The company calculated that 30% of the frack fluids would need to flow before hydrocarbons would be released in meaningful quantities. In oil production this is often referred to as the well kicking, the density of the fluid in the production tubing lowers as oil and gas displaces the static column
Looking at the current plans, it appears they are focused on getting the kick
Step 1, soaking/shut in
Allows time for the pressure to replenish from the formation
Imbibition takes place, both creating pressure by displacing hydrocarbons in the pores and reducing the volume of frack water that needs to be removed prior to hydrocarbons flowing. Also allowing the capilary and osmotic forces drawing water into the pores to reach equilibrium, so reducing the opposing flow pressure.
On completion, flow will be reinitiated with a repressurised fracture matrix, pushing out a lesser quantity of frack fluid, (16% has already flowed leaving 14% to come and imbibition could have removed half of that, leaving only 7% to remove)
It is a realistic probability that the kick will be achieved this time, given the 16% flow achieved in the first attempt.
Step 2 (Swabbing is only used if no kick is achieved in step 1)
Stimulating flow with a temporary period of mechanical swabbing until hydrocarbons begin to flow. This choice implies belief that once the kick is achieved flow will continue without artificial lift. Otherwise a gas lift/nitrogen injection or permanent pumping system would have been chosen for long term artificial lift
Looking at the clip below based on an 8000ft well helps to clarify what a difference the kick makes to the available differential pressure. Differential pressure is the driving force of flow, viscosity and permiability are the restrictive elements.
When the water in the column is replaced with oil DP increases by 20%. In our case with an 11100 ft well thats 1000 psi more driving force. Then blend a potion of gas into the oil column and 2000 psi DP looks achievable
View attachment 671031
(20min delay)