Download - Chemical Enhanced Oil Recovery
-
8/18/2019 Chemical Enhanced Oil Recovery
1/83
CHEMICAL ENHANCED OIRECOVERY
-
8/18/2019 Chemical Enhanced Oil Recovery
2/83
•
Surfactants to lower the interfacial tension between the oilwater or change the wettability of the rock
• Water soluble polymers to increase the viscosity of the wate
• Surfactants to generate foams or emulsion
• Polymer gels for blocking or diverting flow
• Alkaline chemicas such a sodium carbonate to react with crigenerate local surfactant and increase pH
• Combination of chemicals and methods
-
8/18/2019 Chemical Enhanced Oil Recovery
3/83
The role of surfactant:
• Lowering oil-water interfacial tension
• Altering rock wettability
• Lowering bulk-phase viscosity
• Promoting emulsification
The role of polymer:
• Decreasing mobility ratio by increasing polymer solution viscosity
The role of alkaline:
• In alkaline flooding, high-pH chemical system is injected. Alkaline and acid hydrocarbonspecies in crude oil react to generate the surfactant.
The role of TFSA:
• Altering rock wettability towards a more water-wet
• Lowering oil-water interfacial tension.
-
8/18/2019 Chemical Enhanced Oil Recovery
4/83
CHEMIC L FLOODING
-
8/18/2019 Chemical Enhanced Oil Recovery
5/83
CHEMIC L FLOODING
-
8/18/2019 Chemical Enhanced Oil Recovery
6/83
-
8/18/2019 Chemical Enhanced Oil Recovery
7/83
-
8/18/2019 Chemical Enhanced Oil Recovery
8/83
-
8/18/2019 Chemical Enhanced Oil Recovery
9/83
-
8/18/2019 Chemical Enhanced Oil Recovery
10/83
Polymer
-
8/18/2019 Chemical Enhanced Oil Recovery
11/83
Polymer flooding
-
8/18/2019 Chemical Enhanced Oil Recovery
12/83
-
8/18/2019 Chemical Enhanced Oil Recovery
13/83
-
8/18/2019 Chemical Enhanced Oil Recovery
14/83
-
8/18/2019 Chemical Enhanced Oil Recovery
15/83
-
8/18/2019 Chemical Enhanced Oil Recovery
16/83
-
8/18/2019 Chemical Enhanced Oil Recovery
17/83
-
8/18/2019 Chemical Enhanced Oil Recovery
18/83
Parameter Bio-polymers Synthetic polymers
Such as Xanthan Polyacrylamides
Made by Fermentation Hydrolysis
Charge Neutral Negatively charged
Effect of salinity Less sensitive More sensitive
Viscosity High Medium
Price Expensive Less expensive
Effect of bacteria Attacked Not attacked
Effect of shear Thinning Thickening
Polymers are made up of very large molecules and act as thickeners when dissolved in wa
result in high solution viscosity
Polymer types:
P l l i i i1000
-
8/18/2019 Chemical Enhanced Oil Recovery
19/83
Polymer solution viscositySolution viscosity affected by:
• Polymer type and Concentration
• Salinity
• Shear rate
• Visco-elastic effects
• Inaccessible pore volume (IPV)
1
10
100
0.01 0.1 1
Shear Rate, 1
ApparentViscosity,cp 1000
10000
30000
Salinity, ppm
1
10
100
1000
0.01 0.1 1
Shear Rate,
ApparentViscosity,cp
2000
1000
500
2000
1000
500
Concentrati on, ppm
0
10
20
30
40
50
60
70
80
90
100
0 500 1000 1500 2000
Polymer Concentration, ppm
Solution
Viscosity,
cp
Bio-polymer
HPAM
1% NaCl
Temp. = 25
C
Shear rate = 5 s-1
P bilit d ti d i l ti ff t
-
8/18/2019 Chemical Enhanced Oil Recovery
20/83
Permeability reduction and visco-elastic effect
All polymers exhibit shear thinning, non-Newtonian behavior in laboratory viscometers.
In porous media at very high shear rates, bio-polymers maintain this behavior while HPAM shows
behaves different than laboratory viscometers.
Viscosity of bio-polymers decrease with shear rate till
but retain original viscosity if shear rate is decreased back to
low values.
This behavior (shear thinning) is related to high molecule
elasticity short relaxation time (period required for
molecules to retain original shape after distortion).
Bio-polymers exhibit low apparent viscosity near injection
wells and, consequently; improved injectivity.
HPAM polymers exhibit long relaxation time and some permanent distortion if subjected to very
high shear rate and their apparent viscosity may increase (shear thickening).
Some permeability reduction results from injecting HPAM polymers into reservoir rocks.
0
-
8/18/2019 Chemical Enhanced Oil Recovery
21/83
Resistance factor, permeability reduction factor, and residual resistanc
the technique index of describing the retention amount of polymer a
gel in the porous media. They are denoted by RF, Rk, and RRF.
w p
pw
k
k
P
P R
1
2F after
1
3RF
w
w
k
k P P R
Experimental procedure:
1. Saturating the core by formation water, injected water flooding, recorded the pressure
2. Injected chemical flooding 4PV 5PV, recorded the pressure P2.
3. Injected subsequent water 4PV 5PV, recorded the pressure P3.
The injection rate is 0.3 mL/min, the time interval of pressure record is 30 min.
Fk Rk
k R p
w
p
w
I ibl PV
-
8/18/2019 Chemical Enhanced Oil Recovery
22/83
Inaccessible PV
• Polymer molecules are larger than water molecules
and are large relative to some pores in a porous
rock.
• Because of this, polymers do not flow through all
the pore space contacted by brine.
• The fraction of the pore space not contacted by the
polymer solution is called the inaccessible pore
volume (IPV).
• The magnitude of IPV can range from 1% to 30%,
depending on the polymer and porous medium.
P l t ti
-
8/18/2019 Chemical Enhanced Oil Recovery
23/83
Polymer retention
Polymer adsorption is the main form of retention.
Measured in laboratory using representative core and fluid samples.
Polymer adsorption (p) is a function of polymer concentration (Cpl) in the
Mathematical expression is:
pl p pl p p C bC a 1 p = polymer adsorption, mg/g or g/kgap, bp = constants depend on polymer type
Converted to represent volume of polymer solution per unit pore volume,
pl p p pl C D 1 s = rock solid density, kg/m3 = porosity, fraction
Cpl = polymer concentration in solution, g/m3
Dpl = polymer adsorption, fraction of floodable PV, usua
referred to as polymer frontal advance loss
Polymer retention
-
8/18/2019 Chemical Enhanced Oil Recovery
24/83
Polymer retention
Polymer adsorption is the main form of retention.
Measured in laboratory using representative core and fluid samples.
Polymer adsorption (p) is a function of polymer concentration (Cpl) in the
Mathematical expression is:
pl p pl p p C bC a 1 p = polymer adsorption, mg/g or g/kgap, bp = constants depend on polymer type
Converted to represent volume of polymer solution per unit pore volume,
pl p p pl C D 1 s = rock solid density, kg/m3 = porosity, fraction
Cpl = polymer concentration in solution, g/m3
Dpl = polymer adsorption, fraction of floodable PV, usua
referred to as polymer frontal advance loss
Polymer degradation
-
8/18/2019 Chemical Enhanced Oil Recovery
25/83
Polymer degradation
Temperature
Temperatures in the range 120-130C, could cause most polymer solutions to crack and lose th
Hydrolysis
Can reduce viscosity of all polymers specially at high temperature. This effect more pronounc
environment.
Oxidation
Presence of oxygen, even in very low concentrations can prompt chemical reactions that lead
Microbial
Some types of bacteria in the system can attack and break polymer molecules.
Share rate
High shear rates (in surface pipes, valves, well perforations and near injection wellbore) can b
molecules into smaller segments.
Suitable polymer
-
8/18/2019 Chemical Enhanced Oil Recovery
26/83
Suitable polymer
A suitable polymer should exhibit:
Good viscosity characteristics
High water solubility and easy mixing
Low retention in reservoir rock
Shear, temperature, chemical and biological stability
Ability to flow in the reservoir rock
Reasonable injectivity
Acceptable resistance and residual resistance:
Relatively low values are desirable for mobility control.
High values are desirable for plugging and profile control.
Selecting polymer
-
8/18/2019 Chemical Enhanced Oil Recovery
27/83
Selecting polymer
Polymer concentration required to achieve a maximum mobili
Polymer solution slug size required
Total mass of polymer required for a flood
minimum
behind
wrworo
wrw prp PF
k k
k k M
425.01 22.078.011 w p K or VF IPV pl ps H S DV
2.01log DP DP K V V H
pl psvb C V E nV -310kgmass,Polimer
http://localhost/var/www/apps/conversion/tmp/scratch_6/Examples%20Chemical%20Flooding.xlsxhttp://localhost/var/www/apps/conversion/tmp/scratch_6/Examples%20Chemical%20Flooding.xlsxhttp://localhost/var/www/apps/conversion/tmp/scratch_6/Examples%20Chemical%20Flooding.xlsxhttp://localhost/var/www/apps/conversion/tmp/scratch_6/Examples%20Chemical%20Flooding.xlsxhttp://localhost/var/www/apps/conversion/tmp/scratch_6/Examples%20Chemical%20Flooding.xlsxhttp://localhost/var/www/apps/conversion/tmp/scratch_6/Examples%20Chemical%20Flooding.xlsxhttp://localhost/var/www/apps/conversion/tmp/scratch_6/Examples%20Chemical%20Flooding.xlsxhttp://localhost/var/www/apps/conversion/tmp/scratch_6/Examples%20Chemical%20Flooding.xlsxhttp://localhost/var/www/apps/conversion/tmp/scratch_6/Examples%20Chemical%20Flooding.xlsxhttp://localhost/var/www/apps/conversion/tmp/scratch_6/Examples%20Chemical%20Flooding.xlsxhttp://localhost/var/www/apps/conversion/tmp/scratch_6/Examples%20Chemical%20Flooding.xlsxhttp://localhost/var/www/apps/conversion/tmp/scratch_6/Examples%20Chemical%20Flooding.xlsxhttp://localhost/var/www/apps/conversion/tmp/scratch_6/Examples%20Chemical%20Flooding.xlsx
-
8/18/2019 Chemical Enhanced Oil Recovery
28/83
Surfactants
-
8/18/2019 Chemical Enhanced Oil Recovery
29/83
In a system with water and oil, a surfactant will reduce the interftension between the two liquid phases, which “liberates” residuby capillary forces, i. e. a reduction of capillary pressure in the releaving it water-wet. This “liberated” oil can now be more easilyand produced.
• Many technically successful pilots have been done
• Several small commercial projects have been completed and semore are in progress
• The problems encountered with some of the old pilots are welunderstood and have been solved
• New generation surfactants will tolerate high salinity and high so there is no practical limit for high salinity reservoirs
• Sulfonates are stable to very high temperatures so good surfacavailable for both low and high temperature reservoirs
• Current high performance surfactants cost less than $2/lb of psurfactant
-
8/18/2019 Chemical Enhanced Oil Recovery
30/83
Favorable Characteristics for Surfactant Floo
• High permeability and porosity
• High remaining oil saturation (>25%)
• Light oil less than 50 cp--but recent trend is to apply to viscous o200 cp or even higher viscosity
• Short project life due to favorable combination of small well spahigh injectivity
• Onshore• Good geological continuity
• Good source of high quality water
• Reservoir temperatures less than 300 F for surfactant and less thpolymer is used for mobility control
-
8/18/2019 Chemical Enhanced Oil Recovery
31/83
SURFACTANTS CHARATERISTICS
• Surfactants or surface active agents are chemical substances that conce
surface or fluid/fluid interface when present at low concentration in a s
• Most common surfactants monomer consist of a hydrocarbon portion (
lypophile) called tail and an ionic portion (polar - hydrophile) as the hea
• Classified according to the ionic nature of the head:
Anionic: sodium dodecyl sulfate (C12H25SO4Na+). Exhibit negative charge and yield
dissolved in water.
Cationic: dodecyltrimethyl ammonium bromide (C12H25Na+Me3Br-). Exhibit positi
yield cations when dissolved in water.
Nonionic: dodecyl hexaoxyethylene glycol monoether (C12H25[OCH2CH2]6OH). Neu
ionize in water but provide characteristics similar to surfactants.
-
8/18/2019 Chemical Enhanced Oil Recovery
32/83
• Anionic surfactants preferred
• –Low adsorption at neutral to high pH on both sandstones
carbonates• –Can be tailored to a wide range of conditions
• –Widely available at low cost in special cases
• –Sulfates for low temperature applications
•
–Sulfonates for high temperature applications• –Cationicscan be used as co-surfactants
• •Non-ionic surfactants have not performed as well for EORsurfactants
-
8/18/2019 Chemical Enhanced Oil Recovery
33/83
• Anionic surfactants ionize in water into inorganic cations and hydroca
-
8/18/2019 Chemical Enhanced Oil Recovery
34/83
• Anionic surfactants ionize in water into inorganic cations and hydroca
anions.
• As the surfactant concentration increases, several of the sulfonate an
together in the form of micelles. For this reason, surfactant floods are
referred to as Micellar Floods.
Individual
monomers
Micelles
Surfactant Concen
I F T
Critical Micelle Concentra
(CMC)
-
8/18/2019 Chemical Enhanced Oil Recovery
35/83
Surfactant-water-oil phase behavior
-
8/18/2019 Chemical Enhanced Oil Recovery
36/83
p
Page 40
Daerah
2 Fasa
Daerah
1 Fasa
PlaitPoint
Brine
Surfaktan
Minyak
Brine
Mikroemulsi
Typ
Brine
Brine
Mikroemulsi
minyak
2 Fasa
Daerah
1 Fasa
Surfaktan
Minyak
2 Fasa
Daerah
3 Fasa
Type III
Daerah
2 Fasa
Daerah
1 Fasa
PlaitPoint
Brine
Surfaktan
Minyak
Minyak
Mikroemulsi
Type II-
Salinity increases
-
8/18/2019 Chemical Enhanced Oil Recovery
37/83
Surfactant Phase Behavior
• Winsor Type I Behavior
• Oil-in-water microemulsion
• Surfactant stays in the aqueous phase
• Difficult to achieve ultra-low interfacial tensions
-
8/18/2019 Chemical Enhanced Oil Recovery
38/83
• Winsor Type II Behavior
• –Water-in-oil microemulsion
• –Surfactant lost to the oil and observed as surfactant retent
• –Should be avoided in EOR
-
8/18/2019 Chemical Enhanced Oil Recovery
39/83
• Winsor Type III Behavior
• –Separate microemulsion phase
• –Bicontinuouslayers of water, dissolved hydrocarbons
• –Ultra-low interfacial tensions ~ 0.001 dynes/cm
• –Desirable for EOR
-
8/18/2019 Chemical Enhanced Oil Recovery
40/83
-
8/18/2019 Chemical Enhanced Oil Recovery
41/83
-
8/18/2019 Chemical Enhanced Oil Recovery
42/83
-
8/18/2019 Chemical Enhanced Oil Recovery
43/83
-
8/18/2019 Chemical Enhanced Oil Recovery
44/83
-
8/18/2019 Chemical Enhanced Oil Recovery
45/83
-
8/18/2019 Chemical Enhanced Oil Recovery
46/83
-
8/18/2019 Chemical Enhanced Oil Recovery
47/83
-
8/18/2019 Chemical Enhanced Oil Recovery
48/83
-
8/18/2019 Chemical Enhanced Oil Recovery
49/83
-
8/18/2019 Chemical Enhanced Oil Recovery
50/83
-
8/18/2019 Chemical Enhanced Oil Recovery
51/83
-
8/18/2019 Chemical Enhanced Oil Recovery
52/83
-
8/18/2019 Chemical Enhanced Oil Recovery
53/83
-
8/18/2019 Chemical Enhanced Oil Recovery
54/83
-
8/18/2019 Chemical Enhanced Oil Recovery
55/83
-
8/18/2019 Chemical Enhanced Oil Recovery
56/83
Optimal salinity
-
8/18/2019 Chemical Enhanced Oil Recovery
57/83
1.0E-04
1.0E-03
1.0E-02
1.0E-01
1.0E+00
I F T ( d
y n e / c m )
IFT mo
IFT mw
l um
0.0
4.0
8.0
12.0
16.0
20.0
0.2 0.6 1.0 1.4 1.8 2.2 2.6 3.0
V o / V s a t a u
V w / V s )
Vo/Vs
Vw/Vs
Kadar Garam (% Berat NaCl)
At optimal salinity:
Interfacial tensions are e
minimum
Solubilization parameter
and maximum
Displacement efficiency is maximum at optimal salin
-
8/18/2019 Chemical Enhanced Oil Recovery
58/83
sp ce e e c e cy s u op s
0
10
20
30
40
50
60
70
80
90
100
0 0.4 0.8 1.2 1.6 2
Salinity, % NaC
D
isplacementEfficiency
1.E-04
1.E-03
1.E-02
1.E-01
0 0.4 0.8 1.2 1.6 2 2.4 2.8 3.2
Salinity, % NaCl
In
terfacialTension,mN/m
Salinity
Increasing
Salinity
Decreasing
Surfactant retention
-
8/18/2019 Chemical Enhanced Oil Recovery
59/83
Surfactant anions get retained in reservoir rocks due to:
Adsorption on positively-charged surfaces
Reaction with divalent cations
Trapping of oil-continuous micro-emulsions
sl s
sl s s
C b
C a
1
Langmuir Isotherm
0
4
8
12
16
20
24
28
32
36
40
44
48
0 0.2 0.4 0.6 0.8 1 1.2 1.4 1.6 1.8 2
Equilibrium Concentration, g-mole/m3
Adsorption,microg-mole/gclay
10%Co-surfactant
6%Co-surfactant
2%Co-surfactant
No Co-surfactant
Use of co-surfactants can
reduce surfactant retent
Many studies relate surfactant retention in reservoir rocks to clay content
-
8/18/2019 Chemical Enhanced Oil Recovery
60/83
Page 44
Many studies relate surfactant retention in reservoir rocks to clay content
water salinity
Laboratory and field tests can provide reliable retention values
0
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0.8
0.9
1
1.1
0 4 8 12 16
Clay Content, % wt
Surfactan
tRetention,mg/gofRock
Lab Data
Field Data
Lab
Field d
0
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0 0.5 1 1.5 2 2.5 3 3.5
Salinity, % NaCl
Surfactan
tRetention,mg/gofRock
Effect of Phase Trapping
Many studies relate surfactant retention in reservoir rocks to clay content a
-
8/18/2019 Chemical Enhanced Oil Recovery
61/83
Page 44
Many studies relate surfactant retention in reservoir rocks to clay content a
water salinity
Laboratory and field tests can provide reliable retention values
0
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0.8
0.9
1
1.1
0 4 8 12 16 2
Clay Content, % wt
Surfactan
tRetention,mg/gofRock
Lab Data
Field Data
Lab d
Field data
0
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0 0.5 1 1.5 2 2.5 3 3.5
Salinity, % NaCl
Surfactan
tRetention,mg/gofRock
Effect of Phase Trapping
Selecting suitable surfactant
-
8/18/2019 Chemical Enhanced Oil Recovery
62/83
Possible candidate reservoirs for surfactant flood applications:
Medium to high oil gravity
Reasonably low salinity and hardness of formation water
Temperatures less than 100 C Relatively high residual oil saturation
Relatively low clay content with low cation exchange capacity
Select several surfactants based on preliminary screening
Conduct preliminary lab tests for further screening
Select 2 – 3 surfactants for detail lab tests
Find the right formulation and additives
Conduct core floods
Make final selection and design field pilot test
Selecting suitable surfactant
-
8/18/2019 Chemical Enhanced Oil Recovery
63/83
Determination of surfactant retention
Determination of residual oil saturation
Surfactant slug volume required
Mass of surfactant required
Estimating RF from SP floods
http://localhost/var/www/apps/conversion/tmp/scratch_6/Examples.xlsxhttp://localhost/var/www/apps/conversion/tmp/scratch_6/Examples.xlsxhttp://localhost/var/www/apps/conversion/tmp/scratch_6/Examples.xlsxhttp://localhost/var/www/apps/conversion/tmp/scratch_6/Examples.xlsxhttp://localhost/var/www/apps/conversion/tmp/scratch_6/Examples.xlsxhttp://localhost/var/www/apps/conversion/tmp/scratch_6/Examples.xlsxhttp://localhost/var/www/apps/conversion/tmp/scratch_6/Examples.xlsxhttp://localhost/var/www/apps/conversion/tmp/scratch_6/Examples.xlsxhttp://localhost/var/www/apps/conversion/tmp/scratch_6/Examples.xlsxhttp://localhost/var/www/apps/conversion/tmp/scratch_6/Examples.xlsxhttp://localhost/var/www/apps/conversion/tmp/scratch_6/Examples.xlsxhttp://localhost/var/www/apps/conversion/tmp/scratch_6/Examples.xlsxhttp://localhost/var/www/apps/conversion/tmp/scratch_6/Examples.xlsxhttp://localhost/var/www/apps/conversion/tmp/scratch_6/Examples.xlsxhttp://localhost/var/www/apps/conversion/tmp/scratch_6/Examples.xlsx
-
8/18/2019 Chemical Enhanced Oil Recovery
64/83
Surfactant Selection Criteria
• Minimal propensity to form liquid crystals, gels, macroemul
• Microemulsion viscosity < 10 cp
• Rapid coalescence to microemulsion
• Undesirable if greater than a few days and preferably less th
day• Slow coalescence indicates problems with gels, liquid crysta
macroemulsions
-
8/18/2019 Chemical Enhanced Oil Recovery
65/83
lkaline
WHAT IS ALKALINE FLOODING?
-
8/18/2019 Chemical Enhanced Oil Recovery
66/83
WHAT IS ALKALINE FLOODING?
It is an EOR method in which an alkaline chsuch as Sodium hydroxide,Sodium
Orthosillicate or Sodium carbonate is injec
during polymer flooding or water flooding
Operations.Alkaline flooding is also knownCaustic flooding.
HOW THIS WORKS INSIDE THE
-
8/18/2019 Chemical Enhanced Oil Recovery
67/83
HOW THIS WORKS INSIDE THE
RESERVOIR?
The alkaline chemicals reacts with certain types ooil,forming surfactants inside the reservoir
Eventually,the surfactants reduce the interfacial
tension between oil and water and trigger an
Increase in oil production.Wetting characteristics
of the reservoir also can change due to Formatio
of surfactants inside the reservoir or it can be du
to some other reasons.
The use of alkali in a chemical flood is beneficial in many ways:
1 reduces the absorption of the surfactant on the reservoir ro
-
8/18/2019 Chemical Enhanced Oil Recovery
68/83
1. reduces the absorption of the surfactant on the reservoir ro
2. alkali makes the reservoir rock more water-wet.
3. alkali is relatively inexpensive.
-Softened injection water is required in ASP i.e. very low conceof divalent cations (hardness) such as Ca +2 and Mg +2 . Othethese cations react with the alkali agent and form a precipitatehydroxides), which could plug the pores of most reservoirs.
-Higher salinity of the water phase can also be undesirable; it c
decrease the solubility of surfactant molecules in the water. In the alkali, usually caustic soda, reacts with components presenoil to form soap.
-
8/18/2019 Chemical Enhanced Oil Recovery
69/83
CONSIDERATIONS FOR USING
-
8/18/2019 Chemical Enhanced Oil Recovery
70/83
CONSIDERATIONS FOR USING…
Alkaline flooding is not recommended forcarbonate reservoirs due to the abundance
of
Calcium:The mixture between the alkaline
chemical and the calcium ions can produce
Hydroxide precipitation that may damage
the formation.
CRITERIA FOR USING…
-
8/18/2019 Chemical Enhanced Oil Recovery
71/83
CRUDE OIL
Gravity 13 – 35 API
Viscosity 20 md
Depth
-
8/18/2019 Chemical Enhanced Oil Recovery
72/83
EFFECTIVENESS OF DIFF.
CHEMICALS…
i. Sodium Orthosillicate upto 100%
ii. Sodium Carbonate upto 65%
iii.Sodium Hydroxide upto 80%
ADVANTAGES AND LATEST
-
8/18/2019 Chemical Enhanced Oil Recovery
73/83
TECHNOLOGY…
Alkaline flooding is usually more efficient if the
acid content of the reservoir oil isRelatively high.
A new modification to the process is the addition
of surfactant and polymer to the alkali,
Giving rise to an Alkaline-surfactant-polymer(ASP) EOR method.
This method has shown to be an effective,less
costly form of micellar-polymer flooding.
PROBLEMS IN USING
-
8/18/2019 Chemical Enhanced Oil Recovery
74/83
PROBLEMS IN USING…
1.Scaling and plugging in the producing
wells.
2.High caustic consumption.
-
8/18/2019 Chemical Enhanced Oil Recovery
75/83
• Mobility control is critical. According to Malcolm Pitts, 99% f
-
8/18/2019 Chemical Enhanced Oil Recovery
76/83
will fail without mobility control
• Floods can start at any time in the life of the field
•
Good engineering design is vital to success• Laboratory tests must be done with crude and reservoir roc
reservoir conditions and are essential for each reservoir con
• Oil companies are in the business of making money and areadverse so....
• Process design must be robust
• Project life must be short
• Chemicals must not be too expensive
-
8/18/2019 Chemical Enhanced Oil Recovery
77/83
-
8/18/2019 Chemical Enhanced Oil Recovery
78/83
-
8/18/2019 Chemical Enhanced Oil Recovery
79/83
-
8/18/2019 Chemical Enhanced Oil Recovery
80/83
-
8/18/2019 Chemical Enhanced Oil Recovery
81/83
-
8/18/2019 Chemical Enhanced Oil Recovery
82/83
• Don W. Green and G. Paul Willhite, 2003, Enhanced Oil Recovery, SPE Textbook Series Vol. 6,
Petroleum Engineers Inc., USA.
-
8/18/2019 Chemical Enhanced Oil Recovery
83/83
• Ezzat E. Gomaa, 2011, Enhanced Oil Recovery - Methods, Concepts, and Mechanisms, KOPUM
• L.P. Dake, 2002, Fundamentals of Reservoir Engineering, Elsevier Science B.V. Amsterdam, the
•
Larry W. Lake, 2005, Petroleum Engineering Handbook – Chemical Flooding, Society of PetrolRichardson, Texas, USA.
• Hestuti, E., Usman, Sugihardjo, 2009, “Optimasi Rancangan Injeksi Kimia ASP untuk Impleme
EOR”, Simposium Nasional IATMI 2009, Bandung, IATMI 09 – 00X.
• Zhijan, Q., Zhang, Y., Zhang, X., Dai, J., 1998, “A successful ASP Flooding Pilot in Gudong Oil Fi
SPE/DOE Improved Oil Recovery Symposium, Oklahoma, USA, SPE 39613.
• Harry L. Chang, Xingguang, S., Long, Xiao., Zhidong, G., Yuming, Y., Yuguo, X., Gang, C., KoopinJames, C. Mack, 2006, “Successful Field Pilot of In-Depth Colloidal Dispersion Gel (CDG) Tech
Daqing Oil Field”, SPE Reservoir Evaluation & Engineering (Desember 2006), pp. 664 – 673.