ENHANCED PRODUCTIVITY IN A HEAVY OIL RESERVOIR AS A RESULT OF IMMISCIBLE GAS AND FOAM INJECTION

By: Dr. NASSER ALIZADEH

Vali-e-Asr avenue, Vanak Square, Daman Afshar St., No. 3, Tehran nalizadeh@tehran.oilfield.slb.com

ABSTRACT

Summary Is the era of heavy oil arrived? On the one hand, huge undeveloped heavy oil reservoirs in Iran and on the other hand increasing oil price have made the enhanced oil recovery very economically attractive, and that could be the beginning of an era when unconventional petroleum sources become economic. Different IOR methods have been used so far to produce heavy oil including horizontal wells, ESP, steam injection, hot water injection, water alternating steam, combustion, miscible and immiscible gas injection. In the immiscible aspect of the gas injection, the viscosity reduction effect of the gas, generally unimportant in light-oil reservoir, could play a significant role in the recovery of heavy oil. In this paper we have searched for a technique to recover more heavy oil from the reservoir. We inject gas and foam in the reservoir to make the unmovable oil movable and to reduce the gas mobility in order to increase the displacement efficiency. A black-oil simulator (ECLIPSE 100) was used to match performance history of a heavy oil reservoir to predict its future performance under continued immiscible gas injection. The ECLIPSE foam model was also used to model the flow of the foam in the reservoir. This model accounts for adsorption onto the rock and decay over time. The purpose of this study is to present new insights into the performance of the reservoir through applying EOR method. We are not trying to make recovery predictions under various field development scenarios to choose the optimal production scenario. Introduction Foam can be used in a number of ways to increase the production from an oil reservoir. The foam acts to decrease the mobility of gas; this effect can be used to slow the breakthrough of injected gas or to reduce the production of gas cap gas. The foam can be transported with the gas flow into the reservoir. The major beneficial effect of the foam is to reduce the mobility of the gas. Note that in foam flooding the reduction of the interfacial tension (between oil and water) is not a significant effect. The reduction of gas mobility will typically be dependent on a range of factors including pressure and shear rate. The foam stability will have a major effect on the usefulness of foam injection. Typically the foam will suffer from adsorption on to the rock matrix, decay over time, and enhanced decay in the presence of water. The ECLIPSE Foam Model does not attempt to model the details of foam generation, flow and collapse. In this model we assume that foam is transported with the gas phase, and hence we model the foam by a tracer in the gas phase that accounts for adsorption on to the rock and decay over time.

Foam as an EOR Agent Foam is a dispersion of a relatively large volume of a gas in a small volume of the liquid. Foams are useful in EOR processes because they have a relatively high resistance to flow when displaced through a porous medium. Thus, they are potentially suitable for improving displacement efficiency in a process or for the flow of condensed fluids.

The following are possible applications:

1- Blocking or restricting flow of undesired fluids, such as the coning of gas or water in a production well. 2- Blocking or restricting flow of injected fluids in high permeability streaks or fractures. 3- Improving the mobility ratio in displacement processes by reducing the mobility of the injected phase.

Properties That Characterize Foam

Foams typically are characterized by quantifying foam quality and bubble size. Foam quality is expressed as the fraction or percentage of total volume that is gas. Bubble size is specified in terms of average size or diameter and the range of bubble sizes present.

Foam quality typically ranges from 75% to 90% but may be higher, approaching 97% or significantly lower. Quality is a function of pressure and temperature, as well as foam constituents and physical conditions associated with the production and handling of the foam.

Foaming Agents

A foaming agent (i.e. a surfactant) is required to produce a foam. Numerous surfactants are suitable for this purpose. Surfactants generally are selected for specific applications on the basis of laboratory test procedures and empirical relationships. There are no theoretical quantitative relationships available to make reliable, detailed predictions of foam properties.

Heller et. al. and Dellinger et. al. studied the behavior of a number of surfactants for possible use in mobility control with the CO2 miscible process. Because CO2 is generally injected above its critical temperature and pressure, it is a relatively dense fluid at displacement conditions, typically having a density greater than 0.6 g/cm2. Because of this, Heller et. al. studied surfactants known to be good liquid emulsifying agents.

A parameter used to rank surfactants is an empirical number called the hydrophile/lipophile balance (HLB) number. Heller et. al. used surfactants with HLB number of 8 to 13. They also required that the surfactants be soluble in an Nacl/Cacl2

brine and that they be anionic or nonanionic. This latter requirement was imposed because cationic surfactants probably would adsorb strongly onto reservoir rock.

Foam also has been tested as a way to modify the permeability profile in injection wells in a waterflood. More than 100 surfactants were tested for this purpose, and it was found that certain ethoxylated alkyl sulfates containing amide stabilizers were efficient foaming agents. For the field test, a modified ammonium lauryl sulfate called O.K. liquid was used.

Foaming agents are applicable in steam drives as steam-diverting agents. Gravity override and steam channeling are important problems in steam displacement. By creating a high flow resistance, foams can be used as diverting agents to make steam move more uniformly through a reservoir. Surfactants used in conjunction with steam displacement must be capable of generating flow resistance and remaining stable at steam flood temperature, which are commonly about +400°F.

Rheology of Foams – Flow in a Tube

Experiments have determined that a foam behaves as a non-Newtonian fluid. The foam typically has the characteristics of a pseudoplastic fluid: i.e. the apparent viscosity of the foam decreases as the shear rate increases.

For a Newtonian fluid, the relationship between shear stress, τ, and shear rate, γ, is given by:

τ=µ γ [Eq.1]

is the fluid viscosity and it is not a function of the shear rate.µWhere Viscosity is dependent on temperature and pressure. Shear rate is expressed in terms of a velocity gradient, such as dv/dr, in flow in a tube.

As previously discussed, Eq.1 does not hold for non-Newtonian fluids because the relationship between τ and γ is nonlinear. A useful model to describe non-Newtonian fluid is the power-law model attributed to Ostwald and the Waele. The model is given by Eq. 2, which is rewritten here as

τ =K γn [Eq. 2]

Where K is the power-law constant or consistency index and n is the power-law exponent or flow-behavior index. The shear stress, τ, is related to pressure drop, and shear rate, γ, is related to volumetric flow rate for flow in a tube as

q=∆p.d/4L [Eq.3]

where ∆p is the pressure drop along a length L of the tube, d is the tube diameter, L is tube length, q is the volumetric flow rate, and consistent units are used.

Fig.1- Pseudoplastic characteristics of foam Fig.2- Foam data represented by Ostwal model

Figures 1 and 2 show foam data. Fig.1 plots shear stress vs. shear rate for a foam formed of nitrogen and brine. The different curves are for capillary tubes of different lengths. The curves are all slightly concave downward, indicating that the shear stress is not increasing linearly with the imposed shear rate. On this plot, the apparent

viscosity of the foam at any point is the ratio τ/ γ. As seen, the apparent viscosity of the foam decreases as shear rate increases, a behavior called pseudoplastic. Comparison of Eqs. 1 and 2 shows that the apparent viscosity, µa, also can be expressed as:

µa=Kγn-1 [Eq. 4]

power-law fluids should yield a straight line when log τ is plotted vs. log γ (Eq.2). Figure 2 shows several data sets for tubes of different lengths and diameters. The slop of each line is the flow behavior index n. When the slope is unity (n=1), the fluid is Newtonian and K is the Newtonian viscosity. Fluids exhibit greater non-Newtonian behavior as n deviates more from unity. For foams, n<1, indicating pseudoplastic behavior.

The foam indices in fig.2 are functions of capillary-tube diameter and length, a characteristics of foams observed by other investigators. Foam-behavior indices are also known to be functions of the foam composition and quality, as well as temperature and pressure.

Foam rheological behavior is somewhat like that of the polymers. However, the foam flow is more complex and is dependent on a large number of variables, as discussed.

Experimental work of the type discussed indicates that foams can be described in a useful way by a power-law model. Foams are complex systems, however, and the model parameters are not unique but depend on the system geometry, foam properties, pressure, and temperature.

Flow of Foams in Porous Media

Foam rheology depends on the geometry of the flow system. This is particularly true when foam flows through a porous medium. Heller et. al. discussed two important requirements for the rheological characterization of a foam geometrically independent. First, the foam-bubble (cell) size should be at least 20 times smaller than the characteristic flow dimension (pore size). Otherwise, the effect of the pore walls on the foam macroscopic or bulk behavior will be significant. Bulk properties, such as apparent viscosity or even quality, will be affected by the geometry at low ratios of bubble size to flow dimension. Dietz et. al. pointed out that foam flow at the pore level may be such that rheology data taken in a standard viscometer may be meaningless. Second, pressure variations along this flow path should be such that fluid compressibility effects are negligible. Standard viscometry measurements are based on incompressible fluids, and large compressibility effects during flow can introduce significant error. The rheological description of foam flow in porous media has been treated in different ways. One approach has been to use the single-phase fluid viscosities to calculate relative permeability’s to each fluid on the basis of experimental measurements of flow rates and pressure drop in foam flow through a porous medium. In the displacements, water or foaming-agent solution was displaced through a sand pack at different rates, holding the pressure gradient constant. A constant gas pressure was maintained at the injection face of the sand pack. The relative permeability to the gas and the gas saturation were measured.

Gas saturation was determined to be the same at a given flow rate, regardless of whether a foam was present. The relative permeability to the gas phase was very dependent on the presence of foam, however, and was more than two orders of magnitude smaller when foam was flowing in the sand pack than when water was flowing with no foaming agent. This approach to describing rheology in effect treats the flow of foam as two-phase flow. Another approach to describing foam rheology has been to calculate an apparent foam viscosity from flow-rate and pressure-drop measurements made during flow through a porous medium. Darcy’s law is used with the rock permeability, or water relative permeability if an oil phase is present, to calculate apparent foam viscosity. Results show that the apparent viscosity calculated in this manner is a strong function of foam quality, decreasing approximately linearly as foam quality increases. This approach essentially treats the foam as a single phase.

A third approach is to describe the foam flow in terms of foam mobility, λ. The quantities typically measured in a displacement or flow experiment in porous media are pressure drop and flow rate. These results can be used with Darcy’s law to calculate mobility.

λ =k/µ = (qt/A)/(∆p/L) [Eq. 5]

Where qt is the total volumetric flow rate, A is the cross-sectional area normal to flow direction, ∆p is the pressure drop across the porous medium, L is the length of the porous medium, λ is the foam mobility, and consistent units are used. A relative mobility, λr, also can be defined as:

λr=λ/k [Eq. 6]

Where k is the permeability of the porous medium.

Heller et al. analyzed a number of experimental results reported in the literature. They restricted their analyses to experiments that met the following conditions.

1. The experiment was conducted under steady-state conditions. The results would thus represent conditions well behind a foam displacement front where properties are changing.

2. the foam quality was though to be fairly uniform along the length of the system. Compressibility effects should therefore be small.

The Simulation Model

Foam Conservation Equation

Although foam is essentially a mixture of gas, water and surfactant, ECLIPSE models it as an effective concentration of surfactant transported in the gas phase. Hence, the foam concentration can be thought of as the surfactant concentration existing in foam form.

The foam conservation equations are solved fully implicitly at the end of each time step after the oil, water and gas flows have been computed. The foam is assumed to exist only in the gas phase. Account is taken of the adsorption and decay of the foam. The modification of the gas mobility is treated explicitly, with the mobility modification being applied at the subsequent time step.

Adsorption

The adsorption of foam is assumed to be instantaneous, and the quantity adsorbed is a function of the active foam concentration. You are required to supply an adsorption isotherm as a function of foam concentration. The quantity of foam adsorbed on to the rock is given by:

r.CA(Cfoam)ρM=V.[(1-Φ)/Φ]. [Eq.7]

r isρWhere M is the mass of the adsorbed foam, Φ is the porosity, the mass density of the rock and CA(Cfoam) is the adsorption isotherm as a function of local foam concentration in solution.

There are two adsorption models, which can be selected. The first model ensures that each grid block retraces the adsorption isotherm as the foam concentration falls in the cell. The second model assumes that the adsorbed foam concentration on the rock may not decrease with time and hence does not allow for any de-adsorption.

Foam Decay

Foam effectiveness will typically reduce over time, even in conditions very favorable to foam stability. This reduction in effectiveness may be accelerated in the presence of water or oil. The reduction in foam effectiveness over time is modeled by foam decay; the half-life of the decay can be a function of both oil and water saturation. If the decay half-life is a function of both oil and water saturation, the foam is assumed to decay with the minimum half-life.

Gas Mobility Reduction

The foam modifies the gas mobility by way of a simple multiplier supplied as a function of foam concentration (that is the effective surfactant concentration). The mobility modification is applied explicitly; the modification associated with the conditions at the end of each time step is applied at the subsequent time step.

Fg=[Krg/(µgBg)] .T.DP [Eq.8]

Fgm= M(Cfoam).[Krg/(µgBg)] .T.DP = M(Cfoam).Fg [Eq.9]

Where Fg is the unmodified gas flow, Fgm is the modified gas flow, Krg is the gas relative permeability, µg is the gas viscosity, Bg is the gas formation volume factor,T is the transmissibility, DP is the potential difference, M(Cfoam) is the input mobility reduction factor, Cfoam is the foam concentration.

The mobility reduction factor M(Cfoam) can optionally be influenced by two separate effects, both of which will tend to increase M (that is to increase the gas mobility again). M(Cfoam) can be varied as a function of both pressure and shear rate.

The mobility reduction factor including the pressure effect is:

MP=[1-M(Cfoam)].Mp(p)+M(Cfoam) [Eq.10]

where MP is the mobility reduction factor with the pressure effect, M(Cfoam) is the original reduction factor as a function of foam concentration, Mp(P) is the pressure dependency function and P is the oil pressure.

The mobility reduction factor including the shear effect is:

MF=(1-MP)Ms(υ)+MP [Eq.11]

Where MF is the final mobility reduction factor, MP is the mobility reduction factor after applying the pressure effect, Ms(υ) is the shear dependency function, υ is the gas velocity.

The gas velocity is calculated as:

υ=Bg[(Fg/(Φ.A)] [Eq.12]

Fg is the gas flow rate in surface units, Bg is the gas formation volume factor, Φ is the average porosity of the two cells, and A is the flow area between the two cells.

The X Field

The X field is a large anticlinal closure, which encompasses over 260 square kilometers (64876 acres). Water depth over the field area average approximately 140 feet. The formation is characterized by excellent porosity (average 25%), permeability (1-14 Darcies), and low water saturation (6-11 %). There is oil gravity variation with depth in the formation but it is not clear if this variation is uniformly distributed throughout the field. Generally, the oil gravity in the formation decreases from around 20 degrees at the top of the structure to 10 degrees near the oil-water contact. In this field we have the intention of demonstrating the effectiveness of foam injection on mobilizing the immobile heavy oil.

Model Study o Foam adsorption: the quantity of the foam adsorbed on the rock is a function of the active foam concentration. We supplied the adsorption isotherms as a function of the foam concentration in the model.

o Foam decay: the reduction in foam effectiveness in the presence of water or oil is modeled by foam decay half time.

o Foam mobility reduction factor: the gas mobility modification is applied explicitly in the model. We supplied the mobility reduction factors as a function of the foam concentration.

o Pressure effect on the mobility reduction: to model the effect of pressure on the mobility reduction factor we supplied the pressure modifier on the mobility reduction as a function of the oil phase pressure. o Shear rate effect on the mobility reduction: we supplied the shear rate modifier on the foam mobility reduction as a function of gas velocity to model the effect of shear rate on the gas velocity.

o Shear rate effect on the mobility reduction: we supplied the following shear

rate modifier on the foam mobility reduction as a function of gas velocity to model the effect of shear rate on the gas velocity:

Two scenarios are modeled: 1st scenario: there are 3 wells in the model, 2 producers and 1 injector. We inject gas in the reservoir from 2004 to 2020. 2nd scenario: there are 3 wells in the model, 2 producers and 1 injector. We inject gas in the reservoir from 2004 and then we start injecting foam from 2013 to 2020. Field oil production rate and field pressure of two scenarios are compared in figures 1 to 2 respectively. Through the observation of theses figures we can simply observe that in 2013 when we start injecting foam in the reservoir, the field oil production rate, and field pressure increase considerably.

Figure 1- Cumulative oil production

Figure 2- Field GOR.

Fig. 3- Recovery factor.

Fig.4- Residual oil.

Figure 5- Field oil Production rate.

Fig. 6- Field pressure.

Conclusions

• The immiscible gas injection can be used successfully in the heavy oil reservoirs to produce heavy oil.

• " Foams can be used in a number of ways to increase the production from the heavy oil reservoirs. The foam acts to decrease the mobility of gas; this effect can

be used to slow the breakthrough of the injected gas or to reduce the production of gas-cap gas.

• Foams are useful in EOR processes. They are potentially suitable for improving displacement efficiency in a displacement processes.

• Foams can improve the mobility ratio in displacement processes by reducing the mobility of the injected phase.

• Immiscible gas and foam injection in heavy oil reservoirs can enhance the productivity by reducing the residual oil saturation.

• • Foam injection in heavy oil reservoirs can enhance the productivity by reducing the residual oil saturation.

References

1- Van Poollen H.K., Fundamentals of the enhanced oil recovery, 1980

2- Doscher , T.M.: Tertiary recovery of crude oil, ‘Pergamon Press, New York, 1976

3- Houpeurt, A. H.: Tertiary oil recovery processes, Pergamon Press, New York, 1976

5- Green w. Green: Enhanced oil recovery

6- Chiang J. C. et. al.: foam as a mobility control agent in steam injection processes,

paper SPE 8912, presented at the 1980 SPE califprnia.

7- Albrecht, R.A. and Marsden jr. : foam as blocking agents in porous media, SPEJ 1970

8- Minssieux, L: oil displacement by foam in relation to their physical properties in porous

media, JPT Jan. 1974.

9- Bernard, G.G. and Holm, L.W. : Effect of foam on permeability of porous media to gas,

SPEJ, Sept. 1964, AIME. 231

10- Dietz, D.N., Bruining , J and Heijna, H.B.: Foam drive seldom meaningful, JPT, May 1985

11- Ostwald, W.: uber die geshwindigkeitsfunktion der viskositat dispersen systeme,

Kolloid z. 1925

12- Reza, S.H. and Marsden Jr. s.s.: The streaming potential and the rheology of foam,

SPEJ, Dec. 1967.

13- Delinger, S.E. , Dalton J.T. , and Holbrooks, S.T.: CO2 miscibility control. SPEJ 1984.

14- David, A. and Marsden gr. s.s.: The rheology of foam, SPE Denver, sept. 28-Oct.

15- Dake, L.W. :Enhanced oil recovery, NJ- 1989.

16- Heller, J.P., Change, L.L., and Murty, S.K.: foam-like dispersions for mobility control in

CO2 floods, SPEJ, Aug. 1985

17- Holm, L.W.: Foam injection test in the stiggins field, JPT, Dec. 1970.

18- Patton, J.T. , Holbrook, S.T. and Hsu w.: Rheology of mobility control foams, SPEJ. 1983

19- Reza S.H. , Foam in porous media: characteristics and potential applications, SPEJ, 1970