bluuebunny/crossref_metadata_2025_split huggingface dataset:
Alternate Methods for Installing ESP's
Authors: Robison C.E. , Cox D.C. 
Published: October 2008

ABSTRACT
In place of using a workover rig, this paper introduces: two different ways of running and pulling electric submersible pumps (ESP's), the conditions that make the methods attractive, the completion options for such installations, and computer generated graphs to show the expected production capacities for several combinations of pumps and completion schemes.

INTRODUCTION
ESP's are typically installed on threaded pipe joints with a workover rig; and while this is the industry standard, a number of alternatives are now available. Two cable deployed methods have been demonstrated in live wells and the results are a matter of record. This paper will describe two additional deployment options; using coiled tubing and using a hydraulic workover un it, both of which use proven techniques and equipment.

BACKGROUND
Conventional workover rigs have been used to install and retrieve ESP's due to availability, cost and familiarity of the method. However, in remote or offshore areas there may be a significant length of time an ESP is shut down awaiting service due to logistical problems in mobilizing the ri g or in the cost associated with a workover. It is in these areas that an alternative means of servicing ESP wells is desirable.
Deploying ESP's on cable has been presented previously. 1,2,3,4,5 In one configuration, the strength cable is integrated with the electrical power cable so there is not a requirement to insta11 supportive devices between the power cable and strength cable. A modified coiled tubing injector is then used to run the pump and cable into the well. This results in the most straightforward installation and retrieval method of any option available.
Perhaps overlooked, coiled tubing offers a viable means of deploying ESP's. The modular design of a coiled tubing unit makes it easier to mobilize and more flexible as to location than a workover rig. Coiled tubing runs smoothly and continuously without the sudden jerks and starts of rig installations. This is easier on the ESP. In a 6000 foot installation, coiled tubing eliminates 200 threaded joints; each a possible leak point. A standard ESP wellhead can also be used.
ESP's have been installed with a hydraulic workover unit (sometimes referred to as snubbing units). Like workover rigs, threaded pipe joints are used. Although the process is a bit slow, in those cases where offshore deck space is at a premium it may offer the only means of servicing the pump short of a cantilever jack-up rig. The length of time needed to schedule and deploy such rigs can be considerable; and while waiting, the well produces no revenue. The time to mobilize a hydraulic workover unit will usually be much shorter so that the additional service time to deploy or retrieve the ESP is not significant.

DESCRIPTION OF SYSTEM
The components of the coiled tubing system are shown in Fig. 1. The system is comprised of a tubing injector, a work window, a spool of coiled tubing, a spool of electrical power cable, and a hydraulic power pack and operator's console (not shown).
Laboratory Testing of Reflected Pressure Pulses in Small-Diameter Tubing
Authors: McStravick D.M. , Rothers David , Blum Gerhard 
Published: October 2008

Abstract
This paper reports on analysis and laboratory testing of induced hydraulic transients in 1/4 inch tubing. The form of the reflected pulses gives information as to the end condition of the far end of the tubing. This paper gives results of testing with up to 1500 ft. of 1/4 inch tubing. Classic open and closed end conditions show the expected opposite signs in the reflected pulse. The intermediate condition of a chamber at the end of the line shows a combination open end response followed by a closed end response.

Introduction
1/4" Tubing is commonly used to actuate hydraulic safety valves and for chemical injection lines. The safety valve closure mechanism is controlled by an internal hydraulic actuator which shifts from a small volume position (closed) to a larger volume (open) condition. The valves are remote from any personnel and so there is no local confirmation of valve actuator status. Hydraulic transients which are normally a nuisance in hydraulic systems and can show up as "water hammer" in hydraulic systems and even household plumbing, can be used to supply some information about the far end of a hydraulic line. Potentially these pressure pulses can give the actuator status (open or closed).
This paper reviews the laboratory testing to investigate reflected hydraulic transients both in regard to arrival time and the pressure pulse shape.
The classic analysis of water hammer shows that if flow is stopped suddenly (a valve is closed) a positive pulse is generated. This positive pulse will travel to the end of the conduit and reflect as a positive pulse if the end of the conduit is closed (ref.l). If the end empties into a large reservoir (an open end condition) the positive pulse will reflect as a negative pulse (ref. 2 and 3). Water hammer pulses result from changes in flow velocity; pulses an be generated in a closed system (that has no flow) using a plunger type device. This method results in pulses that will travel down the tubing and undergo a reflection as in the water hammer analysis. In a liquid filled tube the reflected pulse can carry information as to the far end condition ofthe tubing. This is shown schematically in figure 1. A positive pulse reflects at a closed end as apositive pulse; a positive pulse reflects at an open end as a negative pulse (ref. 2). As will be seenlater in the paper for the intermediate case of a chamber (a small volume reservoir) at the end of the line, a positive pulse will reflect as an initial negative pulse followed by a positive pulse.

Wave Velocity
Although liquids are relatively incompressible for many analyses, the elastic nature of liquid for compression waves is a key aspect to phenomena of sound transmission, water hammer, sonar etc.
A Simulation Of The Formation Of The Mississippi Fan
Authors: Williams G.N. , Warren J.D. , Parmley K.L. 
Published: October 2008

ABSTRACT
A methodology has been developed which allows the structural history of a multi-layered marine sediment deposit such as a sub-marine fan to be recreated by simulating the fan's growth, layer layer, from the beginning of its existence until the present time. The technique is based on the concept of geotechnical stratigraphy and involves the simulation of two processes: the deposition of new sediment layers, and the consolidation of existing layers, This research describes the development of a numerical modeling and simulation technique for application in the field of geotechnical e engineering

INTRODUCTION
The advent of the electronic computer during the last half of this Century has produced spectacular advances in the applied sciences. In the process, a completely new mode of research, the computational approach, has come into existence. One of the primary tools of this new approach is the technique of computer modeling and simulation which allows a physical system to be studied by computer manipulation of its mathematical model
The primary objective of the research described hem was to develop new modeling and simulation methods for the study of multi-layered marine sediment deposits such as submarine fans In particular, the methods were applied to the large Mississippi Fan located in the Gulf of Mexico. Since consolidation is generally the most important process affecting fan geometry, the modeling and simulation techniques were designed around this concept. The goal was to develop techniques which could provide insight into how the formation and evolutionary processes active within the Mississippi Fan have changed the fan's geometry during the roughly two million years of its history. The basic approach was to recreate the fan's structural history through the use of a numerical simulation of the consolidation process.
The research can be partitioned into the following basic task:Develop an appropriate simulation model which quantifies the consolidation processDevelop a simulation database containing a discretized representation of fan structure.Collect and process sufficient data for defining current fan geometry.Perform a digital simulation to generate the fan's structural historyDevelop a visualization to show how the fan structure has changed during its past history

THEORY AND GOVERNING EQUATIONS

SUBMARINE FAN FORMATION
The Mississippi Fan is a large deep-sea turbidite deposit located in the northeastern Gulf of Mexico. It is generally. fan-shapedand composed of predominantly terrigenous sediments which have accumulated at the lower end of the Mississippi submarinecanyon. The fan is marked by a seaward bowing of the bathymetric Contours1 and extends seaward from the continental shelf of Louisiana to abyssal depths (Figure 1). The west Florida carbonate platform forma the fan's eastern flank, while the Texas-Louisiana Florida continental slope borders on the north and west. The fan's deeper portions merge with the Florida plain to the southeast and the Sigsbee plain on the southwest2.
The Investigation And Repair Of Defective Joints On The Kinsale Alpha Platform
Authors: Murphy Fergal , Smith B.L. 
Published: October 2008

ABSTRACT
This paper describes studies carried out to determine the cause of weld cracking experienced on the Kinsale Alpha jacket in the Cc/tic Sea and the subsequent design and installation of repair steelwork.
An investigative approach was used to create a life history of the jacket from fabrication to in-service conditions. This included consideration of both available field data and theoretical techniques to establish the probable causes of fatigue damage. In particular, the potential influence of fatigue damage due to wind induced vortex shedding vibrations experienced during construction was considered.
The design and installation of stressed grouted clamp repair schemes to five cracked joints, the methodology associated with their successful installation and the various crack monitoring methods used are all presented.
This work demonstrates the significance of wind induced vortex shedding on fatigue life, the use of recently available subsea monitoring techniques and the effective use of grouted clamps in providing a cost effective repair to subsea structural damage.

INTRODUCTION
In July 1990, during under water inspection of the Kinsale Head Alpha platform, severe cracking of the weIds at three joints was discovered. The platform is located offshore Cork, Ireland in the Celtic Sea and is operated by Marathon Petroleum Ireland, Ltd., (MPIL). The jacket is an eight legged structure, installed in 1977 and standing in a water depth of three hundred feet. The cracks were detected in joints at the -158ft, and -217ft, elevations and were in the member end connection welds of long slender horizontal diagonals.
The cause of the weld defects could not be explained as being due to in-service fatigue damage as all of the defective joints had calculated fatigue lives in excess of 1000 years, In addition, inspection of the same welds on a sister structure, the Kinsale Bravo platform, which was of identical design, yielded none of the problems identified on alpha.
Following a redundancy analysis which confirmed the medium term integrity of the structure, MPIL decided to commission studies to examine options for repair and investigate the cause of the weld cracking, Positive results from the investigative studies would provide confirmation of the extent of the existing problem and direction for future inspection programmed on both structures,
During a follow up inspection programme in May 1991, cracking was discovered at two further joints at the -158ft, elevation, again in the end connection welds of long slender horizontal diagonals. As part of this inspection programme, acoustic monitoring transducer arrays and strain gauges were fitted at some of the defective joints in an effort to obtain information on crack growth rates and strain fluctuations over the winter of 1991/92,
After consideration of all of the various options, it was decided to carry out repairs to the cracked joints during the 1992 diving season by installation of stressed grouted clamps.
Concrete Floating Central Facility
Authors: Marshall P.W. , Chabot L.G. 
Published: October 2008

ABSTRACT
The paper describes a large floating production/storage structure for 3000 ft. water in the Gulf of Mexico, which would serve as a central facility for several small TLWJ'S, mini-spars, or subsea templates.

INTRODUCTION, SUMMARY AND CONCLUSIONS
Figure 1 shows the concrete floating central facility (CFCF) which was studied. This would serve as a "mother"facility for several small TLWJ'S (tension-leg wellhead jackets), mini-spars, or subsea templates, in staged development of a giant offshore field, as well as for regional development of the surrounding deep water Gulf of Mexico basin. With smaller motions than a ship-shape FPSO, and no weathervaning, hard steel catenary risers can be used instead of flexibles, while the congestion and complexity of a 28-riser turret and swivels are eliminated. Production facilities would be installed in two stages, to accommodate an ultimate production rate of 150,000 b/d, as well as gaslift and waterflood. Storage of 500,000 bbl, with direct offloading into two DP shuttle tankers, can handle this throughput, with gas export via a small pipeline. The "mother" facility has no wells of its own.
Configuration studies yielded a concrete hull with 200- ft draft, a base tank diameter of 243-ft., and a clover leaf of four 88-ft. tanks at the waterline. These provide 16 points of support for the deck modules, with no Module Support Frame (MSF). First and second-order motions, and the response of several alternative moorings, were subject to two independent analyses. Structural design and outfitting studies were performed by Aker/NC. Two construction scenarios were investigated based on Gulf Coast construction.
Concrete quantity is 0.10 m3 per tonne of displacement, showing the benefit of using shell forms rather than flat walls, as well as the economy of large enclosed volumes. Motions are within previously defined limits for hard risers. Deck accelerations, including the gravity component of pitch, are 0.38g in the 100-year design storm, and 0.09 g in the annual winter storm. The hull can be completed and fully outfitted (including pre-installed interconnecting piping) at dockside, and floated out with a 45-ft. draft. The mooring and its installation accounts for 38% of the total installed cost. Deck modules are lifted on offshore, similar to a fixed platform. Payload can be carried on the CFCF for 50 to 65% of the cost of putting it aboard a TLP, while oil storage capacity can be provided at 80% of the cost for storage in a concrete senisumbersible.
The concrete floating central facility is a robust concept, adaptable to various Gulf of Mexico conditions, and belongs on the list of tankering options for deep water development.

MOTIVATION FOR A BIG CENTRAL FACILITY
At the 1991 OTC, a large discovery in 3000-ft. of water depth, in the Gulf of Mexico, was announced (ref.1). The reported size of the discovery, if fully developed, would be large enough for it to join the exclusive ranks of only seven other giant offshore fields in U.S. waters (ref. 2).
Production Geological Challenges Of Characterizing The Thin Oil Rims In The Troll Field
Authors: Evensen J.E. , Skaug Mari , Goodyear Peter 
Published: October 2008

ABSTRACT
The giant Troll Gas Field is located offshore Norway in water depths of 315–340m. Hydrocarbons are trapped in a shallow Upper Jurassic reservoir sequence comprising sands of excellent reservoir quality. The structure is subdivided into three large eastwardly dipping fault blocks. each with an underlying oil rim of varying thickness. A development plan is approved for the western most fault block area (Troll West Oil Province), which has the thickest oil rim (22–26m). The plan encompasses an extensive subsea development, based upon 18 horizontality completed production wells, the first of which will be drilled in early 1994.
During the past years, Norsk Hydro a.s have through integrated production geology evaluations, reservoir simulation studies and Iongterm horizontal well testing, both proven the producibility of these thin oil rims, and identified the critical elements of a successful horizontal well.
The current production geological efforts are directed towards effective geophysical, geological and petrophysical modeling of the reservoir package, to reduce the uncertain y associated with mapping of the location and geometry of high permeability sands within the oil column. This has involved increasing utilization of the extensive high frequency 3-D seismic datasets. Uncertainty will not be removed by adopting such techniques, so to quantify and understand the remaining uncertain y, stochastic modeling of the reservoir heterogeneities has been conducted in parallel with deterministic modeling.
Evaluation work also continues within the Troll West Gas Province fault block (12–14m oil rim). in an effort to prove The commercial potential for an additional 25–30 horizontal/ Producers.

1 INTRODUCTION
The Troll Field is located offshore Norway, in water depths of 315 to 340 m, some 100 km north of Bergen as shown in fig. 1. The field stretches into 4 Concession Blocks and comprises 2 Production Licences; i.e. Block 31/2 awarded in 1979 under Licence 054 with A/S Norske Shell as operator and the Blocks 3113, 3115 and 3116 awarded in 1983 under Licence 085 with Statoil, Saga Petroleum a.s and Norsk Hydro a.s as joint operators. Other participating companies are Conoco Norway Inc., Elf Aquitaine Norge A/S and Total Norge A/S. The individual shares of the participating companies were unitised in 1986 on the basis of Troll as a single field.
The Troll Field is a major gas accumulation with considerable volumes of oil located in thin oil rims between a large gas cap and a large aquifer. It can be separated into three major provinces:Troll West Oil Province (TWOP) Gas accumulation with an oil rim of 22:26 mTroll West Gas Province (TWGP) Gas accumulation with an oil rim of 12-14 m.Troll East (TE) Gas accumulation with an oil rim of O -4 m.
The outline of the provinces and the distribution of hydrocarbons in place are shown in fig. 2.
Extreme Surge And Mooring Load Of Fps Structures
Authors: Dogliani M. , Pittaluga A. 
Published: October 2008

ABSTRACT
Offset is an important parameter in a compliant structure mooring design. To evaluate maximum offset, commonly adopted methods are based on the assumption that the combined linear and Iow-frequency wave induced off sets are Rayleigh distributed.
This assumption could result incorrect, particularly in those cases, as for instance large volume tension leg platforms and tankers at single point mooring (SPM) where the low frequency component dominates the horizontal motion response.
Aim of the paper is to discuss this assumption and to evaluate the sensitivity of the extreme response of an SPM tanker to the damping, non-linearities in the mooring system as well as to sea state parameters.
To do this, a systematic analysis has been performed and the peak distribution of surge motion and mooring loads have been derived by means of a simplified numerical procedure specifically developed for extreme value evaluation.
The results show that the Rayleigh assumption is not suitable and that particular care is needed in the selection of environmental parameters, including the spectral shape. Even if the analysis has been limited to simple conditions (one degree of freedom, slow drift force only, long crested head sea) the conclusions are believed to hold true in most general cases.

INTRODUCTION
The use of floaters for production end storage is being more and more adopted for both marginal fields and deep water exploitation.
For marginal fields, tankers at single point mooring have became so popular that ad hoc guidelines and regulations have been put in force or are under development with e.g. API, ISO TC7 and IMO MSC Design and Equipment Committee.
As far as the safety of the SPM is concerned, one of the most critical aspects is the mooring system: its loss of holding capacity could lead to the tanker loss with extremely heavy consequences in terms human lives, environmental pollution of investment.
For this reason, it is essential that reliable predictions of the extreme mooring load can be made at the design stage.
Mooring loads are of random nature. Therefore, in order to predict their extreme values, a reasonably accurate, and suitable for design, stochastic model is needed which is not an easy goal to achieve.
As a contribution to the solution of this problem, a sensitivity analysis has been performed with the aim of investigating some still controversial points in presently adopted guidelines, namely the assumed Rayleigh distribution of SPM response peaks and the effects of sea state parameters, in particular the wave spectrum shape and the influence of wave peak period.

NUMERICAL METHOD
According to the simplified character of the analyses to be made, a single degree of freedom system has been adopted to represent the dynamic behaviour of the moored tanker the following equation of motion has been considered.