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George King: Things to Do Before You Frac that Old Well


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SIPES Houston: 2015 Continuing Education Seminar

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George King: Things to Do Before You Frac that Old Well

  1. 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. 1
  2. 2. Era of Construction – Technology in Practice 2 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. 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? 3
  4. 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? 4
  5. 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. 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. 7. 10/6/2015 7Well Integrity Course
  8. 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. 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. 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. 11. Open Annulus and Open Shoe. Still a viable completion?
  12. 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. 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. 13
  14. 14. Do All Perf Clusters or Fracs Produce?
  15. 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. 16. Candidate Selection Characteristics 16
  17. 17. Effect of Regional Fractures in One Field
  18. 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. 18
  19. 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. 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. 20
  21. 21. Backflow – most basic 21
  22. 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? 22