Geoscience Reference
In-Depth Information
see how the distribution of hydrocarbons in the reservoir evolves during production
by repeating the seismic survey after some production has taken place (4-D seismic,
towards the producer wells, perhaps because faults form a barrier to flow; additional
wells can then be targeted on these pockets of bypassed oil. In this application, 3-D
seismic is essential because the better focussing and denser data are needed to look
for subtle clues to reservoir quality and hydrocarbon presence.
The decision on whether or when to shoot 3-D seismic is essentially an economic
one. Does the value of the subsurface information obtained justify the cost? This issue
has been discussed by Aylor (
1995
), who collated data on 115 3-D surveys. At the
time, the average cost for a proprietary marine survey was US $4.2 million, and for
a land survey it was US $1.2 million. The average 3-D development survey resulted
in the identification of six previously unknown high-quality drilling locations. It also
separated good from bad locations: before 3-D the average probability of success (POS)
of a well was 57%, whereas after 3-D the locations fell into two groups, with 70% of
locations having an increased POS of 75%, and the remaining 30% of locations having a
much reduced POS of only 17%. 3-D seismic was also very effective at targeting sweet
spots in the reservoir: initial production rates per well averaged 565 barrels per day (b/d)
without 3-D and 2574 b/d with it. Using this information together with information on
direct 3-D survey costs (for acquisition, processing and interpretation), and the indirect
costs due to the delay in development while the 3-D survey was being acquired and
worked, it was calculated that the average 3-D survey added US $14.2 million in value,
most of which came from the addition of previously unrecognised drilling locations and
the higher initial production rates. Results from this limited database thus indicate the
positive value of using 3-D seismic. Studies of a larger database would be instructive,
but unfortunately industry-wide information on 3-D seismic costs and benefits is elusive
(Nestvold & Jack,
1995
).
However, the oil industry as a whole is convinced of the value of 3-D survey, as can
be seen from the growth of 3-D seismic acquisition worldwide. According to a survey
by IHS Energy Group (summarised in
First Break
,
19
, 447-8 (
2001
)), onshore annual
3-D acquisition increased from 11 000 sq km in 1991 to 30 000 sq km in 2000, while
annual offshore 3-D acquisition rose from 15 000 sq km to 290 000 sq km. Over the
same period, 2-D acquisition fell from 260 000 line km to 110 000 km onshore, and from
1 300 000 km to 840 000 km offshore. The striking increase in offshore 3-D coverage
is no doubt due to the efficiency of marine acquisition and resulting low cost per square
kilometre. It may also reflect the high fixed costs of marine survey. Almost all modern
marine seismic is shot by specialist contractors, who need to keep their boats working
continuously; this results in a mix of commercial arrangements, including surveys shot
exclusively for one oil company, surveys shot for a group of companies, surveys shot
at the contractor's risk with the intention of selling the final processed data on the open
market, and various hybrids between them.
