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Inhibitor Squeeze Design

Inhibitor Squeeze Design. Effects of divalent and trivalent metal ions (Ca 2+ , Mg 2+ , Fe 2+ , Al 3+ ) on inhibitor return and inhibitor foam squeeze. Outline of Presentation. Overview of Inhibitor squeeze chemistry and modeling Effects of Al 3+ , Mg 2+ in overflush on inhibitor return

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Inhibitor Squeeze Design

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  1. Inhibitor Squeeze Design Effects of divalent and trivalent metal ions (Ca2+, Mg2+, Fe2+, Al3+) on inhibitor return and inhibitor foam squeeze

  2. Outline of Presentation • Overview of Inhibitor squeeze chemistry and modeling • Effects of Al3+, Mg2+ in overflush on inhibitor return • Effects of Ca2+ in pill and overflush • Effects of Fe2+ in overflush • Preliminary study of inhibitor foam injection

  3. 1 4 Ca2+ 3 6 Ca2+ 2 Ca2+ 5 Proposed Inhibitor Retention Mechanism Calcite, surface pH ~9 Cr. Ca-Phn Phase, III Hi. Sol. Ca-Phn Phase, II Am. Sol. Ca-Phn Phase, I pH 4 - 8 Phn chemisorbed at calcite surface to form a low solubility crystalline salt. Further calcite dissolution is inhibited, thus, the pH of the bulk solution is lower than that of the surface boundary. High solubility Ca-Phn phases are formed in bulk solution phase at lower pH. Three Ca-Phn solubility limits are used to model the inhibitor return. The distribution of three Ca-Phn solid phases depends on pill, overflush and formation characteristics.

  4. Testing Parameters Return brine: 1000 mg/L Ca, 915 mg/L alkalinity, 1 atm PCO2, pH 5.6

  5. SqueezeSoftPitzer Prediction Smith Well: 390 bbl 1.55% acidic NTMP, 480 mg/L Ca, 2300 BPD water, 160 F

  6. Inhibitor Selection 182 bbl 3% Acidic Inhibitor, 800 bbl overflush, 2300 BWPD

  7. Effect of Fe2+ First 10 PV return Long term Inh Return

  8. Effect of Ca2+ Initial Phn. Return Long term Phn. Return

  9. Fe2+, Ca2+ Calcite, surface pH ~9 Cr. Ca-Phn Phase, III Hi. Sol. Ca-Phn Phase, II Am. Sol. Ca-Phn Phase, I Ca2+, H+ Conclusions • Ca and Fe in pill and/or overflush solution significantly increased phosphonate retention. • Mg and Al have little effect on phosphonate retention. • High Fe concentration may cause the phosphonate return concentration to be too low.

  10. Prediction of Scale Formation and Precipitation in the Presence of Methanol and Ethylene Glycols

  11. Objectives • Critically evaluate the accuracy of ScaleSoftPitzer prediction of SI at common oilfield conditions: high T, P, TDS. • Develop solubility data for common oilfield minerals in methanol and glycol containing brine.

  12. Barite Solubility at Elevated Temperature and Pressure

  13. 1 m NaCl ScaleSoftPitzer Prediction – Calcite/MeOH, MEG/Brine MeOH/Calcite MEG/Calcite

  14. ScaleSoftPitzer Prediction – Barite/Methanol/Brine

  15. SI Prediction by ScaleSoftPitzer

  16. Effect of Hydrate Inhibitors on Calcite/Barite/Halite SI Calcite, 77 ºF Barite, 77 ºF Halite, 77 ºF

  17. Effect of MEG on Calcite Solubility For example, at 200 F = 366 K and 70,000 mg/l TDS the change in the SI (Calcite) would be:

  18. Scale Control In the Presence of Hydrate Inhibitor

  19. Outline of Presentation • Xinmin Wu – Visiting scholar, Associate Professor, Xi’an Petroleum University • Case study– Scale/corrosion problem in methanol recovery plant in China, Chang Qing Gas Field - Wu • Nucleation kinetics of calcite scale formation in the presence and absence of methanol - Tomson • Inhibition of calcite/barite scale formation by scale inhibitors -Tomson

  20. Case Study – Treatment of Methanol/Brine for Reinjection and Reuse in China Xinmin Wu Associate professor Department of Petroleum Engineering, Xi’an Shiyou (Petroleum) University, xi’an, China

  21. Scale/Corrosion Inhibitor • HEDP, 5 mg/L • Acrylic acid/Acrylic ester/Acrylic sulfonate copolymer (R-SO3), 6 mg/L • Benzotriazole (BTA), 2 mg/L • No precipitation observed at 50 – 100 ºC • Corrosion is less than 0.2 mm/a

  22. Methanol/Brine Treatment H2O2 NaOH 2B Sedimentation Tank Reactor Filter Heater Methanol/Brine Input HEDP BTA R-SO3 Clean brine For re-injection 96% Pure Methanol Distillation Tower

  23. Field Test Results

  24. Effect of Hydrate Inhibitors - Barite Nucleation Time

  25. Calcite Precipitation In the Presence/Absence of Methanol

  26. Turbidity (NTU) Log (tind, sec) Control Barite Scale with Scale Inhibitors and Low MeOH Conc. BaSO4 = 1.1 mm, Ca= 0.09 m, 1 m NaCl, 24 C, BHPMP No MeOH 10% MeOH (w/w) 20% MeOH(w/w) SI = 2.05 SI = 2.79 SI = 3.43

  27. BaSO4 = 1.1 mm Ca=0.09 m, 0.98 m NaCl, pH 6.4, 24 C, SI=2.61 BaSO4 = 1.8 mm Ca=0.045 m, 1.0 m NaCl, pH 6.4, 24 C, SI=3.08 BaSO4 = 1.8 mm Ca=0.045 m, 1.0 m NaCl, pH 6.4, 24 C, SI=3.08 40% TEG (w/w) 40% MEG (w/w) 40% MEG (w/w) Turbidity (NTU) Log(tind, sec) Control Barite Scale with Scale Inhibitors and MEG, TEG

  28. Calcite Inhibition at High Temperature Can Pseudoscale Form?Pseudoscale formation is a function of temperature, pressure, pH, TDS, Ca, Mg, Ba, Fe concentrations Ca-DTPMP ion product = 1053.6 or 1054.3 at 75 C and 100 C with 1 mg/L DTPMP; Ca-DTPMP crystalline solubility product = 1053.8 64,158 mg/L TDS, 1,600 mg/L Ca, 1200 mg/L alkalinity, pH 6.2 75 C, DTPMP 100 C, DTPMP

  29. Inhibition of Calcite Scale by DTPMP in 50% Methanol 64,158 mg/L TDS, 1,600 mg/L Ca, 1200 mg/L alkalinity, pH 6.2

  30. Limits of Inhibition – Ca-Phn Pseudoscale Formation 1.11 mm BaSO4, 0.09 m Ca, 1 m NaCl, 24 C, 6.4 pH, 30% (w/w) MeOH, SI=3.9 Added BHPMP Conc. ~1.8 mg/L BHPMP Remained in solution

  31. Conclusions • Barite and calcite scale formation at low methanol concentrations can be inhibited by common scale inhibitors at threshold level, if barite SI  3 and calcite SI  2.5. • Calcium inhibitor pseudoscale formation can occur in high Ca brine and limit the effectiveness of phosphonate type inhibitor at high concentrations. • Scale inhibition is easier in glycol containing brine than in methanol containing brine.

  32. Kinetics of scale deposition and dissolution - Issues important to seawater/brine injection and control

  33. Importance • Seawater injection • Tolerance of low sulfate seawater (LSSW) • Mixing of incompatible brines • Brine disposal • Efficiency of inhibitors in porous media

  34. A B Experimental AEG: 40% Quartz, 40% feldspar, clay 20% calcite, 0.06% Barite LS (Low Sulfate) Brine: 1 m NaCl, 4.55 mm SO42-, 4.03 m HCO3- SW (Seawater): 0.49 mNa+, 0.01 mCa2+, 0.01 m K+, 0.05 m Mg2+, 0.57 m Cl-, 0.029 m SO42-,0.002 m HCO3- Column: 0.5 cm ID, 7.6 and 15 cm L, Porosity~0.35, A/V~ 1000 m2/L AEG LS Brine SW EDTA 210 ºF

  35. Barite Dissolution from AEG Sulfate Brine, 210 ºF Radius form Center of Well Radius form Center of Well Both barite and calcite dissolution were not affected by flow rate and had reached equilibrium solubility at flow rates equivalent to the flow rates within 1 – 20 ft radius from the center of the well.

  36. Seawater and Low Sulfate Brine Injection Ion exchange of Mg in seawater with solid phase may release Ca into the pore water

  37. Seawater and Low Sulfate Brine Injection Ca in seawater and Ba in pore water are expected to precipitate during seawater injection due to temperature and pore water composition changes

  38. Barite and Calcite SI During seawater and LS brine injection, the pore solution is supersaturated with respect to both calcite and barite, i.e., Kinetics of precipitation is slow.

  39. Calcite/Barite Dissolution in the Presence of BHPMP Flow interrupted overnight Flow interrupted overnight

  40. Dissolution in the Presence of BHPMP - Barite and Calcite SI

  41. Conclusions • A new apparatus to study mineral precipitation/dissolution kinetics in porous media at oilfield condition has been developed. • In the absence of inhibitor, dissolution of barite and calcite is very fast, while precipitation can be kinetically slow at the oilfield condition. • In the presence of inhibitor, dissolution of barite and calcite is not at equilibrium and is not affected by changes in flow rates. • This research can be important to better design scale control strategies for seawater injections, brine mixing and disposal.

  42. ScaleSoftPitzer Overview and Use • Explain Input Cells • Calculate inhibitor needed with and without MeOH • Illustrate the GoalSeek-type feature: • A. What P-CO2 would make the downhole SI = 0.00 • B. What seawater SO4 level would make the Inh Conc. • equal to 1) zero, 2) a small value (e.g., 0.01 mg/l) • Use of SSP SI values to calculate precipitation • and dissolution in flooding

  43. CaCO3 Fe(OH)2 MgSiO3 Na2SiO3 (H2CO3 + HAc + H2S + HCl)aq H2CO3 + HAc + H2S + H2O + NaCl HCO3- Ac- HS- OH- SiO2 CO32- S2- -H+ Weak-acid buffer solutions. Alk  [HCO3-] + 2[CO32-] + [Ac-] + [HS-] +2[S2-] + [OH-] - [H+] in units of (eq./L)  [HCO3-] + [Ac-]  [HCO3-] • 1. If you are given HCO3- as mg/l HCO3,then enter this number as Alkalinity in Cell C21; • 2. If you are given Alkalinity as mg/l HCO3, then enter this number as Alkalinity in Cell C21; • 3. If you are given Alkalinity as mg/l of CaCO3, then multiply this value by 1.22 and enter the product as Alkalinity in Cell C21; • 4. If you are given both mg/l HCO3 and mg/l CO32-, then multiply mg/l CO3 by 2.03 and add to mg/l HCO3 and enter the sum as Alkalinity in Cell C21; 5. If you are given a value for phenolphthalein Alkalinity as mg/l CaCO3 in addition to bicarbonate alkalinity as mg/l CaCO3, then add these together and multiply by 1.22 and enter the result as Alkalinity in Cell C21. Alkalinity in oilfield brines

  44. The two pH options: I. (0, no), do not use measured pH; and II. (1, yes), use the measured pH

  45. H2S gas and solution

  46. Carboxylic Acids and Total Dissolved Solids (TDS)

  47. Effect of pressure and gas, oil, and water volumes on gas composition In the water in each case: [HCO3-] =305 mg/L =0.005 eq/L (M) STP conditions Pressure = 1 atm Volume = 200,000 ft3 yCO2 = 0.01 Pressure at some point down the well: Pressure = 400 atm Volume = 109 ft3 yCO2 = 0.0011 Hy=“hydrocarbon” in g/o/w phases. Pressure at bubble point = 513 atm; Volume of gas = 0.0 CO2 Hy CO2 Hy 100 B of Oil 100 B of Oil 100 B of Oil CO2 Hy CO2 Hy CO2 Hy CO2 Hy CO2 Hy CO2 Hy 1000 B of W 1000 B of W 1000 B of W CO2,w = 0.00028 M pH = 7.25 CO2,w = 0.0120 M pH = 5.76 CO2,w = 0.0123 M pH = 5.62

  48. Total Dissolved Solids (TDS) and Density

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