Larry Britt – DLOnline 14 November - Questions/Answers
Iman Oraki Kohshour
How can we manage unpropped fracture conductivity?
You can't manage un-propped conductivity! Either you have it or you
do not. If you have some un-propped conductivity and knowing the
reservoir permeability you can then manage the un-propped fracture
height by controlling the proppant volume to ensure that you have a
vertical Dimensionless Fracture Capacity, FCD-vert, greater than 2 so
as not to lose rate and reserves.
Iman Oraki Kohshour
Could you elaborate more on Slide #24?
Water-frac's are inappropriate for conventional reservoirs because
the reservoir permeability is too high to manage the un-propped
fracture height and maintain an FCD-vert of at least 2. Put
differently, a fracture stimulation in a conventional reservoir
requires more fracture conductivity than can be achieved with
treated water and low proppant concentrations. Further, in
permeable reservoirs, leak-off to the formation is somewhat
controlled by the fracturing fluid. As a result, the use of un-gelled
water as a fracturing fluid in a conventional reservoir will result in
excessive fluid loss.
Iman Oraki Kohshour
Why water frac is inappropriate in conventional reservoirs?
Raki Sahai
what is the source of the equivalent FCD equation? Tulsa Thesis?
The source of the equivalent FCD Equation is Curtis Bennett's 1982
PhD thesis from the University of Tulsa entitled "Analysis of
Fractured Wells"
Matthew hekimian
the treating rate looks low for treated water
The fracturing fluid (in this case treated water) serves several
purposes. First, in the pad the fluid is used to (1) initiate and
propagate the fracture, (2) generate sufficient fracture width, and (3)
to act as sacrificial fluid for leak-off. In the slurry stage it is used to
transport the proppant and finally to displace the slurry to the
perforations. Pump rate positively effects the generation of
sufficient fracture width, leak-off, and proppant transport. Pumping
a water frac with too low a pump rate can result in proppant
bridging and a screen-out while pumping at too high a pump rate can
generate excessive fracture width requiring additional proppant to
manage the un-propped fracture height. Fracture modeling would
indicate and my experience supports that the optimum pump rate
for typical reservoirs (Young's Modulus in the 3 to 6 x 106 psi) is on
the order of 25 to 60 BPM. Recent work by Sanchez-Nagel suggests
that high pump rates do not affect the shear to tensile ratio and
therefore, isn't warranted if generating complexity or stimulated
reservoir volume is the goal. Pump rate just acts as a bigger and
more expensive hammer increasing horsepower and proppant
requirements while improving transport and operational efficiency.
Zeno Philip
Have you published this work in a paper? Can you provide paper
numbers? Thanks
This work has been presented as part of the 2007-2008 Distinguished
Lecture Program and was based on a paper SPE 10227. Britt, L. K.,
Smith, M. B., Haddad, Z., Lawrence, P., Chipperfield, S., and Helman,
T.:”Water-fracs: We Do Need Proppant Afterall,” paper SPE 102227
prepared for presentation at the 2006 Annual Technical Conference
and Exhibition in San Antonio, TX, Sept. 24-27.
Iman Oraki Kohshour
Is your simulation study on unpropped fracture conductivity (I think
slide 22) published?
Slide 22 on un-propped conductivity published partly in SPE 102227
and in more detail in paper SPE 125525.
Britt, L.K., and Schoeffler, J.: “Geomechanics of a Shale Play: What
Makes a Shale Prospective,” paper SPE 125525 prepared for
presentation at the 2009 Eastern Regional Meeting held in
Charleston , West Virginia, Sept. 23-25.
J Isaac Diboue
Larry, in your conclusion do you mean that using the
"hydrid""method will definitely improve the productivity?
Hybrid fracturing fluids can be used in areas where we know little
about the geomechanics and the rocks. In these areas we may have
rocks that are too ductile to retain un-propped conductivity or have
in-situ stress contrasts which are too small to contain downward
height growth making it difficult to maintain un-propped fracture
height sufficient to achieve an FCD Vertical of 2. In these cases a
hybrid fluid system (treated water and linear gel for example) can
allow the design engineer the ability to place enough proppant to
manage the fracture conductivity as well as post fracture rate and
reserves.
Nestor Natareno
Is there any issues with pumping such low rates when it comes to
proppant transport? Was this based on a vertical well study?
Pumping at low pump rates does affect proppant transport and rate
and transport should always be considered in water-frac treatment
design. The work was originally developed for vertical well
applications but has been reviewed and tested for horizontal
applications. Fracture geometry in horizontal wells is similar to
vertical wells as it is still controlled by in-situ stress contrast, Young's
Modulus, and leak-off with additional considerations of stress
alignment and fracture competition.
Matthew hekimian
how valid is this for a liquid rich reservoir
Managing Un-propped conductivity is most important to gas and gas
condensate reservoirs. In oil reservoirs or in reservoirs producing oil
and water it is difficult to produce liquids through an un-propped
fracture at any realistic effective stress. In such reservoirs, the liquids
need some propped and conductive fracture to maximize or at least
optimize recovery.
Andy Sookprasong
From the graph (slide 29 or 30?), it appears that we have to keep FCD-vert has to be 2 or less ; if F-CD-vert of 2.5 then the initial rate is
less -- unpropped height is less than propped height (less than onehalf of total pay) - thank you
The FCD vertical must be greater than 2 to keep from losing rate and
reserves.
Matthew hekimian
how does Fcd of 2 relate in a horizontal well with 5 or 6 fractures per
stage
The use of FCD vertical of 2 is applicable in horizontal wells where
we have 5 or 6 fractures per stage. In this application the FCD
vertical of 2 applies to each fracture. If the FCD vertical is less than 2
for a given fracture then it will underperform.
Iman Oraki Kohshour
How much did the Kv/Kh ratios were varied in Slide#22?
Vertical to Horizontal permeability ratios were varied from 0 to
about 20%.
Iman Oraki Kohshour
How do we resolve the fluid loss issue with water frac?
The fluid loss issue isn't resolved with a water-frac. Leak-off is still an
important part of the development of fracture geometry. However,
treated water should only be used in low permeability reservoirs
where leak-off isn't the dominant consideration. In such reservoirs,
leak-off or fluid loss isn't controlled by the fracturing fluid it is more
controlled by the reservoir itself.
Yuxiang Liu
Is it possible to predict the unpropped fracture conductivity and
include it into the fracture design?
We conduct laboratory studies of un-propped conductivity and use
that data in our fracture designs. Based on our laboratory studies unpropped conductivities of 0.5 to 5 mdft are not unusual. Post
fracture production analysis has been used to support such unpropped conductivities . A paper by Mayerhoffer and Cipolla on the
Barnett Formation indicated un-propped conductivities of 2 mdft
were required to match post fracture well performance. This value is
similar to our post fracture evaluations.
Mian Ahmad
there are continues changes occuring in stimulation. Now operators
are switching from long stages to reduced cluster spacing (RCS), any
thoughts on it. Thx
Stimulation design does continually change, however, the
fundamental objectives should be the same. Per well reserves are
increased by longer horizontal wells and longer fractures. Increasing
the number of fractures can and does improve the initial rates but
may not increase the reserve recovery. For a few wells per section
the objective should be to maximize the fracture length. For six or
eight wells per section that objective may be altered due to well
density. After all, if you have five hundred feet between wells does
it matter whether your fracture half-length is 500 feet or 2,000 ft?
The general trend in the industry is to increase the stage length and
number of clusters per stage thereby, reducing the number of
stages. In this manner the completion costs can be managed. As an
industry we are good at managing costs. It remains to be seen if we
are managing our way out of rate and reserves.
David Norman
Fluid loss would be pressure dependent leakoff as the permeability
increases.. so where is you turnover point?
Fluid loss often results from pressure dependant leak-off in
unconventional resources. However, given the low reservoir
permeability and small net pressures due to the use of treated water
I do not see leak-off as a major driver of the induced fracture
geometry. The pressure dependant leak-off can result in greater
network complexity, however, in my opinion that is less important to
overall well performance than the multiple induced fractures. We
can dilate the fissures and increase complexity through treated
water injection but can we effectively produce hydrocarbons
through the fissures/complexity given the high near wellbore
stresses (Post Frac ISIP - Bottom Hole Flowing Pressure) acting to
close the them?
Adaqngo Miadonye
Considering the low cost associated with this process, how much
emphasis is place on water recovery if atal?
We need to consider water recovery from an environmental
standpoint. The more water we recover the more of it that can be
reused in subsequent stimulations and the less make up water that is
required. The use of water and water recovery isn't only a cost issue
it is one of good stewardship as well.
Nestor Natareno
With higher rates do you believe that you are creating more fissures
rather than frac extension? I have been trying to convince our
customers to perform seismic to adjust our frac designs but they
believe that they are creating more fissures but when we start
seeing offset wells experiencing pressure changes during the
stimulation it really supports my thoughts that the higher rate is not
creating more fissures but long defined fracture. Do you recommend
rates on the lower side (45-65 bpm) Juan Carlos Clarembaux Olivieri
How do you evaluate the production from each cluster?
The question of Do high pump rates create more fissures? is one
being asked quite often today. My opinion is that pump rate does
not have a major affect on natural fissure complexity . This opinion is
based on numerous post fracture evaluations and work by SanchezNagel showing that shear failure is not enhanced with pump rate.
Shear failure is enhanced with low viscosity fracturing fluids,
however. As a result, I would recommend that we manage pump
rate in the 40 to 60 BPM range to manage the water-frac design.
Higher pump rates increase fracture width and require more
proppant to manage the un-propped fracture height and are
therefore more expensive. Proppant transport does need to be
considered, however, as higher pump rates can transport the
proppant further resulting in longer induced fractures. That said,
there are limits to transport and therefore limits to pump rates!
Barry Chovanet
What method have you used to determine that 30% - 50% of your
perforations clusters were not productive? Production logs in
horizontal wells any good?
There are several studies out there that show that in specific
unconventional resources 30 to 50% of the perforations do not take
fluid and proppant. These studies used production logs and
radioactive tracers to determine the cluster effectiveness. Although I
am skeptical about the use of these diagnostics as they are near
wellbore investigative tools. These results are at least consistent
with some finite element work that we and others have done
investigating fracture interference effects. FEM shows that clusters
that are significantly closer than fracture height do not propagate
effectively where clusters with spacing in excess of one to two times
the fracture height do.
Feng Zhang
all the cases are from shale gas reservoirs, have u considered tight oil
gas like bakken formation, is there any difference?
There can be differences in oil reservoirs as I indicated before.
Liquids have difficulty flowing in un-propped fractures at effective
confining conditions.
Rick Stanley
Internationally we often find it hard to design / understand hybrid
fracs or even know when a hybrid frac is warranted. Can you point us
to some SPE papers or fracturing support info that can help with
this?
In permeable reservoirs (> 0.1 md) I do not see significant benefits in
using hybrid fracture designs. However, in low permeability
reservoirs a hybrid design can be used to maximize fracture length
and conductivity while allowing some shear dilation with treated
water. Two hybrid fracture papers I would reference I believe were
both done on the Bossier Formation. These are paper SPE 89876 by
Sharma and Sullivan and paper SPE 110451 by Handren adn Palisch.
Perry baycroft
Will the FCD vert =>2 work for tigh oil formations like the Mississippi
Lime, or should it be greater?
The FCD vertical in the Mississippi Lime Formation should be at least
2. However, achieving an FCD vertical of this magnitude may be
difficult as the reservoir permeability can be relatively high. The Miss
Lime is several hundred feet thick and any natural fissures would
have relatively low retained conductivity meaning that in a
permeable section of the reservoir it would be difficult to maintain
an fcd vertical of 2.
Robert Meij
How do you determine what unpropped KfW is ?
Un-propped conductivity can be measured in the laboratory with
core from the formation of interest. Contact me at lkbnsi@aol.com
or rocklaboratory.com for additional information.
Mustafa Al-Alwani
Why we flow wet Nitrogen instead of natural gas?
In our lab tests we use wet nitrogen rather than methane for safety
and data control issues. Wet nitrogen is similar in molecular size as
methane and is not as effected by temperature.
William Hoffman-Turner
Have you seen success with longitudinal fracturing using slickwater
fracturing fluids? What are some of the major challenges compared
to transverse fractures?
Longitudinal fractures (horizontal wellbore drilled in the direction of
the maximum horizontal stress) are generally more successful in
higher permeability applications. The lower the permeability, the
better the transverse horizontal well will be in comparison to a
longitudinal well. From a fracturing perspective, a longitudinal well
should be much easier to complete and stimulate than a transverse
well.
Rodrigo Vela
any book or additional material where I could find more information
about the topic
I teach an unconventional completion and stimulation course for
Petroskills and have a manual that I use for that that includes an
extensive discussion of the water-frac treatment design. In addition
to the papers I sited previously (SPE 102227 and 125525) I have also
written an article in the Journal of Natural Gas Science and
Engineering, Volume 8, September 2012 (pgs 34-51) entitled
"Fracture Stimulation Fundamentals."
Ron Auflick
frac water post stimulation retained (+/- 65% in the Marcellus case)
in the well, do you feel this retained water is a barrier limiting
ultimate production?
Is this 'barrier' an underestimated negative of stimulating with
water?
The final question is about whether water left behind following load
recovery inhibits well performance? My answer to that is no, I do not
think that water left in the fracture limits well productivity. Over the
years we have studied fracture fluid clean-up extensively and found
that polymer left in the fracture does limit productivity. However,
water left behind does not. In fact, we found that the better
correlation showed that the greater the load recovery the poorer the
well performance was and the poorer the load recovery the better
the well performance. This is because that most of the load recovery
is fluid being recovered from the fracture itself. Little of the fluid that
has leaked off to the reservoir is recovered. Better quality reservoirs
with higher permeability and leak-off have poor load recoveries but
produce great. This same work also indicated that in low
permeability reservoirs one of the best ways to improve clean-up,
rate, and reserves was to shut the well in for days to weeks at a time.