NOVEL HIGH UPTAKE SULFUR SOLVENT SYSTEMS AND METHODS FOR MAKING AND USING SAME

[0001] 1. Field of the Invention

[0002] Embodiments of the present invention relates to compositions for dissolving or removing sulfur deposits from reservoir formations, production tubing and flow lines due to the production of sour gas and/or oil, and methods for making and using same.

[0003] More particularly, embodiments of the present invention relates to compositions for dissolving or removing sulfur deposits from reservoir formations, production tubing and flow lines due to the production of sour gas and/or oil, where the compositions include an effective amount of a reaction product of a diamine and an aldehyde or an aldehyde donor prepared at a diamine to aldehyde molar ratio between about 1:1 to about 1:6 and methods for making and using same.

[0004] 2. Description of the Related Art

[0005] Sulfur deposition is becoming more pronounced due to the number of wells that are now sour. Canada is one of the biggest producers of sour gas wells in the world and as a result has had to come up with methods to remove the sulfur from reservoir formations, production tubing and flow lines.

[0006] Currently, sulfur solvents are either used on a continuous or batch wise basis to remove sulfur deposition from formation surfaces and equipment surfaces. The sulfur solvents typically used are based either on amines, aromatic hydrocarbons, or dimethyl disulfide (DMDS). The first two products have limited sulfur uptake at room temperature (approximately 2%) and typically retain between 5% and 15% sulfur after reacting with sulfur at 80° C. DMDS on the other hand may have up to a 100% sulfur uptake at room temperature. However, there are handling and HSE issues with using DMDS based products, which limits their application especially if the problem exists outside of Canada. Current suppliers are of these sulfur dissolution products include Weatherford International Inc. or Clearwater International LLC for aromatic hydrocarbon based products and DMDS based products, Baker Huges for amine based product, and Multi-Chem Group for aromatic hydrocarbon products.

[0007] Hydrogen sulfide (H₂S) is a naturally occurring component during the production of crude oil and natural gas. The presence of H₂S in oil and gas is challenging because it is corrosiveness, scale forming, toxic, and posses environmental and safety concerns. In Alberta, Canada one-third of the natural gas wells contain H₂S. The main flow assurance problem associated with H₂S is elemental sulfur formation. Precipitation of elemental sulfur occurs when the thermodynamic conditions of the process changes. High temperature and pressure favors the formation of polysulfides, whereas a decrease in temperature and pressure favors the reverse reaction of polysulfide to elemental sulfur and H₂S¹, shown in the reversible reaction below:

H₂S+SxH₂S_x

[0008] Deposition of solid elemental sulfur may block pores in producing formations and/or may block production tubing, pipelines, and/or surface equipment. Sulfur has a tendency to bond extensively to itself forming chains such as S₈ molecules with a variety of molecular configurations. Sulfur also has the potential to act as a fairly strong oxidizing agent and causes corrosion in stainless steel equipment, particularly pitting and other forms of localized corrosion.

[0009] Different solvents have been used in the field to remove sulfur deposition from formation faces and production tubing strings. Based on the literature², elemental sulfur is dissolved in sour gas either by a physical or chemical mechanism with hydrogen polysulfide. Ockelmann and Blount (1973) reported that physical solvents of high aromatic content had higher sulfur carrying capacity than lean hydrocarbons' and this agrees with what is commercially available today especially with the SULPH-AMAX® (a registered trademark of Weatherford/Lamb, Inc.) product line. Chemical solvents work as a sulfur solvent by reacting with the S₈ ring. Most widely used chemical solvents are based on amines, which react with elemental sulfur in the presence of H₂S to produce ionic polysulfide according to the following reaction:

H₂S+amine→amineH⁺·SH⁻

[0010] Dimethyl disulfide (DMDS) is another sulfur solvent that dissolves sulfur more effectively through both physical and chemical interaction. However, the handling of a DMDS is difficult because of its strong unpleasant odor. Currently there is a significant difference in sulfur uptake between DMDS and the amine/hydrocarbon systems currently available.

[0011] While there are several options for removing elemental sulfur deposits from reservoir formations, production tubing and flow lines, there is still a need in the art for other compositions that are effective at removing elemental sulfur deposits from reservoir formations, production tubing and flow lines.

[0012] Embodiments of the present invention provide sulfur deposit dissolving or removal compositions including a reaction product of a diamine and an aldehyde or an aldehyde donor prepared at near equal molar ratio of the aldehyde to diamine. In certain embodiments, the aldehyde or aldehyde donor, where the aldehyde has the general formula R¹CHO, where R¹ is a hydrogen atom, a hydrocarbon group having between 1 and 20 carbon atoms, and mixtures or combinations thereof, and when R¹ is a hydrocarbon group, then R¹ may be linear, branched, cyclic, or any combination thereof. In certain embodiments, the aldehyde or the aldehyde donor include formaldehyde or a formaldehyde donor. In certain embodiments, the diamines are of general formula H₂N—R²—NH₂, where R² is a hydrocarbon group having between 3 and 20 carbon atoms and may be linear, branched, cyclic or any combination thereof. In certain embodiments, R² is a hydrocarbon group of the general formula —(CH₂)_n—, where n is an integer having a value between about 3 and about 20, an oxyhydrocarbon group of the general formula —((CH₂)_m)O)_nCH₂—, where m is an integer having a value between 1 and 3 and n is an integer having a value between about 1 to about 10 and a cyclic hydrocarbon group having between about 6 and about 20 carbon atoms or a mixture or combination thereof. In other embodiments, the diamines include a,w-diamino alkanes having between about 3 and 20 carbon atoms. In other embodiments, the diamines are selected from the group consisting of 1,3-diamine propane, 1,4-diamino butane, 1,5-diamine pentane, 1,6-diamine hexane, 1,7-diamine heptane, 1,8-diamine octane, higher a,w-diamino alkanes and mixtures or combinations thereof.

[0013] Embodiments of the present invention provide methods for removing or dissolving sulfur deposit on surfaces of producing formations, downhole equipment, and/or surface equipment, where the methods include contacting the surfaces with a sulfur dissolving or removal compositions including a reaction product of a diamine and an aldehyde or an aldehyde donor prepared at near equal molar ratio of the aldehyde to diamine. In certain embodiments, the aldehyde or aldehyde donor, where the aldehyde has the general formula R¹CHO, where R¹ is a hydrogen atom, a hydrocarbon group having between 1 and 20 carbon atoms, and mixtures or combinations thereof, and when R¹ is a hydrocarbon group, then R¹ may be linear, branched, cyclic, or any combination thereof. In certain embodiments, the aldehyde or the aldehyde donor include formaldehyde or a formaldehyde donor. In certain embodiments, the diamines are of general formula H₂N—R²NH₂, where R² is a hydrocarbon group having between 3 and 20 carbon atoms and may be linear, branched, cyclic or any combination thereof. In certain embodiments, R² is a hydrocarbon group of the general formula —(CH₂)_n—, where n is an integer having a value between about 3 and about 20, an oxyhydrocarbon group of the general formula —((CH₂)_m)O)_nCH₂—, where m is an integer having a value between 1 and 3 and n is an integer having a value between about 1 to about 10, a cyclic hydrocarbon group having between about 6 and about 20 carbon atoms, or mixtures and combinations thereof. In other embodiments, the diamines include a,w-diamino alkanes having between about 3 and 20 carbon atoms. In other embodiments, the diamines are selected from the group consisting of 1,3-diamine propane, 1,4-diamino butane, 1,5-diamine pentane, 1,6-diamine hexane, 1,7-diamine heptane, 1,8-diamine octane, higher a,w-diamino alkanes and mixtures or combinations thereof.

[0031] The inventors have found that reaction products of linear and cyclic diamines with aldehydes in a diamine to aldehyde mole ratio between about 1:1 and about 1:6 to produce compositions having unique sulfur uptake capabilities compared to amines alone or hydrocarbon sulfur solvents alone. Embodiments of the invention also relate to reaction products of linear and cyclic diamines with aldehydes in a diamine to aldehyde mole ratio between about 1:1 and about 1:3 to produce compositions having unique sulfur uptake capabilities compared to amines alone or hydrocarbon sulfur solvents alone. Embodiments of the invention also relate to reaction products of linear and cyclic diamines with aldehydes in a diamine to aldehyde of 1:1 mole ratio or at or near a 1:1 mole ratio to produce compositions having unique sulfur uptake capabilities compared to amines alone or hydrocarbon sulfur solvents alone. The term about means that the molar ratio value is within ±5. In other embodiments, the term means that the molar ratio value is within ±2.5. In other embodiments, the term means that the molar ratio value is within ±2. In other embodiments, the term means that the molar ratio value is within ±1. In other embodiments, the term means that the molar ratio value is within ±0.5. In other embodiments, the term means that the molar ratio value is within ±0.1. The term at or near 1:1 mole ratio means that the ratio may vary between 0.8:1.2 and 1.2:0.8. In other embodiments, the ratio may vary between 0.9:1.1 and 1.1:0.9. In other embodiment, the ratio may vary between 0.95:1.05 and 1.05:0.95. In other embodiment, the ratio may vary between 0.99:1.01 and 1.01:0.99. The inventors have found that the compositions of this invention are capable of sulfur uptake of up to 30% sulfur at room temperature and at elevated temperatures uptakes of sulfur of greater than 60% may be achieved without any sulfur separation after 24 hours, when the treated fluid is left to equilibrate at room temperature. The inventors have found that the methods for preparation of the reaction products include drop wise addition of the amine to formalin at a controlled rate such that the temperature during addition remains below about 110° C. The reaction is then refluxed with condensate removal to a temperature of below about 130° C. The inventors performed testing on neat compositions of this invention, both virgin and spent, with respect to corrosiveness, where the testing showed that composition of this invention may be prepared having less than 1 mpy for 1018 carbon steel. Even when the compositions of this invention were diluted 50% in fresh or produced water, uptakes of sulfur between about 20% and about 30% are still achievable at 80° C. In certain embodiments of this invention, the compositions are capable of sulfur uptake of at least 10% at 25° C. In other embodiments, the compositions are capable of sulfur uptake of at least 20% at 25° C. In other embodiments, the compositions are capable of sulfur uptake of at least 30% at 25° C. In other embodiments, the compositions are capable of sulfur uptake of at least 40% at 25° C. In other embodiments, the compositions are capable of sulfur uptake of at least 50% at 25° C. In certain embodiments of this invention, the compositions are also capable of sulfur uptake of at least 10% at 80° C. In other embodiments, the compositions are capable of sulfur uptake of at least 20% at 80° C. In other embodiments, the compositions are capable of sulfur uptake of at least 30% at 80° C. In other embodiments, the compositions are capable of sulfur uptake of at least 40% at 80° C. In other embodiments, the compositions are capable of sulfur uptake of at least 50% at 80° C. In other embodiments, the compositions are capable of sulfur uptake of at least 60% at 80° C.

[0032] The new products are different from amines and hydrocarbon based sulfur solvent products due to their unique ability to significantly uptake more sulfur by up to 15 times at room temperature and 5 times at 80° C. The resultant spent products are stable at room temperature and the products will still uptake the same corresponding amount of sulfur even when diluted. The new systems are not corrosive and have no handling issues requiring special equipment to deploy the products in the field or overseas.

[0033] Suitable aldehyde and aldehyde donors for use in the present invention include, without limitation, formaldehyde, formaldehyde containing solutions such as formalin, formaldehyde donors such as paraformaldehyde, aldehydes having the general formula R¹CHO, where R¹ is a hydrogen atom, a hydrocarbon group having between 1 and 20 carbon atoms, and mixtures or combinations thereof, when R¹ is a hydrocarbon group, then R¹ may be linear, branched, cyclic, or any combination thereof. Exemplary R¹ groups include, without limitation, a hydrogen atom, an alkyl group, an alkyleneoxide group, an aryl group, an alkaryl group, an aralkyl group, and mixtures or combinations thereof.

[0034] Suitable diamines for use in the present invention include, without limitation, diamines of the general formula H₂N—R²—NH₂, where R² is a hydrocarbon group having between 3 and 20 carbon atoms and may be linear, branched, cyclic or any combination thereof. In certain embodiments, R² is a hydrocarbon group of the general formula —(CH₂)_n—, where n is an integer having a value between about 3 and about 20, an oxyhydrocarbon group of the general formula —((CH₂)_m)O)_nCH₂—, where m is an integer having a value between 1 and 3 and n is an integer having a value between about 1 to about 10, a cyclic hydrocarbon group having between about 6 and about 20 carbon atoms, and mixtures or combinations thereof. Exemplary diamine include, without limitation, α,ω-diamino alkanes having between about 3 and 20 carbon atoms. Specific examples include 1,3-diamine propane, 1,4-diamino butane, 1,5-diamine pentane, 1,6-diamine hexane, 1,7-diamine heptane, 1,8-diamine octane, higher α,ω-diamino alkanes and mixtures or combinations thereof.

[0035] The candidates were prepared by either adding formaldehyde, a formaldehyde solution, or a formaldehyde donor to a diamine or diamine solution or adding a diamine or a diamine solution to formaldehyde a formaldehyde solution, or a formaldehyde donor with stirring.

[0036] This preparation illustrates the synthesis of composition SF2, which is a reaction product of formaldehyde as a 37 wt. % aqueous solution (formalin) and 1,4-diaminobutane. Table I lists that ingredients, molar equivalents, molecular weight, and weight of ingredient used.

TABLE I
Ingredients Used to Prepare SF2
	TMDA*	Formalin**
	Molar	1	1
	MW	88	30
	WT	704 g	648.6 g
	*1,4-diaminobutane (TMDA) (>99%) available from Sigma Aldrich Corporation
	**Formalin (37% formaldehyde solution) available from Clearwater International, LLC

[0037] The indicated amount of formalin was charged to the reactor and agitated. The indicated amount of TMDA was added drop wise to the formalin, while monitoring the temperature of the reaction mixture. The reaction is exothermic and a lot of heat was released upon contacting the ingredient. The reaction temperature was allowed to rise to 105° C. and the reaction mixture started to reflux, which occurred when about 20% of TMDA had been added. TMDA addition was stopped and the reaction mixture was allowed to cool to a temperature of about 90° C. Once the reaction mixture had cooled, TMDA drop wise addition was continued. All of TMDA was added over about 75 minutes. After all the TMDA was added into the reactor, the reaction mixture was heated to reflux. Some light yellow solid may form during addition of TMDA, but it dissolved soon after the heating was applied. The reaction mixture was heated to reflux at a reflux temperature of about 107° C. Heating was slowly increased to keep reaction mixture refluxing, but not over-heating. The color of reaction changes from colorless to light yellow. The reaction was heated over about a 6 hour period of time to a temperature of about 121° C. and 311 mL of condensate water was collected. The reaction mixture was finished by removing heating resource. The synthesis was carried out in a 3*24/40, 1*#7 2 L reactor for ACE Glass equipped with an agitation system, a 24/40 250 mm condenser, a 100 mL dropping funnel, a 25 mL condensate receiver, and 1000 mL flask.

[0038] All of the other compositions were made by an analogous synthetic procedure including compositions SF5 and SF7 using the amounts of the ingredients set forth in Table II below.

[0039] The sulfur carrying capacity of certain formaldehyde diamine reaction based compounds were investigated through sulfur uptake testing. Simple gravimetric analysis was used to determine the amount of sulfur dissolved by each composition. In each test, a known amount of sulfur dissolving composition and sulfur was placed into a round bottom flask, which was then sparged with H₂S gas for up to 3 minutes. A round bottom flask was placed on a rotary evaporator and subjected to a desired test temperature at 50 rpm as shown in FIG. 1. The experiments were stopped once all the sulfur had dissolved/reacted in the solution or the maximum time was exceeded, and the time to complete dissolution/reaction was noted. After each experiment, a weight of the remaining sulfur relative to initial sulfur present was determined and used to calculate the sulfur uptake.

[0040] Several studies were conducted to determine the best sulfur dissolving composition. Table II lists the formulas prepared for testing. Table III lists test conditions and sulfur uptake values at 80° C. for the sulfur dissolving compositions along with observations with respect to sulfur re-crystallization, once the fluids had equilibrated at room temperature.

TABLE II
Reaction Product Formulations
Formula	Reagents	Mole Ratio
SF1	amine heads and formalin	1:3
SF2	amine heads and formalin	1:1
SF3	1,6-diaminohexane and formalin	1:2
SF4	1,2-diaminocyclohexane and formalin	1:2.44
SF5	1,2-diaminocyclohexane and formalin	1:1
SF6	1,4-diaminobutane and formalin	1:2.44
SF7	1,4-diaminobutane and formalin	1:1
SF8	1,4-diaminobutane and formalin	1:2
SF9	1,4-diaminobutane and formalin	1:3
SF10	1,4-diaminobutane and formalin	1:6
SF11	1,4-diaminobutane and paraformaldehyde	1:6
SF12	amine heads and formalin	1:2.44
SF13	amine heads and formalin	1:2.4

TABLE III
Sulfur Uptake Efficiency Values in a H2S Environment at 80° C.
Formula	Time	S8 Uptake	Observation
SF1	7 h	<20	wt %	High Sulfur re-crystallized
				upon cooling
SF2	2 h	40	wt %	No sulfur re-crystallized upon
				cooling
SF3	3 h	<20	wt %	High Sulfur re-crystallized
				upon cooling
SF4	7 h	<10	wt %	High Sulfur re-crystallized upon
				cooling
SF5	3 h	40	wt %	No sulfur re-crystallized upon
				cooling
SF6	7 h	8	wt %	Small amount of sulfur re-
				crystallized upon cooling
SF7	3 h	40	wt %	No sulfur re-crystallized upon
				cooling
SF8	7 h	29	wt %	Small amount of sulfur re-
				crystallized upon coolin
SF9	7 h	10	wt %	Slight sulfur re-crystallization
				within 24 hrs
SF10	7 h	17	wt %	No sulfur re-crystallized upon
				cooling
SF11	4 h	<20	wt %	High sulfur re-crystallization
				upon cooling
SF12	3 h	15	wt %	No sulfur re-crystallization,
				hazy like solution at the bottom
SF13	3 h	<15	wt %	High sulfur re-crystallization
				upon cooling

[0041] Among the compounds tested, SF2, SF5, and SF7 exhibited the highest sulfur uptake and exhibited the fastest sulfur uptake kinetics. The above results confirm that reaction products of formaldehyde (formalin) and a diamine or mixture of diamines prepared using a near 1:1 mole ratio produces sulfur uptake compositions having the highest and fastest sulfur uptake at 80° C. While not intending to be bound by any theory, it is hypothesized that the amino groups present in the reaction products may open the eight-membered sulfur ring making the resulting opened sulfur chains more reactive with the reaction products dissolving/reacting/removing sulfur deposits.

[0042] Based on the screening results, compositions including reaction products of formaldehyde (formalin) and a diamine or a mixture of diamines as at a near 1:1 mole ratio produce highly effective sulfur dissolving compositions as shown in FIG. 2. Thus, compositions SF2, SF5, and SF7 showed superior sulfur uptake over the other ratios tested. In order to simplify the testing, a simple corrosion test was performed to see which of these three highly effective products had the lowest corrosion rate for the unreacted products. We had already found that certain amine type sulfur removal compositions cause high corrosion rates, which may be problematic when applying them in the field. The results showed that SF7 had the lowest corrosion rate, while SF5 showed the highest corrosion rate (17.10 mpy). Because SF7 and SF2 showed the lowest corrosion rates, these products were chosen for H₂S tolerance testing.

[0043] It is common knowledge that H₂S scavengers based on triazine chemistry have a tendency to form solids in the presence of excess H₂S, which could cause detrimental problems as these solids are not generally soluble in known solvents. In order to check the H₂S solubility tolerance of SF2 and SF7, 100% H₂S was bubbled through solutions of SF2 and SF7 for 30 minutes to see if any solids were formed. SF5 was not chosen due to its high corrosion rate. Because there was a possibility that unreacted formaldehyde was present, the chosen products were heated to 120° C. under vacuum to remove any water/methanol and formaldehyde present.

[0044] The results showed that the amine heads version SF2 even after the removal of any excess formaldehyde showed solids formation in the presence of excess H₂S, whereas the 1-4-diaminobutane version SF7 did not show any solids formation even after 10 days as shown in FIG. 3. As a result of the H₂S tolerance test and the corrosion test, we proceeded with further testing using SF7.

[0045] In order to evaluate the kinetics or how fast elemental sulfur is dissolved/reacted using SF7, experiments were conducted at different temperatures in a rotary evaporator as described above. The testing was performed with and without the presence of H₂S to assess, if H₂S catalyzed the reaction.

[0046] In the presence of H₂S, the reaction kinetics was faster and the uptake was 50 wt % at 80° C. and 100° C. Once the fluids had equilibrated at room temperature, the sulfur remains in solution for 12 hours after which the sulfur re-crystallized. In order to reduce sulfur re-crystallization, experiments were carried out with 40 wt % sulfur. At 40 wt. % sulfur, sulfur did not re-crystallize from the SF7 containing composition. Referring now to FIG. 4A, as the reaction temperature was increased, the rate and uptake of sulfur by a SF7 containing composition increased. While temperature is known to increase rates of reaction, it was unexpected that increasing temperature would result in the simultaneous increase in rate and uptake.

[0047] In the absence of H₂S, the sulfur uptake kinetics was noticeably slower at 40° C. as it took almost 65 hours to dissolve 35 wt. % sulfur compared with 24 hours in the presence of H₂S. In addition, more sulfur re-crystallization was observed from tests conducted at 80° C. and 100° C. compared with tests performed in the presence of H₂S. Re-crystallization of sulfur began after two days in both 80° C. and 100° C. tests as shown in FIG. 4B.

[0048] After the experiments, the test samples were tested for the presence of H₂S using a Multiwarn H₂S monitor. Experiments conducted at room temperature and 40° C. showed no H₂S/Mercaptan was present in the headspace; however, the experiments conducted at greater than or equal to 80° C. generated H₂S/Mercaptan. It is possible that at higher temperatures, the process actually uses H₂S to catalyze the reaction and hence the re-generation.

[0049] In order to compare the influence of CO₂ on sulfur uptake and uptake rate, experiments were conducted in the presence of H₂S and CO₂ to see how long it took to uptake 40 wt. % of elemental sulfur. The SF7 containing composition was purged as follows and then placed on the rotor-evaporator:

[0050] Test 1 was sparged with H₂S for 3 minutes. Test 2 was sparged with 100% CO₂ for 1.5 minutes and 100 H₂S for 1.5 minutes for a total of 3 minutes. Test 3 was sparged with a gas mixture containing 3% CO₂ and 10% H₂S for 3 minutes as shown in FIG. 4C. The data showed that the reaction proceeds at slower rate (approximately 50%) in the presence of CO₂ compared to H₂S alone.

[0051] SF7 uptake at 80° C. was reduced by 50% by adding 50% water or synthetic brine (100,000 ppm chlorides) however if we take in to account the dilution factor then the uptake is not affected by either fresh water or brine. With respect to the kinetics it was observed that the high salinity brine showed a 50% reduction in the time required to uptake 40% sulfur when 10% brine was present. There was only a marginal improvement in uptake kinetics when 50% brine was used as shown in FIG. 5.

[0052] The data from FIG. 5 shows that there is no negative effect on the sulfur uptake when using either freshwater or brine. It was observed that when we use the brine in the system it forms a hazy solution at the bottom after 24 hours as shown in FIG. 6. The solution was not a solid and moved freely and is not expected to be a problem

SF7 Sulfur Uptake under Temperature and Pressure

[0053] Solubility of sulfur in the sour gas depends upon temperature, pressure and sour gas composition. Hence, in this stage, bench top autoclave was used to conduct the sulfur uptake under pressure (100 psi) and different composition of H₂S. 40 wt % of sulfur in 200 g of sulfur solvent was placed in an autoclave and then pressurized with different compositions of H₂S gas as shown in Table IV. The autoclave was heated to 80° C. for the predetermined time of 16 h at 300 rpm. Upon test completion, the autoclave was degassed in the fume hood and the sulfur solvent was removed to check its sulfur uptake.

TABLE IV
Sulfur uptake Testing Parameters
	Test Number	Gas composition
	Test 1	H2S sparge for 3 mins
	Test 2	2% H2S
	Test 3	20% H2S
	Test 4	20% H2S + 3% CO2
	Test 5	20% CO2 + 3% H2S

Tests 1 to Test 4 showed a 40 wt % sulfur uptake in 16 h, whereas Test 5, which was a CO₂ dominant environment (20% CO₂+3% H₂S), showed a 12.5 wt. % sulfur uptake. The decrease in the sulfur dissolution activity may be due to the formation of carbamate salts during the test.

2R-NH₂+CO₂→RHNCOO⁻.RNH₃⁺

[0054] Literature also reported that the amine-based solvent in CO₂-dominant environment had lower sulfur uptake than that for predominantly H₂S environment⁶. After completing the experiment all samples were kept at room temperature for several days and no re-crystallization of sulfur was found in Test 1 to Test 4, however sulfur did re-crystallize in the CO₂ dominant environment after 24 hours.

[0055] The water content of SF7 was determined using the Karl Fischer method, and it was measured at 40 wt %. Using rotor-evaporator at a temperature of 120° C., 20 wt % of a water/methanol/formaldehyde blend was removed from the composition and the activity was increased to 80 wt. %. The concentrated SF7 sulfur uptake was conducted at different temperatures, namely room temperature, 40° C. and 80° C. for 24 hours.

[0056] As can be seen from FIG. 7 the uptakes were 30 wt. % at room temperature and 65 wt. % at 80° C. No sulfur re-crystallized was observed in the system even after one week.

[0057] The increase in the room temperature sulfur uptake suggests that something more maybe happening than just removing water, methanol, and formaldehyde as this uptake doubles. It could be possible that we are driving the reaction to completion as per Le Chateliers Principle or we may be even polymerizing the reaction product.

[0058] This part of the study was performed to evaluate the corrosion properties of the sulfur solvent on 1018 carbon steel as per what could potentially happen in the field. Corrosion studies were performed on the virgin and spent fluids in the presence of freshwater and brine (100,000 mg/L Chloride) to simulate the two extremes seen in the field. The tests were performed according to the set up shown in FIG. 8.

[0059] Each coupon was pre-weighed and immersed in a test solution and placed in a high-temperature, high-pressure autoclave for 3 days. Table V lists the experimental conditions for the corrosion test. After 3 days, the coupons were rinsed to remove residual test solution and loose corrosion products with inhibited hydrochloric acid and dried. Each coupon was weighed and the change in weight during immersion was used to determine the corrosion rate.

TABLE V
Stirred Autoclave Test Conditions
	Temperature	80° C.
	H2S partial Pressure	100	psi
	CO2 Partial Pressure	15	psi
	Total Pressure	500	psi
	Test Duration	3	days
	Flow Regime	No Stirring

[0060] Testing was also run to simulate under deposit elemental sulfur corrosion to see whether there was any negative impact from using the new solvent. In the presence of water, sulfur is capable of producing acid by a hydrolysis reaction which leads to severe corrosion problems. Further, elemental sulfur can cause extremely high corrosion rates when it has direct contact with steel surfaces⁷.

[0061] The corrosion study was split in two parts where corrosion testing was done without sulfur and the second where sulfur was melted on to the coupon to simulate under deposit corrosion as can be seen in FIG. 9. In the first part, we evaluated the effect of just the sulfur dissolution composition virgin and spent compositions. In the second part of the study, we simulated sulfur deposition by melting 3 grams of elemental sulfur on one side of the coupon as per FIG. 9 and measured the corrosion rate in the presence of the virgin sulfur dissolution composition.

[0062] Spent dissolution composition was prepared by sparging the composition with H₂S and then adding 30 wt % of sulfur and heating to 80° C. for 16 hours. After 16 hours, the spent composition was cooled down to room temperature and loaded into the autoclave for the corrosion test. The corrosion tests were set up as per Table VI using the conditions in Table V.

TABLE VI
Composition of the Spent Sulfur Dissolution Compositions
Spent Dissolution Composition	Formulation
A	90% SF2 + 10% brine
B	90% SF2 + 10% tap water
C	75% SF2 + 25% brine
D	75% SF2 + 25% tap water

[0063] FIG. 10 showed the rate of corrosion for brine and tap water with/without sulfur. FIG. 11 showed the rate of corrosion for the spent sulfur solvent in the presence of brine and tap water. FIG. 12 showed the rate of corrosion for simulated under deposit sulfur corrosion. FIGS. 10 and 14 showed how corrosive sulfur is when it is deposited on a metal surface with corrosion rates of 120 mpy and severe pitting. Even with freshwater one can see corrosion rates of 20 mpy without sulfur and nearly 40 mpy with sulfur with visible pitting. FIG. 11 shows the corrosion rates for the spent solvent and the results clearly show that the corrosion rate is extremely low compared with the blank and there were no visible pits as can be seen from FIG. 13. FIG. 12 clearly shows that even in the presence of sulfur deposition SF7 actually aids in preventing corrosion as compared to the blank. The virgin SF7 exhibits no corrosion potential and as a result shows zero corrosion even in such a corrosive environment.

[0064] The following references were cited in the specification:

• • [0065] 1. Hyne, J. B, “Study aids predication of sulfur deposition in sour gas wells,” Oil & Gas J. (25 Nov. 1968) 107.
  • [0066] 2. S. A. Al-Mutairi, A. I. Abdulhadi, and I. M. Al-Taie, “Sour Gas Dehydration System: Corrosivity and Selection in the Presence of Elemental Sulfur”, Corrosion/2003, Paper no. 07397, NACE International, Houston, Tex., 2007.
  • [0067] 3. H. Ockelmann, F. E. Blount. “Ten Years Experience with Sour Gas Production in Germany”, Paper presented at 48th Annual Fall Meeting of the Society of Petroleum Engineers of AIME (September 1973).
  • [0068] 4. T. K. Wiewiorowski, F. J. Touro, J. Phys. Chem. 70 (1966) 234-238.
  • [0069] 5. R. A. Marriott, Ed Fitzpatrick, K. L. Lesage, “The solubility of H₂S in liquid sulfur”' Fluid Phase Equilibria 269 (2008) 69-72.
  • [0070] 6. L. J. May and W. Wamburi, “Sulfur solvents: Understanding operating envelopes through laboratory studies and field case histories,” NACE International, Houston, Tex., 2007.
  • [0071] 7. H. Sun, H. Fang, J. Davis, R. Hudgins, “Elemental Sulfur Corrosion and Inhibition in the Presence of Sulfur Solvent,” NACE International, Houston, Tex., 2011.

[0072] All references cited herein are incorporated by reference. Although the invention has been disclosed with reference to its preferred embodiments, from reading this description those of skill in the art may appreciate changes and modification that may be made which do not depart from the scope and spirit of the invention as described above and claimed hereafter.