bluuebunny/crossref_metadata_2025_split huggingface dataset:
Use of Cumulative-Production Type Curves in Fracture Design
Authors: Elbel J. L. , Sookprasong P. A. 
Published: December 2007

Summary
When a fracture treatment is designed, the expected increase in productivity or production rate is usually considered. Because production rate varies with time, an economic evaluation based on a production rate increase at a given time can be misleading. A better method of economic evaluation would use the cumulative production after some time period. This can be determined by reservoir simulators that incorporate the effect of propped hydraulic fractures. These simulators are not readily accessible to everyone, however, and are time-consuming and expensive to run. Several authors have stated that cumulative-production type curves can be made with data generated by dimensionless-pressure type curves for a fractured well with infinite fracture conductivity. This paper shows how cumulative-production type curves for finite fracture conductivity can be generated from published dimensionless reciprocal-rate type curves or from reservoir simulators. A simple graphic procedure can then be used to give the combinations of fracture lengths and dimensionless fracture conductivity that will show the desired cumulative production or production rate at some particular time. Charts and simple equations also are given that will allow a quick estimate of the proppant volume required for the various fracture geometries needed for the desired production. This would form the basis for optimizing the fracture treatment. When used with methods to determine fracture fluid volumes for various fracture lengths, the minimum cost for any desired production can be made.
Automatic Custody-Transfer System at Lake Pelto, Louisiana
Authors: Tansil John T. , Moor Leslie M. 
Published: December 2007

Abstract
The production system and custody-transfer system for the Sun Oil Co.-Pure Oil Co. installation at Lake Pelto La., was designed to operate continuously and automatically to achieve maximum throughput with a minimum requirement for on-lease storage and manual attendance. Suitable equipment was installed in such a manner that all the wells can be controlled from a central production platform; their produced liquids can be processed continuously and delivered to the custody-transfer system with the assurance that all oil delivered is of merchantable quality. The custody-transfer system was designed to deliver oil automatically from the production system to the gathering line, using positive-displacement meters and related equipment for the measurement function.

Introduction
Everyone is aware that the cost of oil production and handling facilities in water locations is quite high. These costs have been trimmed a little through the years by more careful engineering, by prefabrication, and even by some attempts at mass production; today, however, the greatest hope for cost reduction lies in the use of newer improved oil-handling techniques.
For this reason, in planning the facility to serve the Sun Oil Co. operated Louisiana State Lease 2620 in the Lake Pelto field, the design section was instructed to utilize automatic control systems and equipment wherever the application could be of economic or operational advantage.
The full portent of this charge was realized when initial engineering estimates were summarized to showthat a continuous throughput design, utilizing automatic custody transfer, would reduce oil storage requirements 60 to 70 per cent compared to a conventional system andthat the additional cost of the equipment and controls necessary to make the operation continuous and completely automatic was approximately the same as the cost of 1,000 bbl of storage in this water location.
The Statistical and Dimensioniess-Time Analog to the Generalized Dykstra-Parsons Method
Authors: Enick Robert M. , Reznik Alan A. , Miller Robert A. 
Published: December 2007

Summary
Statistical and graphic representation of the recently generalized Dykstra-Parsons vertical stratification analysis are presented for the injection constraints of constant rate and pressure. Waterflood performance parameters include the instantaneous reservoir water cut and the vertical coverage as functions of dimensionless real time and injection constraint for a complete range of mobility ratios and permeability variations. The layer permeabilities are log-normally distributed.
The real times associated with the two injection constraints are reduced to dimensionless forms by use of reference times that are both rational and different for the respective injection constraints. The introduction of real time or dimensionless real time reveals the dramatic distinction in performance characteristics between the constant-injection-rate (CIR) and constant-injection-pressure (CIP) cases. Elimination of the time basis between the waterflood performance parameters masks the distinction between the two injection constraints and reduces the graphic solutions to those originally presented by Dykstra and Parsons without the inclusion of their severely restrictive recovery correlation.
The relationship between complete vertical coverage and dimensionless time is shown to be a simple analytic function of the permeability variation statistic and the number of beds for the case of constant injection pressure.
Protective Coatings for Corrosion Control in Production Operations
Authors: Robinson R.M. 
Published: December 2007

Introduction
Coatings are used in production operations for identification purposes, for appearance and for corrosion control. The role of coatings as a corrosion-control measure in production operations has become an increasingly important one during the last several years. There are a number of reasons for this, the primary one, of course, being costs. Labor and equipment-replacement costs have risen sharply during the past decade, but the price of the prime product, oil, has not risen accordingly. Another reason for increased use of coatings is the presence of severer corrosive environments such as those encountered in offshore operations. Also, more operators have become aware of the savings and benefits to be gained from the proper selection and use of coatings.
When used for corrosion control, coatings serve as barriers to separate the metal from the corrosive environment. In production operations, the corrodents and physical conditions are almost innumerable. Consequently, a myriad of coatings and coating types have been offered to the industry, and new ones are being marketed almost daily. Many tapes and sheathing materials also are available for use as corrosion barriers. Tapes and sheathing materials are discussed later in conjunction with the services for which they are used.
Present-day coatings belong to many generic types. Some "dry" by solvent evaporation, some dry by oxidation while others dry, or "cure", by polymerization. Oxidation or polymerization may be catalyzed by chemical additives or by baking at elevated temperatures. Relative resistances of the coating materials vary greatly between, and even within, generic families. Therefore, it becomes the corrosion man's problem and responsibility to select the proper coating for a particular corrosive environment.
Efforts to Develop Improved Oilwell Drilling Methods
Authors: Ledgerwood L.W. 
Published: December 2007

Abstract
During the past three decades, the oil industry has expended increasing efforts seeking improved drilling tools or systems to reduce drilling costs. The total cost of these efforts is unknown, but it certainly amounts to tens of millions of dollars. Most of the "new" systems that past and present investigators have sought to develop actually are old public information.
In seeking to implement new-system concepts, investigators have tested the following: impact at frequencies ranging from 6 to 300 cycles per second; electrical, mechanical and hydraulic means of actuating percussors; bit rotary speeds up to 2,000 rpm; electric and hydraulic bottom-hole means of rotating bits; bottom-hole machines with power outputs up to 400 hp; shock waves; explosives; high-velocity pellets; flame; arc; grinding wheels; abrasive jets; erosion by high-velocity gases;chemical attack; electric current; magnetic waves; retractable rock bits; reelable drill pipe; continuous coring with reverse circulation; and automation of drilling rigs. Table 1 shows how these investigations are grouped for discussion purposes in this paper.
In spite of these efforts to discover new and improved systems, rotary drilling maintains its economic leadership. Undoubtedly, rotary drilling costs will continue to be reduced by rigid application of the best available technology and by development of new rotary technology. In view of the extensive past development programs, however, significant long-range improvement appears to be a research, not a development problem. Research must postulate and prove theories and principles governing various subsurface rock-failure processes pertinent to both rotary and new systems. Also, research must produce physical and engineering data relative to these processes. When such information is available, earth boring will graduate from an art to a science. Major improvements in rotary drilling can then be expected, and the systematic evolution of an improved drilling method can be initiated-with a strong probability for success.
Additive Effectiveness and Contaminant Influence on Fluid-Loss Control in Water-Based Muds
Authors: Nyland T. , Azar J. J. , Becker T. E. , Lummus J. L. 
Published: December 2007

Summary
The proper fluid-loss control of drilling muds becomes more difficult when drilling high-temperature, high-pressure formations. Chemical additives for reducing fluid loss differ considerably in effectiveness; in turn, these differences vary, often unpredictably, with temperature and pressure. This paper discloses the results of static-filtration experiments that compare capabilities of various additives to minimize filtrate invasion at elevated temperatures when the mud contains certain common contaminants. The effects of mud weight, high-temperature aging, and the presence of asphalt on mud fluid loss were also investigated.
The additives selected for study were WL-100™, carboxymethyl cellulose (CMC), Dextrid™, CC-16™, Resinex™, and several asphalts. Certain combinations of these were also studied. The contaminants used typify those originating from drilled formations: sodium chloride, calcium sulfate, sodium sulfate, cement, and Rev Dust.
On a cost-equalized basis, a combination of Dextrid and CC-16 was found to be a good additive for controlling fluid loss at high temperatures and pressures regardless of whether contaminants were present. The additives WL-100 and Dextrid were also effective.
The Effect of Instability on Relative Permeability Curves Obtained by the Dynamic-Displacement Method
Authors: Peters Ekwere J. , Khataniar Santanu 
Published: December 2007

Summary
A study was undertaken to investigate how instability would affect the oil/water relative permeability curves obtained by the dynamic-displacement method. In this method, stable Buckley-Leverett displacement theory is used to calculate relative permeability curves from coreflood data. Thus, to obtain the true relative permeability curves by the dynamic-displacement method, the coreflood must be stable. However, the method frequently has been applied to unstable corefloods. The consequence of this application of the method has not been previously reported.
We compared oil/water relative permeability curves from steady-state and dynamic-displacement experiments at several levels of instability. The results showed that the dynamic-displacement relative permeability curves deviated significantly from the steady-state curves as the degree of instability increased. This observation indicates the need to scale laboratory relative permeability measurements to account for instability. To obtain representative relative permeability curves for numerical modeling of a reservoir, laboratory displacement experiments should be conducted at the same degree of instability as that in the reservoir.
Progress Review of the K&S Carbonated Waterflood Project
Authors: Hickok C.W. , Christensen R.J. , Ramsay H.J. 
Published: December 2007

Abstract
A carbonated waterflood process which comprises the treatment of a hydrocarbon reservoir with controlled amounts and concentrations of carbon dioxide is one of the newer methods of increasing oil recovery being used in a commercial field application. The process consists of the treatment of a crude-oil reservoir with controlled amounts and concentrations of carbon dioxide (CO2) or solutions of carbon dioxide. To achieve this end, the techniques of water flooding are combined with the injection of carbonated water into a reservoir during the early stage of the flood. The K and S project is the first commercial application of this process.
Water injection was initiated on the and project in Feb., 1958, and CO2 injection started in April of the same year. The carbonation period should be completed by April 1, 1960. At this time it is too early to predict the ultimate oil recovery from the project. However, several notable accomplishments have been recorded to date. When the project was initially developed, several areas were noted to be highly water productive due to a previous dump flood. These areas subsequently have produced considerable oil, indicating that additional recovery has been gained. Second, injectivity has been increased to two to four times the rate of neighboring input wells which have not been subjected to the carbonated water process. And third, in 1959 more oil was produced than has been previously produced for the total primary life of the property.

Introduction
This paper is a progress report outlining the accomplishments and difficulties experienced to Jan. 1, 1960, at the K and S project. The K and S project is located 10 miles north of Bartlesville, Okla., and consists of three contiguous leases totaling 240 acres. There are 35 input wells and 24 producing wells spaced on a regular 10-acre five-spot pattern, as shown in Fig. 1. Water injection was initiated in Feb., 1958, and CO2 injection started in April of the same year. CO2 injection will be completed by April 1, 1960. Water injection will continue throughout the life of the project. The property was acquired in June, 1957. With 80 per cent of the working interest, Oil Recovery Corp. acts as engineering consultant and supervises the application of the process. Wellsville Oil Co., with the remaining 20 per cent of the working interest, is flood operator of the joint venture.
Use of Potassium/Lime Drilling-Fluid System in Navarin Basin Drilling
Authors: Holt C. A. , Brett J. F. , Johnson J. B. , Walker T. O. 
Published: December 2007

Summary
This paper presents a case history of Amoco Production Co.'s use of potassium-lime mud (KLM) for drilling a series of wells in the Navarin basin. The remote location, logistical concerns, environmental regulations, and the high cost of the operation mandated that the project be carefully planned. Planning, however, was hampered because the nearest offset to any of the wells was more than 100 miles [160 km] away. This paper describes the planning, implementation, and results of the mud system used to drill the wells. It includes a matrix of tests used to define further the nature of KLM, presents the methods used to run the system while the wells were drilled, and describes the results of using the mud in the basin. Navarin basin experience suggested that KLM should be considered when clay inhibition is needed and moderate bottomhole temperatures (BHT's) are expected.
Predicting the Build/Drop Tendency of Rotary Drilling Assemblies
Authors: Jogi P. N. , Burgess T. M. , Bowling J. P. 
Published: December 2007

Summary
Today, the majority of rotary bottomhole assemblies (BHA's) for directional control are designed through practical experience and trial and error. This approach can produce satisfactory results when a great deal of local experience can be drawn on. It can prove costly, however, during drilling in a new area because of the increased number of trips and correction runs. This paper demonstrates how a BHA model can be used to predict the directional inclination tendencies of rotary assemblies, thus limiting the uncertainty associated with the traditional BHA design techniques.
The technique is demonstrated on data from 17 bit runs from three wells on the same platform in the Gulf of Mexico. Predicted tendencies from BHA descriptions alone proved to be accurate (to an error of ±0.1°/100 ft [±0.03°/10 m]) in more than half the cases. The uncertainty of other predictions appeared to depend on the hole gauge. The distance taken for a BHA to reach a stable build/drop rate after the start of a bit run depends on the length of the BHA. This factor must be taken into account in the prediction of BHA performance.
The Application of Slim-Hole Completions to Secondary Recovery
Authors: Hinckley Jack 
Published: December 2007

Introduction
Oil men are probably as tired of hearing about rising costs as they are of experiencing them. It goes without saying that we are vitally concerned with discovering less expensive methods of developing production, both primary and secondary. Slim-hole completions are believed to be a partial solution to this problem. Contrary to what many people think, slim-hole completions are not new. One operator, the Stekoll Petroleum Corp., has been completing wells with 2 7/8-in., or smaller, casing for 18 years. The purpose of this paper is to review this development and discuss its application to secondary recovery. Slim-hole completions should not be confused with slim-hole drilling. The primary purpose of a slim-hole completion is to save money. Quite often, the cost of drilling a small-diameter hole is more than that of a slightly larger one. In such cases, it is defeating the purpose of slim-hole completions to insist on the drilling of a smaller hole.

History of Development
In 1942, Stekoll initiated a water flood in the Bolton field of Montgomery County, Kans. The Bartlesville sand in this area lies at a depth of approximately 1,000 ft, and the property was developed as a flowing-type water flood. The completion cost of wells with 4-in. casing, which size was customary for the area, was compared with the cost of completions using 2-in. casing. This study indicated that the additional capital investment resulting from completing with the larger casing would be very substantial when applied to the entire property. Because of this and because of the shallow depth of the wells, it was decided that 2-in. line pipe would be used for casing in both producing and injection wells. As a result, total development costs were reduced by 33 1/3 per cent.
A short time later, another Kansas water flood was developed on wider spacing, and producing wells were pumped instead of being flowed. It was here that the company first attempted to pump inside 2-in. casing using a reciprocating string of 1-in. line pipe as tubing and rods. An insert-type bottom-hole pump was adapted successfully. Operating costs over the past 15 years have been equivalent to those of conventional wells.
A Correlation of Dewpoint Pressure With Fluid Composition and Temperature
Authors: Nemeth L.K. , Kennedy H.T. 
Published: December 2007

Abstract
The investigation presented in this paper was performed to develop a relationship between the dewpoint pressure of a hydrocarbon reservoir fluid and its composition, temperature and characteristics of the heptanes-plus fraction. This is part of an over-all program to develop correlations for the essential properties of reservoir fluids with the composition, temperature and pressure. In all, 579 dewpoint pressures, determined experimentally on 480 different condensate systems along with their compositions and temperatures, were obtained from the literature and from previously unpublished sources. Compositions were expressed in terms of mol fractions of methane through heptanes-plus, nitrogen, carbon dioxide and hydrogen sulfide, and the molecular weight and specific gravity of the heptanes-plus fraction. Distribution of the samples assured a good representation of most of the major oil-producing areas in the world.
A multiple regression analysis program written for the IBM 7094 digital computer was used to compare numerous equations and to calculate their coefficients. The final equation containing 11 coefficients resulted in an average absolute deviation of 7.4 percent for all the samples. Segregation of data on the basis of one or more variables did not materially improve the results. The correlation developed is useful in predicting the dewpoint pressure of condensate reservoir fluids from variables normally measured in the laboratory.

INTRODUCTION
In any discussion of the dewpoint of hydrocarbon mixtures, it should be noted that there are two kinds of dewpoints which, must be distinguished. The first type, or normal dewpoint, usually occurs at low pressures as dry gas is compressed to the point where liquid first forms. The second type, sometimes called the retrograde dewpoint, occurs when a gas mixture containing heavy hydrocarbons in solution is depressured until a liquid is formed. The first type, as applied to condensate mixtures, would normally be below atmospheric pressure and would be of no interest in reservoir performance. The second type is of great significance in interpreting reservoir behavior and is the property referred to throughout this paper.
Laboratory measurement of dewpoints is laborious, expensive and subject to many errors, and it is desirable to find a reasonably accurate method to predict dewpoint pressures from the composition and other readily available properties normally measured on the fluids. A possible method of calculating dewpoint pressures would be to employ a set of equilibrium ratios (K-values).1 However, the K-values themselves depend on composition as well as temperature and pressure; presently their use adds nothing to the accuracy of predicting dewpoints. If future correlations provide a significantly better method of estimating K-values for heavy hydrocarbons, they may be of greater use.
Mechanism of Transit Time Increase and Its Interpretation After Water Injection into Reservoir M in the Lao Jun Miao Oil Field
Authors: Hao Zhi-xing , Shen Lian-di 
Published: December 2007

Summary
Reservoir M in the Lao Jun Miao oil field is a very massive sandstone oil reservoir about 60 m [200 ft] thick. Within the reservoir, there are no evident shale barriers and no interlayer standard water zones. This reservoir is classified as a fractured porous reservoir. The reservoir rocks have a high shale content; montmorillonite is the main clay mineralwith a maximum percentage content of up to 60%. After water injection, the sonic transit time was increased substantially in the flooded rather than in the nonflooded intervals.
This paper gives an idea of the mechanism for the increase in sonic transit time in flooded intervals of the reservoir on the basis of the measurement and analysis of the noninvaded cores. Study results show that the increase in sonic transit time after flooding is linked to the rock texture in relation to the high montmorillonite content.
It is well known that montmorillonite expands when it absorbs water and can plug the formation. However, it is possible to have better communication in the pores locally. These concepts are important and useful for better oilfield development and in the evaluation of the sweep efficiency of waterflooding.
This paper also gives an in-house measurement technique for samples with high montmorillonite content.
On the basis of core analysis and well testing data, we propose a comprehensive interpretation technique for determining flooding or nonflooding intervals that uses the transit time from sonic logging as the main data. Good results have been obtained.