bluuebunny/crossref_metadata_2025_split huggingface dataset:
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

ABSTRACT
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

ABSTRACT
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

ABSTRACT
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

SUMMARY
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

ABSTRACT
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

ABSTRACT
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

ABSTRACT
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.