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Research Papers: Petroleum Engineering

A New High-Temperature Gel for Profile Control in Heavy Oil Reservoirs

[+] Author and Article Information
Changjiu Wang

Department of Petroleum Engineering,
China University of Petroleum-Beijing,
Changping,
Beijing 102249, China
e-mail: jiuchangwang@163.com

Huiqing Liu

Department of Petroleum Engineering,
China University of Petroleum-Beijing,
Changping,
Beijing 102249, China
e-mail: liuhuiqingcup@sina.com

Qiang Zheng

CNOOC Research Institute of China National
Offshore Oil Corporation,
Dongcheng,
Beijing 100027, China
e-mail: coolmail86830@126.com

Yongge Liu

Department of Petroleum Engineering,
China University of Petroleum (East China),
Shandong, Qingdao 266580, China
e-mail: yg.leo@foxmail.com

Xiaohu Dong

Department of Petroleum Engineering,
China University of Petroleum-Beijing,
Changping,
Beijing 102249, China
e-mail: dongxh0578@gmail.com

Cheng Hong

Department of Petroleum Engineering,
China University of Petroleum-Beijing,
Changping,
Beijing 102249, China
e-mail: hc900107@163.com

1Corresponding author.

Contributed by the Petroleum Division of ASME for publication in the JOURNAL OF ENERGY RESOURCES TECHNOLOGY. Manuscript received September 13, 2015; final manuscript received September 24, 2015; published online October 15, 2015. Assoc. Editor: Egidio Marotta.

J. Energy Resour. Technol 138(2), 022901 (Oct 15, 2015) (10 pages) Paper No: JERT-15-1344; doi: 10.1115/1.4031706 History: Received September 13, 2015; Revised September 24, 2015

Controlling the phenomenon of steam channeling is a major challenge in enhancing oil recovery of heavy oil reservoirs developed by steam injection, and the profile control with gel is an effective method to solve this problem. The use of conventional gel in water flooding reservoirs also has poor heat stability, so this paper proposes a new high-temperature gel (HTG) plugging agent on the basis of a laboratory experimental investigation. The HTG is prepared with nonionic filler and unsaturated amide monomer (AM) by graft polymerization and crosslinking, and the optimal gel formula, which has strong gelling strength and controllable gelation time, is obtained by the optimization of the concentration of main agent, AM/FT ratio, crosslinker, and initiator. To test the adaptability of the new HTG to heavy oil reservoirs and the performance of plugging steam channeling path and enhancing oil recovery, performance evaluation experiments and three-dimensional steam flooding and gel profile control experiments are conducted. The performance evaluation experiments indicate that the HTG has strong salt resistance and heat stability and still maintains strong gelling strength after 72 hrs at 200 °C. The singular sand-pack flooding experiments suggest that the HTG has good injectability, which can ensure the on-site construction safety. Moreover, the HTG has a high plugging pressure and washing out resistance to the high-temperature steam after gel forming and keeps the plugging ratio above 99.8% when the following steam injected volume reaches 10 PV after gel breakthrough. The three-dimensional steam flooding and gel profile control experiments results show that the HTG has good plugging performance in the steam channeling path and effectively controls its expanding. This forces the following steam, which is the steam injected after the gelling of HTG in the model, to flow through the steam unswept area, which improves the steam injection profile. During the gel profile control period, the cumulative oil production increases by 294.4 ml and the oil recovery is enhanced by 8.4%. Thus, this new HTG has a good effect in improving the steam injection profile and enhancing oil recovery and can be used to control the steam channeling in heavy oil reservoirs.

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References

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Figures

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Fig. 1

HAAKE RS600 rheometer

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Fig. 2

Effect of the main agent concentration on gelling strength

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Fig. 3

Effect of the AM/FT ratio on gelling strength

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Fig. 4

Effect of the crosslinker concentration on gelling strength

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Fig. 5

Effect of the initiator NO-100 concentration on gelation time

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Fig. 6

Morphology of the HTG after gelling at 90 °C

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Fig. 7

The schematic of singular sand-pack flooding experiments

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Fig. 8

The schematic of three-dimensional scale physical simulation experiment

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Fig. 9

Morphology of the HTG at different temperatures for 72 hrs after gelling

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Fig. 10

Heat stability of other two kinds of gel: (a) crude-starch gel and (b) gelatinized-starch gel

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Fig. 11

Injectability of the HTG

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Fig. 12

Washing out resistance of the HTG

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Fig. 13

Temperature distribution at the top of model when steam channeled in each well during the fourth steam flooding period

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Fig. 14

Temperature distribution at the top of model when steam channeled in each well during the third gel profile control period

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Fig. 15

Temperature distribution at the bottom of model when steam channeled in each well during the fourth steam flooding period

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Fig. 16

Temperature distribution at the bottom of model when steam channeled in each well during the third gel profile control period

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Fig. 17

Average pressure change in the model during the fourth steam flooding period

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Fig. 18

Average pressure change in the model during the third gel profile control period

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Fig. 19

Gelling state of the HTG in the oil sand

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