Estimad@ Compañer@, en mi escrito anterior, Parte 84, recomendé, entre otras cosas, el uso en el campo de las tecnologías THAI(Toe to Heel Air Injection) y THAI-CAPRI(Toe to Heel Air Injection - CAtalytic upgrading PRocess In-situ). Por eso, voy a presentarle lo que se ha hecho experimentalmente con estas tecnologías. En primer lugar, lo novedoso de las mismas hará levantar las cejas a más de uno, sobre todo a los escépticos y que quieren que las cosas sigan haciéndose como hasta ahora; en segundo lugar, mi reflexión sobre el hecho indiscutible de que la mayoría de los adelantos científicos e industriales primero funcionan en el computador y no es distinto con estas tecnologías; en tercer lugar los beneficios tanto operacionales como económicos en comparación con otras tecnologías térmicas de recuperación de Bitumen, de petróleo pesado y petróleo extrapesado; en cuarto lugar recomendaciones sobre los beneficios de las tecnologías; en quinto lugar espero que, a través de Ustedes, llegue este mensaje a SUPERBIGOTE que, creo, es el único que puede innovar en la Industria de los Hidrocarburos haciendo que estas tecnologías se apliquen en Venezuela. Si Superbigote no interviene va a ser muy difícil explotar las grandes reservas de petróleo de La Faja Petrolífera del Orinoco Hugo Chávez Frías y, en sexto lugar, un anexo de un artículo, en inglés, que no solo detalla los avances de THAI y THAI-CAPRI sino que, en su bibliografía, abundan artículos hechos por diferentes autores de diferentes partes del mundo que para el interesado lo lleva desde los primeros ensayos desde hace más de 15 años.

No faltarán quienes digan que como son tecnologías nuevas y no probadas ni técnicamente ni financieramente, no es bueno arriesgarse porque se corre mucho riesgo. Quiero hacerle unas cuantas preguntas sobre los experimentos que se hacen no solo en la Industria de los Hidrocarburos, sino en otras disciplinas:

1. ¿Dónde vuelan, por primera vez, los aviones? Si, vuelan en los modelos de diseño y funcionamiento en programas computarizados. Hace mucho tiempo que ya no se hacen diseño en papel de los nuevos aviones, todo se hace en computadoras.
2. ¿Dónde se diseñan y prueban, por primera vez, las moléculas de nuevos productos farmacéuticos como las vacunas para el coronavirus? Si, en modelos computarizados. Pero no solo eso, sino que todos estos procesos se basan en NANOTECNOLOGÍAS, es decir, se trabaja en el mundo atómico y sub atómico. Puedo, seguir enumerando más productos que se elaboran, primero, en modelos computarizados.
3. El uso de los modelos computarizados tampoco empiezan con THAI Y THAI-CAPRI, desde hace años, en el mundo petrolero, también, se han estado usando los modelos computarizados. Es bastante común que un Balance de Materiales y modelos de comportamiento de yacimientos de hidrocarburos se hace con modelos computarizados. Sería imposible hacerlo a mano o con una calculadora. De la misma manera los modelos de caracterización de yacimientos, también, desde hace mucho tiempo, se hacen con modelos computarizados.

¿Por qué hago las referencias anteriores? Porque tanto los aviones, como las moléculas de nuevos fármacos y los modelos de yacimientos de hidrocarburos primero funcionan en el computador y después, con toda seguridad, funcionan en el mundo real.

De la misma manera, pasa con todos los modelos computarizados y experimentales en el laboratorio que se han desarrollado para probar las tecnologías THAI Y THAI-CAPRI.

Ojalá, algunos de Ustedes tengan la oportunidad de adentrarse, un poco mas, en los beneficios de estas tecnologías, que mas adelante enumeraré y las más de 40 referencias bibliográficas que encontrarán en el artículo que anexaré a este artículo, y puedan llegar a presentarlos a SUPERBIGOTE. Sin duda, si se quiere se puede. Puesto de otra manera, espero que algunos de Ustedes se "enamoren" de estas tecnologías.

De mi parte, seguiré usando el mismo canal que he estado usando para la publicación de mis más de 100 artículos relacionados con la Industria de Hidrocarburos de Venezuela esperando, también, que le llegue a SUPERBIGOTE.

ALGUNAS RECOMENDACIONES Y BENEFICIOS DE LAS TECNOLOGÍAS THAI Y THAI-CAPRI

1. En el laboratorio se ha logrado el mejoramiento del BITUMEN de las Oil Sands de Canadá de 7 grados API a un petróleos mejorado entre 17,9 y 24 grados API dependiendo de las presiones con las que se realice la inyección de aire. Esto mismo pasaría con el petróleo extrapesado de La Faja.

Estos resultados harían innecesarios dos cosas: una, la construcción de mejoradores adicionales y dos, la dilución de los petróleos producidos para su transporte y comercialización de las mezclas resultantes.

1. Eliminación de azufre, nitrógeno, metales pesados, etc, lo que hace más comercializable el petróleo mejorado obtenido.
2. Disminución, en gran medida, el uso de agua dulce. Esto permite el mantenimiento casi en condiciones inalterables los acuíferos presentes en los estratos superiores, en el caso de Venezuela, donde se almacena el petróleo extrapesado de La Faja. Sabemos que otros métodos de producción de Bitúmenes y petróleos extrapesados como la inyección de vapor requiere del uso de grandes cantidades de agua dulce, poniendo, por eso, en peligro el mantenimiento de los acuíferos tan necesarios para consumo humano y para la producción de alimentos con la agricultura.
3. Eliminación de subproductos como el coque y el azufre, productos de difícil colocación en el mercado; además de generar problemas ambientales por las grandes acumulaciones como se pueden ver en Jose, estado Anzoátegui.
4. Poca o ninguna necesidad de usar gas natural, ya que no se requiere en el proceso de combustión. No así los otros métodos que se usan para producir petróleos extrapesados.
5. Factores de recobro del petróleo, originalmente en sitio, en el orden del 85 por ciento a diferencia con el método, actualmente, usado en Venezuela que está en el orden del 10 por ciento.
6. Disminución de las emisiones de gases de efecto invernadero ya que elimina estos en la producción de petróleos extrapesado así como los que se generan, también, en los procesos de mejoramiento.
7. El gasto de energía en el uso de THAI Y THAI-CAPRI es infinitamente menor a lo que se gasta con los otros métodos térmicos que consumen casi la mitad de la energía que se obtiene del barril final en la producción del mismo.
8. A diferencia de otros métodos térmicos que requieren altos espesores de lo estaros petrolíferos, esta tecnología no tiene limitación en espesores. Recalco que entre 20 y 30 por ciento de las reservas de La Faja están contenidos en arenas con espesores de menos de 30 pies.
9. Es probable que el uso de estas tecnologías estén protegidas por patentes de sus creadores. Sin embargo, eso no debe ser obstáculo para que el estado venezolano negocie con sus propietarios y lograr acuerdos en los que ambas partes ganen.
10. La infraestructura para la aplicación de la tecnología tanto en la superficie como en los pozos está disponible, ya sean los compresores, tuberías de los pozos y el aire, el cual es gratis y ciertas combinaciones de catalizadores con algún tipo de patente propietaria. Pero me atrevo a asegurar que los componentes de los catalizadores bien podrían estar disponibles en Venezuela.
11. Sin duda los costos de producción por barril del petróleo mejorado en el yacimiento bajarán significativamente comparado con otros métodos.
    1. Se eliminan los costos asociados al Diluyente ya que no solo NO se comprará ni se pagará por su transporte desde el exterior sino que no se incurrirá en los costos asociados a su manejo dentro del país y su transporte e infraestructura en los pozos.
    2. No habrá costos asociados a la generación de vapor de alta calidad en caso que se decidiera usar algún otro método térmico de recuperación.
    3. No se usará gas en el proceso que, por el contrario, se requiere en otros métodos térmicos.
    4. Se eliminan no solo la inversión en nuevos mejoradores cuya exigencia de capital es enorme (entre 20 y 30 mil millones de dólares por mejorador) así como los costos de su mantenimiento. Al mismo tiempo se eliminarían los costos de mejoramiento por barril.
    5. No habrá costos de manejo de subproductos como coque, metales pesados, nitrógeno, azufre, etc. ya que estos se quedarán en el subsuelo.
12. Para asociarnos, además de los creadores de las tecnologías, debemos hacerlo para la aplicación de las mismas con nuestros, digo Yo, dos socios estratégicos mas importantes, como son Rusia y China, cuyos acuerdos, recomiendo, que se haga y de gobierno a gobierno. Aquí Superbigote tiene que hablar nada mas y nada menos que con Xi Jinping y Vladimir Putin.
13. Apreciado Lector, espero que "se le haya hecho agua la boca" para apoyar e impulsar el uso de las tecnologías THAI y su variante THAI-CAPRI. Si ese fuera el caso, contribuirán a que Superbigote autorice el uso, en Venezuela, de esas tecnologías.
14. Debemos olvidarnos de esas compañiitas de maletín que salen por ahí y que por recomendación de alguien se le han otorgado algunos contratos, cuyos resultados dejan mucho que desear.
15. Para nadie es un secreto que tenemos algunas puertas cerradas para la explotación de las grandes reservas de petróleo de La Faja que ya las he señalado en otros de mis escritos. Así que con THAI y THAI-CAPRI se abre una Gran Puerta de oportunidad no solo para producir nuestro petróleo extrapesado, sino que le daríamos un "portazo" a todas las trabas que se están oponiendo a que Venezuela siga siendo un país petrolero por muchos años más.
16. No me extrañaría que el Presidente haya basado sus comentarios de no depender más del petróleo y que estamos en vías de una economía posrentística influenciado por gente de PDVSA que no le encuentra salida eficiente y moderna a la explotación de La Faja. Soy de la idea de que se le debe dar la importancia que tiene cada sector de nuestra economía, pero eso no debe significar que se deje a un lado o se le rebaje la importancia que tiene y debe seguir teniendo la Industria de los Hidrocarburos de Venezuela. Como SUPERBIGOTE tiene más poderes que el Presidente, tengo mis esperanzas puestas en Él.

Si vemos los ejemplos de Canadá, Rusia, China. Irán, Arabia Saudita, etc. Tienen una industria petrolera poderosa que provee recursos importantes a sus respectivas economías y, al mismo tiempo, no han dejado de desarrollar otras áreas de su economía.

Así que, amigo lector, que no se apodere de Usted el sentimiento de derrota de nuestra Industria de Hidrocarburos. Sigamos echando pa’lante.

El contenido del artículo anexo, es solo una muestra de los avances logrados con las tecnologías THAI y THAI-CAPRI y solo es uno de las decenas de artículos y tesis de grado a nivel de master y PhD que demuestran con claridad los orígenes y estado actual de esas tecnologías y que están disponibles en la Internet con solo "buscar en google" "THAI y THAI-CAPRI HEAVY OIL UPGRADING".

Espero que, algunos de Ustedes, así como se han enamorado de otras tecnologías, se enamoren del THAI y THAI-CAPRI y pasen a la historia como los venezolanos que implementaron la tecnología que ayudó a la explotación mas eficiente de los 250 mil millones de barriles de reservas probadas de petróleo de La Faja Petrolífera del Orinoco Hugo Chávez.

Finalmente, he enviado este artículo a 30 petroleros, incluido Usted, que son los que tengo en mi lista de distribución. Si Usted tiene su propia lista de petroleros, le agradezco que le haga llegar esta información, para asi aumentar la cadena e incrementar la probabilidad que THAI y THAI-CAPRI, encuentren más "Apóstoles" que le puedan llegar a SUPERBIGOTE.

Le deseo una Feliz Navidad

Edmundo.Salazar@Yandex.com

Effect of operating pressure on the performance of THAI-CAPRI in situ combustion and in situ catalytic process for simultaneous thermal and catalytic upgrading of heavy oils and bitumen

Muhammad Rabiu Ado a, b, *, Malcolm Greaves c, Sean P. Rigby b

a Department of Chemical Engineering, College of Engineering, King Faisal University, P.O. Box: 380, Al-Ahsa, 31982, Saudi Arabia b Department of Chemical and Environmental Engineering, University of Nottingham, University Park, Nottingham, NG7 2RD, UK c Department of Chemical Engineering, University of Bath, Claverton Down, Bath, BA2 7AY, UK

a r t i c l e i n f o

Article history:

Received 1 August 2021

Received in revised form

24 September 2021

Accepted 25 September 2021 Available online xxx

Keywords:

Toe-to-heel air injection (THAI)

Enhanced oil recovery (EOR)

Reservoir simulation

In situ combustion (ISC)

Heavy oil/Bitumen/Tar sand

In situ catalytic upgrading

a b s t r a c t

According to the analysis of the 2020 estimates of the International Energy Agency (2020), the world will require up to 770 billion barrels of oil from now to 2040. However, based on the British Petroleum (BP) statistical review of world energy 2020, the world-wide total reserve of the conventional light oil is only 520.2 billion barrels as at the end of 2019. That implies that the remaining 249.8 billion barrels of oil urgently needed to ensure a smooth transition to a decarbonised global energy and economic systems is provided must come from unconventional oils (i.e. heavy oils and bitumen) reserves. But heavy oils and bitumen are very difficult to produce and the current commercial production technologies have poor efficiency and release large quantities of greenhouse gases. Therefore, these resources should ideally be upgraded and produced using technologies that have greener credentials. This is where the energy efficient, environmentally friendly, and self-sustaining THAI-CAPRI coupled in situ combustion and in situ catalytic upgrading process comes in. However, the novel THAI-CAPRI process is trialled only once at field and it has not gained wide recognition due to poor understanding of the optimal design parameters and procedures. Hence, this work reports the first ever results of investigations of the effect of operating pressure on the performance of the THAI-CAPRI process. Two experimental scale numerical models of the process based on Athabasca tar sand properties were run at pressures of 8000 kPa and 500 kPa respectively using CMG STARS. This study has shown that the higher the operating pressure, the larger the API gravity and the higher the cumulative volume of high-quality oil is produced (i.e. a 2300 cm3 of z24 oAPI oil produced at 8000 kPa versus the 2050 cm3 of z17.5 oAPI oil produced at 500 kPa). The study has further shown that despite presence of annular catalyst layer, the THAI-CAPRI process operates stably. However, it is found that a more stable and safer operation of the process can only be achieved at optimal pressure that should lie between 500 kPa and 8000 kPa, especially since at the lower pressure, should the process time be extended, it will not take long before oxygen breakthrough takes place. The simulations have shown in details that at higher pressures, the catalyst bed is easily and rapidly coked and thus the catalyst life will be very short especially during actual field reservoir operations. Since the oil drainage flux into the HP well at field-scale is different from that at laboratory-scale, and at field-scale, the combustion front does not propagate inside the HP well, it will be practically very challenging to regenerate or replace the coke-deactivated annular catalyst layer in actual reservoir operations. Therefore, it is concluded that during field operation designs, an optimum pressure must be selected such that a balance is obtained between the combustion front stability and the degree of catalytic upgrading, and between the catalyst life and its effectiveness.

© 2021 Chinese Petroleum Society. Publishing services provided by Elsevier B.V. on behalf of KeAi Communication Co. Ltd. This is an open access article under the CC BY license (http://creativecommons. org/licenses/by/4.0/).

1. Introduction

* Corresponding author. Department of Chemical Engineering, College of Engineering, King Faisal University, P.O. Box: 380, Al-Ahsa, 31982, Saudi Arabia. Based on the latest projections by the International Energy

E-mail address: mado@kfu.edu.sa (M.R. Ado).

https://doi.org/10.1016/j.ptlrs.2021.09.010

2096-2495/© 2021 Chinese Petroleum Society. Publishing services provided by Elsevier B.V. on behalf of KeAi Communication Co. Ltd. This is an open access article under the CC BY license (http://creativecommons.org/licenses/by/4.0/).

 

Please cite this article as: M.R. Ado, M. Greaves and S.P. Rigby, Effect of operating pressure on the performance of THAI-CAPRI in situ combustion and in situ catalytic process for simultaneous thermal and catalytic upgrading of heavy oils and bitumen, Petroleum Research, https://doi.org/

 

10.1016/j.ptlrs.2021.09.010

Fig. 1. Three-dimensional (3D) diagram of THAI-CAPRI laboratory-scale numerical model control volume with its wells configuration. The annular catalyst layer is shown by the

thick yellow lines.

Agency (IEA) (2020), the current world-wide energy policies are not in the neighbourhood of those required to achieve full decarbonisation of the global energy and economic systems by the year 2050. In fact, the estimates show that it is highly unlikely that that can be realised even by 2070. Furthermore, based on estimates from the IEA's predictions, if the 2020 corona virus pandemic crisis is brought under control by 2021, the world would need around 770 billion barrels of oil to cater for demand from now to the next two decades (i.e. to year 2040). This is also in order to satisfy the rising demand from the petrochemicals and transportation sectors which do not have any feasible alternatives. However, according to the BP statistical review of world energy 2020 (British Petroleum (BP), 2020), the current global proven reserves of both conventional and unconventional oils as of 2019 total to 1734 billion barrels. However, out of that, the conventional light oil contributes 30% (i.e. 520.2 billion barrels) only (Elahi et al., 2019; Guo et al., 2016; Liu et al., 2019). Putting these into perspective, the remaining 249.8 billion barrels of oil needed to satisfy the surging demand from now to 2040 must come from the unconventional oils (i.e. the heavy oils and bitumen). However, these large quantities of the virtually unexploited unconventional resources are very difficult to produce due to their inherently large content of asphaltic molecules and hence high viscosities which are more than 104 cP (Hein, 2017; Li et al., 2020; Zhang et al., 2019). As a result, upgrading and producing from heavy oils and bitumen reservoirs is highly energy intensive that is largely associated with release of high quantity of greenhouse gases, and is water-intensive which leads to wastewater treatment and disposal problems. However, the current climate change mitigation strategies require that these absolutely needed petroleum resources for smoother transition to a decarbonised global energy and economy must be exploited using technologies that are energy-efficient and environmentally friendly. Thermal enhanced oil recovery (EOR) processes, such as steam-based and in-situ-combustion-type processes, have the preceding qualities since the viscosity of heavy oils and bitumen decreases exponentially with increase in temperature. However, relatively speaking, the steam-based processes, such as Steam Flooding (SF), Cyclic Steam Stimulation (CSS) and Steam-Assisted Gravity Drainage (SAGD) etc., are shown to have limited applications as they work in only select few reservoirs. They can only be applied to relatively thick reservoirs, they suffer from considerable wellbore heat losses thereby consuming more steam to compensate for the thermal energy lost, they are water-intensive and thus generate large amount of wastewater, they are negatively affected by reservoir heterogeneities such as shale lenses and barriers, they only alter the physical properties of the hydrocarbon which are reversed when the initial condition is returned to, they do not provide substantial heavy-to-light-petroleum chemical-alterations upgrading within the reservoir, and they have very low recovery factors when compared with their in-situ-combustion-types counterparts (Gates, 2010; Gates and Larter, 2014; Shi et al., 2017; Wang et al., 2019; Zhao et al, 2013, 2014). Additionally, in some of the commercial operations, SAGD, which is the major steam-based process being currently applied, has been found to not be a net energy producer as it consumes more thermal energy than the chemical energy it produces (Gates and Larter, 2014). However, the in-situ-combustion-type processes, namely conventional In Situ Combustion (ISC) and Toe-to-Heel Air Injection (THAI), are shown to have none of the disadvantages of the steam-based processes. Furthermore, they provide appreciable heavy-to-light oil underground upgrading. But the ISC suffers from gravity segregation and hence excessive gas override, and delayed oil production as the mobilised partially upgraded oil has to travel over hundreds of meters before it reaches the vertical production well and get produced (Sharma et al., 2021; Turta et al., 2020; Wei et al., 2020). The THAI process on the other hand has none of the disadvantages of the ISC as it is a short-distance oil displacement process and according to laboratory studies, it has very high oil recovery factors of up to 85% of oil originally in place (OOIP) (Greaves et al,1999, 2008; Xia et al., 2005; Xia and Greaves, 2002, 2006). Furthermore, the THAI process has been studied through numerical simulations with aims of providing design and operation procedures as can be found in multiple articles (Ado, 2020a, 2020b, 2020c, 2020d, 2020e, 2021a, 2021b, 2021c; Rabiu Ado, 2017; Rabiu Ado et al., 2017). The THAI process uses horizontal well technology to produce partially upgraded oil as combustion is propagated from toe-to-heel of the well. Another advantage of the THAI process is the ease with which an annular layer of hydro-processing catalyst can be emplaced around the horizontal producer (HP) well to form a coupled process called THAI-CAPRI. The THAI-CAPRI involves in situ heat generation from combustion of the immobile, unproducible carbonaceous fraction of the oil in place (which is around 5e10% OOIP (Kovscek et al., 2013)) which is then utilised to mobilise and partially upgrade the remaining 90e95% producible oil via thermal cracking. The catalytic upgrading in the THAI-CAPRI process is realised when an annular layer of industrial hydro-processing catalyst, such as alumina-supported cobalt-oxide-molybdenum-oxide (CoMo/gAl2O3), alumina-supported zinc-oxide-copper-oxide (ZnCu/gAl2O3), etc., surrounding the HP well is contacted by hydrogen and thermally partially upgraded THAI-oil only. The removal of impurities such as sulphur, nitrogen, heavy metals, etc., during the operation of the THAI-CAPRI process leads to production of higher volume of higher-quality oil relative to that that can be obtained in the THAI process alone. Furthermore, the THAI-CAPRI process has the added advantages of being energy self-sufficient if waste heat is recovered to run utilities, locking the heavy oils and bitumen impurities permanently underground, providing higher-quality and easily transportable feed oil to refineries and thus minimising the need for surface upgrading facilities, being carbon-capture-ready for sequestration, and providing an environmentally friendly alternative means of achieving higher-value petroleum products. These have been demonstrated successfully at laboratory-scale by either using combustion tube or using 3D combustion cell (Abu et al., 2015; Cavallaro et al., 2008; Weissman et al., 1996; Xia and Greaves, 2001; Xia et al., 2002). However, no numerical simulation model either at laboratory-scale or field-scale was developed to investigate the upgrading mechanism given that numerical simulations of the THAI process alone has shown that the mobile oil zone (MOZ) where the catalytic upgrading is envisaged to be taking place has temperatures of less than 300 C (Greaves et al., 2012; Rabiu Ado et al., 2018; 2017). This is below what is required for the industrial hydro-treating catalysts, such as CoMo/g-Al2O3, ZnCu/gAl2O3, etc., to be effective and thus for catalytic upgrading to take place. Furthermore, one of the key parameters that will determine the degree of catalytic upgrading is operating pressure, and to the best of our knowledge, there is no study in the literature that has investigated it. Therefore, given the necessity for establishing process design procedures and optimal operating conditions, it is one of the aims of this work to shade light on the influencing parameters requiring full evaluations prior to field deployment of the THAI-CAPRI process. To achieve these, the Computer Modelling Group's (CMG's) commercial reservoir simulator, STARS, is used.

2. Models development

In this work, the Canadian Athabasca bitumen reservoir conditions and fluids properties are used. These are in accordance with previous validated laboratory-scale numerical models (Ado, 2020b; Rabiu Ado et al., 2017). The THAI-CAPRI model, which can be seen in Fig. 1, is of the same dimensions as that of the THAI experimental-scale numerical models reported in Greaves et al. (2012) and Rabiu Ado et al. (2018, 2017). It contains horizontal injector (HI) and horizontal producer (HP) wells arranged in a staggered line drive (SLD). In addition, the THAI-CAPRI model has an annular catalyst layer emplaced around the HP well as indicated by the thick yellow lines in Fig. 1. In the CMG STARS, the model is discretised into 30 in i direction 19 in j direction 9 in k direction grid blocks with the variable thickness in the latter two directions. Since the thickness of the combustion front is around 1 inch, to better capture it is full dynamics, each grid block is further refined into 3 sub-grid points in i direction. These make the total number of grid blocks, including those of the discretised wellbore which is invoked to account for the transient nature of the transport processes inside the HP well, to be 19,900.

2.1. Petro-physical parameters

The reservoir initial fluids saturations are made up of 85% oil, 15% water, and 0% gas. The reservoir initial temperature and porosity are 20 C and 34% respectively. These figures are similar to those used in the validated laboratory-scale numerical simulation models which can be found in Rabiu Ado et al. (2017) and Ado (2020b). The relative permeability curves are the same as those reported in previous work of Rabiu Ado et al. (2017) and consequently, are not repeated here.

2.2. Pressure-volume-temperature (PVT) data

In order to include the catalytic reactions in the numerical simulation model, a simulated distillation data for the THAI oil upgraded using CAPRI under nitrogen atmosphere and at process conditions of 425 C and 20 bar were used. Peng-Robinson Equation of State (PR-EOS) in Aspen HYSYS software was used to fit a calculated distillation curve so that the PVT data of two oil pseudocomponents (i.e. light upgraded oil (LUO) pseudo-component and heavy upgraded oil (HUO) pseudo-component) was obtained.

2.3. Kinetics scheme

In the CAPRI coupled to the THAI process (i.e. THAI-CAPRI process), catalytic reactions, in addition to the thermal cracking and combustion reactions, which are described in Abu et al. (2015) also take place. These catalytic reactions that take place in the presence of hydro-treating catalyst under sufficient temperature and pressure (e.g. 425 C & 20 bar), are mainly hydrodesulphurisation (HDS) and hydrodenitrogenation (HDN) reactions. They only, however, take place in the presence of the main co-reactant, i.e. the hydrogen (H2) which experimental studies showed to be generated during the operation of air injection in situ combustion enhanced heavy oil recovery process (Abu et al., 2015; Greaves et al., 2004; Hajdo et al., 1985). The generation of water vapour (H2O(g)) and carbon monoxide (CO(g)) from the combustion zone, the presence of hydrotreating catalyst and importantly that of gaseous hydrocarbons were observed to result in hydrogen generation via water-gas shift (WGS) and steam gasification (SG) reactions (Abu et al., 2015;

Cavallaro et al., 2008; Moore et al., 1999; Weissman, 1997; Weissman et al., 1996). The generalised forms of the WGS and SG reactions are:

WGS: CO þ H2O )/ CO2 þ H2

SG: CXHb þ 2xH2O / xCO2 þ (2x þ b/2)H2

However, the above reactions are not included in the numerical simulation model because of the unavailability of kinetics data which is derived from the THAI-CAPRI process. Instead, the hydrogen is injected together with the air. By varying the hydrogen-air ratio (HAR) from model to model, the effect of the concentration of the in situ generated hydrogen can be investigated. Therefore, this is parallel to the study carried out by Shah et al. (2011) in which hydrogen and flue gas mixture, and pure hydrogen were injected into a micro-reactor to respectively simulate the effect of combustion gases on the THAI-CAPRI process.

 

Fig. 2. 3D shape of combustion front based on oxygen mole fraction for (a) model CP1 and (b) model CP2 respectively, both at the end of 320 min of process operation time.

The thermal cracking and combustion reactions used in this study are based on the modified Greaves et al. (2012) kinetics scheme which is shown in Ado (2020b). Therefore, the HDS and HDN reactions are based on the Heavy and Light oil pseudocomponents making up the native Athabasca reservoir oil. For the catalytic reactions, the carbon-sulphur and carbon-nitrogen bonds are respectively cleaved, thereby resulting in the formation of new carbon-hydrogen bonds in either case. The substituted heteroatoms, namely sulphur and nitrogen, combine with the hydrogen to form hydrogen sulphide and ammonia respectively. The reaction orders of the HDN and HDS, for the Athabasca bitumen-derived heavy gas oil and with the respect to each oil pseudo-component are first and three-half respectively (Ferdous et al., 2006; Yui and Sanford, 1989). Since there are two oil pseudo-components, the catalytic reactions are represented by two balanced chemical reactions viz:

Catalytic hydrodesulphurisation and hydrodenitrogenation reactions:

Heavy oil þ5.7470 H2 / 3.4770 HUO þ0.2925 H2S þ 0.0945 NH3

Light oil þ1.6905 H2 / 1.3280 LUO þ0.0968 H2S þ 0.0055 NH3

Fig. 3. Produced oxygen mole fraction for models CP1 and CP2 at operating pressures of 8000 kPa and 500 kPa respectively.

 

The activation energy and frequency factor of the overall HDS and HDN reactions are taken from Ferdous et al. (2006). In each case, the same kinetics parameters are assigned to both the Heavy oil and Light oil pseudo-components. The justification being only overall kinetics parameters are available, and therefore, the stoichiometry of each reaction will determine the extent of heteroatom removal. However, it should be noted that the respective HDS and HDN reactions for the Heavy and Light oil pseudo-components were specified independently in the simulator.

In this study, the concept of activation temperature, first introduced by Coats (1983) to correct for the effect of field-scale grid blocks sizes, is used to account for the inadequacy of temperature around the mobile oil zone (MOZ). A minimum activation temperature, Ta, of 400 C was set into the model. That is, if the catalyst temperature in the MOZ is less than Ta, then the temperature dependent HDS and HDN reaction rates in that zone are respectively calculated using Ta. When the catalyst temperature is more than Ta, then the actual temperature is used to calculate the rates of the HDS and HDN reactions. That means, under this situation, the emplaced annular catalyst layer around the HP well is simulated as a sort of already heated porous cylindrical wall via which when mobilised oil flows, it becomes further upgraded through carbonnitrogen and carbon-sulphur bonds breakage and carbonhydrogen bonds formation. This is in accordance with the experimental studies by Shah et al. (2011). However, this method of activating the catalyst has the downside of considering the catalytic reactions to take place along the entire length of the HP well surrounded by the catalyst layer. As a result, the predicted degree of upgrading could be much more than that would have been achieved if the heating is localised to the region of the MOZ only. This might not necessarily be the case since neither of the two THAICAPRI experiments (Xia and Greaves, 2001; Xia et al., 2002) used an external heater to activate the catalyst despite the upgrading achieved by up to 6 oAPI points.

3. Results and discussions

To study how operating pressure affects the different parameters, such as catalyst coking, degree of upgrading, cumulative oil production, produced oxygen concentration, etc., critical to the successful operation of the THAI-CAPRI process, two numerical models CP1 and CP2 at operating pressures of 8000 kPa and 500 kPa respectively and having similar input parameters were simulated using the CMG STARS.

3.1. Shape of combustion front

The shape of the combustion front corresponds to that of oxygen mole fraction. The combustion reactions, therefore, take place at the leading edge where the concentration of oxygen drops to zero. Fig. 2a shows that throughout the combustion time, the oxygen did not reach the toe of the horizontal producer (HP) well, which was shown in Rabiu Ado et al. (2017) to be one of the causes of early start of oxygen production. This could be attributed to the high producer back pressure (i.e. 8000 kPa) compared to that used (i.e. 170 kPa) to simulate the THAI process in Rabiu Ado (2017). This is further supported when Fig. 2a and b are compared. In the latter, the combustion front has reached the toe of, and propagated along, the HP well, and as a result, oxygen production began 100 min after the start of gas (i.e. air & hydrogen) injection (Fig. 3). Initially, the concentration of the produced oxygen rose sharply, reaching a maximum value of 1.05 mol% at 165 min before dropping to 0.6 mol % at 195 min. Thereafter, it steadied out at 0.6 mol% for the rest of the combustion period. At the top of the cell (Fig. 2a), the combustion front has a wedge-like protrusion, with tendency to be parabolic if the process time is extended. The same observation can be made in model CP2 (Fig. 2b), which also has a wedge-like protrusion at the bottom of the cell and along the HP well. The bottom protrusion is longer than the top one, causing the combustion front to be backward leaning, which is a sign of instability. This can be attributed to the use of low operating pressure thereby causing intense drawdown into the HP well. This observation is similar to that reported experimentally by Liang et al. (2012) and also shown through numerical simulation by Rabiu Ado et al. (2017).

Fig. 4. Fuel availability along the vertical mid-plane and at the end of 320 min of process operation time for (a) model CP1 and (b) model CP2 respectively.

In model CP1, along the longitudinal axis of the HP well (i.e. laterally in the vertical middle plane of the reservoir), where the process experiences the most intense gravity drainage, the combustion front has a higher advance rate, especially at the top, compared to the other parts of the sandpack (Fig. 2a). The low residence time of the mobilised upgraded oil along the longitudinal axial direction of the HP well resulted in the deposition of low concentration of fuel at the top of the reservoir (Fig. 4a), which is then rapidly consumed and thus allowed the combustion front to advance at faster rate in that region. This was also partly due to the use of very large producer back pressure. In model CP1, the overall effect of the faster advancement of the combustion front along the longitudinal axial direction of the HP well and at the top of the combustion cell is the production of oxygen from the heel of the HP well (Figs. 2a and 3). Unlike in model CP2, the maximum concentration of the produced oxygen is, however, less than 0.3 mol%, indicating that the THAI-CAPRI process, when operated at high pressures which is the case in model CP1, operates stably as was shown experimentally (Xia and Greaves, 2001; Xia et al., 2002). It also shows that the process will continue to be run for a while before oxygen breakthrough takes place at which point it will no longer be economical and safe to continue the operation.

3.2. Fuel availability

 

Fig. 5. Porosity along the vertical mid-plane and at the end of 320 min of process operation time for (a) model CP1 and (b) model CP2 respectively.

 

The concentration of the fuel is not constant but varies with the location in the sandpack, which is similar to the observation made from studies of the experimental shape of coke profiles by Greaves et al. (2012). The reservoir operating pressure has considerable influence on the concentration of deposited fuel (Fig. 4). When the process was run at the pressure of 8000 kPa (i.e. model CP1, Fig. 4a), more than three quarters of the longitudinal length of the sandpack is covered by coke, with concentrations of 69e110 kg m3 surrounding the annular catalyst layer. This is also what stopped the combustion front from reaching the toe of the HP well as the large concentration of fuel slowed it is rate of advance vertically downward. Therefore, the coke deposited on the catalyst layer is not burned. On the contrary, the decrease in the operating pressure by a factor of 16 (i.e. model CP2, Fig. 4b) caused a considerable decrease in the fuel concentration ahead of the combustion front. In this case, the fuel availability ranges from 41 to 69 kg m3 and as a consequence, the combustion front propagated along the HP well, which was earlier described as one of the causes of early oxygen production. It can also be observed in model CP2 that the coke deposited on the pores of the catalyst is burned by the advancing combustion front propagating along the HP well. This implies that the catalyst can be regenerated through combustion as was reported experimentally. However, no further upgrading can be achieved with the regenerated catalyst as there is no oil behind the combustion front. This is in the case of these experimental-scale numerical models which is unlike for field-scale reservoirs where most of the mobilised partially upgraded oil enters the HP well via its toe (Ado, 2020e, 2021c). Ahead of the combustion front, and within the HP well and on the annular catalyst layer, the deposited coke concentration ranges from 14 kg m3 to 69 kg m3 (Fig. 4b).

Similarly, for model CP1, the coke deposited on the catalyst packing pores and within the HP well has concentrations ranging from 14 kg m3 to 97 kg m3. As a result, in all the two models, the catalyst packing porosity is decreased due to the deposition of coke onto the catalyst layer (Fig. 5).

3.3. Porosity and catalyst coking

 

Fig. 6. Temperature profile along the vertical mid-plane and at the end of 320 min of process operation time for (a) model CP1 and (b) model CP2 respectively.

 

The combustion cell was assigned uniform porosity of 34% whilst the catalyst packing porosity in either model is 45%. Fig. 5 shows that wherever coke is deposited in high concentration, the porosity has decreased. From the side view of Fig. 5a, model CP1, the packing porosity of the catalyst layer just above the HP well barely changed as it mostly ranged from 41 to 45%. This is because the coke deposited there has quite low concentrations (14e28 kg m3) that no pronounced observable change occurred. Additionally, just above the catalyst layer that is in turn above the HP well, the reservoir porosity has decreased substantially from the initial value of 34% to mostly 26%. This shows that the pathways via which the mobilised THAI-upgraded oil can reach the inner catalyst are partly blocked by the deposited coke on the surface thereby resulting in achieving lower catalytic upgrading compared to that achievable when the annular catalyst surface is cokeuncoated. These are very useful findings since in field-scale reservoir, highest oil drainage rates enter the HP well at its toe region which is different from the drainage pattern in the laboratory-scale control volume. The catalyst layer just below the HP well, however, has coke concentrations of 41e69 kg m3, and as a result, the catalyst packing porosity dropped to within a range of 19e26%. In model CP2, the coke in the thermal cracking zone, which is just behind the mobile oil zone (MOZ) as can be identified by the oil flux vectors superimposed on Fig. 5b, has porosity ranging from 24 to 33%. In the same zone, which is not swept by the combustion front, the catalyst packing porosity dropped from 45% to within a range of 37e41%. These, therefore, show that the catalytic reactions in the THAI-CAPRI process take place in the mobile oil zone (MOZ), which was previously envisaged to be the case by Greaves et al. (2012). However, future work should look at the catalytic reactions zone in field-scale reservoir since the mechanism of oil drainage into the HP well is scale-dependent (Ado, 2021c).

 

Fig. 7. API gravity (top) and Produced H2S mole fraction (bottom) as function of time for models CP1 and CP2.

 

Since the process will be operating at the reservoir pressure, which is around 2800 kPa in the Athabasca deposits, it means the severity of catalyst coking might not heavily affect the performance of the THAI-CAPRI process, most especially that the coke is deposited behind the MOZ as revealed by this laboratory-scale simulations studies. It should, however, be noted that this study did not add an external source of heat around the MOZ, which, if so, would have resulted in thermal cracking, and thus catalyst coking within the MOZ. Future simulation studies should look at how heating the catalyst layer around the MOZ would affect the effectiveness of the catalyst. This is critical considering the observations made by Shah et al. (2011) that operating the THAI-CAPRI process at 420 C and 2000 kPa is a compromise but it still resulted in substantial coke deposition onto the catalyst to the extent that the catalyst lifetime was quite short, only z 3.2 days. Research is being carried out to investigate the feasibility of using nano-catalysts to achieve in situ catalytic upgrading.

3.4. Temperature distribution

 

Fig. 8. Cumulative oil production (top) and oil production rate (bottom) as function of time for models CP1 and CP2.

 

The temperature distribution gives an indication of the extent of combustion reactions, heat transfer, and whether the process is operating in a low temperature oxidation (LTO) or high temperature oxidation (HTO) mode. Fig. 6 shows the temperature distribution along the vertical mid-plane where the HP well is located. In model CP1 (Fig. 6a), it is observed that the temperature in the mobile oil zone (MOZ), where the catalytic reactions take place, is 255 C. The same observation can be made in model CP2 (Fig. 6b), except that the temperature in the MOZ is 234 C. These observations are in accordance with the earlier results reported by Greaves et al. (2012) and Rabiu Ado et al. (2017). They showed that the use of activation temperature to represent the temperature of the catalytic reactions zone is necessary as long as there is no external source of heat used. Future studies should look at the use of external source of heat in order to better capture the full Physics of the whole process.

3.5. Degree of upgrading and cumulative oil production As seen previously, the use of high pressure, as is the case in model CP1, resulted in not only substantial thermal cracking, resulting in significant coke deposition, but also resulted in higher catalytic upgrading. This is because, the higher the pressure, the lower the concentration of the oil components going into vapour phase and hence the larger the liquid oil available to be thermal cracked and catalytically upgraded. Fig. 7 (top) shows that the API gravity in model CP1 (pressure of 8000 kPa) is on average 7 API points above that in model CP1 (pressure of 500 kPa). To further support the fact that higher catalytic upgrading is achieved in model CP1 compared to CP2, a plot of hydrogen sulphide (H2S) versus time is shown in Fig. 7 (bottom). In it, it can be seen that substantially more H2S is produced in model CP1 (which is approximately 15 times that of model CP2 during most of the combustion time), which is the product of the catalytic reactions.

Therefore, it follows that optimum pressure must be determined commensurate with catalyst life and catalytic upgrading. Since higher overall upgrading is realised with the model CP1, it follows that higher volume of oil should be cumulatively produced in model CP1 compared to CP2. This is shown by Fig. 8 (top). However, that was only the case prior to the increase in the gas flux. This counterintuitive behaviour can be explained by observing the shape of the oil production rate curves (Fig. 8 (bottom)). It can be seen that oil production in model CP1 began only after the start of gas injection (i.e. at the end of the pre-ignition heating cycle (PIHC)) whilst it began 12 min earlier in model CP2. This is what causes the cumulative oil production curve of CP2 to lie above that of CP1 prior to the increase in the flux. However, as the oil production rate in model CP1 is higher during most of the combustion period, the cumulative oil production curve of CP1 eventually became equal to that of CP2 between 165 and 190 min. Thereafter, curve CP1 lies above CP2 (Fig. 8 (top)) for the rest of the combustion time and at the end, more oil is produced in model CP1 (2300 cm3) compared to that in CP2 (2050 cm3). Similar conclusion as that with regard to the overall degree of upgrading can be drawn, which is that: an optimum pressure must be determined for economically justifiable incremental oil production compared to the gas injection pressure. 4. Conclusion

The first ever numerical simulations of effect of operating pressure on in situ catalytic upgrading of heavy oils and bitumen in conjunction with the in situ combustion are presented in this work. This work provides the starting point for future studies required for actual design of field operations. It will also serve as a guide for thoroughly interpreting experimental results. Two experimental scale numerical models of the THAI-CAPRI process based on Athabasca tar sand and reservoir properties were run at pressures of 8000 kPa and 500 kPa respectively using CMG STARS. The study has shown that the higher the operating pressure, the larger the API gravity and the higher the cumulative volume of higher-quality oil is produced (i.e. a 2300 cm3 of z24 oAPI oil produced at 8000 kPa versus the 2050 cm3 of z17.5 oAPI oil produced at 500 kPa). The study has further shown that despite presence of annular catalyst layer, the THAI-CAPRI process operates stably. However, it is found that a more stable and safer operation of the process can only be achieved at optimal pressure that should lie between 500 kPa and 8000 kPa especially since at the lower pressure, should the process time be extended, it will not take long before oxygen breakthrough takes place. The simulations have shown in details that at higher pressures, the catalyst bed is easily and rapidly coked and thus the catalyst life will be very short especially during actual field reservoir operations. Since the oil drainage flux into the HP well at fieldscale is different from that at laboratory-scale, and at the field-scale the combustion front does not propagate inside the HP well, it will be practically very challenging to regenerate or replace the cokedeactivated annular catalyst layer in actual reservoir operations. Therefore, it is concluded that during field operation designs, an optimum pressure must be selected such that a balance is obtained between the combustion front stability and the degree of catalytic upgrading and the catalyst life. As part of suggestions for future studies, it is concluded that a new study should investigate the feasibility of in situ catalyst regeneration at experimental-scale. Additionally, future work should investigate the zone at which the catalytic reactions take place in field-scale reservoir. Finally, this study has also shown that an external source of heating the catalyst bed must be provided in order to activate the bed to the required temperature for achieving catalytic upgrading. Therefore, a new study should conduct investigations of the feasibility of implementation of microwave, conductive, or resistive heating or all of them around the catalyst bed.

Declaration of competing interest

The authors declare that they have no known competing financial interests or personal relationships that could have appeared to influence the work reported in this paper.

Acknowledgements

The authors are grateful to the Computer Modelling Group (CMG) for supplying comprehensive reservoir simulator, STARS.

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