Overview

Cardium formation has seen prolific production in the Ferrier/Strachan area of the Alberta Foothills since being thoroughly explored in the historical days of the industry.  Most of the conventionally-drilled wells had long since depleted their economic reserves prior to the emergence of Hz multi-frac’ technology.  The fast-paced gains and cost efficiencies of current industry trends are of particular economic importance to this mature neighborhood. 

Sansum’s Cardium prospect, however, follows an unexplored Cardium trend linked to challenging river valley topography and access issues.  This may have been a barrier to past development and presents geologic and strategic opportunity.  A combination of raw exploration and rapidly evolving technology highlight the emerging economic viability as proven by Sansum’s 1-19-39-10W5M Cardium A well awaiting tie-in. 

PHOENIX CARDIUM A and B TRENDS

Sansum owns three contiguous sections (shaded yellow below) of P&NG rights to the Cardium formation.  The Cardium A well at 1-19-39-10W5M was drilled by Burlington in 2005 and was subsequently completed with a 20t oil frac’ by Albreda Resources in 2010. 

The Cardium B sandstone in the Phoenix area was deposited in a shallow shelf environment.  The Strachan Cardium B pool in Township 38, Range 9 and 10W5, to the southeast, was deposited as a near shore marine sandstone within this shallow shelf environment.  The sand in this pool varies in thickness from 2 to 4 meters, with log porosities from 4 to 8%.  Production is a liquids rich gas that that has initial flow rates from 0.5 mmcf/d to just over 1 mmcf/d.

1-19-39-10W5M BOREHOLE

The 1-19 borehole proves the validity of the prospect as a Hz multi-frac’ drilling candidate.  Sansum conducted a 4-day flow test in the fall of 2017.  The Cardium A reservoir at the 1-19 location is over-pressured (>34Mpa), liquids rich (80-100BBL/mmcf condensate), has a 1.5m porosity streak of 15% (4m >6%) and a permeability of 0.015 mD.  Regional seismic analysis indicates folding over portions of the land related to centrally located thrust faults.  The establishment of rollover and presence of druzy quartz crystals in the drill cuttings are indicative of a fracture porosity component not apparent in the 2017 1-19 test results.

The models at left are built from the 2010 1-19 e-report utilizing 800m Hz leg 8-stage 20t multi-frac’ wells.  The 1-19 in its current form is in red and various fracture porosity scenarios are plotted as presented.

The 1-19 surface lease location is an ideal multi-pad location and its strategic down-dip location could be utilized to drill numerous Hz wells.

Yhe models at left are built from the 2010 1-19 e-report utilizing 800m Hz leg 8-stage 20t multi-frac’ wells.  The 1-19 in its current form is in red and various fracture porosity scenarios are plotted as presented.

The 1-19 surface lease location is an ideal multi-pad location and its strategic down-dip location could be utilized to drill numerous Hz wells.

1-19 SLICKWATER FRAC’

Sansum believes the 1-19 has near-borehole damage in the Cardium A due to a highly-pressured single-stage casing cement job in 2005 and an abandonment operation attempted by Bonterra in 2016 which released 25 m3 of freshwater kill fluid into the formation.  The 2010 fracture stimulation is calculated to have a 28.5m frac’ half-length and may be less.  

Sansum has investigated the merits of conducting a 50t slickwater frac’ on the 1-19.  A Trican modelling simulation predicts a 343m half frac’ length.  However, the 1-19 has 4.5”

casing with a limitation near the frac’ pressures contemplated.  A 3.5” frac’ string should be used.  This creates operational friction-related concerns which Trican has assessed in predicting a 60% chance of attaining a 343m half-length and a 90% chance of attaining 100m.   Cost: $600k.

SLICKWATER FRAC’ PRODUCTION MODELS

Sansum has run production models for 100m, 200m and 300m half frac lengths.  A 300m half-length increases the 1-19’s production by a factor of about 10.  The chard below shows various Phoenix payout scenarios (All assuming 100 BBL/mmcf liquids component).  August 8, 2018 prices, $86.35 Cond.; $1.82/mcf Gas/net $71.35; $.47/mcf – 5% GORR.

PROCESSING FACILITY ACQUIRED

Sansum has acquired a 57% working interest in a processing facility at the 7-21-39-10W5M location.  It is ideal for the production of the liquids-rich gas discovered at the 1-19, has 650 hp of compression and is capable of processing 10 mmcf/day.  The facility has an insured replacement value of over $2.8 million.  A 4” pipeline tie-in to the 1-19 has been surveyed and can be constructed for $1.6 million.  Sansum has acquired the applicable pipeline corridor approval and is preparing to begin construction in later this autumn.

INDISTINCT NATURE OF MATERIAL GAIN

All projections and modelling utilized in this summary are based on actual 1-19 production test data.  The well’s positioning on the very edge of the mapped trend, areal and vertical extent of the 15% porosity streak and the suggestion of a natural fracture porosity component are silent factors which could lead to enhanced results.

A 2009 1-19 drill cutting analysis by D. Hayden RPT (Geol) indicates a permeability streak of up to .3 mD, well above the .015 mD determination of the 1-19 e-report.  Formation damage could reconcile this incongruous data. The cement hydrostatic head on the 1-19 wellbore at the top of the Cardium formation has been calculated at 47,059 kPa.  The 2010 20t oil frac’ experienced a near-identical breakdown pressure during the 2010 fracture stimulation of 47,466 kPa.

Sansum has reviewed the drilling records and believes that the Cardium formation at the 1-19 wellbore may have experienced significant near-wellbore skin damage related to cement losses during the production casing’s single stage cement job.  Barite weighted mud losses during drilling may have also contributed to this damage.  Drilling records indicate that while cementing the production casing, 30% excess volume (based on the caliper log) was pumped as there were no cement returns to surface and the annular fluids did not remain static after pumping was stopped. 

Whether whole cement was lost to invasion-prone fracture porosity or the hydrostatic head pressure allowed cement filtrate to invade the formation outside of the near wellbore area, it  may be possible that this invasion reached further than the effective 28.5m half-length of the 20t frac’ stimulation.  If this were the case, then some of the assumptions used in the test analysis may not be reflective of what the formation can actually yield in an undamaged, stimulated state.

Seismic mapping of the Cardium A indicates major faulting in immediate proximity to the 1-19.  Should anticipated slickwater frac’ half-lengths encounter an undamaged natural fracture porosity matrix, all bets are off.