module 6

PETE 609 - Module 6 Improved Water Flooding Processes

Class Notes for PETE 609 – Module 6 /91 Author: Dr. Maria Antonieta Barrufet – Fall, 2001

Learning Objectives

After completion of this module, you will be able to:

• List typical polymer types and compare their physical properties.

• Understand the rheological behavior of polymers.

• Understand the importance of salinity, temperature, polymer concentration, and shear rate in determining the polymer solution properties.

• Understand the principles of permeability reduction.

• Summarize polymer retention mechanisms.

• Evaluate polymer adsorption.

• Learn the major steps involved in designing a polymer flood.

Module 6 – Improved Waterflooding Processes

Estimated Duration: 2 weeks

Improved Waterflooding Processes.

Polymer Flooding.

Rheology of Polymer Solutions. Polymer Adsorption and Retention.

Micellar-Polymer or Microemulsion Flooding.

Properties of Surfactants and Cosurfactants.

Surfactant-Brine-Oil Phase Behavior.

Caustic Flooding.

Performance evaluation.

Suggested reading: MAB, L, R24



• Compare polymer versus waterflood using a Polymer Flood Simulation program provided in class.

• Analyze various production strategies in polymer floods (slug size, concentration, injection rates, etc.).

• Recognize the importance of lowering the interfacial tension (Micellar-Polymer flooding, and caustic flooding).

• Identify the terminology and identify process variations.

• Define the chemical basis for surfactants.

• Identify types of phase behavior for different oil/surfactant/brine systems.

• Define and use optimal salinity.

• Summarize caustic flooding mechanisms.

• Evaluate fractional flows in caustic flooding processes.

Improved Waterflooding Processes

This module covers a variety of methods classifies as improved waterflooding processes. These are implemented and analyzed in the same way as a waterflood, but with some variations and complexities. Improved waterflooding processes consist in changing the properties of the water (brine) used by adding some chemicals. The target of these chemicals is to increase the water viscosity to improve mobility ratios, or to lower the IFT between oil and water by using surfactants, or a combination of both. These surfactants are either added to the water (micellar flooding), or generated in-situ by chemical reactions of acidic components of the oil with a caustic solution.

In this module, we will cover,

• Polymer Flooding,

• Micellar- Polymer Flooding,

• Alkaline Flooding.



There are other improved waterflooding processes such as foam flooding which will not be covered in this course due to time constraints. Most of the material for this section has been taken from Lake (1989).

Polymer Flooding

Polymer flooding consists of adding polymer to the water of a waterflood to lower its mobility. The resulting increase in viscosity, as well as a decrease in aqueous phase permeability that occurs with some polymers, causes a lower mobility ratio.

A lower mobility ratio increases the efficiency of the waterflood by increasing the volumetric sweep efficiency. Although polymer addition does not normally decrease residual oil saturation it reduces the water-cut as oil is recovered.

It has also been reported that the addition of some polymer reduces rock permeability to the polymer-water solution, thereby favorably reducing water mobility and increasing both areal and vertical reservoir sweep efficiency.

The greater recovery efficiency constitutes the economic incentive for polymer flooding when applicable. Generally, a polymer flood will be economic only when the

• waterflood mobility ratio is high,

• the reservoir heterogeneity is high,

• a combination of these two occurs.

Polymers have been used in oil production in three modes.

1. As near-well treatments to improve the performance of water injectors or watered-out producers by blocking off high-conductivity zones.

2. As agents that may be cross-linked in situ to plug high-conductivity zones at depth in the reservoir.

3. As agents to lower water mobility or water-oil mobility ratio.



The first mode is not truly polymer flooding since the effect is to lower the water production, and due to this lower water/oil ratio the oil production may become profitable.

The second mode requires that polymer be injected with an inorganic metal cation that will cross-link subsequently injected polymer molecules with ones a lready bound to solid surfaces.

Most polymer EOR projects have been in the third mode, the one we emphasize here. We discussed how lowering the mobility ratio affects displacement and volumetric sweep efficiency in Module 3.

Figure 1 shows a schematic of a typical polymer flood injection sequence along with typical concentrations of chemicals and pore volumes injected.

Chase Water

Taper MobilityBuffer

Slug Preflush

Mobility buffer

250-2500g/cm3

polymer

Biocide

0-100% Vpf

Slug

Polymer Solution

(2500-10000)g/cm3

5-20% Vpf

Preflush

Electrolyte (Na+, Ca++, etc.)

Sacrificial chemicals

0-100% Vpf

Chase Water


Slug Preflush

Mobility buffer

250-2500g/cm3

polymer

Biocide

0-100% Vpf

Slug

Polymer Solution

(2500-10000)g/cm3

5-20% Vpf

Preflush



0-100% Vpf

Figure 1 - Schematics of a typical polymer flood injection sequence.

The oil bank at the front end is being pushed by a preflush, which usually consists of a low-salinity brine to condition the reservoir. Next follows the slug of the polymer solution itself, followed by a freshwater buffer to protect the polymer solution from backside dilution. Many times the buffer contains polymer in decreasing amounts (a grading or taper) to lessen the unfavorable mobility ratio between the chase water and the polymer solution, finally the sequence ends with the chase or drive water.

Because of the driving nature of the process polymer floods are always done through separate sets of injection and production wells.



Mobility is lowered in a polymer flood by injecting water that contains a high molecular weight, water-soluble polymer. Since the water is usually a dilution of oil-field brine, interactions with salinity are important, particularly for certain classes of polymers.

Salinity is quantified by the total dissolved solids (TDS) content of the aqueous phase.

Chemical flooding properties depend on the concentrations of specific ions rather than salinity only. The aqueous phase's total divalent cation content is known as hardness is usually more critical to chemical flood properties than the same TDS concentration. These divalent cations are mostly Ca++ and Mg++.

Salinities from representative oil-field brines can range from as low as a few thousand ppm to over 250,000 ppm. While hardness, which is expressed as the ion concentration of Ca++ and Mg ++ may be from 100 to about 20,000 ppm. (Lake, 1989).

Because of the high molecular weight the water soluble polymers used in this EOR

technique (1 to 3 million), only a small amount (about 500 g/m3) of polymer will bring about a substantial increase in water viscosity. Further, several types of polymers have been reported to lower the mobility by reducing the water relative permeability in addition to increasing the water viscosity. In reality the oil permeability is also altered and there is a reduction of both oil and water, but this effect is more pronounced in the water relative permeability.

The mechanisms by which polymer lowers mobility, and the interactions with salinity, can be qualitatively illustrated by discussing polymer chemistry, and polymer rheology.

Polymer Characteristics

Polymers Used

Some of the polymer types that have been considered for polymer flooding include:

• Xanthan gum (biopolymer)

• Hydrolyzed polyacrylamide (HPAM)



• Copolymers (a polymer consisting of two or more different types of monomers) of acrylic acid and acrylamide

• Copolymers of acrylamide and 2-acrylamide 2-methyl propane sulfonate (AM/AMPS)

• Hydroxyethylcellulose (HEC)

• Carboxymethylhydroxyethylcellulose (CMHEC)

• Polyacrylamide (PAM)

• Polyacrylic acid

• Glucan

• Dextran polyethylene oxide (PEO)

• Polyvinyl alcohol

• Modified starches

Virtually all the commercially attractive polymers fall into two generic classes:

• polyacrylamides

• polysaccharides (biopolymers)

Figure 2 shows representative molecular structures for these two major types.



Figure 2 - Molecular structures of polyacrylamides and polysaccharides (Willhite and Dominguez, 1977). Taken from Lake (1992).

Polyacrylamides

These are polymers whose monomeric unit is the acrylamide molecule. As used in polymer flooding, polyacrylamides have undergone partial hydrolysis, which causes anionic (negatively charged) carboxyl groups (-COO-) to be scattered along the polymer chain. The polymers are called partially hydrolyzed polyacrylamides (HPAM) for this reason.



Typical degrees of hydrolysis are 30%-35% of the acrylamide monomers; hence the HPAM molecule is negatively charged, which accounts for many of its physical properties.

This degree of hydrolysis has been selected to optimize certain properties such as water solubility, viscosity, and retention. If the level of hydrolysis is too small, the polymer will not be water soluble. If it is too large, its properties will be too sensitive to salinity and hardness, loosing part of the functionality for which has been selected.

The viscosity increasing feature of HPAM lies in its large molecular weight.

This feature is accentuated by the anionic repulsion between polymer molecules and between segments on the same molecule. The repulsion causes the molecule in solu-tion to elongate and snag on others similarly elongated, an effect that accentuates the mobility reduction at higher concentrations.

If the brine salinity or hardness is high, this repulsion is greatly decreased through ionic shielding since the freely rotating carbon-carbon bonds allow the molecule to coil up. This feature is illustrated in Figure 3. The shielding causes a corresponding decrease in the effectiveness of the polymer since snagging is greatly reduced. Virtually all HPAM properties are sensitive to salinity and hardness, an obstacle to using HPAM in many reservoirs. On the other hand, HPAM is inexpensive and relatively resistant to bacterial attack, and it exhibits permanent permeability reduction.



-C-C-C-C-C-C-C-C-C-C-C-C-C-C-- - --

-


-

C-C-C-C-C-C-

C-C-C-C-

Na+Na+

Na+-

--

ElectrostaticRepulsion

Coiling in

Brines


-


-

C-C-C-C-C-C-

C-C-C-C-

Na+Na+

Na+-

--


Coiling in

Brines


-


-


--C-C-C-C-C-C-C-C-C-C-C-C-C-C--- -- ----

--


--C-C-C-C-C-C-C-C-C-C-C-C-C-C--- -- ----

--

C-C-C-C-C-C-

C-C-C-C-

Na+Na+

Na+-

--

C-C-C-C-C-C-

C-C-C-C-

Na+Na+

Na+--

----


Coiling in

Brines

Figure 3- Schematics of the structure on HPAM in fresh water and in brines.

Polysaccharides

These polymers are formed from the polymerization of saccharide molecules Figure 2 b), a bacterial fermentation process. This process leaves substantial debris in the polymer product that must be removed before the polymer is injected (Wellington, 1980). The polymer is also susceptible to bacterial attack after it has been introduced into the reservoir. These disadvantages are offset by the insensitivity of polysaccharide properties to brine salinity and hardness.

Figure 2 b shows the origin of this insensitivity. The polysaccharide molecule is relatively nonionic and, therefore, free of the ionic shielding effects of HPAM. Polysaccharides are more branched than HPAM, and the oxygen-ringed carbon bond does not rotate fully; hence the molecule increases brine viscosity by snagging and adding a more rigid structure to the solution. Molecular weights of polysaccharides are generally around 2 million.

HPAM is usually less expensive per unit amount than polysaccharides, but when compared on a unit amount of mobility reduction, particularly at high salinities, the costs are close enough so that the preferred polymer for a given application is site specific.



Historically, HPAM has been used in about 95% of the reported field polymer floods (Manning et al., 1983). Both classes of polymers tend to chemically degrade at elevated temperatures.

Polymer Preparation Methods

Polymers to prepare polymer solutions are purchased in three different forms:

• Powders

• Broths

• Emulsions

Powders, the oldest of the three methods, can be readily transported and stored with small cost. They are difficult to mix because the first water contacting the polymer tends to form very viscous layers of hydration around the particles, which greatly slow subsequent dissolution.

Broths are aqueous suspensions of about 10 wt.% polymer in water which are much easier to mix than powders. They have the disadvantage of being more expensive because of the need to transport and store large volumes of water. Broths are quite viscous so they can require special mixing facilities. In fact, it is this difficulty which limits the concentration of polymer in the broth.

Emulsion polymers, the newest polymer form, contain up to 35 wt. % polymer solution, suspended through the use of a surfactant, in an oil-carrier phase. Once this water-in-oil emulsion is inverted (next lectures) the polymer concentrate can be mixed with make-up water to the desired concentration for injection.

Polymer Properties

In this section, you will see qualitative trends, quantitative relations, and representative data on the following properties:

• Polymer Rheology

• Viscosity relations



• Non-Newtonian effects

• Polymer transport

• Inaccessible pore volume

• Permeability reduction

• Chemical and biological degradation

• Mechanical degradation.

Polymer Rheology

To understand the behavior of the polymer viscosity we must introduce some rheological concepts.

Rheology is the science that studies the deformation and flow of matter by describing the manner in which materials respond to applied stress and strain.

Viscosity, one of the properties that affects flow the most, is needed in polymer flooding processes, in the design of drilling fluids, and in transportation trough pipes and facilities design.

Before classifying a fluid in terms of their rheological behavior we have to define some terminology.

Stress is the ratio of force over area. Forces can be perpendicular (normal) to the area, parallel, or combined. This gives rise to normal stresses (tensile or compressive) and to shear stresses.

Figure 4 illustrates the concept of normal and shear stresses, as well as combined stresses that induce bending.



tensile force

compressive force

Shear forces parallel to thesurface they act

Combined forces inducingbending

tensile force

compressive force

Shear forces parallel to thesurface they act

Combined forces inducingbending

Figure 4 - Illustration of forces and stresses.

Stresses are a tensorial quantity and 9 nine separate quantities are required to describe completely the state of stress in a material as indicated in Figure 5.

σi j

σxx

σxy

y

zx

σxz

Direction of face upon theforce acts

Direction of the force

σσσσσσσσσ

=σ

331231

132221

131211rr3

2

1

σi j

σxx

σxy

y

zx

σxz

Direction of face upon theforce acts

Direction of the force

σσσσσσσσσ

=σ

331231

132221

131211rr3

2

1

Figure 5 - Tensorial nature of stresses.



Another important definition is the Strain, which is defined as a relative deformation. Mathematically is

llδ

=γ (1)

and the instantaneous rate of strain or shear rate is defined as

dtdγ

=γ& (2)

Rheograms are plots of the variation of the shear stress (scalar) versus the shear rate. The behavior of these plots gives rise to the classification of fluids in terms of their rheological behavior. Figure 6 sketches typical responses that serve to classify fluids accordingly.

She

ar S

tress

Shear Rate, 1/s

Bingham

Shear- thinning

Shear - thickening

µ

Herschel-Bulkley

Newtonian

She

ar S

tress

Shear Rate, 1/s

Bingham

Shear- thinning

Shear - thickening

µ

Herschel-Bulkley

Newtonian

Figure 6 - Shear stress/shear rate behavior for fluids.



For a Newtonian fluid the viscosity, which is defined as the slope of the shear stress versus shear rate curve is constant. That is the viscosity is independent of the shear rate. This slope is always positive and it can be very small for gases at standard conditions, to very high for highly viscous fluids such as heavy oil.

For a shear-thinning fluid an apparent viscosity can be defined at the various shear rates and this decreases with shear rate. Most polymers fall within this category.

For a shear-thickening fluid an apparent viscosity can be defined at the various shear rates and this increases with shear rate.

For a Bingham-plastic fluid, the behavior is similar to a Newtonian fluid (constant viscosity) but a certain shear stress must be applied before the fluid begins to flow.

For a Hershchel-Bulkley fluid, the behavior is similar to a shear-thinning fluid (decreasing viscosity) but a certain shear stress must be applied before the fluid begins to flow.

Non-Newtonian Effects

Polymers are non-newtonian fluids - which means viscosity is not a constant. They are defined as pseudoplastic under most conditions, and their viscosity decreases with increasing shear rates, which accompany increasing flow rates.

At high flow rates encountered in injection wells polymers sometimes deviate from pseudoplastic behavior and exhibit viscoelastic effects. This results in an increasing apparent viscosity, caused by the polymer rapidly moving through expansions and contractions within the rock matrix.

Additional variables influence the polymer apparent viscosity and can be evaluated for specific polymers and water available for mixing. These include mix water composition, polymer molecular weight, degree of hydrolysis and concentration.

The freshest economically available water compatible with the rock, and the lowest polymer concentration that furnishes the desired mobility should be used.

Figure 7 sketches the behavior of most polymer solutions used for oil recovery. Note the different parameters that affect the viscosity.



Figure 7- Typical viscosity response of polymer solutions versus shear rate. (From Core laboratories manual).

Variable flow rate tests on core samples yield data that reflect polymer viscosity. Data are referred to as Reciprocal Relative Mobility, and vary with polymer concentration. Figure 8 shows these tests on a commercial polymer determined by Core Lab laboratories.

Pore sizes and distribution influence polymer flow. Polymer molecules do not move into pores below some critical size, resulting in reduced adsorption in non contacted rock. (A certain permeability may be needed for a specific polymer to prevent filtration on the well bore injection face.)



Figure 8 - Viscoelastic effects for a commercial polymer (Core laboratories manual).

Figure 9 shows polymer solution viscosity pµ versus shear rate γ& measured in a

laboratory viscometer at fixed salinity. At low shear rates, pµ is independent of γ& , and

the solution behaves like a Newtonian fluid. At higher γ& , µ decreases, approaching a

limiting value. A fluid whose viscosity decreases with increasing γ& is shear thinning.

The shear thinning behavior of the polymer solution is caused by the uncoiling and



unsnagging of the polymer chains when they are elongated in shear flow. Below the critical shear rate, the behavior is part reversible.

Figure 9 - Shear thinning behavior of various Xanflood polymer concentrations (from Lake, 1992).

Figure 10 shows a viscosity-shear-rate plot at fixed polymer concentration with variable NaCl concentration for an AMPS polymer. The sensitivity of the viscosity to salinity is profound. As a rule of thumb, the polymer solution viscosity decreases a factor of 10 for every factor of 10 increase in NaCl concentration. The viscosity of HPAM polymers and HPAM derivatives are even more sensitive to hardness, but viscosities of polysaccharide solutions are relatively insensitive to both. This behavior is favorable

because, for the bulk of a reservoir's volume, γ& is usually low (about 1-5 s-1), making it

possible to attain a design mobility ratio with a minimal amount of polymer. But near the

injection wells, γ& can be quite high, which causes the polymer injectivity to be greater

than that expected based on nominal viscosity.



Figure 10 - Effect of salinity on polymer solution viscosity (take from Lake, 1992)

The relative magnitude of this enhanced injectivity effect can be estimated once quantitative definitions of shear rate in permeable media, and shear-rate-viscosity relations are given.

Viscosity Relations

Figure 11 shows a plot of Xanflood viscosity versus polymer concentration. This type of curve has traditionally been modeled by the Flory-Huggins equation (Flory, 1953).

( )K++++µ=µ 33

2211 pwpwpwbp CaCaCa (3)

Where Cpw is the polymer concentration in the aqueous phase, µb is the brine (solvent) viscosity, and ai (i =1, 2, …) are constants depending upon the polymer used.



The usual polymer concentration unit is g/m3 of solution, which is approximately the same as ppm. A useful conversion to recall is that 1,000 g/m3 = 0.1% weight approximately.

The linear term in Equation (3) accounts for the dilute range where the polymer molecules act independently (without entanglements). For most purposes, this equation can usually be truncated at the cubic term.

Figure 11 - Polymer (Xanflood) viscosity as a function of polymer concentration (1% NaCl brine) at fixed shear rates (and Lake, 1992).

For a 1,000 g/m3 Xanflood solution at 0.1 s-1 in 1 wt % NaCl brine at 24 oC,

the viscosity is 70 mPa-s (70 cp). Compared to the brine at the same conditions, this is a substantial increase in viscosity brought about by a relatively dilute concentration, therefore Xanflood at these conditions is an excellent thickener. However, note that a shear rate of 5 s-1, the viscosity dropped to 10 cp.

A more fundamental way of measuring the thickening power of a polymer is through its intrinsic viscosity which is defined as



[ ]

µµ−µ

=µ→ pwb

bp

C Cpw

limit0

(4)

From its definition, [µ] is a measure of the polymer's intrinsic thickening power. It is insensitive to the polymer concentration. The intrinsic viscosity for the Xanflood polymer under the conditions given above is 70 dl/g, the units being equivalent to reciprocal weight percent. Intrinsic viscosity is the same as the a1

term in Equation (3).

For any given polymer-solvent pair, the intrinsic viscosity increases as the molecular weight of the polymer increases according to the following equation (Flory, 1953):

awMK'=µ (5)

The exponent a varies between about 0.5 and 1.5 and is higher for good solvents such as freshwater. K' is a polymer-specific constant.

These relationships are useful for characterizing the polymer solutions. For example, the size of the polymer molecules in solution can be estimated from Flory's (1953) equation for the mean end-to-end distance

( ) 318 /µ= wp Md (6)

This is an empirical equation that requires certain units; [µ] must be in dl/g, and dp is returned in Angstroms (10-10 m).

This measure of polymer size is useful in understanding how these very large molecules propagate through the small pore openings of rocks. The molecular weight of Xanthan gum is about 2 million.

Using Equation (5) for Xanthan gum gives a dp of about 0.4 µm. This is the same size as many of the pore throats in a low-to-moderate permeability sandstone. As a result, we would expect to, and in fact do, observe many polymer-rock interactions.



The relationship between polymer-solution viscosity and shear rate may be described by a power-law model

( ) 1−γ=µ plnplp K & (7)

where Kpl and npl are the power-law coefficient and exponent, respectively. For shear thinning fluids, 0 < npl < 1; for Newtonian fluids, npl = 1, and Kpl becomes the viscosity,

γ& is always positive.

Equation (7) applies only over a limited range of shear rates: Below some low shear

rate, the viscosity is constant at ( )0pp µ=µ and above the critical shear rate, the

viscosity is also constant at ( )∞µ=µ pp .

Another useful model is the Meter model (Meter and Bird, 1964)

1

21

0

1−

∞∞

γ

γ+

µ−µ+µ=µ

Mnpp

pp

/&&

(8)

where Mn is an empirical coefficient, and 21/γ& is the shear rate at which pµ is the

average of 0pµ and

∞µp .

As with all polymer properties, all empirical parameters are functions of salinity, hardness, and temperature.

When applied to permeable media flow, the above general trends and equations

continue to apply. pµ is usually called the apparent viscosity appµ and the effective

shear rate eqγ& is based on capillary tube concepts.



For power-law fluids, the apparent viscosity of a flowing polymer solution is (Hirasaki and Pope, 1974).

11 −− γ==µ plpl npl

nplapp KuH & (9)

where,

( )( ) 211

831 /pl

pln

ww

n

pl

plplpl k

nn

KH −−

φ

+= (10)

Combining Equation (9) with Equation (10) yields the equivalent shear rate for flow of a power-law fluid

wwpl

pleq k

un

n

φ

+=γ

8

31& (11)

The aqueous phase permeability wk is the product of the phase's relative permeability

and the absolute permeability, wφ the aqueous phase porosity defined as wSφ .

Polymer Transport

Polymers are retained in permeable media because of adsorption onto solid surfaces or trapping within small pores. Polymer retention varies with polymer type, molecular weight, rock composition, brine salinity, brine hardness, flow rate, and temperature.



Field-measured values of retention range from 7 to 150 µg polymer/cm3 of bulk volume,

with a desirable retention level being less than about 20 µg/cm3.

Retention causes the loss of polymer from solution, which can also cause the mobility control effect to be lost - particularly at low polymer concentrations.

Evaluation of Polymer Retention

Polymer adsorption can be represented empirically using a Langmuir type isotherm

pp

pppr Cb

CaC

+=

1 (12)

where pC and prC are the polymer concentrations in the aqueous and on the rock

phases.

The units of adsorption can take on a variety of forms, but mass of polymer per mass of rock is most common. Typical shapes of polymer adsorption isotherms are indicated in Figure 12.



Figure 12 - Typical Langmuir isotherm shapes (Lake, 1989).

Polymer adsorption does increase with increasing salinity and hardness and it is unknown wether adsorption is reversible. Typical polymer adsorption isotherms are quite steep; that is, they attain their plateau value at very low concentrations .

Equation (12) is a general isotherm function. The specific form depends on the units of the retention; unfortunately, no standard form exists for this. Common ways to report retention are,

• Mass Polymer / Mass Solid ** (more common)



• Mass Polymer / Surface Area

• Mass Polymer / Bulk Volume

• Mass Polymer / Pore Volume

Inaccessible Pore Volume

Offsetting the delay caused by retention is an acceleration of the polymer solution through the permeable medium caused by inaccessible pore volume (IPV). The most common explanation for IPV is that the smaller portions of the pore space will not allow polymer molecules to enter because of their size. Thus a portion of the total pore space is uninvaded or inaccessible to polymer, and accelerated polymer flow results.

IPV depends on polymer molecular weight, medium permeability, porosity, and pore size distribution and becomes more pronounced as molecular weight increases and the ratio of permeability to porosity (characteristic pore size) decreases. In extreme cases, IPV can be 30% of the total pore space.

Permeability Reduction

For many polymers, viscosity-shear-rate data derived from a viscometer (viscosity versus shear rate) and those derived from a flow experiment viscosity versus equivalent shear rate) will yield essentially the same curve. But for HPAM, the viscometer curve will be offset from the permeable medium curve by a significant and constant amount. The polymer evidently causes a degree of permeability reduction that reduces mobility in addition to the viscosity increase.

Permeability reduction is only one of three measures in permeable media flow (Jennings et al., 1971). The resistance factor RF is the ratio of the injectivity (mobility) of brine to that of a single-phase polymer solution flowing under the same conditions: either constant flow rate or constant pressure drop.

pw wF w app

p p w

kR

k

µ λ= = λ µ = λ µ

(13)



For constant flow rate experiments, RF is the inverse ratio of pressure drops; for constant pressure drop experiments, RF is the ratio of flow rates.

RF is an indication of the total mobility lowering contribution of a polymer. To describe the permeability reduction effect alone, a permeability reduction factor Rk is defined as

w wk F

p p

kR R

k

µ= = µ

(14)

A final definition is the residual resistance factor RRF, which is the mobility of a brine solution before (λwb) and after (λw a) polymer injection

wbRF

wa

Rλ

=λ

(15)

RRF indicates the permanence of the permeability reduction effect caused by the polymer solution.

RRF is the primary measure of the performance of a channel-blocking application of polymer solutions. For many cases, Rk and RRF are nearly equal, but RF is usually much larger than Rk because it contains both the viscosity-enhancing and the permeability-reducing effects.

Figure 13 shows some typical resistance factors measured by Core Labs on a commercial polymer. Note the viscoelastic effects at high injection rates.

The most common measure of permeability reduction is Rk, which is sensitive to polymer type, molecular weight, degree of hydrolysis, shear rate, and permeable media pore structure. Polymers that have undergone even a small amount of mechanical degradation seem to lose most of their permeability reduction effect. For this reason, qualitative tests based on screen factor devices are common to estimate polymer quality.



Figure 13 - Typical resistance factors for a commercial polymer (Core Lab, laboratory manual).

The screen factor device is simply two glass bulbs mounted into a glass pipette as shown in Figure 14. Into the tube on the bottom of the device are inserted several fairly coarse wire screens through which the polymer solution is to drain.



To use the device, a solution is sucked through the screens until the solution level is above the upper timing mark. When the solution is allowed to flow freely, the time required to pass from the upper to the lower timing mark td is recorded.

30 ml Timing Marks2R

h1

h2

Five 100 mesh screens0.25 inches in d iameter

Polymer Solutio n

Figure 14-Screen factor device.

The screen factor for the polymer solution is then defined as

dF

ds

tS

t= (16)

where tds is the similar time for the polymer-free brine.



Screen factors are particularly sensitive to changes in the polymer molecule itself. One definition of polymer quality is the ratio of the degraded to the undegraded screen factors. This use is important for screen factor devices, particularly in locations that prohibit more sophisticated equipment.

Chemical and Biological Degradation

The average polymer molecular weight can be decreased, to the detriment of the overall process, by chemical, biological, or mechanical degradation. We use the term chemical degradation to denote any of several possible processes such as thermal oxidation, free radical substitution, hydrolysis, and biological degradation.

For a given polymer solution, there will be some temperature above which the polymer will actually thermally crack. Although not well established for most EOR polymers, this temperature is fairly high, on the order of 260oF. Since the original temperature of oil reservoirs is almost always below this limit, of more practical concern for polymer flooding is the temperature other degradation reactions occur at.

The average residence time in a reservoir is typically very long, on the order of a few years, so even slow reactions are potentially serious. Reaction rates also depend strongly on other variables such as pH or hardness. At neutral pH, degradation often will not be significant, whereas at very low or very high pH, and especially at high temperatures, it may be. In the case of HPAM, the hydrolysis will destroy the carefully selected extent of hydrolysis present in the initial product.

To prevent biological reactions the following chemicals are used (commonly used bactericides)

• Acrolein

• Formaldehyde

• Sodium dichlorophenol

• Sodium pintachiorophenol

To prevent oxidation reactions the following chemicals are used



• Oxygen scavengers

• Hydrazine

• Sodium bisulfite

• Sodium hydrosulfite

• Sulfor dioxide

Oxidation or free radical chemical reactions are usually considered the most serious source of degradation. Therefore, oxygen scavengers and antioxidants are often added to prevent or retard these reactions. These chemicals are strong reducing agents and have the additional advantage of reducing iron cations from the + 3 to the +2 state. They, in turn, help prevent gelation, agglomeration, and other undesirable effects that can cause wellbore plugging and reduced injectivity.

Wellingnton (1980) found that alcohols such as isopropanol and sulfur compounds such as thiourea make good antioxidants and free radical inhibitors.

Biological degradation can occur with both HPAM and polysaccharides, but is more likely with the latter. Variables affecting biological degradation include the type of bacteria in the brine, pressure, temperature, salinity, and the other chemicals present. As in waterflooding, the preventive use of biocide is highly recommended. Often too little biocide is used or it is started too late, and the ensuing problems become almost impossible to correct.

Mechanical Degradation

High shear flow rates can break the linear chain and reduce apparent viscosity. The higher the salinity, the greater the susceptibility to shear degradation - with calcium solutions more sensitive than sodium.

Mechanical degradation is potentially present under all applications. It occurs when polymer solutions are exposed to high velocity flows, which can be present in surface equipment (valves, orifices, pumps, or tubing), downhole conditions (perforations or



screens), or the sand face itself. Perforated completions, particularly, are a cause for concern as large quantities of polymer solution are being forced through several small holes. For this reason, most polymer injections are done through open-hole or gravel-pack completions.

Figure 15 shows typical viscosity reductions using these two types of completions.

% V

isco

sity

Red

uctio

n

100

Maximum Shear Rate , 1/s100 1,000 10,000 100,000

Perforated hole

Openhole or Gravel Pack

50

% V

isco

sity

Red

uctio

n

100

Maximum Shear Rate , 1/s100 1,000 10,000 100,000

Perforated hole

Openhole or Gravel Pack

50

Figure 15 - Comparison of Viscosity reduction in different completions.

Partial preshearing of the polymer solution can lessen the tendency of polymers to mechanically degrade. Because flow velocity falls off quickly with distance from an injector, little mechanical degradation occurs within the reservoir itself.

All polymers mechanically degrade under high enough flow rates. But because of their ionic nature HPAMs are most susceptible under normal operating conditions, particularly if the salinity or hardness of the brine is high.



Polymer Injectivity

The economic success of all EOR processes is strongly tied to project life or injection rate, but polymer flooding is particularly susceptible. In many cases, the cost of the polymer itself is secondary compared to the present value of the incremental oil. Because of its importance, many field floods are preceded by single-well injectivity tests.

Lake (1989) gives a simple technique for analyzing injectivity tests based on the physical properties provided earlier.

The injectivity of a well (volumetric flow rate over pressure drop) is defined as

Pi

I∆

= (17)

where i is the volumetric injection rate into the well, and P∆ is the pressure drop between the bottom-hole flowing pressure and some reference pressure. Another useful measure is the relative injectivity

wr I

II = (18)

where wI is the water injectivity.

rI is an indicator of the injectivity decline to be anticipated when injecting polymer. Both

I and rI are functions of time, but the long time limit of rI for a Newtonian polymer

solution is simply the viscosity ratio if skin effects are small. However, the ultimate rI for

an actual polymer solution can be higher than this because of shear-thinning.



This treatment is limited to several simplifying assumptions as follows

• The well, of radius Rw, whose injectivity we seek, is in a horizontal, homogeneous, circular drainage area of radius Re.

• The pressures at Re, and Rw are Pe and Pwf , respectively. Pe is constant (steady-state flow), but Pwf can vary with time.

• The fluid flowing in the reservoir is a single aqueous phase, at residual oil saturation, which is incompressible with pressure-independent rheological properties.

• Dispersion and polymer adsorption are negligible although the polymer can exhibit permeability reduction.

• The flow is one-dimensional and radial.

Finally, the entire shear rate range in the reservoir lies in the power-law regime; hence Equation (7) describes the apparent viscosity.

Subject to these assumptions, the continuity equation in radial coordinates reduces to

( ) 0=rrudrd

(19)

where ur is the radial volumetric flux. This equation implies the volumetric rate is independent of r and equal to i since

rturHi π= 2 (20)

Equation (19) is a consequence of the incompressible flow assumption; however, i is not independent of time.

Let us substitute Darcy's law for ur

in Equation (20)



app

pr

kdrdP

uAi

µ−== (21)

using the definition of Rk

drdP

RuH

krHdrdPkrH

ik

nrpl

bt

app

pt

pl 122

−π−=

µπ

−= (22)

This equation has been defined so that i is positive.

Now replace appµ from Equation (7). The permeability reduction factor Rk is introduced

through to replace kp.

Eliminating ur yields an ordinary differential equation, which may be integrated between

the arbitrary limits of P1, r1 and P2, r2.

( )( )plplpl

nn

plb

kpln

trr

nkRH

Hi

PP−− −

−

π

=− 12

1112 12

(23)

The Newtonian flow limit kpl Rn == 1 and appplH µ= of this equation is the familiar

steady-state radial flow equation,

π

µ=−2

112 2 r

rHk

iPP

tb

b ln (24)



We now apply these equations to the polymer flood injectivity.

At some time tp during the injection, the polymer front (assumed sharp) is at radial position Rp where

( ) ( )pt

p w t oridt R R H S= π − φ −∫ 2 2

0

1 (25)

The left side of this equation is the cumulative volume of polymer solution injected. Therefore, Equation (23) applies in the region Rw < r < Rp, and Equation (24) applies in the annular region Rp < r < Re. With the appropriate identification of variables, we have for the second region

p

b eR e

b t p

i RP P ln

k H R

µ− = π 2

(26)

and for the first

( ) ( )plplpl

p

nw

np

plb

kpln

tRwf RR

nkRH

Hi

PP−− −

−

π

=− 11

12 (27)

where pRP is the pressure at the polymer-water front. Adding these two equations

gives the total pressure drop from Rw to Re.



( ) ( )pl

pl pl

nn npl k

wf e p wt b pl

b ew

b t p

H RiP P R R

H k n

i R ln s

k H R

− − − = − π −

µ+ + π

1 1

2 1

2

(28)

where SW, the intrinsic skin factor of the well, has been introduced to account for well damage.

Equation (28)substituted into the injectivity definition Equation (17) gives

( ) ( )

+

πµ+−

−

π

= −−−w

p

e

tb

bnw

np

plb

kpln

t

sRR

HkRR

nik

RH

Hi

I plplpl

ln212

111 (29)

The water injectivity Iw is evaluated from Equation (24) with r1 = Rw and r2 = Re.

This and I, yield an expression for Ir as it will be evaluated in an exercise.

Both I and Ir relate to the cumulative polymer solution injection (or to time).

Figure 16 Illustrates these two regions.



Figure 16 - Schematics of the regions used to evaluate injectivity in radial geometry.

Fractional Flow in Polymer Floods

The fractional flow treatment of polymer floods is the same as seen in the previous module (Here we will use a Polymer Flood software from DOE). The only major complications are the addition of terms for polymer retention and inaccessible pore volume (IPV).

Expected results are that:

1. The oil bank breakthrough time (reciprocal of the oil bank specific velocity) increases as the oil saturation increases, suggesting polymer floods will be more economic if they are begun at low initial water saturation. Of course, the

Ht

Re

Rp

Rw

Re

RpRw

Ht

Re

Rp

Rw

Re

RpRw



lower Sw, the higher the mobile oil saturation, also a favorable indicator for polymer floods.

2. Adsorption causes a delay of all fronts. This can be large if the porosity is low, the retention is high, or the injected polymer concentration is low.

3. Inaccessible pore volume causes an acceleration of all fronts, exactly opposite to retention. In fact, retention and IPV can exactly cancel so that the polymer front and the denuded water front travel at the same velocity.

Figure 17 indicates the laboratory procedures commonly used to screen polymer flood candidates.



Polymer Floods

Reservoir Rock Characterization

Crude Oil Characterization

Phase Behavior of Crude+Brine+Surfactant+

Cosurfactant (middle phase desired)

Polymer Buffer Selection

Micellar Adsorption

Core Displacement Studies to Define Sor

Microemulsion viscosity vs.Cosurfactantcomposition

& concentration

Thin Sections for Mineral Content

X-Ray for Clay Identification

SEM for Clay Location

Drainage Imbibition

Microemulsion Formulation

and Core Testing

Relative Permeability

Capillary Number

Water Permeability

Crude Oil Equivalent

Molecular Wt.

IFT Tests to Define

Equivalent Alkane Carbon No.

Waterflood core to residual oil

Inject micellarslug

Inject polymer

Polymer Floods

Reservoir Rock Characterization

Crude Oil Characterization

Phase Behavior of Crude+Brine+Surfactant+

Cosurfactant (middle phase desired)

Polymer Buffer Selection

Micellar Adsorption

Core Displacement Studies to Define Sor

Microemulsion viscosity vs.Cosurfactantcomposition

& concentration

Thin Sections for Mineral Content

X-Ray for Clay Identification

SEM for Clay Location

Drainage Imbibition

Microemulsion Formulation

and Core Testing


Capillary Number

Water Permeability

Crude Oil Equivalent

Molecular Wt.

IFT Tests to Define

Equivalent Alkane Carbon No.

Waterflood core to residual oil

Inject micellarslug

Inject polymer

Figure 17 - Laboratory screening procedures for designing a polymer flood.

Elements of a Polymer Flood Design

Polymer flood design is a complex subject. But most of the complexity arises from reservoir-specific aspects of a particular design. In this section, we deal in generalities that apply to all types of polymer flooding.



A polymer flood design procedure will follow the following steps.

Screen the candidate reservoirs The distinction between technical and economic feasibility is important. Technical feasibility means a given reservoir can be polymer flooded regardless of the funds available. Economic feasibility means the project has a good chance of being profitable. Technical feasibility screening parameters are only two: the reservoir temperature should be less than about 170 oF to avoid degradation, and the reservoir permeability should be greater than about

0.02 µm2 to avoid plugging. Economic feasibility can be estimated by simple hand calculations (as in the fractional flow method) or through using predictive models (Jones et al. 1984), which requires deciding how the polymer is to be used.

Decide on the correct mode of polymer use The choices are (a) mobility control (decrease M), (b) profile control (improve the permeability profile at the injectors or producers), or (c) some combination of both. We want to inject an agent that will alter the permeability so that more fluid will go into the tight rock than into the high-permeability rock. We can do this by using gels, polymers, and solids and by using selective perforation. When selective perforation is ineffective or incompletely effective, we use chemical agents or solids.

Select the polymer type. The requirements for EOR polymers are severe. An outline of the principal ones is as follows:

Good thickening. This means high mobility reduction per unit cost.

High water solubility. The polymers must have good water solubility under a wide range of conditions of temperature, electrolyte composition, and in the presence of stabilizer additives.

Low retention. All polymers adsorb on reservoir rocks to various degrees. Retention may also be caused by plugging, trapping, phase separation, and other mechanisms. Low is less than 20 µg/g.

Shear stability. During flow through permeable media, stress is applied to the polymer molecules. If this is excessive, they may me-chanically break apart or permanently degrade, resulting in less viscosity. HPAM is especially subject to shear degradation.



Chemical stability. Polymers, like other molecules, can chemically react, especially at high temperature and in the presence of oxygen. Antioxidants are used to prevent this

Biological stability. Both HPAM and polysaccharides can be degraded by bacteria, but the latter are more susceptible. Biocides are required to prevent this.

Good transport in permeable media. This means the ability to propagate the polymer through the rock intact and without excessive pressure drop or plugging. Good transport also means good injectivity and no problems with microgels, precipitates, and other debris. Obviously, no one polymer can universally meet these requirements for all reservoir rocks. Thus we must tailor the polymer to the rock to some extent. Some general guidelines are possible for minimum standards, but the ultimate criterion must be economics.

Estimate the amount of polymer required. The amount, the total mass in kilograms to be injected, is the product of the slug size, the pore volume, and the average polymer concentration. Ideally, the amount would be the result of an optimization study that weights the present value of the incremental oil against the present value of the injected polymer.

Design polymer injection facilities. Getting a good quality solution is, of course, important, but the cost of the injection facilities is usually small corn- pared to well and chemical costs. The three essential ingredients are mixing facilities, filtration, and injection equipment. The type of mixing apparatus depends on the polymer. For solid polymers, a skid-mounted solid mixer is required. Concentrates or emulsion polymers require somewhat less sophistication although the latter may require some emulsion breaking. Filtration largely depends on the success of the mixing, but ordinarily it is no more stringent than what is required by waterflooding. But if exotic and difficult filtration is required, the complexity and cost can become significant. Injection equipment is the same as that for Waterflooding. All surface and downhole equipment should be modified to avoid all forms of degradation.

Consider the reservoir. Little is required here beyond the usual waterflood considerations such as the optimal well pattern and spacing, completion



strategy. pattern allocation (balance), reservoir characterization, and allowable injection rates.

Optimal values of these quantities imply precise values that will result in the maximum rate of return on investment. Since several quantities are involved, it is usually not possible to perform optimizations on everything. Hence most of the parameters must be fixed by other considerations (such as striving for a target mobility ratio). But for the most sensitive quantities, optimization is required.

Micellar-Polymer Flooding

Most of this material is taken from Lake (1992).

An injected surfactant lowers interfacial tension (IFT) between oil and water, and thereby recovers the residual oil that normally remains after water flood. This is followed by polymer to efficiently displace the surfactant and mobilized oil. Most projects inject a surfactant slug, and the laboratory tests assist in formulation of the slug and the polymer solution to push it. Displacement tests furnish surfactant oil recovery data in the reservoir rock.

Mobility design and control is an essential part of field application. Without proper mobility, surfactant will finger through the oil bank formed, or polymer drive water will finger through the surfactant bank. Fingering reduces oil recovery.

Capillary forces due to large IFT between oil and water resist the externally applied viscous forces and cause the injected water to bypass the oil.

Micellar-Polymer (MP) flooding is the predominant EOR technique to lower the IFT. We have already seen that very low IFT’s, of the order of 1µN/m, are required to substantially lower the residual oil saturation. These very low IFT’s can be achieved by using highly surface active chemicals.

Recall that the competition between viscous forces and capillary forces was given by the capillary number.



The following figure illustrates laboratory recoveries as a function of the capillary number for two types of rock.

Figure 18 - Residual oil saturation as a function of Capillary Number and rock type.

Other names for the MP process are: detergent, surfactant, low tension, chemical, and microemulsion flooding. The difference with alkaline flooding is that the surfactant is injected, while in alkaline flooding it is generated in-situ.



MP is the most complex EOR process from the view point of alternatives involved in its design. In this section our emphasis is to present the fundamentals so that you can understand the basis for design and reasons for how it performs.

Figure 19 shows an idealized sketch of a MP sequence. The process can be applied when the oil production from waterflood is at the expense of very high water-oil ratios.

The sequence involves:

Preflush - Brine is injected to change (usually to lower) the salinity of the resident brine so that mixing with the surfactant will not cause to lower the interfacial activity. Preflushes can be as high at 100% of the floodable pore volume Vp of a reservoir. In some cases a sacrificial agent (cheap material) is added to minimize the surfactant retention in the rock.

Micellar-Polymer Slug - This volume, ranging from 5 to 20% Vp in field applications contains the main oil-recovery agent (the surfactant). Typical surfactant concentrations range from 1 to 20% on a volumetric basis. Among the types of MP slugs are: aqueous slugs A (surfactant dissolved in water), oleic slugs O (surfactant dissolved in oil) and variations between these two extremes. Other chemicals are necessary to design an optimum oil recovery. The nature and purpose of these chemicals will be discussed later.

Mobility Buffer - This fluid is a dilute solution of a water-soluble polymer and its purpose is to drive the MP slug and banked-up fluids to the production wells.

Mobility Buffer Taper - This consists of a volume of brine containing a concentration of polymer grading between the one of the mobility buffer at the front and zero at the back. The gradual concentration decrease mitigates the adverse mobility ratio between the mobility buffer and the chase water.

Chase Water - The objective of this is to reduce the costs of injecting polymer continuously. If the taper and mobility buffer have been designed properly, the MP slug will be produced before it is invaded by the chase water.



Chase Water


Slug Preflush

Mobility buffer

250-2500g/cm3

polymer

0-1% Alcohol

Stabilizers

Biocide

0-100% Vpf

Slug

1-20% Surfactant

0-5% Alcohol

0-5% Cosurfactant

0-90% Oil

Polymer

5-20% Vpf

Preflush



0-100% Vpf

Chase Water


Slug Preflush

Mobility buffer

250-2500g/cm3

polymer

0-1% Alcohol

Stabilizers

Biocide

0-100% Vpf

Slug

1-20% Surfactant

0-5% Alcohol

0-5% Cosurfactant

0-90% Oil

Polymer

5-20% Vpf

Preflush



0-100% Vpf

Figure 19 - Sketch of a Micellar-Polymer sequence.

The success of a MP flooding process depends upon meeting certain criteria.

First, the surfactant slug must be propagated in its interfacial active mode. This is accomplished through the chemical formulation steps.

Second, the amount of surfactant injected mus t be enough to overcome the retention by the porous media. This is accomplished by using some sacrificial agents, scale-up studies, laboratory experiments, and numerical simulation.

Third, the MP displacement must be designed such that dissipation due to dispersion and channeling are minimized.

Surfactants Used

To understand the role of the surfactants in MP flooding, we will define their physical properties, how they affect phase behavior, and how phase behavior and interfacial tension are correlated.



Molecular Structure

A typical surfactant monomer is composed of a polar (hydrophilic) portion, and a non-polar (lypophilic) portion. The entire monomer is sometimes called amphiphile because of this dual nature.

Surfactants are classified in 4 groups based on their polar groups. These are:

Anionics: The monomer is associated with an inorganic metal (a cation, which is usually sodium). In an aqueous solution the molecule dissociates into free cations (positively charged), and the anionic monomer (negatively charged). The solution is electroneutral, which means positive and negative charges balance. Anionic surfactants are the most common in MP flooding because they are good surfactants, relatively resistant to retention, stable, and can be made relatively cheap.

Cationic: In this case the surfactant molecule contains a an inorganic anion to balance the charge. In solution it ionizes into a positively charged monomer, and the anion. Cationic surfactants are highly adsorbed by clays and therefore have not much use in MP flooding.

Non-ionic: This class of surfactant does not have ionic bonds, but when dissolved in aqueous solutions, exhibits surfactant properties mainly by electronegativity contrasts among its constituents. Non-anionic surfactants are much more tolerant to high salinities than anionic, but they are poorer surfactants. The non-ionic surfactants are used extensively in MP floods mainly as co-surfactants.

Amphoteric: This class of surfactant has not been used in oil recovery. They contain aspects of two or more of the previous classifications.

Table 1 contains ranges where MP has been applied.



Property Range

Depth [ft] 350 - 4550 (107 - 1387 m)

Reservoir Temperature [ºF] 55 - 200 (12.8 - 93 ºC)

Porosity [%] 13 - 32

Permeability [md] 7 - 300+ {avg.}

Type of Reservoir Unconsolidated to well cemented

sandstones, limestones

Formation Water [ppm TDS] 3000 - 160,000 (3000 - 160,000

mg/kg)

Hardness [ppm Ca, Mg, Fe] 25 - 5000 (25 - 5000 mg/kg)

Crude Gravity [ºAPI at 60ºF] 15 - 45 (0.965 - 0.801 g/cm3)

Crude Viscosity [cp] 3 - 31.7 (3 - 31.7 m Pa*s)

Crude Type Aromatic-Paraffinic-Naphtenic

Table 1 - Range of oil field characteristics to which microemulsion flooding has been applied.

Figure 20 shows some examples of these surfactants.



S O-Na+

O

O

R

(b) Texas No. 1 sulfonate

S O-Na+

O

O

CC

CC

CC

CC

CC

CC

CC

C

C

(a) Sodium dodecyl sulfate

O

CC

CC

CC

CC

CC

CC

O S O-Na+

O

- x

+ -+ x

+ -

Anionics Cationics Noionics Amphoterics

Sulfonates, Sulfates,

Carboxylates, Phosphates

Quaternary ammonium organics, pyridinum,

imidazonlinium, piperidinium, and

sulfononium compounds

Alkyl-, alkyl- aryl-, acyl-, acylamindo-

acyl- aminepolyglycol, and polyol ethers

Aminocarboxylic acids

Figure 20 - Examples of surfactants for the different classifications. (Taken from Lake, 1992).

The following Table shows some typical properties of commercial sulfonates. Typical molecular weights range from 350 to 450 kg/kmole. Lower MW has better water solubilities. Part of the purchased surfactant is inactive in the sense that may contain impurities for example unreacted oil from the sulfonation step and water from the neutralization. In same calculations the concentration of surfactant is expressed at Equivalent weights (which is the Mw/charge – i.e. number of polar active sites).



Table 2 - Properties of commercial surfactants (from Lake, 1992).

Critical Micelle Concentration

If an anionic surfactant is dissolved in an aqueous solution the surfactant dissociates into a cation and a monomer. If the surfactant concentration is increased, the lypophilic portions (moieties) of the surfactant begin to cluster among themselves to form aggregates, or micelles, containing several monomers each. A plot of the surfactant monomer concentration versus the total surfactant concentration, as indicated in Figure 21, shows a curve that begins at the origin, increases monotonically with init slope, then levels off at the so called critical micelle concentration CMC. Above the CMC, all further increases in surfactant concentration cause increases in the micelle concentration only. CMC’s are typically small, and the surfactant in oil applications is in the micellar state. That is the reason of the name Micellar flooding. Typical CMC values are

10-5 – 10-4 kg-mol/m3. And the size of the micelles is 10-4 to 10-6 mm.



Monomers

Micelles

Total Surfactant Concentration

Su

rfac

tan

t Mo

no

mer

C

on

cen

trat

ion


(CMC)

MonomersMonomers

Micelles

Total Surfactant Concentration

Su

rfac

tan

t Mo

no

mer

C

on

cen

trat

ion


(CMC)


(CMC)

Figure 21 - Surfactant monomer concentration versus total surfactant concentration.

When the surfactant solution contacts an oleic phase, the surfactant tends to accumulate at the interface. The lypophilic tail “dissolves” in the oil phase, and the hydrophilic end “dissolves” in the aqueous phase. The surfactant prefers the interface over the micelle. Now it becomes clear the purpose of the dual nature of the surfactant since its accumulation at the interface will lower the IFT between the oleic and the aqueous phase. This interface blurs in the same manner as as do interfaces in vapor-liquid-equilibrium (VLE) near a critical point. We need to design the surfactant to maximize the solubility in this interface, however brines affect greatly the surfactant behavior. Therefore we need to analyze the interactions surfactant-oil-brine. Depending on the salinity, micelles may form either with water or oil as the external phase as indicated in Figure 22.



Surfactant-Brine-Oil Phase Behavior

Here we use a ternary diagram to indicate this behavior as indicated in Figure 23. Conventionally the surfactant is indicated at the top of the diagram, the lower left indicates the brine, while the lower right indicates the oil. Following Lake’s (1992) nomenclature we associate numbers to the phases and species, as indicated in Table 3.

WATER

WATER

OIL

OIL WATER(O)

MOLECULARDISPERSION

IN OIL

(W)

MOLECULARDISPERSIONIN WATER (S1)

WATEREXTERNAL

(S 2)

OILEXTERNAL

Figure 22 - Different types of micelles structures.



Figure 23 - Conventional representation of surfactant/oil/brine phase behavior. Salinity is fixed.

i Species Concentration Unit j Phase

1 Water Volume Fraction 1 Aqueous

2 Oil Volume Fraction 2 Oleic

3 Surfactant Volume Fraction 3 Microemulsion

4 Polymer Weight percent or g/m3

Table 3 - Numbering of phases and species according to Lake, 1992.



Type II (-) Behavior

At low brine salinity, a typical MP surfactant will exhibit good aqueous phase solubility and poor oil phase solubility. Therefore, an overall composition near the brine -oil boundary of the ternary plot will split into two phases: an excess oil phase which is essentially pure oil, and a water external microemulsion phase that contains brine surfactant, and some solubilized oil. This oil occupies the central core of the swollen micelles. The tie lines within the two-phase envelope have a negative slope. The plait point PR in this system is located closer to the oil apex. Any overall composition above this envelope (also called binodal curve) is a single phase (all components are miscible). Figure 24 is an schematic representation of this type of behavior.



Figure 24 - Schematic representations of the Type II (-) system, from Lake, 1984.

Type II (+) Behavior

For high brine salinities, electrostatic forces decrease the surfactant solubility in the aqueous phase drastically. An overall composition within the two-phase region will now split into an excess brine phase and a microemulsion phase (oil external) which contains most of the surfactant and some solubilized brine. The brine is solubilized through the formation of inverted swollen micelles, with brine globules at their cores.



The plait point PL, is now located closer to the brine apex. The tie lines here have a positive slope. Figure 25 illustrates this concept.

Figure 25 - Schematic representation of high-salinity type Ii (+) system, from Lake 1984.

Type III Behavior

At intermediate salinities there must be a continuous change between Type II (-) and Type II (+) systems. The intuitive change of a plait point migration to the top and



horizontal tie lines is incorrect. There is no salinity for which the solubilities of the surfactant for the brine-oil and oil-rich phases are exactly the same. What occurs under these conditions is the formation of three phases (therefore the name Type III).

An overall concentration within the three phase region separates into excess oil and brine phases as in Type II (-) and Type II(+) environments, and into a microemulsion phase whose composition is represented by an invariant point. Now there are two IFT’s

between the microemulsion and the oil ( )moγ and between the microemulsion and the

brine ( )mwγ . Figure 26 illustrates this behavior.



Figure 26 - Schematic representation of optimal-salinity type III system, from Lake, 1984.

Figure 27 illustrates the three types of behaviors just described.



Figure 27 - Simplified version of phase diagrams for a microemulsion system.

Changes in Phase Environments

Figure 28 shows the entire progression of phase environments from Type II (-) to Type II (+), over the type III salinity range. The invariant point M migrates from near the oil apex to near the brine apex before disappearing at the critical tie line. As the migration takes place, the surfactant concentration in the microemulsion phase goes through a minimum, where the brine-oil ratio at the invariant point becomes one. Type III environments are those at which all the IFT’s are the lowest.

There are parameters other than salinity that which can cause phase environment shifts. In general, changing any condition that enhances the surfactant’s oil solubility will cause a shift from type II (-) to type II (+). Some of these include

• Decreasing the temperature

• Increasing the surfactant molecular weight

• Decreasing the oil specific gravity

• Increasing the concentration of high molecular weight alcohols.



Decreasing the surfactant’s oil solubility will cause the reverse change.

Figure 28 - Pseudoternary or 'tent' diagram representation of micellar-polymer phase behavior, from Lake, 1984.

Phase Behavior and IFT’s

IFT’s vary with the types and concentration of surfactant, co-surfactant, electrolytes, oil, polymer, and temperature. However, one of the most significant advances in MP technology is that all IFT’s correlate directly with the MP phase behavior. One of the biggest advantages of this is that difficult measurements of IFT’s can be supplanted by easier phase behavior measurements.

Solubilization Parameters

Lake (1992) defines the volume fractions of oil, brine, and surfactant in the

microemulsion phase as: swo VVV ,, respectively. The solubilization parameters

between the microemulsion-oleic phase for type II(-) and type III behavior, and between the microemulsion-aqueous phases for type II (+) and type III are defined as.



s

omo V

VS = or

33

23

CC

(30)

and

s

wmw V

VS = or

33

13

CC

(31)

The IFT’s between the corresponding phases are only functions of theses solubilization parameters. Other nomenclatures in use, particularly by Lake (1992), are introduced here to understand the following figures taken from his book.

He uses two numbered subscripts one defines the component and the other the phase.

For example

ijC

componenti =

phasej =

as indicated in Table 3: (1) stands for aqueous phase and brine, (2) stands for oleic phase and oil, and (3) stands for surfactant and microemulsion.

The solubilization parameters are defined as the ratios indicated in the following figure



Figure 29 - Correlation of solubilization parameters with interfacial tensions (from Glinsmann, 1979; and Lake, 1992).

Optimal Salinity

The behavior of the IFT’s versus salinity is indicated in Figure 30 to Figure 35.

The optimum salinity is when both IFT’s are at its minimum, and this is normally achieved for type III behavior. Since optimal phase behavior salinity translates into a maximum oil recovery, the objective is to design the proper slug-brine-surfactant formulation that will achieve this salinity insitu. Dilution effects and adsorption must be taken into account as well.



Unfortunately, for most commercially attractive surfactants in most MP candidate reservoirs, the optimal salinity is lower than the resident brine salinity. Optimal salinities can be raised by adding to the slug any chemical, a co-surfactant, which increases the primary surfactant’s brine solubility. The addition of co-surfactants to the MP slug normally increases the optimal IFT as well.

Figure 30 - Interfacial tensions and solubilization parameters (from Reed and Healy, 1977; and Lake, 1992).



Figure 31 - Correlation of phase volume and IFT behavior with retention and oil recovery (from Glinsmann, 1979; and Lake, 1992).



Figure 32 - Phase volume diagrams (salinity scans) at three water-oil ratios (from Englesen, 1981).



Figure 33 - Microemulsion as a function of salinity (from Jones, 1981).



Figure 34 - Schematic diagram of the effect of increasing salt concentration on phase volumes of multiphase microemulsion system.



Figure 35 - Interfacial tension versus salinity for multiphase microemulsion system.

The velocity of the microemulsion can be tailored by proper additions of alcohols (or co-surfactants). Figure 36 and Figure 37 show the effect of alcohol concentration upon viscosity.



Figure 36 - Viscosity of a microemulsion composed of 12 vol. % petroleum sulfonate, 24.9 vol. % water, and 63.1 vol. % hydrocarbon versus added cosurfactant, isopropyl alcohol.



Figure 37 - Viscosity and stability limits of a microemulsion composed of 11.7 vol. % petroleum sulfonate, 65.5 vol. % water, and 22.8 vol. % hydrocarbon versus added cosurfactant, p-hexanol or p-pentanol.

Surfactant Retention

Surfactant retention is probably the most significant barrier to the commercial application of MP flooding . The surfactant should be designed for good selectivity to the oil/water interfaces, but poor selectivity to the fluid/solid interfaces.

Some possible mechanisms that explain the retention of surfactants in the rock include:

1. Adsorption on metal oxide surfaces. While the surfactant concentration is lower than the CMC it will adsorb through hydrogen bonding and ionic bonding to cationic surface sites.

2. Hard brines cause the formation of surfactant-divalent complexes that have low solubility in brine. These complexes precipitate out of solution causing retention. However, when the surfactant encounters the oil phase this effect is lessened due to the solubility of the surfactant in the oleic phase.



3. In reservoirs that contain clays the surfactant can exchange the cations with the clays and become attached to the surface. The addition of co-surfactants reduces the density of surfactant molecules at the surface.

A useful way to estimate the volume of surfactant required for a MP slug is defined by Lake (1992).

ρρ

φ

φ−=s

s

s

rs C

aD

1 (32)

where as is the surfactant retention in mg/g, φ is the porosity, Cs is the surfactant

concentration in the MP slug, and rρ and sρ are the rock and surfactant density

respectively.

Ds expresses the volume of surfactant retained at its injected concentration as a

fraction of the pore volume Vp.

For optimal surfactant usage, the volume of surfactant injected should be large enough

to contact the entire Vp, but small enough to prevent excessive production of the

surfactant. Besides wasting an expensive chemical, this could lead to severe production of emulsions.

According to Lake (1992), the MP slug size should be equal to or a little bit larger (5-

10%) than Ds. The volume of surfactant needed is the product of the slug size and the

surfactant concentration.

Screening Tests for Micellar-Polymer Floods

Screening tests for micellar-polymer suitability vary. The laboratory test sequence should culminate in reservoir condition floods (or reservoir temperature floods) using the formulated surfactant and polymer to measure oil mobilized and displaced.

Crude Oil Characterization Tests

Crude oil acid number, equivalent molecular weight and equivalent alkane carbon number (EACN) are determined. The EACN identifies the crude oil (which is a complex



mixture of hydrocarbons) as having equivalent behavior to a single pure component such as hexane or octane in the presence of surfactants. Knowing the pure component which matches crude oil behavior yields access to correlations which assist in selecting surfactants and co-surfactants to mix with the crude oil and water to form stable microemulsion slugs. Interfacial tension measurements are part of the EACN evaluation.

Microemulsion Formulation Tests

Complex theories exist to assist in formulations. Reservoir oil and brine are mixed with surfactant and co-surfactants in bench tests to identify stable microemulsions that exhibit middle phase (or Type III) behavior. Brine salinity is varied and oil and water solubility in the middle phase is observed to define optimum formulation.

The co-surfactant concentration is varied to adjust microemulsion viscosity. In some systems polymer is added to adjust slug viscosity.

Mobility Control Polymer Tests

Measured data include viscosity, screen factors (for polyacrylamides) and filtration tests (for polysaccharides), injectivity behavior, and mobility (Resistance Factors) in the formation rock as a function of polymer concentration and rate.

Analyses of formation water, polymer make up water, and drive water are required. Polymer compatibility with these waters as well as with the microemulsion slug must be evaluated.

Rock Property Tests

The lithology of reservoir rock influences surfactant floods. Sandstone reservoirs are the best candidates. Limestones are poor as they adsorb excessive surfactant. Anhydrite (CaSO4) associated with carbonates can increase the calcium content in flood waters and reduce surfactant and polymer effectiveness.

Clays exhibit cation exchange capacity and act as ionic exchange media causing rock-water reaction and reduced injectivity. Calcium and magnesium released from clays to the flood water reduce surfactant effectiveness. Surfactants are also more readily adsorbed on high surface area clays than on normal silica surfaces, and loss varies with clay type.



Sacrificial agents such as sodium carbonate, sodium silicate in a high pH (>10) solution, or certain organic compounds have been proposed to reduce surfactant absorption - and have been supported by laboratory tests.

X-ray, thin section and SFM tests identify rock minerals (including clays) and location; rock-water sensitivity tests and relative permeability data are needed for mobility design of the micellar flood.

Core Floods

Micellar fluids and polymer drive slugs are injected in radial or linear flood tests. Initial tests are made on Berea sandstone, with final evaluation utilizing actual reservoir rock at reservoir temperature.

Cores are water flooded to residual oil, and selected micellar and polymer fluids are subsequently injected to define increased oil recovery and reduced residual oil.

The example illustrates the increase in oil cut in the produced fluids following surfactant injection, and the tertiary oil recovery as a percentage of residual oil-in-place.

The following figure illustrates the sequence of tests performed to design a MP flood



Surfactant-PolymerFloods

Reservoir RockCharacterization

Crude OilCharacterization

Phase Behavior ofCrude+Brine+Surfactant+

Cosurfactant (middlephase desired)

Polymer BufferSelection

Micellar Adsorption

Core DisplacementStudies to Define Sorr

Microemulsionviscosity vs.Cosurfactantcomposition

& concentration

Thin Sections forMineral Content

X-Ray for ClayIdentification

SEM for ClayLocation

Drainage Imbibition

MicroemulsionFormulation

and Core Testing


Capillary Number

Water Permeability

Crude OilEquivalent

Molecular Wt.

If Tests to DefineEquivalent Alkane

Carbon No.

Waterflood coreto residual oil

Inject micellarslug

Inject polymer



Alkaline Flooding

Alkaline flooding, is a high pH chemical EOR method which has many similarities with micellar flooding. The difference is that in micellar flooding the surfactant is injected, while in alkaline (or caustic) flooding the surfactant is generated in situ.

High pH’s indicates large concentrations of the hydroxide anions OH

C − . The pH of an

ideal aqueous solution is defined as

( )HpH log C += − (33)

where the concentration of protons (hydrogen ions) is expressed in kg-moles/m3. A pH of seven is neutral, lower than that is acid and higher than that is alkaline. As the

concentration ofOH

C − increases, the concentration of H

C +

must decrease since the two are related through the dissociation of water

OH Hw

H O

C Ck

C− +

=2

(34)

and the water concentration in an aqueous phase is nearly constant. This illustrates that there are two methods of increasing the pH of a reservoir:

(1) By dissociation of a hydroxyl containing species such as NaOH, or KOH.

(2) By adding chemicals that will bind withH

C +

Many chemicals could be used to generate high pH’s, but the most common are: sodium hydroxide, sodium carbonate, ammonia, and sodium orthosilicate. Sodium



hydroxide or sodium carbonate dissociate in water generating OH

C − according to the

following dissociation reactions:

−−

−

+⇔+

+⇔

OHCOHOHCO

NaCOCONa

22

2

3222

3

2332

(35)

−+ +⇒ OHNaNaOH (36)

The single sided arrow in the last reaction indicates that the reaction is favored to the right. While two sided arrows indicate that the reaction is reversible. That means the reaction could go either way depending upon the pH.

High-pH chemicals have been used in field applications in concentrations of up to 5 wt % (injected pH’s 11 to 13) and with slug sizes of up to 0.2 PV.

Surfactant formation

OH- by itself is not a surfactant since the absence of a lypophilic tail makes it exclusively water soluble. However, if the oil contains acidic hydrocarbon components (HAo), some of it may partition into the aqueous phase as indicated in Figure 38.



OIL

ROCK

M

H

NaOH

H2O

H2O

HAoOH-

Na+ A-

HAo

HAw A- + H+

OIL

ROCK

M

H

NaOH

H2O

H2O

HAoOH-

Na+ A-

HAo

HAw A- + H+

Figure 38 - Schematic of alkali recovery process.

We assume that the acid species in the oil is represented by a generic single component named HAo. This acid component will not be soluble in an aqueous phase with neutral pH (i.e., 7). However if the pH is increased with a caustic solution the acid will be extracted from the oil to the aqueous phase.

The exact nature of the acidic component is unknown, but it is probably highly dependent on the crude oil type. The deficiency of protons (high PH) in the aqueous phase will promote the chemical reactions to the right. The anionic species A- is a surfactant with many of the properties described in MP flooding.

If no acidic species are present in the crude, no surfactant can be generated. Therefore to determine the oil characteristics needed for alkaline flooding we must characterize its acidity. The attractiveness of an oil for alkaline flooding is given by its acid number.

The acid number is the milligrams of potassium hydroxide (KOH) needed to neutralize one gram of crude oil. To make this measurement, the crude oil is extracted with water until the acidic species HAo is removed. The aqueous phase is then brought to neutral pH=7 by adding KOH.

For a meaningful value, the oil must be free of acidic additives such as corrosion inhibitors and acidic gases such as H2S and CO2.



A good alkaline flooding candidate will have an acidic number of 0.5 mg/g or greater.

Displacement Mechanisms

We postulate that the following dissociation reactions may take place with sodium hydroxide

oHA NaOH NaA H O+ ⇔ + 2 (37)

NaA Na A+ −⇔ + (38)

where A- is a surface active ingredient.

The following reaction represent the extraction of the acidic component from the oil phase into the aqueous phase.

o wHA HA⇔ (39)

The concept is analogous to vapor-liquid-equilibria.component distribution. The susbscripts o and w indicate that the acidic component partitions into the oleic and aqueous phase respectively. A material balance for the acidic component HA, must take into account the quantities present in the oil phase and in the aqueous phase. If the pH of the aqueous media is high, this partition will be more favored to the aqueous phase.

The acid distribution between oil and water phases can be quantified through the distribution coefficient (analogous to k-values).

o

w

HAD

HA

Ck

C= (40)



This coefficient is a measure of the solubility of acid in the water phase.

Once the acidic component is in the aqueous solution it may hydrolyze (decompose in water phase) as indicated by the following equation

wHA H A+ −⇔ + (41)

The extent of this dissociation is determined by the acid dissociation constant

w

H AA

HA

C Ck

C+ −

= (42)

This constant controls the pH range for which the surfactant hydrolysis occurs.

Our objective is to find out what is the concentration of the surfactant component in the aqueous phase and see how this surfactant concentration may alter the fractional flow curve.

To do this we use the dissociation constants (Equations,(40) and (42)), the water dissociation constant, and the electro neutrality condition.

Since water concentration is essentially constant, the water dissociation constant can be expressed as.

w w H O H OHk k ' C C C+ −= =

2 (43)

The electro neutrality condition states that positive and negative charges must balance

Na H A OHC C C C+ + − −+ = + (44)



Using the equations described above we find an analytical expression to evaluate the surfactant concentration (Equation (45)). This is left as an exercise.

o

o o

w HANa NaA

HA HA

k CC CC

k k kC C

+ +

−

= + + + +

2

412 1 1

(45)

where

D w

A

k kk

k= (46)

At high pH, the concentration of acidic species in the oil phaseoHAC is very small and

the concentration of protons may be neglected in the electroneutrality condition expressed in Equation (44)- Thus Equation (45) can be simplified and the following expression results

o

NaA

HA

CC

kC

+

− =+1

(47)

Therefore, to determine the concentration of surfactant in the aqueous phase we need to have values, either experimental or theoretical, for the distribution constants

( )D w Ak ,k ,k .

You can show that k is the inverse of the overall equilibrium constant of Equation (37).



Some typical values for these dissociation constants are,

wk mol / liter−= × 145 10

Dk = 410

Ak mol / dm−= 10 310

These constants depend upon temperature.

In addition to the liquid reactions (oil/alkali), we may find reactions between the rock and the caustic species. The hydroxyl can interact with the rock in several ways depending upon its mineralogy. For example silicates may dissolve irreversibly, and we may have precipitation of insoluble solids, although we will not consider these rock dissolution effects to simplify the model. However, we cannot ignore mineral-base exchange sites which may have dramatic consequences.

A typical chemical reaction taking place at Liquid-Solid interface is the Na+/H+ reversible exchange

( ) ( )M H Na OH MNa H O+ −+ + ⇔ + 2 (48)

This exchange causes NaOH retention. Figure 39 shows the time Bτ expressed in pore

volumes for caustic to elute from a Wilmington sand core at various injection caustic concentrations. It can be observed that lower injected caustic concentrations (low pH) take longer to breakthrough the core. These predictions have been verified experimentally.



0

2

4

6

8

10

12

14

10 11 12 13 14

pH

τB, P

ore

Vol

umes

Calculated NaOH breakthrough T = 52.5 oC NaCl = 1% (wt)

0

2

4

6

8

10

12

14

10 11 12 13 14

pH

τB, P

ore

Vol

umes

Calculated NaOH breakthrough T = 52.5 oC NaCl = 1% (wt)

Figure 39 - Time ( Bτ ) in PV for caustic to breakthrough as a function of pH for

Wilmignton sands.

Displacement Model

The chemical reactions taking place between oil and alkali can be incorporated into a displacement model. The assumptions here are:

• Model a linear, homogeneous porous medium

• Temperature is constant

• Uniform initial saturation and composition

• Mobile, immiscible, and incompressible oil and water phases

• Local and instantaneous equilibrium

• Negligible dispersion and capillary pressure forces

• Stable displacement front without viscous fingering

• No emulsion formation



• Continuous alkali injection

We have 6 unknowns and two liquid phases (oleic and aqueous) and three equilibrium relation constants.

These unknowns are,

o wHA ,HA , A ,Na ,OH ,H− + − +

Define a dimensionless time and a dimensionless distance as

Dimensionless time à utL

τ =φ

Dimensionless distance à Lχ

χ =%

Local conservation of water demands,

w wS f∂ ∂= −

∂τ ∂χ% (49)

and a local sodium ion balance is

( ) ( ) ( )w wNa Na NaS C n f C+ + +∂ ∂ ∂ − φ+ = − ∂τ φ ∂τ ∂τ

1 (50)

The sodium ion exists in the aqueous phase, where their accumulation and convection must be accounted for. Additionally, the ions exchange with the rock as indicated in Figure 38.



The relation

[ ]Na OH

moles absorbedn n

solid rock volume+ −

−= =

− − (51)

gives the adsorption amount of sodium or hydroxide in moles per solid-rock volume. For the local equilibrium assumption, we have that sodium interchange with rock

( )Na OH Na

OH

n n C

C+ − +

−

∂ ∂ ∂= ⋅ ∂τ ∂ ∂τ

(52)

The exchange isotherm for caustic is concave to the abscissa, thus a shock front will develop when injecting alkali. The concentration velocity of this shock is regulated by the isotherm chord and it is represented by a pore volume delay parameter.

OH

OH

n

C−

−

− φα = ⋅ φ

1 (53)

A differential material balance for the acid species is

( ) ( )

( ) ( )

w o

w o

w HA w HAA

w HA w HAA

S C C S C

f C C f C

−

−

∂ + + − = ∂τ∂ − + + − ∂χ

1

1%

(54)



To respond to the question of how does the A- generated influence fw, this is

accomplished by altering the residual oil saturation.

The following model can be proposed to describe the change in orS with A

C −

AOr

CS c c exp

c−

= + −

1 23

(55)

where the constants are determined experimentally.

The following graph illustrates the change in residual oil saturation using certain values for the constants c1 to c3.

0.0

0.1

0.2

0.3

0.4

0.00 0.02 0.04 0.06 0.08 0.10

CA- [mol/dm3]

Sor

Sor(CA-) = c1 + c2 exp(-CA- / c3)

c1 = 0.05c2 = 0.35c3 = 1.18 x 10-3

mol/dm3

Figure 40 - Assumed variation of residual oil saturation with surfactant concentration.

To draw the fractional flow curve we may propose the following relative permeability models



( )w w

o o

o nr r

Por r

k k S

k k S

=

= −1 (56)

where

w wc

or wc

S SS

S S−

=− −1

(57)

Figure 41 shows the effect of a given alkali concentration in the fractional flow curve. The power indexes for the water and oil relative permeability have been taken as 2 and 2.5 respectively.

0

0.2

0.4

0.6

0.8

1

0 0.2 0.4 0.6 0.8 1Sw

f w

Alkaline FloodCA- = 5.5(10-4) mol/dm3

WaterfloodCA- = 0

Swc1-Sor(CA-)

Figure 41 - Fractional flow for a waterflood and an alkaline flood.



Displacement Calculations

This section outlines the procedure to make displacement calculations, and shows the results obtained for the proposed model. A detailed explanation can be found in deZabala et al. (1982).

There are 3 PDE 's (water, sodium, and acid balances) which are solved by using the coherence technique which transforms PDE's to algebraic equations

Suggested reading on this topic are the papers by Helfferich, SPEJ, February, 1981 and by Hirasaki, SPEJ, April, 1981

Figure 42, and Figure 43 show the saturation and chemical profiles for an alkaline flood at two different times.

Sw

0.8

0.6

0.4

0.2

1312111098

pH

0.0 5.0 1.0χ~

τ = 0.25 PVM = 2.0pH = 12.75α = 1.5

( )82mol/dm050 3 ..=oHAC

( ) 34 mol/dm 1055 −=− .A

C

1-Sor(CA-)SR

WaterfloodSw

0.8

0.6

0.4

0.2

1312111098

pH

0.0 5.0 1.0χ~

τ = 0.25 PVM = 2.0pH = 12.75α = 1.5

( )82mol/dm050 3 ..=oHAC

( ) 34 mol/dm 1055 −=− .A

C

1-Sor(CA-)SR

Waterflood

Figure 42 - Saturation and chemical profiles for a secondary alkaline flood at τ = 0.25 PV of displacement.



0.15

0.35

0.55

0.75

0.0 0.2 0.4 0.6 0.8 1.0χ

Sw

τ = 5.0 PVM = 2.0pH = 12.75α = 1.5

WaterfloodOH-

CHAo = 0.05 mol/dm3 (2.8)

CA- = 5.5(10-4) mol/dm3

1312111098

pH

Figure 43 - Saturation and chemical profiles for a second alkaline flood at τ= 5 PV.

Additional References for Module 6

Akstinat, M.H., "Surfactants for EOR Process in High-Salinity Systems, Product Selection and Evaluation”, "Enhanced Oil Recovery”, Elsevier Scientific, New York, New York, 1981.

Bragg, J.R., Gale, W.W., McElhannon, W.A., Davenport, O.W., "Loudon Surfactant

Flood Pilot Test," SPE 10862, presented at the Third Society of Petroleum Engineers Symposium on EOR, Tulsa, Oklahoma, 1982.



Bunge, A.L., and Radke, C.J. "Migartion of Alkali ne Pulses in Reservoir Sands," SPEJ, Vol 22, (December 1982), 998-1012.

Clampitt, R.L., and Reid, T.B., "An Economic Polymerfood in the North Burbank Unit, Osage County, Oklahoma," SPE 5552,presented at the 50th Annual Fall Technical Conference and Exhibition of the SPE, Dallas, Texas, Sept. 28, Oct.1, 1975.

DeZabala, E.F, Vislocky, J.M, Rubin, E., Radke, C.J., "A Chemical Theory for Linear Alkaline Flooding" SPEJ, April 1982 pp 245-258.

GIinsmann, G.R., "Surfactant Flooding with Microemulsions Formed In-situ - Effect of Oil Characteristics," SPE 8326, presented at the Society of Petroleum Engineers 5th Annual Technical Conference and Exposition, Las Vegas, Nevada, 1975.

Glover, C.J., Puerto, M.C., Maerker, J.M., and Sandvik, E.I., "Surfactant Phase Behavior and Retention in Porous Media," Society of Petroleum Engineers Journal, 19, (1979) 183-193.

Gogarty, W.B., Meabon, H.P., and Milton, H.W., Jr., "Mobility Control Design for Miscible-type Waterfloods Using Micellar Solutions," Journal of Petroleum Technology, 22, (1970), pp 141-147

Graue, D.J. and Johnson, C.E., "Field Trial of Caustic Flooding Process," JPT, (December 1974). Pp 1353-1358.

Gupta, S.P., "Compositional effects on displacement mechanisms of the micellar fluid injected in the Sloss Field Test," SPE 8827, presented at the First Joint Society of Petroleum Engineers/Department of Energy Symposium on Enhanced Oil Recovery, Tulsa, Oklahoma, 1980.



Healy, R.N., and Reed, R.L., "Physiochemical Aspects of Microeumulsion Flooding,"

Society of Petroleum Engineers Journal, 14, (1974) pp 491-501.

Healy, R.N., and Reed, R.L., and Stenmark, D.G., "Multiphase Microemulsion Systems," Society of Petroleum Engineers Journal, 16, (1976) 147-160.

Hirasaki, G.J., and Pope, G.A., "Analysis of Factors Influencing Mobility and Adsorption in Flow of Polymer Solution through Porous Media," Society of Petroleum Engineers Journal, 14, (1974) pp.337-346.

Holm, L.W., "Design, Performance and Evaluation of the Uniflood Micellar-Polymer Process- Bell Creek Field," SPE 11196, presented at the 57th Annual Fall Technical Conference and Exhibition of the Society of Petroleum Engineers, New Orleans, Louisiana, 1982.

Jennings, R.R., Rogers, J.H., and West, T.J., "Factors Influencing Mobility Control by Polymer Solutions," Journal of Petroleum Technology, 23, (1971) 391-401.

Maerker, J.M., "Mechanical Degradation of Partially Hydrolyzed Polyacrylamide Solutions in Unconsolidated Porous Media," Society of Petroleum Engineers Journal, 16, (1976) 172-174.

Lake L.W, Enhanced Oil Recovery, (1989). Chapters 8 and 9. Edited by Prentice Hall.

Lake, L.W., Stock, L.G., and Lawson, J.B., "Screening Estimation of Recovery

Efficiency and Chemical Requirements for Chemical Flooding," SPE 7069, presented at the Society of Petroleum Engineers Fifth Symposium on Improved Methods for Oil Recovery, Tulsa, Oklahoma, 1978.



Lake, L.W., and Helfferich, F., "Cation Exchange in Chemical Flooding, Part II- The Effect of Dispersion, Cation Exchange, and Polymer/Surfactant Adsorption on Chemical Flood Environment," Society of Petroleum Engineers Journal, 18, (1978) 435-441.

Lake, L.W., and Pope, G.A., "Status of Micellar-Polymer Field Tests," Petroleum Engineers International, 51, (1979) 38-69.

Nelson, R.C., and Pope, G.A., "Phase Relationships in Chemical Flooding,:Society of Petroleum Engineers Journal, 18, (1978) pp 325-338.

Nelson, R.C., "Effect of Live Crude on Phase Behavior and Oil-Recovery Efficiency of Surfactant Flooding Systems," Society of Petroleum Engineers Journal, 23, No. 3, (1983) pp. 501-520.

Winsor, P.A., Solvent Properties of Amphiphilic Compounds. Edited by Butterworths, London, 1954.

Savins, J.G., "Non-Newtonian Flow Through Porous Materials," I & EC, 61 (10), (1969) 19.

Seright, R.S., "The Effects of Mechanical Degradation and Viscoelastic Behavior on Injectivity of Polyacrylamide Solutions," Society of Petroleum Engineers Journal, vol. 23 (3), (June 1983) pp. 475-485

Wellington, S.L., 1980, "Biopolymer Solution Viscosity Stabilization Polymer Degradation and Antioxidant Use," SPE 9296, presented at the 55th Annual Fall Technical Conference and Exhibition of the SPE, Dallas, Texas, Sept. 21-24, 1980.

Willhite, G.P. 1986, Waterflooding Monograph. SPE Textbook series Vol. 3.

module 6

Documents

micellar polymer flooding

caustic flooding processes

polymer concentration

polymer adsorption

water micellar flooding

foam flooding

alkaline flooding

microemulsion flooding