bluuebunny/crossref_metadata_2025 huggingface dataset:
Auger's Lateral Mooring System: Key Learnings
Authors: Lohr C.J.
Published: October 2008

Installation of the Auger TLP was completed in February 1994 with fit production in April 1994. The lateral mooring system (LMS) was critical to the successful mating of the hull and deck and installation of the tendons. The LMS is currently used to position the TLP over the wells during drilling operations and to assist the tendons in holding station during storm events. This paper describes the most significant lessons learned duringdesign, fabrication, installation and operation of the LMS. me results presented in this paper will be useful to mooring system designers, component manufacturers, installation contractors and other operators pursuing floating system options for development of deepwater fields.

Specific results to be addressed include design criteria component selection, corrosion protection systems, component manufacture, anchor performance, locked coil failures, buoy pin retainer failures, line tension measurements, installation procedures and offshore operations. ?the most significant aspect of this paper will be to provide the industry with the key Iearning from the Auger LMS so that deepwater mooring systems maybe further improved for future applications

INTRODUCTION

Auger's LMS is a combination wide chain mooring system with submersible buoys and drag embedment anchors secured on the TLP by linear winches (See Figure 1). The entire winching system, except for the bending shoes, is located in the TLP hull columns (See Figure 2), Each of the eight mooring lines has a minimum breaking strength of 2900 klps. All components are corrosion protected, except the chain, and designed for a 30 year service life, An overview of the Auger LMS is presented in Ref. 1. A general discussion of lateral mooring systems for TLPs is presented in Ref. 2.

SYSTEM DESIGN

Numerous studies were performed in-house, with mooring component manufacturers, and with outside consultants to optimize the LMS configuration in terms of performance, COSL weight and schedule. Joint Industry Studies conducted by Noble Den ton (DMOOR mooring analysis program, Wire Fatigue, Chain Fatigue) and Aker Omega (Large Scale Anchor Test) provided valuable information that influenced the LMS design. The LMS design also built on the experience gained from the Lena guyed tower (Ref. 3) and Placid FPS (Ref. 4) mooring systems.

Design Criteria

The LMS was designed by Shell in accordance with API RP 2FP1 (Ref. 5) and additional criteria developed within Shell. Limits were placed on ?TLP offset line tension, anchor loads, buoy depth and fatigue for both operating and design conditions. Higher safety factors were specific for the operating condition where the LMS is used to pull the TLP over an outermost well. Line dynamics and line fatigue were analyzed during the design process. A detailed description of the LMS design criteria is presented in Ref. 1.
Thin Walled Liner Hanger Equipment Enables Well Deepening Project
Authors: Sutherland Jamie , Weaver Chris , Aiello Peter
Published: October 2008

Shell Canada estimates that a thin-walled, slimhole design for liner equipment can save up to $3-4 million (U.S.) per well in deep re-entry applications by allowing existing wells to ix. deepened (or sidetracked) rather than drilling new wells from surface. The design makes it possible to reenter existing wells, successfully isolate depleted zones, and deepen the well into virgin-pressured reservoirs, The design includes thin-walled, close-tolerance liner hangers, liner top packers, tie-back seal assemblies, and liner setting sleeves that provide reasonable burst and collapse resistance while maintaining an inside diameter to facilitate drilling deep, deviated 4-3/4" hole with a tapered2-7/8" × 3-1/2" drill string, The authors will explain the design and the rationale behind it, and illustrate its value, using case studies from Shell Canada's Waterton field as examples. In this field, gas-producing wells originally drilled in the 1950s, '60s and '70s to depths of up to 14,760 ft (4500 m) were completed with perforations in 7" casing and open hole, These wells are now being reentered in an attempt to tap new reserves. The reentries encounter particular y challenging sour-gas/low-temperature/diverse formation pressure conditions. The objective of the reentry program is to seal off the depleted bottom zones of the wells and tap into the same fault-repeated formations at virgin pressure, at a deeper level.

Introduction

Like other operating companies, Shell Canada is faced with the challenge of continually lowering its finding and producing costs. One way of meeting [his challenge is through reentry and deepening projects, which use existing well structure to tap new zones. Reentering and deepening an existing well rather than drilling a new one eliminates a major new capital investment, resulting in drilling and construction costs potentially less than half of what they would be for a new well. Further benefits accrue if the project can be carried out using slimbole techniques, Both of these factors influenced Shell Canada's decision to undertake a reentry and deepening project in 1995 in its Waterton field in western Canada.

Waterton Field Background and Project Objective

Waterton field production capability has recently declined to the point where produced volumes are unable to fully utilize the Waterton Plant, particularly as a result of the near depletion of the prolific Sheet if Rundle-Wabamun'A' pool. New reserves and additional deliverability are of utmost importance in keeping the plant at capacity in order to maximize revenue and maintain low unit operating cost.

The purpose of the reentry and deepening initiative was to determine whether commercially viable pools of hydrocarbons exist at the south end of the Waterton complex, beneath the Devonian Wabamun formation.
The Yme Jack-Up with Skirt Foundation
Authors: Eide A. , Tuen K.A. , Beerheim M.
Published: October 2008

The Yme field is developed using the Maersk Giant jack-up as a permanent drilling and production platform. This paper will present the structural and geotechnical design aspect of jack-up with skirts to document this new way of utilising jack-up structures. It will also outline the design of the riser system and installation aspects of the rig, The skirt foundation is an innovative cost effective foundation concept offering substantial opportunities for extending the use of jack-up structures compared to traditional spud-ears foundations. The Yme field development would not have been economically attractive without skirted foundations on the jack-up.

Introduction

The Yme field is located approx, 100 km south-west of Egersund in Block 9/2 offshore Norway. The water depth is 93 m. The field is marginal with an estimated economical lifetime of 70 months. The producible reserves are approx, 10.4 mill Sm3 oil. The maximum production rate is stipulated to 8000 Sm3 pr day.

The drilling and production facilities are provided by means of a converted jack-up platform, Maesk Giant. The rig was equipped with process weighing 1150 tonnes. In addition the hull was modified to provide support for eight production risers.

A converted oil tanker with capacity of 150000 m' oil is utilised as a Floating Storage Unit (FSU). The vessel is located about 2.500 m from the jack-up platform, and offloading is done by shuttle tankers connecting to the stem of the FSU, ref. fig 1.

Jack-up rigs are widely used as mobile drilling units for the exploration of hydrocarbons. At present jack-up rigs have been placed in water depths of up to 125 m, but there is interest in extending their use to greater depths and larger deck weights, To demonstrate the feasibility of standard jack-up rigs for the Yme field Statoil found it necessary to account for the rotational stiffness of the footing in the structural analysis. Small skirts have previously ken used on spud-cans in shallow water to reduce scour. At Yme, the skirts were used to achieve restraint (bottom Fixity) and thereby reducing the leg utilisation drastically. This new Statoil approach of utilising skirts have previously been used in connection with the Sleipner Vest development in the North Sea, but was then used mainly for increasing the bearing capacity ref. /1/.

Foundation

Skirt Geometry. The spud can-skirt arrangement is shown on figure 2. Each spud-can is equipped with skirt extending 4,8 m down from the circumference of the spud can. The skirt was built up of six 30 mm thick half cylinders, welded to the extension of the three chords and to bottom of the thickness of the lower part of the skirt was increased to 60 mm to resist the forces from the installation phase.
Liuhua 11-1 Development-Subsea Conductor Installation in the South China Sea
Authors: Herrmann Robert P. , Coleman Rod A. , Hughes John D. , Mu Huang Chang , Jiang Zhang Ming , Macfariane Andrew M.
Published: October 2008

This paper describes the initial phase of a multi-well subsea development using a building block technique. This phase included the setting of the conductors for all 20 wells, manifold piles and pipeline bases and the drilling of 15 wells to various stages of completion. Offshore operations were conducted in batches to maximize efficiencies and economies of scale. The emphasis of paper is on the jetting operation of the conductors and the positioning techniques used to meet the requirements of the later phases of the building block process.

Introduction

The foremost challenge for deep water operators today is to develop oil and gas fields economically. Using non-conventional techniques, Amoco Orient Petroleum Company, and its partner China Offshore Oil Nanhai East Corporation, and Kerr-McCiee China Petroleum Ltd., have responded to the challenge by developing the Liuhua field in the South China Sea in a low cost, technically innovative manner that doubled drill-rig productivity and eliminated the need for costly subsea templates. OTC paper 8172 (Ref. 1) presents an overview of the Liuhua project.

The Liuhua reservoir, located 120 miles southeast of Hong Kong will produce oil with an average crude gravity of 22° API and a GOR of 20 scf/bbl. The development plan calls for a manifold with 20 horizontal wells arranged in two parallel lime soften each. Refer to Fig. 1 for the field location and Fig. 2 for the field layout. The deviated wells are horizontal in the pay zone and are produced with submersible pumps powered by cables suspended from the Floating Production System (FPS). The subsea equipment will be created building-block style from the manifold outward, as illustrated in Fig. 3. This approach allows the subsea facility to be expanded by adding future wells or tying in remote clusters. The Liuhua field will produce from ten wells initially with a number of wells being added after for oil. The wells are located without the aid of a template. Production lines or jumpers are measured and fitted between wells after setting the guide bases. These jumpers are fabricated aboard the FIN and can be installed before or after setting the horizontal trees, as described in OTC paper 8175 (Ref. 2).

In October 1994, the Reading & Bates semi-submersible, Jim Cunningham, was contracted to commence development of the Liuhua Field. During this initial five-month drilling phase, five wells were scheduled for drilling to TD and conductor pipe was to be drilled and run for the remaining 15 wells and the two manifold piles. These wells and piles required precise positioning to correctly define the field orientation and to facilitate fabrication of the well-to-well production jumper spools on the FPS. The allowable position error for the locations was l2 ft horizontally and vertically relative to the previous conductor. In the field, a target vertical tolerance of was adopted.
Liuhua 11-1 Development-Downhole Completion Program with Electric Submersible Pumps and Wet-Mateable Electrical Connectors
Authors: Rohloff James M. , Bourne Douglas R. , Shan Yao Jun , Reid James , Hay Donald H.
Published: October 2008

Amoco Orient Petroleum Company, in partnership with China Offshore Oil Nanhai East Corporation and Kerr- McGee China Petroleum Ltd. is installing the first field-wide, subsea electric submersible pump system in the Liuhua Field. Located in the South China Sea, the Liuhua project uses many existing stand-alone technologies, but has created a unique situation by combining them in the development of one field.

As with other subprojects within the overall Liuhua development, Amoco and partners brought in LasalIe Engineering to provide expertise in completions and especially ESP applications, Selection of the completion equipment suppliers and the specific equipment was a joint decision by the partners and Lasalle Engineering.

The equipment selection criteria were driven by the concept of 'fit for purpose,' meaning: 'select the most appropriate supplier and equipment to fit the specific Liuhua Field requirements.' Supplier and equipment selections were based on a matrix of criteria, including:Information case histories of the recommended equipmentWork history in ChinaThe company's safety philosophyQA planTraining philosophyFailure analysis philosophycostsOther factor

Lasalle's compensation for the completion equipment is based on an incentive scheme that results in Lasalle sharing significant risk. Essentially, if the equipment is available for production, a daily rate is paid. If it is not available, then payments stop. The actual daily rate value diminishes with every new installation, thereby requiring increasingly longer operating-run lives to recover their investments.

This paper describes some of the unique completion equipment requirements, the equipment selection methodology, and the completion equipment incentive contract scheme used for the Liuhua Field.

Liuhua Field Description

The Liuhua Field is located in the South China Sea approximately 120 miles (200 km) southeast of Hong Kong (Fig. 1). The field is located in approximately 1,020 ft (310 m) of water. Liuhua was discovered in 1987, and appraisal and delineation drilling occurred through 1989. Amoco Orient Petroleum Company, and partner China Offshore Oil Nanhai East Corporation (CONHE) received approval for the development of the Liuhua Field in 1993 (Refs. 1 and 2). The field development plans include 20 subsea horizontal wells, all incoporating ESPS for artificial lift. As shown in Fig. 2, the offshore facilities include a floating production system (FPS) described in OTC 8187 (Ref. 3), a subsea production system described in OTC 8175 (Ref. 4), and a floating production, storage, and offloading (FPSO) vessel described in OTC 8188 (Ref. 5). The FPS is a semi-submersible drilling unit that has been retrofitted to house the subsea facility control system and provide the power generation for the wells. The FPSO is a 143,000 dwt tanker that has been retrofitted to include the field's process equipment, oil storage, and offloading.
NORSOK Standards -Replacing Company specifications in the North Sea.
Authors: Johansen A.R. , Langeland T. , Tangen T.A. , Haugland T.J.
Published: October 2008

The rising cost of offshore development and reduction in oil prices required new initiatives for the business to survive.

Therefore, the Norwegian oil industry has, as a part of the NORSOK initiative, developed a set of new industry standards to replace individual company specifications. The ultimate goal is to develop a set of international (ISO) standard for the industry.

Abbreviations

CENEuropean Standardization Organization HTML Hypertext Markup Language ISO International Organization for Standardization MIE Minister for Industry and Energy NCS Norwegian continental Shelf NORSOKThe Competitive Standing of the Norwegian Offshore Sector NPD Norwegian Petroleum Directorate NS Norwegian Standard NSFNorwegian Standards Association NTSNorwegian Technological Standards Institution OLF The Norwegian Oil Industry Association SGML Standard General Markup Language TBL The Federation of Norwegian Engineering Industries

The Initiative

The NORSOK initiative was started in the summer of 1993 by the Norwegian Minister of Industry and Energy, Mr. Finn Kristensen. He established the Development and Production Forum for the Petroleum Sector, with top imaging directors of the oil and gas industry, including the politician and the authorities concerned.

The coat of exploration, development and operation was escalating to m alarming level, while the price of oil was dropping. Exploration drilling in the last few years had turned out few discoveries of larger fields, while many small discover were uneconomical to develop with current technology.

The main aim for the Forum was to identification improvement potentials in cost of field developments and petroleum policies that would make the Norwegian Continental Shelf (NCS) more competitive with other petroleum-producing provinces, in order to attract further investment. Two subsidiary objectives were formulated when NORSOK was launched:A 40-50 per cent reduction in cost and lead time over the next five-year period, baaed on beat practice in 1993.Good results have been obtained from work with safety and environmental protection on the NCS, and Norway's oil industry can reasonably be described as one of the safest in the world. It is intended to maintain this position.

The consequent of this initiative was thus hoped to be a continuation end prolongation of North Sea activities, with continued employment and commercial activities in the oil and gas industry. AS this industry currently provides for a substantial income to the state of Norway, this was very much a political issue as well m an industrial matter.

Organization Of work

Having worked for six months on this task, the Abovementioned Forum proposed to the Minister in February of 1994 to launch 7 workgroups, to identical and implement measures that would improve the competitive standing of the Norwegian petroleum industry, and one of these were to deal with Standard. The work groups were to deliver their reports to the Minister within one year.
Liuhua 11-1 Development-MAXIMO Systematic Maintenance System
Authors: Corrigan Mike M. , van Rooy William , Hong Zhao Tian
Published: October 2008

Amoco Orient Petroleum Company (AOPC) used a systematic approach to develop the maintenance systems and programs for its Liuhua Field located in the South China Sea. The development of the Liuhua Field has presented many exciting and unique challenges from both the engineering and operational perspectives. The Liuhua Overall Development Plan established the mission for the operating company to produce and market the Liuhua crude by providing for the design, construction, and installation of the offshore facilities, and for the drilling and completion of the wells. Development of maintenance and operating systems proceeded in parallel with the engineering and construction of the facilities. AOPC took advantage of the opportunity to develop operating and maintenance systems specifically tailored to the unique requirements of the Liuhua Field. A comprehensive plan for maintenance management was developed shortly after project approval, and was executed throughout the construction phase, This paper provides an overview of the approach taken to develop the maintenance programs and systems, and the steps taken to implement the comprehensive system into AOPC.

Introduction

The Liuhua 11-1 Field is located in the South China Sea, approximately 120 miles (200 km) southeast of Hong Kong. The field development plan includes 20 subsea wells produced through electric submersible pumps (ESPS) powered from a permanently moored FPS. The wells are produced through subsea pipelines to a permanently moored, 143,000 FPSO 1,7 miles (2,8 km) away. A location map and field perspective view are shown in Figs. 1 and 2, OTC 8172 (Ref. 1) presents an overview of the Liuhua 11-1 Field Development, its history and the challenges presented to partners, Amoco Orient Petroleum Company (AOPC), China Offshore Oil Nanhai East Corporation, and Kerr-McGee China Petroleum Ltd

Amoco included a small group of experienced operations personnel in the conceptual design phase of the Liuhua project, who were charged with providing practical operations and maintenance input. Based on Amoco's experience at other locations, it was determined early in the conceptual stage of project planning to use a reliability-centered maintenance (RCM) approach in formulating a maintenance strategy to cover preventive, corrective, and compliance related work, and the development and specification of the supporting spare parts inventories. The main objective of the RCM approach is to maintain the inherent reliability that was designed into the facility. Moubray (Ref. 2) provides a detailed explanation and history of RCM. The RCM methodology is based on the following principles:Identifying system functions and defining how those functions are preservedIdentifying failure modes whereby system functions are lost or degradedPrioritizing the importance of the failure mode in relation to the system affectedSelecting effective maintenance tasks that are applicable and appropriate for the equipment component failure modes that impact the identified function
Efficient High-Permeability Fracturing Offshore
Authors: Phillipi Max , Farabee Mark
Published: October 2008

Offshore operators can more efficiently and effectively perform high-permeability and conventional hydraulic fracture treatments by blending treatment slurries under microprocessor control, adding undiluted acid on-the-fly, and altering sand concentrations and other slurry properties instantaneously. A two-skid system has been designed with these considerations in mind. The system, which can be shipped efficiently in 1S0 containers, has been tested on fluids up to 210-cp viscosity and can step or ramp sand concentrations up to a maximum of 20 lb/ gal. All additives, including acid treatments, are added on-the; leftover additives and acids may be stored for future jobs.

The system may be applied in most conditions, including offshore wells requiring conventional or high-permeability fracture treatments and certain land-based wells in remote areas where a compact skid is needed.

Three significant benefits have resulted from using the compact-skid system:Offshore operators have been able to ship the skid system at 2070 of shipping costs of non-ISO equipment.On-the-fly mixing has prevented material waste associated with batch-mixing.Volumes pumped on actual jobs have closely matched job designs.

Data has been collected from several Gulf of Mexico jobs run with the two-part skid system that has been designed for conducting hydraulic fracture treatments from offshore rigs

Transportation

Since shipment of oilfield service equipment is a significant element of well-completion expense, especially in the Gulf Coast area and remote areas, engineers developing the two-skid set designed it to fit into two 1S0 shipping containers. Figure 1 illustrates a typical ISO stacking arrangement commonly used in the holds or on the decks of ocean-going ships and barges. In this example arrangement, it is possible to transport 60 1S0 containers in the proposed space. If a conventional fracturing skid is shipped in the space, it must be placed on the lowest level and nothing can be stacked on top of it (Figure 2). Since the skid extends past the floor-plan borders of three cargo spaces and spaces are five-high, the skid occupies 15 cargo spaces.

The two-part, 1S0 skid conserves shipping space (Figure 3) because it occupies two standard ISO spaces, which can be anywhere in the 60-space group.

Design Considerations

Several requirements were considered and incorporated into the design of the two-skid system. The equipment was designed to blend sand (at concentrations up to 20 lb/gal) with clean fluids varying from water to 210-cp gels. The capability to pump at a range of delivery rates and to blend highly corrosive acids meant that the equipment needed a variety of liquid additive pumps.
Development of a Self-Equalizing Surface Controlled Subsurface Safety Valve for Reliability and Design Simplification
Authors: Hill Thomas G. , Bhavsar Rashmi
Published: October 2008

Surface Controlled Subsurface Safety Valves (SCSSVS) are normally closed devices that provide control of wellbore fluids, and w-c required in virtually all offshore wells world wide. This paper describes self-equalizing SCSSVS, discusses the evolution of the technology, reviews current design issues, and offers a recent technological advance that places an equalizing passageway in a unique configuration. Procedures required to open non-equalizing SCSSVS are discussed, as well as methods of providing an internal equalizing passageway in the valve, and the inherent advantages and disadvantages of each.

Self-equalizing SCSSVS featuring a 'through-the-hard-seat' equalizing passageway will have wide apply in low to medium pressure offshore wells where operational difficulties may rule out a traditional surface equalizing system. The economics of most producing fields will be enhanced by the lower cost, ease, the simplicity and reliability of this development.

Performance of the valve in cycle testing, sand slurry testing, flow erosion testing and temperature testing is discussed in summary

Introduction

The most common SCSSVS on the market today have flapper closures, and are biased closed by an internal spring. A small diameter control line conveys hydraulic fluid under pressure from a surface pump to a piston internal to the valve, which compresses the spring and holds the valve in the open position, Loss of control line pressure for any reason causes closure of the valve. Pressure builds below the closed SCSSV, while the pressure above bleeds off, and a pressure differential across the flapper is established.

For several reasons, the pressure in all SCSSVS upstream and downstream of the closure must be nearly equal before opening. When the valve is in the closed position, well fluid pressure acting upon the relatively large surface area of the flapper makes opening difficult because the hydraulic area of the operating piston is smaller. This difficulty in opening cannot be easily overcome simply by increasing hydraulic control pressure, The mechanical force exerted against the flapper by the relatively small cross-sectional area of the opening piston and cylinder assembly is simply inadequate to open the valve at normal hydraulic pressures. Increasing the control fluid pressure in an effort to overcome closing forces may burst the control line carrying the hydraulic fluid and/or damage critical internal parts. Even if the flapper could be opened under a differential, the initial flow of well fluid would erode the primary sealing surface of the flapper and/or seat, Any damage to this primary sealing surface is extremely critical because it must remain intact to prevent uncontrolled flow of well fluids when the valve is closed in an emergency, To overcome these difficulties, mechanisms have been developed to allow the pressure above and below the flapper to equalize prior to the complete opening of the flapper.
Pompano Subsea Development - TFL Well Design for Deepwater Unconsolidated Waxy Oil Reservoirs
Authors: Holt J. , Black J.W. , Meader A. , Whitehead N.
Published: October 2008

BP Exploration's Pompano subsea development, in 1865 ft of water uses a subsea production system to produce oil to a host platform 4.5 miles away. This paper describes the well construction and completion design for a template/manifold Through Flowline (TFL) subsea oil production system. Including are an outline of the rig upgrade requirements, casing design, completion design, and simultaneous operations strategy. It will provide a useful guide for drilling staff involved in planning and execution of a subsea development.

Introduction

The Pompano field is located 24 miles southeast of the Mississippi River Delta and comprises 5 Gulf of Mexico Outer Continental Shelf lease blocks. It is being developed by BP Exploration Inc. and its partner Kerr McGee Corporation with a conventional 40 slot platform and a 10 slot subsea production template/manifold. The platform was installed during 1994, in the southeast corner of Viosca Knoll Block 989, in a water depth of 1290 ft. The subsea production/manifold was installed during 1995 in Mississippi Canyon Block 28, about 4.5 miles southeast of the platform, in a water depth of 1865 ft.

The reservoir is located at a true vertical depth of approximately 10,500 ft. Initial bottom hole pressure is about 6,700 psi which equates to a maximum shut-in wellhead pressure of about 4,600 psi, Bottom hole temperature is about 200°F.

BP Exploration had a unique set of problems to solve in exploiting the Miocene reserves of the Pompano field locatedin Mississippi Canyon 28 and 72.Deepwater drillingBlack oil with a high cloud pointUnconsolidated sands.

This paper presents the technical highlights of the well and completion design, necessary rig upgrades required to install the completion and Tlrough Flowline (TFL) trees in 1865 ft water depth, key parts of the TFL completion installation procedure, and the simultaneous operations strategy in order to maximise oil production during a continuous drilling program.

First oil was achieved from the platform in the fourth quarter 1994, and is expected from the subsea in the first quarter 1996. This paper should be read in conjunction with 1996 OTC papers 8205 and 8209 (Refs, 1 and 2) in order to gain a full understanding of the complexity of the Pompano subsea development scheme.

Well Design

Rig Upgrade. A rig was selected that would be able to perform completion operations in 1865 ft water depth and handle 55 ton subsea trees. However, there were a number of additional modifications which needed to be carried out in order to perform the requird operations on this development. These consisted of:-

Mooring. Additional 3.25 in anchor chain was added to allow the mooring system to meet the BP Exploration design criteria of being able to handle a 15 year return period hurricane with one mooring line broken.
Oman India Pipeline: An Operational Repair Strategy Based on a Rational Assessment of Risk
Authors: German Philip
Published: October 2008

This paper describes the development of a repair strategy for the operational phase of the Oman India Pipeline based upon the probability and consequences of a pipeline failure. Risk analyses and cost benefit analyses performed provide guidance on the level of deepwater repair development effort appropriate for the Ornan India Pipeline project and identifies critical mm toward which more intense development effort should directed.

The risk analysis results indicate that the likelihood of a failure of the Oman India Pipeline during its 40-year life is low, Furthermore, the probability of operational failure of the pipeline in deepwater regions is extremely low, the major proportion of operational failure risk being associated with the shallow water regions.

Introduction

The Oman India Pipeline (OIP) will transport natural gas approximately 1100 km from Oman to India under the Arabian Sea at water depths to 3540 meters. The majority of the Oman India Pipeline route is not diver accessible, Diverless pipeline repair systems are currently under development by the offshore industry at a modest pace, but a diverless pipeline repair has not been performed to date; although a number of pipelines are currently in operation in water depths beyond diver reach. Hydrate formation resulting from pipeline failure and subsequent water ingress is the subject of a separate program of investigation. This programmes includes physical testing and mathematical modeling to gain thorough understanding dehydrate morphology and confirm the proposed engineering solutions.

Risk Analysis

Overview. As part of the comprehensive risk analysis program undertaken for the Oman India Pipeline project, an operational risk assessment of the subsea pipeline was performed to determine pipeline failure probability subsequent to successful installation and start-up, during its 40-yw design life. Expected hazards which may threaten the subsea pipeline during operation and the of failure initiating events resulting from those hazards were identified. Hazards evrduated include those that stem from natural phenomena such as earthquakes, subsea landslides and ocean dynamics; third-party events such as vessel accidents and anchor dragging incidents, sabotage and military action and processes such as internal and external corrosion. The operational risk analysis was performed for discrete regions or zones along the proposed pipeline route permitting characterization of the various zones based on unique features or common susceptibility to hazards. The overall pipeline operational reliability was then obtained by integration of the reds for each zone.

Zone Delineation.

The subsea portion of the pipeline was segregated into sixteen zones along the planned route across the Arabian Sea and the hazard probabilities for were zones were ranked and quantified.
The Application of Strain B ased Design Methods to Achieve Cost Effective Subsea Pipelines
Authors: Walker A.C. , Williams K.J. , Wickham A.H.S.
Published: October 2008

This paper is concerned with a Joint Industry Study which has prepared criteria and analysis method for the strain based design and assessment of subsea pipelines. The study has been sponsored by six oil companies, two regulatory authorities, a design contractor and an installation contractor. ?The main study was preceded by a pilot investigation performed on behalf of the UK Health and Safety Executive. The work in the project encompasses full scale testing of a range of pipeline diameters and materials, development of finite element models and simplified formulations to evaluate the limit states of pipes. The results from the tests have been used to validate the numerical analysis method.

The procedure for the tests and details of the test specimens are described in (he paper. Some example results from the tests and analysis are presented to illustrate the approach followed in the project.

Introduction

Pipeline engineering is a rapidly evolving area of technology in which new materials and installation techniques are being developed to cope with requirements for the pipelines to operate in deep water transporting sometimes very corrosive contents at high temperatures and pressures. Allied to these technical challenges are the ever-present requirements that engineers face of designing sub-sea systems which will operate at appropriate evels of safety during a specified lifetime and can be installed and maintained at acceptable costs. Much of current design of pipelines is performed according to stress-based codes. That is, the loads applied 10 the pipe must not cause stresses, longitudinal, circumferential and combined, which exceed a specified proportion of the material yield stress. ?This approach has resulted in pipeline systems which have been successfully installed and safely operated.

In some circumstances the requirement to restrict (he stress levels means that the pipeline may incur unnecessary economic penalties during installation or operation and in some circumstances, may not be feasible. These circumstances correspond to states in which the deformation of the pipeline is completely controlled. Examples of this arebending over a stingerbending on a reel and straightener systeml bending in a J-tubeconforming to the seabed topographyoperating at high temperatures

In these cases when the pipeline deformations are controlled experience has shown that the pipe can sustain strains greater than those corresponding to the limiting stresses without loss of capacity to operate safely, Similarly, pipelines may experience damage during operation, or may have requirements for alterations of the operational conditions. In these circumstances if the pipe is assessed using the method with which they were originally designed, i.e. the stress based approach, it may show the pipe to be unacceptable for continued use. On the often hand, if the deformations are controlled the application of limiting strain criteria may confirm that in fact the pipe could be tit for purpose.
Subgouge deformations and the security of Arctic marine pipelines
Authors: Woodworth-Lynes Christopher , Nixon Derick , Geotech Nixon , Phillips Ryan , Palmer Andrew
Published: October 2008

Pipeline engineers have been concerned to protect underwater pipelines from icc masses, which can gouge 5 m and more below mudline. Their initial concern focused on a requirernent 10 avoid contact between the icc and the pipeline: if the pipeline was trenched below the maximum gouging depth below mudline, the pipeline was supposed to be safe.

It is now clear that this is not so. Very Iarge deformations occur in the soil below a gouge, so that a pipeline can he damaged even if' it is too deep for the icc to reach it. This has been demonstrated by the PRISE joint-industry project, which combines centrifuge modelling; analytical and finite element studies of gouging processes and pipeline response; and field studies of relic gouges. The results give some guidance on the necessary depth of burial, which is significantly greater than the maximum gouge depth, but this is a premilinary Study and further verification and research are neccessary.

Introduction

Large areas of the seabed in the Arctic arc heavily gouged by grounded sea icc pressure ridges. Icc gouges arc most frequent in shallow water, but extend to water depths beyond .S0 m, much further in areas where icebergs occur. Gouge may be 5 m or more deep and 50 m or more wide. Respective mapping confirms that gouging is a contemporary rather than a relic phenomenon. Straight forward calculations show that enough driving force is available the observed gouges, anti [hat icc keels can be strong enough 10 do so although a degree of smoothing occurs when a keep first contact the bottom, particularly if it is an weak(unconsolidated first-year keel).

Gouging has serious implications for subsea pipelines, An icc mass Iarge enough and strong enough 10 cut a deep gouge can damage a pipeline severely if comes into contact. A rough of the gouge force can readily be made', and can be confirmed by the modeling described Iater. A Iarge gouge requires an icc force of the order of 200 MN tonnes. This is 1000 times the pullover forces which are known not 10 damage properly-designed large North Sea pipelines when they arc struck by trawlgear. on the other hand, it is lot) times Iarger than the forces occasionally accidentally applied by anchors, which are known to cause extensive damage. While in principle it is practicable to design a protective system to withstand these huge forces, if demands a radical change in design, and the cost of the productive structure would be extremely high. until relatively recently, it was thought that a pipeline would be safe if it were buried sufficiently deep below the seafloor for icc to cross the pipeline without it.
Subsea Manifolds Optimization - The combination of Mature and New Technologies
Authors: Paulo C.A.S.
Published: October 2008

Subsea equipments can be considered nowadays a mature option for offshore field developments. In Brazil, since the first oil in Campos Basin, different concepts ranging from one atmosphere chambers to deepwater guidelineless x-mas trees, have been tested, contributing for this development. @The experience acquired during these years makes it possible to combine the proven systems to the new technologies being developed, for the design of subsea manifolds The main target is more etllciency and cost reduction. When choosing a manifold concept. a usual rule is applicable: the simpler the better.

The maturity, confidence and reliability obtained, allow the usage of resident hydraulically actuated valves, simplifying considerably the manifold arrangement. Other contributions come from: the reduction of piping bend radius allowed by the new pigs; the increased reliability of subsea instrumentation and chokes, allowing elimination of the gas-lift-test flowline, and the development of the direct vertical connection, that turns subsea tie-ins very fast and easy operations. Combining all that with the new technology of multiphase meter (to eliminate the test flowline and even the test separator on the platform), we can achieve a cost effective solution.

This paper describes the possibilities of simplifying the subsea manifolds and presents a comparison of different designs. The usage of mature technology combined with the new developments, can help the industry to make deep water developments profitable, worldwide.

Introduction

Aiming cost reduction, efficiency and reliable solutions for future deepwater developments, PETROBRAS has carried out a study for comparison of different manifold concepts to identify the potential more attractive ones. For a more realistic analysis, [he manifold was not studied as an isolated item, but, using a system approach, all the subsea components were considered trees - flowlines - connections - controls - manifold - export lines and umbilicals. @In this comparative study, mature technologies of subsea valves, chokes, controls and instrumentation were combined with the new developments of flowline connection systems and multiphase meters to achieve cost effective alternatives.

Base Case and Technical Parameters Set-Up

The base case used for this comparative work was a system composed of 8 subsea wells that produce crude oil (3000 BOPD each) during the life time of 20 years, using gas-lift as the artificial lift method. The production is commingled in a diverless guidelineless subsea manifold, located 400 m (1,312ft) away from the wellheads. The export lines (production outlet and lift gas inlet) are connected through flexible lines to the floating process unit 3.2 km (2 miles) away from the manifold, Flexible lines are also used for the subsea trees to manifoId connections. Electro-hydraulic multiplexed control system is considered.
Shasta/Mustique Subsea Equipment Platform Interface and Operability
Authors: Jefferies Andrew T. , Loegering Cory , Steib Don , Schlater Don
Published: October 2008

The economic benefits of all inclusive systems engineering approach is now recognized in the offshore industry. Nowhere is this more evident than in the area of deepwater subsea tiebacks to existing facilities. This type of development requires effectivemanagement of the interfaces between personnel on the existing facility and the new project team, the interfaces between the new subsea facilities and the existing platform, and the interface of the new operating procedures with the existing platform daily routine.

A second factor in tie economic viability of many of these projects is the need to minimize operating costs by avoiding the need fm subsea .system repair intervention, An operability analysis focusing on the subsea system and platform interface engineering was used on the Hardy projects to address the concern with the potential for interventions, With minimum operating costs as a primary goal, Hardy encouraged participation from both host platform operating groups from the outset of both projects. This cooperation was critical since both projects were planned to mow than double the throughput for both host platforms without adding platform operating personal. The approach of operator involvement also ensured a safe, reliable, and economic transition between the installation and operating phases of the developments.

INTRODUCTION

This paper describes the operability and interface management effort on the SHASTA and MUSTIQUE developments in [he Gulf of Mexico. Hardy's project management approach was apply 10 both developments, however (his paper focuses on the SHASTA development specifically for the installation and operation phase.

The SHASTA field is located in Green Canyon block 136 in approximately 1000ft of water. Hardy Oil & Gas USA inc. was the development opera[or with responsibility for the design, drilling. and installation cycles of the project. Texaco Exploration & Production INC (TEPI) took over as operator of all facilities on production start up. Equity ownership of the field is 50% TEPI, 25% Hardy, and 25% Samedan.

Subsea wells produce gas and condensate through Iwo export flowlines to the Green Canyon block 6 Texaco platform in 612 tl of water. The # 6 well is located in 860 ft of water while the # 7 well is in I(M2 R. The two wells are located 1-1/2 miles apart with the closest well (#6) being 9-1/2 miles from the platform.

The SHASTA subsea wells are controlled from the platform using a multiplexed electro-hydraulic control system. The production facilities added to the platform specifically for S1IASTA have a throughput capacity of 60MMSCFD and include dedicated provisions for flowline pigging and continuous methanol and corrosion inhibitor inject ion. Figure I illustrates the overall field arrangement.
Horizontal Subsea Trees for the Shasta Development:An Operators Perspective
Authors: Lorimer David
Published: October 2008

The Shasta project was managed by Hardy Oil and Gas and the operation handed over to Texaco after first production in November 1995. Weekly team meetings were held from May 199-t to October 1995. These meetings covered the Engineering and Construction phases of the project. Hardy created a unique project team environment which provided an open forum for group discussion. The Shasta subsea team consisted of a Hardy team leader, a Texaco engineer, a Texaco production supervisor and representatives from contractors and manufacturers. Team members were chosen on a partnering basis and not via a formal bidding process. It was decided that a Horizontal tree system should be used for the project (reference Figure 1). This paper describes why and how this decision was made, how the system was put together and how it has worked to date, The Shasta tree is an cmbodiment of team contributions to improvements in the following areas;SafetyReliabilityControls interfaceEase of installationEase of interventionEnvironmental protectionSeal designWireline plug designSystcrn integrationOperability

Introduction

The Shasta field development consists of two subsea wells tied back to Texaco's Green Canyon 6 platform, ?Kilauea'. The offset to the first well is approximately nine miles with an additional mile and a half to the second well, Water depths are 84(M and 104t)ft respectively, The wells arc electrohydraulically controlled by a multiplexed umbilical tied into the G.C. 6 platform Control of the wells is also relayed to the Texaco New Orleans office via the Texaco Stormac SCADA system which allows production to continue in the event of Hurricane evacuation of G.C. 6.

An environment of partnership, team-work and open mindedness on the part of the oil companies and the subsea contractors was essential to the success of the project. All project team members demonstrated a willingness to adopt common goals and strive to overcome traditional technical, logistical and commercial obstacles in new ways. Each contributing team member strove to break new ground and prove their abilities to meet the needs of an ever more demanding subsea environment. The result of this open team approach was the synergy of various abilities, levels of experience and expertise to develop a cost effective subsea production system. Ease of installation and operational flexibility were major considerations during the design stages.

Why a Horizontal Tree?

In order to ensure that the appropriate subsea tree configuration was selected for Shasta, some three months were spent discussing various designs with a number of subsea wellhead manufacturers. The recommendation to use a horizontal tree was made in July 1995, and a thorough project team and partner review was conducted, An extensive Hazop was then conducted to establish operational viability.