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Inflatable Casing Packers - ICP Inflatable Production & Service

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Page 1: Inflatables presentation 9.17.15 rev1

Inflatable Casing Packers - ICP

Inflatable Production & Service Packers - IPP

Page 2: Inflatables presentation 9.17.15 rev1

Who is Iso-Tech Isolation Technologies?

Funded by Intervale Capital in September, 2014 to manufacture the most reliable Inflatable Casing Packers in the world

40,000 square foot manufacturing plant located at 4607 World Houston Parkway, Houston, TX

Management has over 120 years of combined Inflatable Packer experience

Committed to the highest standards of qualifying and testing of inflatable packers

Page 3: Inflatables presentation 9.17.15 rev1

Why Isolation?• The running of concentric casing requires

ZERO gas/oil migration into annuli• In many cases, this is enforced by local

governance and ordinance• This has been magnified by a recent

GOM incident• Additionally, reservoir characteristics

pose challenges with OWC/GOC and large permeability differences that allow unwanted flow into wellbore

Page 4: Inflatables presentation 9.17.15 rev1

Isolation Solutions• Historically, the method for providing

isolation has been cement• While cement is a good isolation medium, it is

susceptible to voids and non-conformances• Often bad cement jobs result in workover and

secondary squeeze operations• Cement used alone in highly

deviated/horizontal wells leads to fluid swapping and high-side channels

• Inflatable Casing Packers

Page 5: Inflatables presentation 9.17.15 rev1

Inflatable Casing Packer - ICP

• Built on a joint of casing and run as an integral part of casing string

• After inflation, it provides immediate zonal isolation

• May be set inside open hole or cased hole• Setting hole range is largest of ANY

packer type• Can be manufactured on casing sizes

ranging from 2-3/8” to 20”

Page 6: Inflatables presentation 9.17.15 rev1
Page 7: Inflatables presentation 9.17.15 rev1

IsoTech ICP Design Advantages

• Patented lock ring: Superior method of securing outer subs to mandrel and holds more load in the event the ICP hits a ledge during run-in; has been tested to twice the anticipated load. Example: 5-1/2” tested to 375K lbs with no movement

• High-flow valve system: Heat-treated and coated with a special abrasion-resistant coating to substantially reduce erosion effects of heavy mud or cement through valve system. ie: flow test of 3 bbls of 16# cement at .25 bbl/min with ZERO erosion

• High-strength valve system: after functioning, successfully tested to 12,500 psi from ID of casing simulating frac pressure

• Valve system rating: FULL casing rating

Page 8: Inflatables presentation 9.17.15 rev1

Design Advantages

• Improved end sleeves: designed to take max inflation pressure without deforming thus increasing the element’s differential capability

• Element stability: As rubber cures, it flows into a shallow square groove pattern that has been machined into mandrel. This prevents rubber from bunching up if packer encounters a tight spot running in hole

Page 9: Inflatables presentation 9.17.15 rev1

Grooved pattern in Mandrel

Page 10: Inflatables presentation 9.17.15 rev1

ICP Dimensions

Page 11: Inflatables presentation 9.17.15 rev1

Differential Pressure Capabilities

Page 12: Inflatables presentation 9.17.15 rev1

Supporting Cement in Vertical Wells

Problem: During drilling, a lost circulation zone cannot sustain a column of cement

Solution: An ICP is run in conjunction with a Stage Tool

- Once inflated, the ICP will act as the support for the cement above when the lower zone can’t sustain the pressure

- Packer provides immediate isolation while the cement cures

Page 13: Inflatables presentation 9.17.15 rev1

Gas Migration Prevention Problem: Shallow gas zones can have

adverse effects on cement during curing, causing a “honeycombing” of the column and allowing gas flow to surface

Solution: Using an ICP as a barrier to isolate the gas flow so that the cement may cure uncorrupted

- Position the ICP just above the gas zone- Perform primary cementing through the

shoe- Bump top solid plug and inflate the ICP

Page 14: Inflatables presentation 9.17.15 rev1

Supporting Cement

Page 15: Inflatables presentation 9.17.15 rev1

Isolating water contact

Page 16: Inflatables presentation 9.17.15 rev1

Isolating producing zones

Page 17: Inflatables presentation 9.17.15 rev1

Preventing gas migration

Page 18: Inflatables presentation 9.17.15 rev1

Providing segregation within horizontal zones

Page 19: Inflatables presentation 9.17.15 rev1

Isolating the build section from a horizontal producing zone

Page 20: Inflatables presentation 9.17.15 rev1

Isolating build section from a low-pressure

horizontal zone

Page 21: Inflatables presentation 9.17.15 rev1

Plugging and abandoning

Page 22: Inflatables presentation 9.17.15 rev1

Valve System OperationRun in hole

Page 23: Inflatables presentation 9.17.15 rev1

Valve Sequence

Page 24: Inflatables presentation 9.17.15 rev1

Valve Sequence

Page 25: Inflatables presentation 9.17.15 rev1

Valve Sequence

Page 26: Inflatables presentation 9.17.15 rev1

Cement Inflation - 1

Page 27: Inflatables presentation 9.17.15 rev1

Cement Inflation - 2

Page 28: Inflatables presentation 9.17.15 rev1

Cement Inflation - 3

Page 29: Inflatables presentation 9.17.15 rev1

Cement Inflation - Full

Page 30: Inflatables presentation 9.17.15 rev1
Page 31: Inflatables presentation 9.17.15 rev1

Questions for engineers• Have you been doing any squeeze

work?• Are you getting full returns on your 1st

stage cement jobs?• Are you experiencing high water

production in your conventional wells?• Do you have any casing pressure

issues at surface?

Page 32: Inflatables presentation 9.17.15 rev1

Inflatable Production & Service Packers - IPP

Page 33: Inflatables presentation 9.17.15 rev1

Why an IPP? Injection Production Packers (IPP’s) can be

run into to completed or open-hole wellbores to perform testing, stimulation and / or temporary abatement

Due to the nature of the slim design, IPP’s can be run into wells with restrictions in the completion such as; safety valves, wellheads, nipples, etc,…

The various setting / bleeding options allows for reliable performance in even the most challenging conditions

No pipe movement needed to set packer Full ID with no restrictions through tool

Page 34: Inflatables presentation 9.17.15 rev1

AlternativesCompression-type Packers

Hole setting ID ranges are usually very small

Not ideal for run-in with restrictions Small elements can fail when tensile

loading is experienced Not recommended for open-hole

Wireline / Tubing-conveyed Bridge Plugs Not capable to setting in highly deviated

wells Limited options when referring to

stimulation below the packer

Page 35: Inflatables presentation 9.17.15 rev1

Inflatable Production & Service Packer

IPP’s are reinforced inflatable elements Once inflated, provide immediate zonal

isolation Can be set inside casing and open hole Can be set multiple times during the same

run Stimulation and treating below the packer

without hindering seal

Page 36: Inflatables presentation 9.17.15 rev1

Casing Integrity Testing

Problem: There has been various instances of casing failure in a given field and finding the leak is top priority

Solution: Running an Multi-Set IPP on drillpipe to pressure test the casing in sections to determine the leak location The IPP is inflated using workstring pressure to

provide a point of isolation in the casing Pressure can then be applied above or below the

packer to test integrity Can be run with a J-Circulating Valve which can be

actuated to communicate flow from tubing to annulus

Page 37: Inflatables presentation 9.17.15 rev1

Isolating below Casing Patch or Damaged Casing

Problem: An Operator is facing issues with damaged / corroded casing above his producing section and would like to bypass casing patched areas

Solution: The reduced OD of the IPP allows it to be drifted through the damaged section and past the casing patches until it can be set inside good casing Set IPP below the damaged sections Production can continue through the workstring

without needing to kill the well

Page 38: Inflatables presentation 9.17.15 rev1

Open Hole Bridge Plug

Problem: If a lower section is starting to produce water or production has become financially unviable it should be shut-off

Solution: Running an IPP with a hydraulic or mechanical disconnect to leave plug in the well Set IPP above desired shut-off zone Disconnect from the packer using either a

hydraulic or mechanical disconnect Optionally pump cement on top of packer for

a permanent plug

Page 39: Inflatables presentation 9.17.15 rev1

Bridge Plug in section-milled casing in P&A Operation

Position IPP in larger casing in milled section Drop ball, inflate packer, close tubing test

valve Dump cement

Page 40: Inflatables presentation 9.17.15 rev1

Scab Liner with Production Packer

Problem: After a period of time the open hole production has see unwanted flow coming from the heal of the well

Solution: Running an IPP and mechanical packer with a section of tubing connecting the two IPP is set below the heal (in the horizontal

zone) Mechanical packer is set inside the casing Solid tubing between both packers with

prevent any flow from the heal

Page 41: Inflatables presentation 9.17.15 rev1

THANKS!