Reservoir and operational parameters influence in SAGD process

Journal of Petroleum Science and Engineering 54 (2006) 34 – 42 www.elsevier.com/locate/petrol

Reservoir and operational parameters influence in SAGD process J.L.M. Barillas a,⁎, T.V. Dutra Jr. a , W. Mata b Universidade Federal do Rio Grande do Norte, Departamento de Engenharia Química — CT — Campus Universitário UFRN, Lagoa Nova, Natal/RN — CEP: 59078-970, Brazil b Universidade Federal do Rio Grande do Norte, Departamento de Engenharia Elétrica — CT — Campus Universitário UFRN, Lagoa Nova, Natal/RN — CEP: 59078-970, Brazil

a

Received 23 September 2005; received in revised form 20 June 2006; accepted 30 July 2006

Abstract Thermal processes are used to improved heavy oil recovery, and they could be based on the steam injection, i.e. cyclic or continuous injection. The continuous injection has many variations, and has been studied both theoretically and experimentally (in pilot projects and in full field applications). One of the technologies that is being studied is one variation of the continuous injection, the steam assisted gravity drainage (SAGD). This process uses two horizontal wells: the steam injector at the top of the reservoir and the producer in the bottom. The purpose of this design is to create a steam chamber, providing a better sweep of the reservoir. This process comes as a quite an efficient alternative to recover heavy oils and bitumen. In this study a homogeneous model was idealized to analyze the effect of permeability barriers and vertical permeability on cumulative oil. A steam optimization was done for some reservoir parameters. It was found that heterogeneity and vertical permeability had a major influence on oil recovery and that optimal steam rate varies depending on the reservoir characteristics. © 2006 Elsevier B.V. All rights reserved. Keywords: IOR; SAGD; Thermal methods; Reservoir modeling

1. Introduction Steam assisted gravity drainage (SAGD) process is an effective method for heavy oil and bitumen production and involves two parallel horizontal wells, one above the other, where the top well is the steam injector and the bottom is the oil producer. When steam is continually injected in the top well the oil is heated up and forms a steam chamber which grows upward and to the surroundings (Butler and Stephens, 1981; Butler, 1991) and continues to grow with continuous steam injection. Fig. 1 shows a schematic representation of that theory. ⁎ Corresponding author. Fax: +55 84 32153760. E-mail address: [email protected] (J.L.M. Barillas). 0920-4105/$ - see front matter © 2006 Elsevier B.V. All rights reserved. doi:10.1016/j.petrol.2006.07.008

The temperature inside the steam chamber becomes essentially equal to the temperature of the injected steam. At the interface with cold oil (oil at reservoir temperature) the steam condenses and the heat is transferred to the oil. Heated oil and condensed water then drain to the horizontal producer due to gravity segregation. The SAGD process can reach a great area of the reservoir to be drained. In this process, heat exchange can occur by conduction, convection, and due to the latent heat of steam. SAGD theory for heavy oil recovery using horizontal wells was developed by Butler (Butler and Stephens, 1981; Butler, 1991). The equation that describes the initial theory is: q = √[(2ϕΔSo Kgαh) / (mνs); where, q: oil drained rate; ϕ: porosity; ΔSo: difference between the initial and the residual oil saturation;

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Fig. 1. Butler's SAGD theory (Butler, 1991).

k: effective oil permeability; g: gravitational constant; α: thermal rock diffusivity; h: steam chamber height; m: dimensionless coefficient that relates viscosity and temperature in an empiric form; and νs: cinematic oil viscosity at interface temperature. The consequences of this theory (Akin and Bagci, 2001) could be that the steam chamber growth is necessary for oil production; in other words, oil production occurs while steam is injected and an increase of steam temperature increases oil temperature and oil production. The SAGD process presents a significant advantage when compared to conventional continuous steam injection process. In continuous steam injection, oil is pushed to a cold area where its mobility is reduced, while in the SAGD process, oil is drained with a flow approximately parallel to the steam chamber, arriving at the producer well still warm and with high mobility (Butler, 1991). SAGD performance can be significantly affected by operational and geometric reservoir parameters (Kamath et al., 1993; Akin and Bagci, 2001; Kisman and Yeung, 2002; Queipo et al., 2002; Barillas et al., 2004). Examples of that could be: horizontal and vertical rock permeability, reservoir heterogeneity, oil reservoir thickness, and operational conditions such as: distance between wells, wells' length and steam rate. This study analyzed the sensibility of reservoir heterogeneity on oil rate and on cumulative oil, and studied the influence of vertical permeability on cumulative oil and gas–oil ratio. Also, steam was optimized for some reservoir parameters such as: heterogeneity, permeability, viscosity and oil thickness. All studied cases were done using the simulator ‘Stars’ from CMG (Computer Modelling Group, version 2004.2). 2. Reservoir modeling The physical model corresponds to an oil reservoir of 100 m × 600 m × 20 m size, with an aquifer of 100 m × 600 m × 6 m at the reservoir bottom (three layers). The model has two horizontal wells, one injector located above the oil producer. Steam is injected

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continually while the producer well is drained continually. The limits of the reservoir were considered closed to the flow of fluids, allowing heat exchange with the surroundings. Other considerations were: reservoir fluids were modeled with three phases (oleic, gaseous and aqueous) and there are three components: oil (heavy hydrocarbons), water and gas (light hydrocarbons); oleic phase is composed by gas and oil; aqueous phase is only composed of water; gaseous phase can contain steam and gas; chemical reactions don't exist; solids don't exist in the considered fluids. Grid, rocks, and fluid properties used in the computational model are presented in Table 1; oil viscosity and relative permeability for oil, water and gas are presented in Tables 2 and 3. Table 4 shows the range of reservoir attributes analyzed and the base case. Ranges that were considered for permeability and viscosity are values found in a Brazilian sedimentary basin. 3. Results 3.1. Reservoir heterogeneity For this analysis, barriers with very low permeability were considered in the reservoir. Three different systems were analyzed: a single barrier of 60 m × 300 m × 2 m size, Table 1 Reservoir model Total grid blocks Reservoir size in x-axis (m) Reservoir size in y-axis (m) Reservoir size in z-axis (m) Reservoir temperature (°C) Reservoir thickness (m) Grid size i direction (m) Grid size j direction (m) Grid size k direction (m) Number blocks i direction Number blocks j direction Number blocks k direction Initial oil saturation, So (%) Initial water saturation, Sw (%) Original oil in place (m3 std) Horizontal permeability, Kh, (mD) Vertical permeability, Kv (mD) Porosity (%) Steam quality Steam injection rate (t/day) Thermal conductivity of rock and surrounding formation overburden and underburden (BTU/ft-day-F) Thermal conductivity of water (BTU/ft-day-F) Thermal conductivity of oil (BTU/ft-day-F) Thermal conductivity of gas (BTU/ft-day-F) Volumetric heat capacity of surrounding formation overburden and underburden (BTU/ft3-F)

10,920 100 600 26 37.8 20 Variable 15 2 21 40 13 61 39 217,190 1000 100 30 0.50 100 24 8.6 1.8 0.6 35

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Table 2 Oil viscosities 300 cP

1000 cP

3000 cP

Temperature (K)

Viscosity (cP)

Temperature (K)

Viscosity (cP)

Temperature (K)

Viscosity (cP)

316 335 346 360 374 402 457 513 569 624 652

4013.4 671.0 300.0 129.6 64.8 22.3 5.6 2.3 1.2 0.7 0.6

316 335 346 360 374 402 457 513 569 624 652

23,028.0 2645.3 1000.0 363.4 158.0 44.2 8.8 3.3 1.6 0.9 0.7

316 335 346 360 374 402 457 513 569 624 652

113,632.5 9257.9 3000.0 929.5 354.9 81.8 13.1 4.4 2.1 1.2 0.9

a single barrier of 60 m × 510 m × 2 m size and two barriers of 60 m × 180 m × 2 m size located in the same layer, leaving 150 m of distance between them. Fig. 2 shows a schematic representation for the barriers system in the reservoir. Each barrier was modeled with a horizontal permeability of 1 × 10− 7 mD and a vertical permeability of 1 × 10− 9 mD. The location of these barriers in the reservoir grid is shown in Table 5. The influence of the barrier depth on oil rate and on cumulative oil was analyzed for all systems. 3.1.1. Barrier with 60 m × 300 m × 2 m size Fig. 3 shows oil rate production with a barrier between the injector and producer wells. This barrier has a smaller length than both wells and was located at different depths. Fig. 3 also shows oil saturation at block

Table 3 Relative permeabilities Relative water permeability

Relative gas permeability

Sw

Krw

Krow

Sl

Krg

Krog

0.28 0.31 0.34 0.36 0.39 0.42 0.45 0.48 0.50 0.53 0.56 0.59 0.62 0.64 0.67 0.70 1.00

0.00 0.01 0.01 0.03 0.04 0.06 0.08 0.10 0.12 0.14 0.16 0.19 0.21 0.24 0.27 0.30 1.00

0.80 0.74 0.67 0.61 0.55 0.49 0.43 0.38 0.32 0.27 0.21 0.16 0.12 0.07 0.03 0.00 0.00

0.70 0.72 0.74 0.76 0.77 0.79 0.81 0.83 0.85 0.87 0.89 0.91 0.92 0.94 0.96 0.98 1.00

0.45 0.41 0.36 0.32 0.28 0.25 0.21 0.18 0.14 0.11 0.09 0.06 0.04 0.02 0.01 0.00 0.00

0.00 0.01 0.04 0.06 0.10 0.14 0.18 0.23 0.28 0.34 0.39 0.45 0.52 0.58 0.65 0.72 0.80

11, 20, 8, located at center of the producer well center. After 14 years of production, cumulative oil rate for each case was 69.6, 69.5 and 68.0 × 103 m3 STD (barriers at layers 4, 5 and 6 respectively). There was no significant influence of the barrier depth on oil rate neither on cumulative oil. It can be observed that the barrier's depth did not affect the oil produced. However, presence of a barrier permits a stable production flow rate, which stays above 10 std m3/day for 13 years. When injection begins steam pushes oil vertically towards to the producer end due the barrier, leading to a rapid increase on oil rate that reaches a peak before one year of production. Once the steam front reaches producer end, it pushes the oil horizontally to the well center. During this period oil rate is stabilized as can be seen in Fig. 3. The figure also shows stable oil saturation in a block at the producer center during most of the time, corresponding to the near constant oil rate period. By the end of period, saturation and oil rate decrease. Similar behavior was observed in other blocks along the producer, with a decrease in saturation Table 4 Reservoir range parameters Reservoir parameter

Minimum

Maximum

Base model

Horizontal permeability (mD) Vertical permeability (mD) Oil viscosity (cP) Oil reservoir thickness (m) Permeability barriers

500

2000

1000

50

400

100

300

3000

1000

10

30

20

60 m × 510 m × 60 m 60 m × 300 m × 60 m Without barriers

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Fig. 2. Barrier's systems.

occurring at different times according to the block position relative to well center. 3.1.2. Barrier with 60 m × 510 m × 2 m size In this system the barrier and wells length have the same size (510 m). Fig. 4 shows the oil production and cumulative oil with a barrier between the injector and producer wells at different reservoir depths. Oil rate curves do not match that maximum production peak observed in Fig. 3. This could be due to the barrier length and the very low permeability which does not allow the steam chamber to extend completely. Steam flow should surround the barrier to arrive at the producer that is below the barrier. The barrier just allows the steam chamber to flow upward and to the sides, not allowing the heated oil to drain easily to the producer well in the initial production period (before 3 years of production). Then, the

Table 5 Permeability barriers in the grid blocks Shale barriers

i

j

k

Distance between well and barriers (m)

300 m × 60m × 2 m

4–18

11–30

510 m × 60 m × 2 m

4–18

4–37

180 m × 60 m × 2 m

4–18

4–15 and 26–37

4 5 6 4 5 6 4 6

4 6 8 4 6 8 4 8

fluid arrives at the producer well only after having surrounded the permeability barrier, and increases the oil rate production for more eight years. Fig. 4 also shows too cumulative oil for different depth barriers and it can be observed that a barrier closer to the injector well (located in layer 4) increases the cumulative oil production. Apparently the barrier is acting as a heat distributor, helping to spread the steam in the whole reservoir, increasing oil production. 3.1.3. Two barriers with 60 m × 180 m × 2 m size each one Two barriers with 60 m × 180 m × 2 m in size were located in same layer separated each other by 150 m (see Fig. 2). Cumulative oil production (after 14 years) was 72,019 and 69,365 m3 std, this for the barriers located at layers 4 and 6 respectively. The barrier depth has low influence on cumulative oil production; however, oil recovery and cumulative oil are both higher when the barriers are located closer to the injector well. 3.1.4. Comparison between barriers All barriers showed the same behavior, i.e., when the barrier is closer to the injector well, cumulative oil increases. Fig. 5 shows the effects of barriers on oil recovery; this graph could be used to verify which one could be the most favorable situation. Before 7 years of production, it is better not to have any barrier to obtain a high oil recovery, but later a larger barrier can be more favorable in terms of oil recovery. Cumulative oil is affected by reservoir heterogeneity, but in this model heterogeneity could be favorable to oil recovery.

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Fig. 3. Cumulative oil and oil rate for 300 m × 60 m × 2 m shale barrier, at different layers.

3.1.5. Optimum steam rate In order to do a steam optimization (for all cases studied and modeled), a plot of steam rate versus final oil recovery was done. The final oil recovery was at 14 years of production or when a minimum oil-steam ratio of 0.1 m3/t was reached. Steam optimization was done for two barriers (60 m × 300 m × 2 m and 60 m × 510 m × 2 m respectively). Fig. 6 shows the steam rate versus final oil recovery. It can be observed that the maximum oil recovery, 34%, is larger for a barrier with 500 m of length when the steam is optimized at 90 t/day. For the 300 m length barrier, the maximum oil recovery was 32% with an injection of approximately 100 t/day. In this model, the optimum steam rate is affected by barriers in the reservoir. Fig. 6 shows that, barriers provide better oil

recovery when compared to the base model (without barrier — homogeneous model). 3.2. Vertical permeability To study the influence of vertical permeability (Kv) on cumulative oil, five cases were considered: 50 mD, 100 mD, 200 mD, 300 mD and 400 mD. Horizontal permeability (Kh) was fixed at 1000 mD, giving a Kv/Kh ratio of 0.05, 0.1, 0.2, 0.3 and 0.4, respectively. Cumulative oil production and gas oil ratio at reservoir conditions are presented in Fig. 7 It is observed that cumulative oil increases with a decrease of vertical permeability, and it can also be visualized that above 200 mD the influence of this parameter on cumulative oil production is small. The best curve of cumulative oil

Fig. 4. Oil rate and cumulative oil for 510 m × 60 m × 2 m shale barrier, at different layers.

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Fig. 5. A comparison between barriers on oil recovery.

production was obtained with the smallest vertical permeability (50 mD) studied. In the modeling of Ugnu tar sands reservoir (North Slope, Alaska), the simulation indicated an inverse behavior, when the anisotropy decreased the oil rate and cumulative oil production also decreased (Sharma et al., 2002). The reason for this behavior may be because this is a homogeneous model and steam is moving directly to the producer well due to high vertical permeability and not allowing a good lateral expansion of the steam chamber. Fig. 7 shows gas oil ratio (GOR) for vertical permeability values studied. The reservoir with larger vertical permeability (400 mD) has a larger GOR curve, indicating that the steam is flowing directly to the producer well due to high vertical permeability, and consequently chamber expansion is smaller and oil production decreases. A steam optimization model was also carried as showed in Fig. 8. Maximum oil recovery was obtained in

the reservoir with smaller vertical permeability, and the best steam rate was approximately 75 t/day (in the base model, the steam rate was 100 t/day). It can be visualized that a high vertical permeability requests a smaller amount (70 t/day) of steam to obtain maximum oil recovery in the SAGD process. Therefore, to maximize oil recovery, the steam rate should be decreased when the vertical permeability is higher. 3.3. Horizontal permeability The steam rate was optimized for different horizontal permeabilities (Kh = 500, 1000 and 2000 mD), and results showed that oil recovery is better when the reservoir permeability is high. For the studied cases the influence of horizontal permeability on optimum steam rate is not significant. Maximum oil recovery obtained was 31% for 2000 mD permeability with 80 t/day of

Fig. 6. Steam rate versus oil recovery for different shale barriers.

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Fig. 7. Oil recovery and gas oil ratio at reservoir conditions for different vertical permeabilities.

Fig. 8. Steam rate versus oil recovery for different vertical permeabilities.

steam injection, 29% for 1000 mD with 79 t/day of steam, and 26% for 500 mD permeability with 78 t/day of steam. Therefore, horizontal permeability has a small effect on the steam rate optimization.

3.4. Oil viscosity The steam rate was optimized for different oil viscosities (300, 1000 and 3000 cP, initial viscosities at

Fig. 9. Steam rate versus oil recovery for oil reservoir thickness.

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Fig. 10. Pore volume injected versus oil recovery for different oil reservoir thickness.

reservoir conditions), and it was found that oil recovery is better when oil viscosity is small. It can be observed that for the three studied cases (300, 1000 and 3000 cP), it is necessary to inject between 75–80 t/day of steam to obtain a maximum oil recovery (32%, 29% and 26% for 300 cP, 1000 cP and 3000 cP, respectively). It was also observed that there is a small difference of steam requirement between the lower (300 cP) and the higher (3000 cP) oil viscosity, with the lower viscosity requiring less steam injection. 3.5. Oil reservoir thickness The effect of oil reservoir thickness on oil recovery was also studied. Steam rate injected was 100 t/day for all cases. It was observed that for the same injected pore volume a smaller oil recovery was obtained for the smaller oil reservoir thickness (10 m), and a larger oil recovery was obtained for the thickest reservoir (30 m). Fig. 9 shows oil recovery as function of steam injection rate for different oil reservoir thickness. It can be observed that for the largest thickness (30 m) a steam rate of 110 t/day is necessary to obtain the maximum oil recovery of 28%, and that the lowest thickness (10 m) requires a smaller rate (50 t/day) to obtain also a maximum oil recovery of 28%. Maximum oil recovery is approximately equal to 28% for all reservoirs; the difference is the steam injection rate. In this model it could be observed that the best steam rate depends on the oil reservoir thickness. Fig. 10 shows oil recovery versus pore volume injected when optimized steam rate obtained from Fig. 9 is used. It can be observed that larger oil reservoir thickness (30 m) leads to greater oil recovery for a same pore volume injected that was the

same behavior when the steam rate injected was constant for all three reservoirs (10, 20 and 30 m). 4. Conclusions It was found in this heterogeneous reservoir model that: • The barriers between injector and producer wells also affected oil recovery. The presence of a barrier located closer to an injector well increases oil recovery when the steam is optimized. In this study, the steam requirement was largely influenced by the barriers in the reservoir; • Vertical permeability affects largely oil recovery. When Kv/Kh is lower, cumulative oil production and oil recovery increase. This parameter affects the optimum injected steam rate. The gas oil ratio at reservoir conditions increase when vertical permeability is higher; • Parameters such as horizontal reservoir permeability and oil viscosity showed little influence on optimum steam rate, within the ranges considered in this study; • A larger oil reservoir thickness (range studied between 10 m and 30 m), increases oil recovery at the same pore volume of steam injected. Oil reservoir with the smallest thickness required a lower steam injection rate to obtain maximum oil recovery. Acknowledgements The authors want to thank Petrobrás and the PRHANP 14 for the support received in the execution of this work.

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References Akin, S., Bagci, S., 2001. A laboratory study of single-well steamassisted gravity drainage process. J. Pet. Sci. Eng. 32, 23–33. Barillas, J.L.M., Mata, W., Dutra, Jr., T.V., Queiroz, G.O., 2004. A parametric simulation study for SAGD thermal method. 25th Iberian Latin American Congress on Computational Methods in Engineering. CILAMCE 2004: Recife — Brazil, 672. Technical paper in CD-ROM: 25th Iberian Latin American Congress on Computational Methods in Engineering XXV CILAMCE 2004. 10–12 November. Butler, R.M., 1991. Thermal Recovery of Oil and Bitumen, vol. 7. Prentice Hall, New Jersey USA, pp. 285–358. Butler, R.M., Stephens, D.J., 1981. The gravity drainage of steam heated heavy oil to parallel horizontal wells. J. Can. Pet. Technol. 4–6.

Kamath, V.A., Sinha, S., Hatzignatiu, U., 1993. Simulation study of steam-assisted gravity drainage process in Ugnu Tar Sand reservoir. SPE Western Regional Meeting Held in Anchorage. SPE, Alaska U.S.A, pp. 26–28. May. Kisman, K.E., Yeung, K.C., 2002. Numerical study of the SAGD process in the Burnt Lake oil sands lease. SPE International Heavy Oil Symposium Held in Calgary. SPE, Calgary Canada, pp. 19–21. June. Queipo, N.V., Goicochea, J.V., Pintos, S., 2002. Surrogate modelingbased optimization of SAGD processes. J. Pet. Sci. Eng. 35, 83–93. Sharma, B.C., Khataniar, S., Patil, S.L., Kamath, V.A., Dandekar, A.Y., 2002. A simulation study of novel thermal recovery methods in the Ugnu Tar Sand reservoir. SPE Western Regional/AAPG Pacific Section Joint Meeting Held in Anchorage. SPE, Alaska, USA. 20–22. May.