Optical method for determining fouling of crude and heavy fuels

A method for detecting the formation of at least one phase in a mixture, particularly a hydrocarbon mixture. The method may include using a probe to expose a portion of the mixture to electromagnetic radiation to determine the value of a parameter of interest indicative of the formation of a phase. The method may also include using the value of the parameter of interest with a correlation between a known property of the mixture and the value of a parameter of interest to detect the formation of a phase.

FIELD OF THE DISCLOSURE

This disclosure generally relates to transportation, storage and mixing of hydrocarbons and, in particular, detecting solubility changes within a hydrocarbon mixture.

BACKGROUND OF THE DISCLOSURE

Hydrocarbon mixtures, such as crude oils and heavy fuel oils, with a general phase may be subject to physical properties changes such as solubility due to a series of operational parameters, such as temperature, pressure, and blending with different fluids such as hydrocarbon mixtures, water, and other liquids that may adversely affect the solubility of the resulting mixture, etc. Hydrocarbon mixtures may include hydrocarbons that may form hydrates when exposed to a variety of conditions, particularly a combination of lower temperature and higher pressure, in the presence of water. Hydrate solids (or crystals) may cause plugging and/or blockage of pipelines or transfer lines or other conduits, valves and/or safety devices and/or other equipment, resulting in shutdown, loss of production and risk of explosion or unintended release of hydrocarbons into the environment either on-land or off-shore.

Hydrocarbon hydrates are clathrates, and are also referred to as inclusion compounds. Clathrates are cage structures formed between a host molecule and a guest molecule. A hydrocarbon hydrate generally is composed of crystals formed by water host molecules surrounding the hydrocarbon guest molecules. The smaller or lower-boiling hydrocarbon molecules, particularly C1(methane) to C4hydrocarbons and their mixtures, are more problematic because it is believed that their hydrate or clathrate crystals are easier to form. For instance, it is possible for ethane to form hydrates at as high as 4° C. at a pressure of about 1 MPa. If the pressure is about 3 MPa, ethane hydrates can form at as high a temperature as 14° C. Even certain non-hydrocarbons such as carbon dioxide, nitrogen and hydrogen sulfide are known to form hydrates under the proper conditions.

Solubility variations in hydrocarbon mixtures may have objectionable effects on the mixture as a whole, such as when impurities drop out of the general phase to form undesirable precipitates, such as flocculation of asphaltenes (forming the additional phase), such as fouling scale deposits, etc. These impurities may precipitate out of the mixture or remain suspended. While remaining as an additional phase, the impurities may aggregate into substantial masses that may foul piping, storage facilities, and processing units as well as degrade the quality of the mixture. When a hydrocarbon mixture has formed an additional phase with objectionable properties, the mixture may be characterized as “unstable” or as “demonstrating instability.”

Additives may be introduced to hydrocarbon mixtures to prevent or inhibit formation or aggregation of the additional phase (such as flocculated asphaltenes) and to restore stability to the hydrocarbon mixture. However, detection of formation of an additional phase generally must occur quickly to avoid aggregation of the additional phase into a substantial mass. On the other hand, since the additive is likely to be relatively expensive, the decision to introduce an additive, and a minimum appropriate amount of the additive, should be made judiciously. Hence, it is desirable to continuously monitor hydrocarbon mixtures for the aggregation of asphaltenes, and other substances that may form substantial masses within the hydrocarbon mixture, so that additives may be introduced quickly to mitigate problems due the flocculation of substances and their aggregation. It is also desirable to control or prevent the formation of an additional phase by identifying ratios of blend components such that stability of the hydrocarbon mixture is preserved.

SUMMARY OF THE DISCLOSURE

In aspects, this disclosure generally relates to transportation, storage, and mixing of hydrocarbons involving, particularly monitoring, hydrocarbons for preventing, mitigating, and monitoring the formation of phases that may result in fouling and/or instability.

One embodiment according to the present disclosure may include a method for detecting phase formation in a hydrocarbon mixture comprising: detecting formation of a second phase in the hydrocarbon mixture with a first phase using data from a probe and a known property of the hydrocarbon mixture.

Another embodiment according to the present disclosure may include a computer-readable medium product having stored thereon instructions that, when executed by at least one processor, perform a method, the method comprising: detecting formation of a second phase in a hydrocarbon mixture with a first phase using data from a probe and a known property of the hydrocarbon mixture.

Another embodiment according to the present disclosure may include a method for detecting phase formation in a hydrocarbon mixture, comprising: detecting formation of a second phase in a substance with a first phase by comparing a change in a parameter of interest of the hydrocarbon mixture, estimated by a probe, by a selected threshold.

Examples of the more important features of the disclosure have been summarized rather broadly in order that the detailed description thereof that follows may be better understood and in order that the contributions they represent to the art may be appreciated.

DETAILED DESCRIPTION OF THE DISCLOSURE

The present disclosure relates to methods and apparatuses for detecting the formation of phases in hydrocarbons that may cause or lead to fouling of a hydrocarbon mixture. The present disclosure also relates to methods and apparatuses for preventing the formation of phases in hydrocarbons. The hydrocarbon mixture, when fouled, may be viewed as a colloidal suspension, wherein the colloidal suspension may have two phases: an internal phase of solids or other matter, and a continuous phase that suspends the solids or other matter. The continuous phase of the colloidal suspension may be similar to the general phase or “first phase” of the hydrocarbon mixture prior to formation of an additional phase, also called herein an “internal phase” or “second phase.” Herein “fouling” refers to the undesirable formation of an internal phase within the continuous phase of the hydrocarbons. In other aspects, the hydrocarbon mixture, when fouled, may take on the characteristics of a solution undergoing precipitation, again with an internal phase of solids at least temporarily suspended by a continuous phase. With fouling, the internal phase may demonstrate objectionable properties, such as high viscosity, clumping, and aggregation. Internal phases formed in hydrocarbon mixtures may include, but are not limited to, asphaltenes, scale, solids, polynuclear aromatics, and hydrocarbon hydrates. An internal phase may be formed by several mechanisms including, but not limited to, precipitation, aggregation, matrix destabilization, nucleation, solubility changes and coagulation.

The internal phase may demonstrate properties different from the properties of the continuous phase, and these differences may be identified optically, such as by absorption or diffusion of electromagnetic radiation. Detection of fouling may be performed by analyzing a parameter of interest of the hydrocarbons. Parameters of interest may include, but are not limited to, relative permittivity, refractive index, dielectric constant, electrical conductivity, ultrasound scattering, viscosity, electromagnetic radiation absorption, electromagnetic radiation diffusion, stability of continuous phase, optical or microscopical detection of the formation of the internal phase, absorption changes, conductivity, and viscosity. One of skill in the art with the benefit of this disclosure will see that the parameters of interest may be used to identify internal phase formations in fluids that are: (i) non-hydrocarbon mixtures, (ii) only partially made up of hydrocarbons, and (iii) non-mixtures whether containing hydrocarbons or not.

In some embodiments, the parameter of interest of a substance may be the refractive index. A refractive index, n, of a medium may be defined as the ratio of the speed, c, of a wave phenomenon, such as electromagnetic radiation or sound, in a reference medium to the phase speed, νp, of the wave in the medium in question:

In the context of electromagnetic radiation,
n=√{square root over (∈rμr)}  (2)
where ∈ris the relative permittivity of the medium and μris the relative permeability of the medium. For most materials, μris close to 1, however, ∈rmay vary with temperature, pressure, and chemical changes. Since μrmay be relatively uniform, for some substances, changes in the relative permittivity, ∈r, may be used to identify the formation of an internal phase.

Relative permittivity of a substance may have complex characteristics, such that relative permittivity may be expressed in terms of a real component and an imaginary component, when an electromagnetic field with frequency ω is applied to the substance. The complex permittivity may be expressed as:
{circumflex over (∈)}(ω)=∈′(ω)+i∈″(ω)  (3)

where ∈″ is the imaginary part of the relative permittivity, which is related to the dissipation (or loss) of energy within the medium, and ∈′ is the real part of the relative permittivity, which is related to the stored energy within the medium. In some embodiments, the formation of an internal phase may be detected by a change in the real component of relative permittivity. The real part of the permittivity may be obtained from the signal intensity change in the interference pattern. This signal can be monitored and correlated with the imaginary part of the permittivity.

In real materials, the polarization does not respond instantaneously to an applied field. This causes dielectric loss, which can be expressed by a permittivity that is both complex and frequency dependent. Real materials are not perfect electrical insulators either (i.e. they have non-zero direct current conductivity). Taking both aspects into consideration, a complex index of refraction can be defined:
ñ=n+iκ
Here, n is the refractive index indicating the phase speed, while κ is called the extinction coefficient, which indicates the amount of absorption loss when the electromagnetic wave propagates through the material. Both n and K are dependent on the frequency (wavelength). Note that the sign of the complex part is a matter of convention, which is important due to possible confusion between loss and gain.

FIG. 1Ashows an exemplary embodiment of a probe for detecting a value of a parameter of interest according to the present disclosure. The probe100may include a housing or body110that may contain, or serve as, a conduit for an electromagnetic source180(FIG. 1B). A reflector120may be disposed on the housing110such that electromagnetic radiation may be reflected back into the housing110after passing through a gap130between the housing110and reflector120. The gap130is formed from at least one open space between the housing110and the reflective surface125of reflector120such that fluid140may intervene between the electromagnetic radiation and the reflector120. Fluid140may be a mixture that includes one or more of: (i) a hydrocarbon and (ii) a non-hydrocarbon. The housing110may also contain a sensor190(FIG. 1B) to measure the reflected electromagnetic signal that has passed through fluid140across gap130and returned across gap130after contacting reflector120. In some embodiments, housing110may include an optical cable. Herein, “optical” refers to the electromagnetic domain, including, but not limited to, visible light, infrared light, and ultraviolet light, together with coherent and incoherent light. In some embodiments, a sensor (not shown), replacing or in addition to sensor190, may be disposed next to or replace reflector120, such that one path of the electromagnetic radiation only passes through fluid140once before reaching a sensor (not shown). Gap130may be formed by one or more slits, holes, or other passages in the reflector120, housing110, both, or by a disposing the reflector120and housing110so as to leave a space between them. In some embodiments, gap130may be dimensioned to allow free flow of fluid140between housing110and reflector120. In some embodiments, gap130may be dimensioned such that capillary action may draw a portion of fluid140into gap130. In one embodiment, gap130may be dimensioned to have a narrow dimension of about 16 micrometers across, in a non-limiting embodiment. Gap130may be dimensioned based on the coherence length of the electromagnetic signal generated by electromagnetic source180. Indeed, it was surprisingly discovered that a probe100having a very small slit or gap130on the order of only about 16 micrometers across was able to draw within it relatively viscous mixtures such as crude oil, heavy crude oil, #6 oils, diesel oil, bunker fuel oil, and fuel oil. In some embodiments, gap130may not be uniform in depth across its length and/or width. In some embodiments, the gap130may be dimensioned based on the intensity or frequency of electromagnetic radiation generated by electromagnetic source180. In some embodiments, electromagnetic source180may generate one or more of: (i) a coherent light beam, (ii) a collimated light beam, and (iii) a non-collimated light beam.

FIG. 1Bshows another orientation of the exemplary embodiment100fromFIG. 1A. InFIG. 1B, electromagnetic source180and sensor190are shown disposed at one end of housing110. A light beam160emitted from electromagnetic source180is shown passing through fluid140in gap130to be reflected by reflector120. The reflected beam170then passes through fluid140in gap130to reach sensor190. Housing110may be hollow or partially or completely filled with one or more substances that are transparent to the passage of the electromagnetic beams160. The positions of electromagnetic source180and sensor190are illustrative and exemplary only, as the electromagnetic source180and/or sensor190may be disposed within housing110or in another position relative to the housing110. Electromagnetic source180may be configured to generate an electromagnetic beam160that may be responsive to fluid140such that the electromagnetic beam160may respond differently to the internal phase of fluid140than to the continuous phase of fluid140. In some embodiments, electromagnetic source180may be configured to generate electromagnetic beam160such that the continuous phase of fluid140may be transparent or almost transparent to electromagnetic beam160. Herein, the use of the term “beam” may be construed as meaning emitted light and does not imply that the electromagnetic radiation must be concentrated, focused, coherent, or collimated. In some embodiments, fluid140may be a mixture. In some embodiments, fluid140may be a hydrocarbon mixture, including, but not limited to, one or more of: (i) a crude oil, heavy crude oil, (ii) a heavy fuel oil or #6 oils, (iii) a diesel oil, and (iv) a bunker fuel oil. In some embodiments, fluid140may include a substance that may form a gas hydrate, such as, but not limited to, a hydrocarbon hydrate. In some embodiments, the fluid140may be flowing through gap130or stagnant.

FIG. 1Cshows another embodiment, probe101, according to the present disclosure. Probe101may include a housing or body111configured as a conduit for an electromagnetic beam161from an electromagnetic source180. Electromagnetic source180and sensor190may be disposed along housing111. Housing111is at least partially transparent to an electromagnetic beam161emitted from electromagnetic source180and includes, at least in part, a material with a refractive index that is higher than fluid140, such that at least part of electromagnetic beam161is at least partially internally reflected at the interface126between body111and fluid140to form reflected electromagnetic beam171, while the remainder of electromagnetic beam161is refracted into the fluid140as electromagnetic beam176. One example of a body and sensor combination as envisioned in this disclosure is the K-PATENTS™ Refractometer Model No. PR-23-GP. The use of a triangular prism as housing101is exemplary and illustrative only, as embodiments according to the present disclosure may be realized with other shapes of prismatic objects (polygonal and non-polygonal), including prismatic objects with more than one interface configured to cause internal reflections (trapezoidal shapes, spheres, etc.).

FIG. 2Ashows an exemplary method201for using the probe100to detect the formation of an internal phase. In step210, probe100may be installed in a fluid140. Fluid140may be a mixture containing at least one hydrocarbon, alcohol, or glycol. Installation may be permanent or temporary, and probe100may be stationary or in motion after installation. In other alternative embodiments, the probe100may be retractable, for instance, when in operation inserted or placed into the flow in a pipeline or into a mixture stored in a tank, and then retracted for cleaning, calibration, replacement or other service. In step220, probe100may estimate the value of a parameter of interest of the fluid140that occupies the gap130between housing110and reflector120. In step230, the estimated value of the parameter of interest may be combined with a known property of the fluid140to determine if an internal phase has formed or is in the process of forming. Estimating the value of the parameter of interest of the fluid may be performed once, continuously, or periodically. In some embodiments, step210may not need to be performed. In some embodiments, if an internal phase has formed or is in the process of forming, the method201may include adding a chemical additive or changing temperature/pressure to the fluid140to reduce or eliminate the internal phase. In some embodiments, the method201may include the step of detecting the reduction or elimination of an internal phase using a value of the parameter of interest of the fluid140. In some embodiments, the method201may include the step of adjusting an amount of additive added to the fluid140based the value of the parameter of interest of the fluid140. In some embodiments, the known property of fluid140may be a correlation between the formation of an internal phase a value of a parameter of interest. In some embodiments, the known property of the fluid may be correlated with the formation of an internal phase through experimental trials. In some embodiments, the correlation may be established by performing a test on fluid140or a substantially similar sample, using as the testing technique, but not limited to, one of: (i) p testing, (ii) titration, and (iii) optical detection. Herein, p-testing means the determination of a p-value as an indicator of stability of a hydrocarbon containing fluid. P-value is the ratio of precipitating paraffins to oil (volume/mass) necessary to generate phase separation of foulants (such as asphaltenes). P-testing may include adding n-cetane to a vistar (visbroken tar and/or vacuum residuum) or heavy fuel oil sample, heating and cooling the sample for specified periods of time, and evaluating the sample for microscopic flocculation/aggregation of asphaltenes.

FIG. 2B, shows another exemplary method202for using probe100to detect the formation of an internal phase. In step210, probe100may be installed in a fluid140. Fluid140may be a mixture containing at least one hydrocarbon. Installation may be permanent or temporary, and probe100may be stationary or in motion after installation. In step240, probe100may monitor the value of a parameter of interest of the fluid140that occupies the gap130between housing110and reflector120. Monitoring may be performed continuously or periodically. In step250, an estimated value of the parameter of interest compared with one or more previously estimated values of the parameter of interest to detect a change in the value of the parameter of interest that exceeds a selected amount or threshold. In some embodiments, the threshold may be established based on the refractive index of the fluid at various temperatures. In some embodiments, the threshold may be a change of refractive index of between about 0.001 to about 0.05 RI units. The selected amount may indicate that an internal phase has formed or is in the process of forming. One of skill in the art with the benefit of the information in the present disclosure will appreciate that the selected amount of change may vary for a particular fluid due to one or more properties of the fluid, including, but not limited to: composition, temperature, and pressure. In some embodiments, step210may not need to be performed. In some embodiments, step250may be performed by trending, graphing, or plotting the data obtained during step240. In some embodiments, if an internal phase has formed or is in the process of forming, the method202may include adding an additive to the fluid140to reduce or eliminate the internal phase. In some embodiments, the method201may include the step of detecting the reduction or elimination of an internal phase using a value of the parameter of interest of the fluid140. In some embodiments, the method202may include the step of adjusting an amount of chemical additive added to the fluid140based the value of the parameter of interest of the fluid140.

As shown inFIG. 3, certain embodiments of the present disclosure may be implemented with a hardware environment that includes an information processor300, a data storage medium310, an input device320, processor memory330, and may include peripheral data storage medium340. The input device320may be any data reader or user input device, such as data card reader, keyboard, USB port, etc. The data storage medium310stores formation characteristic data provided by a user or user system. Data storage medium310may be any standard computer data storage device, such as a USB drive, memory stick, hard disk, removable RAM, or other commonly used memory storage system known to one of ordinary skill in the art including Internet based storage. Data storage medium310stores a program that when executed causes information processor300to execute the disclosed method. Data storage medium310may also store the formation data provided by the user, or the formation data may be stored in a peripheral data storage medium340, which may be any standard computer data storage device, such as a USB drive, memory stick, hard disk, removable RAM, or other commonly used memory storage system known to one of ordinary skill in the art including Internet based storage. Information processor300may be any form of computer or mathematical processing hardware, including Internet based hardware. When the program is loaded from data storage medium310into processor memory330(e.g. computer RAM), the program, when executed, causes information processor300to retrieve formation data from either data storage medium310or peripheral data storage medium340and process the formation data to characterize the formation.

FIG. 4shows an exemplary correlation between a parameter of interest and a known property of fluid140. Here, the parameter of interest is the refractive index (RI), which is correlated with an ISI Solubility Blending Number (ISI SBn) for fluid140. In one embodiment, the refractive index data obtained by probe100may be used to determine the ISI Solubility Blending Number for the fluid140, which corresponds to the stability of fluid140. The ISI SBn refers to the result of a method for estimating the stability of fluid140that may employ a near infra-red source and detector, which may be used as an alternative to the p-method. The relationship between the ISI Solubility Blending Number and the formation of an internal phase may be established through experimentation or other techniques known to those of skill in the art with the benefit of the present disclosure. The use of the ISI Solubility Blending Number is exemplary and illustrative only, as other indicators (such as particle size changes, p-value stability, and titration-based methods) may be correlated with the formation of an internal phase.

In alternative embodiments, the methods herein may include the introduction of a chemical additive in response to detecting the formation of a second phase in the substance to inhibit or prevent the further formation of the second phase. Such chemical additives may include, but not necessarily be limited to, asphaltene inhibitors, scale inhibitors, hydrate inhibitors, dispersants, reactive agents, antifouling additives, and the like which are known in the art. In a different non-limiting embodiment, the conditions of the substance or mixture may be changed to inhibit or prevent formation of the second phase, including, but not necessarily limited to, changing the temperature, pressure, or composition of the substance or mixture (e.g. adding a solvent in addition to or instead of an inhibitor). In these ways, the stability of the substance or fluid may be improved.

One skilled in the art will recognize that the various components or technologies may provide certain necessary or beneficial functionality or features. Accordingly, these functions and features as may be needed in support of the appended claims and variations thereof, are recognized as being inherently included as a part of the teachings herein and a part of the disclosure disclosed. For instance, the methods and apparatuses may be advantageously employed at some distance into a wellbore or along a pipeline (e.g. about 4 km or more). The probes and methods herein may be non-explosive. The methods and apparatuses may also be advantageously employed at relatively high temperatures, for instance up to 300° C., or even higher.

Further, the methods and apparatuses described will find particular use in mixing two or more different hydrocarbons, in a non-limiting example, two different crude oils, to detect the aggregation of asphaltenes or other second phases in the mixtures. It often happens that two or more crude oils may be stable at a particular temperature and pressure, but when mixed asphaltene precipitation may occur spontaneously. This may be because the asphaltene becomes destabilized and start to aggregate in species that are not as soluble in the mixture and thus form, flocculate, or precipitate only after mixing. The asphaltene-forming molecules may be kept from undesirably forming by Brownian motion, maltenes, aromatics, and more aromatic and polar containing species and forces which are likely disturbed upon mixing. There presently exist tests for detecting such asphaltene formation, but these tests may take many hours or even days to perform, whereas the apparatus and methods herein may give very fast (on the order of minutes or seconds) detection of aggregation of asphaltenes and other second phase formation in online or continuous stream applications.

The words “comprising” and “comprises” as used throughout the claims is to be interpreted to mean “including but not limited to”.