bluuebunny/crossref_metadata_2025_split huggingface dataset:
Shallow Seismic As An Aid To Locating Offshore Installations
Authors: Huysinga J.K. , Biddle A.R. 
Published: December 2007

Summary
The geotechnical characteristics of the North Sea soils are often highly variable even over small distances.
To derive a three-dimensional picture of an area earmarked for platform location is only possible by integrating seismic data and information from soil borings.
This information is needed to select the best location for the structure and to optimise its design.

INTRODUCTION
The final choice of location for the placement of large production platforms in the North Sea is mainly dependent upon the size, depth and lateral extend of the hydrocarbon-bearing reservoirs. However, the soils of the North Sea have been found to be highly variable and often weak in geotechnical terms at shallow depths. This variability in soil types makes it imperative that optimum sites, from an engineering design and installation viewpoint, be found for a particular structure under consideration.
It has been shown that a small shift of a platform site can have a considerable impact on both type of platform and the costs involved in construction and installation. Geophysical techniques have been used in an attempt to determine the lateral continuity of soil layers revealed in site investigation borings. Problems of inadequate seismic resolution and penetration have had to be contended with but it has been found that provided the appropriate tools to suite a particular soil stratigraphy are selected much useful data can be obtained to aid platform site selection. This effort has stimulated the development of new shallow seismic tools and recording techniques which have improved the capability of the industry. This paper describes methods used in the North Sea to obtain the soil data needed for platform location selection and stresses the need for good consultation between the reservoir engineering team, the soil specialists, and the construction engineering team before a final decision on the platform site is take.

RESERVOIR UNCERTAINTIES
Experience in the North Sea. has shown that there is a certain amount of flexibility (sometimes as much as lkm) in locating a platform when only the optimum drainage pattern of the reservoir is considered. The drainage area of a single platform varies in diameter from 6 to 8 km depending on the depth of the reservoir. For fields whose areal extent in one or more directions is larger than the maximum drainage circle and for fields which are much smaller than this circle there is usually no unique optimum platform site.
For nearly all fields in the North Sea there is an even greater apparent freedom of choice if one realises that at the time when a decision for the site has to be taken the field is generally still not well defined. Small shifts of the location of the platform can there fore nearly always be absorbed in the flexibility allowed in the development plan of a given field.
Garoupa Subsea Production System
Authors: DeJong J. , Adamson S.M. 
Published: December 2007

Abstract
The Garoupa production system installed offshore Brazil for Petrobras is now onstream. This system represents one of the most ambitious undertakings of its kind. The nine subsea wells are completed using a dry one-atmosphere chamber system supplied by Lockheed Petroleum Services (LPS). Well production flows to a Petroleum Services (LPS). Well production flows to a seabed dry manifold centre where it is controlled and manifold. Pipelines connect the MC to a mooring tower to which a converted tanker is moored for processing of crude and its temporary storage. A second mooring tower provides for tanker transport of crude to land. provides for tanker transport of crude to land. Installation of the subsea equipment is described. Flowline bundle and pipeline and start-up progress to March 1979 is described and some of the problems encountered their solution and impact on project schedule are discussed.

Introduction
The Garoupa field seafloor production system installed by the Brazilian National Petroleum Company. Petroleo Brasileiro S.A. (Petrobras), is the largest and most ambitious subsea production project initiated to date. The field, which is located 250 km. east-northeast of Rio de Janeiro, and 80 km offshore, (see Fig. 1) was discovered in November 1974. Further drilling proved it to consist of two separate structures, the northern Garoupa field and the southern Namorado field. The subsea production system is installed in water depths between 120–166 m. (394–544 ft). The system (Fig. 2) consists of:nine one-atmosphere wellhead chambers (WHC)supplied by Lockheed Petroleum Services.a nine-well one-atmosphere manifold centre (MC)supplied by Lockheed Petroleum Services.an electro-hydraulic control system supplied by Cameron Iron Works.
Geological Aspects Of The Drilling Of The Buchan Field
Authors: HILL P.J. , Smith G. 
Published: December 2007

INTRODUCTION AND HISTORICAL BACKGROUND
The Buchan field, located some 150 km north east of Aberdeen in 120 m of water, is situated largely in the UK licence block 21/1 (P.241) that was granted to Transworld Petroleum (UK) Ltd. in July 1972. (Fig. 1) The discovery Petroleum (UK) Ltd. in July 1972. (Fig. 1) The discovery well 21/1-1 was drilled in June 1974, and was followed during 1975–76 by three appraisal wells, two of which eventually penetrated and tested the reservoir. However, the appraisal wells 21/1-2 and 21/1-4 experienced serious drilling problems at the top of the reservoir section and were eventually lost. These wells serve as illustrations of the extreme difficulties encountered in drilling this structure and proved the existence of a complex, fault-controlled structure with a maximum oil column of 582 m in overpressured, highly fractured, low porosity reservoir sandstone of Devonian-Lower Carboniferous porosity reservoir sandstone of Devonian-Lower Carboniferous age (Fig. 2).In July 1977 as a result of a farm-in agreement BP Petroleum Development Ltd., became the operator of Petroleum Development Ltd., became the operator of licence P.241 and took a 54 1/76 per cent interest in the Buchan field. In planning any development of the field it became evident that a conventional North Sea drilling production platform would be economically, a very high production platform would be economically, a very high risk proposition. The size and complicated nature of the structure and reservoir sandstones posed many questions regarding the reliable calculation of oil in place and recovery factor, and make the field worthy of the title marginal. As a result of feasibility studies it was decided to develop the field from eight wells producing to a converted semi-submersible platform. Transportation of the stabilized crude will be by a tanker shuttle service via an offshore loading buoy located close to the platform (Fig 3.). Production is planned to start in the autumn of 1979. In Production is planned to start in the autumn of 1979. In a time sensitive plan of this nature, and in view of the past drilling history, the successful completion of the past drilling history, the successful completion of the drilling phase was an important step in the development of the field. Development drilling commenced in September 1977 and was completed in early November 1978.
Drilling, Evaluation And Completing High Angled Wells In The North Sea
Authors: Woodall-Mason N. 
Published: December 2007

Abstract
Drilling, evaluating and completing two wells at angles in excess of 70 degrees required planning to account for the reduced along hole component of gravitational force. Drilling assemblies and their build up characteristics were affected and friction forces experienced by surveying and electic logging tools and perforating guns necessitated the use of the pump down technique. An S shaped hole allowed free fall below the shoe of the pump down string. The high angle adversely affected bore hole stability requiring higher mud weights to hold back the hole and hole condition was found to be more sensitive to changes in mud properties and to mud quality. A production test procedure and completion string were compiled and procedure and completion string were compiled and designed, neither of which made use of gravitational forces for wireline tool operation below 4,000 ft.

Introduction
In order to reach areas of the Aukfield not falling within the existing drainage pattern, Shell Expro embarked upon the drilling of 2 highly deviated offshore wells. A-03 and A-09, with a view to completion as single string oil producers. Auk-A is a small 12 slot steel platform located producers. Auk-A is a small 12 slot steel platform located in 280 ft of water in the central North Sea. Eight wells had then been drilled into various areas of the reservoir. The central North Sea Lithology is well known for its high content of both mud making and dispersible clays above 7,000 ft requiring a mud weight of some 12.5 pounds per gallon (ppg). Below 7,000 ft in the fractured pounds per gallon (ppg). Below 7,000 ft in the fractured Cretaceous and Permian evaporites (Fig. 1), losses had been experienced with mud weights in excess of 10.5 ppg necessitating the setting of a string of intermediate casing. In previous wells where the angles were less than 60 degrees it was possible to drill for and set 9 5/8 in. casing in the top chalk. However, with the long tangent sections in A-03/ A-09, the 9 5/8 in. was required higher necessitating a 7 in. liner in its place and a 4 1/2 in. liner across the reservoir section of Zechstein chalk and Rotliegend sandstone (Fig. 2).
Treatment Fluids To Improve Sea Water Injection
Authors: Davison P. , Hyatt J.P. , Grist D.M. , Gardiner D.C. 
Published: December 2007

Introduction
Sea water injection to maintain reservoir pressure is currently practised in several North Sea reservoirs viz: Beryl, Forties, Montrose, Piper and Claymore. Injection wells may be completed wholly in an oil bearing zone (pattern flood case) or partly in an oil bearing or transition zone (peripheral flood case). In either case the rate of water injection is restricted by the presence of crude oil in the pores of the rock particularly in the region immediately around the well. This oil is immobile despite continued water injection. The injection rates can be raised, however, if the oil in this critical region is removed as the conductivity (permeability) of the formation will be increased. Very considerable increases in injection rates were reported by previous investigators who used micellar solutions (complex surfactant solutions) to stimulate wells by residual oil removal.
Corrosion Control For Fixed Production Platforms Subsea By Coatings And Cathodic Protection - A Review Of Recent Experience
Authors: Pursell M.J. 
Published: December 2007

Introduction
British Petroleum has tong had a different approach to the underwater protection of fixed structures from that of other oil companies. The major point of divergence is the use of paint coatings in conjunction with sacrificial cathodic protection. The technique has proved remarkably successful, especially for deep water structures. This paper reviews the history and development of the technique and it discusses in greater depth its application to the deep water Forties field structures. The author has insufficient knowledge of the particular applications of competitive techniques to make safe comparisons. Those with more intimate knowledge must judge.

HISTORY AND DEVELOPMENT
BP formed its ideas through the 1960s. which was a period when it was developing offshore oilfields for Abu period when it was developing offshore oilfields for Abu Dhabi Marine Areas (ADMA) and a gas field at the West Sole in the southern North Sea. Both had water depths in the order of 30 m. and were developed with a lumber of small structures. Some know-how was available in the late 1950s from mainly US sources but it was some of BP's own work on the protection of salt water fed cooling equipment that was found to be the most convincing. Particularly the work had shown the value of coatings for the improvement of the spread of protection and for the extension of anode life. If coal tar/epoxy paints had not been developed around the same time then the technique would probably not have been a success. The pure epoxies used for the cooling water work were too expensive and too difficult to apply for use on structures. The bituminous paints used for a few early ADMA structures suffered badly from attack by marine growth. Coal tar/epoxy has been proved to be cheap enough and sufficiently tolerant in application. Recent inspections on the West Sole have shown no coating degradation after ten years service. Minor mechanical damage has occurred due to abrasion by for instance, wire rope debris and during marine growth removal.
Pipeline Trenching In The Future
Authors: Erling Saebo , Andersen Terje 
Published: December 2007

Abstract
Like all other work related to offshore activities. trenching of pipelines seems to be more troublesome in the North Sea than in other parts of the world. This is either because more attention is paid to the results in this area, or because the environmental conditions make it more difficult to perform satisfactorily with the same equipment. The problem with conventional trenching equipment is that it does not perform well in clayey soils. and in several cases misoperation has resulted in damage to coating and pipeline (leading to rupture during pressure testing). This pipeline (leading to rupture during pressure testing). This possibility. taking into account the cost of trenching and possibility. taking into account the cost of trenching and pipeline repairs. should be weighed against the protection pipeline repairs. should be weighed against the protection provided by a trench towards natural and man-made provided by a trench towards natural and man-made hazards. This paper discusses the influence of trenching on pipeline safety for trunk lines with a diameter of more than pipeline safety for trunk lines with a diameter of more than 30 in. For smaller diameter pipelines the conditions may be different. Statistical analysis of pipeline failures show that the most important causes are corrosion and equipment fault. These types of failure can hardly be affected by trenching. Another important cause is anchor dragging, which also only to a limited extent can be protected for by trenching. For the major offshore pipelines constructed or planned in the North Sea over the last few years. great emphasis has been put on thorough investigation of the needs for protection of pipelines of the seabed. Based on our protection of pipelines of the seabed. Based on our knowledge of these investigations carried out by owners and operators of submarine pipelines. and on our experience as a certifying agency and consultants to oil companies. our evaluation of trenching as a safety pressure is given in this paper. A shore summary is given pressure is given in this paper. A shore summary is given below.
Operational Experiences With The Offshore Loading Units Auk-ELSBM And Brent-SPAR
Authors: Buyzen J.P.M. 
Published: December 2007

Buyzen, J.P.M., Shell Expro UK Ltd. Scotland

Introduction
Shell Expro operates in the British sector of the North Sea on behalf of Shell and Exxon. The company has three operating locations: London, (Head Office), Lowesoft (Southern Gas fields) and Aberdeen (Middle and Northern North Sea). This paper deals with the operation of the Auk-ELSBM (Middle North Sea) and Brent-SPAR (Northern North Sea), activities which are controlled from Aberdeen (Fig. 1).

DESCRIPTION OF THE INSTALLATIONS

General
The hostile environment of the North Sea demands a major effort with respect to the design and effective operation of the offshore loading facilities. Although designs show significant differences, each of these installations is a variation of the Single Point Mooring theme, in that they all incorporate some form of mooring turntable and fluid swivel, which permits the tanker, while remaining moored, to weathervane around the SPM in response to the prevailing weather and sea conditions.
THE AUK-ELSBM (Exposed Location Single Buoy Mooring)

Location
The ELSBM is located 2,000 m from the Auk platform and moored to the seabed by 8 anchors, each weighing 15 tons, which are set around the buoy in a circle with a 460 m radius. Each anchor is attached to the ELSBM by a 3 in. diameter stud link chain and is pretensioned (Fig. 2). The water depth in the Auk field is 84 m.
The World Bank Program To Accelerate Oil And Gas Production In The Developing Countries
Authors: Friedmann Efrain , Elejalde Eduardo 
Published: December 2007

Introduction
I would like to thank you for the opportunity to discuss with you the World Bank's Program to Accelerate Oil and Gas Production in the Developing Countries. Before discussing the program itself, and the role we see for the World Bank in assisting developing countries to manage their energy resources, I will say a few words about the World Bank.

The World Bank
The World Bank was established in 1945 following a United Nations Monetary and Financial Conference of 44 Governments at Bretton Woods, New Hampshire. The International Monetary Fund also was founded as a result of that conference. The World Bank is owned by the governments of 132 countries. It obtains its funds primarily from its own borrowings in the world capital markets, from its net earnings, the flow of repayments of its loans, and also from the paid in capital subscriptions of its member countries. The Bank's first loans were made for post-World War II reconstruction. However, by 1949, the emphasis had shifted to loans for the purpose of economic development. Loans are made directly to governments, to state enterprises, or to private companies, with a government guarantee. The bulk of the World Bank loans have been for specific projects in such sectors as agriculture and rural development, education, electric power, industry, population planning, telecommunications, tourism, urban development and water supply in developing countries.
Characterization and Mapping of Burrowed and Microporous Intervals in the Arab D Reservoir, Dukhan Field, Qatar
Authors: Trabelsi Ali , Beg Mirza Arshad 
Published: December 2007

Abstract
Several burrowed and microporous intervals occur throughout the Jurassic Arab D Reservoir of the Dukhan Field, Qatar. Burrowed intervals are characterized by variations in porosity and permeability values between the burrow structures and the surrounding rock matrix. Measured porosity and permeability of burrows in most instances is higher than the surrounding rock matrix. The burrows were selectively dolomitized, whereas the surrounding rock matrix remained unaffected.
Microporosity also occurs in several intervals of the Arab D Reservoir. Qualitative petrographic examination indicates that microporosity occurs within allochems (peloids, ooids and skeletal grains) and rock matrix. Thin section point counts and pore throat size distributions derived from capillary pressure data were used to estimate the amount of microporosity. Microporosity varies from sample to sample and can range from 5 % to about 90 % of the total measured porosity of a sample. Depositional texture, grain mineralogy and microstructure control variations in microporosity abundance and type. Microporosity resulted from dissolution and incomplete re-precipitation of metastable carbonate and boring of grains by fungi and endolithic algae.
We are documenting the abundance of microporosity and mapping the occurrence and distribution of the burrowed and intervals. This will lead to a better understanding of the properties of the fluid flow and the ultimate recovery of hydrocarbons in this giant field.
Towards Zero Flaring Emission
Authors: El Messiri Amir , Al Attas M.O. , Nashat Mohamed , Malash Karim 
Published: December 2007

Abstract
ADMA-OPCO Drilling Division took the initiative and formed a joint Task Force with ZADCO and put together, with the help of the contracted service providers, a plan to gradually achieve ADNOC's targets for Flaring Emission Reduction, categorized in Three stages as follows:- (see summary-Table-1)
Two pumping systems were introduced in May 1998, to serve the full range of the operating envelope of all ADMA and ZADCO wells. A third "Pumping System" was introduced in December 1999. This helped reduce oil flaring by 65% (200,000 bbls oil were re-injected).
ADMA-OPCO had successfully tried, via the Rigless well Invention Operations to re-inject the produced separated gas, together with the oil. ADMA-Drilling are currently studying this process with ADMA-Engineering Division, in order to Safely introduce this scenario to the eleven operating rigs. This step once implemented can reduce ±30% of gas flaring emission related to drilling operations.
Neutralization Systems neutralize the well's back flowed effluents allowing to flow immediately through the test separator, thus re-injecting the oil at the clean up phase. The 1st Neutralization trial job was carried out in February 2000 where zero oil flaring was achieved. It is expected that oilflaring reduction would reach 90%+ by the utilization of Neutralization Systems before end Year 2000. Currently only two neutralization units utilized. However, it is planned to have four units in operation before the end of year 2000.
The introduction of multi-Phase pumps, to replace the currently utilized single phase oil re-injection pumps will help achieve the re-injection of the gas, commingled with the oil (currently, this gas is being routed to the burners). It is targeted to have these pumps operational during 2001.
By the introduction of the Multiphase Pumps and with the aid of the neutralization systems, it is believed that we would achieve the Practical Zero Flaring Emission.

Introduction
ADMA and ZADCO were burning oil, during drilling related clean-up and testing operations. Estimated quantities of oil and gas burned and re-injected from Jan. 1997 to May 2000 are summarized in Table-2. About 100,000 bbls of oil were reinjected during 1999. Clean up operations were conducted to achieve a zero BS&W in ZADCO wells while ADMA were accepting higher range of BS&W. ZADCO main reasons are to protect surface facilities and sea line from corrosion. It took approximately three hours to clean up the well from 5% BS&W until it was allowed to start re-injecting the oil into the production facility (See table 3). The Flaring Emission Reduction Task Force (FERTF) was convinced that a large quantity of oil is being flared unnecessarily, hence discussions within ZADCO lead to some flexibility without compromising the Production line integrity. ZADCO agreed that re-injection can commence once BS&W reaches a stable condition for three continuous hours, provided that Cl++ and Ca++ are within an acceptable range. This has saved three hours of oil flaring (±3,000 bbls of oil).