bluuebunny/crossref_metadata_2025_split huggingface dataset:
Emerging Frontiers: Keeping Up With Emerging Communication
Authors: Spath Jeff 
Published: February 2015

President's column
In this first article on technological frontiers, I will focus on the ways in which modern knowledge-transfer avenues are impacting the industry and, more specifically, SPE. While communication methods like social media have been in our vocabulary for years, their presence is now ubiquitous in our workplace and, more recently, on our mobile devices. Just look at how social media and mobile devices are now being used as tools to disseminate information about current events.
Beyond using the various social media methods “socially” and for news, the technologies behind the methods are changing the way we work. It is estimated that the number of social network users around the world will increase 18% from 1.47 billion in 2012 (eMarketer newsletter, 18 June 2013) to 1.73 billion this year. Granted, some of this could be posting our latest travel pictures on Facebook or tweeting about vacations, but I see engineers, particularly young professionals, or the “Sony” generation as I like to call them, writing blogs on their specific engineering issues, posting comments on The Way Ahead Facebook page, and using many other of SPE’s social media platforms.
As the use of social media has grown among our members, SPE has recognized the need to create and engage with members through social media outlets. With the evolving crew change, it is important that we reach and share with members, particularly young members—where they are and where they expect us to be. Building and maintaining social media platforms are necessary to engage with membership.
In line with SPE’s mission to collect, disseminate, and exchange technical knowledge, our social media channels serve that purpose while also allowing SPE and its members the platform to engage, share, learn, and interact with sections, chapters, companies, and industry enthusiasts from around the world. From showcasing the latest news in our flagship magazine, JPT, to highlighting student chapters, to what one can expect at an upcoming event, to who will be instructing training courses, SPE’s social media channels are designed to communicate all things SPE.
SPE Social Media
Our social media channels are varied, with each serving a different purpose. Facebook is the hub, where SPE activities are shared directly with more than 32,000 connections. With a following consisting predominantly of university students and young professionals, a recent Facebook posting about why people chose a career in the oil and gas industry sparked a lot of comments about the great benefits of working in the industry. The post was viewed by more than 11,000 people. At a time when the industry is in need of talented young people, it is exchanges like this that will help communicate the benefits of the industry and reach the level of human resources needed to meet future demand.
Degradable Frac Ball Holds Solution to Persistent Problem in Fracturing
Authors: Aviles Isaac , Dardis Michael , Marya Manuel 
Published: February 2015

Technology Update
A highly efficient and popular technique for multistage fracturing involves placing a completion string in the open hole with a series of ball-actuated stages isolated by hydraulically set or swellable packers. This practice has been instrumental to the increase of activity in hydrocarbon-bearing reservoirs, as it allows continuous operation while performing a large number of stimulation treatments.
When using this technique, sections of the reservoir can be selectively accessed by pumping actuators, or frac balls, from surface that land on correspondingly sized seats that have progressively larger diameters as operations advance from toe to heel. When all stages have been treated, the well is allowed to flow back, flushing the balls back to surface where they are caught in a ball trap.
Despite more than a quarter of a million stages that have been treated using the sliding sleeve technique, the results are not always up to expectation. Operators have experienced sub-optimal production from wells in which logs and tests indicated high productivity. In searching for a root cause, it has been discovered that often not all balls are recovered. Further investigation has sometimes found that balls may have deformed and become jammed in their seats, plugging all production from beneath. The only solution is to trip into the well and mill out the seats.
Aside from the added cost and risk, the challenge is that this undesirable situation is difficult to identify because other reservoir problems that milling will not solve can present a similar production profile. This adds uncertainty to any decision to mill out the system.
Frac balls are typically made from phenolic or composite materials. The composite material is laminated and, depending upon the orientation of the laminar planes, it can fracture when it seats and is subjected to additional hydraulic pressure during fracturing operations. If the ball fractures before it has served its purpose, the entire job may be jeopardized. Both types of balls are subject to deformation, often referred to as egging, when under pressure (Fig. 1). Slight egging can cause the ball to stick in the upper seats when the well is put on production, or the ball can jam itself into the seat so tightly that the only way to remove it is by milling. A stuck or jammed frac ball acts as a permanent isolation point for all treated stages below it.
Improved Matrix Body Design: Five Factors to Achieve Exceptional Bit Performance in Hard, Abrasive Rock
Authors: JPT staff _ 
Published: February 2015

Young Technology Showcase
Matrix body bits are known for longevity and reliability in challenging formations such as granite, chert, and abrasive sandstones and conglomerates. What is often missing from bit performance under these conditions is the ability to maintain a relatively high rate of penetration (ROP) while maximizing footage drilled in one run. The goal remains the same: Drill every interval in one run at the optimal ROP. In other words, the bit should not be the limiter when it comes to drilling performance.
Focusing on five key factors that contribute to ROP and longevity, a major bit supplier has designed a matrix body fixed-cutter bit that is setting records in a wide range of fields and formations. The whole is greater than the sum of the parts: The five new technologies comprising the design work to create a significantly higher standard of performance than is typically accepted for hard rock/abrasive rock drilling.
The examples following represent distinct formation types such as sand and shale intervals in the Rockies, limestone and sandstone in east Texas, the Granite Wash formation in the Texas Panhandle, and limestone and dolomite in the Permian Basin. All of these examples are laden with transition zones and most include conglomerate or other challenges to impact and abrasion resistance. The bits have been run in conventional and motor applications with equally good outcomes.
Five Performance Factors Cutters. A critical improvement to the new bit design is the polycrystalline diamond compact (PDC) cutter technology. The proprietary interface design of the cutters used provides an extremely durable and efficient cutting element, removing significantly more rock with substantially less wear.
Furthermore, increased abrasion resistance in PDC cutters also increases the ability to withstand intense heat situations, contributing to thermal stability. While both thermally stable bits and abrasion-resistant bits perform similarly at the start of drilling, as cutter wear begins, the thermally stable products wear more slowly.
Ongoing research into wear mechanisms has optimized abrasion and impact resistance, and advanced the vital performance criterion of thermal mechanical integrity (TMI), or resistance to heat-generated wear. With greater TMI, the new cutters are highly TMI-qualified, able to withstand the extreme temperature cycling that occurs during drilling to provide greater strength and durability.
George P. Mitchell and the Barnett Shale
Authors: Steward Dan B. 
Published: February 2015

Mitchell and the Barnett Shale
George P. Mitchell died on 26 July 2013 at the age of 94. He left behind a multifaceted legacy that testified to his entrepreneurship, philanthropy, and love of country. Within the oil and gas community, this legacy focused on his work to prove up the Barnett shale unconventional gas resource, which established him as the “Father of the Shale Gas Revolution.” Through his vision, perseverance, and commitment, the knowledge base and application of existing and new technologies not only revolutionized the search for shale gas, but also carried over into tight oil and gas reservoirs, changing the global outlook for both.
Beginnings: Getting Into the Gas Business
George Mitchell entered the oil and gas industry through the encouragement and tutelage of his older brother Johnny. After graduating from Texas A&M University in 1940, earning a degree in petroleum engineering with an emphasis in geology, Mitchell served in the Army Corps of Engineers during World War II. He began working with his brother on oil prospects while still a member of the Army Corps. He and Johnny established their first company, Oil Drilling Inc., in the late 1940s, with George generating drilling prospects and his brother finding investors.
Ellison Miles, an acquaintance of George’s from his time at A&M, started a drilling company in north Texas after leaving the Army. He and business associate, John A. Jackson, became aware of the potential for a large stratigraphic gas accumulation in Pennsylvanian-age Atoka conglomerates in the Fort Worth basin of Texas and communicated their thoughts to George. Oil Drilling put together the necessary money and took their first lease in the Fort Worth basin, a 3,000-acre tract in southwest Wise County.
In 1952, George Mitchell’s journey to the Barnett began with the drilling of the first well on this lease, the D.J. Hughes No. 1. The well encountered multiple members of productive conglomerates and was completed as a shut-in gas well. According to Kutchin (2001), within 90 days of this discovery, Oil Drilling acquired 300,000 acres in the north Texas area. Subsequent test and re-entry of previously plugged wells confirmed the significance of the find.
SPE Liquids-Rich Basins Conference: New Technology for Old Plays
Authors: Beckwith Robin 
Published: February 2015

Conference review
SPE’s recent Liquids-Rich Basins Conference rewarded attendees with far-reaching insight into how to economically exploit liquids-rich plays. Based on the theme “New Technology for Old Plays,” SPE held the conference in Midland, Texas, from 11 to 12 September. The 29 speakers explored a wide range of topics and points of view from macro to detailed perspectives, centered on strategic thinking; current understanding of reservoir characteristics; proper application of completion, stimulation, and production techniques and tactics; and case histories.
This is the third year the conference has been presented. Almost 300 attendees gathered at the Midland Convention Center to listen to four technical sessions—each with three speakers—each day; interact with four Knowledge-Sharing Poster speakers who presented during four half-hour breaks; hear a keynote speaker at Thursday’s luncheon; and investigate the offerings of more than 20 exhibitors.
Two training courses were also given—a 2-day course Monday and Tuesday, 9 and 10 September, titled “Modern Production Data Analysis for Unconventional Reservoirs”; and a 1-day course Friday, 13 September, titled “An Overview of Microseismic Imaging of Hydraulic Fracturing.”
Thinking Strategically
The first session highlighted commercial and financial interests in oil resource plays and price pressures imposed by limited transportation in the areas of rapid development.
Crude and Liquids Growth in the US. Dave Pursell, managing director of Tudor Pickering Holt, kicked off the conference with his presentation, “US Crude Oil Production Growth and the Impact on Price Differentials… or Get Me off This Rock!” “‘Liquids-rich’ is my least favorite term,” he said. “It’s as accurate as calling a dog a non-cat.”
Basically, he said further, what people are talking about is natural-gas liquids (NGLs): “If it’s crude, they’re going to say it.”
When considering the question of why Brent crude is at USD 110/bbl, he said, “Risk premium is the last possible answer before the shoulder shrug.” He assured the audience that global crude fundamentals are fine, with crude inventories pointing to a balanced global market and global refined inventories below 10-year norms.
The big story is taking place in the US. While US crude production has grown from around 7 million B/D in 2005 to around 9 million B/D in 2012, non-US, non-Organization of Petroleum Exporting Countries’ (OPEC) crude production during the same period has remained fairly stagnant at around 44 million B/D. Organisation for Economic Cooperation and Development (OECD) countries’ demand, which hovered at around 50 million B/D from 2000 to 2007, has tapered down to around 46 million B/D in 2012 and non-OECD demand has grown precipitously from less than 30 million B/D in 2000 to close to 45 million B/D in 2012.
Novel, Thermally Stable Fluid-Loss Pill Performs Better Than Guar-Based Gels
Authors: Wilson Adam 
Published: February 2015

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 165096, ’Performance and Formation-Damage Assessment of a Novel, Thermally Stable Solids-Free Fluid-Loss Gel,’ by Pubudu Gamage, Jay P. Deville, SPE, and Bill Shumway, SPE, Halliburton, prepared for the 2013 SPE European Formation Damage Conference and Exhibition, Noordwijk, The Netherlands, 5-7 June. The paper has not been peer reviewed.
A novel solids-free fluid-loss pill for higher-temperature reservoirs has been formulated. This pill can be used effectively in reservoirs with temperatures up to 350°F. Static thermal aging at 320°F demonstrated no noticeable loss of gel strength for at least 20 days. With regard to thermal stability and fluid loss, the synthetic-polymer-based gel outperforms guar-/borate-based gels tested under similar conditions.
Introduction
High downhole temperatures put a strain not only on equipment but also on the complex chemistry of drilling muds, drill-in fluids, and viscous pills. Some conventional materials, such as polysaccharide gums and sodium tetraborate crosslinking agents, are demonstrably unstable or simply rendered useless under high thermal loads for extended periods. This paper describes the development of a material for one such challenge—replacement of biopolymer-based gels for high-temperature applications. Research produced a novel, workable aqueous monovalent brine-based gel derived from a synthetic water-soluble polymer. The gel, which can be used for a variety of downhole applications including well kills, perforations, and other fluid-loss applications, is thermally stable and can be applied at temperatures up to 350°F, conditions where both polysaccharides and borate crosslinking begin to fail.
The gel was specifically developed to be used in a 320°F gas reservoir. Gas regained permeability was used to assess any formation-damage issues of the gel in downhole applications. However, leakage of brine into the core during the hold-off period alters the water saturation of the core, adding complication in the regained permeability experiments because of water blockage.
Experimental Section
Gel Formulation. Gel was formulated with a high-density brine solution of a synthetic water-soluble polymer and a metal-based crosslinker. Further additives include pH buffers to lower the pH to an appropriate range for crosslinking to occur (pH of 4 to 5) and thermal stabilizers to mitigate gel decomposition by radical reactions and other processes. Concentration of polymer, the polymer/crosslinker ratio, and the pH of the formulation were tuned carefully to provide optimized gelling and fluid-loss properties. The formulations presented in this paper were based on 10.0-lbm/gal brine prepared by diluting stock 12.5-lbm/gal NaBr brine with water.
Impact of Liquid Loading in Hydraulic Fractures on Well Productivity
Authors: Carpenter Chris 
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 163837, ’Impact of Liquid Loading in Hydraulic Fractures on Well Productivity,’ by Samarth Agrawal and Mukul M. Sharma, SPE, The University of Texas at Austin, prepared for the 2013 SPE Hydraulic Fracturing Technology Conference, The Woodlands, Texas, USA, 4-6 February. The paper has not been peer reviewed.
One of the major challenges in fracturing low-permeability gas formations is the loss of well productivity caused by fluid entrapment in the matrix or fracture. Studies have suggested that this water is trapped in the rock matrix near the fracture face and remains trapped because of the high capillary pressure in the matrix. This study shows that, in regard to hydraulic fractures in horizontal wells, the fluid may also be trapped within the fracture itself and may affect the cleanup as well as productivity.
Introduction
The loss of fracturing fluid and its impact on the productivity of hydraulically fractured wells have been studied for many years. Conventional wisdom suggests that the liquid is trapped at the fracture face because of capillary effects. This reduces the relative permeability of the hydrocarbon phase during flowback. Most studies published thus far on the subject ignored the accumulation of liquid in the fracture itself and the effect of gravity and fluid segregation in the fracture. In this study, we show that liquid accumulation in the fracture itself can be significant and that this fluid saturation is coupled with the fluid saturation in the matrix, leading to a very different cleanup profile and time scale for cleanup. A 3D reservoir simulator was used to investigate liquid loading in hydraulic fractures in a horizontal well. Generally, hydraulic fractures in horizontal wells range from tens to hundreds of feet in height. If liquid loading takes place in a certain section of the fracture, it will impair the flow of gas there. This will lead to a reduction in the effective producing fracture area, even if the drawdown is greater than the capillary pressure.
Liquid Loading Inside the Fracture. The desired lift velocity for unloading liquid and the available gas velocity in a fracture differ by almost two orders of magnitude. It is, therefore, very like-ly that the lower portions of fractures will be filled with liquid when production is initiated. This suggests that concerning load recovery from hydraulically fractured horizontal wells, even if the drawdown is able to overcome the capillary pressures, the inflow gas velocity may not be high enough to lift the liquid against gravity into the wellbore (Fig. 1). Liquid loaded inside the fracture in this way will affect the productivity of the well and the cleanup of the matrix. Understanding the conditions for liquid loading within the fracture will help identify remedial measures, which may be significantly different from remedial measures for reducing liquid blocking at the fracture face.
Reducing Intervention in Subsea Wells With Fiber-Optic Technology
Authors: Carpenter Chris 
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 23929, ’Reducing Intervention in Subsea Wells With Fiber-Optic Technology,’ by John Lovell, Schlumberger, prepared for the 2013 Offshore Technology Conference, Houston, 6-9 May. The paper has not been peer reviewed.
Fiber-optic-system installations have reduced the need for intervention by logging tools and have given crucial insights into wellbore integrity and reservoir production. Consequently, a prime application of fiber technology should be in deepwater fields, where intervention can be prohibitively expensive. The reluctance to incorporate downhole fiber appears to be caused by limitations of technology relating to cables, deployment, acquisition, and interfacing. These barriers are slowly being eliminated, and a small number of subsea wells have now been implemented with in-well fiber.
Introduction
Permanently installed fiber-optic systems have been commercially available in the oil field since the early 1990s, with the bulk of the deployments providing fiber-optic distributed temperature based upon Raman backscattering. This Raman distributed-temperature-sensing (DTS) measurement system provides continuous data along the length of the completion without the need for intervention and without introducing restrictions in the inner diameter of the completion tubulars, restrictions that could impede subsequent wellbore access. Typical DTS spatial resolution is better than one data point per meter, with a temperature resolution of 0.01°C. Applications of the distributed-temperature data have included calculating flow contributions across the sandface, evaluating water-injection profiles, diagnosing the effectiveness of fracture jobs, finding cement tops behind casing, and identifying crossflow between producing zones.
The growth of fiber installations for dry-tree (land and platform) applications is increasing exponentially. More than 1,200 installations have been deployed by one service company alone. Most of those installations were single-stage completions, often for thermal or steam-assisted-gravity-drainage (SAGD) application, and relied upon the ability to pump fiber along a control line to convey the sensing fiber. Approximately 20 of those wells have fiber pumped along the sandface of dual-stage openhole-gravel-pack (OHGP) completions.
A significant advantage of the pumped fiber was that, if the fiber degraded over time, it could be pumped out and replaced. This was particularly important before the discovery of how to construct fibers with some immunity to darkening from H+ and OH− ions. With hydrogen resistance came the possibility of increased longevity for fixed-fiber cables, and, since 2006, an alternative to pumped fiber has been available that combines multiple hydrogen-resistant fibers with an electronic line to create a hybrid cable (Fig. 1). This cable can power high-accuracy quartz gauges and can also give the benefits of fully distributed Raman DTS. More than 60 such systems have been deployed to date.