Chemical Flooding

Polymer, Surfactant and Alkaline Flooding.
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  CHEMICAL FLOODING  –   POLYMER, ALKALINE & SURFACTANTS 1)    POLYMER FLOODING INTRODUCTION EXTRAS TECHNICAL SCREENING GUIDES Consist of adding water soluble polymers to the water before it is injected into the reservoir. Simplest and most widely used chemical EOR  process for mobility control. High mobility ratios cause poor displacement and sweep efficiencies, and result in early water  breakthrough of injected water. By reducing the mobility of water, water breakthrough can be delayed by improving the displacement, areal and vertical sweep efficiencies, therefore more oil can be recovered at any given water cut. Polymer concentrations: low (250  –   2000mg/L) Polymer solution slug size: (15-25% of the reservoir PV) Type of polymer used: (1)   Hydrolyzed polyacrylamides (HPAM)  –   reduce water mobility by increasing viscosity. Can alter the flow path by reducing the permeability of the formation to water. (2)   Biopolymer Xanthan - reduce water mobility by increasing viscosity. Resistance Factor:    Term used to indicate the resistance to flow that is encountered by a polymer solution as compared to the flow of plain water.    If RF = 10, 10 times more difficult for the  polymer solution to flow through the system, or the water mobility is reduced 10-fold. Crude oil    Gravity: >25° API    Viscosity: <150 cp (preferably < 100)    Composition: Not critical Reservoir    Oil saturation: >10% PV mobile oil    Type of formation: SS preferred but can be used in carbonates     Net thickness: Not critical    Average permeability: >10 md (as low as 3 md in some cases)    Depth: < about 9,000 ft (see temperature)    Temperature: <200°F to minimize degradation MECHANISMS LIMITATIONS PROBLEMS Increasing the viscosity of water Decreasing the mobility of water Permeability reduction Contacting a large volume of the reservoir If oil viscosities are high, a higher polymer concentration is needed to achieve the desired mobility control. Polymer flooding outcome is better if the  project is started before water-oil ratio becomes excessively high. Clays increase polymer adsorption. For conventional polymer flooding, reservoir with excessive fractures should be avoided. Lower injectivity than with water can adversely affect oil production rate in the early stages of the polymer flood. Limited to reservoir T < 200F Xanthan gum polymers are subject to microbial degradation. Polymer adsorption onto solid surfaces or trapping within small pores. Adsorption causes the loss of polymer from solution, which can also cause the mobility control effect to be lost.   CHEMICAL FLOODING  –   POLYMER, ALKALINE & SURFACTANTS 2)    ALKALINE FLOODING INTRODUCTION ASP FLOODING TECHNICAL SCREENING GUIDES Improve oil recovery by lowering IFT between oil and water. Surfactants are generated in situ (alkaline materials react with crude oil). This technique normally only viable when the crude oil contains sufficient amount of organic acids to produce natural surfactants. Other possible mechanisms: emulsification of the oil & wettability alteration either from oil-wet to water-wet or vice versa when alkaline agent react with the reservoir rock surfaces. Alkaline solution slug size: 10-15% PV Alkaline chemical concentration  –   0.2-5% A preflush of fresh or softened water often  precedes the alkaline slug, and a drive fluid (either water or polymer-thickened water) follow the alkaline slug. Uses a combination of chemicals to lower  process costs by lowering injection cost and reducing surfactant adsorption. These ASP mixtures permit the injection of larger slugs of injectant because of the lower cost. Crude oil    Gravity: 13° to 35° API    Viscosity: <200 cp    Composition: Some organic acids required Reservoir    Oil saturation: Above waterflood residual    Type of formation: SS preferred     Net thickness: Not critical    Average permeability: >20 md    Depth: < about 9,000 ft (see temperature)    Temperature: <200°F preferred MECHANISMS LIMITATIONS PROBLEMS A reduction of IFT resulting from the produced surfactants Changing wettability from oil-wet to water-wet or vice versa Emulsification and entrainment of oil Emulsification and entrapment of oil to aid in mobility control Solubilization of rigid oil films at oil-water interfaces Best results are obtained if the alkaline material reacts with the crude oil, the oil should have an acid number of more than 0.2mg KOH / g of oil. Acid number  –   number of milligram required to neutralize oil. IFT should be less than 0.01 dyne/cm At high temperatures and in some chemical environments, excessive amounts of alkaline chemicals may be consumed by reaction with clays, minerals, or silica in the sandstone reservoir. Carbonates are usually avoided because they Scaling and plugging in the producing wells. High caustic consumption.  often contain anhydrite or gypsum, which interact adversely with the caustic chemicals. CHEMICAL FLOODING  –   POLYMER, ALKALINE & SURFACTANTS 3)    SURFACTANT (MICELLAR/POLYMER) FLOODING INTRODUCTION SURFACTANT TECHNICAL SCREENING GUIDES Surfactant / polymer flooding, also called micellar / polymer or microremulsion flooding, consists of injecting a slug that contains water, surfactant, electrolyte (salt), usually a co-solvent (alcohol), and possibly a hydrocarbon (oil). Injection processes that use special chemicals (surfactant) dissolved in the injection water that lower the IFT between oil and water. At lower IFT, oil will breakup into tiny droplets that can be drawn from the rock pores by water. The surfactant slug is followed by polymer-thickened water to push the mobilized oil-water  bank to the producing wells. Surfactant is a surface active materials. 2 parts    Polar / Water Loving (Hydrophilic)     Non-polar / Oil Loving (Oleophilic) Grouped as anionic, nonionic and cationic.    Cationic adsorb strongly on clays  –   oil wet Main function  –   to reduce IFT between oil and water. Size of the slug: 5%-15% PV for a high surfactant concentration system and 15%-50% PV for low concentrations. Concentrations of the polymer often range from 500-2,000 mg/L; the volume of polymer solution injected may be 50%, more or less, depending on the process design. Crude oil    Gravity: >25° API    Viscosity: <30 cp    Composition: Light intermediates are desirable Reservoir    Oil saturation: >30% PV    Type of formation: SS preferred     Net thickness: >10 ft    Average permeability: >20 md    Depth: < about 8,000 ft (see temperature)    Temperature: <175°F MECHANISMS LIMITATIONS PROBLEMS Lowering the IFT between oil and water Solubilization of oil Emulsification of oil and water Mobility enhancement An areal sweep of more than 50% on waterflood is desired. Relatively homogeneous formation is preferred. High amounts of anhydrite, gypsum, or clays are undesirable. Complex and expensive system. Possibility of chromatographic separation of chemicals. High adsorption of surfactant. Interactions between surfactant and polymer. Degradation of chemicals at high temperature.   


Jul 23, 2017

Hamming Code

Jul 23, 2017
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