bluuebunny/crossref_metadata_2025_split huggingface dataset:
Environmental Planning For New Energy Resource Development On Public Lands
Authors: Stone Reid T. , Johnson Harry R. 
Published: December 2007

This paper was prepared for the 47th Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in San, Antonio, Tex., Oct. 8–11, 1972 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 usually granted upon requested to the Editor of the appropriate journal, provided agreement to give proper credit is made. 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
Spurred by an ever-increasing demand for clean energy and dwindling supplies, interest has been renewed in the energy resources found on public lands. Before these resources can be developed, potential environmental effects must be weighed against the benefits to be derived from their use. A national concern for environmental quality has been translated into policy by the National Environmental Act of 1969.
Complying with the requirements of the Act for new energy resources development on public lands is a complex undertaking requiring public lands is a complex undertaking requiring (1) clearly defined program objectives, (2) an organization which can integrate public policy with diverse scientific disciplines, and (3) flexibility to adjust planning as various sections of the Act are clarified by Court decisions. This discussion explores the interrelationship between these factors using, as an example, the planning and organization created specifically to develop the Department of the Interior's Proposed Prototype Oil Shale Leasing Program.

Introduction
In September, 1972, the Department of the Interior filed with the Council on Environmental Quality one of the most complex draft environmental statements ever prepared. Some 1,200 pages long, it was prepared. Some 1,200 pages long, it was nearly three years in preparation by over 200 professionals of widely diverse backgrounds.
The statement details a program designed to stimulate commercial oil shale development and describes the potential environmental consequences of that development however, the program itself has greater significance beyond the specific environmental concerns related to oil shale development.
The Use Of Dispersants In Cement Slurries To Improve Placement Techniques
Authors: Boughton L.D. , Pavlich J.P. , Wahl W.W. 
Published: December 2007

Publication Rights Reserved
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 considered for publication in one of the two SPE magazines with the paper.

Abstract
Field results indicate that displacing cement in turbulent flow during the primary cementing operation has materially reduced remedial cementing. Lower displacement rates with subsequently reduced frictional pressures have been achieved by using dispersants or thinners in the cement slurry. Failures caused by lost circulation and formation breakdown during primary cementing, sometimes encountered when high displacement rates are necessary for turbulent flow, have been substantially reduced.
The paper presents laboratory analyses of the effects of some dispersants on the rheological properties of cement slurries. These dispersants include (1) lignosulfonates; (2) phosphates; (3) alkyl-aryl sulfonates; (4) synthetic polymers. Such dispersants probably function somewhat like viscosity-reducing agents in muds, although the viscosity resulting from the gel structure of the hydration products apparently is reduced also.
Results on actual jobs using slurries containing thinners investigated are discussed. These results indicate that laboratory rheological measurements on slurries can be used successfully to predict pump rates necessary to achieve turbulency. Cementing operations using both low- and high-velocity displacement rates are compared.

Introduction
High displacement rates required during casing cementing operations to improve mud displacement impose certain restrictions limiting use of this technique. Specifically, rheological properties of many commonly used cement systems preclude approaching turbulency in the annulus because the frictional pressures induced at the critical velocity approach or exceed the formation breakdown pressure.
A Simplified Approach To Pressure Prediction And Well Planning In The Rocky Mountain Area
Authors: Morton D.H. , Vesely D.P. 
Published: December 2007

This paper was prepared for the Rocky Mountain Regional Meeting of the Society of Petroleum Engineers of AIME, to be held in Casper, Wyo., May 15–16, 1973. 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 usually granted upon requested to the Editor of the appropriate journal, provided agreement to give proper credit is made. 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
Generalized methods for determining pore pressures and fracture gradients have been pressures and fracture gradients have been developed for the Rocky Mountain Area. These methods, utilizing sonic log data and wellsite measurements, are based entirely on empirical data.
A generalized fracture gradient chart and formation density overlay has been developed to assist in well planning and mud density control.

Introduction
Methods for determining pore pressures from logs have been used on the Gulf Coast, and accepted for several years. These methods have not been as useful in the Rocky Mountains and other "Hard Rock" areas; lithology changes are frequent and drilling may progress from Tertiary to PreCambrian rocks on a single well.
Known methods for determining fracture gradients generally yield much higher values than are normally observed in the Rockies. This may exist since much of this area is naturally fractured.
Shale density overlays developed on the Gulf Coast have little application at most Rocky Mountain drill sites. These overlays were developed for use, with good clean shales which are uncommon in the Rockies.
A method for predicting pressures from sonic logs 51 was developed by examining these logs and comparing them with mud records. High and low pressure zones can be defined from the sonic plot, and the maximum mud weight required can be estimated by using a simple method.
A fracture gradient chart has been prepared by using mud records and sonic log prepared by using mud records and sonic log data.
A formation density overlay developed from several observed wells is submitted as an alternate to those previously developed.

SONIC LOG METHOD
The conductivity and resistivity methods of pressure profiling provide erratic data in the Rockies, since good clean shales are hard to find. Sonic logs will provide excellent data that are affected little by lithology (Fig. 1) if the values are averaged. Either the one- or two-inch per 100-foot scale will facilitate data averaging.
Adsorption and Desorption of Corrosion Inhibitors in Anaerobic Brine
Authors: Blair Charles M. 
Published: December 2007

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 simple procedure is described for measuring instantaneous corrosion rates in brines under conditions simulating those encountered in the field. Rates of adsorption and desorption of n-dodecylamine inhibitor in mildly acidic, anaerobic brine saturated with carbon dioxide were inferred from corrosion rate measurements. Adsorption rates were also studied in brine saturated with hydrogen sulfide.
Both adsorption and desorption rates appear to be strongly dependent on concentration of the inhibitor during the adsorption period. Where adsorption equilibrium is approached slowly desorption rates in uninhibited brine appear to be very slow.
The results lead to suggested methods of improving field application of inhibitors.

Introduction
Almost twenty-five years ago it was discovered that the very severe corrosion problems occurring in petroleum production and refining equipment could be petroleum production and refining equipment could be mitigated by adding small concentrations of certain classes of cationic, surface-active compounds to the fluids involved. With suitable formulation and application these products have been found broadly effective in most typical oxygen-free systems containing hydrocarbons.
Large volumes of corrosive anaerobic brine are now handled in the oil fields, especially in the United States. Somewhat surprisingly, the use of the familiar cationic inhibitors in such brines has been generally disappointing. The degree of inhibition has been limited or costly concentrations have had to be used continuously.
A principal aim of the present work was to study the behavior of cationic inhibitors in mildly acidic brines with the aim of elucidating their behavior and, hopefully, finding means to improve their effectiveness. A special aim of this work was to devise a means of studying rates of adsorption and desorption of inhibitor films.
Earlier work with oil and brine fluids from oil wells indicated that organic inhibitors function in such systems by adsorbing on the exposed metal surfaces to form very thin — possibly monomolecular — films which present a barrier to corrosion reactions.
Rx for Gumbo Shale Drilling
Authors: Allred Robert B. , McCaleb Stanley B. 
Published: December 2007

Abstract
Exploration strategies have caused large investments in the search for offshore production. Many of these areas are characterized by poorly consolidated sediments and associated problems of gumbo shales. These problems not only slow down problems of gumbo shales. These problems not only slow down drilling procedures, but in some cases may cause the loss of the hole. These offshore areas have high hydrocarbon potential and high drilling costs. Control of gumbo shales during drilling has become the number one problem in these areas.
Many papers have been written on gumbo shale drilling but usually the control method is based upon a particular remedy not necessarily applicable to all cases. This paper explores the nature of gumbo shales and presents a survey of the many remedies that have been recommended. Solutions to the effective drilling of gumbo shales are suggested based upon the nature of the shale.
Drilling fluid design is the cure for problems caused by gumbo shale. Five remedies for controlling gumbo problems have been used:coating the shale surface,inhibiting the shale,removing water from the shale osmotically,controlling shale influx by increasing the hydrostatic head, andremoving shale cuttings from mud.
The drilling fluid components used for each of the five control measures are evaluated in terms of effectiveness in the different types of gumbo shale. Prescriptions for drilling fluid control are suggested utilizing the five methods of control. Drilling rates and solids removal equipment are also discussed as they contribute to the gumbo shale control problem.
There are some very effective remedies for gumbo shale problems but the proper treatment must be used for a specific kind problems but the proper treatment must be used for a specific kind or type of gumbo shale problem. A new Sun invention will be disclosed as a gumbo control device.

Introduction
Gumbo shales are composed of a range of materials which either have a very high content of silt-sized and/or clay-sized materials or a very high content of minerals of the montmorillonite type. Both become exceedingly sticky and tenacious when water contents are high. The great plasticity which results causes the gumbo to stick to surfaces and when mechanically mixed or sheared builds up large plastic masses.
Field Preparation of Polymer Solutions Used to Improve Oil Recovery
Authors: Schurz George 
Published: December 2007

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
Polymer solutions used to increase oil recovery by waterflood are prepared with automated equipment which dissolves dry polymer powder in flood brine. Proper equipment design, powder in flood brine. Proper equipment design, compatible brine and correct polymer selection are essential to providing a polymer solution which exhibits good mobility control at lowest cost and which retains mobility control throughout the life of the flood. Brine requirements, equipment arrangements and additives for a variety of field conditions are discussed.

Introduction
High molecular weight polymers are increasingly used to improve sweep efficiency in waterfloods. Improved sweep is obtained because the polymers reduce the mobility of the water polymers reduce the mobility of the water Polymer is used during a substantial part of the Polymer is used during a substantial part of the flood life, a period of several years, so that efficient, economical means of preparing the polymer solutions are required. polymer solutions are required. Preparation of the polymer solution require the blending of dry polymer powder with brine to form a slurry, this slurry is given sufficient dissolving time and finally the solution is injected into the formation. This paper will discuss the properties of the polymers used, required properties of the brine, mechanical equipment needed and the methods of solution quality control used.
POLYMER PROPERTIES POLYMER PROPERTIES Prior to the start of the field operation, the proper polymer is selected on the basis of laboratory studies using cores and fluids from the field in question. The mobility of the crude oil, of the brine used, and of the polymer solutions at various strengths is measured in the field cores. From these measurements, a flood play is developed for the most profitable operation. This plan specifies the amount and use rate of polymer and the laboratory measurements define the properties of the solution which must be handled in the plant.
Specifically the properties to be discussed in this paper refer to PUSHER chemicals. These are a family of partially hydrolyzed polyacrylamides especially manufactured for waterflood use. polyacrylamides especially manufactured for waterflood use. As furnished, PUSHER chemical is a finely ground, moderately hygroscopic powder supplied in 50 pound sacks, 250 pound drums or as bulk material pound sacks, 250 pound drums or as bulk material in hopper cars or trucks. Bulk density of PUSHER chemical is 42 pounds per cubic-foot. PUSHER chemical is 42 pounds per cubic-foot.
A New And Fast Method For Solving Large Numbers Of Reservoir Simulation Equations
Authors: Routt Kenneth R. , Crawford Paul B. 
Published: December 2007

1973 Third Symposium on Numerical Simulation of Reservoir Performance, Houston, Texas January 11–12, 1973. Performance, Houston, Texas January 11–12, 1973

Abstract
Computer modeling of petroleum reservoirs leads one to the problem of solving large numbers of simultaneous fluid flow equations. The purpose of this paper is to propose a new method for solving these equations and present comparisons between our method and the strongly implicit procedure (SIP) proposed by Stone and others. We have compared the new technique with SIP for a number of two-dimensional, steady state problems in both homogeneous and strongly heterogeneous reservoirs, with reservoir sizes ranging from 100 to 800 blocks. For some heterogeneous cases the ratios of transmission coefficients varied by a ratio of one million to one for testing. Compared to SIP, our method requires less computer storage space, compiles faster, executes up to 2.96 times faster, has no iteration parameter, is easier to program, requires about two-thirds an many cards, and gives excellent agreement in regard to material balance and final values of Pi,j. The method has been applied to problems with from 2 to 16 wells positioned in the reservoir corners, immediately adjacent, in line, and in random positions. Well magnitudes have been allowed to range up to a ratio positions. Well magnitudes have been allowed to range up to a ratio of 10,000 to 1.0 in the same problem. For every problem thus far attempted, the method has converged to the same answers as SIP in less computer time. Based upon our experience with this new method, we feel that the new method is substantially superior to SIP.
A Generalized Model For Predicting The Performance Of Gas Reservoirs Subject To Water Drive
Authors: Katz Donald L. , Tek M. Rasin , Jones Stanley C. 
Published: December 2007

Publication Rights Reserved
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 considered for publication in one of the two SPE magazines with the paper.

Abstract
A calculation procedure for predicting the performance of water-drive gas reservoirs without the usual assumptions of simplified geometry and homogeneity is presented. A characteristic pressure drop curve for a constant rate of water influx is calculated from field-performance data. Its extrapolation allows prediction of future water movement and pressure behavior when a projected production or pressure schedule is given.
The procedure has been extended to handle "moving boundary" problems resulting from the growth of the gas bubble in early stages of aquifer storage.
Two field case histories are presented where predicted performance is compared with direct field data.

Introduction
Gas reservoirs adjacent to water bearing formations are subject to water movement resulting from fluctuations in the gas bubble pressure. The rate of this water movement has been an area of interest to oil and gas production and storage industries for some time. The recent advent of aquifer storage, where the pore volume necessary for the storage of gas is created through the expulsion of water from its native formation by pressurization above discovery level is perhaps the most prominent example where the information on the extent and the nature of water movement is desired.
Solution of the diffusivity equation governing the movement of water in aquifers has been given in the literature for various geometries. These solutions are all based on some simplifying assumptions such as: uniform formation properties, gas bubble of constant volume, etc.
Numerical Simulation of the Zarzaitine Devonian F4 Reservoir, Algeria
Authors: Dorsey J.B. , Jones L.D. , Bencheikh A. 
Published: December 2007

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
The principal producing reservoir of Algeria's second largest oil field, Zarzaitine, has been studied using a three-dimensional reservoir simulator. When the study was conducted, the reservoir had been producing for over 10 years, the last 5 of which had been with peripheral water injection. The primary objective of the study was to determine how to maximize current production without sacrificing a significant quantity of ultimate recovery. To accomplish this objective required, first, attaining a reasonable match of past performance and then investigating future field operational techniques. A five-layer, three-dimensional, three-phase model was used to accomplish this objective.
A one-dimensional model was used extensively to first evaluate overall reservoir volumetrics, then nine 3-D runs through various periods of performance history were required to obtain an acceptable match of gas- and water-oil ratios and reported bottomhole pressures. To develop the match it was pressures. To develop the match it was necessary to adopt a multiple kg/ko correlation and, since bubble-point pressure varied with depth, it was necessary to account for depthwise changes in fluid properties.
Predictions of future reservoir performance under three plans of operation were performance under three plans of operation were studied with the model. An elaborate prediction routine which provided for the effects prediction routine which provided for the effects of tubing size and gathering-system pressure on productivity and injectivity was used in the study. In the course of these predictions, additional drilling, workover of predictions, additional drilling, workover of existing wells, cycling of the reservoir's gas cap, and various water-injection programs were considered in arriving at a recommended optimum plan of operation.
It was concluded that the 1-D and 3-D model combination provided a practical and accurate means of evaluating the Zarzaitine F4 reservoir.

Introduction
The Zarzaitine field is located in the Sahara Desert of southeast Algeria and is one of that country's major fields (Figure 1). Discovered in 1957, it has a productive area of approximately 35 square miles and produces from several horizons. The major reservoir is a series of Devonian sandstone members designated as the F4 which initially contained about 2 billion stock tank barrels in place.