bluuebunny/crossref_metadata_2025_split huggingface dataset:
Technology Focus: Subsea Technology (August 2012)
Authors: Skeels Brian 
Published: February 2015

Technology Focus
The post-Macondo era is starting to write a new chapter in subsea history. Subsea is still one of the more popular development methods offshore, but the reservoirs being tapped are becoming more complex and more difficult to interpret remotely than ever before, with regulatory authorities scrutinizing and challenging the norm of operations and surveillance. To add to the mix, alternative petroleum sources (such as shale gas and shale oil) are entering the marketplace to compete for market share. Recent technical papers are falling into the following two camps in response to these drivers:
Increasing improved oil recovery (IOR) from more-complicated reservoirs remotely subsea but having to do it at a lower cost or in a technically clever manner to compete with a burgeoning market influx from alternative sources
A renewed vigor toward remotely operated vehicles (ROVs), performing more intervention tasks for IOR beyond the traditional hardware performance or assistance in installation or observation
IOR continues to be the engine of recent subsea-technology development as it grows and matures. But, it is the second camp that took me by surprise. ROV technology improvements have been plodding along at a modest pace because of the economic pressure of a commodity-driven service market. Modest revenues could not support step-change technology investments. However, the IOR market appears to be the source of renewed interest in expanding ROV technology. IOR needs more of a hands-on ability to continue its technology growth and has turned to ROVs for the care and feeding of subsea processing.
So, this crop of technical papers reflects the expected and the unexpected in sub-sea technology.
Recommended additional reading at OnePetro: www.onepetro.org.
OTC 23317 Improvements to Deepwater Subsea Measurements RPSEA Program: ROV-Assisted Measurement by E. Toskey, Letton-Hall Group
OTC 21324 Introduction to Remotely Operated Vehicle Assisted Subsea Sampling by Christopher Mancini, Oceaneering International, et al.
SPE 152188 BC-10: The First Successful Replacements of Caisson ESPs in Deepwater Brazil by David Harris, Baker Hughes, et al.
OTC 23178 Pazflor SSPS Project: Testing and Qualification of New Technology—A Key to Success by Steinar Eriksen, FMC Technologies, et al.
OTC 23218 High-Pressure/High-Temperature-Sensor Development and Qualification by J.E. Hall, Letton-Hall Group
Deepwater Well Operations Could Benefit From Advances in Space Robotics Technology
Authors: Wilson Adam 
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper OTC 22989, ’Space Robotics Technologies for Deep Well Operations,’ by Hari Nayar, Khaled Ali, Andrew Aubrey, Tara Estlin, Jeffery Hall, Issa Nesnas, Aaron Parness, and Dean Wiberg, Jet Propulsion Laboratory, California Institute of Technology, prepared for the 2012 Offshore Technology Conference, Houston, 30 April-3 May. The paper has not been peer reviewed.
A number of similarities exist between applications in space and those in the oil and gas industry. In both cases, systems are deployed at remote locations with limited access for intervention, maintenance, or repair. The operational environments are often hostile, with harsh temperatures and pressures and corrosive materials. Reliability of systems is extremely important in space and in the oil and gas industry. Operations in the respective environments have high risk, and failures can be catastrophic.
Introduction
As the number of wells in remote and hazardous environments increases, the technologies to explore, drill, produce, and handle accidents associated with them need to evolve to address the increased complexity and difficulty. Dependence on robotics technologies and more-sophisticated instruments is increasing. Enhancing existing systems with greater intelligence, autonomy, and reliability should help relieve human operators of the tedious and time-consuming aspects of operations. More-precise data from new instruments, improved models of environmental conditions, more-capable actuators, and greater sensory perception of these remote environments can extend operational capabilities, improve safety and reliability, reduce the environmental impact, and reduce costs of operations.
Space Robotics Technologies
Science and Instruments. The Jet Propulsion Laboratory ( JPL) draws on decades of development of instruments and sensors that have been deployed successfully to planetary surfaces as in-situ instruments and to the far reaches of our solar system. The technical requirements for in-situ instruments often push the limits of engineering capabilities for operation in these harsh environments. Thus, the technological solutions often redefine the state of the art, which helps ensure efficient operation in the operating environment.
JPL’s design of science instruments and sensors for unique planetary-surface environments enables translation of engineering heritage to capabilities necessary for extreme terrestrial environments. Such stringent environmental requirements include wide ranges of operating temperatures, pressures, humidity, and corrosive conditions. Just as important to the robust design and engineering of planetary instruments is minimization of mass and power for every flight instrument. Thus, the small size and low power demand necessary for deployment on autonomous underwater vehicles (AUVs) are identical to the engineering goals for planetary instruments.
Separation Technology Shrinks To Fit Subsea Development in Deep Water Better
Authors: Wilson Adam 
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper OTC 23223, ’Compact Separation Technologies and Their Applicability for Subsea Field Development in Deep Water,’ by A. Hannisdal, R. Westra, and M.R. Akdim, SPE, FMC Technologies; A. Bymaster and E. Grave, SPE, ExxonMobil; and D. Teng, Woodside Energy, prepared for the 2012 Offshore Technology Conference, Houston, 30 April-3 May. The paper has not been peer reviewed.
Deepwater discoveries have driven the development of new compact separation technologies, a core aspect of subsea processing. Compact separators are much smaller than conventional separators and have the potential to significantly reduce capital expenditure for deepwater developments. Unfortunately, reducing the size of separators generally reduces the separation performance and the ability to handle changes in flow rate and composition. Therefore, it is essential to find an acceptable balance between the realized reduction in overall capital expenditure and reduced tolerance to changing conditions.
Introduction
Value Drivers for Subsea Gas/Liquid Separation. Subsea gas/liquid separation has proved to provide strong business incentives with enabling capabilities, including (1) more-efficient liquid boosting, (2) longer-range gas compression from subsea to onshore, (3) cost-efficient hydrate management, (4) effective riser slug depression, and (5) access to challenging field developments that otherwise would be abandoned or not developed because of their remote location, harsh conditions, longer tie-back requirements, or low reservoir drive.
Compact Separation and Available Technologies. The motivation for making compact separators is to improve project economics. Large vessels for deep water are heavy and affect the overall cost of the subsea station. Retrievability of separators is affected by module weight and the availability of installation or intervention ships, which can affect project economics.
Reducing the size of separators and their control volume generally reduces the separation performance and the ability to handle changing flows. Even if compact and ultracompact separators minimize the capital expenditure for the subsea station and increase the availability for retrieval, the risk of nonconformance with separation requirements is increased, especially under slugging conditions. Consequently, the risk for loss of revenue because of reduced separation performance is increased compared with that for a large separator.
Currently, deepwater subsea separation and boosting applications have been met only by electronic- submersible-pump (ESP)/caisson technology. The caisson is a tall separator that is installed in a dummy well. The system has a tangential inlet to a tall narrow separator that accommodates slugs, provides surge volume for the separated production fluids, and supports the ESP.
Real-World Application of the Bow-Tie Method
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 154549, ’Lessons Learned From Real-World Application of the Bow-Tie Method,’ by Gareth Book, Risktec Solutions, prepared for the 2012 SPE Middle East Health, Safety, Security, and Environment Conference and Exhibition, Abu Dhabi, 2-4 April. The paper has not been peer reviewed.
Also known as barrier diagrams, bow-tie diagrams provide an understandable visualization of relationships between the causes of business upsets, the escalation of such events to a range of possible outcomes, the controls preventing the event from occurring, and the preparedness measures in place to limit consequences. Preventive and mitigating measures are linked to tasks, procedures, responsible individuals, and competencies. This crucial connection between risk controls (whether hardware or human intervention) and the management system ensures ongoing effectiveness.
Introduction
The primary motivation for the use of bow-tie diagrams was to seek assurance that fit-for-purpose risk controls were consistently in place throughout all operations worldwide. Their use has spread between companies, industries, and countries and from industry to regulators. This paper aims to demonstrate the practical uses and benefits of this versatile tool, which can be used to qualitatively assess and to demonstrate control of all types of risk in many industries and business sectors. The complete paper details an example case.
Bow-Tie Method
The bow-tie method shown in Fig. 1 provides a readily understood visualization of the relationships between the causes of business upsets, the escalation of such events, the controls preventing the event from occurring, and preparedness measures to limit the business effects. In its most common use, the ultimate aim is to demonstrate control of health, safety, and environmental (HSE) hazards; therefore, it is first necessary to identify those hazards requiring bow-tie analysis. Once hazards have been identified, the bow-tie method can be applied to assess risks further and provide a framework for demonstrating effective control. Typically, bow ties are developed by asking a structured set of questions that build the diagram in a step-by-step fashion, detailed in Figs. 2 through 4 in the complete paper.
Applying the Technique. Development of the bow-tie diagrams and critical tasks should be carried out in a structured manner to obtain quality information and best represent the actual risk-control arrangements. Fig. 2 summarizes an effective building process, which has been developed and refined through experience with a variety of companies, industries, and work groups.
Lessons Learned Following Macondo - Safety Enhancement
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper OTC 23436, ’Lessons Learned Following Macondo - Safety Enhancement on the US Outer Continental Shelf,’ by J.G. Lantz, P.E. Little, J.P. Nadeau, and J.D. Reynolds, US Coast Guard, prepared for the 2012 Offshore Technology Conference, Houston, 30 April-3 May. The paper has not been peer reviewed.
The US Coast Guard is responsible for protecting the marine environment, promoting the safety of life and property, and ensuring security on the US outer continental shelf (OCS). Though the Macondo incident was not initiated by failures within areas of US Coast Guard jurisdiction and safety systems regulated by the US Coast Guard generally performed well under the extreme conditions, the US Coast Guard is reviewing its regulatory construct and seeking “lessons learned” from this tragic incident.
Authority and Regulatory Construct
The US Coast Guard, within the US Department of Homeland Security (DHS), has broad authority under the Outer Continental Shelf Lands Act to regulate the safety of life and property on facilities and vessels engaged in US OCS activities and the safety of navigation. The US Coast Guard also is responsible for promoting workplace safety and health by enforcing requirements related to personnel, workplace activities, and conditions and equipment on the US OCS.
A US OCS activity is any activity on the US OCS associated with exploration, development, production, transportation by pipeline, storage, or processing of mineral resources, including hydrocarbons. A US OCS facility is any artificial island, installation, pipeline, or other device permanently or temporarily attached to the seabed, erected for the purpose of exploring for, developing, producing, transporting by pipeline, storing, or processing mineral resources from the US OCS. This term does not include ships or vessels for transporting produced hydrocarbons.
Lessons Learned From Macondo
The Deepwater Horizon accident was a catastrophic event initiated by failure of well containment, an area that falls under the jurisdiction of the US Bureau of Safety and Environmental Enforcement (BSEE). Volume 1 of the report of the US Department of Interior and DHS joint-investigation team (JIT) revealed that, in general, the safety systems aboard the Deepwater Horizon regulated by the US Coast Guard had a beneficial effect, despite the extreme nature of the event. Of the 126 people onboard, 115 survived the explosions and subsequent fire. All survivors were able to evacuate the mobile offshore drilling unit (MODU) by way of the installed life-saving equipment, except for at least six who jumped from the rig into the water. Even though significantly damaged by explosions and initial effects of the fire, the Deepwater Horizon was able to stay afloat for more than 48 hours while engulfed in a major fire, fed by an uncontrolled fuel source.
Downhole Electronic Components: Achieving Performance Reliability
Authors: Beckwith Robin 
Published: February 2015

Electronic Component Reliability
Measurement-while-drilling (MWD) tools were introduced to the oil and gas industry in 1978 by what was then known as Teleco Oilfield Services (bought by Baker Hughes in 1992). Ever since, the industry has had to contend with designing computer circuit boards populated with electronic components that must perform reliably under a combination of extremely harsh downhole conditions. The primary hostile conditions are temperature, variable amounts of vibration, and intermittent shock. Additionally, designers must consider the limitations of the downhole batteries and alternators used to power the electronic assembly. This combination of conditions, in fact, is at least as demanding than those encountered in the defense, space, aeronautics, and automotive industries.
Electronic components include capacitors, resistors, inductors, transistors, oscillators, resonators, semiconductor chips, processors, and memory chips.
The bulk of the electronic component market serves commercial needs. “Even though it’s come a long way in the last 10 to 15 years,” said Matthew White, director of engineering at Ryan Directional Services, “still I would estimate that 85% of the integrated circuits [ICs] and parts on the market today are rated at 85ºC. And another 10% to 12% are rated to 125ºC. Maybe 2% or 3% are rated anything above that.”
With downhole temperatures routinely reaching 150ºC to 175ºC within the deep shale plays in the United States, and offshore downhole temperatures reaching as high as 200ºC, particularly in southeast Asia, the industry demand for reliable MWD and formation-evaluation-measurement-while-drilling (FEMWD, also known as logging-while-drilling or LWD) tools continues unabated. The problem is that the oil and gas industry’s demand for high-temperature electronic components is comparatively tiny—combined with defense, space, aeronautics, and automotive, estimated to be less than 1% of the total component market.
Additional splintering of demand results from individual oilfield services companies keeping exclusive agreements with component manufacturers secret. “I’m more of the opinion,” said Robert Estes, manager of emerging technology, Drilling & Evaluation at Baker Hughes, “that we have to encourage the development of components that can be shared between military, aerospace, automotive, oilfield operations, and geothermal.”
Aaron Schen, department manager of the Electronics Development Group (Downhole) at National Oilwell Varco (NOV), notes that, generally, non-semiconductor downhole components such as sensors and connectors are pretty well supported by vendors. “It is routine to find high-temperature, high-severity, and high-pressure (if needed) ratings for those types of components,” he said. He contends this is because a small, niche-market company “can be happy making a couple hundred pressure sensors a year. Chips are turned out in the millions.”
Gas-to-Liquids Comes of Age in a World Full of Gas
Authors: Jacobs Trent 
Published: February 2015

Gas-To-Liquids Developments
By the end of the decade, modular gas-to-liquids (GTL) plants distributed around wellheads in places such as North Dakota, USA, and Siberia, Russia, may become commonplace as pressure mounts on producers to monetize marginal natural gas resources.
Small-scale GTL plants take the unwanted natural gas that is a byproduct of oil production, known as associated gas, and transforms it into more valuable liquid products. The technology can also be used to produce stranded gas reserves where a lack of distribution infrastructure exists.
The current disparity between crude and natural gas prices and the ever-rising estimates of global natural gas reserves are driving oil companies to study the feasibility of using small-scale GTL plants. North America, where the use of hydraulic fracturing has led to a surge in oil and gas production, will likely be the first region to see the widespread adoption of modular GTL technology.
With every new oil well that comes online, operators face tighter pipeline constraints, less gas-processing capacity, and increasing scrutiny from both regulators and the public sector on the disposal of associated gas through flaring. The associated gas that bubbles up with the crude is a phenomenon virtually all oil wells experience and, according to a 2011 report published by the World Bank, more than 5 Tcf of this gas is flared annually while another 15 Tcf is estimated to be reinjected.
Two companies, CompactGTL and Velocys, are at the forefront of small-scale GTL development, and both have systems designed specifically to address the untapped markets that associated and stranded gas represent.
CompactGTL, based in the United Kingdom, has plans to commission its first modular GTL plant in North America by the end of 2016 to produce synthetic crude oil, or syncrude, from natural gas. Syncrude, a milky white substance, is so free of impurities such as sulfur that it can command a premium price over crude oil because of the flexibility it gives refiners to optimize their operations. “There is an enormous amount of interest in North America for this solution,” said Iain Baxter, director of business development at CompactGTL. “The ability to take natural gas at the point of production and convert that into oil there and then—that is an incredibly valuable capability.”
A Design Combining API and ASME Codes for Subsea Equipment in HP/HT Conditions
Authors: Carpenter Chris 
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 23928, ’A Design Method Combining API and ASME Codes for Subsea Equipment in High-Pressure/High-Temperature Conditions,’ by Parth D. Pathak, Christopher G. Kocurek, and Samuel L. Taylor, Cameron International Corporation, prepared for the 2013 Offshore Technology Conference, Houston, 6-9 May. The paper has not been peer reviewed.
The design of subsea equipment for pressures greater than 15,000 psi and temperatures more than 250°F is a substantial challenge. The current standard from the American Petroleum Institute (API), Specification17D, for designing subsea equipment provides little guidance on conditions exceeding these measurements. This work has been performed to demonstrate the acceptance of existing methods for high-pressure/high-temperature (HP/HT) conditions and introduce advanced American Society of Mechanical Engineers (ASME) methods for designing subsea equipment.
Introduction
The design methods given in API 17D refer to the design methods of API 6A, which are valid for working pressures up to 20,000 psi and temperatures up to 650°F. The ASME Boiler and Pres-sure Vessel Code (BPVC), Section VIII, Division 2 and Division 3, provides design methods for high-pressure vessels. These design methods must meet the API allowable limits and material and test requirements. ASME BPVC has its own design material and test requirements to be used along with the design methods outlined in the ASME codes. A design method combining the ASME design techniques with API material and test requirements that satisfies both the codes is desirable. An example evaluation is presented of an API 17D (API 6A, 4-in. 20K) flange flow loop for a design pressure of 20,000 psi and a temperature of 350°F with external tension and bending loads.
The ASME BPVC was a result of a committee set up in 1911 to formulate standard rules for the construction of steam boilers and other pressure vessels. This code is formulated for pressure vessels in the nuclear industry, and for designing storage and transportation tanks. API 17D was formulated for standardization of subsea production systems.
The ASME and API codes differ in material, hydrostatic-test, and nondestructive-examination (NDE) requirements in particular. The API codes provide temperature derating factors for elevated-temperature design. The standard hydrostatic-test requirement per API 17D is 1.5 times the rated working pressure, whereas in BPVC, Section VIII, Division 2, the hydrotest requirement is 1.43 times the working pressure. Additionally, the hydrostatic test pressure in ASME varies between divisions and has also fluctuated over time.