Research Papers: Oil/Gas Reservoirs

The State of the Art and Challenges in Geomechanical Modeling of Injector Wells: A Review Paper

[+] Author and Article Information
J. F. Bautista, A. Dahi Taleghani

Department of Petroleum Engineering,
Louisiana State University,
Baton Rouge, LA 70803

Contributed by the Petroleum Division of ASME for publication in the JOURNAL OF ENERGY RESOURCES TECHNOLOGY. Manuscript received October 12, 2016; final manuscript received November 14, 2016; published online December 22, 2016. Editor: Hameed Metghalchi.

J. Energy Resour. Technol 139(1), 012910 (Dec 22, 2016) (10 pages) Paper No: JERT-16-1404; doi: 10.1115/1.4035257 History: Received October 12, 2016; Revised November 14, 2016

Fluid injection is a common practice in the oil and gas industry found in many applications such as waterflooding and disposal of produced fluids. Maintaining high injection rates is crucial to guarantee the economic success of these projects; however, there are geomechanical risks and difficulties involved in this process that may threat the viability of fluid injection projects. Near wellbore reduction of permeability due to pore plugging, formation failure, out of zone injection, sand production, and local compaction are challenging the effectiveness of the injection process. Due to these complications, modeling and simulation has been used as an effective tool to assess injectors' performance; however, different problems have yet to be addressed. In this paper, we review some of these challenges and the solutions that have been proposed as a primary step to understand mechanisms affecting well performance.

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Fig. 1

Injection history (pressure and flowrate) of a water injector in the offshore Gulf of Mexico borrowed from Ref. [40]

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Fig. 2

Lost frac-pack due to fluid injection: (a) The frac-pack is placed at the perforations, (b) the initial fracture resumes growth as fluid is injected the proppant progresses into the formation, (c) the high permeability channel between the proppant and the well is filled back with formation sand during shut-in periods

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Fig. 3

Two-dimensional experiments on fluid injection into unconsolidated porous media: (a) μ = 176 cP and 5 ml/min, (b) μ = 176 cP and 50 ml/min, and (c) μ = 176 cP And 125 ml/min taken from Ref. [11]

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Fig. 4

(a) Pressure profile after high permeability channels develop as a consequence of solid transport (channelization) and (b) fluid injection induced channels

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Fig. 5

Wellbore shut-in pressure response, these pressure fluctuations may cause flowback to the wellbore

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Fig. 6

Possible flooding patterns for fracture azimuth toward producers (left) and away from producers (right). The situation on the left-hand side might cause an early water breakthrough due to the higher hydraulic conductivity from fractures in the producer's direction.

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Fig. 7

Fracture growth across heterogeneous formations: (a) Fracture extension equal across layers and (b) fracture length variation across layers of dissimilar properties




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