bluuebunny/crossref_metadata_2025_split huggingface dataset:
Techbits: Report of the SPE Gulf of Mexico Deepwater Drilling and Completions Advisory Summit
Authors: JPT staff _ 
Published: February 2015

Techbits
On 17–18 March 2011, SPE sponsored a two-day summit to answer questions proposed by a US National Academy of Engineering/National Research Council (NAE/NRC) panel examining US Gulf of Mexico deepwater operations. The NAE/NRC committee, which has been asked by the US Secretary of the Interior to identify ways of reducing the risk of incidents similar to the Macondo well blowout from occurring in the future, prepared a list of questions for consideration by the summit participants.
This SPE Technology Summit, titled “Gulf of Mexico Deepwater Drilling and Completions Advisory Summit to NAE/NRC Committee,” was attended by oil and gas industry professionals from operating companies, service companies, consulting companies, and academia. The participants were accepted based on their industry experience, and were explicitly asked to contribute their own views as engineers, not as advocates for their organizations.
Summit participants met in five breakout groups and as a whole to discuss the questions. The following are excerpts from the report, organized by session topic. The complete report is available online at www.spe.org/industry/hse.
Section 1: Oversight
What are the potential values and feasibilities of using a separate path of reporting and oversight for cost and schedule versus decisions affecting the integrity and safety of the well?
Summit participants do not believe there is value in using a separate path of reporting and oversight. Safety cannot be separated from operational decisions. Good safety practices and good business practices (including cost and schedule) go hand in hand. The industry has reduced occupational injuries in the past by integrating operations and safety reporting and oversight. Further improvements can be made in well integrity and process safety by applying similar integration principles.
To what extent should the oversight be performed by the companies, independent third parties (e.g., classification societies), or regulators?
All three parties need to be involved in various levels of oversight. Company oversight should include a quality assurance process. The company is ultimately responsible for its safe operations. Independent third parties (both external and internal) have a role in providing specific expertise, broader industry perspective, and objectivity. Government regulators have a critical role in ensuring that all parties meet compliance obligations.
Connecting R&D with the Goals of E&P
Authors: Rassenfoss Stephen 
Published: February 2015

When researchers gathered for the SPE 2011 Research & Development Symposium in June, the topics ranged from the tiniest particle to the biggest oil fields, with an underlying theme of effectively managing an unpredictable process.
During the three-day meeting in Austin, Texas, there were some common themes, including the importance of making long-term commitments, reaching out to original thinkers, encouraging collaboration, developing the next generation of talent, and focusing on the goals of the enterprise.
Petrobras’ broad research program is focused on developing the country’s rich reserves, which present many technical challenges, and a research center it hopes will remain after the oil boom has passed. “Through these technologies, we are targeting a step change in how we explore and produce oil and gas, and a step change in how these technologies are developed,” said Carlos Tadeu Da Costa Fraga, executive manager of research and development center at Petrobras.
In the keynote address, Scott Tinker, director of the Bureau of Economic Geology at the University of Texas at Austin, offered a detailed discussion of what it takes to create and run an industry-supported energy research program.
The speech described the creation and operation of the Advanced Energy Consortium (AEC), where Tinker is also director. Its goal is to discover something as useful as seismic or well logging, and so small it can be measured in nanometers. Bringing together 10 companies to fund the consortium, top research talent, and the legal and institutional framework took about four years before the research could begin.
The operation of the AEC is built on a high level of interaction with researchers at 25 institutions around the world. Every other month, it holds an update meeting on each of the 30 projects. Once a year, a decision is made on whether to continue, wind down or redirect each of the projects.
“There is a lot more oversight Tinker than the researchers are used to,” said Tinker. “Most have come to appreciate the feedback and interaction when faced with difficulties, and they understand that some research ideas are not working out.”
Each year about 20 percent of the projects are phased out, and another 20 percent are asked to go in another direction. “Any time you kill a project, it is hard,” said Tinker. He added that when it comes to research, generally, there is a need for more critical thinking about what is the best use of resources.
Australia's Quiet Success Story: The Riches of Bass Strait
Authors: Beckwith Robin 
Published: February 2015

Major liquefied natural gas (LNG) developments tend to grab Australian energy headlines, with Shell’s Prelude floating LNG, Chevron’s Gorgon and Wheatstone, Woodside’s Pluto, Santos’ Gladstone, ConocoPhilips’ Darwin, and Inpex’s Ichthys projects prominent among them. However, to be a net exporter of natural gas—currently the world’s fourth largest (after Qatar, Malaysia, and Indonesia) on course to achieve status as the second largest possibly by 2020—Australia must first meet the needs of its own population. With a vast area of 7.75 million sq km, whose cities tend to hug the nation’s 25,760 km coastline, the country faces continual economic challenge to be efficient in delivering both oil and gas to its 21.8 million people. Playing a critical role in such delivery are the oil and gas riches first identified in 1965 in the hostile waters of Bass Strait.
Throughout the 42 years following first oil and gas production, Bass Strait has served Australia’s economy as the source of almost two-thirds of its oil and approximately 30% of its gas. The rock underlying its relatively shallow but notoriously rough waters continues to yield resources, with several projects—the largest being the Esso-BHP Billiton joint venture’s Kipper Tuna Turrum Project and Origin Energy’s BassGas Project—extending natural gas and liquid hydrocarbon supplies to Australia’s southeastern states of Victoria, Tasmania, and New South Wales for several decades, well beyond the strait’s originally projected 35-year life span.
The AUD 4.4 billion Kipper Tuna Turrum Project in the offshore Gippsland Basin is currently under development, with pipelines, subsea equipment, and jackets installed throughout this year, and final infrastructure installation, tie-in activities, and start-up due in 2012–2013. Operational since mid-2006, the BassGas Project, at an estimated cost of AUD 750 million, centers on the Yolla field in the Bass Basin, in waters administered by Tasmania.
The Flow of History
In 1798–1799, surgeon and explorer George Bass traveled through and delineated the strait subsequently named after him. Two hundred and thirteen years later, Australia’s Bass Strait reached the 46th anniversary of another discovery: natural gas from its first well, the Barracouta I, drilled by the Glomar III, which withstood the brunt of the strait’s legendary hostile waters to find the resources. Since 1969, the channel of water—which lies between the state of Victoria, to the north on the mainland, and the island state of Tasmania to the south, and between the Indian Ocean to the west and the Tasman Sea to the east—has yielded more than 4 billion bbl of crude oil and more than 7 Tcf of natural gas.
Navigating the Gulf of Mexico Hurricane Season: Past Lessons and a Path Forward
Authors: Braswell Gentry 
Published: February 2015

In a body of water commonly traveled by powerful cyclones during hurricane season, weather challenges in the US Gulf of Mexico (GOM) must be met with equally formidable technology.
Such technology includes the dynamic positioning of vessels and disconnectible transfer systems; streamlined evacuation, abandonment, and plugging procedures; platform mooring, floaters, and risers; rig and module tie down; post-storm structural inspection; and weather-savvy structure design.
Integrity Performance and Data
The GOM platform design criteria have become more stringent following the major storms of the past several years. The impact of these storms on oilfield infrastructure has been greater on the GOM continental shelf, where development began in 1947, than on deepwater regions where facilities’ installation began in 1995.
Today, shelf development is in decline and deepwater infrastructure is fundamentally different, said Mohammad Rahman, lead analyst for the Gulf of Mexico at Wood Mackenzie. Deepwater platforms are too deep for platform jackets and rely instead on mooring cables for which weather design specifications regarding strength and number have recently become stricter, he said.
For example, regarding the comparison of fiber rope mooring systems’ performance testing methods, modeling with Young’s Modulus by Cross Sectional Area with an upper- and lower-bound linear fiber rope stiffness model, compared with modeling the true nonlinear stiffness behavior exhibited by fiber ropes, was presented in paper OTC 20838-MS, “Fiber Rope Mooring Assessment-API RP 2SM Piecewise Linear Stiffness Vs. Nonlinear Stiffness With Integrated Permanent Rope Elongation (E.H. Zimmerman, Delmar Systems, et al, 2010).” The latter nonlinear method also incorporates a function to capture permanent or nonrecoverable rope elongation caused by a hurricane, and its impact on the performance of a mooring system.
“By modeling the true nonlinear stiff-ness and being able to capture the permanent nonrecoverable elongation of fiber mooring ropes in a mooring analysis, the designer can more accurately assess the vessel motions during a storm event and more effectively plan component lengths such that retensioning operations will not significantly impact the facility’s ability to operate,” the paper said.
Bringing Frontline Workers Into the 21st Century
Authors: Murray Phil 
Published: February 2015

Management
As the oil and gas industry grapples with the challenge of understanding how best to react to the lessons of Macondo, there is growing recognition that the answer to the wider challenge of fundamentally improving the way the industry operates is not a simple one.
“The Chief Counsel’s Report: National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling Report to the President” was direct in stating that Macondo was more than a series of disparate technical failures, but also an overarching failure of management. “Ultimately, the companies placed undue reliance on timely intervention and human judgement in light of their failure to provide individuals with the information, tools, and training necessary to be effective,” it said.
As a result, industry safety continues to be at the epicentres of many discussions and debates post-Macondo. This was reflected at this year’s Offshore Technology Conference (OTC), where regulators, operators, contractors, academics, and consultants offered insights into the underlying issues behind the tragic event. Some of the key questions and observations from the debate and discussion at OTC included the following:
Should the regulatory environment provide more prescription or more goal setting?
Has the industry’s successful focus on personnel safety created a process safety blind spot?
Frontline operations need to improve across the globe.
Greater engagement of the whole workforce is needed in operational risk management.
It is clear that ongoing challenges remain with risk assessment practices and, more importantly, how they affect decision making. Despite years of focus by the industry, the general consensus is that an opportunity remains to significantly improve operational risk management. That said, managing operational risk is a complex task involving a number of interrelated processes and issues.
One of the key areas where performance and operational risk management can be significantly improved, but has often been overlooked or where little attention is paid, is front-line work execution. How can we help frontline workers make better operational decisions to deliver safe and efficient operations?
What is Missing
Historically, significant investment has been made in people, processes, and systems in two key operational areas: management, and planning and process control. However, a key aspect of operations is often overlooked: work execution, where frontline workers routinely intervene in plant operations. This area is where safety and environmental performance is delivered by people with wrenches in their hands. Typically frontline workers depend upon a plan developed onshore that can never be complete as it cannot predict the dynamic nature of frontline work. As a result, the risk analysis and management during the planning phase do not account for the ad hoc nature of frontline work during the execution phase.
Henry Subsea Development - Challenges and Solutions
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 133631, ’Henry Subsea Development - Challenges and Solutions,’ by Stephen Henzell, SPE, WorleyParsons Services Pty. Ltd., and Andrew Glucina, Santos Ltd., originally prepared for the 2010 SPE Asia Pacific Oil & Gas Conference and Exhibition, Brisbane, Australia, 18-20 October. The paper has not been peer reviewed.
The Henry and Netherby gas fields are in Victorian waters in southeast Australia. They have been developed by extending the Casino production system which comprises two subsea wells in the Casino field producing by pipeline to an onshore gas plant. The entire development is subsea. During the Casino design, provisions were made for future extension of the production system. The full-length paper discusses the provisions made and their effectiveness during the expansion project.
Introduction
The Henry gas development has developed the reserves of the Henry and Netherby reservoirs by extending the existing Casino subsea-production system. The Casino, Henry, and Netherby gas fields are approximately 250 km southwest of Melbourne. The Casino reservoirs began production through two wells in January 2006. Henry and Netherby reservoirs began production in February 2010.
Casino Production System
The Casino production system currently comprises four subsea wells, Casino 4, Casino 5, Henry 2, and Netherby 1. The subsea wells are arranged in a daisy-chain configuration. Each subsea well ties into the pipeline through a short 150-mm-diameter flowline approximately 40 m in length at a tee in the pipeline. The pipeline is routed to pass near each well.
The pipeline has provision for future wells along the pipeline route. The last 5 km of the pipeline extend beyond the Netherby-1 tee to the Pecten East field area. This section of the pipeline currently is suspended, waiting for successful drilling of an appraisal well. The 300-mm subsea pipeline is approximately 55 km in length, laid in two separate sections with a tie-in point between the two at the Casino-4 pipeline-end module (PLEM). The pipeline reaches landfall by a horizontally directionally drilled (HDD) section crossing the shoreline. The subsea pipeline is terminated onshore at the HDD exit in the mainline-valve (MLV) site. The 300-mm onshore pipeline continues approximately 12 km from the MLV site to the Iona gas plant (IGP), where raw gas is processed into export-quality gas and stabilized condensate.
Subsea Water Treatment Comes of Age
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 21578, ’Subsea Water Treatment Comes of Age,’ by David Pinchin, SPE, Well Processing A/S, originally prepared for the 2011 Offshore Technology Conference, Houston, 2-5 May. The paper has not been peer reviewed.
This subsea seawater-treatment system has undergone several phases of development since its inception in 2002. It works by extracting water from the seabed area (where there are inherent advantages such as space, stable temperatures, lower degree of bacterial concentration, and distance from platform discharges). A combination of residence time within a “still room,” two steps of electrochemical disinfection, and chemical dosing are implemented to achieve disinfection and solids reduction.
Introduction
Water injection (waterflooding) is by far the most used method of increasing oil recovery from an oil reservoir. Water quality is an important factor for maximizing sweep efficiency (displacement of oil) during waterflooding and also preventing reservoir souring. Key objectives of seawater-treatment plants are therefore to minimize the blocking of reservoir pores (e.g., with solids, biomass, and scale) and to control reservoir souring.
The full-length paper describes a subsea seawater-treatment system that is seen as filling the “missing link” to the already proven technology of “raw” seawater injection on the seabed by subsea pumps. To be accepted as a viable water-treatment process, it must be capable of providing at least the same level of reservoir protection as afforded by a topside seawater-treatment plant.
Subsea Treatment System and Testing
The subsea treatment unit comprises several equipment items assembled in such a way as to maximize solids removal and disinfection of the seawater. The process uses the seabed environment and makes use of its beneficial effects. A still room is used to isolate the water to be treated from external conditions (e.g., storms and tidal movements). The inlet compartment is designed to allow for a good degree of solids settling with sufficient density to drop out. The water then is chlorinated by electrolysis as it transfers to a second compartment where it is afforded a long residence time to allow the chlorine reaction to take place and to allow further solids settling. The water exiting the still room then flows through a hydroxyl-radical generator where a final oxidation process takes place. The treatment unit therefore generates its own treatment chemicals by electrolysis and requires only a combined power/control signal interface cable. For the testing, a submerged lift pump was used to induce flow through the subsea treatment unit and up to an onshore sampling/control container.
Technology Focus: Health, Safety, Environment, and Social Responsibility (August 2011)
Authors: Garland Emmanuel 
Published: February 2015

Technology Focus
Offshore-drilling safety and oil-spill prevention and response have taken the lead in discussions, worldwide, as a consequence of the Macondo accident last year. Cap and containment became new key issues. Many initiatives have risen around the world; everybody fears that such an accident may happen in their backyard, if not in the center of their home. Many reports have already been published, and many more are expected to be issued in the coming weeks or months. There has been extensive discussion on this topic at all SPE major conferences this year.
But a major accident does not write the whole story, nor does it stop the need for oil and gas. We should not forget that there are many more issues to be addressed by the upstream oil and gas industry. The industry is committed to improve its health, safety, and environment performances.
A list of all health, safety, environment, and social responsibility topics that should be considered these days would be too long and may not be useful. To mention a just a few: safety culture, occupational health, security, asset integrity, naturally occurring radioactive material, aging installations, produced-water discharges, chemicals used and discharged, remote sensing (satellite imaging), emission of greenhouse gases, energy efficiency, shale gas, social impact, local content, and sustainable development.
I stated last year that the industry—at least petroleum-industry professionals—needs to focus more on technology. We need more-efficient tools, pieces of equipment, and models. I reiterate the same view this year. It is the core for improvement. It is our license to operate that is at stake.
Health, Safety, Environment, and Social Responsibility additional reading available at OnePetro: www.onepetro.org
SPE 135004 • “Achieving Sustainable Incident-Free Operations Through Managing the Human Factor: A Success Story of Applying E-Colors” by Eli R. Barakat, SPE, Chevron, et al.
OTC 21695 • “No-Solvent Oil-in-Water Analysis—A Robust Alternative to Conventional Solvent-Extraction Methods” by Dale F. Brost, Turner Designs Hydrocarbon Instruments, et al.
OTC 22009 • “Satellite-Based Ice and Iceberg Monitoring for Offshore-Engineering Design and Tactical Operations” by C. Randell, C-CORE, et al.
OTC 21515 • “Deepwater Archaeological AUV Surveys and Photo Capabilities” by Robert A. Church, C & C Technologies, et al.
SPE 136576 • “Optimizing Stakeholder Communication Through Institutional and Community Focal Points To Foster a Stable Operating Environment” by Robert Hirst, Yemen LNG Company, et al.
SPE 142803 • “Good Practice in Controlling Employees’ Exposure to Noise and Vibration in the Oil and Gas Industry” by Bruce Appleton, Health & Safety Executive, UK.
Frigg Decommissioning: HSE
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 21712, ’Frigg Decommissioning - HSE,’ by Bjorn Oscar Tveteras, Total E&P Norge A/S, originally prepared for the 2011 Offshore Technology Conference, Houston, 2-5 May. The paper has not been peer reviewed.
The decommissioning of large North Sea platforms gives rise to significant health, safety, and environmental (HSE) challenges. These include a high level of work activity, numerous lifting operations, and work in an exposed area, all of which take place on a platform where the layout rapidly changes from day to day. Hazardous materials, such as asbestos, scale, and mercury, need to be removed and must be handled in a safe manner.
Introduction
The Frigg and manifold-and-compression platform 01 (MCP01) Cessation Project is the largest decommissioning project undertaken in recent years and includes removal of six topsides, three steel jackets, and sealines, with a final disposed-of weight of 87 000 tonnes. Different methods have been applied, from single and module-based lifts to “piece small” dismantling and removal.
The Frigg field was a gas field in the North Sea, on the border between Norway and the UK. The field was developed with three installations in the Norwegian sector, a drilling and production platform, a treatment and compression platform (TCP2), and an unused steel substructure damaged during installation in 1974. Three other installations were in the UK sector, a treatment platform (TP1), a concrete drilling platform (CDP1), and a living-quarters platform. The platforms were installed in the period 1974–77. The produced gas was transported to St. Fergus in Scotland, through the Frigg pipeline, passing through MCP01 at the midpoint of the pipeline. The Frigg field production was shut down in 2004, with decommissioning starting in 2005 after cleaning of the process equipment/utilities and removal of most loose hazardous wastes. The Frigg field was the first large field to be fully shut down and decommissioned in the Norwegian sector of the North Sea.
Three Frigg field substructures (TCP2, TP1, and CDP1) were made of concrete while the other three substructures were steel jackets. MCP01 also was made with a concrete substructure. None of the substructures have been used for storing crude oil. The concrete substructures were not designed and built for removal, and the assessment of the alternatives for removal and onshore disposal, or partial removal through cutting of the substructure, revealed too high a risk and uncertainty.