bluuebunny/crossref_metadata_2025_split huggingface dataset:
Q&A with Lyn Arscott
Authors: Arscott Lyn , Donnelly John 
Published: February 2015

Editor's Note: In recognition of SPE's 50th anniversary this year, JPT is conducting interviews with several Society luminaries about their careers, their relationship with SPE, and the changes they have seen in the oil and gas industry and the Society over the past several decades.

How did you get involved in SPE?
As a young engineer coming into the petroleum industry, I needed to learn petroleum technology and the obvious place was SPE. I had a PhD degree in rock mechanics and I had taken a job with the Gulf Oil Research Center in Pittsburgh, Pennsylvania. For young engineers, there is no better place to learn the technology of petroleum engineering than SPE meetings and literature. It's simply a must-do.

What was your early experience with SPE like?
I began to get involved in the SPE Pittsburgh Chapter where there was a heavy involvement from the Gulf research people and a lot of representation from the natural gas sector because of all of the gas activity in that area. The meetings were exciting for me because I was young and eager to learn and I particularly enjoyed the Distinguished Lecturers. I would attend every meeting I could, and before long I was invited into the local officer rotation. About 1974, I became Chairperson of that section, and that is when I really got involved in SPE activities.

How has SPE benefited you professionally?
SPE helped me become knowledgeable about oil and gas production technology and it has kept me up to date for my whole career. Another important benefit has been networking. I have always found that the SPE community is nonconfrontational and offers a lot of mutual support. I would call an SPE member who worked for another company and expect to receive a very cordial response to any question, and I would reciprocate. People would call me and say, "I met you at an SPE meeting, and what do you know about this or that?" I have found the SPE network to be invaluable.

What did you take away from your experience as SPE President in 1988?
I joined the SPE Board of Directors as treasurer in 1984, so I had been on the board for several years before becoming President-elect. As President, I was able to travel throughout the United States and abroad, and it was then that I realized how big was the SPE global empire and how important was the role we play in the international oil and gas business. When traveling in the centrally planned economies of China and Russia, I remember the difficulty in explaining that SPE was a voluntary organization. They kept asking what part of the US government did we belong.
Technology Update: Oil-Soluble LDHI Represents New Breed of Hydrate Inhibitor
Authors: JPT staff _ 
Published: February 2015

Natural-gas hydrates may stand alone among oil and gas production problems in both the rapidity with which a severe problem can develop and the potentially catastrophic safety, environmental, and financial risks raised by worst-case scenarios.
Unlike corrosion or scale or paraffin buildup, which typically take months or years to evolve into production problems, gas-hydrate plugs have been known to form in subsea flowlines and pipelines in an hour or less. Fig. 1 depicts a gas-hydrate plug that has been removed from a production line by means of pigging. Once a hydrate plug has formed, it can take weeks or even months to dissociate it safely. Meanwhile, downtime and production losses mount day by day, and this impact can be huge, compared with other production problems. Gas hydrates are ice-like crystals composed of water and natural gas, in which methane or carbon dioxide has become trapped in hydrogen-bonded cages.
Unlike ice formed from H2O, though, gas hydrates are quite flammable and explosive. A cubic foot of gas hydrate at standard conditions contains 0.8 ft3 of water and 182 ft3 of methane. The hydrate plug can explode with a huge destructive force that may rupture subsea flowlines, damage production equipment, place workers at high risk, and endanger the ocean environment. Given these risks and the difficulty of remediating gas-hydrate plugging, most operators view prevention as their only real strategy for dealing with the problem.

Hydrate Conditions in Deep Water
Hydrates are formed thermodynamically whenever natural gas and water are present in the right combinations of low temperature and high pressure. Unlike pure ice, hydrates can form at temperatures much greater than 32 degrees Fahrenheit (°F). Hydrates have been shown to form in gas/water mixtures at temperatures of 40°F with pressure as low as 166 psi. It has been demonstrated, furthermore, that if pressures are great enough, hydrates can form in some gas/water compositions at temperatures as warm as 80°F.
The extreme temperature and pressure regimes encountered on the world's ultradeepwater exploration and development frontiers combine to create almost perfect conditions for hydrate creation. In thousands of feet of water with long subsea tiebacks, production cools rapidly as it travels through flowlines from the well to the producing facility. The farther the flowstream travels, the more it is cooled by the surrounding seawater and the greater its risk of gas-hydrate formation somewhere within the production system.
Techbits: Digital Technologies Highlighted at Conference
Authors: Moon Ted 
Published: February 2015

The energy industry is at the start of an unavoidable renaissance, driven by increased globalization of E&P, the development of a multicultural workforce, and the increased need for data on demand. This was the message of the SPE 2007 Digital Energy Conference and Exhibition, held in April in Houston. The 2-day event was organized through SPE's Gulf Coast section Digital Energy Study Group.
The conference began with a focus on current successes in implementing digital technologies in the workplace and what technology is needed going forward. Charlie Williams, Chief Scientist of Well Engineering and Production Technology, Shell International E&P, gave the first keynote address, describing how Shell has implemented digital technologies in its field operations with particular emphasis on "smart fields." An executive roundtable that followed brought together executives from operating and technology companies to discuss business drivers in the E&P community and the types of supporting technologies that have been developed to address these drivers.
The luncheon keynote was delivered by Phiroz Darukhanavala, BP Vice President and Chief Technology Officer of Digital and Communications Technology. "Knowledge, computing power, and technological evolution are exploding at such a rate that we are seeing a blurring of boundaries between the physical world and the digital world," he said. These advances are evident on the Internet and in fields such as aviation, and the oil and gas industry has been swept up in this digitization as well. "It's happening upstream and down, from the initial exploration efforts to drilling to production, refining, transportation, and out to the customer's gas tank," he said.
Darukhanavala pointed to several current examples of how digital advances affect daily operations. One is in so-called smart drilling, being able to run an analysis at the rigsite and get the results in minutes vs. having to capture mud samples, send them to a laboratory, and wait 2 to 3 days for results. Other examples include being able to quickly measure production flow rates, wirelessly monitoring the working condition of rotating equipment, and seamlessly tracking the location and movements of rail cars and other transportation vessels.
While all of this digitization has resulted in an exponential growth in the amount of information available to make informed decisions, Darukhanavala warned that it might be too much of a good thing. "With this deluge of data, the question becomes, How do we manage it and not drown in it? In my opinion, a data plug is almost as bad as a data drought, and even more expensive for the business," he said.
SPE Approves New Reserves/Resources Document
Authors: Ritter John 
Published: February 2015

In the December issue of JPT, I reported on the progress that had been made developing a revised set of reserves and resources definitions. I am now honored to announce that the 2007 SPE/World Petroleum Council (WPC)/American Association of Petroleum Geologists (AAPG)/Society of Petroleum Evaluation Engineers (SPEE) Petroleum Resources Management System (PRMS) has been approved by the SPE Board of Directors. The new system was approved previously by the respective boards of WPC, AAPG, and SPEE, and it is now posted on the spe.org website. Based on results of extensive industry review and broad consultation, PRMS represents the current consensus of the international stakeholders regarding resource evaluations.
Coordinated by the SPE Oil and Gas Reserves Committee (OGRC), the new system consolidates, builds on, and replaces guidance previously contained in the 1997 SPE/WPC Petroleum Reserves Definitions, the 2000 SPE/WPC/AAPG Petroleum Resources Classification and Definitions, and the 2001 SPE/WPC/SPEE Guidelines for the Evaluation of Petroleum Reserves and Resources. It should be noted that the last of these documents remains a critical reference tool in support of the new PRMS. The new document's Appendix A, a Glossary of Terms Used in Resources Evaluations, updates and replaces that published in 2005.

The People and the Process
By late 2004, it became increasingly clear to many users that the current guidance was not sufficiently rigorous or encompassing to meet the requirements of industry stakeholders because of advancements in technology, the international expansion of the industry, and the increasing role of unconventional resources. It was clear that revisions were required to achieve a high level of consistency in estimating resource quantities. The OGRC took the lead in the update, seeking to obtain stakeholder input to fashion a system that would meet industry needs. The primary components of that process includedDeveloping a mapping document (available on the SPE website) to identify best practices in eight other targeted definition systems, completed in December 2005.Creating eight drafts of the document, primarily within the OGRC, though with input from cosponsoring organizations, former OGRC members, and other industry professionals.Providing an extended industry review period of approximately 100 days. During this period, more than 120 letters were mailed to different stakeholder groups requesting comment, more than 30 presentations were made worldwide to provide awareness of the process, and emails were sent to individual SPE members, in addition to postings on the SPE and AAPG websites.Consolidating comments by the OGRC and drafting three additional versions of the system, leveraging advice and input from representatives of the cosponsor groups.
In all, the process took more than 2 years' time to complete, dating from the creation of OGRC Mapping and Definitions Subcommittees in December 2004.
Technology Drives Deepwater GOM Winning Streak
Authors: Parshall Joel 
Published: February 2015

The oil and gas industry appears to be on a winning streak in the deepwater Gulf of Mexico. When major newspapers in New York, Washington, Los Angeles, and other cities run lengthy articles focusing on an extended well test 175 miles offshore Louisiana, as they did last September about Chevron's Jack-2 well (Walker Ridge Block 758), then something is up. Likewise, something is up when BP discovers, as it did last August, 800 net ft of pay in 5,860 ft of water at Kaskida (Keathley Canyon Block 292). That opened an important new lane in the Lower Tertiary play. As industry consulting firm Wood MacKenzie later reported, 2006 was "an exceptional year for exploration in the deepwater Gulf of Mexico," with discoveries such as Pony (Green Canyon Block 468) by Hess and Great White West (Alaminos Canyon Block 856) by Total adding to the buzz.
The discovery rate per well drilled in 2006 climbed to more than 40 million barrels of oil equivalent, the consulting firm noted, making it the most successful year since 1999 when BP discovered Thunder Horse. Discussing U.S. production, Cambridge Energy Research Associates labeled the Lower Tertiary play "the most significant oil trend since the discovery of the Prudhoe Bay field in 1968" and said that as much as 800,000 barrels per day—11% of U.S. production—could be flowing from this reservoir in the GOM by 2012–14.
The essential driver of the success so far, and of that possibly just over the horizon, is technology that continually challenges and in so many cases finds ways to overcome steep technical obstacles that once seemed indomitable. Recent advances in seismic-acquisition techniques, for example, have brought step changes in the quality of images obtained from beneath the extensive and often thick salt canopy of the deepwater GOM, areas that not too long ago were simply avoided as virtually impossible imaging targets. Fifth-generation dynamically positioned (DP) rigs being delivered are equipped to lead drillers out to 12,000-ft waters, while synthetic mooring lines are enabling floating production facilities to cross the 8,000-ft threshold and look beyond to where the new rigs will go and the next producing floaters will follow. Innovative real-time monitoring tools are guiding drillers down some of the longest, costliest, and riskiest wellbores with the narrowest pressure-gradient windows for reaching their targets safely. And expandable pipe is enabling these drillers to meet high-risk downhole contingencies with flexible, optimized casing programs.
What follows is a look at those and other technologies, with perspectives from the people who work with them and in some cases helped develop them.
Overview: Deepwater Exploration and Production (June 2007)
Authors: Barnes John 
Published: February 2015

Offshore operators and contractors continue to accept and meet new deepwater challenges. As shown in the following articles, the apparent limits of deepwater technologies are extended every year, and new records and "firsts" are achieved to meet projects' increasingly ambitious requirements. Subjects covered this year include the first operational use of a new major equipment type, one of the first secondary-recovery projects in a deepwater environment, and two very different major deepwater projects.
The projects and technologies described in the articles entail significant risks, and some of the articles discuss the risk management strategies used. The technical and commercial success of these projects depends on accurate risk assessment, risk mitigation strategies, and the continued progressive development of cutting-edge technologies. The use of new technologies, however, does not always result in increased risks. In some cases, technologies are devised to mitigate an identified risk, as indicated in the articles' discussions of "improved reliability," "enhancements in functionality," "optimization," "standard interfaces and interchangeability," "increased data quality," "improved durability," "improved facility uptime," and other key themes.
Management of project risks is one of the most important tasks in project management. Rather than a one-off activity that is addressed only with a workshop facilitated by an outside expert and filed away, risk management should be an ongoing process that starts with project initiation and continues through the end of facility operation.
Deepwater Exploration and Production additional reading available at the OTC Library: www.otcnet.org
OTC 18768 "Polyester Mooring Lines on Platforms and MODUs in Deep Water," by John F. Flory, Tension Technology, et al.
OTC 18493 "Extreme Wave Effects on Deepwater Floating Structures," by Bas Buchner, Maritime Research Institute Netherlands, et al.
OTC 18797 "Combined Tow Method for Deepwater Pipeline and Riser Installation," by Alf Roger Hellestø, Subsea 7, et al.
OTC 18844 "Special Session: AUVs: Groundtruthing High-Resolution AUV Side-Scan-Sonar Contacts for Unexploded Ordnance in a Deepwater GeoHazard Assessment," by Lynn B. Samuel, C&C Technologies, et al.
Vibration and Rotation To Extend Coiled-Tubing Reach
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 106979, "Vibration and Rotation Considerations in Extending Coiled-Tubing Reach," by K.R. Newman, SPE, CTES, prepared for the 2007 SPE/ICoTA Coiled Tubing and Well Intervention Conference and Exhibition, The Woodlands, Texas, 20–21 March.
In recent years, there has been increased use of coiled tubing (CT) to drill shallow wells or to drill laterals from existing wellbores. Often the weight on bit (WOB) that can be applied with CT is limited as a result of friction between the CT and the wellbore, making some drilling operations impossible. Two methods proposed to reduce this friction are CT vibration and rotation. The full-length paper presents research performed to determine the effectiveness and practicality of these two means of friction reduction.

Introduction
The US Dept. of Energy (DOE) funded research in microhole drilling with CT. A portion of this funding was devoted to researching methods for mitigating downhole friction to enable CT to be used for extended-reach-drilling applications. Small-diameter CT (used for microhole drilling) helically buckles easily when in compression. Once helically buckled, additional wall-contact forces (WCFs) are caused by CT contact with the wellbore. These additional WCFs increase friction between the CT and the wellbore. This friction increases exponentially with the compressive force in the CT until no additional force can be transmitted to the bit. This situation is known as helical lockup. When the axial force reaches the helical-bucking load (HBL), the additional WCF caused by buckling far exceeds the WCF resulting from weight.
Methods To Increase WOB. Geometry Changes. Increasing CT diameter or decreasing hole diameter is an effective way to increase WOB. Increasing CT wall thickness may increase WOB, especially in vertical wells.
Lubricants. Various lubricating fluids have been used to reduce the friction coefficient between the CT and well tubulars or the wellbore. These lubricants have been somewhat successful in cased-hole workover applications. However, in drilling applications, the drilling fluid must turn the downhole motor, maintain well control, and carry the cuttings out of the hole. It is difficult to design a drilling fluid that will perform all of these functions and also provide significant lubrication.
Tractors. Downhole tractors are available for CT-drilling (CTD) applications. Tractors provide the WOB so the CT can remain in tension. However, a downhole tractor adds additional deployment logistics, risk, and expense. Currently, tractors are not available in sufficiently small diameters to perform microhole drilling.
Rollers. Various types of rollers have been developed that can be attached to the CT and to the drilling bottomhole assembly. The time and logistics associated with attaching and removing rollers make them undesirable.
Discussion/Reply of February 2007 Guest Editorial
Authors: Claridge Eldon L. , Graham Seldon B. , Hart Phil , Skrebowski Chris , Aleklett Kjell , Jackson Peter M. 
Published: February 2015

Discussion
Elmond L. Claridge, Pearland, Texas
I am a retired researcher in the enhanced-oil-recovery field (recognized by SPE as a pioneer in that field) and was Director of the Master's Degree Program in Petroleum Engineering at the University of Houston during the 1980s. I was stimulated by the Guest Editorial in your February 2007 issue by Peter M. Jackson of Cambridge Energy Research Associates (CERA) to write you concerning both issues that he addressed and those he did not address that are related to the general subject of peak oil.
In Jackson's article, he points out, as has been long known, that King Hubbert's curves for discovery and production of petroleum were based on inadequate data. It was apparent, with the discovery of the Prudhoe Bay resources plus research on methods of additional oil recovery, that his assumptions about the total initial oil in place and the fraction of this oil that could be recovered were too low. Instead of a peak in production in about 1970 as Hubbert predicted, Jackson now predicts that the peak can occur no sooner than 2030, and may well be later. Hubbert's database was too small, but the prediction of eventual exhaustion of the world's supply of produced crude oil, as he was first to point out, is still correct.
In my Introduction to Petroleum Engineering classes at the University of Houston, I had students calculate a date of the catastrophic exhaustion of petroleum production, using as base data an estimate of 6 trillion bbl of initial oil in place, of which 35% (2.1 trillion) could be recovered by primary and secondary production, plus the known world population and its exponential growth rate, and the historical rate of growth of oil products consumption per person. They calculated exhaustion dates in the 2040s. Of course, as I pointed out to the students, exhaustion would not occur catastrophically; the consumption of petroleum would decrease gradually. First would come a decrease in consumption as fuel, followed by long-term use only as a source for chemicals (plastic articles including clothing, medicines, fertilizers, etc.).
I see that Jackson's estimate of total possible production is 4.8 trillion bbl yet to be produced, plus 1.1 trillion already produced, for a total of 5.9 trillion, compared to the 2.1 trillion I used in the class exercise.
But this approximately three-fold increase in future-plus-past-production (based on better data than I had available in the 1980s) has in recent years been accompanied by a probable large increase in the per-person consumption rate due to the recent rapid industrialization of China and India with their very large populations. If new estimates of an increase in the growth rate of population and of an increase in consumption per person were included in a new calculation of the catastrophic exhaustion date, it would be very interesting to see how much further in the future this date would be than my students' calculated value.