CA2900178C - Recovering hydrocarbons from an underground reservoir - Google Patents

Abstract

Disclosed herein is a composition for mitigating the presence of a second liquid phase in an underground hydrocarbon reservoir, in the wellbore, or in surface facilities of a solvent dominated recovery process (SDRP). A goal of mitigating the presence of the second liquid phase is to improve flow assurance in the reservoir, in the wellbore, or in surface facilities. In a SDRP, the viscosity-reducing component may be combined with a high-aromatics component, for instance one comprising at least 60 wt. % aromatics, based upon total weight of the high-aromatics component.

Description

RECOVERING HYDROCARBONS FROM AN UNDERGROUND RESERVOIR
BACKGROUND
Field of Disclosure [0001] The disclosure relates generally to the recovery of hydrocarbons. More specifically, the disclosure relates to the recovery of hydrocarbons from an underground reservoir.
Description of Related Art

[0002]
This section is intended to introduce various aspects of the art, which may be associated with the present disclosure. This discussion is believed to assist in providing a framework to facilitate a better understanding of particular aspects of the present disclosure.
Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art.

[0003]
Modern society is greatly dependent on the use of hydrocarbon resources for fuels and chemical feedstocks. Hydrocarbons are generally found in subsurface formations that can be termed "reservoirs." Removing hydrocarbons from the reservoirs depends on numerous physical properties of the subsurface formations, such as the permeability of the rock containing the hydrocarbons, the ability of the hydrocarbons to flow through the subsurface formations, and the proportion of hydrocarbons present, among other things.
Easily harvested sources of hydrocarbons are dwindling, leaving less accessible sources to satisfy future energy needs. As the prices of hydrocarbons increase, the less accessible sources become more economically attractive.

[0004]
Recently, the harvesting of oil sands to remove heavy oil has become more economical. Hydrocarbon removal from oil sands may be performed by several techniques.
For example, a well can be drilled to an oil sand reservoir and steam, hot gas, solvents, or a combination thereof, can be injected to release the hydrocarbons. The released hydrocarbons may be collected by wells and brought to the surface.

[0005] At the present time, solvent-dominated recovery processes (SDRPs) are not commonly used as commercial recovery processes to produce highly viscous oil.
Solvent-dominated means that the injectant comprises greater than 50 percent (%) by mass of solvent or that greater than 50% of the produced oil's viscosity reduction is obtained by chemical solvation rather than by thermal means. Highly viscous oils are produced primarily using thermal methods in which heat, typically in the form of steam, is added to the reservoir.
Cyclic solvent-dominated recovery processes (CSDRPs) are a subset of SDRPs. A
CSDRP
may be a non-thermal recovery method that uses a solvent to mobilize viscous oil by cycles of injection and production. One possible laboratory method for roughly comparing the relative contribution of heat and dilution to the viscosity reduction obtained in a proposed oil recovery process is to compare the viscosity obtained by diluting an oil sample with a solvent to the viscosity reduction obtained by heating the sample.

[0006] In a CSDRP, a viscosity-reducing solvent may be injected through a well into a subterranean formation, causing pressure to increase. Next, the pressure is lowered and reduced-viscosity oil is produced to the surface of the subterranean formation through the same well through which the solvent was injected. Multiple cycles of injection and production may be used.

[0007] CSDRPs may be particularly attractive for thinner or lower-oil-saturation reservoirs. In such reservoirs, thermal methods utilizing heat to reduce viscous oil viscosity may be inefficient due to excessive heat loss to the overburden and/or underburden and/or reservoir with low oil content.

[0008] References describing specific CSDRPs include: Canadian Patent No.
2,349,234 (Lim et al.); G. B. Lim et al., "Three-dimensional Scaled Physical Modeling of Solvent Vapour Extraction of Cold Lake Bitumen", The Journal of Canadian Petroleum Technology, 35(4), pp. 32-40, April 1996; G. B. Lim et al., "Cyclic Stimulation of Cold Lake Oil Sand with Supercritical Ethane", SPE Paper 30298, 1995; U.S. Patent No.
3,954,141 (Allen et al.); and M. Feali et al., "Feasibility Study of the Cyclic VAPEX
Process for Low Permeable Carbonate Systems", International Petroleum Technology Conference Paper 12833, 2008.

[0009] The family of processes within the Lim et al. references describes a particular SDRP that is also a cyclic solvent-dominated recovery process (CSDRP). These processes relate to the recovery of heavy oil and bitumen from subterranean reservoirs using cyclic injection of a solvent in the liquid state which vaporizes upon production.

[0010] With reference to Figure 1, which is a simplified diagram based on Canadian Patent No. 2,349,234 (Lim et al.), one CSDRP process is described as a single well method for cyclic solvent stimulation, the single well preferably having a horizontal wellbore portion and a perforated liner section. A vertical wellbore (1) driven through overburden (2) into reservoir (3) is connected to a horizontal wellbore portion (4). The horizontal wellbore portion (4) comprises a perforated liner section (5) and an inner bore (6). The horizontal wellbore portion comprises a downhole pump (7). In operation, solvent or viscosified solvent is driven down and diverted through the perforated liner section (5) where it percolates into reservoir (3) and penetrates reservoir material to yield a reservoir penetration zone (8). Oil dissolved in the solvent or viscosified solvent flows into the well and is pumped by downhole pump through an inner bore (6) through a motor at the wellhead (9) to a production tank (10) where oil and solvent are separated and the solvent is recycled.

[0011] Solvent dominated recovery processes (SDRPs) may produce a second liquid heavy phase. This second liquid phase may form in the reservoir or in surface facilities, which may not be advantageous and may, for instance, impair flow assurance.
Thus, there is a need for a process that mitigates the presence of this second liquid phase.
SUMMARY

[0012] It is an object of the present disclosure to provide a process that mitigates the presence of a second liquid phase.

[0013] Disclosed herein is a composition for mitigating the presence of a second liquid phase in an underground hydrocarbon reservoir, in the wellbore, or in surface facilities of a solvent dominated recovery process (SDRP). A goal of mitigating the presence of the second liquid phase is to improve flow assurance in the reservoir, in the wellbore, or in surface facilities. In a SDRP, the viscosity-reducing component may be combined with a high-aromatics component, for instance one comprising at least 60 wt. %
aromatics, based upon total weight of the high-aromatics component.

[0014] The foregoing has broadly outlined the features of the present disclosure so that the detailed description that follows may be better understood.
Additional features will also be described herein.

BRIEF DESCRIPTION OF THE DRAWINGS

[0015] These and other features, aspects and advantages of the disclosure will become apparent from the following description, appending claims and the accompanying drawings, which are briefly described below.

[0016] Fig. 1 is a schematic of a cyclic solvent-dominated recovery process.

[0017] Fig. 2 is a ternary phase diagram for bitumen, propane, and a third fluid being xylene, LCGO, or dilutent.

[0018] Fig. 3 is a graph of bitumen to solvent ratio versus time.

[0019] Fig. 4 is a graph of propane volume ratio in produced fluid versus rate ratio of diluent and total production.

[0020] Fig. 5 is a graph of propane volume ratio in produced fluid versus rate ratio of LCGO and total production.

[0021] Fig. 6 is a flow chart of process for recovering hydrocarbons.

[0022] It should be noted that the figures are merely examples and no limitations on the scope of the present disclosure are intended thereby. Further, the figures are generally not drawn to scale, but are drafted for purposes of convenience and clarity in illustrating various aspects of the disclosure.
DETAILED DESCRIPTION

[0023] For the purpose of promoting an understanding of the principles of the disclosure, reference will now be made to the features illustrated in the drawings and specific language will be used to describe the same. It will nevertheless be understood that no limitation of the scope of the disclosure is thereby intended. Any alterations and further modifications, and any further applications of the principles of the disclosure as described herein are contemplated as would normally occur to one skilled in the art to which the disclosure relates. It will be apparent to those skilled in the relevant art that some features that are not relevant to the present disclosure may not be shown in the drawings for the sake of clarity.

[0024] At the outset, for ease of reference, certain terms used in this application and their meaning, as used in this context, are set forth below. To the extent a term used herein is not defined below, it should be given the broadest definition persons in the pertinent art have given that term as reflected in at least one printed publication or issued patent. Further, the present processes are not limited by the usage of the terms shown below, as all equivalents, synonyms, new developments and terms or processes that serve the same or a similar purpose are considered to be within the scope of the present disclosure.

[0025] A "hydrocarbon" is an organic compound that primarily includes the elements of hydrogen and carbon, although nitrogen, sulfur, oxygen, metals, or any number of other elements may be present in small amounts. Hydrocarbons generally refer to components found in heavy oil or in oil sands. Hydrocarbon compounds may be aliphatic or aromatic, and may be straight chained, branched, or partially or fully cyclic.

[0026] "Bitumen" is a naturally occurring heavy oil material. Generally, it is the hydrocarbon component found in oil sands. Bitumen can vary in composition depending upon the degree of loss of more volatile components. It can vary from a very viscous, tar-like, semi-solid material to solid forms. The hydrocarbon types found in bitumen can include aliphatics, aromatics, resins, and asphaltenes. A typical bitumen might be composed of:
19 weight (wt.) percent (%) aliphatics (which can range from 5 wt. % - 30 wt.
%, or higher);
19 wt. % asphaltenes (which can range from 5 wt. % - 30 wt. %, or higher);
30 wt. % aromatics (which can range from 15 wt. % -50 wt. %, or higher);
32 wt. % resins (which can range from 15 wt. % - 50 wt. %, or higher); and some amount of sulfur (which can range in excess of 7 wt. %), based on the total bitumen weight.
In addition, bitumen can contain some water and nitrogen compounds ranging from less than 0.4 wt. % to in excess of 0.7 wt. %. The percentage of the hydrocarbon found in bitumen can vary. The term "heavy oil" includes bitumen as well as lighter materials that may be found in a sand or carbonate reservoir.

[0027] "Heavy oil" includes oils which are classified by the American Petroleum Institute ("API"), as heavy oils, extra heavy oils, or bitumens. The term "heavy oil" includes bitumen. Heavy oil may have a viscosity of about 1,000 centipoise (cP) or more, 10,000 cP
or more, 100,000 cP or more, or 1,000,000 cP or more. In general, a heavy oil has an API
gravity between 22.3 API (density of 920 kilograms per meter cubed (kg/m3) or 0.920 grams per centimeter cubed (g/cm3)) and 10.0 API (density of 1,000 kg/m3 or 1 g/cm3). An extra heavy oil, in general, has an API gravity of less than 10.0 API (density greater than 1,000 kg/m3 or 1 g/cm3). For example, a source of heavy oil includes oil sand or bituminous sand, which is a combination of clay, sand, water and bitumen.

[0028]
The term "viscous oil" as used herein means a hydrocarbon, or mixture of hydrocarbons, that occurs naturally and that has a viscosity of at least 10 cP
(centipoise) at initial reservoir conditions. Viscous oil includes oils generally defined as "heavy oil" or "bitumen". Bitumen is classified as an extra heavy oil, with an API gravity of about 100 or less, referring to its gravity as measured in degrees on the American Petroleum Institute (API) Scale. Heavy oil has an API gravity in the range of about 22.3 to about 10 . The terms viscous oil, heavy oil, and bitumen are used interchangeably herein since they may be extracted using similar processes.

[0029] In-situ is a Latin phrase for "in the place" and, in the context of hydrocarbon recovery, refers generally to a subsurface hydrocarbon-bearing reservoir. For example, in-situ temperature means the temperature within the reservoir, in another usage, an in-situ oil recovery technique is one that recovers oil from a reservoir within the earth.

[0030]
The term "subterranean formation" refers to the material existing below the Earth's surface. The subterranean formation may comprise a range of components, e.g.
minerals such as quartz, siliceous materials such as sand and clays, as well as the oil and/or gas that is extracted. The subterranean formation may be a subterranean body of rock that is distinct and continuous.
The terms "reservoir" and "formation" may be used interchangeably.

[0031]
The terms "approximately," "about," "substantially," and similar terms are intended to have a broad meaning in harmony with the common and accepted usage by those of ordinary skill in the art to which the subject matter of this disclosure pertains. It should be understood by those of skill in the art who review this disclosure that these terms are intended to allow a description of certain features described and claimed without restricting the scope of these features to the precise numeral ranges provided. Accordingly, these terms should be interpreted as indicating that insubstantial or inconsequential modifications or alterations of the subject matter described and are considered to be within the scope of the disclosure.

[0032]
The articles "the", "a" and "an" are not necessarily limited to mean only one, but rather are inclusive and open ended so as to include, optionally, multiple such elements.

[0033] "At least one," in reference to a list of one or more entities should be understood to mean at least one entity selected from any one or more of the entity in the list of entities, but not necessarily including at least one of each and every entity specifically listed within the list of entities and not excluding any combinations of entities in the list of entities. This definition also allows that entities may optionally be present other than the entities specifically identified within the list of entities to which the phrase "at least one"
refers, whether related or unrelated to those entities specifically identified. Thus, as a non-limiting example, "at least one of A and B" (or, equivalently, "at least one of A or B," or, equivalently "at least one of A and/or B") may refer, to at least one, optionally including more than one, A, with no B present (and optionally including entities other than B); to at least one, optionally including more than one, B, with no A present (and optionally including entities other than A); to at least one, optionally including more than one, A, and at least one, optionally including more than one, B (and optionally including other entities). In other words, the phrases "at least one," "one or more," and "and/or" are open-ended expressions that are both conjunctive and disjunctive in operation. For example, each of the expressions "at least one of A, B and C," "at least one of A, B, or C," "one or more of A, B, and C," "one or more of A, B, or C" and "A, B, and/or C" may mean A alone, B alone, C alone, A and B
together, A
and C together, B and C together, A, B and C together, and optionally any of the above in combination with at least one other entity.

[0034] Where two or more ranges are used, such as but not limited to 1 to 5 or 2 to 4, any number between or inclusive of these ranges is implied.

[0035] As used herein, the phrase, "for example," the phrase, "as an example,"
and/or simply the term "example," when used with reference to one or more components, features, details, structures, and/or methods according to the present disclosure, are intended to convey that the described component, feature, detail, structure, and/or method is an illustrative, non-exclusive example of components, features, details, structures, and/or methods according to the present disclosure. Thus, the described component, feature, detail, structure, and/or method is not intended to be limiting, required, or exclusive/exhaustive; and other components, features, details, structures, and/or methods, including structurally and/or functionally similar and/or equivalent components, features, details, structures, and/or methods, are also within the scope of the present disclosure.

[0036] CSDRP Process Description

[0037] While CSDRP is described in detail, the disclosure is not limited to any particular type of SDRP.

[0038] During a CSDRP, a reservoir may accommodate injected viscosity-reducing solvent and non-solvent fluid (also referred to as "additional injectants" or "non-solvent injectants") by dilating a reservoir pore space by applying an injection pressure. Dilating the reservoir pore space may be any effective mechanism for permitting viscosity-reducing solvent to enter into reservoirs filled with viscous oils when the reservoir comprises unconsolidated sand grains. The viscous oils may interchangeably be referred to as hydrocarbons. The solvent fingers into the oil sands and mixes with the viscous oil to yield a reduced viscosity mixture with higher mobility than the native viscous oil.
"Fingering" may occur when two fluids of different viscosities come in contact with one another and one fluid penetrates the other in a finger-like pattern, that is, in an uneven manner.
The primary mixing mechanism of the solvent with the oil may be dispersive mixing, not diffusion.
Injected fluid in each cycle may replace the volume of previously recovered fluid. Injected fluid in each cycle may add additional fluid to contact previously uncontacted viscous oil.
The injected fluid may comprise greater than 50% by mass of viscosity-reducing solvent.
The injection well and the production well may utilize a common wellbore.

[0039] While producing hydrocarbon during the CSDRP process, pressure may be reduced and the viscosity-reducing solvent(s), non-solvent injectant, and viscous oil may flow back to the same well in which the solvent(s) and non-solvent injectant were injected and are produced to the surface of the reservoir as produced fluid. The produced fluid may be a mixture of the viscosity-reducing solvent and viscous oil. As the pressure in the reservoir falls, the produced fluid rate may decline with time. Production of the produced fluid may be governed by any of the following mechanisms: gas drive via viscosity-reducing solvent vaporization and native gas ex-solution, compaction drive as the reservoir dilation relaxes, fluid expansion, and gravity-driven flow. The relative importance of the mechanisms depends on static properties such as viscosity-reducing solvent properties, native GOR (Gas to Oil Ratio), fluid and rock compressibility characteristics, and/or reservoir depth. The relative importance of the mechanism may depend on operational practices such as viscosity-reducing solvent injection volume, producing pressure, and/or viscous oil recovery to-date, among other factors.

[0040] During an injection/production cycle (i.e. a cycle comprising injecting an injected fluid followed by producing hydrocarbons), the volume of produced oil within the produced fluid may be above a minimum threshold to economically justify continuing the CSDRP process. The produced oil within the produced fluid may be recovered.

[0041] CSDRP Process Description - Solvent composition

[0042] The solvent may comprise a light, but condensable, hydrocarbon or mixture of hydrocarbons comprising ethane, propane, butane, or pentane. Additional injectants may include CO2, natural gas, C5+ hydrocarbons, ketones, and alcohols. Non-solvent injectants may include steam, water, non-condensable gas, or hydrate inhibitors. The injected fluid may comprise at least one of diesel, viscous oil, natural gas, bitumen, diluent, 05+
hydrocarbons, ketones, alcohols, non-condensable gas, water, biodegradable solid particles, salt, water soluble solid particles, and solvent soluble solid particles.

[0043] To reach a desired injection pressure of the injected fluid, a viscosifer and/or a solvent slurry may be used in conjunction with the solvent. The viscosifer may be useful in adjusting solvent viscosity to reach desired injection pressures at available pump rates. The viscosifer may include diesel, viscous oil, bitumen, and/or diluent. The viscosifier may be in the liquid, gas, or solid phase. The viscosifer may be soluble in either one of the components of the injected solvent and water. The viscosifer may transition to the liquid phase in the reservoir before or during production. In the liquid phase, the viscosifers are less likely to increase the viscosity of the produced fluids and/or decrease the effective permeability of the formation to the produced fluids.

[0044] The viscosifier may reduce the average distance the solvent travels from the well during an injection period. The viscosifer may act like a solvent and provide flow assurance near the wellbore and in the surface facilities in the event of asphaltene precipitation or solvent vaporization during shut-in periods. Solids suspended in the solvent slurry may comprise biodegradable solid particles, salt, water soluble solid particles, and/or solvent soluble solid particles.

[0045] The solvent may comprise greater than 50% C2-05 hydrocarbons on a mass basis. The solvent may be greater than 50 mass % propane, optionally with diluent when it is desirable to adjust the properties of the injectant to improve performance.
Wells may be subjected to compositions other than these main solvents to improve well pattern performance, for example CO2 flooding of a mature operation.

[0046] The solvent may be as described in Canadian Patent No. 2,645,267 (Chakrabarty, issued April 16, 2013). The solvent may comprise (i) a polar component, the polar component being a compound comprising a non-terminal carbonyl group; and (ii) a non-polar component, the non-polar component being a substantially aliphatic substantially non-halogenated alkane. The solvent may have a Hansen hydrogen bonding parameter of 0.3 to 1.7 (or 0.7 to 1.4). The solvent may have a volume ratio of the polar component to non-polar component of 10:90 to 50:50 (or 10:90 to 24:76, 20:80 to 40:60, 25:75 to 35:65, or 29:71 to 31:69). The polar component may be, for instance, a ketone or acetone. The non-polar component may be, for instance, a C2-C7 alkane, a C2-C7 n-alkane, an n-pentane, an n-heptane, or a gas plant condensate comprising alkanes, naphthenes, and aromatics.

[0047] The Hansen Solubility Parameter System is now described further.
In principle, each solvent has a unique set of solvency characteristics described by their Hansen parameters: D = dispersive or "non-polar" parameter; P = polar parameter; and H = hydrogen bonding parameter. Each of the parameters describes the bonding characteristic of a solvent in terms of polar, non-polar, and hydrogen bonding tendencies.
According to the Hansen Solubility Parameter System, a mathematical mixing rule can be applied in order to derive or calculate the respective Hansen parameters for a blend of solvents from knowledge of the respective parameters of each component of the blend and the volume fraction of the component in the blend. Thus according to this mixing rule:
Pblend = Vi Pi and Hblend =Vi Hi, where Vi is the volume fraction of the ith component in the blend, Pi is Hansen polar parameter for component i, Hi is the Hansen hydrogen bonding parameter for component i, and where summation is over all i components. For further details and explanation of the Hansen Solubility Parameter System see, for example, Hansen, C. M. and Beerbower, Kirk-Othmer, Encyclopedia of Chemical Technology, (Suppl.
Vol. 2nd Ed), 1971, pp 889-910 and Hansen Solubility Parameters A User's Handbook by Charles Hansen, CRC Press, 1999.

[0048] A "substantially aliphatic substantially non-halogenated alkane"
means an alkane with less than 10% by weight of aromaticity and with no more than 1 mole percent halogen atoms. In other embodiments, the level of aromaticity is less than 5, less than 3, less than 1, or 0 % by weight.

[0049] The solvent may be as described in Canadian Patent No. 2,781,273 (Chakrabarty, issued May 20, 2014). The solvent may comprise (i) an ether with 2 to 8 carbon atoms; and (ii) a non-polar hydrocarbon with 2 to 30 carbon atoms.
Ether may have 2 to 8 carbon atoms. Ether may be di-methyl ether, methyl ethyl ether, di-ethyl ether, methyl iso-propyl ether, methyl propyl ether, di-isopropyl ether, di-propyl ether, methyl iso-butyl ether, methyl butyl ether, ethyl iso-butyl ether, ethyl butyl ether, iso-propyl butyl ether, propyl butyl ether, di-isobutyl ether, or di-butyl ether. Ether may be di-methyl ether. The non-polar hydrocarbon may a C2-C30 alkane. The non-polar hydrocarbon may be a C2-05 alkane.
The non-polar hydrocarbon may be propane. The ether may be di-methyl ether and the hydrocarbon may be propane. The volume ratio of ether to non-polar hydrocarbon may be 10:90 to 90:10; 20:80 to 70:30; or 22.5:77.5 to 50:50.

[0050] CSDRP Process Description - Phase of Injected Solvent

[0051] The solvent may be injected into the well at a pressure in the underground reservoir above a liquid/vapor phase change pressure such that at least 25 mass % of the solvent enters the reservoir in the liquid phase. At least 50, 70, or even 90 mass % of the solvent may enter the reservoir in the liquid phase. The percentage of solvent that may enter the reservoir in a liquid phase may be within a range that includes or is bounded by any of the preceding examples. Injection of the solvent as a liquid may be preferred for increasing injected fluid injection pressure. When injecting the solvent as a liquid, pore dilation at high pressures is thought to be a particularly effective mechanism for permitting the solvent to enter into reservoirs filled with viscous oils when the reservoir comprises largely unconsolidated sand grains. When injecting the solvent as a liquid, higher overall injection rates than injection as a gas may be allowed.

[0052] A fraction of the solvent may be injected in the solid phase in order to mitigate adverse solvent fingering, increase injection pressure, and/or keep the average distance of the solvent closer to the wellbore than in the case of pure liquid phase injection. Less than 20 mass % of the injectant may enter the reservoir in the solid phase. Less than 10 mass %
or less than 50 mass % of the solvent may enter the reservoir in the solid phase. The percentage of solvent that may enter the reservoir in a solid phase may be within a range that includes or is bounded by any of the preceding examples. Once in the reservoir, the solid phase of the solvent may transition to a liquid phase before or during production to prevent or mitigate reservoir permeability reduction during production.

[0053] Injection of the solvent as a vapor may assist uniform solvent distribution along a horizontal well, particularly when variable injection rates are targeted. Vapor injection in a horizontal well may facilitate an upsize in the port size of installed inflow control devices (ICDs) that minimize the risk of plugging the ICDs. Injecting the solvent as a vapor may increase the ability to pressurize the reservoir to a desired pressure by lowering effective permeability of the injected vapor in a formation comprising liquid viscous oil.

[0054] The solvent volume may be injected into the well at rates and pressures such that immediately after completing injection into the injection well during an injection period, at least 25 mass % of the injected solvent is in a liquid state in the reservoir (e.g., underground).

[0055] A non-condensable gas may be injected into the reservoir to achieve a desired pressure, followed by injection of the solvent. Alternating periods of a primarily non-condensable gas with primarily solvent injection (where primarily means greater than 50 mass A of the mixture of non-condensable gas and solvent) may provide a way to maintain the desired injection pressure target. The primarily gas injection period may offset the pressure leak off observed during primarily solvent injection to reestablish the desired injection pressure. The alternating strategy of condensable gas to solvent injection periods may result in non-condensable gas accumulations in the previous established solvent pathways. The accumulation of non-condensable gas may divert the subsequent primarily solvent injection to bypassed viscous oil thereby increasing the mixing of solvent and oil in the producing well's drainage area.

[0056] A non-solvent injectant in the vapor phase, such as CO2 or natural gas, may be injected, followed by injection of a solvent. Depending on the pressure of the reservoir, it may be desirable to heat the solvent in order to inject it as a vapor. Heating of injected vapor or liquid solvent may enhance production through mechanisms described by "Boberg, T.C.
and Lantz, R.B., "Calculation of the production of a thermally stimulated well", JPT, 1613-1623, Dec. 1966. Towards the end of the injection period, a portion of the injected solvent, perhaps 25 mass % or more, may become a liquid as pressure rises.
After the targeted injection cycle volume of solvent is achieved, no special effort may be made to maintain the injection pressure at the saturation conditions of the solvent, and liquefaction may occur through pressurization, not condensation. Downhole pressure gauges and/or reservoir simulation may be used to estimate the phase of the solvent and non-solvent injectants at downhole conditions and in the reservoir. A reservoir simulation may be carried out using a reservoir simulator, a software program for mathematically modeling the phase and flow behavior of fluids in an underground reservoir. Those skilled in the art understand how to use a reservoir simulator to determine if 25 mass % of the solvent would be in the liquid phase immediately after the completion of an injection period. Those skilled in the art may rely on measurements recorded using a downhole pressure gauge in order to increase the accuracy of a reservoir simulator. Alternatively, the downhole pressure gauge measurements may be used to directly make the determination without the use of reservoir simulation.

[0057] Although a CSDRP may be predominantly a non-thermal process in that heat is not used principally to reduce the viscosity of the viscous oil, the use of heat is not excluded. Heating may be beneficial to improve performance, improve process start-up, or provide flow assurance during production. For start-up, low-level heating (for example, less than 100 C) may be appropriate. Low-level heating of the solvent prior to injection may also be performed to prevent hydrate formation in tubulars and in the reservoir.
Heating to higher temperatures may benefit recovery. Two non-exclusive scenarios of injecting a heated solvent are as follows. In one scenario, vapor solvent would be injected and would condense before it reaches the bitumen. In another scenario, a vapor solvent would be injected at up to 200 C and would become a supercritical fluid at downhole operating pressure.

[0058] CSDRP Process Description - Pore Volume

[0059] As described in Canadian Patent No. 2,734,170 (Dawson et al., issued September 24, 2013), one method of managing fluid injection in a CSDRP is for the cumulative volume injected over all injection periods in a given cycle (V
INJECTANT) to equal the net reservoir voidage (V VOIDAGE) resulting from previous injection and production cycles plus an additional volume (V ADDITIONAL), for example approximately 2-15%, or approximately 3-8%
of the pore volume (PV) of the reservoir volume associated with the well pattern. In mathematical terms, the volume (V) may be represented by:
V ¨ V + V

[0060] INIECTANT VOIDAGE ADDITIONAL

[0061] One way to approximate the net in-situ volume of fluids produced is to determine the total volume of non-solvent liquid hydrocarbon fraction produced (V PRODUCED
OIL) and aqueous fraction produced (V PRODUCED WATER) minus the net injectant fractions produced (V INJECTED SOLVENT -V PRODUCED SOLVENT)= For example, in the case where 100% of the injectant is solvent and the reservoir contains only oil and water, an equation that represents the net in-situ volume of fluids produced (V VOIDAGE) is:
VvõiõAõL = 17õ1:1"D
1?"'"" VwPARI(E"i)?("" (VINJECTED
SOLVENT L,7) 1,N"L
IC"

[0062])

[0063] Estimates of the PV are the reservoir volume inside a unit cell of a repeating well pattern or the reservoir volume inside a minimum convex perimeter defined around a set of wells in a given cycle. Fluid volume may be calculated at in-situ conditions, which take into account reservoir temperatures and pressures. If the application is for a single well, the "pore volume of the reservoir" is defined by an inferred drainage radius region around the well which is approximately equal to the distance that solvent fingers are expected to travel during the injection cycle (for example, about 30-200m). Such a distance may be estimated by reservoir surveillance activities, reservoir simulation or reference to prior observed field performance. In this approach, the pore volume may be estimated by direct calculation using the estimated distance, and injection ceased when the associated injection volume (2-15%
PV) has been reached.

[0064] As described in the aforementioned Canadian Patent No. 2,734,170, rather than measuring pore volume directly, indirect measurements can be made of other parameters and used as a proxy for pore volume.

[0065] CSDRP Process Description - Diluent

[0066] In the context of this specification, diluent means a liquid compound that can be used to dilute the solvent and can be used to manipulate the viscosity of any resulting solvent-bitumen mixture. By such manipulation of the viscosity of the solvent-bitumen (and diluent) mixture, the invasion, mobility, and distribution of solvent in the reservoir can be controlled so as to increase viscous oil production.

[0067] The diluent is typically a viscous hydrocarbon liquid, especially a C4-C20 hydrocarbon, or mixture thereof, which may be locally produced and may be used to thin bitumen to pipeline specifications. Pentane, hexane, and heptane may be components of such diluents. Bitumen itself can be used to modify the viscosity of the injected fluid, often in conjunction with ethane solvent.

[0068] The diluent may have an average initial boiling point close to the boiling point of pentane (36 C) or hexane (69 C) though the average boiling point (defined further below) may change with reuse as the mix changes (some of the solvent originating among the recovered viscous oil fractions). More than 50% by volume of the diluent has an average boiling point lower than the boiling point of decane (174 C). More than 75% by volume, such as more than 80% by volume or more than 90% by weight of the diluent, may have an average boiling point between the boiling point of pentane and the boiling point of decane.
The diluent may have an average boiling point close to the boiling point of hexane (69 C) or heptane (98 C), or even water (100 C).

[0069] More than 50% by weight of the diluent (such as more than 75% or 80% by weight or more than 90% by weight) may have a boiling point between the boiling points of pentane and decane. More than 50% by weight of the diluent may have a boiling point between the boiling points of hexane (69 C.) and nonane (151 C), particularly between the boiling points of heptane (98 C) and octane (126 C).

[0070] By average boiling point of the diluent, we mean the temperature at which half (by volume) of a starting amount of diluent has been boiled off as described in section 15.1 and shown in Table 6 of ASTM D7096-10 (Standard Test Method for Determination of the Boiling Range Distribution of Gasoline by Wide-Bore Capillary Gas Chromatography). The average boiling point can be determined by gas chromatographic methods or more tediously by distillation. Boiling points are defined as the boiling points at atmospheric pressure.

[0071] Table 1 outlines the operating ranges for certain CSDRPs. The present disclosure is not intended to be limited by such operating ranges.

[0072] Table 1. Operating Ranges for a CSDRP.
Parameter Broader Option Narrower Option Cumulative Fill-up estimated pattern pore Inject a cumulative volume in a injectant volume volume plus a cumulative 3-8% cycle, beyond a primary pressure per cycle of estimated pattern pore threshold, of 3-8% of estimated volume; or inject, beyond a pore volume.
primary pressure threshold, for a cumulative period of time (e.g. days to months); or inject, beyond a primary pressure threshold, a cumulative of 3-8% of estimated pore volume.

Injectant Main solvent (>50 mass%) Main solvent (>50 mass%) is composition, 02-Cs. Alternatively, wells may propane (03) or ethane (02).
main be subjected to compositions other than main solvents to improve well pattern performance (i.e. CO2 flooding of a mature operation or altering in-situ stress of reservoir). 002 Injectant Additional injectants may Only diluent, and only when composition, include CO2 (up to about 30 needed to achieve adequate additive mass%), 03+, viscosifiers (e.g. injection pressure. Or, a polar diesel, viscous oil, bitumen, compound having a non-terminal diluent), ketones, alcohols, carbonyl group (e.g. a ketone, for sulphur dioxide, hydrate instance acetone).
inhibitors, steam, non-condensable gas, biodegradable solid particles, salt, water soluble solid particles, or solvent soluble solid particles.
Injectant phase & Solvent injected such that at Solvent injected as a liquid, and Injection the end of the injection cycle, most solvent injected just under pressure greater than 25% by mass of fracture pressure and above the solvent exists as a liquid dilation pressure, and less than 50% by mass of Pfracture > Pinjection > Pdilation >
the injectant exists in the solid Pvapor.
phase in the reservoir, with no constraint as to whether most solvent is injected above or below dilation pressure or fracture pressure.
Injectant Enough heat to prevent Enough heat to prevent hydrates temperature hydrates and locally enhance with a safety margin, wellbore inflow consistent with Thydrate 5 C to Thydrate Boberg-Lantz mode +50 C.

Injection rate 0.1 to 10 m3/day per meter of 0.2 to 6 m3/day per meter of during completed well length (rate completed well length (rate continuous expressed as volumes of liquid expressed as volumes of liquid injection solvent at reservoir conditions). solvent at reservoir conditions).
Rates may also be designed to allow for limited or controlled fracture extent, at fracture pressure or desired solvent conformance depending on reservoir properties.
Threshold Any pressure above initial A pressure between 90% and pressure reservoir pressure. 100% of fracture pressure.
(pressure at which solvent continues to be injected for either a period of time or in a volume amount) Well length As long of a horizontal well as 500m ¨ 1500m (commercial well).
can practically be drilled; or the entire pay thickness for vertical wells.
Well Horizontal wells parallel to Horizontal wells parallel to each configuration each other, separated by some other, separated by some regular regular spacing of 20 ¨ 1000m. spacing of 50 ¨ 600m.
Also vertical wells, high angle slant wells & multi-lateral wells.
Also infill injection and/or production wells (of any type above) targeting bypassed hydrocarbon from surveillance of pattern performance.

Well orientation Orientated in any direction. Horizontal wells orientated perpendicular to (or with less than 30 degrees of variation) the direction of maximum horizontal in-situ stress.
Minimum Generally, the range of the A low pressure below the vapor producing MPP should be, on the low pressure of the main solvent, pressure (MPP) end, a pressure significantly ensuring vaporization, or, in the below the vapor pressure, limited vaporization scheme, a ensuring vaporization; and, on high pressure above the vapor the high-end, a high pressure pressure. At 500m depth with pure near the native reservoir propane, 0.5 MPa (low) ¨1.5 MPa pressure. For example, (high), values that bound the 800 perhaps 0.1 MPa kPa vapor pressure of propane.
(megapascals) ¨ 5 MPa, depending on depth and mode of operation (all-liquid or limited vaporization).
Oil rate Switch to injection when rate Switch when the instantaneous oil equals 2 to 50% of the max rate declines below the calendar rate obtained during the cycle; day oil rate (CDOR) (e.g. total Alternatively, switch when oil/total cycle length). Likely most absolute rate equals a pre-set economically optimal when the oil value. Alternatively, well is rate is at about 0.5 x CDOR.
unable to sustain hydrocarbon Alternatively, switch to injection flow (continuous or when rate equals 20-40% of the intermittent) by primary max rate obtained during the production against cycle.
backpressure of gathering system or well is "pumped off' unable to sustain flow from artificial lift. Alternatively, well is out of sync with adjacent well cycles.

Gas rate Switch to injection when gas Switch to injection when gas rate rate exceeds the capacity of exceeds the capacity of the the pumping or gas venting pumping or gas venting system.
system. Well is unable to During production, an optimal sustain hydrocarbon flow strategy is one that limits gas (continuous or intermittent) by production and maximizes liquid primary production against from a horizontal well.
backpressure of gathering system with or without compression facilities.
Oil to Solvent Begin another cycle if the Begin another cycle if the OISR
of Ratio OISR of the just completed the just completed cycle is above cycle is above 0.15 or 0.25.
economic threshold.
Abandonment Atmospheric or a value at For propane and a depth of 500m, pressure which all of the solvent is about 340 kPa, the likely lowest (pressure at vaporized.
Steps e) and f) obtainable bottomhole pressure at which well is (described below) may start the operating depth and well produced after from this point at the same or below the value at which all of the CSDRP cycles higher pressure.
propane is vaporized. Steps e) are completed) and f) (described below) may start from this point at the same or higher pressure.

[0073] In Table 1, the options may be formed by combining two or more parameters and, for brevity and clarity, each of these combinations will not be individually listed.

[0074] Composition for Mitigation of Second Phase

[0075] Proposed herein is a composition for mitigating the presence of a second liquid phase in the reservoir, in the wellbore, or in surface facilities of a SDRP. The SDRP
may or may not be cyclic, i.e. which may or may not be a CSDRP.

[0076] A goal of mitigating the presence of the second liquid phase is to improve flow assurance in the reservoir, in the wellbore, or in surface facilities.

[0077] In a SDRP, the viscosity-reducing component may be combined with a high-aromatics component, for instance one comprising at least 60 wt. %
aromatics, based upon total weight of the high-aromatics component. One suitable and inexpensive high-aromatics component is gas oil from a catalytic cracker of a hydrocarbon refining process, also known as a light catalytic gas oil (LCGO).

[0078] The LCGO may comprise primarily poly-cyclic aromatics, to make the component composition more miscible with bitumen. This can be done by co-injecting LCGO
with the viscosity-reducing component into the reservoir to reduce phase splitting in the reservoir and/or surface facilities, and/or injecting an amount of LCGO in to the wellbore and/or surface facilities to mitigate the second liquid phase formation when the pressure or temperature conditions change or to re-dissolve the second liquid phase after it forms to facilitate transporting the produced fluids. The amount of high aromatics component used may be adjusted over time.

[0079] Lab tests have shown that LCGO is capable of fully dissolving a heavy phase with a high asphaltene content (66 wt. % asphaltenes) in 6-9 hours, however, diluent is only able to dissolve <50% after 4 weeks.

[0080] Fig. 2 is ternary phase diagram for bitumen, propane and a third component.
The third component is xylene, LCGO, or diluent. Fig. 2 illustrates that LCGO
may be more effective than diluent in mitigating the second liquid phase in a propane-dominated process.
While LCGO is slightly less effective than xylene, it is more environmentally friendly and far less costly, making it potentially more commercially attractive.

[0081] An optimum ratio of viscosity-reducing component and LCGO during co-injection may be determined based on lab and/or field tests, reservoir simulation, and/or economics evaluation.

[0082] Fig. 3 shows reservoir performance (in terms of produced bitumen to injected solvent ratio) predicted by a reservoir simulation model after one short cycle of co-injection of propane with diluent (88 vol. % propane and 12 vol. % diluent or LCGO). The diluent case is based on a model history-matched to field data. The same model predicts that LCGO would generate approximately 20% uplift in oil recovery.

[0083] The ratio of LCGO added in wellbore or surface facilities to produced fluid may be determined from the composition of the produced fluid to minimize formation of second liquid phase. This ratio may be adjusted at different stages of the production through reservoir and facility surveillance. Figs. 4 and 5 provide a comparison of the effectiveness of diluent and LCGO in mitigating the second liquid phase formed in a pipeline condition and also an illustration of how to determine the high aromatics component rate based on the produced fluid composition and production rate.

[0084] In particular, Figs. 4 and 5 show the heavy phase volume percentages for different propane volume ratios in the produced fluid when utility diluent or LCGO is injected at surface (at a certain rate relative to the total production rate) at pressure and temperature (PIT) lower than those at the reservoir condition. These figures are provided as an illustration for a given PR'. Similar technical analysis can be performed for other PIT
conditions.

[0085] The propane ratio in the produced fluid can be determined from reservoir surveillance, for example from produced density measurement or compositional analysis.
Facility surveillance also provides pressure and temperature (PIT) in surface facilities and pipelines, through pressure/temperature transmitters. Based on the propane ratio in the produced fluid and the PIT conditions, one can determine how much heavy liquid phase may be formed for any given amount of diluent or LCGO added to the produced liquid.
Depending upon the facility tolerance of second liquid phase, one can determine the amount of LCGO needed to achieve that. For example, with reference to Figs. 4 and 5, to fully mitigate a second liquid phase, a reasonable amount of diluent alone will not be sufficient when the propane volume ratio is between 0.3-0.5, however, it can be achieved with a maximum 20 mol % LCGO added to the production.

[0086] A solvent composition, for use in a solvent dominated recovery process for recovering hydrocarbons from an underground reservoir to improve reservoir or wellbore flow assurance, may comprise at least 50 mol % of a viscosity-reducing component (based upon total moles of the solvent composition) and at least 5 mol % of a high-aromatics component (based upon total moles of the solvent composition) comprising at least 60 wt.
% aromatics (based upon total mass of the high-aromatics component). The high-aromatics component may comprise LCGO.

[0087] The LCGO may comprise at least 60 wt. % aromatics, wherein at least half of the aromatics by weight are two-ring or three-ring aromatics; less than 20 wt.
% paraffins;
and less than 20 wt. % cycloparaffins, all based upon total weight of the LCGO. The aromatics may comprise at least 10 wt. % alkybenzenes; at least 5 wt. %
combined indans, tetralins, and indenes; at least 30 wt. % naphthalenes; and at least 5 wt. %
combined acenaphthenes, acenaphthalenes, and tricyclicaromatics, all based upon total weight of the LCGO.

[0088] The LCGO may have an API gravity of 15 to 35 degrees. The LCGO may have a boiling point of greater than 150 C. The LCGO may have a solubility blending number greater than 80 when blending with bitumen at a 1:1 volume ratio. The LCGO may not precipitate asphaltene when mixed with bitumen at any blending ratio. The API gravity is measured by ASTM D1298. The "solubility blending number" is described in I. A.
Wiehe and R. J. Kennedy, Energy & Fuels, 14, 56 ¨ 63 (2000).

[0089] The viscosity-reducing component may comprise ethane, propane, butane, pentane, heptane, hexane, dimethyl ether, or a combination thereof. The viscosity-reducing component may comprise ethane, propane, butane, pentane, or a combination thereof. The viscosity-reducing component may comprise ethane or propane.

[0090] The viscosity-reducing component may comprise (i) a polar component, the polar component being a compound comprising a non-terminal carbonyl group; and (ii) a non-polar component, the non-polar component being a substantially aliphatic substantially non-halogenated alkane; wherein the viscosity-reducing component has a Hansen hydrogen bonding parameter of 0.3 to 1.7; and wherein the viscosity-reducing component has a volume ratio (a):(b) of 10:90 to 50:50. The Hansen hydrogen bonding parameter may be 0.7 to 1.4. The volume ratio may be 10:90 to 24:76, or 20:80 to 40:60, or 25:75 to 35:65, or 29:71 to 31:69. The polar component may be a ketone. The polar component may be acetone. The non-polar component may be a 02-07 alkane, a 02-07 n-alkane, n-pentane, n-heptane, or a gas plant condensate comprising alkanes, naphthenes, and aromatics.

[0091] The viscosity-reducing component may comprise (i) an ether with 2 to 8 carbon atoms; and (ii) a non-polar hydrocarbon with 2 to 30 carbon atoms. The ether may have 2 to 4 carbon atoms. The ether may be di-methyl ether, methyl ethyl ether, di-ethyl ether, methyl iso-propyl ether, methyl propyl ether, di-isopropyl ether, di-propyl ether, methyl iso-butyl ether, methyl butyl ether, ethyl iso-butyl ether, ethyl butyl ether, iso-propyl butyl ether, propyl butyl ether, di-isobutyl ether, or di-butyl ether. The ether may be di-methyl ether. The non-polar hydrocarbon may a 02-030 alkane, a 02-05 alkane, or propane. The ether may be di-methyl ether and the non-polar hydrocarbon may be propane. The component may have a volume ratio of the ether to the non-polar hydrocarbon of 10:90 to 90:10, or 20:80 to 70:30, or 22.5:77.5 to 50:50.

[0092] The compositions described herein may be used in a solvent dominated recovery process for recovering hydrocarbons from an underground reservoir.

[0093] Light catalytic gas oil (LCGO) may be used for assisting wellbore flow assurance of produced fluids in a solvent dominated recovery process.

[0094] A composition comprising at least 10 mol % of a high-aromatics component, based upon total weight of the composition, comprising at least 60 wt. %
aromatics, based upon total weight of the aromatics, together with a viscosity-reducing component may be used in a solvent dominated recovery process for blending with produced hydrocarbons to improve facility or pipeline flow assurance, wherein the produced hydrocarbons comprise injected viscosity-reducing component.

[0095] A high-aromatics component comprising more than 60 wt. %
aromatics, based upon total weight of the high-aromatics component, may be used for blending with produced hydrocarbons from a solvent dominated recovery process for recovering hydrocarbons from an underground reservoir, for improving facility or pipeline flow assurance, wherein the produced hydrocarbons comprise injected viscosity-reducing component.

[0096] A light catalytic gas oil (LCGO) may be used for assisting flow assurance in surface facilities of a solvent dominated recovery process.

[0097] With reference to Fig. 6, a cyclic solvent-dominated recovery process, for recovering hydrocarbons from an underground reservoir, may comprise: (a) injecting injected fluid into an injection well completed in the underground reservoir (602), wherein the injected fluid comprises the composition as described herein; (b) halting injection into the injection well and subsequently producing at least a fraction of the injected fluid and the hydrocarbons from the underground reservoir through a production well (604); (c) halting production through the production well (606); and (d) repeating the cycle of steps (a) to (c) (608). The injection well and the production well may utilize a common wellbore. The hydrocarbons may be a viscous oil having a viscosity of at least 10 cP at initial reservoir conditions. The injected fluid may comprise diesel, viscous oil, natural gas, bitumen, diluent, C5+
hydrocarbons, ketones, alcohols, non-condensable gas, water, biodegradable solid particles, salt, water soluble solid particles, solvent soluble solid particles, or a combination thereof.
The injected fluid may comprise at least 25 mass % liquid at the end of an injection cycle, based upon total mass of the injected fluid. The injected fluid may comprise less than 50 mass A liquid at the end of an injection cycle, based upon total mass of the injected fluid. At least 25 mass % of the viscosity-reducing component in an injection cycle may enter the reservoir as a liquid, based upon total mass of the viscosity-reducing component. At least 25 mass % of the viscosity-reducing component at the end of an injection cycle may be a liquid, based upon total mass of the viscosity-reducing component. An in-situ volume of fluid injected over a cycle may be equal to a net in-situ volume of fluids produced from the production well summed over all preceding cycles plus an additional in-situ volume of fluid.
The additional in-situ volume of fluid may be, at reservoir conditions, equal to 2% to 15% of a pore volume within a reservoir zone around the injection well within which solvent fingers are expected to travel during the cycle. An LCGO injection rate into the surface facilities to mix with the produced hydrocarbon liquid may be determined by: a produced hydrocarbon rate, a produced hydrocarbon composition, and a facility temperature and pressure, in order to mitigate formation of second liquid phase in the facilities.

[0098] A
light catalytic gas oil (LCGO) may be used for removing asphaltenes from surface facilities of a solvent dominated recovery process or upstream of a pig to assist pigging of a pipeline.

[0099] It should be understood that numerous changes, modifications, and alternatives to the preceding disclosure can be made without departing from the scope of the disclosure. The preceding description, therefore, is not meant to limit the scope of the disclosure. Rather, the scope of the disclosure is to be determined only by the appended claims and their equivalents. It is also contemplated that structures and features in the present examples can be altered, rearranged, substituted, deleted, duplicated, combined, or added to each other.

Claims (68)

CLAIMS:

1. A solvent composition for use in a solvent dominated recovery process for recovering hydrocarbons from an underground reservoir to improve reservoir or wellbore flow assurance, the solvent composition comprising:
a. at least 50 mol % of a viscosity-reducing component, based upon total moles in the solvent composition; and b. at least 5 mol % of a high-aromatics component, based upon total moles in the solvent composition wherein the high-aromatics component comprises at least 60 wt. %
aromatics, based upon total weight of the high-aromatics component.

2. The composition of claim 1, wherein the high-aromatics component comprises light catalytic gas oil (LCGO).

3. The composition of claim 2, wherein the LCGO comprises:
a. at least 60 wt. % aromatics, wherein at least half of the aromatics by weight are two-ring or three-ring aromatics;
b. less than 20 wt. % paraffins; and c. less than 20 wt. % cycloparaffins, all based upon total weight of the LCGO.

4. The composition of claim 3, wherein the aromatics comprise:
a. at least 10 wt. % alkybenzenes;
b. at least 5 wt.% combined indans, tetralins, and indenes c. at least 30 wt. % naphthalenes; and d. at least 5 wt. % combined acenaphthenes, acenaphthalenes, and tricyclicaromatics, all based upon total weight of the aromatics.

5. The composition of any one of claims 2 to 4, wherein the LCGO has an API
gravity of 15 to 35 degrees.

6. The composition of any one of claims 2 to 5, wherein the LCGO has a boiling point of greater than 150 C.

7. The composition of any one of claims 2 to 6, wherein the LCGO has a solubility blending number greater than 80 when blending with bitumen at a 1:1 volume ratio.

8. The composition of any one of claims 2 to 7, wherein the LCGO does not precipitate asphaltene when mixed with bitumen at any blending ratio.

9. The composition of any one of claims 1 to 8, wherein the viscosity-reducing component comprises ethane, propane, butane, pentane, heptane, hexane, dimethyl ether, or a combination thereof.

10. The composition of any one of claims 1 to 8, wherein the viscosity-reducing component comprises ethane, propane, butane, pentane, or a combination thereof.

11. The composition of any one of claims 1 to 8, wherein the viscosity-reducing component comprises ethane or propane.

12. The composition of any one of claims 1 to 8, wherein the viscosity-reducing component comprises:
a polar component, the polar component being a compound comprising a non-terminal carbonyl group; and (ii) a non-polar component, the non-polar component being a substantially aliphatic substantially non-halogenated alkane;
wherein the viscosity-reducing solvent has a Hansen hydrogen bonding parameter of 0.3 to 1.7; and wherein the viscosity-reducing solvent has a volume ratio (i): (ii) of 10:90 to 50:50.

13. The composition of claim 12, wherein the Hansen hydrogen bonding parameter is 0.7 to 1.4.

14. The composition of claim 12, wherein the volume ratio is 10:90 to 24:76.

15. The composition of claim 12, wherein the volume ratio is 20:80 to 40:60.

16. The composition of claim 12, wherein the volume ratio is 25:75 to 35:65.

17. The composition of claim 12, wherein the volume ratio is 29:71 to 31:69.

18. The composition of any one of claims 12 to 17, wherein the polar component is a ketone.

19. The composition of any one of claims 12 to 17, wherein the polar component is acetone.

20. The composition of any one of claims 12 to 19, wherein the non-polar component is a C2-C7 alkane.

21. The composition of any one of claims 12 to 19, wherein the non-polar component is a C2-C7 n-alkane.

22. The composition of any one of claims 12 to 19, wherein the non-polar component is an n-pentane.

23. The composition of any one of claims 12 to 19, wherein the non-polar component is an n-heptane.

24. The composition of any one of claims 12 to 19, wherein the non-polar component is a gas plant condensate comprising alkanes, naphthenes, and aromatics.

25. The composition of any one of claims 1 to 8, wherein the viscosity-reducing component comprises:
(i) an ether with 2 to 8 carbon atoms; and (ii) a non-polar hydrocarbon with 2 to 30 carbon atoms.

26. The composition of claim 25, wherein the ether has 2 to 4 carbon atoms.

27. The composition of claim 25, wherein the ether is di-methyl ether, methyl ethyl ether, di-ethyl ether, methyl iso-propyl ether, methyl propyl ether, di-isopropyl ether, di-propyl ether, methyl iso-butyl ether, methyl butyl ether, ethyl iso-butyl ether, ethyl butyl ether, iso-propyl butyl ether, propyl butyl ether, di-isobutyl ether, or di-butyl ether.

28. The composition of claim 25, wherein the ether is di-methyl ether.

29. The composition of any one of claims 25 to 28, wherein the non-polar hydrocarbon is a C2-C30 alkane.

30. The composition of any one of claims 25 to 28, wherein the non-polar hydrocarbon is a C2-05 alkane.

31. The composition of any one of claims 25 to 28, wherein the non-polar hydrocarbon is propane.

32. The composition of claim 25, wherein the ether is di-methyl ether and the non-polar hydrocarbon is propane.

33. The composition of any one of claims 25 to 32, wherein the viscosity-reducing component has a volume ratio of the ether to the non-polar hydrocarbon of 10:90 to 90:10.

34. The composition of claim 33, wherein the volume ratio of the ether to the non-polar hydrocarbon is 20:80 to 70:30.

35. The composition of claim 33, wherein the volume ratio of the ether the non-polar hydrocarbon is 22.5:77.5 to 50:50.

36. A use of the composition of any one of claims 1 to 35, in a solvent dominated recovery process for recovering hydrocarbons from an underground reservoir.

37. A use of a light catalytic gas oil (LCGO) for assisting wellbore flow assurance of produced fluids in a solvent dominated recovery process.

38. A composition for use in a solvent dominated recovery process for blending with produced hydrocarbons to improve facility or pipeline flow assurance, wherein:
a. the produced hydrocarbons comprise injected viscosity-reducing component;
and b. the composition comprises at least 10 mol % of a high-aromatics component, based on total moles of the composition, comprising at least 60 wt. %
aromatics, based on total weight of the high-aromatics component, together with a viscosity-reducing component.

39. The composition of claim 38, wherein the high-aromatics component comprises light catalytic gas oil (LCGO).

40. The composition of claim 39, wherein the LCGO comprises:
a. at least 60 wt. % aromatics, wherein at least half of the aromatics by weight are two-ring or three-ring aromatics;
b. less than 20 wt. % paraffins; and c. less than 20 wt. % cycloparaffins, all based upon total weight of the LCGO.

41. The composition of claim 40, wherein the aromatics comprise:
a. at least 10 wt. % alkybenzenes;
b. at least 5 wt.% combined indans, tetralins, and indenes c. at least 30 wt. % naphthalenes; and d. at least 5 wt. % combined acenaphthenes, acenaphthalenes, and tricyclicaromatics all based upon total weight of the aromatics.

42. The composition of any one of claims 39 to 41, wherein the LCGO has an API gravity of 15 to 35 degrees.

43. The composition of any one of claims 39 to 42, wherein the LCGO has a boiling point of greater than 150°C.

44. The composition of any one of claims 39 to 43, wherein the LCGO has a solubility blending number greater than 80 when blending with bitumen at a 1:1 volume ratio.

45. The composition of any one of claims 39 to 44, wherein the LCGO does not precipitate asphaltene when mixed with bitumen at any blending ratio.

46. A use of a high-aromatics component comprising more than 60 wt. %
aromatics for blending with produced hydrocarbons from a solvent dominated recovery process for recovering hydrocarbons from an underground reservoir, for improving facility or pipeline flow assurance, wherein the produced hydrocarbons comprise injected viscosity-reducing component.

47. The use of claim 46, wherein the high-aromatics component comprises light catalytic gas oil (LCGO).

48. The use of claim 47, wherein the LCGO comprises:
a. at least 60 wt. % aromatics, wherein at least half of the aromatics by weight are two-ring or three-ring aromatics;
b. less than 20 wt. % paraffins; and c. less than 20 wt. % cycloparaffins all based upon total weight of the LCGO.

49. The use of claim 48, wherein the aromatics comprise:
a. at least 10 wt. % alkybenzenes;
b. at least 5 wt.% combined indans, tetralins, and indenes c. at least 30 wt. % naphthalenes; and d. at least 5 wt. % combined acenaphthenes, acenaphthalenes, and tricyclicaromatics all based upon total weight of the aromatics.

50. The use of any one of claims 47 to 49, wherein the LCGO has an API
gravity of 15 to 35 degrees.

51. The use of any one of claims 47 to 50, wherein the LCGO has a boiling point of greater than 150°C.

52. The use of any one of claims 47 to 51, wherein the LCGO has a solubility blending number greater than 80 when blending with bitumen at a 1:1 volume ratio.

53. The use of any one of claims 47 to 52, wherein the LCGO does not precipitate asphaltene when mixed with bitumen at any blending ratio.

54. The use of any one of claims 47 to 53, wherein the LCGO does not precipitate asphaltene when mixed with bitumen at any blending ratio.

55. A use of a light catalytic gas oil (LCGO) for assisting flow assurance in surface facilities of a solvent dominated recovery process.

56. A cyclic solvent-dominated recovery process for recovering hydrocarbons from an underground reservoir, the cyclic solvent-dominated recovery process comprising:
(a) injecting injected fluid into an injection well completed in the underground reservoir, wherein the injected fluid comprises the composition of any one of claims 1 to 35;
(b) halting injection into the injection well and subsequently producing at least a fraction of the injected fluid and the hydrocarbons from the underground reservoir through a production well;
(c) halting production through the production well; and (d) repeating the cycle of steps (a) to (c).

57. The process of claim 56, wherein the injection well and the production well utilize a common wellbore.

58. The process of claim 56 or 57, wherein the hydrocarbons are a viscous oil having a viscosity of at least 10 cP at initial reservoir conditions.

59. The process of any one of claims 56 to 58, wherein the injected fluid comprises diesel, viscous oil, natural gas, bitumen, diluent, C5+ hydrocarbons, ketones, alcohols, non-condensable gas, water, biodegradable solid particles, salt, water soluble solid particles, solvent soluble solid particles, or a combination thereof.

60. The process of any one of claims 56 to 59, wherein the injected fluid comprises at least 25 mass % liquid at the end of an injection cycle.

61. The process of any one of claims 56 to 60, wherein the injected fluid comprises less than 50 mass % liquid at the end of an injection cycle.

62. The process of any one of claims 56 to 59, wherein at least 25 mass %
of the viscosity-reducing component in an injection cycle enters the reservoir as a liquid, based upon total weight of the viscosity-reducing component.

63. The process of any one of claims 56 to 59, wherein at least 25 mass %
of the viscosity-reducing component at the end of an injection cycle is a liquid, based upon total weight of the viscosity-reducing component.

64. The process of any one of claims 56 to 63, wherein an in-situ volume of fluid injected over a cycle is equal to a net in-situ volume of fluids produced from the production well summed over all preceding cycles plus an additional in-situ volume of fluid.

65. The process of claim 64, wherein the additional in-situ volume of fluid is, at reservoir conditions, equal to 2% to 15% of a pore volume within a reservoir zone around the injection well within which solvent fingers are expected to travel during the cycle.

66. The use of claim 46, wherein an LCGO injection rate into the surface facilities to mix with the produced hydrocarbon liquid is determined by:

a. a produced hydrocarbon rate;
b. a produced hydrocarbon composition; and c. a facility temperature and pressure;
in order to mitigate formation of second liquid phase in the facilities.

67. A use of a light catalytic gas oil (LCGO) for removing asphaltenes from surface facilities of a solvent dominated recovery process.

68. A use of a light catalytic gas oil (LCGO) upstream of a pig to assist pigging of a pipeline.