SECTION
3
DEALING WITH HIGH WATER PRODUCTION DURING PRIMARY PRODUCTION
Various options to reduce lifting and/or water handling
costs are available in dealing with wells that produce large amounts of
water. These include water shut-off treatments using gelled polymers,
reducing beam pump lifting costs, power options to reduce electrical
costs, and separation techniques. Not all wells are conducive to having
any or all of these techniques applied, but in the right circumstances,
major economic benefits can be realized.
Water Shut-off Treatments Using Gelled Polymers.
The majority of polymer treatments to control water production
in producing wells are performed in
fractured carbonate/dolomite formations associated with a natural water
drive.10 Gelled polymers are created when dry polymer is
mixed in water and crosslinked with a metal ion (usually chromium
triacetate or aluminum citrate). Gelation is controllable, ranging from
a few hours to weeks. Slower gelation time allows for more volume and
deeper placement. Different polymer systems are available from different
service providers. Recent successful treatments in the midcontinent have
used the MARCITsm technology developed by Marathon Oil
Company. MARCITsm is the acronym for MARathon Conformance
Improvement Treatment.
Service company experience seems to be the dominant
factor in estimating how a particular formation in
a given area will respond to
gelant injection. The service provider must be prepared to alter the
original design based on the ability of a formation to accept a viscous
fluid. A
formation injectivity test is important in determining any changes in
the original design.
Creating a pressure response during treatment is the
single most important indicator of a potentially successful water
control project. A slow, steady pressure increase over a period of time
during pumping will tell the operator one of two things: 1) the
formation is reaching fill-up of polymer into the problem zone, or 2)
the reservoir temperature is causing the polymer to crosslink and build
viscosity.
Pressure response is a product of polymer volume,
injection rate and gel strength. Altering any or all of these factors
can improve the success of the treatment if reservoir resistance is not
seen as the gelant is being pumped. Increasing polymer volume is
typically the first step many service companies recommend if the Hall
plot indicates only a slight increase of pressure near the end of the
treatment. The advantage of pumping a larger volume is that greater
in-depth reservoir penetration can improve the longevity and
effectiveness of the treatment. The disadvantage of more volume is
increased treatment costs due to longer pump times and additional
chemicals.
Usually injection rates are increased at the beginning
of the treatment in order to determine how easily the formation can
accept a viscous fluid. Recent research and field experience have shown
that higher pump rates can improve the effectiveness of treatments in
carbonates that exhibit secondary permeability and porosity features.
Increasing the injection rate also reduces the service company’s field
time, which translates into a cost reduction for the operator.
Increasing gel strength or gel viscosity is
the third method for achieving a pressure response. This method is
typically used at the midpoint of a treatment when the Hall plot
shows no increase in slope or after several treatments in a particular
field indicate the need for such action. Improving gel strength can be
done by accelerating the crosslinking, increasing the polymer loading of
the gelant, or using a higher molecular-weight polyacrylamide.
Acceleration of the crosslinker in Marathon’s MARCITsm
is accomplished by adding chrome chloride to the chromic triacetate.
Mature gels can be formed in approximately 4-6 hours at a temperature of
90o F with the accelerated crosslinker, as compared to the
normal time of 16-18 hours. The advantage of this technique is that
treatment volume may be significantly decreased in heterogeneous
carbonates while the gel is placed into the highest permeability
features of the formation. The disadvantage is that higher temperature
reservoirs may cause the gel to prematurely set in or near the wellbore.
Increasing polymer loading will also improve gel
strength. A 4,000 ppm gel contains 1.4
pounds of polymer per barrel of mix water. Increasing the concentration
to 5,500 ppm will add 0.52 pounds per
barrel, which is a nominal change in chemical cost. The
advantage of high polymer loading is having a stronger gel that
crosslinks in a shorter time.
Molecular weight also plays an important part in gel
strength. Most treatments utilize polyacrylamides that have a molecular
weight of 4-8 million. This medium molecular-weight polymer can be used
for both high permeability matrix and smaller fracture systems. Service
companies can also supply higher molecular-weight products that are
designed for use in high conductive secondary features. Gels formed with
this polymer will enter only the highest permeability sections of the
reservoir where the water problem exists. The disadvantage of high
molecular-weight gels is that in-depth reservoir penetration and
subsequent water diversion may be
reduced.
Candidate selection.
Best candidates are shut-in wells or wells producing at or
near their economic limit. These wells benefit most from a successful
treatment and little is at risk if the treatment fails, other than the
treatment cost. Other selection criteria include significant remaining
mobile oil in place, high water-oil ratio, high producing fluid level,
high initial productivity, wells associated with active natural water
drive, structural position and high
permeability contrast between oil and water-saturated rock (i.e., vuggy
and/or fractured reservoir). Successful treatments have been conducted
in both cased and open hole completions.
Treatment sizing.
Only empirical methods exist at this time for sizing
treatments. Experience in a particular formation is most beneficial.
However, in many instances larger volume treatments appear to decrease
water production for longer periods of time and recover more incremental
oil. Some rules of thumb include two times the well’s daily production
rate as the minimum polymer volume or using the daily production
capacity of the well at maximum drawdown (i.e., what the well would be
capable of producing if it were pumped off) as the treatment volume.10
In lower fluid level wells the daily production rate is sometimes used
as the minimum polymer volume.
Preparation prior to pumping.
Ensure the wellbore is clean, acidize if necessary (typically
350-500 gal 15% acid, pump away with water). Establish a maximum
treating pressure; run a step rate test to determine parting pressure,
if necessary. Select an acceptable source of water to blend and pump the
treatment. Have the service provider test the water’s
compatibility to form the desired gels. Select a
polymer-compatible biocide for the mix water (typically 5-10 gallons per
500 barrels of mix water). Set tubing and packer above the zone to be
treated.
Placing treatment.
Use stages
of increasing polymer concentration. Inject treatment at a rate similar
to the normal producing rate. Keep treatment pressure below reservoir
parting/fracture pressure. Changing conditions during treatment may
warrant design changes during pumping. Over displace the treatment with
water or oil. In some instances, a
rapid pressure response early in the treatment is
a danger sign the treatment may not be successful.
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