1Electric submersible pump as an effective artificial lift method to control bottom-hole pressure in a producing gas hydrate well, JOGMEC/NRCan/Aurora 20072008 Mallik Gas Hydrate Production Research Well ProgramM. Rojas1, C.K. Martin2, L. Hernandez-Johnson2, D. Ashford2, J.F. Wright3, K. Yamamoto4, M. Numasawa4, S.R. Dallimore3, and R.E. Isted5

Rojas, M., Martin, C.K., Hernandez-Johnson, L., Ashford, D., Wright, J.F., Yamamoto, K., Numasawa, M., Dallimore, S.R., and Isted, R.E., 2012. Electric submersible pump as an effective artificial lift method to control bottom-hole pressure in a producing gas hydrate well, JOGMEC/NRCan/Aurora 20072008 Mallik Gas Hydrate Production Research Well Program; in Scientific results from the JOGMEC/NRCan/Aurora Mallik 20072008 Gas Hydrate Production Research Well Program, Mackenzie Delta, Northwest Territories, Canada, (ed.) S.R. Dallimore, K. Yamamoto, J.F. Wright, and G. Bellefleur; Geological Survey of Canada, Bulletin 601, p. xxxx

Abstract: Gas hydrate is a potentially vast, high-energy hydrocarbon resource. It is known to occur in deep-water marine sediments along continental margins, and in cold Arctic regions beneath thick permafrost. The challenge in producing methane gas from gas hydrate lies in controlling the gas hydrate dissociation process through depressurization and/or thermal stimulation (addition of heat). The first sustained production of gas hydrate was achieved at the Mallik site in Canadas Mackenzie Delta over a period of 6.8 days during March 2008, as part of the 20072008 JOGMEC/NRCan/Aurora Mallik Gas Hydrate Production Research Well Program. In this test, gas hydrate dissociation was initiated by simple depressurization of the gas hydrate reser-voir, using mechanical manipulation of fluid levels within the producing well to maintain bottom-hole pressure and temperature conditions outside the methane hydrate stability field.

This paper addresses the design criteria and equipment selection for the artificial lift component of the 20072008 gas hydrate production test. The equipment was specially configured to operate in the very low ambient wellbore temperatures and potentially abrasive conditions. An electric submersible pump (ESP), pressure and temperature sensors, down-hole induction heater, and a variable speed drive were used to maintain the stable pump-intake pressure and temperature required to sustain the dissociation process. The ESP down-hole equipment operated as expected and was capable of significant turn-down to produce at relatively low flow rates of 10 to 15 m3/d under a variety of intake pressures. The variable speed drive enabled the maintenance of stable intake pressures throughout the production test.

1Schlumberger Canada Limited, 5253rd Avenue SW, Calgary, Alberta T2W 0G4, Canada, mrojas4@slb.com2Schlumberger Canada Limited, 5253rd Avenue SW, Calgary, Alberta T2W 0G4, Canada3Natural Resources Canada, Geological Survey of CanadaPacific, 9860 West Saanich Road, Sidney, British Columbia V8L 4B2, Canada

4Japan Oil, Gas and Metals National Corporation, Technology and Research Center, 1-2-2 Hamada, Mihama-ku, Chiba, 261-0025, Japan

5Madis Engineering Ltd., Bay #7, 9510 114th Avenue SE, Shepard Industrial Park, P.O. Box 81068, Calgary, Alberta T2W 7C9, Canada

2Rsum : Les hydrates de gaz constituent potentiellement une vaste source dhydrocarbures haute ner-gie. Ils se manifestent surtout dans les sdiments marins deau profonde en bordure des marges continentales, ainsi que dans les rgions froides de lArctique sous une paisse couverture de perglisol. Le dfi que pose la production de mthane partir des hydrates de gaz est li au contrle du processus de dissociation des hydrates de gaz, soit au moyen de la dpressurisation, soit au moyen de la stimulation thermique (ajout de chaleur), ou les deux. La premire instance de production soutenue dhydrates de gaz a eu lieu au puits Mallik, dans le delta du Mackenzie, au Canada, et sest droule sur une priode de 6,8 jours en mars 2008; cet exercice sinscrivait dans le cadre du Programme de puits de recherche sur la production dhydrates de gaz JOGMEC/NRCan/Aurora Mallik. Au cours de cet essai, on a tout simplement procd la dpressurisation du rservoir des hydrates de gaz pour provoquer le phnomne de dissociation des hydrates de gaz; pour ce faire, il a fallu manipuler mcanique-ment les niveaux des fluides lintrieur du puits producteur afin de maintenir les conditions de pression et de temprature de fond du puits au-del des limites du champ de stabilit des hydrates de mthane.

La prsente communication porte sur le choix dquipement et les critres de conception de la composante dascension artificielle utilise lors de lessai de production dhydrates de gaz ralis en 2007-2008. Lquipement a t spcifiquement conu pour fonctionner aux tempratures ambiantes trs basses qui se manifestent dans les puits et rsister aux conditions abrasives qui peuvent y svir. Le recours une pompe submersible lectrique (ESP), des dtecteurs de pression et de temprature, un appareil de chauffage par induction dans le puits et un entranement vitesse variable a permis de maintenir les conditions stables de pression et de temprature lentre de la pompe requises pour assurer de faon soutenue le processus de dissociation. Lquipement (ESP) dans le puits a fonctionn tel que prvu et sa marge de rglage considrable lui a dailleurs permis de fonctionner aux taux dcoulement rela-tivement faibles de 10 to 15 m3/d, et ce divers niveaux de pression dadmission. Lentranement vitesse variable a permis de maintenir les pressions dadmission stables tout au long de lessai de production.

3M. Rojas et al.

INTRODUCTIONAt in situ formation temperatures and pressures common

to most marine and Arctic terrestrial gas hydrate reservoirs, gas hydrate exits within a few Celsius degrees of its pres-sure-temperature (P-T) phase-equilibrium threshold (Fig. 1). During the past dozen years, Canada and Japan have con-ducted a series of collaborative research and development programs to investigate the production potential of a terres-trial Arctic gas hydrate deposit, in preparation for potential future commercial development of gas hydrate in Arctic Canada and offshore from Japan.

The original JAPEX/JNOC/NRCan Mallik 2L-38 gas hydrate research well, situated in the Mackenzie Delta, Northwest Territories (Fig. 2), was drilled to a depth of 1150 m during February and March 1998 (Dallimore et al., 1999). The program included sophisticated well-logging and geophysical studies, as well as limited coring and recovery of gas-hydrate-bearing reservoir sediments. The program enabled the first detailed geological characterization of a ter-restrial gas hydrate reservoir, and confirmed the presence of more than 100 m cumulative thickness of gas hydrate, occur-ring mainly in sand-dominated sedimentary strata, with in situ gas hydrate concentrations commonly ranging from around 50% to greater than 90% pore saturation. Coring operations yielded approximately 75 m of high-quality core, which supported a variety of on-site measurements of reser-voir properties, as well as extensive post-field investigations of the properties and behaviour of gas hydrate occurring in a natural geological reservoir.

The Mallik 2002 Gas Hydrate Production Research Program, conducted between December 2001 and March 2002, featured more extensive coring, state-of-the-art well logging and surface geophysics, and a full-scale production test using hot-water circulation to force in situ gas hydrate dissociation and recovery of produced gas at the surface (Dallimore and Collett, 2005). This represented the worlds first in situ production of natural gas from methane hydrate, but the production rates achieved during 5 days of testing were very modest. Post-field evaluation of the Mallik 2002 production test yielded general agreement that heating alone likely could not generate and sustain sufficiently high rates of gas production to be practically viable over the longer term.

The Mallik 20072008 Gas Hydrate Production Research Well Program was implemented over two successive winter seasons (Jan.Apr. 2007 and Jan.Mar. 2008), and was designed to evaluate the production response of gas hydrate to simple depressurization of the host reservoir (Dallimore et al., 2008; Kurihara et al., 2008).

An initial short-term production test was conducted in March 2007, the strategic objective of which was to provide a basis for evaluating the initial response of the reservoir (in terms of gas- and water-flow rates, and solids production) to depressurization. Critical observations and knowledge could

then be used to refine the design of an extended-duration production test scheduled for the following winter. Although this objective was, in fact, achieved, higher-than-expected rates of sand production into the well forced an early ter-mination of the test, emphasizing the need for positive sand control in future production-testing operations at Mallik. In contrast, gas and water production rates during the testing period were within the expected ranges.

The objective of the 2008 production-testing program was to measure, record, and prove the dissociation/produc-tion of gas hydrate, over an extended time frame, by simple depressurization of the well using an electric submersible pump system as a viable method to control the production of natural gas from gas hydrate reservoirs. Electric submersible pumps (ESPs) have been used increasingly as an artificial lift option for producing wells with a high gas/liquid ratio (GLR) or gas/oil ratio (GOR), heavy-oil wells, and steam-assisted

0

5

10

15

20

0 105 15 20Temperature (C)

Pres

sure

(MPa

)

Liquid water+ methane gas

-5

Methanehydrate+ ice

Methane hydrate+ liquid water

Ice + gas

Tuktoyaktuk

137W

68N

132W70N

MackenzieBay

Inuvik(field lab)

Aklavik

BeaufortSea

Mallik3L-, 4L- and 5L-38

2L-38L-38

0 25km 68N

70N

137W 132W

Taglustagingsite

Yuko

n

Nor

thw

est T

err

itorie

s

Figure 1. Simplified phase diagram for methane hydrate.

Figure 2. Location of the Aurora/JOGMEC/NRCan Mallik 2L-38 gas hydrate production-test well, 140 km west of Tuktoyaktuk in the Mackenzie Delta, Northwest Territories.

4GSC Bulletin 601

gravity drainage (SAGD) wells with different types of com-pletion. The selection of basic pump type, as well as custom design considerations, can vary substantially depending on specific well conditions at a given site.

This paper summarizes the selection criteria and speci-fications for an ESP that could handle the gas and sand production at very low fluid rates, in the range of about 10 to 20 m3/day. These pump characteristics are required to pro-vide effective control of fluid levels within the wellbore, as a means for maintaining bottom-hole pressure (BHP) at target values, and stable conditions and constant dissociation in the gas hydrate reservoir. Note that the same pump design was used in both the 2007 and 2008 winter production-testing programs, but its location and configuration in the well dif-fered between years. This paper will focus mainly on the ESP and related components, as they were applied to the Mallik 2008 extended production-test program.

Also, to guarantee flow assurance during production oper-ations, the application of a down-hole heater situated below the ESP to heat the produced fluids (water and gas) prior to entering the ESP intake was considered in the pump design.

ESP DESIGN AND CONSIDERATIONSThe parameters in Table 1 were used as input information

for software used to design the ESP. The initial design of the 2008 extended production test specified three operational stages, with successive BHP targets of 8, 6, and 5 MPa. To achieve these targets, the pump operator must be able to con-trol pumping rates to maintain a stable bottom-hole flowing pressure (BHFP) during each production stage, with refer-ence to actual operational pressures at the pump intake. Six different scenarios (Table 2) were simulated in order to cover a range of the possible down-hole conditions that might be encountered during each production stage.

As per Tables 1 and 2, design considerations for an ESP included the capacity to operate satisfactorily at both low and high GLRs, in the presence of substantial abrasive solids (sand), at relatively low temperatures, and at flow rates ranging from very low to moderate.

DOWN-HOLE HEATER CONSIDERATIONS

A down-hole electrical induction heater (Fig. 3) was incorporated into the completion string for the Mallik 2008 extended production test. The heater was installed in the wellbore at a depth of about 830 m, such that it was pos-itioned between the perforations at the production zone (approx. 1100 m) and the pump intake (approx. 811 m). In this position, the heater increased the temperature of the fluid in the wellbore (both produced and residual) before it entered the ESP pump intake. The heater was designed to

increase fluid temperature by an amount sufficient to ensure that P-T conditions within the pump and production tubing remained outside the methane hydrate stability field, thereby preventing gas hydrate re-formation in the tubing and poten-tial restriction of fluid flow to the surface.

Several simulations were conducted using PIPESIM analysis software to better evaluate flow-assurance con-siderations for this particular well. An example of typical PIPESIM output is shown in Figure 4. The major findings of this analysis were:

Tubing outside diameter 73.025 mm Tubing weight 9.67 Kg/m Tubing threads EUE Casing outside diameter 244.475 mm Casing weight 59.53 Kg/m Top of perforations 1093 m Bottom of perforations 1105 m Static bottom-hole temperature 12qC Well construction Cased-hole, perforated, verticalWater specific gravity 1.03 SG Water specific gravity with solids (valves input in the software to simulate the pump with sand and water production)

1.18 SG

Gas specific gravity 0.65 SG Water cut (% water) 100 Reservoir pressure 11100 KPa Bottom-hole flowing pressure (Scenario 1) 8 MPa Daily flow rate 23 m3/d Bottom-hole flowing pressure (Scenario 2) 6 MPa Daily flow rate 30 m3/d Bottom-hole flowing pressure (Scenario 3) 5 MPa Daily flow rate 42 m3/d Production gas-liquid ratio 0190 m3/m3 Solids production (estimated) 0.1589 m3/h Desired tubing pressure Requires further analysis Producing casing pressure (max) 4000 Kpa

Table 1. Basic design parameters for an electric sub-mersible pump for the Aurora/JOGMEC/NRCan Mallik 2L-38 gas hydrate production-test well.

Scenario

Bottom-hole flowing

pressure (MPa)

Productivity index

(m3/d/KPa) Gas-liquid ratio

1 8 0.007419 0 2 8 0.007419 40 3 6 0.00588 40 4 6 0.00588 140 5 5 0.006885 40 6 5 0.006885 180

Table 2. Scenarios used for design of an electric submersible pump for the Aurora/JOGMEC/NRCan Mallik 2L-38 gas hydrate production-test well.

5M. Rojas et al.

Electromagnetic energy from theinductors passes through the annulusfluid to heat the casing near the wellboredirectly.

A series of temperature sensorsmeasure the tool skin

temperature at multiple points within theassembly.

Tool skin temperatures are transmitted toa power-conditioning unit at the surface,and are used to control power delivery tothe inductors via a feed-back controlloop. Each inductor is controlledseparately.

A pressure sensor located in theinstrument pod provides real-time down-hole pressure data.

(34 perinductor)

0.0 m

0.75 m

4.68 m

8.55 m

12.43 m

13.08 m

17.8 cm (7-inch) diametersteel casing

Inductor A

Inductor B

Inductor C

Tubing

Inducto-tool assembly

Centralizer (x 4)

Pressure sensor

Instrument pod

MxL Inductor Tool AssemblyWeight 550 kg

Madis Engineering Ltd., Calgary, Alberta

Cable

Figure 3. Design of down-hole heater for the Aurora/JOGMEC/NRCan Mallik 2L-38 gas hydrate production-test well, with 17.8 cm (7-inch) diameter casing cover to increase heat-transfer efficiency.

0 2 4 6 8 10 12 14-2-4-60

2

4

6

8

10

12

Ice line

Methane hydrate stability curve

P-T condition at pump discharge

START

END

BHP = 6 MPa, GLR = 100, ESP @ 960 m

Temperature (C)

Pressure

(MPa)

Figure 4. Example of PIPESIM output for evaluating flow-assurance characteristics in the production tubing of the Aurora/JOGMEC/NRCan Mallik 2L-38 gas hydrate produc-tion-test well. Abbreviations: BHP, bottom-hole pressure; ESP, electric submersible pump; GLR, gas/liquid ratio.

6GSC Bulletin 601

An estimate of the actual operational GLR is required to reliably evaluate the chances of gas hydrate re-formation.

Down-hole heat is required to assure with confidence that no gas hydrate will form in the production string between the pump and the surface.

Depth positioning of the ESP is an important factor in determining the amount of heating required to keep gas hydrate from re-forming in the production tubing.

In general, a higher GLR results in an increased prob-ability of gas hydrate formation. Based on lab analysis and some basic operational assumptions provided by NRCan and JOGMEC, it was estimated that the actual GLR during production would be approximately 100 or lower. This esti-mate is based on a lab-derived GLR for dissociated methane hydrate of 180, and considers the effect of a centrifugal gas separator integrated in the ESP design.

Numerical modelling (using PIPESIM) of a variety of equipment configurations and specifications supported an assessment of such flow-assurance parameters as pump loca-tion (depth), inlet and outlet pressures and temperatures, GLRs, and supplementary heating of wellbore fluids. Based on the modelling, it was determined that a down-hole heater with the capacity to provide a 12C temperature rise under dynamic conditions would be sufficient to prevent gas hydrate from re-forming in the production tubing during the testing period.

COMPLETION OF THE ELECTRIC SUBMERSIBLE PUMP

The basic criteria for selection of a down-hole pump sys-tem relate to the fundamental characteristics of the well and the expected operational requirements. Because of significant unknowns regarding the actual production characteristics

of the Mallik 2L-38 well, it was felt that the pump selected would have to be capable of a fairly wide range of pumping rates, from about 40 m3/d or less to more than 300 m3/d, with a lifting capacity of about 1000 m. This range was due to uncer-tainty regarding the actual volume of formation water that would be produced in conjunction with the produced gas. As mentioned earlier, the pump selected would also have to oper-ate reliably within a specified range of ambient temperatures and withstand the abrasive effects of a potentially significant solids component (produced sand and silt) in the fluid stream.

In terms of pump design and construction, a compression-type pump with abrasion-resistant zirconia (ARZ) bearings was selected for this application. Compression pumps can operate below the minimum recommended operating flow rate, under poor lubrication conditions, and in the presence of abrasives. The ARZ bearings employed in the head and base of the pump provide stabilization for the drive shaft, support the radial load, and feature superior wear resistance. Hydrogen-saturated nitrile (HSN) materials were used in the elastomers of all the ESP components to make them compat-ible with low well temperature and the expected chemistry of auxiliary injection fluids, such as cesium formate and methanol.

A schematic of the complete ESP assembly and related auxiliary components is shown in Figure 5. A Vortex gas separator assembly (VGSA) and Poseidon advanced gas handler (AGH) were chosen to handle the high GLR and avoid possible gas locking of the pump during operations. It was expected that the majority of the free gas entrained in the production-fluid stream would be separated by the VGSA prior to entering the pump proper. Any gas remaining after separation would flow with the water to the Poseidon AGH, which is designed to handle up to 75% free gas without locking.

DescriptionDepth

From To

Tubing

CTS gauge

Pup joint

Discharge pressure sub

Pump (DN1750 CR-CT 86 STG 400/400 110 CS VTHD, .68 MON, S-TRM, HSN, ARZ)

Pump (DN1750 CR-CT 86 STG 400/400 110 CS VTHD, .68 MON, S-TRM, HSN, ARZ)

Poseidon (D8-42 CR-CT, 400/400 CS, 0.87 INC, S-TRM, HSN, FBH-SICG, NI-RST,anti-rotation, extd. head)

Intake / gas separator (VGSA D20-60, 400/400, Rloy, .87 INC, M-TRM)

Adapter (GS/INTK 400 X PROT 540, CS)

Protector (BPBSL, 540/540, KTB/HL, 1.18 INC, CS, HSN)

Protector (BPBSL, 540/540, KTB/HL, 1.18 INC, CS, HSN)

Motor (562, 4, F045 DOMINATOR RX-S, CS, M-TRM XD, AS, AS;120 hp, 2558 V, 28 A)Phoenix adapterPhoenix multisensor (XT type 1, AISI 420, HSN, 5000 psi)

Perforations

0.00

798.00 (approx)

799.43 799.66

799.66 804.60

804.60 809.54

809.54 811.67

811.67 812.69

812.69 812.84

812.84 815.56

815.56 818.28

818.28 821.68

821.68 822.38822.38 822.94

1093.00 1105.00

Figure 5. Configuration of the ESP assem-bly and related components employed in the Aurora/JOGMEC/NRCan Mallik 2L-38 gas hydrate production-test well. Diagram compliments of Schlumberger Ltd.

7M. Rojas et al.

The selection of a drive motor for the pump assembly (ESP, VGSA, and Poseidon AGH) involved consideration of several parameters, including the power required to drive the three integrated units, voltage and cabling requirements, and operating temperatures. For all cases considered, the max-imum power requirement was 120 hp. Motor cooling was not considered to be a critical issue in the Mallik 2L-38 well, given that the maximum expected operating temperature (including the effect of the down-hole heater) was approximately 90C, well below the maximum winding temperature permissible for the motor. The motor selected to drive the pump assem-bly was rated at 120 hp when operating at 2558 V and 28 A. Electrical power was delivered to the motor by a suitably sized electrical cable running from a surface generator. Despite the other flow-assurance efforts already mentioned, an auxiliary capillary tube was run from the surface in parallel with the

electrical cable to enable the injection of methanol into the pump intake, as required, to prevent or remediate potential gas hydrate formation within the pump assembly.

PUMP POSITIONING AND FLOW ASSURANCE

The positioning of the ESP within the well was an import-ant secondary factor affecting flow assurance during the Mallik 2008 production test. The lower the ESP is positioned in the wellbore, the greater is the likelihood of gas hydrate re-forming in the production tubing. This is due mainly to the higher fluid pressures prevailing at greater depths, given that fluid temperatures in the well (in the absence of supple-mentary heating) were not expected to vary greatly from the

intrinsic dissociation temperature expected at each depressurization stage. All else being equal, the ESP will pump the gas-water fluid mixture to comparatively higher pressures at greater installation depths, such that P-T conditions at the pump outlet will move closer to, or into, the methane hydrate stability threshold. Therefore, by positioning the pump at lesser depths, com-paratively lower fluid pressures are generated at the pump outlet, thus decreasing the potential for gas hydrate to re-form in the production tubing en route to the surface. Note, however, that this effectively imposed a practical operating limit on location of the pump (a depth of approx. 800 m) because depressurization (production stimula-tion) of the reservoir was achieved by varying fluid level in the well,

In addition, a cable-to-surface (CTS) gauge was installed above the discharge of the pump to monitor annular pressure and tubing pres-sure. A Phoenix down-hole gauge was installed at the bottom of the motor to measure intake pressure, discharge pressure, intake temperature, motor-winding temperature, and vibration. These data allowed real-time monitoring and adjust-ment of pump operating conditions and output, and served as a basis for estimating the values of critical production parameters during testing, such as fluid levels in the well, fluid specific grav-ity, and bottom-hole flowing pressure (BHFP). These measurements were subsequently used, in turn, to fine-tune operational parameters in order to maintain stable production during each testing stage, to evaluate the production response in nearreal time, and to support critical deci-sion-making regarding potential adjustments of conditions throughout the production period. The complete down-hole equipment setup installed in the Mallik 2L-38 well (Fig. 6) consisted of the following components:

20 in., 94lbs./ft., J55 at 103 m

2.875 in. EUE, L80 Tbg

Permafrost base at 640 m 13.375 in., 61lbs./ft., J55 at 677 m

ESP cable with chemical injection #4CTS cable (back-up ESP sensor)Downhole heater, #4 cable, no chemical injectionBleeder valve at 683 m

Bleeder valve at 739 m

Bleeder valve with stop at 795 m

CTS gauge carrier at 798 m

Chemical injection splice (injection point at 811 m)

Pump intake at 811 m

Phoenix gauge at 822 m

Downhole heater at 825837 m

Annular gauge carrier (bottom at 1083 m)Model LB permanent packer (top at 1083 m)Mesh-Rite sand-control screensA zone at 10931105 m

Model LB permanent packer (top at 1110 m)Cement plug at 1194 mBridge plug at 1202 m

Model S packer at 1211 mModel S packer at 1218 m

2.313" landing SXN nipple at 1240 mModel B shear plug at 1238 m (sheared)Flood collar at 1275 m

Shoe, 9.625 in., 40 J55 at 1288 mlbs./ft.,

Injection zone at 12241230/12381256/12701274 m

Figure 6. Well-completion diagram for the Aurora/JOGMEC/NRCan Mallik 2L-38 gas hydrate production-test well. Diagram compliments of Schlumberger Ltd. Abbreviations: CTS, cable to surface; ESP, electric submersible pump; FC, final completion.

8GSC Bulletin 601

Down-hole Equipment Bleeder valve

Centralizer: 0.073 m external upset ends (EUE) x 1.21 m Pup joint: 0.073 m EUE (box pin) x 1.828 m CTS gauge

Discharge sub-sensor: 0.1143 m EUE x 2.444 m

Head: bolt-on discharge pump, 400, CS, 0.073 m OD 8RD EUE

Pump: DN1750 CR-CT 86 stg 400/400 110 CS VTHD, 0.68 MON, S-TRM, HSN, ARZ, 0.1016 m OD x 4.94 m

Pump: DN1750 CR-CT 86 STG 400/400 110 CS VTHD, 0.68 MON, S-TRM, HSN, ARZ, 0.1016 m OD x 4.94 m

Multiphase gas-handling system: Poseidon D8-42 CR-CT 400/400 CS VTHD, 0.87 INC, S-TRM, HSN, 0.1016 m OD x 4.94 m.

Intake: VGSA D20-60, 400/400 RLOY 0.87 INC, M-TRM ES, 0.1016 m OD x 1.2 m

Adapter: GS/INTK 400 X PROT 540, CS Protector: BPBSL, 540/540, KTB/HL, 1.18 MON, CS,

HSN, 0.137 m OD x 2.72 m

Protector: BPBSL, 540/540, KTB/HL, 1.18 MON, CS, HSN, 0.137 m OD x 2.72 m

Motor: 562, 120 hp / 2558 V / 28 A, 4, F045 Dominator RX-S, CS, M-TRM, 0.142 m OD x 3.40 m

Base: UMB 562 S/A CS, HSN MTC 250 D F BHT MAX Multisensor: 7.303 cm EUE x 1.143 m (2.875 in. EUE

x 3.75 ft; to provide readings of Pi, Pd, Tm, Ti, vibration, and current leaks)1

Centralizer: 7.303 cm EUE x 1.143 m (2.875 in. EUE x 4 ft.)

Cable: REDALEAD 4, 5KV (4/1 EHLB-NS G5F W/ 3/8 TUBE)

Surface Equipment Sine-wave variable-speed drive: 200 kVA

Integrated surface panel.

Elevator transformer: 200 kVA

CALCULATION OF BOTTOM-HOLE PRESSURE AT PERFORATIONS

Equations 1 and 2 were used to calculate the percentage of free gas and the specific gravity of the fluid mixture in the wellbore in the vicinity of the pump intake.

FreeGas%Q

P

Q

GasAtSurfaceAnnulus

GasAtSurface

=

101 3

10

.

11 3.P

QAnnulus

Liquid

+

SG FreeGas% SGP

FreeGas% SG

Fluid GasAnnulus=

+ ( )

101 3

1

.

LLiquid( )

Early in the 2008 test, it was determined that the values calculated from these equations generated a misleading picture of what was actually occurring down the hole. During the operation, it was found that liquid rates (water production) were much lower than expected, so the assumption that the liquid and gas would be travelling at roughly the same velocity within the wellbore proved to be incorrect. Consequently, the difference in residence time between the gas and liquid in the wellbore meant that, for a given volume of fluid-filled casing, considerably less volume was occupied by gas compared to water at any particular moment in time (than was initially estimated). Unfortunately it was not known precisely how much faster the gas would travel relative to the liquid. An Internet search yielded a bubble velocity for methane in salt water of approximately 15 cm/s or 540 m/h. The liquid-inflow rate could be estimated reasonably accurately based on its bulk occupancy of the casing volume (with reference to the pumping rate), and the gas rate was subsequently adjusted according to the intrinsic bubble velocity (buoyancy) of the gas phase within the liquid stream (Equations 3 and 4).

F

Q

QLiquidHoldUp

Liquid

Liquid=

+

0 0394 24

540

0 0

.

. 3394 24

FreeGas%Q

P FGasAtSurface Annulus LiquidHoldUp=

101 3.

QQP F

QGasAtSurfaceAnnulus LiquidHoldUp

Liquid

+

101 3.

Further refinement was achieved with the addition of a function to iteratively recalculate the velocity of the liquid based on the new free-gas percentage previously calculated (Equation 5). Excel software, with an iteration limit of 100 times, was employed to fine-tune these values.

F

QFreeGas%

LiquidHoldUp

Liquid

0 0394 24 1540

. ( )

+

( )

QFreeGas%

Liquid

0 0394 24 1.

1Abbreviations: Pi, intake pressure; Pd, discharge pressure; Tm, motor temperature; Ti, intake temperature

(1)

(2)

(3)

(4)

(5)

9M. Rojas et al.

So, while one calculation was evolving during the first phase to determine the current pressure at the perforations, a second parallel calculation was also being performed. This calculation was based on the differences in annular pressure readings between the CTS gauge and the Phoenix sensor. Unfortunately, at higher liquid-flow rates. there would be significantly higher free gas percentages above the intake of the pump relative to below it, which would adversely affect the accuracy of the calculation. Although both gauges are reasonably accurate in terms of pressure, they are not entirely exact. As a result, the calculation of specific gravity based on the difference between gauge readings had to be modified to account for this variance. Based on observed differences in the absolute pressure readings, a calibration factor of 54 kPa was employed to adjust the calculated specific gravity to 1.03 kg/L, the value it was known to be at the beginning of the test (Equation 6).

SGP P

FluidAnnulusPhoenix AnnulusCTS=

+( )( )

54

822 94 798 131

. .

.1102

Both calculations resulted in similar values at the perforations, and it was believed at the time that these calculations also provided a reasonable estimate of the actual pressure.

By the time the calculations were completed, it was found that the pressure at the perforations, although stable, was not at the desired 8 MPa target pressure but rather at approximately 7.3 MPa. It was decided to hold at this pressure because the maintenance of a stable driving force (depressurization) for production was considered more important than achieving a precise target for pressure drawdown. Unfortunately, during this holding period, a line froze at surface and the casing had to be shut in, leading to a build-up of gas pressure in the cas-ing. The increase in casing pressure resulted in a reduction in the pressure differential across the pump; thus, for a given pump speed, a greater volume of fluid was removed from the annulus per unit time because less lifting head was required

to pump fluid to surface. When the casing was reopened, it was found that the well was slow to recover from these events and fluid inflow from the formation into the well was barely 4 to 5 m3/d. Gas-flow rates at the beginning of stage 1 were initially in excess of 3500 m3/d, but they decreased steadily for the duration of the stage, finally reaching about 2000 m3/d.

PERFORMANCE OF THE ELECTRIC SUBMERSIBLE PUMP DURING THE PRODUCTION TEST

The Mallik 2L-38 well was tested at producing pressures of approximately 7.5, 5.0, and 4.3 MPa. To achieve these target pressures, the ESP was operated at frequencies ran-ging from 25 to 37 Hz. Figure 7 shows the intake pressure and discharge pressure as a function of the pump-operation frequency. As an example, the differential pressure across the pump at 7.5 MPa BHP was approximately 3.7 MPa, giv-ing a nominal fluid-pumping rate of 20 m3/d, based on the pump-performance curve shown in Figure 8.

STAGE 1 STAGE 2 STAGE 3 0

40

80

100

11

Pres

sure

(MPa

)

12 13 14 15 16

20

60

0.0

2.0

4.0

6.0

8.0

10.0

Frequ

ency

(Hz)

1.0

5.0

9.0

3.0

7.0Discharge pressure

Pump frequencyIntake pressure

Date (March 2008)Figure 7. Intake and discharge pressures as a function of oper-ating frequency of the electric submersible pump during the gas hydrate production test on the Aurora/JOGMEC/NRCan Mallik 2L-38 well.

Pres

sure

(kPa

)

0.0

2.0

4.0

6.0

1.0

5.0

3.0

0 25 50 75 100 125 150 175 200Capacity (m /d)3

10

20

30

5

25

15

Hp

20%

40%

60%

10%

50%

30%

Eff.B E PQ = 143P = 7.99H = 2464.62

E = 68.51

Figure 8. Performance curve for the electric submersible pump employed in the gas hydrate production test on the Aurora/JOGMEC/NRCan Mallik 2L-38 well. Abbreviations: BEP, best efficiency point; E, Eff, efficiency; Q, flow rate; H, pump head; Hp, horsepower; P, power.

STAGE 1 STAGE 2 STAGE 3 0

40

80

100

11

Tem

pera

ture

(C)

12 13 14 15 16

20

60

0

20

40

60

80Fr

eque

ncy

(Hz)

10

50

30

70Motor temperature

Pump frequencyIntake temperature

Date (March 2008)

Figure 9. Motor-winding and pump-intake temperatures as a function of operating frequency of the electric submersible pump during the gas hydrate production test on the Aurora/JOGMEC/NRCan Mallik 2L-38 well.

(6)

10

GSC Bulletin 601

Finally, motor-winding temperature must be maintained within specified tolerances, which can be problematic at low flow rates and high GLR. Figure 9 shows the variation in the motor-winding temperature and pump-intake temperature as a function of pump frequency. The maximum motor-wind-ing temperature actually recorded during operations was about 65C, which is well below the maximum allowable for the pump.

CONCLUSIONSThe electric submersible pump (ESP) system deployed

in the JOGMEC/NRCan/Aurora Mallik 20072008 Gas Hydrate Production Research Well Program proved to be an effective means of achieving and maintaining close con-trol of bottom-hole pressures driving natural gas production from the dissociation of gas hydrate. The ESP system per-formed well at the very low water-production rates (approx. 1020 m3/d) realized during production testing. The system, which included a Vortex gas separator and Phoenix gas hand-ler, was applied successfully to the first extended production test of a gas hydrate reservoir.

We can draw the following conclusions based on the production test carried out at the Aurora/JOGMEC/NRCan Mallik 2L-38 well:

An ESP designed to produce flow rates of 30 to 120 m3/d, with a best efficiency point (BEP) of 150 m3/d, per-formed adequately in a gas hydrate well in which actual fluid production was generally 10 to 15 m3/d.

The ESP system enabled effective control of fluid levels in the well, permitting the achievement and stable mainten-ance of the target bottom-hole pressures specified in the production-testing program, using sine-wave variable-speed drive (VSD) and a variety of down-hole gauges for monitoring and adjustment of intake pressures.

The motor-winding temperature never exceeded the maximum specified for safe operation.

ACKNOWLEDGMENTSThe authors thank Natural Resources Canada, the Japan

Oil, Gas and Metals National Corporation, and the Aurora Research Institute, We also Schlumberger Ltd. for granting permission to publish this paper.

REFERENCESDallimore, S.R., Uchida, T., and Collett, T.S. (ed.), 1999.

Scientific results from JAPEX/JNOC/GSC Mallik 2L-38 gas hydrate research well, Mackenzie Delta, Northwest Territories, Canada; Geological Survey of Canada, Bulletin 544, 403 p., [accessed April 6, 2011].

Dallimore, S.R. and Collett, T.S. (ed.), 2005. Scientific results from the Mallik 2002 Gas Hydrate Production Research Well Program, Mackenzie Delta, Northwest Territories, Canada; Geological Survey of Canada, Bulletin 585, 140 p. and 2 DVD-ROMs, [accessed April 6, 2011].

Dallimore, S.R., Wright, J.F., Nixon, F.M., Kurihara, M., Yamamoto, K., Fujii, T., Fujii, K., Numasawa, M., Yasuda, M., and Imasato. Y., 2008. Geologic and porous media factors affecting the 2007 production response characteristics of the JOGMEC/NRCan/Aurora Mallik gas hydrate production research well; in Proceedings of the 6th International Conference on Gas Hydrates (ICGH 2008), Vancouver, British Columbia, July 610, 2008, Paper 5829, 10 p.

Kurihara, M., Funatsu, K., Ouchi, H., Masuda, Y., Yasuda, M. Yamamoto, K., Numasawa, M., Fujii, T., Narita, H., Dallimore, S.R., and Wright, J.F., 2008. Analysis of the JOGMEC/NRCan/Aurora Mallik gas hydrate production test through numerical simulation; in Proceedings of the 6th International Conference on Gas Hydrates (ICGH 2008), Vancouver, British Columbia, July 610, 2008, Paper 5831, 13 p.

IntroductionESP DESIGN AND CONSIDERATIONSDOWN-HOLE HEATER CONSIDERATIONSCOMPLETION OF THE ELECTRIC SUBMERSIBLE PUMPPUMP POSITIONING AND FLOW ASSURANCEDown-hole EquipmentSurface Equipment

CALCULATION OF BOTTOM-HOLE PRESSURE AT PERFORATIONSPERFORMANCE OF THE ELECTRIC SUBMERSIBLE PUMP DURING THE PRODUCTION TESTCONCLUSIONSACKNOWLEDGMENTSREFERENCES