American Oil and Gas Reporter - February 2016 - 56

SpecialReport: Improved Oil Recovery

Elm Coulee CO2 Pilot Test
The Elm Coulee Field pilot test was conducted jointly by Continental Resources, Enerplus, and XTO Energy in the Burning
Tree-State No. 36-2H well in Richland County, Mt. This horizontal well was completed in the Middle Bakken and was stimulated using a single-stage hydraulic fracturing operation. The
test used a huff-and-puff approach, with injection beginning in
early 2009.
Figure 1 shows oil production for the Burning Tree well. Prior to injection testing, oil production ranged from 30 to 40 barrels a day. Over the course of a 45-day test in January and February, approximately 45 million cubic feet (2,570 tons) of CO2
were injected at rates as high as 3.0 MMcf/d. After injection, the
well was capped and the CO2 was allowed to soak for 64 days.
The well then was opened and allowed to flow freely.
After rapidly climbing to peak production of 160 bbl/d eight
days after opening the well, oil production settled into an averFIGURE 1
Huff-and-Puff CO2 Injection Results
For Burning Tree-State 36-2H Pilot
1,400
Oil Production
CO2 Huff-and-Puff Test Period

1,200

Oil (bbl/month)

1,000
Period of Possible
Incremental Oil Recovery?
800

600

400
Well Put Back on Pump
200

Fe
b

-0
8
Ju
n08
O
ct
-0
8
Fe
b09
Ju
n09
O
ct
-0
9
Fe
b10
Ju
n10
O
ct
-1
0
Fe
b11
Ju
n11
O
ct
-1
1
Fe
b12
Ju
n12
O
ct
-1
2
Fe
b13
Ju
n13
O
ct
-1
3

0

Production Month

56 THE AMERICAN OIL & GAS REPORTER

FIGURE 2
CO2 Injection Results for NDIC 16713 (Top)
And NDIC 16768 Offset Well (Bottom)
35,000
30,000

On Pump
Monthly Oil
CO2 Injection Test

Oil (bbl)

25,000

Well Returned
to Sales

20,000
15,000
10,000
5,000
0
Aug-07

Jun-08

Mar-09

Jan-10

18,000

Nov-10
Date

Sep-11

Jul-12

May-13

16,000

Monthly Gas

14,000

CO2 Injection Test

12,000
Gas (Mcf)

The Bakken CO2 Storage & Enhanced Recovery Program at
the Energy & Environmental Research Center at the University
of North Dakota is conducting a variety of research activities. The
program is funded by a consortium that includes the U.S. Department of Energy through the National Energy Technology Laboratory, the North Dakota Industrial Commission, and several operators and service companies. The program includes laboratory- and modeling-based investigations to support a pilot-scale field
demonstration.
The ultimate goal of the program is to provide guidance in designing a commercially viable injection/production scheme for
CO2 EOR and storage in tight oil formations. The program seeks
to determine what makes a good candidate site; which types of
injection/production schemes are most effective; what site-specific data need to be collected prior to, during and after the injection test; and the expected time frame for CO2 to enhance production.
As part of the effort to address those questions, the research
is examining publicly available data from Bakken wells in which
injection tests have been conducted. The data include a pilot-scale
CO2 injection test in the Elm Coulee Field in Montana as well
as four water, CO2 and/or produced field gas injection projects
in North Dakota.

Mar-14

CO2 Breakthrough
Detected

10,000
8,000

Additional Production
from Injection Test?

6,000
4,000
2,000
0
Aug-07

Jun-08

Mar-09

Jan-10

Nov-10
Date

Sep-11

Jul-12

May-13

Mar-14

age of 20 bbl/d during the first 30 days after the soak period. By
the end of June 2009, the well was no longer flowing and was
put on pump. Daily oil production did not return to the preinjection range until late 2009, nearly eight months after the well was
opened.
Oil production continued to rise slowly in early 2010, reaching a peak post-injection high approaching 44 bbl/d in March 2010
(a higher rate than was achieved during any of the 14 months immediately prior to the injection test). Conversations with the operators indicate that the higher production rate may be related to
workover activities on the well as opposed to delayed CO2 effects.
Other than in the first few days, which saw an initial spike in
fluid production that was likely the result of pressure buildup as
opposed to miscibility-related CO2 effects, the Burning Tree well
did not see a dramatic production increase. But CO2 was injected successfully and reservoir fluids subsequently were produced.
Taking a longer view, there was a period (January to March
2010) that saw a gradual oil productivity increase, and although
it was delayed and certainly not dramatic, this improved productivity might be at least partially attributable to injection.
Unfortunately, the nature of the available data makes it difficult to determine how much of the improvement could be related to the CO2 or whether it actually was associated with other
operational factors. Gaps in the injection monitoring data were
perhaps the most significant limitation to fully assessing the effect of CO2 on the Burning Tree well. While gas analysis data
show that approximately 50 percent of the CO2 injection volume
was recovered between May and August 2009, there were no further testing results from the well.
Furthermore, it appears that during the test period, no offset



American Oil and Gas Reporter - February 2016

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

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American Oil and Gas Reporter - February 2016 - Cover2
American Oil and Gas Reporter - February 2016 - Contents
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