bluuebunny/crossref_metadata_2025_split huggingface dataset:
Approaching the Technical Limit: Mature Basin Benefits from Influx of Advanced Drilling Rigs/Tool Technology
Authors: Márquez Hugo , Crovetto Marcelo 
Published: March 2011

Abstract
An operator working a mature field in southern Argentina's San Jorge Basin wanted to use the latest drilling technologies to establish a new field benchmark. The basin has been producing hydrocarbons for approximately 100 years, and most operators active in the area were reluctant to apply high-end technology to develop what the industry considered to be marginal reserves.
In spite of the economic risk, a plan was initiated in Q1 2009 to deploy new automated flexible-drilling rigs in conjunction with high-performance downhole tools designed to efficiently use the rig's increased hydraulic horsepower capabilities. Due to hole deviation problems, a reliable yet cost effective vertical drilling system was employed, because it could withstand the application's extreme flow rates, high weight on bit (WOB), and still deliver the required wellbore trajectory and superior borehole quality. The deviation control system uses a high-power positive displacement motor (PDM) and proven packed hole bottomhole assembly (BHA) design techniques.
The new tools were run on several wells in the field with outstanding results. This paper will outline the learning curve and engineering process that led to advanced performance and improvements: new-technology adaptation to the actual and aggressive drilling plans that helped the operator reduce drilling costs, delivery of a high-quality in-gauge wellbore and efficiently achieving the mandated drilling schedule.
Emergency Severance of Casing for Deepwater Operations: A Design Build and Test Programme of Novel Technologies
Authors: Richmond N. , Bamford N. J. , Bamford A. S. 
Published: March 2011

Abstract
In deep-water, emergency disconnection while running casing, is the action of last resort. It requires the casing to be sheared and the well bore sealed. In an 18-3/4" BOP cutting casing sizes of 9-5/8" and above can be difficult and may impinge on the bore of the BOP.
An Annular Cutting Tool (ACT) has been developed that can be implemented inside an API housing, spool piece or an extension to a BOP ram body. The ACT has been designed to work with conventional drill pipe blind rams. The cutting mechanism is swarf free and produces a good quality cut for later re-entry to the well.
After engineering design, a prototype tool to cut 7-5/8" casing was developed and tested. The system in its current state of design, uses a rotating plenum driven by a sealed bevel gear cartridge, with six elliptical pistons each incorporating a cutting wheel. The paper will describe the selection and testing of bearing and seals and how the drive and control system was optimised to cut the casing in less than 45 seconds required by API RP 53. The effects will be illustrated of varying system rotational speed and applied pressure to the cutting wheels.
Plans for future testing are described including; the effects of varying pipe grade, wall thickness, and casing load conditions consisting of different combinations of tension and bending.
The ACT design has to ensure that there are two physical blocks between the wellbore pressure and the external seawater environment; each of these blocks is independently tested.
Challenging Multilateral and Completion Design for a Deepwater Well in Italy: Decision Support through Risk Analysis
Authors: Repetto C. , Sanasi C. , Di Vincenzo S. , Cordeddu C. , Maccarini G. Ricci , Tufo M. , Michelez J. , Rossi N. 
Published: March 2011

Abstract
Oil and gas industry is increasingly approaching more challenging situations where it is of primarily importance to carefully assess the technical solutions to maximize productivity, to evaluate the economic worth of investment and identify all the risks and opportunities involved in the project.
A challenging subsea well is planned to be drilled and completed in a deep offshore field in the Adriatic Sea (Italy).
This project includes all the challenges and criticalities related to: deepwater wells, sour environment, gas lift wells, multilateral and intelligent wells.
The objective of the study was to provide decision support for the selection of the most suitable multilateral and completion design addressing, through a probabilistic approach, all the uncertainties regarding reservoir characteristics, well design and productivity in terms of duration and cost.
A multidisciplinary working team, including drilling and completion engineers, geologists and reservoir engineers, has been created in order to assess all the aspects of the project with its opportunities and criticalities.
Different scenarios have been compared with regards to the available technologies for multilateral and intelligent completions.
The first step of the analysis was the identification of the uncertainties (opportunities and risks) related to technical, organizational or environmental issues, successively reported in a probabilistic time and cost model.
A dedicated fault tree approach was deemed useful to focus on the combination of events leading to a potential branch loss and to calculate the associated probability.
All uncertainties were then combined with production profiles into a technical unit cost ($/bbl).
This paper describes workflow and results. The results provide the managers with a comprehensive picture of a complex issue to make the investment right decision at a given confidence level.
This should provide a guideline to engineers, geologists and managers on the risked approach for the development of complex projects.
Intergranular Cracking of Oil Field Tubular Components Resulting from the Tempering Process
Authors: Koneti Srinivasa , Gokhale Samit , Wadsworth Thomas 
Published: March 2011

Abstract
Oil country tubular components manufactured from low carbon and alloy steels often fail through brittle intergranular cracking when exposed to an environment containing aqueous H2S. Such failures promulgate the notion that detection of intergranular cracking morphology on fracture surfaces is confirmation of failure through sulfide stress cracking (SSC) or hydrogen embrittlement, even when no evidence exists for exposure to H2S or a source of nascent hydrogen. Study of intergranular cracking related failures has shown that such failures can occur not only when the component is exposed to H2S, but can also be caused by temper embrittlement due to improper heat treatment.
This paper presents case studies and lessons learned from the analysis of such failures. The paper is based on the results of metallurgical analyses performed during the investigations as well as the results of the follow up re-heat treatments performed with different heat treatment parameters and procedures. If a component fracture presents signs of intergranular cracking with no supporting evidence of environmental attack, failure resulting from temper embrittlement is a strong possibility that must be considered and investigated.
For the failures analyzed, the manufacturing and heat treatment operations performed on the component at the mill were studied. Re-heat treatment and material testing of a failed component was performed to study the temper embrittlement phenomenon. By re-heat treating the failed component, temper embrittlement of the material was removed with substantial improvement in the material properties. If the component had undergone proper heat treatment and had the properties of the re-heat treated steel initially, the failure likely would have been avoided.
The paper presents the metallurgical and analytical techniques that need to be utilized to identify the temper embrittlement mechanism. This paper also provides guidelines on traits related to alloying elements used, impurity elements, and tempering temperatures commonly associated with failures caused by temper embrittlement.
Coating Optimized for Abrasion and Fatigue Resistance for Use in Extreme Well Geometries
Authors: McCormick John E. , Le Joe , Evans Chad 
Published: March 2011

Abstract
Extreme well geometries, extended reach wells, and other applications that test the technological limitations of drill strings and tools are becoming more commonplace in the industry. A new high velocity oxy fuel (HVOF) applied tungsten carbide coating has been developed for use on performance drilling tools for these challenging applications. Tungsten carbide coatings are known for abrasion resistance and lab testing has proven this coating is also ductile.
Key benefits include reducing the risk of damage or failure of critical drilling tools and pushing the technology envelope. Extensive testing shows excellent resistance to repeated bending cycles, which leads to cracking and possibly catastrophic failures in drilling environments.
In order to develop a suitable coating for fatigue resistance, abrasion resistance and cost, several hard-facing coatings and application methods that have been continuously developed for downhole tool applications were selected for extensive lab testing. The coating hardness and the ductility of the matrix within which the tungsten carbide resides were optimized, inducing more abrasion resistance and raising the fatigue life. Rotating drilling tools now have a coating that has been identified and tested as acceptable for use in extreme well geometries.
Directional assemblies, jars, torque and drag reduction subs, and any other rotating tools susceptible to wear that are used in high dogleg environments are all potential beneficiaries of a highly reliable coating.
A test with a standard tungsten carbide HVOF hard-facing coating and application method generated cracks within the coating. These cracks did not propagate into the base metal, but it is conventionally impossible for inspectors to differentiate between cracks in the coating vs. the base metal. The decision was made to explore different methods with regard to the coating thickness, matrix ductility, application method.
Multiple coatings tested on varying sizes of tools has led to the development of a tungsten carbide coating that has withstood 10,000,000 cycles at 12 deg/100 ft, and an additional 2,000,000 cycles at 25 deg/100 ft, without the development of fatigue cracks. The test was concluded when the mounting apparatus gave out.
The coating will assist in pushing the technical envelope that restricts operators from economically reaching reservoirs in today's challenging energy environment. Main contributions are an expansion of the technology envelope and the reduction of risk related to damaged tools and failures while drilling challenging wells.
Fatigue-Based Tubular Connection Performance for a CSS Operation
Authors: Hsu S.-Y. , Searles K. H. , Aylor A. W. 
Published: March 2011

Abstract
The Cold Lake heavy oil development, located in northeast Alberta, Canada, began commercial operation in 1985 and uses a thermal recovery process called cyclic steam stimulation (CSS). During steaming and production cycles, the dilation and re-compaction that occur within the reservoir cause the overburden to deform much like the motion of flexing a thick telephone book. At weak overburden layers, shear slip plane(s) can form due to excessive shear stress. Over multiple steaming/production cycles, the cyclic flexing and associated shear slip may lead to overburden casing fatigue failures.
In this paper, a multi-scale geomechanics modeling methodology is presented to predict the onset of casing and connection failures due to CSS-induced ultra low cyclic fatigue (ULCF). The modeling methodology consists of building a global model of single or multiple pads, a next level submodel of near-well formation and cement, and a final submodel of casing and connection. To predict the ULCF life, an algorithm based on the concept of cyclic void growth is incorporated into the casing/connection submodel. It provides the capability to predict the number of steam cycles to failure using the concepts of demand (load) and capacity (resistance).
A sensitivity study of connection offset to shear slip plane suggested that fatigue life could be extended by placing the connection away from shear slip planes. A series of parametric studies were also conducted to characterize the impact of threaded connection design on fatigue life. Several design scenarios were studied including upset pin, oversized coupling, special clearance coupling, and truncated-length coupling. By selectively reducing the coupling length (truncated) or outer diameter (special clearance), the fatigue life could be prolonged. Based on these promising results, new connection design concepts are being considered for CSS operations in Cold Lake.
One Sack Rapid Mix and Pump Solution to Severe Lost Circulation
Authors: Clapper Dennis K. , Szabo Joseph J. , Spence Steven , Otto Mike , Creelman Brian , Lewis Tom G. , McGuffey Gary 
Published: March 2011

Abstract
Lost circulation events continue to plague drilling operations. Severe lost circulation can result in complete loss of the hole along with drilling equipment. When attempting to stop massive losses, rapid preparation and placement of a lost circulation treatment will improve the frequency of successful application. A fiber pill formulation has been developed to address common operational concerns that exist with current lost circulation pill procedures. The one-sack product is designed for rapid mixing and pumping with a minimum of equipment. This product does not require any activators, retarders, set time calculations, or temperature activation. Laboratory testing has demonstrated the ability of the fiber pill slurries to rapidly dewater/de-oil and form a sealing plug. Testing also indicates that the fiber product formulated as a weighted pill with barite will form a plug with measurable compressive strength. The fiber product can be used with a wide range of fluids including freshwater, brines, and base oils. The product, which meets environmental requirements for use in the Gulf of Mexico, can be rapidly mixed and pumped on location using standard rig equipment. The fiber formulation is compatible with all mud systems and is easily removed with standard solids control equipment. This new approach to control severe losses has been successfully applied in several field tests. A few of these field applications will be discussed in detail.
A Systematic Approach to Performance Drilling in Hard Rock Environments
Authors: Dykstra Mark , Schneider Barry , Mota Jose 
Published: March 2011

Abstract
The Haynesville shale gas play in North Louisiana poses a number of significant technical challenges. One of the most daunting is penetrating the hard, abrasive Hosston sandstone-shale sequence and hard Knowles limestone in the intermediate section of the overburden. The high strength and interbedded nature of these formations trigger bit and drillstring vibration that can lead to short, slow bit runs and unacceptably high cost per foot.
The operator applied a systematic Drilling Efficiency Optimization (DEO) approach encompassing well planning, well execution and post-well analysis to drive performance improvement through these formations. Optimization efforts focused on polycrystalline diamond compact (PDC) bit design, bit hydraulics, positive displacement motor (PDM) selection, soft torque rotary system (STRS) utilization, bottom hole assembly (BHA) design and active management of drilling parameters. Combined, these efforts reduced cost per foot and days per thousand feet by over 50% while drilling approximately 70 wells over a two year period.
Drilling Performance Improvement in the Haynesville Shale Play
Authors: Billa Rich , Mota Jose , Schneider Barry , Weissman Mike 
Published: March 2011

Abstract
Significant drilling performance improvement was achieved over a two year period in the HPHT Haynesville Shale Play in North Louisiana. Technical challenges include drilling through abrasive, high compressive strength formations, bottom hole temperatures exceeding 360°F, sour gas and shut-in surface pressures near 10,000 psi. The wells are horizontal with 12,500 to 14,500 ft TVD, and 16,500 to 18,500 ft MD. The application and optimization of managed pressure drilling (MPD), underbalanced drilling (UBD), hard rock drilling, casing drilling, casing design and installation procedures will be discussed.
Can Safety Improvement Increase Drilling Efficiency?
Authors: Pavel David , Boutalbi Said , Grayson Brian 
Published: March 2011

Abstract
The number one operational safety risk during the drilling and completion of a well is the risk of a kick becoming uncontrollable and the danger that can place on people, assets and environment. Another risk is the potential misdiagnosis of a kick and the ability to quickly and efficiently identify downhole anomalies. Is it a kick, or is the wellbore breathing when making a connection? Are we experiencing losses, or is the wellbore ballooning when the mud pumps are turned back on after a connection is made? If a wrong decision is made based on a misdiagnosed situation, the results can range from costing millions of dollars in nonproductive time to loss of life and rig.
There are numerous key technology elements in the industry today that can greatly mitigate these risks and create a substantially safer drilling and completion operation and environment. These elements are field-proven over 40 plus years, are readily available from many vendors and are relatively economical. Surprisingly, these elements are not used on the most critical, risk-laden and expensive wells being drilled globally. These risk-mitigating elements include such systems as rotating control devices, flow-metering technologies, automated drilling choke systems, and downhole isolation valves.
Individually these elements add incremental benefits and increase the overall safety of the drilling and completion operations. When these systems are paired or used in combination with each other to create a closed and pressurizable mud-returns system, the benefits escalate exponentially when compared to cost or perceived inconveniences of these elements.
Furthermore, when the closed-loop system is designed as such – a system – as opposed to being piecemealed together, the operational benefits of the system are maximized.
This paper describes how a few of these basic elements greatly enhance operational safety and efficiency. A closed mud-returns system will allow us to identify kicks and losses quickly and accurately, thereby minimizing risk, without sacrificing other operational elements.
Integrated Drilling Optimization and Downhole Drilling Dynamics Enables PDC Bits to Drill in the Colorado Region of the San Juan Unconventional Gas Basin
Authors: Pink Tony , Harrell Lisa , Perez Danny , Carrico John , Mackinnon Paul 
Published: March 2011

Abstract
The San Juan basin is a prolific natural gas play in northwestern New Mexico and southwestern Colorado. For more than four years, all attempts to find a poly crystalline diamond compact (PDC) solution for the northern part of the basin have been unsuccessful or uneconomic; in addition, the performance of insert bits had also reached a plateau of roughly 60 ft/hr. In order to achieve the next step change in drilling performance, it was decided that a drilling optimization process that was integrated with high speed downhole drilling dynamics was required. The optimization process required the cooperation of the client, the directional drilling company, and the optimization company. The team was challenged to find a fixed cutter solution that could drill from surface to total depth (TD) in one run and at over 100 ft/hr; these challenges thus became the project's two primary objectives.
This paper discusses how an optimization process was integrated with high speed, multiple placement, downhole drilling dynamics analysis in order to discover what was limiting the performance of fixed cutter bits. The process involved four phases - analysis, planning, execution, and evaluation - utilizing a four well project. The lessons learned from each well were then applied to the next well in the sequence. From the lessons learned, small changes were made to the drilling assembly after each well in the sequence. These changes were then analyzed on the subsequent well. On each section, the downhole drilling dynamics data was merged with surface data.
The analysis of this data demonstrated that the main limiters to drilling performance were poor weight transfer and vibration. On the fourth well in the sequence, a specially designed, six bladed fixed cutter PDC bit drilled the entire 2,858ft of the 7 7/8" section, in one run. The overall rate of penetration (ROP) including connection time, was 102 ft/hr, surpassing the goal of 100 ft/hr.
The First Successful Short-Radius Re-Entry Well in Deep Gas Drilling in Saudi Arabia
Authors: Al-Khamees Shaker , Okwa Hope , Verma Jaywant , Ganda Sukesh 
Published: March 2011

Abstract
This paper discusses the planning and execution of the first successful short-radius sidetrack in deep gas drilling in Saudi Arabia. ANDR-XYZ was sidetracked from vertical at 12,242 ft and built inclination to 90° with maximum dog leg severity recorded as 39°/100 ft. Thereafter, a 2,400 ft lateral was drilled in the Khuff-B reservoir. Total depth was revised because of deteriorating reservoir quality. The operating time was 53 days versus 60 days planned. The short-radius sidetrack was one of three options (option 3, below): Sidetracking in the 9 5/8-in. casing set in the Khuff formation. Apart from cost reasons, this option was discarded because of high Jilh pressure requiring the mud weight to be increased from 102 pcf to 152 pcf, which would create well control and directional drilling difficulties.Milling the 7-in. liner, drilling a new 8 3/8-in. hole, setting a new 7-in. liner, and then drilling a 5 7/8-in. hole across the reservoir. Apart from being time consuming and costly, this option did not reduce technical complexity since it might have exposed the 9 5/8-in. casing across the liner lap. The condition of this section could not be guaranteed because of a previous milling operation while drilling the original wellbore.Re-entering the well by sidetracking in the 7-in. liner below the 9 5/8-in. casing. This required drilling a short-radius curve in the 5 7/8-in. section and continuing drilling and geosteering the well through the reservoir. Such a high buildup rate had never been successfully achieved before at this sidetrack depth in the Khuff reservoirs in Saudi Arabia.
Several technical considerations were taken into account including the depth and type of whipstock, the length of rathole, design and analysis of the sidetrack bottomhole assembly (BHA) including torque and drag analysis, as well as overall operations strategy to achieve the well objectives. Several challenges were overcome and lessons were learned, which will be detailed in this paper.
The successful delivery of this well resulted in saving of 45 rig days compared to the other options. The well also extended the frontier of drilling and workover options and opened up avenues to reenter several wells in deep gas drilling in Saudi Arabia.