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A laboratory study of hot WAG injection into fractured and conventional sand packs

A laboratory study of hot WAG injection into fractured and conventional sand packs method used in heavy oil fi elds. To increase the extent of the reservoir contacted by the injected gas, the gas is generally injected intermittently with water. This mode of injection is called water-alternating- gas (WAG). This study deals with a new immiscible water alternating gas (IWAG) EOR technique, “hot IWAG” which includes combination of thermal, solvent and sweep techniques. In the proposed method CO will be superheated above the reservoir temperature and instead of normal temperature water, hot water will be used. Hot CO and hot water will be alternatively injected into the sand packs. A laboratory test was conducted on the fractured and conventional sand packs. Slugs of water and CO with a low and constant rate were injected into the sand packs alternatively; slug size was 0.05 PV. Recovery from each sand pack was monitored and after that hot water and hot CO were injected alternatively under the same conditions and increased oil recovery from each sand pack and breakthrough were measured. Experimental results showed that the injection of hot WAG could signifi cantly recover residual oil after WAG injection in conventional and fractured sand packs. Hot water-alternating-gas (WAG), enhanced oil recovery (EOR), fractured sand pack, Key words: conventional sand pack, gas injection past, CO and hydrocarbon gases constitute the major share 1 Introduction 2 of injectants (~90%). CO is ideally suited for use in gas Under conditions prevailing in many oil reservoirs, gas- injection projects in the U.S. scenario. Abundance of reserves oil immiscible displacement has higher microscopic sweep of almost pure CO and availability of technical know-how efficiency than water-oil displacement. However, gas as a has been the cause for the growth of CO injection processes displacing agent suffers the obvious drawback because of its in the U.S. Carbon sequestration is now an added advantage very high mobility (Lawrence et al, 2003). The WAG process of the CO injection projects (Kulkarni and Rao, 2005). has been proven effective in providing mobility control The main design parameters that need to be evaluated on a laboratory scale to evaluate the feasibility of the process for horizontal gas floods, as demonstrated by many field are: reservoir heterogeneity, rock type, fluid characteristics, applications, most of which aimed at reaching miscibility injection gas, WAG ratio, and gravity considerations. Other between the injected gas and the reservoir fl uid. Immiscible parameters those are important for gas injection and tertiary WAG (IWAG), on the other hand, has a smaller record of fi eld recovery in general, are those of miscibility development and experience (Christensen et al, 2001). The development of composition of oil and brine (Kulkarni, 2003). the water-alternating-gas (WAG) process aims at improving Little is known about the application of WAG injection flood profile control. The higher microscopic displacement in naturally fractured reservoirs. It was believed that it effi ciency of gas combined with the better macroscopic sweep was impossible to use the advantages of water flooding efficiency of water significantly increases the incremental and gas injection together due to the existence of fractures oil production over that from a plain water flood. Nearly in reservoirs (Haghighat, 2004). Fractures cause rapid all the commercial gas injection projects today employ the advancement of injected fluids that changes a major WAG method (Kulkarni and Rao, 2005). In spite of these advantage of WAG injection; namely, water cycles that improvements, the fi eld performance of WAG process (5%- are stabilizing the flooding front (Heeremans et al, 2006). 10% OOIP recovery) is disappointing (Rao, 2001). In the However, there are some examples from the fi eld that show United States, most of the WAG applications are onshore, that there is potential of WAG injection in naturally fractured employing a wide variety of injection gases for a wide range reservoirs (Christensen et al, 2001). of reservoir characteristics in the miscible mode. Although The main objective of this work is to investigate the many types of injectant gases have been attempted in the feasibility of hot WAG injection by using hot CO and hot water in conventional and fractured sand packs, focusing on *Corresponding author. email: amohebbi2002@yahoo.com, amohebbi@ the heat transfer of hot CO and hot water and hydrocarbons mail.uk.ac.ir in these sand packs. Received January 27, 2009 Pet.Sci.(2009)6:400-404 401 401 2 Water-alternating-gas (WAG) technique 3 Materials and methods Water-alternating-gas (WAG) injection is a tertiary oil For a reservoir with a long CO injection history, the recovery process that has been growing in popularity since reservoir temperature will be reduced a little. The highest it was first introduced in the 1950’s. The tertiary recovery reduction is seen in the proximity of injection wells. In this process known as WAG is a combination of two secondary study, the temperature was set at 100 ˚C to represent the recovery processes of water fl ooding and gas injection. The temperature of CO flooded zones. The pressure was one WAG process was proposed originally to aim for an ideal atmosphere because the process was immiscible. The full system of oil recovery: improvements in macroscopic and details of the sand packs, fl uids, and experimental set up are microscopic sweep effi ciencies at the same time. The water given in the following sections. is used to control the mobility of the gas. The cyclic nature of the WAG process causes an increase in water saturation 3.1 Sand pack samples during the water injection half cycle and a decrease in water In this study, two sand packs were used. The structure saturation during the gas injection half cycle. This process of two sand packs was the same with a length of 35 cm inducing cycles of fl ooding and drainage causes the residual and a diameter of 4.2 cm. One of the sand packs as a oil levels when using WAG to be typically lower than that of fractured model contains a fracture in its middle. The water flooding and similar to those of gas flooding or even properties and dimensions of the two sand packs are better if capillary trapping due to small scale heterogeneities summarized in Table 1. is signifi cant (van Lingen et al, 1996). Table 1 Model properties Permeability Porosity Connate water Diameter Length Area Bulk volume Sample 2 3 D % % cm cm cm cm Conventional 1.1 20 15.66 4.2 35 13.8 484.9 Fractured 5.0 28 15.06 4.2 35 13.8 484.9 3.2 Fluid samples 3.3 Matrix and fracture system Oil used in all experiments was prepared from the Maroon Both sand packs were conventional at fi rst. For fabricating reservoir at south of Iran and its composition is given in Table a fractured sand pack, one of the sand packs was selected 2. The composition of the experimental brine (prepared in the and cut in the middle and the space between two halves of laboratory) is similar to that of reservoir brine and is given in the sand pack was fi lled with glass wool with a diameter of 2 Table 3. Injected gas was pure CO . The viscosity and density mm. The artifi cial fracture acted similar to an actual fracture. of fl uids in WAG experiments are given in Table 4. The glass wool had no effect on the surface area of the middle of the sand pack and did not influence the fluid which was used later to saturate the sand pack. This was investigated Table 2 Oil composition at 220 ˚F by measuring sand pack permeability before and after using (%) glass wool. The middle of the sand pack filled with sealing C C C i-C n-C i-C n-C C C HSCO material had zero permeability, and the sand pack had its 1 2 3 4 4 5 5 6 7+ 2 2 initial permeability of 1.1 D. The glass wool was a porous 48.45 9.223 5.144 0.867 2.507 1.032 1.289 2.129 29.36 0 0 medium with high permeability so in the middle of the sand pack it acted like a real fracture. Table 3 Brine composition 3.4 Initial saturations (%) The pore volume was measured by saturating the sand Component KC MgCl CaCl NaCl H O 2 2 2 packs with brine. The oil with a composition as shown in Table 2 was then injected into the sand packs at a rate of 0.5 Composition, % 0.03 0.43 3.20 3.60 92.74 cm /min. In this case the sand packs were vertical and oil was injected from the top of the sand packs. In the conventional sand pack, oil breakthrough was observed after 69.06 cm Fluids used in WAG experiments and their viscosities and densities Table 4 of brine was produced. The total volume of oil injected into the sand pack was 145.5 cm (1.5 PV) and the total volume Fluid Density, g/mL Viscosity, cp of brine produced from the conventional sand pack was 81.8 cm . In the fractured sand pack, oil breakthrough was Oil 0.87 2.168 observed after 97.78 cm of brine was produced. The total Water 1.00 1.020 volume of oil injected into the sand pack was 204.3 cm (1.5 PV) and the total volume of brine produced from the fractured Gas 1.6e-03 0.0182 3 sand pack was 115.3 cm . Thus, the initial water saturations, 402 Pet.Sci.(2009)6:400-404 S for conventional and fractured sand packs were 15.66% and the CO temperature increased to 120 ºC and the water wi 2 and 15.06%, respectively. Also, the initial oil saturations, S was heated to 90 ºC. Hot CO and hot water were injected oi 2 for conventional and fractured sand packs were 84.3% and alternatively into the conventional sand pack. The volume of 84.9%, respectively. This initialization was done at 25 ºC and injected fl uids, the cumulative volume of produced fl uids, and the pressure was one atmosphere. the breakthrough time were measured too. Hot gas and hot water slug sizes were about 0.05 PV and WAG ratio was 1. 3.5 Experiments The next experiment was done on the fractured sand pack to indicate the feasibility of hot WAG injection in a fractured To generate accurate predictions by field simulations of sand pack. The temperature of oven was set at 100 ºC and WAG injection into conventional and fractured reservoirs, a CO and water were injected into the fractured sand pack at set of WAG injection experiments should be performed under 2 a rate of 0.5 cm /min and 25 ºC. All the process was similar near reservoir conditions to check EOR mechanisms. to the conventional sand pack runs. The volume of CO In this study, the sand packs were placed horizontally in 2 and water injected into and the cumulative volume of fl uids the oven. The whole setup is shown in Fig. 1. In the fi rst step, produced from the fractured sand pack, and the breakthrough the conventional sand pack was targeted. The temperature of time were measured. The WAG injection was continued oven was set at 100 ºC and CO and water (room temperature until no oil was produced at the outlet. After that the heater (25 ºC)) were injected alternatively into the conventional which was in the direction of fluid injection was turned on sand pack at a rate of 0.5 cm /min. Gas and water slug sizes and the CO temperature increased to 120 ºC and the water were about 0.05 PV and WAG ratio was 1. The volume of 2 was heated to 90 ºC. Hot WAG was injected into the fractured CO and water injected into and the cumulative volume of sand pack and the volume of fluids injected into and the fluids produced from the sand pack and the breakthrough cumulative volume of fluids (oil, water and CO ) produced time were measured. The WAG injection was continued until 2 from the fractured sand pack were measured too. no oil was produced at the outlet. After that the heater which The capillary number is a dimensionless group that was in the direction of CO and water injection was turned on represents the ratio of viscous forces to the interfacial forces affecting the fl ow of fl uid in porous media. The main goals Gas metering system of any EOR method are increasing the capillary number and providing ‘favorable’ (M < 1.0) mobility ratios. The capillary number is defi ned as the ratio of viscous to capillary forces. Separator Effluent collection Viscous forces vP ca (1) Capillary forces V Backpressure valve where v and μ are the velocity and viscosity of the displacing fluid, respectively; σ is the oil-water interfacial tension. In -7 this study, the capillary number was 2.171×10 for the sand packs. This shows that the fl ow in our models is dominated by capillary forces. 4 Results and discussion Fig. 2 shows the cumulative oil produced by WAG flooding at a rate of 0.5 cm /min in the conventional sand pack. The cumulative volume of oil produced was 0.61 PV after 2.7 PV of fl uids (water and CO ) were injected into the conventional sand pack. CO breakthrough was observed before the water injection because CO is more mobile than Air bath water and the CO breakthrough was observed after 0.68 PV 0.8 Valve 0.7 0.6 Piston of water 0.5 Heater 0.4 0.3 0.2 0.1 Piston of gas 0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 Thermometer High pressure gas Fluid injected, PV Fig. 1 Schematic diagram of set up Fig. 2 Produced oil versus WAG injection in the conventional sand pack Number 1 Number 2 Oil produced, PV Pet.Sci.(2009)6:400-404 403 injection. Also, the results show that hot WAG injection is a reduced oil viscosity and interfacial tension and caused feasible method to increase oil recovery in conventional sand oil swelling; therefore, oil recovery increased. The tertiary packs. recovery process known as hot WAG is a combination of Fig. 3 shows the volume of oil produced while the two tertiary recovery processes of hot water flooding and conventional sand pack was targeted with hot WAG injection. hot gas injection. WAG flooding has become the leading Before the conventional sand pack was flooded with hot enhanced oil recovery technique for light and medium oils WAG, it has been fl ooded by WAG completely. As shown in but hot WAG can be used in heavy oil reservoirs because hot Fig. 3, after 2.7 PV of hot fl uids were injected into the sand WAG injection is a combination of thermal and gas injection pack the increased oil recovery was 0.16 PV with respect methods. Since the heat content of CO is low, the use of hot to WAG injection and CO breakthrough was observed WAG may not be feasible in deep reservoirs because of the at an injection of 0.57 PV of hot fluids, so the hot WAG heat losses and the high cost. breakthrough was observed earlier than that of WAG. The earlier breakthrough was due to lower viscosity and higher 0.12 mobility of hot CO and hot water. 0.10 0.08 0.20 0.06 0.15 0.04 0.02 0.10 0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 0.05 Fluid injected, PV 0 1.0 2.0 3.0 4.0 Fig. 5 Increased oil recovery versus hot WAG injection in the fractured sand pack Fluid injected, PV Fig. 3 Increased oil recovery versus hot WAG injection As can be expected, all EOR processes have limitations in the conventional sand pack on their applicability. Some of the hot WAG limitations are the high cost of double injection and high cost of heating Fig. 4 shows the cumulative oil produced by WAG the water and CO . A large gas cap or aquifer are usually injection at a rate of 0.5 cm /min in the fractured sand pack. unfavorable factors. Large fractures provide preferential This fi gure showed that the cumulative produced oil was 0.54 pathways from injection to production wells and this method PV after 2.4 PV of fl uids were injected into the fractured sand may be not feasible in deep reservoirs because of heat losses, pack. The CO breakthrough was observed after 0.43 PV of also naturally and economically availability of CO and water WAG injection. This rapid breakthrough was due to the high are important. permeability of the fracture. 5 Conclusions 0.6 To the best of our knowledge, this is the fi rst time the hot 0.5 WAG method has been used. Hot CO alternating hot water 0.4 were injected into the conventional and fractured sand packs. 0.3 Use of the hot WAG method in comparison with the WAG 0.2 method increased oil recovery 0.16 PV in the conventional sand pack and 0.10 PV in the fractured sand pack. 0.1 Experimental results showed that the hot WAG method was 0 0.5 1.0 1.5 2.0 2.5 3.0 a feasible enhanced oil recovery method in conventional and fractured sand packs and increased oil recovery signifi cantly. Fluid injected, PV Fig. 4 Produced oil versus WAG injection in the fractured sand pack References Chr istensen J R, Stenby E H and Skauge A. Review of WAG field experience. SPE Reservoir Evaluation and Engineering. 2001. 4(2): After the fractured sand pack was completely flooded 97-106 (SPE paper 71203) by WAG injection, hot CO and hot water were alternatively Hag highat S A. WAG Modeling in Fractured Reservoirs. Thesis Report injected. Fig. 5 showed that after 2.7 PV of hot fluids were MTA/PW/04-15 TU Delft, August 2004 injected the increased oil recovery was 0.10 PV compared Hee remans J C, Esmaiel T E H and van Kruijsdijk C P J W. Feasibility with WAG injection and the CO breakthrough was observed study of WAG injection in naturally fractured reservoirs. SPE/DOE at an injection of 0.39 PV of hot fluids. Therefore, the hot Symposium on Improved Oil Recovery held in Tulsa, Oklahoma, WAG breakthrough was observed earlier than that of WAG. USA, April 22-26, 2006 (SPE paper 100034). The high temperature of CO and hot water in hot WAG 2 Kul karni M M. Immiscible and miscible gas-oil displacements in Increased oil recovery, PV Oil produced, PV Increased oil recovery, PV 404 404 Pet.Sci.(2009)6:400-404 porous media. MSc Thesis. The Craft and Hawkins Department of Conference held in Bahrain, April 5-8, 2003 (SPE paper 81459) Petroleum Engineering, Louisiana State University and Agricultural Rao D N. Gas injection EOR: a new meaning in the new millennium. and Mechanical College, Baton Rouge, LA, July 2003 Journal of Canadian Petroleum Technology. 2001. 40(2): 11-18 Kul karni M M and Rao D N. Experimental investigation of miscible van Lingen P P, Barzanji O H M and van Kruijsdijk C P J W. and immiscible Water-Alternating-Gas (WAG) process performance. WAG injection to reduce capillary entrapment in small-scale Journal of Petroleum Science and Engineering. 2005. 48(1-2): 1-20 heterogeneities. SPE Annual Technical Conference held in Denver, Law rence J J, Teletzke G F, Hutfilz J M, et al. Reservoir simulation Colorado, October 6-9, 1996 (SPE paper 36662) of gas injection processes. SPE 13th Middle East Oil Show & (Edited by Sun Yanhua) http://www.deepdyve.com/assets/images/DeepDyve-Logo-lg.png Petroleum Science Springer Journals

A laboratory study of hot WAG injection into fractured and conventional sand packs

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References (10)

Publisher
Springer Journals
Copyright
Copyright © 2009 by China University of Petroleum (Beijing) and Springer Berlin Heidelberg
Subject
Earth Sciences; Mineral Resources; Industrial Chemistry/Chemical Engineering; Industrial and Production Engineering; Energy Economics
ISSN
1672-5107
eISSN
1995-8226
DOI
10.1007/s12182-009-0061-5
Publisher site
See Article on Publisher Site

Abstract

method used in heavy oil fi elds. To increase the extent of the reservoir contacted by the injected gas, the gas is generally injected intermittently with water. This mode of injection is called water-alternating- gas (WAG). This study deals with a new immiscible water alternating gas (IWAG) EOR technique, “hot IWAG” which includes combination of thermal, solvent and sweep techniques. In the proposed method CO will be superheated above the reservoir temperature and instead of normal temperature water, hot water will be used. Hot CO and hot water will be alternatively injected into the sand packs. A laboratory test was conducted on the fractured and conventional sand packs. Slugs of water and CO with a low and constant rate were injected into the sand packs alternatively; slug size was 0.05 PV. Recovery from each sand pack was monitored and after that hot water and hot CO were injected alternatively under the same conditions and increased oil recovery from each sand pack and breakthrough were measured. Experimental results showed that the injection of hot WAG could signifi cantly recover residual oil after WAG injection in conventional and fractured sand packs. Hot water-alternating-gas (WAG), enhanced oil recovery (EOR), fractured sand pack, Key words: conventional sand pack, gas injection past, CO and hydrocarbon gases constitute the major share 1 Introduction 2 of injectants (~90%). CO is ideally suited for use in gas Under conditions prevailing in many oil reservoirs, gas- injection projects in the U.S. scenario. Abundance of reserves oil immiscible displacement has higher microscopic sweep of almost pure CO and availability of technical know-how efficiency than water-oil displacement. However, gas as a has been the cause for the growth of CO injection processes displacing agent suffers the obvious drawback because of its in the U.S. Carbon sequestration is now an added advantage very high mobility (Lawrence et al, 2003). The WAG process of the CO injection projects (Kulkarni and Rao, 2005). has been proven effective in providing mobility control The main design parameters that need to be evaluated on a laboratory scale to evaluate the feasibility of the process for horizontal gas floods, as demonstrated by many field are: reservoir heterogeneity, rock type, fluid characteristics, applications, most of which aimed at reaching miscibility injection gas, WAG ratio, and gravity considerations. Other between the injected gas and the reservoir fl uid. Immiscible parameters those are important for gas injection and tertiary WAG (IWAG), on the other hand, has a smaller record of fi eld recovery in general, are those of miscibility development and experience (Christensen et al, 2001). The development of composition of oil and brine (Kulkarni, 2003). the water-alternating-gas (WAG) process aims at improving Little is known about the application of WAG injection flood profile control. The higher microscopic displacement in naturally fractured reservoirs. It was believed that it effi ciency of gas combined with the better macroscopic sweep was impossible to use the advantages of water flooding efficiency of water significantly increases the incremental and gas injection together due to the existence of fractures oil production over that from a plain water flood. Nearly in reservoirs (Haghighat, 2004). Fractures cause rapid all the commercial gas injection projects today employ the advancement of injected fluids that changes a major WAG method (Kulkarni and Rao, 2005). In spite of these advantage of WAG injection; namely, water cycles that improvements, the fi eld performance of WAG process (5%- are stabilizing the flooding front (Heeremans et al, 2006). 10% OOIP recovery) is disappointing (Rao, 2001). In the However, there are some examples from the fi eld that show United States, most of the WAG applications are onshore, that there is potential of WAG injection in naturally fractured employing a wide variety of injection gases for a wide range reservoirs (Christensen et al, 2001). of reservoir characteristics in the miscible mode. Although The main objective of this work is to investigate the many types of injectant gases have been attempted in the feasibility of hot WAG injection by using hot CO and hot water in conventional and fractured sand packs, focusing on *Corresponding author. email: amohebbi2002@yahoo.com, amohebbi@ the heat transfer of hot CO and hot water and hydrocarbons mail.uk.ac.ir in these sand packs. Received January 27, 2009 Pet.Sci.(2009)6:400-404 401 401 2 Water-alternating-gas (WAG) technique 3 Materials and methods Water-alternating-gas (WAG) injection is a tertiary oil For a reservoir with a long CO injection history, the recovery process that has been growing in popularity since reservoir temperature will be reduced a little. The highest it was first introduced in the 1950’s. The tertiary recovery reduction is seen in the proximity of injection wells. In this process known as WAG is a combination of two secondary study, the temperature was set at 100 ˚C to represent the recovery processes of water fl ooding and gas injection. The temperature of CO flooded zones. The pressure was one WAG process was proposed originally to aim for an ideal atmosphere because the process was immiscible. The full system of oil recovery: improvements in macroscopic and details of the sand packs, fl uids, and experimental set up are microscopic sweep effi ciencies at the same time. The water given in the following sections. is used to control the mobility of the gas. The cyclic nature of the WAG process causes an increase in water saturation 3.1 Sand pack samples during the water injection half cycle and a decrease in water In this study, two sand packs were used. The structure saturation during the gas injection half cycle. This process of two sand packs was the same with a length of 35 cm inducing cycles of fl ooding and drainage causes the residual and a diameter of 4.2 cm. One of the sand packs as a oil levels when using WAG to be typically lower than that of fractured model contains a fracture in its middle. The water flooding and similar to those of gas flooding or even properties and dimensions of the two sand packs are better if capillary trapping due to small scale heterogeneities summarized in Table 1. is signifi cant (van Lingen et al, 1996). Table 1 Model properties Permeability Porosity Connate water Diameter Length Area Bulk volume Sample 2 3 D % % cm cm cm cm Conventional 1.1 20 15.66 4.2 35 13.8 484.9 Fractured 5.0 28 15.06 4.2 35 13.8 484.9 3.2 Fluid samples 3.3 Matrix and fracture system Oil used in all experiments was prepared from the Maroon Both sand packs were conventional at fi rst. For fabricating reservoir at south of Iran and its composition is given in Table a fractured sand pack, one of the sand packs was selected 2. The composition of the experimental brine (prepared in the and cut in the middle and the space between two halves of laboratory) is similar to that of reservoir brine and is given in the sand pack was fi lled with glass wool with a diameter of 2 Table 3. Injected gas was pure CO . The viscosity and density mm. The artifi cial fracture acted similar to an actual fracture. of fl uids in WAG experiments are given in Table 4. The glass wool had no effect on the surface area of the middle of the sand pack and did not influence the fluid which was used later to saturate the sand pack. This was investigated Table 2 Oil composition at 220 ˚F by measuring sand pack permeability before and after using (%) glass wool. The middle of the sand pack filled with sealing C C C i-C n-C i-C n-C C C HSCO material had zero permeability, and the sand pack had its 1 2 3 4 4 5 5 6 7+ 2 2 initial permeability of 1.1 D. The glass wool was a porous 48.45 9.223 5.144 0.867 2.507 1.032 1.289 2.129 29.36 0 0 medium with high permeability so in the middle of the sand pack it acted like a real fracture. Table 3 Brine composition 3.4 Initial saturations (%) The pore volume was measured by saturating the sand Component KC MgCl CaCl NaCl H O 2 2 2 packs with brine. The oil with a composition as shown in Table 2 was then injected into the sand packs at a rate of 0.5 Composition, % 0.03 0.43 3.20 3.60 92.74 cm /min. In this case the sand packs were vertical and oil was injected from the top of the sand packs. In the conventional sand pack, oil breakthrough was observed after 69.06 cm Fluids used in WAG experiments and their viscosities and densities Table 4 of brine was produced. The total volume of oil injected into the sand pack was 145.5 cm (1.5 PV) and the total volume Fluid Density, g/mL Viscosity, cp of brine produced from the conventional sand pack was 81.8 cm . In the fractured sand pack, oil breakthrough was Oil 0.87 2.168 observed after 97.78 cm of brine was produced. The total Water 1.00 1.020 volume of oil injected into the sand pack was 204.3 cm (1.5 PV) and the total volume of brine produced from the fractured Gas 1.6e-03 0.0182 3 sand pack was 115.3 cm . Thus, the initial water saturations, 402 Pet.Sci.(2009)6:400-404 S for conventional and fractured sand packs were 15.66% and the CO temperature increased to 120 ºC and the water wi 2 and 15.06%, respectively. Also, the initial oil saturations, S was heated to 90 ºC. Hot CO and hot water were injected oi 2 for conventional and fractured sand packs were 84.3% and alternatively into the conventional sand pack. The volume of 84.9%, respectively. This initialization was done at 25 ºC and injected fl uids, the cumulative volume of produced fl uids, and the pressure was one atmosphere. the breakthrough time were measured too. Hot gas and hot water slug sizes were about 0.05 PV and WAG ratio was 1. 3.5 Experiments The next experiment was done on the fractured sand pack to indicate the feasibility of hot WAG injection in a fractured To generate accurate predictions by field simulations of sand pack. The temperature of oven was set at 100 ºC and WAG injection into conventional and fractured reservoirs, a CO and water were injected into the fractured sand pack at set of WAG injection experiments should be performed under 2 a rate of 0.5 cm /min and 25 ºC. All the process was similar near reservoir conditions to check EOR mechanisms. to the conventional sand pack runs. The volume of CO In this study, the sand packs were placed horizontally in 2 and water injected into and the cumulative volume of fl uids the oven. The whole setup is shown in Fig. 1. In the fi rst step, produced from the fractured sand pack, and the breakthrough the conventional sand pack was targeted. The temperature of time were measured. The WAG injection was continued oven was set at 100 ºC and CO and water (room temperature until no oil was produced at the outlet. After that the heater (25 ºC)) were injected alternatively into the conventional which was in the direction of fluid injection was turned on sand pack at a rate of 0.5 cm /min. Gas and water slug sizes and the CO temperature increased to 120 ºC and the water were about 0.05 PV and WAG ratio was 1. The volume of 2 was heated to 90 ºC. Hot WAG was injected into the fractured CO and water injected into and the cumulative volume of sand pack and the volume of fluids injected into and the fluids produced from the sand pack and the breakthrough cumulative volume of fluids (oil, water and CO ) produced time were measured. The WAG injection was continued until 2 from the fractured sand pack were measured too. no oil was produced at the outlet. After that the heater which The capillary number is a dimensionless group that was in the direction of CO and water injection was turned on represents the ratio of viscous forces to the interfacial forces affecting the fl ow of fl uid in porous media. The main goals Gas metering system of any EOR method are increasing the capillary number and providing ‘favorable’ (M < 1.0) mobility ratios. The capillary number is defi ned as the ratio of viscous to capillary forces. Separator Effluent collection Viscous forces vP ca (1) Capillary forces V Backpressure valve where v and μ are the velocity and viscosity of the displacing fluid, respectively; σ is the oil-water interfacial tension. In -7 this study, the capillary number was 2.171×10 for the sand packs. This shows that the fl ow in our models is dominated by capillary forces. 4 Results and discussion Fig. 2 shows the cumulative oil produced by WAG flooding at a rate of 0.5 cm /min in the conventional sand pack. The cumulative volume of oil produced was 0.61 PV after 2.7 PV of fl uids (water and CO ) were injected into the conventional sand pack. CO breakthrough was observed before the water injection because CO is more mobile than Air bath water and the CO breakthrough was observed after 0.68 PV 0.8 Valve 0.7 0.6 Piston of water 0.5 Heater 0.4 0.3 0.2 0.1 Piston of gas 0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 Thermometer High pressure gas Fluid injected, PV Fig. 1 Schematic diagram of set up Fig. 2 Produced oil versus WAG injection in the conventional sand pack Number 1 Number 2 Oil produced, PV Pet.Sci.(2009)6:400-404 403 injection. Also, the results show that hot WAG injection is a reduced oil viscosity and interfacial tension and caused feasible method to increase oil recovery in conventional sand oil swelling; therefore, oil recovery increased. The tertiary packs. recovery process known as hot WAG is a combination of Fig. 3 shows the volume of oil produced while the two tertiary recovery processes of hot water flooding and conventional sand pack was targeted with hot WAG injection. hot gas injection. WAG flooding has become the leading Before the conventional sand pack was flooded with hot enhanced oil recovery technique for light and medium oils WAG, it has been fl ooded by WAG completely. As shown in but hot WAG can be used in heavy oil reservoirs because hot Fig. 3, after 2.7 PV of hot fl uids were injected into the sand WAG injection is a combination of thermal and gas injection pack the increased oil recovery was 0.16 PV with respect methods. Since the heat content of CO is low, the use of hot to WAG injection and CO breakthrough was observed WAG may not be feasible in deep reservoirs because of the at an injection of 0.57 PV of hot fluids, so the hot WAG heat losses and the high cost. breakthrough was observed earlier than that of WAG. The earlier breakthrough was due to lower viscosity and higher 0.12 mobility of hot CO and hot water. 0.10 0.08 0.20 0.06 0.15 0.04 0.02 0.10 0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 0.05 Fluid injected, PV 0 1.0 2.0 3.0 4.0 Fig. 5 Increased oil recovery versus hot WAG injection in the fractured sand pack Fluid injected, PV Fig. 3 Increased oil recovery versus hot WAG injection As can be expected, all EOR processes have limitations in the conventional sand pack on their applicability. Some of the hot WAG limitations are the high cost of double injection and high cost of heating Fig. 4 shows the cumulative oil produced by WAG the water and CO . A large gas cap or aquifer are usually injection at a rate of 0.5 cm /min in the fractured sand pack. unfavorable factors. Large fractures provide preferential This fi gure showed that the cumulative produced oil was 0.54 pathways from injection to production wells and this method PV after 2.4 PV of fl uids were injected into the fractured sand may be not feasible in deep reservoirs because of heat losses, pack. The CO breakthrough was observed after 0.43 PV of also naturally and economically availability of CO and water WAG injection. This rapid breakthrough was due to the high are important. permeability of the fracture. 5 Conclusions 0.6 To the best of our knowledge, this is the fi rst time the hot 0.5 WAG method has been used. Hot CO alternating hot water 0.4 were injected into the conventional and fractured sand packs. 0.3 Use of the hot WAG method in comparison with the WAG 0.2 method increased oil recovery 0.16 PV in the conventional sand pack and 0.10 PV in the fractured sand pack. 0.1 Experimental results showed that the hot WAG method was 0 0.5 1.0 1.5 2.0 2.5 3.0 a feasible enhanced oil recovery method in conventional and fractured sand packs and increased oil recovery signifi cantly. Fluid injected, PV Fig. 4 Produced oil versus WAG injection in the fractured sand pack References Chr istensen J R, Stenby E H and Skauge A. Review of WAG field experience. SPE Reservoir Evaluation and Engineering. 2001. 4(2): After the fractured sand pack was completely flooded 97-106 (SPE paper 71203) by WAG injection, hot CO and hot water were alternatively Hag highat S A. WAG Modeling in Fractured Reservoirs. Thesis Report injected. Fig. 5 showed that after 2.7 PV of hot fluids were MTA/PW/04-15 TU Delft, August 2004 injected the increased oil recovery was 0.10 PV compared Hee remans J C, Esmaiel T E H and van Kruijsdijk C P J W. Feasibility with WAG injection and the CO breakthrough was observed study of WAG injection in naturally fractured reservoirs. SPE/DOE at an injection of 0.39 PV of hot fluids. Therefore, the hot Symposium on Improved Oil Recovery held in Tulsa, Oklahoma, WAG breakthrough was observed earlier than that of WAG. USA, April 22-26, 2006 (SPE paper 100034). The high temperature of CO and hot water in hot WAG 2 Kul karni M M. Immiscible and miscible gas-oil displacements in Increased oil recovery, PV Oil produced, PV Increased oil recovery, PV 404 404 Pet.Sci.(2009)6:400-404 porous media. MSc Thesis. The Craft and Hawkins Department of Conference held in Bahrain, April 5-8, 2003 (SPE paper 81459) Petroleum Engineering, Louisiana State University and Agricultural Rao D N. Gas injection EOR: a new meaning in the new millennium. and Mechanical College, Baton Rouge, LA, July 2003 Journal of Canadian Petroleum Technology. 2001. 40(2): 11-18 Kul karni M M and Rao D N. Experimental investigation of miscible van Lingen P P, Barzanji O H M and van Kruijsdijk C P J W. and immiscible Water-Alternating-Gas (WAG) process performance. WAG injection to reduce capillary entrapment in small-scale Journal of Petroleum Science and Engineering. 2005. 48(1-2): 1-20 heterogeneities. SPE Annual Technical Conference held in Denver, Law rence J J, Teletzke G F, Hutfilz J M, et al. Reservoir simulation Colorado, October 6-9, 1996 (SPE paper 36662) of gas injection processes. SPE 13th Middle East Oil Show & (Edited by Sun Yanhua)

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Petroleum ScienceSpringer Journals

Published: Nov 26, 2009

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