The handful of major international
oil companies that negotiated concessions with the Angolan government
in the early to mid-1990s seem like geniuses today.
But in reality, the world-class petroleum play that's exploded over
the last five years was initially just an effort to leverage shallow
water production.
"When we (Chevron and partners Sonangol, Totalfina-Elf,
Agip and Petrogal) acquired Block 14 (in 1995), which covers about
1,560 square miles outboard of our shallow water Block 0 concession,
we didn't anticipate the enormous potential of the Tertiary turbidite
trend," said Tad Schirmer, exploration manager of Block 14 for Chevron
Overseas Petroleum. "It simply fit into our company strategy."
That strategy involves minimizing risk as much as
possible in the upstream "by working in areas with proven petroleum
systems and leveraging our existing experience and infrastructure."
So, he added, this was a natural progression for
Chevron in Angola.
"We felt it was likely that the petroleum system
existed in deeper water," Schirmer said, "but the real question
was, how much riskier was the traditional play going to be?
"We recognized that as we went into deeper water
it was likely that the producing horizons on Block 0 could become
too deep in terms of porosity retention and risk of gas cracking,"
he continued.
"There was quite a bit of risk pursuing an entirely
separate play in this deeper water block, but we did realize that
the Zaire-Congo River fan was a major subsea fan feature driven
by long-term Tertiary deposition and drainage of the central African
continent.
"It was possible," he added, "there could be a turbidite
play similar to what had been recognized in the deep-water Gulf
of Mexico."
Generating Some Heat
Several factors converged to make the mid-1990s the
jumping-off point for what has become one of the hottest exploration
plays in recent years.
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Geoscientists began to recognize the geologic elements conducive
to hydrocarbon occurrence in the new area.
Such elements as an active petroleum system with multiple source
rocks, widely distributed, excellent quality, deep-water turbidite
sandstone reservoir rocks and complex tectonic history with
salt dynamics, producing multiple structural trends and a myriad
of traps across the basin.
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Advances in technology that allowed exploration and development
of oil fields in deep-water settings.
- Support of the government for the petroleum industry in Angola.
"When you combine all those elements this was a compelling
play when we began negotiating for Block 14," Schirmer said. "We
give a lot of credit to the Angolan government and Sonangol, the
state oil company, for providing a business environment that is
conducive to this initially high-risk exploration."
Of course, Chevron wasn't alone. Elf Aquitaine and
Shell, along with Chevron, were the first players to stake a claim
offshore Angola. That was a gamble that's paying off tremendously
today.
Chevron and its partners drilled the first exploratory
well, 14-1X, in 1996 to test the deeper Cretaceous play that is
productive in shallow water, as well as some seismic amplitude anomalies
in the Tertiary section, to calibrate whether they were sands and
if there were hydrocarbons present.
The well did successfully encounter turbidite sands
that were oil charged in the Miocene interval.
"We tested those sands, declared a discovery, and
kicked off explosive growth in our exploration portfolio on Block
14," Schirmer said. "We now knew there were sands in the system
and these seismic features could be oil charged."
From 1996 to 1998 the Chevron portfolio grew from
a few prospects in the Pinda, which is the productive formation
in shallow water and a primary focus when the block was acquired
in 1995, to about 80 prospects in the Tertiary turbidites.
That first well indicated that the Pinda reservoirs
were tight and that had a negative impact on the firm's perception
of the deeper play. The success in the Tertiary more than offset
that disappointment.
'A Tiger By the Tail'
Elf announced the first commercial discovery offshore
Angola in 1996 as well, discovering the Girassol Field on Block
17.
While Chevron's first well was not a commercial success
-- the terms of the Production Sharing Agreement and expected development
costs called for flow rates of 5,000 barrels per day from a single
reservoir, and the 14-1X tested 2,700 barrels of oil daily -- it
was definitely a geologic success.
"Following that well we went on a very aggressive
interpretation process to map up all these channels we were seeing
on the 3-D data," Schirmer said. "Our original 3-D dataset was 1,100
square kilometers in the eastern portion of the block in less than
500 meters of water. We studied the imaged channels in that sector,
and that's what drove the first seven wells in our program."
All those wells successfully encountered hydrocarbons.
"We had a tiger by the tail," he continued. "We recognized
a new play existed, the hydrocarbon system worked and we had significant
positive results in the turbidite sands with high quality reservoirs
and robust trap geometries."
Today Chevron has shot over 2,500 square kilometers
of 3-D seismic covering most of the block, and has an extensive
portfolio of prospects.
First Success
Chevron drilled its first commercial discovery in
1997 with its second well, the 14-2X. The Kuito Field discovery
well tested a robust amplitude anomaly in a flat spot in the northeast
portion of block 14.
The well tested 7,500 barrels a day on a restricted
flow rate from the Upper Miocene. The firm immediately drilled three
appraisal wells, delineated the field and quickly moved to a phased
development.
Chevron achieved first oil at Kuito in December 1999
-- just 30 months from declaration of discovery -- and today the
field accounts for the only production from the deep-water turbidite
play.
"We wanted to establish production in the block to
generate cash flow to move the exploration program forward -- and
to gain as much information about the reservoirs as possible," Schirmer
said.
Today the Kuito Field is producing 65,000 barrels
of oil a day from an FPSO, with ultimate production when all phases
are complete to hit over 90,000 BOPD. Kuito is Chevron's first giant
field in the play.
Chevron decided on the Floating Production Storage
and Offloading System (FPSO) for several reasons:
- The offshore environment of Angola is quite benign with no
major storm tracks like you see in the Gulf of Mexico or the North
Sea.
- Deep-water settings are conducive to FPSO technology.
- The FPSO allowed Chevron to get the field on-line quickly.
Ups, Downs and Ups
Chevron's third exploratory well (14-6X) commenced
in 1997, 20 kilometers from Kuito, and the firm made its second
commercial discovery in a new horizon. The well proved hydrocarbons
in the Lower Miocene and was depositionally different from the Kuito
accumulation.
"Upper Miocene features like the one at Kuito are
turbidite fills in very deep canyon cuts -- similar to what we see
in the present day Congo Canyon in the block," Schirmer observed.
"These canyon cuts are eroded and depositionally backfilled and
infilled with shale and turbidite sandstones."
The Lower Miocene, however, is generally deposited
in more distributed turbidite channels with more subtle basal cuts
and more laterally distributed channels, he added, as opposed to
deeper eroded and vertically filled canyons.
Following the Landana Field discovery, Chevron drilled
the 14-7X in 1998, 20 kilometers south of the Landana and 50 kilometers
from Kuito. The new wildcat tested an Upper Miocene anomaly that
appeared similar to Kuito.
The well was successful, but did not achieve commercial
flow rates.
That same year the firm drilled two wells five to
six kilometers south of Kuito, and both were commercial discoveries.
- The 14-9X was a dual discovery from the Middle Miocene and
Lower Miocene, once again proving up a new horizon in the Middle
Miocene and confirming the Lower Miocene as a target. The well
achieved a flow rate of 30,000 barrels of oil daily on a test.
- The 14-10X well was a Middle Miocene discovery that flowed
10,000 barrels of oil per day on a test.
The Benguela and Belize fields will be developed
together as a separate development from Kuito. Presently Chevron
is in development planning for the fields with project authorization
targeted for early 2002.
Coming Up Dry
Following 3-D seismic acquisition in the deeper portions
of the block, Chevron was ready to step out with its exploration
program in 1999. The company drilled two wells in deeper water in
the block's western portion, and both were dry holes.
Factors of failure included trap risk and the need
to understand the relationship of the seals within the section.
"Also, during this time we were trying to understand
the relationship of seismic amplitudes -- especially amplitude vs.
offset -- to the sands and hydrocarbons," Schirmer said. "We felt
like we had a handle on that relationship based on the earlier wells,
but when we stepped out into deeper water those seismic amplitude
relationships had a subtle change.
"The information we gleaned from these two unsuccessful
wells allowed us to fine tune our modeling efforts," he added. "We
certainly weren't discouraged after all the success we have had."
The two dry holes forced Chevron to go back and analyze
its portfolio based on the new information.
"We had a large number of prospects, and we went
through a very rigorous process of maturing all the channels, making
sure they were evaluated with a consistent risk and volumetric type
approach," he said. "We racked up the entire inventory with our
partners on a consistent common basis, and we incorporated lessons
learned from all our previous drilling activity to better understand
this relationship of traps and seismic amplitude to try and understand
how to lower the risk on subsequent wells."
Modern-Day Pioneers
All that worked paid off last year, when Chevron
discovered the Tomboco Field in the Middle and Lower Miocene about
six kilometers west of the Benguela Field in 500 kilometers of water.
The well flowed 16,000 barrels of oil a day on test.
That discovery was followed by the Lobito discovery
in the Lower Miocene, which flowed 10,200 barrels daily on test.
"These last two wells were significant breakthroughs
for us," Schirmer said. "We developed a new methodology for looking
at seismic amplitudes, and it broke some of the paradigms we had
previously held. We've learned a great deal about what types of
seismic attributes we need to see and how they relate to hydrocarbon
sands within Block 14."
Chevron and partners recently announced a discovery
at Tombua No. 1 that is one of the firm's key wildcats in 2001,
and tested a new structure on the block. The Tombua 1 well flowed
over 10,000 bopd from two zones in the lower Miocene.
Indeed, Chevron and its partners have drilled 12
exploratory wells in just four and a half years, gotten a field
on-line and planned other major capital projects that will come
on-stream between now and 2005.
Plus, Chevron has more primary exploration to do
that has a similar risk profile to what has already been found.
"I've been working with Chevron for 15 years and
started my career in the United States onshore working mature basins,"
Schirmer said. "I really felt like I'd missed out by a generation
on the excitement of finding big fields and we were just mopping
up.
"But here's a place where my generation has the opportunity
to do the same kind of exciting wildcatting that generations before
us enjoyed," he said. "It's incredible."