Experimental research on amphiphilic polymer/organic chromium gel for high salinity reservoirs

Yang, Hongbin; Iqbal, Muhammad Waseem; Lashari, Zeeshan Ali; Cao, Changxiao; Tang, Xuechen; Kang, Wanli

doi:10.1016/j.colsurfa.2019.123900

Cited by 62 publications

(22 citation statements)

References 36 publications

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“…The activation temperature of phenol/formaldehyde cross-linked by acrylamide-based copolymer is above 80 °C, which is suitable for use in middle-/high-temperature oil reservoirs. When the reservoir temperature is low, the cross-linking condensation reaction of this system will slow down, and better formation effects cannot be guaranteed [ 25 , 26 ]. Since the formation of brine will affect the gelation time and stability of the dynamic gel, the researchers tried to develop a salt-insensitive gel system using a special salt-insensitive modified polymer (PAN, PVA, PAMPS, PSSA, etc.)…”

Section: Introductionmentioning

confidence: 99%

Soft Movable Polymer Gel for Controlling Water Coning of Horizontal Well in Offshore Heavy Oil Cold Production

Wang

You

et al. 2022

Gels

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Horizontal well water coning in offshore fields is one of the most common causes of rapid declines in crude oil production and, even more critical, can lead to oil well shut down. The offshore Y oil field with a water cut of 94.7% urgently needs horizontal well water control. However, it is a challenge for polymer gels to meet the requirements of low-temperature (55 °C) gelation and mobility to control water in a wider range. This paper introduced a novel polymer gel cross-linked by hydrolyzed polyacrylamide and chromium acetate and phenolic resin for water coning control of a horizontal well. The detailed gelant formula and treatment method of water coning control for a horizontal well in an offshore field was established. The optimized gelant formula was 0.30~0.45% HPAM + 0.30~0.5% phenolic resin + 0.10~0.15% chromium acetate, with corresponding gelation time of 26~34 h at 55 °C. The results showed that this gel has a compact network structure and excellent creep property, and it can play an efficient water control role in the microscopic model. The thus-optimized gelants were successively injected with injection volumes of 500.0 m3. The displacement fluid was used to displace gelants into the lost zone away from the oil zone. Then, the formed gel can be worked as the chemical packer in the oil–water interface to control water coning after shutting in for 4 days of gelation. The oil-field monitoring data indicated that the oil rate increased from 9.2 m3/d to 20.0 m3/d, the average water cut decreased to 60~70% after treatment, and the cumulative oil production could obtain 1.035 × 104 t instead of 3.9 × 103 t.

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Section: Introductionmentioning

confidence: 99%

Soft Movable Polymer Gel for Controlling Water Coning of Horizontal Well in Offshore Heavy Oil Cold Production

Wang

You

et al. 2022

Gels

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“…“Fisheye” scaling may occur near the well area of the polymer injection well because of the low solubility of the dry polymer powder or deviation in the construction means. 18 − 20 Adsorption and trapping of injected polymers in the reservoir, particularly at tiny pore openings, can limit the reservoir permeability. 21 − 24 The water used to manufacture the polymer may be incompatible with formation water, resulting in inorganic scaling.…”

Section: Introductionmentioning

confidence: 99%

Mechanistic Study on the Decrease in Injectivity during Salt-Resistant Polymer Flooding

et al. 2022

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According to numerous laboratory experiments and field applications, polymer flooding can effectively modify the liquid absorption profile and increase the sweep efficiency, thereby enhancing the oil recovery. However, long-term injection of polymers decreases the effective permeability of the reservoir and plugs the formation pores, resulting in irreversible reservoir damage. In the development process, polymer types and concentrations must be selected according to the reservoir to avoid problems such as plugging of the formation pores. This study was aimed at clarifying the degree of plugging and the injection limit of the reservoir when a salt-resistant polymer (SRP) is used in production processes of the Daqing Oilfield. To this end, oil displacement experiments, dynamic and static adsorption experiments, and SEM observations were performed using representative reservoir fluid and core samples. The static adsorption of “medium-molecular” SRP reached equilibrium after 36 h, and the saturated adsorption capacity was 3.56 mg/g, which was approximately 2–5 times the dynamic adsorption capacity. For medium-molecular SRP, with a molecular mass of 7 million, the lower limit of the core permeability was 20–40 mD. When the permeability was less than 100 mD, the SRP concentration injected into the core could not exceed 900 mg/L. The oil displacement capacity of SRP decreased owing to the macromolecular hydration radius and the strong aggregation effect of SRP. Polymer adsorption and the retention of sand-carrying critically decreased water permeability. This study provides insights into SRP flooding under different geological conditions in the Daqing Oilfield and can help clarify the molecular mass and concentration of polymers with changes in the reservoir conditions.

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“…Polymer–surfactant composites have become a research hotspot both in academia and industry for the past decades because of its particular synergistic behaviors. [ 1–12 ] They have a wide range of applications in many industrial formulations, such as laundry detergents, [ 13,14 ] cosmetics, [ 15 ] drug deliveries, [ 16–20 ] petroleum productions, [ 21–23 ] and so on. In this regard, researchers have proposed several synthetic strategies for preparing hydrophobically associated water‐soluble polymers (HAWSPs) such as: inverse emulsion polymerization, post modification process, solution polymerization, and micellar polymerization.…”

Section: Introductionmentioning

confidence: 99%

An Advanced Material with Synergistic Viscoelasticity Enhancement of Hydrophobically Associated Water‐Soluble Polymer and Surfactant

Wang

Kang

Yang

et al. 2021

Macromol. Rapid Commun.

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In order to prepare materials with controllable properties, changeable microstructure, and high viscoelasticity solution with low polymer and surfactant concentration, a composite is constituted by adding surfactant (sodium dodecyl sulfate, SDS) to hydrophobically associated water‐soluble polymer (abbreviated as PAAC) solution. The viscoelasticity, aggregate microstructure, and interaction mechanism of the composite are investigated by rheometery, Cryo‐transmission electron microscopy (Cryo‐TEM), and fluorescence spectrum. The results show that when the mass ratio of polymer to surfactant is 15:1, the viscosity of the composite reaches the maximum. The viscosity of the composite system increases hundredfold. The viscosity plateau under dynamic shear is generated. The composite has the properties of high viscoelasticity, strong shear thinning behavior, and good salt tolerance, and temperature resistance. The maximum viscosity of the composite is shown at the salinity of 20000 mg L−1. In addition, there is no phase separation in the composite with the increase of polymer and surfactant concentration, which indicates the good stability of the system. It is proposed a method to obtain a high viscoelasticity solution by adding surfactants without wormlike micelles to a hydrophobically associated water‐soluble polymer solution.

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Experimental research on amphiphilic polymer/organic chromium gel for high salinity reservoirs

Cited by 62 publications

References 36 publications

Soft Movable Polymer Gel for Controlling Water Coning of Horizontal Well in Offshore Heavy Oil Cold Production

Soft Movable Polymer Gel for Controlling Water Coning of Horizontal Well in Offshore Heavy Oil Cold Production

Mechanistic Study on the Decrease in Injectivity during Salt-Resistant Polymer Flooding

An Advanced Material with Synergistic Viscoelasticity Enhancement of Hydrophobically Associated Water‐Soluble Polymer and Surfactant

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