bluuebunny/crossref_metadata_2025 huggingface dataset:
Atlantis-II-Deep's Metal Reserves and Their Evaluation
Authors: Guney M. , Nawab Z. , Marhoun M.A.
Published: October 2008

The Atlantis-II-Deep's metalliferous sediments were recently discovered along the mid-ocean ridge system extending into the Red Sea, at a mean water depth of 2,200 m. The average thickness is 7 to 11 m in different sub-basins. The metal-bearing mud contains sulfides of zinc, cupper and iron with significant amounts of silver, gold and cobalt. A variety of oxide, siliceous and carbonaceous gangue minerals are also present.

To determine the in-situ characteristics pertaining to the variability of the metal grades and mineralized thickness, and to study the natural phenomena, mining geostatistics was applied to estimate the Red Sea offshore mineral resources. Horizontal experimental variograms were computed along 0±180 degrees and then models were fitted to analyse the mineralization in each area. Kriging estimates indicate that 696.330 million tons of bulk sediments contain 1.891 million tons of zinc, 0.425 million tons of copper and 3.75 thousand tons of silver. Gold and cobalt contents were calculated from the analysis of solids in flotation concentrates as 47 tons and 5,368 tons respectively.

The significant outcome of implementing geostatistics to the Red Sea brine preciptates is not only for the evaluation of metal reserves, but it also provides a useful tool in the optimization of selective dredging of appropriate areas to be mined.

INTRODUCTION

The Atlantis-II-Deep is a unique marine deposit with a 2,200 m-thick sea water overburden. The stratified muds consist of varying quantities of very fine grained oxides, silicates and sulfides of zinc, copper and iron, and considerable concentrations of gold and cobalt. Extensive systematic exploration has revealed the fact that brine precipitates formed this potentially mineable orebody of economic interest.

The resource potential and economic worth of the Atlantis-II-Deep has been studied at different times utilizing data provided by exploration campaigns. The following are those worthy of mention.

In 1969, Bischoff and Manheim (1) assessed the in-situ value of the deposit at $2.5 billion, based on 41 analyses from 7 piston core samples that were collected during the Chain cruise. This represents:2.9 x106 tons of zinc,1.06x106 tons of copper,8.0 x104 tons of lead,4.5 x103 tons of silver, and4.5 x10 tons of gold. In 1969, the Wando River cruise yielded channel samples from 28 stations within the Hackett and Bischoff (2)in 1973 calculated the estimates and amount of valuable metals in ore on the dry-salt-free material as:32.7 x105 tons of Zn at a grade of 3.48 x103 g/m38.2 x105 tons of Cu at a grade of 0.869xl03 g/m384.01x107m3 of sediment volume. This amounted to a total value of $ 2.33 billion for in-situ resources at the 1972 market metal prices.2.4 x106 tons of zinc,0.5 x106 tons of copper, and8.6 x103 tons of silver. The economic value at this time reached $ 4.2 billion.

In 1977/1978 and 1979, Meseda 1 cruise of Sonne and Meseda 2 cruise of Valdivia were undertaken to obtain an additional 195 statistically distributed core samples.
Suitability of Tankers for Floating Production Systems in Hostile Environments
Authors: Key J.W. , Shumaker F.E. , McClure Alan C.
Published: October 2008

This paper discusses the advantages and disadvantages of semisubmersibles and large tankers (150,000 to 250,000 DWT) when used as floating production and storage systems. Primary technical considerations which are discussed include:Mooring LoadsProduction RisersVessel MotionsCrude Storage and OffloadingSystem ReliabilityField Shut-In ParametersCapital ExpendituresLead Times

The data included is based on computer simulation, model tests, and industry successes in meeting similar challenges.

INTRODUCTION

In the past decade several fields have been produced in the North Sea with semi submersible drilling units which were converted to production units. As a result of the proven suitability of semi submersible production units in hostile environments (Argyle & Buchan Fields), many people believe that only semi submersibles are suitable for those locations. With the increasing use of converted tankers as floating production, storage and offloading units, it is appropriate to evaluate their suitability for more hostile environments.

SYSTEMS EVALUATED

Five basic configurations which are considered in this paper are:Converted Semi; Shuttle Tanker. This includes a semisubmersible drilling unit (modified with production equipment), with continual offloading to dedicated shuttle tankers.Converted Semi; Storage Tanker. This includes a semi submersible drilling unit (modified with production equipment), a permanently moored storage tanker, and periodic offloading with shuttle tankers.Custom Semi Production and Storage. This includes special design and construction of a large semisubmersible, with periodic offloading with shuttle tankers.Production and Storage Tanker; SPM. This includes a very large crude carrier (VLCC), or a converted tanker (150,000 to 250,000 DWT), permanently moored with an articulated tower or single anchor 1eg mooring (SALM) with a rigid yoke, and periodic offloading with shuttle tankers.Production and Storage Tanker; Turret Mooring. This includes a converter a tanker or VLCC permanently moored with a turret mooring system, and periodic offloading with shuttle tankers.

For each case, it was assumed that major pipe1ines are not in place, necessitating the use of shuttle tankers.

MOORING LOADS

Typical mooring loads (without shuttle tanker attached) are shown on Figure 1. The mooring forces are significantly lower for the tanker based unit which weathervanes than for a semi submersible exposed to beam seas. Therefore, a much greater factor of safety can be maintained with similar mooring systems, or the size of the tanker-based mooring can be reduced in order to minimize capital expenditures. The mooring loads for the tanker may be slightly larger than shown when the wind, waves and currents are not collinear.
Acoustic Tracking of Towed Bodies
Authors: Neudorfer M.L.
Published: October 2008

I. ABSTRACT

Results of tests are presented that show that a simple mechanically fixed mount ultra short-baseline transducer array can be successfully used to acoustically track deep and near-surface towed bodies. An in-water calibration procedure that reduces errors due to transducer array assembly system installation and sound velocity variations is also discussed.

II. INTRODUCTION

The use of ultra-short baseline acoustic systems is common in survey applications for tracking towed bodies. These applications include tracking of deep-towed seismic towfish and near-surface seismic streamers and airgun floats. A common requirement of these applications is accurate determination of a towed body position in geographical coordinates.

This paper describes the results of two tests of an ultra-short baseline acoustic system featuring a fixed-mount transducer array1. The transducer array features wide-beam elements that constantly monitor the entire 360 degrees of the acoustic field. The array is most sensitive in the downward direction but it has sufficient sensitivity at near horizontal angles to perform well in towed body applications. The array's elements are arranged in a perpendicular pattern that enables the system to calculate the three dimensional position of an acoustic transponder.

Near-surface tows were conducted in Puget Sound, Washington and deep tows were conducted in Hogs Fjord, Norway. Accuracy and range performance during these tests is presented and analyzed in this paper.

This paper also describes the steps taken to achieve best accuracy. An in-water calibration procedure that will reduce errors due to transducer array assembly, system installation, and sound velocity variations is also presented.

III. NEAR-SURFACE TESTS

Near-surface tow tests were conducted in Puget Sound, Washington. The transponders used 22 and 24 kHz pulses of 1.33 ms duration. The source level was 190 dB//1 microPascal at 1meter.

A towed beacon was tracked out to a maximum range of 365 meters at a depth of 13 meters in sea state 1 to 2 conditions. With the beacon lowered to 60 meters, a range of 1500 meters was achieved. Tow speeds ranged from 4 to 6 knots.

Tilting the transducer array up 25 degrees so that its sensitive axis would point more closely at the transponder did not increase the achievable range. This result agrees with the general rule that in near horizontal acoustic transmission the achievable range is limited by environmental conditions (usually acoustic ray bending due to thermal variation).

This environmental constraint was observed again when, in sea state 5 to 6 conditions, the transponder had to be lowered to 36 meters to achieve the 365 meter range achieved at 13 meter depth in calmer seas.
Some Recent Applications of Reliability Theory in Offshore Structural Engineering
Authors: Edwards G.
Published: October 2008

This paper describes some recent applications of reliability theory in offshore structural engineering.

In two of the applications, concerning a) a gas riser and b) the steel deck beams of an offshore structure, probabilistic fracture mechanics calculations have been used to investigate safety levels associated with crack-like weld defects and hence give guidance in operational decision-making situations.

In the third application, modern ideas in Bayesian statistics have been used to treat an increasingly common problem - that of developing a fatigue design (S-N) curve from a very limited amount of test data. The Bayesian S-N curve can be used as a design criterion in its own right or as a means of assessing the benefits of performing more experimental work.

Overall, the applications illustrate that probabilistic structural reliability theory has progressed to a stage where it can provide valuable information in real operational situations - provide that appropriate data and analysis capabilities are available. When data are scarce, the advantage of adopting the Bayesian approach to probability theory is also clearly illustrated.

INTRODUCTION

In recent years, important advances have been made in the development of probabilistic structural Reliability Analysis (PSRA) techniques for use in offshore engineeringl,2. Basically, PSRA employs probability theory and statistics to treat the uncertainties in all stochastic variables governing structural behaviour in an explicit manner. In this way, a notional 'probability of failure' can be calculated for the structure or component of interest during a specified time period, usually the service life. This failure probability is recognised as being a more rational measure of safety than the traditional 'safety factor', which has been used for many years in design.

This paper summarises some recent applications of PSRA in offshore engineering. In two cases concerning a) a gas riser and b) the steel deck beams of an offshore platform, probabilistic fracture mechanics calculations have been used to investigate safety levels associated with crack-like weld defects. In the other application, Bayesian statistical theory has been employed to establish a fatigue design curve from a very limited amount of test data.

Since the applications described make use of both classical and Bayesian forms of statistical inference, some background information on these two topics will be given first.

DIFFERENT VIEWS OF PROBABILITY AND STATISTICS

Recent developments in many areas of statistical application - including PSRA - demand a sound understanding of the different views of probability theory and statistics which can be adopted. Broadly, there are two schools of thought (i) the classical (frequentist) school and (ii) the Bayesian (subjective) school.
Recording Technologies for High-Rate Marine Seismic Data
Authors: Aarnaes E. , Sidlowski D.G.
Published: October 2008

Developments in marine seismic data acquisition technology have made available streamer systems with 1000 channels and high sampling frequency. The resulting data rates and volumes are above the capacity of the current magnetic tape recording systems. The recording requirements of high rate seismic systems could be met through developments in laser disc technology, in the area of magnetic tape systems or through online pre-processors reducing the amount of data. New recording technologies are essential for the feasibility of high rate seismic systems.

INTRODUCTION

Industry demand for increased resolution of offshore seismic surveys has resulted in development of more sophisticated acquisition systems. Digital streamers have made possible significant increases in spatial and temporal sampling rates. Some streamer systems provide the possibility of recording up to 1000 channels in addition to high temporal sampling rates. These developments have led to significantly higher data rates than common in marine seismic data recording today.

Standard computer readable magnetic tape, which is well known to the seismic industry, is still the state-of-the-art medium for recording of seismic data. Even though this technology has remained essentially the same for several years, it has so far proved to be reliable and sufficient. Unchanged, however~ it will not be adequate for the kind of high rate seismic data recording indicated above. Implementation of new recording technologies is therefore essential to the feasibility and cost effectiveness of high rate seismic acquisition systems

The increased recording density and speed requirements of high rate acquisition systems can be met in several ways; through new developments in laser disc technology, in magnetic computer tape technology resulting in magnetic tape systems with higher data rate and density, or through the use of high density digital recorders to seismic data acquisition. Another attractive alternative is to use online pre-processors to perform data reduction to match the recorded data volume to the capabilities of current magnetic tape systems. However, online pre-processing is a large subject which we will leave out of this paper.

In this paper we will discuss the use of these recording systems for high rate seismic recording and the status of their development. However, we will begin with a review of some geophysical and operational reasons for using high rate seismic recording.

SOME GEOPHYSICAL ASPECTS.

Increasing production and development costs of off-shore oil fields have forced many oil companies into careful evaluation of new fields and reevaluation of existing fields currently in production. To meet the required data quality may in some areas require fine spatial sampling intervals of the seismic data, in some cases significantly less than 10 m. The Delphi Survey respondents (Hewitt, 1983) predicted that 25 percent of recording systems in use by 1990 will have at least 1000 channel capability and that this percentage could increase to 50 by 1995.
Offshore Exploration Potential
Authors: St. John B.
Published: October 2008

There are 799 indentified sedimentary provinces which possibly could contain hydrocarbons. Of these, 481 are located offshore or partly offshore. Eight of the 481 are considered to have excellent future hydrocarbon potential, 34 good-to-excellent, 42 good, 72 fair-to-good, 100 fair, 80 poor-to-fair, and 145 poor.

There are numerous basins or provinces classification schemes attempting to equate type with hydrocarbon potential. The Bally and Snelson system and Klemme classification in current use indicate the most hydrocarbon-prone provinces are those formed on continental crust and associated with plate collision.

The identification, location, classification and seriatim of offshore future hydrocarbon potential can be utilized by explorationists to screen those provinces having relatively poor hydrocarbon potential and those politically and environmentally unacceptable. The elimination of the objectionable provinces will enable the explorationists to concentrate on the high potential areas with acceptable parameters.

INTRODUCTION

There are 799 sedimentary provinces identified on the map, Sedimentary Provinces of the World (St. John, 1984). The term "provinces" includes basins, foldbelts, carbonate banks, cratonic arches, and deep sea fan and cone deposits of 1,000 meters or greater thickness. Of the provinces, 307 are located offshore, 174 are sited partly on and partly offshore, and 318 are onshore. Only those 481 provinces located offshore or partly offshore are considered in this report. Table 1.

CLASSIFICATION

There have been numerous attempts to classify sedimentary basins, or provinces, and to relate the various types to hydrocarbon potential. Two of the most frequently quoted systems are Bally and Snelson (1980), and Klemme (1971). Not all of 481 offshore provinces have been classified by Bally and Snelson or Klemme, whereas some have been assigned two classifications where there is superposition of types. Table 2.

Numerically, the majority of sedimentary province considered offshore fall in Bally and Snelsons' genera types 1 and 3 and in Klemme's type III. However, a study of the location of known giant oil and gas fields (Carmolt and St. John, 1984), indicates the giants are found most commonly in provinces formed on continental crust and associated with plate collision. These are Bally and Snelson type 22, and Klemme type IIc.

SERIATIM

The 481 offshore sedimentary provinces are rated subjectively as to hydrocarbon potential. Political and environmental aspects are not considered. Table 4

The quality of hydrocarbon potential does not appear to be concentrated geographically but is distributed evenly worldwide. Table 5.

The offshore sedimentary provinces having ranking from Excellent through Poor -to-Fair are presented in a seriatim of declining hydrocarbon potential for the top 337 provinces (Appendix). The 145 offshore provinces considered to have Poor potential were not ranked.
Leg Strengthening of a North Sea Jacket
Authors: Forster M.L.
Published: October 2008

Proposed changes to topside weight on a 9 year old North Sea jacket were going to create unacceptably high static stress levels on two legs within the splash zone.

These members were strengthened in advance by jacking 2200 kips out of each leg into steel sleeves, which were subsequently grouted and stressed around the legs.

The paper reviews the describes the evolution of model testing, fabrication trials and installation.

Areas of potential use and benefits to other offshore installations are discussed.

INTRODUCTION

As production platforms and their oil reservoirs age, topside loading requirements can change significantly. Additional well work over, new oil and gas processing requirements, together with associated additional accommodation needs, are all factors Which can lead to large topside load increases and/or redistribution. This is particularly relevant to the first generation of North Sea platforms which were installed prior to the existence of local case histories of aerial reservoir and operational needs. In addition, weight audits have shown in many cases, that the operational topside load was greater than the original design value.

Hence, static stresses due to axial loads in the jacket legs can assume great importance. The locations of the highest stress values can often occur in the splash zone, where corrosion is most virulent.

Just such a situation existed on the Occidental Group's Piper platform in late 1983. Further development of the 8 year old reservoir required the installation of new work over facilities. The stresses in two corner legs were such that this would not be possible without relieving some of the existing axial load in each leg.

SITUATION

The Piper field is situated 100 miles north east of Aberdeen in Block 15/17 in the U.K. sector of the North Sea. The field was discovered in January 1973, the jacket launched in June 1975 and production commenced in December 1976.

The all-steel platform sits in 474 ft of water and has the elevation shown in Figure 1. The derrick can be seen on the southern flank.

Following a series of design developments and loading increments, the topside load on the platform was scheduled to increase in 1984 by 10%, much of this to be applied near the south end.

The jacket framing from the underside of the Deck Support Frame at the +68 ft level, to below the -50 ft framing is shown typically for the south-west corner in Figures 1 and 2. The critical zone for loading is between the +20 ft and -50 ft framing where the corner legs are 48" diameter with 1.125" wall thickness. From -6 ft level to the +20 ft node a further ½" corrosion allowance of steel wall thickness is available. This splash zone has since been redefined such that corrosion should be allowed for to a depth of 10 ft below Lowest Astronomical Tide (L.A.T.) (1). To date, no reduction in wall thickness has been found, but the remaining design life of the platform is in excess of 15 years.
An Investigation of Dynamic Wind Loads on Offshore Platforms
Authors: Vickery B.J. , Pike P.J.
Published: October 2008

A wind tunnel investigation of dynamic wind loads on a 1:400 scale model of the Exxon Company, U.S.A. Lena guyed tower offshore platform was conducted. The objectives of this investigation were to (1) investigate the dependence of wind loads on flow structure and turbulence intensity, and (2) obtain data necessary to permit an assessment of theoretical and semi-empirical methods of estimating the effects of dynamic wind loads on offshore platforms. There are two fundamental reasons for conducting this investigation. First, relevant experimental data on dynamic wind effects on offshore platforms is limited, and there is a need to improve the experimental data base upon which dynamic wind design procedures can be evaluated. Second, dynamic wind loads can contribute significantly to the design requirements of compliant offshore structures (e.g., the Lena guyed tower) because of the relatively long-period response of these structures.

This paper presents the major results of the experimental investigation and shows the results of a measured vs. calculated comparison of dynamic wind loads. The comparison shows that dynamic wind loads calculated using free-stream wind engineering theories are conservative relative to the model test data.

INTRODUCTION

Compliant offshore structures such as guyed-tower or tension-leg platforms are susceptible to wind loads which, under design conditions, may be responsible for over 25% of the overall response to wind, wave and current. Constant loads due to steady winds and currents are not counteracted by inertia loads induced by platform movement (compliancy) and thus, unlike wave loads, must be fully resisted by the platform restraints. In addition, the relatively long natural period or low natural frequency places such structures in the energy containing region of the wind turbulence spectrum and, despite the comparatively high hydrodynamic damping, the dynamic response to wind can be significant.

The development of compliant offshore structures has necessitated the development of wind design procedures that explicitly account for the dynamic interaction of the structure and the Wind. Unfortunately, the relevant experimental data base upon which the accuracy of such procedures can be evaluated is limited. A previous investigation of wind loads on offshore platforms by the authors [1] was concerned with mean loads under predominately steady, fully-coherent wind conditions. In the case of dynamic wind loads, however, the structure of wind turbulence, particularly the spatial characteristics of wind gusts relative to the spatial dimensions of the platform, should be considered.

The study presented herein is concerned with a detailed examination of both the mean and dynamic wind loads acting on a 1:400 scale model of the Exxon Company, U.S.A. Lena guyed tower offshore platform when placed in correctly scaled turbulent shear flow.
The Design and Analysis of a TLP 9 5/8-in. Threaded Connection
Authors: Valka W.A. , Fox S.A.
Published: October 2008

The design of a 9–5/8 inch threaded connection for long term production applications is presented. The threaded connection was designed for joining sections of 9–5/8 inch production riser for a tension leg platform in 1600 feet of water for the Santa Barbara Channel. The connection utilizes a tapered thread profile, a preloaded external shoulder and a primary metal-to-metal pressure seal at the nose of the pin.

The following items were evaluated for the threaded connection using finite element analysis and the results are presented: the ability to transmit the applied static loads. the ability to survive the applied cyclic loads and the ability to maintain a seal under all load conditions.

INTRODUCTION

A production riser connector for long term service must satisfy requirements similar to both drilling riser and normal casing connectors. Like a drilling riser connector, a production riser connector must withstand significant load variations in the riser and be designed for fatigue. In addition. like a casing connector. a production riser connector must be designed for full well pressure in case of a tubing leak and for major workovers. Metal to metal sealing is also required due to the long term application.

Production risers, 9–5/8, were studied for the TLP application considered. Riser analyses were performed to determine the maximum combination of bending and tension loads at any point in the riser for various design conditions. These conditions and loads are summarized in Table 1. In addition to these loads. a full spectrum of bending loads for fatigue design was determined. The spectrum was in the form of bending load ranges and number of corresponding cycles in a years time.

FEATURES OF THE CONNECTOR

The connector chosen to satisfy these conditions consists of a box and pin member with a two thread per inch, two inch diametral taper per foot thread. The nose of the pin forms the metal-to-metal primary pressure seal by creating an interference fit with the box during assembly. The seal is pressure energized which assures sealing integrity without the need for excessive interference and resulting high assembly stresses. The connector has an external shoulder which is preloaded during assembly. The external shoulder provides for positive makeup. reduces the alternating stresses in the pin threads. and ensures that the connector will remain assembled. The connector ends are sized to weld directly onto the 9–5/8 inch pipe, therefore, upset pipe is not required. The connector assembly with overall dimensions is shown in Figure 1. Figure 2 shows the overall and detailed view of the connector box. Figure 3 shows the same view for the connector pin.
CIDS Completion And Mobilization To The Antares Site
Authors: Phillips G.W. , Chen A.C.T.
Published: October 2008

The Glomar Beaufort Sea I was successfully mobilized to its first drilling location, the Exxon Antares prospect in the Alaskan Beaufort Sea, only 13-1/2 months after go-ahead. The paper reviews the completion of construction, describes the site surveys and its characterization, and details mobilization operations from Japan to Alaska.

INTRODUCTION

The Glomar Beaufort Sea I, a Concrete Island Drilling System (CIDS), is a United States Coast Guard certified Mobile Offshore Drilling Unit (MODU) and is classed by the American Bureau of Shipping as a Maltese Cross A-I Caisson Drilling Unit. Its structure is comprised of three basic stacked components:A compartmented A537 steel Mud Base 312 ft in length, 295 ft in breadth and 25 ft deep with raked sides.A central core prestressed and post-tensioned concrete BRICK, octagonal in shape, 234 ft across the flats, 44 ft in height, straight sided.An EH-36 (modified to -60"F) steel deck unit,290.5 ft in length, 274 ft in breadth, and 26 ft deep with raked sides built as two independent deck barges. The Glomar Beaufort Sea I (CIDS) was installed on its initial Alaskan Beaufort Sea drill site, the Exxon Antares' prospect, only 13.5 months after a letter of intent was signed with the Nippon Kokan (NKK) shipyard in Japan and 10 months after the first concrete was poured. At the peak of activity, 4 shipyards and 2 offsite facilities utilizing over 1600 workers were engaged in fabricating the principal sub-assemblies: mud base, brick, port and starboard deck barges, drill rig, and quarters. Numerous papers and articles have detailed the design (References 1 through 15). This paper summarizes the completion of construction and its mobilization to the drill site.

CONSTRUCTION COMPLETION

Mud Base Construction

Construction of the Mud Base began at NKK's Tsurumi Works on September 28, 1983 and continued until March 13, 1984. The Mud Base was launched by skidding it onto a submersible barge. This created an interesting multiple degree of freedom problem involving variable and offset loads and inclination of the barge coupled with tidal effects that the shipbuilder resolved with a computer controlled barge ballast system. The Mud Base was then launched from the barge and towed 250 miles from the Tsurumi works to the Tsu works to await assembly with the BRICK. After arrival at Tsu, a 3 inch thick asphalt rubber compound was applied hot over the entire top of the Mud Base within the shear curb using conventional road building equipment to evenly distribute the load from the BRICK into the Mud Base structure. The asphalt rubber compound was developed and tested under contract by B.A. Va11erga, Inc. and consisted of 15% asphalt paving grade binder, which contained 20% ground vulcanized rubber, and 85% aggregate, made up of 70% clean dry river sand and 30% Meso1ite.
Offshore Pipeline Construction By A Near-Surface Tow
Authors: Tatsuta M. , Kimura H.
Published: October 2008

A pipe tow method is one of the most economical ways to construct offshore pipelines. It is a method that does not require large equipment such as a tensioner or a lay barge. The long pipe strings, however, are affected by waves and currents. If a surface tow is adopted, the action of waves is severe and results in high dynamic stresses. The effect of wave force has strong nonlinear characteristics. It is therefore important to establish ways to evaluate the motions of long pipe strings in waves.

Model tests were conducted using three types of models. A computer program based on the finite difference method was also developed to analyze the dynamic response of pipe strings to waves. Test models were analyzed by the program, and the validity of the analysis method was confirmed.

This paper discusses the results of the model tests, theoretical calculations and fatigue investigations. It also describes the near-surface tow method used for offshore pipeline construction in Chengbei oil field in 1985.

INTRODUCTION

For constructing offshore pipelines, the most popular method is the lay barge method. For waxy crude .oil pipelines insulated by a coaxial system, however, a large amount of welding is required. But a tow method presents great economical advantages, compared with the lay barge method. In an area where the water is shallow and the seabed consists of soft clay, the surface tow method and the near-surface tow method are preferred over the mid-depth tow method or the bottom pull. method.

During towing, the pipe strings are affected by waves and currents. They are bent by currents and develop dynamic stresses under wave action. Wave induced cyclic stresses may cause fatigue damage in the pipe strings. The waves also create dynamic forces. in the bands which connect the pipe and the floater.

The method to predict the motions of long towed pipe strings was reported by Verner et al.(1984)! No reports have been published on the influence of wave action on pipe string motion except by Costello et al.(1983),2 though they provided no detailed information concerning wave influence.

Until now, no elaborate method to predict the pipe motion during towing has been available because of the considerably complicated analysis that results from the interaction between the wave and the pipe-floater system. A constructor has to select comparatively conservative conditions on the basis of past experience.

If we can evaluate the critical sea conditions for towing and the degree of fatigue damage during towing, the safety of surface and near-surface towing can be ensured and the tow method can be applied to a wider range of sea conditions than previously.

To predict the influence of wave action on pipe strings, model tests, theoretical calculations and fatigue investigations were conducted. The results are described in this paper.
The Eider Production Platform Concept: A Platform in Deep Water With Small Reserves
Authors: Smulders B.H.N. , Franklin J.L. , Logan B.L.
Published: October 2008

1. ABSTRACT

The Eider Field is a relatively small North Sea oilfield in 157m (515 ft) water depth. A cost effective design was essential to allow economic development of the field.

This paper describes a number of unique features of the Eider development which include the minimisation of platform based facilities by extensive use of two nearby platforms, state of the art jacket design, a large integrated deck containing all process facilities and utilities, a power export facility to utilise excess gas, and a control and safety system to allow manned and unmanned operation. As a result of these and other measures the capital and operating costs were substantially reduced below the original budget estimates.

2 FIELD DEVELOPME NT

2.1 Reservoir

The Eider Field is located in Block 211/16a and 211 /21a in the UK sector of the North Sea, some 187 km north east of the onshore oil terminal in the Shetlands, and 13 km north of the Shell/Esso existing North Cormorant platform (Fig 1). The field is an elongated banana shape of about 8 km length, with oil bearing formation at around 2750m (9000 ft) below sea level in the Middle Jurassic Brent group of sands. The field can be developed from a single platform.

The current expectation of recoverable reserves is 85 MMSTB (million stock tank barrels), which will be produced at an average oil rate of 45,000 BPD in the peak year requiring a peak gross capacity of 65,000 BPD. Pressure maintenance by means of water injection at a peak of 75,000 BPD will be required almost from the start of production, and will be managed to ensure natural flow of the wells throughout the field life of 20 to 25 years. The Eider Field is being developed by Shell UK Expro, the operator for the joint venture between Shell and Esso.

2.2 Concept Development

When a project team was formed in April 1984, the proposed concept was a stand alone fully integrated steel platform at an estimated MOD (Money of the Day) cost of just over £900 million, including drilling. The proposed concept was fully self supporting with oil being processed to satisfy the Brent oil transportation system requirements for entry at the nearby North Cormorant platform. The concept had been chosen on the basis of three exploration wells and preliminary reservoir studies, which estimated the recoverable reserves at 115 - 125 MMSTB.

Shortly thereafter the full 3D seismic studies reduced the estimated reserves to 85 MMSTB and the economics of the original concept were at best marginal. In a first review the original platform was scaled down for the lower throughput but this resulted in only marginal savings. Then the project went back to the drawing board reviewing many alternatives including floating production units and subsea developments. The new "composite satellite" concept as described in this article was finally selected.
Measurement Of Ekofisk Subsidence
Authors: Rentsch H.C. , Mes M.J.
Published: October 2008

Subsidence of Ekofisk platforms was recognized late 1984. Several measurement programs were initiated to determine the subsidence bowl shape as well as the subsidence history at the seabed. The measurement programs are described, their apparent accuracies are shown and their contributions to specific knowledge of Ekofisk seabed subsidence is discussed.

INTRODUCTION

Phillips Petroleum Company Norway is the operator for the Ekofisk Field, located roughly in the center of the North Sea. Several platforms, located near the center of' this field, are connected by bridges. This group of platforms is referred to as the Complex. One of these platforms is a concrete tank structure, a perforated wall surrounds this structure. The field was discovered in 1969 and has produced oil and gas since 1971.

The Subsidence of the platforms at the Ekofisk Complex was noticed late 1984. The most obvious indication of seabed Subsidence at Ekofisk was a change in the number of visible holes in the breakwater wall on the Tank. When the Tank was installed in the summer of 1973, five holes were visible (Figure 1). Today only 3 holes are visible.

Another indication of subsidence was the obvious high water level with respect to the steel platform references. The boat landing of one of the older jackets (the 2/4-C jacket) was located at the water level originally. This boat landing was below water even at low tide in 1984. Certain inspection and maintenance work that could originally be done with scaffolding started to require divers. A map of the Greater Ekofisk Area is shown in Figure 2.

These indications were stronger than could be expected from platform settlement. This led to the SUsplcl0n of subsidence. Several measurement programs were initiated to determine if a Subsidence bowl was present and what the rate of subsidence might be.

The first measurements which clearly demonstrated the presence of a subsidence bowl were bathymetric measurements obtained along pipelines in the Ekofisk area during the summer of 1984. The pattern of the pipelines form a 10-armed starfish. It was possible to interpolate between pipelines to obtain a crude bathymetric map. A subsidence bowl was clearly evident from this mapping process indicating that the platforms were following the movement of the seabed and not just settling.

The methods for precise subsidence monitoring started during the 1984/1985 winter. Searching of historical files and intensive subsidence monitoring, permitted Phillips Petroleum Company to piece together a picture of the process of subsidence to date. From a review of all available data, a picture has been created to show the historical subsidence trends and the accuracy associated with these estimates.

DESCRIPTION OF MONITORING METHODS

Several measurements systems were used in determining the total amount of subsidence. They are illustrated in Figure 3. The pre-1984-measurements were not intended for Subsidence monitoring, so their accuracy is not as good as would be desired. Other monitoring methods were initiated after the subsidence was discovered.
Station Keeping In Deep Water: An Alternative To Dynamic Positioning
Authors: Wolff C.V. , Lohr C.J. , Wudtke D.J.
Published: October 2008

As recently as 10 years ago, deep water for drilling rigs was 600 feet and beyond. Really deep water, 1000'+, was on the horizon but reserved for dynamically positioned ships. Only 2-3 years ago some experts still proclaimed that moored operations beyond 2000' were not possible or realistic. Today, a number of semi's moor routinely in 2000-3000' WD; the new Trendsetter class semi, "Zane Barnes," now operates in the Gulf of Mexico in up to 4000' WD, while D.P. drill ships are working beyond 700Q'. Both types are projected to go well beyond this with present day equipment. Although distinctly different, technologies for deep water mooring and dynamic positioning have come of age. They have proven reliable, effective, and economical. The question no longer is whether one could moor at all or should use D.P., but which is the more economical and expedient way to operate. Today, moored drilling operations are realistic in up to 6000' WD and may possibly exceed this with current state-of-the art technologies. Economic considerations will dictate where the transition to D.P. occurs. A hybrid, i.e., a semi that has deep water mooring as well as D.P. capability, may eventually evolve if market conditions demand drilling beyond 6000' WD. Design aspects of riser systems and sub-sea equipment will dominate and outweigh stationkeeping concerns.

INTRODUCTION

Reading & Bates has been a leader in deepwater mooring technology from the start. Until the "Zane Barnes" was built, the RB semi's "M. G. Hulme, Jr." and "Sovereign Explorer" have held water depth records in the North Sea. The key to success in deepwater mooring is the result of many factors, namely:Reliable design, analysis, selection, and testing of the mooring tackle, i.e., anchor, chain, and wire rope.Innovative design and selection of the proper machinery to store, deploy, retrieve, and tension the mooring lines.Design, selection, and use of a reliable and proven anchor handling system.Employment of a sufficiently powerful and adequately outfitted anchor handling vessel managed by an experienced crew.Selection and training of knowledgeable and experienced marine rig operating crews.Reliable and expedient engineering support during construction, start-up, and operations.

Design effort for the "Zane Barnes" got under way early in 1~84. The emphasis was on new technology, not simply scaling up existing designs. Many new ideas took hold and bore fruit. Today, one can simply state that most goals were achieved, and the "Zane Barnes" is a resounding success.

OBJECTIVES AND HISTORIC BACKGROUND

Primary emphasis in the initial concept formulation for a new class semisubmersib1e was put on much greater deck variable load, superior motion, very deep water capability, efficient and safe operating characteristics.

Previously, maximum water depth was approximately 1500–2500' for moored semi's, and about 6000' for D.P. drill ships. Market projections in 1984 were for 3000' WD in the near term, and 5000' in the long term.
With Poseidon Technology Towards Year 2000
Authors: Furuholt E.M. , Torp T.A.
Published: October 2008

The Poseidon project aims at developing technology for subsea multiphase development of offshore oil and gas fields. This paper shows the potential of this technology through three synthetic North Sea field examples. The investment cost may be reduced by 10-40% using multiphase technology. Realizing this technology with an unmanned wellhead platform concept or a subsea (Poseidon) concept may give neglible cost differences. The main technical areas of concern are listed and some conclusions are drawn as to the future use of multiphase technology.

THE POSEIDON PROJECT

The Poseidon project was started in 1984 as a cooperation between Institut Francais du Petrole (IFP), Total and Statoil. The aim of the five year project is to develop the technology for subsea development of deepwater oil and gas fields. The concept, fig. 1 includes subsea wells, subsea multiphase pumps and long distance multiphase pipelines.

In this project, IFP has developed a multiphase pump. An industrial prototype of this pump will be tested in a flow-loop, outside Lyon late 1988. Total has developed the subsea station and put main emphasis on full-scale test of an electric motor for the multiphase pump. This motor was tested in 150 meters of water outside the west coast of Norway in the autumn of 1987. Statoil's part of the work has been the pipeline system. A computer program for dynamic simulation of multiphase flow has been developed and used to study slugging phenomena and transient behaviour during start-up and shut-down of the pipeline. Moreover, numerous tests have been performed to study hydrate formation in flowing media as well as corrosion and erosion in the presence of oil, gas water and sand. Special consideration has been given to corrosion under sand beds and inhibitor efficiency in the roof of pipelines carrying mainly gas. Instrumentation for reservoir monitoring and control of pump inlet conditions have been studied. Finally, Statoil has headed the field concept studies in which also personnel from Total and IFP have taken part. This paper will present some of the conclusions from these studies.

CONVENTIONAL OIL AND GAS FIELD DEVELOPMENTS

Fig. 2 shows the functions included in a conventional field development. To arrive at new concepts it is necessary to consider if all these functions are necessary and where the accompanying equipment should be placed.

Apart from the pipelines, the main part of the equipment and therefore also the investment and operating costs are connected to well control/manifolding, separation and pumping.

Well control and manifolding are always necessary. The question is therefore whether the equipment should be placed on a platform or on the sea bottom.

The equipment for separation and pumping is today always placed on a platform. Platforms for water depths of 70 to 500 meters, as in the Norwegian part of the North Sea, tends to be very large constructions, fig. 3. The Gullfaks C platform, which will be installed in 220 meters of water depths late this year, will cost in the order of 18 billion NOK.
I-Rjs-199 B: First Deepwater Test In Offshore Brasil
Authors: Sancho J.
Published: October 2008

Elf Aquitaine acting as operator of a joint venture including Agif and Hispanoil spudded in November 1982 a well 1-RJS-199 B) by 808 meters of water.

This well, located on the South-east corner of the block ACS 50 at the top of a salt related structure, was drilled to a total depth of 5015 meters.

This block is situated on the northern margin of the Santos basin at less than 200 km of the main Campos discoveries.

The carbonates of the Macae formation and the turbiditic sands of the Ubatuba formation which constituted the main objectives of the well were recognized.

Significative shows of hydrocarbons were observed in the turbiditic sands of the Ubatuba formation. Carbonates of the Macae formation were completely tight.

GENERAL INFORMATION

The well 1-RJS-199 B has been drilled by the dynamic positioning drill ship "PELERIN" to fulfill the well commitment taken by the ELF - AGIP - HISPANOIL joint venture on service contract block ACS 50 (SF 23 - X - IV).

This block which covers an area of 2825 Sq km is located 75 km south of RIO de JANEIRO and 180 km south west of the Campos fields.

Drilling started on November 19th, 1981 on the top of a large salt related anticline.

Water depth on this location was 808 meters.

The well was plugged and abandonned on March 17th 1982 after reaching the depth of 5015 m.

The geographic coordinates of the well are as follows :X = 42° 03' 04" 87 WY = 23° 53' 03" 37 S

REGIONAL GEOLOGICAL FRAMEWORK

The Santos basin encompasses an area close to 120.000 sq km between latitudes 24° and 28°.

It covers all the continental shelf and extends over a large part of the slope.

A ridge appears beyond the 2000 m water depth (Torres - Trinidade ridge) which is underlined by a noticeable reduction of sediment thickness (less than 5 km).

This ridge marks the limit between the Santos basin and the Sao Paulo plateau where the sedimentary column grows thicker.

A major trenching fault (Santos fault) the outline of which is nearly parallel to the coast separates two large domains.

To the west of this fault the internal part of the Santos basin is covered by reduced series of Upper Cretaceous and Tertiary age only the thickness of which is less than 3000 m. Towards the coast it rests on the Precambrian series which are represented by the Serra do Mar.

This fault, the actual throw of which can reach 3000 m, has probably an ancient inheritance.

All its life long the internal part of the basin has been the site of an intense erosion.

It helped to feed the external part of the Santos basin located on the downthrown side of the fault where the sedimentary thickness can reach 9000 m.