bluuebunny/crossref_metadata_2025_split huggingface dataset:
Gel-Block Technique: A Successful Application for Zonal Isolation in a Depleted Reservoir
Authors: Mbaba P. E. 
Published: December 2007

Summary
This paper discusses the successful application of a polymer gel during a cement squeeze of a depleted zone in a gravel-packed producing well. The process involves proper placement of polymer gel to isolate zones in a gravel-pack completion during a cement squeeze. The report also discusses diagnostic well tests before and after the cement squeeze. The use of polymer gel as a blocking agent during a cement squeeze of a gravel-pack completion of a thermally stimulated well does not appear to be a common practice and has not been reported previously.
Well Test Analysis of Naturally Fractured Reservoirs
Authors: Aguilera Roberto 
Published: December 2007

Summary
Methods are presented for matching observed pressure data during drawdown or buildup tests. The methods, illustrated with step-by-step examples, allow calculation of fracture transmissivity, storage capacity coefficient, skin, size of matrix blocks, fracture porosity, fracture storage, and radius of investigation. The effect of matrix block shapes in the transition period has been investigated by use of a stratum model, a model made of cubes with spaces between the cubes, and a model made of "matchsticks" separated by two orthogonal fracture planes. Consideration has been given to a gradient flow model as well as to unsteady-state and pseudosteady-state interporosity flow. Because many naturally fractured reservoirs are fault-related, the effect of single and intercepting sealing faults has been investigated.
Even after a match of observed pressure data is obtained, there is uncertainty about calculated parameters. Consequently, a synergetic approach integrating geologic models, logs, cores, outcrops, and well testing is the only sound procedure for evaluating naturally fractured reservoirs.
Computer Image Processing: A New Tool for Studying Viscous Fingering in Corefloods
Authors: Peters Ekwere J. , Broman John A. , Broman William H. 
Published: December 2007

Summary
Computer image processing technology was used to study the patterns of viscous fingering in laboratory corefloods. The fingering patterns in unstable immiscible corefloods were captured and photographed with the aid of a fluorescent dye. The photographs were digitized and stored as computer image files for subsequent processing. A program was written to count the fingers, to determine their sizes, to compute the sweep efficiencies at the core cross sections, and to determine the frequency contents of the fingering patterns. The frequency contents were used in conjunction with stability theory to estimate the effective interfacial tension (IFT) required for calculating the stability numbers of the floods. Results show that computer image processing technology can be used to study the performance of laboratory corefloods quantitatively.
Analysis of an Interwell Tracer Test in a Depleted Heavy-Oil Reservoir
Authors: Ohno Kenji , Nanba Takao , Horne Roland N. 
Published: December 2007

Summary
This paper presents field data and analyses of an interwell tracer test conducted in the Niitsu oil field, which is a fully depleted heavy-oil reservoir of unconsolidated sand formation. Water containing a chemical tracer was injected at a constant rate into an injector surrounded by three production wells. Effluent analyses showed very early breakthrough of injected water at two of the producing wells. The test results suggest a strong areal heterogeneity of the tested formation.
An appropriate analytic model was used to obtain a preliminary interpretation of the results. A modified three-dimensional (3D) black-oil model developed to simulate the polymer flood process was then used for analyzing the data in more detail. The model treats tracer solution as a fourth component and can also account for adsorption of tracer. Simulation efforts were concentrated on matching the breakthrough times and tracer profiles after breakthrough. Through both the analytic and the simulation work, the reservoir is characterized by a highly heterogeneous distribution of horizontal permeability, a thin layer of high permeability, and a natural waterdrive that cause a preferential flow trend in a direction toward one producer. We conclude that the interwell tracer test is an effective tool for evaluating reservoir heterogeneities and a quantitative analysis of test data is done with the polymer option of a black-oil simulator.
Analysis of Waterflood Performance - Block VI Ranger Zone, Wilmington Field, Calif.
Authors: Roark Gene R. 
Published: December 2007

Abstract
An engineering analysis of the performance of the Block VI Ranger zone water flood operation from its inception in July, 1956, to date is presented. Implications of this performance with respect to future potential of a full-scale project are interpreted. Details are given of the expansion program currently underway, together with a description of the cooperative plan of operation in effect with offset operators.
The dual purpose to be accomplished in the flood is explained. The objectives are to effect an economic waterflood operation and to control subsidence of the overlying area through control of reservoir pressure. Reservoir engineering and mechanical problems connected with the operation are treated.

Introduction
The first waterflooding Operations in the Ranger zone of Wilmington field, Los Angeles County, Calif., were initiated in July, 1956, as a pilot operation on the Producing Properties, Inc., N–1 and S–1 leases in Fault Block VI. The project is situated near the most easterly extension of the field and in the region where the Ranger zone underlies the downtown area of the city of Long Beach.
The N–1 and S–1 leases of Producing Properties, Inc. are communitized leases comprising approximately 346 acres of town-lot development. Because the drilling of oil wells is prohibited by city ordinance within the area of these leases, the development drilling was accomplished from drill sites located on the west berm of the Los Angeles County flood control channel. This strip, which is located approximately 1,400-ft west of the western limit of Fault Block VI, is 26-ft wide and 5,570-ft long.
As will be seen later, the fact that all wells producing from the properties are slant holes drilled from the western drill site has created unique problems in waterflood planning and in interpretation of the results observed in the pilot operations to date.
At the time pilot operations were commenced, a total of 65 producing wells existed on the two leases in Fault Block VI; cumulative production had reached 8,889,773 bbl of oil, 12,191,422 Mcf of gas and 398,214 bbl of water. The Parcel A properties of the city of Long Beach. operated by Richfield Oil Corp. and bordering the pilot area to the south, had reached a development of 20 wells and had produced 2,348,465 bbl of oil, 3,764,623 Mcf of gas and 79,607 bbl of water. Development drilling in Fault Block VI of the Ranger zone stops at Pine Avenue in the city of Long Beach, or at its linear projection. The oil-productive Ranger zone unquestionably extends to the east in substantial development beyond this arbitrary boundary. The pilot area is offset to the north by the E. C. Simmons N–3 lease which had two producing wells and had produced 141,315 bbl of oil, 218,046 Mcf of gas and 11,531 bbl of water. Thus, at the commencement of the pilot operation. cumulative production from the Fault Block VI Ranger zone had been 11,379,553 bbl of oil, 16,174,091 Mcf of gas and 489,352 bbl of water.
Slug Size and Mobility Requirements for Chemically Enhanced Oil Recovery Within Heterogeneous Reservoirs
Authors: Wright R. J. , Wheat M. R. , Dawe R. A. 
Published: December 2007

Summary
The influence of fluid mobilities on channeling and crossflow is demonstrated and quantified in systems containing thin high-permeability layers. Flow visualization of continuous and slug-mode displacements was performed under conditions in which capillary pressure, gravity, and dispersion were insignificant. The data from numerous experiments were correlated by a mathematical model and the viscous crossflow effects for layered media quantified. The analytical approximation, although simple, is novel and gives good agreement with the data. Such a model is essential for the initial design of stable slugs before computer simulation of the oil recovery process. For heterogeneous reservoirs, prevention of slug disintegration caused by chase fluid bypassing clearly requires oil recovery agent plus mobility buffer quantities of around 1 PV and stringent mobility balancing. The slug design criteria are more demanding than previously thought necessary for reservoirs with normal degrees of heterogeneity.
The initial assessment of chemical EOR schemes, especially polymer flooding and surfactant/polymer methods, should be aided by our design criteria, which also provides guidelines for optimization of the slug size and its chemical concentration.
Application of Exploration and Production Cost Trends to Determination of Fair-Market Gas Prices
Authors: Eggleston W.S. 
Published: December 2007

Abstract
The purpose of this paper is to outline a method of determining fair-market prices for gas sold in interstate commerce.
The Supreme Court of the United States, in the Phillips Decision of 1954, held that a producer who sells gas in interstate commerce is subject to regulation by the Federal Power Commission. The Federal Power Commission was, in effect, ordered to regulate gas prices paid to gas producers.
It has been interpreted by the courts that under utility-type regulation it is necessary to consider the cost of service of producing gas in determining a just and reasonable price. Neither the Federal Power Commission nor the gas producers have been able to establish fair and reasonable prices in any instance based on this concept. One important reason for such failure can be attributed to the impossible task of allocating costs between oil and gas on a realistic basis.
A more practical approach to this problem would be to use as a starting point prices established in a competitive market prior to regulation, adjusted for increases in costs since that time. The average weighted increase in the costs of exploration and production over the past 10 years amounts to approximately 108 percent. The application of this weighted increase in costs to prices established in 1948 can be used to determine prices for current years as a point of departure for the purpose of establishing specific prices.
Points of departure determined by this method indicate a price of 17.7 cents/Mcf in 1957, 19 cents/Mcf in 1958 and approximately 21 cents/Mfc in 1959 for South Louisiana. Specific prices for this area could be determined by such modifying factors as reserves, deliverability, location, quality and pressure of the gas.

Introduction
Technical journals and magazines periodically have carried articles on the increasing costs of both exploration and production. As a rule, these studies are expressed in terms of cost per barrel of oil found and of oil produced. This is only natural because, after all, we have all grown up under an oil economy where a barrel of oil was the basic measuring unit. Traditionally, where gas and oil were produced together, most of the income and all of the costs have been related to a barrel of oil - gas was only a by-product or a fire hazard; it was flared or sold at give-away prices.
Severe Slug Flow in Offshore Flowline/Riser Systems
Authors: Pots Bert F. M. , Bromilow Ian G. , Konijn Martin J. W. F. 
Published: December 2007

Summary
Small-scale experiments are described that simulate the unstable two-phase flow pattern of severe slugging often found in offshore flowline/riser systems. In particular, the effects of riser-base supplementary gas lift, flowline orientation, and liquid viscosity have been examined. To place the tests in perspective, the physics of severe slugging is discussed, including a method for scaling between model and prototype situations. Test results are compared with a simple hydrodynamic computer model.
Process Simulators for Oil- and Gas-Plant Operators
Authors: Dempsey J. , Richardson J. L. 
Published: December 2007

Summary
Process simulators have been used for some years in the oil and gas industries. As a training device, the simulators allow the trainee to perform plant or platform operations under normal and abnormal conditions without risk to personnel, equipment, or production. Startup and commissioning phases of new plants and processes are shortened and proceed more smoothly because tasks have been rehearsed through simulation. This paper describes how simulator systems have been successfully integrated into an operator training program.
Design and Installation of a High-Pressure Gas Cycling System
Authors: Stallings Lynn W. 
Published: December 2007

Abstract
The Gillis-English Bayou field is ahigh pressure gas reservoir locatedapproximately five miles north ofLake Charles, La., in CalcasieuParish. The field was discovered by SunOil Co. with the drilling of the LayneLouisiana Co. Well No. 1 in Dec.,1961. Sun Oil and others have drilleda number of wells in this reservoirin the last four years. Since thereservoir was found to be a gas phaseaccumulation, which had severeretrograde condensation characteristics, a gas cycling program was begun toobtain maximum liquid recovery. Agas cycling unit called the UpperHackberry Unit was established byorder of the Louisiana Department ofConservation in Nov., 1964. The need to inject gas in the wellswhich had tubing pressures of 5,000psi presented mechanical designproblems previously not encountered bySun Oil in the Gulf Coast Division. Extensive investigation revealed threeor four places in the southern UnitedStates where injection compressorswere being operated at the highpressures expected in this project. Production control of the wells, processing of the gas and oil for injectionand sale, respectively, and safe, unattended operation of the entirefacility and associated properties wereall factors considered duringplanning of this program. This paperdescribes design considerations and theparticular items of equipment used toaccomplish the gas cycling programwhich has been in operation forapproximately one year.

Introduction
The Upper Hackberry reservoir ofthe Gillis-English Bayou field hasfour sands occurring in threelocalities, or a total Of nine sandaccumulations, all in pressure communicationand Comprising a single reservoir. These sands occur between twounconformities and are productive atdepths ranging from approximately9,750 to 10,020 ft (Fig. 1). Bottom-hole pressure data andanalyses of recombined reservoir fluidsamples indicate the reservoir fluid tobe in a vapor phase with a 7,000-psidew point. Further, there is noindication of a significant water drive inthe reservoir. Reservoir fluid analyseshave indicated severe retrogradecondensation. This, in conjunction withthe depletion-type drive mechanism, will result in 84 per cent loss ofinplace reservoir liquids which wouldrepresent a 13 million bbl loss ofliquids if preventive measures were nottaken. To prevent these losses, SunOil decided to instigate a gas cyclingprogram. Parties with an interest inthe reservoir were contacted during1963 and advised of Sun's programand plans to establish a LouisianaDepartment of Conservation unit forthe purpose of gas cycling. A formalhearing was held in Sept., 1964, andthe resultant order was issuedeffective Nov. 1, 1964; gas cycling wasinitiated Jan. 24, 1965.
JPT
P. 1286ˆ
Effect of Completion Fluids on Well Productivity in Permafrost, Umiat Field, Alaska
Authors: Gates George L. , Caraway W. Hodge 
Published: December 2007

Introduction
During the years from 1944 to 1953, the U. S. Navy conducted an extensive exploration program in U. S. Naval Petroleum Reserve No.4, northern Alaska, to determine the oil possibilities. The area was designated a petroleum reserve by the U. S. Congress in 1923 and consists of approximately 37,000 square miles.
As a cooperating agency, the Geological Survey, U. S. Department of the Interior, made an extensive study of the area both in the field and in the laboratory, and reports have been published describing the general characteristics and geology of the region.
The exploratory program included several test wells on the Umiat structure in the southeastern part of the naval reserve. Of the 11 wells drilled, some were productive and some were not, but oil-bearing cores or other indications of oil were obtained from all. Several types of drilling muds were used including fresh-water muds, salt-water muds, emulsion muds and oil-base muds. At the request of the navy, the Bureau of Mines of the U. S. Department of the Interior, cooperated in the program to obtain and study the cores and core data and to determine the best completion practice.
Recently, information on these wells was removed from the restricted classification, and a study of the relation of completion methods and well productivity has been conducted so that the experience in this field may be made available.

Physiography
The Umiat field is located in the southeastern part of Naval Petroleum Reserve No.4 on the Arctic slope and lies entirely within the continuous-permafrost zone (as shown in Fig. 1). The Arctic slope is bounded on the south by the crest of the Brooks Range and on the north by the Arctic ocean. The Brooks Range, the Alaskan counterpart of the Rocky Mountains, encompasses several groups of rugged, glaciated mountains having a relief of 3,000 to 6,000 ft and maximum altitudes of 3,600 to 9,200 ft. Anaktuvuk Pass, at an altitude of 2,200 ft, is the highest elevation on the land route between Fairbanks and the Arctic plain.
Proppant-Settling Correlations for Non-Newtonian Fluids
Authors: Shah Subhash N. 
Published: December 2007

Summary
This paper expands and improves the data analysis for estimating particle-settling velocity in non-Newtonian fracturing fluids. It is shown that the available settling-velocity correlations for Newtonian fluids cannot be used for non-Newtonian fluids when an apparent viscosity term is substituted for Newtonian viscosity. Significant deviation from Newtonian correlations has been shown if such an approach is taken.
A Digital Filter for Data Smoothing With Application to Relative Permeability Estimation
Authors: Tao T. M. , Kerig P. D. , Watson A. T. 
Published: December 2007

Summary
Automatic data acquisition systems that allow data to be sampled very rapidly can provide much more information from experiments than manual data sampling. Computer storage and work requirements for interpretive procedures for calculating rock properties from measured data, however, generally increase significantly with the number of data. Rather than choosing a sampling rate on the basis of work requirements of· the interpretive procedure, we recommend sampling as frequently as possible. Improved estimates for data values to be used in the interpretive procedure can then be obtained by a smoothing process.
We present a simple digital filter for data smoothing. We evaluate improvements in relative permeability estimates that may be obtained when the digital filter is used with data collected from displacement experiments. The use of the digital filter can result in significant improvement in the accuracy of relative permeability estimates.
Short-Term Transient-Rate and Pressure-Buildup Analysis of Low-Permeability Reservoirs
Authors: Ahmed Usman , Kuchuk Fikri , Ayestaran Luis 
Published: December 2007

Summary
A majority of low-permeability wells, both unfractured and fractured, are analyzed with the conventional transient-pressure-buildup test. Application of this technique to wells faced with wellbore storage, even small amounts, can be time-consuming and may not provide accurate answers. Wellbore storage and its effect on the transient regime duration distorts early-time data. Such early-time data could range from a couple of hours to days and weeks. This constraint makes long-term data necessary and does not allow the interpretation of early transients reflective of near-wellbore conditions that are unaffected by outer boundary effects.
This paper presents a technique that reduces test time considerably and obtains accurate formation flow properties before any boundary effects are felt. The technique involves measuring transient rate and pressure at the wellbore during the buildup period and a few minutes before the surface shut-in of the well. The technique is called TRAP™ (transient rate and pressure) analysis. Having the transient rate during the pressure buildup allows the engineer to correct the pressure data collected during the early portion and to perform the analysis for permeability, skin factor, reservoir pressure, and other formation characteristics.
A field example is presented to show the effectiveness of the technique in analyzing low-permeability reservoirs.
Peripheral Water Flood as a Supplement to Gas Injection Pressure Maintenance
Authors: Storer T.C. , Plaza J.B. 
Published: December 2007

Abstract
Wiliamar West field has been operated with a crestal gas injection program for several years. The analysis and its results which led to the decision to water flood the field are discussed. Economics based on this analysis appear to be favorable for the simultaneous application of both gas and water injection.

Introduction
Willamar West is a field in which a successful gas injection pressure maintenance program, started during the primary life of the reservoir, is to have a peripheral water flood imposed also, the two to operate simultaneously at opposite sides of the oil column. The Willamar West unit's working interest owners have only recently agreed to water flood the Willamar pay zone; consequently, only the theoretical considerations leading to that decision can be shown at this time.

History of Unit
Willamar West field is located in east Willacy County approximately 12 miles east of Raymondville, Tex. The Willamar structure is separated by faults into three main producing areas. These areas (Fig. 1) have been designated Willamar West field, Willamar North Graben field and Willamar field by the Railroad Commission of Texas. The Willamar field was discovered by Pan American Production Co.'s Willamar Community Well No. 1 in March, 1941. Subsequent drilling resulted in the discovery of Willamar West reservoir by the completion of Pan American Production Co.'s Kent No. 1. The field was developed very slowly during World War II. However, development was more rapid after 1944, and the field was completely developed for all practical purposes by 1947.
The allowable was initially 103 B/D/well, and all of the three Willamar producing areas were considered as having one field MER. As a result of plummeting bottomhole pressures and a rising field GOR, this MER was reduced in 1949 to permit more efficient use of the expansive energy of gas caps and aquifer (particularly the caps). Because of a growing concern over pressure decline and the flaring of casinghead gas, the Willamar Engineering Committee was formed which, with the help of consultant's studies, investigated the advantages of gas injection.