progress in global gas hydrate development and production
TRANSCRIPT
Progress in Global Gas Hydrate Development and Production as a New Energy Resource LIU Liping1, 2, 3, SUN Zhilei2, 3, *, ZHANG Lei4, WU Nengyou2, 3, Yichao Qin5, JIANG Zuzhou2, 3, GENG Wei2, 3, CAO Hong2, 3, ZHANG Xilin2, 3, ZHAI Bin2, 3, XU Cuiling2, 3, SHEN Zhicong1 and JIA Yonggang1 1 College of Environmental Science and Engineering, Ocean University of China, Qingdao 266100, Shandong, China 2 Laboratory for Marine Mineral Resources, Pilot National Laboratory for Marine Science and Technology (Qingdao),
Qingdao 266071, Shandong, China 3 The Key Laboratory of Gas Hydrate, Ministry of Natural Resources, Qingdao Institute of Marine Geology, Qingdao
266071, Shandong, China 4 Drilling Technology Research Institute of Shengli Petroleum Engineering Corporation Limited, SINOPEC, Dongying
257017, Shandong, China 5 Linyi University, Linyi, 276000, Shandong, China Abstract: Natural gas hydrates have been hailed as a new and promising unconventional alternative energy, especially as fossil fuels approach depletion, energy consumption soars, and fossil fuel prices rise, owing to their extensive distribution, abundance, and high fuel efficiency. Gas hydrate reservoirs are similar to a storage cupboard in the global carbon cycle, containing most of the world’s methane and accounting for a third of Earth’s mobile organic carbon. We investigated gas hydrate stability zone burial depths from the viewpoint of conditions associated with stable existence of gas hydrates, such as temperature, pressure, and heat flow, based on related data collected by the global drilling programs. Hydrate-related areas are estimated using various biological, geochemical and geophysical tools. Based on a series of previous investigations, we cover the history and status of gas hydrate exploration in the USA, Japan, South Korea, India, Germany, the polar areas, and China. Then, we review the current techniques for hydrate exploration in a global scale. Additionally, we briefly review existing techniques for recovering methane from gas hydrates, including thermal stimulation, depressurization, chemical injection, and CH4–CO2 exchange, as well as corresponding global field trials in Russia, Japan, United States, Canada and China. In particular, unlike diagenetic gas hydrates in coarse sandy sediments in Japan and gravel sediments in the United States and Canada, most gas hydrates in the northern South China Sea are non-diagenetic and exist in fine-grained sediments with a vein-like morphology. Therefore, especially in terms of the offshore production test in gas hydrate reservoirs in the Shenhu area in the north slope of the South China Sea, Chinese scientists have proposed two unprecedented techniques that have been verified during the field trials: solid fluidization and formation fluid extraction. Herein, we introduce the two production techniques, as well as the so-called “four-in-one” environmental monitoring system employed during the Shenhu production test. Methane is not currently commercially produced from gas hydrates anywhere in the world; therefore, the objective of field trials is to prove whether existing techniques could be applied as feasible and economic production methods for gas hydrates in deep-water sediments and permafrost zones. Before achieving commercial methane recovery from gas hydrates, it should be necessary to measure the geologic properties of gas hydrate reservoirs to optimize and improve existing production techniques. Herein, we propose horizontal wells, multilateral wells, and cluster wells improved by the vertical and individual wells applied during existing field trials. It is noteworthy that relatively pure gas hydrates occur in seafloor mounds, within near-surface sediments, and in gas migration conduits. Their extensive distribution, high saturation, and easy access mean that these types of gas hydrate may attract considerable attention from academia and industry in the future. Herein, we also review the occurrence and development of concentrated shallow hydrate accumulations and briefly introduce exploration and production techniques. In the closing section, we discuss future research needs, key issues, and major challenges related to gas hydrate exploration and production. We believe this review article provides insight on past, present, and future gas hydrate exploration and production to provide guidelines and stimulate new work into the field of gas hydrates. Key words: natural gas hydrate, gas recovery, production technique, shallow gas hydrate, environmental monitoring
Citation: Liu et al., 2019. Progress in Global Gas Hydrate Development and Production as a New Energy Resource. Acta Geologica Sinica (English Edition), 93(3): 731–755. DOI 10.1111/1755-6724.13876
* Corresponding author. E-mail: [email protected]
Acta Geologica Sinica (English Edition), 2019, 93(3): 731–755
© 2019 Geological Society of China http://www.geojournals.cn/dzxbcn/ch/index.aspx; https://onlinelibrary.wiley.com/journal/17556724
REVIEWS
Liu et al. / Review of the Progress in Global Gas Hydrate Research 732
1 Introduction 1.1 Global occurrence of gas hydrates
Gas hydrates are ice-like crystalline solids that form when water and suitably sized guest molecules such as methane combine under certain pressure and temperature conditions (Makogon, 2010). Gas hydrates form one of the largest methane reservoirs in the global carbon cycle, with 1 m3 of gas hydrate containing no less than 160 m3 of gas at standard temperature and pressure. This means that there is twice as much carbon trapped in gas hydrates as there is in the world’s combined fossil fuels (Song et al., 2014). Naturally occurring gas hydrates are commonly found in permafrost area sediments (Collett et al., 2011), active and passive continental margin oceanic sediments (Kvenvolden, 2003), inland lake and sea deep-water sediments (e.g., Black Sea, Caspian Sea, and Lake Baikal) (Kvenvolden, 1985), and continental and continental shelf polar sediments (Mienert and Posewang, 1999). Continental margins, where sediments contain substantial amounts of organic matter, account for most the marine gas hydrates. More than 99% of gas hydrates are from continental slope marine sediments, with 95.5% of these found in deep water (usually greater than 1000 m) and 3.5% in shallower water (normally less than 500 m) on upper continental slopes (Ruppel and Kessler, 2017). Additionally, at some submarine cold-seep sites, massive pure hydrates exist on the seafloor, in shallow subseabed strata, or even in gas conduits (Liu et al., 2016).
Marine gas hydrates are stable over a range of high-pressure (>10 MPa) and low temperature (<10℃) conditions typical for deep-water sediments, at water depths greater than 300–600 m and beneath permafrost at high latitudes (Ruppel and Kessler, 2017). Data from seismic observations and drilling programs for gas hydrate exploration, show that marine gas hydrates are scattered through sediment layers from 500 m to 1500 m water depth (Paull and Dillon, 2001), but most gas hydrates are found from 800 to 2100 m water depth, especially in the Pacific Rim (Spence et al., 2000), at the Atlantic Margin (Dillon and Max, 2000), in the northern Indian Ocean (Max, 2003), around the Antarctic Peninsula (Tinivella et al., 2002), and in the Arctic (Yoon and Kim, 2001).
Gas hydrate deposit thickness and burial depths generally have close links with local heat-flow regimes. Based on more than two thousand heat-flow values provided by the International Heat Flow Commission, scientists have shown that estimated the base of gas hydrate stability fields is consistent with results from drilling core samples (Paull and Dillon, 2001). Therefore, it is obvious that the heat-flow regime plays a key role in gas hydrate deposit burial depth. Moreover, heat-flow regimes correspondingly vary for different continental margin types (Fig. 1). The most significant findings are: 1) Heat-flow values are relatively high at active continental margins because of active plate subduction. Thus, these continental margins generally have shallower gas hydrate deposits and thinner hydrate stability zones. Typical examples can be found around the Pacific Rim, where gas hydrate deposits have burial depths of approximately 170–300 m (Paull and Dillon, 2001; Kretschmer et al., 2015;
Ruppel and Kessler, 2017). 2) In contrast, heat-flow is relatively low at passive continental margins. Thus, gas hydrate deposits are correspondingly deep and hydrate stability zones are thicker (Paull and Dillon, 2001; Ruppel and Kessler, 2017). For example, hydrate deposits in Atlantic and the Antarctic Ocean have burial depths of 150–460 m (Paull and Dillon, 2001; Collett et al., 2015; Ruppel and Kessler, 2017).
1.2 Gas hydrates as a potential energy resource
Many studies during the past four decades have focused on estimating the global gas hydrate inventory; however, the results from these studies vary significantly. Over time researchers have developed their understanding of how gas hydrates are distributed and concentrated in marine sediments and permafrost, thus there is a difference of three to four orders of magnitude between the earliest and most resent estimates (Milkov, 2004). This can be clearly seen through a negative correlation between gas hydrate inventory estimates and the number of research papers on gas hydrates being published (Wang et al., 2005).
The methods used to estimate global hydrate-bound gas volumes in marine sediments can be categorized into three periods: 1) The 1970s to the early 1980s, which involved pre-mapping and pre-drilling estimates, from Trofimuk et al., (1973) to McIver, 1981 (Milkov, 2004); 2) the late 1980s to the early 1990s, where pre-drilling estimates from Kvenvolden and Claypool (1988) to Harvey and Huang (1995) were dominant; and 3) the late 1990s to today, where estimates are based on drilling results from Ginsburg and Soloviev (1995) onward. It is noteworthy that global gas hydrate inventory estimates decreased by at least one order of magnitude from one period to the next (Fig. 2).
Current global estimates of hydrate-bound gas in marine sediments are obviously far lower than the originally estimated volume, largely because the earliest estimates were carried out before hydrate samples could be collected from marine sediments. At the same time, an agreed upon method for calculating need did not exist. Scientists based their work on different approaches, such as drilling samples, seismic reflection profiles, and simulation models, and the parameters applied in these approaches such as total organic carbon content, hydrate saturation, sediment porosity, and hydrate zone thickness. (Milkov, 2004; Wang et al., 2005). Scientists outside of China often use global hydrate inventory assumption parameters based on core drilling and seismic reflection profiles (e.g., bottom-simulating reflection (BSR)), and their estimates tend to be closer to actual results. However, scientists in China used to use simulation-and assumption-based parameters that might yield significant differences from international research (Yao, 2001; Zeng and Zhou, 2003; Chen et al., 2004).
Currently, the most popular measurement method for estimating hydrate-bound gas is the volumetric method (Milkov, 2004; Sun et al., 2013). On this basis, recent years have seen the proposal of a “gas hydrate-petroleum system” theory (Collett, 2009) that has provided a theoretical model for assessing gas hydrate resources more precisely. On one hand, this theory considers conditions
Acta Geologica Sinica (English Edition), 2019, 93(3): 731–755 733
that sustain gas hydrate reservoir stability, such as water depth, pressure, bottom water temperature, and heat-flow regime, which are applied to estimate hydrate stability zone burial depth and thickness (Paull and Dillon, 2001; Xu et al., 2012; Ruppel and Kessler, 2017). On the other hand, the gas hydrate-petroleum system theory is much more focused on actual geological conditions. That is, this theory is more reliable as it determines the parameters used in global hydrate-bound gas estimates (e.g., thickness, coverage, and hydrate saturation) using seismic data analysis and drilling results. Moreover, this method
yields a better constrained estimate of methane gas hydrate inventories for targeting future commercial production fields (Paull and Dillon, 2001; Milkov, 2004; Sun et al., 2013).
Kvenvolden (1999) analyzed a subset of estimates and suggested that the global hydrate inventory estimate should be 21×1015 m3 of methane at STP (approximately 1000 Gt of methane carbon). This was the most widely cited estimate and has been proposed as a consensus value because many independent estimates converged around that value. With the advent of core drilling methods and geophysical well logging since the mid-1990s, natural hydrate host sediment samples and quantitative borehole logs have revealed that only a small fraction of formation porosity typically bears gas hydrates (Boswell and Collett, 2011), except for some coarse-grained reservoirs with high-permeability (Liu et al., 2016). It appears that global volume of natural hydrate in host sediments is in the range 0.7–2×1015 m3. The best reflection of current marine gas hydrate knowledge yields a range of 1–5×1015 m3 (approximately 500–2500 Gt of methane), which is 4–20 times less than the most widely cited value of 21×1015 m3 (Milkov, 2004). Therefore, although global gas hydrate inventory is not as large as previously thought, it still amounts to a huge volume of natural gas that may be comparable in size to other organic carbon reservoirs, such as those of conventional petroleum and natural gas. This conclusion has also been supported by several recent studies. A recent global estimate performed by Boswell and Collett (2011), based on an exhaustive review of assessments and data from many drilling programs, yielded approximately 3×1015 m3 of methane in place at STP in global gas hydrates, which corresponds to approximately 1500 Gt of carbon or 2.0 million Tg of methane. Ruppel and Kessler (2017) preferred to adopt an in-place value of approximately 1800 Gt of carbon (which corresponds to 2400 Gt of methane) in hydrates for the global system, excluding the Antarctic.
Although global gas hydrate resource estimates lower than previous results, we should recognize that gas hydrate is an energy resource with massive amounts of stored methane, twice the amount of carbon found in all fossil fuels on Earth (Chong et al., 2016). The United States Department of Energy International Outlook report of 2013 proposed that global energy consumption would increase by 56% from 524 quadrillion BTU in 2010 to 820 quadrillion BTU in 2040 (US E.I.A., 2013). As energy portfolios and infrastructure transition to a gas-based economy, the more extensive geographic distribution and high energy density of gas hydrates would likely ignite interest from global research groups and industry. Additionally, gas hydrates are considered to generate less carbon dioxide per unit of energy than other fossil fuels, such as oil and coal; therefore, using gas hydrates as an alternative energy resource is a promising strategy for slowing greenhouse warming induced by carbon dioxide emissions (Chong et al., 2016; Koh et al., 2016).
Prior to this work, many papers from different perspectives on gas hydrate exploration have been published on; however, most focused on very specific topics of interest. Additionally, although a few review
Fig. 1. Theoretical gas hydrate stability zone thickness (modified from Ruppel and Kessler, 2017). Blue circles: recovered hydrate samples; red circles: inferred gas hydrates based on well loggings or geophysical indicators like bottom-simulating reflection at the base of hydrate stability.
Fig. 2. Estimates of methane held in hydrates worldwide (cited from Beaudoin et al., 2014). Earlier gas hydrate resource potential estimates made before hydrate had been collected from marine sediments (encompassed by the green re-gion), are high because hydrates were assumed to exist in nearly all global marine sediments. Subsequent estimates are lower (represented by the blue region) because the heterogeneous distribution of organic matter from which hydrate-associated methane originates was still uncertain. Despite this, marine hydrates are thought to contain one to two orders of magnitude more methane than global conventional natural gas reserves. Methane hydrates in permafrost (shown by the pink region) are estimated to be one percent of the marine estimates.
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articles in recent years have summarized gas hydrate statuses of different countries and field production trials, no review paper has focused on new progress and future ongoing works related to gas hydrates since methane was successfully recovered from hydrate reservoirs in the South China Sea. Our primary objective here is to provide a holistic review of all aspects of hydrate production carried out so far, especially the Shenhu production test, including production techniques and environmental monitoring systems. We also highlight how shallow gas hydrates are more suitable and promising for future production. Finally, we propose future research needs and identify major gas hydrate exploration and production challenges.
2 Gas Hydrate Exploration and Production 2.1 Gas hydrate exploration
Gas hydrate research can be divided into four periods (Zhang et al., 2005): 1) laboratory synthesis of gas hydrate in the early 19th century; 2) research on the formation mechanism of gas hydrate blockages during the test of deep-water gas wells and related facilities in the 1930s; 3) research proving the existence of gas hydrate reservoirs in the 1960s; and 4) exploration and gas hydrate field trials beginning in the 1990s.
Like conventional energy resource development, gas hydrate development generally occurs through two linked phases: exploration and production (Beaudoin et al., 2004). By far, hydrate exploration is mainly based on the seismic reflections of gas hydrate stability zone and hydrate dissociation-related leakage structures (also called cold seep system). Generally, there are three structural elements of a cold seep system (gas/fluid source, gas/fluid migration and seeping structures at or near seafloor) (Talukder et al., 2012). During the exploration phrase, various biological, geochemical and geophysical indications produced by cold seep systems are applied to guide exploration of possible gas hydrate occurrence to find the most promising reservoirs and evaluate their energy potential (Wei et al., 2016) (Table 1). Detailed monitoring or detection methods and integrated monitoring systems have been reported in our sister paper (Liu et al., 2019). In this paper, major technologies for
exploration of gas hydrate-bearing sediments are discussed in Table 2. Subsequently, interpretations from the exploration phrase are further verified by prospect drilling for extensive data collection such as geophysical well logging and drill core sample analysis. If drilling results are positive, delineation wells are then applied to define the extent and features of promising fields. Finally, numerical simulation models are used to assess recovery rate and potential economics of future field production (Moridis, 2002). Only after it has been deemed cost-effective to exploit gas hydrate deposits, based on required environmental standards, will the process enter the production phrase (Beaudoin et al., 2004).
Gas hydrate exploration approaches and techniques have gradually developed toward maturity, with the improved traditional petroleum systems concepts that guide conventional hydrocarbon exploration now being used for exploration of the most promising areas of gas hydrate accumulation. In addition to deep-water settings (Ginsburg, 1998), viable exploration approaches have also been taken in the Antarctic (Tinivella et al., 2002) and Arctic Ocean (Yoon and Kim, 2001). In these settings, pre-drilled wells, geochemical, and geophysical-based predictions were confirmed by later drilling. Recent ocean drilling programs have collected real hydrate samples from promising fields. Recent ocean drilling programs (ODPs) enabled the collection of gas hydrate samples from promising fields (Table 3). Scientific ocean drilling projects for gas hydrate systems and major deep-sea drilling voyages for the selection of production test sites are also reported in Table 3. Slowly, it has been realized that promising locations for sediments with high gas hydrate concentrations should be areas where there is combined evidence of hydrate existence from seismic surveys and later drilling activity (Wu et al., 2003; Beaudoin et al., 2004).
Currently, several countries have conducted national programs aimed at feasible exploration and exploitation of gas hydrates. In this section, we review the history and status of gas hydrate exploration in the USA, Japan, South Korea, India, Germany, the polar areas, and China.
2.1.1 USA
Gas hydrate investigations in the USA began in 1968
Table 1 Biological, chemical, and physical indications of possible gas hydrate occurrence Types Indicators Classifications Details
Biological indications
Cold-seep community
Ice worms δ13C, δ18OTube worms δ13C, δ18OBivalves δ13C, δ18OBacterial mats Microbial community composition
Biomarkers Associated with methane-oxidizing archaea Oprenoids and free isoprenoid hydrocarbons Associated with sulfate-reducing bacteria Dialkylglycerol diethers (DGDs) and fatty acids
Geochemical indications
Pore water anomalies
Methane anomalies Methane concentration, δ13C, δ18O Cation concentration Ca2+, Mg2+, Sr−, B3+, NH4+ Anion concentration Cl−, Br−, I−, SO4
2−
Authigenic minerals
Authigenic carbonate Petrology and mineralogy, δ13C, δ18O, rare earth elements (REE) Pyrite Petrological and mineralogical characteristics, S isotope, Fe isotope Authigenic sulfide minerals (gypsum, barite) Petrology and mineralogy
Geophysical indications
BSR / /Fluid plumbing
system Mud volcanos, diapirs, faults, fractures, slope failures
Acoustic turbidity, acoustic curtain, acoustic blanket, acoustic column, enhanced reflection, incoherent zones
Gas leakage Plumes Height and shape
Acta Geologica Sinica (English Edition), 2019, 93(3): 731–755 735
with Blake Ridge as the research area; consequently, gas hydrate samples were acquired from the ODP Leg 164 sites in 1995 (Party OL1SS, 1996). Methane seeps widely occur in areas such as the Gulf of Mexico (GOM); In particular, in GOM, a unique type of methane seep is associated with migrating brines. However, the high chloride concentration inhibits the formation of gas hydrates, thus facilitating the migration of methane-bearing fluids into the overlying water column. In non-brine seep sites, methane-bearing fluids migrate to the gas hydrate stability zone, where methane can be captured in hydrate cages. Methane seeps in the GOM have been investigated via collaborative efforts of scientists from the U.S. Department of Energy, the U.S. Geological Survey, the Ohio State University, and Columbia University. A consortium of production and service companies also founded the GOM Gas Hydrates Joint Industry Project (JIP) in 2001. The JIP focuses on the assessment of hazards associated with hydrate-bearing marine sediments, the investigation of the formation and distribution patterns of gas hydrates, and the development of tools for monitoring environmental impacts related to marine natural gas hydrates dissociation (Ruppel et al., 2008). The JIP confirmed the presence of gas hydrates in the GOM in 2005 and reported a high saturation accumulation of gas hydrate in sand layers during the JIP Leg II in 2009. The JIP estimated the volumes of gas hydrate resources and the geotechnical parameters for production tests, following the review of potential drilling sites (Collett et al., 2012).
Studies using shipboard hydrocasts, multibeam bathymetry, satellite remote sensing, and ground-truth sampling over a large area, identified approximately 5,000 seep sites at water depths below 200 m in northern GOM. The results showed that methane contents in surface waters reached up to 1,000 times saturation relative to the atmosphere (Solomon et al., 2009). Seismic data revealed that gas hydrates in the GOM formed at water depths below 400 m, and 80% of these gas hydrates occur around seep sites linked with faults system. Drilling activities and
well logging in the GOM in 2017, conducted by researchers from the University of North Texas, resulted in the recovery of twenty-one 1-m long core samples. The GOM Hydrate Research Consortium introduced a Monitoring Station/Seafloor Observatory to monitor the dynamics of hydrate-bearing sediments in the Woolsey Mound of the Mississippi Canyon Block (MC118). The seafloor observatory comprises seismic–acoustic receiving arrays, geochemical arrays in the bottom water column and upper sediments, and micro-biologic sensors designed to monitor ambient seismic–acoustic noise, gas or fluid venting, and geochemical environmental conditions over a period of five to ten years (Mcgee, 2006). Multi-resolution seismic evidence collected by the seafloor observatory depict the Woolsey Mound as a mature example of a hydrate mound or outcrop with a fault gas-passage system emanating from the underlying salt diapirs. This system facilitates the migration of fluids from deeply buried oil and gas reservoirs into the hydrate stability zone. The occurrence of frequent gas seepage at the site of the seafloor observatory is responsible for the presence of chemosynthetic communities, authigenic carbonates, pockmarks, and hydrate outcrops in the seabed.
Significant research exists for the GOM but no commercial production has been reported. In contrast, the Ignik Sikumi #1 was drilled in the permafrost regions of the north slope of Alaska in 2012. The test well that was specifically designed for methane recovery through CO2/CH4 exchange in the hydrate-bearing sandstones lasted for 30 days and yielded 2.8×104 m3 of gas (Anderson et al., 2014).
2.1.2 Japan
The interest in gas hydrate exploration has surged in Japan owing to its consideration as a promising energy alternative to petroleum. Offshore gas hydrates exploration commenced in Japan in 1995. Between 1995 and 1999, Japan launched investigations on the occurrence and formation of gas hydrates in the eastern Nankai
Table 2 Technologies for exploration of gas hydrate-bearing sediments and sediment samplingTechnologies Classifications Technical purposes
Bathymetry systems
Single-beam system Multiple-beam system Split-beam system
1) Seabed topography observations in hydrate reservoirs; 2) Monitor submarine cold-seep system; 3) Detect gas plumes related to hydrate dissolution
Seismic systems
Single-channel cable seismic, SCS; Multi-channel cable seismic, MCS; Deep-tow multi-channel cable seismic, DTMCS; Vertical seismic cable, VSC; Ocean bottom seismograph, OBS/OBN; Ocean bottom seismic cable, OBC
1) Identify the bottom-simulating reflection (BSR) distribution; 2) Identify possible migration conduits of hydrate-related gas and their relationship with the free-gas reservoir below the BSR
Pressure tight piston corers
Pressure temperature core sampler (made in Japan); Pressure core barrel (used by the Deep Sea Drilling Project (DSDP));Pressure core sampler (used by the Ocean Drilling Program (ODP)) Fugro pressure corer (produced by Fugro)
Core samples were used to perform precise ground truth sampling and successfully recover hydrate deposit sediments at in situ pressure
Well-logging systems
Measurement while drilling (MWD) Wireline log
1) Identify hydrate-bearing layers; 2) Well-logging systems are usually applied during the middle period, thus, they can provide an additional tool between seismic surveys and drilling for determining hydrate saturations, which could help achieve a stereoscopic exploration from a point observation.
Submarine visual systems
Deep-tow digital camera system Remote operated vehicle (ROV) Autonomous underwater vehicle (AUV) Deep-tow geo-acoustic systems Human occupied vehicle (HOV)
1) Submarine visual systems are capable of directly observing seafloor microtopography and other geological features around hydrate-related cold-seep sites. 2) Advanced positioning systems mounted on them are capable of performing accurate and precise ground truth sampling.
Liu et al. / Review of the Progress in Global Gas Hydrate Research 736
Tabl
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01
2006
K
rishn
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odaw
ari o
ffsh
ore
basi
n an
d A
ndam
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land
s D
rillin
g ve
ssel
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IDES
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olut
ion”
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/san
dsto
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-fill
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and
frac
ture
fillin
g ‐
hydr
ate/
mas
sive
blo
ck, v
eins
, len
s-sh
aped
92
0–26
60
30–7
00
120–
620
NG
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02
2015
K
rishn
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ari o
ffsh
ore
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kyu
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lock
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ens-
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0
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GS1
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07
the
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hu A
rea,
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ope
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outh
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na S
ea
Dril
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vess
el “
Bav
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ne-g
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rticl
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13
the
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gsha
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ion,
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orth
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outh
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ea
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re v
esse
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e”
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actu
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li‐
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ydra
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eds,
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ock,
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ns, n
odul
ar p
artic
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rticl
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1747
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0 80
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GS3
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15
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hu A
rea,
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ther
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th C
hina
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rillin
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ssel
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ate/
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ea /X
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uddy
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lty m
ud
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ults
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200
Not
e: *
all r
efer
ence
s are
from
Pau
ll an
d D
illon
(200
1)
Abb
revi
atio
ns: O
DP,
Oce
an D
rillin
g Pr
ogra
m; I
OD
P, In
tegr
ated
Oce
an D
rillin
g Pr
ogra
m; J
IP, G
ulf o
f Mex
ico
Gas
Hyd
rate
s Joi
nt In
dust
ry P
roje
ct; G
OM
, Gul
f of M
exic
o G
as H
ydra
te C
onso
rtium
; MET
, Cen
ter f
or M
arin
e R
esou
rces
and
Env
ironm
enta
l Tec
hnol
ogy;
UB
GH
, Ulle
ung
Bas
in G
as H
ydra
te; N
GH
P, In
dian
Nat
iona
l Gas
Hyd
rate
Pro
gram
; GM
GS,
Gua
ngzh
ou M
arin
e G
eolo
gica
l Sur
vey
Acta Geologica Sinica (English Edition), 2019, 93(3): 731–755 737
Trough, resulting in the collection of gas hydrate samples in 1999. A national project aimed at promoting the exploration for gas hydrates in the deep sea (>1000 m) in Japan’s Exclusive Economic Zone was proposed in 2001. The Research Consortium for Methane Hydrate Resources in Japan (MH21) conducted research following the Methane Hydrate Exploitation Program issued by the Advisory Committee. According to the project, the three major research areas for Japan’s offshore gas hydrate exploration include resource assessment, production method and modeling, and environmental impacts. Two-dimensional (2D) and three dimensional (3D) seismic reflection data acquired in 2001 and 2002 from the Nankai Trough, provided geophysical evidence on gas hydrate accumulation and saturation (Fujii, 2008). The Ministry of Economy, Trade and Industry’s (METI’s) “Tokai-oki and Kumano-nada” exploratory test wells that were drilled in 2004, served in the acquisition of well logs and core data for the assessment of methane resources (Awashima et al., 2008).
An initial full-scale production test was performed in the north slope of the Daini-Atsumi Knoll in the eastern Nankai Trough, Japan in 2013. The results indicated that depressurization was a feasible technique for commercial gas production from the offshore hydrate-bearing sediments. However, sand flow into the production wells halted the first production test (Konno et al., 2017). Despite addressing the problems encountered during the first production test and optimizing the well design, a second production test that began near the site of the first in 2017, was also halted owing to blockage by ice. Shallow gas hydrates present as massive aggregates on
the seafloor or in near-surface sediments have recently been discovered in the offshore area of Joetsu, Japan. According to METI, gas chimneys and venting structures facilitate the migration of gas and associated fluids from below the seabed (METI, 2013). As part of the national project on shallow gas hydrate exploration, a high-resolution acoustic survey using an autonomous underwater vehicle was conducted in the offshore area of Joetsu, Japan in 2014 (Matsumoto et al., 2014; Liu et al., 2016). The survey clarified the topography and shallow geological structures in the hydrate mounds and the pockmarks on the seafloor and captured acoustic blanks and enhanced reflection layers generally indicating high accumulation of gas hydrates.
2.1.3 South Korea
Geological and geophysical investigations for the development of gas hydrate as an alternative resource in Korea dates to 1997. The Korea Institute of Geoscience and Mineral Resources (KIGAM) conducted research in the Ulleung Basin, East Sea, off the east coast of Korea. Seismic profiles first revealed bottom simulating reflectors (BSRs) as indicators for the presence of gas hydrates in 1998. 2D multichannel reflection seismic data, 38 piston cores, and multibeam echo-sounder data were acquired between 2000 and 2004. Laboratory analyses of cores yielded high total organic carbon contents and high levels of residual hydrocarbon gas (Ryu and Riedel, 2017). Besides the abundance of BSRs across the Ulleung Basin,
the survey also resulted in the discovery of numerous gas chimneys. The research vessel R/V TAMHAE II, enabled the acquisition of 700 km2 of 3D seismic, high resolution compressed high intensity radar pulse, and echo-sounder data from 2005 to 2009 (Ryu and Riedel, 2017).
Two gas hydrate deep drilling expeditions, the UBGH1 and UBGH2, were completed in 2007 and 2010, respectively. The purpose of the UBGH1 was to confirm the distribution of gas hydrates in the Ulleung Basin. Seismic observations from the UBGH1 revealed five features indicative of the presence of gas hydrates including BSRs, methane plumes, gas chimneys, seismic blank zones, and enhanced reflections (Ryu et al., 2013; Yoo et al., 2013). The UBGH2 served for resource assessment and for the selection of sites for production tests in the Ulleung Basin. Remotely operated underwater vehicle (ROV) operations during the UBGH2 provided information on the morphology of the seafloor, and the dissolved methane concentrations of water near the seafloor and in push cores (Ryu et al., 2013). Chemical analyses, physical property measurements, pressure core analyses, and microbiological analyses were conducted in the “Main Lab” onboard the ROV or in the KIGAM laboratory (Ryu et al., 2013). The assessment of the in-place gas hydrate resources in the Ulleung Basin was completed in 2011 using seismic data and data from the UBGH2. Gas hydrate reservoir characterization for the selecting the trial sites for production occurred from 2011 to 2013. Financial constraints resulted in the postponement of the production test in the Ulleung Basin, originally planned for 2015 (Liu et al., 2019); the test remains unscheduled thus far. Nevertheless, environmental impact studies of gas hydrate in the Ulleung Basin have been performed to ensure future safe production since 2012 (Ryu et al., 2016).
2.1.4 India
The depletion of fossil fuel and the growing demand for carbon emission-free energy reinforces the need for an alternative source of energy in India. The Geological Survey of India has been conducting geological, geochemical, and geophysical investigations on offshore hydrate deposits since 1995. The Indian National Gas Hydrate Program Expedition 01 (NGHP-01) undertaken in 2006, provided information on the existence of gas hydrates along the passive continental margin of the Indian Peninsula and in the Andaman convergent margin together with insights on the geological factors controlling the accumulation of gas hydrates in both settings (Collett et al., 2014). During the NGHP-01 expedition, 39 holes at 21 sites were cored and/or drilled in the Kerala-Konkan, the Krishna-Godavari, the Mahanadi, and the Andaman deep offshore areas to assess the regional occurrence and features associated with offshore gas hydrate reservoirs along the continental margin of India. Besides, logging-while-drilling occurred in 12 holes and wireline logging in 13 additional holes (Collett et al., 2014). The Indian National Gas Hydrate Program Expedition 02 (NGHP-02) performed in 2015 off the east coast of India, explored the saturated hydrate deposits occurring in sand layers that are
Liu et al. / Review of the Progress in Global Gas Hydrate Research 738
targeted for production trials in India (Collett et al., 2017). A review of publications on the exploration, potential,
and development of gas hydrates in India revealed a compressive research-oriented program that focused on identification and quantification (Sain and Gupta, 2012). An updated gas hydrate stability thickness map along the Indian shelf providing the spatial and depth domains for gas hydrate exploration emerged in 2011. Detailed investigations on gas hydrates in the unexplored Cauvery and Kerala–Laccadive basins were proposed during 2012–2017 for their hydrate prospects. Review of literature however exposed no plan for a seafloor observatory or an integrated monitoring system for future offshore production tests in India.
2.1.5 German
Scientists in Germany are interested in gas hydrate research, with a significant focus on the impact of hydrate-related methane leakage on the global environment. Germany in cooperation with Russia conducted investigations on hydrate deposits in the Okhotsk region in 1998. Subsequently, scientists from Germany collected seismic data and sediment samples in the potential hydrate reservoirs of the Cascadia Subduction Zone, offshore western Oregon (Tréhu et al., 1999). Since the 1990s, Germany in association with collaboration programs has conducted hydrate investigations in the East Pacific Ocean, the Southwest Pacific, and the GOM. Another noteworthy investigation involving scientists from Germany is that of the active submarine cold seep system, the Håkon Mosby Mud Volcano (HMMV) (Vogt et al., 1997). Through partnerships with scientists from Norway and France, scientists from Germany significantly contributed to the understanding of the fluid and gas flow, hydrate distributions, geochemical characteristics, and microbial growth rate measurements in this cold seep system (Niemann et al., 1997). Researchers from Germany have focused on investigations of the methane leakage rate and the methane flux together with leakage impacts on the microbial community and their differences in the Black Sea and the GOM (Riedinger et al., 2010).
2.1.6 Polar areas
Investigations on gas hydrates in the continent of Antarctica began in the 1970s. High methane concentrations in Sites 271, 272, and 273 of the Ross Sea in Leg 28 of the Deep Sea Drilling Project (DSDP) signaled the presence of hydrates (Kvenvolden et al., 1993). Thus far, 9 expeditions of the DSDP and the ODP have established 67 drilling stations offshore Antarctica. Evidence from BSRs, geochemistry, and geophysics suggests that gas hydrates are likely to occur around the continental margin of the Ross Sea, Wilkes Land, the Prydz Bay, the Riiser-Larsen Sea, the South Shetland Islands, and the southeast continental margin of the South Orkney Islands (Wu et al., 2010). During the 34th expedition of the R/V “Xiangyanghong No.1” in Antarctica, scientists from China used seismic surveys, sub-bottom profiling, and TV grab sampling data to infer that sediments in the submarine environments affected by
hydrothermal activities and cold seeps existed in Antarctica. In these environments, metal-dependent anaerobic oxidation of methane dominates the consumption of hydrate-related methane and precipitation of carbonates. This implies that metalliferous sediments may exert a certain impact on the consumption of methane in Antarctica.
Analyses of samples from drilling, core logging data, and geophysical surveys suggest that gas hydrates in the Arctic generally occur beneath the permafrost regions and in offshore sediments around the shelf and continental margins. Gas hydrates are mainly distributed in the north slope of Alaska, around the Canadian Arctic Archipelago (Beaufort Sea margin and Mackenzie Delta), and the Siberian region of Russia (Boswell et al., 2011; Hung et al., 2017). In addition, hydrate samples were also discovered in offshore west Svalbard, the Barents Sea, and the Bering Sea (Collett et al., 2011). Gas hydrate reservoirs in the north slope of Alaska have been intensively investigated, with samples recovered from the area by scientists from the USA as early as 1972. Since then, gas hydrate reservoirs in the area have further been investigated via a collaboration of scientists from Japan, Canada, and America, with the aim of estimating the gas hydrate resource volume and delineating areas for exploration and production (Collett et al., 2011). Canada’s Mackenzie Delta hosts the highest number of gas hydrate exploration wells among permafrost regions in the world. Research on gas hydrate deposits in the Mackenzie Delta dates more than 30 years (Dallimore and Collett, 2005). The Håkon Mosby Mud Volcano (HMMV), one of the most active cold seep systems documented, located in the eastern continental margin of the Barents Sea, has attracted considerable attention since 2001. A submarine observation station of the Norwegian Margin node has been proposed for the long-term in situ monitoring of the environmental dynamics of the HMMV to determine a seep regime for this volcano system (Vogt et al., 1997).
2.1.7 China
The history of investigations on gas hydrates in China is divided into the following four stages:
(1) Preliminary stage (1995–1998) Scientists in China used an extensive review of
literature in the 1990s to understand the conditions of formation, worldwide distributions and impacts of gas hydrates on geological features and global climate. They proposed that marine gas hydrates were likely to occur southeast of the Dongsha Islands, Xisha Trough, and the Zhongjiannan Basin in the South China Sea (Guo et al., 2004).
(2) Initial field investigations (1999–2001) Scientists conducted investigations on gas hydrate-
bearing reservoirs in the Xisha Trough from 1999–2000. This resulted in the collection of multichannel seismic reflection data, multibeam bathymetric data, and surface sediment samples (Wu et al., 2005). This also provided the initial evidence of the presence of BSRs in the Xisha Trough (Zhang et al., 2002; Wu et al., 2005; Jiang et al., 2008). Scientists began assessing the gas hydrate resources in the East China Sea in 2001 and
Acta Geologica Sinica (English Edition), 2019, 93(3): 731–755 739
simultaneously investigated the impact of the occurrence of gas hydrates in the East China Sea on partitioning the exclusive economic zones between China and Japan (Luan et al., 2001).
(3) Field investigation and assessment (2002–2010) Since 2012, scientists in China have performed
multidisciplinary field investigations around the northern continental slope of the South China Sea, which is considered as the most promising area for gas hydrate exploitation in China; this slope includes the Xisha Trough, the Shenhu area, the Dongsha Region, and the Qiongdongnan Basin (Li et al., 2010). These investigations involved geophysical surveys (high-resolution multichannel seismic survey, multibeam bathymetry, and sub-bottom profiling), deep-sea video recording, and geological sampling. The scientists suggested that exploration for gas hydrates could rely on the identification of BSRs, amplitude blanking, cold seep-related geomorphic features, and geochemical anomalies. In 2007, gas hydrate samples were collected from the Shenhu area of the South China Sea (Li et al., 2010).
(4) Field investigation and preparation for production trials (2011–2018)
Comprehensive geological studies, geochemical surveys, and core drilling have been performed by the Chinese Geological Survey since 2013 to explore potential areas of gas hydrate accumulations in South China Sea. Core drilling expeditions in 2015 and 2016 resulted in the discovery of eight hydrate deposits, with an estimated total gas hydrate resource of 100 billion cubic meters in the north slope of the South China Sea (Liu et al., 2019). Two seeps (ROV1 and ROV2) referred to as the “Haima seeps” were identified in 2015 during ROV surveys in the northeastern slope of the South China Sea. Authigenic carbonate deposits containing abundant mussel shells, tubeworms, and mussels were encountered within the seep sites (Liang et al., 2017a). Scientists in China proposed the Shenhu area as the offshore test site for methane production from marine hydrates based on extensive geophysical, geological, and geochemical investigations.
Information on marine gas hydrate exploration worldwide reveals that sampling devices include box corers, TV grab samplers, gravity corers, and geological dredges. Techniques for finding indicators during gas hydrate exploration include multichannel seismic profiling, multibeam bathymetry, sub-bottom profiling, sampling of bottom water temperatures from a CTD (Conductivity Temperture Depth, CTD) cast, and data from an ocean-current meter (Table 1). The objectives of the hydrate exploration generally include: 1) monitoring dynamics of biogeochemical properties in hydrate-related cold seep areas; 2) gas hydrate-derived methane emission (leakage to seepage and venting); 3) hydrate-induced seafloor instability (Liu et al., 2019). More detailed information about monitoring techniques associated with hydrate exploration can be found in our sister paper (Liu et al., 2019). Based on the overview of information on gas hydrate exploration in published literature and reports, we propose a 3D monitoring platform for the identification of gas hydrates and characterization of impacts of marine hydrate formation and dissociation on the environment
(Fig. 3).
2.2 Gas hydrate production 2.2.1 Hydrate production techniques and field production tests
As with conventional energies, such as petroleum and natural gas, gas hydrate recovery will also occur through a routine process that includes exploration, reservoir evolution, potential recovery, potential economics, and so on. This process will be used to determine the most suitable gas production technique and the full production plan. Conventional energy reservoirs are sealed by sediments that are impermeable or have ultra-low permeability, thus the traditional gas and oil production technique is to excavate a channel into the reservoir and pump oil or gas to the surface. However, current studies of gas hydrate production involve two production mechanisms. The basic concept of the first type is based on in situ shifting of hydrate stability conditions to dissociate gas from the hydrates and create a channel to allow recovered gas to flow to the surface (Li et al., 2016). This concept includes depressurizing the reservoir, heating the reservoir, and chemical stimulation. The other concept, known as CO2–CH4 replacement, is based on replacing methane in hydrates with another gas molecule (CO2 or mixed gases) resulting in more thermodynamically more stable hydrates (Beaudoin et al., 2004; Li et al., 2016). The commonly used depressurization and thermal/heating techniques shift local P-T conditions to the unstable side, whereas chemical stimulation depends on in situ alteration of the phase equilibrium boundary to induce gas hydrate dissolution (Liu et al., 2013; Chong et al., 2016; Yang et al., 2016). In this section, we briefly and systematically review research progress on hydrate deposit gas production techniques and their advantages and disadvantages.
(1) Depressurization Depressurization can be carried out by decreasing
hydrate reservoir pressure or that of the overlying sediments adjacent to hydrate reservoirs. In this technique, pressure changes can be transferred to hydrate reservoirs through mechanical means. Additionally, it is important to note that gas hydrates in marine sediments are generally spatially linked to large volumes of methane occurring as free gas adjacent to the hydrate stability zone, which could be potentially released by pressure or temperature perturbation of gas hydrate provinces (Gorman et al., 2002; Flemings et al., 2003; Bai et al., 2009). The results of pressure reduction within the free-gas interval in underlying sediments can be transmitted to overlying hydrate deposits and induce hydrate dissociation (Rupple and Kessler, 2017). Some deposits in the Arctic that contain substantial free gas beneath hydrate reservoirs may be recovered using depressurization. The Messoyakha gas field in Russia is the first documented case of gas recovery from hydrate deposits (Table 4) and has produced gas from hydrate deposits almost continuously since 1970. The field trapped a large amount of free gas beneath the hydrate reservoirs that experience large temperature variations during the year. Therefore, free-gas production combined with hydrate reservoir
Liu et al. / Review of the Progress in Global Gas Hydrate Research 740
pressure decreasing to below hydrate stability’s equilibrium pressure contribute to the acceleration of the process of transferring hydrate into free gas (Makogon et al., 2005).
However, because of the endothermic heat of reaction, it is noteworthy that local temperature will continuously decrease with hydrate dissociation. If the temperature decreases to the equilibrium temperature at a certain pressure, the dissociation process may be impeded. Techniques used to alleviate this issue include adding heat to the production system or injecting a chemical inhibitor. Thereby, hydrate saturation decreases and effective permeability increases with hydrate dissociation, thus further inducing the growth of the reservoir with lower pressure (Li et al., 2016). However, the need to inject a chemical inhibitor or add heat to production facilitates may increase costs. For example, the Messoyakha gas field’s lifting cost is 15 to 20% higher than that of other gas fields in the area due to methanol injection costs (Makogon et al., 2005). Regardless, comparatively, thus far depressurization is regarded as the most cost-effective and practical method for recovering gas from hydrate reservoirs (Beaudoin et al., 2004).
(2) Heating the reservoir The objective of heating the reservoir (also known as
thermal stimulation) is to increase reservoir temperatures above the local gas hydrate stability temperature threshold to dissociate the hydrate. Heat may come from different sources, such as hot water, vapor, electricity, or even solar energy. The heating method can directly apply production equipment with conventional energy production. There are three ways to heat hydrate reservoirs (Li et al., 2016): 1) hot water circulation; 2) hot water huff and puff; and 3) wellbore heating. The first two methods depend on injecting hot water or vapor; however, the wellbore heating method uses electric energy and was first proposed by Islam in the 1990s (Li et al., 2012). Wellbore heating significantly reduces heat transmission loss during hot water or vapor injection, which is considered heating injection’s greatest disadvantage.
The only full-scale field trial applying heating stimulation was performed at the Mallik site in Canada’s Mackenzie Delta in 2002 (Dallimore and Collett, 2005). Hot brine (70℃ at the surface and 50℃ in the hydrate reservoir) was circulated through a 13-meter thick perforated test interval. This field test yielded less than 500 m3 of gas (Table 4), which implies that it is not particularly productive, as this test was not designed to evaluate a potential production method and prove the the hydrate reservoir’s commercial feasibility (Hancock et al.,
Fig. 3. A graphical view of environmental monitoring for a methane seepage and hydrate production test (Cited from Liu et al., 2019).
Acta Geologica Sinica (English Edition), 2019, 93(3): 731–755 741
2005). The test’s true objective was to observe the dissociation of a well-defined and geologically constrained hydrate interval at temperatures greater than the hydrate stability point, while maintaining constant pressure during a production test. Results from this field trial would provide data to laboratory numerical simulation models to determine the in situ kinetic and thermodynamic properties of hydrate reservoirs. Numerous experimental simulations of heating stimulation have been performed since Holder et al. evaluated the feasibility and effectiveness of this technique in 1980 (Holder et al., 1980). Using numerical simulation models, Moridis and Reagan (2007) and Moridis et al. (2009) suggested that thermal stimulation is thousands of times less effective than depressurization as a dissociation-inducing technique for recovering gas from hydrate deposits. The endothermic heat of reaction hinders rapid dissociation of hydrates and renders the production scenario a self-regulating process (Ruppel and Kessler, 2017). However, thermal stimulation is beneficial to overcome endothermic cooling induced by hydrate dissociation to prevent reformation of gas hydrates inside the wellbore. Moreover, a combination of depressurization and supplementary in situ thermal stimulation might be optimal for sustaining long-term hydrate production (Moridis and Reagan, 2007; Moridis et al., 2009; Beaudoin et al., 2014).
(3) Chemical stimulation Chemical stimulation generally refers to
injection of chemical inhibitors. Chemical inhibitor injection-based hydrate production involves control of phrase-equilibrium conditions or slowing hydrate formation rates by injecting dissociation-inducing inhibitors. This approach was initially applied to maintain wellbore flow assurance and prevent blockages in tubing due to unwanted hydrate formation (Beaudoin., 2014). Slowly, it was recognized that this principle was feasible for hydrate production. There are currently two kinds of chemical inhibitors on the market: thermodynamic inhibitors and kinetic inhibitors. Thermodynamic inhibitors, such methanol and ethanol glycol, work by changing phrase-equilibrium conditions, whereas kinetic inhibitors work by slowing the hydrate formation rate (Li et al., 2016). Like thermal stimulation, the key problem for chemical stimulation also has the disadvantage of fluid diffusion and effective permeability to the hydrate deposits.
Tabl
e 4
Prod
uctio
n fie
ld te
sts i
n on
shor
e an
d of
fsho
re g
as h
ydra
te d
epos
its
R
ussi
a C
anad
a U
nite
d St
ates
Ja
pan
Chi
na
Ons
hore
/offs
hore
on
shor
e
onsh
ore
on
shor
e on
shor
e
offs
hore
of
fsho
re
onsh
ore
on
shor
e of
fsho
re
offs
hore
Ye
ar
1972
–200
4 20
02
2007
, 200
8 20
12
2013
20
17
2011
20
16
2017
20
17
Test
site
M
esso
yakh
a M
allik
site
, M
acke
nzie
Del
ta
Mal
lik si
te,
Mac
kenz
ie D
elta
A
lask
a N
orth
Slo
pe
Dai
ni–A
tsum
i Kno
ll,
east
ern
Nan
kai
Trou
gh
Dai
ni–A
tsum
i Kno
ll,
east
ern
Nan
kai
Trou
gh
Qili
an M
ount
ain
Perm
afro
st
Qili
an M
ount
ain
Perm
afro
st
Shen
hu a
rea,
no
rther
n So
uth
Chi
na S
ea
Liw
an g
as
rese
rvoi
rs,
north
ern
Sout
h C
hina
Sea
W
ater
dep
th
—
—
—
—
~100
0 m
~1
000
m
—
—
1266
m
1310
m
Hyd
rate
rese
rvoi
r de
pth
730
m b
elow
the
land
su
rfac
e 90
0 m
bel
ow th
e la
nd su
rfac
e 11
00 m
bel
ow th
e la
nd su
rfac
e 70
0 m
bel
ow th
e su
rfac
e 30
0 m
bel
ow th
e se
aflo
or
350
m b
elow
the
seaf
loor
13
0–40
0 m
bel
ow
the
land
surf
ace
130–
400
m
belo
wth
e la
nd su
rfac
e 20
3–27
7 m
belo
w
the
seaf
loor
117–
196
m
belo
w th
e se
aflo
or
Hyd
rate
rese
rvoi
r lit
holo
gy
Sand
y-ar
gilla
ceou
s pe
rmaf
rost
laye
rs
Sand
-dom
inat
ed
perm
afro
st la
yers
Sa
nd-d
omin
ated
pe
rmaf
rost
laye
rs
Hig
hly-
satu
rate
d hy
drat
e-be
arin
g sa
nd
rese
rvoi
rs
Sand
-ric
h re
serv
oirs
San
d-ric
h re
serv
oirs
Fine
-gra
ined
sa
ndst
one
and
silts
tone
Fine
-gra
ined
sa
ndst
one
and
silts
tone
Cla
y si
lt la
yers
Mud
ston
e,
silts
tone
, and
cl
ay si
ltsto
neTe
chni
ques
of g
as
prod
uctio
n D
epre
ssur
izat
ion
+ C
hem
ical
inhi
bito
r in
ject
ion
Ther
mal
st
imul
atio
n D
epre
ssur
izat
ion
+ Th
erm
al st
imul
atio
n C
O2–
CH
4 re
plac
emen
t +
Dep
ress
uriz
atio
n
Dep
ress
uriz
atio
nD
epre
ssur
izat
ion
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Liu et al. / Review of the Progress in Global Gas Hydrate Research 742
Moreover, the costs associated with adding large amounts of chemical inhibitors to a reservoir are major considerations, as water released during hydrate dissociation may dilute inhibitors and decrease their effectiveness.
(4) CO2–CH4 exchange This production technique involves injecting CO2 into
hydrate-bearing reservoirs to induce a chemical exchange reaction that releases CH4 and traps CO2 in a solid CO2 hydrate, an idea that was first introduced by Japanese scientists (Ebinuma, 1993). The principle of this technique is that a CO2 hydrate is more thermodynamically stable than a CH4 hydrate at low temperature (Ota et al., 2005). This is because the equilibrium pressure for a CO2 hydrate is lower than that of a CH4 hydrate. Moreover, CO2 hydrate formation enthalpy (−63.6 to −57.7 kJ/mol) is lower than that of CH4 hydrate formation enthalpy (−55.4 to −52.7 kJ/mol) (Hossainpour, 2013). Therefore, exothermic heat from CO2 hydrate formation may drive the replacement rate through rapid CH4 hydrate micro-dissociation. The replacement mechanism has also been demonstrated by experiments using in situ Raman spectroscopy (Li et al., 2016). The core dispute regarding this technique is whether CH4 hydrates first disrupt and then reconstruct or if CO2 molecules directly replace CH4 molecules without changing hydrate structure.
The production of methane from hydrate formations by injection of industrially released carbon dioxide is a promising approach for simultaneously accessing an unconventional energy reserve while allowing synergistic storage of carbon dioxide (Beeskow–Strauch and Schicks, 2012). However, a major technical challenge is injecting carbon dioxide into water-bearing, low-permeability hydrate reservoirs. A CO2–CH4 exchange field trial, Ignik Sikumi #1, was conducted from temporary ice pads in the Prudhoe Bay area of Alaska’s North Slope in 2012. This field trial’s goal was to provide insight into basic scientific and engineering issues associated with this techniques potential for future use for synergistic methane production and carbon dioxide sequestration in hydrate deposits (Anderson et al., 2014). Table 4 shows the results of this field trial. To prevent the potential loss of injectivity due to hydrate reformation caused by free water or injectant, mixed gas (23% CO2+77% N2) rather than pure CO2 was used to enhance the opportunity for CO2 to interact with local gas hydrates (Hossainpour, 2013). Theoretically, depressurization could recover 95% or more of hydrates within a production well’s influence area, whereas carbon dioxide can only exchange with CH4 in larger clathrate structure cages with 64% exchange efficiency (Lee et al., 2003; Anderson et al., 2014). However, mixed gas injection can boost the recovery rate to 85% (Park et al., 2006) because the second gas achieves some displacement from smaller sI cages (Anderson et al., 2014). Anyway, applying CO2+N2 to produce CH4 from hydrate reservoirs shows great potential and is of future interest.
(5) Global field tests from onshore and offshore gas hydrate deposits
A summary of published studies shows that 82 countries have conducted research related to gas hydrate production(Chong et al., 2016). Based on the number of published
works, Japan, China, the United States, South Korea, and India are at the top of the list. Currently, hydrate field trials aim to demonstrate the feasibility of hydrate production techniques and prepare for future commercial production. In Table 4, we have reviewed onshore and offshore gas hydrate deposit field tests. The Messoyakha gas field has produced methane almost continuously since 1970, and by 2005, gas produced from this field has replaced 97% of the bituminous coal previously used (Makogon et al., 2005). Canada performed two field tests on onshore gas hydrate deposits at the Mallik site, Mackenzie Delta. The United States performed one field test on offshore hydrate deposits in Alaska’s North Slope (Collett et al., 2011). Japan carried out two field tests on offshore hydrate deposits in the Daini–Atsumi Knoll, in the eastern Nankai Trough. It is obvious that only China and Japan have carried out hydrate field trials on offshore hydrate deposits. However, gas hydrates are still a long way from commercial production. Each production technique discussed above has its shortcomings, such as high cost, low production rate, or energy waste; therefore, a combination of these techniques may be a better way to enhance production efficiency. For example, combining thermal stimulation and depressurization has been found to be more efficient for gas production from hydrate reservoirs. Gas could be recovered using depressurization after applying thermal stimulation, as was found in the 2007 Mallik production test and Qilian mountain permafrost test. Another example is combining chemical inhibitor injection with thermal stimulation, which may effectively prevent hydrate reformation induced by temperature decreases during hydrate dissociation. Meanwhile, inhibitors can easily flow to areas farther from the wellbore together with hot water (Li et al., 2016). However, to date this has not been verified in any significant hydrate deposits. 2.2.2 First offshore hydrate production test in northern South China Sea
Existing hydrate field trials have clearly focused on diagenetic gas hydrates. However, especially in marine sediments, most vein-like or bulk hydrates and those in fine-grained sediments are non-diagenetic gas hydrates. Generally, unlike conventional hydrocarbon reservoirs or sandstone hydrate reservoirs, hydrate deposits have no stable entrapment structures that can seal fossil fuel resources (Zhao et al., 2017). Based on thermal stimulation and depressurization, scientists in China have proposed two techniques: solid fluidization and formation fluid extraction. These two approaches have been verified in field trials in hydrate reservoirs in the northern South China Sea, and are introduced in the following two paragraphs.
(1) Solid fluidization The solid fluidization technique is specially designed
for non-diagenetic gas hydrates stored in poorly cemented shallow oceanic mud-sand layers. The ore bodies of this type of hydrate are crushed into fine particles by the jet at the borewell bottom and are transferred to a controllable tubing system through a sealed gas-liquid-solid multi-phase lifting system (Zhou et al., 2014; Zhou et al.,
Acta Geologica Sinica (English Edition), 2019, 93(3): 731–755 743
2017a). The sand is then returned to the seabed and the remaining gas-liquid-solid fluids return to the lifting system (Zhou et al., 2014). During the lifting process, increased seawater temperature and decreased hydrostatic pressure cause the crushed hydrate to dissociate. Thus, it is a well controllable process that can achieve green and safe production.
This technique was successfully applied in the Shenhu area of the South China Sea. Equipment and production processes rely on independent intellectual property rights in China (Zhao et al., 2017). In May 2017, the China National Offshore Oil Corporation used the deep-water engineering survey vessel HYSY708 at site LW3 in the northern South China Sea and produced methane from a hydrate reservoir 117–196 m below the seafloor at a water depth of 1310 m (Zhou et al., 2017a). This test was a successful implementation of a solid fluidization borewell and was the world’s first production of non-diagenetic hydrate in shallow layers.
Currently, solid fluidization is an unprecedented production gas recovery method that has the advantages of low pollution and no damage to underlying porous hydrate reservoirs. However, its major challenges lie in high energy consumption and high lifting costs during field production. Additionally, assessments of seabed mechanical stability prior to a large-scale production test are necessary to avoid geological hazards and uncontrollable gas leakage (Wu et al., 2017; Zhou et al., 2017b).
(2) Formation fluid extraction Since 2003, the China Geological Survey (CGS) has
investigated and assessed gas hydrates in the Shenhu Area, in the north slope of the South China Sea, using geological, geophysical, and drilling surveys (Xu, et al., 2010; Yang et al., 2010; Zhu et al., 2013; Su et al., 2014; Wang et al., 2014; Su et al., 2017). In 2007, hydrate samples were obtained for the first time (Li et al., 2010), and during expeditions in 2015 and 2016, eight hydrate deposits, estimated to be as much as a hundred billion cubic meters of controlled gas resources, were discovered (Guo et al., 2017). However, gas hydrates in the Shenhu area are mostly developed in fine-grained silty clay formations (Wu et al., 2009), which differ from the coarse sand reservoirs in Japan and the gravel reservoirs in the United States and Canada. It is well known that clay-silt hydrate reservoirs, which account for 90% of worldwide hydrate inventory, are more difficult to exploit (Boswell and Collett, 2006; Johnson, 2011). The major issue is that these formations have very low permeability and strong sensitivity to flow speed, which are unprecedented challenges to be overcome during hydrate field trials.
To manage low permeability of hydrate reservoirs in the Shenhu Area and assure reservoir flow, a “three-phrase control” exploitation theory was proposed for the hydrate field trial in 2017. The key idea is to establish predominant fluid channels in the formation by extracting fluids to decrease formation pressure, thus effectively controlling the change and transfer of formation pressure and obtaining phase transformation and inducing gas hydrate dissociation, while retaining the hydrate reservoir’s mechanical stability (Li et al, 2018; Ye et al,
2018). A “formation fluid extraction” technique was thus proposed for the methane hydrate extraction test of Shenhu area based on this theory (Fig. 4). Methane gas is produced by extracting fluids from the formation to control the transformation of phase behaviors of methane hydrate systems on the premise of keeping the formation stable (Li et al, 2018). Figuratively speaking, hydrates are like clotted blood in the veins of the body, whereas fluids extracted during the production test are like melting blood due to depressurization. This technique is a refinement of depressurization, with the special advantages of achieving control of hydrate phase transition and keeping hydrate formation stability during the production test.
To be more specific, during the Shenhu area field trial, a hydrate reservoir below 1530 m (236 mbsf) is the most active section (Li et al., 2018), where temperature and pressure are closest to phase equilibrium curve of gas hydrate, meaning fluids will be more prone to flow, thus decreasing pressure in this interval first. Pressure will drop then vertically in hydrate reservoirs away from the borehole, inducing methane hydrate dissociation.
It is noteworthy that a combined gas-water separation and depressant injection system is applied during the production test to prevent from secondary hydrate formation (Fig. 4). The purpose of the gas-water separation system is to reduce contact between gas and produced water. Concentric tubes and double-end oil tubes with inner and outer flow passages were used to separate gas from the gas-liquid mixture extracted from the hydrate reservoir, and deliver them to the surface through respective flow passages (Li et al, 2018; Ye et al, 2018). Moreover, ethylene glycol (a chemical depressant) was injected in the borehole to avoid gas hydrate reformation.
As a result, the first offshore natural gas hydrate production test the Shenhu area, northern South China Sea (May 10 to July 9, 2017) set a world record for the longest continuous methane production, lasting sixty days from starting to pump, drop pressure, and ignite to well killing, yielding 3.09×105 m3 of gas (Li et al, 2018). This successful test demonstrated that formation fluid extraction is a feasible gas recovery technique for fine-grained silty clay reservoirs with low permeability (Wu and Wang, 2018).
(3) Environmental monitoring of the gas hydrate production test in Shenhu area, northern South China Sea
The acceleration of exploration and production of gas hydrates from marine hydrate reservoirs and potential impacts on local and global environments have attracted broad attention, especially from international academia, in recent years. Environmental issues, such as subsidence (Sultan et al., 2012), landslides (Lu et al., 2017), marine ecosystem changes (Boudreau et al., 2016), and greenhouse warming (Ruppel and Kessler, 2017), which hydrate dissociation may induce, have been more frequently discussed by scientists during the past decade. Many studies of monitoring or detection methods, integrated monitoring systems, and seafloor observatories and networks have been carried out in cold-seep sites locating above hydrate reservoirs, as have offshore methane production field trials (Fig. 3). Production field
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trials implemented by Canada, the United States, Japan, and China have successfully extracted methane from gas hydrate reservoirs in permafrost or marine sediments. Currently, scientists are focusing on developing exploration techniques, conducting lab experiments to test how feasible those techniques are for future methane production, and determine how to increase the methane recovery rate. However, very few papers specializing in hydrate production test environmental monitoring results have been published. For the first offshore methane production, Japan sent a research group responsible for developing environment monitoring technologies prior to the Nankai Trough field test. Their approach mainly included monitoring sensors (e.g., CH4 sensors, seabed deformation sensors, and biosensors), an integrated monitoring system, and other auxiliary devices such as power supplies, electric cables, and autonomous underwater vehicles (AUVs) (Awashima et al., 2008). In fact, during the Nankai Trough test, hydrate reservoir temperature and seabed deformation were monitored by an integrated monitoring system consisting of two temperature monitoring wells (Natl. Corp, 2014), a methane leakage systems made up of CH4 sensors (Lee et al., 2013) and other chemical sensors, and a seabed deformation device equipped with water pressure gauges and liquid electrolytes (Yokoyama et al., 2014). Here we introduce an environmental monitoring system and present preliminary results from a gas hydrate production test in the South China Sea in 2017.
A more crucial issue concerning scientists is the effects of methane inadvertently released during the production test. Thus, methane leakage was the main monitoring focus during the Shenhu area methane production test. An environmental monitoring system known as “four-in-one,” which observed conditions in the atmosphere, in the seawater column, on the seafloor, and underground, was implemented around the production platform “Blue Whale 1” (Fig. 5) (Ye et al., 2018).
Both before and after the production test, seawater column dissolved methane concentration was measured using a METS methane sensor (Franatech Inc., Germany) mounted on a SBE 917plus CTD that can supply power and collect data (Li et al., 2018; Ye et al., 2018). Background methane levels ranged 1.0–27.8 nmol/L at the seafloor in the targeting production area (Liang et al., 2017b). During the test, a METS with a data collector was applied to monitor methane leakage on the seafloor and operated by the operator of a remote operated vehicle (ROV). Five submarine buoyant systems were deployed around the production wellhead to collect real-time bottom water methane concentrations (Li et al., 2018; Ye et al., 2018). However, only one buoyant system 87 m away from the production well successfully measured dissolved
methane during the test. Table 5 shows methane concentrations in bottom water
near the production wellhead before, during, and after Shenhu area field test (Li et al., 2018; Ye et al., 2018). Methane leakage was obvious during the well completion stage, whereas those of the other stages remained within the background level. Methane was not released into the atmosphere (Li et al., 2018; Ye et al., 2018). In short, results showed that the formation fluid extraction technique was feasible for offshore methane production in the Shenhu area and did not lead to a large-scale methane release (Li et al., 2018; Ye et al., 2018). 2.2.3 Improved production techniques for gas hydrate resources
Perhaps one of the most important challenges for future commercial methane production is increasing recovery efficiency. Scientists have taken measures to redesign well drilling technologies, and some new ideas for improving existing production techniques have also been proposed.
(1) Vertical well and clustered well systems Single vertical well systems are the most commonly
used production well type thus far. It is suitable for methane production from various hydrate reservoir types, especially those with free gas underlying the deposits. Based on the previous section’s discussion, a vertical well could be drilled through the hydrate zone to directly recover the free gas, subsequently reducing pressure in the overlying hydrate reservoir.
To improve the methane recovery rate, various new well drilling designs, such as horizontal well, multiple well, and clustered well systems, have been proposed (Li et al., 2011; Wu et al., 2016). It is noteworthy that the horizontal well and water fracturing technique, which was previously proposed by Russian scientists for application in shale-gas and conventional petroleum production, has also been introduced to gas hydrate production research. Water fracturing can create fractures in target sediments, which then provide conduits favorable for fluid migration and increases the contact area between hydrates and heat flow (Fig. 6).
A clustered well system is generally designed with five wells, and there two patterns for well spacing: 1) four production wells arranged around a heat injection well in the center and 2) four heat injection wells arranged around a production well in the center (Wang et al., 2013; Wu et al., 2016). Therefore, clustered well systems combine thermal stimulation and depressurization techniques in the same hydrate reservoir, significantly enhancing the methane recovery rate.
(2) Geothermal as heat source for hydrate production
Some brand-new ideas to improve existing hydrate
Table 5 Dissolved methane contents in bottom seawater near the wellhead prior to and after the field trial in Shenhu area (cited from Li et al., 2018 and Ye et al., 2018)
Date Process of the test Methane content (nmol/L) Average (nmol/L) Standard deviation2017/3/6–2017/3/27 Prior to drilling 1.1–2.9 2.0 0.37 2017/3/28–2017/4/17 Well-drilling stage 1.7–8.0 2.7 1.18 2017/4/18–2017/5/9 Completion stage 2.0–193.0 22.8 38.58 2017/5/10–2017/7/9 Testing stage 1.5–19.7 3.2 2.28 2017/7/10–2017/7/18 After close in stage 1.6–4.4 2.7 0.88
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Fig. 4. Schematic diagram of formation fluid extraction (modified from http://www.chinacaj.net/i,5,7299,0.html).
Fig. 5. “Four-in-one” environmental monitoring system employed during the Shenhu area production test (cited from Ye et al., 2018).
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production techniques have been recently proposed. Finding heat sources for thermal stimulation is one of the most active research fields. For example, Russian scientists proposed a method to press radioactive wastes beneath the seabed, thus enabling hydrates to be dissociated by heat from radioactive decay. Another method they proposed relies on heat released by acid-base neutralization reactions (Wu et al., 2016). Chinese scientists proposed heating hydrate reservoirs by igniting injected nanometer aluminum (Wu et al., 2016).
Gas hydrate production techniques using geothermal heat are based on vertical well and water fracturing technology. Seawater heated by hot rocks in the subseabed can be lifted through the hydrate reservoirs. To be more specific, multilateral wells are drilled into layers bearing hot rock to create substantial interconnected fractures within the hot rocks, thus enhancing surfaces for heat exchange. Casing pipes can then be drilled through the hydrate reservoirs. Subsquently, oriented perforation in the casing pipes is operated and seawater heated by the hot rocks is pumped into the pipes and flows into the hydrate reservoir through the perforations. Methane from hydrates can be recovered in this manner (Fig. 7) (Dou Bin et al., 2011).
The techniques discussed in this section are just some ideas or designs proposed by scientists, or there have been laboratory and numerical studies conducted to investigate their feasibility in future offshore production field tests. However, none have been verified through field trials. 3 Shallow Hydrate Mounds: More Promising Deposits for Production
Oceanic hydrates can be divided into two types: deeply
buried gas hydrates and shallow hydrate mounds (Boswell and Collett, 2006; Liu et al., 2016). Deeply buried gas hydrates are distributed in sediments hundreds of meters beneath the seafloor. Gas or fluids from the deep methanogenesis zone migrate along fractures or occupy pore spaces, causing hydrates to form when temperature and pressure conditions are suitable (Talukder, 2012; Suess, 2014). In some marine seep sites, expelled deep-source fluids migrating along the subsurface plumbing system lead to the occurrence and development of concentrated near-surface accumulation of gas hydrates. Near-surface deposits occur as relatively pure hydrates in seafloor mounds, shallow layers (tens of meters beneath the seafloor), or gas conduits (Fig. 8) (Matsumoto et al., 2014). In fact, shallow gas hydrates often occur in upper continental slope depths (Macdonald et al., 1994; Chapman et al., 2004; Hovland and Svensen, 2006; Brooks et al., 2010) and have been observed in many tectonic settings worldwide, such as the Barkley Canyon in the Canada Cascadia Margin (Pohlman et al., 2005), the Joetsu Basin in Japan (METI, 2013), the Ulleung Basin in the East Sea of Korea (Ryu et al., 2009), and offshore Angola (Serie et al., 2012). For example, high-saturated hydrates are widely found in bulk in the Gulf of Mexico, with some mounds up to five to six meters in diameter (Boswell, 2009; Brooks et al., 2010). Serie et al. (2012) found that in offshore Angola, individual mounds could
have hydrate volumes reaching as high as 1.1×106 m3, which is equivalent to 2.0×108 m3 of methane. Therefore, it seems that the advantages of high saturation, shallow depth, and easy access would cause this type of gas hydrate resource to attract more and more attention from international academia and industry in the future.
After gas hydrate nucleation within highly permeable and porous sediments, fluids along faults, fractures, or other conduits will sustain the hydrate formation and development in shallow layers, causing overlying sediments to swell, or leading to pure hydrate outcrops on the seafloor (Serie et al., 2012). Hydrate mount size, morphology, and geophysical signatures highlight different development periods associated with hydrate formation and dissociation in shallow layers and their linkage with the deep-rooted plumbing systems that provide the gas and fluid venting pathways (Zhang et al., 2017). The formation of massive hydrates in shallow layers or seafloor outcrops requires continuous high-flux fluids to sustain methane saturation within seafloor sediments and overlying seawater near the boundary to prevent hydrate dissociation. Thermogenic and biogenic gas sources are provided by deep-source rock and shallow organic-rich sediments (Serie et al., 2012). Additionally, pore fluids expelled during sediment compaction also act as sources (Brownfield and Charpentier, 2006).
Favorable structural evolutions create preferential fluid migration pathways known as plumbing systems. Scientists in Japan and Korea have suggested that well-developed vent structures, chimney structures, and diapirs are associated with the occurrence of shallow gas hydrates (METI, 2013; Liu et al., 2016). Thousands of chimney structures and plumes have been observed on the seafloor in Japan’s Joetsu Basin, where plumes could rise hundreds of meters above the seafloor into the water column (Matsumoto, 2009). Chimney structure diameters range 200–900 m. In this area, hydrates often grow in conduits or seafloor outcrops (Freire et al., 2012). Ultra-high resolution three-dimensional seismic data has enabled a better understanding of submarine plumbing systems and their relationships with shallow gas hydrate occurrences (Gay et al., 2009; Andresen et al., 2011). Hydrate mounds are now better imaged through the use of advanced submarine visual systems, such as ROVs, AUVs, and deep-towed systems (Sun et al., 2016). We show a flow chart (Fig. 9) demonstrating investigations of hydrate mounds or shallow gas hydrates.
Shallow gas hydrates have a relatively dispersed distribution globally. Characterized by high saturation and shallow occurrence, this type of hydrate is one of the largest methane reservoirs in the global organic carbon cycle, and should be considered more suitable for production. Currently, Japan is partnering with the MHWirth to explore shallow hydrate production techniques in Japan's exclusive economic zone (METI, 2013). Because it is less damaging to the environment, Japan proposes a technique similar to solid fluidization. That is to say, they plan to use an excavating tool with a disc to break hydrates into fine particles and extract them upward using a tubing system.
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Fig. 6. Hydrate production using vertical and horizontal wells (modified from Li et al., 2011).
Fig. 7. Schematic diagram showing gas hydrate production using a geothermal heat source (cited from Dou et al., 2011).
Liu et al. / Review of the Progress in Global Gas Hydrate Research 748
4 Research Needs: Important Issues of Natural Gas Hydrate Exploration and Production 4.1 Further study into gas hydrate accumulation theory
Several countries have successfully extracted core samples from depth that contain gas hydrates. Geological, geophysical, and chemical surveys, together with advanced positioning systems for precise ground truth sampling, have guided gas hydrate deposit exploration during the past decade (Lu et al., 2013; Sultan et al., 2014; Martens et al., 2016; Zhang et al., 2017; Lei et al., 2018). As our recognition of evidence of gas hydrate presence, such as plumes, cold-seep microbial communities, and gas migration pathways, has increased, scientists have realized that more focused efforts should be taken to explore details of the processes of gas or fluids ascending from conduit systems and how gas hydrates accumulate. These are considered the most complex and least known parts of gas hydrate systems (Talukder, 2012). This knowledge will become even more critical because fluid migration and hydrate accumulation are closely linked with assessing future resource potential and economics of methane production plans. However, little has been done on quantitative interpretations of oceanic gas hydrate accumulation for now. Specifically, there has been almost no research analyzing in situ behaviors of fluid migration. This is largely because scientists fail to collect samples from the center of gas conduits and obtain in situ dynamic data of fluid ascending through pathways. Fluid accumulation processes may be crucial to understand gas hydrate reservoir formation. As a result, there seems to be a need to investigate hydrate accumulation theory in various geological settings and meticulously detail up-well fluid source-migration-accumulation processes. 4.2 Optimizing and improving production techniques for gas hydrate resources
In terms of gas hydrate exploration prior to production tests, new submarine technologies such as high-resolution seismic, deep-towed systems, and deep-sea sampling devices are still being developed and as such have not met requirements for engineering applications.
Because gas hydrate occurrence is strongly based on constraints of high-pressure and low temperature, production methods differ from those of conventional resources like petroleum and natural gas. Hydrate production test optimal target zones generally belong to sandy reservoirs, which are more likely to have an underlying free-gas layer adjacent to the hydrate stability zones. Proposed methods are based on either hydrate dissociation by changing thermo-pressure conditions or replacement of methane with another molecule, resulting in more thermodynamically stable hydrates (Anderson et al., 2014). Depressurization has the merits of low cost and high gas recovery rate; however, it typically requires precise control of the pressure drop during hydrate production. Other techniques, such as chemical injection and thermal stimulation, are usually limited by high cost and energy consumption, and thus far, several small-scale field trials have been conducted to prove their viability for
routine hydrate production. Methane is not currently being commercially produced from gas hydrates; however, given the increase in scientific knowledge about hydrates gathered during the past few decades and continuing innovation in recovery techniques, it is likely that large-scale methane production from hydrates will be viable in the near future (Demirbas, 2010; Beaudoin, 2014).
Applying solid fluidization to recover shallower gas hydrates or hydrate outcrops has been proposed (Zhou et al., 2017a), and this technique was tested for a short time in a shallow non-diagenetic hydrate reservoir in the northern South China Sea. In the future, hydrates in shallower sediments may attract extensive attentions because of their high saturation and lack of influence on underlying sediments (Zhou et al., 2014). Therefore, efforts should be made to focus research on development and innovation of excavating equipment and fluidization lifting systems and related drilling equipment.
Additionally, existing hydrate field trials have been carried out on vertical and individual wells. In the future, applications of some improved and well-designed horizontal wells, multilateral wells, and cluster wells may be put on the commercial hydrate production agenda. 4.3 Increasing deployment of seafloor observatories for long-term in situ measurements
Dissociation of hydrates acting as a cementing agent between particles would cause shear strength loss, leading to sediment deformation and failure (Yang et al., 2017). In most geological scenarios, external factors such as tectonic activities, earthquakes, and tidal cycles may trigger hydrate dissociation, resulting in hydrate reservoir instability and ecological changes in the marine environment. A more crucial issue is the influence on the environment from methane inadvertently released during hydrate production, especially at the large scale envisioned for a commercial operation (Ruppel and Kessler, 2017). In addition, drilling operations during the production of methane from gas hydrates are likely to trigger geological hazards such as drilling mud discharge, sand production, slope failure, and seafloor subsidence (Yokoyama et al., 2014). However, there has been little comprehensive and systematic study of geological risks posed by drilling operations during gas recovery, largely owing to the lack of long-term production experience and in situ mechanical data. Additionally, more attention should be paid in the future to reduce potential risks posed by slope failure and subsidence on offshore production platform engineering facilities (And et al., 2007). After all, analysis of gas hydrate-bearing sediment geotechnical properties has great significance to the mechanical stability of gas hydrate reservoirs during gas production and to assessing reservoir gas recovery rates (Yoneda et al., 2015). Therefore, prior to gas production operations, it is essential to understand hydrate reservoir geotechnical properties in the target area (Abegg et al., 2008; Song et al., 2014).
However, abilities to predict geohazards related to hydrate dissociation remain rudimentary. Additionally, it is difficult to obtain sediment samples with high-quality and actual geotechnical data, because they are usually disturbed by both sampling processes and limited storage
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conditions (Vanneste et al., 2014). As such, it is essential to build monitoring platforms to capture and collect field behaviors of geological risks or hazards in situ (Ryu, 2016). Therefore, future work should focus on developing long-term in situ measurements, such as deploying benthic landers, and further building local seafloor networks that combine OBS, anchor systems, seafloor deformation monitoring systems, and so on that can transmit data to onshore platforms in real time (Awashima et al., 2008). However, a long-term production test required to assess impacts of production on the marine environment, climate, and humans is still in the planning stages. 5 Conclusions
The global volume of gas hydrate-bearing sediments is
likely in the range of 0.7–2×1015 m3, and large concentrated gas hydrate accumulations are usually linked with submarine geological structures that can expel migrating fluid into hydrate stability zones. Therefore, exploring relationships between gas sources, fluid migration, and accumulation is the most important approach for revealing gas hydrate formation and providing estimates of hydrate-bound gas. Fluid plumbing systems directly determine occurrence properties of hydrate, such as the distribution, thickness, and saturation of hydrate reservoirs. However, little research has investigated quantitative interpretations of the dynamic of fluid migration for oceanic gas hydrate accumulation. Additionally, there has been almost no research focusing on in situ investigations of fluid migration behaviors, largely owing to a failure to collect samples from the centers of gas conduits and obtain in situ dynamic data of fluid ascending through pathways.
Although marine gas hydrate exploration methods and instruments have improved in recent years and are approaching perfection today, most have not met requirements for engineering applications. Thus far, the main principle of hydrate production techniques has been to change conditions under which hydrates can remain stable to extract gas from hydrates. To realize high gas recovery rates in future commercial production, improved gas hydrate production techniques have been proposed, such as horizontal wells and multilateral wells.
In situ data collected during drilling activities during production tests are key to understanding potential geological risks due to hydrate dissociation in process. Moreover, a related issue is the potential influence of methane inadvertently released during methane production, especially at the large scale envisioned for commercial activities. However, the lack of experience in long-term field trials and in situ mechanical data means that the types and mechanism of potential geological hazards and threats to marine ecosystems are still poorly understood.
6 New Outlooks
More research should be directed toward exploring
details of gas and fluid migration pathways, which are considered effective parts influencing temporal and spatial variation of methane seeps and distribution of hydrates with high saturation. Additionally, to collect samples from the centers of gas conduits and obtain in situ dynamic data on fluid ascending, higher performance drilling vessels should be built in the future. By far, improved production techniques have been considered effective only through laboratory numerical stimulation. Over at least the next 30
Fig. 8. Peculiarities of deep (left) and shallow (right) gas hydrate reservoirs in marine sediments (modified from Matsumoto et al., 2014; Liu et al., 2016).
Liu et al. / Review of the Progress in Global Gas Hydrate Research 750
years in China, these proposed production techniques will be tested using field trials in promising hydrate reservoirs. Commercial methane production is absolutely the way forward; however, methane release and geological hazards are major challenges requiring more attention and research. Large-scale transient discharge due to human disturbance will likely receive much more attention in the future. In addition to numerical tools, more efforts are urgently needed to develop new environmental monitoring equipment and techniques, especially real-time in situ monitoring and warning systems and seafloor observation networks to assist with hydrate exploration and production decisions. Lastly, but perhaps most importantly, gas hydrate accumulations linked with deep-water fluid venting sites occur in very shallow sediments or even on the seafloor and have the highest hydrate saturations. Gas resources in such accumulations are thus relatively easy to
access and could be more likely to be the first gas hydrate formations to be exploited in the future.
Acknowledgements
This study was supported by Natural Science
Foundation of China (91858208), National Key Basic Research and Development Program of China 2018YFC0310003 and 2017YFC0307704), Taishan scholar Special Experts Project (ts201712079), the Foundation of Key Laboratory of Marine Geology and Environment, Institute of Oceanology, CAS (MGE2017KG05) and the Marine Geological Survey Program of China Geological Survey (DD20190819).
Manuscript received Oct. 31, 2018
accepted Dec. 20, 2018
Fig. 9. Flow chart demonstrating investigations of hydrate mounds or shallow gas hydrates.
Acta Geologica Sinica (English Edition), 2019, 93(3): 731–755 751
associate EIC HAO Ziguo edited by LIU Lian
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About the first author
LIU Liping, female, born in 1988 in Weifang City, Shandong Province; a doctoral student studying in Ocean University of China; She is now interested in the study on environmental impacts related to marine natural gas hydrates. Email: [email protected]; phone: 17864278680.
About the corresponding author SUN Zhilei, male, born in 1975 in Linyi City, Shandong Province; Ph.D; graduated f rom Guan gzhou Ins t i t u t e o f Geochemistry, Chinese Academy of Sciences, China; He now is an associate researcher and based in the Marine Hydrocarbon and Gas Hydrate Geology Division of Qingdao Institute of Marine Geology. His research interests include environmental assessment of marine gas hydrate resources and exploration of deep-sea mineral resources. Email: zhileisun @yeah.net; phone: 0532-85720106.