bluuebunny/crossref_metadata_2025_split huggingface dataset:
New Well Architecture Successfully Optimizes the Development of Fluvio-Deltaic Multi-Layered Gas Field
Authors: Dyer George R. , Ismanto Bambang , Haas Mike 
Published: December 2007

Abstract
VICO Indonesia operates the Sanga-Sanga Block in Indonesia as a Production Sharing Contractor to PERTAMINA, the Indonesian National Oil Company. The Sanga-Sanga Block is located in East Kalimantan near the city of Balikpapan and consists of four major fields producing approximately 1.3 BCFD of gas and 50,000 BLPD. The processed gas is delivered into a pipeline system that carries the gas to the Bontang liquefaction plant. The gas is converted to LNG for distribution and sales throughout the Asia Pacific Rim.
The main geological depositional system is fluvio-deltaic. Nilam and Badak, the two largest fields, contain numerous stacked pay intervals that can total up to 1,000 net feet of pay in 50 separate reservoirs that are distributed over as much as 7,000 vertical feet. The reservoirs are in a sand/shale sequence deposited in a channel sand and point bar environment. There are some oil accumulations, but the majority of the reservoirs are gas. There are a few large reservoirs in the hundreds of BCF range, but most are smaller reservoirs, less than 20 BCF.
For over twenty years, VICO Indonesia drilled and completed "conventional" gas wells that included dual tubing strings and multiple packers. The large number of individual reservoirs and their small size makes dedicating a well to a single reservoir impractical. Numerous workovers are required with this type of geology and the dual completions are complicated and expensive. As the fields age, the number and cost of the workovers continuously increase. Because of the mechanical limitations in dual tubing string completions, the options for stimulation are limited and the potential for formation damage during workover operations is substantial.
In 1996, a multi disciplinary team was formed to evaluate the benefits and risks of various new well architectures for future Nilam Field development. The study concluded that a monobore or tubingless completion was the best option. The 4-1/2" monobore completion eliminates all packers, nipples and sliding sleeves and is especially appropriate for gas production because water handling and artificial lift is usually not required. This new well architecture has been implemented and successfully reduces drilling and completion cost by 20%. It also allows significant improvement in completion techniques, eliminates rig workovers, increases reserve recovery per well, and reduces the number of future drilling wells. The tubingless completion also allows better reservoir evaluation and selective zone stimulation or isolation. This paper will review the monobore evaluation process, benefits, and results to date.
Computerized Sucker Rod Pumping Evaluation
Authors: Cochran P.F. , Miller L.N. , Threewit C.R. 
Published: December 2007

Publication Rights Reserved
This paper is to be presented at the 38th Annual Fall Meeting of the Society of Petroleum Engineers of AIME in New Orleans, La., on October 6–9, 1963, and is considered the property of the Society of Petroleum Engineers. Permission to publish is hereby restricted to an abstract of not more than 300 words, with no illustrations, unless the paper is specifically released to the press by the Editor of the JOURNAL OF PETROLEUM TECHNOLOGY or the Executive Secretary. Such abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or SOCIETY OF PETROLEUM ENGINEERS JOURNAL is granted on request, providing proper credit is given that publication and the original presentation of the paper.
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
A computer program has been developed which utilizes readily available information to calculate (1) the dynamic forces in a sucker rod pumping system, (2) the efficiency with which the installed equipment is operating, and (3) the actual cost of operation of the installed equipment and the cost of any inefficiency with which the equipment is operating.
The print-out contains all the information necessary for comparison of actual and ideal operating conditions. Experience to date indicates that 20 to 60 percent of the cost of operating sucker rod pumping systems is the result of inefficient use of pumping equipments

Introduction
The goal of any producing operation is to recover the maximum oil at the minimum expense consistent with good operating practice. During the past several years, The Pure Oil Company has been increasing its concentration on this philosophy. An analysis of operating costs almost invariably resulted in the conclusion that something needed to be done about pumping costs. Not only were milling systems operating at low efficiencies but, in addition., it appeared that considerable money was being spent for oversized equipment.
A well by well study and analysis of pumping systems did not appear feasible because (1) dynamometer analyses require far more time than Pare's technical staff could devote to the problem and (2) manual calculation methods are time consuming and not sufficiently accurate to yield worthwhile results.
During early 1962, Midwest Research Institute, under contract to Sucker Rod Pumping Research, Incorporated completed the development of a method of calculating the dynamic forces in a sucker rod pumping system. The method requires only input data which are readily available and, as Pare's field tests have proven, yields results which compare very well with measured values. The major exception to the good comparison is in calculated torque, which ranges up to 60 percent above the measured torque.
Use of High-Strength Proppant for Fracturing Deep Wells
Authors: Cooke Claude E. , Gidley John L. , Mutti Dean H. 
Published: December 2007

Abstract
A new fracturing process using a high strength bauxite as the proppant has been developed which generates long-lasting, high conductivity fractures in deep, hard, high stress formations. No unusual difficulties have been experienced in handling and pumping the proppant. Good production increases have been obtained in most of the wells treated with the new process.
The process is particularly applicable to deep reservoirs. Detailed economic analyses, made with a reservoir simulator and using reservoir and economic parameters for a deep, tight, East Texas area gas well, show that large economic benefits can be expected from use of the process.

Introduction
The use of high-strength bauxite as the proppant in hydraulic fracturing was reported proppant in hydraulic fracturing was reported at the Fall Meeting of SPE in 1976. The purposes of this paper are to give an updated purposes of this paper are to give an updated report on usage of the material in Exxon USA wells and to discuss an economic analysis that can be used to evaluate the usage of an improved propping material. propping material. Many deep wells will require hydraulic fracturing treatments in order to produce at economic rates. Other wells can be greatly improved economically by a successful hydraulic fracturing treatment. To achieve successful fracturing results, a material having properties superior to sand is needed to prop open the hydraulic fractures created at the high earth stresses present in deep wells. Silica sand, the commonly used propping material, tends to crush in closure stresses encountered in deep formations, producing fine particles or fragments that can drastically reduce fluid conductivity of the propped fracture. This crushing of the sand leads to lower productivity of the well.
The problem of finding a proppant material that will withstand high stress without excessive crushing has been the subject of research in the oil industry for a number of years. Exxon Production Research Company (EPR) worked for several years on this problem. A wide variety of materials were tested in the laboratory, following the development of equipment suitable for simulating reservoir conditions.
Assessing the Capabilities of a Cased-Hole Reservoir Analysis System in the Gulf of Thailand
Authors: Odom Richard C. , Platt Christopher J. , Pavlakos Paul 
Published: December 2007

Abstract
The option of using a cased-reservoir analysis system as an alternative to traditional open-hole log analysis was tested as a method to reduce drilling rig time. On a series of five wells in the Gulf of Thailand, an integrated pulsed-neutron system that measures Sigma, inelastic spectroscopy, neutron porosity and density was used to drive the cased-hole analysis. The capabilities and accuracy of the cased-hole results were compared to open-hole porosities and water saturations.
One concern for cased-hole logging is accuracy in this well-completion environment. These wells are completed as monobores with 2⅞-inch tubing cemented directly into the 6⅛-inch open hole (no well casing). Initially, the pulsed-neutron porosity coefficients for 5½-inch casing were used with reasonable accuracy. To increase the porosity accuracy, the data from this test served as input to an artificial neural network for determining porosity coefficients in this specific borehole environment.
The project consisted of 12,099 feet of log data including 30 gas sands, 5 oil sands, and numerous water sands in the five wells. The results of this assessment are shown via log examples over specific intervals. In addition, several cross-plots comparing open-hole data to cased-holed data show the results of this evaluation. Graphs of net pay, net effective porosity, net shale volume, and water saturation are shown for the entire project.
Sand Control Screen Plugging and Cleanup
Authors: Asadi Mahmoud , Penny Glenn S. 
Published: December 2007

Abstract
Sereens are used to mechanically restrain formation solid entrance to a wellbore. As effective as this process may be, in many cases it fails to retain solids. This is due to screen plugging either during screen run in a wellbore or during production where larger size particles bridge against a screen and finer size particles plug the screen. In either case, plugged screens are subjected to a cleanup treatment. In this paper, a series of large-scale tests are conducted to evaluate screen cleanup methods such as acid spotting, use of enzyme and acid activated-breaker, backflow, and a combination of these methods under downhole conditions. At first, each screen's retention performance is evaluated. Then, a drill-in-fluid containing solids is pumped into a large-scale flow-cell at a constant pressure drop across the screen to simulate a screen run down in a wellbore. Inlet and outlet samples are collected to evaluate removal efficiency of each screen. Then, each plugged screen is subjected to a cleanup method. The effectiveness of each cleanup technique is evaluated based on the retained permeability of each screen. Degree of plugging and percent area open to flow for each screen is also presented.
The Future of Partnering and Alliancing
Authors: Elshahawi H. , Sengul M. 
Published: December 2007

Abstract
Since its birth, the oil and gas Industry has been faced by sudden and brutal variations in its economics. The recent shock that occurred in the late 90's has forced the entire industry into major restructuring, including consolidations and mergers. The major initiative to define and implement new business relationships between oil and gas producers and service suppliers had already begun in the early nineties and had been driven by oil company strategic thinking in the relatively stable yet uncertain environment that prevailed earlier to that last shock. Moreover, deliberate restructuring has been taking place within many oil companies throughout the decade, and innovative technology was being introduced by the service industry at an unprecedented rate. Key developments such as 3D seismic, horizontal drilling, geosteering, coiled tubing applications, improved stimulation methods and advanced wireline logging technology have made many challenges of the past realities of the present. Additionally, the information technology revolution has created virtual teams by linking experts and data sources worldwide.
In reaction to restructuring, innovative technology, and the uncertain future of the market, there has been an increasing trend in the petroleum industry to establish strategic partnerships. Such partnerships represent a departure from the conventional oil company philosophy that relied on internal administrative controls. This paper investigates the benefits of partnerships to both oil and service companies. Industry perceptions of partnerships and past performance are discussed, the future of alliancing is explored, and a formula for successful partnering is proposed.
Legendre: A Team Effort Makes a Small Offshore Development Economically Viable
Authors: Clegg Duncan , Guerrera Lupo , Kirk-Burnnand Baden , Steenson Bruce 
Published: December 2007

Abstract
The Legendre North and Legendre South fields lie in 50m water depth in Production License WA-20-L, some 100km north of Dampier West Australia. The Legendre North field was discovered in 1968, but appeared uneconomic until further drilling, following the acquisition and interpretation of 3D seismic, augmented the resource base by extending the northern field and discovering Legendre South in 1997/1998. Subsequent geoscience and engineering studies have shown that the development of the 44 MMbbl oil reserves at the probable level is feasible, but is nevertheless still not without risk in this challenging metocean and geotechnical location. A cooperative effort between the Joint Venture participants coupled with somewhat novel facilities concept and contracting has however made it viable.
The two fields will be developed via four production wells producing to a single Mobile Offshore Production Unit (MOPU), converted from an existing jack-up drilling rig. Oil will be exported from the production facility via a 2.5km pipeline to a tanker moored to a Catenary Anchored Leg Mooring (CALM) buoy. Excess associated gas will be reinjected via a dedicated injection well. The MOPU is to be provided under a Service Agreement through which the contractor will receive a daily fee for processing the Legendre production, reinjecting excess associated gas and exporting the crude oil product to the tanker on the buoy.
Woodside Energy Ltd. is operator of the Licence with JVP's Apache Northwest Pty Ltd. and Santos Limited. The project is being managed by a small integrated team which, through its membership, combines the best of both Woodside and Apache expertise and management styles.
This paper provides an overview of the development concept, the integrated project management structure and the contracting strategy, which seeks to align the business objectives of the Joint Venture and the main contractor for the benefit of all involved in the project.
A Method to Estimate the Drainage Area of a Horizontal Well
Authors: Permadi P. , Putra E. , Butarbutar M. E. 
Published: December 2007

Abstract
Evaluation of the production performance of a horizontal well is an effort to justify both the technical and economie successes of the project, particularly in an area of horizontal well development. When this implementation shows a good promise for the plan of reservoir management, the engineers involved should be able to estimate the drainage area of the horizontal well. This is of importance in optimizing well spacing for the development.
This paper presents a method to estimate the drainage area of a producing horizontal well. The method was developed by combining an equation of production decline introduced by Shirman (1998) with an equation of material balance. The advantages of the method presented here over the existing ones available in the literature are simple and no requirement of ultimate recovery data.
Field data of four producing horizontal wells were used to evaluate the proposed method. Having the production performance and the rock and fluids properties data, calculation was performed to determine the drainage area of each well under the study. The validation was done by (1) comparing our results with that of a previous study and (2) calculating the productivity index (PI) using a horizontal well inflow equation and then compared with that measured in the field. The comparisons show a very good agreement for all the cases considered, revealing that the method is successfully applied.
In addition, the paper also discusses the strategy of orienting a horizontal wellbore to maximize the benefit of horizontal well application.
Stag Development - Challenges and Successes in the First Two Years
Authors: Goodacre J. , Ion A. M. , Alexander I. R. , Aitken K. J. 
Published: December 2007

Abstract
Stag oilfield commenced production in May of 1998 and reached peak rates in excess of 30,000 barrels of oil per day in July 2000.
Stag development is an $A200 million oil development on the Northwest Shelf of Western Australia (Fig 1) designed to produce in excess of 50 million barrels of oil over the life of the field. The field was discovered in mid-1993, delineated in 1994 to 1996, and tested with a horizontal well production test in 1996. The development consists of a Central Production Facility containing wells and processing equipment, a 2km subsea line to a CALM buoy and FSO storage and export tanker. Designed to have five producers and three water injectors producing around 30,000bopd oil, the field did not meet initial expectations. Gas-oil ratios were higher than forecast, peaking in excess of 1000scf/bbl and causing significant operating problems for the process plant and electrical submersible pumps. Oil production was lower in the east of the field than anticipated, due to the thinning or absence of high productivity sand units, reservoir pressure support was poorer than modelled leading to more rapid pressure decline than anticipated, and one well produced significant quantities of sand and clayey solids. These challenges led to a significant re-work of the development. Subsea water injectors were added, wells were recompleted in better quality reservoir, pump designs were significantly changed, the reservoir model was rebuilt and more producers were added (Fig 2).
At year-end 1999, Stag came of age - production reached design basis levels, reliability approached 100% and overall reservoir performance met expectations.
The paper reviews three key elements of the development - Reservoir Description and Performance, Completion Design and, Facility Design and Performance - and presents the lessons learned.
Characteristics of Fractured Reservoirs in Magmatic Rocks and Their Reservoir Properties
Authors: Koshlyak V. A. , Dong T. L. , Hai P. D. 
Published: December 2007

Abstract
Oil in magmatic rocks has been known for a long time, however exploration for it has been conducted relatively weakly. In the meantime, proceeding from the concepts of plate tectonics, geodynamics of rock deformation, the significance of the rocks in oil accumulation increases and they have high hydrocarbon potential confirmed by a number of discoveries in the last years.
The reasons for the careful approach to the type of reservior rocks are: 1. very complex porous patterns, and the processes leading to generating reservoir properties, time of the generation and reservoir property distribution in area and in sequence are not clear; 2. the problem of searching appropriate geophysical methods to delineate fractured zones has not been resolved; 3. no log interpretation methodogy has been worked out, and; 4. the drilling, testing and stimulating technologies for the basement rocks ocurring at deep depths are not suitable. The genesis of the oil, its migration and accumulation in the basement reservoir is also not clear. The published articles deal with fields in the kind of the rocks are limited and they mainly described the geology of the fields.
To resolve the mentioned above problems, all geological and production data of well studied fields in the world should be carefully learned and analyzed in order to built a appropriate reservoir rock model for each of them. In this sence White Tiger oilfield - a unique large off-shore field in South Vietnam - serves as one of the models of magmatic reservoir rocks.
Application of One-Trip Multi-Zone Gravel Pack to Maximize Completion Efficiency
Authors: Vickery E. Harold , Bayne Christian F. , White William G. , Liu Liang Yue , Yue Jiang He , Chen Bi , Wu Cheng Hao 
Published: December 2007

Abstract
This paper uses case histories from several 3- and 4-zone gravel packed wells in The Peoples Republic of China's Jinzhou 9-3 (JZ9-3) Bohai Bay field to address the potential of one-trip multi-zone gravel packing. Objectives included improvement of economic margins in development wells by maximizing efficiency and reducing rig time for completion operations. The paper describes the operational and reservoir parameters that led to successful application of this technique during development of the JZ9-3 field. Based on this study, the authors provide guidelines for application of the technology to other reservoirs and compare rig times with those of more conventional methods currently used to complete multi-zone wells.
The scope of the project did allow for some optimizations to be made both in operations and in design of the system. These enhancements resulted in a system that can be used for zones of varying length. The system also allows gravel placement across each individual zone to be performed either below or above fracture pressure, while maintaining total pressure isolation from all other zones.
Data are presented that show the actual average time saved in excess of 50 percent for 4-zone gravel packed wells.
Technology Advancements in Optimum Wellbore Placement
Authors: Md Zin Che' Lah , Sering Lancelot , Kamarrudin Sazli , Good Alan , Gjerdingen Tore 
Published: December 2007

Abstract
Advances in drilling technology are now making possible the drilling and completion of oil and gas wells thatjust a few years ago would have been inconceivable. Significant advances in downhole tool sensor placement and reliability are aiding operators in optimizing wellbore placement to within a matter of tens of centimetres in the vertical plane. Over and above this lateral well placement in the 3D horizontal plane now make it possible to intersect high permeabily horizons and steer the wellpath in three dimensions to ensure the well is able to maintain its position within the "sweetest zone"
In this paper the authors will demonstrate how advanced technology was used to drill the Sotong 5, 6 and 7 trilateral wells using a rotary closed loop drilling system. These types of tools provide enhanced drilling-while-steering efficiency and improved hole quality. It comprises a surface to downhole guidance system, formation evaluation (with optional LWD) and downhole pressure monitoring. These tools can automatically guide the bit to a preprogrammed target and two-way surface communication allows rigsite engineers to adjust the well trajectory to meet drilling objectives and redirect the wellpath based on real-time formation logs, through the utilisation of reservoir navigation services (geosteering). This eliminates the "wait and see" aspect of drilling with conventional steerable systems, which often results in less than optimal well placement, as well as getting continuously updated models of the placement of the drainhole within the reservoir. This technology is augmented through realtime wellsite information transfer from the rigsite to the office. Therefore the critical well path decisions can be made in real time by the team in the office and implemented at the wellsite instantaneously. The paper will discuss tangible performance metrics and attempt to quantify through statistical analysis the added value of such systems.