bluuebunny/crossref_metadata_2025_split huggingface dataset:
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.

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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.