bluuebunny/crossref_metadata_2025_split huggingface dataset:
Coiled-Tubing-Deployed Electric Submersible Pumping System
Authors: Lidisky D.J. , Pursell J.C. , Russell W.K. , Dwiggins J.L. , Lidisky Reda , Coburn G.S. 
Published: October 2008

ABSTRACT
The results of what is believed to be the first CT deployed Electric Submersible Pump (ESP) will be presented in this paper. Coiled tubing (CT) has long been used to accommodate many workover operations where a drilling or workover rig is either not available or is cost prohibitive. In many areas, the cost or lack of available rigs to service an ESP has been a limiting factor when considering ESPS for artificial lift. This field example shows the effectiveness of a coiled tubing unit for installing an ESP. The technical considerations addressed when designing a completion are discussed as they relate to a specific field installation. The installation proves the viability of using CT units as a means to utilize ESPS for artificial lift.

INTRODUCTION
CT has been used throughout the world for a variety of workover operations since its introduction in the 1960s. CT is used extensively for a variety of purposes including: logging highly deviated wells, well stimulation, cementing, perforating, drilling and cleaning out fill material. The same economics which drive the use of CT for the above operations, make it an attractive method for deploying ESPS where the cost of a workover rig is prohibitive.CT is a continuous length of tubing coiled onto a large reel which is driven by a portable control unit. An injector feeds the tubing into the well and is also used to pull the tubing out of the well (Fig. 1). The tubing is fed through well control equipment and into the well. CT is currently available in a variety of sizes ranging from 0.75 inch outside diameter (0. D.) (19.1 mm) to 3-1/2 inch O.D. (88.9 mm). Also, yield strengths from 70,000 psi (483 MPa) to 100,000 psi (689 MPa) are available. Most CT is similar to standard N-80 grades of tubing and may be considered for use in environments suitable for N-80 tubing. If extreme corrosion resistance is a requirement for a given completion, other materials such as titanium exist to suit almost any downhole environment.
The ESP system comprises a downhole pump, electric power cable and surface electrical controls. In a typical application, the downhole pump is suspended on a tubing string hung in the wellhead and submerged in the well fluid (Fig. 2). The ESP has the broadest range of any artificial lift method. Pumps are available from 100 bbl/day (18.4 m3/day) up to 95,000 bbl/day (15,100 m3/day). ESPS can produce from depths up to 15,000 feet (4570 meters) in 4- 1/2 inch (114.3 mm) and larger casings. Systems are available to perform in wells with bottom hole temperatures up to 450 deg F (232 deg C).
Because both the CT technology and the ESP technology already existed, only the details of a work window for the purposes of assembling and running ESP equipment had to be designed and built. Also, a procedure for using ESPS and CT together had to be formulated.
Installation Of 27 7/8-In. Coiled-Tubing Tailpipes In Live Gas Wells
Authors: Campbell J.A. , Bayes K. 
Published: October 2008

ABSTRACT
This paper describes a technique for installing 2 7/8" coiled tubing as tailpipe extensions below existing production packers in live gas wells.
Large savings in rig time and deferred production have been made using this technique. Fluid losses to the formation do not occur and no expensive rig time is used in killing or cleaning up the wells as would occur in conventional workovers below existing production packers.
This technique has applications particularly in depleted reservoirs that could be impaired by traditional workover methods.

INTRODUCTION
The Leman gas field was discovered in the early 1960's and has been producing gas from the Rotleigendes sandstone sincel969. (See Figure I.) As cumulative production has increased, reservoir pressures have declined to the point where the formation is no longer able to support a column of fluid, consequently causing problems whenever workovers are attempted which require kill fluid across the perforated interval. These operations can result in large amounts of fluid being lost to the formation, resulting in formation damage and delayed reinstatement of production. In most cases, any tubular change outs or work associated with completions are performed by setting isolation plugs in the existing tailpipes, preventing any associated problems with loss of kill fluids to the producing interval. As production rates have declined, the ability of individual wells to lift out produced fluid has been reduced, resulting in liquids accumulating in the wellbore. Liquid load up in the wellbore has resulted in increased hydrostatic pressure on the reservoir, further reducing the energy available to produce gas.
Over recent years a number of Leman wells have been worked over using a cantilever jack-up rig to remove the original 5½" production string and replace it, typically, with a 3 ½" diameter string to improve production velocities and fluid removal from the wells.
These operations have continued, however, in 1991 it was recognised that to optimise production velocities in the casing sections below the production packers, the existing tailpipes would have to be extended several hundred feet down to the perforated interval.
With the known problem of performing workovers across the perforated interval, it was decided to use wireline to install 2 7/8" tailpipe extensions with the wells still live. It was felt that any technique to install tailpipes would only be financially beneficial if it could be accomplished without introducing kill fluid into the producing formation. The maximum length of tailpipe that could be run on wireline with current techniques was in the order of 50 feet. Post commissioning results have shown that tailpipes of this length did not provide any substantial benefits and it was recognised that the length of the tailpipe would be crucial to maximise the lifting capacity of the produced gas below the production packer.
Design Of Insulated Flowlines For Mobile Bay
Authors: Hoose J.W. , Hazlegrove B.M. 
Published: October 2008

ABSTRACT
Insulated CRA flowlines are used in Mobile Bay for connecting well templates to host processing platforms. This paper describes the design of the flowline insulation system. Design issues for structural integrity are presented. Inlet temperatures of up to 200°F and operating pressures of up to 11,000 psi are accounted for. The flowline system consists of a 4-inch CRA pipe in an 8-inch carbon steel jacket.

INTRODUCTION
Gas reserves in three offshore fields in the Mobile Bay area are being developed; the Bon Secour Bay Field (inside Mobile Bay), the Northwest Gulf Field (south of Dauphin Island), and the North Central Gulf Field (south of Fort Morgan Peninsula). Water depths in the area range from 10 to 50 feet. Insulated subsea flowlines were designed to connect three 8-pile production platforms to seven remote well templates, while a gathering system connects the production platforms to an onshore processing plant in south Mobile County. The primary fluid service is hot, high pressure, sour gas.
The flowline system consists of two fluid conduits, produced gas and dilution water, and an 8 Kv rated electric power cable. Deoxygenated dilution water is pumped from shore to the production platforms and then to the well templates for use in flushing out the wells to dissolve salts. Power is supplied from the production platforms to the well templates. The produced gas flowline design pressure is based on shut-in tubing pressures of 8700 psi for Bon Secour Bay and North Central Gulf Fields and 11,000 psi for Northwest Gulf Field. The design flowline temperature is based on a maximum cooler inlet temperature of 2000 F. The flowline is Insulated to prevent hydrate formation under reduced f10wrates during winter months.
The flowline field arrangement (In Figure 1) includes the following:Bon Secour Bay (BSB) Field Production platform In Alabama State Block 62 connected to a remote well template In Alabama State Block 63 with two (2) gas flowlines, two (2) dilution lines, and one (1) power cable.North Central Gulf (NCG) Field Production platform In Alabama State Block 115 connected to a remote well template In Alabama State Block 114 with one (1) gas flowline, one (1) dilution line, and one (1) power cable.Production platform in Alabama State Block 115 connected to a remote well template in Alabama State Block 827 with one (1) gas flowline, one (1) dilution line, and one (1) power cable.Northwest Gulf (NWG) Field Production platform In Alabama State Block 112 connected to a remote well template In Alabama State Block 112 with one (1) gas flowline, one (1) dilution line, and one (1) power cable.Production platform In Alabama State Block 112 connected to a remote well template In Alabama State Block 868 with one (1) gas flowline, one (1) dilution line, and one (1) power cable.
Investigation Of A North Sea Oil Platform Drill Cuttings Pile
Authors: Hartley J.P. , Watson T.N. 
Published: October 2008

ABSTRACT
A comprehensive study of the drill cuttings pile at N W Hutton was undertaken in August, 1992. Fifty one welIs have been drilled in the field, mainly using mineral oil based drill fluids, with the cuttings discharged to sea.
The cuttings pile was mapped using a 3D side scan sonar system and the periphery was defined by towed side scan sonar and gamma ray spectrometer surveys. The pile was cored by vibrocorer to a maximum depth of 2.35m. The cores were assessed geotechnically and subsampled for physicaI and chemical analyses.
Environmental impact was investigated by grab sampling at 12 stations out to 7500m, Selected on the basis of cuttings distribution.
All surveys and samples were located using a differential global positioning system.
The results are relevant to the corrosion and long-term environmental effects of oily cuttings piles, the remove/leave alone debate, and abandonment planning.
Beneath the platform the pile is 5m high, with a low angle of repose and extending out to about 200m.
The cuttings in the cores were SOJ, with laminations and only minor compaction in deeper layers. The top 1-1.5m resembled freshly discharged material. The cores were sub sampled for hydrocarbon, trace metals and sulphide content and grain size analysis. Metals analyses included identification of metal species to estimate bioavailability and implications of pile disturbance.
Estimates of oil migration within the pile are made from correlation of the chemical analyses results with the drilling history, in particular the change from diesel to low toxicity base oil in 1984.
Strong gradients were found in the faunal data which correlate well with the physical and chemical results. Dense populations of opportunists species were present adjacent to the platform, including a novel molluscan opportunist.
This is the first comprehensive study of an oily cuttings pile and is a contribution to the debate on their long term impact and fate on abandonment.

INTRODUCTION
Oil based drilling fluids (OBM) have been extensively used in the development of North Sea oil and gas reserves to facilitate the drilling of often highly deviated wells through long sections of halite or reactive shales. The discharge to sea of the resultant rock chippings (cuttings) has been permitted by North Sea states, although with progressively more stringent discharge standards.
OBM cuttings tend to be more cohesive than those drilled with water based fluids (WBM) because a proportion of the mud remains adhered to the cuttings surface even after treatment with efficient shale shakers. Unless strong water currents are present (as for example, in the southern North Sea) this cohesive nature results in the majority of cuttings forming a mound beneath and adjacent to the installation. These piles of discharged cuttings have a number of operational implications including hindering jacket inspection and maintenance, increased loading of structural members and enhanced corrosion through sacrificial.
Confirmation Of A Wel ?S Mechanical Integrity
Authors: Bigelow E.L. 
Published: October 2008

ABSTRACT
Environmental protection is a major consideration in developing today's offshore resources. Protecting the natural habitat from pollutants is a significant factor in offshore drilling and production. It is also important that shallow, potable water supplies and other important minerals be protected from contamination beneath the surface. Today, wireline technique scan effectively monitor tubular goods and annular cement to determine their capacity to confine potentially harmful materials. The location of corrosion, pits, splits, and other corrosive effects on the inside or outside of tubular goods can be pinpointed, and the magnitude quantitatively evaluated with acceptable accuracy. A system of sectorial evaluation permits the entire tubular periphery to be accurately evaluated for cement shear and hydraulic bond, and to determine if effective zone isolation is established. Data from several test wells and practical field examples support the effectiveness of the sectored, pad-mounted bond log instrument. Recognition of zone isolation and/or hydraulic cement integrity is virtually 100% accurate with the proper measurements, and pinpointing problem areas in a casing string permits effective remedial action to be taken. When conditions are irreparable, the well can be properly plugged and abandoned.

CASING OVERVIEW
Steel casing is manufactured by means of two successive processes that convert an iron oxide to an iron and steel alloy. A blast furnace initially transforms the iron ore to molten pig iron, a solution of carbon, iron, silicon, phosphorous and sulfur. The pig iron is then refined by a steelmaking process to reduce the high concentrations of unwanted elements to acceptable levels, steel being the end product. Steel is formed into casing and other tubular goods at a pipe mill. The heat energy used to convert iron ore to steel is ironically the cause of corrosion of steel casing in a wellbore (Fig. l).l

CEMENT OVERVIEW
During well cementing operations, a cement slurry is pumped downhole through the casing and back up the annular space between pipe and borehole wall. The cement is then allowed to "set" or "cure" and, as a result, develop its compressive strength.2 Cement serves two principal function:shear bond, which mechanically supports the casing, Andhydraulic bond, which restricts fluid movement longitudinally along the casing and between adjacent geological horizons
A fundamental problem in cementing is fully displacing the fluid in the casing annulus. Hydraulic bond at the cement- to-formation interface is largely influenced by the presence or absence of filter cake and by rock type.
Permeable formations usually experience better hydraulic bond because cement slurry loses water to the formation and develops a higher compressive strength.2 High efficiency is often difficult to achieve as a result of the ease with which cement flows through the larger annular regions and its ability to flow through narrow annular regions. Several remedial measures alleviate the problem, Also, well cement.
Collar Load Support (CLS) Tubing Running Procedure
Authors: Boutwell D.F. , Webre C.M. 
Published: October 2008

ABSTRACT:
This paper discusses a significant new procedure for running CRA tubulars that relies on new innovative technology. The procedure completely eliminates all die marks and other mechanical damage that result from traditional running procedures and hardware. This is accomplished through the use of a number of new and innovative devices that rely on supporting the tubing string weight on the face of the coupling.
This procedure, known as the Collar Load Support(CLS) Tubing Running Procedure (U.S. Patent 5,083,356), employs the use of Load Transfer Sleeves(L'f13)to lower the tubing string into the well bore. These sleeves carry the weight of the string under the face of the coupling. The sleeves transfer string loads between elevator and a special landing spear without allowing any radial loads to be applied to the tubular body. The connections are made up power tight with specially built power tongs that employ new technology for gripping both the tubular body and coupling O.D. through the use of friction rather than toothed dies.
Utilization of the procedure requires that additional design considerations of the tubing string (specifically couplings) be evaluated and satisfied, along with the anticipated environmental requirements. The history of the development of the procedure is discussed, and the testing program to prove the feasibility of the procedure is detailed. The resulting data and actual performance of the CLS Running Procedure in a ease study clearly demonstrates the potential for cost savings via reduced wall thickness requirements and increased tubular life in the well.

INTRODUCTION:
Hostile environments found in deep, high pressure gas wells require that extra precaution be taken to extend the productive life of the well. These measures often result in the use of corrosion resistant alloys (CRA'S)to prevent premature failure of the production tubing.
Traditional procedures and hardware used to carry out installation of tubing, rely on toothed inserts or dies and gripping mechanisms that force the die or insert teeth to penetrate into the outer wall of the tubing. The dies or inserts are forced radially inward against the pipe O.D. by the interaction between the tapered bowls and slips into which the dies are fitted. The magnitude of the radial forces is quite high and is influenced by the condition of the slips and bowl along with the lubrication between the slips and bowls. The resulting die marks in the pipe are typically abrupt V-shaped notches. In the process of deforming the material to allow for die penetration, the pipe wail beneath these notches is work hardened, thus compounding the severity of the die marks.
CRA materials are typically restricted to a maximum hardness or hardness range in order to obtain satisfactory corrosion resistance performance. Many industry majors have developed guidelines which limit the acceptable depth of these die marks. Ideally complete elimination of the injurious die marks and associated cold working would permit optimum performance of the CRA material.
Ocean Drilling Program: Results From Ninth Year Of Drilling Operations
Authors: Rabinowitz P.D. , Francis T.J.G. , Baldauf J.G. , Coyne J.C. , Harding B.W. , McPherson R.G. , Merrill R.B. , Olivas R.E. 
Published: October 2008

ABSTRACT
The Ocean Drilling Program (ODP) has completed 52 internationally staffed expeditions and nine years of scientific ocean drilling in search of answers relating to the tectonic evolution of passive and active continental margins, origin and evolution of oceanic crust, origin and evolution of marine sedimentary sequences, and paleoceanography. To address these problems, ODP has made numerous advances in technology for retrieval of continuous undisturbed cores under hostile environmental conditions. ODP curates over 187 km of cored material and associated scientific data bases and publishes results of the scientific expeditions in a continuous series of Proceedings volumes.
During its ninth year, ODP completed its pioneering exploration in the Pacific Ocean and commenced a campaign of Atlantic Ocean coring. Leg 147 sampled Hess Deep in order to understand igneous, tectonic and metamorphic evolution of fast spreading oceanic crust and to understand the processes of rifting in young ocean crust. Leg 148, near the Galapagos, deepened Hole 504B, the deepest hole we have beneath the deep sea floor to 2111 mbsf in an attempt to penetrate oceanic Layer 3. Leg 149, entered the Atlantic Ocean and cored the rifted margin of the Iberian Abyssal Plain in order to study its subsidence history and the age and nature of the ocean-continent transition. Leg 150 retrieved 4034 m of core on a transect of sites off New Jersey aimed at studying late Oligocene through Miocene sea level changes. Leg 151 in the Norwegian-Greenland Sea made use of an ice-support vessel in the Fram Strait region of the Arctic Ocean to investigate high northern latitude ocean's role in global climate and ocean systems. Leg 152 investigated deformation of the lithosphere and mechanisms of magma emplacement on the East Greenland Margin.
Leg 153 is scheduled to drill the lower crust and upper mantle in the MARK area of the mid-Atlantic Ridge; Leg 153, on the Ceara Rise in the western equatorial Atlantic will piston core a depth transect and answer important questions of paleoceanographic significance; Leg 155 on the Amazon Fan will sample several acoustic units to determine their lithologies, facies and ages; and Leg 156 is scheduled to drill a number of holes penetrating the deéollement zone and spanning the deformation fronton the Northern Barbados Ridge. Legs 157 to 165 will continue our Atlantic Ocean exploration by drilling near Volcanic Island Apron of the Canary Islands (Leg 157), TAG Hydrothermal province of Mid-Atlantic Ridge (Leg 158), Equatorial Atlantic Transform (Leg 160), Mediterranean (Leg 161, 162), Atlantic Arctic Gateways (Leg 163), Gas Hydrates on Blake-Outer Ridge (Leg 164) and Vema Fracture Zone (Leg 165). One expedition will visit the SW Indian Ridge in the Indian Ocean (Leg 159).
This paper focuses on ODP'S scientific and technical achievements during its ninth year of field operations and discusses areas of future study.