Recovery from oil fields by natural drive mechanisms (e.g. solution gas drive, gas cap drive, water drive) is called Primary Recovery. When oil production declines, gas or water is injected to maintain reservoir pressure. This process is called Secondary Recovery. Statistically, after a Secondary Recovery, more than half of the oil originally in place in the reservoir still remains trapped. Therefore, Enhanced Oil Recovery (EOR) process such as thermal, chemical and gas injection etc. come into picture at tertiary stage, where, application of heat for reducing the viscosity of oil in thermal EOR, chemicals are injected to reduce the interfacial tension(surfactant and alkali etc) and control the mobility of the injected fluid(polymer) extract the remaining oil. This paper reveals an attempt to inject chemicals i.e surface active agent (surfactant) at the secondary stage instead of the reaching the tertiary stage.
Cores were flooded by screened surfactants in the laboratory at secondary as well as tertiary stage to compare the results. Core Flood Simulations were performed by implicit pressure explicit saturation (IMPES) formulation and results matched with that of the laboratory tests. Next, pilot scale simulation of this process was performed in order to check the feasibility on field level. Results showed that cumulative oil recovery when surfactants applied on secondary stage flooding was more (~5.27% in core flooding; ~7% in pilot scale) than when applied at the tertiary stage. Sensitivity analysis showed that on selection of surfactants with appropriate (lesser) critical micelle concentration (CMC) value and with greater capacity of reducing interfacial tension (IFT), percentage cumulative oil recovery at the secondary stage was further enhanced. Therefore, the analysis converges to the point that chemical flooding is beneficial for an oil field early in the production cycle if economically viable.
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After a successful water or gas injection, as much as half of the initial oil in place remains entrapped in the pores of the reservoir rock . This remaining residual oil needs a very high pressure gradient to be mobilized owing to the capillary forces needed to drive the isolated oil bubbles through the narrow neck of the porous medium . To recover this residual oil under the usually applied field pressure gradients, the interfacial tension between the oil and the displacing fluid must be either greatly reduced or completely eliminated. This can be done chemically by injecting completely or partially miscible solutions in both oil and water phases. Since these solutions are usually very expensive, slugs of these solutions are driven by water. Mobility control can be achieved by injecting a buffer zone of polymers . Displacement by surfactant solution is one of the important tertiary recovery processes by chemical solutions. In petroleum industry, this process is known by several names, micellar flooding, low tension water flooding and microemulsion flooding. The term microemulsion flooding was introduced by Healy et al. .
All investigation of the surfactant flooding has been reported concerned with displacement of residual oil after secondary processes i.e. tertiary recovery. But the sufficient studies of surfactant flooding in the secondary stage have not been conducted. The main objectives of this research were to perform core flooding tests and field level modeling to investigate oil recovery behavior under both tertiary and secondary conditions to find the optimum economical design for both processes.
Description of UTCHEM simulator The UTCHEM simulator is a sophisticated three dimensional compositional simulator. The solution scheme used is analogous to IMPES. First, the pressure equation is solved implicitly for an aqueous phase pressure using explicit dating of saturation dependent terms. Second, the conservation equations are solved explicitly for total concentrations. Liu et al. (1994) implemented a third order total variation diminishing (TVD) numerical scheme to reduce the numerical dispersion. The simulator was originally developed by Pope and Nelson in 1978 to simulate the enhanced oil recovery of oil using surfactant and polymer processes. The extension of the model including other chemical processes and a variety of geochemical reactions has been done by Bhuyan et al. in 1990, for aqueous and solid phases.
The first time, in 1927, a surfactant-based chemical enhanced oil recovery (EOR), patent was issued to Atkinson. In that patent, he proposed that surface tension between crude oil and reservoir rock can be reduced using soap or other aqueous solutions . In 1959, Holm and Bernard  proposed that surfactant adsorption in water-wet porous medium can be reduced by injecting 0.1-0.3% concentration of surfactant dissolved in a hydrocarbon solvent with a low viscosity. In situ Application of high temperature resistant surfactants to produce water continuous emulsions for improved crude recovery was incorporated by Gregoli, et al . Berger, et al. [7,3] formulated a composition of surfactants containing a weak and a strong anionic functionality group, into a concentrated surfactant blend. The concentrated surfactant blend contained an aqueous solvent such as water or brine, and a cosurfactant/solvent such as a lower molecular weight alcohol or alcohol ether.
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The important factor of low recovery at the primary and secondary stage is the interfacial tension between oil and water. Oil/water interfacial tension is usually about 25 dynes/cm and adding surfactant to water would reduce the oil/water interfacial tension to less than 10-4 dynes/cm, which leads to huge reduction of capillary pressure in the reservoir. The capillary pressure is defined as the difference between the pressure of non-wetting fluid (Pnw), which is oil and the pressure of wetting fluid (Pw), which is water .
Where; Ïƒ= interfacial tension, Î¸= contact angle, r= pore radius.
According to the equation, the capillary pressure can be positive or negative; if the system is water wets, the Pc will be negative whereas for oil wets system the Pc will be positive. The capillary pressure is usually positive and would prevent additional oil recovery, because the capillary pressure gradient is often more than the pressure gradient in the reservoir. This means that the amount of oil that may be recovered is proportional to the pressure drop applied in the porous medium and inverse proportional to capillary pressure. Raising the pressure drop in the oil reservoir is limited and must be less than the fracture pressure; therefore the reduction of the interfacial tension will lead to enhance the oil recovery. This can be achieved by Surfactant flooding. Therefore, the lowering of interfacial tension between oil and water is very important to reduce the capillary forces and to increase the oil recovery. This can be achieved by adding surfactant (surface-active agents) to water to reduce the interfacial tension between water and oil.
The literature reviewed of surfactant flooding in the previous section demonstrated the potential of the process in terms of oil recovery. The parameter that affects surfactant flooding success was found lacking. There are several issues related to surfactant that needed to be further investigated to determine the feasibility and applicability of the process. Some of those issues are: (a) appropriate time for implementation of chemicals i.e surface active agent; and (b) Sensitivity analysis of chemical parameters of surfactant as well as petro physical properties of rock.
The surfactant wettem 3083/R was used for core flooding at secondary stage as well as tertiary stage. Wettem 3083/R is the blend of non- ionic and ionic surfactant. In the effluent study the adsorption of surfactant wettem 3083/R was found to be in the range of 13.5-27.6 mg/ 100gm of the rock for native core where as 7.8-9.0 mg/ 100 gm of rock for Berea core. The spinning drop method was used to measure the Interfacial tension reduction behavior of surfactant. The interfacial tension reduction behavior of surfactant showed that the 750 ppm concentration of surfactant is the optimal concentration of surfactant; Table (1). The critical micelle concentration and molecular weight of the surfactant were 800ppm and 342 respectively.
The formation water has the salinity of NaCl 673 mg/l, with the concentration of 54 mg/l of magnesium and 24 mg/l of calcium. The composition of formation and injection water are given in Table (2), the optimum concentration of salt was decided on the basis of interfacial tension reduction study; Table (3). The results of this study showed that the optimum concentration of salt is in range of 1.5% Salt (NaCl).
Core flooding Laboratory Description and Modeling The core flood configuration is horizontal and the Surfactant slug is injected from the one end of the core. The core was used of 0.5 foot long with a diameter of about 3.8 cm and 11.346 cm2 cross sectional area. The Berea sand stone core (Core A1) was flooded with 2.2 PV of wettem 3083/R surfactant without water flooding i.e. secondary stage flooding. Where as, the second Berea sandstone core (Core A2) was flooded with 0.57 PV of water, and with 1.62 PV of same surfactant in the tertiary stage. Water followed with a Surfactant slug with an average flow rate of ~10 ml/hr. The dimensions of core for tertiary stage were same as secondary stage flooding. After that the 1D simulation was carried out for the same dimensions of core and slug sizes as used in laboratory by UTCHEM simulator for the laboratory results match purposes. The input file was created based on the core properties and physical design parameters. Fluid properties are set according to the field; Table (4). Phase behavior input parameters are obtained by running the batch file of UTCHEM. Other measured parameters such as the relative permeability, residual saturations and Corey's endpoints, and surfactant adsorption are updated in the input.
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Modeling of Sector (3D) Model In this section, we extend the modeling and simulation of surfactant flooding to the field-scale. We investigate the feasibility of the surfactant process at secondary stage for a sandstone reservoir for western onshore filed of India with a light crude oil, using vertical injectors and producers. The sector model has 14 grid blocks in the x direction, 16 grid blocks in y direction, and 10 grid blocks in the z direction. Well were arranged in the 5 spot inverted type manner. The initial oil saturation is about 0.74% in the layers. The vertical permeability in the field scale simulation is 0.2 times the horizontal permeability. All the rock and fluid, phase behavior parameters are identical to those in 1D simulation. The petro physical properties of the field have given in the Table (5). There are 4 producers and one injector in layer 8. Injection and production wells are rate constrained. The injection well rate was 5298 ft3/day, where as production well were producing by 1324.5 ft3/ day, for balanced injection and production. The reservoir is 5576 feet deep, 80oF, 30 feet thick, and has petro physical properties indicative of a water-wet rock.
For tertiary stage, the reservoir has had a long history of primary and secondary recovery. Therefore, a water flood was simulated to obtain conditions similar to the current state of the reservoir with one pore volume of water injected. This simulation generated the oil saturation and pressure distribution after secondary recovery.
Sensitivity analysis of chemical parameters A sensitivity analysis was important because a chemical project has significant risks based on financial, process, and reservoir uncertainties. Chemical flood simulations are dependent on a large number of variables used for reservoir description, fluid and rock properties and process design. Following the assessment of the base case simulation, a method of testing the sensitivity of each key process variable was generated with the intent of obtaining the optimum surfactant design and observing the effects of uncertain design parameters.
The sensitivity analysis of the some important chemical parameters such as critical micelle concentration and interfacial tension was carried out by UTCHEM simulator along with physical properties simulation such as exponents of fluid and end point relative permeabilities of water and oil. The residual saturation, end point relative permeability and exponents of oil and water has been set according to that should be satisfy the water-wet, oil wet, Table (6). All sensitivity simulations were performed by adjusting one parameter at a time and leaving the remaining parameters identical to the base case. The key parameters are surfactant interfacial tension reduction, critical micelle concentration and optimal concentration of surfactant, which strongly control the oil recovery, mobility control, and economics. Therefore, more emphasis was placed on these parameters.
Results and Discussion
Figure (1) and (2) show the relationship between cumulative oil recovery from tertiary/secondary stage and the pore volumes of liquids injected. It is clearly revealed from these figures that for a secondary surfactant flood about ~ 57% oil recovery was obtained by injecting 2.2PV, where as for a tertiary surfactant flood, by injecting of same pore volume only ~ 52% oil recovery may possible. The simulation results also matching with core flooding laboratory results.
The pilot scale (sector 3D) model results are demonstrated in figures (3) and (4). The cumulative oil recovery behavior at secondary and tertiary stage, shows that for the same ultimate oil recovery (~ 65%), the required pore volume at secondary stage is 1.4PV, whereas for the tertiary stage it is 2.2PV and this very worthful in valuating the two processes economically.
The Sensitivity analysis results provide the insight that screening of the surfactant before use is very important. Critical micelle concentration sensitivity analysis shows that the surfactant which has low CMC value is more efficient for oil displacement where as the interfacial tension analysis shows that the surfactant should capable to reduce the IFT value to at lowest level. The sensitivity analysis results have been showed in fig (5) and (6). In fig (4), oil recovery is maximum at low IFT value(67 mdynes/cm).Moreover, the conclusion of sensitivity study is that the well-screened surfactants which have the less static adsorption; more capability to reduce the interfacial tension, less CMC value can be used at secondary stage to further enhanced the oil recovery.
Summary and Conclusions
The objective of this research was to investigate the oil displacement efficiency under secondary and tertiary conditions by surfactant flooding.
Based on laboratory and simulation results
For a secondary surfactant flood, ultimate oil recovery (~ 65%) was obtained by injecting about 1.3 pore volumes of fluids, where as for a tertiary surfactant process, the same ultimate recovery was obtained by injecting about 2.2 pore volumes of fluids.
The oil-water bank is more stabilized in secondary surfactant slug process which implies a favorable mobility.
Injection of surfactant slug during the secondary stage increases the oil- water relative permeability ratio and hence improving the sweep efficiency.
Sensitivity analysis results show that the further enhancement in the oil recovery may be possible if the surfactant has low CMC value and should have the capability to reduce the interfacial tension value.
Overall, surfactant flooding at secondary stage compared well with surfactant flooding at tertiary stage, indicating that the potential of surfactant process as a feasible secondary stage method. However, more core floods under varying conditions of rock properties are required to ascertain the full potential of the process. Since alkalis are available at the less cost than the surfactants. Hence, as a continuation of this work, future core floods are planned for alkali-surfactant flooding at secondary stage