bluuebunny/crossref_metadata_2025_split huggingface dataset:
Deepwater Tie-In Operations For A Large-Diameter Pipeline
Authors: Gray W.E. , Appleby R.J.T. , Gray D.A. 
Published: October 2008

ABSTRACT
As a part of its expansion of the SYU field in the Santa Barbara Channel, Exxon selected the "deflect to connect" method for making the tie-ins of the 20"D emulsion lines at the jackets. The two jackets, Heritage and Harmony, are in 1070 and 1200 FSW, respectively, requiring completely diverless operational methods -- no divers were present. This paper describes the tie-in of the three lines as well as the planning, testing, tooling and training that led to the successful operations results.
By the success of the operations, this work provides assurance of the ability to reliably connect large diameter pipelines to risers in greater-than-diver water depths.
This is believed to be an industry first for pipe size, water depth, tie-in method and for system sophistication.

INTRODUCTION
EXXON USA is engaged in an expansion of its Santa Ynez Unit facility (See Figure 1). This involves the installation of two new jackets Harmony and Heritage, the former in 1200 ft. of water, the latter in 1070 ft. of water. The pipeline which will carry the crude emulsion to the onshore treating facility is a 20 in. pipeline with weight coating. This line is in two parts; a section that goes from Platform Heritage to Platform Harmony and another which goes from Harmony to onshore. Other smaller diameter pipelines are connected to the platform facilities by means of a J-tube pull but the 20 in. pipelines are too large for this method. Consequently, the connections to the platforms were made by the deflect-to-connect method. Because of the water depth, all subsea work was carried out by diverless means.
The deflect-to-connect method of making a pipeline tie-in to a platform riser is accomplished by laying a pipeline with a sled in a target area in a carefully defined location to one side of the platform (see Figure 2). A winch on the +27 level of the platform is connected to a pre-installed cable on the corner leg of the platform. The end of the cable is carried across the bottom to the sled and a mechanical connection made. The pipeline has buoyancy tanks along the last 1500 ft. of its length which are used to elevate the pipeline about 8 ft. off the bottom. When the deflection cable is hauled in, the pipeline deflects and the sled at the pipeline end moves to a position approximately 30 ft. from the receiver which has been pre-installed on the jacket at the mud line. An ROV is used to connect two pullin cables to the sled, These cables are connected to winches which are also on the +27 level. When these winches haul in on the lines the sled is drawn in. The sled is locked to a carriage on the receiver by hydraulically set pins. When the carriage is retracted using hydraulic rams, a collet connector on the receiver is engaged with the hub on the sled and the tie-in and connection is complete.
The Role Of Duplex Stainless Steels For Downhole Tubulars
Authors: Francis Roger 
Published: October 2008

ABSTRACT
In sour conditions there is an increasing trend to turn to corrosion resistant alloys for downhole tubulars. The most commonly used CRA tubular is 13Cr, and there are thousands of feet in service. However, there are limits to the use of 13Cr, ie., the risk of sulphide stress corrosion cracking at high HZS levels, and the possibility of pitting or high corrosion rates in waters with high chloride contents. Where the service conditions are felt to be too severe for 13Cr alloys it has been traditional to switch to nickel base alloys such as alloys 825 and C-276 (UNS N08825 and N10276). The alloys are much more expensive than 13Cr, and in recent years the duplex stainless steels have been selected as alloys with superior corrosion and SSCC resistance compared with 13Cr, and having lower cost than nickel alloys.
Originally the 22Cr duplex alloy (UNS 31803) was used, but more recently the 25Cr super duplex alloys (UNS S32760 and S32750) have become more available. The present paper reviews the data available for 13Cr and the limits of applicability. Data is also presented for laboratory tests for both the 22Cr and 25Cr super duplex alloys. There is extensive service experience with both 22Cr and 25Cr super duplex in the North Sea, covering both downhole tubulars, manifold and post wellhead equipment. Data is presented showing some of the sour condition being experienced in the North Sea by super duplex alloys. These results show that there is a substantial gap between the limits of use for 13Cr and the 25Cr super duplex stainless steel alloys. This means that in many sour environments super duplex stainless steel provides a cost effective alternative to nickel-base alloys.

INTRODUCTION
Oilfield downhole tubulars (OCTG'S) are usually high strength carbon manganese steels. However, under severe operating conditions, such as high C02 or H2S, excessive corrosion occurs. Under such conditions it is necessary to consider the use of a corrosion resistant alloy (CRA). These range from 13Cr martensitic steels through duplex stainless steels to nickel base alloys. The aim of the present report is to review the available data on the corrosion resistance of CRA's from both laboratory tests and service experience, and suggest limits of use.

MATERIALS
The alloys being considered in this review are listed in Table 1 with their compositions. The 13Cr martensitic alloys are widely used by the oil and gas industry. Alloy 410 is low carbon and hence it is not possible to obtain such high strength as alloy 420 and L80. However, because of its lower carbon content alloy 410 can be welded, and it has been widely used for wellhead and Christmas trees. It is easier to achieve a uniform martensitic and delta-ferrite-free microstructure with alloy 420.
Delta-ferrite is detrimental to both impact and environmental cracking resistance.
The Safe Recovery Of Hazardous Materials From An Underwater Offshore Site
Authors: Watt A.M. , Craft D.C. 
Published: October 2008

ABSTRACT
This paper describes the planning, preparation, offshore recovery and subsequent disposal of the toxic cargo which was lost from the container ship M/V SANTA CLARA 1 during the storms of January, 1992. Recovery of the toxic substance was undertaken by the vessel owners as a result of being served with, what is believed to be, the first offshore CERCLA (also referred to as Superfund) 106 removal order on February 20, 1992.

BACKGROUND
The M/V SANTA CLARA 1 was caught in a fierce storm early in January, 1992, while in transit from New York to Baltimore. In the early morning hours of January 4, she lost approximately 20 shipping containers over the side, but, due to the darkness and severity of the storm, those navigating her were unaware of the loss until entering the sheltered waters of the Delaware Bay. After daylight, the crew established that, according to the cargo manifest, four of the lost containers each contained 108, 25-gallon metal drums of arsenic trioxide (As203), palletized and bound with metal strapping.
The storm damage and the cargo loss was reported to the United States Coast Guard (USCG), As the nature of the loss and the geographical position offshore the New Jersey beaches became public information, local concern was aroused; especially since this event followed on the heels of the 1991 closures of the beaches due to medical waste washing ashore, The medical waste pollution problem had created great hardship and financial loss to the seaside business community and others. Naturally, the same local businessmen were extremely concerned that once again the beaches would be closed and another year of loss and hardship encountered.
City councilmen, mayors, congressmen, senators, environmentalists and many others were extremely concerned, even more so when the fishing grounds in the area of the cargo loss were closed. The jurisdictional body which must deal with such a problem is the USCG. Is human life, marine life or the environment at risk? Was the loss caused by an Act of God? Who pays for the search and recovery of the cargo, if necessary? These are only a few of the questions that had to be addressed. The USCG responded and these activities re reported in the Marine Safety Council Proceedings. This paper limits its discussion to the planning, recovery and subsequent disposal of the toxic materials.

INTRODUCTION
The SANTA CLARA owners and insurers had for several years retained the services of a prestigious American Admiralty Law firm with an in-house Rapid Response Team. The team responded immediately, seeking answers to the many questions which were being raised. The Rapid Response Team added a Search and Recovery Manager with in-depth experience in underwater search, salvage, diving and remote vehicle operations.
Prior to completion of the Federal Safety Plan, the project looked like a very simple salvage operation where divers or remotely operated vehicles (ROVS) would locate the cargo and attach recovery lines.
The Gryphon Management Strategy And Outcome
Authors: Doble P.A. , Strudwick Maurice , Gregory John , Keyworth Steve 
Published: October 2008

ABSTRACT
Extensive reservoir appraisal and numerous engineering studies concluded that the most economic development plan for the Gryphon field, UK North Sea, made use of a Floating Production Storage and Offloading (FPSO) Unit (Ref. 1). Maintaining the robust economics of this relatively small field required quick and reticent implementation.
First oil from Gryphon occurred only one year from the time agreement was reached to purchase the FPSO. Such fast-track projects often imply high costs in order to meet short delivery times. The Gryphon project management strategy, implemented a contractual philosophy which did not allow costs to escalate or long timescales.
This paper describes the Gryphon project management strategy and outcome.

OVERVIEW
Given the fact that no acceptable infrastructure for the export of crude exists in the Gryphon field area, development studies focused on offshore loading schemes with low production downtime. This led to the recommendation to provide storage as a buffer while shuttle tankers were delivering product to customers.
In December 1989 a contract was let with a Spanish shipyard to build a Floating Storage Unit (FSU) by a Norwegian ship owner, The construction was placed on a speculative basis with the intention that the vessel could be used as a drilling, production or test ship.
The design of the ship which became Gryphon 'A' (and was also known as the Tentech 850C, PTS 850C and Smedvig Production Unit (SPU)) was a derivative of the Petrojarl design, a production/test ship successfully operating in the North Sea. The vessel hull was launched in April 1992 and fitting out as an FSU was scheduled for completion by the end of the year.
Following negotiations with the owners, a 'Memorandum of Agreement' was signed in October 1992 to purchase the vessel. The Gryphon project called for design and construction of the processing facilities and modification of the ship to convert it to a Floating Production Storage and Offloading (FPSO) Unit in one year (Figure 1). With a firm plan in place the UK government approved the development in December 1992.

PURCHASE OF THE VESSEL
The vessel was to be delivered to its new owners as a fully operational, registered Floating Production and Storage Unit with a UK Certificate of Fitness and Det norske Veritas Classification (DnVC) class certificate, To maintain the delivery schedule the new owners could not interfere with completion of the ship or modify its design. This philosophy formed the cornerstone of the management strategy for converting the ship from a Floating Storage and Offloading Unit into a Floating Production Storage and Offloading Unit.

MANAGEMENT STRATEGY
The management strategy included a number of principles :employ a small number of competent experienced people to execute the projectpurchase goods and services from competent suppliersdevelop a common purpose of overall project success, not just maximizing income for individual participants/contractors
Comparative Evaluation Of A Concrete And Steel Hull For A Deepwater Gulf Of Mexico Tension Leg Platform
Authors: Nygaard Chris , Huang Ed 
Published: October 2008

ABSTRACT
This paper outlines the concept development and comparison of a steel hull and a concrete hull TLP designed for the same Gulf of Mexico (GOM) conditions in 3,000 ft. water depth. The global performance of the two TLP's is evaluated to the same level of detail using widely accepted analytical procedures. The global performance analysis and recent model tests confirm that the results are comparable and with no significant advantages nor disadvantages for the steel vs. the concrete alternative. Innovative construction and assembly methods for the concrete hull, specifically engineered for the inshore shallow water GOM conditions are highlighted. A cost efficient construction technique based on local construction has been developed for the concrete alternative. cost evaluation confirms that a concrete TLP is a competitive alternative to a steel hull TLP.

INTRODUCTION
The success of concrete gravity based structures in the North Sea is indisputable. Lately, there has been considerable industry interest in the use of concrete construction also for floating platform hulls. Several publications on concrete versus steel for floaters, and in particular, Tension Leg Platforms (TLP), have been presented. in general, the comparisons have been promising for the concrete alternatives. The previous studies comparing steel and concrete TLP hulls have, however focused on large TLP's. This will be the first published study of the use of concrete for a smaller "second generation" TLP, designed specifically for GOM construction. The results, of the extensive work on both steel and concrete TLP's will provide valuable information to a designer/operator to make an objective assessment of the relative merits of the two materials.
The decisions by Conoco Norway and Norsk Hydro to have concrete hulls for the Heidrun and Troll Oil platforms, both in the North Sea, were a breakthrough for floating concrete structures. Both the Heidrun TLP and the Troll Oil Semisubmersible are very large floaters. Heidrun carries some 90,000 st above top of columns and has a displacement of 290,000 st while Troll Oil carries 32,000 st and has a displacement of 270,000 st. Both platforms are scheduled for installation in 1995.
Considerable experience has been accumulated over the years in the analysis and design of steel hull TLP's, Hutton, Jolliet, Snorre and Auger are all installed and the fifth steel TLP is in the detail engineering phase while Heidrun is the only concrete hull TLP so far. The present study is based on state of the art technology. The comparative evaluations are based on a steel TLP already developed for the GOM and a concrete TLP designed with an identical design basis.
Although the development has addressed most aspects related to a TLP concept, the main focus in this presentation is on comparing global performance of a steel and a concrete TLP and construction/installation scenarios of the concrete TLP.
Physical Modelling Of Vertical Multiphase Flow: Prediction Of Pressure Gradients In Oil And Gas Wells
Authors: Zabaras G.J. 
Published: October 2008

ABSTRACT
A new method is presented for predicting pressure profiles in oil and gas wells. The method combines mechanistic low pattern transition criteria with physical models for pressure loss and liquid holdup calculations for each of the flow patterns considered. Past published methods relied heavily on empirical fit of limited field data. As a result, they are inaccurate when used outside the range of data upon which they are based. In contrast, the new method is universally applicable to all types of wells under all operating scenarios since it is based on fundamental physics rather than curve-fit of field data. Its prediction performance has been demonstrated by extensive comparison to field data from a variety of wells.
Profitable production of many offshore oil and gas fields relies on accurate prediction of the multiphase well tubing flow. Economic tubing and gas-lift system designs strongly depend on reliable calculation of multiphase flow pressure gradients under a variety of operating conditions.
The predictions of the proposed method have been compared to 1895 data sets from oil and gas wells including carbon dioxide source wells, carbon dioxide EOR wells, high H2S wells, and high pressure deepwater wells. The comparison results show that the proposed method outperforms eight of the most known published and proprietary methods used by the industry. Based on all data tested, the new method gave a near zero percent arithmetic error in the total tubing pressure drop and an average absolute error of only eleven percent.
The proposed method is largely based on mechanistic modelling of vertical and inclined multiphase flow. It has been validated by comparison to the largest ever reported well data base. It has also outperformed eight of the most known published and proprietary methods used by the petroleum industry.

INTRODUCTION
Two-phase upward gas-liquid flow is of great importance to the production of oil and gas. It has received continuous and strong attention by many investigators from the early days of the invention of the air-lift pump to the present time. The application of gas-lift principles in the late 1920's stimulated further interest in the area of vertical two-phase flow and resulted in a large number of theoretical as well as experimental studies. However, while considerable progress has been made in the overall and qualitative understanding of the problem, much remains to be done from a quantitative point of view. The main difficulties in analyzing vertical gas-liquid flow is the variety of flow patterns possible and the existence of slip between the phases. Four flow patterns are usually defined for vertical upward flow: bubble, slug, churn and annular flow. In a very short pipe only one of these patterns will exist for a given pair of liquid and gas flow rates. However, in long risers and in the tubing of oil wells usually two or three flow patterns can exist at different locations along the pipe.
Development Of An Advanced Drilling System For A Deepwater Jackup Hpht Project In The North Sea
Authors: Monjure N.A. , Brunjes Jean 
Published: October 2008

Abstract
As drilling In the North Sea began to reach deeper and deeper zones In the Central Graben area of the North Sea, the combined effects of high pressure and high temperature created a number of highly publicized well control problems as available technologies simply reached their limits. When a consortium of major operators decided to drill a deep, high pressure, high temperature Central Graben well to test the production capacity of this Jurassic reservoir, drilling practice and regulatory guidelines dictated that existing wellhead, valve, and mudline suspension technology would have to be extended to meet the base requirements for a system capable of operating up to 18,000 psi and 450°F In approximately 300 feet of water. In Stuart, MacKay, Seymour, et al1, the decision process to use a jack-up rig Is examined along with the general guidelines required by United Kingdom regulatory bodies for approval of the overall drilling project. In Seymour, Stuart, Simpson, et al2, the development of the blowout preventer system and drilling program are detailed. This paper addresses the specific technology development of the surface drilling and completion system, the mudline suspension system, the development of a design and testing program to meet requirements which were outside the scope of published guidelines and Industry specifications, and the teambulldlng process which enabled this portion of the project to be successfully completed on time.

Background
Gas or gas condensate wells with pressures exceeding 15,000 psi have been successfully completed and produced by the petroleum Industry since 1974. In addition, wells with abnormally high surface producing temperatures have been successfully completed since 1976. In fact, a large number of wells which meet the criteria as an HPHT well have been drilled and produced over the last ten years. However, developments requiring combined pressure rating over 15,000 psi and temperature rating over 350°F are few In number. When combined with the additional requirements for tensioned conductor strings, mudline suspension, and large bore completion capacity, the number of similar projects prior to the Central Graben 29/4b-C dwindles to zero. Although It was not entirely clear at the beginning of the project, new product development would be required for a 30/20 non-welded conductor tensioning system which worked Integrally with the surface wellhead and the conductor connectors, a non-welded wellhead-to-casing attachment system which was mechanically compatible with the other components of the system, a 21-1/4" 5M by 13-5/8" 15M Surface Wellhead System with fast make-up non-flanged connections, suitable for use with mudline suspension equipment but providing all metal primary sealing, a mudline suspension system capable of 16,000 psi at 350°F at the Intermediate casing string, an 11" 20,000 psi production casing spool assembly rated for 350°F, and an 11" 20,000 × 3-1/2 - completion system rated for 18,000 psi at 450°F.