Saudi Aramco is gearing up R&D that includes nanotechnology to explore unconventional gas reservoirs. Petrobras is exporting its deepwater field development technology. Statoil is at the forefront of developing subsea gas compression systems. These national oil companies (NOCs) are prime examples of industry-leading innovators.

NOCs have moved beyond the limited role they used to have. Having learned from the international oil companies (IOCs), NOCs “are now developers and operators of our own and overseas assets,” said Dato Wee Yiaw Hin, executive vice president of E&P business for Petronas, at the Offshore Technology Conference (OTC) 2013 May 6 in Houston. “NOCs are now truly global, integrated oil and gas companies. We have started to go overseas in competition with the IOCs. NOCs own 80% of global oil and gas reserves.”

But not all NOCs are operating at that level. At the other end of the NOC scale are companies struggling to come to terms with exploration successes in their countries that then drive demand for revenues from the local governments. The biggest challenge for most of these NOCs is finding ways to both fund the governments and find billions of dollars to invest in major development projects.

Many of these NOCs have carried interests in exploration drilling. But, like ENH in Mozambique, many NOCs will have to meet their financial obligations for the cost of the development, which will be in the billions of dollars, in a country where the price of a single LNG plant with two trains is more than the country’s gross domestic product (GDP).

A lot of these governments still do not have the regulations or infrastructure in place to deal with the unexpected bonanzas from oil and gas discoveries. The NOCs in these countries are usually brand new and have not had to negotiate production-sharing agreements (PSAs) or handle oil and gas lease sales, especially offshore. Getting resource development right is crucial to the welfare and growth of those countries’ economies.

The NOCs are facing issues such as developing sizeable fossil fuel resources in remote areas for global markets while converting those resources into socially beneficial stimuli. These companies see the attractiveness of devising new legal regimes and adapting the latest technology to achieve their goals.

Pushing technology

After years of relying on international expertise, Saudi Aramco is developing its own technology inhouse as it focuses on R&D for onshore and offshore exploration and in developing reservoirs using nanotechnology robots one-thousandth the size of a human hair.

“At Saudi Aramco we are pushing from a traditional role as buyer and consumer of technology to our own global technology and R&D strategy,” said Khaled Buraik, vice president of petroleum engineering and development for Saudi Aramco, at OTC 2013. “We envision becoming an enabler and center of new technologies in the business that we do. We are pursuing R&D to bring about breakthrough achievements, not merely incremental enhancements.”

Saudi Aramco is continuing its reservoir nanoparticle program. The reservoir robots, or “Resbots,” move through water and into reservoirs to capture data that could be used to increase recovery. Perhaps most significant for Saudi Aramco, the company is producing the technology itself.

“We have already conducted a major field test in-house with manufacturing of nano particles,” Buraik said. “This year we will conduct two major field tests. One will focus on enhanced reservoir characterization, the other enhanced recovery.”

The key questions the company is trying to answer involve acquiring four times the seismic data 50% of the time at 50% of the cost and how to increase reservoir recovery by 15% to 20%, he continued.

“Now we are moving to a new frontier, which is the unconventional,” Buraik said. “The pursuit of unconventional gas is one of our most exciting new efforts. Given our local infrastructure, the availability of water is a challenge.” Research is under way for different types of water use.

Technology also has come into play in the Red Sea, where Saudi Aramco is undertaking deepwater exploration. In the past few years the company has completed seismic tests in the Red Sea and is now drilling its first deepwater well. Because the prospect is below a thick salt section, the company has adopted an integrated approach to exploration using seismic, electromagnetics, and high-precision gravimetrics to better define the substructure below the salt, he said.

Deepwater success, challenges

Petrobras has had impressive success with its deepwater production from presalt wells since 2006. Seventeen presalt wells are producing 300,000 b/d. The company will invest US $236.7 billion over the next four years, including $137.5 billion in E&P, according to Maria das Gracas Silva Foster, Petrobras CEO.

Yet Petrobras faces significant challenges in meeting a target of producing 5.2 MMboe/d by 2020. To develop these world-class resources, the company will need to add another 17 deepwater drilling rigs to the 41 rigs currently working. This also includes the construction or refurbishment of more than 24 FPSO units.

In all, Petrobras will have more than 38 new production units and drilling rigs entering service over the next seven years, said Carlos Tadeu da Costa Fraga, E&P presalt executive manager for Petrobras, at OTC 2013.

“From September 2008 to April 2013, Petrobras has witnessed a 50% reduction in drilling time from 134 days to 70 days per well with an attendant 50% reduction in drilling costs. We finished a well [in late April] in 40 days. We are progressing with the support of drilling contractors and our suppliers,” he continued.

In other new technology, Petrobras is testing its first intelligent completion module at Sapinhoa with the first well producing 25,000 b/d. A Sapinhoa pilot project was placed online in January 2013. It is one of seven initiatives scheduled for 2013. The project involves the Ciudade de Sao Paulo, an FPSO vessel that will produce 120,000 b/d from 13 interconnected wells, Costa Fraga explained.

Petrobras is not the only NOC focusing on subsea technology. More than 50% of Statoil’s current production comes through subsea systems from about 500 operated subsea wells. The company believes new subsea processing options are vital for operators to develop ultra-deepwater projects or fields in remote, harsh environments like the Arctic Ocean.

Statoil pointed out that wet tree developments with boosters can improve recovery rates by 5% to 20% compared to dry trees. The company is at the forefront of subsea gas compression. It plans to use the technology on its Asgard field, which is expected to begin production in 2015; Gullfaks South field, also in 2015; and Ormen Lange field. The company also has at least 10 other projects that it is considering for the same application.

New technology development continuously opens the door to new ways of applying subsea processing, said Simon Davies, project manager of technology for Statoil. In the future there is likely to be even tighter integration of subsea processing building blocks used as part of a complete field development concept.

Diversifying internationally

The mid-size NOCs face a different set of problems. Often the resources within the countries of origin are insufficient to meet domestic energy demands. Petrovietnam, for example, has gone from being an E&P company in Vietnam to a vertically integrated energy company in Vietnam that is involved in oil and gas production, refining and petrochemicals, international E&P, power generation, and oilfield services. The company has been expanding its operations internationally to increase its reserve position.

“We have been going overseas since the early 2000s,” Dr. Khanh Van Do, president and CEO of Petrovietnam Exploration Production Co., said at OTC 2013 on May 6. “We are now working in 15 countries with 20 projects in Russia, Central Asia, Southeast Asia, South America, and North Africa. Of the projects we are implementing overseas, three are under production, and our share is 36,000 b/d. We started production two years ago. By 2015 overseas production will be 50,000 b/d.”

Five other projects are under development internationally. One project in Algeria should begin production in 2014 with peak production of 40,000 b/d. Two other projects in Russia are slated to start production in 2014 and 2015. The company also is in a project in Venezuela that is producing very heavy oil.

Petrovietnam is expanding by diversifying with overseas ventures. The company has a project in Peru, where it bought a 50% interest in Block 67. First oil is expected in November 2013 with maximum production of 60,000 b/d.

Offshore Myanmar, the company is the operator of one block with an 85% interest. The company is seeking other partners to farm out 35% of the block. A data room has been open for the last year, he continued.

Domestically, Petrovietnam produces about 110,000 boe/d. By 2015 production should increase to 180,000 boe/d, rising to 470,000 boe/d by 2025. Production is expected to grow annually at a rate of 10% starting in 2016.

Petrovietnam has lots of opportunities for new partners in the Red River, Phu Khanh, and Nam Con Son basins and is actively pursuing partners for deepwater exploration. Do pointed out that data rooms were open in Hanoi for interested companies. Petrovietnam also is looking for companies that could provide expertise in developing marginal gas fields and formations with high CO2content.

Expanding domestically

In Equatorial Guinea, the Ministry of Mines, Industry, and Energy announced in a release dated April 10, 2013, the ratification of eight production-sharing contracts (PCSs), originally signed in December 2012. Operators of the eight oil blocks include Murphy Equatorial Guinea Oil (Block W off Rio Muni); Xuan Energy (Block Y); Royal Energy (Block Z offshore Bioko Island); Glen-core Exploration (Block EG-05 offshore Bioko Island); and G3 Oleo e Gas, Pan Atlantic Oil and Gas, and Elegance Power, respectively (blocks EG-01 to EG-04 onshore and offshore Rio Muni). All the contracts have the state-owned GEPetrol as a partner.

Equatorial Guinea is preparing for the sale of new oil blocks after the successful signing and approval of the PSCs. The sale is set for later this year. The ministry intends to acquire 3-D seismic data for blocks F-13/G-13,I-13/I-14, and I-15/I-16 in the coming months. These blocks will be offered to the international petroleum industry later in the year once the 3-D seismic data have been acquired and processed.

Already, exploration has intensified as new discoveries are being made. On May 20, PA Resources said the Carla South (1-7) exploration well in Block 1 offshore Equatorial Guinea encountered approximately 12 m (39 ft) of net oil pay in good-quality sandstones. The discovery extended the proven Carla trend from Block 0 into Block 1.

Equatorial Guinea’s current oil reserves are estimated at 1.1 Bbbl. Oil officials in Malabo said the Zafiro field continues to be the single largest producer. However, field production is in decline.

But officials expect the country’s declining output to reverse. New oil production is expected in 2013 from the $1.6 billion Alen gas condensate field, which lies in Block 0 and is being developed by Noble Energy, officials said.

The Alen field, located in the Douala basin, is expected to have an initial output of about 37,000 b/d, according to the US Energy and Information Administration. The field extends from Block 0 (95%) to the northern part of Block I (5%).

With the increased activity, awarding of oil blocks between 2010 and 2012, and another planned lease sale, oil officials in Malabo expect oil production to jump by more than 100,000 b/d within two to three years.

NOCs struggle with success, lack of revenues

Countries such as Bangladesh, Liberia, and Mozambique have experienced exploration success but do not have the domestic markets or infrastructure to use the reserves found offshore. The governments are dependent on international markets to provide the investment to develop the resources. Not everything is going smoothly as these countries wrestle with devising regulations and PSAs that will attract that investment.

For example, Bangladesh Oil, Gas, and Mineral Corp. (Petrobangla) was forced to change PSC terms after poor response to the Bangladesh Offshore Bidding Round 2012. Of the 12 oil and gas blocks offered, it received bids from two companies for only three offshore blocks.

Petrobangla was scheduled to offer deepwater blocks before the end of May with revised PSC guidelines, Muhammad Imaduddin, Petrobangla director, said in a press release. The state-run upstream company would reseek bids for the three deepwater blocks it offered in the December 2012 bidding round.

“We want to ensure that the terms and conditions of the PSC for our deepwater blocks are competitive with those of neighboring countries like Myanmar and India,” Imaduddin said.

In the proposed changes,

  • Contractors will be allowed to sell half of their explored and extracted volume of oil or gas to third parties without Petrobangla’s right of first refusal;
  • The cost recovery limit will increase to a maximum of 70% per calendar year, instead of 55%, of all available oil, gas, or condensate from the contract area;
  • Wellhead gas price will be pegged to high-sulfur fuel oil (HSFO) prices, which would offer a maximum price for gas of $6.50 per Mcf; and
  • Contractors will enjoy a tax holiday during the entire exploration, development, and production phases. Petrobangla already has moved a proposal to amend the existing model PSC to the Ministry of Power, Energy, and Mineral Resources for approval. “The proposed changes will be notified after the final approval by the Cabinet Committee on Economic Affairs [headed by the prime minister],” Imaduddin said. “Petrobangla will complete evaluating bids within May and award the blocks to ONGC Videsh and ConocoPhillips by July.”

Another country with a nascent oil and gas sector is Liberia. With ExxonMobil entering Liberia, the country is forging ahead with development since African Petroleum discovered a large accumulation of oil deposits last year. The National Oil Co. of Liberia (NOCAL) said in a release on April 5, 2013, that it has completed “an historic landmark deal to secure the entry of ExxonMobil [operator] and Canadian Overseas Petroleum [COPL] into the country’s offshore hydrocarbon sector.”

The PSC gives ExxonMobil an 80% interest in Liberia’s offshore Block 13 (LB13) and COPL a 20% interest, according to the NOCAL release. The new PSC, which replaces the previous contract for Block 13, is among the country’s first to include provisions in which citizens could receive dividends if exploration leads to production.

“The PSC includes a 5% citizen participation share in Block 13. If exploration and development in Block 13 are successful, revenues will be available to share with citizens after ExxonMobil and COPL have recovered their exploration, development, and production costs,” Israel Akinsanya, vice president of public affairs for NOCAL, said in the release.

If the provisions for citizens are successful in Liberia, they may be copied by other African oil producers to pacify agitations for shares in oil resources by host communities in West Africa’s oil-producing areas. The PSC includes the right for Liberia to receive a 10% share in Block 13 at the start of commercial production, he said.

“Liberia is at least five to seven years away from producing a drop of oil,” Akinsaya said. “We are still in the exploration phase, and the discovery made by African Petroleum in February needs to be further evaluated.”

Across the African continent, Mozambique is racing to develop oil and gas laws to maximize the benefit to the countries. “The Mozambique Petroleum Law, regulations, and exploration, production, and concession contract will all be updated,” said Carlos Zacarias, minister of the National Institute of Petroleum in Mozambique at OTC 2013.

There will be a new bidding round after the new petroleum law is enacted. “In 2014, we will make an announcement of the bidding round,” he continued.

“In the last two years, we have had amazing gas discoveries in the Rovuma basin. There have been 12 discoveries in a 50-km (30-mile) radius.” The country’s reserves have gone from about 7 Tcf in 2009 to 170 Tcf in 2013, he added.

The country is developing a gas utilization plan, which will address options for pricing structures and mechanisms for using the gas revenue stream for Mozambique for fertilizer, petrochemicals, gas-to-liquids, power generation, and LNG.