Key problems and solutions in supercritical CO₂ fracturing technology

Abstract

Supercritical CO₂ fracturing is considered to be a new method for efficient exploitation of unconventional reservoirs, such as shale gas, coal bed methane, and tight sand stone gas. Supercritical CO₂ has many special properties including low viscosity, high diffusion coefficient, and lack of surface tension, which brings about great advantages for fracturing. However, these properties also cause several problems, such as difficulty in proppant transportation, high friction loss, and high pump displacement. In this paper, the above problems were analyzed by combining field test with laboratory study and specific solutions to these problems are given. The high frictionloss in the pipeline could be reduced by developing a new drag reducing agent and selecting large-size casing. Besides, for the problem of poor capacity in proppant carrying and sand plug, the methods of adding tackifier into supercritical CO₂, increasing pump displacement and selecting ultra-low density proppants are proposed. Moreover, for the problem of fast leak-off and high requirement for pump displacement, the displacement can be increased or the pad fluid can be injected into the reservoir. After solving the above three problems, the field test of supercritical CO₂ fracturing can be conducted. The research results can promote the industrialization process of supercritical CO₂ fracturing.

Keywords

supercritical CO₂ / fracturing / friction loss / proppant carrying / flied test problem

Introduction

Supercritical CO₂, which is colorless, tasteless, and readily available, has many unique physical and chemical properties. Its density is close to that of liquid while its viscosity is close to that of gas [¹,²]. Besides, it has a large diffusion coefficient but has no surface tension. Previous research has shown that supercritical CO₂ can reduce the initiation pressure of rocks when it is used in fracturing because of its low viscosity. In the meantime, complex fracture networks are generated in the reservoir, greatly improving the efficiency of fracturing. In addition, supercritical CO₂ is harmless to the reservoir and underground water [³,⁴]. It also has a higher adsorption capacity in rocks than methane gas, which can replace the methane gas in shale or coal [⁵]. As a result, output is increased and permanent CO₂ storage is achieved [⁶,⁷]. Therefore, supercritical CO₂ fracturing is considered as a new method for efficient exploitation of unconventional oil and gas [⁸].

The unique physical properties of supercritical CO₂ have brought about both great advantages a series of problems [⁹]. First of all, the viscosity of supercritical CO₂ is low, only about 1/10 of water viscosity, and its density is slightly lower than water under well pressure and temperature, which leads to its poor capacity in sand carrying [¹⁰]. Consequently, the proppants settle down rapidly near the wellbore, causing sand plugging and the failure of fracturing [¹¹–¹³]. Secondly, the low viscosity of supercritical CO₂ can lead to a serious energy dissipation turbulent state even with low flowing velocity [¹⁴,¹⁵]. The Reynolds number is large, the friction coefficient is high, and friction along the pipeline is high, causing the overpressure of surface equipment [¹⁶–¹⁸]. Moreover, the low viscosity and high diffusion characteristics of supercritical CO₂ lead to a fast filtration rate in the reservoir [¹⁹]. Compared with conventional fracturing fluids, it is more difficult to set up high wellbore pressure during supercritical CO₂ fracturing because it requires a higher displacement [²⁰,²¹].

The above problems have become the bottleneck restricting the industrialization of the supercritical CO₂ fracturing technology. To thoroughly understand and solve these problems, according to the field test results of supercritical CO₂ fracturing in a shale gas well in northern Shaanxi, combined with laboratory experiments and theoretical research, the root causes of the problems are analyzed in detail, and solutions are proposed, hoping to lay a foundation for the development of supercritical CO₂ fracturing technology.

Supercritical CO₂ fracturing

Unlike the conventional fracturing fluids, supercritical CO₂ must be stored in sealing pressure vessels. Therefore, coiled tubing is recommended for multilayer and multistage fracturing to avoid CO₂ leakage caused by POOH and RIH of pipe strings.

Figure 1 shows the configuration of supercritical CO₂ fracturing with coiled tubing [⁹]. CO₂ is stored in a high-pressure tank to keep it in a liquid state. The sand jet perforation is first conducted. The liquid CO₂ is pumped into the sealings and mixer and mixed with abrasives of 60–80 mesh. Then, the mixed fluid is pumped into the downhole through the coiled tubing. When the fluid is pumped through the nozzle of the jet fracturing tool, supercritical CO₂ abrasive jet is formed to perform perforation window of casing and formation. The operation lasts for 5–10 min. After sand jet perforation, abrasives are no longer added to CO₂ and pure CO₂ is continuously pumped to carry the abrasives out of the well, in case of sandburying of strings. Then pure CO₂ should be continuously pumped with a large displacement into the formation. When the downhole pressure exceeds the formation fracturing pressure, proppants are mixed into the CO₂ to be carried to the well bottom through the coiled tubing. Proppants can also be pumped simultaneously through the annulus and the coiled tubing to reduce wear of the coiled tubing and pressure drop.

After the proppants are transported to the right position, pure CO₂ is continuously pumped to carry the proppants that fail to enter the fractures and are left in the well bore as well as at the well bottom, avoiding sand burying. If the next stage of fracturing is required, the coiled tubing and the jet fracturing tool are pulled up to the next targeting formation to perform the second stage of fracturing. By doing this for several times, multistage fracturing can be achieved. After fracturing, the well can be shut in 5–10 days for soaking and then produce oil and gas directly without blow out, which can greatly improve the output and recovery rate. If the production task is urgent, the downhole pressure can be released slowly after fracturing and the well is put into production directly.

Main problems in supercritical CO₂ fracturing

Hard to carry sand and frequent sand plugging

Viscosity is one of the important parameters determining the sand carrying capacity of fluid since the supercritical CO₂ viscosity is about 1/10 of water viscosity, whose sand carrying performance is worse than that of the conventional water-based fracturing fluids [²²–²⁴]. To understand the sand carrying characteristics of supercritical CO₂ fluid, the sand carrying capacity of supercritical CO₂ fluid and slick water in the fractures are numerically simulated.

The simulation software is ANSYS Fluent. As listed in Table 1, the length, width, and height of the simulated fracture are respectively L_f = 3000 mm, W_f = 10 mm, and H_f = 400 mm. The pressure at the fracture outlet is 20 MPa, the temperature of the supercritical CO₂ injected is 320 K, and the temperature inside the fracture is 330 K. As demonstrated in Fig. 2, in the early stage of 10–15 s, the proppant distribution in the fracture is similar either in slick water fracturing or in supercritical CO₂ fracturing, and the height of the sand bed made of proppants delivered by supercritical CO₂ increases with time. For slick water fracturing, with injection time increasing, the flow of the sand carrying fluid develops more fully in the fracture, making the proppant distribution more uniform and the height of the sand bed smaller. The reason for this is that the viscosity of supercritical CO₂ is far lower than that of slick water, the same with the density, resulting in poor sand carrying ability in the fracture.

The field test of sand carrying in supercritical CO₂ fracturing has also confirmed this result. Before adding sand, the casing pressure was stable at 40MPa, the tubing pressure was about 55 MPa, and the displacement was about 2.5 m³/min. The sand ratio gradually increased from 0 to about 4% after the sand addition work began. The pressure of tubing increased from 55 MPa to 65 MPa. In the initial stage, the casing pressure remained stable at 43 MPa, and 10 min later it suddenly rose to 65 MPa, the same as the tubing pressure. These phenomena indicated that the total amount of proppants was small in the initial stage, which had little effect on the fracture. Therefore, CO₂ could smoothly enter the formation. With the increase of sand, because of the poor sand carrying capacity of supercritical CO₂, the proppants were gradually deposited at the fracture entrance and bottom well, and finally, the fracture and wellbore were blocked up, resulting in sand plugging.

The above numerical simulation and field test indicate that the sand carrying performance of supercritical CO₂ is poor, which needs to be further improved before field application.

High frictional resistance and high work pressure

Both gaseous and supercritical CO₂ are highly compressible fluids. Therefore, to obtain supercritical CO₂ in high pressure, it is necessary to use plunger pump to inject liquid CO₂ instead of directly pumping gaseous or supercritical CO₂ (The efficiency of the gas booster pump is low and the displacement is small. Hence, the displacement demanded for fracturing cannot be met.). Liquid CO₂ is gradually heated to a supercritical state as the depth increases. The temperature of CO₂ at the wellhead is generally about –10°C and the liquid CO₂ flows through the tubing to the well bottom. When the displacement is 2 m³/min, the CO₂ at the well bottom of 2000 m can be heated to about 35°C. As tabulated in Table 2, in the field test, the frictional resistance was about 7.5 MPa, much higher than the pressure loss of 6.2 MPa in the slick water fracturing. The local head loss was about 27 MPa, also much higher than the pressure loss of 19.3 MPa in slick water fracturing. As a result, the high-pressure pump could not be increased to an effective displacement and overpressure happened frequently for the ground equipment.

Fast filtration loss and large displacement

Table 3 shows the comparison of viscosity between supercritical CO₂ and water under reservoir condition. It can be seen from Table 3 that the viscosity of supercritical CO₂ is relatively low, which is only about 1/4 to 1/5 of water. For the seepage of fluid in porous media, the lower the viscosity, the easier the flow is. Therefore, the flow resistance of supercritical CO₂ in porous media is smaller than that of water.

In addition, the supercritical CO₂ diffuses easily and has no surface tension. Therefore, it can enter any space larger than its molecular size, and can flow under little pressure without overcoming the capillary force. The previous researchers compared the filtration rate of supercritical CO₂, water and nitrogen gas in shale reserviors. They found that at the same temperature and pressure, the filtration rate of CO₂ is about twice that of water.

From above it can be observed that, with the same displacement, the bottom hole pressure of supercritical CO₂ fracturing is lower than that of conventional hydraulic fracturing because it is easier for supercritical CO₂ to filtrate in the reservoir. Therefore, in supercritical CO₂ fracturing, a higher injection displacement is needed.

Solutions

Tackifier, large displacement, and ultra-low density proppant

For hydraulic fracturing, the sand carrying performance of pure water is poor. Therefore, tackifiers such as guar gum are often added to fracturing fluid to improve its sand carrying performance. The viscosity of supercritical CO₂ is lower than that of water, so its sand carrying performance is worse. A direct way to improve its sand carrying performance is to add a tackifier. However, since CO₂ molecule is non-polar, so the solubility of conventional polymer tackifiers in CO₂ is very low and is affected by the change of temperature and pressure, making the viscosity enhancement effect very limited. Although fluorinated polymers can effectively increase viscosity, the cost of fluorine-containing materials is high, and they are not easy to degrade, which pollutes the natural environment [²⁵]. In addition, when tackifiers are added, besides efficiency, environmental protection and cost should also be taken into account. Tackifiers not only pollutes the environment, but also causes damage to the reservoir [²⁶]. Otherwise supercritical CO₂ fracturing is meaningless. Therefore, developing a low-cost, environment-friendly tackifier suitable for supercritical CO₂ fluid should be given priority to.

The movement of solid particles such as proppants in the fluid is also affected by the fluid flow. Increasing the flowing velocity can increase the drag force to the solid particles, so as to delay the settlement of proppants in the fracture. Therefore, if the fracturing equipment permits, pump displacement should be increased to its maximum.

In addition, the density of solid particles is one of the important factors affecting the settling in solid-liquid two-phase flow. In general, the lower the density of solid particles, the more slowly they settle down in fluid. When the density is equal to that of the fluid, particles can be suspended in the fluid. At present, the common low-density proppants include nanocomposite microspheres, porous ceramic microspheres, high-strength nut shells and so on, whose density is slightly higher than that of water [²⁵]. Therefore, it is necessary to further develop low-density proppants suitable for supercritical CO₂ fluid, whose apparent density should be reduced to 0.8–1.0 g/cm³.

Development of drag reducers and optimization of pipe string

As depicted in Fig. 3, under the same temperature and pressure conditions, the frictional resistance of supercritical CO₂ pipe flow is equal to or slightly smaller than that of pure water pipe flow. However, in order to reduce the frictional resistance during fracturing, drag reducers are often added to water (The mixed fluid is often called slickwater.). The frictional resistance is reduced to about 60% of the original loss after adding the drag reducer. The drag reducer can suppress the energy loss caused by turbulence. Therefore, for supercritical CO₂ fluids, it is also necessary to add a matching drag reducer to reduce the frictional resistance. However, few such studies have been conducted.

On the other hand, with the same displacement, enlarging the pipe size can also reduce the frictional resistance. A casing size of 7” for cementing is most common for oil and gas wells in general. A tubing size of 2 7/8”–3 1/2” is generally adopted during fracturing which can completely meet the requirements for conventional fracturing fluids such as slickwater. However, for supercritical CO₂, the frictional resistance is large. Meanwhile, a large displacement is required, which can lead to over pressure of the ground equipment and cannot meet the fracturing demand. Therefore, it is suggested that for oil and gasfields developed with supercritical CO₂ fracturing, the casing size should be optimized at the beginning of drilling. In other words, the integrated design scheme of drilling and fracturing strings should be adopted, in which large size casing should be used to enlarge the fluid flow channel and reduce frictional resistance.

Increase displacement and inject pad fluid

To effectively crack the reservoir, the fracturing fluid must be injected with a rate higher than the absorption capacity of the formation during fracturing. Rapid filtration loss of supercritical CO₂ makes it difficult to set up high wellbore pressure with conventional displacement [²⁷–²⁹]. Therefore, large displacement must be adopted in supercritical CO₂ fracturing. However, large displacement also leads to high frictional resistance, thus it is necessary to use large size pipelines to reduce frictional resistance, which is complementary to the measures taken in the previous section.

In addition, before fracturing, the filtration rate of supercritical CO₂ can be reduced by injecting high viscosity pad fluid into the reservoir to temporarily block formation pores. The high-viscosity pad fluid should cause no damage to the reservoir.

Conclusions

Supercritical CO₂ fracturing is considered to be a new efficient method for unconventional oil and gas reservoirs. Although field tests and laboratory research have been conducted, the following problems remain unsolved before industrialization: high frictional resistance, high displacement, poor sand carrying performance, easy sand plugging and fast filtration.

In view of the problem of high frictional resistance and high displacement, a new drag reducer can be developed. Besides, large size casing can be selected to reduce the resistance. Aiming at the problem of poor sand carrying performance and easy sand plugging, adding tackifiers into supercritical CO₂, increasing injection displacement and using ultra-low density proppants are viable solutions. As for the problem of fast filtration and large displacement requirement, the injection displacement can be increased as high as possible when fracturing equipment can bear or the pad fluid is pumped into the reservoir before fracturing.

The existing problems of supercritical CO₂ fracturing are discussed in this paper. Based on the field fracturing test and laboratory research, some qualitative opinions and suggestions are proposed, but detailed countermeasures need further studying. It is suggested that the above three key problems be tackled in order to promote the industrialization process of supercritical CO₂ fracturing.

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