bluuebunny/crossref_metadata_2025_split huggingface dataset:
Water for Oil - A Rational and Regional Approach of Water Supply Problems for Secondary Recovery in Hassi-Messaoud Field, Algeria
Authors: Ghalem Tahar , Delhomme Abdelkader , Lagarde Andre 
Published: December 2007

ABSTRACT
When water is needed for water injection in oil fields of an arid country, far from sea, the water supply is facing various technical and economical problems. The only solution is to find underground waters unattractive for any other possible use. In the selection of water sources, oil exploration is a big chance for underground aquifer surveys and knowledge. This paper shows how it has been used in defining the best way to provide the oil industry water needs and in evaluating possible interferences with other uses such as regional agricultural development plans.
First geological studies from oil exploration or development wells allowed to reach a good definition of aquifer extensions and thicknesses. Then water well tests first led to a good knowledge of hydrogeo-logical characteristics. Finally, mathematical models were specially built to define the aquifer delivera-bilities, the best water well schemes and the regional consequences on water levels.
Combined use of the two deep aquifers, confined turonian aquifer at an average of 850 meters below ground level with very salty water and artesian albian-barremian aquifer at an average depth of 1400 meters below ground level with fresh water, has been shown necessary to satisfy oil injection water needs and local industrial and domestrical water consumption that together will reach about 1 m /s during the next ten years.
Demonstration of Massive Hydraulic Fracturing, Piceance Basin, Colorado
Authors: Strubhar Malcolm K. , Fitch John L. , Medlin W. Louis 
Published: December 2007

ABSTRACT
Demonstration of massive fracturing to provide gas production from tight gas sands in the Piceance Basin was the objective of this work by Mobil. The project was partially funded by the U.S. Department of Energy. During the period 1974-1979 two wells were drilled, tested and fractured. Encourging results were obtained from the second well.
The first well, Brush Creek Unit 1-25, located near Collbran, Colorado, was drilled to 10,330 ft. Three Mesaverde formation intervals were tested and two of these were fractured. Results were discouraging because of low formation conductivity which ranged from 0.005 to 0.15 md-ft in the three zones. The second well, Piceance Creek Unit 31-13, located near Rio Blanco, Colorado, was drilled-to 10,800 ft. Nine intervals were tested in the Mesaverde and Fort Union formations and six fracturing treatments were performed. Combined flow from all of these zones began at 3.2 MMSCF/day and declined to 1.7 MMSCF/day in 207 days.
Details of drilling, testing and completion are given in this paper along with estimates of fracture effectiveness. Preliminary economics are also given, based on the short production history available.
A Post Analysis of Field Development Projects
Authors: Franzen Donald M. , Whittenburg Larry A. , Sawyer David N. 
Published: December 2007

ABSTRACT
The objective of this study was to determine the reliability of original estimates made for forty offshore field development projects.
From the results of the study, we conclude that a bias exists in estimates of field development events, e.g. project time, anticipated drilling schedules, initial production rates. There was no significant bias in recoverable reserves due to large variance in data. A statistical analysis was performed to determine the magnitude of the bias in each event and the 95% confidence limits.
Improved Well Testing in the Denver Unit
Authors: Neely A. B. , Bridges G. L. , Ganus P. G. 
Published: December 2007

ABSTRACT
A computer pump-off control system is in operation in the Denver Unit of the Wasson Field. The system and its major advantages have been previously reported by Hunter et al.1 An unexpected benefit of the system has been the improved reliability of well testing that has occurred. The ability to monitor pumping hours and downhole pump action gives independent data for comparison with the periodic well tests. This comparison spotlighted the weakness in some of our well test equipment and maintenance procedures. Upgrading of some of the equipment and improved maintenance procedures has occurred. All equipment maintenance for the 34 test stations is now done by one small specialized crew.
Prior to these changes, runs from the field averaged about five percent below the sum of the well tests. Over the past six months, this difference has dropped to less than two percent. We believe this improvement represents a combination of more accurate tests and increased production due to quicker realization of a drop in production on a well.
Reservoir Simulator Employing a Fine-Grid Model Nested in a Coarse-Grid Model
Authors: Graham Michael F. , Smart G. Thomas 
Published: December 2007

ABSTRACT
This paper describes a reservoir simulator that uses a fine-grid model nested in a coarse-grid model for areal simulation representing a reservoir in communication with a large pressure-supporting aquifer. It discusses the motivation for using such a simulator and describes how the simulator was implemented.
Computer Analysis of Drilling Fluids
Authors: Sampey James A. , Cottingham Richard 
Published: December 2007

ABSTRACT
A computer program has been developed which analyzes drilling fluids by using the information given on the standard API Drilling Mud Report. The program incorporates the latest drilling fluid engineering technology, coupled with years of field experience. A simple, straightforward style of input, combined with the use of portable terminals linked to a central computer, allows the program to be used by anyone wherever telephone communications exist. It has proved effective in the onsite analysis and treatment of drilling fluids, as well as in simultaneous monitoring of a number of different operations from a central office.
Waterflood Operations, Loudon Pool, Illinois
Authors: Fox M.E. 
Published: December 2007

Abstract
Discovered in 1937 and now one of the nation's larger waterflood developments, the Loudon pool, Ill., has a history of practical application of advanced conservation techniques. Careful spacing analysis, multiple horizon completions and gas partial pressure maintenance were all part of primary depletion history. Primary recovery of 180,000,000 bbl from 24,500 productive acres of Chester sands will be greatly enhanced by the current waterflood operation. Waterflood exploitation was begun in 1950. After flood ability was demonstrated, an expansion program was begun and by June 1, 1957, the flood covered an area of 13,700 acres. Current planning indicates the flood area will total 19,000 acres when fully developed. Water flooding has increased total pool production 21,000 B/D during the past four-year period. Because of the flood program size, unique problems have been encountered in maintaining an adequate supply of water for injection. Waterflood behavior of the reservoirs has been carefully analyzed as a guide to optimum ultimate results.

Introduction
The Loudon pool is located in south-central Illinois on the northwest flank of the Illinois basin. Its location in relation to other producing pools in the basin is shown in Fig. 1. Since discovery of the field in 1937, development and production operations at Loudon have been characterized by use of the best conservation practices which were applicable. The latest and most significant of these techniques is the water flood program which by June 1, 1957, covered 13,700 acres, involving the properties of 40 operators. The water flood is expected to increase pool ultimate recovery by 140,000,000 bbl.

Development and Production History
The producing horizons under flood at Loudon are four Mississippian Chester sand reservoirs, the Weiler, Paint Creek, Bethel and Aux Vases, encountered at subsurface depths ranging from 1,400 to 1,600 ft. Productive areas of these four reservoirs are outlined in Fig. 2. The Weiler, Paint Creek, and Bethel sands contribute the principal oil reserves.
Mobilization Of An Oil Drop Trapped In A Noncircular Pore Throat Upon Contact With Surfactants
Authors: Arriola Alfredo , Willhite G. Paul , Green Don W. 
Published: December 2007

ABSTRACT
Results are described for an experimental study to identify mechanisms by which an oil drop, trapped in a noncircular pore throat, is mobilized upon contact with surfactants. Experiments were done in a square capillary (100 μm × 100 μm) cell with a pore throat (11 μm × 11 μm) drawn at one end of the capillary. Mobilization was investigated by conducting a series of displacement experiments in the capillary cell. In each experiment, an oil drop about 890 am in length was trapped at the constriction by brine (10,100 ppm NaCl) flowing at an average pore velocity of 1.3 ft/day. A chemical slug containing surfactant was injected into the capillary cell and displaced toward the trapped oil drop by the brine. The mobilization process was observed through a microscope. High speed movies and 35 mm photographs were taken through the microscope to record fluid interactions.
Five different surfactant systems were studied. These included two microemulsions containing brine, nonane, IPA and TRS 10-80. A third system was similar but contained no nonane. The fourth system was a dilute solution of TRS 10-80 in brine, and the fifth was a macroemulsion produced from a displacement experiment in a Berea core using one of the microemulsion systems. Nonane was the oil phase except for the dilute surfactant displacement which utilized octane.
Data from the experiments allowed two mechanisms to be identified which cause mobilization of a trapped oil drop when contacted by surface active agents. In mechanism I, minute quantities of the surfactant and/or co-surfactant were carried ahead of the main surfactant slug by brine which bypassed the slug. This reduced the interfacial tension between the oil and brine. The oil drop moved further into the constriction and a snap-off process ensued. Mechanism II occurred when a "sharp" interface of the surfactant slug contacted the trailing edge of a nonane drop which was either trapped or in a snap-off process. A series of events which mobilized the drop occurred over a very short time period (&lt; 4.0 sec). The events included rupture of the drop interface, rolling motions inside the drop with resulting emulsification, and passage of the emulsified drop through the pore constriction without snap-off. The emulsification reflected hydrodynamic instabilities, i.e. a Marangoni effect.
Applying New Technology to Optimize Mature Oil and Gas Fields
Authors: Stefanescu D. P. , Serrano G. , Wegemer K. , Stolk W. 
Published: December 2007

Abstract
Laslau Mare is a gas field developed by Romgaz (an exploration and production company) 30 years ago. This field reached its maximum production capacity during 1981, after which production decline began. In general, innovation costs in mature oil and gas fields seem high due to the declining production. It is well known though, that the application of new technology greatly improves quality, making the "high price" well worth the cost. Over a year ago Romgaz and Schlumberger (an integrated services company) have developed a new business model where risk and rewards are shared to overcome these obstacles.
With the only objective of rejuvenating declining gas assets, Romgaz and Schlumberger built a multidisciplinary field optimization team. Initially the project took over Laslau Mare field operations in order to obtain a good base to measure and quantify success. The multidisciplinary approach started by identifying the local current technology, equipment and process’ and integrated them with new technology to make the project as cost effective as possible. The result has been the improvement of the complete system, from reservoir to sand face to wellbore, to surface/transmission facilities.
During the initial stage, some areas for critical development were identified. Vital improvement was needed in surface facilities de-bottlenecking and subsurface data compilation and analysis. The application of new technologies to such areas helped identifying new opportunities, which have been a key factor in the rehabilitation of the field. After 10 months of constant improving and monitoring, success has been measured and the project has achieved a 40% altering the declining slope and stretching the life of the field
Optimum Fracture Design under Transient and Pseudosteady Conditions Using Constant Fracture Volume Concept
Authors: Rueda J. I. , Voronkov A. , Mach J. 
Published: December 2007

ABSTRACT
The Unified Fracture Design (UFD) or constant proppant volume technique introduced by Valko and Economides1,2 was originally developed for pseudo-steady state flow conditions and oil industry has been applying this technique even for low permeability reservoirs where the transient conditions last considerable time. There is nothing in the literature that shows that optimum fracture design using constant-proppant volume concept for pseudo-steady state flow is the same or different than the optimum one for transient flow conditions.
This paper will present an extension of UFD technique (fixed proppant volume technique) to cover not only pseudosteady conditions but also transient flow regime. Results have shown that each "dimensionless time snap shot" presents a similar JD type curve3 with different optimum design curve. Therefore, the optimum fracture design is time dependant until pseudo-steady state condition is reached. Additionally, this paper presents a equivalent pseudo-steady state equation to calculate the dimensionless productivity index (JD) of finite-conductivity fractured wells producing at either transient or pseudo-steady state conditions. The pseudosteady state equation uses the definition of equivalent wellbore radius presented by Rueda3, to take into account the finite conductivity, fracture penetration and time dependency of the solution. Following pseudo-steady state equation concept, new correlations (from 1500 numerical simulation runs) to calculate shape factors and f-functions for a fractured well were developed, where the f-function is an extension of the original Cinco-Ley's function for transient and pseudo-steady state flow period. These correlations are functions of dimensionless fracture conductivity (CFD), fracture penetration ratio (Ix), and dimensionless time (tDA). This pseudo-steady state equivalent equation can be used to generate a series of new JD type curves of a finite-conductivity fractured well for different dimensionless times tDA. Having this equation, a new approach to get the optimum fracture geometry for a specific proppant number (Nprop) for a "fixed period of time" was also developed and presented in this paper.
Pipeline Transportation of Waxy, High Pour Point Crudes as Slurries
Authors: Drayer Dennis E. 
Published: December 2007

ABSTRACT
A novel process for the pipeline transportation of high pour point, highly paraffinic crudes has been developed. The process involved formation of a hydrocarbon slurry after distillation of the crude into two fractions. Small, solid particles of the heavy fraction were formed and dispersed in the light liquid fraction. Experimental flow data for these non-Newtonian slurry systems have been scaled to commercial-size pipelines. The process has been adapted also to several shale oil systems.
Integrated Reservoir Modelling Enhances the Understanding of Reservoir Performance of the Dolphin Gas Field, Trinidad and Tobago
Authors: Sylvester I. F. , Cook R. , Swift R. , Pritchard T. , McKeever J. 
Published: December 2007

Abstract
The Dolphin Field in Trinidad and Tobago has consistently performed better than original Field Development Plan. This has resulted in the static model Gas Initially In Place (GIIP) historically lagging behind the reservoir simulation model GIIP.
Reservoir characterization and modelling studies in 2003/04 has resulted in close alignment of the static GIIP and the dynamic history match GIIP. This paper will describe the modelling work flow and discuss the key lessons learned from applying an integrated reservoir management solution to this significant producing gas field.
An in Situ Coal Quality Prediction Technique
Authors: Norris Janice O. , Thomas Randy 
Published: December 2007

ABSTRACT
The classic method of quantitatively evaluating coal still underground Involves obtaining cores from boreholes and evaluating these cores in the laboratory Since coring is time-consuming and costly, using quantitative log data to calculate coal quality Information without complete dependence on cores is desirable. Quality Information derived from such log data allows a more extensive evaluation of coal beds while decreasing coring costs and allows the Information to be available as soon as the hole is logged. Alhough initial correlation of core with log data for an area is required, later in situ analyses are possible. Initial results show the values generated by the in situ quality model fall within a few percentage points of the core values for moisture and ash and fall within several percent of the core heat content values.
Prospects for Dually Completed Wells in the Northern Appalachian Basin
Authors: Tarr Earl G. 
Published: December 2007

ABSTRACT
Application of a dynamic exploration program in conjunction with increased prices and improved production technology can result in the recovery of significant commercial quantities of the natural gas considered to be entrapped in the fractured Devonian Shales in the northern Appalachian basin.
In February, 1979, under Department of Energy Contract Number DE-AC-21-79MC10389, Tetra Tech, Inc. began work on a Morgantown Energy Technology (METC) program designed to test the natural gas productivity of dually completed wells in the Devonian Shale and Clinton Sandstone in the northern Appalachian Basin.
To insure success of the concept, an exploration program was initiated in August, 1979, under Modification A002, to identify prospective trends and prospects for dual completion in the Devonian and other stratigraphic zones. This work is now culminating in the drilling and testing phase to substantiate the results of the exploratory work.
A single well producing from more than a single reservoir is a multiple completion technique for handling flowing production and maximizing daily output. Factors to be considered when implementing multiple completions are: (1) higher producing rate, (2) faster payout, and (3) multi-reservoir control requirements.
With the exception of the commingling of production from several zones in certain localized areas, multiple zone well completions are not used in the Appalachian basin. Of the numerous possible multiple completion configurations, the Single String-Single Packer is a simple low-cost dual completion technique having the most practicality for use in the Appalachian region. An excellent opportunity to utilize this method is afforded in wells that are drilled to objectives overlying and underlying the Devonian Shale sequence.
Operators and industrial users that are willing to include dual completions in their drilling programs will not only realize the cost effectiveness of dual completions in the Devonian Shale and another reservoir, but provide an effective low-cost means of exploiting the Devonian Shale and other reservoirs.
Pricing requirements governing tight sands and unconventional reservoirs under the Natural Gas Policy Act, may necessitate the segregation of producing intervals.
Appraisal and Development of a Heavy Oil Field in Glacial Clastics
Authors: de La Grandville Baudoin F. , Howells Martyn 
Published: December 2007

ABSTRACT
The paper outlines appraisal of the Marmul field in South Oman from discovery in 1956 to its coming on stream in 1980.
Appraisal drilling has revealed a combination of two traps: a structural trap of late Palaeozoic glacial clastics and a peripheral stratigraphic trap of fluviatile sands. From geological, seismic and petrophysical data, a model has been developed to describe this complex field, to predict trends of good reservoir development and to allow a better estimate of the oil in place.
The properties of the oil determine that primary and even conventional secondary recovery processes would only recover a small fraction of the oil in place. Consequently, enhanced oil recovery methods involving steam and/or polymer injection are proposed for field testing.
The Application of Natural Gamma Ray Spectrometry Log as an Aid in Log Evaluation in Saudi Arabia
Authors: Youngblood William E. 
Published: December 2007

ABSTRACT
The Natural Gamma Spectrometry log (NGS) was first introduced in Saudi Arabia in late 1976. Initially, the NGS log was used primarily to solve the stratification problems associated with the offshore fields. Using conventional logs, correlation has always been a problem due to lenticularities in bedding. Identification of continuous shales by the NGS has improved correlation from well to well.
Examples will be shown where log calculated porosities have been improved by using a corrected gamma ray (the amount of uranium subtracted out) which gives a more accurate percentage of shale and consequently improved reservoir description.
The NGS has also been used to differentiate between carbonaceous layers (uranium rich) and true shales (Thorium/Potassium rich) which may determine the probability of lateral continuity.
The ratios of TH/K may help in establishing marine and non-marine environments as well as changes in clay type.
Other uses will be found when geological information can be viewed with the NGS response in sedimentary rocks.
Reservoir Simulation on Vector Processing Computers
Authors: Nolen James S. , Stanat Patricia L. 
Published: December 2007

ABSTRACT
Vector processing computers have been designed so that carefully designed FORTRAN programs can achieve large speed increases relative to existing scalar computers. Since traditional approaches to various aspects of reservoir simulation are not amenable to vectorization, the methods used in reservoir simulators should be evaluated for possible change.
This paper examines the distribution of CPU use in a three-dimensional, three-phase reservoir simulator that uses finite difference approximations which are fully implicit in both saturation and solution gas-oil ratio. Results are presented for operation in both scalar and vector mode on the CYBER 203 computer.
It was found that vectorization reduced scalar run times by a factor of 3.7 for a problem using a grid of 25 × 20 × 4. The distribution of work in the simulator was so broad that all repeatedly executed code, except well performance and output routines, had to be vectorized to achieve this result. Estimates of run times for a simulator with explicit saturations suggest that the highly stable, implicit formulation increases run times by only 50-80% compared to the relatively unstable IMPES method.