In the exploration and development business
scientists are after two things — the maximum amount of data
to mitigate risk, and the most efficient and economic operations
Unfortunately, those two goals are not always compatible.
Fortunately, new technological advances are getting
better at reconciling these problems.
That's certainly true for borehole imaging —
particularly microresistivity images, which in recent years have
become important, efficient, cost-effective tools providing vital
data in subsurface geological investigations.
But there's a drawback of conventional microresistivity
tools: They can have problems in oil-base muds, and oil-base and
synthetic-base drilling muds have become increasingly popular because
they provide increased drilling efficiency and improved borehole
Consequently, microresistivity images must be abandoned
in wells drilled with oil-base muds or the mud must be changed,
which is expensive and inconvenient — and too often the lack
of these images means the loss of critical information.
The search for solutions continues, however, including
development of the Oil-Base Micro Imager tool (OBMI). The new tool,
offered commercially for the first time this spring after about
a year of field testing, is already proving its worth, according
to Bingjian Li, a senior geologist with Schlumberger Oil Field Services
Li, along with co-authors. — M. Marshall and
P. Goetz from El Paso Oil and Gas Canada, J. Deering and N. Begin
from Talisman Energy, P. Cheung and A. Etchecopar from Schlumberger,
have written a paper outlining the new tool describing the technology
and its geological applications in the structurally complex Canadian
"Integrating seismic data with borehole images
offers the best solution to structural problems," Li said. "Today
we can offer that combined data, even in oil-base mud environments."
In the past companies tried various methods to
provide the same information available from microresistivity borehole
images, including full-bore cores, ultrasonic images and/or oil-base
mud dipmeters. Each option, Li said, had limitations both in cost
Previously, the most common source of dip information
in synthetic or oil-base mud filled boreholes came from oil-base
dipmeter tools. However, a dipmeter with its small number of sensors
can only measure dips in simple geological settings. Stratigraphic
details, i.e. cross bedding, or fracturs are often difficult to
Li said the OBMI tool can solve these issues.
"It operates in all typical oil-base muds from
diesel to synthetic," Li said.
Its four pads provide a total of 20 resistivity
measurements with an effective button size of 0.4 inch, giving coverage
of 32 percent in an eight-inch borehole, he said. It provides images
for formation resistivities ranging from below 0.2, such as those
seen in extremely conductive water sands in the Gulf of Mexico,
to over 10,000 _m, like the highly resistive carbonates in Canada.
"Calibrated high-resolution resistivities also
are provided," he said, "which represent a first in the oil-base
According to Schlumberger, the OBMI tool provides
details for stratigraphic analysis. Large- to medium-scale sedimentary
structures can be potentially identified on OBMI images, which offers
useful information for depositional environment characterization.
"The tool's ability to provide the interpreter
with the detail required to fully describe small features on or
near the borehole wall depends on the size of the object," Li said.
The tool sees fractures and allows their orientation,
dip angle and density to be determined — but because the measurement
is taken in non-conductive muds, differentiating open fractures
from healed fractures, or those filed with resistive minerals, is
difficult for interpreters, since both appear as highly resistive.
Li said the OBMI tool has proven valuable in a
number of settings, including deep-water logging operations in the
Gulf of Mexico and offshore West Africa and structurally complex
Canadian Foothills, where the vast majority of wells are drilled
using synthetic-base muds.
"One of the major applications of the OBMI tool
in the Gulf of Mexico deepwater is to characterize the thinly bedded
reservoirs and refine the net pay count." Li said. "An operator
ran the OBMI images in a partially cored appraisal well and the
OBMI images accurately reproduced the cored interval to fully locate
those thin beds. In addition, through using the OBMI data in the
uncored interval in the well, the net pay count was increased by
more than 50 ft from that determined by conventional log analysis."
The foothills of the Canadian Rocky Mountains —
a classic example of a thin-skinned fold-thrust belt — have
been another proving ground for the OBMI technology.
Two case studies using the OBMI tool are centered
in the northern portion of the Alberta sector of the foothills.
"A regionally significant detachment in the Shunda
formation carries Turner Valley dolomite reservoir into thrust related
structural traps. The thrusts carrying the Turner Valley continue
upwards through the Jurassic and Lower Cretaceous frequently soling
out in the Upper Cretaceous Blackstone Formation. The tectonic movement
causes intense folding and imbrication in the Jurassic and Cretaceous
sediments complicating interpretation." Li said.
Two-D and 3-D seismic data have been used for subsurface
structural determination in this area for decades, but defining
the deep structures precisely with only seismic data due is challenging
due to the highly deformed strata, he said. The clearest picture
of the subsurface is obtained when seismic data is reinforced with
in-situ dip measurements from the borehole images.
In one study, Talisman Energy recently drilled
a well in the Canadian Foothills to locate a linear northwest-southeast
trending structure in the subsurface indicated by surface seismic
Three sections were planned for the well —
a vertical section with a build at the base, an angled pilot hole
and a horizontal leg within the reservoir.
In the vertical section, the operator had to use
oil-base mud for borehole stability and decided to use OBMI images
for structural information.
In the angled pilot hole, water base mud was to
be used as they did always in the previous wells in this area. However,
if the OBMI shows surprising dips particularly in the last few hundreds
meters of the vertical section, they may have to do some tricky
re-designing of the well bore. In the pilot hole to be drilled in
WBM, the conventional Formation Microresistivity Imager (FMI) log
was to be used.
The horizontal section was to be drilled along
the structural strike to maximize penetration of the reservoir and,
"The horizontal leg design was to be based on the
integration of structural data from borehole images and seismic
data, so the structural information from the lower part of the vertical
section OBMI as well as the pilot hole FMI was very important."
The vertical leg of the well was drilled to 3,888
meters and OBMI data analysis for the upper part indicated that
the dips are relatively high angle (10 to 40 degrees) and dipping
predominantly to the southwest. The structural strike is northwest
to southeast, which is close to what was estimated from the seismic
An obvious structural domain change was detected
at 3,385 meters in the OBMI images; most dips at this interval are
low angle (five to 15 degrees), dipping toward the west. Structural
analysis shows the strike of the structure below 3,385 meters orients
north-south. This was not evident on seismic.
Following the plan, Talisman changed to water-base
mud and logged the FMI in the pilot hole to confirm the north-south
structural trend. The FMI logged the interval from 3,884 to 4,090
meters, and about four meters of overlap between the OBMI and FMI
logs allowed direct comparison of both images in the same interval.
The FMI logs confirmed the structural trend of the lower structure
observed in the OBMI.
"The regional structural trend was understood from
the surface seismic," Li said. "The local variation of the structures
around the wellbore has been precisely defined from the OBMI and
FMI borehole image data. The two data sets, one with good lateral
coverage and the other with excellent vertical resolution, are complementary,
allowing Talisman's geologists to acquire a more accurate picture
of the structure at the reservoir level."
The second study concerns a well drilled by El
Paso Oil & Gas Canada Inc. in conjunction with Suncor Energy,
targeting the Turner Valley Formation carbonates in the northern
Alberta foothills. There are two major challenges to determine subsurface
structures in this area using seismic data alone. First, it is difficult
to position the structures precisely due to the anisotropy effect
on seismic data. Second, imaging the highly deformed beds can be
a difficult task. Therefore, it is important to acquire reliable
and accurate in-situ dip measurements from borehole images.
To improve borehole stability and drilling speed, El Paso et al
decided to drill the vertical hole to the reservoir level using
oil base mud and log with OBMI to tie-in their seismic data structurally.
If the well was found to be well-positioned, a horizontal extension
would be drilled through the reservoir to maximize production. Otherwise,
a sidetrack would be needed to reposition the well to a more favorable
location and the horizontal well drilled from there. After the OBMI
data from the main hole was acquired and analyzed, El Paso understood
that the well was not well-positioned structurally. A sidetrack
based on the OBMI data as well as re-interpreted 3-D seismic images
after correcting anisotropy effect directed successfully the well
into the favorable location — near the crest of the structure.
In the subsequent horizontal drilling, over 650 m of Turner Valley
Formation carbonate reservoir with well-developed natural fracture
network was penetrated. The well has been tested with excellent
daily production rates.
El Paso Oil and Gas Canada Inc., Suncor Energy
are acknowledged for the release of the well data and Veritas DGC
Inc. Company for allowing the publication of the 3D seismic data.
Talisman Energy is acknowledged for the release of the well data.
The authors would thank following people within Schlumberger for
their support to this project: D. Largeau, G. Mathieu , R. Laronga,
P. Montaggioni, O. Faivre, P. Vessereau, M. Garber, M. Lamb, J.
Kovacs, A. Kusama, H. Lindsay, L. Silinsky-Kephart.