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.”

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.”

“This will give Statoil and the license group a fit-for-purpose rig, which is important in order to develop the Mariner project in a safe and efficient manner,” Jon Arnt Jacobsen, chief procurement officer for Statoil, said. JX Nippon Exploration and Production and Cairn Energy are license partners with Statoil on the heavy-oil project. The field development plan was approved in February by the UK Department of Energy and Climate Change.

“Mariner is the largest new offshore development in the UK in more than a decade. It will generate jobs and substantial ripple effects for UK and the wider Aberdeen region,” Morten Ruud, Statoil vice president for Western Europe in development and production international, said. The project entails investments of more than GBP 4.7 billion (approximately US$7.14 billion).

First production from Mariner, which is expected to produce for at least 30 years, is planned for 2017. Average production has been estimated at approximately 55,000 bbl/day of oil over the plateau period from 2017 to 2020.

The Mariner field is located on the East Shetland Platform of the UK North Sea, approximately 150 km east of the Shetland Isles.

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.”

Lionel Lee, chairman and director of Triyards Holdings Ltd.

With the launch of TDU-400 jackup, a new Premium Class 400 HPHT rig, Triyards Holdings Ltd. has become one of three Singapore yards able to design and build its own proprietary jackups and self-elevating units. “The design is in the final submittal stage to ABS, and from a construction standpoint, we are getting ready to order components,” Richard Altman, senior vice president for global business development, said at a press conference Monday at the 2012 OTC. Triyards is in discussion with clients for a rig and hopes to have an order in the next three months, Lionel Lee, chairman and director, stated.

Richard Altman, senior vice president for global business development

The TDU-400 is designed to capitalize on the most advanced drilling systems and equipment available today. The design can be customized to meet the disparate needs of clients without having to be continuously redesigned, thus avoiding costs associated with variation in orders. “We wanted to design something that is shipyard friendly,” Mr Altman said. “We wanted to offer a premium performance package as light weight as we could develop with a jackup.”

The jackup can withstand 100-knot winds and meets wave criteria for global utilization. Providing accomodation for up to 220 personnel, the jackup boasts leg lengths of more than 535 ft (163 meters) and can operate in water depths of up to 400 ft (120 meters). The rig is rated to 32,500 ft drilling depth with 1.5 million tons of hookload. “We’ve incorporated a 1,000-ton topdrive, which gives you more torque,” Mr Altman said, “and today’s horizontal application or extended-reach applications need that additional torque.”

A well abandonment, along with continued incidents of kicks and losses and nonproductive time (NPT), provided the impetus for Petrobras to embark on its first managed pressure drilling (MPD) operation from a floating rig for an exploratory well in the Santos Basin, setting the stage for future MPD endeavors in the region over the next four years. “Large formation losses, high pore pressure, a narrow operating window and a high risk of ballooning made this well particularly challenging for us. After we were unable to reach total depth (TD), we realized we needed to implement MPD to prevent further losses,” said Emmanuel Nogueira, petroleum engineer for Petrobras. In a presentation at the 2013 IADC/SPE Managed Pressure Drilling & Underbalanced Operations Conference & Exhibition in San Antonio on 17-18 April, Mr Nogueira and his Petrobras colleague Guilherme S. Vanni described the extensive planning, training, rig modifications and collaboration with multiple service providers that Petrobras undertook to launch the project.

The presentation also highlighted ongoing challenges in training and rig equipment, as Petrobras anticipates drilling at least 25 exploratory wells requiring MPD, and some development wells, in shallow, deepwater and ultra-deepwater fields in the Santos Basin between now and 2017.

In adopting the MPD strategy, Petrobras aims to reduce fluid gains and losses, mitigate problems associated with ballooning, increase rates of penetration, extend TD, reduce probability of drill string sticking, minimize formation damage and well stability problems and open up possibilities for automatically switching to pressurized mud cap drilling, Mr Nogueira said.

The project required a number of modifications to the fifth-generation semisubmersible, including retrofitting the riser and blowout preventer to accommodate rotating control devices (RCD). In designing the well, engineers selected a large-bore wellhead system and an 18-in. liner to run 13 5/8-in. casing without underreaming to drill the 12 ¼-in. and 8 1/2-in. sections of the well, using hydrostatically underbalanced (UB) fluid.

Petrobras initially devised an extensive pre-job planning scenario, including the development of 44 specific procedures for the MPD operations. “We got all the service companies together and formed a task force that held weekly meetings and monitored all the actions needed to complete a successful job in all well sections,” Mr Vanni said. These included development of casing and liner contingencies.

Training was another key issue and remains a significant concern going forward, he continued. “Today, we have a lot of new offshore rigs in Brazil and very inexperienced drilling crews. Some crews have just four or five years of experience. For this operation, we provided internal training and also engaged the service companies to provide hands-on training for the well design team and advanced training in MPD RCD technology for all the rig teams.” Alongside those efforts was development of standards and procedures for MPD and mud cap drilling (MCD) and a process of defining well control procedures. Discussions about well control using MPD for even the most minor influx remains an important priority.

Looking ahead, Petrobras anticipates having as many as six MPD rigs ready by mid-2014. But the company has ongoing concerns about the widespread implementation of MPD on offshore vessels as it relates to crew competency, the ability of service providers to conduct multiple simultaneous deepwater operations and a lack of MPD equipment on existing rigs. “For example, we have severe restrictions with upper riser equipment,” Mr Vanni noted. “Ninety-five percent of riser systems have restrictions for running assemblies for RCDs. This signals a need to modify existing rig equipment and find ways to implement or retrofit MPD equipment into existing rigs for efficiency.”

Acknowledging increasing adoption of MPD in the offshore sector, Mr Vanni emphasized the cost benefit of MPD over conventional drilling methods. “Between 2010 and 2012, Petrobras drilled 67 conventional wells, 29 of which had kicks or losses,” he said. “That translated to nearly 4,600 lost hours and 191 lost days, which is ultimately much more expensive than MPD.”

Part of the reforms that the Interior Department undertook after Macondo was a requirement for deepwater operators to demonstrate immediate access to surface and subsea containment resources that would be adequate to promptly respond to a blowout or other loss of well control. Several such components are being tested in the exercise initiated today.

“We fully expect operators to have the plans, equipment and capabilities in place to respond to a subsea blowout in deepwater at a moment’s notice,” BSEE Director Jim Watson said. “These types of exercises give us an opportunity to see how the equipment is deployed in real-world conditions and to learn lessons that can be shared across the industry to protect the environment and improve the safety of offshore operations.”

During this exercise, Helix’s capping stack will be mobilized and deployed to the sea floor in 5,047 ft of water, latched to a test wellhead and pressurized. The exercise is also designed to test Noble Energy’s ability to obtain and schedule the deployment of the supporting systems necessary for successful containment. The Helix capping stack is similar to the technology used to stop the flow of oil from the Macondo well.

BSEE inspectors, engineers and spill response experts will be embedded in various locations throughout the exercise, including in the command center and on the vessel deploying the capping stack, to oversee the mobilization, deployment and associated tests of the system. BSEE experts will oversee the capping stack being lowered to the seafloor by wire, a technique that offers the potential to be significantly faster than the deployment via pipe that occurred during the Macondo response.

Helix is one of two consortia that provide contract access to well containment equipment to oil and gas operators in the Gulf of Mexico. This equipment is required by BSEE for drilling with subsea blowout preventers in deepwater, among other situations. The other consortium, the Marine Well Containment Company, successfully completed a similar deployment exercise in July 2012.

Baker Hughes recently opened its new Upstream Chemical Deepwater lab, where FATHOM subsea-certified chemicals are assessed for product reliability, quality and performance. The lab uses equipment, such as visual hydrate rocking cells, as part of a 16-step FATHOM deepwater subsea-certification process.
Image courtesy of Baker Hughes.

By Katherine Scott, associate editor

Baker Hughes is further investing in the deepwater frontier with the opening of its new Upstream Chemicals Deepwater Laboratory in Houston on 25 April. Located within the company’s Center for Technology Innovation (CTI), the $4.5 million lab is dedicated to deepwater research, studies and testing.

“A lot of focus in this market talks about ‘no more easy oil.’ It’s been that way for quite some time,” Mark Lewis, vice president of upstream chemicals, said at the launch event. “In my view, deepwater is the definition of ‘no more easy oil.’ This means a need for exceptional technology developments in seismic, drilling, completions, production and production treatment as E&P companies push further out and push the envelopes of performance, particularly around HPHT.”

The lab features equipment to assess product reliability and quality, as well as performance of the company’s FATHOM subsea-certified chemicals, designed as deepwater flow assurance treatments. Through a 16-step deepwater subsea-certification process, the lab can confirm that each chemical product is qualified for subsea application through tests such as hydrate stability, high temperature thermal stability and chemical fluid compatibility. The FATHOM test is built on standards recommended by the Blockage Avoidance in Subsea Injection and Control Systems (BASICS) joint industry project and published in API specification 17A TR6.

Equipment in the lab includes a high-pressure rheometer, cloud point/pour point analyzer, proprietary high-pressure umbilical approval test loops, a high-pressure viscometer, temperature cycling ovens, a high-pressure density meter, particle size analyzer, visual hydrate rocking cells, a paraffin cold finger, high-pressure asphaltene flocculation tester, dynamic tube blocking equipment for scale and a core flood apparatus.

With water depths reaching 10,000 ft, pressures up to 30,000 psi, and temperatures of 400°F in some deepwater environments like the Gulf of Mexico’s Lower Tertiary, Ann Davis, director of deepwater solutions at Baker Hughes, said more needs to be done to operate in HPHT. “The industry currently doesn’t have all the necessary tools they need to manage these conditions. My team is hoping to take some lessons learned at CTI and expand our capabilities in the lab to be able to evaluate our products under those conditions. We’re also hoping to expand our FATHOM capabilities to be able to test our products at those conditions.”

Just a couple of days before the opening of the Houston lab, Baker Hughes also launched its new Center for Offshore Cementing, Fluids and Chemicals in Broussard, La. It is designed to support the continued growth of the deepwater market as well. The company envisions using the centers to collaborate on technological development. “We’re starting to push our capability in deepwater out to where the deepwater hubs are, ” Mr Lewis said. “The upstream personnel in Louisiana will work in tandem with the technologies that we develop both out of the Houston facility and in our Sugar Land facility.”

FATHOM is a trademark of Baker Hughes.

This Douglas-Westwood chart shows deepwater activity in Asia Pacific growing faster compared with the rest of the world. The graph is indexed to show growth in the number of wells drilled since 2005. Asia Pacific’s 2013 index is 2.1, which means it’s projected there will be 2.1 times more wells drilled in 2013 in the region compared with 2005.

By Astrid Wynne, contributing editor

A study of offshore E&P in Asia Pacific, unveiled at the Asia Offshore Technology Conference in Singapore on 16 April, predicts a marked increase in the proportion of deepwater drilling in the region over the next five years. “This is one of the fastest-growing areas worldwide,” said John Westwood, group chairman of Douglas-Westwood, which carried out the study, “Asia has traditionally been seen as ‘where old rigs come to die,’ but this will change. In most Asia Pacific regions, shallow-water production is maturing rapidly, driving a requirement for deeper water exploration. Regional deepwater production currently accounts for 7% of supply and is expected to reach 17% by 2020. However shallow-water fields with high CO₂ and H₂S content are another significant challenge.”

The report was based on interviews with 44 major players in the Asia Pacific region, 53% of whom came from E&P and drilling-related companies. It was commissioned by DNV Deepwater Technology Centre, Innovation Norway, the commercial section of the Royal Norwegian Embassy and the Norwegian Business Association in Singapore, in part motivated by last year’s launch of DNV’s Deepwater Technology Centre in Singapore.

“Once the industry’s needs are fully understood, we can align our R&D initiatives and service deliveries with such challenges” said Alex Imperial, managing director of DNV Deepwater Technology Centre.

The report suggests that a total of 6,995 wells will be drilled in Asia Pacific over the next five years at a cost of $73.8 billion, compared with 6,212 wells costing $59.3 billion over the past five years. Over the 2013-17 period, Asia Pacific deepwater (500-1,000 meters) expenditure is expected to increase by 46% from $4.2 billion to $6.1 billion, which will represent 33% of total MODU drilling costs in the region. In the same period, it’s expected there will be 854 deepwater subsea oil and gas wells globally, of which 574 will be in Asia Pacific, according to the study.

Asia Pacific is also expected to outpace the rest of the world in terms of absolute growth in terms of deepwater activity, with a 20% increase. Australia, Indonesia, China, India and Malaysia will account for 87% of projected deepwater activity in the region, with Australia at 22%, Indonesia and China each at 17%, India at 16% and Malaysia at 15%. Survey feedback singled out the South China Sea as having the greatest deepwater potential, but political uncertainty in the area is likely to affect how this plays out.

Shallow-water drilling is expected to rise too, albeit under more difficult conditions. Major technical challenges facing Asia Pacific drillers are fields with high CO2 and H2S content and HPHT reservoirs. More and higher-specification drilling equipment will be required in the region moving forward.

“Certain aspects of the required technology are already in production, like the seven-ram BOPs required in the GOM,” said Mike Brogan, vice president, technical director of DNV’s Asia Pacific and Middle East division. “The 20K drilling rig is the big question mark. As you increase the drilling pressure, the vessel becomes larger to house the topside equipment, like hoisting equipment and associated increase in deck load requirements, as well as new flexible hoses. 20K will happen – back in the ’80s it was the move from 10K to 15K and they said that could never be done – but it will take joint industry cooperation.”

In February, BP and Maersk Drilling announced a partnership agreement to develop conceptual engineering designs for deepwater drilling rigs for reservoirs up to 20,000 psi and 350°F.