Research Papers: Petroleum Engineering

Investigation of Formation Damage Induced During Drill-In Process of Ultradeep Fractured Tight Sandstone Gas Reservoirs

[+] Author and Article Information
Dujie Zhang

State Key Laboratory of Oil and Gas Reservoirs
Geology and Exploitation,
Southwest Petroleum University, Chengdu
610500, China;
Department of Civil Engineering and
Applied Mechanics,
McGill University,
817 Sherbrooke Street, West,
Montreal H3A 0C3, QC, Canada
e-mail: dujie.zhang@mail.mcgill.ca

Yili Kang

State Key Laboratory of Oil and Gas Reservoirs
Geology and Exploitation,
Southwest Petroleum University,
Chengdu 610500, China
e-mail: cwct_fdc@163.com

Lijun You

State Key Laboratory of Oil and Gas Reservoirs
Geology and Exploitation,
Southwest Petroleum University,
Chengdu 610500, China

Jiaxue Li

PetroChina Tarim Oilfield Company,
Kolar 841000, China

1Corresponding authors.

Contributed by the Petroleum Division of ASME for publication in the JOURNAL OF ENERGY RESOURCES TECHNOLOGY. Manuscript received July 20, 2018; final manuscript received December 4, 2018; published online January 9, 2019. Assoc. Editor: Gensheng Li.

J. Energy Resour. Technol 141(7), 072901 (Jan 09, 2019) (10 pages) Paper No: JERT-18-1555; doi: 10.1115/1.4042236 History: Received July 20, 2018; Revised December 04, 2018

Ultradeep fractured tight sandstone gas reservoir is easy to suffer from severe formation damage during the drill-in process, yet few papers have been published on the corresponding formation damage mechanisms. This paper focuses on a typical ultradeep fractured tight sandstone reservoir in the Tarim Basin, China. Fluid sensitivity damage, phase trapping damage, and the formation damage induced by oil-based drill-in fluids were evaluated by a serious of modified experimental methods. As a supplement, the rock physics and surface property were analyzed deeply. Results showed that severe fluid sensitivity damage occurred with a decrease in fluid salinity (critical value: 3/4 formation water salinity (FWS)) and an increase in fluid pH value (critical value: pH = 7.5). The change in water film thickness, the enhancement of hydrophilia, particle detachment, and dissolution of quartz/albite under high formation temperature are the main damage mechanisms. Abnormal low water saturation, mixed wettability, abundant clay minerals, and complex pore structures are contributing to the severe phase trapping damage. The dynamic damage rate of oil-based drill-in fluids is 60.01%, and inadequate loading capacity is the main trigger of lost circulation. Finally, a formation damage control strategy was proposed, and a field test proved its feasibility.

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Fig. 1

Schematic diagrams of the modified coreflood experiment apparatus

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Fig. 2

The schematic diagrams of loading capacity experimental apparatus

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Fig. 3

Results of the salt sensitivity experiments included (a) matrix samples (UD2-9: porosity is 3.06% and permeability is 0.004472 mD; UD1-9: porosity is 4.12% and permeability is 0.011170 mD; and UD3-1: porosity is 2.47% and permeability is 0.033370 mD) and (b) fractured samples (UD1-7: porosity is 4.79% and permeability is 61.43 mD; UD1-15: porosity is 3.22% and permeability is 59.71 mD; and UD3-3: porosity is 2.40% and permeability is 72.01 mD)

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Fig. 4

Mercury intrusion test results of the tight sandstone samples included (a) capillary pressure curves and (b) permeability contribution ratio of the pore throats with different radii

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Fig. 5

Results of the alkali sensitivity experiment included (a) matrix samples (UD1-18: porosity is 3.40% and permeability is 0.005768 mD; UD2-10: porosity is 3.52% and permeability is 0.006840 mD; and UD5-6: porosity is 3.90% and permeability is 0.01997 mD) and (b) fractured samples (UD1-12: porosity is 3.30% and permeability is 117.99 mD; UD1-15: porosity is 2.92% and permeability is 61.43 mD; and UD3-3: porosity is 2.30% and permeability is 33.82 mD)

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Fig. 6

Description of spontaneous imbibition processes included (a) liquids saturation versus imbibition time of simulate formation water/diesel oil and (b) liquids saturation versus square root of time

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Fig. 7

Liquid saturation versus time during displacement processes

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Fig. 8

Images of the multiscale natural fractures within this reservoir included (a) microresistivity images (FMI), (b) image of core observation, (c) casting thin sections image, and (d) SEM image

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Fig. 9

Scanning electron microscopy images of tight sandstones cores from K gas field: illite with silk-thread form, 7733.53 m

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Fig. 10

The distribution conditions of loss oil-based drill-in fluids in the fractures after loading capacity experiments. The fracture widths are included (a) 50 μm, (b) 100 μm, (c) 150 μm, (d) 200 μm, (e) 300 μm, and (f) 500 μm.

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Fig. 11

The PSD of oil-based drill-in fluids



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