American Oil and Gas Reporter - January 2015 - 57

Outlook 2015
water, sand and horsepower. The challenge now is determining
how to break the rock to improve frac conductivity and resource
recovery. Whether through enhanced microseismic, petrophysics
or rock mechanics, we need to work on breaking the rock in a
way that maximizes reservoir productivity.
On the drilling side, optimizing around programmable AC-powered rigs has driven step-change increases in drilling efficiency.
Plus, the technological advancements in safety on these rigs are
amazing. There has been a huge push for safety improvement,
and it is at the forefront of everything we do. The equipment and
operations are so focused on safety that the industry has done a
great job of engineering out a lot of the hazards in both drilling
and completion.
That said, I keep telling our drilling guys that rigs for the Permian, Bakken and other resource plays need to be 1,500-horsepower units with all the bells and whistles, but they must be able
to move faster. The industry needs to continue to make strides
in rig design to enhance the ways in which rigs move. We need
to be able to move from location to location in two days. The rigs
that can accomplish that today are smaller. We need large-horsepower rigs with the same fast-move capability.
Technology improvements also are needed for artificial lift in
horizontal wells. Rod pumping, electric submersible pumps, gas
lift and other methods are certainly important, but they all have
limitations in long-lateral wells. The ideal would be a pump that
could produce down the lateral without being impacted negatively by the high decline rates in resource plays. We are hearing about
electric pump designs that can be run into the lateral and pump
from the horizontal. That is something the industry will accomplish in time. I have no doubt that other methods also will emerge
to improve artificial lift in horizontal wells.

Lateral lengths and the number of hydraulic fracture
stages pumped per well have increased dramatically in tight oil and gas shale plays. How does your company determine an "optimal" lateral length and number of fracs? Will
well refracturing become common in U.S. resource plays?

HOOVER: Lateral length is highly dependent on the acreage
positon and whether a unit can be formed. Can you drill a twosection lateral, or can you drill only a single-section lateral? It
looks like a 1.5-mile lateral length is optimal for us in the Wolfcamp right now, but we expect to standardize around a 2.0-mile
lateral once we get a better grip on motor and bit performance.
We have drilled some pad wells, but we are still in an acreagehold position to extend leases by drilling our lease obligations.
There is no doubt that the development stage of our acreage position will be done with pad wells and batch drilling. We are planning for that, and our locations are located optimally so that we
can drill multiple wells from every site.
We have been using a 200-foot stage length since we started
drilling in the Permian, and are happy with the performance.
Brigham Exploration did a lot of stage spacing iterations in the
Bakken, starting at 500 feet and moving all the way down to 250
feet. We pushed the envelope on increasing the number of frac
stages in the tighter part of the Bakken in McKenzie County, N.D.,
on the western side of the play. By increasing the numbers of stages
and using swell packers, we made an area that had been uneco-

nomic very economic. We had put together a 375,000-acre position, so when the frac design started making the wells work, it
was a great thing.
We now are getting ready to turn the wellbore azimuth "knob"
in the Permian, and we think it could be a similar game changer. The goal is to align the lateral perpendicular to the direction
of maximum reservoir stress. We are preparing to drill our first
well using an azimuth of north-55 degrees-east. We have lot of
log data to tell us the direction of maximum stress, so in a big
contiguous block with room to stack slanted laterals and pool different wells drilled diagonally, intersecting the stress regime at
just the right azimuth could optimize fracturing effectiveness and
move the needle on well performance and EUR.
I absolutely believe that refracturing is a big part of the future
in unconventional reservoirs. I am not yet sure what that is going to look like because there are different refrac techniques. One
solution is running an expandable liner section inside existing liner, expanding the new casing, and then perforating and stimulating between existing stages. There also are coiled tubing solutions to cut a new slot and back your way out with the CT string
stimulating parts of the reservoir that were not perforated.
Both approaches can stimulate rock between stages that may
not have been treated effectively before. I think a lot of ideas will
be tried across the different resource play basins, and I expect numerous technological developments to give operators the tools
to economically refracture and restimulate producing wells that
are on the backside of their decline curves.

Developing resources plays requires a certain amount
of collaboration and integration. Do you see a need
for tighter and more coordinated integration of technologies,
data and technical domains to improve performance in these
plays? Is it difficult to achieve? How critical is it for improving
recovery factors?
HOOVER: Smaller companies actually have a big advantage
in integrating different disciplines and departments. Everyone at
smaller companies has to be on the same page. We sit at the same
meetings, work with the same data, and bring all the information
and people together on every project. We do not need to worry
about fostering collaboration; we are doing it already. The bigger the company, the more challenging it is to integrate and collaborate across departments.
The drilling guys can put all kinds of curves and dips in a wellbore, but the poor guys in the production department end with
a tortuous well they have to artificially lift with a rod pump. Everyone involved has to communicate to create a win-win outcome.
The drilling guys probably would not even think about what a tortuous wellbore meant to production costs without collaborating
and communicating on a common goal. Getting drilling and completion engineers thinking about how a well will be produced, and
production engineers thinking about how a well will be drilled
and completed, helps minimize problems and improve results.
We are technologically proactive. For example, we have supervisory control and data acquisition systems on all our tank batteries. I can look at my computer any time and see the tank level on any battery. The technology is available to monitor all aspects of production, and as we do more development drilling and
JANUARY 2015 57

American Oil and Gas Reporter - January 2015

Table of Contents for the Digital Edition of American Oil and Gas Reporter - January 2015