bluuebunny/crossref_metadata_2025 huggingface dataset:
A New Concept for Sand Monitoring: Sand Probe Based on the ER Technique
Authors: Braaten N.A. , Johnsen Roy , Sirnes Geirfinn , Solberg Tom , Søntvedt Terje
Published: October 2008

This paper describes a new concept for sand monitoring in multiphase flow regimes and presents results from a thorough test programme, run in a dedicated sand probe test rig at Norsk Hydro's Research Centre at Herøya. The sand probe has been developed as a result of the need for sensors that ean give real quantification of the sand content in oil and gas as well as multiphase flow. This type of probe requires no on-site calibration, and has in principle no lower limit on the smallest detectable sand concentration.

This sand monitor is based on measurements of change in resistance in thin, corrosion resistantsensing elements, as these are eroded by the sand. The probe is manufactured with typically four sensing elements which together will cover the whole internal pipe diameter.

L%e system has been tested under both bubble and slug flow. All tests clearly demonstrate the probe response's linear dependence on sand concentration, and that the probe can measure the sand content regardless of turbulence level.

INTRODUCTION

The production of sand and solids in oil and gas can represent a major problem in terms of erosion and damage to production equipment. Sand production can also lead to a degradation or, in the worst ease, a collapse of the reservoir. This sand probe has been developed as a result of the need for sensors that ean measure the sand content accurately both in oil and gas as well as multiphase flow. The CarOcean sand probe is particularly beneficial in situations with low gas/liquid ratios, where accurate quantification of sand with traditional acoustic methods has proven to be difficult.

This article presents data from a 9 month test programme run in a new, dedicated test rig at the Norsk Hydro Research Centre at Herøya, Norway. The purpose of the tests was to qualify this new type of sand probe, and to develop a computer model to be used for quantitative analysis of the sand content in the flowing medium. The test programme was divided into three parts An initialtest performed in water, a qualifying test in oil and finally, a test in pure gas phase. The data from the gas tests in annular flow were still under analysisat the time when this article was prepared, and will therefore be published later.

Four parameters were focused on during thetest programme:Mixture velocityGrain sizeGas-Liquid RatioProbe positioning

A large number of data were analyzed during the course of the test programme, to ensure that thederived formula was as accurate as possible. Due to limited space, this article can only present a small fraction of the data.
Downhole and Subsea Completion Design for a High-Pressure North Sea Gas Condensate Field
Authors: Gomersall S.D. , Sardar Khalid , Rae G.R.
Published: October 2008

This paper details the overall system design for a 15,000 psi subsea, gas condensate well in the North Sea. Currently, significant industry interest exists in the technology required to complete wells of this type, which would enable substantial hydrocarbon reserves to be developed. Subsea wells such as this have not yet been completed.

INTRODUCTION

A significant number of high pressure discoveries with surface pressures in excess of 10,000 psi have been made in the Central Graben of the North Sea which await attractive project economics to allow their development. A reduction in cost and risk associated with such a development may provide the incentive required. The technology needed to develop these discoveries economically is likely to include subsea production systems as these are now a proven means of providing a low cost development. Subsea technology has not previously been applied to these high pressure wells and the downhole technology has only previously been applied from platform or land based developments. This paper presents the issues concerned with the completion of such a well and where possible makes recommendations for a special design. In areas where it has not been possible to specify a design comments are made regarding the issues to be considered or resolved and suggestions are made for additional industry development.

The work is based upon in-house designs and external studies performed for Marathon Oil UK in order to allow the future development of it?s high pressure prospects and discoveries. This design isbased upon the known and anticipated data from one such North Sea reservoir, Figure 1 shows the formation pressure of this reservoir in relation to existing fields in the North Sea and elsewhere and to other as yet uncompleted prospects. Table 1 lists the operating conditions. The pressures and temperaturesencountered in this design are not as severe as some other discoveries and do not meet some definitions of'hostile? (reference 1) or high pressure / high temperature (HP/HT) (reference 2). However, both these definitions are somewhat arbitrary, and since 15,000 psi drilling and production equipment isrequired for the field, it is a significant departure from previous subsea completion experience.

The issues raised in this paper are relevant to the completion of wells with greater pressures and temperatures than those in this well and as such this design can be seen as a 'stepping stone? to overcoming the problems likely to be encountered in these wells. The wide ranging nature of the subject prevents an in depth analysis of each issue but is intended to stimulate and encourage further work in septic areas. Certain aspects and recommendations are likely to be controversial but it is hoped that bypublishing the work and sharing ideas, the development of 15,000 psi subsea wells may become one step closer.
Development of Conventionally Uneconomic Reserves Using Subsea Completion Technology: Garden Banks Block 224,Gulf of Mexico
Authors: Cooke J.C. , Cain R.E.
Published: October 2008

With the advent of increased drilling in the deeper waters of the Gulf of Mexico, discoveries are going to be made which will not support development with a bottom founded structure and associated facilities. Floating production systems are an alternative for producing these discoveries, but are often expensive to outfit and operate, and are dependent on supply. Utilizing satellite subseatrees and flowlines to produce the well to a host platform for processing produce a dual benefit. It acilitates. production "conventionally uneconomic reserves at a lower development costand benefits the host platform through potential processing fees and extended economic life.

Introduction

Exploratory drilling in Garden Banks Block 224, Gulf of Mexico delineated approximately 46 BCF recoverable reserves in f 50' water depth. Preliminary studies indicated development scenarios requiring bottom founded structures orfloating pro3uction systems would not generate sufficient return on investment. The determination was made to use a single subsea completion to recover the majority of the reserves. The gas would be produced to a host platform 14.5 miles to the North utilizing a diverress lay-away subsea tree design four inch flexible pipe/hard pipe flowline and a multiplexed electro-hydraulic control system. The design would apply previously tested technologies together for the first time in the Gulf of Mexico. This paper provides adetailed review of major decision points evaluated through the course of this project.

Exploration History

Garden Banks Block 224, OCS-G-6364 (Fig.1), was purchased in Au st 1983. The No. 1 well was drilled as an expendable straight hole to a total depth of 16000' MD, and found two productive sands, the TA-2B and TA-2C at 7938' ISF and 8030' ISF respectively (Fig. 2). The two sands were gravel packed and tested to 7.7 MMCFD, O BCPD, 36 BWPD at 3520 psi FTP for the TA-2C sand, and 6.3 MMCFD, O BCPD, 14 BWPD at 2430 psi FTP for the TA-2B. Each of the two zones exhibited significant skin damage during testing. The No. 2 well was drilled as an expendable straight hole downdip to the No. 1 and while the TA-2B and TA-2C sands were primarily wet, the TA-2A sand was productive (Fig. 3). The TA-2A sand was gravel packed and tested at 9.4 MMCFD, O BCP, 71 ;WPD at 2850 psi FTP. The TA-2A completion, like the tests from the No. 1 well, exhibited significant skin damage during testing. Well No. 3 was drilled across a fault to the South, encountered some potential pay, but was not tested. Well No. 4 was drilled u dip but found the productive sands pinched out (Fig. 4).

Development Analysis

The exploratory wells were drilled as expendable because development wells were to be drilled from a fixed platform.
Poseidon Multiphase Pump: Field Tests Results
Authors: Gié Pierre , Buvat Pierre , Bratu Christian , Durando P.
Published: October 2008

This paper presents recent attainments of one of the main components of the POSEIDON project launched in 1984 by TOTAL, IFP and STATOIL : the multiphase pump. After successful bench tests, the pump had been installed on a real field in Tunisia. Four thousand running hours without mechanical problems have provided a better understanding of how a multiphase pump behaves when placed in a production network.

INTRODUCTION

With the necessary development of small oil accumulation, either onshore or offshore and the increasing depth of offshore exploration especially in Brazil and in the Gulf of Mexico, it is widely accepted that there will be a need to pump the effluent from the wellhead to the nearest processing facility without treatment on site. This results from both a technical limitation of the traditional platforms when faced with deeper waters and from economic considerations of lower cost offered by this new technique.

For shallower waters, even when a platform could be envisaged, the size of the accumulations often rules out the development because of economic constraints.

As the maximum possible distance that can be covered by a multiphase effluent with the natural pressure appears to be limited to about 15/20 km of pipe line (15 km for DON, BP), a satellite developments could use a new type of technology to add energy to the flow at the beginning of the line. The available economic studies [I] show that the majority of reserves in the North Sea are at a distance of 50 km or less from existing facilities, and that 80% of the discoveries with a total of 10 million of barrels of reserves are located withing 35 km of them, thus giving access to additional oil at acceptable cost, should an industrial boosting technique be made available to the operators.

The POSEIDON project was created in 1984 by TOTAL, IFP and STATOIL to review all the problems to be solved to build a multiphase subsea station. One of the major element of such a station was the multiphase pump.

At that time no pump capable of handling a multiphase fluid was available and hence a major effort was agreed upon by the associates to develop an emerging technology in order to reach a very ambitious goal : a pump able to create a differential pressure on any liquid, with a gas fraction from O to 95% in steady state flow and the capability of handling void fraction of 100% in case of slugs of pure gas.

The available technology of the end at the 70?s was an ESP (electric submersible pump) able to pump a fluid with GLR of 3(gas to liquid ratio) under down hole conditions. Today the POSEIDON multiphase pump is industrially proven, has
A Multiphase Flowmeter Test and Calibration Facility
Authors: King N.W.
Published: October 2008

The paper describes the new Oil and Multiphase Flow laboratory at NEL add in particular the oil, Water and gas multiphase flow facilities which will be available. A central feature of the multiphase facilities is the design and Construction of a Multiphase Flowmeter Calibration Facility to be commissioned in early 1993. This, it is believed will be the only facility world-wide capability of calibrating the many new multiphase flow which are presently under development and scheduled for field user in the coming years.

All these facilities are available to meet the needs of the Offshore oil industry and this paper is therefore presented firstly to inform the industry of the capabilities, and secondly to invite comments and suggestions from all those with an interest in oil and multiphase flow measurement.

Although the primary function of the is in flow measurement, other aspects of multiphase flow can also be accommodated such as mixing, separation, pumping and control.

INTRODUCTION

At a recent North Sea Flow Measurement Workshop,(Reference 1) the discussion group Assigned to multiphase flow identified some 18 Different multiphase flowmeter projects currently in progress. Though only a few of these are at a stage where test results have been pub1ished (Referencse2–5) it is known that of the Projects are primarily motivated by future developments in the North Sea. The reasons for this are fairly well known (Reference 6) and centre on the need for the successful control, transport and metering of multiphase flows if marginal or deep-water fields are to be economically exploited. A lot of money is being spent on developing multiphase - many of the 18 projects identified bove are in the multi-million dollar range- and yet little consideration is being given as to how the meters will be calibrated. As any instrument is only as good as its calibration this seems to be a weakness in the development plans of the multiphase flowmeter projects.

Because NEL holds the UK national Flow Measurement Standards for oil, water, and gas single-phase flows because of its proximity to the North Sea, it seemed sensible that NEL should try and rectify this weakness by providing a national standard for multiphase flow measurement. The idea was not a new one as NEL had been involved in multiphase flow research for many years (references 7–9) and is currently developing a multiphase flowmeter under the sponsorship of a consortium of oil companies and the EEC. The opportunity arose when the decision to build a new and larger Oil and Multiphase laboratory at NEL coincide with the decision by the UK Department of Trade and Industry to provide funding for a multiphase calibration facility and that NEL would be the chosen site.

The task of providing a multiphase flow measurement standard gives rise to many design challenges. It Is not just a question of mixing together individually metered supplies of oil, water and gas and passing them through the meter to be calibrated.
A New System for On-Line Monitoring of Corrosion and Bacteria in Pipelines
Authors: Smart J.S. , Pickthall T.M.
Published: October 2008

A new system for on-line monitoring of 'internal corrosion and bacteria in pipelines has been developed which maintains till pigging capability in the pipeline. Fluids are withdrawn from the pipeline and passed through a test chamber specially designed to provide reliable corrosion rate measurements under pipeline operating conditions. The system duplicates and measures worst case pipeline corrosion conditions, provides evaluation of corrosion and bacteria control programs in an on-line manner, and can function in the absence or intermittent presence of water in the pipeline. Corrosion and bacteria probes are able to be replaced under atmospheric conditions, greatly simplifying operation, and the unit can be easily cleaned of accumulated solids. All equipment is built to API pipeline codes, and the system can be installed on new pipelines and/or retro-fitted to existing pipelines.

INTRODUCTION

Minerals Management Service data (Ref 1) indicates that corrosion was the cause of at least half of all pipeline failures in the US Gulf of Mexico for the period 1967–1987, as shown in Figure 1. This compares to 20% due to third party mechanical damage, and 12% for storm and mud slide induced damage. Of the total of 343 offshore corrosion failures in this period, 15% were caused by internal corrosion, 46% from external corrosion, and 39% from "general" corrosion. Even though gas pipelines have a larger population in the Gulf of Mexico than oil lines, half of the offshore failures were in oil pipelines. Of thebalance, 28% occurred in gas pipelines, 3% each in multi-phase and miscellaneous lines, and 16% not reported.

Recently, the 169 KM (104 mile) Forties Field pipeline was replaced due to internal corrosion (Ref 2). Design pressure of this 32 inch pipeline was 2084 psi (142 bar), and it was fabricated of API 5L X65 pipe with a 19 mm wall thickness. Corrosion was described as "characteristic of individual corrosion pitting, general corrosion containing pitting, selective corrosion attack of girth welds, and areas of relatively uniform metal loss, which resembles general wall thinning but with a rough internal surface texture."

Most oil and gas pipelines are well designed for corrosion control in their initial operation, but changing conditions frequently result in off-design operation after some period of time. System add-ons and partial abandonments change the type and volume of fluids inthe line and create dead spaces. Maturing of oil and gas fields results in greater amounts of water and smaller amounts of oil and/or gas. This results in lower linevelocity and allows water to stratify in the bottom of or at low spots in the line where it can cause corrosion. Ricca has also reported that internal corrosion has occurred in "dead legs" in the Trans Alaska Pipeline (Ref 3).

Full Well Fluids Transmission (FWFT), has resulted insubstantial volumes of water being transmitted through offshore pipelines which did not previously transport water, and for which the pipelines were not designed.
Cement Slurry Batch Mixing: A Critical Step for Slurry Quality Control
Authors: Vidick Benoit , Hibbert A.P. , Kellingray D.S.
Published: October 2008

The properties of batch mixed slurries prepared in a series of yard tests using full scale equipment are compared with laboratory tests on the same materials. Dramatic differences have been observed between conventional laboratory tests and field scale properties. By splitting the batch mixing process into distinct steps, a laboratory method is tested against the observed differences.

It is shown that mixing energy is an important parameter in slurry design and that energy levels substantially above the conventional API laboratory mixing energy may degrade slurry properties such as pumping time.

INTRODUCTION

Batch mixing of slurries for critical jobs is a common practice when the size of the job allows, (say), less than 100 bbl. Many different types and size of batch mixer are available to cope with offshore restrictions and batch mixing offers the assurance of good quality control of the slurry prior to pumping. The density can be controlled within tight limits and the slurry is fully homogenized and can even be subjected to testing prior to committing to pumping.

Although physical and chemical aspects of mixing have been investigated before1,2, there is little data on the effect of batch mixers on slurry properties and no industry accepted laboratory test procedure to design such slurries to account for the numerous parameters involved. Laboratory testing invariably follows the API procedure3 for thickening time and, although this may be adequate in some cases, it cannot universally predict field behaviour.

The mixing, homogenization, pumping and displacement of the cement slurry all play a part in determining the hydration and thickening behaviour. The relative contributions from each part of the process need to be understood if failures are to be avoided. In general, it has been found that increasing the mixing energy up to the value experienced in the API laboratory test is a good thing. Many slurry properties are improved2. At levels of mixing energy greater than the API value, properties w degrade. The actual behaviour will depend on the type of slurry design, the brand of the cement as well as its API classification and, in the case of batch mixing, the volume mixed and the amount of shear energy delivered during mixing and homogenization. Again, the process needs to be viewed as a whole. Surface lines can provide extra mixing energy as, indeed, can pumping through coiled tubing. Often these contributions may not have a significant impact on slurry properties but do need to be quantified and understood. In batch mixing of relatively small volumes of slurry (1Obbl), profound changes can occur in properties compared with conventional laboratory testing.

This paper describes a series of yard tests using full scale equipment coupled with considerable laboratory testing of samples of slurry taken from the yard and also mixed in the laboratory using identical material.
The Reduction Of Low-Frequency Motions Of Moored Fpsoâ??S
Authors: Pinkster J.A. , Luth H.R.
Published: October 2008

In this paper the merits of a wave energy conversion device which directly converts wave energy into useful thrust directed into the oncoming waves is investigated both experimentally and by means of computations. The device consists of a horizontal airfoil section located at the keel level at the bow of the storage vessel. In high wave conditions the foil produces mean and low frequency thrust in counter-phase with the mean and low frequency wave drift forces acting on the vessel. The results of detailed experiments using a model of a 65000 dwt tanker in head seas verify that with the foil system a significant reduction in the overall forces on the vessel is obtained. Details are given of the vessel and foil characteristics as well as a review of tests and test results.

INTRODUCTION

Permanently moored tanker-based storage and production vessels have been in use by the offshore industry for many years. Such low-cost systems have been applied mostly in relatively mild climates due partly to the problems encountered in mooring large vessels in more harsh sea conditions. The reduction of oil prices, the increased knowledge with respect to the design of mooring systems and experience and confidence with use of such systems has, in recent years, led to an increasing number of applications of such vessels in more exposed locations. It is recognized that in a number of cases the economical feasibility of the particular system can be adversely affected by the higher costs of the mooring system which results from the more severe sea conditions for which it is designed. In order to make such systems economically viable disconnectable systems which make it possible to uncouple the vessel from its mooring at times when severe sea conditions prevail, have been designed and built. See reference [1]. In other cases purposely installed thruster systems which are intended to relieve the loads on the mooring system in severe sea conditions have been applied. See reference [2]. If such additional means are not applied the only means available to the designer in order to ensure the integrity of the mooring system and the survivability of the moored vessel is to design heavier mooring systems of which the component parts are capable of accepting higher loads. Another method of approaching the mooring system problem is to optimize the design of the vessel with a view to minimizing the mooring loads. Due to the fact that in general useis made of existing vessels this approach has not been followed systematically up to now. Reduction of the horizontal motions and mooring forces can also be achieved by an increase in the damping of the horizontal motions since the cause of the large amplitude motion and force components is partly due to the fact that the motions are very lightly damped and concentrated around the natural frequency of the moored system. See ref. [3].
An Improved Lightweight Bottom-Founded Offshore Platform
Authors: Lewis R.E.
Published: October 2008

This paper presents the design and analysis of an improved lightweight, bottom-founded, offshore platform for multi-purpose use in support of field development operations in water depths to 500 feet and possibly greater, and in severe as well as in mild marine environments. The concept, an innovation based on current tripod-type structures, utilizes a novel framing support system which results in an extremely efficient design with a broad range of applicability. The development of diverse applications for the concept and an assessment of its limits of applicability are discussed.

This paper is of interest to the designer, the engineer, or others wh O are seeking an alternative, straightforward and cost effective approach to the design and installation of offshore platforms. The data presented is useful to those assessing the economic feasibility of an offshore field development.

The paper discusses platform performance data, including member stresses, deflections, and natural periods of vibration, and offers criteria related to the environment, payload, and water depth for which the concept is best suited. Estimated platform weight and cost data versus water depth for various environments and development scenarios are presented and compared with data from more conventional platform concepts. It is demonstrated that the improved concept offers significant advantages over current designs.

OBJECTIVE OF THE DESIGN

This design concept was developed in response to the ever growing need for more cost effective solutions to the development of our offshore hydrocarbons reserves. The objective of the design was to develop an offshore structure that 1) is very lightweight, 2) has a relatively high deck load capacity, 3) is suitable for use in a large range of water depths, 4) is adaptable for the pre-drilling and completion of wells, 5) can be fabricated in a relatively short period of time, 6) can be installed with conventional lifting and/or drilling equipment, and 7) can be easily relocated for reuse at another offshore site where the water depth differs greatly from the first site.

GENERAL DESCRIPTION

The basic concept is a tripod structure as illustrated in Figures 1 to 3. The configuration shown in these figures is called a "Right Angle" configuration because it appears, when viewed from the side, as a 90Â° right angle. The right angle configuration offers greater access for the drilling of wells. In a "symmetrical" configuration the apex of the tripod is placed at the centroid of the triangular base. The symmetrical configuration is suitable for those applications that do not have wells.

The principal component of the structure is the column. The column is designed as a separately installed element which is lifted or floated into place offshore in a single piece. It may contain risers, umbilicals, sumps, caissons, and other facilities as needed for offshore operations. The column is designed to support a cantilevered equipment deck.
Design And Installation Of A Cost-Effective Spar Buoy Flare System
Authors: Korloo Jafar
Published: October 2008

To meet the requirements of flaring large amounts of gas, a cost effective Spar Buoy Flare (SBF) system was designed, built and installed by IMODCO in less than a year at AGIP Petroleum's Agbara field production platform, offshore Nigeria. The system is designed to withstand the 100 year return storm and is capable of flaring 116,500 m3/Hr of gas at an exit velocity of 150 m/s.

This paper presents the system development design, installation, model testing of the Agbara SBF system.

INTRODUCTION

To meet increasing gas production rates disposal requirements at the Agbara field, Nigeria, a cost effective Spar Buoy Flare (SBF) was designed, constructed and installed within ten months. The Agbara platform was designed originally with an integral flare boom for gas disposal. The increasing production required the need for a system capable of remotely flaring large amounts of gas from the offshore platform.

The gas is flared continuously through a 17 inch internal diameter flexible pipe that runs from the production platform to the SBF structure.

Compared with other types of remote flaring structures such as bridge and platform, tripod and articulated type the SBF offers the following advantages:SBF's light weight structure is efficient and particularly suited to deep water.SBF is fabricated in cylindrical sections and is designed for easy local assembly.SBF can be installed with light offshore equipment.SBF can be adapted to different sites.An SBF is a cost effective system especially when considered on a turnkey basis.SBF variable ballast allows for maintenance of splash zone and inspection of chain stoppers.

The general arrangement of the Agbara SBF is shown in Figures 1 and 2.

SBF DESCRIPTION

The SBF is an all cylindrical welded steel structure with an upper section that is 21 m long with a 1.6 m diameter, and a lower section that is 45 m long with a 2.25 m diameter. Between the upper and the lower section is a transition cone which is 2 m long.

The SBF has eleven watertight compartments. The spacing of the compartments allows for accidental flooding of any one compartment without losing stability. The bottom three compartments are used for permanent and seawater ballasting. The bottom compartment is designed for high density ballast, The SBF structural arrangement and the installed configuration of the SBF are shown in Figures 3 and 4.

The major components of the SBF include:SBF pipingChain stoppers interfaceFlare tipWalkway, ladder and boat landingBallast/venting pipingMooring systemCathodic protectionFlexible pipeBallast system

The Agbara SBF structural mass is approximately 100 tonnes; total installed displacement is approximately 200 tonnes.

Flare Piping

The transition piping from the flexible pipe to SBF is provided at approximately 23 m above the SBF keel, The pipe penetrates the decks through seal welded collars that maintain the watertight compartments. Provisions are made to allow the pipe to expand thermally in theaxial direction.
High-Pressure Gas Swivels For A New Generation Of Fpso Systems
Authors: Drijver F.P. , d'Hautefeuille B.B. , Pollack Jack
Published: October 2008

The use of tanker based Floating Production, Storage and Offloading systems has been restricted due to the throughput and pressure limitations of the multiple swivel assembly, which is the key element of the gas and fluid transfer system of a weather vaning Single Point Mooring system. This paper outlines the state of the art of high pressure swivels, particularly for gas applications. It also describes the development of three prototype high pressure gas swivels. The latest constructed one, is a twelve inch pipe diameter toroÏdal gas swivel with a 1900 mm (75 inch) seal diameter, designed for 30 MPa (4350 psi) and 125°C (257 F). The availability of high pressure swivels with very large seal diameters, enables the single point mooring systems to handle larger throughputs of gas, crude oil and other fluids, while several spare swivels can be included in the stack to increase redundancy and future expansion.

INTRODUCTION

Single Point Mooring (SPM) systems are used for loading and offloading crude oil tankers and for tanker based Floating Production, Storage and Offloading (FPSO) systems. The use of SPM for FPSO application has been restricted due to the lack of reliable large gas swivels due to throughput and pressure limitations. The multiple high pressure swivel assembly designs (figure 1) are today all based on individual stackable toroÏds. This stackable modularity allows for the addition of one or more paths to an existing swivel assembly for expansion reasons and it allows the change-out and repair of a defective swivel without disassembly of the other modules. The toroÏdal modules have a central opening for the piping of above placed swivels. The required size of this opening depends on the number and size of pipes connected to these above swivels. Consequently, the bottom swivels need the largest central openings and have therefore the largest seal diameters. The assembly of a large number of swivels was restricted due to the limited central opening size of the largest available high pressure swivels. High pressure swivels with large seal diameters are, therefore, required to overcome the throughput and pressure restrictions of multi path swivel assemblies, The essential aspect in the design of swivels is the sealing of the product between the relatively moving parts of a swivel. Due to the basic concept of the toroÏdal swivel designs, sealing is required around the circumference of a relatively large diameter. The sealing of small and medium size fluid swivels (up to 1,5 meter seal diameter) is achieved with standard sealing techniques, which have been extrapolated to the swivels' diameters, The standard swivel concept is based on this sealing arrangement and has been proven to be reliable in various tests and many real applications. The sealing of gas, however, is very difficult due to its low viscosity and the risk of fire and explosion in case of leakage.
The Application Of Horizontal Wells To The Troll Oil Development:An Operational Review
Authors: Jacobsen R.I. , Rushworth Philip
Published: October 2008

Under the large gas accumulation of the Troll field lies a significant quantity of oil. However, this oil is contained in thin layers distributed over a wide area and therefore cannot be developed using conventional wells.

In 1988 Norsk Hydro re-evaluated possible development schemes for the oil resource, and concluded that the application of horizontal well technology could provide an economically viable means of developing the resource. Appraisal and development study activities were started which included the drilling, completion and testing of 2 horizontal wells. The success of these two wells confirmed that horizontal well technology could be applied to a full scale development.

The operator evaluated a wide range of development options based on the use of horizontal wells, and prepared a comprehensive development plan. The plan was submitted to the Norwegian authorities in December 1991, approximately 3 years after taking the decision to drill the first well.

INTRODUCTION

Background

The Troll field is located offshore Norway in 300m water depth (Figure 1J. The field is divided into 3 areas, Troll East, the Troll West Gas Province (TWGP) and the Troll West Oil Province (TWOP). The individual areas and the hydrocarbons in place are shown in Figure 2. The oil resources are located in thin layers trapped between large gas caps and an active aquifer; Figure 3 shows a cross section through the 3 provinces.

The Use of Conventional Wells

Development of the oil layers using conventional wells was evaluated in 1985 and 1986. Due to the high permeability and the presence of the overlying gas cap, conventional wells could not sustain sufficiently high oil rates and quickly began to cone gas in increasing quantities. Furthermore, a large number of subsea wells were required to develop the field resulting in unacceptably high costs.

The Use of Horizontal Wells

Studies in 1988 concluded that horizontal wells could be used to develop the oil reserves in the 22-26m oil layers in the TWOP. The principal advantages were perceived to be:Higher oil rates at reduced drawdown thereby minimising oil and water production.Longer production period before gas breakthrough thus providing high initial oil production rates.Higher oil recovery per well with lower cumulative gas production.Fewer wells required and hence lower investment costs.

To support these theoretical conclusions it was decided to drill and production test a well in the TWOP. The success of this well lead to the decision to test a horizontal well in the 12–14m oil layers of the TWGP.

This paper describes the design, planning and execution of the drilling, completion and testing operations with the main emphasis on practical and operational considerations. How the experience gained from the wells is being applied to the full field development is also described.
Subsea Processing System Ready for Gulf of Mexico Field
Authors: Lovie P.M. , Baugus V.E. , Grecco M.G. , Schutter D.S.
Published: October 2008

Use of subsea processing (i.e. subsea separation and Single phase pumping) to produce smaller more remote oil fields has been the subject of field tests and studies since 1969, reported in 9 OTC papers from 1974-1992.

The advance in GLASS [a] is to create a relatively "low tech" and proven solution. Although originally intended for the Gulf of Mexico, it may be applicable in Brasilian, North Sea and other areas. Parallel with the engineering development, composite judgments have been developed for the economic performance for CAPEX and OPEX using recently available probabilistic methods. Connector advances in 1991–1992 may further simplify use of this system design.

Application is relatively insensitive to water depths, e.g. 300–3,000fi. Offset distances from a host platform may be in the region of 5–50 miles. The system was developed for a Base Case in l,500ft. of water with 12,000 bopd initial production with 8 wells from a 25 MMBBL recoverable reservoir, with GORS in the region of 1,000 scf/bbl. Installation equipment comprises the semisubmersible drilling unit and standard offshore service vessels, implying economy and flexibility for use in worldwide application. Hydrate, sand, shutdown and startup operating conditions were addressed.

PRECEDENT SINCE 1969:

The first trials for a subsea processing system were the experiments in 1969-1971 offshore Abu Dhabi at the Zakum field, conducted by BP and Total when they installed a subsea separator and booster pump in about 72 feet of water and operated the system over a three year period, including a year long period when about 1.7 MMBBL of oil was produced. OTC paper no. 1942 in 1974 outlined this pioneering effort.

That prior work was systemized and updated for North Sea field conditions in the GA-SP project (e.g. 30,000 bopd from 4 wells in 984 fl. of water), culminating in full scale prototype trials in a dry doc kin 1990on behalf of eight operators: it was reported in OTC papers 6722, 6766 and 6767 in 1991. This system design used water injection hydraulic power to drive the booster pump, a 4 level component arrangement and a multiple stage subsea separator to provide oil of export quality from a hypothetical arrangement of 4 producing wells with 4 water injection wells, with GORS of about 450. Another series of experiments with a subsea separator was made in live offshore conditions in about 248 ft. of water, near the base of a platform in the North Sea operated by Hamilton Brothers. This test series with the BOET separator design is reported in OTC paper nos. 5922 and 6423 in 1989 and 1990, respectively. It would therefore appear that significant precedent now exists for subsea processing - indicating it is concept whose time has arrived.

ENHANCED RECOVERY FROM REDUCTION IN WELL BACK PRESSURE:

A major benefit of the use of subsea separation and boosting in deep water is that the back pressure on the wells can be reduced and total recovery can be enhanced.
Grid Tensioning System: A New Approach To Deepwater Riser Tensioning
Authors: de Paiva Leite A.J. , Paiva Filho E.F. , Cardellini David
Published: October 2008

The move towards deeper waters for oil and gas production over the past decade, has resulted in higher development costs.

The use of floating structures with surface completion and rigid risers is an attractive approach for development in this scenario.

This paper presents a new riser tensioning concept designed for a so-called "minimum heave" semi-submersible (ref.1). Sixteen risers are connected to a common grid-like structure supported by twelve pairs of tensioners placed around its outer perimeter. Computer based analysis highlights the significant design considerations for this concept and, finally, a comparison is made with individual riser tensioning.

INTRODUCTION

Their small sensitivity to increases in water depth, make floating systems a natural option for deep water hydrocarbon developments On the other hand, the costs of subsea equipment, their installation and maintenance as well as the higher risks involved in subsea completion (sand production, wax formation, leakage control, etc...) pave the way for floating systems with surface completion. This option involves, however, motion compensation and minimization.

The traditional method of providing motion compensation for a large number of steel risers on a floating platform is to provide a separate set (usually four) of tensioner assemblies for each individual riser.

This approach works quite well when the vertical stroke of riser top is limited to around 6 to 9 ft (1.8 to 2.7 m) as in the case of TLP's.

When designing a semi-submersible with dry completion, however, where the stroke can surpass 20 ft (6 m), the wellhead arrangement becomes very complex if individual riser tensioning is to be used.

Other undesirable consequences in this case, are long stroke tensioners of relatively low tension capacity, leading to either unstable, long rod cylinders of normal working pressure, or heavy and costly, low working pressure cylinders of a more stable structural design. Direct tensioning becomes also difficult to accommodate due to the large vertical clearances needed in this case and their quite negative consequences to the platform's stability.

A different approach to supporting a number of risers from the seabed to a floating vessel has been developed. This approach is loosely referred to as the "grid tensioning concept"and is suitable for both semisubmersibles, TLP's or any other type of offshore system where motion compensation/riser tensioning is of concern.

The concept consists of a group of risers connected to a common grid-like structure. The grid itself is allowed to articulate with respect to the vessel, and is connected to it via a series of compensated tensioners arranged around the perimeter of the grid.

The grid is allowed to move vertically within the vessel's moon-pool and to tilt about any axis in the horizontal plane.

The concept was applied to a so-called "minimum heaven semi-submersible (ref.1), where 16 rigid risers are supported by a grid using 12 duplex tensioners.
Design, Construction, And Operation Of A Novel Well Control System
Authors: Marschke C.R. , Wu Nanping , Alcocer C.F.
Published: October 2008

This paper presents the development of a new revolutionary oil/gas well control system. This system has been created to provide effective control and management of oil/gas wells under diverse abnormal situations. The system is versatile in its capabilities and can be used offshore and onshore. The system main/y consists of a cutting tool, a specially designed plug/valve, supporting structures and a power system.

This paper describes the prototype of the new system and the results of laboratory tests simulating the actual conditions of operating oil/gas wells, Actual casing and tubing arrangements were used in the laboratory tests. Finite element Analysis (FEA) and force and stress/strain analysis were performed to design the system and to ensure the integrity of the structure of the well during control operations.

INTRODUCTION

There is an increasing need for systems to be used to fully control wells on fire due to explosion or blow-out, inactive wells where the master valves are not operational due to corrosion problems, and wells where the wellhead has been damaged accidentally during drilling, storms and/or repair operations.

A novel oil well control system has been developed and a prototype has been tested recently. It mechanically blocks the oil path regardless of the condition of the wellhead and/or master valve(s).

EQUIPMENT DESIGN AND CONSTRUCTION

The principle of operation is first to drill through the casing and tubing and then to use the plug/valve system to block the flow of oil/gas and bring the well under control. The system mainly consists of a operation mechanism and a supporting structure. The operation mechanism is mainly composed of a cutting tool, a plug shaft and a hydraulic motor, and the supporting structure includes a yoke and a saddle, as shown in Fig. 1.

Following, are highlighted some design features and the FEA and force and stress/strain analysis, which were performed to determine design parameters to ensure a safe and successful operation.

1. CUTTER/PLUG: The uniquely designed cutter/plug is shown in Fig. 2. It has eight blades and two internal holes. One is for removing the cut material and the other provides a oil path for re-operation. The plug is hardened and tapered. Completely shutting off both the production casing and production tube relies on a metal to metal seal. The pipe material should be sufficiently stressed but not cracked.

A FEA computer software1 was utilized to locate the high stress concentration areas and to find the magnitude of the maximum stress to prevent the material from being overstressed, FEA is a numerical method for stress and strain analysis. It divides a structure into many interconnected elements. Each element has governing equations, force and boundary conditions. With the help of computers, the large amount of equations (with specified force and boundary conditions) are integrated into a matrix form of.
The Advanced Risk Management System: Arms
Authors: Seridji Abder , Pathe-Cornell E.M. , Regan Peter
Published: October 2008

ARMS is a decision support system built to help operational managers hand/e hazardous situations onboard offshore production platforms. It provides the platform operators with an estimation of the risk level at any given time, and of expected changes in the risk level within a specified time window. It also provides guidance for rational risk management decisions within that time window.

DECISION SUPPORT FOR REAL-TIME RISK MANAGEMENT*

The 1988 Piper Alpha disaster, in which 167 men died(165 of 226 onboard and 2 rescue workers) from an explosion and subsequent fire in the North Sea, heightened risk awareness in the offshore industry. The Piper Alpha disaster provided a deep motivation for systematic risk analysis and risk management [1, 2,3, 4].

Risk management involves not only the financial aspects of insurance but also the choice of risk reduction measures, both technical and managerial. In this form, it is one of the best practices for improving the safety of operations onboard offshore oil production platforms. Such a function requires a systematic risk assessment which provides a means to examine and discuss the risk elements in day-to-day activities.

The objective of our Advanced Risk Management System -ARMS [5]- is to facilitate the risk management on site. It allows experienced managers and supervisors to understand the hazards and to control risk more quickly, more thoroughly, and at a lower cost than classical approaches. ARMS analyzes the effect on the risk of three major elements [6]:The offshore organization that runs the platform and its links with the onshore departments.The production activities on the deck (including supervision and control).Basic information from different sources about the facility and its critical components.

The objectives of the system require :Improvement of factual information in order to gather the relevant evidence and present the facts that matter in a synthetic and useful way.Safety supervision of the work process on board : this function requires helping the user identify and overcome incompatible activities within a task and between tasks that are planned to take place at the same time.Risk assessment for potentially hazardous situations and computation of the future risk level for any task within different time windows given the work plan.Decision support and presentation of appropriate recommendations : this function requires judging the acceptability of various risk levels and generating a set of possible risk reduction alternatives. The system must then be equipped to allow reasonable tradeoffs between safety and production. It must also be able to support decisions to gather additional information within short delays so as to prevent the worsening of critical problems.

Therefore, the challenge is to use the available risk information and to generate new information as required to support management decisions. This includes ranking and balancing risks during day-to-day operation of a platform.