Alkaline Surfactant Polymer Research Articles

The effect of biosurfactant on the interfacial tension and adsorption loss of surfactant in ASP flooding

An investigation into the feasibility of using biosurfactant-rhamnolipid-fermentation liquor (RH) as a sacrificial agent was conducted in the laboratory and alkaline-surfactant-polymer (ASP)-flooding pilot test. The interfacial tensions (IFTs) between solutions containing biosurfactant or mixture of biosurfactant and alkylbenzene sulfonate (ORS) at different ratios and crude oil were studied at a constant NaOH concentration. The results show interfacial characteristics (IFT, interfacial viscosity and adsorption) of RH and significant synergic effect between RH and ORS. Adsorption isotherms of RH and ORS were determined to assess the effect of RH on reducing the adsorption of ORS on sandstone. Static adsorption experiments indicate that adsorption loss of ORS can be reduced by 25–30% when RH is mixed with ORS or pre-adsorbed on sandstone. The core-flooding tests show that the enhanced oil recovery with the formulation of ASP of 0.2 wt.% RH and 0.15 wt.% ORS (system 1) is 7% more than that with the formulation of ASP of only 0.15 wt.% ORS, and is equal to that with the formulation of ASP of 0.3 wt.% ORS. This indicates that using RH can reduce the cost of ASP flooding. The ASP-flooding pilot test was conducted with system 1 and resulted in 16.6%(OOIP) of the enhanced oil recovery in the whole test area.

ASP System Design for an Offshore Application in La Salina Field, Lake Maracaibo

SummaryLa Salina Field, on the eastern coast of Lake Maracaibo, Venezuela, was designated as a Laboratorio Integrado de Campo (Integrated Field Laboratory, or IFL) by PDVSA to evaluate the potential application of different EOR processes. One of the main goals at La Salina IFL was to evaluate the alkaline-surfactant-polymer (ASP) technology potential in an oil reservoir near the end of its waterflood life.La Salina produces a medium-gravity crude oil (25°API) from the LL-03/Phase III Miocene reservoir at 915 m (3,000 ft). The feasibility of applying the ASP technology was based on a series of experiments including fluid compatibility, chemical thermal stability, phase behavior, interfacial tension between crude oil and ASP solution, chemical retention by the porous media, and physical simulation with reservoir core samples. The laboratory design involved 23 commercial surfactants, five polymers, and two alkalis. Interfacial tension reductions in excess of 25,000-fold were observed for a variety of ASP solutions. Type II- and Type III phase behaviors were observed. Linear coreflood results indicate that high-molecular-weight, partially hydrolyzed polyacrylamide polymers can be injected into La Salina sand. Radial sandpack floods produced an average oil recovery of 45.6% original oil in place (OOIP) with water injection. Injection of 30% pore volume of ASP solution, followed by 30% pore volume of polymer drive solution, produced (on average) an additional 24.6% OOIP for an average total oil recovery of 70.2% OOIP.The design of the injection plant for La Salina is a challenging task because this will be the first offshore application of the ASP technology in the world. The initial decision for the plant design was to use an existing platform instead of a barge for the construction of facilities. As a result, critical parameters such as treatment sequence, equipment footprint, and storage space for injected and treatment chemicals were considered. Preparation and transport of a phase-stable ASP solution through the injection lines and into the reservoir are crucial. Designed chemical concentrations and physical characteristics must be maintained.

Effects of Modified Natural Mixed Carboxylates in ASP‐Flooding Systems

A series of surfactants, whose major components are natural mixed carboxylates from the heels of vegetable oil and fats such as soybean oil, vegetable oil, animal oil, and tea oil etc., was developed. An orthogonal‐test‐design method was used to screen the alkaline/ surfactant/polymer (ASP) flooding systems by measuring the transient interfacial tensions at the oil/aqueous interface, and the optimal formations were obtained. The results show that the oil recovery can be increased by 26.8% of the original oil in place (OOIP) using the core‐flood experiment. The wastewater resulting from the production of SDC (natural mixed carboxylates) also has high surface activity, especially the wastewater of SDC‐V, which was treated as SDC solution, and can increase the oil recovery ratio by 19.0% (OOIP).

Effects of alkaline/surfactant/polymer on stability of oil droplets in produced water from ASP flooding

Abstract Alkaline/surfactant/polymer (ASP) flooding technology has been used successfully in the Daqing oilfield, but the produced water is more difficult to treat than that from water flooding and polymer flooding. Simulation experiments were conducted to investigate the effects of ASP on the stability of oil droplets in the produced water. Settling experimental results showed that polymer favored oil–water separation when its concentration was less than 1000 mg l−1. Oil concentrations in the water after settling separation increased with the increase of surfactant concentration, and increased with the increase of NaOH concentration up to 200 mg l−1 and then decreased with the further increase of alkaline concentrations. The interfacial properties of oil–water were investigated to find the mechanisms for the stability of oil droplets in produced water from ASP flooding. The synergetic action of surfactant ORS-41 and NaOH was found to greatly influence the interfacial tension of oil and water. ORS-41 and polymer can increase the density of negative electrical charges on the surface of oil droplets and the interfacial elasticity of oil and water. Alkaline however can increase the density of negative electrical charges of oil droplets and the interfacial elasticity of oil and water in lower alkaline concentrations, but the effect is reversed in higher alkaline concentrations. On the other hand, the flocculating ability of the polymer also helps small oil droplets coalesce and form big ones. The flocs of oil droplets were found in produced water from ASP flooding with a microscope.

Micellar Flooding and ASP-Chemical Methods for Enhanced Oil Recovery

Abstract Chemical flooding methods hold particular attraction for recovering the "residual oil" left in the reservoir after waterflooding. This paper describes and compares the results for two promising methods, viz. micellar flooding and alkaline-surfactant-polymer (ASP) flooding processes. Both of these methods have been tested successfully in the field, notably micellar flooding. Laboratory results are described for micellar floods in consolidated sandstone cores as well as in unconsolidated sand packs, including a three-dimensional model, equipped with horizontal or vertical wells. Floods were also carried out in unconsolidated cores using combinations of an alkali, surfactant and a polymer. Individual slugs were injected sequentially in some of the experiments, while the three components were mixed and injected as a single slug in other experiments. Oil recoveries in the two cases were similar. Results for the two processes are compared and contrasted, showing that, on the basis of oil volume recovered per unit mass of the chemical used, the two processes are similar, with micellar flooding having an edge. However, on the basis of total oil recovery, micellar flooding is the superior process, with oil recoveries ranging from 50 to 80﹪ of the oil left in the porous medium after a waterflood. Practical implications of the results are discussed. Introduction Among chemical flooding methods, micellar flooding and alkaline- surfactant-polymer (ASP) flooding processes are particularly effective for recovering a large fraction of the conventional oil (25 °CDATA[API, or higher) left in the reservoir after a waterflood, which could be as much as 60﹪ of the original oil in place. Many field tests of the micellar flooding process and several of ASP have established the effectiveness of these methods for mobilizing waterflood residual oil. The present laboratory study compares and contrasts the two processes, based on tertiary floods in sand packs and Berea sandstone cores. A number of investigators have noted the use of an alkali for reducing the divalent ion content and increasing the negative charge of the rock with a view to reducing chemical loss(1,2). Surkalo(3) reported the alkaline-surfactant-polymer (ASP) process as an alternative to micellar flooding. Several field tests have also been reported. Another function of alkali, if the Acid No. of the crude oil is large enough (> 0.5 mg KOH/g crude oil) is that the alkali may react with the acid components to form a surfactant in situ. Other factors, such as gravity segregation of alkali solutions, rate of diffusional and mechanical mixing, and subsequent mixing of surfactant formed would limit the effectiveness of this mechanism. The Process Chemical flooding methods are based on improving the mobility ratio, i.e., making the mobility of the displacing flood less than or equal to the mobility of the displaced fluid, and increasing the capillary number, mainly by making the interfacial tension (IFT) between the displacing and the displaced phases small, usually by about 1,000 fold. Other effects are also present, such as formation of macro- and microemulsions, formation of precipitates, wettability changes, relative permeability shifts, etc. Macroemulsions may improve the mobility ratio through drop entrainment and entrapment. At the same time, surfactant adsorption occurs on the rock surface.

Alkaline-Surfactant-Polymer Flooding of the Cambridge Minnelusa Field

SummaryThe Cambridge Minnelusa field alkaline-surfactant-polymer (ASP) flood was an economic and technical success, with ultimate incremental oil of 1,143,000 bbl at a cost of $2.42 per barrel. This success was due to an integrated approach of the application, including: reservoir engineering and geologic studies, laboratory chemical system design, numerical simulation, facilities design, and ongoing monitoring. This paper discusses how each of these was used in the design and evaluation of the Cambridge ASP project.

What is the Criterion for Selecting Alkaline/Surfactaint/Polymer Flooding Formulation: Phase Behavior or Interfacial Tension

An experimental study on determination of alkaline, surfactant, polymer (ASP) flooding systems using natural mixed carboxylate was conducted to examine the decisive factor for ASP flooding, phase behavior or interfacial tension. The volume and color of middle phase liquid were observed, the transient interfacial tension at different salt and alkaline concentrations were measured and, finally, coreflood test in laboratory were made. The results showed the flooding system with larger volume and brown color of middle phase emulsion sometimes not to obtain better oil recovery efficiency. The primary and more important phenomenon affecting the oil recovery is a lower or ultralow minimum interfacial tension value at the crude oil/soluble phase interface.

Pilot Tests of Alkaline/Surfactant/Polymer Flooding in Daqing Oil Field

Summary After the success of polymer flooding in Daqing, two alkaline/surfactant/polymer (ASP) floods were conducted to increase oil recovery further, to study the feasibility of ASP flooding, and to provide technical and practical experience for expanding the ASP pilots. The crude oil of both pilots has a high paraffin content and low acid value. After extensive screening, an ASP system with very low surfactant concentration and wide range of ultralow interfacial tension (IFT) with any concentration change of the three components was determined for each pilot. Coreflooding and numerical simulation show more than 20% original-oil-in-place (OOIP) incremental recovery by ASP over waterflooding for both pilots. The ASP flood pilot tests are technically successful and, on the basis of preliminary evaluation, economically feasible; therefore, much larger-scale ASP-flooding field tests are planned in Daqing oil field in the near future.

Alkaline/Surfactant/Polymer Pilot Performance of the West Central Saertu, Daqing Oil Field

SummaryA tertiary pilot application of the alkaline/surfactant/polymer (ASP) process was initiated in Sept. 1994 in the west central area of Daqing oil field. The pilot pattern consists of four inverted five-spots, including four injectors, nine producers, and 2 observation wells, encompassing an area of 90 000 m2 and with a pore volume (PV) of 203 300 m3. The target layer is the Saertu II1.3 (SII1.3) sandstone, with an average porosity of 26% and permeability of 1.426 [m2. The crude-oil viscosity is 11.5 mPa • s at reservoir temperature and the connate-water salinity is 6800 mg/L. The pilot performance shows a pronounced response from ASP injection. The average pilot area oil production rate increased from 36.7 to 91.5 m3/d, while water cut decreased from 82.7% to 59.7%. For the central well Po5, which is surrounded by injection wells, the oil production rate increased from 3.7 to 27.1 m3/d, while water cut decreased from 84.0% to 45.8%. Numerical simulation results forecast that the oil recovery will be increased by 18.1% original oil in place (OOIP). Total pilot oil production as of March 1996 is 67 500 m3 of which 25 300 m3, or 18.3 % OOIP, is additional produced oil with the current oil cut of 29.7%.

Design and Application of an Alkaline-Surfactant-Polymer Recovery System for the West Kiehl Field

SUMMARY The West Kiehl Unit, Crook County, Wyoming produces from the Minnelusa Lower "B" Sand reservoir. Original oil in place (OOIP) is estimated at 238, 481 m3. Estimated ultimate primary production is 27, 028 m3 or 11% OOIP. Four enhanced oil recovery methods were considered for application in this reservoir: conventional waterflood, polymer flood, an alkaline-polymer flood, and an alkaline-surfactant-polymer (ASP) flood. Estimated ultimate recoveries are 95, 392 m3 (40% OOIP), 95, 392 m3 (40% OOIP), 95, 392 m3 (40% OOIP), and 135, 934 m3 (56% OOIP), respectively. The polymer flood is expected to deplete the field faster than a conventional waterflood without an increase in ultimate recovery, while the ASP technology is expected to extend the field life and increase ultimate recovery dramatically. The ASP process has been implemented and early performance is very good. Two purposes are being served by implementation of the West Kiehl alkaline-surfactant-polymer flood. The first is to recover additional oil not recoverable by a waterflood or a polymer flood. The second is to pilot this potentially significant enhanced oil recovery (EOR) technique for other Minnelusa reservoirs. If this method proves successful, it will represent a sizable increase in ultimate recovery with the incremental oil recovery ranging as high as 25% OOIP. This paper discusses the goal for utilizing the alkaline-surfactant-polymer technology at the West Kiehl. Further, it details the development of the West Kiehl Field project including laboratory studies, reservoir parameters, initial injection and production history, facilities design, and operations of the flood.