The Lawrence Livermore National Laboratory developed the CRIP method in the US in 1970 (Kumar, 2014). The production wells are drilled vertically, and the injection wells are drilled using directional drilling techniques to connect to the production wells. Once the channel is established, a burner attached to the retractable coiled tubing is used to initiate the gasification cavity, which ignites the coal as it burns the borehole casing (Hill, 1983). CRIP provides a stationary state of the vertical press-in well, but if necessary, the press-in point moves to fresh coal within the coal seam (Hill, 1983). Studies in Klimenko (2009) have confirmed that the flash point can be moved along the horizontal injection well to create a new gasification cavity when the coal near the cavity is exhausted. The second combustion begins near the injection well when the first combustion is finished. This way, the progress of gasification can be precisely controlled, and this procedure continues until the seams are burned out. Syngas, more than one-third of hydrogen in many early UCG pilots (the rest are CO₂, CO, CH₄, and higher hydrocarbons), is brought to the surface and processed to remove particles, CO₂, and H₂S. Moreover, CO is converted. From CH₄ and higher hydrocarbons to more hydrogen (Burton et al., 2006). See Figures 2A, B.

The concept of CRIP can be divided into Linear-CRIP (L-CRIP) (see Figure 2C) and Parallel-CRIP (P-CRIP) configurations. In the L-CRIP configuration, both process points are linked by one intra-seam excursion well. In a P-CRIP configuration, both process wells are drilled into the seam parallel to each other. See UGE (1999) and Nourozieh et al. (2010) for more information on the two processes.

SHS(2012) states that the LVW method is one of UCG’s oldest methods and is derived from technology developed in the former Soviet Union. A vertical well is drilled at the coal seam and uses the coal’s internal pathways to direct the oxidizer flow and produced gas from the inlet to the exit borehole. Internal pathways can occur naturally or be constructed via reverse combustion, electrical coupling, and hydraulic fracturing (Shafirovich and Varma, 2009).

The injection point is located at the complete base of the vertical injection well, and the production point is at the complete base of the vertical production well (Mostade, 2014). In the simplest form, the entry and exit drilling positions of the LVW method are stationary throughout the life of the system. However, it has been found that as the coal surface moves during operation and the distance from the coal surface to the oxidant injection point increases, system control, performance, and syngas quality are adversely affected (Liang et al., 1999). This factor significantly decreases the viability of a simple LVW system. When the coal in the area is exhausted, a new hole will be drilled to replace the new coal, forming new zones. See Figures 3A, B.

Ergo Energy’s UCG is a proprietary process used by Ergo Exergy and may be based on the former Union of Soviet Socialist Republics (USSR) UCG technology. It relies on using the natural passages at the coal seams and strengthening them as needed to establish a connection between the press-in well and the production well. Ergo Energy’s UCG technology is practical and based on the practical experience of operating a commercial UCG factory. The design flexibility and multiple methods and technologies used by Ergo Exergy enable it to be applied to various coal qualities and grades (from lignite to bituminous coal) and geological environments (Burton et al., 2006).

It employs all currently available drilling methods, including precision directional wells and traditional vertical and sloping (tilted) wells. Its arsenal includes different ways to connect wells, different oxidant injections (air, O₂/H₂O.), and different underground vaporizer designs. It can be applied to coal under various geological and hydrogeological conditions. In each geological environment, the specific Ergo Energy’s UCG design is tailored to the specific conditions of the coal seam of interest (Power, 2011).

Early UCG tests applied flow meters, thermocouples, and gas analyzers to monitor temperatures and combustion conditions from the underground (Blinderman and Jones, 2002). These measurements track underground combustion conditions and their corresponding subsidence but are effective for shallow coal seams and lower resolution for deep coal seams. However, in a hot and humid UCG setting, the accuracy of such sensors may be low and may not work properly. In addition Mellors et al. (2016) researched and designed a UCG monitoring system based on a self-organizing network of wireless sensors. However, the system has been tested in the laboratory, and the high temperature and high humidity environmental factors were not considered in the design. Wang et al. (2017) used Siemens S7-300 PLC and Fame View configuration software to develop a real-time monitoring system for UCG. However, the laboratory has tested the system, and the design does not consider the hot and humid environmental factors. Using the Siemens S7-300 PLC and Fame View configuration software, Wang et al. (2017) developed the UCG real-time monitoring system. However, the system is used for teaching experiments, and the design does not consider environmental factors such as high temperature and humidity (Guan et al., 2016) built a wireless sensor network and planned a UGS monitoring system to monitor groundwater pollution during gasification. However, its sensor components are inappropriate for the representative UCG high humidity and temperature setting. Barnwal et al. (2017) proposed a new method of producing coal with high moisture and low calorific value to improve the synthesis gas quality of UCG technology. However, these methods are expensive or temporarily not scalable. On the other hand Kostúr et al. (2015) created the UCG visualization information system to visualize the state of the UCG record. Based on this Nurzynska et al. (2014) monitors UCG data using GPR and visualizes them in 3D, see Figure 5. However, standard commercial radar systems are used to check the on-site and off-site coal combustion conditions. The results show that this method monitors and visualizes the coal gasification process under off-site combustion conditions. It is not suitable for other situations; that is, it is impossible to control the combustion state of coal in a real gasification process.

UCG control is a developing area with few references to theoretical research and laboratory simulations. Kotyrba and Stanczyk. (2017) established and deduced the mathematical expression of gasified coal particles based on the theory of mass conservation, energy conservation, and chemical thermodynamics based on model tests. The calculated value is the same as the model test value. Some scientists have studied the combustion state of the gasifier based on mathematical models (Yang and Liu, 2010). These studies are effective in predicting the state of combustion. However, this is necessary in practice to accurately assess the combustion state in real-time (Khan et al., 2015) provides related properties that affect the combustion state of UCG through laboratory simulation experiments. The team then experimented to determine optimal operating conditions for syngas conversion and studied the effects of numerous operating parameters on changes in the gasified surface (Daggupati et al., 2010). However, a correct mathematical model was not provided to define these processes. Therefore Stanczyk et al. (2012) developed a one-dimensional numerical model to study the influence of operating conditions (for example, temperature, pressure, water flow, gas composition) and coal characteristics (for example, thermomechanical exfoliation characteristics, reactivity, composition) on the growth rate of local cavities and energy efficiency. It has been found that the thermal-mechanical cracking of coal, ash behavior, and the amount of carbon incorporated in the coal mainly affect the combustion rate (Perkins and Sahajwalla, 2006) projected a one-dimensional packed bed model for UCG control, which maintains the expected calorific value of the exhaust gas mixture by controlling the injected gas flow rate. The model can also predict important data parameters such as gas composition and combustion speed. However, in these control models, it is necessary to assume that the total concentration of all gases in the entire active chamber is constant. Uppal afterward improved the design of the simplified UCG model sliding mode control algorithm to ensure the stability of the thermal output value of the entire system (Uppal et al., 2014; Uppal et al., 2018; Saravanan et al., 2018).

Pre-combustion CO₂ capture is largely employed in IGCC and coal gasification-based polygeneration systems. IGCC and CCS/CCUS are currently one of the most promising directions. In the pre-combustion capture process, the fuel is changed into synthesis gas in the reformer or gasifier and then undergoes a shift reaction to yield a mixture of CO₂ and H₂. CO₂ is mainly captured from this gas blend containing H₂ at high pressure of 10–80 bar and moderate CO₂ content of 15%–40%. In addition to CO₂/H₂ separation, the gas supply also contains CO, H₂S, and, other sulfur components. The high pressure of this generated gas stream promotes the removal of CO₂. The main CO₂ removal technology is the absorption process, and the solvent can be a chemical or physical solvent. Removing u sulfur components, such as H2S, is also necessary from the gas stream (European Technology, 2005). See Figure 9.

PCC CO₂ capture removes CO₂ in flue gas discharged after combustion. Many first-generation CCS projects are expected to be implemented through PCC based on chemical absorption (Nakaten et al., 2014), as seen in Figure 10. Amine-based post-combustion capture is the most developed of the CO₂ capture options. PCC CO₂ recovery after combustion can remove CO₂ in the flue gas emitted. As shown in Figure 10, numerous first-generation CCS developments are projected to be carried out through PCC connected with chemical absorption (Nakaten et al., 2014). Currently, the utmost advanced CO₂ capture selection is the amine-based PCC.

Combustion enhancement, characterized by oxy-fuel combustion, has been effectively applied in minor pilot projects. For example, the Schwarze Pumpe (30 MW) in Germany, Callide (30 MW) in Australia, and the 35 MW oxy-combustion test unit in Yingcheng, Huazhong University of Science are successful applications (Tollefson, 2011). See Figure 9.

Captured CO₂ is typically pumped into deep saline and undeveloped deep coal or oil and gas-depleted fields (see Figure 11). Recently developed CO₂ utilization technologies include chemical, geological, and bio utilization (Wang et al., 2011). However, traditional storage operations such as in brine formations and oil and gas fields are well known. These technologies are not expected to pose additional risks to the operation of UCG and should be considered the initial project development target. In contrast, storage in non-traditional units (oil shale, basalt) requires more scientific knowledge than is currently available (Burton et al., 2006).

CO₂ transport methods primarily include tankers, vessels, and pipelines, and transporting CO₂ over pipelines is considered the most cost-effective and consistent method for bulk and long-distance transport (Wang et al., 2011). Figure 12 shows a schematic flowchart of CCS and transportation.

Daggupati et al. (2011) and IEA (2016) carried out research scale UCG tests utilizing superheated steam as a gasifying medium. The advent of steam at a low temperature of 150°C to UCG combustion depth quenches the fire front and leads to unproductive gasification (IEA, 2016). Especially in the light of high ash Indian coals, steam dissemination through an ash deposit within the cavity may decrease the temperature. Furthermore, superheated steam transportation to deep underground cavities (>300 m) is challenging due to heat loss via pipelines. The linings of the pipelines result in extensive energy demand in the steam-based UCG process. Thus, according to (Stanczyk et al., 2012), UCG oxygen gasification is deliberate for coals with excessive ash content, and research shows the viability of creating a medium calorific product gas with enhanced CO (∼210 kJ/mol) in the absence of steam to the UCG input stream.

In UCG oxygen gasification, the integral moisture reactivity with char enhances the steam gasification reaction at the early stages of combustion; in any case, combustion-generated CO₂ improves the Boudouard equation (Eq. 1) by reacting it with the adjoining char sites at the moisture depleted conditions of the coal seam.

Boudouard equation: C + C O 2   →   2 C O   Δ H = + 168.9   K j / m o l (1)

Therefore, research results from (Stanczyk et al., 2012) show high UCG practicability to be carried out in a CO₂ mode, which is a promptly accessible enhancer for gasification. In addition Prabu and Jayanti (2012), examined Indian coal inherent gasification kinetic parameters in the temperature range of 800–1,050°C given CO₂ based UCG with a thermogravimetric analyzer (Mandapati et al., 2012) experimented on O₂/CO₂ UCG gasification with different CO₂ concentrations in a virtual coal seam. It was observed that CO₂ UCG gasification increases the CO/H₂ product gas ratio and improves gas calorific content. For proficient gasification, preheating the CO₂ as a gasifying medium to high temperatures is cost-effective relative to the generation of superheated steam in a UCG steam-based operation. Furthermore, CO₂ gas can be delivered at room temperature to the profound underground cavities for in-situ gasification.

Several works of literature have outlined ongoing research that uses CO₂ gas as a key coal gasifying agent (Chen et al., 2013) carried out two-stage underground coal gasification using CO₂ air as the gasifying medium. It was observed that with a rise in the CO₂/oxidant molar ratio, the calorific content of the syngas reduced progressively. At 0.5 M proportion of CO₂/oxidant, a syngas with a least standard calorific value of 65 kJ/mol is delivered. Figure 12 shows the calorific value of the product gas for the experiment in (Chen et al., 2013). Thus, it was established that the ideal stream rate of CO₂ is 0.2 LPM for the O₂/air molar proportion of 0.11 for coals with low ash. However, relative to high ash coals, the rise in the CO₂ stream rate to 0.3 LPM led to quenching within the borehole combustion front. In this way, 0.2 is the ideal molar ratio of CO₂/oxidant for high ash coals at the O₂/air molar ratio of 1.

Under the guidance of national policy and with the support of government departments at all levels, China has built more than a dozen CCS demonstration facilities with a CO₂ capture capacity of over ten thousand tons in coal-fired power plants and coal chemical plants. The largest CO₂ capture capacity in these facilities is over 10 million tons per year. In addition, CO₂ injection demonstrations have been conducted in the enhanced oil recovery and carbon storage industry, with the largest reserves exceeding 15 million tons per year. Completed demonstration projects include 10 million tons per year for brackish terrestrial CO₂ storage projects, microalgae carbon capture projects (Global CCS Institute, 2017). See Table 6 for an overview of major CCUS pilot demonstration projects in China. Table 8 shows key project events and the budget for the Shenhua CCS project.

UCG-based power plants are similar to IGCC power plants, except for surface gasifiers (Burton et al., 2006). A simplified comparison of the capital costs of UCG power plants and IGCC can be made by comparing the required process units and capacity. The published cost estimate of the IGCC process unit is based on the analysis of a GE airflow gasifier with a carbon capture function (Burton et al., 2006). According to the design configuration and simulation results, the main differences between UCG and IGCC ground equipment. By eliminating the surface gasification device and reducing the size of the ASU, the overall capital cost of the UCG power plant is expected to be saved by 33%.

Several studies have been published on the economics of IGCC power plants and pulverized coal power plants, the current standard. According to the information developed by Burton et al. (2006), the cost of a supercritical pulverized coal (SCPC) power plant ranges from $1200 to $1460/kW. The same study estimates that the next-generation of IGCC power plants will be about 10% more expensive than the SCPC plants (vs. the current 20–25% premium). These places the cost of IGCC plants at $1440 to $1750/kW current technology, and $1320 to $1600/kW (advanced technology). Peng et al. (2016) has estimated the cost of an IGCC plant at $1,350/kW, which is in the same range as that estimated by Burton et al. (2006) for the advanced technology IGCC plants.

Much research has been published on the economics of IGCC power plants and the current standard pulverized coal power plants (Burton et al., 2006) states that the charge range of supercritical pulverized coal (SCPC) power plants are between $1200 to $1460/kW. Furthermore, future IGCC power plants will be approximately 10% cost higher than the SCPC power plants. These bring the cost of the IGCC plant to current technology from $1440 to $1750/kW and $1320 to $1600/kW (advanced technology). Peng et al. (2016) and (Burton et al., 2006) estimates a similar cost range of the IGCC plant or the advanced technology IGCC plant to be $1350/kW.

Another indicator of cost competitiveness is electricity prices (COE). Estimates by Peng et al. (2016) place COE for IGCC plants and SCPC at $46.6/MWh and $49.9/MWh. An advanced competitive economic study (Nakaten et al., 2014) indicates that for UCG power generation, the Levelized COE is estimated at €49/MWh without CCS and €72/MWh with CCS. Regarding figures released by Ergo Exergy (Maev et al., 2018), UCG-IGCC plants significantly have lower COE and construction costs. The cost of capital for a 177 MW plant presented by Maev et al. (2018) is approximately $600/KW and $450/KW for a 280 MW plant. The COE is projected to be around $12/MWh. According to Green (2018), CO₂ emissions from UCG power generation using combined cycle gas turbine (CCGT) range from 570 to 785 kg CO₂/MWh without resources to CCS, compared to 400 kg CO₂/MWh natural gas. CCS can decrease UCG emissions to less than 100 kg CO₂/MWh. These remarkable figures make UCG comparable to renewable energy and achieve the highest fossil fuel emissions in CCS.

Recently, UCG projects are common in China, South Africa, and Australia. These projects have chemical plants or operating power plants powered by UCG syngas. However, in Canada and the US, these projects are still in their development stages (Clean Air Task Force Report, 2009). Studies by Burton et al. (2006) state that the recent promising blend of technological features offers a commercially viable opportunity for the UCG process by enhancing the UCG technical variables and lowering the extreme effect on the environment. The same studies indicate that the first nation to introduce a general program for UCG R&D was USSR. By 1928, different national research projects had been organized, and in 1933 underground experiments began in Kurtova, Tula, Shati, Rennis-Kuznets, Korevka, and Lysychansk. While carrying out the experimental plan, theoretical plan and laboratory research were also carried out.

Currently, in the US, there are no UCG facilities in operation, and no major company is working on UCG research, but many other research projects are underway. In other regions, UCG projects have set off a new upsurge (Dalton, 2004) demonstrates the primary UCG projects overseas in the 20th century (from 1934 to 1997). Primary UCG projects from 2007 to 2011. In 2017, Geeta and Prabu (2017) pointed out that UCG activities were intense in many countries, which signifies a reduction in global UCG development 3 years ago. Table 7 shows the major UCG schemes and progresses in 2017.

The Chinese government has decided to develop the UCG project to reduce the pollution of coal-fired power plants, Private companies, like Seamwell Int. Hongli Clean Energy and others continue to maintain an interest in UCG feasibility and semi-commercial studies, mainly in Inner Mongolia, for the production of chemicals and power from UCG syngas (Khadse et al., 2007). According to Daggupati et al. (2010), this places UCG test centers in China to approximately 15 (Blinderman, 2005).