METHOD AND SYSTEM FOR STIMULATING FLUID FLOW IN AN UPWARDLY ORIENTED OILFIELD TUBULAR

Abstract

A method for stimulating fluid flow in an upwardly oriented oilfield tubular (1, 12) comprises heating the tubular along at least part of its length to such a temperature that at least some liquid hydrocarbons, such as crude oil and/or condensates, evaporate and provide a gas lift effect.

Description

BACKGROUND OF THE INVENTION

The invention relates to a method and system for stimulating fluid flow in an upwardly oriented tubular.

It is known to stimulate fluid flow in oilfield tubulars by using pumps, such as beam pumps, Electrical Submersible Pumps (ESPs) and/or injecting lift gas into an upwardly oilfield tubular to reduce the density and thus the hydrostatic pressure drop of the mixture of oil reservoir effluents.

U.S. Pat. Nos. 1,681,523 and 2,350,429 and US patent application US2006/0051080 disclose electrical heaters for inhibiting deposition of wax, paraffins and other fouling compositions in production tubings of oil production wells.

U.S. Pat. No. 1,681,523 discloses that air may be injected into the heated production tubing to distribute the heat and lift the heated crude oil to the earth surface.

International patent application WO2009/032005 discloses an inline downhole heater that is configured to keep paraffinic well effluents in a liquefied state and that can also be utilized to generate steam for converting heavy hydrocarbons into light hydrocarbons. A limitation of this known inline heater is that not all well effluents comprise paraffin and/or water and that it does not evaporate produced hydrocarbon liquids, so that it does not provide a gas lift effect in an oilfield tubular through which no water flows. The known inline heater therefore only prevents solidification of paraffin and generates steam, whereas paragraph [0044] indicates that it is designed to prevent gas locking of a downhole production pump, so that it is clearly not designed to evaporate liquid hydrocarbons and provide a gas lift effect.

A disadvantage of the known methods for stimulating fluid flow in well production tubings and other inclined oilfield tubulars is that pumps and lift gas injection systems are complex, expensive and wear prone. The complexity makes them less favourable in extreme conditions such as arctic and/or remote offshore production platforms.

Another disadvantage of known flow stimulation methods is the number of potential leak paths or increased intervention/workover frequencies that result in increased health, safety or environmental exposure—which is a specific concern when hydrocarbon reservoirs contain toxic elements like H₂S.

A further disadvantage of known flow stimulation methods and systems is that their operating window is constraint for pressure (maximum well depth, max deepwater depth) for horizontal reach, for deployments in multilateral well configurations, for maximum and minimum operating and standby temperatures, for reservoir fluid chemical composition (chlorine, CO₂, H₂S) and for physical properties (sand, viscosity, multiphase pumping limits etc).

There is a need for an improved method and system for stimulating fluid flow in an upwardly oriented oilfield tubular, which does not only inhibit deposition of wax, paraffins, hydrates and other fouling compositions and is less expensive, less wear prone, brings an extended operating window, and yields in a safer operations than the known artificial lift flow stimulation techniques using gas lift injection and/or Electrical Submersible Pumps (ESPs).

SUMMARY OF THE INVENTION

In accordance with the invention there is provided a method for stimulating fluid flow in an upwardly oriented oilfield tubular through which liquid well effluents comprising liquid hydrocarbons flow in an upward direction, the method comprising heating the tubular along at least part of its length to such a temperature that at least some liquid hydrocarbons evaporate into vapour bubbles that reduce the density of the fluid, hence reduce the hydrostatic pressure drop between reservoir and wellhead, and thus provide a lift gas effect.

The liquid well effluents may comprise at least some natural gas, condensates, crude oil with light oil fractions and/or water, and the well effluents inside the tubular may be heated along at least part of the tubular length to such a temperature that at least some crude oil and/or condensates are evaporated, for example to a temperature above 50°, 100° Celsius, or above 200° Celsius. For a typical oil field reservoir, due to the decline in hydrostatic pressure while moving towards earth surface, light oil fractions (e.g. ethane, propane, butane) bubbles already form naturally while the fluid travels against gravity. The disclosed method aims to accelerate that effect, so that more bubbles appear deeper in the well already, resulting in the desired gas lifting effect without necessarily bringing compressed gas from surface back into the well.

For a typical oil well, the reservoir is hotter than the formation rock (and eventually the surface wellhead) temperature. Fluid inside the production tubing cools down when travelling upwards, both due to the geothermal temperature gradient and due to the Joules-Thompson effect when hydrostatic pressure decreases. Rather than heating the fluid, systems exploiting the disclosed method often merely need to reduce this cooling effect in order to trigger or maintain bubble formation at the desired depths.

The oilfield tubular may be a production tubing within a crude oil production well, an inclined underwater oil transportation pipeline or oil production riser at an offshore crude oil production facility, or an inclined crude oil transportation pipeline in possibly a cold or arctic area.

In accordance with the invention there is further provided a system for enhancing fluid flow in an upwardly oriented oilfield tubular through which liquid well effluents comprising liquid hydrocarbons flow in an upward direction, the system comprising a heater for heating the well effluents inside a tubular along at least part of its length to such a temperature that at least some liquid hydrocarbons evaporate and provide a gas lift effect, which may involve bringing the natural bubble formation point lower into the well.

In such case the oilfield tubular may be provided with an electrical resistance heater for heating the well effluents at a plurality of heating locations along at least part of the length of the oilfield tubular and with a Distributed Property Sensing (DPS) and/or other sensor assembly for measuring the density and/or temperature of the well effluents at a plurality of measuring locations along at least part of the length of the oilfield tubular, wherein at least one of said measuring locations is located upstream of said plurality of heating locations and at least one other of said measuring locations is located downstream of said plurality of heating locations.

These and other features, embodiments and advantages of the method and system according to the invention are described in the accompanying claims, abstract and the following detailed description of non-limiting embodiments depicted in the accompanying drawings, in which description reference numerals are used which refer to corresponding reference numerals that are depicted in the drawings.

BRIEF DESCRIPTION OF THE DRAWING

FIG. 1 depicts an upwardly oriented oilfield tubular which is heated to enhance fluid flow by evaporating hydrocarbon well effluents in accordance with the invention;

FIG. 2 depicts a conventional oil well where lift gas is injected into the production tubing to provide a gas lift effect; and

FIG. 3 depicts an oil well which is heated to evaporate liquid well effluents to provide a gas lift effect in accordance with the invention.

DETAILED DESCRIPTION OF THE DEPICTED EMBODIMENT

FIG. 1 depicts an upwardly oriented oilfield tubular 1 through which a stream of well effluents flow in an upward direction as illustrated by arrow 2.

An electrical heating cable 3 and a fiber optical Distributed Temperature Sensing (DTS) cable 4 extend in a longitudinal direction along at least part of the oilfield tubular 1.

By transmitting electrical current through the electrical heating cable 3 the well effluents are heated to such a temperature that at least some well effluent evaporates as illustrated by dotted area 5.

The DTS cable 4 monitors the temperature of the stream of well effluents 2 and is connected to an electrical power control unit (not shown) that controls the amount of electrical energy transmitted through the electrical heating cable 3 such that the temperature of the stream of well effluents 2 is elevated to at least the bubble point of that fluid, at the pressure at that elevation, or to another elevated temperature at which at least some water, condensates and/or crude oil evaporates and provides a gas lift effect as illustrated by dotted area 5.

FIGS. 2 and 3 each depict an oil production well comprising a well casing 10, having a perforated lower section that permit influx of crude oil into the well from an oil containing formation 11. A production tubing 12 is suspended within the well casing 10 and a sealing assembly 13 is arranged in an annular space 15 between the well casing 10 and production tubing 12 just above the perforated lower section of the well casing 10. FIG. 2 shows a conventional gas lift assembly wherein lift gas is injected through a lift gas injection conduit 14 via the annular space 15 and lift gas injection ports 16 into the interior of the production tubing 12.

FIG. 3 shows a lift gas generation assembly according to the invention wherein an electrical power supply cable assembly 17 is arranged in the annular space 15, which assembly 17 provides electrical power to a series of electrical resistance heaters 18 arranged in the interior or wrapped around the outer surface of the production tubing 12. The electrical heaters 18 are each configured to generate such an amount of heat in the well effluents flowing through the production tubing 12 that at least some well effluents, such as water, crude oil and/or condensates evaporate and generate lift gas that reduces the density of the well effluent column within and thereby stimulates and enhances the upward flux of well effluents from the oil containing formation 11 through the production tubing 12 to the wellhead at the earth surface.

It will be understood that electrical heaters 18 may evaporate and generate lift gas not only in an upwardly oriented production tubing 12 of an oil well, but also in an upwardly oriented production tubing of a gas well, in which case the electrical heaters 18 may be configured to evaporate any water and condensates flowing through the production tubing 12, and also in other upwardly oriented oilfield tubular, such a risers of an offshore oil and/or gas production facility, underwater flowlines at an inclined water bottom, for example subsea to beach flowlines and/or arctic flowlines at a tilted underground or support, provided that the oil and/or gas well effluents flow in an upward direction through at least part of the length of the oilfield tubular, which may have any tilt angle from zero up to and including 90° degrees relative to a horizontal plane, so that the production tubing 12 or other oilfield tubular may have an inclined or vertical orientation.

It will be understood that the term crude oil as used in this specification and claims refers to reservoir oil as present in the pores of an underground oil bearing formation, including any changes to the composition of the reservoir oil as it travels through the pores of the reservoir to an inflow region of an oil production well and as it travels through the production tubing of such production well and any grid of oilfield tubulars at the earth surface which is connected to a wellhead of the oil production well.

Claims

1. A method for stimulating fluid flow in an upwardly oriented oilfield tubular through which liquid well effluents comprising liquid hydrocarbons flow in an upward direction, the method comprising heating the tubular along at least part of its length to such a temperature that at least some liquid hydrocarbons evaporate and provide a gas lift effect.

2. The method of claim 1, wherein the liquid hydrocarbons comprise crude oil and gas condensates and the tubular is heated along at least part of its length to such a temperature that at least some crude oil and/or gas condensates are evaporated.

3. The method of claim 1, wherein the tubular is heated along at least part of its length to a temperature above 50° Celsius, optionally above 100° Celsius, or above 200° Celsius.

4. The method of claim 1, wherein

the oilfield tubular is heated at a first location along its length;

a physical property, such as the temperature, density, pressure, flow rates, gas/liquid ratio of the well effluents is measured at a second location, which is located upstream of the first location, and at a third location, which is located downstream of the first location; and

the heating at the first location is controlled in response to a difference of the physical properties of the well effluents measured at the second and third locations.

5. The method of claim 1, wherein the well tubular is heated at a plurality of heating locations along at least part of its length and the physical property, such as density, temperature, pressure, flow rate and/or gas/liquid ratio of the well effluents is measured at a plurality of measuring locations along at least part of the length of the oilfield tubular, wherein at least one of said measuring locations is located upstream of said plurality of heating locations and at least one other of said measuring locations is located downstream of said plurality of heating locations.

6. The method of claim 1, wherein the oilfield tubular and the well effluents within the tubular are heated by an electrical resistance heater, which extends along at least part of the length of the oilfield tubular.

7. The method of 1, wherein the physical property of the well effluents is measured at a plurality of locations along at least part of the length of the oilfield tubular by a fiber optical Distributed Property Sensing (DPS) cable extending along at least part of the length of the oilfield tubular.

8. The method of claim 6, wherein the electrical resistance heater and fiber optical DPS cable extend through the interior of the oilfield tubular.

9. The method of 3, wherein the electrical resistance heater and fiber optical DPS cable are located outside and located adjacent to an outer surface of the oilfield tubular.

10. The method of claim 8, or wherein the electrical resistance heater comprises an electrical conductor that transmits both electric heating power supply and bi-directional communication signals so that longitudinally spaced segments of the electrical resistance heater and multiple sensors for measuring one or more physical properties in the vicinity of these segments are individually addressable.

11. The method of claim 10, wherein the electrical conductor comprises an electrical circuit formed by either:

a) an electrical supply conductor formed by an electrical cable wire and an electrical return conductor formed by an electrically conductive metal in the wall of the tubular;

b) a pair of co-axial pipes such as a well casing and production tubing, as commonly used in oil or gas wells.

12. The method of claim 6, wherein

the electrical resistance heater comprises:

a) a series of longitudinally spaced self regulating Positive Temperature Coefficient (PTC) resistors that safeguard against local overheating;

b) an inductive heating system that inductively heats up a metal wall of the oilfield tubular from either the interior the exterior of the oilfield tubular;

c) a microwave heater that heats up the well effluents; and/or

d) an ohmic resistance heater formed by all or part of a metal wall of the oilfield tubular that is either galvanically isolated segment by segment, or whose power supply is locally galvanically isolated.

13. The method of claim 1, wherein the upwardly oriented oilfield tubular comprises:

a) an upwardly oriented production tubing within a crude oil production well;

b) an upwardly oriented underwater crude oil transportation pipeline or crude oil production riser at an offshore crude oil production facility; and/or

c) an upwardly oriented crude oil transportation pipeline.

14. A system for enhancing fluid flow in an inclined oilfield tubular through which liquid reservoir effluents comprising liquid hydrocarbons flow in an upward direction, the system comprising a heater for heating the tubular along at least part of its length to such a temperature that at least some liquid hydrocarbons evaporate and provide a lift gas effect.

15. The system of claim 13, wherein the oilfield tubular is provided with an electrical resistance heater for heating the well effluents at a plurality of heating locations along at least part of the length of the oilfield tubular and with a Distributed Property Sensing (DPS) and/or other sensor assembly for measuring the density and/or temperature and/or pressure and/or flow rate and/or gas/liquid ratio of the oilwell effluents at a plurality of measuring locations along at least part of the length of the oilfield tubular, wherein at least one of said measuring locations is located upstream of said plurality of heating locations and at least one other of said measuring locations is located downstream of said plurality of heating locations.

16. The system of claim 13, wherein the oilfield tubular is a production tubing in gas well and the well effluents comprise natural gas, condensates and/or water, and system is configured to reduce hydrostatic pressure drop along at least part of the length of the production tubing so that wellhead pressure and well effluent production rate are maintained at an elevated level during the lifecycle of the gas well, thereby reducing a need for compressors in the well and/or at the earth surface.