American Oil and Gas Reporter - January 2015 - 52

Outlook 2015
The EUR Factor

Q:

Jay Ottoson, SM Energy Company

Since 2007, U.S. oil production has jumped 4 million
barrels a day while gas production has soared by 5
trillion cubic feet annually. With check marks beside gamechanging reserve and production growth, what comes next
for independent companies in unconventional oil and gas
plays? Where the past decade was characterized by securing
leaseholds and navigating the drilling and completion
learning curve, what will be the hallmarks of the next two to
five years?
OTTOSON: Over the next two to five years, I think the industry will see a continued focus on how to recover more resources
from source-rock plays. We are starting to see green-field exploration slow in the lower-48. As this portion of the cycle slows,
the industry's focus is moving to how to best optimize the plays
we have captured already and how to recover the most resource
in the most cost-effective way.
Our industry-SM Energy included-has made a big push to increase recoveries by continually testing the way we drill and complete wells to maximize and/or accelerate the recoverable resource.
We have increased the lateral lengths of horizontal wells and nearly doubled the amount of sand per lateral foot in our Eagle Ford
completions to create more frac complexity near the wellbore,
leading to increased productivity and estimated ultimate recoveries. Advancements in fracture modeling have been key in helping us understand what is going on with the rock while we are
completing wells, helping us to understand not only what we are
fracturing, but also what we are propping.

Q:

The average recovery factor in resource plays is a fraction of that in higher-permeability conventional
reservoirs. What is the potential size of the prize for increasing
the EUR factor in "source-rock" reservoirs? Are there certain plays
where maximizing EUR could have particularly strong economic incentives?
OTTOSON: The potential increase in ultimate recoveries is
enormous. When you look at the U.S. Energy Information Administration's estimates for recoverable oil from shale plays, they
assume a 5 percent recovery of oil in place. If we were able to
increase that recovery by 20 percent-for example, going from 5
percent to 6 percent recovery-we would be talking about an 8 billion-barrel increase in recoverable oil in four of the large tight
oil plays in the United States: the Eagle Ford in South Texas, the
Bakken/Three Forks in the Williston Basin, the Permian Basin
in West Texas and southeastern New Mexico, and the Niobrara
in Colorado and Wyoming. The role of technology in unlocking
additional resource in these shale plays will be a game changer
in the years and decades to come.

52 THE AMERICAN OIL & GAS REPORTER

Q:

Boosting EURs in unconventional reservoirs sounds
straightforward enough, but it is obviously a grand
challenge. Where is the industry in terms of understanding how
to accomplish that objective?
OTTOSON: I think there is still a lot to be learned about shale
plays and how best to develop them. Our understanding of these
plays and the tools we have available to evaluate them is changing constantly, resulting in an ever-evolving thesis of how best
to develop shale plays. As an industry, we really have pushed the
envelope in trying to increase recovery factors. Apart from the
drilling we have ahead of us, I think there is also a tremendous
amount of refracturing opportunities in unconventional fields that
have been drilled and completed already with what we now know
were suboptimal completion designs.

Q:

SM Energy operates large leaseholds in several unconventional plays, including the Bakken/Three Forks, Eagle Ford, Woodford, Haynesville and Permian. Recognizing that
the geology is different in each of these plays, what has SM Energy learned about the kinds of variables that influence productivity, decline curves and EURs? Are there commonalities
among these plays with respect to drilling, completion and production practices that ultimately could help improve EURs?
OTTOSON: These plays vary considerably, and we do have
to treat each of them differently. The commonality is the workflow and technical tools we employ in developing these resources.
It starts with our geoscience staff identifying the most productive and "fracturable" interval within the target formation, and
then collaborating with our drilling team to assure that a high percentage of the lateral is geosteered in this zone. Completions, geology and reservoir personnel work together to design and evaluate treatments that create a complex and conductive fracture network around the wellbore. Production designs are established to
maximize value, but also to maintain the productivity of that network.
The different characteristics of the plays, whether it is absence
of frac barriers, interbedded ductile intervals, in-situ stresses, and/or
adjacent pressure sinks, to name a few, require us to treat them
individually. The continual evaluation of our results, treatments
and interpretation advances our understanding and leads to maximizing the value from a variety of assets.

Q:

Technology has enabled economic production from
unconventional formations. Going forward, what
types of technologies are likely to prove most critical in improving EURs from these reservoirs? Will the tools and techniques
be the same for oil as for natural gas? How important will it be
to integrate technologies and skill sets from multiple oil and
gas disciplines?
OTTOSON: We have seen the industry progress from developing assets with single well pads, laterally spaced in the same
interval and completed in sequence; to multiwell pads, staggered



American Oil and Gas Reporter - January 2015

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