Unconventionals lead the way for drilling automation, but business model defines uptake

John de Wardt, president of DE WARDT AND COMPANY, says the drilling sector’s business model based on dayrates hampers the rate of adoption of automation. Mr de Wardt moderated the SPE/IADC Drilling Systems Automation symposium earlier this year and will moderate a panel discussion at the Business Solutions for Drilling Automation workshop on 18 June in Istanbul.

By Katie Mazerov, contributing editor

Industry’s ongoing efforts to bring automation to the drilling sector will progress over time as a “natural alignment” occurs among the various players, with unconventional developments serving as the impetus for change, a Shell executive contends. “While we see significant opportunities in utilizing automation to improve drilling efficiencies, there is a lack of natural alignment to move it forward,” said Jeff Wahleithner, vice president, global unconventional wells for Shell. “As the industry develops further, the business opportunities for automation will become more obvious, and it will happen, as it has in other industries. It’s a matter of time.”

Mr Wahleithner will be among five presenters in a panel discussion at the Business Solutions for Drilling Automation workshop on 18 June in Istanbul. The event, which is being held in advance of IADC World Drilling 2013, is sponsored by the IADC Advanced Rig Technology (ART) Committee and the SPE Drilling Systems Automation Technical Section (DSATS). Registration can be completed here.

“Shell is pursuing automation to improve safety and efficiency,” he said. “The industry is going through a step-change with the unconventional plays, as massive resources are now recognized as potential developments. These developments will require a high intensity of manpower and equipment. Automation is a critical tool to address these challenges and continuously improve the efficiency.”

That intensity is manifested by the fact that unconventional production requires a large number of wells, with repetitive drilling techniques that lend themselves to automation. “Relative to most conventional operations, the number of wells required to increase production in unconventionals is significant,” Mr Wahleithner continued. “The overall efficiency of the well construction dominates the economics for unconventional developments.”

Joining Mr Wahleithner on the panel will be Jay Minmier, 2013 IADC vice chairman and president of Nomac Drilling; Hege Kverneland, corporate vice president and chief technology officer, National Oilwell Varco; Miguel Angel Fernandez, director, vertical market chemical industries for Siemens; and Mikael Larsson, robotics manager, ABB Turkey. Their presentations will be followed by a group discussion.

The panel will be moderated by John de Wardt, president, DE WARDT AND COMPANY. Mr de Wardt agrees that unconventionals will be a driver of change, but he also says the drilling sector’s business model that is still based on dayrates is impeding the transition. “A new demand for highly efficient, repetitive drilling for unconventionals creates an environment where adoption of automation will bring benefits,” he said. “But the rate of adoption of automation in drilling is hampered by the current business models, not the technology application.”

“Right now, the industry is very fragmented so that when we go to drill a well, we have an array of different pieces of equipment and services,” Mr de Wardt continued. “In order to enable automation, there needs to be integrator for bringing data together and moving data between the multiple sensors and various pieces of equipment into a closed-loop system so it can operate autonomously. At the same time, the business model needs to change to drive the rewards for applying integration and automation.”

Mr de Wardt also contends the drilling industry remains far behind industrial automation, including autonomous mining systems with remote control, as demonstrated at a DSATS/ART symposium held in Amsterdam in March. “This application gap provides an opportunity to accelerate the adoption of automation, which is our reason for bringing outside speakers to the debate.”

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US unconventionals at center of Statoil’s E&P strategy

By Joanne Liou, associate editor

Although Statoil has deep roots as a Norway-based offshore operator, the company is now finding the US onshore business to be at the heart of its E&P strategy. With core operations in the Bakken, Marcellus and Eagle Ford, the US onshore business has become the fastest-growing sector for Statoil within the past three years, Stephen Bull, vice president – commercial North America, D&P, said. Mr Bull discussed how the company landed in the US onshore business and how it has become part of Statoil’s corporate strategy in a presentation at the IADC Drilling Onshore Conference on 16 May in Houston.

Statoil’s goal is to produce 2.5 million bbls/day by 2020, and US unconventionals is at the heart of its E&P strategy to accomplish that goal, Stephen Bull, vice president – commercial North America, D&P for Statoil said.

Statoil is a historically deepwater-oriented company, Mr Bull said; approximately 1.5 million bbl of its 2 million-plus bbl daily production come from Norway, and the remaining comes from Angola, Azerbaijan and Brazil. However, “the fastest-growing area is by far North America,” Mr Bull stated. In fact, the US unconventional business is now at the center of Statoil’s goal to produce 2.5 million bbl/day by 2020. This E&P strategy consists of three elements: a strong management system, technology, and a long-term commitment to the communities in which it operates.

The first element – a robust management model – is applied through the whole company, Mr Bull emphasized. For example, when Statoil entered the US onshore business, the company created an operations support team to analyze performance metrics to enhance its understanding of the business. “That team is developing a cross-functional collaboration,” he said. “We looked at the best wells in the Eagle Ford. We looked at other operators, benchmarked them completely across the board, gave them rational reviews and looked at what are the best operations.” Based on those findings, Statoil saw the potential for 45% to 50% improvement in performance. “The first few wells that we have drilled in the Eagle Ford have been fairly close to what we want to achieve.”

Statoil also aims to apply its knowledge and experience in hostile recovery techniques used in the Norwegian sector to the US onshore. In Norway, the company has achieved more than 50% recovery rates in some fields and some as high as 75%. While acknowledging that the US plays behave differently and have different permeabilities, “we want to apply that (experience) to the US onshore” to increase recovery rates, Mr Bull said.

In the Williston Basin, Statoil has been swapping out its older rigs for walking rigs that can reduce drilling and skid times and is using dual fuel technologies when possible, Mr Bull said. Further, the company has 700 miles of oil, freshwater and saltwater pipelines in the Williston Basin that help to “reduce thousands of trucks on the road when we are doing our frac jobs,” he continued. Statoil also continues to develop new technologies and solutions for unconventionals at its research center in Houston.

Part of Statoil’s long-term perspective is its investment in industry collaboration and commitment to the communities in which it operates. Mr Bull believes that his company’s efforts are apparent in three ways: direct financial support, participation on local boards and volunteer efforts. “Employees serve on school boards, hospital boards and volunteer efforts as well, from trash pickups to cook-offs,” he noted.

Besides communication and leadership knowledge and understanding, Mr Bull noted that there’s also an X factor to Statoil’s E&P strategy. “You can’t just come in here and talk about processes and ‘you must follow this,’ ” he stated. “We need some creativity in there, and you need a just-do-it attitude and an entrepreneurial feeling you get in the US onshore. We don’t want to lose that.”

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Fit-for-purpose rigs, unconventionals drive Statoil production goals

By Joanne Liou, editorial coordinator

Statoil is directing its fit-for-purpose rig fleet and technology strategy to help reach a production goal of more than 2.5 million boe/day by 2020, up from 1.9 million boe/day in 2010. Noting recent successes in increasing the average oil recovery rate from Statoil-operated fields from 49% to 50%, the company wants to push that percentage even higher, Karl Johnny Hersvick, Statoil senior vice president of technology excellence, stated. The company outlined its growth strategy in a series of press conferences at the 2012 OTC last week in Houston.

Jon Arnt Jacobsen, chief procurement officer at Statoil, and Oystein Arvid Haland, senior vice president drilling and well, discussed their company’s shift from fixed platforms to using mobile rigs to drill subsea wells. In collaboration with Aker Solutions, Statoil’s Category B rig is under construction, with delivery of the first unit expected in the second half of 2015. The rig design fills the gap between light intervention vessels (Category A, which has been in operation since 2003) and conventional rigs (Category C), according to Statoil. The rig is designed to improve oil recovery, and its design has been optimized for heavy intervention and light drilling in existing wells.

A Category D rig, targeted for mid-water production operations, also is under construction and expected to be delivered in 2014 to 2015, while Category J is designed for shallow waters and harsh environments. The latter is expected to be delivered in 2015 and will provide 20% more cost-effective well construction.

Statoil’s developing rig fleet is compounded with the company’s focus on four areas: seismic imaging and interpretation, reservoir characterization and recovery, efficient well construction, and a “subsea factory.” The subsea factory project involves the development of the Åsgard subsea gas compression by 2015 and acquiring all the necessary elements for a subsea process facility on the seabed to accelerate production. “Our mission is that technology connected to (reservoir recovery) will contribute to increase an additional 1.5 mboe/d by 2020,” Siri Espedal Kindem, senior vice president of research and development, said. “Just as important is a step-change in well construction efficiency. We have a clear ambition ahead to reduce the time we spend on well construction by 30% and 15% in spending.”

Statoil currently has about 3,000 employees working on 300 increased-oil-recovery projects. In August, the research and development division will become the research, development and innovation division, Mr Hersvick stated. “It’s a concrete measure to get our hands on more good ideas, to push recovery rate even further. We cannot compete with supermajors of this world when it comes to funds and resources, but we can and we will compete when it comes to innovation.”

Statoil expects 12% of its portfolio to come from North American unconventionals by 2020, Torstein Hole, senior vice president of development production North America – US onshore, said.

Moving onshore, Statoil expects 500,000 million boe/day to come from North American unconventionals by 2020, Torstein Hole, senior vice president of development production North America – US onshore, said. The company’s strategy for growth in US shale plays is founded in its presence in the Marcellus, Eagle Ford and Bakken, with the Eagle Ford paving the way for Statoil’s operatorship. Statoil entered a 50/50 joint development agreement with Talisman in 2010. With 165,000 net acres and 12 rigs currently drilling, the play has produced about 640 million boe to date. Statoil is positioned to become operator within that play by the end of 2013.

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