Chemical Flooding Design Moving to Field Studies
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1 Chemical Flooding Design Moving to Field Studies V L A D I M I R A L V A R A D O C H E M I C A L A N D P E T R O L E U M E N G I N E E R I N G J U L Y 2 6,
2 Outline Introduction 2012 Summary EOR Screening (discontinued) DC ASP Low sal., shallow Minnelusa TC SP High sal., deeper Minnelusa 2013 Plan
3 Introduction: Program Summary (2012) A screening method was developed (discont.) An ASP formulation for DC field based on phase behavior studies, corefloods and simulation. Evaluation of semi-commercial surfactants (SASOL) was conducted A design for more saline and deeper Minnelusa reservoirs has initiated with promising results
4 Casey Gregersen and Mahdi Kazempour FIELD D ASP OPTIMUM DESIGN
5 Materials and Methods Connate brine Component Wt (gr) MgSO KCl Injection brine Only 1600 ppm NaCl CaCl 2.2H 2 O NaCl Na 2 SO TDS 7100 ppm
6 Materials and Methods Dead man Field Creek D Crude Oil Surfactant Polymer Alkali Core Viscosity at 48 o C = 83 cp 0.75wt%PS13-D wt%PS3B Flopaam-3330s 2000 ppm (ASP) 1000 ppm (P) Berea: (ASP 1) L= cm D= 3.73 cm PV= cc Φ= 25.62% K air = md 1wt% NaOH Minnelusa: (ASP 2) L= cm D= cm PV= cc Φ= 21.43% K air = md
7 micro micro Oil 24 hr Brine + surfactant Initial interface Pipette (bottom sealed) Varying parameter Parameter Salinity Surfactant blend ratio Soap/surfactant ratio Winsor Winsor Type - I - I Type - - III III Winsor Type -- II II Optimal parameter
8 Results (ASP#1)
9 Results (ASP#2) WF ASP P WF 9
10 Observed precipitation at effluent samples: Ca Spectrum 1 Cl Na O K Ca S K Cl Si Cl K Ca Full Scale 4240 cts Cursor: (82 cts) kev Spectrum 4 Ca Cl Cl K O Ca Na Si S Cl K K Ca Full Scale 5549 cts Cursor: (361 cts) kev As we expected some secondary minerals was produced (here calcite, also some sulfur was produced which is a really evidence for anhydrite dissolution)
11 Mitigation of Anhydrite Dissolution 11
12 (ASP in Conditioned Brine) 12
13 DC Project Highlights Practically speaking : A potentially effective laboratory-based ASP formulation was developed More in-depth research outcomes: Differentiated behavior of alkaline agents Direct proof of impact of anhydrite dissolution Importance of geochemical coupling analysis Paradigm to mitigate of anhydrite dissolution
14 Dr. Mahdi Kazempour HIGHER SALINITY/TEMPERATURE TOWARD FIELD PROJECTS
15 Tested surfactant blends for Field B project Surf 1: Petrostep-S2 (0.5wt%) + Petrostep-S3B (0.25wt%) + Petrostep-C8 (0.25wt%) Surf 2: Petrostep-S2 (0.75wt%) + Petrostep-S3B (0.25wt%) Surf 3: Alfoterra L123-4S 90 (1wt%) Surf 4: Petrostep-S2 (0.5wt%) + Petrostep-S13D (0.5wt%) Surf 5: Alfoterra S23-7S 90 (1wt%) Surf 6: Alfoterra L145-4S 90 (0.5wt%) + Alfoterra S23-7S 90 (1wt%)
16 Field B formation brine composition (25 o C) Ions Concentration (mg/lit) Na + 35,545 Ca 2+ 1,124 Mg SO 2-4 3,309 Cl - 54,200 ph 7 TDS 94,506
17 Calcium mineral saturation ratio of Field B brine (25 o C < T< 71 o C)
18 Phase-behavior results (coarse screening) Field B crude oil Aqueous: 0.5wt% surfactant + 50% diluted Field B brine Surfactant Bulk Precipitation Phase-behavior Surf1 Cloudy + OK Surf2 Cloudy + OK Surf3 Surf4 Cloudy ( not very) Clear (but not 100%) - OK - OK Surf5 Cloudy - Not satisfactory Surf6 Cloudy - OK
19 Phase-behavior results (coarse screening) TC crude oil Aqueous: 0.5wt% surfactant + 50% diluted Field B brine Surf.3 Surf.4 Surf.5 Surf.6
20 Phase-behavior results Surf. 3 (1wt%)- at 71C (Stability test) NaCl increases (ppm) 10K 20K 30K 40K 50K 60K 70K 80K 90K 100K Aqueous phase is Cloudy (but no precipitation)
21 Surf. 4 (1wt%) - at 71 C NaCl increases (ppm) 10K 20K 30K 40K 50K 60K 70K 80K 90K 100K Initial interface Opt. salinity range (σ>10)
22 Effect of hardness (Ca 2+ and Mg 2+ ) Surf. 4 (0.5wt%) - at 71 C Samp. 1 Samp. 2 NaCl conc. = 70K ppm Sample 1 Ca 2+ = 600 ppm Mg 2+ =200 ppm Sample 2 Ca 2+ = 1200 ppm Mg 2+ =600 ppm Initial interface
23 Effect of alkali
24 Surf. 4 (1wt%) + Na4EDTA.2H2O (1.1wt%) - at 71 C NaCl increases (ppm) 10K 20K 30K 40K 50K 60K 70K 80K 90K 100K Initial interface Opt. salinity range (σ>10)
25 Surf. 4 (1wt%) + Na4EDTA.2H2O (1.1wt%) - at 71 C NaCl increases (ppm) 10K 20K 30K 40K 50K 60K 70K 80K 90K 100K Initial interface Opt. salinity range (σ>10)
26 Effect of hardness (Ca 2+ and Mg 2+ ) Surf. 4 (1wt%) + Na4EDTA.2H2O (1.1wt%) - at 71 C NaCl conc. = 70K ppm Sample 1 Ca 2+ = 600 ppm Mg 2+ =200 ppm Sample 2 Ca 2+ = 1200 ppm Mg 2+ =600 ppm Samp. 1 Samp. 2 Initial interface
27 Surf. 4 (1wt%) + NaBO2.H2O (1wt%) - at 71 C NaCl increases (ppm) 10K 20K 30K 40K 50K 60K 70K 80K 90K 100K Initial interface Opt. salinity range (σ>10)
28 Surf. 4 (1wt%) + NaBO2.H2O (1wt%) - at 71 C NaCl increases (ppm) 10K 20K 30K 40K 50K 60K 70K 80K 90K 100K Initial interface
29 Effect of hardness (Ca 2+ and Mg 2+ ) Surf. 4 (1wt%) + NaBO2.H2O (1.wt%) - at 71 C NaCl conc. = 70K ppm Sample 1 Ca 2+ = 600 ppm Mg 2+ =200 ppm Sample 2 Ca 2+ = 1200 ppm Mg 2+ =600 ppm Samp. 1 Samp. 2 Initial interface
30 Surf. 4 (1wt%) + NaOH (1wt%) - at 71 C NaCl increases (ppm) 10K 20K 30K 40K 50K 60K 70K 80K 90K 100K Initial interface Opt. salinity range (σ>10)
31 Surf. 4 (1wt%) + NaOH (1wt%) - at 71 C NaCl increases (ppm) 10K 20K 30K 40K 50K 60K 70K 80K 90K 100K Initial interface
32 Surf. 4 (1wt%) + NaOH (0.3wt%) + Na2SO4 (29.58gr/lit)- at 71 C NaCl increases (ppm) 10K 20K 30K 40K 50K 60K 70K 80K 90K 100K Initial interface Opt. salinity range (σ>10)
33 Effect of hardness (Ca 2+ and Mg 2+ ) Surf. 4 (1wt%) + NaOH (0.3wt%) + Na2SO4 (29.58gr/lit)- at 71 C NaCl conc. = 70K ppm Sample 1 Ca 2+ = 600 ppm Mg 2+ =200 ppm Sample 2 Ca 2+ = 1200 ppm Mg 2+ =600 ppm Samp. 1 Samp. 2 Initial interface
34 Effect of surfactant concentration
35 Surf. 4 (0.5wt%) - at 71 C NaCl increases (ppm) 10K 20K 30K 40K 50K 60K 70K 80K 90K 100K Initial interface Opt. salinity range (σ>10)
36 Effect of hardness (Ca 2+ and Mg 2+ ) Surf. 4 (0.5wt%) - at 71 C NaCl conc. = 70K ppm Sample 1 Ca 2+ = 600 ppm Mg 2+ =200 ppm Sample 2 Ca 2+ = 1200 ppm Mg 2+ =600 ppm Samp. 1 Samp. 2 Initial interface
37 Viscosity (cp) Rheological behavior of different SP blends varying water chemistry (1wt% Surf. 4 +2,250 ppm Flopaam 3330s at 71 o C) K 50K Ca 600ppm-Mg 200ppm-70K Ca 1200ppm-Mg 400ppm-70K 70K Ionic strength increases Shear rate (1/s)
38 Viscosity (cp) Rheological behavior of injected SP and chasing polymer blends at 71 o C Injected SP: 1wt% Surf ,250 ppm Flopaam 3330S prepared in injected water (IW) Injected chasing polymer (P): 1,000 ppm Flopaam 3330S prepared in injected water (IW) Injected_SP Injected_P Shear rate (1/s)
39 Water composition during different flooding steps Waters Connate water (CW) Water flooding (WF) Ions Concentration (mg/lit) Injected water (IW) Na + 35,545 29,363 17,698 Ca 2+ 1, Mg SO 4 2-3,309 2, ,876 Cl - 54,200 46,070 25,085 ph TDS 94,506 80,330 46,448
40 First chemical flooding condition Flow rate: 0.5 cc/min Confining pressure: 2,000 psi Back-pressure: 1,500 psi Temperature: 71 o C Utilized core: core 104-b Contains anhydrite L= cm and D= 3.805cm Porosity= 16.2% and PV= cc K air = 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
41 Core 104-b (anhydrite distribution) 2) 3) 4)
42 Primary results of first coreflooding WF SP flood P flood Post-WF Looks very promising
43 Future work Analyses of coreflooding tests data Additional coreflooding experiments to evaluate other possibilities Support of Pilot test (to be defined by EORI & Operators)
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