bluuebunny/crossref_metadata_2025_split huggingface dataset:
Selection of a Waterflood Pattern for the Jay-Little Escambia Creek Fields
Authors: Shirer J.A. , Ainsworth W.J. , White R.W. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Abstract
A Three-to-One Staggered Line Drive pattern was selected to initiate the pattern was selected to initiate the waterflood in the Jay-Little Escambia Creek Fields of northwest Florida and southern Alabama. This pressure maintenance program should recover in excess of 200 program should recover in excess of 200 million stock tank barrels of oil over primary operations. primary operations

Introduction
The Smackover-Norphlet Reservoir in the Jay-Little Escambia Creek Fields of northwest Florida and southern Alabama was discovered in June 1970 and is the largest oil discovery in the lower 48 states in the last two decades. Original-oil-in-place was in excess of 700 million stock tank barrels. The reservoir is located below 15,000 feet and contains a volatile, sour crude which is highly undersaturated. Production was initiated in December 1970 after sweetening facilities were installed.
A reservoir study conducted in mid-1971 indicated that there was little likelihood a natural water drive would be effective and that primary recovery would be low. Unitization and pressure maintenance were urgently needed to maintain productivity and increase ultimate oil recovery. The recovery potentials of several types of fluid injection potentials of several types of fluid injection processes were evaluated using two-dimensional processes were evaluated using two-dimensional computer simulation. Screening studies indicated that waterflooding was the most appropriate recovery process.
In early 1972 evaluations were begun to determine the optimum waterflood pattern using two-dimensional reservoir simulation and a 3:1 Staggered Line Drive was selected to initiate the waterflood. A three-dimensional reservoir model was constructed in mid-1973 to confirm the effectiveness of the 3:1 Line Drive pattern prior to converting flowing oil wells pattern prior to converting flowing oil wells to water injection service.
Results of early reservoir simulation were used to design and justify ordering long delivery waterflood equipment concurrent with field development and unitization. The effective date of the Unit was March 1, 1974, and water injection was initiated four days later on March 5, 1974.
This paper presents the methods used to select the optimum waterflood pattern to initiate the pressure maintenance program for the Jay-Little Escambia Creek Fields.
A New Approach for Enhancing Fracture Conductivity
Authors: Nguyen P.D. , Dewprashad B.T. , Weaver J.D. 
Published: December 2007

Abstract
A new liquid surface-modification system has been developed for coating proppant, dramatically increasing its surface friction and allowing it to interact instantaneously with surrounding particulates. High surface friction between the coated proppant grains allows them to withstand high flow rate, minimizing their flowback potential after fracture-stimulation treatments. According to field results, when this surface-modification material was used as a flowback-control agent after conventional fracturing treatments, it permitted more aggressive flowback procedures. This treatment did not impair conductivity, and in fact, increased proppant conductivity at closure stresses below 4,000 psi (27 600 kPa). Better vertical proppant distribution occurred in experiments that demonstrated how the surface modification significantly hindered proppant settling. Fines that already existed within the proppant (generated from the formation or derived from crushed proppant upon fracture closure) all adhered to the treated proppant, which inhibited them from migrating and blocking the pore throats of the proppant pack. This unique coating technology further enhanced conductivity by improving frac-gel breaker action in certain fluids. This behavior results in faster, more effective well cleanup after stimulation.
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Meeting the HSE Challenge
Authors: Mohamed Zarei B. 
Published: December 2007

Abstract
Petronas Carigali (PC) visions to be a multinational E&P company of choice in all areas including HSE. To advance in this effort, PC developed its Health, Safety and Environment Management System (HSEMS). PC believes in top management commitment, integration of HSE into its core business and total involvement by all including contractors. HSE which has already been accepted as line responsibilty was further strengthened by making supervisors accountable for incident reduction, regardless of company or contractor personnel. Every individual in PC promotes, practices and participates in HSE. In 1995, various HSEMS models were studied to develop a model that suits PC. During the process, stakeholders discussions were held to ensure agreement and buy-in. In 1996, PC was rated as one of the best three worldwide by E&P Forum with LTIF rate of 0.87 per million manhours and Total Recordable Cases Frequency (TRCF) rate of 1.94 per million manhours for combined company and contractor personnels. In 1997, PC bettered its LTIF and TRCF performances to 0.24 and 1.43 per million manhours respectively. The paper will discuss on the elements incorporated into PC HSEMS and the key work areas that made PC rated amongst the best.. It will also touch on PC's HSE philosophy for its international operations.
Use of Guar Gum and Synthetic Cellulose in Oilfield Stimulation Fluids
Authors: Anderson Robert W. , Barker James R. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.
Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Abstract
The use of polysaccharides to alter the rheological properties of aqueous fracturing fluids has been a common practice for many years. In certain cases the inherent properties of these natural and synthetic polymers have been negated by their sensitivity to adverse parameters present in both the base fluid and the formation. Some of these parameters have been identified as ionic strengths, transition metal concentrations, high bottom hole temperatures, and chemical redox systems.
Chemical solutions to these problems, which eliminate or minimize the detrimental effects, have been developed for field operations. Once the problem has been recognized and defined, an appropriate chemical treatment will usually make the field water usable, bypassing the necessity of finding an alternate supply. The specific treatment will depend on whether the end product is to be the polymer sol or a complex gel. Additional beneficial effects have been observed as a result of at least two of these chemical treatments. Higher base viscosities of the polymer sol and less polymer sensitivity to the ionic strength of the field polymer sensitivity to the ionic strength of the field waters have been noted in several instances. Exceptional polymer stability at higher temperatures has been obtained polymer stability at higher temperatures has been obtained with one procedure. This has effectively extended the usefulness of several polysaccharides at higher bottom hole temperatures. This paper presents a description of the various polysaccharide systems, their sensitivities, and the methods employed in countering these sensitivities.

Introduction
Since its inception, the art of hydraulic fracturing has employed an extensive array of fluids and systems. Polymers were initially developed to reduce pumping Polymers were initially developed to reduce pumping friction losses. Almost simultaneously, polymers were found useful in improving propping agent transportability and placement. The efficiency of frac fluids was later improved by additives which controlled fluid leak-off in more permeable reservoirs and in this role polymers were found to play an important part. More recently, the search for further improvement in fluid loss control, proppant transport and placement, and fracture extension proppant transport and placement, and fracture extension brought about the use of crosslinking agents to form super-viscous gels where three-dimensional networks are produced in the polymer solution. produced in the polymer solution. Howard and Fast reported properties which a frac fluid should possess.
Reservoir Management Making a Difference in Australia's First Oilfield Developed Entirely with Horizontal Wells
Authors: Allard D.N. , Sawiris R.S. 
Published: December 2007

Abstract
The Roller and Skate oil field is located 13 miles south-southwest of production facilities at The venard Island and 4 miles from the mainland coast of Western Australia. Roller was discovered in 1990, and Skate the year after. Production began in 1994. Roller and Skate original oil in place is approximately 77 million barrels.
Roller and Skate reservoirs are complicated by different oil/water and gas/oil contacts, 3 different gas caps within Roller and 1 within Skate, and distinct differences in oil/gas gravity and chemical composition. Net oil pay is up to 56 feet within friable sands of the Barrow Group Formation.
The paper will discuss the various development options considered, final selection, and achievements made in drilling and facilities installation.
The uncertainties overcome prior to development were; structural uncertainty due to limited well control and poor quality 3-D seismic, uncertainty of formation integrity to support barefoot horizontal completions, and uncertainty of aquifer support. In addition, effective gas-management was critical as government policy required no flaring of free gas.
This paper will highlight reservoir management practices that are being used to optimise current and future performance.
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Case History of a Marginal Oil Field Development
Authors: Soetedja V. , Suyana D. , Kontha I.N.H. 
Published: December 2007

Abstract
Development of a marginal oil field offers a unique set of challenges. These challenges were experienced in the development of VICO's Semberab Field, located in East Kalitnantan of Indonesia Semberab Field was originally thought to be a small oil accumulation in a mainly gas area; therefore, the facilities and development plans were conceived around a target of 5,000 BOPD. However, an aggressive development effort which included, in addition to moderate drilling and re-completions, an ongoing cost effective production optimization effort of both surface facilities and downhole completions have resulted in maintain the oil production at a level of more than 12,000 BOPD for the last five years.
This paper presents example of the ongoing development process of the Sembenrab field. Under a complex geological environment and multi-layered sandstone reservoir, the thin non-continuous oil sands encountered were initially developed without detailed planning. Rather than being driven by reservoir studies to guide the delineation program, the life of the field is extended by cost effective production optimization that in turn encourages further reservoir review.
The optimization efforts have resulted in several significant upward reserve revisions of the Semberah field. The whole field is now re-mapped with a probabilistic method in an afterupt to capture the uncertainty of the sand development. Future efforts for additional improvement will be centered on a newly instituted multi-discipline asset team.
P. 175
Propped Fracture Geometry of Three Hydraulic Fractures in Sydney Basin Coal Seams
Authors: Jeffrey R.G. , Vlahovic W. , Doyle R.P. , Wood J.H. 
Published: December 2007

Abstract
Three propped hydraulic fractures, placed in coal seams from vertical wells, were recently mapped as the coal mine workings passed through the site of the wells. The fractures were propped with sand and, in each case, the geometry of the propped fracture was mapped during mining as it was exposed on the roof, floor and rib (sides) of the mine openings. Permeability, stress, and structural data were collected at each site so that the fracture geometry could be assessed against these site characteristics.
The fractures at all three sites were affected by pre-existing joint and cleat fractures in the coal. Some degree of multiple subparallel fracture development occurred in each case, with the fracture at Appin being the most complex. At Appin and Munmorah the hydraulic fractures propagated along the direction of the face cleat, while at Dartbrook the fracture followed the major vertical joint direction which cuts across the face cleat direction at an angle of about 30 degrees. The fracture at Appin was contained to the seam and the fracture at Munmorah grew into the floor rock but then became horizontal. At Dartbrook, the Wynn seam is part of a thick mega seam and the hydraulic fracture grew into the over- and underlying coal, which is left unmined.
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Post-PSCs Business Development Opportunities
Authors: Yusoff Samsudin Mohamed , Kario Mohamed Wahid 
Published: December 2007

Abstract
Some of the early Malaysian Production Sharing Contracts (PS Cs), in particular those signed in the mid 70s have expired or are expiring. These PSCs have either been replaced or are in the process of being replaced with new arrangements. While some of the PSCs ceased operations or expired as per their natural terms, other expiring PSC's operations were modified upon mutual agreements between the PSC Contractors and PETRONAS to allow both parties to enter into more dynamic and exciting new arrangements on a long term basis.
This paper will attempt to share PETRONA'S broad experience and general approach in addressing the expiring PSCs and giving life's to these PSCs after they have expired. The paper highlights among others how PETRONAS goes about balancing between issues such as diverse commercial perspectives/forecasts and expectations; long term relationships and commitments; win-win new arrangements while enforcing national requirements.
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Implementation of "Twin Well" Technology Offshore Sarawak
Authors: Hashim S. , Runggai T. , Khalid M.Z. , Kruit W. , Short D. , Duncan B. , Pauzi N. , Haron J. , Low F.N. 
Published: December 2007

Abstract
Many of the existing matured fields operated by PETRONAS Carigali Sdn. Bhd. (PCSB) still contain substantial remaining reserves. However, there are often limited spare well slots or re-entry possibilities available on existing platform structures from which new wells can be drilled. Putting in new structures is costly and in many cases would render new drilling projects uneconomic. In search of new technologies to develop its matured fields, PCSB has identified the "Twin-Well" technology as a viable and relatively low risk means of further developing such fields offshore Sarawak. This paper will present the application and construction of PCSB's "Twin Well" with two separate wells (one single and one dual completion) from one conductor. The paper will highlight how this new technology was applied successfully in the Tukau field which has significantly reduced project costs and has made in-fill drilling economically more attractive. In many cases the well jackets in these fields are relatively small and normally accommodate up to four wells. In the Tukau field, no spare conductors were available and none of the existing jackets could accept more than one additional conductor. Applying "Twin Well" technology has allowed two wells to be drilled from one platform structure thus saving cost of visiting an additional jacket and having to install an additional conductor to achieve the same project objectives. The way forward will also be presented with PCSB's plans to merge the "Twin Wells" and Multilateral well technology for their future field development projects. The fact that more reserves can be developed with fewer wells from smaller platforms will allow previously uneconomic projects to now become economically robust.
This paper is well suited with the theme of this Conference "Making a difference", as a new approach is required to develop reserves under the new challenging economic conditions.
P. 293
Economic Decision-Making Practices in the U.S. Petroleum Industry
Authors: Mathur Shri B. , Carey Omer L. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.
Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Abstract
This paper explores several aspects of economic decision making in actual use by members of the petroleum industry, including cost of capital, measures of investment evaluation, required minimum rate of return, and risk-analysis methodology. Certain internal procedures utilized by the responding firms in procedures utilized by the responding firms in the application of the above mentioned measures are reported and compared.
The contents of this paper have valid implications for a variety of audiences. This study illustrates how different petroleum executives are handling economic decision making and evaluates the state-of-the-art of the economic decision-making process in the petroleum industry. The results of this study petroleum industry. The results of this study can be used by firms to evaluate and possibly improve their own practices. This paper can make its greatest contribution to smaller firms in the industry who have not yet adequately developed their economic-analysis capabilities and, hence, are searching for procedures to improve their economic decision making.
This paper is based on the responses to a four-page questionnaire that was mailed to the chief executive officers of 15 major companies in the petroleum industry; 12 companies responded.

Introduction
The opportunities for investment or capital outlays form the framework for a company's future development and are a major determinant of efficiency and competitive power. Consequently, a corporation's investment decisions have a profound effect upon its future earnings. profound effect upon its future earnings. Any business is continuously faced with the problem of making investment decisions. Even problem of making investment decisions. Even for the small business, the problem of reinvestment of earnings, expansion, or diversification is a continuing one.
Investment opportunities usually are analyzed by various segments of the organization, but the final decision is the responsibility of top management. This situation points out the need for sound programs of evaluation. Management needs an objective means of measuring and comparing the economic worth of the individual investment proposals submitted by various divisions of the organization in order to have a realistic basis for choosing among them and selecting those that will make the greatest contribution to meeting corporate goals. In addition, using objective criteria and formal guidelines for processing of capital investment proposals allow some investment decisions to be proposals allow some investment decisions to be delegated to lower levels of management, economizing on top-management time.
Strategic Planning of the NWS Offshore Expansion Activities
Authors: Goodson R.J. , di Prinzio S. 
Published: December 2007

Abstract
The North West Shelf Gas Project (NWSGP) comprises North Rankin A and Goodwyn A processing platforms exporting dehydrated gas and condensate through a single multiphase trunkline to an onshore processing plant on the Burrup Peninsula, N W Australia. Demand for domestic gas has been recently stimulated while the Western Pacific Rim region presents an expanding LNG market. The proximity of these markets, together with the Venture's reputation for reliable supply, and a highly successful gas exploration program, places the NWS Venture in a strong position for substantial growth in its LNG, Domgas and liquids business.
The current offshore infrastructure will require expansion to capture the future market demands (Figure 1). Woodside has initiated an Offshore Development Planning (ODP) Process designed to deliver insight and understanding into the complex technical and commercial issues which surround the continued development of the NWS. Major uncertainties facing the Venture include timing of expansion opportunities; proven and exploration reserves; and the capacity, reliability and safety of surface facilities. The ODP is a decision-focussed process that analyses major infrastructure decisions and presents understanding and insight in support of development recommendations.
This paper reviews the work associated with the current ODP program, describing the methodology and expansion strategies evaluated and how these methodologies have made a difference in the overall development strategy of the NWS.
P. 361
Probabilistic Addition of Gas Reserves Within a Major Gas Project
Authors: Carter Peter J. , Morales Enrique 
Published: December 2007

Abstract
The paper presents a new approach to the probabilistic addition of gas reserves within a major gas project. The correct determination of proved reserves underpins the contracted gas volumes for the project. Each individual field has a determined range of gas reserves. Whilst the proved reserves have a 90% chance of being exceeded at the field level, the arithmetic sum of the proved reserves across the project have a much higher chance (of order 99%) of being exceeded due to the independent nature of many of the risks. An appropriate technique has been developed for probabilistic addition of reserves such that the proved reserves correctly have a 90% chance of being exceeded at the project level. The approach takes into account the known dependencies between some of the assets.
The result is an auditable process that underpins the handling of subsurface dependencies within a single project to give a robust estimate of proved reserves.
Profile Control Technology of Thermal Recovery in Shengli Oilfield
Authors: Chen Shen 
Published: December 2007

Abstract
In the process of oil recovery by steam injection in Shanjiasi Oilfield, main problems are as following:
steam override or steam break due to gravity segregation and heterogeneity; low recovery percent of reserves after several cycles and large recovering discrepancy in vertical; active edge and bottom water as well as serious water invasion in producing wells; uneven steam injection profile and low steam sweep efficiency.
The technologies of profile control by steam foam, nitrogen and super-fine cement fly ash have been studied in this article. Filed applications in steam stimulating wells show that the technology of profile control by super-fine cement fly ash has good effect of oil-cement and water-control in Shanjiasi reservoir with active edge and bottom water. 34 well-times of applications have been carried out and the effectiveness reaches 91.7%. The effect of steam stimulation has been improved successfully. This paper describes the feasibility of adopting these conformance control technologies in Shanjiasi Oilfield. The operational parameters were accessed and optimized. A comprehensive analysis of application results was also conducted.
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