bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Design, Drilling, and Testing of a Deviated High-Temperature, High-Pressure Exploration Well in the North Sea
Authors: Seymour K.P. , MacAndrew Robert 
Published: October 2008

ABSTRACT
Significant quantities of hydrocarbon reserves are contained in North Sea high temperature, high pressure reservoirs. Development of these reserves will require the drilling of deviated wells.
This paper outlines the planning. drilling and testing of the ftrst deviated HTHP well in the UK North Sea.

INTRODUCTION
Within the oil industry there is a general term "high temperature, high pressure (HTHP) drilling". This term has slightly varying definitions in different areas. In this paper the definition used for HTHP drilling is that of the UK Health and Safety Executive (HSE) which has the statutory responsibility for safety in the UK.
This definition is contained in Continental Shelf Operations Notice (CSON) 591 and is that the undisturbed bottom hole temperature must exceed 300°F (149°C) and have a pore pressure gradient in excess of O.8psi/ft or require the use of well control equipment in excess of l0,000psi working pressure.
These wells may be characterised by the following:A rapidly rising pore pressure profile.Convergence of pore and fracture pressures.High gas levels from the source rocks.Loss gain phenomena.Potentially long sections leading to high over balances.Elevated temperatures.
The high temperature requires mud systems, downhole equipment and tools designed to work at elevated temperature.
The convergence of pore and fracture pressures (see figure 1) leads to problems due to the narrow band of mud weight between inducing losses and inducing a kick. This is the aspect of these wells which most probably leads to most trouble.
The high mud weights required for well control leads to a situation, common in the North Sea, where due to the large difference between formation fluid and mud pressure gradients (see figure 2) mud overbalance becomes so high at the bottom of long permeable hole sections that differential sticking becomes likely.
These problems are magnified when drilling small diameter directional holes. The most important single factor is mud, it's weight and system design.

BACKGROUND
Well 22/22b-2 was a farm in exploration well. The objective was to test a Jurassic fault block by drilling to 16,000ft. The well was planned to penetrate the Jurassic in an up-dip location on the upthrown side of the large fault therefore the well had to be deviated (see figure 3).

WELL DESIGN

Casing
The casing design was conventional by North Sea standards (see figure 4 and table 1); Krus and Prieur2 have described the factors in HTHP well design in U.K. waters.
Despite it's conventional appearance there were two major points which had to be addressed. The first was the placing of the 13-3/8" casing shoe. The question here was whether to place the shoe above or below the Palaeocene sands. There are two schools of though on this. One is that the shoe should be placed above the Palaeocene with the top of the deep casing cement below the bottom of the Palaeocene.
High-Precision, Low-Cost Bathymetry Surveys
Authors: Mes M.J. 
Published: October 2008

SUMMARY:
The subsidence bowl at the offshore North Sea Ekofisk field is measured periodically by high precision bathymetry surveys. Phillips Petroleum Company Norway, the operator of the Ekofisk field, installed heave compensated echo sounding equipment on the "Viking Troll" one of the largest North Sea supply boats. With this relatively small investment we can obtain high quality relative bathymetry measurements with the ship's crew as surveyors. Survey data are presented which explain improved survey procedures used to obtain high accuracy bathymetry surveys. Advances in data processing are described. This include procedures to de-tide waterdepth information as well as de-spike the original waterdepth records.

INTRODUCTION
The Ekofisk field is located in the central North Sea. It is oil and gas producing field. Hydrocarbons are produced at a rate of approximately 200,000 bbls per day from three offshore platforms on the field. In November 1984 subsidence in the Ekofisk area was observed and programs to measure the subsidence and its progression were subsequently developed.
We conduct regular bathymetry surveys to check the development of the subsidence measurements of a relative accuracy in excess of what is customary for this type of survey work. Renting a crew and a survey vessel periodically to conduct such a survey is expensive. For that reason we decided to install a GPS navigation system, a digital Navisound 2000 echosounder and a heave compensator on a supply boat on long term contract to us, the m/s "Viking Troll". This vessel is a 3000 ton supply boat. In combination with other work such as platform standby, duty and freight service this boat is ideally suited to conduct bathymetry survey's during periods when there is no higher priority work for the vessel.
Our reference Greater Ekofisk area survey consists of 1200 kilometers East-West and North-South survey lines over the Ekofisk, West Ekofisk and Eldfisk area. The survey line spacing is one kilometer for the general area and 500 meters near Ekofisk and West Ekofisk.
From the Navstar Global Positioning System (GPS) the geographical position is obtained and supplied to a portable computer (PC) every four seconds. Apart from a positioning system the GPS system also supplies clock and calendar information. Because this information is independent of PC settings, we use the GPS system also for time tagging the bathymetry information. The PC polls the echo sounder and heave compensator for waterdepth and ship's heave information. Data are stored on diskettes and on the PC hard disk as a backup.
The survey lines are pre-programmed when the survey on a particular line is system and type in the survey line number. started, the vessel crew switches on the On a monitor mounted near the helm, the ship's position with respect to the ideal position is shown on a map which also shows the platforms in the area and the survey line. The orientation of the map is such that the end point of the survey line is always at the top of the screen.
Geotechnical Aspects Of Bucket Foundations Replacing Piles For The Europipe 16/11-E Jacket
Authors: Tjelta Tor-lnge 
Published: October 2008

ABSTRACT
A major departure from traditional foundation piles for jackets is planned for the Europipe 16/11-E riser platform in the North Sea. Scheduled for installation in the summer 1994 in 70 m water depth, the jacket will have no piles. The permanent foundation will consist of a 12 m diameter mudmat at each of the 4 corner legs fitted with skirts projecting down from its periphery. This new concept will use suction to achieve the fill penetration depth of 6 m. The structure will not rely on gravity platform principles only, but will use passive suction generated by tension load to resist the overturning moment from environmental forces.

INTRODUCTION
Jacket structures have always been supported and tied down to the sea bottom by piles. Only one known steel structure is different, the Maureen steel gravity structure, ref. Agostoni et al. (1980). With the exception of Maureen, alternatives to piled steel jackets have not been available.
The riser platform now under construction for the Europipe gas pipeline in block 16/11 has its piles replaced by bucket foundations, see Fig, 1. In each corner of the four legged jacket the mudmat has been equipped with 6m steel skirts projecting down into the soil. Baerheim (1994) presents further structural details. Even though skirted mudmats are not a new type of foundation since it has been used for a number of jackets to secure on bottom stability, they have always represented a temporary solution prior to pile installation, probably because of a reluctance to accept that tension capacity is available in soils. Tension capacity refers here to the uplift resistance of an object being retrieved from the sea bottom within a limited time period.
This uplift capacity is well documented in clay and is the basis for the skirted concrete foundation units used for the Snorre TLP, ref. Andersen (1992). For sand the same uplift capacity is less accepted in the industry, but development work supporting the Europipe jacket foundations has given confidence in this new concept, called in this paper bucket foundation.
The adequateness of a bucket foundation, from a geotechnical point of view, for supporting a jacket on strong soils can be shown in two example calculations for clay and sand: Given a steel plate with dimensions 2×20m and 25rnm thickness. This plate can theoretically provide bearing capacity in three different ways:A vertical plate penetrated into the soil,The same plate rolled as a pile andThe plate laying flat on the ground.
For a clay with undrained shear strength of 100 kPa. For a dense North Sea sand, the capacities correspond to the values in Fig. 3(available in full paper). From a theoretical standpoint, the flat plate resting on the surface is the obvious choice.
Since the non-stiffened flat plate is not the practical way of supporting structures, a structural compromise can be the inverted bucket which has the highest capacity of all the alternatives.
Captain Extended Well Test Program: Project Management And Execution
Authors: Lovaas W.L. , Weller C.N. , Huddleston Wayne , Wells Brian 
Published: October 2008

ABSTRACT
Extended Well Tests (EWTs) are gaining increasing recognition throughout the offshore industry as a useful tool for evaluation of field development prospects. These tests, which can range from a few weeks to several months in duration, provide valuable data for reservoir evaluation and design of field development facilities. This paper describes how a contractor serving as project manager supported Texaco North Sea (UK) Company in the planning, organization and execution of a fast-track EWT at the Captain field prospect offshore Scotland.

INTRODUCTION
In November 1992, Texaco North Sea (UK) Co. awarded a contract to Oceaneering to perform project management services for an extended well test (EWT) of its Captain prospect. Captain is located in the Moray Firth, Block 13/22 of the UK sector, 90 kilometers east of Wick, Scotland, in 107 meters of water, Fig. 1.
The field was discovered in 1977 when an exploratory well encountered 191 feet of oil-bearing sand. Further delineation followed in 1989 and 1990 with additional wells. A well to the north in 1989 found 93 feet of oil sands and flowed at 740 BOPD using an electric submersible pump (ESP). It was determined that horizontal wells were necessary if commercial production rates were to be achieved. In 1990, one horizontal well was drilled. Again using an ESP, it produced 6,500 BOPD of heavy 19Degree API gravity oil. From this and other data it was theorized that there might be about 200 million barrels of recoverable oil in the field.
The EWT program was originally scheduled to commence with the drilling phase in January, 1993, and to conclude following a 90day extended well test in September. During the test phase, the produced crude would be Processed by equipment installed a board a semisubmersible drilling rig and exported to a storage tanker as clean stabilized crude oil.
The purpose of the extended well test program was to confirm the magnitude and producibility of the Captain field. Test results would be used to determine sustainable crude oil flow rates and the probability of early water cuts which would impact field economics. This information would contribute to design of the eventual field development program and facilities. It was very important to test the oil and water separation techniques the high viscosity crude with the ESP-induced emulsions.
The main task a fix the EWT program included the following:Establish appropriate management systems and ProceduresFinalize vessel and hardware subcontractsFinalize flowline design and submit it to regulatory authoritiesDirect requisite rig modificationsto accommodate the process facilityEnsure timely detail process design and fabrication.
The main EWT system components used during execution of the well test program were: the spread-moored semi- submersible which drilled the wells and later served as the test platform for the process equipment; the process system; the flexible export flowline and the dynamically positioned storage tanker, Fig. 2.
Inter Platform Power Distribution
Authors: Evans A.R. , McConnell James , French B.D. , Kauffman B.A. 
Published: October 2008

ABSTRACT
In today's world of high operating costs and low oil prices new methods of construction are needed to ensure economic viability. One such way is to maximise the use of an existing infrastructure.
Marathon utilized surplus power generated on Brae A and Brae B to supply the requirements of East Brae using transfer by 33kV sub-sea cable. First oil was produced in December 1993.
This resulted in platform weight savings of ground 3000 tonnes, with cost savings in excess of £60 million.

INTRODUCTION
East Brae is the third of a three platform development located in the UK sector of the North Sea and operated by Marathon Oil UK on behalf of the Brue Group, see Fig, 1. First oil was produced from the East Brae reservoir, on schedule, during December 1993.
In today 's world of high operating costs and low oil price, new methods of construction are required to ensure economic viability. One such way to reduce expenditure is to maximise the use of the existing infrastructure, thus reducing weight. capital expenditure and operating costs.
Marathon utilised that existing surplus power generated on the Brae A and Brae B platforms to supply the power requirements of East Brae. This took the form of a "ring-main" between the three platforms. sec Fig. 2(Available in full paper).
There are four dual fuelled turbine/generator units installed on Brae A, each rated at 20MW, giving a total capacity of SOMW, the load on this platform is now 33MW.
On Brae B there are three dual fuelled turbine/generator units installed, each rated at 24MW, giving a total capacity of 72MW, the load on the platform is 27MW.
This gives an installed field capacity of 152MW and a firm capacity of 128MW. (152 - 24), The final load on East Brae will eventually be in the order of 20MW.
The total field power requirements will therefore be 33+27+20 = 80MW, which can be achieved by operating any five of the seven generators. This is sufficient for HT motor starting and also avoids the need to loud shed upon failure of a single generator.

JUSTIFICATION
Before a start could be made on the project it was necessary to confirm the feasibility of the proposed scheme and in order to arrive at that stage it was essential to make a number of assumptions. One of these was in respect of the platform loadings at the time when East Brae would come into production (late 1993).
Other assumptions made, concerning the Electrical Engineering aspect, were that the existing switchgear was suitable to absorb the extra current loading and that the fault level ratings of the switchgear were capable of taking the added fault contribution when the three platforms were inter-connected.
Load flow diagrams were produced showing the envisaged current flows when the platforms were interconnected. From these diagrams it was confirmed that the main bus-bar ratings were acceptable. The only modification required was that the "droppers" to the new circuit breakers for the sub-sea cable, from the main bus-bar, would have to be increased from 1600 amps to 2000 amps, the bus-bar rating.
Deepwater Pipelines: Improving State Of The Art
Authors: Palmer A.C. 
Published: October 2008

Abstract
The paper examines the factors that need to be taken into account in the design of pipelines in deep water, and the extent to which proven construction techniques and existing equipment can be applied. It considers the design problems that arise in deep water, particularly the need for the pipeline to resist external pressure if conventional pipe laying practice is followed. It shows that much can be done with existing knowledge, and explores the problems that remain.

Introduction
Pipelines are far the most economical method for transporting large quantities of fluids. Other modes are more economical only when the quantities are too small to justify the capital cost of a pipeline, or when political disruptions make it impossible to agree on the construction of a line or to make its continued operation secure and reliable, or in a few instances where technical difficulties. Make it impossible to construct a pipeline. The principal technical difficulties are related to extreme depths, and occasionally to uneven seabed and to high currents. The difficulties are more often political than technical.
There is a demand for pipelines in very deep water. The demand comes from various directions. First, there are known to be oil, gas, condensate and hydrate fields in sedimentary basins in several areas, among them the Gulf of Mexico, the Atlantic Ocean west of Shetland, north-east of Greenland and east of the United States, the Davis Strait between Canada and Greenland, the Canadian Arctic Archipelago, and several areas in south-east Asia. Some of these resources are beginning to be developed, notably in the Gulf of Mexico, where the comforting factor of political stability makes up for the high cost of development. It is difficult to imagine that many of these projects will go ahead when the oil price is as low as it is now ($14.14 /barrel on the day this is written), but the world consumes oil at a frightening rate, about 50 million barrels a day, and deep-water reserves will be needed before too long.
Second, there are ambitious projects for long-distance transportation of gas. Marine transportation of gas as LNG is less attractive than marine transportation of oil, because about 30 per cent of the original energy content of the gas is lost in the process of liquefaction, transportation and degasification, Gas is such an attractive and convenient fuel and petrochemicals feedstock that once it becomes available economies use gas in preference to other fuels. In the past, much associated gds was flared, an example of irresponsible waste of nature's resources that we must reproach ourselves with, but the demand now is to move gas to markets, even markets at a long distance from reserves. These factors generate demands for long-distance pipelines, and among possible projects are several lines which include deep-water crossings:from Nigeria and Algeria to Europe;from the middle East westward into Europe;from the middle East eastward to Pakistan, India, China and Japan;from Siberia eastward to Japan;from south-east Asia north to China and Japan.
Deepwater Pipelay: Extending The Limits
Authors: Tollin B.I. , Wilson G.J. , Martin R.G. 
Published: October 2008

ABSTRACT
The Stena Apache laid pipe in a record 900 metres water depth in 1994 following vessel modifications and remote systems development. The potential limits for further advances into deeper waters are explored. It is concluded there is scope for further enhancement such that potential deeper water developments can be economically brought on stream.

INTRODUCTION
In recent years, the offshore industry has shows a determination to develop prospects in deeper water. This has resulted in the frontiers of deepwater pipelay being pushed to new limits.
Pipelay is typically performed using J-Lay or S-Lay methods from laybarges, or by reel-lay as with the Stena Apache reelship. The Stena Apache uses what is essentially a J-Lay method over an adjustable ramp which is fed by pipe from the reel. The reel is loaded with pipe at a welding spoolbase located at a convenient onshore location.
The Stena Apache has undertaken many pipelay works, primarily in the North Sea. Work outside the North Sea has taken the vessel to the Bass Strait in Australia, the Gulf of Mexico, the Malaspina and Georgia Straits off Vancouver, Canada and the Campos Basin in Brazil.
In mid 1993, Petroleo Bràs sileiro S.A. (Petrobras) awarded a contract to Stena Offshore Ltd. for the installation of multiple flowlines for the Marlim Phase I Development Project, located in the Campos Basin, Brazil.
Stena Offshore had previously performed other work for Petrobràs in the Campos Basin area. In the most recent works, completed in early 1992, the Stena Apache laid 10 inch pipe in a maximum water depth of 705 metres.
The progression of pipelay depth for the Stena Apache has increased rapidly in the last five years, from average water depths of about 140 metres in the Northern North Sea, to the recently completed works off Brazil to 900 metres, see Fig. 1.
The industry is currently looking to lay pipe in even deeper waters, for example to 1800 metres in the Gulf of Mexico and to 3000 metres in the Arabian Sea1.
The means by which the Stena Apache was able to successfully extend the depth lay record to 900 metres is discussed. The depth and pipe size limits for the Stena Apache, with the proposed modifications scheduled for the winter of 1994/1995, is investigated, and possible further enhancements which could further extend the depth and weight handling capacities, are reviewed.

CAPABILITIES OF THE STENA APACHE REELSHIP
The Stena Apache is a specialised pipelay vessel, unique in its technique for the handling of pipe by the use of a large, vertically mounted main reel, see Fig. 2. The reel measures 25.0 metres in diameter with a hub diameter of 16.5 metres and has the capacity to carry 1815 tonnes of pipe.
Pre-fabricated pipe stalks are spooled on to this reel from an onshore spoolbase, thus minimizing the field duration required for pipelay operations. This allows the utilisation of shorter weather windows and decreased operating time in the field.