• The fracture stimulation for Leo 1, 2 & 3 wells commenced on 10 October
• Leo #2 will be fracture stimulated first, followed by Leo #1 and #3. Each well will take 2 days to frac. The wells will then be shut-in for 7 days to minimise sand flow back during production
• Flow testing of all three wells is expected to commence the last week of October
• The Leo Sparky Wells (3rd Generation) have been optimised with respect to horizontal length, and planned fracture stimulation intensity. The 3 wells have averaged ~3,720m MD (~320m longer than previous generation) and will each have ~50 fracture stages averaging 1.0 tonnes of sand per meter over the productive zone
• Each well is being fractured with approximately 6,000m3 of frac fluids. Around 50% of the frac fluid is expected to be recovered (expected to take 30-60 days) before any definitive production rates will be established for each of the wells
• The frac fluids include a tracer system which will trace multiple stages of each frac. This will provide critical data on determining future frac programs in the 4th Generation wells
• These wells are anticipated to produce IP90 rates between 270-460 boe/d (80% oil)
Jordan Kevol, Calima CEO, states that:
“The fracture stimulation portion of the Leo program has begun. The pumpers are rigged in, and we are pumping. The three wells will be pumped back-to-back, and if all goes well, we will be finished pumping by the weekend. Then after the shut-in period of one week, we will run pumping equipment, and open up each of the wells and begin the flow-back process. We anticipate first oil within 7-10 days, and expect to know the full potential of each well 30-60 days after initial flowback. The length of the well bore and the frac intensity has increased from historical Thorsby wells which should result in higher flow rates and EUR from these wells.”
Leo #1-3 Wells;
100% WI Completion style Each of the Leo wells were completed with ~50 frac stages spaced approximately 42m apart. The fracs are planned to have 44 tons of sand per stage with some adjustments in tonnage allocated for variations in perceived reservoir thickness, porosity, and permeability. The frac intensity will be approximately 1 ton of sand per meter of horizontal length within the portion of the wellbore that encountered the Sparky Formation. Once each frac stage has finished pumping on each of the wells, the frac interval multi-cycle sliding sleeve will be closed to allow the newly initiated fractures to “heal” around the frac sand proppant. This is a mitigating factor to ensure that the frac sand stays in the formation which helps minimize the need for future frac sand cleanouts, as well as increasing the effectiveness of the frac conductivity and production.
These 3rd Generation 1 ton per meter (t/m) frac designs represent the highest frac intensity in the Sparky wells to date. The previous second generation frac intensity averaged ~0.75t/m of sand. Additionally, the 3rd Generation Leo wells are ~320 m longer than previous generation wells. Frac tracer technology The frac sand will include the addition of multiple unique chemical tracers to improve understanding of the flowback characteristics of each frac stage and inter-well communication. This will provide the Company with intricate data that will contribute to frac design evolution for future 4th Generation Thorsby wells.
After the 7-day shut-in period, each of the wells will have their multi-cycle sliding sleeve frac ports opened up, pumping equipment run, and the wells will begin the flow back period. Since large amounts of frac fluid (~6,000m3/well) are being used, it takes 30-60 days to recover enough frac fluid before the commencement of reliable oil and gas flow rates from the Sparky Formation. Being these are the largest fracs pumped in the Thorsby field, additional time is expected before “first oil”. On lease tie-ins Once the Leo wells have produced enough frac fluid to start seeing true formation fluid, and related hydrocarbons, they will be temporarily shut-in to facilitate tying them in to our Thorsby oil battery. As seen in recent video footage released by the Company, each of the Leo wells are on the same pad site as the Company’s Thorsby oil processing facility. The wells will be tied into the battery as well as the gas sales line in an expedient and efficient fashion. The wells will then be brought back onto production, and the initial flowback period will commence, with all hydrocarbons going to sales. 30 and 90 day initial production rates It is anticipated that initial flowback will occur by the last week of October for all three Leo wells. Once the wells are flowing back frac fluid, it is anticipated that it will take 7-10 days to see any traces of hydrocarbon. Once hydrocarbons begin to appear, and the brief shut-in period to tie-in the wells, the “IP30” period will commence. This IP30 period will continue to be a combination of both frac fluid and formation fluid (oil/gas/water). It will be in the 60-90 day period where each of the wells is anticipated to be producing at their full potential, around December 2021 / January 2022.
Sparky Economics Prior to this drilling program the Company had drilled 11 Sparky wells. Of this total, the tier 1 wells (2nd Generation) averaged ~3,400m MD and 36 fracture stages with an average of 0.75 tonnes of sand per meter over the horizontal length. The Leo 1, 2 and 3 (3rd Generation) Sparky Wells have been optimised and averaged ~3,720m MD (~320m longer) and ~50 fracture stages with an average of 1 tonne of sand per meter over the horizontal length. The optimised wells are budgeted for $3.2 million per well and the Company anticipates IP90 rates of 270-460 boe/d (80% oil) with cumulative production of up to 462,000 boe. Well paybacks are 5-10 months and the NPV at 10% discount is ~C$6.5-$9.0 million.
* The 3 well Leo Drilling Campaign is anticipated to cost C$10.6m. The campaign is funded from cash flow and the Company’s working capital facility with National Bank of Canada. Production is anticipated to commence in December/January which will then be used to pay down the working capital facility. Thorsby Development Field Thorsby provides a land base of ~108 net sections (69,120 net acres) that can be developed from multi-well pads, which minimises the environmental footprint and ensures year-round access. Oil processing facilities of 3,000 bbl/d oil capacity are currently on site. Existing Thorsby wells averaged gross production of ~780 boe/d in August 2021 (100% WI) solely from the Sparky Formation. There are 11 wells drilled to date with future well recoveries estimated at 352 - 462 mboe (80% oil).
Well inventory includes 86 net Sparky Formation and 12 net Nisku Formation wells identified with multiple pools to be delineated (27 booked Sparky locations). Selected wells demonstrated significant type curve outperformance in the Sparky Formation.