bluuebunny/crossref_metadata_2025_split huggingface dataset:
Expert System for Simulation of Oilfield Development: EKRAMON
Authors: Maksimov M. M. , Tetelbaum Y. l. 
Published: December 2007

Abstract
The expert system EKRAMON for choosing of the oil field development method and simulation of the oil field development process, working in an interactive user dialog mode on the base of IBM/AT class personal computer with an extended memory and giving the consultation results without any sufficient delay, is described.
It can be reached by striving for a diminishing number of the rules entered in the system with the help of expert work proper organization and an interpretation of expert data, according the developed method of certainty factors using. The high trustworthiness of the variants to be chosen could be achieved with the help of using a fuzzy logic. Different knowledge bases of the considered expert system are described.
A Practical Artificial Intelligence Application in Well Test Interpretation
Authors: Allain Olivier , Houzé O. P. 
Published: December 2007

AbstractThe take-off in Artificial Intelligence (AI) in the last decade has led to the development of such software tools as expert system shells, causing a tremendous incentive for applying AI in the Industry. In many cases, however, the original enthusiasm has gradually faded away as the results obtained did not meet the original expectations1.This paper deals with AI applications to welltest interpretation and presents what can be achieved practically today and what can be expected in the future. Most of the early work was focused on developing assistant programs, helping the interpretation engineer to select the appropriate solution model(s). The goal of this study is instead to facilitate and speed-up the task of the interpretation engineer. An interactive computer program developed in this framework is described and several real test examples are presented. The practical advantages and limitations of the program are described in detail.
Use of Pressure Gauge Differentials in Well Test Quality Control and Well Performance Evaluation
Authors: Cliff W. J. , Boertje Alexander , Fjaere Ole 
Published: December 2007

Abstract
Over recent years, Well Test Analysis techniques and software have developed to the stage where it is possible to match a wide range of pressure responses using one or more model solutions! However, experience in Shell Gabon has shown that the pressure correction from gauge to sandface, along the wellbore, should not be overlooked when analysing the observed gauge response.
This paper examines the use of procedures, based on time synchronisation and analysis of differences between pressures measured on tandem precision pressure gauges, to assist in understanding the wellbore environment, and therefore in making this correction. Extension of the methodology to analysis of bottom hole to surface pressure differentials can also be used to better understand and optimise well performance. Specially-written software has been developed to assist in this ‘Differential Pressure Analysis’.
Hydraulic Jet Drilling
Authors: Maurer William C. , Heilhecker Joe K. 
Published: December 2007

Abstract
As a result of a detailed survey of over 25 novel drilling techniques, a laboratory study of hydraulic jet drilling was made. In initial tests, a cannon was used to fire 1.45-gal water pulses at rocks at pressures up to 25,000 psi. These tests showed that a threshold nozzle pressure must be exceeded before hydraulic jets will drill rock. Water jets having diameters of 0.2- to 1-in. drilled holes with diameters ranging from 0.8 to 4 in. in sandstone and limestone. These holes, which were 1 to 3 in. deep, were drilled in 0.02 to 0.2 seconds. These tests showed that water jets can effectively drill sedimentary rocks.
Following these tests, a 2-in.-diameter hydraulic jet drill was tested in a laboratory rig. A high-pressure pump was used to pump water continuously through this drill at pressures up to 13,500 psi. This drill penetrated pressures up to 13,500 psi. This drill penetrated Carthage marble at 180 ft/hour, Indiana limestone at 280 ft/hour and Berea sandstone at 300 ft/hour. These tests showed that a full-scale hydraulic jet drill [3,000 hp] should drill 8-in.-diameter holes in average-strength sedimentary rocks at rates of 200 to 300 ft/ hour, These high drilling rates show that hydraulic jet drills have high potential for drilling oil wells economically.
Introduction
A survey of over 30 novel drilling techniques revealed that full-scale hydraulic jet drills [also drilled erosion drills] should have high drilling rates in oil wells. These hydraulic jet drills use high-pressure water jets [5,000 to 70,000 psi] to shatter rock and pump the debris from the hole bottom. pump the debris from the hole bottom. Following this survey, we measured hydraulic jet drilling rates and studied variables that affect hydraulic drilling rate. These tests showed that hydraulic jet drills can drill sedimentary rocks at high rates and that they have potential for drilling oil wells economically. Our results, along with a summary of the findings of other investigators, are presented in this paper.
BACKGROUND INFORMATION
Rock Removal Mechanism
A threshold nozzle pressure must be exceeded before water jets will effectively shatter and drill rocks. This threshold pressure increases with rock strength; many water pressure increases with rock strength; many water jets will effectively drill weak materials such as coal or concrete, but will not drill hard rocks such as granite or basalt. Abrasives [e.g., sand or steel shot] have been used in erosion jets operating below threshold pressure.
Review of New API-Recommended Practices for Petroleum Production Above Ground Storage Tank Installation, Inspection, and Repair
Authors: Hein N.W. , Loudermilk M.D. 
Published: December 2007

Abstract
Safe operation and mechanical integrity of above ground storage tanks are very important to the petroleum industry due to both environmental and financial considerations. Recent work by API and the industry resulted in new, consensus recommendations for production tanks. These recommended practices have been detailed in a new API document that covers installation, leak detection, inspection requirements, maintenance and repair of the above-ground production storage tanks. Also included in this document are qualification requirements for the three levels of personnel and the different inspections that they can do. This paper reviews the major, new recommended practices and changes to the previous edition of the API Recommended Practice 12R1.

Introduction
The 1988, diesel fuel tank failure in Pennsylvania spurred the petroleum production, refining and transporting industries to develop environmentally safe practices for the inspection and maintenance of above ground storage tanks (AGSTs).
Originally, the American Petroleum Institute (API), which coordinated the efforts for the petroleum industry, had the Refinery Department developing a document that could be used for the entire industry. This was undertaken since the majority of refineries are located near waterways, rivers, etc. and their large volume AGSTs posed a greater risk for environmental problems than storage tanks from the production side of the industry.
The Refinery Department's main document developed for maintenance and inspection of AGSTs was API Standard 653. While this document was being developed, the API had two independent studies conducted. The first was a survey of AGSTs. This survey developed estimates of the number and capacity of AGSTs in the petroleum industries. The results of this survey are shown in the following comparison table.
Innovative Treatment Alternatives for Oily Wastes Generated During the Exploration and Production of Oil and Gas
Authors: Kabrick R. M. , Rogers L. A. 
Published: December 2007

Abstract
The Exploration and Production (E & P) of oil and gas generates significant quantities of oily wastes, including oily drill cuttings, spent oil-based drilling muds, crude oil contaminated soils, crude oil tank bottoms, and reserve pit oily sludges. As E & P companies have become increasingly aware of environmental liabilities (past, present, and future) associated with E & P operations, they have sought alternatives to their present oily waste management practices. This paper discusses two innovative treatment alternatives for E&P oily wastes, thermal desorption and biological liquid/solids treatment. These two technologies are fully developed and have just recently been demonstrated at full-scale on refinery oily wastes and at pilot-scale on E & P oily wastes.
Results of pilot-scale testing indicate that biological liquid/solids treatment of E & P oily waste can significantly decrease the oil and grease (O & G) fraction of the waste in a reasonable time period and for a reasonable cost (&lt;$75/yd3). O & G half-lives were measured at &lt;15 days. Thermal desorption can reduce O & G to &lt; 1% in oily drill cuttings at a cost of &lt;$100/yd3. Both technologies are currently being applied to the treatment of refinery oily wastes. An overview of both treatment technologies is presented in this paper, including process fundamentals, operational considerations, and results of recent pilot-scale testing on E & P oily wastes.
Laminar Displacement in Annuli: A Combined Experimental and Theoretical Study
Authors: Tehrani Ahmadi , Ferguson John , Bittleston S. H. 
Published: December 2007

Abstract
The placement of cement in an annulus is a crucial operation in the life of an oil well. To ensure zonal isolation, the drilling mud must be completely displaced from the annulus. Poor displacements require remedial squeeze cementing which is both costly and time consuming. The process is complex, involving the time-dependent motion of multiple non-Newtonian fluids, with different densities and rheologies, flowing in a three dimensional well-bore. Hence, it is not surprising that there are conflicting views on the best possible way to control displacement.
This paper discusses the displacement process from both a theoretical and experimental points of view. A lab scale facility has been designed by applying dynamic similarity. This allows a careful investigation of displacement. A brief outline is given of a model for predicting the process. It is shown that the experiments and theory are in excellent qualitative agreement. We discuss some of the controlling mechanisms and show that under some circumstances azimuthal instabilities arise. Finally, we simulate a typical complicated situation and show the importance of good spacer design.
Field Testing of a Cationic Polymer/Brine Drilling Fluid in the North Sea
Authors: Beihoffer T. W. , Growcock F. B. , Deem C. K. , Dorrough D. S. , Bray R. P. , Munro Roderic , Guild G. J. , Hanni G. L. , Prewett H. H. 
Published: December 2007

ABSTRACT
This paper discusses the field testing of a cationic polymer/brine drilling fluid (CBF) on seven wells drilled in the North Sea. Two wells were drilled in the Norwegian sector and five wells were drilled in the U.K. sector. Hole sizes on the wells varied from 17.5" to 6", hole deviations varied from vertical to 55 degrees and maximum TD was below 14,000 feet measured depth. Field data are presented along with a discussion of the performance of CBF, including benefits, limitations and costs as compared to oil-based and conventional water-based muds.
CBF appears to be more inhibitive than other water-based drilling fluids used in the area. The tests prove that CBF, while not as inhibitive as oil-based mud (OBM), is sufficiently inhibitive to be used as an alternative to OBM in many areas where OBM has previously been thought necessary.
Advantages of CBF over conventional water-based fluids include: Ease of maintenance: Tests have been developed to quantitatively measure the inhibitive components of the fluid. This allows the fluid to be run like a chemical process without guesswork.Contamination resistance: Large amounts of solids contamination can be tolerated without adverse changes in fluid rheology.The ability to independently control fluid properties: The major components of CBF work independently of each other, greatly simplifying maintenance. This is significantly different from conventional fluids where the addition of polymers to control fluid loss or improve inhibition often causes large changes in fluid rheology.
The information provided in this paper can assist operators in evaluating alternatives to oil-based fluids in areas where the use of OBM is restricted.
CO2 Foam Field Verification Pilot Test at EVGSAU: Phase II—Foam Injection Design and Operating Plan
Authors: Stevens J. E. , Harpole K. J. , Zornes D. R. , Martin F. D. 
Published: December 2007

ABSTRACT
The East Vacuum Grayburg San Andres Unit (EVGSAU) operated by Phillips Petroleum, is the site selected for a comprehensive evaluation of the use of foam for improving the sweep efficiency of a CO2 flood. The four-year project is jointly funded by the EVGSAU Working Interest Owners (WIO), the U.S. Department of Energy (DOE), and the State of New Mexico. The Petroleum Recovery Research Center (PRRC), a division of the New Mexico Institute of Mining and Technology (NMIMT), is providing laboratory and research support for the project. A Joint Project Advisory Team (JPAT) composed of technical representatives from numerous major oil companies, PRRC, and DOE provides input, review and guidance for the project.
This paper is the second in a series of papers detailing various aspects of the CO2 Foam Field Verification Pilot test at EVGSAU. An earlier paper summarized the project plans and detailed the laboratory work leading to the selection of a surfactant for the field trial. This paper presents: 1) an overview of the operating plan for the project, 2) details of the foam injection schedule and design criteria, and 3) a discussion of the data collection program and performance criteria to be used in evaluating successful application of foam for mobility control in the EVGSAU CO2 project.
Specific items discussed in the foam injection design include the determination of surfactant volume and concentration, selection of the surfactant-alternating-gas (SAG) injection sequence for foam generation, field facilities, operations during foam injection, and contingency plans. An extensive data collection program for the project is discussed including production testing, injection well pressure and rate monitoring, injection profiles, production well logging, observation well logging program, and both gas and water phase tracer programs.
Cyclic CO2 Injection for Heavy-Oil Recovery in Halfmoon Field: Laboratory Evaluation and Pilot Performance
Authors: Olenick Steve , Schroeder F. A. , Haines H. K. , Monger-McClure T. G. 
Published: December 2007

ABSTRACT
This paper describes an immiscible CO2 project conducted in Halfmoon field, Wyoming. Laboratory results indicated that CO2 could improve recovery of the asphaltic, 17 °API gravity crude. The primary project incentive was that a gas source existed in the field. Incremental oil was produced in the field, but the project was not economic at present oil prices.
Economic Shortsightedness: One Cause and Cure
Authors: Campbell J. M. , Campbell R. A. 
Published: December 2007

Abstract
Oil companies are currently being chastised by employees and investors for taking extremely shortsighted perspectives in both operations and investment practices. Such criticism is old hat for other industries in the Western world. Advocates of the Japanese business style actively promote radical restructuring of American business to force management to take a longer view, especially in the petroleum industry. Even as the flaws in the Japanese system become more apparent, raising some doubts about the Japanese ability to sustain future growth, the core question still remains: Is the petroleum industry taking a shortsighted view and if so, what are the causes?
Only one possible cause for shortsightedness is addressed in this article. Other causes certainly do exist and deserve discussion but are beyond the scope of this paper. The economic methodology forming the basis for investment and operating budgeting decisions provide is the only explanation discussed. The current methodology, in its myriad of applications, contains several fundamental assumptions whose implications for investment strategies are not well understood. This shortcoming causes some to favor extreme conservatism over a thoughtful, long-run strategic plan.
The background for the shortsightedness is reviewed first and the implications for petroleum investments summarized. One possible solution for the shortsightedness and the habit of multi-counted risk levels is outlined. No single measure of profit, however, can ever hope to encompass the vast range of risk and return issues facing companies today. To realize the limitation of any single profit measure is the first step toward a more thorough decision-making process.
Displacement by Foam in Porous Media
Authors: Liu Dianbin , Castanier L. M. , Brigham W. E. 
Published: December 2007

Abstract
In steam drives and certain gas injection projects, the use of foamers to reduce steam and gas mobility has become a common way of improving sweep efficiency. Although the process is widely used, no effective means have been available to optimize it because there is no convenient flow model that properly describes the displacement characteristics of foam flow the way Buckley-Leverett theory describes simple two phase flow.
To attempt to develop a useful model for foam displacement, a number of experiments were run using surfactant laden water displaced by air at a constant rate in linear sandpacks. To decouple the displacement problem from the heat transfer mechanisms, no steam was used in these experiments. The saturations were measured in situ using the Cat Scanner; and, in addition, production and pressure histories were measured for the overall system.
First, water containing various concentrations of surfactant was displaced by air. As expected, these displacements follow Buckley-Leverett theory with saturation distributions growing linearly with volume injected. Also, as expected, the effective mobility of the air was a strong function of surfactant concentration as well as the air/water saturations. In addition, irreducible water saturations were found to be a strong function of surfactant concentration. Analytic expressions were developed to describe the relative permeability relationships as a function of saturations and surfactant concentration.
Next, experiments were run where surfactant laden water and air were injected simultaneously into a porous medium filled with pure water. This process more closely resembles field applications. The displacement fronts were spread more than when the water in place contained surfactant. When multiple fronts of different concentrations were used to match the displacements, the calculations predicted the greater spread observed experimentally, but did not properly ape the effect of distance moved. These calculations, for example, predicted that the saturation dissipation length would double as twice as much fluid was injected. The experiments showed less growth than this.
This slower growth rate could be the result of a dispersion term in the displacement. An equation was developed which included such a term and its predictions were found to match the experiments. The in situ saturation distributions were matched with distance and time as well as the overall recovery histories of the displacements. Under the conditions of these experiments, about 20% of the total spread of the displacements was caused by dispersion, and the rest was caused by Buckley-Leverett spreading.
These modeling efforts have already resulted in insight for practical application. They predict that a large slug of surfactant solution at low concentration injected ahead of the steam will have a greater mobility control effect than will the same amount of surfactant injected simultaneously with steam.
Use of Pressure Transient Testing To Identify Reservoir Damage Problems
Authors: Kamal M. M. , Braden J. C. , Park Heungjun 
Published: December 2007

Abstract
This paper describes a model that was developed to interpret the pressure transient data from producing wells in the Prudhoe Bay waterflood area. The model provides a quantitative description of reservoir permeability as it changes with radius. The match between field data and the model quantifies the trend of the permeability distribution around the producing wells.
Some producing wells in the waterflood areas of the Prudhoe Bay field showed decline in oil and total fluid production rates with the onset of water breakthrough. Pressure buildup tests were run in an attempt to identify the cause of the production decline. Qualitative analysis of the signature of buildup tests was used to identify the most likely reservoir description that would produce similar results. That reservoir description was for a system of gradually decreasing permeability towards the wellbore.
After developing the model, it was added to a non-linear regression analysis program and the resulting package was used to determine the reservoir parameters. The excellent match between field and model results, obtained only from that model, helped identify the reason for declining production rates in the waterflood area of the field.
The solution presented in this paper can be used to analyze transient tests from reservoirs with damage problems or permeability variations with distance.
Horizontal Permeability Anisotropy Characterization by Pressure Transient Testing and Geological Data
Authors: Bandiziol Danilo , Massonnat Gerard 
Published: December 2007

Abstract
The anisotropy of horizontal permeability plays an important role in fluid flow distributions in reservoirs. However, it is rarely detected in the early stage of a reservoir study. Water break-through during production is usually the first evidence of such anisotropy. A technique to investigate the horizontal permeability has been developed, based on pressure transient analysis and geological data.
Anisotropy has been detected and quantified using a pressure transient analysis and a knowledge of the reservoir geometry derived from geological analysis. The results obtained are subsequently confirmed by petrophysical measurements on oriented cores. The use of these results has been of primary importance in matching the pressure history of the "full-field" numerical simulation.
The origin of the anisotropy was identified by a sedimentological study, based on core analysis and FMS interpretation. The anisotropy is related to the internal structure of the sandbodies (foresets), which were deposited in a shore-face environment. The azimuth of the paleo-coastline corresponds to the direction of the maximum value of permeability derived from the well-test analysis and the core measurements.