bluuebunny/crossref_metadata_2025 huggingface dataset:
Captain Horizontal Development Wells: A review of Key Design and Operational Issues
Authors: Tavendale F.M.
Published: October 2008

The Captain field, situated in the U.K. sector of the Central. North Sea, is a shallow heavy oil accumulation contained within massive and unconsolidated sandstone. In order to commercially develop Captain, production wells require to be drilled and completed with up to 6000 ft. of horizontal reservoir section. Key design, planning and operational issues leading to the successful pre-drill and suspension of seven wells are discussed.

Introduction

The Captain field is located in a water depth of 341ft. Hydrocarbons are trapped in two structural closures, the Main and Eastern Closure areas. The contents of this paper pertain to the pre-drilling of development wells in the Main closure area (denoted Area A). Two reservoir intervals are hydrocarbon bearing in the Main closure area; the Lower Cretaceous, Upper and Lower Captain Sands. The reservoirs have the characteristics of high permeability averaging 7 Darcies, high porosity circa 30% and are unconsolidated. Average reservoir depth and temperature are -2900fi. tvdss and 87 degrees F respectively. The oil is viscous and heavy by North Sea standards with oil viscosity at reservoir conditions between 47 and 205 centipoise (cP) and an oil gravity of between 19 and 21 degrees API (Table 1). The fluid properties and offshore environment require innovative horizontal drilling, completion and artificial lift technology for economically successful field development. Development risks were significantly reduced with the successful drilling and 93 day testing of a prototype field development well during 1993 (13122a-10).

The initial development area covering the western sector of the Captain Field comprises a wellhead protection platform (WPP) tied back by a suite of pipelines to a floating production, storage and offloading vessel (FPSO) from which export quality crude is offloaded by shuttle tanker. In order to accelerate field plateau oil rate of 60000 bopd seven wells were predrilled, lined with screens through the reservoir and suspended for future reentry from the WPP. Of the seven wells three are horizontal oil producers to the Upper Captain Sand (UCS), two are horizontal oil producers to the Lower Captain sand (LCS), one is a horizontal water injector to the ucs and one is a high angle water supply well (WSW) to a lower isolated reservoir (Fig 1, Table 2). The main design, planning operational concerns related to the drilling of a typical oil producer are discussed.

Well Design

Casing/Hole Size. Production rate requirements for each well dictated that a in internal diameter be provided in the reservoir section. This defined a minimum hole size of 8.5 in through the reservoir to accomodate pre-packed screens. The hole size was subsequently modified to 8.75 in. The size of Electrical Submersible Pump (ESP) required to deliver 15000 BOPD established the requirement for a minimum casing size of 9-518 in. above the reservoir.
Steel Catenary Riser for a Taut-Leg Moored Semi-submersible Platform
Authors: Franciss R. , Torres A.L.L. , Mourelle M.M. , Pinto F.J.C.P. , Souza L.F.A.
Published: October 2008

Following the tendency of using steel catenary risers (SCR's) for export lines in Campos Basin, PETROBRAS developed a project for installation of two 12" oil export SCR's in the semi-submersible platform P-19, at Marlim Field, in a water depth of 770 meters. The platform will be taut leg anchored with 16 polyester chain lines. The risers will be connected to the portside platform pontoon, in order to minimize the action of the waves directly on the risers and for safety reasons. This paper describes the design, components, specification and installation of the SCR's.

INTRODUCTION

To continue the development of exploration and production of Campos Basin, PETROBRAS will install in 1997, the P-19 platform, a taut leg moored semi-submersible platform located in the Marlim Field, in 770 m of water depth. The production will flow through flexible lines, hanging at the spider deck level. The oil will be exported to a Pipeline End Manifold, using two 12" steel catenary risers (SCR) connected to two 12" pipelines.

This solution was first studied in 1987, when PETROBRAS participated in a IIP' developed by SHELL and, since then, further studies were performed by PETROBRAS, at it's Research Center and at the E&P Department, to develop this technology.

PETROBRAS will install its first SCR, as a prototype, in the P-XVIII Semi-submersible platforms, in 910 m water depth, in 1997. This riser will be monitored during one year and the results will be compared with the design data and with simulations that will be performed with computer programs. Stresses, vibrations due to wave forces and vortex shedding, offsets and platform motions will be measured. Metocean data, including directional waves, currents and wind will be monitored too. This riser will be connected later in the end of 1997 with flexible lines, to the P-26 Platform.

A TAUT LEG PLATFORM

The function of a mooring system is to restrict the lateral motions of the floating structure within specified operational constraints. The overall design parameters are typically in terms of maximum allowable offsets, varying according to the platform operating conditions and the riser requirements, with limitations on maximum mooring line loads and other more specific constraints.

The design loads on the system are generated by wind, waves and currents. The mooring system operates by developing horizontal components at the points of attachment to the floating structure.

The polyester rope taut leg mooring concept allows cost reduction and improves the station keeping performance3. In the taut leg geometry, the platform mooring lines are terminated with suction piles or vertical loaded anchors, as showed in Fig. 1, to develop higher horizontal components, resulting in reduced mooring pattern radius around the platform.
Marlin Deepwater Riser Alternatives Risk Assessment
Authors: Wolford Andrew J. , Penyman Stephen R. , Deegan F. Jonathan , Gosch Stuart  W. , Stahl Bemhard
Published: October 2008

A study was undertaken to determine, for the Marlin deepwater development, the risks and benefits associated with the use of dual casing risers, compared to single casing riser design.

The study involved carrying out and linking 1) Failure Modes and Effects Analysis, 2) Fault Tree Analysis, 3) consequence severity ranking by experts, 4) cost (risk) 1 benefit assessment, 5) decision analysis, and perhaps most importantly, the study led to 6) team building and buy-in.

The results produced in the study were robust and demonstrated a clear preference for the single casing riser alternative.

Introduction

Amoco Production Co. is the designated operator of the Marlin deepwater development, located in the Viosca Knoll area 85 miles ESE of Venice, LA in 3240 feet of water. Key parameters from the Design Basis Document are summarized in Table 1.

The initial development of Marlin will consist of a five well (2 gas / 3 oil) development. In addition, when some of these wells are exhausted, one up hole re-completion and one sidetrack and completion are planned. The initial five wells will be pre-drilled using a MODU and once the platform isinstalled the final completion of these five wells will be undertaken using a workover rig. The subsequent workover and development drilling operations will be carried out using a similar workover rig.

The Marlin design team's conceptual design basis assumed that the wells would be tied back from the seafloor to the surface vessel with dual casing production risers, capable of carrying full shut-in tubing pressure. These risers are essentially dual concentric, redundant risers surrounding the production tubing running from 200 feet below mudline to the surface wellhead. A number of potential hazards during production and workover can prompt a requirement for this level of redundancy in barriers.

The purpose of this study was to determine the risk-benefit associated with the use of dual casing risers, compared to single casing riser design.

System Description

The Marlin riser systems consist of two similar designs of production riser system. The two designs are similar in most aspects except for the second (concentric) riser casing string in the dual riser case.

A system definition and boundaries were developed for the study. The basis for the definition of these system boundaries was the Marlin Field Design Basis Document and the details of the system components provided by the Marlin well systems team members.

The system configuration for the normal production mode is represented in the simplified completion diagrams shown in Fig. 1 for the single and dual riser cases.

The system configuration changes when the system is operating under either a workover or development drilling mode.
lnstallation of DeepStar's Polyester Taut Leg Mooring
Authors: Dove P.G.S. , Fulton T.M. , Devlin P.V.
Published: October 2008

During the summer of 1995, an attempt was made to install DeepStar's single leg polyester Taut Leg Mooring (TLM). Problems were encountered with chafing on one of the polyester rope sections and installation could not be completed on its first attempt. In September 1996, however, the system was successfully installed by Aker Marine Contractors, Inc. (AMC), under contract to DeepStar.

This paper describes the lessons in polyester rope handling and installation learned through the 1995 attempt, and how they were applied to the successfid installation work that took place in 1996. It also describes the TLM and its instrumentation and details the procedures used for the installation work.

The TLM, whch is located about two and one-half miles to the south of Shell's Auger TLP, is now being used as a standby mooring to allow supply vessels servicing the TLP to secure during delays in offloading. The TLM is equipped with special instrumentation that monitors real time tension, buoy heave and a heading sensor that determines buoy rotation. An onboard computer receives and stores the measured data, which is transferred to AMC's offices on a regular basis. The TLM will remain on station until September 1998, at which time it will be recovered by AMC. Three polyester rope section types were included in the TLM: two of a parallel-strand construction and one a multi-strand type. After recovery, 40 ft sections of type will be break tested and compared against new samples that were not installed in the system.

The test marks an important continuation of the development work in deep water moorings being conducted by DeepStar and industry and should allow the large scale use of polyester in TLMs in the Gulf of Mexico by the turn of the century.

Introduction

In recent years much attention has been paid to mooring systems for very deep water drilling and floating production applications. Because of the potential for reducing mooring system costs and limiting vessel excursions, the offshore industry has recently given serious consideration to the use of taut leg mooring systems. Although costs can be reduced for deep water mooring applications (>3,000-4,000 ft) using conventional components in a taut leg system (i.e., steel wire rope and chain and driven or drilled/grouted piles), additional cost savings can be achieved by considering the use of synthetic materials to replace the steel used in mooring ropes and either suction pile anchors or vertically loaded drag embedment anchors (VLAs) to replace piled anchors. For these reasons, polyester taut leg mooring systems have been a focus area for the DeepStar project over the last few years and the reason that DeepStar has embarked on the TLM test program. The test system installation and lessons learned are described in this paper.

Test Objectives

The following objectives were sought by DeepStar in the decision to proceed with the single leg polyester TLM test:
Low Cost Deepwater Hybrid Riser System.
Authors: Hatton S.A.
Published: October 2008

The design and analysis of a cost effective multi flowpath production riser for deep and ultra deep water floating production systems is presented. The design is based on a bundled concept using beach fabrication and installation by near surface tow. The study has been funded by the Deepstar project and addresses water depths between 1300 and 2200m in the Gulf of Mexico. The riser is designed to interface with a semi submersible production vessel but may also be used with an FPSO with minor modifications.

The design approach minimisis the riser steel weight and buoyancy requirements and achieves an optimum dynamic response through an efficient structural design and buoyancy distribution. This maximises riser flexibility and minimises hydrodynamic wave loading.

Introduction

The definition of 'Deep water' changes every year. Operators are currently developing reservoirs in water depths up to 1500m and have drilling campaigns planned for depths beyond 2000m. Production technology for such water depths is likely to center on semi submersible and ship shaped floating production systems which are well established in shallower water depths.

The riser systems, used to transport production fluids between the seabed and vessel, will become an increasingly important aspect in deep water developments. Risers are dynamic systems which operate at high pressures and temperatures often with corrosive fluids. Consequently, risers are technically complex and the materials and methods of manufacture and make them costly. These issues are compounded as water depths increase due to higher loads and lengths involved making riser system selection and optimization even more complex. Deep water developments to date have largely extended shallow water, flexible riser, technology through the development and application of new materials and manufacturing techniques. However, extending a successful shallow water solution to deep water is not necessarily the most economic or technically preferable approach. Whilst in shallow water high pipe flexibility is required to accommodate vessel motions, in deep water stiffer pipe may be considered due to the beneficial effect of water depth on riser system compliancy.

In recent years new riser arrangements have been conceived to meet the challenge of deep water, offering significant commercial and technical advantages over conventional riser systems. These new riser systems utilize steel pipe which has a relatively low cost compared to flexible pipe. The importance of these new riser systems is significant. Commercially, they provide an alternative to the flexible riser but more importantly, in many cases, they provide a technical solution where no feasible solution exists with flexible pipe.

The two most promising riser concepts are the hybrid riser [1,4] and the steel catenary [2,5]. Both concepts can be configured in a number of ways depending on application and even combined as in the case of the Tension Leg Catenary (TLC).
Applied High Pressure Coiled Tubing Technology Solves Resin Sand Control Problems In A Gulf Of Mexico High Pressure Gas Well
Authors: Zimmerman Joe , Sargent Tim , Clawson Greg
Published: October 2008

The current API and ASME design codes on wall thickness selection are too restrictive for the application of high pressure subsea flowlines. At present the codes require flowlines to be designed to wellhead shut-in pressure using Barlow design formula, which is based on first yield, and working stress safety factors established decades ago. Recent advances made in pipe manufacturing, design engineering, and the considerable plasticity of thick walled steel pipe render the current design overly conservative, resulting in severe cost penalties for long distance subsea tiebacks.

The current work describes the application of Burst Limit State Design principles to the design of subsea tiebacks. The paper discusses the limitations of the classical approach and quantifies the uncertainties, risks, and economics of limit state design, based on results obtained from burst pressure test data obtained from various industry sources. It is expected that this work will lead to a review of the existing codes by the regulatory bodies and the recommendation to change current in design practices.

The work will enable deepwater subsea tiebacks to be designed in accordance with limit state principles and safety factors reflecting the current state-of-the-art technology of pipe materials, manufacture, welding, quality control and pipeline design. This will lead to the optimum design of subsea flowlines.

This work is mainly directed towards the large D/T ratios required for high pressure subsea flowlines, and is different from the low D/T ratio work carried out by SUPERB and IS0 working committees in Europe. However, it is intended that this work will complement the work carried out elsewhere, leading to a consistent application of burst pressure design to pipelines and flowlines.

Introduction

DeepStar 3300 Committee commissioned a study to evaluate the feasibility of using the Burst Limit State criteria to design subsea flowlines. The work consisted of:Collection of data from published sources and DeepStar members.Identification of Limit State Design models for Burst Assessment of code compliancePreparation of submissions to API and ASME for code changes

The work presented here is limited to the Phase 1 of the study, and includes a description of the data collected, and the preliminary Limit State Design philosophy under development. Comparative cost data for current design practices, and Limit State Design also given to establish the potential cost savings of using Limit State Design.

Recognition of the uncertainties associated with engineering systems has led to the wide application of the concept of reliability as a basis for structural design. This is evidenced by the move in Europe and North America to develop limit states codes for pipeline design.
Field Cases of Cost Efficient Slickline Well Interventions
Authors: Larimore David R. , Fehrmann Gary Z.
Published: October 2008

The comparison of today's slickline capabilities with its early usage for routine remedial workovers and maintenance best illustrates the significant advances that have occurred within slickline technology. Today, for example, slickline can be used to I) set and retrieve slickline-retrievable safety valves or plugs, 2) open and close downhole circulating devices, 3)retrieve accurate depthhime data for correlating with memory production surveys for well diagnostics (problem identification) reservoir description, or flow analysis, 4) provide accurate correlation of tubing casing collars, and 5) pull and run multiple flow controls set packers and other downhole equipment without explosives; setting monobore tools; and other perform other well interventions that are dependent upon measurement accuracy. Less than a decade ago, slickline was only considered for mechanical well workovers.

This paper will discuss the newly developed technology that allows slickline to economically provide alternatives to services traditionally reserved for other, more costly options. Case histories will be used to illustrate the enlarged scope of services and how the equipment combines to provide the innovative low cost service options that the industry has been seeking.

Introduction

Economic initiatives are usually the drivers of new technologies, and thus, reacting to the significant decline in the oilfield climate during the last decade, no era has been as momentous in providing stimuli for operational change. Unfortunately, operators who are seeking new methods usually look to new technologies as the potential problem solvers, and in so doing, overlook enhancements to the older, proven technologies that could provide the cost efficient alternatives they want.

This has been the case with slickline. Until the resurgence of investigation into new strategies to meet the oilfield cost constraints of the last decade, slickline service was only considered for routine mechanical workovers. Who would have considered using slickline to set a packer in the early 90's.

The capabilities that have changed the profile of slickline service from one of routine mechanical well work overs to a multi-faceted service technology are derived from the new slickline tools that can be used independently or combined to further enhance the scope of services. The equipment includes an electronic triggering device (ETD) that enables safe detonation of explosive devices, a battery-operated, electro-mechanical tool that sets wellbore devices on slickline and braided line without explosives, an electronic measurement system that automatically corrects measurement inaccuracies resulting from line stretch and environmental stress factors, a slickline collar locator (SLCL) that accurately verifies collar locations in a tubing string, and data job loggers or acquisition software systems that connect to the electronic measurement system to graphically record dynamic wireline information.
A New Concept for Multibranch Technology
Authors: Stracke Mark , Neme Eric , Leismer Dwayne , Buytaert Jean
Published: October 2008

Industry interest for multibranch wells has grown in the past few years thanks primarily to the new capabilities offered by quickly evolving drilling technologies. A wide range of applications. all aiming at improving reservoir production economics, has already been identified.

However, multibranch wells have also created new challenges. Well construction. well control. as well as completion of the branches remain key issues yet to be satisfactorily addressed.

A new concept of multibranch system design has been developed not only to address short term well construction issues (milling, drilling, and completing), but also to answer the needs of reservoir management during the life of the well. Input from over fifty oil companies was gathered to define this system's specifications. It was developed by a multidisciplinary team of specialists from major directional drilling, completion, drilling fluids, and cementing companies.

This system is designed to provide a prefabricated sealed connection between the branches and the main trunk of the well. It will be functionally tested in a workshop prior to installation. Once installed in a well, the system provides ready to use sealed outlets which do not require window milling, nor does it rely on cement for pressure integrity, and it maintains full bore access below each branch. Other features include selective reentry ability in each branch at any stage of the life of the well, with minimal time spent for intervention

Introduction

A multibranch well is a vertical, deviated, or horizontal main conduit with two or more lateral conduits drilled at am depth, in any direction, and either horizontal or slit inclination. The main conduit may be an existing well (reentry) or a new well drilled specifically for the multibranch application. Multibranch wells provide opportunities for increased production rates at lower costs than single bore horizontal wells, and are particularly applicable for high cost and small fields. They will pennit a reduction in the surface construction requirements for wells; wellheads, surface and intermediate casing strings, and their corresponding costs. One of the greatest potential applications for multibranch wells will be in the development of deep water reservoirs where the number of wells and their surface construction items are commonly major driving factors in production system design and costs.

Multibranch well technology is not a new technology. Since the early 1950s oil company operators have experimented with multibranch wells. These early wells were exclusively open hole sidetracked completions. Even today this is the most common example of multibranch well drilling as evidenced by the hundreds of multibranch wells being drilled in such areas as the Texas Austin Chalk and Canada.
Use of Electrical Power in Control of Wax and Hydrates
Authors: Aarseth Finn
Published: October 2008

Electrical heating of subsea flowlines represents an effective method to prevent wax and hydrate formations, especially at long transportation distances and in deep waters with a low seabed temperature.

Such systems are available to be used in conjunction with bundles, pipe-in-pipe and wet thermal insulation systems, enabling an environmental friendly fluid temperature control without use of chemicals and flaring for pipeline depressurizing.

Enhanced production availability is achieved as no time is lost by unnecessary de-pressurizing, pigging, heating medium circulation or removal of hydrate and wax blockages.

Introduction

The seabed temperature at 100 m water depth and lower may range from 7 °C to -1.5° C, causing a rapid cooling of hot well streams being transported in subsea flowlines, see Fig. 1.

Vulnerable crudes and multiphase compositions will at such super cooling deposit wax and asphalts, and the gas - water phase may freeze solid hydrate particles that can permanently block the pipeline.

A conventional approach to secure a safe subsea transportation has been to use thermal insulated flowlines in combination with the following measures:Continuous injection of chemicals to reduce the hydrate freezing point and the rate of wax deposition.Depressurization of the flowline to enable a further reduction of the hydrate freezing-point.Use of twin parallel flowlines to achieve a more effective depressurizating of potential hydrate plugs, and to perform pig cleaning operations. Further to circulate hot waterloil in order to melt out wax and to pre-warm the flowlines after long lasting shut downs.

It is obvious that these measures do have physical, economical and environmental limitations especially in deeper waters and over very long transportation distances:The pressure head in deep water pipelines may give an insufficient pressure relieve at blow downs.Blow down and pressurisation of pipelines will involve pressure drop expansions and a related Joule-Thomson supercooling of multiphase fluids, that by itself can cause severe wax deposits and hydrate plugs.Heat loss in long twin pipelines that shall be preheated in a serial configuration, will restrict adequate heating above 10-15 km length.Continuous injection of large amounts of hydrate and wax inhibitors will dissolve in the produced water that may have a restricted release to sea.Long twin flowline installations will generate high investment and operational costs.

Thermal insulated and electrically heated flowlines represent an alternative prevention method for wax and hydrates that will not be restricted with the same limitations.

A market review of different designs and functional principles conclude that electrical heating technology is available for flexible risers and flowlines, pipelines, pipe-in-pipe and bundle systems for all practical lengths in subsea transportation. Some of these have been in operation with a satisfactory performance over a period of more than 20 years.
Cased Insulated Pipeline Bundles
Authors: Nock Mendel , Bomba John
Published: October 2008

Bottom tow pipeline bundle installations are gaining acceptance in deepwater developments. This is particularly the case where paraffins and hydrates pose a problem, since insulation and heating lines may easily be added inside the buoyancy casing, with less cost impact than in vessel based methods.

However, barriers to more extensive use of the bottom towed bundle technique are perceived problems of potential leakage into the outer casing and perceived problems related to the pressurization of the casing.

Approaches to mitigation of such problems, such as Bulk heading and foam filling are proposed and evaluated herein.

Introduction

Deepwater developments currently underway are increasingly requiring either insulation or heating to prevent hydrate formation or waxing in flowlines traversing cold ambient waters. Flowlines may be insulated either with directly applied insulation, pipe-in-pipe insulation, or insulation wraps within cased bundles. Heating may be achieved utilizing heating water in separate lines or annular jackets, or electrically, utilizing skin effect current transfer or other means.

Possible installation methods, already in use or imminent, include reeling, J-lay, S-lay or towing of bundled pipelines. In a towed installation, the pipelines and casing are welded into strings on a beach. To date, all Gulf of Mexico bottom towed bundles have been fabricated at Matagorda Peninsula, just down the coast from the mouth of the Colorado River. Thus site accommodates bundles up to 10 miles long. The bundle is then deflected laterally off of the beach and towed to the site. Pipelines may be towed on the sea dace, at mid- depth, or on bottom. All the Gulf of Mexico bundled installations have been by bottom tow.@ The bundled approach to installation of multiple pipelines, is to gather the several pipelines into a single package, and to provide a casing around the entire package which brings the total bundle submerged weight into a desired range. For a bottom towed bundle this submerged weight must be great enough to provide stability during the launch and tow process but low enough to permit towing by available vessels. The casing diameter required for correct submerged weight is normally sufficiently large such that an insulating wrap layer may be added to the flowlines without change in the design of the bundle, and the low density of insulating materials makes only a modest change in the submerged weight.

In shallow water depths the casing may resist hydrostatic collapse through its inherent stiffness, however, as water depths increase the increase in wall thickness required to prevent buckling makes it impossible to achieve a desired submerged weight.
The Development and Use of a Subsea Multiphase Flow Meter on the UK South Scott Field
Authors: Slater S.G. , Paterson A.McK. , Marshall M.F.
Published: October 2008

In May 1995 a multiphase flow meter (MPFM) was installed in a subsea production manifold on the UK South Scott Field operated by Amerada Hess Limited. This achievement was the culmination of a three year collaborative development programme, the objective of which was to develop and prove a prototype MPFM for a commercial subsea application.

The incorporation of the MPFM in the South Scott production facilities had two main benefits. It reduced the complexity of the infrastructure required to develop the field by eliminating the need for a dedicated test pipeline and riser system, and significantly reduced the project capital expenditure. Additionally the application provided the opportunity to deliver benefits to the production and reservoir engineering community by allowing real time monitoring of well tests.@ Despite the comprehensive testing undertaken during the development programme, the South Scott MPFM experienced an electronic component failure early in its operational service life, which resulted in the recovery of the meter and a subsequent failure investigation. This process uncovered a more complex problem associated with one of the sensor units, which required the development of a new technology for a solution. Through the sustained efforts and commitment of the venture partners, the initial setbacks have been overcome and the meter is planned to be operational on the South Scott field in February 1997.

Introduction

The development of hydrocarbon reserves in the mature province of the United Kingdom Continental Shelf is an increasingly challenging business. As the production from the large pioneering fields gradually declines and the discovery of significant reserves becomes a less frequent occurrence, the development focus has fmly turned to the exploitation of marginal and mini fields. As many of these accumulations are in the proximity of existing platforms, the option to produce the fields through subsea facilities tied back a to host platform is an attractive development concept. The limitations posed by existing infrastructure and the characteristics of some of the new fields has necessitated the advancement of new technology to provide novel equipment and processes for the economic development of these fields.

New Technology Initiative

In recognising the need for new technology and the significant contributions it can make to the core business areas of finding, developing and producing offshore hydrocarbon reserves, Amerada Hess Limited embarked upon an initiative to search out specific emerging technologies which could benefit the business if progressed to the level of commercial availability.

During the course of evaluation studies performed as part of the initiative, the topic of subsea multiphase separation, transportation and measurement was repeatedly identified as being of major importance to the development of future prospects.
Applications of Multiphase Meters at the Gullfaks Field in the North Sea
Authors: Økland O. , Kleppe K. , Berentsen H. , Klemp S.
Published: October 2008

The development of Multiphase Meters (MPM) has been an important R&D project for Statoil during the last decade. Extensive testing of MPM the last 4 years, leading to significant improvement of the accuracy and reliability of the meters, has proved that today the performance of MPMs are within our specifications.

The first large scale tests of MPMs from the vendors Fluenta, Framo and MFI took place at Statoil's Gullfaks B platform during the period from December 1992 to November 1994. The results from these tests have been published earlier [1,2,3]. The Gullfaks B conditions are, however, considered not to be too difficult for multiphase metering. This is due to relatively good mixing of the phases and a low gas volume fraction.

In 1995 the fist testing of commercial multiphase meters over a broad operational domain took place. This qualification test was performed in Norsk Hydro's test facility in Porsgrunn [4]. The test campaign was repeated in 1996. Improved commercial meters from Fluenta, Framo and MFI were tested together with two meters under development (Kvzrner Process Systems and ISA Control). The test was sponsored by 9 different oil companies.

In August 1996 Statoil awarded a contract for the supply of 8 topside MPM for the Gulfaks Satellite project. This was followed by a new award in November 1996 for 18 subsea MPM (with an option for another 9 meters) for the field developments of Asgard and Gullfaks Satellites. Bothcontracts were awarded to the Norwegian company Multi-Fluid Int. (MFI).

For applications of subsea MPM it is of crucial importance that the accuracy, stability and repeatability of the meters are according to the specifications. To be able to learn from practical experiences of operating such meters, Statoil has installed two subsea meters from MFI and Framo for a one year test at the Gullfaks B platform.

At Gullfaks B another MPM has been in operations since November 1996 for allocation metering of the production from a long reach well. The well has been drilled into a nearby reservoir where other tax regulations appliescompared to the main field.

Initial comparisons of the MPM and the test separator shows encouraging results.

Introduction

The large economical potential for applying multiphase meters has been the driving force behind the various development projects supported by the oil industry for the last 10-15 years. Today, several first generation meters are commercially available and the oil industry is now starting to use them in large numbers. Multiphase meters are either used for well testing or for production allocation metering.
France's Forty Years of Experience in Offshore Technology
Authors: Appert O. , Burger J.
Published: October 2008

This paper focuses on some particularly illustrative contributions of oil companies, service and equipment suppliers, research centers from France, to the history of forty years of offshore adventure.

Other advances are still to be expected, and some major trends for the coming decades are discussed.

Introduction

The importance of France's technological input to offshore industry may surprise since France holds very low oil and gas reserves on its territory. Despite this situation, Elf and Total are in the top 20 of the world's oil companies, the French supply and services industry has developed worldwide activity, Institute Francais du Petrole (IFP) and other research institutions are known internationally for their contribution to the progress of the oil and gas industry.

This situation results from the fact that after World War I the security of energy supply has been recognized by the successive governments of France as a major political issue. Therefore, the necessary impetus has been constantly given to encourage the development of the French oil and gas sector. Under the umbrella of this oil policy, a close cooperation between oil companies, suppliers and research centers has been set up in order to develop competences to take up the new technological challenges. This was clearly the case for offshore activities.

A Retrospective View

In the early sixties, the geopolitical situation led France to define a new policy, and it was decided to launch an important programme of development in order to diversify the sources of oil supply (Ref. 1). Offshore was still at the infancy. In fact, the first real offshore discovery had been made on November 14, 1947 in the U.S., 15 km off the coast of Louisiana, in a water depth of 6 m (20ft), with congratulations expressed for having surmounted such a "technical difficulty"; but the exploration activity on the continental shelves really started in 1960. In 1965, gas was discovered by BP in the North Sea: the technological challenge of offshore development effectively deserved to be coped with. When the first oil shock occurred, the French industry had developed the necessary background for taking its share in the development of the promising reserves of the European offshore domain.

In this context, the European Commission launched in 1973 a technological program to promote the development of hydrocarbon resources in Europe. During this period of high oil prices, new technologies were studied and tested at the prototype stage with the aim of overcoming the bottlenecks to exploration and production with regard to hardly accessible offshore reserves. French companies have been strongly involved in this adventure and contributed to major issues, as indicated below, while promising international partnerships were initiated.
Meeting the Challenge Regarding the Quality of Drilling and Production Data Recovered From Offshore Wells
Authors: Debray Benoit , Haines George
Published: October 2008

This paper presents the efforts made by a service company during the past thirty years to participate in the development of offshore activities, by continuously meeting technical challenges in the monitoring of drilling, testing and production of offshore wells. Offshore operators have long recognized the need for a maximum of drilling and production data of the highest possible quality. Today's stringent requirements for increased safety, environmental protection and minimum cost have increased the importance of data quality and are being applied worldwide.

On site real-time data aids offshore development : many case histories have demonstrated how the use of rig site data acquisition computers provides geologists and drillers with valuable data from which rapid and efficient decisions could be made a1 the drill site. Surface data logging is a unique opportunity to obtain direct evidence of oil as well as recording all main well events; offshore constraints have speeded up the development of on-site data storage and offshore-onshore teletransmission.

Technical advances applied to surface and down hole equipment enable efficient appreciation of onshore exploratory wells : once a system is installed to acquire, monitor and transmit data during the drilling phase, it is convenient to also use it during the testing phase. The quality of the monitoring of well testing activity relies on the ability to obtain accurate bottom hole data in real-time, which can be difficult while running a DST. Newly available technical advances help in solving such problems, as well as improving the quality of pressure measurements and optimizing the cost of the test by reducing its overall duration.

Introduction

We present here an overview of advances in information technology and remote sensing by a particular service company that we believe have had a significant impact in offshore drilling, well testing and production. These innovations have been developed over the past 30 years and are being implemented worldwide. The general aim of these technological refinements has been to close the decision loop that is to increase the reliability of data and shorten the time required to make critical decisions.

On Site Real-Time Data Aids Offshore Development

Mud Logging, sometimes referred to by the modern term of Surface Data Logging (SDL) provides the only broad-based method to combine geological and drilling data in real time. This provides a unique opportunity to obtain direct evidence of oil and gas as well as recording all main drilling events. SDL is an evolutionary step beyond basic mud logging services, recovering transient drilling and geologic information to allow better 'tuning' of the well construction process for highest efficiency. A major component of SDL is the effort to simplify, as much as possible, the presentation of ever-more complex operating conditions, while reducing the need for operator intervention to understand the nature of well events.
Joint Inversion Of Resistivity Logs: Limits And Possibilities
Authors: Strack K.M. , Mezzatesta A.G. , Frenkel M.A.
Published: October 2008

In the search of hydrocarbon bearing formations, borehole electrical logging techniques play a key role in distinguishing between oil and water saturated rocks. Among the electrical techniques, both induction and current injection (galvanic) tools, are of significant importance in determining movable and residual hydrocarbons. In the past, the borehole electrical logs have been mostly interpreted using curve matching or approximate modeling techniques. This often resulted in underestimating the hydrocarbons in the subsurface and/or misled distinction between the water and oil bearing zones. Here, we present an automated interpretation technique which has become feasible to the oil industry with the advancement in geophysical inversion and modeling and the event of smaller parallel computers. In addition to being able to provide an automated and more reliable interpretation, one can also combine numerous different electrical measurements to avoid the inherent bias of the individual logging tools. Further, a thorough analysis of the interpretation methodologies used (namely inversion) allows us to provide uncertainty estimates for the interpretation results which can be translated directly into confidence intervals with minimum and maximum pay values. The benefits of this technology can be best presented using case histories from different environments.

Introduction

In estimating the amount of hydrocarbons in the ground, one interprets the characteristics of the earth's formation by using borehole logs. Figure 1 shows a typical sketch of formation intervals where electrical logs are being used to determine the existence of oil in the formation. In the left part of the figure, the formation is usually a thin zone where the pore fluid is replaced by the borehole mud. This zone is called the invaded zone. The character of this invaded m e can change from being exclusively by the borehole mud or mixed invasion of borehole fluid, formation water and formation hydrocarbons (Fig. 1). The distinction between these zones are mostly done through induction or current injection (galvanic) logs. This is because the oil is resistive while the formation water in general, is very conductive. During the tuna when the industry was predominately producing large pay zones, curve and approximate numerical techniques were quite sufficient to distinguish between the oil and the water. As the targets move to thinner and thinner reservoirs and more complicated environments, the systematic underestimation of reservoir reserves and a decreasing hit to miss ratio of oil bearing zones become apparent.@Although solutions have been suggested many years ago1,2 the techniques have only been used on a research level because commercial applications to real log data was not feasible because of the large amount of data being obtained during a logging run and also the complexity of the numerical problems on hand.
Efficient F-K Domain Wavefield Interpolation
Authors: Gulunay Necati , Chambers Ronald E.
Published: October 2008

Often, economic reasons dictate that seismic data be recorded with much larger spatial sampling intervals than basic sampling interval. This can cause harmful aliasing effects in prestack and post stack multi channel processing algorithms such as f-k filtering, Radon transform filtering, DMO, and migration. A common solution to sampling deficiencies is to use trace interpolation during processing. Among methods used in trace interpolation are sinc interpolation, dip search and slant stack, f-k domain deterministic dealiasing and the popular prediction filter based algorithms. Only the last class of algorithms can interpolate aliased temporal frequencies for steeply dipping events, but are expensive. Because of wrapping of aliased data inherent in the f-k domain, this domain was previously thought unsuitable for trace interpolation in the presense of steep dips. But, because of its efficiency, the f-k domain is an attractive domain to work with. This paper will present an efficient f-k domain data adaptive interpolation method that overcomes the problems in aliased data. The capabilities to interpolate steeply dipping events, to handle curvature by spatial windowing and to help in the removal of multiple interference will be illustrated. This new f-k wavefield interpolation is now used in production to minimize the aliasing effects in 3-D prestack multichannel processing.

Introduction

The recorded wavefield is a sampled version of the continuous wavefield and field geometry serves as a digital sampling process. Coarse digital sampling is known to cause aliasing. Ideally, shot, receiver, and temporal sampling intervals should be selected so that it is possible to construct a continuous wavefield from the recorded samples. The data are then said to be "properly sampled." The resulting sampling intervals are called "basic sampling intervals'." Experience has shown that harmful aliasing effects in prestack and poststack multichannel processing result from data recorded with a much larger spatial sampling interval than the basic sampling interval. Even when the signal (primaries) is properly sampled, it is quite likely that organized noise such as ground roll, mud roll, and multiples is under sampled, especially in areas where the noise or multiple energy has a much lower move out velocity compared to the signal. With the improved dynamic range of current field equipment, it is common practice to use smaller arrays in the field and deal with the noise during processing. Although NMO correction is sometimes used to reduce the aliasing problem, for some recording geometries such as offend marine shooting, an inherent aliasing problem remains in the common offset and common midpoint domains, even when shot and receiver domains are properly sampled.