Majors drive search for solutions to deepwater challenge

Upstream megaprojects are always risky endeavors, whether they are onshore or in shallow water. The fact that the average success rate for these projects – in terms of sticking to a budget – is only around 22% is evidence of that.

But frontier deepwater and ultra-deepwater developments typically carry inherently more technical risks in addition to what are commonly already very complex nontechnical risks. Managing large projects successfully in deeper and usually more remote waters around the world with more challenges and larger risks means that oil companies must constantly reassess their methods as well as their openness to additional proactive measures and techniques. Companies also must exercise continuous rigor in terms of specifications and controls.

Most of all, it still appears that there comes a point when a pioneering operator needs boldness – without being reckless – when making the decision to innovate. That drive for creativity is constant since complex challenges remain to be faced in the greater, colder water depths that are encountered. It is not only water depth that is the problem; the issue of ever more difficult fluids (such as those that are HP/HT, high-viscosity, low-API, and waxy) is having an increasing impact.

FIGURE 1. The year 2012 set a record for oil and gas finds made in more than 1,220 m of water, with 52 discoveries announced. There have been more than 180 finds announced beyond 1,220 m between 2008 and 2012. (Image courtesy of Noble Drilling; data courtesy of IHS Petrodata)

Innovation is the key

As always, technological innovation is the key, and a recent industry event saw deepwater heavyweights Shell, Total, and Exxon outline their varying but not dissimilar approaches to developing their respective portfolios.

Like many other oil companies, these three majors have deepwater projects built into their forward business plans for at least the next two decades, with global strategies mapped out involving huge levels of investment.

The reason is that an increasing majority of exploration drilling activity is moving firmly into water depths beyond 1,220 m (4,000 ft). New discoveries also are increasingly being made in waters beyond that same depth milestone, with approximately 35% of new finds currently made beyond that depth, rising from an average figure of 25% in the middle of the last decade. In 2012 alone there were 52 discoveries (a record figure) made in water depths of more than 1,220 m in 14 different countries (Figure 1).

Forecasts for production reflect the same rising trend. In 2005 deepwater liquids production made up just 3% of the total global figure of more than 70 MMboe/d. By 2040 that percentage will have risen to 13% (14 MMboe/d) out of a forecast liquids total of around 110 MMboe/d, according to Exxon-Mobil’s “2013 Energy Outlook.”

Matthias Bichsel, Shell’s projects and technology director, highlighted at Quest Offshore’s recent MCE Deepwater Development (MCEDD) event in the Netherlands that in the “golden triangle” of Brazil, the Gulf of Mexico (GoM), and Nigeria alone the level of total reserves is more than 80 Bboe. “It is the power of innovation in deep water that is key. Shell spends more than [US] $1 billion a year on research and development in all areas, aimed at helping us to find oil and gas resources and better ways of developing those resources through wells and facilities,” he said.

He flagged the Mars project in the GoM, saying the company “would never have gotten started” without new technology developed for its Deimos field.

Project complexity

The challenges that lie ahead revolve around the increasing complexity of projects, Bichsel continued. Shell is innovating with respect to the use of ROVs to move ocean-bottom sensors from one location to another. The company is working on using AUVs to do this task to help reduce costs.

“We need to get better at managing costs as an industry,” he said. “There are things that can help, like rigless well intervention – we are doing this on our Bonga field [offshore Nigeria] and on our Parque de Conchas project [offshore Brazil].”

The company also is developing a BOP device for essentially “pinching the wellbore shut” if the BOP fails, he continued. There also is another solution that cuts and drops the tubular. “All this reflects how vital deep water is to the world’s energy needs,” he said.

His colleague, Martijn Dekker, Shell’s development manager for the Stones project in the US GoM, said that frontier deepwater projects typically carry inherently more technical risks on top of what are commonly already very complex nontechnical risks.

Examples of technical risks he highlighted include issues stemming from geological settings; the lack of production analogs; the need for new technology to address deeper, higher pressure, and hotter environments; location such as remote new basins; and HSE concerns.

Nontechnical risks, meanwhile, include highly aware stakeholders; resources such as qualified people, integration, and venture setup; contractor capability and experience; and regulatory and political issues such as evolving/new regulation, expectations in new basins, and fiscal risks.

FIGURE 2. There will be as many subsea trees installed in this decade alone as there were in the previous four decades. (Image courtesy of ExxonMobil; data courtesy of Quest Offshore)

Rolling Stones

Shell’s planned ultra-deepwater FPSO project for its Stones field in the US GoM was held up as one of four examples where the operator’s development strategy of aligning stakeholder expectations and project risks has been key.

Stones is something of an ultra-deepwater pioneer project for Shell since it will be the company’s first to incorporate an FPSO vessel in the GoM. It also will be the deepest production facility in the world at a depth of 2,895 m (9,500 ft) and the first disconnectable FPSO vessel with lazy wave risers in the world. In addition, it will have the deepest gas export pipeline worldwide.

The operator selected a phased approach for the field, with a potential second phase to include another host facility. The operator also will employ wells with artificial lift from multiple Lower Tertiary reservoirs similar to those employed on its groundbreaking Perdido field development now producing in the GoM (another Lower Tertiary field).

According to Dekker, the development strategy for such fields is key in aligning the technical and nontechnical risks, and getting the strategy into the early framing and shaping phase of a project is critical. To do so, development strategy needs to be considered during the feasibility phase when there is sufficient understanding of the opportunity but while it can still influence appraisal. In addition, development strategy needs to be selected early in the concept selection phase.

A lack of a clearly defined and agreed approach to the strategy and selection will lead to internal and external stakeholder misalignment, he said; therefore, it is a must to build a framework linking development strategy to project complexity and schedule drivers at the right time.

Dekker added that development strategy “is the terrain of seasoned development experts,” and companies should draw where they can on in-house, partner, and industry experience and expertise.

Quantum challenges

FIGURE 3. The gap between drilling and production technologies in deep water has never been closer. (Image courtesy of ExxonMobil)

According to David Wilkinson, senior subsea systems consultant for ExxonMobil, the challenges in deepwater are still increasing. Speaking at MCEDD, he pointed out the rising number of both large and small subsea developments and the increasing complexity of the required technologies and execution methods.

Specifically flagging the forecast global subsea trees market by decade, he highlighted that in the current decade (from 2010 onward) there will be more trees installed than in the whole of the previous four decades combined (Figure 2).

The “quantum challenges,” as he termed them, included dealing with large greenfield projects; increasing brownfield projects; and an increasing base to be supported for the life of the field with services including facility modifications and well intervention; abandonment and decommissioning; and inspection, maintenance, and repair.

He also outlined specific technology and execution challenges related to increasing equipment and installation demands, including HP/HT up to 20,000 psi and 204°C (400°F); more difficult fluids and poorer rock properties; more challenging seabed and metocean environments; large-bore equipment for high-rate gas wells; longer field lives; and long-distance tiebacks and depths beyond 3,000 m (9,843 ft).

Water depth ‘gap cycle’

According to Wilkinson, for several decades there has been a water-depth “gap cycle” between the drilling and production sectors (Figure 3). “Production technology is, however, now probably as close as it has ever been to drilling technology. We are going down now toward 4,500 m (14,765 ft) water depth. That’s the kind of acreage the industry is now looking at,” he said.

Execution also is becoming increasingly complex, Wilkinson continued, with the growing requirements for logistics and emergency response preparedness in very remote locations, regulatory and environmental expectations, local content and partnering requirements, supply-chain management complexity, and new technology issues.

The solution is not exactly rocket science, however, with Wilkinson encouraging the industry as a whole to do more with less.

For equipment that means more standardization on fit-for-purpose designs for common needs; making more use of automation, remote monitoring systems, and artificial intelligence; and using fit-for-purpose marine vessels (e.g. for light well intervention work).

Other subsea technology challenges were flagged by Lee Tillman, vice president of engineering at ExxonMobil. Speaking about developing smarter solutions for subsea at the GE Oil & Gas annual meeting earlier this year, he highlighted the continually quickening pace of technology-driven progression into deep water (Figure 4).

The present subsea scenario is set in water depths of up to 3,000 m, with tieback distances of up to 150 km (93 miles) and field lives of between 20 and 25 years, while reservoir pressures and temperatures are generally up to 15,000 psi and 177°C (350°F). The future challenge, he said, was in dealing with water depths beyond 4,000 m (13,124 ft), subsea tieback distances of 150 km to 500 km (311 miles), and field lives beyond 30 years. In some extreme cases reservoir pressures would be likely to exceed 30,000 psi and temperatures could exceed 260°C (500°F).

ExxonMobil’s in-house subsea technology project, launched back in 2008, is focused on the development and qualification of technologies that could deal with these ultra-harsh conditions. Some 20 technology areas currently are being developed and qualified, Tillman said, including gravity-based separation, compact separation, single and multiphase pumps, and subsea compression – technology areas that many of the company’s peers also are heavily focused on.

500-km tiebacks

That includes fellow deepwater pioneer Total, which has undertaken some of the most challenging projects so far offshore West Africa.

FIGURE 4. Technology advances are increasing the industry’s pace into deepwater and ultra-deepwater production, spanning the gap from approximately 600 m (1,969 ft) of water in 1990 to nearly 3,000 m of water today after having taken more than 15 years to extend from the shallows to 600 m deep. (Image courtesy of ExxonMobil; subsea wells data courtesy of Quest Offshore)

According to the company’s head of subsea, Per Arne Nilsen, speaking at MCEDD, significant R&D investments are needed to overcome these kinds of technological barriers in the impending increased water depths.

He highlighted prospective sedimentary basins around the world in depths of up to 5,000 m (16,405 ft), saying, “There are potential discoveries in that type of water depth, and we need to be prepared for that in the future. We are talking about perhaps 300-km, 400-km, even 500-km tiebacks. Beyond 500 km offshore, this will happen at some time in the future.”

He also flagged high-pressure reservoirs such as the company’s recent North Platte discovery in the GoM as an area of continued focus. “That is a very high-pressure reservoir but not high-temperature, so we need technology to go to these higher pressures. Now, 20,000 psi is something the industry is getting to, but for 25,000 psi we are stretching. Can we get there? Maybe, but we may need new materials,” he said.

Other technologies Total is pushing include subsea processing advances in separation, boosting, and compression systems; all electric technologies (a good option for the Arctic); lower power generation; and innovative materials.

Significant challenges remain to be faced by the offshore industry as it heads into greater depths, with ever more difficult and complex fluids and more demanding thermal and distance requirements (colder, with longer offsets) encountered along the way.

Based upon the future plans of these companies and their peers, these challenges will be overcome with the industry’s usual mixture of applied technological innovation, some good imagination, and a whole lot of hard work.