The Science and a Case History of CO 2 Conformance Through the Use of Complex Nano Fluids

Transcription

1 The Science and a Case History of CO 2 Conformance Through the Use of Complex Nano Fluids Glenn Penny, Ph.D., Director of Technology Tom Pursley, IOR Technical Manager

2 Conformance Challenge: Divert CO2 from High Perm Streaks or swept areas of reservoir into Unswept Reservoir; Idea is to Increase CO2 Sweep Efficiency or Utilization; Increase Oil Production; Candidate patterns are generally selected according to the following criteria. 1. Unusually high gas rate and high gas/oil ratio (GOR), 2. Low wellhead pressure in the contributing injection well. 3. Rapid interwell transit. 4. Identifiable, high-permeability thief zone. 2

3 Previous polymer methods to achieve CO 2 conformance and mobility control Preformed Polymer gel (PPG) Good for very high perm thief zones (>3 Darcies) Crosslinked Gel Injection 10 to 15kgal ppm PAM + Cr Incremental oil costs 5 to $7/bbl depending on field (about 150 jobs performed in W TX 15 to 20% with CO2 Gelled foam injection (Freidman SPE 38837) CO2 replaces 60% of the volume Cost of gel conformance decreased 50% to around $3/bbl but only lasted 4 months in a limited field trial 3

4 Previous CO2 Conformance with Surfactants Surfactant injection with the CO2 (Sanders, Linroth SPE Observed that more CO2 was injected into additional deeper zones but only while surfactant was being pumped SAG Surfactant Alternating gas (Hoefner SPE 27787) some profiles improved while many were not, the injection profile modification was highly transient CO2 foam to increase CO2 viscosity to match reservoir oil to achieve favorable mobility ratio (Stephenson SPERE Aug 93) An extended field test showed the foam bank propagated only a few meters from the wellbore 4

5 New Technique Strategy: Develop a low adsorbing high salt and oil tolerant foamer that works with CO2 Complex nanofluid (CnF + Foamer) Inject CnF + Foamer in water phase and follow with CO2 to divert Investigate in a CO2 core flood using a Dual Core Flood Apparatus with 50 md and 250 md Core Plugs. Action: Inject a Complex Nano Fluid (CnF( ) Product Containing a Low Adsorbing salt tolerant Foamer into candidate injection well followed by CO2 to Create Conformance. Follow production of CO2 and oil before and after. 5

6 One Method to Mitigate Adsorption is to Formulate in a Complex NanoFluid (CnF): Oil/Solvent + Surfactant + Water = Clear Additive Water Surfactant 1 phase 2 phases 3 phases Ternary Diagram Oil/ Solvent Water oil and surfactant form Veronoi Type structures on the order of nm Ternary Type structures diagram on the order shows of 10 areas of microemulsion system stability. Area of 1 phase indicates oil water and surfactant appear as a single phase. Oil is dispersed as Droplets that are nano to micrometers is size These structures maintain their integrity and clarity even at very dilute concentrations

7 CnF Nanodroplet Size Distribution Maximize Propagation into Reservoir Matrices nm Nanodroplet With Foamer PSD weight-based (acoustics), % by weight Acoustic spectroscopy Emulsion Complex Nanofluid (CnF), neat CnF diluted (20 gpt, 2% KCl) Dynamic light scattering (PCS) CnF diluted (2gpt, 2% KCl) E PSD volume-based (PCS), % by volume Droplet diameter ( m)

8 Micellar Solutions Vs. Complex NanoFluid Injected fluid in contact with the formation σ LG σ LG nanodroplets σ LL σ SL σ SL Micellar Solution CnF System Surfactant adsorption minimizes free energy of the system Presence of liquid-liquid interface prevents surfactant adsorption

9 Adsorption Test: Fluid flowed through a 12 X 1 1 diameter column filled with cuttings. Surface tension measured after each pore volume. Kruss 100, Surface Tension 80 Surface Tension (dynes/cm) Pore Volumes 2% FS NP AE ME ME+ 2%FS Higher surface tensions Vs. Pore vol shows adsorption Adsorption mitigated by CnF/ME formulation 9

10 Foam viscosity in core vs Surfactant Type, Concentration Salinity and Pressure Surfactant Concentration Salinity Pressure

11 Foamer Selection Surfactants Foam Salinity Retention on Sandstone Temp Oil Betaine X AOS X X Formulation 1: Betaine : AOS = 2: 8 #2Micro-emulsion +Betaine +AOS good improved decreased good improved

12 Static Adsorption of Betaine vs ME+AOS+Betaine

13 Oil Effect on Foam

14 Dual Core Flooding Tests with Oil Label Formulation Concn (gpt) Preflush (PV) Back Pressure (psi) Core permeability (md) Test 1 Betaine and 9 Test 2 #1AOS-BET and 81 Test 3 Test 4 #2AOS-BET- CnF17 #2AOS-BET- CnF and and 85

15 CO 2 WAG Conformance

16 Dual Core System for CO 2 Foam Diversion Testing

17 Inject 0.5 PV of 5 gpt Formula F 15% Salinity, 1200 psi 335 and 70 md Flow ratio changes from 5 to 1 to 2.5 to 2 And is stable with time

18 Oil Recovery in Dual Core Tests Test 1Betaine Test 2AOS-BET8-2 Test 3AOS-BET-ME Test 4AOS-BET-ME

19 Case History CnF Based Foam Diversion 19

20 Reservoir Conditions Sandstone Permeability range of 50 md and 200 md T=150 o F Formation Brine (FB) Salinity is 15% TDS with divalent ions West Texas Crude Oil API 37.7 at 60 o F, MMP = 2200 psi

21 Field treatment Select injector that has low injection pressure relative to the others. Inject ½ pore volume of CnF based foam based on suspected flow profile This was 3000 gal of 0.3% CnF Foamer injected at the end of the water injection cycle Convert to CO2 CO2 contacts the foamer placed in the high perm area and the CO2 is diverted to lower perm unswept zones Observe CO2 emission rate and oil production rate

22 CnF Foam Conformance CnF Foamer Pumped 22

23 CnF Foam Conformance CnF Foam Pumped 23

24 CnF Foam Conformance StimOil FD 1 Pumped 24

25 CnF Foam Conformance StimOil FD-1 1 Pumped 25

26 CnF Foam Conformance Incremental Improvement 26

27 CnF Foam Conformance Facts: Improved Production to Date: 14,110 Bbls. Cost per Incremental Bbl. to date: $0.58 Improved COP Percentage: 75% Improved NPV Percentage: 75% 27

28 Conclusions 1. Foamer created with a combination of CnF+AOS+ Betaine surfactant mixture is more resistant to crude oil ; more resistant to high salinity Has decreased betaine adsorption on sandstone; 2. Dual core flow tests show O.5 PV injection changes flow ratio from 8 to 1 to 2.5 to 2 and recovers 80% of the oil in the low perm core 3. Field results show that the flared CO2 was reduced from 1.5 MMCFD to 0.5 MMCFC after the CnF Foam treatment 4. The production has steadily increased after the CO2 diversion resulting in 14,000 Bbl of oil in 4 months. 28

29 Thank You! 29