OTC Highlights Technical Challenges, Effects of Oil Price Volatility

The sold-out exhibition was the largest in show history at 695,005 ft2, including outdoor exhibits, up from 680,025 ft2 in 2014.

The effects of oil price volatility on operators and service companies, technological advances, safety and environmental risks, economic and regulatory impacts, and sustainability were highlighted in the sessions and discussions during the annual Offshore Technology Conference (OTC) held 4–7 May in Houston.

More than 94,700 attendees from 130 countries gathered to exchange ideas and opinions. It is the sixth largest attendance in the conference’s 47-year history. This year’s conference also had 2,682 companies exhibiting, up from 2,568 in 2014, representing 37 countries. International companies made up 42% of exhibitors.

The event featured 11 panel sessions, 29 executive keynote presentations at luncheons and breakfasts, and nearly 300 technical paper presentations. Speakers from major, independent, and national oil companies, federal and regional government officials, and academics presented their views on a variety of topics such as future industry directions, operational integrity, and risk management.

North American Energy Outlook

The North American energy outlook, simultaneously reflecting surging production and resource abundance and the uncertainty surrounding the steep decline in oil prices, Mexican energy reform, and the future shape of regulation, was the focus of panelists from Canada, Mexico, and the United States in one of the sessions.

Gamal Hassan, chief executive officer (CEO) of ADH International, described North America as being “at an inflection point in energy” and said, “The biggest question is how the US [industry] will restructure itself.”

Gustavo Hernandez-Garcia, director general of Pemex Exploration and Production, forecast a moderate recovery in oil prices late this year through 2016 but with significant long-term risks.

Addressing the changes at Pemex as Mexico undertakes industry reform, Hernandez said the company needs to improve its cash flow, is divesting itself of noncore assets, and is looking to acquire complementary assets “on the cheap” while prices are down. “We are trying to produce more value barrels rather than just volume,” he said.

Hernandez outlined three possible outcomes for Mexican energy reform: 1) Achieving full potential and being competitive in the market; 2) Mixed results with part of the company being market competitive and part continuing to rely on state support; and 3) Unrealized potential because of “slow-motion implementation.” He said that Pemex prefers the first scenario.

Paula Gant

Paula Gant, deputy assistant secretary for oil and natural gas at the US Department of Energy (DOE) Office of Fossil Energy, stressed the importance of the ongoing trilateral cooperation on energy between the US, Canada, and Mexico and pointed to “the robust and resilient infrastructure” of the three countries’ energy systems.

The continent’s oil and gas resources are abundant, and the US DOE is focused on the three countries “working together to maximize this regional abundance,” Gant said.

To achieve the potential held by the continent’s resource base depends on maintaining public confidence, and the US DOE plays a critical role in this by providing “a solid scientific base” for public policy decisions, Gant said.

David Ramsay, government minister of the Northwest Territories (NWT), Canada, spoke on unlocking the energy potential of the territorial area. The NWT hold shale oil resources estimated at 3 billion to 5 billion bbl, and TransCanada’s proposed ­Mackenzie Gas Project would build a 750-mile pipeline to link 80 Tcf of natural gas in place in the NWT with North American markets, he said.

The Arctic waters offshore the NWT have the oil and gas potential to rival the Gulf of Mexico. “We need to explore the Arctic now,” Ramsay said.

Mike Bahorich, executive vice president and chief technology officer at Apache, discussed how his company is “positioning for success” with the low oil price. Apache has gone from running 90 rigs in the US when oil prices were high to recently running 17, Bahorich said. The company is focused on attacking its cost structure, consolidating acreage, lowering the base decline rates of its wells, maximizing recovery, and minimizing operating expense, he said.

Apache sold USD 7 billion of assets in 2014, which included exiting the liquefied natural gas (LNG) business. The company expects modest production growth in the Permian Basin, despite a reduced rig count, Bahorich said.

Improving the supply chain for shale development to make it more like a mining operation is critical for the industry. Apache has hired more than 100 people to focus on supply chain issues, and at least one competitor has also recently hired staff in this area, Bahorich said. The industry supply chain “is still kind of stuck in the stone age,” he said.

John Chisholm, CEO and president of Flotek, was relatively optimistic about oil prices, saying that he expected them to “drift back toward the mid-70s through the balance of this year.” He described the market as being “closer to a bottom than a top.”

US Representative Bill Flores (R-­Texas) addressed the need for change in US government energy policies. Calling for a “moon shot” approach similar to the US commitment to put a man on the moon in the 1960s, Flores called for greatly expanded oil and gas exploration and development.

“We should make all nonenvironmentally sensitive taxpayer-owned lands and offshore areas available for energy production,” Flores said. “We need to take the revenue from that enhanced production from federal lands and put it into an endowment.” The endowment could be used to fund education, infrastructure, and basic research.

Flores added that the use of natural gas as a transportation fuel should be encouraged and that the government should approve construction of the Keystone XL Pipeline and LNG export projects.

Developing Lighter-Than-Air Shipping Capabilities for Remote Projects

Jack Betz, JPT Staff Writer

As cheap-to-produce oil and gas reservoirs become less and less common, operators are also being pushed farther away from easily traversable land with abundant infrastructure and predictable political climates. This trend has made it more difficult for logistics companies to move heavy equipment.

During a breakfast panel, Brent Patterson, senior vice president of global projects at the Houston-based Blue Water Shipping, highlighted difficulties that are often overlooked in coordinating operations in remote areas.

The challenges of procurement are well-known for international megaprojects, however, movement of modestly-sized equipment can pose problems when compounded by right-of-way and regulatory issues.

Patterson discussed a case study in which Chevron fabricated modules in the state of Idaho, planning to ship them to Canada. Because of permit hurdles and complicated regulations around road usage, the units were too large to be moved while fully assembled.

“A million dollars later—or whatever the exact cost was—the modules did not move,” said Patterson. “They had to go back to Idaho, cut the modules apart, and refabricate them later.”

Panelist Timothy Kenny, director of engineering at Aeroscraft, had answers to at least some of Patterson’s concerns in the form of a bottom-loading airship, which is in its prototype phase.

Aeroscraft’s helium-filled Dragon Dream prototype can take off vertically and requires only one-and-a-half times the vehicle’s length to land. By compressing its helium, it can also control its static weight, which means that ships will not need mooring systems or large ground crews to land them. “What this will allow us to do is go anywhere in the world without having to develop infrastructure,” said Kenny.

While the vehicle is not practical for every client, Kenny said that those who wish to transport large pieces of equipment over less-than-certain routes may find it cheaper and safer than sending it over road, rail, or sea.

Patterson’s company follows UK-style anti-bribery standards, which means that in shipping equipment to its final destination, it refuses to provide even a single “facilitation payment.” Not complying with this institutionalized corruption can lead to delays in moving cargo. Using lighter-than-air shipping methods could eventually allow companies to avoid bribery-plagued areas on international routes, he said.

An additional use for airships that Kenny proposed was shipping of equipment to arctic regions, where roadways are unavailable until thawing, or are nonexistent and cannot be built due to environmental regulations.

The company plans to offer 66-ton and 250-ton models and expects the first 250-ton ship to be on the market in 2021. Kenny said the company is in the process of getting the vehicles approved by the US Federal Aviation Administration.

Industry Collaborative Projects

The International Association of Oil and Gas Producers (IOGP) highlighted case studies of four broad industry collaborative projects at a panel session.

The London-based IOGP, with 77 member companies worldwide, focuses on industry improvement in safety, environmental, and social performance. Michael Engell-Jensen, IOGP executive director, said the organization may be the largest keeper of safety data throughout the industry. The case studies showed how collaboration in the IOGP framework “is changing the upstream industry for the better,” he said.

The projects were conducted under IOGP auspices. The case studies presented were

  • Lifesaving Rules—The Power of Databases
  • Global Standards Used Locally Worldwide
  • The Subsea Well Response Project
  • Oil Spill Response Joint Industry Project (JIP)—Common Operating Picture

Mike Denkl, performance systems governance manager at Schlumberger, told how the lifesaving rules project drew on the benefits of a global database and collaborative effort to formulate eight core and 10 supplementary rules that, if followed, may have prevented the majority of fatalities occurring in industry operations. The project identified “statistically meaningful trends that would not have been possible for any company to do on its own,” Denkl said.

Ian Cummings, vice president of engineering in global projects at BP Upstream, discussed the global standards case study, noting that simplification and standardization are vital to continued industry innovation. Unnecessary, bespoke engineering specifications, in some cases running to 1,200 pages for a single piece of equipment, are costly and inefficient, and vendors are rarely in a position to challenge them, he said.

“We have found different testing standards [in the company] for the same types of equipment tested at the same time,” Cummings said.

A new BP program to prevent value loss caused by “preferential engineering” has shortened timetables, reduced costs, and allowed smaller engineering teams. Thus, suppliers see greater consistency among projects, and a common platform for learning emerges, Cummings said.

David Brookes, senior consultant for subsea and floating at BP Exploration, spoke about the subsea well response project (SWRP), which was initiated in the aftermath of the deepwater Macondo blowout in the US Gulf of Mexico. “It has been a story of success over a 4-year period,” he said.

The project has overseen the design of four capping stacks and their installation systems, all of which have been delivered; a chemical oil dispersant system with improved surface safety features; and subsea spill containment systems.

The SWRP was expanded to develop a containment system for shallow-water blowouts during which the upward flow of oil and gas prevents surface access directly above the well for installing a containment device. Brookes said a subsea delivery system using drag chains has been designed to move a 150-ton capping stack along the seafloor to the wellsite, where the stack is lifted over the well and pulled downward into position with mooring wires. The initial system will be delivered by early next year, he said.

Roger Abel, geomatics manager at Shell, summarized the work by the Oil Spill Response JIP to develop a Common Operating Picture. The effort involved combining three smaller JIPs under a heading of surveillance, modeling, and visualization, incorporating work packages on in-work and surface surveillance and metocean modeling. The Common Operating Picture, which is created from geographical information system (GIS) data, “is the glue putting all of this stuff together,” Abel said.

For a potential oil spill, there are a number scenarios to consider. “It could be on land, it could be in a coastal environment, it could be a tanker in transit at sea anywhere,” Abel said. “It could be a platform, a pipeline, or in the very worst case of Macondo, it could be that deepwater well blowout with a big uncontrolled release. And the common thing here in this picture is geography.”

GIS technology allows geographical information to be split into different layers and reintegrated in a spatial (latitudinal and longitudinal) framework. This makes it possible to have a continuous, time-referenced picture for maintaining situational awareness, a practice heavily used in the military and one that Abel said is “critically important” to managing a spill response.

Abel said the JIP has developed a recommended practice for the industry and plans to complete “an outstanding piece of work” on data models this year.

Abu Dhabi Megaprojects Survive Price Drop

Stephen Rassenfoss, JPT Emerging Technology Senior Editor

To expand production and sustain it for decades to come, Abu Dhabi’s national oil company is not slowing down megaprojects, but ADNOC sees the drop in oil prices as an opportunity to trim the cost of the work.

“When you do megaprojects … it is like a train you cannot stop,” said Ali Rashid Al-Jarwan, CEO of ADMA-OPCO, the offshore arm of& ADNOC.

During a breakfast presentation, he described work onshore and offshore Abu Dhabi to increase production from 2.9 million B/D to 3.5 million B/D. While the company is not altering its plans, it is looking for ways to reduce the cost of executing them.

“We will do things in a more cost-effective way and are negotiating more with contractors,” he said. The discounts have been from 10% to 15% he said, adding, “We want to make it a win-win for a contractor who continues to serve us at a reasonable price.”

Even with a bit of economizing, the cost is staggering for projects to build islands, conduct one of the largest offshore seismic surveys ever, do the first large sour gas development in the region, and create a system to remove carbon dioxide from the exhaust of a steel plant and transport it offshore for enhanced oil recovery.

As a result, production is expected to hit 3.5 million B/D by 2017, by when the production infrastructure will be installed to allow the country to sustain its production for another 25 years. Abu Dhabi’s goal is to ultimately produce 70% of the oil and gas in the ground. So far it has extracted about 30% of it, and Al-Jarwan noted that it gets harder as they near the halfway point in that journey.

Vietnam Holds Offshore Opportunities, Challenges

Officials from Vietnam’s oil and gas sector discussed the opportunities and technical challenges of drilling and developing the country’s offshore fractured granite-basement reservoirs at an industry breakfast.

These types of reservoirs are composed of nonsedimentary basement rock that is not usually associated with oil and gas accumulations but under certain conditions can hold hydrocarbons that have migrated from nearby source rock. While fractured granite-basement reservoirs have low permeability, they also have natural fracture networks where migrated hydrocarbons can accumulate. But understanding these reservoirs is challenging because of their heterogeneity.

The officials discussed the industry’s experience in the Cuu Long Basin, where a substantial portion of past and current drilling and production activity has involved the development of fractured granite-basement reservoirs.

Of approximately 1,000 wells drilled in the basin, 500 have been landed in the fractured granite basement, said Nguyen Tien Long, vice president of exploration at PetroVietnam Exploration and Production. A number of companies have drilled these wells, including PetroVietnam, Vietsovpetro, Petronas, PTTEP, and others. The hydrocarbons in the Cuu Long granite basement migrated from world-class source rock, with basement reservoir intervals ranging from 100 m to 2000 m, he said.

There is good, intensive 2D and 3D seismic data on the Cuu Long granite basement, and the Vietnamese oil and gas industry has a good understanding of the fracture networks, Long said. Estimated 2P reserves in the granite basement are 6.5 billion bbl of oil equivalent (BOE), and a cumulative 2.5 billion BOE has been produced. There are 16 fields on production, five in development, and 10 undeveloped discoveries, Long said.

Pham Tien Dung, president and CEO of PetroVietnam Drilling and Well Services, described the fractured granite basement in the Cuu Long Basin as “one of the most difficult environments seen in our industry,” with challenges such as low drill bit rate of penetration and short bit life, lost circulation, and high torque drag during drilling.

However, continued improvements in bit design and mud motors have made a major difference. Wells that once took 90 days to drill are now drilled in 30 to 45 days, Dung said.

Lost circulation is a frequent problem, with loss rates ranging as high as 2,000 bbl per hour. Seawater is used as a drilling fluid, accompanied by a system that compensates for lost circulation by flooding the annulus with an equivalent amount of seawater. Many successful wells have been drilled, Dung said.

To conclude the session, Dao Nguyen Hung, manager of oil and gas field development at Vietsovpetro, presented a case study on the White Tiger field—one of the most successful fractured granite-basement developments in the Cuu Long Basin.

The field is produced from a reservoir that is 15 km long×6 km wide×1.9 km deep. The reservoir is heterogeneous in permeability and porosity, both of which decrease with depth. There is no bottom water aquifer, so water is injected beneath the hydrocarbon zones to create an artificial oil/water contact that is continuously monitored, Hung said.

The field was discovered in 1986 with production originating from a Lower Miocene structure. Production from the granite basement began in 1988 and has reached a cumulative level of 1.3 billion BOE.

While none of the speakers addressed the impact of low oil prices on potential future Vietnamese fractured granite-basement development during their prepared remarks, Dung was asked about that afterward and said operators generally believe USD 70/bbl is the price at which new projects would be economic.

System Improves Safety, Environmental Performance

The Safety and Environmental Management System (SEMS) is a tool that is playing an important role in improving safe and environmentally sound offshore operations. The present and potential benefits of the SEMS were the focus of a double panel session hosted by the Center for Offshore Safety (COS). Representatives of operating and service companies composed the consecutive panels.

The SEMS is a nontraditional, performance-oriented tool for integrating and managing offshore operations to enhance safety by reducing the frequency and severity of accidents. The system focuses on the influences of human error and poor organization on accidents, continuous improvement of safety and environmental records, the encouragement of performance-based operating practices, and government/industry collaboration to promote offshore worker safety and environmental protection.

The US Bureau of Safety and Environmental Enforcement (BSEE) required SEMS implementation for oil and gas companies operating in federal waters in 2010, following the Macondo blowout. Practices that previously had been voluntary became mandatory as a result of the SEMS mandate. Expanded SEMS requirements announced in 2011 became effective in June 2013, with compliance required by June of last year. The US BSEE requires that operator SEMS programs be regularly audited.

The COS was created by the American Petroleum Institute following the Macondo incident to promote improved safety in offshore drilling, well completions, and operations. Based in Houston, the center has more than 25 member companies that include project owners, operators, and leaseholders; drilling contractors; and service and equipment providers. The COS provides certification of operator SEMS programs through accredited third-party audits and third-party SEMS certification of drilling contractors and service and equipment companies.

Kevin Renfro, general manager of Gulf of Mexico compliance and regulatory affairs at Anadarko, said that the SEMS as an integrated management tool centers on risk management. While planning and implementation are both essential, he said that risk management programs historically have had more issues with implementation than planning.

“Rocky Ride” Ahead for Shale Industry

Trent Jacobs, JPT Senior Technology Writer

Grey skies have settled over the upstream industry as it faces mounting challenges from the depressed oil market. The situation has perhaps been most pronounced in the US where rig counts have fallen at a record pace and the future of the shale revolution is unknown.

When will oil prices strengthen again? No one knows for sure. But history has proven that the pendulum swings both ways and when oil prices fall, at some point they head back up. “We have seen this again and again in the petroleum industry, and I am sure we will see it this time as well,” said Statoil’s Torstein Hole, the senior vice president for US onshore operations.

Hole, who has a background as an economist, offered his thoughts on the industry downturn during a luncheon at the conference. He said while he personally believes that prices will rebound, the industry will face a “rocky ride” and that now is the time to make steep reductions in development costs.

“We know that before this downturn, with oil above USD 100 a barrel, our industry was actually spending even more to produce less volume,” he said. “Based on this realization, Statoil had already started our improvement program to bring down costs before the market dropped, but now the situation has become critical.”

Some of the progress Statoil has made in this regard includes a reduction in the per-bbl cost of US shale oil by 20% in the past 2 years and Hole said the company is pursuing rate reductions from service companies. He added that the company is still looking for other reductions that will improve its long-term economics.

One of those cost-saving initiatives involves Statoil’s program to use carbon dioxide (CO2) foam for hydraulic fracturing instead of water. Hole said that the company has drilled a well in the Bakken for the pilot test, which is scheduled for September. Statoil has been working with General Electric to devise a way to recapture the CO2 after fracturing so that it can be used for multiple wells.

Hole opened his address by retelling the story of how Edwin Drake’s first commercial well in Titusville, Pennsylvania, led to the first oil boom and subsequent price crash in 1859. Many fortune seekers followed Drake’s lead and within 3 years the US was pumping out 3 million B/D of oil. Then prices fell into the basement and it would take the US Civil War to lift them once again. “So there is nothing new in this, but it feels just as painful every time,” said Hole.

The Drake Well was used as an analogy to our current times. Hole explained that high oil prices enabled the shale revolution to begin in Texas and North Dakota. But then the price of oil began its collapse late last year as the markets realized an oversupply and the US rig count fell at a record pace from nearly 2,000 last May to less than 700 as of that day.

Hole said that the path many companies were taking amid higher oil prices is now unsustainable. He added that while shale producers have the ability to produce more and adapt to lower prices, it remains to be seen how quickly that will take place.

 

Measures identified during planning, such as installing protective barriers and safeguards, must be executed. “We have to make sure that you’re doing that all the time,” Renfro said. “We have to have operational discipline, making sure that I am walking the talk. That what I say I’m going to do, I actually do on a daily basis consistently, whether someone else is watching or not.” The SEMS must regularly measure the company’s culture and its systems for achieving its safety and environmental objectives, he said.

Dwight Johnson, vice president of HSE (health, safety, and environment) for deepwater at Shell, spoke on the process safety management aspect of the SEMS. He noted that Shell has had an asset-integrity process-safety management program throughout his 35 years with the company. The program has evolved, and it fit well within the SEMS framework, requiring only modest change, when the SEMS rule was put into effect, he said.

The Shell process safety program, Johnson said, focuses on leadership behavior, effective design and application of barriers, standards and processes, motivated and competent people, and complacency avoidance. “We have a term we use around Shell called chronic unease—never get comfortable, never get complacent, always get better,” he said.

Kathy Kanocz, vice president of HSE for development and production North America at Statoil, said that while the SEMS rule came from a US regulatory body, the company learnings that have resulted have been global.

“We actually made a decision in 2013 that there was a better way to structure our emergency response,” Kanocz said. Statoil adopted an incident-command structured system globally, supplanting a system that had been in place for 40 years. “That was a big change,” she said. “And the business case for doing it had to be quite strong. At the end of the day, the business case was pretty simple—it was simplification, standardization, and the ability to have industry collaboration.”

Drilling contractors and service and equipment companies are not re-quired to have an audited SEMS, but many of these companies have implemented SEMS programs. Offshore operators must show the US BSEE that the companies with whom they contract are SEMS compliant.

OTC Programs Offer Networking Opportunities and Recognize Achievement

  • OTC’s Spotlight on New Technology Awards recognized 17 technologies for their innovation in allowing the industry to produce offshore resources, including two companies in the new category of Small Business Awards.
  • During the fifth Annual OTC Dinner, OTC presented the 2015 Distinguished Achievement Award to Elmer Peter Danenberger for his significant contributions to offshore safety and environmental protection. The Distinguished Achievement Award for Companies, Organizations, and Institutions was presented to Petrobras for its pre-salt development, and Ray Ayers was honored with the OTC Heritage Award in recognition of his 50-plus years in offshore research and development.
  • OTC also hosted The Rice Alliance Startup Roundup. At the new event, 50 emerging companies had the opportunity to meet one-on-one with investors.
  • The Next Wave, OTC’s program for young professionals, was attended by nearly 500 people and focused on how to face the challenges ahead.

 

Chris Tagoe, vice president of HSE at Cameron, said that the introduction of the SEMS “was a great opportunity for us to look at what we were doing and ask ourselves how we could make that switch to competency assurance.” In implementing the SEMS, Cameron has created a single, new training and competency platform applicable across its workforce.

Through the SEMS, the company has “been able to identify gaps in competency assurance,” Tagoe said. He pointed to the success of internal SEMS audits and said that the company gets “very direct feedback” on the needs to address.

Bob Moschetta, senior vice president of HSE, training, and quality at Oceaneering, praised the increased focus and collaboration that has resulted from the SEMS within his company and the industry. “From an audit point of view, being a service provider, having a common language, common understanding, and protocol is important as we work for various operators,” Moschetta said. The SEMS has brought about “significant improvement in process safety from a service company, provider point of view,” he said.

A checkpoint system now in effect calls for his company’s personnel to have the operator verify a work order, such as cutting a subsea line, before the work proceeds. Moschetta said that this process had already allowed one operator to catch an error and revise a work order to prevent the wrong line from being cut.

Paul Linkin, vice president of quality and HSE at Pacific Drilling, said that his company entered the US Gulf of Mexico market and became an early adopter of the SEMS. The company voluntarily went through an independent third-party audit in 2013 when it joined and became a board member of the COS. Pacific Drilling became the first contractor company to earn SEMS certification by the COS, and Linkin urged other contracting companies to do the same. Schlumberger has earned COS SEMS certification, and other contractors are doing so, he said.

“It is not just Pacific Drilling that benefits from the process we went through,” Linkin said. “The fact that we can present a certificate just to show that we have an independent verification of our management system is one way that we can support the operator.”

OTC Highlights Technical Challenges, Effects of Oil Price Volatility

Joel Parshall, JPT Features Editor

01 July 2015

Volume: 67 | Issue: 7

STAY CONNECTED

Don't miss the latest content delivered to your email box weekly. Sign up for the JPT newsletter.