Petrobras, IOCs share subsalt, presalt exploration views

All eyes are on Brazil's "presalt" play at the Rio Oil & Gas Expo and Conference, taking place Sept. 15-19 in Barra de Tijuca, an eastern suburb of Rio de Janeiro.

Sep 17th, 2008

Nina M. Rach
Drilling Editor

RIO DE JANEIRO, Sept. 17 -- All eyes are on Brazil's "presalt" play at the Rio Oil & Gas Expo and Conference, taking place Sept. 15-19 in Barra de Tijuca, an eastern suburb of Rio de Janeiro.

State-owned Petroleo Brasileiro SA (Petrobras) and international oil company (IOC) executives spoke on sub-salt exploration activities during the first 2 days of the conference. Several senior executives of Houston-based operators did not appear for scheduled presentations, because of problems caused by Hurricane Ike, and were represented by in-country staff.

In a plenary session on Sept. 15, Petrobras, Chevron, and Shell shared "Subsalt Experiences." Moderator Murio Marroquin, president of Devon Energy do Brazil, stressed the distinction between "presalt" plays off Brazil and "subsalt" plays in the Gulf of Mexico.

Petrobras
Francisco Nepomuceno Filho, E&P corporate executive manager for Petrobras, reviewed the company's recent offshore development strategy and results.

In 2000-01, Petrobras concentrated on monetizing its deepwater assets in the Campos basin, increasing oil production to 1.5 million b/d from 500,000 b/d. Likewise, it increased Tertiary sandstone reserves to 10 billion bbl from 3 billion bbl.

In 2003-06, Petrobras went outside the Campos basin, drilling in water 1,000-2,000 m deep in Espiritu Santo basin to the north, and Santos basin to the south. Filho said the company found "five new giant fields" outside Campos and explored deeper, Cretaceous sandstones. During this time, Petrobras began using centrifugal pumps, boosting oil production to 1.8 million b/d, up from 1.5 million b/d, and increasing reserves to 14 million bbl, up from 10 million bbl.

By 2007, Petrobras had accrued production of 11.5 billion bbl, and logged reserves of 14 billion bbl, with most of the reserves in deep water. Filho noted that Petrobras' previous strategic plan, including forecasts to 2012, was made before the presalt discoveries. He said a new strategic plan would be released before yearend.

During 2006-08, Petrobras explored and discovered light oil in presalt reservoirs, including eight discoveries in the deepwater Campos basin with 28-30° oil. Filho said cluster drilling in the Santos basin's Litoral Norte led to discoveries of light oil in complex carbonate reservoirs, typified by Tupi and Iaga. The salt is 2,000-m thick, and the hydrocarbons have associated CO2. The high-pressure, acid environment requires special production equipment.

Filho believes that Brazil's presalt prospectivity is greater than that of the Gulf of Mexico, noting that all nine of Brazil's presalt wells produced oil. Although wells in the Gulf of Mexico are deeper, they are not as productive, he said.

About 20% of Petrobras' presalt reserves are natural gas, leading to revisions in the company's Plangas project. Petrobras planned to increase gas production in south and southeastern Brazil nearly 350% by 2010. Two new pipelines were designed to carry 55 million cu m/d (1.94 bcfd) up from 15.8 million cu m/d. Filho said the capacity has already increased to 25 million cu m/d.

The Tupi production pilot in the Santos basin should begin producing in 2010, and Petrobras has approved two additional presalt pilots, to begin in 2013-14.

Chevron
Chevron Vice-Pres. Steven P. Thurston said the company has made 25 discoveries in deep water and is running18 deepwater projects, with 8 of those already producing. Thurston participated in the subsalt experiences plenary on behalf of Melody Meyer, president of Chevron Energy Technology Co.

Chevron is investing billions in Brazil as a partner with Petrobras on Campos basin Block BC-20, which includes the Frade discovery, and in other areas.

Deepwater developments require integrated surface and subsurface technologies, he said. Chevron is working in deep water because it "offers a significant reward," and the company can leverage its people, portfolio, and deepwater capability. He described wide-azimuth 3D seismic as a "breakthrough" technology because of its use in subsalt imaging.

Thurston noted the success of the extended production test in 2006 at the subsalt Jack discovery in the Gulf of Mexico's Lower Tertiary trend. The water at Jack is deeper than 2,000 m and the well's TD was more than 8,000 m. Chevron will next run a well test at nearby St. Malo, also on Walker Ridge. The company uses titanium tubulars to mitigate high temperatures and pressures, and plans for subsea artificial lift and pumping systems.

"We believe we will find a commercial solution," Thurston said.

Thurston mentioned the installation of the topsides on the Tahiti truss spar in Green Canyon Block 640, which Hurricane Ike passed over with no problems. Tahiti is still expected to come online in third-quarter 2009, producing from Miocene reservoirs that are 25,000-28,000 ft subsea.

Chevron is working on ultradeepwater developments with long-distance tiebacks of more than 50 miles for oil and more than 200 miles for gas. Thurston said the company plans to drill through as much as 3,300 m of salt, and anticipates host facilities "with small field tie-ins."

Shell
Peter Voser, chief financial officer at Shell, described the company as a deepwater pioneer, citing the Perdido development in the Gulf of Mexico (OGJ, Sept. 8, 2008, p. 35) and the BC-10 development in Brazil (OGJ, May 5, 2008, p. 53).

Voser said Shell has discovered 8 billion bbl of oil in the last 7 years globally and increased its research and development spend to $1.2 billion/year, up from $500,000/year. He mentioned the success of ocean bottom sensor technology in seismic imaging.

Shell is building a new class of rigs called "bully rigs" and will take delivery of the first in 2010. It expects to realize fuel savings, safety improvements, and optimized operational rig performance. It plans to use them in deep water and in the Arctic.

Voser said Shell has the largest LNG capacity of any IOC, and the company is investigating the use of floating LNG systems to tap and monetize hard-to-reach gas.

Shell's subsalt experience begins with the Groningen gas field, discovered in 1959, that has been producing since 1965. The company is adding compression at Groningen to extend production by a few decades and using it as a swing producer.

About 10% of Shell's annual production comes from subsalt wells in Gabon, Oman, Kashagan, and the Gulf of Mexico.

In Oman, Shell is involved in a JV with Petroleum Development Oman LLC to develop intrasalt and presalt carbonate fields requiring advanced well techniques. PDO is a joint venture of the government of Oman 60%, Royal Dutch/Shell Group 34%, Total SA 4%, and Partex Oman Corp. 2% (www.pdo.co.om).

In the Gulf of Mexico, the Princess subsalt well was discovered in 2000, in water 1,083 m deep on Mississippi Canyon Block 765. Production began in 2002.

Shell first distributed oil products in Brazil in 1913 and in the 1970s during the risk contract round was the only company to find hydrocarbons, with Merluza gas field in the Santos basin.

It now has interests in 10 offshore blocks, including 5 in the Santos basin. The company currently produces about 26,000 boed from Bijupira-Salema. Voser said Shell will drill more than 10 new wells in the coming years, many of which are targeting the presalt play in water deeper than 1,500 m. The company is fabricating subsea hardware in Brazil, and plans to incorporate subsea separation and pumping. The FPSO for BC-10 should arrive soon.

Panel
In a panel discussion on Sept. 16, Chevron, Schlumberger, and Petrobras discussed technological and economic challenges of exploring and exploiting subsalt reservoirs.

Mark Riding, deepwater theme director at Schlumberger, described a new seismic acquisition method developed by Schlumberger. "Coil shooting" is a full-azimuth (FAZ) technique with a circular geometry, in which a single vessel sails in overlapping circles, acquiring data constantly. Riding said FAZ data images subsalt more accurately than wide-azimuth data.

Riding also mentioned magnetotellurics; optimized drilling and well placement; geosteering; and fluid sampling and analysis (fluid profiling) as significant technologies that will enable cost-efficient development of subsalt reservoirs.

"Deepwater E&P is on a technology fast track," he said.

Petrobras and partners began drilling presalt prospects in the Santos basin in 2005.

Brazil's national petroleum agency (ANP) approved five new deepwater fields in the Santos basin: Parati (BM-S-10); Tupi (BM-S-11); Caramba (BM-S-21); and Carioca and Guará (both BM-S-9). Three more fields are under negotiation, according to Jose Formigli, executive manager of subsalt E&P at Petrobras.

The presalt reservoirs are complex carbonates, chiefly extensional basin sag ("sag") and syn-rift ("rift") formations.

Petrobras produced 1.79 million b/d in 2007 and expects production to increase at least 7%/year through 2012. In addition, the company anticipates that its new presalt fields in the Santos basin will begin commercial production in 2010, with a "steep ramp-up" to follow. By 2017, the presalt cluster in Santos will produce 1.126 million boed, Formigli said.

Petrobras said it will release its business plan for 2009-20 next month.

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