Challenges and Recent Advances in Sustainable Oil and Gas Recovery and Transportation

Challenges and Recent Advances in Sustainable Oil and Gas Recovery and Transportation delivers a critical tool for today’s petroleum and reservoir engineers to learn the latest research in EOR and solutions toward more SDG-supported practices. Packed with methods and case studies, the reference starts with the latest advances such as EOR with polymers and EOR with CCS. Advances in shale recovery and methane production are also covered before layering on sustainability methods on critical topics such as oilfield produced water. Supported by a diverse group of contributors, this book gives engineers a go-to source for the future of oil and gas.

The oil and gas industry are utilizing enhanced oil recovery (EOR) methods frequently, but the industry is also tasked with making more sustainable decisions in their future operations.

• Provides the latest advances in enhanced oil recovery (EOR), including EOR with polymers, EOR with carbon capture and sequestration (CCS), and hybrid EOR approaches
• Teaches options in recovery and transport, such as shale recovery and methane production from gas hydrate reservoirs
• Includes sustainability methods such as biological souring and oil field produced water solutions

• Language: English
• Publisher: Elsevier Science
• Release date: Mar 10, 2023
• ISBN: 9780323993050

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Part 1

Basics and advancements in oil and gas recovery

Outline

Chapter 1 Methane production techniques from methane hydrate reservoirs

Chapter 2 Biosurfactants and their significance in altering reservoir wettability for enhanced oil recovery

Chapter 3 Fluid production from NGH reservoir: fundamental physics, numerical model, and reservoir simulation

Chapter 4 Role of nanofluids in chemical enhanced oil recovery

Chapter 5 Biostimulation in microbial enhanced oil recovery: from laboratory analysis and nutrient formulation to field monitoring

Chapter 6 Microbial enhanced oil recovery: application of biosurfactants in oil and gas industry

Chapter 7 Simulation and modeling of fractured reservoirs: an overview

Chapter 8 Synergistic interactions of SmartWater with surfactant and polymer chemicals for enhanced oil mobilization

Chapter 1

Methane production techniques from methane hydrate reservoirs

Şükrü Merey¹ and Lin Chen²,³,    ¹Department of Petroleum and Natural Gas Engineering, Batman University, Batman, Turkey,    ²Institute of Engineering Thermophysics, Chinese Academy of Sciences, Beijing, P.R. China,    ³University of Chinese Academy of Sciences, Beijing, P.R. China

Abstract

Methane hydrates are considered as near-future energy resources. In the last two decades, many methane hydrate exploration activities were carried out in Canada, the United States, China, Japan, and India. One of the main difficulties in obtaining feasible gas production from methane hydrates is directly related to production techniques. This chapter aims to explain the currently available gas hydrate production techniques: depressurization, thermal stimulation, chemical injection, CH4–CO2/N2 replacement, and their combinations. Recent methane hydrate tests have shown that well stimulation techniques (i.e., fracturing and acidizing) are also crucial for higher gas production rates from methane hydrate reservoirs. Thus in this section well stimulation techniques for methane hydrate reservoirs are also discussed. The results of methane hydrate production tests in Canada, the United States, Japan, and China are analyzed to show both advantages and disadvantages of the currently available gas hydrate production techniques. Numerical gas production simulations in methane hydrate reservoirs are essential before applying a methane hydrate production test on a field scale. The recent improvement in methane hydrate simulators in the world is discussed in this section.

Keywords

Methane hydrates; methane production; gas hydrate; well stimulation; production simulations

1.1 Introduction

Gas hydrates are ice-like crystalline structures formed by water molecules and gas molecules at low-temperature conditions and high-pressure conditions (Chen & Merey, 2021). Although the first gas hydrate discovery was made by Sir Humphrey Davy in 1810 with chlorine hydrate, experience with hydrocarbon gas hydrates was attained after the plugging of hydrocarbon pipelines with hydrates in the 1930s (Sloan & Koh, 2007). Since the 1930s, many experimental and analytical studies were conducted for pure and mixed hydrocarbon compounds to form their gas hydrate equilibrium curves. The main targets of these studies were to avoid gas hydrate formation in pipelines, because gas hydrates were initially a problem for the oil and gas industry in both pipelines and drilling operations. After the 1970s, it was found that a huge amount of natural gas (mostly methane) is stored in hydrate-bearing sediments. Since then, many studies have aimed to estimate the amount of methane in methane hydrates in the world. Taking into account the scale of the earth and lack of the data these reserve estimations (varying from 30 to 7.60×10⁶ standard trillion cubic meters) were speculative (Chong et al., 2016). However it is obvious that the methane amount in methane hydrates in both marine and permafrost environments is enormous, and with this potential, gas hydrates can be considered "near-future energy resources," which has led to hot discussions and various designs of comprehensive utilization methods in recent years (Chen et al., 2017). Compared to other fossil fuels natural gas is much more environmentally friendly. Thus mainly the countries with a lack of conventional hydrocarbon reservoirs have focused on the exploration and production projects in gas hydrates.

1.2 Worldwide status of methane hydrate utilization

In the Siberian region of Russia, the Messoyakha gas field (Fig. 1.1) was discovered. Although initially it was considered a conventional gas reservoir, later, it was understood that it is a Class 1 hydrate reservoir (hydrate reservoir underlying a free gas layer) (Makogon & Omelchenko, 2013). However, due to the lack of data related to this field, the pioneering steps were taken in gas hydrate production trials at the Mallik Field of Canada (Fig. 1.1). The gas hydrate production trial in 2002 was conducted by applying the thermal stimulation method (50°C hot water circulation). The test conducted in 2002 was the first gas production test directly aiming to understand the production characteristics of methane hydrate-bearing sediments. This multi-national project helped scientists from the United States, Canada, India, and Japan gain experience in gas hydrates. In the 2002 test of the Mallik Field, 470 m³ of methane was produced with an average gas production rate of approximately 91 m³/day during the 124 hour test (Fig. 1.2). As seen in Fig. 1.2A, this gas production rate is far below the commercial level of gas production. Low reservoir temperature, high gas hydrate saturation (up to 80%) (Table 1.1), and low effective permeability of the Mallik Field are the main reasons for the low gas production rate. In 2007 and 2008, the depressurization method was applied to dissociate methane hydrate-bearing sediments. For depressurizing the methane hydrate intervals, the electrical submersible pump was used. However, an insufficient gas production rate was obtained, as shown in Fig. 1.2, during the 2007 test (12.5 hours) and 2008 test (144 hours) in the Mallik Field. The endothermic nature of gas hydrate dissociation caused a huge decline in the reservoir temperature around the wellbore. Thus the rate of gas hydrate dissociation decreased quickly.

Figure 1.1 Gas hydrate distribution in the world.

Figure 1.2 (A) Cumulative gas production and (B) gas production rate in the gas hydrate production trials in the world since 2002.

Table 1.1

Although the duration of gas hydrate production tests (2002, 2007, and 2008) was 12.5–144 hours in the Mallik Field, the scientists from Canada, the United States, India, and Japan gained great experience with gas hydrate reservoirs. Gas hydrate production trials in the Mallik Field were also beneficial for testing/improving gas hydrate numerical simulators. Since then (Figs. 1.1 and 1.2), the number of gas hydrate exploration activities and gas hydrate production trials has increased. Korea, the United States, China, Japan, and India were the main countries carrying out these gas hydrate projects. In 2012, depressurization and thermal stimulation (hot water injection and steam injection) production methods were applied for the gas hydrate (thermogenic sII hydrate) reservoir located in the Qilian Mountain permafrost (Fig. 1.1 and Table 1.1). During the 84 hour test, only 102 m³ of gas (mixture of methane, ethane, propane, butane, and CO2) was produced (Xiao et al., 2017). The main reason for this low production is the high stability of sII hydrates of the gas mixture, low permeability of shale–silt–sand mixed sediments, and high hydrate saturation.

Another gas hydrate production trial in the permafrost regions was conducted by the United States in Ignik Sikumi #1 well in Alaska in 2013 (Fig. 1.1). There are several concerns related to depressurization and thermal stimulation methods: sand production, geomechanical risks, and so forth. This is because sediments become looser after the dissociation of gas hydrates in the porous media. The CH4/CO2 replacement production method is suggested to provide CH4/CO2 replacement in the porous media. This will lead to CO2 sequestration, higher geomechanical stability, and lower water production. Approximately 4737 m³ of N2 and 1376 m³ of CO2 were injected into methane hydrate-bearing sandstone (Table 1.1) within 14 days. After the soaking period, 24,410 m³ of methane was produced within a month (Schoderbek et al., 2013) (Fig. 1.2). The replacement of CH4/CO2–N2 in the porous media was proved. However, low injection rates, low replacement ratio, and CO2/N2 hydrate formation risks are the main drawbacks of this method. Thus it has not been tested in the fieldscale since the Ignik Sikumi#1 well test was conducted.

Compared to permafrost gas hydrate exploration and production trials, the cost of these in offshore environments is quite higher. Therefore, between 2002 and 2012, mainly gas hydrate production trials were conducted in gas hydrate reservoirs in the permafrost regions. These tests were quite beneficial for understanding the gas production behavior of hydrate-bearing sediments with depressurization, thermal stimulation, and CH4–CO2/N2 replacement. It was understood that it is possible to drill gas hydrate wells if hydrate equilibrium conditions are not disturbed. Moreover, it was shown that there is no uncontrolled gas hydrate dissociation by these gas hydrate production wells. Low gas hydrate dissociation rates were the problem of these production trials. With these experiences, many countries (i.e., Japan, China, India, United States, and Korea) aimed to conduct gas hydrate exploration projects in their exclusive economic zone in the marine environment. This is because it is considered that approximately 99% of gas hydrates are deposited in the porous media of marine sediments (Beaudoin et al., 2014). After the collection and analysis of seismic, drilling, well logging, coring, and geological and geochemical data in the Nankai Trough (Japan) (Fig. 1.1), the first offshore gas hydrate production test was conducted in the Nankai Trough of Japan in 2013. By considering the huge potential of marine gas hydrates, this production test was a milestone for the gas hydrate industry. In the 2013 gas hydrate production test in the Nankai Trough, methane hydrate-bearing sands in an alternating turbidite (sand/clay) system (Table 1.1) were depressurized from 13.5 to 4.5 MPa by using the electrical submersible pump. Different from most conventional natural gas production wells, pumps are essential in gas hydrate wells because of huge water production together with gas from gas hydrate reservoirs. In the 2013 Nankai Trough test, approximately 120,000 m³ of methane was produced within 6 days, as shown in Fig. 1.2 (Yamamoto et al., 2017). However, the high water production (1200 m³), sand production (30 m³), and bad weather conditions caused the early termination of this production test (144 hours) (Chen et al., 2020). The experiences in the 2013 Nankai Trough gas hydrate production trial showed that water production and sand production are the main problems to be dealt with. Up to the second gas hydrate production trial in the Nankai Trough in 2017, careful well completion and production design were made by mainly overcoming the problems faced in the 2013 gas hydrate production trial in the Nankai Trough. For this purpose, in 2017, two separate gas production trials (24-day depressurization test and 12-day depressurization test) were conducted in the hydrate-bearing sand sections in the turbidites of the Nankai Trough (Fig. 1.2). In these two tests, the duration of the gas hydrate production trial was extended. In one of two test wells, ESP malfunction caused by sand production was detected, although specially designed gravel packing completion and sand screens were used. Although 200,000 m³ and 35,000 m³ of cumulative gas productions were observed in these tests (Yamamoto et al., 2019), they also faced the problems of declining gas production rate, increasing water production rate, and declining depressurization rate with decreasing reservoir temperature during endothermic gas hydrate dissociation.

Since the beginning of 2000s, China has conducted gas hydrate exploration studies in its exclusive economic zones (mainly in the South China Sea). These exploration studies showed that silty-clayey sediments are common in the South China Sea within the gas hydrate stability zone. However, gas hydrates are homogeneously distributed in the porous media of these low-permeable sediments. The effective permeability of hydrate-bearing silty-clayey sediments is much lower than that of hydrate-bearing sands (Li et al., 2018; Ye et al., 2018). For this reason, all gas hydrate exploration and production trials aim to provide gas production from methane hydrate-bearing sands except the gas hydrate production trials in the South China Sea, as listed in Table 1.1. China became the second country to conduct gas hydrate production trials in the marine environment in 2017. However, it was the first country to conduct gas hydrate production trials in hydrate-bearing silty-clayey sediments. In the Shenhu Area of the South China Sea (Fig. 1.1), a 60-day gas production trial from methane hydrate-bearing silty-clayey sediments was conducted by applying the fluid extraction production method. This production method is a combination of depressurization, sand controlling technology, and well/air/seawater monitoring technology. Approximately 309,000 m³ of gas was produced within 60 days (Fig. 1.2), which is the longest gas hydrate production test up to 2021, and no sand production was reported (Li et al., 2018). In 2017, another gas production test was conducted by China in the Liwan Area of the South China Sea. Different from all the previous production trials in the world, the solid fluidization production method was applied in this test. Basically, by water jetting, gas hydrate-bearing sediments (silty-clayey) along the wellbore were crushed to finer particles, and by circulation, gas was produced. For 8 days, only 81 m³ of gas was produced (Liu et al., 2019). This method might be harmful to health and environmental aspects. In Chinese gas hydrate production trials in the South China Sea, unique production methods together with well configuration and well stimulation were tested. This is because the target of these production tests is hydrate-bearing silty-clayey sediments. The absolute permeability of these sediments is in the range of a few millidarcy (md). Thus well configurations and other well stimulation techniques are essential to provide a commercial level of gas production rates from low-permeable methane hydrate-bearing silty clays. Thus horizontal wells are essential to reach the commercial level of gas production rates for methane hydrate-bearing silty-clayey sediments in South China. In 2020, for the first time, a gas production test (formation fluid extraction method) was conducted with the horizontal well section in the Shenhu Area (Fig. 1.1). During this 30-day test, approximately 861,400 m³ of gas (Fig. 1.2A) was produced, and this was a world record among all gas hydrate production tests (Ye et al., 2020). However, the gas production rate in this test is still below the commercial level of gas production (Fig. 1.2B). Thus the application of the horizontal well together with well stimulation techniques (fracturing, acidizing, etc.) has become a new step to reach the commercial level of gas production from methane hydrate reservoirs.

1.3 Well stimulation techniques for methane hydrate reservoirs

1.3.1 Fracturing in methane hydrate reservoirs

As seen in Fig. 1.2B, all gas hydrate production trials in the world could not provide a commercial level of gas production. Thus the gas hydrate industry seeks methods to increase gas production rates. Well stimulation techniques are commonly used in the oil and gas industry. For example, with the advancement in horizontal drilling technology and hydraulic fracturing technology, a commercial level of gas production was attained for shale gas reservoirs. Especially for low-permeable silty-clayey hydrate reservoirs, fracturing might provide additional gas production. Thus recently, experimental and numerical studies have been conducted to investigate the effect of fracturing in gas production from gas hydrate reservoirs. For instance, Zhao et al., in 2021, simulated core-scale hydrate numerically. It was shown that fracturing provides effective depressurization for hydrates deposited in sediments with low intrinsic permeability. Fracturing depth is important for effective gas production. Ma et al. (2021) used TOUGH+HYDRATE software to understand the effect of fracturing on gas production from the silty-clayey hydrates of the Shenhu Area. In different well completion scenarios, it was shown that 5 m horizontal fractures provide good channels for gas and water to flow through the wellbore. Although hydraulic fracturing in the hydrate-bearing layers provides additional gas production numerically and experimentally, the application of this well stimulation technique in the fieldscale might cause negative effects on gas production. Gas hydrates in the marine environment are a few hundred meters below the seafloor, so the sediments at these depths are very loose. During the fracturing of hydrate-bearing layers, overburdened sediments and underburdened sediments saturated with water might also be activated. This might cause a huge reduction in gas production rates and high water production. For this purpose, the sealing of hydrate-bearing layers’ top and bottom boundaries with sealing chemical agents was proposed by Li et al. (2021). The field-scale (in the conditions of the Shenhu Area) numerical simulations showed that this technique is important for higher gas production rates and lower water production rates in gas hydrate production wells. Gas hydrates in the marine environment are very close to the seafloor and fill the porous media of loose sediments. Therefore, it is quite difficult to frack only gas hydrate-bearing sediments. The wrong fracturing design might cause formation stability in these loose sediments (Kim et al., 2016). A new method stratification split grouting foam mortar method (SSFMM) was suggested to frack the low-permeable sediments having the permeability coefficient lower than 10−6 cm/s by injecting high-pressure mortar to overcome the initial stress and tensile strength of the sediments. This method was tested numerically in the conditions of the Shenhu Area gas hydrates in the study of Li et al. (2020). With this technique, numerically, it was shown that higher gas hydrate dissociation rate, higher cumulative gas production, and energy efficiency might be obtained. Different from other studies, in the study of Li et al. (2020), the geomechanical changes in the hydrate-bearing were also tracked by coupled thermal–hydraulic–mechanical processes. The SSFMM was also advantageous in terms of reservoir stability with increasing gas production. According to the analytical approach of Liu et al. (2020), the increasing injection rate and flow behavior of fracking fluid through hydrate-bearing sediments might provide high resistance to flow, and in this way, it is possible to create more short fractures in these loose sediments. With this technique, controlled mini fractures might be created around the frac-pack horizontal wells with efficient solid flow control. As expected, these fractures provide a higher depressurization rate, higher gas production rates, and higher gas recovery.

Although field-scale numerical simulations for hydraulic fracturing are essential for large-scale evaluations, small-scale experimental studies should also be conducted to understand the behavior of gas hydrate-bearing sediments during/after fracturing. It is essential to find the answers to the following questions (Too et al., 2018):

• Are proppants essential for keeping the fractures open in methane hydrate-bearing sediments?

• How much gas production increase can be obtained by fracturing?

• What would be the characteristics of fractures and what factors affect them?

Konno et al. (2016) tried to understand the behavior of methane hydrate-bearing sands during hydraulic fracturing experimentally. In this core-scale fracturing experiment in the triaxial cell, computerized tomography (CT) was helpful to track the changes during hydraulic fracturing. When the injection pressure exceeded the minimum principal stress above 2.9–3.9 MPa, fractures were created. CT showed that these fractures are laminar. Interestingly, the fracturing behavior of unconsolidated sediments was similar to consolidated rocks (i.e., tensile failure behavior). The increased permeability of sediments with fracturing was preserved even after fracture closing in low-permeable sediments (as in the Shenhu Area) (Konno et al., 2016). Shi et al. (2020) conducted triaxial fracting experiments. It was shown that better fracturing performance was obtained with higher gas hydrate saturation. However, the geological risks should also be evaluated during gas production from artificially fractured hydrate-bearing sediments.

1.3.2 Acidizing in methane hydrate reservoirs

With the gas hydrate production trials in the South China Sea (Fig. 1.1 and Table 1.1), low-permeable hydrate-bearing silty-clayey sediments have become new targets for the commercial level of gas production from gas hydrates. Considering the wide existence of low-permeable hydrate-bearing sediments in the world, a commercial level of gas production from these hydrate reservoirs will be a big step for the gas hydrate industry. However, horizontal well technology and well stimulation technologies are essential to reach the commercial level of gas production rates in gas hydrate production wells. Despite the application of horizontal well technology in the low-permeable hydrate-bearing sediments of the Shenhu Area of the South China Sea, well stimulation is essential for higher gas production rates. Hydraulic fracturing is a practical way to provide flow channels for these low-permeable systems. Moreover, acidizing is a well-known well stimulation technique that has been used in the oil and gas industry for many decades. Therefore, the effect of acid injection into methane hydrate-bearing sediments was investigated in the core-scale experimental setup by Nakano et al. (2018). HCl and HNO3 acids were injected into hydrate-bearing porous media at different concentrations. The inhibitor effect of acid heat released due to the reaction of acid and sediments (including Al, Mg, Ca, Si, etc.) provided significant increment (more than twice) in gas production recovery from hydrates. Sakamoto et al. (2020) proposed that acid injection might be preferred as an enhanced methane recovery technique after depressurization operation. For a better acidizing design, it is essential to conduct elemental analysis of the sediments.

1.4 Recent improvements in methane hydrate production simulators

Numerical simulations for the fluid flow in porous media are commonly conducted in the oil and gas industry. Mostly, numerical simulations are made under isothermal conditions by keeping the reservoir temperature constant. The fluid in the porous media is water, oil, gas, or their combination depending on the reservoir type. Mostly, geomechanical changes are ignored in conventional oil and gas simulations. However, gas hydrate in the porous media is unique in many aspects:

• Solid hydrate including gas and water and also its sediment cementing behavior

• The changes in pressure, temperature, and chemical conditions cause gas hydrate dissociation and the release of gas and water through the porous media.

• The change in reservoir temperature with the endothermic nature of gas hydrate dissociation or exothermic nature of gas hydrate reformation.

• With the dissociation of solid hydrate into free gas and free water, sediments become looser and geomechanical changes occur.

Due to the unique aspects of the gas hydrates mentioned above, the modifications are essential in classical reservoir simulators. Darcy flow equations are still valid in gas production simulations from gas hydrate-bearing sediments. In gas hydrate production simulations, the components in the porous media are methane, water, hydrate, chemicals (if they exist), and heat. Gas hydrate equilibrium conditions should be tracked in these simulators under nonisothermal conditions. Especially, after the 2000s, the number of gas hydrate production simulators increased. Many simulators were suggested by different research centers. Initially, these were mainly HydrateResSim, TOUGH+HYDRATE, CMG-Stars, STOMP-HYD-KE, Mix3HydrateResSim, MH-21, and Houston University simulator (Gaddipati, 2008). These simulators can predict gas and water production from methane hydrate-bearing sediments by using depressurization, thermal stimulation, chemical injection, and their combination. Different from other simulators, STOMP-HYD-KE and Mix3HydrateResSim can predict CH4-CO2/N2 replacement production methods for gas production from methane hydrate-bearing sediments. Due to the differences of gas hydrate production simulators from conventional oil and gas production simulators, it was crucial to validate the results of these simulators with field-scale gas hydrate production results. The first gas hydrate production trials in the Mallik Field were quite beneficial for improving gas hydrate production simulators (Johnson & Max, 2015). In a project of the DOE (Department of Energy, USA)/NETL (National Energy Technology Laboratory), the code comparison studies were conducted for seven case problems of gas hydrate simulations by five different reservoir simulators: CMG STARS, HydrateResSim, MH-21, HYDRES, STOMP-HYD, and TOUGH+HYDRATE (Anderson et al., 2008). As the production results were obtained by each simulator, quite different results were obtained. This showed that the improvements in gas hydrate production simulators by using long-term gas hydrate production tests are essential.

The gas hydrate production trial in the Nankai Trough of Japan in 2013 showed that sand production is an important risk of gas production from methane hydrate-bearing sands. As gas hydrate was dissociated by applying the depressurization method, free water and free gas were released through the porous media. The solid nature of gas hydrate keeps the loose sand grains together. Up to 2013, almost none of the gas hydrate production simulators mentioned above could predict sand production and geomechanical changes with gas production from gas hydrates. Thus it is essential to combine these gas hydrate production simulators with geomechanical modules. Then, many gas hydrate production simulators with geomechanical modules were released: HydrateBiot Code+FEM; TOUGH+HYDRATE; GEOS w/; MIX3HRS-GM; STOMP-HYDT-KE; UC Berkeley THM Code; and Geo-COUS. In 2020, these simulators with geomechanical modules were compared with the international code comparison study on coupled thermal, hydrologic, and geomechanical processes of natural gas hydrate-bearing sediments (White et al., 2020). At the same reservoir conditions, the gas production rates and water production rates were not the same, but this comparison study was important to improve the quality of gas hydrate simulators. Partial results and discussions of those simulators for multi-scale analysis of gas hydrate exploration and utilization have also been summarized by Chen and Merey (2021). In addition to the reliability of numerical simulators, the reliability of data used in these simulators is also significant. The reliability of relative permeability data, gas hydrate saturation data, porosity data, and so forth is important to obtain reliable gas and water production results.

As mentioned in Fig. 1.2, although the duration of gas hydrate production trials increased, a commercial level of gas production rate could still not be obtained in these trials. China showed that silty-clayey-bearing hydrates might also be a target for the commercial level of gas production. However, horizontal well production technology and well stimulation techniques are essential for attaining the commercial level of gas production rates. For this purpose, the number of gas hydrate production simulations for horizontal/deviated wells and fractured wells has increased recently (Chen et al., 2018; Yuan et al., 2021). In the last two decades, the gas hydrate production simulations were mostly conducted in 2D reservoir models. The reason for this was probably the lack of data sets and inability of gas hydrate simulators. However, considering the necessity of deviated/horizontal wells for hydrate-bearing low-permeable sediments and availability of reservoir heterogeneity data, gas production simulations with 3D reservoir models have been conducted recently (Ubeyd & Merey, 2021). With 3D simulations, supercomputers or big data servers are essentials.

Except for the simulators applying the CH4–CO2/N2 replacement method, all gas hydrate production simulators conduct flow simulations for 100% CH4. This is because most gas hydrate reservoirs include approximately 100% CH4. However, there are gas hydrate reservoirs that still include natural gas mixtures. For these gas hydrate reservoirs, it is quite difficult to track gas hydrate equilibrium conditions and compositional changes in the porous media. This also causes convergence problems in numerical simulations. The requirement of additional memory with gas compositions is also a problem for this kind of numerical simulation.

1.5 Worldwide projects initiated after ice-breaking trials in Japan and China

After the ice-breaking trials of methane hydrate production in Japan and China, there has been a new round of competition around the world for methane hydrate explorations. For those countries that import a large amount of natural gas, the governmental and commercial developments happened very quickly after the real trials since the 2000s. Large funds have been deployed in Japan and China for real explorations at Nankai Trough (Japan) and Shenhu Area of South China Sea (China), which finally led to the trials in Japan (2013 and 2017) and also in China (2017 and 2020) (Chen et al., 2018). For China’s real production in the Shenhu Area, the production rate was increased to around 20,000 m³/day in 2020 tests using horizontal well technology. In October 2020, China established its first National Key Laboratory of Gas Hydrate, and it will focus on fundamental research of hydrate physics and exploration technologies.

According to Chen and Merey (2021), in the United States, multi-authorities, such as governmental, public, and scientific organizations (DOE, USGS, BOEM, BLM, NRL, NOAA, etc.), have participated in a 5-Year Plan for Methane Hydrate Research and Development and then in the 10-Year (2015–25) plan of gas hydrate program, aiming at the continuous exploration at Gulf of Mexico and northern Alaska, where the infrastructure of gas/oil fields could be utilized for basic drilling tests. Also, a new project has been initiated in 2020 for a new round of tests in North Alaska (DOE, 2019). Between 2022 and 2023, at least 1-year gas hydrate production test (depressurization) will be conducted in the North Slope of Alaska with the collaboration of the USA and Japan. In April 2019, the US Department of Energy had a Board Committee meeting and slightly increased the budget for 2020–35 (DOE, 2019), aiming to conduct real production tests in the Gulf of Mexico in the 2025–35 period.

In 2021, the updated methane hydrate organization, a continuation of MH21 organization, MH21-S R&D consortium has been initiated by Japan Oil, Gas and Metals National Corporation (JOGMEC) The National Institute of Advanced Industrial Science and Technology (AIST). This organization is a renewed organization of MH 21, which is oriented toward the pore-filling type gas hydrate in the sand, and also organized with a continuation of Phase IV of MH21. The newly set target is 2023 for commercial-stage technology of pore-filling type gas hydrate utilization.

1.6 Trend discussion and future concerns

Since the beginning of 2000, there have been important developments in the gas hydrate industry. Before the 2000s, gas hydrates were considered very fragile systems and it was quite difficult to drill hydrate-bearing sediments. However, drilling expeditions in the last two decades have shown that it is possible to drill gas hydrate sediments safely by taking essential precautions. Most of these drilling operations were conducted with the logging while drilling system to gather in-situ reservoir data. The analysis of these data sets is important to estimate and predict in-situ reservoir conditions of hydrate-bearing sediments. Although considerable progress was attained regarding the drilling, completion, coring, and well logging of gas hydrate reservoirs, gas production has been the main problem for the commercial level of gas production from gas hydrate reservoirs. Depressurization, thermal simulation, depressurization combined with thermal stimulation, CH4–CO2/N2 replacement, and solid fluidization were tested in short-term (maximum 60 days) production tests. However, gas hydrate dissociation rate decline with reservoir temperature decline, sand production, high water production rates, low CH4–CO2 replacement rates, economical factors, technology limitations, and other environmental concerns are the main obstacles to reaching the commercial level of gas production from the gas hydrate reservoir in the long term.

Up to 2017, methane hydrate-bearing sands were the main targets for gas hydrate exploration and production projects. This is because hydrate saturation, porosity, and permeability in these reservoirs are high compared to other sediments. However, between 2017 and 2020, China showed that methane hydrate-bearing silty clayey (homogenously distributed in the porous media) might be another target for the commercial level of gas production from gas hydrates with the gas hydrate production trials in the Shenhu Area of the South China Sea.

The negative outcomes of long-term gas production from gas hydrates might be geophysical hazards (i.e., landslides, reservoir subsidence, gas seeps, etc.) and climate change effects (Partain & Yiallourides, 2020). Thus the selection of appropriate gas hydrate reservoirs and appropriate production methods with minimum risks is essential. However, there is something missing in the international legislation restricting and controlling gas hydrate exploration and production activities. It is essential to look into this before the worldwide application of the commercial level of gas production from gas hydrate reservoirs in terms of health, safety, and environmental aspects.

In 2020, China succeeded in its second test with daily production of 2.87×10³ ST m³ for a month, which brought large scale utilization of gas hydrate slightly closer to reality. In the plan of MH 21-S, the development of methane hydrate is entering the fourth stage of technological breakthrough and commercial production. These new trials and judgment will largely affect, toward a positive direction, the next round of investments and development in gas hydrate exploration. Major players of commercial traders and buyers of natural gas are paying attention to these recent developments and also carrying out investment into those emerging fields.

From technological aspects, new designs are still lacking for those different routes for utilizing methane hydrate. Given the complicated geological situations of hydrate mines and also the low production rate problem, new trials with different drilling, recognizing, monitoring, and simulating procedures are largely in demand. It is recommended that new designs and simulators be developed soon and worldwide comparisons are made to improve the prediction of production technologies in the