bluuebunny/crossref_metadata_2025_split huggingface dataset:
Seeking Ways to Make Better Diamonds by Tending to the Tiniest Details
Authors: Rassenfoss Stephen 
Published: February 2015

Diamond Drill Bits
Competition among drill-bit makers can be measured by the performance of a thin layer of industrial diamond. It is both the cutting edge of the tools, as well as the technology race among competitors seeking a competitive edge. The thumb-size cylinders made of tungsten carbide topped with a thin layer of industrial diamond are mounted in pockets in the heavy metal heads of fixed cutter bits, which have become a key product line.
The ability of these fixed cutters to efficiently grind through rock has quickly made diamond drill bits the dominant bit design, representing 80% of the footage drilled worldwide last year. That represents a rapid shift in buyer preferences in a market where bits using roller cones were once as dominant. That allowed Schlumberger’s Smith Bits to grab the largest share of a dynamic market where rivals such as Baker Hughes, National Oilwell Varco (NOV), and Halliburton see opportunities to move ahead if they can find new ways to significantly increase cutter performance.
There are many factors in determining drill-bit success, but the one that gets the most attention is narrowing the performance gap between man-made and natural diamonds. Diamond bit demand growth has tracked the marked improvement in cutters. “Compared to the cutter of 10 years ago, a cutter today is 30 times more abrasion-resistant than they were. It wears 30 times slower,” said Rob Arfele, technology discipline manager for fixed cutter drill bits at Halliburton.
Energized Fractures: Shale Revolution Revisits the Energized Fracture
Authors: Jacobs Trent 
Published: February 2015

Energized Fractures
In the years since George Mitchell’s engineers first used the cocktail of water, sand, and a small batch of chemicals called slickwater to crack open the Barnett Shale in north Texas, trillions of gallons of the low-viscosity mixture have been pumped into shale formations all over the United States and Canada. While the resulting shale revolution owes much of its success to the use of slickwater, it has come at a high cost in terms of dollars and increased public scrutiny.
In response, a growing chorus of suppliers, researchers, and service companies are on a mission to get operators working in North American shale plays to re-examine their almost exclusive use of slickwater and consider displacing large volumes of it with carbon dioxide (CO2) and nitrogen (N2).
Those in the industry pushing the change say the “energized” fracturing of horizontal wells is a proven technology that stands to improve the economics of completions and the productivity of horizontal oil and gas wells. They point to a growing body of evidence from both Canada and the US that shows energized fractures greatly reduce the amount of water and proppant required to stimulate shale formations, and have the potential to increase recovery rates substantially. Internationally, the technology could help speed up lagging unconventional shale development by alleviating water scarcity issues.
In Search of Better Reservoir Imaging Using Fiber Optic Receivers Downhole
Authors: Rassenfoss Stephen 
Published: February 2015

Seismic Receivers
After nearly 4 decades of work, Bjorn Paulsson has created a system using fiber optic seismic receivers so sensitive that he said it will be able to create much more accurate, detailed seismic images with features too small to be seen now, detect the sounds of fracturing never heard before, and stand up to temperatures exceeding 300°C and pressures of more than 30,000 psi.
But he needs USD 12 million from companies interested in using it in their wells, which is nearly equal to the financial backing he has received from the United States Department of Energy (DOE) to get to this stage.
Paulsson and the DOE’s Research Partnership to Secure Energy for America (RPSEA) were organizing a meeting in late May seeking the support of oil companies to develop a full-scale version of the system he describes as “more than an order of magnitude better than what we can do now. This is not a small step up, it is a huge step.”
The plan is to build a system that can place 200 fiber optic seismic sensors, each of which has three channels (3C) allowing it to detect the direction of incoming signals along three axes, deep in a 30,000-ft deep well. There would be a receiver every 50 ft covered by a metal housing capable of standing up to the extreme pressures found in wells in the ultradeepwater US Gulf of Mexico, and clamped tightly onto a drilling pipe that can deliver it to the end of a long horizontal well.
Technology Focus: Coiled-Tubing Applications (June 2014)
Authors: Crabtree Alex 
Published: February 2015

Technology Focus
It has been said that there is nothing new under the sun, which, if true, would imply that, in a mature industry such as ours, there is little opportunity for innovation or original thought. Another oft-quoted idiom is “to think outside the box,” which raises the questions for me of “What box?” and “Who keeps making these boxes?” Are we really in an industry that is so mature that it is devoid of new thoughts and incapable of generating new concepts to meet the challenges that we face?
I would contend not. The coiled-tubing industry has always been defined by energetic and innovative people meeting the new challenges they encounter. Today is no exception. Wells in which coiled tubing is used have become deeper, have longer horizontal sections, have higher pressures, and are less accessible because of platform and crane limitations. The recent SPE/ICoTA Coiled Tubing and Well Intervention Conference and Exhibition held in The Woodlands, Texas, showcased varied solutions, both in the exhibition hall and in the technical sessions. Innovative downhole tools; newer, stronger materials; new fluid additives; improved equipment; software improvements; and a deeper understanding of fundamental mechanics were among the many progressive steps being shared with attendees. Older techniques that had been rethought and applied to today’s issues were also presented.
Enhancing Offshore Coiled-Tubing Interventions in Difficult Weather Conditions
Authors: Carpenter Chris 
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 24693, ’Enhancing the Operational Envelope for Offshore Coiled-Tubing Interventions To Be Performed in Monsoon Season,’ by Reawat Wattanasuwankorn, Franklin Hammer, and Richard Christieson, Halliburton—Boots & Coots, and Yan Song and Nick Long, Brunei Shell Petroleum Company, prepared for the 2014 Offshore Technology Conference Asia, Kuala Lumpur, 25-28 March. The paper has not been peer reviewed. Copyright 2014 Offshore Technology Conference. Reproduced by permission.
An operator requiring an offshore coiled-tubing (CT) intervention offshore Brunei in the South China Sea encountered challenging monsoon weather conditions as well as limited and aging offshore facilities. Innovative technologies from various applications, including a full-catenary CT system, a dynamic-positioning (DP) vessel, a knuckle-boom crane, and a heave-compensated gangway, were combined to provide the operator with a successful solution for CT-intervention improvement.
Introduction
Operations were performed in the Darussalam offshore waterflood oil field. The field’s average sea depth was approximately 30 m of water, and the field was approximately 70 km northeast of Seria. A central field complex had living quarters for approximately 160 personnel, gas lift and compression facilities, and water-injection facilities. Waterflooding was a significant factor supporting the hydrocarbon-production levels, and, to increase hydrocarbon production, water-injection improvements were required.
During monsoon season, the conventional well-intervention vessel had a limited operating envelope because it was unable to hold in a rough sea position and lacked emergency-disconnect CT and hydraulics-hose systems and a compensated gangway. These limitations made safe operation impossible during monsoon season. Once the operating rate was deemed limited, stimulation (acidizing) activity was postponed, thus affecting production results. However, with new concepts of intervention, the vessel was able to continue operating during rough sea conditions safely and more efficiently.
Technology Focus: Matrix Stimulation (June 2014)
Authors: Morgenthaler Lee 
Published: February 2015

Technology Focus
Matrix stimulation encompasses pumping processes used to improve the connection between the wellbore and the reservoir. They are effective in a wide range of lithologies and have been successful in most types of completions: cased and openhole, horizontal and vertical, simple and complex, injectors and producers. Wells are matrix stimulated during completion and to remove production- or injection-induced impairment. The defining characteristic of matrix stimulation is the use of chemical systems to dissolve material in the near-wellbore region pumped at pressures below those that propagate reservoir fractures.
Chemical systems have been developed to attack carbonates (impairment and reservoir material), organic deposits, aluminosilicate minerals (fines), and sulfate scales. They have been used widely below approximately 120°C, but formulating effective systems for higher temperatures is a challenge. Carbonate dissolution is generally extremely rapid at downhole conditions. Current developments are focused on controlling this reaction either with novel organic acids or with gel systems whose rheology changes with the acid reaction. Solvents for organic deposits and sulfate scales react very slowly. The challenge is to speed up the reaction and develop treatment methods with the necessary contact time. The reaction with fines is extremely complex and can lead to precipitation of solids that are more damaging than the minerals themselves. Several promising new chemistries combining chelants and organic acids are being studied to prevent these damaging precipitates.
Placement of Stimulating Fluids in Multilayered Carbonate Reservoirs
Authors: Carpenter Chris 
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 166184, ’Achieving Optimum Placement of Stimulating Fluids in Multilayered Carbonate Reservoirs: A Novel Approach,’ by Pierre Ramondenc, SPE, Bruno Lecerf, and Philippe M.J. Tardy, SPE, Schlumberger, prepared for the 2013 SPE Annual Technical Conference and Exhibition, New Orleans, 30 September- 2 October. The paper has not been peer reviewed.
This paper presents an alternative approach to designing and executing matrix-stimulation treatments in multilayered carbonate reservoirs. The proposed workflow does not rely on damage skin by layer during the design and the execution phases of the treatment. It instead requires a step of determining where the acid must be injected, and at which rate and volume, to meet an objective function. The workflow presented here allows decoupling the questions of optimal placement of a fluid for a given well, the performance of the materials selected, and the treatment schedule considered.
Introduction
Because acid dissolves carbonate formation without damaging reactions, the main challenge in acidizing multilayered carbonate reservoirs is to achieve optimum placement of the stimulating fluid. Heterogeneities such as the inherent dual porosity, high permeability contrasts of carbonate rocks, variable extent of damage, presence of natural fractures, or existence of differential pressure between reservoir layers—which can sometimes feature very large heights or lengths—tend to affect the fluid-injection profile. The uncertainty and often limited knowledge of those various parameters usually complicate the design of carbonate-acidizing treatments, whose outcome very much depends on how well the rock and damage characteristics have been taken into account when selecting the stimulation fluids and how and where those fluids will be pumped into the formation.
Wired-Drillpipe Technology in a Deep Ultradepleted Reservoir
Authors: Carpenter Chris 
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 163501, ’Using Wired-Drillpipe Technology During Managed-Pressure-Drilling Operations To Maintain Direction Control, Constant Bottomhole Pressures, and Wellbore Integrity in a Deep, Ultradepleted Reservoir,’ by John Rasmus, SPE, Alain Dorel, Tony Azizi, Andre David, Ember Duran, Hector Lopez, Gare Aguinaga, Juan Carlos Beltran, and Antonio Ospino, Schlumberger, and Eduardo Ochoa, NOV IntelliServ, prepared for the 2013 SPE/IADC Drilling Conference and Exhibition, Amsterdam, 5-7 March.
Wells drilled with nitrified drilling fluids require a solution for the transmission of measurement-while-drilling (MWD) surveys, bidirectional communication with rotary-steerable systems (RSSs), and transmission of MWD and and logging-while-drilling (LWD) measurements of downhole temperature and annular pressure for surface choke adjustments. Results from a well recently drilled into an underpressured reservoir in southern Mexico provided an opportunity to demonstrate the applicability of wired drillpipe (WDP) to deliver the required measurements and maintain the proper directional control while keeping the well fluids under control.
Introduction
This paper describes how WDP and managed- pressure drilling (MPD) enabled an operator to drill a severely depleted reservoir with an inverse-emulsion mud mixed with nitrogen delivered through a drillpipe-injection system.
This field has a complex structure divided by a salt intrusion into northern and southern portions. Six reverse faults oriented in different directions are involved in this structure. The reservoirs are found in the Middle and Lower Cretaceous and in the Kimmeridgian-Jurassic. Initial production was from the Lower Cretaceous interval, which is now below saturation pressure. The reservoir pressure has declined dramatically, making it necessary to provide a gasified fluid system to avoid lost-circulation problems while drilling.
Waterflooding Proves Useful in Deepwater Gulf of Mexico Overpressured Turbidites
Authors: Wilson Adam 
Published: February 2015

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper OTC 24111, ’Water Injection in Deepwater, Overpressured Turbidites in the Gulf of Mexico: Past, Present, and Future,’ by X. Li and K.K. Beadall, SPE, Knowledge Reservoir; S. Duan, SPE, Chevron Corporation; and J.R. Lach, SPE, Knowledge Reservoir, prepared for the 2013 Offshore Technology Conference, Houston, 6-9 May. The paper has not been peer reviewed.
Good primary recovery, high drilling cost, and facility limitations mean water injection is not commonly used in the deepwater Gulf of Mexico. However, waterflooding can supply additional reservoir energy for producing substantial quantities of oil trapped by limited displacement drive and poor sweep efficiency. This paper is a detailed examination of Pleistocene-to-Upper- Miocene turbidite reservoirs in the deepwater Gulf of Mexico under water injection. Waterflooding strategies have proved to be highly effective in achieving good incremental oil recovery from these reservoirs.
Introduction
So far, oil and gas production in the deepwater Gulf of Mexico is mostly from Neogene (Pleistocene, Pliocene, and Upper Miocene) reservoirs. The Neogene reservoirs can be characterized broadly as overpressured, unconsolidated, and highly compacting, with high permeability and containing black undersaturated oil of medium gravity with moderate gas/ oil ratio and some aquifer support. Although waterflooding is a mature technology, few water-injection projects have been conducted in the Neogene reservoirs because they exhibit good primary recoveries, exist in high-cost offshore environments, and are relatively small. In some of these fields, a limited volume of water was injected.
Modeling, Monitoring Aid Fight Against Scale in Alkali/Surfactant/Polymer Floods
Authors: Wilson Adam 
Published: February 2015

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 165285, ’The Use of Modeling and Monitoring To Control Scale in Alberta ASP Floods,’ by Kate Hunter, SPE, Lee McInnis, SPE, and Tyler Ellis-Toddington, SPE, Husky Energy, and Scot Kerr, Baker Hughes, prepared for the 2013 SPE Enhanced Oil Recovery Conference, Kuala Lumpur, 2-4 July. The paper has not been peer reviewed.
Two alkali/surfactant/polymer (ASP) floods became operational in the Taber area of Alberta, Canada, in 2006 and 2008. Throughout the course of both projects, extreme scale deposition was observed. Scale-inhibition and -remediation strategies were developed that included a comprehensive monitoring program, chemical scale inhibition, and mechanical scale-prevention techniques. From the large amount of data gathered, models were created to predict scale severity and content and to develop specific mitigation plans.
Introduction
In southern Alberta, the Mannville B Taber South (Warner) pool was discovered in 1963 and has been under waterflood since 1967 and the Glauconite K Taber (Crowsnest) pool was discovered in 1943 and has been under waterflood since 1971.
The Warner ASP flood was the first fieldwide ASP flood in Canada and began injection in May 2006. The Crowsnest ASP flood began injection in January 2008. Both floods used a 0.75-wt% concentration of NaOH as the alkali and continue to use recycled produced water for injection.
Scale and its associated problems and mitigation strategies have evolved over the course of these projects.
Leading Our Way to Zero Harm
Authors: Veazie Bob , Knode Tom 
Published: February 2015

Guest editorial
A key theme of SPE’s 11th International Conference on Health, Safety, and the Environment in Oil and Gas Exploration and Production was how to achieve an incident-free workplace. Leadership is one of the critical elements of reaching this goal. This column explores components of effective leadership as it pertains to safety and its effect on employees.
Safety is about managing risk. Although the people who manage risk within an organization generally have “manager” titles, these are usually not the people who are injured. Consequently, to attain excellent safety levels, it is essential that all employees who are at risk of injuries be included in organizational risk-management activities.
Employees currently address risks in many ways, including performing audits of workplace conditions and writing work orders to ensure follow-up on key workplace conditions that require continuous improvement. Employee responsibilities also include collecting and using key information about near misses before an injury actually occurs. Perhaps most importantly, employees in many organizations are also asked to create a more interdependent workplace in which they watch out for one another and always act in service of one another in “moments of choice” to ensure that, when coworkers perform a behavior that puts themselves or others at risk, an intervention takes place before an injury occurs.
This growing requirement of interdependent behavior within organizations requires that employees personally develop the courage to care. It also requires them to develop the humility to care enough to receive feedback, which includes dropping defensiveness and listening to peer coaches in the interest of always working more safely. This is hard work that requires personal transformation. The achievement of this degree of personal transformation requires an increased level of leadership effectiveness of those in the management positions.
So how do managers exercise increased leadership in moving toward an employee-empowerment model essential for ownership of everyone’s safety at the appropriate levels across the entity?
Empowering Employees for Safety Excellence
World-class safety, in which all employees assume the responsibility of their own safety and the safety of those around them, arises only out of discretionary behavior. Discretionary behavior is simply a choice made by each employee every day; employees cannot be mandated to comply. It is what they do all day, every day, when no one is watching.
Because discretionary behavior is the response of employees to their experience in the workplace, managers have a great deal of influence on its occurrence. Management affects employees’ workplace experience; the more positive the experience the more discretionary behavior that the employees provide. The more negative the experience, however, the more employees will just mechanically perform their work to obtain credit for success or to avoid the consequences of failure.
Pros and Cons of Applying a Proxy Model as a Substitute for Full Reservoir Simulations
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 124815, ’Pros and Cons of Applying Proxy Models as a Substitute for Full Reservoir Simulations,’ by D.I. Zubarev, SPE, SPT Group, prepared for the 2009 SPE Annual Technical Conference and Exhibition, New Orleans, 4-7 October. The paper has not been peer reviewed.
A comparative study was made of proxy-modeling methods (also known as surrogate modeling or metamodeling) as a computationally inexpensive alternative to full numerical simulation in assisted history matching, production optimization, and forecasting. The study demonstrated the solution-space complexity for different simulation models and the applicability of the proxy models to mimic it. Focus was given to practical aspects of model construction and to limitations of which engineers should be aware.
Introduction
Recent improvements in computational hardware and software have advanced reservoir modeling. However, for many workflows in uncertainty quantification and optimization with application to reservoir simulation, the availability of computing resources is still a limiting factor.
Here, a “proxy model” is a mathematically or statistically defined function that replicates the simulation-model output for selected input parameters. Typical proxy models in reservoir simulation include the following.
Sensitivity analysis of uncertainty variables
Probabilistic forecasting and risk analysis
Conditioning a simulation model to observed data (history matching)
Field-development planning and production optimization
Proxy models, combined with design-of-experiment techniques, are used widely for sensitivity analysis. Application scenarios include the traditional one-parameter-at-a-time approach for linear-sensitivity analyses and advanced experimental designs that are capable of resolving correlation and higher-order effects. For probabilistic forecasting, proxy models are used routinely as input to a Monte Carlo sampling process. The high computational efficiency of proxy models enables exhaustive sampling rates.
This study investigated the predictive quality and computational effort required for different proxy-modeling algorithms to provide acceptable results in solving reservoir-simulation problems. Three simulation models of different complexities were selected to understand the effect of the simulation-model structure on the efficiency of the proxy-model performance. Different application workflows [i.e., history matching, production optimization, hydrocarbons initially in place (HCIIP), and oil-recovery forecasting] were used to investigate the effect of the simulation-model output-data type on the proxy-model performance.