examples of ior by controlling water - uw - laramie, wyoming

Examples of IOR by Controlling Water

Rick Hutchins, Schlumberger

Advisor

2

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

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* 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

Annular Chemical Packer (SPE 86938 and SPE 38832)

Coiled Tubing Inflatable Packers

Slotted Liner

Open Hole

Chemical Packer

•Selective Zonal Isolation

Annular Chemical Packer

Treatment can now be

pumped with isolation

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.

24 September 12-13, 20

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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

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.


Venezuelan case history results


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.


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.


Tool Measurement

ACTive Gamma Ray Specifications

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Environmental

Tensile: 45,000 lbs



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

ACTive Tension & Compression Specifications

Tool

Environmental

Tensile: 45,000 lbs



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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examples of ior by controlling water - uw - laramie, wyoming

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