Heavy

Article pubs.acs.org/IECR

Cite This: Ind. Eng. Chem. Res. XXXX, XXX, XXX-XXX

Reservoir Simulation and Production Optimization of Bitumen/Heavy Oil via Nanocatalytic in Situ Upgrading Ngoc Nguyen,* Zhangxin Chen, Pedro Pereira Almao, Carlos E. Scott, and Brij Maini Schulich School of Engineering, University of Calgary, Calgary, Alberta T2N 1N4, Canada ABSTRACT: This paper presents recent development of in situ upgrading technology (ISUT) for producing heavy oil and bitumen in which a mixture of catalyst, hydrogen, and vacuum residue are injected together with steam to improve oil quality by converting heavy oil components into lighter oil components. Consequently, the produced oil is upgraded and the oil recovery factor is increased while less steam is used, which results in lower capital and operational costs. This technology helps to reduce environmental impacts and greenhouse gas emissions. Numerical simulation of a steam-assisted gravity drainage (SAGD) well pattern was conducted to study the improvement of oil production by applying coinjection of steam and the ISUT mixture (ST-ISUT). The results show that ST-ISUT method can increase the oil recovery factor by 36% and lowers the requirement of steam by 50% in comparison with the conventional steam injection method, and the produced oil has much better quality.

1. INTRODUCTION Athabasca oil deposits are the largest oil sand reserves in Alberta, Canada and are the third largest oil reserves in the world. Oil sands are a mixture of sands, minerals, water, and bitumen. Bitumen has an extremely high viscosity at reservoir conditions16 and cannot be produced naturally. Heavy oil/bitumen can be produced by reducing its viscosity in situ. Steam injection allows the development of a heated fluid chamber and generates mobile oil surrounding production wells, for example. Steam injection is a common and successful method applied all over the world. Nevertheless, the produced oil needs diluents to make it movable at the surface conditions. It also requires a large amount of water to generate the steam. Another drawback of steam injection is that chemical reactions between steam and heavy oil can generate free radicals that participate in polymerization reactions and form bigger molecules, leading to production of more viscous oil instead of reducing its viscosity.5 One possible way of permanently reducing the viscosity of the produced oil is to upgrade it in the reservoir prior to reaching the surface, thus producing a synthetic crude oil that meets or is close to pipeline specifications. With the purpose of reducing the use of diluents and avoiding the formation of free radicals, researchers have recently started investigating injection of ultradispersed particles (catalysts) which can be used along with steam to significantly improve the quality of in situ oil.1,9,13,14,19,21 The technology of combining catalysts and steam has been proposed and performed successfully in laboratory experimental tests. The catalysts are injected into cores at high temperature from 240 to 350 °C and promote reactions which convert heavy oil components into light oil components, leading to production of better quality oil. © XXXX American Chemical Society

The work on catalytic aquathermolysis has been reviewed by Maity et al.,11 and it has been shown that several metal catalysts may catalyze the aquathermolysis of heavy oils under steam injection conditions and lead to a significant reduction in oil viscosity. Thus, Jiang et al.9 found that a synergetic effect between catalysts and hydrogen donors was indicated in their experiments, which leads to chemical reactions changing the structure of oil components and finally upgrading the oil. Zhang et al.21 conducted several experiments to study the effect of catalyst (Fe(acac)3) on oil recovery compared to other solvent or steam methods. They also investigated the effect of temperature on heavy oil upgrading by utilizing a catalysts, hydrogen, and a tetralin/decalin mixture. Their results showed that the mixture can reduce viscosity significantly and that the optimum upgrading temperature is about 300 °C.

Figure 1. Research workflow.

Received: Revised: Accepted: Published: A

September 15, 2017 November 8, 2017 November 8, 2017 November 8, 2017 DOI: 10.1021/acs.iecr.7b03819 Ind. Eng. Chem. Res. XXXX, XXX, XXX−XXX

Article

Industrial & Engineering Chemistry Research

maximum effect was observed at 270 °C. They also showed that the concentration of the light oil components (C30) decreased as the result of breakage of C−S bonds in the asphaltene fraction. Additionally, they investigated injection of the nickel nanoparticles in heavy oil reservoirs, together with surfactant and polymer, which can increase oil recovery by an additional 7% compared to the injection of only polymer and surfactant. Shuwa et al.19 presented the effect of a submicrometer dispersed trimetallic catalyst (Ni−Co−Mo) for upgrading of Omani heavy crude oil. These catalysts stayed in a water-in-oil emulsion and were then injected into sand packs together with steam. They concluded that the oil recovery increased 15% and the oil viscosity reduced about 25% in the case of using these catalysts compared to conventional steam injection. Their experimental results also showed that the API increased about 10% with a significant decrease in sulfur content (26%). As a result, the produced oil is upgraded leading to a reduction in the cost of transportation and refining processes at the surface and also in the cost of generating the steam due to reduced steam requirements. Another advantage of this technology is that harmful products, such as metals, sulfur, and nitrogen, remain in the reservoir, as was clearly proven in studies of Shokrlu and Babadagli17 and Shuwa et al.19 The use of in situ combustion (ISC) and catalysts has also been proposed as a way of producing oil and upgrading of heavy oils and bitumen.2,3,8,12,20 Most recently, Abu et al.,1 using untradispersed catalysts, reported that an improvement in oil quality and a reduction in viscosity depend on the type of catalysts and oil components and that there is a critical temperature level to promote chemical reactions. For example, in their experiments, the catalysts were heated to 325 °C when these catalysts were used together with in situ dry combustion and to 275 °C with wet combustion. The results of their experiments showed that the API gravity was increased from 10.3 for the original bitumen to a maximum of 23.1.

Shokrlu and Babadagli18 presented a kinetic model for in situ upgrading in the presence of nickel nanoparticles at different temperatures and different lengths of time. The results of their experiments showed that the nickel nanoparticles reduce the activation energy of reactions from 69 to 38 kJ/mol, and their

Figure 2. Injection and production illustration.

Table 1. Lumped Components and Oil Mole Fraction lumps

temperature (°C)

components

mole fraction

gases naphtha distillates vacuum gas oil (VGO) residue (VR)

IBP−216 216−343 343−545 +550

C1−C4 C5−C12 C13−C20 C21−C44 C45+

1.00098 × 10−7 0.041644 0.13114 0.32281 0.5044

Figure 3. Kinetic model for hydrocracking and hydroprocessing of Athabasca residue.

Table 2. Kinetic Parameters for Catalytic Hydroprocessing of Athabasca Vacuum Residue temperature (°C) −1

reaction constant (h ) k1 k2 k3 k4 k5 k8

320 0.00126 0.00060 0.00012 0.00001 0.00042 0.0000

380 0.00441 0.00124 0.00037 0.00009 0.00145 0.00092

395

pre-exponential factor (h−1)

activation energy (kJ/mol)

R2

0.00792 0.00166 0.00046 0.00021 0.00217 0.00392

6.831 × 10 3.745 16.145 5.486 × 107 7.045 × 102 9.15 × 1025

76.6 43.2 58.1 146.6 70.8 362.7

0.979 0.988 1.000 0.995 0.996 1.000

3

B

DOI: 10.1021/acs.iecr.7b03819 Ind. Eng. Chem. Res. XXXX, XXX, XXX−XXX

Article


(ISUT), which integrates enhanced recovery and in-reservoir catalytic upgrading of bitumen based upon the injection of a nanocatalyst, suspended in the hot fluid, and hydrogen. The nanocatalyst is retained in the reservoir and remains active anywhere from several months to a few years. This process also focuses on reducing the environmental footprint of heavy oil production by enhancing the upgrading of bitumen or heavy oil directly in the reservoir. It consists of separating the heaviest fraction of the oil (the vacuum residue) at the surface and producing catalytic nanoparticles suspended in the heavy oil fraction which is reinjected in the well. The vacuum residue (VR) reinjected is converted, in the presence of the catalyst and hydrogen, to a product with composition similar to that of the original oil in place. Thus, Da Silva4 investigated the conversion of Athabasca VR, using a combination of catalysts and hydrogen, at conditions similar to those that would be used in the ISUT process, and found that it is possible to convert the VR and reduce the viscosity of heavy oil in Athabasca reservoirs. Given the encouraging experimental results obtained, the present work presents the development of a simulation model of this new approach and attempts to find the optimal operational conditions to recover maximum oil production while using a minimum amount of steam. The simulation studies show that this process provides a higher oil recovery factor, better oil quality, and a lower requirement of steam. The STARS software22 is used to build a half section of two horizontal SAGD wells. SAGD is widely used for bitumen recovery from oil sands in Alberta. The existing SAGD well pad was used to simulate and evaluate this new technology. The simulation model is run for one year in conventional steam injection mode to preheat the reservoir and then followed by injection of steam plus catalyst, hydrogen, and vacuum residue (ST-ISUT) until the end of simulation. Several different injection strategies including continuous injection of ST-ISUT and alternating injection between steam and ST-ISUT are tested to compare oil recovery and to find the best injection method. The results of simulation runs are discussed in detail in the following sections.

Table 3. Reservoir Properties Used for Building a Simulation Model properties

value

porosity (%) horizontal permeability (mD) vertical permeability (mD) reservoir Pressure (kPa) reservoir temperature (°C) oil saturation (%)

33 3600 1800 2000 11 0.81

Table 4. Properties of Athabasca Bitumen property density (g/cm3)

viscosity (cp)

composition (wt %)

value 15.56 °C, 101.3 kPa 120 °C, 2000 kPa 140 °C, 2000 kPa 160 °C, 2000 kPa 180 °C, 2000 kPa 11 °C 25 °C 50 °C 100 °C 150 °C 200 °C asphaltenes heavy oils (C > 40) light oils (C < 40)

1.0129 0.9480 0.9353 0.9232 0.9099 654 228 148 912 9 749 336 37 10 17.85 38.23 43.92

The use of hydrogen and ultradispersed nanocatalysts have been shown to be a very promising alternative for in situ upgrading.6,7,10,13 The combination of the hydroprocessing/ hydrotreating catalyst and hydrogen (in relatively small proportion) offer the advantage of avoiding coke and coke precursors formation, by saturation of the free radicals formed during the process, as well as the partial removal of unwanted fractions like sulfur-containing organometallic compounds and asphaltenes. Thus, a Canadian patent14 describes a process called hot fluid injection (HFI) or in situ upgrading technology

Figure 4. Cross section of simulation model. C


Article

Industrial & Engineering Chemistry Research Table 5. Description of Simulation Casesa case

injection type

remarks

1 2

7 years of pure SAGD Stage 1: 1 year of SAGD Stage 2: 6 years of ST-ISUT injection Stage 1: 1 year of SAGD Stage 2: 6 years of ISUT injection Stage 1: 1 year of SAGD Stage 2: alternating 6 months of steam injection and 6 months of ST-ISUT injection Stage 1: 1 year of SAGD Stage 2: alternating 1 year of steam injection and 1 year of ST-ISUT injection Stage 1: 1 year of SAGD Stage 2: alternating 2 years of steam injection and 2 years of ST-ISUT injection

Base case: steam injection Volume fraction of injection fluid for ST-ISUT: 0.0495 water +0.007854 VR + 1.14 × 10−6 catalyst + 0.9426 H2

3 4

5

6

a

Volume fraction of injection fluid for ISUT: 0.0083 VR + 1.2 × 10−6 catalyst + 0.9917 H2 Volume fraction of injection fluid for ST-ISUT: 0.0495 water + 0.007854 VR + 1.14 × 10−6 Catalyst + 0.9426 H2 Volume fraction of injection fluid for ST-ISUT: 0.0495 water + 0.007854 VR + 1.14 × 10−6 catalyst + 0.9426 H2 Volume fraction of injection fluid for ST-ISUT: 0.0495 water + 0.007854 VR + 1.14 × 10−6 catalyst + 0.9426 H2

Catalysts are suspended in oil phase (VR) with a small concentration (200 ppm).

Figure 5. Results of simulation for six cases.

2. RESEARCH METHODOLOGY AND IN SITU UPGRADING TECHNOLOGY

reservoir conditions, and it can reduce the demands of energy (steam) and the environmental impacts for heavy oil production and refining. However, this method has been investigated and implemented only in the laboratory. To the best of our knowledge, until now, there are no field application and simulation results published about this technology. For these reasons, an injection simulation model is constructed for a reservoir, which has properties similar to those of Athabasca

Even though current commercial processes for producing heavy oils/bitumen are based on a thermal treatment, it is recognized that catalytic processes with hydrogen addition can produce higher yields of liquid fractions with better oil quality, as mentioned above. This is called in situ upgrading of bitumen occurring at the D


Article


Figure 6. Steam oil ratio and cumulative injected VR amount.

Figure 7. Temperature profiles after 7 years of production.

reservoirs. In the simulation model, a mixture of nanocatalysts and vacuum residue is injected together with hydrogen and steam into the reservoir after preheating the formation by conventional SAGD injection. Reducing the steam amount while increasing oil

production is the main target of this process, helping to reduce the injection cost and lower greenhouse gas emissions. The recovery mechanisms involved in this method include aquathermolysis, solution gas drive, gravity drainage, hydrogenation, E


Article


Figure 8. Oil viscosity after 7 years of production.

the case of applying this new technology compared to the optimal SAGD injection. Figure 2 presents a schematic diagram of the injection and production operations. The injection is proposed as follows: 1. Applying steam injection: A steam injection is first run to create a heated chamber until it reaches the top of the formation. 2. The produced fluid is sent to a vacuum or atmospheric distillation unit, and the distillation residue is used to prepare the injection fluid. 3. Injecting steam together with a mixture of vacuum residue, nanocatalysts, and hydrogen (ST-ISUT): This period can be a continuous injection of ST-ISUT or an alternative injection between steam and ST-ISUT. 4. The produced fluid is sent to the vacuum or atmospheric distillation unit, and catalysts (if any), hydrogen, gases, and vacuum residues are recycled. 5. Repeat steps 2−4.

and hydrocracking processes. During aquathermolysis, the C−S bonds of organosulphur compounds are broken, and this generates carbon monoxide (CO). This CO will react with water and produce hydrogen (water gas shift reaction). The produced hydrogen molecules plus added hydrogen in the injected fluid attack the unstable and unsaturated molecules of oil and produce lighter and saturated molecules by means of hydrogenation or hydrogenolysis.17 The reactions of generating hydrogen happen in a temperature range of 200−300 °C, and it can be promoted by catalysts. Finally, the heated oil drains into a producer by gravity force and solution gas drive. Figure 1 shows the workflow used in this study. It starts with developing a kinetic model based on the laboratory results and ends in an optimization of operation conditions. First, a kinetic model was developed and incorporated into the simulation model, based on the experimental results of Da Silva.4 Next, several simulation models were built to find an optimal injection strategy, which can help to obtain the highest oil production. Finally, a sensitivity analysis and optimization of injection conditions were performed to determine which proportion of steam and hydrogen is the best to produce the highest oil recovery factor while injecting the lowest steam and hydrogen amount for the study case. It is concluded that there is a significant increase in oil production and much less steam is needed in

3. KINETIC MODEL OF HYDROPROCESSING ATHABASCA VACUUM RESIDUES Many experiments were done in the laboratory and showed that the studied catalysts have potential to be used in in situ upgrading, and a kinetic model was constructed for these catalysts and implemented F


Article


Figure 9. Profiles of oil mass density (kg/m3).

The kinetic model proposed by Sanchez et al.15 consists of five lumped components, including residue, vacuum gas oil (VGO), distillates, naphtha, and gases, and ten reactions which convert residues into lighter products. Reactions 1−4 relate to the conversion of residues into VGO, distillates, naphtha, and gases, respectively. Reactions 5−7 represent VGO reactions with hydrogen to produce distillates, naphtha, and gases, respectively. Reactions 8 and 9 represent the conversion of distillates into naphtha and gases, respectively, and reaction 10 represents the conversion of naphtha into gases. However, the kinetic model developed for Athabasca vacuum residues has only six reactions including reactions 1, 2, 3, 4, 5, and 8. Table 2 shows the kinetic parameters for catalytic hydroprocessing of a vacuum residue. The activation energy of reactions 1−5 ranges

in the simulation models. The kinetic model used in all these simulations was taken from the study of Da Silva.4 This kinetic model was developed for a catalytic hydroprocessing of vacuum residues of an Athabasca reservoir, using catalysts and hydrogen at reservoir conditions. The catalysts used in these experiments consist of metal salts such as ammonium heptamolybdate, ammonium metatungstare, nikel acetate, and ammonium sulfide. Table 1 and Figure 3 show the lumped components for Athabasca bitumen based on the model suggested by Sanchez et al.15 The oil components were lumped into five pseudocomponents, and their oil mole fractions were calculated by using WINPROP.22 The kinetic parameters were regressed as proposed by the study of Da Silva.4 The model was validated in terms of deviation and accuracy. G


Article


Figure 10. Oil saturation after 7 years of production (Soi = 0.81).

from 43.2 to 146.6 kJ/mol, and the activation energy of reaction 8 is higher (about 362.7 kJ/mol). On the basis of the results of Da Silva’s experiments, reactions 7, 9, and 10, which produce gases from VGO, distillates, and naphtha, respectively, and reaction 6 can be ignored. In consequence, the residue reactions and the conversion of VGO into distillates are dominant. The conversion rates of a residue into VGO and VGO into distillates are of the same level. At low temperature, the production of naphtha only comes from residue reactions; however, at higher temperature, the conversion of distillates into naphtha becomes more significant.

the producer and the maximum bottom-hole pressure at 2656 kPa for the injector. A second constraint is a maximum surface liquid rate of 344 m3/d for the producer and a maximum water rate of 191 m3/d for the injector. Steam is injected at 210 °C with steam quality of 95%. The producing rate is monitored by adding minimum steam trap control of 10 °C subcool. As mentioned above, the conventional steam injection is first applied to generate a steam chamber in the reservoir. Thus, the simulation model is set to run one year of steam injection and then alternated to inject a steam, catalyst, and vacuum residue mixture, together with hydrogen (ST-ISUT) for the next 6 years. The maximum bottom-hole pressure and maximum surface total phase rate set for this injection slug are 2700 kPa and 6000 m3/d, respectively. The production obtained from this injection method is compared to that from the steam injection in terms of improving oil recovery and reducing steam requirement. The kinetic model includes 12 reactions. It consists of six reactions which represent the conversion of in situ oil components as described in the kinetic model section and six other reactions which are the same reactions but are for conversion of injected oil components. Therefore, we can track the front and the amount of the injected residue and its products during the injection process.

4. SAGD ST-ISUT INJECTION MODELING The reservoir modeled in this study is shallow, with top depth at 200 m. The reservoir’s and fluid’s properties are described in Tables 3 and 4. A simulation model was conducted with 40 × 10 × 30 grid cells. The grid cell sizes are 1 m in the I direction, 50 m in the J direction, and 1 m in the K direction. This model consists of two wells, including one producer at the bottom and one injector located 5 m above the producer (Figure 4). Both the producer and injector are operated by constraining the minimum bottom-hole pressure at 2164 kPa for H


Article


Figure 11. VR mole fraction maps (initial value = 0.5044).

5. COMPARISON OF INJECTION STRATEGIES Six study cases, numbered 1−6, as shown in Table 5, have been carried out to compare the advantages of a ST-ISUT injection method. The results of simulation will reveal the best injection strategy for the studied reservoir. For all runs, the injectors work at 210 °C for steam injection and 350 °C for ISUT/ST-ISUT injection. The constraints of steam injection are all similar to the base case described in the injection modeling section. Figure 5 shows the cumulative oil production curves of the six cases. The results of simulation show that the coinjection of steam and ISUT (case 2) has the highest oil production compared to other cases, while a conventional steam injection (SAGD, case 1) and case 3 have the lowest oil production (Figure 5a). Although the total cumulative oil production of

case 3 is equal to the one of case 1, its recovery factor is much lower (Figure 5b) because it produces much less in situ oil (Figure 5c). Figure 5d shows that the injected VR and the products from it are reproduced as much as the injection amount (Figure 6b, 83 925 m3) and this production is two and half times higher than the one in case 2, which applies the injection of ST-ISUT. These results are confirmed again by the 3D results; the steam chamber of case 3 is smaller than the one of case 1. The injection fluid of case 3 without steam only develops a heated region surrounding the injector but is not able to expand that heated area as large as in cases 1, 2, and 4 (Figure 7). The other runs (cases 4−6) are alternating injections of steam and ST-ISUT with three different cycles including 6 months, 1 year, and 2 years. They are identical in terms of the oil recovery I


Article


Figure 12. VGO mole fraction maps (initial value = 0.3228).

factor (Figure 5b). They are different only in terms of faster recovery with a longer cycle of injection. Case 6 with a 2 year cycle has faster recovery than cases 4 and 5 in the first three years of injection (Figure 5b). These three injection strategies have production and oil recovery factors lower than those of case 2, continuous injection of ST-ISUT, but they are higher than those of case 1, conventional steam injection, and case 3, only ISUT injection. In consequence, the results of simulation show that the ST-ISUT fluid does promote reactions of converting heavy oil components into lighter oil components in a heavy oil reservoir and the steam will reduce the viscosity of bitumen and expand the heated chamber leading to production of more movable oil toward the producer.

To investigate the role of steam, catalyst, hydrogen, and VR in ISUT and ST-ISUT injection, the results of four simulation runs (cases 1−4) are chosen to analyze their effect on a reduction in the oil viscosity, oil mass density, and residual oil, as shown in Figures 8−10. Figure 8 presents the profiles of the oil viscosity at the end of simulation. For case 1, steam injection can reduce the viscosity of bitumen to 968 cP. Moreover, it has a greater reduction if steam is combined with catalyst, hydrogen, and VR (cases 2−4), leading to the oil viscosity lower than 753 cP. Conversely, there is not much reduction if the ISUT is injected without steam (case 3). There is a big area which has a viscosity as high as the viscosity of the original bitumen (577 416 cP) because the injection fluid does not reach these parts of the J


Article


Figure 13. Distillate mole fraction maps (initial value = 0.1311).

except the region around the injector and the right bottom part of the reservoir, while the oil mass density of case 1 is still high above 900 kg/m3. From these results, catalysts and hydrogen induce chemical reactions, which convert heavy oil components into lighter oil components leading to a reduction in the final oil mass density. This also indicates that the ISUT fluid containing catalysts and hydrogen must be injected together with steam to achieve their advantages, otherwise the injected fluid cannot penetrate deeply into the reservoir; however, chemical reactions do occur to generate lighter oil components, but a lot of immovable bitumen/heavy oil still remains (case 3, Figures 8 and 9). With reduced oil viscosity and density and increased size of the steam chamber, the oil saturation in cases 1, 2, and 4 is decreased by half of the original value from 0.81 to 0.4, as seen in Figure 10.

reservoir. These viscosity profiles have shown the necessity of steam in all injection methods for bitumen/heavy oil reservoirs, and more benefits can be obtained when combining steam with the ISUT method. Figure 9 presents the oil mass density maps at the end of simulation for those four runs. The oil mass density of the original bitumen before applying any injections is 1011 kg/m3, and then it reduces gradually in a region around the injector and at the top of the formation while injecting steam in stage 1. As soon as injection of catalysts and hydrogen into the reservoir (cases 2 and 4) starts, the oil mass density is reduced further with a wider region and is much lower than the density in case 1, which injects only steam. At the end of simulation, the oil mass density in cases 2 and 4 is less than 880 kg/m3 in the whole reservoir K


Article


Figure 14. Naphtha mole fraction maps (initial value = 0.0416).

Case 3 shows high oil saturation in the whole reservoir because of injecting the ISUT fluid into the reservoir without steam. In addition, the mole fraction maps of each in situ oil component are analyzed to investigate the roles of catalysts, VR, hydrogen, and steam in ST-ISUT injection, as presented in Figures 11−15. Figure 11 presents the distribution of the in situ VR mole fraction in the reservoir. For steam injection (case 1), the VR mole fraction is significantly increased within the steam chamber and marginally decreased along the boundary of the steam chamber. But it can decline to zero in cases of injecting catalysts and hydrogen (cases 2−4). This shows that the VR in bitumen is consumed in the presence of both catalysts and hydrogen. The VR component is converted into lighter oil components including VGO, naphtha, distillate, and gases,

as seen in Figures 12−15. In steam injection, the in situ VGO mole fraction reduces from the initial value of 0.3228 to zero around the injector and gradually increases up to 0.5 mole fraction in the other regions. However, with ST-ISUT injection (cases 2 and 4), the mole fraction of VGO in the middle part of the steam chamber increases significantly up to 0.97 mole fraction and is very small in the outer and top parts of the chamber (Figure 12) because it is converted to distillate according to the kinetic model (Figure 13). The naphtha mole fraction in cases 2 and 4 is higher than that in case 1 in some parts of the reservoir because of conversion of both VR and distillate (Figure 14). The mole fraction of gases, the last product of this kinetic model, is higher in case 2 compared to case 1, because of the conversion of VR to gases in the presence of catalysts and hydrogen (Figure 15). L


Article


Figure 15. Gases mole fraction maps (initial value = 1.01 × 10−7; white cells show gas mole fraction is less than 1.01 × 10−7).

In summary, the results of simulations have confirmed that the catalysts have a strong effect in reducing the oil viscosity and increasing the oil production, when injected with hydrogen and VR into steam injection in bitumen/heavy oil reservoirs. The mechanisms in this process include thermal expansion, viscosity reduction, and conversion of heavy oil components into lighter oil components. It is consistent with the results of our experiments in the laboratory. At the beginning (the steam injection stage), thermal expansion promotes the flowing force and heats the bitumen leading to a reduction in oil viscosity around injectors and producers. The oil flows into the producers by the mechanisms of solution gas drive and gravity drainage. Next, when catalysts and hydrogen in ST-ISUT injection are introduced into the reservoir at higher temperature, the reactions

(hydrogenation and hydrocracking) occur, which generate gases and light oil components. Then these light hydrocarbons play a role as diluents in the heavy oil leading to further reduction in the oil viscosity, increasing oil mobility, and finally increasing oil production.

6. ANALYSIS OF ST-ISUT PERFORMANCE In this section, a sensitivity analysis is performed to determine the influences of injectors’ and producers’ parameters to two objective functions in ST-ISUT injection such as recovery factor (RF) and steam-oil ratio (SOR). The sensitivity analysis consists of eight parameters, and their ranges are shown in Table 6. The results of the sensitivity analysis are shown in Figure 16. These results were obtained using the Morris method, which is provided in CMOST.22 M


Article


the optimization parameters. From the results of our laboratory experiments, the effective temperature for hydrocracking reactions in the presence of catalysts must be above 300 °C. It is also the conclusion of Shuwa et al.;19 they stated that the catalyst could not be activated when the injection was performed at temperature lower than 280 °C; they even got worse results, a lower oil recovery factor. Therefore, the uncertain range of temperature in the optimization runs is varied from 300 to 360 °C. Other parameters are considered in the optimization including injection fluid composition (i.e., amount of steam, a ratio of hydrogen per vacuum residue as well as their volumes) and operation conditions (i.e., injector’s bottom-hole pressure and injection rate, steam quality, producer’s bottom-hole pressure and production rate). The main purpose of the optimization runs is to find the combination of operation conditions that can achieve the highest oil production with the minimum steam requirements. Therefore, a multiple objective function optimization method is applied in this study. The first objective function is to maximize in situ oil production, and the second objective function is to minimize the steam−oil ratio. Then the optimal solution of ST-ISUT injection is compared to the optimal solution of conventional steam injection to get an understanding of the benefits of this new injection method. Thus, there are two optimization runs, one for ST-ISUT injection and one for SAGD. The optimization parameters and their uncertain ranges for those two runs are shown in Table 6. Figure 17 shows a Pareto front of the objective functions, which points out the optimal solutions of two targets: maximizing in situ oil production and minimizing the steam−oil ratio. In the optimization process for ST-ISUT injection, the ratio of hydrogen to vacuum residue is changed from 100 to 200 as recommended in laboratory studies together with changing water fraction, which presents an amount of steam in ST-ISUT injection. The water volume fraction varies from 0.5% to 10% of the total injection fluid volume. Therefore, the injection rate of each injected fluid such as water rate, hydrogen rate, and VR rate is calculated for each run. Considering the results of ST-ISUT optimization (Figure 17a), about 34.4% of the original oil in place (OOIP) can be recovered, with a very low SOR of 0.53 (solution A in Figure 17a); however, increasing SOR to 1.65 could increase the oil recovery factor (RF) to 92.1% (solution B in Figure 17a).

Table 6. Sensitivity and Optimization Parameters parameters H2/VR ratio water fraction fluid injection rate, Q (m3/d) water injection rate (m3/d) injection BHP (kPa) injection temp, C production BHP (kPa) production rate (m3/d) steam quality

uncertain ranges for ST-ISUT injection

uncertain ranges for SAGD

100−200 0.005−0.1 4000−6500

− − −

−

20−500

2000−4000 300−360 2000−2400 300−550 0.7−0.95

2000−4000 170−240 2000−2400 300−550 0.7−0.95

The Morris results, which measure the mean and standard deviations of an objective function, are analyzed to rank the sensitive parameters in order of importance. A mean presents an assessment of the overall influence of a parameter on the objective function, and a standard deviation presents the ensemble of the parameters’ effects. A high mean indicates a factor with an important overall influence on the objective function, and a high standard deviation indicates that either the parameter is interacting with other parameters or the parameter has strong nonlinear effects on the objective function. The Morris chart (Figure 16) indicates that INJ_BHP, with the highest values of the mean and standard deviations, is the most important parameter impacting the two objective functions, followed by the water fraction. The amount of water (steam) tends to play a more important role in RF than in SOR. At the same time, these two objective functions seem relatively sensitive to PRO_BHP, injection temperature, production rate, and steam quality. The ratio of H2/VR has neither an interaction effect nor a main effect on RF, but it is a main effect on SOR.

7. OPTIMIZATION OF ST-ISUT INJECTION This section presents the results of optimization for ST-ISUT injection. It is clearly shown in the experiments that temperature contributes in the thermal expansion during the injection process. Increasing temperature increases the thermal effect and encourages the performance of catalysts, leading to an increase in oil recovery. In consequence, temperature is chosen as one of

Figure 16. Sensitivity analysis results. N


Article


Figure 17. Pareto front of two objective functions: SOR vs RF (red points are optimal solutions; solutions A, B, C, and D are selected).

Figure 18. Oil viscosity profiles of optimal solutions.

This value of SOR is still smaller than the essential value to be economic in SAGD injection (SOR ≥ 2.7, solution C in Figure 17b).

In general, RF in SAGD strongly depends on the amount of steam. Figure 17b shows a trend of RF versus SOR in SAGD. O


Article


Figure 19. Comparison of oil recovery factors between SAGD optimal case and ST-ISUT optimal case.

Figure 20. Profiles of oil mass density (kg/m3) of optimal solutions.

SAGD injection by generating lighter oil components in the presence of catalysts and hydrogen. This also leads to a lower requirement of steam and reduces the need of solvents at the surface transportation and upgrading processes.

The highest RF achieved in SAGD is about 59.24% with SOR equal to 3.2 (solution D in Figure 17b). However, applying ST-ISUT injection can help produce an extra 32.87% oil, with a nearly half lower SOR (1.65). Figure 18 presents a comparison of the oil viscosity profile between the optimal SAGD injection and the optimal ST-ISUT injection. Again, the ST-ISUT injection can reduce the oil viscosity better over a wider region than in SAGD injection. After just 1 year of injection, the oil RF of ST-ISUT injection increases to almost double the value of SAGD injection (Figure 19). It can be seen that the ST-ISUT injection pushes more oil to the producers from the first month of injection, and the incremental RF steeply rises to a peak around two and half years of injection and then falls over the subsequent years. From Figure 18, after 3 years of injection, oil in the ST-ISUT injection case is able to flow in the whole reservoir, causing an increase in oil production while one-fourth of the reservoir still has unmovable oil in the SAGD case. A reduction in the oil mass density in ST-ISUT injection is another advantage of this new technology. As seen in Figure 20, ST-ISUT injection can reduce the oil mass density better than

8. SUMMARY The following points enumerate specific conclusions that can be drawn from this study: • ST-ISUT injection is a promising method for improving oil recovery compared to a conventional steam injection method. • The incremental oil production comes from the superior effectiveness in decreasing the viscosity and mass density of heavy oil. • The coinjected steam injection plays an important role in achieving the better performance of ISUT. • For the synthetic simulation model, ST-ISUT injection can increase oil recovery by 35.81% and reduces the SOR up to 50% in comparison with the conventional steam injection. P


Article


■

• Simulation results indicate that a combination of catalysts, hydrogen, and vacuum residue helps to improve the quality of the produced oil.

(14) Pereira-Almao, P.; Chen, Z.; Maini, B.; Scott, C. E. In situ upgrading via hot fluid injection. Can. Patent 2,810,022, 2014. (15) Sanchez, S.; Rodriguez, M. A.; Ancheyta, J. Kinetic model for moderate hydrocracking of heavy oils. Ind. Eng. Chem. Res. 2005, 44, 9409−9413. (16) Scott, C. E.; Pereira-Almao, P. Catalysis for heavy oils and bitumen upgrading-review. Cur. Top. Catal. 2014, 11, 1−23. (17) Hamedi Shokrlu, Y.; Babadagli, T. In-situ upgrading of heavy oil/ bitumen during steam injection by use of metal nanoparticles: a study on in-situ catalysis and catalyst transportation. J. SPE Res. Eval. Eng. 2013, 16, 333−344. (18) Hamedi Shokrlu, Y.; Babadagli, T. Kinetics of the in-situ upgrading of heavy oil by nickel nanoparticle catalysts and its effect on cyclic-steam-stimulation recovery factor. J. SPE Res. Eval. Eng. 2014, 17, 355−364. (19) Shuwa, S. M.; Al-Hajri, R. S.; Mohsenzadeh, A.; Al-Waheibi, Y. M.; Jibril, B. Y. Heavy crude oil recovery enhancement and in-situ upgrading during steam injection using Ni-Co-Mo dispersed catalyst. In SPE EOR Conference at Oil and Gas West Asia, March 21−23, 2016, Muscat, Oman; Society of Petroleum Engineers: Richardson, TX, 2016; SPE 179766-MS. (20) Weissman, J. G.; Kessler, R. V.; Sawicki, R. A.; Belgrave, J. D. M.; Laureshen, C. J.; Mehta, S. A.; Moore, R. G.; Ursenbach, M. G. Downhole catalytic upgrading of heavy crude oil. Energy Fuels 1996, 10, 883− 889. (21) Zhang, Z.; Barrufet, M.; Lane, R.; Mamora, D. Experimental study of in-situ upgrading for heavy oil using hydrogen donors and catalyst under steam injection condition. In SPE Heavy Oil Conference Canada, June 12−14, 2012, Calgary, Alberta, Canada; Society of Petroleum Engineers: Richardson, TX, 2012; SPE 157981-MS. (22) CMG software. Computer Modeling Group Ltd.: Calgary, Alberta, Canada.

AUTHOR INFORMATION

Corresponding Author

*Tel: +1 4039268056. E-mail: [email protected]. ORCID

Ngoc Nguyen: 0000-0003-3490-1598 Notes

The authors declare no competing financial interest.

■

ACKNOWLEDGMENTS The authors thank the CMOST research team of the Computer Modelling Group Ltd. for many helpful discussions. This work is partly supported by NSERC/AIEES/Foundation CMG and AITF Chairs.

■

REFERENCES

(1) Abu, I. I.; Moore, R. G.; Mehta, S. A.; Ursenbach, M. G.; Mallory, D. G.; Pereira-Almao, P.; Carboganani-Ortega, L. Upgrading of athabasca bitumen using supported catalyst in conjunction with in-situ combustion. J. Can. Pet. Technol. 2015, 54, 220−232. (2) Abu, I. I.; Moore, R. G.; Mehta, S. A.; Ursenbach, M. G.; Mallory, D. G.; Pereira-Almao, P.; Scott, C. E.; Carbognani-Ortega, L. Supported catalyst regeneration and reuse for upgrading of athabasca bitumen in conjunction with in-situ combustion. J. Can. Pet. Technol. 2015, 54, 372−386. (3) Cavallaro, A. N.; Galliano, G. R.; Moore, R. G.; Mehta, S. A.; Ursenbach, M. G.; Zalewski, E.; Pereira-Almao, P. In situ upgrading of lancanello heavy oil using in situ combustion and downhole catalyst bed. J. Can. Pet. Technol. 2008, 47, 23−31. (4) Da Silva, F. J. Kinetic Modeling of Catalytic in situ Upgrading for Athabasca, Deaspalting Pitch and Vacuum Residue. Master Thesis, University of Calgary, Calgary, Alberta, 2014 (5) Desouky, S.; Al-sabagh, A.; Betiha, M.; Badawi, A.; Ghanem, A.; Khalil, S. Catalytic aquathermalysis of egyptian heavy crude oil. Inter. J. Chem. 2013, 7, 286−291. (6) Galarraga, C. E.; Pereira-Almao, P. Hydrocracking of althabasca bitumen using submicronic multimetallic catalysts at near in-reservoir conditions. Energy Fuels 2010, 24, 2383−2389. (7) Galarraga, C. E.; Scott, C.; Loria, H.; Pereira-Almao, P. Kinetic models for upgrading athabasca bitumen using unsupported NiWMo catalysts at low severity conditions. Ind. Eng. Chem. Res. 2012, 51, 140− 146. (8) Hovsepian, C. N.; Ortega, L. C.; Pereira-Almao, P. Laboratory twodimensional experimental simulation of catalytic in situ upgrading. Energy Fuels 2016, 30, 3652−3659. (9) Jiang, S.; Liu, X.; Liu, Y.; Zhong, L. In-situ upgrading heavy oil by aquathermolytic treatment under steam injection conditions. In 2005 SPE International Symposium on Oilfield Chemistry, February 2−4, 2005, Houston, TX; Society of Petroleum Engineers: Richardson, TX, 2005; SPE 91973-MS. (10) Loria, H.; Trujillo-Ferrer, G.; Sosa-Stull, C.; Pereira-Almao, P. Kinetic modelling of bitumen hydroprocessing at in-reservoir conditions employing ultradispersed catalysts. Energy Fuels 2011, 25, 1364−1372. (11) Maity, S. K.; Ancheyta, J.; Marroquín, G. Catalytic aquathermolysis used for viscosity reduction of heavy crude oil: a review. Energy Fuels 2010, 24, 2809−2816. (12) Moore, R. G.; Laureshen, C. J.; Mehta, S. A.; Ursenbach, M. G.; Belgrave, J. D. M.; Weissman, J. G.; Kessler, R. V. A down-hole catalytic upgrading process for heavy oil using in situ combustion. J. Can. Pet. Technol. 1999, 38, 72−96. (13) Pereira-Almao, P. In situ upgrading of bitumen and heavy oils via nanocatalysis. Can. J. Chem. Eng. 2012, 90, 320−329. Q


Heavy

Recommend Documents