bluuebunny/crossref_metadata_2025_split huggingface dataset:
Offshore Oil and Gas Installation - Aging and Life Extension
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 146225, ’Aging and Life Extension of Offshore Oil and Gas Installations,’ by Iain Wright, ABB Engineering Services, prepared for the 2011 SPE Offshore Europe Oil and Gas Conference and Exhibition, Aberdeen, 6-8 September. The paper has not been peer reviewed.
More than half of the offshore oil and gas installations in the UK Sector of the North Sea have been operating for at least 20 years. Most assets are approaching or operating beyond their original design intent. With the rise in oil and gas prices and advances in technology, there is an increasing requirement to extend the operational life of these assets. Safety-case regulations were modified to include a technical justification for extended operation, and the UK Health & Safety Executive (HSE) launched Key Programme 4 (KP4) to ensure that all duty holders have suitable management systems in place to address aging-related issues adequately.
Introduction
Coupled with the age is that most installations have encountered considerable changes in the composition of the well fluids over the life of the field and that there is an increasing trend for additional subsea tiebacks. All of these issues have raised concerns regarding the integrity and fitness for purpose of the structures and equipment for this extended life. This study aimed to answer key questions relating to aging and life extension.
Aging and Life Extension
According to HSE Research Report RR509—The Plant Ageing Guide, “Ageing is not about how old the equipment is. It’s about what is known about its condition, and how that’s changing over time.” This definition is illustrated in Fig. 1.
During the initial operation phase, design faults, installation issues, commissioning issues, or early-life operating faults are realized. Once equipment is in the mature stage, it generally is operating well within design limits, routine inspection and maintenance are being undertaken, and, in general, there is slow degradation. During the aging stage, the design limits for the equipment are approached, process changes usually have taken place, frequent repairs are required, and the overall degradation rate increases. In the end-of-life stage, the safe operating limits for the equipment are approaching, advanced inspection techniques are required at closer intervals to determine fitness for purpose, major repairs are required, and there is accelerating deterioration. The key to longer-term reliability and safety is to establish effective management systems early on to prolong the mature stage, because starting at later stages requires considerably more effort and cost.
Performance, Operability, and Risk Assessment of the Shtokman Floating Platform in Ice
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper OTC 22100, ’Approach to Performance, Operability, and Risk Assessment of the Shtokman Floating Platform in Ice,’ by Pavel Liferov, Guillaume Le Marechal, Marc-Marie Albertini, Michel Metge, and Erik ter Brake, Shtokman Development A.G., prepared for the 2011 Arctic Technology Conference, Houston, 7-9 February 2011. The paper has not been peer reviewed. Copyright 2011 Offshore Technology Conference. Reproduced by permission.
The Shtokman gas/condensate field (SGCF) is 610 km from Murmansk, Russia, in the Barents Sea. The water depth is approximately 340 m. The offshore facilities of the SGCF Phase-1 development will include an ice-resistant ship-shaped disconnectable-turret-moored floating platform (FP). Significant sea-ice invasions occur at Shtokman approximately 3 out of every 10 years. Icebergs also may occur in the SGCF area. Ice and iceberg management is planned to support the FP operations. The performance, operability, and risk of the FP in waters where occasional invasion of sea and glacial ice is anticipated were assessed.
Introduction
The main challenge was to achieve an appropriate reliability level at acceptable costs, while minimizing operational downtime. The main ice-related challenges identified in the prefront-end engineering and design (FEED) and updated during the FEED included FP loss of station keeping because of actions from sea ice, FP loss of station keeping because of actions from icebergs, and underhull ice interaction in the riser-connection area.
It was decided early on to establish challenging but realistic design targets for the main systems (e.g., hull, mooring, and disconnection system) and, in parallel, work on design of operational measures, including assessment of efficiency and reliability. Further, quantitative operability and risk assessments of the entire system were performed to evaluate potential optimization needs.
Ice-Related Design and Operating Philosophy
The FP was designed as an ice-resistant disconnectable production unit, able to withstand independently almost all ice and iceberg actions expected to occur at Shtokman. The following conditions are the design limits, and acceptable response criteria under these conditions and interaction scenarios must be satisfied.
Ultimate-limit-state (ULS) mooring safety factor under:
Head-on interaction with unmanaged 100-year-return-period (YRP) ice ridge (with corresponding companion environmental actions)
Ice vaning in unmanaged 100-YRP level ice (with corresponding companion environmental actions)
Interaction with 10,000-YRP iceberg in open water (for demonstration purpose, not for use in operations)
5000-t horizontal load (as practically achievable value, on the basis of results from initial studies)
The Second Unconventional Gas Wave
Authors: Miller Jeff 
Published: February 2015

Guest editorial
Gas exploration activity in North America looks like it is in the doldrums. In the past 12 months, gas-directed North American rig counts have fallen by almost half. This is easy to understand. Since the beginning of 2010, front-month gas futures prices have fallen from USD 5.60/MMBtu to their current level of USD 3.60/MMBtu. I have a bullish view on the long-term future of natural gas. When accounting for all of the upside influences—environmental imperatives, relentless demand growth in the developing world, the potential of the domestic power sector, revitalization of the US industrial base, and downstream innovations such as gas to liquids (GTLs)—the picture looks positive. At the same time, I have a firm belief that continuing innovation will drive efficiency, making gas an even more attractive alternative and leading to more exploration and development. These indicators lead me to believe a second wave in the development of the North American gas business is on the way.
The first wave has been quite a ride. Only a few years ago, gas industry pundits assumed that new gas demand could only be met with imports. An entire subindustry was developed around the regasification, storage, and transport to market of imported liquefied natural gas (LNG). Today, LNG regasification facilities are largely idle. Instead of increasing, gas imports have fallen dramatically—from 12.6 Bcf/D in 2007 to less than 9 Bcf/D in the most recent 12 months.
Although gas production has increased dramatically, from just under 55 Bcf/D in 2007 to a current rate of 69 Bcf/D, the increases in production have been absorbed incrementally, without long-term structural adjustments in the US energy economy or significant investments in infrastructure. Existing gas plants displacing coal in the power sector and reductions in imports have absorbed more than 70% of the increase in gas production.
The United States is still a net gas importer, but the industry is now focused on developing export markets. Those markets are there. Demand growth in China is almost certain for a generation. If Japan follows up on its commitment to step away from nuclear power, new supplies will need to be found there.
Exporting gas will require us to adopt workable regulations, develop infrastructure, and change a mind-set. The United States is accustomed to thinking as an energy importer. As new sources are developed, we tend to guard them jealously and reserve them for domestic use. The Federal Energy Regulatory Commission approves the construction of LNG liquefaction facilities and the Department of Energy grants export licenses based on a “public interest” standard.
Techbits: IPEC 2012: Promoting Industry Diversity
Authors: JPT staff _ 
Published: February 2015

Techbits
The International Professionals in Energy Conference (IPEC 2012) “Empowering Women’s Leadership” was held recently in Kuwait under the patronage of the Kuwait Minister of Oil and Chairman of the Board of Kuwait Petroleum Corporation Hani A. Hussain.
During the two days of IPEC 2012, attendees representing international oil companies, national oil companies, multinational service companies, consulting firms, and academia discussed topics related to gender diversity in the industry. More than 270 delegates representing 53 companies from 15 countries attended.
The opening ceremony featured Farouk Al Zanki, deputy chairman of the Board of Directors and CEO, Kuwait Petroleum, and Hosnia Hashim, deputy managing director, North Kuwait, Kuwait Oil, who was also the conference chairperson. The executive plenary session included Sami Al Rushaid, chairman and managing director, Kuwait Oil; Maha Mulla Hussain, chairperson and managing director, Petrochemical Industries Company; Andrew Gould, chairman, BG Group; and Bernadette Spinoy, senior vice president, refining and petrochemicals Eastern Hemisphere, Total. The speakers shared their personal experiences and their companies’ strategies for creating balanced leadership.
Held alongside IPEC was a Region-al Education Day, attended by 200 students from public and private schools in Kuwait. The aim was to introduce students to the discipline of petroleum engineering and the industry in general.
Three key concepts arose during the conference:
The inclusion, retention, and empowerment of women in the workforce is a clear business necessity.
Companies need to ensure that all employees positively embrace the increased presence of women in the workforce.
The implementation of gender-balanced guidelines for promotion processes is necessary.
The inclusion, retention, and empowerment of women was described as important because the expansion plans of the industry to meet global energy demand will require new staff. The second concept, one met with surprise by several attendees, is the recognition of the need to train men in the industry to accept and embrace the incremental presence of women in all roles and ranks of the workplace, especially in field operations, where a female presence is still uncommon in many places of the world. In field operations, special accommodations and facilities may be needed to follow cultural acceptance.
The third key concept will require implementation of gender-balanced guidelines for promotion to maintain managerial balance in companies.
Panelists concluded that the industry’s workforce is in need of change to reach its potential, and that future energy challenges will require richer and more diverse viewpoints. The oil industry must incorporate concepts of diverse work teams as well as best practices in diversity and inclusion processes to enable and promote contribution from professionals with different experiences and perspectives. This diversity will allow for better decisions.
Unconventional Exploration Reaches: Alaska's North Slope
Authors: Rassenfoss Stephen 
Published: February 2015

North Slope Shale
On the day last February that the US Geological Survey (USGS) came out with a report saying up to 2 billion bbl of oil could be produced from shale formations on the North Slope of Alaska, a company was already planning to drill on its 500,000-acre lease.
That was a striking change at the agency where years separated the release of assessments and exploration in plays such as the Marcellus said David Houseknecht, a research geologist for the USGS and the lead author of the North Slope assessment.
The explorers and the government geologists drew on similar sources to conclude the North Slope could be a likely spot for the next US shale exploration boom.
While the USGS was working on its North Slope evaluation, geologists like Ed Duncan were looking for signs the rocks that were the source of oil that migrated over long periods into huge conventional reservoirs, such as the Prudhoe Bay, Kuparuk, and Alpine, could also be rich sources of oil.
Using what he’d learned early in his career working the North Slope and later as a consultant for companies seeking new shale plays, Duncan and his wife Karen Duncan, formed a company called Great Bear Petroleum and put in a surprise bid at the December 2010 Alaska state lease sale.
“I was stunned by the potential, with three of the most prolific oil source rocks and nobody was doing anything with them,” said Duncan, who is president and chief executive officer at Great Bear.
At the time he told the story of how he came to explore the North Slope, Duncan was in Golden, Colorado, at a Weatherford lab studying the core samples collected from Great Bear’s test wells, the Alcor and the Merak, drilled in the summer of 2012.
The wells near the gravel road that parallels the Trans-Alaska Pipeline penetrated all three source rock formations. The early evaluations were all in line with expectations but in late December he was just beginning to see the results of the tests of formations so rarely seen that a USGS geologist came out to examine them.
Duncan hopes to drill a horizontal well, fracture it, and do a production test next, but: “As much as I would love to say here is the result, let’s go ahead with a fracture-flow test, that is not the case,” he said.
“We are learning a tremendous amount every day,” Duncan said after 2 days in Golden. But critical tests on the rock properties indicating whether it could be effectively fractured would not come in until February. “My father would say there is plenty of wood to chop here,” he said.
Tight Resources, Promising Economics: The Permian Basin Continues Yielding Liquid Riches
Authors: Beckwith Robin 
Published: February 2015

Permian Basin
There is no doubt that the 86,000-sq-mile Permian Basin, encompassing 52 counties in west Texas and eastern New Mexico, is experiencing a renaissance in drilling activity. According to the Railroad Commission of Texas (RRC), the Texas Permian Basin rig count climbed from 129 in 2005 to 355 in 2011, sustaining a dip to 103 in 2009 with no drop in crude oil production. Total Permian Basin rig count climbed to 500 in May 2012, according to a US Energy Information Administration (EIA) report, and as of late December 2012, stood at 454. The number of drilling permits issued by the RRC has exhibited a similar rise, from 4,459 in 2005, with a downdip to 3,369 in 2009 and then a steep climb to 9,347 in 2011.
The price of natural gas remains depressed in the US, largely because of a glut due to a rush to exploit very tight gas resources in shale plays such as the Marcellus, Eagle Ford, Barnett, Haynesville-Bossier, Fayetteville, Woodford, and Bakken. A trend over the past few years has therefore been building towards a focus on liquids-rich plays.
As a result, US production of crude oil is reaching levels not seen in 15 years, at approximately 2.1 billion bbl/year as of September 2012, according to the US Department of Energy’s (DOE) EIA. The US now produces an average of 6.41 million BOPD, a 14% increase from 2011, according to a December 2012 DOE report—around 50% of the crude oil it consumes.
The two US states emerging as yielding the greatest amount of liquids are North Dakota (the Bakken) and Texas (Permian Basin and Eagle Ford).
From September 2011 through September 2012, Texas onshore crude oil production increased by more than 500,000 BOPD, due to increases in Eagle Ford and Permian Basin production.
The Permian Basin now accounts for more than 18% of domestic US crude oil supply. It has more than 400 active drilling rigs, by far the most of any US basin, that are drilling a large number of wells very quickly.
The EIA estimates (Fig. 1) that crude oil production from the Permian Basin surpassed 1.25 million B/D in November 2012, 33% greater than the estimated 0.93 million B/D in the Western Gulf basin and 45% greater than the 0.86 million B/D in the Williston basin.
Pioneer Resources: Targeting the Wolfcamp with Integrated Services
Authors: JPT staff _ 
Published: February 2015

Permian Basin
Pioneer Natural Resources is a large independent oil and natural gas company, with resources throughout the US—in south Texas, the Rockies and Mid-Continental regions, the Barnett shale, and in Alaska’s Oooguruk field. The company also is one of the most active drillers in Texas’ Spraberry/Wolfcamp oil field in the Permian Basin. Covering nine counties, the Spraberry field produces sweet crude and gas from formations between 6,700 and 11,000 ft below the ground. Pioneer is also in the early stages of a new horizontal drilling program in the Wolfcamp shale interval of the Spraberry field.
In a recent interview, Pioneer’s Tom Spalding, vice president, geoscience, explained, “Pioneer is a major operator in the Spraberry vertical and the horizontal Wolfcamp shale—in the center of the basin.”
The company is interested in drilling deeper in the Spraberry, targeting the Strawn, Atoka, and Mississippian. “In fact,” said Spalding, “Vertical wells with multistage completions that include these deeper zones accounted for about 65% of our 2012 vertical drilling program.”
Pioneer boasts one of the largest acreage positions in the Permian Basin, approaching 900,000 acres—and it is highly leased up. “We also have a big push on with unconventional horizontals drilling into source rock—the Wolfcamp, which is the major source rock in the area,“ said Spalding. “The beautiful thing about the Midland basin Wolfcamp formation is it just happens to be in the right window—buried to the right depth and exposed to the proper temperatures—so that over time the kerogen has ‘cooked’ so it is converted to oil (liquids).”
This “right window” underlies across the Permian Basin, where the Wolfcamp is a thick formation—the source rock—underneath other formations, such as the Spraberry. Pioneer has been drilling its southern 200,000 acres first, to hold some expiring leaseholds. “The Wolfcamp is a little shallower there,” he said.
Deeper drilling in the Spraberry, targeting the Strawn, Atoka, and Mississippian, accounted for 65% of Pioneer’s 2012 vertical drilling program. All these formations lie beneath the Wolfcamp, which lies beneath the Spraberry. The deeper drilling provides the potential to add up to 100,000 BOE (in addition to the 140,000 BOE obtained from the commingled Spraberry and Wolfcamp).
Technology Focus: Offshore Facilities (February 2013)
Authors: Ball Ian G. 
Published: February 2015

Technology Focus
In last year’s Offshore Facilities Technology Focus (February 2012), we highlighted the increasingly important role that constructive collaboration plays in facilitating delivery of successful field-development outcomes in increasingly challenging environments.
In this edition, we illustrate the vital importance of innovative technological advances in enabling some of these challenging field developments that would otherwise not be technically feasible.
Operators have generally tended to shy away from the upsides available by embracing new technology for fear of incurring downsides from suboptimal performance of the technology. This has inevitably slowed down the whole cycle of investment in, and adoption of, commercially advantageous technology to the ultimate detriment of the industry as a whole. It also certainly has tarnished our industry’s attractiveness to bright young engineers of the future.
An interesting shift, however, has been evident in recent years. There have been a growing number of instances whereby operators have been unable to implement potentially lucrative field developments without adopting technology that they would hitherto have deemed to be inadequately proven by others. In the overwhelming majority of such cases, where the desire to implement the field development has overridden the reluctance to adopt the necessary new technology, the outcomes have been successful.
A couple of key characteristics underpin these successes. One of those is constructive collaboration, which we have already touched on. The other is ensuring that both the nature and the dimensions of the associated technology-implementation challenges are properly understood and that the efforts established to overcome the challenges are realistically resourced to achieve success.
Very few operators are large enough to have the necessary specialist resources available in house for planning and executing such projects with demonstrable confidence that success will be delivered. However, those resources are still readily available to any operator for any desired duration if the appetite is there to enter into a collaborative venture for achieving the available upsides.
I hope you enjoy the opportunity to read how one operator is taking advantage of multiple recent technological advancements to complement an innovative commercial approach in transforming a hitherto unviable discovery into a fully viable field development. We also take a look at some other ongoing technological advances that have the potential to change the way we will do business in years ahead.
Please let me also take this opportunity to remind interested readers of the new sister SPE publication Oil and Gas Facilities, in which many more aspects of offshore facilities are explained and discussed. Your feedback on how you would like to see that publication evolve would be very much welcomed.
Recommended additional reading at OnePetro: www.onepetro.org.
OTC 23365 Autonomous Inspection Vehicle, A New Dimension in Life of Field Operations by James Jamieson, Subsea 7, et al.