bluuebunny/crossref_metadata_2025 huggingface dataset:
Observations Of Cetaceans In The Central And Western Gulf Of Mexico
Authors: Avent R.M.
Published: October 2008

With thousands of OCS oil and gas platforms in the Gulf, it has been questioned whether the many species of whales and dolphins are affected by physical structures, noise, effluents, spills, boat and air traffic, and explosive platform removals. This presentation reviews the results of recent major offshore vessel and aircraft surveys of marine mammals including the ongoing "GULFCET" study. It reviews the implications to the petroleum industry, and possible future research directions.

INTRODUCTION

The Minerals Management Service (MMS) has the responsibility for leasing, exploration, and development of submerged Federal lands on the U, S. Outer Continental Shelf (OCS). The MMS Environmental Studies Program (ESP) was initiated in 1973, largely to evaluate the environmental effects of OCS oil and gas activities on the OCS. In response to the Endangered Species Act (ESA) of 1973 and the Marine Mammal Protection Act (MMPA) of 1972, the ESP has funded an evolving series of studies on protected species potentially affected by OCS oil and gas operations. The ESA provides for the conservation of endangered and threatened species. It requires that Federal actions, including the regulation of petroleum activities, do not jeopardize species listed as threatened or endangered by the U.S. Fish and Wildlife Service. The MMPA of 1972, as amended, further requires that all marine mammals be protected, whether listed under the ESA or not. Through formal "Section 7" consultations with the National Marine Fisheries Service (NMFS), the MMS is required to assess the level of potential industry impact to the marine environment and its living resources. In response to these consultations and the recommendations of a 1989 protected species workshop (Tucker and Associates, 1990) the MMS supports studies on protected species in the Gulf of Mexico.

One of these is presently being conducted by the Texas A&M University at Galveston and the National Marine Fisheries Service. This "GULFCET" study calls for systematic shipboard, aerial, and acoustic census surveys over the outer continental shelf and slope, in the western and central Gulf, the areas most prone to deep petroleum exploration and development. In addition, attempts are being made to tag and track the movements of the endangered sperm whale.

METHODS

The methods used in the present deep water study include the following (see overall study area, Figure 1):Aerial surveys are conducted over the slope seasonally, employing dedicated aircraft, a NOAA deHaviland Twin Otter, when available. Preset flightlines are flown while trained observers identify and count animals and record observations, along with ocean conditions and position, on a portable computer. Limited departures from flightlines are made to refine species identifications and counts and to make and record behavioral observations.Shipboard surveys are conducted along preset transects as observers using large mounted binoculars identify and count animals. Hydrographic measurements and multichannel acoustic recordings are taken concurrently.
Biological Noise On Seismic Data
Authors: Fulton T.K.
Published: October 2008

The geophysicist increases the resolution of the subsurface by using closely-spaced detectors. Ambient noise becomes more important with the short recording arrays so as to increase the importance of biological noise. It becomes causes a crew to stop shooting rather than simply degrading the final results Planning acquisition with knowledge of the habits and sounds of creatures can reduce possible down time and additional processing costs to attenuate the noise Noise avoidance is both cost effective and environmentally desirable. The objectives of this paper are to illustrate some noises, identify others, and alert the industry about the problem.

The problem is not new; biological noise also degrades the ability of the Navy to identify distant ships. The sources of biological noise are migratory. Navy research and data bases of biological an ambient noise can be useful to the seismic industry to enable it to avoid the noise when possible.

INTRODUCTION

Forget what you've heard about the silence of the sea. It's not always quiet down there. Many fish and other animals grunt, squeak, or whistle by grinding their teeth vibrating their swim bladders, or by burping out air. While the spectrum of most fish noise is higher than the useful seismic spectrum, many whale noises are near 20 Hz. Noise due to shipping, on the other hand, clusters around 50 Hz. An authority on ambient marine noise indicated that at one time, noise at 20 Hz was thought to also be due to shipping as peaks in the spectrum at 20 and 50 Hz seemed to change together with the relative amount of shipping. It seems that whales, like humans, just â??talk' louder in a noisy environment. Background noise has also been noted to increase with seismic activity in a similar way. While biological noise may increase with the presence of a seismic survey, the failure of the sources to leave the area allow one to conclude that the sources are not threatened. The proximity of biological creatures to the seismic sensing cable allows their noise to be a problem. Noises from toad, menhaden, croaker, drum, and cat fish can be detected for perhaps 1000 feet Snapping shrimp are also responsible for a high ambient noise level.

OBSERVATIONS

The seismic industry has long had problems with shark damage to its recording cables. Figure 1 (reproduced from OTC paper 4929) shows a shark bite which damaged a cable. Manta rays have also become entangled in recording gear to cause damage.

Biological noise can be thought of as a point source near the seismic cable. Energy from such a source arrives at the cable to form a pattern dependent on the offset. The left portion of Figure 2 shows predictable first break patterns as a function of offset and spread geometry. The right hand portion shows a shot record with a separate noise source at an offset of about 1000 feet estimated from the curvature of the arrival time pattern.
Historical Development And Assessment Of The Current Api Design Methods For Axially Loaded Pipes
Authors: Pelletier J.H. , Murff J.D. , Young A.C.
Published: October 2008

The design methods for axially loaded piles contained in the API RP 2A, Recommended Practice for Planning. Designing and Constructing Fixed Offshore Platforms are continually evaluated and updated. To support this activity, API has funded research over the past 10–12 years which has resulted in the establishment of an internationally recognized data base of axial pile load tests. Subsequent interpretation of these data led to significant changes in the design methods for axially loaded piles for both sand and clay. The sand revisions, first incorporated into the 15th Edition of RP 2A provide improved statistical predictions (bias and coefficient of variation) of the sand data base than did the design methods for sand contained in earlier editions. The clay revisions, first incorporated into the 17th Edition of RP 2A provide a statistical description of the clay data base that is similar to descriptions provided by earlier clay methods. Both the revised clay and sand methods provide a more technically sound framework than the methods contained in earlier editions. The revised methods are contained in the current, i.e., the 20th Edition of RP 2A (1993). These revisions have initiated considerable debate, and have prompted the authors to present their thoughts herein. A discussion of the data base, review of the philosophy and evolution of the design method, and a summary and analysis of the key criticisms are provided. The data have been exceedingly useful in formulating design practice, but in our opinion they are too limited to conclusively resolve many of the important issues. While some modifications to the present practice seem to be indicated, the authors believe that when combined with a careful site investigation, attention to installation detail and good engineering judgment, RP 2A continues to provide a sound basis for design of axially loaded piles.

INTRODUCTION

The empirical design methods for axially loaded piles contained in the 20th Edition of RP-2A (1993) evolved over a number of years and are subject to continuing review and updating. This process led to significant changes in the design criteria for piles in both sand (15th Edition 1984) and clay (17th Edition 1987). The revisions have given rise to several years of international discussion among engineers, government agencies, API, and certification authorities as to the applicability of the revised methods, especially for sites outside the Gulf of Mexico.

In this paper we first describe the role and history of W 2A, including summaries of selected relevant studies. Similar histories were presented by Focht (1983) and Toolan and Horsnell (1992), but some repetition is given here for completeness and continuity. This history includes important research findings that impact unresolved design issues. This discussion is followed by a brief analysis of each of these issues. Finally we present our own views of the validity of the current RP 2A pile design methods and our comments on their future evolution.
Reservoir Management Aspects Of Producing Oil From Thin Oil Rims In The Troll Field
Authors: Kydland Torgeir , Wennemo S.E. , Olsen Gudmund
Published: October 2008

The 22–26m thick oil zone in the Troll West Oil Province, offshore Norway, is planned to be developed by 18800m long horizontal wells. The viability of such wells has been proven by long-term testing. To obtain economic oil production the wells will be completed in the lower part of the oil rim close to the oil-water contact. The high water production which is expected can, to some extent, be controlled by gas reinfection. A flexible gas injection scheme will therefore be implemented.

Allowing wells to produce free gas together with the oil (supercritical - production) has been shown to accelerate oil recovery and to improve lift and balance well pressures at the subsea manifolds.

The complexity of the Troll field together with simultaneous oil and gas production from different parts of the field makes development planning and reservoir management a great challenge. Significant movements of the fluid contacts across the field are expected. To predict the global effects accurately in addition to local phenomena, such as gas and water coning in oil wells, very flexible simulation models have been constructed.

INTRODUCTION

The Troll oil and gas field is located in 300m water depth offshore Norway and covers an area of 700km2 (Fig. 11. It contains an up to 26m thick oil rim sandwiched between a large gas cap and an active aquifer. The field consists of three easterly tilted fault blocks (Fig.2). In the western most fault block, the Troll West Oil Province (TWOP), the oil column is 22- 26m thick. The estimated oil in-place in this province is 155x106m3. In the central fault block, the Troll West Gas Province (TWGP), the oil zone is 12 – 14m thick and the estimated oil in-place 440x 106Sm3. In the Troll East fault block the oil column is only O - 4m.

The major gas accumulation is found in Troll East with a gas in-place estimated at 1072x109 Sm3. In the TWGP the estimated gas in-place is 570x109Sm3, and in the TWOP 2.7x109Sm3.

The development of Troll is divided in three phases. Phase 1 includes gas production from Troll East and is planned to start in October 1996. Phase 2 covers development of the oil resources. A plan for development and operations(PDO) of the oil in the TWOP was prepared during 1991 and was approved in 1992. This plan assumes production startup by the beginning of 1996. Oil production from the TWGP is presently under evaluation, The TWOP development concept has flexibility to include a future development also of the oil resources in the TWGP.

Phase 3 includes large scale gas production from Troll West. The gas strategy will be coordinated with the oil production and will not be settled until the extent of the oil development in the TWGP has been defined.
Development Of Shuttle Tanker Loading Systems In The Norwegian Sector Of The North Sea
Authors: Krogstad Ivar
Published: October 2008

The bow loading systems developed for the Norwegian sector are relatively sophisticated. Continuous improvement in the designs has taken place.

Several of the components we have developed have new advanced features:Chain stopper releasable up to the chain breaking load.Crude oil coupler for engagement with self closing hose termination piece.Drum with radial rope outlet which eliminates chafing contact.Cardan suspension of the crude oil riser which allows both the use of conventional pipe swivels and a load cell carrying the complete riser load.

All crude oil transported from the Norwegian sector of the North Sea passes through the above system. This system is also used in the British sector and in the first loading system offshore Nova Scotia. The number of offloading operations has passed 4000.

INTRODUCTION

The weather conditions in the North Sea are harsh and the strain on the mooring and crude oil transfer equipment is considerable. In the Norwegian sector there has been a continuous development of the shuttle tanker loading systems. This development is carried out partly to counteract heavy strain, but the main reason for the modification of the tanker loading systems is changes in the loading buoy design.

LOADING BUOY TYPE AND CHANGES

Fig. 1 shows the location of the various crude oil fields with shuttle tanker loading facilities. The present, and some future such fields, are summarized as follows: Crude oil loading from two CALM buoys was started at Ekofisk in July 1971 and terminated in October 1975 when the pipeline to Teeside was put into operation1,4

In 1978 the first articulated loading platform (ALP) at Statfjord was put into service and later four similar buoys installed, two at Statfjord and two at Gullfaks. The two first Statfjord buoys were later replaced by subsurface loading buoys without mooring facilities (UKOLS).

On the Oseberg field the test production phase 1986–88 was carried out by means of a PTS vessel with stern offloading facilities. A pipeline to Sture took over the crude oil transport.

On Haltenbanken further north in the Norwegian Sea a floating loading platform will be installed on the Draugen field in 1993 and two subsurface buoys for turret mooring and oil transfer are intended for the Heidrun field.

SHUTTLE TANKER BOW LOADING SYSTEMS

The shuttle tanker loading systems used to date in the Norwegian sector of the North Sea are bow loading systems (BLS), i.e. both the hawser and the hose are connected to the tanker bow section. The hawser connection for these shuttle tankers are in the vessels centerline. The position of the hose connection is in the centerline below the hawser connection on the Statfjord and Gullfaks tankers, and on the port side of the forecastle deck for the remaining systems.

EKOFISK TYPE1,2,4

A "self-mooring" system was specified for the shuttle tankers. The 12 inch circ. floating polypropylene messenger was picked up by a grapnel, hoisted through the SPM fairlead and connected to a dummy line from a traction winch.
Deepwater Tie-In Operations For A Large-Diameter Pipeline
Authors: Gray W.E. , Appleby R.J.T. , Gray D.A.
Published: October 2008

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

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

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

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

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

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

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.
Use Of Corrosion-Resistant Weld Overlays For High-Pressure Applications
Authors: Maligas M.N. , Vicic J.C.
Published: October 2008

High performance, corrosion resistant alloys CRA'S are specified for oilfield applications where severe environments such as general corrosion, pitting, crevice corrosion, chloride stress corrosion cracking and more importantly sulfide stress corrosion cracking are encountered. Historically, alloy 625 weld overlay has successfully been used in severe corrosive environments.

INTRODUCTION

The trend in oil and gas production has been towards deeper wells, which has resulted in more hostile environments due to increased temperatures, pressures and the presence of H2S, CO2 and chlorides. Many wrought CRA alloys in the cold worked, or aged condition, have been used for different components (Table 1). There exist many applications where, due to the massive and intricate nature of certain components involved, it is not practical or cost effective to use wrought products. In many cases, the materials with the appropriate corrosion resistance are limited in mechanical properties (Table 2). In such cases, the desired mechanical properties can only be achieved through cold working which are unpractical for many product configurations. For these cases, historically welding has been used to overlay the corrosion resistant alloy on low alloy steel.

The alloy that has extensively been used for such applications has been alloy 625 UNS 06625.

Although alloy 625 has been the primary weld overlay material used in oil field applications, there have been instances where, this alloy under severe sour corrosion conditions and temperatures, has proven to be unacceptable. Another drawback of this alloy 625 has been its limited mechanical properties.

WELDING PROCESS

The gas-metal arc welding (GMAW) process uses a constant power source and continuous wire feed. The wire electrode forms an arc with the base metal and is consumed in the weld pool. The weld metal is protected by shielding gases. Depending on the welding parameters selected, four different modes of metal transfer can be utilized. The four modes of metal transfer that can be used are: spray; globular; short circuiting; and pulsed arc transfer. The protective atmosphere for gas-metal-arc welding is usually a combination of argon, helium and carbon dioxide. The optimum shielding gas will vary with the type of metal transfer used.

SAMPLE PREPARATION/PROCEDURE

Weld overlay samples were prepared using the gas metal arc welding (GMAW) process. The substrate tubes were fully heat treated AISI 4130 with a nominal O.D. of 9" × 6" I.D. × 12" long (23 cm. × 14 cm. × 30 cm.). Welding was performed using alloy 625, alloy 59, alloy 686, alloy 725 and alloy C-22. Single layer and two layer weld deposits were applied to the inside diameter of the substrate tube. For the single layer sample, the deposited thickness was sufficient to achieve a 3 mm minimum clad thickness when the I.D. was machined concentric with the O.D. For the two pass samples, the final machined clad thickness was 9 mm. After welding, a stress relieve was performed on the alloys tubes.
Design Methodology: Code-Driven Design Of Pipelines In Deep Water
Authors: Lawson John
Published: October 2008

The present day approach to writing and presenting Engineering Design Codes and Standards could be measurably improved by adopting a methodological approach to their composition. Current design Methodologies are examined to establish their adaptability to such a role. It is concluded that a multidimensional relationship could be successfully developed in such a way as to integrate the preparation of codes with their intended use as design models. Examples of existing Codes, with a particular emphasis on pipelines for use in deep water, are used to demonstrate one such development. It is proposed that Codes might be produced as stand-alone tools of design methodology and that a new approach to their composition could lead to a more effective, productive and efficient utilisation of their content.

INTRODUCTION

The design of underwater pipelines suitable for the transportation of hydrocarbon products has been going on since before the first pipeline was laid, whenever that may have been. Certainly a few decades have passed since then. Like any other specialist discipline, subsea pipelines have their own peculiarities and they must be properly, rigorously designed to minimise the possibility of catastrophic rupture, with subsequent loss of production, loss of revenue and, above all, the environmental consequences of such an event. Pipelines are being laid in deeper and deeper water as the search for recoverable resources is extended. It is certain that these peculiarities will not became more easily addressed; the reverse is almost certain to be the case.

The pipeline engineer has a number of tools at his elbow to aid him in his design work and to help make sure that the finished product is "fit for purpose". He has a number of codes at his disposal to which he can make reference for guidance on what is considered mandatory and to assist him in evaluating his analyses such that those bodies responsible for the acceptance of the design, including his client, will have confidence in the package which he produces for approval and acceptance. Such Codes include:IP6API RP1111DnV rules8S8010

At his elbow he might also have an in-house set of design guidelines or even a sophisticated suite of software programmes. He might have a mathematical package to do the complex calculations, a graphics package to represent results. It would be even nicer if he had a good, solid design methodology at his fingertips; it would be more economic and less prone to error.

Recognised design methodologies too have been around for a few decades. The latest trend of thought is to marry a design methodology with a software solution, something that has not really been available until the recent advent of affordable, real computing power, currently in the shape of 32 bit, 66 MHz desk top computers.
Debris Protection System For Liner Tops
Authors: Telfer George , Sweeney Dave
Published: October 2008

This paper will introduce a new design of debris protection system for liner tops. The system has been used extensively in the North Sea and has solved the problem of well debris (e.g. formation cuttings/fines, mud solids, cement solids, foreign bodies etc.) entering the liner top P.B.R. and sticking the setting tools.

INTRODUCTION

Well debris entering liner top polished bore receptacles (P.B.R.'s) during cementing operations has been a notorious problem for many years, and in some cases has led to liner banger setting tools becoming stuck in the liner top P.B.R. This can lead to the setting tool being cemented in place and result in an expensive fishing job or side-track. This paper will describe how Enterprise Oil experienced severe problems with well debris entering the liner top P.B.R. and sticking the liner hanger setting tool, In addition, it will describe how a prototype debris protection system was developed and tested prior to offshore application, and the subsequent successful use of the tool on Nelson development wells.

DESCRIPTION OF PROBLEM

During drilling of the early Nelson development wells in the UK North Sea, severe problems were experienced with well debris entering the liner top P.B.R. As a result, difficulties occurred retrieving the liner hanger setting tool. Although in all cases the setting tools were successfully recovered, it was evident that there had been a significant risk of cementing the liner running string into the liner top P.B.R.

In all cases, the well debris entering the liner top P.B.R. consisted of fine cavings of shale originating from the base of the Balder formation (see fig. 1). The setting depth of the 9.5/8" casing strings on Nelson development wells is governed by two factors, these being :The Eocene formation must be cased off prior to drilling the Forties formationCasing must be set prior to drilling into a loss zone. 85 feet TVD below the top of the Balder formation.

The Eocene formation consists of highly reactive and over-pressured shales which become unstable if drilled with mud weights less than 14.0 ppg, and the Forties formation is normally pressured sandstone in which differential sticking may occur if drilled with mud weights above 10.0 ppg. Therefore, to allow the Forties sandstone to be successfully drilled without inducing borehole collapse in the Eocene, the 9.5/8" casing string is set in the Balder formation. In addition, the Balder also contains a known loss zone when drilling with 14.0 ppg mud, above which the 9.5/8" casing must be set. These criteria dictate the setting depth of the 9.5/8" casing shoe. Having run and cemented the 9.5/8" casing string, the 14.0 ppg mud used to drill the 12. ¼" hole section is displaced to 10.0 ppg mud prior to drilling the 8. ½" hole section.