FR2618876A1 - Process for treating and transporting a gas containing methane and water - Google Patents

Abstract

Process for treating and transporting, in a pipe 105, a gas comprising methane and water, characterised in that it comprises the following stages: a solvent phase 117 comprising at least one of the following solvents, alone or in a mixture, is added to the gas at the inlet of the pipe 105: N,N-dimethylformamide, N-formylmorpholine and N-methylpyrrolidone; the whole of the resulting mixture is transported in the said pipe as a polyphase flow; on arrival at the reception site, the gas phase and the solvent phase are separated B101; the solvent phase arising from the preceding stage is regenerated by pressure release B103 and B104 and/or distillation C101. This treatment makes it possible to avoid the formation of hydrates in the transportation pipe and optionally to deacidify and dehydrate B102 the gas.

Description

 The current economic context encourages offshore oil and gas companies to significantly reduce investment and operating costs (fewer platforms and transfer of treatment to effluent arrival sites). down). In the case of condensate gases, one of the solutions consists of transporting the effluent via a pipe to the ground either without treatment or by carrying out the minimum transformations making the fluid transportable. In this case, three phases coexist in the transport pipe: gas, liquid and reservoir water. The liquid is either a condensate or an oil depending on the type of deposit. The presence of water causes risks of clogging by formation of hydrate crystals which are compounds where the hydrocarbons are included in cages that form the molecules of water.

It is necessary to solve these problems of clogging of pipes and pipes, by the hydrates; they appear for example for a natural gas under 200 bar at 20C. In particular, numerous studies are currently being carried out on the development of underwater production stations, including the development of
pumping or compressing multiphase effluents, and the problems
hydrate formation arise especially in this case.

The two-phase evacuation of a gas-to-condensate deposit can be
ensured by prior treatment of the well effluent; in particular,
dehydration of the gas, for example by washing with triethylene glycol,
then recombination of the condensate with the gas. A solution more
is the triphasic transport of the water-oil-gas mixture in
the pipes; for this a treatment preventing the formation of hydrates
is necessary.

Many works have already been done on the treatment
prevent natural gases with methanol and ethylene glycols; this treatment makes it possible, thanks to the injection of solvent, to avoid the
dehydration. These two families of solvents have
different disadvantages:
~ methanol has a vapor pressure under the conditions
as a large fraction goes into the vapor phase.
which greatly reduces its efficiency (as a result of the decrease in its
concentration in the aqueous phase) on the one hand and leads to losses
important on the other hand. This implies that significant quantities
not only are necessary but in addition are consumed.

the mono-, di- or tri-ethylene glycols, also used, exhibit
the disadvantage of a high viscosity. The viscosity of these solvents
makes it unusable in practice at low temperatures; at -40 C for example,
the viscosity of mono-ethylene glycol is so high that it is practically
impossible to circulate.

It was discovered that solvents, which until now were not
used for this purpose, show good efficacy in inhibiting
hydrates, as shown in Example 3, not having the disadvantages
previously mentioned. These solvents are N, N-dimethylformamide
(DMF), N-methylpyrrolidone (NMP) and N-formylmorpholine
(NFM).

It has also been discovered that the same solvents can be advantageously used to carry out a stage of the treatment of the gas at the end of the transport in multiphase flow.

The principle of the method will be described in connection with an example illustrated by the diagram of FIG.

The pressurized gas is produced by a wellhead from where it is discharged through the conduit 1. The gas production in 1 can be followed by a separation of the liquid water in a settling tank BI, the water being discharged through the conduit 18. At the outlet of B1, the inhibiting solvent for the formation of hydrates, arriving via the conduit 17, is injected into the pipeline to allow transport, in the conduit 5, without risk of clogging. On arrival either on land or on a central platform, the gas will be treated so as to recover the solvent and evacuate the hydrocarbons to the areas of use.

The multiphase mixture contained in the gas pipeline 5 is introduced into a flask B2 where the separation between the gas and the solvent phase is carried out. The gas is evacuated via line 15 and the solvent phase through line 9.

If the gas further contains at least one hydrocarbon other than methane, which forms a liquid phase distinct from the substantially solvent-water fraction, the hydrocarbon fraction is separated and discharged from the process. This fraction appears during the cooling which takes place during the transport under the sea, for example. In this case, the flask B2 is replaced by the settling tank B3 (FIG 3) to effect the water-oil-gas separation; this step allows separation of a condensate consisting of condensable hydrocarbons at the conditions of pressure and outlet temperature of the pipeline. In the flask B3, three fractions are thus separated: a gasoline fraction which is evacuated via the duct 8.

a gaseous fraction which is evacuated via line 15.

~ an aqueous fraction which settles at the bottom of the flask and which is evacuated via line 9.

The solvent phase from the flask B2 (or B3) is then treated.

The aqueous phase discharged from the flask B2, via the duct 9, undergoes a first expansion in the expansion valve V100, a portion of the acid gases is vaporized and separated in the flask B4, the gaseous fraction thus separated being discharged through the duct 6. The remaining solvent phase is discharged through line 11 and expanded again through expansion valve V101 so as to reach atmospheric pressure, the residual gaseous phase, after separation in balloon B5, thus formed being sent via line 7. The solvent-rich liquid fraction, sent via line 13, is distilled in column C1 in order to obtain, at the top of the water, and at the bottom, the solvent phase which is then injected via line 17 and the circulation pump. at the entrance to the transport pipe 5.

 The column C1 has a reboiler 2, a separator tank 3 and a return line of the vapors 4; a condenser 8, a separator tank 10, a reflux line 12 and a water discharge line 14.

Ultimately, the method is therefore characterized in that: a. A solvent phase comprising at least one of the solvents, alone or as a mixture, is injected:
N, N-dimethylformamide, N-formylmorpholine and N-methylpyrrolidone in the outlet pipe at the wellhead outlet, b. The entire mixture discharged from the wellhead in multiphase flow is conveyed in a pipe in the presence of the solvent phase, c. On arrival at the receiving site, the gas phase and the solvent phase are separated, d. The solvent phase from stage c is regenerated by expansion and / or distillation.

It is then possible to advantageously recycle the regenerated solvent phase from step d to step a.

If the gas contains, moreover? at least one hydrocarbon other than methane, which forms a liquid phase in step a distinct from said fraction consisting essentially of solvent and water, said hydrocarbon fraction is decanted in step c and discharged therefrom of the process.

Preferably, a mass ratio of the solvent phase flow rate injected during step a is chosen to the flow rate of water contained in the gas of between 0.1 and 3. In order to reduce the amount of solvent used, it is advantageous to (but not mandatory), prior to step a to separate by decantation free water ie water contained in the gas in the liquid phase. This is done in the case of the arrangement shown in the diagram of Figure 1 in the settling tank B 1.

The process according to the invention applies to a natural gas. This natural gas may be a condensed gas or an associated gas whose treatment conditions are similar to those of the condensate gas.

The treated gas may also be a so-called dry gas because it does not produce a liquid hydrocarbon fraction under normal production conditions.

In some cases the gas to be treated may contain a relatively large proportion of acid gases such as CO2 and H2S and it may be necessary to reduce this acid gas content.

In such a case, it is advantageous to include in the process an additional acid gas removal step, using the same solvent as used in step a.

Such an elimination can be carried out for example by operating according to the diagram of FIG.

In the case of the version of the process shown diagrammatically in FIG. 2, this step can take place after step c.

The gas is produced by a wellhead from where it is discharged through line 101.

The inhibiting solvent for the formation of hydrates, arriving via line 117, is then injected into the pipeline to allow transport, in conduit 105, without risk of clogging. On arrival at the site or on the ground, the gas will be treated so as to recover the solvent and evacuate the hydrocarbons to the areas of use after a treatment allowing the absorption of acid gases.

The mixture contained in the pipe 105 is introduced into a balloon
B101 where the separation between the gas and the solvent phase is carried out. The gas is evacuated via line 106 to be treated and the solvent phase via line 107. The gas is countercurrently contacted with the solvent phase arriving via line 116 in zone G100 formed, for example, by a packed column. Preferably, a ratio of the molar flow rate of solvent to the molar flow rate of gas of between 0.1 and 3 and more particularly of 0.6 and 2 is chosen.

The gas discharged via line 110 is a gas substantially free of acid gases. The solvent phase charged with acid gases is conducted (line 108) to that from separator B101 and the resulting phase (line 109) is regenerated by simple expansion (valve V10). To reduce the solvent losses, it is advantageous to operate successive detents.

The additional step introduced in this version of the process is therefore characterized in that the gas resulting from the preceding steps is contacted with a solvent flow rate sufficient to cause the acid gases to be removed, the solvent phase resulting from this washing operation being regenerated by one or more successive relaxations then distilled and recycled.

The solvent phases from the flask B101 via the conduit 107 and from the flask B102, where the absorption of the acid gases took place, via the duct 108 are collected and directed via the duct 109 to the expansion flask B103.

The solvent phase undergoes a first expansion in the expansion valve
V10, a portion of the acid gases is vaporized and separated, the gaseous fraction thus separated being discharged through the conduit 111. The remaining solvent phase is discharged through the conduit 112 and expanded again through the expansion valve Vil to reach the atmospheric pressure, the residual gaseous phase thus formed being discharged from the flask B104 via the duct 11. The solvent-rich liquid fraction, sent via the duct 114, is distilled in the column C101 in order to obtain at the head of the water and background the solvent phase that is evacuated through the conduit 115
This aqueous phase is then injected through the conduit 117 at the inlet of the transport pipe 105 on the one hand and sent, on the other hand, to the absorption zone on the packed column via the conduit 116. C101 is similar to the column C1 with its reboiler 102 and its condenser 103 and is therefore not further described. The water is partly drawn off (104a) and partly refluxed (104b).

This version of the process according to the invention is illustrated by Example 2.

The solvents used in the process according to the invention can be used pure or as a mixture. They may also incorporate a minor fraction (minor fraction denoting a mole fraction of less than 0.5) of a commonly used solvent such as methanol or an ethylene glycol.

 The process according to the invention applies to a natural gas. This natural gas can be a condensed gas. The gas to be treated may also be an associated gas whose treatment conditions are similar to those of the condensate gas. This invention is also applicable to a dry gas or a refinery gas containing hydrogen.

It goes without saying that various modifications can be made to the embodiments that have been described, solely as non-limiting examples, without departing from the scope of the invention.

In particular the step of regeneration of the solvent can be carried out according to various methods known to those skilled in the art without modifying the principle of the invention: the number of successive detents for the purpose of eliminating the acid gases can vary as well as pressure levels.

It is also possible to introduce a step of rectification of the gas phase produced by expansion to remove the solvent entrained in said gas phase.

It is also possible to make the countercurrent contact between the treated gas and the solvent phase in two stages with solvent levels and / or different pressure conditions so as to separately absorb CO2 and H2S.

The acid gases thus separated can in certain cases be reinjected into the well. In other cases, they must be eliminated. The fraction rich in
H2S is toxic and H2S can be removed according to one of the known techniques, in particular by the Claus reaction which produces sulfur and water. Different equipment can be used. In particular, the step of countercurrent contact between the treated gas and the solvent phase may be carried out in a packed column and also a plate column. Similarly, the distillation step may be carried out either in a tray column or in a packed column.

To reduce the energy consumption during the distillation step, the reboiling heat may be at least partly provided by the condensing heat of the overhead vapor after recompression of said overhead vapor to a level of pressure such that the condensing temperature of the overhead vapor becomes higher than the reboiling temperature of the bottom liquid.

The process according to the invention is particularly advantageous for exploiting a natural gas reservoir when the production wells are located at sea. In fact, it makes it possible to minimize the treatment on the production site, to transport the gas without any risk of formation of gas. hydrates and postpone the majority of the treatment ashore. It is possible in this case: ~ Either to collect the gas by driving it to a production platform, the separation of the free water contained in the gas and the injection of solvent being carried out on the platform, where is the shipment of the multiphase mixture.

~ Either to produce the gas by means of submarine wellheads, the injection of solvent being carried out underwater conditions and the multiphase mixture being discharged by an underwater pipe.

In these two modes of production at sea, steps c and d are normally carried out on land.

However, although the process is particularly advantageous in the case of natural gas production at sea, it is also applicable in the case of production on land.

The principle of the invention is illustrated by the following examples.

EXAMPLE 1
In this example, we proceed according to the diagram of Figure 1.

Considering a gas containing little liquid water and therefore does not require separation before transport. To illustrate the process, the treated gas can be assumed to be a dry gas, ie containing few hydrocarbons other than methane; there is therefore no condensation of liquid hydrocarbons in the tray B3.

The gas to be treated, saturated with water, arrives from the underwater wellhead through line 1 with a flow rate of 50,000 kg / h. The solvent, N-methylpyrrolidone (NMP) of the empirical formula CSH9NO, is injected via line 17 at a flow rate of 340 kg / h, in order to prevent clogging of the duct by the hydrates during transport to the coast. This corresponds, for a water flow rate of 700 kg / h, to a solvent-to-water ratio of approximately 0.5.

The mixture arrives on the treatment unit via line 5 at a pressure of 5 MPa and a temperature close to 25 C; the temperature under the sea is such that the temperature of the gas can go down to a few degrees and then rise during the journey on land.

The gas enters the flask B2 where the solvent phase and the gas phase are separated. The solvent phase is collected with a flow rate of 1700 kg / h.

The solvent phase first undergoes a first expansion at 2 MPa operated through the valve V100; the solvent phase and the gas phase are separated in the B4 flask. The solvent phase is then sent through the conduit 11 to undergo a second expansion through the valve V101 to atmospheric pressure. A solvent phase containing N.M.P. is thus obtained at the bottom of the flask BS. and water.

This solvent phase is then sent through line 13 to a distillation column where the feedstock is heated to a temperature of 150 ° C. The N.M.P. leaving the bottom of the column is then returned via line 17 to the inlet of the pipeline.

EXAMPLE 2
In this example, we proceed according to the diagram of Figure 2.

Considering a gas containing little liquid water and therefore does not require separation before transport. To illustrate the process, the treated gas can be assumed to be a dry gas, ie containing few hydrocarbons other than methane; there is therefore no condensation of liquid hydrocarbons in the tank B101.

The gas to be treated, saturated with water, arrives from the wellhead through line 101 with a flow rate of 120,000 kg / h. The solvent, dimethylformamide of the empirical formula C3H7NO, is injected via line 117 at a flow rate of 540 kg / h, ie a solvent / water ratio of 0.25, in order to avoid clogging of the duct with hydrates during transport to the water. coast in a sea at the temperature of S'C. No hydrate formation is observed in the conduit 105.

The mixture arrives on the treatment unit via line 105 at a pressure of 7 MPa and a temperature close to 30 C, the heating occurring during the journey to earth. The gas enters the flask B101 where the solvent phase and the gas phase are separated. The solvent phase is collected at a rate of 2700 kg / h.

The gas phase is then sent through the conduit 106 to the flask B102 where it is contacted against the flow in the packing G100 with a liquid phase containing the dimethylformamide arriving via the conduit 116 of the column C101 with a flow rate of 31 500 kg / h .

A solvent phase is collected consisting firstly of the CO2 coming from the gas and absorbed by the solvent and partly of the solvent-laden water coming from the gas-liquid contact in the packing G100, its flow rate is 38000 kg / h.

This solvent phase from the B102 flask is collected with that from the B 101 flask and thus has a solvent phase flow in the conduit 109 of 40 700 kg / h. This solvent phase is substantially charged with acid gases which are removed by simple expansion.

To reduce the solvent losses, it is more interesting to operate successive detents. In the diagram of Figure 2, the elimination of acid gases is effected by means of two detents.

The solvent phase first undergoes a first expansion at 2.5 MPa operated through the valve V10; the solvent phase and the gas phase are separated in the B103 flask. The solvent phase is then sent through line 112 to undergo a second expansion through valve Vil to atmospheric pressure. A solvent phase containing D.M.F. is thus obtained in the bottom of the flask B104. and water, its flow is 34 200 kg / h.

 This solvent phase is then sent through line 114 to a distillation column where the feed is heated to a temperature of 1300C. D.M.F. leaving the bottom of the column is then shared to be sent through the conduit 116 to the balloon B102 acid gas absorption and water and through the conduit 117 to the gas pipeline.

EXAMPLE 3
Use of DMF and NMP to shift the hydrate formation point in the case of methane hydrates.

Dimethylformamide was used at various mass concentrations to decrease the hydrate formation temperature at a given pressure. It appears that the higher the concentration by weight of the DMF, the better its inhibitory power. In addition, a mass percentage of fixed additive was made, a comparison of the various solvents usually used, DMF and NMP.

It follows (Table 1) that DMF, although less effective than methanol, has more interesting antihydrate possibilities than those of ethylene glycols, as for NMP, it has the same qualities as glycols without have the disadvantages. DMF and NMP are therefore solvents which do not have the drawbacks already mentioned, methanol (excessive volatility) and ethylene glycols (viscosity, Table 2), and which fall within the operating ranges of these same solvents.

Table 1. hydrate formation temperature

<tb> Solvent <SEP> Tf <SEP> for <SEP> 100 <SEP> bar <SEP> Tf <SEP> for <SEP> 50 <SEP> bar <SEP> Tf <SEP> for <SEP> 30 <SEP > bar <SEP>
<tb> 20 <SEP>% <SEP><SEP> methanol <SEP> 1 C 20 <SEP>% <SEP><SEP> -5 C <SEP> -9 C-5 C <SEP>
<tb> 20% <SEP> ethylene <SEP> 6 <SEP> C <SEP> 2 <SEP> C <SEP> -3 <SEP> C
<tb> glycol
<tb> 20% <SEP> DMF <SEP> 5C <SEP><SEP> -1C <SEP><SEP> -5C <SEP>
<tb> 20% <SEP> NMP <SEP> 7C <SEP><SEP> 2C <SEP><SEP> -3C <SEP>
<tb> solvent <SEP> 13 C <SEP> 7 C <SEP> 2 C
<Tb>
Table 2. Viscosity of solvents at 20 ° C.

<tb><SEP> Solvent <SEP> Ethylene <SEP> Glycol <SEP> Ethylene <SEP><SEP> Glycol <SEP> Ineibylene <SEP><SEP> Glycol
<tb><SEP> n <SEP> in <SEP> Ns / m2 <SEP><SEP> 0.02198 <SEP> 0.036 <SEP> 0.049
<tb><SEP> Solvent <SEP> Methanol <SEP> DMF <SEP> NMP
<tb> n <SEP><SEP> in <SEP> Ns / m2 <SEP> 0.0005929 <SEP> 0.0009243 <SEQ> 0.001666
<Tb>

Claims (11)

N, N-dimethylformamide, N-formylmorpholine and N-methylpyrrolidone, b. The resulting mixture is conveyed in said pipe in multiphase flow, c. On arrival at the receiving site, the gas phase and the solvent phase are separated, d. The solvent phase from stage c is regenerated by expansion and / or distillation.  1. A method of treatment and transport in a pipe of a gas comprising methane and water, under conditions where a hydrate can be formed in the absence of additives, characterized in that it comprises the following steps: a. At the inlet of the pipe, gas is added a solvent phase comprising at least one of the solvents, alone or as a mixture: 2. Method according to claim 1 characterized in that the transported and treated gas comprises at least a fraction of natural gas, and in that step a is carried out at the production site. 3. Method according to claim 1 characterized in that the gas to be transported is a refinery gas further comprising hydrogen, step a being performed on a first industrial site where said gas is produced and steps c and d being performed on a second industrial site where said gas is used. 4. Method according to one of claims 1 to 3 characterized in that separates, previously-by settling, the free water contained in the gas to be treated. 5. Method according to one of claims 1 to 4 characterized in that the mass ratio of the solvent phase flow rate injected during step a to the flow rate of water contained in the gas is between 0.1 and 3 . 6. Method according to one of claims 1 to 5 characterized in that, at the end of step c, is contacted with a solvent phase from step d, the gas phase in a contact column to countercurrent, the ratio of the molar flow rate of solvent to the molar flow rate of gas being between 0.1 and 3, so that the water and the acid gases contained in the gas phase are at least partially entrained in the solvent phase and said water and said acid gases are separated from said solvent phase in step d. 7. Method according to one of claims 1 to 6 characterized in that the gas to be transported and treated further comprises a liquid hydrocarbon fraction, in that said fraction is transported at the same time as the gaseous fraction at during step b and in that said fraction is separated from the gaseous phase and the solvent phase by decantation. 8. Method according to one of claims 1 to 7 characterized in that the solvent phase used comprises a minor fraction of methanol or ethylene glycol. 9. A method according to one of claims I to 8 characterized in that regenerates the solvent phase during step d by at least two successive detents, in that one evacuates the gaseous fractions obtained rich in acid gases. in that the relaxed solvent phase is sent to a distillation column and the said regenerated solvent phase is discharged from the said column at the top of the water.  10. Method according to one of claims 1 to 9 characterized in that the gas to be transported and treated comes from an underwater wellhead, in that the transport step b is carried out by means of a underwater conduct and in that steps c and d are carried out on land. 11. Process according to one of claims 1 to 10 characterized in that recycles the regenerated solvent phase of step d in step a.