Geophysics Optimize Performance Of Tight Oil Resource Plays

JANUARY 2013
The “Better Business” Publication Serving the Exploration / Drilling / Production Industry
Geophysics Optimize Performance
Of Tight Oil Resource Plays
By Glenn Winters
MIDLAND, TX.–Fasken Oil and Ranch Ltd. has been involved in the
petroleum industry since the 1940s, when oil was discovered on the
sprawling West Texas C Ranch purchased by David Fasken in 1913.
Despite decades of drilling and production activity on the 200,000plus-acre ranch, unconventional resource plays have completely
changed Fasken Oil and Ranch’s development strategy, shifting the focus from conventional carbonate and sand reservoirs to thousands of
drilling targets in low-permeability formations such as the Spraberry,
Wolfcamp, and Pennsylvanian (Cline) Shale. In addition to the
West Texas plays, the company also owns large acreage blocks in the
Eagle Ford Shale in South Texas and the Bone Spring horizontal
resource play in New Mexico.
These plays are transforming the industry’s understanding of North
America’s resource potential and are sparking high levels of activity
in even the most established basins. But resource plays also introduce
challenges that were not present in developing conventional reservoir
systems.
Reproduced for SeisWare International with permission from The American Oil & Gas Reporter
www.aogr.com
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Consequently, unconventional plays are driving evolutionary technological advances necessary to develop the resource
base economically, particularly with respect to drilling and
completing wells. Geophysics has a critical role to play in optimizing production performance by well placement, especially in tight oil reservoirs.
Fasken Oil and Ranch is using various geophysical techniques to look at key factors in each of its three play areas. In
the Eagle Ford, 3-D seismic is used primarily as a structural
guide in areas with limited well control to keep horizontal laterals extending one to two miles within their target zones. However, we also are analyzing prestack data sets and seismic inversions, and from these data, we see important variations and
sweet spots within the reservoir.
An example of the benefits of utilizing prestack data volumes and seismic inversions occurred in the Eagle Ford, where
fracture networks created and rejuvenated during the fracturing of a horizontal well propagated through natural fracture
systems to affect a vertical well that was being drilled one mile
away. That was surprising, considering the ultralow permeability of the rock.
The data resulted in a revision of the drilling, completion,
and line of communication between the two operators involved
in these wells so that a similar circumstance would be unlikely
to occur again.
In many cases, horizontal Eagle Ford wells are being drilled
on spacing of 500-800 feet or less. If natural fracture systems
are present, seismic data show that frac treatments may preferentially follow the natural fracture system, conveying the network created from one horizontal well into the rock surrounding well bores as distant as one to two miles. This, conceivably,
One of the lessons learned from analyzing seismic data in the
Wolfberry play is that the geology can change quickly, and intervals present in the stratigraphy of one well can be absent in
the next well. This image compares wells 709 and 710, which
are located only 550 feet apart. The seismic lines are the conventional bandwidth extension in the upper section and seismic inversion in the lower section. The arrows mark the interpreted zone. Contrasted to the conventional data, the inversion
shows a pod of low-velocity material.
This cross-section shows the Strawn formation coming in 60
feet lower in Well 710 than in Well 709. The seismic also identifies the lower-velocity material and matches the well data.
could create complex communication and production interference issues between horizontal wells.
Wolfberry Play
Fasken has acquired 3-D seismic data over the entire ranch
in the Permian Basin, and last year completed a major initiative to reprocess all those data. We break data into volume types,
including “conventional” 3-D seismic, 3-D inversion volumes,
and 3-D depth volumes created from post-stack time migration, using a hybrid technique that incorporates stacking velocities that ultimately provide an accurate map of converted
depths. In addition to prestack inversion and depth imaging,
we are experimenting with a number of other techniques to see
what ultimately could prove valuable.
As in the Eagle Ford, the primary application for seismic in
the West Texas Wolfberry play is mapping structure for several
formations. One of the important lessons learned from our experience analyzing seismic data in the Wolfberry is that carbonate deposition present at one well location can be entirely
absent at the next location some 600 feet away.
Even though the Wolfberry is a resource play where the development model is to drill vertical wells at tight spacing and
fracture 10 or more intervals, our seismic data illustrate these
intervals come and go in the subsurface cross-section underlying Fasken’s development area. Two wells may be spaced only
660 feet apart, but intervals present in the stratigraphy of one
well could be missing in the other. The point is, these are not
“blanket” formations that are deposited continuously everywhere across a portion of the basin, let alone an entire section.
Currently, the Wolfberry remains mostly a vertical play in
which 8-12 zones are completed per well. The development
strategy for many operators is to repeat the same drilling and
completion design in every well. So if a vertical Wolfberry well
encounters a carbonate interval in one well, the same depth is
typically perforated and fractured in all subsequent wells.
Operators are always looking for ways to cut costs during
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One area with significant potential for innovation is integrating
surface seismic and microseismic data. Bringing microseismic
data acquired during frac treatments into the 3-D seismic data
model can help identify potential geohazards and eliminate prob-
well completions. A questionable method is one that attempts
to reduce the number of perforations by leaving out some intervals in a well, and by fracturing that interval in the next well,
hoping that stimulation will be accomplished in both treated
and untreated wells for the zone.
However, detailed analysis of 3-D seismic inversion data
clearly shows discontinuities within formations throughout the
Spraberry and Wolfcamp. These variations make a “cookie cutter” approach with a single completion design ineffective because it will end in treating intervals that are missing in some
locations, and can overlook highly productive zones present in
other wells.
For example, Fasken has identified areas where there are
conventional carbonate buildups within the Spraberry and Wolfberry, missed targets of earlier drilling in the 1980-90s. As we
move to new areas on the ranch to extend the play, we seek
these targets for optimally placing the first wells where the likelihood of good reservoir is present.
For the sake of argument, if our drilling pattern dictates
drilling 20 vertical wells in a section, we try to place the first
10 locations where the seismic suggests the best part of the
reservoir exists. The goal is to drill the best wells first to maximize the return on investment. We seek to high-grade well locations by using seismic to find areas with traditional carbonate porosity reservoirs as well as exclude locations with tight
zones that are dispersed throughout the Wolfberry play.
Several Wolfberry operators active in leases surrounding
Fasken’s West Texas acreage are attempting to experiment
with horizontal drilling. We at Fasken believe the Wolfberry
play eventually will become a multilevel horizontal play, similar to the Bone Spring 1-3 formations of New Mexico and
the Delaware Basin that are age equivalent to the Spraberry
and Dean formations. Horizontal activity on lands near our
ranch includes four wells drilled in the Mississippian, one in
the Penn Cline, 13 in the Wolfcamp and four in the Basal San
Andres.
lems. These images illustrate how the presence of a thief zone
that was initially undetected in the Strawn formation impacted
the stimulation results in one stage of the frac treatment.
The potential of multiple intervals has partially influenced
our vertical drilling patterns. For instance, we may want to drill
vertical wells aligned in three rows across a section, and then
come back and drill horizontal wells between the rows, again
using seismic analysis to find the intervals that are more continuous with better porosity.
Unlike vertical Wolfberry wells, horizontal wells target one
primary zone within the Wolfcamp/Spraberry package. It is a
matter of development economics. If a vertical well with 10
stages produces 150-200 barrels a day, the average contribution from each stage would range from eight to 30 bbl/d.
Horizontal Targets
5,000’ Interval
To Choose From
BSA
BSA “Upper Leonard”
aka Avalon Shale
1SST_SPRABERRY
2ND_SPRABERRY
JoMill
JOMILL
DEAN_LIME
Wolfcamp
Multiple Targets
“A, B, C, D, Middle, etc”
Penn “Cline”
Atoka Lime
DEAN
WOLFCAMP
M_WC_MKR
LOWER_WOLFCAMP
BASAL_WOLFCAMP
PENN
STRAWN
ATOKA
ATOKA_LIME
UPPER_BARNETT
Moonlight
MOONLIGHT
LOWER_BARNETT
Lower Barnett
Current intervals tested
LOWER_MISS
Courtesy of Stonnie Pollock Fasken Oil and Ranch
Fasken believes the Wolfberry play eventually will become a
multilevel horizontal play, similar to the Bone Spring 1-3 formations of New Mexico and the Delaware Basin. Several Wolfberry
operators active in leases surrounding Fasken’s West Texas
acreage are experimenting with horizontal drilling. Horizontal
activity on nearby lands includes four wells drilled in the Mississippian, one in the Penn Cline, 13 in the Wolfcamp and four
in the Basal San Andres.
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If, instead, a horizontal well is targeting a single formation–perhaps a conventional carbonate or maybe a tight shale such as
the Cline, depending on local geology–that single zone has produced more than 700 bbl/d. Even though horizontal wells cost
more than vertical wells, the early completion results show that
the economics likely will support drilling a few single-zone
horizontals as opposed to a larger number of multiple-zone verticals.
It is foreseeable in the very near future that drilling could
consist of a dozen vertical wells followed by an additional
four horizontal wells in three reservoirs in one square-mile
section.
Data Integration
One area with significant potential for innovation is integrating surface seismic and microseismic data. Bringing microseismic data acquired during frac treatments into the 3-D
seismic data model can help identify potential geohazards and
eliminate potential problems.
In one Wolfberry well, for example, microseismic data indicated the frac treatment had stayed within the target zone during the first stage, but in later stages the induced fractures propagated out of zone, moving 700-800 feet to the southwest, and
therefore did not stimulate the reservoirs as anticipated. When
we re-examined the high-frequency 3-D seismic data, faults
were evident in the upper intervals.
Instead of stimulating the perforated section of rock, the
treatment reactivated the faults, resulting in the frac stages moving out of zone. By examining the 3-D surface seismic volume
with the microseismic data, we were able to better understand
the subsurface and how faults could impact treatment effectiveness in the multistage frac intervals.
Fasken has traded microseismic survey data with other operators, and has had the opportunity to evaluate the different
types of microseismic products available. Some products do a
particularly good job of showing the fracture networks created. Mapping these networks on a reservoir scale is critical for
figuring out where to place new wells and how to fracture them,
and that leads to another question: When drilling horizontally
and the seismic data indicate areas along the lateral well path
with poor or absent porosity, should those areas be fractured?
The industry’s approach has been to perforate and frac at
regular intervals of, say, every 200 or 300 feet from the toe to
the heel in the lateral. But if the seismic indicates little porosity in a section of the reservoir, and no gas increases were recorded in the mud log during drilling, does it make sense to frac
that stage?
It is very hard for a company not to perforate every 200 to
300 feet along the well path. But significant cost savings are
achievable if one could avoid fracturing 1,000 or more feet of
unproductive section in a 5,000-foot lateral, where perhaps the
well veered out of zone because of structural changes caused
by dip change or faulting, or possibly reservoir porosity was
temporarily lost because of a facies change. A huge piece of
the puzzle that has not yet fallen completely into place is having the confidence in the geophysical model to make these kinds
of engineering determinations, especially if the decision is to
not fracture. That leads to the historical pessimism by engi-
neers toward geophysics’ creditability in predicting what is
ahead of the drill bit.
Building Credibility
Geophysics utilizes second-order seismic data combined
with first-order geologic well data that often results in an answer that is typically not in the order of magnitude that engineers commonly deal with. I often hear my peers challenged
on ways to encourage management and engineers to incorporate geophysics in tight oil plays that helps provide significant
and credible results to a company’s drilling program, and ultimately, its bottom line.
The geophysicist analyzes thousands of seismic traces across
several square miles on a macro scale over hundreds and thousands of feet horizontally and tens of feet vertically. And, of
course, as we will discuss shortly, these samples or traces are
spaced anywhere from 40 to 150 feet apart. The engineer is
looking at the reservoir on more of a micro scale of inches or
up to several feet. It is the geophysicists’ responsibility to
demonstrate to engineers (who usually control the purse strings)
how seismic can create value in drilling and completion decision-making processes.
One of the fundamental questions is how accurate the seismic needs to be. Geophysics, historically, were an exploration
tool, but over the years have helped in development, and finally, tertiary field development. Where the initial exploratory
wells were drilled one per section, the margin for error might
be 20, 40 or 60 feet or more in subsurface determination of a
formation.
In the Wolfberry play, where Fasken is drilling vertical wells
660 feet apart on 20- to 40-acre spacing, that margin for error
becomes very small. We have observed stretching of wireline
cables that demonstrates up to 20 feet of variance for a cased
well log, compared with an open-hole log. When most of the
wells are logged as cased hole, this can lead to problems for
the geophysicist who is converting to depth using formations
tops determined by faulty logging tools.
To optimize performance long term and to recover more than
the typical 10-15 percent of the reserves in a reservoir, operators
are going to have to rely on seismic to provide big-picture perspectives and delineate differences across large areas before ultimately creating finer-scale reservoir models. Rather than drilling
every section the same, geophysics can help delineate critical
reservoir differences to optimize drilling and completion design,
and ultimately, improve bottom-line performance.
In West Texas, Fasken is analyzing more than 500 square
miles of 3-D data across the ranch to high-grade areas in the
Wolfberry play and provide structure maps so geologists and
engineers can determine the best completion designs during
predrill planning. One example is using regional-scale seismic
to accurately predict the depths at which drillers can expect to
encounter different formations.
Another application is identifying anomalies in the seismic
data that can indicate drilling hazards. Most of the wells in
Fasken’s drilling program employ mud loggers from the San Andres through the Atoka intervals, depths from 5,500 to 11,500
feet. If an anomaly is observed in the seismic data in a shallow-
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er interval such as the Yates or Graysburg/San Andres, a mud logger can be put on the well earlier to deal with any uncertainties.
Seismic Inversions
Seismic inversions are a critical technology at Fasken Oil
and Ranch. I believe post-stack inversions should become an
everyday routine (if not already in your shop) for most projects. Inversion allows the different disciplines to speak more
closely in a common language. When the geophysicist discusses an amplitude that is higher in one section than another section, the amplitude meaning is difficult to ascertain. But when
showing an inversion that has values related to rock properties
of velocity and porosity, everyone is on the same page. Fasken
is experimenting with shear-wave data derived from sonic logs
and bandwidth-extended prestack seismic inversions.
As part of prestack inversion processing, we are working with
Geotrace Technologies Inc. to calculate elastic modulus and Poisson’s ratio from sonic logs, in addition to the compressional-wave
information in the 3-D seismic volume. With a combination of
attributes, it becomes possible to obtain information about frac
gradients that engineers can use to design completions, especially for the first wells in a new area. The frac gradient in one formation may be 0.56 over part of the ranch and 0.70 at another
place, which is a difference to the completions engineer.
The interpreter’s goal in a resource play today is to get information on reservoir properties; not simply interpreting peaks,
troughs and amplitudes on conventional seismic data, but determining and then relating Elastic modulus, Poisson’s ratio, and
other relevant engineering measurements, from seismic and well
log data to drilling locales. Utilizing actual P- and S-wave data
measurements, when available, could help to better determine
rock properties. Fasken realizes the importance of collecting as
much data as early as possible in these resource plays, especially open-hole logs. Fasken also is participating in several core
consortiums, which is another source of rock property data.
That said, it is too early to know how significant a role 3-D
seismic shear data can play in drilling vertical or horizontal
wells in the Wolfberry. I am not sure shear can provide much
benefit for the additional costs when wells are drilled 660 feet
apart. However, as the Wolfberry becomes a multilevel horizontal play, adding S-wave data to the P-wave data could yield
additional benefits that we have yet to factor in.
Seismic surveys Fasken has collected generally are designed
to record high-fidelity, high-frequency data with extended bandwidths, and higher fold and smaller bin sizes. We are in the process
of acquiring a portion of a survey in the Bone Spring play in
New Mexico that was acquired with very wide azimuths, high
fold, and much closer bin spacing than anything Fasken has been
involved with in the past in this area. One survey that I am familiar with in the play had a very high channel count, and the receiver spread, when activated, covered more than 20 square miles.
The goal of these large, high-channel count surveys is to get long
offsets, finer spatial sampling, and higher fold in deeper formations. One of our data sets in the Eagle Ford has 60-foot bin spacing and is more than 60 fold at the target interval.
Another volume data set we are experimenting with is rangelimited stacks. A common depth point bin in a 3-D seismic data
survey that was collected prior to the last five years typically
would contain offset ranges from 200 to 14,000 feet because
of equipment limitations, resulting in data that would have 40
fold at a target depth of 10,000 feet. With today’s seismic crews
possessing higher channel equipment, data collected results in
much higher-fold data, such as100 fold at14,000 feet not being
uncommon, with 60 fold at 7,000 feet and greater azimuthal
range distribution.
Other Technologies
Other interpretation techniques that Fasken routinely incorporates in its unconventional plays is semblance, maximum curvature, and spectral decomposition calculations, to name a few.
Maximum curvature is an important tool in the Eagle Ford,
since it is used to highlight possible fracture swarms, and in the
Permian Basin plays to incorporate frac stage results for specific intervals. We use spectral decomposition to help highlight
sweet spots.
With respect to software, geological and geophysical platforms are changing drastically, and independents no longer have
to invest huge sums of money to get advanced software capabilities or do without the tools of the big boys. Fasken is using
SeisWare™ geophysical interpretation software, which is a relatively low-cost package that possess sophisticated wavelet
analysis capabilities, visualization, the ability to interpret data
depth or time, and easy data loading both of seismic data and
integration of well data from several packages, such as Petra™.
The next step is figuring out how geophysicists can better
use microseismic data by integrating those data sets into seismic interpretation platforms.
Some of the other technologies the company has experimented with include:
• Wireless 3-D acquisition;
• 3-D spectral decompositioning;
• Quantum resonance interferometry and voxel analysis to
predict permeability, porosity, and the presence of hydrocarbons from 3-D data;
• Reverse-time migrated processing; and
• Permanently embedded microseismic monitoring arrays.
Fasken deployed wireless sensors in a microseismic survey
in the Eagle Ford, laying the survey in an elliptical area covering 30,000 square feet. There is a huge benefit in being able to
tell landowners that we are going to install small sensors without cables, using four-wheelers or simply walking in and leaving phones for 10 days before picking them up in the same way.
The only concern with wireless geophones for a 3-D seismic survey is that it is difficult to sweep test and perform other
parameter testing, and receive the data instantaneously, although
the technology is advancing. I am sure data collecting problems
will be solved. In addition, wireless sensors can be left in place
for long periods (weeks to a month) to record data before phones
need to be collected and recharged.
I am a big fan of spectral decomposition, where I have used
it successfully to highlight conventional reservoirs in carbonates and also in the Spraberry trend to isolate channel sands,
and to identify sweet spots in the Lower Eagle Ford.
Fasken worked with ViaLogy a couple years ago to test its
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quantum resonance interferometry technology and analyze 3D multicomponent seismic data to locate Strawn targets in a
10-square-mile block of our ranch in the Permian Basin. Strawn
Limestone porosities typically are very low, and the technology had some success detecting continuous zones of higher porosity from seismic data. The first well completed using this technology has been one of our best Strawn producers in the area,
but we have a lot more testing to do before we have complete
confidence in this technique.
When this field test was conducted, Fasken was not yet
drilling in the Wolfberry. Everything changed when the Wolfberry play took off, and because the technology focuses on
porosity, its application is geared toward conventional reservoir settings. However, we are going back into that same acreage
to drill through the Wolfberry and test the Strawn formation in
each well, so we will be able to verify how well quantum resonance interferometry identifies reservoir rock.
We also are very interested to see whether this technology
will be able to help identify and high-grade deeper stratigraphic units, such as the Mississippian. Mississippian conventional
reservoirs in the basin have recovered more than 350,000 barrels from a single vertical well at 11,500 feet, and companies
are looking at this formation as an equivalent to the Bakken as
a horizontal target. In fact, one company in the basin has successfully drilled horizontally in this unit and is quite happy with
the production stream.
Microseismic Monitoring
There are several sophisticated software packages for microseismic, but small companies may not conduct enough microseismic surveys to warrant investing in high-end software
packages. How can little guys access state-of-the-art microseismic software? I would like to see the industry get these packages out to smaller companies that may do only a couple microseismic surveys each year, or at least provide a reasonably
The interpreter’s goal in resource plays is to get information on
reservoir properties; not simply interpreting peaks, troughs and
amplitudes on conventional seismic data, but relating Elastic
modulus, Poisson’s ratio, and other relevant engineering meas-
priced service.
I believe time-lapse microseismic monitoring is a very good
idea. Fasken laid a permanently embedded array consisting of
cemented geophones buried 200 feet in the ground over 16
square miles in the Wolfberry play. That way, anytime we completed wells in the area, we would be able to monitor them and
be prepared to monitor horizontal completions in other formations (such as the Cline and Strawn) in the future, allowing us
to see how those formations fractured differently.
Unfortunately, we did not collect usable data from the buried
phones. However, this is another technology that is advancing
rapidly. Companies are placing an increasing number of advanced phones in the well bore at different intervals, demonstrating the significant potential of time-lapse microseismic
monitoring.
Time-lapse monitoring also may have a particular application when production declines and refracturing is required. Tight
oil zones will need to be refractured at some point, and that
makes it all the more imperative to know where frac fluids exited the reservoir rock the first time. To effectively refracture
and enhance the stimulated reservoir volume, we must understand the frac system created in the initial treatment. It will not
do much good to refrac a 10-stage Wolfberry vertical well or a
22-stage Eagle Ford horizontal well if half the stages are out of
zone. Knowing the results of the initial treatment is critical to
designing a refracture program.
Of course, refracs are one aspect of solving the long-term
challenge of improving production and recovery rates in tight
oil plays. At the end of the day, optimizing recovery boils down
to knowing our reservoirs. It is no different from conventional
plays. As an industry, we need to do more reservoir modeling
and collect the information necessary to build accurate models
to find out how much oil has been recovered and how much
reservoir volume is left to stimulate.
To accomplish these objectives, geologists, geophysicists
urements from seismic and well log data to drilling locales. These
images illustrate the differences between an amplitude map and
a Poisson’s map in the Eagle Ford Shale play.
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and engineers must work together. Geophysicists have to communicate with engineers in a language they understand. I can
talk to an engineer all day about a root mean square amplitude,
and it probably will mean nothing to him. However, if I was to
tell him the average velocity was 13,000 feet per second in one
place and 16,000 feet per second in another, he could understand the concept of fast versus slow rock, and appreciate what
it meant to the drilling and completion design.
It is clear that all rock is not the same in resource plays. Critical parameters can change from one drill site to another. Should
a well be drilled at a given location simply because it adheres
to a specified drilling pattern, or should that capital be allocated to locations where seismic data indicate more favorable reservoir properties?
Does it may make more economic sense to target a conventional carbonate reservoir with a horizontal well, or complete
multiple tight zones in a vertical well? Should all wells complete the same intervals, or can we be selective in determining
where to place frac stages?
The next step forward for geophysics is to help guide these
kinds of critical decisions by applying advanced seismic technologies.
❒
GLENN
WINTERS
Glenn Winters is the chief geophysicist at Fasken Oil and Ranch Ltd. in Midland, Tx. He began his career in 1981, working as a staff geophysicist for Texaco in the Permian Basin. In 1985,
he transferred to Texaco’s Denver office, working in special projects and seismic data processing. Winters returned to the company’s Midland office in 1989, where he interpreted seismic data
throughout the Permian Basin. He joined Fasken Oil and Ranch in 2002 as a staff geophysicist.
Winters continues to focus on acquiring, processing and interpreting seismic data in the Permian Basin as well as the Eagle Ford Shale play in South Texas. He is a former president of the Permian Basin Geophysical Society. Winters has worked on several projects with Bob Hardage and
the Bureau of Economic Geology at the University of Texas over the past several years, including collecting mode-converted seismic data on Fasken-owned and operated properties. He has
been instrumental in helping companies test new technologies in a known test area on Fasken’s
ranch. Some of the technologies Winters has helped introduce in Fasken’s operations are ViaLogy’s
QuantumRD® quantum resonance interferometry software, Wave Imaging Technology’s prestack
depth migration algorithms, and Gore Industries’ surface geochemical technology. He holds a B.S.
in engineering geology from Purdue University.