bluuebunny/crossref_metadata_2025_split huggingface dataset:
Coiled Tubing Injection-Well Cleanouts with Tapered-OD Strings
Authors: Love Douglas , Mullins Rufus , Brelih William A. 
Published: December 2007

Abstract
This paper presents a case history in which a tapered-OD coiled tubing (CT) workstring and a blast nozzle were used for cleanout and stimulation work in a west Texas well. The tubing&apos;s tapered OD allowed it to pass through restricted downhole IDs while maximized flow rate was maintained. These techniques resulted in greater cleaning energy, higher annular velocities, and reduced pump times.
The workstring used was primarily 1 ¼-in. OD, but it was tapered to 1 in., and then to ¾ in. The ¾-in. portion was the only part of the string that penetrated beyond the depth of the shutoff valve in the injection string. A single injector head with a vee-block design allowed for smooth size transition as the tapered string was run in and retrieved. Three or four passes of the coiled tubing length were made with the blast nozzle.
Conventional tubing cleanouts in this field require approximately 10 to 14 days; however, by using the tapered CT string and a body-load coiled tubing unit (CTU) operators can perform such treatments in 8 to 10 hours. In addition to injection-well cleanouts, other potential applications for tapered-diameter CT are presented in this paper.
Effects of Coiled Tubing Shear History on the Rheological and Hydraulic Properties of Fracturing Fluids
Authors: Shah S.N. , Subramanian R. 
Published: December 2007

Abstract
Coiled tubing shear history effects on the rheological and hydraulic properties of various fracturing fluids are investigated using the experimental equipment available at the Fracturing Fluid Characterization Facility (FFCF), located at the University of Oklahoma. The primary investigation includes tubing curvature effects on the frictional pressure losses using various lengths of coiled tubing and on the fracturing fluids apparent viscosities, over a range of selected linear and crosslinked fluids, using a unique High Pressure Simulator (HPS), capable of operating at elevated temperatures and pressures. To ensure a comprehensive understanding of the curvature effects on the rheological and hydraulic properties of the selected fracturing fluids, both coiled and straight tubings are investigated. The results show that coiled tubing curvature increases the frictional pressure losses for fluids such as water, linear guar gum and Hydroxypropyl guar (HPG), and borate-crosslinked guar and HPG fluids. Also, the study shows that frictional pressure losses within a coiled tubing are dependent of coiled tubing shear history for borate-crosslinked HPG gels and are independent of coiled tubing shear history for borate-crosslinked guar gels. On the effects of coiled tubing shear on the rheological properties of the fracturing fluids, the study indicates that apparent viscosities of borate-crosslinked gels are a function of shear history, pH, and temperature. Furthermore, the results show that for certain fluids, there exist an optimum pH, where shear history does not affect fluid's apparent viscosity.
Accuracy and Reliability of Coiled Tubing Depth Measurement
Authors: Pessin J-L. , Boyle B.W. 
Published: December 2007

Abstract
Coiled Tubing Depth Measurement has become more critical with the advent of new coiled tubing services, such as logging, drilling, perforating and zonal isolation. For depth critical applications, multiple depth correlation measurements are often made using expensive down hole tools. A reliable measurement system can significantly lower costs and simplify logistics by reducing the need for multiple depth correlation measurements. This paper presents the results of a comprehensive study of the causes of depth errors, and proposes a strategy to improve reliability and accuracy of the depth control.
The causes of errors with depth are classified in four categories: errors of reference; errors of procedure; errors of surface measurement; and errors due to down hole deformation of the Coiled Tubing.
The order of magnitude of these errors prioritizes a depth control strategy based on: the elimination of reference and procedure errors by providing computer tools; a new surface measurement system that emphasizes the role of repeatability versus accuracy; and the use of the pipe models. Based on this strategy, we can improve the reliability and accuracy of depth measurements and limit depth correlation to the necessary cases.
Results can apply to all coiled tubing operations, particularly zonal isolation, perforating, drilling and logging.
A Case Study of Downhole Obstruction Avoidance for CT-Conveyed TCP Operations
Authors: Conrad A. Bruce 
Published: December 2007

Abstract
Tools such as mud motors, indexing tools, and hydraulic kickovers use pumping for rotation or lateral displacement. In special cases, however, coiled tubing operators must manipulate coiled tubing (CT) bottomhole assemblies (BHA’s) without the benefit of pumping.
On this occasion the production company’s tubing-conveyed perforating (TCP) guns did not fire. Operators cut the guns off, expecting them to drop in the rathole, but instead, the guns lodged in mud solids at the production interval. CT engineers had to design a toolstring that could bypass the obstruction and access the unperforated production interval with TCP guns without the use of conventional hydraulic or rotational tools.
In this particular case study, operators did not have to pump to bypass a downhole obstruction, such as a fish in a deviated wellbore; instead, they used mechanical indexing tools that had been configured into specialized BHA’s.
New Seismic on an old Field : The impact of the 1995 Brent 3D seismic survey
Authors: van Dierendonck A.I. , Pronk D.W. , Ward V.C. 
Published: December 2007

Abstract
As the Brent Field moved into the latter stages of field life it had become increasingly apparent that the resolution of the 1986 Brent 3D survey was insufficient to meet the demands for increased geological detail. Hence in 1995 a 320 sq.km 3D seismic survey was acquired over the field with a denser subsurface sampling than the previous survey. Compared to the previous survey the seismic resolution of this dataset has clearly improved. Fault definition is superior, especially in the so-called "slumped" areas, where a substantial portion of the field's remaining reserves are located. Detailed field wide structural maps will form the basis for the year end review of reserves and have already been incorporated at an early stage into detailed dynamic reservoir models of complex areas. The improved seismic data quality of the new survey justifies the application of "state-of-the-art" geophysical techniques to obtain additional information which could help the determination of reservoir quality characteristics and the prediction of produced fluid contacts. These techniques include Amplitude Vs Offset, Seismic Inversion, Amplitude studies, and 4D Time Lapse studies. Parallel to these initiatives continuous data processing refinements are being tested (amongst others pre-stack depth migration) in an effort to further enhance seismic resolution.
The challenge is to manage these large numbers of continuously improving seismic datasets, whilst at the same time maintaining their impact on the maximisation of the remaining value of the Brent Field.

Introduction
The Brent field, located 160 km NE of the Shetland Islands in the UK sector of the North Sea, was discovered in 1971 and production started in 1976. Hydrocarbons are produced from the Jurassic Brent and Statfjord reservoirs trapped in a westerly dipping monocline with slump (crestal collapse) features. Remaining reserves are currently estimated at around 400 MMbbl oil and 2.6 TCF gas. A new phase of development has started for the Brent field where reservoir depressurisation will gradually transform it from an oil to a gas producing field. Major efforts are now concentrated on locating and developing the field's thin remaining oil rims. It had become increasingly apparent over the last few years that the previous 3D seismic survey, shot in 1986, was insufficient to meet these demands. Re-processing of this survey, carried out in 1989 and again in 1993, had failed to significantly improve the quality of the data which considerably downgrades its usefulness. Hence a new high resolution 3D survey was acquired in 1995. In addition a high quality seismic dataset prior to field depressurisation may provide a suitable base line survey for possible future time lapse seismic surveys.
Phase 2 Development of the Slumped Crestal Area of the Brent Reservoir, Brent Field
Authors: Coutts S.D. , Jurgens M. , van Kessel O. , Pronk D. , Ward V.C. 
Published: December 2007

Abstract
The Brent Field consists of a major, westerly dipping fault block, with a crestal area broken up into a series of slumped fault blocks. Development of these complex slumped blocks started in 1993 and to date a series of 9 roughly parallel horizontal east-west oil producers have been drilled, some of which have subsequently been converted into water injectors. Oil production to date, at a total rate of up to 100,000 b/d, exceeds the 1993 Development Plan forecast by 11%, despite poorer than expected east-west and north-south communication in some parts of the field.
Key conclusions from the first phase of the development are:-–The Development Plan concept of multi-purpose horizontal wells (appraisal, production, injection) has been successful mainly because of the validity of the geological model. This has allowed optimal positioning of wells, with sand-sand juxtaposition initially providing sufficient pressure support via the West Flank.–Controlled reservoir depletion can be used as a method to establish fault block connectivity and to steer the flow of injection water. Uncontrolled depletion will lead to unwanted crossflow, ultimate recovery loss due to oil shrinkage and hazardous drilling due to large pressure differences.–The introduction of 7" monobore completions, combined with consecutive perforation and isolation of 150–250m reservoir sections, has increased ultimate recovery and reduced cost. Multi-straddle assemblies have proved to be ineffective, because communication patterns cannot be predicted accurately enough.
An extensive data gathering programme has now been largely completed, consisting of new 3D seismic, borehole imaging logs, radioactive tracer injection, interference testing, advanced PLT logging and permanent downhole gauge output. This has so far resulted in an adjustment to the Development Plan in the compartmentalised Brent Horst and Graben areas, successfully targeting one water injector to support two producers 1500m apart, and in one infill well to appraise the quantity and quality of reservoir rock between the top Etive and the X-unconformity erosional surface. In combination with advanced drilling techniques a recovery factor of 50% is now considered achievable.

Introduction
The Brent Field consists of a major, westerly dipping fault block, with a crestal area broken up into a series of slumped fault blocks. Development of the Brent slumps started in 1993 and to date a series of 9 roughly parallel, horizontal east-west oil producers have been drilled, two of which have subsequently been converted into water injectors (see Figure 1). The wells in question are listed (in chronological order) in Table 1. They are all part of the first stage of the 1993 Development Plan (ref. 1), eventually comprising of 6 horizontal producers, interspersed with 6 horizontal water injectors.
P. 135^
Integrating Parallel Engineering with Phased Field Development in order to Balance Cash Flow, Net Present Value, and Risk
Authors: Preece Mark , MacLeod Andrew 
Published: December 2007

Abstract
The future of the offshore oil/gas industry in the UKCS faces a growing number of challenges. Not least of these are the technical complexity of the reservoirs currently available for development, and their lower recoverable reserves.
Current exploration and production efforts are concentrating on either stand alone small/marginal fields or brown field developments, exploiting hitherto untapped reserves near to existing facilities.
Technical advancements are playing their role in enhancing the ability of operators to reduce development costs. The greatest constraint on extracting the maximum value of these reserves is, however, the field development process. This constraints can only be overcome by introducing new business and engineering processes which are focused on achieving both the goals of the operator and of the field development contractor.
An integrated field development contractor, with access to key technology, personnel, and equipment, can assist in the enhancement of the value of these small/marginal fields by structuring the development process such that it provides the optimal balance between cash flow, Net Present Value (NPV), and risk.
Multi Lateral Rewards in Tern Field
Authors: Roberts M. J. , Tolstyko M. 
Published: December 2007

Abstract
Tern Field represents a significant production asset, making an important contribution to Shell net income on a global scale. With the initial development programme having successfully developed the bulk of the Brent Etive reserves, attention is now also focused on profitable oil production from STOIIP locked in the poorer quality Ness and Rannoch formations. A new approach, driven by factors including platform slot constraints, maximising profitability and increasing production levels, has led to a development strategy which adopts multi lateral technology as a springboard to achieve identified rewards.
Well TA14, completed in Q3 1996, combined a successful exploration and appraisal of Triassic near-facilities-potential with a subsequent Brent reservoir dual-lateral oil producer: all attained in one well. Cost savings of £4.5 million have been achieved over more conventional drilling methods, together with important project acceleration. Follow up development of Triassic oil will be in 1997 via a dedicated Triassic multi lateral well (TA17), just 18 months after TAM proved the reserves. Well TA19 was planned and executed as a sidetrack multi lateral producer which targets bypassed Lower Ness oil. The results of this trial are expected to positively influence future Brent Group production operations.
Shell is actively driving the continual development of multi lateral technology and promoting longer term working relationships with integrated Service Companies. In particular, the application of geosteering techniques, slim-hole LWD logs (plus office-based real-time display), selective lateral isolation capabilities and multi lateral water injection wells represent substantial advances to maximise Tern Field oil development opportunities.
What Can The UK Oil Industry Realistically Expect to Export?
Authors: Forrest K. P. , Darbyshire B. 
Published: December 2007

Abstract
Introduction
Britain is a trading nation, exporting some 23% of its GDP which compares favourably with Germany and France at just below this figure, and perhaps rather surprisingly for some of you well ahead of the USA and Japan each of which have about 10%. We have over 6% of total world exports, which places us among the small group of leading exporting countries. It is therefore not unreasonable to expect that the UK should be able to export a sizeable proportion of the goods and services it provides for the oil, gas and petrochemicals industry. But before testing the validity of this statement, let us first take a look at the make-up of our oil and gas supply industry.
Companies involved can broadly be divided into two groups. First, there are those which for many years have been providing a range of goods and services to many sectors of activity. These companies were established long before the first discovery of North Sea oil and gas and are generally large enterprises making significant contributions to the UK economy.
Second, there are those which have been set up specifically to respond to the needs of the oil industry and have been in the business for a rather shorter period of time. Companies involved in this category are, for the most part, relatively small, but their capabilities are good and they have established a presence in several niche areas. One exception to this is the significant number of international contractors, mainly of American origin, which have set up in the UK initially to service the UK Continental Shelf.
Application of Downhole Video Technology to Multilateral Well Completions
Authors: Maddox S. D. 
Published: December 2007

Abstract
Current downhole video systems have successfully been used during the multilateral completion process. The technology is specifically being applied to the testing, inspection, and evaluation of multilateral junctions. Some examples are presented, complete with video footage from different stages in the process of building a multilateral junction.
Downhole video field data is also presented demonstrating cases of properly milled casing windows, malfunctioning whipstock equipment, and a casing window inadvertently drilled in an unconsolidated formation.
Applications of Downhole Magnetic Resonance Imaging in the North Sea
Authors: White Jim 
Published: December 2007

Abstract
In-situ reservoir description has recently taken a major step forward with the introduction of combinable Nuclear Magnetic Resonance (NMR) sensors. Run as a pad or mandrel device in combination with other logging tools, they can provide direct information on the properties of the pore structure and pore fluid. Much of this potentially valuable information has only been previously available from core data and formation fluid samples.
The paper will briefly review the principle of NMR measurement, then concentrate on some of the ever widening range of applications. Examples of these are taken from in and around the North Sea, and cover the following areas of reservoir evaluation.
Development and Testing of Downhole Pump for High-Pressure Jet-Assist Drilling
Authors: Veenhuizen S. D. , Stang D. L. , Kelley D. P. , Duda J. R. , Aslakson J. K. 
Published: December 2007

Abstract
A second generation prototype ultra-high pressure (UHP-30,000 psi) downhole pump (DHP®) for jet-assist drilling has been tested in the laboratory and downhole. The development and testing program has been supported by the Gas Research Institute (GRI) and the U.S. Department of Energy Federal Energy Technology Center (DOE-FETC). It is anticipated that with development of this technology, drilling penetration rates in the harder, slower drilling formations in gas and oil wells could be increased 1.5 to 2 times through jet-assist of the drill bit.
As with the first generation prototype DHP, the ultra-high pressure pump is designed to be located downhole in the BHA just above the drill bit. It is rated at an output pressure of 30,000 psi at about 20 gpm. Power to drive the DHP is delivered downhole via the conventional mud stream through elevating the surface mud pump pressure 1,500 to 2,000 psi using conventional flow rates downhole.
The operating principle and general arrangement of the DHP pump is discussed along with the operating behavior and performance characteristics. The pump has been tested eight times downhole in three commercial gas wells in the Travis Peak Formation of East Texas and a granite test well in Norway. Rate of Penetration (ROP) enhancements observed were up to 1.5 to 1.6 times conventional penetration rates. Testing in the laboratory to evaluate design issues that have limited downhole operating hours is summarized in terms of fluid sealing, mechanical strength, and fluid erosion. Jet-assist drilling ROP enhancement is also discussed in terms of laboratory drilling test results and field drilling results utilizing the DHP in East Texas and Norway. The main technical design challenge remaining before commercialization of the DHP technology is erosion within the pump when drilling very abrasive formations.
Advanced Sandstone Acidizing Designs Using Improved Radial Models
Authors: Gdanski Rick , Shuchart Chris 
Published: December 2007

Abstract
With the recent development of a comprehensive theory for the complete chemistry and kinetics of sandstone acidizing, it was appropriate to develop useful radial models for exploring and simplifying the application of the new technology. These radial models were designed to accommodate both the positive and negative aspects of the recent discoveries. These discoveries included ion-exchange transformation of brines, decomposition of clays in hydrochloric acid, precipitation of fluosilicates, removal of carbonate to prevent the precipitation of complex aluminum fluorides, silica-gel filming, colloidal silica-gel precipitation, precipitation of the various complex aluminum fluorides, mixing between the various stages of the treatment, damage removal, permeability modeling, and skin evolution. Calculations were initially performed with a comprehensive workstation-based computer model so that the magnitude of the various effects could be measured. These calculations showed that many negative effects could be minimized or eliminated by special design considerations. A PC-based model was then written that could help design engineers avoid serious problems when acidizing sandstone formations and provide them with visual guidance for some of the other issues that were relevant. The "avoiding problems" approach for the PC-based radial model provided a powerful basis for introducing advanced designs for sandstone acidizing that have dramatically improved the success rates of field treatments. In addition to choosing the correct HF fluid to avoid secondary precipitations, considerations for choice of preflushes to condition the formation proved essential. Proper choice of preflush is based on acid stabilities of the clays, carbonate removal, and the avoidance of deep clay swelling. Appropriate acid-preflush volumes help ensure carbonate removal for at least 24 in. and provide sufficient fluid spacing between formation brine and the spent HF fluids at the end of the treatment.