bluuebunny/crossref_metadata_2025 huggingface dataset:
New Solutions to Remedy Lost Circulation, Crossflows, and Underground Blowouts
Authors: Sweatman R. E. , Kessler C. W. , Hillier J. M.
Published: December 2007

Costly lost circulation, crossflows, and underground blowouts result in mud losses, wasted rig time, often ineffective remediation materials and techniques, and sometimes lost holes, sidetracks, abandoned wells, relief wells, and lost petroleum reserves. In early 1996, a service company initiated a project to review conventional remediation materials and methods, search for more effective remedies, and field-test new solutions. The project has led to the development of several novel lost-circulation material squeeze systems (LCMSS). These LCM squeeze systems were applied in wells after conventional materials/ methods failed, and they successfully cured lost circulation, increased the integrity and frac gradient (FMW) of weak zones (formations with low mechanical strength), sealed high-pressure water and gas zones, safely allowed deeper drilling, and stopped underground blowouts. Data from these field tests show encouraging trends and prospects not only to save costs associated with drilling trouble, but also to reduce normal exploration and production costs for casing, liners, drilling/completion fluids, rig time, poor primary cementation, remedial cementing, and water production.
A Novel Technique for Predicting End-Point Relative Permeabilities of Heterogeneous Limestones from Log Derived Input Data
Authors: Kalam Mohammed Zubair , Al-Alawi Saleh M , Al-Shekaili Suhail
Published: December 2007

Artificial neural network models are increasingly prevalent in predicting various reservoir engineering parameters. The petroleum engineering community at large is witnessing a surge in the use of expert systems and artificial neural networks related technologies, within the broader domain of artificial intelligence. These relatively new computer based tools provide answers to a number of engineering problems which are usually expensive to quantify experimentally, and at the same time reduce the uncertainties inherent in many of the measurement techniques.

Kalam and Al-Alawi1-4 have successfully applied artificial neural network (ANN) derived models to assess formation damage in limestone formations, and prediction of wettabilities of cores from diverse producing carbonate reservoirs in the Sultanate of Oman. The ANN predictions were then compared with measured data, and a number of established empirically derived correlations (commonly used in typical reservoir simulation studies).

The developed ANN models provide quick and fairly accurate predictions of the end-point relative permeabilities of reservoir cores from naturally fractured heterogeneous reservoirs, using simple log derived input parameters. Errors in estimating in these important reservoir characterisation properties from a number of widely used correlations are significantly higher than the experimental measurements. The relative permeability curves from ANN models predictions are consistent with those determined from the tedious and rather expensive SCAL programmes, and as such reduce the uncertainties in reservoir simulations.
3-D Reservoir Characterization for Improved Reservoir Management
Authors: Uland M. J. , Tinker S. W. , Caldwell D. H.
Published: December 2007

Three dimensional (3-D) reservoir characterization tools have reached a development stage where they can be used cost-effectively to help solve reservoir management problems. A principle goal of 3-D reservoir characterization is to derive a spatial understanding of inter-well heterogeneity using integrated geophysical, geological, and engineering data. Traditionally, geologic attempts to characterize interwell heterogeneity have been done using hand-drawn or computer generated 2-D maps and cross-sections. Results can be dramatically improved using 3-D interpretation and integrated analysis techniques. The end product of 3-D reservoir characterization is a more accurate 3-D reservoir model that can optimize answers to reservoir management questions.

Three-dimensional reservoir characterization requires the same input data as 2-D methods, does not add to reservoir characterization costs, improves the integrity of the geologic interpretation, and requires less time than equivalent projects done in 2-D. Updates can be made to the full-field 3-D integrated model within days, as opposed to weeks or months for equivalent changes in a 2-D modeling environment. The enhanced speed allows the user to make several versions of a 3-D model to capture the range of stratigraphie and depositional possibilities. This results, ultimately, in a more accurate 3-D reservoir description.

Five case studies will be presented, including a proximal turbidite, middle-shelf carbonate, two outer-shelf carbonates, and a distal turbidite field. For each field, a synopsis of the reservoir management problem, geology, available data, 3-D model solution, and reservoir management benefits will be presented. Several case studies illustrate data quality control, volumetric calculations, improved reservoir management decisions, and communication between disciplines.
A Study Of The Dodsland Viking Sand Oil Reservoir Dodsland Field9 Saskatchewan
Authors: Maugh J.B. , Edgington A.N. , Hunter J.P.
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.

This paper presents as of the results of the study of the Dodsland Viking sand reservoir located in the province of Saskatchewan, Canada. It is the first engineering paper written about the field where production is found in a 15-mile trend, at a depth of approximately 2,300 ft. Theological data incorporated in this paper are based on the work of M. B. B. Crockford which was presented to the AAPG Regional Meeting in Billings, Mont., during Feb., 1960. The data and material are of interest in the presentation and the paper timely because of the large areal extent of the potentially oil-productive sand and because the field has many producing and completion problems.

The reservoir is characterized by a thin, gently-dipping, shallow sandstone reservoir rock. The up-dip portion of the sand is gas-bearing and covers approximately 70,000 acres, while the oilbearing portion may cover as much as 20,000 acres. Down-dip limits appear to be governed by a deterioration in reservoir quality. The predominating recovery mechanism is expected to be a solution gas drive, possibly assisted in localized parts of the field along the gas-oil contact zone by an expanding gas-cap. Primary oil reserves may reach 10 million bbl. The sand is fine grained, friable, argillaceous, and approximately 10 ft in net thickness. The oil has a gravity of 38 degrees API.

The performance of the individual wells is characterized by a rapid initial decline in productivity, followed by a leveling off in the decline as production continues. The reservoir rock properties are such that completion damage to the sand as a result of using fresh water base drilling fluid is probably quite severe. The rock characteristics and the performance of the individual wells indicate the need for large volume, high injection rate, fracture treatments utilizing a coarse propping agent.

Introduction

The Dodsland Viking sand field is located in southwestern Saskatchewan, about 200 miles northwest of Regina, about 50 miles east of the Alberta-Saskatchewan border, and about 200 miles north of the International Boundary [Fig. 1]. The field limits as defined by the Saskatchewan government cover all of Townships 30 to 32, Ranges 20 to 22, W.3.M., with the exception of the wells in Sections 6 and 7, Township 31, Range 22, which are included within the field limits of the Coleville-Eureka Viking pool. Situated immediately west of the Dodsland field are the Eureka and Coleville oil fields while the Smiley and Buffalo Coulee fields are nearby.
Corrosion Monitoring In Abu Dhabi Oilfields
Authors: Moosavi Ali N
Published: December 2007

The systematic selection approach for corrosion monitoring systems and locations for our oil and gas fields is described. A major factor in the selection process is the high level of H2S in some of our fields. This limits the number of monitoring systems that can successfully be used and also adds to the safety concerns. New probes for corrosion monitoring have been tested by us and the results of the trials are discussed here.
An Independent Guide to Well Engineering and Integrated Services Management
Authors: Stuart Colin , Kelly Ian
Published: December 2007

The paper describes the approach taken by an independent provider of well construction and well management services, and how this has developed over the last nine years. The essential elements for a successful project outcome for both operator and the various contractors involved are discussed.

The importance of getting early agreement on and definition of the scope of work will be emphasized with examples given of the variety of workscopes currently existing under the much abused "Integrated Services" banner and the flexibility of approach required to be a competitive supplier of such varied workscopes.

The process used in determining the appropriate bid strategy will be explored, including selection of alliance or sub contractor partners, objective setting and resource allocation. The issue of bid preparation costs will be discussed with suggestions on how this can be reduced and/or more equitably shared.

Issues relating to the risk aspect of managing Integrated Services, including underwriting joint and several liabilities arising and the risk relationship between the Operator, Integrated Service provider and subcontractor.

The organization of an Integrated team which combines the skills requirement with the available resources from all participants requires careful consideration at the earliest stage. Information transfer in the form of verbal, written and electronic communication must be cost effectively provided without in built barriers or duplication created out of traditional thinking.

The future development of the business relationship between operators and contractors will be discussed from an integrated services perspective. It is concluded that this relationship will develop positively if there is a common understanding of what constitutes a fair return on investment for all parties and a reasonable sharing of the gains or "profits". Bidding Strategies in the North Sea context will be discussed with suggestions as to how Operators could benefit from earlier involvement of contractors e.g. by discussing the possibility of factoring in overall cost reduction potential for new technology equipment which may have a higher unit cost.

The authors will draw from experience of providing integrated services in the North Sea over the last 9 years to discuss and demonstrate the foregoing issues.
Renewal Efforts In the Gulf of Suez
Authors: Fattah Emad Abdel
Published: December 2007

From late 1993 forward, Gupco has accelerated its Renewal process. A primary feature of this process has been the development of a staff of Gupco employees who have the capability to manage work processes using principles of continuous improvement (CI) and Total Quality Management (TQM). EGPC and Amoco have provided support for this process, agreeing that Gupco should strive for preeminence among joint venture operations in the world-wide petroleum industry. The results of these efforts – from accumulated data and dominant impressions – indicated that Gupco's and Shareholders' benefit from Renewal was great. Gupco will continue to implement renewal and progress and will continue to share this fruitful experience with others.
Environmental Performance Indicators Applied to the Norwegian Oil and Gas Industry
Authors: Rye Henrik , Celius Harald , Husdal Geir , Guttormsen Ralph
Published: December 2007

Environmental Performance Indicators are considered for application to the oil companies operating on the Norwegian Continental Shelf. The indicators considered apply to performance of the industry with respect to the external environment (like air and water releases and the different impacts from these). The starting point is the "core set of environmental indicators" proposed by OECD in 1994. This set has later been modified by the Nordic Countries of Ministers to be applied within the Nordic Countries. The present paper explains an attempt to apply these indicators to the oil and gas industry operating on the Norwegian Continental Shelf. The paper concludes that the indicators proposed have to be adjusted to the specific conditions that the oil and gas industry are operating under, reflecting the actual reservoir, production and the need for transport of hydrocarbons for each separate field development.
The Environmental Case - An Holistic Approach to Managing the Environmental Impacts of the Offshore E&P Industry
Authors: Duff A. A. , Appelbee J. F. , Booth M. J. , Walls A. H. , Whitehead A.
Published: December 2007

There is a distinct lifecycle sequence to the activities involved in the discovery and development of offshore oil and gas reserves. This sequence begins with licence acquisition then seismic survey, exploration and appraisal drilling, design and construction, production operations and finally decommissioning. Current industry environmental management practice typically considers the licensing and exploration phases separately. However it is now widely recognised that this approach can be improved by considering the entire lifecycle, and by adopting a risk-based, "fit-for-purpose" Environmental Case approach.

Essentially the Environmental Case approach involves the application of the company Environmental Management System to a specific project throughout its lifecycle. As a structured document it will specifically contain:- a description of the environment, a description of the activities being undertaken, an assessment of the potential impacts of these activities to the environment, a description of the mitigation/control measures proposed to minimise impacts to an acceptable level, the operational management activities necessary to implement these measures, and the monitoring and reporting actions in place to record the effectiveness of the management programme and compliance with the planned activities. Whilst there are parallels with aspects of the now familiar Safety Case, there are also significant differences.

The mechanisms of this holistic approach have still to be developed, however the benefits to the industry are numerous.
Core and Log Determination of Residual Oil After Waterflooding - Two Case Histories
Authors: Strange L.K. , Baldwin W.F.
Published: December 2007

Two sandstone fields which are approaching the economic limit for waterflooding were considered as locations for improved waterflood recovery tests, and evaluations were made of the in-place oil saturations after secondary waterflood, using both coring and logging techniques. Core saturations were measured by an extraction technique. Induction electric logs were utilized for determination of in-place saturations.

Logging results were in good agreement with the in-place oil saturations determined by material balance calculations and with some of the flood pot test data. Despite careful attention to coring and core handling techniques, oil saturations measured in the cores in all cases were substantially-lower than saturations determined by log analysis. It appears likely that most of the loss of Oil saturation occurred due to gas expulsion as the cores were retrieved from the well bottoms, though lower saturation values in poorly consolidated cores suggests that poorly consolidated cores suggests that flushing also was a problem.

Use of low fluid loss coring muds in conjunction with a pressure-type core barrel should provide much better oil saturation information in waterflooded cores than is possible using conventional core barrels.

Introduction

While secondary recovery water injection frequently is a particularly effective means of increasing recovery from an oil reservoir, the fact is that a substantial quantity of oil usually remains in the reservoir at the economic limit of water injection. The average residual oil is perhaps one-third of the original oil. Interest has developed in directing some of the new improved recovery processes (e.g., miscible flooding, processes (e.g., miscible flooding, fireflooding, chemical additive waterflooding) toward recovery of this residual oil.

All of the improved recovery processes are costly, either as a consequence of utilizing expensive materials for injection, or because of the high cost of injection of compressible fluids. When the expensive injection operation is coupled with high field operating costs attendant with high water cuts, old wells, and worn or obsolescent equipment, the economic outlook is frequently less than attractive. A key feature in measuring economic potential is of course the expected oil production rate, which is related to the quantity of oil in place.
Measurement of Aldehydes in Internal Combustion Engine Exhaust
Authors: Shareef Gunseli Sagun , Ogle Larry , Ferry Kathy , LaCosse Jeff , Johnson Kevin , McCarthy James
Published: December 2007

In the 1990 Clean Air Act (CAA), Congress included provisions to reduce emissions of hazardous air pollutants (HAPs) considered to pose a risk to human health and the environment. The U.S. Environmental Protection Agency (EPA) defined a schedule for developing air toxic regulations for various source categories, including a target promulgation date of 2000 for stationary internal combustion (IC) engines. To assist the gas industry to respond to these and other upcoming federal and state regulatory requirements, the Gas Research Institute (GRI) is investigating air toxic emissions from natural gas industry sources. Based on the results of Phase I of this research, IC engines have been identified as a high priority source, due to the potential for emissions of formaldehyde. This paper summarizes the results from GRI's ongoing effort to evaluate HAP emissions from IC engines, including the new measurement method developed to measure formaldehyde.
Control Device Monitoring for Glycol Dehydrator Condensers: Testing and Modeling Approaches
Authors: Beitler C. M. , Reif D. L. , Rueter C. O. , Evans James M.
Published: December 2007

The Maximum Achievable Control Technology (MACT) standards for the oil and natural gas industry are expected to be proposed in early 1997, with promulgation later in the year. These standards will include "control device monitoring" requirements to show that controlled sources are in "continuous compliance" with the MACT standard. Since condensers are the most widely used control option for glycol dehydrators, the monitoring requirements for condensers are of particular interest; this requirement may include recording the condenser outlet temperature. Performance testing on all condenser units may be required to establish the appropriate site-specific temperature that indicates whether a unit is achieving the desired level of control.

Computer modeling is a less expensive and more flexible alternative for establishing this temperature and defining a site-specific condenser curve, but this approach has not previously been validated through field measurements. Gas Research Institute (GRI) has initiated a field condenser test program to collect the data necessary to validate the use of computer programs, such as GRI-GLYCalc™ and commonly available process simulation packages, in predicting glycol dehydrator vent condenser efficiency. A series of nine test, at seven sites have been conducted to collect these data.

This paper will present the results of the field testing (performed on several different condenser types, including air-, glycol-, and water-cooled systems), and make comparisons to the modeling results. The paper will also include general information on the key process parameters affecting condenser performance.
Absorption of BTEX and Other Organics and Distribution Between Natural Gas Sweetening Unit Streams
Authors: Skinner F. D. , Reif D. L. , Wilson A. C. , Evans J. M.
Published: December 2007

Amine sweetening units are widely used in the gas industry to remove acid gases (H2S, other sulfur species, and/or CO2) from sour natural gas. Field and laboratory measurements have shown that VOCs and HAPs present in the natural gas are partially absorbed into the lean amine solution. Depending on composition of the natural gas entering the sweetening unit and the gas throughput, these units may represent a significant source of VOC and HAP emissions if the acid gas stream from the amine regenerator is discharged directly into the atmosphere. This paper presents measurements from six field tests showing the amounts of VOCs and HAPs (primarily BTEX species) absorbed by amine solutions and the distribution of these species between flash gas, regenerator overhead gas, and lean amine streams.
Title V and the Exploration and Production Industry: DOE Seeks to Reduce Cost through Outreach and Technology Transfer
Authors: Frederick J. D. , Weaver M. S. , Alleman D.
Published: December 2007

In early 1996, the United States Department of Energy commissioned the development of Guidance Manuals to assist oil and gas exploration and production operators in understanding and complying with the new permitting requirements mandated by Title V of the 1990 Clean Air Act Amendments. The objective of the program was to reduce the compliance costs associated with the Title V program through outreach and technology transfer. Guidance Manuals were constructed for fifteen states containing significant oil and gas exploration and production activities. Phase II of the project contemplates the completion of the outreach effort through development and implementation of hands-on training classes.
Characterization of Current U.S. Exploration and Production Facilities and Waste Management Practices
Authors: Smith G. E. , Gopinath A. , Freeman B.
Published: December 2007

In 1985, the American Petroleum Institute (API) conducted a survey of the U.S. exploration and production (E&P) industry to collect data on volumes of wastes being generated and current waste management practices. This study, now over a decade old, remains the primary source of data on wastes and waste management. Knowing that industry waste management practices have evolved since the mid-1980s, API decided to update this survey in order to characterize current practices and facilities. Besides wastes and waste management, the study also characterizes, for the first time, much of the equipment at E&P sites that may contribute to air emissions. This information will provide valuable input about the nature of industry operations to regulations currently planned or under development to control emissions. The purpose of this paper is to describe API’s current industry survey, the methodology used, the current status of the analysis, and provide initial observations based on responses received to date. The paper also includes a discussion of API’s planned uses for the survey results.
Technology Alone is Not the Answer
Authors: Cook William S.
Published: December 2007

The regulatory program for oil and gas operations conducted on the Federal OCS is administered by the Minerals Management Service (MMS). Those regulations are based upon the use of best available and safest technology. The program is intended to ensure a balance between orderly oil and gas development and protection of the environment. Simply complying with those regulations does not ensure safety and environmental protection. The technology must be integrated into the human environment of the operator through a system safety management approach to be most effective.
Right-to-Know Reporting for the Oil and Gas Exploration and Production Industry
Authors: Rubin Mark A. , Petten Kim M.
Published: December 2007

The United States Environmental Protection Agency (EPA) is considering whether to expand the Emergency Planning and Community Right-to-Know Act of 1986 Section 313, the Toxics Release Inventory, to include the oil and gas exploration and production (E&P) industry. EPA has indicated that an Advanced Notice of Proposed Rulemaking on expansion of the TRI program to the E&P industry may be published by mid-1997. Expansion of the TRI program to the E&P industry would be expected to create an extensive administrative burden and other associated costs. The Interstate Oil and Gas Compact Commission recently completed a report on the existing reporting requirements for the oil and gas E&P industry. The IOGCC makes it clear that the information currently being reported for state and federal regulatory programs provides adequate public information regarding E&P operations.
An Internal Compliance Review Program
Authors: Coppersmith B. B.
Published: December 2007

An oil company's new internal review program has proven extremely successful, resulting in an increased level of safety and environmental performance. The key goals of the program are to provide periodic third party review of both management and operations systems and to provide employees with an opportunity to became more knowledgeable about compliance issues, thereby elevating their level of safety and environmental awareness and subsequent performance. These goals are accomplished through a team of operations, engineering, legal, financial, drilling, and safety, health, and environmental (SH&E) personnel identifying key issues, developing common strategies, sharing information, and recommending courses of corrective/improved actions.

Management support is crucial to the process, manifesting itself in commitment of resources and personnel, but several other critical components exist: documentation of compliance against procedures, policies, rules, and regulations; consistency of these standards and their applications; objective and periodic review; timely feedback of review results; timely resolution of corrective measures; and attorney client privilege.
New Technology for Prevention of Sour Oil and Gas
Authors: Hitzman D. O. , Dennis D. M.
Published: December 2007

The occurrence of sulfide in gas wells is a major problem for the oil and gas industry. Sulfide causes production and revenue loss, increased corrosion, and is a serious environmental hazard. A new low cost technology has been field demonstrated which both remediates sulfide in oil and gas wells and additionally prevents the ongoing biogenic formation of sulfide in the well. This treatment system is based on the biocompetitive exclusion of the sulfide generating (sulfate reducing bacteria) microbial population by its replacement with a beneficial indigenous microbial consortium. This enhancement of an already existing microbial population requires only the addition of a selected nutrient salts formulation. The inorganic salts composition is tailored to maximize the treatment response and minimize treating levels. Treatment of producing wells with low concentrations of these water soluble nutrients has shown a long term control of sulfide in field tests sponsored by the Department of Energy. Levels of sulfide can be reduced to zero and can be maintained at low levels with periodic treatments. The effectiveness of these treatments as demonstrated by sulfide reduction measurements is illustrated by field examples. The technology offers oil and gas producers a new low cost methodology to successfully treat wells with sulfide problems.
Assessment of the Subsurface Environmental Fate of Amines Used by the Gas Industry
Authors: Sorensen J. A. , Hawthorne S. B. , Gallagher J. R. , Thompson J. S. , Harju J. A. , Evans J. M. , Chollak D.
Published: December 2007

Atkanolamines are commonly used by the natural gas industry to remove acid gases from the natural gas stream. At gas processing plants that use alkanolamines for acid gas removal (AGR), spills and the on-site management of wastes containing alkanolamines and their associated sludges have commonly resulted in subsurface contamination that is presently the focus of some environmental concern. Research has been conducted by the Energy & Environmental Research Center that examines the subsurface transport and fate of the most commonly used alkanolamines, namely, monoethanolamine (MEA), di- iethanolamine (DEA), and methyldiethanolamine (MDEA), and process-derived sludge from AGR units that utilize each of those compounds. Experimental activities were conducted that can be grouped into three areas: 1) qualitative, semiquantitative, and quantitative characterization of alkanolamine-derived sludges; 2) investigations of the interactions of MEA, DEA, and MDEA with soils; and 3) activities investigating the biodegradability of MEA, DEA, MDEA, and associated sludges. Characterization of the sludges was performed using gas chromatography coupled with mass spectroscopy (GC-MS). In order to examine the potential effects of different soil types on subsurface transport and fate, investigations of interactions between alkanolamines and soil and of biodegradation of alkanolamines and process- derived sludges were performed using soils collected from Louisiana, New Mexico, and Alberta. These areas were selected to represent not only three unique soil types, but also to represent three regions of North America that produce an abundance of "sour" natural gas. The results of this research provide the natural gas industry with data and insights that will enable them to 1) significantly improve the assessment of subsurface alkanolamine-related contamination where it is known or suspected to occur and 2) make soundly based decisions concerning the remediation of that contamination.
Alternative Approaches for the Determination of Environmentally Acceptable Endpoints (EAEs) for Contaminants in Soil
Authors: Nakles D. V. , Roose T. R. , Hayes T. D.
Published: December 2007

The environmental closure of sites requires the establishment of contaminant concentrations that can be left in the soil and groundwater. It must be demonstrated that these concentrations, otherwise known as environmentally acceptable endpoints (EAEs), are protective of both human health and the environment. Due to the complexity associated with the soil-contaminant interactions, the release and movement of contaminants in the subsurface environment, and the different mechanisms of contaminant uptake by living organisms, no single approach for the establishment of EAEs has evolved. For example, to date, alternative measures of EAEs for contaminated sites have focused on several direct, and indirect, measurements of reduced contaminant availability: (1) the lack of availability of soil-bound contaminants to microorganisms, (2) the lack of toxicity of the soil-contaminant matrix to test organisms, and (3) the lack of mobility of soil-bound contaminants to the environment. Intrinsic processes of contaminant biodegradation and sorption in the subsurface environment have also been incorporated into these definition of EAEs. The Gas Research Institute (GRI), in conjunction with the Petroleum Environmental Research Forum (PERF), has compiled and summarized the results of the field applications of several of these approaches to hydrocarbon- impacted sites. This paper presents several case studies that demonstrate the use of the different measurements of reduced contaminant availability for the closure of sites contaminated with hydrocarbons.
Reserve Analysis and Economic Evaluation of Wasatch/Mesaverde Reservoirs, Greater Natural Buttes Producing Area, Southeastern Uinta Basin, Utah
Authors: MacMillan Logan
Published: December 2007

The Greater Natural Buttes (GNB) is located in the southeastern Uinta Basin of northeastern Utah. Cumulative production of the nonassociated gas of the producing area is 521 MMCF(1) and has been described as a continuous-type(2,3) or basin-centered gas accumulation. The GNB includes the Chapita Wells, Ouray, Natural Buttes, Island, and River Bend Federal Exploratory Units (Figure 1). The GNB field presently includes more than 880 producing wells, encompasses an area of 345,000 acres, producing from multiple fluvial sandstones in the Tertiary Wasatch and the Upper Cretaceous Mesaverde Formations. Since 1990, more than 350 additional wells have been drilled within GNB as infill development wells on an effective spacing of 80 acres, although the full development of the field area is not yet complete on this spacing pattern. There are three main operators in the field, with several additional operating companies around the perimeter of the field, as it is defined today.

The eastern limit of the Natural Buttes field has been defined generally by the economic limit of Wasatch and Mesaverde gas production. Data presented in the Utah Geological Association's 1992 Uinta Basin Guidebook show that the economic limit of Natural Buttes production(4) is related to the thermal maturity of that field's source rocks: the coal-rich beds in the basal Mesaverde Formation(5,2). Drilling activity in the GNB in 1991 and 1992 increased dramatically over the previous five years, due in part to tax incentives allowed for gas produced from formations designated as "Tight."

The Uinta basin contains some of the largest accumulations of oil and gas in any of the Western Interior basins, with production, indesending order, from the Tertiary Uinta Formation (gas), Green River Formation (oil and gas), Wasatch Formation (gas), and the Upper Cretaceous Mesaverde Group (gas). Figures 1 & 2 show diagrammatically the location of the significant gas producing fields: Natural Buttes and Island fields, as well as the other mlijor oil-producing fields in the Uinta and Piceance basins.
Economic Evaluation in the Courtroom: The Problem with Some Experts
Authors: Richard J.
Published: December 2007

This paper will examine the influence of some recent court decisions on the preparation and presentation of scientific and technical evaluation as part of expert witness and other testimony amid the mounting concern about "junk science" in the courtroom. The implications of the Daubert and Robinson decisions, will be discussed in terms of the geologic and engineering evaluation of oil and gas properties and projects which may be used for expert witness testimony or which have the potential to end up in civil or administrative litigation. The Daubert decision, in particular, has resulted in considerable review of the common practice of relying on methods deemed to be "generally accepted" and had required some, but not all, courts and other judicial bodies which are subject to court review, to adopt more restrictive standards. These new standards include demonstration of the sources of supporting and derivative information, determination of error rates for the analytical methods used, and demonstration of the acceptance of the evaluation methods used among knowledgeable persons in the field This paper will explore the application of these standards to examples of evaluation for geologic prospect development, in reservoir engineering analysis of EOR reserves, and in the development of economic parameters such as price/cost projections, comparable sales analysis, and discount rates for use in economic evaluations for tax or other purpose.
Acquiring Producing Properties Via Oil & Gas Auctions
Authors: Gibbs J. A.
Published: December 2007

Oil and gas auctions were relatively uncommon before 1987. Since then the auction market has grown at a rate of almost forty percent annually, and auctions have become a useful and accepted method of buying and selling producing interests. Thousands of properties, totaling almost $200 million, are anticipated to be committed to auctions in 1997.

Auctions provide advantages to both sellers and buyers. For sellers, they offer a quick and convenient means of "rationalizing" lower value, non-operated or geographically dispersed interests. For buyers, bids are transparent, against other willing bidders. Titles pass the day of the auction, eliminating the delays inherent in negotiated sales.

Disadvantages exist. Lack of time or data for sufficient due diligence increase the risks of mistakes. Nevertheless, for many buyers the opportunity to acquire good properties at reasonable costs outweigh concerns.
Determination of the Residual Oil Saturation in Two Aux Vases Sandstone Reservoirs
Authors: Sandiford B.B. , Eggebrecht N.M.
Published: December 2007

In order to determine the residual oil saturations in two sandstone reservoirs that were considered for tertiary oil recovery projects, test wells were drilled and the projects, test wells were drilled and the reservoirs were cored and logged. Both oil fields are located in South Central Illinois, and they had been under waterflood for about ten years. In one case the reservoir was cored by a special pressure core barrel that was developed by Esso Production Research laboratory; this same well was logged by an electric log and by a neutron decay time log. The oil saturations measured in the water swept areas of these two reservoirs ranged from 6% to 26% of the pore space.

Introduction

Material balance calculations show that many millions of barrels of potentially recoverable tertiary reserves are in Aux Vases sand reservoirs in the Illinois Basin. These reserve calculations are based on a residual Oil saturation equal to about 25 percent of the pore volume after waterflooding. Aux Vases sands are more uniform than most reservoir sands that we have studied, but interbedding of small gray shale laminations and variations in carbonate cementing material has caused heterogeneities. This heterogeneity and also the well locations affect the flow of fluids during primary and secondary recovery operations. It is possible that a large portion of the residual oil is retained in the periphery of these reservoirs and outside the well patterns; however, we are primarily interested in the residual oil that remains in areas between wells. We should be able to move this oil by miscible displacement, but we need to determine if this can be done economically, and the economics depends to a great extent on the oil saturation in the swept areas. In this paper we describe our methods for evaluating two Aux Vases sand reservoirs before selecting a test site for a tertiary recovery process. We were interested in finding a test process. We were interested in finding a test area in the Aux Vases reservoir that contained a typical residual oil saturation so that a tertiary recovery process could be applied to other similar areas. We used three common basic methods for determining oil saturations in the two areas.
An Optimization Model for Allocating Capital to Business Segments in an Integrated Oil Company
Authors: Burness G. C. , Fryer V. I. , Gupta R. K. , Novotnak J. F.
Published: December 2007

Capital investment strategies are being analyzed within an integrated oil company utilizing information from a mathematical model which determines optimal allocations of single and multi year capital outlays that will maximize the net worth of the company over a long term horizon. The optimal processes focus on an economic profit measure which is closely related to net present value or market value added when applied to any business segment or operating level within the company. It provides a more robust and comprehensive measure of value created for the shareholder than more traditional financial and accounting measurements such as net income, cash flow, earnings per share, or return on assets. The optimization model is described and the theoretical aspects and application of the economic profit measure are discussed.
The SPE/WPC Reserve Definitions: The Impact on Past and Future Reserve Evaluations
Authors: McMichael Claude
Published: December 2007

Petroleum reserves are one of the most fundamental elements in the international petroleum industry. To the producing company, reserves are the asset base from which future profits and investment capital will be derived. To the investor, they are a reflection of the financial strength of a company and an indication of future growth potential. For a government, they are a major source of energy and a key factor in the continued development the country’s economy. It is essential for future planning that both governments and industiy have a clear understanding of the quantities of oil and gas available for production, as well as, those quantities which are anticipated to become available through additional field development, technological advances, and exploration. To achieve such an assessment, the industry needs a simple and widely understood nomenclature for classifying the current and future quantities expected to be recovered from petroleum reservoirs based on the likelihood of their commercial recoverability.

Over the past sixty years, numerous technical organizations, regulatory bodies, and financial institutions have introduced nomenclatures for the classification of petroleum reserves. In 1987, the Society of Petroleum Engineers (SPE) and the World Petroleum Congress (WPC), working independently, developed sets of reserve definitions which were strikingly similar in most key aspects. Both gained wide acceptance and have become the preferred standards for reserves classification across much of the industiy. Soon after their introduction, it became apparent to both organizations that these two could be combined into a single set and that such a development would improve consistency in reserves evaluation and reporting across the industiy. Contacts between representatives of the two organizations started shortly after the publication of the initial sets of definitions and were increased in June 1994. A joint Task Force was established between the SPE, under the guidance of the Oil and Gas Reserves Committee, and the WPC with the assignment of drafting the joint definitions. This effort was completed in the July 1996 and the draft proposals distributed for industry review and comment in August 1996. The revised draft was submitted for consideration to the SPE and WPC Boards of Directors in February 1997.

This paper will review the efforts of the SPE/WPC Task Force and highlight the significant differences between past definitions and those now being proposed. It will, also, address the impact the changes will have on industry, discuss implications for existing reserve estimations and bookings, and highlight several outstanding reserve issues not addressed in the current proposal.
The Philosophy of Reserve Estimation
Authors: Ross J. G.
Published: December 2007

The recent publication for discussion of the SPE/WPC draft reserve definitions1 has highlighted the difficulty in attempting to relate deterministically-derived reserve estimates with those based on a probabilistic methodology. Although the debate over the benefits/disadvantages of the two estimation approaches will no doubt be rekindled, a more fundamental issue is that of the difference between an "incremental" (or risk) based philosophy to reserve estimation and a "Best Estimate" (or uncertainty) based one.

The current SPE definitions2 are based on an incremental philosophy where Proved reserves are "reasonably certain", Probable reserves are "less certain" than Proved reserves and the summation of Unproved (Probable and Possible) reserves with Proved reserves is precluded "because of different levels of uncertainty". The use of "uncertainty" in this context really reflects risk. This philosophy is perfectly acceptable and has been the fundamental basis of reserve estimation (especially in the USA) for many years; however, it is not directly comparable to the philosophy on which the probabilistic approach is based.

The Best Estimate philosophy reflects the hypothesis that the primary objectives of reserves estimation are (a) to make the best estimate possible as to what hydrocarbon volumes will actually be recovered up to field abandonment, and (b) to assess what is the uncertainty in that estimate. This philosophy is inherent in the probabilistic approach, but it is clear that the deterministic methodology can also be (and is) applied using this logic. If the Best Estimate philosophy is applied, deterministic and probabilistic reserve estimates may be comparable (in theory at least).
Comparison of Finite Volume Schemes for Reservoir Simulation on Unstructured Grids: Application to Productivity Index Calculations
Authors: Trujillo D. , Blanc G. , Estebenet T. , Quettier L. , Thomas J.-M.
Published: December 2007

Comparison of Finite Volume Schemes for Reservoir Simulation on Unstructured Grids: Application to Productivity Index Calculations D. Trujillo, University of Pau, G. Blanc, SPE, IFP, T. Estebenet, IFP, L. Quettier, SPE, EAP, and J.-M. Thomas, University of Pau

Introduction

In reservoir simulations, it is difficult to choose among the great number of numerical methods adapted to solve diffusion equations in porous media. A solution may seem to satisfy reservoir simulation constraints while numerical dispersions or axis effects may discredit it completely. In the absence of general analytical results, numerical tests were could help the user choose a method for his specific application even though conclusions arising from these numerical tests rely greatly on the case treated. Nevertheless, it is very useful to consider some advantages and disadvantages of each numerical method, in order to be able to choose the best adapted one each particular application.

Finite element methods

There exists a great number of finite element methods. They are most often used to solve elliptic equations of the form - div(K P) = f or parabolic equations, for instance in the case of single phase flow. In fact, when it is possible to split the equations into a set of hyperbolic equations and a set of parabolic or elliptic equations associated with the pressure, a finite element method can be used to discretize the pressure equations. This approach is particularly suitable in the case of two phase incompressible flow.

Firstly, we obtain an approximation Ph for the pressure P, which uses piece-wise polynomial bases functions. From Ph we compute the velocity of filtration and then the saturation. A better approximation of the velocities can be obtained when considering them as unknowns in the pressure equations. This method is the so-called mixed finite element method.

Finite elements have been preferred to finite differences in recent years, because of their flexibility when dealing with irregularities in both geometry of domain and position of nodal points. Unfortunately, in the case where there is no possibility of splitting, the finite element schemes lead to numerical instabilities which necessitate the subsequent use other numerical schemes such as finite volume methods. Finite volume methods

There are two great classes of finite volume methods. The simplest one, in terms of programming, is the Control Volume Finite Difference (CVFD) method. However it cannot be applied on general domains.

The second class which is described here is the Control Volume Finite Element (CVEE) method, introduced to overcome the lapse of flexibility. Given a triangulation related to the pressure (with triangles or tetrahedrons), we build a control volume associated with the saturation around each vertex : for each triangle T of the triangulation, we consider an arbitrary point aT of T.

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