bluuebunny/crossref_metadata_2025_split 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

ABSTRACT
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

ABSTRACT
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

ABSTRACT
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

ABSTRACT
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

ABSTRACT
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

ABSTRACT
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

ABSTRACT
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

ABSTRACT
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].