Background of Invention

[0001] The need for effective methods and compositions for scavenging hydrogen sulfide and/or other sulfur containing compounds, such as mercaptans, from fluids, especially hydrocarbon-containing liquids and gases produced from wells, has long been recognized. Unless removed or reacted to form other compounds, sulfide contaminants in such fluids are undesirable and hazardous because of the associated corrosivity and toxicity. A large number of compositions are known for removing or reducing the content of hydrogen sulfide and mercaptans in natural gas, crude oil, and other hydrocarbon streams.

[0002] One such group of compositions include those based on alkanolamine and aldehyde reaction products such as described in U.S. Pat. No. 4,978,512 which issued on Dec. 18, 1990 to Quaker Chemical Corporation. These reaction products include triazine compounds, and in particular 1,3,5 tri-(2-hydroxy-ethyl)-hexahydro- S-triazine. While alkanolamine and aldehyde reaction products such described in U.S. Pat. No. 4,978,512 are effective hydrogen sulphide scavengers, they are known to form solids upon reaction with hydrogen sulphide. In particular, the reaction with hydrogen sulphide forms dithiazine which is not water soluble. Dithiazine forms a separate liquid phase or layer in gas processing equipment. In temperatures of about 20° C. or lower, solid dithiazine crystals form in this layer and precipitate out of solution.

[0003] Substantial amounts of dithiazine solid deposit buildup routinely occurs in gas processing equipment, particularly in colder weather applications. These dithiazine deposits are crystalline in nature and are particularly difficult to remove. For example, in bubble tower gas contactors, dithiazine crystals build up in the bottom of the tower and plug the lines through which the spent scavenger chemical is drawn off. Similarly, dithiazine forms a solid crystalline layer in the bottom of the spent scavenger chemical storage tanks located at the well site. Even for inline injection applications, dithiazine crystals tend to accumulate in areas of line restriction such as chokes and in dips or "dead spots" in the gas line.

[0004] Further, crystallization can occur in bulk truck tanks used to haul away spent product and can cause plugging problems in produced water disposal wells. An enormous amount of effort continues to be expended simply in cleaning out gas processing equipment to remove dithiazine deposits. Often, the only practical solution is to manually chip away the deposits and/or dissolve the dithiazine deposits by steam or hot water.

[0005] A second method for the removal of mercaptans from liquid hydrocarbons involves aqueous treatment methods, hi one conventional method, the hydrocarbon contacts an aqueous treatment solution containing an alkali metal hydroxide, such as sodium hydroxide. The hydrocarbon contacts the treatment solution, and mercaptans are extracted from the hydrocarbon to the treatment solution where they form mercaptide species. The hydrocarbon and the treatment solution are then separated, and a treated hydrocarbon is conducted away from the process. Intimate contact between the hydrocarbon and aqueous phase leads to more efficient transfer of the mercaptans from the hydrocarbon to the aqueous phase, particularly for mercaptans having a molecular weight higher than about C4.

[0006] However, such intimate contact often results in the formation of small discontinuous regions (also referred to as "dispersion") of treatment solution in the hydrocarbon. While the small aqueous regions provide sufficient surface area for efficient mercaptan transfer, they adversely affect the subsequent hydrocarbon separation step and may be undesirably entrained in the treated hydrocarbon.

[0007] In another conventional method, an aqueous treatment solution is prepared by forming two aqueous phases. The first aqueous phase contains alkylphenols, such as cresols (in the form of the alkali metal salt), and alkali metal hydroxide, and the. second aqueous phase contains alkali metal hydroxide. Upon contacting the hydrocarbon to be treated, mercaptans contained in hydrocarbon are removed from the hydrocarbon to the first phase, which has a lower mass density than the second aqueous phase. Undesirable aqueous phase entrainment is also present in this method, and is made worse when employing higher viscosity treatment solutions containing higher alkali metal hydroxide concentration.

[0008] Other methods for removing or deactivating sulfur containing species have also been attempted. For example, U.S. Pat. No. 4,252,655 discloses the use of organic zinc chelates for the removal of hydrogen sulfide in fluids for drilling, completing or servicing wells. Multi-component systems have also been attempted. For example, U.S. Pat. No. 4,748,011 discloses a method for the separation and collection of natural gas that uses a "sweetening solution." The sweetening solution consists of an aldehyde or a ketone, methanol, an amine inhibitor, sodium or potassium hydroxides and isopropanol. The amine inhibitor includes alkanolamines to adjust the pH.

[0009] Other commercially available compounds generally classified as anti¬ microbial agents, bactericides, fungicides and preservatives have previously been recognized for their usefulness in reducing microbial, bacterial or slime contamination of aqueous fluids. In some instances, such fluids have also been disclosed for use in controlling the growth of sulfate-reducing bacteria in oil field flooding applications to minimize plugging and corrosion. Such agents are typically injected into fluid streams at a single point in concentrated form. Single point injection causes a high concentration of hydrogen sulfide scavenger in the bulk fluid at the point of injection, but does not facilitate uniform or maximum distribution of the chemical agent throughout the hydrogen sulfide-containing fluid.

[0010] Various other compositions have also been proposed and used for the treatment of hydrocarbons to remove or reduce hydrogen sulfide and/or mercaptan contaminants. See, for example, Gatlin's U.S. Pat. Nos. 5,128,049, 5,486,605, 5,488,103, and 5,498,707. More recent systems include the use of potassium formate with a sulfide scavenger to remove and treat hydrocarbons. For example, U.S. Publication No. 20020157989 discloses the use of an aqueous potassium formate solution and sulfide scavenger. [0011] What is still needed, however, are simple, effective systems that are capable of removing or deactivating the general mercaptan or hydrogen sulfide compositions found in hydrocarbon fluids.

Summary of Invention

[0012] In one aspect, the present invention relates to a method for reducing the levels of sulfide impurities in a hydrocarbon stream, the method including contacting an effective amount of a compound as shown below with the hydrocarbon stream:

where R is a hydrogen or halogen, R1 is a halogen, and R2 may be H, an alkyl group having 1-6 carbons, an alkene group having 1-6 carbons, or an aromatic group.

[0013] Other aspects and advantages of the invention will be apparent from the following description and the appended claims.

Detailed Description

[0014] In one aspect, the present invention relates to a method and compound for reducing the amount of hydrogen sulfide, mercaptans and other sulfur containing species in hydrocarbon fluids (which expressly includes both liquid and gas). More particularly, the present invention relates to the use of a known class of compounds as an agent to reduce or deactivate sulfur containing species in hydrocarbon fluids.

[0015] Specifically, embodiments of the present invention relate to methods which use compositions that include a compound having a structure represented by Formula 1 below:

Formula 1

where R is a hydrogen or a halogen, Ri is a halogen, and R2 may be H, an alkyl (C1-C6), an alkene (C1-C6), or an aromatic group.

[0016] More specific embodiments of the present invention use an effective amount of the following compound:

Formula 2

[0017] An "effective amount," as used herein refers to the amount sufficient to reduce the hydrogen sulfide or mercaptan contamination in the hydrocarbons below a desired or predetermined level. One of ordinary skill in the art would appreciate the effective amount is a function of the concentration of the sulfur contaminants and the volume of the hydrocarbons to be treated. Those having ordinary skill in the art will recognize that Formula 2 is the chemical structure for 2,2- Dibromonitrilopropionamide (hereinafter DBNPA). DBNPA is a known biocide, which may be obtained by the bromination of cyanoacetamide in an aqueous medium. U.S. Patent No. 4,925,967, for example, discloses one prior art technique for the preparation of DBNPA. That patent is expressly incorporated by reference in its entirety.

[0018] Those having ordinary skill will recognize that a number of derivatives of DBNPA may be formed that fall within the scope of Formula 1 above, without resorting to undue experimentation. For example, chloro or iodo derivatives may be used.

[0019] The following test illustrates the efficacy of DBNPA as an agent to remove mercaptans and other sulfide compounds. The various chemicals (listed in table 1 below), were evaluated using the following test procedure: First, 25 ml of oil was transferred to a 125 ml Erlenmeyer flask fitted with a stopper and containing a stir bar. Second, 38 μl (approximately 1520 ppm by volume) of the potential sulfide scavenger was added to the Erlenmeyer flask. Third, the flask was placed in a water bath maintained at 54 0C, while stirring. After one hour, the flask was poured into a titration beaker for analysis. In order to determine the mercaptan content of the oil, UOP 163 "Hydrogen Sulfide and Mercaptan Sulfur in Liquid Hydrocarbons," was followed. The results of the test are shown in Table 1 below:

Table 1 - Comparative results of mercaptan scavengers

[0020] Table 1 shows that DBNPA, under the above conditions, is an effective mercaptan scavenger. As explained in the background section, the reduction of mercaptans is extremely important due to toxicity, corrosion, and purity concerns. In particular, as governmental regulation of hydrocarbon production increases, more stringent environmental regulations are being placed on the hydrocarbon producing industry.

[0021] The efficacy of DBNPA as a hydrogen sulfide or mercaptan scavenger at various concentrations was then tested. Table 2 below illustrates the results on mercaptan concentration under the testing conditions described above for various concentrations of DBNPA. Table 2: Efficacy of DBNPA at varying concentrations

[0022] Table 2 above illustrates that DBNPA is effective as a sulfide scavenger at varying concentrations. At approximately 1500 ppm, most (>90%) of the mercaptan was removed or deactivated. Thus, for this particular oil sample, 1500 ppm by volume of DBNPA is an effective amount.

[0023] The hydrocarbon streams can contain quantities of sulfur impurities from less than 1 ppm sulfur to over 100,000 ppm, typically from about 10 to about 2000 ppm, more typically from about 10 to 2000 ppm. Such hydrocarbon streams can be effectively treated in accordance with this invention to reduce the sulfur contamination to a selected level, which may be based on a number of conditions, such as cost of treatment, duration of treatment, method of injection, etc.

[0024] Those having ordinary skill in the art will recognize that a number of different methods may be used to inject the sulfide scavenger into a hydrocarbon stream. In a preferred embodiment, DBNPA is dissolved in an alcoholic solvent, such as monoethylene glycol, and injected into a hydrocarbon stream. Such an approach may be preferred because it does not, in general, require modification of the process equipment, temperature, or pH. Additionally, test results have shown that other chemicals are not required in order to achieve efficient reduction of mercaptans. In particular, embodiments of the invention do not require the addition of formate.

[0025] In preferred embodiments, the sulfide scavenger is injected at a concentration sufficient to reduce the mercaptan concentration to values below approximately 5-15 ppm. The above described procedure may be used with hydrocarbon streams that are naturally contaminated with hydrogen sulfide or mercaptans, or may be used with hydrocarbon streams that have become contaminated as a result of being transported in a pipeline that was previously used to transport sour hydrocarbon streams, such as sour petroleum crudes. In the latter case, it is known that residual sulfur from the sour crudes may contaminate the pipeline. Non-limiting examples of hyrdocarbon streams that can be treated in accordance with the present invention include gasoline, jet fuel, diesel fuel, kerosene and dialkyl ethers containing same. Alkyl ethers are typically used to improve the octane rating of gasoline. These ethers are typically dialkyl ethers having 1 to 7 carbon atoms in each alkyl group. Illustrative ethers are methyl tertiary-butyl ether, methyl tertiary-amyl ether, methyl tertiary-hexyl ether, and ethyl tertiary-butyl ether.

[0026] The proportion of sulfide scavenger to solvent in a "treating solution" in accordance with embodiments of the invention may vary within a wide range. As noted above, the solvent may be any number of compounds, but alcoholic solvents are typically preferred. Typically, the treating solution contains sulfide scavenger in the range of about 5% to 50%.

[0027] The amount of the treating solution used in the field may vary from about 10 ppm to about 2000 ppm. The relative amount of treating solution in the hydrocarbon stream to be treated may also vary within a wide range, depending on the concentrations of the sulfur-containing contaminants.

[0028] Treating conditions that can be used in the practice of the present invention may be adapted to fit conditions used in conventional oil field operations. For example, the contacting of the hydrocarbon stream to be treated is preferably effected at ambient temperature conditions, although higher temperatures up to about 100° C, or higher, may be used. Substantially atmospheric pressures are suitable, although higher pressures, for example, up to about 1,000 psig may also be used.

[0029] As previously noted, contact times may also vary widely depending on the hydrocarbon stream to be treated, the amount of sulfhydral group therein, and the concentration of the treating solution. The contact time should be chosen to effect the desired degree of mercaptan reduction. Contact times will generally range from about a few minutes to a few hours. [0030] Advantageously, embodiments of the present invention may be used to scavenge hydrogen sulfide and mercaptans from a variety of hydrocarbon streams, including sour natural gas streams and liquid hydrocarbon streams. The sulfide scavenger of the present invention can be contacted with natural gas by a number of means including inline injection or with a contact scrubber tower. Further, the sulfide scavengers of the present invention may advantageously be used to reduce the level of hydrogen sulfide in natural gas streams to pipeline specifications (which is typically 16 ppm or lower) or to 0 ppm. Significantly, DBNPA used in preferred embodiments is a common biocide used in water treatment. This chemical is relatively benign to the environment, which is an important consideration in oilfield operations.

[0031] As previously noted, while a general class of compounds has been described, those having ordinary skill in the art will appreciate that other R-SH alkylating agents may be used in connection with the present invention. In particular, iodoacetic acid, iodoacetamide, N-akyl malemide, will also work.

[0032] While the invention has been described with respect to a limited number of embodiments, those skilled in the art, having benefit of this disclosure, will appreciate that other embodiments can be devised which do not depart from the scope of the invention as disclosed herein. Accordingly, the scope of the invention should be limited only by the attached claims.