First Ever Field Pilot on Alaskas North Slope to Validate the Use of - PowerPoint PPT Presentation

First Ever Field Pilot on Alaska’s North Slope to Validate the Use of Polymer Floods for Heavy Oil Enhanced Oil Recovery (EOR) a.k.a Alaska N North Slop ope Field L Labor oratory (ANSFL) (A L) DE-FE0031606 Abhijit Dandekar (University of Alaska Fairbanks) and Reid Edwards (Hilcorp Alaska LLC) U.S. Department of Energy National Energy Technology Laboratory Addressing the Nation’s Energy Needs Through Technology Innovation – 2019 Carbon Capture, Utilization, Storage, and Oil and Gas Technologies Integrated Review Meeting August 26-30, 2019

Presentation Outline • ANSFL Overview • Pilot Wells, Patterns and Polymer Slicing Unit • Technical Approach and Status • Task-wise Project Progress • Accomplishments to Date • Lessons Learned • Synergy Opportunities • Project Summary • Appendix 2

Alaska North Slope Field Laboratory (ANSFL): Overview Mt. Elbert #1 • Significant heavy oil Project area Project area resource (20-25 billion bbls); N N too large to ignore. • Poor waterflood sweep due Prudhoe Bay Unit to mobility contrast. • Limitation of deploying 7-11-12 Miles Miles Ignik Sikumi #1 (proposed site) thermal methods due to “permafrost”. • Light crude diluent still available for high viscosity oil Hydrate Test Wells transport through Trans 3 Alaska Pipeline System. Source: AK DNR, Division of Oil & Gas

ANSFL Overview • Joint efforts among government, academia, and industry • Primary objectives ✓ Utilize multiple technologies to develop heavy oil EOR process ✓ Observe field performance to optimize design ✓ Minimize disruption to field operations ✓ Resolve technical issues regarding heavy oil polymer flooding ✓ Integrate lab work, reservoir simulation, field pilot performance, injection conformance and flow assurance studies in an iterative optimization process 4

ANSFL Overview • Milne Point Unit • ~50,000 acres • ~250 wells -12 pads – 1 CFP • Field Development - 1985 • Cumulative Production - 353 MMBO – Light oil – 267 MMBO – Heavy oil – 86 MMBO • Current oil rate: ~30 MBD • WIO: Hilcorp 50%, BP 50% • Polymer Test Site - J Pad 5 Ning et. al. URTeC, 2019

Polymer Flooding • What is polymer - • Non-toxic polyacrylamide powder • What does it do - • Increases the viscosity of injected water • Why inject it - • Increases sweep efficiency by reducing the mobility ratio (viscosity oil / viscosity water) • Timing - • Typical polymer flood design 0.5 to 1 pattern pore volume • Long term, several years of injection Image Source - https://www.surtek.com/chemical-eor/chemical-enhanced-oil- recovery/

Target Formation • Schrader Bluff – Shallow marine / Fluvial deltaic – 3,400’ – 4,500’ SSTVD – Gross thickness ~250’ (Net – 60’) – ~7 intervals • Target Interval - Nb sand: – Net pay = 10-18 ft – Porosity = ~32% – Permeability = 500-5,000 md – Oil gravity = ~15 API – Oil viscosity = ~300 cp 7

Pilot Wells and Patterns 450 acres 8

Polymer Slicing Unit Utility Hopper PD Pressure injection Polymer letdown makedown pumps Polymer currently in use is Flopaam 3630S 9

Technical Approach No large s scale polymer projects in t the US US, and m d many unresolved d issues that n need d to b be a addr ddressed d via: • Laboratory corefloods ( Task sks 2 s 2 a and 3 3 ) – optimization of injected polymer viscosity/concentration, quantification and retention. – optimization of injection water salinity and identification of conformance control strategies. • Reservoir simulation ( Task sk 4 4 ) – history matching (HM) of laboratory corefloods, field waterflood, and polymer flood pilot. – optimization of the polymer injection strategy for the project reservoir. 10 – scale up to full field oil recovery from polymer injection.

Technical Approach • Implementation of polymer flood field pilot ( Task sk 5 5 ) – prior lab studies used in initial polymer selection. – interactively integrate lab tests, reservoir simulations, and field tests. – long time (years) required for polymer injection to quantify the benefit. • Flow assurance ( Task sk 6 6 ) – develop literature based initial strategy to deal with produced fluids from a separation and processing standpoint. – revise flow assurance strategy concurrently. 11

Technical Status 12

Technical Status 13

Technical Status 14

Task 2 – Polymer Retention 1.2 1.0 0.8 Value 0.6 Pressure across core relative to final value Effluent tracer relative to injected 0.4 Effluent viscosity relative to injected 0.2 Effluent carbon relative to injected Effluent nitrogen relative to injected 0.0 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 Pore volumes of polymer injected 15

Task 2 – Polymer Retention k w at Overburden Polymer retention, µg/g Sand Polymer Dv(10), Dv(50), K, S or , pressure, Nitrogen Viscosity µm µm md md psi 1 st 3630 36 166 10900 7000 0 28 45 NB 1 st 3630 36 166 548 50 1000 372 931 NB 2 nd 3630 73 179 625 73 1700 533 844 NB OA 3630 41 97 233 19 800 126 593 OA 3630 41 97 158 No oil 500 87 246 OA 3430 41 97 328 No oil 1000 0 33 16

Task 3 – Optimization of Injection Water Salinity Salinity: WF, PF~26,700 ppm; LSW, LSP~2500 ppm Viscosity: PF & LSPF~45 cp D L PV K Sandpack porosity Swi cm 3 cm cm mD NB 2.54 20.40 24.35 0.236 248 0.261 17

Task 3 – Optimization of Injection Water Salinity Homogeneous model Lower Upper Limit Limit No 0.8 5 Nw 0.8 5 Shear thin 0.3 0.9 Coefficient HSPF LSPF HSWF LSWF HSWF LSWF HSPF LSPF 18 Oil Production History Match Injection Pressure History Match

Task 3 – Optimization of Injection Water Salinity Heterogeneous model Lower Limit Upper Limit No 0.8 5 Nw 0.8 5 Shear thin 0.3 0.9 Slope Channel 0.01 1.124 Thickness, cm 1 100 K_Ratio LSPF HSWF LSWF HSPF HSWF LSWF HSPF LSPF 19 Oil Production History Match Injection Pressure History Match

Task 4 – Numerical Simulation K rw = 0.2 at S or 0 psi of overburden 1 0.4 Krow Krw (Sandpack) Krw (Core NB-1) Krw (Core OA) K rw = 0.116 at S or Krw (Core NB-2) 0.8 0.3 1,700 psi of overburden Kro Krw 0.6 0.2 0.4 K rw = 0.095 at S or 1,000 psi of overburden 0.1 0.2 0 0 0.2 0.3 0.4 0.5 0.6 0.7 K rw = 0.082 at S or Sw 800 psi of overburden 20

Task 4 – Numerical Simulation Solid Volume Changes, ft 3 K rw = 0.082at S or 126 µg/g retention K rw = 0.095 at S or 240 µg/g retention K rw = 0.116 at S or 532 µg/g retention 21

Task 4 – Numerical Simulation Multiple permeability heterogeneity models 8-strips 16-strips 26-blocks/strips 32-strips 22

Task 4 – Numerical Simulation 26-blocks/strips model history match using relative permeabilities 23

Task 4 – Numerical Simulation The new heterogeneous model is developed by re-interpreting the seismic data. 24

Task 4 – Numerical Simulation Ensemble smoother method Model parameters can be updated by assimilating production data at all timesteps simultaneously in ES method.  ES-MDA analysis equation ) ( ) ( − = + α + 1 − = ， u p p  m m C C C d d j 1,2, , N j j MD i D DD uc j , j e = + α 1 2 d d C z uc obs i D d N 1 ∑ a = =  1, i 1,2, , N α a = i 1 i m : model parameters (porosity, permeability and relative permeability, etc.); d : observation data (oil production rate, water cut and bottom hole pressure, etc.); C MD : cross-covariance matrix between the prior vector of model parameters and predicted data; C DD : auto-covariance matrix of predicted data; C D : covariance matrix of observed data 25 measurement errors.

Task 5 – Polymer Field Pilot Polymer Start J-23A Injection Rate and Pressure 45 cp target viscosity 26

Task 5 – Polymer Field Pilot Polymer Start J-24A Injection Rate and Pressure 45 cp target viscosity 27

Task 5 – Polymer Field Pilot J-23A - 50% loss J-24A - 60% loss 28

Task 5 – Polymer Field Pilot J-27 Production Water Cut – 60%  45% 29

Task 5 – Polymer Field Pilot J-28 Production Water Cut – 60%  25% 30

Task 5 – Polymer Field Pilot Pre Polymer Tracers • Pumped 8/3/18 (3 week prior) • J-23A to J-27 - 70 days • J-23A to J-28 - 160 days • J-24A to J-27 – 240 days J-24A Post Polymer Tracers J-27 • Pumped 3/28/19 • As of 7/24/19 - No observed J-23A tracer response (118 days) J-28 31

Task 6 – Treatment of Produced Fluids Emulsion studies 32

Task 6 – Treatment of Produced Fluids 1 Separation efficiency 0.5 Emulsion breakers E12085A E18276A N1691 R01319 0 0 5 10 15 20 25 30 Time, mins 33

Task 6 – Treatment of Produced Fluids Fouling of heater tubes Copper Tube Testing Solution on Stirrer Recirculator for Hot Oil 34 Thermocouple Data Logger

Task 6 – Treatment of Produced Fluids 260 All runs at 350 350 o F 160ppm polymer Cumulative deposit, mg 400ppm polymer 210 800ppm polymer White 160 deposit sticks 110 60 Run 5 at 350 o F, 10 160ppm 1 2 3 4 5 Test run 35