Comprehensive Report of Phase 2 & 3 Research Results

IV Gas Production Techniques from MH Reservoir
IV.1 Basic ideas behind gas production and advances in verification(1) Introduction
In order to obtain combustible natural gas from solid-state MH underground, one possible method is to
excavate it using a similar method as that used to excavate coal or minerals. Another method is to dissociate
it into movable fluids (water in the liquid state, and methane vapor) and collect it through well-likeconventional oil and natural gas (the in-situ dissociation method). The mining method, however, seems to
be impractical for deep-water MH from the viewpoints of safety, environmental impact, and cost. On theother hand, the in-situ dissociation method is advantageous if the host sediment of MH has some degree ofhydraulic permeability. This is because we can collect gas and water through permeable formations at thewell, and so petroleum exploration technologies can be applied. Furthermore, the activities footprint on theseafloor is limited to regions in close proximity to the borehole.
MH21 regarded the in-situ dissociation method as a realistic technique to use, and has attempted to verify
that the depressurization technique is the most efficient way to achieve in-situ dissociation. In this section,
the theoretical basis of the method and its verification processes are outlined.

(2) Mechanism and condition for application of the depressurization method
In order to dissociate MH that is stable under low temperature and high pressure conditions, raising thetemperature (thermal stimulation), reducing the pressure (depressurization), and also alternating the phaseequilibrium conditions (inhibitor injection) can be used for in-situ dissociation.
When the first phase of the MH21 was started in 2001, the effectiveness of each of the above methods was
not apparent. However, it was known that MH dissociation is an endothermic process, and thatapproximately 436.8kJ of heat is necessary in order to dissociate 1kg of MH, the equivalent to 160 liters of
methane gas. This value is higher than the heat necessary to raise the temperature of the same mass of waterfrom freezing point to just below boiling point. Furthermore, given that some of this energy will be
consumed in warming the sediment and pore fluid around MH, not all of this injected heat will be used for
MH dissociation. It can therefore be understood that simple thermal stimulation is not entirely efficient interms of energy balance.
Meanwhile, if the pore pressure of formation can be reduced, the difference in heat between the originalformation temperature and phase equilibrium temperature- multiplied heat capacity of the formation can beused for MH dissociation, and gas can be generated without any artificial thermal energy input (Fig. 1). In
this case, the gas generated by depressurization can be regarded as the equivalent to “primary recovery” ofconventional oil (oil that erupts by its own motive force). However, when the formation temperaturereaches the phase equilibrium temperature, the dissociation is terminated. In this case, the recovery rate of
MH is limited. If some heat supply by conduction or convection from surrounding formations continues, itwill affect the gas production rate. In the case of depressurization, the direction of the expected heat supply
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is the same as the fluid motion (inward to wellbore). In this case, convection can contribute to the supply.
In the case of thermal stimulation from a single wellbore, expected heat and fluid flow are in the opposing
direction. This is because the heat should be transported from the wellbore to the dissociating area (in theoutward direction). After the dissociation of MH in the pore space, enhancement of permeability is
expected and the pressure reduced region may extend from near the well bore to regions further away (Fig.
2). The inhibitor injection technique has a similar disadvantage to thermal stimulation. This is due to thefact that the inhibitor is required to be brought from the center (well) to the outside.
For the above reasons, the depressurization method is judged as being the most efficient method for the
dissociation of MH. Even given this case, the method is applicable under the following conditions (Fig. 3):
 That the original formation temperature is high enough (that there is sufficient heat available)
 That the initial formation permeability has reached a certain value (that the reaction area issufficiently large)
 That the formation permeability after dissociation is sufficiently high (that the pressure drop
between the MH dissociating area and the wellbore is low).
 That the dissociated zone is protected from the surrounding water sources (that there is limited
water production).
In the case of offshore resources, research has shown that it is necessary to ensure depressurized conditions
exist at the bottom of the deep-water well, and also that the operation should be conducted safely under the
metocean conditions of the target area. The MH21 study has attempted to verify the applicability of thedepressurization method through appropriate technical development and data acquisitions.
On the other hand, thermal stimulation and inhibitor injection may be necessary measures as well as
stimulation or enhanced recovery techniques necessary for the improvement of recovery rates andproductivity.

(3) Field verification of depressurization method
In the Messoyakha gas field in western Siberia in Russia, it is argued that depletion of the gas field caused
unintended dissociation of MH in the overburden formation, and accelerated pressure recovery. (Makogon,
1984).
In 2002, the world’s first intentional gas production from MH-bearing sediment was achieved in the Mallik
field in the Northwest Territories of Canada. This was a collaborative project involving Japan, Canada,
India, Germany and the United States. While it utilized thermal stimulation (warm fluid circulation(Hancock et al., 2005a), the volume produced was small, (468 m3 during five days of operation) and notstable. Meanwhile, the small scale depressurization test carried out using Modular Dynamics Tester (MDT,Mark of Schlumberger) proved that MH-bearing sediment has finite permeability (Hancock et al., 2005b,
Kurihara et al., 2005a). This result suggested the applicability of the depressurization technique. (Dallimore
and Collett, 2005a).
This result promoted further studies in Japan. Large numbers of laboratory experiments on MH dissociation
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using natural or artificial core sample were carried out (Okui et al., 2005; Kawasaki et al., 2005), andnumerical simulations (Kurihara et al., 2004; Masuda et al., 2005) were conducted in order to prove theapplicability of this method to the natural MH system.
Meanwhile, the drilling of the “MITI Nankai Trough” (1999-2000), 2D and 3D seismic surveys in theeastern Nankai Trough (2001-2002), and the drilling campaign of “METI Tokai-oki to Kumano-nada”(2003-2004) revealed the existence of MH-concentrated zones (MHCZs) – that is accumulation of pore
filling type MH together with substantial thickness of sandy turbidite sediments in the Japanese EEZ (Saeki
et al., 2008; Fujii et al., 2008). The obtained data suggested that the permeability and formation temperatureof some MHCZ satisfy the applicability criteria of the depressurization method.
To prove applicability of the concept to a real field, a second offshore trial was conducted at the Mallik site
during the winter seasons of both 2007 and 2008. The depressurized condition was realized by using anelectric submersible pump (ESP) to displace water in the borehole. During the first winter, due to a sandproduction problem, operation was terminated after a short period. However, the produced gas volume was
830 m3 during a half day of operation, a figure that was larger than the result of the entire five-day
operation in 2002. Subsequent to the installation of a sand control device, the second year’s test was
conducted and 13,000m3 of gas was produced continuously and in stable conditions (Dallimore et al., 2012)(Fig. 4).
Based on these data and experiences, the Phase 2 and 3 studies carried out by MH21 have aimed to apply
the depressurization method to offshore MH-concentrated zones and also to prove the concept of thismethod and its technologies.
During Phase 2 (2009-2015 JFY), the first offshore production test (2013) resulted in 119,000 m3 of gas
production during six days of depressurization. As was the case previously, this test was terminated bysudden production of sand. In order to obtain the necessary data to understand long-term behaviors, thesecond test was carried out during Phase 3 (2016-2018 JFY) while applying improved sand control andother techniques. The operation lasted a total of 36 days in two boreholes. Large amounts of information
crucial to the estimation of long-term behavior was obtained.
Some unseen technical issues surfaced, however, such as the difference between results predicted by themodel and actual gas production behavior. Accrual of further knowledge about long-term behavior shouldbe critical to resolving those issues going forward. Due to the fact that long-term (for example, more than
one year in duration) operations in offshore conditions are costly and technically difficult, a next step is anonshore production test in Alaska to be carried out with the cooperation of the United States.

(4) Conclusion
The applicability of the energy-efficient depressurization method is a key to gauging economies in gas
production from MH. Integration of surveys, laboratory studies, numerical simulation, and field tests were
performed in the first to third phases of the MH21 project. The current status of the project is thattechnologies carried out over several weeks of offshore operation were proved, and that while it was shown
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Comprehensive Report of Phase 2 & 3 Research Resultsthat gas was able to be produced by the depressurization method, its long-term behavior is considered
uncertain. One of the more important issues is the difference between what the models actually predict andthe behavior of actual gas production. While a large number of uncertainties remain regarding gas
production such as those revolving around well productivity and recovery factors, it is expected that many
hurdles can and will be cleared in order to achieve commercial gas production in future.
In the following subsections, the technical achievements of the offshore tests, the current status of theplanned onshore test, and the individual study status of the production technologies during Phase 2 and 3
will be introduced.

References
Saeki, T., Fujii, T., Inamori, T., Kobayashi, T., Hayashi, M., Nagakubo, S., Takano, O. (2008): Extraction of Methane Hydrate
Concentrated Zone for Resource Assessment in the Eastern Nankai Trough, Japan, 2008 Offshore Technology
Conference, 5-8 May, Houston, Texas, USA.
Fujii, T., Saeki, T., Kobayashi, T., Inamori, T., Hayashi, M., Takano, O., Takayama, T., Kawasaki, T., Nagakubo, S.,
Nakamizu, M., Yokoi, K. (2008): Resource assessment of methane hydrate in the Eastern Nankai Trough, 2008 Japan,
Offshore Technology Conference, 5-8 May, 2008, Houston ,Texas.
Dallimore, S.R. and Collett, T. S. (2005): Summary and implications of the Mallik 2002 gas hydrate production research wellprogram. in Scientific Results from the Mallik 2002 Gas Hydrate Production Well Program, Mackenzie Delta, Northwest
Territories, Canada edited by Dallimore, S. R. and Collett, T. S., Geological Survey of Canada Bulletin 585.
Dallimore, S. R., Wright, J. F., K. Yamamoto and Bellefleur, G. (2012): Proof of concept for gas hydrate production using thedepressurization technique, as established by the JOGMEC/NRCan/Aurora Mallik 2007-2008 Gas Hydrate Production
Research Well Program, in Scientific results from the JOGMEC/NRCan/Aurora Mallik 2007-2008 gas hydrate
production research well program, Mackenzie Delta, Northwest Territories, Canada; Dallimore, S R (ed.); Yamamoto, K(ed.); Wright, J F (ed.); Bellefleur, G (ed.). Geological Survey of Canada, Bulletin 601, 2012, p. 1-15.
Hancock, S. H., Collett, T. S., Dallimore, S. R., Satoh, T., Inoue, T., Huenges, E. and Weatherill, B. (2005a): Overview ofthermal stimulation production-test results for the JAPEX/JNOC/GSC et al. Mallik 5L-38 gas hydrate production
research well. in Scientific Results from the Mallik 2002 Gas Hydrate Production Well Program, Mackenzie Delta,
Northwest Territories, Canada edited by Dallimore, S. R. and Collett, T. S., Geological Survey of Canada Bulletin 585.
Hancock, S. H., Dallimore, S. R., Collett, T. S., Carle, D., Weatherill, B., Satoh, T. and Inoue, T. (2005b): Overview ofpressure-drawdown production-test results for the JAPEX/JNOC/GSC et al. Mallik 5L-38 gas hydrate production
research well. in Scientific Results from the Mallik 2002 Gas Hydrate Production Well Program, Mackenzie Delta,
Northwest Territories, Canada edited by Dallimore, S. R. and Collett, T. S., Geological Survey of Canada Bulletin 585.
Kawasaki, T., Tsuchiya, Y., Nakamizu, M. and Okui, T. (2005): Observation of methane hydrate dissociation behavior inmethane hydrate bearing sediments by X-ray CT scanner. Proc. 5th Int. Conf. on Gas Hydrates, Trondheim, Norway,
June 13-16, 2005. Paper 1041.
Kleinberg, R. L., Flaum, C. and Collet, T. S. (2005): Magnetic resonance log of JAPEX/JNOC/GSC et al. Mallik 5L-38 gas
hydrate production research well: gas hydrate saturation, growth habit, and relative permeability. in Scientific Results

MH21 Research Consortium

Ⅳ‐4Comprehensive Report of Phase 2 & 3 Research Resultsfrom the Mallik 2002 Gas Hydrate Production Well Program, Mackenzie Delta, Northwest Territories, Canada edited by
Dallimore, S. R. and Collett, T. S., Geological Survey of Canada Bulletin 585.
Kurihara, M., H. Ouchi, Y. Masuda, H. Narita, and Y. Okada. (2004): Assessment of gas productivity of natural methane
hydrates using MH21 Reservoir Simulator. Proc. AAPG Hedberg Conference, Vancouver, B.C., Canada, September
12-16, 2004.
Kurihara, M., Funatsu, K., Kusaka, K., Yasuda, M., Dallimore, S.R., Collet, T.S. and Hancock, S.H. (2005a): Well-test
analysis for gas hydrate reservoirs: examination of parameters suggested by conventional analysis for the
JAPEX/JNOC/GSC et al. Mallik 5L-38 Gas Hydrate Production Research Well. in Scientific Results from the Mallik
2002 Gas Hydrate Production Well Program, Mackenzie Delta, Northwest Territories, Canada edited by Dallimore, S. R.
and Collett, T. S., Geological Survey of Canada Bulletin 585.
Makogon, Y. F. (1984): Production from natural gas hydrate deposits. Gazovaya Promishlennost, 10, 24-26.
Masuda, Y., Konno, Y., Kurihara, M., Ouchi, H., Kamata, Y., Ebinuma, T. and Narita, H. (2005): Validation study ofnumerical simulator predicting gas production performance from sediments containing methane hydrate. Proc. 5th Int.
Conf. on Gas Hydrates
Okui, T., Uchida, T., Masuda, Y., Munakata, T. and Kawasaki. T., (2005): Laboratory analysis of gas hydrate dissociation incores from the JAPEX/JNOC/GSC et al. Mallik 5L-38 gas hydrate production research well: observational andexperimental investigations using X-ray computed tomography. in Scientific Results from the Mallik 2002 Gas Hydrate
Production Well Program, Mackenzie Delta, Northwest Territories, Canada edited by Dallimore, S. R. and Collett, T. S.,
Geological Survey of Canada Bulletin 585.
Yamamoto, K. (2009): Gas production technique and Field production test of methane hydrate. Journal of Geography, 118(5),913-934.
温度 (℃)
1514

初期の地層温度圧力

ハイドレート／ガス

13

相平衡曲線

12

10

圧力 (MPa）

dp
 
 

k 'ij
p q
dt x j x j dT
T qi
  ' T  Q
dt
xi

dp
 
 

kij
p q
dt x j  x j 

11

dT
T
 qi
 T  Q
dt
xi

海中・地中の温度圧力（水深1000mの場合）

98k’ >>k,  ’~

減圧

7

MH安定

6

減圧による
温度低下

5

熱の流れと水の流れが同じ方向

分解後の浸透率向上により遠くまで減圧が伝わる

4

熱の流れ

3
2

減圧後の
相平衡温
度圧力

1
0

0

1

2

圧力分布

MH分解
3

4

5

流体の流れ

温度分布
6

7

8

9

10

11

12

13

14

15

Fig.1
Heat
supplymechanismofdepressurization method. Difference between
initial temperature and phase equilibrium
temperature after pressure drop produces heat.

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Fig.2 Heat and mass transport during
depressurization operation. Heat and fluidmass (water and gas) move to wellbore.

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Fig.3
Applicability
criteria
ofdepressurization method based on modellingstudy. High initial and absolute permeability(kinit,kabs) and high temperature are
preferable conditions (Class A).

Fig.4 First and second onshore production
test result. Stable gas production was
realized by the depressurization method.

Fig.5
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Views of Mallik site during operations in 2008.
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IV.2

Process of the First and Second Offshore Production Tests

2.1 Location of the First and Second Offshore Production Tests and Related Geological Conditions
1) The location of the first production test and related geological conditions.
The location of the first offshore production test was chosen from two proposed sites that are methane
hydrate concentrated zones (MHCZ) in the Eastern Nankai Trough. The two sites are called α MHCZ andβMHCZ．
We chose a "βMHCZ" the site for the test. The site is located on the north slope of the Second Atsumi
Knoll, off the coast of Atsumi Peninsula and Shima Peninsula. From seismic data analysis and well data
analysis, we interpreted the concentrated zone of Methane Hydrate as "β MHCZ" located at a water depthof approximately 1000m and located between 270m and 330m below the sea floor. We used data acquired
from 16 wells from "Kiso Shisui Tokai Oki – Kumano Nada (2004)", a domestic exploration program inJapan.
The hydrate layer of the β MHCZ is located relatively deeper than in α MHCZ. In addition, in β MHCZ,
there is the relatively thick clay layer approximately 100m from the sea bottom to above the hydrate layer.
Therefore, β MHCZ is a relatively easy-to-isolate production section from the bottom of the sea. The β
MHCZ location is suitable as a place to set well-head equipment of the well, and there is the advantage that
it is easy to secure space to store pit underground equipment. In addition, stratum temperature was higher
than αMHCZ, so we judged the β MHCZ was a more advantageous site in terms of gas production.
We selected the location of the production test in βMHCZ due to the high possibility of the existence ofMH based on results of the reservoir property evaluation: (1) existence of sand as observed by channel
facies analysis, (2) distribution of high P wave velocity, and (3) amplitude anomaly distribution. In addition
to this MH reservoir property evaluation, we examined the next item in order to choose the location of the
production test. The location had to be a sufficient distance away from existing wells on an area of sea floor
that was not sloping excessively. We ultimately decided to drill the first offshore production test well in the
AT1 area (Fig. 1(c)) approximately 150m southwest of the beta 1 well location that we drilled in 2004.

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Fig.1 Approach of proposed site choice in first offshore production test（Fujii et al., 2016）2)

The location of the second production test and related geological conditions.

Basic conditions for choosing the candidate sea area site of the second production test for methane were as
follows:(1) New well locations are around 100-200m from existing wells in order to minimize risk of new wells
and maximize prior drilling experience.
(2) A target zone where we can expect stable production at sufficient production rates.


We considered that an important area for the production test would be at the upper part of the

MHCZ. The alternate layers of sand and mud support efficient MH dissolution as is evidenced by thetemperature change noted at the observation well during the first production test.
The product section as long as possible in order to minimize the risk that water will be drawn
from the top and bottom of the adjacent formation.

(3) There are few risks of interference with the existing well.
(4) There are few risks of drawing water from the fracturing zone.
(5) There are few risk of drawing water from the middle interval section (the low
saturation of the MH layer).
(6) The slope of the seabed above the MHCZ is not steep.

We took the above-mentioned conditions into consideration and chose two locations (location 1 and 2 ') toshow in Fig. 2. We recognized risks associated with location 1 and location 2.

In the case of location 1,

the upper MHCZ involves risks of water being drawn from under the BSR (the down dip side) although we
could to a degree expect the distribution of "sand mud alternated layers". In the case of location 2, we can
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have a long production zone for a test, however, the upper MHCZ involves risks of water being drawn fromthe upper dip side, and we recognized risks associated with the distribution of "sand mud alternated layers"(Fig. 3). Therefore, we will decide the location of the second offshore production test after obtaining
geological information from the additional well (AT1-UD) in the up dip side (Figs. 2 and 3).
In the UD well, we obtained data about important properties of the reservoir formation including resistivity
images, neutron / density, sonic and nuclear magnetic resonance by logging while drilling tool (LWD). In
Fig. 4, we show well logging data, natural gamma-rays and resistivity of the UD, MT2, MT3, MT1 and MC
wells. As a result of our integrated evaluation coupled with a reservoir property evaluation, and after having
examined it after drilling the UD well, we chose location 2 for the second offshore production test site.
(7) We can expect a total production section length at location 2 of 50m, over double the length of the
production section at location 1, even if stop a above is 15m above BSR.
(8) We expected a layer thickness of approximately 20m at the AT1-P3 well as alternate thin layers ofsand and mud supported efficient production in the section of the upper MHCZ during the first
offshore production test. We estimated the thickness using the interpolation method and AT1-MC
well data and AT1-UD well data.
(9) We considered that there was no increased risk that water would be drawn from the up dip at thelocation.

Fig. 2

Location of second offshore production test from methane hydrate（Layer thickness of the upper
part of MHCZ, sand mud alternated layers）

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Fig. 3Fig. 4

Cross section of second offshore production test

Well correlation （UD-MT2-MT3-MT1-MC wells）

Reference[1] (Tesuya Fujii, Kiyofumi Suzuki, Machiko Tamaki, Yuhei Komatsu, Tokujiro Takayama,2016 ：Reservoir properties and heterogeneity of turbidite sediment revealed from the exploration of methane
hydrate in the eastern Nankai Trough, Japan)(JAPT, 81(1)、84-95.)
IV.2.2 Overview of Offshore Production Tests and Design Concepts of Used Boreholes

IV.2.2 Overview of Offshore Production Tests and Design Concepts of Used Boreholes(1) Introduction
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were planned to obtain data about MH dissociation and gas production behavior under depressurization
conditions. Test terms were planned to be relatively short, e.g. approximately one month. Both projects
were multi-year operations that included preliminary site surveys, well construction and data acquisition,
flow tests, and plug and abandonment (P&A). An important objective of the second test was to verify
countermeasures for technical problems that arose in the first test.

(2) Schedules and Drilled Boreholes
The major objectives of the operation along with the production tests themselves were to evaluate theeffectiveness of the depressurization method, estimate long-term gas production behavior, and to obtain
information about geological and petro-physical (hydraulic, thermal, and mechanical) properties. To
accomplish this, geophysical logging, sampling (coring), and downhole monitoring (pressure andtemperature - PT measurements) were important elements of the operations.
Another important aspect was HSE, and it was crucial that all boreholes, devices and operations met therelevant safety and environmental standards of the oil industry for drilling, production and P&A.

A. First Production Test (2012-2013)
The test utilized one producer well and two monitoring boreholes (Fig. 1).
 February 2011: Preliminary site survey
Geotechnical hole (shallow borehole in overburden) drillings at two sites in the Daini Atsumi
area and geotechnical and micro-bathymetry surveys using AUV were conducted for site
selection, well design, and geo-hazard study purposes (see V-7).
 February to March 2012: Drilling and data acquisition operations
Two monitoring boreholes (AT1-MC: the inside of the casing was kept open for cased-hole
logging after the test, and AT1-MT1: the inside of the casing was filled with cement for highresolution temperature measurement) and the shallow part of the producer well (AT1-P) were
drilled, and geo-physical logging data were taken by logging-while-drilling (LWD) and wireline
tools. Temperature sensors were installed outside the casing of the monitoring holes, andlong-term measuring began (see IV-2-5).
 July 2012 (AT1-C, see V-1)
AT1-C well was drilled.
 January to March 2013: AT1-P production test (March 12-18)
After drilling the reservoir section of the AT1-P well, a sand control device (gravel packing)was installed, and the test string (sensor, downhole separator, ESP, production packer etc.) was
run into the hole. A flow test was conducted by applying the maximum 9 MPa drawdown(bottom hole flowing pressure (BHFP) down from 13.5 MPa to 4.5MPa), and 119,000m3 of gas
was produced in the six-day operation. On the seventh day, sudden and severe sand production
occurred. ESP was still running but sand and water volumes were outside the range ofMH21 Research Consortium

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shipboard treatment capacity, so the crew terminated the depressurization operation.
P&A operation on AT1-P was carried out.
 July to August 2013: P&A and additional data acquisition
P&A on AT1-MC and MT1 and recovery of data storage after the cased hole logging in the
AT1-MC well. To obtain information about reservoir character alternation, two holes(AT1-LWD1/LWD2) were drilled in the vicinity of AT1-P.

B． Second Production Test (2016-2018)
Some improvement of the sand control devices, downhole production devices, and subsea and riser
tools were made as solutions to mitigate the problems that were encountered during the first test(see IV-2-3 and IV-2-4). Two different types of the shape memory material (activated andun-activated GeoFORMTM）were installed in two producer wells for comparison purposes.
 May to June, 2016:
Drilling of exploration well AT1-UD to aid in the decision of where to locate the well, andsubsequent drilling of two monitoring holes (AT1-MT2/MT3) and the shallow part of the twomonitoring holes (AT1-P2/P3) utilizing geophysical logging (Fig. 2). Improved PT sensors
were installed in the monitoring holes and long-term monitoring commenced.
 April to June, 2017:
Drilling of the reservoir sections of the two producer holes and installation of the sandcontrol devices.



Production test on AT1-P3
Eight MPa drawdown (13MPa to 5MPa in BHFP) was achieved, however, intermittent
sand production events were observed from an early stage. Sanding ceased once but thenoccurred again on a larger scale. After 12 days of gas production, we decided that enoughdata had been acquired from well operations, and we made the decision to terminate theflow to protect subsea and shipboard devices.



Production test on AT1-P2
Some additional countermeasures were carried out to prevent sand production and manage
the sand on the deck, and BHFP was gradually reduced from 13MPa to 10MPa. Due to thelarger than expected amount of water produced and the plugging of one of the waterproducing lines, BHFP was kept at 10 MPa for a period of several days. After the closed
line was re-opened, drawdown to 8 MPa was made.
Due to expectedly rough sea conditions, a planned disconnect between the WCP (wellcontrol package) and the EDP (emergency disconnect package) was carried out on the 21stday, subsequent re-connection was successfully carried out, and flow was resumed. A totalof 24 days of flow was achieved.



After the flow tests, two producer wells were suspended.

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

Drilling of two new holes (AT1-CW1/CW2) for additional data acquisition
A pressure coring was made and wireline logging tools were subsequently run into eachhole. AT1-CW1 was drilled at a location between AT1-P2 and AT1-MT2 to represent data
affected by the production test. On the other hand, AT1-CW2 was drilled at a location 20
m west of AT1-MT3 to represent a test case that was not affected by the flow test.



Plug and abandonment of all boreholes
The memory gauge with one year’s worth of PT data in the AT1-P2 was successfully
recovered. An attempt was made utilizing a wash-over operation to recover the sensors andtroublesome sand control device in the AT1-P3 well that had been buried under sand,however, the attempt failed. The data storage containing two year’s worth of PT data wasrecovered.

To mitigate the well deviation problem that occurred during the first test drilling (2012 and 2013), a
rotary steerable tool (Power V system produced by Schlumberger) was used to accurately drill
vertical wells. The well location was selected to minimize interference between two producers and to
distinguish the effects of initial fluid motion from the effects of MH dissociation.
Detailed time charts of the flow tests are shown in Table 1. Along with the well operation stated here,
four component seismic and environmental impact surveys were carried out in the vicinity of theholes.

(3) Operation Platform
Due to the uncertainty of the economic value of MH and appropriate technologies to produce gas, the test
operations were designed to minimize the capital cost of the test system by using or improving existing andfield-proven infrastructure instead of developing newly designed or constructed equipment. As theoperation platform, D/V Chikyu, a DPS drilling vessel owned by the Japan Agency for Marine-Earth
Science and Technology (JAMSTEC), was used for IODP projects because of her operation capacity andrelatively low cost of mobilization and de-mobilization.
The dynamic positioning system (DPS) vessel could drill holes in the test area where many subsea
communication cables ran, and mooring was quite difficult. The wide operation window for the met-ocean
conditions of the Daini Atsumi area was expected. The vessel’s liquid reserve tanks could hold produced
water temporarily, her large accommodation capacity enabled many scientists and engineers to remain on
board the vessel to carry out complicated operations, and her laboratory and other scientific researchfacilities and staff matched the objectives of the R&D project.
Borehole-related operations such as drilling and flow tests were carried out by the D/V Chikyu while otherships were utilized for supply, environmental surveys, and 4C seismic surveys.

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Comprehensive Report of Phase 2 & 3 Research Results(4) Organization for Operations
Both offshore production tests were regarded as mining operations for inflammable natural gas under theJapanese mining law and the mining safety act. Japan Exploration Co., Ltd. (JAPEX) worked as theoperator of the first trial, and Japan Methane Hydrate Operation Co., Ltd. (JMH) cooperated with JAPEX
for the second test. For both tests, development of test equipment was carried out by Japan Drilling
Company (JDC), and Schlumberger K. K. designed and operated the long-term downhole monitoring
systems. Many other companies worked to support each operation. Onshore and onboard data analysis was
carried out by JOGMEC and AIST with cooperation from universities and companies. The organization
chart of both projects is shown in Fig. 3.

(5) Major Results and Conclusions
The first offshore production test (2013) was the world’s first gas production attempt from a MH deposit
below the seafloor. Large depressurization and subsequent gas production was successfully implemented
using a floating drilling vessel, and MH dissociation and continuous production of methane gas wasachieved for a period of six days. However, sudden and severe sand production forced the crew to terminate
the flow, and as a result, stability of gas production was not able to be successfully proven. The large
amount of data acquired shed light on the relationship between MH dissociation and reservoir
characteristics, however, the data was not sufficient to enable prediction of the long-term behavior of gas
production. Furthermore, a number of technical challenges surfaced such as how to control sand, separate
downhole gas-water, and manage the risks of carrying out an emergency disconnect.
To demonstrate the reliability of countermeasures to the technical challenges that arose, and to acquire datathat would facilitate understanding of long-term behaviors, the second test was planned with the aim ofachieving longer-term gas production. In the AT1-P3 well, 12 days of gas production was achieved with 8
MPa drawdown in spite of intermittent sand production. The gas production rate was as low as 3,000-4,000
m3/d and the expected increase in the gas production rate was not observed. The water production rate wasapproximately 80m3/d.
The following operation in the AT1-P2 well suffered from a higher water rate than expected (300-500m3/d)
as well as a limited drawdown (maximum 5 MPa during stable term), however, a higher gas production rate
(10,000 m3/d) was achieved. Several flow assurance problems due to re-association of MH in the flowline
occurred as a result of insufficient drawdown that made the PT condition around the seafloor be within the
MH stability condition. A planned disconnect was successfully carried out, and the operation was resumed
after re-connection. A total of 24 days of flow was achieved from the well.
A total of 36 days of flow was achieved and a large amount of data was acquired as a result of operations
carried out at the producer and monitoring holes. Technical and scientific results of the tests are shown in
the following sections.

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Reference
Yamamoto, K., Terao, Y., Fujii, T., Ikawa, T., Seki, M., Matsuzawa, M. and Kanno, T. (2014): Operational
overview of the first offshore production test of methane hydrates in the eastern Nankai Trough.” Proc.
2014 Offshore Technology Conference, Houston, Texas,
USA, 5-8 May 2014.

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Table 1 Conditions and Results of the first and second offshore production tests

Production

AT1-P

AT1-P3

AT1-P239 m

60 m (drilling interval)

60 m (drilling interval)

41 m (interval except forintervalisolated zone by packers)

45.4 m (interval except for
isolated zone by packers)

Flow

05:00 March 12, 2013 ~16:00 May 2, 2017~

20:30 May 31~ 18:50 June 28

duration*

15:00 March 18, 2013

11:00 May 15#1 20:30 May 31 - 23:00 June

(6d10h00m)#1: 16:00 May 2-7:30 May 3

20 (20d2h30m)(0d15h30m)(Planned disconnect)(ESD malfunction)#2 20:30 June 22 - 8:10 June

#2 21:10 May 3- 11:00 May

24 (1d11h40m)

15 (11d13h50m)(Removal of MH plug)

Total 12d5h20m#3 14:25 June 25- 15:20 June
25 (0d0h55m)(Removal of MH plug)#4 4:50 June 26-18:50 June 28(2d14h0m)
Total 24d4h5m

Max9MPa (13.5MPa-4.5MPa)

7.85MPa(13.0MPa–

6.73MPa(13.0MPa – 6.27MPa)

5.15MPa)

drawdown

Instantaneous:

Stable term: 5MPa (13.0MPa –8MPa)CumulativeGas：119,000Sm3

Gas：40,849.9Sm3

Gas：222,587.1 Sm3

production

Water：1245m3

Water：922.5m3

Water：8246.9m3

Sand production

Sand production

No sand production

3/18 4:05~15:00#1

volumeMajor events

5/4

4:30~5/6(intermittent)#2 5/11 5:00~5/15 5:00
(intermittent)

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6:00

Planned disconnect
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Fig. 1 Well configuration of the first test (2013)

Fig. 2 Well configuration of the second test (2017)

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Ⅳ.2.3 Production Test System(1) Purpose
For the first and second offshore gas production tests, we developed dedicated production systems thatenabled continuous gas and water production by reducing the bottomhole pressure.

(2) Background
The production systems consist of a downhole string, surface process facilities comprising gas and watertrains, and riser pipes for connecting these. In both tests, the downhole pressure was reduced by pumping
up water in the wellbore using an electric submersible pump (ESP), and thereby methane hydrate in theformation was dissociated into gas and water.
Since the test sites have a water depth of approximately 1,000 m, we conducted engineering studies anddesigned a system that can be operated in a safe and secure manner from the drilling vessel. A particulartechnical challenge involved riser disconnection in preparation for rough weather or at drift-off/drive-off
events. Detailed flow assurance and pump design studies were also needed so that we could maintain thebottomhole pressure and prevent hydrate reformation in the flow path.

(3) Implementation and results
The production systems will be outlined below with a focus on bottomhole pressure control and riser
disconnection.
①

Gas-liquid separation and bottomhole pressure control

Figure 1 shows a schematic view of the downhole systems used in the first and second tests. In the first test,
the ESP with an inverted shroud was installed in the 9-5/8" casing [1]. The fluid level in the drill pipe was
reduced by controlling the ESP to start gas production. Production continued for five and a half days before
sand production started. The main operational issue was poor phase separation and the slug flow that
continuously reached the on-board gas train. As a result, the bottomhole pressure was not reduced to 3 MPa
as planned, even when the pump was run at the maximum speed [2] (Fig. 2).

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Fig.1 The downhole system for the first (left) and second tests

Fig.2 Changes in downhole pressure and production rate in the first test
During the second test, an ESP was installed inside the larger 13-3/8” casing to promote gravity separation.
Furthermore, a choke valve was added to the on-board gas train to control the back pressure.
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Consequently, gas was continuously produced for a total of 36 days from the two wells while the liquid
level in the riser was reduced and the production of water accompanying the gas train was suppressed. The
downhole pressure was controlled by either the ESP or the choke valve. However, it was not possible todepressurize the bottomhole to 3MPa as expected, due to the significant amount of sand produced in the P3
Well, and water production beyond the design flow rate in the P2 Well (Fig. 3). In addition, several signs ofblockage caused by hydrate that had reformed in the flow path were confirmed in the P2 Well, andmeasures were subsequently taken, such as methanol injection.

Fig.3 Changes in downhole pressure and production rate in the second test②

Riser disconnection

During the first test, the downhole test string and drill pipes were installed inside the drilling riser and theblowout preventer (BOP). When emergency disconnection took place, it was planned that the test string
would be sheared with the BOP, and then the drilling riser would be disconnected. Due to the two-step
disconnections, the allowable offset of the drilling vessel during gas production was limited to 14 m,
therefore, concern remained regarding the risk of interrupting the experiment during rough weather
conditions. In addition, in the case of a planned disconnection, the downhole string should be pulled up to
the vessel for reconnection, and the test restarted because the downhole cables must be disconnected at thedry-mate connectors in the subsea test tree. Therefore, it was postulated that the experiments after
disconnection should be abandoned, and riser disconnection during the production tests was fortunately
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avoided.
During the second test, by using the workover riser system, installation was carried out with the downhole
string connected to the riser, which significantly reduced the installation time. It was possible tosimultaneously disconnect the gas and water production lines at the seabed, between the well control
package (WCP) and the emergency disconnect package (EDP) shown in Figure 4. As a result, the allowableoffset of the vessel was expanded to 44m, and the test can be continued even in certain adverse weather
conditions. In addition, since the downhole cables can be disconnected and reconnected in the sea at the
wet-mate connectors, this enabled us to switch the two production wells within a short time frame.

Fig.4 Riser disconnection devices, WCP (bottom) and EDP (top)(4) Conclusions
The results of the two offshore production tests demonstrated that continuous gas production using adrilling vessel is possible if sand inflow from the formation can be controlled. Significant design
improvements were made for the second system with regard to the downhole pressure control as well as theriser disconnection and reconnection. On the other hand, design and operation issues such as hydrate
blockage emerged throughout the second production test, which should be tackled and overcome to help
ensure longer-term production in future.

References[1] A Completion System Application for the World's First Marine Hydrate Production Test, Matsuzawa,
Maki, Terao, Yoshihiro, Hay, Bill, Wingstrom, Luke, Duncan, Mike, Ayling, Ian, 25310-MS OTC
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Conference Paper - 2014[2] Issues and Challenges With Controlling Large Drawdown in the First Offshore Methane-Hydrate
Production Test, Sakurai, Shunsuke, Nishioka, Itoyuki, Matsuzawa, Maki, Matzain, Bazlee, Goto,Ayae, Lee, Jay E., 182230-PA SPE Journal Paper -2017

Ⅳ.2.4 Sand Control Device(1) History of Sand Control for Methane Hydrate Development
The pore filling type of hydrate, which exists in unconsolidated sand formations, can fluidize and disturb
the formation when it dissociates. This fluidized formation material can easily fill up the well if sandcontrol devices are not functioning correctly.
During the first winter of the second onshore production test (2007-2008), an unexpected volume of sandflowed into the well and led to the forced termination of the production test. The possibility of sandproduction was recognized in advance through the plugging of the MDT (Modular Formation Dynamics
Tester: trademark of Schlumberger) tool used in the first onshore production test, therefore the well was
drilled deeper than the production layer to accumulate the produced sand at the bottom of the hole.
However, the volume of produced sand - which filled up the hole - was beyond our expectations. The
alternative measure, taken to overcome this problem during the second winter of the second onshore
production test, was to install a sand control device. This led to six days of continuous production.
During the second phase of the project, which started in 2009, sand control was regarded as one of anumber of critical issues to be tackled based on the above-mentioned experience. Therefore, the study
about sand control methods for the first offshore production test, which was planned for the second phase,
was started from the beginning of this phase.

(2) Selection of Sand Control Device for First Offshore Production Test
Throughout the onshore production tests mentioned above, the effectiveness of sand control was a key issue.
However, for the first offshore production test, it was necessary to select another optimal sand control
method because the particle size distribution was considerably different between the onshore site and theoffshore planned test site, where the existence of a large volume of fine contents was identified. (Fig.1)

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Fig.1 Particle size distribution of offshore (left) and onshore (right) site
For the first step of this study, a potential sand control device was identified based on particle size
distribution data from Advanced Well Technologies PTY Ltd (AWT: Now, NauticAWT). The necessity of
depth filtration and overall contact without gaps with the borehole wall was indicated as a possible
requirement. As a result, Premium screen and Frac Pack were identified as candidates. The gravel pack wasalso thought to be one of the candidates and further testing was suggested to confirm its applicability
although it was considered to be rather inappropriate for the layer with a high content of fine particles.
For the next step, laboratory testing for some of the candidate sand control devices was conducted by
Oilfield Production Technology (A consignee of AWT: currently Oilfield Technologies). A sand pack test
and a slurry test (Fig.2) [4] were performed to gain an understanding of the possibility of production
failures due to plugging and the size of particles that pass through those devices, as well as to assess theapplicability of the selected candidates. Similar testing was also conducted for the gravel pack to check theeffect of fine particles. As a result, one of the premium screens exhibited good performance and indicatedthe applicability to the planned offshore production test. In addition, the gravel pack exhibited effectivenessfor the offshore test site although concerns about the possibility of plugging caused by long-term
production still remained.
水Water

サンドパックテスト
Sand Pack Test

Sand砂と水& Water

スラリーテストSlurryTest

Fig.2 Outline of the experiment

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Fig.3 Gravel pack screen (left) and image of section of openhole gravel pack completion(right) (Extracted from Presentation of Methane Hydrate Forum 2014 (Japanese only))
From studies based on the above-mentioned results, the open-hole gravel pack was chosen for completionin the first offshore production test. [5][7] To achieve this, sand screens are installed into an open-hole wellwith annulus between sand screens and formations filled up with gravel. This secures a large flow area andreduces the risk of partial high velocity. In addition, the thickness of gravel in the annulus could work as
depth filtration. On the other hand, some risks of fracturing and/or damage to the formation, which maylead to loss of gravel, could be recognized if the specific gravity of gravel exceeds the formation fracture
pressure. As a countermeasure against these risks, a lightweight material called “LiteProp125” (product ofBaker Hughes, a GE Company) was used.

(3) Sand Production in the First Offshore Production Test
Sand production occurred on the sixth day of the production test. There was no indication of the existenceof sand at the onboard facility, however, real time monitoring data showed a sudden increase in current in
the pump with a reduction in pump frequency due to activation of the safety device. Bottomhole pressure
was expected to recover as the water volume increased. (Fig.4 (left))
Operation of the pump recovered within a short period of time, however, the amount of produced water was
too great to facilitate continued production, and then 15 minutes later, sand was confirmed onboard. Aroundthe same time, it was observed that the temperature in the wellbore increased to almost the same level as
the initial value as pressure recovered. (Fig.4 (right))

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Pump Freq.

Pump
OutletPress.

Pump Press.
IntakeFig.4 Pump behavior (left) and temperature change (right) during sand production(Extracted from Presentation of Methane Hydrate Forum 2014 (Japanese only))

Fig.5 Sand Production(Extracted from Presentation of Methane Hydrate Forum 2014 (Japanese only))

From the recognized events and measured data, the following three hypotheses were set up as a cause ofsand production.
① Damage of screen due to pressure difference caused by depressurization and formation stress: This
includes destruction of base pipe and screen due to overloading, buckling, and bending.
② Lowering of gravel top level caused by contraction of the formation: Gravel may flow out into
gaps in the formation, which could arise due to contraction of the formation as a result ofdepressurization, resulting in sand inflow from the top void space.
③ Formation contacting the screen due to gravel being pushed out: Fluidized sand may push out theused lightweight gravel and then erode the screen.
After repeated analysis and discussions, we inferred that the most likely cause of sand production that
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Comprehensive Report of Phase 2 & 3 Research Results(4) Selection of Sand Control Device for the Second Offshore Production Test
The sand control device for the second offshore production test was selected based on the following
requirements, which were derived from the studies about the issues that occurred during the first offshore
production test. [9]① Device, procedure and/or materials that can eliminate the effects of pressure created during theoperation② The gravel or alternatives that must not move
③ Multiple barriers with material that is physically strong and resistant to erosion④ Cost effective technology for future cost reduction
By considering the above four requirements, four types of sand control measures shown in Fig.6 wereselected as candidates for the second offshore production test.
The first candidate shown in Fig.6 (a) is a prepack screen, which has two layers of screen with gravel
between them. However, a number of technical issues such as limitation of the packer size for isolating thewater layer and reliability were raised. Both of the second and third candidates shown in Fig.6 (b) and (c)are combinations of GeoFORMTM (Shape memory polymer: Trademark of Baker Hughes, a GE Company)
and beads insert. The difference between the two is, for (b) GeoFORM TM will be activated (expanded)
before installation, however, for (c), activation will be conducted in the well, or after installation. The
advantage of option (b) is that waiting time for activation can be reduced, leading to a reduction in rig costs.
On the other hand, the advantages for (c), activated in the well, can also fill up the gap between theformation and screen, which can prevent movement of formation material during production.
Fig.6 (d) is a combination of gravel pack and beads insert. The beads insert is understood to be physicallystronger than sand screens. Also, heavy gravel was considered for use to prevent gravel migration. However,this option was considered to be difficult in terms of isolating the water layer, as well as being difficult to
install.
All four candidates were considered to meet the technical requirements extracted from the first offshore
production test, however, because of the fourth requirement, or the cost effective technology for future cost
reductions, (b) and (c) were selected for the second offshore production test and we decided to apply (b) to
one production well and (c) to another production well.
Fig.7 presents the structure of the selected sand control device. This device consists of three layers ofbarriers. The outer layer is GeoFORMTM, which is the shape memory polymer with a certain degree ofthickness and that works as depth filtration. The middle layer is the mesh screen, and the inner layer is thebeads insert. With this system, sand production will not occur unless all three layers of barriers aredamaged.

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Comprehensive Report of Phase 2 & 3 Research Results(d)(a)プレパックスクリーン
Prepack
Screen
ダブルスクリーン内グラベルパック(b)GeoFORM ＋ビーズインサート
TM+Beads Insert(c)
GeoFORM
TM
TM

Gravel will be packed between two screens

TM＋ビーズインサート
TM+Beads Insert(c)GeoFORM(b)
GeoFORMTM
GeoFORM
GeoFORMTMを坑内に設置後に活性化する物
will be activated in the well

GeoFORM
を事前に活性化したものを設置
GeoFORMTM will be activated before installation(d)ビーズインサート＋グラベルパック(a)Gravel Pack+Beads Insert

Fig.6 Selected sand control device candidates

Fig.7 GeoFORMTM(Extracted from Presentation of Methane Hydrate Forum 2017 (Japanese only))(5) Sand Production During Second Offshore Production Test
During the second offshore production test, production was conducted in two wells (AT1-P3 & AT1-P2).
Sand production occurred in the first well (AT1-P3), which was completed by previously activated
GeoFORMTM. The first instance of sand production was recognized during the second depressurization
after the malfunction of ESD (Emergency Shutdown). In this early stages of sand production, the amount ofsand that collected on board was small, and contained particles that were smaller than the mesh size of thesand control devices, which means that the collected sand was able to pass through those devices. However,it was noted that over time, the particle size as well as the volume increased. When the frequency of thepump was reduced, sand production stopped for a few days, however, when the test reached the mid-termstage, sand production occurred again. For the latter instance of sand production, the flow of sand into thewellbore was predictable, due to significant temperature and pressure changes confirmed by the real-time
in-situ measurement. (Fig.8)[11] In the end, in order to prevent the facility from being damaged andadverse effects from occurring during the next instance of production in the AT1-P2 well, a final decision
was made to stop production after 12 days of continuous tests.

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Fig.8 Example of pressure variation due to sand production
From the detailed study of the measured data, the sand produced in the AT1-P3 well was considered tocome from the bottom side of the well. Erosion or destruction of the sand control device was one of thepossible causes of this sand production, however, according to the experiment conducted in the laboratory,
the shape memory polymer and the beads insert were strong enough for us to conclude that the possibilityof erosion or destruction was very low. Instead, the most likely cause of sand production was considered
to be the malfunction of a portion called a GPV shoe that has a check valve installed at the bottom of theassembly. Detailed analysis of the data showed clear evidence of warm flow coming from the bottom sideof the well, and the pressure and temperature changes were also occurring from the bottom.
For the AT1-P2 well, to address the possible cause of sand production in the AT1-P3 well, a plug was set
above the GPV shoe to prevent flow into the well from the bottom of the assembly. In addition, for the
onboard facility, an additional sand management system was installed to handle sand. As a result, no sandwas produced during 24 days of production, even with a longer production period and a larger volume ofwater produced than that of AT1-P3. These results suggest that the sand control device used in the test
worked effectively although further verification in the test may be needed. [12](6) Future Tasks
We have selected the sand control device for each production test taking into account the previous results oflaboratory testing and field production tests. The results obtained so far clearly show the effectiveness of
depth filtration and the necessity of sand control.
On the other hand, we have not yet obtained a sufficient amount of information to understand the long-term
effectiveness of sand control measures, considering the future long-term production. The high content offine particles may cause clogging around the well or sand control device itself due to accumulation of fineparticles, therefore the long-term production effect of sand control measures still needs to be clarified. Also,
other sand control devices or new technologies need to be developed to create more suitable sand control
against specific geological conditions.

References
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Comprehensive Report of Phase 2 & 3 Research Results[1] MH21, 2008: Japan’s Methane Hydrate R&D Program Phase 1 Comprehensive Report of Research
Results,p.33-35[2] MH21, 2014: Presentation of Methane Hydrate Forum[3] MH21, 2017: Presentation of Methane Hydrate Forum[4] Yoshihiro Nakatsuka・Yoshihiro Terao, 2011: Study for Sand Control and Perforation, JOGMEC Oil &Gas Technical Activity Report April 2010-March 2011, 133-135[5] Yoshihiro Terao, 2012: Studies of Gravel pack for the 1 st Methane Hydrate Offshore Production Test,
2011 JOGMEC Oil & Gas Technical Activity Report, 181-182[6] Koji Yamamoto, 2013: Overview of the First Offshore Production Test of Methane Hydrates in the
Eastern Nankai Trough, 2012 JOGMEC Oil & Gas Technical Activity Report, 212-214[7] Yoshihiro Terao, 2013: Gravel Pack Operation for Methane Hydrate Formation at the First Methane
Hydrate Offshore Production Test, 2012 JOGMEC Oil & Gas Technical Activity Report, 233-235[8] Koji Yamamoto・Masahiro Mizuguchi, 2015: Studies on Sand Production Phenomena, JOGMEC Oil &Gas Technical Activity Report April2014 - March2015, 123-124[9] Masahiro Mizuguchi・Koji Yamamoto, 2015: Plan of Sand Control Device for Next Offshore Production
Test, JOGMEC Oil & Gas Technical Activity Report April2014 - March2015, 132-133[10] Koji Yamamoto・Masahiro Mizuguchi, 2016: Study on Sand Control Device, JOGMEC Oil & Gas
Technical Activity Report April2015 - March2016,99-100[11] Koji Yamamoto・Yoshihiro Nakatsuka, 2018: Outline of the Second Offshore Production Test,
JOGMEC Oil & Gas Technical Activity Report April2017 - March2018, 142-144[12] Koji Yamamoto・Yoshihiro Nakatsuka, 2018: Solutions for Technical Issues (2) Sand Control,
JOGMEC Oil & Gas Technical Activity Report April2017 - March2018, 155-158

IV.2.5 Monitoring system device
During the gas production test using the depressurizing method, it is expected that the formation
temperature, pressure, and other properties surrounding the production well will change due to thedissociation process of MH. To capture such reservoir responses and property changes in situ, the downhole
monitoring system was installed to acquire formation temperature and pressure data, and geophones werealso deployed in the vicinity of the production well to acquire 4C seismic data.
Ⅳ.2.5.1 Downhole monitoring(1) Objective
When conducting a study on the MH development system with the aim of achieving long-term production,
it is desirable to acquire as much data as possible about reservoir characteristics and responses. In fact,
monitoring wells completed near the production well have the advantage of being able to passively observe
reservoir responses during the production period. Therefore, the following objectives for downhole
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Comprehensive Report of Phase 2 & 3 Research Resultsmonitoring were determined for the first and second offshore production tests:Capturing the initial condition of formation and in-situ property information

Acquiring information about formation response against the depressurization method

Understanding the dissociation behavior of MH

Acquiring knowledge about heat and fluid movement in the formation

To achieve these objectives, we aimed to acquire data about reservoir temperature in the first offshore
production test, and about reservoir temperature and pressure in the second offshore production test. In thefollowing, we will report on the techniques used to acquire temperature and pressure data performed inPhase 2 and 3, and the results of the data analysis.

(2) Background
In Phase 1, the downhole temperature sensor was introduced and installed in “Tokai-oki to Kumano-nada”
in 2002 [1]. Subsequently, temperature measurements were performed in two on-shore production tests [2].
In Phase 2 and 3, the temperature measurement system was developed and enhanced to meet therequirements of the offshore environment for the production tests.
For the first offshore production test in 2013 during Phase 2, a monitoring system equipped with two kindsof temperature sensors using DTS (Distributed Temperature Sensing) and array-type RTD (Resistivity
Temperature Detector) was installed into a borehole and at the seabed of two monitoring wells, andtemperature measurements were carried out during the six-day production test.
Further upgrades and enhancements enabling in-situ pressure measurement were implemented on thedownhole monitoring system developed for the second offshore production test in 2017 during Phase 3.
This uniquely-developed subsea monitoring system equipped with both temperature and pressure sensors
was deployed in two monitoring wells around the production well.

(3) Contents and results① Monitoring system design
a. Results of temperature measuring
To measure formation temperature, an integrated system of DTS (Distributed Temperature Sensing) andRTD (Resistance Temperature Device) was designed for monitoring. DTS is a fiber optic distributed sensor
that can measure temperature distribution as a function of depth from seabed to well bottom, while RTD isa resistor sensor in an array that mainly covers the MH-concentrated zone with higher temperature
resolution.
The subsea monitoring system with a pressure vessel containing the measurement unit, battery, and othercritical components was installed at seabed level so that it can control acquisition and store data obtained
from downhole sensors. (Fig.1, 2) Both DTS and RTD sensors acquired reservoir temperature for morethan a year, and real-time data acquisition was achieved during the production period.

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Fig.1 Overview of formation temperature monitoring system for first offshore production test

Fig.2 Overview of formation temperature and pressure monitoring system
for second offshore production test

b. Results of pressure measuring
Although reservoir pressure measuring in the monitoring well was waived during the first offshore
production due to its technical complexity, realization of in-situ pressure measuring incorporated into themonitoring system was considered in order to provide such vital reservoir parameters along withtemperature data.
At each monitoring well, the pressure sensors were respectively installed in upper and lower
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MH-concentrated zones. To measure formation pressure, several pressure ports on the sensor protector
were especially designed and developed to realize conduction of pressure propagation. Similar totemperature monitoring, pressure was recorded for more than a year while real-time data acquisition was
confirmed during the production period.
② Demonstration of acoustic communication system
During the second offshore production test, acoustic communication system was used to retrieve the data atmonitoring wells during and after the production period in order to efficiently data transfer from the seabedto the surface without requiring a physical connection comprised of subsea cables. (Fig.3)
With this system, the data was acquired as per the retrieval schedule, and establishment of reliable wirelessdata communication was confirmed during the offshore production test. As a result, operation efficiency
and safety were significantly improved.

Fig.3 Data retrieval operation with acoustic communication system③ Key findings and knowledge obtained from acquired data
a. Evaluation of impact from cement heat release on MH in the surroundings
One of the concerns in terms of completing a MH well is the integrity of cement used to maintain theseparation between the production layer and another formation or the seabed. In this context, there is aconcern that heat generation and temperature increases at the time of cement hydration could cause MH
dissociation to affect the stability of the MH layer.
DTS started recording the temperature data before cementing (Fig. 4), and these temperature data areused to estimate the spatial impact by heat generation from cement at each depth level near themonitoring well. Since the amount of heat generation is relative to that of cement in place, a hightemperature increase was observed in the interval where the borehole diameter became washed out andMH21 Research Consortium

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enlarged.
Based on the heat generation model of cement constructed in Phase 2, the stability of the MH layer in thevicinity of the monitoring well during cementing was evaluated. As a result, MH dissociation around themonitoring well arising from the cement hydration heat was in the order of several centimeters, andsubsequently it was not considered to pose a particular hazard [4].

Fig.4 Temperature profiles in MT1 including period prior to cementing

b. Initial formation temperature determination
The installation of thermometers was attempted in the 2004 campaign at “Tokai-oki to Kumano-nada",
however, the data could not be acquired in the Daini-Atsumi Knoll wells.
For the first offshore production test, stable temperature measurement in the formation was attained afteralmost reaching an equilibrium state, because there was one-year period for the temperature to relax
between the drilling/cementing stage and the start of the production test [5].

c. Determination of sand produced interval
During the first offshore production test, sudden sand production occurred six days after the start ofdepressurization, and rapid temperature changes were observed in some formation layers in the monitoring
well at almost exactly the same time that sand was seen inside the production well. Since a large amount ofwater was also noted to accompany sand production simultaneously, it was inferred that high permeable
layers existed in the formation between the production and monitoring wells, and that the temperature
measurement in the monitoring well supported the determination of the sand produced interval.
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Comprehensive Report of Phase 2 & 3 Research Resultsd. Validity of in-situ pressure measurement
The figure at left in Fig. 5 shows the pressure transients in the production and monitoring wells. By
comparing these two curves, a strong pressure reduction correlation was identified in the monitoring wellfollowing the production well. The figure at right shows the phase diagram of the pressure and temperatureobserved in each monitoring well, and the general trend and change of pressure/temperature tracing the
curve of MH dissociation during the test period that supported the valid and effective measurement of
in-situ pressure.

Pressure data

Phase diagram (P/T)

Production well

Monitoring well

Monitoring well
(P/T)

Fig.5 Pressure transients in production and monitoring wells (left), Pressure/temperature transients onphase diagram in each monitoring welle. Understanding of MH dissociation behavior
During the second offshore production test, reductions in temperature were observed in the monitoring
wells at the corresponding depths where the temperature in the production wells fell due to the dissociatedwater and gas inflow (Fig.6). From the temperature transients in the monitoring wells, layer permeability
was estimated in the gas production interval from the numerical simulation assuming adiabatic conditions[6], (Fig.7).
It was also found that there was a difference in the dissociated interval among two production wells during
each depressurization and flow test period by integrating the temperature data in the production andmonitoring wells (Fig.8). The analysis of the MH saturation changes from the observed temperature andpressure data indicated that the estimated change in saturation would be within the range of a few
percentage points, and that it is in line with the results of the first offshore production test.

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Fig.6 Resistivity image in MH reservoir (left track) and temperature change in monitoring wells (middle
and right track)

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Fig.7 Simulated (dashed) and actual temperature changes for various layer permeability in AT1-MT1

Fig.8 Temperature change in two production wells and two monitoring wells(4) Summary
During the first and second offshore production tests conducted during Phase 2 and 3, the downhole
monitoring system was developed and installed to measure reservoir temperature and pressure.
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Data transfer from the seabed to the drilling vessel was carried out through using the acoustic
communication system, which eliminated the need to have a physical connection using a cable. As a result,the necessary rigging time was shortened for the data retrieval operation, and the safety margin in case of
emergency disconnection was increased.
The MH dissociation range as well as the characteristics of thermal transport in the reservoir were analyzed
from the monitoring data obtained during the production periods. In future, it will be necessary to further
improve and enhance the monitoring system according to the feedback and inputs from the data analysis
and study results for future production tests with a focus on the commercial phase.

Citation and references[1] Schlumberger, Methane Hydrate Temperature Measurement System Deployment Feasibility Study andHigh-level Design, 2013.
[2] Research Consortium for Methane Hydrate Resources in Japan, “Japan’s Methane Hydrate R&D
Program - Phase1 Comprehensive Report of Research Results”, Aug 2008.
[3] X. Wang, M. Takekoshi, T. Kanno, V. Shako, V. Pimenov, A. Parshin, and K. Yamamoto, "Numericalsimulation on the impact of temperature behavior for cement hydration for the world's first offshore
methane hydrate production test", OCT2014, 25326, Houston, Texas, United States, May 2014.
[4] X. Wang, T. Kanno, S.S. Chee, V. Shako, V. Pimenov, and K. Yamamoto, "Review of in-situ monitoringdata from the cement heat of hydration for the first and second Offshore MH production test in the
Eastern Nankai Trough, Japan", ICGH9, Denver, Colorado, United States, June 2017.
[5] T. Kanno, M. Fukuhara, O. Osawa, S. Chee, M. Takekoshi, X. Wang, V. Shako, V. Pimenov, T. Fujii,
and K. Yamamoto, "Estimation of geothermal gradient in marine gas-hydrate-bearing formation in the
Eastern Nankai Trough", ICGH8, Beijing, China, July, 2014.
[6] K. Yamamoto, T. Kanno, X. Wang, M. Tamaki, T. Fujii, S.S. Chee, X. Wang, V. Pimenov, and S. Valery,"Thermal responses of a gas hydrate-bearing sediment to a depressurization operation", RSC Adv., vol.
7, pp. 5554-5577 2017.
[7] Yamamoto, K., Konno, Y., Wang, X.-X., Wang, X.-W., Kanno, T., 2017: Thermal Data Analysis toInvestigate Mass and Heat Transport during Methane Hydrate Dissociation Processes, 6th Biot
conference on poromechanics, July 10-13, Paris, France.

IV.2.5.2 Four component seismic survey(1) Background and Results
During the first offshore production test carried out in Phase 2 aimed at gaining an understanding of thechanges in physical properties that accompany MH dissociation as a result of gas production tests,
geophysical monitoring was carried out using four component seismic surveys. An OBC with 4 built-in
components (two horizontal accelerometer components, vertical component, hydrophone) was installed
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near the production well, and seismic data was acquired (Fig.1). Data was acquired on three occasions,once before the gas production test (August 2012), and twice after the gas production test (April 2013 andAugust 2013). The purpose of acquiring data twice after the gas production test was to understand whatkind of changes occurred by comparing the data after the gas production test approximately four months
prior.
The obtained result shows that the changes in physical properties could be understood by comparing data
before and after the gas production test.
During the analysis process, it was initially thought that the changes in physical properties were due to MH
dissociation or the generation and regeneration of MH. A subsequent study has revealed that there arevarious factors involved such as changes in the gas saturation of pore water after MH dissociation, andchanges in density due to consolidation of sediments.
In order to determine whether the difference due to the comparison the data before and after the gas
production test is significant, it is necessary to improve the quality of acquired data and review dataprocessing of acquired data. Subsequently when carrying out geophysical monitoring during the second
offshore production test, a technological study involving items such as the receiver point and source point
layout for enhancing imaging effects near the gas production test well, the method to improve source point
accuracy, and data acquisition time, was conducted.
In order to significantly enhance the reservoir image near the gas production test by carrying out asimulation in advance (Fig.2), the two receiver cables were arranged in east and west directions with thegas production test well in between, and the source point was placed within the range of 4km north by 3km
east to west centering on the gas production test well (Fig.3). In addition, in order to improve the accuracyof the source point, a GPS antenna was installed at the center of the float beneath the air gun (Fig.4).
Data was acquired before the gas production test (M0) was conducted from late July to early August 2016.
Fig.5 shows a comparison of the source point, receiver point, well location, and data acquisition
specifications, and Table.1 shows the comparison of data acquisition specifications between the first andthe second offshore production tests.
The first data acquisition (M1) after the gas production test was conducted from the end of October 2017 to
the beginning of November 2017.
In addition, data processing of acquired data was carried out, and M0 data and M1 data were compared.
Time-lapse data processing for the purpose of comparing data before and after the gas production test was
carried out. In addition, the reproducibility index was calculated to evaluate the appropriateness of thetime-lapse data processing result. As a result, the NRMS value became 10% in the region where theinfluence of the pressure reduction is small and the changes in physical properties due to the reduction is
also small. It is judged that appropriate time-lapse data processing is applied because the NRMS value thatis considered to be good for reproducibility is 30% or less (Johnston, 2013). An interpretation example ofM0 and M1 is shown in Fig.6, and an amplitude image in the MH reservoir is shown in Fig.7.
The second data acquisition (M2) after the gas production test was acquired in late July 2018, and data
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processing of M2 data and time-lapse data processing of M0, M1 and M2 data were carried out to evaluate
physical properties before and after the gas production test.

(2) Conclusion
In Phase 2 from 2012 to 2013, four component seismic surveys were conducted before and after the gas
production test during the first offshore production test, and changes in physical properties could beunderstood from data comparisons before and after the gas production test. On the other hand, the causal
relationship between MH dissociation and changes in physical properties remained a problem.
Based on the technical examination of issues at the time of the first offshore production test, four
component seismic surveys were carried out a total of three times each involving M0, M1, and M2 from2016 to 2018 during Phase 3 of the second offshore production test. Data processing has been completed
and the analysis of those data is currently ongoing. Finally, based on the comparison of M0 and M1, andM0 and M2, the changes in physical properties due to the influence of MH decomposition is evaluatedbased on the examination of the significance of the difference. Furthermore, the comparison between M1
and M2 also confirms what changes have occurred after the gas production test. These results are expected
to be useful for MH reservoir assessment.

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Fig.1: Receiver points/ shot points/ well location/ specifications of data acquisitionin the first offshore production test

Fig.2: Result of simulation

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Fig.3: Layout of OBC and shots area

Fig.4: Arrangement for improving the accuracy of source point

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Fig.5: Receiver points/ shot points/ well location/ specifications of data acquisitionin the second offshore production test

Table.1: Comparison specifications

Receiver line

First offshore production test

Second offshore production test

36 units in one line

35 units in two lines each

Interval of

Approx. 200 m

receiver line
Interval receive

26.5 m26.5 mNorthwest – Southeast: eleven
Source line

lines 11 lines
Northeast – Southwest: twolines

Interval of source
line

Northwest – Southeast: 100 m
Northeast – Southwest: 267.5m

Interval of source
point
Number of source
point

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East - west: Forty one lines
South – north: thirty one lines
East - west: 106 m
South – north: 106 m

26.5 m26.5 m

1,797

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Fig.6: Examples of interpretation of M0 and M1

Fig.7: Amplitude image of M0 and M1 in the MH reservoir

ReferenceJohnston, D. H. (2013). Practical applications of time-lapse seismic data. Society of Exploration
Geophysicists.

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