By 2030, world energy demand is expected to grow by about 50%. Fossil fuels are likely to continue to dominate global energy supplies. According to BP’s September 2008 Technology Report, there are 40 years of oil in reserves economically recoverable today.

In September, Aker Solutions celebrated production of first oil from Reliance Industries’ MA-D6 field, located in the Bay of Bengal offshore India. The project is 100% Aker field development.

Both the subsea system and floating production, storage, and offloading system (FPSO) were delivered less than 16 months after contracts were awarded. Field development happened in less than 21?2 years.

“Never has a complex deepwater project been delivered quicker from a supplier standpoint, and never has a field been developed that quickly,” Raymond Carlsen, executive vice president of Aker Solutions, said.

Aker Solutions delivered the subsea production system and managed installation of the subsea equipment. Aker Floating Production converted and delivered the FPSO Dhirubai 1, while Aker Solutions delivered process equipment and offloading system to the FPSO.

Expansion at Tengiz

Also in September, Chevron Corp. announced its affiliate Tengizchevroil LLP completed a major expansion at the Tengiz field in Kazakhstan that nearly doubles production capacity at one of the world’s largest oil fields.

Expansion completion brings Tengizchevroil’s daily crude production capacity to 540,000 bbl. The first phase, accomplished earlier this year, increased daily capacity from approximately 310,000 to 400,000 bbl.

“This demonstrates how Chevron is leading the industry in selection and execution of major capital projects while providing increased value for our host countries and partners,” said George Kirkland, executive vice president, Chevron Global Upstream and Gas.

The sour gas injection (SGI) operations and crude processing portion of the second-generation plant (SGP) were in service several months while the natural gas and sulfur portions of SGP were being completed. SGP’s full facilities now stabilize and sweeten crude oil as well as separate and process natural gas into gas products and elemental sulfur. SGI re-injects one-third of produced sour gas into the reservoir at very high pressures to help preserve gas pressure.

BP looks ahead

Early this year, BP announced it expects to pump four million b/d of oil until 2020. In doing so, it replaced its annual production by 112% in 2007, taking its proved reserves of oil and gas to 17.8 billion bbl. It also added some 2.4 billion bbl to its non-proved resource base, which now stands at a further 42.1 billion boe.

Assuming a US $60 oil price, the company says, the strength of this position — reinforced by recent access to new opportunities in Oman, Libya, and Colombia, along with heavy oil in Canada — supports production potential of around 4.3 million b/d by 2012, BP Chief Executive Tony Hayward said.

At the company’s annual strategy presentation to financial analysts, Hayward said that in a $60 price world BP was confident not only of boosting output over the next four years but of sustaining production of at least 4 million b/d until 2020, with no new discoveries or access to new opportunities.

“However, bearing in mind a rise in exploration spend to nearly $1 billion this year, together with significant additions of fresh acreage in established areas such as the deepwater Gulf of Mexico and a continuing drive to access new provinces around the world, we expect to do better than this,” Hayward said.

LUKOIL, ConocoPhillips

In August, OAO LUKOIL President Vagit Alekperov and ConocoPhillips Chairman and CEO Jim Mulva participated in a special ceremony marking startup of the Yuzhno Khytchuyu (YK) field located in the Nenets Autonomous District.

One of the biggest fields in the north of the Timan Pechora oil and gas province, this field was developed by OOO Naryanmameftegaz, a LUKOIL and ConocoPhillips joint venture. Discovered in 1981, its oil quality surpasses the Russian Urals export blend quality; its density is 35.5 API, and sulfur quality is 0.71%.

The first stage comprises 32 development wells, an oil treatment unit, oil desulfurization unit, tank farm with the total volume of 40,000 cu m, power supply complex, and other units.

Second stage startup is scheduled for December 2008, with an additional 32 wells put into operation and a high-pressure compressor station, sulfur disposal, and storage facilities completed. The design oil-production level in the field is expected to exceed 150,000 b/d in 2009.

Product is transported by a 98-mile (158-km)-long pipeline to the Varandey Oil Export Terminal located on the Barents Sea coast, with the capacity of 12 million tons per year. “The launching of the YK field is a major accomplishment. In less than three years, we have built both producing facilities and a transportation infrastructure,” Mulva said.

First floating liquefaction plant

In September, Dresser-Rand Group announced it had received a “letter of authorization to proceed” from Kanfa Aragon to supply the compression equipment for the world’s first floating liquefaction plant (FLNG), the Flex LNG Ltd. LNGP1 destined for operation offshore Nigeria. The award was approximately $55 million.

“Over the past three years we have identified LNG liquefaction as a strategic growth opportunity for the coming five- to 10-year period. While many land-based projects continue to experience delays in permitting and partner funding, it now appears that the offshore floating projects present a real and present opportunity,” said Vince Volpe, Dresser-Rand president and CEO.

Floating liquefaction units provide an economic means to develop stranded gas reserves to help meet growing demand for natural gas. While the conventional, land-based liquiefied natural gas (LNG) projects focus on an estimated 70 to 80 fields with gas reserves greater than 5 Tcf, there are more than 1,400 small-to-medium fields with reserves between 0.25 and 5 Tcf that can be developed using floating LNG technology.

Nailsea 25th year anniversary

In April, VetcoGray, a GE Oil & Gas business, celebrated 25 years of subsea engineering achievements at the company’s Nailsea site. Activities included announcement of a new, multimillion-dollar hyperbaric test center for the facility.

The new world-class hyperbaric test center will simulate seabed operational conditions for testing of subsea control modules to identify dormant fault conditions prior to installation.

Dave Tucker, VetcoGray chief operating officer, noted, “Over the next five years, most of our projects will involve testing of equipment at depths of 3,000 meters (9,843 ft). But the trend in the industry is toward application in deeper water. Our new facility will have a test capability of 4,000 meters (13,124 ft).”

Twenty-five years ago, the first subsea control system was delivered from the then-GEC Marconi group in Nailsea, producing first oil on the BP Magnus project. Since then, the VetcoGray Controls business has undergone a series of name and ownership changes, and in February 2007 became part of GE Oil & Gas.

Exxon Angola production

In August, ExxonMobil Corp. announced that its subsidiary, Esso Exploration Angola (Block 15) Limited (Esso Angola), has started production from the Saxi and Batuque fields as part of the development progression of the Kizomba C project.

Combined with a third Kizomba C field, Mondo, which came onstream in January, the project should reach a total production rate of 200,000 b/d of oil over the life of the three producing fields, located approximately 90 miles (145 km) off the coast of Angola in water depths of nearly 2,400 ft (800 m).

The Kizomba C development includes two FPSOs and 32 subsea wells, making it the largest subsea development operated by an ExxonMobil affiliate. The twin FPSO vessels are the fourth and fifth production hubs on Block 15, following Xikomba in 2003, Kizomba A in 2004, and Kizomba B in 2005. Block 15 production is expected to total approximately 700,000 b/d when the Saxi and Batuque fields reach peak production.

“This is another example of integrating ExxonMobil’s project management capabilities with development of Angola businesses and suppliers to deliver exceptional value,” said Mark Albers, senior vice president of ExxonMobil Corp.

More from Madagascar

In October, Madagascar Oil announced increased resource estimates for the heavy oil field Tsimiroro to up to 1.3 Bbbl of oil in place, based on the company’s successful 2008 drilling program. “Our efforts to explore 10 new structures, identified by an independent evaluation from Weinman Geoscience, had an 80% exploration success rate,” said Alex Archila, president and CEO, Madagascar Oil.

Eight of 10 exploration wells drilled within the Tsimiroro area of interest yielded discoveries, showing oil in place ranges between 700 MMbbl and 1 Bbbl. In addition, five appraisal wells helped confirm the company’s estimate of approximately 300 MMbbl of oil in place within the central part of the Tsimiroro area of interest, the TO-1 pool, where a steam pilot project has been ongoing since March 2008. Results show Tsimiroro’s oil gravity in the range of 14° API gravity.

The company successfully completed its objectives for the cyclic Steam Pilot Program, including efficient thermal response, determination of well productivity, absence of sand, and determination of quality and characteristics of crude. Madagascar Oil is currently planning a Phase 2 Pilot Program using a steam flood approach, which is expected to raise the oil recovery factor from 15% to 60%.