ENHANCED OIL RECOVERY
Principles, Importance, Status, and Operation S.M. Farouq Ali HOR Heavy Oil Recovery Technologies Ltd. e-mail:
[email protected]
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(Numbers give reserves in billions of barrels)
SAUDI ARABIA (260)
IRAQ (115) OTHER MIDDLE EAST (37)
ABU DHABI (92)
KUWAIT (99)
LIBYA (41)
NIGERIA (36)
CANADA (179)
IRAN (136)
KAZAKHSTAN (30)
USA (22)
RUSSIA (60) ALGERIA (12)
CHINA MEXICO NORTH SEA (12) (16) (12)
OTHER (78)
VENEZUELA (80)
WORLD OIL CONSUMPTION IN 2006
SMFA-ST 20071128 31 billion barrels SMFA20070423
(Data from Oil & Gas Journal, Dec.18, 2006)
al u q e s i e ld. uar oil r q o s w h ’s Eac e year of the n n to o umptio s c on 2
World oil consumption 2006 85 million B/D 2030 115 million B/D
7 1 9 1
il o d rl n o o i W t p m u /D s B n o c ion l l i m 1.5
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CONTENTS • General concepts • High pressure gas drives – miscible and immiscible • Chemical recovery methods • Thermal recovery methods • Related topics
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GENERAL CONCEPTS
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RESOURCE, RESERVES, RECOVERY FACTOR Reserves = Resource x Recovery Factor Resource is what is in the reservoir Reserves are what is producible using current technology under current economics
Recovery Factor is the key number that we need SMFA-ST 20071128
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RECOVERY FACTORS
: s r o t ac F y Ke ogy – Solution gas drive 10-15% light oil l o es e i t G r • e p o r P l 3-5% heavy oil •Oi – Water drive 25-50% light oil 5-10% heavy oil
• Primary Recovery
• Waterflooding
10-30% light oil 5% heavy oil
• Steamflooding
50-60% (California heavy oil) 10-40% (California heavy oil) 30% (Cold Lake heavy oil) 50% ? (Athabasca bitumen)
• Cyclic Steaming • SAGD SMFA-ST 20071128
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OIL RESERVES
OIL RESOURCES
LIGHT OIL
HEAVY OIL & TAR
(BILLION BARRELS)
(BILLION BARRELS)
World U.S.A. Canada Venezuela Kuwait Saudi Arabia Oman
1212 22 180 73 99 259 6
World 5000 U.S.A. 53 Canada 1670 Venezuela 2000 Kuwait ? Saudi Arabia ? Oman 5
Recovery Factor 33%
Recovery Factor 10%
ar e y e n o in ls e r r a b n o 1 billi SMFA-ST 20071128World consumes 3
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GAS RESERVES Russia Iran Qatar Saudi Arabia U.S.A. Venezuela Canada
1680 trillion cubic feet 812 508 224 183 148 60
One trillion = 1012
ne year o in ft u c n o li il tr 0 6 World consumes SMFA-ST 20071128
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Present world energy consumption is over 200 million oil equivalent barrels per day.
OTHER ENERGY RESOURCES • • • • • • • • •
Coal Becoming increasingly important Oil shale Little chance of commercial viability Nuclear Small, will increase Wind Very small, will increase Solar Very small, will increase Biomass Small, may increase Hydroelectric More or less maximum now Geothermal Small, limited es im t 3 > e b ll i w n o umpti s n o c y g r e n e , 0 ? Other 6 m o r f In 20 e m o c t i l il ew
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h er w – t n e s e r p e th that of
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UNCONVENTIONAL HYDROCARBON RESOURCES
ls e r r a b n o i trill 0 1 t u o b A
• Heavy oil – U.S.A.
Venezuela
Canada Other countries
Venezuela
U.S.A.
• Tar Sands – Canada
• Oil Shale – U.S.A.
Other countries
• Coal – U.S.A. SMFA-ST 20071128
Canada
Other countries 11
COST OF PRODUCING ONE BARREL OF OIL • California: heavy oil ($60/Bbl) Canada: Cold Lake heavy oil ($36/Bbl) • Canada: SAGD ($36/Bbl) • Canada: Surface Mined Oil Sd • North Sea: light oil • Venezuela: heavy oil $10 • Middle East: light oil $2 • Shale oil (Colorado oil shale) $80+ • Oil from coal $80+ SMFA-ST 20071128
$20 $20 $30 (?) $30 $30-40 re a s t s o c l Al g n i s a incre il price o h t i w
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DEVELOPMENT OF THE COLD LAKE PROJECT Slow process, requiring experimentation and careful engineering.
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GENERAL DESIGN OF EOR PROJECTS TOTAL TIME COULD APPROACH 20 YEARS 1. Site selection 2. Geology 3. Process selection 4. Lab testing and physical models 5. Numerical simulation 6. Pattern size and type 7. Pilot design/operation
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8. Observation/sampling wells 9. Post-project coring 10. Pilot evaluation 11. Prototype design 12. Operation 13. Decision for commercial project
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EOR – CLASSIFICATION
EW F Y R E V RK O W
EOR METHODS
Non-Thermal
Thermal Steam
Hot Water
CSS
Steam flood Frac.
Non-Frac.
In Situ
SAGD
Conduction Forward Reverse Heating
VAPEX
Dry
VAPEX + Steam
Wet
SAGP
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With Additives
Electrical High Press. Air Injection
Miscible
Chemical
Gas Drives
Other
Slug Process
Polymer
CO2
MEOR
Enriched Gas Drive
Surfactant
Flue Gas
FOAM
Alkaline
Inert Gas
Vaporizing Gas Drive N2
Emulsion
THAI
CO2 miscible
Micellar
CAPRI
Alcohol
ASP
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TARGET OF EOR (Assuming an Soi of 85% PV) Light Oil
Heavy Oil
Initial fluid in place EOR Target
EOR Target
Water
Water
Secondary Primary
Secondary
Primary – 25% OOIP Secondary – 30% Remaining – 45%
Primary
Primary – 5% OOIP Secondary – 5% Remaining – 90%
Tar Sand EOR Target Water
Primary – 0% OOIP Secondary – 0% Remaining – 100% SMFA-ST 20071128
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MISCIBLE AND IMMISCIBLE GAS INJECTION
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• Gas Injection for pressure maintenance the oldest recovery method • Gases as displacing fluids – – – –
Natural Gas Flue Gas Air, Nitrogen Carbon Dioxide
• Miscible or immiscible displacement SMFA-ST 20071128
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MISCIBLE & IMMISCIBLE FLUIDS
• Mainly Three Types of Systems: – Gas Only Systems • Miscible in All Proportions
– Gas-Liquid Systems • Solubility a Function of:
– Pressure, Temperature – Liquid-Liquid Systems • Miscible Fluids • Immiscible Fluids SMFA-ST 20071128
nd ies a ty mpl i l i b I u y l t So cibili Mis mical Che ilarity Sim
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GAS INJECTION FOR OIL RECOVERY • HISTORY – In use since 1950’s – Natural Gas, Flue Gas, Air, N2, CO2 were commonly used – Initially as Secondary Recovery Process – Immiscible Displacement • Left high residual oil saturation: 40-60% OOIP – Miscible Displacement • Large density difference between displacing and displaced fluids • Low volumetric sweep SMFA-ST 20071128
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GAS INJECTION: HISTORY
Cont’d • Search for more efficient miscible fluids • Alcohol Flooding – Large volumes of alcohols required – Uneconomic due to high cost of alcohols
• Surfactant Based Processes – Micellar Flooding • Proven effective in recovering residual oil • Can give good volumetric sweep • Chemical costs and operational expenses are prohibitive SMFA-ST 20071128
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GAS INJECTION: HISTORY Cont’d
• Solvent Injection recovered more oil after primary production • Hydrocarbon solvents include: – Natural gas, LPG, Propane – Miscible with certain type of crude oils – Can become miscible under certain conditions
• CO2 and Flue Gas were also used SMFA-ST 20071128
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GAS INJECTION: HISTORY Cont’d
•
Mainly two types:
•
Single Contact Miscible (SCM) Process – –
•
Also known as First Contact Miscible (FCM) Solvent and reservoir oil are directly miscible
Multiple Contact Miscible Process – MCM – –
Solvent and reservoir oil become miscible after continued contact Two variations Also know a s • Vaporizing Gas Drive D y na n Misc mic • Condensing Gas Drive ibl e Proc e sse s
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GAS INJECTION: HISTORY Cont’d
• Large number of projects in Canada and the U.S.A. • Low viscosity (1 results in low volumetric sweep • Low oil recovery after solvent breakthrough • In miscible floods, breakthrough recovery governed by μo SMFA-ST 20071128
μs
(After Stalkup, Stalkup, Jr., F.I Miscible Displacement, SPE, Richardson, TX, 8, 1992) 1992)
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VISCOUS INSTABILITIES • Excessive fluid mixing due to: – Unfavorable mobility ratio – Large difference in fluid densities – Permeability variations
• • • •
Unstable displacement Early breakthrough of solvent Low sweep efficiency Low oil recovery
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VISCOUS INSTABILITIES Cont’d
• Viscous fingers increase in size and number with time – Influenced by dispersion – Length proportional to flow t rate – Width proportional to
• Merging and overlapping may impart better stability SMFA-ST 20071128
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GRAVITY TONGUING/OVERRIDE • Displacing fluid overrides the oil – Large density difference – Can lead to viscous instabilities if M>>1 – Viscous to gravity ratio control the vertical sweep
• Viscous instabilities can completely dominate displacement
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(After Stalkup, Stalkup, Jr., F.I Miscible Displacement, SPE, Richardson, TX, 8, 1992) 1992)
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GRAVITY TONGUING/OVERRIDE Cont’d • Particularly problematic in horizontal reservoirs • Gravity effects can stabilize displacement front in vertical reservoirs – Must have good vertical permeability – Preferably thick pay zone – Longitudinal dispersion prominent than transverse dispersion
• Production rate controlled not to exceed the critical velocity SMFA-ST 20071128
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AREAL SWEEP EFFICIENCY, EA • Definition: Ev =
Area swept by the displacing fluid total reservoir area
• Controlling Factors are: – – – –
Permeability heterogeneities Injection-production well pattern geometry Mobility Ratio Gravity and Viscous forces
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VERTICAL SWEEP EFFICIENCY • Definition: Pore space swept by the displacing fluid Ev = Pore space in the layers behind the leading edge of the displacing front
• Major Controlling Factors: – Gravity Segregation • Large density differences • Very low injection rates
– Mobility Ratio • Gravity override suppressed when M 1 > n ofte
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VISCOSITY OF HC LIQUIDS AT 1ATM
After Brown et al.: Natural Gasoline and the Volatile Hydrocarbons, Natural Gasoline Association, Tulsa, O.K., SMFA-ST 20071128 1948
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VISCOSITY OF GASES • Pressure, Temperature effects: Propane gas
w es, o l At ssur y T t e i s r p cos s a e vis reas s e inc reas inc
Liquid propane
After Katz, D.L.. Handbook of Natural Gas, McGraw Hill Book Co. NY, 1959.
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MISCIBLE DISPLACEMENT PROCESSES • First Contact Miscible Process – (FCM, SCM) – Reservoir oil and injected fluid miscible upon contact
• Multiple Contact Miscible Process – (MCM) – Miscibility achieved after several contacts
• • • •
Continuous Injection Slug Process Solvents: Ethane, Propane, Butane, LPG Drive Fluids: Methane, Natural gas, Nitrogen
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FIRST CONTACT MISCIBLE PROCESS (FCM/SCM) • Reservoir oil and solvent are directly miscible ~1100-1300 psi
~100-200 psi
• LPG, Slug Process • Slug Size: 4-5% HCPV • Drive Gas: 20-40% HCPV methane or N2 SMFA-ST 20071128
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PHASE BEHAVIOR - SCM • Data from PVT Experiments
Impurities alter miscibility pressure
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Pressure required for drive gas-solvent slug miscibility is the controlling pressure Higher pressures give greater flexibility in injected gas composition
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OTHER FACTORS - SCM • Reservoir Temp. below Tc of solvent : – Asphaltene precipitation • Ethane – Hexane may cause precipitation from asphaltic crude oils • Plugging near wellbore region • Laboratory tests to evaluate the extent of precipitation
• Reservoir Temp. above Tc of solvent: – Miscibility possible at pressures above cricondenbar • Depends on reservoir temperature and oil composition also
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SCM – OTHER FACTORS Cont’d • Process Efficiency – Slug Size
• Oil SMFA-ST 20071128
• Larger slug size gives higher recovery, but process efficiency drops • Depends on : V P HC – Oil viscosity % 5 4 r – Permeability Stratification he t s ire m fo ver PV u o le q – kv/kh u e y t R nim ili dab – well spacing mi scib floo mi tire Recovery: 60-80% OOIP en
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SCM - SCREENING CRITERIA • Oil viscosity - ≤ 2 cp, >5 cp too viscous • API Gravity - 35-45º API, 40º API Oil viscosity < 3 cp ( 25% PV Rock - Sandstone, Carbonate Depth - Enough to contain the pressure required for miscibility • Minimum of 5,000 psi recommended
• Oil must be undersaturated with respect to methane
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DISCUSSION OF FIELD PROJECTS MITSUE GILWOOD SAND UNIT #1 HORIZONTAL MISCIBLE FLOOD Two-stage miscible flood with WAG injection, started in 1985 Successful SMFA-ST 20071128
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RESERVOIR LOCATION Fr
- --
s ga ee
-- -- -A r-ife qu -- -
--- --
Figure shows the miscible flood area only.
- --
• Located in northwest Alberta • Reservoir is 42 miles long • 120,000 acres • Excellent example of reservoir management and EOR
--
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FORMATION DESCRIPTION • Gilwood fluvial sandstone (Devonian) • Extensive aquifer at the (downdip) western edge of the pool • Regions of free gas at the (updip) edge • Six channel sands – – – –
-5 of 1 Upper layer: Channels 1 and 2 s er 5% y 9 a L in a t Middle layer: Channels 3 to 5 con oil Lower layer: Channel 6 the Shales are present between the channels
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FORMATION and OIL PROPERTIES • Net pay 17.8 ft • Porosity 13.5% • Average permeability 230 md • Oil viscosity 0.6 cp (41º API) • Oil density 0.7 g/cc • bpp 1450 to 1800 psia • Miscible flood operating conditions 2500 psia, 144º F SMFA-ST 20071128
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FIELD HISTORY • • • •
Discovered in 1964 Primary recovery to 1968 Waterflood to 1985 Waterflood recovery 44.6% in the miscible flood area • Miscible flood started in 1985
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Recovery 245 MMSTB or, 27.2% in the Unit y b ry e v
co e r if % e , t s 6 d a a 4 o w e m o i l t f Ul ter ued to b wa ntin ted co tima es
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MISCIBLE FLOOD DESIGN • Done on the basis of phase behaviour studies, slim tube, slim tube simulation, core floods, and numerical field simulation • 15% HCPV solvent (enriched solution gas) slug, followed by 25% HCPV lean gas slug, all with water (WAG ratio 1:1) • Injected solvent was first contact miscible with oil at 2500 psia and 144º F • Flood done in two stages (Stage 1 in 1985, Stage 2 in 1986), to minimize off-lease gas and NGL purchases for solvent enrichment SMFA-ST 20071128
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MISCIBLE FLOOD DESIGN Cont’d
• • • • • •
Stage 1: 27 inverted five-spots Stage 2: 28 inverted five-spots 95 infill wells drilled for the miscible flood Expected incremental recovery 12.2% Expected solvent recovery 73% Expected chase gas recovery 44%
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INJECTION and PRODUCTION Water
GOR Oil
WOR Solvent
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WAG ratio
Tertiary oil
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PRODUCTION HISTORY • Within a year after start-up, oil prices dropped, hence: – solvent inj rate was reduced – water rate increased, – WAG ratio was increased (cumulative WAG 1.34)
• Initial design was for FCM, but was changed to MCM in 1989-91 to cut down cost – Solvent slug size increased from 15% to 18% in 33 patterns
• By 1991-92, entire project was on chase gas injection
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PERFORMANCE • Tertiary recovery to April 1995 6.3% OOIP • Peak production 11,400 B/D in August 1990 – at the end of solvent injection 85% of project oil • Effective Reservoir Management:production was tertiary – Collection and organization of large amount of data – Interpretation and diagnosis of flood performance – Timely and accurate recommendations – Accessibilty of data base to engineers and geologists SMFA-ST 20071128
oil
GOR Oil
WOR
Tertiary oil
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PERFORMANCE Cont’d • Project-wide solvent injection 14.1% HCPV • Project-wide chase gas inj. was 9.3% HCPV – • Solvent BT in 123 out of 163 wells • Solvent recovery (1995) 61.6% of injected
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OPERATIONAL ASPECTS • 54% of gas produced is chase gas • Solvent breakthrough identified by – (C2+C3)/C1 ratio [C2 and C3 added for enrichment; before BT, ratio was 0.35, after BT >0.9] – solvent tracer breakthrough – GOR increase – Oil increase
• Chase gas breakthrough identified by – C1 mole fraction increased SMFA-ST 20071128
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STREAMTUBE MODEL STREAMLINES
Areal sweep calculated from the streamtube model.
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SOLVENT BREAKTHROUGH
Areal sweep patterns were used to calculate solvent BT – good agreement with the actual.
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COMPARISON WITH WATERFLOOD O il ra te
W a te rflo o d
P re d ic tio n
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DISCUSSION OF FIELD PROJECTS BEAR LAKE CARDIUM UNIT Pembina Field, Alberta
Rich Gas Drive Miscible Flood Secondary Scheme Successful SMFA-ST 20071128
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RESERVOIR LOCATION • Located in the northwestern part of Pembina field (4th largest in North America)
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RESERVOIR PLAN VIEW 29 WELLS, 3 INJECTORS, 25 PRODUCERS 1 SHUT-IN
Water injector
Solvent injector
Water injector
Area: 4160 acres SMFA-ST 20071128
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FORMATION DESCRIPTION • Depth 4,857 ft • Deltaic sand bar 1½ miles wide, 6 miles long (Cretaceous) • Conglomerate on top (up to 41 ft thick), sand below, 0 to 35 ft thick SMFA-ST 20071128
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CROSS-SECTIONS
• Notice the scale is highly exaggerated •Reservoir is very thin compared to the areal extent • Notice the cross-sections at different parts of the field SMFA-ST 20071128
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DEPTH TO THE TOP OF PAY
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TYPICAL PROPERTIES • • • • • • • • •
Sand permeability 20 md, cgl 700 md Wide permeability variation Porosity in both 11% il o r oi kh > 10 kv v r se ed t e a R hly tur Connate water saturation 11% hig ersa d OOIP 61.4 million STB un Initial BHP 2620 psia (1975: 1600 psia) Oil viscosity 1.5 cp (37.6 API black oil) Bubble point press 1304 psia, solution gas 310 scf/STB • Solvent viscosity 0.029 cp (1500 psia, 112 F) SMFA-ST 20071128
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PRODUCTION HISTORY free gas
250 scf/STB
Oil
pb 600 STB/D
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DETAILS
• Production started in 1959 • Pressure declined 2620 to 1300 psi during primary • 9 years of primary produced 1.8 million bbls (RF 2100 psig; multiple contact miscibility at lower pressures • Slug volume 1.2 million res bbls (3% HCPV) – WAG Process in 4 cycles
• Chase gas slug 2.8 million res bbls methane – WAG Process SMFA-ST 20071128
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MONITORING OF THE FLOOD
Production histories of two wells shown
Only these wells showed solvent prod These wells were completed in the upper conglomerate Wells shut in due to excessive gas production SMFA-ST 20071128
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PERFORMANCE • Good: oil prod rate increased from 600 to 4000 B/D (5.6 million bbls oil) • low WOR and GOR • Often loss of injectivity occurred in the solvent injection well, when switching from water to solvent • Only two wells showed LPG production, with simultaneous GOR increase SMFA-ST 20071128
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PERFORMANCE ANALYSIS • Compositional simulation showed: – gravity segregation of gas and water a short distance from the injection wells – high-methane content gas formed and accumulated at the solvent-oil front – LPG enriched oil channelled rapidly through highpermeability layers, leading to early breakthrough
• Gravity override was the most important mechanism • WAG was largely ineffective due to strong gravity effect • Project produced additional oil over a waterflood
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CARBON DIOXIDE INJECTION FOR OIL RECOVERY • HISTORY – CO2 lab and field studies since 1950 – Early 1970’s • High oil prices • Oil embargo, declining production • Hence interest in CO2
– Currently several large projects, total 62 projects in North America SMFA-ST 20071128
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CO2 PROCESSES • Two Types: • Immiscible (or subcritical) process for heavy oils (10-25 ºAPI, 100-1000 cp) • Miscible process for light/medium oils (>30 API, 2000 psi), and temp. 100-200º F • Extracts (C5-C30) – Intermediate press. (1000-2000 psi), and temp.
