bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Drilling Contractor's View of Underbalanced Drilling
Authors: Murphy R. D. , Thompson P. B. 
Published: December 2007

Abstract
This paper is not a technical discussion of under balanced drilling (UBD). Nor is it a filled with "tricks of the trade" advocating a better technical means of drilling wells using UBD. It is a discussion about the best method, from one drilling contractor's view, to execute a safe and productive UBD project. There is no magic formula, no exotic management technique and no revolutionary equipment design that will guarantee success. Rather this is a frank discussion, without references, about the "mindset" that an operator and drilling contractor has when approaching a UBD project. The authors have worked as an operator and a drilling contractor on a variety of successful and unsuccessful (some disastrous) UBD projects. The goal of this discussion is to help the operator and the drilling contractor better understand the strengths, weaknesses, needs, concerns and goals of each other to better deliver a successful UBD project.
How the Bit Profile and Gages Affect the Well Trajectory
Authors: Menand S. , Sellami H. , Simon C. , Besson A. , Da Silva N. 
Published: December 2007

Abstract
The importance of wellbore deviation is well recognized by the drilling industry. An analysis of the directional behaviour of a drilling system must include the directional characteristics of the drilling bit. A comprehensive analysis of the directional behaviour of PDC bits is presented in this paper, including the effect of bit profile, gage cutters and gage length. Numerical simulations as well as laboratory tests have been carried out in order to better understand the mechanisms of PDC bits deviation and to evaluate the most important parameters affecting the directional behaviour of PDC Bits.
The analysis of the directional behaviour of PDC bits presented in this paper shows that each part of the PDC bit (bit profile, active and passive gages) plays a major role on the walking tendency and steerability of the bit. A quantitative evaluation of the contribution of these factors on the well trajectory (inclination and azimuth) is given.
A full-scale directional drilling bench was built to measure, for the first time, the walking tendency and the steerability of PDC bits. The results obtained demonstrate that the bit profile, the gage cutters and the gage length have a significant effect on the walking tendency and on the steerability of the PDC bits. A 3D theoretical rock-bit interaction model was developed to reproduce the drilling tests results.
Evaluation of Solids Carrying Capacity in Aerated Fluid Drilling: Real Scale Tests and Modeling
Authors: Martins A. L. , Lourenço A. M. F. , Andrade P. H. , Silva V. , Silva P. R. C. , Nakagawa E. Y. 
Published: December 2007

Abstract
This paper summarizes the results of two sets of experimental tests performed at PETROBRAS real scale test facility aiming the evaluation of solids return times in aerated fluid drilling. The effect of the following parameters was studied: liquid and gas injection rates, particle diameter and depth. Results indicate that the gas has a major effect in accelerating the liquid phase, which would be responsible for carrying the particles to the surface. The concept of effective liquid velocity coupled with an adequate procedure for particle sedimentation velocity calculation reproduced the experimental results adequately.
Designing Invert Drilling Fluids to Yield Environmentally Friendly Drilled Cuttings
Authors: Growcock F. B. , Curtis G. W. , Hoxha B. , Brooks W. S. , Candler J. E. 
Published: December 2007

Abstract
An invert emulsion drilling fluid has been developed that possesses the drilling properties of conventional invert muds, yet can be discharged onto land as a soil enhancer. The individual components of this Soil-Enhancing Synthetic Based Mud (SE-SBM) -- base fluid, internal polar phase, emulsion stabilizers, wetting agents, fluid-loss-control agents and weighting material -- also possess these attractive features.
One version of the SE-SBM produces mud-laden cuttings that can be land-farmed directly without pretreatment. Where discharges are severely restricted with respect to salt, oil and/or grease content, another version of the SE-SBM is particularly well suited for pretreatment of the cuttings in a bioreactor or other rapid biotreatment technique.
Avoiding Catastrophes in Dynamic Positioning; Integrating Key Parameters Using a Systems Approach
Authors: Weingarth Lew 
Published: December 2007

Abstract
Recent newbuild and major upgrade deep water Dynamically Positioned (DP) rigs have been plagued by station-keeping difficulties. Many of these problems have been attributed to the DP system, the power management system, or the DP operators’ capabilities. Maximum efficiency and minimum non-productive (down) time for DP rigs can best be achieved by using an approach that considers all of these factors simultaneously – a SYSTEMS approach.
DP operation successes and failures will be illustrated using case studies from five drilling rigs with which the author has personal experience. Each of these cases will demonstrate the inter-dependence of critical equipment and systems that allow a rig to maintain position.
Additionally, the paper will describe latent problems identified, as well as describe why a systems approach would have avoided them. Primary emphasis will be on the symbiotic relationship between the DP and power plant management control systems, as well as the resident anti-blackout software in both. Cases will illustrate:Who's right, DP or power management?The DP rabbit and power plant turtle.How lack of DP operator knowledge can defeat even the smartest software.When does too much redundancy reduce reliability?What happens when one computer doesn't notice the other one died, or why is it critical that BOTH systems be designed as parts of a whole?
Finally, a brief analysis will offer how to best implement the systems approach on future projects, from both the owner and operator viewpoints. The analysis will cover how the systems approach impacts the following:Making certain that lessons from prior catastrophes are incorporated in the current projectUtilizing the relative strengths of in-house and third party personnelUnderstanding effective DP operator trainingEnhancing troubleshooting and downtime avoidance
Design for Semisubmersible Deepwater Development Drilling Unit Conversions is Achieved by Careful Listening
Authors: Quintero Alan 
Published: December 2007

Abstract
Atwood Oceanics, Inc. is upgrading two of its third generation semisubmersible units to operate conventionally in up to 5,000’ of water. In preparation for these upgrades we asked ourselves: "How do we decide what items to upgrade, and to what extent are these upgrades value added?" This paper will present the process Atwood Oceanics took to determine what upgrades we would undertake, and will summarize our final definition of a "fit for purpose, 5,000’ semisubmersible" based on the research.
In 1999/2000, Atwood Oceanics, Inc. was in the process of planning an upgrade to the Atwood Eagle from it's existing 2,000’/3,300’ water depth rating to 5,000’ of water. To prepare the upgrade scope Atwood Oceanics, Inc. researched published specifications of competing units. The data was split into two classes of rigs: 3,500’ to 4,000’ of water depth rating, and 4,500’ to 5,500’ of water depth rating. Items reviewed included general particulars, mooring systems, lifting, drilling equipment and mud system. From the research Atwood Oceanics conducted, we developed specifications for a "mid spec" rig in each of these categories.
In addition, Atwood decided to go to its clients to get input to what the industry believes a "fit for purpose, 5,000’ of water depth drilling unit" is. We met in small groups with some of our clients, and sent a client survey to 14 contacts in nine companies.
This paper will include the results of the client survey, the "mid spec" rig specifications developed, how these specifications were converted to an actual upgrade scope, and a discussion of why certain decisions were made. This information should give the industry a good snapshot of value-adding features of drilling units, and may serve as a first-pass tool for rig selection.
Cost-Effective Subsea Drilling Operation on the Smallest Norwegian Field Development
Authors: Blikra H. , Andersen R. , Hoset H. , Vestvik J. , Berg H. 
Published: December 2007

Abstract
Drilling and completing 4 horizontal and one vertical injection well during the months from October 2000 to May 2001 cost-effectively developed the Glitne subsea field in the Norwegian Continental Shelf. The operation was completed six weeks ahead of budget time and included an extended drilling programme of additional 5000 m compared to the development plan.
This paper will focus mainly on the drilling operation and why it succeeded. It will also include a brief description of the whole field development solution. As time is the main cost driver on a subsea operation, beating the time schedule was the primary goal for this operation. The drilling programme focused on a well planned and effective batch drilling operation for all hole sections, and the extended use of cost-effective rotary steerable assemblies.
Real-Time Specific Energy Monitoring Reveals Drilling Inefficiency and Enhances the Understanding of When to Pull Worn PDC Bits
Authors: Waughman Robert J. , Kenner John V. , Moore Ross A. 
Published: December 2007

Abstract
Optimizing when to replace worn bits can yield substantial cost savings, especially in the high cost deep water offshore drilling fields, however, recognizing when a bit is "dull" and past its true economic life can be difficult. All too often, speculation and the hope that the bit will "break through" into something more drillable has remained the driving force for determining whether to change a bit or leave it in the hole. This decision making process is extremely inefficient and does not further the philosophy on continuous improvement.
The concept developed to dramatically improve this inefficient decision process involved measuring the mechanical energy input at the drill rig floor; calculating the drilling specific energy; checking current formation type via real-time downhole gamma ray readings; comparing the specific energy with the benchmark new bit specific energy and then using these values to assess the bit's "dull" state. This method has been proven to work in synthetic based mud systems where balling does not mask bit dull condition. Since both balled-new bits and dull bits exhibit similar levels of inefficiency, it was imperative the operator proved this process worked in water-based drilling fluids that had replaced earlier synthetic muds. Synthetic muds were replaced by the water-based fluids due to environmental concerns, cost, and improved performance in WBM. Recently, the operator established that this process worked in water based mud systems that are treated with anti-balling chemicals. The case studies where this methodology was developed will be presented and discussed.
An Innovative Approach to Stuckpipe Reduction in the Niger Delta
Authors: Magaji M. A. , Amoo Olufunso A. , Owoeye Oladele O. 
Published: December 2007

Abstract
Stuck pipe used to be the major problem resulting in 80% of lost time during drilling operation in Shell petroleum development Company, Nigeria, the major operator in the Niger Delta area. A survey on borehole stability in the Eastern SPDC operations between 1996-1999 showed that eight (8) string months was lost to hole instability problems. During the period, forty (40) stuck pipe incidents were recorded in 70% of the wells accounting for over 80% of the lost time. The alarming rate of reoccurrence of this industry problem made it necessary for management to seek for solution within. Subsequently a Stuck Pipe Risk Factor (SPRF) prediction Tool was developed based on prevailing occurrence and existing data. The tool is being used to predict the inherent risk of getting stuck in well planning and design stages. In addition to that, it is used for change control during drilling, especially when lithological, formation pressure and rock mechanical properties changes are encountered during the execution phase of the well.
This paper reviewed the implementation strategy of the SPRF tool in the well engineering Operation of SPDC-Nigeria, both at conceptual and execution stages. The review showed that as a result of strict implementation of SPRF in all stages of well Delivery processes, major stuck pipe incidence dropped to 7 in the year 2000 when a total footage 241,013ft was made compared to 27 incidence in 1999, when 234,814ft was made. This represent 75% drops in stuck pipe incidence in year 2000. Similarly a 58% reduction in Non Productive Time (NPT) was recorded in year 2000 compared to 1999; resulting in 45% reduction in money lost
In conclusion, SPRF Tool have come to be accepted in SPDC as a reliable, fast and accurate way of simulating well design with ultimate aim of eliminating potentials for stuck pipe problems. It is also extensively used at the well site for operational monitoring where significant lithological, formation pressure and rock mechanical properties changes have been encountered.
It has also earned Shell Nigeria a ‘Center of Excellence’ award by the Shell Group Global Hole Stability (GHOST) Team.
Marlin Failure Analysis and Redesign; Part 1, Description of Failure
Authors: Bradford D. W. , Fritchie D. G. , Gibson D. H. , Gosch S. W. , Pattillo P. D. , Sharp J. W. , Taylor C. E. 
Published: December 2007

Abstract
The Marlin Field is located in the Gulf of Mexico, Viosca Knoll Blocks 871/915, and was originally intended to be produced from a TLP via five dry tree penetrations. First production from the A-2 well began in November, 1999. Shortly thereafter a minor, but persistent tubing leak occurred. Between November 7 and November 20, Well A-2 was alternately flowing and shut-in, depending on shakedown of the surface equipment and availability of the pipeline. On November 20, the casing pressure jumped to shut-in tubing pressure, signifying a major tubing failure.
This first of three related papers describes the actions of an incident investigation team formed to evaluate the failure of Well A-2. Possible failure modes investigated by the team include:
Helical buckling of the production tubing, with or without the combined loss of a tubing centralizer; Crushing of the tubing by ratcheting displacement from a failed centralizer; Lateral deflection of the subsea wellhead; Collapse of the production (and/or intermediate) casing onto the tubing due to one or a combination of: Hydrate formation outside the intermediate casing due to gas migration from a shallow hydrocarbon zone, with subsequent dissolution during initial production; Non-uniform loading of the production casing due to the geometry of the sub-mudline pack-off tubing hanger; Leak of the production casing connection; Annular fluid expansion; Formation of a heat pipe in the production tubing by production casing / riser annulus; Casing wear on the intermediate casing; Excessive initial pressure resulting from setting the casing hanger seal assembly in the subsea wellhead; Inadequate performance of the tubing or casing, either due to an incorrectly run or inadequately manufactured joint.
The current installment will, by deduction from both analysis and the physical evidence, narrow the field of candidate failure modes to a small subset. The application of these results and analytical techniques as incorporated into the re-design of the subsequent completions is to be addressed in the second paper of the series1. The final paper describes the implementation of the redesign as an insulated tubing completion2.
Marlin Failure Analysis and Redesign; Part 3, VIT Completion with Real-Time Monitoring
Authors: Gosch S. W. , Horne D. J. , Pattillo P. D. , Sharp J. W. , Shah P. C. 
Published: December 2007

Abstract
Following the failure of the initial well in the Marlin field1 the preferred solution for completing the remaining wells was to control wellbore temperature via vacuum insulated tubing (VIT)2. Implementation of VIT required a number of computational and experimental innovations, including:
Provision for insulating the tubing couplings, the source of up to 90% of VIT heat loss; Detailed flow loop temperature profiles using both axial probes and radial probes traversing the annulus outside the VIT. These profiles supplemented the conventional values of overall heat transfer coefficient and thermal conductivity obtained from the flow loop measurements; VIT performance, as measured experimentally, must exceed both thermal and mechanical design bases.
As well survival depends on proper VIT performance, a distributed temperature monitoring system was developed and evaluated during full scale testing. On the Marlin TLP, fiber optic is run in each well along the length of the VIT to continuously monitor the production annulus temperature profile. A software system was also developed to take binary fiber data and feed an integrated thermal simulator-casing design software package that calculates safety factors for the B and C annuli. These real time safety factors interface with the platform alarm system and are continually monitored by operators. If a low safety factor is calculated, a well will be shut-in. In addition to feeding the platform alarm system, the software provides data to a web based plotting program. If a single joint of VIT loses its insulating properties, this specific joint can be identified and appropriate action taken. The monitoring system has also proved to be a valuable quality assurance measure for special annular gels used to minimize conduction and natural convection in the production annulus.
This paper focuses on the value of the combined VIT and fiber/software monitoring system as a means of both controlling and observing well thermal behavior. Typical temperature vs. depth curves are used to illustrate the detailed information retrieved.
Successfully Replacing Oil-Based Drilling Fluids with Water-Based Drilling Fluids: Case Study Demonstrates Value of Extensive Planning and Execution in Extended-Reach Well
Authors: Stawaisz R. , Taylor S. , Hemphill T. , Tare U. , Morton K. , Valentine T. 
Published: December 2007

Abstract
An extended-reach [ERD] well was planned and successfully drilled in Block 16/26 of the U.K. Central North Sea with water-based drilling fluid in an area where wells have historically been drilled with mineral oil-based and ester-based drilling fluids. With increasingly stringent environmental regulations, the current utilization of mineral oil-based fluids is dependent upon shipping all cuttings back to shore for processing and subsequent disposal, resulting in high supplemental costs. Additionally, potential adverse weather conditions could temporarily preventing the transfer of cuttings from the platform to a supply vessel, thereby curtailing the drilling operations and further increasing drilling costs. The operator realized that significant savings to the current overall well costs could be realized if a water-based drilling fluid system were successfully used to drill the large-diameter hole interval that produced the highest volumes of cuttings.
Expandable Sand Screen: Three New World Records in the Brigantine Field
Authors: Weekse Alex , Steve Grant , Urselmann Rob 
Published: December 2007

Abstract
Between October 2000 and March 2001, Shell Expro, operating in the UK sector of the North Sea on behalf of Shell UK Limited and ExxonMobil UK Limited set three new world records in the application of expandable tubular technology, in 6" horizontal hole. Firstly, deployment and expansion of 4000 ft of 4" Expandable Sand Screens [ESS] in Brigantine B; surpassing the previous record tenfold. Secondly, deployment of 7000 ft of 4" ESS in Brigantine A and fully expanding 4920 ft of this screen. Thirdly, using the modified Compliant Rotary Expansion System [CRES] for full primary expansion of 60 ft of the 2150 ft ESS as Proof of Concept deployed in Brigantine C.
Brigantine is a small offshore gas field located some 100 miles northeast of the Bacton Gas Terminal in the UK Southern North Sea. The field contains three small hydrocarbon-bearing blocks, deemed individually uneconomical since their discovery in 1986. However, Deliver the Limit [DtL] concept, teamwork and application of three new technologies improved the economics of these accumulations and hence another success story for Shell Expro.
The three new technologies are listed below: The Brigantine Wells were drilled from two minimum facility Trident Platforms, which had won international recognition for their revolutionary design.Geo-steering Technology was chosen to drill the long 6" horizontal sections to maximize reservoir connectivity and overcome the risk of compartmentalisation within the structures.An integrated sand study carried out confirmed the need for downhole sand exclusion. The selected option was the Expandable Sand Screen. This novel approach, developed by Shell Technology with Weatherford Completion Systems (WCS) having a licence, was preferred to conventional methods, such as ‘Gravelpack’, due primarily to the larger bore it provides to maximise deliverability and the high potential to eliminate annular flow when fully expanded against the wellbore. However, ESS Technology was in its infancy and classified internally as ‘new unproven technology’.
The three wells were completed 32 days ahead of plan, achieved initial production of between 23% and 40% above expectation with total ESS added value of £13.5 million.
The following paper documents the decision to choose ESS as the preferred Sand Exclusion Technology, and the ESS delivery process from ‘unproven technology’ to deployment and expansion in the Brigantine Wells.
Wedge Thread Tool Joints: Applications and Economics
Authors: Reynolds Harris A. , Greenip John F. 
Published: December 2007

Abstract
Series 500™ Wedge Thread™ (WT) tool joint connections were developed in 1993 for high-torque extended-reach drilling applications in the North Sea.
These non-shouldered connections offer extremely high torque limits and a small OD/ID profile for improved drilling hydraulics. The combination of features on WT tool joint connections has enabled a series of ground-breaking applications in extended reach and slim profile drilling around the world.
Recent analysis of more than 4 years worth of operational data on the Wedge Thread tool joint connection has yielded the unanticipated result that WT tool joint connections have lower average operating costs than API Numbered Connections (NC). In many cases, the marginal investment in a WT drill string has a payback of less than 2 years, independent of the special technical features of the connection such as higher torque and better hydraulics.
This paper describes the special drilling applications enabled by Wedge Thread tool joints, including considerations of drilling hydraulics, fishing, pipe running and handling, inspection and repair, and especially the concept of using one WT string to substitute for two conventional NC drilling strings.
A methodology is presented for evaluating the economics of using WT tool joints connections in everyday drilling, in lieu of API Numbered Connections.