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.

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.