Oil and gas asset teams are very much in vogue these
days.
The upside: Interdisciplinary team members contribute
their individual expertise, interacting for the common goal of finding
and producing hydrocarbons.
The downside: How do you communicate when each discipline
has its own unique language?
Drillers talk about penetration rates, pore pressures,
compressive strength and such. Geologists talk about matrix, lithology
and porosity, while their geophysical counterparts speak in such
esoteric terms as impedance and velocity.
"This is a big problem with asset teams," said Roger
Young, chief technology officer at Houston-based eSeis Inc., "where
they all want to understand the rocks, but they have no common way
to communicate.
"If you look at an outcrop, you don't see impedances,
you see lithology."
To cut to the chase and get all team members onto
the same page, Young preaches the theme of seismic petrophysics,
or rock-based integration. Unlike many of today's statistically
based inversion programs, seismic petrophysics takes the concepts
of well log analysis -- where the available data are cross-plotted
to yield information about reservoir lithology, porosity and fluids
-- and applies them to seismic data.
"People take well logs to the rocks using log analysis,"
he said, "and we're doing this with seismic, which is the most spatial
data. The seismic becomes lithology, porosity and fluid, so now
we're all talking the same thing."
Young pioneered development of the "LithSeis" processing
technique in the early 1990s while at Union Texas Petroleum Holdings
(UTP), where he noted the process played a role in the discovery
of the Alpine Field on Alaska's North Slope.
The Canadian-based company retained by UTP to write
the computer code and develop the software for the technique was
purchased by eSeis early last year.
'A Quicker Look'
This approach to hydrocarbon detection can be used
with both 2-D and 3-D seismic data. Using amplitude variation with
offset (AVO) analysis -- looking at the seismic data before the
individual traces are averaged, or stacked -- shear and compressive
impedances are extracted from the seismic data. The shear wave data
can be inferred without being acquired via multicomponent acquisition
technology.
The information from the compressional and shear
waves is cross-plotted and color coded using LithSeis, indicating
formation lithology, relative porosities and fluid content, noted
eSeis president Dan Morris.
He cautions this is not a standalone tool, noting
the end result must undergo geologic scrutiny to determine if it
is plausible in the particular geologic setting.
"It is a good device for studying AVO and extracting
interpretable information," said University of Cape Town senior
lecturer in applied geophysics George Smith. Author of numerous
published technical papers on AVO and inversion, Smith said he has
kept a close eye on the technique since he was first introduced
to it about five years ago. He noted that some promising tools have
been added to its basic toolbox, such as the approach to moveout
velocity extraction and absorption
Morris emphasized the technique reduces turnaround
time dramatically, enabling asset team members to work through an
entire 3-D data set in a day and come up with multiple leads.
Ron Neal, president of Houston Energy and Development
(HED) and an AAPG member, concurs.
"It does offer a quicker look," he said. "LithSeis
begins with AVO, and if you have a line or volume of AVO, then the
tool is not only relatively quick but also relatively inexpensive."
If a company has no AVO, the eSeis team reprocesses
the available data for AVO analysis and then takes it to LithSeis.
"This makes the assumption the processing gives reliable
AVO," Neal cautioned.
Although it will be about 90 days yet before HED
drills a well where the technique was used in the evaluation process,
Neal said he is very positive on it as a potential indicator.
Ibhubesi Success Story
Still, the ultimate value of any hydrocarbon detection
technique is proven only with the drillbit.
Forest Oil International has some impressive results
to show for using LithSeis in its active -- and expanding -- drilling
program in the Ibhubesi Field in South Africa.
The Albian-Lower Cretaceous stratigraphic play was
first discovered in the mid-1980s by Soekor, the south African national
oil company, which thought it was drilling a small structural test,
according to chief geophysicist and AAPG member Tim Berge at Forest.
The test well had a DST for gas but was considered uneconomic at
the time and was plugged and abandoned.
Forest became a leaseholder on a couple of blocks
there via a trade with Anschutz in 1998 and subsequently rediscovered
the field.
"There was a lot of 2-D in the block area, and about
18 wells had been drilled," he said, "with three of these having
a DST recovery of gas or oil.
"We began mapping on the 2-D and couldn't get the
structure to close," Berge said, "and we couldn't account for the
gas trapping with a simple structural model. We realized there had
to be a stratigraphic component to the field and argued for 3-D
to image that.
"The upside is that a structural closure would have
to have been limited areally and the field size would be small,"
he said. "We now think the stratigraphic accumulation is regional
in nature and much larger than we originally might have suspected."
Indeed, while Berge refrained from designating an
estimated ultimate recovery from the field, he pegged the estimated
regional resource at 10-20 Tcf.
Thus far, Forest has drilled four wells at a depth
of 3,400 meters, or about 11,000 feet, with one dry hole and three
commercial gas discoveries. The A-Y1 well was the largest gas test
in south African history, testing 70 MMcfgd and almost 2,000 barrels
of condensate, Berge said.
"LithSeis was the primary data volume on which the
drilling campaign was based," said AAPG member Jeff Aldrich, chief
geologist at Forest. "It let us have a much higher confidence in
what we were drilling and the visualization of the reservoir."
He said that quantifying the reserves is quite complicated
because of the complex geometry of the reservoirs. There are numerous
compartments that in themselves are winding, meandering fluvial
channel systems.
"To map the reservoir effectively, we needed some
sort of inversion that would intervalize the reservoir," Berge noted.
"In a regular seismic volume, you get the reflection off the top
and off the bottom. What we needed to do was to look at an event
that corresponded to the reservoir itself and not a reflection from
top and base, and we needed to invert the data to do that.
"This tool makes P-wave and S-wave inversion and
cross-plots the two traces, and it uses gathered data, which isn't
used in simple recursive-type inversion," he continued. "It doesn't
require -- although it benefits from -- well calibration, so it
can be used in the early phase of exploration where there's not
a lot of well control."
Aldrich said they estimate that using the combination
of 3-D and LithSeis in the evaluation resulted in an increased chance
of success rate of 67 percent in the drilling program.
"We made 10 reservoir predictions in the course of
the program," Aldrich said. "All 10 found reservoir, and eight found
commercial gas reservoir."
Berge mentioned that other inversion approaches they
took required a lot of well control for calibration, but they are
using some of these to predict water rather than gas.
"Even though we have an 80 percent success rate for
gas content prediction," he said, "we're trying to solve the other
20 percent of the problem."
There will be plenty of opportunities for problem
solving. Forest intends to add to its existing 312 kilometers of
3-D data when it kicks off a new 3-D program in December that will
encompass 2,000 square kilometers of 3-D acquisition.
"We think we've just hit the edge of the play," Berge
said, "and we plan 77 wells for full development."
Because there is no gas infrastructure in South Africa,
Forest is building the gas pipeline and the infrastructure, while
proceeding to develop the components of the field. Production is
expected to commence in 2004.
The whole program including the infrastructure could
ultimately be a $2 billion investment, anticipated to come from
multiple sources, according to Berge. He predicts it will have a
huge economic impact on the whole western Cape province.
Trap Play
The sensitivity of the LithSeis technique to gas --
even 10 percent gas in oil or water will show up as gas -- isn't
deterring Larry Baria, president of Jura-Search, who's using the
tool in north Louisiana and south Arkansas, where he's wildcatting
for oil potential in the Smackover.
"We're probably pushing the limits of the tool trying
to find oil," he said, "but we ran test lines through existing fields
and the porous productive wells stood out against the porous wet
ones. We're boldly going to drill a LithSeis anomaly shortly.
"We've also used the technique 'after the fact' following
our discovery well at Mariner Field in Hancock County," Baria added.
"There, we're looking at lower Miocene Amphistegina sands with 34
percent porosity and as much as 95 percent gas saturation, so it
really lends itself to hydrocarbon indicator processing."
Baria said he plans to drill three development wells
in the field during the next five months based on the technique.
He cautioned that it's advisable to have a good seismic product
to put into the processing tool upfront. And he noted there appears
to be a lower porosity cutoff limit.
"It's mainly effective for high porosity, stratigraphic
traps," he said. "While it's not a panacea, it does seem to have
a balance of throwing AVO, absorption, inversion and several other
things into the pot in the proper ingredients to come out with something
that so far seems to work.
"I'm hoping that four months from now we'll be so
elated," Baria said, "that we'll be revving up to use this technology
in any number of basins."