ENHANCED OIL RECOVERY METHODS TO MAXIMIZE RECOVERY FROM MATURE FIELDS
Enhanced Oil Recovery •
EOR normally known as tertiary recovery process
•
Applied to mobilize trapped oil in pores held up by viscous and capillary forces
•
Thermal, chemical, solvent/gases are the most common forms of various EOR processes
•
EOR is normally applied after primary and secondary recovery. However these can be applied at any stage of a producing field depending upon the performance history
Recovery Factor Defined as
Volumetric sweep X Displacement efficiency Areal sweep X Vertical sweep X Displacement efficiency • Areal sweep depends on the fluid mobility ,pattern type, aeal hetegeneity & total volume of fluid injected • Vertical sweep is governed by vertical heterogeneity, gravity segregation, fluid mobilities & total fluid injected • Displacement efficiency is a function of injection rate, viscosity, density and IFT of displacing fluid
Basic purpose of EOR processes is to improve sweep and displacement efficiency
Role of Mobility ratio and Capillary number on recovery Mobility ratio
M = λw / λo = Krw / Kro X μo / μw e.g. 100 / 0.5 = 200, water is 200 times more mobile compared to oil • To control the mobility ratio, increase the viscosity of water or reduce the viscosity of oil • This can be achieved by thickening water by polymer or heat application
Capillary number Capillary number = μv / σ μ = viscosity in cp v = darcy velocity of displacing fluid σ = IFT interfaced between displaced fluid and brine • If σ can be reduced by the order of 1000 ROS can be reduced to 10-15 %
Need for EOR • To maximize recovery after primary and secondary recovery from mature fields which is currently 30-50 % • Risk of applying EOR is considered reduced in view of better understanding, advances in R & D studies and successful pilot tests and field tests • Declining production trends and lesser large sized discoveries are important for EOR to tap additional oil
Part I Chemical EOR
Chemical EOR processes • These are applied in tertiary mode to mobilize the oil in pores held by capillary forces and adhesive forces and thus to reduce the ROS • This can be applied in secondary mode in combination with other displacement processed such as water or gas
• Basic mechanism involved are • Reduction in interfacial tension between oil and brine • Solubilization of released oil • Change in the wettability towards more water wet • reducing mobility contrast between crude oil and displacing fluid
Contd…
• In surfactant assisted chemical EOR it is mainly IFT reduction, wettability change and solubilization • In polymer assisted chemical EOR it is mobility control and improving sweep efficiency
Various chemical EOR processes • • • • •
Micellar/surfactant polymer flooding Alkaline flooding Alkali-surfactant flooding Alkali-surfactant-polymer flooding Polymer flooding
Selection of chemical EOR processes • • • • • • •
Type of reservoir Rock mineralogy, clay, heterogeneity Reservoir pay thickness, K, Ø Reservoir temperature Reservoir oil properties ROS Salinity of formation water and presence of bivalent cations
Technical screening criteria for chemical processes ASP/Micellar
Polymer
Gravity,0API
> 20
>15
Viscosity, cp
< 35
<100
Composition
Light Intermediate hydrocarbons are desirable for micellar and high acid number needed in alkaline flooding
Not critical
Oil saturation, %PV
> 35
>50
Formation water salinity
Chloride < 20000 ppm, Ca + Mg < 500 ppm
Type of Formation
Sandstone preferred
Crude Oil
Reservoir
Average permeability,
Depth and Temperature
>50 md
< 9000 ft, Temperature < 2000F
Application of various chemical EOR processes Micellar polymer flooding/surfactant polymer flooding •
Classic micellar polymer flooding consists of injecting a slug that contains surfactants, polymers, electrolyte, co-solvents and oil
•
The size of slug may vary from 5-15 % PV (for high surfactant concentration system) 15-50% PV (low surfactant concentration system)
•
Micellar process is highly effective, but it is costly
•
Low adsorption surfactant developed can replace the micellar solution and can be directly used in combination with the polymer as a surfactant polymer flooding
•
Recovery of the surfactant in SP flooding is comparable or even higher than ASP or micellar flooding
Polymer process The process improve recovery by reducing the mobility contrast between
•
oil and water and improving the overall sweep efficiency The polymer process can be applied in secondary mode to improve the
•
efficiency of water flood It can also be applied in combination with other chemical EOR such as
•
alkali, surfactant and ASP processes to improve the mobility of the respective processes This process does not reduce ROS
•
Alkaline-Surfactant-Polymer Flooding •
The process is normally applied in tertiary mode to reduce ROS
•
Addition of alkali and low slug volume make the process cost effective
•
Recovery in range of 15-25 % is observed
Alkaline-Surfactant Flooding • This process is applied in light oil reservoirs where polymer is not required • This can be applied in both carbonate as well as sandstone formations • However in the absence of mobility control displacement efficiency are low • Large slug volume is required • It can be combined with other EOR processes like gas injection to improve performance
Addition of alkali Advantages of adding alkali with surfactants
• improves the wetting characteristics of the rock • reduces the adsorption of surfactants • produces natural surfactant if crude is acidic
Alkaline / Alkaline Polymer Flooding • Applied in viscous crude with high acid number • Formation of tough emulsions observed in many cases • Reaction of alkali with clays and zeolites makes the process less effective • Corrosion is also a problem associated with the alkali process
Selection of surfactant and alkali
• Surfactants and alkali are integral part of chemical flooding • ¾ ¾ ¾ ¾ ¾ ¾ ¾
Selection of surfactant is based on Ability to reduce IFT between crude and brine Thermal stability Tolerance to salinity and hardness of brine Solubility in brine Phase behaviour parameters Adsorption test under static and dynamic conditions Displacement studies under reservoir conditions
Selection of alkali is guided by ¾ Type of formation, clay type & bivalent cations ¾ In carbonate reservoirs Na metaborate is used in place of other alkali ¾ If reservoir contains clays NaHCO3 is preferred ¾ Na2CO3 is the most commonly used alkali. It is cheap and transports better in porous media
Advances in the area of surfactants and polymers •
High performance surfactants have been developed which tolerates salinity up to 100000 ppm and 2500 ppm bivalent cation
•
SS surfactants show very low adsorption compared to conventional. Can be used alone or as SP flooding without alkali.
•
Blends of surfactants mixtures improves WF efficiency significantly.
•
Surfactants are available which are thermally stable up to 2600C
•
Recent R & D studies indicate that sulphonated acrylamide copolymers can tolerate high bivalent cations and temperature up to 1200C
Types of surfactants used in EOR • Normally anionic surfactants are used for EOR applications. Some blends of different surfactants are also used to get low IFT conditions and favourable wettability changes • Surfactants used in EOR are the following types; ¾ Petroleum sulphonate (PS), for reservoirs with temperature, low salinity and bivalent cations Better tolerance to salinity ¾ α-olefin sulphonate and hardness, ¾ Internal olefin sulphonate high temperature stability ¾ Alkyl-Aryl sulphonate, for high temperature applications ¾ Ethoxylated alcohol
Thermal stability of the surfactants are in the following order AAS > IOS > AOS > PS > Ethoxylated alcohol
Advantages of chemical EOR processes • Right blend of chemical system can increase recovery factor by 15-20 % • Chemical processes can be combined with other EOR processes to derive advantage of each other • Processes can be tailor made to suit specific crude and reservoir conditions • Can be applied in both sandstone and carbonate formations • Can improve recovery of polymer flooding after it reaches its limit • Low tension flooding improves the efficiency of water flooding/injectivity
Limitations of chemical EOR processes • Adsorption of chemicals on rock surfaces, particularly in carbonate formations and sandstone formations containing zeolites/clays • Chromatographic separation of chemical where thickness vary • Dilution of chemical in active water reservoir • Incompatibility with formation fluids in which high bivalent-cations are present • High temperature and high salinity limits application of chemical processes. Reaction of alkali with clays and swelling causes permeability reduction
Case history of chemical EOR (Indian scenario)
Sanand Polymer Flood
Because of mobility contrast and low primary recovery, it was decided to go for polymer flooding
Sanand Polymer Flood Polymer pilot, 1985 Expanded pilot, 1993 Commercial scheme
Scheme, 1999
Polymer Injectors Chase Water Injectors New polymer injectors
Performance of polymer flood Production increased from 100 M3/day to 400 M3/day Water cut reduced from 88% to 68% WC remains constant since last 6 years (63-68%) Current recovery – 25 % Expected recovery – 36 % by 2030 Performance Plot of KS-III sand of Sanand Field 100
600 Commerc ialisation
Qo m3/d
500
90
Pilot
w/c %
80
Extended Pilot
400
70
50
300
40 200
30 20
100
10
Feb-08
Jun-06
Oct-04
Feb-03
Jun-01
Oct-99
Feb-98
Jun-96
Oct-94
Feb-93
Jun-91
Oct-89
Feb-88
Jun-86
Oct-84
Feb-83
Jun-81
Oct-79
Feb-78
Jun-76
Oct-74
Jan-73
0 May-71
0
w/c
60
May-69
Oil Rate
• • • • •
Viraj ASP Pilot Based on the low primary recovery and mobility contrast and high acid number of the crude, ASP pilot was decided in the Field
Sep-08
Jun-08
Mar-08
Jan-08
200 100
180 90
160 80
W/C
120 60
100 50
80 40
60 30
40 stop C/W 20
20 10
0 0
W/C, %
Oil rate
Oct-07
Jul-07
Base oilrate
Apr-07
Jan-07
Oct-06
C/W
Jul-06
140
Apr-06
Jan-06
PB-3
Oct-05
Jul-05
Apr-05
PB-2
Jan-05
Oct-04
Jul-04
PB-1
Apr-04
Jan-04
Oct-03
ASP
Jul-03
Apr-03
Jan-03
Oct-02
Jul-02
Oil, m3/d
Performance plot of Viraj ASP Pilot
70
Observations • Pilot was successful with increase in production • Preferential movement of chemical • Water cut increase at start of buffer and chase water injection • Simulation studies indicate slug size and polymer concentration on low side • Lesson learned from this pilot are being taken care in other upcoming pilots
Other envisaged pilots • ASP Jhalora • ASP Kalol • ASP Mangala
Chemical EOR - World Scenario (Active projects) Country
Number of active chemical projects Polymer
Micellar/Polym er
ASP
USA
4
-
-
China
18
-
-
France
1
-
-
India
1
Indonesia
-
1
-
Venezuela
-
-
2
24
1
3
Total
1
Part II GAS Flooding
Gas Flooding • This process is mostly applied in light and tight reservoir because of its high microscopic displacement efficiency • This process can be combined with other recovery processes such as water or surfactant system. • It can be applied in both miscible and immiscible ways • The efficiency of miscible process is high compared to immiscible process
Various types of gas flooding • Hydrocarbon flooding (LPG, Enriched and Lean gas) • CO2 flooding • N2 and Flue gas injection
CO2 flooding (Miscible/Immiscible) • •
•
•
The process is the most widely used and involves the injection of CO2 (15-30 % of HCPV) into reservoir CO2 recovers oil by • Swelling the crude oil (CO2 is highly soluble in low gravity oil) • Lowering the viscosity of oil (much more than nitrogen and methane) • Lowering the IFT between oil and CO2/oil phase in near miscible region • Generation of miscibility The CO2 flooding is similar to vapourizing gas drive but only difference in CO2 process is that wider range of C2-C30 are extracted CO2 flood process is applicable to wider range of reservoirs because of its lower miscibility pressure than that for vapourizing gas drive
Screening criteria of CO2 Flood Recommended
Range of current projects
Gravity,0API
> 22
27 to 44
Viscosity, cp
< 10
0.3 to 6
Crude Oil
Composition
High percentage Of Intermediate Hydrocarbons (Especially C5 to C12)
Reservoir Oil saturation, %PV
> 20
15 to 70
Type of Formation
Sandstone or carbonate and relatively thin unless dipping
Average permeability, md
Not critical if sufficient injection rates can be maintained.
Depth and Temperature
For CO2 miscible Flooding
For immiscible (lower CO2 Flooding oil recovery)
Depth should be enough to allow injection pressures greater than the MMP, which increases with temperatures and for heavier oils. Recommended depths for CO2 floods are as follows: Oil Gravity, oAPI
Depth must be greater than,(ft)
> 40
2500
32 to 39.9
2800
28 to 31.9
3300
22 to 27.9
4000
< 22
Fails for miscible
13 to 21.9
1800
<13
All reservoirs fail at any depth
At < 1800 ft, all reservoirs fail screening for either miscible or immiscible flooding with supercritical CO2
Hydrocarbon flooding process (miscible/immiscible) Hydrocarbon miscible flooding recovers crude oil by • Generating miscibility (in the condensing and vapourizing gas drive) • Increasing oil volume by swelling • Decreasing the oil viscosity • Immiscible gas displacement, especially enhanced gravity drainage with reservoir conditions
Different HC Flooding Process are • LPG Process ¾ Consists LPG (5% of HCPV) followed by natural gas and water • Enriched gas process ¾ Process consists of injecting natural gas (10-20% HCPV) enriched by C2-C6 followed by lean gas and water • High pressure lean gas injection (vapourizing gas drive) ¾ Injection of lean gas at high pressure help to vapourize C2-C6 component of crude oil being displaced
Screening criteria for Hydrocarbon Miscible process Recommended
Range of current projects
Gravity,0API
> 23
24 to 54 (miscible)
Viscosity, cp
<3
0.04 to 2.3
Crude Oil
Composition
High percentage of light hydrocarbons
Reservoir Oil saturation, %PV Type of Formation Net thickness, ft
> 30
Sandstone or Carbonates with minimum of fractures and high permeability streaks Relatively thin unless formation is dipping
Average permeability, md Depth, ft Temperature,0F
30 to 98
Not critical if uniform > 4000
4040 to 15900
Temperatures can have significant effect on the minimum miscibility pressure (MMP); it normally raises the pressure required. However, this is accounted for in the deeper reservoirs that are needed to contain the high pressures for the lean gas drives.
N2/Flue gas flooding • This process recovers oil by – vapourizing the lighter component in the crude – generating miscibility if the pressure is high enough providing a gas drive where significant portion of the reservoir is filled with low cost gases – Enhancing gravity drainage in the dipping reservoir • It can be applied in both miscible as well as immiscible way depending on the temperature, pressure and oil composition • Because of low cost large volumes can be injected • N2/Flue gas can also be used as chase gas for HC and CO2 flood
Screening of N2 & Flue Gas Flood Recommended
Range of current projects
Gravity,0API
> 35
38 o 54 (miscible)
Viscosity, cp
< 0.4
0.07 to 0.3
Crude Oil
Composition
High percentage of light hydrocarbons
Reservoir Oil saturation, %PV Type of Formation Net thickness, ft
> 40
Sandstone or carbonates with few fractures and high permeability streaks Relatively thin unless formation is dipping
Average permeability, md Depth, ft Temperature,0F
59 to 80
Not critical > 6000
10000 to 18500
Not critical for screening purposes, even though the deep reservoirs required to accommodate the high pressure will have high temperatures.
Advantages of different gas flooding processes CO2 flooding • CO2 flood process can be applied to wider range of reservoir because of its lower miscibility than that for vapourizing gas drive • Oil recovery are high in miscible displacement, less in immiscible displacement • It swells the oil and reduces its viscosity even before miscibility is achieved HC flooding • Recovery factor in miscible HC flooding (LPG & Enriched) is quite high • Suitable for tight as well as light oil reservoirs • Can be applied both in carbonate and sandstone formations • Can be applied in reservoir depths ranging from 1000-5000 meters N2 flooding • It is a cheaper process and large volume can be applied • Can be applied in deep, tight and light reservoirs
Limitations of Gas flooding processes • • • •
N2 /Flue gas Flooding Can be applied only in high gravity and deep reservoirs Miscibility pressure is quite high, can not be applied in depleted reservoirs with high temperature Separation from non hydrocarbon gases from hydrocarbon gases at the surface Recovery efficiency is low (<5%) compared to other gas processes HC Flooding
• • • • •
Required pressure for LPG is 1280 psi 4000 to 5000 psi is required for high pressure gas drive Solvent trapped may not be recovered in LPG method Low viscosity results in poor vertical and horizontal sweep efficiency Large quantity of available hydrocarbons are required
Contd
CO2 Flooding • •
Sources of CO2 act as limitations for process to be applied CO2 gets dissolved into formation water making it acidic, causing corrosion of tubulars
Common limitations in gas flooding processes • • •
• • • •
Mobility control is an area of concern Viscous fingering may result in poor vertical/horizontal sweep Steeply dipping formation is desired for gravity stabilization of the displacement front, both for miscible and immiscible displacement Early breakthrough of gas is another issue, particularly if the reservoir contains natural and induced fractures Large volume of gas requirement makes the process expensive Attaining miscibility in depleted reservoirs with high temperature is an area of concern Immiscible displacement yields lesser recovery compared to miscible displacement
Other gas flooding processes • To derive the benefit of microscopic displacement efficiency of gases and megascopic displacement efficiency of water different combined EOR processes have been developed such as • Water Alternate Gas • Simultaneous Water and Gas Injection • Surfactant alternate Gas Flooding • Foam flooding
Case history
Miscible HC Gas Injection: Gandhar GS-12 •
•
Reservoir parameters – Depth – 2900m – Temperature 1260C – Thickness 4 m – API Gravity 45 – Initial saturation 52.5% – MMP 270 kg/cm2 Details of Pilot – Started in 1999 – Initial gas injection 200000 m3/day through 4 injectors – Current gas injection 700000 m3/day
Contd… : 36 % : 58 % : 14 (700,000 m3/d) : 270 ksc : 800 m3/d / 1%
1250
300
1000
240
750
180
500
120
250
60
0
Gas Inj 1991
92
93
94
95
96
97
98
99
2000
01
02
03
04
05
06
07
0
Pressure(kg/cm2)
Oil Rate (m3/d)
Waterflood Recovery HC Miscible Gas Inj. Recovery Gas Injectors Avg Res Pressure Oil rate / water cut
Gas Flooding - World Scenario Country
Number of active Gas Injection Projects Carbon Dioxide
HC
Others
USA
71
8
4
Canada
2
29
1
Libya
-
1
-
China
-
-
-
Colombia
-
-
-
India
-
1
-
Mexico
-
-
1
UAE
-
1
-
Indonesia
-
-
-
Trinidad
5
-
-
Venezuela
-
8
1
Turkey
1
-
-
Total
79
48
7
Part III Thermal EOR
Thermal EOR Thermal methods normally are used: ¾To recover viscous and thick oil ¾41% EOR oil of all EOR process produced by thermal process. ¾Physical and chemical changes occur because heat supplied. ¾Changes occur in form of reduction in: Viscosity Specific gravity IFT The principle of all the thermal processes are same i.e. reduction of viscosity. Only pathways are different. Chemical changes involve different reaction such as cracking and dehydrogenation to produce low molecular wt compound
Contd.. ¾ The products of oxidation and combustion such as flue gases, hot water steam or vapourised lighter fraction in different thermal processes, also help in reducing the viscosity and act as artificial driving forces to mobilize oil towards producers ¾ Only in low temperature oxidation (HPAI) in light oil reservoir, viscosity reduction is less dominant compared to role of intermediate products which acts as artificial driving force increasing microscopic displacement efficiency
Thermal EOR Processes Mainly there are two types thermal EOR processes ¾ Steam Flood ¾ In-situ combustion process (HTO & LTO)
Steam Flood Process Steam flooding, CSS and SAGD are various form of steam injection process Functions:¾ Steam recovers the crude oil by heating the crude and reducing its viscosity ¾ Supplying pressure to drive oil to the producing wells ¾ Heat also distills lighter components which condenses in oil bank ahead of steam further reducing oil viscosity ¾ The hot water that condenses from steam acts as artificial drive to sweep oil toward producers ¾ Steam also lowers IFT also which detach paraffin and asphaltene from the rock surface
Criteria for Selection of Steam Flood Recommended
Range of current projects
Gravity,0API
8-25
8-27
Viscosity, cp
< 100000
10-137000
Crude Oil
Composition
Light ends for steam distillation will help
Reservoir > 40
Oil saturation, %PV Type of Formation
Sandstone with high porosity and permeability
Net thickness, ft Average permeability, md Depth, ft Temperature,0F
35-90
>10 ft > 200 md 300-500 Not critical
63-10000 md 150-4500 60-2800C
Limitation of Steam Flood Process Process is applicable: ¾ In shallow and thick, high permeability sand stone and unconsolidated sand to avoid heat loss in well and adjacent formation ¾ Steam flooding is not normally used in carbonate formation and also where water sensitive clays are present ¾ Also high mobility and challenging of steam may make the process unattractive ¾ In high depth reservoir maintaining steam quality is not possible ¾ Because of very high temperature special metallurgy tubing required in producers and injectors ¾ Cost per incremental bbls is high ¾ Normally 1/3 of incremental oil is used in generation of steam
In-situ Combustion Process There are two type of in-situ combustion processes, High temperature oxidation (HTO) and low temperature oxidation (LTO) ¾ High temperature oxidation (500 – 600ºC) is for heavy oil ¾ Low temperature oxidation (150 - 300ºC) is used for light oil
High Temperature In-situ Combustion Process Functions: ¾ In situ combustion recovers crude oil by application of heat which is transferred downstream by conduction and convection process thus lowering the viscosity of crude ¾ As fire moves produced mixture of hot gases, steam and hot water which reduces viscosity of oil and displaces toward producers ¾ Light oil and steam move ahead of burning front and condense in liquid add the advantage of miscible displacement and hot water flooding
Criteria for Selection of In-situ Processes Recommended
Range of current projects
Gravity,0API
10-27
10-40
Viscosity, cp
< 5000
6-5000
Crude Oil
Composition
Some asphaltic component to aid coke formation
Reservoir > 50
Oil saturation, %PV Type of Formation
Sand or sandstone with high porosity
Net thickness, ft
>10 ft
Average permeability, md
> 50 md
Depth, ft Temperature,0F
60-94
<11500 > 1000C
85-4000 md 400-11300 100-2200C
Limitations ¾ Process will not sustain if sufficient coke is not formed. Hence not suitable for paraffinic crude ¾ Excessive deposition of coke also leads to slow advance of combustion front ¾ Oil saturation and porosity should be high to minimise the heat loss ¾ The process trends to sweep upper part of reservoir, therefore sweep efficiency in thick reservoir is less
Problem associated with ISC process ¾ Complex process which is capital intensive and difficult to control ¾ Unfavourable mobility ratio and early break through of combustion front ¾ Produced flue gases pose environmental problem ¾ Operational problem such as Severe corrosion by low pH, hot water, tough emulsion, increase sand production, deposition of carbon and pipe failure in producing wells because of high temperature
High Pressure Air Injection (HPAI) ¾ The process can be applied in tight and light oil reservoirs ¾ The oil recovery mechanism by this process is flue gas sweeping and thermal effect generated by oxidation and combustion ¾ The process is similar to ISC, but oxidation reaction pathways are different for light and heavy oil ¾ In case of light oil , combustion takes place at low temperature in the range 150 – 300ºC Advantages ¾ Source is available everywhere. ¾ Can be applied in tight reservoirs where water injectivity is low. Limitations ¾ Controlling channeling of injected air is important because early breakthrough of air reduces oil production period significant ¾ Tight reservoirs having induced fracture are not suitable for HPAI process
Case history of ISC process – Indian scenario Mar 1990
ISC Pilot
Balol
Jan 1992
Semi-commercial
Balol
Apr 1997
Phase-I (Commercial)
Santhal
Oct 1997
Phase-I (Commercial)
Balol
May 2000
Main (Commercial)
Balol
Sep 2000
Main (Commercial)
Santhal
Case History In-situ Combustion, Balol Depth
1000 m
Type
Unconsolidated sand stone
Area
17 sq km 6m
Porosity
25-30%
Permeability
1-5 d
Dip
5º
Oil saturation
70
Pressure
hydrostatic
Drive
Active aquifer
Oil viscosity
150-1500 cp
API
15
Envisaged
12
Res. Temp.
70ºC
¾ Balol pilot started : March, 1990 ¾ Pilot area: 5.5 acres ¾ Sustained combustion and productions from producers lead to conceptluation and commercial in entire Balol ¾ Considering similar characteristics, it was decided to implement in Santhal field ¾ Commercial scheme started : 1997, Balol & Santhal ¾ 64 well have been ignited in both fields ¾ A commercial scheme to be implemented to Lanwa field
Performance - Balol No. of Flowing wells Air Injectors on stream Air Injection rate, MMNm3/d (MMSCFD) Oil rate, tpd (bopd) Water Cut, %
: : : : :
1000
90 21 0.60 (20) 618 (4130) 58 100
Water Cut 80
Oil Rate
600
60 Commercialisation
400
40
200
20
0
0
W/C, %
Oil Rate, tpd
800
Thermal EOR - World Scenario (Active Projects) Country
Number of active thermal projects Hot water
Steam
Combustion
USA
3
46
7
Canada
-
13
3
China
-
17
1
Colombia
-
2
-
India
-
-
3
Indonesia
-
2
-
Trinidad
-
8
-
Venezuela
-
38
-
Total
3
126
14
Emerging technologies in EOR • • • •
Low tension water flooding Low salinity water flooding AS alternate gas flooding Microbial flooding
Possible EOR processes
Tight and light oil reservoirs • • • • •
High pressure air injection Gas injection Surfactant assisted gas flooding Surfactant assisted water flooding N2/Flue gas in deep light reservoir
Medium viscosity oil reservoirs • Polymer flooding • ASP flooding/SP Flooding Carbonate reservoir • Surfactant flooding • Surfactant alternate alkali flooding • WAG/SWAG Waxy crude reservoir • Alkali surfactant followed by Polymer • Alkali surfactant followed by Gas Before considering any process detailed laboratory investigation&pilot is requir requi
Conclusions • Right selection of EOR process and accurate knowledge about the reservoir holds key to success of EOR process • Chemical EOR, gas injection and their combination appears promising EOR process for Indian reservoir • MDT approach including geologist, geophysicist, reservoir engineer, chemist, production and drilling engineers is needed for laboratory investigations, designing, implementation and monitoring of an EOR process • Advances and better understanding in the area of various EOR techniques
Contd.. • •
•
•
Challenges are more but with sustained efforts right solutions can be arrived Meticulous monitoring of pilots and remedial measures are needed before implementation on filed scale In-house manufacture should be encouraged to develop and manufacture high performance EOR chemicals such as polymers and surfactants Expertise of domain expert help while designing and evaluation of EOR process
Case history of chemical EOR (Indian scenario) Sanand Polymer Flood Characteristics of Field • • • • • • • • • • •
Type of formation- Sandstone Thickness- 2-8 mts Porosity- 24-32 % Permeability- 1500 md Temperature- 850C Depth- 1325 mts Pressure- 100 kg/cm2 Primary recovery 14.7% Oil viscosity- 20 cp Drive – Partial edge water Salinity of formation water – 10000 ppm
Because of mobility contrast and low primary recovery, it was decided to go for polymer flooding
Contd..
• Based upon laboratory investigations pilot started in 1985 – inverted five spot • Extended pilot in 1993 – 4 injectors and 9 producers • After successful pilot test polymer flood on entire field was commercialized in 1996 • Project performance was reviewed in 2005 • Redistribution of polymer injectors and adding more under polymer flood
Observations • Frequent injectivity decline observed in polymer/chase water injectors • Preferential movement is part of reservoir • Bacterial activity • Remedial measures are taken to minimize above problems
Viraj • • • • • • • • • • • •
Formation – Sandstone Thickness – 16 mts Porosity – 25-30 % Permeability – 4 to 9 Darcy Oil saturation Temperature – 810C Pressure - 135 kg/cm2 Oil viscosity 35-50cp Salinity – 10000 ppm Acid number – 1.625 Drive mechanism – active edge water drive Average water cut – 85%
Contd..
• Based on laboratory studies ASP pilot was designed • Pilot started in 2002 (inverted five spot with 4 injectors and 9 producers) • Polymer slug completed in March 2005 and chase water was started and is continuing
Successful case studies of chemical EOR processes
Field
Region
Start
API
Oil Viscosity - cp
Adena
Colorado
2001
43
0.42
Cambridge
Wyoming
1993
20
25
Cressford
Alberta
Type
Pore Volume Chemicals
Tertiary
In progress
Secondar y
Oil Recovered % OOIP
60.40%
28.07%
Secondar y
1987
Chemicals US Cost/bbl
Chemical system
$2.45
Na2CO3
$2.42
Na2CO3
$2.25
Alkali and Polymer Only
Daquing BS
China
1996
36
3
Tertiary
82.10%
23.00%
$7.88
NaOH Biosurfactan t
Daquing NW
China
1995
36
3
Tertiary
65.00%
20.00%
$7.80
NaOH
Daquing PO
China
1994
26
11.5
Tertiary
42.00%
22.00%
$5.51
Na2CO3
Daquing XV
China
36
3
Tertiary
48.00%
17.00%
$9.26
NaOH
Daquing XF
China
36
3
Tertiary
55.00%
25.00%
$7.14
NaOH
$8.01
ASPFoam Flood following WAG
1995
Daquing Foam
China
1997
Daquing Scale Up
China
David
Alberta
1985
Driscoll Creek
Wyoming
1998
Enigma
Wyoming
2001
Etzikorn
Alberta
??
NA
NA
Tertiary
54.80%
22.32%
Reported to be Shut In Due to QC Problems with Surfactant
Curren t
23
Tertiary
$0.80
Acrylamid converted to acrylate - water cut lowered 24
43
Secondar y
In progress
In progress - Information not released
$2.49
Na2CO3
Contd.. Oil Field Gudong
Region China
Start
API
1992
OilViscosity cp
17.4
Type
41.3
Tertiary
Pore Volume Chemical s
recove red % OOIP
55.00%
26.51%
Chemicals US Cost/ bbl
Chemical syste m
$3.92 Alkali and Poly mer Only
Isenhaur
Wyoming
1980
43.1
2.8
Seconda ry
57.70%
11.58%
$0.83
Karmay
China
1995
30.3
52.6
Tertiary
60.00%
24.00%
$4.35
Lagomar
Venezuel a
2000
24.8
14.7
Tertiary
45.00%
20.11%
$4.80
Single Well Test
Mellot Ranch
Wyoming
2000
22
23
Tertiary
$2.51
NaOH
Minas I
Indonesia
1999
Minas II
Indonesia
Curren t
$6.40
Low Acid Numb er Visco us
$2.82
NaOH
Micellar Polymer Failed when salinity of slug decreased Lignin II Surfactant - In progress - Information not released
Sho Vel Tum
Oklahom a
Bevery Hills
California
Tanner
Wyoming
2000
21
11
Secondary
West Kiehl
Wyoming
1987
24
17
Secondary
West Moorcroft
Wyoming
`
In progress
26.4
41.3
Tertiary
60.00%
16.22%
Surfactant Injectivity Test
1991
22.3
20
Secondary
In progress 26.50%
20.00%
20.68%
15.00%
$2.13
$1.46
Alkali and Poly mer Only No
White Castle
Louisiana
1987
29
2.8
Tertiary
26.90%
10.10%
$8.18
Poly mer
Major challenges in Gas EOR • Availability of required quantity of gas • Depleted reservoirs attaining miscibility is an area of concern • Mobility control is another issue • Dipping reservoirs are needed • Immiscible process results in poor recovery • Presence of lighter hydrocarbons • Cost is high
WAG Process •
• • • • • • • •
•
Combines benefits of higher microscopic displacement efficiency of gas and high macroscopic displacement efficiency of water leading to lower ROS Contact of unswept zone by segregation of gas to top and water to bottom Good in reservoir with fining upward sand Lower ROS in three phase zone due to gas trapping mechanism Reduced mobility to both water and gas in three phase zone condition due to relative permeability hysteresis Vaporization of oil due to mass transfer Water reduces the mobility of gas and gas gets higher contact time with oil WAG ratio 1:1 which can be tapered later on Process does not allow uniform distribution of water and gas, particularly due to difference in viscosity of water and gas, gravity separation of the component can occur, thereby decreasing the efficiency of the process WAG is technoeconomially heavy
Immiscible WAG Pilot •
•
•
•
Reservoir parameters – GS-11, a clastic light oil reservoir in Gandhar – Depth – 2700m – Temperature 1300C – Thickness 5-6 m – API Gravity Reasons for selecting – Favourable mobility ratio for ideal water flooding – High reservoir temperature rules out most of the chemical processes – Availability of natural gas from deeper reservoir – High miscibility process even with enriched gas – MMP – 270 kg/cm2 (methane – 70%) – MMP – 285 kg/cm2 (methane content – 83%) – Non availability of enriched gas/CO2 – WAG combined benefit of water and gas Laboratory findings – Water flooding – 66% – WAG – 75% – ROS – 12 % Details of Pilot – WAG started in 2006 as a normal 5 spot pattern – Gas injection is 100000 m3/day – Water injection is 600 m3/day
: :
137 21
Air Injection rate, MMNm3/d (MMSCFD) Oil rate, tpd (bopd) Water Cut, %
: : :
0.85 (30) 1086 (7200) 61
Qo, tpd
No. of Flowing wells Air Injectors on stream
2000
100
1600
80
1200
60
800
40
400
20
0
0
Water Cut, %
Performance - Santhal
Summary of EOR processes world wide • 2-3 % of world production • As on 1.4.2004 : 311 active projects Country
Number of active EOR projects Thermal
Gas
Chemical
Other
USA
56
83
4
-
Canada
16
32
-
-
China
18
-
18
2
Colombia
2
-
-
-
France
-
-
1
-
India
3
1
2
3
Indonesia
2
-
1
-
Libya
-
1
-
-
Mexico
-
1
-
-
Trinidad
8
5
-
-
Turkey
-
1
-
-
UAE
-
1
-
-
Venezuela
38
9
2
1
Total
143
134
28
6
Criteria for Selection of Crude oil: ¾ API ¾ Viscosity ¾ Composition
: 8 to 20 : <1,00,000 : Light ends for steam distillation will help ¾ Oil saturation, %PV : >40 ¾ Type of formation : Sand stone with high K & O ¾ Av. Permeability : > 200 ¾ Depth, ft : 300 – 500 ¾ Temp. of Res. : N.C.
Part IV Microbial EOR
Microbial Enhanced Recovery Processes ¾
¾ ¾ ¾ ¾ ¾ ¾ ¾
MEOR is family of microbial processes which involves injection of microbes & nutrients to improve oil production from the well/ reservoir It involves -- Injection of microbes/ nutrients in reservoir -- Incubation -- Growth, proliferation & generation of metabolites -- Mobilization of oil Applied mostly -- Huff-puff mode. -- Few case history are available where it has applied in water injection mode
Microbial Products and Their Action Improves:
Acids
• porosity • permeability
Gases (CO2, CH4)
• Increase pore pressure. • Oil swelling • Viscosity reduction
Solvents
• Solubilize oil
Surfactants
• Lowers interfacial tension
Polymers
• Mobility control
Microbial Vs Conventional EOR Processes ¾ Conventional EOR processes are specific for a particular reservoir and crude oil. Microbial process can be applied in varied conditions ¾ Microbial solution contains live micro organisms and can transport themselves in different directions where they are most needed ¾ Problem of adsorption of chemicals is inherent part of any conventional chemical process, which is least in microbial processes
Selection of Microbes ¾ ¾ ¾ ¾
Type of reservoir and petro-physical properties Temperature and pressure Property of crude oil and formation water Purpose for which microbes are being used
Microbial Processes Developed Microbial EOR ¾ IRSM1 & IRSM2 bacterial consortia active upto 65ºC ¾ S-2 bacterial consortium active upto 90ºC ¾ NJS7- 91 & NJS4- 96 bacterial consortia active at 91 and 96ºC ¾ Stimulation of In-Situ microbes ¾ R 2 & HS4-2 Biosystems producing biosurfactants
Bacterial Consortium S-2 (Upto 90 °C) Characteristics High Temperature Microbes : S-2 •
The consortium is THBA
•
pH Tolerance : 4 – 9
•
Cell Morphology : small cocci ,short rods & size- 0.1- 1.3 micron
•
Useful Metabolites: Volatile Fatty acids, Carbon dioxide
•
Energy Source : Molasses (3%)
•
Incubation : 21 days
•
Pathogenicity : Non-pathogenic
•
Applied : 30 wells (39 jobs)
Micro- photograph
Well Selection Criteria for Application of MEOR Parameter
Recommended Range
Type of formation
Sand stone (preferably)
Temperature
< 90°C
Pressure, Kg/cm2
< 300 Kg/cm2
Reservoir rock permeability
>50 md
°API gravity of crude oil
> 20
Viscosity of oil
< 20 cp (under reservoir conditions)
Water cut
30-90 %
pH
4-9 (preferably 6-8)
Residual oil saturation
> 25 %
Salinity as NaCl
<5 %
Field Response ¾
¾ ¾ ¾ ¾
Applied in 43 wells of 4 different fields of ONGC & 8 wells of OIL, Duliajan. Total Oil gain around 43,000 m3. Gain around 1000 m3 per well per job. Average life cycle 6-8 months. Success ratio 70%.
Performance of MEOR job in SB # 36
Ql: 14.3 W/C: 78%
Post job Ql: 19-31 W/C: 42-80% :
Q0: 3.1
Q0: 6.6-14.5
Incremental oil gain, m3
2300
Oil Rate (m3/d)
Pre job:
40
10 0
35
90
30 25
80
Well closed
70
Water Cut
20
50 40
15 10 5
60
30
MEOR job
Oil Rate
20 10
0
0
Date
Water Cut (%)
Date of MEOR job: 22.01.2004
Status of various EOR Processes ISC process Commercial • • • •
Balol Phase-I Santhal Phase-I Balol Main Santhal Main
To be commenced • Lanwa ISC project
Gas injection process Commercial • GS-12, miscible gas injection Ongoing pilots (WAG) • GS-11, Gandhar Pilot to be intiated (WAG) • GS-4 and GS-9 sand Ongoing SWAG pilot •
MHS, SH platform
Chemical EOR Commercial • Sanand polymer flood Ongoing ASP pilot • Viraj ASP pilot • Jhalora ASP pilot To be commenced • Kalol ASP pilot
Microbial System For High Temperature Reservoirs Above 90°c • NJS7-91 and NJS4-96 were isolated from formation fluids of Nandej and Sobhasan wells. •
Both the isolates are • Anaerobic Hyper thermophilic: grow at 91 & 96 °C Halophilic : grow in 7% and 4% salinity • respectively. • Non-pathogenic • Optimum incubation period : 2-3 weeks
Selection Of Consortia Based on surface tension reduction, yield stability and core flooding experiment, two consortia selected: HS4-2 & R-2 Results: Surface tension : 35 dynes Surfactant product : 1 gm/litre CMD : 80 Additional oil recovery over OIIP(%) : 19 for HS4-2 08 for R-2 IFT reduction : 0.064 dynes/m for HS4-2 0.535 dynes/m for R-2
Future Activities •
Isolation of thermophilic bacteria for profile modification.
•
Isolation and identification of bacteria for enhancing oil recovery in water flood mode.
•
Development of suitable bacteria for heavy crude.
