Mini-Frac Treatment: Details on terminology & Step-down Rate Test
This blog serves as the third installment in our Blog Series: Mini-Frac Treatment, The Key to Successful Hydraulic Fracturing.
In the last blog, we outlined the execution phases of minifrac treatment and how each phase is used to extract different key information regarding the target formation. In this blog, we will discuss in detail the terminologies used in minifrac analysis and discuss in detail the step-down test that is used to estimate perforation & near-wellbore friction.
Net Pressure is a function of volume of fluid entering the fracture versus volume leaking off into matrix. More the rate of injected volume means higher net pressure. In absolute terms (keeping rock nature out of mind), higher net pressure intuitively means more force available to crack open the rock, leading to larger frac width and larger dimensions of frac (height, length).
Closure pressure is an indigenous property of rock and is function of overburden, resultant lateral deformation and techtonics. As the relationship between closure and net pressure suggests in above equations, higher closure pressure means smaller net pressure which means smaller fracture geometry.
Frictional pressure loss is a function of multiple interconnected parameters including pumping rate, fluid rheology, tubular roughness, perforations and near wellbore tortuosity etc. Higher frictional losses mean that system is stealing away from the applied horsepower before it finally reaches inside fracture (and contributes to net pressure). Pipe friction, generally being more predictable, can be simulated for a given fluid type, pipe ID & roughness and pumping rate. Remaining two contributors to losses are perforation and NWB region, for which step-down tests are carried out. Any sudden drop in bottomhole pressure from a corresponding drop in pumping rate represents friction and step down rate test analyses helps to identify tortuosity and perforation friction values from total frictional losses so that remedial action can be taken place (treatment design modification, re-perforation, acid wash etc). With this analyses being done through computer aided models, the basic idea is to curve fit the measured frictional pressure loss values with following relation and predicting individual pressure loss values as a function on pumping rate:
Total Frictional Pressure Loss = C . Q1/2 (NWB friction) + C . Q2 (Perforation friction)
Where,
C is empirical constant
Q is pumping rate
(Left plot) Typical step-down rate test at end of minifrac pumping. (Right Plot) Total friction & individual components of friction as a function of rate
Following step rate test as pumps are shut-in, pumping rate through tubular and across sand face goes down to zero in few seconds. Frictional pressure losses being function of pumping rate, also become zero and surface gauge pressure at this moment is resultant of net fracture pressure. This pressure is referred to as ISIP (instantaneous pump shut-in pressure) or frac gradient when normalized with vertical depth of target zone. This piece of information is related to other key values as following:
ISIP = Net Pressure + Closure Pressure
ISIP= Surface pump shut-in Pressure + Hydrostatic Pressure
Picking up right ISIP through Mini Frac helps in more reliable estimation of pumping pressure requirements during main frac as well for fracture modeling purposes.
In the next installment of this blog series, we will discuss the two different parts of pressure fall of data that is analyzed post minifrac pumping. This categorization is made through the closure point, the point when fracture closes. Data recorded before this point and after pump shut-off is called pre-closure period, while data after closure point is called post-closure period.
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