EP1349904B1

EP1349904B1 - Hydrogen sulphide scavenging method in hydrocarbon feedstocks

Info

Publication number: EP1349904B1
Application number: EP01270582A
Authority: EP
Inventors: John Andrew Hardy; Waleed John Georgie
Original assignee: Amerada Hess Ltd
Current assignee: CNOOC Petroleum Europe Ltd
Priority date: 2000-12-14
Filing date: 2001-12-13
Publication date: 2005-06-29
Anticipated expiration: 2021-12-13
Also published as: ATE298779T1; WO2002048284A8; WO2002048284A1; EP1349904B8; DE60111778D1; US20040074813A1; NO20032669D0; EP1349904A2; BR0116164A; CA2432071A1; NO20032669L; AU2002222189A1; GB0030555D0

Abstract

A process for scavenging hydrogen sulphide from a mixed phase system, in particular a hydrocarbon fluid having a liquid phase and a gaseous phase, is described. The hydrocarbon fluid contains a high level of hydrogen sulphide, which can be above 5000 ppm by weight in the gaseous phase of the fluid prior to treatment. Formaldehyde, preferably water, with is added to the fluid. The process is particularly useful for in-line scavenging of hydrogen sulphide from sour crude oil containing very high hydrogen sulphide levels. The hydrogen sulphide content of the crude oil that is delivered to the platform is reduced to safe and commercially acceptable levels and solid by-product formation is insignificant. This process thus advantageously provides a low cost manner of developing sour oil fields that would otherwise not be safe or economically viable to develop or advantageously provides a way of modifying existing processes of handling sour hydrocarbon fluids, for example, within oil fields already in production, such that the method according to the present invention replaces existing methods adopted.

Description

This invention relates to a high efficiency chemical scavenging method for reducing hydrogen sulphide in multiphase well streams, in particular where conventional methods of removal such as the use of an amine plant is not commercially viable.

Background

The presence of hydrogen sulphide in hydrocarbon fluids is a well known problem in many oil and gas fields. Hydrogen sulphide is an undesirable contaminant which presents many environmental and safety hazards. It is corrosive, malodorous, toxic if inhaled, a strong irritant to eyes and mucous membranes and is associated with the formation of acid rain. Accordingly it is necessary to remove hydrogen sulphide from hydrocarbon production, or at least reduce the levels of hydrogen sulphide in hydrocarbons during the production, storage or processing of hydrocarbon fluids to levels that satisfy safety and product specification requirements.

Methods of removing or reducing hydrogen sulphide in hydrocarbon production by treating the gas phase, commonly termed hydrogen sulphide "removal" or "scavenging" processes, are well known in the art. The methods are generally described as being regenerative (recoverable) or non-regenerative (non-recoverable). One known regenerative approach used in the oil industry is to install contactor-based recoverable scavenging systems which use suitable recoverable chemical solvents such as alkanolaines to act as hydrogen sulphide absorption compounds which remove hydrogen sulphides from the gas phase of separated production streams.

Most commonly non-regenerative chemical scavengers are injected into the gas phase. The non-regenerative scavengers, such as triazines typically react with the toxic hydrogen sulphide in-line to form a sulphur-containing by-product. Such non-recoverable systems are described for example in GB 22900542 A, EP-A-0411745, US5354453, US6063346, US5674377, US5554349 and US5744024.

Moreover, US6063346 describes the use, inter alia, of formaldehyde to scavenge hydrogen sulphide non-regeneratively from a hydrocarbon fluid that contains, by weight of the fluid, between 5ppm and 200ppm of hydrogen sulphide prior to treatment. However, it has, up until the present invention, not been considered feasible to remove hydrogen sulphide from hydrocarbon fluids and, in particular, multiphase well streams and other unprocessed streams containing higher concentrations of hydrogen sulphide by non-regenerative means.

Although contactor-based recoverable scavenging systems are used to treat hydrocarbon fluids containing high concentrations of hydrogen sulphide, these systems have had limited application away from processing sites or for relatively small fields with low production rates, whether on-shore or off-shore. This is largely because of the high capital and operating costs and the safety issues that bringing such high levels of hydrogen sulphide onto offshore platforms present. Furthermore, it has been generally considered the non-recoverable in-line methods would require the use of prohibitively high amounts of chemical scavenger in order to reduce the hydrogen sulphide levels sufficiently and would promote the undesirable formation of large amounts of reaction products. Accordingly, the development of small offshore oil fields that contain such high levels of hydrogen sulphide (250 ppm or more) has not been considered to be economically viable or safe and thus oil production form such fields is presently extremely rate.

Accordingly, a need has been long felt in the industry to develop a process which can successfully reduce hydrogen sulphide concentrations to safe levels in multiphase production containing high levels of hydrogen sulphide, whilst overcoming problems such as high cost, unacceptable safety hazards and unmanageable solid by-product formation, that are associated with developing sour oil reservoirs.

Summary of the Invention

According to the present invention there is provided a method for reducing the amount of hydrogen sulphide in a multiphase hydrocarbon produced fluid prior to phase separation and processing, the method comprising the step of adding formaldehyde to the produced fluid, which produced fluid had, prior to the addition of formaldehyde, a concentration of hydrogen sulphide of at least 250ppm by weight of the fluid.

It has surprisingly been found that formaldehyde can be used successfully to reduce the hydrogen sulphide content of produced fluid that initially contains such high levels of hydrogen sulphide which can be 10,000 ppm or more in the gas phase and more particularly more than 250 ppm by weight of the multiphase hydrocarbon fluid overall. Such technology is highly advantageous since it allows, for example, oil production from fields containing reservoir fluids having a hydrogen sulphide content that is too high to satisfy safety requirements or for commercial acceptance, and which would otherwise be left undeveloped, in a manner which is highly effective and provides significant safety benefits at relatively low cost.

The method of the invention is particularly valuable because of its effectiveness on the liquid phase of the multiphase system. In general, the multiphase system will be crude oil which typically comprises a liquid phase and an associated gas phase and may contain water as a liquid phase additional to an oil phase and/or as part of an oil/water phase. It is any such system which is referred to herein as "produced fluid".

The method thus has particular application in the oil industry, for example where the hydrocarbon fluid is an oil reservoir fluid, such as crude oil and its associated gas, and where the oil well produced fluids (crude oil having a liquid phase and associated gas phase) flow through a sub-sea flowline.

Although the method of this invention can be used to good advantage when the produced fluid flows through an on-shore pipeline, the method is particularly useful for in-line scavenging of hydrogen sulphide from a subsea well-produced sour crude oil containing very high hydrogen sulphide levels and where the well is tied back via a flow line to a host facility at which there is no provision for H₂S scavenging and/or where a H₂S removal facility is too expensive and/or impractical to install. As a result of this method, the hydrogen sulphide content of the crude oil that is delivered to the platform is reduced to safe and commercially acceptable levels and reaction by-product formation is manageable. This process thus advantageously provides a low cost manner of developing sour oil fields that would otherwise not be safe or economically viable to develop or advantageously provides a way of modifying existing processes of handling sour hydrocarbon fluids, for example, within oil fields already in production, such that the method according to the present invention can replace and/or supplement existing methods.

The method of this invention is particularly suitable for reducing the H₂S content of the produced fluid by at least 95%. The examples which follow how efficiency of scavenging to such an extent can be obtained. However, the method can also be used to achieve less efficient scavenging for example by a minimum of say 20%, for example 50%, 70% or 90%. This lower efficiency may be acceptable when the H₂S-reduced produced fluid is to be co-mingled with a sweet produced fluid.

Detailed Description of the Invention

The invention relates to a process for scavenging (reducing or removing) hydrogen sulphide from any hydrocarbon fluid that contains high levels of hydrogen sulphide. By "high" is meant that the hydrogen sulphide is contained in the produced fluid in an amount, by weight of at least 250ppm, preferably at least 500ppm, more preferably at least 1000ppm and most preferably at least 2000ppm. This method is particularly useful for scavenging hydrogen sulphide from a produced fluid containing, by weight from 500 to 5000ppm so that, for example, the costs of the method are economically justifiable.

The formaldehyde is usually added as an aqueous solution, in the form of formalin. The formalin solution typically comprises 30 to 40% active formaldehyde, commonly being 37% active, with 5 to 10% methanol added as a stabiliser. Where reference is made hereinafter to quantities of formaldehyde, these are related to 37% active formalin. Obviously, adjustments are to be made in respect of formalin solutions of different concentrations. The amount of methanol may be increased in order to increase the low temperature stability of formaldehyde and to compensate for possible loss via the delivery systems.

In carrying out the method of the present invention, the chemical scavenger, formaldehyde, is added to the produced fluid in a concentration sufficient to reduce substantially the amount of hydrogen sulphide in the fluid. Typically the formaldehyde will be used in an amount in excess of stoichiometric with respect to the hydrogen sulphide in the multiphase production. Preferably, the formaldehyde is added to the fluid in a ratio by weight of formaldehyde to hydrogen sulphide in the multiphase production of from 2:1 to 8:1. It has been found that where a higher ratio of formaldehyde to hydrogen sulphide then stoichiometric is used, the fate of hydrogen sulphide removal may be increased.

Thus, in order to optimise formaldehyde use by minimising reaction by-product formation whilst maximising the efficiency of hydrogen sulphide removal, a weight ratio of formaldehyde to hydrogen sulphide of from 2:1 to 6:1 is preferred and a ratio of between 2:1 to 4:1 is optimal.

Once the formaldehyde has been added to the multiphase production by any conventional means, such as chemical injection, the formaldehyde disperses through the produced fluid substantially homogeneously by the natural turbulence of the fluid flow. A mixing device may be also be used to achieve thorough mixing if desired.

In order to optimise the reduction of hydrogen sulphide concentration in the produced fluid, the contact time of the formaldehyde and hydrogen sulphide is preferably at least 20 minutes. More preferably, the contact time is from 30 to 60 minutes. For example, where the weight ratio of formaldehyde added to hydrogen sulphide to be removed is between 2:1 to 6:1, a contact time of between 45 to 60 minutes has been found to achieve 95 to 99% removal of the hydrogen sulphide. Furthermore, the temperature is preferably in the range 60 to 75 deg C and, although no advantage in efficiency at higher temperatures is seen, there is no detrimental effect at up to 120 deg C. The efficiency and rate of reaction is also pressure dependent and minimum pressure is preferably 20 bar, more preferably 30 bar, and although reaction continues at lower pressure, the scavenging may not be to the same level.

In the treatment of produced fluid, the formaldehyde is preferably added upstream at a point which provides an appropriate residence time of the hydrogen sulphide and formaldehyde in the production fluid. By the time the produced fluid reaches the processing facility, the hydrogen sulphide content of the fluid should generally have been reduced to relatively safe and conventionally treatable levels, such as between 0 to 600ppm by volume in the gaseous phase.

In situations where the contact time of the hydrogen sulphide and formaldehyde is restricted, for example where the production well is close to the processing facility the formaldehyde may be added into the production tubing downhole as deep as may be necessary to provide sufficient residence time to effect the scavenging process.

Any residual hydrogen sulphide that has not been scavenged by the formaldehyde can be easily removed from the gas phase by any conventional physical or chemical method of reducing/removing hydrogen sulphide from the separated gas phase containing low levels, typically less than 600 ppm by volume. For example, a chemical scavenger such as a triazine compound can be added to the gaseous phase in the conventional manner. A methyl triazine compound may be preferred due to its efficiency in removing hydrogen sulphide from gaseous hydrocarbon streams. The triazine can be added at a ratio, by weight of triazine to hydrogen sulphide, of between 15:1 to 6:1, most preferably between 8:1 to 13:1 and optimally at 10:1, to maximise the residual hydrogen sulphide removal at minimum cost.

The method further comprises the step of adding water to the hydrocarbon fluid. This is likely to be necessary with dry crude oil production before water production has occurred. When water production has occurred, water content of the multiphase system may become sufficiently high for water addition to be obviated. The presence of water, optionally an addition, advantageously improves the efficiency of the scavenging reaction and provides a carrier phase for some of the reaction products. If water is added, addition is preferably at a point substantially upstream of the processing facility in order to enhance the dispersion of some insoluble reaction products, which may be the by-products of the hydrogen sulphide and formaldehyde reaction. Ideally the water is added at substantially the same time as the formaldehyde to be sure that water is present from the start of the formaldehyde/hydrogen sulphide reactions. It has been found that the addition of water does not reduce the efficiency of hydrogen sulphide removal by the formaldehyde in this method and has no effect on the stoichiometry o the reaction, which requires 1 mol of formaldehyde as such for 1 mol of hydrogen sulphide.

Dry crude oil is regarded as being "substantially free of water", by which is meant here less than 2% by volume of water is present in the produced fluid. It has been found that formaldehyde treatment of dry crude oil, that contains a high level of hydrogen sulphide, particularly higher than 250ppm by weight of the fluid, may produce insoluble by-products. Solids formation is particularly important to avoid in offshore oil processing systems to prevent blockages occurring and thus to reduce downtime of the production process. The extent of the formation of oil-soluble or oil and water-insoluble products is dependent on the mercaptan content of the produced fluid. Mercaptans are usually present in significant quantities in sour crudes and act as 'chain terminators' in the formaldehyde scavenging reaction preventing the formation of insoluble high molecular weight products and results in formation of oil soluble by-products. However if the mercaptan level is low or does not prevent formation of insoluble products the presence of a water phase allows dispersion of the water insoluble reaction products. This positive addition of a water phase to such water-free produced fluids, particularly, but not only, dry crude oil, advantageously minimises the concentration of solids to a manageable amount. By "manageable amount" is typically meant less than 30 mg of solids formation per ml of the water phase.

The water used in the water addition step may be sea water, modified sea water or fresh water depending on availability and compatibility. The water is preferably added in an amount such that the reduction of the capacity of the lines for carrying production fluid is minimised, whilst the dispersion of insoluble by-products is maximised. An amount of water of at least 5%, even as much as 50%, but preferably 5% to 10%, by volume of the produced fluid, is added.

The method of the present invention has been found to be particularly efficient in circumstances where the CO₂ content of the produced fluid is high. For example up to 140 mol% of the gas phase. Indeed in circumstances where the produced fluid comprises a gaseous phase containing carbon dioxide, the formation of insoluble products is minimised whilst hydrogen sulphide removal remains efficient.

For a better understanding of the invention, and to show how the same may be carried into effect, reference will now be made, by way of example, to the accompanying drawings, in which:

Figure 1 shows a schematic diagram showing the application of the method of the present invention to scavenge hydrogen sulphide from sour crude oil produced via a subsea well; and

Figure 2 is a schematic diagram of a high pressure test loop used in examples set out hereinafter and

With reference to Figure 1, a typical application of the method of the present invention is shown.

A stabilised formaldehyde solution containing 37% formaldehyde and 7% methanol is stored in the storage tank 1. The tank 1 is connected by an injection or umbilical line 2 to a valve injector (not shown) which is fitted into the wall of the flow line 3 immediately down stream of a remote sub-sea wellhead 4. The valve injector has a spray nozzle for atomising the formaldehyde solution into the flowing stream of the well produced crude oil flowing through the flowline 3 from the wellhead 4 to the platform 5.

Low sulphate sea water is supplied from facility 6 through an injection or umbilical line 7 to a valve injector (not shown) which is fitted into the wall of the flow line 3 immediately down stream of the formaldehyde injection point 15.

Methyl triazine is stored in the storage tank 8. The tank 8 is connected by an injection or umbilical line 9 to a valve injector (not shown) which is fitted into the wall of the on-platform line 10.

Line 10 carries the gaseous phase of the production on the platform after separation of the fluid stream. Line 12 carries the liquid phase and line 13 carries the aqueous phase.

In operation, well-produced dry crude oil having a liquid phase and a gaseous phase and having a hydrogen sulphide concentration of 2000ppm by weight of the fluid, flows as a liquid and gaseous stream along a 10 km sub-sea flowline 3 from the wellhead 4 to the platform 5. The residence time of the crude oil in the flow line 3 from wellhead 4 to platform 5 is approximately 1 hour. The dry crude oil contains 40mol% of carbon dioxide in the gaseous phase. The pumps of the storage tank 1 and facility 6, pump formaldehyde solution and water into the flow line 3 at

points

15 and 16 respectively. The water is injected into the flow line, at substantially the same point as the formaldehyde injection, in an amount of 5% by volume of the crude oil.

The flowing gaseous phase is analysed from time to time for example (at

points

20, 21 and 22) in the conventional manner to determine the hydrogen sulphide content of the gaseous phase. The flow of formaldehyde is adjusted in the conventional manner to add an amount that is sufficient to reduce the crude oil hydrogen sulphide concentration to less than 600ppm by volume in the gaseous phase, at the point where the crude oil is brought onto the platforms. This concentration is measured at point 20. Typically, where the residence time is approximately one hour and the temperature within the flowline is around 65°C and average pressure is 30 bar, approximately 2 to 3 litres of the formaldehyde solution per kg of hydrogen sulphide to be scavenged is sufficient to reduce the hydrogen sulphide concentration to 100ppm by volume in the gaseous phase, at the point where the crude oil is brought onto the platform. However, the ratios of formaldehyde added to hydrogen sulphide to be removed depends on the temperature and residence time.

The crude oil is delivered to the platform 5 and fed into a separator 11, which separates the gaseous hydrocarbon phase, liquid hydrocarbon phase and aqueous phase into

separate lines

10, 12 and 13 on the platform. The aqueous phase, containing some formaldehyde/hydrogen sulphide reaction by-products is delivered by flow line 13 to a disposal well. The liquid hydrocarbon phase containing less than 10ppm hydrogen sulphide by weight of the liquid and some oil soluble reaction product is delivered by line 12 for export or further processing. The gaseous phase containing 100ppm by volume of hydrogen sulphide in the gaseous phase is delivered by line 10 for further scavenging treatment. For this purpose, methyl triazine, stored in tank 8, is injected into the line 10, at a weight ratio of methyl triazine to hydrogen sulphide of approximately 10:1, in the conventional manner, in order to scavenge the residual hydrogen sulphide not removed by the sub-sea formaldehyde treatment.

By virtue of the above described process, the oil reservoir crude oil fluid that, prior to formaldehyde treatment contained hydrogen sulphide at a concentration of approximately 2000ppm by weight of the crude oil fluid, is delivered to the platform containing, in the gaseous phase, a hydrogen sulphide concentration of 100ppm by volume of the gaseous phase and contains an insignificant amount of solid by-products, typically less than 30 mg of the solids per ml of the aqueous phase. After the methyl triazine scavenging treatment, the gaseous phase contains less than 10ppm by volume of hydrogen sulphide. The liquid phase, in line 12 contains less than 10ppm by weight of liquid.

In order that the present invention may be more readily understood, the following examples are given, by way of illustration only. All examples and test data are based on tests that were carried out either in a high pressure autoclave cell or a closed test loop as illustrated in Figures 2a and 2b.

Example 1

This example demonstrates the optimum contact time required for formaldehyde to effectively reduce the concentration of hydrogen sulphide in a dry crude oil stream containing, prior to the addition of formaldehyde, a hydrogen sulphide concentration of 8,500ppm by volume in the gaseous phase as measured at atmospheric conditions. The dry crude oil stream was treated in a high pressure autoclave cell formaldehyde solution at a ratio by weight of formaldehyde to hydrogen sulphide of 4:1 and at a temperature of 75°C and 60 Bar pressure. The results are set out in Table 1 below. The data was generated from a high pressure autoclave.

Time (minutes)	ppm H₂S by volume in gas phase
0	6000
5 min	5500
10 min	3500
15 min	3000
20 min	2000
30 min	1300
45 min	1100
60 min	700
75 min	600
90 min	600

As can be seen from the results, significant hydrogen sulphide removal is achieved, about 90 % removal being achieved after 60 minutes contact time while subject to vigorous mixing.

Example 2

This example compares the effectiveness of two scavengers, formaldehyde and triazine, in reducing hydrogen sulphide from a crude oil stream containing, prior to the addition of scavenger, hydrogen sulphide at a concentration of 8,500ppm by volume in the gaseous phase of the crude oil. The crude oil stream was treated in a line using the scavengers at a ratio by weight of scavenger to hydrogen sulphide as shown in Table 2 and at a temperature of 65°C. The results are set out in Table 2 below. The data was generated in a closed test loop as shown in Figure 2 of the accompanying drawings and which was constructed and operated as follows.

A test loop 100 having a volume of 340 litres was constructed from a 70.5m length of 7.6cm diameter stainless steel pipe and incorporated a vertical separator vessel 31 having a volume of 197 litres and a centrifugal circulation pump 32. A gas by-pass line 33 was extended from the top of the vessel 31 to a 28mm flow restriction orifice 34 located in the pipework between flanges approximately 5m downstream of the pump 32 and acting as a venturi to produce a vacuum when oil was circulated. This sucked the gas from the top of the separator vessel 31 into the loop 100 so creating a gas circulation when a gas by-pass valve 35 was opened.

The venturi 34, allowed gas circulation to be restricted when the by-pass valve 35 was closed.

The venturi 34 acted to ensure a constant flow rate by balancing the outlet from pump 32 with the fluid level in the separator vessel 1, which was maintained at an approximate level of 700-800mm by adjusting vessel outlet valve 36.

The test loop incorporated also three in-

line mixer units

37a, 37b, 37c spaced around the loop at approximately 0.7m, 29.5 m and 48.8m from the restriction orifice at 36. These were removable to determine the effect of different mixing regimes.

Temperature control was provided by heat tracing the loop and separator vessel and insulation of the system insulated.

Additional features of the test loop are injector 38 for scavenger,

sampling valves

39a, 39b and 39c and vent stack 40 and flushing valve 41.

Efficiency of Formaldehyde and Triazine
Time (Minutes)	% H₂S removal Efficiency
	Formaldehyde applied at 6:1	Triazine applied at 12:1
30	99.8	37.5
45	99.9	70.0
60	99.9	75.0

As can be seen from the results, formaldehyde is significantly more efficient than triazine, even at a lower ratio, at scavenging hydrogen sulphide from such sour crude oil as was used for testing.

Example 3

This example demonstrates the effect of adding water to the dry crude oil on the scavenging efficiency of formaldehyde when treating the crude oil stream of Example 1 under the same conditions as Example 1. The results are set out in Table 3 below. The data was generated from a high pressure autoclave.

Efficiency of Formaldehyde under dry and 10% water cut
Time (minutes)	H₂S removal % efficiency with dry oil	H₂S% removal efficiency with water in oil
5	8.33	10.00
10	41.67	60.00
15	50.00	80.00
20	66.67	87.00
30	78.33	96.80
45	81.67	98.00
60	88.33	98.60
75	90.00	99.00
90	90.00	99.00

As can be seen from the results, the addition of water makes a significant improvement on the scavenging efficiency of formaldehyde with high pressure.

Example 4

This example demonstrates the effect of scavenging at relatively low pressure of 20 bar under dry and with 10% water cut and the effect on the scavenging efficiency of formaldehyde when treating the crude oil under other conditions similar to Examples 1 and 3. The data were generated from a high pressure autoclave. The results are set out in Table 4 below:

Efficiency of Formaldehyde at 75°C under dry and 10% water cut conditions and at 60 Bar and 20 Bar pressures and 75°C
Time (minutes)	H₂S removal % Efficiency with dry oil @ 60 Bar	H₂S removal % efficiency with 10% water in oil @ 60 bar	H₂S removal % efficiency with dry oil @ 20 bar	H₂S removal % efficiency with 10% water in oil @ 20 bar
5	8.33	10.00	7.14	20.00
10	41.67	60.00	14.29	53.33
15	50.00	80.00	21.43	60.00
20	66.67	87.00	28.57	60.00
30	78.33	96.80	21.43	66.67
45	81.67	98.00	21.43	73.33
60	88.33	98.60	28.57	76.00
75	90.00	99.00	28.57	80.67
90	90.00	99.00	28.57	80.00

As can be seen from the results, the addition of water make a significant improvement to the scavenging process at lower pressure.

Example 5

This example demonstrates the effect of the presence of carbon dioxide in the gaseous phase on the scavenging efficiency of formaldehyde when treating the crude oil under similar condition in terms of high H₂S in the gas phase (about 8000 - 10000 ppm), namely same chemical ratio of H₂S scavenger, 65 C and 60 bar pressure. By varying CO₂ level in the mixture, it was demonstrated that the efficiency would not be affected by the different concentrations in the gas phase. The data were generated using a high pressure autoclave. The results are set out in Table 5 below.

Efficiency of Formaldehyde when working under different carbon dioxide contents and with 10% water
Time (minutes)	H₂S removal % efficiency with 40% CO₂ in gas phase	H₂S removal % efficiency with 30% CO₂ in gas phase	H₂S removal % efficiency with 20% CO₂ in gas phase	H₂S removal % efficiency without any CO₂ in gas phase
5 min	60.00	53.33	46.67	50.00
10 min	85.00	66.67	60.00	76.00
15 min	89.00	80.00	71.67	88.00
20 min	93.00	83.33	80.00	92.00
30 min	98.00	88.33	85.00	96.00
45 min	96.75	85.71	84.38	94.00
60 min	99.60	95.67	94.00	97.20

As can be seen from the results, the presence of carbon dioxide does not markedly affect the scavenging efficiency of formaldehyde.

Example 6

This example demonstrates the effect of temperature on the scavenging efficiency of formaldehyde when treating the crude oil mixture under similar conditions to earlier examples at 60 bar pressure, using 4:1 scavenging ratio, with 10% water by volume having been added to the dry crude oil. The data were generated using a high pressure autoclave. The results are set out in Table 6 below.

Efficiency of Formaldehyde at different temperatures and 10% water cut
Time (minutes)	H₂S removal % efficiency @ 45 °C	H₂S removal % efficiency @ 65 °C	H₂S removal % efficiency @ 75 °C	H₂S removal % efficiency @ 85 °C	H₂S removal % efficiency @ 120 °C
5	35.71	40.00	10.00	57.45	50.00
10	35.71	50.00	60.00	78.72	71.43
15	64.29	50.00	80.00	81.91	87.14
20	71.43	66.00	87.00	92.55	97.14
30	73.57	72.00	96.80	98.72	98.86
45	78.57	79.00	98.00	97.87	99.50
60	82.86	85.00	98.60	98.51	99.43
75	85.00	96.00	99.00	98.51	99.29
90	85.71	98.60	99.00	98.72	99.29

As can be seen from the results, the scavenging efficiency of formaldehyde increases with temperature, with an optimum scavenging efficiency being attained at 75°C.

Example 7

This example demonstrates the scavenging efficiency of formaldehyde under different ratios by weight of formaldehyde to hydrogen sulphide when treating the crude oil stream of Example 1 under the same conditions as Example 1 except that 50% water by volume was added to the dry crude oil. The data were generated using a high pressure autoclave. The results are set out in Table 7 below.

Efficiency of Formaldehyde at different scavenging ratios and with 50% by volume water
Time (Minutes)	% H₂S removal Efficiency at HCHO : H₂O ratio of
	02:01	04:01	06:01
30	91.2	98.75	80.0
45	98.0	99.0	96.0
60	98.8	99.65	99.0

As can be seen from the results, a significant hydrogen sulphide removal efficiency is achieved at a 4:1 ratio.

Example 8

This example demonstrates the effect of different mixing rates on the scavenging efficiency of formaldehyde when treating a dry crude oil mixture under similar conditions to earlier examples at 75°C, 60 Bar, 4:1 scavenging ratio, with 10% water by volume added to the dry crude oil. The data were generated using a high pressure autoclave. The data were generated using a high pressure autoclave. The results are set out in Table 8 below.

Efficiency of Formaldehyde under different mixing rates and 10% water cut
Time (minutes)	H₂S removal % efficiency @ 800 rpm	H₂S removal % efficiency @ 400 rpm	H₂S removal % efficiency @ 200 rpm
5	10.00	20.00	8.33
10	60.00	30.00	25.00
15	80.00	60.00	29.17
20	87.00	74.00	25.00
30	96.80	87.00	25.00
45	98.00	95.00	33.33
60	98.60	96.00	66.67
75	99.00	98.20	70.83
90	99.00	99.20	71.67

As can be seen from the results, the scavenging efficiency of formaldehyde improves with increase in the mixing rate since the mass transfer will improve.

Example 9

This example demonstrates the effect of pressure on the scavenging efficiency of formaldehyde at different degrees of mixing of formaldehyde with dry crude oil and 10% water added. Testing was carried out using the test loop of Figure 2. Different mixing regimes were achieved by controlling the flow of the gas phase through the dedicated separator and into the circulating liquid. The gas flow into the main oil loop was controlled by the valve in the gas line. The results are set out in Table 9 below.

% Efficiency of Formaldehyde under dry and 10% water cut conditions
%H₂S removal % Efficiency
Time
	10% water in oil @ 60 Bar / gas line valve open	10% water in oil @ 60 Bar / gas line valve closed	Dry oil @ 60 Bar / gas line valve closed	10% water in oil @ 20 Bar / gas line valve closed	Dry oil @ 20 Bar / gas line valve closed	10% water in oil @ 20 Bar / gas line valve open
5	25.00	14.29	25.00	25.00	42.86	10.00
10	50.00	42.86	55.00	52.50	71.43	60.00
15	75.00	72.86	82.50	82.50	90.00	76.00
20	85.00	84.29	86.25	85.00	90.00	83.00
30	95.00	90.00	90.00	90.00	92.86	89.00
45	97.75	95.43	95.00	95.25	94.57	95.00
60	99.25	98.29	96.75	97.50	96.29	97.40

As can be seen from the results, whatever the levels of mixing between the gas and the liquid phases, whether using dry or wet oil, and when working at relatively low pressure or high pressure, the efficiency of scavenging is within 95% after one hour in the test loop. This is an indication of the efficiency of the mass transfer of the chemical scavenger process and the flexibility of the process in achieving optimum scavenging under different flow conditions in multiphase loops.

Claims

A method for reducing the amount of hydrogen sulphide in a multiphase hydrocarbon produced fluid prior to phase separation and processing, the method comprising the step of adding formaldehyde to the produced fluid, which produced fluid has, prior to the addition of formaldehyde, a concentration of hydrogen sulphide of at least 250ppm by weight of the fluid.
A method according to claim 1, wherein the produced fluid comprises liquid and gaseous hydrocarbon phases with or without water.
A method according to claim 1 or 2, wherein the formaldehyde is introduced as formalin in-line into the multiphase system.
A method according to claim 3, wherein the formaldehyde is introduced to the hydrocarbon fluid at a ratio by weight of formaldehyde (expressed as 37% formalin) to hydrogen sulphide of from 2:1 to 8:1.
A method according to any preceding claim, wherein the multiphase system flows through a sub-sea flowline.
A method according to any one of claims 1 to 4, wherein the multiphase system flows through an on-shore pipeline.
A method according to claim 5 or 6, wherein the formaldehyde is added at a location which provides a contact time of at least 20 minutes.
A method according to claim 7, wherein the location provides a contact time of from 30 to 60 minutes.
A method according to any preceding claim, wherein the method comprises the additional step of adding water to the hydrocarbon fluid.
A method according to claim 9, wherein the hydrocarbon fluid is substantially free of water prior to the water addition step.
A method according to claim 9 or 10, wherein an amount of water of at least 5% by volume and preferably not more than 10% by volume is added to the hydrocarbon fluid.
A method according to any preceding claim wherein the water is added at substantially the same time as the formaldehyde.
A method according to any of claims 2 to 10, which is applied to a said multiphase system which comprises carbon dioxide.
A method according to any preceding claim, which is carried out at a temperature of 60-75°C and/or at a pressure of at least 20 bar.