American Oil and Gas Reporter - February 2016 - 58

SpecialReport: Improved Oil Recovery
producing wells were monitored in a way that could shed light
on possible CO2 migration. Testing for CO2 in offset wells provides the mass balance calculations necessary to fully evaluate
the movement of both injectant and mobilized oil within the reservoir.
North Dakota Injection Tests
The North Dakota Industrial Commission's well file database
includes information on four injection tests in Bakken wells conducted between 1994 and 2014 that could provide insights on both
Bakken waterflooding and CO2 EOR.
The first was a water injection test by Meridian Oil in NDIC
9660 in the Bicentennial Field in McKenzie County. Approximately 13,200 barrels of freshwater were injected into a horizontal well
in the Upper Bakken Shale for 50 days in 1994. The well was shut
in for two months, after which oil production remained below
pretest rates for the rest of the well's operational life.
In late 2008, EOG conducted a CO2 injection test in NDIC
16713 in the Parshall Field in Mountrail County. This horizontal well was drilled into the Middle Bakken and was completed
using a six-stage hydraulic fracture treatment. Based on incomplete well file data, an estimated 30 MMcf of CO2 were injected using a huff-and-puff approach. No data on pre- or post-test
reservoir conditions were available. However, after 11 days of injection, CO2 breakthrough was observed in offset well NDIC
16768, located one mile west of the NDIC 16713.
Figure 2 shows oil and gas production data for both the test
and offset wells. The Parshall Field has a high degree of natural
FIGURE 3
Produced Water and Field Gas Injection Results
For NDIC 16986 (Top)
And NDIC 16461 Offset Well (Bottom)
30,000
25,000

Monthly Oil
Monthly Water

Volume (bbl)

20,000

Field Gas Injection Test
Waterflood Injection

15,000
10,000

Resume
Production

5,000

Volume (bbl)

-1

8,000
7,000

Monthly Oil

6,000

Monthly Water
Monthly Gas
Field Gas Injection Test

Waterflood Injection

5,000
4,000

10,000

3,000
2,000

5,000

1,000

r-0
8
Au
g08
De
c-0
8
Ma
y-0
9
Se
p09
Ja
n10
Ju
n10
Oc
t-1
0
Fe
b11
Ju
n11
No
v-1
1
Ma
r-1
2
Ju
l-1
2
No
v-1
2
Ap
r-1
3
Au
g13
De
c-1
Ma 3
y-1
4
Se
p14

y-1

De
c

r-1

-1

l-1

No
v

r-1

9,000

Gas (Mcf)

15,000

v-1

Date

25,000
20,000

t-1

y-0

c-0

r-0

Date

58 THE AMERICAN OIL & GAS REPORTER

fracturing, and the high mobility of CO2 in this fractured system
indicates that conformance control is likely a major factor in designing EOR operations. Also of interest is the fact that three other offset wells located within one mile of the injector did not see
CO2 breakthrough, suggesting that understanding the local natural fracture system is key to EOR planning.
EOG conducted a produced water injection test in another well
in the Parshall Field, the NDIC 17170. Injection began in the spring
of 2012 with plans to operate the well in a huff-and-puff
scheme according to a 30-day injection and 10-day soak schedule. Data in the well file indicate that 10,000 barrels of water were
injected in April and 29,000 barrels were injected in May 2012.
Again, no data on pre-test or post-test reservoir conditions are publicly available. There was no observable incremental improvement in oil production attributable to water injection.
A third Parshall Field well operated by EOG, the NDIC 16986,
has been the subject of both produced water and field gas injection testing. Water injection was conducted periodically from April
2012 to February 2014 in a "waterflood pilot." Figure 3 shows
fluid production data for the injection well and nearby offset well
NDIC 16461. Nearly 439,000 barrels of water were injected before the well was returned to production in March 2014.
Starting in June 2014, EOG began injecting field gas mingled
with produced water injection. According to statements in the well
file, water was used to "manage effects of gas mobility in the fracture system," or if needed, "build system pressure with less gas
volume." Through Aug. 20, 2014, a total of 88.729 MMcf had
been injected.
No data on pre- or post-test reservoir conditions are available,
and there is nothing in the well file to suggest that the testing activities were considered successful by the operator. Changes in
fluid production rates were observed in two offset wells, demonstrating that communication between wells can occur rapidly.
The information available in the NDIC well file database provides only limited details about pre- or post-test reservoir conditions, injection schemes, or effects on offset wells. Geologic
data, operator notes and activity logs, and information on natural and induced fracture networks, are severely limited as well.
This lack of information limits our ability to draw authoritative
conclusions about potential EOR schemes.
Generally speaking, however, the tests do suggest that injectivity is not a limiting factor in the Middle and even Upper Bakken,
Also, examining monthly oil, gas and water production data for
the test wells and neighboring offset wells indicates that communication was observed in some offsets. However, in all cases, the
specific objectives of each pilot test were unclear, and a lack of
information on operational aspects of the injection and offset wells
make it difficult to independently evaluate the success of the tests.
Path Forward
Most Bakken injection tests have used a huff-and-puff approach. Successful CO2 huff-and-puff operations in conventional wells typically see dramatically improved oil production shortly after soaking for several weeks, or even months. While these
Bakken tests would not be considered successful compared with
conventional huff-and-puff tests, it is important to keep in mind
that the Bakken is an unconventional tight oil play.
When viewed through a "conventional" lens, a reservoir that
is highly fractured with a tight matrix is not a good candidate for
any conventional CO2 EOR approach. That is why these early tests
should be viewed in the context of pioneering efforts and

American Oil and Gas Reporter - February 2016

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