Overview of thermal-stimulation production-testresults for the JAPEX/JNOC/GSC et al. Mallik5L-38 gas hydrate production research well

S.H. Hancock1, T.S. Collett2, S.R. Dallimore3, T. Satoh4, T. Inoue5,E. Huenges6, J. Henninges6, and B. Weatherill1

Hancock, S.H., Collett, T.S., Dallimore, S.R., Satoh, T., Inoue, T., Huenges, E., Henninges, J., andWeatherill, B., 2005: Overview of thermal-stimulation production-test results for the JAPEX/JNOC/GSCet al. Mallik 5L-38 gas hydrate production research well; in Scientific Results from the Mallik2002 Gas Hydrate Production Research Well Program, Mackenzie Delta, Northwest Territories,Canada, (ed.) S.R. Dallimore and T.S. Collett; Geological Survey of Canada, Bulletin 585, 15 p.

Abstract: The thermal-stimulation test conducted on the JAPEX/JNOC/GSC et al. Mallik 5L-38 gashydrate production research well in March of 2002 was designed to increase the in situ temperature of a portionof a well defined and constrained gas hydrate reservoir above the gas hydrate stability point, while maintainingconstant pressure. Data collected, including surface and downhole instrumentation readings and data fromadvanced logging and seismic programs, were then used to calibrate numerical gas hydrate reservoir-simulation models and determine the kinetic and thermodynamic properties of the in situ gas hydrate.

The thermal-stimulation test was successful: bottomhole temperature was increased to greater than50°C during the test; gas from dissociated gas hydrate was produced, sampled, and flared at surface; andsignificant amounts of real-time downhole temperature and pressure data, as well as other scientificmeasurements, were obtained.

1APA Petroleum Engineering Inc., 1400–800 Fifth Avenue SW, Calgary, Alberta, Canada T2P 3T62United States Geological Survey, Box 25046, MS-939, Denver, Colorado, U.S.A. 802253Geological Survey of Canada, 9860 West Saanich Road, P.O. Box 6000, Sidney, British Columbia, Canada V8L 4B24Japan Petroleum Exploration Co. Ltd., 2-2-20 Higashi-Shinagawa, Tokyo 140-0002, Japan5JNOC Technology Research Center, Japan National Oil Corporation,1-2-2 Hamada,Mihama-ku,Chiba 261-0025, Japan6GeoForschungsZentrum Potsdam, Telegrafenberg, D-14473 Potsdam, Germany

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Résumé : L’essai de stimulation thermique effectué en mars 2002 sur le puits de recherche sur la produc-tion d’hydrates de gaz JAPEX/JNOC/GSC et al. Mallik 5L-38 avait été conçu pour élever la température insitu d’une partie spécifique et bien délimitée d’un réservoir d’hydrates de gaz au-delà de la limite de stabilitédes hydrates de gaz, tout en maintenant une pression constante. Par la suite, les données obtenues, quicomprenaient les données d’usage recueillies par des instruments situés à la surface et dans le puits, demême que des données recueillies au moyen d’appareils sophistiqués de diagraphie et de sismique, ont étéemployées pour accorder à la réalité des modèles numériques servant à simuler les réservoirs d’hydrates degaz, et pour déterminer les propriétés cinétiques et thermodynamiques des hydrates de gaz in situ.

L’essai de stimulation thermique a été une réussite : on a pu accroître la température au fond du puits àplus de 50 °C durant l’essai; on a produit, échantillonné et brûlé à la surface du gaz naturel provenant de ladissociation des hydrates de gaz; et on a généré, entre autres données scientifiques, une quantité considérablede mesures de température et de pression, acquises en temps réel dans le puits.

INTRODUCTION

The thermal-stimulation test conducted at the JAPEX/JNOC/GSCet al. Mallik 5L-38 gas hydrate production research well wasnot a production test in the normal oilfield sense, in that it wasnot designed to evaluate a potential production method or toprove the commercial viability of the gas hydrate deposit.The objective of the test was to observe the dissociation of awell defined and geologically constrained gas hydrate inter-val at temperatures above the gas hydrate stability point,while maintaining constant pressure. The results of this testwould then be used to calibrate numerical-simulation modelsto determine the in situ kinetic and thermodynamic propertiesof the gas hydrate (Satoh et. al., 2005).

As discussed in Satoh et al. (2005), the method selectedfor the thermal-stimulation test at the Mallik 5L-38 well was asimple hot-water circulation system. Advantages of this methodincluded 1) the simple and reliable downhole and surfaceequipment; 2) the ability to maintain relatively constantdownhole pressure and temperature; and 3) the elimination of

many flow-assurance issues associated with more complexthermal-stimulation methods (such as reforming gas hydratefurther uphole, freezing, unsteady-state gas production, etc.).Heat transfer into the reservoir would be primarily by con-duction, although it was recognized that some fluid movementin the dissociated gas hydrate region would contribute to theconvective distribution of heat energy into the reservoir. Itwas anticipated that, as dissociation continued, pressure inthe dissociated (free) gas region would build up and over-come the hydrostatic pressure in the wellbore (even thoughthe circulating pressure was above the apparent reservoirpressure), thus releasing gas to surface.

In addition to the surface and downhole instrumentationand data-collection programs associated with a typical pro-duction test, the Mallik 5L-38 program included a number ofadvanced monitoring and investigation tools and services,including 1) mass-flow meters to measure the anticipated lowand unsteady-state gas-production volumes; 2) a fibre-opticdistributed temperature sensor (DTS) system installed on theoutside of the production casing (Fig. 1; Henninges et al.,

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Figure 1. Schematic diagram, geophysical logs, and core description for the thermal-test interval,JAPEX/JNOC/GSC et al. Mallik 5L-38 gas hydrate production research well. Abbreviations: CCL,casing collar locator; DPHZ, density porosity; CCL, casing collar locator; DTS, distributed temperaturesensor; GR, gamma ray; HDAR, calliper; KB, kelly bushing; NPHI, thermal neutron porosity; Sh, gashydrate saturation; TCMR, total combinable magnetic resonance porosity.

2005), which provided real-time temperature profiles fromsurface to below the gas hydrate thermal-test interval; 3) a chem-ical tracer in the thermal-circulation fluid to detect dilution; 4)continuous online gas-chromatograph readings (Wiersberget al., 2005); 5) a gas-sampling program for conventional andisotope analyses (Lorenson et al., 2005); 6) cross-well tomogra-phy and other seismic investigations (Bauer et al., 2005;Kleinberg et al., 2005); and 7) a post-test, cased-hole loggingprogram with Schlumberger’s Reservoir Saturation Tool (RST)™and Cased Hole Formation Resistivity Tool (CHFR)™, todetermine the radius of gas hydrate dissociation (Anderson etal., 2005).

TEST INTERVAL

Figure 1 contains a schematic diagram of the downhole con-figuration for the thermal test, together with representativegeophysical logs and core descriptions (Collett et al., 2005;Medioli et al., 2005). The gas hydrate interval selected for theproduction tests (906–924 m; all depths are measured fromthe kelly bushing, approximately 4.6 m above ground level)was a relatively uniform, clean sandstone with gas hydratesaturations ranging from 70 to 80%. The exception to this wasan anomalous conglomerate layer, from 913 to 915 m, with aninitial gas hydrate saturation of approximately 50 to 55%.

The upper boundary of the thermal-test zone was a shale,approximately 2 m thick. The lower boundary was a thinnershale, less than 1 m thick. Below this lower boundary shale, agas-hydrate-bearing sandstone, approximately 4 m in thickness,overlies a thin shale section and a fractured, water-bearing,carbonate-cemented sandstone layer. The completion logsindicated good cement quality above and below the selectedtest interval.

The test interval was perforated from 907 to 920 m toavoid disturbance of the boundary beds and especially toavoid breaking into the fractured water-bearing zone, whichwould have effectively ended the experiment due to loss ofcirculation fluids. The circulation string was landed belowthe perforations at approximately 921 m (Fig. 1), on the basisthat the heat-affected interval would be limited to just abovethe lower bounding shale, leaving the gas hydrate below theshale undisturbed.

INITIAL COMPLETION

Two full loops of DTS cables were installed outside and onopposite sides of the production casing, and cemented inplace. After installation, only one DTS cable remained func-tioning below the thermal-test zone (Fig. 1). Details on theinstallation procedure, an explanation of the DTS technol-ogy, and an analysis of the geothermal conditions can befound in Henninges et al. (2005). In order to ensure survivalof the DTS cable during the test, the 13 m thermal-test inter-val (907–920 m) was perforated with a 54 mm SchlumbergerPower Enerjet™ perforating gun (19.7 shots/m [spm], zerodegree phased). The effect of the gas-hydrate-filled porosity

on the performance of the perforation charges is not wellunderstood compared to their performance in normal porousmedia. The objective, however, was only to provide holesthrough the casing and cement sheath. It was assumed thatgas production rates would be sufficiently low that skin dam-age and resulting pressure loss associated with perforationefficiency and a tortuous, nonradial flow path into the wellbore(from the zero degree phasing) would have a minimal effecton the test.

The perforation event was clearly observed on the DTSthrough both thermal and mechanical effects. The instanta-neous temperature pulse associated with perforating resultedin a temperature increase along the perforated interval ofapproximately 6°C, as indicated in Figure 2. Subsequently,

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Figure 2. Distributed temperature sensor (DTS) responseduring perforation, JAPEX/JNOC/GSC et al. Mallik 5L-38 gashydrate production research well. Abbreviations: KB, kellybushing; CNTS, cleaned non-temperature sensitive signal(i.e. the signal intensity of the Stokes band wavelengths(non-temperature sensitive) with the background opto-electronicnoise subtracted (cleaned); this signal usually serves as areference for fibre integrity; the attenuation was calculatedfrom the ratio of the local and initial signal intensities in unitsof decibels per metre).

the temperature decreased slightly in the perforation intervaland simultaneously increased above the perforated interval,due to fluid convection inside the casing. At the same time thetemperature increased, a change in the attenuation of thebackscattered laser signal was observed, also illustrated inFigure 2. The increased attenuation at the top and bottom ofthe perforated interval is attributed to mechanical stress,which was exerted on the DTS sensor cable as a result of theinstantaneous pressure pulse associated with perforating. Onthe basis of the observed changes, the DTS depths could becorrelated with the log and core depths for the well. Becausethe observed changes have no sharp transitions, an uncer-tainty of ±0.25 m of the indicated DTS depth values should beassumed. The radial position of this DTS cable with respect tothe single-phase perforations, however, is not known.

After wireline perforating was complete, the 88.9 mmproduction tubing was run in the hole along with a retrievablepacker. A thermal-expansion joint, to allow tubing move-ment without creating excessive packer loads, was run imme-diately above thepacker.Dualelectronicpressureand temperaturegauges were installed one joint above the expansion joint.The packer was landed above the perforations with the centreelement at 902 m (based on measured depth), with the expan-sion joint one-third closed. The overall length of the packerand expansion joint assembly was 4.8 m and, given the steelconstruction and large diameter of both components, thepacker assembly did not provide a distinct thermal break.There was, however, sufficient character in the DTS tempera-ture profile to locate the packer within 1 m of the measureddepth, above the perforations. Likewise, the 42.1 mm circula-tion string was landed approximately 1 m below the perfora-tions, based on both measured depth and indications from theDTS temperature profile.

The packer fluid was a clean potassium-chloride polymerdrilling mud, with no solids content. The yield point of themud was sufficient to prevent the formation of eddy currentsin the annular space; this significantly reduced heat transferfrom the tubing into the formation, compared to fresh water.

The polymer mud was also used as the thermal-circulationfluid. The mud density provided a hydrostatic pressure of9830 kPa at the perforation depth (compared to the estimatedformation pressure of 9640 kPa). The polymer in the mudacted as a friction reducer, so circulating pressures across theperforations were generally less than 1000 kPa above themud hydrostatic pressure.

The thermal pulse of the perforation was probably signif-icant enough to dissociate a small amount of gas hydrate.Nevertheless, no free gas was detected at surface and no fluidloss or gain was observed in the well between perforation andthe start of the thermal test.

SURFACE-FACILITY OPERATION

Figure 3 illustrates the closed-loop process used to thermallystimulate the gas hydrate interval. Starting at the wellhead,heated brine fluid was injected down a 42.1 mm circulatingstring. Fluid was then circulated past open perforations, and thefluid and produced gas were returned to surface in the annu-lus between the 42.1 mm circulating string and the 88.9 mmtubing string. The fluids and produced gas were separated in ahigh-pressure and low-pressure separator. Gas was measuredand flared, and the circulating fluids were transferred to aninsulated atmospheric tank. Supplementary cooling was thenused to adjust tank temperatures to an acceptable level for thecement-pump intake. The brine was then repressurized usingthe cement pump, passed through a high-pressure line heater,and injected downhole to continue the cycle.

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Figure 3. Schematic diagram of the thermal-test process, JAPEX/JNOC/GSC et al. Mallik5L-38 gas hydrate production research well. Abbreviation: DTS, distributed temperaturesensor.

The wellbore circulation volume was approximately 4.1 m3,and the total active circulation-system volume, includingwellbore, piping, tanks, and separators, was approximately48.5 m3. With an average circulation rate of 348 L/minute,the average circulation time for the well was approximately11.8 minutes. During the thermal test (123.65 hours), the wellwas circulated approximately 630 times, and the entire fluidvolume was circulated approximately 53 times.

Surface data collected during the thermal test includedwellhead-injection pressure, temperature, and rate; return-fluidpressure and temperature; separator pressures; gas-meterreadings, including the Vortex gas meter (50.8 mm high-rategas meter), plus the high-pressure 12.7 mm and 6.4 mmmass-flow meters, and the low-pressure 6.4 mm and 2.5 mmmass-flow meters.

Data-collection frequency ranged from the 1-second intervalscollected automatically by the surface data-acquisition com-puter (for the mass-flow meters) to manual readings input onan occasional basis (for the surface-fluid inventory).

CIRCULATION RATES, PRESSURES,AND TEMPERATURES

Figure 4 illustrates the wellhead injection and return-fluidtemperatures, as well as the circulation rate and surface-fluidinventory. Note that time zero has been designated as the startof circulation for the test. The following points can be observedon this figure:

• The surface-return temperature was generally within 10°Cof the injection temperature, a heat loss expected due tothe use of noninsulated tubing strings.

• Except for the points noted below, the small oscillation inthe surface temperature was due to manual operation ofthe mud-chiller system used to control inlet-fluid temperatureto the cement (circulation) pumps.

• Surface temperatures declined at 6.6 hours into the testdue to line-heater problems (circulation downhole continuedthrough this period). Line-heater operation was restoredat 7.9 hours, and surface temperatures increased thereafter.

• Gas was detected at surface by gas chromatograph at 2.1 hoursinto the test. At 20.5 hours, the mass-flow meters becamesaturated with water from condensation in the gas line,and the circulation system was shut down to assess andcorrect the problem (injection and return temperatures arenoted as declining during this time period, but thesereflect surface conditions only). At 22.3 hours, circulationwas restored with the mass-flow meters back on line.

• At 65.7 hours, a power failure resulted in a short shutdownof the line heater. Power was restored at 66.3 hours, duringwhich time surface temperatures dropped approximately10°C.

• At 88.6 hours, the surface temperature was reduced (andcontrolled by automatic thermostat) in an attempt toreduce liquid carryover in the gas lines.

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Figure 4. Surface temperatures, surface volume, and circulation rate during thermal stimulation of theJAPEX/JNOC/GSC et al. Mallik 5L-38 gas hydrate production research well.

• At 103.6 hours, an electrical system problem resulted inan extended shut-down of the line heater, resulting in asignificant surface temperature decline (circulation wasmaintained during the shut-down, so some heat was extractedfromthewell).Line-heateroperationwasrestoredat108hours.

• The surface-volume inventory (consisting of the horizontalatmospheric tank plus low-pressure and high-pressureseparator liquid volumes) was manually recorded throughoutthe test, and appears to vary by approximately ±5 m3.Although this may indicate that some fluid was intermittentlyproduced from or lost to the gas hydrate interval, thereappears to have been no significant change in fluid volume.

Figure 5 illustrates the surface-injection and flowing-wellhead pressures and the circulation rate during the test.The following points can be observed on this figure:

• Surface-injection pressures were generally in the 13 000to 14 000 kPa range.

• Flowing-wellhead pressures were controlled by the separatorpressure. Pressure in the first stage of separation was generallyheldatapproximately200kPaforgas-measurementpurposes.

SURFACE GAS PRODUCTION

As anticipated during planning of the test, there was neversufficient gas volume or pressure at surface to maintain a steady-state operation of the separation vessels or normal orifice-typemetering equipment. The separators therefore acted as accu-mulators, and gas was released and measured on an intermittentbasis, as controlled by the PLC (programmable logic controller)and the control-valve–mass-flow-meter arrangement.

Sufficient pressure was maintained in the separator ves-sels to allow the transfer of fluids from the high-pressure tothe low-pressure separator, and from the low-pressure sepa-rator to the surface tank. Due to the low pressures andgas-flow rates, timing of the fluid-transfer process was manu-ally controlled. Dumping fluids from one vessel to the nextsignificantly affected separator pressures, which in turn affectedthe timing of the gas releases. Therefore, the corrected gasrates and total cumulative gas volumes do not necessarilyreflect the instantaneous production from the gas hydrateinterval.

Figure 6 illustrates total gas rates measured by the mass-flowmeters at 1 minute intervals throughout the thermal-stimulationperiod. The cumulative gas production versus time and thecalculated hourly average gas-production rate are also shown.The raw data include a very few readings that were affectedby liquid carryover in the mass-flow meters. These erroneousdata points were removed and, where required, gas-productionreadings were interpolated using gas rates from periods immedi-ately before and after the affected readings. The cumulativegas-production curve and the calculated gas-production rateconsider only these corrected data. The calculated gas rateindicates two minor and one major gas-production peaks (at10 and 80 hours, and 45 hours, respectively).

At the end of the thermal-stimulation test, the cumulativegas production was 468 m3. After the circulation was stopped,the well was allowed to cool naturally for approximately 8hours. Subsequently, for approximately the next 26 hours, thewell was killed by circulating with chilled weighted fluiduntil gas production ceased and the well stabilized. Duringthe cool-down and well-kill periods, an additional 48 m3 ofgas were recovered, an amount that is not included in Figure 6.

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Figure 5. Injection pressure, flowing-wellhead pressure, and circulation rate during thermal stimulation ofthe JAPEX/JNOC/GSC et al. Mallik 5L-38 gas hydrate production research well.

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Figure 6. Gas production during thermal stimulation of the JAPEX/JNOC/GSC et al. Mallik 5L-38 gashydrate production research well. ‘Raw meter readings’ are the total gas rates measured by the mass-flowmeters; red curve, daily production rate; blue curve, cumulative production.

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Figure 7. Downhole pressure and temperature during thermal stimulation of the JAPEX/JNOC/GSC et al.Mallik 5L-38 gas hydrate production research well.

DOWNHOLE PRESSURE-TEMPERATURE DATA

Figure 7 illustrates the pressure and temperature data from thedownhole quartz gauge located at 876.4 m KB (30.6 m abovethe top of the perforations). Data were collected at 4 secondintervals throughout the test. The following points can beobserved on this figure:

• Recording time started approximately 51 hours prior tothestartof the test (0hours represents thestartof circulation).

• Prior to circulation, the initial hydrostatic pressure was9434 kPa at gauge depth. This is equivalent to 10.76 kPa/m,or an equivalent density of 1097 kg/m3 (slightly higherthan the 1070 kg/m3 from the mud report). At the midpointof perforations (MPP) at 913.5 m, the initial hydrostaticpressure would have been 9830 kPa.

• During circulation, the flowing bottomhole pressure wastypically in the order of 10 400 kPa at gauge depth, or10 800 kPa at MPP (neglecting friction, which wasinsignificant on the return flow path). The overbalance(over gas hydrate pore pressure) during circulation wastherefore in the order of 1200 kPa.

• Prior to the thermal test, the initial temperature at gaugedepth was 7.7°C, having risen approximately 1.7°C in theprevious 24 hours (wellbore temperatures were disturbeddue to fluid circulation during completion operations).

Several pressure spikes were recorded throughout the cir-culation test, some of which may have resulted in instanta-neous pressures above the fracture pressure of the gas hydrate.There are no obvious events in the test report associated withthese pressure spikes other than start-up of the cement pumpfor circulation. These pressure spikes may therefore be due toa water-hammer effect (due to the start-up of a large posi-tive-displacement pump), or possibly partial plugging on theflow path (with solids, gas hydrate or through freezing),which was subsequently broken down.

Other than the hydrostatic information, no analyzablepressure-transient data were collected from the downholegauges. Given the very low volumes of gas produced, multiphaseflow analysis of the return fluid flow provided no usefulinformation.

DISTRIBUTED TEMPERATURESENSOR (DTS) DATA

During the thermal-stimulation experiment, the temperaturevariations along the Mallik 5L-38 wellbore were continuouslymonitored by GeoForschungsZentrum Potsdam (Henningeset al., 2005), using the Sensa DTS 800 M10 fibre-optic dis-tributed temperature sensing (DTS) system. In the Mallik5L-38 well, temperatures were measured from the wellheaddown to a depth of 938.6 m, approximately 15 m below thebottom of the thermal-stimulation zone. Distributed tempera-ture sensor logging started 1 day after installation of the

production casing and continued for a period of 17 days, fromFebruary 24, 2002 to March 12, 2002, which spanned theentire thermal-production testing program.

Temperature profiles were recorded at incremental depthsof 0.25 m along the entire wellbore, with a sample frequencyinterval of 2.5 minutes. For a given DTS installation, the pre-cision or random error of the DTS temperature data dependsmainly on the integration time over which the data are aver-aged. For the chosen sampling interval of 2.5 minutes, themeasured temperatures have a precision of ±0.30°C. Throughthe use of appropriate postprocessing methods (e.g. averag-ing, smoothing) the precision can be improved to ±0.05°C(Henninges et al., 2005).

During the initial 36 hours of thermal circulation, downholetemperatures increased gradually from approximately 8°C to52°C (Fig. 8), as predicted by the Wellcat™ Prod wellbore-thermal-simulation program (Satoh et al., 2005). After that time, thebottomhole temperature was held relatively constant by adjustingsurface-injection temperatures and circulation rates. Interrup-tions to the surface operations (discussed above) are generallyreflected in the bottomhole temperature (Fig. 5).

A characteristic pattern of the temperature distributionalong the perforated gas hydrate interval developed early inthe test and underwent only minor changes until the end of thecirculation. Temperature profiles during selected time peri-ods from the start of circulation are illustrated in Figure 8,which includes a schematic diagram of the thermal-stimulationset-upanddownholegeophysicalandgeological logs (Collettetal.,2005; Medioli et al., 2005). There was no correlation betweentemperature change and gas production evident in any of thetemperature profiles, but this is to be expected given the lowmass of produced gas.

The highest DTS temperatures (57.8°C) were generallyobserved at the bottom of the stimulation zone at 920.2 m,approximately 1 m above the bottom of the injection tubing(Fig. 8, 87.7 hour temperature profile). Temperature readingsin this region were probably controlled by a number of factors,including 1) turbulence and direct impingement of circulationfluid on the casing at the bottom of the thermal-stimulationzone; 2) formation properties, including the creation or pres-ence of potentially open fractures, as discussed in Kurihara etal. (2005); and 3) fluid migration in the reservoir.

Farther uphole, toward the centre of the gas hydrate interval,the temperature decreased approximately 5.1°C opposite theconglomerate layer (Fig. 8, 87.7 hour profile). Above the con-glomerate, the temperature increased gradually to approximately55.5°C at 903.3 m, which appears to be the location of thebottom packer element. Above the production-packer assem-bly, temperatures rapidly decreased to approximately 30°Cwithin an interval of approximately 4 m. A temperaturedecrease was evident at approximately 900 m, in the vicinityof a 2 m gas hydrate interval hydraulically isolated from themain gas hydrate test interval.

Figure 9 illustrates the DTS temperature profile over thegas hydrate test interval during approximately 8 hours of natu-ral cooling at the end of the thermal test; temperature; and,finally, profiles during the well-kill operation when chilled

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Figure 8. Typical distributed temperature sensor (DTS) response during thermal stimulation of theJAPEX/JNOC/GSC et al. Mallik 5L-38 gas hydrate production research well. Abbreviations: GR, gammaray; KB, kelly bushing; Sh, gas hydrate saturation.

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Figure 9. Distributed temperature sensor (DTS) response during cool-down of the JAPEX/JNOC/GSC etal. Mallik 5L-38 gas hydrate production research well.

(-4 to -6°C), weighted drilling fluids were circulated. Althoughthe bottom of the thermal-test interval (approx. 920–921 m)consistently recorded the highest temperatures during circu-lation, this region also experienced the most rapid temperaturecool-down when circulation was stopped. In addition, tem-peratures in the sump below the bottom of the 42.1 mm circu-lation string, which were relatively constant during the circulationprocess, began to rise by several degrees. Both of these eventswere likely due to a combination of factors, including 1) fluidmovement in existing fractures, which resulted in a larger localdissociation radius (Anderson et al., 2005); and 2) convectionof fluids inside the wellbore and/or formation.

The observed changes in temperature are mostly influ-enced by the strength of the heat source, including 1) circulationrate and temperature of the fluid, and local variations inside theborehole (flow conditions, completion geometry); 2) heattransfer from the borehole into the formation; 3) thermal proper-ties of the formation; and 4) latent heat effects (i.e. endothermicprocess of gas hydrate dissociation).

A possible cause of variations in the measured tempera-ture with depth is the position of the DTS cable within thecement annulus. At the locations of the casing connectors(Fig. 1, CCL log), the DTS cable is attached directly to thesteel casing. Between the connectors, however, a variation ofthe radial position of the DTS cable within the cementbetween the casing and the borehole wall is possible. Duringthe thermal stimulation, a high temperature gradient wasexpected in a radial direction away from the borehole axis,possibly resulting in some variability in measured tempera-tures with depth. There is no obvious correlation, however,between the observed temperature changes and the locationsof the casing collars within the test interval. This suggests thatthe installation of the DTS cables and the location of the cableclampshadnosignificant influenceonthemeasured temperatures.

In general, the observed temperature distributions haveno strong correlation with lithological changes or gas hydratesaturation. Nevertheless, despite a slight offset in depth, theoccurrence of a low-temperature zone around 913.6 m sug-gests a connection to the gas-hydrate-bearing conglomeratelayer between approximately 913 and 915 m.

In a thermally stimulated section of wellbore, a low-temperature region would be expected across a formation ofhigher thermal conductivity, which would enhance the heatloss from the wellbore; alternatively, a low-temperature regionmight represent a mobile-fluid zone. Nevertheless, even thoughthe conglomerate layer had a lower initial gas hydrate satura-tion than the surrounding sandstone, it was expected that,overall, the thermal conductivity of the conglomerate wouldbe lower due to poor sorting and limited grain contact, and, insome of the conglomerate lenses, the gas hydrate forming thematrix (Wright et al., 2005). In addition, as the gas hydratedissociated, the natural gas and fluid saturations in the near-wellbore area would have changed throughout the test, whichwould dynamically change the near-wellbore thermal con-ductivities of all layers in the test interval. Other evidence,such as the results from the post-test cased-hole logging pro-gram (Anderson et al., 2005), suggest that only limited disso-ciation occurred in the conglomerate layers, which supports

the low-conductivity assumption. This complex issue hasbeen investigated as part of the thermal-simulation studies(Kurihara et al., 2005; Moridis et al., 2005).

Figure 10 compares the average of the DTS readings acrossthe face of the perforations (907–920 m) with the single-pointelectronic-temperature-gauge reading from above the packer.The electronic-gauge readings were generally lower than theaverage DTS readings (expected due to the location of theelectronic gauge higher in the wellbore); however, there are anumber of time periods where the electronic-gauge reading issignificantly above the average DTS reading. Although thevariations in the electronic-gauge temperature would nor-mally indicate a change in mass-flow rate, there is no strongcorrelation with either changes in gas-production rate or changesin circulation rate that can account for these temperature spikes.

Even in times of high gas production, only minor devia-tions from the established temperature distribution occurred.Even when the highest rate of gas production occurred (Fig. 6),only a slight decrease in temperature of approximately 0.8°Cwas observed at around 910.6 m (Fig. 8, 51.8 hour and 53.6hour temperature profiles).

FLUID SAMPLES

During the thermal-stimulation production test at the Mallik5L-38 well, the produced gas was analyzed online with a massspectrometer, a gas chromatograph, and a radon detector(Wiersberg et al., 2005). The gas samples taken during thethermal test were predominantly methane, although manyhad high nitrogen fractions (all separators were purged withnitrogen prior to the start of the test and, given the low flowrate of natural gas, displacement of this nitrogen would nothave been efficient). The online gas analysis also revealedshort-term variations in carbon dioxide, helium, and higherhydrocarbons. The variations in carbon dioxide correlatepositively with the temperature of the circulating brine, as thehigh solubility of carbon dioxide is strongly temperaturedependent. The variations in the helium and hydrocarbonconcentrations correlate directly and can be explained by ver-tical heterogeneity in the gas composition of the thermal-testinterval.

Samples were collected as follows:

• 26 pressurized gas samples (500 cm3) at the gas outletfrom the high-pressure separator

• 94 pressurized gas samples (75 cm3) at the gas outlet fromthe high-pressure separator, which were subsequentlysubsampled to atmospheric containers for isotope analyses(Lorenson et al., 2005)

• 99 samples of circulation fluid for analysis of potassiumand chloride concentrations

• 36 sample pairs of circulation fluid for analysis of chemicaltracer

• 2 samples of solids/mud taken from the high-pressureseparator at the end of the test

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GSC Bulletin 585

CIRCULATION-FLUID ANALYSES

Figure 11 illustrates the change in the calculated potassiumion (K+) concentration in the circulation fluid versus time.The measurement technique has an associated error of ±4%.A slight declining trend is apparent, indicating dilution on theorder of approximately 1.7%. Assuming that there was no netfluid gain during the thermal test (only exchange of fluid) anda total system volume of 48.5 m3 (including active surfacevolume, plus well and pipe volumes), this would indicate thatapproximately 0.8 m3 of formation water was mixed into thecirculation fluid.

Figure 12 illustrates the change in the calculated chlorideion (Cl-) concentration in the circulation fluid versus time.The measurement technique has an associated error of ±1.7%.In this case, a slight increasing trend is apparent, indicatingmixing of the circulating fluid with a more chloride-richwater. The trend line shown indicates an increase in chlorideconcentration of approximately 2.7%.

The circulation fluid was also traced using fluorinatedbenzoic acid (FBA) at an initial concentration of approxi-mately 4500 ppb. Although FBA can be detected in concen-trations as low as 50 ppt, repeated measurements on identicalsamples indicated measurement errors on the order of ±2.75%.If the sample pairs that have significantly different readingsare compared, the amount of dilution that is predicted to haveoccurred is significantly greater than that indicated by the ionanalyses.

On the basis of the fluid-sample analyses and tracer analyses,although some water was expelled into the wellbore and off-set by the loss of circulating brine into the formation (circula-tion fluid volume remained relatively constant), the total amountof water released into the wellbore cannot be estimated withany degree of confidence.

FORMATION SOLIDS ANALYSES

Formation solids were recovered both during and after thethermal test. Solids were detected by centrifuge separation ofwellhead choke samples taken throughout the circulationperiod. Typical solids contents were in the range 1.5 to 2.5%,with several readings of 17 and 19%. It should be noted, how-ever, that these data are relatively limited, so it is not possibleto estimate with any degree of certainty the amount of solidsproduced from the formation during the circulation period.

Two 1 L samples of solids were recovered from the high-pressure separator at the end of the thermal test. Subsequentanalysis of these samples indicated predominantly mud sol-ids, with 14 to 29% quartz and 5% clay minerals. Samples ofsolids detected in the tracer-fluid samples were also analyzedand also indicated that quartz and clay formation solids hadbeen produced throughout the thermal test.

In addition, during post-test cased-hole logging, it wasdetermined that approximately 11 linear metres of fill, assumedto be primarily formation solids (with minor amounts of per-foration debris), had accumulated on top of the suspensionplug–cement at approximately 948 m (top of fill at approximately

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S.H. Hancock et al.

0

5

01

51

02

52

03

53

04

54

05

55

06

08106104102100108060402002-

Time (hours)

Tem

pera

ture

(˚C

)

eguag ztrauq RME drofrehtaeW

GeoForschungsZentrum DTS mean temperature

:etoNBKm 0.029-0.709 morf egareva STD -

BKm 4.678 at eguag ztrauQ -

Figure 10. Comparison of average distributed temperature sensor (DTS) and quartz-gauge temperaturesduring thermal stimulation, JAPEX/JNOC/GSC et al. Mallik 5L-38 gas hydrate production research well.Abbreviation: EMR, electronic memory recorder.

937 m). This volume equates to approximately 0.22 m3 offormation solids, not accounting for any differences in sorting/packing. Assuming a 222.3 mm wellbore diameter, this vol-ume would be equivalent, for example, to the first 22 mm offormation around the well over the 13 m test interval.

Formation solids were also produced during the thermaltest, with approximately 1200 kPa overbalance pressure beingmaintained during circulation. The annular velocities duringcirculation were sufficient to transport medium-grained sand

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GSC Bulletin 585

00003

00523

00053

00573

00004

041021001080604020

Circulation time (hours)

K+ c

once

ntra

tion

(mg/

L)

Figure 11. Potassium ion concentration in the circulation fluid during thermal stimulation, JAPEX/JNOC/GSCet al. Mallik 5L-38 gas hydrate production research well.

Circulation time (hours)

00003

00523

00053

00573

00004

041021001080604020

Cl- c

once

ntra

tion

(mg/

L)

Figure 12. Chloride ion concentration in the circulation fluid during thermal stimulation, JAPEX/JNOC/GSCet al. Mallik 5L-38 gas hydrate production research well.

to surface, so the fill in the sump may consist of heavier parti-cles (perforation debris, very coarse sand, or gravel), or maybe sand that slumped during a shut-in period.

FACTORS AFFECTING GAS PRODUCTION

The test, as originally envisioned, involved simply heating aconfined gas hydrate layer with relatively uniform propertiesabove the gas hydrate dissociation temperature and measuringthe gas production. The gas-production values discussed aboverepresent the gas produced to surface and do not represent thetotal amount of gas hydrate that dissociated. Assuming all gaswas initially in gas hydrate form, the initial free-gas saturationin the test interval would be zero. After dissociation, a newphase (free gas) would have been introduced and, dependingupon the reservoir rock properties, a residual free-gas satura-tion (or higher) would remain. Assuming a 10% residual gassaturation, the amount of gas that could be stored in the porespace of the sandstone where gas hydrate has been dissociatedcould be in the order of 50 m3, or approximately 10% of theamount of the total gas measured at surface.

This reservoir storage phenomenon could possibly alsobe used to explain the cyclic nature of the production curvefor the thermal test. As the radius of dissociation increasedthroughout the test, the gas evolved from the gas hydratewould build up pressure until it overcame the hydrostaticbackpressure of the circulating hot brine. At a critical pressure,the gas would unload from the wellbore, resulting in a lighterfluid column in the well, and gas would continue to flow untila second, lower critical pressure was reached. The hydro-static pressure of the circulating fluid would increase as thegas production rate declined and gas would then begin toaccumulate in the reservoir until a critical pressure was againreached, and the cycle would begin again.

A critical consideration in this theory, however, is that thereservoir storage volume would change with time as theradius of dissociation increased. Increasing storage volumeswould increase the formation storage capacity and bufferingeffects on the release of gas. Numerical-simulation modellingwas required to determine the extent of the effect on reservoirstorage of the observed production profile (Kurihara et al.,2005; Moridis et al., 2005). Among other things, the modelhad to consider

• changing gas hydrate dissociation radius with time;

• changing gas hydrate, water, and gas saturations;

• multiphase fluid flow;

• changing pressures in the reservoir and the wellbore(backpressure will not be constant); and

• changing temperature of gas in the gas hydrate dissociationarea.

The existence of an initial fluid permeability in a naturallyoccurring gas hydrate in the low microdarcy range is a possi-bility, based on interpretation of test results from the Mallik5L-38 well using Schlumberger’s Modular Formation Dynamics

Tester™ (MDT; Hancock et al., 2005). Although this requiresa separate investigation, the effects of basic reservoir parame-ters on interpretation of the thermal-test results are veryimportant. Assuming an initial hydrostatic pressure of 9630 kPaand an injection pressure of 10 800 kPa (typical backpressureduring circulation), a relatively significant amount of gas couldhave been injected into the formation, in addition to that producedto surface during the thermal-stimulation test. This phenome-non was also a major consideration in the production-testnumerical simulation (Kurihara et al., 2005).

Subsequent to the thermal test, investigation of other welldata, including logs, cores, and MDT test results, determineda number of important factors that must be considered fortheir potential effects on the thermal-test results. These include1) the effects of low relative permeabilities to fluids in the gashydrate zone (Hancock et al., 2005); 2) an unusually low frac-ture pressure and/or fracture extension pressure, which mayhave allowed gas to break away from or into the thermal-testinterval (McLellan et al., 2005b); and 3) the presence of exist-ing open fractures in the test interval (McLellan et al., 2005a),which may have allowed both movement of gas out of thethermal-test interval and migration of thermal-circulationfluid into the reservoir.

SUMMARY

It is beyond the scope of this paper to fully analyze theresponse of the gas hydrate to the thermal-stimulation test.Numerical-simulation studies, conducted by Kurihara et al.(2005) and Moridis et al. (2005), were used to evaluate the insitu formation properties and gas hydrate production response.These reservoir models had to consider dynamic reservoirstorage, changing fluid saturations, relative permeability effects,the effects of potential open and/or gas-hydrate-filled frac-tures, and the gas hydrate dissociation process. Other projectdata and studies, including core data, logging results, detailedfibre-optic temperature data, continuous gas chromatogra-phy, and cross-well tomography and other seismic data, werealso evaluated. The following major conclusions pertain tothe actual production-test procedures and data obtained:

• The thermal stimulation test at the JAPEX/JNOC/GSC etal. Mallik 5L-38 gas hydrate production research wellwas successful in meeting all planned objectives:

- The test was conducted safely without significantoperational problems, delays, injuries, or accidents,under extreme Arctic conditions.

- Gas was produced to surface.

- Gas samples were obtained.

- Good-quality production data, including surface pressureand temperature, downhole pressure and temperature,and temperature profiles from a fibre-optic distributedtemperature sensor (DTS) cable, were obtained throughoutthe test.

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S.H. Hancock et al.

• The DTS system provided invaluable data during theactual test operation, and was a key source of data for theinterpretation of the test results. Based on a review of alimited amount of DTS data, the following points arenoted:

- Average temperature across the face of the gas hydrateremained relatively constant at approximately 52.5°Cafter the wellbore was stabilized.

- The DTS temperatures were generally highest at thebottom of the circulation tubing, probably due toimpingement of the heated fluid on the casing at thebottom of the circulation string.

- The temperature profile across the face of the gashydrate differed by as much as 5°C, which may havebeen controlled by lithology or the flow of fluid andgas into and out of the formation.

- The thermally stimulated interval did not extend beyondapproximately 3 m below the perforated interval.

• The total thermal-stimulation (circulation) time was123.7 hours. The bottomhole temperature was increasedfrom 7.7°C to more than 50°C in approximately 36 hours.Thereafter, for the remainder of the thermal test, thebottomhole temperature was held at a relatively constant52.5°C (based on average DTS readings), with only minorfluctuations due to surface operating problems. Gas wasdetected at surface 2.1 hours after circulation had started.

• A total of 468 m3 of gas was produced to surface duringthe thermal test. An additional 48 m3 of gas were recoveredat surface during the well-kill operation. These valueswere corrected from field readings due to intermittentcarryover of water into the mass-flow meters.

• Due, in part, to the buffering effect of the large separatorvessels and the manual control of liquid levels in thosevessels, the instantaneous gas-production rates measuredduring the test were not necessarily representative of thewell-production rate. After correcting meter readings forliquid carryover and smoothing the production-rate dataover hourly periods, three main production events can beidentified during the test:

- Approximately 75 m3 of gas were produced in the firstevent (from 0 to 25 hours), with a peak rate in the orderof 140 m3/day.

- Approximately 255 m3 of gas were produced in thesecond event (from 25 to 55 hours), with a peakproduction rate in the order of 360 m3/day.

- Approximately 138 m3 of gas were produced in theremaining 68.7 hours (55 to 124 hours), with a peakproduction rate of 70 m3/d. The final production rateat the end of the test was in the order of 20 m3/d.

• The gas was produced into the wellbore, against backpressures (circulating pressures) approximately 1200 kPaabove the initial pore pressure in the gas hydrate testinterval.

• The gas measured at surface does not necessarily representthe total amount of gas dissociated during the thermalstimulation. The reservoir rock could have stored significantquantities of gas in the remaining pore space after dissociationof the gas hydrate. In addition, gas may have leaked orbeen injected into the formation, depending on the initialgas effective permeability in the gas hydrate.

• There was no significant gain or loss of circulating fluidvolume during the test, indicating that the wellbore anddissociated gas hydrate interval remained as a closedsystem (not in contact with a high-permeability zone).Subsequent analyses of brine and tracer concentrationsindicate that the circulation fluid was diluted with someamount of relatively fresh formation water (brine andfresh water mixed in both the reservoir and wellbore);however, the results are not conclusive and the amount ofdilution could not be determined.

• Formation solids were also produced into the wellbore,against circulating backpressures approximately 1200 kPaabove the initial hydrostatic pore-pressure conditions.Solids found in sample pairs taken during circulationwere primarily quartz with some clay minerals.

• Solids were also recovered in the separators after the testand again determined to be primarily quartz with some clayminerals. During final cased-hole logging operations, itwas also determined that approximately 11 linear metresof fill had accumulated on the suspension plug set belowthe perforations. Some of this fill would have been debrisfrom the perforation guns; however, the majority waspresumed to be either gravel or coarse-grained sand (thecirculating velocities were sufficient to lift medium-grainedsand to surface), or the result of formation slumpingduring a shut-in period.

• After circulation was stopped, the wellbore was allowedto cool naturally for approximately 8 hours while thetemperature decline was monitored with the DTS surfacereadout. An additional 26 hours of circulation with chilledfluids (including increased fluid weights), were requiredbefore gas hydrate dissociation ceased and the well wasconsidered dead.

ACKNOWLEDGMENTS

The authors acknowledge the international partnership thatundertook the Mallik 2002 Gas Hydrate Production ResearchWell Program: Geological Survey of Canada (GSC), JapanNational Oil Corporation (JNOC), GeoForschungsZentrumPotsdam (GFZ), United States Geological Survey (USGS),India Ministry of Petroleum and Natural Gas (MOPNG),BP-ChevronTexaco-Burlington joint-venture parties, andUnited States Department of Energy (USDOE). The programalso received financial support from the International ContinentalScientific Drilling Program (ICDP). The partnership acknowl-edges Imperial Oil Ltd. for granting use of their site lease.

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GSC Bulletin 585

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in order to determine the depth of gas hydrate dissociation during thethermal test in the JAPEX/JNOC/GSC et al. Mallik 5L-38 gashydrate production research well; in Scientific Results from theMallik 2002 Gas Hydrate Production Research Well Program,Mackenzie Delta, Northwest Territories, Canada, (ed.) S.R. Dallimoreand T.S. Collett; Geological Survey of Canada, Bulletin 585.

Bauer, K., Haberland, C., Pratt, R.G., Hou, F., Medioli, B.E., andWeber, M.H.2005: Ray-based cross-well tomography for P-wave velocity, anisotropy,

and attenuation structure around the JAPEX/JNOC/GSC et al.Mallik 5L-38 gas hydrate production research well; in ScientificResults from the Mallik 2002 Gas Hydrate Production ResearchWell Program, Mackenzie Delta, Northwest Territories, Canada,(ed.) S.R. Dallimore and T.S. Collett; Geological Survey of Canada,Bulletin 585.

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research well downhole well-log and core montages; in ScientificResults from the Mallik 2002 Gas Hydrate Production ResearchWell Program, Mackenzie Delta, Northwest Territories, Canada,(ed.) S.R. Dallimore and T.S. Collett; Geological Survey of Canada,Bulletin 585.

Hancock, S.H., Dallimore, S.R., Collett, T.S., Carle, D., Weatherill, B.,Satoh, T., and Inoue, T.2005: Overview of pressure-drawdown production-test results for the

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on phase changes and thermal properties; in Scientific Results fromthe Mallik 2002 Gas Hydrate Production Research Well Program,Mackenzie Delta, Northwest Territories, Canada, (ed.) S.R. Dallimoreand T.S. Collett; Geological Survey of Canada, Bulletin 585.

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gas hydrate production research well: gas hydrate saturation, growthhabit, and relative permeability; in Scientific Results from theMallik 2002 Gas Hydrate Production Research Well Program,Mackenzie Delta, Northwest Territories, Canada, (ed.) S.R. Dallimoreand T.S. Collett; Geological Survey of Canada, Bulletin 585.

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Lorenson, T.D., Whiticar, M.J., Collett, T.S., Dallimore, S.R., andDougherty, J.A.2005: Complete gas composition and isotopic geochemistry from the

JAPEX/JNOC/GSC et al. Mallik 5L-38 gas hydrate productionresearch well: cuttings, core, gas hydrate, and production testing

results; in Scientific Results from the Mallik 2002 Gas HydrateProduction Research Well Program, Mackenzie Delta, NorthwestTerritories, Canada, (ed.) S.R. Dallimore and T.S. Collett; GeologicalSurvey of Canada, Bulletin 585.

McLellan, P.J., Gillen, K.P., Podetz, C.G, and Dallimore, S.R.2005a: Characteristics of natural fractures in the JAPEX/JNOC/GSC et al.

Mallik 5L-38 gas hydrate production research well; in ScientificResults from the Mallik 2002 Gas Hydrate Production ResearchWell Program, Mackenzie Delta, Northwest Territories, Canada,(ed.) S.R. Dallimore and T.S. Collett; Geological Survey of Canada,Bulletin 585.

McLellan, P.J., Gillen, K.P., Podetz, C.G., Dallimore, S.R., Inoue, T., andHancock, S.H.2005b: In situ stresses in the Mallik area; in Scientific Results from the

Mallik 2002 Gas Hydrate Production Research Well Program,Mackenzie Delta, Northwest Territories, Canada, (ed.) S.R. Dallimoreand T.S. Collett; Geological Survey of Canada, Bulletin 585.

Medioli, B.E., Wilson, N., Dallimore, S.R., Paré, D., Brennan-Alpert, P.,and Oda, H.2005: Sedimentology of the cored interval, JAPEX/JNOC/GSC et al.

Mallik 5L-38 gas hydrate production research well; in ScientificResults from the Mallik 2002 Gas Hydrate Production ResearchWell Program, Mackenzie Delta, Northwest Territories, Canada,(ed.) S.R. Dallimore and T.S. Collett; Geological Survey of Canada,Bulletin 585.

Moridis, G.J., Collett, T.S., Dallimore, S.R., Inoue, T., and Mroz, T.H.2005: Analysis and interpretation of the thermal test of gas hydrate disso-

ciation in the JAPEX/JNOC/GSC et al. Mallik 5L-38 gas hydrateproduction research well; in Scientific Results from the Mallik 2002Gas Hydrate Production Research Well Program, Mackenzie Delta,Northwest Territories, Canada, (ed.) S.R. Dallimore and T.S. Collett;Geological Survey of Canada, Bulletin 585

Satoh T., Dallimore, S.R., Collett, T.S., Inoue, T., Hancock, S.H.,Moridis, G.J., and Weatherill, B.2005: Production-test planning for the JAPEX/JNOC/GSC et al. Mallik

5L-38 gas hydrate production research well; in Scientific Resultsfrom the Mallik 2002 Gas Hydrate Production Research WellProgram, Mackenzie Delta, Northwest Territories, Canada, (ed.)S.R. Dallimore and T.S. Collett; Geological Survey of Canada,Bulletin 585.

Wiersberg, T., Erzinger, J., Zimmer, M., Schicks, J., and Dahms, E.2005: Real-time gas analysis at the JAPEX/JNOC/GSC et al. Mallik

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Wright, J.F., Nixon, F.M., Dallimore, S.R., Henninges, J., and Côté, M.M.2005: Thermal conductivity of sediments within the gas-hydrate-bearing

interval at the JAPEX/JNOC/GSC et al. Mallik 5L-38 gas hydrateproduction research well; in Scientific Results from the Mallik 2002Gas Hydrate Production Research Well Program, Mackenzie Delta,Northwest Territories, Canada, (ed.) S.R. Dallimore and T.S. Collett;Geological Survey of Canada, Bulletin 585.

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