bluuebunny/crossref_metadata_2025_split huggingface dataset:
Technology Focus: Wellbore Tubulars (May 2010)
Authors: McDonough Casey 
Published: February 2015

Technology Focus
Shortly after the invention of gunpowder came the invention of the cannon. The first cannon barrels were made of paper and bamboo. Accuracy and distance requirements forced the refinement of the 13th-century cannon to the artillery guns of today. The first refinements came from incorporating different materials. The bamboo was replaced by iron. Other refinements came from shaping and treating the materials. As iron-working techniques developed, so did the cannon. Early cannons were cast with a bore, and then bores were machined. Smooth bores were replaced with rifling to further improve the accuracy of the projectile exiting the cannon. Through the centuries, material science and machining techniques were required to manage the rapidly expanding gas in a tube to propel projectiles to combat an enemy. See the parallel in our industry?
The use of different materials and techniques to combat physical and economic restraints of drilling and completing complex wellbores is the obvious theme of 36 papers reviewed for this feature. Recurring themes include applications for expandable casing, the use of unconventional tubular materials for drilling and completion operations, and combating corrosion. A majority of the articles covered extended-reach and horizontal applications. Modern drilling and completion technology depends critically on the availability of advanced materials and on tailoring these materials with a desirable set of structural and functional properties.
Many times, the use of new materials and technology solves some of the problems facing our industry. But many times, the solution is application of existing materials and technology in an innovative way. Of particular interest in my organization is tubular technology that may have merit in the vast domestic unconventional shale plays. Can different materials be used to reduce torque and drag while drilling and still provide the benefits of conventional methods? Can we squeeze more performance out of smaller rigs? And finally, can expandable casing be used to recomplete or restimulate an existing wellbore?
Wellbore Tubulars additional reading available at OnePetro: www.onepetro.org
SPE 120084 • “Effects of Friction on Post-Buckling Behavior and Axial-Load Transfer in a Horizontal Well” by Guohua Gao, SPE, University of Tulsa (now with Shell), et al.
SPE 126515 • “Influence of Relevant Parameters on Hole Cleaning and Pipe-String Erosion in Air Drilling” by Hongjun Zhu, SPE, Southwest Petroleum University, et al.
SPE 120542 • “Successful Application of Extra-Long Expandable Cased-Hole Liner Remediates Production Well” by Riyadh Al-Barghawi, Saudi Aramco, et al.
Deepwater Workover Experience With Extreme Hydrostatic Overbalance
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 134378, ’Deepwater Workover Experience With Extreme Hydrostatic Overbalance, 2002-2009’ by G. Myers, SPE, D. Cahill, SPE, P. Clay, SPE, B. Esquinance, B. Smith, SPE, and R. Zeringue, SPE, Shell E&P Co.; C. Davis, SPE, Shell International E&P; and T. Kenney, Crown Consulting, originally prepared for the 2010 SPE Annual Technical Conference and Exhibition, Florence, Italy, 19-22 September.
The full-length paper presents planning and execution details for fluid-loss control during workovers with “extreme-hydrostatic-overbalance” (EHO) conditions (i.e., between 1,500 and 4,000 psi). Actual results for several wells from three deepwater fields in the Gulf of Mexico (GOM) are included. The information is applicable to operators that face similar requirements to maintain well control throughout the workover, mitigate any damage to the installed sand control or reservoir, and complete removal of the fluid-loss barrier to re-establish production.
Introduction
For many years, the industry has dealt with large hydrostatic overbalances in a variety of ways during workovers. Onshore, operators of tight gas fields initially may pump fluid to kill the well for rig up, then add fluid intermittently during the job as required to work safely. Offshore, operators of shallow-water, higher-permeability fields may initially kill the well with seawater for rig up, then continuously feed or “let the well drink” seawater to maintain hydrostatic overbalance during the job. The full-length paper focuses on direct-vertical-access (surface tree) wells in deepwater GOM fields. These wells are characterized by high-permeability, thick sand intervals; downhole sand control; and very high fluid-loss rates after perforating or stimulation. Profitability is tied to maintaining high production rates without significant solids production. It is the combination of extreme hydrostatic overbalance, high permeability, downhole sand control, and high production potential that makes these wells so challenging. Subsea wells in deepwater GOM fields must be handled differently because of the potential for riser collapse, use of riser fill valves, and the daily cost of floating rigs.
EHO is a term used to describe conditions significantly outside the normal. It is common to execute workovers in the GOM with 200- to 300-psi hydrostatic overbalance—that is, the difference between the hydrostatic-column pressure at the perforations and the near-wellbore reservoir pressure. Depending on the reservoir-drive mechanism, workovers in later life may be executed with 300- to 800-psi hydrostatic over-balance (moderate) or 800- to 1,500-psi overbalance (high). The term EHO is used to describe wells with 1,500-psi or greater overbalance and is not a precise definition. Depending on the job, 1,200-psi hydrostatic overbalance may require similar planning. To date, jobs have been planned with overbalance approaching 4,000-psi, typically using seawater as the workover fluid.
Parque das Conchas (BC-10) - Delivering Deepwater Extended-Reach Wells in a Low-Fracture-Gradient Setting
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper OTC 20608, ’Parque das Conchas (BC-10) - Delivery of Deepwater Extended-Reach Wells in a Low-Fracture- Gradient Setting,’ by Wouter Bode, Robin Hartmann, and Andrew Kenworthy, Shell Brazil, prepared for the 2010 Offshore Technology Conference, Houston, 3-6 May. The paper has not been peer reviewed.
Delivering wells capable of high production rates and high ultimate recovery of heavy oil is a key requirement for the ultradeepwater Parque das Conchas development in Block BC-10, Campos basin, Brazil. The well design presented here achieved these objectives while confronting key challenges including the shallow reservoir and the low-fracture-gradient setting.
Introduction
Block BC-10 is approximately 120 km southeast of Vitoria off the coast of Brazil. Water depths range from 1400 to 2000 m. A total of 14 exploration and appraisal wells had been drilled at the time this paper was written. Five oil accumulations were discovered and appraised in Block BC-10. In June 2006, field-development plans were submitted for the Ostra, Abalone, Argonauta-BW, and Argonauta-ON fields. Phase 1 of the project comprised development of the first three fields. Argonauta-ON is part of Phase 2. A combination of long horizontal wells and artificial lift is required to deliver and maintain economic rates.
Phase 1 of the drilling and completion campaign began in April 2008 from the mobile drilling unit. As of December 2009, six horizontal producers and one vertical gas injector at Ostra, one deviated producer at Abalone, and two horizontal producers at Argonauta-BW had been drilled and completed.
Well Design
Well-design work commenced in 2005. The key challenges of the well design were as follows.
3D nature of the wells with the fixed subsea layout and revised subsurface horizontal entry points
Shallow reservoir below mudline and a limited pore-pressure/fracture-gradient-pressure ratio
Unconsolidated reservoir sands with highly nonuniform sands and large packages of shales
Low reservoir temperatures with high in-situ fluid viscosities
Stratigraphically complex and faulted reservoirs
Screen selection to produce safely without a full gravel pack
A production screen test of the drilling fluids to provide sufficient hole-cleaning rheology and shale inhibition while drilling the target reservoir
To deliver wells capable of high rates over a long life, the base design required long horizontal wells with sand control. It should be noted that these wells are classified as extended-reach wells because of their shallow reservoir entry.
Resistivity, Imaging-While-Drilling Tool Helps Well Placement in Chinese Tight Reservoirs
Authors: Gang Lv Zong , Run Peng Hai , Li Yang Jin , Qiang Zhang Shi , Halomoan Parlindungan Monris , Zhao Jack , Yang Liu , Ha Stephanie Chow Yuk , Denichou Jean Michel 
Published: February 2015

Technology Update
Two case studies describe the use of a new resistivity and imaging-while-drilling tool that was used to improve well placement in the Sichuan Basin of central China—a drilling environment presenting high levels of geological uncertainty. The first case involved the technology’s application in a very thin tight dolomite gas reservoir, and the second case involved the first commercial development well in the region to target a carbonate oil reservoir. In addition to assisting well placement, the technology enabled valuable information about the natural fracture network to be obtained to support the completions design.
Background
The Sichuan Basin holds the biggest gas reserves in China and is the country’s leading gas production region. The basin rests in a major compressional tectonic area, highly compressed and characterized by thrust-faulted anticlines. Modern exploration and production started in the 1950s. Most of the gas and modest quantities of oil are produced from fractured carbonate and low-permeability sand-stone reservoirs.
PetroChina Southwest Oil & Gas Company (SWOGC)—one of the biggest subsidiaries of PetroChina—operates in the basin. It has more than 100 exploration and development concessions in the region, covering a total of 180 000 km2. Natural gas reserves in place are 842.2 billion m3, with estimated recoverable reserves of 320 billion m3.
During the early phases of exploration and development, wells were drilled vertically. Horizontal wells were introduced during the 1990s to enhance production from tight reservoir plays, which include limestone, dolomite, and tight sands. Logging-while-drilling (LWD) applications used for formation evaluation and well placement typically included propagation resistivity, density/porosity measurements, and real-time density image logging.
Today, after more than 20 years of production, most of the thickest tight gas reservoirs have been intensively developed. Since 2011, PetroChina SWOGC has increasingly targeted ever thinner tight gas formations using long horizontal drilling combined with multistage hydraulic fracturing. However, several subsurface challenges needed to be overcome for these efforts to succeed, particularly because of the extensive faults and fractures in the reservoir rock.
To meet these challenges, and enhance reservoir understanding, the company has deployed advanced LWD real-time acquisition and transmission technology providing high-resolution electrical borehole images, azimuthal gamma ray, and multidepth formation resistivity measurements.
Barriers to Implementing a Real-Time Drilling Operations Strategy
Authors: Crawley Charles , Rizvi AiJaz 
Published: February 2015

Management
The digital oilfield and real-time operations continue to be the subject of a great deal of emphasis and interest. Although enormous potential has been demonstrated by a few industry bright spots, the development and adoption of the real-time centers seems to be somewhat slow and progressing at a very gradual pace.
This article is based on a survey conducted by the Real-Time Optimization Technical Interest Group (RTO TIG). In conducting this survey, the RTO TIG was interested in the progress being made toward real-time drilling operations with drilling center support. The survey was structured to isolate information about the barriers associated with moving from data acquisition to decision to action. A survey of a subset of SPE members with a drilling interest was conducted to gain an insight into these issues. Understanding where we are and the barriers in the way of where we want to go will help us focus on what must be done.
This article is based on the fifth in a series of SPE papers sponsored by the RTO TIG (see www.spe.org/groups/tigs).
The Survey
The survey was sent by email to a subset of the drilling community with representation from national oil companies (NOC), major integrated oil companies (MIOC), large independents (LI), small to medium independents (SMI), and service companies and consultants (SCC).
The survey recipients were asked to provide their perspectives regarding where along the process they were finding difficulties. In other words, where were efficiencies lost and what caused wasted effort and lost time?
The survey had two focuses:
The first focus was on the overall process of drilling a well, from the initial modeling and well planning to the actual drilling of the well and making decisions and improvements in real time. The effective use of the real-time drilling concept involves the bridging or integration of all steps in the process, including initial planning, data collection, actual drilling, continuous validation of models during the process, and making decisions and taking action based on the real-time data flow (Fig. 1). Although we expected to find snags and bumps in the road, we were pleased to learn that few respondents saw major roadblocks in the path.
The second focus of the survey was on the specific technical steps of the process and the approaches being used during these steps. We were particularly interested in the differences in approach taken by the different operators because the differences may highlight an easier path to implementation.
Unconventional Resources: Cracking the Hydrocarbon Molecules In Situ
Authors: Karanikas John M. 
Published: February 2015

R&D Grand Challenges - This is the sixth in a series of articles on the great challenges facing the oil and gas industry as outlined by the SPE Research and Development (R&D) Committee.The R&D challenges comprise broad upstream business needs: increasing recovery factors, in-situ molecular manipulation, carbon capture and sequestration, produced water management, higher resolution subsurface imaging of hydrocarbons, and the environment. The articles in this series examine each of these challenges in depth. The R&D Grand Challenges Series, comprising articles published in JPT during 2011 and 2012, is available as a collection on OnePetro (SPE-163061-JPT).
Discoveries of accumulations of light crude oil are dwindling, and known resources are increasingly concentrated in areas that are predominantly accessible by state-owned or state-affiliated energy companies. As a result, the quality of (conventional) crude oil—particularly oil sourced from non-OPEC reservoirs—has been declining. The trend is bound to accelerate as unconventional hydrocarbons such as bitumen are brought into production to satisfy the world’s energy demand, which is expected to increase by slightly less than 50% in the next 20 years.
Because the recovery and surface processing of these heavier molecules is more difficult, it is appropriate to ask whether a portion of the surface processing can be performed downhole (in situ). In fact, in the case of deeper-lying oil shale, it is the only realistic recovery option. There are three approaches by which in-situ manipulation of molecules can be accomplished: biological, chemical, and thermal. Although this article focuses on the thermal route, it should be noted that hybrid recovery methods may be more effective in satisfying the requirement to maximize economic value while minimizing water consumption, emissions, and land usage.
The oil sands of Alberta, Canada, and the oil shale deposits in Colorado contain volumes of hydrocarbons that are at least comparable to the conventional oil resources in the Middle East (Fig. 1). Extraction by open pit mining is the dominant recovery method for commercial exploitation of the oil sands and is the only commercially practiced recovery method for oil shale. However, 70% to 80% of the oil sands in Alberta are deposited at intervals that are too deep (deeper than 60 m) to mine economically, and the same holds true for the richest and thickest sections of oil shale (deeper than 1,000 ft). Ever-increasing concerns about the environmental impact of mining (soil removal, tailings ponds, etc.) provide additional incentives toward the use of in-situ recovery methods.
Overcoming Black Sea Ultradeepwater Drilling Challenges
Authors: Wilson Adam 
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper OTC 21676, ’Overcoming Black Sea Ultradeepwater Drilling Challenges,’ by Luiz A.S. Rocha, SPE, Edgard G.A. Arduino, SPE, Danilo S. Gozzi, Sandra B. Duarte, Gabriel H. Azevedo, SPE, Luis A.N. Suarez, Jose C.S. Bruno, Bruno C.M. Pereira, and Patricia O.A. Pessoa, Petrobras, prepared for the 2011 Offshore Technology Conference, Houston, 2-5 May. The paper has not been peer reviewed.
A well-management process that includes design methodology and well-execution procedures was used by Petrobras to drill its first ultradeepwater well in a remote and challenging area of the Turkish waters in the Black Sea (Fig. 1). Ranked as a well of the highest complexity level, this wildcat deepwater well faced a number of expected hazards, such as shallow gas zones, long abnormally pressurized intervals, low-fracture-pressure-gradient sections, lost-circulation zones from the presence of fractured limestone, great potential for false kicks (breathing formation and ballooning), and the possibility of gas migration into the riser. Petrobras also developed a well-classification method that takes into account several factors, including water depth, number of wells drilled in the area, and the existence of abnormally pressurized formations. The main goals of this procedure are to establish the proper well robustness (WR) and to define operations that should be used to mitigate operational problems. Despite all of these challenges, the well was executed according to its original plan, indicating that the method was applied successfully and can be repeated in other wells.
Introduction
The depletion of old oil fields has caused operators to seek new opportunities in previously unexplored areas. The challenges of these new frontiers and the high cost of drilling usually result in expensive wells. These high costs, in turn, may tempt some operators to implement dangerous cost-reduction techniques. These cuts can lead to underestimated well design, which often leads to the loss of the well and the construction of another one. Thus, the cost reduction expected at the beginning becomes, in the end, a huge and unexpected increase in costs.
This paper refers to the drilling of an ultradeepwater wildcat exploration well located in the Turkish Black Sea, in water deeper than of 2000 m (6,560 ft), that reached a final depth greater than 5000 m (16,405 ft). This well was drilled by Petrobras using the fifth-generation semisubmersible Leiv Eiriksson drilling rig, operated by Ocean Rig.
Pushing the Extended-Reach Envelope: Drilling a Record-Reach Well
Authors: Wilson Adam 
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 151046, ’Pushing the Extended-Reach Envelope at Sakhalin: An Operator's Experience Drilling a Record-Reach Well,’ by Michael W. Walker, SPE, ExxonMobil, prepared for the 2012 SPE/IADC Drilling Conference and Exhibition, San Diego, California, 6-8 March. The paper has not been peer reviewed.
Extended-reach drilling (ERD) has become a common means to access reserves economically from existing infrastructure, provide access to reserves that were previously out of reach, and reduce the environmental footprint of drilling and production facilities. ExxonMobil, as operator for the Sakhalin 1 project, recently completed drilling operations at the Odoptu field, located offshore Sakhalin Island, Russia. The Odoptu development drilled nine extended-reach wells from shore, culminating with the world-record-reach OP-11. This record-setting extended-reach well reached a total depth of 12 345-m measured depth (MD) (40,502 ft) and 1784-m true vertical depth (TVD), with 11 479 m of vertical section in 60 days with less than 1% nonproductive time.
Introduction
The Sakhalin 1 project comprises the Chayvo, Odoptu, and Arkutun Dagi fields, located off the east coast of Sakhalin Island, Russia (Fig. 1).
As of January 2011, 15 of the 20 longest-reach wells in the world had been drilled in the Sakhalin 1 project, with the Odoptu Well OP-11 surpassing the 2008 Maersk Well BD-04A in Qatar.
Because of limited exploration-drilling data from the Odoptu field, the development was designed to be performed in stages. The first stage of development was designed to ascertain drilling and production performance, thereby allowing future development operations to be optimized. Hence, the project included drilling a vertical disposal well and seven ERD wells, with two additional ERD wells added subsequently.
Following the drilling of a vertical cuttings-reinjection well, the first two ERD wells at Odoptu were designed to ascertain the height of the oil column, thereby refining the remaining drilling objectives. The first well, Well OP-8, drilled an 8½-in. pilot hole that penetrated the reservoir section horizontally in the oil column and was geosteered updip to locate the gas/oil contact, measure reservoir pressures (and determine fluid gradients), and exit the top of the reservoir again at a 99° inclination. The pilot hole was then plugged, and a horizontal production hole was drilled and completed. The second well, Well OP-7, was drilled downdip to determine the pressure and fluid gradient in the aquifer leg of the reservoir. It was subsequently sidetracked horizontally through the oil column and placed into production. Using the pressure and fluid-contact data from these two wells, the height of the oil column was deter-mined and vertical placement of subsequent wells in the reservoir sections was highgraded.