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Examples of IOR by Controlling Water
Rick Hutchins, Schlumberger
Advisor
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Outline
Introduction
Reservoir vs. wellbore: sweep efficiency vs. channels
Treating Injectors
ACTive* tool for interventions
Horizontal wells and the problems they present
Isolation in slotted liners
Temporary plugs
Concluding remarks
2
* Mark of Schlumberger
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Introduction to water control
Viewed as a mature science by those not directly involved
Seen as a toolbox by those with some past history
May be looked on as a succession of field experiments with
past history as a guide
Results can range from failure to huge success, giving the
art of water control a certain mystique.
Evaluation employs many disciplines
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Sweep efficiency
Failure to understand heterogeneity can determine the
success of an enhanced oil recovery project.
The use of reservoir diagnostic tools such as interwell
tracers, pulse testing, interference testing, simulation and 3D
seismic combined with detailed geological studies is key to
understanding heterogeneity.
Diversion of injected fluids is critical to maximizing sweep
efficiency and ultimate oil recovery where reservoir
heterogeneity exists.
Diversion techniques are varied as are the practical results. 4
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Historical literature claimed success in diversion
South Swan Hills using massive lignosulfonate gel injections
claimed 3.3 million bbl incremental response (SPE 15547). One
year later, a paper (PETSOC 87-06-07 ) stated:
“Lignosulphonate gel treatments and dual completions were tried in
the early stages of the secondary flood in an attempt to improve
vertical distribution of the injection fluids. However, the applicability
and success of these methods were limited”
5;
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Historical literature claimed success in diversion
Foam diversion in steam flooding yielded 6-14 % OOIP in
pilots (SPE 20201)
Foamed gel employing large volume treatments for injected
CO2 diversion cites 40,000 bbl of incremental oil (SPE 54429)
BrightWater® states 60,000 bbl incremental oil (SPE
121761)
6;
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Historical literature techniques for channels and linear
features
Moderate volume crosslinked polymer gels for single well
remediations (SPE 49075, SPE 22649 , SPE 26653, SPE
30426, SPE 98119)
Large volume crosslinked polymer injections used in
fissured and fractured reservoirs (SPE 21894, SPE 27825, SPE
112021)
Microgel injection (SPE 82228, SPE 106042)
Preformed gel injections (SPE 89389, SPE 113997)
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Treating injectors
Treating the injection side
is often the most efficient use
of chemicals.
In a pattern flood with
suitable geology, shutting off a
high permeability thief zone
can drastically improve oil
recovery.
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Injection treatment summary
Water injection well in a pattern waterflood
Sandstone
Permeability = 1400 md
Reservoir temperature = 200°F
Injection well temperature = 80°F
Top zone treated with 290 bbl of a rigid gel
Bottom 2 zones acid stimulated
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Combined Production Response (5 offsets)
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ACTive real time monitoring with coiled tubing
Verifies isolation success when setting through the tubing
packers or bridge plugs.
Provides real time, downhole treatment parameters
CCL for accurate depth control
Monitor inflation pressure for packer
Monitor packer differential pressure to prevent leaks
Temperature to detect fluid flow
Helps define optimal treatment sequences
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Enhanced PTC Specifications (ACTive)
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Environmental
Tensile: 45,000 lbs
Pressure: 12,500 psi
Temperature: 300 deg F
Flow Rate: 2 bpm
Physical
Outer diameter: 2-1/8”
Makeup length: 7.2 ft
Pressure
• Accuracy:
– Typical: +/- 3 psi
– Maximum: +/- 5 psi
• Resolution: 0.075 psi
Temperature
• Accuracy: +/- 1 ºF
• Resolution: 0.03 ºF
Casing Collar Locator
• Resolution: +/- 1 ft (at 30 fpm)
Tool Measurement
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Use of real time monitoring during water shutoff
Measure
– depth for setting of packer using CCL
– differential pressure to avoid exceeding packer capabilities
and prevent leaks
– bottomhole temperature for optimal cement/gel design and
effects on packer differential
Temperature increased during inflation which increased
internal pressure by ~300 psi, so inflation was halted until
stabilization, which prevented a packer failure .
Inflation resumed until disconnect; cement placed on top of
the packer to fully isolate the water at the toe of the well.
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Results of wellbore isolation
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Use of real time monitoring to isolate one of two closely
spaced laterals with an inflatable bridge plug
Tubing tail was tagged and CCL flagged for depth control.
Entry into correct lateral was confirmed by the CCL data.
Proper setting of bridge plug between casing collars via CCL
This operation could not have been done without the real
time CCL.
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Horizontal wells and the problems they present
Many wells are openhole, have sand
control completions or slotted liners -
making isolation difficult.
Access can be a challenge due to
length and restrictions.
Water intrusion often favored near
heel which affects entire well production.
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Homogeneous Formation
Heel Toe
Length
Flu
x
Homogeneous Formation
Heel Toe
Length
Flu
x
Length of the well favors random intersection with faults
Added economic pressure to recover additional costs involved
in completing the horizontal relative to a vertical well
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Horizontal wells
Faults and highly permeable
pathways often result in water or
gas problems.
Problem definition is costly
and may require sophisticated
logging with tractor for
conveyance.
Isolation is difficult.
Potential gain is substantial.
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Fractures or Faults in a layer of water (horizontal well)
Fault
Fault
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Highly deviated well in carbonate treated for rising
water contact
Well water cut rose from 70% to 95% over last 3 years.
Water salinity constant
Total fluid production constant
Openhole completion with three zones in a fissured
carbonate with fractures
Plan to set a packer, pump MARCIT below packer into
zone 3 followed by MARA-SEAL to cap the MARCIT gel
CCL used to position packer and pressure monitoring
ensured proper inflation. BHT used to adjust gel recipe.
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Fluid Schedule: MARCIT, MARA-SEAL, Cement
110 bbl of uncrosslinked polymer
140 bbl of 0.5% polymer
570 bbl of 0.7% polymer
375 bbl of 1% polymer
25bbl of 1.2% polymer
150 bbl of MARA-SEAL gelant
Class G cement in wellbore in case packer fails
Shutin 48 hours 19
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Results of gel shutoff
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Isolate a section of a horizontal well with slotted liner
Isolation tools needed for difficult wells
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Annular Chemical Packer (SPE 86938 and SPE 38832)
Coiled Tubing Inflatable Packers
Slotted Liner
Open Hole
Chemical Packer
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•Selective Zonal Isolation
Annular Chemical Packer
Treatment can now be
pumped with isolation
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Isolation of slotted liners, gravel packs and openholes
Technology is available to isolate but …
Requires many runs with inflatables
Wellbore restrictions may prevent entry
Complex procedure subject to errors
Isolation fluids are still in their infancy as they need to be
shear thinning, thixotropic and have the ability to fully
recover after shear.
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Temporary plugs
Needed to avoid damaging
productive zones
Can be useful for well
control during critical steps of a
workover procedure
Allows time for placement
of water control solution
Tend to be gels themselves
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Shown is a high concentration
temporary gel based on natural
polymer
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Venezuelan case history (SPE 111512)
Wells completed with slotted
liners or MeshRite screens with
water on bottom.
Mechanical isolation difficult
Use a temporary gel to
isolate oil zone, perforate water
zone, treat with water control
gel, finish with cement and
break temporary gel.
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Venezuelan case history results
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Venezuelan case history results
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Venezuelan case history results
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Concluding remarks
Water control techniques can have a large impact on sweep
efficiency, horizontal well performance and well production.
As new tools become available, some of the challenges of
treating wells are reduced.
Continued monitoring of the isolation technique, bottomhole
pressure and temperature allows real time decisions to
enhance a treatment for water control whether the answer is
mechanical or chemical shutoff.
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Concluding remarks
Isolation with chemical packers is feasible but risks mount
with multiple packer runs, long treatment times and non-proven
fluids.
Temporary gels are vital for treating horizontal wells but
employ 1960s technology. More effort is needed to develop
modern, robust solutions.
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Tool Measurement
ACTive Gamma Ray Specifications
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Environmental
Tensile: 45,000 lbs
Pressure: 12,500 psi
Temperature: 300 deg F
Flow Rate:
– GRSM: 1.5 bpm
– GRNM: 2 bpm
Physical
Outer diameter:
– GRSM: 2.5”
– GRNM: 2.375”
Gamma
• Standard output (gapi)
• Sensitive to:
– Thorium
– Uranium
– Potassium
Makeup length:
– GRSM: 3.3 ft
– GRNM: 3.1 ft
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ACTive Tension & Compression Specifications
Tool
Environmental
Tensile: 45,000 lbs
Pressure: 12,500 psi
Temperature: 300 deg F
Flow Rate: 2 bpm
Physical
Outer diameter: 2-1/8”
Makeup length: 4 ft
Measurement
Axial load
• Range: -10,000 lb to 45,000 lb
• Uncertainty (application dependent)
– Absolute: Typical 500-600 lbs
– Localized: Typical 300-500 lbs
• Resolution: < 0.1 lbs
Torque
• Range: 0 to 800 ft-lb
• Uncertainty: < 50 ft-lb
• Resolution: < 0.1 ft-lb
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