Longer, Deeper, Colder

Deepwater and ultra-deepwater E&P activities mainly carried out until recently in the established "Golden Triangle" of West Africa, Brazil, and the Gulf of Mexico (GoM) are being rapidly expanded by operators and contractors to include emerging remote frontiers offshore East Africa, the eastern Mediterranean, Northwest Australia, and Southeast Asia. There also is a large crossover in terms of the same deepwater technologies and solutions being potentially applicable to harsh environment areas such as the Arctic and sub-Arctic. At present, the Golden Triangle still dominates deepwater output and expenditure but the picture will soon start to change. In terms of production, the situation is this:

• Deepwater oil production is dominated by Brazil, the US, Angola, and Nigeria;
• Deepwater gas production is dominated by the US, Nor-way, Egypt, and India;
• Deepwater production growth is rapid, forecasted to grow at 6% per year over the next decade; and
• Significantly, ultra-deepwater output – in more than 1,500 m (4,921 ft) water depth – is expected to grow at 12% per year.

According to Infield Systems, deepwater (more than 500 m/ 1,640 ft) is the key growth market within the offshore oil and gas sector and the most capital-intensive area for development.

The emerging trends within the deepwater and ultra-deepwater sector reflect the dynamic state of the industry and the strong level of operator optimism going forward, according to Infield. With advances in upstream technologies combined with a growing geological understanding of deepwater plays, international oil companies, independents, and national oil companies (NOCs) are all looking ahead to an increasing number of prospects within the deepwater market in established areas as well as in areas previously deemed to be of marginal value.

Infield's "Global Perspectives Deep and Ultra-Deepwater Market Report" covering the period to 2016 also points out, however, that in addition to the environmental and geological challenges of deepwater production, with rising resource nationalism and increasing NOC involvement, geopolitics also will continue to shape the future of activities going forward.

Deepwater capex leaders

In terms of major deepwater players, Petrobras is the continually dominant figure – according to Infield, the state-owned giant's projected share of capex to 2016 is forecast to make up more than a quarter (26%) of the total global deepwater spend and will be directed predominately toward its presalt assets in the Santos basin.

By 2020, deepwater production from the current major contributors will have risen still further but with growing contributions from emerging areas such as Australia, Israel, Malaysia, and Indonesia. (Source: Rystad Energy; McKinsey analysis)

Adding to this will be high investment levels by the supermajors, the firm said. Chevron, Total, Shell, BP, and ExxonMobil will, combined with Petrobras, make up more than two-thirds (65%) of the total global deepwater capex figure to 2016.

The growing influence of independent operators such as Anadarko Petroleum, Noble Energy, Hess, and Tullow Oil also is apparent, with these companies expected to substantially increase their proportion of capex within the deepwater market over the next five years. For Anadarko, the rise in investment is particularly significant, with key projects including the GoM's Lucius project and exciting new developments offshore East and West Africa.

In terms of reserves coming onstream over the period 2012-2016, from a regional perspective it is again Latin America (almost entirely Brazil) that will dominate, with the area forecast to supply 39% of total global reserves additions. More than 60% of these are projected to come from Brazil's presalt basins.

However, the largest deepwater field development expected onstream during the same five-year period is located offshore Australia at a depth of 1,300 m (4,265 ft), with the ExxonMobil-Chevron joint development at Jansz (Greater Gorgon) expected to start flowing in 2014 with reserves totaling some 2.8 Bbbl.

Offshore Africa, Infield anticipates strong investment will continue, with the region holding an equal global deepwater capex share to that of Latin America at 30% across the 2012-2016 timeframe. Comparatively, North America's capex share of the market is expected to stand at 21%, followed by Europe and Asia.

The largest technology segment for investment will be pipeline installations – Infield expects this to comprise 39% of total global deepwater expenditure. Latin America and Africa are expected to account for the greatest proportion of deepwater pipeline spend, although the single most capital-intensive pipeline project is expected to be Gazprom's South Stream development, which was approved recently by the Russian government and which will be situated in up to 2,200 m (7,218 ft) water depth.

Subsea spend stays strong

Deepwater subsea expenditure is expected to remain high, with projects offshore West Africa forecast to comprise the largest share of subsea demand over the same five-year period.

According to Infield, oil and gas operators venturing into deeper, harsher, and more remote locations increasingly need "top tier" equipment – often at a significantly higher cost than more standard equipment – to access these reserves.

Ultra-deep installations will account for almost 25% of the annual subsea tree market by 2016, and Infield said the potential for subsea capex throughout the forecast period "has increased dramatically."

Petrobras is again a leading light, with an expected capex of US $18.9 billion between 2012-2016 and key developments such as the pilot projects on the Iara and Guara fields and a series of extended well tests on Iara, Libra, Franco, and Iguacu fields. In Brazil, an estimated 38% of the projected subsea capex will be needed to develop the region's presalt projects.

Prospects for manufacturers also are looking positive globally, with the market outlook showing a well-supplied market with a total capacity of 690 trees. Toward the end of the forecast period, Infield expects higher utilization rates and the start of a saturated market, driven mostly by the increasing demand for subsea trees in main phases in Brazil and West Africa.

Global subsea tree manufacturers' utilization rates are expected to increase to an average of 75% in the next three years, up from 49% in the 2009-2011 period.

Advanced seabed technologies

Advances in technology are increasingly being tested and deployed in response to the industry's insatiable demand for solutions to deepwater and harsh environment challenges as well as sustaining production rates in mature developments, boosting flow rates in low pressure reservoirs, accommodating a larger number of fields tied back to host facilities, and ensuring the energy and cost-efficiency of a project.

Infield highlighted that potential projects that could benefit from the use of advanced seabed technologies include mature fields in the North Sea and the US GoM, where a large number of smaller developments are expected to be tied back to existing platforms to be commercially viable.

It also expects West Africa will be one of the key regions for implementing subsea processing because of the region's already extensive deepwater production; significant oil reserves; and geographical distribution of its fields, which require multiple wells being tied back to single central processing facilities.

In Africa, oil companies such as Total, BP, ExxonMobil, Chevron, and Eni will try to take advantage of the area's ample resources to leverage against the declining reserves from other mature areas. Total is leading the subsea charge there with a projected $8 billion of expenditure within the forecast period, according to Infield.

Australia also was flagged as a major player in the global gas market, largely due to the development of its offshore natural gas projects. Post-2013, a significant backlog of major projects is predicted to provide a boost to the market, with more than 50% of the forecasted subsea market expected to relate to tiebacks to a fixed, floating, or terminal facility.

Lastly, in the GoM the changing regulatory environment governing operators' activities will lead to future subsea equipment and infrastructure needing to comply with stricter regulations. This will result in higher safety specifications and consequently lead to greater capital expenditure per development, Infield said.

Chevron at the sharp end

Chevron has been a key player offshore, having invested in deep water for an extended period of time as a major part of its future production profile.

Project expenditure over the next six years will see deepwater projects account for nearly 30% of its total spend, only just behind the company's largest project investment area (LNG), which comprises more than 35% of its total spend. This year deepwater project startups for Chevron include the Usan and Agbami II developments offshore Nigeria and Tahiti II in the deepwater GoM. These will be followed in 2013 by Papa Terra offshore Brazil and the following year by the Jack/St. Malo, Big Foot, and Tubular Bells projects in the GoM and Gorgon offshore Australia.

Gary Luquette, president, Chevron North America E&P Co., said, "We've had a strong presence in deep water for many years and are focused on maintaining this going forward. Our exploration success has translated into world-class producing fields such as Tahiti in the Gulf of Mexico, Agbami in Nigeria, and BBLT in Angola. These projects, along with many others, are delivering about 375,000 b/d. Our success has led to a strong queue of major capital projects, resulting in a full pipeline that is expected to grow our deepwater production to 470,000 b/d by 2017."

Chevron has three deepwater projects in various stages of early startup. In Nigeria it has Usan, with a peak capacity of 180,000 b/d of oil, which began production in February. Ten wells already have been drilled, and peak production is expected in 2013. Also in Nigeria, the company expects to start production from Phase 2 of Agbami. This was originally planned for 2011, but strong production performance from existing wells kept the field's FPSO at capacity throughout the year. Chevron said it presently is drilling Phase 2 wells to maintain that production plateau. In the GoM, the company's Tahiti II project is progressing despite some delays due to the recent moratorium. The topsides water injection equipment has been installed, Luquette confirmed, and the operator began injection in February. "We're currently drilling and completing additional producers, which are expected to reduce field declines and improve ultimate recovery," he said.

Jack/St. Malo: a template for others

Looking further out to 2014, Chevron is continuing with construction for its Jack/St. Malo development in the Lower Tertiary trend in the GoM. Fabrication of the floating production facility's hull and topsides is under way, and in late 2011 the operator began drilling the initial development wells at both Jack and St. Malo. In addition, the nearby third-party operated Julia field will be tied back to the production hub, increasing its capital efficiency and investment returns.

Helix Energy Solutions Group’s Well Enhancer intervention vessel has just completed a three-month campaign carrying out West Africa’s first well intervention work and subsea well operations conducted from a mono-hull intervention vessel. This was the deepest operation conducted by the Well Enhancer since it joined the Helix fleet in 2009. (Photo courtesy of Helix Energy Solutions Group)

"A noteworthy aspect of Jack/St. Malo is that it's designed to provide a template for future developments," said Luquette. "We're already evaluating its potential use for our Buckskin and Moccasin co-development. Big Foot also is making significant progress. The hull and the topsides fabrication has begun, and we are currently drilling the initial set of production wells."

Another GoM project, Tubular Bells, has a total development cost estimated at about $2.3 billion, with production expected to peak at 40,000 b/d. Like Big Foot, Tubular Bells will develop a Miocene reservoir. These are characterized by relatively high flow rates and high recoveries, Luquette said.

He also stressed the impact of advancing technology for incremental recovery on Chevron's deepwater developments. "When we drilled the initial discovery wells at Jack and St. Malo, it was clear the Lower Tertiary trend held a significant resource base. We also recognize the importance of incremental recovery through technology.

"Our industry's experience is that big fields tend to get bigger, and with continued development and application of technology, the reserve base in the Lower Tertiary trend will continue to grow. We sanctioned Jack/St. Malo on the basis of existing technology and recovery of less than 10%. With incremental technologies, we see the potential to increase ultimate recovery to more than 20%. By doubling recovery, we have effectively added 500 million barrels to Jack/St. Malo, and we're looking forward to applying what we learn here to other Lower Tertiary developments."

He also gave extra insight into the GoM's current activity status. According to Luquette, Chevron is now ahead of its pre-Macondo, pre-moratorium pace in the deepwater GoM. "We were at three drill-ships at the time the moratorium was put in place, and we now have five deepwater drillships – four on location and a fifth one, the Pacific Santa Ana, that will arrive soon. That level of capability is something that we're going to sustain for the foreseeable future. It's the right level for us," he said.

Of the five drillships that the company is going to have working over the next couple of years, four will be engaged in development drilling as a result of its success with its exploration program and getting Jack/St. Malo and Big Foot online with a full complement of wells.

Collaborative technology development

Chevron has been one of the main supporters of the upstream industry's increasingly collaborative efforts to research and develop new and improved deepwater technologies through globally respected and well-established programs such as DeepStar.

The industry is generally focusing its attention on achieving improvements in areas such as:

• Subsalt imaging;
• 3-D wide-azimuth surveys;
• Drilling in 3,000 m (10,000 ft) water depth;
• Next-generation drillships;
• Single-trip multizone frac pack completions;
• In-well artificial lift;
• Rigless well intervention;
• Long-distance tiebacks (oil: 80+ km, gas: 322+ km);
• Seabed boosting and processing;
• Host facilities with small-field (50-200 MMbbl) tieback;
• Hull/mooring design standardization;
• Compact modular processing systems;and
• Intelligent wells and i-field solutions.

DeepStar still delivering

Shell’s Perdido spar facility has been producing from the Lower Tertiary since 2010 in 2,450 m (8,000 ft) water depth. (Photo courtesy of Shell)

Having started back in 1992, DeepStar is administered by Chevron Energy Technology Co. The latest phase (Phase XI) kicked off in January, and its focus reflects many of the above interest areas. Some of the key deepwater challenges being tackled in the latest phase are:

Ultra-deepwater development:

• Seafloor boosting;
• Subsea systems;
• Risers in 3,000 m water depth; and
• Unconventional flowlines.

Enhanced well productivity and recovery:

• Subsea boosting and artificial lift; and
• Remote well test pressure monitoring

Flow assurance:

• Asphaltene deposition simulation and validation;
• Hydrate kinetics and plugging;
• and Cold restart.

Enhanced deepwater production systems:

• Global performance;
• Alternative systems and methodologies; and
• Extreme current and wave measurement.

Well cost reduction:

• Dual density/riserless mud recovery; and
• Conceptual improvements.

It also is tackling other areas including improved economic thresholds for small fields; systems operability – availability and reliability; drilling, completion, and intervention paradigm shifts; and early production systems.

DeepStar's collaborative efforts are being driven by participation from oil companies and contractors, all of whom increasingly recognize the benefits of addressing common challenges. This latest phase has 10 oil company participants, and DeepStar has more than 35 service and vendor company contributor members.

The development of next-generation drillships like the Stena Drillmax, capable of drilling in ultra-deepwater and harsh environment areas such as the Norwegian and Barents Sea, has enabled operators to tackle exploration in remote frontier areas previously beyond their reach. The drillship currently is carrying out ultra-deepwater exploration drilling offshore Ghana for Hess Corp. (Photo courtesy of Stena Drilling)

Within DeepStar oil companies, vendors, regulators, academic institutes, and research organizations cooperate to develop technologies necessary to meet the identified challenges. In doing so, each participant reduces the cost and risk of developing technology with leveraged funds and the collective wisdom of more than 1,000 subject matter experts in areas absent of competitive advantage (to the oil companies).

Phase XI will conclude at year-end 2013, while most ongoing projects in Phase X will be completed by 2Q 2012.

The DeepStar program also regularly links with other similar joint industry projects around the world, further accenting the value of this kind of partnering for technology development. These include organizations such as Research Partnership to Secure Energy for America (RPSEA), Norway's Demo 2000, and the UK-based Industry Technology Facilitator (ITF).

RPSEA program rolls on

One of these, RPSEA, recently selected six research proposals as part of its own ongoing Ultra-Deepwater Program. These were chosen as part of its contract with the US Department of Energy's National Energy Technology Laboratory, with the US government contributing $9.6 million towards the projects.

Along with contributions from research partners, the investment will total more than $26 million over three years.

The selected projects, in summary, are:

• More improvements to deepwater subsea measurement. Project Leader: Letton-Hall Group. Other participants include Oceaneering International/Deepwa- ter Technical Solutions, Joe Brown Company, BP, Chevron, ConocoPhillips, Shell, Statoil, and Total;
• Coil tubing drilling and intervention system using cost-effective vessels. Project Leader: Nautilus International. Other participants: INTECSEA/WorleyParsons Group, General Marine Contractors, NOV CTES, Tidewater, GE VetcoGray, Anadarko Petroleum, Chevron, Shell, ConocoPhillips, Hess, Halliburton, Baker Hughes, and Rolls-Royce;
• Effect of climate variability and change in hurricane activity in the North Atlantic. Project Leader: University Corporation for Atmospheric Research. Other participants: Willis and Chevron;
• Deepwater reverse-circulation primary cementing. Project Leader: CSI Technologies. Other participants: Weatherford International and the University of Houston;
• Autonomous underwater inspection using a 3-D laser. Project Leader: Lockheed Martin. Other participant: 3-D at Depth; and
• All-electric subsea autonomous high-integrity pressure protection system architecture. Project Leader: Granherne.

The ITF, meanwhile, has identified deepwater-related priorities mainly in the subsea sector that it says its operator and service company members want to see tackled in 2012. This will include subsea power, ultra long-distance tiebacks, produced water and separation, and cleaning and replacement of valve actuators.

ITF is offering up to 100% funding for the right solutions for some of the most pressing challenges and is aiming to secure around $75 million of investment directly from its members over the next three years for this and other technology priorities.

Such collaborative industry programs and initiatives, because of the beneficial effect they have in terms of reducing the costs and increasing the speed of development of new technology solutions for deepwater projects, will play a vital role in the race to find and produce new reserves to meet growing global energy demand.