bluuebunny/crossref_metadata_2025_split huggingface dataset:
Use of a Dropped Dynamic Penetrometer in Cohesionless Soil.
Authors: Orenberg Peter , True Daniel , Bowman Lora , Herrmann Herbeft , March Robert 
Published: October 2008

Abstract
The U.S. Navy has developed a dynamic penetrometer called the expendable Doppler Penetrometer XDP) to determine in situ soil stren@. The XDP was originally designed to provide an undrained shear strength profile in SOR cohesive sediments by measuring the instantaneous velocity of a sound source probe as it falls through the water column and penetrates the seafloor. The Navy recently has added and verified a capability to determine strength properties of cohesionless soils.

Introduction
Seafloor characterization is an ever-present need and challenge in the ocean engineering world. In situ soil strength is a vital aspect of seafloor engineering in the offshore environment. However, determining this soil strength is very time consuming and expensive with present conventional methods. The expendable Doppler Penetrometer (XDP) was developed to aid in satisfying the Navy's continuing need for expeditious means for seafloor characterization. This dynamic penetrometer was originally designed to provide undrained shear strength profiles by measuring its deceleration as it penetrates the seaftoor after falling through the water column. The Navy recently has added the capability to determine the strength of cohesionless soils. Controlled laboratory tests were conducted simulating XDP deployments in a highly dense, completely saturated cohesionless soil. The results of these tests were used to formulate relationships to determine the relative density and undrained angle of internet friction of cohesionless soils from the XDP. The results of the laboratory tests and the newly developed relationships are presented. These new relationships were used to estimate the soil strength of two field sites, one a calcareous sand site offshore Key West, FL and the other a dense quartz/mineral sand offshore Biloxi, MS. The results from the XDP tests and an established in situ test, the piezocone, at these field sites are presented and conclusions are drawn regarding the capability of the XDP to measure soil strength in cohesionless soils.

Expendable Doppler Penetrometer Features and Use
The expendable Doppler Penetrometer (XDP) system (fig. 1) is designed to determine the soil strength of various types of ocean seafloors. The system initially measures the instantaneous velocity of a probe with a sound source as it free-falls through the water column and penetrates the seafloor. Utilizing the Doppler Shift principle whereby the apparent frequency is a direct function of the probe's velocity away from a receiving hydrophone, the velocity of the probe is determined up through the point that it comes to rest in the seafloor. The velocity-time curve that is produced enables estimates to be made of the undrained shear strength ofcohesive soils and the penetrability of seafloor soils in general.
The XDP probe (fig. 2) is a hydrodynamically shaped body made of aluminum and steel. The probe has a body of diameter of 3.5 in. and weighs 59.8 lb. in air and 47.6 lb. in sea water.
Use of Decision Risk Analysis in Selecting Field Development Options A Case Study: Alba Field Phase II
Authors: Ahmetf S. , Murphy S.J. 
Published: October 2008

Abstract
This Paper describe show a Decision Risk analysis approach has been used to develop an optimum solution to complete the Alba Field development. In particular this covers the process adopted and the utilisation of a series of tool which give a formal stucture to the work conducted.
The process described has been applied to derive a Development Plan for the concluding phase of a two phase project. Examples are given of how the methodology allows resources [o be allocated 10dlfferenl work areas priorities are defined by the lmpact on project value of reducing uncertainty in a given variable.

Introduction
The Alba Field is located in Block 16/26 of the UK Continental Shelf. lying about 130 miles north-east of Aberdeen III 138 metres of water The reservoir IS a long, narrow Eocene sandstone deposit located at a depth of approximately 6,3W' TVDSS. The field was discovered by the 16/26-5 well in 1984 A phased development was selected in 1990 because of uncertainties in the geology, reservoir performances and the processing of the Alba produced fluids. The scheme allows experience horn the first phase to be used to optimise the second phase. A development schematic is shown in Figure 1
The Alba Field Development Plan contained a commitment to a two phased development. phase 1 came on .stream in January 1994 and comprises the Alba Northern Platform (ANP), We Alba Floating Storage Unit (FSLJ). and drilling encompassing the Northern half of field reserves. Phase II was outlined as an Ah Southern plateform installed 5 years after ANP with a I March 1999 first oil..
Since Development Plan approval, a downwards shift in crude price projections led to a rethink over Southern Area development options.
Conceptual studies commenced in July 1993 to investigate a range of options for exploring the reserves in the southern portion of the field. The objective was to recommend a preferred development option. A Decision Risk Analysis methodology provided a defined process leading up to project approval A process comprising four discrete stages was adopted as shown n In Figure 2Framing the problem by agreeing the details of what is to be studied and the decision making criteriaDeterministic analysis to identify key project drivers.Probabilistic analysis to compare strategic options,Appraisal of results leading to a final development option decision.

Decision Making Process
Decision Risk Analysis is a systematic process, with intermediate reviews that ensures quality decisions, it helps expose the Project uncertainties and quantifies their impact, It also allows us toEvaluate a range of strategic alternatives from a business and tecfudcaf perspective.Effectively Incorporate and understand project risks and rewards.Determine a course of action that balances project risk with project value.
The 3 Column TLP - A Cost Efficient Deepwater Production and Drilling Platform
Authors: Murert Jan , Flugstad Per , Greiner Bill , D&apos;Souza Richard , Solber Inge C. 
Published: October 2008

ABSTRACT
Worldwide, operators are focusing efforts on deep water prospects in their search for new oil and gas discoveries. In the US Gulf of Mexico, Tension Leg Platforms (TLP) are drilling and producing in 800 meters water depth and developments in even deeper water are underway. Current TLP technology can be extended to approximately 1,500 meters, but in order to make developments at such water depths (and deeper) economical, new and innovative solutions are required to reduce costs and shorten development schedules. The 3 column TLP design described in this paper satisfied such requirements. The concept features a simplified and cost effective tendon system and a modularized deck design utilizing a ‘splash zone truss’.

INTRODUCTION
The concept presented is based on approx, 10,000 man hours of conceptual study work carried out over the last two years in close cooperation with Saga Petroleum. The work was focused on an 800 meters water depth Norwegian North Sea harsh environment case (ref. Table 1), but the feather of the 3 column TLP discussed in this paper are generic and applicable to almost any deepwater region worldwide.
The first half of the paper gives a general description of the 3 column TLP concept, including deck structure, hull and tendon system. Comparisons to conventional 4 column TLPs arc made, where relevant and advantages and savings quantified. The second half of the paper discusses the global performance and hydrodynamic aspects of the 3 column TLP including major findings of a recently completed model test. Lastly, the relevance and validity of the main features of the 3 column TX-Pis discussed for application in other geographical regions.
Cost Drivers. In an attempt to few the attention and effort in areas where the largest cost savings could be achieve the development work initially concentrated on identifying the main deep water TLP cost drivers;The hull size is a primary cost driver as it governs both the tendon system design and hull structural weight, The hull size is dependent on the topside load, tendon pretension and hull weights.The TLP tendon system cost increase with water depth, so hull optimization with respect to tendon responses and tendon pretension becomes important.For the TLPs installed in the Norwegian North Sea to date (Snorre and Heidnm), the tendon top/bottom connectors and installation teds represents approx. 70 % of the total tendon system cost. This percentage decreases for deep water, but a simplified tendon design still has a significant potential for cost savings.Important cost drivers for the TLP installation are the requirement for heavy lift barges with deep water station keeping capability, the tendon deployment duration, and the need for specialized tendon installation aid.
PETROJARL FOINAVEN - A West of Shetland Challenge
Authors: Brarresen R. , Krafft H. 
Published: October 2008

INTRODUCTION
The Foinaven field was first discovered in late 1992. The field will produce oil for the partners BP and SHELL in [996. The owners laid out a commercial strategy in line with the CRINE initiative for the field development. One of the leading ideas in this respect is to utilize Industry standard and knowledge to a greater extent than had previously been common in the offshore oil industry.
When the first oil starts flowing at Foinaven later this year, three and a half challenging years are behind. BP, SHELL, the contracting companies and personal involved, will probably admit that they have been involved in a major frontier project, and have contributed in setting some new milestones and yardsticks for the industry.
The challenges of the project have been encountered within the wide spectrum of disciplines of a large offshore project. The time span of approximately three and a half years testifies to an accelerated timescale as compared with a traditional approach. The Fast Track characteristic is an essential origin for the wide range of challenges that were encountered. Throughout the project, major decisions had to be taken in an environment of ‘continous specification and design development’. This required flexibility and a ‘parallel engineering’ approach.
The field development has been effected within the realm of the Safety Case regulations. We have experienced that the industry still is in the transition zone between the previous regime of prescriptive regulatory requirements and the risk based design approach. Challenges were associated with the task of managingand implementing a common understanding of the regulatory authority expectations, and with work definition and timing resulting in a smooth and rational design and construction process.
The Field will be produced by a Production Ship, hooked up to the subsea production system via flexible risers and umbilicals. The 300,000 barrels storage capacity ship, PETROJARL FOINAVEN, will be turret moored in the field. The technical challenges in the Production Ship design have been closely related to the field location in the Atlantic ocean west of Shetlands. Here the water depth is 500 meters, and the weather is blessed with a climate harsher than the North Sea (e.g. the 100 year wave is some 18 meter significant.)
The ship solution has been designed by Golar-Nor Offshore, and is being built by Astano shipyard, with a McDermott Engineering oil process design. The ship is owned and operatedby Golar-Nor Offshore under a lease agreement with the field operator BP. This presentation will adress aspects of the Production Ship design, being one element at the Foinaven Field development. The other element is the subsea system described in an other paper in this conference.
Hydrodynamic Studies on a Cyclonic Separator
Authors: França F.A. , Rosa E.S. , Banmvart A.C. , Moura L.F. , Ahanati F.J. 
Published: October 2008

Abstract
The paper describes the operational principles, the modeling foundations and some laboratory results of the gas-liquid separation process taking place within a cyclonic gas-oil separator. The centrifugal and the gravity forces, acting on the flow of the gas-liquid mixture, are the main driving mechanism to separate the phases. A research program, conducted by PETROBRAS and UNICAMP, was aimed to the hydrodynamic processes occurring within the equipment. Laboratory data were obtained from down size scale models operating with mixture of air and liquid with different viscosities. The basis for the modeling is launched and a discussion regarding the limitations and constraints of the operation is presented in light of the experimental results. Prospective field applications, based on the extension of the laboratory results to actual fluids and full dimension prototypes, are also presented.

Introduction
The cyclonic separator is designed to separate the free gas and oil at the well-head. Once the fluids are separate4 they can be transported to the platform through individual lines. The oil is pumped by a conventional ESP - Electrical Submersible Pump, installed in the lower part of the device. The gas is driven upward by the pressure difference that exists between the separator and the collecting vessel on the platform. This concept of separation has a number of advantages: the pressure at the well head is lowered thus increasing the reservoir production; the oil, separated from the gas, can be pumped by a centrifugal pump transporting gas and oil to the platform through distinct pipelines avoids, or at least reduces, some typical problem in two-phase flows; separating the phases at the well head makes feasibly measuring each stream, which results in a better inventory of the reservoir. Such benefits enable this technology as a &date to develop deep water or marginal oil fields.
This concept of separation system herein described is a variation of the Vertical Annular Separation and Pumping System - VASPS. VASPS is a UK patent application issued to the British Petroleum Company in 1988. Publications describing the operational principles of VASPS can be found in Refs, 1 through 3. The testing of VASPS is now a subject of the "VASPS Pre-Sub sea Phase 11"Project.which has been operated by AGLP on behalf of Mobil and Brasoil. At its present development stage, scale models of VASPS have been tested at AGIP's production and test site in Trecate.
The present work is a joint development between PETROBRAS and UNICAMP - The State University of Campinas, in Brazil. The contract pointed out to the development of a model expressing the two-phase hydrodynamic processes occurring within the separator. During the period of the work, down size prototypes were built and experimental data was taken to calibrate the model and support it. The purposes of the laboratory simulations were two-fold: to reveal the basic mechanisms of separation and to find the operational limits of the prototypes.
Heidrun - Results from Pre-Completed Techniques ells Using Innovative Gravelpacking
Authors: Landrum W.R. , Burton R.C. , MacKinIay W.M. , ErIandsen A. , Vigen A. 
Published: October 2008

Abstract
During the initial phase of the Heidrun Field development, 5 wells were pre-completed using state of the art cased hole gravel packing techniques. The wells were tested and temporarily abdomen, awaiting tie-back to the Heidrun Tension Leg Platform (TLP). This paper describes the completion techniques applied and preaenta results of an evaluation of gravel pack efficiency for the wells. Flow and build-up tests were carried out on the semi-submersible drilling rig before and after gravel packing to evaluate initial productivity. Stabilized well test data acquired on the Heidrun TLP at full production is presented to document ultimate completion performance for each well.
Many innovative completion techniques were applied to ensure high well productivity and secure the operational efficiency required for the Heidrun TLP.

Innovations.
The production casing was perforated via Tubing Conveyed Perforating (TCP) guns, 12 shots per foot, on a Drill Stem Test (DST) string with down hole gauges, thus allowing perforating, perforation clean-up and flow back, pre-gravel pack testing, and gravel pre-packing to be performed in a single run. A unique loss control formulation (LCM) was developed and applied to control fluid losses to the formation. This was the first application of an LCM which had an internal, temperature actuated, acid breaker integral to the LCM filter cake. Pre-pack modeling and alternating stage a of clear brine and slurry were used to optimize gravel placement. Zones ranged from 164 to 300 ft MD, and 1 to 10 Darcy permeability, in wells with inclinations from 45 to 53 degrees. A temporary abandonment system was developed and installed which utilized a weight actuated ball valve, run in the same trip as the post-gravel pack test string, in order to temporarily abandon the well without placing any damaging fluids across the production zone. This allowed the potions to be temporarily suspended with hydrocarbons across the zone and two mechanical barriers in place. The gravel pack screen assemblies included alternative path gravel placement utilizing 4 shunt tubes per gravel pack screen assembly.
The innovative gravel packing techniques used at Heidrun resulted in high completion productivity and correspondingly high flow rata. A study performed to evaluate the economic impact of acceleration showed that going from a 20,000 BOPD well rate to a 30,000 BOPD well rate added $108 million in pre-tax NPV to Heidrun project economics. Actual results will be grater since well rates have exceeded 43,000 BOPD.
An Innovative Fast-Track Development for CMe d'lvoire
Authors: Kreider G.J. , Barnes J.E. , Smitherman J.E. , McFarland J.M. 
Published: October 2008

Introduction
In May, 1994, approval was received for the development of the Panthere Gas Field and Lion Oil Field by UMC Petroleum Corporation as operator with its painters Plus petrol, Global Natural Resources, International Finance Corporation and the national oil company of C6te d'Ivoire, Petrol. At that time, UMC had drilled one well from a jack up at Panthere in 270 feet of water and had set a guyed caisson, Following thePanthere gas discover, the Lion oil discovery well was drilled in 235 feet of water and another guyed caisson was set.
Paragon Engineering Services had been hired in late 1993 to develop project scenarios and cost estimates and as the project evolved, detailed engineering, procurement and construction management services. The original plan of development is shown in Figure 1. Production equipment for 30,000 BOPD, 16,000 BWPD and 75 MMSCFD was to be installed on a jack up drilling rig converted to a Mobile shore Production Unit (MOPU) located at the Lion 'A' caisson. Production from Panthere would flow through an 8-inch line to the MOPU. The production equipment on the MOPU would (1) separate oil, water and gas, (2) treat the oil for sale and the water for discharge, (3) pump the oil into an 8-inch pipeline to the refinery in Abidjan, (4) compress the oil well and gas well gas as needed, and (5) dehydrate it for sale. A CALM buoy with shuttle tanker was included in the original plan for early production and as a backup to the oil pipeline. It was also unknown at project initiation whether a gas sales contract would be successfully negotiated, and thus the project was to proceed on the basis of flaring produced gas with capability to add equipment at a later date for gas sales.
As the development proceeded a second caisson was installed at lion the 8-inch onshore oil line to the refinery was not installed the capacity of the gas process equipment was increased from 75 to 100 MMSCFD, an FPSO was instead, gas sates was require the government required the gas sales line to be oversized for future expansion and the separation metering and heating station required for delivery of gas at the power plant in Abidjan was more elaborate than anticipated.
An ambitious schedule was laid out in May 1994 calling for first oil delivery in April 1995 and in the event of successful negotiation of a gas sales contract with the power plant in Abidjan first gas delivery in October, 1995.
Although approval was received to begin detail engineering in May 1994, money was not approved to purchase equipment needed for oil production until September, 1994. The gas sales contract was not signed until September 30, 1994 and approval to purchase equipment necessary for gas sales was not granted until December, 1994. Key dates are shown in Table 1
Strategies For Cost Effective Solutions in Deep Water Production
Authors: Karrer Eduando , Meter Wagner G. 
Published: October 2008

Abstract
The objective of this paper is to present the strategies adopted by Petrobass in the exploitation of deep water giant oil fields, comparing the use of new buildings and the conversion option.11 pints out the F.P,S.0, and semi submersible solutions, describing the eases of Petrobass 32 and 33 (F.P.S.O. units) as well as Petrobras 18, 19 and 26 (semi submersible units). h is also presented a comparison of schedules and cost in both cases, for the F.P.S.O. and semi submersible options (conversion and new building). Finally is presented the future trends for possible optimization in a short and long term scenarios.

Historical Background
The exploration of oilfields alongside the Brazilian coastline was performed in hove distinct conceptual phases, to wit: during the first phase. the Company exploited up to water depths of 200 meters. utilizing the offshore fixed platform concept, During this stage, a total of 72 such platforms were installed in Brazilian coastal waters. The second phase initiated with the discoveries of the giant oilllekis of Madim, Albaeora and Barracuda, the Company resolved to use floating production systems associated to wet Christmas trees, a method which embled the Company to set repeated world production ramrods.
The Anticipated Production Systems (SPA's) were among the first systems to lx projected and installed in extremely short lead times. The majority of these methods provided for oil production and burning of the gas thereby produced. The burning of gas and the use of standardized and small-capacity process plants turned various utits feasible, within eight to ten months - from the signing of the contract to the first oil being extracted.
Based in this initial production concept, the offshore activities improved significantly in the Campos Basin, off the coast of the State of Rio de Janeiro, with the fixed platform concept including a process plant, utilities and living at waters, all integrated on a single module. From the total amount of fixed platforms installed in this phase, almost the totality used steel as the basic material for the jacket and decks, with the exception of two concrete platforms that were installed in the Ubarana field, being named PUB-1-and PUB-2 platforms. This step was in all affects, considered of extreme importance to PETROB in that it initiated the search for technical capacity in the direction of deep-water oilfield production. Such technological parity was in fact consolidated and exenterated at PETROBFL4Sin its CENPES, the research and elopers center as well as in its various independent same provirus in Brazil.

Selecting the Alternative to be Adopted
The selection process for the adoption of the most suitable platform alternative normally takes place during the project's feasibility study. when all the technically field-proven solutions are analyzed, taking into account such factors as the availability of vessels, rigs, etc.