Chemical Injection

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Chemicals used in enhanced oil recovery have been water-soluble polymers, polymer gels, surfactants, alkalis, and combinations of these. Individually, these chemicals improve oil recovery over that achieved by waterflooding by increasing either

  • Volumetric sweep efficiency (Ev), or
  • Displacement efficiency (Ed).
Note that: 

•  Oil recovered at reservoir conditions
        = Areal Extent x Reservoir Thickness x Porosity x So x Ev x Ed

      Ev = Ea x Eh
      Ed = (So – Sor) / So

      Ea = Areal Sweep Efficiency
      Eh = Vertical Sweep Efficiency
      So = oil saturation at the start of the chemical flood
      Sor = residual oil saturation after the chemical flood
•  Ea and Eh depend on the system mobility ratio (M), which is defined as:
      M = mobility of the injected fluid / mobility of the reservoir oil
      mobility = relative permeability / viscosity
    The lower the mobility ratio, the higher will be the areal and vertical sweep efficiencies. A mobility ratio of approximately 
    one, or less, is considered favourable and higher than one is considered to be adverse or unfavourable.
    Ea also depends on well pattern configuration.
•  The residual oil saturation, Sor, after the chemical flood depends on the capillary number of the system. Capillary number, 
   Nc, is defined as the ratio of the viscous to the local capillary forces, one form of which is:
      Nc = u µ / σ
      u and µ are the flow velocity and viscosity of the injected fluid respectively, and σ is the interfacial tension 
      between the injected fluid and the reservoir oil

Figure 1 shows published experimental data on the mobilization and recovery of additional oil saturation (beyond waterflooding) as a function of capillary number. At higher capillary numbers (i.e. lower interfacial tension) displacement efficiency improves, as indicated by the reduction in residual oil saturation. Also noteworthy from these data is that the wettability of the reservoir is quite important.

Figure1 Chemical Injection

General Design Considerations:

  • Reservoir architecture, mineralogy, permeability, viscosity ranges, temperature, and salinity have an impact on the
  • feasibility of these processes and also on the economics.
  • The chemicals have to be formulated into a stable product that has to meet several requirements for it to be usable in 
    the field.
  • Water breakthrough to producing wells can dramatically increase fluids separation challenges. This is because the 
    properties of the additives that make them effective in aiding hydrocarbon recovery from the reservoir can exacerbate 
    oil/water emulsion tendencies.
In general, chemical injection methods are classified according to the main chemical agents used to improve oil recovery. Properly selected and implemented, they are all proven, highly effective EOR techniques.

Polymer Injection

Polymer Injection Process Description

Polymer injection is directed toward improving the volumetric sweep efficiency of a waterflood. Water-soluble polymers are added to the injection water to increase its viscosity and thereby improve (lower) the mobility ratio for displacing oil.

Figure 2 Chemical Injection

Figure 2 shows displacement fronts up until breakthrough for mobility ratios from 0.151 to 71.5 within a quarter of a five-spot pattern. Two points should be noted here:
  • The lower the mobility ratio the higher the areal sweep efficiency at breakthrough of the injected fluid.
  • For situations involving adverse mobility ratios, viscous fingers develop that causes severe bypassing of the reservoir oil by the injected fluid.

Polymer solution viscosity must therefore be carefully tailored to mitigate any tendency for the injected fluids to finger through the reservoir.

Economic considerations dictate that polymer floods be conducted using only a slug of polymer solution (3.5% to 45% reservoir pore volume have been used) displaced with drive water.

It is common practice not to inject the polymer slug solution at a constant concentration. Rather a "graded concentration profile" is employed. The leading edge of the polymer slug is designed with sufficient effective viscosity to improve the oil displacement mobility ratio as required with allowance made for adsorption losses (most polymers adsorb to the reservoir rock to some degree). The polymer concentration is then reduced in multiple stages towards the trailing edge of the slug, which

Reduces the overall cost of the slug, and Prevents an adverse mobility ratio from existing between the slug and the drive water.

Polymer in Use and their Properties

When polymers are hydrated in water, they form long-chain molecules with molecular weights in the millions. As a result polymers are able to significantly change the viscosity of injected water at relatively low concentrations, such as 250 to 1500 ppm. An example of polymer thickened water viscosity is shown in Figure 3.

Although other types of polymers have been proposed, the two most often used materials in polymer flooding are:

  • Polysaccharide biopolymers produced by the microorganism Xanthomonas Campestris
  • Polyacrylamides that are produced artificially by combining carbon, hydrogen, oxygen, and nitrogen into a basic unit called an amine monomer.

Polymers are non-toxic and non-corrosive. Usually the only equipment necessary for polymers that is not already installed for waterflooding is mixing and filtration equipment.


To be effective, polymer solutions must remain stable for a long time at reservoir conditions. They are sensitive to degradation of the following types:

Figure 3 Chemical Injection
  • Chemical. At the conditions of elevated temperatures in oil reservoirs polymers are subject to attack by oxygen.
  • Mechanical. All polymers mechanically degrade under high enough flow rates, but polyacrylamides are most susceptible under normal operating conditions, particularly at high salinity or hardness.
  • Thermal. For a given polymer solution, there will be some temperature above which the polymer will thermally crack. This temperature is on the order of 95oC � 120oC.
  • Biological. Variables affecting biological degradation include the type of bacteria in the brine, pressure, temperature, salinity and other chemicals.
These degradations can be prevented using special equipment and techniques.

Adsorption, Entrapment, Residual Resistance Factor

Polymer losses are attributed to physical adsorption on solid rock surfaces and retention by mechanical entrapment. It is largely irreversible and constitutes an economic loss. Polymer loss is a highly variable property, being a function of the salinity and pH of the water, the clays available, and pore size distribution, etc., and therefore must be measured for any polymer injection project. A related phenomenon is Residual Resistance Factor (RRF). Early investigators found that the apparent permeability of porous rock was permanently reduced by the passage of the polymer solution. Adsorbed polymer molecules influence the flow of any aqueous phase through the porous medium by blocking some very small pore channels and by reducing the dimensions of others. RRF = (initial water mobility) / (water mobility after polymer flood) This quantity should be measured and taken into account in polymer flood calculations. The value of the residual resistance factor is typically considerably greater than 1.0 and could be as high as 20.

Inaccessible Pore Volume

When polymer solutions are injected into porous media containing only water, they do not displace all of the water present. This inaccessible pore volume arises because the polymer molecules are so large that they are unable to flow into some of the pore space. As much as 30% of the rock pore volume may not be accessible to polymer molecules (Dawson and Lantz, 1972). Inaccessible pore volume can be beneficial to field performance. The rock surface area in contact with the polymer will be reduced, thus decreasing the amount of polymer adsorbed.


Timing / Mobile Oil Saturation

Polymer flooding is applied most effectively in the early stages of a waterflood while the mobile oil saturation is still high. The higher the producing water-oil ratio at the start of polymer injection, the higher the risk of failure will be. This is because polymer flooding does not reduce the oil saturation significantly in the swept zone. Its primary effect is to accelerate recovery and increase ultimate oil production (over normal waterflooding) by increasing the volume of reservoir contacted.

Sloat (1970) analyzed 56 polymer waterflood projects with respect to the time in the flood life that the polymer treatment was started. Improvement in oil recoveries of 5 to 15 percent occurred where polymer treatment was started early, when the water-oil ratio (WOR) was less than four.


Adsorption, mobility and permeability reduction characteristics of polymer solutions are significantly affected by water salinity. More than 90% of the viscosity of polyacrylamide solutions can be lost at high salinities (IOCC, 1983). Salt alters the shape of the polymer molecules from distended to more nearly spherical.

Reservoir Depth

Both shallow and deep reservoirs present design concerns. Injection pressure is a limitation for shallow reservoirs, and the deeper formations are usually associated with higher temperatures and higher salinities.


Since polymer solutions are designed to have lower mobility than water, reservoirs with permeabilities less than 20 md should be avoided if vertical wells are being used for two reasons:

  • Polymer injection rates would be relatively low, which would prolong the life of project beyond the economic limit, and
  • There would be high shear rates around the vertical well bores which would cause shear degradation of polyacrylamide polymers.
Horizontal wells have been successfully used to overcome polymer injectivity concerns in heavy oil applications in Western Canada (Zaitoun et al., 1998).

Stratification Control

The existence of fractures or severe permeability heterogeneities can cause premature water breakthrough and poor waterflood performance, even when the oil viscosity is not high. In these instances, the flow characteristics of polymer solutions will tend to promote a more even flood front (improved vertical sweep efficiency) by diverting injection into the lower permeability zones.

A polymer slug having a viscosity ratio of water approximately equal to the ratio of the thief-zone permeability to the reservoir permeability improves this situation but the risk factor is high.

Mobility Control for Other Processes

An important use of polymers is as a mobility buffer between surfactant and alkaline flooding chemicals and the drive water.

Polymer Selection Considerations

Polysaccharides are much less sensitive to salinity and shear than polyacrylamides. However, as currently manufactured, these polymers need to be filtered through submicron-sized filters to prevent well plugging.

Polyacrylamides can achieve very high molecular weights, up to 20 million. Therefore they have the advantage that a small amount of this material can create a very large increase in the viscosity of the aqueous solution. This effect is its greatest advantage in that a lower concentration is required (and hence cost) compared to biopolymer.

Western Canadian Heavy Oil Innovation

Canadian Natural Resources is currently implementing polymer flooding using horizontal wells in the Wabiskaw reservoir at Pelican, Lake Alberta. This reservoir has an oil gravity of 14.5 oAPI and dead oil viscosity that ranges fromf 800 cp to 80,000 cp.

The company estimates that polymer injection will increase recovery factor in their heavy oil Pelican Lake field to an ultimate recovery to 20% of the original oil in place at a relatively low cost; an incremental $0.40 to $0.60 per barrel in operating cost plus an incremental $6 to $8 per barrel of reserves in capital cost. Ninety percent of their produced water is recycled and they have initiated brackish water usage to mix with the polymer.

Alkaline Flooding

Alkaline Flooding Process Description

Alkaline flooding is capable of mobilizing and recovering a part of the residual oil remaining after waterflood.

Figure 4 Chemical Injection

Some crude oils contain organic acids. These acidic compounds are probably mostly carboxylic acids and contain ring and fused structures. They are therefore relatively high molecular weight species with very low solubility in water.

The occurrence of these natural organic acids appears to be associated with the maturity of the oil. They are most prevalent in oils containing significant amounts of asphaltenes and resins and these oils have API gravities of 25o to 30o as an upper limit.

It is possible to saponify or hydrolyze the naturally occurring organic acids in crude oils at high pH. When this happens, the ionized organic acid molecules become surface active. That is, they tend to associate at the boundary between the oil and water phases, and interfacial tension between the two phases decreases dramatically with increasing concentration of hydroxide ion (see Figure 4).

Several compounds which are relatively cheap will significantly raise the pH of water: sodium hydroxide, sodium carbonate, sodium orthosilicate and ammonium hydroxide. For example a 1% solution of sodium hydroxide raises the pH of water to 13.3

The formation of surfactants in alkaline flooding improves oil recovery by one or more of the following mechanisms:

Interfacial tension reduction
Wettability alteration

It is not clear whether these mechanisms are mutually exclusive. However, oil acid compositions, rock mineralogy and type of alkali formulation determine which of these will be the controlling mechanism. Prior to discussing these mechanisms, it is useful to examine the effect of aqueous phase salinity on the ability of alkalis to reduce interfacial tension.

Effect of Aqueous Phase Salinity

Electrolyte strength of an aqueous solution of surfactants controls the solubility of those surfactants in the water phase. Therefore, when a surfactant is partitioning between water and oil, an increase in salinity of the water phase will decrease the solubility of the surfactant molecules in the water and drive them to the water/oil interface. The presence of salts will therefore have a strong effect on the interfacial tension as a function of the concentration of each ion.

Figure 5 shows typical interfacial tension change caused by sodium chloride concentration in the water phase, and Figure 6 shows the effect of flood water salinity on recovery of crude oil by alkaline flooding.

Figure 5 Chemical Injection

This recovery mechanism relies on the dramatic decrease in interfacial tension to allow the oil phase to be emulsified in the water in very fine drops. They can be entrained and transported through the reservoir pore structure by the flow of water. This would result in a reduction in oil saturation.

If the emulsified oil droplets encounter pore throats that are too small for them to pass through under the available pressure gradient, they will become trapped. The resulting effect is a reduction in mobility of the injected water and an increase in sweep efficiency.

Wettability Alteration

Wettability alteration can be either from oil-wet to water-wet or vice versa.

If the injection of alkali chemicals alters the adsorbed species to the rock surfaces to the extent that the wettability were changed from oil-wet to water-wet, the water relative permeability would be lowered and a more favourable water-oil mobility would be achieved. In this case, high concentrations of alkali (2-5 %) at low salinities are required (Leach et al., 1962; Ehrlich et al. 1974).

If the wettability were reversed from water-wet to oil-wet, discontinuous residual oil could be converted to the continuous wetting phase. The previously trapped oil would now have the continuity to flow out of the reservoir. In this case, higher salinities in the water phase are required to drive the natural surfactants out of the water into the oil and onto the rock surface.

Technical Difficulties

The most severe problem associated with alkali flooding is chemical loss from mineral interactions and reactions with reservoir brines. Among these, mineral interaction appears to be the most significant.

Mineral Interaction

Minerals within oil reservoirs typically contain exchangeable cations and anions. Cation exchange capacity (CEC) is measured in standard practice. This quantity must be taken into account in alkaline flooding.

Gypsum and montmorillonite clays are extremely harmful to alkaline solutions. Reported alkali consumption ranged from 10,000 lb/acre-ft of rock for Berea sandstone to 200,000 lb/acre-ft for Grayburg dolomite in West Texas (Ehrlich and Wygal, 1976).

Long-term chemical consumption of ions in the alkali solution by silica-based compounds in sandstones also exists and will increase with both the concentration of the alkali and the time the sandstone is exposed to the alkali solution.

Reservoir Brines

Divalent ions such as calcium and magnesium in reservoir brine will consume hydroxide ion to form insoluble calcium and magnesium hydroxides.


The alkaline flooding process has been known for more than 80 years. However, due to its applicability to special types of crude oils and the complex mechanisms involved, large-scale commercial field operations have not been undertaken. The following recommendations can however be made with respect to applicability of the process.

Acid Number

The acidic content of a crude oil is commonly characterized as the acid number, i.e. the milligrams of potassium hydroxide required to neutralize one gram of crude oil. An acid number of 0.1 would be quite low and 5.0 would be very high.

Crude oil acid numbers above 0.5 mg KOH/g oil generally indicate good candidates, and acid numbers between 0.2 and 0.5 justify further evaluation. However, it is not necessarily true that all crude oils having high acid content are good candidates.

Water Hardness

Because of the incompatibility of alkaline chemicals with divalent ions, low salinity reservoirs are preferred and soft water is required to make the alkaline solution. Further, if the hardness content on the formation water is high, a preflush is needed to separate the reservoir brine from the alkaline slug.


Sandstone reservoirs with low gypsum and clay content are preferred.

Surfactant Flooding

Surfactant Flooding Overview

Surfactant flooding is a more complex EOR process that alkaline flooding and, historically, it includes a great variety of technologies to achieve improvement in oil recovery. The most important are plain aqueous surfactant flooding, low tension flooding, micellar flooding, microemulsion flooding, and soluble oil flooding. All of these methods involve the injection of surfactants to either create a drastic reduction in interfacial tension between the oil and the water (so as to achieve a lower residual oil saturation due to the high capillary number), or displace the oil using a fluid which is miscible with it. The problem with the injection of surfactants in petroleum reservoirs is that surfactants are surface active. That is, they have a high affinity for adsorption from solution onto the rock in great quantities.

Even the injection of the cheapest materials can be extremely expensive if great quantities are required because of chemical adsorption (see also alkaline flooding in the presence of gypsum and montmorillonite). Therefore the many surfactant injection technologies have been designed to minimize adsorption and slug dispersion, while promoting low interfacial tension or direct miscibility with oil.

Many types of surfactants have been injected into reservoirs. The cheapest ones which are effective are those derived from petroleum by sulphonation. The petroleum sulphonates are anionic surfactants. Cationic surfactants have been tested, but it was found that their adsorption was much more severe than that of anionic surfactants.

Surfactant Liquid Structures

When a surfactant is dissolved in water the molecules initially congregate at interfaces such as the air/water and liquid/solid interfaces. With the addition of more surfactant to water, a saturation point is reached beyond which the surfactant molecules aggregate as shown in Figure 7. These aggregates are called micelles. The concentration at which the surfactant begins to create micelles is called the critical micelle concentration (CMC).

Figure 7 Chemical Injection

Within each micelle is an oil-like (non-polar) environment in which oil can dissolve. This process is call solubilization.

With increasing surfactant and oil concentration, the structure in the liquid undergoes several changes: cylindrical configuration of the micelles, hexagonal packing of cylinders, planar lamellar structures, and close packing of cylinders of water inside protective cylinders of surfactant molecules.

Finally the addition of a short-chain alcohol, converts the structure into a water-in-oil microemulsion. In this arrangement the surfactant molecules have their polar heads aiming inwards towards the water phase and their oleic tails outward into the oleic phase.

The effective viscosity of these structures varies enormously (Shah et al. 1977).

Effect of Salinity

Although surfactant flooding mixtures normally have more than three components, it is customary to represent the phase behaviour on a pseudo-ternary diagram of the three major components: surfactant, oil, and water or brine. As shown in Figure 8, surfactant components in a fixed ratio are represented at the top of the diagram, the water solution of salts in a fixed ratio (brine) is represented at the lower left corner, and the lower right corner represents the crude oil.

Figure 8 Chemical Injection

Surfactant flooding phase behaviour is strongly affected by the salinity of the brine. Consider the sequence of changes as the brine salinity is increased (refer to Figures 8a and 8b.

At low brine salinity, a typical surfactant will exhibit good aqueous-phase solubility and poor oil-phase solubility. Near the brine-oil boundary there will be an excess oil phase that is essentially pure oil and a water-external microemulsion phase that contains brine, surfactant and some solubilized oil in swollen micelles. Note that the tie lines within the two-phase region have a negative slope. This type of phase environment has been given various names: Winsor Type I System, a lower-phase microemulsion, or a Type II(-) system.

At high brine salinities, electrostatic forces drastically decrease the surfactant's solubility in the aqueous phase. The mixture will now split into an excess brine phase and an oil-external microemulsion phase that contains most of the surfactant and some solubilized brine in inverted swollen micelles. This phase environment is referred to as a Winsor type II system, an upper-phase microemulsion, or a Type II(+) system.

At salinities between those in Figure 8a and Figure 8b there is a range of salinities where a third surfactant-rich phase is formed (Figure 8c). The mixture splits partitions into excess oil and excess brine phases, and also a microemulsion phase. This environment is called a Winsor Type III system, a middle-phase microemulsion, or a Type III system.

Figures 9 and 10 Chemical Injection

Reed and Healy (1977) measured the interfacial tensions between the upper and middle phases and the middle and lower phases. They found dependences with temperature, salt concentration, surfactant concentrations, etc. In correlating these measurements with results of coreflood tests with the same micellar fluids and the same oils, the optimum conditions for oil recovery were those where both the upper-middle and the middle-lower interfacial tension were minimized.

These interfacial tensions have been shown to correlate with phase behaviour. Let Com, Cwm, and Csm be the volume fractions of oil, brine, and surfactant in the microemulsion phase. Solubilization parameters between the microemulsion-oleic phase Sso for Type II(-) phase behaviour, and between microemulsion-aqueous phases Ssw for Type II(+) are defined as

Sso = Com / Csm Ssw = Cwm / Csm

Figure 9 shows that both interfacial tension curves are the lowest in the three-phase Type III region, and where both solubilization parameters are large. The interfacial tensions between the corresponding phases, sso and ssw, are empirical functions of only the solubility parameters, Sso and Ssw, respectively (refer to Figure 10).

Practical benefits of this correlation are that difficult measurements of interfacial tension can be replaced by relatively easy phase behaviour measurements and that it provides a basis for surfactant flood design.

In concluding this section, it is important to mention that Hirasaki (1980), Nelson (1980), and others have shown both mathematically and experimentally that oil recovery by chemical flooding can be greater when the salinity of the injected surfactant solution is varied in a prescribed manner such as a linear gradient. The salinity gradient reduces surfactant adsorption losses and concentrates it in a limited zone in the advancing slug.

Adsorption from an oil-rich phase is much less than from aqueous phases. The researchers suggest a salinity gradient from high salt to low salt. This forces the surfactant to move slowly at the front of the slug since it is in the oil (high salt Type II(+) system), and quickly at the rear of the slug in the more mobile water (low salt Type II(-) system). The result is a peak in surfactant concentration, a minimum adsorption loss, and maximum oil recovery.

Surfactant Flooding Processes

Surfactants to improve oil recovery have been used in the field since the late 1920s and early 1930s. The early systems used very low surfactant concentrations, usually below or close to the critical micelle concentration for the surfactant used. Later, surfactant processes with compositions well above the critical micelle concentration were patented and field tested. Reed and Healy (1977) have conveniently depicted on Figure 11 the various surfactant flooding processes.
Figure 11 Chemical Injection

Aqueous surfactant flooding has no oil in the injected fluid. The injected fluid therefore has its composition located at point "A" on the surfactant-water axis. Low tension floods involve the injection of surfactant, oil and mostly water. The injected fluids are immediately immiscible with the reservoir oil and therefore lie on the boundary (point "I") between the single-phase and multi-phase regions. Micellar floods are usually considered to be the same as micro-emulsion floods. The injected fluid consists of higher concentrations of surfactants and the composition is located in the single-phase region "M".

Soluble oil flood injection mixtures consist of surfactant and oil with some water present. The composition is located at point "S", near or on the surfactant-oil axis. The advantages of aqueous surfactant and low tension injection are that large volumes of relatively low concentrations of surfactant can be used and it less critical to reduce physical dispersion of the slugs to a minimum. Although these processes do not reduce the residual oil saturation to zero, they may still recover a significant amount of oil. They suffer from a potential mobility control problem (refer to discussion on viscous fingering in polymer injection section), as the viscosities of these injected fluids are likely to be low, unless water soluble polymers are added to them.

Micellar / micro-emulsion flooding solutions have considerably higher concentration of surfactants. Therefore, economic considerations imply that small slugs of these expensive chemical formulations must be used in these processes. The formulations of the solutions are very sophisticated since additional compounds must be added to minimize the size of the multiphase region and to solubilize the maximum amount of oil.

The soluble oils are designed to be completely miscible with the reservoir oil, and therefore have the advantage of leaving nearly zero residual oil saturation. They are less sensitive to reservoir salinity and can be potentially miscible with the aqueous phase pushing them if the salinity of the drive water is carefully adjusted so that the proper micellar solutions are formed.

Note that:

The surfactants used in most flooding mixtures cover a range of molecular weights (monosulfonates, disulfonates and trisulfonates and possibly some sulphates) so that they will accommodate the range of molecular weights found in crude oil. Co-surfactants (usually alcohols or ethoxylated alcohols) are added to the mix to force the surfactants to reside at phase interfaces and to minimize the amount of surfactant needed.

Technical Challenges

Currently, the formulation of a micellar fluid for a particular reservoir oil, water, salinity, permeability and mineral environment is a trial and error process.

It is common to use polymer as a mobility buffer between the micellar solution and the drive water. Polymer and micellar solutions are however not always compatible chemically; polymers require different salinity environments and adverse phase changes can occur in the micellar fluids.

Figure 12 Chemical Injection

Figure 12 is a cross-section of a typical micellar-polymer flood. The approaches for generating optimal conditions for this process are:

Raise the optimal salinity of the micellar slug to that of the reservoir brine. This is usually the most difficult approach.

Lower the resident salinity of the candidate reservoir to match the slug's optimal salinity. This common approach is the main purpose of the preflush step.

Use a salinity gradient design. This has several advantages: it is resilient to process uncertainties, provides a favourable environment (low salinity) for the polymer in the mobility buffer, minimizes retention, and is indifferent to the surfactant dilution effect. Another problem associated with microemulsion flooding is the treatment of produced emulsions. Depending on the design of the injected microemulsion slug system, the produced emulsion can be very serious or minimal. Consequently the cost of breaking the emulsion can be either very high or routine.


Surfactant flooding is applicable to many reservoirs which have been successfully waterflooded.

It is technically applicable for secondary or tertiary recovery. If used for secondary recovery, it eliminates one set of operating costs (produced water handling from prior waterflood); however it should still be justified economically on the incremental oil it will recover over waterflooding.

The process is best applied to reservoirs with medium gravity crude oils. Prospects with low gravity crudes would present economic challenges. A low-gravity, high-viscosity crude would call for increasing the viscosity of the micellar and polymer slugs for a favourable mobility ratio, resulting in higher costs.

Alkaline-Surfactant-Polymer (ASP) Flooding

The ASP process was developed in the early 1980s as a lower-cost alternative to micellar/surfactant polymer flooding.

The process consists of injecting a slug mixture of alkali-surfactant-polymer, followed by the injection of additional polymer and then chase water. The combination of the three chemicals in the slug is synergistic, being more effective than injection as individual components.

Surfactant is added to the mix to lower the interfacial tension between water and oil, which results in the mobilization residual oil saturation trapped by capillary forces. The alkali serves as a sacrificial component to reduce the adsorption of the surfactant on the reservoir rock. Alkali is also able to react with acidic components of the oil to form additional surfactants in-situ. As alkali is inexpensive, this helps to reduce the cost of an ASP flood. The addition of polymer increases the vertical and areal sweep efficiency.

ASP technology is simple in concept, but very complicated in design and application. It requires much thorough laboratory testing and research. Sometimes a proper formulation of alkali-surfactant-polymer mixture cannot be designed to achieve good displacement in a particular reservoir.

In selecting chemicals for an ASP flood (or any chemical EOR flood for that matter), it is necessary to consider availability, quantities required, cost, performance, and logistics. All of these factors are critical due to the large quantities usually required to flood one field, which can run into the hundreds of millions of pounds. Therefore in order to minimize costs, it is critical that:

  • There be chemical manufacturing plants large enough to accommodate the capacity needed and in close proximity to the field being flooded to reduce transportation costs,
  • Chemical cost is low enough to make the sizable investment in chemicals profitable in the long term.

Polymer Gels

Apart from mobility control, polymers are also used in near-wellbore treatments to improve the performance of water injectors or high water-cut producers by blocking off high-conductivity zones. A solution containing a polymer and a cross-linker (sometimes referred to as gelant), is injected in desired zones and allowed sufficient time to set into a solid gel. The cross-linker (usually low concentrations of metal ions from chromium triacetate or aluminum citrate), causes the polymer molecules to bond together (gel). Gellation is controllable, ranging from a few hours to weeks. Longer gellation time allows for more volume to be injected and therefore deeper placement.

Gels can be created that completely block the flow of fluid through all reservoir rock or they can preferentially reduce permeability and fluid flow through only the most permeable and conductive pathways. In injection wells these gels can be used to divert the flow of injected water or gas (CO2) to un-swept zones where additional oil can be recovered. In production wells they may be used to shut-off excessive water inflow resulting from coning or breakthrough situations.

The treatments are relatively inexpensive because they contain 98% or more water, and are equally applicable to sandstone and carbonate reservoirs. The gels can be created in virtually any water, at temperatures up to 400 oF, and in high H2S environments. Special equipment is normally required to properly blend and pump.

Gels can be created with polymer concentration ranging from a few hundred to more than 50,000 ppm; low polymer concentration means less gel strength and higher concentration means more gel strength. Weaker gels (colloidal dispersion gels) are used in reservoirs dominated by matrix flow conditions and stronger gels (bulk gels) are used in reservoirs dominated by fracture or vug flow conditions. Note that long-term performance of these treatments relies on the in-situ solutions having sufficient strength to stay in place during drawdown.

Finally, selection criteria for injection well candidates are sweep efficiency related:

  • significant remaining mobile oil-in-place that can be recovered if sweep efficiency is improved,
  • premature water breakthrough at producing wells resulting from channelling through fractures, or high degree of reservoir heterogeneity,
  • high injection rates associated with low wellhead pressure which could also be due to channelling behind the casing.


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