bluuebunny/crossref_metadata_2025_split huggingface dataset:
Drillable Perforating System Saves Effort and Rig Time
Authors: Ortiz Jonathan , Hinkie Ron 
Published: December 2007

Abstract
This case-history paper presents accounts of several field applications of a drillable perforating system (DPS) that has been used on 400 jobs in the Gulf of Mexico, with a near-100% success rate.
Components of the drillpipe-conveyed system are both drillable and disposable. The aluminum gun is mounted below a drillable packer. After perforating, the packer and gun can be drilled out by conventional drilling methods. There are no mobilization or demobilization charges such as those associated with use of wireline units. Because no mud system is needed for the operation, clear fluids can remain in place for workover operations. Once in place, the firing head is actuated by pump pressure applied through the tubing.
The paper describes use of the system to perforate underbalanced, perform plug-to-abandon operations, perform block squeezes, and perform other operations. The DPS can be used to cement and perforate in underbalanced conditions, limited-entry in-flow testing, cementing with clear fluids, and plugging and abandoning wells.
The paper presents results that show the DPS to be an effective alternative to conventional perforation and squeezing methods now followed in the oil and gas industry. In case histories presented, significant rig time was saved, along with savings in material and time to first sale after application. DPS offers several advantages over conventional equipment and techniques.
Clear fluids can remain in place during workover operations because no mud system is needed for well control. The DPS is a cost-effective and safe alternative to traditional methods of squeeze perforating. The DPS assembly is a one-trip perforating, packer-placement, and squeeze-cementing method that can eliminate a great amount of rig-time expense.
Enhancing Drilling Risk & Performance Management Through the Use of Probabilistic Time & Cost Estimating
Authors: Akins W. M. , Abell M. P. , Diggins E. M. 
Published: December 2007

Abstract
Not only is risk management critical to the well construction process, but in several jurisdictions around the world, a demonstrated risk management plan is a pre-requisite to doing business. One of the key elements of well risk management is a comprehensive understanding of the inherent risks at each stage of the process, their inter-relationships and the impact on project cycle time and capital cost. This paper describes a probabilistic approach to developing a drilling / completion time and cost model that can be used throughout the well construction life cycle, from project conception through operations and as a tool for project review.
The process starts with the development of a well specific sequence of operational steps. A step by step risk and hazard analysis is undertaken including examination of time and cost variances from relevant offsets, probability of occurrence of events representing both productive and non productive / problem time, and identification of possible contingency steps. The result of this analysis is a time and cost distribution for each step in the operational sequence. These distributions are input to a Monte Carlo simulator and the subsequent output includes a comprehensive time and cost probability distribution, including detailed risk information. Multi-well / campaign models can be developed by connecting a series of individual wells but with the added feature of applying appropriate learning curves and optimization measures.
This process allows for a non-biased, statistically based approach to project scoping, AFE preparation and management of capital spend through the operating phase allowing more informed decision making to occur at critical points in the project. It provides a tool which can be used to enhance senior management / asset team understanding of possible project time and cost outcomes; recognizing the inherent risks and the sensitivity of time and cost to these risks.
Extended Reach Drilling in the GOM - Ram Powell Case Study
Authors: Algu Dave , Landgrave Steve , Esquinance Bruce , Volokitin Yakov , Derise Bill 
Published: December 2007

Abstract
The Ram-Powell Unit encompasses eight OCS leases in the Viosca Knoll Area of the Eastern Gulf of Mexico.
The blocks are located approximately 125 miles east, southeast of New Orleans and approximately 80 miles south of Mobile, Alabama in water depths ranging from 2,000 to 4,000 ft. Since the drilling of the discovery well on Viosca Knoll Block 912 in May 1985, five commercial pay sands have been logged between 5,500 and 13,500 ft subsea.
This paper describes the planning and successful execution of the highly challenging A9 extended-reach well designed as the first development of the G sand interval. G sand represents the new geological play for the field as it is approximately 1,500 ft shallower than the main reservoir horizons of the field. The well was designed as a combined exploration and development project and a fast-track completion scheme was devised
The authors will discuss the design strategy, which focused on hole cleaning and the urgency of getting the casing to bottom immediately after drilling. The drilling and completion team employed a systematic approach to planning and execution of the well, which integrated both drilling and completion.
Along with detailing the planning and execution of the project, the authors also will detail the lessons learned, including the difficulty in distinguishing between borehole instability and hole cleaning problems when pulling out of the hole.
New Slimhole Technology Maximizes Productivity in Middle East Horizontal Drilling Programs
Authors: Al-Wahedi Tariq , Hay Mahmoud Abdel , Waheed Tamer , Grimes Bobby , Tyagi Sarvesh 
Published: December 2007

Abstract
Numerous operators are using advanced slimhole drilling technologies in development programs throughout the Middle East. These programs involve new and re-entry wells with long horizontal sections, typically 6" or 6-1/8" in diameter. Rollercone bits are often used in these applications because of their overall robustness, superior directional characteristics and predictable sidecutting ability. Slimhole PDC bits are run when possible, but problems with high torque, toolface control and drillstring dynamics often prevent their use. Traditionally, operators have been reluctant to attempt long runs with slimhole rollercone bits due to the potential for lost cones after undetected seal failures.
An innovative new metal sealed slimhole rollercone bit was recently developed. The downsized primary metal seal has proven its ability to significantly improve bearing life and reliability. The longevity of the new bearing has allowed operators to gain considerable confidence, which has translated into more on-bottom drilling hours and a high TD rate. The metal seal is especially useful on high speed (200 – 450 rpm) steerable motor assemblies, where elastomer seals wear at an accelerated rate.
The new bits are achieving over 1100 krevs at 80% reliability throughout the Middle East, while conventional elastomer sealed bits achieve only 600 krevs at 80% reliability in head to head comparisons. In Abu Dhabi, the new bits are used to drill out from 7" casing, then geosteer horizontally for 4000ft+ of limestone with a UCS between 5,000 psi and 15,000 psi.
The authors will document significant cost reductions through improved bit performance from several years of drilling in active fields in UAE (2003 - Aug 2004). The primary advantage of utilizing the new slimhole bit is they can drill the horizontal section in one fast run. Historically, it takes two elastomer sealed bits to complete the hole section. Reduction in drilling time due to higher ROP and elimination of tripping for a new bit has led to significant savings in rig time while minimizing formation damage by reducing the exposure of reservoir formations to drilling fluids.
Overbalanced Pre-Khuff Drilling of Horizontal Reservoir Sections with Potassium Formate Brines
Authors: Simpson M. A. , AbdRabAlreda S. H. , Al-Khamees S. A. , Zhou S. , Treece M. D. , Ansari A. A. 
Published: December 2007

Abstract
Interbedding of hard shale and sandstone sequences across the Lower Permian ‘Unayzah and Jauf formations of Saudi Arabia which usually occur between 12,900 to 14,600 ft tvd, present unique drilling fluid density requirements such that 90-102 pcf (12.0-13.6 ppg) drilling fluids are often required to mechanically stabilize the shales while only 66-89 pcf (8.8-11.9 ppg) is needed to balance the ‘Unayzah and Jauf reservoir pressures.
Review of offset wells drilled with similarly high overbalances indicated that the differential sticking forces effected drilling 5-7/8" horizontal hole with conventional KCl-polymer water based drilling fluids or halide brines weighted up with calcium carbonate can easily exceed the allowable overpull on 5" drillpipe if as little as 200 ft of high permeability virgin reservoir is traversed and drilling fluid HTHP filtrate, HTHP filter cake; bridging material particle size distribution and lubricity are not properly maintained; resulting in differentially stuck pipe, expensive fishing and or sidetracking operations.
The requirement to drill 1500 to 5000 ft horizontal sections across the pre-Khuff with 250 to 3508F BHST's which severely degrade the aforementioned fluids properties; catalyzed Saudi Aramco's search for an alternative drilling fluid which was also non-damaging to the sensitive pre-Khuff sandstone reservoirs.
Formate brine drilling & completion fluids appeared to meet all of the above criteria and were therefore selected for field trials.
This paper describes the use of a 90 pcf (12.0 ppg) sodium/potassium (Na/K) formate brine to drill a 1556 ft build to horizontal section across the ‘Unayzah-A formation at 13,900 ft tvd, with 820 psi overbalance and 2958F BHST in TINT-3, a 92 pcf (12.3 ppg) potassium (K) formate brine to drill a 1761 ft horizontal section across the Jauf formation at 14,500 ft tvd with 302°F BHST in HWYH-201 and the use of a 102-105 pcf (13.6-14.0 ppg) Na/K-formate system with calcium carbonate used as a bridging and supplementary weighting agent to drill a 1646' horizontal section across the ‘Unayzah-B formation at 13,900 ft tvd, with maximum overbalance of 1600 psi and BHST of 3238F in HRDH-658.
One of the wells exhibited greatly improved drill string/wellbore lubricity, bit performance, reduced torque and drag, ECD's and pump pressures whilst inadequate drilling fluid density masked the full benefits of formate brine use on the other two. However, differential sticking did not occur in any of the wells.
Rotating While Packed off May Cause Unexpected Heat-Induced Drill Pipe Tensile Failures
Authors: Gokhale Samit , Reynolds Nicholas , Ellis Sean 
Published: December 2007

Abstract
The amount of tensile pull that can be applied to free a stuck drill string is usually restricted by the drill string's minimum margin of overpull (MOP).1 To free a stuck string, the drill string is often rotated and pulled simultaneously. When this is done, the maximum permitted pull is reduced, depending on the amount of torque applied.
Application of pull, either based on MOP or the decreased tensile rating given the applied torque, has resulted in instances of overload failures of drill pipe. These failures have occurred at loads significantly lower than the drill strings rated capacity. In each of these failures, the formation had packed off around the string and circulation was lost.
This paper presents case studies and lessons learned from the analysis of such drill pipe failures. Metallographic examination of the failed drill pipe has revealed that the frictional forces produced while rotating the string induced sufficient heat to either locally temper the pipe or cause a phase transformation (change in grain structure) of the drill pipe material. As the material gets locally heated (often to temperatures above 1,500°F), the material hardness (and thus strength) decreases. The actual load capacity of the drill string depends on the temperatures reached downhole.
This paper discusses the factors that contribute to these failures and provides test data to support the findings. In addition, this paper presents the limitations of currently available methods used to determine the maximum allowable loads that may be applied when packed off with no circulation.
Magnolia Deepwater Development – Striving for Best in Class Drilling Performance
Authors: Reinhardt W. Randall , Williamson Roger N. , Eaton Luke F. , Actis Stephen C. 
Published: December 2007

Abstract
ConocoPhillips is developing the Magnolia field with a Tension Leg Platform (TLP) in 4674 ft of water at Garden Banks (GB) block 783 in the Gulf of Mexico (GOM), see Figure 1. The field was discovered in 1999 and appraisal wells were drilled in 2000 and 2001. The well construction strategy included drilling six additional development wells from a mobile offshore drilling unit (pre-drilling) prior to the installation of the TLP. Drilling the new wells consisted of two phases; batch setting all six wells through 20 in. casing followed by deepening the wells to total depth (TD). The wells targeted multiple zones resulting in complex, designer directional wells with 50°-60° maximum hole angles. This paper examines the application of drilling best practices that were used to deepen the wells to TD after batch-setting operations were complete1.
To minimize drilling costs while deepening the wells to TD, project goals were to eliminate trouble time; minimize combined drilling, circulating and tripping time per interval; maximize simultaneous activities; and reduce the number of trips necessary to drill the well. The goal of achieving Best-n-Class performance required detailed planning, documenting and implementing results and lessons learned, effective communications, equipment quality control, and implementation of a team environment with all the companies involved in the drilling program. The complex high angle wells required employing extended reach best practices to balance on-bottom drilling performance with the ability to effectively clean the hole to allow trouble free tripping of the bottom hole assembly (BHA), running of casing, and obtaining primary cement jobs.
The best practices discussed in this paper include changes made to improve rotary steerable reliability; simultaneous drilling and under reaming BHA design2; hole cleaning; and torque and drag monitoring. The paper will also discuss activities that reduced the number of required trips and activities that were conducted out of critical path such as moving the subsea BOP from wellhead to wellhead with an innovative bottom hole assembly (BHA), BHA run and retrieve wear bushings, subsea guidebase installation via a winch and ROV, off critical path make-up of BHA components, and drill string management.
Performance and Safety Gains with New Generation Land Rigs
Authors: Orr Alan , Tardio Juan Pablo 
Published: December 2007

Abstract
SPE-92482-PP
A fleet of 32 new-build Flex3Rigs has accumulated 55 rig years of experience as of 1 November 2004. Performance highlights to date include, but are not limited to the following:
&gt;70% of the wells have been drilled under the customers' time estimate Average well cycle times have been greatly reduced Record wells have been drilled in several areas TRIR rates have been dramatically reduced &gt;99% utilization rates Personnel retention has been much improved
These significant gains in productivity and safety are the result of:
Implementation of new technology Value by design Continuity of personnel Elimination of repetitive manual labor that can be mechanized or does not add value to the well construction process Safety by design Training Daily communication, sharing of learning and performance achievements across the rig fleet
Customers are demonstrating their support for this approach by paying premium dayrates in exchange for lower total well (drilling) costs and accelerated production.
The latest field data, including drilling curves, from the 55 rig years of experience will be used to support this.
The "learnings" from this paper may be applied by operators to make better value based decisions and by drilling contractors to evaluate strategy and new rig design alternatives.
The proposed paper adds technical knowledge by demonstrating the synergistic power of the following concepts/principles:
New technology can be successfully implemented on a large scale Creation/provision of an enhanced "working environment" greatly improves personnel safety and retention and enables field employees to achieve breakthrough results Pre-project training coupled with daily sharing of learning and performance achievements creates a progressive learning and performance environment for achieving breakthrough results.
Comparison of Formation Pressure and Mobility Data Derived During Formation Testing While Drilling with a Mud Motor with Production Data and Core Analysis
Authors: Strobel J. , Bochem M. , Doehler M. , Meister M. , Buysch A. , Pragt J. , Schrader H. 
Published: December 2007

Abstract
New tools for Formation Testing While Drilling (FTWD) were introduced to the market less than two years ago. They are used in an increasing number of wells in a wide range of operating environments. The tools are capable of performing accurate tests in the dynamic drilling environment of rotary and rotary steerable drilling. They measure formation pressure and some provide formation mobility estimations in real-time. The application expands formation testing into extended reach drilling where pipe conveyed wireline testing is of high risk. It also allows formation pressure testing in boreholes where drilling risk or hole stability exclude conventional data acquisition. During FTWD operations circulation is maintained at all times to insure wellbore integrity. This presents a challenging dynamic environment for accurate formation pressure measurements.
In this paper, the application of an FTWD tool in conjunction with a mud motor is described within an even more challenging environment, due to motor rotation and associated drillstring vibrations, as no circulation bypass valve was used. The Baker Hughes INTEQ TesTrak tool was capable of performing accurate formation pressure and mobility measurements with an overall success rate of over 80% in an extreme pressure and vibration environment. Pressure and mobility test results will be shown and compared to conventional wireline logging results from nearby wells. Mobility data, which are calculated downhole and transmitted to surface in real-time, are compared to previous well test data from neighboring wells. The FTWD mobility data showed a good match with reservoir simulation and core data, and even better agreement than the data derived from conventional wireline measurements.
In this application the FTWD tool was run in combination with a triple combo LWD suite. This allowed real-time reservoir evaluation as well as optimizing pressure point selection during on-site formation evaluation. No additional wireline logs needed to be run afterwards and the hole could be cased immediately.
Project-Specific High-Pressure Completion Tubular for ChevronTexaco's Tahiti Project
Authors: Chandler R. Brett , Hensley J. Rodney , Gonzalez Manuel E. , Muradov Andrei , Jellison Michael J. 
Published: December 2007

Abstract
This paper presents the results of a two-year comprehensive effort to design, test, manufacture and implement a high-pressure completion tubular for ChevronTexaco's Tahiti project. Several enabling technologies resulted, including the project-specific design of a premium seal, rotary shouldered connection to withstand absolute pressures up to 29,000 psi, metallurgical and heat treatment advances to permit manufacture of ultra-high strength tool joints (12.5% greater than the industry standard yield strength) and an industry first rotary shouldered connection testing program consisting of simultaneously applied internal and external pressures with temperature, bending, tension and compression loads. Field results from the completion operations are presented.
Underbalanced Coiled Tubing Drilling Update on a Successful Campaign
Authors: Pruitt Randal , Leslie Charlie , Smith Bruce , Desplain Olivier , Kavanagh Tom , Woolham Tony , Baker Allistar Law , Christou Nick , Borling Daniel 
Published: December 2007

Abstract
Located in the Emirate of Sharjah, United Arab Emirates, the Sajaa onshore gas field is a Thamama Group limestone reservoir ranging from 11,000 to 13,000 feet true vertical depth (3350 to 3960 meters). Bottomhole temperature ranges from 260 to 310 degrees Farenheight (126 to 154 Celcius) and bottomhole pressure from 1100 to 1900 psi (75 to 129 atmospheres). This paper contains lessons learned from the project to date by the various authors directly involved with this unique and highly successfull Underbalanced Coiled Tubing Drilling project.
Field Proof of the New Sliding Technology for Directional Drilling
Authors: Maidla Eric , Haci Marc , Jones Scott , Cluchey Michael , Alexander Michael , Warren Tommy 
Published: December 2007

Abstract
This work shows how sliding to make a trajectory correction can significantly improve directional drilling with a mud motor and measurement while drilling (MWD) system using a new surface only technology called Slider.
Slider deploys a small robot to interface with the trop drive control panel that automatically rocks the pipe to the right and left following a rigorous analysis of torque by a computer/software that receives the surface torque and stand pipe pressure values as feedback.
Improvements from this sliding technique included the following:
Increasing sliding rate of penetration (ROP) by more than three-fold in some cases. Reducing motor stalls to zero (sometimes seven stalls per slide were recorded for the conventional method on a slide distance that ranged from 5 ft to 15 ft). Reducing time to orient tool face by an order of magnitude. Tool face orientation was obtained in about 1½ to 2 minutes without coming off bottom, as compared to enormous difficulties while trying to do this manually for the larger horizontal departures. Providing a means to release the bottomhole assembly (BHA) when becoming differentially stuck without having to come off bottom and with minimal disturbance to the tool face. Removing the tedious work the directional driller had in "rocking" the pipe, which also reduces the risk of torque breakouts.