Workshop: Minnelusa I Day 3 10:40 11:40 am ASP Blend Optimization - - PowerPoint PPT Presentation

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Workshop: Minnelusa I Day 3 10:40 11:40 am ASP Blend Optimization - - PowerPoint PPT Presentation

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Workshop: Minnelusa I Day 3 10:40 11:40 am ASP Blend Optimization Challenges and Strategies June 5, 2014 1 Gillette, WY Vladimir Alvarado, Ph.D. Outline Introduction: Critical Issues Issues specific to Minnelusa reservoirs

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SLIDE 1

June 5, 2014 Gillette, WY Vladimir Alvarado, Ph.D. 1

Workshop: Minnelusa I

Day 3 10:40 – 11:40 am ASP Blend Optimization Challenges and Strategies

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SLIDE 2

Outline

 Introduction: Critical Issues  Issues specific to Minnelusa reservoirs  Minnelusa ASP Design Example  Minnelusa SP/ASP at higher temperature  Summary

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SLIDE 3

Issues specific to Minnelusa

 Chemical methods critical constraints:

 Reservoir characterization → Conformance &

location of ROIP.

 Water source → Fresh vs. produced  Rock-fluid interaction → Calcium sulfate!

 What about Minnelusa sands?

Foxhill water is not a major issue, except for exacerbation of anhydrite dissolution. This sustains calcium concentration at equilibrium

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SLIDE 4

Issues specific to Minnelusa

 Most reservoirs contain measurable fractions

  • f calcium sulfate in the form of anhydrite

 Water source typically employed ranges in

salinity from 100’s to less than 2000 ppm, which leads to dissolution of anhydrite

 As a result, salinity can be low, but calcium

concentration can be high

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SLIDE 5

Issues specific to Minnelusa (cont.)

 Low-salinity conditions complicates

attainment of optimum salinity, which can be mitigated with the use of alkali

 Inexpensive alkalis will tend to precipitate and

high-pH conditions can accelerate anhydrite dissolution

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SLIDE 6

MINNELUSA ASP EXAMPLE

Casey Gregersen and Mahdi Kazempour

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SLIDE 7

Parameter

  • Salinity
  • Surfactant blend ratio
  • Soap/surfactant ratio

Optimal parameter Winsor Type - I Winsor Type - II Varying parameter Winsor Type - III

micro micro

Pipette (bottom sealed) Brine + surfactant Oil Initial interface 24 hr

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SLIDE 8

 Connate brine

  • Injection brine

Only 1600 ppm NaCl

Component Wt (gr) MgSO4 0.313 KCl 0.136 CaCl2.2H2O 1.676 NaCl 0.697 Na2SO4 4.661 TDS 7100 ppm

Materials and Methods

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SLIDE 9

DC Crude Oil

Viscosity at 48oC = 83 cP

Surfactant

0.75wt%PS13-D + 0.25wt%PS3B

Polymer

Flopaam-3330s 2000 ppm (ASP) 1000 ppm (P)

Alkali

1wt% NaOH

Core

Berea: (ASP 1) L= 7.904 cm D= 3.73 cm PV= 22.12 cc Φ= 25.62% Kair= 366.9 md Minnelusa: (ASP 2) L= 7.017 cm D= 3.728 cm PV= 16.41 cc Φ= 21.43% Kair= 808.2 md

Materials and Methods

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SLIDE 10

Results (ASP#1: Model Rock)

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SLIDE 11

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WF ASP P WF

Results (ASP#2: Minnelusa Rock)

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SLIDE 12

Observed precipitation at effluent samples:

Cl K Si Cl Ca K Ca K S O Na Cl Ca 1 2 3 4 5 6 7 8 9 10 keV Full Scale 4240 cts Cursor: -0.031 (82 cts) Spectrum 1 Cl K Si Cl K Ca Ca S K O Na Cl Ca 1 2 3 4 5 6 7 8 9 10 11 keV Full Scale 5549 cts Cursor: -0.009 (361 cts) Spectrum 4

As we expected some secondary minerals was produced (here calcite, also some sulfur was produced which is a really evidence for anhydrite dissolution)

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MITIGATION OF ANHYDRITE DISSOLUTION

Casey Gregersen and Mahdi Kazempour

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SLIDE 14

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Mitigation of Anhydrite Dissolution

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SLIDE 15

Model Rock

W F AS P P W

Anhydrite-Rich Rock

Traditional Design Designed Brine Kazempour et al., 2012, 2013

Mitigation of Anhydrite Dissolution

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MINNELUSA ASP/SP AT HIGH TEMPERATURE

Casey Gregersen and Mahdi Kazempour

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TC formation brine composition (25oC)

Ions Concentration (mg/lit) Na+ 35,545 Ca2+ 1,124 Mg2+ 328 SO4

2-

3,309 Cl- 54,200 pH 7 TDS 94,506

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SLIDE 18

Calcium mineral saturation ratio of TC brine (25oC < T< 71oC)

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Surfactant Bulk Precipitation Phase-behavior Surf1 Cloudy + OK Surf2 Cloudy + OK Surf3 Cloudy ( not very)

  • OK

Surf4 Clear (but not 100%)

  • OK

Surf5 Cloudy

  • Not satisfactory

Surf6 Cloudy

  • OK
  • TC crude oil
  • Aqueous: 0.5wt% surfactant + 50% diluted TC brine

Phase-behavior (coarse screening)

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SLIDE 20
  • TC crude oil
  • Aqueous: 0.5wt% surfactant + 50% diluted TC brine

Surf.3 Surf.4 Surf.5 Surf.6

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SLIDE 21

Phase-behavior results

  • Surf. 3 (1wt%)- at 71C (Stability test)

10K 20K 30K 40K 50K 60K 70K 80K 90K 100K NaCl increases (ppm) Aqueous phase is Cloudy (but no precipitation)

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SLIDE 22
  • Surf. 4 (1wt%) - at 71 C

10K 20K 30K 40K 50K 60K 70K 80K 90K 100K

NaCl increases (ppm) Initial interface

  • Opt. salinity

range (σ>10)

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SLIDE 23

Effect of hardness (Ca2+ and Mg2+)

  • Surf. 4 (1wt%) - at 71 C

NaCl conc. = 70K ppm

  • Sample 1
  • Ca2+= 600 ppm
  • Mg2+=200 ppm
  • Sample 2
  • Ca2+= 1200 ppm
  • Mg2+=600 ppm

Initial interface

  • Samp. 1 Samp. 2

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SLIDE 24

Effect of alkali

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SLIDE 25
  • Surf. 4 (1wt%) + Na4EDTA.2H2O (1.1wt%) -

at 71 C

10K 20K 30K 40K 50K 60K 70K 80K 90K 100K

NaCl increases (ppm) Initial interface

  • Opt. salinity

range (σ>10)

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SLIDE 26
  • Surf. 4 (1wt%) + NaBO2.H2O (1wt%) - at 71 C

10K 20K 30K 40K 50K 60K 70K 80K 90K 100K

NaCl increases (ppm) Initial interface

  • Opt. salinity

range (σ>10)

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SLIDE 27
  • Surf. 4 (1wt%) + NaBO2.H2O (1wt%) - at 71 C

10K 20K 30K 40K 50K 60K 70K 80K 90K 100K

NaCl increases (ppm) Initial interface

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SLIDE 28

Effect of hardness (Ca2+ and Mg2+)

  • Surf. 4 (1wt%) + NaBO2.H2O (1.wt%) - at 71

C NaCl conc. = 70K ppm

  • Sample 1
  • Ca2+= 600 ppm
  • Mg2+=200 ppm
  • Sample 2
  • Ca2+= 1200 ppm
  • Mg2+=600 ppm

Initial interface

  • Samp. 1
  • Samp. 2

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SLIDE 29
  • Surf. 4 (1wt%) + NaOH (1wt%) - at 71 C

10K 20K 30K 40K 50K 60K 70K 80K 90K 100K

NaCl increases (ppm) Initial interface

  • Opt. salinity

range (σ>10)

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SLIDE 30
  • Surf. 4 (1wt%) + NaOH (1wt%) - at 71 C

10K 20K 30K 40K 50K 60K 70K 80K 90K 100K

NaCl increases (ppm) Initial interface

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SLIDE 31
  • Surf. 4 (1wt%) + NaOH (0.3wt%) + Na2SO4 (29.58gr/lit)- at 71 C

10K 20K 30K 40K 50K 60K 70K 80K 90K 100K

NaCl increases (ppm) Initial interface

  • Opt. salinity

range (σ>10)

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SLIDE 32

Effect of hardness (Ca2+ and Mg2+)

  • Surf. 4 (1wt%) + NaOH (0.3wt%) + Na2SO4 (29.58gr/lit)- at 71 C

NaCl conc. = 70K ppm

  • Sample 1
  • Ca2+= 600 ppm
  • Mg2+=200 ppm
  • Sample 2
  • Ca2+= 1200 ppm
  • Mg2+=600 ppm

Initial interface

  • Samp. 1 Samp. 2

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SLIDE 33

Effect of surfactant concentration↓

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SLIDE 34
  • Surf. 4 (0.5wt%) - at 71 C

10K 20K 30K 40K 50K 60K 70K 80K 90K 100K

NaCl increases (ppm) Initial interface

  • Opt. salinity

range (σ>10)

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SLIDE 35

Effect of hardness (Ca2+ and Mg2+)

  • Surf. 4 (0.5wt%) - at 71 C

NaCl conc. = 70K ppm

  • Sample 1
  • Ca2+= 600 ppm
  • Mg2+=200 ppm
  • Sample 2
  • Ca2+= 1200 ppm
  • Mg2+=600 ppm

Initial interface

  • Samp. 1 Samp. 2

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SLIDE 36

Rheological behavior of different SP blends varying water chemistry

(1wt% Surf. 4 +2,250 ppm Flopaam 3330s at 71 oC)

1 10 100 1000 1 10 100 Viscosity (cP) Shear rate (1/s)

10K 50K Ca 600ppm-Mg 200ppm-70K Ca 1200ppm-Mg 400ppm-70K 70K

Ionic strength increases

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SLIDE 37

Rheological behavior of SP blend & chasing polymer at 71 oC

  • Injected SP:

 1wt% Surf. 4 + 2,250 ppm Flopaam 3330S prepared in injected water (IW)

  • Injected chasing polymer (P):

 1,000 ppm Flopaam 3330S prepared in injected water (IW) 1 10 100 1 10 100 Viscosity (cP) Shear rate (1/s)

Injected_SP Injected_P 37

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Water composition during different flooding steps

Waters Connate water (CW) Water flooding (WF) Injected water (IW) Ions Concentration (mg/lit) Na+ 35,545 29,363 17,698 Ca2+ 1,124 955.4 627 Mg2+ 328 278.8 162 SO4

2-

3,309 2,812.7 2,876 Cl- 54,200 46,070 25,085 pH 7 7 7 TDS 94,506 80,330 46,448

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SLIDE 39

First chemical flooding condition

  • Flow rate: 0.5 cc/min
  • Confining pressure: 2,000 psi
  • Back-pressure: 1,500 psi
  • Temperature: 71 oC
  • Utilized core: core 104-b
  • Contains anhydrite
  • L= 6.671 cm and D= 3.805cm
  • Porosity= 16.2% and PV= 14.13 cc
  • Kair= 139 mD
  • Flooding steps:

1. Aging the core in connate brine (TDS= 95K) for one week at above conditions and then measuring brine permeability (Sw=1) 2. Establishing Swi by injecting TC crude oil and then aging the core for one more week for any possible of wettability alteration in presence of crude oil 3. measuring oil permeability at Swi at the end of aging period 4. 8 PV injection of WF brine in secondary mode (TDS= 80K) 5. Measuring water permeability at Sor 6. 1 PV injection of SP blend prepared in IW (TDS= 46K) 7. 1 PV injection of P solution prepared in IW (TDS= 46K) 8. 3 PV injection of WF brine (TDS= 80K) in the post-brine flooding mode

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Core 104-b (anhydrite distribution)

2) 3) 4)

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Primary results of first coreflooding

WF SP flood P flood Post-WF Looks very promising

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Summary

 Low salinity conditions in Minnelusa

reservoirs under fresh water flooding can be addressed with proper ASP design

 Issues associated with anhydrite dissolution

can be dealt with proper water strategy and understanding of geochemical effects

 High-salinity, higher temperature reservoirs

are better targets for SP designs, which alleviates the need for high-quality water

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