bluuebunny/crossref_metadata_2025 huggingface dataset:
The Prestige Wreck Fuel-Recovery Project
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 17534, "The Prestige Wreck Fuel-Recovery Project," by R. Hernan, A. del Corral, C. Berenguer, SPE, R. Paez, J. Sparrowe, and J. Moro, Repsol YPF, originally prepared for the 2005 Offshore Technology Conference, Houston, 2-5 May.

This article is an overview of the recovery project to extract the hydrocarbons remaining in the wreck of the Prestige tanker. The ship, carrying approximately 77 000 tonnes of heavy fuel oil, broke up and sank in 3850-m-deep water in November 2002, 240 km off the northwestern coast of Spain. During the sinking, and for a period of several months afterward, a large amount of fuel was spilled, ending up mainly on the shores of Galicia. Repsol YPF, though in no way connected to the vessel or its cargo, was appointed by the Spanish government to recover the fuel remaining inside the wreck. Extraction of the remaining fuel was carried out in 2004 by use of large-volume aluminum shuttles. An innovative core-flow technique was used to extract this extremely viscous fuel (500 kPa·s at the shuttle offloading conditions) from the shuttles and offload it into a floating storage and offloading (FSO) vessel. Finally, bioremediation was used to accelerate the biodegradation of the remaining immobile fuel.

Project Summary

On 19 November 2002, the oil tanker Prestige broke up and sank in two parts. Approximately 37 000 tonnes of heavy fuel was believed to remain in the wreck, which continued leaking. The Spanish government commissioned a permanent solution for stabilizing the wreck and neutralizing its cargo. Potential solutions included the use of shuttle tanks to transport oil from the wreck to a surface container, pumping the oil to the surface by use of a riser system, and enclosing the whole wreck in a sarcophagus.

Fuel viscosity at the wreck conditions was extreme (3 to 4×106 kPa·s), which, at this depth, precluded the use of conventional techniques. Repsol YPF (with technical assistance from BP, Eni, Petrobras, Statoil, and Total) outlined an action plan to be completed in 2003. The plan approved by the Spanish government consisted of the following.

- Develop work-class remotely operated vehicles (ROVs) to operate at 4000 m water depth.

- Seal all remaining leaks.

- Carry out data acquisition on the wreck and its fuel composition and mobility, as well as on the environment and the marine soil, to assist future interventions.

- Test a batch-extraction scheme that used shuttle bags.

- Perform basic engineering studies of confinement solutions as an alternative if the above scheme did not work.

Sonsub was hired as the main contractor, and, in the spring and summer of 2003, it carried out an offshore campaign for the above program to establish the basis for the actual fuel recovery planned for 2004.
Technology Tomorrow: The Chemistry of Carbon Capture and Storage
Authors: Pike Richard
Published: February 2015

Editor's note: This is the third installment of a yearlong series designed to stimulate discussion in research and development. The oil and gas industry faces the prospect of progressively increasing CO2 production because of the presence of CO2 in produced natural gas and the fact that petroleum production is becoming heavier. However, the industry is uniquely positioned to sequester CO2, no matter the source. This article features the perspective of an expert outside the oil and gas industry regarding the challenges associated with CO2 capture and storage. Comments on articles in the Technology Tomorrow series are welcome. Please send any questions, comments, or ideas to vik.rao@halliburton.com.

Evidence linking anthropogenic carbon emissions with climate change is accepted by many experts, and the key challenge now is to act to avert disaster. Countries signed on to the Kyoto Protocol and those that have set more stringent domestic targets are now defining energy policies that balance energy efficiency and energy technologies alongside measures for energy security. In the U.K., the government is currently reviewing its energy policy and is examining a range of policy and technological measures that will secure clean and affordable energy for the long term while meeting the U.K. target of reducing carbon emissions 60% by 2050 (based on 1990 levels). It is widely expected that the U.K. will continue to rely upon fossil fuels for electricity, transportation, and heating for the foreseeable future, and, therefore, it is important that carbon-abatement technologies are employed when feasible.

The chemical sciences have played a crucial role in optimizing energy output from fossil fuels through developments in areas such as combustion chemistry and fuel additives. The chemical sciences will be critical in providing future energy technologies such as batteries, fuel cells, solar power, microgeneration, energy-efficient lighting, new nuclear power and nuclear waste management, and carbon capture and storage (CCS).

CCS is not a new technology. In fact, there are a number of examples of its application around the globe (e.g., in ammonia production). It has been predicted that CCS technologies could reduce carbon dioxide (CO2) emissions from power plants (and other energy-intensive processes such as oil refining and steel and cement manufacturing) by up to 85%. However, the technology will reduce the energy efficiency of power plants significantly and increase the cost of energy production, according to the Intergovernmental Panel on Climate Change (Table 1).
Management: It's Time for an Industry Initiative on Heavy Oil
Authors: Belani Ashkok
Published: February 2015

Last year, five of the 10 largest development projects in the world were going after heavy oil. When oil experts assure outsiders that there are significant petroleum reserves yet to be developed, they are talking about the class of crude that is so difficult to produce, transport, and refine that many companies have stayed away, until now.

What has changed, of course, is supply and demand. Asset managers know they cannot ignore it any longer; if they want to book new reserves, they have to look at heavy oil. There is also some urgency to produce the heavy oil associated with lighter reserves. The reason is transportation. Heavy oil is often blended with conventional crude to make it light enough to flow through a pipeline. If operators wait until the lighter crude is gone, their heavy oil assets may become stranded.

The good news is that heavy oil reservoirs can be huge. What is more, the wells tend to produce at a steady rate and for much longer than conventional wells. Some heavy oil operators producing 100, 000 BOPD expect to maintain that rate for 15 or 20 years. Total recovery of the oil in place can be as great as 70% for certain processes, which is much better than the rate for lighter crudes. While a handful of companies have been producing heavy oil for decades, many more are just entering the game. The knowledge gap between those two groups is large, but even the most experienced players face new challenges.

The Nature of Heavy Oil

Tip a beaker of heavy oil and chances are it will not run out, at least not right away. One definition of heavy oil is any hydrocarbon with a gravity of 22.3° API or below. On the lighter end, that includes oil with the consistency of honey. At room temperature, ultra heavy oil can be as thick as peanut butter. Motor oil has a gravity of approximately 35° API.

Refiners often use API gravity to describe and set the price of heavy oil. For reservoir engineers, however, the more important number is viscosity, because that tells them how well the heavy oil is likely to migrate through the reservoir. Although there is a correlation between gravity and viscosity, the distinction is misleading. Heavy oils with the same gravity can have very different viscosities.

Historically, heavy oil has come from relatively shallow reservoirs. Most are less than 500 m (1,650 ft) deep, but some new plays are as deep as 2700 m (9,000 ft). Even that is not a limit. At greater depths, temperature plays a big role in the ease of production because any oil flows better when it is hot. Keeping heavy oil flowing is the trick. That is a particular challenge in cold climates, or when producing heavy oil from subsea wells.
Overview: Deepwater Exploration and Production (June 2006)
Authors: Barnes John
Published: February 2015

Deepwater oil and gas projects are some of the most challenging of human endeavors. The sheer size of many of these efforts—and the impressive new technologies used—is truly amazing. Deepwater projects also entail great risk, however, and things sometimes do go wrong. Of course, things go wrong on all types of projects, but the deepwater environment itself and the large-scale nature of many projects exacerbate the severity of any problem. Costs can increase to many times the budget, the details associated with implementing new technology can be overwhelming, and schedules easily can slip enough to jeopardize the commercial success of the project.

Some problems are related to project decisions that are made to maintain schedule before all of the needed facts are available. On a complex project, decisions are made that, in retrospect, are clearly wrong. Other problems arise simply as a result of mistakes made by the project management or technical teams. To be successful, the project team must be willing to recognize mistakes as early as possible and take corrective action. Knowledge of how mistakes were addressed on previous projects, both successfully and unsuccessfully, can be invaluable in selecting an appropriate corrective action.

Examining lessons learned from previous projects provides one of the most important methods for improving project execution. Barry LePatner, an attorney testifying before a U.S. House of Representatives Science and Technology Committee on disclosure of information from building failures, made the following observation:

"Good judgment is usually the result of experience. And experience is frequently the result of bad judgment. But to learn from the experience of others requires those who have the experience to share the knowledge with those who follow."

The sharing of project-management lessons learned on deepwater projects, however, is a relatively recent development. Project management is as important to the success of deepwater projects as technology. The continued sharing of project-management lessons learned would help project teams meet the myriad nontechnical challenges associated with deepwater projects.

Deepwater Exploration and Production additional reading available at the OTC Library: www.otcnet.org

OTC 17971 "Albacora Leste Deepwater Field: Improvements on Well Construction," by E. de Melo Sanches, Petrobras, et al.

OTC 17806 "Combined Effect of Flowline Walking and Riser Dynamic Loads on HP/HT Flowline Design," by M.S. Brunner, Technip U.S.A., et al.

OTC 18311 "K2 Topside Facilities—Design Challenges," by F. Colbert, OFD Engineering LLC, et al.

OTC 17655 "The Significance of Gas Hydrate as a Geohazard in Gulf of Mexico Exploration and Production," by M.A. Smith, U.S. Dept. of the Interior, Minerals Management Service, et al.
Characterization of Defects in Coiled Tubing From Magnetic-Flux-Leakage Data
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 100121, "Observations on Characterization of Defects in Coiled Tubing From Magnetic-Flux-Leakage Data," by T.R. McJunkin, K.S. Miller, and C.R. Tolle, Idaho Natl. Laboratory, prepared for the 2006 SPE/ICoTA Coiled Tubing and Well Intervention Conference and Exhibition, The Woodlands, Texas, 4-5 April.

The full-length paper presents observations on use of magnetic-flux-leakage (MFL) data to detect flaws in coiled-tubing (CT) strings. Sixty-six flaws of various shapes and types, ranging from 0.3-mm-deep pits to 9.5-mm-long slots, artificially created in 44.45-mm-outside-diameter pipe, were analyzed. The detection algorithm and the information extracted from the data are described.

Introduction

CT defects reduce CT life and must be detected to prevent costly failures in the field. One method commonly used for CT nondestructive inspection is MFL, where a magnetic field is generated with a coil or permanent magnets and Hall-effect sensors positioned around the CT measure the variation in the field near the CT surface. Flaw characterization is important for failure-prediction models. The size and shape of a flaw influence MFL-signal amplitude and duration and are directly related to expected CT-string life. The full-length paper describes an effective method of detecting flaw signatures in an MFL signal.

Equipment and Processes

A laboratory-scale experimental CT MFL-sensor head was constructed. The coil used to create the field in and around the CT was an 89-mm-long solenoid with a 102-mm inside diameter. One-thousand four-hundred turns of 18-gauge copper wire were wound evenly along the length of the coil. Data presented in the full-length paper were acquired by use of a 5-A direct current in the coil. This current was sufficient to saturate the pipe and permit flaw detection on the inner surface of the CT. Plastic frames, or "shoes," were populated with three ratiometric linear Hall-effect sensors oriented orthogonally in cylindrical coordinates (i.e., radial, longitudinal, and circumferential). Five shoes were distributed circumferentially around approximately one-fourth of the circumference of the CT samples. Artificially created defects were moved past the sensors, with the defect centered approximately on the middle of the five shoes.

Data from the Hall-effect sensors were acquired at a 2000-samples/s rate. A first-order low-pass Butterworth filter with a 100-Hz cutoff frequency was used as a digital filter. The time-series signal was converted into distance vs. amplitude by adjusting for scan velocity and sample rate.
Guest Editorial: What Big Oil Can Learn From Big Blue
Authors: Perrons Robert K.
Published: February 2015

Let's face it: everyone likes to feel special. It is therefore somewhat understandable that decision makers in the energy industry often believe that trends and patterns that have emerged elsewhere in the business world do not apply to the oil patch. "The oil business is different!" they proclaim. "That could never happen to us!"

But sometimes we are not exempt from the immutable forces that shape the rest of the business community. Decidedly unoriginal concepts such as supply and demand do tend to be reliable predictors of oil and gas prices, and prospective investors scrutinize energy companies' profit and loss statements as closely as those from any other industry. It therefore follows that we might be able to learn from other sectors from time to time. The evolutionary history of IBM—frequently referred to as "Big Blue" in the business press—may offer just such an opportunity.

The oil and gas sector historically has been very slow to develop and adopt new technologies, and relative investment in R&D by Big Oil traditionally has been only a fraction of that spent in other industries. But the industry is being forced to change. Future hydrocarbon resources—particularly in non-OPEC countries—will tend to be deeper, harder to find, and in environments that are significantly more difficult to access. There can, therefore, be little doubt that technology will play a pivotal role in the success or failure of tomorrow's oil and gas firms.

This sharper focus on technology is shaking up the strategic fundamentals of our industry. Many years ago, when innovation was less critical, much of the oil and gas sector's technology came in the form of know-how and experience that was often uncoded, nonverbalized, and embedded in organizational routines. A country with hydrocarbon reserves usually enlisted the assistance of international oil companies (IOCs) to gain access to engineers who collectively held the knowledge required to turn the country's energy resources into revenue. The know-how required to achieve this end was both difficult to reproduce and hard to get from any source other than a handful of firms.

A Shift to Science

As the industry has been forced to reach for more technically ambitious reserves, however, this uncoded knowledge is giving way to technologies that are based less on experience and more on hard science. While decisions might have been made a generation ago with rules of thumb and gut instinct, data now reign supreme. Reservoirs are modeled in three or four dimensions with high-end computers not unlike those used by NASA, and the entire production system can be monitored by "smart" sensors that allow engineers to observe various aspects of its performance. Rules of thumb will probably always be handy for engineers, but today's oil and gas technologies are frequently too complex for unaided human judgment.
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.
Building Bridges: Work to Advance Use of Reserves Guidelines Continues
Authors: Cobb Bill
Published: February 2015

President's column

Much has happened since the Petroleum Resources Management System (PRMS) was completed in March 2007, providing updated definitions and a related classification system for petroleum reserves and resources. This landmark document reflects advancements in technology, the international expansion of the industry, and the increasing role of unconventional resources, as well as incorporating recommended best practices identified in other international petroleum and mineral classification systems.

SPE is proud to have led the effort that produced a set of technical guidelines that can be adopted by oil and gas companies to better manage their business and that can be consistently used in estimating reserves by international financial, regulatory, and reporting bodies. The PRMS is the result of more than 2 years of collaboration by SPE, the World Petroleum Council (WPC), the American Association of Petroleum Geologists (AAPG) and the Society of Petroleum Evaluation Engineers (SPEE), with considerable input from the industry at large and other external organizations.

Our work was not over with the completion of the technical definitions. Intense education and training are required to support consistent use by the industry and other financial and regulatory bodies. I want to give you a brief report on the progress that has been made to educate important stakeholders about the new system.

In December, the U.S. Securities and Exchange Commission (SEC) announced it would seek public comment on possible revisions to disclosure requirements for oil and gas reserves, citing the extent and nature of changes that have occurred in the oil and gas industry in the nearly three decades since the commission first adopted its oil and gas disclosure rules. SPE's Oil and Gas Reserves Committee, among many others, provided comments to the SEC that recommend the use of PRMS as the technical basis for a reporting process. It is notable that the overwhelming majority of comments made to the SEC that addressed the PRMS recommended using it in some form. All of the comments can be viewed on the SEC website at http://www.sec.gov/comments/s7-29-07/s72907.shtml.

To help energy professionals apply the definitions, the Oil and Gas Reserves Committee and SPE's Reserves Education Committee are collaborating on an applications manual for the PRMS that will include detailed discussion and examples of use. Companies have been asked to submit examples and case studies from petroleum provinces worldwide.

The applications manual will be a valuable, comprehensive, and long-lasting reference document. The manual will be consistent with the PRMS, update and incorporate the content of the 2001 "Guidelines for the Evaluation of Petroleum Reserves and Resources," and expand the content to address the full spectrum of hydrocarbon evaluation situations experienced by industry. It will be available in the reserves section of www.spe.org.
Deepwater Gulf of Mexico Development Challenges
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 113011, "Deepwater Gulf of Mexico Development Challenges Overview," by Frank Close, Bob McCavitt, SPE, and Brian Smith, Chevron North America E&P Company, prepared for the 2008 SPE North Africa Technical Conference and Exhibition, Marrakech, Morocco, 12–14 March. The paper has not been peer reviewed.

A high-level review of recent development challenges for the deepwater and ultradeepwater fields in the Gulf of Mexico (GOM) is presented. How these challenges were addressed and how Chevron plans to address even-more-demanding challenges in the future are summarized.

Introduction

Operating in all areas of the world presents many challenges. The GOM, although a long-established and prolific hydrocarbon basin, has, over the past 15 or so years, evolved into an arena where operations challenges have been encountered in ever-increasing water depths further from the coast. These challenges include seismic acquisition, drilling operations, completion operations, subsea operations, production operations, logistics support, and many more. Fields are being developed in the GOM that pose the greatest engineering challenges that the company has addressed. It is anticipated that developing resources in water depths of 10,000 ft will be fundamental to the continued long-term success of the GOM as one of the world's major producing basins.

Challenges

Many of the prospects in the ultradeep-water GOM have a unique combination of challenges. The combination of deep water (to 10,000 ft water depth), high pressure (>10,000 psi shut-in pressures), high temperatures (>350°F bottomhole temperature), problematic formations (e.g., salt or tar zones), deep reservoirs (more than 30,000 ft true vertical depth), tight-sandstone reservoirs (<10 md), and fluids with extreme flow-assurance issues separates many GOM deepwater and ultradeepwater wells from deepwater and ultradeepwater wells in other parts of the world.

As Fig. 1 shows, much of the prospective GOM deepwater exploration area is in 4,000 to 10,000 ft of water. Most of this area is in a subsalt environment, with salt canopies ranging from 7,000 to 20,000 ft thick and target depths ranging from 25,000 to 35,000 ft true vertical depth.

The vast salt zones inhibit deep-seismic resolution, presenting great challenges in exploration, appraisal, and development operations. Understanding the geology associated with the massive salt and, more importantly, the quality of imaging below the salt is paramount.

A key technology being developed to address this challenge is wide-azimuth-towed-streamer technology. This technique allows better subsurface imaging for effective reservoir management and will dictate well placement and number of wells required to drain the reservoir optimally. The true vertical depths of some deepwater wells are in excess of 34,000 ft. Fig. 2 shows some of the drilling challenges.
Dual Activities Without the Second Derrick
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 112869, "Dual Activities Without the Second Derrick - A Success Story," by Tamara Webb and Kasim Selamat, SPE, Murphy Sabah Oil; and Bill Fletcher, SPE, Seadrill, prepared for the 2008 IADC/SPE Drilling Conference, Orlando, Florida, 4–6 March. The paper has not been peer reviewed.

Kikeh field is 120 km from Labuan, offshore Sabah, Malaysia. The field, in 1330-m water depth, is the first deepwater development in Malaysia and consists of subsea and surface-piercing-articulated-riser (SPAR) development wells. Considering the wide scope of completion work outlined in the program, a detailed work assessment was conducted focusing on processes for which offline activities could be conducted safely and efficiently. As a result, at least seven completion-related activities were identified. During the first batch of SPAR completions, which involved five wells, several activities were completed offline successfully, allowing the rig to be used for critical-path operations.

Introduction

Completion operations played a major role in the overall Kikeh deepwater development, with 25% of the total field development and 58% of the capital expenditures attributed to well completions. Early focus was on timesaving opportunities that could be performed off of the rig's critical-path operations. Many factors were assessed including rig capabilities, SPAR capabilities, and personnel. The need for extensive planning and proper communication was investigated, as were completion activities and equipment design.

The scope of SPAR-completion activities was divided into nine phases: production tensioner and riser installation, wellbore cleanout, tubing-conveyed perforation, lower-completion installation, upper-completion installation, tree installation, riser-annulus dewatering, well cleanup, and testing. In addition, several completion-phase activities were identified: cement- and riser-evaluation logging and installation/commissioning of the umbilicals and flowline jumpers.

During the first completion campaign, the following eight activities were consistently performed off the rig's critical-path operations. The work description and how the work objectives were achieved are detailed in the full-length paper.

Offline Activities

Tubular Makeup and Racking Back. Rig design contributed to the success of offline activities. The offline-activities cantilever (OAC), shown in Fig. 1, consists of two dedicated mouse holes capable of handling various ranges of pipe and an overhead crane mounted in the derrick, which accommodated racking tubulars on both the driller side and the off-driller side of the derrick. The OAC provides adequate space to set up a power tong inclusive of a torque turn system.