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
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.
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
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
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
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
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
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
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
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.
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.