Title:
Sour Natural Gas Pretreating Method
Kind Code:
A1


Abstract:
The invention relates to a method of pretreating a natural gas, water-saturated or not, essentially comprising hydrocarbons, a substantial amount of hydrogen sulfide and possibly carbon dioxide. The method according to the invention comprises an H2S-rich stream recycling stage.



Inventors:
Lemaire, Eric (Anse, FR)
Huyghe, Raphael (Lyon, FR)
Lecomte, Fabrice (Paris, FR)
Lallemand, Francois (Morlaas, FR)
Application Number:
11/560527
Publication Date:
06/28/2007
Filing Date:
11/16/2006
Primary Class:
International Classes:
C10G45/00; C10G17/00
View Patent Images:



Primary Examiner:
PETTITT, JOHN F
Attorney, Agent or Firm:
ANTONELLI, TERRY, STOUT & KRAUS, LLP (1300 NORTH SEVENTEENTH STREET, SUITE 1800, ARLINGTON, VA, 22209-3873, US)
Claims:
1. An improved method of pretreating a natural gas under pressure containing hydrocarbons, at least one of the acid compounds hydrogen sulfide and carbon dioxide, and water, comprising: a) cooling the natural gas so as to produce a liquid phase and a gas phase, b) contacting in a distillation column the gas phase obtained in stage a) with a liquid phase obtained in stage c) so as to produce a gas phase and a liquid phase, c) cooling the gas phase obtained in stage b) so as to produce a liquid phase and a gas phase, characterized in that at least part of the liquid phase obtained in stage b) at the column bottom is recycled upstream from natural gas cooling stage a).

2. A method as claimed in claim 1, wherein at least part of the liquid phase obtained in stage b) at the column bottom is directly recycled into said distillation column.

3. A method as claimed in claim 2, wherein at least part of the liquid phase obtained in stage b) at the column bottom is directly recycled into said distillation column at a lower level than the gas phase intake.

4. A method as claimed in claim 2, wherein at least part of the liquid phase obtained in stage b) at the column bottom is directly recycled into said distillation column at a higher level than the gas phase intake.

5. A method as claimed in claim 2, wherein at least part of the liquid phase obtained in stage b) at the column bottom is directly recycled into said distillation column at the same level as the gas phase intake.

6. A method as claimed in claim 1, wherein said recycle stream is subjected to a thermal exchange stage in order to be heated.

7. A method as claimed in claim 6, wherein said recycle stream is subjected to a thermal exchange stage in order to be heated between 50° C. and 150° C., preferably between 75° C. and 120° C.

8. A method as claimed in claim 1, wherein said recycle stream is determined in such a way that, after mixing with the input gas, the H2S content of the effluent entering the column ranges between 15% and 50% by mole, preferably between 20% and 45% by mole.

Description:

FIELD OF THE INVENTION

The invention relates to a method of pretreating a water-saturated natural gas containing a substantial amount of hydrogen sulfide and possibly carbon dioxide and other sulfur compounds. The invention mainly comprises a stage of recycling a stream containing a large amount of hydrogen sulfide.

BACKGROUND OF THE INVENTION

Natural gas treatment generally requires a method in three successive stages. The first stage generally consists in reducing the proportion of sour gases such as hydrogen sulfide and carbon dioxide. This first stage, also known as deacidizing stage, is often followed by a water removal or dehydration stage, and by a consecutive stage of heavy hydrocarbon recovery or stripping.

French patent FR-2,814,378 describes a natural gas pretreating method allowing to obtain, at a lower cost, a methane-rich gas depleted in hydrogen sulfide and freed of substantially all the water that said natural gas initially contained. Simultaneously, a hydrocarbon-depleted aqueous liquid containing a large part of the hydrogen sulfide is obtained and generally injected into an underground reservoir, an oil production well for example. Thus, the method described in this French patent allows, in a single stage, to remove or to significantly reduce the water initially contained in the natural gas while reducing the acid constituent contents. The method described in this patent also allows to obtain a liquid phase containing mainly hydrogen sulfide that can be readily pressurized prior to being injected into the well.

However, French patent application FR-2,814,378 does not allow the hydrogen sulfide and carbon dioxide content of the gas to be treated to be reduced to an acceptable level as regards commercial requirements. It is therefore often necessary to reduce this sour gas content by means of a post-treatment. The methods generally used for these post-treatments are chemical absorption methods using, for example, solvents containing amines and carried out at high temperatures or temperatures close to the ambient temperature. These post-treatment methods allow to achieve natural gas deacidizing: the chemical solvent absorbs the acid constituents by chemical reaction. However, they have the drawback of lading the deacidized gas with water, the chemical solvent being used in aqueous solution. Thus, using a chemical solvent requires a third treatment for removing the water contained in the deacidized gas in order to prevent hydrate formation.

The present invention thus relates to a method that has been improved in relation to the method of the prior art described in document FR-2,814,378 filed by the applicant in that the proportion of acid components at the bottom of the separation column is notably increased.

SUMMARY OF THE INVENTION

The present invention therefore relates to a method of pretreating a natural gas under pressure containing hydrocarbons, at least one of the acid compounds hydrogen sulfide and carbon dioxide, and water, comprising:

a) cooling the natural gas so as to produce a liquid phase and a gas phase,

b) contacting in a distillation column the gas phase obtained in stage a) with a liquid phase obtained in stage c) so as to produce a gas phase and a liquid phase,

c) cooling the gas phase obtained in stage b) so as to produce a liquid phase and a gas phase.

According to the invention, at least part of the liquid phase obtained in stage b) at the column bottom is recycled upstream from the gas phase intake into said column.

At least part of the liquid phase obtained in stage b) at the column bottom can be recycled upstream from natural gas cooling stage a).

At least part of the liquid phase obtained in stage b) at the column bottom can be directly recycled into said distillation column.

At least part of the liquid phase obtained in stage b) at the column bottom can be directly recycled into said distillation column at a lower level than the gas phase intake.

At least part of the liquid phase obtained in stage b) at the column bottom can be directly recycled into said distillation column at a higher level than the gas phase intake.

At least part of the liquid phase obtained in stage b) at the column bottom can be directly recycled into said distillation column at the same level as the gas phase intake.

The recycle stream can be subjected to a heat exchange stage so as to be heated.

The recycle stream can be subjected to a heat exchange stage so as to be heated between 50° C. and 150° C., preferably between 75° C. and 120° C.

The recycle stream can be determined in such a way that, after mixing with the input gas, the H2S content of the effluent entering the column ranges between 15% and 50% by mole, preferably between 20% and 45% by mole.

BRIEF DESCRIPTION OF THE FIGURES

Other features and advantages of the present invention will be clear from reading the description hereafter, given by way of non limitative example, with reference to the accompanying figures wherein:

FIG. 1 shows an example of a process flowsheet according to the invention,

FIG. 2 shows an advantageous variant of the process flowsheet according to the invention.

DETAILED DESCRIPTION

The object of the present invention shows that it is possible, under suitable thermodynamic conditions, to concentrate the initial natural gas in methane while removing the major part of the sour gases and substantially all of the water it contains. Substantially all of the water means that the amount of water present in the final gas is below 50 ppm by mole, preferably below 10 ppm by mole, and more preferably below 5 ppm by mole.

The invention relates to an improved method allowing to prevent hydrate formation in all the stages of the device allowing said methane concentration.

According to the present invention, after treating according to the present method the natural gas coming from the production well, a final gas containing the major part of the hydrocarbons contained in said gas is recovered. What is understood to be the major part of the hydrocarbons is at least 90% hydrocarbons, preferably at least 95% hydrocarbons and more preferably at least 97% hydrocarbons.

Furthermore, the present invention advantageously allows to save, under stabilized conditions, using an anti-hydrate such as methanol whose transport, use and/or recovery can be expensive and/or complex.

In general terms, the invention relates to a method of pretreating a natural gas under pressure containing hydrocarbons, at least one of the acid compounds hydrogen sulfide and carbon dioxide, and water, comprising:

a) cooling the natural gas so as to produce a liquid phase and a gas phase,

b) contacting in a distillation column the gas phase obtained in stage a) with a liquid phase obtained in stage c) so as to produce a gas phase and a liquid phase,

c) cooling the gas phase obtained in stage b) so as to produce a liquid phase and a gas phase.

The improvement of the present invention lies in that part of the liquid phase obtained in stage b) is recycled upstream from the distillation column intake so that, after mixing with the input gas, the H2S content of the effluent entering the column ranges between 15% and 50% by mole, preferably between 20% and 45% by mole.

In stage c) of the method according to the invention, the gas phase obtained in stage b) can be cooled by means of a heat exchanger and/or of an expander.

The method according to the invention can comprise the following stage:

d) cooling the gas phase obtained in stage c) by means of an expander so as to produce a gas phase and a liquid phase that is recycled to stage b).

The method according to the invention can comprise the following stage:

e) compressing at least one of the gas phases obtained in stage c) and in stage d) using the energy recovered from the expander.

In stage c) of the method according to the invention, the gas phase obtained in stage b) can be cooled by means of a venturi throat, said liquid phase being collected at the level of the venturi throat and said gas phase being recovered at the outlet of the divergent tube of the venturi throat. The liquid phase collected at the venturi throat can be cooled to produce the liquid recycled to stage b) and a gas phase.

The gas phases obtained in stage c) and in stage d) can be used to cool the gas phase obtained in stage b) and/or to cool the natural gas in stage a).

The method according to the invention can comprise the following stage:

f) vaporizing at least part of the liquid phase obtained in stage b) and feeding said vaporized at least part of the liquid phase into the distillation column to create an ascending vapour flow within said column.

According to the present invention, part of the heat of the liquid phase obtained in stage b) can be used to heat the gas phase obtained in stage a).

In stage a) of the method according to the invention, the liquid phase and the gas phase can be separated in a drum.

The operating conditions of the method according to the invention can be as follows:

Distillation Column of Stage b)

T° C.=−20° C. to 100° C., preferably −15° C. to 70° C.

P>1 MPa abs., preferably 4 to 10 MPa abs.

Cooling Pressure and Temperature in Stage c)

T° C.=−100° C. to +30° C., preferably −40° C. to 0° C.

P>1 MPa, preferably 4 to 10 MPa

Cooling Temperature of Said Natural Gas in Stage a)

0° C. to 50° C., preferably 20° C. to 40° C.

According to the present invention, the hydrogen sulfide partial pressure in the natural gas can be at least 0.5 MPa, preferably at least 1.5 MPa. The distillation column can comprise at least 3 theoretical stages, preferably 4 to 6. In stage a), the natural gas can be at a pressure ranging between 6.5 MPa and 12 MPa, and at a temperature above 15° C.

The liquid phases obtained in stages a) and b) can be fed into a well.

Thus, according to the present invention, the method describes control of the thermodynamic conditions (pressure and temperature for example) depending on the nature of the gas treated (notably the water content thereof), said control allowing progressive drainage of the water contained in said gas while preventing hydrate formation. In general, according to the present method, a distillation column allowing progressive drainage of the water from the bottom to the top of the column is used, so as to recover at the top of said column a substantially water-free gas, i.e. comprising an amount of water that is lower than the hydrate formation limit at the lowest temperature reached during next stage c) of condensation by cooling and by expansion. In particular, according to the invention, the water-saturated gas from stage a) is introduced at a sufficiently low level of the column, i.e. at a sufficiently high temperature to prevent hydrate formation. The column must therefore contain a rather large number of theoretical stages to allow drainage of the water and to obtain a temperature gradient between the cold top and the bottom of the column. Furthermore, addition of a reboiler advantageously allows to maintain a rather high temperature in the column and therefore to prevent hydrate formation, and to minimize and/or control hydrocarbon losses.

The essential improvement provided by the present invention lies in that part of the H2S-rich liquid phase obtained in stage b) is recycled upstream from the distillation column intake so that, after mixing with the input gas, the H2S content of the effluent entering the column ranges between 15% and 50% by mole, preferably between 20% and 45% by mole. The examples hereafter show the improvement efficiency.

EXAMPLE 1

The process flowsheet described hereafter corresponds to FIG. 1. The compositions and the properties of the streams are numbered from 1 to 10 on the lines of the process flowsheet and they are defined in Table 1. The crude gas (1) is available at 30° C. and 62.3 bars. It contains approximately 18.8% by mole H2S and 1000 ppm by mole water. It is mixed with recycled stream (9). Injection of the H2S-rich liquid stream is carried out in the direction of flow of the stream through a branch line at the top of the line. The recycled stream is very rich in H2S (about 78% by mole), at a higher temperature than the crude gas because it directly comes from reboiler E2 of the column. A gas/liquid mixture (2) that is homogenized by passage through a mixer M1 is obtained.

At the outlet of mixer M1, the stream is heated up to 30° C. This stream is fed into separating drum B1. The gas phase (4) obtained is saturated with water, the excess water (5) condensing in drum B1. Gas phase (4) thus obtained is fed into separation column C1. This column allows significant removal of the H2S while limiting hydrocarbon losses. The gas obtained at the top of the column is cooled in exchanger E3, then in exchanger E4, so as to reach a temperature of −30° C. The liquid/gas mixture obtained is separated in drum B2. Liquid phase (6) is used as reflux for column C1 after passage through pump P1. The gas phase is used for precooling the gas from the top of the column in exchanger E3.

The gas obtained (7) contains 10% by mole H2S, i.e. removal of about 50% of the H2S contained in the crude gas. It no longer contains water (content below 5 ppm by mole). The liquid at the bottom of column C1 is passed through pump P2. At the outlet of pump P2, part of the liquid is sent to reboiler E2, another part (9) is recycled to the gas feed point (1) of the plant, and the last part is sent to reinjection pump P3. The liquid stream (5) obtained at the bottom of drum B1 is added to stream (8) prior to reinjection. Recycling of H2S-rich liquid stream (9) allows the H2S content of the input gas to be greatly increased. In this example, 20% recycling allows the H2S concentration to be raised by 18% to 30% by mole.

EXAMPLE 2

The process flowsheet described below corresponds to FIG. 2. The compositions and the properties of the streams are numbered from 1 to 11 on the lines of the process flowsheet and they are defined in Table 2.

In the diagram of FIG. 2, recycling (9) is achieved directly into separation column C1 with the stream bearing reference number (11). This recycling to the column is shown entering below gas feed point (4), but in other variants shown by dotted lines (11′), (11″), recycling can be achieved at any other level of the column, above or at the feed point. The stream directly fed into column (11) can represent all of or only part of recycled stream (9), and the other part (11′″) can be sent to gas intake (1) for example.

FIG. 2 illustrates the layout of a thermal exchanger E5 in relation to liquid recycled stream (9) from the column bottom. This exchanger allows the liquid to be more or less heated, to obtain either a gas/liquid mixture, or a gas at the dew point thereof, or an “overheated” gas (i.e. at a temperature above the dew point thereof). Typically, the temperature at the outlet of this exchanger can range between 50° C. and 150° C., preferably between 75° C. and 120° C. This exchanger can be used whatever the recycling inlet point.

The main advantages of this variant of the present invention are as follows:

    • The change to the vapour phase of the recycled liquid can allow better mixing with the gas supplied, whatever the recycling inlet point,
    • the possibility of bringing calories upon recycling provides operating flexibility to the plant, notably as regards control of the thermodynamic conditions, the temperature increase of the recycled stream can allow to prevent hydrate formation risks.

The advantages of recycling from the column bottom to the intake in relation to the SPREX™ process can be described as follows:

    • During the starting stages, the methanol is used to prevent hydrate formation in the facilities; recycling allows to minimize the amount of methanol to be used. In fact, it is mainly present in the liquid from the column bottom and it is also recycled into the input gas,
    • recycling requires no additional equipment because pump P2 at the column bottom is essential to provide forced circulation in reboiler E2 of thermosiphon type and thus to be able to exceed 30% vaporization in the reboiler,
    • recycling allows to reach a sufficient H2S concentration to prevent hydrate formation. In fact, if the H2S content of the gas is too low, the liquid/vapour traffics and the thermal levels in the column can then favour hydrate formation,
    • recycling only reduces very slightly the treating capacity of the process; in fact, the recycled stream is extremely rich in H2S,
    • the recycled stream is very rich in water (more than 4000 ppm by mole), however drum B1 allows to condense this water, the gas entering the column therefore does not contain more water than without recycling, which is very important to minimize hydrate formation risks,
    • the recycled stream is collected prior to mixing with liquid stream (5) from the bottom of drum B1, which allows to prevent the water from “going round in circles” and the content from increasing too much,
    • the recycling system allows the H2S content to be adjusted to the desired value if that of the crude gas varies with the evolution of the reservoir or the management of the various production site wells. It also allows to treat natural gases whose H2S content is lower than a content commonly considered by the SPREX™ process, for example below 20% by mole H2S,

recycling allows a general increase in the “ease of operation” of the plant.

TABLE 1
Name of stream
12345678910
PhaseVapourMixedVapourVapourLiquidLiquidVapourLiquidLiquidLiquid
Flow Rate kg-mol/hr0.08590.16280.16280.11840.04440.00560.00040.04120.07690.0856
H2O
N20.21890.21920.21920.21920.00000.02370.21870.00010.00030.0001
CO28.53699.43309.43309.43290.000110.53208.05670.48020.89610.4803
H2S15.249730.006830.004630.00370.000824.73747.33897.907714.75717.9086
METHANE53.102253.662553.663553.66340.000015.936052.80290.30020.56030.3003
ETHANE2.27002.60862.60882.60880.00002.66362.08870.18140.33860.1814
PROPANE0.72151.41971.42081.42080.00001.26970.34840.37410.69820.3741
BUTANE0.41351.16381.16381.16380.0000.12260.01140.40210.75030.4021
PENTANE0.46211.32371.32371.32370.0000.01230.00040.46170.86160.4617
Total Flow Rate kg-mol/hr81.0607100.0000100.000099.95470.045355.303070.866610.148818.939310.1941
Temperature ° C.30.000019.697930.000030.000030.0000−30.0000−1.815068.541568.541567.3981
Pressure BAR (GA)62.300061.900061.400061.400061.400060.800060.300063.500063.5000250.0000
Enthalpy mm kcal/hr0.12660.16240.18940.18900.0000−0.02050.06550.01920.03570.0157
Molecular weight23.592826.119226.119126.122618.369430.867521.685736.932236.932236.8496
Vapour molar fraction1.00000.94601.00001.00000.00000.00001.00000.00000.00000.0000
Liquid molar fraction0.00000.05400.00000.00001.00001.00000.00001.00001.00001.0000

TABLE 2
Name of stream
1234567891011
PhaseVapourMixedVapourVapourLiquidVapourLiquidLiquidLiquidVapour
Flow Rate kg-mol/hr0.09010.09010.09010.09010.00680.00050.08860.12980.08860.1298
H2O
N20.22950.22950.22950.22950.02560.22950.00010.00010.00010.0001
CO28.95188.95188.95188.951811.37468.65040.30060.44030.30060.4403
H2S15.990715.990715.990715.990725.70717.69568.309412.16928.309412.1692
METHANE55.682855.682855.682855.682817.078855.53790.14440.21140.14440.2114
ETHANE2.38032.38032.38032.38032.91152.26050.11930.17470.11930.1747
PROPANE0.75660.75660.75660.75661.37140.37460.38120.55830.38120.5583
BUTANE0.43360.43360.43360.43360.09170.00860.42020.61530.42020.6153
PENTANE0.48460.48460.48460.48460.00710.00020.47860.70090.47860.7009
Total Flow Rate kg-mol/hr85.000085.000085.000085.000058.574774.757710.242315.000010.242315.0000
Temperature ° C.30.000029.739930.000030.0000−30.0000−2.400076.943376.943375.6265100.0000
Pressure BAR (GA)62.300061.900061.400061.400060.800060.300063.500063.5000250.000063.5000
Enthalpy mm kcal/hr0.13280.13280.13340.1334−0.02170.06870.02180.03200.01750.0643
Molecular weight23.592823.592823.592823.592830.821721.742237.068837.068837.068837.0688
Vapour molar fraction1.00001.00001.00001.00000.00001.00000.00000.00000.00001.0000
Liquid molar fraction0.00000.00000.00000.00001.00000.00001.00001.00001.00000.0000