Post STRESSFRAC® Production Test Results
Viking and Belly River Gas Wells

Viking Gas Well

Summary of Observations
  1. The reservoir pressure of the Viking formation was measured to be 7177.5 kPa, from the pre-cleanup shutin. Upon completion of this test the average reservoir pressure was found to be 7214.5 kPa, which indicates that there was no depletion associated with this test. The late time behaviour suggests that the reservoir could be an extremely narrow reservoir with the nearest boundary or reduction in transmissibility being about 32 metres (105-ft.) (+/-2%) away from the wellbore.

  2. The transmissibility pf the Viking formation is kh/µg = 0.42mDmµPa.s and the near wellbore area appears to be quite stimulated (St = -3.18) as a results of the stress frac performed on this reservoir. The effective permeability to gas is estimated to be 2.2 mD (+/-3.2%), using the total net pay of 2.5 metres (8-ft.)

  3. The AOF potentials of the reservoir (at test conditions) is estimated to be 12.550 10³ m³/D. The Wellhead deliverability is reduced to 12.040 10³ m³/D, due to the frictional pressure drop associated with the produced liquids. The Stabilized deliverability potentials included in this report are subject to some error due to the apparent late time behaviour. The Stabilized Sandface AOF is estimated to be 10.566 10³ m³/D.

  4. Assuming that this well will effectively drain 256 hectares (based on the information provided), the OGIP could be as high as 79.644 106 m³ (2.827 bcf). The total net pay of 2.5 metres (8-ft.) was used in this estimate. There was insufficient pressure decline for the P/Z plot to be used to verify the Volumetric reserves estimate.

  5. The apparent late time behaviour seen during this test is consistent with the drawdown pressure profile seen during the flow test. The AOF potentials quoted in this report may be quite pessimistic given the slugging that was evident during the flow test. Artificial lift should be considered as a means of optimizing the productivity of this well.


Reservoir Evaluated: Viking Model of Behaviour: A Bounded
Homogenous Reservoir Model
Completed Interval: 1283.0-1286m KBMPP @ 1279.9 m CF
PARAMETER
METRIC UNITS

FIELD UNITS
Extended Sandface AOF Potential (n=1.0):12.550(10³m³/D)0.445(MMscf/D)
Stabilized Sandface AOF (256 ha):10.566 (10³m³/D) 0.375(MMscf/D)
Extended Wellhead AOF Potential (n=1.0):12.040 (10³m³/D) 0.427 (MMscf/D)
Stabilized Wellhead AOF (256 ha):7.849 (10³m³/D) 0.279 (MMscf/D)
Initial Reservoir Pressure (P151 prior to cleanup):7177.5 (kPa) 1041.0 (psia)
Average Reservoir Pressure (PR) MBH:7214.5 (kPa) 1046.4 (psia)
Final Flowing Pressure (Pwf):2126.7 (kPa) 308.5 (psia)
Final Shutin Pressure (Pws):7205.4 (kPa) 1045.1 (psia)
Change in Pressure seen During Buildup Test: 5078.7 (kPa) 736.6 (psia)

Gas Deviation Factor @ 42.2° C:
  • @ Initial Reservoir Pressure (P151):
    		• 0.8761 ( ) 0.8761 ( )
  • @ Final Flowing Pressure (Pwf):
    		• 0.9606 ( ) 0.9606 ( )
  • @Average Reservoir Pressure (PR):
    		• 0.8757 ( ) 0.8757 ( )

    Total Transmissibility (kh/µ)g:
    0.42
    (mDm/µPa.s)
    1370.4
    (mDft/cp)
    Total Mobility (k/µ)t:0.17 (mD/µPa.s) 167.1 (mD/cp)
    Reservor Capacity (kh)g:5.5 (mDm)18.0 (mDft)
    Effective Permeability to Gas (kg):2.2 (mD)2.2 (mD)
    Effective Permeability to Water (kw):0.0 (mD)0.0 (mD)
    Total Apparent Skin (St):-3.18 ( )-3.18 ( )
    Pressure Drop due to Skin (dPskin):-2126.7 (kPa)-308.5 (psia)
    Total Flow Efficiency (FE):1.42 ( )1.42 ( )
    Damage Ratio (DR):0.71 ( )0.71 ( )
    Radius of Investigation (Rinv):100.3 (metres)329.2 (feet)
    Time to Pseudo Steady State (256 ha):11203 (hours)11203 (hours)
    Cumulative Gas Production (Gp):65.286 (10³ m³)2.317(MMscf)
    Cumulative Condensate Production (Np):0.673 (m³)4.23 (STB)
    Cumulative Water Production (Wp):1.578 (m³)9.93 (STB)
    Water-Gas Ratio (WGR):0.052 (m³/10³ m³)9.28 (bbls/MMscf)




    Belly River Gas Well

    Summary of Observations
    1. The reservoir pressure prior to the test was found to be 3163.8kPa. The average reservoir pressure after the test was 3161.1 kPa suggesting that the reservoir was not depleted as a result of this test. Given the possibility that this reservoir could be limited in areal extent, it is recommended that another static gradient be conducted on this well. The recorders should be landed over the perforations for at least 30 minutes to ensure that the readings are accurate.

    2. The AOF potential of the Belly River formation is estimated to be 88.455 10³ m³/D. The Wellhead deliverability is slightly less at 69.593 10³ m³/D, suggesting that the productivity of this well was reduced by the frictional pressure drop associated with tubulars. The Stabilized AOF potentials quoted in this report are quite sensitive to the shape of the reservoir used consequently, the reservoir shape should be verified using the Geological model of the reservoir of this area.

    3. The transmissibility of the reservoir was calculated to be kh/µg = 31.0 mDm/µPa.s and the near wellbore area appears to be slightly stimulated (St = -0.25). The effective permeability to gas is estimated to be about 48.3 mD, assuming that the net pay is 7.5 metres (24.5-ft.). The pressure enhancement associated with the total skin factor is only 37.9 kPaa, suggesting that the stress fracture treatment performed on this well was successful in removing the apparent skin that may have existed previously.

    4. The volumetric equation yields a reserves estimate of 86.159 106 m³ or 3.058 bcf. This assumes that the well will drain one section and that the net pay is constant at 7.5 metres (24.5-ft.). There was insufficient pressure and production history provided to perform a material balance reserves estimate.

    5. Despite the uncertainty associated with the late time derivative response, this behaviour should be noted or used as a flag as the well continues to produce. Based on the Type Curve analysis the channel or permeability trend intersected by this well has a width of about 110 metres (361-ft.)


    Reservoir Evaluated: Belly River Model of Behaviour: A Homogenous
    Model w/ Linear Flow
    Perforated Interval: 699.5-707.5m KBMPP @ 699.4 m CF

    PARAMETER

    		METRIC UNITS

    FIELD UNITS

    Extended Sandface AOF Potential:88.455(10³m³/D)3.140(MMscf/D)
    Stabilized Sandface AOF (As=259ha):80.260 (10³m³/D) 2.849 (MMscf/D)
    Extended Wellhead AOF Potential:69.593 (10³m³/D) 2.470 (MMscf/D)
    Stabilized Wellhead AOF (As=259ha):63.201 (10³m³/D) 2.243 (MMscf/D)
    Initial Shutin Reservoir Pressure (P151):3163.8 (kPa)458.9 (psia)
    Average Reservoir Pressure (PR):3161.1 (kPa)458.5 (psia)
    Final Flowing Pressure (Pwf):2070.4 (kPa)300.3 (psia)
    Final Shutin Pressure (Pws):3152.3 (kPa)457.2 (psia)
    Change in Pressure seen During the Test:81.9 (kPa)11.9 (psia)

    Gas Deviation Factor @ 26.2° C:
  • @ Initial Reservoir Pressure (P1):
    		• 0.9396 ( )0.9396 ( )
  • @ Final Flowing Pressure (Pwf):
    		• 0.9602 ( )0.9602( )
  • @Average Reservoir Pressure (PR):
    		• 0.9397 ( )0.9397 ( )

    Total Transmissibility (kh/µ)g:
    31.0
    (mDm/µPa.s)
    101656.6
    (mDft/cp)
    Total Mobility (k/µ)t:4.13 (mD/µPa.s)4131.3 (mD/cp)
    Reservor Capacity (kh)g:362.2 (mDm)1188.4 (mDft)
    Effective Permeability to Gas (kg):48.3 (mD)48.3 (mD)
    Effective Permeability to Water (kw):0.0 (mD)0.0 (mD)
    Total Apparent Skin (St):-0.25 ( )-0.25 ( )
    Pressure Drop due to Skin (dPskin):-37.9 (kPa)-5.5 (psia)
    Total Flow Efficiency (FE):1.03 ( )1.03 ( )
    Damage Ratio (DR):0.97 ( )0.97 ( )
    Transient Rinv (Assumes IARF):203.8 (metres)668.6 (feet)
    Time to Pseudo Steady State (A=259 ha):805 (hours)805 (hours)
    Cumulative Gas Production (Gp):88.410 (10³ m³)3.138(MMscf)
    Cumulative Condensate Production (Np):0.0 (m³)0.0 (STB)
    Cumulative Water Production (Wp):0.0 (m³)0.0 (STB)
    Water-Gas Ratio (WGR):0.0 (m³/10³ m³)0.0 (bbls/MMscf)


     

    For technical assistance please contact:
      Gary Loman (805) 967-3578 Santa Barbara, California
      Doug Hartle (403) 270-0787 Calgary, Alberta




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