bluuebunny/crossref_metadata_2025_split huggingface dataset:
Floatation of 10¾-in. Liner—A Method Used to Reach Beyond 10 km
Authors: Eck-Olsen Johan , Haugom Rune , Løklingholm Geir , Sletten Håkon 
Published: December 2007

Abstract
The requirement to drill longer wells to reach reserves on the boundaries of the Statoil operated Gullfaks Field required new solutions and techniques. The planning of the 10 km+ long well A-32 C presented a challenge where floatation technology was required. The 4660 m (15285 ft) long 10 3/4" liner was successfully floated to section TD at 7721 m (25324 ft) on May 9th 2006.
The Gullfaks well A-32 C, named Gulltopp, is the longest well planned from an offshore installation with a planned TD at 10+ km. The simulation in the planning phase indicated it would be very difficult or impossible to run the 5 km 10 ¾" liner to TD with conventional methods due to drag and buckling. The floatation method was selected for the 10 ¾" liner to overcome drag and buckling problems. Simulation showed using floatation and running the liner fully evacuated with air, gave substantial reduction in torque and drag.
This solution required development of new equipment with special floats to withstand more than 360 bar (5200 psi) differential pressure. Snubbing slips were used to secure the liner during running. It took more than one year to plan and prepare this well. The paper describes the planning and obstacles met to achieve this challenging goal of drilling the Gullfaks well A-32 C – Gulltopp.
Coiled Tubing Re-Entry Whipstocks: The Next Evolutionary Step in Drilling Practices for Mature-Field Development
Authors: Garfield Garry , Mackenzie Gordon 
Published: December 2007

Abstract
Creating a sidetrack out of the main wellbore has become a more common oilfield drilling practice particularly in the revitalization of mature fields. In the past, re-entry applications have used a sidetrack philosophy governed by threaded tubular drilling conveyance; however, from the standpoint of a coiled tubing methodology, the practice of sidetracking a well may still be seen by some as being in its infancy with the practice not gaining real acceptance until the early to mid 1990s. It was a natural desire to be able to exploit the inherent advantages of coiled tubing and marry it to the practice of being able to perform a sidetrack. The main advantages for the operator community to utilize coiled tubing includes improved safety primarily from a pipe handling perspective, faster trip times, under-balanced capability, reduced operational footprint and environmental impact, and achieved economic returns. The paper will discuss in detail an overview of utilizing a whipstock system with the conveyance method of coiled tubing in order to create a casing / liner window. The overview will also discuss general practices, tool selection criteria, and provide case history demonstration of each. The case histories demonstrated will be representative of placement of the whipstock with both electric wireline and coiled tubing with actual window milling being performed with coiled tubing workover motors. The case histories will encompass monobore applications, through tubing re-entry environments, fluid operations, and under balanced nitrogen driven applications demonstrating how coiled tubing re-entry can economically rejuvenate mature fields.
Improvements in Operations Using a High Efficiency Jackup
Authors: Hart Gordon , Ramsing Allan 
Published: December 2007

Abstract
The paper presents the operational experiences gained in using a high efficiency ultra large jack up rig in operations offshore Norway for ConocoPhillips at the Ekofisk Field.
The rig features a new concept in cantilever skidding called x-y. It is also rigged with a quadruple derrick with dual standbuilding capability and space for casing racking.
The dual pipe handling, offline activity features have during recent drilling programmes saved as much as 25% to 30% on earlier offset wells drilled with more conventional units.
Contracts have been made according to which these rigs have been paid standard rates only, and recovery of the additional investment has been made possible by built-in incentive agreements.
A 200°C, 35,000-psi HP/HT MWD Tool: Development Program, Architecture, Mission Profile, and Prototype Testing Results to Date
Authors: Mayes J. C. , Boling B. E. , Mootoo D. M. , O'Keefe Meghan , Gwilliam W. J. 
Published: December 2007

Abstract
Military electronics and sensors with hermetic packages specified to 125°C have been the mainstay of the industry for many years. Oilfield service companies have long designed these components into downhole tools that operate in environments up to 175°C, but for significantly reduced periods of time. However, new development of hermetic military electronics has all but ceased, forced from the marketplace by less demanding, lower temperature consumer applications such as cell phones, portable computers, and personal data assistants (PDAs). Unfortunately, downhole tools designed with consumer electronics face substantially reduced life at higher temperatures. Therefore, oilfield service companies must employ innovative solutions and rigorous environmental qualification to ensure maximum reliability. At the same time the desire for additional services in ever more extreme environments is growing. This paper describes the development program, tool architecture, mission profile, and prototype testing results to date of a retrievable, reseatable measurement-while-drilling (MWD) tool specifically designed to operate at temperatures up to 200°C and pressures up to 35,000 psi.
Extreme Drilling Environment Forces Evolution of Rotary Steerable Systems and Rotary Steerable Bit Technology
Authors: Cox Bronwyn , Romo Louis , Champion Brett , Maung Osman , Card Kirk , Barton Steve 
Published: December 2007

Abstract
Wells drilled in the Tuscaloosa Trend located near Baton Rouge have long been recognized for the extreme nature of the High-Pressure / High-Temperature (HP/HT) operating environment and potential for well control problems1. The current focal point, however concerns drilling the highly abrasive formations contained within the intermediate and drilling liner sections to depths of ± 20,000-ft. These sections have been a major cause of bit, directional tool and drill string failures. The directional complexity of the wells has increased exponentially in recent years due to surface location constraints and reservoir compartmentalization. New drills are therefore primarily directional in order to penetrate multiple stacked targets, fault-out depletion; which would otherwise result in drilling differentials in excess of 13,000 pounds per square inch (psi) and adhere to regulatory constraints imposed upon building surface locations in certain areas.
Directional control in the intermediate hole section is challenging as it requires drilling through the abrasive and damaging Wilcox formation and still risks the wellbore drifting out of the target. However, below the intermediate section we encounter significant directional tool constraints as in situ temperatures range from 300-°F to 400-°F. Poor directional response, low penetration rates as well as increased motor failures due to stator deterioration have traditionally resulted in long and costly sections. The impact of conducting directional operations in the intermediate or drilling liner hole sections has resulted in an incremental spend of up to $3.0MM on some wells and a 30-day to 45-day delay in first production.
This paper focuses on the improvements which have been achieved over a 5-year period due to the implementation of Powered Rotary Steerable Systems (PRSS) coupled with Rotary Steerable Bit Technology. The step-change in performance has been evidenced by reduction in days per 10,000-ft (D/10K) drilled from 86-D/10K to 55-D/10K. The improved time to first production has been attributed to the systematic learning and the successes of several office based, well site and third party teams.
Deepwater Blowout—A Case History: Shallow Gas Hazards Hide in the Weeds
Authors: Flores William Jr. , Garner John B. , Scarborough Chris 
Published: December 2007

Abstract
This paper will detail the sequence of events involving the blowout of a deepwater development well adjacent to the discovery well, while Loop Current prevented running of the BOP stack and riser following the cementing of surface casing. Water depth was 2,400ft. The cause of the blowout was gas flow after cementing.
The operator designed the discovery well to incorporate the pump and dump process and successfully drilled riserless through a shallow gas hazard. Surface casing was run and cemented and the #1 well drilled to the objective depth and completed, pending field development.
The operator spudded the #2 well less than 200ft from the #1 well and duplicated the process, drilling riserless through the shallow hazard and running surface casing. After circulating lead cement to the mud line and observing cement returns at the wellhead, a proprietary cement slurry designed to achieve "right-hand set profile" was circulated into the well as planed.
The drill string was withdrawn and preparations were made to run the subsurface stack and riser. However, Loop Current developed and prevented the running of any equipment until the currents subsided.
Almost three weeks elapsed before the Loop Current abated, at which time the ROV was deployed and discovered the blowout. The plume of the blowout carried over 300ft. This paper will chronicle the extensive effort which the operator expended to reenter the well, perforate, pump kill mud, confirm that the well was static and cement. The conclusion however, is somewhat surprising: three days dormant after cementing the #2 well, while drilling the replacement well, the #2 blew out again. The paper will also present solutions implemented to successfully drill the replacement well.
Pin-Point Fracturing (PPF) in Challenging Formations
Authors: Beatty K. J. , McGowen J. M. , Gilbert J. V. 
Published: December 2007

Abstract
Over 145 pin-point fracturing (PPF) treatments have been performed in Australia's Cooper Basin since the introduction of the technology in mid 2004. The PPF method creates perforations by pumping abrasive slurry down the coil tubing through a jetting nozzle while the main treatment is then pumped down the annulus around the coil tubing. Isolation between fracture treatments is accomplished using sand plugs (preferred method) or composite bridge plugs. Fracturing treatments in the Cooper Basin have historically been problematic due to the combination of high rock strengths (average modulus of sand/shales of 4-5 million psi), proximity to coal formations, high formation temperatures (250-400 deg F), and high fracture gradients (often above 1.0 psi/ft). Screen-outs occur in ~40% of all treatments, so useful experience has been obtained on managing these events. This paper discusses the successful and unsuccessful experiences that have occurred using PPF techniques in these harsh situations. While PPF has improved well performance, the placement of treatments is still problematic. The paper details the experiences with varying abrasive jetting and breakdown techniques, modifying the bottom-hole assembly (BHA), changing the isolation techniques, modifying the treatment schedules, and extending PPF treatments to older wells.
Effect of Shear on Flow Properties During Placement and on Syneresis After Placement of a Polyacrylamide-Chromium Acetate Gelant
Authors: McCool Stan , Li Xianping , Wilhite G. Paul 
Published: December 2007

Abstract
Typical gel polymer treatments to treat fractured rock consist of injecting inline mixed gelant into the reservoir for times usually much longer than the bulk gel time of the gelant. Flow experiments were conducted to determine the effect of shear on the flow properties of the gelant for durations greater than the bulk gel time. Inline mixed gelant was injected through a 1031-ft long tube to simulate a fracture. Flow resistance increased down the tubing to steady values indicating gelation of the flowing system. Similar flow experiments were conducted by injecting preformed gel through the tubing. Flow resistances decreased down the tubing to steady values indicating breakdown of the gel structure. Flow resistances at the steady downstream sections were higher during the injection of inline mixed gelant compared to injection of preformed gel and both were much lower than literature values determined where preformed gel was injected through short fractured rocks and short lengths of tubing. Gel samples underwent syneresis after they were formed during shear flow in the tubing and in a rheometer. Interpretations of flow resistance data from injection of inline mixed gelants and preformed gels in long tubing are presented.
Staircase Lifting of Oil Using Venturi Principle: A New Artificial-Lift Technique
Authors: Gupta Siddhartha 
Published: December 2007

Abstract
Artificial lift systems are now being considered of extreme importance as the reserves across the globe are depleting and the wells are unable to flow naturally. Over the years a number of artificial lift techniques have evolved as a result of extensive research and ground work. All the systems have proven their worth by increasing the productivity of the field by many folds. But each of these artificial lift systems has economic and operating limitations that eliminate it from consideration under certain operating condition. However all the conventional artificial lift systems have a common feature. The energy added to the lift the fluid from the wellbore is lost in the process and cannot be utilized for some other operation.
This paper describes a new technique of artificial lift which uses the concept of venturi to lift the fluid to the surface. A high velocity power fluid is used to create drawdown at the throat of a surface venturi and this pressure drawdown is transmitted downhole by pressure tappings. The drawdown lifts the fluid through the production tubular in a stepwise manner. The power fluid coming out from the other end of the venturi is used to drive a turbine which generates power as a result. This power is used to operate the inlet compressor thus the cycle being completed. After startup, effectively, no energy is used up to keep operating the system.
The system is of immense economic benefit as the operating expenditures are low. Also this system uses zero-cost air as power fluid. It is a space efficient package which can be used on offshore locations as well.
The paper describes the individual components of the system and the calculations involved therein. The economic and technical comparison of this system with the conventional methods is also enlisted.
Modeling Shear Failure and Stimulation of the Barnett Shale after Hydraulic Fracturing
Authors: Palmer Ian , Moschovidis Zissis , Cameron John 
Published: December 2007

Abstract
In the Barnett Shale, microseismic bursts are caused by shear failure on planes of weakness well outside the central fracture plane. Some data show that greater gas flowrate is correlated with a larger "failed reservoir volume", and a higher net fracturing pressure. These aspects have been integrated into a theoretical model. Shear slip or failure along planes of weakness is instigated by pore pressure increases during injection of frac fluid, and pressure transient theory is used to describe that. A knowledge of in situ stress, and strength (or failure envelope) for the planes of weakness, is needed to predict how far away from the central fracture plane this failure zone extends. The failed reservoir volume can be matched to the volume of the microseismic cloud, using injection permeability is the matching parameter. The predictions appear to be reasonable. The injected permeability we obtain is greater than the virgin permeability, and this is interpreted as enhanced permeability due to shear or tensile failure away from the central fracture plane. The permeability enhancement increases as fracturing pressure increases. We have compared the permeability enhancement with history matching of gas production in Barnett Shale wells, and with theoretical matching of Cooper basin data in Australia. The model is a screening model, and may be viable to design a fracture treatment to optimize the enhanced permeability, and the gas production. An advantage of the screening model is its ability to quickly run a number of different scenarios, to choose an optimal stimulation. The model is completely general, and should be applicable to other formations, such as coals and tight sands.
The Optimisation of a Scale Management and Monitoring Program for During the Production-Decline Phase of the Life Cycle
Authors: Jordan Myles , Archibald Ian , Farrell Rod , Johnston Clare , Strachan Alistair 
Published: December 2007

Abstract
This paper presents field results from scale squeeze treatments carried out on platform and subsea horizontal wells from a oilfield in the UK sector of the North Sea. Downhole scale control and the resulting squeeze treatments to production wells were highlighted as one of the most expensive items in the production chemical budget and impacted topside separation during treatment back production. The development of optimized scale squeeze treatments and monitoring policy has been critical to reducing the operating cost and deferred oil production of this asset as the produced water cut rose.
Scale squeeze treatments have been optimised over the years with the aid of detailed reservoir simulation indicating water rates along the production wells being input into scale squeeze design software. The requirement to extend treatment life while minimising the deferred oil was one of the critical factors in selecting improved scale inhibitor chemistry. The field data from these wells will be presented comparing treatment lifetime rates between conventional treatments and the improved scale inhibitor chemistry.
Evaluation of residual chemical concentration or scaling ion chemistry has long been used in monitoring programs. All these methods prove that the chemical is present in the brine when sampled or that scale formation is not occurring at the point of brine analysis. This paper outlines the experimental methods developed to evaluate the suspended solids collected from the produced brine by environmental scanning electron microscope (ESEM) and the associated brine chemistry to evaluate the scale risk within the produced fluids. The combination of these methods has improved the integrated scale management program in terms of evaluating scale squeeze placement effectiveness, squeeze lifetime and providing the confidence to extend the period between scale squeeze treatments and in some cases stop treatment where brine analysis alone would have suggested further scale squeeze applications.
Multiscale Mixed-Finite-Element Modeling of Coupled Wellbore/Near-Well Flow
Authors: Krogstad S. , Durlofsky L. J. 
Published: December 2007

Abstract
An accurate well modeling capability is important for both production and reservoir engineering calculations. Ideally, the models used for these two applications should be related in a logical manner. Multiscale methods allow varying degrees of resolution and can therefore provide a natural linkage between production and reservoir models. In this work, we present a coupled wellbore-reservoir flow model that is based on a multiscale mixed finite element formulation for reservoir flow linked to a drift-flux wellbore flow representation. The model is able to capture efficiently the effects of near-well heterogeneity in the reservoir and phase holdup and pressure variation in the wellbore. The formulation presented here is for oil-water systems. The basic reservoir-wellbore linkage is described and validated through comparison to results from an existing simulator. The multiscale methodology is then applied to a heterogeneous reservoir model. Both vertical and deviated wells are considered. Comparisons of the multiscale solution to the fully resolved (fine-scale) solution demonstrate the high degree of accuracy of the method, for both reservoir and wellbore quantities, as well as its efficiency.
Practical Iterative Coupling of Geomechanics With Reservoir Simulation
Authors: Samier P. , De Gennaro S. 
Published: December 2007

Abstract
The use of reservoir simulation coupled with geomechanics to model physical phenomena such as compaction, subsidence, induced fracturing, enhancement of natural fractures and/or fault activation, SAGD recovery etc.., has been increasing. Different methods of coupling have been investigated by numerous researchers: fully implicit coupling, iterative coupling and one way coupling. So far, the iterative explicit method appears to be the prefered method for field-scale simulation.
This method is a loose coupled approach between a reservoir simulator (finite volumes) and a geomechanical simulator (finite elements). At user-defined steps, the fluid pressures calculated by the reservoir simulator are transmitted to the geomechanical tool which computes the actual stresses and reports the modifications of the petrophysical properties (porosities and permeabilities) back to the reservoir simulator. In the classical iterative scheme, at each stress equilibration step, the reservoir simulation needs to be restarted from the previous converged step. This restart based scheme can be difficult to implement in practice within an industrial IT environment.
This paper presents a new iterative scheme which allows: –any reservoir simulator,–to be coupled with any nonlinear FEM package for the stress analysis, with no limitations on the functionality of either simulator.
This is achieved by performing the pressure/stress iterations at the end of a complete reservoir simulation. Porosity and permeability modifications at various times are calculated, and the complete reservoir simulation is then repeated. Iterations are continued until convergence is achieved.
The convergence of this new scheme is discussed and results are presented for two cases described below.