1. This document discusses factors to consider before fracturing an old well, including evaluating the well's integrity and cement quality, understanding the original well design and changes in use, selecting optimal fracture initiation points, and designing fractures based on formation characteristics. 2. Key aspects of well integrity to examine are the condition of cement barriers, potential for corrosion or channeling behind the casing, and how the well may respond to fracturing. Understanding the era and methods used for original well construction is important context. 3. When designing fractures, considerations include injection rates, pressures, proppant selection and volume, as well as analyzing flowback to understand fracture geometry and reservoir interactions. The goal is an economic refrac that improves

1. Things To Do Before You Frac
That Old Well
George E. King, P.E.
Apache Corporation
Presented at the Sipes/API Continuing Education Seminar, “Old Field
Revitalization”, Houston Texas, August 25, 2015.
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2. Era of Construction – Technology in Practice
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Pollution potential & risk are functions of
technology & maintenance in practice over time.
1905 vs. 2015
9 hp., 25 mph and every
practical safety device
known to man in 1905.
640 hp., 200 mph and every practical
safety device known to man in 2015.
10/6/2015
Well Integrity Course
Old well behavior doesn’t necessarily describe new well behavior.

3. Today’s Engineered Fracs and Your “Old” Well
1. What’s in your well integrity? – Have a “no surprise” policy.
2. Fracture Initiation Points – Don’t waste money on what won’t flow.
3. Fracture Design – pressure, rate, proppant and CHEMICALS!
4. Flowback – what’s in it for you?
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4. Well Integrity – The Obvious and The Hidden
• Your well was once strong – is it still?
• How good was your cement job? – TOC, displacement, centralization..
• Have channels developed behind pipe?
• Sections of cement can sometimes be destroyed by multi-fracturing.
• Has corrosion weakened your pipe and cement?
• Wear points in the casing?
• What can you expect your well to do during a frac?
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5. What Fails?
Is it related to a barrier
failure or a well
failure?
Is it prevented by
another step such as
cementing?
What should happen
in a design to prevent
it?

6. Erosion & Corrosion – at the coupling
• Gap at coupling
creates an
upset in the
flowing
boundary layer
that serves as a
cushion for
corrosion or
erosion.
• The disturbance
lasts for 8 to
14+ diameters
downstream.
10/6/2015 6
During
Frac –
erosion is
shallow in
first 5
joints
During
Production
– corrosion
in pin
above the
gap. May
be in top
2000’

7. 10/6/2015 7Well Integrity Course

8. Thread Leaks
• Many different types of threads – can
rely on mechanical seal(s) or thread
dope, depending on the pipe thread
type.
• Many older connections, such as API and
buttress threads were selected for
availability or strength, but are difficult to
seal gas tight. These threads can be
subject to small leaks if the pipe dope
seal deteriorates.
• Patented threads, with much better
elastomer and metal-to-metal seals, are
available for situations requiring seals.
8Well Integrity Course10/6/2015

9. Severe pressure cycling may crack cement
Small time Interval, and pressure swing
10/6/2015 Well Integrity Course 9
1,000 psi pressure swing
Both examples had sleeve type confining of 15,000 psi
Caution – this
test is not
equivalent to
conditions
found in a well
Is this a problem?
Older well cements may
require investigation and
testing.

10. The Best “Tool” for Evaluating Cement Quality is the Pump Chart
1 Filling surface equipment w/ fresh water
2 Pressure test – two leaks in surface connection & a successful test
3 Pump spacer to separate mud from cement
4 Constant density spacer and early batch mixed cement
5 Shut down to drop bottom plug & switch to on-the-fly cement
6 Pumping cement – within density guidelines, but barely.
7 Cement free-fall – heavier cement pushes mud faster than pump in.
8 Cement density variance – was a special tail-in slurry used?
9 Shut-down to flush surface lines and drop the solid top plug.
10 Bottom plug lands, diaphragm ruptures & cement into annulus.
11 Free-fall make up – more flow in than out - pressures equalizing
12 Cement lift pressure too low – check return volumes and timing.
13 Top plug “bumps” (lands in the shoe track) – placement complete.
14 Hold back pressure on casing if float valve fails. (not in this case).

11. Open Annulus and Open Shoe.
Still a viable completion?

12. Well Type Influence – Change in Well USE from original Design or Use
is identified as a higher risk.
Barrier type, number & construction method vary w/ well type.
Well age is important, but secondary to:
1. Era of construction – what technologies were used?
2. Care with which a well is constructed.
3. Culture of maintenance.

13. Fracturing - Initiation Points & Ten Things I’ve Learned:
1. All parts of the formation are not created equal.
2. All parts of the formation are not filled/charged equally.
3. There are preferential flow paths through the formation – some help – some hurt.
4. Some flow paths connect with water, some don’t.
5. Some of best hints on flow will come from drilling, logs, offsets & a lot of study.
6. Unconventional formations different from conventional formations.
7. What produces at surface may not describe what’s in the formation.
8. Insitu stresses, mineralogy & post-depositional changes shape recovery potential.
9. There are reasons that oil declines faster than gas – some can be fixed.
10. New technologies can sometimes help if you understand what needs to be fixed.
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14. Do All Perf Clusters or Fracs Produce?

15. Look for the Gas Shows
•Gas Show
•Quantity
•Ratio of gasses
•Corresponding GR
•Other logs (CNL, Density) to help
assess TOC
•Density for Brittleness
•Resistivity for water saturation and
salinity
•ROP (rate of penetration)
•Is it a hot shale or a natural fracture?
The objective is to align the
perf clusters with natural
fractures.

16. Candidate Selection Characteristics
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17. Effect of Regional Fractures in One Field

18. Fracture Design
• This isn’t the fracture job of the 50’s, 60’s, 70’s, 80’s or 90’s and it has
changed a lot since 2008.
• The formation directs the frac – you just pump it, However….
• How you pump the frac makes a difference in how well it works.
• Surface Injection Rate Application can keep you in zone.
• Frac growth related to rate, pressure and proppant – different for each well
• What goes in the fracture treatment has changed:
• Surface and fluid modification.
• Chemicals with EOR-style character.
• Volume of proppant makes a difference.
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19. Frac Breakdown
• Frac gradient is usually 0.65 psi/ft to 0.85+ psi/ft.
Breakdown pressure
usually spikes and
drops back at the frac
is formed.
Acid, ball sealers, XGL,
and other operations
may be necessary to
more to frac
development.
This job was slowly
ramped up to develop
natural fractures and
avoid fracturing
downward.

20. Flowback – don’t ignore it anymore…..
• Proppant flowback control.
• Potential for destroying the frac-to-wellbore connection.
• May shut-in reduce frac water return – does it help or hurt?
• Formation sensitive – may not have much effect in some places
• Can reduce disposal volumes in some cases.
• Possibly can improve recovery.
• What can it tell you?
• Complex or planar fracturing.
• Where your frac water has been.
• What your frac water is reacting with.
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21. Backflow – most basic
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22. Conclusions
• Look at your well stock closely.
• For what specific reasons would a refrac be beneficial?
• Skipped pay.
• Poor initial frac.
• Declining production with stable pressure.
• Repaired well with residual damage.
• Can the refrac be done economically?
• Is Well Integrity acceptable?
• What can you learn from a refrac that would make a refrac more economical?
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