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Chemical EOR.pdf

This document discusses chemical EOR methods including surfactants and polymers. Surfactants are used to lower interfacial tension between oil and water, change rock wettability, and generate foams or emulsions. Polymers such as HPAM increase water viscosity for mobility control. Successful polymer flooding projects can recover 5-30% of original oil in place through improved sweep efficiency. Key factors for polymer flooding include reservoir continuity, remaining oil saturation, and favorable injection conditions.

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Chemical EOR
Motivations for CEOR 2 ⚫Low primary recovery with little reservoir support ⚫Low waterflood recovery  Mobility ratio is unfavorable, (M>~50)  Reservoir heterogeneity leads to premature water breakthrough  Viscous fingering 0.10 0.00 0.20 0.30 0.50 0.40 0.60 0.70 0.80 0.90 1.00 0.00 0.10 0.20 0.30 0.70 0.80 0.90 1.00 0.40 0.50 0.60 Water Saturation, Sw Fractional Flow of Water, f w Water: Mo = 54 Polymer: Mo = 0.3 Surfactant: Mo = 2
Chemical Methods of EOR 3 ⚫ Surfactants:  Lower the IFT between the oil and water  Change the wettability of the rock  Generate foams or emulsions ⚫ Polymers:  Water soluble polymers to increase the Method Reduce Mobility ratio Reduce Sor Modify Pore Structure P ++ + S+P or M+ P + ++ + A + viscosity of the water Papay, 200  Polymer gels for blocking or diverting flow ⚫ Alkaline agents:  React with crude oil to generate soap and increase pH ⚫ Combinations of chemicals and variants  ASP (Alkali-Surfactant-Polymer) flooding  MP (Micellar-Polymer) flooding  Brightwater flooding  Low Salinity water flooding 3. P=Polymer, S=Surfactant, M=Micellar, A=Alkaline
1. Polymer Flooding  krd   d D SD    Sd    M   4 Polymer-augmented waterflooding asamobilitycontrolagent is to provide better displacement andvolumetric sweepefficiencies during awaterflood Mobility of displacing fluid  krD  Mobility of displaced fluid 𝑆𝑑 𝑆𝐷
Polymer Flooding: Introduction 5 ⚫ Mature method with 40+ years of commercial applications ⚫ Polymer injection is more popular than other CEOR at a lower risk and a wider range of reservoir conditions. ⚫ The range of recovery with polymer is 5-30% of OOIP (Courtenay, France), and efficiency is in the range of 0.7- 1.75 lb/bbl of incremental oil production ⚫ Loss to rock by adsorption, entrapment, salt reactions ⚫ Loss of injectivity ⚫ High velocity shear (near wellbore), ageing, cross-linking, formation plugging mixing zone Polymer Flood drive water polymer slug water oil residual oil
Polyacrylamide Polymer 6 • Hydrolyzed polyacrylamide (HPAM) is probably the only commonly used EOR polymer, and can be used up to about 185 F depending on the brine hardness. • Molecular weights up to 30 million now available at the same cost as 8 million 30 years ago--about $1.50/lb • Quality has improved • Modified polyarcrylamides such as HPAM- AMPS co-polymers cost a little more ($1.75/lb) but have better calcium tolerance  Synthetic polymer  Linear, flexible macromolecule Molecular weight ~ 5 to 30 million Partially-Hydrolyzed Polyacrylamide  Supplied as a powder, gel or emulsion –– CH2 – C H – CH2 – C H – CH2 – C H ––– Cost-effective among available polymers C = O C = O C = O n  Polymer flooding may be limited by reservoir conditions NH2 O-Na+ NH2 Sensitive to salinity and divalent ions Shear stability/ Mechanical degradation
Hydrolyzed Polyacrylamide (HPAM) Polymer 7 Structure of Partially HPAM
Viscosity vs Salinity for HPAM 8
Xanthan Polymer 9 Xanthan gum  Bacterial fermentation product  Semi-flexible macromolecule  Molecular weight ~ 2 to 8 million  Supplied as a powder or a crude fermentation broth  Sensitive to biodegradation  Broader polymer flooding applications than PAM  High-salinity and shear tolerant  More expensive than PAM
Polymer Rheological Properties 10 Typical for Xanthan Gum Biopolymer Effects of HPAM Concentration Power Law: 𝜇 = 𝐾 𝜸 𝜸 ̇𝑛−𝟏𝟏 Newtonian Newtonian Non-Newtonian
Modeling Polymer Viscosity 11 Shear dependent polymer bulk viscosity (Meter and Bird, 1964) Low shear viscosity 0  p  w  p w    P1 1     1/ 2    Shea rate Water viscosity  0 : input parameter 1 2 P  Input parameter
viscosity(cp) Polymer Rheological Properties 12 Lab data at p (zero shear) 6 cp 0.82 % TDS 1500 ppm UTCHEM w 0.72 cp Shear Rate Viscosity Viscosity P 1.9 (sec -1) (cp) cp 0.01747 5.99929  1/2 350 0.0237 5.280 5.999066 7.000 6.000 5.000 4.000 Lab Model 3.000 2.000 1.000 0.000 0.01 0.1 1 10 100 1000 shear rate(1/sec) 0.0323 5.998766 0.0439 5.469 5.998374 0.0596 5.997859 0.0811 5.401 5.997176 0.1102 5.996279 0.1498 5.394 5.995096 0.204 5.993527 0.277 5.391 5.991479 0.376 5.988787 0.512 5.610 5.985206 0.695 5.980539 0.945 5.658 5.97437 1.285 5.966256 1.747 5.733 5.955601 2.37 5.941732 3.23 5.923 5.923282 4.39 5.899346 5.96 6.001 5.868259 8.11 5.827547 11.02 5.82036 5.775079 14.98 5.707464 20.4 5.5552 5.620472 27.7 5.511319 37.6 5.42429 5.37494 51.2 5.20488 69.5 4.9245 5.000804 94.5 4.757405 128.5 4.43484 4.47577
Polymer Rheological Properties 13 ⚫ The mechanical degradation is generated directly at the injection point ⚫ The chemical degradation happens a few hours after injection and polymer solution is then stable Viscosity cps Mechanical degradation Chemical degradation Stable fluid Time
Effect of Salinity on HPAM 14 • When salt is added to a polymer solution, the repulsive forces are screened by a double layer of electrolytes and extension is reduced. • As the electrolyte concentration increases, the extension of polymer chain decreases and the solution viscosity declines • The effect of divalent-ion concentration on relative viscosity is more pronounced than sodium-ion concentration because the divalent ions locate themselves in such a way as to screen the negative charges on the backbone more effectively
Polymer Retention 15  The amount of polymer retained must be determined by experimental measurement.  Polyacrylamides used in mobility control processes must be partially hydrolyzed to reduce adsorption to acceptable levels
Methods to Determine Polymer Retention 16 Continuous injection slug injection Willhite and Green
Polymer Retention 17  Low permeability leads to high polymer retention • excessive mechanical entrapment • higher clay content
Modeling Polymer Retention by Adsorption 18 Langmuir isotherm model: 𝐶̂ = 𝑎1𝑏1𝐶 1 + 𝑏1𝐶 𝐶̂= polymer adsorption 𝐶 = 𝑝𝑜𝑙𝑦𝑚𝑒𝑟 𝑐𝑜𝑛𝑐𝑒𝑛𝑡𝑟𝑎𝑡𝑐𝑐𝑜𝑛 𝑐𝑐𝑛 𝑠𝑜𝑙𝑢𝑡𝑐𝑐𝑜𝑛 𝑎1, 𝑏1: 𝑐𝑜𝑛𝑠𝑡𝑎𝑛𝑡 𝑑𝑒𝑡𝑒𝑟𝑚𝑐𝑐𝑛𝑒𝑑 𝑏𝑦 𝑒𝑥𝑝𝑒𝑟𝑐𝑐𝑚𝑒𝑛𝑡𝑠 In UTCHEM: Adsorbed conc. Overall conc. ˆ  ~ a4 ~ 4  C ˆ4   C4  min C4, C ~   1 b4C4  Ĉ4
• • • • Inaccessible pore volume 19 Polymer molecules > some pores The fraction of pore space not contacted by the solution is called the inaccessible PV Reduction in porosity due to inaccessible pores to large size polymer molecules Faster polymer velocity than water • About 24% of the pore space was not accessible to the polymer
Permeability reduction 20  Polymer solutions reduces water mobility  Polymer solutions reduce the effective permeability  Resistance factor is a measure of combined effect of increased viscosity and reduced permeability  Effect of permeability reduction is assumed to be irreversible
Flow Regimes of Polymer Solution 21 p p unC L   kp p   p L
Field Cases for Successful Polymer Flooding 22 ⚫ Christopher et al. SPE 17395 (1988)  Good example of quality control process ⚫ Koninget al. SPE 18092 (1988)  High viscosity oil ⚫ MaitinSPE 24118 (1992)  Incremental recovery of 8 to 22% OOIP reported  Good example of individual well responses ⚫ Takagi et al. SPE 24931 (1992)  History match of polymer flood pilot ⚫ Putzet al. SPE 28601 (1994)  Very good performance in high perm sand  Example of good data on produced polymer ⚫ Wang et al. SPE 77872 (2002) ⚫ Chang et al. SPE 89175 (2006)  World's largest polymer flood at Daqing-235 MMBbls(2004) with incremental recovery of 12% OOIP
Daqing Polymer Injection ⚫ Project description  2000+ wells now injecting polymer at Daqing  Typical slug size is 0.6 PV  Most well patterns are 5-spot  About 30-50% of injected polymer is produced.  Maximum produced polymer onc. Is approx. 2/3 of injected 23 Lessons Learned: • Higher initial water cut results in lower incremental gains in recovery (see figure to left) • The total cost of polymer flooding ($6.60/bbl inc. oil) is actually less than for waterflooding ($7.85/bbl inc. oil) due to decreased water production and increased oil production. • More heterogeneous reservoir: – larger increase in sweep efficiency – shorter response time to polymer flooding –strongest influence on recovery is connectivity of pay zones • To obtain higher recovery with polymer flooding: – lower producer WHP – stimulate producers – increase polymer concentration – increase polymer molecular weight
Favorable Characteristics for Polymer Flooding 24 ⚫ Good geological continuity ⚫ High remaining oil saturation (>Sor) ⚫ High permeability and porosity ⚫ Sufficient vertical permeability to allow polymer to induce crossflowin reservoir and good geological continuity ⚫ High polymer concentration and slug size ⚫ High injectivity due to favorable combination of high permeability, wells, or injection of parting pressure ⚫ Fresh water and/or soft water ⚫ Reservoir temperatures less than 220 F
2. Surfactants 25
Capillary Desaturation Curve 26 ⚫ Purpose is to reduce the IFT; ⚫ Limitations mainly come from high viscosity of emulsions on microemulsions and high retention as a result of adsorption on rock surface. ⚫ Variations  Surfactant-Polymer Flood (SP)  Low Tension Polymer Flood (LTPF) ⚫ Slug dissipation due to dispersion ⚫ Slug dilution by water ⚫ Formation of emulsions  Treatment and disposal problems
Surfactant Flooding 27 Inject Produce Chas e Water Taper Polymer electrolyte Mobilit y Buffer Polymer Electrolyte Chemic al Slug Surfact ant cosolvent polymer Preflush Electrolyt e Na+, C+ a+ Sacrifice chemical s Initia l res. Oil and water electrolyte  Requires small well spacing  Requires large initial investment  Large amount of chemicals  Oil production is delayed therefore low rate of return  0.1 - 0.5 PV Surf. Slug  0.1 to 4 wt% surfactant  250 to 2000 ppm Polymer  Polymer drive (250-2000 ppm polymer)  Water postflush
Surfactants 28 • A surfactant, or surface active agent, is any substance that lowers the energy barrier between two immiscible phases • A surfactant molecule consists of two parts. o Hydrophilic part (water-soluble) o Hydrophobic part (oil-soluble) Air Oil Interface Water Water • Hydrophobic portion can stick out of the • Surfactant molecules will be drawn into the oil- water (air is more hydrophobic than water interface water) • Hydrophobic portion exists in oil and Hydrophilic portion exists in water
Critical Micelle Concentration Concept 29 https://www.kibron.com/critical-micelle-concentration https://www.kruss-scientific.com/services/education-theory/glossary/critical-micelle- concentration-cmc-and-surfactant-concentration/
Micelles and Microemulsion 30 Description of Microemulsions ⚫Thermodynamically stable and swollen micellar solutions should not be confused with macroemulsions ⚫Forming stable microemulsions rapidly is cornerstone of application of surfactants for enhanced oil recovery
Surfactant Adsorption Isotherm 31 1. Region I was a region of low adsorption densities. • Monomers adsorption primarily from electrostatic forces between surfactant ions and the charged solid surface. 2. Region II, the adsorption was due to the electrostatic attraction between the ions and the charged solid surface and hemimicelles association of hydrocarbon chains. • This transition from region II to region III was marked by a decrease in the slope of the isotherm. 3. In region III the surfactant ions were probably due to the association between the hydrocarbon chains. 4. Region IV was called the plateau adsorption region. • The transition from region III to region IV usually occurs above the CMC of the surfactant.
No energy input Sheth et al., 2020, Natural Reviews Materials, 5, 214-228 32 Need energy input Kinetically stable and nonreversible Reversible
33 e.g 500 nm e.g 5 nm Hydrophobe (Oil-soluble) Hydrophile (Water-soluble) Soap Non-ionic Ethoxylates H2 H2 H3C C mC H2 H2 O C C O n H Hydrophobe (Oil-soluble) Hydrophile (Water-soluble) Hydrophobe (Oil-soluble) Hydrophile (Water-soluble) Linear Alkylbenzene Sulfonate
Surfactant Phase Behavior 34 ⚫Winsor Type I Behavior  Oil-in-water microemulsion  Surfactant stays in the aqueous phase  Difficult to achieve ultra-low IFT. ⚫Winsor Type II Behavior  Water-in-Oil Microemulsion  Surfactant lost to the oil and observed as surfactant retention  Should be avoid in EOR oil Water micelles Reverse micelles
Matching the Surfactant to the Oil 35 Winsor type III: • Surfactants with an equal attraction to the oil and water are optimum • Separate microemulsion phase • Bicontinuous layers of water, dissolved hydrocarbons • Ultra-low IFT~0.001 dynes/cm • Desirable for EOR
Phase Transition for Type I-III-II 36 Transition from Type I-III-II • Increase electrolyte • Alcohol concentration • Temperature • Surfactant tail length • EACAN • Pressure
Surfactant Types 37 ⚫Anionic surfactants preferred  Low adsorption at neutral to high pH on both sandstones and 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  Cationics can be used as co-surfactants ⚫Non-ionic surfactants have not performed as well for EOR as anionic surfactants
Surfactant Ionic Type Classification 38 Soaps Anionic surfactants preferred: Low adsorption at Sulfates Anionics Sulfonates neutral to high pH on both sandstones & Phosphates carbonates; low cost in special cases. Sulfosuccinates Ethoxylated alcohol Nonionics Ethoxylated sorbitan fatty ester Sulfoxides Surfactants Amine oxides Cationics: Can be used Cationics Amine salts as co-surfactants Quaternary ammonium Imidazoline Betaines Amphoterics Sulfobetaines Amino acid Lecithins
Surfactant Selection Criteria 39 ⚫ High solubilization ratio at optimum (ultra low IFT) ⚫ Commercially available at low cost ⚫ Feasible to tailor to specific crude oil, temperature and salinity ⚫ Highly branched hydrophobe needed for low viscosity micelles and microemulsions ⚫ Low adsorption/retention on reservoir rock ⚫ Insensitive to surfactant concentration above CMC and low CMC ⚫ Minimal propensity to form liquid crystals, gels, macroemulsions – Microemulsion viscosity < 10 cp ⚫ Rapid coalescence to microemulsion – Undesirable if greater than a few days and preferably less than one day –Slow coalescence indicates problems with gels, liquid crystals or macroemulsions
Phase Behavior Experiments 40 ⚫Phase behavior experiments  Inexpensive technique to screen surfactants  Measure solubilization parameters/IFT’s  Measure coalescence/equilibration time  Determine microemulsion viscosities ⚫ Specific surfactants can be tailored for specific oils ⚫Coalescence time: defined as the time to reach phase equilibrium; should be less than 40 hours.
IFT Depends on 41 Co-surfactant • Surfactant type(s), concentrations • Co-surfactant (co-solvent) types, concentration • Electrolyte types(s), concentration • Oil characteristics • Polymer type, concentration • Temperature
Microemulsion Phase Behavior 42  Solubilization Parameters (SP): mL of oil solubilized per gram of surfactant, increase SP for more efficient surfactant
Solubilization Parameters 43 Healy et al. expressed the amount of oil and water solubilized by a unit of surfactant in terms of solubilization parameters as follows: P  Vo  V. of Oil in ME o V V. of Surfactant in ME s P  Vw  V. of Water in ME w V V. of Surfactant in ME s Vs is the volume of surfactant and does not include co-surfactant
Salinity Impact on IFT 44 • 𝜎𝑚𝑜 decreases as salinity increase • Increasing solubilization of oil from the excess phase into the microemulsion, yielding a low-density ME. • Both 𝜎𝑚𝑜 and 𝜎𝑚𝑚𝑚are defined in the middle-phase environment. • 𝜎𝑚𝑜 = 𝜎𝑚𝑚𝑚: optimal salinity, very close to optimal salinity for phase behavior. 4.80 • Nelson model: logmo,mw  5.4 1 0.21V /V '  o,w s • Huh’s model: 𝐶ℎ𝑢ℎ 𝜎 = 𝐶ℎ𝑢ℎ 𝜎𝑜𝑚 = 𝑉 2 𝑚 𝑚 𝑚 𝑉 2 𝑜 𝑚 𝑚 Where 𝑉𝑠 𝑉𝑠 Chuh : Huh’s constant Lowest possible IFT, the highest possible SP
Oil/Microemulsion System 45
Brine/Microemulsion System 46
Oil/Microemulsion/Brine System 47
Volume Fraction Example 48 Salinity scan: Overall composition of surfactant and cosurfactant is fixed, and only salinity is a variable in x-axis.
Chun Huh’s Model & Measurement 49
Variables Affecting Phase Behavior and IFT 50 • Effect of oil type • Cosurfactant type • Temperature/Pressure • Divalent ions • Surfactant structure
Adsorption 0 1 2 3 4 5 6 7 0 5 25 30 Adsorbed Surfactant Concentration, mol/g 10 15 20 Surfactant Concentration in Microemulsion, mmol/L UTCHEM model Measured data of Shiau et al., 1994   3 3 3   3 3 C  Ĉ ~ 1 b  a3 C ~ 3  Ĉ3   ~  min C , Ĉ a3  a31  a32CSE  Where Ĉ3 = adsorbed surfactant concentration 3 C ~ = overall surfactant concentration 51  Surfactant Adsorption (Langmuir Isotherm)
Favorable Characteristics for Surfactant Flooding 52 • High permeability and porosity • High remaining oil saturation (>25%) • Light oil less than 50 cp--but recent trend is to apply to viscous oils up to 200 cp or even higher viscosity • Short project life due to favorable combination of small well spacing and/or high injectivity • Onshore • Good geological continuity • Good source of high quality water • Reservoir temperatures less than 300 F for surfactant and less than 220 F if polymer is used for mobility control
Alkaline Flooding 53 ⚫ Process depends on mixing of alkali and oil  Oil must have acid components (petroleum acids), usually low API gravity oil ⚫ Emulsification of oil, drop entrainment and entrapment occur  Effect on displacement and sweep efficiencies? ⚫ Polymer slugs used in some cases – Polymer alkali reactions must be accounted for ⚫ Complex process to design mixing zones low drive caustic IFT water water slug zone oil residual oil Alkaline Flood De Zabala et al., 1982
High pH and/or ASP Flooding 54 ⚫ Surfactant adsorption is reduced on both sandstones and carbonates at high pH ⚫ Alkali is inexpensive, so the potential for cost reduction is large ⚫ Carbonate formations are usually positively charged at neutral pH, which favors adsorption of anionic surfactants. However, when Na2CO3is present, carbonate surfaces (calcite, dolomite) become negatively charged and adsorption decreases several fold ⚫ Alkali reacts with acid in oil to form soap, but not all crude oils are reactive with alkaline chemicals ⚫ High pH also improves microemulsion phase behavior ⚫ Mobility control is critical. According to Malcolm Pitts, 99% of floods 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 rock under reservoir conditions and are essential for each reservoir condition
ASP: Alkali-Surfactant-Polymer Flooding 55 ⚫ Several variations:  ASP  SAP  PAS  Sloppy Slug FieldtestshavebeenencouragingSuccessful inbankingand producingresidual oil Mechanismsnot fullyunderstood Injected as premixed slugs or in sequence ASP Flood oil bank Surf alkali drive water polymer oil water Core length, 27.79 cm Porosity, 0.19 Permeability: 448 mD Oil viscosity: 3 cp The core was originally saturated with 3 wt% NaCl brine 0.1 PV Surfactant slug-3% surfactant (IOS C20-24), 2500 ppm polymer (AN125),1.0% Na2CO3+1.9% NaCl Polymer drive-2500 ppm polymer, 1.0% Na2CO3 +1.0% NaCl
Micellar Flooding 56 ⚫ Utilizes microemulsion and polymer buffer slugs ⚫ Miscible-type displacement ⚫ Successful in banking and producing residual oil ⚫ Process limitations:  Chemical slugs are costly  Small well spacing required  High salinity, temperature and clay  Considerable delay in response  Emulsion production mixing zone drive water micellar slug polymer water oil bank mixing zone Micellar Flood
Alkali/ASP flooding 57 • Alkali reacts with acids in crude oil to form soap and thus reduces the need for synthetic surfactant • Improves microemulsion phase behavior • Alkali increases pH and reduces surfactant adsorption • Stabilizes alkoxy sulfate surfactants at high temperature • Can be used to control salinity gradient • Sodium carbonate protects HPAM polymer • Makes it easier to satisfy aqueous stability since a hydrophilic surfactant can be used to balance soap • Can be used with co-solvent in ACP process Alkali is inexpensive and reduces overall chemical cost
Alkali/ASP flooding 58 Partitioning of acid component between H A KDHA o     w oil and aqueous phase HAw  K D  H A  o Dissociation of acid component in the presence of alkali to produce soluble anionic surfactant (A-) HAo : Concentration of acid in oil HAw : Concentration of acid in water KD : Partition coefficient of HAo HA  Ka H  A w  H  A  Ka      HAw 
Alkali Effect on Surfactant Adsorption  Surfactant adsorption is reduced on both sandstones and carbonates at high pH  Alkali is inexpensive, so the potential for cost reduction is large  Carbonate formations are usually positively charged at neutral pH, o Favors adsorption of anionic surfactants at neutral pH o When Na2CO3 is present, carbonate surfaces (calcite, dolomite) become negatively charged and adsorption decreases several fold 0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 59 4.0 0.0 0.5 1.0 1.5 2.0 Residual Surfactant Concentration (mmol/L) Adsorption Density, 10 -3 mmol/m 2 3% NaCl 5% NaCl 5% NaCl without alkali 3% NaCl with ~1% Na CO 2 3 From Hirasaki
CEOR-General Limitations & Failure Reasons 60 ⚫ Cost of chemicals  Excessive chemical loss: adsorption, reactions with clay and brines, dilution ⚫ Gravity segregation  Lack of control in large well spacing ⚫ Geology is unforgiving!  Great variation in the process mechanism, both areal and cross-sectional  Insufficient description of reservoir geology o Permeability heterogeneities o Excessive clay content o High water saturation o Bottom water or gas cap o Fractures  Inadequate understanding of process mechanisms  Unavailability of chemicals in large quantities  Heavy reliance on unscaled lab experiments
Upscaling Experimental Results 61 ⚫ Require:  Knowledge of process variables or complete mathematical description  Derivation of scaling groups  Model experiments  Scale-up of model results to field ⚫ Greater confidence to extend lab results to field

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Chemical EOR.pdf

  • 1.
  • 2.
    Motivations for CEOR 2 ⚫Lowprimary recovery with little reservoir support ⚫Low waterflood recovery  Mobility ratio is unfavorable, (M>~50)  Reservoir heterogeneity leads to premature water breakthrough  Viscous fingering 0.10 0.00 0.20 0.30 0.50 0.40 0.60 0.70 0.80 0.90 1.00 0.00 0.10 0.20 0.30 0.70 0.80 0.90 1.00 0.40 0.50 0.60 Water Saturation, Sw Fractional Flow of Water, f w Water: Mo = 54 Polymer: Mo = 0.3 Surfactant: Mo = 2
  • 3.
    Chemical Methods ofEOR 3 ⚫ Surfactants:  Lower the IFT between the oil and water  Change the wettability of the rock  Generate foams or emulsions ⚫ Polymers:  Water soluble polymers to increase the Method Reduce Mobility ratio Reduce Sor Modify Pore Structure P ++ + S+P or M+ P + ++ + A + viscosity of the water Papay, 200  Polymer gels for blocking or diverting flow ⚫ Alkaline agents:  React with crude oil to generate soap and increase pH ⚫ Combinations of chemicals and variants  ASP (Alkali-Surfactant-Polymer) flooding  MP (Micellar-Polymer) flooding  Brightwater flooding  Low Salinity water flooding 3. P=Polymer, S=Surfactant, M=Micellar, A=Alkaline
  • 4.
    1. Polymer Flooding krd   d D SD    Sd    M   4 Polymer-augmented waterflooding asamobilitycontrolagent is to provide better displacement andvolumetric sweepefficiencies during awaterflood Mobility of displacing fluid  krD  Mobility of displaced fluid 𝑆𝑑 𝑆𝐷
  • 5.
    Polymer Flooding: Introduction 5 ⚫Mature method with 40+ years of commercial applications ⚫ Polymer injection is more popular than other CEOR at a lower risk and a wider range of reservoir conditions. ⚫ The range of recovery with polymer is 5-30% of OOIP (Courtenay, France), and efficiency is in the range of 0.7- 1.75 lb/bbl of incremental oil production ⚫ Loss to rock by adsorption, entrapment, salt reactions ⚫ Loss of injectivity ⚫ High velocity shear (near wellbore), ageing, cross-linking, formation plugging mixing zone Polymer Flood drive water polymer slug water oil residual oil
  • 6.
    Polyacrylamide Polymer 6 • Hydrolyzedpolyacrylamide (HPAM) is probably the only commonly used EOR polymer, and can be used up to about 185 F depending on the brine hardness. • Molecular weights up to 30 million now available at the same cost as 8 million 30 years ago--about $1.50/lb • Quality has improved • Modified polyarcrylamides such as HPAM- AMPS co-polymers cost a little more ($1.75/lb) but have better calcium tolerance  Synthetic polymer  Linear, flexible macromolecule Molecular weight ~ 5 to 30 million Partially-Hydrolyzed Polyacrylamide  Supplied as a powder, gel or emulsion –– CH2 – C H – CH2 – C H – CH2 – C H ––– Cost-effective among available polymers C = O C = O C = O n  Polymer flooding may be limited by reservoir conditions NH2 O-Na+ NH2 Sensitive to salinity and divalent ions Shear stability/ Mechanical degradation
  • 7.
    Hydrolyzed Polyacrylamide (HPAM)Polymer 7 Structure of Partially HPAM
  • 8.
  • 9.
    Xanthan Polymer 9 Xanthan gum Bacterial fermentation product  Semi-flexible macromolecule  Molecular weight ~ 2 to 8 million  Supplied as a powder or a crude fermentation broth  Sensitive to biodegradation  Broader polymer flooding applications than PAM  High-salinity and shear tolerant  More expensive than PAM
  • 10.
    Polymer Rheological Properties 10 Typicalfor Xanthan Gum Biopolymer Effects of HPAM Concentration Power Law: 𝜇 = 𝐾 𝜸 𝜸 ̇𝑛−𝟏𝟏 Newtonian Newtonian Non-Newtonian
  • 11.
    Modeling Polymer Viscosity 11 Sheardependent polymer bulk viscosity (Meter and Bird, 1964) Low shear viscosity 0  p  w  p w    P1 1     1/ 2    Shea rate Water viscosity  0 : input parameter 1 2 P  Input parameter
  • 12.
    viscosity(cp) Polymer Rheological Properties 12 Labdata at p (zero shear) 6 cp 0.82 % TDS 1500 ppm UTCHEM w 0.72 cp Shear Rate Viscosity Viscosity P 1.9 (sec -1) (cp) cp 0.01747 5.99929  1/2 350 0.0237 5.280 5.999066 7.000 6.000 5.000 4.000 Lab Model 3.000 2.000 1.000 0.000 0.01 0.1 1 10 100 1000 shear rate(1/sec) 0.0323 5.998766 0.0439 5.469 5.998374 0.0596 5.997859 0.0811 5.401 5.997176 0.1102 5.996279 0.1498 5.394 5.995096 0.204 5.993527 0.277 5.391 5.991479 0.376 5.988787 0.512 5.610 5.985206 0.695 5.980539 0.945 5.658 5.97437 1.285 5.966256 1.747 5.733 5.955601 2.37 5.941732 3.23 5.923 5.923282 4.39 5.899346 5.96 6.001 5.868259 8.11 5.827547 11.02 5.82036 5.775079 14.98 5.707464 20.4 5.5552 5.620472 27.7 5.511319 37.6 5.42429 5.37494 51.2 5.20488 69.5 4.9245 5.000804 94.5 4.757405 128.5 4.43484 4.47577
  • 13.
    Polymer Rheological Properties 13 ⚫The mechanical degradation is generated directly at the injection point ⚫ The chemical degradation happens a few hours after injection and polymer solution is then stable Viscosity cps Mechanical degradation Chemical degradation Stable fluid Time
  • 14.
    Effect of Salinityon HPAM 14 • When salt is added to a polymer solution, the repulsive forces are screened by a double layer of electrolytes and extension is reduced. • As the electrolyte concentration increases, the extension of polymer chain decreases and the solution viscosity declines • The effect of divalent-ion concentration on relative viscosity is more pronounced than sodium-ion concentration because the divalent ions locate themselves in such a way as to screen the negative charges on the backbone more effectively
  • 15.
    Polymer Retention 15  Theamount of polymer retained must be determined by experimental measurement.  Polyacrylamides used in mobility control processes must be partially hydrolyzed to reduce adsorption to acceptable levels
  • 16.
    Methods to DeterminePolymer Retention 16 Continuous injection slug injection Willhite and Green
  • 17.
    Polymer Retention 17  Lowpermeability leads to high polymer retention • excessive mechanical entrapment • higher clay content
  • 18.
    Modeling Polymer Retentionby Adsorption 18 Langmuir isotherm model: 𝐶̂ = 𝑎1𝑏1𝐶 1 + 𝑏1𝐶 𝐶̂= polymer adsorption 𝐶 = 𝑝𝑜𝑙𝑦𝑚𝑒𝑟 𝑐𝑜𝑛𝑐𝑒𝑛𝑡𝑟𝑎𝑡𝑐𝑐𝑜𝑛 𝑐𝑐𝑛 𝑠𝑜𝑙𝑢𝑡𝑐𝑐𝑜𝑛 𝑎1, 𝑏1: 𝑐𝑜𝑛𝑠𝑡𝑎𝑛𝑡 𝑑𝑒𝑡𝑒𝑟𝑚𝑐𝑐𝑛𝑒𝑑 𝑏𝑦 𝑒𝑥𝑝𝑒𝑟𝑐𝑐𝑚𝑒𝑛𝑡𝑠 In UTCHEM: Adsorbed conc. Overall conc. ˆ  ~ a4 ~ 4  C ˆ4   C4  min C4, C ~   1 b4C4  Ĉ4
  • 19.
    • • • • Inaccessible pore volume 19 Polymermolecules > some pores The fraction of pore space not contacted by the solution is called the inaccessible PV Reduction in porosity due to inaccessible pores to large size polymer molecules Faster polymer velocity than water • About 24% of the pore space was not accessible to the polymer
  • 20.
    Permeability reduction 20  Polymersolutions reduces water mobility  Polymer solutions reduce the effective permeability  Resistance factor is a measure of combined effect of increased viscosity and reduced permeability  Effect of permeability reduction is assumed to be irreversible
  • 21.
    Flow Regimes ofPolymer Solution 21 p p unC L   kp p   p L
  • 22.
    Field Cases forSuccessful Polymer Flooding 22 ⚫ Christopher et al. SPE 17395 (1988)  Good example of quality control process ⚫ Koninget al. SPE 18092 (1988)  High viscosity oil ⚫ MaitinSPE 24118 (1992)  Incremental recovery of 8 to 22% OOIP reported  Good example of individual well responses ⚫ Takagi et al. SPE 24931 (1992)  History match of polymer flood pilot ⚫ Putzet al. SPE 28601 (1994)  Very good performance in high perm sand  Example of good data on produced polymer ⚫ Wang et al. SPE 77872 (2002) ⚫ Chang et al. SPE 89175 (2006)  World's largest polymer flood at Daqing-235 MMBbls(2004) with incremental recovery of 12% OOIP
  • 23.
    Daqing Polymer Injection ⚫Project description  2000+ wells now injecting polymer at Daqing  Typical slug size is 0.6 PV  Most well patterns are 5-spot  About 30-50% of injected polymer is produced.  Maximum produced polymer onc. Is approx. 2/3 of injected 23 Lessons Learned: • Higher initial water cut results in lower incremental gains in recovery (see figure to left) • The total cost of polymer flooding ($6.60/bbl inc. oil) is actually less than for waterflooding ($7.85/bbl inc. oil) due to decreased water production and increased oil production. • More heterogeneous reservoir: – larger increase in sweep efficiency – shorter response time to polymer flooding –strongest influence on recovery is connectivity of pay zones • To obtain higher recovery with polymer flooding: – lower producer WHP – stimulate producers – increase polymer concentration – increase polymer molecular weight
  • 24.
    Favorable Characteristics forPolymer Flooding 24 ⚫ Good geological continuity ⚫ High remaining oil saturation (>Sor) ⚫ High permeability and porosity ⚫ Sufficient vertical permeability to allow polymer to induce crossflowin reservoir and good geological continuity ⚫ High polymer concentration and slug size ⚫ High injectivity due to favorable combination of high permeability, wells, or injection of parting pressure ⚫ Fresh water and/or soft water ⚫ Reservoir temperatures less than 220 F
  • 25.
  • 26.
    Capillary Desaturation Curve 26 ⚫Purpose is to reduce the IFT; ⚫ Limitations mainly come from high viscosity of emulsions on microemulsions and high retention as a result of adsorption on rock surface. ⚫ Variations  Surfactant-Polymer Flood (SP)  Low Tension Polymer Flood (LTPF) ⚫ Slug dissipation due to dispersion ⚫ Slug dilution by water ⚫ Formation of emulsions  Treatment and disposal problems
  • 27.
    Surfactant Flooding 27 Inject Produce Chas e Water Taper Polymer electrolyte Mobilit y Buffer Polymer Electrolyte Chemic alSlug Surfact ant cosolvent polymer Preflush Electrolyt e Na+, C+ a+ Sacrifice chemical s Initia l res. Oil and water electrolyte  Requires small well spacing  Requires large initial investment  Large amount of chemicals  Oil production is delayed therefore low rate of return  0.1 - 0.5 PV Surf. Slug  0.1 to 4 wt% surfactant  250 to 2000 ppm Polymer  Polymer drive (250-2000 ppm polymer)  Water postflush
  • 28.
    Surfactants 28 • A surfactant,or surface active agent, is any substance that lowers the energy barrier between two immiscible phases • A surfactant molecule consists of two parts. o Hydrophilic part (water-soluble) o Hydrophobic part (oil-soluble) Air Oil Interface Water Water • Hydrophobic portion can stick out of the • Surfactant molecules will be drawn into the oil- water (air is more hydrophobic than water interface water) • Hydrophobic portion exists in oil and Hydrophilic portion exists in water
  • 29.
    Critical Micelle ConcentrationConcept 29 https://www.kibron.com/critical-micelle-concentration https://www.kruss-scientific.com/services/education-theory/glossary/critical-micelle- concentration-cmc-and-surfactant-concentration/
  • 30.
    Micelles and Microemulsion 30 Descriptionof Microemulsions ⚫Thermodynamically stable and swollen micellar solutions should not be confused with macroemulsions ⚫Forming stable microemulsions rapidly is cornerstone of application of surfactants for enhanced oil recovery
  • 31.
    Surfactant Adsorption Isotherm 31 1.Region I was a region of low adsorption densities. • Monomers adsorption primarily from electrostatic forces between surfactant ions and the charged solid surface. 2. Region II, the adsorption was due to the electrostatic attraction between the ions and the charged solid surface and hemimicelles association of hydrocarbon chains. • This transition from region II to region III was marked by a decrease in the slope of the isotherm. 3. In region III the surfactant ions were probably due to the association between the hydrocarbon chains. 4. Region IV was called the plateau adsorption region. • The transition from region III to region IV usually occurs above the CMC of the surfactant.
  • 32.
    No energy input Shethet al., 2020, Natural Reviews Materials, 5, 214-228 32 Need energy input Kinetically stable and nonreversible Reversible
  • 33.
    33 e.g 500 nm e.g5 nm Hydrophobe (Oil-soluble) Hydrophile (Water-soluble) Soap Non-ionic Ethoxylates H2 H2 H3C C mC H2 H2 O C C O n H Hydrophobe (Oil-soluble) Hydrophile (Water-soluble) Hydrophobe (Oil-soluble) Hydrophile (Water-soluble) Linear Alkylbenzene Sulfonate
  • 34.
    Surfactant Phase Behavior 34 ⚫WinsorType I Behavior  Oil-in-water microemulsion  Surfactant stays in the aqueous phase  Difficult to achieve ultra-low IFT. ⚫Winsor Type II Behavior  Water-in-Oil Microemulsion  Surfactant lost to the oil and observed as surfactant retention  Should be avoid in EOR oil Water micelles Reverse micelles
  • 35.
    Matching the Surfactantto the Oil 35 Winsor type III: • Surfactants with an equal attraction to the oil and water are optimum • Separate microemulsion phase • Bicontinuous layers of water, dissolved hydrocarbons • Ultra-low IFT~0.001 dynes/cm • Desirable for EOR
  • 36.
    Phase Transition forType I-III-II 36 Transition from Type I-III-II • Increase electrolyte • Alcohol concentration • Temperature • Surfactant tail length • EACAN • Pressure
  • 37.
    Surfactant Types 37 ⚫Anionic surfactantspreferred  Low adsorption at neutral to high pH on both sandstones and 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  Cationics can be used as co-surfactants ⚫Non-ionic surfactants have not performed as well for EOR as anionic surfactants
  • 38.
    Surfactant Ionic TypeClassification 38 Soaps Anionic surfactants preferred: Low adsorption at Sulfates Anionics Sulfonates neutral to high pH on both sandstones & Phosphates carbonates; low cost in special cases. Sulfosuccinates Ethoxylated alcohol Nonionics Ethoxylated sorbitan fatty ester Sulfoxides Surfactants Amine oxides Cationics: Can be used Cationics Amine salts as co-surfactants Quaternary ammonium Imidazoline Betaines Amphoterics Sulfobetaines Amino acid Lecithins
  • 39.
    Surfactant Selection Criteria 39 ⚫High solubilization ratio at optimum (ultra low IFT) ⚫ Commercially available at low cost ⚫ Feasible to tailor to specific crude oil, temperature and salinity ⚫ Highly branched hydrophobe needed for low viscosity micelles and microemulsions ⚫ Low adsorption/retention on reservoir rock ⚫ Insensitive to surfactant concentration above CMC and low CMC ⚫ Minimal propensity to form liquid crystals, gels, macroemulsions – Microemulsion viscosity < 10 cp ⚫ Rapid coalescence to microemulsion – Undesirable if greater than a few days and preferably less than one day –Slow coalescence indicates problems with gels, liquid crystals or macroemulsions
  • 40.
    Phase Behavior Experiments 40 ⚫Phasebehavior experiments  Inexpensive technique to screen surfactants  Measure solubilization parameters/IFT’s  Measure coalescence/equilibration time  Determine microemulsion viscosities ⚫ Specific surfactants can be tailored for specific oils ⚫Coalescence time: defined as the time to reach phase equilibrium; should be less than 40 hours.
  • 41.
    IFT Depends on 41 Co-surfactant •Surfactant type(s), concentrations • Co-surfactant (co-solvent) types, concentration • Electrolyte types(s), concentration • Oil characteristics • Polymer type, concentration • Temperature
  • 42.
    Microemulsion Phase Behavior 42 Solubilization Parameters (SP): mL of oil solubilized per gram of surfactant, increase SP for more efficient surfactant
  • 43.
    Solubilization Parameters 43 Healy etal. expressed the amount of oil and water solubilized by a unit of surfactant in terms of solubilization parameters as follows: P  Vo  V. of Oil in ME o V V. of Surfactant in ME s P  Vw  V. of Water in ME w V V. of Surfactant in ME s Vs is the volume of surfactant and does not include co-surfactant
  • 44.
    Salinity Impact onIFT 44 • 𝜎𝑚𝑜 decreases as salinity increase • Increasing solubilization of oil from the excess phase into the microemulsion, yielding a low-density ME. • Both 𝜎𝑚𝑜 and 𝜎𝑚𝑚𝑚are defined in the middle-phase environment. • 𝜎𝑚𝑜 = 𝜎𝑚𝑚𝑚: optimal salinity, very close to optimal salinity for phase behavior. 4.80 • Nelson model: logmo,mw  5.4 1 0.21V /V '  o,w s • Huh’s model: 𝐶ℎ𝑢ℎ 𝜎 = 𝐶ℎ𝑢ℎ 𝜎𝑜𝑚 = 𝑉 2 𝑚 𝑚 𝑚 𝑉 2 𝑜 𝑚 𝑚 Where 𝑉𝑠 𝑉𝑠 Chuh : Huh’s constant Lowest possible IFT, the highest possible SP
  • 45.
  • 46.
  • 47.
  • 48.
    Volume Fraction Example 48 Salinityscan: Overall composition of surfactant and cosurfactant is fixed, and only salinity is a variable in x-axis.
  • 49.
    Chun Huh’s Model& Measurement 49
  • 50.
    Variables Affecting PhaseBehavior and IFT 50 • Effect of oil type • Cosurfactant type • Temperature/Pressure • Divalent ions • Surfactant structure
  • 51.
    Adsorption 0 1 2 3 4 5 6 7 0 5 2530 Adsorbed Surfactant Concentration, mol/g 10 15 20 Surfactant Concentration in Microemulsion, mmol/L UTCHEM model Measured data of Shiau et al., 1994   3 3 3   3 3 C  Ĉ ~ 1 b  a3 C ~ 3  Ĉ3   ~  min C , Ĉ a3  a31  a32CSE  Where Ĉ3 = adsorbed surfactant concentration 3 C ~ = overall surfactant concentration 51  Surfactant Adsorption (Langmuir Isotherm)
  • 52.
    Favorable Characteristics forSurfactant Flooding 52 • High permeability and porosity • High remaining oil saturation (>25%) • Light oil less than 50 cp--but recent trend is to apply to viscous oils up to 200 cp or even higher viscosity • Short project life due to favorable combination of small well spacing and/or high injectivity • Onshore • Good geological continuity • Good source of high quality water • Reservoir temperatures less than 300 F for surfactant and less than 220 F if polymer is used for mobility control
  • 53.
    Alkaline Flooding 53 ⚫ Processdepends on mixing of alkali and oil  Oil must have acid components (petroleum acids), usually low API gravity oil ⚫ Emulsification of oil, drop entrainment and entrapment occur  Effect on displacement and sweep efficiencies? ⚫ Polymer slugs used in some cases – Polymer alkali reactions must be accounted for ⚫ Complex process to design mixing zones low drive caustic IFT water water slug zone oil residual oil Alkaline Flood De Zabala et al., 1982
  • 54.
    High pH and/orASP Flooding 54 ⚫ Surfactant adsorption is reduced on both sandstones and carbonates at high pH ⚫ Alkali is inexpensive, so the potential for cost reduction is large ⚫ Carbonate formations are usually positively charged at neutral pH, which favors adsorption of anionic surfactants. However, when Na2CO3is present, carbonate surfaces (calcite, dolomite) become negatively charged and adsorption decreases several fold ⚫ Alkali reacts with acid in oil to form soap, but not all crude oils are reactive with alkaline chemicals ⚫ High pH also improves microemulsion phase behavior ⚫ Mobility control is critical. According to Malcolm Pitts, 99% of floods 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 rock under reservoir conditions and are essential for each reservoir condition
  • 55.
    ASP: Alkali-Surfactant-Polymer Flooding 55 ⚫Several variations:  ASP  SAP  PAS  Sloppy Slug FieldtestshavebeenencouragingSuccessful inbankingand producingresidual oil Mechanismsnot fullyunderstood Injected as premixed slugs or in sequence ASP Flood oil bank Surf alkali drive water polymer oil water Core length, 27.79 cm Porosity, 0.19 Permeability: 448 mD Oil viscosity: 3 cp The core was originally saturated with 3 wt% NaCl brine 0.1 PV Surfactant slug-3% surfactant (IOS C20-24), 2500 ppm polymer (AN125),1.0% Na2CO3+1.9% NaCl Polymer drive-2500 ppm polymer, 1.0% Na2CO3 +1.0% NaCl
  • 56.
    Micellar Flooding 56 ⚫ Utilizesmicroemulsion and polymer buffer slugs ⚫ Miscible-type displacement ⚫ Successful in banking and producing residual oil ⚫ Process limitations:  Chemical slugs are costly  Small well spacing required  High salinity, temperature and clay  Considerable delay in response  Emulsion production mixing zone drive water micellar slug polymer water oil bank mixing zone Micellar Flood
  • 57.
    Alkali/ASP flooding 57 • Alkalireacts with acids in crude oil to form soap and thus reduces the need for synthetic surfactant • Improves microemulsion phase behavior • Alkali increases pH and reduces surfactant adsorption • Stabilizes alkoxy sulfate surfactants at high temperature • Can be used to control salinity gradient • Sodium carbonate protects HPAM polymer • Makes it easier to satisfy aqueous stability since a hydrophilic surfactant can be used to balance soap • Can be used with co-solvent in ACP process Alkali is inexpensive and reduces overall chemical cost
  • 58.
    Alkali/ASP flooding 58 Partitioning ofacid component between H A KDHA o     w oil and aqueous phase HAw  K D  H A  o Dissociation of acid component in the presence of alkali to produce soluble anionic surfactant (A-) HAo : Concentration of acid in oil HAw : Concentration of acid in water KD : Partition coefficient of HAo HA  Ka H  A w  H  A  Ka      HAw 
  • 59.
    Alkali Effect onSurfactant Adsorption  Surfactant adsorption is reduced on both sandstones and carbonates at high pH  Alkali is inexpensive, so the potential for cost reduction is large  Carbonate formations are usually positively charged at neutral pH, o Favors adsorption of anionic surfactants at neutral pH o When Na2CO3 is present, carbonate surfaces (calcite, dolomite) become negatively charged and adsorption decreases several fold 0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 59 4.0 0.0 0.5 1.0 1.5 2.0 Residual Surfactant Concentration (mmol/L) Adsorption Density, 10 -3 mmol/m 2 3% NaCl 5% NaCl 5% NaCl without alkali 3% NaCl with ~1% Na CO 2 3 From Hirasaki
  • 60.
    CEOR-General Limitations &Failure Reasons 60 ⚫ Cost of chemicals  Excessive chemical loss: adsorption, reactions with clay and brines, dilution ⚫ Gravity segregation  Lack of control in large well spacing ⚫ Geology is unforgiving!  Great variation in the process mechanism, both areal and cross-sectional  Insufficient description of reservoir geology o Permeability heterogeneities o Excessive clay content o High water saturation o Bottom water or gas cap o Fractures  Inadequate understanding of process mechanisms  Unavailability of chemicals in large quantities  Heavy reliance on unscaled lab experiments
  • 61.
    Upscaling Experimental Results 61 ⚫Require:  Knowledge of process variables or complete mathematical description  Derivation of scaling groups  Model experiments  Scale-up of model results to field ⚫ Greater confidence to extend lab results to field