# Performance Evaluation and Site Application of a Hydrophobic Long-Chain Ester-Based CO2 Fracturing Fluid Thickener

Authors: Jianqiang Lu; Meilong Fu; Liu Xu; Qian Huang; Yan Zheng
Journal: Geofluids
 (2021)

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## Abstract

Nowadays, there are a wide variety of thickeners developed for dry CO2 fracturing worldwide, but numerous problems remain during in situ testing. To address problems in CO2 fracturing fluid operation (high frictional drag, low viscosity, low proppant-carrying capacity, narrow reservoir fractures, etc.), the authors have synthesized the novel hydrophobic long-chain ester thickener, studied viscosity, frictional drag, and proppant-carrying capacity of CO2 fracturing fluid and core damage by CO2 fracturing fluid by varying the temperature, pressure, and level of injection of the novel thickener and explored the thickening mechanism for this thickener in CO2. Based on the study results, as the temperature, pressure, and amount of injected thickener increased, fracturing fluid viscosity increased steadily. In the case of shearing for 125 min under conditions of 170 S−1, 40°C, and 20 MPa, when the thickener level increased from 1% to 2%, fracturing fluid viscosity increased and then decreased, varying within 50–150 mPa·s, and the viscosity-enhancing effect was evident; under conditions of 20°C and 12 MPa, as the flow rate increased, drag reduction efficiency reached 78.3% and the minimal proppant settling speed was 0.09 m/s; under conditions of 40°C and 20 MPa, drag reduction efficiency reached 77.4% and the proppant settling speed was 0.08 m/s; with the increases in temperature, pressure, and injection amount, core damage rates of the thickener varied within 1.77%–2.88%, indicating that basically no damage occurred. This study is of significant importance to the development of CO2 viscosity enhancers and CO2 fracturing operation.


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## Body

## 1. Introduction

Research on CO2 dry fracturing technology has been carried out in the world in the past years. Dry CO2 fracturing technology is more advantageous than conventional hydraulic fracturing technology in that dry CO2 is water-free and residue-free and flows back more quickly; however, in fracturing practice, liquid CO2 has such problems as high frictional drag and low proppant-carrying efficiency. To address this issue, we have to add a thickener into CO2 fracturing fluid. Based on the systematic analysis of the current situation of CO2 thickeners worldwide, CO2 thickeners can be divided into fluorinated, siloxane, and hydrocarbon thickeners. Huang et al. [1] obtained polymer polyFAST by copolymerization between styrene and fluorinated acrylate, its CO2 thickening effect was good, the solubility of polymer polyFAST in CO2 decreased with increasing polymer molecular weight, and when n(styrene) : n(fluorinated styrene) is about 3 : 7, the prepared copolymer had the best CO2 thickening effect. But fluorinated polymers do not apply to real production due to great environmental hazard and high cost; Shi et al. [2] prepared a thickener for dense CO2 and found that, at thickener concentrations of 2%–4%, the viscosity of liquid CO2 increased by a factor of 2–3. Cui et al. [3] developed a surfactant-based thickener for liquid CO2 and simulated the liquid CO2 thickening process by rheological testing. As the surfactant formed micelles in liquid CO2, the viscosity of liquid CO2 increased by a factor of about 86–216 and the maximum viscosity was 21.6 mPa·s. Shen et al. [4] synthesized a polyvinyl acetate telomere through free radical polymerization catalyzed by azodiisobutyronitrile (AIBN) and then the telomere underwent polymerization reaction with styrene to generate a binary copolymer, followed by molecular structure characterization by FTIR and HNMR. The styrene–vinyl acetate copolymer itself has CO2-philic groups and styrene thickening groups, and thus, in theory, it can become a high-performance low-cost thickener that is friendly to the environment and causes little damage to the rock core. Bae and Irani [5] prepared a silicon-containing polymer from a siloxane and methane and studied its impact on liquid CO2 viscosity. The study shows that the viscosity of a mixture of 4% silicon-containing polymer+20%toluene+76% CO2 was 1.2 mPa·s; thus, the viscosity of liquid CO2 increased by a factor of 30, but to thicken liquid CO2 with the polymer, a great amount of toluene has to be added; thus, excessive cosolvent consumption leads to poor economics, making the wide application impossible. In summary, even though varieties of CO2 thickeners have been developed to date, slow dissolution, need of a cosolvent, insignificant viscosity-enhancing effect, environmental pollution of fluorinated thickeners, and other major issues are still present. In contrast, the hydrophobic long-chain ester thickener synthesized in this study, upon dissolution in liquid CO2, exhibits essential properties of a dry fracturing fluid, eliminating the need of any cosolvent; at room temperature, the novel thickener at a concentration of 1.0%–3.0%, if fully stirred, can be directly dispersed and dissolved in 3 min and viscosity enhancement is evident, with the viscosity varying within 50–150 mPa·s; after dissolution of the thickener, the resulting viscoelastic fluid exhibits good dynamic proppant-carrying capacity, with a proppant concentration of up to 30%, its shear thinning behavior is good, with frictional drag reduction efficiency of over 70%, and its core damage range is 1.77%–2.88%, indicating that it is basically pollution free.


## 2. Experimental

### 2.1. Materials

#### 2.1.1. Thickener Samples

The hydrophobic long-chain ester thickener was synthesized from the following chemicals: oil-soluble solvents (petroleum ether and white mineral oil), CO2-philic solvent (propylene carbonate), highly CO2-philic monomer (allylmethyl carbonate), structural monomers (styrene, and stearyl acrylate), viscosity-enhancing monomers (methyl methacrylate, and methyl acrylate), dissolution-assisting monomers (n-propyl vinyl ether, and ethyl propenyl ether), oil-soluble chain transfer agents (dodecyl mercaptan and butyl mercaptan), and oil-soluble initiator (azobisisobutyronitrile). The old thickener sample, fluoroacrylate-styrene copolymer (code Znj01, supplied by Jilin Oilfield), is a white single-phase fluid product classified as a modified fluorinated polymer.


#### 2.1.2. Gas Sample

Carbon dioxide, purity 99.99%, was from Wuhan Xinxing Gas Co. Ltd.


#### 2.1.3. Proppant Sample

A novel low-density ceramsite was selected as the proppant, its particle size isф0.3–0.6 mm or 20–40 mesh, and its bulk density is 1.33 g/cm3.


#### 2.1.4. Experimental Cores

Each of the natural long cores to be used in the experiment was jointed by a few short cores, a single fracture was artificially crafted on each core, and basic physical parameters of these cores are shown in Table1.Table 1
Natural short core-related physical parameters.
No.Length (cm)Diameter (cm)Permeability (mD)Porosity (%)Mean porosity (%)Mean permeability (mD)1#6.6642.3260.693814.0815.720.77582#6.5082.3280.760815.623#6.7562.3280.771315.114#7.1562.3260.788416.485#6.1882.3260.864817.34


### 2.2. Experimental Equipment

A HAAKE RS6000 rheometer, frictional drag test apparatus for CO2 fracturing fluid, visual high-temperature and high-pressure PVT test system, leak-off and damage test apparatus for CO2 fracturing fluid, visual dissolubility and dispersibility test apparatus for CO2, and pco.dimax cs1 high-power microscope were used.


### 2.3. Methodology

#### 2.3.1. Synthesis of the Hydrophobic Long-Chain Ester Thickener

The hydrophobic long-chain ester thickener was prepared from oil-soluble solvents (10%–15%) and CO2-philic solvent (45%–65%) as reaction solvents, highly CO2-philic monomer (1%–3%), structural monomers (3%–5%), viscosity-enhancing monomers (15%–20%), dissolution-assisting monomers (5%–10%) as copolymerization monomers, oil-soluble chain transfer agents (0.5%–1%), and the oil-soluble initiator (0.5%–1%), wherein all the contents are on a mass basis. After completion of the reaction, the resulting copolymer was directly dissolved in the CO2-philic solvents and the oil-soluble solvent without separation, removal, and other posttreatment processes, making its preparation convenient. The preparation procedure is detailed as follows: (1) adding solvents: while the reactor temperature was kept at 35°C, 18 g of petroleum ether, 18 g of white mineral oil, and 194.1 g of propylene carbonate were added successively into the reactor; (2) adding copolymerization monomers: while stirring was kept in the reactor, 3 g of allylmethyl carbonate, 6 g of styrene, 6 g of strearyl acrylate, 12 g of methyl methacrylate, 24 g of methyl acrylate, 9 g of n-propyl vinyl ether, and 6 g of ethyl propylene ether were added in turn such that the monomers were completely dissolved; and (3) adding the initiator and the chain transfer agents: 1.5 g of azobisisobutyronitrile was added to initiate polymerization reaction for 2 h, then, 1.2 g of dodecyl mercaptan and 1.2 g of butyl mercaptan were added, the reactor was closed and heated to 100°C, followed by 8 h isothermal reaction, and the internal pressure of the reactor was controlled throughout the process to be up to 0.4 MPa. After reaction completion, cooling water was circulated in the reactor jacket to lower the temperature to 30°C, resulting in white emulsion in the reactor; the emulsion was pumped into a plastic bucket to obtain the hydrophobic long-chain ester thickener, which is the novel thickener for site application experiment mentioned in Section 5.2.


#### 2.3.2. Viscosity Test

A rheology test method for CO2 fracturing fluid was established using a HAAKE RS6000 rheometer: viscosities of liquid/supercritical CO2 fracturing fluids at variable concentrations were determined after shearing at 170 S−1 for 125 min, the viscosity-enhancing effect of the viscosity enhancer was evaluated, and rheological behavior and viscosity variability patterns of CO2 fracturing fluids under different influential factors were analyzed. Variations in rheological properties of the fluid under different conditions could be detected using a high-temperature closed system, and the fluid temperature/shear resistance test and pressure versus viscosity relationship test could be performed [6, 7]. Specifically, a liquid CO2 tank is fully filled with pressurized liquid (supercritical) CO2 for layer use. A thicker sample at a preset test concentration was put into a mixing tank which was then closed. Thereafter, liquid (supercritical) CO2 was introduced into the mixing tank till a preset volume. The stirrer was turned on such that the thickener became fully dissolved. The well-dissolved dry fracturing fluid was introduced into the measuring cylinder of the rheometer and sheared at preset temperature, pressure, and shear rate until being stable before data saving.


#### 2.3.3. Frictional Drag Test

On a CO2 fracturing fluid frictional drag test apparatus, differential pressures of liquid/supercritical CO2 fracturing fluids in the pipeline subject to thickener addition were determined by high-pressure long-tube flow differential pressure test, where the high-pressure long tube was 10 m long and 10 mm in diameter. And drag reduction efficiency was calculated using Dr=ΔP1−ΔP2/ΔP1×100% (Dr is the drag reduction efficiency, ΔP1 is the differential pressure of neat liquid CO2 when passing through the long tube, and ΔP2 is the differential pressure of CO2 fracturing fluid fed with the novel thickener when passing through the long tube). In this experiment, at 20°C/12 MPa and 40°C/20 MPa, drag reduction efficiencies of the fluid fed with the thickener at different concentrations at variable flow rates were determined [8].


#### 2.3.4. Proppant-Carrying Capacity Test

Assisted by a high-temperature high-pressure visual PVT experimental system, this experiment studies the settling patterns of the proppant in liquid and supercritical CO2 fracturing fluids, determines settling speeds of the proppant in liquid and supercritical CO2 fracturing fluids versus thickener concentration and proppant concentration as well as their variability patterns, and analyzes the settling speed of the proppant in each CO2 fracturing fluid. On a proppant settling test apparatus, the experiment was carried out according to a procedure detailed as follows:
(1)
Fill the thickener at a volume ratio into an autoclave and put the ceramsite on top of the visual autoclave(2)
Heat the autoclave by a water bath surrounding it such that a desired test temperature is achieved(3)
Open the CO2 cylinder and fill CO2 into the autoclave via an air compressor such that within-reactor pressure reaches a desired pressure(4)
Set the stirrer speed to 1000 rpm such that the thickener can be fully dissolved in CO2(5)
Rotate the manual ball releaser on top of the autoclave such that the ceramsite falls inside the autoclave and record the ceramsite settling time(6)
Calculate ceramsite settling speed


#### 2.3.5. Core Damage Test

The long core leak-off damage evaluation test was performed on a CO2 fracturing fluid leak-off damage test apparatus, and leak-off quantity Q, leak-off coefficient C, and leak-off velocity V were used to explore the leak-off behavior of liquid/supercritical CO2 fracturing fluids; by substituting permeability values prior to and after damage of the experimental core into core damage rate calculation formula Dd=K1−K2/K1×100% (predamage and postdamage permeability values are K1 and K2 mD, respectively), the core damage rate can be obtained [9]; hence, the degree of core damage of the CO2 fracturing fluid was evaluated by the fracturing fluid performance evaluation method according to SY/T 5107-1995 National Standards for Oil and Gas Industry in the People’s Republic of China (see the flowchart of the apparatus operation in Figure 1).Figure 1
Flowchart of the damage test apparatus for CO2 fracturing fluid.


#### 2.3.6. Explorative Test on the Thickening Mechanism

The visual carbon dioxide dissolution dispersion test apparatus and pco.dimax cs1 high-power microscope were employed to observe the dissolution and dispersion state of the viscosity enhancer in liquid/supercritical CO2 fluids, and the CO2 fracturing fluid thickening mechanism was discussed according to the solvent-solute molecular dissolution theory [10].


## 2.1. Materials

### 2.1.1. Thickener Samples

The hydrophobic long-chain ester thickener was synthesized from the following chemicals: oil-soluble solvents (petroleum ether and white mineral oil), CO2-philic solvent (propylene carbonate), highly CO2-philic monomer (allylmethyl carbonate), structural monomers (styrene, and stearyl acrylate), viscosity-enhancing monomers (methyl methacrylate, and methyl acrylate), dissolution-assisting monomers (n-propyl vinyl ether, and ethyl propenyl ether), oil-soluble chain transfer agents (dodecyl mercaptan and butyl mercaptan), and oil-soluble initiator (azobisisobutyronitrile). The old thickener sample, fluoroacrylate-styrene copolymer (code Znj01, supplied by Jilin Oilfield), is a white single-phase fluid product classified as a modified fluorinated polymer.


### 2.1.2. Gas Sample

Carbon dioxide, purity 99.99%, was from Wuhan Xinxing Gas Co. Ltd.


### 2.1.3. Proppant Sample

A novel low-density ceramsite was selected as the proppant, its particle size isф0.3–0.6 mm or 20–40 mesh, and its bulk density is 1.33 g/cm3.


### 2.1.4. Experimental Cores

Each of the natural long cores to be used in the experiment was jointed by a few short cores, a single fracture was artificially crafted on each core, and basic physical parameters of these cores are shown in Table1.Table 1
Natural short core-related physical parameters.
No.Length (cm)Diameter (cm)Permeability (mD)Porosity (%)Mean porosity (%)Mean permeability (mD)1#6.6642.3260.693814.0815.720.77582#6.5082.3280.760815.623#6.7562.3280.771315.114#7.1562.3260.788416.485#6.1882.3260.864817.34


## 2.1.1. Thickener Samples

The hydrophobic long-chain ester thickener was synthesized from the following chemicals: oil-soluble solvents (petroleum ether and white mineral oil), CO2-philic solvent (propylene carbonate), highly CO2-philic monomer (allylmethyl carbonate), structural monomers (styrene, and stearyl acrylate), viscosity-enhancing monomers (methyl methacrylate, and methyl acrylate), dissolution-assisting monomers (n-propyl vinyl ether, and ethyl propenyl ether), oil-soluble chain transfer agents (dodecyl mercaptan and butyl mercaptan), and oil-soluble initiator (azobisisobutyronitrile). The old thickener sample, fluoroacrylate-styrene copolymer (code Znj01, supplied by Jilin Oilfield), is a white single-phase fluid product classified as a modified fluorinated polymer.


## 2.1.2. Gas Sample

Carbon dioxide, purity 99.99%, was from Wuhan Xinxing Gas Co. Ltd.


## 2.1.3. Proppant Sample

A novel low-density ceramsite was selected as the proppant, its particle size isф0.3–0.6 mm or 20–40 mesh, and its bulk density is 1.33 g/cm3.


## 2.1.4. Experimental Cores

Each of the natural long cores to be used in the experiment was jointed by a few short cores, a single fracture was artificially crafted on each core, and basic physical parameters of these cores are shown in Table1.Table 1
Natural short core-related physical parameters.
No.Length (cm)Diameter (cm)Permeability (mD)Porosity (%)Mean porosity (%)Mean permeability (mD)1#6.6642.3260.693814.0815.720.77582#6.5082.3280.760815.623#6.7562.3280.771315.114#7.1562.3260.788416.485#6.1882.3260.864817.34


## 2.2. Experimental Equipment

A HAAKE RS6000 rheometer, frictional drag test apparatus for CO2 fracturing fluid, visual high-temperature and high-pressure PVT test system, leak-off and damage test apparatus for CO2 fracturing fluid, visual dissolubility and dispersibility test apparatus for CO2, and pco.dimax cs1 high-power microscope were used.


## 2.3. Methodology

### 2.3.1. Synthesis of the Hydrophobic Long-Chain Ester Thickener

The hydrophobic long-chain ester thickener was prepared from oil-soluble solvents (10%–15%) and CO2-philic solvent (45%–65%) as reaction solvents, highly CO2-philic monomer (1%–3%), structural monomers (3%–5%), viscosity-enhancing monomers (15%–20%), dissolution-assisting monomers (5%–10%) as copolymerization monomers, oil-soluble chain transfer agents (0.5%–1%), and the oil-soluble initiator (0.5%–1%), wherein all the contents are on a mass basis. After completion of the reaction, the resulting copolymer was directly dissolved in the CO2-philic solvents and the oil-soluble solvent without separation, removal, and other posttreatment processes, making its preparation convenient. The preparation procedure is detailed as follows: (1) adding solvents: while the reactor temperature was kept at 35°C, 18 g of petroleum ether, 18 g of white mineral oil, and 194.1 g of propylene carbonate were added successively into the reactor; (2) adding copolymerization monomers: while stirring was kept in the reactor, 3 g of allylmethyl carbonate, 6 g of styrene, 6 g of strearyl acrylate, 12 g of methyl methacrylate, 24 g of methyl acrylate, 9 g of n-propyl vinyl ether, and 6 g of ethyl propylene ether were added in turn such that the monomers were completely dissolved; and (3) adding the initiator and the chain transfer agents: 1.5 g of azobisisobutyronitrile was added to initiate polymerization reaction for 2 h, then, 1.2 g of dodecyl mercaptan and 1.2 g of butyl mercaptan were added, the reactor was closed and heated to 100°C, followed by 8 h isothermal reaction, and the internal pressure of the reactor was controlled throughout the process to be up to 0.4 MPa. After reaction completion, cooling water was circulated in the reactor jacket to lower the temperature to 30°C, resulting in white emulsion in the reactor; the emulsion was pumped into a plastic bucket to obtain the hydrophobic long-chain ester thickener, which is the novel thickener for site application experiment mentioned in Section 5.2.


### 2.3.2. Viscosity Test

A rheology test method for CO2 fracturing fluid was established using a HAAKE RS6000 rheometer: viscosities of liquid/supercritical CO2 fracturing fluids at variable concentrations were determined after shearing at 170 S−1 for 125 min, the viscosity-enhancing effect of the viscosity enhancer was evaluated, and rheological behavior and viscosity variability patterns of CO2 fracturing fluids under different influential factors were analyzed. Variations in rheological properties of the fluid under different conditions could be detected using a high-temperature closed system, and the fluid temperature/shear resistance test and pressure versus viscosity relationship test could be performed [6, 7]. Specifically, a liquid CO2 tank is fully filled with pressurized liquid (supercritical) CO2 for layer use. A thicker sample at a preset test concentration was put into a mixing tank which was then closed. Thereafter, liquid (supercritical) CO2 was introduced into the mixing tank till a preset volume. The stirrer was turned on such that the thickener became fully dissolved. The well-dissolved dry fracturing fluid was introduced into the measuring cylinder of the rheometer and sheared at preset temperature, pressure, and shear rate until being stable before data saving.


### 2.3.3. Frictional Drag Test

On a CO2 fracturing fluid frictional drag test apparatus, differential pressures of liquid/supercritical CO2 fracturing fluids in the pipeline subject to thickener addition were determined by high-pressure long-tube flow differential pressure test, where the high-pressure long tube was 10 m long and 10 mm in diameter. And drag reduction efficiency was calculated using Dr=ΔP1−ΔP2/ΔP1×100% (Dr is the drag reduction efficiency, ΔP1 is the differential pressure of neat liquid CO2 when passing through the long tube, and ΔP2 is the differential pressure of CO2 fracturing fluid fed with the novel thickener when passing through the long tube). In this experiment, at 20°C/12 MPa and 40°C/20 MPa, drag reduction efficiencies of the fluid fed with the thickener at different concentrations at variable flow rates were determined [8].


### 2.3.4. Proppant-Carrying Capacity Test

Assisted by a high-temperature high-pressure visual PVT experimental system, this experiment studies the settling patterns of the proppant in liquid and supercritical CO2 fracturing fluids, determines settling speeds of the proppant in liquid and supercritical CO2 fracturing fluids versus thickener concentration and proppant concentration as well as their variability patterns, and analyzes the settling speed of the proppant in each CO2 fracturing fluid. On a proppant settling test apparatus, the experiment was carried out according to a procedure detailed as follows:
(1)
Fill the thickener at a volume ratio into an autoclave and put the ceramsite on top of the visual autoclave(2)
Heat the autoclave by a water bath surrounding it such that a desired test temperature is achieved(3)
Open the CO2 cylinder and fill CO2 into the autoclave via an air compressor such that within-reactor pressure reaches a desired pressure(4)
Set the stirrer speed to 1000 rpm such that the thickener can be fully dissolved in CO2(5)
Rotate the manual ball releaser on top of the autoclave such that the ceramsite falls inside the autoclave and record the ceramsite settling time(6)
Calculate ceramsite settling speed


### 2.3.5. Core Damage Test

The long core leak-off damage evaluation test was performed on a CO2 fracturing fluid leak-off damage test apparatus, and leak-off quantity Q, leak-off coefficient C, and leak-off velocity V were used to explore the leak-off behavior of liquid/supercritical CO2 fracturing fluids; by substituting permeability values prior to and after damage of the experimental core into core damage rate calculation formula Dd=K1−K2/K1×100% (predamage and postdamage permeability values are K1 and K2 mD, respectively), the core damage rate can be obtained [9]; hence, the degree of core damage of the CO2 fracturing fluid was evaluated by the fracturing fluid performance evaluation method according to SY/T 5107-1995 National Standards for Oil and Gas Industry in the People’s Republic of China (see the flowchart of the apparatus operation in Figure 1).Figure 1
Flowchart of the damage test apparatus for CO2 fracturing fluid.


### 2.3.6. Explorative Test on the Thickening Mechanism

The visual carbon dioxide dissolution dispersion test apparatus and pco.dimax cs1 high-power microscope were employed to observe the dissolution and dispersion state of the viscosity enhancer in liquid/supercritical CO2 fluids, and the CO2 fracturing fluid thickening mechanism was discussed according to the solvent-solute molecular dissolution theory [10].


## 2.3.1. Synthesis of the Hydrophobic Long-Chain Ester Thickener

The hydrophobic long-chain ester thickener was prepared from oil-soluble solvents (10%–15%) and CO2-philic solvent (45%–65%) as reaction solvents, highly CO2-philic monomer (1%–3%), structural monomers (3%–5%), viscosity-enhancing monomers (15%–20%), dissolution-assisting monomers (5%–10%) as copolymerization monomers, oil-soluble chain transfer agents (0.5%–1%), and the oil-soluble initiator (0.5%–1%), wherein all the contents are on a mass basis. After completion of the reaction, the resulting copolymer was directly dissolved in the CO2-philic solvents and the oil-soluble solvent without separation, removal, and other posttreatment processes, making its preparation convenient. The preparation procedure is detailed as follows: (1) adding solvents: while the reactor temperature was kept at 35°C, 18 g of petroleum ether, 18 g of white mineral oil, and 194.1 g of propylene carbonate were added successively into the reactor; (2) adding copolymerization monomers: while stirring was kept in the reactor, 3 g of allylmethyl carbonate, 6 g of styrene, 6 g of strearyl acrylate, 12 g of methyl methacrylate, 24 g of methyl acrylate, 9 g of n-propyl vinyl ether, and 6 g of ethyl propylene ether were added in turn such that the monomers were completely dissolved; and (3) adding the initiator and the chain transfer agents: 1.5 g of azobisisobutyronitrile was added to initiate polymerization reaction for 2 h, then, 1.2 g of dodecyl mercaptan and 1.2 g of butyl mercaptan were added, the reactor was closed and heated to 100°C, followed by 8 h isothermal reaction, and the internal pressure of the reactor was controlled throughout the process to be up to 0.4 MPa. After reaction completion, cooling water was circulated in the reactor jacket to lower the temperature to 30°C, resulting in white emulsion in the reactor; the emulsion was pumped into a plastic bucket to obtain the hydrophobic long-chain ester thickener, which is the novel thickener for site application experiment mentioned in Section 5.2.


## 2.3.2. Viscosity Test

A rheology test method for CO2 fracturing fluid was established using a HAAKE RS6000 rheometer: viscosities of liquid/supercritical CO2 fracturing fluids at variable concentrations were determined after shearing at 170 S−1 for 125 min, the viscosity-enhancing effect of the viscosity enhancer was evaluated, and rheological behavior and viscosity variability patterns of CO2 fracturing fluids under different influential factors were analyzed. Variations in rheological properties of the fluid under different conditions could be detected using a high-temperature closed system, and the fluid temperature/shear resistance test and pressure versus viscosity relationship test could be performed [6, 7]. Specifically, a liquid CO2 tank is fully filled with pressurized liquid (supercritical) CO2 for layer use. A thicker sample at a preset test concentration was put into a mixing tank which was then closed. Thereafter, liquid (supercritical) CO2 was introduced into the mixing tank till a preset volume. The stirrer was turned on such that the thickener became fully dissolved. The well-dissolved dry fracturing fluid was introduced into the measuring cylinder of the rheometer and sheared at preset temperature, pressure, and shear rate until being stable before data saving.


## 2.3.3. Frictional Drag Test

On a CO2 fracturing fluid frictional drag test apparatus, differential pressures of liquid/supercritical CO2 fracturing fluids in the pipeline subject to thickener addition were determined by high-pressure long-tube flow differential pressure test, where the high-pressure long tube was 10 m long and 10 mm in diameter. And drag reduction efficiency was calculated using Dr=ΔP1−ΔP2/ΔP1×100% (Dr is the drag reduction efficiency, ΔP1 is the differential pressure of neat liquid CO2 when passing through the long tube, and ΔP2 is the differential pressure of CO2 fracturing fluid fed with the novel thickener when passing through the long tube). In this experiment, at 20°C/12 MPa and 40°C/20 MPa, drag reduction efficiencies of the fluid fed with the thickener at different concentrations at variable flow rates were determined [8].


## 2.3.4. Proppant-Carrying Capacity Test

Assisted by a high-temperature high-pressure visual PVT experimental system, this experiment studies the settling patterns of the proppant in liquid and supercritical CO2 fracturing fluids, determines settling speeds of the proppant in liquid and supercritical CO2 fracturing fluids versus thickener concentration and proppant concentration as well as their variability patterns, and analyzes the settling speed of the proppant in each CO2 fracturing fluid. On a proppant settling test apparatus, the experiment was carried out according to a procedure detailed as follows:
(1)
Fill the thickener at a volume ratio into an autoclave and put the ceramsite on top of the visual autoclave(2)
Heat the autoclave by a water bath surrounding it such that a desired test temperature is achieved(3)
Open the CO2 cylinder and fill CO2 into the autoclave via an air compressor such that within-reactor pressure reaches a desired pressure(4)
Set the stirrer speed to 1000 rpm such that the thickener can be fully dissolved in CO2(5)
Rotate the manual ball releaser on top of the autoclave such that the ceramsite falls inside the autoclave and record the ceramsite settling time(6)
Calculate ceramsite settling speed


## 2.3.5. Core Damage Test

The long core leak-off damage evaluation test was performed on a CO2 fracturing fluid leak-off damage test apparatus, and leak-off quantity Q, leak-off coefficient C, and leak-off velocity V were used to explore the leak-off behavior of liquid/supercritical CO2 fracturing fluids; by substituting permeability values prior to and after damage of the experimental core into core damage rate calculation formula Dd=K1−K2/K1×100% (predamage and postdamage permeability values are K1 and K2 mD, respectively), the core damage rate can be obtained [9]; hence, the degree of core damage of the CO2 fracturing fluid was evaluated by the fracturing fluid performance evaluation method according to SY/T 5107-1995 National Standards for Oil and Gas Industry in the People’s Republic of China (see the flowchart of the apparatus operation in Figure 1).Figure 1
Flowchart of the damage test apparatus for CO2 fracturing fluid.


## 2.3.6. Explorative Test on the Thickening Mechanism

The visual carbon dioxide dissolution dispersion test apparatus and pco.dimax cs1 high-power microscope were employed to observe the dissolution and dispersion state of the viscosity enhancer in liquid/supercritical CO2 fluids, and the CO2 fracturing fluid thickening mechanism was discussed according to the solvent-solute molecular dissolution theory [10].


## 3. Results and Discussion

### 3.1. Results of the Viscosity Test

Thickener concentration versus CO2 viscosity curves and fracturing fluid viscosity versus shear time curves at variable concentrations of the thickener in the fluid were obtained by the HAAKE RS6000 rheometer.As shown in Figure2, CO2 fluid at 20°C/8 MPa was in a liquid state, while at 40°C/15 MPa and 45°C/7.5 MPa, CO2 fluid was in a supercritical state, as the injection concentration of the thickener increased, the viscosities of both liquid CO2 and supercritical CO2 fracturing fluids tended to increase; in particular, when the thickener injection concentration was greater than 1.2%, the viscosity of liquid CO2 fracturing fluid was always greater than that of supercritical CO2 fracturing fluid. As shown in Figures 3–5, at 40°C/20 MPa, when thickener concentration was 1.0%, the viscosity of CO2 fracturing fluid tended to increase and then decrease over time and remained at 30 mPa·s or so at 30 min till the end of experiment; likewise, when thickener concentration increased to 1.5%, the viscosity remained at 60 mPa·s or so over time; when thickener concentration increased to 2%, the maximum fracturing fluid viscosity was 140 mPa·s, and at the later stage of the experiment, the viscosity decreasing trend was shown but overall viscosity was greater than 100 mPa·s. After shearing at 170 s−1 for 125 min, this thickener remained highly stable and had good viscosity-enhancing effect, indicating strong temperature/shear resistance. Given a constant temperature, viscosity of CO2 fracturing fluid increased with increasing pressure, indicating that pressure variation has indeed significant impact on viscosity of CO2 fracturing fluid and pressure increase leads to more violent momentum exchange between thickener molecule and CO2 molecule and higher density of CO2 fluid such that thickener solute becomes more soluble in CO2, further increasing viscosity of the fracturing fluid system. Therefore, increasing the thickener concentration and test pressure has important impact on the increase in viscosity of liquid or supercritical CO2 [11].Figure 2
Curves of thickener concentration versus CO2 viscosity.Figure 3
Curve of viscosity versus shear time at a thickener concentration of 1%.Figure 4
Viscosity versus shear time curve at a thickener concentration of 1.5%.Figure 5
Curve of viscosity versus shear time at a thickener concentration of 2.0%.


### 3.2. Results of Frictional Drag Test

On a frictional drag test apparatus for CO2 fracturing fluid, the high-pressure long-tube flow differential pressure test was conducted to determine differential pressures of CO2 fracturing fluid in a pipeline subject to thickener addition and a formula for drag reduction efficiency calculation was used to obtain drag reduction efficiency; then, drag reduction efficiency versus flow rate curves at 20°C/12 MPa and 40°C/20 MPa was obtained through data analysis.As can be seen in Figures6 and 7, with the increases in the flow rate and concentration of injected thickener, drag reduction efficiency increased significantly. Given a constant temperature, frictional drag coefficient increased gradually with increasing pressure because higher pressure leads to smaller intermolecular distance and stronger friction force. When the temperature, pressure, and pipe diameter were constant, the faster the flow rate of the fluid in pipeline, the greater the degree of turbulence and the friction loss and drag reduction effect became more significant at higher Reynolds numbers. As temperature and pressure varied, drag reduction efficiency of the thickener ranged within 59.1%–78.3%. When thickener concentration was 2% and flow rate was above 2.0 m/s, drag reduction efficiency reached 78.3%.Figure 6
Flow rate versus drag reduction efficiency at 20°C/12 MPa.Figure 7
Flow rate versus drag reduction efficiency at 40°C/20 MPa.


### 3.3. Results of the Proppant-Carrying Capacity Test

Settling times and settling speeds of single-particle proppant and the proppant at a proppant concentration of 5% in liquid/supercritical CO2 fracturing fluids were determined by a proppant settling test apparatus, as shown in Tables 2 and 3.Table 2
Settling speeds of single-particle proppant in CO2 fracturing fluids.
SystemTemperature (°C)Pressure (MPa)Amount of injected thickener (%)Settling time (s)Settling speed (m/s)Liquid CO220800.471.34Thickener+liquid CO22081.03.120.202081.54.850.132082.07.040.09Supercritical CO2401500.621.02Thickener+supercritical CO240151.04.170.1540151.55.730.1140152.07.880.08Table 3
Settling speeds of proppant at 5% proppant concentration in CO2 fracturing fluids.
SystemTemperature (°C)Pressure (MPa)Amount of injected thickener (%)Settling time (s)Settling speed (m/s)Liquid CO220800.640.98Thickener+liquid CO22081.03.940.162081.55.710.112082.07.830.08Supercritical CO2401500.850.74Thickener+supercritical CO240151.05.250.1240151.56.920.0940152.08.940.07As inferred in Tables2 and 3, supercritical CO2 is generally superior to liquid CO2 in proppant-carrying capacity: in the case of a single-particle proppant, the minimum settling speed in liquid CO2 was 0.09 m/s while the minimum settling speed in supercritical CO2 was 0.08 m/s; in the case of 5% proppant concentration, the minimum settling speed in liquid CO2 was 0.08 m/s while the minimum settling speed in supercritical CO2 was 0.07 m/s, because the hydrophobic long-chain ester thickener dissolved in CO2 is markedly viscoelastic and thus has excellent proppant-carrying capacity. Given a constant amount of the injected thickener, increases in temperature and pressure enabled higher fracturing fluid viscosity such that the proppant settling speed became slower. In comparison with single-particle settling, the proppant settling speed at 5% proppant concentration was lower than the free single-particle settling speed due to intermolecular interference and the single-particle settling will cause upward flow of the surrounding liquid which impedes the surrounding fluid from sinking; thus a greater drag will be present at a proppant concentration of 5% and the increase in proppant concentration is, in fact, equivalent to increases in proppant buoyancy and settling drag, manifested as a slower settling speed [12].


### 3.4. Core Damage Evaluation

The long core leak-off and damage test was carried out on a CO2 fracturing fluid leak-off and damage test apparatus at a temperature of 55°C and a pressure of 14 MPa. The core leak-off performance of CO2 fracturing fluid is shown in Table 4, the parameters of damage evaluation of fracturing fluid are shown in Table 5, and the core damage performance of the CO2 fracturing fluid was shown in Table 6.Table 4
Core leak-off performance of CO2 fracturing fluid.
Temperature (°C)Pressure (MPa)Mean permeability (mD)Fracturing fluid systemLeak-off coefficient (10−2 m/min0.5)Leak-off velocity (m·min−1)Cumulative leak-off quantity (mL)45100.7758CO25.3280.0371124645100.7758Thickener+CO21.7280.0128175Table 5
Parameters of damage evaluation of fracturing fluid.
Fracturing fluid damage rate (%)NoneWeakModerately weakModerately strongStrongDegree of damageDd <55<Dd≤3030<Dd≤5050<Dd≤7070<DdTable 6
Core damage performance of CO2 fracturing fluid.
Fracturing fluid systemTemperature (°C)Pressure (MPa)Amount injected (%)PermeabilityK1 (mD)PermeabilityK2 (mD)Core damage rateDd (%)Degree of damageThickener+CO22081.00.4530.4451.77Nil2081.50.4470.4382.01Nil2082.00.4490.4372.67Nil40151.00.4420.4341.81Nil40151.50.4560.4452.41Nil40152.00.4520.4392.88NilAs shown in Table4, under the condition of 45°C/10 MPa, the leak-off velocity of supercritical CO2 fluid in the long core was 0.037 m·min−1, while the leak-off velocity of supercritical CO2 fracturing fluid containing a 1.5% viscosity enhancer injected into the long core was 0.012 m·min−1, and in comparison, the leak-off coefficient of CO2 fracturing fluid into which the viscosity enhancer was injected was markedly lower than that of pure CO2 fluid, indicating that this viscosity enhancer reduces the leak-off property of supercritical CO2 fluid to some extent. As CO2 fluid is residue free, no filter cake will be formed at the front end of the core in a long core leak-off test, indicating a greater leak-off coefficient and a faster leak-off velocity; after a thickener was incorporated, the CO2 fracturing fluid will form gradually flocculent filter cakes at the front end of the rock core, resulting in lower leak-off coefficient, indicating that CO2 fluid incorporated with a thickener has pronounced effect of leak-off reduction after entering fractures and thus ensures fracture forming efficiency of a fracturing fluid. And in Table 6, where core damage rate Dd was calculated by substituting the leak-off coefficient into the calculation formula for Dd, it can be found that the CO2 thickener had low core damage rates ranging within 1.81%–2.88%, and in comparison with the core damage criteria for fracturing fluids in Table 5, its damage to the rock core is almost negligible; moreover, CO2 is slightly soluble in water and readily soluble in the in-place oil; therefore, the thickened CO2 fracturing fluid system would be well compatible with the formation.


## 3.1. Results of the Viscosity Test

Thickener concentration versus CO2 viscosity curves and fracturing fluid viscosity versus shear time curves at variable concentrations of the thickener in the fluid were obtained by the HAAKE RS6000 rheometer.As shown in Figure2, CO2 fluid at 20°C/8 MPa was in a liquid state, while at 40°C/15 MPa and 45°C/7.5 MPa, CO2 fluid was in a supercritical state, as the injection concentration of the thickener increased, the viscosities of both liquid CO2 and supercritical CO2 fracturing fluids tended to increase; in particular, when the thickener injection concentration was greater than 1.2%, the viscosity of liquid CO2 fracturing fluid was always greater than that of supercritical CO2 fracturing fluid. As shown in Figures 3–5, at 40°C/20 MPa, when thickener concentration was 1.0%, the viscosity of CO2 fracturing fluid tended to increase and then decrease over time and remained at 30 mPa·s or so at 30 min till the end of experiment; likewise, when thickener concentration increased to 1.5%, the viscosity remained at 60 mPa·s or so over time; when thickener concentration increased to 2%, the maximum fracturing fluid viscosity was 140 mPa·s, and at the later stage of the experiment, the viscosity decreasing trend was shown but overall viscosity was greater than 100 mPa·s. After shearing at 170 s−1 for 125 min, this thickener remained highly stable and had good viscosity-enhancing effect, indicating strong temperature/shear resistance. Given a constant temperature, viscosity of CO2 fracturing fluid increased with increasing pressure, indicating that pressure variation has indeed significant impact on viscosity of CO2 fracturing fluid and pressure increase leads to more violent momentum exchange between thickener molecule and CO2 molecule and higher density of CO2 fluid such that thickener solute becomes more soluble in CO2, further increasing viscosity of the fracturing fluid system. Therefore, increasing the thickener concentration and test pressure has important impact on the increase in viscosity of liquid or supercritical CO2 [11].Figure 2
Curves of thickener concentration versus CO2 viscosity.Figure 3
Curve of viscosity versus shear time at a thickener concentration of 1%.Figure 4
Viscosity versus shear time curve at a thickener concentration of 1.5%.Figure 5
Curve of viscosity versus shear time at a thickener concentration of 2.0%.


## 3.2. Results of Frictional Drag Test

On a frictional drag test apparatus for CO2 fracturing fluid, the high-pressure long-tube flow differential pressure test was conducted to determine differential pressures of CO2 fracturing fluid in a pipeline subject to thickener addition and a formula for drag reduction efficiency calculation was used to obtain drag reduction efficiency; then, drag reduction efficiency versus flow rate curves at 20°C/12 MPa and 40°C/20 MPa was obtained through data analysis.As can be seen in Figures6 and 7, with the increases in the flow rate and concentration of injected thickener, drag reduction efficiency increased significantly. Given a constant temperature, frictional drag coefficient increased gradually with increasing pressure because higher pressure leads to smaller intermolecular distance and stronger friction force. When the temperature, pressure, and pipe diameter were constant, the faster the flow rate of the fluid in pipeline, the greater the degree of turbulence and the friction loss and drag reduction effect became more significant at higher Reynolds numbers. As temperature and pressure varied, drag reduction efficiency of the thickener ranged within 59.1%–78.3%. When thickener concentration was 2% and flow rate was above 2.0 m/s, drag reduction efficiency reached 78.3%.Figure 6
Flow rate versus drag reduction efficiency at 20°C/12 MPa.Figure 7
Flow rate versus drag reduction efficiency at 40°C/20 MPa.


## 3.3. Results of the Proppant-Carrying Capacity Test

Settling times and settling speeds of single-particle proppant and the proppant at a proppant concentration of 5% in liquid/supercritical CO2 fracturing fluids were determined by a proppant settling test apparatus, as shown in Tables 2 and 3.Table 2
Settling speeds of single-particle proppant in CO2 fracturing fluids.
SystemTemperature (°C)Pressure (MPa)Amount of injected thickener (%)Settling time (s)Settling speed (m/s)Liquid CO220800.471.34Thickener+liquid CO22081.03.120.202081.54.850.132082.07.040.09Supercritical CO2401500.621.02Thickener+supercritical CO240151.04.170.1540151.55.730.1140152.07.880.08Table 3
Settling speeds of proppant at 5% proppant concentration in CO2 fracturing fluids.
SystemTemperature (°C)Pressure (MPa)Amount of injected thickener (%)Settling time (s)Settling speed (m/s)Liquid CO220800.640.98Thickener+liquid CO22081.03.940.162081.55.710.112082.07.830.08Supercritical CO2401500.850.74Thickener+supercritical CO240151.05.250.1240151.56.920.0940152.08.940.07As inferred in Tables2 and 3, supercritical CO2 is generally superior to liquid CO2 in proppant-carrying capacity: in the case of a single-particle proppant, the minimum settling speed in liquid CO2 was 0.09 m/s while the minimum settling speed in supercritical CO2 was 0.08 m/s; in the case of 5% proppant concentration, the minimum settling speed in liquid CO2 was 0.08 m/s while the minimum settling speed in supercritical CO2 was 0.07 m/s, because the hydrophobic long-chain ester thickener dissolved in CO2 is markedly viscoelastic and thus has excellent proppant-carrying capacity. Given a constant amount of the injected thickener, increases in temperature and pressure enabled higher fracturing fluid viscosity such that the proppant settling speed became slower. In comparison with single-particle settling, the proppant settling speed at 5% proppant concentration was lower than the free single-particle settling speed due to intermolecular interference and the single-particle settling will cause upward flow of the surrounding liquid which impedes the surrounding fluid from sinking; thus a greater drag will be present at a proppant concentration of 5% and the increase in proppant concentration is, in fact, equivalent to increases in proppant buoyancy and settling drag, manifested as a slower settling speed [12].


## 3.4. Core Damage Evaluation

The long core leak-off and damage test was carried out on a CO2 fracturing fluid leak-off and damage test apparatus at a temperature of 55°C and a pressure of 14 MPa. The core leak-off performance of CO2 fracturing fluid is shown in Table 4, the parameters of damage evaluation of fracturing fluid are shown in Table 5, and the core damage performance of the CO2 fracturing fluid was shown in Table 6.Table 4
Core leak-off performance of CO2 fracturing fluid.
Temperature (°C)Pressure (MPa)Mean permeability (mD)Fracturing fluid systemLeak-off coefficient (10−2 m/min0.5)Leak-off velocity (m·min−1)Cumulative leak-off quantity (mL)45100.7758CO25.3280.0371124645100.7758Thickener+CO21.7280.0128175Table 5
Parameters of damage evaluation of fracturing fluid.
Fracturing fluid damage rate (%)NoneWeakModerately weakModerately strongStrongDegree of damageDd <55<Dd≤3030<Dd≤5050<Dd≤7070<DdTable 6
Core damage performance of CO2 fracturing fluid.
Fracturing fluid systemTemperature (°C)Pressure (MPa)Amount injected (%)PermeabilityK1 (mD)PermeabilityK2 (mD)Core damage rateDd (%)Degree of damageThickener+CO22081.00.4530.4451.77Nil2081.50.4470.4382.01Nil2082.00.4490.4372.67Nil40151.00.4420.4341.81Nil40151.50.4560.4452.41Nil40152.00.4520.4392.88NilAs shown in Table4, under the condition of 45°C/10 MPa, the leak-off velocity of supercritical CO2 fluid in the long core was 0.037 m·min−1, while the leak-off velocity of supercritical CO2 fracturing fluid containing a 1.5% viscosity enhancer injected into the long core was 0.012 m·min−1, and in comparison, the leak-off coefficient of CO2 fracturing fluid into which the viscosity enhancer was injected was markedly lower than that of pure CO2 fluid, indicating that this viscosity enhancer reduces the leak-off property of supercritical CO2 fluid to some extent. As CO2 fluid is residue free, no filter cake will be formed at the front end of the core in a long core leak-off test, indicating a greater leak-off coefficient and a faster leak-off velocity; after a thickener was incorporated, the CO2 fracturing fluid will form gradually flocculent filter cakes at the front end of the rock core, resulting in lower leak-off coefficient, indicating that CO2 fluid incorporated with a thickener has pronounced effect of leak-off reduction after entering fractures and thus ensures fracture forming efficiency of a fracturing fluid. And in Table 6, where core damage rate Dd was calculated by substituting the leak-off coefficient into the calculation formula for Dd, it can be found that the CO2 thickener had low core damage rates ranging within 1.81%–2.88%, and in comparison with the core damage criteria for fracturing fluids in Table 5, its damage to the rock core is almost negligible; moreover, CO2 is slightly soluble in water and readily soluble in the in-place oil; therefore, the thickened CO2 fracturing fluid system would be well compatible with the formation.


## 4. Discussion on the Thickening Mechanism of the Hydrophobic Long-Chain Ester Thickener in CO2 Fracturing Fluids

The dissolution and dispersion states of the viscosity enhancer in liquid/supercritical CO2 fluids were examined by visual dissolution and the dispersion test apparatus and the pco.dimax cs1 high-power microscope. The results of the sample dispersion test are shown in Table 7, and the dissolution status of the thickener in CO2 is seen in Figure 8.Table 7
Results of the sample dispersion test.
SampleTemperature (°C)Pressure (MPa)Amount of injected thickener (wt.%)Dispersion time (min)Thickener2082.0<2Thickener40152.0<2Thickener457.52.0<2Figure 8
Dissolution of the thickener in CO2.Intermolecular interactions between viscosity enhancer solute and CO2 solvent include (1) solvent-solute intermolecular interaction: solute-to-solvent aggregates will form due to strong interaction between solute and solvent molecules and (2) solvent-solvent intermolecular interaction: in highly compressible dilute supercritical fluid, apart from solvent-solute aggregates, there are solvent-solvent aggregates. Dissolution and dispersion of the hydrophobic long-chain ester thickener in CO2 were examined using a pco.dimax cs1 high-frequency microscopic camera, results of the dispersion test of the same amount of thickener injected at different temperatures and pressures are shown in Table 7, and dissolution details are seen in Figure 8. As shown in Figure 8, the hydrophobic long-chain ester thickener dissolves instantly in CO2; at a thickener concentration of 2%, it can be directly dispersed and dissolved in CO2 in less than 2 min, so it is readily dispersible and soluble in liquid CO2 and supercritical CO2. In terms of synthetic composition, propylene carbonate is a CO2-philic solvent, white mineral oil and petroleum ether are oil-soluble solvents, allylmethyl carbonate is a strong CO2-philic monomer, and ethyl propenyl ether and n-propyl vinyl ether are cosolvent monomers, while methyl acrylate and methyl methacrylate are viscosity-enhancing monomers. When the thickener is dissolved in CO2, it can be quickly dispersed and dissolved due to effects of the CO2-philic solvent and oil-soluble solvents, as the copolymer components have been directly dissolved in the CO2-philic and oil-soluble solvents first, making the polymeric molecular chains prestretched, and during dissolution, the viscosity-enhancing groups on the molecular chains dissolve to enhance viscosity, meanwhile multiple association effects between them and intramolecular and intermolecular structural groups via the hydrogen bond and dispersion force as well as Lewis acid-base reaction contribute to structural viscosity; thereby, the viscosity-enhancing effect is greatly increased [13–18].


## 5. Site Application

### 5.1. Basic Geology of Experimental Well

Well Hong 87-X is located at block M in oilfield J. This block is in the southern part of the Rangzijing structure in the central depression area of the southern Songliao Basin, neighboring the Gudian reverse fault of the Fuxin uplift zone in the east and SW-dipping slope zone of the Xinli structure in the north, and the slope zone is subjected to regional compressive torsional stress and forms a NNW-trending fold zone associated with a number of fault zones parallel axially to the fold zone. The oil reservoir belongs to the fault rock-type oil reservoir in the setting of the westward-dipping slope. The bed of interest is 3300 m deep, the reservoir temperature is 104°C, the gradient of formation pressure is 0.9 MPa/100 m, the calculated Poisson’s ratios of the reservoir are 0.20–0.22, the Young’s moduli of the reservoir are (2.74–2.82)×104MPa, and the closure pressure was 35.4 MPa. The in-place oil has a density of 0.826 t/m3, a viscosity of 5.60 mPa·s, original saturation pressure of 5.1 MPa, a volume coefficient of 1.076, and original solution gas-oil ratio of 27 m3/m3. And porosity values of the pay bed are generally 6.0%–12.0%, averaging 8.7%; permeability values of the pay bed are generally 0.06–2.0 mD, averaging 0.15 mD. In general, the reservoir is characterized in low porosity and ultralow permeability. The reservoir lithology is dominated by greyish-brown siltstone and fine sandstone, mainly including lithic arkose or feldspathic litharenite. Particle sizes of the rocks are generally 0.03–0.25 mm, and the clay mineral content is 14.2%.


### 5.2. Site Operation Process

The fracturing operation of Well Hong 87-X in block M of oilfield J with old thickener Znj01 did not get desirable effect. Later, the CO2 dry fracturing operation with the novel thickener was conducted, where 835 m3 of liquid CO2 was consumed, ceramsite of 20–40 mm in the size was chosen as the proppant, pumping rates were 5.2–8.2 m3/min, proppant loading was 9 m3, proppant concentration was 4%, operation pressures were 21–37 MPa, and pump-shutoff pressure was 20.8 MPa. Prior to operation, the pipeline was circulated with CO2 to test the pressure, ensuring that all the CO2-related lines are free of liquid buildup; the ratio of liquid CO2 to the thickener was kept at 100 : 1; the prepad fluid volume and proppant transport program were adjusted based on the results of the prefracturing test; the site should support continuous proppant loading and continuous liquid supply. Figure 9 shows the dry fracturing operation curve of Well Hong 87-X.Figure 9
Dry fracturing operation curve of Well Hong 87-X.


### 5.3. Operation Effect Analysis

Based on the comparison between Figures10 and 11, in the case of the novel thickener, at the stage of proppant loading, the pumping rate was 5.2 m3/min while proppant concentrations were 3%, 4.5%, 5.8%, and 8%, respectively, and after entering the reservoir, stable pressure and superior proppant-carrying capacity were noted; in the case of the old thickener Znj01, the pumping rate was 5 m3/min and the proppant concentration was 2.5% at the stage of proppant loading, and after entering the formation, the pressure surged and eventually led to sand plug. Given the equivalent pumping rate, compared with the old thickener, the novel thickener had more stable proppant-carrying capacity during proppant loading. As a result of the site application, when the old thickener was used, the daily oil output of this well was up to 3.86 t; while after the novel thickener was used, the maximum daily oil output reached 7.4 t, with an increment of 3.54 t.Figure 10
Curves of fracturing with the new thickener for Well Hong 87-X at pumping rates of 5–5.2 m3/min.Figure 11
Curves of fracturing with old thickener Znj01 for Well Hong 87-X at pumping rates of 4.8–5.1 m3/min.


## 5.1. Basic Geology of Experimental Well

Well Hong 87-X is located at block M in oilfield J. This block is in the southern part of the Rangzijing structure in the central depression area of the southern Songliao Basin, neighboring the Gudian reverse fault of the Fuxin uplift zone in the east and SW-dipping slope zone of the Xinli structure in the north, and the slope zone is subjected to regional compressive torsional stress and forms a NNW-trending fold zone associated with a number of fault zones parallel axially to the fold zone. The oil reservoir belongs to the fault rock-type oil reservoir in the setting of the westward-dipping slope. The bed of interest is 3300 m deep, the reservoir temperature is 104°C, the gradient of formation pressure is 0.9 MPa/100 m, the calculated Poisson’s ratios of the reservoir are 0.20–0.22, the Young’s moduli of the reservoir are (2.74–2.82)×104MPa, and the closure pressure was 35.4 MPa. The in-place oil has a density of 0.826 t/m3, a viscosity of 5.60 mPa·s, original saturation pressure of 5.1 MPa, a volume coefficient of 1.076, and original solution gas-oil ratio of 27 m3/m3. And porosity values of the pay bed are generally 6.0%–12.0%, averaging 8.7%; permeability values of the pay bed are generally 0.06–2.0 mD, averaging 0.15 mD. In general, the reservoir is characterized in low porosity and ultralow permeability. The reservoir lithology is dominated by greyish-brown siltstone and fine sandstone, mainly including lithic arkose or feldspathic litharenite. Particle sizes of the rocks are generally 0.03–0.25 mm, and the clay mineral content is 14.2%.


## 5.2. Site Operation Process

The fracturing operation of Well Hong 87-X in block M of oilfield J with old thickener Znj01 did not get desirable effect. Later, the CO2 dry fracturing operation with the novel thickener was conducted, where 835 m3 of liquid CO2 was consumed, ceramsite of 20–40 mm in the size was chosen as the proppant, pumping rates were 5.2–8.2 m3/min, proppant loading was 9 m3, proppant concentration was 4%, operation pressures were 21–37 MPa, and pump-shutoff pressure was 20.8 MPa. Prior to operation, the pipeline was circulated with CO2 to test the pressure, ensuring that all the CO2-related lines are free of liquid buildup; the ratio of liquid CO2 to the thickener was kept at 100 : 1; the prepad fluid volume and proppant transport program were adjusted based on the results of the prefracturing test; the site should support continuous proppant loading and continuous liquid supply. Figure 9 shows the dry fracturing operation curve of Well Hong 87-X.Figure 9
Dry fracturing operation curve of Well Hong 87-X.


## 5.3. Operation Effect Analysis

Based on the comparison between Figures10 and 11, in the case of the novel thickener, at the stage of proppant loading, the pumping rate was 5.2 m3/min while proppant concentrations were 3%, 4.5%, 5.8%, and 8%, respectively, and after entering the reservoir, stable pressure and superior proppant-carrying capacity were noted; in the case of the old thickener Znj01, the pumping rate was 5 m3/min and the proppant concentration was 2.5% at the stage of proppant loading, and after entering the formation, the pressure surged and eventually led to sand plug. Given the equivalent pumping rate, compared with the old thickener, the novel thickener had more stable proppant-carrying capacity during proppant loading. As a result of the site application, when the old thickener was used, the daily oil output of this well was up to 3.86 t; while after the novel thickener was used, the maximum daily oil output reached 7.4 t, with an increment of 3.54 t.Figure 10
Curves of fracturing with the new thickener for Well Hong 87-X at pumping rates of 5–5.2 m3/min.Figure 11
Curves of fracturing with old thickener Znj01 for Well Hong 87-X at pumping rates of 4.8–5.1 m3/min.


## 6. Conclusions

(1)
The novel hydrophobic long-chain ester thickener synthesized in this study is a linear block copolymer supplied in the form of white emulsion with a molecular weight ranging within about 500,000–800,000. Based on performance testing, its density was 1.05 g/cm3 and its pH was 7.5; the thickener at 2.0 wt% could be dissolved in liquid CO2 in 3 min to form a fracturing fluid at a viscosity of 80 mPa·s, and its drag reduction efficiency was 78.3%(2)
The viscosity-enhancing effect, frictional drag, proppant-carrying capacity, and core damage of the novel thickener in CO2 fracturing fluid were experimentally determined, and the thickening mechanism of this novel thickener in CO2 was discussed. As a result, with the increase in the amount of the injected thickener, the viscosity of CO2 fracturing fluid increased gradually, and when the concentration of the injected thickener was greater than 2%, the viscosity-enhancing effect in liquid CO2 fracturing fluid was superior to that in supercritical CO2 fracturing fluid; the drag reduction effect was notable when the thickener concentration was 2.0% and the flow rate of the fracturing fluid was more than 2.0 m/s. The thickener, if dissolved in CO2, could form multiorder structures and become significantly viscoelastic, resulting in higher viscosity; thus, it has excellent proppant-carrying capacity. After the novel thickener was added into CO2 fracturing fluid, the maximum core damage rate was 2.88%, which is negligible(3)
After CO2 dry fracturing of Well Hong 87-X in oilfield J using the novel thickener, the fracturing effect was remarkable and the oil output of the well was substantially elevated; given the equivalent pumping rate, compared with the old thickener, the novel thickener had more stable proppant-carrying capacity during proppant loading, indicating that the novel thickener has better effect of viscosity enhancing and proppant carrying; moreover, the CO2 dry fracturing technology is of significant importance to CO2 sequestration and the reduction of greenhouse gas emission; it increases the oil output and protects the environment as well, resulting in a win-win situation in line with the China national strategy of “carbon peak and carbon neutralization”



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