bluuebunny/crossref_metadata_2025 huggingface dataset:
HT Stimulation Fluid Based On GLDA Meets Productivity, Environmental Need
Authors: Nasr-El-Din Hisham A.
Published: February 2015

Technology Update

Industry operations are shifting toward high-temperature (HT) downhole set-tings, expensive tubular metallurgy, and extended reach wells, while health, safety, and environmental requirements become stricter. Consequently, conventional stimulation treatments, such as applications using hydrochloric acid-based fluids, will no longer meet the industry’s needs as operational environments evolve. A new stimulation fluid developed by AkzoNobel, Dissolvine StimWell, is based on glutamic acid diacetic acid (GLDA) and has been successfully applied in the field.

GLDA has high thermal stability and low corrosion potential, and is an effective stimulation fluid without adverse environmental impact. A vertical gas well in a deep, sour carbonate reservoir was successfully stimulated using GLDA. Previous matrix stimulation treatments with conventional acids in this HT gas well did not sustain the performance, and a fracture treatment was considered for the well. However, the case proved that matrix acidizing with the GLDA-based fluid was the best stimulation method for the well in terms of cost-effectiveness and regulatory issues.

Stimulation Purpose

The object of stimulation is to remove the production zone damage caused by the drilling and completion processes in sandstone reservoirs, and to create channels or wormholes in carbonate reservoirs. Although an industry workhorse for decades, hydrochloric acid (HCl) often produces subpar stimulation results, especially at high temperatures, because of its fast reaction near the wellbore, low acid penetration, and high corrosivity. Many problems may occur during sandstone acidizing with HCl/hydrofluoric mud acid, such as decomposition of clays in HCl acids, precipitation caused by the presence of fluoride, silica gel filming, and colloidal silica gel precipitation. As a result, mud acid may cause significant damage to sandstone reservoirs, especially for those with a high content of calcite or clays such as illite. The desirable alternative stimulation fluid would be suitable for all of these conditions, be globally applicable, and have an acceptable environmental profile.

Fluids based on GLDA meet those requirements. The fluids are effective in improving permeability in carbonate and sandstone formations. Many additives such as iron control agents that are required in other fluids are not needed in GLDA-based stimulation fluids.
Techbits: Defining Unconventional Resources
Authors: JPT staff _
Published: February 2015

Techbits

SPE recently held an Applied Technology Workshop (ATW) on “SPE Petroleum Resources Management Systems (PRMS) Reserves and Resources Definitions–Applicable to Both Unconventional and Conventional Resources?” in Penang, Malaysia. The unprecedented growth in the exploration and production of unconventional resources in North America has sparked widespread interest in the Asia Pacific region. In parallel with the North American shale gas boom, the emergence of several mega coal seam gas to liquefied natural gas projects in Australia has also renewed interest in coalbed methane (CBM) in the region.

The differences in reservoir characteristics and producing mechanisms between conventional and unconventional resources have provided technical, developmental, and economic challenges to the industry, with consequential effects on resource assessment. The question therefore arises as to the suitability and applicability of the SPE PRMS to unconventional resources.

The workshop attracted 93 participants, representing 13 countries and 23 organizations. The program committee for the workshop consisted of 12 members:

Cochairperson:

Norhayati Hashim, Petronas

David Ahye, Gaffney, Cline and

Committee member:

Yousef Al-Shobaili, Saudi Aramco

Abdolrahim Ataei, Petronas

Kamarul Ariffin Buang, ExxonMobil E&P Malaysia

Bruce Gunn, RISC

Greg Horton, Santos

Krit Ngamkamollert, PTT Exploration and Production

Douglas Peacock, Gaffney, Cline and Associates

Aidil Shabudin, Petronas

Mike Reeder, RPS

Yang Hua, RIPED, China

Session 1: Introduction/ Opening/Keynote Address

Hazli Sham Kassim, general manager of resources enhancement at the petroleum management unit of Petronas was the keynote speaker. He spoke about the background of the PRMS and its goal to provide a standardized and consistent approach to assessment of risk and uncertainties related to petroleum reserves and resources. He also recommended that the SPE considers introducing abbreviations for Prospective Resource categories, similar to 1C, 2C, and 3C, and 1P, 2P, and 3P and suggested the abbreviations 1U, 2U, and 3U, as currently used internally by Petronas.

Greg Horton, member of the SPE Oil and Gas Reserves Committee (OGRC), then gave an overview of the PRMS and the updated application guidelines document (published November 2011). He also presented an update on what other international professional societies were doing with regard to updating their own guidelines and alignment with the PRMS.

Session 2: Characteristics of Unconventional Reservoirs

Session 2 provided an introduction and overview of the major types of unconventional reservoirs to ensure a common understanding by all. An overview was provided on CBM, tight gas, and shale gas. The session also included an introduction to the application of the PRMS to unconventional reservoirs.
Making Unconventional Resources Less So
Authors: Rassenfoss Stephen
Published: February 2015

Emerging Technology

The label unconventional resources, for shale or other nontraditional oil and gas formations, has its detractors.

Bruce Vincent, president of Swift Energy, said in a speech in August that “it is not unconventional any more.” The problem, he explained, was that “unconventional sounds unreliable,” despite the large and growing volumes produced by companies like Swift, an independent whose operations include the Eagle Ford Shale.

But those on the technology-development side of the industry describe unconventional development as a precocious newcomer that has achieved much, with the US predicted to be the world’s largest producer by the end of the decade, but it is far from mature.

When SPE’s six technical directors were asked to talk about some of their priorities for technology development in unconventional reservoirs, they pointed to the areas where change is needed to realize the potential for resources. On the list are improved reserve estimates, adding flexibility to standardized drilling and completion methods, and a greater focus on what it will take to maximize long-term production.

A word used over and over by Vincent and the tech directors was optimizing.

The business whose methods have evolved based on experience will have the opportunity to improve its results based on increasing data from testing.

“We will know so much more in a year to two years from now,” said Shauna Noonan, SPE technical director for Production and Operations. “We are in uncharted territory. We are learning something new every day.”

The growing body of information will raise more questions, and make demands on operations. The “cookie cutter” methods developed to economically deliver the thousands of wells needed for development in shale and coal-seam methane deposits need to be adjusted to allow changes and tradeoffs between spending and performance.

Adjusting where a formation is fractured is likely to add cost, but could pay off in greater production if the system allows well-to-well adjustments.

There is also a push and pull between the long term and the short term.

The standard systems used to drill wells in an assembly line fashion need to build wells in a way that allows later efforts to extend the life of the field. A small cost saving now may cost more in the future.

Long-term decisions are based on only short-term data from recently developed fields. There is a need for statistics-driven methods to mine the data in search of ways of predicting what will happen over the long term and what changes are likely to enhance that outlook.

Future production declines are predicted based on old models developed for conventional reservoirs, which perform quite differently. More resources need to be committed to developing better methods to measure the productive reservoir volume—the area where natural and manmade fractures allow oil and gas to flow—and the amount it will ultimately yield.
Natural Gas: A Rich Resource for Technological Challenges
Authors: Rassenfoss Stephen
Published: February 2015

Emerging Technology

When Gerald Schotman Shell’s chief technology officer looks at the unconventional oil and gas business, he sees so many young technologies and “from the perspective a chief technology officer, that is such an opportunity.”

Shell’s list of promising areas for research and development is broad, ranging from creating cheaper, more effective sensors for seismic testing to a new generation of specialized, automated drilling rigs.

The goal is always “change that creates value.” In natural gas the rewards can be broken down three ways: produce more gas per well now, bring down the costs per well, and reduce the footprint when doing so.

The footprint can be defined in many ways: the size of the pads used for drilling multiple wells; the level of emissions; the water used; and the many ways exploration and production can touch the people and the environment, near and far.

The long list of things to do represents large investments of money and time, which Schotman says could be rewarding in multiple ways.

“As it happens, some of the research helps two or three goals at a time,” Schotman said in an interview. Often with “the gas agenda a nice thing is you do not have to trade off.”

A continuously better understanding of why specific fractures are more effective than others could lead to hydraulic fracturing methods using less water and sand, saving money, producing more, and reducing the footprint.

There is a wide range of research to respond to “the things where we can find new approaches for these plays.”

Enhanced seismic imaging is a priority because many of the growth areas are in tight, poorly understood rocks onshore, such as shale and coal-beds. Laboratory studies are needed to observe how reservoir rocks interact with hydrocarbon molecules on a microscopic scale.

The goal is to learn: “How is Mother Earth organized to release these molecules, and what is the most low-energy way to get it into the wells?” he said.

Rethinking Exploration

Unconventional formations demand unconventional approaches.

 “You have to get back to the fundamentals to make it a business,” Schotman said. “With these types of plays there are specific cost challenges….There are things that do not work well for these plays.”

The reasons are many and the rocks are complex, but generally unconventional formations require more inputs for less output than conventional formations.
Artificial Intelligence Comes of Age in Oil and Gas
Authors: Braswell Gentry
Published: February 2015

Artificial Intelligence

Once the stuff of science fiction, artificial intelligence (AI) has become ubiquitous in our daily life, and the modern oil and gas industry is no exception.

Artificial neural networks, fuzzy logic, and evolutionary algorithms are common among AI techniques being applied today in oil and gas reservoir simulation, production and drilling optimization, drilling automation and process control, and data mining.

“Today, when you talk to information technology (IT) people, they mention four trends: social media, mobile devices, the cloud, and big data,” said Reid Smith, manager of IT Upstream Services at Marathon Oil, and a fellow of the Association for the Advancement of Artificial Intelligence.

Social media are in everyday use for collaboration; mobile devices are proving valuable in field operations; cloud computing has the potential to deliver cost savings and increased flexibility and performance in networking and data management; and hyperdimensional, complex, big data are well suited for analysis by machine learning, which is a key element of today’s applications of AI.

In addition to a large existing volume of historical oil and gas data, today’s increasingly complex upstream environments generate vast amounts of data for which the value is greatly enhanced with cutting-edge IT. “Some argue there is a substantial amount of oil to be found by applying new analysis techniques to data already on the shelf,” Smith said.

It is important to distinguish between data management and AI. SPE’s Artificial Intelligence and Predictive Analytics (AIPA) group was previously a subsection of SPE’s Digital Energy Technical Section. Now it constitutes its own technical section, Petroleum Data Driven Analytics. Essentially, digital energy is the curating—gathering, storage, and generation—of data, whereas AIPA involves using the data to perform tasks without human intervention, said Shahab D. Mohaghegh, professor of petroleum and natural gas engineering at West Virginia University, and founder of oil-field consulting and software company Intelligent Solutions, Inc. (ISI).

“There is a push in our industry toward smart fields,” Mohaghegh said. “There is a misconception in our industry today that equates automation with intelligence. Just because an operation is automated does not mean that it is smart. Without AI, you may have auto-mated fields, but you will not have smart fields. An automated field may provide the brain, but AI provides the mind. AI is the language of intelligence; it is what makes the hardware smart. To fully realize this, one must subscribe to a complete paradigm shift.”

A good modern example of the data-driven model outside the industry is credit card fraud detection and prevention tools that monitor consumer purchasing habits. “At ISI, that’s how we build reservoir management tools today,” Mohaghegh said. “We are now using the pattern recognition power of this technology to predict, manage, and design hydraulic fracture details in shale, using the hard data rather than soft data.”
Surveillance and Complex Well Work Combine To Extend Life of Mature Field
Authors: Wilson Adam
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 146157, ’Unlocking the Future for a Mature Field: Surveillance and Complex Well Work Combine To Extend Field Life,’ by Matthew Dunning, SPE, John Stripe, Patrick Keatinge, Peter Newton, Ann Davies, SPE, and George Waugh, BP Exploration, prepared for the 2011 SPE Offshore Europe Oil and Gas Conference and Exhibition, Aberdeen, 6-8 September. The paper has not been peer reviewed.

Ravenspurn North is a mature gas field forming part of BP’s United Kingdom Continental Shelf portfolio. The field commenced production in 1990 through 42 wells and three platforms; but, by 2006, half of the wells had ceased to flow. A surveillance campaign suggested a common failure mode for many wells, a postulation that large amounts of proppant had accumulated in the wellbore. Pressures measured downhole above the proppant fill supported a significant increase of the remaining gas potential. A project to rejuvenate this field was initiated in 2007.

Introduction

Ravenspurn North encompassed two discrete areas—a relatively high- permeability area referred to as the “sweet spot” where wells were completed without any stimulation and a low-permeability area referred to as the “tight spot” where every well was hydraulically fractured with up to 1.3 million lbm of ceramic proppant. The hydraulically fractured wells were generally located on unmanned satellite towers.

By 2006, 50% of the wells across the field had ceased flowing, the majority of these being the fractured wells in the tight spot. With production falling, Ravenspurn North was facing an uncertain future.

Building the Technical Case

In 2007, a thorough review of BP’s southern North Sea fields was completed with the objective of bringing fresh perspective to these mature fields. For Raven spurn North, the opportunity to repair and reinstate wells to production appeared logical. However, available surveillance data suggested limited remaining-resource potential, and it was believed that the wells that had ceased to flow had simply produced most of their contacted gas. If this was correct, then undertaking expensive interventions to repair the wells would not be wise. The story, though, was far from crystal clear.

First, the remaining-resource estimate was based on P/z trends that were recognized to contain uncertainty in a tight gas environment because the wells never truly reached steady-state production. In early time, the P/z trends presented a credible straight-line fit; however, in later time, a number of higher-pressure measurements that did not fit the trend were observed (Fig. 1). Because the majority of the data points were surface pressures converted to bottomhole pressure, some of the measurements could be explained partly by hydrostatic uncertainty. Other data points, though, were believed reliable and indicated higher reservoir pressures than the overall trend would suggest, pointing to higher contacted gas and the possibility of more potential in these wells.
Benefits of Single Platform Lifting Lead to Design, Construction of New Giant Ship
Authors: Wilson Adam
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper OTC 23169, ’Building a Giant for Single Platform Lifts,’ by Edward P. Heerema, Allseas Group, prepared for the 2012 Offshore Technology Conference, Houston, 30 April-3 May. The paper has not been peer reviewed. Copyright 2012 Offshore Technology Conference. Reproduced by permission.

The ship described here was designed and is being built for single lifting of topsides of offshore platforms up to 53,000 short tons and jackets up to 27,500 short tons. The vessel will have a wide slot at the bow that fits around platform substructures and will be equipped with a hydraulically operated topside-lifting system. For installing or removing platform jackets, it will have a system of two tilting lift beams at the stern. The building of the vessel and equipment is in progress; the vessel is scheduled to be commissioned by the end of 2013.

Introduction

The ship described here was designed and is being built for single lifting of top-sides of offshore platforms up to 53,000 short tons and jackets up to 27,500 short tons. The vessel will have a wide slot at the bow that fits around platform substructures and will be equipped with a hydraulically operated topside-lifting system. For installing or removing platform jackets, it will have a system of two tilting lift beams at the stern. The building of the vessel and equipment is in progress; the vessel is scheduled to be commissioned by the end of 2013.

Traditional Modular Lifting vs. Topside Floatovers

Installing large offshore platforms so far has generally been performed with crane vessels. Large topsides have to be installed module by module to ensure that the lifts remain within the capacity of the cranes. This can lead to considerable offshore hookup costs to complete the topside, which are greater than when performed on land.  However, by single lifting the offshore hookup, costs can be reduced significantly. If a topside structure is completed on land and installed in one piece, the making of all the connections between elements or modules—structural, electrical, hydraulic and piping—is faster and less costly.

Removing a large topside by traditional crane vessels requires the topside to be removed module by module or by more time-consuming, hazardous, and expensive dismantling offshore in small pieces. When removing the topside in a modular way, every module must be cut loose from the surrounding modules, lift points must be reinstalled, and lift rigging must be attached. Platform walkways, escape routes, and safety plans must be adjusted several times during the removal process. Several make-safe campaigns are required offshore and onshore. At an early stage, the accommodation facilities will have to be removed because of their outside position and then will no longer be available to the dismantling crew.
North West Hutton Decommissioning - Major Challenge Turns to Major Success
Authors: Wilson Adam
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 156827, ’North West Hutton Decommissioning - A Major Challenge, a Major Success,’ by Caroline White and Ged Adams, BP Exploration Operating Company, prepared for the 2012 SPE/APPEA International Conference on Health, Safety, and Environment in Oil and Gas Exploration and Production, Perth, Australia, 11-13 September. The paper has not been peer reviewed.

Excellent health, safety, and environment (HSE) performance was maintained throughout the decommissioning and removal of the first major offshore UK installation of the North Sea, the North West Hutton (NWH) installation. The NWH installation was composed of an 18 000-t steel jacket support structure and 20 000 t of topside modules. The total offshore removal program was executed with approximately 900,000 man-hours, with no days-away-from-work cases or high-potential-safety incidents. 

Introduction

The NWH installation (Fig. 1) was a large steel jacket installation 130 km north-east of the Shetland Islands in a water depth of 144 m. It was composed of a 18  000-t steel jacket support structure and 22 000 t of topside modules. At its peak, NWH produced a maximum of 86,500 BOPD.

Following cessation of production in January 2003, the NWH installation went into a phase of engineering down, which involved vessel cleaning and module separation in preparation for removal. The installation then went into a normally unmanned installation (NUI) mode for 4 years, during which time a decommissioning program was developed.

The decommissioning program was based on a comparative assessment of all decommissioning options, including some 50 external studies, a wide stake-holder consultation process, and review by an independent review group.

Knowledge Management

In order to capture existing information to support safe engineering design and removal, the following key activities were initiated:

A review was made of all incidents from previous North Sea decommissioning projects.

The project sought to retain key NWH operations personnel to support the installation in its NUI status and through the engineering design and offshore execution.

Access to installation data was challenging. The installation was installed in 1983, when there were no electronic data management systems. Installation as-built data were available, however, because engineering and ownership changes over its lifetime required comprehensive and accurate data. The data were critical for understanding the structural integrity and for development of the module weight reports. Where gaps in knowledge were identified, a detailed offshore survey program was initiated.
Charles Frederic Rand and Robert Earll McConnell: The Men Behind the Awards
Authors: Beckwith Robin
Published: February 2015

SPE Awards

Charles Frederic Rand:  A Life of Mining Achievement

Born in Canaan, Maine, on 7 August 1856, Charles Frederic Rand was to become, according to the Engineering and Mining Journal-Press (15 July 1922), “one of the leaders in all engineering movements for many years.” Although now little is known about his life, it is evident he was a skilled leader and a man of intense drive—a self-educated engineer, president of numerous companies through-out the world, and developer of iron, steel, and manganese mines and iron mining processes.

One can glean some idea of the nature of his achievements from the honors he received. In 1913, the Spanish government presented him with the Grand Cross of Knight Commander of the Orden de Isabel la Catolica (Order of Isabella the Catholic). Since it was established in 1815, this honor has been bestowed upon notable people outside Spain in recognition of services that benefit that country. In 1922, Rand also received the Croix de Chevalier de la Legion d’Honneur [Chevalier (Knight) Cross of the Legion of Honor] from the French government. Normally reserved for French nationals, this honor can be conferred upon those outside France who have served the country or advanced its ideals.

The New York Times (NYT) cites, on 3 July 1921, a cable received by the American Institute of Mining Engineers (AIME) headquarters noting Rand’s “election as honorary member of the Iron and Steel Institute of Great Britain.” The NYT describes him as “one of the leaders of post-war [i.e., WWI] research in American industry.” It states further, “He is identified with the construction of railways and the opening and operation of iron mines in Cuba, besides being largely interested in mines of manganese and copper ores.”

Beginning his career in the railroad industry, Rand later turned to mining. By 1886, he was president and general manager of the Aurora, Ashland, Atlantic, Iron Belt, Superior, Palms, and Comet iron mining companies, representing oil tycoon John D. Rockefeller’s interests. He went on until 1902 to represent his principals’ interests in the Monte Cristo, Washington, and Coeur d’Alene, Idaho, mining districts. Rand’s attention then turned also to steel and manganese.
A Long-Term View From Multiple Angles
Authors: Rassenfoss Stephen
Published: February 2015

SPE Technical Directors' 2014 Outlook

A condensed version of what is on the minds of SPE’s technical directors is: The industry needs multidisciplinary, data-driven ways to adapt to what is ahead, focus on what is critical for decision making, and take a long view as another generation takes over.

In other words, this group of six representing key industry disciplines has a lot of ideas. When SPE’s technical directors met in October 2013, they discussed two big ideas that may become group projects: better management of critical processes to ensure they are done safely, and caring for aging fields.

A discussion of whether managing aging fields is worthy of greater attention brought up the challenge of permanently plugging offshore wells not designed with current technology in mind, whether worn tubulars in old wells can withstand the stress of life-extending fracture treatments, and estimating how long a well is likely to be producing.

“It crosses disciplines. There are problems, and opportunities to get more out of fields, that cross the lines,” said Roland Moreau, SPE technical director for Health, Safety, Security, Environment, and Social Responsibility, who has taken a personal interest in process safety.

Smarter, faster use of data is a common theme. David Curry, SPE technical director for Drilling and Completions, wants to see drilling systems that are wired to manage the data needed to observe what is ahead and intelligently respond to it. Olivier Houzé, SPE technical director for Reservoir Description and Dynamics, sees the need for better systems to highlight critical bits of information from all the data flowing in as more sensors are built into wells.

Shauna Noonan, SPE technical director for Production and Operations, is interested in better long-term production management of unconventional wells. Her concern overlaps Houzé’s work on predicting reservoir life for unconventional wells because “part of the plan is for retirement, but how do you do that when you do not know what the retirement age is?”

When it comes to petroleum engineering educators, the average retirement age is uncomfortably close for two-thirds of those in academia. The academic crew change comes at a time when there has been a surge in the number of students enrolled, putting stress on institutions that are struggling to keep up. Cindy Reece, SPE technical director for Management and Information, said SPE needs to actively foster new ideas and greater cooperation between academia and industry to ensure a quality education for future petroleum engineers. “When we look at what is needed in the future, what we have today is not sustainable,” Reece said.
Kuwait Unveils Upstream Opportunities
Authors: Henni Abdelghani
Published: February 2015

The inaugural SPE Kuwait Oil and Gas Show and Conference (KOGS), held 7–10 October 2013 in Kuwait, attracted more than 3,000 delegates representing major oil and gas companies from all over the world.

The event, under the patronage of Kuwait’s Prime Minister Sheikh Jaber Mubarak Al-Hamad Al-Sabah, carried the theme “The Power of Collaboration...People and Technology in the Oil and Gas Industry,”

Hosnia Hashim, KOGS conference program chairperson and vice president of operations at Kuwait Foreign Petroleum Exploration Company (KUFPEC), said that the gathering allowed exploration and production professionals to network with colleagues from around the world and celebrate key successes in the industry. “For the first time ever in Kuwait,” she said, “we launched a technical event with outstanding participation, having received more than 520 papers, from 104 organizations and 69 universities, from 37 countries.”

In his opening remarks at the Conference Opening Ceremony, Kuwait Deputy Premier and Minister of Oil Mustafa Al-Shimali, reiterated Kuwait’s unflinching commitment, in its capacity as a main oil producer, to ensuring regular supplies to world markets. “This conference is timely and logical, as the Kuwait oil sector is undertaking plans to ensure that it meets and fulfills its international role as a reliable supplier. We have allocated billions of US dollars to reach production capacity of 4 million BOPD by 2020. An international exchange of technology and experience is critical to realizing these plans,” Al-Shamali said.

At the Executive Plenary Session, Nizar Al-Adsani, chief executive officer of Kuwait Petroleum Corporation (KPC), aentation titled “Kuwait Experience: The Power of Collaboration, People, and Technology in the Oil and Gas Industry,” that the challenges ahead for his country are great. “The emergence for new competitors, changes in supply and demand dynamics, social and environmental pressures, and demographic shifts, are transforming and reshaping our industry,” he said.

Al-Adsani said that technology has been the driving force behind the industry’s continued ability to deliver increased oil and gas production safely, efficiently, and in an environmentally friendly manner, adding that he believes that the excellence required is only provided through the strength of human resources.

The CEO said that his company is proceeding with its ambitious plans to enhance KPC’s role in the international oil industry and to be more effective in supply security for the world’s energy, adding that KPC wants to focus on the upstream. “Achieving our crude oil production growth target of nearly 1 million BOPD by 2020, and maintaining it through 2030, depends on the successful implementation of advanced technology in both improved and enhanced oil recovery,” he said.
Technology Focus: Decommissioning and Abandonment (January 2014)
Authors: Thornton Win
Published: February 2015

Technology Focus

Industry perceives decommissioning projects as more risky and uncertain than capital projects. Several recent decommissioning projects delivered in an immature marketplace seem to support this view. What can be done to change this perception and enable delivery of safe and cost-effective decommissioning projects?

I have always been a fan of this quote from Irving Fisher: “Risk varies inversely with knowledge.” I believe it can provide insight into a strategy that can improve the delivery of decommissioning projects. What can be done around decommissioning projects to gather knowledge of the asset to facilitate better planning and delivery and reduce the risk and uncertainty associated with decommissioning? The selected papers and additional reading listed here illustrate the use of knowledge to plan decommissioning more effectively and to understand the risks associated with selected end states. The following are a few thoughts on the use of knowledge to reduce risk and uncertainty in decommissioning:

Decommissioning differs from a capital project in that we know (or think we know) what the asset looks like. The critical uncertainty is the condition of that asset at end of life. What diagnostic information do we gather routinely over the life cycle that can provide clarity on the condition of that asset for decommissioning? Perhaps we need a key performance indicator analogous to front-end loading in capital projects that addresses the quality of our decommissioning and condition knowledge of that asset.

Identify the responsible party in an organization for gathering, distilling, and using asset knowledge for decommissioning. Asset information comes from various sources over the life cycle of the asset but needs a decommissioning set of eyes to identify and manage these risks. An analogy could be how we typically view and manage regulatory or asset-integrity information. This is an accountability that spans the life cycle of the asset through to decommissioning.

When planning the actual decommissioning work, identify and perform diagnostic work in cooperation with the supply chain as part of your market-engagement strategy. It is better to know the condition of what needs plugging and decommissioning than to find out halfway in. The unknowns become planned work activities instead of risks. This optimally is a cooperative effort between the owner and contractor to identify and manage uncertainties of the project, not just a set of contractual terms and conditions.

Share detailed experience, case studies, and lessons learned through professional forums such as SPE. JPT

 

Recommended additional reading at OnePetro: www.onepetro.org.

IPTC 16945 Environmental Liabilities in the Oil and Gas Industry and Life-Cycle Management by Lian Zhao, Integrated Environments, et al.

OTC 24461 Advances in Autonomous Deepwater Inspection by D. McLeod, Lockheed Martin, et al.

SPE 161556 Axis of Success: A Unique Professional Plug-and-Abandonment Project in a Populated Town Area by Hazem Abdelsalam, ADCO, et al.
Tap into the Talent Pipeline: Number of New Graduates in Petroleum Engineering Increases, Opening Window of Opportunity for Addressing Talent Shortage
Authors: Holditch Stephen A.
Published: February 2015

Guest editorial

During the last 3–5 years, one of the top priorities and challenges for the oil and gas industry has been trying to find the next generation of petroleum engineers, driven by the increasing demand for oil and gas and the aging workforce. And a related concern is how the industry will transfer the knowledge from its experienced professionals to the new entrants.

 Responding to the looming “big crew change” that will result from the retirement of so many petroleum professionals in the next few years, universities have increased enrollment in petroleum engineering departments. US petroleum engineering departments are now producing more graduates than at any time in the last 20 years (Table 1, Fig. 1). Similarly, the number of graduates in petroleum engineering has increased worldwide. Petroleum engineering department heads at US universities have shared enrollment data that indicate total enrollment has leveled off. Many universities are capping enrollment as a result of restrictions on space and the number of professors who are teaching. We expect the number of total graduates in 2011 and beyond to hover around 1,000–1,200.

No one counted on a global economic recession that has caused many experienced professionals to postpone their retirement, delaying the long-anticipated “brain drain.” With lower revenues, companies have reduced or put a hold on recruiting new graduates.

The result is that the number of jobs being offered to new graduates is being reduced just as the pool of graduates has been enlarged. In 2009, more than 90% of petroleum engineering graduates of US schools were offered jobs or went to graduate school. According to feedback from the US department heads, the 50 oil and gas companies that recruited on campus in 2008 and 2009 are estimating that they will hire only approximately 70% of available graduates in 2010, leading to an estimated 300 graduates needing jobs. Company reports and information from WorldWideWorker.com, which provides the job board for SPE student members, also confirm that global hiring plans for new graduates are expected to be substantially lower in 2010.
Advances in Perforating Technology Continue
Authors: Bell M.R.G. , Clark N.G. , Hardesty J.T. , Zaleski T.
Published: February 2015

Technology Update

Perforations represent the critical link between the wellbore and reservoir in cased wells and, thus, have a significant impact on well productivity and ultimate recovery. Important advances have been made in the past several years in the technology of perforation through the incorporation of reactive materials into oilfield shaped charges and through the advancement of stressed-rock testing of charge systems, as opposed to testing performed in cement. A new and potentially powerful extension to stressed-rock testing is the use of 3D digital-imaging technology and advanced analytical methods.

The advances being achieved in perforating appear likely to play a vital role in meeting the challenges of maximizing the productivity and recovery of wells drilled in the hard, low-permeability rock increasingly being targeted by the drill bit today. And although not yet exploited commercially, the capability already exists to design charges for application in specific lithologies, possibly even individual formations. 

Testing Under More Realistic Conditions

In practical terms, penetration into cement under surface conditions is an unreliable indicator of the performance that can be expected when charges are shot under real, downhole conditions. Stressed rock does not behave like un confined cement. More specifically, the new reservoirs of the 21st century—such as hard, subsalt carbonates or shales with nanodarcy permeability—are fundamentally different, and several orders of magnitude more difficult to understand than the sandstones on which predictive correlations from cement penetration to rock penetration were based (Behrmann et al. 2009). New science and products have been needed to complete wells effectively in these environments.

The first step toward developing solutions for such environments was the construction of perforator-evaluation facilities in which shaped-charge systems could be tested under conditions more closely representing the wellbore and reservoir (API RP 19B 2006). In this type of facility, frequently referred to as a flow lab, natural-rock targets are subjected to realistic levels of effective stress, while wellbore and pore pressures are accurately simulated to create appropriate static and dynamic pressure effects. If these tests are designed and executed successfully, they can provide a whole new level of insight into how effectively a particular perforating system will connect a wellbore to its target formation. It is fair to say that only the handful of companies that have invested in such flow-lab facilities are uncovering perforating solutions suitable for the increasingly complex reservoirs that will be the industry’s focus in the years ahead.
Managing Change in Difficult Times
Authors: Johansson Jan Erik
Published: February 2015

Management

The recent economic crisis provided a sense of urgency that helped organizations everywhere to successfully implement changes that would have been difficult otherwise. Companies spanning all global geographies and across all market segments, including energy, are being forced to examine the fault lines in their business under the pressure of sharply reduced demand, the failure of suppliers and partners, limited access to finance, and other consequences of the downturn. Many firms find this an inauspicious environment in which to attempt fundamental change in processes, behaviors, or structures, for fear of subjecting the organization to even greater strain. Others, however, see the crisis as a unique opportunity to achieve just that.

To assess the degree of change that firms have been experiencing since the onset of the economic crisis, and how they are handling its internal consequences, the Economist Intelligence Unit surveyed more than 500 European and US executives in July and August 2009 as part of Celerant Consulting’s second annual global survey on change.

More than half (59%) of global business executives who responded to the survey say that the current economic crisis has revealed shortcomings in their organization that they are attempting to redress and two-thirds (66%) of participants state that their organization is using the crisis as an opportunity to drive change that would have been difficult to achieve in better times.

Maintaining Change Programs

During times of economic uncertainty it is common for companies to attempt to simply weather the storm and not invest in organizational changes that will ultimately result in more efficient and effective business practices. However, the survey reveals that only 6% of firms have suspended change programs—structured approaches to implementing and managing change within a company—as a result of the financial crisis and the majority (60%) of firms are continuing with and even accelerating existing change programs while also launching new ones.

There is a danger, however, that firms are using the crisis to launch change initiatives too rapidly, with too heavy a focus on short-term objectives which yield only one-time saving rather than creating sustainable cost improvements that will continue over time. More than half of respondents in the survey confirmed this.
Drilling a Hole in Granite Submerged in Water By Use of CO2 Laser
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 119914, ’Drilling a 2-inch in Diameter Hole in Granites Submerged in Water by CO2 Lasers,’ by Toshio Kobayashi, SPE, and Masahiro Nakamura, Japan Drilling Company, and Satoshi Kubo and Makoto Ichikawa, SPE, Japan Oil, Gas, and Metals National Corporation, originally prepared for the 2009 SPE/IADC Drilling Conference and Exhibition, Amsterdam, 17-19 March. The paper has not been peer reviewed.

As part of a fundamental study of rock drilling by laser irradiation, the full-length paper describes laser drilling of a 5.08-cm-diameter hole in granites submerged in water. The laser beams melted the granite surface locally to form small glassy beads. Repetition of this procedure demonstrated that a high-power laser beam propagating in water can be used to generate a hole in rocks.  

Experimental

A 10.6-µm carbon dioxide (CO2) laser was used. The laser had a 5-kW peak-output power, a 5-ms pulse width, a 10-Hz repetition rate, a 250-J pulsed energy, and a 50% duty ratio. The CO2 laser has a ring mode. A laser-irradiation nozzle with a 20-in. focal length was used for irradiation in air and in water. For irradiation in water, a 300-mm3 acrylics chamber was used. A high-speed video camera was placed at the side of the chamber to photograph the dynamic behavior of the formation of bubbles induced by laser irradiation. A rock specimen was placed in the chamber so that the distance from the water surface to the top surface of the granite was 50 mm. The CO2 laser was intermittently irradiated perpendicularly from a muddy-water surface. The irradiated laser beam was absorbed in the water and formed cone-shaped bubbles that had an irregular interface. Because the induced bubbles kept their shape until a subsequent laser beam reached the rock, the laser beam could drill the rock effectively.

Rock Specimens

Inada granite was selected as a rock specimen because the Inada granite is representative of quartz-group minerals and quartz-bearing rocks in Japan. Its K-Ar chronology is 60 Ma. Inada granite often is used as construction materials and experimental materials. The Inada granite contains 33.7% quartz, 32.1% potash feldspar, 30.3% plagioclase, and 3.8% biotite. Physical characteristics of Inada granite are as follows: 180-MPa uniaxial compressive strength, 0.75-MPa split-ting tensile strength, 65-GPa Young’s modulus, 2.63 g/cm3, 0.75% porosity, 0.0167- to 0.0377-J/(g-K) specific heat, and 54.4- to 83.7-W/(m.K) thermal conductivity.

Results and Discussion

In earlier experiments with Inada granite irradiated in air with a CO2 laser, transparent glassy objects crystallized on the walls of the created hole. It was observed that the fused Inada granite could not fully flow out of the hole, solidifying on the bottom to close the bottom of the hole. As a result, a complete hole cannot be created by the laser irradiation in air.
Post-Mortem Analysis of MODUs in Hurricanes Katrina and Rita
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper OTC 20144, ’Post-Mortem Analysis of MODUs in Hurricanes Katrina and Rita,’ by Malcolm Sharples, Offshore: Risk and Technology Consulting and John Stiff, ABSG Consulting, prepared for the 2009 Offshore Technology Conference, Houston, 4-7 May. The paper has not been peer reviewed.

Several hurricanes have passed through the Gulf of Mexico (GOM) resulting in mobile offshore drilling units (MODUs) parting moorings or collapsing, but none have come close to the devastation caused by Hurricanes Katrina and Rita, in August and September 2005. Twenty semisubmersible MODUs suffered significant mooring impairment, and eight jackups were declared total losses (with many more suffering additional settlement and other damage). In the aftermath of these hurricanes, which followed Hurricanes Lili and Ivan, the industry re-examined and upgraded the standards for setting MODUs.  

Overview of Hurricanes Katrina and Rita

In August 2005, Hurricane Katrina moved through the US GOM. Katrina was the second Category-5 hurricane of the 2005 Atlantic season. In September 2005, Hurricane Rita also tracked through the GOM. Hurricane Rita reached Category-5 strength before entering the warm waters of the oil- and gas-exploration regions in the central GOM where it passed over the deeper outer-continental-shelf (OCS) structures as a Category-4 hurricane. Rita weakened to a Category 3 before making landfall along the upper coast of Texas.

Sixteen semisubmersible MODUs were in the vicinity of Hurricane Katrina, with two other MODUs stacked, undergoing repairs. Of these MODUs, five suffered complete mooring failure, two had partial failure, and one incurred limited anchor slippage. Most of the semisubmersibles were on the less-severe west side of the storm track. However, Hurricane Rita passed to the south of most of the semisubmersible MODU fleet leading to more MODUs being exposed to severe conditions. Seven semisubmersibles suffered complete mooring failure, four suffered partial failure, and one had limited anchor slippage.

The route of Hurricane Rita probably was the worst possible regarding the number of jackups exposed. Many of the jackups were in water depths where the storm was greater than the design extremes, and in many cases the storm was greater than the 100-year extreme for the location. During these hurricanes, there were approximately 90 jackups in the GOM. Of those, 25 jackups were impacted by Katrina and 54 were impacted by Rita. Two were a total loss in Katrina, and six were a total loss in Rita. Of those that survived impact, seven were “surprising survivals” in Hurricane Katrina and sixteen were surprising survivals in Hurricane Rita. Of the jackups damaged, but not destroyed, only three independent-leg jackups and two mat-supported jackups needed to return to the shipyard for repair. Five independent-leg jackups and four mat-supported jackups were repaired on location and returned to work.