Workshop: Minnelusa I Day 3 8:10 9:10 am Minnelusa IOR/EOR - PowerPoint PPT Presentation

Workshop: Minnelusa I Day 3 8:10 – 9:10 am Minnelusa IOR/EOR options and feasibility June 5, 2014 1 Gillette, WY Vladimir Alvarado, Ph.D.

Outline  Introduction  IOR and EOR  Traditional EOR targets  Workflow and need for screening  Traditional screening & advanced methods  Gas methods  Chemical methods  Issues specific to Minnelusa reservoirs  Summary 2

IOR and EOR Modified from Chadwick, 2003 3 3

Recovery Efficiency = × E E E R D V  E R : overall recovery efficiency  E D : displacement efficiency or microscopic  E V : volumetric sweep efficiency 4

Mobility Ratio Mobility k k k λ = λ = λ = g ; ; o w µ µ µ o w g o w g Mobility Ratio ( ) ( ) λ λ µ k S / ≡ = w = S D rw or w M M or ( ) ( ) λ λ µ w , o k S / d d ro wc o S wc Similarly for other phase ratios 5 5/29/2014

Traditional Phases of Field Production Field Development Plan Simulation and engineering studies (Update reservoir model) Optimization of operation Production Production starts 2 ary Recovery / Pressure Exploration appraisal maintenance 3 ary Recovery (EOR) Natural Abandonment/ Depletion Decommissioning Geologic Model 6 Time

A Possible Workflow (for success?) • Frame the problem Conventional Screening Conventional Screening Conventional Screening Conventional Screening adequately Geologic Screening Geologic Screening Geologic Screening Geologic Screening • Avoid excessive and often Field Cases Type I Field Cases Type I Field Cases Type I unnecessary reiteration of Advanced Screening Advanced Screening Advanced Screening Advanced Screening analysis that leads nowhere Evaluation of Soft Variables Evaluation of Soft Variables Evaluation of Soft Variables Evaluation of Soft Variables • Realize when simpler is better or new data are Re-evaluation cycle Re-evaluation cycle Re-evaluation cycle Decision Analysis Decision Analysis Decision Analysis Decision Analysis Stop Stop Stop Stop necessary Performance Prediction Performance Prediction Performance Prediction Performance Prediction • Manage soft issues, before Field Cases Type II Field Cases Type II Field Cases Type II they become hard lessons Analytical Simulation Analytical Simulation Analytical Simulation Analytical Simulation Numerical Simulation Numerical Simulation Numerical Simulation Numerical Simulation • Understand that a bad outcome does not qualify a Economics Economics Economics Economics decision Decision Analysis Decision Analysis Decision Analysis Decision Analysis Stop Stop Stop Stop 7

Lookup Table Screening Criteria Oil Properties Reservoir Characteristics Detail EOR Method Gravity Viscosity Composition Oil Formation Net Average Depth (ft) Temperature ( o API) ( o F) Table (cp) Saturation Thickness Permeability Type (ft) (md) Gas Injection Methods (Miscible) >35 ↑48 ↑ <0.4 ↓0.2 ↓ >40 ↑75 ↑ 1 Nitrogen and flue High percent Sandstone Thin unless NC >6,000 NC gas of C1 to C7 or dipping Carbonate >23 ↑41 ↑ <3 ↓0.5 ↓ >30 ↑80 ↑ 2 Hydrocarbon High percent Sandstone Thin unless NC >4,000 NC of C2 to C7 or dipping Carbonate >22 ↑36 ↑ <10 ↓1.5 ↓ >20 ↑5 ↑ 3 CO2 High percent Sandstone Wide Range NC >2,500 NC of C5 to C12 or Carbonate >35 ↑70 ↑ NC if dipping 1-3 Immiscible gases >12 <600 NC NC NC >1,800 NC or good Kv Enhanced Waterfflooding >20 ↑35 ↑ <35 ↓13 ↓ >35 ↑53↑ >10 ↑450↑ >9,000 ↓ >200 ↓80 4 Micellar Polymer, Light Sandstone NC ASP, and Alkaline intermediate, preferred 3,250 flooding organic acids >50 ↑80↑ >10 ↑800↑ >200 ↓1400 5 Polymer Flooding >15 <150, >10 NC Sandstone NC <9,000 preferred Thermal/Mechanical High φ sand >10 ↑16 >50 ↑72↑ >11,500 ↓ >100 ↑135 6 Combustion <5,000 Some >10 >50 ↓1,200 asphaltic /Sandstone 3,500 components High φ sand >40 ↑66↑ >200 ↑2,450 >4,500 ↓ 7 Steam >8 to 13.5 <200,000 NC >20 NC ↓4,700 ↑ /Sandstone 1,500 - Surface Mining 7 to 11 Zero cold NC >8wt% Mineable tar >10 NC >3:1 NC overburden flow sand sand to sand

Advanced Screening Criteria Cluster 4 Method % Cluster 6 CO2 Immisc. CO2 Immisc. 22.58 Air 12.90 Method % Cluster 5 Water Flooding 12.90 N2 Misc. 42.86 CO2 Misc. Method % CO2 Misc. 9.68 N2 Immisc. 21.43 Polymer 9.68 Air 41.38 WAG N2 Misc. 14.29 N2 Immisc. WAG HC Immisc. 9.68 Water Flooding 14.29 Steam 27.59 N2 Misc. 6.45 WAG HC Misc. 7.14 WAG HC Misc. 6.45 N2 Misc. CO2 Immisc. 10.34 N2 Immisc. 3.23 Polymer 8.62 Steam 3.23 Polymer WAG CO2 Immisc. 5.17 3.23 WAG CO2 Misc. Water Flooding 5.17 Steam 1.72 N2 Immisc. WAG CO2 Immisc. WAG HC Immisc. WAG CO2 Misc. WAG HC Misc. Air Water Flooding Cluster 2 % Method Water Flooding 38.46 Cluster 1 WAG CO2 Misc. 13.46 Method % WAG HC Misc. 13.46 29.17 Water Flooding Cluster 3 N2 Misc. 9.62 20.83 CO2 Misc. CO2 Misc. 7.69 Polymer 18.75 Method % N2 Immisc. 7.69 N2 Immisc. 6.25 Water Flooding 48.28 Polymer 5.77 Steam 6.25 Polymer 25.29 WAG HC Misc. 6.25 Air 3.85 WAG CO2 Misc. 12.64 CO2 Immisc. 4.17 CO2 Misc. 10.34 WAG CO2 Misc. 4.17 N2 Immisc. 1.15 9 9 N2 Misc. 2.08 WAG HC Misc. 1.15 WAG N2 Misc. 2.08 Steam 1.15 SPE-78332

EOR Gas Methods Gas injection methods can be classified as:  Miscible processes  Immiscible processes Miscibility of two fluids occurs at either first contact or multiple contacts (condensing and vaporizing gas drives). Generally, gas injection processes in heavy and medium crude oil reservoirs (< 25 ° API) are immiscible. However, miscibility in medium crude oils can be achieved in deep, high temperature, high pressure reservoirs. 10 10

Phase Behavior in Gas EOR 11 11 Ternary diagram for three-component mixture

First Contact Miscibility Mixtures miscible with oil Oil compositions 12 12 miscible with gas

Multiple Contact Miscibility: Condensing Gas Drive (continued) Type of displacement GI 1 So Oil Gas 0 X Oil Piston-like displacement 13

Screening Criteria Basic Screening Criteria Major criteria for immiscible and miscible gas injection ( SPE-88716; SPE-35385 ) Immisicible Gas Miscible Miscible CO 2 Miscible N 2 injection HC Injection Depth (m) > 200 > 1200 > 600 > 1800 Oil Saturation (%) > 50 > 30 > 25 > 35 Oil Gravity (°API) > 13 > 24 > 22 > 35 Oil Viscosity @ Pb < 600 < 5 < 10 < 2 (mPa.s) High % of light High % of light High % of light Crude Oil hydrocarbons hydrocarbons hydrocarbons NC composition (C 2 to C 7 ) (C 5 to C 12 ) (C 1 to C 7 ) NC = Not critical 1 mPa.s = 1 cp 14

CO 2 Flooding Geologic Screening Criteria: Clastic Reservoirs (continued) LATERAL HETEROGENEITY LOW MODERATE HIGH Delta-front mouth bars Wave-dominated delta Proximal delta front Meander belts* Barrier core LOW (accretionary) Fluvially dominated delta* Barrier shore face Tidal Deposits Back Barrier* Sand-rich strand plain Mud-rich strand plain (2) (2) (7) / [2] VERTICAL HETEROGENEITY Shelf barriers MODERATE Eolian Alluvial Fans Braided stream Wave-modified delta Fan Delta Tide-dominated delta (distal) Lacustrine delta Distal delta front (1) / [1] (3) / [1] (3) / [2] Back barrier** HIGH Coarse-grained meander belt Fluvially dominated delta** Basin-flooring turbidites Braid delta Fine-grained meander belt** Submarine fans** [1] (6) * Single units **Stacked Systems Tyler and Finley clastic heterogeneity matrix showing depositional systems of 24 15 15 successful (Blue) and 7 failed [Red] CO 2 injection projects

CO 2 Flooding Screening Criteria of CO 2 Floods Main Screening Criteria ( SPE-35385 ) Main reservoir properties of CO 2 floods ( SPE-94682 ) 16 16

CO 2 Flooding Quick Rules of Thumb • Reservoirs with good water flood response are best candidates for CO 2 . • Recovery factor using miscible CO 2 is 8%–11% OOIP. Immiscible CO 2 is 4%–6% (50% of miscible). • MMP equals initial bubble point pressure. • CO 2 requirement is 7–8 Mcf/barrel plus 3–5 Mcf/barrel recycled. • Water injection required to fill gas voidage and increase reservoir pressure above MMP. • WAG is alternative but 10 Mcf/barrel still required ( Most common development of CO 2 floods ). • Top down CO 2 injection alternative is effective but requires more capital investment for higher CO 2 volume (WAG Tapered). 17

CO 2 Flooding Unfavorable Reservoir Characteristics for Empirical Screening • High concentrations of vertical fractures • Very high, or very low, permeability • Vertical segregation or fracture channeling (WAG injection strategies preferred in these cases) • Thick reservoirs with no layered horizontal permeability barriers • Reservoirs with poor connectivity Well spacing >80 acres (4,047 m 2 ) • • Poor material balance during water flood (high water loss out of zone, water influx, or high water cut during primary production) • Asphaltene precipitation in the presence of CO 2 18

Chemical Methods: Polymer+Surfactant+Alkali 19 19