bluuebunny/crossref_metadata_2025 huggingface dataset:
Collaboration's Critical Role in Reaching Total Depth
Authors: Emerson Brent
Published: February 2015

Guest editorial

Drillers around the world share a common goal: to get their well to its targeted depth with the proper hole size such that reservoir contact and, ultimately production, are optimized.

However, given the diverse drilling environments that operators work in today—from reactive shales and tar zones to salt domes and depleted zones commingled with high-pressure zones—the challenges are as varied as each well drilled. How do we safely reach total depth with the right hole size to ensure that kicks or losses are minimized and wellbore integrity is assured? And how do we achieve optimal efficiency to avoid the time and money lost by drilling delays?

As exploration and production operators know, collaboration is key to success in reaching total depth—in particular, collaboration between the operator and an integrated service provider who brings complementary services and technologies to well construction. The ultimate benefit of this collaborative approach can be fully realized only if the service provider is involved as early as possible. Indeed, the contributions made in the predrill planning stage can have a positive knock-on effect for subsequent stages—from engineering to execution and, eventually, to operation. Everything the operator and its service partners do ahead of the well’s onset of production can bolster, or undermine, the long-term viability of a well.

So, what can an integrated service provider help deliver? Early collaboration helps deliver on the promise of well integrity—the concept of having no uncontrolled inflows of drilling mud into the formation or outflows of formation fluid into the wellbore—throughout the life cycle of the well. Armed with an in-depth understanding of the operator’s well integrity challenges, the service provider can help the operator determine the best way to run casing to depth, ensure high-integrity cementing, and achieve proper zonal isolation to generate reliable and long-term production from the well.

A close working relationship between operator and integrated service partner also helps ensure drilling reliability, which is tied to having the right products and services available that consistently deliver the well plan with a minimum of nonproductive time (NPT). While much of today’s drilling equipment is highly reliable, with an uptime of 98% or more, the industry must develop even more reliable equipment. This is because of the additive nature of equipment downtime in wells of increasing complexity, which lowers the reliability of the cumulative technology offering and increases NPT. Our industry must continue to develop better equipment designs that push reliability gains rivaling the electronics industry, that is, greater than 99%. And while next generation products may cost more both in up-front research and development investments and price, they will more than pay for themselves by boosting overall system reliability and lowering NPT.
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.
Fatigue Testing of Shrink-Fit Couplings for Joining High-Strength-Steel Riser Pipe
Authors: Carpenter Chris
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 24069, ’Fatigue Testing of Shrink-Fit Couplings for Joining High-Strength- Steel Riser Pipe,’ by J. Shield and J. Wightman, Subsea Riser Products; J. Pappas, RPSEA; and J. Bowman, Chevron, prepared for the 2013 Offshore Technology Conference, Houston, 6-9 May. The paper has not been peer reviewed.

The shrink-fit connection is a method of joining pipes to couplings or flanges by thermally expanding the coupling or flange over the pipe; sealing and static capacity are achieved by the contact pressure and friction between the components once they have cooled. This method enables the manufacture of high-pressure deepwater riser systems when traditional pipe-join methods are not feasible. A program was devised to test the manufacturability of shrink-fit joints made from high-strength (greater than 100 ksi) mill pipe and forged couplings.

Introduction

The objective of the project was to qualify the shrink-fit technology to project-ready status—any further testing on the connector would be for project qualification rather than further development. This development project involved two stages: (1) proving the feasibility of machining and assembly from seamless pipe and (2) hydrostatic and resonant fatigue testing of shrink-fit connections.

Six specimens were manufactured to demonstrate that pressure containment is maintained for maximum working pressures and hydrotest pressures, while target fatigue life is achievable without loss of pressure integrity in the connection. Before testing, a finite-element model was used to address residual shrink-fit stresses, safe hydrotest pressure, predicted connection-fatigue response, and the choice of internal pressure for fatigue testing.

Current Technology

The use of pipe for offshore oil and gas risers in various types and sizes requires intermediate connections because continuously cast pipe is not used for large-diameter offshore risers, and the pipe tends to come in limited lengths. For all drilling risers, the riser is usually required to be deployed and retrieved on a regular basis, so a coupling is employed on the joint extremities, which are designed for repeated assembly/disassembly. For shallow-water drilling risers, joint lengths of 40 ft are commonplace, but, for deepwater, larger joint lengths of up to 90 ft are increasingly desirable to reduce riser running time (and thus reduce drilling costs). These larger joints usually require one or more midjoint pipe connections.

The shrink-fit connection has al-ready been delivered for a full 19.25-in.-bore drilling-riser project for the North Sea. The benefits of this shrink fitting include a connection demonstrably stronger than the pipe. Also, very-high-strength material grades can be used. The problems with the technology include a lack of resonant-bending-fatigue data and a need for pipe that is produced to reasonable dimensional tolerances.
Company's Revised Approach to Safety Strives To Make Standards More Natural
Authors: Wilson Adam
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 163757, ’A Hurt-Based Approach to Safety,’ by R.M. Smith, SPE, and M.L. Jones, ExxonMobil, prepared for the 2013 SPE Americas E&P Health, Safety, Security, and Environmental Conference, Galveston, Texas, 18-20 March. The paper has not been peer reviewed.

ExxonMobil has traditionally used industry standards driven by the US Occupational Safety and Health Administration (OSHA) to classify safety events on the basis of the treatment or restrictions provided. However, this treatment-based approach has limitations. With its focus on administrative reporting and incident-escalation management, the approach does not naturally resonate with workforce members to enable desired cultural changes. A hurt-based approach has been adopted to mitigate the limitations of the treatment-based approach.

Traditional Treatment-Based Approach

In the treatment-based approach to personnel safety, an incident, from the treatment or restrictions provided, is classified as a lost-time incident (LTI), restricted-work incident (RWI), medical-treatment incident (MTI), first aid, no treatment, near miss, or unsafe act/unsafe condition. These are usually represented by the traditional safety pyramid (Fig. 1). Benefits of this approach include

It provides historical metrics common across multiple industries.

It allows comparisons on a similar basis.

It is consistent with many government/regulatory-agency reporting requirements.

However, this approach also has significant limitations:

It is not consistently descriptive of actual injury severity; for example, body damage such as a minor laceration, a sprained ankle, or a broken neck could each be correctly classified as an LTI, depending on the circumstances.

It does not have an integral potential injury severity; safety events with low actual consequence (e.g., minor hurt, near misses) are often overlooked or simply not reported.

It creates a blind spot relative to exposures for severe injuries by focusing solely on traditional safety metrics [e.g., total recordable incident rate (TRIR), LTI rate (LTIR)]; certain activities and activities managed by safety controls require greater exposure awareness.

It is not an enabler for a culture of caring; workers can perceive case-management priority to be about reducing the number of recordables (perhaps by minimizing treatment) and not about the elimination of all injuries.
Safety-Management Leading Indicator Results in Unintended Consequences
Authors: Wilson Adam
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 164961, ’Unintended Consequences of a Promising Safety-Management Leading Indicator,’ by Carl D. Veley, SPE, vMBA Consultants, prepared for the 2013 SPE European HSE Conference and Exhibition, London, 16-18 April. The paper has not been peer reviewed.

A metric based on a corrective-action-classification system initially appeared to be a valuable leading indicator for management purposes. However, after trial applications, it became clear that, when this metric was used to define performance goals, it had unanticipated consequences that cumulatively and insidiously caused more damage than the accidents it was intended to prevent. Category matching is an upgrade of that original metric and eliminates harmful unintended consequences of corrective-action classifications used alone.

Background

Trailing indicators are by far the most common type of safety statistic. Governments, insurance companies, corporations, and essentially everyone who tracks accidents will record the number and type of injuries, plus the money spent on repairs, machinery replacements, wasted time, or other harmful consequences of accidents. Leading indicators are complicated by the fact that some dangerous acts (e.g., touching high-voltage switchgear) will always produce an accident with severe consequences while other dangerous acts (e.g., running a stop sign) might be repeated hundreds of times without causing an accident. In industrial work situations, no scientifically defensible equation exists where X dangerous acts produce Y accidents with Z fatalities.

As shown in Fig. 1, accidents come in packages with four components. In reverse chronological order, they are (1) consequences, meaning harm (either injury or damage); (2) the accident itself, an unplanned event; (3) an act of people, not intended to produce the accident; and (4) the reason the accident was not anticipated. A broken leg is never an accident. It is an injury and the consequence of an accident. An accident is an unplanned event, and a fall is always an accident regardless of whether it causes injury. The vast majority of accidents cause little or no harm, but confusing an accident with its consequences is a major obstacle to preventing accidents because the target of corrective actions is not clear.
Experiments on Large-Scale Fires Reveal Benefit of Greater Water Deluge
Authors: Wilson Adam
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 164973, ’The Effect of Deluge Spray Systems on Large-Scale Fires,’ by Stian Hoiset and Eli Glittum, Statoil, prepared for the 2013 SPE European HSE Conference and Exhibition, London, 16-18 April. The paper has not been peer reviewed.

A series of 56 large-scale fire experiments in the range of 40–120 MW has been carried out in a generic offshore module. The effect of deluge fire-water application has been measured for different setups. Both deluge nozzle type and water-application rate have been varied in the experiments.

Introduction

The use of water-spray systems for fire-fighting is standard for most offshore oil and gas installations. The requirements to and guidelines for control and mitigation of fires are stated in International Organization for Standardization (ISO) 13702, Petroleum and Natural Gas Industries—Control and Mitigation of Fires and Explosions on Offshore Production Installations—Requirements and Guidelines. Appendix C in ISO 13702 lists the recommended fire-water-application rates for areas and rooms on an oil- or gas-production installation. Typically, the minimum recommended water-application rate is listed as 10 (L/min)/m. NORSOK Standard S-001, applicable for installations on the Norwegian continental shelf, states that the effect of deluge may be taken into account for process equipment and piping, provided that there is proper documentation of the fire-water effect (and that there are requirements to the reliability of the fire-water system).

In order to document the effect of the recommended fire-water-application rate, a set of full-scale fire experiments with application of fire water was carried out at SINTEF NBL.

Background

Today’s design of oil- or gas-production installations includes deluge-fire-water systems as standard. These are costly and may require extensive maintenance. Despite the costs involved, little knowledge is available on the actual effect of fire-water systems under different operating conditions.

Appendix C in ISO 13702 recommends a typical water-application rate of 10 (L/min)/m. National Fire Protection Association (NFPA) 15: Standard for Water Spray Fixed Systems for Fire Protection recommends a design objective for control of burning of not less than 20 (L/min)/m. NORSOK S-001 refers to NFPA 15 but prescribes 10 (L/min)/m for process areas and equipment surfaces and 20 (L/min)/m for the wellhead area. American Petroleum Institute (API) 2030, Guidelines for Application of Water Spray Systems for Fire Protection in the Petroleum Industry, prescribes 20 (L/min)/m where pumps are present and 10 (L/min)/m for pipe racks and piping. To what extent do these water-application rates actually affect the fire?
Legislation, Commerce, and Ethics Drive Design of Quieter Facilities in Australia
Authors: Wilson Adam
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 156732, ’Why Quiet? Legislative, Commercial, and Ethical Drivers Behind the Design of Quieter Offshore Facilities in Australia,’ by Andrew Chandran, Chevron Australia, prepared for the 2012 SPE/APPEA International Conference on Health, Safety, and Environment in Oil and Gas Exploration and Production, Perth, Australia, 11-13 September. The paper has not been peer reviewed.

Legislation, economics, and ethics are major drivers behind the adoption of engineering noise controls during offshore-facility design in Australia. The global challenge facing noise advisers is to understand how these factors influence the adoption of engineering noise controls and to work closely with project teams to ensure that operational-noise risk is as low as reasonably practicable (ALARP). Implementing these controls during the front-end engineering and design (FEED) can ultimately protect a company and its workforce during facility operation and can turn major capital projects (MCPs) into valued legacy operations.

Introduction

It is commonly said that “health and safety are good for business” without seeing substantiated claims. However, if health and safety truly are good for business, it should be demonstrably so. This may involve an evaluation of the costs vs. benefits of each health and safety initiative, as well as the feasibility of implementing them. One such initiative is hearing preservation.

Cost/benefit analysis (CBA) is an important tool that can be used to com-pare the net economic worth of various health and safety initiatives to deter-mine how best to allocate finite project resources to maximize a project’s value. Various international cost/benefit models exist to help companies perform economic evaluations of health and safety initiatives. An Australian ALARP model recently used by Chevron Australia during the design of an offshore production facility in the North West Shelf of Western Australia is one of them.

Additionally, discounted-cash-flow (DCF) analysis is introduced as a means of supplementing conventional CBA to help decision makers determine when, during the lifetime of a project, engineering noise controls should be implemented to maximize a project’s net present value (NPV).

The decision to implement effective engineering noise controls is not based solely on economics, but it is a major driver behind the selection and implementation of proposals that can affect a company’s bottom line. Other key drivers are legislation and business ethics or cultural expectations.
Comments: Reader Feedback (August 2014)
Authors: Donnelly John
Published: February 2015

Editor's column

Every year, JPT surveys its readership to help determine future coverage and to ensure that it is fulfilling its mission. Along with other important SPE programs such as meetings, workshops, training programs, and other services, one of JPT’s major roles is to help SPE provide high-quality technical information to members and to the industry at large.

The emailed survey was sent to a representative sample that took into account the respondent’s company type, geographical location, age, and industry experience. A little more than a third of respondents classified themselves as engineers, with the next highest category managers at 20%. Approximately 42% of respondents reside in North America and 59% of them reported having at least 10 years of experience in the oil and gas industry.

Looking at the survey results, three-fourths of survey respondents rate JPT as “very good” or “excellent,” in line with survey findings of the past 2 years, and 96% of respondents ranked it as good to excellent. Of the various standing features in each issue of the magazine, the most read were Technology Update, articles describing how new technologies are being used in the field; summaries of selected SPE technical papers spanning 47 technical categories over the course of the year; staff-written feature articles about emerging technologies; and Technology Applications, short articles about newly commercialized technologies.

The synopses of technical papers presented at SPE conferences are selected by the 48-person JPT Editorial Committee as the best or most interesting in that particular category. The technical categories that attract the most reader interest are hydraulic fracturing, unconventional resources, reservoir performance and modeling, and field development projects. Also ranking high were mature fields and well revitalization, production operations, high-pressure/high-temperature challenges, completions, and horizontal and complex-trajectory wells.

Other Findings

Compared with other magazines serving the E&P industry, 80% of survey respondents rank JPT better or significantly better, slightly higher than the response to the same question in the 2013 survey. Although several respondents complained about the number of advertising pages in the magazine, others said they ranked JPT higher than other publications because it is less commercial and contains better and more reliable industry content. Other readers noted JPT’s relationship with SPE as the reason they consider the magazine more trustworthy and industry-relevant.

Among other findings in the survey: 90% of respondents find JPT somewhat or very useful to them in their jobs, and JPT is most read in print compared with other publishing platforms. Internet access ranks second, followed by tablet and smartphone app. JPT’s Editorial Committee and SPE staff will use the information in the survey to further improve the magazine and to ensure that it remains useful and relevant to its readers. JPT
Program Ranks Musculoskeletal Risk of Operating Valves in Process Industries
Authors: Wilson Adam
Published: February 2015

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 165690, ’A Method for Ranking the Musculoskeletal Risk of Operating Valves in Process Industries,’ by Dennis A. Attwood, Human Factors Applications, and Alicia T. Tys, Marathon, prepared for the 2013 SPE Eastern Regional Meeting, Pittsburgh, Pennsylvania, USA, 20-22 August. The paper has not been peer reviewed.

Every process plant presents a high number and diversity of valves that control the flow of feedstock, products, and service liquids and gases. A comprehensive program was developed for a major US refinery to assess the musculoskeletal risk associated with manually operated valves then to rank each valve according to the risk each poses to plant operators and maintenance technicians. Valve repair and replacement is expensive, so the cost-effective approach was to assess only those valves that are critical to plant operation.

Introduction

Process plants contain a large number of process valves with a wide diversity of designs that control the flow of a wide range of fluids. The ergonomic issues associated with the design, operation, and maintenance of valves include

Physical stress to open and close them

Potential for injuries and subsequent related costs

Lack of access to process-critical valves

Difficulty of removing and replacing them

Potential for process upsets when valves cannot be operated in the time required

As a result of injuries suffered while operating valves, a major US petroleum-refinery company initiated a program to identify high-risk valves and to modify them to reduce the operating risk of injury.

A model, illustrated in Fig. 1, was developed to create a systematic approach to identify the valve issues in a process plant, analyze the issues, prioritize the valves that need attention, implement a solution, and measure the results. The approach can be modified to reflect the unique character of the plant that implements the program.

The objectives of the study were to

Develop a valve-risk-assessment program unique to the process plant based on the plant’s human-factors engineering-design standards and the valve-assessment model.

Assist site personnel in identifying the process-significant valves and surveying them to determine the top candidates for repair or replacement.
Technology Focus: Reservoir Performance and Modeling (September 2010)
Authors: Vikane Erik
Published: February 2015

Technology Focus

Understanding and management of subsurface uncertainties are crucial for successful development of early-phase projects. The development solution, drive mechanism, processing capacities, and number of slots needed all affect the net present value and the capital and operating expenses. Planning and execution of early-phase data acquisition and the effect these data have on late-life economics are a theme that deserves more attention. Concept selection is the most important part of an early-phase development from a subsurface point of view. Because of the high well cost, deepwater projects are sanctioned with few appraisal wells and limited dynamic information. The importance of an overall strategy to manage subsurface uncertainties is described in the paper regarding the development of the greater Plutonio area.

Dynamic information, both horizontal and vertical permeability, is always on top of every reservoir engineer’s wish list. Wireline formation testing is a cost-effective way of addressing dynamic information, keeping in mind that an extended well test or a drillstem test is not always feasible for economic or practical purposes.

Determination of remaining oil is key to increased oil recovery. A proactive approach to surveillance gives insight into the reservoir and has potential to mitigate unpleasant surprises. The paper describing the proactive well and reservoir management and the paper assessing fluid migration and quantifying remaining-oil saturation are both excellent examples of creating value through systematic reservoir surveillance.

Reservoir Performance and Monitoring additional reading available at OnePetro: www.onepetro.org

IPTC 13640 • “Successful Reservoir Monitoring With 4D Microgravity at Ras Laffan, State of Qatar” by A.F. AhmadZamri, SPE, RasGas Company, et al.

IPTC 13185 • “Reservoir Modeling and Production Evaluation in Shale-Gas Reservoirs” by C.L. Cipolla, SPE, Carbo Ceramics, et al.

SPE 127858 • “Perdido: The First Smart Field in the Western Hemisphere” by Robert K. Perrons, SPE, Shell.

SPE 128137 • “Integrated-Production-Model Calibration Applied to a Gulf of Mexico Subsea Field” by L. Saputelli, SPE, Hess Corporation, et al.