Patent Application
20150329785
Embodiments of the invention relate to techniques for pyrolyzing type IIs kerogen compositions derived therefrom, and to related methods of hydrotreating.
The world's supply of conventional sweet, light crude oil is declining, and discoveries and access to new resources for this premium oil are becoming more challenging. To supplement this decline and to meet the rising global demand, oils of increasing sulfur content are being produced and brought to market. Sources of sulfur-rich oil may be found in Canada, Venezuela, the United States (California), Mexico and the Middle East.
Although sulfur-rich oils, such as Maya crude, contribute significantly to the world's oil reserves, the economic and environmental costs of refining heavy oils can be significant.
Many sulfur-rich hydrocarbons are sourced from a subset of Type II kerogen known to be sulfur-rich, called Type II-s or IIs. A schematic representation of one type of organic matter in Type IIs kerogen is illustrated below:
Originating from a marine-depositional environment, Type II-s kerogen is rich in sulfur-bearing organic compounds, and during thermal maturation produces oil and bitumen with high sulfur content. For example, the oil produced in some Iraqi oil fields have sulfur content of ˜4%.
Sulfur-rich oils include both conventional oils as well as unconventional oils. As conventional oil becomes less available (e.g. due to the increased cost of producing conventional oil from remote locations) and/or unable to meet world demand, it can be replaced with production of unconventional oils. Unconventional oils may be derived from a number of sources, including but not limited to oil sands, oil shale, coal, biomass, and bitumen deposits.
Presently, however, sulfur-rich oils are expensive to develop and bring to market for a variety of reasons. Sulfur rich oils must be treated with costly hydrogen gas during the refining process to lower the sulfur content of the oil, a process called hydrodesulfurization. Hydrotreating includes the effort to hydrodesulfurize and hydrodenitrify. Furthermore, sulfur rich oils are typically hydrotreated in sturdy but costly vessels due to the high pressures and temperatures required. When the sulfur-rich oils include significant quantities of metals, their presence of them may poison the catalysts, thereby requiring larger quantities of expensive catalyst.
Embodiments of the present invention relate to apparatus, methods and compositions associated with oil production from sulfur-rich Type IIs kerogen. One example of a Type IIs kerogen is kerogen of the Ghareb formation of Jordan.
Embodiments of the present invention relate to a novel technique for pyrolyzing sulfur-rich type IIs kerogen, a novel oil derived therefrom, and novel techniques for hydrotreating the same at only low-severity conditions.
By slowly pyrolyzing sulfur-rich Type IIs kerogen at relatively low temperatures, it is possible to obtain an oil which is surprisingly easy to hydrotreat, despite its relatively high sulfur content. In some embodiments, this ease of hydrotreating relates to one or more of the following properties: (i) a relatively high concentration of alkylthiophene relative to multi-ring sulfur heterocycles such as benzothiophenes or dibenzothiophenes and/or (ii) a relatively high concentration of low molecular weight alkylthiophene (i.e. C1-C3 alkylthiophenes) relative to higher molecular weight alkylthiophenes.
Speciation experiments conducted on a blend of hydrocarbon pyrolysis liquids derived from Ghareb formation oil shale indicates that an abundance of C3 thiophenes and a substantial lack or complete absence of C4+ thiophenes. Furthermore, analysis of these pyrolysis liquids shows that they are both alkylthiophene rich and surprisingly easy to hydrotreat.
Analogously, it is believed that oils derived by low-temperature pyrolysis of type IIs kerogen are (i) relatively rich in alkylpyridines compared to a concentration of multi-ring nitrogen basic heterocycles (i.e. alkylquinolines, alkylisoquinolines and alkylacridines); and (ii) relatively rich in alkylpyrroles compared to a concentration of multi-ring nitrogen neutral heterocycles (i.e. *alkylindoles and alkylcarbazoles).
Analogously, it is believed that low-temperature pyrolysis of type IIs kerogen tends to favor formation of lower molecular-weight pyridine and pyrrole species, with little or no formation of higher molecular-weight pyridine and pyrrole species.
Advantageously, these lower molecular-weight single-ring heterocyclic compounds are significantly easier to hydrotreat than their multi-ring and/or higher-molecular weight counterparts. As noted below, it is possible to regulate the pyrolysis process so as to favor formation of heterocyclic species which are easier to subsequently hydrotreat.
Furthermore, experiments conducted on the aforementioned oil blend of hydrocarbon pyrolysis liquids derived from Ghareb formation oil shale indicates that this oil is surprisingly easy to hydrotreat. In particular, experiments indicate that it is possible to produce, from sulfur-rich type IIs kerogen, a light, sweet synthetic crude oil having a sulfur content of at most 1% wt/wt and a nitrogen content of at most 0.2% wt/wt without relying on external sources of hydrogen gas (e.g. using only hydrogen gas formed by pyrolysis of the kerogen) and/or whereby hydrocarbon liquids are subjected to at most low-severity hydrotreatment.
In some embodiments, it is possible to optimize the ease of hydrotreating by maximizing the amount of pyrolysis that occurs at very low temperatures—e.g. between 270 and 290 degrees Celsius. Kinetics experiments for the pyrolysis of kerogen of oil shale from the Ghareb formations indicates that a rate of pyrolysis is surprisingly high at these low temperatures. Thus, it is possible to arrange heater well spacing and/or regulate power of subsurface heaters in order to maximize the amount of low-temperature pyrolysis.
As discussed below with reference to
Thus, in some embodiments, a majority or a substantial majority of kerogen of a portion (for example, a target portion having length, width and height of at least 20 meters, or at least 50 meters, or at least 100 meters, or at least 150 meters) of a formation is pyrolyzed in a temperature range between 270 and 290 degrees Celsius.
Alternatively or additionally, in embodiments related to in situ pyrolysis, it is possible to regulate a power level of subsurface heaters so as to maximize, within the hydrocarbon pyrolysis formation liquids, at least one of: (i) a fraction of sulfur heterocycles that are alkylthiophenes; (ii) a fraction of basic nitrogen heterocycles that are alkylpyridines; (iii) a fraction of neutral nitrogen heterocycles that are alkylpyrroles. For example, it may be possible to monitor any of the aforementioned fractions, and in response to a monitored value or a change therein, increase or decrease a power level of one or more of the subsurface heaters.
Alternatively or additionally, in embodiments related to in situ pyrolysis, it is possible to regulate a power level of subsurface heaters so as to maximize, within the hydrocarbon pyrolysis formation liquids, at least one of: (i) a ratio between a concentration of alkylthiophenes and a concentration of alkylbenzothiophenes; (ii) a ratio between a concentration of alkylthiophenes and a concentration of alkyldibenzothiophenes; (ii) a ratio between a concentration of alkylpyridines and a sum of concentrations of alkylquinolines and alkylisoquinolines; (iii) a ratio between a concentration of alkylpyridines and a concentration of alkylacridines; (iv) a ratio between a concentration of alkylpyrroles and a concentration of alkylindoles; (v) a ratio between a concentration of alkylpyrroles and a concentration of alyklcarbazoles. For example, it may be possible to monitor any of the aforementioned ratios, and in response to a monitored value or a change therein, increase or decrease a power level of one or more of the subsurface heaters.
As noted above, one advantage of the presently disclosed hydrocarbon pyrolysis liquids derived from relatively low temperature and/or slow pyrolysis of type IIs kerogen is the predominance of easier-to-hydrotreat alkylthiophenes relative to harder-to-hydrotreat alkylbenzothiophenes and alkyldibenzothiophenes. Furthermore, speciation experiments performed on the aforementioned oil blend of hydrocarbon pyrolysis liquids derived from Ghareb formation oil shale indicate that the relative concentration of the different species of alkylthiophenes follow a definitive pattern. In particular, speciation data indicates that substantially all thiophenes are C2-C3 thiophenes, with low concentration of C1 thiophenes and even lower concentrations of both thiophene C4H4S as well as C4+ thiophenes.
Although C2-C3 thiophenes are slightly or somewhat harder to hydrotreat than C1 thiophene or thiophene C4H4S, they are significantly easier to hydrotreat than the multi-ring heterocyclics, or than the heavier C4+ or C5+ or C6+ or C7+ alyklthiophenes. The surprising predominance of C2-C3 thiophenes is advantageous because: (i) these species are ‘easy enough’ to hydrotreat and (ii) in contrast to hydrotreatment of thiophene C4H4S which produces less valuable and non-condensable butane, hydrotreating of C2-C3 thiophenes produces more valuable hexane and heptane.
Towards this end, in some embodiments related to in situ pyrolysis, it is possible to regulate a power level of subsurface heaters so as to maximize, within the hydrocarbon pyrolysis formation liquids, at least one of: (i) a ratio between concentrations of C3 alkylthiophenes and C4 alkylthiophenes; (ii) a ratio between concentrations of C3 alkylpyridines and C4 alkylpyridines; (iii) a ratio between concentrations of C2 alkylpyridines and C3 alkylpyridines; (iv) a ratio between concentrations of C3 alkylpyrroles and C4 alkylpyrroles; (v) a ratio between concentrations of C2 alkylpyrroles and C3 alkylpyrroles.
Furthermore, preliminary GC results for the aforementioned blend of hydrocarbon pyrolysis liquids indicate that at most small quantities of ethyl-thiophene are formed by low-temperature pyrolysis of type IIs kerogen. This indicates that a substantial majority, or substantially all C2 alkylthiophenes are di-methyl thiophenes rather than ethyl-thiophenes. The present inventors propose a pyrolysis mechanism related to slow pyrolysis of kerogen comprising sulfur cross-linked chlorophyll chains at low pyrolysis temperature (e.g. in the range between 270 and 290 degrees Celsius).
According to this proposed mechanism, at temperatures between 270 and 290 degrees Celsius, the weakest sulfur-sulfur bonds are the first to be broken. In a Type IIs kerogen, S—S bonds crosslink the chlorophyll chains comprising a backbone of about 20 carbon atoms. After the S—S bond is thermally cleaved, the backbone ‘folds around’ and forms an alkylated thiophene having one or more CN alkyl groups where N is a ‘large’ number (e.g. typically about 20 carbons in naturally-occurring high sulfur oils derived from Type IIs kerogen)). However, unlike the naturally-occurring oils, when the kerogen is maintained at the low pyrolysis temperatures between 270 and 290 degrees C. for a relatively ‘long’ period of time, the kinetics favor breaking the long carbon chains at their weakest point, leaving only relatively stable methyl groups attached to the thiophene ring. The low temperature long duration pyrolysis yields primarily methyl-thiophene or di-methyl-thiophene or tri-methyl-thiophene or tetra-methyl-thiophene.
Thus, when kerogen is exposed to these low-temperature pyrolysis temperatures for a relatively long period of time, significant quantities of alkylated thiophenes may be yielded, where the thiophene ring is alkylated only by one or more methyl group(s).
Not wishing to be bound by theory, it is believed that this is in contrast to conventional oil formed from Type IIs kerogen over millions of years at significantly lower temperatures, where not enough energy is provided to cleave the C—C bond at its first position to yield methylated thiophenes, and where most alklylated thiophenes are CN alkyl thiophenes where N is relatively ‘large,’ being equal to at least 5 or at least 10 or at least 20.
Not wishing to be bound by theory, it is believed that this is also in contrast to pyrolysis liquids generated from conventional high-temperature, ‘fast-heating’ surface retorts, which are known to generate mostly high-molecular weight species, including sulfur-bearing compounds. These higher molecular weight species comprise high concentrations of multi-ring aromatic compounds, including dibenzothiphenes and alkyl dibenzothiophenes, which are much more difficult to hydrotreat than the methylated thiophenes.
Embodiments of the present invention relate to techniques for producing, from sulfur-rich type IIs kerogen, a light, sweet synthetic crude oil having a sulfur content of at most 1% wt/wt and a nitrogen content of at most 0.2% wt/wt in a manner that is self-sufficient with respect to hydrogen gas and/or whereby hydrocarbon liquids are subjected to at most low-severity hydrotreatment.
By pyrolyzing the type IIs kerogen at relative low temperatures which are sustained for a relatively long period of time, it is possible to generate hydrocarbon pyrolysis formation fluids that are surprisingly easy to hydrotreat. Experimental data indicates that these formation fluids are rich in easier-to-hydrotreat heterocyclic species, in contrast to hydrocarbon formation fluids obtained from similar kerogen under higher temperature and/or ‘fast-heating’ conditions.
For the present disclosure, ‘low severity’ hydrotreating conditions are characterized by (i) a maximum temperature of at most 350 degrees Celsius or at most 340 degrees Celsius or at most 330 degrees Celsius; and (ii) a maximum pressure of at most 120 atmospheres (atm) or at most 110 atm or at most 100 atm or at most 90 atm or at most 80 atm or at most 70 atm.
For the present disclosure, the statement “hydrotreating is sustained only by the hydrogen gas component of the pyrolysis gases” includes only H2 gas formed as a reaction product of the pyrolysis itself, and does not include hydrogen gas derived from steam methane reforming of the pyrolysis gases.
For the present disclosure, a process that is ‘self-sufficient with respect to hydrogen gas” consumes only the H2 gas formed as a reaction product of the pyrolysis itself, and does not include hydrogen gas derived from external hydrogen sources or steam methane reforming of the pyrolysis gases.
“Sulfur-rich” type IIs kerogen refers to type IIs kerogen having an average sulfur content of at least 8% wt/wt (in some embodiments, at least 10% wt/wt or at least 12% wt/wt) and an average nitrogen content of at least 1.5% wt/wt (in some embodiments, at least 1.75% wt/wt or at least 2% wt/wt).
Type IIs kerogen is pyrolyzed to form hydrocarbon pyrolysis fluids, which are hydrotreated only at low-severity conditions and/or without relying on external sources of hydrogen gas. In some examples, the pyrolysis is performed primarily at relatively low temperatures and/or in a manner that maximizes a ratio between respective concentrations of alkylthiophenes and alkyldibenzothiophenes within the resulting pyrolysis liquids. In some embodiments, the pyrolysis is performed in a manner that maximizes a fraction of alkylthiophenes that are either (i) unalkylated or (ii) alkylated only by one or more methyl groups. In some embodiments, the pyrolysis is performed in a manner that maximizes a fraction of alkylthiophenes that are (i) unalkylated or (ii) C1-C3 alkylthiophenes. In some embodiments, the pyrolysis is performed in a manner that maximizes a fraction of alkylthiophenes that are (i) unalkylated or (ii) C2-C3 alkylthiophenes.
It is believed that the pyrolysis primarily at low temperature is conducive for formation of relatively high concentrations lower-molecular-weight and single-ring heterocyclic species that are easier to hydrotreat than their multi-ring or higher-molecular-weight counterparts.
Although low-temperature pyrolysis may be significantly slower than pyrolysis at higher temperatures for well-studied kerogens such as Green River Type I kerogen, experiments commissioned by the present inventors indicate that type IIs kerogen, such as that in Ghareb formations, pyrolyzes at a surprisingly fast rate even at low temperatures of less than 290 degrees Celsius, where the pyrolysis liquids are relatively rich in easier-to-hydrotreat species.
In order to maintain the type IIs kerogen within a desired low-temperature pyrolysis range for sufficient time, it may be desirable to quickly ramp up to a desired low temperature pyrolysis temperature, and then to control heater power (e.g. reducing heater power) in a manner so as to prolong an amount of time the kerogen is maintained at ‘low’ range of pyrolysis temperatures below 290 degrees Celsius.
For convenience, in the context of the description herein, various terms are presented here. To the extent that definitions are provided, explicitly or implicitly, here or elsewhere in this application, such definitions are understood to be consistent with the usage of the defined terms by those of skill in the pertinent art(s). Furthermore, such definitions are to be construed in the broadest possible sense consistent with such usage.
For convenience, in the context of the description herein, various terms are presented here. To the extent that definitions are provided, explicitly or implicitly, here or elsewhere in this application, such definitions are understood to be consistent with the usage of the defined terms by those of skill in the pertinent art(s). Furthermore, such definitions are to be construed in the broadest possible sense consistent with such usage.
If two numbers A and B are “on the same order of magnitude”, then ratio between (i) a larger of A and B and (ii) a smaller of A and B is at most 15 or at most 10 or at most 5.
Unless specified otherwise, a ‘substantial majority’ refers to at least 75%. Unless specified otherwise, ‘substantially all’ refers to at least 90%. In some embodiments ‘substantially all’ refers to at least 95% or at least 99%.
Embodiments of the present invention relate to compositions (e.g. oils) containing one or more types of heterocyclic compounds including (i) sulfur heterocyclic compounds such as the single-ring alkylthiophenes, or the multi-ringed alkylbenzothiophenes or alkyldibenzothiophenes and (ii) nitrogen heterocyclic compounds such as the single-ringed alkylpyridines or alkylpyrroles, or the multi-ringed alkylquinolines, alkylisoquinolines, alkylacridines, and alkylindoles, and alkylcarbazoles. The term ‘alkylthiophenes’ includes thiophene C4H4S as well as alkylated thiophenes. ‘Alkylated thiophenes’ are thiophenes where an alykl group is bonded to one or more locations on the thiophene ring. Thiophene C4H4S is an ‘alkylthiophene’ but is not an ‘alkylated thiophene.’ Examples of alkylated thiophenes include but are not limited to methyl thiophenes, di-methyl thiophenes, ethyl thiophenes, ethyl methyl-thiophenes, propyl thiophenes, etc. Analogous definitions (i.e. analogous to ‘alkylthiophenes’) apply to the multi-ring sulfur heterocyclic compounds (i.e. alkylbenzothiophenes and alkyldibenzothiophenes) to the single-ring nitrogen heterocyclic compounds (i.e. alkylpyridines and alkylpyrroles) and to the multi-ring nitrogen heterocyclic compounds (i.e. alkylquinolines, alkylisoquinolines alkylacridines, and alkylindoles and alkylcarbazoles).
By way of example, methyl thiophenes are a ‘C1 alkylthiophene’ because the total number of carbon atoms of alkyl groups bonded to a member of the thiophene ring is exactly 1. Both di-methyl thiophenes and ethyl thiophenes are ‘C2 alkylthiophenes’ because the total number of carbon atoms of bonded-alkyl group(s) bounded to a member of thiophene ring is exactly 2. C3 alkylthiophenes are molecules where the total number of carbon atoms of bonded-alkyl group(s) bounded to a member of thiophene ring is exactly 3—thus, C3 alkylthiophenes include tri-methyl thiophenes, methyl ethyl thiophenes and propyl thiophenes. Analogous definitions (i.e. analogous to ‘alkylthiophenes’) apply to the multi-ring sulfur heterocyclic compounds (i.e. alkylbenzothiophenes and alkyldibenzothiophenes) to the single-ring nitrogen heterocyclic compounds (i.e. alkylpyridines and alkylpyrroles) and to the multi-ring nitrogen heterocyclic compounds (i.e. alkylquinolines, alkylisoquinolines alkylacridines, and alkylindoles and alkylcarbazoles).
For a positive integer N, the terms ‘CN alkylthiophenes’ and ‘CN thiophenes’ are used synonymously and refer to alkylthiophenes (which also happen to be ‘alkylated thiophenes’) where the total number of carbon atoms of bonded-alkyl group(s) bounded to a member of thiophene ring is exactly N. Analogous definitions (i.e. analogous to ‘alkylthiophenes’) apply to the multi-ring sulfur heterocyclic compounds (i.e. alkylbenzothiophenes and alkyldibenzothiophenes) to the single-ring nitrogen heterocyclic compounds (i.e. alkylpyridines and alkylpyrroles) and to the multi-ring nitrogen heterocyclic compounds (i.e. alkylquinolines, alkylisoquinolines alkylacridines, and alkylindoles and alkylcarbazoles).
For a positive integer N, the terms ‘CN+ alkylthiophenes’ and ‘CN+ thiophenes’ are used synonymously and refer to alkylthiophenes (which also happen to be ‘alkylated thiophenes’) where the total number of carbon atoms of bonded-alkyl group(s) bounded to a member of thiophene ring is greater than or equal to N. Analogous definitions (i.e. analogous to ‘alkylthiophenes’) apply to the multi-ring sulfur heterocyclic compounds (i.e. alkylbenzothiophenes and alkyldibenzothiophenes) to the single-ring nitrogen heterocyclic compounds (i.e. alkylpyridines and alkylpyrroles) and to the multi-ring nitrogen heterocyclic compounds (i.e. alkylquinolines, alkylisoquinolines alkylacridines, and alkylindoles and alkylcarbazoles).
For positive integers N, M (M>N), the terms ‘CN-CM alkylthiophenes’ and ‘CN+ thiophenes’ are used synonymously and refer to alkylthiophenes (which also happen to be ‘alkylated thiophenes’) where the total number of carbon atoms of bonded-alkyl group(s) bounded to a member of thiophene ring is either (i) exactly N; or (ii) exactly M or (iii) greater than N and less than M. Analogous definitions (i.e. analogous to ‘alkylthiophenes’) apply to the multi-ring sulfur heterocyclic compounds (i.e. alkylbenzothiophenes and alkyldibenzothiophenes) to the single-ring nitrogen heterocyclic compounds (i.e. alkylpyridines and alkylpyrroles) and to the multi-ring nitrogen heterocyclic compounds (i.e. alkylquinolines, alkylisoquinolines, alkylacridines, and alkylindoles and alkylcarbazoles).
When determining concentration of alkylthiophenes (or, by analogy, alkylbenzothiophenes or alkyldibenzothiophenes or alkylpyridines and alkylpyrroles or alkylquinolines, or alkylisoquinolines or alkylacridines or alkylindoles or alkylcarbazoles), the location to which alkyl group(s) are attached is immaterial.
For the present invention, an ‘alkylthiophene-rich oil’ is an oil where a majority (or a substantial majority) of the sulfur compounds are alkylthiophenes and/or an oil that is at least 10% or at least 20% by volume alkylthiophene. For the present invention, an ‘alkylpyridine and/or alkylpyrrole rich oil’ is an oil where a majority (or a substantial majority) of the nitrogen compounds are alkylpyridines or alkylpyrroles and/or an oil that is at least 10% or at least by volume either alkylpyridines or alkylpyrroles.
For the present disclosure, a ‘sulfur-rich feedstock’ or a ‘sulfur-rich pyrolysis liquid’ is at least 3% wt/wt or at least 4% wt/wt sulfur.
For the present disclosure, sulfur-rich type IIs kerogen is at least 6% wt/wt or at least 7% wt/wt or at least 8% wt/wt sulfur.
For the present disclosure, ‘low temperature pyrolysis’ is pyrolysis that occurs at temperatures of at most 290 degrees Celsius over a period of at least 3 months or at least 6 months or at least 1 year. In some embodiments, ‘low temperature pyrolysis’ occurs between 270 degrees Celsius and 290 degrees Celsius over this period of at least 3 months or at least 6 months or at least 1 year. In some embodiments, ‘low temperature pyrolysis’ occurs between 280 degrees Celsius and 290 degrees Celsius over this period of at least 3 months or at least 6 months or at least 1 year. In this temperature range, pyrolysis proceeds quickly enough to be feasible, while favoring formation of easier-to-hydrotreat species.
For the present disclosure, a process that is ‘self-sufficient with respect to hydrogen gas” consumes only H2 gas formed as a reaction product of the pyrolysis itself, and does not include hydrogen gas derived from steam methane reforming of the pyrolysis gases.
For the present disclosure, ‘low severity’ hydrotreating conditions are characterized by (i) a maximum temperature of at most 350 degrees Celsius or at most 340 degrees Celsius or at most 330 degrees Celsius; and (ii) a maximum pressure is at most 120 atmospheres (atm) or at most 110 atm or at most 100 atm or at most 90 atm or at most 80 atm or at most 70 atm.
For the present disclosure, unless otherwise specified, when a feature related to a portion or a fraction of a composition (e.g. of an oil) is disclosed, this refers is by weight (e.g. wt/wt %) and not by mole or by volume. For the present disclosure, unless otherwise specified concentrations and ratios therebetween are by weight (e.g. wt/wt %) and not by mole or by volume.
Embodiments of the present invention relate to a multi-stage technique for producing a light, sweet synthetic crude oil having a sulfur content of at most 1% wt/wt and a nitrogen content of at most 0.2% wt/wt from sulfur-rich type IIs kerogen without relying on external sources of hydrogen gas. Experiments conducted by the present inventors indicated that after generating hydrocarbon pyrolysis fluids by pyrolyzing type IIs kerogen having a sulfur content of at least 8% wt/wt (or higher—for example, at least 10% wt/wt or at least 12% wt/wt) nitrogen content primarily at low temperatures of at most 350° C., it is possible to hydrotreat the hydrocarbon pyrolysis fluids into a light, sweet synthetic crude oil: (i) under low severity conditions of at most 120 atmospheres and at most 350 degrees Celsius; and (ii) in a manner where at most only 180 Nm3m−3 of hydrogen gas is consumed in the hydrotreating process.
As a result of the surprisingly low consumption of hydrogen gas, it is possible to perform the hydrotreating process without requiring external sources of hydrogen gas. Instead, it is possible to rely only upon the quantities of pyrolysis hydrogen gas generated by the pyrolysis of the type IIs kerogen, without any need to steam reform pyrolysis methane gas and without any need to construct and maintain a hydrogen gas pipeline. One characteristic of the process is that it is self-sufficient with respect to hydrogen gas.
As illustrated in
The concentrations of sulfur and nitrogen for these four experiments together with the feedstock values were curve-fit as a function of hydrogen gas consumption—the results are presented in
In
As illustrated in
One salient feature of any pyrolysis process is that hydrogen gase is produced along with hydrocarbon liquids and gases. For the presently-disclosed pyrolysis process of the Ghareb formation, it is believed that the pyrolysis process yields about 900 standard cu. ft. of hydrogen gas per barrel of hydrocarbon pyrolysis liquid—in metric units this is approximately 160 Nm3/m3. As illustrated in
Thus, the data of
Although the present invention is not limited to in situ pyrolysis practices, in some preferred embodiments, the pyrolysis of the type IIs kerogen is carried out in situ. As discussed above with reference to
A plurality of heaters 220 (e.g. electrical heaters or molten salt heaters) are deployed within a target portion 284 of the hydrocarbon-containing subsurface formation 280. Thermal energy is transferred from the heaters 220 to the target portion 284 so as to heat the target portion 284 and to eventually pyrolyze kerogen therein. Formation gases and liquids are recovered via production well 224 so that (i) pyrolysis formation gases comprising acid gases, hydrogen gas, and hydrocarbon gases are received into gas separator 250 and (ii) hydrocarbon pyrolysis formation gases are received into stabilizer 254 and eventually pass into hydrotreater 258.
As noted above, the data of
As noted above, for the present disclosure, ‘low severity’ hydrotreating conditions are characterized by (i) a maximum temperature of at most 350 degrees Celsius or at most 340 degrees Celsius or at most 330 degrees Celsius; and (ii) a maximum pressure is at most 120 atmospheres (atm) or at most 110 atm or at most 100 atm or at most 90 atm or at most 80 atm or at most 70 atm.
The present inventors are now disclosing, for the first time, that surprisingly low-severity hydrotreating of pyrolysis liquids derived from sulfur-rich type IIs kerogen is sufficient for generating a low-sulfur and low-nitrogen hydrotreated oil.
As a result of the surprisingly low levels of nitrogen and sulfur obtainable at these low pressures and temperatures, it is possible to reduce the capital cost required to hydrotreat the pyrolysis fluids. In particular, it is possible to employ vessels constructed from carbon steel or other similar materials that are designed to operate only at pressures of up to 120 atmospheres, rather than relying on more expensive stainless steel vessels that are typically required at higher pressures.
It is believed that the reason that the presently-disclosed hydrocarbon pyrolysis formation liquids are surprisingly easy to hydrotreat is that they are formed mostly at low temperatures. These low temperatures favor formation of easier-to-hydrotreat species such as single-ring heterocyclic compounds, for example, a single-ring heterocyclic aromatic compound of relatively low molecular weight.
As discussed below in examples below, the hydrocarbon pyrolysis liquids of the ‘blend experiment’ were subjected to speciation analysis. The results are illustrated in
As shown in
In the chosen low-pyrolysis temperatures (e.g. between 270 and 290 degrees Celsius), the easier to hydrotreat thiophenes are produced in greatest quantity. This temperature range captures only the beginning of benzothiophene formation, and the tail-end of thiolane production. The chosen temperature range is selective against the harder to hydrotreat dibenzothiophenes.
As discussed below in examples below, the present inventors have conducted kinetics experiments related to kerogen pyrolysis kinetics. Results are presented in
Economic Advantages
As noted above, one advantage of the presently-disclosed synthetic oil derived from pyrolysis of type IIs kerogen is the ability to pyrolyze in a less sturdy but less expensive hydrotreating vessel rated to only low intensity operating conditions.
An additional advantage is the low metal content of the hydrocarbon pyrolysis liquids, discussed below in examples below. By pyrolyzing kerogen primarily at low pyrolysis temperatures, it is possible to obtain pyrolysis liquids having a lower concentration of metal contaminants than would be otherwise possible. In particular, it is believed that metals are primarily bound up in the surrounding matrix, and are less likely to be removed from this matrix to enter the pyrolysis liquids at lower temperatures.
This is extremely advantageous, since metal-free feedstock is typically much less expensive to hydrotreat than feedstock containing significant quantities of metal, since metals often poison the catalysts used to hydrotreat the feedstock. Furthermore, this obviates the need to use expensive demetalization guard beds to pretreat feedstock in refineries.
In some embodiments, the pyrolyzing of the sulfur-rich type IIs kerogen is performed at relatively low pyrolysis temperatures that do not exceed 290 degrees Celsius. For example, a majority (or significant) majority of the sulfur-rich type IIs kerogen may be pyrolyzed at the low pyrolysis temperatures.
Alternatively or additionally, it is possible to collect hydrocarbon pyrolysis fluids formed at the lower temperatures and keep these low-temperature pyrolysis fluids separate from hydrocarbon pyrolysis fluids formed at higher temperatures—i.e. preventing mixing therebetween.
Features Related to Hydotreating
A guard bed of appropriate demetalization catalyst is not needed to remove any metal ions considered to interfere with the catalysts of hydrotreating as the pyrolysis process as described above produces a hydrocarbon pyrolysis liquid that is contaminant metal-free.
The hydrotreating is preferably performed in the presence of hydrogen and a catalyst. Which catalyst can be chosen from those known to one skilled in the art as being suitable for this reaction. Catalysts for use in this step typically comprise an acidic functionality and a hydrogenation-dehydrogenation functionality. Preferred acidic functionalities are refractory metal oxide carriers. Suitable carrier materials include silica, alumina, silica-alumina, zirconia, titania and mixtures thereof. Preferred carrier materials for inclusion in the catalyst for use in the process of this invention are silica, alumina and silica-alumina. Preferred hydrogenation-dehydrogenation functionalities are Group VIII non-noble metals, for example iron, nickel and cobalt which non-noble metals may or may not be combined with a Group IVB metal, for example W or Mo, oxide promoters. The catalyst may comprise the hydrogenation/dehydrogenation metal active component in an amount of from 0.005 to 5 parts by weight, preferably from 0.02 to 2 parts by weight, per 100 parts by weight of carrier material. A particularly preferred catalyst comprises an alloy of Nickel and Molybdenum and/or Cobalt and molybdenum on an alumina carrier. If desired, applying a halogen moiety, in particular fluorine, or a phosphorous moiety to the carrier, may enhance the acidity of the catalyst carrier. The catalyst bed does not need protection by a guard bed against potential fouling due to particulates, asphaltenes, and/or metals present in the feed.
The sulfur-sulfur bonds in the kerogenous organic material break in the low temperature regime and the C—C bonds break in the high temperature regime. The resultant pyrolysis product shows greater benefit than expected. The Applicants believe that this is due to free radical formation, which initiates carbon-carbon bond cleavage catalyzing the further pyrolysis of the remaining kerogenous material.
The above description is not intended to limit the claimed invention in any manner; furthermore, the discussed combination of features might not be absolutely necessary for the inventive solution.
The present invention will be further illustrated in the following examples. However it is to be understood that these examples are for illustrative purposes only, and should not be used to limit the scope of the present invention in any manner
An 8.6 cm diameter (3.4 inch) PQ core sample of type IIs kerogen was cored from an oil shale with the following petrophysical properties: porosity of 35-40%, permeability of 0.05-0.2 mD, and total organic carbon (TOC) of 14-18 wt %. A Fischer Assay in which 100 grams of the raw rock were crushed to <2.38 mm pieces, heated to 500° C. at a rate of 120° C./min, and held at that temperature for 40 minutes was performed. The distilled vapors of oil, gas, and water are condensed and centrifuged to assess the amount of oil yielded by the rock sample. Fischer Assay results for the oil shale is 24-29 gal/ton. Elemental analysis of a specific raw rock sample from the Ghareb formation, a bituminous and kerogenous chalk, gave the kerogen composition presented in the table below.
First, Fischer Assay numbers were collected from the samples, then the API gravity of the Fischer Assay oil was measured. All measurements were reported on a dry weight basis. Samples of type IIs kerogen-bearing oil shale was crushed to 1-5 mm pieces and packed into a retort. The retort vessel chosen was a pressure-regulated semi-batch pyrolysis reactor.
The weight change of the retort system was tared, then measured every 1.5 hours. Flow measurements were also made. A gas chromatograph (GC) was run every 1.5 hours, timed to be coincident with the weight and flow measurements, to identify compounds in the pyrolysis fluids. The H2S level was measured with a Draeger tube, a colorimetric gas detection technology, downstream of the reactor and GC.
Approximately 30 experimental runs were conducted. The temperature ramps and the constant pressure for the system during a single run were varied from one run to another according to the inventors' specifications. Temperature ramps ranged from 1-4° C./hr starting from ambient temperature increasing to no higher than 430° C. with a back pressure on the system held constant at a pressure chosen from between 0-150 psig.
For example, an experiment held at 150 psig for the duration of the experiment and with a maximum temperature of 430° C., with a 1-2° C. rate was conducted as follows. The reactor/retort was heated at a rate of 1° C./min on the skin temperature up to 175° C. and held at that temperature for 1 hour minimum. From 175° C., the temperature was increased by 2° C./hr on the skin temperature until the skin temperature reached 200° C. The retort was held at this temperature until the center shale temperature reached 200° C. (Free water boils at 185° C., so the reactor pressure was carefully adjusted and from this point on, the top head heater of the retort was held at a 5-10° C. hotter temperature in order to prevent water vapors from condensing on the head.) A water product receiver was weighed every 3 hours until all of the water was removed from the retort system. Beyond 200° C., heating continued at 2° C./hr on the skin temperature. Gas was collected on another product receiver, which was also tared and weighed. When the system reached 300° C., the weight and volume of oil and water removed are measured. Oil and water were held in reserve in a sealed refrigerated container. Product collection continued with a separate product receiver. When the mid-retort shale temperature reached 430° C., the temperature was held for at least 8 hours with only the head temperature held 10° C. higher. When the N2 content reached 80% according to the GC analysis, all retort heaters were turned off. As soon as the pressure measured decreased, purging with N2 or Argon, allowed for obtaining the final oil product collection. Retort was checked for residual oil. Product samples were stored in a sealed refrigerated container. The spent shale was weighed and used to perform three Fischer Assays to compare with the initial Fischer Assay.
This procedure was performed in the same manner for samples at other pressures and temperature ramps. The samples collected from this experiment were also subjected to elemental analysis and will be discussed further below.
The pyrolysis liquid products from the various temperatures and pressures were blended to create a more accurate representation of product in the field. The properties of pyrolysis liquids blended from the aliquots collected in the procedure described above are given in
Other general observations regarding the properties of the hydrocarbon pyrolysis liquid product, compared with other shale oils, can be summarized in the three points as follows: a) the density, boiling end point and pour point are relatively low, characteristic of an overall light material, b) metal contaminants were uncommonly low, (Low levels of contaminants generally result in lower complexity and lower cost of upgrading the oil), and c) the carbon:hydrogen ratio was relatively low, which agreed with the low aromatic content.
Chromatography tests using a Pulse Flame Photometric Detector (PFPD) optimized for sulfur detection were performed to determine the identity of the sulfur-containing compounds in the hydrocarbon pyrolysis oil product. The concentrations of identifiable compounds derived from GC peak areas are summarized in
High concentrations of Fe, Ni and Cr were measured in the gasoil fraction (62, 5 and 9 ppm respectively). These values appear artificially high and caused most likely by interaction between the pyrolysis liquid product and the type-304 stainless steel column used for fractionation at the high temperature required to separate this cut. The pyrolysis liquid product used for the hydroprocessing runs in the following Example was not at risk of this contamination, since no fractionation was performed prior to the tests.
Upgrading studies focused on two main scenarios: a) full upgrading into marketable products with generation of ultra-low sulfur diesel (ULSD) as the main objective, and b) partial upgrading into synthetic crude oil (SCO), suitable for further processing at external conventional oil refineries. To fulfill objectives a) and b), different catalyst combinations and process conditions were tested, resulting in a total of five cases, as detailed in
For characterization purposes, the pyrolysis liquid product was sampled whole and also after fractionating into the following four cuts: a) Naphtha (C5-349° F. or C5-176° C.), b) Jet fuel (349-469° F. or 176-243° C.), c) Diesel (469-649° F. or 243-343° C.), d) Gasoil (649° F.+ or 343° C.+). The same cut points were used to distill and characterize the products from the upgrading tests.
The upgrading pilot tests were performed in a small downflow fixed bed reactor (micro unit) and the results reflect only start-of-run catalyst activity. The contaminant of greatest concern was C1, present at 5 ppm. While hydrotreating catalysts and desalting procedures can generally remove C1 from the feed, byproducts of this reaction, such as HCl, may cause corrosion problems to stainless steel upgrading equipment. For this reason, the hydroprocessing tests were run on a micro unit reactor, shown in
The same micro unit was used for all hydroprocessing tests. It consists of two downflow reactors in series. Liquid feed and hydrogen gas are fed in once-through mode. Each reactor is a ⅜″ OD tube (7 mm ID) which can be loaded with up to 10 cc of catalyst. The unit piping includes valves that enable bypassing the second reactor as well as operation of both reactors in series. Each reactor is placed inside a three-zone clamshell electric furnace. Temperatures are read from three skin thermocouples, each placed in the middle of each heated zone. Layers of catalyst are generally loaded in the center of the reactor, so that the entire bed fits within the middle heated zone to ensure uniform temperature across the bed Immediately after leaving the last reactor, the effluent was separated into liquids and non-condensable gases in a high-pressure separator. For this study, when operating in ultra-low sulfur diesel (ULSD) production mode (Cases 1, 2 and 3), the liquid stream flowed through two strippers in series. The strippers were operated to achieve product separation with cut points of 469 and 649° F., respectively. The overhead product of the first stripper was further separated in a condenser into light hydrocarbon gases and light hydrocarbon liquids, the latter corresponding to the combined naphtha and jet fuel products. The bottoms product of the first stripper was fed into the second stripper, where diesel was separated as overhead product and gasoil as bottoms. Off-line distillation was necessary to separate the naphtha from the jet fuel products. Only one stripper was used when operating to produce synthetic crude oil (Cases 4 and 5).
Chevron Lummus Global's commercial hydroprocessing catalysts were used for the upgrading tests, loaded in the micro unit reactors as crushed extrudates of 24-42 mesh size. Only hydrotreating and hydrocracking catalysts are considered active catalysts. Traps and hydrodemetallation (HDM) catalysts are not considered active catalysts and were included in the load simply as precaution for contaminant removal. Space velocity calculations are based only on the volume of active catalysts. Cases 1 and 2 include both hydrotreating and hydrocracking catalysts. Catalyst ICR 250 has mild hydrocracking activity and was included in the load attempting to maximize diesel yield by converting the gasoil-range material in the feed mainly by ring opening. It also has significant hydrotreating activity of its own. To run Case 2, Reactor 2 was bypassed after running Case 1, so the catalyst charge in Reactor 1 was used for Cases 1 and 2. Cases 4 and 5 focused mainly on hydrotreating to produce a synthetic crude oil of acceptable purity, as determined by the extent of removal of heteroatoms, such as sulfur, nitrogen and oxygen in the feed.
Base metal catalysts, such as the ones typically used for hydroprocessing, need to be converted into the active sulfide form before the start of any actual hydroprocessing. Sulfiding was performed in situ in the liquid phase by contacting the catalysts with a sulfiding feed containing dimethyl disulfide (DMDS) diluted in straight-run diesel. After sulfiding, the catalysts were lined out for three days by feeding straight run diesel at 650° F. and at the target reaction pressure. After the line-out period, the feed was switched to whole pyrolysis liquid product and the temperature was raised to the target reaction temperature at 50° F./hr. Process conditions for all cases are shown in
Liquid product samples from the stripper or strippers were collected daily for inspections. The gas effluent was also collected daily in a glass bulb for GC analysis. All liquid products were routinely analyzed for API gravity, hydrogen, nitrogen and sulfur content. In addition, the diesel product was tested for cloud point and aromatics concentration by SFC (supercritical fluid chromatography). Selected samples were also tested for oxygen content by NAA (neutron activation analysis). One result of interest was that inclusion of 35% hydrocracking catalyst in the reactor load did not significantly change the yield structure when compared with the load containing 100% hydrotreating catalyst. This may be a result of the unique chemical composition of the pyrolysis-liquid hydrotreating feedstock.
The presence of a hydrocracking catalyst in Case 1 does not result in significantly large differences in yield structure compared with Case 3 (
2. Conversion into Finished Products
3. Conversion into SCO
Data presented here indicate that even at the mildest conditions studied, removal of heteroatoms upon hydrotreatment is relatively straightforward; during initial planning discussions, production of SCO with 1% wt sulfur had been considered a reasonable objective. The high degree of HDS even at the mildest conditions is easily identifiable in our GC trace using a PFPD to quantify sulfur compounds in Case 5 SCO (not shown here). Afterwards, the only peak on the plot corresponds to elemental sulfur derived from the oxidation in air of residual H2S in the sample. GC analysis in the PFPD shows that sulfur removal is nearly complete after hydrotreating.
The change in quality from untreated pyrolysis liquid product to SCO can be also plotted as function of sulfur content and API gravity by adding data of Case 5 SCO to
Because the pyrolysis liquid product contains large concentrations of heteroatoms (S, N, O), upon hydrotreatment the product boiling range significantly shifts toward lighter products, such as naphtha and jet fuel. Relatively mild conditions (660° F., 1500 psig total pressure) can be used to produce synthetic crude oil (SCO) of high purity over 100% hydrotreating catalyst while consuming a moderate amount of hydrogen. This SCO is suitable for further upgrading at conventional refineries.
Elemental analysis was performed on both the hydrocarbon pyrolysis liquid product and hydrotreated oil. The hydrocarbon pyrolysis liquid product was found to be 11.5% wt and the hydrotreating product 13% wt, so roughly 1.5% wt of H2 is consumed in the hydrotreating process. The experiments conducted showed that this method produced 700-1000 scf of H2 per barrel of oil depending on conditions varying either or both temperature and pressure.
Because hydrogen availability is frequently a limiting factor in hydroprocessing operations, the pyrolysis-liquid-derived hydrotreated product properties are plotted as function of the required hydrogen consumption in
The experimental data from these studies can be used to model and optimize conditions for process design and potential future tests. Specifically, data from Cases 3 and 4 can be used to model chemical kinetics of the HDS and HDN reactions as function of temperature. Data from Cases 4 and 5 can be used to explore the pressure dependence of the same reactions.
In their simplest form, hydrodesulfurization and hydrodenitrification reactions can be empirically modeled as first order reactions. In this case, the temperature-dependent rate constant k(T) is related to the conversion of a reactant, such as sulfur or nitrogen, by an equation of the form:
k(T)=LHSV*ln(Cf/Cp)
Here, Cf refers to the reactant's concentration in the feed, Cp is the concentration in the product and LHSV is the space velocity.
The rate constant dependence on absolute temperature is given by the Arrhenius equation:
k(T)=A0exp(−Ea/RT)
Here, Ea is the activation energy of the reaction. The Arrhenius plot (ln k vs 1/T), using data from
k
2
/k
1=(pH2/pH1)x
Here, k is the reaction rate constant (HDS or HDN), pH is the hydrogen partial pressure and subindices 1 and 2 refer to two different conditions. Using data from Cases 4 and 5:
These values are within the common ranges of:
| Filing Document | Filing Date | Country | Kind |
|---|---|---|---|
| PCT/IB2013/053027 | 4/16/2013 | WO | 00 |
| Number | Date | Country | |
|---|---|---|---|
| 61668003 | Jul 2012 | US | |
| 61738393 | Dec 2012 | US | |
| 61759309 | Jan 2013 | US | |
| 61787183 | Mar 2013 | US |
| Number | Date | Country | |
|---|---|---|---|
| Parent | PCT/US13/36674 | Apr 2013 | US |
| Child | 14412698 | US |
