Research Papers: Oil/Gas Reservoirs

CO2 Flooding to Increase Recovery for Unconventional Liquids-Rich Reservoirs

[+] Author and Article Information
B. Todd Hoffman

Colorado School of Mines,
1500 Illinois St.,
Golden, CO 80401
e-mail: thoffman@mines.edu

Shehbaz Shoaib

Montana Tech,
1300 W. Park St.,
Butte, MT 59701

Contributed by the Petroleum Division of ASME for publication in the JOURNAL OF ENERGY RESOURCES TECHNOLOGY. Manuscript received January 18, 2013; final manuscript received October 23, 2013; published online December 23, 2013. Assoc. Editor: Sarma V. Pisupati.

J. Energy Resour. Technol 136(2), 022801 (Dec 23, 2013) (10 pages) Paper No: JERT-13-1024; doi: 10.1115/1.4025843 History: Received January 18, 2013; Revised October 23, 2013

The rising energy demand is causing the petroleum industry to develop unconventional oil reservoirs; however, the primary recovery factor is low in these types of reservoirs. Alternative methods to increase recovery need to be studied. This paper analyzes the impact of CO2 flooding a sector of the Elm Coulee field using reservoir modeling. The sector is two miles by two miles and consists of six original single-lateral horizontal wells. Two different reservoir models are built for the sector: a primary recovery black oil model and a CO2 flood solvent model. They are used to determine the additional recovery due to a CO2 flood. Furthermore, the CO2 flood model is executed with different scenarios to determine the best well locations and injection schemes. The models demonstrate that CO2 flooding horizontal wells in the Elm Coulee field increases production. Comparison of vertical and horizontal injection techniques indicates continuous horizontal CO2 injection is more efficient; it yields higher injection rates, and it is also beneficial for long-term recovery. Focusing on horizontal injection, the best scenario involves the practice of drilling new injectors and producers along with converting existing producers to injection wells. In order to satisfy production requirements, production wells can be drilled such that there is an injector between two producers. This type of arrangement on horizontal injection increases the field recovery factor over 15% after eighteen years of injection.

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Fig. 2

Map of Elm Coulee field with sector selected for modeling

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Fig. 3

Permeability multiplier values as function of reservoir pressure for the shale region

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Fig. 4

Fluid properties for Elm Coulee reservoir model

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Fig. 5

Two dimensional view of reservoir grid highlighting the six well locations

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Fig. 6

Comparison of historical and simulated production data [17]

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Fig. 7

Comparison of historical and simulated oil production rates in the future on primary recovery

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Fig. 8

Values of solvent (CO2) formation volume factor and viscosity as a function of pressure

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Fig. 9

Increase in sector production rate after CO2 injection from twelve vertical injectors (Scenario 1)

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Fig. 10

Extent of areal sweep in the layer 1 and cross section of A to A′ after the addition of twelve vertical injectors of CO2 (Scenario 1)

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Fig. 11

Location of four horizontal injectors, HINJ1–HINJ4, with respect to production wells (Scenario 2)

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Fig. 12

Increase in sector production rate after CO2 injection from four horizontal injectors (Scenario 2)

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Fig. 13

Location of newly added injectors, producers converted to injectors, and newly added producers (Scenario 3)

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Fig. 14

Increase in sector production rate after addition of two horizontal injectors, conversion of two existing producers and addition of two production wells (Scenario 3)

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Fig. 15

Extent of areal sweep in the layer 1 and cross section of A to A′ for Scenario 3

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Fig. 16

Increase in sector production rate after cyclic CO2 injection treatment on all producers (Scenario 4)

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Fig. 17

Porosity and permeability data from Elm Coulee core sample

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Fig. 18

Variation in permeability in x-direction in top layer of reservoir




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