Method for removing H2S and Co2 from crude and gas streams

The present invention relates to a method for removing H₂S and CO₂ from crude and gas streams.

A long standing problem in the oil and gas industry is the presence of H₂S or hydrogen sulfide gas in hydrocarbons. H₂S must frequently be removed before a hydrocarbon can be further processed and/or used as a commercial product.

Another routinely encountered contaminant is CO₂, which frequently must be removed as well.

Various surface scrubbing methods and H₂S or CO₂ removal devices and methods are known, but the need remains for a simple and efficient method for removal of contaminants in a downhole environment as well as at the surface.

It is therefore the primary object of the present invention to provide a method for removing H₂S and/or CO₂ from hydrocarbon gas and crude streams.

It is a further object of the present invention to provide a method for removal of H₂S which is simple and economic in use, and friendly to the environment.

The problems are solved by the teaching according to the independent claims. Particular developments are given in the dependent claims. Within the frame of the invention are all combinations of at least two of the descriptive elements and technical features disclosed in the claims and/or in the description.

In accordance with the present invention, the foregoing objects and advantages have been readily attained.

According to the invention, a method is provided for removing at least one contaminant selected from the group consisting of H₂S and CO₂ from hydrocarbon streams, which method comprises the steps of providing a stream of hydrocarbon containing said at least one contaminant; and positioning metal-containing nanoparticles in said stream, said metal-containing nanoparticles being selected from the group consisting of metal oxides, metal hydroxides and combinations thereof, whereby said nanoparticles adsorb said at least one contaminant from said stream.

In accordance with a preferred embodiment of the present invention, the hydrocarbon stream to be treated is a downhole stream established from a hydrocarbon producing subterranean formation to a hydrocarbon producing well, and the nanoparticles are positioned in fractures induced into the formation in the form of propants and/or additives to propants, whereby the hydrocarbon stream produced through the fractures is exposed to the nanoparticles and H₂S and/or CO₂ are adsorbed downhole.

In accordance with another preferred embodiment of the present invention, the contaminant-adsorptive nanoparticles of the present invention can be utilized at surface locations as well, for example in packing filters and the like, so as to advantageously adsorb H₂S and CO₂ contaminants from hydrocarbon streams.

Further advantages, characteristics and details of the invention are apparent from the following detailed description of preferred embodiments of the invention with reference to the attached drawing schematically illustrates a multi-stage process in accordance with the present invention, wherein: <ul id="ul0001" list-style="none" compact="compact"><li>Figure 1 illustrates a preferred embodiment of the present invention wherein a fracturing fluid is injected into a well to form fractures and nanoparticles are disposed therein;</li><li>Figure 2 further illustrates the embodiment of Figure 1, wherein particles within fractures are positioned in a stream of hydrocarbon flowing from a formation into a production well;</li><li>Figure 3 illustrates an alternative embodiment of the present invention wherein a hydrocarbon stream is treated using a schematically illustrated filter pack, for example at a surface location.</li></ul>

The present invention relates to a method for removing H₂S and CO₂ from hydrocarbon streams, and advantageously provides for positioning of H₂S adsorptive metal-containing oxide nanoparticles within the stream at desirable locations whereby H₂S and/or CO₂ are absorbed so as to produce a hydrocarbon stream having reduced H₂S content.

In accordance with the present invention, it has been found that reactive nanoparticles having high surface area provide for excellent adsorption of H₂S and CO₂ from crude and gas hydrocarbon streams, and the adsorption capacity of such particles is not substantially adversely affected by increased temperatures. This is particularly surprising in that many conventional systems for removal of H₂S are rendered less effective in the presence of CO₂, wherein the nanoparticles of the present invention have been found to be effective at removal of both H₂S and CO₂. This finding advantageously allows for such metal oxide nanoparticles to be disposed in downhole locations whereby H₂S and CO₂ removal can be accomplished in the well as the hydrccarbon stream is being produced.

In accordance with a particularly preferred embodiment of the present invention, the reactive metal-containing nanoparticles are preferably selected from the group consisting of metal oxides and metal hydroxides, and mixtures thereof. These nanoparticles are useful at both surface and downhole locations, and downhole applications are particularly advantageous environments of use. For use in a downhole location, a fracturing fluid can be introduced into a well so as to form fractures in the hydrocarbon-producing formation, and the nanoparticles are then disposed in such fractures, either as propants and/or as an additive or coating to a propant, whereby hydrocarbon streams produced through the fracture are exposed to the nanoparticles as desired.

In accordance with the present invention, suitable nanoparticles preferably have a particle size of less than or equal to about 100 nm, preferably less than or equal to about 30 nm, more preferably between about 1 nm and about 20 nm and most preferably between about 1 nm and about 10 nm. These nanoparticles can be produced utilizing any known techniques. Examples of disclosures related to preparation of suitable nanoparticles are presented in U.S. Patent Nos. 5,759,939, 4,877,647 and 6,087,294.

It is preferred that the nanoparticles of the present invention have a surface area greater than or equal to about 80 m²/g, which has been found to provide excellent adsorption capacity as will be demonstrated in the examples which follow.

Suitable materials from which nanoparticles can be provided in accordance with the present invention include metal oxides and/or metal hydroxides, and the metal is preferably a metal selected from the group consisting of calcium, magnesium, zinc, iron and other metals from groups 8, 9 or 10 or the periodic table of elements (CAS Group VIII). For adsorption of H₂S, the most preferred material is calcium oxide (CaO), and for adsorption of CO₂, the most preferred material is calcium oxide coated with irom oxide ([Fe₂O₃]CaO). For environments where both H₂S and CO₂ are to be removed and CO₂ is present in amounts of greater than 50% by vol., the most preferable nanoparticles have been found to be calcium oxide coated with iron oxide ([Fe₂O₃]CaO).

It is particularly preferred that nanoparticles in accordance with the present invention have a chemical structure containing less than or equal to about 100 atoms. This advantageously provides for increased surface area and adsorption of H₂S and CO₂ even in the presence of other gases, all as desired in accordance with the present invention.

As set forth above, nanoparticles in accordance with the present invention are positioned in an H₂S and/or CO₂-containing hydrocarbon stream, and the nanoparticles serve to adsorb the H₂S/CO₂ from the hydrocarbon stream so as to provide a hydrocarbon product having reduced H₂S content.

The nanoparticles in accordance with the present invention can be positioned within a stream of hydrccarbon to be treated in a number of different ways. It is within the broad scope of the present invention to position the nanoparticles in various packed filters, which can be made from nanoparticle pellets or powder packing, and such filters can be positioned at the surface of a well and/or downhole through a production tubing, or in any other desired location. In accordance with a particularly preferred embodiment of the present invention, in wells which are to be fractured for enhancing production, nanoparticles are disposed in the fractures for contacting fluid as it flows into the well.

In the downhole fracture environment, nanoparticles may suitably be disposed within the fractures by fracturing the formation with a fracturing fluid and following the fracturing fluid with a fluid carrying the nanoparticles. Flowing of this fluid through the formed fractures disposes the nanoparticles therein and serves to stabilize such fractures as desired, and further position the desired high surface area metal-containing nanoparticles within the hydrocarbon stream to be produced through such fractures, all as desired in accordance with the present invention.

Referring to Figure 1, this preferred embodiment. is schematically illustrated. Figure 1 shows a well 10 positioned to a subterranean hydrocarbon producing formation 12 and having perforations 14 through which hydrocarbons are produced. A fracturing fluid 15 is injected into well 10 and reaches formation 12 through perforations 14 at pressure and flow rate sufficient to form fractures 18 within formation 12. Fluid 16 carrying nanoparticles in accordance with the present invention is then pumped into well 10, and the nanoparticles are positioned within fractures 18 as schematically illustrated in Figure 1 and as desired in accordance with the present invention.

It is conventional in fracturing processes to include various propant particles in the fracturing fluid, or in a wash after the fracturing fluid, so that such propant particles are positioned within the fractures to hold such fractures open and enhance flow through same. In accordance with the present invention, the reactive metal oxide nanoparticles may themselves be used as propant particles, or such nanoparticles can be disposed as a coating or other ingredient or additive to the propants, so as to provide the desired positioning within fractures 18.

In accordance with the present invention, the metal-containing nanoparticles may be utilized in various forms. The most preferred form is to agglomerate these nanoparticles into pellets of suitable size and dispose such pellets into the hydrocarbon stream. Alternatively, if desired, the nanoparticles may be disposed onto other substrate particles and the like, if desired.

It should be noted that Figure 1 illustrates a well 10 having perforations 14. The method and nanoparticles of the present invention would also be applicable for open hole wells and any other environment for downhole or surface application.

Figure 2 shows the well 10 of Figure 1 after the fracturing step has been carried out and schematically shows hydrocarbon 20 being produced from fractures 18 into well 10 and flowing past particles within fracture 18, such that product 22 has reduced H₂S and CO₂ content.

In accordance with the present invention, it has been found that suitable metal-containing nanoparticles have substantially larger adsorption capacity than any conventional product, and that this H₂S adsorption capacity is not adversely affected by the presence of other gases such as CO₂, or by increased temperature, and CO₂ can in fact be removed as well. As set forth above, the resistance to increased temperature makes the nanoparticles of the present invention particularly well suited to downhole application as illustrated in Figures 1 and 2.

Depending upon the flow to which nanoparticles in accordance with the present invention are exposed, nanoparticles will have a useful lifetime of approximately two years. Of course, nanoparticles can readily be replaced in the form of different filter packs, and/or during other service operations on the well.

Turning to Figure 3, an alternative application of nanoparticles in accordance with the present invention is illustrated. As schematically shown, nanoparticles can be disposed within a filter pack 24 and positioned along a flow of hydrocarbon to be treated. Figure 3 schematically shows a stream 26 containing H₂S and CO₂ being fed to filter pack 24, and a product stream 28 having reduced H₂S and CO₂ content as desired in accordance with the present invention. Such a filter pack 24 can advantageously be positioned at any desired location along a hydrocarbon stream carrying hydrocarbons to be treated.

It is noted that the embodiments of Figures 1-3 all advantageously serve to provide excellent reduction in H₂S and CO₂ content in the hydrocarbon stream, and show enhanced removal-capacity as compared to commercial products. Further, the particular characteristics of nanoparticles in accordance with the present invention allow for the downhole application of such nanoparticles, and thereby the downhole removal of H₂S and CO₂, which provides a significant benefit in the industry.

It has also been found that the process by-products are environmentally friendly metal sulfates which can be used in other applications and industries, for example as a fertilizer for agriculture and soil enrichment, and in the fabrication of cement for construction applications. Thus, the metal oxide nanoparticles and method for using same in accordance with the present invention also provide an environmentally friendly method for disposition of the H₂S and CO₂.

EXAMPLE 1

A number of different metal oxide compounds were evaluated to identify the typical surface area thereof, and this information is set forth in Table 1 below. <tables id="tabl0001" num="0001"><table frame="all"><title>Table 1</title><tgroup cols="4" colsep="1" rowsep="0"><colspec colnum="1" colname="col1" colwidth="39.37mm" /><colspec colnum="2" colname="col2" colwidth="39.37mm" /><colspec colnum="3" colname="col3" colwidth="39.37mm" /><colspec colnum="4" colname="col4" colwidth="39.37mm" /><thead valign="top"><row rowsep="1"><entry namest="col1" nameend="col1" align="left">Compound</entry><entry namest="col2" nameend="col2" align="center">Typical Surface Area (m²/g)</entry><entry namest="col3" nameend="col3" align="center">Compound</entry><entry namest="col4" nameend="col4" align="center">Typical Surface Area (m²/g)</entry></row></thead><tbody valign="top"><row><entry namest="col1" nameend="col1" align="left">AP-MgO</entry><entry namest="col2" nameend="col2" align="center">400</entry><entry namest="col3" nameend="col3" align="left">AP-CaO</entry><entry namest="col4" nameend="col4" align="center">130</entry></row><row><entry namest="col1" nameend="col1" align="left">CP-MgO</entry><entry namest="col2" nameend="col2" align="center">200</entry><entry namest="col3" nameend="col3" align="left">CP-CaO</entry><entry namest="col4" nameend="col4" align="center">100</entry></row><row rowsep="1"><entry namest="col1" nameend="col1" align="left">CM-MgO</entry><entry namest="col2" nameend="col2" align="center">10-30</entry><entry namest="col3" nameend="col3" align="left">CM-CaO</entry><entry namest="col4" nameend="col4" align="center">1-3</entry></row></tbody></tgroup></table></tables>

The compounds evaluated were three different types of magnesium oxide and three different types of calcium oxide. The three types of magnesium oxide were AP-MgO, CP-MgO, and CM-MgO. AP-MgO is magnesium oxide prepared according to an aerogel process, which is a non-evaporative process for forming nanoparticles. The CP-MgO is magnesium oxide formed according to conventional nanoparticles-forming processes, and the CM-MgO is commercially available magnesium oxide. The AP, CP and CM denominations have the same meaning for the calcium oxide particles as well.

The compositions of Table 1, as well as iron oxide-coated calcium oxide Fe₂O₃(CaO)-AP were evaluated at 40°C and at 120°C for adsorption capacity in terms of adsorption capacity (pounds of gas removed per pound of product), as were one commercial H₂S product bearing the trademark SULFATREAT™, from Sulfatreat Company.

Table 2 below sets forth the results in terms of adsorption capacity (lb/lb) for each oxide. <tables id="tabl0002" num="0002"><table frame="all"><title>Table 2</title><tgroup cols="4" colsep="1" rowsep="0"><colspec colnum="1" colname="col1" colwidth="39.37mm" /><colspec colnum="2" colname="col2" colwidth="39.37mm" /><colspec colnum="3" colname="col3" colwidth="39.37mm" /><colspec colnum="4" colname="col4" colwidth="39.37mm" /><thead valign="top"><row rowsep="1"><entry namest="col1" nameend="col1" align="left">Ads</entry><entry namest="col2" nameend="col2" align="left">Temp</entry><entry namest="col3" nameend="col3" align="left">Gas</entry><entry namest="col4" nameend="col4" align="left">Ads. Cap. (lb. gas rem/lb. product)</entry></row></thead><tbody valign="top"><row><entry namest="col1" nameend="col1" align="left">CaO-CP</entry><entry namest="col2" nameend="col2" align="left">40°C</entry><entry namest="col3" nameend="col3" align="left">H₂S</entry><entry namest="col4" nameend="col4" /></row><row><entry namest="col1" nameend="col1" align="left">CaO-CP</entry><entry namest="col2" nameend="col2" align="left">120°C</entry><entry namest="col3" nameend="col3" align="left">H₂S</entry><entry namest="col4" nameend="col4" align="char" char=".">0.628</entry></row><row><entry namest="col1" nameend="col1" align="left">Fe₂O₃(CaO) (AP)</entry><entry namest="col2" nameend="col2" /><entry namest="col3" nameend="col3" align="left">H₂S</entry><entry namest="col4" nameend="col4" align="char" char=".">0.54</entry></row><row><entry namest="col1" nameend="col1" /><entry namest="col2" nameend="col2" align="left">40°C</entry><entry namest="col3" nameend="col3" align="left">H₂S</entry><entry namest="col4" nameend="col4" align="char" char=".">0.43</entry></row><row><entry namest="col1" nameend="col1" align="left">Fe₂O₃(CaO) (AP)</entry><entry namest="col2" nameend="col2" align="left">120°C</entry><entry namest="col3" nameend="col3" align="left">H₂S</entry><entry namest="col4" nameend="col4" align="char" char=".">0.37</entry></row><row><entry namest="col1" nameend="col1" /><entry namest="col2" nameend="col2" /><entry namest="col3" nameend="col3" align="left">H₂S</entry><entry namest="col4" nameend="col4" align="char" char=".">0.19</entry></row><row><entry namest="col1" nameend="col1" align="left">MgO-AP</entry><entry namest="col2" nameend="col2" align="left">40°C</entry><entry namest="col3" nameend="col3" align="left">CO₂</entry><entry namest="col4" nameend="col4" align="char" char=".">0.12</entry></row><row><entry namest="col1" nameend="col1" align="left">Sulfatreat</entry><entry namest="col2" nameend="col2" align="left">40°C</entry><entry namest="col3" nameend="col3" align="left">CO₂</entry><entry namest="col4" nameend="col4" align="char" char=".">0.41</entry></row><row><entry namest="col1" nameend="col1" align="left">CaO-CP</entry><entry namest="col2" nameend="col2" align="left">40°C</entry><entry namest="col3" nameend="col3" align="left">H₂S</entry><entry namest="col4" nameend="col4" align="char" char=".">0.56</entry></row><row><entry namest="col1" nameend="col1" align="left">[Fe₂O₃]CaO</entry><entry namest="col2" nameend="col2" align="left">40°C</entry><entry namest="col3" nameend="col3" align="left">H₂S</entry><entry namest="col4" nameend="col4" align="char" char=".">0.48</entry></row><row><entry namest="col1" nameend="col1" align="left">Ca(OH)₂</entry><entry namest="col2" nameend="col2" align="left">40°C</entry><entry namest="col3" nameend="col3" align="left">H₂S</entry><entry namest="col4" nameend="col4" align="char" char=".">0.38</entry></row><row><entry namest="col1" nameend="col1" align="left">ZnO</entry><entry namest="col2" nameend="col2" align="left">40°C</entry><entry namest="col3" nameend="col3" /><entry namest="col4" nameend="col4" align="char" char=".">0.43</entry></row><row rowsep="1"><entry namest="col1" nameend="col1" align="left">ZnO</entry><entry namest="col2" nameend="col2" align="left">120°C</entry><entry namest="col3" nameend="col3" /><entry namest="col4" nameend="col4" /></row></tbody></tgroup></table></tables>

It should be readily appreciated that a method has been provided in accordance with the present invention which advantageously meets the objective set forth Herein, and which is particularly useful in removal of H₂S from hydrocarbon streams at surface or downhole locations.

It is to be understood that the invention is not limited to the illustrations described and shown herein, which are deemed to be merely illustrative of the best modes of carrying out the invention, and which are susceptible of modification of form, size, arrangement of parts and details of operation. The invention rather is intended to encompass all such modifications which are within its spirit and scope as defined by the claims.