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.”

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.

Petrobras has cut its average drilling time by approximately 50% since 2006 to around 70 days per well in 2012, Carlos Tadeu da Costa Fraga, executive manager for Petrobras, said during a luncheon at the 2013 OTC.

By Joanne Liou, associate editor

Recounting Petrobras’ history in pre-salt activities so far, Carlos Tadeu da Costa Fraga, executive manager for Petrobras, shared the company’s strategy to accelerate the transformation of discoveries to producing fields. In 2012, its pre-salt production made up 7% of the company’s total output, Mr Fraga stated at the 2013 OTC in Houston on 7 May. “We expect to have 42% of production coming from pre-salt in 2017 and 50% of the total production coming from the pre-salt in 2020.”

Petrobras’ pre-salt exploration of the Santos Basin began in 2000 and 2001 with the acquisition of the Santos Basin pre-salt blocks, drilling the first wildcat well in 2005. In 2006, the company made its first major discovery with the Lula field, and by 2010, Petrobras had declared commercial production from that field. Drawing a comparison between the Campos and Santos basins, Mr Fraga noted the sizeable volume being discovered in the Santos Basin in a relatively short amount of time. “The Campos Basin took us 23 years since the first discovery to have the current assessment that we have regarding the volume of oil and gas in place,” he said. “In pre-salt, just after the first four years of exploration and after the first discovery, we’ve reached the same point in oil and gas assessment.”

Although it took Petrobras a much shorter timeline to explore and assess the Santos Basin than Campos, Mr Fraga noted that the strategy used was the same for both areas. “First is a very intensive appraisal step to understand the reservoir and to come up with the proper and responsible decision after we learn about the area.” In the Santos Basin alone, up to the end of 2012, Petrobras had drilled 60 wells, run 41 drill stem tests and cut approximately 4,900 ft (1.5 km) of coring. The company had run 72 conventional logs and 57 production logs during wells tests.

Production numbers indicate the company’s success, with its approximately 300,000 bbls/day of production expected to reach more than 1 million bbls/day by 2017 and more than 2 million bbls/day by 2020. “It’s possible, but it’s going to demand a lot of energy and work,” Mr Fraga said. “I’m very confident we are going to do it. We need to count on you all to have those projects in on time and on schedule and on cost,” he told the OTC audience.

Mr Fraga referred to innovation acceleration – technological development from geological models and flow models, well technology and subsea equipment, which is key to ramp up production. “As we have a very sizeable area, as we are going to have long-term performance, we want to be able to accommodate any new technology that may come in the future,” he said. Petrobras also is working to reduce its drilling costs, which represent approximately 50% of its capital expenses in pre-salt. The current average drilling time for a well is already 50% less than the average time of 143 days in 2006. “We are drilling wells around 70 days,” Mr Fraga said. “Last week we finished a well in less than 40 days.”

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-010
• DNV 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.

The SeaONYX BOP surface control system utilizes a control platform that the company says has been designed for obsolescence management. The system addresses the challenge of ensuring availability, especially for electronic components, for a product expected to operate for 20 years or longer.

A BOP surface control system and operator interface designed for deepwater drilling was among several technologies GE launched this week at the 2013 OTC. The Acoustic Leak Detection System and the Subsea Multi-domain Condition Monitoring System were two other technologies introduced at the Houston event.

The SeaONYX BOP surface control system from GE Oil & Gas incorporates the company’s Mark Vle hardware and Proficy software tools. It uses dual redundant electronic control systems to control the subsea equipment. The Mark VIe control components allows the SeaONYX to use a configuration that has been installed in more than 2,000 thermal, wind, hydro and nuclear facilities, according to GE.

“SeaONYX is a control system that helps to manage our BOPs in deepwater drilling operations. The development of the new system is an outstanding example of importing industry-leading technologies from other GE businesses into the oil and gass space,” said Chuck Chauviere, president of drilling for GE Oil & Gas. “In this case, our customers will be benefitting from a control system solution that has a strong track record of success and high-level performance in the global power generation industry.

A critical advance with the new control system’s Mark Vle control platform is its inherent design for obsolescence management. The system addresses the industrywide challenge of ensuring availability, especially for electronic components, for a product expected to operate for 20 years or longer. The SeaONYX system does this by using a standard footprint for the major components that will be used in future releases of Mark VIe hardware.

Another feature of the Mark Vle architecture is the ability to “hot swap” certain components while the system is running. When an individual component requires replacement, the rest of the system remains active while it is replaced. The new component will boot up, configure itself and typically come back online in a matter of minutes, increasing system availability.

The two condition monitoring and sensing solutions for the subsea sector, launched by GE’s Measurement and Control business, will allow operators to monitor the integrity of their subsea installation. The Acoustic Leak Detection System (ALD) uses passive, acoustic hydrophone technology to detect and locate subsea oil and gas leaks by discriminating the noise of a leak from other sources of sound. Developed from naval military technology, the system detects “silent” leaks that occur when there is low flow rate or low differential pressure.

The ALD can detect both crude oil and gas with a coverage up to 500 meters.

The Subsea Multi-Domain Condition Monitoring System combines electric emission monitoring and acoustic hydrophones designed for monitoring the operating condition of subsea machinery and processes — from pumps and valves to supporting infrastructure. Typically combined with ALD to detect subsea leakage, the system performs multi-domain analysis supported by proven pattern recognition and machine learning algorithms to identify and display subsea structure, machine and pipeline activities and anomalies.

“As subsea exploration and production becomes increasingly important globally, many customers are looking to expand these topside capabilities to the seabed,” said Jens Abrahamsen, Naxys business leader for GE Measurement & Control, a GE Oil & Gas division. GE acquired Naxys in 2012. “By combining subsea sensors and acoustic condition monitoring with existing GE technology, GE customers can expand their view into operations and make intelligent, critical decisions about their operations.”

Julio Quintana, president and CEO of Tesco

Tesco Corp has completed tests for two products – the HXI 150-ton top drive and Hydraulic Compact CASING DRIVE SYSTEM (HCCDS) – for extended reach.

The HXI 150t, the 12^th of TESCO’s top drive line, features the same benefits as the HXI 250t but is lighter and smaller and allows operators to move the top drive between mobile rigs. “The R&D groups did a great job of looking at this unit and shrinking it down substantially,” Julio Quintana, president and CEO of Tesco, said at a press conference at the 2013 OTC on 7 May. “You’re able to put it on essentially any rig in the world.”

Generating 24,000 ft/lbs of drilling torque, the HXI 150t is designed for the horizontal value stream, as well as the vertical stages of the well, including drilling sections, rotating casing to TD and cementing the casing. Its integrated safety interlock of the process logic controller system and driller’s control panel maximizes operating efficiency while minimizing risks.

“Consistent with our customer intimacy culture, we asked our customers what attributes of the top drive were critical to their operations and they told us: rig integration, smaller footprint and mobility,” Jeff Foster, vice president of top drives, said. “We designed the HXI 150t to meet all of those demands, and after a year of field testing, we are confident that it is the most versatile and dynamic top drive to meet those challenges.”

Complementing the HXI 150t is TESCO’s HCCDS, a compact, lightweight version of the company’s 500-ton CASING DRIVE SYSTEM.  Replacing conventional power tongs, traveling elevators and removing the need for a stabbing board, the HCCDS allows circulation, rotation and reciprocation of the casing to ensure it reaches casing point and in conjunction with TESCO’s Dynamic Cementation System improves the cement bond and wellbore integrity.

“By eliminating traditional equipment, the HCCDS is cost-efficient and maximizes safety by eliminating risks associated with conventional casing running equipment,” Nick Mawford, vice president of tubular services, said. “The HXI 150t top drive, coupled with TESCO’s HCCDS provides operators and end-users a compact rig solution for any drilling environment.”

Hydraulic Compact CASING DRIVE SYSTEM and CASING DRIVE SYSTEM are trademarks of Tesco Corp.