American Oil and Gas Reporter - December 2016 - 27

TECHCONNECTIONS
DFIT Provides
One Method To Analyze
Formation Data
Data collection related to unconventional reservoirs in North
America is expanding rapidly. However, for many folks,
integrating these data into day-to-day operations sometimes can
prove daunting. Like many technologies and industry best
practices, there is no shortage of opinions, techniques, and controversy surrounding the interpretation and analysis of this data.
One method of collecting reservoir data commonly used in
unconventional reservoirs is the diagnostic fracture injection
test (DFIT). As the name implies, this process involves injecting
fluid into the producing reservoir at a rate just high enough to
create a small hydraulic fracture. This provides pressure fall-off
data that can be analyzed to gain information related to in-situ
stresses, reservoir fluid flow and pore pressure, to name a few.
Essentially, DFIT helps engineers paint a more detailed picture
of what is going on down hole, and hopefully will help operators
design more optimized completions.
This test has been used for many years. However, as unconventional reservoirs have become the norm, DFIT has played a
key role in understanding and developing these unique reservoirs.
In October, I served as a session chair for a Society of
Petroleum Engineers workshop titled, "Diagnostic Fracture
Injection Test: Processes and Applications." The first-of-its-kind
SPE event was held on the BP campus in Houston, and was led
by Prue Smith from BP and David Cramer from ConocoPhillips.
The workshop was divided into sessions on job design and
execution; theories, concepts, and concerns; data signatures; data
utilization; modeling and data integration; and vertical pilot wells.
Each session featured presentations from experts in hydraulic
fracturing and data analysis. Since there are varying opinions
regarding how the DFIT process is designed, implemented and
analyzed, each session stimulated passionate debate regarding
individual ideas on what worked and what didn't.
Day one began with Michael B. Smith from NSI Technologies
in Tulsa posing a simple question: "Why are we Doing This?"
Smith outlined the traditional information that many folks are
looking to obtain when they pump a DFIT. Among these data
are fracture parameters such as closure, geometry, and fluid efficiency; and formation parameters such as reservoir pressure
and permeability.
Smith suggested that rather than diagnostic fracture injection
test, perhaps DFIT should stand for diagnostic formation injection
test, since the formation really is what engineers are interested in
evaluating. He contended that if one was looking for closure
pressure, performing a DFIT on an unconventional reservoir
really was not necessary. He said injection pressure could be
found with a simple five-minute injection test, and that pressure
analysis often was negated by multiple fractures, lack of measured
bottom-hole pressure, and near-well tortuosity. He said fluid efficiency was not important for designing water frac treatments.
Smith went on to argue that the critical data were system
permeability, reservoir pressure, and any indications of stresssensitive natural fissure permeability, asking, "Are our test procedures masking these critical data?"

"DFIT data can be analyzed to gain information related to in-situ stresses,

"

reservoir fluid flow and pore pressure.

He then outlined case studies suggesting that conducting a
DFIT in an open-hole environment could provide more favorable
results, avoid lost data, and provide indications of natural fissure
permeability.
Later that day, Robert D. Barree from Barree & Associates
in Lakewood, Co., presented "DFIT Data Signatures: Welcome
to the Real World." Barree highlighted multiple case studies on
DFIT signatures and their interpretation. Using examples, he
discussed identifying instant shut-in pressure and the fracture
extension gradient, as well as wellbore compression and blowdown effects on pressure decline. Later, while looking at the GFunction plot, he asked what "derivative hump" meant, and
whether it was caused by some sort of wellbore mechanism.
Additionally, Barree looked at some potential causes of GFunction "derivative belly" shape. Finally, he discussed afterclosure analysis, looking at pore pressure in linear and pseudoradial flow, as well as determining reservoir transmissibility.
Finally, in a presentation titled, "Applying a Discrete Fracture
Network Simulator to Understand Non-Ideal DFITs and Fracture
Closure," Mark McClure of McClure Geomechanics discussed
simulation work he conducted with Hojung Jung and Mukul
Sharma from the University of Texas at Austin, and Dave
Cramer and Sean Oakes from ConocoPhillips. In this project,
researchers compared detailed numerical simulations of DFITs
with field data. While the group achieved a close match to the
field data before, during and after closure, McClure said they
were surprised to learn that using conventional methods to pick
closure were not accurate, compared with the simulation.
These were only three of the many quality presentations
provided at this important event, and while there were many disagreements over the course of the workshop, the discussion
around this topic definitely will propel this event forward as one
of the more important events to attend in the coming years. r

JEREMY VISCOMI is the di-

rector of technology transfer
for the University of Kansas
Tertiary Oil Recovery Program
and the PTTC Midcontinent
Region office. He has more
than a decade of experience
in developing and organizing
technical conferences and special events.
DECEMBER 2016 27



American Oil and Gas Reporter - December 2016

Table of Contents for the Digital Edition of American Oil and Gas Reporter - December 2016

Contents
American Oil and Gas Reporter - December 2016 - Cover1
American Oil and Gas Reporter - December 2016 - Cover2
American Oil and Gas Reporter - December 2016 - Contents
American Oil and Gas Reporter - December 2016 - 4
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American Oil and Gas Reporter - December 2016 - Cover3
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