Injection and Disposal Wells

• What is different

• How to convert producers to injectors

Purpose of an Injector

• Injectors and disposal wells have one common purpose:– To place the fluids into the correct zone, at the

highest possible rate at the lowest injection pressure.

– Achieving that goal requires knowledge of the connection of the well to the reservoir.

What Changes When a Producer is Converted to an Injector?

Few Examples…………

1. Direction of prevalent flow

2. Type of fluid flowing

3. Type of corrosion

4. Access to the formation

5. Pressure distribution in the tubulars

6. Force loads on the tubulars and packer

7. Temperature distribution along the wellbore

8. Seal behavior – fluids, pressures, temperature

9. Type of stimulation

10. Need for flow regulation

First, look at the problems -

• Placement – do the fluids enter the zone at the right place? – both depth and aerially

• Rate of injection – friction dominated?• Conformance – do they stay in the zone?• Corrosion – is corrosion as low as possible?

– Effect of oxygen, bacteria, salts, acid gasses

• Plugging – what causes it?• Can you avoid having an injector/disposal well?

Placement

• Injector placement requires that you know how the fluid moves in the reservoir.– Reservoirs are not homogeneous– Wells are not necessarily connected by permeable strata– All connections are not equal– Faults don’t necessarily seal– Seals are frequently bridged (broken) by fracturing– Some channels in the formation may be an order of

magnitude higher permeability than others.– Channels in the cement sheath may be there from the start

or may open at any time – you must check regularly.

Vertical Fractures – where do they stop?

Fluid Friction Effect on Pipe Load and Pipe Length

• Caused by fluids moving through the tubing

• A basic friction

• Maximum in high rate injection wells and high rate production wells (especially with gas breakout)

Friction Pressure vs Rate, 5-1/2" Tubing, Flowing Water

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Plastic CoatedTubing

Clean 13 Chrome

Clean Carbon SteelTubing

Corroded and ScaledTubing

Union 76 study

Frictional Pressure Force – if the tubing is free to move

• Ffr = (-p / L)*A*L

Ffr = frictional pressure force (lb)

A = flow area

L = length in FT Below point if in water injection

Above point if production

p / L = positive for flowing well

p / L = negative for injector

Force Example, Injector

• Water Injector, 30,000 bpd, 5-1/2” (17 lb/ft), 8,000 ft depth

Ffr = (59 psi/1000ft) * (8,000 ft) * (18.8 in2)

Ffr = 8874 lb

This is the force exerted on the tubing by the reactive friction from the flowing fluid – A tension force.

Depth of perfs vs. Conformance

• Where are the channels? What permeability?• Do you use them or not?

– How fast can you stand breakthrough?– Can you repair (plug off) easily?

• How can you trace fluids breaking out of zone?• How can you control it?• Will the well fracture at the injection rate? Will it

fracture from thermal effects? Is fracturing desired? (consult the field operation/depletion plans on this question)

Tracers

• What is in the injection water that is different from the other waters? – Can it be used to identify the water at breakthrough?

– Can it be used to distinguish the injection water from a leak source?

• Natural Tracers – ion types & concentration• Added Tracers – dye, isotopes, alcohols, salts, etc.

– Must not adsorb

– Must be inexpensive for large projects

Endicott Survey

A total of 20 water injector (70% of all water injectors) have been traced beginning in 1988 with other tracers injected in 1989, 1991 and 1996. 78 producers (88% of all producers) have been sampled during the tracer program.

A total of 20 water injector (70% of all water injectors) have been traced beginning in 1988 with other tracers injected in 1989, 1991 and 1996. 78 producers (88% of all producers) have been sampled during the tracer program.

Limestone Waterflood PilotSimple Integration Process:

Make Cross-SectinsPoste OH Logs, Tops, Perfs, RFTs, & TDT data. (Structural & Stratigraphic)

Post other Surveillance DataPLT splits & fluids, Existing Water & Oil intervals, Pressures & WC

Post Important GeologyPressure Barriers & Baffles, High k (thiefs) zones, erosion & facies changes

Draw Fluid MovementsLook at Vertical and Areal fluid movements

Review Production/Injection PerformancePost prod/inj plots & analyze (rates, whp, chokes, etc.)

SA Top MA Structure Map (MaA)

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0 SA-119

RFTs

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Key Wells

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SA SW-NE Schematic cross-section (2000)

SA-088 SA-100 SA-075

MaA

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MaJMaI2

NESWSA-119

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TDT Water

PLT Water

Direct Inj Com.? 1st

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Clastic Mudrock

Bioturbated Sandstones

So: 80 % OHL 55 % TDT So: 95 % OHL(pre-Inj)

45 % TDT (+/- 10%)

50% WC 15% WC

Tighter Wackstone & Clay Bearing Packstone horizons

Clastic/Glauconitic Packstone horizons

2ndPre-MaG Unconformity

Hotter Water Entry

? Aquifer???

Run TDT

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?

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Observation

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SA NW-SE Schematic cross-section (2000)

SA-098

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4% WC

TDT Water

PLT Water

Clastic Mudrock

Bioturbated Sandstones

20% WC

Tighter Wackstone & Clay Bearing Packstone horizons

Clastic/Glauconitic Packstone horizons

Pre-MaG Unconformity

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Hotter Water Entry

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SA Fluid/Response Map last Peer Review1998

SA-091

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Best Interference Response

Early Water Breakthrough

DECREASINGRESERVOIRPRESSURE

SA Schematic water movement map1999

SA-091

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SA-098

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SA-029

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SA-075

SA-099

SA-088

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MaB

MaC

MaD/E?MaH ss

MaG?

??

SA-119

DECREASINGRESERVOIRPRESSURE

SA Schematic water movement map2000

SA-091

N

SA-093SA-060

Key Wells

SA-098

SA-124

SA-102

SA-114

SA-029

SA-039

SA-125

SA-075

SA-099

SA-088

SA-100

MaB

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MaD/EMaH ssMaG

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SA-119

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MaH SandsAquifer Influx

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DECREASINGRESERVOIRPRESSURE

Patches seal off perfs in high perm streaks – check burst, collapse, metallurgy, and clearances. Patches are more reliable than cement squeezes to shut off perfs.

Downhole chokes and flow regulators help split up flow

Bridge plugs when zone isolation below a point is needed – may need cement cap in some cases.

Mechanically set up the wellbore for injection – look at entry points and crossflow.

Remember – isolation at the wellbore is only as good as the cement sheath isolation. Cement squeeze repairs may be needed.

Injectivity Reduction in Sand Control Injection Wells

• Sources of instability considered1. Sand weakened by water through-put => low UCS 2. Water hammer (reflected waves) fluidizing the sand

face => collapse of formation tunnels?3. U-tube/backsurge caused by momentum of the water

column => major sand production4. Crossflow/backflow during shut-in where a high

pressure (low perm) zone backflows to a higher k zone => produces sand.

5. Particle plugging from suspended sand carried in front of the injected fluid => reduces permeability

SPE 47329

• Non-Gravel Packed Injectors– Injection dropped from 8,000 m3/d (50,000

bpd) to 0, in 30 minutes following a shut-in.– Backflow helped but only briefly– A cleanout found several hundred meters of

formation sand above the top perforations. – Authors cited 4 damage mechanisms –

including water hammer.

Water Hammer

• Water hammer is the force generated by a reflected wave, primarily behind the valve, when the valve is closed rapidly on flow of a primarily incompressible fluid.

• A water hammer force can be created when the valve closure time is shorter than 2L/c, where L is the length of the tube from valve to source and c is the speed of sound in the liquid filled system.

Water Hammer – Strength in Injector

• Water hammer is fundamentally a reflected wave force that has its maximum impact behind (the upstream side of) a valve that is closed faster than the sonic travel time from the valve to the flow source and back.

• In the Statoil paper (SPE 47329) the reflected wave measured with a surface pressure gauge. In this experiment using a hard shut-in, the magnitude of the pressure spike at surface was only 15 bar or 225 psi. They measured 80 bar (1450 psi) at bottom hole – was this a water hammer or a U-tube created underbalance?

Problem – More than one cause?

• In injectors in formations where sand control is required, there is an often sudden injection decline following shut-in.

• From an analysis of literature, there appear to be links between: – incident of rapid injectivity decline and current

formation strength; – rapid injectivity decline and fast shut-ins; – rapid injectivity decline and completion type; and – severity of damage and type of damage mechanisms.

Some Unanswered Questions

• Momentum of the flowing water column in a vertical well is not accounted for in the literature. Beirute identified this a U-Tubing in the cementing literature. Shutting in a fast moving column of water would not keep fluid from flowing down the well, underbalancing the wellbore hydrostatic and resulting in an underpressured state that would lead to backflow and sand production.

• The vacuum produced as the water column dropped would not pass a reflected wave, seriously damping the compressional force application of a wave and effectively eliminating the reflection wave.

• Without significant backflow – as from U-tubing, there is no way to carry the amount of sand with a a water hammer wave.

Injector Suggestions

• Non packed injectors– Slowly shut-in wells to limit “water hammer” or “U-Tube”

pressure effect. Slowing pumps down over 10 to 15 minutes may have better effect than a slow shut in of the system – production may have to shut down, but sea water make up can be used to slow pumps down gradually.

– 4 hour shut-in to allow sand settling– Deep penetrating, oriented perfs – Magnus experience

• Alternate Completions– Frac packed, 180o phasing, limited entry, resin coated

proppant– SPE 84416 – self cleaning downhole screen injector

Corrosion/Erosion

• Remove the oxygen – 80% problem reduction. Oxygen in an injector accounts for the bulk of corrosion and much of the bacteria problems.

• If gas injector, what are the gas properties at the operation pressure? How much CO2 – and water?

• Erosion and abrasion considerations

Dissolved Gas Effect on Corrosion

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Tubular Selection

• Low/no oxygen – carbon steel for short term• Duoline – fiberglass lined pipe – for long term.

May also run plastic liner without pulling the tubing.

• Super Duplex – e.g., Sumitomo SM25CRW - tungsten in the alloy helps resist pitting, even in fully aerated brines.

• Don’t use chrome tubing – combination of oxygen and chlorides will fail the chrome strings quickly.

Plugging

• Why? Solids are one of the reasons that injection pressures rise during injection well operation. Others:– Solids carryover (sand, silt, wax, asphaltenes)– Corrosion products (mill scale, oxides, sulfides)– Oils and greases (compressor oil in gas re-injection is a major

damage item)– Relative perm? (fluid and reservoir dependent)– Clay damage? (unlikely, but possible – fracturing usually offsets the

effect.)– Connection restrictions – usually natural problems– Reservoir fill-up. Common in small or long, thin reservoirs with few

injection wells.

Converting an Producer to an Injector

• Concerns:– Corrosion in the tubulars– An injector may handle >10 times greater fluid rate than a

producer.– There may be large amounts of residue in the well (pipe

dope, scale, paraffin, asphaltenes, corrosion products, fill, silt, sand, etc.) that need to be removed first. Consider a jetting cleanup run over the entire wellbore that is in the injected fluid path.

– A solvent flush may be necessary in some cases (remove heavy oil, sludging oil, emulsifying oil, etc.) before first water injection.

Tubular Design Suggestions

• Avoid chrome tubulars in most water disposal wells where oxygen is present in the injected fluids.

• Use the largest tubing possible.• Plastic line the tubulars:

– Prevents further corrosion

– Prevents much of the erosion

– Reduces friction (less injection power required at a given rate).

Oxygen levels in brine – Chrome Pipe Corrosion

From laboratory testing and experience with storage of 13Cr in coastal areas subject to salt spray (like Trinidad) we have seen that 13Cr pits rapidly in oxygen saturated brines. The O2 levels in the brine in this case are in the range of 6-8 ppm (6000-8000 ppb) because they are saturated with air at 1 atm. These levels are higher than what we would encounter in a typical injection or production well.

The bad news, though, is that while laboratory tests showed 13Cr to tolerate low O2 levels, actual experience with 13Cr tubing in injection wells indicates that damage can occur even at very low oxygen levels – perhaps at the 20ppb level. The damage mechanism is not pitting per se. The tubing does not fail because of general pitting on the surface like we see with fully aerated brines or the failures in storage yards. The failures occur in the crevices at the metal to metal seals in the connections.

Note the seal crevice corrosion – this caused a leak to the annulus.

Source – John Alkire

Crevice Corrosion

• The physical nature of the crevice formed by the seal produces a low pH aggressive environment that is different from the bulk solution chemistry – hence a material that looks fine when tested as a flat strip of metal can fail when the test sample (or actual tubing) includes a tight crevice.

•  This damage can be very rapid – causing failure of the metal to metal seals in a matter of months.

Crevice Corrosion

• There have been three notable instances of this occurring in seawater injection systems in the North Sea – a Statoil well after 9 months, – Gyda where they claimed O2 levels were

kept to <20 ppb, – at Macher (part of ETAP) where O2 levels

were controlled to 50 ppb or lower.

Note the pit that started the washout – seal crevice corrosion at a highly stressed area.

Source – John Alkire

Closeup on damage to back side of pin. Source – John Alkire

For Larger Volumes and Rates…

• Tubular size as large as possible to cut pump power requirements and improve volumes handled.

• Tubulars have smoothest possible finishes to reduce friction

• Can you inject down plastic lined casing to maximize rate and minimize power cost?

• Make sure perforated intervals are correct. Is perforation density sufficient?

• Will the well fracture during injection? Will fracture be contained in the target zone?

Removing Debris and Residue Before Injecting

• Methods:– Backflow – excellent first step if pressure will achieve

backflow (hint: don’t re-inject the backflow without filtering the solids out first). Consider backflow during foam jetting if this is a low pressure well.

– Jetting – excellent method of cleaning tubulars.

– Acidizing – can improve near-well formation permeability, but clean the wellbore tubulars before acidizing (or all the debris will be transported to the formation).

Formation Interferences

• Permeability barriers – only fracturing has any impact on deep problems. Matrix acidizing will only reach a few inches.

• Limited connection – consider re-completing the well; either re-perforate into the zone or kickoff and re-drill.

• Poor sweep – recomplete well to deviated or horizontal wellbore?

Operation

• Start up, shut down and switching fluids in WAG floods creates severe pressure swings (often 1000 psi or greater) in bottom hole conditions. This may cause solids to move downhole. Slowing the rate of start-up and shut-down can help in this case.

• Also, multiple zones open at once can see crossflow between zones. This can be detrimental in some cases

Filtering????

• Produced water will have some debris. Make-up (surface) water will have both debris and bacteria.

• Debris can plug permeability.• Bacteria can sour the reservoir.• Filtering can remove both, HOWEVER, filtering

is a large investment in both initial and maintenance cost.

• Is there another way?

Cleaning the Water

• Solids Removal Methods:– Filtration with either DE or cartridges – very positive method

but costly and time consuming.– Sand filters – marginally effective filtration, but usually are

breeding grounds for bacteria colonies.– Settling tanks – efficient if space permits, but there are

problems with oxygen input.– Strainers – only get out large pieces – usually only effective in

sequence filtration.– Cyclones – good first step for very dirty fluids – usually not a

long term approach for final cleaning of water.

• Bottom line? – there really is not a good, cheap way.

Oil

Water

Fluid

Patent 4,619,771 issued Oct. 28, 1986

Technique for increased retention time in oil field settling tanks

Filtration Level

• If filtration is used, the level of filtration to prevent all damage would be 2 to 5 microns at a beta of over 1000. This is not practical for most operations.

• Any filtration of the fluid is helpful. The time to plug a well operating below fracturing pressure is a function of the reservoir area open to injection and the size and amount of solids that flow into the well.

Other Unwanted Materials

• Oxygen – needs to be removed to curtail corrosion. Best approaches are sealed tanks, air tight handling systems and O2 scavengers.

• Bacteria – serious problems in corrosion and souring. SRB’s (sulfate reducing bacteria) are the worst, but other bacteria can also be detrimental. Removed by bactericide flushes, continuous treating, etc. Filtration has to be to 0.5 micron to remove most bacteria – this is not practical.