The Opinion of CO2 Storage Potential of Heavy Oil Reservoirs in the Junggar Basin

Introduction

On May 2021, 131 countries with more than 65% of greenhouse gas emissions and 75% of gross national product have established the goal of carbon neutrality. As one of the largest emitters of carbon dioxide, with 103.57 million tons of CO₂ emissions every year, China should put more cocentration on carbon dioxide emissions (Lu, 2021).

Carbon capture utilization and storage (CCUS) technology is currently considered to be the most promising technology for reducing greenhouse gas emissions. Studies by international organizations such as IPCC, IEA, GCCSI, and others show that CCUS technology is indispensable to achieve the targets for greenhouse gas emission reduction (Yu, 2020).

CO₂ capture and storage (CCS) technology can not only drastically reduce the concentration of CO₂ but also inject captured CO₂ into special underground geological structures to achieve the purpose of permanent storage of CO₂. The geological structures that are used to store CO₂ include oil and gas reservoirs under development or abandoned, deep brine layers, and oil reservoirs without exploitation value (Wang et al., 2021). CO₂ injection into oil and gas reservoirs can not only achieve CO₂ storage but also increase oil and gas recovery (Duan et al., 2018; Liu et al., 2018), which is currently the main form of CO₂ storage and has good economic benefits.

In 2007, China designed the first domestic CO₂ storage project in the Jilin oil field and the Caoshe Oilfield of East China Branch of Sinopec and achieved industrialization of the CCUS–enhancement oil recovery (EOR) technology. The annual CO₂ storage amounted to 350,000 t. In 2012, the Yanchang Oil Company completed a 50,000 t/a CO₂ capture and utilization project. The project used CO₂ that was produced by the coal chemical industry, and purified and pressurized liquefied by low temperature methanol washing technology, which was then injected into the oil field permanently. The viscosity of the crude oil was reduced, the recovery rate of the crude oil was increased, and then the permanent storage of CO₂ realized. In 2015, the CCUS project of refinery tail gas in Sinopec Zhongyuan oil field was completed, and the project was close to abandoned oil fields. The recovery rate of the oil field was increased by 15% by CO₂ flooding. At present, millions of tons of CO₂ has been stored underground (Zhang X et al., 2021; Li, 2018) (Figure 1) reflects the mechanism of CO₂ storage and is intended to provide the reader with a better understanding of the storage process.

FIGURE 1

FIGURE 1. Schematic diagram of CO₂ storage mechanism. Sources: Wang et al. (2013) and Syah et al. (2021). (A) The supercritical CO₂ injection into porous media. (B) Schematic diagram of CO₂ injection to enhance oil recovery. (C) Schematic diagram of CCS scenario in a saline aquifer.

Increasing the oil recovery rate by CO₂ flooding is the most economical and effective means to achieve greenhouse gas emission reduction and deal with world environmental problems at this stage. At present, some oil reservoirs in China have carried out field tests of CO₂ flooding and achieved preliminary success. However, there are few studies on the development of heavy oil reservoirs by using CO₂ flooding to increase recovery and storage efficiency. Whether heavy oil reservoirs are suitable for using CO₂ flooding to increase recovery and storage technology still lacks in-depth studying (Wang, 2010; Wang et al., 2013).

The Junggar Basin has rich heavy oil reservoirs, which are distributed in 29 layers of six oil fields in the northwestern margin and two eastern oil zones. According to the 2020 data, Xinjiang Oilfield has developed more than 1 billion tons of heavy oil resources and a cumulative proven oil area of 348.9 km² and geological reserves of 596 million tons. Currently, water flooding and steam stimulation are mainly used as the main development technologies. Through the exploitation experiences for heavy oil reservoirs in the Junggar Basin, the results show that the development of heavy oil reservoirs is faced with many problems, such as low overall production, large production decline, high injection–production ratio of heavy oil, serious formation deficit, significant drop in stratigraphic pressure, and poor development effect.

After years of research and a large number of CO₂ storage tests, the geological storage of CO₂ is technically feasible, but people have been worried and in doubt about whether the stored CO₂ will leak (the safety of store CO₂) (Ren et al., 2017), which is one of the important factors restricting the development of CO₂ geological storage technology. In addition, with the development of more and more CCUS projects, the screening and evaluation of stratigraphy will be essential (Geng et al., 2009). Reservoir screening studies have also been developed over many years with the implementation of the EOR program (Luo et al., 2013; Tan et al., 2015), and there are many existing methods and screening criteria. The methods to screen and evaluate the existing research criteria have far-reaching significance for the studies of increased oil recovery and storage efficiency with CCUS technology.

Mechanism of Carbon Dioxide Storage in Reservoirs

1) Oil and water in the reservoir occupy a certain space, and CO₂ is injected into the exploited oil layer by CO₂ flooding for increasing oil recovery. Under a high pressure condition, crude oil is driven by CO₂ to flow to production wells, and oil recovery is increased accordingly. A part of CO₂ is stored in formation pores or dissolved in crude oil that cannot be exploited; and a part of CO₂ is discharged from the production wells and injected circularly with crude oil, water, and natural gas.

2) CO₂ can be dissolved in residual oil and residual water. Because the oil–water with dissolved CO₂ is heavier than that without CO₂, the oil–water with dissolved CO₂ can be deposited for a long time.

3) CO₂ is weakly acidic after encountering with groundwater, and it can react with minerals around rocks to form new minerals, and thus CO₂ is permanently stored. But the trap is small and the reaction is slow.

4) If there is edge and bottom water in the reservoir, CO₂ can be injected into this part of the water layer and be dissolved in water. After a long time, the water that is saturated with CO₂ becomes more and more viscous, and it is easy to store in the formation for a long time no longer upward migration to increase the storage capacity (Zhang and Lv, 2021).

CO₂ Storage in the Reservoir Has the Following Main Advantages

1) Professional technical experience of CO₂ flooding has been accumulated in the process of reservoir development.

2) CO₂ injection for increasing oil recovery has been tested and the economic benefits of this have been achieved.

3) The storage state of natural CO₂ gas reservoir reveals that favorable geological structure conditions can store CO₂ for a long time. The cost of CO₂ storage in depleted reservoirs is lower, and the economic and environmental benefits are remarkable.

Main Factors Affecting CO₂ Storage

Rock Properties

A certain amount of CO₂ can be stored through the reaction of CO₂ with mineral rocks, but not all mineral rocks can react with CO₂. Only those mineral rocks containing Fe/Ca/Mg can react with CO₂ to form siderite, calcite, and dolomite. But the reaction of mineral rocks with CO₂ can also bring some adverse effects, such as reducing formation permeability and CO₂ injection capacity.

Oil Field Water Character

The solubility of CO₂ in formation water is mainly affected by the salinity of formation water; in general, the solubility of CO₂ decreases with the increase of formation water salinity.

Crude Oil Properties

The solubility of CO₂ in crude oil is mainly affected by the properties of the crude oil. Generally, CO₂ solubility in light oil is higher than it is in heavy oil.

Reservoir Temperature and Pressure

The phase state of CO₂ is significantly affected by temperature and pressure. When CO₂ is in the supercritical state under reservoir temperature and pressure, it is the most suitable for geological storage. Low reservoir pressure or high reservoir temperature are not suitable for CO₂ storage.

CO₂ Storage Capacity of Jiuqu Carboniferous Reservoirs in Junggar Basin

Jiuqu Carboniferous reservoir is located 40 km northeast of Karamay and is located in the upper plate of Baijiantan South Fault in the northwestern margin of the Junggar Basin alluvial zone. The top surface of Jiuqu Carboniferous bedrock is a fault nose with northwest–southeast tilt controlled by the Xibaibaibai fault, the central fault of Jiuqu and the fault of Well Jian 229 in the upward direction. Jiuqu and Jiuqian 25 well areas are located in the upper part of fault nose structure and monoclinic fault blocks controlled by Xibaibaibai fault, central Jiuqu fault, Jiuqian 25 well fault, and Jian 229 well fault. The high point of storage depth for Carboniferous reservoir in this area is 220 m, which shows the pattern of low in the southeast and high in the northwest. The slope of the erosion surface at the top of the Carboniferous is 3°–10°, and the slope of paleogeomorphology gradually becomes steeper along the dip direction of the structure, and the storage depth is gradually deepened. The reservoir data and formation conditions of the Carboniferous in the ninth area are as follows: geological reserves is 1344.88 × 10⁴ t, formation temperature is 26°C, formation pressure is 7.16 MPa, crude oil volume coefficient is 1.09, and CO₂ storage stock is 140 × 10⁴ t.

Based on the numerical simulation model of carboniferous reservoir in nine districts and the optimization of numerical simulation parameters, the development effect of CO₂ flooding in the target area is predicted. The working system is as follows: daily gas injection rate is 2.5 × 104 m³, water is injected once every 4 months to reduce gas channeling pressure, daily water injection rate is 40 m³; define continuous work for 2 years as a cycle, a total of three gas injection cycles, each cycle continuous gas and water alternate four times, its time-exhausted production; the predicted time was 15 years from May 1, 2012, and compared with the failure plan. The simulation results show that the recovery rate is 12.08% in the depletion stage and 18.08% in the CO₂ flooding stage. The recovery rate of CO₂ flooding is 6.0 percentage points higher than that in the depletion stage, and 4.07 × 10⁴ t of CO₂ is stored in the gas injection production process.

Conclusion

After the description on the sequestration status for natural CO₂ gas reservoirs (Guo et al., 2016), it shows that favorable geological structures are capable of storing CO₂ for long periods of time, in which the cost is low and the economic and environmental benefits are significant. The main factors that affect CO₂ storage include: rock properties, formation water properties, crude oil properties, and reservoir temperature and pressure.

In the coming decades, CO₂ storage technology is one of the most promising ways to solve the problem of carbon emission. In the long run, the cost of CO₂ storage technology will be lower. Hence, in the field of carbon emission reduction technology in China, CO₂ geological storage technology is a potential breakthrough.

At present, many CCUS projects prefer oil and gas fields as storage sites. In the process of oil and gas exploration and development, the oil and gas industry has accumulated rich geological data and has a natural advantage in carrying out carbon dioxide storage (Wang et al., 2013). CCUS technology that combines CO₂ storage with EOR, which integrates the utilization and storage of carbon dioxide, has received great attention in recent years with the continuous expansion of unconventional oil and gas development.

China’s Junggar Basin is rich in heavy oil resources and has the conditions for studying CO₂ flooding to increase recovery and storage technology. Therefore, it is of great theoretical value and strategic significance to carry out the feasibility study of CO₂ flooding development and storage technology in heavy oil reservoirs in the Junggar Basin.

Author Contributions

YZ, KD, HZ, and QG contributed equally to this work.

Conflict of Interest

Author HZ is employed by the Petroleum Engineering Co. Ltd. Author QG is employed by the Tuha Oilfield Company, CNPC.

The remaining authors declare that the research was conducted in the absence of any commercial or financial relationships that could be construed as a potential conflict of interest.

Publisher’s Note

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