US20220056346A1

US20220056346A1 - A method for desalting produced hydrocarbons

Info

Publication number: US20220056346A1
Application number: US17/415,880
Authority: US
Inventors: Ingvild Johanne Haug; Børre Tore Børresen; Heidi Mediaas; Hege Kummernes; Ivar Øystein Larsen
Original assignee: Equinor Energy AS
Current assignee: Equinor Energy AS
Priority date: 2018-12-21
Filing date: 2019-12-19
Publication date: 2022-02-24
Also published as: GB201821093D0; GB2580145B; CA3124548A1; AU2019403728A1; BR112021012070A2; NO20210876A1; GB2580145A; WO2020130850A1

Abstract

A method for desalting produced hydrocarbons includes injecting reduced-salinity water into produced hydrocarbons in a production well or riser, to dilute high-salinity produced water contained in the produced hydrocarbons.

Description

TECHNICAL FIELD

The present invention relates to the treatment of produced hydrocarbons, and in particular to desalting in produced hydrocarbons.

BACKGROUND

Liquid hydrocarbons are typically produced from a reservoir in a formation, and are conveyed from the reservoir via a production well. Produced liquid hydrocarbons typically contain a variety of impurities and/or foreign substances. Such impurities and/or foreign substances include water, salts (which may be contained in the water), gases, organometallic compounds and organic acids, and solids. To mitigate potential damage to equipment and to comply with regulations and/or customer requirements, it is necessary to remove, reduce or transform the impurities and/or foreign substances before the crude is sold to customers. To achieve this, the liquid hydrocarbons are typically processed at a processing facility.
Typical processing steps performed at the processing facility include gas/liquid separation, oil/water separation, and desalting. The desalting step may form part of the oil/water separation step. One desalting method involves the addition of fresh (i.e. reduced-salinity or low-salinity) water to dilute high-salinity formation/produced water contained in the produced liquid hydrocarbons. The fresh water is mixed into the liquid hydrocarbon to dilute the high-salinity formation/produced water. The mixing intensity applied during addition of fresh water results in water-in-oil (WiO) emulsions, and contact between the high-salinity formation water and the added fresh water. Only a fraction of the added fresh water will be mixed with, and result in dilution of, the high-salinity formation water. This fraction is referred to as the mixing efficiency, E, which is used to design desalting processes. The mixing efficiency is known to reach maximum levels of ≤75% during operation. However, the mixing efficiency is often much lower and in the range of 10-40% for one-stage desalting, meaning that only 10 to 40% of the added fresh water can contribute to reducing the salinity of the produced water. A low E value will increase the quantity of fresh water required to obtain sufficient desalting. The emulsion formed can contain water droplets with varying salinity. The water can be separated from the liquid hydrocarbon using gravitational forces or using an electrical field (electrocoalescence) to meet market-acceptable levels of water and salt. In many cases, it may be difficult to ‘break’ the emulsion formed after addition of fresh water even when an electrical field is used (for example in a coalescer, which is a vessel with internal electrodes). It may be more difficult to break a WiO emulsion including water with a lower salinity, and for smaller amounts of water relative to the amount of liquid hydrocarbon. Stable emulsions will result in poor desalting and dewatering. The oil may therefore still contain undesirable amounts of salt following the desalting procedure.

SUMMARY

It is an object of the present invention to overcome or at least mitigate the problems identified above.
In accordance with a first aspect of the present invention there is provided a method for desalting produced hydrocarbons. The method comprises injecting reduced-salinity water into produced hydrocarbons in a production well or riser, to dilute high-salinity produced water contained in the produced hydrocarbons.
The reduced-salinity water may have a salinity lower than seawater in a body of water above a field in which the production well is located, and/or has a salinity lower than the high-salinity produced water.
The reduced-salinity water may have a salinity of less than 60 000 mg/L, preferably less than 55 000 mg/L, more preferably less than 40 000 mg/L, and still more preferably less than 31 000 mg/L.
The reduced-salinity water may be injected into the produced hydrocarbons through one or more openings in production tubing located in the production well, or one or more openings in the riser. The one or more openings in the production tubing or production riser may be provided with valves to control the inflow of reduced-salinity water.
The produced hydrocarbons may be contained in production tubing located in the production well, wherein the reduced-salinity water is injected deep in the production well such that injection takes place close to a lower completion section.
The reduced-salinity water may be injected in an amount sufficient to create an oil-in-water emulsion in which the produced hydrocarbons are suspended as a dispersed phase within a continuous phase provided by the reduced-salinity water.
The reduced-salinity water may be injected in an amount sufficient to create a water-in-oil emulsion in which the reduced-salinity water is suspended as a dispersed phase within a continuous phase provided by the produced hydrocarbons.
The reduced-salinity water may be configured to provide a mixing efficiency of greater than 50%, preferably greater than 60%, and still more preferably greater than 75%, with the produced hydrocarbons.
The reduced-salinity water may have a higher temperature than fluids in a reservoir from which the produced hydrocarbons are produced.
The reduced-salinity water may be injected into the produced hydrocarbons in combination with gas. The reduced-salinity water and the gas may be injected simultaneously into the produced hydrocarbons in the production well.
Embodiments of the invention will now be described by way of example only and with reference to the accompanying drawings, in which:

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 shows a system for injecting a treatment fluid into a production well.

FIG. 2 shows a system for injecting a treatment fluid into a flowline.

FIG. 3 shows a system for injecting a treatment fluid into a riser.

FIG. 4 shows a high-level flow diagram describing a method in accordance with the invention.

DETAILED DESCRIPTION

The invention is beneficial in that a conduit, e.g. a well, production riser, production tubing, or production flowline, that conveys produced liquid hydrocarbons at least part of the way between a reservoir and a processing facility is used as a ‘reactor’, i.e. a processing container, to perform processing steps that may otherwise need to be performed at the processing facility. The processing facility may be, for example, an oilfield facility located between a production well and a storage tank, a topsides processing facility located e.g. on a floating platform, or a processing facility located on the seabed at a riser base between a flowline and a riser. The processing steps performed in the conduit may completely replace, or render obsolete, processing steps that would otherwise be performed at the processing facility, or processing steps may be performed partially in the conduit and partially at the processing facility. The substance(s) required for the processing steps, which may be a treatment fluid such as reduced-salinity or low-salinity water for desalting, are injected into the produced liquid hydrocarbons while the hydrocarbons are located in the conduit. This means that the time taken for the produced liquid hydrocarbons to traverse the conduit, and to traverse any subsequent part of the production structure before the processing facility, is usefully exploited to increase the temperature, contact time and/or the potential for mixing between the treatment fluid(s) and the liquid hydrocarbons, thereby increasing the efficacy of the processing. The temperature of the conduit can be increased using heated liquids from the processing facility, resulting in more efficient processing. One or more processing stages may be performed before the treatment fluid is injected into the produced hydrocarbons. For example, a desalting stage may be performed at a subsea facility before the produced hydrocarbons enter a flowline, where the treatment fluid is injected into the produced hydrocarbons. In another possible embodiment, oil/water separation may be performed on produced hydrocarbons downhole, before the treatment fluid is injected into the produced hydrocarbons at a later stage in the production tubing in the well. The injection of the substance(s) into the liquid hydrocarbons while the liquid hydrocarbons remain under near-reservoir conditions, i.e. at desirable pressure (and, optionally, temperature), is an early intervention that may remove the need for processing steps that would otherwise be required at the processing facility.
Produced hydrocarbons often contain water, and the produced water contained in the produced hydrocarbons can have a high salinity, mostly due to the presence of sodium, calcium and/or potassium chlorides. Lower concentrations of other salts may be present. The produced water is typically dispersed within the produced hydrocarbons in a water-in-oil emulsion, but may form a continuous phase in which the produced hydrocarbons are dispersed, i.e. an oil-in-water emulsion. Liquid hydrocarbons, e.g. oil, must meet certain standards with respect to salinity and water content before the oil can be transported away from a field, e.g. via pipeline, and/or sold to a customer. In particular, a low salt content is desired because salt may lead to corrosion during transportation and refining, and may compromise the quality of the oil for final sale and consumption. A desalting method in accordance with the invention comprises injecting reduced-salinity or low-salinity water into produced hydrocarbons contained in a conduit for conveying the produced hydrocarbons, to dilute high-salinity produced water contained in the produced hydrocarbons. The conduit is, for example, a production well, production tubing in a production well, a flowline, a production flowline, a riser, or a production riser. In one embodiment the reduced-salinity water is injected into the produced hydrocarbons before the produced hydrocarbons reach a processing facility, and before the produced hydrocarbons are subjected to any processing stages at a processing facility. Alternatively, one or more processing stages—for example, separation in the well, subsea separation or separation at a wellhead platform, which may in effect be desalting operations—may be performed on the produced hydrocarbons before the reduced-salinity water is injected into the produced hydrocarbons. As set out above, this desalting method exploits the time that the produced hydrocarbons spend in the conduit to perform processing operations, in this case desalting, that would otherwise need to be performed at a processing facility.
FIG. 1 shows a well 114, in particular a production well, extending through a formation 122, and through a cap rock 113. The well has a conductor 111 and casings 112. Produced hydrocarbons 124 are conveyed in production tubing 126 from a reservoir 120. The production tubing 126 is located within the well 114. The produced hydrocarbons 124 typically contain liquid hydrocarbons, and impurities such as water, salts (which may be contained in the water), gases, organometallic compounds and organic acids, and solids. The liquid hydrocarbons are referred to here as oil. In this embodiment the formation 122 is a subsea formation and a Christmas tree (xmas tree) 102 is located on the seafloor above the well 114. The produced hydrocarbons 124 are routed through the xmas tree 102 to a processing facility 105, which is located between the xmas tree 102 and a storage tank 106. The produced hydrocarbons are subjected to processing stages such as gas/liquid separation and oil/water separation at the processing facility 105. Following processing, oil may be stored in storage tank 106, and/or transported away via pipeline or flowline. Treatment fluid 108 is injected into the produced hydrocarbons 124 before the produced hydrocarbons reach the processing facility 105. In particular, the treatment fluid 108 is injected into the produced hydrocarbons while the produced hydrocarbons are in the production tubing 126 located in the well 114. The treatment fluid is conveyed by a tube 101 towards the xmas tree 102, and is conveyed through the xmas tree to an annulus 103 between the production tubing 126 and a tubular outside the production tubing, e.g a casing. The treatment fluid 108 is injected into the produced hydrocarbons in the production tubing via an opening in the production tubing. In an embodiment the opening contains a valve 104 to control the inflow of treatment fluids into the production tubing. In an embodiment the tube extends through the xmas tree and the annulus and terminates at the opening in the production tubing. In an embodiment the opening is located below the water, below the seafloor and below the cap rock, close to a lower completion section.
In an embodiment the treatment fluid 108 is water or an aqueous solution, and gas 107 as well as treatment fluid 108 is injected into the production tubing, in line with the simultaneous water and gas lift (SWAGL) technique described in WO2017158049, the entire contents of which is incorporated herein by reference. The gas 107 may be combined with the treatment fluid 108 in the tube 101 before entering the well, or may be injected using separate tubing and a separate opening in the production tubing. The injection of both water and gas simultaneously reduces pressure losses both due to friction and gravity. The gas 107 may be sour gas. Without adding further pressure, the well pressure itself may be sufficient to transport the production fluids to the surface in combination with the reduction of pressure losses after injection of water and gas.
The treatment fluid may be heated before injection, and injected at a temperature higher than fluids in the reservoir from which the produced hydrocarbons are produced. Injecting heated treatment fluids will increase the temperature of the conduit, and increase the temperature of the produced hydrocarbons in the conduit. This will decrease the viscosity of the liquid hydrocarbons, increasing the mixing efficiency and facilitating transport of the produced hydrocarbons through the conduit. Alternatively, the treatment fluid may be injected at a temperature lower than, or substantially equal to, fluids in the reservoir from which the produced hydrocarbons are produced.
In an embodiment the treatment fluid is reduced-salinity water that is injected into the produced hydrocarbons to dilute higher-salinity water contained in the produced hydrocarbons. Injecting reduced-salinity water into the produced hydrocarbons in accordance with the invention eliminates, or at least mitigates, the need for a desalting stage at the processing facility. The reduced-salinity water has a salinity lower than seawater in a body of water above the field in which the production well is located, and/or has a salinity lower than the higher-salinity water contained in the produced hydrocarbons. In particular, the reduced-salinity water has a salinity of less than 50 000 mg/L, preferably less than 55 000 mg/L, more preferably less than 40 000 mg/L, and still more preferably less than 31 000 mg/L. The reduced-salinity water is injected in an amount sufficient to create an oil-in-water emulsion in which the produced hydrocarbons are suspended as a dispersed phase within a continuous phase provided by the reduced-salinity water. Creating an oil-in-water emulsion in this way increases the mixing efficiency, i.e. the likelihood that the reduced-salinity water will contact the higher-salinity water contained in the produced hydrocarbons, to thereby dilute the higher-salinity water, is increased. The overall volume fraction of higher-salinity water in the mixed fluid is also reduced by the addition of the reduced-salinity water. In particular, the reduced-salinity water is injected to provide a mixing efficiency of greater than 50%, preferably greater than 60%, and still more preferably greater than 75%, with the produced hydrocarbons. Alternatively, the reduced-salinity water may be injected in smaller amounts sufficient to create a water-in-oil emulsion wherein the reduced-salinity water is suspended as a dispersed phase within a continuous phase provided by the produced hydrocarbons. Mixing efficiency is dependent on water droplet size in oil (for oil-continuous production), water droplet collision frequency, reaction time and oil viscosity. In water-continuous production in the well, it will be easier to mix the reduced-salinity water and the produced water.
FIG. 2 shows an embodiment which is functionally similar to the embodiment of FIG. 1, with the exception that the location of the processing facility and the location at which the treatment fluid is injected are different. Produced hydrocarbons 224 are conveyed from a reservoir via a production well 214 and through an xmas tree 202. The produced hydrocarbons 224 may be stored in storage tank 206 before being transported via production flowline 215 to a processing facility 205. In FIG. 2 the processing facility 205 is shown at or near the base of a riser 216. Alternatively, the processing facility 205 may output oil and/or other products of the processing to a further flowline or other conduit. Treatment fluid 208 is injected into the produced hydrocarbons while the produced hydrocarbons are located in the production flowline 215, and before the produced hydrocarbons reach the processing facility 205. The treatment fluid 208 is injected via an opening in the production flowline. The opening may contain a valve 204 to control the inflow of the treatment fluid.
FIG. 3 shows an embodiment which is functionally similar to the embodiment of FIG. 1 and FIG. 2, with the exception that the location of the processing facility and the location at which the treatment fluid is injected are different. Produced hydrocarbons 324 are conveyed from a reservoir via a production well 314 and through an xmas tree 302. The produced hydrocarbons 324 may be stored in storage tank 306 before being transported via production flowline 315, riser base 317 and riser 316 to a topsides processing facility 305 located on a platform 318. The platform 318 may be, for example, a floating platform anchored to the seabed by cables, or another type of floating unit, e.g. a floating production storage and offloading (FPSO) unit. Treatment fluid 308 is injected into the produced hydrocarbons while the produced hydrocarbons are located in the production riser 316, and before the produced hydrocarbons reach the processing facility 305. The treatment fluid 308 is injected via an opening in the production flowline. The opening may contain a valve 304 to control the inflow of the treatment fluid.
FIG. 4 shows a high-level flow diagram illustrating the method. In step S402, reduced-salinity water is injected into produced hydrocarbons in a production well, flowline or riser, to dilute high-salinity produced water contained in the produced hydrocarbons.
Features of the embodiments described above may be combined as required.
It will be appreciated by the person of skill in the art that various modifications may be made to the above described embodiments without departing from the scope of the present invention.

Claims

1. A method for desalting produced hydrocarbons, the method comprising:

injecting reduced-salinity water into produced hydrocarbons in a production well or riser, to dilute high-salinity produced water contained in the produced hydrocarbons.

2. The method of claim 1, wherein the reduced-salinity water has a salinity lower than seawater in a body of water above a field in which the production well is located, and/or has a salinity lower than the high-salinity produced water.

3. The method of claim 1, wherein the reduced-salinity water has a salinity of less than 60 000 mg/L, preferably less than 55 000 mg/L, more preferably less than 40 000 mg/L, and still more preferably less than 31 000 mg/L.

4. The method of claim 1, wherein the reduced-salinity water is injected into the produced hydrocarbons through one or more openings in production tubing located in the production well, or one or more openings in the riser.

5. The method of claim 4, wherein the one or more openings in the production tubing or production riser are provided with valves to control the inflow of reduced-salinity water.

6. The method of claim 1, wherein the produced hydrocarbons are contained in production tubing located in the production well, wherein the reduced-salinity water is injected deep in the production well such that injection takes place close to a lower completion section.

7. The method of claim 1, wherein the reduced-salinity water is injected in an amount sufficient to create an oil-in-water emulsion in which the produced hydrocarbons are suspended as a dispersed phase within a continuous phase provided by the reduced-salinity water.

8. The method of claim 1, wherein the reduced-salinity water is injected in an amount sufficient to create a water-in-oil emulsion in which the reduced-salinity water is suspended as a dispersed phase within a continuous phase provided by the produced hydrocarbons.

9. The method of claim 1, wherein the reduced-salinity water is configured to provide a mixing efficiency of greater than 50%, preferably greater than 60%, and still more preferably greater than 75%, with the produced hydrocarbons.

10. The method of claim 1, wherein the reduced-salinity water has a higher temperature than fluids in a reservoir from which the produced hydrocarbons are produced.

11. The method of claim 1, wherein the reduced-salinity water is injected into the produced hydrocarbons in combination with gas.

12. The method of claim 11, wherein the reduced-salinity water and the gas are injected simultaneously into the produced hydrocarbons in the production well.