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A new organic fiber composite gel as a plugging agent for assisting CO2 huff and puff in water channeling reservoirs
Journal of Petroleum Science and Engineering 179 (2019) 70–79
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A new organic fiber composite gel as a plugging agent for assisting CO2 huff and puff in water channeling reservoirs
T
Qingjun Dua,b, Jian Houa,b,∗, Fan Zhaoa,b, Kang Zhoua,b, Wenbin Liua,b, Yongge Liua,b a b
Key Laboratory of Unconventional Oil & Gas Development (China University of Petroleum (East China)), Ministry of Education, Qingdao, 266580, P.R. China School of Petroleum Engineering, China University of Petroleum (East China), Qingdao, 266580, P.R. China
ARTICLE INFO
ABSTRACT
Keywords: CO2 utilization ratio Organic fiber composite gel Water channeling reservoir Real rock plate experiment Numerical simulation
The utilization of CO2 for enhancing oil recovery is an environmentally friendly way to dispose the industrial CO2 emissions. CO2 utilization ratio is defined as the volume ratio of produced oil to injected CO2. CO2 huff and puff technology can further improve oil recovery in high water cut reservoirs. However, as the huff and puff cycle increase, gas channeling is easy to happen and the utilization ratio of CO2 is reduced. Organic fiber composite gel is an effective plugging agent for gas channel. The major objective of this paper is to study the mechanisms of increasing CO2 utilization by injecting organic composite gel as the plugging agent. A large scale (40 cm*40 cm*3 cm) natural rock model with grooves is used to simulate the experimental conditions such as channeling channel and horizontal well. Two groups of experiments of direct CO2 huff and plugging agent assisted CO2 huff and puff were conducted. By comparing the pressure changes during the experiments, the mechanism of blocking the channel, balancing the CO2 displacement front and improving the utilization ratio of CO2 were analyzed. The experimental process was fitted by reservoir numerical simulation, and the remaining oil distribution, plugging agent distribution and CO2 distribution in CO2 huff and puff under different conditions were further demonstrated. Results show that compared with direct CO2 stimulation, the distribution of remaining oil saturation and reservoir pressure become more uniform and the utilization ratio of CO2 is greatly increased after injecting organic fiber composite gel. It is mainly due to the fact that the injected plugging agents flow preferentially into high water saturation region along the high permeability channels. Then, they can generate the organic fiber composite gel and remain in the channeling paths. As a result, the following injected CO2 will be forced to flow towards oil-rich regions radially and uniformly. Thereby, more CO2 can contact and react with the in-situ oil, resulting much higher oil recovery. In other words, the utilization ratio of CO2 is greatly improved. Taking Jidong oilfield as an example, it has been injected 19.2 × 104 t CO2 with the total oil production by 21.1 × 104 t. The utilization ratio of CO2 is calculated as high as 1.09. The observations of this study provide the theoretical basis for future application of organic fiber composite gel before CO2 flooding in the water channeling reservoirs.
1. Introduction 1.1. CO2 capture and utilization China is in a critical period of industrialization and urbanization, and the energy consumption and carbon emissions caused by economic development have attracted widespread attention both at home and abroad (Wei et al., 2006, 2015). CO2 capture and storage technology are an effective method to reduce CO2 emission (Li et al., 2009). Due to the high cost, there are few real examples of direct implementation of CO2 buried technology in the world. The application of industrial CO2
emissions in oilfield production can not only increase the oil recovery, but also realize the recycling of CO2. Tangshan, China where the Jidong Oilfield is located, is an important steel industry base in China. In 2017, China's steel production amounted to 831.7 × 106 tons, accounting for 49.2% of global crude steel production, of which one-seventh was produced from Tangshan. Steelmaking needs to burn large amounts of coke and produce large amounts of CO2 gas. According to the average emission intensity of 2.2 t (CO2)/t (steel) in China's iron and steel enterprises, Tangshan produced 261.4 × 106 tons of CO2 gas in 2017, and if it is discharged into the air directly, it will cause serious pollution. If the CO2 gas produced by Tangshan City iron and steel enterprises can
∗ Corresponding author. Key Laboratory of Unconventional Oil & Gas Development (China University of Petroleum (East China)), Ministry of Education, Qingdao, 266580, P.R. China. E-mail address: [email protected] (J. Hou).
https://doi.org/10.1016/j.petrol.2019.04.034 Received 5 November 2017; Received in revised form 9 April 2019; Accepted 10 April 2019 Available online 16 April 2019 0920-4105/ © 2019 Elsevier B.V. All rights reserved.
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be efficiently utilized in developing Jidong Oilfield, it will have an important economic and social benefits.
during the process of production in oil well. Since 2010, CO2 stimulation technology has been implemented in horizontal wells to enhance oil recovery. However, due to the existence of high-permeability water channeling, CO2 will flow along the channeling in the injection stage, resulting in a small contact area between CO2 and crude oil, a low crude oil output and a low CO2 utilization ratio. CO2 utilization ratio, defined as the volume ratio of produced oil to injected CO2, is an important parameter to evaluate the effect of CO2 on enhancing oil recovery (Ma et al., 2015). In the practical application of the oilfield, the organic fiber composite gel is used as the plugging agent in order to improve CO2 utilization ratio. The gel system is generated by mixing viscoelastic plugging agent and organic fiber composite gel. Thereby, it has the advantages of generalizability, high strength and environmental friendliness. Before the formation of gel, the fluid viscosity and injection resistance coefficient are low, but its residual resistance coefficient becomes higher after the formation of gel. It is suitable to be injected into the channeling-path to plug the formation, which will improve the CO2 utilization ratio (Li et al., 2016b; Abdulbaki et al., 2014). According to the development situation, this paper uses physical simulation to evaluate the plugging effect of plugging agent and to provide the plugging performance parameters for numerical simulation. Based on the results from history matching physical simulation, the numerical simulation is used to understand the mechanisms and influence factors of enhancing CO2 stimulation performance using organic fiber composite gel plugging agent by comparing the distribution of remaining oil saturation after water flooding, CO2 stimulation and plugging agent assisted CO2 stimulation, the position of CO2 dissolved in oil and plugging agent, etc. This technology has been applied in oilfield successfully.
1.2. CO2 utilization in increasing oil recovery At present, a certain amount of CO2 gas is generally injected into the oil layer by stimulation technology (Yang et al., 2015; Liu et al., 2018a; Tharanivasan et al., 2006; Yang and Gu, 2006; Firouz, 2011). After mixing CO2 with crude oil, the viscosity of crude oil is reduced and the formation pressure is increased, which thus increases the production of the crude oil. Many scholars have done a lot of basic research on CO2 utilization (Liu et al., 2018b; Sun et al., 2016; Yu et al., 2015; Zhang et al., 2015; Li et al., 2016a; Abedini and Torabi, 2014; Zhao et al., 2016; Sanchez-Rivera et al., 2015; Huang et al., 2019). CO2 stimulation as a technology to enhance oil recovery has been successfully used in many countries (Sun et al., 2016; Ma et al., 2015, 2016; Lv et al., 2015; Tang et al., 2016; Wang et al., 2016). However, CO2 huff and puff technology is mainly used in tight and low-permeability reservoirs as well as light oil reservoirs. For tight and low-permeability reservoirs, CO2 huff and puff generally combines horizontal well and fracturing technology to increase oil production (Yang and Gu, 2006). The diffusion coefficient of CO2 in low-permeability reservoirs is one of the important factors. Many scholars have carried out experimental study on CO2 diffusion coefficient in low-permeability reservoirs (Liu et al., 2018b; Sun et al., 2016). Daniel Sanchez-Rivera built a numerical reservoir model to optimize the CO2 huff and puff parameters (SanchezRivera et al., 2015). For light-oil reservoirs, CO2 huff and puff technology is mainly used to increase oil production by achieving oil miscibility. Although CO2 huff and puff technology has been successfully applied in low-permeability and light-oil reservoirs, the reservoir conditions are worse in China, and the permeability heterogeneity of reservoir is strong, the viscosity of crude oil is high. In the process of CO2 huff and puff, gas channeling is easy to occur. The utilization ratio of CO2 decreases with the increase of cycle huff and puff. Taking the Ng12 reservoir in North Gaoqian area of Jidong Oilfield as an example, viscosity of the underground oil is as high as 90 mPa s, the depth of oil is 1895m, the original formation pressure is 18200 kPa, and the average permeability is 1527.5 × 10−3μm2. In the process of oilfield development, the oil field is driven by edge water and produced by horizontal well. Due to the loosening of reservoir sandstone cementation and the long-term erosion of the edge water, a large number of high-permeability water channeling are formed in the reservoir between the edge water area and the horizontal production well. The permeability contrast is as high as 5 to 40, resulting in a rapid increase in the water cut
2. Physical experiment 2.1. Physical model and apparatus The two-dimensional real rock plate model is used to conduct the experiments, which employs the plugging agent to improve the CO2 utilization ratio in water channeling reservoir. The experimental procedures are shown in Fig. 1. This model has the following advantages: ① The large-scale (40 cm × 40 cm × 3 cm) model can simulate the characteristics of the actual reservoirs by groove model, such as the dominant seepage channels, horizontal wells and edge water driving. ② Compared with the common sand-packing model, the pore throat structure, wettability, sensitivity and other properties are more conform to the real formation conditions by using the real rock sample model. ③
Fig. 1. Experimental apparatus. 71
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Using the high temperature and high pressure resistant colloidal material to pack the plate model can realize the simulation of high pressure and high temperature environment, which can better reflect the mechanism of CO2 dissolution, viscosity reduction, and expansion. The rock samples were collected from the outcrop of Zigong of China. They were cut into 40 cm × 40 cm × 3 cm square plate models. Each gap with the depth of 1.5 cm is cut in the two opposite sides. One is connected with the water injection pipeline for simulating the edge water driving; the other is connected to CO2 injection pipeline and plugging agent pipeline for simulating the horizontal well production and plugging agent assisted CO2 stimulation. As shown in Fig. 1, two grooves with the length of 10 cm and the depth of 1.5 cm are cut at points C and D, which are perpendicular to the two gaps of the plate model. The plate model is encapsulated by high temperature and high pressure resistant colloidal material to prevent leakage of fluid inside the rock during displacement. The plate model is evenly distributed with 21 pressure sensors for recording the change of pressure at different positions during the experiments. The encapsulated plate model is placed in a specially designed large rock holder. The rock holder can resist pressures up to 40000 kPa and temperatures 50 °C. It can establish the required environment for the experiment through the internal circulation of high-temperature and high-pressure fluid. The constant pressure and speed pump are used to drive different intermediate containers to inject fluid into the flat plate model. CO2 gas cylinder is used to supply gas source. The constant pressure pump is used to provide the back pressure at the outlet. During the experiment, pressure changes at each pressure point on the flat model are monitored continuously and the volume of injected and produced fluid are recorded.
Pr =
kw
kd kd
× 100%
(1)
where Pr is the plugging rate; kw is the core permeability of water flooding; kd is the core permeability after plugging. 2.3. Procedures According to the experimental processes as shown in Fig. 1, the paper carried out direct CO2 stimulation and plugging agent assisted CO2 stimulation experiment in water channeling reservoirs. This work compares the plugging channeling and increasing oil performance of the two experimental plugging agents. The steps are listed as follows: (1) Make a three-dimensional real rock model, and switch in the experimental processes after encapsulation. During the experiments, the experimental temperature was kept at 50 °C. (2) Vacuum the plate model from point B and inject standard saline from point A and make the rock saturated, then measure the permeability and porosity of the rock. Inject crude oil to displace formation water from point A, then calculate initial oil saturation after saturated crude oil. (3) Edge water flooding experiment. Keep the rock holder confining pressure at 18000 kPa, simulate the process of horizontal well production by injecting water at 0.7 mL/min from point A and producing from point B. Close the output pipeline until water cut of the produced fluid reaches 90%. Measure the volume of oil and water during the experiment. (4) Direct CO2 stimulation experiment (# 1). Keep the injection pressure at 18000 kPa, inject CO2 into the model from the point B, and keep the constant pressure for 1 h, then produce fluids from point B (outlet pressure is 0) and measure the volume of oil and water. Repeat the experiment for 3 cycles. (5) Plugging agent assisted CO2 stimulation experiment (# 2). Make three-dimensional real rock model again, switch in the experimental process after encapsulation, and perform the experimental steps (2)–(3). Then inject the prepared organic fiber composite gel from point C at a constant pressure of 1000 kPa, and stop the injection after producing 20 mL fluid from point D. In the experiment, about 38.5 mL gel agent are injected to the rock model. Simulate the injection of the overflush fluid and clean the horizontal wellbore by injecting water from point D and producing fluid from point A. Stand for 48 h until the gel coagulation, then carry out the CO2 stimulation experiment like step (4).
2.2. Materials 2.2.1. Oil and gas The experimental crude oil is degassed oil obtained from the Ng12 reservoir in North Gaoqian area of Jidong Oilfield. The viscosity of the crude oil was 400 mPa s, and the molecular weight was 251.89 g/mol. CO2 is industrial waste gas obtained from a steel enterprise in Tangshan, and its purity is 99.9% after purification. 2.2.2. Rock The experimental rock is taken from the outcrop of Zigong. The average permeability is about 410 × 10−3μm2, and the porosity is about 0.16. 2.2.3. Brine and plugging agent In order to prevent water sensitivity, 10000 ppm standard brine is used as the experimental water. The organic fiber composite gel applied in Jidong Oilfield is used as the experimental plugging agent. Its chemical composition is organic fiber particle ATS + cross-linking agent JL + stabilizer TJ, and the gelling time is 48 h. The plugging agent has three characteristics: ① In the non-gel injection stage, the fluid viscosity is low (3–10 mPa s) and the resistance coefficient is small (2–5). Therefore, it is ready to be injected into the channeling position of the larger level difference formation. It will not block the near wellbore area and thus doesn't affect the follow-up crude oil production. ② Complex chemical reaction will occur between the three kinds of chemical agents after the gel system reaches the predetermined position and enters the standing stage. The reaction can generate some fibrous material, of which the viscosity is up to 8000 mPa s, the residual resistance coefficient is as high as 15–30 and the plugging rate (defined as the degree of reduction in core permeability after plugging, as in Equation (1)) is more than 95%. ③ The generated gel system has good viscoelasticity and strong scour resistance. It is difficult to be extracted during CO2 flowback, and it can still effectively block channeling in the subsequent huff and puff cycle.
3. Numerical simulation 3.1. Reservoir modelling parameters In order to further study the incremental oil mechanism of the plugging agent assisted CO2 stimulation, the paper uses the reservoir numerical simulation technology to match the experimental results and determine the performance parameters of plugging agent. Then the paper studies the mechanisms and influence factors of enhancing oil production and increasing CO2 utilization ratio using organic fiber gel plugging agent in CO2 stimulation projects by analyzing the distribution of remaining oil saturation and the molar concentration of dissolved CO2 in crude oil. The numerical simulation is carried out by using the STARS module (Version 2012, Computer, Modelling, Group, Ltd.). A 20 × 20 × 1 grid system is established, and the mesh size is 2 cm × 2 cm × 3 cm. In the same position of the physical model, the numerical simulation sets up at the high-permeability zone and carries out refinement at grids where the well point and high-permeability zone locates, as shown in Fig. 2. Other reservoir and fluid parameters are shown in Table 1. 72
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Fig. 4. Effect of CO2 molar concentration on oil viscosity.
CO2.
Fig. 2. Mesh and permeability distribution.
3.3. Organic fiber composite gel parameters
Table 1 Characteristic parameters of simulation model. Property
Value
Initial pressure (kPa) Crude oil density (g/cm3) Crude oil viscosity (mPa·s) Crude oil compressibility (1/kPa) Water density (g/cm3) Water viscosity (mPa·s) Water compressibility (1/kPa) Rock compressibility (1/kPa)
18000 0.956 400 5.12 × 10−7 1.0 0.45 1.0 × 10−6 4.4 × 10−7
After the organic fiber particles ATS and the cross-linking agent JL are injected into the formation, the organic fiber composite chemical agent is formed after a period of chemical reaction under the effect of stabilizers TJ. It is in the fibrous solid state and can plug high-permeability sites. Organic fiber composite gels reduce fluid channeling through two mechanisms: ① Improve the effective viscosity and reduce the effective permeability of aqueous solution. The resistance coefficient (RF) is defined as the ratio of the seepage pressure gradient of the organic fiber composite gel solution to that of the pure water in the injection process. The residual resistance coefficient (RRF) is defined as the ratio of the seepage pressure gradient after generating organic fiber composite gel to that of the pure water in order to characterize the reduction of water effective permeability in the channeling path during the output stage of CO2 stimulation. ② Decrease the gas relative permeability and inhibit the flow of CO2 gas to the high-permeability channels. The reduction coefficient of gas phase permeability Rg is defined to characterize the reduction degree of gas phase permeability after gel formation. As in Equation (1), krg is the gas relative permeability with gel and krg0 is the gas relative permeability without gel.
3.2. Phase equilibrium parameters The paper uses the Winprop module (Version 2012, Computer Modelling Group Ltd.) to match the crude oil phase of the G104-5 fault block in North Gaoqian area, and then determines the characteristics of crude oil and the change of physical properties after CO2 dissolution. According to the results, the primary contact miscibility pressure of CO2 is 82.3 MPa, and CO2 huff and puff processes are immiscible flooding process. The parameters of relative volume and viscosity can be used to characterize the effect of CO2 on crude oil. The relative volume is defined as the ratio of the crude oil volume after CO2 dissolution to the degassed oil volume under the same temperature and the same pressure. The effects of injecting different molar concentrations of CO2 on the relative volume and viscosity of the crude oil are indicated in Fig. 3 and Fig. 4. The relative volume of crude oil expands rapidly with the decrease of pressure, and it is larger with the increase of the molar concentration of CO2; the viscosity of crude oil decreases greatly with the increase of CO2 molar concentration. The results show that the crude oil of target block is suitable for studies on improving crude oil production using the solution, expansion and viscosity reduction of
(2)
krg = kkr 0 × Rg
The resistance coefficient of the organic fiber composite gel is 3 and the residual resistance coefficient is 20. The gas-liquid relative permeability curve is shown in Fig. 5.
Fig. 3. Effect of CO2 molar concentration on relative volume.
Fig. 5. Relative permeability curve. 73
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4. Results and discussion
cumulative recovery percentage of the three cycles increases by only 3.4%; as for the plugging agent assisted CO2 stimulation in the experiment # 2, the recovery percentage increases significantly in all of the three cycles. The numerical simulation results are basically consistent with the experimental results, and the fitting performance of oil recovery percentage is good. A little difference exists between the fitting curves in the second cycle of the plugging agent assisted CO2 stimulation experiment. It may be due to many factors including the distribution of plugging agent in the rock, the control style differences between experiment and numerical simulation, or the gel parameters of simulation.
4.1. Experimental results and numerical simulation fitting The oil recovery percentage is the ratio of the volume of produced crude oil to the total volume of crude oil saturated in the rock. CO2 utilization ratio, defined as the volume ratio of produced oil to injected CO2, is a crucial economic indicator for evaluating whether an operation is successful or not (Ma et al., 2015). 4.1.1. Fitting results The experimental results of direct CO2 stimulation and plugging agent assisted CO2 stimulation are shown in Table 2. The established numerical simulation model is used to simulate the CO2 stimulation experiment # 1 and # 2 conducted on the plate model. The initial pressure is 18000 kPa, and the oil saturation is 0.79 and 0.67. The injection well is injected at a constant injection rate. The injection rate is 0.7 mL/min and the maximum injection pressure is 18500 kPa. The production well is produced with constant bottom hole flow pressure of 18000 kPa. After the water cut of production well reaches 90%, the production well carries out 3 cycles of direct CO2 stimulation and plugging agent assisted CO2 stimulation. In the experiment # 2, 0.05 PV of organic fiber composite gel solution is injected.
4.1.2. CO2 utilization ratio The comparison result of the CO2 injection volume and CO2 utilization ratio in each cycle of the two experiments are shown in Table 2 and Fig. 7. In the experiment # 1, CO2 gas is injected directly after water flooding. Only 28 mL of CO2 gas is injected in the first cycle. The oil production at this stage is 9.5 mL, and the oil recovery percentage at this stage is 1.6%. This is mainly because the viscosity of the crude oil is high, the water channeling is formed between the high permeability channels (groove) at the stage of water flooding, and the remaining oil saturation is low. Under the effect of constant pressure, the injected CO2 flows mainly along the water channeling, the remaining oil saturation
Table 2 Summary of the experiment of CO2 huff and puff. No.
Porosity (f)
Permeability ( × 10−3μm2)
Oil saturation (f)
Stage
CO2 volume (mL)
Produced Oil volume (mL)
Stage oil recovery (%)
#1
0.160
410
0.79
#2
0.158
410
0.67
Water flooding 1st cycle 2nd cycle 3rd cycle Water flooding 1st cycle 2nd cycle 3rd cycle
– 28 36 76 – 30.65 68 89.8
111.4 9.5 5.4 5.2 73.6 37.5 66.9 62.9
18.4 1.6 0.9 0.9 15.3 7.8 13.9 13.1
CO2 utilization (mL/ mL) 0.34 0.18 0.06 1.22 0.74 0.7
The fitting results on the change of oil recovery percentage with time between physical experiment and numerical simulation are shown in Fig. 6. It can be seen that the oil recovery percentage increases rapidly with time at the water flooding stage; at the CO2 stimulation stage of experiment # 1, the oil recovery percentage increases only in the first cycle, but it is not obvious increased in the second and third cycles, the
in CO2 sweeping region is low, and the CO2 volume dissolved in crude oil is small. Therefore, the injection volume is small, and it mainly produces light components in the production stage. With the increase of the CO2 stimulation cycles, the remaining oil is mainly composed of heavy components in the channel, and the mutual solubility with CO2 is weaker. Although the sweep region and the volume of the injected CO2
Fig. 6. The fitted results of recovery factor.
Fig. 7. The comparison of CO2 utilization and injection volume between #1 and #2.
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are increased, the CO2 utilization ratio is decreased. In the experiment # 1, although the injection volume reached 89.9 mL in the third cycle, the oil recovery percentage at this stage is only 0.9% and the CO2 utilization ratio is decreased to 0.06. After water flooding in the experiment # 2, the organic fiber gel solution is first injected into the production well. Because the viscosity of the organic fiber gel solution is far below the viscosity of crude oil, it will flow firstly to the water channeling region where the permeability is high, and the oil saturation is low, and it can thus plug in situ after gelling. The subsequent injection of CO2 will flow evenly to the horizontal segment of the CO2 stimulation well, and the remaining oil saturation will be high in the near-wellbore area. In the first cycle, after 30.65 mL CO2 is injected, the oil production is 37.5 mL, and the CO2 utilization ratio is as high as 1.22. With the increase of CO2 stimulation cycles, CO2 extends to the area farther from the production well, the CO2 sweep region increases, the injection volume increases, the oil production at this stage is higher, and the CO2 utilization ratio is above 0.7. Among the first three cycles, the oil production in the second cycle is the highest and it decreases slightly in the third cycle. The oil recovery percentage reached 50.2% after three cycles of CO2 stimulation. Compared with the experiment # 1, the CO2 utilization ratio of plugging agent assisted CO2 stimulation is much higher than that of direct CO2 stimulation in the model with high-permeability zone and water channeling formed at the water flooding stage.
curve for the experiment #1 and Experiment #2. In the Figures, the sensor position 1 is the position for water injection, and the sensor position 12 is the position for CO2 injection & production. The pressure of each sensor at the water flooding stage is low and the pressure difference is small. In the CO2 huff and puff process, the pressure of sensor of initial production is high and then decreases rapidly; the pressure of sensor 12 is the lowest and the sensor 12 is the highest. The comparison between the experiment #1 and experiment #2 shows that in the experiment #1, and the injected CO2 flow along the gas channel. The viscosity of the crude oil was high and the residual pressure in the rock was high. With the increase of the cycle numbers of CO2 huff and puff, the swept volume of CO2 increases, and the residual pressure in rock decreases. In the experiment #2, due to the plugging agent to block gas channel, the swept volume of CO2 is large, and the residual pressure in rock is lower than that in the experiment #1. Fig. 10 is the pressure distribution at different times for the first cycle of the experiments #1 and #2. In the figure, (a), (b) and (c) are the time of produced at the 1, 30 and 60 min, respectively. The pressure in the experiment #1 and experiment #2 is about 15000 kPa at the initial time of production. In the experiment #1, after 30 min of production, the average pressure decreased to about 7800 kPa, and the low-pressure region formed between grooves connected by injection well and production well. It is mainly due to the formation of gas channeling between the grooves connected by the injection and production wells during CO2 injection. In addition, because CO2 does not affect outside of the low-pressure region, crude oil is hard to flow, so the pressure is higher. After 60 min' production, the low-pressure region still exists. In the experiment #2, because the plugging agent was injected into the gas channel, the injected CO2 extends to the rock around the well and does not form a gas channel. After 60 min’ production, the low-pressure region was not formed. In addition, because the injection volume of CO2 in the experiment #1 is lower than that of the experiment #2, the viscosity of crude oil and the residual pressure is higher.
4.1.3. Pressure distribution During the experiments, 21 pressure sensors were used to measure the pressure in different parts of rock. Fig. 8 and Fig. 9 are the pressure
4.2. Mechanisms of improving CO2 utilization ratio using organic fiber composite gel In order to know the incremental oil mechanism of plugging agent assisted CO2 stimulation in mid-high permeability and high water-cut reservoirs by the results of numerical simulation, the paper simulates the development performance of three schemes based on the model with high permeability channeling. The basic model uses the experimental conditions of plugging agent assisted CO2 stimulation (the initial oil saturation is 0.67). Scheme 1: water flooding directly to the water cut of 98%; scheme 2: direct CO2 stimulation (Experiment # 1) after water flooding to the water cut of 90%; scheme 3: plugging agent assisted CO2 stimulation (Experiment # 2) after water flooding to the water cut of 90%. CO2 stimulation scheme is implemented for 3 cycles. CO2 is injected at a constant pressure of 18.5 MPa, and each cycle lasts for 60 min.
Fig. 8. Pressure curve of important sensors for Experiment # 1.
Fig. 9. Pressure curve of important sensors for Experiment # 2.
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Fig. 10. Comparison of pressure distribution at different time of CO2 stimulation (kPa).
forming water channeling paths and increasing water cut of the production well. However, because the sweep region of water flooding is small, the remaining oil is still enriched, which is far from the highpermeability zone and near the production well. Fig. 12 (b) shows the distribution of remaining oil saturation at different development stages with the direct CO2 stimulation (scheme 2). The three figures correspond to the start time of the three cycles (end of injecting CO2). The distribution of CO2 mole concentration in crude oil at different cycles are shown in Fig. 13 (a). The permeability of high-permeability zone near the production well is higher than the average permeability and the remaining oil saturation near the highpermeability zone is low, so the injected CO2 mainly flows into the high-permeability zone, which increases CO2 molar concentration in the crude oil. Due to the miscibility expansion of CO2 and crude oil, the high saturation oil wall forms and the remaining oil saturation near the production well increases. At the end of the first cycle, lots of crude oil of the high-permeability zone is produced, and the remaining oil saturation is lower than that of water flooding. In the second and the third cycles of CO2 stimulation, the injected CO2 still mainly flows along the high-permeability zone. Because of the reduction of the remaining oil saturation and the sharp decrease of injected CO2 volume, the volume of oil production is decreased. Fig. 12 (c) shows the distribution of remaining oil saturation at different development stages of the plugging agent assisted CO2 stimulation (scheme 3). And the three figures correspond respectively to the start time of the three cycles (the end time of injecting CO2). The distribution of CO2 mole concentration in crude oil at different cycles are shown in Fig. 13 (b). The concentration distribution of organic fiber composite gel plugging agent in the model at the first cycle is shown in Fig. 14. The injected plugging agents mainly flow along the high-permeability zone at the beginning of the first cycle. After standing for 48 h, the high viscosity blocking system is formed and then plugs the
The simulation results of oil production are shown in Fig. 11. The oil production during water flooding (scheme 1) is lowest and the plugging agent assisted CO2 stimulation (scheme 3) is highest for every cycle. With the increase of stimulation cycles, oil production of both water flooding and direct CO2 stimulation decreased. The oil production of plugging agent assisted CO2 stimulation is low in the first cycle and highest in the second cycle. Then, it decreases gradually in the subsequent cycles.
Fig. 11. Comparison of oil content.
Fig. 12 (a) shows the distribution of remaining oil saturation at different stages of water flooding (scheme 1). The three figures of Fig. 12 (b) - (c) correspond respectively to the start time of the first cycle, the second cycle and the third cycle in schemes 2 and 3. It can be seen that the injected water flows along the high-permeability zone and offsets to another high-permeability zone near the production well due to the effect of high permeability zone. As time goes on, the remaining oil saturation between two high-permeability zones decrease gradually,
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Fig. 12. Remaining oil saturation distribution at different stages of different schemes.
Fig. 13. CO2 mole concentration distribution in crude oil at different cycles of different schemes.
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Fig. 14. Concentration distribution of plugging agent.
Fig. 16. Daily oil production curve during CO2 expiry date of well G211-7 in Jidong Oilfield.
high-permeability zone, which inhibits the fingering during the subsequent injection of CO2, which forces the CO2 to advance evenly along the radial direction of the production well. Compared with the direct CO2 stimulation (scheme 2), the distribution range of CO2 mole concentration in crude oil is bigger in this scheme, and the volume of injected CO2 and produced oil are larger. In the second and the third cycles of the plugging agent assisted CO2 stimulation, the injected CO2 advances farther away from the production well and reduces the oil viscosity in the frontier. At the end of the production, the remaining oil saturation is reduced, and the scheme produces more crude oil than water flooding (scheme 1) and the direct CO2 stimulation (scheme 2).
flow along the channeling path. Thereby, the daily oil production reduced to 2.4 t/d and the stage cumulative oil production was only 214 t. The third cycle used the plugging agent assisted CO2 stimulation. The 75 t organic fiber composite gel was injected before the CO2 injection, and they plugged the gas channeling-path and expanded the sweep region of injected CO2. The CO2 injection increased to 500 t, the highest oil production reached about 4.3 t/d, and the stage cumulative oil production reached 535 t. Fig. 17 compares the average single well oil production of each cycle in recent years between direct CO2 stimulation and plugging agent assisted CO2 stimulation in the whole Jidong Oilfield. The average single well oil production of CO2 stimulation decreased as the stimulation cycle increased in Jidong Oilfield, which significantly
5. Field application Jidong Oilfield started the CO2 stimulation since 2010. By 2015, a cumulative total number of 568 wells have implemented and some wells have carried out five cycles. Parts of the wells, which have implemented plugging agent assisted CO2 stimulation, are shown in Fig. 15. With the increase of stimulation cycles, there has been a serious gas channeling phenomenon and the oil increment of direct CO2 stimulation declined sharply. Since 2015, Jidong Oilfield has been implemented organic fiber composite gel plugging agent assisted CO2 stimulation in some gas channeling wells. Taking the well G211-7 for example, the change of daily oil production with time in the three cycles of CO2 stimulation are collected (see Fig. 16). In the first and second cycles, the direct CO2 stimulation is used. In the third cycle, the plugging agent assisted CO2 stimulation is used. As can be seen from Fig. 15, the G211-7 wells is located in water flooding channeling path. In the first cycle of direct CO2 stimulation, the CO2 injection was 300 t, the daily oil production was 5.5 t/d and the cumulative oil production was 814 t. In the second cycle, the CO2 injection was 375 t, but they
Fig. 17. Incremental oil effect of plugging agent assisted with CO2 stimulation in Jidong Oilfield.
Fig. 15. Well location map of plugging agent assisted with CO2 stimulation in Jidong Oilfield. 78
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decreased after the third cycle. Some wells implemented plugging agent assisted CO2 stimulation since the second cycle, and the average oil production was obvious higher than that using the direct CO2 stimulation in every cycle. By the end of 2016, Jidong Oilfield had injected a total of 19.2 × 104 t CO2. The cumulative oil production is 21.1 × 104 t and the utilization ratio of CO2 reached 1.09. It has increased oil production and economic benefits at the same time of reducing CO2 emissions.
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6. Conclusions As a kind of plugging agent, organic fiber composite gel can block gas channels in CO2 injection process, increasing crude oil recovery and further improving CO2 utilization rate. Combined with the physical experiment and numerical simulation, the mechanisms of increasing oil production and CO2 utilization ratio for high-permeability reservoirs are revealed using organic fiber composite gel plugging agent assisted CO2 huff and puff. The experimental and reservoir numerical simulation results show that water flows along the high-permeability zone and the water cut rises rapidly in the water flooding process in the high-permeability zone model. If the production well implements direct CO2 huff and puff, the injected gas will break through along the high-permeability zone and channeling-path, and the sweep region is thus small. Using plugging agent assisted CO2 huff and puff, the injected plugging agent firstly seep into the high water-cut area along the highpermeability zone. Then, it can be adsorbed and retained after the gel is generated. Thereby, the injected CO2 mainly spreads uniformly along the radial direction of the production wellbore and can improve the crude oil production. The plugging agent assisted CO2 stimulation has achieved remarkable performance in Jidong Oilfield. The cumulative utilization of CO2 reached about 19.2 × 104 t, the cumulative oil production increased by 21.1 × 104 t, and the utilization ratio of CO2 reached 1.09. Acknowledgments The authors greatly appreciate the financial support of the Project supported by the National Science Foundation for Distinguished Young Scholars of China (Grant No. 51625403), the Important National Science and Technology Specific Projects of China (Grant no. 2016ZX05025-003-006), the Fundamental Research Funds for the Central Universities (Grant no. 15CX08004A). Appendix A. Supplementary data Supplementary data to this article can be found online at https:// doi.org/10.1016/j.petrol.2019.04.034. References Abdulbaki, M., Huh, C., Sepehrnoori, K., Delshad, M., Varavei, A., 2014. A critical review
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A new organic fiber composite gel as a plugging agent for assisting CO2 huff and puff in water channeling reservoirs
T
Qingjun Dua,b, Jian Houa,b,∗, Fan Zhaoa,b, Kang Zhoua,b, Wenbin Liua,b, Yongge Liua,b a b
Key Laboratory of Unconventional Oil & Gas Development (China University of Petroleum (East China)), Ministry of Education, Qingdao, 266580, P.R. China School of Petroleum Engineering, China University of Petroleum (East China), Qingdao, 266580, P.R. China
ARTICLE INFO
ABSTRACT
Keywords: CO2 utilization ratio Organic fiber composite gel Water channeling reservoir Real rock plate experiment Numerical simulation
The utilization of CO2 for enhancing oil recovery is an environmentally friendly way to dispose the industrial CO2 emissions. CO2 utilization ratio is defined as the volume ratio of produced oil to injected CO2. CO2 huff and puff technology can further improve oil recovery in high water cut reservoirs. However, as the huff and puff cycle increase, gas channeling is easy to happen and the utilization ratio of CO2 is reduced. Organic fiber composite gel is an effective plugging agent for gas channel. The major objective of this paper is to study the mechanisms of increasing CO2 utilization by injecting organic composite gel as the plugging agent. A large scale (40 cm*40 cm*3 cm) natural rock model with grooves is used to simulate the experimental conditions such as channeling channel and horizontal well. Two groups of experiments of direct CO2 huff and plugging agent assisted CO2 huff and puff were conducted. By comparing the pressure changes during the experiments, the mechanism of blocking the channel, balancing the CO2 displacement front and improving the utilization ratio of CO2 were analyzed. The experimental process was fitted by reservoir numerical simulation, and the remaining oil distribution, plugging agent distribution and CO2 distribution in CO2 huff and puff under different conditions were further demonstrated. Results show that compared with direct CO2 stimulation, the distribution of remaining oil saturation and reservoir pressure become more uniform and the utilization ratio of CO2 is greatly increased after injecting organic fiber composite gel. It is mainly due to the fact that the injected plugging agents flow preferentially into high water saturation region along the high permeability channels. Then, they can generate the organic fiber composite gel and remain in the channeling paths. As a result, the following injected CO2 will be forced to flow towards oil-rich regions radially and uniformly. Thereby, more CO2 can contact and react with the in-situ oil, resulting much higher oil recovery. In other words, the utilization ratio of CO2 is greatly improved. Taking Jidong oilfield as an example, it has been injected 19.2 × 104 t CO2 with the total oil production by 21.1 × 104 t. The utilization ratio of CO2 is calculated as high as 1.09. The observations of this study provide the theoretical basis for future application of organic fiber composite gel before CO2 flooding in the water channeling reservoirs.
1. Introduction 1.1. CO2 capture and utilization China is in a critical period of industrialization and urbanization, and the energy consumption and carbon emissions caused by economic development have attracted widespread attention both at home and abroad (Wei et al., 2006, 2015). CO2 capture and storage technology are an effective method to reduce CO2 emission (Li et al., 2009). Due to the high cost, there are few real examples of direct implementation of CO2 buried technology in the world. The application of industrial CO2
emissions in oilfield production can not only increase the oil recovery, but also realize the recycling of CO2. Tangshan, China where the Jidong Oilfield is located, is an important steel industry base in China. In 2017, China's steel production amounted to 831.7 × 106 tons, accounting for 49.2% of global crude steel production, of which one-seventh was produced from Tangshan. Steelmaking needs to burn large amounts of coke and produce large amounts of CO2 gas. According to the average emission intensity of 2.2 t (CO2)/t (steel) in China's iron and steel enterprises, Tangshan produced 261.4 × 106 tons of CO2 gas in 2017, and if it is discharged into the air directly, it will cause serious pollution. If the CO2 gas produced by Tangshan City iron and steel enterprises can
∗ Corresponding author. Key Laboratory of Unconventional Oil & Gas Development (China University of Petroleum (East China)), Ministry of Education, Qingdao, 266580, P.R. China. E-mail address: [email protected] (J. Hou).
https://doi.org/10.1016/j.petrol.2019.04.034 Received 5 November 2017; Received in revised form 9 April 2019; Accepted 10 April 2019 Available online 16 April 2019 0920-4105/ © 2019 Elsevier B.V. All rights reserved.
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be efficiently utilized in developing Jidong Oilfield, it will have an important economic and social benefits.
during the process of production in oil well. Since 2010, CO2 stimulation technology has been implemented in horizontal wells to enhance oil recovery. However, due to the existence of high-permeability water channeling, CO2 will flow along the channeling in the injection stage, resulting in a small contact area between CO2 and crude oil, a low crude oil output and a low CO2 utilization ratio. CO2 utilization ratio, defined as the volume ratio of produced oil to injected CO2, is an important parameter to evaluate the effect of CO2 on enhancing oil recovery (Ma et al., 2015). In the practical application of the oilfield, the organic fiber composite gel is used as the plugging agent in order to improve CO2 utilization ratio. The gel system is generated by mixing viscoelastic plugging agent and organic fiber composite gel. Thereby, it has the advantages of generalizability, high strength and environmental friendliness. Before the formation of gel, the fluid viscosity and injection resistance coefficient are low, but its residual resistance coefficient becomes higher after the formation of gel. It is suitable to be injected into the channeling-path to plug the formation, which will improve the CO2 utilization ratio (Li et al., 2016b; Abdulbaki et al., 2014). According to the development situation, this paper uses physical simulation to evaluate the plugging effect of plugging agent and to provide the plugging performance parameters for numerical simulation. Based on the results from history matching physical simulation, the numerical simulation is used to understand the mechanisms and influence factors of enhancing CO2 stimulation performance using organic fiber composite gel plugging agent by comparing the distribution of remaining oil saturation after water flooding, CO2 stimulation and plugging agent assisted CO2 stimulation, the position of CO2 dissolved in oil and plugging agent, etc. This technology has been applied in oilfield successfully.
1.2. CO2 utilization in increasing oil recovery At present, a certain amount of CO2 gas is generally injected into the oil layer by stimulation technology (Yang et al., 2015; Liu et al., 2018a; Tharanivasan et al., 2006; Yang and Gu, 2006; Firouz, 2011). After mixing CO2 with crude oil, the viscosity of crude oil is reduced and the formation pressure is increased, which thus increases the production of the crude oil. Many scholars have done a lot of basic research on CO2 utilization (Liu et al., 2018b; Sun et al., 2016; Yu et al., 2015; Zhang et al., 2015; Li et al., 2016a; Abedini and Torabi, 2014; Zhao et al., 2016; Sanchez-Rivera et al., 2015; Huang et al., 2019). CO2 stimulation as a technology to enhance oil recovery has been successfully used in many countries (Sun et al., 2016; Ma et al., 2015, 2016; Lv et al., 2015; Tang et al., 2016; Wang et al., 2016). However, CO2 huff and puff technology is mainly used in tight and low-permeability reservoirs as well as light oil reservoirs. For tight and low-permeability reservoirs, CO2 huff and puff generally combines horizontal well and fracturing technology to increase oil production (Yang and Gu, 2006). The diffusion coefficient of CO2 in low-permeability reservoirs is one of the important factors. Many scholars have carried out experimental study on CO2 diffusion coefficient in low-permeability reservoirs (Liu et al., 2018b; Sun et al., 2016). Daniel Sanchez-Rivera built a numerical reservoir model to optimize the CO2 huff and puff parameters (SanchezRivera et al., 2015). For light-oil reservoirs, CO2 huff and puff technology is mainly used to increase oil production by achieving oil miscibility. Although CO2 huff and puff technology has been successfully applied in low-permeability and light-oil reservoirs, the reservoir conditions are worse in China, and the permeability heterogeneity of reservoir is strong, the viscosity of crude oil is high. In the process of CO2 huff and puff, gas channeling is easy to occur. The utilization ratio of CO2 decreases with the increase of cycle huff and puff. Taking the Ng12 reservoir in North Gaoqian area of Jidong Oilfield as an example, viscosity of the underground oil is as high as 90 mPa s, the depth of oil is 1895m, the original formation pressure is 18200 kPa, and the average permeability is 1527.5 × 10−3μm2. In the process of oilfield development, the oil field is driven by edge water and produced by horizontal well. Due to the loosening of reservoir sandstone cementation and the long-term erosion of the edge water, a large number of high-permeability water channeling are formed in the reservoir between the edge water area and the horizontal production well. The permeability contrast is as high as 5 to 40, resulting in a rapid increase in the water cut
2. Physical experiment 2.1. Physical model and apparatus The two-dimensional real rock plate model is used to conduct the experiments, which employs the plugging agent to improve the CO2 utilization ratio in water channeling reservoir. The experimental procedures are shown in Fig. 1. This model has the following advantages: ① The large-scale (40 cm × 40 cm × 3 cm) model can simulate the characteristics of the actual reservoirs by groove model, such as the dominant seepage channels, horizontal wells and edge water driving. ② Compared with the common sand-packing model, the pore throat structure, wettability, sensitivity and other properties are more conform to the real formation conditions by using the real rock sample model. ③
Fig. 1. Experimental apparatus. 71
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Using the high temperature and high pressure resistant colloidal material to pack the plate model can realize the simulation of high pressure and high temperature environment, which can better reflect the mechanism of CO2 dissolution, viscosity reduction, and expansion. The rock samples were collected from the outcrop of Zigong of China. They were cut into 40 cm × 40 cm × 3 cm square plate models. Each gap with the depth of 1.5 cm is cut in the two opposite sides. One is connected with the water injection pipeline for simulating the edge water driving; the other is connected to CO2 injection pipeline and plugging agent pipeline for simulating the horizontal well production and plugging agent assisted CO2 stimulation. As shown in Fig. 1, two grooves with the length of 10 cm and the depth of 1.5 cm are cut at points C and D, which are perpendicular to the two gaps of the plate model. The plate model is encapsulated by high temperature and high pressure resistant colloidal material to prevent leakage of fluid inside the rock during displacement. The plate model is evenly distributed with 21 pressure sensors for recording the change of pressure at different positions during the experiments. The encapsulated plate model is placed in a specially designed large rock holder. The rock holder can resist pressures up to 40000 kPa and temperatures 50 °C. It can establish the required environment for the experiment through the internal circulation of high-temperature and high-pressure fluid. The constant pressure and speed pump are used to drive different intermediate containers to inject fluid into the flat plate model. CO2 gas cylinder is used to supply gas source. The constant pressure pump is used to provide the back pressure at the outlet. During the experiment, pressure changes at each pressure point on the flat model are monitored continuously and the volume of injected and produced fluid are recorded.
Pr =
kw
kd kd
× 100%
(1)
where Pr is the plugging rate; kw is the core permeability of water flooding; kd is the core permeability after plugging. 2.3. Procedures According to the experimental processes as shown in Fig. 1, the paper carried out direct CO2 stimulation and plugging agent assisted CO2 stimulation experiment in water channeling reservoirs. This work compares the plugging channeling and increasing oil performance of the two experimental plugging agents. The steps are listed as follows: (1) Make a three-dimensional real rock model, and switch in the experimental processes after encapsulation. During the experiments, the experimental temperature was kept at 50 °C. (2) Vacuum the plate model from point B and inject standard saline from point A and make the rock saturated, then measure the permeability and porosity of the rock. Inject crude oil to displace formation water from point A, then calculate initial oil saturation after saturated crude oil. (3) Edge water flooding experiment. Keep the rock holder confining pressure at 18000 kPa, simulate the process of horizontal well production by injecting water at 0.7 mL/min from point A and producing from point B. Close the output pipeline until water cut of the produced fluid reaches 90%. Measure the volume of oil and water during the experiment. (4) Direct CO2 stimulation experiment (# 1). Keep the injection pressure at 18000 kPa, inject CO2 into the model from the point B, and keep the constant pressure for 1 h, then produce fluids from point B (outlet pressure is 0) and measure the volume of oil and water. Repeat the experiment for 3 cycles. (5) Plugging agent assisted CO2 stimulation experiment (# 2). Make three-dimensional real rock model again, switch in the experimental process after encapsulation, and perform the experimental steps (2)–(3). Then inject the prepared organic fiber composite gel from point C at a constant pressure of 1000 kPa, and stop the injection after producing 20 mL fluid from point D. In the experiment, about 38.5 mL gel agent are injected to the rock model. Simulate the injection of the overflush fluid and clean the horizontal wellbore by injecting water from point D and producing fluid from point A. Stand for 48 h until the gel coagulation, then carry out the CO2 stimulation experiment like step (4).
2.2. Materials 2.2.1. Oil and gas The experimental crude oil is degassed oil obtained from the Ng12 reservoir in North Gaoqian area of Jidong Oilfield. The viscosity of the crude oil was 400 mPa s, and the molecular weight was 251.89 g/mol. CO2 is industrial waste gas obtained from a steel enterprise in Tangshan, and its purity is 99.9% after purification. 2.2.2. Rock The experimental rock is taken from the outcrop of Zigong. The average permeability is about 410 × 10−3μm2, and the porosity is about 0.16. 2.2.3. Brine and plugging agent In order to prevent water sensitivity, 10000 ppm standard brine is used as the experimental water. The organic fiber composite gel applied in Jidong Oilfield is used as the experimental plugging agent. Its chemical composition is organic fiber particle ATS + cross-linking agent JL + stabilizer TJ, and the gelling time is 48 h. The plugging agent has three characteristics: ① In the non-gel injection stage, the fluid viscosity is low (3–10 mPa s) and the resistance coefficient is small (2–5). Therefore, it is ready to be injected into the channeling position of the larger level difference formation. It will not block the near wellbore area and thus doesn't affect the follow-up crude oil production. ② Complex chemical reaction will occur between the three kinds of chemical agents after the gel system reaches the predetermined position and enters the standing stage. The reaction can generate some fibrous material, of which the viscosity is up to 8000 mPa s, the residual resistance coefficient is as high as 15–30 and the plugging rate (defined as the degree of reduction in core permeability after plugging, as in Equation (1)) is more than 95%. ③ The generated gel system has good viscoelasticity and strong scour resistance. It is difficult to be extracted during CO2 flowback, and it can still effectively block channeling in the subsequent huff and puff cycle.
3. Numerical simulation 3.1. Reservoir modelling parameters In order to further study the incremental oil mechanism of the plugging agent assisted CO2 stimulation, the paper uses the reservoir numerical simulation technology to match the experimental results and determine the performance parameters of plugging agent. Then the paper studies the mechanisms and influence factors of enhancing oil production and increasing CO2 utilization ratio using organic fiber gel plugging agent in CO2 stimulation projects by analyzing the distribution of remaining oil saturation and the molar concentration of dissolved CO2 in crude oil. The numerical simulation is carried out by using the STARS module (Version 2012, Computer, Modelling, Group, Ltd.). A 20 × 20 × 1 grid system is established, and the mesh size is 2 cm × 2 cm × 3 cm. In the same position of the physical model, the numerical simulation sets up at the high-permeability zone and carries out refinement at grids where the well point and high-permeability zone locates, as shown in Fig. 2. Other reservoir and fluid parameters are shown in Table 1. 72
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Fig. 4. Effect of CO2 molar concentration on oil viscosity.
CO2.
Fig. 2. Mesh and permeability distribution.
3.3. Organic fiber composite gel parameters
Table 1 Characteristic parameters of simulation model. Property
Value
Initial pressure (kPa) Crude oil density (g/cm3) Crude oil viscosity (mPa·s) Crude oil compressibility (1/kPa) Water density (g/cm3) Water viscosity (mPa·s) Water compressibility (1/kPa) Rock compressibility (1/kPa)
18000 0.956 400 5.12 × 10−7 1.0 0.45 1.0 × 10−6 4.4 × 10−7
After the organic fiber particles ATS and the cross-linking agent JL are injected into the formation, the organic fiber composite chemical agent is formed after a period of chemical reaction under the effect of stabilizers TJ. It is in the fibrous solid state and can plug high-permeability sites. Organic fiber composite gels reduce fluid channeling through two mechanisms: ① Improve the effective viscosity and reduce the effective permeability of aqueous solution. The resistance coefficient (RF) is defined as the ratio of the seepage pressure gradient of the organic fiber composite gel solution to that of the pure water in the injection process. The residual resistance coefficient (RRF) is defined as the ratio of the seepage pressure gradient after generating organic fiber composite gel to that of the pure water in order to characterize the reduction of water effective permeability in the channeling path during the output stage of CO2 stimulation. ② Decrease the gas relative permeability and inhibit the flow of CO2 gas to the high-permeability channels. The reduction coefficient of gas phase permeability Rg is defined to characterize the reduction degree of gas phase permeability after gel formation. As in Equation (1), krg is the gas relative permeability with gel and krg0 is the gas relative permeability without gel.
3.2. Phase equilibrium parameters The paper uses the Winprop module (Version 2012, Computer Modelling Group Ltd.) to match the crude oil phase of the G104-5 fault block in North Gaoqian area, and then determines the characteristics of crude oil and the change of physical properties after CO2 dissolution. According to the results, the primary contact miscibility pressure of CO2 is 82.3 MPa, and CO2 huff and puff processes are immiscible flooding process. The parameters of relative volume and viscosity can be used to characterize the effect of CO2 on crude oil. The relative volume is defined as the ratio of the crude oil volume after CO2 dissolution to the degassed oil volume under the same temperature and the same pressure. The effects of injecting different molar concentrations of CO2 on the relative volume and viscosity of the crude oil are indicated in Fig. 3 and Fig. 4. The relative volume of crude oil expands rapidly with the decrease of pressure, and it is larger with the increase of the molar concentration of CO2; the viscosity of crude oil decreases greatly with the increase of CO2 molar concentration. The results show that the crude oil of target block is suitable for studies on improving crude oil production using the solution, expansion and viscosity reduction of
(2)
krg = kkr 0 × Rg
The resistance coefficient of the organic fiber composite gel is 3 and the residual resistance coefficient is 20. The gas-liquid relative permeability curve is shown in Fig. 5.
Fig. 3. Effect of CO2 molar concentration on relative volume.
Fig. 5. Relative permeability curve. 73
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4. Results and discussion
cumulative recovery percentage of the three cycles increases by only 3.4%; as for the plugging agent assisted CO2 stimulation in the experiment # 2, the recovery percentage increases significantly in all of the three cycles. The numerical simulation results are basically consistent with the experimental results, and the fitting performance of oil recovery percentage is good. A little difference exists between the fitting curves in the second cycle of the plugging agent assisted CO2 stimulation experiment. It may be due to many factors including the distribution of plugging agent in the rock, the control style differences between experiment and numerical simulation, or the gel parameters of simulation.
4.1. Experimental results and numerical simulation fitting The oil recovery percentage is the ratio of the volume of produced crude oil to the total volume of crude oil saturated in the rock. CO2 utilization ratio, defined as the volume ratio of produced oil to injected CO2, is a crucial economic indicator for evaluating whether an operation is successful or not (Ma et al., 2015). 4.1.1. Fitting results The experimental results of direct CO2 stimulation and plugging agent assisted CO2 stimulation are shown in Table 2. The established numerical simulation model is used to simulate the CO2 stimulation experiment # 1 and # 2 conducted on the plate model. The initial pressure is 18000 kPa, and the oil saturation is 0.79 and 0.67. The injection well is injected at a constant injection rate. The injection rate is 0.7 mL/min and the maximum injection pressure is 18500 kPa. The production well is produced with constant bottom hole flow pressure of 18000 kPa. After the water cut of production well reaches 90%, the production well carries out 3 cycles of direct CO2 stimulation and plugging agent assisted CO2 stimulation. In the experiment # 2, 0.05 PV of organic fiber composite gel solution is injected.
4.1.2. CO2 utilization ratio The comparison result of the CO2 injection volume and CO2 utilization ratio in each cycle of the two experiments are shown in Table 2 and Fig. 7. In the experiment # 1, CO2 gas is injected directly after water flooding. Only 28 mL of CO2 gas is injected in the first cycle. The oil production at this stage is 9.5 mL, and the oil recovery percentage at this stage is 1.6%. This is mainly because the viscosity of the crude oil is high, the water channeling is formed between the high permeability channels (groove) at the stage of water flooding, and the remaining oil saturation is low. Under the effect of constant pressure, the injected CO2 flows mainly along the water channeling, the remaining oil saturation
Table 2 Summary of the experiment of CO2 huff and puff. No.
Porosity (f)
Permeability ( × 10−3μm2)
Oil saturation (f)
Stage
CO2 volume (mL)
Produced Oil volume (mL)
Stage oil recovery (%)
#1
0.160
410
0.79
#2
0.158
410
0.67
Water flooding 1st cycle 2nd cycle 3rd cycle Water flooding 1st cycle 2nd cycle 3rd cycle
– 28 36 76 – 30.65 68 89.8
111.4 9.5 5.4 5.2 73.6 37.5 66.9 62.9
18.4 1.6 0.9 0.9 15.3 7.8 13.9 13.1
CO2 utilization (mL/ mL) 0.34 0.18 0.06 1.22 0.74 0.7
The fitting results on the change of oil recovery percentage with time between physical experiment and numerical simulation are shown in Fig. 6. It can be seen that the oil recovery percentage increases rapidly with time at the water flooding stage; at the CO2 stimulation stage of experiment # 1, the oil recovery percentage increases only in the first cycle, but it is not obvious increased in the second and third cycles, the
in CO2 sweeping region is low, and the CO2 volume dissolved in crude oil is small. Therefore, the injection volume is small, and it mainly produces light components in the production stage. With the increase of the CO2 stimulation cycles, the remaining oil is mainly composed of heavy components in the channel, and the mutual solubility with CO2 is weaker. Although the sweep region and the volume of the injected CO2
Fig. 6. The fitted results of recovery factor.
Fig. 7. The comparison of CO2 utilization and injection volume between #1 and #2.
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are increased, the CO2 utilization ratio is decreased. In the experiment # 1, although the injection volume reached 89.9 mL in the third cycle, the oil recovery percentage at this stage is only 0.9% and the CO2 utilization ratio is decreased to 0.06. After water flooding in the experiment # 2, the organic fiber gel solution is first injected into the production well. Because the viscosity of the organic fiber gel solution is far below the viscosity of crude oil, it will flow firstly to the water channeling region where the permeability is high, and the oil saturation is low, and it can thus plug in situ after gelling. The subsequent injection of CO2 will flow evenly to the horizontal segment of the CO2 stimulation well, and the remaining oil saturation will be high in the near-wellbore area. In the first cycle, after 30.65 mL CO2 is injected, the oil production is 37.5 mL, and the CO2 utilization ratio is as high as 1.22. With the increase of CO2 stimulation cycles, CO2 extends to the area farther from the production well, the CO2 sweep region increases, the injection volume increases, the oil production at this stage is higher, and the CO2 utilization ratio is above 0.7. Among the first three cycles, the oil production in the second cycle is the highest and it decreases slightly in the third cycle. The oil recovery percentage reached 50.2% after three cycles of CO2 stimulation. Compared with the experiment # 1, the CO2 utilization ratio of plugging agent assisted CO2 stimulation is much higher than that of direct CO2 stimulation in the model with high-permeability zone and water channeling formed at the water flooding stage.
curve for the experiment #1 and Experiment #2. In the Figures, the sensor position 1 is the position for water injection, and the sensor position 12 is the position for CO2 injection & production. The pressure of each sensor at the water flooding stage is low and the pressure difference is small. In the CO2 huff and puff process, the pressure of sensor of initial production is high and then decreases rapidly; the pressure of sensor 12 is the lowest and the sensor 12 is the highest. The comparison between the experiment #1 and experiment #2 shows that in the experiment #1, and the injected CO2 flow along the gas channel. The viscosity of the crude oil was high and the residual pressure in the rock was high. With the increase of the cycle numbers of CO2 huff and puff, the swept volume of CO2 increases, and the residual pressure in rock decreases. In the experiment #2, due to the plugging agent to block gas channel, the swept volume of CO2 is large, and the residual pressure in rock is lower than that in the experiment #1. Fig. 10 is the pressure distribution at different times for the first cycle of the experiments #1 and #2. In the figure, (a), (b) and (c) are the time of produced at the 1, 30 and 60 min, respectively. The pressure in the experiment #1 and experiment #2 is about 15000 kPa at the initial time of production. In the experiment #1, after 30 min of production, the average pressure decreased to about 7800 kPa, and the low-pressure region formed between grooves connected by injection well and production well. It is mainly due to the formation of gas channeling between the grooves connected by the injection and production wells during CO2 injection. In addition, because CO2 does not affect outside of the low-pressure region, crude oil is hard to flow, so the pressure is higher. After 60 min' production, the low-pressure region still exists. In the experiment #2, because the plugging agent was injected into the gas channel, the injected CO2 extends to the rock around the well and does not form a gas channel. After 60 min’ production, the low-pressure region was not formed. In addition, because the injection volume of CO2 in the experiment #1 is lower than that of the experiment #2, the viscosity of crude oil and the residual pressure is higher.
4.1.3. Pressure distribution During the experiments, 21 pressure sensors were used to measure the pressure in different parts of rock. Fig. 8 and Fig. 9 are the pressure
4.2. Mechanisms of improving CO2 utilization ratio using organic fiber composite gel In order to know the incremental oil mechanism of plugging agent assisted CO2 stimulation in mid-high permeability and high water-cut reservoirs by the results of numerical simulation, the paper simulates the development performance of three schemes based on the model with high permeability channeling. The basic model uses the experimental conditions of plugging agent assisted CO2 stimulation (the initial oil saturation is 0.67). Scheme 1: water flooding directly to the water cut of 98%; scheme 2: direct CO2 stimulation (Experiment # 1) after water flooding to the water cut of 90%; scheme 3: plugging agent assisted CO2 stimulation (Experiment # 2) after water flooding to the water cut of 90%. CO2 stimulation scheme is implemented for 3 cycles. CO2 is injected at a constant pressure of 18.5 MPa, and each cycle lasts for 60 min.
Fig. 8. Pressure curve of important sensors for Experiment # 1.
Fig. 9. Pressure curve of important sensors for Experiment # 2.
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Fig. 10. Comparison of pressure distribution at different time of CO2 stimulation (kPa).
forming water channeling paths and increasing water cut of the production well. However, because the sweep region of water flooding is small, the remaining oil is still enriched, which is far from the highpermeability zone and near the production well. Fig. 12 (b) shows the distribution of remaining oil saturation at different development stages with the direct CO2 stimulation (scheme 2). The three figures correspond to the start time of the three cycles (end of injecting CO2). The distribution of CO2 mole concentration in crude oil at different cycles are shown in Fig. 13 (a). The permeability of high-permeability zone near the production well is higher than the average permeability and the remaining oil saturation near the highpermeability zone is low, so the injected CO2 mainly flows into the high-permeability zone, which increases CO2 molar concentration in the crude oil. Due to the miscibility expansion of CO2 and crude oil, the high saturation oil wall forms and the remaining oil saturation near the production well increases. At the end of the first cycle, lots of crude oil of the high-permeability zone is produced, and the remaining oil saturation is lower than that of water flooding. In the second and the third cycles of CO2 stimulation, the injected CO2 still mainly flows along the high-permeability zone. Because of the reduction of the remaining oil saturation and the sharp decrease of injected CO2 volume, the volume of oil production is decreased. Fig. 12 (c) shows the distribution of remaining oil saturation at different development stages of the plugging agent assisted CO2 stimulation (scheme 3). And the three figures correspond respectively to the start time of the three cycles (the end time of injecting CO2). The distribution of CO2 mole concentration in crude oil at different cycles are shown in Fig. 13 (b). The concentration distribution of organic fiber composite gel plugging agent in the model at the first cycle is shown in Fig. 14. The injected plugging agents mainly flow along the high-permeability zone at the beginning of the first cycle. After standing for 48 h, the high viscosity blocking system is formed and then plugs the
The simulation results of oil production are shown in Fig. 11. The oil production during water flooding (scheme 1) is lowest and the plugging agent assisted CO2 stimulation (scheme 3) is highest for every cycle. With the increase of stimulation cycles, oil production of both water flooding and direct CO2 stimulation decreased. The oil production of plugging agent assisted CO2 stimulation is low in the first cycle and highest in the second cycle. Then, it decreases gradually in the subsequent cycles.
Fig. 11. Comparison of oil content.
Fig. 12 (a) shows the distribution of remaining oil saturation at different stages of water flooding (scheme 1). The three figures of Fig. 12 (b) - (c) correspond respectively to the start time of the first cycle, the second cycle and the third cycle in schemes 2 and 3. It can be seen that the injected water flows along the high-permeability zone and offsets to another high-permeability zone near the production well due to the effect of high permeability zone. As time goes on, the remaining oil saturation between two high-permeability zones decrease gradually,
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Fig. 12. Remaining oil saturation distribution at different stages of different schemes.
Fig. 13. CO2 mole concentration distribution in crude oil at different cycles of different schemes.
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Fig. 14. Concentration distribution of plugging agent.
Fig. 16. Daily oil production curve during CO2 expiry date of well G211-7 in Jidong Oilfield.
high-permeability zone, which inhibits the fingering during the subsequent injection of CO2, which forces the CO2 to advance evenly along the radial direction of the production well. Compared with the direct CO2 stimulation (scheme 2), the distribution range of CO2 mole concentration in crude oil is bigger in this scheme, and the volume of injected CO2 and produced oil are larger. In the second and the third cycles of the plugging agent assisted CO2 stimulation, the injected CO2 advances farther away from the production well and reduces the oil viscosity in the frontier. At the end of the production, the remaining oil saturation is reduced, and the scheme produces more crude oil than water flooding (scheme 1) and the direct CO2 stimulation (scheme 2).
flow along the channeling path. Thereby, the daily oil production reduced to 2.4 t/d and the stage cumulative oil production was only 214 t. The third cycle used the plugging agent assisted CO2 stimulation. The 75 t organic fiber composite gel was injected before the CO2 injection, and they plugged the gas channeling-path and expanded the sweep region of injected CO2. The CO2 injection increased to 500 t, the highest oil production reached about 4.3 t/d, and the stage cumulative oil production reached 535 t. Fig. 17 compares the average single well oil production of each cycle in recent years between direct CO2 stimulation and plugging agent assisted CO2 stimulation in the whole Jidong Oilfield. The average single well oil production of CO2 stimulation decreased as the stimulation cycle increased in Jidong Oilfield, which significantly
5. Field application Jidong Oilfield started the CO2 stimulation since 2010. By 2015, a cumulative total number of 568 wells have implemented and some wells have carried out five cycles. Parts of the wells, which have implemented plugging agent assisted CO2 stimulation, are shown in Fig. 15. With the increase of stimulation cycles, there has been a serious gas channeling phenomenon and the oil increment of direct CO2 stimulation declined sharply. Since 2015, Jidong Oilfield has been implemented organic fiber composite gel plugging agent assisted CO2 stimulation in some gas channeling wells. Taking the well G211-7 for example, the change of daily oil production with time in the three cycles of CO2 stimulation are collected (see Fig. 16). In the first and second cycles, the direct CO2 stimulation is used. In the third cycle, the plugging agent assisted CO2 stimulation is used. As can be seen from Fig. 15, the G211-7 wells is located in water flooding channeling path. In the first cycle of direct CO2 stimulation, the CO2 injection was 300 t, the daily oil production was 5.5 t/d and the cumulative oil production was 814 t. In the second cycle, the CO2 injection was 375 t, but they
Fig. 17. Incremental oil effect of plugging agent assisted with CO2 stimulation in Jidong Oilfield.
Fig. 15. Well location map of plugging agent assisted with CO2 stimulation in Jidong Oilfield. 78
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decreased after the third cycle. Some wells implemented plugging agent assisted CO2 stimulation since the second cycle, and the average oil production was obvious higher than that using the direct CO2 stimulation in every cycle. By the end of 2016, Jidong Oilfield had injected a total of 19.2 × 104 t CO2. The cumulative oil production is 21.1 × 104 t and the utilization ratio of CO2 reached 1.09. It has increased oil production and economic benefits at the same time of reducing CO2 emissions.
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6. Conclusions As a kind of plugging agent, organic fiber composite gel can block gas channels in CO2 injection process, increasing crude oil recovery and further improving CO2 utilization rate. Combined with the physical experiment and numerical simulation, the mechanisms of increasing oil production and CO2 utilization ratio for high-permeability reservoirs are revealed using organic fiber composite gel plugging agent assisted CO2 huff and puff. The experimental and reservoir numerical simulation results show that water flows along the high-permeability zone and the water cut rises rapidly in the water flooding process in the high-permeability zone model. If the production well implements direct CO2 huff and puff, the injected gas will break through along the high-permeability zone and channeling-path, and the sweep region is thus small. Using plugging agent assisted CO2 huff and puff, the injected plugging agent firstly seep into the high water-cut area along the highpermeability zone. Then, it can be adsorbed and retained after the gel is generated. Thereby, the injected CO2 mainly spreads uniformly along the radial direction of the production wellbore and can improve the crude oil production. The plugging agent assisted CO2 stimulation has achieved remarkable performance in Jidong Oilfield. The cumulative utilization of CO2 reached about 19.2 × 104 t, the cumulative oil production increased by 21.1 × 104 t, and the utilization ratio of CO2 reached 1.09. Acknowledgments The authors greatly appreciate the financial support of the Project supported by the National Science Foundation for Distinguished Young Scholars of China (Grant No. 51625403), the Important National Science and Technology Specific Projects of China (Grant no. 2016ZX05025-003-006), the Fundamental Research Funds for the Central Universities (Grant no. 15CX08004A). Appendix A. Supplementary data Supplementary data to this article can be found online at https:// doi.org/10.1016/j.petrol.2019.04.034. References Abdulbaki, M., Huh, C., Sepehrnoori, K., Delshad, M., Varavei, A., 2014. A critical review
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