bluuebunny/crossref_metadata_2025_split huggingface dataset:
Numerical Simulation Study on Weak Gel Injection
Authors: Yuan Shiyi , Han Dong , Wang Qiang , Yang Hua 
Published: December 2007

Abstract
The low concentration flowing gel (LCFG) fluid diversion technique is a promising IOR method developed in recent years. The displacement mechanism of the weak gel, the physico-chemical properties and other influencing factors, specifically the gel formation, the physical characteristics, the mobility in porous media and the adjustment of permeability, etc., were studied in detail in this paper. A numerical simulator was accordingly established and used initially to simulate laboratory LDFG displacements with satisfactory results observed. A pilot test of the weak gel fluid diversion was consequently simulated and designed using the simulator. The scenario was optimized and economic evaluation was carried out. The pilot test has been put into implement and the performance was in agreement with the prediction.
A Petroleum Engineering Educational Model Based on the Maureen Field UKCS
Authors: Gringarten Alain C. , Bond Deryck J. , Jackson Matthew D. , Jing Xu -Dong , Ala Mike , Johnson Howard D. 
Published: December 2007

Abstract
Important objectives of the MSc courses in Petroleum Engineering and Petroleum Geoscience at Imperial College are educating students in the work flow concepts now prevailing in the oil industry, and producing petroleum professionals who are specialists in their respective fields but are trained to work effectively in multi-disciplinary teams. One of the tools used to meet these objectives is a group project using data from the UKCS Maureen field and made available by Phillips Petroleum (UK) Ltd. This paper describes the rationale for developing a group project exercise based on real field data, the approach used to develop the group projects and the lessons learned.
Air Drilling Techniques
Authors: Cooper Leonard W. , Hook Roland A. , Payne Bobby R. 
Published: December 2007

Introduction
The use of air or gas as a circulating medium was introduced in the early 1950's. Even though initial attempts were crude, significant increases in penetration rate and bit life were obtained. Since these initial attempts, development of air and gas drilling techniques have expanded and are widely accepted today as a method to reduce drilling times and cut cost of many wells. Along with the time and resultant dollar savings, other advantages such as immediate and continuous hydrocarbon detection, minimum damage to liquid sensitive pay zones, better control of lost circulation, and cleaner cores are obtained.
Today's air drilling technology is attributed to many drilling people whose initiative and accumulative experience have refined the method and determined situations where the technique is most applicable. The lack of understanding, rather than experience, is often the reason for not accepting air drilling. Drilling with air does involve special consideration in the use of equipment and drilling techniques that are not commonly encountered with other drilling media. For example, air, unlike fluids, compresses readily and requires a somewhat more sophisticated engineering approach to achieve the desired results.
This paper discusses the mechanics of air drilling, modifications such as mist or foam drilling, unique equipment requirements, and downhole problems that have been encountered. Special attention is given to presenting techniques developed to prevent or control downhole problems.

Discussion

Mechanics of Air Drilling
Air is the ultimate low density drilling media. In order to achieve optimum results and greatest economy from air drilling, there are several factors which should be considered. Hard formations which are dry or produce relatively few formation liquids provide the best results while air drilling. When the formation is completely dry, or the influx of liquids is slight enough to be absorbed in the air stream, the drill cuttings return to the surface in the form of dust. Also, this allows for immediate and continuous evaluation of hydrocarbons.
Delta Rig 76
Authors: McLean J.D. 
Published: December 2007

Abstract
America's energy outlook is an everchanging thing; however, with the construction of Rig 76 Delta Drilling Company is declaring its faith in the future of ultra-deep drilling in this country. In addition to design criteria and specifications, this paper discusses unique problems encountered-prime mover flexibility, testing of various components, mud handling and solids control equipment, moving considerations, foundation requirements, rig-up and start-up operations, and the outlook for activity both now and in the future.

Introduction
Rig 76 is a raised floor, elevated drawworks design costing in excess of $5,000,000 and requiring 52 machinery loads when moving. At the time of construction, this rig had the only 147 foot mast with a capacity of 1,555,000 pounds. There are seven other rigs now operating with this hook load capacity that have 142 foot masts. There are approximately 150 rigs with raised floor masts and approximately forty rigs with elevated drawworks; however, this is the only rig that has an elevated drawworks with this hook load capacity.

DESCRIPTION
The beam-leg mast has a 147 foot clear height with a 30 foot base at a floor elevation of 34 feet giving an overall height to the top of the crown of approximately 189 feet. Beneath the floor there is 27 feet of clear space below the rotary beams. With this design, the floor is actually built into the leg sections of the mast while the mast is at ground level in the horizontal position. When the mast is raised the floor is then at the 34 foot level.
Rig 76 is a diesel-electric eight motor rig having three motors on the drawworks. It has a working hook load capacity of 1,555,000 pounds with 14 lines strung and a simultaneous set back capacity of 800,000 pounds. The complete structure and the mast pounds. The complete structure and the mast is of A-441 (70,000 psi), alloy steel. The racking stand has capacity for 322 stands of 5 in. drill pipe plus ten stands of 9 in. drill collars. An additional 12 stands of drill pipe may be racked in the alley on the driller's side, giving a total racking capacity of over 30,000 feet. With pipe racked, the mast is designed to withstand 100 mph winds.
Nuclear Magnetic Resonance Log Evaluation of Low-Resistivity Sandstone Reservoirs By-Passed by Conventional Logging Analysis
Authors: Hamada G. M. , Al-Blehed M. S. , Al-Awad M. N. J. 
Published: December 2007

Abstract
The combination of conventional logs such as density, neutron and resistivity logs is proven to be very effective in the evaluation of normal reservoirs. For low resistivity reservoirs, however, an accurate determination of the petrophysical parameters with the conventional log reservoirs is very difficult. This paper presents two cases of low resistivity reservoirs and low contrast resistivity reservoirs where conventional logs fail to determine the petrophysical properties of reservoirs, mainly, low resistivity and low contrast resistivity reservoirs. The problems of these reservoirs is that conventional logging interpretation shows high water saturation zones, but water free hydrocarbon would be produced. In the case of low resistivity contrast reservoirs it is very hard to determine water hydrocarbon contact with resistivity logs. Nuclear magnetic resonance (NMR) has been only available as a supplement tool, to provide additional information on the producibility of the reservoir. The main limitation of NMR, however, has been the cost and time of acquiring data.
This paper shows that in the case of low resistivity reservoirs NMR is very cost-effective tool and helps to accurately determine the reservoir rock petrophysical properties. In the analysis of NMR data, several aspects of NMR technique have been used; 1) T1/T2 ratio for fluid identification, 2) the difference between NMR derived porosity and total porosity to determine the types of clay minerals, 3) NMR relaxation properties to identify fluids nature and rock properties. This paper presents four examples of low resistivity reservoirs. Analysis of NMR data of low resistivity reservoirs has helped to identify the producibility of these zones, to determine lithology independent porosity and to distinguish between bound and free water. For the case of low contrast resistivity reservoir where there was little resistivity contrast between water bearing formation and oil bearing formation, NMR has been able to identify the fluid nature of the two formations and then the height of the oil column. This was based mainly on high contrast of NMR relaxation parameters.
Effect of Gas Saturation on Oil Relative Permeability and Mobility Ratio in Reservoir Simulation using Different Methods
Authors: Kumar Rajesh , Shrivastava S. K. 
Published: December 2007

Abstract
Reservoir simulation involves validation through history matching. Relative permeability plays an important role to accomplish the task of history matching. In the reservoir simulators, there is an option to convert the 2-phase relative permeability data into 3-phase by using different methods. StoneI and StoneII are the two most commonly used for this purpose. However, ECLIPSE software for reservoir simulation has its own default method for segregated flow also, to calculate oil relative permeability.
In the present study, effect of gas saturation on the oil relative permeability and mobility ratio using these three methods has been discussed. The laboratory data from a carbonate reservoir of an offshore field of India has been considered. It has been observed that use of StoneII causes serious problems when it creates immobile oil saturation around the prolific producer wells. In fact, the oil saturation values were quite higher than their residual values at those places. This is because, in StoneII, the occurrence of negative oil relative permeability values implies a complete blockage of oil and as a result oil relative permeability equals zero. On the other hand, ECLIPSE default method give significantly higher values of oil relative permeability and very low values of mobility ratio in comparison to StoneI and StoneII methods over a wide range of gas saturation values. Further, use of this method yields close history match in those wells where they were ceased to produce due to oil blockage using StoneII method. In conclusion, selection of one of these methods should be done with due caution as all these methods have their own limitations and benefits at a given set of saturation values.
Learning from Offshore Decommissioning Practices in Europe and the USA
Authors: Dempsey M. J. , Mathieson W. E. , Winters T. A. 
Published: December 2007

Abstract
Decommissioning in Australian waters is a relatively new activity as only two installations have been fully decommissioned to date. The precedents set by decommissioning projects and regulations elsewhere in the world should be raising questions with the Australian operators and regulators such as the feasibility of an Australian rigs-to-reef program, the acceptabiity of dumping installations to sea, and the management of public concern. In considering these issues the Australian operators and regulators should not underestimate the value of information and experience that is available from the international forum. Information may be sourced from regulatory authorities, operators, personal contacts, in-house personnel with international experience, and literature and internet searches.
Platform Decommissioning Trends
Authors: Anthony N. R. , Ronalds B. F. , Fakas E. 
Published: December 2007

Abstract
Offshore oil and gas decommissioning experience to date, along with future trends, are explored by platform type and by region. There has been considerable decommissioning activity in the Gulf of Mexico, but generally only for small jacket and caisson structures. Partial removal, toppling, reuse and alternative use as an artificial reef are all common destinations of decommissioned platforms. In the North Sea, complete removal has been the preferred option, and this includes the largest platform chosen for decommissioning to date. Forthcoming cases including large concrete platforms will test this trend. Numerous floating facilities have been decommissioned in the North Sea and the majority have found reuse. Operators are also attempting to sell decommissioned North Sea jackets of moderate age.
Infrastructure offshore Australia is much less developed in comparison with the Gulf of Mexico and the North Sea and offshore facilities are smaller than the largest fixed steel and concrete platforms found elsewhere. Nonetheless, the largest jackets decommissioned to date around the world are only one-third the size of Australia's largest platforms. The local industry will watch with interest as decommissioning trends evolve in the early part of the 21st Century.
Evaluation Of Coalbed Methane Potential Of Jharia Basin, India
Authors: Peters James 
Published: December 2007

Abstract
Spurred by the commercial success of coalbed methane activity in USA, India initiated evaluating its coal bearing basins for their coalbed methane potential in 1992. In a short span of five years it tested and flowed coalbed methane from one of the coal seams of Barakar Formation in Jharia basin. This basin is one of the member basins of the Damodar-Koel coal belt of Eastern India. The basin cover an area of 450 square kilometers and exposes sediments of the Permian, Lower Gondwana Group. It is a half graben with the southern boundary fault being more pronounced than the northern boundary fault. The tectonic setting, physio-chemical, and reservoir characteristics, depth and thickness of coal seams, and production testing of one of the coal seams has resulted in demarcating the southern part of the basin to have an attractive coalbed methane play.
The central portion of this part of the basin has been prioritised for converting about 15 billion cubic meters of coalbed methane resources to reserves. Additional 15 billion cubic meters of methane resources could be converted to reserves from the adjoining areas.
Fracturing of the Miocene Sand in South Louisiana
Authors: Cross R.R. , Sheldon Lawson 
Published: December 2007

Abstract
The Miocene sands of South Louisiana have not responded to fracture treatments in the past, or the results have been limited and not past, or the results have been limited and not economical.
Using a two-phase gel system for efficient transport of high sand concentrations in the fracture coupled with high-pressure pumping equipment for placement at depths greater than 16,000 ft has increased the flow capacity and the recoverable reserves sufficiently to make the program economically attractive.
This paper describes the design, job performance, and results of this treatment. performance, and results of this treatment

Introduction
The M-24 Miocene sand is the deepest producing sand in the Venice Field, producing sand in the Venice Field, Plaquemines Parish, La. It is described as Plaquemines Parish, La. It is described as fine to very fine grained, firm to hard, and sometimes silty and shaley. Over all, the sand interval is generally comprised of numerous sand members separated by distinct shale breaks. Characteristically, the M-24 sand has low porosity and permeability, especially when porosity and permeability, especially when compared with shallower Miocene sands in the same field.
Venice Field is located adjacent to a large Salt dome. Fig. 1 is a map of the entire salt dome showing the position of the wells around it and those drilled through the overhanging portion of the salt. Cattle Farms A No. 3 is portion of the salt. Cattle Farms A No. 3 is almost surrounded by faults radiating from the salt dome (Fig. 2). This faulting is sufficient to limit the A No. 3 to a single-well reservoir. Secondary mineralization of salts around the dome eliminated all porosity and permeability in this area.

TREATMENT AND PRODUCTION HISTORY
Cattle Farms A No. 3 was completed in May 1975. Initial production through perforated interval (Fig. 3) 16,105 to 16,120 ft was 89 BOPD, 667 Mcf/D with a flowing tubing pressure of 300 psig. A bottom-hole pressure survey on May 31, 1975, indicated a flowing bottom-hole pressure of only 1,087 psig. After shut-in, pressure of only 1,087 psig. After shut-in, the pressure built to 5,487 psig in 7 hours, indicating wellbore damage or lack of permeability. permeability. Additional perforations in the 16,040- to 16,070-ft interval were added in another sand stringer to increase production.
The Deepwater Subsea Tieback Option for Future Oil and Gas Production in Australia
Authors: Heng E. I. , Ronalds B. F. , Edwards T. J. 
Published: December 2007

Abstract
The role of subsea tiebacks in the economic recovery of oil and gas world-wide is growing. Almost half of all proposed offshore field developments from 1998 to 2002 are expected to be unprocessed subsea tie-backs to surface production systems. With exploration and development venturing into deeper waters, the subsea tieback is proving itself to be a valuable option for the exploitation of these new oil and gas fields.
The design and subsequent operation of subsea tiebacks provides engineers with many challenges. One of the most important considerations is flow assurance. Some difficulties frequently encountered in subsea tieback systems resulting in flow assurance problems include hydrate and wax formation. This paper investigates the design of subsea tiebacks to provide optimum flow assurance, and discusses common strategies used to minimise hydrate and wax formation.
The Gulf of Mexico (GOM) is one of the three main theatres of deepwater oil and gas activity, where the number of developments exceeding 305m (1000ft) has grown significantly over the last decade. Recent deepwater GOM field developments are used to identify trends in subsea tieback developments.
Finally, the potential role of subsea tiebacks in future deepwater oil and gas developments in Australia is discussed. The exploration for oil and gas offshore Australia is moving into deep waters. Subsea tiebacks will play an instrumental role in the future development of these resource rich areas, where there is a lack of production infrastructure.
New Size-Controlled Microgels for Oil Production
Authors: Chauveteau G. , Omari A. , Tabary R. , Renard M. , Veerapen J. , Rose J. 
Published: December 2007

AbstractNew size-controlled microgels formed by crosslinking polymers under shear flow are very promizing for various applications in oil production. Indeed, when produced by using a proper polymer/crosslinker system and under the conditions needed to obtain the desired properties, these microgels should be quasi-ideal products. They are expected to control water mobility at long distances from the wells to improve sweep efficiency and reduce selectively permeability to water for water production control. For this latter application, injecting stable, preformed microgels eliminates the risks inherent to in-situ gelling which is a technique now recognized as being very difficult to control. This paper reports the results of new lab experiments conducted to complete our theoretical description of the crosslinking-under-shear process and to test the properties of these microgels in porous media. The actual properties of these microgels are compared to theoretical predictions. The results provide new theoretical insights into microgel formation and show that such microgels 1) have sizes measured directly by Photon Correlation Spectroscopy which are satisfactorily predicted by our model 2) adsorb quasi-irreversibly, forming adsorbed layers having a thickness equal to two times their viscometric radius of gyration, thus, are capable of controlling permeability more efficiently than the polymer alone 3) can be injected in porous media without any plugging tendency 4) have small internal rigidity as suggested by elastic modulus measurements and thus, they should be ideal disproportionate permeability modifiers 5) have viscosity higher than polymers in the dilute regime and extremely high in the semi-dilute regime, and 6) are stable, showing no tendency to re-form larger microgels when ageing, in presence of a suitable stabilizer.
Effective Chemicals For Microbial Control In Secondary Recovery
Authors: Huddleston Robert L. , Allred Ray C. 
Published: December 2007

Publication Rights Reserved
This paper is to be presented at the Seventh Annual Meeting of Rocky Mountain Petroleum Engineers of AIME May 25–26, 1961, in Farmington, N. M., 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 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 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
In recent years the problem of biological control in secondary recovery has received a considerable amount of attention. In many cases, the success of a waterflood has depended upon the ability of the operator to control microbial growth.
The waterflood operator is faced with two basic microbiological problems:bacterial corrosion andmicrobial plugging of filters, flow lines, and water injection wells.
The waterflood operator must first establish that his problem is biological by a complete microbiological examination of the waterflood system. After finding that such a problem exists and determining the type of organism that is causing the problem, the operator is in a position to evaluate various chemicals for microbial control.
In most instances, nitrogen containing compounds such as quaternaries, amines, diamines, and imidazolines are effective in fresh water systems. The materials have the added qualities of being corrosion inhibitors and surface active agents. In general, the nitrogen containing chemicals are not effective in hard water systems. Chlorinated phenol type chemicals have proven to be effective in hard water brines.

Introduction
Microorganisms in secondary recovery waters are capable of creating problems which, if not controlled, could decrease operating efficiency and; reduce water injection rates. Waterflood operators must know how to detect these problems and how to combat them.