bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Heather Platform Leg Repair
Authors: Thompson J.M. , White A.R. 
Published: December 2007

This case history reviews the analysis and repair of a corner leg of the Heather A platform; damage was caused by a foundation pile dropped during installation. The paper describes the stereophotographic and mechanical templating techniques used to verify shell deformations. The choice of a mechanical solution and the interface with module installation and commissioning are reviewed.

Introduction
The Heather field is located in Block 2/5 of the U.K. sector of the North Sea (Fig. 1). The Heather A platform is located at 0 degrees 56'22.53" longitude and 60 degrees 57'13.51 "latitude, approximately 100 km (64 miles) east of the northern end of the Shetland Islands in 143 m (470 ft) of water. The oil field was discovered in Dec. 1973, and a steel-pile-supported platform was selected to develop the discovery. With the availability of larger pile-driving hammers, the decision was made in the fall of 1975 to drive 1.52-m (60-in.) diameter piles. Each of the 24 piles [96 m long × 64 mm thick (315 ft × 2.25 in.) and 218 Mg (240 tons)] is made from a 64-m (210-ft) lead section with a 32-m (105-ft) extension welded offshore. During the offshore piling operations in the summer of 1977, one of the piles had been joined and was being held by the derrick barge in preparation for lowering to the seabed, then one of the shackles linking two sections of slings broke. The pile, laterally restrained in the guides, dropped more than 40 m (130 ft) in almost free vertical fall before hitting the jacket at the location shown in Fig. 2.The extent of the damage posed a potentially serious setback to field development. With the reduction of load-carrying capability of the platform, the complete module installation program was reanalyzed. The selection of the repair method was judged in line with performing the repair during the winter period. A limited number of modules were installed on the platform by mid-Oct. 1977, when the repair operation commenced from the semisubmersible vessel Treasure Hunter. The first phase of the repair was completed by mid-Jan. 1978, and the second phase from mid-April to the end of May finalized the repair.This paper traces the stages of design, repair, and techniques developed and appraises the interface with the remainder of the development.

Description of Damage
Initial impact of the pile was at the cone-shaped section of the "bottle" where the leg diameter increases from 2.5 to 5.7 m (8 to 18.5 ft). The pile glanced off the cone, buckling the 40-mm (1.625-in.) thick plate and punching a hole [approximately 1.25 × 1 m (4 × 3.5 ft)] in the cylindrical shell. At the junction of the cone and shell is a critical ring stiffener designed to contain the hoop stresses at this change in section. This ring stiffener was torn in two places, and the tongue section in between was bent downward. As the pile fell, it continued to dent the cylindrical shell up to 200 mm (10 in.) radially and caused further damage to a second lower ring stiffener. Denting of the vertical shell was caused over some 4.5 m (14.5 ft).
JPT
P. 569＾
New-Generation Drillstring Safety Valves
Authors: Tarr B. A. , Luy R. , Rabby G. , Kickermann H. , Senftleben J. , Cunningham J. 
Published: December 2007

Summary
Drillstring safety valves (DSSVs) are considered an essential part of the well-control equipment on every rig, but performance problems in stripping operations motivated one operator to lead an industry effort to develop appropriate functional specifications for consideration by API and to conduct the associated performance testing described in this paper. Results of testing three different valves indicate that common DSSV performance problems can be addressed and that the proposed new performance specifications for a new generation of DSSVs are generally workable.
API subsequently incorporated many of the proposed changes into the 40th edition of API Spec. 7, identifying the new-generation valves as Class 2 valves suitable for surface and downhole (stripping) service.
The Arctic Pilot Project
Authors: Milne K.C. 
Published: December 2007

This paper describes the proposed Arctic Pilot Project, consisting of transmission, liquefaction terminal, shipping, and receiving terminal. Emphasis is on the unique problems resulting from the arctic location. Studies conclude that it is feasible to transport gas on a year-round basis from the arctic to the Canadian east coast.

Introduction
The Arctic Pilot Project proposes to transport 250 MMscf/D (7 × 10(6) m3/d) of gas from Melville Island in the Canadian arctic to markets in eastern Canada. The gas will be pipelined from the Drake Point gas field to Bridport Inlet on the south coast Point gas field to Bridport Inlet on the south coast of Melville Island, where it will be liquefied and loaded on ice-breaking LNG carriers for transportation to a regasification terminal in eastern Canada.The economical and environmentally sound transportation of gas from the arctic revolves around the answers to two important and basic questions.1. Can the Melville Island facilities be built on an economical and environmentally sound basis given that the location could be expected to result in conventional facilities that would cost at least five times that of facilities built in settled areas?2. Can large ice-breaking LNG carriers operate year round in the arctic waters leading to Bridport Inlet?Petro-Canada, The Alberta Gas Trunk Line Co. Ltd. (AGTL), and Melville Shipping Ltd. have spent more than $11 million and 2 years finding the answers to these two questions and have concluded that the project is feasible, that the capital cost will be about $1 billion, and that the gas will be delivered to southern markets at a competitive price.

Melville Island Facilities
These facilities include the gas transmission line across Melville Island, the floating LNG plant and storage, and the Bridport shipping terminal.The lack of site specific information, which increases uncertainties in scope definition, and the high cost of on-site labor result in (1) arctic construction costs (using conventional methods) that are at least five times the costs in settled areas; and (2) a high degree of uncertainty in estimating final cost. The cost of on-site labor for this project will be minimized by building facilities to the greatest extent possible in settled areas. This approach minimizes the possible in settled areas. This approach minimizes the environmental and socioeconomic impact on the arctic.

Gas Transmission
The proposed gas transmission line is a 95-mile (160-km), 22-in. (560-mm) buried chilled gas line. This size line has a calculated capacity of 336 MMscf/D (9.54 x 10(6) m3/d) at the design inlet and outlet pressures of 1,200 psig (8268 kPa) and 900 psig (6200 pressures of 1,200 psig (8268 kPa) and 900 psig (6200 kPa).The cost estimate was prepared by AGTL, assisted by Canuck Engineering Ltd. The costs were based on proved construction techniques such as those used in proved construction techniques such as those used in the permafrost sections of the Aleyeska pipeline. The estimators have assumed construction only in the months of April, May, September, and October.
JPT
P. 351
Permanent Mooring System for Large Construction and Support Vessels in the Piper Field
Authors: Lowe E.A. , Yin V.C. 
Published: December 2007

This paper illustrates the requirement, design, development, and installation of a permanent mooring system for construction support vessels in the Piper field in the North Sea. Key features of the mooring system and its installation procedures are detailed.

Introduction
The need for support vessels alongside the platform during construction programs offshore has focused attention on the problems of mooring and maintaining station in this service. In the past, mooring systems under storm situations have been designed primarily for open-ocean applications and have not primarily for open-ocean applications and have not catered to the requirements of operating and surviving alongside a fixed platform. In addition, anchor handling and dragging have been primary causes of damage to submarine pipelines. This problem becomes more acute as the number of problem becomes more acute as the number of vessels around the platform increases and the number of moorings over time becomes significant enough to constitute a hazardous situation.The Piper field operators - Occidental of Britain Inc. on behalf of partners Getty Oil Co., Allied Chemical (Great Britain) Ltd., and Thompson North Sea - experienced these mooring difficulties, compounded by poor topsoil conditions, which led to the design and installation of a fixed, permanent anchor-pile mooring system around the Piper A platform. platform. System Description
Eight anchor piles are positioned symmetrically around the Piper A platform to provide a suitable anchor pattern for a multiservice construction vessel to moor alongside the platform in periods of good weather and away from the platform in periods of bad weather. Each anchor pile is approximately 4,000 ft (1219 m) from the center of the platform, and the 1,010-ft (309-m) connecting chain lies on the seabed in a straight line between the anchor pile and the platform. The free end of each chain is connected to a pendant line and marker buoy, which is used to raise the free end of the chain to the surface during connecting or disconnecting operations (Fig. 1).

System Capabilities
The anchor-pile system is designed to accommodate construction and tender vessels ranging from medium-sized to third-generation semisubmersibles with operating draft displacements in excess of 40,000 Mg. This system allows for vessels to moor on any of the four sides of the platform and maintain adequate clearance of the mooring catenary from the legs of the platform jacket. The vessel anchor line is "shackled up" to the anchor pile, making it a semipermanent connection. These piles are able to withstand vertical and horizontal forces, thus allowing for adequate "spring constants" throughout the vessel excursion distance even after introducing uplift forces at the anchoring point.

System Design Mooring System
The mooring system consists of eight anchor piles encircling the platform.
JPT
P. 547
Engineering Calculations of Gas-Condensate-Well Productivity
Authors: Mott Robert 
Published: December 2007

Summary
Accurate forecasting of gas-condensate-well productivity usually requires fine-grid numerical simulation to model the formation of the condensate bank and to account for high-velocity phenomena such as non-Darcy flow and changes in relative permeability at high capillary number.
This paper presents a new technique for forecasting the performance of gas-condensate wells, using simpler techniques that can be used in a spreadsheet. The calculation uses a material-balance model for reservoir depletion and a two-phase pseudopressure integral for well inflow performance. The pseudopressure-integral technique has been extended to include high-velocity effects and to allow for the change in produced-fluid composition caused by the formation of the condensate bank.
The new technique has been tested by comparison with the results of fine-grid compositional simulation, and the results are in good agreement for a wide range of cases covering vertical, horizontal, and hydraulically fractured wells.
The spreadsheet-model approach provides a useful tool for rapid forecasts of condensate-well performance, for examining the effects of condensate blockage in different well types, or for studying sensitivities. It is also valuable where simple models of condensate-reservoir performance are required for use in integrated studies involving issues such as surface facilities, drilling schedules, and gas sales contracts.
Estimation of True Dispersivity in Field-Scale Permeable Media
Authors: Mahadevan Jagannathan , Lake Larry W. , Johns Russell T. 
Published: December 2007

Summary
Simulation studies (Solano et al.1; Stalkup2) show that oil recovery for enriched gas drives depends on the amount of dispersion in reservoir media, but the value of dispersion, expressed as dispersivity, is unknown at the field scale. This work focuses on three types of dispersion in permeable media to obtain realistic estimates of dispersive mixing at the field scale.
The dispersivity from single-well tracer tests (SWTTs), also known as echo dispersivity, is dispersivity that is unaffected by fluid flow direction. Layering in permeable media tends to increase the dispersivity observed in well-to-well tracer tests, also known as transmission dispersivity, but should not affect the echo dispersivity.
We analyzed a collection of SWTT data to estimate echo dis-persivity at the SWTT scale. The estimated echo dispersivities closely match a published trend with length in dispersivities obtained from groundwater tracer tests. This unexpected result—it was thought that transmission dispersivity should be greater than echo dispersivity—is analyzed with numerical simulation.
Another type of dispersive mixing is local dispersivity, or the mixing observed at a point as tracer flows past. Numerical simulation results show that the local dispersivity is always less than the transmission dispersivity and greater than the echo dispersivity. It is closer to one limit or the other depending on the amount and type of heterogeneity, the autocorrelation structure of the medium's permeability, and the lateral (vertical) permeability. The agreement between the SWTT echo dispersivities and the field trend suggests that the field data are measuring local dispersivities. All dispersivities appear to grow with length.
Profitability of Capital Expenditures for Development Drilling and Producing Property Appraisal
Authors: Arps J.J. 
Published: December 2007

Abstract
The appraisal of producing properties and profitability analysis of a proposed capital expenditure are based on the same principles. In both problems a projection of future cash income is compared to one or more capital expenditures. Several different methods have been in use either to compute a price to obtain a given earning power on the investment or to compute the earning power which will result from a given capital expenditure. One of these, the "Average Annual Rate of Return" method, computes in a simple manner the ratio of the present value of the future earnings after amortization to the present value of the undepreciated balances of the investment over the life of a project. This method, not well known generally, appears to have some rather unique advantages in reducing the computation work required, eliminating trial-and-error solutions, and providing a more accurate answer when applied to oil industry investments subject to the unit-of-production basis of amortization. Its derivation is given and its versatility demonstrated in the solution of certain everyday investment problems. A number of charts, useful in applying this method to profitability analysis and appraisal work, are provided. The current trend in the market values of producing properties is shown.

Introduction
Making sound capital expenditure decisions requires an objective means of measuring the productivity of individual investment proposals. Since the best measure of the economic worth of such proposals is their ability to produce profits, it is common practice to grade proposed capital expenditures according to their annual earning power as a percentage of the outstanding capital. The same principles which govern the determination of the rate of return of proposed capital expenditures also apply generally to the problem of determining the appraisal value or purchase price of income-producing oil and gas properties.
Both problems are of prime importance in the producing phase of the oil business, where management is faced daily with decisions to drill or not to drill certain development wells, or with the determination of the appraisal value of producing properties.
Downhole Fiber-Optic Flowmeter: Design, Operating Principle, Testing, and Field Installations
Authors: Kragas Tor K. , Bostick F. X. , Mayeu Christopher , Gysling Daniel L. , van der Spek Alex M. 
Published: December 2007

SummaryThis paper discusses the design, operating principles, flow-loop testing, and initial field installations of the world's first all-fiberoptic flowmeter for downhole deployment. The flowmeter provides real-time measurement of the flow rate, phase fraction, pressure, and temperature. It is deployed with the production tubing and is rated to 125°C and 15,000 psi. It is fullbore, nonintrusive, electrically passive, has no moving parts, and overcomes the design limitations imposed by downhole environments. Thus, it has the potential to provide highly reliable downhole measurements. The flowmeter has been tested extensively in industrial flow loops in a wide range of conditions. Results from the testing have demonstrated the flowmeter's ability to measure flow rates and water fractions in oil/water systems to within ±5% for the entire range of water cuts. These results have been validated by data from several field deployments.
Drag Reduction in Three Distinctly Different Fluid Systems
Authors: Sifferman Thomas R. , Greenkorn Robert A. 
Published: December 2007

Abstract
Drag reduction was observed in three distinctly different flow systems—dilute polymer solutions, two-phase solid/liquid suspensions, and three-phase immiscible liquid/liquid flow with suspended solids—in relatively large-diameter pipes (0.027, 0.038, and 0.053 m). Galvanized pipes presented a rough wall, while glass provided a smooth wall and allowed for flow visualization. By drag reduction, we mean that, for the same flow rate, there is less pressure drop per length of pipe than for the base fluid flowing alone.
Three polymers—sodium carboxymethylcellulose (CMC), polyethylene oxide (POLYOX™), and guar gum (Jaguar™) were mixed with water to form solutions of various concentrations (from 0.001 to 0.3 wt%). Two nominal concentrations (5 to 10%) of silica sand also were suspended with either tap water or some of the polymers. Finally, white mineral oil and either tap water or polymer solutions were tested. Sand also was added to the oil system.
Drag reductions of up to almost 80% were obtained for both the polymer systems and the oil system. Sand suspensions had a maximum of about 35% drag reduction in tap water. However, greatest reductions (more than 90%) were attained with the polymer/sand suspensions.
Since the sand in the polymer solutions reduced the drag even more than the polymers alone, it may be that the drag mechanism is additive and even may be the same type for both polymers and suspensions.
Drag reduction occurs in the region near the wall and could occur in an intermediate layer or zone that allows an effective slip velocity to result. Polymers showed significant deviation from the Newtonian velocity profiles.
Less power was required to pump the polymers than water alone. Viscosity and normal stress data were obtained also.
An Experimental Study of Drag Reduction of Polymer Solutions in Coiled Tubing
Authors: Shah Subhash N. , Zhou Y. 
Published: December 2007

Summary
The drag-reduction (DR) behavior of xanthan gum, partially hydrolyzed polyacrylamide, guar gum, and hydroxyethyl cellulose at various polymer solutions has been experimentally investigated with a full-scale coiled-tubing (CT) test facility that consists of 1-, 1½-, and 2⅜-in. CT reels. Data analysis revealed that the tubing diameter, curvature ratio, and polymer concentration are important factors affecting the DR in CT. The modified DR envelope is a useful tool for evaluating the DR performance of polymer solutions in CT.
Fast Induction-Log Inversion Using Quasi-Newton Updates
Authors: Gao L. 
Published: December 2007

SummaryInterpretation of induction-logging data is difficult because of its diffusive nature and its large volume of investigation. To overcome these difficulties, various techniques have been applied in the past. These techniques include deconvolution filters, least-squares inversion based on the maximization of entropy and on neural-network techniques. Among them, the maximum-entropy method is the most robust. Unfortunately, it is computationally intensive and can only be carried out in computing centers. To reduce this intensity and accelerate the inversion process, a new method has been developed for induction-log inversion using quasi-Newton updates of the Jacobian matrix. Using the new method, 200 ft of log data can be inverted in 80 seconds on an 800-MHz notebook computer.
Application of Water Injection/Falloff Tests for Reservoir Appraisal: New Analytical Solution Method for Two-Phase Variable Rate Problems
Authors: Levitan Michael M. 
Published: December 2007

SummaryThe challenges of reducing or eliminating emissions associated with well-testing operations during reservoir appraisal have revived interest in water injection/falloff tests. However, the two-phase flow and injection-induced temperature changes associated with injection/falloff tests complicate the problem of well-test analysis. Strictly speaking, these effects make the pressure transient problem nonlinear and preclude using conventional superposition technique to construct solutions for variable rate problems.In this paper, we present a new analytical method for accurate solution of the pressure transient problem for two-phase flow associated with water injection/falloff tests. The solution algorithm allows one to compute the solution for any stepwise constant rate sequence that includes multiple injection and falloff periods. The method is general, and can be used for water injection governed by any physically meaningful relative permeabilities, as well as for pistonlike displacement.
Analytical Theory of Coalbed Methane Recovery by Gas Injection
Authors: Zhu Jichun , Jessen Kristian , Kovscek Anthony R. , Orr Franklin M. 
Published: December 2007

SummaryInjection of either carbon dioxide (CO2) or nitrogen (N2) enhances recovery of coalbed methane. In this paper, we provide new analytical solutions for the flow of ternary gas mixtures in coalbeds. The adsorption/desorption of gaseous components to/from the coalbed surface is approximated by an extended Langmuir isotherm, and the gas-phase behavior is predicted by the Peng-Robinson equation of state (EOS). Langmuir isotherm coefficients are used that represent a moist Fruitland coal sample from the San Juan basin (U.S.A.). In these calculations, mobile liquid is not considered. Given constant initial and injection compositions, a self-similar solution consisting of continuous waves and shocks is found. Mixtures of CH4,CO2, and N2 are used to represent coalbed and injection gases. We provide examples for systems where the initial gas is largely CH4, and binary mixtures of CO2 and N2 are injected. Injection of N2-CO2 mixtures rich in N2 leads to relatively fast initial recovery of CH4. Injection of mixtures rich in CO2 gives slower initial recovery, increases breakthrough time, and decreases the injectant needed to sweep out the coalbed. The solutions presented indicate that a coalbed can be used to separate N2 and CO2 chromatographically at the same time coalbed methane (CBM) is recovered.