bluuebunny/crossref_metadata_2025_split huggingface dataset:
Study Of Sweet Corrosion In Horizontal Multiphase, Carbon Steel Pipelines
Authors: Vuppu A.K. , Jepsom W.P. 
Published: October 2008

ABSTRACT
Sweet corrosion in carbon steel pipelines carrying oil-water mixtures has long been a problem in the oil industry. A study to determine the corrosion rates and the type of deposits formed on the pipe surface under such multiphase flow conditions is described. Experiment are performed in a 10.16cm ID flow loop. Full pipe flow and slug flow conditions and the effect of a few inhibitors is studied. Temperatures upto 60C and several pressures, flow rates, oil-water fractions are studied. It is observed that non protective iron carbonate scales are formed below 60C. Iron carbide skeleton which emerges from the carbon steel is detected. Corrosion rates increase with an increase in temperature and carbon dioxide partial pressure and liquid flow rates. With an increase in oil/water fraction, corrosion rates increase upto 60% oil, for the conditions studied. Iron carbonate crystal deposition increases with temperature and pressure. Evidence of bubble collapse and localized corrosion is observed under slug flow conditions.

INTRODUCTION
Corrosion related problems in oil-gas production and processing operations result in millions of dollars each year in down time, lost production and damaged pipelines. With the use of enhanced oil recovery techniques, carbon dioxide corrosion in oil-water pipelines has become common causing much concern in transportation of these multiphase fluids over long distances from remote wells to separation sites. The use of corrosion inhibitors, surfactants and drag reducing agents to reduce the corrosion has met only with partial success. The effectiveness of these corrosion reducing agents depends on the flow regimes existing in the pipeline.
Several workers have studied carbon dioxide corrosion in carbon steel pipelines. However most of the studies were carried out in single phase systems using deionized water, or brine solutions saturated with carbon dioxide. Almost all the previous studies were conducted in rotating cylinder electrode equipment and in autoclaves. Recently some research was conducted in small diameter, single and two phase horizontal pipelines. However the flow mechanisms in small diameter pipelines, i.e. less than 5 cm can be different from those existing in 10 cm and larger diameter pipes. The effects of different flow regimes such as stratified, plug flow and slug flow have not been addressed. Hence, any extrapolation of results from single/two phase small diameter pipelines to multiphase larger diameter ones can lead to grave errors in prediction of corrosion rates.
Green, Johnson and Choi1 have shown the significant effect of the different flow regimes on corrosion rates. In slug flow, the instantaneous corrosion values obtained when a slug passes were at least two orders of magnitude larger than those existing under stratified flow conditions.
Many investigators have studied the chemistry of carbon dioxide corrosion in water and have determined iron carbonate as the main corrosion product.
New Subsea Technology Enhances Safety In Coiled-Tubi Operations During Well Test
Authors: Allred W.R. , Clark J.A. 
Published: October 2008

ABSTRACT
To preserve the safety of the rig when it is necessary to shut-in the well during coiled tubing service operations, the operator must be able to sever or pull the coiled tubing before emergency valve closure can take place. Norman y, because of the time factor, as in the case of a drill ship drive-off condition, pulling the tubing is not a viable option. The operator, therefore, has to depend upon available cutting methods.
Until recently, unless the coiled tubing in use was 1- ¼-inch [3.18 cm] OD × .095 [.241 cm] wall thickness or smaller, the operator had to solely rely on the shear rams of the coiled tubing blowout preventer (BOP) to cut the coiled tubing. Since the method of choice for cutting tubing is with mechanisms that can cut at the safety valve, with the shear ram of the coiled tubing BOP as a secondary safety system, it was apparent that the cutting capabilities of available mechanisms needed enhancement to accommodate the new larger-diameter coiled tubing.
This paper will describe the design and testing of a new 15,000 psi [103.4 1 MPa]-rated ball and seat mechanism that has a 3.O-inch [7.62 cm]-ID and has the capability to cut coiled tubing with OD's as large as 1-½-inches [3.81 cm] and a wall thickness of l/8- inch [.32 cm]. This is an improvement over traditional cutting mechanisms, which only offer 2- ¾-inch [6.99 cm]-ID for 15,000 psi [103.41 MPa]- rated equipment, and a cutting limitation of 1-¼-inch [3.18 cm] OD × .095 [.241 cm] wall thickness coiled tubing.
The increased OD and wall-thickness sizes that can be cut with this ball and seat cutting mechanism provide the operator with a more flexible coiled tubing service program that can enhance operational safety. The mechanism is adaptable to current designs of subsea test trees in use on floaters and drilling ships. Presently, the mechanism is being incorporated into a 15,000 psi [103.41 MPa]-rated safety valve for use on a jackup or land rig (Figure 1) (Available in full paper).
In addition to data from cutting tests performed with the newly-developed ball and seat mechanism, the paper will also address the applicability of this mechanism to new and existing well test safety valve designs.

INTRODUCTION
Since rig safety during a well test is one of the main priorities of the operator, the utilization of a reliable downhole safety valve to insure well control is of major importance. Because of its enhanced safety and flexibility characteristics, the safety valve that is normally used on a floater rig or drillship is the subsea test tree (Figure 2) (Available in full paper). This valve, which is spaced out in the BOP stack on the ocean floor, allows the operator to shut-in the well and unlatch from the test string in the event an emergency situation, such as a drive-off condition on a drillship, occurs.
Optimization Of Hpht Wells: Reducing The Cost Of Design Integrity
Authors: Watkins D.M. , Johnson R.E. , Moe G.R. 
Published: October 2008

ABSTRACT
Optimization of easing and tubing designs for critical wells has become increasingly important for economic reasons. This paper describes an investigation into the relationship between design criteria (minimum acceptable design factors and maximum acceptable number of pipes) and cost. The measurement of design integrity by both design factors and by probability of failure was evaluated with respect to reduction of costs. The results indicate that significant cost reductions, often on the order of 10-20%, are available by optimization of the string design.

INTRODUCTION
Tubular goods represent between 16% to 25% of total well costs 1,2 which amounts to between $3,000,000 and $7,000,000 for a deep, critical well. This provides the opportunity to save millions of dollars per operator per year by optimization of the tubulars so that the casing and tubing in the Well meets design integrity standards without being over-designed.
All designers of casing or tubing make decisions that balance cost against risk. The cost of the casing and tubing string can be reduced to some extent by controlling (operationally) the load on the pipe. Beyond that, the designer is often left to decide what minimum design factors are acceptable based on personal and corporate experience1. In a sense, the designer already considers the perceived probability distribution of the load and of the load resistance of the pipe when selecting an appropriate minimum design factor, yet cannot precisely say how much additional risk is involved in modifying those design factors.
Usually, the rating is some relatively low estimate of the actual load resistance of the pipe and the load is based on a very conservative estimate of the potential load conditions. The resultant design factor's arc used to evaluate a string's design integrity against failure modes: Burst, Collapse, Tension, Compression, and von Mises equivalent (VME) Triaxial Stress. Minimum acceptable design factors are usually greater than 1.0 to account for uncertainty in both load and load resistance.
If the safety factor could be determined, all designs with SF &gt; 1.0 would be acceptable. Since neither the loads nor the load resistance can be known precisely for each point in the string, the chance that SF &lt; 1.0 must be determined in order to estimate a probability of failure (PF).
Lowering the design factors to reduce the cost of the string involves no additional operational expense but does require careful justification. This is the role of PF analysis. Alternatively, increasing the number of pipe sections is a well known but underutilized method of reducing tubular costs. Doing so means that there is less excess load resistance capability along the length of the string. The usual argument against doing this is the additional expenses of maintaining additional categories and tracking the pipe. These expenses are increased in order to lower the risk of mixing the pipe on the rig and inserting a joint or a coupling where its strength will be insufficient.
Fast-Track Flexible Flowline Installation In Mississippi Canyon
Authors: Freet T.G. , Fitzgerald C.W. , Rebello A. 
Published: October 2008

ABSTRACT
Oryx Energy Company has successfully completed the fast track development of three subsea Mississippi Canyon 400 Unit wells in water depths ranging from 1355 feet to 2088 feet. The first well came on line in July 1993, just ten months after project approval, and all three wells were producing within thirteen months of project initiation. Flexible flowlines from each well were tied back to a shallow water platform, resulting in the longest and deepest flexible pipe installation in the Gulf of Mexico to date.
This paper reviews the selection and design of a flexible flowline system for surface connect/layaway from each well and tieback to a host platform covering distances of four to seven miles. The rationale for flowline system selection and actual field experiences of installing flexible pipe with welded connections are discussed. The challenges of coordination and scheduling with the drilling rig, lay barge, and host platform are reviewed. In addition, the inspection and repair of an anchors nagged flexible pipe section is addressed.

FIELD DEVELOPMENT HISTORY
The Mississippi Canyon (MC) 400 Unit is located in the Gulf of Mexico approximately one hundred miles southeast of New Orleans, Louisiana (Figure 1). The Unit consists of Blocks 356, 357, 400, 401, 444, and 445. The Operator became 100% owner of these blocks by acquiring leases, drilling to earn rights, and assuming relinquished ownership interests1.
In 1988, two exploratory wells were drilled in Block 401 (MC 401#1 and 401#2) in water depths of 1355 feet and 1697 feet. The wells were temporarily abandoned pending evaluation and eventual formation of the Unit.
In July 1992, preliminary engineering studies were undertaken to evaluate development options for the Unit. Various scenarios were considered, including well counts ranging from two to five. Concurrent with these studies, an evaluation was performed on the construction of a new platform in MC 357 for the tieback and processing of Unit wells. This evaluation was then compared with tieback opportunities at existing platforms in the area; this was an attractive option because early production could be achieved with lower capital requirements. Negotiations with the platform operator at West Delta (WD) 152 eventually led to a lease space agreement for tieback and production of MC 400 Unit wells.
In October 1992, a project plan was approved to develop three subsea wells in the Unit. The two MC 401 wells were to be completed, while a proposed location in MC 445 would be drilled and completed; all three wells would be tied back to the WD 152 platform (Figure 2).

FLOWLINE SYSTEM SELECTION
During the preliminary engineering phase, one of the first tasks was to perform an initial screening of various flowline scenarios. The objective of the screening evaluation was to focus engineering effort on cases most likely to be recommended, and avoid parallel effort on unlikely scenarios.
Lateral Loading on Piles Due to Slope Instability
Authors: Lupini F. , Chacin M.E. , Furiol A. , Troconis C.M. , Vargas F. 
Published: October 2008

ABSTRACT
This paper presents the Carpet Oil Loading Terminal Case history for which very flat slope instability was esponsible for the failure and structural collapse of seven ooring and/or breasting dolphins, plus the collapse of all Of the intermediate supports of catwalk bridges that rovide access to the dolphins, from or to the loading latforms. These supports collapsed before the dolphinsd as, in the whole, they were much weaker to support ateral thrusts, even though they were strengthened with additional piles, on several occasions. When movement of he dolphinsjrst became apparent, a monitoring program as designed to measure the displacement of the pile caps, Primary cause for failure was the very weak nature of he subsoil, but the triggering mechanism was the need to redge the bottom, further than previously in the past, ecause of the new recent condition of salutation and edimentation and to accommodate larger tankers with nger draughts. Although most of the dolphins failed in a hree year period, the trestles and the loading platformsHave not shown, so far, significant signs of distress.
This paper deals with the site assessment program, with at caused the failures, how the collapse occurred and he conclusions that were drawn during the study. eferencesn, omenclaturea, ndfiguresatendofpaper.

INTRODUCITION
Although Carpet site is not typically offshore the earning's from this case record may be very helpful in xamining other failures such those that have occurred in everal occasions in the Gulf of Mexico, or better in etermining methodologies for the design of offshore tructures that have to be located temporarily or rmanently in soft mud regions elsewhere in the world.
The Caripito Oil Loading Terminal belongs to Lag oven .A. and is located in the north east region of Venezuela, rth of the Orinoco river delta region, as shown in Figure 1.
The facilities consist of two main trestles as shown in igure 2, with two loading platforms (Terminal 2 and rminal 3) and eleven dolphins, numbered 5 to 15, built In 1981-1982. Terminal 1 is a smaller structure for service essels and in all has four dolphins, 1 to 4, built in theSame period. The whole complex is located on the rightiver bank of the San Juan River which, in truth, despite eing located about 70 km up-river horn the sea, behaves ery much like an estuary, with considerable tidal mplification. Tides at sea in the Gulf of Praia seldomReach 2.5 meters while at Carpet Terminal the tidal Fluctuation may reach 4.5 meters. The tide is semidiurnal ith a six hour cycle from low to high tide (MLWS to HWS).
Almost all of the dolphins are located in the slope of the river, except the breasting dolphins 7, 8, 12, 13 which are located near the toe. Because of the high level of salutation nd sedimentation produced after the seventies due to theeforestation process between the late fifties and the sixties, at the river high basin, the terminal area is ermanently dredged to ensure sufficient draught for the vessels.
Development of a New Metocean Design Basis for the NW Shelf of Europe
Authors: Grant C.K. , Dyer R.C. , Leggett I.M. 
Published: October 2008

ABSTRACT
The paper discusses the development of a new metocean design basis for a deep water harsh environment off the NW shelf of Europe. The principal steps taken to achieve this, in an auditable and scientific manner, within the constraints of the available data and short time scale, are described. The industry partnership approach adopted to ensure early acceptance by all the relevant contributors, is outlined.

INTRODUCTION
This paper discusses the development of a new meteorological and oceanographic ("metocean") design basis for the first West of Shetland (WOS) Developmentsquadrant 204 (see Fig. 1). This area is exposed to the fill force of Atlantic storms which together with the water depth and a complex ocean current regime, presentunique challenges.

Location
In the general are the sea bed slopes from the edge of the continental shelf (approx, 200 m), to the bottom of the Fame-Shetland channel, where depths are 1000 m or re. The development location is in a water depth range of 375 m to 850 w with the first field "Foinaven", in 450to 500 m. For comparison the deepest North Sea development in the UK sector is BP's Magnus, in 185 m. ig. 2 demonstrates the differences in metocean designcriteria and illustrates the scale of the engineering challenge.

Data Sources
In the early 1970's, weather ships sponsored by the UK Offshore Operators Association (UKOOA) at "Fitzroy" (60°W, 4°W) measured wind and wave data. These were replaced later in the 70's by weather buoys at the "Foula"location approx. 50 km to the ENE. In the 1980's, dataas collected by the UKOOA data buoy DB3 in Block 206/6. During summer exploratory drilling, oceancurrent measurement campaigns by individual operators are also supported the drilling programmed in the area.
In addition to the measured wind and wave data the North European Storm Study (NESS) provides data from computer models (ref. 1). The NESS dataset contains some 25 years of winter data from 1964 to 1989, and provides output at 30 km intervals over the whole WOS area). Selected grid points and other data source locations are in Fig. 1.

Initial Design and Operational Criteria
Early metocean criteria for Foinaven issued in late 1993, were based on proprietary work carried out for the North West Approaches Group (NWAG) in 1988. NWAG is an ongoing joint industry group, with the objective of exchanging and collecting metocean data for the WOS area. It was formed in 1986 and currently has 13 oil company members (chaired by BP), together with the UKHealth and Safety Executive (HSE).
To reduce the period from discovery to development ("fast-track" project), requires considerable compression of the concept engineering, with design basis development in parallel with reservoir evaluation. The metocean design basis was, therefore, required considerably earlierthan has been traditional practice. A decision on the metoman data gathering was made in late 1993 afterconcept engineering identified the faibility of a floating production development on Foinaven.
An International Company's Gas Strategy In The Far East And Its Related Offshore Operations: A Case History
Authors: Duval B.C. , Beuaue J.M. 
Published: October 2008

ABSTRACT
This exploration and production strategy for gas was first developed in the late 60's when indonesia was rightly perceived as being a country with arge, geologically promising and almost untouched offshore acreage. First oil and later gas, discoveries were made in the Mahakam Delta Basin of Kalimantan, and very large gas fields were developed in response to a fast growing market for LNG, especially in Japan and the Far East Therearfter, a proactive search for opportunities in several countries was started, and this led to a concentration on fields in Thailand and Myanmar that had been already discovered but had not been developed because of specific technical difficulties and/or marketing uncertainties.
The risks and challenges of these projects are discussed, including the replacement of reservesin a mature area (Mahakam), the production of thin, numerous and structurally complicated reservoirs (Bongkot, Thailand), and the resolution of commercial problems (Myanmar), These challenges were successfully dealt with by the application of a combination of modern geo scientific technologies, the integration of separate disciplines and the introduction of cost-reduction measures,

INTRODUCTION
Total (hereinafter called the Company) has put into effect, over a period of the last 20 years, an aggressive strategy for the production of gas in the Far East. For the Company this type of activity had begun at an eelier date in the North Sea, with the discovery, development and production of the Friggfield (in U.K. and Norwegian waters) and in the Middle East with participation in the ADGAS liquefaction project and GASCOS LPG scheme (Abu Dhabi],
Although other gas projects have been launched during recent years in the North Sea (notably theoperated Alwyn-Dunbar complex in the U.K.) and in Argentina, it is in Southeast Asia that the number of developments has grown most spectacularly, to the point that this region of the world, which already figures very significantly in the upstream activity of the Company, will soon become our principal centre of operations and profit.
It seems interesting to describe the birth and development of this strategy with reference to both the planned moves and the events that influencedtheir progress. Each of these projects carried specific risks and challenges, technical or otherwise, and these will be analysed, together with the methodologies and approaches which were adopted to meet these challenges and attain the planned objectives.
The strategy encompassed Indonesia, Thailand, Myanmar and Vietnam, but the latter country will