bluuebunny/crossref_metadata_2025 huggingface dataset:
Techniques and Experiences Using Exploration 3D Seismic Data to Map Drilling Hazards
Authors: Heggland R. , Nygaard E. , Gallagher J.W.
Published: October 2008

This paper will review Statoil's experiences and techniques applied to the mapping of drilling hazards by using exploration 3D seismic data. During the period since first implementing thus approach to shallow gas evaluations, in 1989, the methodology has continued to develop. Attribute mapping techniques have improved the identification of shallow gas and shallow gm traps. Seabed topography may also be mapped using 3D data and attribute analysis. The observation of gas migration through the sediments has significance for the understanding of potential shallow gas accumulations. and different attributes are used to aid in identifying possible gas migration paths. The use of 3D data, modern interpretation techniques and correlation to an extensive well data base, covered by the 3D data, has led to a better understanding of the shallow geology and result in rapid and precise geohazards evaluations. Costs are reduced by minimizing the standard site survey acquisition programmed. and the high degree of accuracy of the predictions has consequences for well planning. leading to safer and less expensive drilling.

Introduction

The technique of using exploration 3D seismic data for detection of shallow gas was pioneered by Statoil during a shallow gas project lasting from 1986 to 1989'. Shallow gas evaluation based on 3D data has since been a standard procedure in Statoil, The technique has, to date, been performed for more than 50 Iocation, i.e. exploration wells, production wells and platform sites, About 150 wells have been used as correlation wells, Early results from Statoil soon encouraged other oil companies to try the same methods, which has had a major impact for site survey contractors who have since had to modify their services offered to accommodate thechanging technology. Later, the Norwegian authorities changed their requirements for shallow gas investigations accordingly to include the use of exploration 3D seismic data where available. The most significant aspect of using 3D data to map drilling hazards is the use of horizontal displays (time slices attribute maps), leading to a better understanding of shallow gas settings and greater reliability of predictions which SUICCimplemented has had an accuracy close to 100 %0. Cost savings by reducing the site survey programmes arc significant. In addition considerable amounts arc saved in the drilling operations due to the accuracy of the predictions which has a direct impact on well planning.

Interpretation Techniques

The method proposed by Gallagher et al,, 1989' and 199 I', was to perform shallow gas evaluations using exploration 3D data loaded to an interpretation station. The most important advantage of this method was the possibility of using time slices. which recvcled shallow gas traps, in particular buried iceberg ploughmarks.
Multi Channel FM Reflection Profiler for Buried Pipeline Surveying
Authors: Schock S.G. , LeBlanc L.R.
Published: October 2008

A towed multi-channel FM acoustic reflection profiler has been developed for locating and generating images of buried objects. One significant application of this sonar is buried pipeline surveying. The multi-channel reflection profiler uses 16 line arrays mounted in a towed vehicle to determined the position and burial depth of an 18 inch steel pipe filled with concrete buried under 1.5 meters of sand. This sonar will allow a survey vessel to continuously track a buried pipeline providing a continuous record of pipe burial depth and position.

Introduction

Locating buried objects under the seafloor is a difficult problem because sediments have surface and volume scattering coefficients that are three orders of magnitude greater than that for water and, consequently, generate acoustic scattering noise that is usually greater than the reflection amplitudes of buried targets. Single channel profilers are practically unusable for finding single objects in sandy seabeds because they have to be towed within a couple of meters of the seabed, can only effectively cover a narrow swath (e.g., less than 2 meters), andprovide little information about object shape and size. Recent experiments using a single channel FM profiler for finding ordnance buried less than a meter in sand show that the beamwidth must be less than 30 degrees and the vehicle tow height must be about a meter above the seafloor in order to reliably detect the ordnance shells.

Buried pipeline surveying is not as difficult as finding buried objects that have a finite length, because towed vehicle positioning is not as critical; the towed sonar vehicle will always pass directly over the pipeline during a crossing. Usually a sonar with a wide along-track beamwidth and a narrow across- track beamwidth is used to find buried pipelines. Survey vessels usually measure the burial depth of pipelines by performing 90 degree crossings of the pipe at selected locations along the pipeline. As the sonar approaches the pipe during each crossing, the two way time travel of the pipeline echo decreases until the sonar is directly over the pipeline. Then the time travel increases as the slant range from the sonar to the pipeline increases. On a paper chart the pipeline echo forms a hyperbola which has a peak at the location where the profiler was directly above the pipeline. Because the crossings must be approximately perpendicular to the pipeline to keep the normal incidence component of the pipeline in the main lobe of the sonar, a pipeline survey can be costly in terms of time and can not provide a continuous record of pipeline burial depth.

Some sediments which have high scattering coefficients due to gas bubbles, shell or other in homogeneities prevent the use of conventional pipeline tracking sonars. In these environments, EM techniques are commonly used to measure pipeline burial depth under the seabed.
Planing and Development of South Pass Block 47 Drilling and Production Platform
Authors: Brokmeyer James E.
Published: October 2008

In February and March of 1993, Energy Development Corporation (EDC) drilled discovery wells in South Pass Blocks 34 and 47 (SP 34 and SP 47). Evaluation of the logs and geologic data indicated reservoirs small in size relative to the water depth and seafloor conditions in the area. EDC'S previous knowledge and experience with the soil condition in the area immediately signaled a very low probability of commercial development of these reservoirs if anything other than a conventional type platform would be required. This paper is a summary of the tasks undertaken to find a way to be able to develop the reserves economically with environmental and safety concerns a high priority.

Introduction

EDC'S initial exploration plans in this area included a geologic prospect in SP 34 and a separate feature in SP 47. It was known through seismic interpretation that the feature in SP 47 would likely be approximately I/3 the size of SP 34 reserves, Therefore, the initial plans called for drilling a discovery well in SP 34 that could be salvaged and utilized as a producing well should SP 47 be proven uneconomic, and an expendable well in SP 47 to test the reservoir. Upon the drilling of the first wells, the final assessment yielded the predicted results of a sizable reservoir in SP 34 and a reservoir approximately 1/3 the size of SP 34 in Block 47.

Planing

Drilling of the wells in SP 34 and 47 resulted in providing the critical information that was necessary to both size the production facilities, but more importantly dictate a maximum amount of capital that could be expended, and yet yield an acceptable rate of return for EDC. At this juncture, several options were available to develop the reserves.

Option 1.

Set a conventional platform at the drill site in SP 34 and abandon the reserves in SP 47 as uneconomic.

Option 2.

Pick a platform site suitable to drill directional wells to develop both Blocks.

Option 3.

Set a conventional platform in SP 34, install a subsea caisson wellhead in SP 47 and lay a flowline to the SP 34 platform.

Option 4.

Install a mud slide design platform at a common site to develop Blocks 34 and 47.

Development

In the case of Option 4, cost estimates in the range of $25,000,000 immediately excluded this as an option. If no other plan could work, the reserves would be uneconomic to develop. It was therefore decided that additional detailed soil data would be required in order to determine if there would be any feasibility to either Option 2 or Option 3. EDC was not prepared at this time to simply write off the reserves in Block 47.
A Cost Effective Newbuild Semisubmersible Floating Production Platform
Authors: D'Souza Richad , Cody Alan , Bauer Tom
Published: October 2008

Semisubmersibie based Floating Production systems (FPS) have been extensively used in offshore field developments worldwide. Most have been converted from existing drilling semisubmersibies. Faced with a rapidly dwindling inventory of existing platforms to convert, the industry near cost competitive new build units. this paper presents the principles and development of just such a platform. It will be demonstrated that this new build platform is cost and schedule competitive with a conversion for a deepwater Gulf of Mexico development.

INTRODUCTION

Monohull or semisubmersible based FPSS converted from existing vessels, featuring low capital mat and cycle times to first oil, permit operators to economically develop small to medium sized fields in deepwater or remote regions [1,2]. Historically, field developments employing floating production systems were focused mainly in Brazil, West Africa the Far East and Australia. More recently, Operators in the U.K. and Norwegian sectors of the North Sea and Atlantic Frontier have accelerated the use of floating production systems to exploit their more remote, deepwater or marginal fields. This increase has been fueled by the growing confident and coat reductions in subsea and riser systems [3]. A case point is the development of the Njord field in the Norwegian North Sea by Norsk Hydro in about 1000 ft. of water by subsea tiebacks to a 45,000 tonne newbuild floating drilling production unit the Aker P45[4].

Semisubmersible based production or drilling and production units, in combination with subsea wells, have been used worldwide to commercially develop small to medium fields (50 to 100 million barrel reserves) in a wide range of water depth and environments [5]. With the exception of 3 newbuild units, most have been converted from second or third generation semisubmersible Mobile Offshore Drilling Units (MODUS) The availability of suitable candidates for conversion was never a problem, until recently. The soaring demand for deepwater exploratory and appraisal drilling has depleted the pool of candidate rigs for conversion and also raised acquisition prices.

There is a perception that a newbuild unit will cost a lot more and will have a significantly greater cycle time to first oil than a conversion. It is the intent of this paper to clearly demonstrate that a newbuild production semisubmersible, adapted from and employing the principles embodied in the Aker P-45 floating production unit can be eonunereially competitive with a converted semisubmersible FPS for a deepwater GOM application.

DESIGN APPROACH

Figure 1 illustrates the fimdarnental departure from the traditional approach to building semisubmersibles, that will achieve the design objectives of low cost and accelerated schedule for a newbuild FPS.
A Semisubmersible type Drilling, Early Production and Testing System with 100,000 bbl Storage for Deepwater
Authors: Nakamura Masahiro , Yokokura Kozo , Nakamura Arata
Published: October 2008

Deepwater petroleum development is increasing throughout the world. Complete evaluation of deepwater oil fields prior to development is extremely important but difficult due to harsh conditions and deepwater. Extended well testing and early production of a field will allow complete evaluation, reducing risk prior to long term commitments. Conceptual design andstudies for a semisubmersible type deepwater drilling, early production and testing system with 100,000 bbl storage (DEPTS) that will allow this have been completed. Needs analysis were performed and several potential concepts compared. Sizing and costing of the semisubmersible unit, mooring, and riser systems as well as selection of the drilling, production, and storage units were carried out. The unique aspect of the system is that the combination of drilling, production facilities, and storage on the same vessel will a How the system to be applied across the early phases of offshore oil field development from drilling to early production. With storage integrated into the vessel, oil production can continue in the most extreme conditions. The system's intended operational area will be the deepwater fields of Asia and Oceania. Studies have been carried out showing the technical and economic feasibility of the system in deepwater up to 2,000 m.

Introduction

The relentless trend of hydrocarbon exploration and development to deeper waters shows no sign of abating in the near future. Developments in 300m water depth are common, with the current deepest development being at 1027 m in the Campus Basin. Deepwater in the 2,000 m range is being explored, with the immediate question being which technologies are most appropriate for which fields. The large amounts of capital required for deepwater exploitation can lead to increased risk for the operators, necessitating measures to decrease risk, decrease overall development cost, or both.

The use of extended well tests (EWT) or easy production systems (EPS) can be used for reducing risk, optimizing full development design, and improving cash flow. For the purposes of this study, the following definitions were used:EWT: An EWT is used only to obtain production data and reservoir characteristics.EPS: An EPS is used to obtain early cash flow and increase a project's economic viability.

The usage of EWT or EPS can improve a project's overall viability in the following ways:The use of an EWT will reduce uncertainties about reservoir characteristic increasing the reliability of project economic forecasts.With better evaluation of reservoir production characteristics, the most appropriate exploitation concept may be developed and optimized, with possible corresponding decreases in total development cost and initial capital cost outlay.
Operational Experience of FPSO Uisge Germ
Authors: van Voorst O.
Published: October 2008

Blue water was awarded a contract by Amerada Hess Limited to provide production services for the Fife Fieids the North Sea using an FPSO based on a converted tanker. The contract required Blue water to provide the production services from the wellhead to the refinery, The construction period of less than 17 months resulted in first oil in August 1995, Preparing for the operational phase and actual operation of the installation after first oil were also part of the contract. This paper briefly describes the construction phase, the preparatory phase for operations and the first 4.5 months of opera tons up to December 1995. The paper concludes that a wellhead to refinery contract is a feasible and commerciality attractive solution for both oil company and FPSO contractor. The Fife Field could not have been developed if this contracting strategy had not been used, as after depletion of the Fife Field the Usage Germ will be available to be utilized on other fields.

1, Project Description

In March 1994 Blue water Offshore Production System assigned a contract with Amerada Hess Limited to provide a production service from Wellhead to Refinery. Amerada Hess Limited required this service to develop the Fife Field, located in blocks 31/26a, 31/27a, 39/1 and 39/2 on the UK continental shelf in the central North Sea.

In order to fulfill the requirements of the contract Blue wateracquired an existing 99.300 DWT product tanker. We converted the vessel to an FPSO, installed process equipment and mooring systems, and completed the conversion scope in less than 17 months, Contractual payments commenced on first oil production and include a provision for keeping the Installation operational which is related to actual uptime achieved. Furthermore, the full offshore manning as well as an Aberdeen onshore support base are being provided by Blue water during the operational phase.

The contract places all risks related to the reservo r performance with Amerada Hess Limited and includes a minimum duration of 4 years. These issues ensured that Blue water has been able to take a completion risk on the construction phase and an uptime risk on the operational phase. These criteria meant a significant challenge for Blue water's project team due to the fact that this was the first contract of this type. A passively moored FPSO based on an existing tanker had never before been utilized in the North Sea environment,

Due to the contractual arrangements and Blue water's responsibilities towards the UK authorities, Blue water is Safety Case Duty Holder and Operator of the Fixed Offshore Installation while Amerada Hess Limited is the Field License Holder,

Due to limited anticipated producible reserves in the Fife Field and a possibility of other minor producible reservoirs in the same general area, contractual as well as hardware facilities have been foreseen to incorporate the tie-in of future wells to the same installation.
New Data on the Fatigue and Ultimate Limit State of Grouted Tubular Joints
Authors: Morahan D.J. , van Foeken R.J. , Lalani M. , Wardenier J.
Published: October 2008

A Joint industry project (JIP) commenced in 1993'" to develop a design manual for tubular joints which are strengthened or repaired through chord grout-filling. This project has been funded by five oil companies and two regulatory bodies. The project has comprised the conduct of over 150 Stress Concentration Factor (SCF) and ultimate load tests on large scale as-welded and grounded tubular joints. Separate data capture studies, including capture of data on double-skin grout reinforced joints, have been conducted, together with studies on offshore deployment, to ensure that complete chord grout-filling is achieved for all practical scenarios.

The primary reason for carrying out this project has been an industry-wide recognition that chord grout-tilling represents an extremely cost-effective and technically-efficient method to strengthen or repair tubular joints. Further, it has been Recognized that double-skin joints (e.g. pile through leg with anisettes grout-tilled) are often present in structures and the resulting enhanced strength and fatigue characteristics should be exploit+ to permit more efficient new platform designs or better estimation of joint performance for existing installations. Although API RP2A(?' permits the use of grouted joints, little guidance is provided, reflecting the lack of data and information in this area. This project has been carried out to generate a significant amount of new data/information, leading to the creation of a design manual for grouted, joint.

Introduction

Grout-tilling of chord members to enhance the static strength and fatigue endurance of tubular joints is recognized as perhaps the most cost-effective and technically efficient solution available for the strengthening, modification and repair of offshore ions. However, there are significant gaps in the data from the standpoint of present-day potential applications, i.e. the range of geometries, configurations, load cases and conditions for which chord grout-filling may be considered relevant and appropriate. Therefore, to generate new data applicable to appropriate strengthening or repair events, a test matrix was selected on the basis of likely strengthening and/or repair scenarios. To enable the measurement of Strain Concentration Factors (SNCFS) for all load types for each specimen, a specialized test rig was designed to facilitate loading in the four loading modes. A sophisticated test rig was designed to enable rapid execution of test measurements in all loading conditions without the need to remove or re-orientate each specimen.

Review of Existing Guidance

The provisions of major design codes on any aspect of grouted joints are limited. API RP2AC', HSE Guidance Notes('), NPD'4' and DNV(s' all state that capacity may be established by testing and/rrr analytical methods. The HSE Gui&nce Notes specifically allows the use of grout filling for joints on existing installations.
Operating Procedures - Preliminary Results of a Safety and Environmental Management Program (SEMP) Case Study Sponsored by the DOE and MMS
Authors: Bresler Richard A. , Tibbetts Owen D. , Von Antz Gerald
Published: October 2008

On June30, 1994, the MMS published a Federal Register notice requesting that industry voluntarily adopt API RP 75 (SEMP). Under the SEMP program, offshore producers would be responsible for identifying potential hazards in the design, construction and operation of drilling and production platforms and developing specific approaches to reduce the occurrence of accidents.

Many smaller and mid-size independent producers have raised questions over the costs and methods for implementing SEMP. The DOE and MMS determined that a carefully documented case study would answer many of the producers' questions. The results of the study would be oriented specifically to small- and mid-size companies, so independent producers would be much more willing to invest the time and resources to adapt theRP 75 procedures to their own operations. As a result, the DOE and MMS have entered into a 30-month study with Taylor Energy Company (TEC) and Paragon Engineering Services (Paragon) to develop a Safety and Environmental Management Plan (SEMP). This program is intended to demonstrate how small- to mid-size companies can effectively and inexpensively develop a SEMP in accordance with API RP 75.

This paper will discuss the preliminary findings associated with the Taylor Energy Company/DOE SEMP case study. Specifically, the development of operating procedures which meet the intent and spirit of SEMP without the traditional high cost typically associated with 'engineered operations manuals' will be discuss.

Introduction

Section 5 of SEMP is titled 'Operating Procedures' and is written almost identically to the Operating Procedures section in API 750, Management of Process Hazards. This fact is important to understand because API 750 was developed for refineries, petrochemical operations, and major onshore processing facilities. API 750 is not directly applicable to most OCS platforms. Since the goal of this SEMP project is to develop a 'cost-effective' method for small and mid-sized independents, this paper will provide thoughts on how to achieve the 'spirit' of SEMP without incurring the paperwork burdens of a complex facility operation.

Overview of Section 5- SEMP Operating Procedure

Section 5.2.a requires that the written procedures include the job title and reporting relationship of the person or persons responsible for each of the facility's operating areas.

This goal can be accomplished with a simple organization chart for moat small and mid-sized independents. In many cases, such a chart already exists. Section 5.2.a offers no pertinent benefit to the small independent because, in the majority of cases, only one operator (and a helper or roustabout) is responsible for an entire platform and perhaps one or more unmanned facilities as well. The small independents' organizational structure is usually very flat, unlike that of a large organization typically associated with a refinery or petrochemical complex.
DP-PS: A Safety Program for DP Operations
Authors: Cordeiro André , Pashoalin Roberto , Fartes Evandro
Published: October 2008

As PETROBRAS develops its deepwater projects. more and more DP units are used on different applications like drilling. completion, intervention and pipeline handling, The increasing complexity of the operations has been considered in a program entitled 'DP-PS' (Safety Program For Dynamic Positioning Operations) in order to minimize the risks of failures which could lead to serious accidents on subsea and surface installations as well as to the DP vessels. This paper briefly presents the DP-PS. consisted of a group of related projects considering different aspects of DP operations, like: Vessels Incidents Databank, Emergency Disconnection Procedures. Risk Comparison, DGPS (Differential Global Positioning System) application, Well Control Equipment and Standard Procedures. Testing Programs and Guidelines for DP Operations. The high number of DP contractors operating in Brazil and the atmosphere of cooperation in which the program has been developed was a key factor for its success, As a result, the number of DP incidents has remarkably decrease.

Introduction

Since it is a quite new activity all over the world there are several concerns related to production in deepwater, ranging from tedmology and related costs to lack of adequate material and equipment resourees, Among them, a key point is the must of conducting the operations un&r a reasonable safety level. This issue turned to be more important considering the characteristics of DP (Dynmnic Positioning) rigs and its application on development tasks which should occur inside restricted areas, different from normally isolated exploration wells.

In December 84 the first program in Campos Basin. DP unit started an exploratory Since then, the DP fleet has increased and for next year eleven units are planned to be simultaneously working. mainly involved on the development plan of Marlin and other deepwater fields.

Some particular initiatives have been taken since that beginning, Among these initiatives there was a particular care about disconnection procedures and well control policies.

Anticipating the new development phase, PETROBRAS established an integrated program which should verify the main safety aspects related to DP equipment application named DP-PS (In Portuguese: DP- Programa de Seguranca).

Program build-up

In 1992, a group of DP rigs arrived in Campos Basin, stepping up to five the number of DP contractors. Brazilian waters became a unique play where so many DP rigs were operating at the same time, bringing the possibility of speeding up the development of operational know-how.

A group of experienced skills in deepwater operations were put together to raise ideas that could enhance safety, A brainstorm session took place and. in sequence, some principles were applied to the proposed ideas: Firstly, the program should focus on important matters from the point of view of the man on board the unit.
Construction of a Large Underwater Acoustic Array
Authors: Zueck Robert F. , Brackett Ron L. , Smith Anthony P. , Shields David R.
Published: October 2008

Recently installed in Lake Penal Oreille, Idaho, the acoustic arrays for the Intermediate Scale Measurement System involved an extensive effort in construction planning, Composed of many inter-connected structural lines, electrical cables, anchors, buoys, sheaves, hydrophones and acoustic transducers, the array was assembled underwater one component at a time. Because each component had to be placed in a precise position, the installation effort required a technically advanced positioning system, a specially built project barge, and unique deployment methods. Many of these installation procedures are applicable to installation of other types of deep-water structures.

Project Background

Situated in Lake Penal Oreille, Idaho, the Intermediate Scale Measurement System (ISMS) provides high quality measurements of the structural acoustic response of large-scale submarine models in a controlled environment 1. Fig. 1 shows the Near-Field Array (NFA) of the ISMS. The NFA consists of the following system components, located in the 1,200-feet (366- meters) deep lake:Transmit Array (TA): A vertical plane of projectors for transmitting an acoustic signal.Target Model Haul-Down (TMH); A mechanism for handling a buoyant submarine model.Receive Array (RA): A horizontal ring of hydrophones for measuring the acoustic signature.l N-Array (NA): A small set of hydrophones for measuring the incident acoustic signal.

All acoustic components and the submarine model are in a horizontal plane at approximately mid-depth in the lake. The TA projectors hang below a rigid buoyant truss structure, Two anchor lines at each end of the TA truss hold the truss approximately 64 feet (20 meters) below the lake surface. Located on shore approximately 2.5 miles (4 km) from the NFA site, winches haul the buoyant submarine model underwater. A network of underwater electrical and fiber-optic cables connects the acoustic arrays to shore. Of the NFA components, the RA provided the most challenging installation effort. Thus in this paper, we shall focus on the RA structure.

Receive Array (RA). The receive array consists of 12 segments of hydrophones, totaling 158 hydrophones. When connected end to end, these segments form an oblong ring surrounding the submarine model. The longest hydrophone segment is 282 feet (86 meters) long. A structural node at each end of each segment holds each hydrophone segment in place. Each node is 602 feet (183 meters) above the lake bottom. Electrical cables carry acoustic information from each end of each RA segment to the TMH and then on to shore.

A buoy near the water surface and three anchors at the lake bottom hold each node in place. Each node buoy is a 6-foot (1.8-meter) diameter syntactic foam sphere. Each anchor is an 8-foot (2.4-meter) square steel 'cookie-cutter,' A 0.5-inch (1 .25- cm) diameter parallel-fiber aramid (Kevlar) line connects each anchor to each node. End sections of wire rope provide for precise final adjustments in length given as-installed anchor locations.
Phillips Seastar Project: A Teamwork Approach
Authors: Upchurch John L.
Published: October 2008

In order to better meet the challenges associated with downsizing and because of the ongoing need to control costs and accelerate project development many companies are trying new and different strategies in managing projects. For the Sea star Project, Phillips adopted a total team approach. The goal of this approach was to develop a win/win attitude for all of the personnel (Phillips, Engineering Contractor and Equipment Vendors) involved in the project. By bringing all the personnel together and focusing on project success it wasthought that costs could be better controlled and that the development schedule could be accelerated.

Project Overview

The Sea star Project is a two well subsea development located in Garden Banks Blocks 70 & 71 approximately 120 miles south of Cameron Louisiana (figure 1). The water depth at the well location is approximately 750 feet and the blocks arc 12- 14 miles from the closest existing platform. These blocks were originally leased by Phillips Petroleum Company, ct al. in 1987. Phillips was not the original operator of these blocks. Two wells were initially drilled (one in each block) but, the reserves were not sufficient to justify development. Phillips took over operator ship in 1992 and drilled Garden Banks Block 7 I #2, which discovered 349 feet of net gas pay in April 1993. Following a successful drill stem test on GB 71 #2 drilling was started on an appraisal well and work beganon a feasibility study to define development options.

Phillips Philosophy/Goals

Phillips project development goal is a safe, customer driven, timely and cost effective development. For various reasons, Phillips had made the strategic decision to not maintain an in house staff of technical project personnel and it was realized that an outside engineering company would need to be contracted for the project.

Phillips was an early pioneer in subsea development and had installed one of the first piloted control systems offshore California, However, Phillips had not installed a domestic subsea development since California (1980) and all of Phillips' international subsea work was in shallower water depths and had shorter offsets. None of Phillips active offshore platform developments were in water this deep either. Lack of experience and the need to control costs resulted in a desire to use as much proven technology as possible in the development. It was felt that the industry had proven technology for these water depths and focusing on proven technology would reduce the project risk; technical, schedule and cost.

Feasibility

A feasibility team was established in April 1993, immediately following the testing of Garden Banks 71 #2, with personnel from Operations and from the Corporate Engineering staff. The purpose of this phase of the project was to identify and review development options so that a final decision on development could be made when Garden Banks 70 #2 was completed.
Experience with Flexible Pipe in Sour Service Environment : A Case Study (The Arabian Gulf)
Authors: Al-Maslamani Moh'd J.
Published: October 2008

The suitability of a flexible pipe was evaluated on a trial basis for a lift gas line in a sour oil field in the State of Qatar, in the Arabian Gulf. Flexible pipes have been successfully used in the oil and gas industries for transportation of methanol, benzene and gas condensates in wet sweet environment at temperatures of Uplo 80°C. However, there is little or no information available as to its corrosion resistance in sour service wells containing 6% co2with 3% mole H2S and at moderate temperatures. The present experience with a flexible pipe in the gas field of Qatar has shown that under sour service conditions, the Iayered, composite material can suffer severe degradation leading to failure. A detailed inspection and failure analysis of the flexible pipe forms the basis of this paper, The failure demonstrates the significant effects of stress Ievel, environmental aggressiveness, and Iocalised hard zones in promoting Sulphide Stress Cracking (SSC). Permeability of the sour gas through the composite layer of the flexible pipe resulted in varying degree of sulphide attack and hydrogen embrittlement depending on the susceptibility of the multi Iayeredmaterial.

Introduction

The application of flexible pipe for pipelines and risers is increasing due 10its low installation costs. Flexible pipes have been used123 in oil and water service with considerable rneasure of success. These pipes have been found suitable for transportation of water and methanol intermittently, and gas condensate containing abut 40% 0bcflane in the Wet sweet gas at temperatures of up to 80°C. However, there are limited operating experience available in the oil and gas industry with flexible pipes in both wet gas and sour gas services. The structure of the flexible pipe is illustrated schematically in Figure (l), and the various layers present are :Polyethylene (HOPE) external sheathFabric tapeCrosswound first armourFlat spiral second armoutZeta spiral reinforcementIntermediate pressure Rilsan sheathIntcdoeked stainless steel type 316L carcass

The pressure and tensile armour wires are encapsulated between an outer (polyethane sheath) and an inner (Rilsan sheath) polymer barrier. The armour wires should remain unaffected by both sea water and the gases (CH H2Sand C02) as long as the polymer barriers are intact. A typical performance characteristic of the flexible pipe is the permeability to gases. All polymers are to some extent permcable4 to gases, and the amount of permeation depends on the type of gas and the type of polymer. In flexible pipe, permeability may allow gases to pass through the primary fluid or gas-containing layer and build-up in the interplay region. The diffusion of corrosive gases into the annulus means that the armour wires are exposed to a corrosive environment.
Problems of Deep Drilling in Abnormally Pressured Zones of the Kara Sea Continental Shelf
Authors: Simonov V.I.
Published: October 2008

There are discussed results of drilling operations in shelf hydrocarbonareas of the Far North of Tyumen Region (Kharassaveiskaya, Bovanenkovskaya andKrusenshternskaya ones) and on the Bely Island. The author describes equipmentand technologies used, problems arising in the process of operations andpossible ways of solving them. Application of the results discussed in thereport seems rather attractive in connection with possible realization of jointprojects on development of the mentioned areas. Thus, company Amoco Eurasiaplans to participate in development of Bovanenkovskoye and Novoportovskoyefields. Well planning for Amoco has been done by specialists ofZapSibBurNIPI.

Experience of Russian drilling companies in Yamal area (Far North of TyumenRegion) has proved that well planning for shelf areas requires specialattention as drilling-in both overpressured zones (Bovanenkovskoye field) andunderpressured ones (Novoportovskoye field) is done actually in balance. Thereare investigated reasons for such drilling problems as kicks and lostcirculation. Taking them into consideration will help to decrease considerablythe cost of well drilling in shelf areas.

Introduction

Field studies in the process of drilling on the Kara Sea shore revealed thatin deep wells lost circulation takes place first of all problems and later, asthe result of considerable mud losses and fast decrease of dynamic level in thehole, it turns into oil or gas kick. It appeared that because of revealedregularities in the geological section of most areas studied it is impossibleto avoid problems just controlling mud density according to preliminary workedout scheme. Due to lack of ideas about the reasons for drilling problems andconsiderable divergence between theoretical data and actual results of drillingin abnormally pressured zones there appeared a necessity to perform on-siteexperiments and to develop on the basis of a rheological model a new theory offracture appearing and closing in rock while drilling which should take intoaccount effect of different stresses in a hydrodynamic system.
Twenty-seven Year Old Jack-up Converted to a MOPU in 122 Days
Authors: Childers Mark A. , Spottswood Rick , Lovaas Wes
Published: October 2008

The conversion of the 27-year-old jack up MODU Gulftide to a Mobile Offshore Production Unit (MOPU) was accomplished on a VERY fast-track schedule at a U. S. Gulf Coast shipyard. The reactivation of the long-term stacked rig, its conversion, mobilization to West Africa and installation were accomplished in a period of less than six months during the spring and summer of 1995. This paper outlines the requirements for this type of conversion process, reviews the permitting, classification, flagging and certification involved, and describes the principal activities and work scope in detail associated with the conversion project, dry-tow mobilization and installation. The general approaches taken to this conversion and the project management techniques applied to it proved highly successful and are suitable for application to a wide range of similar projects.

Introduction And Objective

The Block CI- 11 Field 60 miles west of Abidjan, Ivory Coast, and 8.5 miles offshore first yielded an oil discovery in 1980 that by itself was uneconomic. In December 1993 UMC Petroleum Corp. discovered gas in this remote block and revived the initial oil prospect with another well in March 1994. W the Ivorian government anxious to use the gas by pipeline to fuel an electric power plant, UMC convinced the government that it could deliver gas to the power plant by October 1995, despite the fact that a competing operator had gas in another field to the east. With the obligation to meet the October 1995 gas delivery, an extremely fast-tract scenario was put in place for the total field development, in which a MOPU was to be the Central Production Facility (CPF) receiving well fluids from three caissons. A driving consideration for the overall plan was the lack ofconstruction and oilfield type infrastructure in the area. Figure I shows the general field layout, with Lion 'A' in 235-feet water depth (WD). Lion 'A' and 'B' are predominantly oil, while Panthere is the gas producer.

With a sense of urgency, UMC started design work in May 1994. In the Fall of 1994, UMC anticipated that early production could be achieved via a temporary FPSO tanker arrangement. This was scheduled to start minimal oil production in April 1995. The 58,000-DWT tanker Red Teal was modified as a Floating Storage and Offloading (FSO) unit with some processing capability. A CALM buoy was installed, and the planned oil production from the Lion 'A' was initiated into the Red Teal on schedule during April.

With the design of the MOPS processing equipment proceeding, procurement of long lead production vessels and structure started in August 1994. Initially, the process modules were sized to fit a 250-feet water depth slot-type, mat jack up; however, due to technical and commercial considerations it became apparent in the fall of 1994 that a change to a deepwater independent leg jack up was advantageous, The change of rig design could have had a major impact on the overall schedule since the MOPS was the critical path item.
A Knowledge Based S stem for Economic Analysis and Risk Assessment of Subsea Development z cenarios for Small Oilfields in the North Sea
Authors: Dyer N.J. , Ford J.T. , Tweedie A.
Published: October 2008

The decision to develop a small (C 100 mmbbls) oilfield in the UK sector of the Central/Northern North Sea requires a careful assessment of all aspects of the field development plan:l the reservoir model (reserves and production profile)capital and operating costs, andl the current economic climate (oil price, interest rates, tax regime etc)

This paper describes the development of a knowledge based software package that allows a 'quick look' assessment of the overall economics and risk profile associated with the development of small oilfields in this region. It is a modular system that uses a cost database, cost adjustment algorithms, cash flow analysis engine and simulation procedures to integrate and analyse the impact of reservoir and production characteristics, costs (capex and opex) and economic factors on the decision to develop such a field.

The production system configurations considered by the system are:an unmanned wellhead platform tied back to a third party platform for fluid processing/export,an FPSO with oil export via a shuttle tanker and gas export via a tie-in to the existing North Sea gas pipeline infrastructure, anda straight tie-back from a group of subsea wells to a third party platform for fluid processing/export.

INTRODUCTION

It is generally agreed within the industry that it is extremely difficult to make generalised cost comparisons between alternative field development strategies. This is because the field characteristics vary so widely and have such a large and complex impact on the cost of development, and subsequent financial returns from the project. The software system described in this paper is designed to assist the engineer in this task.

The region selected for analysis was the central and northern sectors of the UK sector of the North Sea. As of March 1995 (ref. I) this region has around 8.3 billion barrels of remainingrecoverable reserves. Of this total, 2.5 billion barrels are associated with fields that are either under development now or probably will be developed in the next 3 to 4 years. Unfortunately the majority of the undeveloped fields are quite small (typically around 30–40 million barrels) and geologically complex.

System Architecture. The overall structure of the package is shown in Figure 1. The core of the system is the cashflow analysis 'engine'. This is a formatted spreadsheet whichallows a cashflow profile, NPV, NPVI and IRR for the project to be computed. This output is generated from the capex (with abandonment costs), opex, field production profile, and the appropriate tax rules and macroeconomic conditions, defined by the user. The spreadsheet is subsequently used to undertake sensitivity analysis, and generate spider diagrams for defined variables, and to allow Monte Carlo simulation for economic risk assessment.
Liuhua 11-1 Development- New Pipeline Technologies for Diverless Connections
Authors: Bludworth Charles K. , Ming Chen , Paull B. Mark , Gates Steve , Manuel William S. , Hervey Donald G.
Published: October 2008

This paper provides an overview of the Liuhua infield production and test pipelines, focuses on new technologies used to tie the pipelines into a subsea manifold, and reviews the basis for selection of flexible pipe in preference to steel pipelines.

The infield pipelines consist of two 13.5 -in.-ID flexible pipes for production and one 6. O-in.-ID flexible pipe for well test. Each pipeline riser is approximately 10,300 ft (3, 130 m) long and runs from the subsea manifold below the FPS, Nanhai Tiao Zhan, to the FPSO tanker, Nanhai Sheng Li.

The technologies used to tie the pipelines into the subsea manifold involved:A transition tie-in base into which the flexible pipe was pulled using ROV-assisted tooling to make up the first end connectorA rigid pipe long jumper from the manifold to the tie-in baseThe survey and measurement tools to set up the jumper welding jigs

Each new pipeline tie-in technology was proven through field tests of actual components before completion of manufacturing and installation.

Flexible vs. Rigid Pipelines

An overview of the manifold-to-pipeline system is provided in Fig. 1. Amoco uses two subsea connection techniques for the Liuhua subsea connection system. To understand how this occurred, a brief history on the Liuhua pipelines is presented. A more detailed discussion of the history and economics of the flexible pipeline selection has been presented previously (Refs. 1 and 2).

During the defining stage, the Liuhua pipeline system consisted of three pipelines - two production and one test. The pipelines were to be of all-steel construction, fabricated either onshore or in shallow water and towed to site prior to the arrival of the vessels. Once the FPS was on site, the pipelines and manifold would be connected via a long jumper that spanned up to 150 ft between the manifold and the lead tow sled.

At Coflexip's (now Coflexip Stena Offshore) request, Amoco agreed to reconsider the use of flexible pipelines. An all-flexible pipeline system was previously rejected due to its perceived higher cost.

Full-cycle economics - including the rental of riser reels, risk of damage to the pipelines and communication cables during tow, and cost of cable crossings, corrosion inhibition chemicals, maintenance, and corrosion monitoring - was performed after receipt of installation bids. The economic result favored two 13.5-in,-ID flexible pipes for production and one 6,0-in, ID-flexible pipe for well testing. In addition, this solution outperformed the rigid pipeline option with respect to risk of damage or failure.

Once awarded the work, Coflexip Stena worked with Amoco to develop an acceptable method to tie the pipelines into the manifold. The designed for steel pipelines, did not permit significant horizontal loads on the manifoldduring a flexible pipe lay away. Pile-founded tie-in bases were selected to resist lay-away loads with rigid-pipe long jumpers connecting them to the manifold.