WO2020263098A1

WO2020263098A1 - Optimisation of water injection for liquid hydrocarbon production

Info

Publication number: WO2020263098A1
Application number: PCT/NO2020/050130
Authority: WO
Inventors: Robert Aasheim; Kjetil Fjalestad; Erling GRAMMELTVEDT; Ivar Øystein LARSEN
Original assignee: Equinor Energy As
Priority date: 2019-06-25
Filing date: 2020-05-19
Publication date: 2020-12-30
Also published as: GB2585367A; GB2585367B; GB201909112D0

Abstract

A method for optimising water injection into a production well or fluid line. The method comprises: (a) injecting water into the production well or fluid line at a first injection point using an injection rate W, to provide a mixture of oil droplets dispersed in water in the production well or fluid line; (b) changing W while measuring a pressure drop ΔP; and/or measuring ΔP during a natural variation in the flow of water, oil and/or gas from a reservoir into the production well, wherein ΔP is measured between a first point and a second point along the length of the production well or fluid line, wherein the second point is downstream from the injection point and the first point; (c) determining a range of ΔP values for which dΔP/dW is positive and close to zero; and (d) adjusting, or maintaining, W to obtain a ΔP value within the range of ΔP values.

Description

OPTIMISATION OF WATER INJECTION FOR LIQUID HYDROCARBON

PRODUCTION

Technical Field

The present invention relates to the optimisation of water injection for liquid hydrocarbon production.

Background

Artificial gas lift techniques may be used to facilitate production of liquid hydrocarbons, e.g. heavy oil, from a reservoir. In a typical gas lift procedure, high-pressure gas is injected into liquid hydrocarbons contained in the production tubing. The injected gas aerates the liquid hydrocarbons, reducing the overall density of the liquid. This reduces the hydrostatic pressure imposed by the fluid column, and allows the formation pressure to more easily‘push’ liquid hydrocarbons from the reservoir into and through the production tubing, thereby increasing the rate of hydrocarbon production. Water may be injected in combination with the gas to reduce the effective viscosity of the fluids in the production tubing, further increasing the production efficiency, or facilitating production where gas lift alone is not sufficient. Such simultaneous water and gas lift (SWAGL) techniques are disclosed in, for example, WO2017158049.

Water may also be injected into a fluid line, e.g. a pipeline extending from a satellite wellpad to a central processing facility, for example an FPSO, to facilitate the transport of liquid hydrocarbons.

In each case, water is typically injected in excess amounts, to avoid the potential stoppage of production and/or plugging of the well or fluid line that could result from the use of too little water.

Summary of Invention

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 optimising water injection into a production well or fluid line. The method comprises: (a) injecting water into the production well or fluid line at a first injection point using an injection rate \N, to provide a mixture of oil droplets dispersed in water in the production well or fluid line; (b) changing \N while measuring a pressure drop D P; and/or measuring D P during a natural variation in the flow of water, oil and/or gas from a reservoir into the production well, wherein DR is measured between a first point and a second point along the length of the production well or fluid line, wherein the second point is downstream from the injection point and the first point; (c) determining a range of DR values for which όDR/dW is positive and close to zero; and (d) adjusting, or maintaining, W to obtain a ZIP value within the range of ZIP values.

The method may further comprise, between steps (c) and (d), periodically measuring D P, and if DR is outside the range of DR values, adjusting W in step (d); or if DR is within the range of ZIP values, maintaining W in step (d).

Changing W may comprise incrementally changing W. Incrementally changing W may comprise incrementally reducing W. The increment by which W is changed may be adjusted based on cfzlP/c/l/1/ values determined while W is incrementally changed. The increment may be reduced as όDR/dW becomes closer to zero.

After steps (a) to (c) are performed, the steps of claim 2 and step (d) may be cyclically repeated.

In the case that D P is measured during a natural variation in the flow of water, oil and/or gas from a reservoir into the production well, adjusting or maintaining W may comprise adjusting or maintaining W automatically, based on the natural variation in the flow of water, oil and/or gas from the reservoir, and a hydraulic model of the production well performance.

The first point and the second point may be located at the same tubing joint or in a tool string section.

The first point may be between 10 and 1000 m, preferably between 10 and 250 m, and still more preferably between 10 and 100 m, from the first injection point. The first point may be located downhole, close to a reservoir.

The second point may be located downhole, close to the reservoir.

The second point may be located at a wellhead.

The first point may be located downstream of the first injection point.

The first point may be located upstream of the first injection point.

In accordance with a second aspect of the present invention there is provided a system for optimising water injection into a production well or fluid line. The system comprises: a production well or fluid line; a water injection line for injecting water into the production well or fluid line at a first injection point using an injection rate 1/1/; a first pressure sensor located at a first point along the length of the production well or fluid line and configured to measure a pressure in the production well or fluid line at the first point; a second pressure sensor located at a second point along the length of the production well or fluid line, downstream of the first injection point and the first pressure sensor, and configured to measure a pressure in the production well or fluid line at the second point; and a control unit configured to determine a pressure drop D P between the first point and the second point based on pressure data measured by the first and second pressure sensors. The control unit is further configured to: change 1/1/ while monitoring D P, and/or measure DR during a natural variation in the flow of water, oil and/or gas from a reservoir into the production well; determine a range of DR values for which όDR/dW is positive and close to zero; and adjust, or maintain, 1/1/ to obtain a D P value within the range of ZIP values.

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 Drawings

Figure 1 shows a system for use in a method in accordance with the invention, when applied in a production well. Figure 2 shows a system for use in a method in accordance with the invention, when applied in a fluid line.

Figure 3 shows a schematic plot that illustrates the optimisation of water injection.

Figure 4 shows a plot illustrating an emulsion viscosity relative to water for a viscous oil at two temperatures/viscosities, with and without emulsion breaker.

Figure 5 shows a plot illustrating a pressure drop in a 2” pipe for a viscous oil as a function of watercut for U_si=2 m/s and a gas volume fraction of 0-40%.

Figure 6 shows a high-level flow diagram describing a method in accordance with the invention.

Detailed Description

Under certain conditions, e.g. for heavy oils, or very cold oils at high reservoir viscosity and relatively low pressure, conventional artificial gas-lift techniques may not be suitable. Under such conditions, gas and oil may create a viscous mousse in a production well, and such a material may flow at a low, or zero, flow rate, due to the resulting high frictional pressure drop in the production tubing. By injecting water (“flipwater”) upstream in the well in a controlled manner, and using enough water to create an oil-in-water fluid, a mixture viscosity similar to water can be achieved, and the gas lift method can be used, or can be optimised to increase oil production efficiency. This simultaneous water and gas lift (SWAGL) procedure is described e.g. in WO2017158049. Of course, the SWAGL procedure may be used with oils of any suitable viscosity to increase production efficiency.

Water injection may be used in a‘water loop system’ for oil transport in pipelines at an offshore oil field, where oil is typically transported from a wellhead platform over many kilometres to a fixed processing platform or a floating production storage and offloading vessel (FPSO). In such techniques, water is typically injected in excess amounts to achieve phase inversion from an oil-continuous fluid to a water-continuous fluid, because the lower effective viscosity of the water-continuous fluid facilitates transport. The amount of water injected may be, for example, 100% more than is needed to achieve phase inversion. The volume of water injected and the proportion of the resultant fluid that is water (the watercut) is typically determined after the fluid has entered the FPSO. In particular, the watercut is typically determined by determining a mass balance of the constituent fluids following a separation process. Any variation in upstream conditions will therefore be discovered much later than the variation occurred.

When injecting water into a production well or a pipeline as set out above it may be difficult to determine the amount of water to inject. Too much water injected will result in lower oil production, and increases pumping energy costs and C02 emissions. Too little water will result in an oil-continuous emulsion, which may have a higher viscosity than the oil itself, and may stop production, and in the worst case plug the tube. Therefore, excess amounts of water are typically used.

The present invention provides a method for optimising the amount of water injected into a production well or a water-continuous fluid transport line. In particular, by systematically varying the water injection rate and measuring a pressure drop over a distance downstream in the well or fluid line, a relation for the variation in pressure drop with changes in water injection rate can be found.

Figure 1 shows a system 100 suitable for use in the method of the invention. A production well 1 10 extends through a subsurface formation of the Earth. Produced fluids 180 are conveyed through the production well 1 10 for subsequent processing, transport and/or sale. In an embodiment, the produced fluids 180 are contained in production tubing, which is in turn contained in the production well 1 10. The produced fluids 180 originate e.g. from a reservoir in the formation (not shown in Figure 1 ). The produced fluids 180 comprise liquid hydrocarbons, and may 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/or solids.

A water injection line 1 12 carries injection water 150, also referred to as flip water 150, to a water injection point 102 located at a given depth in the production well 1 10. The water injection point 102 is also referred to here as a first injection point 102. The injection water 150 is injected into the production well at the water injection point 102 at a given pressure and water injection rate \N. A water injection pressure sensor 1 16 measures the pressure in the water injection line 1 12, and a water injection flow sensor 1 18 measures a flow rate of the injection water in the water injection line 1 12. A water injection choke 128 is used to control the pressure and flow rate of the injection water in the water injection line, to thereby control \N.

A first pressure sensor 104 and a second pressure sensor 106 are located at a first point and a second point, respectively, along the length of the production well. The second point is downstream of the water injection point and downstream of the first point. In an embodiment the first point is also downstream of the water injection point. In an alternative embodiment, the first point is upstream of the water injection point. The first 104 and second 106 pressure sensors are preferably located close to, but not directly adjacent to the water injection point. The first and second pressure sensors may be mounted at a tubing joint, on different tubing joints, or may be located on a tool string that is lowered into the well. In particular, it is preferable for the fluids downstream of the water injection point to be in a fully developed flow state before they reach a pressure sensor, which may be the first pressure sensor 104 if the first and second points are downstream of the water injection point, or the second pressure sensor if the first point is upstream of the water injection point. This implies a preferred minimum distance between the water injection point and the first pressure sensor (or second pressure sensor if the first pressure sensor is upstream of the water injection point). The distance required for a developed flow to be established can be estimated using a rule of thumb, which indicates that to ensure a developed flow, the first pressure sensor (or second pressure sensor if the first pressure sensor is upstream of the water injection point) should be located a minimum of 100 pipe diameters downstream of the water injection point. Therefore, depending on the diameter of the conduit (e.g. production tubing) through which the produced fluids are being transported, the first pressure sensor (or second pressure sensor if the first pressure sensor is upstream of the water injection point) may be between 10 and 1000 m, preferably between 10 and 250 m, and still more preferably between 10 and 100 m, downstream from the water injection point. Further, it is preferable for any change in conditions due to a change in water injection rate to be detected as quickly as possible, and this implies a preferred maximum distance between the water injection point and the first pressure sensor (or second pressure sensor if the first pressure sensor is upstream of the water injection point). This preferred maximum distance is e.g. 1000 m, 250 m or 100 m. If the first and second points are downstream of the water injection point, the distance between the first and second pressure sensors is, for example 5 to 100 meters, 5 to 50 m, or preferably 5 to 10 m, in practice dependent on the length on the tubing joint where the first and second sensors are mounted. If the first point is upstream of the water injection point the distance between the first and second pressure sensors may be greater, and this may reduce the accuracy and response time of the measured pressure data. In an embodiment the second pressure sensor is not downhole, but is instead located at the wellhead.

The first and second pressure sensors are for measuring a pressure drop DR between the first point and the second point. Pressure measurement data from the first and second pressure sensors are transmitted to a control unit 120. The control unit 120 includes a processor configured to compare pressure measurement data from the first pressure sensor and the second pressure sensor to determine DR. The control unit 120 is further configured to change the water injection rate based on the determined DR data, where the water injection rate is changed via a water choke control unit 134, which may be separate from or included in the control unit 120, and the water injection choke 128. The processor of the control unit 120 is further configured to determine DR/dW, where όDR/dW is defined here as a change in DR produced by a given change in water injection rate W. The processor is still further configured to control W to obtain, and/or maintain, a DR value corresponding to a cf7\P/c/ W value within a predetermined range. Further details on how the water injection rate W is changed based on the DR data are set out in relation to Figure 3. Data from the water injection pressure sensor 1 16 and the water injection flow sensor 1 18 are transmitted to the control unit 120, and such data is used by the control unit when determining a change in W.

It is envisioned that when applied in a production well, the invention will typically be used with the SWAGL process as set out in WO2017158049, which exploits the combination of water and gas injection to increase hydrocarbon production. The system of the embodiment shown in Figure 1 therefore also includes a gas injection line 1 14 for conveying gas-lift gas 160 to a gas injection point 108 located in the production well. The gas 160 is injected into the production well 1 10 at the gas injection point 108 using a given gas injection rate. The gas injection point 108 can be located upstream or downstream from the first 104 and second 106 pressure sensors. In an embodiment the gas 160 and the injection water 150 are both injected at the first injection point 102. A gas injection pressure sensor 122 and a gas injection flow sensor 124 measure a gas pressure and a gas flow rate, respectively, in the gas injection line 1 14, and measured data from these sensors are transmitted to the control unit. DR will also be affected by changes in the gas injection rate. The processor of the control unit is configured to control the gas injection rate via a gas choke control unit 132 and gas lift choke 126, based on D P and measured gas pressure and gas flow rate data. .

The embodiment shown in Figure 1 also includes a gas-lift pressure sensor 195 at a relatively shallow location in the production well. When the gas injection point is located downstream from the first and second pressure sensors, a downstream pressure sensor 195 can be used in combination with sensor 104 or 106 and control system 120 to optimize the gas injection rate. Such gas-lift pressure sensors are known to the skilled person and are typically used in artificial gas-lift systems. The gas-lift pressure sensor 195 transmits measured pressure data to the control unit, and the control unit is configured to control the gas injection rate based on the measured pressure data, if required. A multi-phase meter 190 is optionally included in the system 100. The multi phase meter can be located in the production well, or integrated in the wellhead manifold such that the flow from all individual wells leads to the instrument. It also may be located in the production train before a processing facility. Such multi-phase meters are known to the skilled person, and are typically used to measure a proportion of injected water or reservoir water in produced fluids. A water injection rate may be varied based on data from a multi-phase meter. Multi-phase meters are typically expensive, and the data obtained may be of limited use for controlling a water injection rate, because of the large distance from the water injection point to the multi-phase meter, and the consequent difference in the phase proportions between those two points. The embodiment shown in Figure 1 includes a fluid line 185, which is e.g. a production line, and optionally a production choke 130 and production choke control unit 136, via which the control unit can control a flow rate in the production line 185. The fluid line may terminate at a manifold, and the manifold may receive fluid lines from multiple other wells.

Figure 2 relates to an alternative embodiment in which the invention is applied in a fluid line 290, e.g. a production fluid line or fluid transport line, rather than a production well. The fluid line is for transporting liquid hydrocarbons, where the liquid hydrocarbons may have been previously subjected to processing stages such as de-salting and/or separation. If the liquid hydrocarbons are viscous it may be advantageous to inject water into the fluid line to provide a water-continuous fluid, to thereby reduce the viscosity and facilitate transport of the liquid hydrocarbons. If excess water from the reservoir has been removed in a separation stage, the remaining water required to keep the fluid water-continuous can be defined as injection water in this context. It may be difficult to determine what amount of injected water is required in a transport line, and hence a large excess of water is typically used. A multi-phase meter may be used to try to obtain a more accurate idea of how much water should be injected, but such meters are typically located distant from the water injection point, e.g. on an FPSO, and as set out above this means that the data obtained from such a meter may be of limited use. The invention provides a way of accurately obtaining and/or maintaining an optimum water injection rate that maximises production efficiency.

Figure 2 shows a system 200 that, notwithstanding the application of the invention to a fluid line rather than a production well, substantially corresponds to the system 100 of Figure 1 . Elements of the system 200 that correspond to features of Figure 1 are indicated with reference numerals incremented by one hundred. Figure 2 shows a simplified view of the system 200. In particular, the system 200 may include, for example, a multi-phase meter, a production choke or other elements of the system of Figure 1 , but such elements are not shown in Figure 2. The system 200 of Figure 2 does not include any gas-lift features, because in the embodiment of Figure 2 the fluid line is a substantially horizontal fluid transport line. However, in another embodiment the fluid line may be e.g. a riser, and in such a case, gas-lift features corresponding to the gas-lift features shown in Figure 1 may be included.

Injection water 250 carried in a water injection line 212 is injected into the fluid line 290 at a water injection point 202. The system 200 may include a water injection pressure sensor for measuring the pressure in the water injection line 212, and a water injection flow sensor for measuring a flow rate of the injection water in the water injection line 212, corresponding to the water injection pressure sensor and water injection flow sensor of the embodiment of Figure 1. The configuration and operation of the first pressure sensor 204, second pressure sensor 206, control unit 220, water injection choke 228 and water injection choke control unit 234 is substantially the same as set out above for the embodiment of Figure 1.

Figure 3 shows a schematic plot illustrating the variation in D P, which is labelled as dP,P_w on the plot 300, as a function of changes in the watercut Q_w, which is proportional to water injection rate W. This plot illustrates the theoretical basis for a method in accordance with the invention. A tangent line 312 illustrates a change in DR as a function of changes in Q_w that is small, positive and non-zero. If the calculated tangent line has a negative gradient, this means that reducing the water injection will increase the pressure drop in the line, which will increase the bottom hole pressure P_w,, implying that production will be reduced. The watercut is the proportion of the fluids contained in the production well or fluid line (downstream of the water injection point) that is water. For example, a watercut of 1 means that only water is being conveyed through the fluid line (downstream of the water injection point), whereas a watercut of 0.4 means that 40% of the fluid being conveyed by the fluid line is water, with the other 60% being made up of liquid hydrocarbons and potentially other fluids. In the ideal situation schematically illustrated in Figure 3, the watercut is proportional to the water injection rate W. Further, the water injection rate W is the variable that is controlled in the method to change the water cut. It is noted, therefore, that any reference to a change in the watercut in this description can be considered equally to refer to the corresponding change in the water injection rate W. The change in DR as a function of changes in Q_w is therefore equivalent to DR/dW. Over time, water from the reservoir will increase the watercut, and the injection rate W should be reduced in accordance with the described procedure to maintain the optimum watercut. The control system can be used until the water production from reservoir exceeds the optimal watercut for the mixture.

In the first instance a method in accordance with the invention will typically be performed starting from a high watercut in a production well or fluid transport line. In the case when the method is applied in a production well, this may be important because the alternative of starting from a low watercut risks plugging the well with viscous liquid hydrocarbons. In particular, water will typically be injected using a high enough water injection rate/pressure that production of liquid hydrocarbons is suppressed, resulting in a watercut of 1 , or close to 1 . It is of course possible that the method will be performed starting from a lower watercut, once a stable multi-phase production regime has been established, or when the method is being performed in a fluid line to facilitate transport of liquid hydrocarbons. It may be possible to start from a watercut of zero in a fluid line if the method is performed to improve transport of liquid hydrocarbons.

Considering the plot 300 of Figure 3 and starting from a high watercut in a hypothetical water injection procedure, we begin in a high-watercut region 302 at the right hand side of the plot. In this high-watercut region 302 the pressure drop A P is effectively entirely due to the injection of water under high pressure. As the water injection rate (and therefore the injection pressure, and the watercut) is reduced, and/or gas is injected, we move leftward in the plot 300, and ZIP decreases. At some point, the pressure in the fluid line drops below a threshold point at which production of liquid hydrocarbons commences, i.e. liquid hydrocarbons are conveyed in the injected water. In a fluid transport line, the method may potentially be performed starting from this point. As the watercut is further decreased, we reach an inflection point in the plot, and dAP/dW passes through zero. With still further decreases in the watercut, DR begins to increase and dAP/dW becomes negative. The increases in DR in this left-hand region 308 of the plot are due to increases in the viscosity of the fluid, as more and more of the fluid is made up of liquid hydrocarbons rather than water. Dashed line 306 illustrates a point at which the fluids downstream of the water injection point have a high viscosity, since the water-continuous emulsion is close to phase inversion. With further reduction in the water content, the fluids will undergo a phase inversion, switching from a water- continuous fluid to an oil-continuous fluid, and A P increases rapidly as we move further leftward in the plot 300. When the method is applied in practice it is envisaged that the watercut will be maintained within a range of values for which dAP/dW is positive. This is to avoid any potential plugging or production stop, which may be more likely in the left-hand region 308 of the plot.

An aim of the invention is to optimise water injection by staying in a region 304 of the plot 300, in which dAP/dW is small, positive and close to zero. In this region 304, the amount of water injected is close to the minimum amount required to maximise production efficiency. Reducing the amount of water used decreases the amount of energy and maintenance required for water injection, and increases production efficiency simply by increasing the amount of liquid hydrocarbons per unit volume of fluid. Further, A P is close to its minimum in the region 304, and a minimum A P provides a high production efficiency. As set out above, it is preferable to stay in the region in which dAP/dW is positive, rather than zero or negative, to avoid the risk of rapid increases in viscosity that could result in plugging of the well or fluid line.

As a high-level overview, a method in accordance with the invention achieves this aim by determining a range of D P values for which dAP/dW is small, positive and close to zero; monitoring AP and adjusting or maintaining W to obtain a AP value corresponding to a dAP/dW value that is small, positive and close to zero. This effectively involves determining at least a portion of the plot shown in Figure 3, and using the resulting knowledge of the variation in dAP/dW with changes in W to maintain W in a range that provides a small and positive dAP/dW.

In practice, the range of AP values for which dAP/dW is small, positive and close to zero is determined by varying W while monitoring any consequent changes in AP. W is varied e.g. using the control unit 120, water choke control unit 134 and water choke 128. The consequent changes in AP are monitored e.g. using data from the first pressure sensor 104 and second pressure sensor 106 and the control unit 120. When starting from a high watercut, W is varied by incrementally reducing W. In an embodiment, dAP/dW is determined by the control unit while W is incrementally varied, e.g. using a rolling window of AP and W values, and the increment by which W is varied may be changed based on the rate of change in dAP/dW. For example, the increment may be reduced as dAP/dW approaches zero, to provide a higher density of data within the range of AP values that correspond to a region in which dAP/dW is small and positive, and to avoid entering a region in which dAP/dW is negative.

In some cases there are natural variations in water, oil, and/or gas flow from the reservoir, and the variation in well performance as a function of such natural variations is known. In this case, instead of (or in combination with) varying W in a controlled manner to determine the region in which dAP/dW is small and positive, hence obtaining the optimum watercut, another method is to use a hydraulic model for the known well performance, monitor AP during natural variations in the water, oil and/or gas flow to determine the region in which dAP/dW is small and positive, and adjust W automatically to achieve minimum AP. A combination of the controlled variation of 1/1/ and an automatic adjustment of 1/1/ based on natural variations and a mathematical model can also be envisaged.

It is envisaged that the procedure of determining the range of A P values for which dAP/dW is small and positive will be an initial procedure, which typically will not need to be repeated. Following this procedure, DR is monitored, and a small and positive dAP/dW is maintained based on the previously obtained knowledge of the range of A P values for which dAP/dW is small and positive. Monitoring A P comprises periodically measuring A P using the first and second pressure sensors. In particular, A P is measured, for example, once per day, once per hour, or once per minute. Of course, any suitable or necessary time period between measurements of A P can be used. If a measured value of A P falls outside the range of A P values for which dAP/dW is small and positive, 1/1/ is adjusted to provide a A P value within that range. The control unit is configured to automatically control the process of determining the range of A P values for which dAP/dW is small and positive, and the process of monitoring A P and, if necessary, adjusting 1/1/ to provide a DR value within that range.

In an embodiment, the procedure of determining the range of A P values for which dAP/dW is small and positive is repeated periodically, or in response to an event that potentially changes the relationship between dAP/dW and 1/1/. The procedure may be repeated once a month, once every six months, once a year, or using any other suitable repetition time interval. An example of an event that may change the relationship between dAP/dW and 1/1/ is an inflow of gas into a production well. In an embodiment, 1/1/ is varied by incrementally increasing 1/1/, and then optionally incrementally reducing 1/1/ to return to the initial 1/1/ value.

Figure 4 shows a plot of emulsion viscosity (relative to water) as a function of watercut, for a viscous oil at two temperatures/viscosities. For the higher viscosity, data are shown for measurements performed with and without emulsion breaker. As shown in Figure 4, depending the viscosity of the oil, the inversion point between a water- continuous fluid and an oil-continuous fluid (which is indicated by a steep increase in viscosity) is typically in the range of 20-40% watercut. Experiments with a viscous offshore heavy oil have shown that a watercut equal to or greater than 35% provides low viscosity and low pressure drop. Below 35%, the water continuous emulsion viscosity increases since the system is approaching phase inversion, leading to an increase in pressure drop when reducing the amount of water injected.

Figure 5 shows a plot illustrating the pressure drop in a 2” pipe for a viscous oil as function of watercut for a superficial liquid velocity of U_si=2 m/s, and a gas volume fraction of 0-40%. The datapoints grouped around each watercut value show measurements taken at different gas volume fractions, where the differences in the gas volume fraction produced a variation in mix rate. As shown in Figure 5, the variation in mix rate had a relatively small effect on the pressure drop, relative to the large increase in the pressure drop that resulted from decreases in the watercut below approximately 30%. The large increase in the pressure drop occurred as a result of increases in the emulsion viscosity as the watercut was decreased.

The data shown in Figures 4 and 5 indicates that the fluid mix will remain water continuous in an interval between 35% and 20% water cut with increasing viscosity, such that the risk of phase inversion is low if variation is done in small steps.

Figure 6 shows a high-level flow diagram describing a method in accordance with the invention. At step S602, water is injected into a production well or fluid line at a first injection point using an injection rate l/l/, to provide a mixture of oil droplets dispersed in water in the production well or fluid line. At step S604, 1/1/ is changed while measuring a pressure drop D P and/or D P is measured during a natural variation in the flow of water, oil and/or gas from a reservoir into the production well, wherein DR is measured between a first point and a second point along the length of the production well or fluid line, wherein the second point is downstream from the injection point and the first point. At step S606, a range of DR values is determined for which όDR/dW is positive and close to zero. At step S608, 1/1/ is adjusted or maintained to obtain a DR value within the range of DR values.

Using the method of the invention, the water and gas injection rates can be controlled and measured automatically and online, seconds after any variation in upstream conditions. Usage of injection water can be reduced by optimization, and energy consumption can be reduced. 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 optimising water injection into a production well or fluid line, the method comprising:

(a) injecting water into the production well or fluid line at a first injection point using an injection rate l/l/, to provide a mixture of oil droplets dispersed in water in the production well or fluid line;

(b) changing 1/1/ while measuring a pressure drop D P and/or measuring D P during a natural variation in the flow of water, oil and/or gas from a reservoir into the production well,

wherein DR is measured between a first point and a second point along the length of the production well or fluid line, wherein the second point is downstream from the injection point and the first point;

(c) determining a range of DR values for which όDR/dW is positive and close to zero; and

(d) adjusting, or maintaining, 1/1/ to obtain a DR value within the range of DR values.

2. A method according to claim 1 , comprising, between steps (c) and (d), periodically measuring D P, and

if DR is outside the range of DR values, adjusting W in step (d); or

if D P is within the range of D P values, maintaining W in step (d).

3. A method according to claim 1 or claim 2, wherein changing W comprises incrementally changing W.

4. A method according to claim 3, wherein incrementally changing 1/1/ comprises incrementally reducing 1/1/.

5. A method according to claim 4, wherein the increment by which 1/1/ is changed is adjusted based on όDR/dW values determined while 1/1/ is incrementally changed.

6. A method according to claim 5, wherein the increment is reduced as d/lP/cf 1/1/ becomes closer to zero.

7. A method according to any one of claims 2 to 6, wherein, after steps (a) to (c) are performed, the steps of claim 2 and step (d) are cyclically repeated.

8. A method according to any one of the preceding claims, wherein DR is measured during a natural variation in the flow of water, oil and/or gas from a reservoir into the production well, and

adjusting or maintaining W comprises adjusting or maintaining W automatically, based on the natural variation in the flow of water, oil and/or gas from the reservoir, and a hydraulic model of the production well performance.

9. A method according to any one of the preceding claims, wherein the first point and the second point are located at the same tubing joint or in a tool string section.

10. A method according to any one of the preceding claims, wherein the first point is between 10 and 1000 m, preferably between 10 and 250 m, and still more preferably between 10 and 100 m, from the first injection point.

1 1. A method according to any one of the preceding claims, wherein the first point is located downhole, close to a reservoir.

12. A method according to any one of the preceding claims, wherein the second point is located downhole, close to the reservoir.

13. A method according to any one of claims 1 to 1 1 , wherein the second point is located at a wellhead.

14. A method according to any one of the preceding claims, wherein the first point is located downstream of the first injection point.

15. A method according to any one of claims 1 to 13, wherein the first point is located upstream of the first injection point.

16. A system for optimising water injection into a production well or fluid line, comprising:

a production well or fluid line; a water injection line for injecting water into the production well or fluid line at a first injection point using an injection rate l/l/;

a first pressure sensor located at a first point along the length of the production well or fluid line and configured to measure a pressure in the production well or fluid line at the first point;

a second pressure sensor located at a second point along the length of the production well or fluid line, downstream of the first injection point and the first pressure sensor, and configured to measure a pressure in the production well or fluid line at the second point; and

a control unit configured to determine a pressure drop D P between the first point and the second point based on pressure data measured by the first and second pressure sensors,

wherein the control unit is further configured to:

change 1/1/ while monitoring D P, and/or measure DR during a natural variation in the flow of water, oil and/or gas from a reservoir into the production well;

determine a range of DR values for which όDR/dW is positive and close to zero; and

adjust, or maintain, W to obtain a DR value within the range of DR values.