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Noncondensable gas steam-assisted gravity drainage
Journal of Petroleum Science and Engineering 45 (2004) 83 – 96 www.elsevier.com/locate/petrol
Noncondensable gas steam-assisted gravity drainage S. Canbolat a, S. Akin a, A.R. Kovscek b,* a
Petroleum and Natural Gas Engineering Department, Middle East Technical University, 06531 Ankara, Turkey b Department of Petroleum Engineering, Stanford University, Stanford, CA 94305-2220, USA Received 21 August 2003; accepted 19 April 2004
Abstract To investigate steam-assisted gravity drainage (SAGD) mechanisms, experiments with and without carbon dioxide or nbutane mixed with steam were conducted in a scaled physical model. It is packed with crushed limestone premixed with a 12.4j API heavy-oil. Temperature, pressure, production data, and the asphaltene content of the produced oil were monitored continuously during the experiments. For small well separations, the steam condensation temperature and the steam – oil ratio decreased as the amount of carbon dioxide increased. The heavy oil became less mobile in the steam chamber due to lower temperatures and more viscous oil. Thus, the heating period was prolonged and the cumulative oil recovery as well as the recovery rate decreased. Less oil recovery was obtained as the fraction of carbon dioxide injected increased. Little or no change in oil recovery, and the rate of oil recovery, was observed for greater well separations regardless of the fraction of carbon dioxide in the injection gas. Similar behavior was observed when n-butane was injected along with steam instead of carbon dioxide. Cumulative oil recovery, rate of oil recovery, and steam – oil ratio decreased independent of well separation compared to a reservoir with no initial noncondensable gas. These experimental results add to the state of the art understanding of thermal gravity drainage processes. The addition of noncondensable gases during steam-assisted gravity drainage was not beneficial to oil recovery. Nevertheless, experiments do teach that steam injection is effective for producing heavy-oil saturated limestone. D 2004 Elsevier B.V. All rights reserved. Keywords: Gravity drainage; Heavy oil; Thermal oil recovery; Noncondensable gases
1. Introduction A recovery mechanism is required that lowers the viscosity of heavy oil so that it flows easily to a production well. Conventional thermal processes, such as cyclic steam injection, and steam-assisted gravity drainage (SAGD) are based on thermal viscosity reduction and gravity drainage (Butler, 1991). * Corresponding author. Tel.: +1-650-723-1218; fax: +1-650725-2099. E-mail address: [email protected] (A.R. Kovscek). 0920-4105/$ - see front matter D 2004 Elsevier B.V. All rights reserved. doi:10.1016/j.petrol.2004.04.006
SAGD uses horizontal wells to maximize the effect gravity (Butler, 1998). In the idealized SAGD process, a growing steam chamber forms around the horizontal injector and steam flows continuously to the perimeter of the chamber where it heats the surrounding oil. Effective initial heating of the cold oil is important for the formation of the steam chamber in gravity drainage processes (Edmunds and Gittins, 1993; Elliot and Kovscek, 2001). The heated oil drains to a horizontal production well located at the base of the reservoir just below the injection well. Butler (1991) derived Eqs. (1a,b)
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assuming that (1) the steam pressure is constant in the steam chamber, (2) only steam flows in the steam chamber, (3) oil saturation is residual, and (4) heat transfer ahead of the steam chamber to cold oil is only by conduction: sffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffi 1:3/DSo kgah q¼L ð1aÞ mvS where the kinematic viscosity, m ( = shear viscosity/ density), of oil as a function of temperature is given by Ts TR m m ¼ ms ð1bÞ T TR In Eqs. (1a,b), L is the length of the well, / is porosity, DSo is the initial oil saturation minus residual oil saturation, k is the effective permeability for the flow of oil, g is the acceleration constant of gravity, a is the thermal diffusivity, h is the distance from the production well to the top of the reservoir, m is a dimensionless viscosity exponent, ms is the kinematic viscosity of oil at steam temperature (Ts), and TR is the initial reservoir temperature. Empirical correlations or laboratory data are needed to evaluate the residual oil saturation and any effect of temperature on DSo. There are three major consequences of this theory: (1) steam chamber growth is necessary for oil production, and oil production occurs only as long as steam is injected, (2) oil production rate increases as the steam temperature increases, and (3) at a given steam temperature, the oil with the lowest viscosity exhibits the greatest production response. The SAGD process is economic if the steam – oil ratio is not too high (Edmunds, 1999), and is being implemented in a number of projects, mainly in Canada (Butler, 2001). The heat requirements, however, are large in thin reservoirs where heat losses are high and also in low porosity carbonates where the reservoir heat capacity per unit volume of initial oil is high. The simultaneous injection of carbon dioxide and steam is beneficial for recovering heavy oil using vertical wells (Hornbrook et al., 1991). Addition of CO2 to steam results in lower injection temperature without reducing oil recovery as long as the injection temperature remains at or above the steam saturation temperature. For thin reservoirs and some carbonates, vertical well applications are not feasible. These
limitations might be overcome or decreased by using horizontal wells in two ways: addition of noncondensable gas, such as carbon dioxide or methane, to steam (Butler, 1999) and vapor extraction or VAPEX (Das and Butler, 1998). The concept of steam and gas push (SAGP) is similar to conventional SAGD. Steam not only mobilizes the oil by heating, but also equalizes the pressure vertically, because it is relatively inviscid. This is beneficial to oil drainage. In such cases, steam must be injected continuously at relatively high rate, otherwise the steam condenses and the vapor chamber collapses. This limitation is overcome, possibly, in the SAGP process. Even though steam may condense, gas remains in the reservoir, prevents collapse of the heated zone, and maintains pressure. In SAGP, fingers of gas rise warming the reservoir and maintaining pressure. Both effects improve oil recovery (Jiang et al., 2000). In SAGD, however, latent heat has to be carried to the top of the reservoir if steam is to be present there. Thus, the literature suggests it is not necessary to carry the latent heat to the top of the reservoir in the SAGP process. The noncondensable gas rises throughout the recovery process pressurizing the upper portions of the reservoir and thermal conduction provides sufficient heating beyond the steam condensation zone. The chamber temperatures required to achieve production at rates comparable to conventional SAGD are obtained from (Butler, 1999): "
q 2 m Tsz ¼TR þ ðTS TR Þ ðh hi =2Þ2 kga/DSo L hz
# m1
ð2Þ where Tsz is chamber temperature at height z, Ts is steam temperature, and hi is injector height above the bottom of the reservoir. The unknown flow rate, q (m3/s) is obtained from Eqs. (1a,b) by substituting h with hL (height of a SAGD reservoir with the same rate) as (Butler, 1999): hL ¼
pffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffi ð2h hi Þhi
ð3Þ
Eq. (2) suggests that the upper vertical interface of the vapor chamber is at the initial reservoir temperature. Eq. (3) indicates that placing the injector toward
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the bottom of the reservoir improves the production rate; however, as injector and producer become closer, the likelihood of injector – producer linkup and resulting poor contact of injectant with the reservoir increases. It is apparent that the vertical spacing between horizontal injector and horizontal producer may be a critical parameter. Moreover, knowledge of the role of noncondensable gases on recovery performance remains highly schematic. The objectives of this work were to quantify the effect of well spacing and the addition of noncondensable gas to steam with respect to oil recovery, steam-vapor chamber formation, and the spatial distribution of temperature. A suite of SAGD experiments were conducted with CO2 and n-butane added to the injected steam. The effects of injector-to-producer spacing and the presence, or lack, of initial noncondensable gas saturation in the model were examined. A secondary objective was to consider SAGD-like processes for carbonate formations. The SAGD, SAGP, and VAPEX processes are usually considered for sand and sandstone reservoirs. Significant heavy-oil resources are found in carbonate formations (Issever and Topkaya, 1998) that might benefit from a thermal gravity drainage process (AlHadhrami and Blunt, 2001). As a first step toward application of thermal gravity drainage processes in carbonate reservoirs, experiments were conducted using crushed limestone.
2. Experimental equipment and procedure The experimental setup consisted of injection equipment, physical model, and production facilities, as shown in Fig. 1. The oil is a 12.4j API viscous crude oil from the Bati Raman field (Turkey). Fig. 2 gives the oil viscosity versus temperature relationship; the viscosity is roughly 600 cP at the initial temperature of 50 jC. On the injection side, a steam generator and a gas bottle pressured at 10 MPa were used. Carbon dioxide or butane was metered into the live steam using a rotameter. The injection line was insulated and a resistance heater connected to a temperature controller kept the line at the same temperature as the steam generator. Thus, the steam was superheated at 280 kPa and 140 jC and the injected steam quality was 1. The
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production system consisted of a pressure gauge and two fluid separators. System backpressure was held constant at 103 kPa. The production line was heated to 100 jC so that it did not clog with cooled viscous oil. Production was measured volumetrically. The wells were made from perforated tubing wrapped with wire screens. The screens were necessary to prevent migration of unconsolidated particles. The model reservoir was constructed of stainless steel and it is 30-cm tall, 30-cm wide, and 7.5-cm thick. A thermal blanket preheated the model to 50 jC. The position of the injection well was adjustable such that it could be 5, 10, or 15 cm above the production well. Twenty-five thermocouples separated by a distance of 2 cm were placed centrally within the width of the model, Fig. 1. Thermocouples entered the model through tube fittings welded on the model and were connected to a computer. This setup allowed continuous monitoring of the model temperature. To obtain dimensional similarity, it is necessary to pack the model with a much more permeable medium than found in the field. Butler (1991) discusses several quantities for obtaining dimensional similarity and recommends the use of sffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffi kgh B3 ¼ a/DSo mvs
ð4Þ
It is assumed that the terms g, a, m, and DSo are roughly the same between the laboratory and the field. Equating B3 for laboratory and field cases yields the following expression for permeability of the scaled model kh /vs ð5Þ kM ¼ /vs F h M where the subscripts F and M denote field and model, respectively. Bati Raman is a representative fractured carbonate reservoir where the matrix permeability varies from 0.01 to 0.1 d (Issever and Topkaya, 1998), the porosity is about 18%, and the fracture spacing is on the order of 4 to 6 m (Spivak et al., 1989). At 140 jC, the kinematic viscosity of Bati Raman crude oil is estimated as 15 mm2/s at 140 jC and 4 mm2/s at 230 jC; Fig. 2 (Prats, 1986). The former kinematic viscosity is at the model injection temperature. The latter is an estimate for the field
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Fig. 1. Schematic of the experimental equipment.
assuming injection occurs at the depleted reservoir pressure of 3 MPa (Issever and Topkaya, 1998). Setting kF to 0.05 d, hF to the fracture spacing of 6 m, /M//F to 38/18 ( = 1.8), and employing the kinematic viscosities above yield kM equal to 6.3 d. The range of parameters above sets the permeability of the packing material from 1 to 10 d.
Fig. 2. Viscosity – temperature relationship for the crude oil.
The scaling of a field matrix block is only approximate, because the laboratory model is bounded by no-flow boundaries. Fractures may be open and permeable to fluid flow. Additionally, there may be heat transfer among field matrix blocks that is not incorporated in this scaling. Crushed limestone (mesh size 0.5 to 1.4 mm) was obtained from a quarry (Ankara, Turkey). The permeability and porosity of the packed model were 8 d and 38%, thereby meeting the criteria for a scaled physical model. The rock grains displayed no measurable internal porosity. The packed model represents some aspects of fractured limestone. Namely, any interactions of steam with the rock are reproduced, and it resembles the relatively homogeneous matrix in a system containing fractures. The crushed material is well characterized and allows examination of matrix processes. The crushed limestone was washed with deionized water to clean off any residues and coat the solid with water. The limestone/water slurry was mixed with crude oil to yield oil and water saturations of 75%
S. Canbolat et al. / Journal of Petroleum Science and Engineering 45 (2004) 83–96 Table 1 Summary of experimental operating conditions Exp. Description no.
Producer – Injection Injection Steam injector temperature pressure rate spacing, zd (jC) (kPa) (cc/min)
1 2 3 4
0.166 0.333 0.5 0.166
139 134 144 144
316 350 323 254
36.4 47.34 39 22
0.166
139
343
46
0.166
140
382
24
0.166
141
261
22
0.333
143
316
47.34
0.166
140
343
36.4
5 6 7 8 9
SAGD SAGD SAGD SAGD + Initial C4H10 SAGD + Initial CO2 SAGD + CO2 1.29:1 SAGD + C4H10 1.29:1 SAGD + CO2 4.41:1 SAGD + CO2 4.41:1
and 25%, respectively. Initial saturations are held constant throughout the experiments. An experiment proceeded by first selecting a well separation of 5, 10, or 15 cm. The model was positioned vertically and preheated to 50 F 1 jC. The steam generator was brought online and adjusted to 280 kPa and 140 jC. If noncondensable gas was to be used, it was introduced to the steam, after the steam was at the operating temperature and pressure. During the experiments, the injection line temperature, the temperature profile in the model, the pressure, and production data were recorded continuously. Properties of the produced oil and water were measured together with injection and production pressures. Additionally, asphaltene content of produced oil was measured to monitor deposition of asphaltenes and any possible upgrading of the produced oil. Asphaltene was measured by titration following Kokal et al. (1992). Measurements on the same sample indicated repeatability of F 2%. The experiment continued until the cumulative steam –oil ratio began to increase rapidly. The experimental conditions are summarized in Table 1. Nine experiments were conducted.
3. Results and discussion To evaluate whether the addition of noncondensable gases aided recovery, a critical evaluation of conven-
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tional SAGD is necessary. After steam injection is initiated, a steam chamber grows. Butler (1991) notes that the steam chamber initially grows upward, due to gravity, with little lateral spreading until it meets the top of the reservoir. Then the chamber begins to extend horizontally. At the steam-chamber boundary, steam condenses as heat is transferred to the oil. Condensed water and hot oil flow along the steam chamber boundary to the production well. In a reservoir where cold oil is very viscous and does not flow easily, initial production rates via SAGD are very low. In a strict definition of SAGD, steam is expected to enter the reservoir only to fill the void space left by produced oil. If the oil is cold and will not gravity drain into the wellbore at appreciable rates, then the oil must be heated to reduce viscosity so that it will flow. It follows that the vertical distance between the production – injection well pair (Eq. 2) has an effect on system performance; this effect was tested here experimentally. 3.1. Conventional SAGD experiments To test the relationship between producer –injector spacing and recovery, the size and the shape of the steam chamber formed as the injection– production well spacing varied were evaluated. Fig. 3 summarizes results from conventional SAGD experiments. First, the temperature measurements were contour mapped using a kriging algorithm (cf., Deutsch and Journel, 1992). All temperatures reported here are collected from the midplane of the model. Fig. 3a presents the temperature profiles for conventional SAGD for different well separation distances. Producer – injector spacing is described by a dimensionless number (zd) that is the ratio of the well spacing to the height of the reservoir model, Table 1. Regions of the pack that are bypassed by steam have circular shapes because the temperature measurements are kriged from the measured array of data. The heated area, as a function of time, is largest for the smallest well separation. Compare the left column of temperature contours (zd = 0.166) in Fig. 3a to the right column (zd = 0.5). Dark shading corresponds to a temperature of 145 jC, whereas white is 100 jC and less. At a specific time the model is warmer and temperature is more evenly distributed with the smallest well separation. The steam chamber, or heated zone shape, resembles an egg or an inverted, distorted triangle
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similar to the heated-zone shapes reported by Butler (1991). A significant upward movement of steam due to gravity is also present, especially at early times, for all cases. To compare the recovery efficiency for different well separations and to quantify the rate of steam chamber formation, dimensionless steam flooded areas were plotted versus time as shown in Fig. 3b. The dimensionless steam chamber area was obtained by dividing the steam-flooded area where temperatures were greater than 100 jC by the surface area of the model reservoir (i.e. 30 30 cm2). Thus, the dimensionless steam chamber area lies between 0
and 1. The steam chamber formation curves resemble each other for different well separations. Initially the heating is quite fast. The steam chamber expands rapidly until the steam reaches the upper vertical boundary of the model where steam chamber development slows as it expands to first the sides, and then toward the bottom of the model. For the largest injection – production well separation, the injection well is located at the midsection of the experimental model. In this case, the steam chamber reaches the top of the model quite quickly. Thus, the largest well separation heats the model the slowest. These observations are in accord with the ‘‘rising steam cham-
Fig. 3. Summary of conventional SAGD experiments: (a) isotherms for different well spacing zd = 0.166 (left) at 0.32, 0.60, 0.80 and 1.20 PVs injected, zd = 0.3333 (middle) at 0.43, 0.78, 1.05 and 1.25 PVs injected, and zd = 0.5 (right) at 0.50, 0.69, 0.92 and 1.29 PVs injected; (b) effect of well spacing on steam chamber size (dotted lines) and oil recovery (solid lines); (c) effect of well spacing on cumulative produced steam – oil ratio; (d) effect of well spacing on produced asphaltene content.
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aration, in apparent agreement with Eq. (3). This is consistent with the observation of optimum early-time heating with small well separations. All of the production curves indicate gravity drainage of oil to the end of the experiment. Comparison of Fig. 3b and c suggests that had the injection rate been cut significantly at the point that the model was mostly heated, injector-to-producer linkage and cycling of steam could have been reduced and the ultimate recovery increased. That is, the instantaneous steam – oil ratio might be reduced by limiting steam injection after roughly 1 PV of cumulative injection. The asphaltene content of the initial oil in place was measured to be 35% by weight. An initial sharp drop in the asphaltene content of produced oil was observed for dimensionless well separations of 0.3333 and 0.5, Fig. 3d. The decrease suggests a partial upgrading of the oil by asphaltene precipitation and flocculation. As the steam chamber developed, the produced asphaltene content increased slowly but remained below the initial value up to roughly 2.5 PV of injection. Precipitation of asphaltenes still occurred in the newly processed volume created by the injected steam. Asphaltene content of the produced oil increased as the steam chamber grew and the model became warmer indicating mobilization of the precipitated solid, or perhaps a partial redissolution of solids. In all cases, the asphaltene fraction first decreased, went through a maximum and then decreased again. The final asphaltene content of the produced oil was roughly two-thirds of the initial value. 3.2. SAGD style steam – CO2 experiments
Fig. 3 (continued).
ber’’ and ‘‘depleting reservoir’’ phases of Butler’s (1991) discussion of SAGD. Fig. 3b also summarizes the effect of well spacing on oil recovery (percent of original oil in place), whereas Fig. 3c shows the steam – oil ratio. Steam volumes are computed as cold (16 jC) water equivalent (Prats, 1986). The largest, most rapid overall production was obtained from the smallest well sep-
Carbon dioxide or n-butane was injected simultaneously with steam. Two flow rates, one higher than and one comparable to that of the SAGD experiments, were used; Table 1. For the experiments employing CO2 injection, the impact of well spacing on production efficiency also was considered by changing the location of the injection well. These experiments also were analyzed by means of dimensionless steam chamber size obtained from the temperature distributions, cumulative oil recovery, and steam –oil ratio; Fig. 4. Fig. 4a shows isotherms obtained at subsequent times for an identical CO2/steam ratio (4.41) at two different well separations (zd = 0.166 and zd = 0.3333). Again, dark shading represents 145 jC and white is
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100 jC or less. The average temperatures in the chamber for these experiments are lower compared to those for comparable times during SAGD experiments, Fig. 3a. The same amount of steam has been injected at each time for plots in both Figs. 3a and 4a. It appears that CO2 rises to the top of the model quickly and long before the upper portions are heated. During the initial stages of injection, the model is cold and most of the injected steam condenses. The noncondensable gas rises as fingers that displace very little oil. Because gas heat capacity is small, heating is limited in magnitude. This gas collects under the top impermeable boundary of the model as a thin gas zone. In this
Fig. 4 (continued).
Fig. 4. Summary SAGD performance with steam – CO2 injectant: (a) isotherms for different well spacing, CO2 – steam ratio = 4.41, zd = 0.333 (left) at 0.45, 1.40, 2.36 and 2.67 PVs injected and zd = 0.166 (right) 0.95, 1.88, 2.52 and 3.83 PVs injected; (b) effect of well spacing on steam chamber size (dotted lines) and oil recovery (solid lines) for CO2 – steam ratio = 4.41; (c) effect of well spacing on cumulative produced steam – oil ratio, CO2 – steam ratio = 4.41; (d) effect of well spacing on produced asphaltene content for CO2 – steam ratio = 4.41.
sense, the noncondensable gas indeed carries pressure to the upper parts of the reservoir (Butler et al., 2000a,b). The chamber shapes are somewhat different compared to those of the conventional SAGD experiments. This is due to the temperature and pressure gradients introduced into the chamber by the rising noncondensable gas. Steam chamber size was computed in the same way as Fig. 3b. Compared to
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conventional SAGD, the time required to grow a sizeable steam chamber in Fig. 4b is more than two times, and eight times as large for small and large well separations, respectively. Addition of carbon dioxide did not increase the ultimate oil recovery (Fig. 4b), but prolonged the heating period and the project life. The steam – oil ratios (Fig. 4c) were many times smaller compared to those of the conventional SAGD experiments (Fig. 3c), but large nevertheless. Similar to SAGD, the smaller well separation was observed to perform better in terms of heating and oil recovery. Unlike the steam experiments, there was no indication of early time precipitation of asphaltenes (Fig.
91
4d). On the contrary, asphaltene content of the produced oil increased. For small well separation, the asphaltene content fluctuated around the initial value. This is an indication of successive precipitation and mobilization of solids from pores. For larger well separation, however, the asphaltene content increased slowly and remained higher than the starting value. Srivastava et al. (1999) reported similar observations for linear CO2 core floods. Another factor that has an impact on recovery and project economics is concentration of gas in the injected steam – gas mixture. Several experiments were conducted by changing the steam – CO2 ratio
Fig. 5. Summary of SAGD performance with steam – CO2 injectant at variable concentration: (a) isotherms for zd = 0.1666 for steam (left), at 0.32, 0.60, 0.80 and 1.20 PVs injected, CO2 – steam ratio = 1.29 (middle) at 0.38, 0.63, 1.16 and 1.65 PVs injected, and CO2 – steam ratio = 4.41 (right) at 0.95, 1.88, 2.52 and 3.83 PVs injected; (b) effect of CO2 on steam chamber size (dotted lines) and oil recovery (solid lines); (c) effect of CO2 on produced steam – oil ratio for different volumetric steam – CO2 ratios; (d) effect of CO2 on produced asphaltene content for different volumetric steam – CO2 ratios.
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increased due to the reduction in the latent and sensible heat per unit of injectant. Correspondingly, the steam chamber formation rates decreased as shown in Fig. 5a. The shape of the vapor chamber was irregular and appeared to be dominated by wide gas fingers, as compared to conventional SAGD at similar elapsed times. The oil recovery and the production rates decreased (Fig. 5b), but the decrease in steam – oil ratio (Fig. 5c) was much more pronounced as the amount of gas in the mixture increased. For the steam – CO2 ratio of 1:1.29, asphaltene content of the produced oil (Fig. 5d) showing similar behavior to that of the steam only case except for the early-time decrease. At larger steam – CO2 ratio (1:4.41), the asphaltene content was always above the initial value. Late time reductions of the produced asphaltenes for both cases exhibit additional asphaltene precipitation/flocculation in the sand matrix during CO2 injection with steam. 3.3. SAGD-style steam/n-butane experiments
Fig. 5 (continued).
from 0 to 4.41 using the same injection– production location at zd = 0.1333, Fig. 5. This location was chosen because it was the best performing location in terms of oil recovery and the rate of steam chamber formation. As the CO2 concentration in the injected mixture increased, the time required to heat the system
The addition of a hydrocarbon gas to steam also was considered. The same concentration used for the steam – CO2 experiments and the same injection – production locations (zd = 0.1333) were used to inject a steam –butane mixture. Fig. 6a compares the isotherms obtained at different times during the experiment to those obtained for SAGD and steam – CO2 experiments. The shapes of the vapor chamber observed in both steam –noncondensable gas systems resemble each other. This suggests that the production mechanism is little affected by the amount and type of gas in the mixture. As expected, the oil recoveries (Fig. 6b) and the steam – oil ratios (Fig. 6c) were lower compared to conventional SAGD recovery. Performance of CO2 was better than n-butane. The change in asphaltene content of the produced oil as a function of time for steam – butane injection (Fig. 6d) was insignificant compared to steam only and steam – CO2 injection, illustrating that solvent – gas effects are important to asphaltene precipitation. 3.4. Effect of initial presence of noncondensable gases in SAGD experiments The presence of initial gases in the system was investigated. The principal interest is the possibility of
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steam injection following primary production by solution gas drive or immiscible, isothermal gas injection. To achieve initial nonzero gas saturation, several pore volumes of CO2 or n-butane were injected and then the system was shut in for 24 h. During injection, small amounts of oil were produced. By mass balance, the average initial gas saturations of CO2 and n-butane were 8.35% and 3.0% of the original oil in place, respectively. Conventional SAGD was then conducted. Fig. 7a and b compares the oil recovery and steam – oil ratios observed during the experiments. When compared to simultaneous gas and steam injection, initial saturation of n-butane positively affect-
93
ed oil recovery. This is most likely due to viscosity reduction of the heavy oil arising from n-butane dissolution in the oil. The area of the steam chamber (Fig. 7a) at equal times observed for initial saturation of n-butane was somewhat smaller compared to initial CO2 saturation in the system. The initial gas saturation probably created low resistance pathways for the steam to move through the viscous oil saturating the model. The asphaltene content of the produced oil was similar to steam only injection situations, as shown by Figs. 3 and 7c. Again, butane appeared to have relatively little effect on the asphaltene content of the produced oil.
Fig. 6. Summary SAGD performance with steam – butane injectant; (a) isotherms for zd = 0.1666 for steam (left), at 0.32, 0.60, 0.80 and 1.20 PVs injected, steam – CO2 (middle) at 0.38, 0.63, 1.16 and 1.65 PVs injected, steam – C4H10 (right) at 0.35, 0.55, 1.11 and 1.54 PVs injected; (b) comparison of steam – CO2, steam – C4H10 and SAGD oil recoveries (zd = 0.1666); (c) comparison of steam – CO2, steam – C4H10 and SAGD steam – oil ratios (zd = 0.1666); (d) comparison of steam – CO2, steam – C4H10 and SAGD produced asphaltene content (zd = 0.1666).
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Fig. 6 (continued).
3.5. General observations Results from the experiments demonstrate that injector-to-producer spacing is a parameter important to project success that still remains to be fully understood. The oil is mobile following preheating of the model to 50 jC, although it is quite viscous. Small separation between the injector and producer short-
Fig. 7. Summary of experiments with initial gas (CO2 or butane) saturation: (a) comparison of oil recoveries for steam injection in a model initially saturated with CO2 and C4H10 (zd = 0.1666); (b) comparison of steam – oil ratios for steam injection in a model containing initial gas saturation; (c) comparison of produced asphaltene content (zd = 0.1666).
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ened the communication time and promoted the growth of an extensive steam chamber relatively early during the injection. It was assumed that because the oil was initially mobile, the separation between injection and production wells could be increased. Under these circumstances, the differential pressure between the injector and producer was increased to increase steam injection and allow the heating of a greater portion of the model by forcing the steam chamber to expand toward the producer. Table 1 shows that the injection pressure was increased by 34 kPa between experiments 1 and 2. While increasing the vertical separation between wells did reduce the steam –oil ratio, recovery suffered for a given volume of injected steam, Fig. 3. It may be possible to develop a larger steam chamber at greater well separations with increased pressure drop, but the results do not indicate that this is necessarily the case. The addition of CO2 to steam did not appear to have beneficial effects for vertical injection wells. Noncondensable gas reduced the enthalpy of the injectant and slowed gravity drainage as a result of lower steam chamber temperature and greater oil viscosity. Increasing the injection pressure of CO2 –steam mixtures, as in experiment 6, to drive more injectant into the model and increase the delivery of thermal energy did not result in recoveries comparable to pure steam injection. The addition of noncondensable gas only reduced steam – oil ratio slightly for most of the experiments and so had little ancillary benefit. Interpreting asphaltene effects solely from their concentration in the produced oil has proven to be difficult. Currently, we are sampling packing material from the model at the completion of experiments to assay asphaltene content so that a consistent interpretation is developed. Neither deasphalting nor asphaltene enrichment of the oil stops oil flow. No plugging is noted. Virtually all experiments with noncondensable gas mixed with steam showed enrichment of asphaltenes in the produced oil at short times. This suggests that a significant fraction of the asphaltene precipitates remained mobile rather than depositing on rock surfaces.
4. Conclusions 1. For conventional SAGD, smaller injector-to-producer well separations where oil is mobile provide
2.
3.
4.
5.
95
more rapid heating, larger recovery efficiency, and greater steam – oil ratios. When a small amount of noncondensable gas is injected simultaneously with steam, the gas fingers quickly to the top of the model and displaces oil downwards. Addition of noncondensable gas to steam reduced the total heat capacity of the injected hot fluid. In turn, steam – noncondensable gas mixtures displayed steam condensation effects more quickly compared to steam-only injection. This slows the upward movement of heat, and also delays formation of the steam chamber, and decreases its size. The shape of the vapor chamber was irregular in all cases, and most irregular as the fraction of noncondensable gas increased and the enthalpy of the injectant decreased. In conventional SAGD, steam chambers resembled inverted triangles, whereas they adopted an egg-like shape when CO2 or n-butane were added to the injected steam. Vapor chamber development was apparently dominated by fingers that increased in width as the fraction of noncondensable gas increased. The presence of a noncondensable gas saturation within the system at the beginning of pure steam injection has similar effects on vapor chamber formation and oil recovery as the injection of gas and steam together. An initial decrease in the asphaltene content of produced oil was observed for conventional SAGD indicating in situ upgrading. Asphaltene content increased slowly as the steam chamber developed. The effect of steam – noncondensable gas mixtures on asphaltene content was not straightforward. In situ upgrading as well as enrichment with respect to asphaltenes were indicated.
Nomenclature B3 geometrical similarity factor, dimensionless g acceleration due to gravity, m2/s h thickness (reservoir), m k permeability, d L length of horizontal well, m m viscosity exponent, dimensionless q volumetric rate, m3/s S saturation, dimensionless SAGD steam-assisted gravity drainage
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SAGP T VAPEX z
steam and gas push temperature, jC vapor extraction vertical distance from base of reservoir
Greek a / m
thermal diffusivity, m2/s porosity, dimensionless kinematic viscosity, mm2/s
subscripts/superscripts i injector o oil R reservoir s steam sz steam chamber at height z
Acknowledgements This work is supported by the National Science Foundation (USA) under Grant no. INT-0000209 and the Scientific and Technical Research Council of Turkey (TUBITAK). Additionally, the support of the Stanford University Petroleum Research Institute (SUPRI-A) Industrial Affiliates is gratefully acknowledged.
References Al-Hadhrami, H.S., Blunt, M.J., 2001. Thermally induced wettability alteration to improve oil recovery in fractured reservoirs. Soc. Pet. Eng., Reservoir Eng. Eval. 4 (3), 179 – 186. Butler, R.M., 1991. Thermal Recovery of Oil and Bitumen. Prentice-Hall, Englewood, pp. 285 – 359. Butler, R.M., 1998. SAGD comes of age. J. Can. Pet. Technol. 37 (7), 9 – 12. Butler, R.M., 1999. The steam and gas push (SAGP). J. Can. Pet. Technol. 38 (3), 54 – 61.
Butler, R.M., 2001. Application of SAGD, related processes growing in Canada. Oil Gas J. 14, 74 – 78 (May). Butler, R.M., Jiang, Q., Yee, C.T., 2000a. The steam and gas push (SAGP)-3: Recent theoretical developments and laboratory results’’. J. Can. Pet. Technol. 39 (8), 51 – 60. Butler, R.M., Jiang, Q., Yee, C.T., 2000b. The steam and gas push (SAGP)-4: Theoretical developments and laboratory results using layered models. J. Can. Pet. Technol. 40 (1), 54 – 61. Das, S.K., Butler, R.M., 1998. Mechanism of the vapor extraction process for heavy oil and bitumen. J. Pet. Sci. Eng. 21 (1 – 2), 43 – 59. Deutsch, C.V., Journel, A.G., 1992. GSLIB: Geostatistical Software Library and User’s Guide. Oxford Univ. Press, New York, pp. 61 – 116. Edmunds, N.R., 1999. On the difficult birth of SAGD. J. Can. Pet. Technol. 38 (1), 14 – 17. Edmunds, N.R., Gittins, S.D., 1993. Effective application of steam assisted gravity drainage of bitumen to long horizontal well pairs. J. Can. Pet. Technol. 32 (6), 49 – 55. Elliot, K.E., Kovscek, A.R., 2001. A numerical analysis of the single-well steam assisted gravity drainage (SW-SAGD) process. Pet. Sci. Technol. 19 (7 and 8), 733 – 760. Hornbrook, M.W, Dehghani, K., Qadeer, S., Osterman, R.D., Ogbe, D.O., 1991. Effects of CO2 addition to steam on recovery of West Sak crude oil. J. Can. Pet. Technol. 30 (8), 278 – 286. Issever, K., Topkaya, I., 1998. Use of carbon dioxide to enhance heavy oil recovery. Paper no 1998. 141 Presented at the 7th Unitar International Conference on Heavy Crude and Tar Sands, Beijing China, 27 – 30 Oct. Jiang, Q., Butler, R., Yee, C.T., 2000. The steam and gas push (SAGP)-2: mechanism analysis and physical model testing. J. Can. Pet. Technol. 39 (4) 52-61. Kokal, S.L., Najman, J., Sayegh, S.G., George, A.E., 1992. Measurement and correlation of asphaltene precipitation from heavy oils by gas injection. J. Can. Pet. Technol. 31 (4), 24 – 30. Prats, M., 1986. Thermal Recovery. Society of Petroleum Engineers, Dallas, p. 215. Spivak, A., Karaguz, D., Issever, K., Nolen, J.S., 1989. Simulation of immiscible CO2 injection in a fractured carbonate reservoir, Bati Raman Field, Turkey, SPE 18765 Presented at the SPE California Regional Meeting Bakersfield, CA, USA, 5 – 7 April. Srivastava, R.K., Huang, S.S., Dong, M.Z., 1999. Asphaltene deposition during CO2 flooding. Soc. Pet. Eng., Prod. Facil. 14 (4), 235 – 245.
Noncondensable gas steam-assisted gravity drainage S. Canbolat a, S. Akin a, A.R. Kovscek b,* a
Petroleum and Natural Gas Engineering Department, Middle East Technical University, 06531 Ankara, Turkey b Department of Petroleum Engineering, Stanford University, Stanford, CA 94305-2220, USA Received 21 August 2003; accepted 19 April 2004
Abstract To investigate steam-assisted gravity drainage (SAGD) mechanisms, experiments with and without carbon dioxide or nbutane mixed with steam were conducted in a scaled physical model. It is packed with crushed limestone premixed with a 12.4j API heavy-oil. Temperature, pressure, production data, and the asphaltene content of the produced oil were monitored continuously during the experiments. For small well separations, the steam condensation temperature and the steam – oil ratio decreased as the amount of carbon dioxide increased. The heavy oil became less mobile in the steam chamber due to lower temperatures and more viscous oil. Thus, the heating period was prolonged and the cumulative oil recovery as well as the recovery rate decreased. Less oil recovery was obtained as the fraction of carbon dioxide injected increased. Little or no change in oil recovery, and the rate of oil recovery, was observed for greater well separations regardless of the fraction of carbon dioxide in the injection gas. Similar behavior was observed when n-butane was injected along with steam instead of carbon dioxide. Cumulative oil recovery, rate of oil recovery, and steam – oil ratio decreased independent of well separation compared to a reservoir with no initial noncondensable gas. These experimental results add to the state of the art understanding of thermal gravity drainage processes. The addition of noncondensable gases during steam-assisted gravity drainage was not beneficial to oil recovery. Nevertheless, experiments do teach that steam injection is effective for producing heavy-oil saturated limestone. D 2004 Elsevier B.V. All rights reserved. Keywords: Gravity drainage; Heavy oil; Thermal oil recovery; Noncondensable gases
1. Introduction A recovery mechanism is required that lowers the viscosity of heavy oil so that it flows easily to a production well. Conventional thermal processes, such as cyclic steam injection, and steam-assisted gravity drainage (SAGD) are based on thermal viscosity reduction and gravity drainage (Butler, 1991). * Corresponding author. Tel.: +1-650-723-1218; fax: +1-650725-2099. E-mail address: [email protected] (A.R. Kovscek). 0920-4105/$ - see front matter D 2004 Elsevier B.V. All rights reserved. doi:10.1016/j.petrol.2004.04.006
SAGD uses horizontal wells to maximize the effect gravity (Butler, 1998). In the idealized SAGD process, a growing steam chamber forms around the horizontal injector and steam flows continuously to the perimeter of the chamber where it heats the surrounding oil. Effective initial heating of the cold oil is important for the formation of the steam chamber in gravity drainage processes (Edmunds and Gittins, 1993; Elliot and Kovscek, 2001). The heated oil drains to a horizontal production well located at the base of the reservoir just below the injection well. Butler (1991) derived Eqs. (1a,b)
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assuming that (1) the steam pressure is constant in the steam chamber, (2) only steam flows in the steam chamber, (3) oil saturation is residual, and (4) heat transfer ahead of the steam chamber to cold oil is only by conduction: sffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffi 1:3/DSo kgah q¼L ð1aÞ mvS where the kinematic viscosity, m ( = shear viscosity/ density), of oil as a function of temperature is given by Ts TR m m ¼ ms ð1bÞ T TR In Eqs. (1a,b), L is the length of the well, / is porosity, DSo is the initial oil saturation minus residual oil saturation, k is the effective permeability for the flow of oil, g is the acceleration constant of gravity, a is the thermal diffusivity, h is the distance from the production well to the top of the reservoir, m is a dimensionless viscosity exponent, ms is the kinematic viscosity of oil at steam temperature (Ts), and TR is the initial reservoir temperature. Empirical correlations or laboratory data are needed to evaluate the residual oil saturation and any effect of temperature on DSo. There are three major consequences of this theory: (1) steam chamber growth is necessary for oil production, and oil production occurs only as long as steam is injected, (2) oil production rate increases as the steam temperature increases, and (3) at a given steam temperature, the oil with the lowest viscosity exhibits the greatest production response. The SAGD process is economic if the steam – oil ratio is not too high (Edmunds, 1999), and is being implemented in a number of projects, mainly in Canada (Butler, 2001). The heat requirements, however, are large in thin reservoirs where heat losses are high and also in low porosity carbonates where the reservoir heat capacity per unit volume of initial oil is high. The simultaneous injection of carbon dioxide and steam is beneficial for recovering heavy oil using vertical wells (Hornbrook et al., 1991). Addition of CO2 to steam results in lower injection temperature without reducing oil recovery as long as the injection temperature remains at or above the steam saturation temperature. For thin reservoirs and some carbonates, vertical well applications are not feasible. These
limitations might be overcome or decreased by using horizontal wells in two ways: addition of noncondensable gas, such as carbon dioxide or methane, to steam (Butler, 1999) and vapor extraction or VAPEX (Das and Butler, 1998). The concept of steam and gas push (SAGP) is similar to conventional SAGD. Steam not only mobilizes the oil by heating, but also equalizes the pressure vertically, because it is relatively inviscid. This is beneficial to oil drainage. In such cases, steam must be injected continuously at relatively high rate, otherwise the steam condenses and the vapor chamber collapses. This limitation is overcome, possibly, in the SAGP process. Even though steam may condense, gas remains in the reservoir, prevents collapse of the heated zone, and maintains pressure. In SAGP, fingers of gas rise warming the reservoir and maintaining pressure. Both effects improve oil recovery (Jiang et al., 2000). In SAGD, however, latent heat has to be carried to the top of the reservoir if steam is to be present there. Thus, the literature suggests it is not necessary to carry the latent heat to the top of the reservoir in the SAGP process. The noncondensable gas rises throughout the recovery process pressurizing the upper portions of the reservoir and thermal conduction provides sufficient heating beyond the steam condensation zone. The chamber temperatures required to achieve production at rates comparable to conventional SAGD are obtained from (Butler, 1999): "
q 2 m Tsz ¼TR þ ðTS TR Þ ðh hi =2Þ2 kga/DSo L hz
# m1
ð2Þ where Tsz is chamber temperature at height z, Ts is steam temperature, and hi is injector height above the bottom of the reservoir. The unknown flow rate, q (m3/s) is obtained from Eqs. (1a,b) by substituting h with hL (height of a SAGD reservoir with the same rate) as (Butler, 1999): hL ¼
pffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffi ð2h hi Þhi
ð3Þ
Eq. (2) suggests that the upper vertical interface of the vapor chamber is at the initial reservoir temperature. Eq. (3) indicates that placing the injector toward
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the bottom of the reservoir improves the production rate; however, as injector and producer become closer, the likelihood of injector – producer linkup and resulting poor contact of injectant with the reservoir increases. It is apparent that the vertical spacing between horizontal injector and horizontal producer may be a critical parameter. Moreover, knowledge of the role of noncondensable gases on recovery performance remains highly schematic. The objectives of this work were to quantify the effect of well spacing and the addition of noncondensable gas to steam with respect to oil recovery, steam-vapor chamber formation, and the spatial distribution of temperature. A suite of SAGD experiments were conducted with CO2 and n-butane added to the injected steam. The effects of injector-to-producer spacing and the presence, or lack, of initial noncondensable gas saturation in the model were examined. A secondary objective was to consider SAGD-like processes for carbonate formations. The SAGD, SAGP, and VAPEX processes are usually considered for sand and sandstone reservoirs. Significant heavy-oil resources are found in carbonate formations (Issever and Topkaya, 1998) that might benefit from a thermal gravity drainage process (AlHadhrami and Blunt, 2001). As a first step toward application of thermal gravity drainage processes in carbonate reservoirs, experiments were conducted using crushed limestone.
2. Experimental equipment and procedure The experimental setup consisted of injection equipment, physical model, and production facilities, as shown in Fig. 1. The oil is a 12.4j API viscous crude oil from the Bati Raman field (Turkey). Fig. 2 gives the oil viscosity versus temperature relationship; the viscosity is roughly 600 cP at the initial temperature of 50 jC. On the injection side, a steam generator and a gas bottle pressured at 10 MPa were used. Carbon dioxide or butane was metered into the live steam using a rotameter. The injection line was insulated and a resistance heater connected to a temperature controller kept the line at the same temperature as the steam generator. Thus, the steam was superheated at 280 kPa and 140 jC and the injected steam quality was 1. The
85
production system consisted of a pressure gauge and two fluid separators. System backpressure was held constant at 103 kPa. The production line was heated to 100 jC so that it did not clog with cooled viscous oil. Production was measured volumetrically. The wells were made from perforated tubing wrapped with wire screens. The screens were necessary to prevent migration of unconsolidated particles. The model reservoir was constructed of stainless steel and it is 30-cm tall, 30-cm wide, and 7.5-cm thick. A thermal blanket preheated the model to 50 jC. The position of the injection well was adjustable such that it could be 5, 10, or 15 cm above the production well. Twenty-five thermocouples separated by a distance of 2 cm were placed centrally within the width of the model, Fig. 1. Thermocouples entered the model through tube fittings welded on the model and were connected to a computer. This setup allowed continuous monitoring of the model temperature. To obtain dimensional similarity, it is necessary to pack the model with a much more permeable medium than found in the field. Butler (1991) discusses several quantities for obtaining dimensional similarity and recommends the use of sffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffi kgh B3 ¼ a/DSo mvs
ð4Þ
It is assumed that the terms g, a, m, and DSo are roughly the same between the laboratory and the field. Equating B3 for laboratory and field cases yields the following expression for permeability of the scaled model kh /vs ð5Þ kM ¼ /vs F h M where the subscripts F and M denote field and model, respectively. Bati Raman is a representative fractured carbonate reservoir where the matrix permeability varies from 0.01 to 0.1 d (Issever and Topkaya, 1998), the porosity is about 18%, and the fracture spacing is on the order of 4 to 6 m (Spivak et al., 1989). At 140 jC, the kinematic viscosity of Bati Raman crude oil is estimated as 15 mm2/s at 140 jC and 4 mm2/s at 230 jC; Fig. 2 (Prats, 1986). The former kinematic viscosity is at the model injection temperature. The latter is an estimate for the field
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Fig. 1. Schematic of the experimental equipment.
assuming injection occurs at the depleted reservoir pressure of 3 MPa (Issever and Topkaya, 1998). Setting kF to 0.05 d, hF to the fracture spacing of 6 m, /M//F to 38/18 ( = 1.8), and employing the kinematic viscosities above yield kM equal to 6.3 d. The range of parameters above sets the permeability of the packing material from 1 to 10 d.
Fig. 2. Viscosity – temperature relationship for the crude oil.
The scaling of a field matrix block is only approximate, because the laboratory model is bounded by no-flow boundaries. Fractures may be open and permeable to fluid flow. Additionally, there may be heat transfer among field matrix blocks that is not incorporated in this scaling. Crushed limestone (mesh size 0.5 to 1.4 mm) was obtained from a quarry (Ankara, Turkey). The permeability and porosity of the packed model were 8 d and 38%, thereby meeting the criteria for a scaled physical model. The rock grains displayed no measurable internal porosity. The packed model represents some aspects of fractured limestone. Namely, any interactions of steam with the rock are reproduced, and it resembles the relatively homogeneous matrix in a system containing fractures. The crushed material is well characterized and allows examination of matrix processes. The crushed limestone was washed with deionized water to clean off any residues and coat the solid with water. The limestone/water slurry was mixed with crude oil to yield oil and water saturations of 75%
S. Canbolat et al. / Journal of Petroleum Science and Engineering 45 (2004) 83–96 Table 1 Summary of experimental operating conditions Exp. Description no.
Producer – Injection Injection Steam injector temperature pressure rate spacing, zd (jC) (kPa) (cc/min)
1 2 3 4
0.166 0.333 0.5 0.166
139 134 144 144
316 350 323 254
36.4 47.34 39 22
0.166
139
343
46
0.166
140
382
24
0.166
141
261
22
0.333
143
316
47.34
0.166
140
343
36.4
5 6 7 8 9
SAGD SAGD SAGD SAGD + Initial C4H10 SAGD + Initial CO2 SAGD + CO2 1.29:1 SAGD + C4H10 1.29:1 SAGD + CO2 4.41:1 SAGD + CO2 4.41:1
and 25%, respectively. Initial saturations are held constant throughout the experiments. An experiment proceeded by first selecting a well separation of 5, 10, or 15 cm. The model was positioned vertically and preheated to 50 F 1 jC. The steam generator was brought online and adjusted to 280 kPa and 140 jC. If noncondensable gas was to be used, it was introduced to the steam, after the steam was at the operating temperature and pressure. During the experiments, the injection line temperature, the temperature profile in the model, the pressure, and production data were recorded continuously. Properties of the produced oil and water were measured together with injection and production pressures. Additionally, asphaltene content of produced oil was measured to monitor deposition of asphaltenes and any possible upgrading of the produced oil. Asphaltene was measured by titration following Kokal et al. (1992). Measurements on the same sample indicated repeatability of F 2%. The experiment continued until the cumulative steam –oil ratio began to increase rapidly. The experimental conditions are summarized in Table 1. Nine experiments were conducted.
3. Results and discussion To evaluate whether the addition of noncondensable gases aided recovery, a critical evaluation of conven-
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tional SAGD is necessary. After steam injection is initiated, a steam chamber grows. Butler (1991) notes that the steam chamber initially grows upward, due to gravity, with little lateral spreading until it meets the top of the reservoir. Then the chamber begins to extend horizontally. At the steam-chamber boundary, steam condenses as heat is transferred to the oil. Condensed water and hot oil flow along the steam chamber boundary to the production well. In a reservoir where cold oil is very viscous and does not flow easily, initial production rates via SAGD are very low. In a strict definition of SAGD, steam is expected to enter the reservoir only to fill the void space left by produced oil. If the oil is cold and will not gravity drain into the wellbore at appreciable rates, then the oil must be heated to reduce viscosity so that it will flow. It follows that the vertical distance between the production – injection well pair (Eq. 2) has an effect on system performance; this effect was tested here experimentally. 3.1. Conventional SAGD experiments To test the relationship between producer –injector spacing and recovery, the size and the shape of the steam chamber formed as the injection– production well spacing varied were evaluated. Fig. 3 summarizes results from conventional SAGD experiments. First, the temperature measurements were contour mapped using a kriging algorithm (cf., Deutsch and Journel, 1992). All temperatures reported here are collected from the midplane of the model. Fig. 3a presents the temperature profiles for conventional SAGD for different well separation distances. Producer – injector spacing is described by a dimensionless number (zd) that is the ratio of the well spacing to the height of the reservoir model, Table 1. Regions of the pack that are bypassed by steam have circular shapes because the temperature measurements are kriged from the measured array of data. The heated area, as a function of time, is largest for the smallest well separation. Compare the left column of temperature contours (zd = 0.166) in Fig. 3a to the right column (zd = 0.5). Dark shading corresponds to a temperature of 145 jC, whereas white is 100 jC and less. At a specific time the model is warmer and temperature is more evenly distributed with the smallest well separation. The steam chamber, or heated zone shape, resembles an egg or an inverted, distorted triangle
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similar to the heated-zone shapes reported by Butler (1991). A significant upward movement of steam due to gravity is also present, especially at early times, for all cases. To compare the recovery efficiency for different well separations and to quantify the rate of steam chamber formation, dimensionless steam flooded areas were plotted versus time as shown in Fig. 3b. The dimensionless steam chamber area was obtained by dividing the steam-flooded area where temperatures were greater than 100 jC by the surface area of the model reservoir (i.e. 30 30 cm2). Thus, the dimensionless steam chamber area lies between 0
and 1. The steam chamber formation curves resemble each other for different well separations. Initially the heating is quite fast. The steam chamber expands rapidly until the steam reaches the upper vertical boundary of the model where steam chamber development slows as it expands to first the sides, and then toward the bottom of the model. For the largest injection – production well separation, the injection well is located at the midsection of the experimental model. In this case, the steam chamber reaches the top of the model quite quickly. Thus, the largest well separation heats the model the slowest. These observations are in accord with the ‘‘rising steam cham-
Fig. 3. Summary of conventional SAGD experiments: (a) isotherms for different well spacing zd = 0.166 (left) at 0.32, 0.60, 0.80 and 1.20 PVs injected, zd = 0.3333 (middle) at 0.43, 0.78, 1.05 and 1.25 PVs injected, and zd = 0.5 (right) at 0.50, 0.69, 0.92 and 1.29 PVs injected; (b) effect of well spacing on steam chamber size (dotted lines) and oil recovery (solid lines); (c) effect of well spacing on cumulative produced steam – oil ratio; (d) effect of well spacing on produced asphaltene content.
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aration, in apparent agreement with Eq. (3). This is consistent with the observation of optimum early-time heating with small well separations. All of the production curves indicate gravity drainage of oil to the end of the experiment. Comparison of Fig. 3b and c suggests that had the injection rate been cut significantly at the point that the model was mostly heated, injector-to-producer linkage and cycling of steam could have been reduced and the ultimate recovery increased. That is, the instantaneous steam – oil ratio might be reduced by limiting steam injection after roughly 1 PV of cumulative injection. The asphaltene content of the initial oil in place was measured to be 35% by weight. An initial sharp drop in the asphaltene content of produced oil was observed for dimensionless well separations of 0.3333 and 0.5, Fig. 3d. The decrease suggests a partial upgrading of the oil by asphaltene precipitation and flocculation. As the steam chamber developed, the produced asphaltene content increased slowly but remained below the initial value up to roughly 2.5 PV of injection. Precipitation of asphaltenes still occurred in the newly processed volume created by the injected steam. Asphaltene content of the produced oil increased as the steam chamber grew and the model became warmer indicating mobilization of the precipitated solid, or perhaps a partial redissolution of solids. In all cases, the asphaltene fraction first decreased, went through a maximum and then decreased again. The final asphaltene content of the produced oil was roughly two-thirds of the initial value. 3.2. SAGD style steam – CO2 experiments
Fig. 3 (continued).
ber’’ and ‘‘depleting reservoir’’ phases of Butler’s (1991) discussion of SAGD. Fig. 3b also summarizes the effect of well spacing on oil recovery (percent of original oil in place), whereas Fig. 3c shows the steam – oil ratio. Steam volumes are computed as cold (16 jC) water equivalent (Prats, 1986). The largest, most rapid overall production was obtained from the smallest well sep-
Carbon dioxide or n-butane was injected simultaneously with steam. Two flow rates, one higher than and one comparable to that of the SAGD experiments, were used; Table 1. For the experiments employing CO2 injection, the impact of well spacing on production efficiency also was considered by changing the location of the injection well. These experiments also were analyzed by means of dimensionless steam chamber size obtained from the temperature distributions, cumulative oil recovery, and steam –oil ratio; Fig. 4. Fig. 4a shows isotherms obtained at subsequent times for an identical CO2/steam ratio (4.41) at two different well separations (zd = 0.166 and zd = 0.3333). Again, dark shading represents 145 jC and white is
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100 jC or less. The average temperatures in the chamber for these experiments are lower compared to those for comparable times during SAGD experiments, Fig. 3a. The same amount of steam has been injected at each time for plots in both Figs. 3a and 4a. It appears that CO2 rises to the top of the model quickly and long before the upper portions are heated. During the initial stages of injection, the model is cold and most of the injected steam condenses. The noncondensable gas rises as fingers that displace very little oil. Because gas heat capacity is small, heating is limited in magnitude. This gas collects under the top impermeable boundary of the model as a thin gas zone. In this
Fig. 4 (continued).
Fig. 4. Summary SAGD performance with steam – CO2 injectant: (a) isotherms for different well spacing, CO2 – steam ratio = 4.41, zd = 0.333 (left) at 0.45, 1.40, 2.36 and 2.67 PVs injected and zd = 0.166 (right) 0.95, 1.88, 2.52 and 3.83 PVs injected; (b) effect of well spacing on steam chamber size (dotted lines) and oil recovery (solid lines) for CO2 – steam ratio = 4.41; (c) effect of well spacing on cumulative produced steam – oil ratio, CO2 – steam ratio = 4.41; (d) effect of well spacing on produced asphaltene content for CO2 – steam ratio = 4.41.
sense, the noncondensable gas indeed carries pressure to the upper parts of the reservoir (Butler et al., 2000a,b). The chamber shapes are somewhat different compared to those of the conventional SAGD experiments. This is due to the temperature and pressure gradients introduced into the chamber by the rising noncondensable gas. Steam chamber size was computed in the same way as Fig. 3b. Compared to
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conventional SAGD, the time required to grow a sizeable steam chamber in Fig. 4b is more than two times, and eight times as large for small and large well separations, respectively. Addition of carbon dioxide did not increase the ultimate oil recovery (Fig. 4b), but prolonged the heating period and the project life. The steam – oil ratios (Fig. 4c) were many times smaller compared to those of the conventional SAGD experiments (Fig. 3c), but large nevertheless. Similar to SAGD, the smaller well separation was observed to perform better in terms of heating and oil recovery. Unlike the steam experiments, there was no indication of early time precipitation of asphaltenes (Fig.
91
4d). On the contrary, asphaltene content of the produced oil increased. For small well separation, the asphaltene content fluctuated around the initial value. This is an indication of successive precipitation and mobilization of solids from pores. For larger well separation, however, the asphaltene content increased slowly and remained higher than the starting value. Srivastava et al. (1999) reported similar observations for linear CO2 core floods. Another factor that has an impact on recovery and project economics is concentration of gas in the injected steam – gas mixture. Several experiments were conducted by changing the steam – CO2 ratio
Fig. 5. Summary of SAGD performance with steam – CO2 injectant at variable concentration: (a) isotherms for zd = 0.1666 for steam (left), at 0.32, 0.60, 0.80 and 1.20 PVs injected, CO2 – steam ratio = 1.29 (middle) at 0.38, 0.63, 1.16 and 1.65 PVs injected, and CO2 – steam ratio = 4.41 (right) at 0.95, 1.88, 2.52 and 3.83 PVs injected; (b) effect of CO2 on steam chamber size (dotted lines) and oil recovery (solid lines); (c) effect of CO2 on produced steam – oil ratio for different volumetric steam – CO2 ratios; (d) effect of CO2 on produced asphaltene content for different volumetric steam – CO2 ratios.
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increased due to the reduction in the latent and sensible heat per unit of injectant. Correspondingly, the steam chamber formation rates decreased as shown in Fig. 5a. The shape of the vapor chamber was irregular and appeared to be dominated by wide gas fingers, as compared to conventional SAGD at similar elapsed times. The oil recovery and the production rates decreased (Fig. 5b), but the decrease in steam – oil ratio (Fig. 5c) was much more pronounced as the amount of gas in the mixture increased. For the steam – CO2 ratio of 1:1.29, asphaltene content of the produced oil (Fig. 5d) showing similar behavior to that of the steam only case except for the early-time decrease. At larger steam – CO2 ratio (1:4.41), the asphaltene content was always above the initial value. Late time reductions of the produced asphaltenes for both cases exhibit additional asphaltene precipitation/flocculation in the sand matrix during CO2 injection with steam. 3.3. SAGD-style steam/n-butane experiments
Fig. 5 (continued).
from 0 to 4.41 using the same injection– production location at zd = 0.1333, Fig. 5. This location was chosen because it was the best performing location in terms of oil recovery and the rate of steam chamber formation. As the CO2 concentration in the injected mixture increased, the time required to heat the system
The addition of a hydrocarbon gas to steam also was considered. The same concentration used for the steam – CO2 experiments and the same injection – production locations (zd = 0.1333) were used to inject a steam –butane mixture. Fig. 6a compares the isotherms obtained at different times during the experiment to those obtained for SAGD and steam – CO2 experiments. The shapes of the vapor chamber observed in both steam –noncondensable gas systems resemble each other. This suggests that the production mechanism is little affected by the amount and type of gas in the mixture. As expected, the oil recoveries (Fig. 6b) and the steam – oil ratios (Fig. 6c) were lower compared to conventional SAGD recovery. Performance of CO2 was better than n-butane. The change in asphaltene content of the produced oil as a function of time for steam – butane injection (Fig. 6d) was insignificant compared to steam only and steam – CO2 injection, illustrating that solvent – gas effects are important to asphaltene precipitation. 3.4. Effect of initial presence of noncondensable gases in SAGD experiments The presence of initial gases in the system was investigated. The principal interest is the possibility of
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steam injection following primary production by solution gas drive or immiscible, isothermal gas injection. To achieve initial nonzero gas saturation, several pore volumes of CO2 or n-butane were injected and then the system was shut in for 24 h. During injection, small amounts of oil were produced. By mass balance, the average initial gas saturations of CO2 and n-butane were 8.35% and 3.0% of the original oil in place, respectively. Conventional SAGD was then conducted. Fig. 7a and b compares the oil recovery and steam – oil ratios observed during the experiments. When compared to simultaneous gas and steam injection, initial saturation of n-butane positively affect-
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ed oil recovery. This is most likely due to viscosity reduction of the heavy oil arising from n-butane dissolution in the oil. The area of the steam chamber (Fig. 7a) at equal times observed for initial saturation of n-butane was somewhat smaller compared to initial CO2 saturation in the system. The initial gas saturation probably created low resistance pathways for the steam to move through the viscous oil saturating the model. The asphaltene content of the produced oil was similar to steam only injection situations, as shown by Figs. 3 and 7c. Again, butane appeared to have relatively little effect on the asphaltene content of the produced oil.
Fig. 6. Summary SAGD performance with steam – butane injectant; (a) isotherms for zd = 0.1666 for steam (left), at 0.32, 0.60, 0.80 and 1.20 PVs injected, steam – CO2 (middle) at 0.38, 0.63, 1.16 and 1.65 PVs injected, steam – C4H10 (right) at 0.35, 0.55, 1.11 and 1.54 PVs injected; (b) comparison of steam – CO2, steam – C4H10 and SAGD oil recoveries (zd = 0.1666); (c) comparison of steam – CO2, steam – C4H10 and SAGD steam – oil ratios (zd = 0.1666); (d) comparison of steam – CO2, steam – C4H10 and SAGD produced asphaltene content (zd = 0.1666).
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Fig. 6 (continued).
3.5. General observations Results from the experiments demonstrate that injector-to-producer spacing is a parameter important to project success that still remains to be fully understood. The oil is mobile following preheating of the model to 50 jC, although it is quite viscous. Small separation between the injector and producer short-
Fig. 7. Summary of experiments with initial gas (CO2 or butane) saturation: (a) comparison of oil recoveries for steam injection in a model initially saturated with CO2 and C4H10 (zd = 0.1666); (b) comparison of steam – oil ratios for steam injection in a model containing initial gas saturation; (c) comparison of produced asphaltene content (zd = 0.1666).
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ened the communication time and promoted the growth of an extensive steam chamber relatively early during the injection. It was assumed that because the oil was initially mobile, the separation between injection and production wells could be increased. Under these circumstances, the differential pressure between the injector and producer was increased to increase steam injection and allow the heating of a greater portion of the model by forcing the steam chamber to expand toward the producer. Table 1 shows that the injection pressure was increased by 34 kPa between experiments 1 and 2. While increasing the vertical separation between wells did reduce the steam –oil ratio, recovery suffered for a given volume of injected steam, Fig. 3. It may be possible to develop a larger steam chamber at greater well separations with increased pressure drop, but the results do not indicate that this is necessarily the case. The addition of CO2 to steam did not appear to have beneficial effects for vertical injection wells. Noncondensable gas reduced the enthalpy of the injectant and slowed gravity drainage as a result of lower steam chamber temperature and greater oil viscosity. Increasing the injection pressure of CO2 –steam mixtures, as in experiment 6, to drive more injectant into the model and increase the delivery of thermal energy did not result in recoveries comparable to pure steam injection. The addition of noncondensable gas only reduced steam – oil ratio slightly for most of the experiments and so had little ancillary benefit. Interpreting asphaltene effects solely from their concentration in the produced oil has proven to be difficult. Currently, we are sampling packing material from the model at the completion of experiments to assay asphaltene content so that a consistent interpretation is developed. Neither deasphalting nor asphaltene enrichment of the oil stops oil flow. No plugging is noted. Virtually all experiments with noncondensable gas mixed with steam showed enrichment of asphaltenes in the produced oil at short times. This suggests that a significant fraction of the asphaltene precipitates remained mobile rather than depositing on rock surfaces.
4. Conclusions 1. For conventional SAGD, smaller injector-to-producer well separations where oil is mobile provide
2.
3.
4.
5.
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more rapid heating, larger recovery efficiency, and greater steam – oil ratios. When a small amount of noncondensable gas is injected simultaneously with steam, the gas fingers quickly to the top of the model and displaces oil downwards. Addition of noncondensable gas to steam reduced the total heat capacity of the injected hot fluid. In turn, steam – noncondensable gas mixtures displayed steam condensation effects more quickly compared to steam-only injection. This slows the upward movement of heat, and also delays formation of the steam chamber, and decreases its size. The shape of the vapor chamber was irregular in all cases, and most irregular as the fraction of noncondensable gas increased and the enthalpy of the injectant decreased. In conventional SAGD, steam chambers resembled inverted triangles, whereas they adopted an egg-like shape when CO2 or n-butane were added to the injected steam. Vapor chamber development was apparently dominated by fingers that increased in width as the fraction of noncondensable gas increased. The presence of a noncondensable gas saturation within the system at the beginning of pure steam injection has similar effects on vapor chamber formation and oil recovery as the injection of gas and steam together. An initial decrease in the asphaltene content of produced oil was observed for conventional SAGD indicating in situ upgrading. Asphaltene content increased slowly as the steam chamber developed. The effect of steam – noncondensable gas mixtures on asphaltene content was not straightforward. In situ upgrading as well as enrichment with respect to asphaltenes were indicated.
Nomenclature B3 geometrical similarity factor, dimensionless g acceleration due to gravity, m2/s h thickness (reservoir), m k permeability, d L length of horizontal well, m m viscosity exponent, dimensionless q volumetric rate, m3/s S saturation, dimensionless SAGD steam-assisted gravity drainage
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SAGP T VAPEX z
steam and gas push temperature, jC vapor extraction vertical distance from base of reservoir
Greek a / m
thermal diffusivity, m2/s porosity, dimensionless kinematic viscosity, mm2/s
subscripts/superscripts i injector o oil R reservoir s steam sz steam chamber at height z
Acknowledgements This work is supported by the National Science Foundation (USA) under Grant no. INT-0000209 and the Scientific and Technical Research Council of Turkey (TUBITAK). Additionally, the support of the Stanford University Petroleum Research Institute (SUPRI-A) Industrial Affiliates is gratefully acknowledged.
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