Digging deep

Finding and producing oil and gas anywhere in the world is nearly always a challenge, as is developing the technologies required to do it. It is only through continued technological innovation that it can be overcome.

Mark Thomas, Editor-in-Chief

For a global upstream industry currently dominated by issues such as the need to control costs, find the next generation of engineers and operate under increasingly burdensome regulation, it is worth keeping the long-term objective in sight.

As Khalid Al-Falih, CEO of the world’s biggest oil producer, Saudi Aramco, reminded delegates at the recent Offshore Northern Seas (ONS) event in Stavanger, Norway, “To meet forecast demand growth and offset global output decline, our industry will need to add close to 40 MMbbl/d of new capacity in the next two decades.”

The national oil company giant will invest $40 billion per year over the next decade to maintain its oil-producing capacity and increase its gas production. The bulk of that, said Al-Falih, “will be in upstream and increasingly from offshore with the aim of maintaining our maximum sustained oil production capacity at 12 MMbbl/d while also doubling our gas production.”

With oil and gas still forecast to provide 60% of the world’s energy through 2040 and with global liquids production predicted to reach 115 MMbbl/d by that year, the scale of the upstream challenge is clear.

‘Man on the moon’ mentality

According to Gerald Schotman, chief technology officer at Shell, what is required from the upstream sector is akin to what it took to put men on the moon and bring them back safely. Talking earlier this year at the SPE Intelligent Energy event in Amsterdam, he said, “I do believe that if you want to develop a field in 3 km [1.9 miles] of water, you need a ‘man on the moon’ mentality.”

Schotman pointed out that man reached the moon using computing power that at the time “was like a pretty average calculator these days.” He continued, “We have more computing power now, thankfully, and we face similar challenges in meeting energy needs and doing it safely and cleanly. None of us can handle this challenge by ourselves, so we need as an industry to cooperate on this. But we need to get going. Today it is not ‘business as usual’ but ‘business as unusual.’”

Schotman highlighted the increased pace of technology development as a key factor, such as the industry’s ability to get “better pictures” of what lies below the ground’s surface. Seismic advances such as wide-azimuth technology have helped to dramatically improve the quality of the subsurface information, helping to open up new frontiers such as the presalt.

He flagged Shell’s own significant progress, highlighting its Mars B Field development in the Gulf of Mexico (GoM): “The first well—Deimos—started as a completely dry hole. Now it is two discoveries.”

Onshore, improved 4-D seismic data, visualization and interpretation have had great success, he added, but it is not just about the improved technologies.

Schotman commented, “It’s much more than just finding resources. It’s about economics, better planning and budgeting. Having more data is one thing, but it’s also about using [them] better in the fields. Close connections with key developers in this space are crucial—we are cooperating with Intel, for example. They have a better understanding of us, and we have been able to benefit from this.”

Total’s CLOV project offshore Angola started flowing in June. (Source: Total)

Innovation a ‘contact sport’

The process is not easy, however. “Innovation is a contact sport,” said Schotman. “It happens best when the best players get together on shared ground.”

He highlighted some of Shell’s partnering initiatives, such as its well known Game Changer panel and the company’s continuous efforts to monitor innovation taking place in other industries. “Innovation involves getting hold of ‘best in practice’ anywhere,” he said, “and getting over the ‘not invented here’ hurdle.”

His comments were backed up elsewhere by Woodside Petroleum’s Vice President of Technology Brian Haggerty. In his opinion general industry problems and the role of technology are inextricably linked, such as in today’s cost-conscious environment.

Haggerty, speaking at the ONS event, said it was vital for operators to envisage the future and respond to it—“Innovation is required to stop rising costs,” he commented.

Two years ago the company set up a division focused on dealing with issues such as productivity problems and remote stranded gas resources—an issue at the forefront of Australia’s efforts to exploit the vast resources that lie off its western shores. According to Haggerty, these resources “are stranded only because we do not have an economic solution for them.”

Woodside is focused on EOR techniques to help it increase its recoverable reserves. Haggerty highlighted Woodside’s pioneering work with 4-D seismic on the reservoir of its producing Enfield development, the first dedicated time lapse survey to be carried out in Australia.

FLNG solutions

He also mentioned the study of options to reduce development costs such as the potential use of near-shore LNG solutions and the monetization of remote stranded reserves using floating LNG (FLNG) concepts.

On the near-shore LNG work, he said the solution could potentially save up to 25% in costs over a conventional onshore LNG plant, with the additional advantages of working with shipyards, which can provide cost and schedule certainty. In addition, there are the operational advantages of integrating the process, storage and offloading facilities.

Regarding FLNG, the company is pursuing the use of this fresh technology in partnership with Shell for its deepwater Browse project 425 km (264 miles) offshore Western Australia.

That potential megaproject, if it receives a final investment decision before the end of 2015 as currently planned, will see operator Woodside develop the Brecknock, Calliance and Torosa fields located in the Browse Basin. The fields hold nearly 425 Bcm (15 Tcf) of dry gas, with Woodside and its partners studying the use of Shell’s patented technology on possibly up to three FLNG facilities.

Haggerty pointed out that Woodside has strong strategic FLNG relationships with more than 10 companies and that despite initially developing them for the Leviathan project in the Eastern Mediterranean offshore Israel (which it eventually stepped away from), it has “opportunities around the world for the potential use of an LNG-FPSO [vessel].”

He also picked out next-generation LNG solutions as an area of focus for the industry to commercialize currently noneconomic remote gas resources. “Anything less than about 3 Tcf [85 Bcm] is a real challenge,” he said. Designing and building a new generation of small and midscale FLNG units able to deal with this smaller scale of reservoir is, however, something that he feels will be tackled successfully.

Subsea advances

Also highlighted by Woodside’s technology guru was the continuing challenge of developing and improving seabed production solutions such as subsea compression, separation, boosting and power requirements.

With the industry currently working or studying subsea tiebacks of almost 300 km (186 miles) for gas and 70 km (43 miles) for oil, there is now a need to start extending potential tieback distances up to 500 km (311 miles), he said. This can be applied to remote areas not only offshore Australia but in other, harsher environments such as the Arctic, where surface facilities may not be the best operational choice.

Subsea processing is seen by many within the upstream sector as a game-changing enabling technology, with recent seabed separation and boosting applications on deepwater fields offshore West Africa and Brazil acting as building blocks for its field-proven reputation for production-enhancing and reliable performance.

Multiphase pumps

Total is one of the industry’s leading players in this area, with its most recent success coming to fruition earlier this year when its CLOV project offshore Angola started flowing in June.

This is the French operator’s fourth major project in Block 17, with the development of the four fields concerned—Cravo, Lirio, Orquidea and Violeta—notable for its sheer scale. A total of 34 subsea wells are delivering two grades of oil to the project’s FPSO vessel with the produced gas flowing by pipeline to the Angola LNG plant for liquefaction.

FMC supplied all the deepwater vertical trees, wellheads and control systems for the project as well as eight manifolds and two workover systems. It also supplied the world’s largest subsea separation and pumping system for Total’s Pazflor development in the same block, which began producing in 2011.

Wider industry acceptance of subsea processing now appears to have taken place, and the take-up is likely to be rapid. This was the case for FMC’s Riserless Light Well Intervention (RLWI) from a monohull vessel. FMC built its first RLWI stack at a time when there was virtually no demand for the service, and its first customer only initially guaranteed 120 intervention days per year. Several years later the same customer required 900 intervention days per year.

Key subsea technologies on CLOV included Total’s first use of a helical-axial multiphase pumping system, which will help to optimize recovery by compensating for the gradual decline in the pressure from the two heavier oil Miocene reservoirs being produced (Orquidea and Violeta). OneSubsea supplied the Framo subsea multiphase pumping system, with a similar boosting system having also been supplied by Framo to Total for Pazflor.

Secondary from the start

This instance of the installation of secondary recovery equipment at the very beginning of a field’s producing life is expected to become commonplace, with Total itself describing helical-axial multiphase pumps as an “essential solution of the future for improving recovery rates in mature oil fields,” according to Francois Bichon, CLOV’s deputy director, in a press statement at the time of the field coming onstream.

The multiphase system essentially prevents any loss of load and enables the rotor to evacuate a mix of several variable fluids at high speed. Total has two booster pumps installed, one of which is a reserve. It also is planning to incorporate two four-pump multiphase modules on its GirRI (Girassol Resources Initiative) project, also in the same block.

According to Frederic Garnaud, R&D program manager for production and development at Total, the GirRI pumps will be a world first, capable of a record differential pressure of up to 1,885 psi when they are installed in 2015. Speaking at the MCE Deepwater Development event this year, Garnaud said that by 2017 Total would be operating 500 subsea wells, eight FPSO units and two floating production units.

Linked to the subsea processing drive by the industry, Norway’s Statoil and DNV GL are underway with a joint project to develop international standards for the technology to help with its eventual standardization in a bid to control costs.

The ‘T’ is the challenge

Also inextricably linked to the subsea arena are HP/HT projects. FMC Technologies is working with Anadarko Petroleum Corp., BP, ConocoPhillips and Shell to develop subsea production equipment and systems to produce deepwater HP/HT reservoirs with pressures of up to 20,000 psi and temperatures of 177 C (350 F). The companies linked up in July with first-generation equipment likely to be built using existing metals as alloys continue to be improved.

BP’s Project 20K is the most well-known program in this area, with the aim of making advances in four areas—well design and completion; rig, riser and BOPs; subsea production; and well intervention and containment. BP also has teamed up with Maersk Drilling with the goal of building an ultra-HP/HT rig, and in June it also ordered four BOPs and two risers from GE Oil & Gas for the project. Maersk will reveal more details of its super-rig concept in 2015.

HP/HT is particularly relevant to the industry’s efforts to open up the Lower Tertiary (Paleogene) play in the GoM. The challenge of how to best exploit these reservoirs using artificial lift or other enhanced recovery methods is one of the biggest currently being tackled by the oil and gas sector.

It is the “T” in HP/HT that is perhaps the biggest challenge. With temperatures between 204 C and 260 C (400 F and 500 F) being encountered, advances in equipment such as downhole sensors, elastomers and drilling fluids, for example, remain next on the list of solutions to be found.

And the rewards could be substantial, according to Dr. Kevin Kennelly, vice president, upstream facilities at BP. Speaking at the MCE event earlier this year, he said simply, “We estimate there are between 10 Bbbl to 20 Bbbl of oil that we will be able to produce once we attain our 20K goals. That’s the prospects that we have on our books that would be produced.”

Innovative technologies, once more, are the key to unlocking the riches that lie beneath.

What’s next for RPSEA?

JIPs may be the solution as the program struggles without federal funding.

Rhonda Duey, Executive Editor

The Research Partnership to Secure Energy for America (RPSEA) is arguably an example of the U.S. government getting it right when it comes to R&D funding for the oil and gas industry. The program was founded after the passage of the Energy Policy Act in 2005 to lead research in ultradeepwater (UDW) and unconventional technology development as well as aiding small producers. The project was to last 10 years and was given $375 million to fund the research.

A decade later, RPSEA can boast numerous projects that have been completed and new technologies that have been developed. But there are still plenty of projects in the hopper, and as of September 2014, there is no more federal funding for RPSEA. What’s a partnership to do?

“We were instructed by my board to stretch this so it lasts until the end of the program,” said James Pappas, acting RPSEA president. “They were concerned that if we turned all of the project management over to the federal government, we would lose the industry support for the existing 30-plus projects that are still going on. Essentially the lifeblood of this program is the involvement we have throughout the projects themselves.”

Hanging on

With important projects in the balance, RPSEA staff determined that they had to find a way to survive until more funding might become available (which is at least six months from becoming a possibility). The organization has been restructured, and some staff has been let go. Other responsibilities have been turned over to the National Energy Technology Laboratory. But there’s no talk of locking the doors and turning out the lights.

“The technical team is going to stay intact, for the most part,” Pappas said. “We’re going to follow the projects and continue to put the meetings together.”

And help also has been offered by the industry that is benefiting from the technological advances. Pappas said that RPSEA was contacted about 18 months ago by companies that were involved in a specific project. “They said they would like to hire us to put together a joint industry project [JIP] together to carry the project all the way to commercialization,” he said. “We put together a JIP that’s going to get started in three or four months.”

This set the stage for the next phase of RPSEA—marketing the ongoing projects to the industry to encourage additional JIPs. Industry participants provide the funding, and RPSEA provides the oversight and administration. “We looked at a few existing projects and also some of the projects that we wanted to do but couldn’t when they cut our funding,” he said. “We’ve gone back to the blackboard and regenerated those as JIPs, and we’re marketing them right now.”

On the UDW side, which is Pappas’ responsibility, are several exciting technology projects that have piqued industry interest. One of these is the Paulssen project, which has ramifications for both onshore and offshore development. The project involves a vertical seismic profiling (VSP) tool that was originally intended as a seismic-while-drilling tool but is showing promise in microseismic fracture monitoring as well. Pappas said the tool could be run outside casing or tubing to provide a 3-D microseismic picture. “If we can get something in the hole at the same time as we take measurements from the surface, we can visualize a 3-D picture, especially in a horizontal well,” he said. “We could tie all of it together and give a much better indication of where the fracturing is actually taking place.”

Another project involves a tool that could be placed over a BOP as a “last resort,” able to cut anything to 18 in. and seal the well.

A third project entails finding an alternative to an airgun source for offshore seismic surveys. This technique, called a marine vibrator, would act similar to a land vibroseis truck, eliminating the need for the loud surface source that has become an environmental hot-button issue due to the potential effect on marine mammals. Pappas said that other techniques might be evaluated as well.

“We know that if we have a tool that seems to work, we can save time by having an independent group evaluate the effect on mammals while we’re testing it offshore,” he said.

Onshore the potential project list is huge. Kent Perry, vice president of onshore programs, said his group received more than 100 research proposals with a price tag of more than $200 million. That list was reviewed and shortened with the help of industry reviewers and advisers.

“We were about to place the contracts when the program budget was cut by the Murray-Ryan budget bill,” Perry said. “What we are now attempting to do is fund the best set of projects with industry funding via a JIP.”

While he couldn’t go into specifics on the JIPs that are being marketed, he said many of them fall into “areas of current environmental concern” for shale development, including methane emissions, induced seismicity, water management, wellbore integrity and impact on shallow freshwater aquifers.

Cherry-picking

While the JIP route shows great potential for maintaining and reviving some of these projects, Pappas said his team has to be careful not to take on too much. “There’s only so much we can do,” he said. “If we’re too successful, we don’t have the staff to do it right now.”

He’s also concerned about the potential of competing with current RPSEA members like the Gas Technology Institute, the Southwest Research Institute and several universities. “We don’t want to compete with them,” he said. “We’ll lose our members if we do. We need to find the right niche to keep everyone happy.”

And he hopes this will be a short-term problem. There is a bill in Congress to resurrect the program, and if the bill passes, RPSEA will bid for the contract. “Assuming we get it, we’d be back in business with a large-scale $300 million to $500 million program,” he said.

Some successful RPSEA projects

High-resolution 3-D laser imaging for inspection, maintenance, repair and operations

Results of this study validated that the terrestrial accuracies in 3-D laser scanning could be achieved under water.

Autonomous inspection of subsea facilities

The advanced autonomy developed by Lockheed Martin coupled with the Marlin AUV provides industry with a commercial capability to complete subsea inspections in hours instead of days.

Replacing chemical biocides with targeted bacteriophages in deepwater pipelines and reservoirs

Phages have similar inhibitory effects on active sulfate-reducing bacteria cultures as do currently used chemical biocides, are naturally “green” and have a longer lasting inhibitory effect.

Dialing down the ‘mega’ in megaprojects

Standardization, being more selective are two areas where industry should reset its approach toward megaprojects.

Edward Merrow, Independent Project Analysis Inc.

Megaprojects are difficult. It isn’t just their size—more than a billion dollars—but their complexity that drives the difficulty. Although the problems with megaprojects are now the talk of the town, the plain truth is that the industry has struggled with large complex projects for many years. Its track record on megaprojects in the 1990s was not good despite relatively forgiving market conditions that were characterized by a glut of engineering, procurement and construction (EPC) service providers. When the boom years finally arrived in 2004, they ended 20 years of low oil prices that had seen many of the EPC companies disappear. At the same time, the need for opportunities to cash in on the rising market drove the industry to deeper water and harsher climates and into the arms of highly dysfunctional governments. Not surprisingly, it made an already difficult situation much worse.

So what will the future bring? The cost/price squeeze in which the industry once again finds itself has already started to reduce the number of very large projects in companies’ portfolios. Projects that would have been viable in 2004 are not viable today because the cost structure for projects in the industry has completely changed in the past decade.

Even with the reduced demand, megaprojects will face a rough go. The industry is in the midst of a historic changing of the guard as the baby boomers in OECD retire and it faces a generational gap of 20 years. During the 1984 to 2004 era, neither owners nor contractors hired because they were in the midst of an extended cost/price squeeze. The result is a demographic profile that leaves insufficient experience to do large projects well.

So how should the industry respond? First, the industry needs to consciously and deliberately adjust to the new situation. It adjusted to being a high-margin industry very well in 2004 to 2006. Adjusting back to being a relatively low-margin industry is much less fun, but it is essential. The adjustment means that minimizing capital cost must take precedence over schedule. At the same time, the owner teams must focus themselves on rigorous quality control as the EPC’s design capabilities are compromised by inexperience.

Second, the industry will have to become much more selective about which projects are allowed into scope development so that scarce people resources can be dedicated to the projects with real promise rather than spread across any hydrocarbon accumulation a company happens to encounter.

Third, the industry must finally get serious about standardization. The industry has talked about standardization for years, but with few exceptions all it has done is talk. Effective standardization would address many of the industry’s biggest challenges. Standardization reduces capital cost by about 20% by Independent Project Analysis Inc.’s measure. It also reduces the need for engineering services, and engineering services is the weakest link in the projects supply chain today.

Resetting the industry as a relatively low-margin business will not be easy or pleasant. But if it is done thoughtfully, it will ensure the industry’s future while building a more solid foundation for better times in years to come.

Sleuthing out solutions

Through industry’s support of long-term research, solutions to today’s upstream challenges are found by looking for challenges of the future.

Jennifer Presley, Senior Editor, Offshore

It seems counterintuitive to go looking for solutions to tomorrow’s challenges when the industry has so many today that first need solving. But it fits as that is where industry got its start—being counterintuitive is the essence of wildcatting, is it not?

Today’s solutions and tomorrow’s challenges were part of the discussion held as part of the International Energy Agency Gas and Oil Technologies Implementing Agreement workshop “Global Dialogue on Pre-Salt Innovation” held during Rio Oil & Gas 2014. The topic of R&D necessary to support technology innovation generated considerable discussion, particularly in the areas of what industry does not know now that it needs to know for its future presalt efforts.

Alex Moody-Stuart, South America marketing manager for Schlumberger, participated in the discussion as a panelist. He sat down with E&P and provided some additional insight into how the company has approached R&D in the challenging presalt.

E&P: There has been a significant R&D effort in understanding the presalt. What are some of the lingering challenges that industry is working to overcome? As you said in your presentation, “What do we not know?”

Moody-Stuart: Some of the major technical challenges are around increasing the efficiency of well construction, the reliability and maintainability of well systems, and increasing production and recovery factors. Well construction efficiency has a direct impact on saving the rig days during drilling and completion. Improving time between interventions saves on costs and increases production uptime. And we also need to save on intervention cost with the maintainability of well systems. And finally, production and recovery factor maximize the operator’s return on investment.

E&P: How is Schlumberger working to address those challenges?

Moody-Stuart: We are working on technology solutions supported by technical domain experts, both from the operators and our own, in the field . Through close collaboration with customers, our research and engineering (R&E) centers are continuously coming up with ideas that are then prioritized and put into an R&E portfolio that runs from concept through to the commercialized product. This of course requires continual updating to the market requirements to ensure relevance.

E&P: How are research efforts prioritized?

Moody-Stuart: Research is prioritized based on the value the products and services will bring to our customers and to the company. This analysis includes key business and technical criteria including market size, technical requirements, competition landscape, technical risk and cost in product development, to name a few.

E&P: How is a business case made to support long-term research, to go “looking for a problem” that will need a solution?

Moody-Stuart: Part is driven by immediate field requirements. For instance, we should spend so much on finding a solution to the time and risk incurred in drilling out fracture plugs. The technology may be an enabler to an existing system (for example, batteries used in our field systems) or apply directly but has to have a chance to be applicable to our oilfield services market (i.e., how might a given technology be used to address the major challenges mentioned above?). Our portfolio is confidential as the case on these investments is continual and long-term, where our return is linked to our ability to produce products and services that address a market need as soon as possible.

E&P: What are some of the successes of this type of research?

Moody-Stuart: A few successes of this type of research include:

  • Material and chemical research that resulted in dissolving aluminum (dissolving ball instead of drilling out fracture plugs);
  • Real-time fracture diversion that improves fracture propagation (diverting fractures to harder-to-fracture zones in real time);
  • Cement that heals itself (overcoming cracks that are caused by natural aging, chemical corrosion and mechanical deformation of the well); and
  • A bit cutter that rotates, evening the wear and making the bit last longer. This not only allows us to drill faster but for a longer time between trips.