Oil Sands Production Technologies. Milind D. Deo, Professor Department of Chemical Engineering, University of Utah, Salt Lake City, Utah

Transcription

1 Oil Sands Production Technologies Milind D. Deo, Professor Department of Chemical Engineering, University of Utah, Salt Lake City, Utah

2 Acknowledgements Chung-Kan Huang US DOE, Fractured Reservoir Simulation Program at the University of Utah; University of Utah heavy oil program Computer Modeling Group, Calgary, Canada for Academic Licenses and problem templates Gridding CUBIT from Sandia National Lab Academic License

3 Asphalt Ridge PR Spring Sunnyside Tar Sand Triangle Utah Reservoirs 800 MMB 2100 MMB 4500 MMB 2500 MMB 1000 MMB Other smaller deposits 1000 MMB Whiterocks MMB Total Resource MMB Speculative 8000 MMB

4 Where do we go from here? Backdrop Oil at $100/barrel Multi-billion dollar developments in Canada Sporadic attempts to get the industry going in five decades Questions we must answer Is the resource there? Is the technology there? Is there a market?

5 In-situ Bitumen Production Variation of steam injection technologies for heavy oil The most common methods are cyclic and SAGD (Steam Assisted Gravity Drainage) Recognition that utilizing gravity most effective way to produce oil rather than inducing a pressure drop In-situ combustion and associated technologies

6 Sunnyside Cross Section Sunnyside Cross-section From Wally Gwynn, Utah Geological Survey

7 Reservoir description 200ft 200ft 5000 Viscosity of Oil 4000 Viscosity cp ft Layer A 80ft 80ft 1000 Layer B Layer A 20ft 20ft Temp o F Layer B Layer A, Perms Layer B - Perms Layer A - Sat Layer B - Sat OOIP Case / / ,000 Case / / ,000

8 Well strategies Producer Injector Producer Injector Distance between 2 horizontal wells: 20ft Horizontal well pairs are better High water-cut production Steam-oil ratio high (>5) Good recoveries (>35%)

9 Whiterocks: Well log data z y x

10 Whiterocks: Bedding information bottom up Layer Category Perm. Por. Sat. 1 r l r b l b l b v l v b l b v b v b l r v r b l b

11 Geology model 60 ft 80 psi 70 deg 560 ft 220 ft bottom top

12 Whiterocks: Geologic model Y 600 ft 210 ft Z 560 ft X 210 ft? mile? mile

13 Wells Symmetric 600 ft full wells 290 ft 25 ft ½ wells

14 Evolution of the steam chambers SAGD Cyclic

15 SAGD

16 Cyclic Cyclic is a better option

17 What about heterogeneities? Lenticular features looked at to an extent Reservoir may not have enough injectivity Stimulation fracturing What impact does this have? Study this question using fractured simulators developed at the University of Utah

18 Governing equations: Conservation equations Nc components, Np phases, Nf fluid phases, Ne phase equilibriums and Nr chemical reactions, Nc Conservation of the component i: Np p x S v + (x f ) + Δs ϒ = x q p,i p p Nf Nr Nf t φρ p,i p r,i r p,i p p r p Conservation of energy: φ ρ + φ Np Up ps p (1 )Ur Nf Nf p v v + (Hpf p) + qc = Hpqp t p p where v k rpρ p f p = K ( Pp +γp Z) μ p v and qc = λc T

19 Matrix and fracture representation in CVFEM representation uv uv uv qdγ= q dγ+ q dγ m Γ Γ Γ m f f z y x 1 1 4

20 Chemical reactions Power law kinetics: Ea Nc ni r k0 exp( ) Ci RT h i = 1 R = Coats method for free oxygen, 1983 kt T * ( )= * Ae Ea (- ) * RT * ACT = = > * ACT = T T T T T T T T ACT

21 Steamflooding in fractured reservoir Component ID Type Oil Gas Water Heavy oil Oleic Light oil Oleic Water Aqueous Permeability contrast (fracture/matrix): Low: 2 High: 100 BHP Producer: 100 psi Injector: 350 psi (70% steam) 200 X200 X50 Tetrahedrons: Triangles: 3355 Nodes: 5868

22 Steamflooding in fractured reservoir 2000 th day Low permeability contrast High permeability contrast

23 Steamflooding in fractured reservoir low contrast Far well Near well

24 Steamflooding in fractured reservoir high contrast Wells located on fractures

25 Application1: Steamflooding in fractured reservoir high contrast All wells shown

26 Application2: in-situ combustion (Kinetics adapted from a CMG Template) Component ID 100 X100 X25 10X10X5 Type Oil Gas Water Solid Heavy oil Oleic Light oil Oleic CO 2 +N 2 Oleic O 2 Oleic H 2 O Aqueous Coke Solid HO 2.154LO Coke ϒ = kc 1 HO LO O 11.96(CO + N ) H O ϒ = kc P 2 LO O 3 HO O 4 Coke O HO O 51.53(CO + N ) H O ϒ = kc P Coke O 1.00(CO + N ) H O ϒ = kc P Injected Air: Dry Wet (air/water by volume): 99:1 98:2 85:15 80:20

27 In-situ combustion (one-dimensional feasibility test - dry) 1-D dry in-situ combustion Pressure, psi & Temperature, R fraction Pressure, psi Temperature, R So Sg Sw Ss yo X 1/10 ft

28 In-situ combustion (one-dimensional feasibility test - wet) 1-D wet in-situ combustion Pressure, psi & Temperature, R fraction Pressure, psi Temperature, R So Sg Sw Ss yo X 1/10 ft

29 Modeling of in-situ combustion in shale Porosity : 35 % (v f + v k ) (3 ~ 10 % v f ) Parameters (base-case): Initial kerogen concentration. (0.08 lbmol / cf [P.V.] ~ 11.1 wt.%) Air flow rate. (100,000 scf / day) Horizontal permeability. (1,000 md) Vertical permeability. (10 md) Residual water : 10 % Initial pressure : 200 psi P production : 100 psi Perforation 88 ft 88 ft 88 ft

30 Process snapshot 1D O 2 mol. fr Temperature S o coke conc. kerogen conc. in-situ combustion Injector

31 In-situ combustion oil sands 40 th day Dry combustion Wet combustion 80:20

32 In-situ combustion production rate 100:0 99:1 98:2 85:15 80:20

33 Summary Variety of simulation tools available for evaluating in-situ processes Great potential, significant challenges Canadian development did not occur overnight Staged technology development experimental, simulation and pilot research Consistent approach