American Oil and Gas Reporter - June 2014 - 89

SpecialReport: Artificial Lift Technology
CO2 injection results were similar to the miscible gas injection case, even though the properties and miscibility of the injection gases were different. CO2 injection rates ranged between
170 Mcf/d and 700 Mcf/d, which was equivalent to 0.20 PV.
Increases from the production wells were observed after one
month of injection, with the highest rate of 672 bbl/d occurring
eight and a half years after starting injection, which was much
later than with miscible gas injection (Figure 6). The recovery
factor was only slightly higher (21.58 percent, or 15.6 percent higher during the primary phase). In this case, solvent breakthrough
occurred 5.4 years after initiating injection.
While the modeled results show similar recoveries for CO2 and
miscible gas injection, 10 percent more CO2 was injected into the
formation than miscible gas to recover only 0.003 percent more
oil (Table 1). Moreover, the peak production rate was slightly delayed for CO2, and injection and gas breakthrough time occurred
later. These differences likely were related to the ease of hydrocarbon gas miscibility compared with CO2 miscibility.
Economic Considerations
Simple economic cases were developed to evaluate the hydrocarbon injection scenarios. While produced gas can be sold to improve the tight oil project economics in many cases, this analysis compared the value of using the gas to increase oil recovery
versus the value of selling the gas volumes. Obviously, produced
hydrocarbon gas must be compressed before it is reinjected into
the reservoir. The initial investment for the compressors was assumed to be $10 million. In addition, 10 percent of the total injection gas volume will be needed to fuel the compressors.
In the four-section Bakken study area, there would not be
enough gas produced to supply all of the gas needs, so additional makeup gas must come from other sources or areas of the field.
In this analysis, the cost of fuel and injected gas was $5/Mcf (either in the form of lost revenue or purchase cost) and the pre-tax
value of each incremental barrel of oil was $80.
For the immiscible case, the economics appear favorable. The

TABLE 1
Three Injection Scenario Results
Gas
injected

Recovery
factor

Time after injection
to breakthrough

Immiscible gas

0.06 PV

13.3%

3.3 years

Miscible gas

0.18 PV

21.3%

3.6 years

Carbon dioxide

0.20 PV

21.6%

5.4 years

Scenario

internal rate of return was 51 percent with a 2.4-year payout. Using a discount rate of 10 percent, the net present value was $30
million for the Elm Coulee study area. For miscible produced gas,
the results are much better, with an NPV of $68 million, a 1.7year payout, and an 83 percent rate of return. Although many simplifying assumptions were made in this economic forecast, it does
illustrate that injecting hydrocarbon gases has significant potential in tight oil reservoirs from both a technical and economic standpoint.
Gas injection in the Bakken and other shale oil reservoirs looks
promising, particularly for miscible gas. Gas injection is a viable
option for increasing recovery factors above the 5-10 percent that
is observed from primary production in these plays. Importantly, this study demonstrates that significant oil can be recovered,
regardless of the type of gas injected. Even if the gas is not fully miscible with the reservoir oil, additional barrels will be recovered. Moreover, miscible hydrocarbon gas injection performed
as well as miscible CO2 injection.
While the economics of hydrocarbon gas injection appear favorable, much more work needs to be completed before any applications can be implemented in the field. The next steps in this
study effort will focus on hydraulic fracturing and reservoir characterization. This includes modeling transverse fractures, which
have become much more prevalent in shale plays, instead of longitudinal fractures. These efforts should lead to a better understanding of when and where gas injection can improve recovery
from shale oil reservoirs.
r

B. TODD
HOFFMAN

B. Todd Hoffman is an assistant professor in the Department of Petroleum Engineering at the
Colorado School of Mines. Before joining the School of Mines in 2011, Hoffman was a reservoir engineering consultant for Golder Associates and an assistant professor at Montana Tech.
Prior to that, he served in various reservoir engineering positions with Anadarko Petroleum,
Chevron and Arco Alaska. Hoffman's research interests include enhanced oil recovery, shale oil
reservoirs, reservoir model predictions, reservoir characterization, and numerical flow simulation. He holds a B.S. in petroleum engineering from Montana Tech, and an M.S. and a Ph.D.
in petroleum engineering from Stanford University.
JUNE 2014 89

American Oil and Gas Reporter - June 2014

Table of Contents for the Digital Edition of American Oil and Gas Reporter - June 2014