SPE 115710

Oil Recovery by Miscible SWAG Injection M. Jamshidnezhad/ National Iranian South Oil Co

Copyright 2008, Society of Petroleum Engineers This paper was prepared for presentation at the 2008 SPE Russian Oil & Gas Technical Conference and Exhibition held in Moscow, Russia, 28–30 October 2008. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.

Abstract Previous studies showed that injection of water and gas as water alternating gas (WAG) process or simultaneous water and gas (SWAG) process can improve the sweep efficiency. Therefore, oil recovery from depleted reservoirs can be enhanced by combined injection of water and gas. However, SWAG process compare to WAG process is less known. Investigation of factors that affect on miscible SWAG injection is the aim of this study. For this purpose, a three-dimensional finite-difference reservoir simulator is used. Methane (as gas) at minimum miscibility pressure (MMP) is injected into an under-saturated reservoir which contained typical North Sea oil. Water and gas are injected at fixed rates by two separate horizontal wells. For more sweep efficiency and increase the distance gas and water travel before segregation, gas is injected at the bottom of reservoirs. For water, different locations of injection are tested and the effect of water injection location is studied. We also investigate the effect of water to gas injection rate ratios, well models, and reservoir heterogeneity on sweep efficiency and oil recovery.

Introduction Injection of gases (steam, CO2 or hydrocarbon gas) is an important method for increasing recovery in declining oil fields. Gas improved oil recovery (IOR) can in principle recover nearly all the oil in place, but sweep efficiency of injected gas is poor (Lake, 1989). Reasons for poor sweep efficiency include reservoir heterogeneity, low density of gas, and low viscosity of the gas. In relatively homogeneous reservoirs low gas density, leading to gravity override, can severely limit gas sweep and oil recovery. In most cases gas is injected together with, or alternating with, water, to reduce gas mobility. In a homogeneous reservoir the flow of fluids is influenced by the density and mobility differences between the injected and resident fluids. In heterogeneous reservoir permeability differences play a dominant role (Waggoner et al., 1992). The injected fluid(s) prefer to flow through high-permeability layers, which lead to channeling. The low-permeability layers are bypassed and not swept by the solvent. If heterogeneities are not present, gravity governs fluid flow in the reservoir. Solvent in general has a lower density than oil (and water) and segregates to the top of the reservoir, leaving the bottom part untouched by the solvent. Previous studies showed that injection of water and gas as water alternating gas (WAG) process or simultaneous water and gas (SWAG) process can improve the sweep efficiency. Therefore, oil recovery from depleted reservoirs can be enhanced by combined injection of water and gas (Jamshidnezhad et al. 2008). The equations of Stone (1982) and Jenkins (1984) predict the distance gas and water travel before they segregate completely into underride and override zones. The equations describe the steady state that would eventually be attained once all mobile oil has been removed from the region in which segregation occurs. ). In each zone (mixed, override and underride) saturations and mobilities are uniform. In rectangular and cylindrical flow, the mixed zone disappears at position Lg and Rg, respectively:

( )g mz w g rt

QLk gWρ ρ λ

=−

(1)

( )g mz w g rt

QRk gπ ρ ρ λ

=−

(2)

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where Q is total volumetric injection rate of gas and water, kv vertical permeability, ρw and ρg densities of water and gas, respectively, g gravitational acceleration, and λrtm the total relative mobility in the mixed zone.

Shi and Rossen (1998) show that Eqs. 1 and 2 can be recast in the following way:

( )1g m h

g L zw g

pL HkL N R Lkgρ ρ

⎛ ⎞∇ ⎛ ⎞⎜ ⎟= ≡ ⎜ ⎟⎜ ⎟− ⎝ ⎠⎝ ⎠

(3)

( ) ( )( )

( )12 gm h

g zg g L g w g

p R HkR kN R R R gρ ρ

⎛ ⎞∇ ⎛ ⎞⎜ ⎟= ≡ ⎜ ⎟⎜ ⎟⎜ ⎟− ⎝ ⎠⎝ ⎠

(4)

In Eq. 3, L is the length of the reservoir; Ng and RL are dimensionless gravity number and reservoir aspect ratio, respectively, |∇p|m the lateral pressure gradient in the mixed zone at the injection face, H reservoir height, and kh horizontal permeability. In Eq. 4, gravity number and reservoir aspect ratio are defined as functions of the segregation length Rg, the pressure gradient used in the gravity number, |∇p|m(Rg), is defined as the horizontal pressure gradient that would be present in the mixed zone at radial position Rg in the absence of any gravity segregation. At later study, Stone (Stone 2004) showed that injecting gas along with water gives higher oil recovery than water flood alone. He concluded that simultaneous water and immiscible gas floods can reduce water flood residual oil saturations by 50-100 % in water-wet and intermediate-wet reservoirs, and can provide over 3-fold greater vertical gas sweep than alternate injection. The studies presented by Stone did not investigate effects of different parameters on SWAG. Investigation of factors that affect on miscible SWAG injection is the aim of this study. For this purpose, a three-dimensional finite-difference reservoir simulator is used. Methane (as gas) at minimum miscibility pressure (MMP) is injected into an under-saturated reservoir which contained typical North Sea oil. Water and gas are injected at fixed rates by two separate horizontal wells. For more sweep efficiency and increase the distance gas and water travel before segregation, gas is injected at the bottom of reservoirs. For water, different locations of injection are tested and the effect of water injection location is studied. We also investigate the effect of water to gas injection rate ratios, well models, and reservoir heterogeneity on sweep efficiency and oil recovery.

Reservoir Model We built the reservoir model by rectangular Cartesian grids. A summary of reservoir dimensions and physical properties can be seen in Table 1. Gas (methane) and water are injected by two separate horizontal wells on the left-hand site, and fluids are produced by a vertical production well located on the right-hand site of the reservoir. The reservoir is initially saturated by typical North Sea oil (Boersma 1990). PVT properties of oil are summarized in Table 2. Reservoir temperature is 100 oC and fluids are injected at 348 bar (minimum miscibility pressure, MMP, Boersma 1990). In all cases, simulations are done in a randomly generated permeability field, with perturbations of 10%. The values of kz and kh are randomly selected from a uniform distribution extending 10% below and 10% above the average permeability values for each direction. Variations of vertical and horizontal permeability along the wells are plotted in Figure 1. Figure 2 shows relative permeability data. A three-dimensional compositional finite-difference reservoir simulator, STARS (Computer Modeling Group, Alberta, Canada), is used to determine the effects of several design parameters on the efficiency of SWAG injection process. STARS (Steam, Thermal, and Advanced Processes Reservoir Simulator) is CMG's advanced processes simulator for modeling the flow of three-phase, multi-component fluids, which includes options such as chemical/polymer flooding, thermal applications, steam injection, horizontal wells, flexible grids and many more. The injection technique involves the simultaneous injection of water at different locations of the reservoir formation and injecting gas at the bottom of the formation for 10 years. Figure 3 shows the schematic representation of the proposed SWAG injection technique.

Table 1: Grid size and rock properties for different cases Volume (L*W*H) m3

No. of grids ( Nx*Ny*Nz)

Total injection rate (res.m3/d)

Porosity (fraction)

Horizontal permeability (md)

Vertical permeability (md)

(32*40*20) 64*10*43 15000 0.25 1000 210

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Table 2: Fluid properties Fluid Density (kg/m3) Viscosity

(cp) Water 1000 1 N2 163 0.0144 C12H26 804 0.86

Figure 1. Variations of vertical and horizontal permeability along the wells

Kx

920940960980

100010201040106010801100

0 2 4 6 8 10 12 14 16

Grid block number in J direction

Kx

(mD

)

Kz

0

50

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250

0 2 4 6 8 10 12 14 16

Grid block number in J direction

Kz

(mD

)

Figure 2. Relative permeability data

0

0.1

0.2

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0 0.2 0.4 0.6 0.8 1

Sw

Kr Krw

Krow

0

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0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1

Sl

Kr Krg

Krog

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Figure 3. schematic representation of the proposed SWAG injection technique.

Simulation Runs For better understanding the effect of different parameters, we define a "base case" and then compare other cases with the base case. The base case represents a homogeneous reservoir initially saturated with oil (at So) and water (at Swc), and then water is injected at the middle and gas is injected at the bottom through two horizontal wells. For this case, total injection rate of gas and water is about 7000 sm3/day and water fraction of 0.28. Figures 4 and 5 show the results of 10 years gas and water injection in "base case". As we can see from Figure 4, the ultimate recovery for simultaneous injection of water and gas in base case is about 75%. Figure 5 shows that segregation occurs after 7 m traveling in layer 10. Figure 6 reveals nearly uniform movement of fluids before segregation. Figure 4. Recovery factor in base case model Figure 5. Gas-water segregation in base case, view in IK plane

Base case

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Time

RF

In the next case, we investigate effect of water injector location on oil recovery and segregation. Figures 7 and 8 show schematics of two cases: case with water injection at top of reservoir and case with water injection near gas injection well. As we can see from Figure 9, changing the location of water injector has no effect on oil recovery factor. For these cases segregation again occurs at 14th grid( in i-direction) and movement of fluids before segregation is nearly uniform, Figures 10-13. Effect of gas flow rate on segregation length is shown in Figures 14 and 15. In this case we doubled gas flow rate from 7000 sm3/day to 14000 sm3/day. Figure 16 compares oil recovery factor of this case to base case. Another case is a case with double water injection rate. Results of this case are shown in Figures 17 and 18. Effect of increasing water injection rate on oil recovery and its comparison to base case is shown in Figure 19. The last case we study is a heterogenic model. In this case vertical and horizontal permeability are distributed randomly. Horizontal permeability data are between 1 and 1000 md, vertical permeability data are between 1 and 220 md, Figure 20. Effect of heterogeneity on oil recovery is shown in Figure 21. From Figure 22, one can see that heterogeneity increases non-uniformity of gas through the reservoir, however, segregation length is greater than base case, see Figure 23.

SPE 115710 5

Figure 6. Fluids uniform flow before complete segregation Figure 7. Schematic of SWAG, water at nearly top

Figure 8. Schematic of SWAG, water at nearly bottom Figure 9. Effect of water injector location on recovery factor

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Time (day)

RFBase case

Water is injected at top

water is injected neargas well

Figure 10. Gas-water segregation, case of Figure 11. Gas-water segregation, case of “water at top”, view in IK plane “water at top”, view in IJ plane

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Figure 12. Gas-water segregation, case of Figure 13. Gas-water segregation, case of “water at nearly bottom”, view in IJ plane “water at nearly bottom”, view in IK plane

Figure 14. Gas-water segregation, case of Figure 15. Gas-water segregation, case of “doubled gas injection rate”, view in IJ plane “doubled gas injection rate”, view in IK plane

Figure 16. Effect of gas injection rate on recovery factor Figure 17. Gas-water segregation, case of “doubled water injection rate”, view in IK plane

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Figure 18. Gas-water segregation, case of “doubled water Figure 19. Effect of water injection rate on recovery factor injection rate”, view in IJ plane

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w ater is injected atdoubled rate

Figure 20. Horizontal and vertical permeability distribution in heterogeneous case

Figure 21. Effect of heterogeneity on oil recovery factor Figure 22. Gas-water segregation, case of “heterogeneous” view in IJ plane

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Figure 23. Gas-water segregation, case of “heterogeneous” view in IK plane

Conclusions Simultaneous water and gas injection into petroleum reservoirs is more efficient than alone gas injection and water injection. In this study, we investigated effect of several factors on simultaneous water and gas injection. These factors were gas to water injection rates, location of water injector, and heterogeneity of horizontal and vertical permeabilities. As we can see from Figure 24, these factors have no strong effect on oil recovery factor. However, they can affect on segregation length and non-uniformity of gas flow.

Figure 24. Effect of different factors on oil recovery factor

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Gas rate doubled Base caseHeteregenous case Water is injected at topwater is injected near gas well water is injected at doubled rate

References Jamshidnezhad, M., Chen,C. Kool,P. and Rossen, W.R., “Well Stimulation and Gravity Segregation in Gas Improved Oil Recovery”, SPE

112375, presented the 2008 SPE International Symposium and Exhibition on Formation Damage Control held in Lafayette, Louisiana, U.S.A., 13–15 February 2008

Jenkins, M. K., 1984: "An Analytical Model for Water/Gas Miscible Displacements," SPE 12632, presented at the 1984 SPE/DOE Symposium on Enhanced Oil Recovery, Tulsa, OK, April 15-18.

Lake, L.: Enhanced Oil Recovery, Prentice Hall, Englewood Cliffs, NJ (1989). Shi, J.-X., and Rossen, W.R.: ‘Simulation of Gravity Override in Foam Processes in Porous Media,’ SPEREE 1, 148-154, 1998. Stone, H. L.: "A Simultaneous Water and Gas Flood Design with Extraordinary Vertical Gas Sweep," SPE paper 91724, presented at the

2004 SPE International Petroleum Conference in Mexico, 7-9 November, Puebla, Mexico. Stone, H. L.: "Vertical Conformance in an Alternating Water-Miscible Gas Flood," SPE 11130, presented at the 1982 SPE Annual Tech.

Conf. and Exhibition, New Orleans, LA, Sept. 26-29. Waggoner, J.R., Castillo, J.L. and Lake, L.W.: ‘Simulation of EOR Processes in Stochastically Generated Permeable Media,’ SPE 21237,

SPE Formation Evaluation, 173-180, June 1992.