bluuebunny/crossref_metadata_2025_split huggingface dataset:
Monitoring of Sand Deposition in Subsea Separators
Authors: Eriksson Klas Goran , Kirkedam Eivind 
Published: October 2008

Abstract
Subsea processing systems for e.g. water removal and reinjection have been in operation for some time, and are being studied for use in several fields.
In many applications, sand handling is a problem. The sand may accumulate in the separator vessel, and needs to be flushed out at regular intervals. As the sand may accumulate anywhere in the vessel, a wide-area sensing system is required in order to detect sand deposits anywhere in the vessel. The SPC (Subsea Processing Collaboration) project has studied such systems, and selected and lab tested two such systems based on thermal methods. A 1 ft wide, 1" high sand heap can be detected anywhere in the vessel. One system is based on measuring the outside temperature of the separator vessel (inside the insulation). Solids inside will cause the outside to cool, which is readily detectable by Pt100 or fibre optic temperature sensors. Another system is based on internal rods located 1" above the separator floor. These contain "hot spots", to which electric power is fed. The temperature increase depends on whether the "hot spot" is surrounded by water or sand. This paper summarizes the work done by the SPC consortium over the last 3 years, discusses a typical process to highlight the performance requirements, describes the work done on the two types of systems selected, and presents the results of lab testing and simulation done to date. Alternate systems are also discussed.

Introduction
Subsea processing systems for e.g. water removal and reinjection have been in operation for some time, and are being studied for use in several fields.
In many applications, sand handling is a problem. The sand may accumulate in the separator vessel, and needs to be flushed out at regular intervals. As the sand may accumulate anywhere in the vessel, a wide-area sensing system is required in order to detect sand deposits anywhere in the vessel. The SPC project (a collaborative effort between BP, ChevronTexaco, ABB and AkerKvaerner) has studied such systems, and selected two such systems based on thermal methods.

A typical subsea separation process
A subsea separation process typically involves one or several gravity separator vessels, possibly combined with cyclones. A sketch of such a system is found below in fig I below.
Figure I Typical Separation Process (Available in full paper)
The gravity based separator vessel we are discussing is highlighted in the figure. It may be fairly large, e.g. 2.5 × 10 meters (D × L) (10 × 30 ft D × L), and have a volume of 50 - 100 m3. The dry weight can be 50 - 100 tons.

The consequences of sand deposits
As sand deposits in the separator, the volume available for fluid decreases correspondingly. If the separator is e.g. filled to 50% with sand, then the effective volume available for fluid separation has decreased to 50% (i.e. the residence time has been halved). The operator would then need to decrease fluid flow to half in order to maintain the residence time. The sand accumulation may thus necessitate a production reduction.
Offshore Salt Caverns Enable a 'Mega' Sized LNG Receiving Terminal
Authors: McCall M. , Davis J.F. , Krekel M.H. 
Published: October 2008

Abstract
The unique and heretofore unknown combination of gas storage in man made salt caverns with LNG importation presents the possibility for LNG receiving terminals with very large storage capacity and gas send out flow rate. In particular, the use of salt formations for cavern development and LNG receiving in the Gulf of Mexico has the potential for offshore facilities combining easy ship access, large storage, and very large send out to the gas pipeline grid. This paper describes such a facility, its components, capabilities, and operating characteristics as well as an overview of some of the design decisions made as the Basis of Design takes form. This offshore facility will be further described in greater detail as a part of a U.S. Department of Energy (DOE) cooperative research project commissioned by the National Energy Technology Laboratory (NETL) and having cost sharing participants from a wide array of energy industry companies.

Introduction
LNG has been a very small part of the U.S. natural gas supply over the last thirty years. Some forecasts project that LNG imports could make up as much as fifteen percent (15%) of future natural gas supplies to the United States. This means that the capability to receive natural gas in the form of LNG, process that gas if necessary and distribute that gas to a gas hungry nation will require a significant increase in capacities throughout the delivery system. Further complicating the large increase in LNG import expectations is the fact that all LNG is not equal. Depending upon the country of origin and the specific liquefaction plant, the LNG produced can have significant variation in composition. Some plants produce LNG at a little over a thousand Btu/scf others far exceed eleven hundred Btu/scf. All LNG is clean and dry, with low sulfur and low CO2, but the variation in gas liquid content provides an opportunity and a challenge for the gas processing industry.
Table for Source, Lean and Rich (Available in full paper)
There are more than forty LNG receiving terminals in the world. They are the same basic design, differing mostly in size. They consist of a dock to moor an LNG ship, cryogenic loading arms for the product transfer, cryogenic liquid storage tanks, LNG pumps capable of achieving pipeline pressures, and some form of heat exchangers or vaporizers to warm the LNG to pipeline compatible temperatures as it leaves the facility. This basic design has not changed since its introduction in Japan where more than half of the worlds LNG terminals exist, see fig. 1 for a tank based process. Significant scale increases have been introduced into the world's LNG business in liquefaction and shipping. Offshore salt cavern based terminals can provide the corresponding scale increases needed in LNG receiving terminals with storage capacity and send-out volumes far exceeding the tank based terminal model.
Floating LNG Production Facility
Authors: Lund Trygve Johannes , Wichstrøm Finn , Pepperell Ray , Sparby Bjørn 
Published: October 2008

Objective
The objective of the study was to prove the feasibility of a floating LNG (FLNG) production facility for the NnwaDoro gas field, to provide solutions for identified problems and to demonstrate that all FLNG related requirements could be met.
This paper will mainly focus on the safety and layout aspects of the study, but includes also the other parts of the work performed by Aker Kvaerner

Process
The study was based on the Linde MFC ® (Mixed Fluid Cascade) LNG Process for the production of 5.8 MTPA LNG plus propane, butanes and condensate in a single process train. The study was performed by Linde and Aker Kværner as subcontractor on behalf of the MOU Team; Statoil, Shell and NNPC.

HSE
For the NnwaDoro FLNG barge the aspects of gas dispersion and gas explosion was considered as key elements when assessing the governing key parameters for the barge layout. The only established type of method to determine dimensioning explosion loads and gas release type and rate is to perform a proper Risk Analysis, calculating both the probability of accidents to occur and the associated consequences. For a Concept Study this is traditionally performed on a coarse level, however, using all the available information in the project at that time. For the NnwaDoro Study the relevant information available was the Process Flow Diagrams, the 3D model, wind data plus the process calculations. In addition to this generally available information was used. A relevant methodology to be used for a Risk Analysis is NORSOK Z-013.
All explosion and dispersion calculations done within this study was sample calculations. It is important not to misinterpret the safety work carried out under this contract as a substitute for a coarse Risk Analysis. However, the gas cloud sizes and ignition points as well as release rates were chosen in order to be conservative. It was our objective to produce a NnwaDoro FLNG design which was robust and able to absorb natural design development during the coming phases without overturning the basic layout. However, the accidental effects calculated were anticipated to be well within the realistic range. In the course of this study the major FLNG related safety issues have been identified, i. e.:Explosion loads within modules and its impact on other SystemsImpact of explosion loads on carrier during side by side LoadingA safety philosophy for the FLNG facility was establishedDispersion studies was performed and the dispersion of gas jet and general ventilation in the process modules was found to be within acceptable limits
SEDCO - 445 Dynamic Stationed Drill ship
Authors: Hammett Dillard S. 
Published: October 2008

Abstract
This paper deals with the design parameters, fabrication and sea trials of the first ship equipped for dynamic stationing having the specific requirements for drilling exploratory wells in open ocean environment.
Design criteria are reviewed with regard to sea state, environment, propulsion requirements and drilling performance, including automatic control and sensing systems. Model studies and dynamic simulation analyses are presented and compared with the results of early sea trials. Operating systems are summarized, and performance expectations are related to prospective utilization of the vessel in specific ocean areas. Preliminary conclusions are given with respect to vessel response to control and propulsion parameters.

Introduction
The trend in offshore exploration clearly indicates that the Oil Industry must extend its search for oil and gas into water depths beyond the continental shelf. The need for additional oil and gas reserves; and the belief that sizable reserves could indeed exist in greater water depths have encouraged interest in deepwater exploration. This deepwater exploration has resulted in the need for new techniques and tools for water depths of 2,000 feet and greater.
Royal Dutch/Shell Group, with their established world-wide interest in offshore exploration and production and their technological achievements in the offshore environment, has taken a natural step to undertake early development of drilling techniques and tools to explore in the deeper waters.
Extensive study of exploration objectives and research into the means of achieving these culminated in Royal Dutch/Shell engineers drawing up comprehensive engineering specifications for a highly mobile drill ship. Early in 1970, the drilling contractor, SEDCO, Inc., was engaged to design, construct and operate the drilling unit, now known as the "SEDCO 445." At the same time, Royal Dutch/Shell and SEDCO engineers undertook detailed final development of advanced forms of dynamic stationing and underwater drilling equipment. The major limiting factors to existing offshore exploration drilling are the anchoring capability and the underwater drilling equipment system.
A specially designed ship equipped with dynamic stationing has the capability of anchoring in unlimited water depths. The use of new techniques such as Electro-Hydraulic BOP controls; acoustical re-entry; and riser buoyancy increase the capability of the underwater drilling equipment system to something greater than 3,000 feet.
An Overview of More than One-Hundred-Twenty Horizontal Gravel Packing Operations In Campos Basin
Authors: Marques L.C.C. , Calderon A. , Chagas C.M. , Fernandes L.H.C. , Pedroso C.A. , Neumann L.F. , Rocha J.D.H. , Paixão L.C.A. , Barbosa V.P. , Pereira A.Z.I. 
Published: October 2008

Abstract
This paper presents the lessons learned by Petrobras after performing a total of 124 horizontal open hole gravel-packing operations in Campos Basin. The authors intend to describe how the industry-provided standard gravel packing procedures had to be continuously improved and/or adapted to meet Campos basin requirements, such as: -low fracture gradients, - long intervals to be packed, -pumping jobs performed from floating rigs and -the need to sustain high production levels - or high injection rates - to justify the huge amount of investments associated to ultra-deepwater production enterprises. It is also described the main technology innovations that were incorporated to our completion projects in the last few years. Among these innovations one can find: - modified standard tools to reduce pumping pressures, - external casing packers, -inflatable straddle packer to divert post-gravel treatments, -pressure reducer valves, - - flowline's flow meter and shunt tubes. Formation damage in gravel packing operations is addressed on a comprehensive basis, encompassing the following items: -drill-in fluid rheological specifications, - pre-job wellbore cleanup procedures, - optimizing drill-in-fluids mud cake removal, -job design and execution, gravel carrier fluids filtration requirements, -postjob remedial treatments and diversion techniques as well.

Introduction
The most prolific reservoirs in Campos Basin are Tertiary and upper Cretaceous unconsolidated turbidites that require a sand control/exclusion method either to maximize sand-free production or to manage massive water injection to provide reservoir pressure maintenance. Therefore, from the firstdiscovered oifields in shallow waters to the large ones more recently discovered in deep- and ultra-deepwaters scenarios in Campos Basin, emphasis has been placed on total sand exclusion well completion techniques.
Prediction of Spar Responses: Model Tests vs. Analysis
Authors: Steen A. , Kim M.H. , Irani M. 
Published: October 2008

Abstract
The DeepStar Program has sponsored a series of tasks to evaluate the current industry capability in predicting the responses of deepwater theme structures (FPSO, TLP and SPAR). In its Phase IV program, model tests of the FPSO, TLP and SPAR were conducted, and in the Phase V program, engineering companies as well as test basins were invited to evaluate the correlations between the tests and analyses.
This paper presents an overview of DeepStar's effort with emphasis on Spar responses. It covers the following areas of response predictions:Model test setup and test conditionsThe state-of-art analytical tools available to the industryEvaluation approachKey results of comparisons - tests vs. analysesSensitivities and uncertainties in predicting Spar responsesAssessment of current industry capabilitiesAreas of future effort

Introduction
Model tests were conducted November 2000 in the new offshore basin of the Maritime Research Institute Netherlands (MARIN). The objective of the tests was to assess global responses of floaters, with emphasis on the effect of mooring line and riser dynamics in deeper water. These tests included a TLP, Spar and FPSO.
During the early part of last year, industry participants of the DeepStar Program were contracted by Det Norske Veritas (DNV) to analytically model the tests using their in-house programs. This paper presents results of that effort for the spar platform conducted by the authors. Modeling particulars and applied computer programs are presented. Test results and predictions are tabulated and shown graphically. Overall, there is good to excellent agreement between predictions and test measurements.

Model Tests
A brief description of the applied test facility, model and test particulars are given herein. Details may be found in references 1 and 2.

Test Facility
The MARIN deepwater test basin is 10.5m deep and 45m × 36m in cross section. Multi-flap wave generators on two sides can produce long-crested or short crested waves up to 0.4m with periods of 0.3 to 3.0 seconds, model scale. Current can be generated over the full basin depth with a vertical profile. Wind spectra are produced with electrical fans on a free moving and position-controlled platform.

Spar Model
Spar tests were conducted with length scale factor 1:87. This simulated a water depth of 913.5m. The spar model was a "classic" spar which is a vertical steel cylinder supporting topside facilities and a centerwell for top tensioned risers. The full-scale hull depth was 214.9m with a 198.1m draft and 37.2m diameter. The deck length, width and height were 65m, 65m, and 27.1m, respectively, with a vertical cg 241.7m above the spar keel. Mass properties, including adjustments to KG and GM for entrained centerwell water are given in Table 1. A sketch of the spar with mooring and risers is given in Figure 1.
Table 1 Spar Mass Properties (Available in full paper)
Subsea System Design for the HPHT Kristin Field Development. Thermal and Pressure Loads.
Authors: Hundseid Jan , Flaten Gunnar 
Published: October 2008

Abstract
The HPHT field Kristin is located 16 km south west of the Åsgard field in the North Sea. The reservo ir has a temperature of 170°C and a pressure of 911 barg. The field will be produced by pressure depletion from four subsea templates tied back to a dedicated floater. Kristin is the first subsea HPHT field development. First production will be autumn 2005.
The production lines, flexible risers and the topside process are protected by three separate pressure protection systems including a subsea HIPPS system. Direct electrical heating will be installed for the production line as the main hydrate control measure. For the design of the subsea system and the operational procedures for the system, special attention must be given to the high temperature and pressure. The high and low temperatures imposed on the production system by the producing fluid during normal production, shutins, restarts and operational/system failures make the design challenging.
This paper will give an overview of the flow assurance work. The design and operational consequences of the high pressure and temperature loads on the wells, templatepiping, production lines, electrical cable and flexible riser are presented.

Introduction
The Kristin field is located offshore approximately 160 km from the Norwegian coast in the Haltenbanken area. It is a gas/condensate field with estimated recoverable reserves of 42 billion Sm3 of gas and 35 million Sm3 of condensate. The gas will be exported through the 700 km Åsgard pipeline to Kårstø for onshore processing. The condensate will be sent to Åsgard C for storage and offloading. Production start -up is planned October the 15th 2005.
Figure 1 Kristin field (Available in full paper)
Figure 2: Kristin field location (Available in full paper)
The Kristin field is a high pressure and high temperature (HPHT) field2. The producing formations Garn and Ile are located 4500 m and 4850 m below the seabed. The Ile formation has the highest reservoir temperature and pressure of 169°C and 911 bar. The Garn formation has a temperature and pressure of 164°C and 894 bar respectively. The field will be produced by pressure depletion.
The Kristin field is the first HPHT field to be developed subsea. There will be 12 subsea wells and four templates (see Figure 3). There will be four wells at template R and S and two wells at template P and N. Six 10" ID flowlines will transport the produced fluid to the Kristin semi; two flowlines each from template R & S and one flowline each from template P &N. The flowline lengths vary between 6 and 6.8 km. Flexible risers with a length of approximately 700 m connect the flowlines to the process facility on the semi. The water depth on the field varies between 315 and 375 m. The design rate for the flowlines is 4 MSm3/d of gas. Depending on the flexible riser arrival temperature, the production can be increased to 5 MSm3/d. The receiving facility is a semi submergible roduction unit.
Application of Experimental Design in Selecting a Development Plan for the Agbami Field
Authors: Spokes J.J. , Ovuede M.A. , Ginger E.P. , Narahara G.M. , Haga Olav , Gontijo Julio 
Published: October 2008

Abstract
The Agbami project team was challenged to generate a field development plan and to assess that plan over a wide range of uncertainty. Complete stakeholder alignment around the technical aspects of the development plan was a critical issue.
Field data, laboratory data, and analog data were incorporated into a range of reservoir simulation models. The field data included appraisal well logs, cores, 3D seismic, fluid samples, pressure data, and drill stem tests. Three hundred reservoir models were constructed and ranked using streamline simulation for both static and dynamic attributes to assess the range of subsurface uncertainty.
A project team with significant but diverse deepwater development experience was formed and co-located. A formal phased decision making process was implemented. During each phase of the process key parameters of uncertainty were identified and ranked in terms of project impact. Field development options were evaluated in distinct phases over the full range of uncertainty.
Experimental Design (ED) methodology was used throughout the evaluation to obtain the maximum information with the minimum computational effort. The paper shows how the results from this process facilitated the identification of the key uncertainties and provided direct input into economic models for decision analysis.
In Phase Two of the evaluation the pressure maintenance scheme selected for the 17 million year (MY) reservoir was crestal gas re-injection with peripheral water injection. Crestal gas re-injection was selected for the 14MY and 16MY reservoirs. The facility capacity requirements were also selected during this phase at 250,000 stock tank bbl of oil per day (STB/D) and 450,000 thousand standard cubic ft per day (Mscf/D). Peer reviews and assists were held and alignment was obtained along with action items to be included in the subsequent phase.
In Phase Three of the evaluation the well count parameter was investigated and an optimum number of 38 wells was selected. Production profiles were generated and presented in terms of P10, P50, and P90.

Introduction
This paper will focus on the application of Experimental Design (ED) during Phase Three at Agbami. With drilling depths of up to 10,000 ft below mudline in 4,800 ft of water, well costs at Agbami are at the high end of typical deepwater costs. Therefore, the number of wells including their type and location is an important optimization parameter in the field development plan. The probabilistic forecast of all produced and injected fluids is also a key deliverable of the field development plan.
Agbami project stakeholders are aligned on all technical aspects of the field development plan and the project is rapidly proceeding toward sanction and awarding of major contracts.