bluuebunny/crossref_metadata_2025_split huggingface dataset:
Improving Hole Quality and Casing-Running Performance in Riserless Topholes—Deepwater Angola
Authors: Akers T. J. 
Published: March 2008

Abstract
The operator and co-venturers are developing several Angola Block 15 fields in water depths of up to 1400m. To date, 83 development wells and 33 exploration / appraisal wells have been drilled in the Block. Most have experienced hole quality issues in the riserless interval that manifests themselves as tight hole while tripping the BHA and abnormal/excessive drag running casing. In a few cases, casing could not be run to total depth (TD) and in one unfortunate case, the casing buckled in open water.
There has been uncertainty as to the root cause of the hole quality issues which have been attributable to various factors since drilling was initiated. A review of available literature revealed very little published information on riserless drilling and casing running practices. The operator undertook a study of its riserless drilling and casing running practices in order to look for trends that may suggest certain sources as the root cause and to allow a re-examination of long-accepted practices. The study, combined with some new perspectives on directional drilling mechanics, has identified potential root causes not previously considered. Changes to drilling practices have resulted in improved riserless hole quality and smoother casing running operations.
Surface BOP Operations from a Multi-Service Vessel
Authors: Johnston Colin 
Published: March 2008

Abstract
A vessel upgrade to enable completion operations with the goal of drilling operations is discussed. The upgrade being the application of surface BOP technology to enable a subsea construction and well intervention multi-service vessel to become a slimhole completions and ultimately a drilling vessel.
The Q4000 is a column stabilized semi-submersible unit currently applied to subsea construction and subsea well operations in the form of through tubing intervention and well decommissioning. Within the upgrade review presented, the existing vessel configuration is detailed with the current intervention riser system applied to subsea well operations. The specific upgrade requirements are detailed and their impact upon the existing vessel and its operation reviewed. The key point being that the surface BOP operations are an extension of existing high pressure riser based intervention operations of which more than 40 have been conducted from the Q4000.
The upgraded subsea components in the form of a subsea shut off device (SSOD) at the wellhead, and a surface blowout preventor (SBOP) below the vessel with a high pressure riser are described. Operationally the equipment and methods to control and monitor this equipment are detailed with the analytical aspect of completion operations in 2357 ft of water.
The overall application of the upgraded vessel to an existing well completion is described in detail. The requirements to accomplish the operation in terms of equipment deployment, downhole operations and the key differences between SBOP based completion with those of more common subsea BOP and marine riser based operations are presented.
With a view to expanding the scope of application, of both the vessel and the SBOP configuration, future applications are discussed with key issues raised that may impact future operations.
Successful Implementation of First Closed Loop, Multiservice Control System for Automated Pressure Management in a Shallow Gas Well Offshore Myanmar
Authors: Fredericks Paul , Reitsma Don , Runggai Tom , Hudson Neil , Zaeper Ralf , Backhaus Oliver , Hernandez Maximo 
Published: March 2008

Abstract
In plans to explore the shallow gas potential of the Nagar prospect offshore the southern coast of Myanmar, PETRONAS had to contend with a number of potentially high risk issues. The shallow nature of the hazardous prospect made kick detection speed and pressure control accuracy essential to avoid losing returns. Concerns about a weak casing shoe, a narrow drilling margin, the inability to control bottom hole pressure (BHP) while circulating out gas, and the short response time needed, demanded a solution before the shallow gas-bearing sands could be drilled safely from the available moored drill ship with its conventional subsea equipment.
From flow modeling it was estimated that within 3 minutes the system and procedures would have to detect and shut-in a gas influx, then commence circulating it out, all while controlling the BHP of a flowing, multiphase fluid within extremely narrow safe limits. It was concluded that the Nagar well could only be safely drilled with a pressure management system that could maintain BHP within +/− 15 psi while drilling and +/− 45 psi during connections and well control.
In an industry search, PETRONAS learned that no system existed with the functionality needed, but by electing to combine new and existing technologies from three separate providers they were the first to develop one that did.
This industry-first solution involved integrating elements of the technology developed for automated pressure control, pressure while drilling (PWD), and high speed, drill string telemetry. Modifications had to be made to a number of elements, including the pressure control and PWD systems, to obtain the necessary functionality. Given the safety critical nature of the drilling hazards, the modifications and system integration were first tested during simulated kicks with downhole nitrogen injection, before drilling out the casing shoe. During testing on the rig and subsequent drilling operations, the integrated system proved its ability to maintain a near constant BHP, with the accuracy and speed needed to safely and successfully drill the Nagar prospect.
Method to Eliminate Lost Returns and Build Integrity Continuously With High-Filtration-Rate Fluid
Authors: Dupriest Fred E. , Smith Marty V. , Zeilinger C. Sabine , Shoykhet I. Nissan 
Published: March 2008

Abstract
This paper describes a fluid system developed to build integrity continuously to prevent lost returns while drilling. The primary attributes of the fluid that enable this are high solids content and extremely high filtration rates, as reflected in API fluid loss tests. It is referred to here as a drill and stress fluid (DSF).
In field applications, DSF water-based systems appear to be effective over a wide range of conditions. Circulating pressures have been sustained that exceed integrity at the bit by 1.0 to 3.0 ppg without detectable losses in depleted formations with permeability ranging from 1 to 1,000 md and pay zones of 50 to 700 ft (165 to 2,300 m) in length. The mechanism through which the DSF is believed to arrest the growth of lost returns fractures and build near-wellbore stress is described. Generalized design criteria for a DSF system are presented and the assumed relationship between the design parameters and fluid performance is discussed.
The results of the application of DSF are presented for eight wells, including post treatment evaluation logs of the drilling-induced fractures created while building stress. Operational practices that facilitate the safe use of an extremely high fluid loss system with overbalance exceeding 2,000 psi are also discussed.
Use of New Hydrostatic Packer Concept to Manage Lost Returns, Well Control, and Cement Placement in Field Operations
Authors: Dupriest Fred E. 
Published: March 2008

Abstract
A hydrostatic packer consists of a column of light fluid pumped into the annulus or drillstring to cause the total hydrostatic head to be equal to or less than the integrity, which is a product of the fracture closure stress (FCS). This results in positive surface pressure, which allows accurate placement of cement, lost returns treatments, or other fluids in situations where they would otherwise be overdisplaced if a full column of drill-weight mud were used. Although hydrostatic packers are not a physical device, they are referred to as packers because they serve many of the same functions as retainers and squeeze tools and are used in similar operational situations.
The operator has utilized hydrostatic packers in one area for 15 years and globally for the last seven years. Despite the maturity of the practice it has not been adopted by the industry. The business value is large, but lack of understanding of fracture mechanics in the drilling industry raises a significant barrier. The use of hydrostatic packers requires that engineering, operations, and contractor personnel understand the fracture propagation mechanism through which major lost returns events occur, and particularly the role of fracture closure stress. The team must also develop field practices to mitigate specific risks associated with hydrostatic packers. This paper discusses these points as well as the operational issues that must be considered in certain unique situations.
Applications described include stabilizing the annulus following lost returns, controlling placement of lost circulation material (LCM) when pumping pills, controlling cement placement during squeeze operations, achieving high quality cement coverage behind liners with lost returns, and management of downward underground flow.
Hydrostatic packers have been used effectively in over 30 fields and have contributed greatly to the operator's high success rate in treating lost returns events (Dupriest 2005). Their use requires training and structured risk assessment, but they are simple in concept and have been effective in controlling fluid placement in all field applications to date.
Managed Pressure Drilling Success Continues on Auger TLP
Authors: Chustz Mark J. , Smith Larry D. , Dell Dwayne 
Published: March 2008

Abstract
Shell Exploration & Production Company continues to execute redevelopment slim hole sidetracks using Managed Pressure Drilling (MPD) on the Auger TLP in Deepwater Gulf of Mexico. Four sidetracks have been successfully drilled utilizing a Dynamic Annular Pressure Control (DAPC) system to eliminate lost circulation and borehole instability events.
Execution of MPD continues to improve, resulting in operational efficiency gains and allowing access to previously unattainable reservoir targets. Intervals previously considered impossible to drill due to depletion induced frac gradient reduction are being drilled and cased trouble free with MPD.
Recent MPD well designs have incorporated reduced static mud weights below pore pressure to manage the available drilling margin. Bottom hole pressure variation from the defined set point has been reduced and excursions outside of the target pressure window are being eliminated during subsequent MPD well operations.
Auger's field redevelopment history, well designs and Managed Pressure Drilling designs will be reviewed. Execution of MPD operations will be addressed in detail focusing on engineering and operational improvements throughout the four MPD sidetrack campaign.
Tight Clearance Operations—Running 5½-in. Liners in 57/8-in. Holes
Authors: Goertz Markus , Belohlavek Kai-Uwe 
Published: March 2008

Abstract
In North-German gas fields, occasionally 5½-in. liners have to be run in 5⅞-in. boreholes. This low-clearance application does not represent the standard. This paper describes the steps taken to successfully run and cement these liners in spite of the extremely tight clearances by means of two case studies.
One application is to run 5½-in., 32-lb/ft thick wall casing in 5⅞-in. holes to cover squeezing salt sections in order to provide long-term integrity of the well. The other application is to run regular wall 5½-in., 20-lb/ft casing to enable remedial sand control, which would not be possible with standard sized 5 or 4½-in. liners.
In both applications, these liners had to be run through 5⅞-in. drift casing into a directionally drilled 5⅞-in. openhole with actual dogleg severities (DLS) of up to 9°/100 ft. Often, the drilled sections contain hard and abrasive sandstone layers, which have to be drilled with diamond impregnated bits. Thus, underreaming is not economically viable.
To successfully run and cement the 5½-in. liners, the borehole has to be prepared properly by running extremely stiff reaming assemblies. The 5½-in. tubulars do have special flush connections (MUST or V&M-FJL). Experience has shown that a planned DLS of 6°/100ft is feasible. On regular wall 5½-in., centralization is achieved with Ceramic Carbon Fiber Stand-offs. The mud systems used ranged from low solid Formate mud (12.2 ppg with extremely low fluid loss and thin filter cake) to weighted water-based mud (16.4 ppg with high solid content). Additionally, to reduce friction, lubricants based on Glycol or Graphite were successfully applied. Finally, cement recipes have to be carefully adjusted to these mud systems.
Treatment of Nonaqueous-Fluid-Contaminated Drill Cuttings—Raising Environmental and Safety Standards
Authors: Kirkness Alister , Garrick Davie 
Published: March 2008

Abstract
Drill cuttings and other hydrocarbon contaminated wastes generated in offshore drilling operations have been processed onshore for many years, in part to comply with the regulatory restrictions governing offshore disposal and in part to conform to sound environmental practice. However the transporting ("skip & ship") of large tonnages of hydrocarbon contaminated cuttings from offshore installations to shore based processing facilities carries with it considerable environmental and safety implications for the industry.
The concept of processing these hydrocarbon contaminated cuttings offshore and the recycling of both the recovered oil and water back into the drilling fluid provides a unique solution to the inherent problems of "skip & ship", both in the North Sea and elsewhere. The development of this concept into a practical, field proven technology commenced in 2001 and was satisfactorily concluded, following a series of offshore trials in the UK sector of the North Sea, in the latter part of 2002. Since this time the application of this technology has gained wider use and greater acceptance by the industry, allowing for a thorough evaluation of its application in resolving many of the more intransigent problems associated with drilling waste management in offshore operations.
This paper reviews the work completed to date and how it might best be applied in the future. For the work completed, field data will be provided on all aspects of the process and also evaluate the benefits, both in terms of the environment and safety, on a project specific basis.
With regard to the future, the paper will look at ways in which offshore treatment may be better applied to optimize all of the advantages obtained.
MPD Operation Solved Drilling Challenges in a Severely Depleted HP/HT Reservoir
Authors: Bjørkevoll Knut S. , Molde Dag Ove , Rommetveit Rolv , Syltøy Svein 
Published: March 2008

AbstractA novel MPD setup has been tested and used at the Kvitebjørn field in the North Sea to make possible the drilling of 8.5″ holes through reservoirs with heavily depleted zones. A central part of the concept has been to use an advanced dynamic flow and temperature model in combination with an automatic choke system to control open hole pressure very accurately.The paper describes briefly the operations, and discusses challenges and experiences related to making these complex components work reliably together.The system has proven its potential for minimal variations in pressure at a given open hole position, with accurate automatic pressure control in wells were margins are very small, smaller than frictional pressure losses added when circulating at drilling rate.This paper focuses in particular on the use of an advanced transient model for automatic choke regulation. Other aspects of the operation are described in more detail elsewhere, see Refs. 1-3. Challenges exceeded expectations, but after a test period with many improvements based on trial and error inside cased hole, the 8 1/2″ sections were drilled successfully with good pressure control.
Cementless Multi-Zone Horizontal Completion Yields Three-Fold Increase
Authors: Maddox Brad , Wharton Molly , Hinkie Ron , Balcer Brent , Farabee Mark , Ely John 
Published: March 2008

Abstract
This case-history paper presents an account of the application of expandable (swelling) packers and a hydrajet perforating stimulation technique to perform a cementless completion and hydraulic stimulation in a 350° F, openhole horizontal well of 15,700 ft total vertical depth (TVD). Resulting production was more than three times that of an offset vertical well.
The first Wilcox Meek 2 well in the Brazos Bell Prospect Area was drilled and completed to test the effectiveness of horizontal well technology in tight-sand formations. This paper presents the cementless completion process and explores the effectiveness of horizontal-well technology in tight sands by comparing initial horizontal-well production rates to those of offset vertical wells.
The well, which was the first horizontal Wilcox in the area and probably the deepest horizontal well completion for a sandstone reservoir in South Texas, used a 5 ½-in. / 3 ½-in combination string as a production string. The 3 ½-in casing was run in the openhole horizontal lateral section and extended into the 75/8-in liner casing. It employed five swellable packers, strategically placed on the string to facilitate isolation for optimum stimulation results. An additional swellable packer, larger than the previous five, was run on the top of the 3 ½-in casing string and was placed inside the 75/8-in casing to help ensure complete isolation of the annulus. The swelling packers were activated over an 18-day period by hydrocarbons present in the oil-based mud (OBM) in the annulus.
Following packer activation, four fracture-stimulation operations were conducted in a non-cemented hole using a unique fracturing technique that incorporates hydrajet perforating with coiled tubing (CT). This technique allows for (1) multiple stimulation treatments to be performed in series without the CT being removed from the hole, (2) larger stimulation stages, and (3) maximum surface-area exposure to the fracture pressure without formation damage caused by cement.
Offshore Underbalanced Drilling—The Challenge at Surface
Authors: Gough Geoff , Graham Robert 
Published: March 2008

Abstract
This paper is a case study detailing the process followed and challenges encountered, at surface, when drilling oil wells underbalanced offshore in the Danish sector of the North Sea. UBD was identified as an enabling technology in the field to combat conventional drilling challenges due to variations in pressure profile along lengthy horizontal hole sections - the drilled wells comprised 6" horizontal sections in excess of 2000m. The drilling programme presented a significant examination of the surface handling equipment due to the anticipated inflow parameters. The surface system was required to de-energise and separate up to 25,000 bpd returned/produced oil, water and cuttings along with up to 30 MMscfd of gas; returning the water back to the rig for the well circulation system, cuttings into the annulus of an existing well and the routing of produced hydrocarbons to the existing production platform. The first well also utilised platform gas for annular gas injection to maintain the required circulating pressure profile. A rigorous process design procedure was followed to determine the optimum surface equipment configuration to handle the combination of drilling fluid, solids and well effluent that came to surface during underbalanced drilling operations as well as evaluating potential for hydrate formation, foam and emulsions. An alignment of procedures with the rig, production platform and service companies was implemented. In addition, a strategy was employed to facilitate recovery of oil and gas produced during underbalanced drilling operations to the platform process facilities. Challenges that presented themselves included large volumes of friction reducers in the circulating system, lower than expected surface temperatures, ultra fine cuttings production and integrating the platform's data acquisition and emergency shutdown systems.
Multi-Diameter String Tools Deliver Lower Cost-Per-Foot in Demanding Rotary Steerable Applications
Authors: Barton Steve , Jones Wayne , Young Rick , Rorvik Helge 
Published: March 2008

AbstractThe use of hole opening tools in conjunction with Rotary Steerable Systems (RSS) has increased dramatically in the past few years. Although excellent performance has been delivered with the mainstream commercial tools, alternate options have been developed to enable an RSS to drill the pilot hole in conjunction with a string tool to open the hole in a single run.The most popular current option involves a weight or hydraulic activated underreamer. However, fixed blade, multi-diameter reaming tools have recently been developed for use within Rotary Steerable (RS) assemblies: An eccentric string reamer that will pass through a small pilot hole but then drill and produce a larger hole. This provides a significantly lower-cost hole opening option.A concentric string reamer that utilizes a tapered design incorporating a mid and main reamer section. This innovative design uses a mid-reamer that enlarges the pilot hole to an intermediate size and stabilizes the main reamer above it on its gauge pads. Because of its unique design, the mid reamer is able to stabilize the tool even if the pilot hole is of poor quality or is overgauge. This is particularly beneficial with RS tools in soft formations, leading to improved borehole quality and BHA stabilization. It also enables the use of smaller RS tools, thus providing greater directional potential. Additionally, a single RSS can be used to drill multiple hole size intervals, minimizing BHA changes, which in turn increases rig floor safety and lowers costs.Several distinct applications are documented where these fixed bladed solutions, in combination with both Push and Point RS tools, have proven extremely successful. This has provided greater flexibility with regard to tool selection and well planning options, delivering lower cost per foot in RS projects. Case studies are presented from the Far East, Norway, and the Gulf of Mexico.