Article pubs.acs.org/EF
Key Findings of the World’s First Offshore Methane Hydrate Production Test off the Coast of Japan: Toward Future Commercial Production Yoshihiro Konno,*,† Tetsuya Fujii,‡ Akihiko Sato,§ Koya Akamine,§ Motoyoshi Naiki,§ Yoshihiro Masuda,∥,⊥ Koji Yamamoto,‡ and Jiro Nagao*,† †
Methane Hydrate Production Technology Research Group, Research Institute of Energy Frontier, Department of Energy and Environment, National Institute of Advanced Industrial Science and Technology (AIST), 2-17-2-1 Tsukisamu-Higashi, Toyohira-Ku, Sapporo 062-8517, Japan ‡ Methane Hydrate Research & Development Division, Japan Oil, Gas and Metals National Corporation (JOGMEC), 1-2-2 Hamada, Mihama-ku, Chiba-city, Chiba 261-0025, Japan § Petroleum Engineering & Consulting Department, Japan Oil Engineering Co., Ltd., Kachidoki Sun-Square, 1-7-3 Kachidoki, Chuo-Ku, Tokyo 104-0054, Japan ∥ Research into Artifacts, Center for Engineering, The University of Tokyo, Kashiwanoha 5-1-5, Kashiwa, Chiba 277-8568, Japan ⊥ Department of System Innovation, School of Engineering, The University of Tokyo, 7-3-1 Hongo, Bunkyo-ku, Tokyo 113-8656, Japan ABSTRACT: Marine methane hydrate in sands has huge potential as an unconventional gas resource; however, no field test of their production potential had been conducted. Here, we report the world’s first offshore methane hydrate production test conducted at the eastern Nankai Trough and show key findings toward future commercial production. Geological analysis indicates that hydrate saturation reaches 80% and permeability in the presence of hydrate ranges from 0.01 to 10 mdarcies. Permeable (1−10 mdarcies) highly hydrate-saturated layers enable depressurization-induced gas production of approximately 20,000 Sm3/D with water of 200 m3/D. Numerical analysis reveals that the dissociation zone expands laterally 25 m at the front after 6 days. Gas rate is expected to increase with time, owing to the expansion of the dissociation zone. It is found that permeable highly hydrate-saturated layers increase the gas−water ratio of the production fluid. The identification of such layers is critically important to increase the energy efficiency and the technical feasibility of depressurization-induced gas production from hydrate reservoirs.
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INTRODUCTION Natural gas hydrates are crystalline solids composed of water and gas, typically including methane, ethane, propane, and carbon dioxide.1 In nature, methane hydrate, which forms at low temperatures and moderate pressures, occurs in permafrost and marine sediments on the outer continental shelves.2 Methane hydrate offers an unexploited energy resource and could play a significant role in past and future climate changes because a large fraction of the Earth’s fossil fuels are considered to be stored in methane hydrate.3 The most widely cited estimate of global hydrate-bound methane is 20,000 trillion m3 (∼1 × 104 Gt of carbon),4,5 and the present estimate is on a scale of at least 3,000 trillion m3 (1.5 × 103 Gt of carbon).6 Most of them form in undeformed and fractured muds at low concentrations; however, part of them are accumulated in sand reservoirs at high saturation and appear to be the most promising category as an energy resource.2,6 The results of a recent study indicated that a rough estimate of gas-in-place of global gas hydrate in sand reservoirs is in the order of 300 trillion m3 (1.5 × 102 Gt of carbon).6 By considering that global gas demand was estimated at just under 3,500 billion m3 in 2014,7 gas production from hydrate reservoirs could be a game changer in the global gas market. © 2017 American Chemical Society
Gas production from hydrate reservoirs could be realized by dissociating solid-state hydrate into fluid phase gas and water in sediments. Hydrate dissociation occurs by decreasing the pressure below the equilibrium condition, increasing the temperature above the equilibrium condition, and changing the equilibrium condition itself. Makogon proposed the three common methods of hydrate dissociation: depressurization, thermal injection, and inhibitor injection, which are based on the conventional petroleum production technology.8 Depressurization decreases the pressure of a drilled production well and makes gas hydrate in sediments thermodynamically unstable. Hydrate dissociation, which is an endothermic reaction, continues, due to the sensible heat of the reservoir and the heat transferred from the over-/underburden. In the original concept, the well was drilled through the beds containing gas hydrate into the free gas zone in order to propagate depressurization via the free gas zone. Gas hydrate with a subjacent free gas zone is known as class 1.9 Class 1 is the most favorable setting with respect to pure economics; however, such Received: November 25, 2016 Revised: January 31, 2017 Published: February 1, 2017 2607
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Figure 1. (a) Location of the test site, (b) locations of production, monitoring, and coring wells, and (c) geological model, well configuration, and depth profiles of pressure and temperature at the production well AT1-P. The test site is located at the Daini Atsumi Knoll off the coasts of Atsumi and Shima peninsulas, Japan. The mean water depth is 998.7 m. One production well (AT1-P), two monitoring wells (AT1-MC and AT1-MT1), and one coring well (AT1-C) were drilled at the test site. The reservoir consisted of five zones: upper muddy zone, upper MHCZ (thin fine and very fine sand), silt-dominated zone, lower MHCZ (thick fine and very fine sand), and water-bearing zone below the BSR. AT1-P was completed from the top of the upper MHCZ to the upper part of the lower MHCZ. The completion of AT1-P was an open-hole gravel pack.27 The cylindrical coordinate system was adopted to conduct the reservoir simulation.
heat during hydrate dissociation. Hydrate dissociation continues using the enlarged sensible heat of the reservoir, the convection heat of the injected inhibitor, and the heat transferred from the over-/underburden. In recent years, CO2 or CO2-mixed gas injection has been proposed.10−12 The basic mechanism of hydrate dissociation involves changing the phase equilibrium, which is similar to inhibitor injection; however, injected CO2 forms hydrate in sediments and generates heat. Due to the impact such hydrate formation will have on permeability, this method will face significant challenges as a primary means for energy production13 and may also provide opportunities for the sequestration of carbon. The above methods have been compared in terms of energy efficiency, economic efficiency, technological feasibility, and environmental performance. Past laboratory experiments and numerical studies indicated that depressurization is the most promising method for the primary recovery, while the other methods may be more suitable for enhanced recovery or well
accumulations appear to be rare in nature. In contrast, classes 2 and 3,9 a hydrate layer underlain by a water zone and an isolated hydrate layer that is not in contact with any hydratefree zone with mobile fluids, are relatively common in nature. The current concept assumes that such hydrate reservoirs would be directly depressurized because the hydrate reservoir has permeability even in the presence of hydrate. However, instantaneous gas production with favorable rates is difficult to achieve when permeability in the presence of hydrate is low (around 0.1 mdarcy or less). Thermal injection supplies the artificial heat directly into the hydrate reservoir to increase the temperature. Heated fluid such as steam and hot water is injected into the hydrate reservoir or circulated inside the wellbore. Gas hydrate dissociates using the conduction and convection heat from the well. In contrast, in inhibitor injection, methanol or brine is injected into the sediments to change the equilibrium condition of the gas hydrate. The shifted equilibrium condition yields a larger reservoir sensible 2608
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stimulation.14−18 Field tests played an important role in the evaluation of these methods. Currently, Japan, Canada, USA, Germany, China, India, and South Korea have conducted or are planning field production tests. Above all, Japan actively promoted an ambitious 18 year program for methane hydrate research and development since 2001. The program managed by the MH21 Research Consortium consisted of three phases. In phase 1, during financial years (FY) 2001−2008, the original gas-in-place in methane hydrate was evaluated at the eastern Nankai Trough area off the coast of Japan through seismic surveys and exploratory test wells. It was evaluated as 40 Tcf, 20 Tcf of which were reserved in the 16 methane hydrate concentrated zones (MHCZs).19 MHCZ was characterized as sand-hosted methane hydrate with high saturation. Some MHCZs of those were considered as candidates for future gas production tests. In parallel, two onshore production tests were conducted on MHCZ beneath the permafrost in the Mackenzie Delta, Northwest Territories, Canada. In the first test in 2002, the hot-water circulation method was applied. Intentional gas production from MHCZ was confirmed for the first time in the world; however, the cumulative gas produced was only 468 m3 during 5 days.20 It was found that the energy efficiency of this method was unattractive. On the other hand, the wireline formation test showed that the depressurization method could be more suitable, because MHCZ exhibited permeability.21,22 Based on this knowledge, the depressurization method was applied during the second test on Mackenzie Delta in 2007/2008. The 2007 test was interrupted due to abrupt sand production; however, continuous gas production was achieved in 2008 by installing sand screen into the wellbore. The cumulative gas produced reached 13,000 m3 during 6 days.23 This test revealed that depressurization is a promising gas production method for permeable MHCZ. Following the success of depressurization-induced gas production at the permafrost region, phase 2, from FY 2009 to 2015, was launched with the goal of conducting a production test in the selected MHCZ at the eastern Nankai Trough. In 2013, the world’s first offshore methane hydrate production test was conducted by depressurization. A cumulative gas volume of 119,500 m3 was continuously produced until abrupt sand production occurred on day 6.24 Through the production test, the technical feasibility of depressurization for an offshore hydrate reservoir was partially verified. Based on the results of phases 1 and 2, phase 3 commenced in FY 2016. A medium-term (approximately 1 month) offshore production test was scheduled for phase 3, aiming to overcome the technical problems occurring during the first offshore production test. To ensure the success of the next offshore production test and beyond, it was essential to analyze the first offshore production test and predict the longer term production behavior. Numerical simulation was considered the best way to achieve this, and the development of suitable input geological models was critical to conduct exact numerical simulations.25 In this study, we construct the reservoir model of the test site based on the well-logging data and the analysis results on the sediment cores recovered under pressure. Based on the numerical simulation matched with the recorded production gas and water rates, we analyze the reservoir’s response during the first production test. In addition, the longterm (180 days) production behavior is predicted, in order to obtain the key factors for the 1 month production test planned in 2017 and future commercial production.
Article
METHODS
2013 Nankai Trough Production Test. The production test site was set at one of the 16 MHCZs identified in the eastern Nankai Trough. The test site, referred to as AT1, is located at the Daini Atsumi Knoll off the coasts of Atsumi and Shima peninsulas, Japan.26 (Figure 1a) The water depth is approximately 1,000 m. An approximately 60 m thick MHCZ was recognized in sandy turbidite sediments 300 m below the seafloor. The flow test was conducted by the depressurization method during Mar. 12−18, 2013. As shown in Figure 1c, the completion of the production well AT1-P was an openhole gravel pack, which was installed to prevent sand production.27 Water inside the wellbore was pumped out with an electrical submersible pump.28 The wellbore pressure was decreased from 13.4 to approximately 5 MPa during the first day and maintained stable for 4 days. Then, it was further decreased to 4.3 MPa during the last 2 days. By decreasing the wellbore pressure, gas and water generated from methane hydrate flowed into the wellbore according to the pressure gradient of the reservoir. The gas and water volumes produced were measured on the deck of D/V CHIKYU owned by the Japan Agency for Marin-Earth Science and Technology (JAMSTEC). The cumulative gas and water produced during 6 days were approximately 119,500 m3 and 1,250 m3, respectively.24 To detect the front of hydrate dissociation, two monitoring wells, AT1-MC and AT1-MT1, with temperature measurement equipment, were drilled prior to the production test29,30 (Figure 1b). Further details of the operation can be found elsewhere.24 Geological Modeling. Logging data were collected for wells AT1P, AT1-MC, and AT1-MT1.26 In addition, pressure coring was conducted on well AT1-C in 2012.30 Locations of these wells are shown in Figure 1b. Since the good lateral continuity of the lithofacies was confirmed in these logs and pressure coring wells,26 geologic characterization and modeling were conducted based on the logging data of AT1-MC and the pressure core data of AT1-C. The details of logging and pressure core analyses are described in our previous special issue on “Gas hydrate drilling in Eastern Nankai”.31 In this study, a geological model for numerical simulation was compiled from these logging and core data. And some key petrophysical parameters such as hydrate saturation and initial effective permeability were adjusted to reproduce the measured gas and water production rates while referring to these logging and core data. Geological characterization and modeling procedures are outlined as follows. First, geological unit classification (zoning) and lithofacies identification were conducted by analyzing natural γ ray, resistivity, resistivity image, and conventional/pressure core data. Next, the reservoir was divided into 202 layers to construct a geological framework for numerical simulations (layering). Layering was based on the lithofacies; however, a layer thicker than 1 m was divided into finer layers to obtain precise simulation results. Petrophysical parameters such as effective porosity, hydrate saturation, initial effective permeability of water, and absolute permeability were derived from the logging data with the correction of core data for each layer. The density structure of the sediments, which is related to the porosity profile, was estimated from the density log, considering the effect of borehole enlargement.32 The log-based porosity was validated by the core-derived porosity, which was measured under in situ confining pressure.32 These porosity data referred to absolute porosity, including the clay-bound water (CBW). To obtain the effective porosity, which contributes to flow, the CBW derived from nuclear magnetic resonance (NMR) logging was subtracted from the absolute porosity. Hydrate saturation was estimated by the Archie equation.33 Derived saturation was compared to the estimation by the density−magnetic resonance (DMR) method.34 These profiles correlated well with each other in the lower MHCZ; however, the profile estimated by the Archie equation showed high resolution in the upper thin-bedded MHCZ. The validity of the derived saturation was confirmed by the pressure core data.26 The initial effective permeability of the hydrate-bearing sediments is the most important parameter for reservoir simulations; however, it 2609
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Figure 2. (a) Depth profiles of effective porosity, hydrate saturation, and initial effective and absolute permeabilities with lithofacies and (b) relation between initial/absolute permeability and hydrate saturation. Effective porosity was derived from logging (density and NMR) and core data.32 Hydrate saturation was estimated from resistivity logging and pressure core data.26 The initial effective permeability was calculated by NMR logging and pressure core data.26,35 The absolute permeability was derived from the effective porosity based on the Kozeny−Carman model38 and calibrated with the core data collected from hydrate reservoirs at the eastern Nankai Trough.35,39 Eventually, hydrate saturation and initial effective permeability were adjusted through history matching simulation while referring to logging and core data. Numerical Simulations. The area affected by the production test was estimated to be less than a few tens of meters from production well AT1-P. Within this area, good lateral continuity of the lithofacies was confirmed by logging and coring wells, as mentioned above. Thus, we considered the effect of lateral heterogeneity to be negligible during the production test. Based on this assumption, the cylindrical coordinate system was adopted to conduct the reservoir simulation (Figure 1c). The system, including the over- and underburden, and the MHCZs were discretized into 120 × 202 grids in radial and vertical directions. The radial direction was discretized with grid sizes increasing logarithmically. The radial coverage was sufficient large (5000 m) to ignore the effect of model boundaries. The vertical direction (100.25 m) was divided based on the lithofacies mentioned above. Numerical simulations were conducted by a reservoir simulator referred to as MH21-HYDRES. MH21-HYDRES is an original reservoir simulator developed under the MH21 Research Consortium as a compositional reservoir simulator for gas-hydrate-bearing sediments.40,41 MH21-HYDRES includes thermo−chemo−hydro models and can be used to solve multiphase and multicomponent
contains high uncertainty. In this study, the initial effective water permeability was comprehensively examined by NMR logging and pressure core data.26,35 Although both the Schlumberger−Doll research (SDR) model36 and the Timur−Coates model37 are widely used in the estimation from NMR logging, only the Timur−Coates model was adopted in this study. The Timur−Coates model is expressed as follows: k i = A(φNMR )4 (FFV/BFV)2 where ki is the initial effective permeability, A is a constant, φNMR is the NMR-derived porosity, FFV is the free-fluid water, and BFV is the bound-fluid water. φNMR, FFV, and BFV were derived from the NMR logging. Constant A is an empirical parameter specific to the reservoir and dependent on lithology; thus, it was determined for each geological unit according to pressure core data. The absolute permeability (the permeability of host sediments assuming all hydrate removed) was derived from the effective porosity based on the Kozeny−Carman model38 and calibrated with the core data collected from hydrate reservoirs at the eastern Nankai Trough.35,39 2610
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Energy & Fuels problems. Although the sediment compression (porosity change) owing to pressure reduction was considered, fully geomechanical models were not coupled. The reliability of MH21-HYDRES has been established through comparison studies with laboratory experiments and onshore production tests.42−45 Time-series data of the bottomhole pressure recorded in the production test were used as boundary conditions at the production well.
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RESULTS AND DISCUSSION Geological Model. The geologic model is shown in Figure 1c with the configuration of the production well. The reservoir contains mainly turbidite channel-type sediments deposited within a submarine fan system.26 The reservoir consists of five zones: upper muddy zone, upper MHCZ, silt-dominated zone, lower MHCZ, and water-bearing zone below the BSR (bottom simulating reflector). The upper MHCZ consists of thin sand (fine sand and very fine sand) and thin silt (sandy silt and clayey silt) alternations. The silt-dominated zone is the same as the upper MHCZ; however, the ratio of silt-to-sand layers is higher. Although the lower MHCZ also contains sand−silt alternations, channel sand is recognized instead, due to the greatest thickness of the sand layers. Figure 2a shows the depth profiles of effective porosity, hydrate saturation, and initial effective and absolute permeability for the different lithofacies. The composition of the lithofacies has a huge effect on the variations of these petrophysical parameters. Hydrate saturation in fine sand layers is up to approximately 80%. Initial effective permeability in hydrate-bearing layers (permeability in the presence of hydrate) ranges from 0.01 to 10 mdarcies at the production interval, which is higher than the values determined in previous studies.46,47 Absolute permeability of these layers (permeability of host sediments assuming all hydrate removed) exceeds 1000 mdarcies. In contrast, clayey silt layers have no hydrate and show a low absolute permeability of approximately 0.01 mdarcy. Figure 2b shows the relation between initial/absolute permeability and hydrate saturation. Initial effective permeability in hydrate-bearing layers has similar values in different lithofacies and hydrate saturation. It also shows that there is a positive correlation between absolute permeability and hydrate saturation. These results indicate that hydrate accumulation was controlled by absolute permeability linked to lithofacies and terminated when the effective permeability reached a certain value. By identifying the geological unit, the lithofacies, and the petrophysical parameters, the upper and lower MHCZs are recognized as the main targets for gas production. In addition, the upper muddy zone is expected to form the sealing layer, because it consists of thick low-permeable clay layers with a few thin very fine sand layers. Based on the geological information, the vertical production well is completed, from the top of the upper MHCZ to the upper part of the lower MHCZ (Figure 1c). The completion of the production well uses an open-hole gravel pack.27 Gas and Water Production Behaviors. Figure 3 shows the measured and simulated rates of gas and water produced in the production test. The measured rates during the first 3 days yield higher values than the estimates by numerical simulation. Immediate high-rate productions just after depressurization are best explained by the reservoir disturbance around the well. Especially, artificial disturbance owing to drilling and gravel packing operations can expand the high-permeability zone and result in unnatural production behavior. The numerical
Figure 3. Measured and simulated gas and water production rates.
simulation cannot reproduce this anomaly, because lateral reservoir heterogeneity is not considered. After 3−4 days, the measured gas and water rates became stable and matched well with the estimates by numerical simulation until abrupt sand production occurs on day 6. The rates of gas and water production during this stage are approximately 20,000 Sm3/day and 200 m3/day, respectively. These production rates are considered to reflect the original (not disturbed) reservoir’s ability for depressurization-induced gas production. Rapid water production is measured in the real test on day 6, when sand production occurs. Figure 4 indicates the simulated gas and water production rates for each layer in the production interval on day 5. Petrophysical parameters and lithofacies are also shown. The water production rate is magnified a hundred times; thus, the layer where gas is maximum yields higher gas productivity than the average gas−water ratio of 100. Moreover, the high-gasproductivity layers (indicated by red triangles) are basically related to highly hydrate-saturated (approximately 80%) fine sand. The initial effective permeability of these layers ranges from 1 to 10 mdarcies. On the other hand, the low-gasproductivity water dominant layers (indicated by blue triangles) are mainly distributed in moderately hydrate-saturated (approximately 50%) sandy silt. The initial effective permeability of these layers is approximately 10 mdarcies. Gas is produced mainly from the upper and lower MHCZs, as expected, and from the interface layers between the siltdominated zone and the lower MHCZ. Water comes from the top and the bottom of the upper MHCZ, the silt-dominated zone, and the completion bottom in the lower MHCZ. These results indicate that productivity of the hydrate reservoir highly depends on the lithofacies and petrophysical parameters such as the hydrate saturation and the initial effective permeability. Hydrate Dissociation Behavior. The hydrate dissociation zone identified by numerical simulation is shown in Figure 5. 2611
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Figure 4. Simulated gas and water production rates for each layer in the production interval on day 5 . The water production rate is magnified a hundred times. Red and blue triangles indicate the high gas productivity (gas water ratio, GWR > 100) and the water-dominant (GWR < 100) layers, respectively.
interface layers between the silt-dominated zone and the lower MHCZ. One of the reasons for this discrepancy is assumed to be due to the spatial resolution of radial and vertical model discretization. In addition, local heterogeneity of petrophysical properties would affect hydrate dissociation and mass/heat transport in the actual field. In contrast, the lower MHCZ showed little change in both measured and simulated temperatures. The result indicates that relatively tight dissociation was occurring in the lower MHCZ compared to the upper MHCZ. The uneven advance of the dissociation front was confirmed by field measurement and numerical simulation. Long-Term Production Behavior. The hydrate dissociation zone expands with time owing to the permeability increase by hydrate dissociation. Thus, the production rate is expected to increase with time, when the reservoir size is substantially large. Figure 7a shows the predicted gas and water production rates for 180 days production at the test site. The bottom-hole pressure in the production well is reduced to the target pressure of 3 MPa from 4.3 MPa which was the actual bottom-hole pressure in the 2013 Nankai Trough production test. The gas production rate exceeds 75,000 Sm3/day at day 30 and 90,000 Sm3/day at day 180. The gas saturation shown in Figure 7b indicates that the dissociation front reaches around 100 m from the well on day 30 and exceeds 200 m on day 180. In addition, the dissociation zone expands vertically beyond the production interval, as well as laterally with time. Vertical expansion of the dissociation zone is especially recognized in the lower MHCZ, because the lower MHCZ consists of thicker sand layers and has vertical permeability. Numerical simulation shows that an increasing trend in gas production is generally expected at the test site during medium- to long-term production. Flow path blocking caused by hydrate re-formation (secondary hydrate formation) within the reservoir was not obvious in this production term.
The dissociation zone is strongly affected by the vertical reservoir heterogeneity and shows a unique fingering front. The effect of pressure reduction in the production well propagates laterally over 50 m at the front after 6 days. The temperature reduction, which is strongly related to hydrate dissociation, exhibits similar behavior to the pressure reduction; however, the front reaches 25 m at the best. The most advanced fronts are identified at the bottom half layers in the upper MHCZ and at the interface layers between the silt-dominated zone and the lower MHCZ. These are related to thin fine sand layers with moderate hydrate saturation and high initial effective permeability. These layers have relatively high water saturation with good silt sealing. This indicates that pressure reduction is effectively propagated. Silt sealing is also expected as a heat source for hydrate dissociation. These petrophysical and lithological characteristics promote the propagation of pressure reduction and hydrate dissociation. Hydrate and gas saturations show that hydrate has completely dissociated a few meters from the well and is under dissociation at the zone within 25 m. This indicates that hydrate dissociation occurs over a large volume of hydratebearing sediment, rather than only at the sharp front. In terms of gas production, spatial dissociation is desirable, because a high production rate is expected when the dissociation area is large.42 Our previous study showed that a hydrate-dissociation regime transits from a sharp front dissociation to spatial dissociation, when the initial permeability in the presence of hydrate is over 0.5 mdarcy.42 The initial effective permeability in the test site (1−10 mdarcies) meets this criterion and is favorable for conducting depressurization-induced gas production. Figure 6 shows the measured and simulated temperature at the location of the monitoring well AT1-MT1 on day 5. Temperature sensors detected temperature variations during the gas production test due to hydrate dissociation and mass/ heat transport around the wells.29,48 Measured data indicate that temperature drop was broadly occurred mainly in the upper MHCZ; however, the simulated result shows a sharp temperature drop in a small area of the upper MHCZ and the
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CONCLUSIONS Logging and pressure core data show that the test site contains highly saturated (up to 80%) hydrate-bearing sand with 2612
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Figure 5. Distribution of simulated pressure, temperature, and methane hydrate and gas saturations on days 3 and 6.
adequate initial effective permeability (1−10 mdarcies) for depressurization-induced gas production. The 2013 Nankai Trough production test confirmed that methane hydrate in permeable sand could be successfully depressurized and dissociated. The numerical simulation showed that the permeable layer with high hydrate saturation yields high gas productivity; however, the water-rich layer causes high water production and reduces the gas−water ratio of the produced fluid. High water production can cause low energy efficiency, low economic efficiency, and problems during operation. These
results indicate that zone isolation of the water-rich layer is a key technique for reducing the water production and achieve high gas productivity through depressurization. The criterion of hydrate saturation for zone isolation is considered around 50% at the test site. The present long-term simulation predicts that the hydratedissociation zone will expand over 200 m from the well after 180 days production. The effect of lateral reservoir heterogeneity was negligible during the 2013 Nankai Trough production test, because the hydrate-dissociation zone 2613
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bearing zone below the BSR at this site, a connection with the water-bearing zone generally decreases the gas−water ratio of the produced fluid. Specific attention for high water production is needed when the hydrate-dissociation front reaches the water-bearing zone. Furthermore, the well location and the completion interval should be selected carefully, in order to maintain a large dissociation area and to avoid high water production. The long-term simulation also shows that the maximum gas production rate can be increased to over 90,000 Sm3/day after 180 days, if the production pressure is reduced to 3 MPa. To realize this scenario, robust and sustainable production is essential. Especially, sand management is a crucial issue for long-term gas production, because sand production is unavoidable in unconsolidated hydrate reservoirs. The 2013 Nankai Trough production test indicates that the waterdominant layer might trigger abrupt sand production due to its high water production rate.48 The zone isolation of such a layer is important in terms of sand management as well as high gas productivity. In addition, intensive study of the geomechanical and environmental behaviors should be conducted. Although geomechanical response may not matter as much in short-term tests, it is significant for well survivability and seafloor stability when conducting long-term tests. Geomechanical monitoring and analysis are expected to become necessary in a mediumterm (over a month) production test as well. In conclusion, it seems clear that highly saturated hydratebearing sand with adequate initial effective permeability is promising for depressurization-induced gas production and should be the first target for commercial gas production. The identification of permeable highly hydrate-saturated sands is critically important to realize commercial production.
Figure 6. Measured and simulated temperatures at the location of monitoring well AT1-MT1 on day 5. Underground temperature monitoring was conducted in the production test to detect hydrate dissociation and mass/heat transport around the wells.29,48 The offset of the monitoring well AT1-MT1 from the production well AT1-P is 22 m at the reservoir depth as shown in Figure 1b.
expanded only 25 m from the production well; however, it should be considered when conducting longer term tests. For example, reservoir boundaries including a faults system should be carefully identified.25 In addition, vertical expansion of the hydrate-dissociation zone may lead to a connection with the water-bearing zone below the BSR. Although the sandy silt layers in the lower MHCZ block the connection with the water-
Figure 7. (a) Predicted gas and water production rates for 180 days production; (b) distribution of gas saturation on days 30 and 180. 2614
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AUTHOR INFORMATION
Corresponding Authors
*Tel.: +81-11-857-8949. E-mail:
[email protected] (Y.K.). *Tel.: +81-11-857-8948. E-mail:
[email protected] (J.N.). ORCID
Yoshihiro Konno: 0000-0003-2904-1319 Notes
The authors declare no competing financial interest.
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ACKNOWLEDGMENTS This study was financially supported by the Research Consortium for Methane Hydrate Resources in Japan (MH21 Research Consortium) to carry out Japan’s Methane Hydrate R&D Program conducted by the Ministry of Economy, Trade and Industry (METI). We gratefully acknowledge them for the financial support and permission to present this work. We also thank all crews, engineers, and scientists involved with the 2013 offshore methane−hydrate production test. Especially, we express our strong appreciation for Dr. K. Suzuki and Mr. S. Sakurai of JOGMEC and Drs. N. Tenma and J. Yoneda of AIST for fruitful discussions.
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