6th International Conference on Gas Hydrates

ANALYSIS OF THE JOGMEC/NRCAN/AURORA MALLIK GAS HYDRATE PRODUCTION TEST THROUGH NUMERICAL SIMULATION Kurihara, Masanori; Funatsu, Kunihiro; Ouchi, Hisanao; Masuda, Yoshihiro; Yasuda, Masato; Yamamoto, Koji; Numasawa, Masaaki; Fujii, Tetsuya; Narita, Hideo; Dallimore, Scott R.; Wright, J. Frederick 2008

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Proceedings of the 6th International Conference on Gas Hydrates (ICGH 2008), Vancouver, British Columbia, CANADA, July 6-10, 2008.     ANALYSIS OF THE JOGMEC/NRCAN/AURORA MALLIK GAS HYDRATE PRODUCTION TEST THROUGH NUMERICAL SIMULATION  Masanori Kurihara? , Kunihiro Funatsu and Hisanao Ouchi Japan Oil Engineering Company 1-7-3 Kachidoki, Chuo-ku, Tokyo, 104-0054, Japan  Yoshihiro Masuda School of Engineering, The University of Tokyo  Masato Yasuda, Koji Yamamoto, Masaaki Numasawa and Tetsuya Fujii Japan Oil, Gas and Metals National Corporation  Hideo Narita National Institute of Advanced Industrial Science and Technology  Scott R. Dallimore and Fred Wright Geological Survey of Canada, Natural Resources Canada  ABSTRACT A gas hydrate production test using the depressurization method was conducted in early April 2007 as part of the JOGMEC/NRCan/Aurora Mallik production research program.  The results of the production test were analyzed using a numerical simulator (MH21-HYDRES) coded especially for gas hydrate reservoirs.  This paper evaluates the test results based on analyses of production test data, numerical modeling and a series of history matching simulations.  Methane gas and water was produced from a 12 m perforation interval within one of the major methane hydrate (MH) reservoirs at the Mallik MH field, by reducing the bottomhole pressure down to about 7 MPa.  The measured gas production rate was far higher than that expected for a comparatively small pressure drawdown.  However, irregular (on-off) pumping operations, probably related to excessive sand production, resulted in unstable fluid flow within the wellbore, which made the analysis of test performance extremely complicated.  A numerical reservoir model was constructed as a series of grid blocks, including those mimicking the wellbore, to enable rigorous simulation of fluid flow patterns in the vicinity of the wellbore.  The model was then tuned through history matching, not by simply adjusting reservoir parameters, but by introducing the concept that sand production might have dramatically increased the near-wellbore permeability.  The good agreement between observed and simulated performances suggests the mechanism of MH dissociation/production during the test.  The history matched reservoir model was employed to predict the second-year production test performance, in order to examine the gas production potential of the Mallik MH reservoir, and to provide insight into future exploration and development planning for MH reservoirs.  Keywords: production test, numerical simulation, history matching, depressurization, sand production                                                       ?  Corresponding author: Phone: +81 3 5548 1663 Fax: +81 3 5548 1673 Email: kurihara@joe.co.jp  NOMENCLATURE A  cross sectional area of annulus [m2] D  depth [m] G  gas volume in annulus [m3] k  absolute permeability [m2] ke  effective permeability [m2] kr  relative permeability p  pressure [Pa] q  production rate [m3/s] Sh  MH saturation t  time [s] T  Temperature [K] Vsh  shale content W  water volume in annulus [m3] z  gas deviation (compressibility) factor ?  density [kg/m3] ? e effective porosity  subscript ch  casing head g  gas i  time level l  liquid p  phoenix gauge s  standard condition w  water wp  pumping water  INTRODUCTION The 2006-08 JOGMEC/NRCan/Aurora Mallik gas hydrate production research program is being conducted with a central goal to measure and monitor the production response of a terrestrial gas hydrate deposit to pressure draw down (depressurization).  The Japan Oil, Gas and Metals National Corporation (JOGMEC) and Natural Resources Canada (NRCan) are funding the program and leading the research and development studies.  Aurora College/Aurora Research Institute is acting as the operator for the field program.  This paper reviews observations (e.g. gas/water flows, pressure-temperature regimes, etc.) made during the 2007 production test, describes numerical modeling and analyses of production test performances through history matching simulation, and discusses probable mechanisms of MH dissociation and production during this test.  Complimentary papers are also published in this volume describing operations [1], well log characteristics [2] and geophysical monitoring techniques employed [3].  The Research Consortium for Methane Hydrate Resources in Japan (MH21 Research Consortium), which was organized to realize the exploration and exploitation of methane hydrate (MH) offshore of Japan, has implemented a variety of research projects toward the assessment of MH resources, establishment of MH production methods, and examination of the impact of MH development on the environment.  As part of this research, we have developed a state-of-the-art numerical simulator (MH21-HYDRES) for rigorous prediction of MH dissociation and production behaviors both at core and field scales.  This simulator has a capability to deal with 3-D, 5-phase and 4-component problems associated with MH dissociation kinetics.  In April 2007, a field-scale production test was conducted at one of the major Mallik MH reservoirs (Zone A), attempting the dissociation and production of MH by reducing the bottomhole pressure.  Because of the periodic shut-down of the downhole pump, due probably to problems related to sand production, essentially three consecutive pumping cycles (pumping followed by shut-in) were conducted during the production tests.  Although the produced gas was not directly delivered to the surface via the tubing string, it was allowed to accumulate at the top of the casing, and the increase in the casing head pressure clearly indicated continuous MH dissociation and production during the test.  Gas and water production rates were estimated based on continuously monitored parameters such as bottomhole pressure, casing head pressure, and pumping rate.  A series of numerical simulations were conducted to analyze the test performances through history matching.  The gas production rate, which was considerably higher than expected given the bottomhole pressure reduction actually applied, was then successfully history matched based on an assumed improvement of reservoir permeability in the vicinity of the well casing perforations.  Furthermore, the rate of the produced water, which was injected into a lower interval, was also estimated by rigorously matching the evolution of bottomhole temperatures.  Using the reservoir model thus tuned through history matching, the performance of a subsequent planned production test, scheduled for March 2008, was predicted.  These numerical simulation studies show a promising potential for successful MH dissociation and production simply by controlled reduction of the bottomhole pressure.  NUMERICAL SIMULATOR The simulator used in this study was originally developed by the University of Tokyo, and has since been modified and improved by Japan Oil Engineering Company, the University of Tokyo, Japan National Oil Corporation and National Institute of Advanced Industrial Science and Technology [4, 5, 6, 7].  This simulator is able to deal with three-dimensional, five-phase, four-component problems and has the following features:  ?   Three-dimensional Cartesian and two-dimensional radial co-ordinates can be applied with local grid refinement. ?   Four-components (methane, water, methanol and salt) are available. ?   Five phases (gas [V, mobile], water [Lw, mobile], ice [I, immobile], MH [H, immobile] and salt (deposit) [S, immobile]) are available. ?   Darcy?s law and relative-permeability curves are applied to gas and water flows. ?   Endothermic dissociation of methane hydrate and ice, and exothermic formation of MH and ice are accounted for. ?   Kim-Bishnoi equation [8] is used for MH dissociation kinetics. ?   V-H-Lw or V-H-I equilibrium pressure is estimated as a function of temperature and methanol/salt concentration.  Further details on this simulator are given in our previous papers [4, 5, 6, 7].  ESTIMATION OF GAS AND WATER PRODUCTION RATES  Data acquisition Prior to the production test, a suite of well logging data was acquired [2] to enable characterization of important reservoir properties critical for reservoir modeling.  During the production test, a variety of real-time data were acquired at various locations along the bottomhole assembly (Figure 1).  Including:  ?   Pressure and temperature at the phoenix gauge ?   Pressure and temperature at the memory gauge ?   Casing head pressure ?   Pumping rate (estimated based on intake-discharge pressure difference and number of revolutions).  Since neither gas nor water was essentially produced to the surface, the above data were used for estimating of gas and water production rates.              20" 94#/ft J55 @ 103 m         2 7/8" EUE, N80 Tbg5 Mpa @ +/- 581 mPermafrost depth @ +/- 640 m4 Mpa @ +/- 682 m3 Mpa @ +/- 783 m         Perforated Joint @ 649m     13 3/8" 61#/ft, J55 @ 677 mESP cable w/ chemical iny # 4CTS cable back-up ESP sensor ESP cable Splice with Chemical inj @1089mAnular Gauge Carrier bottom @ 1091mA Zone @ 1093 - 1105 mChem inj point ESP cable @1106mPhoenix gauge @ 1124mPump Intake @ 1129mPump Shroud 1127m to 1136mCheck Valve @ 1139mCTS Gauge Carrier @ 1141mSafety Shear Joint @ 1143mChemical Inj Sand Detection @1153mLocator 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 @ 1238mFC @ 1275 mShoe 9 5/8" 40#/ft, J55 @ 1288 m  Figure 1: Scheme of test well completion  Calculation of gas and water production rates  Liquid level: The depth of the interface between the liquid and the gas accumulated at the top of the casing (Dl) was estimated based on the casing head pressure (pch), the depth of the phoenix gauge (Dp) and the bottomhole pressure measured at this gauge (pp).  lchppDD???= , (1)  The gas production thus estimated is shown in Figure 3.  Total gas production during the test was estimated at about 830 m3. where  l  denotes the liquid density, which is equivalent to the density of 5% KCl solution (1.035 gf/cm3=0.0101 MPa/m) in this test.  Water production: The volume of the liquid (Wi) existing above the phoenix gauge at each time can be calculated as   Gas production: Once the liquid level is estimated as describe in the above, the cumulative gas production (Gi), which is accumulated at the upper part of the casing, can be calculated at each time (ti), 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 (A; 0.035 m2 in this test).   ( )lDDAW ?= . (4)  The rate of the water produced from the reservoir (qwi) can be estimated as the summation of the pumping rate (qwpi) and the rate of increase in Wi.   TTzppADG sschl= , (2) 11,????+?iii ttWqq  (5)  The cumulative water production is then calculated integrating qwi.  where ps and Ts denote the pressure (0.1013 MPa) and temperature (288.8 K) at standard conditions, respectively.  Gas production rate (qgi) can be estimated by differentiating Gi.  ( )1,1,, ?? ? iiiwiwiw t  (6)   11,?????=iii ttGdtdGq  (3) Approximately 40 m3 of water was estimated to have been produced from the reservoir, as depicted in Figure 4.  Note that water production may be overestimated because the pumping efficiency was assumed to be 100% in this calculation, even during the period of suspected plugging of the pump.     020004000600080001000012000140001600018000200002007/4/212:002007/4/215:002007/4/218:002007/4/221:002007/4/30:002007/4/33:002007/4/36:002007/4/39:002007/4/312:002007/4/315:002007/4/318:002007/4/321:002007/4/40:00TimePresure (kPa)0100200300400500600700800Liquid level (m)Memory Gauge PressureIntake PressureCasing Head PressureDischarge PressureStart PumpingPlug Off PointsShut Down PumpPerforated Joint DepthCasing Fluid Level#1 #2 #3Start pumpStart pumpStart pumpPlug off Plug offPlug offShut downShut downShut downCalculated4/3 2:00  Gas detection?? Casing valve was closed. Figure 2: Liquid level estimated based on various measured pressures   02000400060008000100002007/4/212:00 PM2007/4/23:00 PM2007/4/26:00 PM2007/4/29:00 PM2007/4/312:00 AM2007/4/33:00 AM2007/4/36:00 AM2007/4/39:00 AM2007/4/312:00 PM2007/4/33:00 PM2007/4/36:00 PMTimeCumulative gas production (m3)02004006008001000Gas production rate (m3/d)(BT(BT(BT(BT(BT(BT  QQ SS PP EE VDVDVDVD UJUJUJUJ PP OO  SS BB UU FFFF 		 TT JJ NN QMQMQMQM ZZZZ DBDBDBDB MM DVMDVMDVMDVMDVMDVM BB UU FEFEFEFE (BT(BT(BT(BT(BT(BT  QQ SS PP EE VDVDVDVD UJUJUJUJ PP OO  SS BB UU FFFF 		 TT JJ NN QMQMQMQM ZZZZ DBDBDBDB MM DVMDVMDVMDVMDVMDVM BB UU FEFEFEFE BGUFBGUFBGUFBGUFBGUFBGUFBGUFBGUF SHBSHBSHBSHBSHBSHBSHBSHB TCMPXTCMPXTCMPXTCMPXTCMPXTCMPXTCMPXTCMPXTCMPXTCMPXTCMPXTCMPX (BT(BT(BT(BT(BT(BT  QQ SS PP EE VDVDVDVD UJUJUJUJ PP OO  SS BB UU FFFF 		 NN PP WW JOJOJOJO HHHH BWBWBWBW FSBFSBFSBFSBFSBFSB HH FF EE (BT(BT(BT(BT(BT(BT  QQ SS PP EE VDVDVDVD UJUJUJUJ PP OO  SS BB UU FFFF 		 NN PP WW JOJOJOJO HHHH BWBWBWBW FSBFSBFSBFSBFSBFSB HH FF EE BGUFBGUFBGUFBGUFBGUFBGUFBGUFBGUF SHBSHBSHBSHBSHBSHBSHBSHB TCMPXTCMPXTCMPXTCMPXTCMPXTCMPXTCMPXTCMPXTCMPXTCMPXTCMPXTCMPX $V$V$V$V NVMBNVMBNVMBNVMBNVMBNVMBNVMBNVMB UJUJUJUJ WFWFWFWF HBHBHBHBHBHB TT QSQSQSQSQSQS PP EVDEVDEVDEVDEVDEVD UU JJ PP OO$VN$VN$VN$VN$VN$VN VV MM BB UU JJ WW FF  HH BTBTBTBT  QQ SPSPSPSP EE VV DUDUDUDU JPJPJPJP OOOO 	B	B	B	B GUGUGUGU FSFSFSFS HHHH BTBTBTBT CCCC MPMPMPMP XX 4I4I4I4I VU%PVU%PVU%PVU%PVU%PVU%PVU%PVU%PVU%PVU%P XX OO  1V1V1V1V NQNQNQNQNQNQNQNQ 4UB4UB4UB4UB4UB4UB SS U1VU1VU1VU1VU1VU1VU1VU1V NQNQNQNQNQNQNQNQ 1MV1MV1MV1MV1MV1MV HH  00 GGGGGGGGGGGG 1P1P1P1P JOJOJOJO UUUUUUUU 4I4I4I4I VU%PVU%PVU%PVU%PVU%PVU%PVU%PVU%PVU%PVU%P XX OO  1V1V1V1V NQNQNQNQNQNQNQNQ Total gas production till pumping period #3 = 830 m3Start pumpPlug offShut downShut down Figure 3: Estimated gas production rate  Start pumpStart pumpStart pumpPlug offPlug offPlug offShut downShut downShut down Figure 4: Estimated water production rate   RESERVOIR MODELING  Estimation of reservoir properties Initial pressure and temperature: The initial reservoir pressure was estimated based on the results of the Modular Dynamic Formation Tester (MDT) tests conducted at 5L-38 wells in 2002 [9] and was calibrated with the memory gauge data acquired during this test.  On the other hand, the initial reservoir temperature was estimated from the Distributed Temperature Sensing (DTS) data measured at 4L-38 well after the MH production test conducted in April 2002 [10] and was adjusted according to the DTS data measured during this test.  The initial pressure and temperature traverses are expressed by the equations below and are shown in Figure 5, which indicates that the initial pressure (11 MPa) and temperature (286 K) 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 (7) ???>?=mm)K(DDT (8)              1S1S1S1S FTFTFTFT TVSTVSTVSTVSTVSTVS F	F	F	F	F	F	 .1.1.1.1 BBBBBB 5F5F5F5F5F5F NQNQNQNQ FSBFSBFSBFSBFSBFSB UVSUVSUVSUVSUVSUVS FFFF 	EF	EF	EF	EF	EF	EF H$H$H$H$H$H$%FQ%FQ%FQ%FQ%FQ%FQUIUIUIUIUIUI	N	N	N	N55 FTUFTUFTUFTUFTUFTU ;P;P;P;P;P;P OFOFOFOF11 SS FF TTVTTVTTVTTVTTVTTV SFSFSFSF5FN5FN5FN5FN5FN5FN QFSQFSQFSQFSQFSQFS BUBUBUBU VSFVSFVSFVSFVSFVSF&& RVJRVJRVJRVJRVJRVJ MJMJMJMJ CSJCSJCSJCSJCSJCSJ VNVNVNVN11 SFTSFTSFTSFTSFTSFT TVTVTVTV SFSFSFSF.P.P.P.P EFEFEFEF M;M;M;M;M;M; POFPOFPOFPOFPOFPOF Figure 5: Initial reservoir pressure and temperature traverses  Reservoir properties: Initial reservoir properties such as effective porosity, shale content, MH saturation and effective permeability were estimated based on interpretation of open hole well logging data acquired prior to the production test [2].  Absolute permeability: Because of the excessive scatter apparent in the simple porosity-absolute permeability relationship derived from the core analysis data of 5L-38 well, as shown in 6a, absolute permeability was estimated by multi-regression analysis as a function of porosity, shale content and MH saturation as presented in Equation (9) and in Figures 6a through 6c.  The absolute permeability values thus estimated are shown in Figures 7a and 7b, indicating a remarkable reduction of estimation error by the multivariate analysis as compared to that of the porosity-permeability relationship.  ()????????+?+=interval6613interval123logshhVSk ?? (9)  Core K vs. Core Fy = 13.067x - 2.7638R2 = 0.6012y = 18.856x - 3.4671R2 = 0.8258y = 14.666x - 2.826R2 = 0.6484-1.00.01.02.03.04.00.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7Core-derived porosity (F)Absolute Permeability (log K)Calculated Permeability (JAPEX/JNOC)Gas Permeability (AGAT/GSC)(JAPEX/JNOC)+(AGAT/GSC)????  (Calculated Permeability (JAPEX/JNOC))????  (Gas Permeability (AGAT/GSC))????  ((JAPEX/JNOC)+(AGAT/GSC))Av. SquareError = 1.04Calculated Permeability (JAPEX/JNOC)Gas Permeability (AGAT/GSC)(JAPEX/JNOC)+(AGAT/GSC)Linear (Gas Permeability (AGAT/GSC))Linear ((JAPEX/JNOC)+(AGAT/GSC))Linear (Calculated Permeability (JAPEX/JNOC))Core K vs. Core Fy = -5.6849x + 3.2783R2 = 0.7801y = -4.8108x + 3.0637R2 = 0.7938y = -4.5868x + 3.047R2 = 0.8168-1.00.01.02.03.04.00.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7Log-derived shale volume (Vsh)Absolute Permeability (log K)Calculated Permeability (JAPEX/JNOC)Gas Permeability (AGAT/GSC)(JAPEX/JNOC) + (AGAT/GSC)????  (Calculated Permeability (JAPEX/JNOC))????  ((JAPEX/JNOC) + (AGAT/GSC))????  (Gas Permeability (AGAT/GSC))Calculated Permeability (JAPEX/JNOC)Gas Permeability (AGAT/GSC)(JAPEX/JNOC)+(AGAT/GSC)Linear (Gas Permeability (AGAT/GSC))Linear ((JAPEX/JNOC)+(AGAT/GSC))Linear (Calculated Permeability (JAPEX/JNOC)) (a) ?  vs. k (b) Vsh vs. k Core K vs. Core Fy = 7.8287x + 0.7498R2 = 0.2953y = 4.6967x - 0.3116R2 = 0.8858y = 3.9269x + 0.378R2 = 0.5278-1.00.01.02.03.04.00.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7Log-derived MH saturation (Sgh)Absolute Permeability (log K)Calculated Permeability (JAPEX/JNOC)Gas Permeability (AGAT/GSC)(JAPEX/JNOC) + (AGAT/GSC)????  (Calculated Permeability (JAPEX/JNOC))????  (Gas Permeability (AGAT/GSC))????  ((JAPEX/JNOC) + (AGAT/GSC))Calculated Permeability (JAPEX/JNOC)Gas Permeability (AGAT/GSC)(JAPEX/JNOC)+(AGAT/GSC)Linear (Gas Permeability (AGAT/GSC))Linear ((JAPEX/JNOC)+(AGAT/GSC))Linear (Calculated Permeability (JAPEX/JNOC)) (c) Sh vs. k Figure 6: Relation between absolute permeability and other reservoir parameters  0.00.11.010.0100.01000.010000.00.0 0.1 1.0 10.0 100.0 1000.0 10000.0Estimated absolute permeability (mD)Measured core permeability (mD) Av. SquareError = 0.32 (a) MH interval  0.00.11.010.0100.01000.010000.00.0 0.1 1.0 10.0 100.0 1000.0 10000.0Estimated absolute permeability (mD)Measured core permeability (mD)Av. SquareError = 0.28 (b) Non-MH interval Figure 7: Relation between estimated permeability and measured permeability  Construction of reservoir model We have constructed a two-dimensional radial reservoir model which reflects the initial reservoir properties estimated above.  Ninety-nine grid blocks with a minimum grid size (? r) 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 8.  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 :0-0 Initial water saturation (%) MH zone : 17-100 water zone : 100-100 Table 1: Reservoir model parameters          Depth(m)Absolute permeability (JOE) Absolute permeability (ECS) Initial permeability (SRD)Average Absolute kh (JOE) Average Absolute kh (ECS) Average Effective kh (SRD)Average Absolute kv (JOE) Average Absolute kv (ECS) Average Effective kv (SRD)88 FF MM MM    OFXOFXOFXOFXOFXOFXOFXOFX  -- .).).).)  [[ POPOPOPO FF  QQ SS PQPQPQPQ FF SS UU ZZZone  A                               Depth(m)Effective porosity (PhiD,GR) MH saturation (QL)Volume of shale (GR) Average VshAverage Effective Porosity Average MH saturation88 FF MM MM    OFXOFXOFXOFXOFXOFXOFXOFX  --  .).).).)  [[ POPOPOPO FF  QQ SS PP QQ FF SS UU ZZZone  AZone AMH: 42 layers  Figure 8: Grid layer properties    RESERVOIR SIMULATION  Conventional runs Using the reservoir model constructed above, gas and water production rates were simulated, with the observed bottomhole pressure profile specified as a boundary condition.  As shown in Figure 9, predicted gas production volumes are far lower than the estimated actual volume of gas produced during the test.  Several simulation runs attempted to history match the gas production rate by increasing the absolute permeability, initial water effective permeability, and/or relative permeability to gas.  Even by increasing these permeabilities, however, the simulated gas production rate was still much lower than the estimated actual rate as shown in Figure 10.  02000400060008000100002007/4/212:00 PM2007/4/23:00 PM2007/4/26:00 PM2007/4/29:00 PM2007/4/312:00 AM2007/4/33:00 AM2007/4/36:00 AM2007/4/39:00 AM2007/4/312:00 PM2007/4/33:00 PM2007/4/36:00 PMTimeGas production rate (m3/d)02004006008001000Cumulative gas production (m3)(BT(BT(BT(BT(BT(BT(BT(BT QSQSQSQS PP EE VDUJVDUJVDUJVDUJVDUJVDUJVDUJVDUJ PP OOOO SBUFSBUFSBUFSBUFSBUFSBUFSBUFSBUFSBUFSBUF 		 .FB.FB.FB.FB.FB.FB TT VSFEVSFEVSFEVSFEVSFEVSFEVSFEVSFE (BT(BT(BT(BT(BT(BT(BT(BT QSQSQSQS PP EE VDUJVDUJVDUJVDUJVDUJVDUJVDUJVDUJ PP OOOO SBUFSBUFSBUFSBUFSBUFSBUFSBUFSBUFSBUFSBUF 		 44 JJ NVNVNVNV MM BB UU FF EE $$ VV NN VV MBMBMBMB UU JJ WW FF HHHH BB TT QQQQ SPSPSPSP EVEVEVEV DD UU JPJPJPJP OO 	.	.	.	.	.	. FF BB TT VV SFSFSFSF EE $VNVM$VNVM$VNVM$VNVM$VNVM$VNVM$VNVM$VNVM$VNVM$VNVM BB UJUJUJUJ WFWFWFWFWFWF HH BTBTBTBTBTBT QQ SPSPSPSP EVDUJEVDUJEVDUJEVDUJEVDUJEVDUJEVDUJEVDUJEVDUJEVDUJ PP OOOO 		 44 JJ NN VMVMVMVM BB UU FEFEFEFE Total gas production estimated = ~830 m3Total gas production simulated = ~ 40 m3  Figure 9: Simulated and estimated gas production  020040060080010002007/4/212:00 PM2007/4/23:00 PM2007/4/26:00 PM2007/4/29:00 PM2007/4/312:00 AM2007/4/33:00 AM2007/4/36:00 AM2007/4/39:00 AM2007/4/312:00 PM2007/4/33:00 PM2007/4/36:00 PMTimeCumulative gas production (m3)MeasuredOriginal runAbsolute permeability ?10Initial permeability ?10original ke x10ka x10Estimated Figure 10: Gas production performances calculated in conventional history matching runs  History matching with enhanced permeability Since the conventional simulation runs revealed the difficulty in reproducing the observed gas production by simply adjusting the bulk reservoir permeability and/or other parameters, it was considered that the high gas production rate might have been caused by a drastic improvement of permeability in the vicinity of the wellbore.  It was speculated that high permeability conduits (such as wormholes or other open pathways) may have been generated in the near-wellbore sediments as a consequence of sand production associated with the dissociation of MH during the test.  To express this phenomenon in the numerical simulation, the simulator was modified so that the absolute permeability of any grid block for which more than 3% (this figure was estimated through trial and error history matching) of MH had been dissociated could be increased by the factor specified (Figure 11).  00.20.40.60.810 0.2 0.4 0.6 0.8 1N=2N=10N=15Permeability Reduction   kD/kD0Hydrate SaturationtionPermeability Reduction k*/kabsWellMH is (partly) dissociated.Permeability gradually increases with decrease in MH saturation.  (a) Conventional model  WellMH is (partly) dissociated. (High permeability conduits such as wormholes may have been generated along with sand production.?? Sh0 101e.g., 45k*/kabsPermeability was assumed to increase more drastically (b) Permeability conduit model Figure 11: Concept of permeability increase along with MH dissociation  Additional history matching simulation was then attempted by employing this adjustment factor for absolute permeability.  Figure 12 shows the simulated gas and water production for the history matched run in which absolute permeability was increased by a factor of 45.  Given that the simulated water production volume is much lower than the estimated actual water production, we acknowledge that Equations (5) and (6) may overestimate water production rates as discussed above.  The predicted two-dimensional spatial distribution of effective gas and water permeabilities at the end of the test are depicted in Figure 13.  History matching simulation suggests that the improvement of near-wellbore permeability may increase the gas production significantly, even though the area of improvement is very limited.  02000400060008000100002007/4/212:00 PM2007/4/23:00 PM2007/4/26:00 PM2007/4/29:00 PM2007/4/312:00 AM2007/4/33:00 AM2007/4/36:00 AM2007/4/39:00 AM2007/4/312:00 PM2007/4/33:00 PM2007/4/36:00 PMTimeCumulative gas production (m3)02004006008001000Gas production rate (m3/d)Gas production rate (measured)Gas production rate (simulated)Cumulative gas production (measured)Cumulative gas production rate (simulated;corrected [cum. @4/3 15:00=0])Cumulative gas production rate (simulated;berfore correction) (a) Gas production  01002003004005002007/4/212:00 PM2007/4/23:00 PM2007/4/26:00 PM2007/4/29:00 PM2007/4/312:00 AM2007/4/33:00 AM2007/4/36:00 AM2007/4/39:00 AM2007/4/312:00 PM2007/4/33:00 PM2007/4/36:00 PMTimeWater production rate (m3/d)01020304050Cumulative water production (m3)Water production rate (simply calculated)Water production rate (simulated)Cumulative water production (simply calculated)Cumulative water production (simulated) (b) Water production Figure 12: Gas and water production predicted by the history matched model  Perforation interval(mD)Well1.0 m (a) Effective permeability to gas  Perforation interval(mD)Well1.0 m (b) Effective permeability to water Figure 13: Distribution of effective permeabilities to gas and water predicted by the history matched model  SIMULATION OF FLUID MOVEMENT IN WELLBORE  Temperature matching As discussed above, the estimation of actual water production rates is very challenging because of the difficulty in specifying the actual pumping rate.  Fortunately, downhole temperatures were measured at the phoenix and memory gauges (Figure 1), providing reasonable estimates of bottomhole temperature.  The initial temperature profile of the liquid in the wellbore as well as that of the surrounding formation was inferred from DTS data.  In addition, the temperature of the water produced from the MH reservoir is roughly deduced from the above history matched simulation results and three-phase equilibrium temperature.  Hence, it may be possible to estimate the actual rate of water production from the reservoir, as well as the actual pumping rate, by matching both the bottomhole pressure and temperature through simultaneous adjustment of these rates.  A radial numerical model with 3x129 grid blocks replicating the wellbore was constructed as illustrated in Figure 14.  The heat transfer coefficient between the fluid inside the wellbore and the surrounding formation was estimated based on the thermal conductivity of fluid, casing, cement, and the formation.  The shape of the protective pump shroud was also incorporated in this numerical model.  Phoenix Gauge Memory Gauge Pump ModelingHeatz directionGasWaterHeatGas/WaterProductionWaterInjectionGasMovementWaterMovementHeat Generationby Pumpr directionopen Figure 14: Grid model representation of the wellbore   Estimation of water production rates The results of the first trial, in which the water rates and the pumping rates estimated above were simply applied as calculation constraints, are shown in Figure 15.  In this case, calculated bottomhole temperatures agree poorly with those actually observed.  After several trial and error simulation runs, a successful match between predicted and observed temperatures and pressures was attained, yielding adjusted estimates of water production rates and pumping rates as shown in Figure 16.  This history matched model suggests that total water production throughout the test period was approximately 20 m3 instead of the 40 m3 initially estimated, as shown in Figure 17.  The results also support the notion that significant reverse flow (from injection zone towards wellhead) occurred during periods when the pump was idle, and that during some pumping periods pump efficiency was considerably lower than previously estimated (Figure 18).  2802852902953002007/4/212:00 PM2007/4/26:00 PM2007/4/312:00 AM2007/4/36:00 AM2007/4/312:00 PM2007/4/36:00 PMTimeTemperature (K)030006000900012000Pressure (kPa)NFNFNFNF NNNN UFUFUFUF NQNQNQNQNQNQ 		 PCTFPCTFPCTFPCTFPCTFPCTFPCTFPCTF SWFSWFSWFSWFSWFSWF EE NFNFNFNF NNNN UFUFUFUF NQNQNQNQNQNQ 		 GG JJ STUSTUSTUSTUSTUSTU  USJBMUSJBMUSJBMUSJBMUSJBMUSJBMUSJBMUSJBMUSJBMUSJBMUSJBMUSJBMQIQIQIQI PFPFPFPF OO JJ YYYY UFUFUFUF NQNQNQNQNQNQ 		 PCTFPCTFPCTFPCTFPCTFPCTFPCTFPCTF SWFSWFSWFSWFSWFSWF EE QIQIQIQI PFPFPFPF OO JJ YYYY UFUFUFUF NQNQNQNQNQNQ 	GJSTU	GJSTU	GJSTU	GJSTU	GJSTU	GJSTU	GJSTU	GJSTU	GJSTU	GJSTU	GJSTU	GJSTU  USJBMUSJBMUSJBMUSJBMUSJBMUSJBMUSJBMUSJBMUSJBMUSJBMUSJBMUSJBMNFNFNFNF NNNN QQ SS FF TT TT  		 PP CTFCTFCTFCTFCTFCTF SS WFWFWFWF EEEENFNFNFNF NNNN QQ SS FF TT TT  		 GG JJ SS TUTUTUTUTUTU UU SJBMSJBMSJBMSJBMSJBMSJBMSJBMSJBMSJBMSJBMQIQIQIQI PFOPFOPFOPFOPFOPFO JJ YY  QSQSQSQS FF TT TT  		 PP CTCTCTCT FF SS WW FF EEEEQQ II PFPFPFPF OJYOJYOJYOJYOJYOJYOJYOJY QQ SS FTFTFTFT T	GT	GT	GT	GT	GT	GT	GT	G JSTUJSTUJSTUJSTUJSTUJSTUJSTUJSTUJSTUJSTU UU SJBMSJBMSJBMSJBMSJBMSJBMSJBMSJBMSJBMSJBM Figure 15: Bottomhole pressure and temperature predicted by the model (first trial)  2802852902953002007/4/212:00 PM2007/4/26:00 PM2007/4/312:00 AM2007/4/36:00 AM2007/4/312:00 PM2007/4/36:00 PMTimeTemperature (K)030006000900012000Pressure (kPa)NFNNFNNFNNFNNFNNFN  UFUFUFUF NQ	PNQ	PNQ	PNQ	PNQ	PNQ	PNQ	PNQ	PNQ	PNQ	P CC TT FSFSFSFS WFWFWFWF EE NFNNFNNFNNFNNFNNFN  UFUFUFUF NQ	NBNQ	NBNQ	NBNQ	NBNQ	NBNQ	NBNQ	NBNQ	NBNQ	NBNQ	NBNQ	NBNQ	NB UU DD II FF EE QIPQIPQIPQIPQIPQIP FOJFOJFOJFOJFOJFOJ YYYY UFNQUFNQUFNQUFNQUFNQUFNQUFNQUFNQUFNQUFNQ 		 PP CC TFTFTFTF SWSWSWSW FEFEFEFEFEFEQIPQIPQIPQIPQIPQIP FOJFOJFOJFOJFOJFOJ YYYY UFNQUFNQUFNQUFNQUFNQUFNQUFNQUFNQUFNQUFNQ 		 NBNBNBNB UDIUDIUDIUDIUDIUDI FF EEEENFNNFNNFNNFNNFNNFN  QSFTQSFTQSFTQSFTQSFTQSFTQSFTQSFT TT  		 PP CTCTCTCT FF SS WW FF EEEENFNNFNNFNNFNNFNNFN  QSFTQSFTQSFTQSFTQSFTQSFTQSFTQSFT T	T	T	T	T	T	 NN BUBUBUBU DIDIDIDI FEFEFEFEFEFEQIPFOJQIPFOJQIPFOJQIPFOJQIPFOJQIPFOJQIPFOJQIPFOJQIPFOJQIPFOJQIPFOJQIPFOJ YY  QQ SS FTFTFTFT TT 	PCT	PCT	PCT	PCT	PCT	PCT	PCT	PCT	PCT	PCT FF SS WW FF EEEEQIPQIPQIPQIPQIPQIP FOJFOJFOJFOJFOJFOJ YYYY QQ SS FTFTFTFT T	NT	NT	NT	NT	NT	NT	NT	N BUDBUDBUDBUDBUDBUD II FF EE Phoenix Gauge Memory Gauge Pump Check ValveOpen?ReverseFlowReverse Flow Figure 16: Bottomhole pressure and temperature predicted by the history matched model  RESERVOIR HISTORY MATCHING SIMULATION (FINAL TRIAL) 01002003004005002007/4/212:00 PM2007/4/23:00 PM2007/4/26:00 PM2007/4/29:00 PM2007/4/312:00 AM2007/4/33:00 AM2007/4/36:00 AM2007/4/39:00 AM2007/4/312:00 PM2007/4/33:00 PM2007/4/36:00 PMTimeWater production rate (m3/d)01020304050Cumulative water production (m3)88 BB UU FF SSSSSSSSSSSS BB UU FF 	O	O	O	O	O	O FXFTFXFTFXFTFXFTFXFTFXFTFXFTFXFTFXFTFXFT UU JNBJNBJNBJNBJNBJNB UU FFFF$V$V$V$V NVMBNVMBNVMBNVMBNVMBNVMBNVMBNVMB UJUJUJUJ WFWFWFWFWFWF XX BB UU FF SS QSPQSPQSPQSPQSPQSPQSPQSP EVEVEVEV DUJDUJDUJDUJDUJDUJ PP O	O	O	O	O	O	 GG JSJSJSJS TUFTUFTUFTUFTUFTUFTUFTUF TUJTUJTUJTUJTUJTUJ NN BUFBUFBUFBUFBUFBUF $V$V$V$V NVMBNVMBNVMBNVMBNVMBNVMBNVMBNVMB UJUJUJUJ WFWFWFWFWFWF XX BB UU FF SS QSPQSPQSPQSPQSPQSPQSPQSP EVEVEVEV DUJDUJDUJDUJDUJDUJ PP O	O	O	O	O	O	 OFXFOFXFOFXFOFXFOFXFOFXFOFXFOFXFOFXFOFXF TUJTUJTUJTUJTUJTUJ NN BUBUBUBU FFFF11 MM VHVHVHVH PPPP GGGGGGGG QQQQ PJOPJOPJOPJOPJOPJO UU TT4I4I4I4I VUVUVUVUVUVU EE PP XX OQVNQOQVNQOQVNQOQVNQOQVNQOQVNQOQVNQOQVNQOQVNQOQVNQOQVNQOQVNQ4U4U4U4U BSUBSUBSUBSUBSUBSU  QQ VV NN QQStart pumpStart pumpStart pumpPlug offPlug offPlug offShut downShut downShut down Since water production predicted in Figure 12b is higher than that estimated through matching of downhole P-T conditions (as above), the reservoir simulation was again performed with the goal of reconciling these predictions.  Successful history matching was attained both for water production and gas production as shown in Figure 19.  The distribution of reservoir properties such as pressure, temperature, MH saturation and gas saturation predicted at the end of the test are presented in Figure 20, which indicates that penetration of the pressure disturbance due to pressure drawdown (and hence of partial or complete MH dissociation) was approximately 7-10 m from the wellbore in the lateral direction and about 4 m above and below the perforation interval in the vertical direction. Figure 17: Water production rate newly estimated  -400-300-200-10001002003004005002007/4/212:00 PM2007/4/23:00 PM2007/4/26:00 PM2007/4/29:00 PM2007/4/312:00 AM2007/4/33:00 AM2007/4/36:00 AM2007/4/39:00 AM2007/4/312:00 PM2007/4/33:00 PM2007/4/36:00 PMTimePumping rate (m3/d)Pumping rate (first estimate)Pump rate (new estimate)Start pumpingPlug off pointsShut-down pumpStart pumpStart pump Start pumpPlug offPlug offPlug offShut downShut downShut down      Figure 18: Estimated and calculated pumping rates                               1.1.1.1.   1111 ..   1111 ..   1111 ..  "" ..   """" ..   """" ..  """" ..  1.1.1.1.  1.1.1.1.1.1.  1.1.1.1.1.1.5JNF5JNF5JNF5JNF5JNF5JNF5JNF5JNFGas production rate (m3/d)Cumulative gas production (m3)Gas rate (measured)Gas rate (simulated)Cumulative gas production (measured)Cumulative gas production (simulated;corrected [cum @4/3 15:00=0.0])Cumulative gas production (simulated:before correction) (a) Gas production  040801201602002402007/4/212:00 PM2007/4/23:00 PM2007/4/26:00 PM2007/4/29:00 PM2007/4/312:00 AM2007/4/33:00 AM2007/4/36:00 AM2007/4/39:00 AM2007/4/312:00 PM2007/4/33:00 PM2007/4/36:00 PMTimeWater production rate (m3/d)051015202530Cumulative water production (m3)Water production rate (new estimate)Water production rate (simulated)Cumulative water production (new estimate)Cumulative water production (simulated) (b) Water production Figure 19: Gas and water production predicted by the final history matched model   (fraction)15 mGas saturationPerforation intervalPressure TemperatureWell(K)(fraction)  Figure 20: Reservoir properties at the end of the test predicted by he final history matched model  PREDICTION OF SECOND WINTER TEST PERFORMANCES Another production test at Mallik was planned for March 2008, to be conducted within the same gas hydrate interval.  Using the final history matched reservoir model, the performances of this test were predicted assuming that  ?   the bottomhole pressure would be gradually decreased to achieve the bottomhole pressure of 8, 6 and 5 MPa with the reduction rate of about 0.42 MPa/h, ?   after the bottomhole pressure reached the target level, it would be kept at constant at 8, 6 and 5 MPa for 12-24 hours, and ?   the area and the intensity of the permeability improvement induced in the 2007 test would not extend further into the formation due to the application of a sand control system.  Figure 21 shows the predicted gas and water production rates for the 2008 test, along with the scheduled bottomhole pressure.  The modeling results suggest that relatively high gas and water production rates are expected reflecting the effect of improved formation permeability in the near-wellbore area soon after lowering the bottomhole pressure.  The model also predicts that gas and water production rates become stable at about 2,000 m3/d and 40m3/d respectively, after 1-2 days following stabilization of the bottomhole pressure.  Time (day)Gas production rate (103 m3/d),Water production rate (10 m3/d)Bottomhole pressure (MPa)(( BTSBTSBTSBTSBTSBTSBTSBTS BUFBUFBUFBUFBUFBUF88 BUFSBUFSBUFSBUFSBUFSBUFSBUFSBUFS SBSBSBSBSBSB UFUFUFUF#)#)#)#) 11  ...... 11 BBBB II II IIIIII Figure 21: Predicted 2008 test performances  CONCLUSIONS Numerical reservoir modeling was conducted for estimating gas and water production rates during the 2007 JOGMEC/NRCan/Aurora Mallik production research program.  Reservoir and wellbore history matching simulations reveal the following:  ?   Gas and water production rates during the first few hours of testing were negligibly small. ?   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 and 10-70 m3/d of continuous water production were achieved. ?   Instantaneous gas production of about 8,000 m3/d was observed when the bottomhole pressure was decreased to 6.9 MPa. ?   Total gas and water production throughout the test period are estimated at about 830 m3 and 20 m3, respectively. ?   During periods of pump shutdown, some of the water injected into the lower water disposal zone reversed-flowed upwards towards the test interval (presumably due to failure of a check valve) increasing the wellbore temperature. ?   Sand production during testing may have created relatively high permeability conduits (e.g. wormholes) resulting in significantly enhanced formation permeability near the wellbore, promoting higher than expected rates of gas production. ?   The area of MH dissociation is estimated at about 7-10 m from the well in the lateral direction and at about 4 m above and below the perforation interval in the vertical direction.  Furthermore, subsequent numerical simulation using the history matched reservoir model predicted the performances of the planned 2008 production test as follows:  ?   Upon achieving the initial scheduled reduction in bottomhole pressure, generally high rates of gas and water production are expected to persist for about one day, reflecting the effect of enhanced near-wellbore permeability. ?   Gas and water production rates become stable at about 2,000 m3/d and 40m3/d respectively, after 1-2 days following stabilization of the bottomhole pressure.  ACKNOWLEDGMENTS This work was financially supported by the Research Consortium for Methane Hydrate Resources in Japan (MH21 Research Consortium) on the National Methane Hydrate Exploitation Program by the Ministry of Economy, Trade and Industry (METI).  The authors gratefully acknowledge these agencies for their financial support and permission to present this paper.  The authors wish to thank the Japan Oil Engineering Company, the University of Tokyo, Japan Oil, Gas and Metals National Corporation, the National Institute of Advanced Industrial Science and Technology, the Geological Survey of Canada and Natural Resources Canada for their technical support.  REFERENCES [1]  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. [2] Fujii T, Takayama T, Dallimore SR, Nakamizu M, Mwenifumbo J, Kurihara M, Yamamoto K., Wright J.F. and  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. [3] Fujii K, Cho, B, Ikegami T, Sugiyama H, Imasato Y, Dallimore SR and 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. [4]  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 presented at 2008 Offshore Technology Conference held in Houston, Texas, U.S.A., 5?8 May 2008. [5]  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. In: S.R. Dallimore, T.S. Collett, editor. Scientific Results from the Mallik 2002 Gas Hydrate Production Research Well Program, Mackenzie Delta, Northwest Territories, Canada, Geological Survey of Canada Bulletin 585, 2005. [6]  Masuda Y, Naganawa S, Ando S, Sato K. Numerical calculation of gas-production performance from reservoirs containing natural gas hydrates. Paper SPE 38291, Proceedings of Western Regional Meeting, Long Beach, California, 1997. [7]  Masuda Y, Fujinaga Y, Naganawa S, Fujita K, Sato K, Hayashi, Y. Modeling and experimental studies on dissociation of methane gas hydrates in Berea sandstone cores. Presented at 3rd International Conference on Gas Hydrates, Salt Lake City, Utah, 1999. [8]  Kim HC, Bishnoi PR, Heidemann RA, Rizvi SSH.  Kinetics of methane hydrate decomposition, Chemical Engineering Science 1987; 42(7):1645?1653. [9]  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; in Scientific Results from the Mallik 2002 Gas Hydrate Production Research Well Program, Mackenzie Delta, Northwest Territories, Canada, In: S.R. Dallimore, T.S. Collett, editor. Scientific Results from the Mallik 2002 Gas Hydrate Production Research Well Program, Mackenzie Delta, Northwest Territories, Canada, Geological Survey of Canada Bulletin 585, 2005. [10] 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; in Scientific Results from the Mallik 2002 Gas Hydrate Production Research Well Program, Mackenzie Delta, Northwest Territories, Canada, In: S.R. Dallimore, T.S. Collett, editor. Scientific Results from the Mallik 2002 Gas Hydrate Production Research Well Program, Mackenzie Delta, Northwest Territories, Canada, Geological Survey of Canada Bulletin 585, 2005.  

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