Examples of IOR by Controlling Water
Rick Hutchins, Schlumberger
Advisor
Outline
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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
* 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.
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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”
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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)
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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)
Tool
Measurement
Environmental
 Tensile: 45,000 lbs
 Pressure: 12,500 psi
 Temperature: 300 deg F
 Flow Rate: 2 bpm
Pressure
• Accuracy:
Physical
 Outer diameter: 2-1/8”
 Makeup length: 7.2 ft
Temperature
• Accuracy: +/- 1 ºF
• Resolution: 0.03 ºF
– Typical: +/- 3 psi
– Maximum: +/- 5 psi
• Resolution: 0.075 psi
Casing Collar Locator
• Resolution: +/- 1 ft (at 30 fpm)
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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
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– 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
Flux
 Many wells are openhole, have sand
Homogeneous
Homogeneous Formation
Formation
control completions or slotted liners Heel
Toe
making isolation difficult.
 Access can be a challenge due to
length and restrictions.
Length
 Water intrusion often favored near
heel which affects entire well production.
 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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Fault
Fault
Fractures or Faults in a layer of water
(horizontal well)
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
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Results of gel shutoff
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Isolation tools needed for difficult wells
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Isolate a section of a horizontal well with slotted liner
Annular Chemical Packer (SPE 86938 and SPE 38832)
Open Hole
Coiled Tubing
Slotted Liner
Chemical Packer
Inflatable
Packers
Annular Chemical Packer
•Selective Zonal Isolation
Treatment can now be
pumped with isolation
Isolation of slotted liners, gravel packs and openholes
 Technology is available to isolate but …
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Requires many runs with inflatables
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Wellbore restrictions may prevent entry
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Complex procedure subject to errors
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Isolation fluids are still in their infancy as they need to be
shear thinning, thixotropic and have the ability to fully
recover after shear.
24 September 12-13, 20
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
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.
26 September 12-13, 20
Venezuelan case history results
27 September 12-13, 20
Venezuelan case history results
28 September 12-13, 20
Venezuelan case history results
29 September 12-13, 20
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.
30 September 12-13, 20
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.
31 September 12-13, 20
ACTive Gamma Ray Specifications
Tool
Measurement
Environmental
Gamma
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• Standard output (gapi)
• Sensitive to:
Tensile: 45,000 lbs
Pressure: 12,500 psi
Temperature: 300 deg F
– Thorium
Flow Rate:
– Uranium
– GRSM: 1.5 bpm
– Potassium
– GRNM: 2 bpm
Physical
 Outer diameter:  Makeup length:
– GRSM: 3.3 ft
– GRSM: 2.5”
– GRNM: 3.1 ft
– GRNM: 2.375”
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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
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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