bluuebunny/crossref_metadata_2025_split huggingface dataset:
An Integrated Digital Well Logging System
Authors: Peressini R. J. , Howells A. P. S. , Fertl Walter H. 
Published: December 2007

ABSTRACT
Basics of the SLAM Digital Combination Logging System are discussed including an overview which describes each of its major components; the computer-based surface data acquisition system, wellsite analysis software package, and the individual and combination measurement systems used with SLAM.
Combination logging runs that are possible with the SLAM system are presented to illustrate their application in a number of different geologic and borehole conditions. The advantages to performing combination logging runs are also discussed.
Log presentations available are illustrated to demonstrate methods for diplaying combination log data in usable formats.
Diagnostic programs and troubleshooting aids arc reviewed to demonstrate their ability to help predict when equipment is becoming marginal, and to minimize lost time due to equipment failure.
Standard methods for performing instrument calibrations are described, including techniques to perform master calibrations at the shop or wellsite, as well as before and after wellsite checks performed with instruments suspended over the borehole, or on the catwalk.
Risk, Stopping Rules, and the Economic Viability of Exploratory Drilling
Authors: Rankin Mark D. 
Published: December 2007

ABSTRACT
The thesis put forth in this paper involves three refinements to the practice of using probability weighted outcomes, or "expected values", as a means of determining the economic viability of an exploration prospect. The first involves the introduction of Polya's distribution in the assessment of conditional probability. In addition, the effect of stopping rules as constraints to the ultimate extent of exploratory drilling is studied. Finally, implications relating to the effects of changes in economic and geologic variables on the levels of exploratory drilling are examined.
Production Scheme for Deep Water Hydrate Deposits
Authors: Rose Walter , Pfannkuch H. O. 
Published: December 2007

ABSTRACT
There is substantial evidence that enormous natural gas hydrate deposits are entrapped in the bottom sediments underlying many of the deep waters that cover the earth, as well as in subsurface permafrost sediments of the polar regions. This paper addresses the important but largely ignored question of how to recover natural gas from the deep water bottom occurrences. The first problem is to gain access to the resource, the second to promote decomposition of the hydrate, and the third is to collect and bring the exsolved gas to the surface. A scheme assumed to be technically feasible involves the use of closely-spaced flexible hoses imbedded to protrude through the underside of the hydrate layer through which warm water can be circulated downwards and recovered gas brought upwards from and to surface floating platforms equipped with pumps, compressors, conversion facilities, storage vessels and pipeline manifolds.
The Austin Chalk—Drilling and Completion Techniques—Marcelina Creek Field Study
Authors: Betz Cynthia A. 
Published: December 2007

Abstract
Exxon Company, U.S.A. has spent considerable time and effort learning how to minimize formation damage in the lost returns prone and clay sensitive Austin Chalk formation. To date, Exxon has successfully drilled 24 Austin Chalk wells in the Marcelina Creek Field in Wilson County, Texas, utilizing a variety of drilling and completion techniques in an effort to determine the optimum method of drilling and completing Austin Chalk wells. This paper describes these different techniques and reviews actual results. Although Exxon has not concluded which drilling and completion technique yields optimum Austin Chalk wells in this field, this paper attempts to develop a correlation between well productivity and the type of drilling and completion technique used.
The Accuracy of Pulsed Neutron Capture Logs for Residual Oil Saturation
Authors: Schenewerk Philip A. , Knapp Roy M. , Fertl Walter H. 
Published: December 2007

ABSTRACT
Pulsed neutron capture (PNC) logs have been used to determine residual oil saturations for many years. A previous study found that at low values of residual oil saturation (ROS) conventional PNC logging techniques did not have the accuracy necessary for enhanced oil recovery decision making requirements. Special log-inject-log techniques were developed in order to reduce the uncertainty in values of ROS measured with PNC logs.
A study of the uncertainty associated with ROS values determined with PNC logs was made using Monte Carlo simulation techniques. Field data was obtained from tests reported in the literature. Using a more realistic confidence interval of 95%, the expected accurace of the ROS values was found to decrease by at least a factor of two in all tests. Additional uncertainty introduced by the log-inject-log process was not modeled.
Development of Cotton Valley Gas in Carthage Field—Price Was the Key
Authors: Lyons Frank E. , Asseff George 
Published: December 2007

ABSTRACT
Development of the Cotton Valley formation in East Texas has been stimulated by the economics of higher gas prices. The combined actions of the industry, Congress, the Federal Energy Regulatory Commission (FERC) and the Texas Railroad Commission (RRC) have added to the market gas reserves that were discovered in 1937, but were not economical to produce until the 1970's.
The Cotton Valley formation in Carthage Field, Panola County, Texas, (Figure No. 1) was first penetrated in 1937, and cores from that well indicated the presence of gas. Drill stem tests in 1944 confirmed the presence of gas in these deep, low permeability sands. The gas price then was $0.03 per MCF.
The first gas production was recorded in 1968, from one well, and by 1975, seven wells were producing. Gas prices had now increased to $0.62 per MCF. When the price of gas reached $2.49 per MCF in 1979, development increased rapidly with 117 new wells being drilled and completed that year, 86 wells in 1980 and 53 wells in 1981.
The drilling of these wells was a result of higher gas prices under the Natural Gas Policy Act of 1978 (NGPA), the "tight" gas classification by FERC on October 24, 1980, and Railroad Commission approval of 320-acre spacing on February 9, 1981, to permit additional drainage wells on the 640-acre units.
The price of gas is now over $6.00 per MCF, and more than 400 wells are producing from the Cotton Valley as development continues.
Ten Years of Handling CO2 for SACROC Unit
Authors: Gill T. E. 
Published: December 2007

ABSTRACT
SACROC Unit initiated CO2 injection in 1972 for oil assisted recovery. Ten years of handling CO2 through the compression, pipeline, injection, and removal facilities has confirmed their original designs and has caused some changes for improved operations. The reader should gain an awareness of the complexities involved in handling CO2 and a perspective for better operating considerations in handling CO2 in the oilfield.
Planning and Development of the Northeast Purdy Springer CO2 Miscible Project
Authors: Brinlee Larry D. , Brandt James A. 
Published: December 2007

ABSTRACT
A carbon dioxide miscible injection project is planned for the Northeast Purdy Springer reservoir. Injection on a WAG basis will begin in mid-1982. A description and overview of the events and activities leading up to the initiation of CO2 injection is described. Three years of planning and evaluation of the project began in 1977 and was followed by two years of field construction development. Incremental oil recovery is expected to be 16.8 million STB.
Installation of the Fulmar SALM and Storage Tanker
Authors: Gunderson R. H. , Coornbe J. G. B. , Lunde P. A. , Etheridge C. O. 
Published: December 2007

ABSTRACT
The Fulmar Single Anchor Leg Mooring (SALM) permanently moors a converted tanker serving as a Floating Storage Unit (FSU) in the North Sea at Shell/Esso's Fulmar Field. The Fulmar storage and offloading system is the first such system installed in a rough weather area.
The installation of the SALM was unique, not by choice, but because of the requirements imposed by the nature of the system and by the environmental effects on the structure during installation. The SALM is comprised of very large, heavy structural components joined by mechanical articulations and connections. The size and weight necessitated that the connection of the FSU to the buoy be made offshore. The installation of the structure was weather sensitive, requiring the design of numerous "hold points" into the procedure; for instance, the SALM buoy acted temporarily as a gravity structure, being transformed finally into a pile founded structure.
The loadout and installation strained the capacity of both dockside and floating equipment and produced several new world weight records. Novel applications of conventional equipment were used for loadout and transport of the components, for rigging used to make the major offshore lifts and connection between moving assemblies and for the rapid slurry installation of the permanent ballast.
This paper describes the installation procedures along with the corresponding field experience. Data on rigging, lift weights, seastate limitations and schedule are presented for use by those who may be faced with a similar opportunity.
Interpretation of Postfracture Temperature Surveys
Authors: Wages Paul E. 
Published: December 2007

ABSTRACT
This paper discusses the interpretation of temperature surveys for evaluating fracture treatments for gas wells in Southwestern Wyoming. In these wells, the treated intervals recorded higher temperatures than would normally be expected, making the interpretation of the survey difficult. The characteristics of this anomaly were investigated by running multiple post-fracture temperature surveys and a gamma ray log for locating radioactive proppant in one well.
Partially Hydrolyzed Polyacrylamides with Superior Flooding and Injection Properties
Authors: Argabright Perry A. , Rhudy John Stanley , Phillips Brian L. 
Published: December 2007

ABSTRACT
Polymers have found widespread use for oil field applications. They play an especially important role in secondary and tertiary oil recovery processes as mobility control agents.1, 2 For a variety of reasons, not the least of which is cost effectiveness, synthetic polymers are favored over their "natural" counterparts - the polysaccharides. Of the multitude of synthetic polymers, partially hydrolyzed polyacrylamide (PHPA) is the most widely used in a spectrum of enhanced oil recovery processes.
PHPA reduces the mobility of displacement water in porous media (reservoir rock) by a combination of increasing its viscosity and reducing the permeability to water in accordance with the equation
For permeability reduction, a manifestation of polymer retention, to be a useful factor, its effect must be propagated uniformly throughout the reservoir. Unfortunately, the available PHPAs of commerce share a common shortcoming - face plugging. That is, permeability reduction is greater around the injector than at more remote distances in the reservoir. Face plugging dramatically reduces injectivity and consequently prolongs project life. In view of this property of the commercial products, a study was undertaken at our laboratory to develop a high performance PHPA that does not exhibit preferential permeability reduction in the near-wellbore region.
Pressure Transient Analysis of Wells in Very Long Narrow Reservoirs
Authors: Nutakki Ramagopal , Mattar Louis 
Published: December 2007

ABSTRACT
In this paper, the radial and linear flow regimes in long, narrow channels were studied. The extent and duration of each regime was noted for a number of different dimensionless channel widths. Both "semilog" and "square root time" plots were made of the pressure transient behavior at the wellbore. These plots, as expected, showed radial flow (semilog straight line) at the beginning and linear flow (square root straight line) at later times. An abrupt change from radial to linear flow does not occur, rather there is a region where the pressure transient behavior closely approximates radial and linear flow at the same time.
An equation was derived for calculating the channel width, using the time where the semilog straight line ends. The linear flow regime in long, narrow channels can be precisely analyzed using existing linear flow equations, with the incorporation of a "pseudo-skin" factor, which accounts for the additional pressure drop due to the decreasing crosssectional area for flow as flowlines converge at the wellbore. Because of this additional "pseudo-skin" factor, log-log plots of the pressure transient behavior of long, narrow channels do not yield lines of slope one half (until time becomes very large), and hence these plots, which are often used to detect linear flow, should not be used.
The practical implications of this study are discussed as they pertain to production and drillstem tests. It appears that the end of the semilog straight line and the beginning of linear flow can be detected during the time that a drillstem test is conducted.
The Natural Gas Policy Act: Past And Future
Authors: Cooper Benjamin S. 
Published: December 2007

Cooper, Benjamin S., Professional Staff Member Committee on Energy and Natural Resources Professional Staff Member Committee on Energy and Natural Resources U. S. Senate

Introduction
Over the past year, a healthy cottage industry has come into existence for the purpose of analyzing the prospects for enactment by the 98th Congress of significant prospects for enactment by the 98th Congress of significant amendments to the existing body of law affecting the natural gas industry. No legislation of this sort was considered on the floor of either House during the 97th Congress. The Administration of President Ronald Reagan accorded a higher priority to other matters, and the members of Congress priority to other matters, and the members of Congress responsible for natural gas policy did not consider the natural gas situation in 1981–1982 to be in sufficient disorder to require them force the issue on their own.
Sand Fracturing With Liquid Carbon Dioxide
Authors: Lillies Allen T. , King Steven R. 
Published: December 2007

ABSTRACT
The quest for cleaner fracturing fluids has led to the development of sand fracturing using liquid carbon dioxide (CO2) as the proppant carrier fluid. CO2 is handled at the surface as a liquid at approximately 200 psi and −30°F. Special blending equipment has been developed to inject proppant directly into the liquid CO2 at these surface conditions. The sand laden liquid CO2 is then pumped by conventional equipment. At stabilized reservoir temperature and pressure, the liquid CO2 vaporizes in a gas well or vaporizes and is partially dissolved in the reservoir oil in an oil well. The greatest potential of liquid CO2 fracturing is the elimination of most of the formation damage normally associated with fracturing fluids and the very rapid clean up and evaluation of the well following the stimulation.
Analysis Of Fracture Treatment Pressure Fall-Off Data
Authors: Newendorp Paul D. , Menzie Donald E. 
Published: December 2007

Abstract
This paper discusses the results of a study that was made to determine if surface pressure fall-off data existing after a fracture treatment could be correlated to reservoir flow capacity. The theoretical aspects of pressure dissipation away from the fracture during and after the treatment are considered, and a method is proposed to calculate reservoir flow capacity from these data. This method is an adaptation of the procedure used for estimating reservoir injective capacity in water infection wells. Field data from five fracture treatments are presented, and calculated flow capacities are compared with existing knowledge of reservoir flow capacity in the particular fields. It was concluded that analysis of fracture treatment pressure fall-off data may be useful in determining reservoir flow capacity. Analysis of these data may also be helpful in evaluating the results of fracture treatments.
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A Review of Sajaa Field Development, Sharjah, UAE
Authors: Blinten J. S. , Wahid I. A. 
Published: December 2007

ABSTRACT
Sajaa Field was discovered in December, 1980 on Amoco's 100% working interest concession in Sharjah, United Arab Emirates. The Sajaa Field is significant as it is both Sharjah's largest producing field and Sharjah's first gas-condensate development. This paper will review the geologic and reservoir data gathered to date and outline the field's Phase One development. The thrusted, lower Cretaceous trend on which the Sajaa Field lies has become an important play as shown by the recent Margham Field discovery in Dubai and the substantial exploration activity in the area. The development cost per barrel for gas-condensate reservoirs is high compared to onshore Middle East oil projects and a firm development plan is required. In order for Amoco to have completed it's Sajaa Phase One development in 18 months, extensive planning and close cooperation with the government of Sharjah were necessary.
The Sajaa Field is a retrograde gas-condensate reservoir found in the thrusted Lower Cretaceous Thamama limestone of east central Sharjah. It is part of the frontal thrust sheet of the Oman Mountains and was moved to its current relative structural position in Late Cretaceous time. The Thamama overlies a massive section of carbonates thought to be Jurassic to Permian in age. The upper Jurassic carbonates have been found containing both rich gas and water depending on its structural position and are considered to be part of the Sajaa Reservoir. Deeper in the Jurassic, a dry gas has been encountered. Development has been centered around the upper Jurassic and Thamama, since the Lower Jurassic dry gas is sour (5% H2S, 14% CO2, 80% CH4) with a high-water to gas ratio (150 BBL/MMSCF, 844 M3 /MMSCM).
The Thamama in Sajaa Field is a massive section of open marine shelf limestones. The average thickness of the Thamama is 2764 ft. (842 m) and is fairly uniform across the field. The limestone section is described as consisting mostly of tight wackestone to packstone with occasional thin shale beds; however, within the limestone substantial pay is found in correlatable intervals in the higher structural positions of the field. Net Thamama pay varies from 90 to 760 feet (27 to 231 m). The porosity found in the Thamama is predominately intercrystalline and a large fracture system is suspected. Several hypotheses of the diagentic history of the Thamama have been proposed, but a completely satisfactory explanation has yet to be determined. The results of the diagentic study will be of major interest for the field's future development.
Cyclic Steam Injection In The Quiriquire Field Of Venezuela
Authors: Payne R.W. , Zambrano Gabaniel 
Published: December 2007

Publication Rights Reserved

Abstract
For the past four years the Creole Petroleum Corporation has been actively testing the use of steam as a production stimulant in the Quiriquire Field of Eastern Venezuela. The method being tested is the so-called "huff-and-puff" method where steam is injected into the formation and the well later returned to production. This method of stimulation has been used for eight wells in the Quiriquire field. In the most successful case a well produced 60 percent more oil over a 490-day period following start of steam injection than would have been obtained had the well been produced in its normal fashion. Steam was injected for 44 days to achieve this increase in production rate. A second cycle of stimulated production was not as favorable as the first for this well.
The quantity of heat injected and the initial selection of wells for steam injection is important. in one case, a well did not produce as much oil following steaming as expected under cold conditions. Creole is planning a more extensive program of well stimulation in the Quiriquire field for application of this process.

Introduction
For the past four years, the Creole Petroleum Corporation has been actively testing the use of steam as a production stimulant in the Quiriquire Field.
The production decline has caused an aggressive program of well stimulation to be initiated. The production has declined from a maximum of 80,000 BOPD in 1951 to a minimum of 33,000 BOPD. All conventional methods of individual well stimulation have been used as well as some methods that have been developed locally. In addition to these methods, it was decided in 1959 to try heat.
The Creole Petroleum Corporation initiated the injection of steam in the Quiriquire field to observe the effect on individual well production rates.
The Quiriquire reservoir does not possess all the optimum qualities for any method of thermal stimulation. The formation is heterogeneous, the oil originally in place was considerably below 1000 barrels per acre-ft., the sands are lenticular and the producing section contains a high percentage of interlaminated shales. The one factor in favor of thermal methods is the relatively high viscosity of the oil.
Distribution And Production Of Oil And Water In Tensleep-Minnelusa Reservoirs
Authors: Aufricht W.R. 
Published: December 2007

Publication Rights Reserved
This paper was prepared for the Rocky Mountain Regional Meeting to be held in Montana, June 10–11, 1965, and is considered the property of the Society of Petroleum Engineers. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made.
Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Abstract
A discussion of the oil and water contents and the producing water cut behavior of Tensleep-Minnelusa reservoirs is given. Interpretations of rock and fluid data, logs and well performance are illustrated.
Interpretation of the basic data indicates the presence in some reservoirs of oil-water transition zones several hundred feet in thickness. The characteristics of these zones are such that they may have interstitial water saturations as low as 20 per cent of pore space and still produce with extremely high water cuts. These characteristics cause evaluation of productivity of both logs and core analyses to be extremely difficult - particularly in exploration wells where the basic data on the reservoir fluids may not be available.
Oil in place values approaching 1000 barrels per acre foot are indicated in zones which may produce at water cuts in excess of 95 per cent. Such productive intervals warrant investigation as secondary recovery prospects using thermal or other advanced techniques.

Introduction
The Pennsylvanian Age sands, particularly the Tensleep-Minnelusa members, are prolific oil producers in many areas of Wyoming and Montana. Much of this production is low gravity oil and is frequently accompanied by high water cuts. Evaluation of such reservoirs, particularly in exploration drilling has proved to be extremely difficult. Intervals which appear from core analyses and log information to be oil productive have frequently been found to produce at uneconomically high water cuts - either upon initial completion or shortly thereafter. A study of certain measured rock and fluid property information and logs has been made in an attempt to explain this performance and to arrive at better means of evaluation of the productive characteristics of this formation.