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Acidizing

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Acidizing

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  1. Acidizing The Fundamentals

  2. Damage Assessment

  3. Workover & Completion Commonalities • Fluid is put into the wellbore and/or formation • Tubulars of some sort are run into the well

  4. Fundamental Acid Techniques • Wellbore clean-up (tubing/casing) • Matrix acidizing (sandstone or carbonates) • Acid fracturing (carbonates)

  5. Types of Acid • Mineral • Hydrochloric - HCl • Hydrochloric/Hydrofluoric - HCl/HF • Organic (slower reacting – less corrosive) • Acetic • Formic • Powdered (acid sticks) • Sulfamic • Chloroacetic

  6. Dissolving Capability • 15% HCL – 1.84 ppg • 28% HCL – 3.68 ppg • 9:1 mix 7.5% HCL : Acetic – 1.64 ppg • 9:1 mix 15% HCL : Acetic – 2.48 ppg • 9:1 mix 28% HCL : Acetic – 3.72 ppg • 10% Acetic – 0.71 ppg

  7. Acid Reaction Rate

  8. Basic Equation 2HCl + CaCO3 H2O + CO2 +CaCl2    Water  Salt Gas 1000 1843 1040 6620 2050 Gals lbs gals ft3 lbs

  9. Controlling Factors • Pressure • Less than 500 psi • Temperature • Add 20°, double reaction rate • Subtract 20°, half the reaction rate • Velocity • Accelerate the mass transfer • Flow patterns – radial, linear, cylindrical

  10. Controlling Factors • Concentration • Stronger is faster (to a point) • Contact area & volume ratio • Matrix = large surface area (30000:1) • 20% Φ limestone with 10 md • Natural fracture (3000:1) • Same limestone with a 0.001” natural fracture • Fracture = smaller surface area (32:1) • Same limestone with a 0.1” created fracture

  11. Controlling Factors • Formation composition • Surface wetting • Viscosity

  12. Retarded Acids • Gelled acid • Mineral/organic mix • Common ion

  13. Basic Equation 2HCl + CaCO3 H2O + CO2 +CaCl2

  14. Retarded Acids • Gelled acid • Mineral/organic mix • Common ion • Oil-wet barriers • Emulsions • High concentrations

  15. Acid additives • Corrosion Inhibitors – specify time and temperature • Surface Active Agents – anionic, cationic, nonionic, amphoteric • Anionic tend to water wet sand, emulsify oil in water, break water in oil emulsions, disperse clays • Cationic tend to water wet carbonates, emulsify water in oil, break oil in water emulsions, flocculates clay • Anionic and cationic surfactants mix like matter and anti-matter • Nonionic tends to be the most popular surfactants

  16. Acid Additives (cont) • Non-emulsifiers (acid and oil) • Chemical retarders (carbonates only) • Foamers • 2 gpt < 75° F • 3 gpt < 130° F • 5 gpt < 200° F • 7 gpt < 250° F • 10 gpt < 300° F • 13 gpt < 350° F

  17. Acid Additives (cont) • Alcohol (dry gas wells) • Methanol < 200° F • Ethanol < 300° F • Mutual solvents (need?) • Anti-sludge agents (asphaltic crudes 5-20 gpt) • Clay stabilizers

  18. Acid Additives (cont) • Iron sequestering agents • Iron in tubulars, scale and fomation minerals • Most treatments minimum control of 1000 mpl requires 10-15 ppt sodium erythorbate • Control severe iron concerns 5000 mpl • 60° to 120° - 1% acetic + 50 ppt citric • 120° to 180° - 2% acetic + 100 ppt citric or 50-65 ppt sodium erythorbate • 180° plus – 50-65 ppt sodium erythorbate

  19. Acid Additives (cont) • Friction reducers • Gelling agents • Fluid loss additives • Diverting material • Rock salt • Wax beads • Oil soluble resins • Benzoic acid flakes (story time)

  20. Wellbore Clean-up • Clean-up • Mill scale • Corrosion scale • Pipe dope • Pickled tubing

  21. The Pickle Job • Minimum volume of aromatic solvent – 250 gallons • Scale basis 0.1 lb/ft in 5 ½” 20# casing (or 0.003” of 5.0 sg magnetite mill scale) • 400 gal/1000’ 5 ½” • 100 gal/1000’ 2 7/8”

  22. The Pickle Job • 15% HCl • Minimum CI • Aromatic solvent pre-flush • No iron control • Catch return samples

  23. Matrix Acidizing • Below fracture gradient • Wormholes • Size? • Length? • Number?

  24. Wormholes • Fluid loss rate determines length, inches to feet long • Fluid loss additives • Viscosity • Not a function of reaction rate! • 28% HCl

  25. Sandstone Matrix Acidizing • HCl for mud damage removal • Carbonate FLA • Dehydrate bentonite clay • HCl/HF for stimulation (sandstone only!) • Always at matrix rate • Permeability dominates • Shallow stimulation

  26. HCl/HF Acidizing • Always need HCl pre-flush • HF reacts more quickly with clays than silica • Don’t use sodium, potassium or calcium salt waters for flush • Feldspar means use half strength (13.5%:1.5%) • Flush with ammonium chloride or HCl spacer

  27. Acid Fracturing (Carbonates) • Factors affecting penetration • Fluid loss • Injection rate • Fracture width • Factors affecting conductivity • Heterogeneity • Closure pressure • Rock strength

  28. Acid Fracturing Methods • Density controlled • Viscous fingering • Foamed acid • Overbalanced surge

  29. Density Control

  30. Density Control

  31. Viscous Fingering Acid

  32. k = 100 md k = 10 md k = 15 md Overbalanced Surging • Placement of unconventionally small volumes of acid in a fracture mode is not possible in a conventional mode.

  33. k = 100 md k = 10 md k = 15 md Overbalanced Surging • Placement of acid is possible with overbalanced surging even with large variances in permeability

  34. Carbonate Acidizing

  35. Reasons for Carbonate Acidizing • Damaged permeability • Low permeability • Low perforation efficiency

  36. Matrix Treatment Design • Determine fracture gradient • Calculate maximum BHTP • Calculate maximum allowable STP • Estimate injection rate - Darcy radial • Determine acid volume – 50-200 gal/ft • Specify acid type, volume, rate and max pressure

  37. Fracture Acidizing • Majority of carbonate reservoir treatments are acid fracs • Good conductivity is the key to successful stimulation • Productivity increases of 2.5-13 fold

  38. Injection rate Fluid viscosity Fluid volume injected Fluid loss Rock properties Formation fluids Formation stresses Reaction rates Factors Affecting Fracture Geometry

  39. Rule of Thumb for Acid Volume Fill the fracture with an acid volume of regular 15% HCl that is three times (3X) the fracture volume to be etched.

  40. Treatment Design • Optimize the treatment • Fracturing calculations • Rock composition • Closed fracture acidizing (10-20%) • Treatment review

  41. General volumes • Acid wash/soak – 10-25 gals/ft • Matrix acid – 100-200 gals/ft • Acid Fracture – 400-600 gals/ft

  42. Questions???

  43. Pat H. Sanderson 1-13 #1Stimulation Evaluation A Look Back and Forward by Pat Handren

  44. Original perforations 16,760 – 16,830’ 85/15 split dolomite/limestone 10,000 gals 15% HCl BHT - 277°F Problems No cooldown Reaction time ~2 min. Small radius of penetration (50-100’) Positives Reservoir has potential! Prior Stimulation Model

  45. Pat H. Sanderson 1-13 #1Condensate History Match

  46. Relative Reaction Rates

  47. Keys to Successful Acidizing • Cool down the reservoir • Increase the fracture width • Rate dependent on pressure • Maximize penetration distance • Closed fracture acidizing • Overflush

  48. First stage 20,000 gals 30# gel 5,000 gals 30# borate x-linked 20,000 gals 20% HCL Pump at 8-10 BPM, but use pressure to dictate maximum rate Divert with 500 bioballs Second stage 15,000 gals 30# gel 5,000 gals 30# borate x-linked 15,000 gals 20% HCL Reduce rate & over flush Two Staged Acid Proposal