bluuebunny/crossref_metadata_2025 huggingface dataset:
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.
Advanced Desander Removes Solids Without Deferring Well Production
Authors: Sherwood Colin
Published: February 2015

Technology Update

As oil and gas fields mature, production of sand and other reservoir solids can become an increasing and sometimes major impediment to hydrocarbon production and facility operations. These solids can move through the wellbore into process facilities, causing flow assurance problems that affect system integrity, export line transportation, cleaning, and disposal. As operators seek to optimize production from mature assets, solids management is likely to take on additional importance. Sand and solids production can also be a problem on some new wells. 

To address these issues, Stork Technical Services developed an advanced online desander (AOD) for managing separator solids, providing thermographic determination of sand accumulation, and enabling clean sand discharge to the sea, with no deferred production (Fig. 1). The system has been used successfully in eight deployments on the Hummingbird floating production, storage, and offloading system (FPSO), which supports Centrica’s Chestnut field, operated by Wood Group, in the United Kingdom North Sea.

Risks of Sand in Production Vessels

The presence of sand in production vessels reduces capacity and affects separation performance, which leads to deteriorating produced water quality and the carry-over of water in the oil phase. If not controlled, the sand can cause a separator to be taken offline and manually cleaned. This exposes facility crew members to process hazards and may damage downstream equipment.

Conventional sand management techniques require a shutdown of 10 to 14 days for manual sand removal, resulting in a significant delay and additional expense. Following this, oil-on-sand discharge rules may limit disposal options and compel storage of some or all of the sand.

The Online Desanding Technology

The desander is designed to allow more operator uptime and to reduce costs, compared with traditional vessel entry cleanout methods. With the new technology, there is no need to shut down production, and the elimination of manual cleaning improves safety. In addition, the technology enables operators to change their approach to planned shutdown periods. Because the system allows a high degree of cleaning to take place before shutdown, the team of technical experts needed for a shutdown can be smaller and planning for it simpler.

The system comprises a number of purpose-designed, integrated components including solids extraction, solids separation, and solids conditioning packages. A high-flow jetting unit with a recovered-liquid package recycles the separator water. The system complies with European Union hazardous area safety requirements and can be used in Zone 2 hazardous offshore environments.
The Keywords For Blowout Preventers Are Trust But Verify
Authors: Rassenfoss Stephen
Published: February 2015

GE Oil & Gas displayed its new blind-shear ram, which is capable of cutting components older blowout preventers could not, at the 2012 Offshore Technology Conference.

Blowout preventers (BOPs) have become a constant concern. Periodic certifications of the equipment and maintenance used to be enough to ensure that this last line of defense would perform if needed. Now, users are constantly “wanting to know, is it ready?” said Chuck Chauviere, the general manager for drilling systems for GE Oil & Gas.

The question can be asked many ways. Is the BOP capable of cutting the pipe or connectors and sealing a blowout? Are the electrical and hydraulics systems working properly? Is the crew trained to quickly make the right decisions in an emergency? Will backup power and communications systems perform under extreme circumstances?

Much has changed in the 2 years since the Macondo disaster in which 11 people died; but, the process is far from over. A rewrite of the American Petroleum Institute (API) guidelines for BOP operations and maintenance, API 53: Recommended Practices for Blowout Prevention Equipment Systems for Drilling Wells, was going through another round of revisions in mid-summer and could be published late in the year, said Roland Goodman, manager of upstream standards at API. The guidelines provide details needed to make changes in the sections of API 16 that cover BOP construction, testing, and recertification.

In May, the Bureau of Safety and Environmental Enforcement (BSEE) kicked off a push to write the first US BOP regulation with a hearing in Washington. Industry representatives got a taste of what is ahead when David Hayes, deputy secretary of the US Department of the Interior, said, “There are at least four things we are looking for in a new proposed rule:

“One, BOPs need to be able to cut whatever is in their way and completely seal off the well.

“No. 2, better maintenance for BOPs, like what you would expect of a jet engine or any other very sophisticated mechanical device upon which lives depend.

“No. 3, BOPs need better sensors to tell us what is happening at the bottom of the sea.

“No. 4, everyone working with BOPs should be fully and properly trained to handle any contingency.”
Key Elements of a Migrant-Worker Health and Welfare Program
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 151765, ’Key Elements of a Migrant-Worker Health and Welfare Program and Its Effect on a Major Construction Project,’ by Israr Ahmed and Herman Wirtz, Qatar Shell; Robin Patrick Donnelly and Alistair Fraser, Shell International; and Salvador Castillo, Qatar Shell, 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.

The Pearl gas-to-liquids (GTL) project required construction of a state-of-the-art hydrocarbon-processing facility with, at peak, 55,000 employed on site. The company created a worker health and welfare program, with a goal to enhance health and performance by creating a culture of care and concern for the wellbeing of workers throughout construction and to mitigate projected risks for a project of such magnitude.

Introduction

Traditionally, construction camps are high risk and high public exposure. There has been a historical tendency to leave the matter of construction-camp planning, design, and management to contractors, with associated risks of under-performance. It is unusual to find a holistic approach for camps that integrates the material aspects with quality of living conditions, action to create social cohesion, and an appreciation of overall worker welfare. However, the realization that there is an opportunity to go beyond compliance with design standards gave rise to a shift toward use of “behavioral and holistic interventions” to improve the safety culture and attitude among workers.

The worker-welfare program was born with the consideration of capitalizing on the caring aspect of safety.  Particularly, the program envisioned to create a facility and community that show empathy for people, a place where members of a large multinational/multicultural workforce live happily and in harmony with each other, where they could enjoy high-quality fulfillment of basic needs and psychosocial support. Therefore, a holistic approach was used that aimed at delivering initiatives targeting the entire range of physical, emotional, mental, and even transpersonal needs of workers in a “high-risk” work area.

Theory

The challenge of making respect for people visible and objective in Shell’s practices was given further push in the area of health, safety, and environmental management. First, in the area of health management, it was imperative in building projects and in operations that controls and regulations be in place to protect and promote the health of employees, contractors, and neighbors by eliminating, reducing, or mitigating health risks in the workplace.
Managing Risk at Ground Level
Authors: Sajjad Joe
Published: February 2015

Guest editorial

The term “risk management” is not new to the oil and gas industry, but its meaning continues to evolve to reflect changing challenges. For many, risk management might be synonymous with safety, or taking proper precautions to minimize the occurrence of an incident or unsafe condition. And while safety is a fundamental component of risk management, the concept also incorporates mitigating risks to service quality, productivity, and the environment.

Although the majority of companies in the oil and gas industry share a commitment to constantly improving their risk mitigation strategies, the execution is sometimes lacking.  This is supported by statistics showing that the number of total recordable incidents in the United States upstream oil and gas industry has reached a plateau in recent years, despite the industry’s best efforts to lower them (Fig. 1).

It is perhaps human nature to take a reactionary approach to changing risk management strategies only after one or more dangerous and environmentally harmful events have occurred. In the past few years, however, operators and service companies alike have been changing their mind-set on risk mitigation by adopting a forward-thinking approach to managing safety, quality, and environmental threats.

This requires a fundamental shift in a company’s risk culture. With regard to safety, for example, many companies historically have fostered a compliance-based safety culture—one that stresses safety for the sake of complying with regulatory guidelines or passing an audit. With this mind-set, the ultimate responsibility for safety might fall to one or more health, safety, and environment (HSE) officers, who perform the audits, fill out a checklist, and point out unsafe practices. Soon after the audit is over, however, the temptation to drift back to the old ways of performing work may be too strong to resist.

Changing Behaviors

A preferred approach, which is gaining traction in the industry, is to build a behavior-based safety culture, one in which each worker is committed to performing his or her work functions with the highest regard to safety, even when no one is looking over his or her shoulder. This behavior-based approach should be supported by top executives, but must start at the ground level, with the rig crews and workshop personnel who are most immediately affected. Achieving this culture begins with empowering employees through a comprehensive training program that gives them the tools and leadership skills to perform their tasks safely, and to intervene when they observe an unsafe act.
New Test Probe Yields Key Reservoir Answers
Authors: Arman Kate , Martin Robin , Tevis Chris , De Santo Ilaria
Published: February 2015

Technology Update

Extreme downhole conditions pose a challenge to formation testing. Acquisition of accurate reservoir pressure data and high-quality formation fluid samples has proved difficult in cases of low reservoir permeability, extremely viscous crude oil, or unconsolidated formations with poor borehole conditions. Opera-tors have often considered these wells untestable. When testing is possible, it is frequently time consuming and costly with the need to set and cement pipe, shoot perforations, and bring in coiled tubing to run the test. Even then, formation pressure estimates on such wells are frequently inaccurate.   

However, a new tool has proved able to extend formation testing parameters to extreme formation and borehole conditions. The Saturn 3D radial probe (Fig.  1) developed by Schlumberger is a complementary module to the Modular Formation Dynamics Tester tool. The probe is capable of performing accurate pressure tests in fluid mobilities as low as 0.01 md/cp, and obtaining high-quality fluid samples in mobilities lower than 1 md/cp.

In Mexico, a friable sandstone reservoir containing 7.5 °API crude oil in extremely unconsolidated formations was successfully sampled by the 3D radial tool in a very rugose borehole with 12% ovality. The data collected would have been unobtainable with previous test assemblies and was critical for a sub-sequent thermal recovery design. Despite the difficult conditions, the new tool was able to conform to borehole irregularities to achieve and maintain a reliable hydraulic seal.

Formation Fluid Challenges

Acquiring representative samples of heavy, viscous crude is only part of the story. A North Sea operator took full advantage of downhole fluid analysis (DFA) to characterize viscous, biodegraded oil in a poorly consolidated field. The Catcher area fields, operated by Premier Oil on behalf of colicensees Cairn Energy and Wintershall, contain 300 million bbl of original oil in place, making them one of the most significant recent discoveries in the United Kingdom Continental Shelf. Six wells and three sidetrack boreholes have been drilled to date.

The fields are partly characterized by a series of sand injectites, overpressurized sediments that are remobilized and forced upward to intrude into overlying layers. Injected sands are typically characterized by high porosity and high permeability, which is why they are often considered as attractive hydrocarbon targets. However, injectites often range from poorly cemented to unconsolidated, which makes attempts to sample high-quality fluid very challenging.
EC-Drill Eliminates Effect of Equivalent Circulating Density
Authors: JPT staff _
Published: February 2015

Young Technology Showcase

When drilling offshore wells, the most common method is to drill with a single gradient fluid with the fluid column extending from the bottom of the well back to the drilling rig. Even in shallow water, this sometimes represents a significant challenge if the formation cannot withstand the hydrostatic pressure from the fluid column. An example would be drilling from a jack-up where hydrostatic fluid pressure causes fracture under the shoe of the conductor pipe.

As water depth increases, so do problems associated with having the fluid column all the way back to the rig. The effect of the water depth is particularly significant in the upper part of the well and, consequently, if it can be eliminated, drilling performance can be significantly improved. For this reason, the industry has been working with developing dual gradient drilling technology for decades.

Several methods can be classified as dual gradient drilling. The most common are the seabed pumping and mid-riser pumping methods. For seabed pumping, the drilling riser typically is filled with seawater and the drilling mud is pumped (or lifted) back to the rig from the seafloor. This represents a drilling method in which the effect of the water depth can be eliminated and the well basically drilled as if the drilling rig were sitting on the ocean floor. The same can be achieved with the mid-riser pumping method, but in this case, the riser is typically filled with a gas.

Another significant problem is the effect of dynamic pressure loss (friction) while circulating drilling mud through the wellbore in order to transport drill cuttings back to the rig. In deep water, the margin between pore pressure and fracture pressure is small; hence, there is a narrow drilling window. For static conditions, the mud must have a weight or density great enough to create a wellbore pressure that is above the pore pressure (static overbalance). When the rig mud pumps are started to circulate fluid around the well, the wellbore pressure increases as a function of friction and the pressure may exceed the fracture gradient (typically at the shore above) and result in lost circulation. This may again result in a kick. For low-pressure reservoirs or depleted fields, this problem is significant and may make the wells undrillable with conventional technology.

This dynamic effect, equivalent circulating density (ECD), is a significant drilling challenge in terms of safety and lost time.
Saudi Aramco Expands Reach Through New Technology Centers
Authors: Henni Abdelghani
Published: February 2015

Saudi Technology Centers

Knowledge is power and technology is a game-changer. Those are the key maxims that Saudi Aramco says it is using to shape its strategy as it aims to become the world’s leading integrated energy and chemicals company by 2020.

“At Saudi Aramco, we are pushing forward from a traditional role as buyers and consumers of technology to our new global technology and R&D strategy. We envision becoming an enabler and creator of new technologies,” Khaled Al-Buraik, vice president of petroleum engineering and development at Saudi Aramco, said during the Offshore Technology Conference (OTC) in May in Houston. “There is new urgency as well as new optimism about where we are going. In the past we have been focused primarily on crude oil and gas; now we are progressing to become fully integrated in gas production, including unconventionals, refining, and chemicals.”

To help meet the goal, the company is boosting its global network of R&D centers. In addition to its local center in Dhahran, the Advanced Research Center in the Exploration and Petroleum Engineering Center, Saudi Aramco plans to open three new centers in the US. “We are emphasizing high-impact technologies that typically involve long-range strategies. We are pursuing R&D to bring about breakthrough achievements—not simple or merely incremental enhancements,” Al-Buraik said. “We believe that achieving our research and technology goals requires expansion and interaction with the best talent worldwide.”

The objective of these centers is to leverage international scientific expertise, gain better access to technology, and strengthen collaboration with industry and academia.

A new center in Houston will be the company’s largest center outside Saudi Arabia. A second North American center will be located in Cambridge, Massachusetts, focusing on computational modeling and nanotechnology research. The third center will be located in Detroit, and will be designed to extend the energy giant’s global research and development network. The Houston and Cambridge centers will be operational by the third quarter of this year, and all three will be operated by Aramco Services Company, a subsidiary of Saudi Aramco. The company also has research centers in Thuwal, Saudi Arabia; Delft, Netherlands; Paris; and Beijing; and a technology center in Aberdeen.
Shell Deploys Next-Generation TLP for Extended Field Development in GOM
Authors: Jacobs Trent
Published: February 2015

Shell Olympus

As the towering Olympus tension leg platform (TLP) entered service in July, it marked the beginning of a mission to extend one of Shell’s most productive deepwater projects in the US Gulf of Mexico (GOM) to at least 2050. The oil company said this is the first time an additional deepwater production facility has been added to an existing field in the GOM.

Shell expects to begin first production from the newly commissioned Olympus TLP at the Mars field next year. The Olympus is the largest TLP the company has deployed in the GOM. The Mars field is located about 100 miles south of New Orleans in approximately 3,100 ft water depth. With 24 well slots, the Olympus TLP will produce up to 100,000 BOEPD from Shell’s West Boreas, South Deimos, and Deimos discoveries. The reservoirs are located at depths ranging from 10,000 ft to 22,000 ft.

When the Mars field began production in 1996, Shell estimated up to 700 million BOE of recoverable reserves. Since then, the field has produced more than 770 million BOE, and it is estimated that there may be 1.1 billion BOE yet to be produced. Shell is calling the field extension project Mars B.  

Shell has gone to great lengths to plan for a decades-long development that ties in new innovations with les-sons learned from five other TLPs that Shell operates in the GOM. “It is a next-generation [TLP] just in the sheer size and capability we have with this rig,” said Arno van den Haak, Shell’s well delivery team lead for the GOM.

At 126,000 tons, the Olympus TLP is more than twice the displacement of the neighboring Mars TLP located only a mile away. The Olympus TLP’s drilling rig has a 2-million-lbm hook load, double the load of the Mars TLP rig, giving it the capability to drill and complete wells at depths of up to 35,000 ft—the deepest for a Shell platform.
Advances in Special-Core-Analysis Data Interpretations of Multiscale Measurements
Authors: Carpenter Chris
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 164140, ’Advances in SCAL Data Interpretations of Multiscale Measurements From Different Carbonate Rock Types in a Giant Oil Field in Abu Dhabi,’ by Moustafa R. Dernaika, Ingrain Inc.-Abu Dhabi; Samy Serag El Din and Zubair Kalam, ADCO; and Loay Hannon, Weatherford Laboratories, prepared for the 2013 SPE Middle East Oil and Gas Show and Exhibition, Manama, Bahrain, 10-13 March. The paper has not been peer reviewed.

The evaluation of complex carbonate reservoirs is a challenging task, and a detailed understanding of reservoir heterogeneity is still lacking. In this study, the effect of static rock type and sample size was investigated on special-core-analysis laboratory (SCAL) data derived from capillary pressure and resistivity-index experiments at reservoir temperature and net confining stress. Whole cores were generally found to yield different capillary pressure and saturation exponents that may not be possible to derive from average plug data.

Introduction

Most carbonate reservoirs are characterized by multiple-porosity systems that impart petrophysical heterogeneity to the gross reservoir interval. Reservoir heterogeneity is dependent upon the depositional environments and subsequent events in the history of the reservoir. In previous work, the effect of multiscale measurements (whole cores down to small trims) was studied on porosity/permeability and cementation factor. The whole-core samples were taken from a single well in a carbonate reservoir in Abu Dhabi, where 1.5-in. core plugs were drilled adjacent to the whole cores. Small trims were cut from the plugs for mercury-injection capillary pressure (MICP) determination. The main findings were that whole-core porosity matched log data very well and the plug porosities, when compared with the whole-core data, were systematically higher. The degree of heterogeneity played a major role in comparing whole-core to plug permeability: In the low- permeability range (less than 10 md), whole cores could enhance 3D connection pathways and yield higher permeability values, whereas, in the high-permeability range, permeability can be overestimated in plugs through relatively larger porosity channels. The cementation factor was systematically reported to be lower in the measured whole-core samples. X-ray computed-tomography (CT) scanning was essential in explaining most of the variability seen in the measured rock properties at different scales. In another investigation on four different wells in the same reservoir, these earlier observations were confirmed on hundreds of multiscale samples.
Reservoir-Fluid Characterization From Tests on Tight Formations
Authors: Carpenter Chris
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 164887, ’Reservoir-Fluid Characterization From Tests on Tight Formations,’ by Brian Moffatt, Michael Fawcett, Jaimar Maurera, and Anna Bruzco, Petrophase, prepared for the 2013 European Association of Geoscientists and Engineers Annual Conference and Exhibition incorporating SPE Europec, London, 10-13 June. The paper has not been peer reviewed.

Drillstem testing of low-permeability reservoirs is challenging because high-pressure drawdown around the wellbore lowers fluids below saturation pressure and creates two-phase flow into the wellbore. The fluids produced at surface no longer represent the original reservoir fluid. This paper shows the benefits of a careful methodology of data selection and equation-of-state (EOS) modeling to validate data used to characterize the reservoir fluid.

Introduction

There are significant technical difficulties in capturing representative fluid samples from tight formations. Attempts to flow to surface from tight formations induce a fall in pressure around the well-bore that may take the reservoir oil or gas below its saturation pressure. Two-phase flow in the wellbore can cause significant errors for sampling downhole, although surface sampling can be less prone to error. However, because the gas within the formation is more mobile than liquid, the surface gas/oil ratios (GORs) are higher than those of the native fluid. This can lead to erroneous assumptions about the reservoir fluid if the separator samples are recombined to the prevailing GOR without reference to what is happening in the reservoir.

Two case studies are presented that resolve apparently conflicting data and use a wider range of well-test data than single data points to define reservoir fluids. Neither study had the benefit of downhole pressure/depth gradients to corroborate reservoir-fluid properties.

Characteristic Test Results for Tight-Formation Drillstem Tests (DSTs)

DSTs performed where the flowing bottomhole pressure (FBHP) stays above saturation pressures are ideal for surface sampling or for taking bottomhole flowing samples. However, the low deliverability of tight-formation wells often makes it difficult to establish stable flowing conditions. The FBHP, flowing well-head pressure, and separator conditions may all be unstable, causing difficulties in establishing the correct GOR even when the total wellbore composition is constant. A further complication can arise if the gas rates are too low to lift liquids to the surface.

GORs for bottomhole samples (BHSs) are measured in the laboratory by flashing the sample to specified conditions. The same wellstream composition sampled at the surface will normally have a lower GOR because separator conditions favor an increase in stable liquid volume. Surface and bottomhole GORs will match only under identical flashing conditions. Typical GOR characteristics for BHSs and surface samples for a tight formation containing oil are shown in Fig. 1.
Review of Water Use at Canada's Oil Sands Points Toward Environmental Sustainability
Authors: Wilson Adam
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 156676, ’Water Use in Canada's Oil-Sands Industry: The Facts,’ by Stuart Lunn, Imperial Oil Resources, 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.

Concerns have been expressed and published about the amount of water used in Canada’s oil-sands industry. The oil-sands deposits are geographically separated from population and agricultural centers in the province of Alberta and are within some of the most prolific river basins. Analysis shows that the amounts of water used by oil-sands operations are low and sustainable. A track record of continuous improvements at existing operations and the application of new technologies will maintain the sustainability into the future.

Introduction

Canada’s oil sands are in three deposits in northern Alberta (Fig. 1). The oil-sands deposits hold 1.8 trillion bbl of oil with 169 billion bbl of economically recoverable reserves. This represents 97% of Canada’s oil reserves, which are the third largest in the world.

The term “oil sands” is used to describe unconsolidated bituminous sands. The oil saturation in the sands has very high viscosity and is commonly called bitumen or tar. The deposits are found within the McMurray, Clearwater, and Grand Rapids formations of the Mannville group. They are of varying depth, from near surface in some parts of the Athabasca deposit to more than 300 m deep in the Peace River and Cold Lake deposits. Where the oil sands are shallower than 70 m, they may be mined by surface strip mining. This represents 3% of the surface area of the oil sands and 20% of the reserves. The remaining 80% of reserves across all three deposits are accessible only by use of in-situ recovery methods. Both mining and in-situ methods are water based.

How Water Is Used in Canada’s Oil Sands

Because of the high viscosity of the bitumen within the oil sands (8–12°API, >50,000 cp), it does not flow easily and is difficult or impossible to recover with conventional oil methods. The vast majority of commercial operations rely on hot water or steam to reduce the viscosity of the bitumen to allow its recovery.

For in-situ methods, this involves the injection of steam into the oil-sands reservoir and subsequent recovery of the bitumen once it is reduced in viscosity. For mining, the water is used to slurry the oil, transport it, and finally separate it from the ore.
The Search for Rock Testing Tools That Are Better Than a Drill Bit
Authors: Rassenfoss Stephen
Published: February 2015

Rock Scans

Whiting Petroleum has made an extraordinary commitment to rock testing. In its office tower in downtown Denver, its digital rock imaging laboratory analyzes about 6,000 ft of core samples each year, examining details down to pores only a few nanometers across.

When evaluating new plays, or considering alternative plans for its proven fields, the independent oil company uses a battery of imaging devices. The common question faced is: “Is it going to work?” said Lyn Canter, a senior geoscience adviser who manages the laboratory at Whiting.

She has been asked the same question by other companies considering whether there is a return for investing in in-house rock imaging. Her answer is: “We think it gives us a competitive edge” by providing timely answers to questions raised by complex tight oil formations, many in the Niobrara and the Bakken, that cannot be answered using routine core testing methods.

One example of its value was that Whiting decided not to go forward with a costly proposed field development project after rock tests indicated it was not permeable enough to support profitable production, Canter said. While she said the equipment has paid for itself at Whiting, it represents an unusual level of support, which would be difficult for others to replicate.

Service companies see growing interest in digital rock testing, but few companies regularly use digital imaging as a reservoir analysis tool, and only a couple of majors in the United States have their own in-house equipment, Canter said.

Generating credible results likely to influence decision makers has required a significant, long-term commitment of equipment, skilled personnel, and the time needed to develop the workflows for generating results that exploration teams will use. This requires selecting representative samples, as small as a grain of sand, to image the pore-scale details from complex rocks with features that are consistently inconsistent.

The tools and processes needed to turn observations of the rock microstructure into measurements is an emerging technology. As a result, engineers are the ones asking the toughest questions about the results, she said.

“We want engineering to buy in to what we are doing,” Canter said, adding, “They are naturally skeptical, but can be convinced by making a good case that the results offer a view of the average properties of the larger reservoir.”
Technology Focus: Formation Evaluation (August 2014)
Authors: Harrison Bob
Published: February 2015

Technology Focus

Any oil and gas deal, whether it is acquisition, divestment, greenfield, brownfield, or out of left field, usually involves a data room, where rich seams of proprietary information can be mined for a limited period. However, this physical data room, as opposed to a virtual version where data are downloadable, is the bane of due diligence.

Some may recall caffeine-fueled assignments to paw through boxes brimming with confidential documents that allegedly held the financial secrets of a potential acquisition. The process is expensive; can be a logistical nightmare of travel arrangements, visas, and inoculations; and is always stressful because of time pressure. Data rooms are migraine inducing.

The priority of the petrophysicist on a data-room team is to access digital data for all wells—for example, logs, wireline formation pressures, and deviation surveys for depth conversion. Often neglected are the log headers themselves, which provide data on tool setup, bottomhole temperature, mud properties, and the casing program and present the logging engineer’s comments. Gathering data is less straightforward if they are in an unfamiliar language or are vintage (noncombinable tools with unfocused measurements requiring more runs). These factors require translation, tool response modeling, and increased depth matching, adding time, cost, and potential for error.

Petrophysicists audit the hydrocarbons in place by reviewing previous studies to confirm the all-important trinity of porosity, water saturation, and net pay claimed by the seller. The appropriateness of the saturation-height function in the geomodel is checked for the assumed hydrocarbon and rock type, or merely to ascertain that one was used at all. Proposed fluid contacts must be verified, no mean feat when faced with structure maps showing only oil-down-to (ODT) and water-up-to (WUT) depths, with the contact possibly being anywhere in between. Some companies assume that the fluid contact is halfway between ODT and WUT, which is a completely arbitrary approach.

In these digital days, almost everything needed to carry out petrophysical due diligence can be downloaded for off-site analysis. However, there are places where it is illegal to take data out of the country, so physical-data-room attendance is compulsory. In these instances, as in the past, the petrophysicist’s briefcase might hold color pencils, a ruler, tracing paper, chart books, and maybe a planimeter, a strange device for measuring areas within mapped contours. Yet painful memories suggest that the most important piece of equipment one should take along to a data room is probably a bottle of aspirin. JPT