bluuebunny/crossref_metadata_2025 huggingface dataset:
Inter Platform Power Distribution
Authors: Evans A.R. , McConnell James , French B.D. , Kauffman B.A.
Published: October 2008

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

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

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.
Field Testing A Downhole Multiwell Drilling Template: A Unique Approach To Individually Drill, Case, And Complete Two Separate Wells From One
Authors: Collins G.J. , Bennett R.D.
Published: October 2008

A downhole multi-well drilling template called a "Downhole Splitter" was successfully field tested in Wyoming. The downhole multi-well drilling template allows two wells to be separately drilled, cased, and completed from one wellbore. When completed, each well can be produced, serviced, and worked over independently of the other.

The information presented will focus on prototype tool development, procedures used to drill and complete the Wyoming wells, the problems that were observed using the new tools, and modifications needed for future successful offshore applications.

APPLICATION

The Downhole Splitter is suitable for use on offshore platforms, subsea completions, offshore exploitation and delineation wells, inland waters, and onshore in environmentally sensitive areas. It is also ideal for planned multi-lateral or multi-vertical completions. The Splitter can reduce the size of a platform being planned or increase the number of wells that can be drilled from an existing platform. Reduction of platform size reduces platform cost. The Splitter also reduces drilling time and cost due to the sharing of one common surface hole.

DOWNHOLE SPLITTER SYSTEM

At present, two wells are drilled and completed independently of each other as illustrated in Figure 1. A Splitter well, also illustrated in Figure 1, shares conductor and surface casing and allows two wells to be drilled from one surface wellbore.

Sequence drawings 1 through 5 in Figure 2(Available in full paper) show how this is accomplished. The Splitter is placed on the bottom of the surface casing which is run in the hole and hung off conventionally in the wellhead (Figure 2.1). Once the splitter and surface casing are in place, a riser, which consists of an anchor latch seal assembly, is run and landed in the first side of the Splitter (Figure 2.2). This side of the Splitter contains conventional cement float equipment, and the surface casing is cemented through the riser. The float equipment and cement are then drilled out and the casing shoe is tested. The first well is directionally drilled to total depth and logged. A conventional liner, with a no-go hanger and liner top packer, is run to depth and hung off in the splitter. The liner is cemented and the liner top packer is set (Figure 2.3). The riser is released from the first side and is automatically oriented 180 degrees from the first well to the second side. The riser is stung into the second side of the Splitter and the second well is directionally drilled to total depth nd logged. A second liner is run and cemented as previously outlined (Figure 2.4). The riser is pulled and the weI1s are tied back into the existing liner tops, and hung off in a special dual-bore wellhead at the surface (Figure 2.5). The wells are now ready for completion as two individual wells.
The Central Cormorant Field Subsea Development: A Case History
Authors: Elgersma A.G.A
Published: October 2008

The Shell U.K. Exploration and Production (Shell/Esso) Underwater Manifold Centre (UMC), a development which extended the frontiers of subsea technology, was installed in 1982 in the Central Cormorant Field and has now been in operation for more than 10years. It has been a profitable system with an excellent availability record. A number of operational experience topics, considered unique for Central Cormorant, are presented in this paper.

INTRODUCTION

This paper describes the operational experience with the Central Cormorant subsea facilities with emphasis on the period post 1986 (A review up to 1986 has been presented in paper OTC 5314). The reference date for this paper is 31 December 1993. After a system overview, several reservoir management aspects are discussed including the role of the TFL system. Well maintenance and some events requiring substantial DSV intervention are described, followed by a final remark and an overall conclusion.

SYSTEM OVERVIEW

The Cormorant Field (See Fig. 1) is located in the Northern North Sea, approximately 150 km North East of Shetland. It extends over 25 km North - South, and consists of four individual fault blocks. Expected ultimate recovery is 607 MMstb. The nine well Underwater Manifold Centre (UMC), installed in 1982, is located between the two fixed production platforms, Cormorant-A and North Cormorant, in 150 m water depth. Its purpose is to produce the 130 MMstb of reserves in Block 1, which was considered outside the reach of both platforms.

The Central Cormorant Underwater Production System (See Fig. 2) also included a single satellite well known as "PI" which produced directly into the Cormorant-A platform. P1 incorporated the same level of technology as the UMC and as such was used as a pilot scheme to prove the numerous innovative components and techniques included in the UMC design. The success of P1 was a key factor in the decision to install the UMC.

Production from P1 commenced in January 1981 and after more than ten year in service without any workovers, a leak developed in the downhole completion. As the remaining reservoir could now be accessed utilising extended reach drilling from the platform, it was decided in 1991 to abandon P1. During its period in operation, PI produced 17.5 MMstb of oil.

The UMC (See Fig. 3) is designed for four basic functions:to collect fluids from subsea completed wells and deliver these to the Cormorant-A platformto distribute treated seawater, pumped from the platform, to water injection wellsto provide a template for drilling, and to connect and service satellite wells drilled at locations remote from the templateto permit servicing of all wells using the Through FlowLine (TFL) system.

The UMC has considerable system and component flexibility and redundancy. The structure supports a total of nine wells (although more are possible with modifications), which may be drilled as template or satellite, and configured as either water injector or oil producer.
An Alternative For Large-Diameter Flexible Riser
Authors: Silva R.M.C. , Scherer I.M.Q. , Sertã O.B. , Andrade B.L.R.
Published: October 2008

This paper presents the technical feasibility study performed to develop an alternative for the sale flexible risers of the Campos Basin deep water fields production systems.

The target was to reach diameters larger than 12" for 500 to 1000m water depths. This represents a present flexible pipe industry limitation in terms of manufacturing and installation, and brings a potential source of cost reduction.

The study is based on the conclusions of a Joint Industry Project (JIP) about the matter. In addition to the steps covered by the JIP, it has been investigated the fatigue life, embracing the first and second order rig motion as well as the vortex shedding loads during its operation.

INTRODUCTION

In order to develop deep water fields with FPS'S, Petrobrás faced technical and economical limitations on large diameter flexible risers (larger than 12") for exporting systems.

The conclusions of the JIP about Deep water pipeline, flowline and riser installation, encouraged Petrobrás to consider SCR as a feasible alternative.

A specific study of a 16 oil export SCR for Petrobrás XXV (a future FPS of Albacora field, to be anchored at 575 meter water depth) started in mid 1993, in cooperation with the University of São Paulo (USP), This case was chosen among several others because it was the most critical one.

STUDY DESCRIPTION

A preliminary study recommended the following basic characteristics for the SCR:OD: 16;ID: 14.75";steel: API 5LX60.

The first step in SCR design is the determination of the static configuration. The following steps are the verification of the SCR behavior when subject to the critical environmental loads (waves and current) and the fatigue analysis.

The static configuration was established considering the maximum of 35% of the steel yield stress. The main criteria established for the design were:the maximum SCR Von Mises stress reached during a critical environmental condition should be limited to 72% of the steel yield stress of the material;the maximum accumulated damage (Miner's rule) should be limited to 10% of the specified service life.

As the service life specified for the production system is 20 years, the SCR should be designed for a 200-years fatigue life to be coherent with the established criteria.

To determine the maximum dynamic response of the SCR it was used the critical loads, obtained from the combination of a 100-year wave and a 10-year Current, or vice-versa, which one is more severe. For this case, the maximum stress obtained was 62.2% of yield stress.

The service life was calculated considering the cumulative effects of the first order motions, the slow drift motions and the oscillations induced by vortex shedding. The service life obtained from the analysis was 102 years, being lower than the established criteria of 200 years.

Other remarkable aspects extracted from the study are:The main contribution for the fatigue damage is given by the slow drift. The vortex shedding gives the smaller contribution among the three considered effects.
Medium-Scale Uniform Pressure Tests on First-Year Sea Ice, 1993
Authors: Masterson D.M. , Spencer P.A. , Frederking R.M.W.
Published: October 2008

A field program was conducted in first-year Arctic sea ice in May, 1993 to record ice failure pressures in a geometrical situation which allowed the collected data to be interpreted in terms of "global" loading situation. The data collected is applicable to the design and safety of ice breaking vessels and to the design and safety of bottom founded structures.

The experimental technique consisted of cutting vertical slots into the top surface of the 1.8 m thick ice sheet and inserting a thin walled metal flatjack, Oil was forced into the flatjack under the control of a high capacity hydraulic servo valve. The experiment continued until either the ice or the flatjack failed or the oil supply was exhausted. The pressure within the flatjack, along with a number of surface displacements, were recorded on a computer data acquisition system. The resulting ice cracking pattern was recorded along with subsidiary measurements of temperature and ice salinity. A total of 26 loading tests were successfully completed.

The size of the flatjack was varied between 1.5 × 0.13 m and 6.0 × 0.75 m and the slot configuration was varied from either a single straight slot or an "H" shaped slot with the flatjack mounted in the middle section, The loaded area of 4.5 m2 represents the largest field test to date. Most tests were conducted with the flatjacks mounted adjacent to the upper surface. Warmer than normal ambient air temperatures for the test period resulted in the flatjack expansion being larger than anticipated, reaching 15 to 25 mm. The loading time to maximum pressure was in the 0.5 to 50 (s) range. In spite of the warm ice temperature, the ice was able to sustain flatjack pressures in the 5 to 12 MPa range. Extensive cracking of the ice adjacent to the flatjacks was produced but in most cases did not lead to a total collapse of the ice.

The major findings of the preliminary analysis areas follows. The shape of the pressure/displacement data are consistent from test to test, although the scales of the displacement and pressures vary. The pressure/displacement shape is similar to that obtained from creep rate uniaxial tests and similar to the shape obtained from other tests in multi-year ice with flatjacks. The similarity between the pressure/displacement date for the flatjack tests allowed the maximum or plateau pressure to be estimated for tests which did not reach that point. Adjustments were also applied for stress/strain rate and ice porosity effects. The adjusted data indicated that pressure from the straight slots were consistently higher than for the "H" shaped slots.

The analysis of the data demonstrates that pressures from this test program are essentially independent of the contact area, thus indicating that, for "intact" ice at these stress rates, there is no size effect.
Design And Installation Of Auger Pipelines
Authors: Kopp Frans , Barry D.W.
Published: October 2008

Shell's Auger Tension Leg Platform (TLP)in Garden Banks Block 426 has been installed in a record water depth of 2864 FSW(873 m). The two 12-inch oil and gas export pipelines from the TLP to shallow water platforms are also the deepest constructed to date in the Gulf of Mexico, requiring record breaking J-Lay construction technology.

This paper describes design of the pipelines, including route selection, determination of the wall thickness, buckle arrestor and J-Lay collar design, and connection to the Auger TLP by means of first time use of a steel catenary riser.

Construction topics discussed include a description of the deepwater J-lay system and a comparison of shallow water S-Lay and deepwater J-Lay.

PIPELINESYSTEN DESCRIPTION

The Auger pipelines were designed and constructed to transport oil and gas from Shell's Auger TLP located in the Deepwater Gulf of Mexico Garden Banks Area (GB426) to existing facilities in shallow water (Figure 1). The oil pipeline is a 12.75" (323.9 mm)outside diameter pipeline, 72 miles (116 km) in length, that runs from the TLP to one of Shell's existing platforms in the Eugene Island area (Block EI 331 'An) in a waterdepth of 250 ft (76 m). The gas pipeline is also 12.75" in diameter and runs from the TLP to Hess's existing platform in the Vermilion South Addition area (BlockVR397 'An) in a waterdepth of 397ft (121 m). The oil pipeline is designed for a 50 MBPD flow rate and the gas pipeline is designed to transport up to 150 14MSCoFfDnatural gas. Both pipelines are rated for ANSI 900service, or 2160psig (14.9 MPa)operating pressure.

PIPELINE ROUTE SELECTION

Several problems exist in routing deepwater pipelines in the Gulf of Mexico:large distance to existing shallow water pipeline infrastructure,generally very rough terrain in the deepwater region (beyond the 800 ft (244m)waterdepth contour),lack of reliable bottom contour and bottom feature data, andpresence of large areas classified by the Minerals Management Service as environmentally sensitive, which means that crossing of these areas by pipelines is prohibited.

All these problems were present for the Auger TLP pipelines and route selection, including multiple surveys, required much more time and effort than at anytime in the past, Especially the oil pipeline routing faced the problem of having to circumvent environmentally sensitive areas and its final route is far from a straight line between the TLP and EI 331 "A" platform.

Figure 1, which shows the routing of the deepwater portion of the pipelines, illustrates the impact of some of the problems caused by rough terrain. Because a portion of the pipeline (beyond the 1200- 1500foot waterdepth contour) could not be installed with conventional S-Lay, a choice had to be Dade:install a 20-mile-long section of each pipeline by first-time use of J-Lay along a smooth seabed, orlay as long as possible with S-Lay, and have only two 10-mile-longsections of J-Layed pipeline to install.
On the Use of SateIlite Wave Data To Derice Extreme Criteria
Authors: Cooper C.K. , Forristall G.Z.
Published: October 2008

Since 1986, nine years of satellite-derived wave data havebeen accumulated and this data base will expand dramatically in the next two years as two more satellites are dded. Several researchers have begun using this data to develop extreme criteria. However, one potential problem with satellite data is their rather poor space-time resolution-satellites only revisit a site once every 10 to 30 days, and their tracks are separated by 100-200 km. With this coarse sampling, the satellite may miss storms since they have characteristic length and time scales as short as a few hours and tens of km. The purpose of this paper is to explore the impact of this under sampling on the calculated 100-yr wave height. We accomplish this by running Monte Carlo simulations of simplified but realistic storms sampled by a simulated satellite, site, and hind cast model. We study the sensitivity of the calculated 100-yr wave to variations in storm type, radius, and forward speed, number of satellites, satellite track, and satellite sampling region. We find the coefficient of variation (COV) of the 100-yr wave based on 20 yrs of satellite data is less than 10% in regions like the North Sea that are dominated by extra tropical storms, provided the satellite data is averaged over a 200-300 km region. This is roughly equivalent to the cove of agood hind cast model. For regions dominated by tropical storms like the Gulf of Mexico the cove for satellite or site-derived extremes is greater than 10%, although the 300-km averaged satellite data is probably acceptable for preliminary design. The situation improves in regions like the South China Sea where storm frequency is roughly four times the Gulf, In any case, some caution must be exercised in using satellite data near the coast where the satellite data itself may be less reliable and simple averaging may remove real spatial gradients.

INTRODUCTION

The feasibility of measuring ocean wave heights from a satellite altimeter was demonstrated by SEASAT in 1978, but it has only been in the last few years that enough altimeter wave data has been collected to enable the compilation of climatologists. Data from GEOSAT (1986-1990), TOPEX (1992-present) and ERS-1 (1991- present) are now available. Combined, these represent about 9 satellite-years of global coverage. The rate of data accumulation is going to increase substantially inthe near future with the launch in 1995 of ERS-2 followed in 1996 by GEOSAT 2. Potentially, this will give four concurrent satellites in operation in the next few years.

The ability of the satellite altimeter to accurately measure wave heights has been demonstrated by several previous studies. Dobson et al. (1987) and Glazman and Pilorz (1990) both compared GEOSAT wave heights to measurements made by the NOAA National Data Buoy Center and found the GEOSAT estimates biased O.4 m lower than the buoy measurements. Carter et al, (1992) m-analyzed this data and concluded that the buoy waves were 13% larger than the altimeterwaves.
Design Of Jacket Horizontal Framing For Buoyancy-Induced Fatigue
Authors: Campo J. , Willis C. , Cinnater L. , Trombatore K.
Published: October 2008

The Main Pass Mine Production Platform No. 1 (PP1) experienced failure of a conductor guide framing level due to buoyancy-induced fatigue. The Mine is unique because several of the platforms are expected to settle up to 60 feet. An inaccurate water depth survey contributed to a horizontal level of PP1 being located exactly at the waterline, which was higher than planned. A replacement horizontal framing level was constructed and installed five feet above the damaged horizontal level and was designed with adequate fatigue life for movement through the waterline. Detailed deterministic and spectral fatigue analyses were performed along with typical wave analyses. Consideration was given to platform settlement, cyclic buoyancy, wave slamming, and wave loads on anodes and plated conductor guides.

INTRODUCTION

Freeport Sulphur Co.'s Main Pass Mine (18 platforms and 13 bridges) is located 20 miles east of Venice, La., in 210 ft. water depth. The Production No. 1 Platform (PP1) is one of two sulphur drilling and producing platforms. A perspective view of PP1 is shown in Fig. 1.

The extraction of sulphur causes the seafloor to subside significantly. PP1 was designed for a maximum vertical subsidence of 36 ft. For the Main Pass Mine platforms that subside significantly, some horizontal framing levels must pass through the waterline. Offshore structural engineering practice is to locate horizontal platform levels away from the waterline. This is partly because the complex behavior of waves and tides in this region is not fidly understood and very difficult to quantity. In addition, wave slamming is a phenomena thatoccurs in the near waterline region which creates significant vertical wave forces on structural members.

In the case of PP1, all leveIs were located such that none would pass through the waterline. The El.(-) 7'-6 horizontal framing, which contains 76 conductor slots, was such a level on PP1. Fig. 2 is aplan view of this level. Subsidence of the seafloor was predicted to occur swiftly, 5 ft. in the first year for PP1 (from the start of mining operations), whichwould have placed this level 12 ft. below the water. However, due to shallower water at the site and the lack of mudmat penetration during installation, the platform was set 7 ft. higher than the design datum. Therefore, the El. (-)7'-6 level is actually located at the waterline. Also, subsidence has not occurred since the June 1991 installation.

The cause of the El. (-) 7'-6 level failure (discovered in June 1993) is believed to be fatigue damage due in great part to the constant immersion in water of this level, creating buoyancy induced stresses by even the smallest waves and tide variations. Fatigue was determined to be the cause of failure based on metallurgical analyses. Fatigue calculations showthat tubular member buoyancy was a prime factorin fatigue of joints.

The initial design of PP1 included strength checks of the El. (-) 7'-6 framing for wave slamming and pressure based on maximum (waterline) vertical.
The Economic Case for Floating Production Facilities
Authors: Smith N.J.
Published: October 2008

Floating production systems have been used for some twenty years, longer if jack-up based systems are included. For most of that time, they have been considered as a "special case" outside the mainstream of offshore oil production.

Their use is now increasing rapidly - not only in their long-term strongholds of the UK North Sea and of Brazil's Campos Basin but in many other theatres of offshore operations. The growth seems so fast that it has been predicted that the number in service will double in the remaining years of this century.

Technological progress has played a major part in the greater acceptance of floating production systems but there have also been powerful economic forces at work. This paper seeks to explain the reasons for the increase in popularity which promises to bring floating production within the main stream of offshore development.

INTRODUCTION

This presentation might better have been entitled "The Economic Case for Mobile Production Units" since the first exposed water example of using a mobile production unit (MPU) was the employment of the jack-up production unit (JPU) GULFT/DE on Norway's EKOFISK field from 1971 to 1976 as an early production system (EPS). Nevertheless, although there have been signs of a recent revival of interest in JPUS in the North Sea, the great majority (probably 90% or more) of the world's MPU experience has been with floating systems. This paper will adopt common industry parlance and refer to floating production, embracing in that term the small number of JPUS. The earliest example of a truly floating production system was the use of the semisubmersible TRANSWORLD 58 (later renamed NORTH SEA PIONEER) from 1975 on the UK's ARGYLL field. Though the original floating production semisubmersible (FPS) itself was later replaced, this proved to be the start of the first life of field (LOF) floater development.

The first deep water monohull floating production storage and offloading system (FPSO) was installed in 1976 on the CASTELLON field in the Spanish Mediterranean, H was a converted tanker. Thus by the mid-1970s floating production seemed to be taking root firmly. Growth occurred over the next ten years, but spectacularly so only in Brazil where the national need to bring new deep-water discoveries onstream in the shortest possible time seems to have overridden the inhibitions which slowed the spread of the technology elsewhere. According to a recent publication (l), oil production by MPU had reached an annual rate of nearly 300 million barrels in 1994, only some 4.5% of total offshore production. However, even this represented a big increase from the less than 2% of 10 years earlier. FIGURE 1 attempts to summarise the growth of MPU production over the last 20 years, both in absolute terms and as a share of world offshore production. It shows that growth was initially slow, but speeded up in the early 1980s. This was followed by a slowing in the late 1980s and then accelerated growth in the early 1990s.
Developments in Coiled Tubing BOP Ram Design
Authors: Palmer R. , Newman K. , Reaper A.
Published: October 2008

Significant technical improvements have been made recently in the design of coiled tubing (CT) blowout preventer (BOP) shear and slip rams. This technology is constantly being enhanced and refined as the CT service industry continues to mature and new operational demands are placed on the CT pressure control equipment. Larger CT sizes require better BOP shearing capabilities. Advancements in the understanding of CT fatigue life25 have caused the life reducing affects of the slip ram markings on the pipe to be examined. This paper explores the circumstances that have precipitated these improvements, and the research and development methods involved in developing better BOP rams.

CT Shear Rams

The CT shear ram should be capable of shearing a specified range of CT with no tension in the string at maximum well head pressure5, leaving a sheared portion of CT with a fishable top profile that has a residual outside diameter equal to or less than the original outside diameter. Equally important is the amount of flow area in the lower fish to permit sufficient circulation through the sheared CT to control the well during the well recovery sequence. With the advent of operations with an electrical wireline installed inside of the CT, it has become an important design criteria that the shear rams cut not only a wide range of CT sizes but also stranded wireline inside the CT. The shear blades must be designed to eliminate any gap between the blades at the point of contact with the stranded wire to prevent trapping small diameterstrands of the cable that would result in an incomplete shear. Also, the ability to repeatedly shear a wide range of sizes and weights of CT offers a definite advantage over previous designs of shear blades which required changing out blades for each size of CT.

Earlier designs of shear blades were lacking in their ability to perform multiple cuts, and to shear wireline.hese designs typically had a "V" pocket configuration as is shown in figure 1, with a knife cutting edge fabricated from carburized carbon steel or hardened tool steel. These blades were generally limited to the smaller CT sizes up to 1-1/4" diameter used during that period. They were designed for a one time emergency cut and were to be replaced after each use due to their tendency to fracture on the first closure. Due to demand for a multiple cut blade and advances in CT metallurgy that propagated larger diameters and weights of CT, new innovations in blade design were required.

The radius pocket blade was introduced with a square cutting edge to overcome the shearing deficiencies of the earlier "V" blades, This concept proved successful in its ability to repeatedly shear CT and wireline without damaging the blade?s cutting edge. This was achieved by the radius pocket and blunt cutling edge, shown in figure 1, that allow the shearing impressive forces to be distributed over the entire cutting edge. Also, the radius net made a preferable cut that left an elliptical profile.
Novel Drilling Technology and Reduction in Drilling Costs
Authors: Enger Th. , Torvund T. , Mikkelsen J.
Published: October 2008

Historically offshore drilling costs represent a large path of Norsk Hydro?s E&P investments. Thus a reduction in drilling costs is a major issue. Consequently an aggressive approach to drilling has taken place focusing upon:

* Reduction in conventional drilling costs, bothin exploration and production drilling. An ambitious programme to reduce drilling costs by 50 % has been introduced. The main improvement potentials include rapid drilling, improved contracts and more selective data gathering.

* Drilling of long reach wells up to approximately 9 km to reduce the number of subsea wells and fixed platforms, and thus improving the total field economy.

Norsk Hydro has also been aggressive in pursuing drilling techniques which could improve the total oil recovery. Horizontal drilling has made possible the development of the giant Troll oil field, even though the oil leg is only O-26m thick. Oil reserves in the order of up to 650 mill bbl will be recovered solely due tointroduction of horizontal wells.

Recently, offshore tests of techniques such as coiled tubing drilling and conventional slim hole drilling have been canted out. The aim k to qualify a concept which could enable us to use a light vessel for exploitation drilling, and not the large semi submersible rigs presently used. Potential future savings could be substantial.

1.INTRODUCTION

The last decade the oil industry has been characterised both by excitement and disappointment. The oil price collapse, the maturing of oil rich regions like the North Sea, etc., have eroded value creation as we knew it in the early eighties.

On the other hand, the period has also been a decade of innovation in oil finding and development techniques, and of newly opened geographies for international oil companies. Massive efforts are also being made to reduce costs in all phases of the activity, with noticeable results so far. And our efforts continue.

The presentation will briefly sketch some of the practical achievements Norsk Hydro has made over the latest years, both in technology improvements and cost reduction initiatives.

Drilling technology and drilling costs are getting more and more central in all phases of activity from exploration to production, and special attention will therefore be given to these developments.

There is no single innovation that is shaking things up.

Rather, every aspect of the petroleum sector is being marked by change, both in technology development and in more cost effective ways ofoperating on all levels.

In the oil sector where most technology is equally available to competitors, the challenge for the oil company usually means being innovative with what is available in the market rather than creating something from scratch. The important thing often is to find, adapt and apply the best technologies and bring them together in new and creative ways to improve business performance. This happens in teams that draw together scientific, engineering and operational expertise from inside - and outside - the company.
Understanding the Value of 3-D Seismic for Exploration
Authors: Downey Marian W.
Published: October 2008

At my age, you don't have to worry about impressing anyone--you don't bother with unnecessary compliment-you get to between as your natural self. and Iet the curmudgeon show that's hidden under the soil and lie.

That's the role I've chosen, as a result of accepting this invitation lo speak to an audience of 3-D believe. I'm DQI here to self 3-D service, not here to make a name as a consult, and not likely to impress anyone with my technical knowledge of the 3-D process

Ins[cad, I want to talk to you as a senior manager. from technical background, who passes on the allocation of money to 3-D project(or not). I use the word allocation very purposefully, since any money used for 3-D comes out of money that be used for wagcs, for research for drilling. or leasehold. My job, as a senior manager for many years. is greatly concerned with the proper allocation of limited funds to numerous groups.

I heard a clamour from these sources all more of the money pie. I have so been hearing some extraordinary claim as to the value of 3-D to extraordinary, I don't Iike to look al some of these claims of benefits and describe to you why I am not yet ready to turn the exploration bussiness over totally to the managers of 3-D seismic.

I have been interested in 3-D seismic since 1970. when G, G. Walton of Exxon prevented an outstanding paper on the 3-D seismic method [o the SEG meeting in New Orleans, in 1970 I think we need to be careful about some of the claims of economic benefits that accrue to exploration from 3-D. l .don't Iike to say, ?.I'm from Missouri,(if I weren't poor of being from Nebraska)

I rural a paper on 3-D recently. and in reading it almost thought 1was seeing a medicine Iabel from o Chinese drug store: you know the kind; .'This extract cures AIDS and infantile paralysis, climinates psoriasis and bad breath and removes unwanted wart and pimples.

Perhaps I should describe my point of view rather particularly i think 3-D seismic is a wonder and a delight but m! job is not to be for technology. but to be the barbarian guarding the money gates. who must insist I that the 3-D work make money for exploration.

Here is something I say nearly every week to my wonderful geologist and geophysicists is a science: geophysics is a science: exploration is n business!

Let mc describe for you the sort of claims for 3-D Success (in the immortal words of Winston Churchill) up with which I shall not put.
Drill Site Geohazard Identification Facilitated by Rework of Suitable Existing 3D Seismic Data Volumes
Authors: Cowlard Andrew P.
Published: October 2008

3D seismic volumes are increasingly being used to assist in the mapping and identification of drilling hazards. A method of reworking the 3D volume, termed the Short Offset method is proposed which offers the benefit of optimised resolution in the shallow section and therefore provides the interpreter with an enhanced in rage of the near surface geology, The processing sequence contrasts markedly with conventional 3D processing and involves the inclusion of only near normal incidence traces Two case histories are described which illustrate the application of the Short Of method and its robustness even in conditions not conducive to enhancing frequency bandwidth. In summary, Short Offset reprocessing results in a product which offers considerably improved resolution when compared to a conventional 3D volume and far finer areal sampling when compared to a traditional 2D site survey thus providing the industry with a valuable tool for drilling hazard investigation.

Introduction

Environmental concerns now have commercial importance for the oil industry. Adverse publicity can directly affect a company's profitability as the unforgiving consumer boycotts its products. Governments will demand full compensation for human injury and damages for oil spillages. Drilling into the Earth's Crust will always be a high risk activity and the oil exploration company should be aware of cost effective methods of reducing the risks involved. It is suggested that reworking existing 3D volumes using the Short offset method can preserve the latent frequency bandwidth available in the raw data and thus allow an interpreter to more readily map near-surface geological strata and identify drilling hazards.

The resolving power of exclusively near normal incidence, or "Short Offset", data volumes has been well understood since the concept was first proposed and successfully demonstrated by Paul Newman (1985). However, it is only relatively recently that the combination of increasingly cheap and plentiful compute resources and 3D surveys with adequate spatial sampling have facilitated the routine generation of Short Offset volumes for the imaging and subsequent mapping of shallow objectives.

In this paper an overview of the Short Offset method is offered and then two case histories are described which illustrate not only the viability of the method but also its robustness when applied to data whose characteristics are far from ideal for high resolution seismic processing.

The Method

In essence, the method demands the recognition of four primary requisites to ensure success, namely the honouring of data positioning, the application of precise time corrections, the preservation of absolute true amplitudes and inclusion of the minimum possible number of near traces.