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IV.3 Data and information that the first and the second offshore production test formethane hydrate provided
IV.3.1

Data of Well, Logging, the Core and the Reservoir

IV.3.1.1

Well Logging and Coring in First and Second Offshore Production Tests(1) Summary
The logging while drilling (LWD) is a very effective tool to ascertain information about properties ofmethane hydrate (MH) reservoirs containing unconsolidated sediment. When you use LWD, you need to becareful about the positions of the sensor. A section between a drill bit and the sensor of the LWD is a nodata section. The no data section will be long when LWD is connected. On the other hand, there is a riskthat water will be produced when we drill into the free gas area where the water zone is below the methane
hydrate reservoir section.
The production well did not drill below the depth of the MH stability lower limit to reduce the risk of water
being drawn from a low-ranking layer in the gas production test zone. Other wells were drilled with a
combination of LWD and wire line logging (WL) to shorten the non logging section as much as possible.
Information about well logging in the first and the second offshore production tests, as well as coring of theSecond Atsumi Knoll are shown in Table 1.
Under room temperature and one atmospheric pressure conditions, MH will change into gas and water, so
we developed a "the pressure coring tool system" that can keep the pressure of the core in-situ.
Development of the device that can measure the sediment properties of the core under in-situ pressureadvanced through phase 2 and 3. Various analyses of the acquisition core were also completed. In addition,
information about analysis of the core is shown in another clause about.

(2) Summary of Well Investigation in Phase 3
In 2012, we carried out coring of the investigation well (geo-technique well) one year before the first
offshore production test was carried out. The purpose of the geo-technique well is to investigate theproperties of the shallow formation above the MH reservoir. The coring carried out at this time was
implemented with a normal core tool that cannot maintain in-situ pressure. As a result, we were not able torecover core samples of semi-unconsolidated sediment or unconsolidated sediment, including MH. At thesame well, a corn penetration test was carried out under in-situ conditions, however, well logging was not
carried out.
The monitoring well was drilled the year before the first offshore production test was carried out. Various
types of well logging were performed in the monitoring well during drilling and after completion. Logging
while drilling (LWD), Open-Hole Wireline logging (OH-WL) and Cased-Hole Wireline logging (CH-WL)
were performed in the AT1-MC well (see Table 2).
The coring in the first offshore production test was performed after these monitoring wells were drilled. We
used both a normal coring tool of IODP, and a pressure coring tool. Both tools and related tasks were
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carried out in the MH reservoir section.
The acquisitioned core was subjected to a dynamics examination and a MH resolution examination, andvarious sediment properties of matter were measured after the density and P wave speed were measured. Inorder to gain an understanding of the geological properties after the gas production test was carried out, twowells, AT1-LWD1 and LWD2, were drilled, and OH-WL well logging was also carried out.
In the second offshore production test, a total of five wells were drilled comprising two production wells,
two monitoring wells, and one prior investigation well. Drilling of the production well was stopped before
the top of the production section was reached in the first year, and a reentry was carried out in the next year
and drilling of a production section was completed. Therefore, drilling of the production well of the second
offshore production test shown in Table 2 and well logging tools are different in each.
By the time the production well drilling took place in 2017, we had planned a large number of OH-WL welllogging with LWD well logging, but we reviewed OH-WL well logging because a significant aperture
diameter expansion was observed as a result of drilling in LWD. As a result, we did not carry out thesaturated rate well logging using the pulse neutron generator of the P3 well. At the time mine abandonment
work of the second offshore production test was carried out, AT1-CW1 and AT1-CW2 were drilled in order
to ascertain formation properties. In AT1-CW1 and AT1-CW2, we carried out OH-WL well logging andimplemented pressure coring using an improved pressure coring tool.

IV.3.1.2

Characteristics of MH Reservoir from Well Logging and Core Data

(1) Lithofacies Distribution
The wells that penetrated the MHCZ with LWD were AT1-MC, LWD1, LWD2, and MT2, UD. Of these,
the three wells that enforced ratio resistance well logging and nuclear magnetic resonance well logging, andwhere the density was measured from pulse neutrons and saturated rate well logging, were AT1-MC, MT2,and UD. These three wells are located in the up dip in the order of MC, MT2, UD. In addition, in the CW1and CW2 wells, well logging by OH-WL was carried out below the lower limit of the domain of the MH
stability zone. Information about the formation continuity of the direction for sedimentation of the turbidite
was provided from these wells (Fig. 1).
In wells AT1-MC, MT2, and UD, the lithofacies profile of the depth direction made it clear that it waspossible to make comparisons using natural gamma rays in terms of a volume of less than 3ms of nuclear
magnetic resonance well logging (Fig. 2). In addition, it was confirmed by natural gamma rays that wells
AT1-MC, MT2, UD had good formation continuity. We can compare the CW2 well with the AT1-CW1 wellequally in a depth profile (Fig. 3). From these well logging results gathered from the first and second
marine production test locations, we were able to recognize the continuity of the formation and ascertainthat there were few lithofacies changes.
We redivided the unit division that was built based on lithofacies information provided by research into
wells drilled during phase 2 of the first and second offshore production tests because we recognized thelower part of Unit III leading to the thin sand mud layer (Unit IV). As a result, we revised the border depth
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Comprehensive Report of Phase 2 & 3 Research Resultsof Unit III and Unit IV and associated it with lithofacies. From the result of drilling in the up dip location,
we discovered that the thick sand of the lower part of the MH reservoir continued to the thick sand under
the lower limit of the MH stable zone. We defined the section of thick sand again as Unit V anddistinguished it from thin sand mud layers (Unit IV) that are the section of the upper part of the MH
reservoir (Fig. 4).
(2)

Resistivity of Wells and MH Saturation

We knew from the results of well logging and core analysis that the distribution of the MH saturation rate isheterogeneous at the location. The resistivity of well logging results made a big difference at each well(Fig.5). The section where low resistivity continued locally in the MH reservoir, was observed
conspicuously in wells, MT2, UD, P2, and so on (low ratio resistance section: Low Resistivity Interval;
LRI). It was confirmed that there was a sand layer in this low ratio resistance section, and the analysis of
the core sample showed that the MH saturation rate was not regulated only by a lithofacies. Because thelow MH saturation sand layer that has such low resistivity becomes the water production layer at the timeof decompression, we need to pay more attention.

IV.3.1.3

Summary of MH Reservoir

From the thawing and re-freezing of MH through past changes in sea levels, it is thought that thecharacteristics of the MH reservoir of the Second Atsumi Knoll that were carried out during the first andsecond offshore production tests have become complicated.
The water production layer obstructs decompression, and there is an inherent risk due to its ability to cause
sand to appear. The technique that detects a water layer in the MH reservoir is required in order to realize
effective gas production without water.
From the viewpoint of natural resource quantities, it is considered that it is important that MH exists in thegood sand layer with a high saturation rate, however, it is important for the initial water existence effectpenetration rate that pressure that spreads during gas production due to decompression in the production
well is not too low. From the production test results of the first and second tests, it was discovered that thesand layer with low MH saturation rates appears to contribute to gas production, and has the opposite
nature to that which exists when there is a water layer. It will be necessary to note this as a result of adecision made by the production section.

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Table 1.
Year

Month

Well list of Second Atsumi Knoll

The survey names

Purpose2011 Feb.～Mar. The first offshore production test feasibility study
2012 Feb.～Mar. The first offshore production test prior drilling
2012
2013

Jun.～Jul. The first offshore production test drillingAug.

The first offshore production test abandoned welllogging

Well nameDrilling section

To understand the geological character of ATS, AT1-GT1, AT1-GT2,
the upper section on the reservoir section AT1-GT3
AT1-MC, AT1-MT1,
Monitoring well, production well drilling
AT1-P

Unit I, Unit II,
Unit III
Unit I, Unit II, Unit III,
Unit IV, Unit V

To understand the reservoir properties

AT1-C

Unit IV, Unit V

To understand the reservoir properties

AT1-LWD1, AT1-LWD2

Unit IV, Unit V

2016

May

The second offshore production test prior drilling

Monitoring well, production well drilling

AT1-MT2, AT1-MT3, AT1-P2*, Unit I, Unit II, Unit III,
AT1-P3*, AT1-UD
Unit IV, Unit V

2017

Apr.

The second offshore production test drilling

Production well drilling, and complation

AT1-P2*, AT1-P3*

Unit IV, Unit V

To understand the reservoir properties

AT1-CW1, AT1-CW2

Unit I, Unit II, Unit III,
Unit IV, Unit V

2018

The second offshore production test abandoned
Mar.～Apr.
well drilling*In the first year, "the AT1-P2 well" and "the AT1-P3 well" were drilled to above the reservoir section, and in the second year they was drilled to each TD and were completed.

Loggings of Second Atsumi Knoll
Wireline Logging
Cased Hole2012 Feb.～Mar. The first offshore production test prior drilling

2013

2016

2017

2018

Aug.

May

Apr.

Mar.～Apr.

The first offshore production test abandoned
well logging

The second offshore production test prior drilling○ ○ ○ ○ ○AT1-MT1

○ ○

AT1-P

○ ○

○ ○ ○

Note

Resistivility

Ganmma Ray

Open Hole

Dipmeter survey etc.

MH Saturation**

Sonic

NMR*

DensityGanmma Ray

Resistivity

MH Saturation**

AT1-MC

Sonic

NMR*

DensityGanmma Ray

Year・Month・The survey names・Well nameResistivity

Logging

MH Saturation**

LWD

Formation Pressure

Table 2.

○ ○ ○ ○ ○ ○ ○ Unit I, Unit II, Unit III, Unit IV, Unit V
Unit I, Unit II, Unit III, Unit IV, Unit V○

AT1-LWD1 ○ ○

○ ○

○

○

AT1-LWD2 ○ ○

○ ○

○

○

We acquired data in some production
section
Unit I, Unit II, Unit III, Unit IV, Unit V(In WL, we acquired data in some sections)
Unit I, Unit II, Unit III, Unit IV, Unit V(In WL, we acquired data in some sections)

AT1-UD○ ○ ○ ○ ○ ○ ○Unit I, Unit II, Unit III, Unit IV, Unit V

AT1-MT2○ ○ ○ ○ ○ ○ ○Unit I, Unit II, Unit III, Unit IV, Unit V

AT1-MT3○ ○○Unit I, Unit II, Unit III, Unit IV, Unit V

AT1-P2○ ○○Unit II, Unit III and some of Unit IV

AT1-P3○ ○○AT1-P2

○ ○

○

○

○ ○ ○

Production sections of Unit IV and Unit V

AT1-P3○ ○○○Unit II, Unit III and some of Unit IV

The second offshore production test drilling

The second offshore production test abandoned
well drilling○ ○Production sections of Unit IV and Unit V

AT1-CW1○ ○ ○ ○

○ ○Unit IV, Unit V

AT1-CW2○ ○ ○ ○

○ ○Unit IV, Unit V*NMR：nuclear magnetic resonance, **MH Saturation：well logging using the pulse neutron generator

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Fig. 1.

Fig. 2.

Main well location in Phase 3

Well log correlation of AT1－MC, MT2, UD (Gamma Ray and NMR(less than 3ms))

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Fig. 3.

Well log correlation of AT1－MC, CW1, CW2, MT2 (Gamma Ray and NMR(less than 3ms))

New Unit and Lithofacies division Name

Unit V

Lower part,thick sandlayer

MC well

Unit IV_a

MH Reservoir

Unit IV_c

Unit V_a

Unit V_b

Upper part,
mud layer

Unit III

Upper part,sand mud alt. layers＊

Unit IV-1

Middle part,
mud layer

Unit IV-2

Lower part,thick sand layer

Unit IV-3

deeper than BSR

Unit VTop of GH
Reservoir

Unit IV_b

Fig. 4.

Old lithofacies division name OldUnit

Unit III

Production Section

Upper part,sand mud alt.
thin layers＊

Water
saturation
section

Unit IV

Upper part,
mud layer

Low
MH saturation
section

New Unit New lithofacies
Name
division name

Unit IIIOld Unit and Lithofacies division Name

Section name,to compare with
MC wellTD
Base of Gas Hydrate
Stability Zone(BGHSZ)

New unit vs

old unit of lithofacies

The new unit division sorts it in lithofacies based on findings. The low MH saturation sand layer as thewater bearing layer in the lower old Unit III and old Unit IV-3 were sandwiched. So, we changed "themud layers" to "sand mud alternated layers".
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Fig. 5.

A resistivity well logging result of each well. Even if we can compare the same horizon, theresistivity levels are different. LRI: Low Resistivity Interval, BGHSZ: Base Gas Hydrate Stability Zone.

IV.3.2 Gas/water Production and Gas Production Behaviors Interpreted from Monitoring Data
(1) Introduction
To evaluate the commercial value of MH, the main objectives of the two offshore production tests carriedout in the Eastern Nankai Trough (2013 and 2017) were to identify how much gas and water can beextracted from a MH reservoir, and how MH dissociation regions were advanced temporally and spatially.
In past onshore tests (Mallik 2002, the Northwest Territories, Canada, Mallik 2007-2008, the Northwest
Territories, Canada, Ignik Sikumi 2012, Alaska, U.S.), distribute acoustic sensor (DTS) and other devices
were installed in boreholes to measure pressure and temperature changes, as well as to measure gas andwater flow rates. Based on such experience, attempts were made to integrate monitoring data from producer
wells and monitoring boreholes during the offshore production tests. Fig. 1 shows the configuration of
boreholes in the two offshore tests.

(2) First Offshore Production Test
Fig. 2 shows the bottom-hole pressure and temperatures, and rates of produced gas and water measured
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during the first offshore test (2013). For this test, two monitoring holes (AT1-MT1; 20m from the producerhole, and AT1-MC, 30m from the producer hole) were drilled and DTS cable was installed into each hole.
Measuring details are described in IV 2-5. Measuring continued after the test for more than 100 days andprovided information about temperature recovery (Fig. 3).
During the first test, approximately 9 MPa of drawdown (from 13.5 MPa to 4.5 MPa in bottom holeflowing pressure) was achieved and lead to the realization of almost stable gas and water flow (20,000
m3/day of gas and 200 m3/day of water). The gas-to-water ratio (GWR) was approximately 100, which was
almost half the theoretical value. This shows that approximately the same volume of original formationwater was produced with gas hydrate dissociated water.
The following points were interpreted from the temperature data: Almost stable gas and water flow was realized with a gas-to-water ratio of approximately 100,
however, no obvious increase in gas rate was observed. In the later stage, a slight increase indrawdown did not lead to an improved gas rate; rather a reduction in the GWR.
 In the producer hole, a temperature drop was observed in the sections of the upper thin-bed
sand/silt alternation (0-20mBTMHCZ) and lower thick sand layer (30mBTMHCZ) as shown in
Fig. 3. The temperature drop in the upper zone was also detected not only in the closer AT1-MT1
well, but also at the more distant AT1-MC. On the other hand, no temperature drop was measured
in the lower zone.
 At the 20 mBTMHCZ of the AT1-MT1 well, a temperature drop was observed at the same time
as drawdown began, however, the reduction trend slowed fairly soon after. This event could not
be explained by dissociation of MH, and may indicate an influx of cooler formation water.
 At the same depth (20m BTMHCZ), anomalously strong water influx to the producer hole wasinterpreted by a detailed temperature analysis (Fig. 5).
 Moreover, this depth is interpreted as being the interval where sand production occurred. The
temperature recovery trend for the depth also differed from that of the other interval.
An inferred situation in the reservoir used in the production test and related observations was summarized
in Fig. 6. It seems that the gas/water production behavior and sand production were strongly affected by theanomalous water producing interval.

(3) Second Offshore Production Test (2017)
Fig. 7 shows the bottom-hole pressure and rates of produced gas and water measured in two producer
boreholes (AT1-MT3 and AT1-MT2) of the second offshore test (2013). In spite of sand production events,
12 days of approximately 7MPa drawdown were realized in the AT1-P3 well, although no increase in gas
rate was observed, and a slight decrease in gas and a slight increase in water rates were observed.
Furthermore, although a relatively large drawdown occurred, the measured gas rate was 3,000-4,000 ㎥/day,which was significantly smaller than the value from the 2013 test (AT1-P well). The water rate was
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approximately 80 ㎥/day, and GWR was 40-50.
The achieved stable drawdown in the AT1-P2 well was limited to approximately 5 MPa due to the excesswater rate to be handled by the installed pump, however, the measured gas rate reached approximately
10,000 ㎥/day. The water rate exceeded 300 ㎥/day, and GWR was as low as 20-30. Under the situation,
frequent flow assurance issues by MH re-association occurred, however, data sets of production behavior
with different degrees of drawdown (3 and 5 MPa) were obtained.
No increase in gas rate was observed in either of the drawdown cases. When the degree of drawdown wasincreased, the gas rate was increased at once but decreased over time to approximately 10,000 ㎥/day. Afterthe planned disconnection on the 21st day, no stable rates were achieved.
From the monitoring data, the following were observed.
From the temperature and fluid density computed from pressure gradient (Fig. 8), the main gas
production interval of AT1-P3 was interpreted as the deep section (40m or deeper below top of
Unit-IVb). The upper thin-bed section, which was the main gas production zone in other wells, did
not contribute to gas production. This might be caused by different reservoir characters (MHsaturation, permeability, etc.) or any other reason that prevented propagation of depressurized
conditions from the borehole to the reservoir.



Meanwhile, the bottom part of the upper section seemed to be the main gas production zone in
AT1-P2, and water was produced from the lower zone and the top of the upper zone.

The temperature and pressure data shown in Fig. 9 indicated a MH dissociation-induced
temperature drop, however, some sensors detected pressure recovery (lower sensor of AT1-MT2
during AT1-P2 production).



By comparing data from producers and monitoring boreholes (Fig. 10), strong correspondence
among wells were seen.

It should be noted that the production behavior of the early stage of AT1-P2 may have been influenced by
the activation fluid, DE-acetate, or the sand control device (GeoFORMTM).

(4) Summary
The data obtained from three boreholes highlighted a variety of production behaviors although the wells
were drilled within a small area (within a circle with 50 m radius). The common observations were no
increase in gas rate over time and degree of drawdown, and a decrease of GWR over time. The reasons forthese observations should be considered critical knowledge to be utilized to improve productivity of MH
reservoirs, and subsequently, further investigations are necessary.

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References
Yamamoto, K., Kanno, T., Wang, X.-X., Tamaki, M., Fujii, T., Chee, S.-S., Wang, X.-W.,Pimenov, V., and Shako, V. (2017a).
“Thermal responses of a gas hydrate-bearing sediment to a depressurization operation.” RSC Adv., 7, 5554 - 5577.
Yamamoto,K., Konno, Y,, Wang, X.-X., Wang X.-W., Kanno, T. (2017b): Thermal Data Analysis to Investigate Mass andHeat Transport during Methane Hydrate Dissociation ProcessesVandamme et al. (eds),

Poromechanics VI:

Proceedings of the Sixth Biot Conference on Poromechanics, 2049 – 2056.

Fig. 1 Borehole configuration of first (left) and second (right) offshore production tests. In first test, somewell inclination was observed, and projected well trajectories were drawn using red lines. As a result,production well was drilled in downdip direction. For second test, monitoring and producer boreholes
were intentionally drilled at vertex points of a parallelogram to distinguish MH dissociation-induced
temperature drop and influx of cool fluid.

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20.0001418.00012
16.000Pressure (MPa-a)

12.00010.0008.000

Pressure (pump intake@-94mBTMHCZ) MPa-a

Pressure (bottom hole gauge@23mBTMHCZ) MPa-a

Tempreature @ 2.192mBTMHCZ (deg C)

Tempreature @ 4.192mBTMHCZ (deg C)

Tempreature @ 6.192mBTMHCZ (deg C)

Tempreature @ 8.193mBTMHCZ (deg C)

Tempreature @ 10.194mBTMHCZ (deg C)

Tempreature @ 12.195mBTMHCZ (deg C)

Tempreature @ 14.195mBTMHCZ (deg C)

Tempreature @ 16.196mBTMHCZ (deg C)

Tempreature @ 18.196mBTMHCZ (deg C)

Tempreature @ 20.197mBTMHCZ (deg C)

Tempreature @ 22.197mBTMHCZ (deg C)

Tempreature @ 24.198mBTMHCZ (deg C)

8

6

Tempreature @ 26.199mBTMHCZ (deg C)

Kill welloperation

6.000

Temperature (deg-C)

1014.000

4

4.000
2.000

Start of pump
operation (0 hr)

2

Pressure surge due
to surface flowline
operation

Onset of sandproduction

Pressure sensor
line malfunction

156

144

132

800

35000

700

30000

600

25000

500

20000

400

15000

300

10000

200

5000

100
156

144

Elapsed time (hrs after pump operation start @05:00 Mar 12, 2012 JST)

132

120

108

96

84

72

60

48

36

24

12

0
0

-12

0

Temperature (deg-C)

120

108

96

84

72

60

Ellapsed
timerate(hrsm3/day
after 05:00
Mar 12, 2012
JST)
Total gas(@ 0.101560
MPa-a/15.56
deg-C)
Water inflow rate m3/day

40000
Gas production rate (Sm3/day)

48

36

24

12

0
0

-12

0.000

Fig. 2 Bottom-hole pressure and temperature, and gas and water rates of first production test (2013).
Reference depth is top of MH concentrated zone (TMHCZ). Temperature data were taken by installed
DTS. Pressure measurement at bottom of hole was interrupted by lost data communication, andpressure at ESP intake was added. Water production rate is converted to influx from reservoir toborehole by subtracting water displacement from wellbore to surface.

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Fig. 3 Comparison of temperature drop data of producer (AT1-P), and monitoring wells (AT1-MT1 andMC). Monitoring well data also indicated temperature recovery term after test. AT1-MC well data wasinterfered with by circulation of water and running of logging tool after production test.

0.7
0.6
0.5

-T (K)

0.4

6mBTMHCZ (12hrs average)
8mBTMHCZ (12hrs average)
10mBTMHCZ (12hrs average)
12mBTMHCZ (12hrs average)
14mBTMHCZ (12hrs average)
16mBTMHCZ (12hrs average)
18mBTMHCZ (12hrs average)

6 mBTMHCZ
8 mBTMHCZ
10 mBTMHCZ
12 mBTMHCZ
14 mBTMHCZ
16 mBTMHCZ
18 mBTMHCZ

0.3
0.2
0.1

0
1.0E+00-0.1

1.0E+01

1.0E+02

10

100

1000

10000

Time after Sanding event (hours)

Elapsed time (from start of pumping) t (hours)

Fig. 4 Detailed temporal change of AT1-MT1 well during flow test (left) and recovery process (right). Data
at 20 mBTMHCZ shows different trend flow from others and may indicate influx of low temperatureformation fluid from up-dip direction. (Monitoring hole was drilled in up-dip direction of producer hole.)

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0.05

0.025

0.05

Gas rate per unit interval (m3/sec/m)

0.025

Gas rate per unit interval (m3/sec/m)

Gas rate of each layer (m3/sec)

Gas rate of each layer (m3/sec)

0.04

0.02

0.04

0.03

0.015

0.03

0.015

0.02

0.01

0.02

0.01

0.01

0.005

0.01

0.005

0
0.001500.004500.001500.0045

Water rate per unit interval (m3/sec/m)

Water rate per unit interval (m3/sec/m)

Water rate of each layer (m3/sec)

0.0035

0.001

0.001

0.00050.000500.0035

Water rate of each layer (m3/sec)

0.00250.00250.00150.00150.00050.0005-0.0005-0.0005-0.001518-0.00150-0.000518-0.0005

16

16

14

14

12

12

10

10

8

8

Measured temperature (°C)
Water tempearture (J.-T.) (°C)
Gas tempearture (J.-T.) (°C)

6

6
4

4

Measured temperature (°C)
Water temperature (initial formation temperature) (°C)
Gas tempearture (base) (°C)

2

2
0

0
-5

0.02

0

5

10

15

20

25

30

35

40

-5

0

ｍTBMHCZ

5

10

15

20

25

30

35

40

ｍTBMHCZ

Fig. 5 Vertical gas and water production profiles calculated under assumption that produced gas was of MH
dissociation origin then cool, but water was mixture of original formation water with MH dissociation
origin, so slightly warm (Yamamoto et al., 2017). Image at left assumes that water temperature is originalformation temperature, and image at right assumes that water temperature depends on MH saturation,and that both water and gas temperature are under influence of Joule-Thomoson effect. In both cases,
strong water flux is expected around 20 mBTMHCZ.

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Fig. 6 Inferred phenomenological scheme of fluid motion and MH dissociation during first production test.
Middle water bearing zone must be source of water and sand. Advance of MH dissociation front was fast in
the upper zone.

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P3 production summary（5/2-15）#2 flow

5/2 16:005/3 7:30

5/3 21:105/15 11:00
Kill well start
5/15 5:05

First series sanding(5/4 4:30~5/6)

Second series
sanding 5/11 4:30

Further
depressurization

MH reassociation

ESD fault
activation

P2 production summary（5/31-6/28）#1 flow
5/31 20:306/20 23:00#2 flow#3 flow#4 flow

6/22 20:306/24 8:10

6/25 14:256/25 15:20

6/26 4:506/28 18:50

Plug of annuls
hose dismissed
Planned disconnect duetto rough weather

No further depress. due
to excess water rate andplug of an annuls hose.
Stable production under
10MPa

MH再生
MH re成による
asscoation
減圧中止

Further
depress. by
坑口圧を払うこreleasing
WHPとで減圧実施Fig. 7 Bottom-hole pressure, and gas and water rates of second production test (2017).

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Fig. 8 Temperature and fluid density measured in production wells of second production test.

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Fig. 9 Pressure and temperature data taken in monitoring boreholes of second production test. Depth isbelow mean sea level.

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Comprehensive Report of Phase 2 & 3 Research Results(1）Temperature gradient in P wells and temperature drop in MT wells(2）Density gradient in P wells and temperature drop in MT wells
Fig. 10 Pressure and temperature data taken during second offshore production test. Negative temperatureand pressure gradients indicate that something cool and low density flowed in, thus gas was produced. Suchsections correspond to temperature drop zone in MT wells.

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IV.3.3 Sample Analysis
At the time of the first and second offshore production tests, a sampling of production gas and production
water was carried out. Many kinds of sample analysis were performed. Here, we will show some analysis
results of production gas and production water when the first and second offshore production tests werecarried out.
The following figures are: “Change in chloride ion concentration of production water during first offshore
production test”, “Change in chloride ion concentration of production of P2 wells water during second
offshore production test” and “Change in chloride ion concentration of production of P3 wells water duringsecond offshore production test”.

IV.3.3.1 Summary of Production Gas Analysis
The production gas analysis was carried out to determine the composition of the gas and carbon isotope inorder to determine the origin of the gas. The sample assayed O2, N2, CO2 and the hydrocarbon(CH4-C6H14) using a gas chromatograph at the Japan Petroleum Exploration Co., Ltd.(“JAPEX”)
Research Center. The apparatus we used were a specific thermal conductivity type detector (TCD), and aflame ionization detector (FID) in GC 7,890A Valve System produced by Agilent Company. In addition,
regarding the ingredient that separated into methane, ethane, propane, isobutane, and normal butane, each
ingredient of carbon dioxide was analyzed using a gas chromatograph combustion i.w. analyzer(GC-C-IRMS). We analyzed the gas carbon isotope composition that was IsoPrime-GC) produced by GV
Instruments Company (Table 1). Measurement accuracy is +-0.2 ‰ degree.

IV.3.3.2 Summary of Production Water Analysis
We acquired measurements of drawn production water during the production test, and the analysis ofvarious elements and ions was accomplished for the purpose of handling this appropriately (Table 7). The
analysis was carried out in the laboratory of the deep drilling ship “Chikyu” managed by Marine Work
Japan (MWJ) Co., Ltd. In addition, we analyzed the production water that was refrigerated on land. As aresult of these analyses, important information about the MH reservoir of the second Atsumi Knoll,
including the chloride ion concentration abnormality of the crack water, was provided.

References
Kida M., Jin Y., Watanabe M., Konno Y., Yoneda J., Egawa K., Ito T., Nakatsuka Y., Suzuki K., Fujii T.,
Magao J., 2015, Chemical and crystallographic characterizations of natural gas hydrates recovered from a
production test site in the Eastern Nankai Trough, Marine and Petroleum Geology”, 66, 396-403.
Egawa K., Nishimura O., Izumi A., Fukami E., Jin Y., Kida M., Konno Y., Yoneda J., Ito T., Suzuki K.,
Nakatsuka Y., Nagao J., 2015, Bulk sediment mineralogy of gas hydrate reservoir at the East Nankai
offshore production test site, Marine and Petroleum Geology”, 66, 379-387.
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Marine research guidelines, Oceanographic Society of Japan, Marine Research Guidelines Editing
Committee, 2016.12, 606p, ISBN-978-4-908553-21-9

Table 1．Production Gas Measuring Equipment Specifications

Equipment

Agilent, GC 7890A Valve System
Thermal conductivity type detector(TCD)

Detector

Separation column

Flame ionization detector(FID)
Column 1 HaySepQ 80/100 Mesh 0.5mm×1/8
TCD(O2 , N2, CO2, Column 2 HaySepQ 80/100 Mesh 6ft×1/8
Separation) Column 3 Hmolecular Sive5A 60/80 Mesh 6ft×1/8
FID(CH4－C5Hl4, Column 4 HP-AL/S 25mm×0.32mm×8μm
Separation)
Column 1 20 mi/min
Column flow quantity

Column 2 25 mi/min
Column 3 25 mi/min
Column 4 1.8359 mi/min
60℃(2 min Hold), 60~80℃(15℃/min),Open
temperature program 80~190℃(20℃/min), 190℃(3min Hold9
Data processor

Agilent ChemStation

Table 2． First Offshore Production Test, Production Gas Composition Analysis
Samplenumber

Gas composition analysis value(vol.%)
n-C4

i-C5

n-C5

n-C6

CO2

GT#9
5.54 24.16 70.28 0.00 0.00 0.00 0.00
GT#24
8.01 31.94 60.00 0.00 0.00 0.00 0.00
GT#27
9.10 37.16 53.68 0.00 0.00 0.00 0.00
GT#31
20.52 79.22 0.21 0.00 0.00 0.00 0.00
GT#36-a0.31 2.14 97.48 0.00 0.00 0.00 0.00
WT#11
11.07 42.88 46.01 0.00 0.00 0.00 0.00
WT#24
11.10 43.47 45.27 0.00 0.00 0.00 0.00
WT#27
15.68 60.86 23.40 0.00 0.00 0.00 0.00
WT#31
20.72 79.02 0.20 0.00 0.00 0.00 0.00
WT#36
0.38 1.99 97.53 0.00 0.00 0.00 0.00
Wetness=(C2+C3+i-C4 +n-C4)/(C1+C2+C3+i-C4+n-C4)×100

0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00

0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00

0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00

0.03
0.05
0.06
0.06
0.06
0.04
0.16
0.06
0.06
0.10

O2

N2

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C1

C2

C3

i-C4

Wetness

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(%)
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00

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Table 3． First Offshore Production Test, Production Gas Carbon Isotope Analysis

Samplenumber
GT#9
GT#24
GT#27
GT#31
GT#36-a
WT#11
WT#24
WT#27
WT#31
WT#36

Table 4．

δ13C(‰)
C1-67.40-67.60-63.90-66.80-63.40-62.20-69.50-68.10-64.30-67.20

C2

C3

i-C4

n-C4

CO2
-6.70
-11.90-12.20-12.50-4.10-15.50-5.60-9.20-11.50-3.10

Second Offshore Production Test, Production Gas Composition Analysis (On Board)

Sample ID
Date
Time
N2
(%)
GC-TCD
O2+Ar(%)
MethaneGC-FID(%)

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Sample 5
2017/5/5
18:15

Sample 7
2017/5/6
5:00

0.4

1.1

-

-

-

0

0.22

-

-

-

100.74100.62

99.53

99.78

100.7

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Sample 15 Sample 20 Sample 27
2017/5/8
2017/5/11 2017/5/14
17:00
5:00
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Comprehensive Report of Phase 2 & 3 Research Results

Table 5． Second Offshore Production Test, Production Gas Composition Analysis
Sampleof P2 Well

Gas composition analysis value(vol.%)

Wetness

C1/(C 2+C3)i-C 4/
n-C 4

Gas
specific
gravityCalculationheat
capacity(MJ/m 3)

Date

Time

O2

N2

C1

C2

C3

i-C4

n-C4

i-C5

n-C5

n-C6

CO2

(%)

2017/6/4

5:30

0.08

0.66

99.25

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.56

39.6

2017/6/4

17:00

0.06

0.46

99.45

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.03

0.00

0.56

39.7

2017/6/5

17:00

0.07

0.37

99.47

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.09

0.00

0.56

39.7

2017/6/6

17:00

0.06

0.39

99.52

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.04

0.00

0.56

39.7

2017/6/7

17:00

0.06

0.36

99.54

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.04

0.00

0.56

39.8

2017/6/8

17:00

0.02

0.35

99.62

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.02

0.00

0.56

39.8

2017/6/9

17:00

0.06

0.40

99.51

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.04

0.00

0.56

39.7

2017/6/10

17:00

0.07

0.49

99.40

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.04

0.00

0.56

39.7

2017/6/11

17:00

0.08

0.58

99.30

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.04

0.00

0.56

39.7

2017/6/12

17:00

0.08

0.44

99.34

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.14

0.00

0.56

39.7

2017/6/13

17:00

0.08

0.50

99.31

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.11

0.00

0.56

39.7

2017/6/14

17:00

0.07

0.50

99.32

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.11

0.00

0.56

39.7

2017/6/15

17:00

0.06

0.60

99.30

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.04

0.00

0.56

39.7

2017/6/16

17:00

0.05

0.66

99.24

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.05

0.00

0.56

39.6

2017/6/17

17:00

0.04

0.69

99.22

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.05

0.00

0.56

39.6

2017/6/18

17:00

0.05

0.67

99.23

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.05

0.00

0.56

39.6

2017/6/19

17:00

0.06

0.79

99.10

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.05

0.00

0.56

39.6

2017/6/20

17:00

0.08

0.74

99.08

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.10

0.00

0.56

39.6

2017/6/23

17:00

0.05

0.52

99.42

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.02

0.00

0.56

39.7

2017/6/26

17:00

0.05

0.46

99.35

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.14

0.00

0.56

39.7

2017/6/27

17:00

0.07

0.66

99.25

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.01

0.00

0.56

39.6

Wetness=(C2+C3 +i-C4 +n-C4)/(C1+C2 +C3+i-C4+n-C4 )×100

Sampleof P3 Well

Gas composition analysis value(vol.%)

Wetness

C1/(C 2+C3)i-C 4/
n-C 4

Gas
specific
gravityCalculationheat
capacity(MJ/m 3)

Date

Time

O2

N2

C1

C2

C3

i-C4

n-C4

i-C5

n-C5

n-C6

CO2

(%)

2017/5/4

2:40

0.19

0.51

99.25

0.02

0.00

0.00

0.00

0.00

0.00

0.00

0.04

0.01

6704

0.56

39.6

2017/5/5

1:00

0.11

0.38

99.46

0.02

0.00

0.00

0.00

0.00

0.00

0.00

0.03

0.02

5871

0.56

39.7

2017/5/5

18:15

0.04

0.39

99.54

0.01

0.00

0.00

0.00

0.00

0.00

0.00

0.01

0.01

9237

0.56

39.8

2017/5/6

5:05

0.15

0.56

99.25

0.01

0.00

0.00

0.00

0.00

0.00

0.00

0.03

0.01

7602

0.56

39.6

2017/5/6

17:00

0.06

0.39

99.51

0.01

0.00

0.00

0.00

0.00

0.00

0.00

0.03

0.01

13176 1.09

0.56

39.8

2017/5/7

17:00

0.04

0.35

99.58

0.01

0.00

0.00

0.00

0.00

0.00

0.00

0.03

0.01

19314 0.89

0.56

39.8

2017/5/8

17:00

0.06

0.42

99.48

0.01

0.00

0.00

0.00

0.00

0.00

0.00

0.03

0.01

9794

0.95

0.56

39.7

2017/5/9

17:00

0.07

0.41

99.49

0.01

0.00

0.00

0.00

0.00

0.00

0.00

0.03

0.01

19421 0.82

0.56

39.7

2017/5/10

17:00

0.08

0.38

99.50

0.01

0.00

0.00

0.00

0.00

0.00

0.00

0.03

0.00

21005 0.86

0.56

39.7

2017/5/11

17:00

0.04

0.33

99.60

0.01

0.00

0.00

0.00

0.00

0.00

0.00

0.03

0.01

8805

0.97

0.56

39.8

2017/5/12

17:00

0.07

0.38

99.51

0.01

0.00

0.00

0.00

0.00

0.00

0.00

0.03

0.01

9195

0.83

0.56

39.8

2017/5/13

17:00

0.03

0.37

99.59

0.01

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.01

10207 0.95

0.56

39.8

2017/5/14

5:00

0.07

0.36

99.53

0.01

0.00

0.00

0.00

0.00

0.00

0.00

0.03

0.01

11476 0.93

0.56

39.8

2017/5/14

17:00

0.09

0.40

99.47

0.01

0.00

0.00

0.00

0.00

0.00

0.00

0.03

0.01

8447

0.84

0.56

39.7

2017/5/15

2:00

0.07

0.40

99.49

0.01

0.00

0.00

0.00

0.00

0.00

0.00

0.03

0.01

8086

0.92

0.56

39.7

Wetness=(C2+C3 +i-C4 +n-C4)/(C1+C2 +C3+i-C4+n-C4 )×100＊Bottle No.9～28：C3, i-C4, n-C4; 0.001%以下

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Table 6． Second Offshore Production Test, Production Gas Carbon Isotope Analysis
Sampleof P2 Well

Sampleof P3 Well

δ13C(‰)

Date

Time

C1

2017/6/4

5:30

-67.4

2017/6/4

17:00 -68.4-11.7

2017/6/5

17:00 -69.2-3.8

2017/6/6

17:00 -68.0-1.4

2017/6/7

17:00 -69.0-3.2

2017/6/8

17:00 -67.7

2017/6/9
2017/6/10

C2

C3

i-C4

n-C4

CO2

δ13C(‰)

Date

Time

C1

C2

2017/5/4

2:40

-69.3

-42.1

2017/5/5

1:00

-67.2

-41.3

-7.5

2017/5/5

18:15 -66.8

-42.4

-11.5

2017/5/6

5:05

-59.8

-27.3

8.8

2017/5/6

17:00 -66.6

-27.4

14.3

-17.0

2017/5/7

17:00 -65.0

-31.1

12.4

17:00 -67.3-6.2

2017/5/8

17:00 -57.5

-43.8

-1.1

17:00 -69.1-4.0

2017/5/9

17:00 -67.0

-42.4

-1.6

2017/6/11

17:00 -69.6-0.3

2017/5/10

17:00 -66.5

-38.6

1.8

2017/6/12

17:00 -68.8-0.2

2017/5/11

17:00 -66.8

-43.0

0.6

2017/6/13

17:00 -62.9-4.3

2017/5/12

17:00 -66.6

-43.3

-0.2

2017/6/14

17:00 -68.1-3.6

2017/5/13

17:00 -65.6-44.0

2017/6/15

17:00 -69.3

2.5

2017/5/14

5:00

-66.3

-43.6

-0.2

2017/6/16

17:00 -68.5

0.9

2017/5/14

17:00 -66.7

-43.5

-4.4

2017/6/17

17:00 -69.5-4.7

2017/5/15

2:00

-43.7

-3.5

2017/6/18

17:00 -68.1-1.7

2017/6/19

17:00 -67.8

1.0

2017/6/20

17:00 -69.1-4.1

2017/6/23

17:00 -68.7-9.1

2017/6/26

17:00 -69.1

0.7

2017/6/27

17:00 -68.1

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-65.8

C3

i-C4

n-C4

CO2
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Comprehensive Report of Phase 2 & 3 Research Results

Table 7．Analytical Instrument We Used In Production Water Analysis and Analysis Item
Analytical instrument

Analysis item
water temperature, dissolved O2,

Quality of the water multi-sensor

turbidity

Digital camera

photography

Conductivity meter

conductivity

Specific gravity meter

Specific gravity

pH meterpH
CODMn

Titrator

Cl-

Refractive index meter

refractive index

Discrete analyzer（DA）

PO43-, NH4+, SiO44-

Ion chromatograph - anion（IC-Anion）

NO2-, NO3-, Br-, SO42-

Ion chromatograph - cation（IC-Cation）

Na+, K+, Mg2+, Ca2+

Inductively

V, Cr, Cu, Zn, As, Rb, Mo, Cd, Cs, Hg,

coupledplasmamass

spectrometry （ICP-MS）

Pb, U

Inductively coupled plasma atomic

Li, B, Si, Mn, Fe, Sr, Ba

emission spectroscopy（ICP-AES）
Gas chromatograph-thermal conductivity

N2, O2detector（GC-TCD）

Table 8． First Offshore Production Test, Production Water Analysis (On Board)sample name

The collection
date and timepHconcentration (mg/L)

EC(mS/cm)

Na+

K+

Ca2+

Mg2+

Li-

Sr

MH4+

Fe

Al

Si

Gas Train Water sample No.6

2013/3/13

0:00

7.85

43.9

11500

355

225

755

0.13

5.4

145

2.0

ND

15.0

Gas Train Water sample No.7

2013/3/13

7:00

7.90

43.6

11600

358

211

723

0.14

5.5

156

2.8

ND

16.1

Gas Train Water sample No.8

2013/3/14

0:00

8.00

44.0

11700

361

187

732

0.14

5.8

177

ND

ND

16.1

Gas Train Water sample No.9

2013/3/14 19:00

8.01

44.1

11700

364

179

730

0.14

6.2

174

ND

ND

16.2

Gas Train Water sample No.10

2013/3/15

1:00

8.06

44.3

11700

367

179

731

0.15

6.5

180

ND

ND

15.9

Gas Train Water sample No.11

2013/3/15

0:00

8.24

44.0

11700

363

171

731

0.14

6.1

180

ND

ND

15.1

sample nameisotopic
composition(‰)

concentration (mg/L)

The collection
date and time
B

Cl-

Br-

I-

SO42- HCO3- CO32-

TDS

DOC

δD

δ18O

Gas Train Water sample No.6

2013/3/13

0:00

4.8

20100

85.1

43.1

350.0

804

2.3

36730

82

-19

2.0

Gas Train Water sample No.7

2013/3/13

7:00

4.6

20300

85.6

45.1

240.0

832

2.4

36790

85

-11

-0.3

Gas Train Water sample No.8

2013/3/14

0:00

4.4

20600

88.8

44.8

94.0

848

3.1

37880

59

-9

2.0

Gas Train Water sample No.9

2013/3/14 19:00

4.3

20600

90.0

45.7

52.0

896

3.3

37350

49

-14

-0.3

Gas Train Water sample No.10

2013/3/15

1:00

4.3

20700

90.5

45.2

45.0

839

3.9

38330

61

-13

0.5

Gas Train Water sample No.11

2013/3/15

0:00

4.3

20700

93.2

45.2

22.0

851

5.0

37760

53

-9

0.8

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Fig. 1．Change in chloride ion concentration of production water of first offshore production test

Fig. 2．Change in chloride ion concentration of production of P2 wells water of second offshore
production test

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Fig. 3. Change in chloride ion concentration of production of P3 wells water of second offshore
production test

Ⅳ.4 Major Findings from the Two Offshore Production Tests
The offshore production tests conducted in Phase 2 and 3 had two major objectives. One was atechnical objective to realize the depressurized condition for a certain duration in a deepwater
well. The other was to gain an understanding of reservoir responses to depressurized
conditions. This section presents major achievements, findings, and remaining issues.
(1) Technical Issues
According to the fact that a total 36 days of depressurization was conducted during thesecond test, technologies that can realize a few months of continuous depressurization
operations are supposed to be ready.
① Stability and Sustainability of the Operation
Both tests (the first test in 2013 and the second test in 2017) were conducted using D/VChikyu, a Dynamic Positioning System (DPS) vessel. Because the production system using adrilling riser system and blow-out preventer (BOP) during the first test could allow a
relatively small operation circle (r<14m), and due to the fact that we experienced difficultyreconnecting after the emergency disconnect sequence (EDS) was activated, an improved
system featuring a workover riser was designed and implemented. The implemented systemenabled a larger operation circle (r<30m) that drastically reduced the probability of EDS andcapacity for reconnection. As a result, a total of 36 days of flow duration with borehole
switching (from AT1-P3 to AT1-P2) and a planned disconnect operation were carried out, anda few months of continuous production was carried out during calm weather between April
and June.
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However, if it becomes necessary to ensure a flow over a period of several months, and inparticular, if operations are required to be carried out during the typhoon season, the vessel
should be moored. In such a case, mooring techniques considering subsea soil condition andinterference with existing subsea communication cables should be employed.
② Sand Control System
Severe sand problems were encountered during the first test and the first well (AT1-P3) of thesecond test. However, despite high water and gas production rates, AT1-P2 well operation wascompleted without sand being produced. Moreover, it is believed to be likely that the AT1-P3
problem was not caused by a malfunction of the sand control device itself but by anotherelement of the borehole taking into account various data and indications. Therefore, the sandcontrol system used during the second test in 2017 was fully functional.
On the other hand, experience gained from two sand production events revealed the fact that
MH bearing sediments are easily slurified after dissociation and tend to flow continuously
into any weak point of the system. From another viewpoint, it is speculated that the relatively
poor productivity of the AT1-P3 well may be influenced by the sand control device (a largepressure drop across the device may occur), and it is necessary to clarify the situation andimprove the system.
③ Downhole Device Design
The downhole system employed during the second test effectively worked, although some
unexpected situations such as sand production occurred. The degree of the drawdown in
AT1-P2 did not reach the target, however, the main reason behind the failure was not asystem design problem but inappropriate prediction of the water rate. The gas/water
separation problem that occurred in the AT-P well (2013) was solved in the AT1-P3 well inwhich water and gas production rates were within the assumed basis of design. The problem
occurred again in the AT1-P2 well, however, the main reason was also the excess water rate.
The AT1-P2 well operation encountered several instances of flow assurance problems due toMH re-association in the flow line, and this was a direct consequence of the insufficient degreeof drawdown (pressure in the low temperature zone around the sea floor was kept within theboundaries of the hydrate stability conditions).
Such flow assurance issues and how to design the production device based on the prediction of
production rates with low certainty will be remaining issues, and continuous studies arenecessary.
④ Other Achievements and Remaining Issues
Well construction operations in shallow sections below deepwater, including casing andMH21 Research Consortium

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cementing of the boreholes, were successfully carried out without zonal isolation problems
occurring (water influx from seafloor, leakage of produced gas to the seafloor, etc.).
Meanwhile, boreholes drilled during the first test had higher deviation angles than planned,
which made it difficult to align production and monitoring boreholes. The problem was solved
during the second test (2017) by using a rotary steerable drilling system by which verticalboreholes were drilled, however, a hole enlargement problem was surfaced. The enlarged holemight affect the isolation of water-bearing zones. The design of the production hole followed
the safety standard for conventional petroleum wells, however, by considering the lowpressure nature of gas hydrate operations, the design could be simplified, and there should bea room to reduce costs.
Several technical issues of the on-board production systems surfaced during the operationsuch as handling of the flare burner and the surface production system in combination withship control, precision and reliability of production rate measurement, precise control of flowrate and pressure, continuation of the operating under unexpected conditions such as sandproduction, etc., however, these issues were mitigated through ship-board discussion and byimproving devices and/or operations. This experience must be utilized in order to improvesystem design in the future.
The produced water from AT1-P and AT1-P3 could be disposed of at sea in accordance with theWater Pollution Controlling Act, however, water from AT1-P2 that was contained MH
inhibitor and GeoFORM activation fluid was transported to shore for treatment. In the latter
case, cost of water treatment may become an issue.
During the production test, the laboratory facility on the D/V Chikyu was effectively utilized
to quickly analyze produced water and sand, and such analyses contributed to thecontinuation of the operation.
(2) Reservoir Responses
The gas production rate from each well was almost stable. In particular, the 24 day-longoperation of the AT1-P2 well could produce data/information about reservoir responses todifferent degrees of drawdown from producer and monitoring boreholes. Such data are quite
valuable in terms of improving reliability of predictions of long-term gas production. On theother hand, there were some discrepancies between model-predicted behaviors and reality.
Some significant discrepancies are listed below:① Different Production Behavior between Wells
It was discovered that there is a large variation in production behavior (gas and water rates tothe degree of drawdown, and their vertical profiles) between three producer wells. There arethree possible causes for this:
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Those wells are drilled within a 50 m radius and the geological and sedimentological settings
are similar, however, a certain degree of hydrate concentration conditions and water bearingzones may exist. Such variety could cause differences in production behaviors.
b. Difference of borehole condition
Three boreholes each had specific sand control devices that could influence production
behavior. Their effects on production had been investigated prior to the tests, however, theactual drilling conditions, such as hole enlargement, type of treatment fluid used to set thedevices, etc., differed somewhat from the assumption, could change the situation, and may
have a negative or positive effect as a result of a pressure drop across the devices or some wellstimulation effect caused by chemical fluid used for GeoFORMTM activation.
In particular, the possibility cannot be ruled out that relatively poor production rates from theshallow section of the AT1-P3 well were caused by the sand control device.
c. Different production conditions
Different rates of drawdown (quick drawdown in AT1-P and P3 vs slow drawdown in AT1-P2)
may affect the formation around wells differently as a result of mechanical processes.
A combination of the above may be the cause, however, the latter two factors are related to apressure drop across the near wellbore region (positive or negative skin) and technicalresolutions of them can be found. Furthermore, they may provide clues in how to improve
productivity.

② Different productivity between reality and model-predicted
The most substantial difference between the model-predicted production behavior and theactual production behavior was the fact that a gradual increase in gas production rates was
not observed in any borehole. The possible causes of this can be categorized into reservoir
scale, and the near-wellbore phenomenon.
a. Reservoir scale phenomenon
Anisotropy and Heterogeneity of Formations
Numerical simulators cannot fully model the various scales of heterogeneity in an actual
reservoir. The elements that are not reflected in the numerical model, such as heterogeneity
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and anisotropy in geological structure, hydrate occurrence, existence of water-bearing zones,
fluid conduit, hydraulic discontinuity, etc., should affect actual production behavior. Eachdata for reservoir characterization, such as seismic survey, geophysical logging, core samples
and in-situ testing, etc., has its own scale and limitation on information. It is necessary tointegrate this information in order to interpret the obtained data.
Physical Process and Material Properties
In the case of the MH reservoir, many parameters such as hydraulic (permeability, etc.),
thermal (thermal conductivity, etc.) and mechanical parameters (strength and elasticity, etc.)
are affected by MH dissociation and pore fluid exchange, and other factors. Some physicaltheories employed during implementation of the model cannot sufficiently reflect the actual
real-word status. Laboratory testing of cores should be combined with field data to improveunderstanding of physical processes.
Thermodynamic Processes
The monitoring data in the production test highlighted the motion of pressure andtemperature conditions along the phase equilibrium curve, which meant a few percent pointsof MH gas in pore spaces was dissociated. However, comparing the modeling result with 2013
test data suggested that the heat was not sufficiently supplied to the MH around the sensor
locations (Yamamoto et al., 2017).
b. Near wellbore situation
As described in ① b., the skin factor (pressure reduction across the near wellbore region due
to fine migration, compaction, issues involving sand control devices, non-Darcy flow ofgas-liquid mixed phase flow) may develop with time. If these phenomena are the main reason
behind the model-reality discrepancy, the situation can be improved by implementing
techniques such as hydraulic fracturing, acid treatment, etc.
(3) Conclusion
The two offshore gas production tests carried out in the Eastern Nankai Trough proved thatthe depressurization operation in a deepwater well and subsequent gas production from thewell is possible. Although adequate information was not obtained during the first test (2013)
due to a flow that was shortened by sanding, 36 days of flow were realized during the second
test (2017) after the design of the systems was improved, and a large amount of data was
obtained from producer and monitoring boreholes. This data contributed to understanding thelong-term behavior of MH dissociation and gas production.
Meanwhile, the obtained data highlighted discrepancies between the model-predicted
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reservoir behavior and the actual response, and causes of those discrepancies should be
investigated in order to improve reliability of the long-term production prediction andevaluate economics of the production more precisely, and also to clarify further R&D subjects
to enable commercial production.
The data obtained in the tests gave us the information about temporal and spatial advances ofhydrate dissociation, and we can make the stage of the study from theory and model based
deductive one to the reality based inductive one.
The obtained data showed the complexity of real reservoirs and physical processes in thereservoir, and it is important to identify technical issues to be solved through the analyses of
those data and to examine relevant countermeasures.

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IV. 5 Study of Long-term Onshore Gas Hydrate Production Testing(1) Introduction
Japan's methane hydrate (MH) resources exist below the deep-sea floor, while MH also exists underneathonshore permafrost in high latitude regions. The onshore MH fields have been utilized effectively for R&D
primarily because the physical properties of onshore MH are similar to those of MH below the ocean floor,
and easier access to the site makes data acquisition more economical.
The first onshore gas hydrate production test was conducted at the Mallik site, Canada, in 2002. It was theworld’s first gas production test from a MH reservoir using the hot water circulation method, and also
provided clues that the depressurization method could be more feasible. The second test at the same placein 2007-2008 saw successful continuation of production using the depressurization method, leading to thedecision to attempt offshore production tests in Japan. In addition, the CO2/CH4 exchange method andsubsequent depressurization method were tested at the Prudhoe Bay Unit, Alaska, USA in 2012. This test
demonstrated that carbon dioxide could be exchanged in-situ with methane molecules (Schoderbek et al.,2013). In this way, the data and information acquired by these onshore production tests have significantly
contributed to the progress of Japan’s MH research and development.
Although it was confirmed that gas can be produced from offshore MH reservoirs by using thedepressurization method in production tests in 2013 and 2017 (see IV.1 and IV.2), it is necessary tounderstand the gas production behavior on an annual basis in order to establish reliable production methods.
However, offshore production test facilities should be almost equivalent to permanent facilities in the caseof production testing carried out throughout the year in such a severe marine environment as that around
Japan, and taking into account the considerable budget that would be required for mid- or long-term
production testing offshore.
Considering the above, and in order to proceed with MH R&D efforts in a reasonable and effective manner,
the onshore production test is recognized as an effective way to understand the long-term production
behavior before conducting mid- or long-term production tests off the coast of Japan.
On the other hand, the United States has also attempted long-term onshore production tests in Alaska(Collett and Boswell, 2009), and Japan and the U.S. have made ongoing efforts to determine a suitablelocation for long-term production test where existing infrastructure, such as permanent access roads, isavailable, in order to realize feasible and operable production test.

(2) Contents and Resultsa. MOU for collaborations towards long-term production test in Alaska
The Memorandum of Understanding (MOU) for collaborations towards long-term production test in Alaska
was signed on November 6, 2014, between JOGMEC and the National Energy Technology Laboratory(NETL), a U.S. Department of Energy (DOE) national laboratory.
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Based on this MOU, the study had started to implement testing in a step-by-step manner as part of aninternational cooperative research and development program involving JOGMEC, NETL and the U.S.
Geological Survey (USGS).
 Phase 1:

Candidate sites screening and prioritization, preliminary planning of stratigraphic test

well (STW), etc.
 Phase 2:

Site Selection, overall planning and implementation, etc.

 Phase 3:

Long-term production test implementation and data acquisition, etc.

 Phase 4:

Post-production test analysis and interpretation, plug and abandonment, etc.

b. Phase 1
Three-dimensional seismic data for the area of set-aside-acreage (designated by State of Alaska) was
purchased, analyzed and interpreted, and geological interpretation work was conducted by utilizing 11 log
data provided by the USGS and mud log data, in order to identify candidate sites from the broad areas
within North Slope. Based on these efforts, candidate sites were selected and prioritized. In addition,
preliminary reservoir simulation models of each candidate site, based on available information andassumptions, were developed to forecast gas and water production profiles, and sensitivity analysis was
conducted considering uncertainties of candidate sites.
In October 2015, a workshop was organized involving NETL, USGS, JOGMEC and Japan’s National
Institute of Advanced Industrial Science and Technology (AIST), in order to discuss and agree objectives of
production testing, and outline of data items to be acquired.
Attending parties reached a consensus that the objectives of production tests would be to achieve
production for as long a period as possible with a target of one year or longer using the depressurization
method in order to understand the long-term response of MH reservoir during production. It was also
agreed that application of enhanced recovery method(s) at the late stage of production would be included in
the implementation plan.
JOGMEC intended to utilize its knowledge and experience obtained through both onshore and offshore
production tests as well as vast amounts of studies performed so far, to contribute to the successful
implementation of the production test, and continued its efforts in the areas of research and development.
Further efforts include studies of sand control, artificial lift, downhole monitoring technology, and welldesign, to develop fit-for-purpose and feasible production technologies.
After the discussions between the U.S. members and JOGMEC about data acquisition items required tounderstand reservoir properties and reservoir behavior with MH dissociation, it was decided to begin
studies and development of new technologies such as downhole sand detection technology with opticalfiber acoustic measurement (Distributed Acoustic Sensing, DAS), Vertical Seismic Profile (VSP) using
DAS, and reservoir deformation detection and measurement technology with optical fiber strain
measurement (Distributed Strain Sensing, DSS), in addition to conventional logging, coring, downhole
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temperature and pressure sensing.

c. Phase 2
Kuparuk State 7-11-12 (Fig. 1), Prudhoe Bay Unit was selected as a promising candidate site based on the
Phase 1 study result, because the existence of MH was confirmed by a near-by well, which meant its
geological risk was relatively low, and temperature relatively high, which is suitable for the
depressurization method. In addition, the site has an existing gravel pad and permanent access roads, whichallow surface activities to be carried out, even during swampy summers. Then the specific target point wasdetermined taking into account the estimated MH distribution and distance to main faults. However, theavailable log data is insufficient to estimate MH existence and reservoir properties. Therefore, it was
decided to drill an exploratory well (STW), and started to develop the implementation plan.
It was presumed that multiple MH sand layers existed below the permafrost around the selected area. The
main target would be B sand where the temperature is relatively high (850 mMSL, 8.5 MPa, 10 °C), and D
sand would also be considered as a candidate testing reservoir (700 mMSL, 7.0 MPa, 5 °C). The
approximate depths are quoted from R. Boswell (2016), the pressures are estimated based on K. A. Lewis etal. (2013) and M. E. Torres et al. (2011), and the temperatures are estimated using the data provided by T. S.
Collett, USGS.
After the technical studies and operator selection, etc., the STW was drilled in December 2018. The
acquired log data and pressure-retained sidewall cores are being analyzed by both Japan and the U.S.
In case this site is judged to be suitable for long-term production testing, it is planned that an additional two
wells, a geo-data well (GDW, for obtaining detailed reservoir information by coring, etc., and downhole
sensors are to be deployed) and a production test well (PTW) will be drilled.
It is also planned that the STW and the GDW will be converted to monitoring wells, and that all the threewells would be deviated wells with inclination angles of less than 30°.
JOGMEC is conducting planning work for system development of production testing, with support from
Toyo Engineering Corporation (TOYO). This work includes preparing drafts for well completions, carryingout studies of monitoring equipment, sand control equipment, artificial lift considering the deep
depressurization method, and combinations of bottomhole equipment in consideration of capabilities to test
two sand layers separately and implement optimized workovers. Fig. 2 shows the assumed wells and themonitoring equipment arrangements.
Investigation of currently available technologies and experiments regarding downhole monitoring
equipment are ongoing. Joint research is conducted with the University of California, Barkley for DSS, andsome experiments are performed and studied including feasibility study of sand detection utilizing DAS.
A preliminary reservoir simulation model has been developed for the selected testing site in order todetermine the appropriate distance between the production well and monitoring wells where reservoir
response is likely to be detected within the production test period, and also to forecast gas and waterproduction profiles based on the depressurization method.
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In addition the above, DAS-VSP was conducted in March 2019, by utilizing distributed acoustic sensing
fiber optic cable as receiver, which was deployed at STW(3) Conclusion
Based on the MOU concluded between JOGMEC and NETL in November 2014, Japan and the U.S.
collaboratively conducted technical studies, candidate sites screening and prioritization, selection of testing
site, planning of stratigraphic test well and preparation work for field activities, and then completed
stratigraphic test well drilling.
In the case both Japan and the U.S. decide to conduct long-term onshore production test based on theanalysis of STW data and related information, a detailed implementation plan would be developed
accordingly
The acquired data and outcomes from various efforts to date should be effectively utilized for Japan’s MH
research and development, including future assessment of MH resources off the coast of Japan, and thedevelopment of production methods/ technologies.

Fig.1: Location of the testing candidate site, Kuparuk State 7-11-12
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Fig.2: Assumed wells and the monitoring equipment arrangements(R. Boswell, US DOE Methane hydrate advisory committee meeting, October 18-19, 2018,https://www.energy.gov/sites/prod/files/2018/11/f57/MHAC_Alaska%20Project%20Update%20Final.pdf)

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Citations and References[1] D. Schoderbek, H. Farrell, K. Hester, J. Howard, K. Raterman, S. Silpngarmlert, K. L. Martin, B. Smith, andP. Klein, ConocoPhillips Gas Hydrate Production Test Final Technical Report, October 1, 2008–June 30,
2013, DOE Award No.: DE-NT0006553.

[2] Collett, T., and Boswell, R. (2009): The Identification of Sites for Extended-term Gas Hydrate Reservoir
Testing on the Alaska North Slope, Fire in the Ice, NETL Methane Hydrate Newsletter, 9(2), 12-16.

[3] Boswell, R. (2016): US DOE Methane hydrate advisory committee meeting, Major Projects Update
Presentation, October 19, 2016[4] Kristen A. Lewis and Timothy S. Collett, Brookian Sequence Well Log Correlation Sections and Occurrenceof Gas Hydrates, North-Central North Slope, Alaska, U.S. Geological Survey Scientific Investigations
Report 2013–5050[5] M.E. Torres, T.S. Collett, K.K. Rose, J.C. Sample, W.F. Agena, E.J. Rosenbaum, Pore fluid geochemistryfrom the Mount Elbert Gas Hydrate Stratigraphic Test Well, Alaska North Slope, Marine and Petroleum
Geology 28 (2011) 332–342

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