Page 210 - A Practical Companion to Reservoir Stimulation

PRACTICAL COMPANION TO RESERVOIR STIMULATION

ball sealers than there are perforations. The excess balls must ity testing between well fluids and breakdown fluids should
be pumped because of ball seating inefficiencies and place- be conducted to identify the most effective nonemulsifier.
ment timing. Breakdown treatments usually consist of only a This type of testing will also reveal any tendency for the well
few thousand gallons of fluid, and all the ball sealers must fluids to drop out paraffins or asphaltenes.
therefore be injected in a short period of time. Some balls In dry gas wells emulsions are not a problem. However,
may be rendered ineffective because they are already below a these formations often tend to retain water because of relative
perforation when it opens and begins accepting fluid. The permeability and capillary pressure effects. Breakdown flu-
seating efficiency is dependent on the density of the ball ids used in these formations should incorporate surfactants
sealer and its velocity, which results from the pump rate. that are efficient in lowering the interfacial tension properties
Figure P-58 shows the required pump rate to efficiently seat of the fluid. To further minimize the potential for a water
ball sealers of varying densities in various size tubulars. block, %reakdown fluids in tight gas reservoirs may benefit
Ball sealers having a higher density than the fluid with frorn.pumping an energized fluid to reduce the amount of
which they are pumped have a lower seating efficiency but water put in the formation. Either C02 or N2 can be used as
will fall into the rathole after the treatment and will therefore the gas phase. The fluid phase can be a weak acid, water or a
not affect subsequent treatments. Lightweight ball sealers water and methanol blend.
will be more efficient at seating but must be circulated out of Clay problems can be minimized by using an organic
the hole before the hydraulic fracturing treatment. If a light- polymer clay stabilizer in addition to 2% KCl water. Ener-
weight ball sealer is left in the hole, it can float in the wellbore gized or foamed fluids may also help minimize the effects of
fluids and reseat once the fracturing treatment begins. It is a water on the clay particles.
good practice to run tubulars past the entire perforated interval Weak acids (7.5% HC1) have long been accepted as com-
to physically knock off any remaining ball sealers before mon breakdown fluids. These fluids are most appropriate in
fracturing operations. carbonate reservoirs where the acid can actually react with
the formation. In sandstone formations the acid may not have
P-5.3: Choice of Breakdown Fluids any material with which to react. A blend of 2% KCl water
Even though production will not be significantly affected by and methanol incorporating a surfactant package has proved
near-wellbore damage once a fracture has been placed, a to be at least as effective as acid. In sandstone formations
nondamaging fluid should be chosen as a breakdown fluid. having carbonaceous cement, an acidic fluid may actually
The fluid design should take into consideration emulsions, destabilize the formation and allow the perforations to col-
water blocks, wettability and destabilization of clays. lapse. If acid is used as the breakdown fluid, reducing agents
Any time water and oil are mixed together the possibility andlor chelants should be added to the fluid to prevent iron
of an emulsion exists. Special nonemulsifying surfactants precipitation damage.
can usually eliminate this problem. Pretreatment compatibil-

P-50