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The catalytic upgrading of heavy crude oil in-situ: the role of hydrogen: a review.


There are many energy sources, but high percentage of the energy used hitherto is petroleum based. The global demand for energy to meet our daily industrial and transportation needs is ever-growing at an average annual growth rate of 1.6% (OECD/IEA, 2005), while the supply of conventional light crude oil to sustain it is continuously declining. Alternative energy sources are yet to be developed to commercial stage, which means that petroleum would continue to dominate global energy supply for several decades. The estimated heavy crude oil reserve globally by the International Energy Agency (IEA) is about 6 trillion barrels, with major reserve found in Canada and Venezuela (OECD/IEA, 2005; Das and Butler, 1998). This shows that the reserve of heavy oil and bitumen/tar sands outweighs that of conventional light oil reserve which is about 1.02 trillion barrels (Hein, 2006); hence it has the potential of meeting global energy needs for decades.

The rising price of crude oil favours the exploitation of heavy oil and bitumen. Therefore, as the reserves of conventional light crude oil is depleting drastically in the face of the existence of abundance heavy crude and tar sands/bitumen worldwide, attention is shifted by the petroleum industry and academic researchers to the recovery and upgrading of heavy oil. Present research works have shown that implementing both recovery and upgrading down-hole in the heavy oil reservoir may result in substantial energy and greenhouse gas (GHG) emission benefits such as cost-effectiveness and environmentally friendly, instead of the current practice where energy is used both to exploit the reservoir as well as carry out surface upgrading which contribute to GHG emissions (Pereira-Almao, 2012).

Furthermore, heavy oil is hard to recover and challenging to process because the production and the market value of heavy crude oil is faced with many technical and commercial hurdles, due to their extremely high viscosity (greater than 1000 cP), low American Petroleum Institute (API) gravity (less than 20oAPI), poor mobility, high carbon to hydrogen atomic ratio (i.e., high tendency to coke), high asphaltenes, sulphur and heavy metal content (Weissman, et al., 1996; Mohammad, 2008). Additionally, the difficulty in transportation via pipeline as well as the inability of refineries to process heavy crude oil directly without firstly undergoing surface upgrading to meet refinery feedstock specifications. Compared to conventional light oil, primary recovery method that relies on the natural energy within the reservoir to push the oil up the production well is less effective for heavy crude recovery (Speight, 2009). This is because the technique is highly dependent on the fluidity of the oil. Under in situ reservoir conditions, heavy oil mobility is extremely low and bitumen viscosity may exceed 1 million centipoises, which indicate immobility. Therefore, most often primary and secondary recovery methods are bypassed, while enhanced oil recovery (EOR) technology is applied. In addition, cold heavy oil production (CHOP) techniques can recover about 10-20% original oil in place (OOIP), which implies that after cold production, there is still 80-95% oil to recover at an economic level (Miller, et al., 2002).

In the light of the above mentioned physico-chemical properties that make it difficult to exploit heavy oil energy resource, several other EOR methods such as vapour-assisted petroleum extraction (VAPEX), steam flooding, chemical flooding, SAGD, heating the reservoir by electrical means, etc. These methods rely on the reduction of the heavy oil viscosity via heating of the oil-bearing formation. The steam-based techniques have recovery factor in the range 20-50% OOIP, while THAI recovering factor is estimated 70-80% OOIP (Speight, 2009). The steam-based methods presently used for the recovery of heavy oil and bitumen are energy intensive due to steam generation, requires large volume of water, and natural gas for steam generation which introduces additional cost into the project. Moreover, environmental pollution resulting from wastewater and gaseous emissions, reduction in thermal efficiency as a result of heat losses to the reservoir formation, and also produced heavy oil requires expensive surface upgrading. Furthermore, injecting light petroleum solvent as in VAPEX is face with the problem of asphaltenes precipitation and additional separation process is required to recover the solvent. The recovered oil using these technologies required surface upgrading, this may lead to the modification of existing refineries. Surface upgrading technologies is energy intensive and emit GHG. Additionally, surface upgrading processes are capital intensive project as it involves the integration one or more of the following processes such as delayed coking, solvent deasphalting, visbreaking, thermal and catalytic hydroconversion, etc. to produce synthetic light crude that is suitable for refining (Pereira-Almao, 2012). Moreover, the surface upgrading processes contribute to GHG emission.

In other to bypass surface upgrading process, the toe-to-heel air injection (THAI) integrated with catalytic upgrading process in situ (CAPRI), collectively called THAI-CAPRI[TM] was developed (Greaves and Xia, 2004). A detail of the technology is provided in section 2. The THAI-CAPRI process integrates both heavy oil recovery and upgrading process in a single unit with the reservoir serving as the reactor vessel. The different surface and in situ upgrading processes are present in Figure 1.


Heavy crude oil and bitumen/tar sands consist of four hydrocarbon fractions, namely, saturates, aromatics, resins, and asphaltenes. It is known that heavy crude oil contain high percentage of asphaltenes. Asphaltenes are structurally poly-aromatics, known to contain hetero-atoms such as sulphur, nitrogen, metals (e.g., V, Fe, Ni, etc.), etc. in their structure (Nassar, 2010; Nassar, et al., 2011). The presence of asphaltenes makes heavy oil difficult to recover by conventional techniques, transport, and refined directly, because the asphaltenes induces high viscosity in the crude oil. Additionally, asphaltenes adsorption on catalyst surfaces during in situ catalytic upgrading of heavy oil causes coke formation, catalyst poisoning and deactivation. This is because asphaltenes are known for high carbon to hydrogen ratio, that is, high Conradson carbon residue (CCR) (i.e., high tendency to coke). Therefore, the significant reduction of asphaltenes contain of the heavy oil in situ would improve its recovery as well as refining.

The catalytic upgrading of heavy oil in situ is limited by the loss of activity due to deactivation of catalyst within a short period of time. This is because of the fouling and poisoning of the catalyst by the components present in the heavy oil such as asphaltenes, high carbon residues, heavy metals (e.g., Ni, V, Hg, etc.), sulphur, etc. Hydrogen donation and transfer reactions have been shown to be important in the conversion of heavy petroleum residuum, for example, hydrocracking, hydrodesulphurisation, hydrovisbreaking, etc. The objective of this process is to breakdown high molecular weight hydrocarbons in the heavy oil into lighter and more valuable crude oil (Sanchez, et al., 2005). It has been reported that the addition of hydrogen donor to the catalytic cracking of heavy oil promotes asphaltenes breakdown to yield aliphatic oil and reduce coke formation in the process (Curtis and Cassell, 1988). In the presence of hydroprocessing catalyst such as Ni-Mo, Co-Mo, Ni-Mo-W, Mo-Co-P, Mo-W-Ni-Co-P, etc. supported on alumina, silica or silicaalumina, hydrogen donor induces simultaneous hydrocracking, hydrodesulphurisation (HDS), hydrodenitrogenation (HDN), hydrodemetallisation (HDM), Conradson carbon removal (HDCCR) and asphaltenes conversion to minimise the sulphur, nitrogen and metal content of the heavy oil at high hydrogen partial pressure (Liu, et al., 2009).

The two main reaction pathways through which heavy oil upgrading occur are: carbon (or coke) rejection as the oil has high carbon-to-hydrogen atomic ratio, to produce light oil of low carbon-to-hydrogen ratio. The other route is via hydrogen addition to favour the yield of liquid product while suppressing coke formation (Speight, 2004). The objectives of these processes are to produce a more valuable light crude oil that meet refinery specification and have minimised heavy metals and sulphur content. Subsequently, many thermal and catalytic reactions involve the formation of unstable intermediates, called free radicals, of which in this case some are coke precursors. Therefore, it is believed that hydrogen basically terminates these free radical chains during thermal-catalytic upgrading of heavy oil in situ to form low molecular weight light oil. This article intend to constitute a review on catalytic upgrading process in-situ, present a brief advantages and challenges, and explore the role of hydrogen in controlling catalyst deactivation, improving distillate yield and removing impurities. Thus, the article will provide direction for further investigation.

Catalytic upgrading Process in situ

The 'toe-to-heel' air injection (THAI[TM]) and its add-on catalytic upgrading process in-situ (CAPRI[TM]), collectively called THAI-CAPRI[TM] was developed in 1998 by the Petroleum Recovery Institute (PRI), Calgary, Canada, in collaboration with the University of Bath Improved Oil Recovery group for the purpose of extraction and in-situ upgrading of heavy oil and bitumen (Greaves and Xia, 2004). The incorporation of catalyst around the perimeter of the production well as presented in Figure 2 is to upgrade the heavy oil by cracking the large molecular weight hydrocarbon. The injected air aids in-situ combustion, to provide the energy that drives the catalytic reactions.


The potential of the THAI-CAPRI process was investigated by Xia and Greaves (2001) using Wolf Lake heavy oil in 3-D combustion cell tests using Ni-Mo and Co-Mo catalysts. It was found that the oil was thermally upgraded to 20oAPI against original 10.5 API by THAI alone, with an additional 4-7 points further increase in API gravity on integration with the catalytic add-on CAPRI, the produced oil has a viscosity as low as 10 mPas at 20[degrees]C and oil recovery factor of about 85% OOIP (Xia and Greaves, 2001). However, the field trial of the THAI-CAPRI process was implemented in September 22, 2008 by Petrobank Energy and Resources Ltd. at Whitesands near Conklin, Alberta, Canada, but at the time of this article the result of the trial has not been published.

Presently, heterogeneous catalyst commonly used in hydrotreating/hydrocracking of heavy petroleum fractions, vacuum residual oil, and heavy crude oil have been found applicable to catalytic upgrading process in situ (CAPRI) (Weissman, et al., 1996). In view of this, conventional hydrodesulphurisation (HDS) catalysts such as those obtained from transition metals like molybdenum (Mo), cobalt (Co), nickel (Ni), tungsten (W), etc. supported on an acidic silica, alumina or silica-alumina are commonly used catalyst for heavy oil or residuum upgrading in the petroleum industry. However, the conventional hydroprocessing catalysts are not designed for down-hole reservoir environment, as in some cases, the catalyst is exposed to brine. Consequently, in the presence of brine, the generation of heat in situ to mobilise the heavy oil and reactants over the gravel pack catalyst along the horizontal production well within the oil reservoir to aid in situ catalytic upgrading present challenges not experienced in conventional surface upgrading process. In CAPRI, the contacting of the reservoir fluids and combustion gases, as they pass over the heated gravel packed catalyst produced upgraded oil. The concept of THAI-CAPRI is capable of in situ upgrading the heavy oil to light crude oil, which is transportable by pipeline without subsequently adding diluents. Other challenges include catalyst deactivation and subsequent plug, loss of stability and quality of upgraded oil due to coke and heavy metal deposition on to the catalyst. Additionally the costs and challenges of packing the well with pelleted catalysts prior to starting up also make the CAPRI process less economically attractive. The comparison of the supported catalyst system and the ultra-dispersed nano-catalysts for in situ catalytic upgrading of heavy oil is presented in Table 1. The comparison is based on the technicalities associated with both technologies.


Easy to get the catalyst into the reservoir energy self sufficiency, lower capital cost since 1-horizontal well, no steam and water handling facilities, recovery rate 70-80% of OOIP (Xia and Greaves, 2001), faster project execution time, on field trial stage and less technicalities to implement compared to nano-catalysts dispersion.

Vast surface area-to-volume ratio, lower mass transfer limitations, high catalyst performance eliminate coking experienced in supported catalyst, and better stability in quality of upgraded oil compared to supported catalyst


Rapid catalyst deactivation, short catalyst lifetime, risk of well plugging due to coke and heavy metal deposits, additional operation cost if the production well plugs, gradual pressure build drop due to coke deposition onto the catalyst, used catalyst can not be regenerated, gradual decline in upgraded oil quality due to catalyst loss of activity time, and additional cost of packing the catalyst pellets

Determining effective size to secure penetration in the porous media of the reservoir less than 200nm in diameter (Pereira-Almao, 2012), higher capital cost compared to supported because it uses double horizontal well configuration like SAGD, agglomeration and particle settling problem due to changes in reservoir temperature, still at the pilot stage of research, reliable oil particle separation, synthesis and delivery of nano-catalyst, challenges of propagating the nano-catalyst through porous media, plugging of porous media due to agglomeration and interaction of particles with reservoir matrix, and particle recycling challenges.

In the light of the above challenges associated with supported catalyst, dispersed nano-catalyst has been proposed as an alternative to the incorporation of catalytic perimeter around the producer. This is because in situ (i.e., within the reservoir) upgrading, offers some environmental and cost-effective advantages over its contemporary surface upgrading processes. The fundamental idea of in situ upgrading is integrating thermally driven catalytic cracking with any of the thermal recovery technologies, whereby the reservoir formation serves as the reactor vessel. Consequently, the high molecular weight hydrocarbons (i.e., asphaltenes) present in the heavy oil, carbon residue (or coke) and metals deposit on the surface of the supported catalyst, plug the pores and then result in rapid deactivation and loss of activity. Hence, unsupported dispersed catalysts via nanotechnology have been developed. This technology of the use of ultra-dispersed metals or nanoparticles as catalysts for in situ upgrading of heavy crude oil and bitumen/tar sands has been reported in the literatures (Ovalles, et al., 1998; Nassar, et al., 2011; Loria, et al., 2011). The feasibility of transporting these nano-particles or ultra-dispersed catalyst through the heavy oil-bearing matrix without causing damage to the reservoir formation during thermal recovery has been investigated by Zamani, et al. (2010). Although, nano-particles have high mobility in porous media because their size are quite smaller compared to the pore size, but some proportion of the catalyst are retained in the sand (Zamani, et al., 2010). Because of the unique properties of nano-particles such large surface area; they have the potential to adsorb asphaltenes present in the heavy oil and bitumen (Nassar, 2010; Nassar, et al., 2011). However, there are still hurdles facing it, which include determining the effective size of the nano-catalyst to secure penetration in the porous reservoir matrix, changes in temperature during operation may result in settling, separation, and possible agglomeration of the nano-catalyst (Pereira-Almao, 2012), synthesis and delivery of the nano-catalyst particles.

The above mentioned challenges explains the reason why the concept of catalytic upgrading in situ or down-hole catalytic upgrading technologies for heavy crude oil are still at the trial stage presently by the petroleum industry, in addition to the technical challenges of monitoring and control the process under reservoir conditions (Ovalles, et al., 2003). Furthermore, in situ catalytic upgrading of heavy crude oil in the oil-bearing matrix prior to reaching the surface offer numerous advantages: (1) reduces environmental impact as contaminants present in the heavy crude oil is left behind in the reservoir; (2) produced an upgraded light crude oil; (3) minimise the amount of sulphur, heavy metal and asphaltenes in the oil; (4) reduce the viscosity of the oil; (5) cost-effective as the reservoir formation serves as a reactor vessel, so there is no need for costly pressure vessel as in the case of surface upgrading process (Weissman, et al., 1996); and (6) easy well-by-well basis application. Additionally, there is reduction in energy consumption since the heat energy generated by in situ combustion or injected steam is utilised to recover the heavy oil as well as create the necessary conditions for upgrading. Another merit of in situ upgrading is that the heavy crude oil is upgraded as whole unlike in surface upgrading heavy crude oil is divided into fractions of different boiling range (Mohammad, 2008).

According to Weissman et al. (1996), a successful implementation of in situ catalytic upgrading process involves: adequate catalyst placement in the heavy oil-bearing matrix; mobilisation of the heavy crude oil and the co-reactants (e.g., hydrogen, carbon monoxide, water, etc.) over the catalyst layer; providing the necessary conditions of temperature and pressure to enhance catalytic upgrading; and subsequently producing upgraded light crude oil. In the case of THAI-CAPRI process, as the heavy crude flows through the fixed catalyst layer integrated along the horizontal well of the THAI-CAPRI technology prior to entering the production well, it is converted (i.e., upgraded) to almost light crude. To achieve this, ISC is used to generate heat necessary to mobilised the heavy crude oil, generate reactive gases as well as create the right condition of temperature over the catalyst layer to stimulate thermal and catalytic cracking during contacting.

The performance of heterogeneous catalysts is deleteriously affected by the deposition of metals and coke mostly from the cracking of the heavy crude oil. This clogs the surfaces of the solid catalyst and thus reduces hydrocracking. This causes undue shut-down and operational drawbacks as the recovery and rejuvenation of spent catalyst is challenging (Strausz, et al., 1999). Alternatively, to overcome these operational challenges, the use of homogeneous catalysts has been investigated for in situ upgrading of heavy oil. These are oil soluble bimetallic catalysts such as ammonium cobalt molybdate (NH4)H[Co.sub.2][(Mo[O.sub.4]).sub.2].[(OH).sub.2] or water soluble catalyst with the same active metals as the heterogeneous catalyst mostly used for heavy crude oil upgrading. They are easy to prepare compared to heterogeneous catalyst, overcome the problem of pore blockage experienced in supported catalyst, and high dispersive properties. Additionally, during heavy crude oil upgrading in situ, they are transformed to metal sulphides to enhance conversion. It involves the injection of the solution containing the catalyst in the form of water or steam flooding into the heavy oil-bearing geologic matrix (Weissman, 1997).

Common examples of homogeneous catalysts includes: polymolybdates like phosphomolybdic acid, ammonium heptamolybdate, etc. Others are ammonium vanadate, vanadyl acetylacetonates, molybdenum paramolybdate, cobalt octylate, etc. (Weissman, 1997). Subsequently, Ze-xia, et al. (2009) reported the use of ionic liquids such as [BMIM][Al[Cl.sub.4]] to extract, upgrade and desulphurise heavy oil, based on its excellent solubility and catalytic activities at the temperature range 65-85[degrees]C. It was found that the viscosity of the heavy oil reduces by 60% and asphaltenes by 78%, respectively. Strausz, et al. (1999), reported the use of gaseous super-acid tetrafluoroboric acid (HB[F.sub.4]) catalyst, to catalysed hydrocracking of heavy oil and tar sands in situ. The mechanism of upgrading reaction in ionic fluid is ionic, instead of free radical mechanism of heterogeneous catalytic cracking to yield liquid fuel product. Additionally, the use of high density water as hydrogen donor for heavy oil and bitumen upgrading, because of its high dissolution and high reactivity at high temperature or in supercritical state has been reported in the literature (Watanabe, et al., 2010).

The Role of Hydrogen

The consumption of hydrogen in the CAPRI process would depend on the heavy oil properties, impurities removal, properties of the catalyst, conversion level, and solubility of the hydrogen (Castaneda, et al., 2011). The various roles hydrogen plays during catalytic upgrading of heavy crude oil are presented in Figure 3.


Petroleum refiners focus attention on maximising the yield of middle distillates from upgraded oil, in order to meet the rising demand of transportation fuels. Jarullah et al. (2011) investigated the yield of fuel distillate from crude oil after hydrotreatment. They found that while the crude residue decrease, the yield of middle distillate by distillation process increased as presented in Figure 4. This is because catalytic cracking of high molecular weight hydrocarbons into lower boiling light hydrocarbons in presence of hydrogen (i.e., hydrocracking) promote saturation with hydrogen to yield distillate fractions with increased hydrogen-to-carbon atomic ratio.


Additionally, polyaromatic hydrocarbons are know contributors to catalysts deactivation through coking. As the cracked heavy crude oil contains unsaturated hydrocarbons as such olefins and aromatics, it becomes necessary to introduce hydrogen. The acid sites of the catalyst support promote selective hydrogenation of the olefinic and aromatic bonds to form saturated hydrocarbons as illustrated in Figure 5, which may have contributed to the increased yield of middle distillates shown in Figure 4.


Furthermore, heavy oil contains high level of impurities that causes drastic catalyst deactivation. Table 2 present the impact of some of the identified impurities in heavy crude oil. However, with the growing concern for the environment, it is essential to produce petroleum distillates with minimised impurities level such as sulphur, nitrogen, heavy metals, etc. to meet stringent environmental legislations.

The Reactants like hydrogen may be introduced to the CAPRI or thermal upgrading process to play the following role: hydrodesulphurisation (HDS) of the heavy crude oil, stimulate hydrocracking (HDC) process in situ, hydrodemetallisation (HDM), hydrodenitrogenation (HDN), and therefore reduces the level of coke formation as it saturates the reactive species of coke precursors formed during the cracking reaction. Hydrogen also helps to stabilised the upgraded oil, and aid asphaltene (known for their low H/C atomic ratio) conversion (Speight, 2009). This implies that the injection of hydrogen or in situ generation of hydrogen (e.g., water gas shift reaction produce hydrogen during in situ combustion) for CAPRI would offer many benefits to the upgrading process. However, the amount of hydrogen generated in situ via water-gas shift reaction is not enough to terminate all the coke precursors active chains formed from carbon rejection reaction or pyrolysis of heavy oil and at the same time remove impurities (Liu and Fan, 2002). In that case, hydrogen addition will enhance the reduction of these impurities (see Table 2) according to the following reactions, where R, R' and R" represent the hydrocarbon molecule of different structure, Asph represents asphaltenes, and M heavy metal (Absi-Halabi, et al., 1991):

Hydrocracking (HC) R-R' + [H.sub.2] [right arrow] R-H + R'-H Hydrodesulphurisation (HDS) R-SH + [H.sub.2] [right arrow] R-H + [H.sub.2]S Hydrodenitrogenation (HDN) R-N + 2[H.sub.2] [right arrow] R-H + N[H.sub.3] Hydrodemetallisation (HDM) R-R' MR" + [H.sub.2] [right arrow] R-H + HR' MR" (soluble) (precipitated) Hydrodeasphaltenization (HDAs) R-Asph + [H.sub.2] [right arrow] R-H + Asph-R (smaller) + [H.sup.+]

The HDS and HDN reactions convert the sulphur and nitrogen components to hydrogen sulphide ([H.sub.2]S) and ammonia (N[H.sub.3]), while HDM reaction converts the metals to metallic sulphides such as vanadium to [V.sub.3][S.sub.4] and nickel to NiS, respectively.

Nonetheless, hydrogen is expensive and these reactions consume lots of hydrogen. In this regard, alternative hydrogen donors are investigated. It has been reported that hydrogen donor additives (e.g., tetralin) have the potential to decrease the asphaltenes content of oil, improve its API gravity, the viscosity, and enhance the distillable proportions of the heavy oil (Vallejos, et al., 1999; Ovalles, 2001). Vallejos (2000) investigation of the pyrolysis of asphaltenes under the presence of hydrogen donor additive, shows that the amount of coke formed is 1.6% and 76% of the asphaltenes were converted to fractions with boiling point below 450oC. It is therefore believed that prolysis or carbon rejection reaction mechanism of the heavy oil proceeds as free radicals. So, the addition hydrogen donor terminates and stabilises the free radicals (Liu and Fan, 2002). But in the absence of hydrogen donor additive, the active chain free radicals react with each other to form high molecular weight hydrocarbons (Liu and Fan, 2002).

The commonly used hydrogen donors in heavy oil upgrading are hydrogen gas, methane, tetralin (or tetrahydronaphthalene, [C.sub.10][H.sub.12]), methylcyclohexane, etc. The hydrogen donor additives releases free active hydrogen that react with the active chain free radicals produced during pyrolysis of the heavy oil, thereby inhibiting the regress of upgraded oil viscosity (Curtis and Cassell, 1988; Ovalles, et al., 1998; Liu and Fan, 2002). This is because active hydrogen molecule size is small, therefore the rate of transfer is fast to terminate the active chain free radicals and coke precursors present in the upgraded oil, leading to low molecular weight hydrocarbons (Liu and Fan, 2002). This means that, the incorporation of hydrogen to thermally driven catalytic cracking of heavy crude oil would increase the hydrogen-to-carbon atomic ratio and suppresses coke formation. This is due to the break of carbon--carbon bonds are saturated with hydrogen (Loria, et al., 2011).

The Heavy Crude oil upgrading Reactions Pathways are

Thermal cracking (or pyrolysis)

Heavy Residue [right arrow] Light oil + Coke J, (reduction in C/H atomic ratio) (1) Hydrogen Addition

[C.sub.n] [H.sub.m] + [H.sub.2] [right arrow] [C.sub.n] [H.sub.m+2] (increases in H/C atomic ratio) (2)

Liu and Fan (2002) reported that the presence of hydrogen donor additives (e.g., tetralin) help to terminate and stabilise the active chain free radicals to produce low molecular weight hydrocarbons, as illustrated below:

In the Presence of hydrogen Donor Additive

Active [H.sub.2] donor + Active chain free radical [right arrow] Active chain termination (low molecular weight hydrocarbon)

In the Absence of Hydrogen Donor Additives

Active chain free radical + Active chain free radical [right arrow] Active chain termination (high molecular weight hydrocarbon)

It is Clear based on the above reactions that poisoning metallic components of the heavy oil and bitumen such as organometallic compounds attached to the asphaltenes including those of nickel and vanadium, and also sulphur, nitrogen, etc. will be minimised in the upgraded oil in the presence of hydrogen and adequate operating conditions of temperature and pressure. Liu and Fan (2002) found that in the absence of hydrogen donor viscosity of upgraded oil regresses with time, due to the reaction of high molecular weight active chains to terminate the free radicals. This may lead to polymerisation and condensation to larger molecular weight hydrocarbon like polyaromatics, thereby increasing the viscosity of the resultant upgraded oil. But the incorporation of hydrogen donor inhibit viscosity regress, therefore, this is avoidable at the expense of hydrogen cost. Additionally, reports in literatures show that there is improvement in upgraded oil properties such as increase API gravity, high hydrogen-to-carbon atomic ratio, reduced asphaltenes, heavy metals, sulphur content and stabilised viscosity (Liu and Fan, 2002; Vallejos, 1999; Vallejos, 2000; Mohammad, 2008). While the amount of resin and asphaltenes reduces, that of saturates and aromatics increases. This lowers the viscosity more effectively and improved the flow properties of the produced oil.

The Deposition of coke on the catalysts from the carbon rejection reaction during thermally driven catalytic upgrading in situ deactivates the catalysts within short time interval. In addition, the presence of heavy metals (V, Ni, etc.), sulphur, nitrogen and other contaminants severely reduces the catalytic activity rapidly (Shah, et al., 2011). Therefore, the minimisation of unwanted species like heavy metals (V, Ni, etc.), sulphur, etc. and coke deposition, will sustain the catalyst activity and improve the lifetime. In this aspect, hydrogen showed the potential to remove these impurities through HDS, HDO, HDM, HDN, HDAs, in addition to hydrocracking to accelerate the breakdown of high molecular weight hydrocarbon to lighter products. It increases the quality and yield of fuel distillate from the upgraded oil through hydrogenation of the cracked fragments of the heavy oil, and reducing coke formation by terminating their precursor and free radicals. Furthermore, thermal cracking in the absence of concurrent or consequent hydrogen transfer without catalyst may lead to unstable upgraded oil product (Pereira-Almao, 2012). In this regard, the favoured route to avoid instability in the upgraded oil, in situ upgrading in the presence of hydrogen would include catalysts.

Concluding Remark and Future Outlook

The THAI-CAPRI process combines both heavy oil recovery and upgrading in a single unit implemented in the reservoir. This concept offers economical as well as environmental advantages over thermal recovery with subsequent conventional surface upgrading process to produce refinery feedstock. The main objective has been to produce valued light crude oil through thermal-catalytic cracking of heavy oil. The review of related literatures on the incorporation of hydrogen donor, indicate that hydrogen donor help to remove heteroatoms attached to the asphaltenes and also inhibit coke formation by hydrogenation of coke precursors formed during thermal-catalytic cracking of the heavy oil. Heterogeneous solid catalysts used in refineries for hydroprocessing of heavy petroleum residue are found suitable for catalytic upgrading process in situ, and are economical because they are relatively cheap. Alternatively, the proposed ultra-dispersed nano-catalyst is faced with the challenges of particle size to secure penetration in the reservoir, agglomeration, and control of permeability with time. Based on this, the supported catalyst is favoured having been on field trial, but limited mostly by catalyst deactivation which has motivated the review of the role hydrogen would play if introduced.

Though investigation carried out by Greaves and Xia (2004) shows the process potential to convert heavy oil into light oil. But some notable limitations of the THAICAPRI process are the rapid deactivation of catalyst and possible plugging of the production well due to coking and heavy metals deposition. In addition, modifying commonly used hydrocracking catalysts to withstand and tolerate the asphaltenes and heavy metal constituents of heavy oil and bitumen, would also help to improve its performance and lifetime. Therefore, to address these limitations future investigation of the CAPRI process would include

Investigation of catalyst performance under high temperature and high pressure reservoir conditions to understand the effect of temperature and pressure on upgrading, in addition to the effectiveness of the catalyst and their performance in terms of the quality of upgraded crude oil and its suitability as refinery feedstock.

Understanding the routes and mechanisms of catalyst deactivation, in order to improve lifetime, sustain its activity and process economics. This will provide bases for controlling catalyst deactivation either by introducing a guard bed in addition to using hydrogen.

Determine the chemistry of the catalytic upgrading process, including effects of asphaltenes and hydrogen. This is to understand the contribution of asphaltenes to the catalyst clogging and how hydrogen would help suppress it effect during the catalytic upgrading.

Investigate the use of guard bed media and effect of catalyst pores on deactivation level.

Conclusively, Economic and environmental evaluation of the THAI-CAPRI process in comparison with existing technology is necessary. Moreover, the presence of water in the reservoir, permeability and rock heterogeneity, mobility of the heavy oil, and properties of the oil may impact differently on the performance of the THAI-CAPRI process.


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Abarasi Hart

School of Chemical Engineering, University of Birmingham

Edgbaston, Birmingham, B15 2TT, UK

Table 1: Comparison of Supported Catalyst and ultra-dispersed
nano-catalyst for Catalytic upgrading in situ

Catalytic upgrading in-situ

Supported catalyst attached to Ultra-dispersed nano-catalysts
Horizontal production (see Fig. 2)

Table 2: Impact of identified impurities in Crude oil

Component Impact

Sulphur Environmental pollution, e.g. SOx, Catalyst
 poisoning, facilitate process equipment,
 pipes, and machines corrosion, gives the oil
 and its products obnoxious odour (i.e.,
 marcaptans), and increase hydrocarbon

Nitrogen Reduce catalytic activity and lifespan,
 environmental pollution, e.g. NOx, toxic
 effect on the storage of petroleum products,
 and catalyst poisoning

Metals Causes rapid catalyst deactivation in
(e.g., Ni, V, Fe, etc) downstream processes, increase equipment
 corrosion, lowers efficiency, environmental
 pollution, and influences the API gravity

Asphaltenes Induces high density and viscosity to the
 crude oil, lower API gravity, causes poor
 flow, sticks on the walls process equipment,
 increase coking and fouling in process lines,
 reactors, and catalyst, increase
 transportation and processing cost, increase
 yield of residue, and precipitation in
 process line causes clogging.
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Author:Hart, Abarasi
Publication:International Journal of Petroleum Science and Technology
Date:May 1, 2012
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