bluuebunny/crossref_metadata_2025 huggingface dataset:
Design, Fabrication, and Integration Testing of the Garden Banks 388 Subsea Production Template
Authors: Ledbetter W.R. , Smith D.W. , Pierce D.M. , Padilla J.R.
Published: October 2008

INTRODUCTION

Project Profile

Enserch Exploration's Garden Banks 388 development has a production scheme based around a floating drilling and production facility and subsea drilling! production template. The Floating Production Facility (FPF) is a converted semisubmersible drilling rig that will drill and produce through a 24-well slot subsea template. This development is located in Block 388 of the Garden Banks area in the Gulf of Mexico approximately 200 miles southwest of New Orleans, Louisiana. The production system is beinginstalled in an area of known oil and gas reserves and will produce to a shallow water platform 54 miles away at Eugene Island 315.

The FPF will be permanently moored above the template. The subsea template has been installed in 2190 feet of water and will produce through a 2,000 foot free-standing production riser system to the FPF. The produced fluids are partially separated on the FPF before oil and gas are pumped through the template to export gathering lines that are connected to the shallow water facility. The system designed through-put is 40,000 BOPD of oil and 120 MMSCFD of gas.

Template Snapshot

The template's function is to provide a controlled drilling pattern for subsea wells and serve as a conduit to produce oil and gas to the FPF. The template has "slots" to accommodate 24 wells and provision to receive oil and/or gas production through two 12-inch pipelines from an adjacent field. The well slots on the template exterior rows can be either drilled and completed through the template structure or can tie in two 4-inch flowlines from satellite completions. The interior well slots can only be completed as template wells.

The primary structure of the GB-388 template is an all steel welded space frame fabricated from wide flange, rolled tubular sections, and flat plate. The structure is 167 feet long, 86 feet wide, and 20 feet high over the area covered by the 24 well slots. The elevation rises to 30 feet at the riser base end of the template. The structure is secured to the sea floor by eight 42 inch diameter piles.

A stiffened steel plate mudmat covers the base of the template, except the 24 well guides and the eight pile sleeves. The mudmat supported the 1,260 ton weight (lift weight) until the piles were driven. The template was leveled and locked into the piles by plastically deforming a section of each pile into premachined grooves in each of the 8 pile sleeves. The four piles in the wellbay area are 395 feet long and penetrate into the soil 350 feet. The four piles positioned around the base of the free-standing production riser are 305 feet long, with a penetration of 250 feet.

The template structure is protected from corrosion by a high quality, two coat epoxy paint system backed up with Galvalum III type (aluminum alloy) cathodic protection anodes.

The functional requirements for the GB-388 template include providing adequate space and structural support for drilling and completing up to 19 template wells.
Deep Water Installation - Heavy Mooring and Riser Systems
Authors: Alvheim N.
Published: October 2008

While the move into deep water has provided exciting challenges often resulting in ingenious and novel equipment it is usually the equipment or the solution itself that is remembered and discussed.

Too often we over look just bow that novel equipment Was actually installed.

Perhaps one of the most exciting and ingenious equipment designs of recent times is the Submerged Turret Loading (STL) system. To date we have had the privilege of installing each of the 3 systems so far produced. Our work is well on course for installing the fourth during the coming summer.

This paper addresses the installation of two of these systems in the summer of 94 in 350m of the hostile Halten 13ankwaters as part of the Conoco Heidrun development. (Slide)

Because the Norwegian oil industry has always been atthe cutting edge of technology each new development results in the usual plethora of statistics which when presented in papers like this area companied with a long list of superlatives like tallest, heaviest deepest, quickest etc.etc. Installation work at Heidrun has a similar list.

Because the 2 STL systems at Heidrun (called Direct Shuttle Landing DSL) were to be installed in such deep water the sheer size of the system components are worthy of review.

Each DSL (see fig. 1) system is composed of the following individual components:One 130 T submerged turret buoy. Once installed the submerged turret buoy floats 50-60m below the surface.One 16" flexible riser.Eight mooring lines. each made up as followsOne 24T fluke anchor.One 120mm studless chain length 600m.One 130mm plastic coated spiral stranded lower segment wire. length 400rn.One 19T mooring line buoyancy elementOne 130mm plastic coated spiral stranded upper segment wire, length 200m.

Fig. 1 (Available In Full Paper)

With the two systems the quantity was of course doubled and therefore both the number and size of the components alone placed considerable constraints on the size and type of installation vessels.

Inconsequence we believe installation could not have been undertaken with the smaller conventional anchor handlers because that would have involved more frequent trips to port or necessitated difficult ship to ship transfers with all the inherent safety risks.

Moreover, several aspects of the system meant that considerable care had to be taken in handling system components,

The first of these being the plastic coated segment wires. Wt the plastic coating would enhance the life of the mooring this meant that the wires were to be handled at all times in such a manner that did not damage the coating.

Additionally the sheer size of the forces that would be encountered as the final connections were made to these wires produced an installation design that required very large items of equipment to be attached to the side of the installation vessel.

With apparently no other constraints it was intended to complete the most of the installation using the MSV Maxita, one of the largest offshore construction support vessels of its type.
Lease Based Production Services
Authors: Gisvold Kaare M.
Published: October 2008

Built in 1986, the PETROJARL 1 production vessel finished its 7th consecutive contract on January 26,1995 after having produced 17.9 mill barrels of oil from the UK Hudson field for Amerada Hess UK.

Table 1 summarizes the main data relating to the 7 historic Petrojarl contracts, A total of 188 MMBBLS of oil has passed through the vessel in these 8 years, while working for 7 different operators. Max.water depth hasbeen 330 m (TROLL) and minimum 71 m. (ANGUS). Max. production has been 41,200 BOPD from HUDSON, while max throughput has been 310,000 BOPD acting as a FSO on FULMAR. Contractual regularity has been in excess of 98 'A, proving that a floater can deliver as well as the best gravity platforms even under North Sea conditions.

Throughout, the vessel, and the associatedshuttling services have been owned and operated by Golar-Nor Offshore AS, acting as a production contractor. Regularity and safety records have been remarkable, andwhat was perceived as exotic and unproven technology is today state-of-the art. The advantages of production contracting have become clear to the industry, and this new contracting niche is now poised for rapidgrowth in the years to come.

A result of this experience is that the Petrojarl 1 has now been contracted to ARCO British to produce their 24 MMBBLS BLENHEIM field over an expected period of 4 years.

A further result is the newbuilding project "Petrojarl 4", currently under construction to meet First Oil in early 1996 from the Foinaven field West of Shetland for BP, in 500 m of water. The contracts are novel intheir format and are further described below.

This paper examines the contract history that has led up to this situation and discusses the way ahead.

PETROJARL 1 employment history

General

The PETROJARL 1 (see Table 2 and Fig, 1) was conceived in 1983, and after extensive technical detail work and thorough market studies, ordered in mid-1984 from NKK in Japan. On ordering the vessel, it was uncontracted, although several companies had expressed interest in using such a vessel, were it only available. In effect, the PETROJARL 1 has created its own market, In retrospect, the timing was perfect. 1984 was a year when oil prices were soaring towards the $30 mark, and finance institutions were bullish and active for new business. All this changed dramatically before the vessel was delivered in May 1986. The world has not looked the same again.

OSEBERG

The vessel secured its first contract for long term testing of the OSEBERG field in Norway, for operator Norsk Hydro late in 1985, after a lengthy negotiation which focused mainly on technology aspects, At that time, the OSEBERG field had already been declared commercial and the purpose of the test was optimisation of well layout, perforation depths and depletion strategy. As a result of the test, some wells were saved, and recovery was increased by approx, 5 mill BBLS. In gross terms, this test alone paid for the vessel, although the greatest beneficiary was the Norwegian government.
The Norne Production Ship - Topside Design and Construction Strategy
Authors: Solberg L. , Urdahl P.
Published: October 2008

Development of the Norne field at 380 m of water depth was dependent of a floating structure with the production capacity to meet the need of 27500 Sm3/SDA Y(770,000bLS/day), and a storage capacity of 115,000 m3. This challenge was met by the selection of the Tentech 850 monohull design and the development of a topside design that meets these requirements. The critical element in selection of the chosen concept, was the solution for the turret and swivel area. Particularly the swivel concept is at the borderline of proven technology so far in the industry, and need special attention during he development phases in 1995-1996. The contracting philosophy in the development of the production ship was to make use of the industries know how in the most efficient way, and design and procure the topside based on a system approach. Thus benefit from utilizing the best know- how and experience in the industry. This paper describes how this is done based on functional specifications, and with a design and layout of the topside to make this system approach possible.

INTRODUCTION

Total reservoir reserve for the Norne field is estimated at 160 mill. Sm3 of oil and 29 mrd. Sm3 of gas.

The reservoir driving mechanism will be a combination of water and gas injection. Produced gas will be reinjected into the gas cap and water will be injected into the water zone.

The topside design has to meet the following Design capacity:

(Available In Full Paper)

After the evaluation of several concepts in the summer of 1993, Statoil and the partners decided that the production and storage monohull vessel combined with a subsea installation was the best technical and economical solution for the development of the field, In the autumn of 1993 the further development of a solution for the vessel in combination with the layout and the main process philosophy for the deck arrangementcontinued in order to chose the best conceptual design for the vessel. The contracting strategy was to chose a concept for the ship in order to develop the building specificationstogether with an engineering contractor to obtain a lump sum contract for the ship during autumn 1994. The emphasis was further to select a topside engineeringcontractor in spring 1994 in order to develop the design for the topside based on functional specifications and place the orders for the main system packages duringautumn 1994 (Fig. 1- Schedule).

TOPSIDE DESIGN

General Layout

The monohull production vessel has some particular advantages compared to other floaters with integrated topsides.

During the operation, weather vaneing around the turret will provide that the ship is headed against the wind and waves at all times. This reduces the movements of the ship, thus minimizing tilting problems in the process equipment. Furthermore, positioning the ship so that the prevailing wind is slightly from the port side forces the exhaust gases to drift quickly to the side of the platform rather than along the process deck.
EURIPIDES, Load Tests on Large Driven Piles in Dense Silica Sands
Authors: Zuidberg H.M. , Vergobbi P.
Published: October 2008

In 1995 an extensive load testing program was conducted on 30' pipe piles in dense silica sands similar to those found in the southern North Sea. A highly instrumented pile was driven at one location, extracted and redriven at a second location. A total of twelve static compression and tension load tests were performed at three penetration depths between 30 and 47 meters.

Test objectives included acquiring reliable data on capacity of offshore type piles in sands which hitherto were hardly available and to understand the failure mechanisms in order to improve current foundation design.

The paper describes the design of the testing programme and project organisation and funding. Details of the lest pile and instrumentation to measure the loads in the pile and the pile-sand interaction are highlighted with an emphasis on quality of the measurements. The field-work and innovative testing facilities are also described.

Introduction

Estimates of axial capacity of open-ended pipe piles in sand are an area of great uncertainty. Various authors (e.g. Pelletier et al., 1993) have argued that the world-wide used API recommended practice (RP2A, 1982-1991) does not properly account for fundamental parameters (pile length, plug behaviour, horizontal stresses, driving history, etc.) and underestimates the capacity of driven piles in very dense sands. On the other hand no other widely recognised design method is currently available.

The base for a design method should be an understanding of the pile-sand load transfer in parallel with representative full scale pile load tests to confirm this (Hobbs, 1992). Some new promising design methods have been published in recent years (Randolph et nf., 1992, Lehane et al., 1992), but the existing data base on pile tests in sand is limited to piles of relatively small size and/or low capacity. Moreover few tests provide instrumented data of enough quality and resolution to confirm the load transfer in detail.

While this unsatisfactory situation has been recognised by most parties involved in foundation design it appeared very difficult to resolve because high capacity pile tests in sand are relatively costly. In 1985 Heerema and Fugro developed a plan to test three 42' piles in very dense sands nearshore Eemshaven in The Netherlands (Fig. 1). On each pile compression and tension tests were foreseen at four penetration depths with a potential ultimate compression load of 90 MegaNewton (MN). The programme costs were estimated at US$ 12 million. Even though a 40% European subsidy was available not enough support from industry could be generated. This contrasts with the fact that about US$ 50 million is spent annually on pile foundations in the southern North Sea and a 30% increase in allowable load could lead to a saving of about US$ 60,000 per pile installed (van Zandwijk, 1986).
Marine Dredging for Gold, Offshore Alaska
Authors: Gamett R.T.
Published: October 2008

Following the discovery of gold in 1900 on the beaches of Nome, a major offshore extension was partially drilled in 1963 and 1972. To mine the marine deposit, WestGold purchased second-hand the world's largest, ocean-going, bucket-ladder dredge, the ‘Bima’. Designed for original use on a very different tin deposit in Indonesian waters, the dredge arrived in Nome in 1986. With an overall length of 140m and >7,000 hp installed, it could dig to 45m depth at a rate of 2,000 m3/hr. Ttreoffshore conditions in Alaska, however, were entirely different from those where the dredge had operated previously. The highest gold grades were in the uppermost 2m, and the sediments were much coarser and very resistant (o digging. The marine conditions were considerably more onerous and the wind/wave conditions grossly exceeded design specifications. Sea ice limited operations to the months June through November, reducing the availability to an average of about 70%. The throughput rate averaged 457 mshour over 4 years. Very high operating costs necessitated an elevated cutoff grade and much more drilling than originally anticipated in order to define a dredge course, Altogether, 1I8,078 oz. of gold were recovered from 1987 to 1990, inclusive, when the operation was stopped because of the low gold price and structural failure. The experience illustrates the need to match marine mining equipment to each unique deposit and to delineate the reserves ahead of mining start-up.

Introduction

Gold was discovered in 1900 on the beach of Nome, Alaska, and in the adjacent shallow water of the Bering Seal. Onshore, the Alaska Gold Company has, until recently, continued to employ two bucket ladder dredges, each of 225 liter (9 ft3)bucket capacity on placer gold production. The company has successfully worked ground similar to that existing offshore but in which the permafrost has been thoroughly thawed in preparation.

Offshore, small scale dredging for gold has been attempted in vain several times this century, Only one company, however, Western Gold Exploration and Mining Company, Limited Partnership (WestGold) has been successful in achieving a significant production. The Nome bucket-ladder dredging operation from 1986 to 1990, inclusive, constituted a unique marine mining experience in the EEZ of the U.S.A.

Six offshore leases were acquired by WestGold from Power Resources Corporation. Extending from the coastline to the 3- mile (4.8km) offshore limit, the total lease area of 8,722 ha already had been partially explored over one third of its extent. Following some geophysical work, sampling had been undertaken with a Becker AP- 1000 hammer drill: in 1963 by Shell Oil Company and in 1972 by Asarco.
Use of a Dropped Dynamic Penetrometer in Cohesionless Soil.
Authors: Orenberg Peter , True Daniel , Bowman Lora , Herrmann Herbeft , March Robert
Published: October 2008

The U.S. Navy has developed a dynamic penetrometer called the expendable Doppler Penetrometer XDP) to determine in situ soil stren@. The XDP was originally designed to provide an undrained shear strength profile in SOR cohesive sediments by measuring the instantaneous velocity of a sound source probe as it falls through the water column and penetrates the seafloor. The Navy recently has added and verified a capability to determine strength properties of cohesionless soils.

Introduction

Seafloor characterization is an ever-present need and challenge in the ocean engineering world. In situ soil strength is a vital aspect of seafloor engineering in the offshore environment. However, determining this soil strength is very time consuming and expensive with present conventional methods. The expendable Doppler Penetrometer (XDP) was developed to aid in satisfying the Navy's continuing need for expeditious means for seafloor characterization. This dynamic penetrometer was originally designed to provide undrained shear strength profiles by measuring its deceleration as it penetrates the seaftoor after falling through the water column. The Navy recently has added the capability to determine the strength of cohesionless soils. Controlled laboratory tests were conducted simulating XDP deployments in a highly dense, completely saturated cohesionless soil. The results of these tests were used to formulate relationships to determine the relative density and undrained angle of internet friction of cohesionless soils from the XDP. The results of the laboratory tests and the newly developed relationships are presented. These new relationships were used to estimate the soil strength of two field sites, one a calcareous sand site offshore Key West, FL and the other a dense quartz/mineral sand offshore Biloxi, MS. The results from the XDP tests and an established in situ test, the piezocone, at these field sites are presented and conclusions are drawn regarding the capability of the XDP to measure soil strength in cohesionless soils.

Expendable Doppler Penetrometer Features and Use

The expendable Doppler Penetrometer (XDP) system (fig. 1) is designed to determine the soil strength of various types of ocean seafloors. The system initially measures the instantaneous velocity of a probe with a sound source as it free-falls through the water column and penetrates the seafloor. Utilizing the Doppler Shift principle whereby the apparent frequency is a direct function of the probe's velocity away from a receiving hydrophone, the velocity of the probe is determined up through the point that it comes to rest in the seafloor. The velocity-time curve that is produced enables estimates to be made of the undrained shear strength ofcohesive soils and the penetrability of seafloor soils in general.

The XDP probe (fig. 2) is a hydrodynamically shaped body made of aluminum and steel. The probe has a body of diameter of 3.5 in. and weighs 59.8 lb. in air and 47.6 lb. in sea water.
Use of Decision Risk Analysis in Selecting Field Development Options A Case Study: Alba Field Phase II
Authors: Ahmetf S. , Murphy S.J.
Published: October 2008

This Paper describe show a Decision Risk analysis approach has been used to develop an optimum solution to complete the Alba Field development. In particular this covers the process adopted and the utilisation of a series of tool which give a formal stucture to the work conducted.

The process described has been applied to derive a Development Plan for the concluding phase of a two phase project. Examples are given of how the methodology allows resources [o be allocated 10dlfferenl work areas priorities are defined by the lmpact on project value of reducing uncertainty in a given variable.

Introduction

The Alba Field is located in Block 16/26 of the UK Continental Shelf. lying about 130 miles north-east of Aberdeen III 138 metres of water The reservoir IS a long, narrow Eocene sandstone deposit located at a depth of approximately 6,3W' TVDSS. The field was discovered by the 16/26-5 well in 1984 A phased development was selected in 1990 because of uncertainties in the geology, reservoir performances and the processing of the Alba produced fluids. The scheme allows experience horn the first phase to be used to optimise the second phase. A development schematic is shown in Figure 1

The Alba Field Development Plan contained a commitment to a two phased development. phase 1 came on .stream in January 1994 and comprises the Alba Northern Platform (ANP), We Alba Floating Storage Unit (FSLJ). and drilling encompassing the Northern half of field reserves. Phase II was outlined as an Ah Southern plateform installed 5 years after ANP with a I March 1999 first oil..

Since Development Plan approval, a downwards shift in crude price projections led to a rethink over Southern Area development options.

Conceptual studies commenced in July 1993 to investigate a range of options for exploring the reserves in the southern portion of the field. The objective was to recommend a preferred development option. A Decision Risk Analysis methodology provided a defined process leading up to project approval A process comprising four discrete stages was adopted as shown n In Figure 2Framing the problem by agreeing the details of what is to be studied and the decision making criteriaDeterministic analysis to identify key project drivers.Probabilistic analysis to compare strategic options,Appraisal of results leading to a final development option decision.

Decision Making Process

Decision Risk Analysis is a systematic process, with intermediate reviews that ensures quality decisions, it helps expose the Project uncertainties and quantifies their impact, It also allows us toEvaluate a range of strategic alternatives from a business and tecfudcaf perspective.Effectively Incorporate and understand project risks and rewards.Determine a course of action that balances project risk with project value.
The 3 Column TLP - A Cost Efficient Deepwater Production and Drilling Platform
Authors: Murert Jan , Flugstad Per , Greiner Bill , D'Souza Richard , Solber Inge C.
Published: October 2008

Worldwide, operators are focusing efforts on deep water prospects in their search for new oil and gas discoveries. In the US Gulf of Mexico, Tension Leg Platforms (TLP) are drilling and producing in 800 meters water depth and developments in even deeper water are underway. Current TLP technology can be extended to approximately 1,500 meters, but in order to make developments at such water depths (and deeper) economical, new and innovative solutions are required to reduce costs and shorten development schedules. The 3 column TLP design described in this paper satisfied such requirements. The concept features a simplified and cost effective tendon system and a modularized deck design utilizing a ‘splash zone truss’.

INTRODUCTION

The concept presented is based on approx, 10,000 man hours of conceptual study work carried out over the last two years in close cooperation with Saga Petroleum. The work was focused on an 800 meters water depth Norwegian North Sea harsh environment case (ref. Table 1), but the feather of the 3 column TLP discussed in this paper are generic and applicable to almost any deepwater region worldwide.

The first half of the paper gives a general description of the 3 column TLP concept, including deck structure, hull and tendon system. Comparisons to conventional 4 column TLPs arc made, where relevant and advantages and savings quantified. The second half of the paper discusses the global performance and hydrodynamic aspects of the 3 column TLP including major findings of a recently completed model test. Lastly, the relevance and validity of the main features of the 3 column TX-Pis discussed for application in other geographical regions.

Cost Drivers. In an attempt to few the attention and effort in areas where the largest cost savings could be achieve the development work initially concentrated on identifying the main deep water TLP cost drivers;The hull size is a primary cost driver as it governs both the tendon system design and hull structural weight, The hull size is dependent on the topside load, tendon pretension and hull weights.The TLP tendon system cost increase with water depth, so hull optimization with respect to tendon responses and tendon pretension becomes important.For the TLPs installed in the Norwegian North Sea to date (Snorre and Heidnm), the tendon top/bottom connectors and installation teds represents approx. 70 % of the total tendon system cost. This percentage decreases for deep water, but a simplified tendon design still has a significant potential for cost savings.Important cost drivers for the TLP installation are the requirement for heavy lift barges with deep water station keeping capability, the tendon deployment duration, and the need for specialized tendon installation aid.
PETROJARL FOINAVEN - A West of Shetland Challenge
Authors: Brarresen R. , Krafft H.
Published: October 2008

INTRODUCTION

The Foinaven field was first discovered in late 1992. The field will produce oil for the partners BP and SHELL in [996. The owners laid out a commercial strategy in line with the CRINE initiative for the field development. One of the leading ideas in this respect is to utilize Industry standard and knowledge to a greater extent than had previously been common in the offshore oil industry.

When the first oil starts flowing at Foinaven later this year, three and a half challenging years are behind. BP, SHELL, the contracting companies and personal involved, will probably admit that they have been involved in a major frontier project, and have contributed in setting some new milestones and yardsticks for the industry.

The challenges of the project have been encountered within the wide spectrum of disciplines of a large offshore project. The time span of approximately three and a half years testifies to an accelerated timescale as compared with a traditional approach. The Fast Track characteristic is an essential origin for the wide range of challenges that were encountered. Throughout the project, major decisions had to be taken in an environment of ‘continous specification and design development’. This required flexibility and a ‘parallel engineering’ approach.

The field development has been effected within the realm of the Safety Case regulations. We have experienced that the industry still is in the transition zone between the previous regime of prescriptive regulatory requirements and the risk based design approach. Challenges were associated with the task of managingand implementing a common understanding of the regulatory authority expectations, and with work definition and timing resulting in a smooth and rational design and construction process.

The Field will be produced by a Production Ship, hooked up to the subsea production system via flexible risers and umbilicals. The 300,000 barrels storage capacity ship, PETROJARL FOINAVEN, will be turret moored in the field. The technical challenges in the Production Ship design have been closely related to the field location in the Atlantic ocean west of Shetlands. Here the water depth is 500 meters, and the weather is blessed with a climate harsher than the North Sea (e.g. the 100 year wave is some 18 meter significant.)

The ship solution has been designed by Golar-Nor Offshore, and is being built by Astano shipyard, with a McDermott Engineering oil process design. The ship is owned and operatedby Golar-Nor Offshore under a lease agreement with the field operator BP. This presentation will adress aspects of the Production Ship design, being one element at the Foinaven Field development. The other element is the subsea system described in an other paper in this conference.
Hydrodynamic Studies on a Cyclonic Separator
Authors: França F.A. , Rosa E.S. , Banmvart A.C. , Moura L.F. , Ahanati F.J.
Published: October 2008

The paper describes the operational principles, the modeling foundations and some laboratory results of the gas-liquid separation process taking place within a cyclonic gas-oil separator. The centrifugal and the gravity forces, acting on the flow of the gas-liquid mixture, are the main driving mechanism to separate the phases. A research program, conducted by PETROBRAS and UNICAMP, was aimed to the hydrodynamic processes occurring within the equipment. Laboratory data were obtained from down size scale models operating with mixture of air and liquid with different viscosities. The basis for the modeling is launched and a discussion regarding the limitations and constraints of the operation is presented in light of the experimental results. Prospective field applications, based on the extension of the laboratory results to actual fluids and full dimension prototypes, are also presented.

Introduction

The cyclonic separator is designed to separate the free gas and oil at the well-head. Once the fluids are separate4 they can be transported to the platform through individual lines. The oil is pumped by a conventional ESP - Electrical Submersible Pump, installed in the lower part of the device. The gas is driven upward by the pressure difference that exists between the separator and the collecting vessel on the platform. This concept of separation has a number of advantages: the pressure at the well head is lowered thus increasing the reservoir production; the oil, separated from the gas, can be pumped by a centrifugal pump transporting gas and oil to the platform through distinct pipelines avoids, or at least reduces, some typical problem in two-phase flows; separating the phases at the well head makes feasibly measuring each stream, which results in a better inventory of the reservoir. Such benefits enable this technology as a &date to develop deep water or marginal oil fields.

This concept of separation system herein described is a variation of the Vertical Annular Separation and Pumping System - VASPS. VASPS is a UK patent application issued to the British Petroleum Company in 1988. Publications describing the operational principles of VASPS can be found in Refs, 1 through 3. The testing of VASPS is now a subject of the "VASPS Pre-Sub sea Phase 11"Project.which has been operated by AGLP on behalf of Mobil and Brasoil. At its present development stage, scale models of VASPS have been tested at AGIP's production and test site in Trecate.

The present work is a joint development between PETROBRAS and UNICAMP - The State University of Campinas, in Brazil. The contract pointed out to the development of a model expressing the two-phase hydrodynamic processes occurring within the separator. During the period of the work, down size prototypes were built and experimental data was taken to calibrate the model and support it. The purposes of the laboratory simulations were two-fold: to reveal the basic mechanisms of separation and to find the operational limits of the prototypes.
Heidrun - Results from Pre-Completed Techniques ells Using Innovative Gravelpacking
Authors: Landrum W.R. , Burton R.C. , MacKinIay W.M. , ErIandsen A. , Vigen A.
Published: October 2008

During the initial phase of the Heidrun Field development, 5 wells were pre-completed using state of the art cased hole gravel packing techniques. The wells were tested and temporarily abdomen, awaiting tie-back to the Heidrun Tension Leg Platform (TLP). This paper describes the completion techniques applied and preaenta results of an evaluation of gravel pack efficiency for the wells. Flow and build-up tests were carried out on the semi-submersible drilling rig before and after gravel packing to evaluate initial productivity. Stabilized well test data acquired on the Heidrun TLP at full production is presented to document ultimate completion performance for each well.

Many innovative completion techniques were applied to ensure high well productivity and secure the operational efficiency required for the Heidrun TLP.

Innovations.

The production casing was perforated via Tubing Conveyed Perforating (TCP) guns, 12 shots per foot, on a Drill Stem Test (DST) string with down hole gauges, thus allowing perforating, perforation clean-up and flow back, pre-gravel pack testing, and gravel pre-packing to be performed in a single run. A unique loss control formulation (LCM) was developed and applied to control fluid losses to the formation. This was the first application of an LCM which had an internal, temperature actuated, acid breaker integral to the LCM filter cake. Pre-pack modeling and alternating stage a of clear brine and slurry were used to optimize gravel placement. Zones ranged from 164 to 300 ft MD, and 1 to 10 Darcy permeability, in wells with inclinations from 45 to 53 degrees. A temporary abandonment system was developed and installed which utilized a weight actuated ball valve, run in the same trip as the post-gravel pack test string, in order to temporarily abandon the well without placing any damaging fluids across the production zone. This allowed the potions to be temporarily suspended with hydrocarbons across the zone and two mechanical barriers in place. The gravel pack screen assemblies included alternative path gravel placement utilizing 4 shunt tubes per gravel pack screen assembly.

The innovative gravel packing techniques used at Heidrun resulted in high completion productivity and correspondingly high flow rata. A study performed to evaluate the economic impact of acceleration showed that going from a 20,000 BOPD well rate to a 30,000 BOPD well rate added $108 million in pre-tax NPV to Heidrun project economics. Actual results will be grater since well rates have exceeded 43,000 BOPD.
An Innovative Fast-Track Development for CMe d'lvoire
Authors: Kreider G.J. , Barnes J.E. , Smitherman J.E. , McFarland J.M.
Published: October 2008

Introduction

In May, 1994, approval was received for the development of the Panthere Gas Field and Lion Oil Field by UMC Petroleum Corporation as operator with its painters Plus petrol, Global Natural Resources, International Finance Corporation and the national oil company of C6te d'Ivoire, Petrol. At that time, UMC had drilled one well from a jack up at Panthere in 270 feet of water and had set a guyed caisson, Following thePanthere gas discover, the Lion oil discovery well was drilled in 235 feet of water and another guyed caisson was set.

Paragon Engineering Services had been hired in late 1993 to develop project scenarios and cost estimates and as the project evolved, detailed engineering, procurement and construction management services. The original plan of development is shown in Figure 1. Production equipment for 30,000 BOPD, 16,000 BWPD and 75 MMSCFD was to be installed on a jack up drilling rig converted to a Mobile shore Production Unit (MOPU) located at the Lion 'A' caisson. Production from Panthere would flow through an 8-inch line to the MOPU. The production equipment on the MOPU would (1) separate oil, water and gas, (2) treat the oil for sale and the water for discharge, (3) pump the oil into an 8-inch pipeline to the refinery in Abidjan, (4) compress the oil well and gas well gas as needed, and (5) dehydrate it for sale. A CALM buoy with shuttle tanker was included in the original plan for early production and as a backup to the oil pipeline. It was also unknown at project initiation whether a gas sales contract would be successfully negotiated, and thus the project was to proceed on the basis of flaring produced gas with capability to add equipment at a later date for gas sales.

As the development proceeded a second caisson was installed at lion the 8-inch onshore oil line to the refinery was not installed the capacity of the gas process equipment was increased from 75 to 100 MMSCFD, an FPSO was instead, gas sates was require the government required the gas sales line to be oversized for future expansion and the separation metering and heating station required for delivery of gas at the power plant in Abidjan was more elaborate than anticipated.

An ambitious schedule was laid out in May 1994 calling for first oil delivery in April 1995 and in the event of successful negotiation of a gas sales contract with the power plant in Abidjan first gas delivery in October, 1995.

Although approval was received to begin detail engineering in May 1994, money was not approved to purchase equipment needed for oil production until September, 1994. The gas sales contract was not signed until September 30, 1994 and approval to purchase equipment necessary for gas sales was not granted until December, 1994. Key dates are shown in Table 1
Strategies For Cost Effective Solutions in Deep Water Production
Authors: Karrer Eduando , Meter Wagner G.
Published: October 2008

The objective of this paper is to present the strategies adopted by Petrobass in the exploitation of deep water giant oil fields, comparing the use of new buildings and the conversion option.11 pints out the F.P,S.0, and semi submersible solutions, describing the eases of Petrobass 32 and 33 (F.P.S.O. units) as well as Petrobras 18, 19 and 26 (semi submersible units). h is also presented a comparison of schedules and cost in both cases, for the F.P.S.O. and semi submersible options (conversion and new building). Finally is presented the future trends for possible optimization in a short and long term scenarios.

Historical Background

The exploration of oilfields alongside the Brazilian coastline was performed in hove distinct conceptual phases, to wit: during the first phase. the Company exploited up to water depths of 200 meters. utilizing the offshore fixed platform concept, During this stage, a total of 72 such platforms were installed in Brazilian coastal waters. The second phase initiated with the discoveries of the giant oilllekis of Madim, Albaeora and Barracuda, the Company resolved to use floating production systems associated to wet Christmas trees, a method which embled the Company to set repeated world production ramrods.

The Anticipated Production Systems (SPA's) were among the first systems to lx projected and installed in extremely short lead times. The majority of these methods provided for oil production and burning of the gas thereby produced. The burning of gas and the use of standardized and small-capacity process plants turned various utits feasible, within eight to ten months - from the signing of the contract to the first oil being extracted.

Based in this initial production concept, the offshore activities improved significantly in the Campos Basin, off the coast of the State of Rio de Janeiro, with the fixed platform concept including a process plant, utilities and living at waters, all integrated on a single module. From the total amount of fixed platforms installed in this phase, almost the totality used steel as the basic material for the jacket and decks, with the exception of two concrete platforms that were installed in the Ubarana field, being named PUB-1-and PUB-2 platforms. This step was in all affects, considered of extreme importance to PETROB in that it initiated the search for technical capacity in the direction of deep-water oilfield production. Such technological parity was in fact consolidated and exenterated at PETROBFL4Sin its CENPES, the research and elopers center as well as in its various independent same provirus in Brazil.

Selecting the Alternative to be Adopted

The selection process for the adoption of the most suitable platform alternative normally takes place during the project's feasibility study. when all the technically field-proven solutions are analyzed, taking into account such factors as the availability of vessels, rigs, etc.
The Heidrun Field:Oil Offtake System
Authors: Rajabi F.D. , Braivik K. , Syvertsen K.
Published: October 2008

Off take of oil from the Heidrun field is achieved through a Direct Shuttle Loading (DSL) system. This approach eliminates the need for an intermediate storage facility, allowing continuous production and transfer of oil directly from the Heidrun TLP to shuttle tankers. Purpose-built or appropriately converted tankers with an integral bow turret locate and connect to a Submerged Turret Loading (STL) buoy which functions both as a tanker mooring point and a termination for the flexible offloading line. The system is designed to permit the tankers to remain connected during loading and to disengage km the STL buy on completion of loading in all weather conditions up to and including the 100 year storm.

This paper describe a implementation of the Heidrun DSL system from conception to first oil. It gives the background for choosing the DSL system and information on the data generated to support the selection process. Design, fabrication and installation of various components are explained to give an sight into the challenges that had to be overcome for realization of this 'first-of-its-kind' system in a record time of about one year

Installation of the complete DSL system in the summer of 1994, approximately one year ahead of the original plans, mabled full scale in situ testing of the system with a purpose modified shuttle tanker. The two-month program provided the equivalent of one year of operational experience with the system before first oil. The paper addresses data obtained during the full scale testing, and comparison with analytical results.

The operation of the Heidrun DSL system is also described, These data together with the experience gained during realization of this bold concept will give key information on how such a concept can be effectively applied to any major or marginal field development scenario either as an off take system or in conjunction with an FPSO/FSO.

Introduction

The DSL represented a method of offloading oil which required a bold decision for its implementation for a major development like Heidrun. When in summer of 1992 Conoco decided to use this concept for Heidrun, the STL technology was still in it a infancy and had not advanced beyond the preliminary design stage. Nevertheless, the idea was promising and offered potentially substantial cost savings when compared with other alternatives. However, the 'first-of-its-kind' and uninvolved nature of the STL technology, combined with the extremely tight schedule for its implementation, presented the Conoco Project Team with a formidable challenge.

An STL system was used for the first time in October 1993, albeit in a permanent connection mode, for the UK Fulmar field. Some Fulmar experience was useful, including the marine operation aspects, in service data, etc. which led Conoca to adopt a modified approach to marine operations and very rigorous testing and trial programs for implementation of the Heidrun DSL system.
Overview & Interfaces: International Standards Organization Design Guidelines for Platforms to Resist Earthquakes
Authors: Craig M.J.K.
Published: October 2008

This paper summarizes the work product and activities of anInternational Standards Organization (1S0) panel (committee) formed to create a set design standards for steel offshore platforms to be located in earthquake prone areas. This work product is a draft set of earthquake design standards which have been submitted for review and eventual incorporation, along with the products of other panels, into a comprehensive set of fixed steel offshore platform design provisions for worldwide use. The 1S0 committee heirarchy, the basic charge to the panel, the mix of necessary talents, liaisons, references, the code development process and the challenges to produce this draft are described. The basic earthquake design process is outlined. Future improvements to this draft are identified, as are the challenges that lie ahead.

Background

An industry initiative to forge a common set of sustainable engineering specifications for oil and gas industry use on a worldwide basis was started in 1993. The drivers behind this are potential cost savings through uniformity, consistency and better communication. These factors can reduce costs through less expensive fabrication and improved safety. The intent is to create global standards that reflect the use of 'Product Service Level' (PSL) philosophy, making maximum use of existing standards and minimum use of manpower. As in the other petroleum-related technical arenas, the global offshore platform design community had to decide how to best organize to meet this challenge, and what base document should be used, since there exist several professional society and national versions of platform design codes. This paper outlines the evolution of one part of this effort, relating to the design of offshore platforms against earthquake effects.

ISO Heirarchy & Panel 5 Charge The various standing, advisory, oversight and ad-hoc 1S0 committees and technical panels formed to develop theseinternational design standards are by default numerous. The author's understanding of the offshore platforms ISO heirarchy is Standing Committee 7 on Offshore Structures (SC7) is responsible for the work products of three Work Groups (WG3 - Fixed Steel Structures, WG4 - Fixed Concrete Structures and WG5 - Floating Systems). These Work Groups direct the work of specialized technical resource panels, which work for one or more of these three Work Groups. This organization is depicted in Figure 1.

Panel 5 on 'Seismic Loadings and Response' presently works for WG3/Steel and WG4/Concrete, and is charged with developing a comprehensive set of seismic design criteria for sizing fit-for-purpose platforms to be located in earthquake prone areas, while utilizing existing standards as much as possible, and incorporating PSL philosophy. Such areas include the Cook Inlet, Alaska, and offshore Southern California, Mexico, Venezuela, Peru, Australia, New Zealand, Indonesia, Japan, China, eastern Russia, india and in the Caspian Sea.