bluuebunny/crossref_metadata_2025_split huggingface dataset:
Advancements in SPOOLABLE Completions to Accommodate Wireline Operations
Authors: Gauthier Sammy , McGavern Cecil , Sides Winfield 
Published: December 2007

Abstract
The benefits of SPOOLABLETM completion systems have become more apparent as the technology develops. Advancements in the first generation of center-set spoolable products have led to the development of concentric throughbore and wireline retrievable technology. This technology includes such products as through-bore, surface-controlled subsurface safety valves, tubing-retrievable, concentric, gas lift valves and wireline-retrievable center set gas lift valves. The advantages of these products is the ability to perform wireline operations, including bottom hole surveys, well control and gas lift valve installation and retrieval through the coiled tubing without pulling the string.
This paper discusses the development and testing of these products along with manufacturing the system assembly and developing installation methods specific to spoolable completions. In addition, typical completion designs including options for hanging the completion and bottom hole seal assemblies are reviewed.
Issues such as helical buckling and residual bend inherent in coiled tubing installations affecting the ability to perform standard wireline operations in coiled tubing completions are discussed. Extensive wireline testing has demonstrated the ability to set and retrieve a gas lift valve through several spoolable completion products. The results and implications of these significant tests are detailed in this paper.
Elongation of Coiled Tubing During its Life
Authors: Newman K.R. , Sathuvali U.B. , Wolhart S. 
Published: December 2007

Abstract
Due to plastic bending at the reel and guide arch, coiled tubing (CT) elongates with each trip into and out of the well. Laboratory experiments, finite element, numerical and theoretical modeling were performed to determine the magnitude of this elongation. The elongation for loads above an axial transition load are permanent while the elongation for loads below this load can be removed by a bending cycle. Theoretical modeling shows that rotation of the CT in the well and axial loading while bending significantly increases the axial elongation.
Surface Characteristics of Coiled Tubing and Effects on Fatigue Behavior
Authors: Tipton Steven M. 
Published: December 2007

Abstract
The manufacturing procedure for coiled tubing induces different surface morphologies on the inner and outer surfaces. Since fatigue is a surface phenomenon, this can lead to different fatigue behavior at the two locations. This has been demonstrated in full-scale bending tests and in axial tests conducted on small coupon samples in closed-loop servohydraulic strain-control. Furthermore, service environments can cause localized defects on the outer and inner surfaces of coiled tubing, such as griding marks, corrosion pits, tool marks or injector block damage, which can have a first order effect on fatigue strength. However, it is demonstrated in this paper that there is an inherent tendency for cracks to initiate on the inner surface of coiled tubing. This tendency leads to the hypothesis that a "threshold severity" for external surface defects could exist, below which the fatigue strength of the tubing is not affected. Limited data confirm this hypothesis, and suggest that the severity could depend on the material grade.
Determining the Mechanical Properties of Coiled Tubing
Authors: Crabtree A. , Skrzypek H. , Wilde G. 
Published: December 2007

Abstract
Coiled Tubing is developing into a multi-talented work horse. Efforts to use the technology in high pressure deep wells, horizontal drilling and production logging require a better understanding of the mechanical properties of the tubing material. The basic design of any Coiled Tubing system causes the tubing to experience bending strains beyond the material's Yield Point when passing between the reel and the wellhead equipment. It is widely expected that such levels of cyclic straining will cause work softening of the tubing material. This paper describes a series of experiments to investigate the effects of plastic levels of strain on the Yield Point and Young's Modulus. A modified method of performing full body uniaxial tensile tests is described.
Further tests were conducted to demonstrate whether any evidence of anisotropy between the material properties in the axial and hoop directions could be found. The use of linear elastic theory to predict the stability of Coiled Tubing during well operations is acceptable in the presence of small degrees of anisotropy.
Using Coiled Tubing to Remove Silicate Scale from Geothermal Wells
Authors: Turton Simon D. , Courville Perry W. , Hewitt Patrick T. 
Published: December 2007

Abstract
Geothermal power plants use heat from the Earth’s interior to produce one of the cleanest sources of electric power currently available, but the production of geothermal fluids can be costly if large quantities of silica scale are deposited on production tubulars. This widespread problem significantly reduces the ID of the tubulars, thereby reducing the production rate of the well. Previously, scale removal techniques involved the use of a drilling rig and a combination of such mechanical tools as drill bits and mills. Rig-based methods, however, are expensive and time-consuming. This paper discusses the design, use, and evaluation of an alternative technique that includes a coiled tubing unit (CTU).
When compared to traditional rig-based scale removal techniques, coiled tubing methods offer several economic, environmental, and safety benefits.1 Specifically, the use of coiled tubing reduces job time because coiled tubing is faster to rig up/down and pull out of the well. From an environmental standpoint, well effluent and debris can be flowed through the flowline to the existing processing facilities; pits are unnecessary. Coiled tubing also provides a greater degree of safety and well control when operations are being performed on a live well.
In the case histories provided in this paper, three methods were used to remove scale. For the first method, the cleaning energy was applied by highly focused polymerized fluid jets, which were specially designed for the job by a computer program. This hydraulic technique can be performed on a live well, which results in additional savings over traditional methods. The steam production during cleaning creates the required annular velocities to remove debris from the well without the need for energized treatment fluids.
The second method consisted of a high-speed coiled tubing motor in combination with a flat-bottom junk mill. Although both mechanical techniques have been performed with varying degrees of success, both increased the geothermal production rates of the wells treated.
The third method involved the use of a silicate scale remover that was used between the slotted liner and openhole section. It was also used to treat the well when either of the first two techniques were slowed or stopped by particularly hard scale deposits.
Development & Application of Inline Connectors for Weight Restricted Offshore Operations
Authors: Reaper Alan 
Published: December 2007

Abstract
Cranage limitations in the North Sea have caused problems for coiled tubing operations for some time, particularly in the southern sector. This has been compounded by the increases in reel weights brought about by the trend towards larger tubing diameters, necessary to provide the desired pumprates and to cope with highly deviated wells. Until now, the options open were limited and all had practical and/or safety implications involving joining of tubing strings offshore by welding followed by radiography, or at least part of the operations being performed between the supply boat and platform. As a solution, in-line connectors for 1.5" and 1.75" OD Coiled Tubing (CT) have been developed which allows two ends of a previously split string to be joined on the platform by simply screwing the ends together before spooling on to a single reel. Once the connection has been made, the pressure and structural integrity of a single string is retained. The connectors are suitable for use in both conventional fluid or gas pumping operations and stiff wireline applications. The technology has now been proven offshore following extensive bench and full scale testing. This paper details the tools development plus the initial application in the North Sea.
An Advanced Coiled Tubing Control System
Authors: van Walsum Eric , Stakkeland Helge 
Published: December 2007

Abstract
A land-based coiled tubing rig with a Cyberbase workstation as its control station is currently in operation. The control system for this rig, including the distributed I/O and PLC networks, man machine interface, data acquisition and logging functions are described. Particular attention is paid to the digital control, automated drilling, tripping and safety shut-down functions. Benefits of the design include reduced cost, rig weight, rig up and tear down time and improved ergonomics for the operator.
Brent Field Reservoir Modelling: Laying the Foundations of a Brown-field Redevelopment
Authors: James S.J. 
Published: December 2007

Abstract
The Brent field was discovered in 1971. It is now a mature asset and, in order to increase oil and gas ultimate recovery, will commence depressurisation in 1997. The redevelopment of the field has been underpinned by extensive static and dynamic modelling studies. Developments in geological computing and the numerical processing power of reservoir simulation platforms significantly improved the quality of the Brent field static and dynamic models. The static models have been used for a range of studies including gas cap volumetrics and bypassed oil investigations. Their functionality provides significant scope for target sizing as a basis for selecting the appropriate reservoir access well technology.

Introduction
The Brent field, located 100 miles north east of Lerwick, Shetland Islands (Fig. 1) was discovered by well 211/29–1 in 1971. With total hydrocarbons initially in place of some 3.8 MMMbbl oil and 7.5 Tscf gas the Brent field ranked as one of the largest fields in the northern North Sea. Following 20 years of production remaining reserves are estimated to be some 400 MMbbl oil and 2.6 Tscf gas and in these terms the Brent field continues to rank as the largest field in the U.K. Sector of the North Sea.
The Brent field is a mature asset. Facilities comprise four platforms providing a total of 154 well slots. Oil export is via the Brent systems pipeline to Sullom Voe and gas export via the FLAGS line to St. Fergus. Production from the extensive West Flank area commenced in 1976 and by January 1997 cumulative production amounted to 1.6 MMMbbl oil, some 80% of anticipated waterflood ultimate recovery, and 3.2 Tscf gas. In order to significantly increase ultimate recovery through field depressurisation an extensive brown-field redevelopment project, costing 1.3 billion, was initiated in 1994. This is now reaching completion with depressurisation commencing in 1997 and low pressure operation in the year 2000. This project has extended the life of the field and increased ultimate recovery.
The redevelopment of the Brent field involved extensive static and dynamic reservoir modelling studies which will continue to guide reservoir management during depressurisation. This paper reviews the development of the current generation of static reservoir models and illustrates their use, not only as the basis for dynamic studies but also in delineating areas of bypassed oil and monitoring gas cap volumetrics.
Experience With a Global Optimisation Approach to Project Scheduling and Resource Allocation
Authors: Harding A. M. , Ponniah D. A. 
Published: December 2007

Abstract
In recent years there has been a growing trend in major projects towards considering the whole project life cycle and its costs. This analysis initially considered concept to commissioning, and later, particularly after Brent Spar, concept to decommissioning. Within this project life cycle, optimal solutions are sought. However, the field of optimisation still tends to focus on improving the performance of elements of the project or small subsystems within the project as a whole. An optimisation across the whole project life cycle is not normally carried out. This paper proposes a general system for such a global optimisation model, which will allow the whole project to be considered within a single optimisation. The strategy consists of a basic scheme for input to an objective function and the definition of its constraints. The objective function can map to a value relating to cost, time, performance or risk, allowing the most important criteria to be maximised or minimised. Other values not mapped to by the objective function can be used as constraints to restrict any detrimental impact to them during the optimisation. The size and complexity of a true globally optimising model is extremely large. If the model is to be able to optimise globally, then it must also be able to arrive at an optimal solution for a local optimisation problem. Therefore its suitability for optimisation is tested on project scheduling and resource allocation, a subsystem of the project. A new approach to modelling project schedule and resource allocation, which will allow the model to fit into the globally optimising model, is developed. Using examples from the literature, the performance of this model on specific locally optimising problems is investigated, using Monte Carlo random search. This, although not normally considered as being an efficient means of finding an optimum, was considered the best approach to initial investigation where the nature of the optimising surface is unknown. In particular, the model is used to solve resource constrained scheduling problems. The difficulty of finding the optimum within the model is also studied, and extensions to the model for further research are proposed.
The Subsea Well Decommissioning Project
Authors: Morrice B. , McGennis E. , Kirby S. J. N. 
Published: December 2007

Abstract
An important new initiative to clean up the seabed has resulted in a major project to decommission and remove redundant subsea wells. The subsea well decommissioning project was instigated by BP Exploration to fulfill its commitments and obligations under various license agreements. When exploration wells are no longer required for further appraisal or development, the requirement is to remove all subsea wellhead equipment and clear the seabed. This paper will describe first the organisation and execution of the project. It will then look at the experience gained and how it challenges the current well suspension philosophy.
Onshore Decommissioning - Receipt, Dismantling, Recycling and Waste Management of Offshore Structures Returned Onshore
Authors: Chaplin Paul D 
Published: December 2007

Abstract
The objective of this paper is to outline some of the issues, equipment and facilities which are required to enable the onshore decommissioning of offshore facilities once they are returned onshore.
It covers the receipt, materials, waste management, methods of dismantling, discussions on the form in which structures are likely to be returned and the requirements of the facilities onshore.
Future Developments in Subsea Autonomous Control Systems
Authors: Garbuglia E. , Calore D. , Guaita P. 
Published: December 2007

Abstract
The need for life cycle cost reduction to increase or simply to allow the profitability of a subsea development does not permit the extended use of conventional control technologies in scenarios more and more characterised by deepwater and long distance. The future subsea scenarios will probably see the development of fields beyond 20 km from the host facilities. The economic advantages of the introduction of autonomous control systems has been demonstrated in several studies. Some technologies have been designed and successfully tested and can today be considered as the valid starting point for any other future initiative. The recent developments in the acoustic transmission techniques through seawater, in the autonomous subsea power generation and in the subsea closed loop hydraulic systems, make now possible to eliminate the control and power umbilical in many subsea development with step-out distances up to 40 kilometres. With respect to the acoustic through seawater, the research efforts in the last years have led to more sensitive and efficient acoustic transducers and to more capable detection algorithms based on coherent demodulation techniques.
In this paper, an overview of these recent developments regarding the acoustic signal transfer is presented. Considering that the electrical power requirements increase with the number of functions and variables to be controlled and monitored, different solutions for subsea power generation are considered for different production scenarios. The progresses regarding the seawater batteries and the thermoelectric generators combined with the developments in the field of low power electronics allow now to satisfy the electrical power requirements in multi wells developments. In case of considerable amount of electric power, the feasibility of subsea turbines, powered by produced or injected fluids, was also demonstrated. Although autonomous solutions have been proven by means of prototypes their reliability is still to be demonstrated in order to gain the necessary acceptance by the oil industry. The next step will be the engineering of the existing prototypes in order to achieve devices suitable for real field scenarios.
Maximizing Profits from Exploration To Marketing
Authors: Oxford Robert J. , Shannon John E. 
Published: December 2007

The natural gas industry is now in the midst of the most critical period in its history. The energy crisis in our nation offers the professional engineer a challenge that perhaps equals the opportunities of the engineers who pioneered the technology in the petroleum industry years ago.
The increasing need for clean-burning fuel by our expanding industry-oriented society requires that we be more diligent in our search for gas, more intelligent in our evaluation of reserves, and more innovative in our approaches to producing and marketing this valuable resource. For years, gas has been an enigma to the petroleum industry, from the lease operator, to the engineer, up to the highest level of management. The discovery and production of crude oil has been our primary goal. We have avoided the handling of gas production problems in favor of maximizing oil recovery. problems in favor of maximizing oil recovery. It has essentially been a matter of economics. Oil has generally been priced at values commensurate with the cost of exploration and production. Gas has had values up until this past year of six cents to twenty cents per thousand cubic feet, and in some cases, no relative value at all. Considered on an energy basis compared to the price of oil, gas should have been valued at over 50 cent per thousand cubic feet at the wellhead.
Engineering technology has begun to grasp the value of the total well stream and significant advances have been made in the production and treatment of gas. We have discovered that a cubic foot of natural gas has many uses and valuable components, just as a barrel of crude produces a variety of products. We must advise petroleum management of this value and assist them in a more vigorous search for gas and development of a broader perspective of its market opportunities.
It is not the purpose of this paper to discuss the technical aspects of gas engineering. We would like to stimulate your imagination with several questions we think are pertinent to the business of handling natural gas in the most profitable manner.
Increased Costs or Increased Profits - Is there a choice?
Authors: Ashraf J. , Vote R. 
Published: December 2007

Abstract
Pressures on the economic margins for offshore production have prompted efforts of reducing costs, usually at the most visual ‘Capital Expenditure’, and ‘Preventative Maintenance’. However, in most cases the lull effects of these measures are not assessed, and there is a real risk that perhaps for a short term gain that problems may arise later and potentially overwhelm the savings that were sought in the first place.
This paper outlines a strategy for increasing profitability in the offshore industry, which is just as effective for optimising existing assets as well as a decision making tool for future developments. This encompasses not only the traditional physical and environmental risk, but also the long term impacts of decision made for investment, design and operations. Hence, the most efficient business strategy can be evolved on a quantitative, rather than merely a qualitative basis.
The method developed is a user friendly menu driven hierarchical modelling system, that encompasses both engineering and economic inputs, which then captures the effects of varying influences on them.
Improvements in the Design of Water Shutoff Treatments
Authors: Hardy Mary , van Batenburg Diederik , Botermans Wouter 
Published: December 2007

Abstract
In the past, high-volume water-shutoff treatments have not been applied because of the economic burdens they incur. Today, many operators have reconsidered high-volume water-shutoff treatments because these treatments make oil production from mature reservoirs more economically feasible. Many wells in mature North Sea reservoirs produce a large amount of water. Consequently, these wells often produce less oil than they potentially could.
The evolution of diagnostic and interpretation techniques has significantly enhanced the degree of accuracy and completeness of production problem diagnoses. Reservoir models can be used to identify and design effective water-shutoff treatments. This paper describes how a production operation simulator is used with an advanced-processes reservoir simulator to design water-shutoff treatments. The following reservoir simulator options were necessary to design the treatments properly.–thermal options–chemical-injection options–chemical-reaction options–flexible-gridding options
The technique was recently used to design water-shutoff treatments and their placement for jobs in the North Sea area. The results of the simulations were used to predict the effects of the following factors.–interval permeability distribution–treatment rate–reaction rates of treatment fluids–resulting gel strength
The technique also allows treatments to be designed on the basis of realistic treatment temperatures rather than bottomhole static temperatures. The results of the simulations were used to optimize treatment placement rates, fluid composition, and shut-in times of jobs pumped in the Norwegian sector of the North Sea.
One case shows how cooldown inside the reservoir can be used to place a treatment that would have otherwise spontaneously gelled at reservoir temperature. Another case shows how temperature histories for different stages of the treatments were constructed from the simulation results. These temperature histories showed that different activator compositions and/or concentrations were required for early, intermediate and final treatment stages.

Introduction
Water production can seriously compromise the profitability of oil- or gas-producing wells. The cost of produced-water disposal is becoming a major burden for many operators. Although prevention is usually more effective than treatment, excessive water production is most often treated rather than prevented. The keys to the success of shutting off or preventing excessive water are:–proper identification of the water-production mechanism–appropriate design of the treatment–effective placement of the treatment

Steps of Typical Water-Shutoff Treatment
Figure 1 illustrates the process of a typical water-shutoff (or conformance) treatment. Each step of the process will now be discussed.
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