bluuebunny/crossref_metadata_2025_split huggingface dataset:
Electric Coiled Tubing Drilling: A Smarter CT Drilling System
Authors: Turner D. R. , Harris T. W. R. , Slater M. , Yuratich M. A. , Head P. F. 
Published: December 2007

Abstract
The paper describes the ongoing development of an electrically powered bottom hole assembly for use in coiled tubing drilling (CTD) applications.
Electric coiled tubing drilling (E-CTD) offers many distinct advantages over conventional CTD which are considered in more depth within the paper. These may be summarised to include: Drive power provided independent of fluid flowHigh tolerance of energised drilling fluids–ideal for underbalanced drilling–ideal for subsea drilling applicationsHigh temperature operationFlexible control of electric power with instantaneous feedback for closed loop drilling and optimisation of drilling efficiencyMotor operation is scalable. The same drive may be used for auxiliary actuation, e.g. orientation, active traction and formation testing.Real-time transmission of data to surface using power cableExtended longevity of motorReduced vibration (affects gyro placement, reliability of other equipment, eg NMR magnets)Reversible direction of rotation (passive or active traction capabilities)
It is these advantages that have driven the development of the electric BHA in a European Drilling Engineers Association [DEA(E)] joint industry project. This paper reviews prototype bottom hole assemblies from phases 1 and 2 of the project. Surface components, the electrical transmission system and its consequences for an integrated drilling package are also considered.
Phase 2 of the project, currently ongoing, has delivered a purpose-built, electric downhole motor (EDM) design suitable for drilling a 3.75" hole. This motor is currently being incorporated into an electric BHA which incorporates pressure, temperature and vibration sensors. The proposed test program is reviewed with some earlier results presented from phase 1 for illustrative purposes.
The ultimate goal of this project is to integrate the electric motor into a ‘smart’, closed-loop drilling system. It is envisaged that, based upon feedback from near-bit sensors, such a system would be able to automatically adjust drilling parameters to optimise drilling performance.
The paper concludes that not only is electric coiled tubing drilling a practical and effective alternative to conventional CTD, but that the system delivers many additional benefits.
New Open-Hole Displacement Procedure Dramatically Reduces Loss of Synthetic Fluids in Deepwater GOM
Authors: Courtney Greg , Elliott Karl , Smothers Neal , Humbles David , Toups Bret 
Published: December 2007

Abstract
Synthetic drilling fluids have evolved into the systems of choice for deepwater drilling, particularly in the Gulf of Mexico. As these systems are proportionately more expensive than their traditional counterparts, the loss of even a few barrels can impact well economics significantly. Historically, it has been commonplace to leave hundreds of barrels of synthetic drilling fluid in the wellbore during open-hole displacements. Attempts to retrieve synthetic muds with water-base systems have proved counter productive. When exposed to water-base muds in open hole, the formation becomes extremely unstable and will literally cave in, resulting in a number of operational problems.
This paper describes the development and application of a new displacement procedure and a modified water-base mud that successfully recovered 961 bbl of synthetic fluid on the Manatee project in the deepwater Gulf of Mexico. When compared directly with conventional open-hole completions in the deepwater GOM, the new procedure resulted in savings of $228,718, not including saved rig time. Furthermore, no additional rig time was required to condition the water-base system used in the successful open-hole displacement. More importantly, the wellbore remained stable and no problems were encountered while tripping through the 4,462-ft of open hole exposed to the re-engineered water-base fluid system.
The authors will describe both the new procedure, which included a casing shoe with an extremely high leak-off test and realigned pumps, and the new 15 lb/gal water-base displacement fluid. The modified system was both inhibitive to reactive shales and could also withstand the contamination effects of the calcium employed in synthetic muds.
New Permeability Plugging Apparatus Procedure Addresses Safety and Technology Issues
Authors: Davis N. , Mihalik P. , Lundie P. R. , Growcock Fred , Calloni G. , Davidson E. 
Published: December 2007

Abstract
For the past nine years, the drilling industry has used the Permeability Plugging Apparatus (PPA) to assist in evaluating and resolving differential sticking and lost circulation problems which may arise while drilling depleted, weak or fractured zones. The increasing use of open hole completions in horizontal wells also means that more attention has to be paid to the cake forming properties of drilling fluids. The PPA is a high pressure, high temperature filtration device designed to evaluate fluid loss and "spurt loss" of drilling fluids under filtration conditions that more closely approximate those encountered downhole than the filter paper normally used. Although filtration occurs under static rather than dynamic conditions, pressures as high as 5000 psi (34,500 kPA) and temperatures of up to 500°F (260°C) may be investigated. The main feature of the PPA is the use of ceramic disks as the filtration medium. These are available in a wide range of porosities and permeabilities to match those properties of the formation much better than filter paper can. There are currently five PPA types with different pressure ratings that are in use in the laboratory and the field. In response to concern about the safe use of these devices, and the reproducibility of the data generated with them, the American Petroleum Institute initiated a program to investigate these issues, and to produce a standardized test procedure.
The new API procedure addresses the safety issues of the PPA cell designs. Further, to provide consistency between users, the procedure outlines a new method of calculating spurt loss and total filtrate volume parameters based on the test data. The new procedure has been used, both in the laboratory and the field, to evaluate seepage loss additives as well as traditional lost circulation additives. Case histories are provided which demonstrate successful use of the device in evaluating lost circulation material and in the prevention of differential sticking problems while drilling depleted zones as well as designing pills for severe lost circulation.
Novel Lime-Free Drilling Fluid System Applied Successfully in Gulf of Thailand
Authors: Harrison James R. , Stansbury Mark , Patel Jay , Cross A. Todd , Kilburn Mark 
Published: December 2007

Abstract
A lime-free, high-temperature invert emulsion drilling fluid has been developed and applied successfully on 53 wells in the Gulf of Thailand (GOT). The subject drilling program included 24 wells in a field with static bottom hole temperatures (BHT) of 400°F. The fluid is run with a pH of less than 7.0, which is accomplished with the introduction of 1 lb./gal of citric acid and the elimination of the alkaline source (lime).
The fluid was mainly developed in search for a high quality drilling mud resistant to heat degradation, therefore allowing stable borehole conditions under which to execute the open hole wireline logging program. The fluid was also developed in part to allow the possibility of logging CO2 formation gas at the surface by utilizing a conventional mud logging unit. The ability to log CO2 gas with surface equipment would help eliminate wireline RFT sampling runs. This could provide significant savings during the course of an extensive drilling program.
The paper will discuss the development of the lime-free emulsifier package, the introduction of a new HTHP fluid loss reducer (stable in excess of 450°F) and low-end rheology modifier, the extensive lab testing, the introduction of the system to the GOT and the drilling of 53 wells.
Data from 250-plus GOT slimhole wells using invert systems were studied prior to the introduction of the new system. The numerous problems that prompted the investigation for a new cost-effective fluid system will be discussed.
Shallow Kick-off Extended Reach Drilling in GOM
Authors: Meize B. , Chesebro’ S. , Stubblefield A. , Lenamond C. , Miller R. 
Published: December 2007

Abstract
Anadarko Petroleum Corporation spudded a shallow kick-off extended reach well from the High Island A-376 "B" platform in December of 1997. The well successfully drilled 8208’ of horizontal displacement to a 3388’(TVD) reservoir target adjacent to the environmentally sensitive Flower Garden Banks National Marine Sanctuary in the Gulf of Mexico. The 9767’MD/3388’ TVD well required significant planning to ensure technical feasibility and execution. Geological control was based on seismic data with no pilot hole planned prior to landing in the target. This required the use of geological steering and measurement-while-drilling techniques to perform the pinpoint landing.
The paper details predicted vs. actual torque and drag numbers for high-angle drilling conditions. The use of pressure-while-drilling tools identified circulating pressure losses associated with synthetic drilling fluids and pressure changes due to hole cleaning. The well features a number of today's technical advancements in extended reach drilling and includes: A 17-1/2" sea water kick-off with build rates of 6 degrees/100’Displacement to true vertical depth ratio greater than 2.5:1Use of top-drive fill-up tool while running 9-5/8" casing allowed greater annular velocities, increasing holecleaning effectiveness and successfully washing casing to bottomRotating a 7" liner in high angle hole made possible due to synthetic mud and use of solid-body centralizersFirst one-trip, weight-set liner top isolation packer run in the Gulf of Mexico on an extended reach well.
The paper concludes that seismic technology and geological steering can eliminate the need for pilot holes. Extended reach drilling through soft sediments to small shallow amplitude events can be economically accomplished from existing structures in the Gulf of Mexico.
A Case Study in Improving Capital Efficiency
Authors: Jackson K. L. , Brennan R. M. , Aranaga R. , Hawker R. , Montaña J. P. 
Published: December 2007

Abstract
The initial phase of Venezuela's first large-scale horizontal development drilling program in the Faja del Orinoco will soon be completed. This project is known as the Venezuela Extra Heavy Oil Project (VEHOP) and is operated by Petrozuata, C.A., a strategic association between Petroleos de Venezuela, S.A. (PDVSA) and Conoco, Inc. The planning process began in 1994 with the evaluation of worldwide heavy oil operations. A test well was drilled which incorporated design changes to improve well productivity and allowed the operator to gain experience in Venezuelan operations.
The Petrozuata development program was based on drilling and completing 95 horizontal wells of identical design as efficiently as possible in order to maximize the project economics. To accomplish this goal, a minimum well design was established based on managed risk. Discrete operations were then analyzed to establish breakthrough targets for drilling performance. To ensure targets were met, a well manufacturing process, including fit-for-purpose drilling rigs, contracting strategy, procurement strategy, and detailed operational plans were developed.
Performance improved significantly from an initial 19.2 days to 5.4 days per well. The basis of design included 4000 foot lateral sections with actual lengths exceeding 6000 feet measured depth (MD). A capital efficiency improvement of 18% is projected based on current performance. This paper details how shared goals, teamwork, and continuous improvement initiatives between the contractors and operator resulted in world-class drilling performance, record setting horizontal completions, and a new standard for future Venezuelan operations.
Drilling and Completion of Depleted Carboniferous Reservoirs in the U.K. Southern North Sea
Authors: Bourassa K. A. , Bujnoch J. A. 
Published: December 2007

Abstract
The objective of this paper is to outline and discuss the learnings which improved the drilling and completion process of horizontal wells in depleted Carboniferous reservoirs.
The learnings were derived from three replacement wells drilled and completed on the Conoco (U.K.) Limited operated Murdoch Field, which is a mature development in the Quadrant 44 area of the United Kingdom Southern North Sea (UK SNS) (refer to Figure 1). The replacement wells were drilled in an effort to restore production volumes that were lost when two of the original wells mechanically failed due to downhole conditions.
The paper will summarise the following: Failure analysis of the original wellsBasis of design for the three replacement wells including sand control issues of depleted reservoirs
Operational summaries for three wells will be thoroughly discussed.
The learnings gained from the failure of the first well was applied to the planning and implementation process of the two remaining wells. The wells were successfully drilled and completed. The initial production rates of these two wells were equal to or greater than the original development wells even though the reservoir pressures were significantly reduced.
GLOMAR HULL 456 CLASS Ultra-Deepwater Drillship
Authors: Dreith Mark W. , Garvin Michael D. , Thorson John A. 
Published: December 2007

Abstract
This paper describes how the Global Marine Hull 456 Class ultra-deepwater drillship is able to improve on conventional floating drilling operations and highlights advances that have been made to maximize efficiency and minimize downtime. The paper will document how the 456 Class uses a unique thruster specification to greatly reduce the amount of downtime due to weather or equipment failure. In addition, Global Marine's unique horizontal/vertical enhanced pipe handling technique will be discussed in depth, with a focus on how this will increase both up time and rig efficiency.
Continuous Improvement in the Design and Execution of Multilateral Projects in the Greater Ekofisk Area
Authors: Berg J. R. , Liland G. 
Published: December 2007

Abstract
Since 1996, Phillips Petroleum Company Norway has drilled and completed 3 bi-lateral production wells in mature chalk fields offshore Norway. There have been technical challenges all the way, but lessons learned have been captured from well to well in a very effective and constructive manner resulting in both technical and commercial success.
Technical challenges were overcome by employing: - A step-by-step approach, going from an open hole lateral to a fully cased, cemented and washed over junction (level 2 junction up to a level 4).A win-win partnering concept with contractors in a Well Construction Team (WCT) relationship;Extensive reservoir studies and modelling to assist in candidate well selection process.Refinements in drilling, completion and stimulation design and practices.Extensive off-site testing of new components and equipment prior to deployment.
A number of world's "firsts" have been achieved during this campaign, including: - Development of a liner hanger system which allows rotation, while preserving the pre-milled, casing exit window orientation.Development of a high-pressure completion window for selective stimulation of lateral and main well branches.Development of removable sleeves for highpressure stimulation which protect the junction during mainbore and lateral stimulation.Pre-milled casing exit windows with pressure integrity, reducing debris problems.
This paper describes the technical innovation and approach employed by the members of Phillip Norway WCT in realization of the multilateral projects. Results from PLTs will be given to document the contribution from the lateral branch in the three wells and a comparison to other standard horizontal wells from the same platform will be presented. Well schematics with depths and casing program will be given to support the technical discussion carried out in the paper. The lessons learned during this multilateral well development campaign have general application to mature fields in other areas of the world.
Burst and Collapse of a Sealed Multilateral Junction: Numerical Simulations
Authors: Bayfield Matt , Fisher Simon , Ring Lev 
Published: December 2007

Abstract
Multilateral well technology has progressed during the 1990s. Much effort is now concentrated on the development of a multilateral system where both a mechanical and a pressure seal are provided throughout by the well casing itself. Such a system would extend the application of multilaterals to a number of new environments (including higher pressure applications) and could also supersede many existing multilateral systems.
This paper describes finite element analysis undertaken to assess the effects of internal and external pressure on a sealed multilateral junction. The studies consider a junction formed between a 9.625 inch mainbore and a 7 inch lateral. Results suggest that an unreinforced junction with lateral inclined at 2.5 degrees to the mainbore would burst at 8 to 16 per cent of the mainbore casing strength and collapse at 8 to 28 per cent. Increasing the angle between mainbore and lateral to 5 degrees gives only a limited increase in strength.
Subsequent finite element simulations were then performed to suggest alternative methods for improving burst and collapse strengths. Findings indicate that values can approach standard oilfield tubular strengths if steel reinforcement is provided at the junction. A significant increase in burst strength is also predicted if the junction can be firmly cemented. The extent of this increase is highly dependent on both the quality of the cementing and the cement material properties. Benefits of cement under external pressure are generally limited due to failure of the cement.
National Health, Wealth, and Energy Use
Authors: Skov Arlie M. 
Published: December 2007

Abstract
There is great disparity in the distribution of wealth among nations of the world. National well-being, as measured by commonly accepted indicators such as infant mortality, child malnutrition, life expectancy, and literacy rates correlate well with national wealth, which in turn correlates well with energy consumption. Developed industrial nations rank high in national well-being, but on a per capita basis, own a disproportionate share of world wealth, and consume a disproportionate share of the world’s energy. Economic growth correlates well with growth of energy consumption in both rich and poor nations, and conversely, reductions in energy consumption correlate with economic decline. When energy consumption is expressed as a function of GNP instead of a per capita basis, developed nations are more efficient in use of energy than poorer ones.
Fossil fuels furnish 90% of the worlds energy (oil and gas supply 63%), and their use has grown by 14% over the last decade (oil and gas use is up 19%). Long range concerns about depleting resources of fossil fuels, and more immediate concerns about increases in atmospheric carbon dioxide produced by their combustion and the postulated ill effects of global warming, weigh against continued increase in use of fossil fuels and favor alternative energy sources. Examination of alternatives suggests that none, other than possibly nuclear and hydropower, both in environmental and political disfavor, offer hope for supplying more than a fraction of demand. Hence either natural limits on use of fossil fuels set by depleting resources, or artificial limits, in an effort to control carbon dioxide emissions as tentatively agreed to in Kyoto and Buenos Aires, stand in stark contrast to the need for more energy consumption to improve the economic development of all nations and particularly the poorer ones.
This paper explores these relationships, and identifies some of the hard choices which lie ahead, and will inevitably impact the use of oil and gas.
Disaggregated Remaining Reserves to Annual Production Ratios
Authors: Lohrenz J. , Williams C. W. 
Published: December 2007

Abstract
One frequently sees ratios - often abbreviated as R/P’s - of the remaining oil and gas reserves to the annual production for a specified producing sector, geographical subdivision, nation, or even the world. Inferences of the remaining "life" of the producing sector treated are then drawn from these R/P’s. These inferences are, however, highly problematic. The reason is that the annual production in the R/P’s is an aggregation of production drawn from reserves added to an inventory in prior history, usually over many years, of the producing sector. In any year, some production likely comes from reserves found when the producing sector was "discovered", some from recent additions to the producing sector’s inventory of reserves, and the rest from reserve additions between those two extremes.
A more meaningful planning tool to assess the future of a producing sector would be a disaggregated R/P unlike the usual aggregated R/P. A disaggregated R/P is a ratio of the new reserves added in a year in a producing sector to the start-of-a-year annual production rate from the new reserves added in each year. Thus, disaggregated R/P’s mirror the choices made regarding how proportionately fast or slow rates of production are developed for each new reserves addition in the history of a producing sector.
Here we invent and use a mathematical model to deduce disaggregated, as opposed to aggregated, R/P’s. We show how disaggregated R/P’s can be interpreted. But, no doubt, the most important showing is the coincidental diagnosis that conventional aggregated R/P’s as predictors have unavoidable afflictions that are, hopefully, terminal.
Economics and Resource Uncertainty: The 1002 Area of the Arctic National Wildlife Refuge
Authors: Attanasi E. D. , Schuenemeyer J. H. 
Published: December 2007

Abstract
The importance of properly characterizing undiscovered oil accumulation size distributions is demonstrated in the context of the recent US Geological Survey’s regional play assessment of the 1002 Area of the Arctic National Wildlife Refuge. The geologic and economic assessments are reviewed. The sensitivity analysis shows that parameters that affect the perceived undiscovered accumulation size distribution exert a dominant influence on estimates of economically recoverable oil.