PETRONAS: NOCs expand globally with increasing autonomy, financial strength

By Joanne Liou, associate editor

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.”

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Exclusive video: Keystone module enables remote control of downhole tools

Posted on 15 May 2013

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Paul Day, business development director for Weatherford, speaks with Drilling Contractor associate editor Katherine Scott about the company’s Keystone module on the exhibit floor of the 2013 OTC on 8 May in Houston. The Keystone module is an RFID-based, remotely operated electronic completion system to control downhole tools that can set packers or open packer setting ports, operate sliding sleeves to allow tubing to annulus circulation, close and open barrier valves, and operate fill subs. The system is made up of four elements— an RFID-hydraulic-power unit, a circulation valve, a production packer and a fall-through-flapper barrier valve.

Keystone is a trademark of Weatherford.

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Exclusive video: New composite wireline cable contains seven-conductor electrical core

Posted on 15 May 2013

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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.

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Statoil sanctions Julia development in GOM with ExxonMobil, pushes ahead with Logan

By Katherine Scott, associate editor

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.”

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BP commits to renewed focus on upstream oil and gas over next decade

By Katherine Scott, associate editor

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.

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DNV: As dual gradient grows, system qualification will be needed to ensure safe operations

By Katherine Scott, associate editor

Qualification of DGD systems is dependent on the specific configuration of the DGD system, the drilling installation and the well conditions, DNV’s Francisco Chávez V. said at the IADC Dual Gradient Drilling Workshop on 9 May in Houston.

As industry gains experience in the deployment of dual-gradient drilling (DGD) systems on floating rigs, qualification of these systems will become necessary to provide documented evidence that the system will operate safely, Francisco Chávez V., principal project manager of the drilling & well section for Det Norske Veritas (DNV), said at the 2013 IADC DGD Workshop in Houston on 9 May. Such qualification would be dependent on three factors: the configuration of the DGD system, the drilling installation and well conditions, he said. “These three set the qualification boundaries, and changing any one of these will require a reassessment of qualification.”

Because new technologies begin with no defined standards that become developed as the technology is utilized, Mr Chávez said, a risk-based, systematic approach to system qualification would ensure that the technology functions reliably within specified limits. This approach should be applied to DGD technologies, he said, which remains new in terms of field deployment, particularly in deepwater environments. It’s also necessary to qualify DGD systems to extend the operational limits when existing DGD technology is used in more demanding operations, he said.

Mr Chávez cited the following as the current, relevant design standards for DGD on floating drilling rigs with DNV Class:

DNV OS E 101 “Drilling Plant”DNV OS A 101 “Safety Principles and Arrangements”DNV OS D 202 “Automation, Safety, and Telecommunication Systems”

Efforts are also ongoing to produce more specific guidelines for designing DGD systems:

The IADC Underbalanced Operations & Managed Pressure Drilling Committee has drafted an API Recommended Practice for managed pressure drilling, “Constant Bottom Hole Pressure using Applied Surface Back Pressure (Category 2 MPD) with Single Phase Fluid”Revised version of NORSOK D-010DNV revision of DNV-OS-E101

“The design of all equipment has to consider the regulations and the standards, which will eventually be used for qualifying such a system for the operation that is intended. Within that, it implies as well the need to assess the reliability of the different components within that part of the classification so the standards and the qualification methods contribute to building trust on the safe operations, the design and the performance, the reliability of a DGD system,” Mr Chávez said.

Paul Guirlet, Pacific Drilling, said at the workshop that the company had to make several modifications to integrate DGD on the Pacific Santa Ana but is incorporating lessons learned on the four rigs still under construction, which will be delivered “as DGD ready as we can.”

In another presentation at the workshop, Paul Guirlet, vice president of technical support for Pacific Drilling, highlighted the challenges and modifications associated with the integration of DGD on rigs, particuarly what the company has accomplished over the past three years working with Chevron on the Pacific Santa Ana.

He acknowledged that integrating DGD on that drillship has been a team-based effort among many companies, including Chevron, GE, AGR and National Oilwell Varco, adding that the biggest challenge from his perspective was finding space on the rig for the system. “Even if we have a very large vessel, the challenge is finding room.” Further, installation of DGD equipment required locations where it would be easy to access, easy to maintain and easy to use. “This is quite a big piece of equipment; consider it like a lower stack of a BOP that needs to be installed a part of the riser string… We’ve done a lot of work trying to optimize and make the best use of the space available on the vessel.” The DGD equipment includes a drilling riser cross-section, subsea rotating device, solids processing unit, MaxLift pump and drill string valve.

Other equipment on the rig, such as the piping system and the Christmas tree, also needed to be retrofitted due to the fluids used in DGD. “All of our vessel are coming with two storages for the BOP, but of course the MaxLift pump was not exactly similar to a BOP, so we needed to upgrade that. We needed to have a second guiding system to make sure the vessel motion would not create any problems.” Pacific Drilling also had to add two Mux reels, he said.

Mr Guirlet noted that Pacific Drilling is taking all the lessons learned from the Pacific Santa Ana, which was delivered in late 2011, to its new ultra-deepwater drillship, the Pacific Sharav. “We really believe in the DGD plan, so all of the four rigs that we’ve got currently under construction at Samsung will be as DGD ready as we can, because there is a lot of development still ongoing at this stage. And we will know more certainly after we drill the first well in not too long.” Samsung is expected to deliver the Pacific Sharav at the end of 2013.

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Different dual-gradient methods enable drilling in deepwater, depleted reservoirs

Increasing pore pressures and fracture gradients in target reservoirs in the Gulf of Mexico have motivated Chevron to use a seabed pumping dual-gradient drilling method, Ken Smith, Chevron, said at the 2013 IADC DGD Workshop on 9 May in Houston.

By Joanne Liou, associated editor

Dual-gradient technology continues to gain attention as an important solution to deepwater drilling and extraction of resources from depleted reservoirs. Chevron is months away from deploying its dual-gradient system in the deepwater Gulf of Mexico, where the environment is largely characterized by increasing pore pressures and increasing fracture gradients, Ken Smith, manager of the dual gradient drilling (DGD) project implementation at Chevron, explained. “We’re really driven by the environment we’re drilling, the rocks that we have to drill. We’re motivated to change the physics behind our drilling,” he said at the 2013 IADC DGD Workshop on 9 May in Houston.

Nonproductive time is a major challenge, averaging up to 30% in the deepwater GOM, Mr Smith noted, adding that one-third of Chevron’s well costs go toward fighting NPT. “It’s getting worse as we routinely drill 30,000-ft wells, and we have leases in up to 20,000 ft of water.” This type of drilling environment is changing the playing field, and DGD will help overcome the challenges, he said. From a well design standpoint, DGD takes water depth out of the equation.

Chevron’s DGD system uses seabed pumping with positive displacement to open up tight pressure margins. “It improves the detection and reaction of the downhole challenges,” Mr Smith explained. “It restores the riser margin and remains overbalanced at all times.” With a restored riser margin, fewer casing strings are needed to reach TD.

In DGD, the fluid in the riser is replaced with seawater-dense fluid, setting up a pressure profile that is aligned with nature’s pressures. “We’re not fighting (natural pressures) as much as we do in conventional drilling,” Mr Smith said. “We enhance operational performance with the MPD capabilities of our system being closed and pressurizeable, which leads to improved well integrity and ultimately well productivity.”

Dag Ove Molde, Statoil, discussed the different types of dual-gradient systems that have been classified under the categories of pre-BOP and post-BOP.

While Chevron’s DGD is an example of seabed pumping, other methods of DGD also were discussed at the workshop, including Dag Ove Molde, specialist drilling technology for Statoil. The IADC DGD Subcommittee recently classified dual gradient systems into two main categories, pre-BOP and post-BOP. Mud-line pumping is one method under pre-BOP, while seabed pumping, dilution and controlled mud level fall under post-BOP.

Mud-line pumping is a riserless concept that has been deployed in the Gulf of Mexico and in the Norwegian sector, Mr Molde said. The system may consist of an interface on the seafloor, a subsea pump, a control system and a return conduit. Subsea pumps return the drilling fluid to the rig through a small-bore riser, which allows the mud to be used in the top sections of the well.

When mud inside the riser is diluted, injecting a lower-density fluid into the drilling annulus reduces the hydrostatic head of the circulating fluid. The mixing process results in the required density to achieve a constant bottomhole pressure, Mr Molde explained. Dilution is applicable from intermediate to deepwater operations.

Controlled mud level systems also use two fluids to control the wellbore pressure gradient. “The main usage is to control equivalent circulation density limitations,” Mr Molde said. The system can be placed at different levels in the riser to achieve variable control over the wellbore pressure based on fluid density and placement. Controlled mud level systems are applicable to intermediate water depth.

Dag Ove Molde, Statoil, discussed the different types of dual-gradient systems that have been classified under the categories of pre-BOP and post-BOP.

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