Production wells are used to produce fluid from reservoirs in the geological subsurface. In particular, fluids in the form of oil and gas are produced through wells, as is routinely the case in the oil and gas industry. The production fluid is typically received in the well from the subsurface reservoir due to the natural pressure conditions, and then flows out of the well inside a dedicated production tubing disposed in the well. The flow of gas and liquids in a production well takes place as a result of pressure in the reservoir. The naturally occurring pressure may be sufficient to lift the fluids to the surface. In addition to the natural flow of fluids, an artificial pressure may be added to increase the flow, or create a flow if the naturally occurring pressure is not sufficient to lift the fluids to the surface. The artificial pressure is also referred to as artificial lift. An electric submersible pump (ESP) is a downhole pump which can be used to create artificial lift. A system of multiple EPS lifted wells may be used, wherein the wells are connected to a common manifold. The production fluid from the well is then transported along pipelines to a downstream facility, for example a floating production platform (in the case of an offshore well) where the fluid may be processed further. Additional booster pumps may be provided in the production system at the surface, for example on the seabed, to help pump the production fluid from the well along the pipeline to the downstream facility at a suitable rate.

The invention provides a method and system as defined in the accompanying claims.

Some embodiments of the invention will now be described by way of example only and with reference to the accompanying drawing, in which:

Fig.1 illustrates schematically a system;

Fig.2 illustrates a method.

A method is provided wherein a combination of water and gas is injected into the well.

The method described herein may be used as an artificial lift method for heavy oil reservoirs where gas-lift cannot be applied due to high viscosity of the reservoir oil. The method described herein provides for a method of injecting a combination of water and gas into a well. This method may be used to create artificial lift.

The water and gas may be injected simultaneously into the well.

The water and gas may be injected into the well through holes in the production tubing, optionally as deep as possible such that injection takes place close to a lower completion section. The holes in the production tubing may be provided with valves to control the inflow of water and gas.

The water and gas may be transported down in the annular space between the tubing and the smallest casing. Alternatively, the water and gas may be transported down in a single shared tubing which is provided inside or outside the production tubing. Alternatively, the water and gas may be transported down in separate tubing inside or outside the production tubing, wherein a first tube is provided for the water and a second tubing for the gas. With separate tubing, water can be provided at any position upstream the gas injection. Water can also be provided by extending the well or a well branch into an aquifer. An advantage of adding or injecting water to the produced reservoir fluid is to generate a flow regime inside the production tubing with a low apparent viscosity, when compared to reservoir fluid without water, to reduce the frictional pressure loss. An advantage of adding or injecting gas to the produced reservoir fluid is to generate a fluid mixture in the tubing with low apparent density, when compared to reservoir fluid without gas.

Consequently, by adding, injecting and/or mixing water and gas down hole in the well with the produced reservoir fluid, the fluid mixture in the tubing will have both low viscosity and low density, thereby combining the advantages of water and gas.

The amount of water and gas injected into the production tubing down hole can be regulated continuously to maximize the production of reservoir fluid. The amount of water and gas injected into the well may be varied depending on the composition of the produced fluid, such as water cut and gas liquid ratio of the produced reservoir fluid. Addition of water with continuous flow conditions can be one solution to secure low apparent viscosity of the fluid in the production tubing.

Injection of both water and gas simultaneously reduces pressure losses both due to friction and gravity. 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 added water to reduce friction pressure loss may also be used in connection with transportation of heavy oil outside the well, such as in pipeline transportation of oil.

A possible problem with providing artificial lift is an increase of pressure at the well beyond a threshold at which the surrounding formation fractures or other undesired effects take place. The downhole well equipment may also fail beyond a threshold pressure.

Existing technology to protect the well/downhole well equipment and rock formation at the intermediate casing shoe depth against overpressure are the use of a first barrier provided by a steel casing, and the use of a second barrier provided by a pressure relief device at the wellhead which limits the maximum pressure of the annular space between the tubing and the smallest casing, hereafter called annulus. The pressure is thus limited to avoid fracturing the formation at the level of the shoe in the well. A casing shoe may be used as a term for the bottom of the casing string, including the cement provided around it.

In a traditional application with only one phase in the annulus (i.e. only water, gas or oil) the effect of the static head is relatively easy to account for. Static head refers to the pressure exerted due to the gravitational force of the fluid column in the annulus. For a gas column used in traditional gas lift, the static head is relatively low and a high topside pressure is permissible. For a water column, the static head is high and permissible topside pressure is thus limited. However, the static head also aids injection of water and the topside pressure need not be too high.

In the method disclosed herein, both water and gas is provided in the annulus. The static head of pure water need to be assumed (~1 bar/10m) as a worst case, i.e. a threshold which should not be exceeded, when defining the set point so the permissible pressure at the wellhead is quite limited in order to protect the formation In normal operation there is a significant amount of gas in the fluid column reducing the density and thus static head. In order to get the lift working, a significant pressure needs to be applied topside, easily exceeding the permissible pressure.

Herein disclosed is a pressure regulating system or a pressure sensing system, comprising one or more tubulars extending downhole. The tubulars may be filled with gas. A positive pressure may be provided in the one or more tubulars. A pressure regulating valve may be provided within the one or more tubulars.

The one or several small bore tubulars may be extended down to the level of the shoe. The tubes may be strapped to the outside of the production tubing as is sometimes done for chemical injection lines. A small positive flow of gas is set from the topside with a flow restriction located between the pressure source and the tubes controlling the flow. A precise control of the flow rate is less relevant for this application. The tubular is now acting as a pressure sensing tube at the level of the shoe with only the relatively small static head of the gas column to be accounted for. The tube may be connected to a pressure relief device, such as a pilot operated relief valve, to ensure that this opens at a correct pressure measured at the level of the shoe after adjusting for the static head of gas. The connection is to be made downstream of the flow restriction from the gas source. The gas source would have a pressure high enough to force open the relief device. If the tubular clogs for any reason or the annulus outlet valve opening is blocked or restricted, the pressure from the gas source will ensure that the pressure relief device takes the desired action. If the pressure relief device opens it will relieve the pressure sources that feed and pressurize the annulus. Other pressure relief devices, including instrumented systems may also be used for pressure protection.

A plurality of separate small gas tubes may be provided inside the annulus and these may be used for measuring and/or controlling the actual downhole pressure inside the annulus and for pressure protection of the well. This method and system can be used on a well where water and gas is injected simultaneously into the well through the annular space between the tubing and the smallest casing, referred to as the simultaneous injection of gas and water used as artificial lift (SWAG-L) method.

By using a dedicated gas filled sensing line one avoids the complication of having to account for a heavy fluid (water) when defining the set pressure topside. Instead, the actual pressure at the level where the system needs to be protected is measured. The operational envelope for topside pressure is not dependent on conservative assumptions and ensures efficient lift.

Figure 1 illustrates a simultaneous water and gas lifted well including a pressure protection system. The system includes a gas supply (1 ) and a water supply (2) which are used to provide a flow of water and gas in the annulus A (3). The gas supply is also connected to small bore injection lines (4) to provide the pressure protection system as described above. A flow measuring element (5) is provided and a flow restriction (6). A pressure safety valve (7) is also connected to the combined water and gas tubular as well as to the small bore injection lines. In the example illustrated in the Figure, the small bore injection lines extend from the surface though the Christmas tree into annulus A, past the sea floor to the intermediate casing shoe (8), where the intermediate casing ends. The injection point where the combined water and gas are injected into the well is provided below the point where the small bore injection lines end. A small positive gas pressure is maintained within the small bore injection lines.

Figure 2 shows a method comprising: (S1 ) providing a gas supply to the annulus through one or more tubulars extending from the surface into the annulus.

Although the invention has been described in terms of preferred embodiments as set forth above, it should be understood that these embodiments are illustrative only and that the claims are not limited to those embodiments. Those skilled in the art will be able to make modifications and alternatives in view of the disclosure which are contemplated as falling within the scope of the appended claims. Each feature disclosed or illustrated in the present specification may be incorporated in the invention, whether alone or in any appropriate combination with any other feature disclosed or illustrated herein.