Dr. Ir. Dedy Kristanto, M.Sc CHEMICAL FLOODING CHEMICAL EOR HOLDS A BRIGHT FUTURE - Conventional oil RF < 33%, worldwide Much of it is recoverable by chemical methods - Chemical methods are attractive: • Burgeoning energy demand and high oil prices, most likely for the long-term • Field data proves chemical flooding is an effective way to recover residual oil • Advancements in technologies • Better understanding of failed projects • New chemical and processes open the door for new opportunities DK - 2 - THE CASE FOR CHEMICAL FLOODING Escalating energy demand, declining reserves Two trillion bbl oil remaining, mostly in depleted reservoirs or those nearing depletion Infill drilling often meets the well spacing required Fewer candidate reservoirs for CO2 and miscible Opportunities exist under current economic conditions Improved technical knowledge, better risk assessment and implementation techniques DK - 3 - 7 3 3 0.9 0.3 0.2 Germany France 0.6 Romania 140 Denmark 4 Dubai 0 4 UK 6 India 160 Oman Norway 9 Brazil 12 10 10 Canada Mexico Qatar 20 China Nigeria Libya 40 Russia 60 Venezuela Abu Dhabi 80 Kuwait 84 Iraq Iran 100 USA 180 S. Arabia Billion Bbls CHEMICAL EOR TARGET IN SELECTED COUNTRIES 173 : . . 120 100 77 63 61 51 40 26 24 DK - 4 - Chemical Floods CURRENT STATUS WORLDWIDE Indonesia Venezuela USA India France China Total Number of Projects: 27 DK .5 - . 6 - .000 B/D DK .Chemical Floods PRODUCTION WORLDWIDE France Indonesia USA China Total oil production: 300. 7 - .Alkaline .Surfactants .CHEMICAL METHODS Chemical EOR methods utilize: .Polymer .Combinations of such chemicals • ASP (Alkaline-Surfactant-Polymer) flooding • MP (Micellar-Polymer) flooding • SS (Smart / Super Surfactant) flooding DK . OBJECTIVES OF CHEMICAL FLOODING Increase the Capillary Number Nc to mobilize residual oil Decrease the Mobility Ratio M for better sweep Emulsification of oil to facilitate production DK .8 - . 9 - . both areal and cross-sectional DK . reactions with clay and brines.Chemical Flooding GENERAL LIMITATIONS Cost of chemicals Excessive chemical loss: adsorption. dilution Gravity segregation Lack of control in large well spacing Geology is unforgiving Great variation in the process mechanism. ALKALINE FLOODING Process depends on mixing of alkali and oil .Oil must have acid components Emulsification of oil. drop entrainment and entrapment occur .10 - .Effect on displacement and sweep efficiencies Polymer slugs used in some cases – Polymer alkali reactions must be accounted Complex process to design mixing zones drive water low caustic IFT slug zone residual oil water oil Alkaline Flood DK . KOH) is injected into the reservoir. DK .+ Acid hydrocarbon components Surfactants In-situ generated surfactants reduce interfacial tension and hence lowering Sor. Help form emulsions near the displacement front. NaOH KOH Na+ + OHK+ + OH- OH.CHARACTERISTICS OF ALKALINE FLOODING A solution of inorganic alkaline substance (NaOH.11 - . May alter the wettability towards water wet. 4 30 3 5 Orcutt Hill 2 0.15 52 1.14 25-35 0.6-1.9 64 17. Basin 5 0. Oil Satn.0 30-40 6 9 Brea-Olinda 1.3 none 8 Harrisburg 9 2.2 3 7 Kern River 48 0. Oil Rec.12 - .2 0.2 4 2 Singleton 8 2. Consum. Ward Estes 15 4.2 8 4 L.2 51 2.12 50-60 2 DK .0 40 5 3 N. % PV wt% %PV mg/g rock %OIP 1 Whittier 8 0.Alkaline flooding FIELD PERFORMANCE Field Slug Size Conc.5 2 6 Van 12 0. A.42 50 0.4-11. Surfactant-Polymer Flood (SP) .Low Tension Polymer Flood (LTPF) Adsorption on rock surface Slug dissipation due to dispersion Slug dilution by water Formation of emulsions .Treatment and disposal problems drive water mixing zone surfactant slug water oil residual oil Surfactant Flood DK .SURFACTANT FLOODING Variations .13 - . More stable than cationic surfactants . Formation of emulsions . where: Surfactant + Water (Inorganic Cation)++ + (hydrocarbon sulfonate anion)-.They resist adsorption .CHARACTERISTICS OF SURFACTANT FLOODING A surface active agents which reduce interfacial tension at the oil-water interface.Easier and cheaper to manufacture DK .14 - .These are anionic compounds. Minimum interfacial tensions occurs at optimal salinity at which an optimum microemulsions is developed and the surfactant is equally soluble in water and oil. DK .15 - .CHARACTERISTICS OF SURFACTANT FLOODING Water salinity (specially divalent cations such as Ca++ and Mg++) play an important role in performance. Surfactant Flooding Surfactant Injection Water Solution From Well Injection Pump Mixing Plant Separation and Storage Facilities 4 1 Oil Zone 2 Surfactant 3 3 2 Polymer Solution Production Well 1 4 Drive Water DK .16 - . 17 - .SURFACTANT FLOOD Injector Producer DK . SURFACTANT FLOOD Injector Producer DK .18 - . SURFACTANT FLOOD Injector Producer DK .19 - . SURFACTANT FLOOD Injector Producer DK .20 - . 21 - .SURFACTANT FLOOD Injector Producer DK . 22 - .SURFACTANT FLOOD Injector Producer DK . SURFACTANT FLOOD Injector Producer DK .23 - . SURFACTANT FLOOD Injector Producer DK - 24 - SURFACTANT FLOOD Injector Producer DK - 25 - Surfactant Flooding Description Consists of injecting a slug containing water, surfactant, electrolyte (salt), usually a co-solvent (alcohol), and possibly a hydrocarbon (oil), followed by polymer-thickened water Mechanisms That Improve Recovery Efficiency Interfacial tension reduction (improves displacement sweep efficiency) Mobility control (improves volumetric sweep efficiency) DK - 26 - Surfactant Flooding Limitations Areal sweep more than 50% for waterflood is desired Relatively homogeneous formation High amounts of anhydrite, gypsum, or clays are undesirable Available systems provide optimum behavior within narrow set of conditions With commercially available surfactants, formation water chlorides should be < 20,000 ppm and divalent ions (Ca ++ and Mg++) < 500 ppm Challenges Complex and expensive Possibility of chromatographic separation of chemicals High adsorption of surfactant Interactions between surfactant and polymer Degradation of chemicals at high temperature DK - 27 - 000 feet < 225 ° F < 150.28 - .000 ppm TDS DK .Surfactant Flooding Screening Parameters Gravity Viscosity Composition Oil saturation Formation type Net thickness Average permeability Transmissibility Depth Temperature Salinity of formation brine > 25° API < 20 cp light intermediates > 20% PV sandstone > 10 feet > 20 md not critical < 8. 29 - .Surfactant flood FIELD PERFORMANCE Glenn Pool Field.0 0 0 100 W OR 10 1984 85 86 87 88 89 90 91 92 DK . Oklahoma O IL 1 . crosslinking.POLYMER FLOODING Loss to rock by adsorption. formation plugging Often applied late in waterflood mixing zone drive water polymer slug residual oil Polymer Flood water oil DK . ageing. salt reactions Loss of injectivity Lack of control of in situ advance High velocity shear (near wellbore).30 - . entrapment. Polymer Flooding Polymer Injection Solution From Well Mixing Plant Water Injection Pump 3 1 Oil Zone 2 Separation and Storage Facilities 2 Polymer Solution Production Well 1 3 Drive Water DK .31 - . DK . Some polymers are used for reducing the rock permeability due to their retention and viscoelastic properties. could be used as plugging agents for profile control. Increasing sweep efficiency. hence improve the mobility ratio. Hence.32 - .CHARACTERISTICS OF POLYMER FLOODING Polymer solutions have high viscosity. crosslinked or gelled polymer techniques may be applicable DK .Polymer Flooding Description Consists of adding water soluble polymers to water before it is injected in reservoir Mechanisms That Improve Recovery Efficiency Mobility control (improves volumetric sweep efficiency) Limitations High oil viscosities require higher polymer concentration Results normally better if polymer flood started before water-oil ratio becomes excessively high Clays increase polymer adsorption Some heterogeneity is acceptable.33 - . but avoid extensive fractures If fractures are present. 34 - . or it increases in salinity and divalent ions Xanthan gum polymers cost more. and have greater potential for wellbore plugging DK . are subject to microbial degradation.Polymer Flooding Challenges Lower injectivity than with water can adversely affect oil production rates in early stages of polymer flood Acrylamide-type polymers loose viscosity due to sheer degradation. DK . Acceptable retention level is less than 20 g/m 3 of rock. Polyacrilamides show higher retention level than biopolymer due to their ionic nature and shear thickening. Field observation indicates retention in the range of 7150 g/m3 of rock. Pore trapping is significant in low permeability rocks.35 - .POLYMER RETENTION Polymer solutions are retained mainly by adsorbtion and sometimes by pore trapping in reservoir rocks. Undesirable for polymer flood but desirable for profile control and thief zone plugging. Required viscosity is determined from maximum mobility ratio and shear rate. DK .36 - .ESTIMATING POLYMER CONCENTRATION Polymer concentrations depends on type and required solutions viscosity. ESTIMATING POLYMER CONCENTRATION DK .37 - . ESTIMATING POLYMER CONCENTRATION DK .38 - . 39 - .ESTIMATING POLYMER SLUG SIZES DK . REQUIRED POLYMER SLUG SIZES DK .40 - . Polymer Flooding Screening Parameters Gravity > 18° API Viscosity < 200 cp Composition not critical Oil saturation > 10% PV mobile oil Formation type sandstone / carbonate Net thickness not critical Average permeability > 20 md Transmissibility not critical Depth < 9.000 feet Temperature < 225 ° F DK .41 - . 42 - .Polymer Flood FIELD PERFORMANCE Sanand Field. India 125 100 650 620 EOR OIL 75 Projected 590 50 560 25 530 0 1989 500 1991 1993 1995 DK . Polymer Flood – FIELD PROJECTS Project 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 Taber Manville South Pembina Wilmington East Colinga Skull Creek South Skull Creek Newcastle Oerrel Hankensbuettel Owasco Vernon Northeast Hallsville Hamm Sage Spring Cr.1 1.2 5 8 6 4 1.5 DK . Unit A West Semlek Stewart Ranch Kummerfeld Huntington Beach North Stanley Eliasville Caddo North Burbank Flood Type Formation Polymer Rec..8 2. %OIP Secondary " " " " " " " " " " " " " " " " Tertiary Tertiary Tertiary Sandstone " " " " " " " " " Carbonate Sandstone " " " " " " Carbonate Carbonate PAA " " Biopolymer PAA " " " " " " " " " " " " " " " 2 0 0 0 8 10 23 13 7 30 13 9 1.43 - . ALKALINE-POLYMER FLOOD David Field. Alberta 1000 100 Oil Cut 100 10 10 Oil Rate 1 Waterflood Alkaline-Polymer Flood Primary 1 0.1 1969 1974 1979 1984 1989 1994 1999 2004 DK .44 - . 45 - .SAP Injected as premixed slugs or in sequence alkali Surf .ASP: ALKALINE-SURFACTANTPOLYMER FLOODING Several variations: .PAS drive water water polymer oil bank .ASP oil ASP Flood Field tests have been encouraging Successful in banking and producing residual oil Mechanisms was fully understood DK . ASP CHEMICAL CONTENTS Alkaline Type of Alkaline for ASP is Sodium Hydroxide (NaOH) and Sodium Carbonate (Na2CO3) Surfactant Type of surfactant in ASP are: 1. Biologically Produced Surfactants Polymer In ASP flooding. Petroleum Sulfonates 3. types of polymer is Hydrolyzed Polyacrylamide (HPAM) DK . Alkyl Benzene Sulfonates 2.46 - . Lignosulfonates 4. Petroleum Carboxylates 5. SCREENING CRITERIA ASP FLOODING - Preferred for sandstones reservoir - Reservoir Temperature less than 200 °F - Lower Ca++ and Mg++ contents - Formation relatively homogeneous - Oil Viscosity < 35 cp and API Gravity > 20 °API - Oil composition is light to intermediate components - Oil Saturation > 35 % PV - Average Permeability > 10 md - Reservoir Depth less than 9000 ft.47 - . DK . 48 - . China 100 Oil Rate 50 Oil Cut 20 10 1993 1994 1995 1996 DK .ASP PILOT – Daqing. 49 - .Chemical slugs are costly .MICELLAR FLOODING Utilizes microemulsion and polymer buffer slugs Miscible-type displacement Successful in banking and producing residual oil Process Limitations: .High salinity.Considerable delay in response drive water polymer .Small well spacing required . temperature and clay Micellar Flood .Emulsion production mixing zone micellar slug oil bank water oil mixing zone DK . to reduce the interfacial tension and hence lowering the residual oil saturation (Sor). Micellar slug. to precondition the reservoir and obtain optimal salinity.MICELLAR FLOODING PROCESSES Injection Well Chase Water Mobility Taper Producer Well Polymer Slug Micellar Slug Preflush Reservoir Solution Fluids Displacement Chase water. to displace injected fluids Mobility taper. for mobility control. to achieve gradual decrease in viscosity of displacing fluids. DK . Polymer slug. Preflush solution.50 - . 51 - .MICELLAR FLOODING DK . MICELLAR FLOODING DK .52 - . 53 - .MICELLAR FLOODING DK . 54 - .MICELLAR FLOODING DK . 5 1 1.%. Cum.5 2 2.5 0 0.Surfactant 10%.% OIP Oil Cut.5 Pore Volumes Injected Earlier oil breakthrough and quicker recovery in micellar DK .5 1 1.55 - . Recovery.% OIP 100 Soi 32% 60 40 Oil Cut 20 80 Alkali 5%.5 Pore Volumes Injected 2 2.ASP vs MICELLAR FLOOD Lab Results – Mitsue Oil Core Floods ASP Flood Micellar Flood 100 Slug 5% Buffer 50% 80 92% OIP Oil Cut.%.Polymer 60% Soi 38% 80% OIP 60 40 Oil Cut 20 0 0 0 0. Recovery. Cum. Micellar flood – TYPICAL PERFORMANCE Bradford Special Project No. 84 Dec. 81 Dec. 83 Dec. 8 1. 82 Dec.56 - .1 micellar injection DK .000 10 Oil Cut 1 100 Oil Rate 10 Dec. 85 0. %PV DK .57 - .Micellar floods – FIELD TESTS 100 Henry S 80 Henry E & Henry W 119-R Wilkins 60 40 Dedrick 20 0 0 2 4 6 8 10 12 14 Micellar Slug Size. 58 - .5 *49. David. 119-R (IL) 1968 Tertiary Benton (IL) Shell 1972 " Robinson.9 766 *24 68 *24 2. India 2002 " Micellar Floods Dedrick (IL) 1962 Secondary Robinson.5 40 160 113 90 407 47 200 40 80 2.4 72 *26. Wyoming 1993 " Daqing.4 766 29. China 1992 " Cambridge. China 1994 " Karamay.4 23. M1 (IL) 1977 " Bradford (PA) 1980 " Salem Unit (IL) 1981 " Louden (IL) 1977 " Louden (IL) 1980 " Chateaurenard. %OIP 252 *21 106 34.8 8.7 39 29 27 11 50 50 47 27 33 67 DK . China 1996 " Viraj. (France) 1983 " Acre Rec. Wyoming 1987 " Gudong.ASP AND MP FIELD PROJECTS ASP Floods Started Appln. Alberta 1986 Tertiary West Kiehl. 219-R (IL) 1974 " North Burbank (OK) 1976 " Robinson.. 0.High divalent cations .Provides ultra-low IFT Super Convenient .02% .Equipment maintenance DK .3%) .No water treatment is required Super Tolerant .Water treatment .59 - .Ultra-Low concentration required (0.No alkali is required .High TDS brine .Potential scale formation .Sludge disposal .SMART SURFACTANT (SS) Super Effective .High temperatures Super Savings .Surface equipment . 00 0.0010 0.000 ppm Temp.25 SS-B2550.05 0.15 0. Mg ~ 95.0000 IFT. ~ 100 C.0100 0.10 0.Interfacial TensionSMART SURFACTANT (SS) SS in High Salinity Brine TDS ~190. API Gravity ~ 35 SS in High Temperature Heavy Crude TDS ~ 250 ppm. WT% DK .0001 0.000ppm. API Gravity ~ 15 1.1000 0. m N/m 0. Ca. Temp.20 0. ~ 50 C.60 - . 61 - .SMART SURFACTANT Injector Producer DK . SMART SURFACTANT Injector Producer DK .62 - . 63 - .SMART SURFACTANT Injector Producer DK . 64 - .SMART SURFACTANT Injector Producer DK . SMART SURFACTANT Injector Producer DK .65 - . 66 - .SMART SURFACTANT Injector Producer DK . SMART SURFACTANT Injector Producer DK .67 - . SMART SURFACTANT Injector Producer DK .68 - . Oil Recovery Comparisons 35000 TDS.1% surfactant 0. 1700 Ca/Mg 0.3% smart surfactant 80 % Recovery OOIP 70 60 15 PV surfactant 50 13 PV water %OOIP 40 CUM.% 30 20 15 PV water 15 PV water 10 2 PV smart surfactant 0 0 25 50 75 PV Injected SPE 84075 DK .69 - . Recycling Surfactant Effluent Residual surfactant present in the effluent Process identifies surfactant in effluent and recycles back to reservoir Savings on surfactant costs Savings on disposal and treatment costs Recovers additional oil SPE 84075 DK .70 - . Bottom water or gas cap .71 - .Excessive clay content .Fractures Inadequate understanding of process mechanisms Unavailability of chemicals in large quantities Heavy reliance on un-scaled lab experiments DK .High water saturation .REASONS FOR FAILURE Low oil prices in the past Insufficient description of reservoir geology .Permeability heterogeneities . Model experiments .Scale-up of model results to field Greater confidence to extend lab results to field DK .SCALE-UP METHODS Require: .72 - .Knowledge of process variables or complete simulation description . RESULTS: PREDICTION vs ACTUAL Oil Recov ery.6 0.2 0.8 1 1.4 0.73 - . %OIP 60 Actual 50 40 30 Predicted 20 10 0 0 0.2 Pore Volumes Produced DK . Surfactant flooding unsuccessful . chemical loss.Often used where steam is not suitable DK .Unfavourable mobility ratio . cyclic stimulation Limited success with WAG Problems: .Alkaline flooding unsuccessful .CHEMICAL EOR AND HEAVY OIL Applicable methods: . inadequate simulation .CO2 immiscible.74 - .Lack of scaling criteria.Gravity segregation .Rock-fluid reactions. dilution . intermediates & organic acids desirable No bottom water or gas cap DK .75 - .000 ft Pressure not critical Oil saturation ≥ 45% Oil in place at process start ≥ 600 Bbl/acre-ft Thickness 20-30 ft Clay content < 5% Salinity < 20.000 ppm Hardness < 500 ppm Oil composition Light.EOR SCREENING CRITERIA FOR CHEMICAL FLOODING Most important: geology and mineralogy Oil viscosity < 35 cp Oil API gravity > 30 API Formation sand stone preferred Permeability ≥ 100 md Porosity ≥ 15% Stratification desirable Temperature < 150 F Depth < 9. The polymer concentration needs to be adjusted based on the alkali conc.10 –1 10 -2 Alkali Requirement Yes Yes Potential Alkali reaction in formation 2NaOH + Ca+2 2Na+ + Ca OH)2 Same as ASP None Same as ASP ~ 500 -1.1 – 0.000 ppm – 2.COMPARISON OF CHEMICAL FLOODING USAGE Properties ASP AP SP Surfactant Concentration 0.000 ppm No 2NaOH + Mg+2 2Na++ Mg(OH)2 Na2CO3 + Ca+2 2Na+ + Ca CO3 Na2CO3 + Mg+2 2Na+ + Mg CO3 Polymer concentration ~1. This means more polymer will be needed. In general.76 - .2% Interfacial Tension (mN/m) 10 –2 ~10 0 .1 – 0.000 ppm. DK .2% 0% 0. 1% alkali will reduce the polymer viscosity by 50%. and the brine salinity. alkali cost. shipping. etc. Same as ASP DK . More polymer is required.77 - .COMPARISON OF CHEMICAL FLOODING USAGE Properties ASP AP SP Water Treatment for higher divalent cations brine Yes Yes No Water treatment cost High High None Additional cost due Yes Yes No to the use of alkali Including water treatment. hazardous material handling. water treatment. equipment. potential scale/ emulsion/ corrosion problems. storage. AP (AlkalinePolymer) SP (Surfactant-Polymer) DK .COMPARISON OF CHEMICAL FLOODING USAGE Properties Adsorption onto Formation ASP AP SP Na2CO3 will be preferentially adsorbed due to its common ion onto the formation and reduce the polymer and the surfactant adsorption. NaOH will also be adsorbed and reduce the adsorption of the polymer and surfactant but to a lower extent Same as ASP In general. the surfactant adsorption of SP is higher than ASP due to the absence of alkali.78 - . The adsorption problem can be minimized by proper design of the surfactant structures and also the flood injection design Potential Yes Yes Minimized to none corrosion /scale problems in the pipeline and equipment Note : ASP (Alkaline-Surfactant-Polymer). 000 2.000 10.000 HydrocarbonMiscible Deep Enough for Required Pressure Nitrogen and Flue Gas Deep Enough for Required Pressure CO2 Flooding Surfactant/ Polymer Deep Enough for Required Pressure Limited by Temperature Polymer Limited by Temperature Alkaline Fire Flood Steam Drive High Consumption Preferred Zone Deep Enough for Required Pressure Normal Range (Possible) RREW-4-2-EORMethodsVG1-79 DK .Depth Limitation for Enhanced Oil Recovery Methods EOR Method 0 Depth (ft) 4.000 8.79 - .000 6. 80 - .0 Very Good Nitrogen and Flue Gas CO2 Flooding Very Good Mining and Extraction Good 100. Fractures. 1. etc.Centipoise at Reservoir Conditions EOR Method HydrocarbonMiscible 0.000 More Difficult Very Difficult Fair Fair Good May Not Be Possible (Can Be Waterflooded) Special Thermal: Shafts.000.000 More Difficult Good Alkaline 1000 More Difficult Good Polymer Steam Drive Good 100 Good Surfactant/ Polymer Fire Flood 10 Fair Not Feasible Difficult Very Difficult Good Not Feasible Not Feasible Not Feasible Good Various Techniques Possible Not Feasible No Established Limits RREW-4-2-EORMethodsVG1-80 DK .000 1.Preferred Oil Viscosity Ranges for Enhanced Oil Recovery Methods Oil Viscosity . Drainholes.1 1. 81 - .Not Critical if Uniform .1 10 HydrocarbonMiscible Alkaline Fire Flood Steam Drive 10.Permeability Guides for Enhanced Oil Recovery Methods Permeability (millidarcy) EOR Method 0.000 .High Enough For Good Injection Rates - Surfactant/ Polymer Polymer 1000 .Not Critical if Uniform Nitrogen and Flue Gas CO2 Flooding 100 Preferred Zone Possible Preferred Zone Preferred Zone Preferred Zone Preferred Zone RREW-4-2-EORMethodsVG1-81 DK . Miscible Immiscible Gas Alkaline/Surfactant/Polymer Polymer Flooding Gel Treatments In situ Combustion Steam Flooding Mining DK .82 - .Oil Gravity Guides for Enhanced Oil Recovery Methods 0 10 Oil Gravity oAPI 20 30 40 50 60 N2 & Flue Gas Hydrocarbon CO2 . Summary of Screening Criteria for IOR and EOR Methods N.C. = Not Critical *Transmissibility >20 md ft/cp **Transmissibility > 100 md ft/cp DK .83 - . Derive necessary scaling criteria .HOW TO PLAN A FLOOD ? Choose a process likely to succeed in a candidate reservoir Determine the reasons for success or failure of past projects of the process Research to “fill in the blanks” .Carry out lab and simulation studies Field based research Establish chemical supply Financial incentives essential DK .Determine process mechanisms .84 - . 85 - .HOW TO REACH SUCCESS ? Select the proper project Utilize the expertise of all involved Chemical optimization Cost efficiency Evaluate the lab and simulation results Select the best process Start the pilot project DK . evaluating and analysis Review and update the Geophysics and Geology Study previously and QC Detail Study of Reservoir Engineering Laboratory Core Analysis (Routine and SCAL) Chemical Laboratory Flooding Test Detail Study of Production Engineering Reservoir Simulation Economic Analysis Recommendations DK .DETAIL STUDY ACTIVITIES Data colecting.86 - . Production History (Dynamic Data) .Validating the Geological Model .Evaluating the Method .Fluid and Rock Properties (Laboratory Data) History Matching .Optimizing Injection Schemes DK .87 - .Geological Model (Static Data) .IMPLEMENTATION STEPS Integrated Reservoir Model .Predicting the Present Fluid Distributions Forecasting Future Performance . Oil saturations from post-flood cores ? DK .Mobility control ? .88 - .PROCESS EVALUATION .Extent of areal and vertical sweep ? .Fluid injectivity ? .Relative permeability changes ? .Compare field results with lab (numerical) predictions . Isopropanol .89 - .$25/bbl Process Efficiency: volume of oil recovered per unit volume (or mass) of chemical slug injected DK .$20/gallon .Polymer . but not in the same proportion Typical Costs: .COST OF CHEMICALS As the oil prices rise.$3/lb .$60/bbl .20/lb .60/lb .Crude oil .$0.$1. so does the cost of chemicals.Surfactant .Caustic .Micellar slug .