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

po