WO2002066137A1

WO2002066137A1 - Process for separation of oil, water and gas in a separator by breaking of water-in-oil emulsions

Info

Publication number: WO2002066137A1
Application number: PCT/NO2002/000077
Authority: WO
Inventors: Johan SJØBLOM; Harald Kallevik; Arild Westvik; Inge Harald Auflem
Original assignee: Statoil Asa
Priority date: 2001-02-23
Filing date: 2002-02-22
Publication date: 2002-08-29
Also published as: NO314389B1; NO20010944D0; NO20010944L

Abstract

Process for separation of oil, water and gas in a separator by breaking of water-in-oil emulsions in a composition comprising a water, oil and optionally a gaseous phase, including the following steps: a) dissolving a gas comprising one or more components into said composition prior to said operator, wherein the amount of said water phase is at least about 1 weight-% based on total composition, b) introducing said composition into said separator, wherein pressure in said separator is of at least about 2 bar, and c) reducing the pressure in said separator in order to facilitate the separation of oil, water and the optional gaseous phase.

Description

PROCESS FOR SEPARATION OF OIL, WATER AND GAS IN A SEPARATOR BY BREAKING OF WATER-IN-OIL EMULSIONS

FIELD OF INVENTION

This invention relates to a process for separation of oil, water and gas in a separator by breaking of water-in-oil emulsions in a composition comprising a water, oil and optionally a gaseous phase.

BACKGROUND OF THE INVENTION

The crude oil production on the Norwegian Continental Shelf is facing new challenges. Many of the oil fields discovered the last years are economically marginal due to their size and location. Thus, the demand for lowering the production cost is obvious. The separation of oil and water and optionally gas from such fields is likely to experience the same type of problems as observed on the larger fields in production today. One of the largest production problems is the formation of emulsions stabilized by polar heavy crude oil components like asphaltenes, resins and waxes. Such problems can be solved by means of addition of chemicals or by use of mechanical separation facilities. However, the costs of these solutions are normally high and the search for new and efficient separation tools is of highest priority. The environmental issue regarding the use of chemicals is an additional disadvantage. Per today there is an increasing challenge for the use of greener and environmentally more friendly chemicals as normally imposed by the state authorities.

The use of a hydrofilic gas, such as for example CO₂, dissolved in water as a possibility to enhance the separability of a water and oil is known per se. Usually, the CO₂ is mixed with the water phase at an early stage in the separation process and the emulsification takes place with an aqueous phase rich in dissolved CO₂. By lowering the pressure in the separator, there will be a release of the CO₂ and the concomitant break of the oil-continuous emulsion.

It is well known that CO₂ will form gas hydrates at low temperatures and high pressures. Separation and injection conditions should therefore be far from the thermodynamic conditions for gas hydrate formation. Further, dissolved CO₂ can constitute a danger for corrosion and low pH's. These conditions must be taken into account in designing a future process and in the choice of the materials.

It would be most beneficial to apply the CO₂ into a two-phase stream with water and oil, i.e. before the emulsification of the phases. The injected polar CO₂ is partitioning between the two phases in the oil-continuous emulsion. Upon pressure reduction (for instance in the separator) two processes will commence: i) the CO₂ dissolved into the aqueous phase (the droplets) will rapidly coalesce and form small bubbles upon a pressure reduction. Due to gravity reasons these bubbles will propagate through the emulsified system. When the droplet leaves the water droplet it has to pass a phase boundary built up by indigenous polar surfactants (asphaltenes, resins and waxes). As a consequence the interface will be ruptured. If the CO bubbles carry with them surface active material from the interface (flotation effect) the time for the interface to reform will be most likely much longer than the coalescence time. Hence the system will break and water and oil phase should appear. ii) the CO₂ dissolved in the oil phase will also rapidly coalesce and form bubbles upon a pressure reduction. Due to buoyancy forces the bubbles will propagate through the emulsified system. In doing so they will rip off surface active material from the o/w interface described as a flotation effect. This effect is not specific for the CO but common for all oil soluble gases below the bubble point. NO B 171 096 describes a process and apparatus for separating a dispersed phase from a continuous phase by means of dissolved gas flotation. The gas is, preferably before the pressure reduction, dissolved in the liquid system. As the pressure is reduced, the dissolved gas is released and thus forming gas bubbles which improves the flotation and hence separation. US A 4 251 361 describes a gas flotation separator for separating oil and water by means of gas, for example CO₂, is dissolved in the liquid and is released as the pressure is reduced. The gas bubbles thus formed in the liquid improves the flotation.

EP A2 298 610 describes a method of oil removal from oil-water emulsions by means of volatile hydrocarbons forming a two-phase system when in contact with the emulsion under pressure to effect the replacement of at least some of the oil in the emulsion phase and dissolved in the volatile hydrocarbon phase. When the pressure is reduced, the volatile hydrocarbon is vaporized and the emulsion separates into a water phase and an oil phase. The prior art documents referred to above relates to the use of CO₂ as separation promoter which all are based upon flotation of oildrops, when the purpose is to remove relatively small amounts of oil in a continuous waterphase.

Further, representative but not exhaustive documents of the present art are GB A 2 323 048, US A 5 580 464, and US A 3 884 803. SUMMARY OF THE INVENTION

It is desirable to provide a process for separation of oil, water and gas in a separator by breaking of water-in-oil emulsions in a composition comprising a water, oil and optionally a gaseous phase. In accordance with this invention, there is provided a process for separation of oil, water and gas in a separator by breaking of water-in-oil emulsions in a composition comprising a water, oil and optionally a gaseous phase, comprising the following steps: a) dissolving a gas comprising one or more components into said composition prior to said separator, wherein the amount of said water phase is at least about 1 weight-% based on total composition, b) introducing said composition into said separator, wherein pressure in said separator is of at least about 2 bar, and c) reducing the pressure in said separator in order to facilitate the separation of oil, water and the optional gaseous phase.

BRIEF DESCRIPTION OF THE DRAWINGS

Figure 1 is a graph showing water separated versus time for a 1 % Crude A in Exxsol D-80, water content 40%. The pressure in the separator was reduced from 65 bar to 1 bar after 5 minutes. Figure 2 is a graph showing % water separated versus time for a Crude A, water content 40%. The pressure in the separator was reduced from 65 bar to 1 bar after 5 minutes.

Figure 3 is a graph showing % water separated versus time for a Crude B, water content 40%. The pressure in the separator was reduced from 65 bar to 1 bar after 5 minutes.

Figure 4 is a graph showing % water separated versus time for a Crude C, water content 35%. There is no pressure drop in the separator.

Figure 5 is a graph showing % water separated versus time for a Crude C at several levels of water content - with and without CO₂. The pressure in the separator was reduced from 65 bar to 1 bar after 2 minutes.

Figure 6 is a graph showing % water separated versus time for a Crude A at several levels of water content - with and without CO₂. The pressure in the separator was reduced from 65 bar to 1 bar after 2 minutes. DETAILED DESCRIPTION OF THE INVENTION

The present invention relates to the use of a polar gas as separation promoter for breaking of water-in-oil emulsions in a composition comprising a water, oil and optionally a gaseous phase, wherein the purpose is to separate the water phase (the dispersed phase) from the oil phase (the continuous phase) in order to break the emulsion and separate into the original components.

The polar gas is selected from polar components which are water-soluble, preferably wherein the gas is selected from CO₂, N₂, O₂, and mixtures thereof, and more preferably wherein the gas is CO₂. Further, the polar gas is selected from nonpolar components which are oil-soluble, preferably wherein the gas is selected from H₂, CH₄, paraffins, and mixtures thereof.

The polar gas is dissolved directly into the water phase before the phases are mixed, or the gas is dissolved countercurrently into the composition before the composition is introduced into the separator. In fig. 1-6 there is experimentally shown that a polar gas, such as CO₂, can accelerate the breaking of crude oil based emulsions. However, this is not possible for all types of crude oil emulsions, but presumably it is possible only for those types of crude oil emulsions which are particle stabilized. In accordance with the present invention, it is shown that merely some types of crude oil emulsions will be effective.

The composition comprising a water, oil and optionally a gaseous phase contains inorganic or organic particulate solids, wherein the amount of inorganic or organic particulate solids is at least about 0,01 weight-% based on total composition, preferably wherein the amount is in the range of 5-15 weight-%. The organic particulate solids are constituted by nanosized asphaltene, metal organic acid, like calcium naphthenate particles, or wax particles, like heavy paraffin particles, or mixtures thereof.

The inorganic particulate solids are constituted by clay, precipitated metal salt or scale particles like calcium carbonate, barium sulphate, or mixtures thereof. In accordance with the present invention the use of CO₂ will be effective in a gravitational separator and most effective in a separator of batch type (batch process), and the emulsion will be hold a few minutes in the separator and settle before the gas pressure in the separator is reduced. In a continuous process, the effect of the content of CO₂ is much less. The pressure in the separator is reduced only after the composition is maintained in the separator at a specific period of time. The period of time is at least about 2 minutes, preferably wherein the period of time is in the range of about 2 to about 5 minutes, and more preferably wherein the period of time is about 4 minutes. Before pressure reduction in the separator, the composition will essentially be steady, and then the released gas effects breaking of the water-in-oil emulsions and thus improves separation. The pressure in the separator is reduced by releasing the separator gas, which can be selected from natural gas, nitrogen, and combinations thereof. The pressure in the separator is of at least about 60 bar, wherein the pressure in the separator is reduced to a value below the separation pressure of the gas in the composition, and the purpose is to reduce the pressure in the separator to a pressure under about 60 bar as CO₂ gas is released as a gas. The pressure in the separator is eventually reduced to 1 bar. The more the emulsions are stabilized by particulate solids (asphaltenes), the better the method of pressure drop works. Especially, small nanosized asphaltene particles will be most effective. If there are no such particulate solids present in the emulsions, the effect of adding CO₂ is not ambiguously positive.

The amount of the water phase is at least about 10 weight-% based on total composition. Preferably, the amount is at least about 30 weight-%, and more preferably the amount is up to about 70 weight-%.

Finally, the pressure of the composition entering the separator is at least about 10 bar. Preferably, the pressure is at least about 30 bar, but can be at least about 70 bar. The following examples are provided for purposes of illustrating the present invention, and are not intended to be limiting of the broadest concepts of the present invention. Unless otherwise stated, all percentages are by weight.

Data of the series of experiments are listed in table 1. PI denotes the pressure of a composition comprising a water phase and an oil phase from a production site, P2 denotes that the pressure of the composition is reduced somewhat before introducing into the separator, and P3 denotes the pressure over the inlet choke to the separator which also applies for the pressure in the separator.

Crude oil characteristics of three types of crude oil emulsions, indicated as Crude A, Crude B and Crude C, are shown in tables 2, 3 and 4, respectively. Table 1. Experimental design

Pressure release

Exp No Oil Phase Water Phase dP (mixing) P (PI ->P2->P3) in separator WC Separator gas

441 1 % Crude A in Exxsol D-80 De-ionised water 20 100->85->65 Yes-5min 40 N₂

442 1 % Crude A in Exxsol D-80 De-ionised water 5 100 c 70 -> 65 Yes - 5 min 40 N₂

443 1 % Crude A in Exxsol D-80 De-ionised water with CO_∑ 5 100- 70^>65 Yes-5min 40 N₂

444 1 % Crude A in Exxsol D-80 De-ionised water with CQ. 20 100^>85->65 Yes -5 min 40 N₂

445 Crude A De-ionised water 20 100- 85->65 Yes -5 min 40 N₂

446 Crude A De-ionised water 5 100- 70- 65 Yes - 5 min 40 N₂

447 Crude A De-ionised water with CO₂ 5 100 - 70 -> 65 Yes -5 min 40 N₂

448 Crude A De-ionised water with CO. 20 100 -> 85 - 65 Yes -5 min 40 N₂

449 Crude A De-ionised water with CO. 20 100->85->65 Yes -5 min 40 N₂

450 Crude A De-ionised water with CO₂ 5 100->70->65 Yes -5 min 40 N₂

451 Crude B De-ionised water 5 100->70- 65 Yes -5 min 40 N₂

452 Crude B De-ionised water 20 100- 85->65 Yes -5 min 40 N₂

453 Crude B De-ionised water with CO₂ 5 100 -> 70 -> 65 Yes - 5 min 40 N₂

454 Crude B De-ionised water with CO₂ 20 100 -> 85 -> 65 Yes -5 min 40 N₂

512 Crude C Synthetic formation water 84 85->85-> 1 No 35 Natural gas 513 Crude C Synthetic formation water 10 85^>85->75 No 35 Natural gas 514 Crude C Synthetic formation water 45 85->85->40 No 35 Natural gas 515 Crude C Synthetic formation water 10 85->85->75 No 35 Natural gas 516 Crude C Synthetic formation water 45 85 ■> 85 -> 40 No 35 Natural gas 517 Crude C Synthetic formation water 84 85->85-> 1 No 35 ' Natural gas 518 Crude C Synthetic formation water with CO₂ 84 85->85- 1 No 35 Natural gas 519 Crude C Synthetic formation water with CO₂ 10 85 -> 85 -> 75 No 35 Natural gas 520 Crude C Synthetic formation water with CO2 45 85->85->40 No 35 Natural gas 521 Crude C Synthetic formation water with CO₂ 10 85->85^>75 No 35 Natural gas 522 Crude C Synthetic formation water with CO₂ 45 85->85->40 No 35 Natural gas 523 Crude C Synthetic formation water with CO₂ 84 85^>85-> 1 No 35 Natural gas

/./.000/Z0ON/X3d /.CΪ990/Z0 OΛV Crude oil characteristics of Crudes A, B and C

Examples

The high pressure separation process is governed by several sub-processes among them both mechanical and compositional effects which seem to be decisive for a successful result. Mechanical effects involve both pressure gradients over inlet chokes (ΔP_mιx) and gas release in the separator (ΔP_sep). The former parameter should determine the level of the energy dissipitation for the dispersive system and hence the droplet size (and distribution) for the dispersed droplets. A large gradient over the inlet choke should render small droplets. The level of ΔP_se = (Pini_et - P_fi_nai) refers to the gas release intensity in the separator, and the final separation will take place below the bubble point of the gas mixture. The compositional state of the crude oil is also influenced by several external parameters among them the start pressure of the mixture comprising the water phase and the oil phase and the final separator pressure at which the separation takes place. It is obvious that the start pressure and the amount of light components being mixed with the original crude components will influence the solubility of heavy components and hence their level of association. The direct conditions in the separator, such as the composition of the separator gas and residence time, will influence the separation process. If the separator is run as a batch separator, i.e. where the separator is filled, the emulsion is allowed to separate. Some of the experiments in this series are performed in a way that the emulsion was kept at an inlet pressure for 2 or 5 minutes after which the pressure was reduced by a degassing process. Under this period of time, the emulsion will undergo a sedimentation process if the droplet size is large enough. The effect of propagating gas bubbles should be larger if the major part of the water droplets is compressed to a dense packed region. Finally, the original composition of the crude oils themselves will of course influence how a gas release can improve the destabilization process. Small nanosized asphaltene particles will give a high level of stability since the protecting w/o interface will show a high rigidity under these conditions.

In the first series of experiments, two different candidates of North Sea crudes are tested, crude oils named Crude A and Crude B. They have both provided very stable water in crude oil emulsions, although the stabilizing mechanisms can be different as revealed by the composition shown in Tables 2 and 3. Crude A is a heavy crude with a high content of asphaltenes, while Crude B is a very acidic crude with a high amount of naphtenic acids. Thus, a value of TAN (Total Acid Number) of Crude B is higher than for Crude A. In addition a model system consisting of Crude A (1 % of Crude A in Exxsol D-80) is tested. Essential for the discussion is that these compositions are run through pressure reductions where the initial pressure (100 bar) is reduced to the separator pressure 65 bar. The separator was run as a batch separator in the sense that the emulsions were placed in the separator for 5 minutes before the final pressure was adjusted as a gas release from 65 bar to 1 bar. Under these experimental conditions, Figures 1 and 2 summarize the separation of water from the corresponding emulsions. The dispersed aqueous phase is either pure water or water saturated with CO₂. The system where 1 % of Crude A is diluted into Exxsol-D 80 and combined with 40 % water with and without CO₂ is presented in Figure 1. The separation level of the model emulsions is much lower, but in this case an acceleration of the gas release on the separation of water is clearly seen. The effect of CO₂ is clearly positive and selective. For Crude A, Figure 2 reveals the effect of the pressure gradient over the inlet choke to the separator and the addition of CO₂. Without CO₂, the pressure gradient (20 or 5 bar) seems to have a minor influence on the separation process. The emulsions are stable, and only 20-25 % of water is separated after 20 minutes. However, in most of the cases the separation is accelerated by the release of CO after 5 minutes. With a pressure gradient of 5 bar, there is no significant difference to the samples without CO₂. However, the large effect is seen for the emulsion with a ΔP = 20 bar and an aqueous phase saturated with CO₂. For these emulsions one observes that as long as the separator pressure is kept at 65 bar (i.e. for 5 minutes), the level of separation is low or almost negligable. After 5 minutes in the separator, i.e. when the pressure reduction takes place, between 50 and 60 % of the water phase will separate within 1-2 minutes, and after 15 minutes, 90 % of the emulsion has broken and separated into the original components. This is a remarkable result for a crude oil which has proven to give very stable emulsions that are resistant to both chemical and mechanical treatment. Figure 3 gives the separation sequence for emulsions based on Crude B.

Characteristically, some separation will for this system take place already at 65 bar. The water separation is at a level of at least about 10 %. However, when the gas is released after 5 minutes, the separation profile changes dramatically. All the graphs (with different pressure drops over the inlet choke to the separator and with and without CO₂ in the water phase) show an acceleration of the resolution of water. However, the selectivity between the different emulsions is lost. Large effects are seen both with and without CO₂ in the aqueous phase and with small and larger pressure gradients over the inlet choke to the separator. One cannot with certainty relate the increased separability to carbon dioxide release. In all the experiments above, N₂ is used as separator gas.

The next series of experiments (Figure 4) refers to Crude C as the crude oil and a natural gas as the separator gas phase. The composition of Crude C is shown in Table 4. These series of experiments are performed according to varying separator pressures. In other words, the pressure after the inlet choke to the separator is also the final separator pressure. Hence the separator pressure was kept at levels of 1 , 40 and 75 bar, and most of the pressure related effects will take place over the inlet choke to the separator. For instance when the separator pressure is below 60 bar, considerable amounts of the CO₂ will be released already over the inlet choke to the separator. The separation picture as a whole is rather «patchy», but after a residence time of 4 minutes, the best result is accomplished for a mild mixing (ΔP = 10 bar) and a corresponding high separator pressure. This picture seems to hold both for systems with and without CO₂. Obviously, the droplet formation conditions seem to be the decisive factor if a batch separator is run according to these specifications. It should be noted that no pressure release is conducted in the separator.

The final Figures 5 and 6 view the influence of the water content for Crude C and Crude A on the separation profile at 1 bar and with and without CO . Figure 5 presents the separation profile of Crude C for the water contents between 20 and 70 volume %. It can be seen that the induction time is high, i.e. after 4 minutes there is only one significant solution of water at the level of 15 %. This accounts for the composition with 70 % of water saturated with CO₂. The highest overall separation (approximately 45 %) is accomplished for 70 % of water without CO . In general, one can conclude that crude oil-based emulsions (Crude C) respond very badly to the separation conditions disclosed in Table 1. For the emulsions based on the Crude A, the situation seems to be more favorable with regard to the solution of water and oil. For higher water contents (i.e. > 30 %), the influence of the released CO₂ gas on the separation efficiency seems to be clear. Within a normal residence time of 4 minutes, almost 80 % of the aqueous phase has separated if the total water content is as high as 60 %.

Claims

1. Process for separation of oil, water and gas in a separator by breaking of water-in-oil emulsions in a composition comprising a water, oil and optionally a gaseous phase, characterized by the following steps: a) dissolving a gas comprising one or more components into said composition prior to said separator, wherein the amount of said water phase is at least about 1 weight-% based on total composition, b) introducing said composition into said separator, wherein pressure in said separator is of at least about 2 bar, and c) reducing the pressure in said separator in order to facilitate the separation of oil, water and the optional gaseous phase.

2. Process according to claim 1, wherein said gas dissolved is selected from polar components which are water-soluble, preferably wherein said gas dissolved is selected from CO₂, N₂, O₂, and mixtures thereof, and more preferably wherein said gas dissolved is CO .

3. Process according to claim 1, wherein said gas dissolved is selected from nonpolar components which are oil-soluble, preferably wherein said gas dissolved is selected from H , CH₄, paraffins, and mixtures thereof.

4. Process according to any of the preceding claims, wherein said gas is dissolved directly into said water phase before said phases are mixed, or said gas is dissolved countercurrently into said composition before said composition is introduced into said separator.

5. Process according to any of the preceding claims, wherein said composition contains inorganic or organic particulate solids.

6. Process according to claim 5, wherein the amount of said inorganic or organic particulate solids is at least about 0,01 weight-% based on total composition, preferably wherein said amount is in the range of 5-15 weight-%.

7. Process according to claim 5 or 6, wherein said organic particulate solids are constituted by nanosized asphaltene, metal organic acid, like calcium naphthenate particles, or wax particles, like heavy paraffin particles, or mixtures thereof.

8. Process according to claim 5 or 6, wherein said inorganic particulate solids are constituted by clay, precipitated metal salt or scale particles like calcium carbonate, barium sulphate, or mixtures thereof.

9. Process according to any of the preceding claims, wherein the pressure in said separator is of at least about 60 bar.

10. Process according to claim 1, wherein said pressure in said separator is reduced to a value below the separation pressure of said gas in said composition.

1 1. Process according to claim 1, wherein said pressure in said separator is reduced to 1 bar.

12. Process according to claim 11, wherein said pressure in said separator is reduced only after said composition is maintained in said separator at a specific period of time.

13. Process according to claim 12, wherein the period of time is at least about 2 minutes, preferably wherein said period of time is in the range of about 2 to about 5 minutes, and more preferably wherein said period of time is about 4 minutes.

14. Process according to any of the preceding claims, wherein said separator is a gravitational separator.

15. Process according to any of the preceding claims, wherein said separator is a separator of batch type.

16. Process according to any of the preceding claims, wherein the amount of said water phase is at least about 10 weight-% based on total composition, preferably wherein said amount is at least about 30 weight-%, and more preferably wherein said amount is up to about 70 weight-%.

17. Process according to any of the preceding claims, wherein the pressure of said composition entering said separator is at least about 10 bar, preferably wherein said pressure is at least about 30 bar, and more preferably wherein said pressure is at least about 70 bar.