bluuebunny/crossref_metadata_2025_split huggingface dataset:
Taking Low Gels to New Highs
Authors: Herring Randy B. , Diede Loren L. 
Published: December 2007

Abstract
This paper documents the evolution of a 2 year hydraulic fracturing program in the Conoco operated San Juan 28-7 Unit located in the San Juan Basin of northwestern New Mexico. This fracturing program utilizes a crosslinked 15 lb. Gel system to pump stimulation treatments at bottom hole temperatures up to 1800 F. Historically, slick water treatments and linear gels have been used to hydraulically fracture the Dakota sandstone in this area. These low viscosity fluids are utilized in an attempt to limit fracture growth into the underlying water bearing zones. Crosslinked gels and nitrogen foam fracs have also been used by some operators in the immediate area on a limited basis. Large, relatively expensive fracs are rare due to economic constraints based on the average well's modest production rate.
These low viscosity fluids require large volumes of water at high rates with low proppant concentrations. Problems associated with these low viscosity treatments include premature screenouts and limited availability of large quantities of, relatively expensive, quality water. The design of the cross-linked low gel load fluid grew out of a need for an economical treatment that could adequately prop the low pressure, low permeability Dakota Sandstone while minimizing gel damage.
To date, 65 frac treatments have been successfully completed using the crosslinked 15 lb gelled fluid. Success in this instance is measured by placing 100% or greater of the designed job at or below projected costs. The success of the Dakota program led to the use of this treatment in the shallower Mesaverde formation.
In the past two years, completion and recompletion costs in the Mesaverde and Dakota formations have been reduced 12% through decreased water volumes and reduced post frac clean up time requirements. In addition early production results indicate that wells treated with this crosslinked low gel system exceed or are comparable to wells treated with other, higher cost treatments.
P. 267
Results of Using a Relative-Permeability Modifier with a Fracture-Stimulation Treatment
Authors: Dalrymple E.D. , Creel P. , Rohwer C. , Crabb H. 
Published: December 2007

Abstract
When stimulation treatments are performed on oil- or gas- producing zones with high-permeability streaks that produce water or that feature water influx, these water-producing zones are often unintentionally stimulated along with the productive zones. In such instances, water production from the formation may be excessive, requiring expensive separation and water disposal. After a stimulation treatment has been performed, a water-control operation may be performed to reduce water production, but the remedial treatments are expensive and are not always successful. Furthermore, the process can result in a plugged formation and lost production.
This paper discusses field results from the combination of a relative-permeability modification (RPM) agent with a fracture- stimulation treatment. The design objective was for the modification agent to be leaked off into portions of the created fracture during the stimulation treatment, thereby alleviating water- production problems. The treatments were performed in April 1997 in the Brushy Canyon formation in southeast New Mexico, a Delaware sand reservoir. Previous fracture treatments in this interval had resulted in water cuts greater than 60%, and the continued production of these wells had been deemed uneconomical because of the presence of damaging scale and a subsequent decline in total fluid production. (The water cuts would remain at 60 to 70%, but the total volume of fluid would decline.)
As a result of the combination of the relative-permeability modifier with the fracture-stimulation treatment, the wells averaged a 65% increase in oil production, a 122% rise in gas production, and a 60% decline in water flow compared to wells stimulated without the RPM agent.
P. 285
Completion and Stimulation Practices in the Prolific Cotton Valley Reef Trend of East Texas
Authors: Richardson Michael F. 
Published: December 2007

Abstract
Over the last several years there has been a highly competitive and active exploration effort focused on the discovery of gas reserves from the Upper Jurassic Cotton Valley Lime (Haynesville) interval in the East Texas Basin. The primary exploration objectives along this carbonate platform are overpressured sour gas Cotton Valley reefs. The frantic land, 3D seismic, and drilling activity have been fueled by some outstanding early results. Initial results drove expectations for the play to unrealistically high levels that included average per well reserves of 70+ Bcf, initial potentials above 25 MMcf/d, and a chance of success using 3D seismic of better than 65% 1-4. As the play has matured and industry's knowledge has increased, these lofty expectations have significantly fallen, but overall trend statistics remain attractive. Recently, in an effort to improve the economics of the play, large hydraulic fracture treatments have been routinely incorporated in the completion of these wells. However, the stimulations have been largely unsuccessful for several reasons. These include high treatment costs, high fracture gradients, the lack of a primary horizontal stress direction, a highly heterogeneous reservoir, poor barriers to fracture height growth, and poor initial estimates of key reservoir parameters. Proper reservoir characterization, depletion of reservoir pressure prior to stimulation, and application of horizontal drilling are offered as possible completion alternatives.
Integration of Discrete Feature Network Methods with Conventional Simulator Approaches
Authors: Dershowitz Bill , LaPointe Paul , Eiben Thorsten , Wei Lingli 
Published: December 2007

Abstract
The discrete feature network (DFN) approach offers many key advantages over conventional dual porosity (DP) approaches, particularly when issues of connectivity dominate recovery and reservoir stimulation in fractured and heterogeneous reservoirs. DP models have been developed for complex multiphase and thermal effects, and have been implemented for basin scale modeling. However, DP models address only the dual porosity nature of fractured reservoirs, generally simplifying connectivity and scale-dependent heterogeneity issues which are modeled efficiently and more accurately by the DFN approach.
This paper describes the development of techniques to integrate DFN and DP approaches. These techniques allow the analyst to maintain many of the advantages of the DP simulator approach without losing the realism of complex fracture system geometry and connectivity, as captured by DFN models.
The techniques described are currently used within a DOE funded research project for linking a DFN and a DP thermal simulation model for the Yates Field, Texas. The paper describes some of the geological and engineering aspects of the Yates Field and gives two examples how DP parameters for the thermal simulation can be derived using DFN modeling techniques.
P. 351
Core Analysis for Optimum Reservoir Exploitation
Authors: Hensel W.N. 
Published: December 2007

INTRODUCTION
Core data can play a vital role in development drilling programs and recovery planning operations. Well-conceived field coring programs and subsequent laboratory testing procedures can strengthen log interpretation criteria, aid in completion/stimulation operations, provide a sound basis for reserves estimates and reservoir modeling, and supply much needed guidance in secondary and tertiary recovery programs.
This paper presents the need for preplanning during the development phase of the reservoir so that necessary parameters are properly evaluated. Coring methods, coring fluids, preservation techniques, and basic laboratory testing procedures are discussed. Suggestions are given for selecting samples for special analysis test work.

THE FIELD CORING PROGRAM
The special core study actually begins during the development drilling program of the field. Failure on the part of all concerned to recognize this can severely encumber the proper planning of pressure maintenance, and secondary and tertiary recovery programs. After all of the wells have been drilled, it is too late to recognize the need for representative cores. A handful of sophisticated suites of logs are poor consolation to the reservoir engineer charged with designing the most efficient means for the recovery of millions of barrels of oil.
The development drilling program gets a lot of attention in its early stages. Drilling problems are encountered and ways are sought to lower the per-footage costs. Coring can only increase such costs. Logs provide a quick, clean way to identify producing intervals. Cores, although helpful, have a longer turnaround time and may cause delays in assigning perforations. The impetus for coring must come from those responsible for the long-range look at the reservoir. A logical choice is the reservoir engineering staff. Through their guidance, an orderly plan for coring operations may be followed, thus insuring that proper data will be available for future studies.
So, how may effective plans be made for the coring program to maximize the return on the data dollar invested? Some companies reportedly use rules of thumb based on the estimated oil in place. Certainly the worth of the reservoir should be a part of the consideration, but it is also important to look ahead and plan the coring to provide guidance in certain areas. What are these areas and how can cores and core data contribute?
The Energy Market Today - An Economic Appraisal
Authors: Perry Harry 
Published: December 2007

This paper was prepared for the 1974 Eastern Regional Meeting of the Society of Petroleum Engineers of AIME, to be held in Washington, D.C., Nov. 14–15, 1974. Permission to copy is restricted to an abstract of not more that 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publications elsewhere after publication in the paper is presented. Publications elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually grated 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 discussions may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Abstract
In the past two years, the energy economy of the U.S. and the rest of the world has been jolted by a series of events that have altered appreciably the historic nature of the energy market. The factors that have caused these major changes in energy markets and the prospects for their continuation in the future are examined. Future prices for energy and the sources of supply are discussed as are the prospects for reduced demand through price prospects for reduced demand through price elasticity, changes in lifestyle, increased conversion efficiencies and energy conservation.
The projections of future energy developments are made for two time frames—the next 10 years and the period beyond. This distinction is necessary because of the long lead times required to make significant changes in either supply or demand without direct government involvement or controls.
The nature of the many different areas in which federal involvement can affect the future of the energy industries and the various federal options and their different impacts are analyzed.

Introduction
In relatively few years nearly everything about the energy industries has changed so rapidly that the historic problems with which we wrestled in the past now no longer seem real. The great debates over whether coal prices would increase from 20 to 25 cents per million Btu or whether the regulated wellhead price of natural gas should be 18 or 20 cents per million Btu are as a dream that never really was. This sudden change in the energy situation was not entirely unanticipated, although some important events which occurred suddenly and without any warning greatly accelerated and aggravated a developing problem. As a result, the two hundred years of low-cost adequate supplies of domestic energy resources available in any form desired came to an abrupt end with the beginning of the decade of the 70s.
To understand what has happened and where we are today requires a separate review of each of the energy industries since no two of them have been influenced by exactly the same factors.
Economic Impact of LNG on Natural Gas Supplies Distribution
Authors: Pastuhov Alexis 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.
This paper was prepared for the 1974 Eastern Regional Meeting of the Society of Petroleum Engineers of AIME, to be held in Washington, D.C., Nov. 14–15, 1974. 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 paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is 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 SPE magazines.

Abstract
The annual estimated curtailment of firm requirements for natural gas for 1974–1975 is 1.8 Tcf. Even if all pending LNG projects were approved today pending LNG projects were approved today they would bring in only 1.2 to 1.45 Tcf. The economic impact of new LNG imports are expected to be important as the exporting countries value their resources on its BTU content and will index natural gas to crude oil. A typical transmission company importing LNG may see its average selling price increase by a factor of 1.6 or more.

Introduction
Has the pendulum swung the other way? This may be the situation today in the LNG business; only two years ago at LNG 3, Washington, D.C., a euphoria prevailed about the bright future of LNG imports to the United States. Today, however, the U.S.A. is at the crossroads of whether or not large scale imports of LNG will materialize. Several major LNG contracts are in the process of being renegotiated. They are El Paso II, Easco, Panhandle Eastern Trunkline, Distrigas (Ben Franklin) and Pacific Lighting (Indonesia). These contracts were scheduled to deliver LNG as early as the spring of 1975.

Background
This paper will deal exclusively with the import of LNG to the United States from an overall point of view and will not examine in detail the effect of the numerous peakload shaving plants now existing or being constructed in the U.S.A. processing pipeline gas and storing LNG in one or more large scale storage tanks.
In the opinion of the author, as long as pipeline gas will remain relatively inexpensive pipeline gas will remain relatively inexpensive in comparison to imported LNG, the public utilities as well as the transmission lines will continue to develop peakload shaving plant and storage facilities as a way of satisfying their winter load requirements. It is obvious that the effect of these facilities is to level the pipeline sendout between summer and winter time.
A New Approach to Preventing Lost Returns
Authors: Carlton L.A. , Chenevert Martin E. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Abstract
Lost returns are one of the oldest problems associated with rotary drilling. problems associated with rotary drilling. Millions of dollars are spent each year by the industry for mud materials and lost rig time because of this problem.
A new technique for preventing lost returns during normal drilling operations has been developed. The technique combines the use of a standpipe choke to minimize pressure required to "break circulation"; pressure required to "break circulation"; the use of a Pressure Integrity Test to determine formation fracture pressure; and a method of accurately calculating and monitoring annular pressure losses while circulating.
Data from a field test where annulus pressure losses were measured with downhole pressure losses were measured with downhole pressure gauges are presented. Predicted pressure gauges are presented. Predicted annular pressure losses, calculated from different mud property measurements are compared to the actual measured losses. Annular pressure losses car, be accurately predicted by calculating inside drill predicted by calculating inside drill string losses and subtracting these from total circulating pressure. The calculation procedure for determining annulus pressure losses is simple and can be made by personnel at the rig using actual field data.

Introduction
Most lost returns occur while circulating or attempting to break circulation. Lost returns may also occur because of high surge pressure created while running pipe and because of vuggy or fractured formations. Except for the case of vuggy or naturally fractured formations, when returns are lost, there is only one cause for the lost returns; THE PRESSURE IN WELL BORE EXCEEDS THE STRENGTH OF THE WELL BORE! On this basis it should be obvious that most lost returns can be prevented if:The strength of the wellbore is known andthe pressure imposed on the wellbore is controlled at a level below that required to fracture or break down the formation.
Several techniques have been developed recently which have proved to be very helpful in reducing the occurrence of lost returns. The stand pipe choke, the pressure integrity test and a new pressure integrity test and a new technique for determining annulus pressure losses and controlling these pressures at a level below fracture pressure will be discussed.
Future Natural Gas Supply Reactions to Higher Prices - Projections of the A.G.A. TERA Model
Authors: Hardy Edwin F. , Neill Charles P. 
Published: December 2007

Future Natural Gas Supply Reactions to Higher Prices - Projections of the Prices - Projections of the A.G.A. TERA Model
American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Abstract
The paper describes the total energy resource analysis (TERA) model developed by the American Gas Association. Emphasis is given to the submodel on natural gas supply. U.S. gas supply projections developed by TERA, using three quite different gas pricing policy scenarios, are reviewed for the time period 1975 to 1985.
Study results indicate that significant gas supply increases during the period 1980 to 1985 will require substantial near-term producer price increases and other policies favorable to price increases and other policies favorable to domestic energy development.

Introduction
In the spring of 1971, when the U.S. natural gas supply shortage was becoming increasingly apparent as the number one problem facing gas transmission and distribution utility companies, the American Gas Association (AGA) initiated design of the "total energy resource analysis model," or TERA model. As now developed, TERA is a computerized simulation model of energy supply, demand, and prices, with special emphasis on the gas industry. TERA incorporates data on all fuels and electric energy in different market sectors for each census region of the U.S., including factors that influence the energy industries-demographic, economic, technological, environmental, regulatory, legislative, and competitive.
TERA has been developed to assist the AGA staff and member companies in developing long range planning studies, policy positions on issues facing the gas industry, and responses to the many questions being asked about the future of this industry. TERA is helping to answer such questions as the following.What producer prices for natural gas will be required to reverse the 6-year reserves decline being experienced now, and when could this reversal occur?How much will natural gas demand be reduced as producer prices increase?What impact will supplemental gas supplies have on total supplies, demands, and consumer prices for gas?What effect will environmental regulations have on gas prices, demands, and supply schedules?What effect will various pricing and supply scenarios for competitive fuels have on the supply and demand for natural gas?
TERA is now answering these types of questions and showing how the answers vary under the influence of changing input variables.
Trends And Projections In Soviet Energy Output
Authors: Shimkin Demitri B. 
Published: December 2007

1961 SPE Annual Meeting, Dallas, October 8–11, 1961
Over the past four years, much authentic information on energy resources, technology, output and utilization in the Soviet Union has become available. The major sources have been technical Journals such as Ugol' (Coal), Neftvanove khoz Vavstvo (Petroleum Economics), and Torfvanava promvshlennost' (Peat Industry); and monographs published by the State Fuel-Technology Press (Gosgortekhizdat), the State Mining-Technology Press (Gosplanizdat), the State Electric-Power Press (Gosenergoizdat), the Coal-Technology Press (Ugletekhizdat), the State Planning Press (Gosplanizdat), and the Academies of Science of the Soviet Union and its Republics. Statistical handbooks published by the Central Statistical Administration, the Ministry or Foreign Trade and other official bodies have also proved valuable. In general, these materials are far more reliable and comprehensive than popular sources or casual Western observers. While ambiguities, gaps and errors do occur, and while differences from Western concepts and practices impose caution, the Soviet technical sources are largely competent, explicit and consistent. Properly used, the data are adequate to develop an effective understanding of Soviet techniques and accomplishments, problems and plans, in energy development and use (see also Shimkin, 1960; n.d.-a.; n.d.-b.)
In this discussion, I shall try to sketch the current energy-resource position of the Soviet Union; major trends and plans in energy output, by source and by region; and current and planned patterns of energy use. I shall also make selected comparisons with the United States, thereby highlighting distinctive features of Soviet practice. One I shall retain for consistency's sake.