Research Papers: Petroleum Engineering

Preparation and Characterization of Chemical Agents for Augmenting Injectivity in Low Permeability Reservoirs

[+] Author and Article Information
Min Zhao

Petroleum Systems Engineering,
Faculty of Engineering and Applied Science,
University of Regina,
Regina, SK S4S 0A2, Canada;
College of Petroleum Engineering,
China University of Petroleum (East China),
Qingdao 266580, China

Xiutai Zhao

College of Petroleum Engineering,
China University of Petroleum (East China),
Qingdao 266580, China

Daoyong Yang

Petroleum Systems Engineering,
Faculty of Engineering and Applied Science,
University of Regina,
Regina, SK S4S 0A2, Canada
e-mail: tony.yang@uregina.ca

1Corresponding author.

Contributed by the Petroleum Division of ASME for publication in the JOURNAL OF ENERGY RESOURCES TECHNOLOGY. Manuscript received September 5, 2017; final manuscript received November 7, 2017; published online January 22, 2018. Editor: Hameed Metghalchi.

J. Energy Resour. Technol 140(3), 032914 (Jan 22, 2018) (9 pages) Paper No: JERT-17-1480; doi: 10.1115/1.4038784 History: Received September 05, 2017; Revised November 07, 2017

In this paper, experimental techniques have been developed to prepare and characterize chemical agents for augmenting injectivity in low permeability reservoirs. First, chemical agents are selected, formulated, and optimized on the basis of interfacial tension (IFT), scale inhibition ratio, and clay particle size distribution and specific surface area. The spinning drop method is utilized to measure the IFT between crude oil and the formulated solution, while contact angle between brine and rock surface is measured to examine effect of the chemical agents on the rock wettability. Also, scale inhibition ratio and antiswelling ratio are, respectively, measured by performing static-state scale inhibition experiments and centrifugation experiments. Then, displacement experiments are conducted to evaluate injectivity improvement after one pore volume (PV) of such formulated chemical agents has been injected into a core plug. It is found that the optimized solution consists of 0.15 wt % fluorocarbon surfactant FC-117, 4.00 wt % isopropanol, 1.20 × 10−3 wt % scale inhibitor 2-phosphonobutane-1,2,4-tricarboxylic acid (PBTCA), and 1.50 wt % clay stabilizer diallyl dimethyl ammonium chloride (DMDAAC). The IFT between crude oil and the optimized solution can be reduced to 5.36 × 10−3 mN/m within a short time, while the scale inhibition ratio and antiswelling ratio are measured to be 94.83% and 86.96%, respectively. It is found from comprehensive evaluation experiments that such a formulated and optimized solution can not only alter the rock surface from oil-wet to water-wet but also reduce the scale formation of the reservoir brine. In addition, it is shown from displacement experiments that the pressure is decreased by 34.67% after the injection of such formulated solution. When the formulated solution contains 0–300,000 mg/L sodium chloride (NaCl) and 0–5000 mg/L calcium chloride (CaCl2) at 50–90 °C, the IFT between crude oil and the formulated solution can be reduced to lower than 10−2 mN/m.

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Fig. 1

Schematic diagram of the maximum bubble pressure apparatus: (a) digital pressure gauge, (b) distilled water, (c) dropping funnel, (d) quartz beaker, (e) outer thimble, (f) capillary tube, and (g) solution

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Fig. 2

Schematic diagram of the displacement experiment: (a) constant-flux pump, (b) transfer cylinder, (c) six-way valve, (d) digital pressure gauge, (e) coreholder, and (f) production fluid collector

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Fig. 3

Relationship between surface tension and concentration of FC-117

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Fig. 4

Relationship between IFT and time with different concentration of FC-117 and isopropanol: (a) 0.05 wt %, (b) 0.10 wt %, (c) 0.15 wt %, and (d) 0.20 wt %

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Fig. 5

Schematic diagram of effect to residual oil by chemical agents

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Fig. 6

The chemical structure of PBTCA

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Fig. 7

The relationship between scale inhibition ratio and concentration of PBTCA

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Fig. 8

The chemical structure of DMDAAC

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Fig. 9

The particle size distribution of kaolin in (a) water and (b) 1.50 wt % DMDAAC solution

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Fig. 10

Wettability alteration of rock surface after being treated by chemical solution

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Fig. 11

Sequential digital images of a sessile brine drop on the rock slide with different treated time: (a) t = 0 h, θ= 104 deg, (b) t = 1 h, θ= 54 deg, and (c) t = 24 h, θ= 35 deg

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Fig. 12

Effect of NaCl and CaCl2 on the minimum IFT

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Fig. 13

Effect of temperature on the dynamic IFT

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Fig. 14

The relationship between injection pressure and injection brine volume



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