ANALYSIS OF 2007/2008 JOGMEC/NRCAN/AURORA MALLIK GAS HYDRATE

ANALYSIS OF 2007/2008 JOGMEC/NRCAN/AURORA MALLIK GAS HYDRATE PRODUCTION TEST THROUGH NUMERICAL SIMULATION

Masanori Kurihara∗ Japan Oil Engineering Company

1-7-3 Kachidoki, Chuo-ku, Tokyo, 104-0054, Japan (at present, Department of Resources and Environmental Engineering, Waseda University)

Kunihiro Funatsu, Hisanao Ouchi and Akihiko Sato (Japan Oil Engineering Company)

Masato Yasuda, Koji Yamamoto and Tetsuya Fujii (Japan Oil, Gas and Metals National Corporation)

Masaaki Numasawa (Japan Petroleum Exploration Company)

Hideo Narita (National Institute of Advanced Industrial Science and Technology)

Yoshihiro Masuda (The University of Tokyo)

Scott R. Dallimore and Fred Wright

(Geological Survey of Canada, Natural Resources Canada)

ABSTRACT Methane hydrate (MH) production tests were conducted using the depressurization method in the Mallik production program in April 2007 and in Mach 2008. In addition to attaining the first and the only successful methane gas production to the surface from a MH reservoir in the world, various data were obtained. The results of the production test were analyzed using a numerical simulator (MH21-HYDRES). This paper evaluates these test results through the analyses of production test data, numerical modeling and a series of history matching simulations. In 2007, a certain amount of gas and water were produced from a 12 m perforation interval in one of the major MH reservoirs at the Mallik site in Canada, by reducing the bottomhole pressure down to about 7 MPa. However, because of the irregular pumping operations, the produced gas was not directly delivered to the surface via the tubing, but was accumulated at the top of the casing. In 2008, much larger and longer gas production was accomplished with a stepwise reduction of the bottomhole pressure down to about 4.5 MPa, resulting in the gas and water produced to the surface. The flow rates of gas and water from the reservoir sand face in these tests were estimated by the comprehensive analysis of the continuously monitored data. The test results were then analyzed using MH21-HYDRES. The reservoir model was tuned through history matching so as to reproduce the flow rates of gas and water estimated in the above, not only by simply adjusting reservoir parameters, but by introducing the concept of the improvement/reduction of near-wellbore permeability reflecting the creation/deformation of high permeability zones associated

∗ Corresponding author: Phone: Phone: +81 3 5286 2697 Fax: +81 3 5286 3491 Email: [email protected]

Proceedings of the 7th International Conference on Gas Hydrates (ICGH 2011), Edinburgh, Scotland, United Kingdom, July 17-21, 2011.

with the sand production. This series of history matching simulation studies clarified the mechanisms of MH dissociation and production during the tests.

Keywords: methane hydrates, production test, numerical simulation, history matching

NOMENCLATURE A cross sectional area [L2] D depth [L] g gravity acceleration [L/t2] G accumulated gas volume [L3] k absolute permeability [L2]

*k effective permeability to single flowing phase in the presence of methane hydrate [L2]

ek effective permeability [L2]

rk relative permeability N permeability reduction exponent p pressure [M/Lt2] q production rate [L3/t] Q cumulative production [L3] r radius [L] S phase saturation t time [t] T temperature [T] V volume content W water volume in annulus [L3] x fraction of high permeability part z gas compressibility factor γ pressure gradient [M/L2t2] ρ phase density [M/L3] φ porosity Superscript: ~ average Subscript: an annulus B mid-perforation interval ch casing head e effective f fluid

fv− for calculation of fluid (gas and water) volumes

g gas phase h methane hydrate phase hp high permeability conduit

)(i (i)th time level l liquid phase m memory gauge

NMR− NMR log

o original ph phoenix gauge s standard condition sh shale

surface− measured at surface t total w water phase wp pumped water INTRODUCTION At Mallik site located in Mackenzie Delta, Northwest Territories of Canada, the 1998 JAPEX /JNOC/GSC Mallik 2L research well program was conducted in 1998, in which the research well 2L-38 was drilled through MH reservoirs and a variety of engineering data including the well log data and the first permafrost MH core samples were collected [1]. In 2002, JAPEX/JNOC/GSC et al. Mallik 5L-38 gas hydrate production research well program was conducted. In this program, the 124 hour thermal stimulation test was performed at another research well 5L-38 along with 2 monitoring wells of 3L-38 and 4L-38, accomplishing the production of 468 m3 of total gas from one of the MH reservoirs by hot water circulation for the first time in the world [2]. Furthermore, 6 pressure drawdown tests were conducted using Schlumberger’s Modular Formation Dynamics Tester™ (MDT) wireline tool at this well [3], the results of which showed the promise of much more gas production from MH reservoirs at this site by the depressurization method [4, 5, 6]. In response to the results of the above tests at the 5L-38 well, the 2006-08 JOGMEC/NRCan/Aurora Mallik gas hydrate production research program was conducted with a central goal to measure and monitor the production response of a terrestrial gas hydrate deposit to pressure drawdown (depressurization). The Japan Oil, Gas and Metals National Corporation (JOGMEC) and Natural Resources Canada (NRCan) funded the program and lead the research and development studies. Aurora College/Aurora Research Institute was acting as the operator for the field program. Since this site was accessed by ice roads that are

available only in the winter season, the production test was conducted in two winter seasons of the years 2007 and 2008. In 2007, the production well was completed in the Zone A MH reservoir by re-entry of the 2L-38 well followed by the short term production test only for about 1.5 days. On the other hand in 2008, the longer term production test was attained for about 6 days, resulting in the world first sustainable gas production to the surface from the MH reservoir by depressurization [7]. The gas and water production from the reservoir during the 2007/2008 production test is estimated in this paper. This paper, then, describes the details of the history matching simulation studies conducted to reproduce the test performances and infers the reservoir behaviors during the test from results of these studies. Complimentary papers are also published describing operations [8], well log characteristics [9], geophysical monitoring techniques employed [10] and production behavior [11, 12, 13]. OVERVIEW OF THE PRODUCTION TESTS 2007 winter test After the re-entry and the re-completion of the Mallik 2L-38 well with the 12 m perforation interval (1,093-1,105 m RKB), the pumping test was commenced at about 16:00 (local time) on April 2nd in 2007. This test, however, could last only for about 60 hours (about 30 hours for main production with 3 times attempts (Stages-1 through -3) to reduce the bottomhole pressure), because of the irregular (on-off) pumping operations due probably to the excessive sand production. The produced gas was not directly delivered to the surface via the tubing, but was accumulated at the top of the casing, while the produced water was injected into the aquifer located below the MH reservoir. Hence, neither the gas production rate nor the water production rate could be directly measured at the surface. During the production (pumping) operation, the bottomhole pressure and temperature were measured at the phoenix gauge (1,124 m: adjacent to the pump intake) and 4 memory gauges (1,091 m) as illustrated in Figure 1. In addition, the pressure at the outlet of the pump (discharged pressure), the temperature of the motor of the pump and the casing head pressure (i.e., pressure

of the annulus between casing and tubing) were measured as depicted in Figure 2, the details of which are presented in our previous papers [11, 12, 13]. The well was then suspended installing cement and bridge plugs toward the field activities in the winter of 2008.

20" 94#/ft J55 @ 103 m

2 7/8" EUE, N80 Tbg

5 Mpa @ +/- 581 m

Permafrost depth @ +/- 640 m Perforated Joint @ 649m

4 Mpa @ +/- 682 m 13 3/8" 61#/ft, J55 @ 677 m

3 Mpa @ +/- 783 mESP cable w/ chemical iny # 4CTS cable back-up ESP sensor

ESP cable Splice with Chemical inj @1089mAnular Gauge Carrier bottom @ 1091m

A Zone @ 1093 - 1105 mChem inj point ESP cable @1106m

Phoenix gauge @ 1124m

Pump Intake @ 1129m

Pump Shroud 1127m to 1136m

Check Valve @ 1139mCTS Gauge Carrier @ 1141m

Safety Shear Joint @ 1143mChemical Inj Sand Detection @1153m

Locator w/seal assembly @ 1211 mModel S packer @ 1211 mModel S packer @ 1218 mInyection zone @ 1224-1230 / 1238-1256 / 1270-1275 m2.313" Landing SXN nipple @ 1240 mModel B Shear Plug @ 1238m

FC @ 1275 m

Shoe 9 5/8" 40#/ft, J55 @ 1288 m Figure 1 Downhole assemblies for 2007 winter

test

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）Casing Head PressureMemory Gauge PressurePhoenix Gauge PressureDischarge PressureStart PumpingPlug Off PointsShut Down PumpMemory Gauge TemperaturePhoenix Gauge TemperatureMotor Temperature

#1 #2 #3Start pump

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Figure 2 Pressure and temperature measured in

2007 winter test 2008 winter test After re-opening and re-completing the 2L-38 well, including the installation of the sand screen at the perforation interval as illustrated in Figure 3, and heating the bottomhole for about 10 hours, the pumping test was commenced at about 18:00 (Greenwich Mean Time) on March 10th in 2008.

First, the bottomhole pressure was reduced from the initial pressure of about 11 MPa to about 7.4 MPa taking about 12 hours. The bottomhole pressure was kept to be almost constant for 39 hours (Stage-1). Spending another 6 hours, the bottomhole pressure was lowered down to about 5.2 MPa, which was maintained for 59 hours (Stage-2). In the last stage (Stage-3), the bottomhole pressure was reduced down to about 4.5 MPa spending 4 hours and was kept at this level for 24 hours. Much larger and longer gas production was accomplished with this stepwise reduction of the bottomhole pressure, preventing sands from flowing into the wellbore by the screen. In this test, both the gas and water were delivered to the surface. The gas and water flow rates were metered at the surface, mainly at 2,000-3,000 m3/d and at 10-20 m3/d, respectively. In addition, the bottomhole pressure and temperature were monitored at the phoenix gauge (822 m: adjacent to the pump intake), CTS gauge (798 m) and 4 memory gauges (1,083 m), and the casing head pressure was also measured (Figure 4).

20" 94#/ft J55 @ 103 m8 Mpa @ +/- 283 m6 Mpa @ +/- 485 m5 Mpa @ +/- 581 m 2 7/8" EUE, L80 Tbg

Permafrost depth @ +/- 640 m 13 3/8" 61#/ft, J55 @ 677 m4 Mpa @ +/- 688 m

ESP cable w/ chemical inj # 4CTS cable (back-up ESP sensor)Downhole Heater #4 cable NO CHEMICAL INJBleeder Valve @ 683m

Bleeder Valve @ 739m

Bleeder Valve w/STOP @ 795m

CTS Gauge Carrier @ +/-798m

3 Mpa @ +/- 789 mChem Injec Splice (injection point @ 811m)

Pump Intake @ 811m

Phoenix gauge @ +/-822m

Downhole Heater @ +/-825 to 837m

Anular Gauge Carrier bottom @ 1083mLB Permanent packer (top @ 1083m)

Mesh-Rite Sand Control Screens

A Zone @ 1093 - 1105 m

LB Permanent packer (top @ 1110m)

Cement plug @ 1194mBridge Plug @ 1202m

Model S packer @ 1211 mModel S packer @ 1218 m

2.313" Landing SXN nipple @ 1240 mModel B Shear Plug @ 1238m (sheared)

FC @ 1275 m

Shoe 9 5/8" 40#/ft, J55 @ 1288 m

Injection zone @ 1224-1230/1238-1256/1270-1274 m

Figure 3 Downhole assemblies for 2008 winter

test

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Figure 4 Pressure and temperature measured in

2008 winter test ESTIMATION OF GAS AND WATER PRODUCTION FROM RESERVOIR Since neither gas production rate nor water production rate was directly measured at the surface in the 2007 winter test, there is no direct information available about how much gas and water flowed from the reservoir. On the other hand in the 2008 winter test, although both gas and water production rates were directly measured at the surface, these rates must be different from those flowing from the reservoir because of the accumulation of gas and water in the wellbore. Analyzing the data acquired, the volumes of gas and water produced from the reservoir were estimated taking account of the change in the pressure and of the gas-water mass balance in the wellbore. Since the detailed calculation for these production volumes are introduced in our previous paper [11, 12, 13], only the calculation procedure and the results are presented below. 2007 winter test Estimation of liquid level The depth of the interface between the liquid and the gas accumulated at the top of the casing ( lD ) was estimated based on the casing head pressure ( chp ), the depth of the phoenix gauge ( phD ) and the bottomhole pressure measured at this gauge ( php ) as

gpp

DDl

chphphl ρ

−−= . (1)

Note that this liquid level was calculated to check the gas volume existing in the annulus above the phoenix gauge. Estimation of gas production Once the liquid level is estimated as describe in the above, the cumulative gas production ( )(igQ ), which is accumulated at the top of the casing, can be calculated at each time ( )(it ) in accordance with the gas deviation factor ( z ), the temperature of the upper part of the casing (T : 273.15 K in this test) and the cross sectional area of the annulus between casing and tubing ( anA : 0.035 m2 in this test) as

TT

zppDAQ s

s

chlanig =)( . (2)

Then the gas production rate at each time ( )(igq ) can be estimated by differentiating )(igQ as

)1()(

)1()()()(

−

−

−−

≈=ii

igigigig tt

QQdt

dQq . (3)

The gas production rate and the cumulative gas production thus estimated are shown in Figure 5. When the bottomhole pressure was reduced from 11 MPa to 7.2-7.5 MPa, 1,000-2,000 m3/d of sustainable gas production was achieved. Furthermore, the instantaneous gas production of about 8,000 m3/d was observed when the bottomhole pressure was decreased to 6.9 MPa. Total gas production throughout the 2007 winter test period is estimated at about 830 m3.

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Shut Down Pump, #2

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pumping period #3 = 830 m3

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Figure 5 Estimated gas production from reservoir

in 2007 winter test

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Figure 6 Estimated water production from

reservoir in 2007 winter test Estimation of water production First, the water production volume was estimated based on the pumping rate simply calculated from the number of revolution and inlet-outlet pressure difference of the pump, assuming the 100% of pumping efficiency. In this case, the volume of the liquid ( )(iW ) existing above the phoenix gauge at each time can be calculated as

( )lphani DDAW −=)( . (4) The rate of the water produced from the reservoir ( )(iwq ) can be estimated as the summation of the pumping rate ( )(iwpq ) and the rate of increase in

( )iW .

)1()(

)1()()()(

−

−

−

−+≈

ii

iiiwpiw tt

WWqq . (5)

The cumulative water production is then calculated integrating ( )iwq .

( ))1()()()1()( −− −+≈ iiiwiwiw ttqQQ . (6) The water production volume calculated in the above must be overestimated because the pumping efficiency was assumed to be 100%, even during the period of suspected plugging of the pump. Hence, the water production volume and pumping rate thus calculated were tuned through history matching simulation using the radial numerical model replicating the wellbore, in order to estimate the actual water production volume and the actual pumping rate more accurately [11, 12, 13]. The adjusted estimate of water production

rate was then yielded as shown in Figure 6. The water production rate from the reservoir ranged from 0 to 80 m3/d and that the total water production throughout the test period was approximately 20 m3. 2008 winter test Estimation of liquid level The liquid level ( lD ) was simply calculated from the depth of the phoenix gauge ( phD ), casing head pressure ( chp ), phoenix gauge pressure ( php ) and the liquid

density ( lρ ) as

gpp

DDl

chphphl ρ

−−= . (7)

Estimation of bottomhole pressure The bottomhole pressure ( Bp ) was estimated assuming that the pressure gradient of the fluid ( fγ ) located between

the memory gauge depth ( mD ) and the mid-perforation depth ( BD ) was identical to that between the phoenix gauge and the memory gauge.

( )mBfmB DDpp −+= γ , (8) where

phm

phmf DD

pp−−

=γ . (9)

The fluid level for calculating the amount of gas and water volumes above mid-perforation in the wellbore was estimated as

gppDD

l

chBBfvl ρ

−−=− . (10)

Estimation of gas production The rate of the gas produced from the reservoir can be estimated as a combination of the gas produced to the surface and that accumulated at the top of the annulus.

( ) sii

s

ii

ichifvl

ii

ichifvlan

isurfacegig

pttT

TzpD

TzpD

A

qq

)1()()1()1(

)1()1(

)()(

)()(

)()(

~~~~−−−

−−−−

−

−⎟⎟⎠

⎞⎜⎜⎝

⎛−+

=

(11) ( ))1()()()1()( −− −+= iiigigig ttqQQ , (12)

where T~ and z~ denote the average temperature and z-factor over the interval between the liquid level and the surface. Estimation of water production The water production from the reservoir was estimated at each time level, based on the rate of the liquid produced to the surface and the change in the liquid level, as

( )( ))1()(

)1()()()(

−

−−−− −

−−=

ii

ifvlifvlanisurfacewiw tt

DDAqq (13)

( ))1()()()1()( −− −+= iiiwiwiw ttqQQ . (14)

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Total gas production volume during 2008 test: ~13,000 m3

Figure 7 Estimated gas production from reservoir

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Figure 8 Estimated water production from

reservoir in 2008 winter test The gas and water production rates thus estimated are depicted in Figures 7 and 8, respectively. It was confirmed that the gas and water were

produced continuously from the reservoir throughout the test period. The gas production rate ranged from 2,000 to 3,000 m3/d and the water production rate was 10-20 m3/d, while the bottomhole pressure was rather stable. The total gas and water production throughout the test period are estimated at about 13,000 m3 and 70 m3, respectively. NUMERICAL SIMULATOR The simulator used in this study (MH21-HYDRES) was originally developed by the University of Tokyo and has since been modified and improved by Japan Oil Engineering Co., Ltd., the University of Tokyo, Japan National Oil Corporation and National Institute of Advanced Industrial Science and Technology [4, 14, 15]. This simulator is able to deal with three-dimensional, five-phase (gas, water, ice, MH and salt (deposit)), six-component (methane, carbon dioxide, nitrogen, water, methanol and salt) problems. Further details on this simulator are given in our previous papers [4, 14, 15]. RESERVOIR MODELING Estimation of reservoir properties Petrophysical properties As stated in the above, the 2007 and 2008 production tests were conducted in the reservoir called “Zone A”. The petrophysical properties of the Zone A reservoir, such as porosity, MH saturation and permeability, were estimated mainly by interpreting the open hole well log data measured while the Mallik 2L-38 well was deepened in 2007 and the core data acquired during the JAPEX/JNOC/GSC et al., Mallik 5L-38 gas hydrate production research well program [6, 9, 11]. The shale content was estimated based on the gamma ray (GR) log data assuming the responses of GR to clean sand and to shale. The effective porosity was calculated correcting the total porosity (estimated from the density log results) by the shale content. The MH saturation was estimated by the following equation, combining the total porosity estimated by the density log results and that by the NMR log results applying the Density-Magnetic Resonance (DMR) method.

t

NMRtthS

φφφ −−

= . (15)

The initial effective permeability to water in the presence of MH was estimated by the Schlumberger-Doll Research (SDR) method. The absolute permeability (in the condition without MH) was estimated based on the core analysis data by multi-regression analysis as a function of porosity, shale content and MH saturation as presented in Eq. (16).

( )

⎪⎪⎩

⎪⎪⎨

⎧

+−

−+−

=

intervalMH-nonfor6613.0331.3855.6

intervalMHfor0106.0123.1436.2220.7

logshe

hshe

V

SV

kφ

φ

.

(16)

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Well : new 2L-38

MH zone property

Zone A

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Well : new 2L-38 MH zone propertyZone A

Zone A

MH: 42 layers Water: 13 layers Figure 9 Reservoir model layer properties

As depicted in Figure 9, Zone A reservoir is composed of 3 major parts in the vicinity of the Mallik 2L-38 well. The upper part is located at the interval of 1,078-1,082 m, where the effective porosity, shale content, MH saturation, absolute permeability and initial effective permeability to water range from 10 to 30%, from 20 to 50%, from 30 to 80%, from 10 to 1,000 mD and from 0.01 to 1 mD, respectively. The middle part, extending from 1,082 m to 1,093 m, is a silty/shaly interbed with relatively low porosity, MH saturation and absolute permeability. In the lower part, extending from 1,093 m to 1,113 m, MH is accumulated most intensively with MH saturation of 70-90%. In this interval, the effective porosity, shale content, absolute permeability and initial effective permeability to water range from 30 to

35%, from 10 to 20%, from 100 to 1,000 mD and from 0.01 to 1 mD, respectively. The lower part is underlain by the layer filled with free water with the effective porosity of 30%, shale content of about 25% and absolute permeability greater than 100 mD. The 12 m interval of 1,093-1,105 m was selected as a perforation interval, since the numerical simulation suggested that this interval was optimal to produce a certain amount of gas and to prevent the bottom water from breaking through during the production test [9]. Initial pressure and temperature The initial reservoir pressure was estimated based on the results of the MDT tests conducted at the Mallik 5L-38 well in 2002 [3] and was calibrated with the memory gauge data acquired during the 2007 winter test. On the other hand, the initial reservoir temperature was estimated from the Distributed Temperature Sensing (DTS) data measured at the Mallik 4L-38 well after the MH production test conducted in April 2002 [15] and was adjusted according to the DTS data measured during the 2007 winter test. The initial pressure and temperature traverses are expressed by the equations below, which indicates that the initial pressure (approx. 11.3 MPa) and temperature (approx. 285.7) at the MH-water contact level (1,113 m) is almost equivalent to the equilibrium condition for MH, methane and water of 50,000 ppm salinity.

39375.0)m(01051.0)PaM( −= Dp (17)

⎪⎪⎩

⎪⎪⎨

⎧

>+

≤+

=

m1085for32.256)m(0267.0

m1085for12.244)m(0379.0

)K(

DDDD

T . (18)

Construction of reservoir model A two-dimensional radial reservoir model was constructed reflecting the initial reservoir properties estimated above. 796 grid blocks with a minimum grid size (Δr) of 2 cm were allocated in the radial direction, while in the vertical direction, 42 and 13 grid layers were assigned for the interval above the MH-water contact and for the free water interval, respectively. The initial reservoir properties such as effective porosity, shale content, MH saturation, effective

permeability to water and absolute permeability were defined for each grid layer as shown in Table 1 and Figure 9 [10, 17].

Model properties Values

Modeling area 5,000 m around the well

Thickness (m) 72.4 (MH zone: 39.4; water zone: 33.0)

Grid system r-z radial coordinate

Number of grid blocks 796 (r-direction); 55 (z-direction)

Initial pressure (MPa) 10.9-11.3 (11.1 @center of MH zone)

Initial temperature (K) 284.8-286.0 (285.6 @center of MH zone)

Porosity (%) MH zone: 5.0-33.8; water zone: 10.3-29.9

Absolute permeability (mD) MH zone: 0.01-1,615.8; water zone: 20.5-1,538.6

Initial effective permeability to water (mD) MH zone: 0.006-63.8; water zone: 20.5-1,538.6

Initial MH saturation (%) MH zone: 0-83.0; water zone: 0

Initial water saturation (%) MH zone: 17-100; water zone: 100-100 Table 1. Reservoir model parameters.

HISTRORY MATCHING SIMULATION Procedure of history matching simulation Figure 10 illustrates the overall procedure of the history matching simulation. As introduced in the above, the gas and water volumes produced from the reservoir sand face were rigorously estimated based on a variety of data measured during the tests. On the other hand, as mentioned in the above, the numerical model for the tested reservoir was constructed based mainly on the results of the interpretation of the well log and core data acquired in the course of the 2007 winter test and/or during the past production tests.

Data AvailableCHPBH P & TMotor TPump rate (?)DTS T

Data AvailableCHPBH P & TSurface gas &water ratesDTS T

discrepancy

History Matchingfor 2007 Test

(adjust parameters)


(adjust parameters)

Liquid level

Liquid level

Data AvailableWell logCore (2002 test)DTS TPhoenix gauge P

Measured BHP

Measured BHP

Simulation of 2007 Test

Performances

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Performances

Matching of BHT

Matching of BHT

2007 Test

2008 Test

Gas rateGas rate

Water rate (?)Water

rate (?)

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ore

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model

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esEs

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of

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ates Liquid

levelLiquid level

Gas rateGas rate

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input

Gas rateGas rate

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Reproduce 2007 Test?

Simulation of shut-in period and 2008 Test Performances

Simulation of shut-in period and 2008 Test Performances

Estim

atio

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oduc

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esEs

timat

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of

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ates

•True water rate•True pump rate


(adjust parameters)


(adjust parameters)



EndEnd

Yes

Yes

Yes

Yes

No

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No

No


EndEnd Figure 10 Overall study flow

First of all, the 2007 winter test performances were simulated specifying the observed bottomhole pressure profile as a boundary condition. The simulated gas and water production volumes showed a significant difference from those estimated based on the observed data. Hence, in the second step, the reservoir model parameters

were adjusted so as to reproduce the observed/estimated gas and water production performances by numerical simulation. Although the simple modification of the reservoir model parameters could not provide good history matching results, the 2007 winter test performances were successfully reproduced through numerical simulation by modifying the model parameters with a new concept that the sand production might have dramatically increased the near wellbore permeability [10, 17]. In the third step, the reservoir performances during the shut-in from the end of the 2007 winters test to the beginning of the 2008 winter test as well as those during the 2008 winter test were simulated using the reservoir model tuned through the history matching simulation for the 2007 winter test. Unfortunately, the simulated 2008 winter test performances did not satisfactorily agree with the observed/estimated test performances. Then, in the fourth step, taking various phenomena that had possibly occurred during the tests into consideration, the reservoir model parameters were adjusted again and again until the reservoir performances for the entire test period (i.e., during the 2007 winter test, shut-in period and the 2008 winter test) could be reproduced by numerical simulation. Final history matching simulation A large number of trial simulation runs were attempted for obtaining good matching between simulated and observed/estimated production performances for both the 2007 winter and the 2008 winter tests. In the course of these history matching simulation runs, the model parameters were adjusted as described below, to attain the final good matching [17]. Modification of effective permeability with high permeability conduits The concept that each grid block consisted of the two parts (i.e., one with the original absolute permeability and the other representing the high permeability conduits) was introduced to reproduce the increase/decrease in the effective permeability of each grid block more flexibly. As shown in Figure 11, each grid block was assumed to be composed of the parts with and without high permeability conduits. It was also assumed that the effective permeability to gas and

water in each grid block could be expressed by the following equations.

( ) ( ) ( )Nhohhp SkxSxkk −−+−= 111 2* (5)

rgeg kkk *= (6)

rwew kkk *= , (7) where x denotes the fraction of the part with high permeability conduits in each grid block and hpk stands for the absolute permeability of a high permeability conduit, which was assumed to be 15 D based on the Hagen-Poiseuille law. Since none of the grid blocks have the part of high permeability conduits before the 2007 winter test, the value of x should be zero throughout the reservoir model in the initial stage. The value of x for each grid block, which represents the intensity and the extent of high permeability conduits associated with the sand production during the 2007 winter test, was then appropriately adjusted with time so that the simulated production performances could agree with the observed/estimated performances for the 2007 winter test. In the simulation for the shut-in period and for the 2008 winter test, the value of x for each grid block was assumed to be constant at the value of x estimated for the end of the 2007 winter test, considering that no more growth of high permeability conduits were expected after the 2007 winter test because of the sand control by the screen.

0

15

0 1

k = original(e.g., 0.5 D)

khp = 15 D

x0

1-x0

High Permeability

SH (fraction)

Original High Permeability region 2007 test (x = 0→x0)2008 test (x = x0 const)

End of 2007 test(x = x0)

Initial (x = 0)

k* (D

)

x

1-x

Original

Grid block

k* changes along this curve in 2008 test

Figure 11 Concept expressing overall grid block permeability as a function of MH saturation with

growth of high permeability conduits Modification of transmissibility To reproduce the observed/estimated gas production smaller than simulated for the period after the middle of the Stage-1 of the 2008 winter test, the transmissibility of the grid blocks located in the vicinity of the well was decreased at the timing of the reduction of the bottomhole pressure (Figure 12). This decrease in the near wellbore transmissibility must

quantitatively reflect the effects of collapse/deformation of high permeability conduits and/or accumulation of fine sand grains in the vicinity of the well.

0

0.2

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tom

ehole

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ssure

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Pa)

Transmissibility multiplier

Bottomhole pressure

high permeability conduits

20 m

deformation/compaction area

perforation interval

3 m

well

Figure 12 Reduction of near wellbore grid block permeability reflecting collapse/compaction of

high permeability conduits (2008 test) Modification of vertical permeability To suppress the simulated water production caused by the cross flow from the water bearing layers overlying the perforation interval, the absolute permeability in the vertical direction was reduced by the factor of 1/5. This may be reasonable taking account of the presence of interbedded silty sand and/or sandy silt. Modification of relative permeability After the major modifications of the reservoir model parameters for the large-scale history matching, the relative permeability curves were slightly modified. Note that the alteration of relative permeability curves was kept to the minimal, only for the fine tuning of simulated gas and water production.

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estimated

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3 )

Water production rate (estimated)Water production rate (simulated)Cumulative water production (estimated)Cumulative water production (simulated)

simulated

estimated

(a) gas production (b) water production

Figure 13 Results of final history matching (2007 test)

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Simulated(calibrated)

estimated

(a) gas production (b) water production

Figure 14 Results of final history matching (2008 test)

The gas and water production performances simulated for the 2007 winter test and for the 2008

winter test using the final history matched model are depicted with the observed/estimated values in Figures 13 and 14, respectively. In addition, Figures 15 and 16 shows the distributions of the reservoir properties such as pressure, temperature, MH saturation and gas saturation simulated using the final history matched model for the ends of the 2007 winter test and the 2008 winter test. Note that the estimated gas production volumes before the shut-in of the casing head valve in the 2007 winter test and the estimated water production volumes measured by the surface flow meter before the tank gauge measurement in the 2008 winter test are unreliable. Hence, the final history matching was attained concentrating on the matching for the test period with the reliable data. 20 m

(MPa) (K)

(fraction) (fraction)

Perforation interval

Gas saturationMH saturation

Pressure Temperature

well

Figure 15 Distributions of reservoir properties

simulated by final history matched model (end of 2007 test)

20 m

(MPa) (K)

(fraction)

Perforation interval

Gas saturationMH saturation

Pressure Temperature

(fraction)

well

Figure 16 Distributions of reservoir properties

simulated by final history matched model (end of 2008 test)

DISCUSSION Judging from the results of the history matching simulation, the following are inferred as the overall MH dissociation and production behaviors

during the 2007/2008 winter tests, which are schematically illustrated in Figure 17.

MH zoneMH zone

Water injection zoneWater injection zone

Dissociation areaDissociation area

Growth of WormholeGrowth of Wormhole

Depressurization!Depressurization!

MH zoneMH zone


Produced sandProduced sand

(a) before 2007 test (b) end of Stage-1 of 2007 test




MH zoneMH zone



Plug off!Plug off!Dissociation areaDissociation area



MH zoneMH zone



(c) end of Stage-2 of 2007 test (d) end of Stage-3 of 2007 test

GasGas

ReRe--formation formation of MHof MH

GasGas

ReRe--formation formation of MHof MH


Deformation/collapse of wormholeDeformation/collapse of wormhole


Skin?Skin?

(e) end of 2007-2008 shut-in (f) end of Stage-1 of 2008 test



Skin?Skin?




Skin?Skin?


(g) end of Stage-2 of 2008 test (h) end of Stage-3 of 2007 test Figure 17 Schemata of reservoir performances

through 2007 and 2008 tests inferred from history matching simulation

• In the 2007 winter test, sand production must

have created relatively high permeability conduits (e.g., wormholes) resulting in significantly enhanced reservoir permeability near the wellbore, promoting higher than expected rates of gas production (Figures 17a through 17d). The extent of the area with high permeability conduits was simulated to be about 10 m from the well (Figure 12). On the other hand, the major area of MH dissociation is simulated to be about 7-10 m from the well in the lateral direction and about 1-2 m above and below the perforation interval (Figure 15), which is almost identical to that with high permeability conduits.

• During the shut-in period from the end of the 2007 winter test to the beginning of the 2008 winter test, all the free gas associated with the dissociation of MH during the 2007 winter test was absorbed to re-form MH (Figure 17e) increasing the MH saturation in the vicinity of

the well by about 1-5%. • In the Stage-1 of the 2008 winter test, the gas

production increased and decreased rapidly followed by the stable and then gradually decreasing gas production. It is inferred that the rapid increase and decrease in the gas production early in this stage was induced reflecting the rapid MH dissociation in the regions with high permeability conduits. The subsequent stable and then gradually decreasing gas production should reflect the dissociation of MH located out of the high permeability regions (Figure 17f). During this stage, the transmissibility in the vicinity of the well decreased down to about 70% of the original value (Figure 12), due probably to the collapse/deformation of high permeability conduits and/or to the migration of fine sand grains.

• When the bottomhole pressure was further decreased early in the Stages-2 and -3, the gas production rapidly increased reflecting the dissociation of MH in the high permeability regions. This increase, however, was not remarkable, affected by the further reduction of the transmissibility in the vicinity of the well down to about 30% of the original value (Figure 12). Since the gas production late in each stage must have been induced by the dissociation of MH located out of the high permeability regions (Figures 17g and 17h), this gas production must suggest the intrinsic (i.e., undisturbed by high permeability conduits) potential of the tested MH reservoir (Zone A).

CONCLUSIONS The MH production tests were conducted using the depressurization methods in the JOGMEC/NRCan /Aurora Mallik production program in April 2007 and in March 2008. By analyzing various data such as wellhead/bottomhole pressure, temperature, and gas/water flow rates acquired during these tests, the gas and water production volumes from the reservoir were estimated. Based on the production thus estimated, the overall performances of the production test were successfully history matched by a series of numerical simulation. Through this history matching simulation, the test performances were quantitatively examined.

1. In the 2007 winter test, a certain amount of gas and water were produced from a 12 m perforation interval in the Zone A MH reservoir at the Mallik site in Canada, by reducing the bottomhole pressure down to about 7 MPa. The produced gas, however, was not directly delivered to the surface via the tubing, but was accumulated at the top of the casing because of the irregular (on-off) pumping operations due probably to the excessive sand production. Hence, the test performances, including the gas and water production rates, were examined based on the monitored data. For example, it was inferred that 1,000-2,000 m3/d of sustainable gas production and 10-70 m3/d of continuous water production were achieved when the bottomhole pressure was reduced from 11 MPa to 7.2-7.5 MPa.

2. In the 2008 winter test targeting the same

reservoir interval, much larger and longer gas production was attained with a stepwise reduction of the bottomhole pressure down to about 4.5 MPa, preventing sands from flowing into the wellbore by the screen. Since both the gas and water could be delivered to the surface, the test performances were analyzed based mainly on the measured gas and water production rates and on the bottomhole data as follows. As a result of these analyses, it was estimated that the sustainable gas production had been accomplished for about 6 days with the stable gas production of 2,000-3,000 m3/d and water production of 10-20 m3/d and that the total gas and water production throughout the test period were about 13,000 m3 and 70 m3, respectively

3. The performances of both the 2007 winter test

and 2008 winter test were successfully reproduced through history matching simulation, by appropriately adjusting the reservoir parameters introducing the hypotheses of the generation and growth of high permeability conduits and the collapse/compaction of these conduits.

4. In accordance with the results of the above

history matching simulation, the test performances are examined qualitatively as follows.

• In the 2007 winter test, sand production must

have created relatively high permeability conduits (e.g., wormholes) resulting in significantly enhanced reservoir permeability near the wellbore, promoting higher than expected rates of gas production. The extent of the area with high permeability conduits was simulated to be about 10 m from the well. The major area of MH dissociation is simulated to be about 7-10 m from the well in the lateral direction and about 1-2 m above and below the perforation interval.

• During the shut-in period from the end of the 2007 winter test to the beginning of the 2008 winter test, all the free gas associated with the dissociation of MH during the 2007 winter test was absorbed to re-form MH increasing the MH saturation in the vicinity of the well by 1-5%.

• It is inferred that the rapid increase and decrease in the gas production early in the Stage-1 of the 2008 winter test was induced reflecting the rapid MH dissociation in the regions with high permeability conduits. The subsequent stable and then gradually decreasing gas production should reflect the dissociation of MH located out of the high permeability regions.

• During the 2008 winter test, the gas producibility gradually decreased down to about 30% of the original value, due probably to the collapse/deformation of high permeability conduits and/or to the migration of fine sand grains.

• The gas production late in each stage was induced by the dissociation of MH located out of the high permeability regions, which must suggest the intrinsic (i.e., undisturbed by high permeability conduits) potential of the tested MH reservoir.

ACKNOWLEDGEMENT This study was financially supported by the Research Consortium for Methane Hydrate Resources in Japan (MH21 Research Consortium) to carry out Japan’s Methane Hydrate R&D Program by the Ministry of Economy, Trade and Industry (METI). The authors gratefully acknowledge them for the financial support and permission to present this paper. The authors also wish to thank Japan Oil Engineering Co. Ltd., Japan Oil, Gas and Metals National Corporation, the Geological Survey of Canada/Natural

Resources Canada, Aurora College/Aurora Research Institute, the National Institute of Advanced Industrial Science and Technology, Schlumberger K. K. and the University of Tokyo for their technical support. REFERENCES [1] Dallimore SR, Uchida T, Collett TS. Scientific results from JAPEX/JNOC/GSC Mallik 2L-38 gas hydrate research well, Mackenzie Delta, Northwest Territories, Canada. Geological Survey of Canada, Bulletin 544, 1999. [2] Hancock SH, Collett TS, Dallimore SR, Satoh T, Inoue T, Huenges E, Henninges J, Weatherill B. Overview of thermal-stimulation production-test results for the JAPEX/JNOC/GSC et al. Mallik 5L-38 gas hydrate production research well. Geological Survey of Canada, Bulletin 585, 2005. [3] Hancock SH, Dallimore SR, Collett TS, Carle D, Weatherill B, Satoh T, Inoue T. Overview of pressure-drawdown production-test results for the JAPEX/JNOC/GSC et al. Mallik 5L-38 gas hydrate production research well. Geological Survey of Canada, Bulletin 585, 2005. [4] Kurihara M, Ouchi H, Inoue T, Yonezawa T, Masuda Y, Dallimore SR, Collett TS. Analysis of the JAPEX/JNOC/GSC et al. Mallik 5L-38 gas hydrate thermal production test through numerical simulation. Geological Survey of Canada, Bulletin 585, 2005. [5] Kurihara M, Funatsu K, Kusaka K, Yasuda M, Dallimore SR, Collett TS, Hancock SH. 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. Geological Survey of Canada, Bulletin 585, 2005. [6] Dallimore SR, Collett TS. Summary and implications of the Mallik 2002 Gas Hydrate Production Research Well Program. Geological Survey of Canada, Bulletin 585, 2005. [7] Dallimore SR, Wright JF, Nixon FM, Kurihara M, Yamamoto K, Fujii T, Fujii K, Numasawa M, Yasuda M, Imasato Y. Geologic and porous media factors affecting the 2007 production response characteristics of the JOGMEC/NRCan/Aurora Mallik gas hydrate production research well. Proceedings of the 6th International Conference on Gas Hydrates, Vancouver, Canada, 2008. [8] Numasawa M, Dallimore SR, Yamamoto K, Yasuda M, Imasato Y, Mizuta T, Kurihara M, Masuda Y, Fujii T, Fujii K, Wright JF, Nixon FM, Cho B, Ikegami T, Sugiyama H Objectives and

operation overview of the JOGMEC/NRCan /Aurora Mallik gas hydrate production test. Proceedings of the 6th International Conference on Gas Hydrates, Vancouver, Canada, 2008. [9] Fujii T, Takayama T, Dallimore SR, Nakamizu M, Mwenifumbo J, Kurihara M, Yamamoto K, Wright JF, Al-Jubori A. Tribus M, Evans RB. Wire-line logging analysis of the JOGMEC /NRCan/Aurora Mallik gas hydrate production test. Proceedings of the 6th International Conference on Gas Hydrates, Vancouver, Canada, 2008. [10] Fujii K, Cho B, Ikegami T, Sugiyama H, Imasato Y, Dallimore SR, Yasuda, M. Development of a monitoring system for the JOGMEC/NRCan/Aurora Mallik gas hydrate production test program. Proceedings of the 6th International Conference on Gas Hydrates, Vancouver, Canada, 2008. [11] Kurihara M, Funatsu K, Ouchi H, Masuda Y, Yasuda M, Yamamoto K, Numasawa M, Fujii T, Naira H, Dallimore SR, Wright JF. Analysis of the JOGMEC/NRCan/Aurora Mallik gas hydrate test through numerical simulation. Proceedings of the 6th International Conference on Gas Hydrates, Vancouver, Canada, 2008. [12] Kurihara M, Sato A, Funatsu K, Ouchi H, Yamamoto K, Numasawa M, Ebinuma T, Narita H, Masuda Y, Dallimore SR, Wright JF, Ashford D. Analysis of production data for 2007/2008 Mallik gas hydrate production tests in Canada. Proceedings of the CPS/SPE International Oil & Gas Conference and Exhibition in China, Beijing, China, 2010. [13] Kurihara M, Sato A, Funatsu K, Ouchi H, Yamamoto K, Fujii T, Numasawa M, Masuda Y, Narita H, Dallimore SR, Wright JF, Ashford D. Analysis of production data of gas hydrate production tests at JOGMEC/NRCan/Aurora Mallik 2L-38. GSC Bulletin, Ottawa, Ontario, Canada, 2011. [14] Masuda Y, Naganawa S, Ando S, Sato K. Numerical calculation of gas-production performance from reservoirs containing natural gas hydrates. paper SPE 38291, Proceedings, Western Regional Meeting, Society of Petroleum Engineers, Long Beach, California, June 25-27, 1997. [15] Masuda Y, Konno Y, Iwama H, Kawamura T, Kurihara M, Ouchi H. Improvement of near wellbore permeability by methanol stimulation in a methane hydrate production well. paper OTC 19433, Proceedings of the Offshore Technology Conference, Houston, Texas, 2008.

[16]Wright JF, Dallimore SR, Nixon FM, Duchesne C. In situ stability conditions of gas hydrate in sediments of the JAPEX/JNOC/GSC et al. Mallik 5L-38 gas hydrate production research well. Geological Survey of Canada, Bulletin 585, 2005. [17] Kurihara M, Sato A, Funatsu K, Ouchi H, Yamamoto K, Fujii T, Numasawa M, Masuda Y, Narita H, Dallimore SR, Wright JF. History Matching Simulation of Gas Hydrate Production Tests at JOGMEC/NRCan/Aurora Mallik 2L-38. GSC Bulletin, Ottawa, Ontario, Canada, 2011.

Documents

ANALYSIS OF 2007/2008 JOGMEC/NRCAN/AURORA MALLIK GAS HYDRATE