Patent Application
20110259794
The present invention relates generally to processes and systems for treating petroleum streams to mitigate effects of hydrate inhibitors.
Natural gas hydrates or clathrate hydrates of natural gases (often simply called “hydrates”) form when water and certain gas molecules are brought together under suitable conditions of relatively high pressure and low temperature. Under these conditions the ‘host’ water molecules will form a cage or lattice structure capturing a “guest” gas molecule inside. Large quantities of gas are closely packed together by this mechanism. For example, a cubic meter of methane hydrate contains 0.8 cubic meters of water and up to 172 cubic meters of methane gas. While the most common clathrate on earth is methane hydrate, other gases also form hydrates, including hydrocarbon gases such as ethane and propane as well as non-hydrocarbon gases such as CO2 and H2S.
Thermodynamic conditions favoring hydrate formation are often found in pipelines and subsea petroleum production lines. This is highly undesirable because the hydrate crystals might agglomerate and plug the flowline and cause flow assurance failure and damage valves and instrumentation. The results can range from flow reduction to equipment damage. Increasingly, deepwater oil field developments face serious technical problems associated with hydrate formation causing blockage in flow lines exposed to very cold temperatures during well start-up or when flow rates are slowed. Typically, hydrate formation and subsequent line plugging is avoided by injecting thermodynamic hydrate inhibitors such as methanol or glycols into the process lines. However, once the well begins or resumes normal production, crude contamination from inhibitor chemicals needs to be mitigated prior to shipment in order to maintain both crude value and crude reputation. For instance, the presence of relatively small amounts of methanol (e.g. greater than 50 ppm) in the crude upsets refinery waste water treatments systems and is undesirable to the refinery customers. Therefore, it is very important to uphold the reputation of crude oil streams by maintaining the integrity and consistency of the refining characteristics of the crude oil preferably at the production location.
Current processes isolate the contaminated crude batch either for discounted sale or for blending with on-spec production crude. Either method can result in significant crude revenue loss. Blending will reduce the methanol concentration, but very large quantities of on-spec crude are needed to achieve sufficient dilution. If the diluted batch does not lower the contamination enough, the significantly larger amount of methanol contaminated crude will result in lost revenue. Improved methods for removing these additives near the production facilities are desired.
Accordingly, a process is provided removing a clathrate inhibitor from a contaminated petroleum stream, comprising maintaining the contaminated petroleum stream at inhibitor removal conditions in a vessel having a liquid volume and a vapor volume, wherein the contaminated petroleum stream contains in the range of from greater than 50 ppm inhibitor to less than 5000 ppm inhibitor, to produce a treated petroleum stream having a reduced inhibitor concentration. In embodiments, the inhibitor is methanol. In embodiments, the petroleum stream is crude oil. In some such embodiments, the contaminated petroleum stream is crude oil that contains methanol. In some such embodiments, the crude oil contains in the range of greater than 50 ppm to less than 5000 ppm methanol as a contaminant. In embodiments, the treated petroleum stream contains less than 50 ppm inhibitor.
In embodiments, the process comprises mixing a methanol-rich stream with crude oil in a crude oil production process to form contaminated crude oil; and passing the contaminated crude oil at methanol removal conditions to a vessel having a liquid volume and a vapor volume, wherein the contaminated crude oil contains in the range of from greater than 50 ppm methanol to less than 5000 ppm methanol, to produce a treated crude oil having a methanol concentration of less than 50 ppm.
A process is presented for treating a petroleum stream that is contaminated with an inhibitor previously added to the stream to mitigate the formation of hydrates. The process involves removing the inhibitor from a contaminated petroleum stream. An exemplary contaminated petroleum stream is a petroleum product, such as gasoline, diesel fuel, naphtha, kerosene, jet fuel or other petroleum products having a boiling point range within the range of 40° C. to 500° C. Another exemplary contaminated petroleum stream comprises crude oil, as produced from a subsurface oil producing formation, or as produced from a subsurface oil producing formation and then degassed to remove low boiling components therefrom. In embodiments, the petroleum stream is crude oil.
The contaminant that is present in the contaminated petroleum stream includes one (or more) additive supplied to the petroleum stream to reduce any deleterious effects that clathrate hydrates might have on the flow of the petroleum stream, and particularly on flow through a conduit. In one embodiment, the additive is supplied to the petroleum stream to inhibit hydrate formation by shifting the hydrate equilibrium conditions towards lower temperatures and higher pressures or by increasing hydrate formation time.
In one exemplary application, the conduit is production tubing that extends in a well from the subsurface oil producing formation to the surface. In another exemplary application, the conduit is a pipeline extending from a subsea production well to water-based or land-based surface facilities. In another exemplary application, the conduit is a pipeline for transporting crude oil from surface facilities to market or to a mobile carrier, such as a ship, a barge, a train or a truck.
Clathrate hydrates (otherwise termed “hydrates”) are crystalline water-based solids physically resembling ice, in which small non polar molecules (typically gases) are trapped inside “cages” of hydrogen bonded water molecules. In one embodiment, the clathrate hydrate is methane hydrate, which is formed by the interaction of water and methane. In one embodiment, the clathrate hydrate comprises nitrogen (N2). In one embodiment, the clathrate hydrate comprises carbon dioxide (CO2).
As described above, the contamination in the contaminated petroleum stream comprises an inhibitor that is added to the petroleum stream to reduce the deleterious effect of and/or to inhibit the formation of clathrate hydrates, such as methane hydrates, in the petroleum stream. Exemplary inhibitors are methanol, ethanol, acetone, dimethyl ether, monoethylene glycol, diethylene glycol and trimethylene glycol. In embodiments, the inhibitor is methanol, and the contaminant that is a component of the contaminated petroleum stream is methanol. The concentration of methanol in the petroleum stream may be determined using ASTM D7059-04.
In embodiments, the process for removing the inhibitor (or mixture of inhibitors) from the contaminated petroleum stream takes place at a facility near the site at which the petroleum stream is produced. In the case of crude oil, the process takes place at the crude oil production platform or at land-based facilities near the oil production site.
The contaminated petroleum stream contains a measureable amount of inhibitor. The process for treating the contaminated petroleum stream comprises removing at least a portion of the inhibitor that is present in the contaminated petroleum stream. In embodiments, the contaminated petroleum stream contains greater than 50 ppm inhibitor, where the concentration of the inhibitor is quantified on a weight basis. In some such embodiments, the contaminated petroleum stream contains greater than 100 ppm inhibitor, or greater than 500 ppm inhibitor, or greater than 1000 ppm inhibitor. In some such embodiments, the contaminated crude oil contains in the range of from greater than 50 ppm inhibitor to less than 5000 ppm inhibitor.
The process for removing inhibitor from the contaminated petroleum stream further comprises maintaining the contaminated petroleum stream at inhibitor removal conditions, including conditions of temperature and pressure at which the inhibitor within the contaminated petroleum stream will vaporize. Exemplary temperatures for inhibitor removal include a temperature of greater than 50° C., or greater than 100° C., or greater than 150° C. or greater than 200° C. In embodiments, the inhibitor removal conditions include a temperature in the range of 0° C. to 200° C., such as, for example, a temperature in the range of 10° C. to 150° C. or in the range of 10° C. to 100° C. or in the range of 10° C. to 60° C. Exemplary pressures for inhibitor removal include a pressure of less than 800 kPa, or less than 625 kPa, or less than 450 kPa or less than 275 kPa. In embodiments, the inhibitor removal conditions include a pressure in the range of 5 kPa to 450 kPa, such as a pressure in the range of 100 kPa to 275 kPa or in the range of 200 kPa to 275 kPa. As used herein, pressure is expressed as absolute pressure. Standard atmospheric pressure is defined as 101.3 kPa.
In embodiments, the process for removing inhibitor from the contaminated petroleum stream further comprises passing the contaminated petroleum stream to a vessel having a liquid volume and a vapor volume (or a vapor “head space” above the liquid volume), wherein any inhibitor that vaporizes into the vapor phase from the liquid inside the vessel collects in the vapor volume. The size of the vapor volume is a matter of engineering discretion, and depends, at least in part, on the temperature and pressure of the contaminated petroleum stream in the vessel, the size of the liquid volume, the size of the vapor volume, the surface area of the liquid/gas interface, and the residence time of the petroleum stream in the vessel.
The process comprises maintaining the contaminated petroleum stream in a vessel having a liquid volume and a vapor volume, to produce a treated petroleum stream having a reduced inhibitor concentration relative to that of the contaminated petrol stream. In embodiments, the vessel is a tank in which the petroleum stream is contained until the inhibitor concentration is reduced to a target value. In other embodiments, the vessel is a conduit having a liquid volume through which the liquid passes in the conduit and a vapor volume in which the vapor collects, the vapor comprising the inhibitor in the vapor phase.
In embodiments, the liquid volume is sized for a liquid residence time in the vessel of at least 2 hours, or at least 4 hours, or at least 8 hours, or at least 16 hours or at least 24 hours. In some such embodiments, the petroleum stream remains in the vessel for an average of from 1 to 10 days. As used herein, residence time is defined as the quotient A/B, were A is the volume of the liquid volume in the vessel, in units of cubic meters, and B is the flow rate of the petroleum stream through the liquid volume, in units of cubic meters per hour. The quotient A/B gives the average residence time of the petroleum stream in units of hours.
The vapor volume is sized such that the inhibitor concentration in the contaminated petroleum stream is reduced as the petroleum stream passes through or is maintained in the vessel, to produce a treated stream having a reduced inhibitor concentration. In embodiments, the treated petroleum stream has an inhibitor concentration of less than 1000 ppm, or less than 500 ppm, or less than 200 ppm, or less than 100 ppm or even less than 50 ppm. In some such embodiments, the treated petroleum stream has an inhibitor concentration of less than 50 ppm, or in the range of from 1 ppm to 45 ppm. Treated petroleum streams containing less than 50 pm inhibitor are suitable for pipeline delivery and/or for petroleum refining. In some situations, a treated petroleum stream containing more than 50 ppm inhibitor is blended with other petroleum streams that contain less than 50 ppm inhibitor. In some situations, the treated petroleum stream containing more than 50 ppm inhibitor is subjected to a liquid wash to remove additional inhibitor from the petroleum stream, in order to produce a petroleum stream comprising less than 50 ppm inhibitor.
In some situations, the treated petroleum stream is contacted with an adsorbent. An exemplary adsorbent that is useful for contacting the treated crude is a crystalline, porous inorganic material, such as a non-acidic 8-membered ring crystalline microporous material. Typically, the porous crystalline material is non-acidic. Suitable porous crystalline materials for use as the adsorbent in the process of the invention include silicates, aluminosilicates, aluminophosphates, gallophosphates, galloaluminophosphates, metalloaluminophosphates and metalluminosilicophosphates. Exemplary materials include silica chabazite (Si-CHA) the aluminophosphates AlPO-34 and AlPO-18 and their corresponding gallophosphates GaPO-34 and GaPO-18.
The temperature at which the adsorption step is conducted is generally between about 273K and about 523K, or between about 323K and about 523K. The upper temperature is selected so as to achieve a significant loading onto the adsorbent material (i.e., weight percent gain) and to avoid the possibility of any unwanted reactions, such as oligomerization and/or polymerization of the olefins in the stream. The pressures at which the adsorption and adsorbent regeneration steps are carried out are likewise a matter of choice. Typically, the adsorption step is carried out at methanol partial pressures in the range of about 4 kPa to about 350 kPa, or in the range of about 5 kPa to about 200 kPa. Typically, the adsorbent regeneration step is carried out at methanol partial pressures in the range of about 0.07 kPa to about 10 kPa, or in the range of about 0.2 kPa to about 7 kPa.
The target amount of inhibitor is controlled by the amount of inhibitor that can be tolerated in downstream processing. For example, the target amount of inhibitor is controlled by the amount of inhibitor that can be tolerated during shipping and handling the petroleum stream. Alternatively, the target amount of inhibitor is controlled by the amount of additional streams containing little or no inhibitor that can be blended with the petroleum stream to produce a blend having an acceptable inhibitor concentration for further processing or shipping. In one such embodiment, a petroleum stream containing up to 5000 ppm inhibitor contamination is passed to a vessel having a liquid volume and a vapor volume, and the treated crude that is withdrawn from the vessel has an inhibitor concentration of less than 50 ppm.
In embodiments, the vapor volume contains a vapor phase blanketing material. An exemplary vapor phase blanketing material comprises at least one of nitrogen, carbon dioxide, synthesis gas (mixture comprising CO and H2), air, and gaseous hydrocarbons. The selection of particular components of the vapor phase blanketing material may be dictated by a specific application of the process. As an example, selection of an inert gas blanketing material, such as nitrogen, carbon dioxide or gaseous hydrocarbons may reduce the reaction of oxygen with the petroleum stream. Alternatively, selection of a non-condensible blanketing material, such as nitrogen, carbon dioxide, or synthesis gas may improve the efficiency of separating the inhibitor from the blanketing material for reuse. Or use of a vapor phase blanketing material may help to maintain a low inhibitor vapor phase partial pressure, and thereby increase inhibitor removal from the petroleum stream.
In embodiments, the vapor volume is pressurized with the vapor phase blanketing material, at a total pressure above ambient of less than 800 kPa, or less than 625 kPa, or less than 450 kPa or less than 275 kPa. In embodiments, the inhibitor removal conditions include a pressure in the range of 5 kPa to 450 kPa, such as a pressure in the range of 100 kPa to 275 kPa.
In embodiments, at least a portion of the vapor phase blanketing material is introduced to the vapor volume as a sweep gas, which is caused to flow within and through the vapor volume and across the surface of the liquid in the liquid volume. An exemplary sweep gas comprises at least one of nitrogen, carbon dioxide, synthesis gas, air or gaseous hydrocarbons. In an exemplary process, a sweep gas is passed into the vapor volume of the vessel, and a contaminated sweep gas, comprising at least a portion of the sweep gas, and enriched in inhibitor, is removed from the vapor volume. Use of the sweep gas reduces the concentration gradient in the vapor volume and enhances the inhibitor evaporation rate into the vapor volume. In embodiments, the sweep gas is introduced to the vapor volume to maintain a vapor superficial velocity across the liquid in the vessel of from 0.2 meters/second to 5 meters/second.
In embodiments, at least a portion of the vapor phase blanketing material is introduced as a stripping gas, which is introduced into the liquid volume of the vessel, and is caused to bubble upward into and through the petroleum stream in the liquid volume. The action of the stripping gas bubbling through the contaminated petroleum stream in the liquid volume further enhances the inhibitor removal from the stream.
In embodiments, the contaminated gaseous product, such as the contaminated sweep gas, that is recovered from the vapor volume of the vessel comprises greater than 5% inhibitor. Other exemplary ranges include the gaseous product containing greater than 10%, or greater than 30% or greater than 50% inhibitor. The contaminated gaseous product may be further treated to recover at least a portion of the inhibitor contained therein, including, for example, burning at least one of the components of the gaseous product, venting at least one of the components of the gaseous product, or otherwise disposing of at least one of the components of the gaseous product. In embodiments, the inhibitor in the gaseous product recovered from the vapor volume is purified by, for example, fractional distillation and/or water washing. Inhibitor recovered from the process may be recycled.
In embodiments, the gaseous product is burned in a combustion process. The combustion process may include a CO2 recovery step. The recovered CO2 may be sequestered in an underground geological formation, both to store the CO2 and reduce gaseous CO2 emissions, or as a gas drive in enhanced oil recovery. In some instances, at least a portion of the gaseous product is combusted, and the process further comprises recovering energy in the form of thermal energy, electrical energy or mechanical energy from the step of combusting.
In embodiments, the treated petroleum stream is contacted with a liquid wash material to remove additional amounts of inhibitor remaining in the stream, and a contaminated wash material and a washed petroleum stream are recovered. The contaminated wash material contains an increased amount of inhibitor relative to the liquid wash material. Likewise, the washed petroleum stream contains a reduced amount of inhibitor relative to the petroleum stream prior to the washing step. An exemplary washed petroleum stream contains less than 200 ppm inhibitor, or less than 150 ppm inhibitor, or less than 100 ppm inhibitor, or less than 50 ppm inhibitor. In some embodiments, the process further comprises treating the contaminated wash material and recovering at least a portion of the inhibitor contained therein. In some such embodiments, a quantity of at least partially purified inhibitor is recovered. The liquid wash material is selected to extract at least a portion of the inhibitor from the petroleum stream. An exemplary liquid wash material is an aqueous liquid. For example, fresh water, seawater, brine or a combination thereof may be used as at least one component of the liquid wash material. In embodiments, the liquid wash material and the treated crude oil are in a weight ratio of between 10:1 and 1:10.
It will be apparent to the skilled practitioner that additional methods may be employed to increase the recovery of the inhibitor from the contaminated petroleum stream. Exemplary methods include heating the petroleum stream prior to passing the stream to the vessel, employing mechanical agitation of the petroleum stream in the vessel and reducing the total pressure in the vessel to a sub-atmospheric pressure. These additional methods, which are a direct extension of the process as described herein, are within the scope of the present process.
A sample of crude oil (boiling point, 120-575° C.) was spiked with 640 ppm methanol. The sample was placed in a vessel with a headspace volume of 20 ml. The sample was allowed to sit for 30 minutes time without agitation. A sample of the crude was removed and subjected to GC analysis. The methanol concentration of the treated crude was 500 ppm.
A 4 mL sample of the same crude oil used in Example 1 was spiked with 300 ppm methanol. The crude was placed in a vessel with a headspace volume of 56 mL. The sample was agitated for 30 seconds. The sample was vented 3 times after which a sample of the treated crude was removed and subjected to GC analysis. The methanol concentration of the treated crude was 209 ppm.
The crude of example 2 (25 mL) was placed in a vessel with a headspace volume of 30 mL (out of 60 mL total volume). To the vessel was added 5 mL of water. The sample was agitated for 30 seconds during which time the sample was vented 2 times. After the crude/water mixture was agitated and vented, a sample of treated crude was removed and subjected to GC analysis. The concentration of methanol in the treated crude sample was below the limits of detection (<5 ppm methanol).
A 40 1 sample of crude oil containing in the range of 1000 to 5000 ppm methanol is passed through a vessel with a headspace volume of 500 liters, with the residence time of the crude oil being in the range of from 2 hours to 16 hours. A nitrogen sweep gas is flowed through the headspace volume and allowed to pass over the crude oil at a superficial velocity of from 0.2 meters/second to 5 meters/second. The temperature of the liquid in the vessel is maintained within the range of 10° C. to 60° C., and the pressure within the range of 200 kPa to 275 kPa. A sample of the treated crude leaving the vessel is found to have a methanol concentration of less than 50 ppm.
