bluuebunny/crossref_metadata_2025_split huggingface dataset:
Innovations in Subsea Development & Operation
Authors: Henry W. C. , Hyden A. M. , Williams S. L. 
Published: December 2007

Abstract
Esso Australia Ltd., on behalf of the Esso/BHP joint venture, recently completed Australia's first deep-water oil and gas development, Blackback, in 395 m water depth in eastern Bass Strait. Esso used a phased development approach and an innovative development concept to mitigate the effect of reserves uncertainty. The development consists of three wells in daisy-chain formation tied back to the existing Mackerel platform, 23 km distant. The development also used innovative approaches for installation of flexible flowline and umbilical jumpers from the drilling rig, management of hydrates in the production flowline and control system integration.
In the same time frame, Esso repaired the failed electro hydraulic control systems of two ten year-old subsea wells. The repair program used an innovative approach to fault diagnosis and field work.
U.S. Drilling - Who, Where, Why and How Deep
Authors: Dougherty Tom 
Published: December 2007

Abstract
1976 was the best year for domestic drilling… in terms of wells completed… since 1964. Improved prices for both oil and gas, despite government controls of both, are reflected in increased drilling during the period 1973–1976. period 1973–1976.Most areas of the country have shared increased activity. The most sizable increase has been in development drilling, followed by close-in exploratory work. Unfortunately, the last two years have brought slight declines in new field wildcats. However, percentage of wildcat success has not dropped.
Production, although still declining, has responded, to a significant degree, to increased activity.
The majority of the nation's drilling is done on an operator-of-record basis, by operators not generally classified as "majors".
Heaviest drilling has tended to appear in areas where gas can be sold to intrastate markets, and in areas where large numbers of oil wells can be completed rapidly, even though the resulting wells would probably have been considered uneconomic at prevailing prices of a few years ago. prices of a few years ago. Average total depths have tended to increase during the past three years, although there has been no marked increase in the number of ultra deep wells.
These, and other characteristics of 1976 drilling activity, with special attention to the Permian Basin, are pointed out in "overview" fashion.

TEXT
The United States became aware, nearly four years ago, of a condition which was well-known to the petroleum industry long before then. There was, and still is, a crisis of energy supply.
The reasons are widely known, but not widely acknowledged. In fact, to this day, the existence of a real problem is not by any means fully acknowledged.
During the period since the 1973 embargo, we have fumbled and faltered our way through charges and counter charges without development of any effective course of action. As a country we still do not have concensus as to what, if anything, should be done, or if anything should be done. One philosophy which has repeatedly been stated, or at least inferred, is that we can do little that's worthwhile in domestic development of conventional energy supplies.
Review of Artificial Lift in Egypt
Authors: Naguib M. A. , Shaheen S. E. , Bayoumi A. El-Wahab , El-Emam N. A. 
Published: December 2007

Abstract
One of the real challenges facing the oil industry in Egypt now, is to keep up production and maximize reserves especially in mature oil fields. The application of artificial lift systems to improve the productivity, whilst ensuring the most effective use of the existing reserves, should optimize the petroleum resources.
A total of 137 oil and gas fields were placed on production since the oil industry in Egypt started in 1910. Currently there are 122 oil and gas fields on stream, among which 9 are gas production fields and the other remaining 113 are producing oil from 1311 oil wells. The natural producing wells are representing 15%, while the gas lifted wells are 24% and the pumped wells are 61%.
This paper presents the philosophy and the methodology of applying artificial lift system in the Egyptian oil fields. Pending on the production forecast and the expected well behavior and also the effects of applying the secondary recovery mechanism either by water flood or gas injection.
Also the problems encountered on well behavior are analyzed and solutions are suggested. Special emphasis is given to the marginal oil fields artificial lifting systems, because of the economical limitation accompanied with such field's development costs.
The concept is not only to equip a well with a cost effective means of artificial lift to be able to continue production, but also to manage the reservoir behavior for the maximum oil recovery.
Mathematical Modelling of Wax Deposition in Crude Oil Pipeline Systems
Authors: Kok Mustafa Versan , Saracoglu Onder 
Published: December 2007

Abstract
Deposition of wax on the wall of the crude oil pipelines is regarded as a problem since the pipeline diameter is reduced. Therefore more power is required to force the same amount of crude oil through the system. In this study, a mathematical model is developed for estimation of wax deposition in crude oil pipeline systems. A computer program was developed to simulate wax deposition phenomena. Each component is characterized by weight fraction, heat of fusion and melting point temperature. Temperature profile along the pipeline, solid-liquid equilibrium constant, wax mole fraction and wax thickness along the pipeline were calculated. This computer program was applied to Kirkuk - Ceyhan crude oil pipeline system. It was observed that wax thickness, after a year, is approximately 0.34 mm and temperature declined from 303 K to around 295 K. The wax mole fraction after a year is approximately 0.2225. The solid-liquid equilibrium constant for the first component was around 0.29 and 355 for the second component after a year.
Successful Optimization and Application of Primary Cement Designs Enables Annular Placement of Casing Perforating Guns for Multiple Zone Completions
Authors: Dillenbeck Robert L. , Cooper Dwayne 
Published: December 2007

Abstract
Recent and exciting technical advances have allowed for the development of a process whereby multiple productive zones in a new well can be identified and set up for external casing perforation and completion in a matter of days instead of weeks. This process uses newly developed tools and perforating guns that are run into the wellbore on the casing exterior prior to the primary cementing of the production casing. Once cemented into the well, the drilling rig can be removed and the well prepared for multiple completions in a single day. However, before any of this can happen, the production casing must be successfully cemented in the wellbore and all productive zones adequately isolated from other formations exposed to the wellbore. Since the annular configuration of the primary casing strings using this new technology is considerably different from a more "conventional" production casing string, they cannot be cemented in the same manner. Due to the unique design of much of the external casing equipment used in this process, many tough cement design and operational challenges had to be analyzed and solved before the first field test well could be drilled and cemented.
The authors will detail the various cementing challenges and how they were overcome in the actual field applications of this new technology. Three new wells in widely separated fields will be examined on a case by case basis to illustrate the application of this new technology and the cementing designs, procedures and techniques used to accomplish the necessary zonal isolation. The three wells ranged from having two productive zones to 12 zones, all of which had to be isolated. Finally, the relative success of the cement isolation of the productive zones in each well will be examined.
Waterflood Redevelopment Prior to Future Tertiary Attempts - A Case History
Authors: Roy M.B. , Tucker C.W. , Lakey C.J. , Cloud W.B. 
Published: December 2007

Abstract
The Postle Field, located in the Oklahoma Panhandle, is typical of modern oil fields with waterflood programs now approaching maturity. The field appears to have all the requisites necessary for a successful tertiary recovery program except adequate crude price incentives. While adequate price incentives for a tertiary project are not yet a reality, an infill redevelopment program has been initiated. This program has profitably increased production, recovered oil from previously bypassed areas, added substantial previously bypassed areas, added substantial insight into field recovery mechanisms, and provided additional information essential for the development of a tertiary recovery program. program

Introduction
Millions of barrels of oil await recovery in existing fields beyond primary and traditional waterflood mechanisms. An approximate U. S. oil scenario is as follows: some 109 billion barrels have been produced to date, and estimates are that an additional 33 billion barrels will be recovered by primary and secondary recovery techniques, of which waterflooding is the chief method. The ultimate recovery of 142 billion barrels via primary and conventional fluid injection techniques represents 32 percent of 442 billion barrels of original oil-in-place. Therefore, the remaining 300 billion barrels offer an enormous potential for application of tertiary recovery potential for application of tertiary recovery methods. In today's state of the art, chemical flooding appears to be the most generally applicable tertiary recovery method. In spite of extensive laboratory studies and a few small-scale field tests, the commercial viability of this technique remains unproved. Today's government imposed restraints on oil prices are certainly not conducive to a badly prices are certainly not conducive to a badly needed momentum in tertiary recovery projects which require a huge front-end cost and a very high risk capital exposure. However, one thing is certain: tertiary recovery efforts must be initiated to help meet this country's energy demands — even though it may be several years from now, pending a favorable economic environment. In the meantime, a number of activities can be incorporated in current operations which will be helpful in the future when a tertiary project is initiated. The Postle Field is a case in point.

FIELD DESCRIPTION
The Postle Field is located 250 miles northwest of Oklahoma City, near the center of the Oklahoma Panhandle.
Norge Unit Plan Implemented
Authors: Jowell Jack H. , Haberthur Charles R. 
Published: December 2007

PUBLICATIONS RIGHTS RESERVED PUBLICATIONS RIGHTS RESERVED Permission to include this paper in the Proceedings for the 1977 Permission to include this paper in the Proceedings for the 1977 Oklahoma City Section Regional Meeting of the Society of Petroleum Engineers, held in Oklahoma City, February 21–21, 1977, was secured from PETROLEUM ENGINEERS, where it was first published in the November, 1976 issue. Permission to copy is restricted. The paper is subject to correction.

Abstract
The engineering and planning activities preceding and following unitization of the preceding and following unitization of the Norge Marchand Unit in Grady County, Okla., are described herein. The 12,000-acre, 75-tract unit was approved by the Oklahoma Corporation Commission in Feb. 1974, 3 years after the discovery of the field.
The unit area contained 75 wells developed on 160-acre spacing and producing from the Marchand sand at a depth of 10,100 to 10,800 ft. Sixty percent of the ultimate primary reserves had been produced prior to unitization.
The plan of operation was designed to maintain reservoir pressure at or near the bubble-point pressure of the reservoir fluid by water injection. The project was expected to increase recoverable reserves by 31,750,000 bbl of oil. This represents an increase in ultimate recovery from 15.7 percent of the original oil in place by primary depletion to 32.5 percent.
Reservoir pressure had declined below the bubble-point pressure of 2,826 psi to 2,405 psi when water injection commenced. Water psi when water injection commenced. Water injection volume has been equivalent to 4.6 percent of the pore volume, or 50 percent of percent of the pore volume, or 50 percent of the required fill-up volume. No severe channeling or water breakthrough has occurred. Producing GOR's have been reduced substantially Producing GOR's have been reduced substantially and reservoir pressure has increased.
The designed injection rate of 35,000 BWPD has been achieved in 23 input wells. A suitable injection to voidage ratio has been maintained throughout the field. A planned eight-well infill development program is in progress to restore some of the productive progress to restore some of the productive capacity lost by injection well conversions. An adequate water supply of desirable quality has been developed and water injectivity has matched predictions closely.

Introduction
Concentrated engineering and planning efforts by 17 oil operators, representing 60 working interest owners and 344 royalty owners, culminated in the unitization of the 12,000-acre Norge Marchand Unit in Grady County, Okla., within 3 years after discovery of the field. By order of the Oklahoma Corporation Commission dated Feb. 19, 1974, the project was authorized for the purpose of pressure maintenance by water injection, which was expected to increase the recoverable reserves by 31,750,000 bbl of oil. Sun Oil Co. was named unit operator.
Prevention and Control of Formation Damage
Authors: Hower Wayne F. 
Published: December 2007

WELL COMPLETION
All wells are susceptible to formation damage at any time during the life of a well. Some damage sources are drilling fluids, cement filtrates, water and/or emulsion blocking, oil wetting of silicate surfaces, "dirty" treating fluids, and clays. Clays may be considered a major source of permeability reduction. This damage can occur when a water foreign to the formation contacts the clays, causing them to break loose and migrate with fluid loss. Subsequent bridging of clay particles at flow restrictions in the rock can then cause a decrease in permeability.
Completion techniques can vary considerably from one field to another as methods should be devised to fit particular conditions. Good completion procedures depend upon having reliable well data available, making use of past experiences, and using clean (filtered) past experiences, and using clean (filtered) an properly treated workover and stimulation fluids.
Permeability damage often occurs with the initial completion of a well. However, this damage usually exists only a short distance into the formation and can be removed with relatively small volumes of various types of acid solutions.
Where a well is to be stimulated, a better procedure can be developed if cores are procedure can be developed if cores are available for tests. The results of these tests will help develop the type of fluid to use for the treatment. Two of the tests that should be conducted are as follows.The selection of a surfactant to be added to the stimulation fluid that will help to prevent emulsion development and also provide very low interfacial tension values provide very low interfacial tension values between the fluid and hydrocarbons in the formation. The latter is essential in the recovery of the stimulation fluid (usually aqueous) from formation flow channels. The surfactant should also leave the rock water wet.The analysis of the cores to determine mineral and clay content is very important. If enough clay is present for the formation to be considered to be water sensitive, 1- to 2-percent potassium chloride or ammonium chloride can be added to the water-base stimulation fluid to minimize possible permeability damage due to clays.
Polyacrylamides Can Restrict Water, Oil and Gas Production - It's Your Choice
Authors: Sparlin Derry D. 
Published: December 2007

Abstract
Production of water from oil wells is becoming an increasingly serious problem each year. As oil reservoirs are produced, increasing water production results from water coning, from rising water-oil contacts, from channeling behind the casing or through high permeability streaks. Increased costs of producing and handling unwanted water are minor compared to the loss of oil production rate or loss of oil because of early abandonment of wells resulting from excessive water production.
Many good water shutoff techniques are available to the industry, but most of them shut off all production from the portion of the wellbore where they are used. Products such as cement, sodium silicate, and plastics are capable of completely sealing a well; thus, they should be selectively placed. Before such materials are used, the exact source of water production must be located and isolated so that only the water is shut off. If this is not done properly, oil production may be reduced permanently. production may be reduced permanently

Introduction
In recent years the most promising water control materials have been polyacrylamides. These water soluble polyacrylamides. These water soluble polymers are capable of greatly polymers are capable of greatly reducing the permeability of a water producing formation without significantly producing formation without significantly altering the permeability to oil in the oil zone. They do this without the need to locate the source of the water or of isolating the water source. This can result in large increases of oil production rates and reduction of water production rates and reduction of water production simply by injecting the polymer production simply by injecting the polymer solution into the well, then returning the well to production. It is postulated that the accelerated oil production that often results from this type of treatment is due to a reduced head in the wellbore as less water is being produced. It is also possible that permeabilities of portions possible that permeabilities of portions of watered out formation are reduced enough by the polyacrylamides that the natural sweep pattern into the wellbore is affected. Thus, additional oil is recovered.
Evaluation of Reservoir and Hydraulic Fracture Properties in Geopressure Reservoirs
Authors: Poe B. D. 
Published: December 2007

Abstract
Field production performance data and multiple pressure transient tests over a period of time for oil and gas wells in geopressured reservoirs have been found to often exhibit marked changes in reservoir effective permeability over the producing life of the wells. Similarly, the use of quantitative fractured well diagnostics to evaluate the production performance of hydraulically fractured wells have clearly shown that effective fracture half-length and conductivity can be dramatically reduced over the producing life of the wells.
This paper reports the results of the research, development, and application of production performance analysis models to directly measure the changes in the reservoir effective permeability and fracture effective conductivity of hydraulically fractured wells completed in reservoirs that are subject to stress-dependent variation of the intrinsic formation and fracture properties. The interpretation model development is documented in the Appendices of this paper. Field examples are presented which demonstrate the application of the interpretation models to both unfractured and hydraulically fractured well production performance analyses in which stress-dependence of the reservoir and fracture properties are clearly exhibited.
Analyzing Pressure Transient Test in Semi-Infinite and Finite Reservoirs Using De-Superposition Method
Authors: Zheng Shi-Yi , Stewart Ggeorge , Corbett Patrick 
Published: December 2007

Abstract
Conventional well test interpretation is dominated by the analysis of pressure BuildUp (BU). The method for analyzing BU is derived by the principal of superposition based on the constant terminal rate DrawDown (DD) solution of an "infinite" reservoir with uniform properties. The presentation of the diagnostic plot (log-log plot) and flow regime identification from the pressure derivative curve – in the Late Time Region (LTR), in particular, critically rely on time functioning. The most popular time functioning used for well test analysis is Horner and Agarwal equivalent time. However, these time functioning methods are not reliable for the LTR analysis. When linear (semi-infinite fluvial channel or compartmentalized systems) and pseudo-steady-state flow (finite or closed system) are present, the flow regime diagnostic at LTR using Horner or Agarwal equivalent time frequently result in a false definition of flow regime and misleads the analyst.
The de-superposition method can present the pressure BU in the same way as that for a DD, so the ambiguity in identifying the LTR behavior can be resolved. On the other hand, the DD LTR behavior (pressure derivative) in semi-infinite or finite reservoir systems is very valuable for the identification of the reservoir external boundary conditions (even though it is usually not good to define the radial flow region due to the rate fluctuation and often, incorrect production history input). Experience has proved that BU analysis using the de-superposition method combined with DD LTR analysis can provide much more confident well test analysis.
In this paper, two field examples conducted in the fluvial gas reservoirs in the Gulf of Thailand have been interpreted in this way. At first, one of the tests has been analyzed using the conventional method by ignoring the DD. Then, the examination of DD LTR and the analysis of pressure BU using de-superposition method have been conducted to show where analysis was wrong in the first approach. Following the same procedures, the second test has been interpreted to further demonstrate the value of de-superposition method in analyzing test conducted in reservoirs with limited extent.
The Price Mechanism of Natural Gas and Its Relative Environment Condition
Authors: Ma Songping , Ma Xin 
Published: December 2007

Abstract
The natural gas market has its own characteristics that are distinguished from other common energy markets. It is presented that two kinds of establishing mechanism in natural gas prices are discussed and the development trend of the natural gas market in China is proposed, i.e. from regulation to deregulation. The related environment conditions on the market deregulation are divided into hard and soft ones. The hard environment conditions are as follows: establishing a competitive supply market structure; the transportation and distribution pipeline network for natural gas developed in a certain degree of scale, on which a competitive market is depended; continuous reorganization of gas production enterprises, establishing independent business for transportation and distribution services of natural gas, nondiscrimination services and rigorous government regulation; increasing the requirement level on natural gas through economic development, and rising gas supply capacity by domestic development and opening up in China’s natural gas industry. The soft environment condition is to build up more complete legal systems for the natural gas market. The time progressing of the gas market deregulation depended on the perfect processing of hard and soft environment conditions. It is maybe required about ten years in China.