Foams: Fundamentals and Applications in the Petroleum Industry

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Steam-Foams for Heavy Oil and Bitumen Recovery Ε. E. Isaacs, J. Ivory, and M. K. Green Alberta Research Council, Oil Sands and Hydrocarbon Recovery, P.O. Box 8330, Station F, Edmonton, Alberta T6H 5X2, Canada Steam-based processes in heavy oil reservoirs that are not stabi lized by gravity have poor vertical and areal conformance, be cause gases are more mobile within the pore space than liquids, and steam tends to override or channel through oil in a forma tion. The steam-foam process, which consists of adding surfac tant with or without noncondensible gas to the injected steam, was developed to improve the sweep efficiency of steamdriveand cyclic steam processes. The foam-forming components that are injected with the steam stabilize the liquid lamellae and cause some of the steam to exist as a discontinuous phase. The steam mobility (gas relative permeability) is thereby reduced, and the result is in an increased pressure gradient in the steam-swept re gion, to divert steam to the unheated interval and displace the heated oil better. This chapter discusses the laboratory and field considerations that affect the efficient application of foam.

Properties of Surfactants at Elevated Temperature Both the effectiveness and the economics of steam-foam processes depend critically on surfactant losses, and it is therefore essential to minimize losses due to the chemical and physical phenomena occurring in the reser voir at elevated temperatures.

Thermal Stability. The thermal stability of surfactants has been investigated in a number of studies (1—5). Surfactants with sulfate moieties decompose rapidly at temperatures above 100 °C, and surfactants

In Foams: Fundamentals and Applications in the Petroleum Industry; Schramm, Laurier L.; Advances in Chemistry; American Chemical Society: Washington, DC, 1994.

236

FOAMS: FUNDAMENTALS & APPLICATIONS IN THE PETROLEUM INDUSTRY

stable above 200 °C have, almost exclusively, sulfonate groups. A large number of anionic sulfonate surfactants are thermally stable in the range 100-300 °C (3, 6). Sulfonates decompose via hydrolytic desulfonation of the sulfonate group. The decomposition of the sulfonate produces acid, and the reaction proceeds according to autocatalytic kinetics (5) as

ArS0 " + 2H 0 ^ Downloaded by UNIV OF CALIFORNIA SAN DIEGO on January 15, 2016 | http://pubs.acs.org Publication Date: October 15, 1994 | doi: 10.1021/ba-1994-0242.ch006

3

2

2

ArH + S0 ~ + H 0 4

+

3

(1)

where Ar represents an alkylaryl group. At low pH and temperatures near 200 °C, this reaction is relatively fast and leads to substantial decomposition within hours or days, but hydrolysis is almost completely inhibited at basic pH. For example, a petroleum sulfonate was only about 10% decomposed after 28 days at pH 9 (not buffered) and 205 °C (2). Thermal stability of sulfonates increases in the order (7): petroleum sulfonates < alpha-olefin sulfonates < alkylarylsulfonates /?-Dialkylarylsulfonates are more stable than the meta-isomers (8), and one material showed essentially no degradation after 10 days at 299 °C and pH 4 (9). The effect of pH (3.1 to 11.0) on the decomposition of an alkylarylsulfonate (Suntech IV) surfactant at 299 °C is shown in Figure 1. Surfactant thermal stability tests carried out in the presence of reservoir sand show that the reservoir rock had little or no effect on the chemical reactivity of the surfactant (1).

Retention in Porous Media. Anionic surfactants can be lost in porous media in a number of ways: adsorption at the solid-liquid interface, adsorption at the gas—liquid interface, precipitation or phaseseparation due to incompatibility of the surfactant and the reservoir brine (especially divalent ions), partitioning or solubilization of the surfactant into the oil phase, and emulsification of the aqueous phase (containing surfactant) into the oil. The adsorption of surfactant on reservoir rock has a major effect on foam propagation and is described in detail in Chapter 7 by Mannhardt and Novosad. Fortunately, adsorption in porous media tends to be, in general, less important at elevated temperatures (10, 11). The presence of ionic materials, however, lowers the solubility of the surfactant in the aqueous phase and tends to increase adsorption. The ability of cosurfactants to reduce the adsorption on reservoir materials by lowering the critical micelle concentration (CMC), and thus the monomer concentration, has been demonstrated (12,13). Both the precipitation and partitioning of anionic surfactants increase with increasing temperature. For a C — C alkylaryl surfactant, such as Suntech IV, surfactant losses due to partitioning were in the range 16

lg


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ISAACS ET AL.

Steam-Foams for Heavy Oil and Bitumen Recovery 237

11.U

Ο


Φ

0

50

Ο

100

150

Time, h

γ ψ

j

200

250

Figure 1. Effect of pH on the rate of reaction at 299 °C. (Data are taken from reference 5.) of 25-40% at 125 °C (14) and 20-30% at 205 °C (1) depending on initial surfactant concentration. As a general guide, partitioning and precipita tion of surfactant increases with increasing temperature, increasing brine concentration, and increasing surfactant chain length. However, the phase behavior of surfactants is a complex phenomenon, and the interaction of divalent (and trivalent) cations with sulfonate surfactants causes surfactant precipitation followed by dissolution of the precipitate at higher concen trations (7 5). The precipitate redissolution phenomenon is not observed with monovalent ions. The emulsification of the aqueous phase in oil is likely to have a det rimental effect only in situations where the heavy oil phase is also flowing in porous media. Reservoir applications of foams invariably assume that the oil phase is at residual saturation (S ). Consequently, emulsification is not generally considered a serious problem in most foam applications. Qr

Interfacial Tension Behavior. Reduction in the residual oil sat uration over and above that obtained by steam injection is desirable and, in many heavy oil reservoirs, essential to ensure efficient foam formation during application of steam-foam processes (13). The extent of heavy oil desaturation is, however, dependent on the reduction in interfacial tension between oil and water. Thus, foam-forming surfactants can improve their own cause by reducing interfacial tensions at steam temperature. Low interfacial tensions ( ε

0.001

Vg=16.5m/day

σ or

0.0001 0.1

( ) Liquid Volume Fraction I

1

10

Velocity of Liquid, m/doy

Figure 6. Effect of liquid velocity on the foamflowresistance.



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ISAACS ET AL,


Figure 7. Effect of surfactant concentration andfluidvelocity at constant LVF on the foamflowresistance. difference between the "flowing" and "trapped" foams is the texture. The higher the surfactant concentration, the greater the foam resistance at all flow rates. Thus, if desired, the surfactant concentration can be used to compensate for the effect of fluid velocity. Furthermore, foams can with stand drastic changes in fluid velocity, and their velocity dependence is exactly what is required in the reservoir, that is, relatively low resistance near the injection well, where velocities are high, and higher resistance further into the reservoir, where velocities are relatively low.

Steam-Foam Performance in Laboratory Cores Constant Flow Rate. Classic experimental evaluation of mobility reduction due to steam or gas foams involves injecting gas and liquid at constant flow rate and monitoring the pressure drop behavior across several subsections (to avoid capillary end effects). Although the results of core-flood studies have been positive, there is concern regarding their applicability to field situations. Under constantflow-rateconditions, the diversion of steam that follows surfactant injection is accompanied by a large increase in pressure drop across the core. It is unreasonable to ex pect that such a large increase in pressure gradient would occur in a reser voir. In fact, if the decrease in mobility caused by surfactant resulted in a drop in flow rate rather than an increased change in pressure (ΔΡ), the foam could collapse, because conditions may fall below a minimum flow velocity for foam formation (30). An additional concern in constant flow


244



experiments is that when saturated steam is injected and a constant back pressure is used, an increase in AP leads to an increase in injection pres sure, which results in a higher injection temperature. Thus the effects of higher temperature are mixed in with the effects of diversion.

Constant ΔΡ. Injection of steam under constant pressure-drop conditions provides a better representation of steam injection into a well than constant flow rate, becausefieldinjection pressures will be limited by the temperature—pressure capabilities of the injection system in relation to the reservoir volume. Implementation is somewhat more complicated than for a constant flow experiment because rates of addition of surfactant solution, steam, and noncondensible gas must be varied in concert to maintain the set point AP, but computer control simplifies the task great ly. In this case, mobility reduction is indicated by a drop in flow rate, rather than an increase in AP. Generally, similar trends in mobility reduc tion with parameters such as surfactant concentration are observed (31). However, as illustrated in Figure 8, the danger of an excessively strong foam is highlighted; blocking was strong enough to limitflowinto the sys tem as a whole to the point where oil productionfromthe core was re duced. Cyclic Steam. The idea of using foams in cyclic-steam operations to control injection profiles is well understood and has been demonstrated in the field (next section). However, the role of a foaming surfactant dur0.4-

0

1

Produced

2 Water,

3 Pore

4 Volumes

Figure 8. Produced oil-water ratio and flow rate during a steam followed by steam-surfactant injection into an Athabasca core.



6.

ISAACS ET AL.


ing the drawdown phase of a cyclic process is less clear. Steam-foam could conceivably play a beneficial role by restricting the flow of flashing steam into the well, with a consequent improvement in water—oil ratio. Strong foam formations, however, could be detrimental, by impeding flow of all fluids to the well. When surfactant is injected with steam, in the absence of noncondensible gas, into an oil sand core while the production pressure is cycled, some mobility reduction due to foam is observed during the drawdown phase, but the greatest effect is seen during periods of steady flow (Figure 9) (32). This result suggests that at least a portion of the recovery enhancement seen during cyclic operations in the field may be attributed to foaming effects during drawdown.

Prefoam Slug Technology. All foaming surfactants are sensitive to oil (Chapter 4). There is considerable interest in developing surfactants with improved oil resistance and in developing strategies to overcome this difficulty. One strategy that appears to have potential is the injection of a prefoam slug to mobilize residual oil ahead of the foaming surfactant and to allow for rapid foam formation (27). As an example, Figure 10 compares three steam-foam experiments in 2-darcy-packs that contain Cold Lake bitumen and have been steam-flooded to residual oil saturation (5 ). In the absence of a prefoam slug, the foam has taken about 10 pore volumes (PV) to generate, even using an oil-tolerant surfactant (Chaser SD1020). Injection of a 0.25PV slug of either diesel solvent or a surfactant that reduces interfacial tension (IFT) has considerably hastened the evolution of the foam. The diesel solvent is miscible with the residual oil, reducing its viscosity and hence making it more amenable to mobilization Qr

Pressures During Drawdown 60

Steam-surfactant

40 20

Pressures During Low Pressure Phase 100 75

Steam-surfactant

50 Steam-only

25 1

1

—

2 3 Cycle Number

T"

Figure 9. Comparison of pressure drop (AV) behavior during the drawdown and low-pressure phases, between steam-only and steam-surfactant runs using Athabasca oil sand cores. The inset indicates the period of surfactant injection.


246

FOAMS: FUNDAMENTALS & APPLICATIONS IN THE PETROLEUM INDUSTRY 2.4

1 r12 darcy sandpack at 180°C

J


Arbitrary liquid, PV

Figure 10. The effect of prefoam slug injected prior to foam formation on the rate of foam propagation.

by steam. The low-IFT slug was designed to mobilize the residual oil by reducing oil—water interfacial tensions below 10" mN/m at run temperatures. An alternative approach to minimizing the effect of residual oil is the injection of air with steam ahead of the foam front. Air converts the residual oil to coke; the result is improved mobility reduction behavior of the ensuing steam-foam (33). 2

Field Experience with Steam-Foams Foam has been used in field applications involving both cyclic and steamdrive processes. Many of the steam-foam tests have been performed in Kern County, California, where most of the U.S. heavy oil is produced. In many situations, foam has successfully increased both volumetric sweep efficiency and oil recovery rates (34). Generally, the application of foam has been considered to be a technical success but economically suspect. The surfactant has been injected as high-concentration slugs [10 wt% active (35)] or continuously at a lower concentration (0.1—1.0 wt% active). Noncondensible gas (at a concentration of 0.5-1.0 mol% in the gas phase) or NaCl (1-4 wt% in the aqueous phase) may be coinjected with the surfactant and steam in order to stabilize the foam. Figure 4 can be used to estimate the minimum concentration of noncondensible gas required. Extra water may be added to the steam to maintain the liquid volume fraction at the desired value (typically above 0.01).

Application of Foams. Foam injection is a simple addition to a steam process. It basically requires a surfactant storage tank or drums, a surfactant pump, a gas compressor, and methods of measuring surfactantinjection rates(e.g., changes in liquid level) and gas -injection rates (e.g.,



6.


ISAACS ET AL.

orifice meter). A schematic of a foam-injection system used in one field test (36) is shown in Figure 11. A number of tests are used to evaluate the effectiveness of foam in field applications. It is crucial that stable baseline measurements for steam-only injection be obtained so that the effect of foam can be deter mined. In addition, influences from wells outside the test pattern should be minimized and estimated. Oil production generally increases as a result of the improved volumetric sweep caused by foam injection. Incremental oil production from down-dip wells is likely to be higher than that from up-dip wells be cause of a reduction in steam override. Changes in the steam—oil ratio (SOR) can provide a reliable indication of foam blocking if steam-drive is the primary displacement method. As a result of an increased flow resistance, foam injection is often ac companied by an increase in the injection-well bottomhole pressure (BHP). Temperature surveys at injection, production, and observation wells indicate whether foam is successfully diverting steam. By minimizing gravity override, a successful foam application increases the temperature

Differential pressure transmitter Treated boiler feed water

^

Steam generator

Prefoamer

control valve

h©

h0 Recycle

.089" or .12" orifice

*V3 A

chart recorder

, M | >'Τ

CFM chemical air actuated , •—.injection pumps 1

'-α Well C-13

1

5500 kPa

f~~77

_J

>*KE) (EH

Purge gas race

Ingersoll Rand gas compressors Chemical drum

Figure 11. Schematic of foam-injection system.



248


near the bottom of the formation. In addition, a decrease in steam channeling is indicated by a reduction in the temperature at the well to which steam previously channeled and by an increase in the temperature at other production wells. The temperature difference (postfoam minus prefoam) at various depths may be integrated over the depth to indicate the effect of foam at a particular observation well (37). Temperature surveys at observation wells at the Grégoire Lake In Situ Steam Pilot (GLISP) site (38) showed that foam successfully reduced the effects of gravity override and diverted steam downward. As a result, the temperature at the center of the oil-rich zone [200 meters from Kelley Bushing (mKB)] increased from 65 °C to 145 °C over the first 74 days of foam injection (Figures 12 and 13). A velocity shot survey is used to determine if the steam flow pattern is being altered near the wéll-bore. This survey involves the injection of cold water at the surface and the injection of a water-based tracer (e.g., iodine-131) down-hole. From the time it takes the tracer to travel between two detectors, it is possible to estimate the perforation depths at which the water preferentially enters the formation. An injection profile survey (39) involves the injection of a radioactive tracer (e.g., iodine-131) at the surface. The well-bore is subsequently logged using a gamma-ray tool. The retained radioactivity adjacent to the well at a given depth is assumed to be proportional to the volume of the liquid or gas (depending on the tracer) entering the formation at that depth. Retained radioactivity lasts only for a few minutes, so logging must be performed quickly after injection of the tracer. These profiles may be in error if some of the retained reactivity is due to adsorption or chemical reactions. Neutron logs (37) have been used to determine changes in the liquid

Observation Well Distances

HO-7toH-3 ΗΟ-8 to H-6 HO-9toH-6

10m 25 m 15 m

Figure 12. GLISP well configuration (reference 38).



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Steam-Foams for Heavy Oil and Bitumen Recovery

249

Temperature (*C)

Figure 13. Well H09 temperature profile (reference 38). saturation near observation wells. A reduction in liquid saturation is an indication of foam propagation. Carbon—oxygen logs provide an estimate of oil saturation (39). Steam diversion may also be indicated by changes in the produced water composition. For example, if the CI" ion concentration in the injected aqueous phase is less than that in the formation, then an increasing CI" ion concentration indicates less channeling and greater contact with "fresh" reservoir. Changes in the produced gas composition (e.g., C 0 or C H concentrations) may also indicate steam diversion. Tracers (40, 41) are used primarily to estimate volumetric sweep and to locate steam channels. The tracer should not react with the reservoir. The four main categories of tracers are radioisotopes (e.g., tritium and krypton), which are used in steam floods; salts (e.g., sodium bromide and sodium nitrate); fluorescent dyes (e.g., uranian); and water-soluble alcohols (e.g., methanol, ethanol, and 2-propanol). The surfactant itself may be used as a tracer. Its concentration at production wells may be determined by using methods such as liquid chromatography, colorimetry, and titration. In addition to these tests, pressure falloff and buildup tests may be performed to determine the effect of foam on steam-zone volume and 2

4


250



transmissibility. The pressure falloff test involves monitoring the decay of the BHP after the end of the injection period. In a buildup test, the increase in BHP is recorded after the end of the production period. The rate of pressure change in both tests depends on the fluid transmissibility in the reservoir.

Cyclic Processes. During thefirstcycle, steam follows the path of least resistance (e.g., high permeability and low oil saturation) and preferentially depletes portions of the reservoir. In subsequent cycles, the flow resistance is even lower in the depleted region. Thus, in every cycle, the steam will preferentially flow to the depleted zone. By significantly increasing the flow resistance in this zone, foam diverts the steam to regions of higher oil saturation. This action results in higher oil recovery rates. As a result of steam diversion, the volume of the depleted zone increases with each cycle. Therefore, the amount of foam injected in each cycle must be increased to maintain satisfactory oil production rates. For cyclic steam-foam injection, it is important that the foam breaks down in the presence of oil or after prolonged exposure to high temperature. In this way, the resistance to the flow of production fluid will not be substantially increased. A concern with a cyclic foam injection process is that the low mobility foam will displace oil further (as compared to steam-only injection) from the well during the injection portion of the cycle. The oil will then have a greater distance to flow to the well during production. Thus, initial water cuts may actually increase in cyclic steamfoam tests (26). The oil recovery may also be low initially but then increase to a level higher than that obtained from a steam-only cycle. Some cyclicfieldfoam test results have been reported as follows: 1.

On the basis of more than 4000 field tests (mostly in Kern County, California) performed by Chemical Oil Recovery Company (CORCO) (35, 42): 3

• 1980-1984: 1.1 m of oil/L of surfactant solution • 1985-1986: 0.3 m of oil/L of surfactant solution • 1990: 0.2 m of oil/L of surfactant solution 3

3

2. The results of two foam tests (using SD1000) performed by Chevron (43) were • at Midway-Sunsetfield,theincrease in injection pressure was 0.6- 1.1 MPa, and the incremental oil production was 0.4-1.2 m /kg of active SD1000 • at Bradley-Canyonfield,the increase in injection pressure was 3.6 MPa, and the incremental oil production was 0.12 m /kg of active SD1000 3

3


6.

ISAACS ET AL.


Drive Processes. A number of foam-drive tests are summarized in Table I. A standard application involves an initial active surfactant concentration in the aqueous phase of about 1 wt% before it is reduced to about 0.2—0.5 wt% after a number of days. The noncondensible gas mole fraction in the vapor phase is in the range 0.5-1.0%. NaCl is sometimes added to reduce ion exchange. The steam quality may be reduced to in crease the LVF. If steam diversion results, then the injection pressure in creases by about 1 MPa. In addition, about 0.3 m of incremental oil is produced per kilogram of active surfactant. However, the behavior of the foam is highly dependent on the condition of the reservoir (permeability streaks, depletion, etc.). Assuming a cost of $10/kg of active surfactant (including noncondensible gas), the cost of incremental oil is $33/m ($5/barrel). However, in many tests the incremental oil production is not high enough to be economical.


3

3

Numerical Modeling of Field Foam Tests Surfactant propagation in the reservoirs has been modeled (44, 45) by al lowing for surfactant adsorption, oil partitioning, andfirst-ordersurfactant decomposition; all of these variables are functions of temperature. The foam mobility reduction is taken into account by reducing the gas relative permeability as follows: / (1 + MRF MRF

eff

)

(2)

es

= MRF (W /W? ) ((S™ - S )/S% ) e°(N j Κ ) "

eff

s

0

c

(3)

where MRF is maximum mobility reduction factor, which is determined from history matching (50); W is surfactant concentration (0.0001875 mol fraction); S is oil saturation to foam (0.25); N is the capillary number (10~); S is gas saturation; the superscript m and the subscript eff denote maximum and effective, respectively; and the superscript r denotes the term reference. A value of 1.0 has been used for the exponents es, eo, and ev, which are the effect of surfactant, effect of oil concentration, and effect of veloci ty, respectively. The following surfactant properties are also specified: s

Q

c

6

g

• • • •

oil-water k value (0.0) maximum adsorption at initial temperature (2.56 mol/m ) maximum adsorption at injection temperature (0.38 mol/m ) surfactant half-life at initial temperature (oo) 3

3


252

FOAMS: FUNDAMENTALS & APPLICATIONS INTOEPETROLEUM INDUSTRY

Table I. Summary of Field Foam

Company


CLD (50) SUPRI, CORCO (51 52) Mobil (53)

Field Midway-Sunset, California Kern River, California Kern County, California

Oil Gravity CAPI) 11 12

Foaming Agents Thermophoam BW-D and air Suntech IV and 2 Linear toluene sulfonate and 2 AOS-1618 and 2 Alkyl toluene sulfonate and N AOS-1618, NaCl and N SD1000 and N~ SD1020 and N~ N

13

N

Shell (49, 54-57) Kern River Unocal (58)

13

Unocal (36, 59)

Guadulupe, California Midway-Sunset

11

Chevron (60, 61)

Midway-Sunset

14

Chevron (41)

Midway-Sunset

—

Amoco (48)

Fremont County, Wyoming Athabasca, Alberta

14

GLISP (38, 62-64)

9

N

2

2

Suntech IV and CH SD1020 and noncondensible ι 4

10

'For 2 days/week for tests 1 and 2.

• surfactant half-life at injection temperature (oo) • injected surfactant concentration (eg., 0.0001875 mole fraction) • surfactant molecular weight (480) Equations are based on experimental observations of the effect of surfactant concentration, oil saturation, and velocity. The values in paren theses were used in an actual field simulation (44). The following conclusions have been drawn from the model results: • If foam is applied late in a steam drive, for an aerially isotropic reservoir, its effect will be minimal because of the large distances it must move to cause an effect. • Even in thin reservoirs, foam can be effective by reducing gravity override. In these reservoirs the growth of the foam zone is spheri cal.


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Steam-Foams for Heavy Oil and Bitumen Recovery

253

Applications in Steam-Drive Processes

Surfactant Noncondensible Cone, (wt % Gas NaCl Active in Aqueous Cone. Cone. Phase) (mol %) (wt %) —


Slugs

Increase in Incremental Oil Injection Production Pressure Active (m /kg (MPa) Surfactant) 3

0.0

0.3

—

Slugs

2

0.0

0.5

>0.1

1 for 1-2 weeks 0.5 for 12-13 months 0.5

0.5

0.0

0.5

0.4

0.06

4.0

0.4-0.45 for 3 years 0.24 for 6 months 0.31 for 3 years 0.24 for 6 months 0.5 for 2 days/week for tests 1 and 2 0.27 after initial 3-day slug 0.4-2.5 2.5-40 0.5 for 2 weeks, 0.2 for 8.5 months followed by 0.1

0.5

0.0

0.8

2.3

1.0°

0.0

1

0.0

2 2 lfor 2 weeks, 0.1-1

0.0 0.0 0.0

—

0.02 0.3

1.4 —

1.0 during slugs 1.4

Foams: Fundamentals and Applications in the Petroleum Industry

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