bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Booster Station: Results Of Extensive Testing And Post-Test Inspection
Authors: Cotton J.L. , Stinessen K.O. 
Published: October 2008

ABSTRACT
The complete Kvaener Booster Station has undergone extensive underwater testing in its test tank in the two-phase laboratory at Tiller, Trondheim, Norway.
The whole range of steady state performance testing up to 11 000 Barrels/Day of liquid and/or 7.0 million SCF/Day of gas has proved the basic concept.
Additionally, significant development of the process control system has resulted in understanding and excellent control of both upstream slug flow and pressured low variations from a simulated well scenario and also the downstream pressure/flow variations representing long, undulating flow lines followed by a riser. Handling of foaming fluids has been achieved, including exceptional foam into the compressor.
The paper presents a brief description of the KBS, the test facilities and the results of the testing. It considers the implications to the user/operator, together with the conclusions from the post-testing inspection.
The Kvaener Booster Station is now considered to k qualifield for use on a subsea application.

BRIEF DESCRIPTION OF THE BOOSTER STATION.

General
The function of the KBS is to increase the pressure in a flowing hydrocarbon stream. As such it is a multiphase pump. The KBS however, separates the flow into a pumpable liquid and a compressible gas. The two phases are then increased in pressure in separate pump and compressor, both electrically driven, and both using known and proven technology. The resulting streams at higher pressures can then be recombined into one flowline or sent in two separate flowlines to the receiving facility. The KBS is divided into three main modules; separator and cyclone scrubber module, pump module; and compressor module. These can be individually sized and configured to suit the application. Figure 1 is a cutaway section of the first KBS, which has a nominal capacity of 10000 Barrels/Day of liquids and 12000 ACF/Hr (or approximately 4.5 million SCF/Day) of gas. The whole KBS tits inside the standard API guide-post spacing, is about 12 meters (40 fi) high and weighs about 50 tonnes as shown in figure 1.
The modules are mounted one above the other with the pump at the bottom, the separator in the middle and the compressor at the top.
Although the KBS at first sight seems complex, it is in fact very simple compared to similar topsides equipment and even the apparently simpler multiphase pump, when all auxilliary equipment has been added. All non-essential equipment has been eliminated. The remaining equipment has been configured in detail by some of Europe's leading suppliers. Only through these routes has it been possible to build in the necessary level of inherent reliability. Maximum use has been made of the subsea environment of water under pressure, and the fact that it is inaccessible.
Evaluation Of Leg Damage Risk For Jackups Going On Location
Authors: Smith I.A.A. , Frieze PA. , Lai P.S.K. , Lewis T.C. , Miller B.L. 
Published: October 2008

ABSTRACT
The objectives and procedures of a recently completed joint industry project (JIP) examining jackup behaviour during touchdown are briefly described. Aspects covered include motions analysis, spudcan-soil behaviour, dynamic impact analysis, leg structural capacity and risk calculations. lhese features ha ve been incorporated in an analytical program, GMIMPACT, intended for use on-board jack-ups.
The emphasis in this paper is on describing the results of the work as they relate to the limiting seastates applicable to a typical jack-up manoeuvring onto location. The variables which were considered were leg length, wave height and period, touchdown operation duration and seabed type.
The paper demonstrates that, by consideration of site specific conditions, the time waiting on weather to move onto or off location can be reduced in a number of circumstances.

INTRODUCTION
A Joint Industry Project (JIP) has been carried out to investigate the behaviour of jack-ups during touchdown. This work comprised two phases and has been undertaken with the dual aims of increasing safety and of reducing weather downtime.
Existing guidance on touchdown is of a very limited nature, the decision as to whether or not to proceed with the operation often being determined by the adoption of a universal limiting significant wave height (typically 5ft).
In addition to a comprehensive set of analytical results, the main product of Phase 1 of the JIP [11 has been a computer program which enables the user to specify details on rig type, soil type, water depth and wave height and provides guidance on risk to assist in the decision making process. Output is in the form of a table showing the percentage probability of leg overstress for various wave periods and directions.
Phase 2 of the JIP extended the work to examine the safety of jack-ups moving onto location in close proximity to a fixed structure - for example in tender assist or workover modes. This work has considered the likelihood and consequences of an impact between a spudcan and the fixed structure as the rig prepares to touchdown.
This paper briefly summarises those aspects of Phase 1 which have already been published [2,31 and then concentrates on explaining the basis for estimating the risks involved in touchdown operations and presents the results of the work.

OBJECTIVES AND PROCEDURE
In attempting to define a basis for proceeding with touchdown, the main criterion is to ensure that the risk of exceeding the leg structural capacity is not unacceptably high. The approach adopted involved the following aspects:Jack-up motions afloatSeabed-soil characteristicsDynamic impact response (finite element analysis)Leg structural limitationsDetermination of probability of exceedance of allowable leg loads.Development of an analytical computer program, combining all the above aspects and providing estimates of risk.
Troll Sealtubes: Deepwater Innovation In Pipeline Tie-Ins
Authors: Thomson Brian , Kalvenes B.K. 
Published: October 2008

Abstract
The Troll Phase 1 development in the Norwegian sector of the North Sea includes a unique pipeline tie-in system. The field is situated in 303 metres water depth. This has resulted in a system concept which combines the facility of a Gravity Base Structure (GBS) dry riser shaft and a diverless pipeline pull-in method. The system offers a simple and cost effective tie-in method which enables construction of several pipelines within the 1995 season.
The critical interface between the GBS and the pipeline is the SealTube System. The SealTube penetrates the GBS riser shaft wall and provides the conduit for the pipeline pull-in phase.
This paper details the design and the development aspects of the SealTube System.

Introduction
The Troll Gas Field has recoverable gas reserves of approximately 1250 billion cubic metres.
Since the Troll Field was declared commercially viable, more than 80 development concepts have been considered. The production concept adopted for Troll Phase I comprises a platform with limited gas treatment facilities (i.e. free water removed) supported on the worlds tallest GBS; two 36" pipelines for transport of the multiphase gas, to shore an onshore processing plant, and a 40" pipeline for dry gas export to Europe. The platform is located 65 km from the landfall area.
The selection of the GBS recognised the significant track record provided by the Norwegian Offshore Industry in the design and manufacture of concrete structures.
It allows the opportunity to effect a conventional welded pipeline to riser tie-in within a dry riser shaft environment. This removes dependence on expensive deep water welding or connection methodologies. The pre-installation of extra risers and SealTubes also provide back-up for the planned construction and additional pipeline tie-in options for the future. The cost effectiveness of the tie-in system is further enhanced by the removal of diving support requirements from the Marine Support Vessel (MSV) which is utilised to provide construction assistance for GBS preparation and pipeline tie-in phases. Remote Operated Vehicles (ROV's) are utilised from the MSV but primarily for monitoring purposes. The tie-in equipment and subsea packages are designed for deployment from, and remote operation on, the MSV.
The pipeline pull-in operation will be achieved using a platform topside winch which will deliver the pullhead and pipeline into the prepared SealTube. The pull-in cable is run from the SealTube to the winch through an 8" diameter pull tube. The pull tube terminates above sea level thus ensuring the GBS riser shaft can remain dry during the pull-in. The laybarge will lay down the pullhead in a target area then continue to deliver pipe while remaining in a fixed position until the pipeline is pulled inside the SealTube by the winch. The pipeline will then be laid approximately 10km to provide sufficient stability for the SealTube related activities to commence.
Development Of Cost-Effective Diverless Tie-In System For Troll Oil
Authors: Halle P.O. 
Published: October 2008

Abstract
A new type combined pull-in and connection system has been developed for the Troll Oil field Development in the North Sea.
At Troll Oil, satellite wells are spread out in a wide area and tied back to the floating production unit by flexible flowlines and umbilicals via manifolds and a riser base. For the 1st phase of the development more than 120 diverless tie-ins of flowlines and umbilicals are required, 2nd phase will require an additional 150 tie-ins. All pull-in and connection operations will be made diverless at a waterdepth of 325m (1OOO ft).
To perform these tie-in operations in an efficient manner the need for a new tie-in system was required.
The tie-in tool PICT is based on subsea pull-in wire establishment, horizontal pull-in and a hinged clamp connector. The system is made to be flexible related to laying method, installation sequence and reversability. This tie-in system represent a new generation of tools which can be further developed for very deep waters.
This paper present the Troll Oil tie-in system and what considerations were made to make the system optimal related to cost and operability.

Troll Oil Field Development
The Troll field is one of the largest gas fields offshore in the world, located near the west coast of Norway at a depth of 325 m (1000 ft). Below the gas there is a thin oil layer. By using horizontal drilling this oil can be developed. The gas in the field is sold and is under development. To produce the oil the gas pressure is required. Troll Oil project had to be developed fast and with a lot of wells spread out in a wide area.
The subsea production system consists of single well satelites tied back to 6 or 8 slots manifolds with gathering lines via a riser base to a floating production unit (FPU). Between the satelites and the manifolds there are one 6" or 8" flexible flowline and one steel tube integrated service umbilical (ISU). Between the manifold and the FPU there are 2 × 9" or 2 × 10" flexible gathering lines and one main ISU. All gathering lines are connected at the riser base to dynamic risers.

Troll Oil Tie-in System Development Schedule
The design of a combined pull-in and connection tool started back in 1991 based on the experience gained on the Troll Oseberg Gas Injection Project (TOGI). Late 1992 basic engineering studies were performed at Troll Oil for the operator Norsk Hydro as. Summer 1992 the tie-in contract were set out. Testing of the first Pull-in and Connection Tools (PICT) started summer 1993 which were followed up by system testing tie-ins at the Production Riser Base, Manifold Centers and the Sattelites/Permanent Guide Bases. Summer 1994, first tie-in operations offshore will be performed. Production start up of the field is scheduled for january 1st 1996.
Variable-Stroke Drilling Mudpump:: A Concept To Meet Future Requirements
Authors: Figenschou Arild , Haughom P.O. 
Published: October 2008

ABSTRACT
A new generation drilling mud pump has been designed and full scale prototype tested. The test program has confirmed the feasibility of the new concept and the special features.
The pump, which is a piston pump, controls the pumped flow by changing piston stroke rather than speed and therefore eliminates the need for SCR systems.
A membrane prevents the drilling fluid from coming into contact with piston. and cylinder, thus eliminating the liner wear problem.
The pulsation in mud discharge is reduced and at constant frequency independent of flow creates an ideal condition for turbo drills and MWD.

INTRODUCTION
This paper presents design and results from a full scale prototype test of a new generation drilling mud pump made by Tonstad Maskin A/S in Norway.
The new drilling mud pump is the result of five years R&D including one year of full scale testing. The background for the development was the perceived need to eliminate some of the drawbacks of the classical mud pumps, to increase efficiency and reduce downtime.
Typical problems previously encountered were:Liner wearThe need to change liner dia to accommodate pressure / flow rate during drilling operationThe irregular pressure pulsation in the dischargeThe power supply based on SCR controlled DC motorsWeight and space requirements
The fill scale prototype mud pump and a 1000 hours test program were partly financed by Norske Shell A/S, Esso Norge as, Norsk Hydro as, and BP Norge a.s.

DESIGN PHILOSOPHY
The pump is a star configured piston pump with variable stroke. Stepless variation of stroke from zero to maximum. The powering / transmission system is based on AC electric motors running on constant speed. The pistons are working in hydraulic oil. A rubber membrane with equal pressure on each side separates the mud from the hydraulic oil. The mud valves are standard type, but built as a modular system for quick change out and maintenance. Keep dimensions small (max. breadth 3000 mm). Keep the pump and the operation of the pump extremely simple and rugged, with a target of 5000 hours maintenance service free.

DESCRIPTION OF CONCEPT

Basic Principle
The basic operating principle of the pump as shown in figure 1.0 is to have a piston pump with variable smoke. This gives the possibility to run on constant speed whilst controlling the flow. As a consequence of the constant speed, the pump can be directly powered by AC motors. To reduce the liner wear the pistons are working in hydraulic oil. The mud is separated from the hydraulic oil by a membrane in the pump chamber.
The base arrangement of the pump is quite similar to the star configured engines having the crank shaft in center and the cylinders extending radially around the circumference. Two mud pump configurations have been designed, a three piston and a five piston pump.
Offshore Dehydration Of Natural Gas: An Evaluation Of Alternatives
Authors: McKee R.L. , Foral A.J. , Meyer H.S. , Gamez J.P. , Stern S.A. 
Published: October 2008

ABSTRACT
Traditionally dehydration has been a triethylene glycol (TEG) unit utilizing a 4-8 tray absorber with bubble cap trays. These units work well and are relatively inexpensive. However, there has been an increasing concern about hydrocarbons emission from the vent gas and produced water over the last few years. The hydrocarbons of greatest concern are benzene, toluene, ethyl benzene, and xylene (BTEX). Units can be added on to mitigate the emissions but they take up extra space and weight which is expensive offshore. Therefore, there is an increased interest in decreasing the cost and size of conventional units or finding an alternative process that is less expensive. Under Gas Research Institute contract a survey of a number of offshore producers to determine present practices was conducted. Several absorber alternatives and/or modifications for conventional TEG units were compared with a hypothetical membrane unit for dehydration of 75 mmscfd of natural gas at 1000 psia and 100°F. Although commercial membrane units are not yet available a "good" hypothetical unit was compared because of its advantages of simplicity and lack of emissions. The membrane unit, however, was not found to be competitive. A TEG unit with a Higee? absorber was found to have a slight advantage over more conventional trayed and random and structured packing absorbers after taking into account the effect of size and weight as well as initial cost.

SURVEY OF OFFSHORE PRODUCERS
A survey of seventeen offshore producers was performed to generate the following information: (Foral, 1994)Present offshore dehydration practices;Level of industry concern over emissions; andA design basis that would be typical of Gulf of Mexico offshore operating conditions.
Eleven companies responded to the survey indicating that the most commonly employed dehydration process used was TEG dehydration with bubble cap trays. In evaluating alternatives, most respondents reported that savings in size and weight were considered important. The savings in size (footprint) was considered somewhat less important than weight. The level of reliability required for offshore processes was reported by most respondents to be in excess of 95%. Before an alternative process would be considered for offshore use, the consensus of the respondents was that:The unit size should be no larger than existing units with equal performance.There should be a history of successful operation for a period of at least 1-3 years.Materials of construction should be compatible with the offshore environment.
Most of the companies indicated that environmental regulations of the emissions of BTEX and other VOC from offshore sources require research and development to develop new technology.

BASIS OF EVALUATION

Operating Conditions.
The operating conditions chosen for sizing the units were:A flow of 75 mmscfd at 1000 psia and 100°F.The gas was assumed to be methane saturated with water.A fuel gas usage equal to 3.4% of the feed at 135 psia.
Evolution Of Subsea Production Systems: A Worldwide Overview
Authors: Hansen R.L. , Rickey W.P. 
Published: October 2008

ABSTRACT
The evolution in the use of subsea technology has seen advancement -from I well in the Gulf of Mexico in 1961 to over 750 wells in a tide variety of locations by the end of 1993. Along with the growth in numbers, the industry has seen rapid advances in technology, distances from the host facility, and water depth records. This paper gives an overview of the evolutionary changes in subsea applications, with emphasis on the most active regions, and some of the milestone installations that shaped the technology advance.

INTRODUCTION
In the 33 years since the first subsea well was completed in the Gulf of Mexico in 1961, the use of subsea wells has spread to most offshore producing areas of the world, as shown by Figure 1. By late 1993, a total of approximately 752 subsea wells have been completed worldwide, with over 440 of these wells still in service. This paper will provide an overview of subsea technology development by focusing on three areas which exemplify the technology used worldwide:The Gulf of Mexico and West Coast of North AmericaThe North Sea andThe Campos Basin of Brazil.

SUBSEA TECHNOLOGY OVERVIEW
Subsea wells have been used in a variety of configurations. Typical arrangements shown by Figure 2 include single satellite wells consisting of subsea trees situated on their individual guidebases; subsea trees located on steel template structures with production manifolds; and clustered well systems which are single satellite wells connected to a nearby subsea manifold. These various design layouts and hybrid arrangements of them are usually produced back to platforms or to floating production vessels, although some have also been produced to shore. Over 50 floating production systems (FPS) have been deployed worldwide, with over 30 currently active.
Maximum water depth experience of subsea wells has reached 2562 feet in the Campos Basin and 2245 feet in the Gulf of Mexico. Figure 3 shows the water depth experience range for worldwide subsea wells. The deepest production experience to date is the Aquila extended well test by Agip in 2788 feet of water in the Mediterranean in 1993. Maximum producing distance to the host facility is 30 miles for a gas reservoir and 12 miles for an oil reservoir, both in the North Sea. Most subsea wells have produced by natural flow, but over 110 wells have been produced by gas lift. Pressure maintenance with subsea water injection wells is used where needed.
Well servicing or workovers can be performed using reentry from a floating drilling unit or jackup, Also, specialized techniques such as through flowline (TFL) operations can be performed downhole by pumping tools from the surface host facility through the flowlines and down the tubing. Chemicals can be pumped into the formation through the flowlines, and chemicals can be injected into the subsea tree or downhole by pumping from the surface host facility through hydraulic hoses in the subsea control umbilical. Pressure and temperature can be monitored at the tree or even downhole.
Marlim-4: A Subsea Production Well Overtaking Deepwater Frontiers-Part Ii-Completion Work
Authors: Dias Ronaldo 
Published: October 2008

ABSTRACT
In order to bring into production Brazilian most prolific offshore fields, all of them situated in water depths beyond 400 m, Petrobras, the Brazilian Oil Company, has developed a simple, reliable and cost effective Guidelineless Wet Christmas Tree, designed for applications up to 1,000 m (3,281 ft) water depth]. After installing 16 such trees in Campos Basin, at a maximum depth of 781 m (2,562 ft), the Company faces the challenge of putting onstream Marlirn-4, a well at 1,027 m (3,370 ft) water depth, in the south area of the Marlim Complex. In addition to its strategic role in the Company's endeavor to produce from increasingly deep waters, Marlim-4 will also establish a new world record for subsea completions. This paper presents a brief summary of Marlim's development plan and describes the activities programmed for Marlim-4' s completion.

INTRODUCTION
Since the first oil strike in Campos Basin, back in 1974, Petrobras has been setting several milestones in the Offshore Industry, developing new production system concepts and improving subsea equipment design. Every achievement attained through these years was based on four major principles: careful planning, feedback from field experience, intensive research and courage to take risks.
As exploratory work went on, hydrocarbons accumulations were discovered in waters deeper than ever before, pointing out the necessity to upgrade the available technology to produce the newly-found areas.
From 1984 on, giant fields, such as Albacora and Marlim, were spotted in ultra-deep waters, representing a challenge harder than the previous ones. To cope with the difficulties of the new enterprise a step by step development plot has been chosen, aiming to get technological capability for fill recovery of the existing reserves, placed in water depths ranging from 400 m (1,312 fl) to 1,000 m (3,281 ft). Looking back at the outstanding success accomplished in the last years, one can easily confirm that this was the right strategy to be followed: 219 WCTS have already been installed in Brazilian's continental shelf and technology to produce wells up to 1,000 m (3,281 ft) is completely dominated, despite the capital constraints suffered by the Company.
Nowadays, an outlook of the two most important offshore provinces in Brazil, Santos and Campos Basins, shows that the future lies in waters even deeper, what imposes the need for another strategy to be defined in order to reach anew target. The experience gained during the development of the Marlim Pilot System has showed that the installation of an early Floating Production System pays, even in deep waters. It is a good manner to pave the way to master new technologies, anticipating oil and gas production and collecting reservoir data that can help to minimize the uncertainties related to geological aspects and production mechanisms, thus increasing the chances of success and decreasing the risks involved.