bluuebunny/crossref_metadata_2025_split huggingface dataset:
Prediction of Flowing Bottomhole Pressures in Gas Wells
Authors: Takacs G. , Guffey C. G. 
Published: December 2007

Abstract
The measurement of flowing bottom-hole pressures in gas wells is a frequently incurred and costly operation in natural gas production. The calculation of this pressure from surface data is complex involving a trial and error solution of Bernoulli's differential equation. A number of methods have been used previously for this solution - usually requiring computer methods. A new procedure for calculating flowing bottom-hole pressures using only simple algebraic equations has been developed.
The new procedure uses factorial design analysis from statistical experimental theory to determine the parameters in an algebraic equation which best fit the "experimental" data for the bottom-hole pressures for a given field. However, instead of actual field data, bottom hole pressures are calculated with a computer using any of several methods (Aziz, Cullender-Smith, Gray, etc.). These calculated "experimental" values are used to determine an algebraic equation which best fits the data. The day-to-day use of the resulting algebraic equation is very simple and can be performed by field personnel using a hand-held calculator for any wellhead pressure for the particular field.
Actual flowing bottom-hole pressure measurements for three gas fields containing 55 wells were used to test the accuracy of the procedure developed. Corrections for condensate flow and sour gas components were required in the calculations. The calculated bottom-hole pressures agreed with measured ones with an average absolute accuracy of 1.9%.
Production Strategies for Tight Gas Sands: A Case Study of the Upper Cozzette Blanket Sand
Authors: Bezilla M. , Adewumi M. A. , Ertekin T. , Sung W. , Frohne K-H. 
Published: December 2007

Abstract
The importance of the role that natural gas from tight formations would play in achieving energy self-sufficiency for the United States cannot be over-emphasized. One reliable source estimates the natural gas reserves of the tight sands of the Western United States alone to be more than 5700 trillion cubic feet. However, the technology for recovering this resource remains elusive, primarily due to lack of adequate understanding of the physics of fluid flow dynamics within this type of porous media. The fluid flow in tight formations does not subscribe to that normally associated with conventional reservoirs. It is believed that tight formations frequently possess dual porosity, and the flow field in these formations may be governed by more than one mechanism. The model utilized in this study possesses proven predictive capabilities, an essential ingredient to production forecasting, and hence is used as a framework for the development of optimal production strategies for the Upper Cozzette blanket sand. The model has multi-well capabilities and has options for either vertically or horizontally fractured wells and horizontal boreholes. Simulation results from a variety of production schemes are presented. The results provide some insight into production strategies involving horizontal boreholes and hydraulic fractures.
The Underwater Power Package
Authors: Johnson F.C. Pat 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.
This paper was prepared for the 42nd Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in Houston, Tex., Oct. 1–4, 1967. 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
Many professional articles and technical papers have been written on the numerous power sources available for oceanographic work, yet none have been specifically oriented to the problems of underwater drilling and completion. This paper will investigate and report on the various types of independent power sources which may be used by the petroleum industry for an underwater operation.
There is little doubt that as the drilling platform moves into deeper water, a power package, independent of the surface rig, will become a necessity. Power to operate the blowout preventer is the initial step; power for the entire drilling operation is the final goal.
The ultimate answer is nuclear power, but a proven design is not available today. Battery power and the fuel cell are possibilities for intermediate power sources. The evolution through batteries and fuel cells to the nuclear power plant will provide an orderly development such that the underwater nuclear power package may be phased in with a thoroughly tested, operational plant as soon as it becomes available to industry.

Introduction
The oil industry has been drilling offshore for about 25 years. Initially, drilling was done with land based equipment adapted (often poorly) for usage underwater. In the last ten years, industry has developed more sophisticated equipment designed specifically to cope with the unique problems of drilling underwater.
One area obviously in need of greater improvement is the power supply to remote underwater tools. The blowout preventer stack and christmas tree require power sources independent of the drill string. These units are presently powered hydraulically from the surface. This method is cumbersome and inefficient.
Intriguing Aspects of the 52-Mile Titas-Joydebpur Gas Line Project in Bangladesh
Authors: Bakht D. 
Published: December 2007

Abstract
This paper is based on experiences of implementing the project with application of labour intensive appropriate technology amidst extremely adverse climatic & terrain conditions within a short time frame and yet achieving a strikingly low inch mile cost. Discussion of different aspects of economic technical & mathematical considerations resulted from a close look of its execution & operation is also included to suggest a priority for over coming the limitations in future projects of similar nature & of equivalent or higher magnitude.
WAG Process Promises Improved Recovery in Cycling Gas Condensate Reservoirs: Part 1—Prototype Reservoir Simulation Studies
Authors: Jones L. G. , Cullick A. S. , Cohen M. F. 
Published: December 2007

Abstract
An unconventional method to improve sweep efficiency in highly stratified or naturally fractured gas condensate reservoirs has been explored through simulation studies. The alternating water and gas injection process (WAG) has not been heretofore seriously considered in gas cycling projects for fear of losing ultimate production. For the base case study presented here, however, WAG is shown to improve sweep efficiency and ultimate recovery by 862 at one pore volume injection over that of dry gas injection alone into a prototype gas condensate reservoir containing a single, high permeability thief zone. The increase in sweep efficiency occurs primarily because the high viscosity water tends to block the thief zone, thus forcing following injection gas to invade the reservoir matrix. The principal factors governing the process are the contrast between thief zone and matrix permeabilities, the viscosities of injected gas and water, and the residual gas saturation to water. Varying the relative permeability curves and water/gas slug sizes and ratios had smaller effects on the results. Since only relatively small amounts of water are required to obtain large increases in recovery, expected detrimental effects from gas trapping and premature abandonment are limited. An additional economic benefit arises because the water occupies space which must otherwise be occupied by make-up gas.
Low Temperature Phase and Volumetric Behavior of Natural Gases
Authors: Gore T.L. , Davis P.C. , Kurata F. 
Published: December 2007

Published in Petroleum Transactions, AIME, Volume 195, 1952, pages 279–284.

Abstract
An experimental method and apparatus for the study of the low-temperature phase and volumetric behavior of volatile mixtures are described. The phase diagrams, including the critical points, and the volumetric behavior of two natural gases at temperatures from -40°F to -200°F and pressures to 1200 lb/sq in are given.

Introduction
Knowledge of the phase and volumetric behavior of light hydrocarbon mixtures at low temperatures is becoming of increasing importance as interest in low-temperature separation processes increases. Ethane and ethylene are already being removed from natural and refinery gases by low-temperature distillation, and removal of nitrogen from natural gases by this process has been proposed as a means of increasing the transmission capacity of existing pipe lines. While existing correlations of equilibrium vaporization constants may be used to predict the vapor-liquid equilibrium behavior of such mixtures at lower pressures, high-pressure phase computations often require knowledge of the critical behavior of the system involved. Although correlations have been developed for the prediction of the critical temperature and pressure of certain types of hydrocarbon systems, they are not applicable to very volatile systems such as nitrogen-bearing natural gases. This paper describes the initial stages of an investigation which had as its main purpose the study of the low-temperature phase and volumetric behavior of such mixtures. The experimental phase diagrams, critical points, and volumetric behavior of two natural gases are presented here.
The published low-temperature vapor-liquid equilibrium data for hydrocarbons and mixtures of hydrocarbons with nitrogen and helium are summarized in Table 1. Most of these data are for binary systems, and the data of Stutzman and Brown, at 100 lb/sq in. are the only data on a natural gas. The data of Bloomer and Parent on the methane-nitrogen system, which have been published since this study was completed, are a valuable addition to the knowledge in this field. Prior to the publication of these data the only critical data on systems having critical temperatures below the ice point were those of Ruhemann, on the methane-ethane system, and those of Eilerts, et al, on a gas-condensate system. These data alone were not sufficient to allow accurate estimation of the critical behavior of the very volatile systems of engineering interest.
Field Engineering Aspects of Formation Stress Testing
Authors: Shaw J. S. , Amick P. C. , Snow G. N. , Graham R. L. 
Published: December 2007

ABSTRACT
This paper presents the equipment requirements and field procedures needed for safely and efficiently conducting in-situ formation stress tests (stress tests). It is set apart from other papers which primarily present data and describe analysis procedures. This work briefly discusses when stress tests are practical and what can be learned. The majority of the work describes detailed equipment requirements and field procedures for openhole and cased-hole tests. Different considerations are also mentioned when working with nitrogen and water. Encountered and potential problems are discussed alerting the operator to equipment and events requiring careful attention. An example is provided outlining actual testing time and related costs along with the information obtained.
Predicting Horizontal Well Production Performance Using Type Curves
Authors: Aminian K. , Ameri S. 
Published: December 2007

ABSTRACT
Significant potential natural gas resources remain in low permeability marginal reservoirs of the Appalachian Basin. Horizontal well as an alternative to fractured vertical well, has a significant potential to enhance the recovery from the low permeability gas reservoirs. This paper addresses the potential contribution of horizontal wells to increasing the economic recovery from the low permeability gas reservoirs.
The selection of horizontal well over vertical well in low permeability gas reservoirs must be based on engineering and economic feasibility evaluations. The accurate prediction of production rates is one of the most important variables for feasibility evaluation of horizontal wells. It is, therefore, desirable to develop and evaluate simple but reliable methods for predicting the production performance of the horizontal wells. The production performance of horizontal wells completed in the low permeability gas reservoirs can be predicted by utilizing production type curves without the need for costly and time consuming computer simulations.
The application of the production type curves and the issues concerning the production performance of horizontal wells in the low permeability gas reservoirs are discussed. In addition, pre-stimulation production data from a horizontal well in West Virginia is compared with the predicted results from the type curves in order to evaluate the applicability of the type curves.
Evaluation of the Breaker Concentrations Required to Improve the Permeability of Proppant Packs Damaged by Hydraulic Fracturing Fluids
Authors: Brannon H. D. , Pulsinelli R. J. 
Published: December 2007

Abstract
The permeability of proppant-packs may be significantly damaged by the gelling agents commonly used in hydraulic fracturing fluids. Several recent fracture conductivity studies have sought to quantify the damage caused by these treatment fluids over a wide range of environmental conditions. Very little, however, has been disclosed in the way of viable methods of minimizing or cleaning up the proppant-pack damage.
Breakers, both oxidative and enzymatic, have been recognized for many years as useful for degrading the viscosity of polymeric treatment fluids. The prevailing assumption was that breaking the treating fluid to a non-viscous state was sufficient to provide for the proppant-pack clean-up upon flowback. Recent studies have illustrated that the permeability is significantly impaired by the polymer residue even though sufficient breaker concentrations have been added to effectively reduce the fluid viscosity.
In this study, the concentrations of a commonly used oxidative breaker which are required to significantly reduce the proppant-pack permeability damage caused by polymeric treating fluids were determined. The fluids which were evaluated were based upon natural guar, derivatized guar (HPG), and hydroxyethyl cellulose (HEC).
The long-term proppant-pack permeability testing was performed using a modified API-type fracture conductivity cell which permitted fluid loss through two, ten square-inch cores. The test temperature was 160°F, which is believed to be below the range at which effective thermal degradation occurs.
Test results indicate that proppant-pack damage can be significantly reduced by the addition of elevated breaker concentrations. An understanding of the effects of breaker concentration on proppant-pack damage can be very useful in the effective design of fracturing treatments.
The Effects of Skin Damage Upon the Productivity of a Well Containing a Horizontal Borehole
Authors: Peterson S. K. , Holditch S. A. 
Published: December 2007

Abstract
The application of horizontal drilling to enhance the production of oil and gas is a topic that has received much attention in the petroleum industry during the past few years. Numerous papers have been published concerning horizontal drilling technology,1-10 completion techniques involved with horizontal wells,11-20 well test design and analysis in horizontal boreholes, and reservoir performance prediction and analysis techniques.25-39 Even though publications are available on these topics, much of what is known within the industry has not been published due to proprietary concerns. Specifically, very little production data and field case histories have been included in the literature. Information concerning the production performance of wells completed with horizontal boreholes is extremely critical to one attempting to evaluate the usefulness of this technology.40
There are many well publicized applications for horizontal wells,41 such as; Improving recovery from naturally fractured reservoirs with widely spaced fracture systems;Producing gas from low permeability reservoirs near aquifers without barriers to hydraulic fracture height growth;Producing shallow, thin reservoirs with large areal extent in which one horizontal well can drain an area that would require multiple vertical wells to properly deplete;Producing reservoirs with thin oil columns and an overlying gas cap or underlying aquifer in which coning occurs at low flow rates from vertical wells; andImproving sweep efficiency in reservoirs where enhanced oil recovery projects are being implemented.
This paper discusses the application of horizontal wells for stimulating low permeability gas reservoirs where hydraulic fracture treatments are normally needed but, for whatever reason, cannot be successfully executed. In many low permeability gas reservoirs, long hydraulic fractures are needed to optimize production and profit from that reservoir.42 If weak barriers to vertical fracture height growth exist, then it may be physically impossible to create long fractures. In other situations, fractures may grow into aquifers or other intervals that prevent optimum performance.
Characterization of Formation Damage in Heavy Oil Formation During Steam Injection
Authors: Okoye C. U. , Onuba N. L. , Ghalambor A. , Hayatdavoudi A. 
Published: December 2007

AbstractEnhanced oil recovery processes can lead to severe and permanent reductions in permeability due to interactions between injected fluids and reservoir rock. This is true particularly in high clay content and poorly consolidated reservoirs. Near wellbore permeability damage was suspected as a factor contributing to post injection production decline observed during high PH cyclic steam injection at Bayou Bleu field. This paper presents the laboratory studies undertaken to evaluate the influence of injection fluid composition, temperature, mineralogy and flow rate on permeability damage. The degree of damage during steam injection was observed to be dependent on PH, rock clay content, temperature and injection rate. Permeability reduction of up to 21% was observed in some cores at varying temperature and PH values for flow test and up to 70% for Rolling Oven test. Partial permeability restoration was obtained in all cases by reversing the direction of steam injection in the cores. Sandstone interaction with high PH steam leads to incongurent dissolution of clay minerals and subsequent precipitation of new aluminosilicates. Steam with caustic soda additive precipitated crystalline zeolite between temperatures of 100° and 300°F, mixture of zeolites and amorphous compound between 300° and 400°F and amorphous precipitate between 400° and 500°F. Mechanical fine migration and hydrothermal effects constitute the primary damage mechanisms when low PH steam is injected into Berea sandstone. The permeability damage due to fine migration was found to be rate sensitive while the damage caused by hydrothermal effect increased with increasing temperature. For high PH steam the primary damage mechanism is chemical dissolution and precipitation of aluminosilicates. The complex chemical activities were found to be temperature and alkali concentration dependent. While increasing temperature and alkali concentration generally increased the dissolution process the precipitation of certain aluminosilicates (zeolites) are inhibited at high temperatures and alkali concentration leading to improved permeability. SEM analysis revealed that the precipitates clogged pore spaces and plugged pore throats. High flow rate reduced the amount and rate of precipitation but at field scale flow rates the precipitation rate was high enough to cause rapid permeability reduction.
Evaluation of Acid System Design and Formation Damage Using Polarized Microscopy
Authors: Dunlap D. D. , Houchin L. R. 
Published: December 2007

Abstract
The evaluation of acid returns is an important tool for optimizing future acid treatments. The physical and chemical properties of the returned fluid are indicative of the rock and fluid interactions which occur during a formation treatment. Polarized microscopy is also an important part of this evaluation. The use of a microscope in return acid analysis permits the detection of specific damage mechanisms such as emulsions, organic deposits, silts, clays and iron.
This study details the use of polarized microscopy and other analytical techniques in thirty-two field applications in oil bearing sandstone formations located in the Gulf of Mexico, California and Alaska. Based on the results of these evaluations, modifications were made on future treatments to optimize stimulation results.
A Qualitative and Quantitative Evaluation of Fracture Treatment Variables Employing a Digital Computer Program
Authors: Harp L.J. , Crawford H.R. , Zachary R.A. 
Published: December 2007

Abstract
This paper describes an approach used in a large gas reservoir to develop a method for more accurately evaluating the effects of treatment variables. The study resulted in an empirical equation which will predict the productivity increase, for any set of treatment conditions, with reasonable accuracy. The value of such a workable tool is quickly realized. Emphasis and resources can be directed toward the important variables. Cost reduction and savings can be made in the area of variables having minimal or negative effects. With this tool, treatment planning, well selection, and economic considerations become relatively simple and confident decisions.
The success of this program indicates that this, or a similar method, can provide more effective and profitable stimulation treatments in other large fields.

Introduction
Since the advent of fracturing in 1949, the industry has witnessed refinement of the process resulting in the development of dozens of additives, processes, theories, and improved methods. Theoretically, all of these things contribute to the overall results of the treatment. Most assuredly, they contribute to the treatment cost. The questions that haunt many of us are—- "Do all of these things really contribute to the overall productivity increase? If so, to what degree does each contribute with respect to its cost?"
In the past we have been content to reach decisions on the basis of theoretical benefit, feel, and hope. Today, pressure for greater assurance of treatment segment effectiveness and economics insists upon a more accurate and dependable method of variable evaluation.
Prediction of Fracture Gradients Offshore Australia
Authors: Vuckovic V. 
Published: December 2007

ABSTRACT
Previous work on developing an empirical correlation between in situ formation stress and depth for some sedimentary basins worldwide has demonstrated that such a correlation is viable for predicting fracture and leak off pressures. These parameters, together with pore pressures, are essential for proper well design from both an economic and a safety viewpoint.
Leak off pressure data have been gathered and analysed from wells drilled offshore Australia to establish empirical correlations which would be applicable for fracture gradient prediction in Australian offshore regions. The empirical relationship between in situ formation stress and depth derived from this study may be used with a high degree of confidence to predict leak off and fracture propagation pressures necessary for safe and economical well design in less than 600 ft (183 m) of water. These correlations can be extended to deep water regions by the application of a single correction.