Zhang Mi, chairman and president of Honghua Group, spoke with Drilling Contractor at the 2013 OTC. He noted that while his company’s current focus is on the US onshore market, he believes Honghua can eventually deploy the same technologies in China once unconventionals development expands in that country.

Honghua Group and its US subsidiary Honghua America are developing a next-generation onshore rig for shale drilling called the US #1; a prototype is under construction at the company’s Houston factory and scheduled for completion in late 2013 or early 2014. Further, the company is working with Baker Hughes to field test Honghua’s 6,000-hp hydraulic fracturing pump in Texas. Speaking during an exclusive interview with Drilling Contractor at the 2013 OTC, Zhang Mi, chairman and president of Honghua Group, noted that such technologies are examples of his company’s focus on the US onshore market; yet, they are also technologies that he believes Honghua can eventually deploy in China once development of unconventionals expands in that country.

The US #1 rig has been designed to be highly mechanized and highly automated, Mr Zhang explained, and one technology that will be incorporated is Honghua’s new direct-drive triplex mud pump. The pump is driven by a top-mounted AC motor that powers the pinion shaft. This removes the intermediate transmission (e.g. belt, chain and gear), reducing maintenance and vibrations and lowering noise.  A smaller environmental footprint is another key feature of the US #1 rig. Mr Zhang noted that it has been designed to be powered with natural gas and LNG, and perhaps even grid power in some cases. “If (US #1 is) successful, it will be an example for Honghua’s next-generation rigs.”

The company also continues work on its 6,000-hp frac pump, introduced at last year’s OTC. Honghua is now working with Baker Hughes to bring this technology to the US market for field-testing, Mr Zhang said. “Once the field tests are complete, I believe it will also bring about step-changes for shale drilling in the US.” Field-testing will likely take place in Texas around August, he said.

Honghua Group’s triplex direct-drive pump, exhibited at the 2013 OTC, reduces maintenance, increases service life and reduces noise emissions and vibrations. The pump will be integrated into Honghua’s next-generation rig, the US #1.

Looking toward the Chinese market, Mr Zhang explained that although there are approximately 2,000 land drilling rigs operating in China, most of them are older mechanical or SCR-style rigs. “There is a significant need for renewal of the fleet,” he said, adding that he believes innovations such as Honghua’s direct-drive triplex pump will be able to impact the Chinese market once it’s proven in the US. “The locations in China where there’s potential for shale gas are not like Texas, where you have wide spaces where you can build wellsites. In China, they are located in mountainous regions, so access to shale gas reserves is more difficult. Being able to reduce the footprint is especially important.”

Although onshore rigs and technology remain at the core of Honghua’s business, the company is also pushing ahead with its entry into the offshore rig construction segment, with the large-capacity Honghai mobile crane the centerpiece technology driving their efforts. “When our Honghai crane is completed with a lifting capacity of 22,000 metric tons, you can construct the entire platform on land and then transport it offshore as a complete piece… We believe this will be a first in the world,” Mr Zhang said.

Construction of the crane began in October 2012 near Shanghai. Once completed, Honghua plans to use it for large-scale and simultaneous production of five to 10 offshore rigs, he said. The crane will be completed by the end of 2013 or Q1 2014, and Mr Zhang noted that discussions for offshore rig orders are ongoing, primarily with non-Chinese companies.

Marathon Oil forecasts its production from US resource plays will increase by 150% from Q3 2011 to Q4 2013, Bryan Roy, vice president – drilling & completions for Marathon Oil, said at the 2013 IADC Drilling Onshore Conference.

Marathon Oil has determined that it may drill more than 3,000 wells in its Eagle Ford acreage, up from an earlier estimate of approximately 1,200. In fact, the company expects production from its US resource assets, which also include the Bakken and the Woodford, to increase by 150% from Q3 2011 to Q4 2013, Bryan Roy, vice president – drilling & completions for Marathon Oil, said. “When you talk about shale and moving the needle for a company that is producing between 400,000 and 450,000 bbls/day, that is substantial,” Mr Roy said during a presentation at the 2013 IADC Drilling Onshore Conference on 16 May in Houston.

For Marathon, the impact that US resource plays are having on the company’s portfolio is significant. As an example, its US business once provided capital for large expenditures overseas, but that pendulum has swung in the opposite direction due to the growth in US unconventionals. “Now, a lot of Equatorial Guinea and Norway production is funding a lot of capital in the US,” Mr Roy said. “We are targeting 5% to 7% average growth rate (in production) across the world.”

Marathon currently has 16 rigs working in the Eagle Ford and expects to spend nearly $2 billion in that play this year, according to Mr Roy. “One of the challenges we continue to have is we tend to overspend our capital because we keep drilling wells so fast,” he stated. “That will continue to be a problem, I hope, because it’s a mark of efficiency.” The company also continues to study its approach to developing its Eagle Ford acreage, such as optimal well density, lateral lengths and completion techniques. “A lot of pilots in the ground now are already completed … and the science looks good. We spent a lot to get into the Eagle Ford, but it’s looking a lot better than what we thought it was going to be,” he said, referring to the increase in the number of estimated wells.

Outside of the US, Marathon also continues an aggressive exploration program in Kurdistan in northern Iraq, where the company made entry in 2010. It currently has two rigs drilling in the Harir and Safen blocks, which Marathon believes have “the potential for the largest unexplored basins in the world,” Mr Roy said. “We are very interested to see how productive the wells could be.”

The region does come with significant operational challenges, however, from security issues to high H₂S concentrations in the ground. In fact, some zones can carry up to 22% H₂S combined with 13% CO₂, Mr Roy said, making it a challenge to complete and make long-term production adequate. Other challenges include lost circulation and issues with primary cement jobs and directional control. Beyond that, “we still have significant issues relative to emergency response plans and evacuations that could be required,” he noted.

Dual-fuel kits on drilling rigs provide flexibility and carry a lower conversion cost than LNG-dedicated rigs, Bryant Dear, Noble Energy, said at 2013 IADC Drilling Onshore Conference in Houston on 16 May. However, the cost savings for dual-fuel engines are still to be determined, he added.

After a pilot program initiated in early 2011 to compare the use of LNG versus diesel to power drilling rigs, Noble Energy now has four dual-fuel rigs and one LNG-dedicated rig operating in the DJ Basin and the Marcellus. “It’s going to cost you to convert your rig to LNG. There’s a price tag to it, but we see that price tag being well worth it,” Sean Howley, senior business analyst for Noble Energy, said in a presentation at the 2013 IADC Drilling Onshore Conference in Houston on 16 May. “We actually think it will pay off in two years,” he said of the LNG-dedicated rigs. “After that, it’s all savings.”

During the pilot program, Noble Energy gathered 12 months of operating data on three rigs – two that were LNG-dedicated  and one running on diesel. The goal was to demonstrate the operational and economic viability of displacing diesel and powering the majority of Noble’s rigs with LNG, Bryant Dear, a co-presenter with Mr Howley, explained. Mr Dear is a drilling engineer in the DJ Basin for Noble Energy.

After evaluating the use of field gas and CNG, Noble decided that LNG would be the best option due to its higher energy density and consistent quality. There were also multiple options for turnkey providers, Mr Howley explained.

Sean Howley, Noble Energy, said at the conference on 16 May that his company is committed to using LNG for more operations going forward. Noble is currently building an LNG plant in Colorado to provide a closer fuel source.

Currently Noble has four fit-for-purpose dual-fuel rigs –Rigs 828 and 829 in the DJ Basin and Rigs 542 and 543 in the Marcellus, all from Precision Drilling. Although the cost savings that can be achieved for dual-fuel rigs are still “to be determined,” Mr Dear said, that is offset by a much lower conversion cost than LNG-dedicated rigs. Each of the four dual-fuel rigs is equipped with a GTI Altronics bi-fuel kit set up on three Caterpillar engines, he explained. “It’s too early to tell what our (fuel substitution) rates are, but we’re working to increase those as technology gets better and these systems get better… One thing we do know is you’ve got to displace as much diesel as possible (to achieve maximum cost savings).”

Mr Howley noted that Noble Energy’s commitment to LNG is such that the company is building an LNG plant in Weld County, Colo. “That’s going to bring our price much further down; it’s going to be an amazing option,” he continued. Not only does Noble plan to build a balanced portfolio of LNG-dedicated rigs and dual-fuel rigs, but the company is already expanding LNG applications to its frac fleet as well.

Noble currently has one frac engine running on a mix of LNG and diesel in the DJ Basin and plans to have another switch to dual fuels by June. “If we don’t need (the LNG) on a frac job, we can roll it over to one of our rigs. When we don’t need it on the rig, we can roll it over to a frac job. It provides some really nice synergies for us,” Mr Howley said.

IADC is working hard to support drillers and ensure that every crew member has the training, knowledge and support they need to work safely and efficiently “in a business that demands the very best,” 2013 IADC chairman David Williams said.

IADC is devoting significant energy and focus to address the interests of its onshore members, including the creation of an Onshore Committee and the establishment of regional forums in Midland, Denver, Lafayette and Oklahoma City, 2013 IADC chairman David Williams said in the keynote presentation at the IADC Drilling Onshore Conference & Exhibition in Houston on 16 May. Such groups will provide places for members to discuss issues that drillers are facing in the onshore market. “Safety, for example, remains the primary focus of IADC and its member companies, and rightly so. Safety is our most important operational integrity measure, and zero incidents is the target of every driller and our customers,” Mr Williams said.

One key initiative that IADC kicked off in 2012 is the Knowledge, Skills and Abilities (KSA) project, which is expected to be completed this year. This milestone project to develop enhanced competency guidelines will help to ensure that rig crews have the appropriate training and skills to work safely and efficiently “in a business that demands the very best,” Mr Williams said.

Another project under way is the IADC Drilling Lexicon, a website that will provide a forum for critical review of drilling terms. “As we all know, terms and definitions shift overtime, and we’ll need everyone in the industry to keep this website up to date for the benefit of everybody,” Mr Williams said. One major goal in providing these commonly used drilling terms is to assist regulators around the world in developing regulations that are consistent with international standards.

IADC has further assembled a team of more than 100 drilling experts to update the IADC Drilling Manual. Major revisions of the IADC HSE Guidelines and Deepwater Well Control Guidelines are under way as well.

Cactus Drilling’s Ron Tyson, who is serving as vice president of the IADC Onshore Division, introduced David Williams at the opening session of the IADC Drilling Onshore Conference in Houston on 16 May.

“These are just a handful of examples of the important initiatives that IADC committees and staff are currently working on to forward the goals of our association. But none of these activities can happen without you. Our members play an integral part in moving the industry forward, and it’s only with your participation that IADC can achieve success. Committees, chapters and conferences like this are all ways to become more involved in IADC,” Mr Williams said.

Additionally, IADC continues an reorganization its committee structure, with one goal being to enhance the value of committees focused on onshore issues, including the Rig Moving and Well Servicing committees, he said. “We recognize that the important work and the necessary work to change our industry for the better is generated in IADC’s committees. The committees are a place where people come together to share experiences, brainstorm new ideas and develop initiatives with the industry,” he stressed.

Jason McFarland, IADC VP of corporate development and chief of staff, opened the conference on 16 May in Houston. He noted IADC’s efforts to enhance communication with members “and demonstrate our relevance to every individual on every rig.”

With significant offshore discoveries and robust growth of shale development, as well as projects such as the Keystone XL pipeline, the US has an opportunity to transform from a nation that imports energy into one that’s independent from the world’s oil market, he continued. “Reaching that potential means that the US and state governments will need to work together with the energy industry to unlock resources to meet future demand… We simply cannot tolerate politics as usual here.” As a call to action, he said that industry must be engaged in active dialogue with stakeholders around the world. “If you are not involved in this debate, get involved… If you don’t, we could be sidelined by those in government who would just as soon see us go out of business. As drillers, it’s time for us to get to work telling our story.”

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.”

Doug Lawler will join Chesapeake Energy as CEO and a member of it Board of Directors in June.

Robert Douglas (“Doug”) Lawler will join Chesapeake Energy as its CEO and a member of the Board of Directors, effective 17 June, the company announced this week. Mr Lawler currently serves as senior vice president, international and deepwater operations at Anadarko Petroleum. He is a petroleum engineer with 25 years of experience in the upstream exploration and production industry, with significant expertise in asset development, operations management and engineering, as well as experience in corporate and strategic planning.

With Mr Lawler assuming the CEO position, the office of the chairman will be discontinued, and Archie W. Dunham, Steven C. Dixon and Domenic J. Dell’Osso Jr. will continue to serve in their roles as non-executive chairman of the board; executive vice president of operations and geosciences and chief operating officer; and executive vice president and chief financial officer, respectively.

“Doug is a talented and proven executive with the ideal skill set to lead Chesapeake forward and capitalize fully on our world-class assets. Throughout his 25 years in the upstream E&P industry, Doug has earned a reputation as a highly engaged and knowledgeable leader who delivers superior operational performance and capital efficiency. The board is confident that Doug’s deep technical upstream and engineering expertise as well as his strategic and financial skills will serve Chesapeake well,” Mr Dunham said.

Mr Lawler commented: “I am honored and excited to be joining Chesapeake Energy with its unparalleled asset portfolio, focused management team and very talented and dedicated employees. There is significant value in Chesapeake’s asset base and the growth potential of the company is tremendous. I look forward to accelerating the momentum that the Chesapeake team has built to generate value for our shareholders in the years ahead.”

During Mr Lawler’s 25 years at Anadarko and Kerr-McGee, he served in multiple engineering and leadership positions within a diverse geographic portfolio, including US onshore, deepwater Gulf of Mexico and international assets. He was most recently senior vice president, international and deepwater operations and a member of Anadarko’s Executive Committee. In this capacity, he was responsible for new and existing developments, including the company’s multi-train LNG project in Mozambique. He previously served as Anadarko’s vice president, operations for the Southern and Appalachia Region, where he directed the development of four major shale plays: Eagle Ford, Marcellus, Haynesville and Permian Bone Spring/Avalon. Prior to that, he held positions of increasing responsibility within Anadarko’s operations, business planning and analysis departments, including vice president, corporate planning. Mr Lawler began his career in 1988 at Kerr-McGee, which was acquired by Anadarko in 2006.

Mr Lawler is a member of the Society of Petroleum Engineers, the World Affairs Council and The Houston Museum of Natural Science. He holds a bachelor of science degree in petroleum engineering from the Colorado School of Mines and an MBA from Rice University.

Speaking at the 2013 OTC in Houston on 6 May, Lamar McKay, chief executive of BP Upstream, said the company has streamlined its upstream portfolio and is focusing on four major areas: the North Sea, Angola, Azerbaijan and the Gulf of Mexico.

Over the next decade, as much as 75% to 80% of BP‘s majority group capital expenditure will be spent in upstream, Lamar McKay, chief executive of BP Upstream, said at the 2013 OTC in Houston on 6 May. “Safe, reliable and compliant operations are the foundation for sustaining our business. With safety being at the core, we’re moving to enhance standardization, simplify our processes and drive integration across the group,” he said. “We know that at BP, to remain competitive, we need to continually adapt. We continue to take a hard look at ourselves and continually improve and refocus on how we do business.”

Mr McKay explained that the company has streamlined its portfolio to concentrate on oil and gas exploration, deepwater operations, technology development and utilization, and management of giant fields. “We moved to focus our business to a smaller operating footprint, generating cash and building a quality platform for the future.” This has primarily been achieved through a structured program of divestments and investments, as well as company reorganization to improve operations, he said. “When we decided to restructure BP Upstream, we asked ourselves a very basic question: What’s our objective? If we were to justify the immense expenditure of time, money and talent necessary to bring new energy supplies to the market, then our objective needed to be value.”

Part of the asset restructuring involved the sale of approximately 30% of BP’s well count and 50% of its pipelines while still retaining 90% of its crude reserves. “That has increased the overall quality of our remaining portfolio significantly, while simultaneously reducing its age and its complexity. We’re now more able to apply our strengths to fields that are younger with more room to grow.”

Much of BP’s current upstream focus is on Angola, Azerbaijan, the Gulf of Mexico (GOM) and the North Sea, Mr McKay said, adding that he expects these four areas to generate about half of BP’s operating income by 2020.

The North Sea is one of BP’s oldest offshore positions, “but it’s got plenty of life left in it,” he said. “After 40 years and nearly $50 billion of BP investment, we still have a staggering 40% of the resources in our portfolio yet to be produced.” He highlighted the Clair field as an example of what technology can accomplish. “This field was discovered in 1977, and due to its complex geology, first oil didn’t produce until 2005. Reserves were estimated at only 250 million bbls, but today that number could be in the billions.” He explained that insight into the field’s complex reservoir and geology was gained through a permanent 4D seismic installation that gathers time-lapsed seismic images over the same area again and again, allowing for the potential to see fluid changes over time.

Angola is the newest of the company’s four focus areas. Last December, BP started the PSVM development in Block 31 offshore Angola, which consists of four fields – Plutão, Saturno, Vénus and Marte. PSVM produces through a converted-hull FPSO that is using subsea infrastructure to develop the four fields simultaneously. “It sits in over 2,000 meters of water, features 75,000 tons of subsea equipment and 20,000 tons on the topside.” The FPSO has already produced more than 10 million bbls since coming online in December, he said, adding that Angola’s pre-salt geological formations are also excellent prospects for seismic technology in BP’s exploration program.

In Azerbaijan, BP has produced 2 billion bbls from the Caspian Sea and believes there is much more. “The region has over 40 years of oil and gas resources, and our position is strong. After 15 years of operations, we’ve produced only 18% of the available resources. We’re planning as much as $12 billion in capital expenditure between now and 2017,” he said.

The company also operates four platform hubs in the GOM, where BP is currently the largest deepwater leaseholder, with more than 700 leases, he said. “Our current plan is to invest about $4 to $5 billion a year for the rest of this decade.” BP’s GOM position is built around assets early in their life cycle, he said. “Only about 20% of our resources base has been produced.” In the GOM, BP also has three major operated projects under development: Galapagos, Na Kika Phase 3 and Mad Dog Phase 2. The operator has seven deepwater rigs in the GOM today and plans to have eight there by the end of the year.

To drive performance in these four areas, as well as other assets, BP has identified several major technology “flagships,” including seismic acquisition and interpretation, enhanced oil recovery and Field of the Future.

“Field of the Future can be described simply as turning bits of data into oil and gas incremental production and recovery,” he said. Boosting data sharing between experts sitting hundreds to thousands of miles apart, the company has laid more than 1,200 miles of fiber optic cable, “nearly the distance between Houston and Detroit.” Mr McKay explained that real-time monitoring of operating production and injection data is becoming fundamental in the management of more reservoirs. “Seismic sensors installed on the seabed gather information about a reservoirs behavior and looks for changes over time. The data is then transmitted to monitoring centers onshore where technicians can analyze it in real time. Technologies like this are helping us manage our operations from anywhere.”

Field of the Future is a registered trademark of BP.

Speaking at the 2013 OTC, Jason Nye, senior vice president US offshore for Statoil, said the company is currently producing three fields in the Gulf of Mexico at approximately 40,000 bbls of oil/day but hopes to increase that number to approximately 200,000 bbls/day by 2020. Statoil recently also announced the sanction of the Julia field development with ExxonMobil.

Pursuing further growth in its US offshore portfolio, Statoil has sanctioned its fourth field development in the Gulf of Mexico (GOM). On 7 May, Statoil and operator ExxonMobil announced the sanction of the Julia field development; the partners each own 50%. “It’s about a $4 billion project for the first phase. I would have to say it’s one of the largest fields ever discovered in the GOM,” Jason Nye, senior vice president US offshore for Statoil, said on 8 May at the 2013 OTC in Houston. “It’s in the emerging Paleogene play, so we decided to do a phase development to reduce some of the risk because it hasn’t been widely drilled or widely produced.”

The first phase will consist of six wells, he said, and drilling operations are expected to start in 2014 and first production in early 2016. “This field is going to be producing for decades and decades, and there will be multiple phases. It’s also going to be a fantastic place to utilize some technology we’re developing and have developed going forward to extract more oil from those reservoirs.” The life of the Julia field is estimated to be up to 40 years, with an initial production rate of as much as 34,000 bbls of oil/day.

The field, located approximately 200 miles south of New Orleans, La., was discovered in 2007 and is estimated to have nearly 6 billion bbls of resource in place. The field development is projected to take approximately three years.

Julia, which is in some 7,000 ft of water and 30,000 ft under the seafloor, will be a subsea tieback to the Jack and St. Malo floating production platform, where Statoil is a co-owner with Chevron, Mr Nye said. The Jack and St. Malo platform is approximately 15 miles from Julia and was sanctioned in 2010.

Further, Statoil is pushing forward with operations in the Logan field, another Paleogene discovery and the company’s first operated discovery in the Gulf of Mexico. The company used the ultra-deepwater semisubmersible Maersk Developer to drill one well in the Logan field, which is currently in the appraisal phase, Mr Nye said. “With that one well, we’ve proved out somewhere between 1 and 2 ¹/₂ billion bbls in place.”

With the block’s lease expiring in April 2015, Statoil has put together a tight schedule to develop Logan. “We expect to have first oil as early as 2018. This could be a stand-alone or a tie-back; it’s an interesting neighbor with some other discoveries.” Statoil will spud Logan’s appraisal well within the next week, again using the Maersk Developer, he said on 7 May, and in about 90 days will know whether to will move forward with project, though the company is very optimistic about the prospects.

Statoil currently has 340 leases in the deepwater GOM and 12 projects, operating in both the Miocene and Paleogene plays. The Miocene is more traditional, Mr Nye said, with high recoveries and high initial rates. The Paleogene play has deeper reservoirs in 7,000 to 10,000 ft of water and reservoirs at 30,000 to 31,000 ft under the seafloor. “I’d say we have a balanced portfolio because we’re evenly mixed between the more mature Miocene and the emerging Paleogene. And we have a significant presence in some of these emerging plays. (Industry has) been producing in the deepwater GOM since the ‘30s, but new plays are coming about, and we’re still finding new things.”

Statoil entered the GOM market in 2004 when the company was looking for areas with significant resource potential, Mr Nye said. “We have a long history of working in challenging and difficult environments, and we felt right at home here in the Gulf of Mexico.”

In addition to its four field developments, the company has three producing fields in its GOM portfolio, including Spiderman, Caesar Tonga and Tahiti. The three fields are currently producing at approximately 40,000 bbls of oil/day total, he said, but Statoil hopes to increase that number to about 200,000 bbls/day by 2020.

On the technology side, Statoil is pursuing a program known as “Crack the Paleogene,” which is focused on developing a tool kit of nearly 20 technologies, including electrical submersible pumps, multilateral technology, and water and gas injection. By applying these technologies, Statoil hopes to increase recovery rates from typical GOM fields from less than 10% to more than 20%, Mr Nye said. “The Gulf of Mexico has been a place where technology has been kind of the leading edge and push the envelope into deeper and deeper water and reservoirs.”

Serko Sarian, telemetry and conveyance portfolio manager for Schlumberger, talks with Drilling Contractor associate editor Katherine Scott about the company’s TuffLINE composite wireline cable on the exhibit floor at the 2013 OTC on 6 May in Houston. Developed over five years at the Schlumberger Houston Conveyance and Surface Equipment Center, the cable consists of a seven-conductor electrical core protected by two opposite wound steel armors and engineers out high-tension conveyance limitations.

Dato’ Wee Yiaw Hin, PETRONAS executive vice president of exploration and production, described the transformation of the company since its inception in 1974 to a Fortune 500 company with increasing global assets, at the 2013 OTC in Houston on 6 May.

National oil companies (NOCs) continue to assume an increasingly meaningful role in the oil and gas industry, a role that may not have been expected just a couple of decades ago, Dato’ Wee Yiaw Hin, PETRONAS executive vice president of exploration and production, said at the 2013 OTC in Houston on 6 May. “NOCs learned from the IOCs to take a more meaningful role in management of their own assets – in the development and operations of their own assets,” he stated. Further, with increasing strategy and operational autonomy, the capacity that they’ve acquired and their financial strength, NOCs are pushing expansion outside their home countries and across the globe, he added.

NOCs hold approximately 80% of the global reserves and production, according to Dato’ Wee, and the percentage of reserves is “expected to grow as (NOCs) expand and others find more globally.” Drawing upon PETRONAS’ transformation, he explained that when the company formed in 1974, its main role was to act as a local regulator and manager of domestic research. Throughout the 1980s to 1990s, “PETRONAS started to build a lot of integrated upstream and downstream and gas projects successfully,” he noted. The company entered the international market in the ‘90s, and by 2012, Fortune Magazine ranked PETRONAS 68 and 12 in revenue and profit, respectively, in its annual listing of Fortune Global 500 Top Companies.

Operating in 55 countries, “PETRONAS is now a fully global and integrated oil and gas company,” Dato’ Wee said.

Crediting the company’s success to strategic and operational autonomy, Dato’ Wee noted that its growth has been unencumbered by governmental bureaucracy and restrictions, and PETRONAS embodies the principles of an incorporated company. “We will comply in terms of strong corporate governance, an independent board and management system,” he said. “We believe that this business model is something we can work with now, globally and in Malaysia. We should be able to stand on our own and be treated in the same way we treat the IOCs.”

PETRONAS’ daily production of 2 million bbl is set to grow by approximately 2.5% a year over the next five years via a focus on three areas: an aggressive EOR program, innovative risk service contracts for marginal and difficult fields, and aggressive exploration to grow domestic reserves and HPHT and deepwater plays, Dato’ Wee explained.

One significant difference between NOCs and IOCs continues to be the fact that NOCs often have a broader role to play in supporting the economic growth of its home country. Growth at PETRONAS, for example, has led to a 10-fold increase in economic activity in Malaysia, Dato’ Wee said. He also encouraged international service contractors to establish a presence in Malaysia, noting the continued need for more capability and technology. “We encourage the transport of technology and capability to our industry through a partnership or JV with a local service contractor,” he said. International service contractors are also encouraged to invest in Malaysia through manufacturing plants and engineering and service centers. “Today, we have 90 active PSCs in Malaysia, and we have some 30 IOCs participating and operating in Malaysia. If you can bring technology and capability, you can be competitive and you can perform; we welcome you to be successful with us.”