Special down hole problems may make it necessary to completely immerse a
specific area of the wellbore with acid, for example:
- · Removing permeability damage caused by mud filter cake or scale deposits on the formation face or in perforation tunnels.
- · Freeing stuck pipe.
- · Dissolving junk in the hole.
When spotting acid in the annulus to solve these problems, the fluid columns in the
tubing and in the casing must be either balanced so that no pressure differential
exists, or enough pressure must be held at the surface to balance out the difference
in hydrostatic heads.
13.1.1 Balanced Columns Method.
When it is necessary to balance the fluid columns, the height to be filled with acid
and or solvent must be determined and the volume of fluid calculated. When this
volume has been pumped into the well, just enough flush and displacement fluid
should be pumped to balance the fluid columns, that is, that the top of the acid and
or solvent is at the same level both inside and outside the treating string (if the hole
is standing full).
13.1.2 Unbalanced Columns Method.
When the bottom of the tubing is below the treating area, enough flush and
displacement fluid must be pumped to displace the acid down the tubing and up the
annulus to the desired location. Normally this spotting method results in an
unbalanced condition between the volumes in the tubing and casing. To prevent
further fluid movement towards equalisation enough pressure must be held on the
tubing at surface to balance out the difference in hydrostatic heads.
Relatively small volumes of fluid are used in spotting pickling and solvent soak
treatments (250 to 1000 gallons). The precise volume used depends upon the
nature of the treatment and the length of section to be filled.
Acid treating solutions typically employed in pickling treatments are NE-Type Acids
which normally consist of inhibited hydrochloric acid with the necessary demulsifying
and low surface tension surfactants. Other acid systems used include Mud Sol
acids, Clean-up and MMR acids, One Shot acid, Sequestering, Organic acids and
The maximum surface treating pressure at the maximum allowable pump rate is
calculated as follows:
Maximum Surface Treating Pressure =
(Fracture Gradient x TVD) + Friction Pressure - Hydrostatic - 300 psi
Note : 300 psi is an arbitrary safety factor to assure that the reservoir will not be
fractured.
In many sandstone matrix stimulation treatments, the initial injection rates will be
substantially less than those predicted when using the above equation and Figure
21, when pumping at the maximum allowable treating pressure. This is caused by
permeability damage in the near wellbore area. Once this damage is removed by the
acid , the predicted and actual injection rates will be close in value.
probably will respond better to a proppant fracturing treatment, than to a sandstone
matrix treatment, since the treating time would be extremely long for matrix
stimulation.
Example :
Well Depth (TVD) 9500 ft
Permeability 100 md
Formation Thickness (MD) 10 feet
Fracture Gradient 0.65 psi/foot
Fluid in Hole 15%:4.0% HCl:HF
Hydrostatic Pressure Gradient 0.476 psi/foot
Formation Pore Pressure 4500 psi
Tubing Size 2-3/8 inch
Formation Fracture Pressure = Fracture Gradient x Depth (TVD)
= 0.65 x 9500
= 6170 psi
Hydrostatic Pressure = Hyd. Pressure Gradient x Depth (T.V.D.)
= 0.476 x 9500
= 4522 psi
Differential Pressure = (Formation Fracture Pressure) -
Formation Pore Pressure - 300 psi
= 6170 - 4500 - 300
= 1370 psi (DP)
Formation Flow Capacity = Formation Thickness (MD) x Permeability
= 10 x 100
= 1000 md. ft.
Maximum Injection Rate = 2.3 Barrels Per Minute.
(From Figure 21)
Friction Pressure = Friction Pressure From Figures x
(From
Figure 17, page 100) Specific Gravity x Depth (MD)/1000
= 90 x 1.08 x 9500/1000
= 922 psi.
Surface Treating Pressure = (Fracture Gradient x TVD) + Friction
Pressure - Hydrostatic - 300 psi
= 6170 + 922 - 4522 -300 psi
= 2270 psi
Therefore maximum surface treating pressure is 2270 psi at a maximum treating
rate of 2.3 barrels per minute.
13.5 Shut-In Times.
Shut-in time is the length of time a well is closed in after a stimulation treatment is
completed, before flow back is initiated. This time is determined by the type of acid
used and by downhole factors such as formation type, bottom hole temperature and
bottom hole pressure.
After an acid solution has been neutralised by reaction with the formation, it is no
longer a stimulation fluid. However it may become harmful to the formation
permeability if allowed to remain downhole.
13.5.1 Hydrochloric Acid with Limestone.
Hydrochloric acid reacts so rapidly with limestone that it is essentially neutralised by
the time the acid has been completely placed. This generally holds true at all ranges
of temperature and pressure. Since limestone formations incorporate varying
amounts of insoluble materials that can plug permeability, if allowed to come to rest,
it is important to remove the neutralised hydrochloric acid as soon as it is spent.
Shut-in times with such formations is zero.
13.5.2 Retarded or Emulsified Acid.
When chemically retarded acids such as the Sta-Live systems, and emulsified acids
such as SRA-3 are used, the reaction time of the acid can exceed the displacement
time. Here a shut-in time of one to two hours is recommended for maximum
stimulation. The shut-in time may be extended where there is sufficient bottom hole
pressure to promote rapid clean-up
.
13.5.3 Organic Acid and HCl Acid Mixtures.
Mixtures of acetic or formic acid with hydrochloric acid delay the time required for
complete spending of the acid mixture and thus require a shut-in time.
13.5.4 Gelled and Cross-Linked Acid Systems.
When Gelled or Cross-linked acids are used the reaction time of the acid can
exceed the displacement time. In these cases, longer shut-in times are required to
allow time for the acid to fully spend and the viscosity to be reduced to allow easy
flow-back.
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