bluuebunny/crossref_metadata_2025_split huggingface dataset:
Design And Installation Of The North Rankin Trunkline And Slugcatcher
Authors: Seymour E.V. , Craze D.J. , Ruinen W. 
Published: December 2007

Abstract
Design studies for the offshore pipeline system for the North West Shelf project in Australia commenced in the early 1970's. Flow mode selection project in Australia commenced in the early 1970's. Flow mode selection resulting in a two-phase flow system for gas and condensate was completed in 1978. A diameter of 1016 mm was selected for the 134 km trunkline from the North Rankin platform to shore. During 1978 and 1979 detailed route surveys, oceanographic investigations and cyclone hindcast studies were completed, allowing detailed engineering to commence. Pipe was ordered from Japan in December 1980 and deliveries were made between April and August 1981. Pipe coating was carried out in Western Australia between August 1981 and March 1982. Pretrenching of portions of the pipeline route was completed between December 1981 and September 1982. Pipeline installation commenced in May 1982 and was completed, including post-trenching, by December 1982. Backfilling over the pipe was carried post-trenching, by December 1982. Backfilling over the pipe was carried out between August 1982 and June 1983. The tie-in to the platform and final hydrostatic test on the pipeline were completed by May 1983. Dewatering, drying and inerting is planned for October and November 1983. The slug catcher associated with the two-phase system will be completed by December 1983. The line is expected to be commissioned in June 1984.

Introduction
The trunkline from the North Rankin "A" platform to shore has recently been completed as the first part of the offshore pipeline system for the North West Shelf project. This pipeline originates from the platform in a water depth of 125 m, enters the mouth of Mermaid Sound, and terminates just south of Withnell Bay on the Burrup Peninsula, on the North West coastline of Western Australia (see Figure 1). The pipeline is 1016 mm (40 inches) in diameter and 134.2 km long. It will operate in two phase flow bringing both gas and condensate to the onshore plant near its landfall. A slugcatcher is under construction within the plant to receive liquid hydrocarbon slugs from the pipeline.
The trunkline to shore will initially serve only the one offshore platform and operate at about 25% of its capacity to supply the Western Australian domestic gas market. The domestic gas plant on the Burrup Peninsula is being constructed by Woodside to produce pipeline quality gas for delivery to the State Energy Commission and condensate for shipment by coastal tankers. A 1500 km long onshore pipeline from the Burrup Peninsula to Perth and other localities in the south west of the State of Western Perth and other localities in the south west of the State of Western Australia is being constructed by the State Energy Commission to supply local domestic and industrial users with up to 10.9 million m3/day of gas (385 MMSCFD).
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Leak Detection Survey of a 36 Inch Diameter 78 Mile Long Submarine Pipeline
Authors: van der Marel M , Sluyter E A 
Published: December 2007

ABSTRACT
In the early part of 1982 a leak detection survey on the 36 inch diameter 78 miles (126 km) long E11 submarine pipeline was carried cut with optical and acoustical equipment during a period of 16 days. Two leaks were detected and identified as 0.5 inch (6 mm) cracks in two different circumferential welds.
Cementation of Intermediate Gas Sands in Central Luconia Province
Authors: Ratcliffe S H 
Published: December 2007

ABSTRACT
This paper is a ‘case study’ of the techniques developed by Sarawak Shell Berhad (SSB) to successfully overcome problems encountered in primary cementing of shallow gas bearing intervals. During a recent gas development project, successful isolation from surface of three separate intermediate gas sands above the main reservoir was achieved by improved cement displacement efficiency and by improved pressure control of the gas sands during cement gellation. This was possible by drilling a smaller hole, minimising hole washouts, using fast setting cement, displacing the cement as fast as possible, reducing the length of cement columns by use of dual stage equipment and by applying backpressure above the cement columns immediately after displacement. The approach used can in principle be applied for the design of any cementation. The specific techniques developed will be applied in future gas developments to be undertaken by SSB, and may find applications with other operators facing similar problems.
Experience With Stratapax Drill Bits
Authors: Thant Myo 
Published: December 2007

Abstract
Polycrystalline Diamond Compact (PDC) bits have been extensively used in Polycrystalline Diamond Compact (PDC) bits have been extensively used in oil field drilling for sometime. Major performance gains have been reported for use of these bits in oil based drilling fluids, operating on mud motors.
This paper describes the experience in Sarowak and Sabah Shell Operations with PDC bits in water based drilling fluids and with rotary drilling. It represents the results of over 80 individual PDC bit runs incorporating over 30,000' of 8 1/2" hole drilled with 4 types of PDC bits from 3 manufacturers, and over 14,000' of 12 1/4" hole with 8 bit types from 4 manufacturers.
The paper discusses the PDC bit runs made, the performance in relation to conventional tri-cone bits, the effects of conventional hydraulics on PDC bit performance and the design of the PDC bits in terms of cutter density and placement, number of nozzles and their placement, and construction methods.
The outlook for future designs of PDC bit with respect to use in water base drilling fluids and on rotary drilling is presented.
The experience presented con be applied to drilling operations in a wide variety of areas to optimise usage of PDC bits in water based drilling fluids and on rotary drilling.
As a result of extensive testing within Sarawak and Sabah Shell operations, the use of 8 1/2" PDC bits in water based drilling fluids on rotary drilling con now be considered a proven application when drilling both clastics and carbonates. Only modest success has been achieved in 12 1/2" hole where tri-cone bit performance (Cost/ft) in generally softer clastic formations has proven more difficult to match with PDC bits.

Introduction
PDC (Stratapax) bit trials were initiated in Sarawak Shell Berhad/Sabah PDC (Stratapax) bit trials were initiated in Sarawak Shell Berhad/Sabah Shell Petroleum Company (SSB/SSPC) operations in July 1981. 30 runs in 12 1/4" size, 55 runs in 8 1/2" size and 4 runs in 6" size have been made. These trials involved a total of 57 bits of 14 different designs from 5 suppliers (Table 1). Bit prices range from US$15,000 to US$34,000 for 12 1/4" size and from US$10,000 to US$19,000 for 8 1/2" size.
All bit runs are judged in terms of profitability (cost per foot comparison against rock bits). Smaller diameter bits have been more successful with 70% success rate in 8 1/2" size (all 6" bit runs are also successful). Cost per foot (standard cost per boot equation using bit cost and cost of rig time) reductions vary from 19% to 250% in 8 1/2" bit runs (See Figures 1 and 2).
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Liquid Mud Plant Use and Benefit in the Arun Field
Authors: Soepardi Mulya , Kimiadi Irwanto 
Published: December 2007

ABSTRACT
This paper briefly discusses the abnormally high temperature and pressure conditions in the Arun Gas Field and examines the special mud requirements caused by these extreme conditions.
The next section focuses on the Liquid Mud Plant (LMP) which has been developed for use in the Arun Fieid to meet these special drilling fluid requirements.
The paper's conclusion points out the particular benefits of the LMP which produce cost savings in terms of both time and materials.
Geothermal Well Cementing Technology
Authors: Shryock S H 
Published: December 2007

ABSTRACT
The success or failure of drilling and completing Geothermal Wells depends reatly on available cementing technology. This requires not only having the knowledge of temperature stable competent materials but also a complete understanding of hole preparation, casing running procedures, mud displacement, lost circulation and the mixing-placing of the cement slurry.
Many steam fields are located where the formation contains poorly consolidated sedimentary deposits, rubblized shales and fractured volcanic rock. These formations are fragile in that some upheaval may have occurred disrupting the structural stability, and with low reservoir pressures, make them prime candidates for lost circulation problems. Many of the geothermal wells have to be drilled through and/or into these fractured formations. Loss of drilling mud or any other fluid put into the hole usually occurs creating problems which are expensive to eliminate. This paper offers methods which have proven successful in combating lost circulation during the drilling and casing cementing operations on geothermal wells located in fields all over the world.
Wareships Provide Economical Supply Base Alternative For Remote Area Drilling
Authors: Williams L.M. , Harrington J.P. 
Published: December 2007

Abstract
This paper discusses the three basic support-supply systems available to an operator when drilling offshore in remote, undeveloped areas of the world. These areoperate from a far distant port;construct one's own share base;use a wareship.
Each of these alternatives are discussed in detail, reviewing the various facets of support logistics for various cases. A cost comparison of the three alternatives for a typical one well and two well program are given. Some examples of Amoco Production Company's experience using wareships are discussed and advantages, other than cost, are listed.

Introduction
One of the major considerations, and often the most difficult, in mobilizing to drill an offshore exploratory well in a remote area is how to support and supply the drill rig. A remote area is one which is undeveloped or lacks adequate port and dock facilities and local infrastructure to provide a shore base. It is generally more than 150 nautical miles (278 km) distance from suitable port facilities. In these circumstances there are basically three alternative supply systems available to the operator:operate from the far distant port;build his own shore base;use a wareship.
This paper will examine each of these alternatives in detail and compare the overall costs for each. Amoco Production Company has used up to two wareships to support remote area operations in various regions of the world since 1974. Amoco's experience with their use is discussed later in the paper. Wareships provide advantages other than lower cost which will paper. Wareships provide advantages other than lower cost which will become evident within the paper.
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The Use of a Real-Time Wave and Weather Measurement Program to Assist in Offshore Operations and Tropical Cyclone Forecasting
Authors: Peters David J H 
Published: December 2007

ABSTRACT
This paper describes a program set up by Conoco to improve weather forecasts in the Gulf of Mexico and minimize the risk to the safety of offshore personnel during severe tropical cyclone events.
A series of automated wind, wave and weather stations have been deployed in the Gulf to improve the real-time data base available for forecasting.
This data is used in support of a hurricane alert program that utilizes the latest state-of-the-art techniques in oceanography and meteorology. Conoco has seen benefits in safer and more efficient evacuations during severe tropical cyclone events, timely return offshore, and a large increase in the amount of real-time information available on these storms.
Hydraulic Fracturing Design and Evaluation: A Case History
Authors: Al-Khatib A. M. , King A. R. , Wilson M. S. 
Published: December 2007

ABSTRACT
A unique method utilizing fluid entry surveys has been developed to improve fracture treatment designs at the Lost Hills Oil Field. Fluid entry surveys were conducted on thirty-two hydraulicly fractured wells in three different sections of the Lost Hills Oil Field. The surveys were analyzed to identify intervals of the completed zone contributing to flow (Contribution Ratio, CR) and to determine intervals of high water production.
Data from this type of analysis were then used to develop a correlation between the total thickness of the perforated/fractured zone and the fraction of that zone contributing to fluid flow (CR).
Considering this relationship as a potential design criteria, many fracture treatments were logged and evaluated. In conjunction with the aforementioned relationship, empirical correlations relating to perforation size and density, friction pressure losses and surface treatment rates were then used to modify the fracture treatment designs.
Foamed Cement: A Second Generation
Authors: Loeffler N. R. 
Published: December 2007

ABSTRACT
Advanced technology in design and implementation of stable foamed cement systems now offers new solutions to critical oil-field cementing problems well beyond the original utility of lightweight slurries in reducing hydrostatic pressure across fracture-sensitive zones. Implications of new high-performance foamed cement capabilities are discussed for specialized applications such as thermal recovery, deep cementing in a narrow annular gap, lost-circulation control and stimulation across fractured or washed-out zones, as well as other unique advantages in primary cementing.
Specialized foamed cement studies reveal improved prevention of strength and permeability retrogression and enhanced thermal isolation for steamflood applications, all at significantly reduced fracture stress as compared to conventional extended systems. Because of their unique rheology, high-performance foam slurries can be designed to exhibit moderate thixotropy but maintain excellent fluidity at extremely low shear. Cement foams further aid zonal isolation due to improved shear bonding and enhanced pipe/cement/formation contact as a result of the expansive nature of the slurry during setting.
A number of successful jobs are documented in which lightweight nitrified systems placed across weak and washed-out zones have been successfully perforated and fractured. Several new potential applications for moderate to high-density, stable, nitrified slurries are also discussed based on their unique performance.
Regional Models of Drilling Activity: Forecasting Rig Count in The Permian Basin
Authors: Dollens K. B. , Williams J. L. 
Published: December 2007

ABSTRACT
Ordinary least squares regression analysis is used to develop a model to forecast the Permian Basin rig count. Comparative analyses of various independent variables in linear, logarithmic and rate-of-change form indicate that approximately ninety percent of the variation in rig count can be explained using four independent variables. These variables represent Windfall Profits Tax, the maximum marginal personal income tax rate, crude oil price, and hourly wages of production workers in oil and gas extraction.
Optimizing Diamond Bit/Turbine Drilling Performance
Authors: Mason C. M. 
Published: December 2007

ABSTRACT
This paper explains the basic concepts and techniques necessary in optimizing and improving a turbine/diamond bit drilling application. Recent turbine/diamond bit drilling experience in the Morrow Formation of the Anadarko Basin indicates that a linear relationship exists between penetration rate and turbine output power available at the bit. Turbine output power is a linear function of the mud weight but more importantly, it is a function of the flow rate raised to the third power; therefore, slight increases in flow rate will yield significant increases in turbine output power. The increased turbine output power allows a higher bit weight which normally results in an increased penetration rate. Actual field data is presented which supports these relationships. Since fluid flow rate is of primary importance this paper describes techniques for maximizing flow rate. The importance of lithology is also presented. Finally, turbine/ diamond bit drilling economic evaluation is described.
Drilling in the Fletcher Area of the Deep Anadarko Basin
Authors: Humphrey D. R. 
Published: December 2007

Abstract
Drilling 20,000'+ high-pressure gas wells in southeastern Oklahoma (figure 1) presented numerous organizational, operational, and technological problems. Long open-hole sections between surface problems. Long open-hole sections between surface pipe shoe and intermediate pipe setting depth pipe shoe and intermediate pipe setting depth presented a number of problems. Among them were presented a number of problems. Among them were hole stability, corrosive gas influxes, over- and under-pressured formations and drill string fatigue. Deep high pressure sections below intermediate casing required high-strength tubulars and wellhead equipment. Industry shortages of materials and equipment plus inexperienced personnel compounded the difficulties. personnel compounded the difficulties.
Techniques for Successful Liner Cementing in the Anadarko Basin
Authors: Muncrief R. E. , LaFollette R. E. , Rainbolt C. G. 
Published: December 2007

ABSTRACT
By planning in advance and following proven techniques, many of the problems associated with the running and cementing of deep liners can be alleviated. Detailed considerations of casing designs, drilling fluid properties, cement designs, and special techniques are discussed.
Due to the nature of wells drilled in the Anadarko Basin, as with any area where abnormally high formation pressures are encountered, it has been noted that poor primary cementing jobs can often plague a well throughout its productive life. This paper deals with procedures which can be followed that should assist in planning and performing the job. Shown will be four separate tubular configurations dealing with three typical Anadarko Basin productive objectives.
Field Experience With Floodwater Diversion by Complexed Biopolymers
Authors: Abdo M. K. , Chung H. S. , Phelps C. H. , Klaric T. M. 
Published: December 2007

ABSTRACT
Due to preferential flow of the injected water through the most permeable zones, waterflooding of stratified reservoirs is generally inefficient. A process for improving the performance of waterfloods in such reservoirs has been developed; it is based on complexing biopolymers with multivalent cations to form gels for selective blocking of water-thief zones, thereby diverting the trailing floodwater to previously under-invaded reservoir regions to recover by-passed oil. This polymeric modification of stratification and of water injection profile leads to increased volumetric sweep of the reservoir by the floodwater and, in turn, to improved oil production. This paper summarizes Mobil's experience in its first seven field projects in Oklahoma using this process. A total of two hundred and five injection wells were treated with complexed biopolymers, resulting in substantial alteration of water flow patterns and in significant incremental oil recovery.
A Laboratory Study of CO2 Foam Properties and Displacement Mechanism
Authors: Wang G. C. 
Published: December 2007

Abstract
This paper presents the results of a comprehensive study of CO2-foam physical properties and a series of displacement tests using a high pressure glass-lined flow-tube. The foam properties were studied in terms of foam quality, quantity and stability as functions of temperature, pressure surfactant concentration and surfactant mixing ratio. The CO2-foam displacement tests were performed using SACROC and Rock Creek crude oils, and the oil recovery efficiency was visually investigated tor both secondary and tertiary modes with varying CO2 slug injection sequence and surfactant concentration.
The results indicate that the increase of pressure promotes foam stability whereas the increase of temperature does the contrary. It was found that CO2-foam generated either externally or internally is susceptible to quick disintegration on contact with crude oil. Therefore, the control of CO2 mobility using a foaming agent could be effective only within a short distance from the injection well. Any improvement on oil recovery or gas-oil ratio is probably obtained as a result of foam blockage of the permeable streaks or channels in the injection formation. It was found that excessively high concentrations of surfactant (foaming agent) may cause "foam barrier" to decrease sweep efficiency.
Handling Water Treating Problems In Steam Injection Projects
Authors: Fincher D.R. , Hagist F.C. , Gallagher D.L. 
Published: December 2007

Publication Rights Reserved
This paper was to be presented at the 40th Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in Denver, Colorado, October 3–6, 1965, and is considered 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 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, with the paper, may be considered for publication in one of the two SPE magazines.

Abstract
Water to be used for steam injection projects must contain a very small amount of hardness ions and oxygen. corrosion should be monitored at several locations. Methods used to accomplish these objectives are described.

Introduction
Steam has been used to transfer energy for many years. In the oil field, steam has been used to heat oil for demulsification and viscosity-reduction purposes, as well as used as a source of power to drill oil wells. During the past few years, much emphasis has been placed on thermal recovery of low-gravity viscous crude by the injection of steam into the reservoir. This use of steam was tried in the 1930s, but it has reached real prominence in the oil industry only during the past five to ten years. Today, much interest exists in the generation of steam for injection into oil bearing strata, and many approaches are offered to the handling of this fluid.

Steam Generator Equipment and Water Sources
Many authors describe the qualities of the waters that are necessary for steam generation. The pitfalls of poor handling of boiler feed water are well known, and they have been made the subject of books and other literature. This paper deals with water treatment and handling designed for a steam product of approximately 80 per cent quality. The equipment referred to includes only the once-through steam generator where there is neither recirculation of the water phase nor blowdown of concentrated, soluble or insoluble, salts from the steam generator.