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By JACK EDWARDS
Santos Finds Took Some Time
Editor's note: Edwards is with the department of geology at the University of Colorado, Boulder.
Antonio Tisi and Gonzalo Encisco, both now in Shell international ventures, published studies of Merluza Field, and parts of their work were used in preparing this description of its discovery.
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Shell Oil's Pecten explored on 23 risk contract blocks in nine onshore and offshore basins in Brazil from 1976 to 1990. A total of 27 wildcats and six development wells were drilled on 13 blocks.
Combining the cost of 43,000 kilometers of seismic surveys with wildcat drilling, Pecten spent $220 million net. Including partners costs, total exploration expenditures were $386 million.
Merluza Field in the Santos Basin (figure 1) was first indicated in 1979 by a wildcat that encountered gas shows while drilling. Two other discoveries were made in the offshore Brahia and Potiguar basins during 1979 and 1982, but were non-commercial.
Persistent belief that the Santos Basin held good exploration opportunities led to the drilling of two more wells that confirmed Merluza as an economic discovery. Geological and geophysical studies, these two more wells and lengthy negotiations with partners and Petrobras led to development of Merluza Field in the late 1980s.
On the basis of the 2-D seismic survey conducted by Petrobras, risk contract blocks were acquired in the Santos Basin in 1978 under the direction of Larry Gordon, Pecten's new ventures manager.
The seismic survey disclosed a number of north-south trending, salt cored Cretaceous anticlines, with amplitudes increasing down dip from west to east. One of the largest structures was 14 kilometers long and three kilometers wide, with 220 meters of vertical closure. This Lower Cretaceous prospect, named Merluza, covered 29 square kilometers.
In 1979 the Merluza prospect was tested by wildcat SPS-11 on block ACS 14, acquired by Pecten/Shell/Marathon. The location was on the fold axis three kilometers north of the crest of the Merluza structure. It drilled through Tertiary and Cretaceous clastics into Albian Guaruja limestone below 5,000 meters (figure 2)
While drilling, a thin gas zone was recognized in an Upper Cretaceous shallow-marine sandstone. A gas show also was indicated in a Turonian sandstone. A strong water flow from the deep Lower Cretaceous limestone forced abandonment without logs or tests being run.
In 1982 after geologic and geophysical review and with partner's agreement, the SPS-21 was drilled four kilometers south of the SPS-11, very near the deep crest of the Merluza structure. It found the thin shallow-marine sandstone, but not the deeper Turonian sandstone -- and partners lost interest and withdrew from the contract.
Pecten geologist Seymore Sharps interpreted from sample studies that the Turonian Lower Itajai sandstone interval with a gas show in the SPS-11 was of turbidite origin. Structural restorations indicated that during Turonian time the Merluza salt pillow grew by sediment loading on the flanks.
The crest was eroded and Lower Itajai turbidite sandstones onlapped the north half of the structure, causing the absence of the turbidite sand in SPS-21 on the crest (figure 3).
Pecten geophysicists Bill Elbel and Tom Baird mapped a high amplitude reflection tentatively tied to the turbidite gas sand interval in the SPS-11. This strong reflection expanded down the north plunge of the anticline from the area between the SPS-21 and the SPS-11.
They interpreted the thickness of the porous sand, which gave rise to this reflection.
Next, a recommendation was prepared under the direction of Richard Gardell and Jack Edwards to drill a third well on the Merluza prospect.
During 1984 Pecten, acting alone, drilled the SPS-20 three kilometers north of the first well (SPS-11) on the fold axis, within closure, but well down the north plunge. SPS-20 was a gas condensate discovery in the Itajai turbidite with 26 meters (86 feet) of pay with 20 percent porosity.
During 1985-86, Pecten conducted additional geologic studies by Sharps and Patricia Santigrossi. Geophysical analysis of reprocessed seismic data (by Elbel, supervised by Baird) resulted in excellent ties with the well log synthetics. This seismic data was used to map the Turonian reservoir thickness and extent.
This work increased confidence in the porosity -- thickness geometry of the reservoir beyond the economic threshold of gas volume needed to proceed with development.
While exploration studies and economic evaluation continued, discussions with Petrobras took place to formulate a gas contract.
The original risk contract did not contain a gas development clause. These discussions were led by Phil Jensen, Bruce Bernard and Fred MacDougal of Pecten, and Luis Reis of Petrobras.
Pecten and Petrobras eventually agreed to a development plan, and from 1986 to 1990 six development wells were drilled based on the seismically mapped reservoir geometry.
A production platform and a 100-mile pipeline to shore was constructed. Commercial production was established in May 1993 and gas began to flow to Sao Palo, Brazil. The Merluza field operation was turned over to Petrobras in accordance with the risk contract.
Merluza has produced an average of 60 million cubic feet of gas and 3,000 barrels of condensate per day. The original estimated ultimate recovery for Merluza Field was 300 billion cubic feet of gas plus 11 million barrels of oil.
Subsequently Petrobras has discovered four oil and gas fields in Lower Cretaceous limestones in the southern part of the Santos Basin. Pecten had drilled one of these blocks and decided not to test or complete the well because of the 2000-ppm H2S content of the gas in this offshore location.
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