermal expansion coefficients and treat them as constants.
Principal Component Analysis Applied to 3D Seismic Data for Reservoir Property Estimation
Authors: Scheevel J. R. , Payrazyan K. 
Published: December 2007

SummaryWe apply a common statistical tool, Principal Component Analysis (PCA) to the problem of direct property estimation from three-dimensional (3D) seismic-amplitude data. We use PCA in a novel way to successfully make detailed effective porosity predictions in channelized sand and shale.The novelty of this use revolves around the sampling method, which consists of a small vertical sampling window applied by sliding along each vertical trace in a cube of seismic-amplitude data. The window captures multiple, vertically adjacent amplitude samples, which are then treated as vectors for purposes of the PCA analysis. All vectors from all sample window locations within the seismicdata volume form the set of input vectors for the PCA algorithm.Final output from the PCA algorithm can be a cube of assigned classes, whose clustering is based on the values of the most significant principal components (PC's). The clusters are used as a categorical variable when predicting reservoir properties away from well control. The novelty in this approach is that PCA analysis is used to analyze covariance relationships between all vector elements (neighboring amplitude values) by using the statistical mass of the large number of vectors sampled in the seismic data set.Our approach results in a powerful signal-analysis method that is statistical in nature. We believe it offers data-driven objectivity and a potential for property extraction not easily achieved in model-driven fourier-based time-series methods of analysis (digital signal processing).We evaluate the effectiveness of our method by applying a cross-validation technique, alternately withholding each of the three wells drilled in the area and computing predicted effective porosity (PHIE) estimates at the withheld location by using the remaining two wells as hard data. This process is repeated three times, each time excluding only one of the wells as a blind control case. In each of the three blind control wells, our method predicts accurate estimates of sand/shale distribution in the well and effective porosity-thickness product values. The method properly predicts a low sand-to-shale ratio at the blind well location, even when the remaining two hard data wells contain only high sand-to-shale ratios.Good predictive results from this study area make us optimistic that the method is valuable for general reservoir property prediction from 3D seismic data, especially in areas of rapid lateral variation of the reservoir. We feel that this method of predicting properties from the 3D seismic is preferable to traditional, solely variogram-based geostatistical estimation methods. Such methods have difficulty capturing the detailed lithology distribution when limited by the hard data control's sampling bias. This problem is especially acute in areas where rapid lateral geological variation is the rule. Our method effectively overcomes this limitation because it provides a deterministic soft template for reservoir-property distributions.
Laboratory Study Investigating Emulsion Formation in the Near-Wellbore Region of a High Water-Cut Oil Well
Authors: Janssen P. H. , van den Broek W. M. G. T. , Harris C. K. 
Published: December 2007

Summary
An experimental study was conducted to determine the morphology of oil/water mixtures produced into a high water-cut well. This information is important for determining the feasibility of downhole oil/water separation.
Core-flow and microflow experiments were performed to simulate the two-phase flow process in the near-wellbore region of a high water-cut well. In the core-flow experiments the morphology of oil/water mixtures leaving different types of porous media was observed and the droplet-size distribution was determined for different fluid properties and flow parameters. In the microflow experiments the flow regimes and breakup mechanisms of the oil phase in the pore space were visualized and observed.
The experimental results show that the oil/water mixture emerging from the porous medium depends strongly on its wettability. When the porous medium is oil-wet, the produced oil is mainly in the form of large drops that are formed at the porous end face. From water-wet porous media, small oil droplets are produced at high flow rates; their sizes are typically of the pore size's order and are formed inside the porous medium. A correlation between the droplet size and relevant fluid, and flow and porous-medium parameters has been developed, allowing for the assessment of circumstances in which downhole separation can be problematic. The experimental results have also shown that in water-wet porous media a transition from capillary-dominated to dispersed flow takes place in the capillary number range investigated (10-5&lt;Nc&lt;10-3).
A Method for Extrapolation of Cut vs Recovery Curves
Authors: Ershaghi Iraj , Omorigie Osazuwa 
Published: December 2007

JPT Forum articles are limited to 1,500 words including 250 words for each table and figure, or a maximum of two pages in JPT. A Forum article may present preliminary results or conclusions of an investigation that the present preliminary results or conclusions of an investigation that the author wishes to publish before completing a full study; it may impart general technical information that does not warrant publication as a full-length paper. All Forum articles are subject to approval by an editorial committee.
Letters to the editor are published under Dialogue, and may cover technical or nontechnical topics. SPE-AIME reserves the right to edit letters for style and content.

Introduction
For a fully developed waterflood with no major operational changes planned, a plot of fractional water cut vs total recovery is used often to obtain a quick estimate of ultimate recovery at a given economic water cut. Extrapolation of past performance on the "cut-cum" plot is a complicated task. The difficulty arises mainly because curve fitting by simple polynomial approximation does not result in satisfactory answers in most cases.This paper presents an equation that is a fair representation of the waterflood process, based on the concepts of fractional flow and the Buckley-Leverett recovery formula,* which may be written as
(1)
ER = over-all reservoir recovery, volume of hydrocarbon recovered divided by oil in place, place,
fw= fractional water cut,
where m and n are constants.
Derivation of the Equation
The fractional flow equation (after neglecting the capillary pressure and gravity terms) may be written as
(2)
The main portion of the ko/kw curve vs Sw plotted on semilog paper is quite linear and may be expressed as
(3)
where a and b are constants. On substitution, Eq. 2 may be written as
(4)
where
As shown by Welge,* the water saturation at the producing end (S,.) may be expressed as producing end (S,.) may be expressed as(5)
where
Sav = average water saturation throughout thesystem.
Since
(6)
In these equation, Swi is the initial water saturation.
JPT
P. 203
The Fluid Travel Log
Authors: Walker Terry , Sherwood John , Sumner Cyril R. , Marshall Ray 
Published: December 2007

Abstract
By using down-hole ejection of radioactive fluid and two gamma counters the velocity of flow at a given point or the determination of whether or not fluid has passed a given point can be determined accurately on production or injection wells. In this method the counters are positioned at the proper points, a small concentrated quantity of radioactive fluid is ejected, and a recorder operating in time-drive records the time interval or fluid movement past the counters, each counter recording on a separate pen for a permanent record. Inside the casing or in open hole if a caliper log is available, a time profile and resulting velocity profile determines the full injection or production distribution. During injection profiling the procedures readily point out and locate any channeling which may exist. Equally simple job procedures are available for detecting casing leaks, tubing leaks, leaking packers and many other operational problems which are detectable by a study of fluid flow. Field examples are given to indicate the success and utility of the method. Of great importance to the operations engineer is the fact that job procedures with the well at normal operating conditions are standardized for ready field interpretation.

Introduction
With the increasing application of water flooding, pressure maintenance and other recovery-increasing techniques in the oil industry, an accurate means of determining input profiles is an absolute requirement. The injection fluid costs, especially in miscible floods and gas injection, are such that channeling behind the pipe must be located and remedied. Also, the efficiency of secondary recovery techniques requires orderly flood-front movement throughout the vertical extent of the zones. Therefore, the input profile must be as desired, and accurate profiling by some means is necessary on the injection wells after completion and at intervals during the flood. In some cases in waterflood projects, even input profiles are not the only requirement-the production profiles should also be such that orderly flood-front movement is obtained. Again, an accurate means of profiling is required at intervals during the project. There are a number of production problems where accurate production profiles can be of great aid in remedial work. Where wells are producing large amounts of water along with a small amount of oil from either long perforated intervals or open hole, shutting off the water section and allowing greater drawdown on the oil section can greatly increase oil production. In wells of this type, of course, are the condition where the highest permeability zones are watered out with oil remaining in the less permeable zones.
JPT
P. 851ˆ
Reliability of Deepwater Subsea Blowout Preventers
Authors: Holand Per 
Published: December 2007

Summary
Operational experience data from deepwater subsea blowout preventers (BOP's) used in the U.S. Gulf of Mexico (GOM) in 1997 and 1998 have been collected and analyzed to reveal BOP reliability problems. Results focus on rig downtime caused by BOP failures, criticality of failures in terms of ability to control a well kick, and BOP subsea test-time consumption. Results have been compared with corresponding results from previous BOP reliability studies carried out for other areas and periods. An overall conclusion is that there are no main differences in overall reliability of deepwater BOP's vs. BOP's operating in "normal" water depths, except for increased downtime caused by increased BOP handling time in deep waters.
Olympic Pool Water Flood
Authors: Stiles W.E. 
Published: December 2007

Abstract
The Olympic pool is located some 12 miles northeast of the city of Wewoka, in Hughes and Okfuskee counties, Okla.
The field was discovered in July 1935. Subsequent rapid development on 10-acre spacing proved 3,500 acres productive in the Senora sand, which is found at an average depth of 1,800 ft. Primary production was by solution gas drive mechanism. By 1940, 14 years after discovery, the field had produced almost 14 million bbl of oil and then was in the stripper stage.
In that year, a pilot water flood was started which in less than one year of injection proved the floodability of the Senora sand. Additional waterflood development followed, and by 1954 the entire field was being operated under a pattern water flood.
A water supply source of some 100,000 B/D of capacity was found and developed after the original source of supply, although sufficient in quantity, proved highly corrosive. The problems encountered in developing, treating and injecting this volume of water are presented.
Production and injection history to Jan. 1, 1956, is presented to show the magnitude of the results being obtained, and the comparison of recoveries under water flood to recoveries under primary operation.

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

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

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