Over the past two centuries, industrial civilization has brought about substantial progress but also caused increasingly severe environmental and climate problems. A low carbon transformation of energy use is the key pillar to reducing CO₂ emissions toward a carbon neutral world. Renewable energy like solar and wind energy may dominate our energy mix completely in the future, but considering its tiny contribution to energy supply at present, the timing is still very uncertain (Michael and Arthur, 2019). According to the BP Statistical Review of World Energy, renewable energy accounts for only about 18% of the world's total primary energy consumption in 2021 (BP, 2022). In the transition to a low-carbon energy future, natural gas is considered a clean, efficient energy source that will likely become an important alternative to coal and oil and a transitional fuel for renewable energy (Javed, 2016; Zheng et al., 2016). With rapid global industrialization, the world’s demand for natural gas will grow sharply in the coming decades and will reach 4.9 trillion cubic meters (tcm) by 2040 (Sanja, 2021).

As conventional natural gas resources become depleted, exploration for unconventional gas resources is becoming increasingly important (Vedachalam et al., 2015; Kong et al., 2018). Natural gas hydrate (NGH), an ice-like carrier substance for natural gas formed by gas molecules and water molecules under high-pressure and low-temperature conditions (Sloan and Koh, 2007), is an unconventional gas resource and contains the largest gas resources remaining on the Earth. It is estimated that the gross carbon reserve of NGH is about twice as much as the total reserve of all the other fossil energy including oil, coal, and natural gas (Makogon, 1981; Kvenvolden, 1988; Englezos, 1993). NGH has been discovered worldwide in polar regions, normally associated with onshore and offshore permafrost, and in the sediment of outer continental and insular margins, with 90% of the ocean serving as potential areas for NGH deposits (Kvenvolden, 1993). In theory, when appropriate hydrate expansion factors are considered, 1 m³ of NGH contains up to 164 m³ of natural gas at standard conditions (Kvenvolden, 1993). According to preliminary estimates, the total global NGH reserve is approximately 1.5 × 10⁴ tcm (Makogon et al., 2005), which is large enough to replace the increasingly depleted traditional oil and gas resources. As a result, NGH is a worldwide strategic and prospecting commercial resource concerned by many countries in the 21st century (Makogon et al., 2005), and its industrialization has great significance for the world’s energy mix optimization, green development, and the achievement of peak carbon dioxide emissions and carbon neutrality.

Natural gas from NGH deposits can be theoretically produced by one or a combination of three main methods (Moridis and Sloan, 2007): 1. depressurization, in which the pressure is reduced below the equilibrium value at the system temperature; 2. thermal stimulation, in which the temperature is raised above the equilibrium value at the system pressure; and 3. injection of inhibitors such as salt and/or alcohol, by which the thermodynamic hydrate stability boundary is shifted to lower temperatures and higher pressures, thus inducing dissociation and gas release. Depressurization is thought to be the most technically efficient means of production from NGH deposits (Walsh et al., 2009; Michael and Arthur, 2019).

Over the last two decades, China has been attaching great importance to research on gas hydrate and has found a total amount of approximately 84 tcm of NGH reserves onshore and offshore, including the South China Sea, the East China Sea, and the Qinghai–Tibet Plateau, nearly 77% of which is distributed in the South China Sea (Tan et al., 2016). In 2013 and 2016, two NGH reserves with natural gas resources of more than 100 billion m³ each were discovered in the eastern offshore area of the Perl River Mouth basin and Shenhu area in the South China Sea (Yang et al., 2017). The NGH industrialization consists of five general stages, namely, the theoretical research and simulation experiment, the exploratory production test, the experimental production test, the productive production test, and the commercial production stages (Hao, 2022). In 2017, China successfully conducted its first offshore exploratory production test from clayey silt reservoirs, the most widely distributed NGH reservoirs in the world. It lasted for 60 days continuously and stably, yielding cumulative gas production of 30.9 × 10⁴ m³ (Li et al., 2018). Three years later, the second major leap was evidenced by the experimental production test in 2020. This time it achieved 30 days of continuous gas production and set a new world record for cumulative gas production of 86.14 × 10⁴ m³ (Ye et al., 2020). Because of these great successes, China has now entered the stage of productive production test and is accelerating its steps to achieve commercial development of NGH by 2030.

Like other conventional and unconventional resources, prior to NGH industrialization, it is necessary to conduct an economic evaluation to determine whether it is profitable or not (Chen et al., 2022a). There exist a lot of factors that can affect the economic feasibility of an NGH exploitation project. Meanwhile, economic production is rare and may be the most important one (Wu et al., 2020). Unfortunately, since now, only a few quantitative analyses of the economic production rate have been carried out. Based on previous studies on NGH industrialization (Yamamoto et al., 2014; Yang et al., 2014; Li et al., 2018; Ye et al., 2020), Wu et al. (2020) proposed that the economic production rate for terrestrial NGH industrial exploitation is 30 × 10⁴ m³/d/well, while for marine reservoirs, it should be no less than 50 × 10⁴ m³/d/well. Compared with several trial productions before, both capacities are still two or three orders of magnitude higher than those of pilot production tests (Figure 1). However, the economic production rate for profitable NGH industrial exploitation is not always fixed, and it may decrease with the development of low-cost exploitation technologies.

In recent years, some scholars have started to try to conduct economic evaluations of NGH exploitation, mostly with the method of energy return on investment (EROI) or the method of discounted cash flow (DCF). Kong et al. (2018) carried out an estimation of China’s production efficiency of NGH in the South China Sea based on different production capacities. The results show if the production rate for a single well can reach 2.3 × 10⁴ m³/d with a 12-year production life, the standard energy return on investment is 1.25, indicating the net energy delivered to society by NGH production is positive. Chen et al. (2022b) calculated each EROI of four NGH exploitation technologies to evaluate the economic potential. She illustrated that compared with thermal simulation, chemical injection, and CO₂ replacement, depressurization is the most economically feasible, with the lowest economic production rate of about 16–25 × 10⁴ m³/d per well. Walsh et al. (2009) presented a preliminary report on the economics of gas production from NGH with the method of discounted cash flow (DCF). According to the results, $12/Mscf (about $10.6/MMBtu) is the lowest gas price that would allow economically viable production from gas hydrates in the absence of associated free gas, while an underlying gas deposit will reduce the viability price estimate to $7.50/Mscf (about $6.62/MMBtu). The results also reported that the production cost for marine hydrate is $3.5–4.00/Mscf (about $3.1–3.5 MMBtu) more expensive than a conventional gas project given a 15% internal rate of return (IRR). Deepak et al. (2019) undertook a techno-economic study of a defined deepwater hypothetical gas hydrate accumulation in the Krishna–Godavari (KG) Basin located along the eastern margin of India. The economic evaluation suggested that when the predicted production rate reaches 600 × 10⁴ m³/d, the production cost will be $9/MMBtu, which means economically viable. Based on the currently assumed production system and gas production behavior, the MH21-S R&D consortium (MH21-S, 2019) described the criteria for NGH commercial production after conducting the economic evaluation of hypothetical hydrate accumulations located in the Nankai Trough, Japan. The calculation results presented that when the LNG price is $10/MMBtu, the production rate per well required for commercial production is about 15 × 10⁴ m³/d or more. Since the technology for commercial exploitation of NGH has not been established yet, exploring the economic production rate is critical to understanding the gap between pilot production tests and the final realization of commercialization. Notably, few studies focusing on the evaluation of the economic production rate for NGH industrial exploitation in the South China Sea have been conducted till now due to the lack of enough field data.

The objective of this article is to estimate the economic production rate required for the industrialization of gas hydrate at different gas prices from an economic point of view and to figure out the key factors affecting production capacity. For evaluation of the economics, calculating capital expenditure (CAPEX) and operating expenditure (OPEX) data are the two fundamental prerequisites. Although the exploitation of marine NGH is similar in many respects to that of offshore conventional gas, there are still some differences in a number of ways, some of which will have a significant effect on the overall economics (Walsh et al., 2009). Unlike conventional gas that can be produced by natural flow, NGH should be first dissociated into a fluid phase (gas and water) that can consume energy (Yamamoto and Nagakubo, 2021). In addition, because the water production from a gas hydrate reservoir could be highly variable, a gas hydrate development will require artificial lift such as electric submersible pumps (ESPs) or gas lift, which will also increase front-end costs in most cases, as well as operating costs over the life of the field (Walsh et al., 2009). On this basis, when the method of discounted cash flow (DCF) is applied, OPEX fully refers to an offshore gas project just as many of the evaluations reviewed previously may cause a large deviation. As for the energy return on investment (EROI) method, it is pretty hard to reasonably calculate CAPEX and OPEX data in energy terms due to the lack of enough available data for trial production tests. As an alternative solution, the authors use a hybrid model, which is widely used in the energy sector (Li and Zhang, 2018, Li and Zhang, 2019) and which combines both discounted cash flow (DCF) and energy return on investment (EROI) to estimate the economic production rate required for NGH industrial exploitation at different gas prices. Section 2 describes the method of discounted cash flow (DCF) and energy return on investment (EROI) and proposes a novel DCF-EROI hybrid model. Section 3 makes a range of assumptions for economic evaluation and gives data estimation of key parameters used in the model. Based on Section 3, Section 4 presents the study results and discussion in four different gas price scenarios. Section 5 carries out sensitivity analyses to reduce the uncertainty resulting from the limited data, and Section 6 states the conclusion.

For economic evaluation of gas hydrate exploitation, the economic production rate for each well is one of the most important factors, and it is obviously affected by the market gas price, which has a significant impact on total sales revenue (cash inflows). Due to the variability, it is pretty difficult to predict future gas prices. In this study, four gas price scenarios are assumed with the gas–water ratio set at 100, which is close to the data observed in the first offshore production test of methane hydrates in the eastern Nankai Trough (Yamamoto et al., 2014). The first scenario is at the gas price of $6.15/MMBtu, the average price of China’s imported pipeline gas in December 2021. The second scenario is assumed at the price of $10/MMBtu, the LNG price used by the MH21-S R&D consortium for economic evaluation. The third one is at $18.93/MMBtu, representing the average price of China’s imported LNG in December 2021. The last scenario is at the price of $35.4/MMBtu, the CIF price of China’s imported spot LNG in August 2022. Table 4 summarizes the economic production rates at sites GMGS1, GMGS2, GMGS3, GMGS4, and GMGS5 in the South China Sea, changing with the number of production wells in these four scenarios. Compared with the previous economic evaluations resulting from the literature reviewed earlier (Deepak et al., 2019; MH-21S, 2019; Wu et al., 2020), the calculation results are nearly within the same order of magnitude, which implies the economic production rates estimated could be regarded reasonable.

As shown in Table 4, under the same conditions of production life and gas–water ratio, economic production rates in the South China Sea are highly dependent on the gas price, ranging from 1.96 to 29.60 × 10⁴ m³/d/well. Given a certain gas price, the economic production rate needed differs at different sites but not very significantly. This is because the eight NGH sites are located in the similar geological condition with near water depth, costing similar capital expenditure and operating expenditure. In addition, all economic production rates at these sites will decrease with the increase of production wells, which may be resulted from the lower marginal costs for each well. Additionally, Table 4 also shows the effect of gas price and the number of wells on the economic production rate vary from site to site. Here, the GMGS4-SC1 site and GMGS5-W9 are taken for example. In most cases, the economic production rate at the GMGS4-SC1 site is a little lower than that at the GMGS5-W9 site with the same gas price and the number of wells, but this situation will reverse when the LNG price is $35.4/MMBtu, and the number of wells is more than 30. The reason causing such an interesting phenomenon is maybe the sensitivity of gas price and well number on economic production rate changes when these two key factors change by themselves, which will be analyzed in Section 5.

In the case of an actual pipeline gas price of $6.15/MMBtu in late 2021, the gas produced from NGH is certainly not competitive against imported pipeline gas at the current stage. In this scenario, the average economic production rate per well should be about 12.96–29.6 × 10⁴ m³/d, almost 4–10 times higher than the rate recorded in the second production test in Shenhu area, South China Sea (Ye et al., 2020). In other words, there is still a big gap between the gas production efficiency of actual production tests and that required for commercial production.

Based on the LNG price of $10/MMBtu, the economic production rates range from 7.45 to 13.26 × 10⁴ m³/d/well, lower than 15 × 10⁴ m³/d/well estimated by the MH21-S R&D consortium (MH-21S, 2019). This may be caused by the different expected well production life in the two models. In this study, the production life for each well is 30 years, while the parameter used by the MH21-S R&D consortium is 8 years. Considering that most of the life span investigated for simulation of gas hydrate exploitation is about 20–30 years or even longer (Cleveland, 1992; Walsh et al., 2009; Yamamoto and Nagakubo, 2021; Chen et al., 2022a; Chen et al., 2022b), it is more reasonable to assume a longer production life span of about 30 years for economic evaluation.

In the scenario of the LNG price of $18.93/MMBtu, it may look pretty promising to exploit gas hydrate with the economic production rate per well 3.67–5.63× 10⁴ m³/d, which can be achieved by some enhancement recovery methods like dual horizontal wells, etc. (MH-21S, 2019; Wu et al., 2020). In addition, when the LNG price is as high as $35.4/MMBtu, it means gas hydrate could be commercially developed with the lowest production rate needed of only 1.86 × 10⁴ m³/d. However, considering the longest production life in trial tests to now is just about 60 days (Li et al., 2018), and the maximum gas produced from production tests over the last two decades is only a total of 8.6 × 10⁵ m³ (Ye et al., 2020), there is still a long way to extract natural gas from NGH at a production rate of 1.86 × 10⁴ m³/d for nearly 30 years, which will have a cumulative gas production of about 122.2 × 10⁸ m³.

High economic production rate results from high cash inflows and low cash outflows over the production life span. As discussed earlier, a lot of factors can affect cash flows, such as the number of wells, gas price, production life, gas-water ratio, etc. In this section, taking the GMGS1-SH2 site as an example for the discussion, a sensitivity analysis is conducted to better understand the effect of four key factors on economic production rate.

As shown in Figure 3, when the number of wells increases, all economic production rates would generally decrease. However, the degree of decline is quite different for different gas prices. The lower the gas price, the faster the economic production rate drops with the rising number of wells. This may be explained by the fact that lower gas price causes lower cash inflows, making the economic production rate more sensitive to cash outflows resulting from drilling more wells. Meanwhile, even at the same gas price, the economic production rate also varies at different levels. Initially, when the number of producing wells increases, the curve of the economic production rate will decline and become more and more flat. While, when the well number reaches about 40, the economic production rate suddenly goes up and then goes down again when the well number arrives at about 47. After that, the curve will become nearly horizontal very slowly. A reasonable interpretation for the variation is that if the number of production wells is less than 40, wells may share the same facilities such as platforms or FPSO (floating production storage and offloading), resulting in the marginal cost for drilling a new well becomes less. Once the well number hits the threshold, another new platform may be needed, and more expenditure will cost.

When the gas–water ratio changes, the energy input for the artificial lift will be different, causing the gas production cost to fluctuate. Similar to the sensitivity analysis on the number of wells, we refine the gas–water ratio to analyze its sensitivity to economic production rate. Figure 4 shows that with the rise of the gas–water ratio, the economic production rate will rapidly drop down from a very high peak and, then the magnitude of the decline becomes smaller and smaller. This is because when the assumed gas price is lower than the cost of lifting produced water, it is impossible to compensate the production cost by sales revenue, no matter how much natural gas is produced. On the other hand, if the gas price is higher than the unit production cost, the higher the gas–water ratio, the less impact it will have on the economic production rate. When the gas–water ratio is higher than 200, the impact is very low; if it is as high as 1,000 or more, the effect of the gas–water ratio can be negligible.

As discussed previously, gas price will directly determine cash inflows. A high gas price means a low economic production rate needed based on the same conditions. Figure 5 illustrates the negative correlation between the economic production rate and natural gas price. Apparently, with a lower number of wells, the gas price has a higher sensitivity to the economic production rate. However, when the number of production wells is more than 40, the gas price has no obvious effect on the economic production rate.

To accelerate the pace of hydrate industrialization, promoting production capacity and reducing the production cost through technological progress are the two main ways. Figure 6 describes the impact of different rates of decreasing production costs on the economic production rate. Gas price fluctuations make the economic production rate go down at different rates. Similar to the gas–water ratio and the number of wells, the lower gas price has stronger negative correlations with the economic production rate. Based on the previous analysis, it is reasonable to conclude that at a lower natural gas price, it is more necessary to develop gas hydrate exploitation technology to reduce production costs.

NGH is a strategic resource with a huge natural gas production potential. The industrialization of NGH has great significance for the achievement of peak carbon dioxide emissions and carbon neutrality. Economic evaluation is a prerequisite for NGH industrial exploitation. In this study, the economic production rate for industrial exploitation of NGH in different parameter scenarios, such as gas price, the number of wells, gas–water ratio, and decreasing rate in production cost, is estimated with a new hybrid method based on the discounted cash flow (DCF) method and the energy return on investment (EROI) method, and the following results are obtained:

1) The economic production rate of natural gas hydrate at sites GMGS1, GMGS2, GMGS3, GMGS4, and GMGS5 in the South China Sea is quantified in four scenarios with different gas prices. Changing the number of wells from 20 to 60, the economic production rate ranges from 1.96 to 29.60 × 10⁴ m³/d/well.