bluuebunny/crossref_metadata_2025_split huggingface dataset:
9/11 as Avant-Garde Art?
Authors: Schechner Richard 
Published: October 2009

[The attacks of 9/11 were] the greatest work of art imaginable for the whole cosmos. Minds achieving something in an act that we couldn't even dream of in music, people rehearsing like mad for 10 years, preparing fanatically for a concert, and then dying, just imagine what happened there. You have people who are that focused on a performance and then 5,000 [sic] people are dispatched to the afterlife, in a single moment. I couldn't do that. By comparison, we composers are nothing. Artists, too, sometimes try to go beyond the limits of what is feasible and conceivable, so that we wake up, so that we open ourselves to another world. … It's a crime because those involved didn't consent. They didn't come to the “concert.” That's obvious. And no one announced that they risked losing their lives. What happened in spiritual terms, the leap out of security, out of what is usually taken for granted, out of life, that sometimes happens to a small extent in art, too, otherwise art is nothing.—Karlheinz Stockhausen (“Documentation”)Stockhausen aside, how can anyone call the 9/11 attack on the Twin Towers a work of art? Of what value is such a designation? What does calling the destruction of the Twin Towers a work of art assert about (performance) art, the authenticity of “what really happened,” and social morality during and after the first decade of the twenty-first century? To even begin to address these questions, I need to refer to the history of the avant-garde—because it has been avant-garde artists who for more than a century have called for the violent destruction of existing aesthetic, social, and political systems.
Re-design of Casing Program Due to Enhanced Shale and Salt Stability
Authors: Moroni Luigi , Denax Alain 
Published: October 2009

Abstract
The Sirte basin is one of the main producing basins in Eastern Libya. The lower cretaceous reservoirs are typically sealed with evaporite sequences; salt and anhydrite. Wellbore instability in the 8½" section can be due to the Sirte & Rachmat shales, coupled with the requirement for high mud weights to stabilize the evaporite sequences. This has led to the typical well being drilled with an 8½" hole down to the top of the reservoir and the reservoir then being drilled with a 6" hole.
The use of a High Performance Water-Based Mud (HPWBM) has allowed a change in the typical drilling practice. These two sections can now be drilled as a single 8½" section. The superior wellbore stability provided by the HPWBM has allowed the mud weight required to stabilize the shales and the evaporites to be reduced significantly. This has had two benefits-the well can be drilled as a single 8½" hole, allowing larger completions to be used, and the option to drill a sidetrack is available if the reservoir quality is poor.
This paper presents field data to demonstrate the ability of the HPWBM to change the typical drilling practice. Case histories are provided which show the evolution of the drilling practice with the introduction of the HPWBM. The performance of the mud system in these harsh environments is also demonstrated with reference to wells drilled in other parts of Libya where extremes of temperature and density are prevalent.
From Fast Track to Fast Success—J4 Small Field Development Accelerates Performance Improvement Process, Northwest Bintulu, Malaysia
Authors: Spalding Trevor , Shafei M. Syazwan B Ahmad 
Published: October 2009

Abstract
J4 project was initially an 8 well small field development. Initial well designs were of 2 dimensional trajectories, a total depth of 7000 feet and a tangent angle not exceeding 60 degrees. Average well P50 drilling authorization for expenditure was calculated at 25 days. By definition of small field, the economics of the project was under management scrutiny with positive performance expected. After drilling the first J4 well and exceeding the AFE by 25% and the eventual loss of the platform slot while drilling the second well, it was apparent that a complete step change during planning and execution was required for the success of the project.
For effective step change, the recently enhanced Performance Improvement Process (PIP) was used. PIP encompasses other performance enhancement methods providing the necessary tools to undertake problem solving in a methodical manner. Additionally, for PIP to be effective it was crucial to harness the experience, knowledge and uninterrupted contribution of the well-construction team. PIP was designed to complement the Core Workflow Process, a systematic method for well planning, well design, and well execution. Besides PIP measurement, the team would investigate the rate of return on investment made in the performance improvement process The J4 team was keen to highlight what level of investment in performance improvement was justified in the tight budgets of a small field development.
As time was limited and the third well pending an assessment and rethink of the remaining wells by way of a structured fast track approach was essential. This would be the first time PIP would be applied to accelerate change to a project in Petronas Carigali SDN.BHD (PCSB). PIP provided the structure and format to enable the team to embark on a comprehensive examination of the geological data, update the geological model, and re-design the projects remaining wells and trajectories through to their successful execution.
This paper will discuss the PIP tools, methods and practices utilized by the well construction team to successfully fast track and improve drilling performance while returning a positive return on investment for the changes made.
The Use of High-Performance Spacers for Zonal Isolation in High-Temperature High-Pressure Wells
Authors: Sarap G. D. , Sivanandan M. , Patil S. , Deshpande A. P. 
Published: October 2009

Abstract
The primary cement job is critical for a successful well completion. To achieve a successful well completion, effective and complete mud removal from the well is recommended (Ravi et al. 1992; Crook et al. 1980). Spacers and flushes are used to remove the mud from the well where cement is to be placed. As hydrocarbon resources become less accessible, operators are required to explore and produce from increasingly more difficult environments. Today, with the increasing number of HTHP wells being drilled, the design of robust yet stable spacers is becoming more critical. Various spacer fluids are available in the oil and gas industry to target effective mud removal. However, these spacers may not be suitable for HPHT wells. The performance of a spacer mainly depends on the rheology of spacer at the desired elevated temperature. In addition, a spacer should be compatible with the highly fit-for-purpose mud being used in the well. This paper compares the performance of Spacer A (advanced performance for weighted spacer) with Spacer B (previous technology weighted spacer) and Spacer C (low-cost, weighted spacer) in detail at various temperatures (80°F, 150°F, 250°F and 350°F) and their compatibility with various water-based muds (brine, clay type, and clay-free).
The new spacer is unique in that the rheology (specifically, the yield point (YP)) remains constant over a wide range of temperatures (80°F up to 350°F). Typically, the spacer YP will fluctuate as a function of temperature. The YP of the fluid plays a critical role in the displacement of mobile mud and erosion of dehydrated mud. In addition, the new spacer is designed to provide accurate and reproducible results from the laboratory to the field, which minimizes testing within the laboratory and on the rig. Lastly, the spacer can be mixed in any equipment found in the oil-field, even mix-on-the-fly applications.
Best Practices and Lessons Learned From 15 Years of Experience of Cementing HPHT Wells in Italy
Authors: Frittella F. , Babbo M. , Muffo A. I. 
Published: October 2009

Abstract
For 15 years, HPHT wells have been cemented in northern Italy, under challenging and often extreme conditions. The need to maintain zonal isolation and casing support, whilst at the same time being able to tolerate massive changes in both temperature and pressure, has led to the development of some highly innovative cement slurry systems.
Chief among the innovations introduced has been the use of manganese tetraoxide as a weighting agent, instead of the traditional hematite. Pre-blended into the mix water, rather than dry blended into the cement powder, this additive has had a massive impact on slurry quality and is now employed as "best practice" throughout the region.
Cement and silica flour remain the most important materials for insuring good and consistent properties in the slurry. Consistent quality of these materials is vital – something that has not always been maintained in the past, resulting in random slurry properties and highly intensive testing. Improved management of the source of these additives has improved the consistency of the test results and reliability of the slurries.
Slurry testing conditions should be customised to be as close as possible to the actual well conditions. In particular, selection of the appropriate consistometer test temperature ramp has proved to be particularly critical.
This paper will highlight the difficulties encountered when designing, testing and executing HPHT cementing jobs. Several cases will be examined in order to illustrate the problems encountered and their solutions.
A Practical Approach to Evaluating Directional Drilling Performance
Authors: Nkwocha Chimerebere O. 
Published: October 2009

Abstract
Earlier attempts to establish DD performance using the directional drilling difficulty Index (DDI) proposed by Oag & Williams1 is flawed and difficult to interprete. The philosophy behind the DDI relationship is based on the perception of a sample space. Thereafter a mathematical relationship between the "perceived" variables identified within the sample space was proposed. DDI can only be applied for performance benchmarking if the planned DDI can be related to the actual DDI. DDI can only be used to compare the difficulty of drilling wells from the same terrain and to similar vertical depths. Since DDI does not consider adherence to the plan to account for differences between plan and actual drilled paths it therefore does not provide much information in the way of performance monitoring or benchmarking.
Is there a need for directional drilling performance monitoring? Is it possible to isolate other methods of measuring performance such as finance or time based relationships? Are we able to demonstrate directional drilling performance in such a way it becomes possible to eliminate the impact of differences and variations in service prices, service tiers, competency of rig crew and rig capability, terrain, etc? This makes the cost based approach quite restrictive in its application in establishing a key performance indicator for directional drilling activities. Traditional methods2 for measuring performance use metrics such as cost/foot, cost/10000 metres or feet, NPT distribution, ratio of NPT-to-Exposure time for specific services, $/BOe and days on well to name but a few. Generally, the metrics are designed either as time or cost based relationships. The implication thereof is that directional drilling competency or performance is somewhat lost within the generalized approach this method requires where information is normalized into time or cost based variations. Therefore, directional drilling impact on the drilling cycle becomes a measure of how quickly the well is drilled with little or no consideration on how to get there and the impact of the tortuous part drilled on the outcome and performance of the well. This paper does not suggest the elimination of traditional methods but looks at ways of establishing a performance metric between the values 0 and1 that can be used to compare directional drilling performance whilst still capturing the essence of time and cost based relationships. Furthermore, this method becomes extremely easy to use and can be easily computed at the well site using a simple spread sheet solution as the inputs for each well can be obtained from the standard directional survey file and the daily drilling reports. The application of the results include benchmarking performance from well-to-well, across projects, contractors and fields and to understand the influence of directional driller competency and geology on the final performance indicator.
Deep Drilling Challenges in OIL's Assam Field—A Case Study
Authors: Borah K. K. , Mishra S. K. 
Published: October 2009

Abstract
Since discovery of oil in deep Eocene formation of Oil India Limited's (OIL) Assam field in 1998, OIL identified the deep Eocene target as strategically important for the future. Kopili shales are potentially serious problem in Eocene wells. These are non reactive, pressured shales. While drilling these shale sections OIL faced lot of problems such as excessive cavings leading to well washouts, frequent held up and reaming during drilling and round trips, stuck pipes, high torque, drag and hole fill up in almost all round trips. These problems led to poor hole condition, logging problem, bad cementation job, time overrun and more importantly formation damage arising out of long exposure time. OIL adopted many measures in steps and lessons learned from previous wells are implemented on the next well to overcome and improve upon the previous problems. OIL so far has introduced change in casing policy, mud system and mud weight to overcome few of its drilling problem.
Saudi Aramco RTOC, Collaborative, Safe and Effective Delivery of Wells from Start to Finish
Authors: Khudiri M. M. , Naser N. A. , AlShehry M. A. , Nassir A. A. , Mokhtar H. K. 
Published: October 2009

Abstract
The objective of this paper is to discuss Saudi Aramco's Drilling RTOC (Real-Time Operating Center) experience in developing personnel, establishing process workflow and acquiring technologies to deliver wells safely and effectively. The paper starts by describing the IT infrastructure that facilitates rapid information flow from drilling sites to the RTOC. Then it discusses the process workflow, which includes pre-drill collaborative planning, real time predictive modeling, and 24/7 monitoring services to provide accurate response to real time trends for successful management of drilling risks, and therefore reduction of nonproductive time (NPT). Finally, overall achievements of 2008-2009 and a case study of one monitored and optimized well is presented.
Meeting the Challenges of Waste Disposal in the Mainland of Russia – Successful Design and Implementation of the First Full-Scale Drilling Waste Injection Project in Western Siberia
Authors: Fetsenets Roman M. , Ovalle Adriana , Still Vic , Blyus Dmitry , Shokanov Talgat , Anokhin Viatcheslav 
Published: October 2009

Abstract
The South part of the Priobskoe field, located in Western Siberia on a flood land of the Irtysh River, is an environmentally sensitive area. Zero discharge regulations prohibit cuttings discharge and spills of liquid wastes on the surface.
Until now, the exploration and full development of such oil and gas fields was a major challenge for operating companies working in Russia as all drilling wastes including cuttings, used muds ready for be disposal, and waste waters which cannot be disposed in this sensitive area. Drilling wastes had to be transported away from the region to areas where waste disposal pits were allowed to be constructed and wastes to be stored.
The major hurdle for the drilling campaign is the cost of transportation of the vast amount of drilling waste generated from multiple rigs. Moreover, during spring or fall, such transportation is virtually impossible because of the absence of winter roads and rivers are impassable due to flooding or ice movement.
A joint effort between a major oil company in Russia and a waste management service company selected Waste Injection (WI) technology as the most efficient, economical and environmentally friendly way to handle the drilling waste in the field. Waste Injection is a relatively new waste disposal methodology used in Russia, although the first injection job on a worldwide basis was in 1991. The first Russian WI operation was successfully implemented in 2004 on offshore projects near Sakhalin Island. Since that time and until October 2008, WI had only been used on several offshore platforms. The need of a robust technology for waste management on the South Priobskoe field was the departure point for implementing WI in mainland Russia.
The following paper describes the steps taken to implement WI on land projects in Russia as the technology that allows for zero discharge, ensuring a safe and permanent drilling waste disposal performed under strict regulations and minimizing associated transportation and cost risks.
Targeting Zonal Isolation Challenges on the Strategic Szoreg UGS Project, Hungary
Authors: Urraca Martin , Balázs István 
Published: October 2009

Abstract
Based on European Union (EU) Directive 2003/55/EC and Hungarian energy regulator "Magyar Energia Hivatal" requirements, Hungary must have sufficient gas reserves to satisfy a full month's household demand. Although five commercial underground gas storage (UGS) fields were operating in Hungary by 2007, a higher rate of gas production was needed. For this reason, the Hungarian government decided to develop a new UGS field rather than to increase the capacity of the existing ones.
Because of favorable reservoir characteristics, Szoreg field was selected, and 44 wells were scheduled to be drilled in 1½ years. Tight drilling and completion schedules, the operating company's turnkey contract terms, and a fixed budget made critical the success of primary cementing jobs with fit-to-purpose systems and without the occurrence of any type of remedial work.
The drilling plan included 34 vertical or deviated wells and 10 horizontal wells, each with 3 casing strings and gravel-packed completions, with the cementing objectives to provide a top of cement to surface for every casing string. For the last cemented (reservoir) casing, the presence of two sands with a marked difference in formation pressure and separated by a shale cap of only 4 m to 7 m in length required perfect zonal isolation.
Depleted and unconsolidated formations required the use of lightweight slurries to reduce hydrostatic pressure on the formation. For further losses prevention and minimization of formation damage deep in the reservoir, engineered fiber material (EFM) was programmed in the cement slurry based on drilling events.
Furthermore, an analytical model showed that the cement sheath located between the casing and the reservoir would be exposed to injection and production cycles with high pressure and temperature differentials which demanded a cement system with sufficient flexibility to withstand the mechanical stresses and to optimize expansion to prevent microannulus creation.
Despite the technical and budgetary challenges, methodical planning, the use of new technologies, and engineered optimization resulted in a successful cementing campaign with the required zonal isolation achieved within the project budget limits.
New Generation PDC Bits Successfully Replace Impregnated Bits Resulting in Significant Performance Improvements and Savings for the Operator
Authors: Nabhani Yaqdhan , Obame-Ondo Henry , Kindi Mahmoud , Saidi Ahmed , Al-Sheriyani Moosa , Reek Edwin , Vempati Chaitanya , Cruz Marco 
Published: October 2009

Abstract
A rigorous engineering and research effort combined with targeted field testing has delivered a new generation of PDC technology. This technology is intended to be used for the most technically challenging drilling applications across the globe.
During the development of this technology, several new design features were successfully tested in Sultanate of Oman in traditional PDC applications. Once the new technologies were fully developed, an effort was made to test these PDC bits in historically non-PDC drillable applications.
One of the first applications identified for the new technology was in Field-A, Sultanate of Oman. The 8 3/8-in. section at Field-A consists of abrasive sands and hard shales of the Haushi and Haima formation groups and is typically drilled using turbines and impregnated bits.
Successful application of PDC bits in Field-A prompted a second application: Field-B. This application is drilled with the turbine/impregnated bit combination through the same formation groups. Penetration rates in Field-B are typically higher and run lengths longer.
In both applications, testing started with the first bit out-of-the-shoe using a rotary assembly. The objective was to understand the capabilities of the new technology, then apply key learnings to the next design iterations.
The authors will describe the technologies developed for the new PDC bits. These new technologies have been able to extend the typical PDC application range into harder abrasive rocks. Improvements in penetration rate of 25% to over 200% have been realized with run lengths competitive to impregnated bits resulting in substantial reduction in drilling cost. Additional cost reduction is achieved by replacing turbine with rotary. Thus far, savings of up to almost 200% have been realized in a single section compared with offsets and 11-day time savings compared to plan.
Advancement in Drilling Increases Penetration Rates in Deep, Hard, and Abrasive Formation
Authors: Gala Deepak M. , Nehus Paul , Vieira Paco 
Published: October 2009

Abstract
This paper details the modifications performed and knowledge gained in late 2007 and early 2008 while drilling three underbalanced (UB) vertical gas wells in the Travis Peak formation of the western east Texas deep Bossier play in the Amoroso field, using jointed pipe. The deep Bossier represents one of the most active onshore plays in the United States. The Travis Peak is also known as ‘tragic peak’ during conventional drilling operations because the sandstone formation is hard and abrasive in nature, leading to an extreme low rate of penetration (ROP). Performance UB drilling (UBD) technology was used to increase the ROP through the formation at depths of 9,800 ft (2,987 m) and greater. The surface and the intermediate casing intervals were drilled conventionally. The next section (8 1/2-in. hole size, using hammer and tricone bits) was drilled using UBD techniques that used straight air or membrane nitrogen (N2).
The injection rates for compressed air or membrane generated N2 ranged from 2,800 to 3,400 scfm, and the liquid rates during mist-foam drilling were 14 to 16 gpm (53 to 61 lpm). The section in the first well was drilled with three hammer bits and one tricone bit with an average ROP (including connection times) of 42 fph (13 m/h). Instantaneous ROP in the range of 350 fph (107 m/h) was observed with the hammer bits. A total of 2,378 ft (725 m) in 55.5 hr was drilled UB. During the entire UB phase, penetration rates were significantly greater than the offset records. The operator carried forward the lessons learned from the first well into the second well. A total of 2,750 ft (838 m) in 58.75 hr (using three hammer bits and one tricone bit) was achieved. Based on the second well's success, planning was initiated for the third well with additional improvements in bit design proposed. Enhanced hammer bit design, however, did not yield promising results; the decision was made to drill the section with tricone bits. A total of 3,010 ft (917 m) in 61.7 hr was drilled UB using four hammer bits and three tricone bits. Improved ROP and overall cost savings were the primary objectives for the client and were achieved.
For the rig crew, drilling with compressed air or N2 was a new experience. Rig training was conducted before the drilling phase by the service company personnel.