water production control
DESCRIPTION
Water Production ControlTRANSCRIPT
Water Production Control
• Setting objectives
• Collecting information
• Selecting a method
• Recompletion as a water control method
• Forget the water, stimulate the hydrocarbon
• Applying the treatment
• How long will it last
Simple Truth
The modification of the reservoir to achieve
water control is a poor substitute for using
reservoir information to plan the best
position of the wellbores - the problem is
we get the needed information about the
reservoir only from producing the wells.
Objectives in Water Control
• Control is not always possible without
reducing hydrocarbon production
• Effective, long lasting water control is
rarely cheap.
Information?
• What is the source of the produced water?
– Solution water - no cure
– Connate water - no cure
– Active drive aquifers (bottom or edge?)
– Water injection (floods) -
– Leaks
• pipe body/coupling breaches
• formation fault, seal or barrier leaks
• channels in cement
Information?
• What is the path of the produced water?
– Matrix - horizontal
– Matrix - vertical
– Fracture - hydraulic - propped
– Fracture - hydraulic - open
– Fracture - natural
– Channel in the cement
– Hole in the pipe
Information?
• Is the water moving the oil?
– Water drive?
– How much water and oil will be lost?
– Is this really economic?
• Cost of water movement (lift, corrosion, disposal)
is usually a very small cost.
• Is water processing in surface facilities limiting
oil production? This is a major argument.
Possibilities and Realities
• Water production in vertical wells.
– Formation barriers between water and oil - plug
shallow.
– Low vertical perm between water and oil - plug
several feet deep.
– No formation barriers and high vertical perm -
must plug water very deep (100 ft?).
Coning Control
• Limiting rates - calculate max production
rate - based on homogenety assumptions.
• Artificial barriers - excuse me, I’ll stop
laughing in a minute or two.
Injection Paths
• Fast zone (high perm layer) - must plug
very deep from both injector and producer.
• Fractures - same as matrix, but must
consider frac height and formations it
contacts.
Treatments (cement)
• Cement slurry - wellbore face plugging of
perfs and fractures.
• Gunk squeezes (cement in diesel) have been
used sucessfully in wider fractures for
shallow plugging.
• Cement dispersion - small particle cement
dispersions (1 lb/gal) have been used to
reduce perm in the bottom of propped
fractures (-12+20 mesh prop) in 28 wells.
Treatments
(polymers/monomers)
• Conventional polymers are very short lived
• Monomers have been used with success in
deep plugging of fractures between injector
and producer - stopped water cycling.
• Plastics good for shallow, permanent plugs.
• Resins good for shallow, not-so-permanent
plugs.
Other Treatments
• Bridge plugs (retrievable or drillable
suggested)
• Foam - hard to get deep, short lived.
• Silica Gel - a good cheap, treatment for
channels.
• Lignosulfonate gels - maxtrix plugger
Other Treatments
• “Selective treatments - only shuts off the
water - doesn’t stop the oil” (please go back
and retake basic reservoir engineering).
Recompletion Potential
• Move the perfs - limited success.
• Move the wellbore - real potential here.
• Plug the propped fracture.
Stimulate the Hydrocarbons
• Selective stimulation possibilities
– perforating
– frac?
Applying the Treatment
• Selective injection usually best method.
• Can you plug a zone from injector and
producer?
• What is the vertical control in the reservoir
when injecting?
How long will the treatment last?
• Is the treatment degradeable? (polymer,
foams, resins, emulsion, etc)
• Is an alternate flow path available to the
water?
Critical Production Rate
• In coning, water is pulled from the
hydrocarbon/water interface by pressure
drawdown from producing fluids.
• The water will rise when the drawdown
exerts a force greater than gravity
Water Coning in a Horizontal Well - an ideal perspective
Not that easy?
• The mobility, K/u is the equivalent mobility of the
flow line extending from the oil/water interface to
the wellbore.
• When water advances through an oil or gas
bearing formation, the porosity accessible to the
water is a function of the change in fractional
hydrocarbon saturation resulting from invasion of
the water times the porosity of the formation.
Example
• If porosity = 20% and oil saturation is reduced from 50% to 25% by advancing water, the porosity accessible to the advancing water, fa, is:
(0.50 - 0.25) (0.20) = 0.05 or 5%
So, linear fluid velocity in the formation, Vf:
Vf = V/fa ??????
Vf = velocity of fluid advance within formation
Critical Production Rate
Qc = 0.0000246 (K/u) (pw-po)h
Qc = critical coning rate
K = permeability, md
pw = density of water
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