TREATMENT OF OIL AND OIL-CONTAINING FORMULATIONS

Abstract

There is disclosed a method of separating a mixture (e.g. dispersion) of oil and water into oil-rich and water-rich phases, the method comprising the steps: (i) selecting a mixture which comprises oil recovered from a subterranean formation and a treatment formulation, wherein said treatment formulation was added to the oil in order to facilitate its recovery and/or mobility, wherein said treatment formulation has an Interfacial Tension (IFT), measured against a sample of said oil in the range 2 to 20 mN/m; (ii) directing said mixture to a separation means; and (iii) in the absence of a chemical demulsifier, heating the mixture until separation is effected at least partially under gravity. Preferably the IFT is in the range 9 to 12 mN/m. The mixture of oil and water may be formed by treating oil in a subterranean formation.

Description

This invention relates to the treatment of oil and oil-containing formulations. Preferred embodiments relate to the separation of formulations, for example dispersions, comprising oil-water mixtures that have been recovered from subterranean formations.

Many oil-containing formulations include oil that cannot be recovered by normal production techniques because the viscosity of the oil is too high. It is known to address this problem by the use of surface active materials to reduce the apparent viscosity of the oil and facilitate its flow. Known surface active materials include emulsifying surfactants, such as described in U.S. Pat. No. 5,641,433 (Intevep) which are delivered in aqueous formulations, and are arranged to cause an emulsion of oil in water to be formed which has a lower apparent viscosity compared to that of the oil itself Thus, the oil can more readily be transported and/or recovered.

However, the oil/water/surfactant mixture, which is recovered, needs to be treated to optimize the amount of oil and preferably to isolate oil which contains a low level of water and/or surfactant. This is however challenging. In fact, the mixture prepared as described in U.S. Pat. No. 5,641,433 cannot readily be separated satisfactorily and so the emulsion is sold under the Trade Mark ORIMULSION (Trade Mark) for low level use, for example as a fuel to be burned. In other prior art, chemical demulsifiers may be used to break the recovered oil-in-water emulsion. However, disadvantageously, such a process requires the use of further potentially expensive chemicals in a further process step which adds to the cost and complexity of the oil isolation process.

It is an object of the present invention to address the above-described problems.

It is an object of the present invention to provide a means for separating an oil-in-water emulsion whilst reducing and/or eliminating use of a chemical demulsifier.

According to a first aspect of the invention, there is provided a method of separating a mixture (e.g. dispersion) of oil and water into oil-rich and water-rich phases, the method comprising the steps:

(i) selecting a mixture which comprises oil recovered from a subterranean formation and a treatment formulation, wherein said treatment formulation was added to the oil in order to facilitate its recovery and/or mobility, wherein said treatment formulation has an Interfacial Tension (IFT), measured against a sample of said oil in the range 2 to 20 mN/m;
(ii) directing said mixture to a separation means; and
(iii) in the absence of a chemical demulsifier, heating the mixture until separation is effected at least partially under gravity.

Since some oils are too viscous for IFT to be conveniently measured, the sample of oil is diluted with toluene at a ratio of oil:toluene of 75:25. The IFT referred to is therefore based on the diluted material. IFT may be measured by a standard method as described in the examples which follow.

Advantageously, effecting separation, at least partially, in the absence of any demulsifier reduces use of chemicals and facilitates the separation process. The separation described in step (iii) is preferably carried out, without there being added demulsifier of any description.

In addition to having the specified IFT, said treatment formulation is also suitably able to increase the mobility of oil in the subterranean formation when treatment formulation is contacted with said oil. Treatment formulations which are able to increase mobility suitably have at least one of the following characteristics (measured at 25° C.) when a selected treatment formulation is contacted with a sample of oil, wherein the ratio of oil:treatment formulation is 70:30:

(a) A dispersion of oil and treatment formulation has a viscosity, at a shear rate of 1 s⁻¹, of less than 5000 cP, preferably less than 4000 cP, most preferably less than 3000 cP.
(b) A dispersion of oil and treatment formulation is pseudoplastic over the shear rate range 1 s⁻¹ to 100 s⁻¹.
(c) A dispersion of oil and treatment formulation has a viscosity, at a shear rate of 100 s⁻¹, of no more than 700 cP, preferably less than 500 cP, most preferably less than 400 cP.

Said treatment formulation preferably includes at least two of characteristics (a) to (c) and, more preferably, includes all three characteristics.

The rheological properties of the interface between oil and the formulation preferably fall within certain structural boundaries. If the interface is not very structured, the dispersion will coalesce and not be mobile. If the interface is too highly structured, the dispersion will be unbreakable. Preferred treatment formulations need to be somewhere in between the referenced “too structured” and “not very structured” extremes. Continuing on this theme, the interface is preferably not too elastic—e.g. it is suitably not an interface which can deform under applied stress rather than rupturing and coalescing. A simple view is that high interfacial structure may be equated with high interfacial viscosity and low interfacial structure may be equated with low interfacial viscosity. However, the rheological properties of fluids are complex and multidimensional, so fully characterising the rigidity, structure and elasticity of an interface is difficult since these properties are related to the organization of the molecules at the interface, which is microscopically small and difficult to address. Modern rheological methods indicate that the structure of the interface may be investigated using rheological methodologies that investigate its Non-Newtonian characteristics such as: interfacial viscosity, shear dependence, viscous moduli, elastic moduli, complex viscosity and phase angle etc.

Said separation means suitably comprises a first receptacle into which said mixture is delivered. The method preferably includes the step of heating the mixture in the first receptacle into which said mixture is delivered. The method preferably includes the step of heating the mixture in the first receptacle, suitably to a temperature of at least 40° C., preferably at least 50° C. The mixture may be heated to less than 90° C. Preferably, the mixture is heated to a temperature in the range 50° C. to 90° C. Said mixture may be heated as described (e.g. so it is within the range 50° C. to 90° C.) for at least 1 hour, at least 12 hours, at least 24 hours or at least 36 hours; it may be heated as aforesaid for less than 90 hours or less than 72 hours.

During said heating, the mixture suitably separates under gravity so that two layers of materials are defined—a lower layer comprising water, water-soluble materials and, if present in the mixture, solids such as sand; and an upper layer comprising oil. The oil layer may be wet in that it includes some water, but preferably it includes less than 20 wt %, or less than 10 wt % of water. The ratio defined as the wt % of water in the mixture before separation in step (iii) divided by the wt % of water in the upper layer after separation is preferably at least 2, more preferably at least 3. It may be less than 50. The lower layer may include at least 70 wt %, 80 wt % or 90 wt % water. It may include less than 99 wt % water. The balance of the lower layer may be made up of one or more additives included in said treatment formulation added, (for example to adjust the IFT of the water of said treatment formulation) and/or sand or other solids.

Said first receptacle preferably includes vent means, suitably at an upper end, for removing gas from within the receptacle. Said first receptacle preferably includes a first outlet, suitably at an upper end, for removing fluid from an upper part of the receptacle, for example for removing fluid from said upper layer. Thus, the method suitably includes the step of removing fluid (e.g. which includes a major amount of oil) from an upper layer of fluid in the first receptacle.

Said first receptacle preferably includes a second outlet, suitably at or towards the lower end for removing fluid from said lower layer. Thus, the method suitably includes the step of removing fluid from the lower layer in the first receptacle. Preferably, the fluid removed from said lower layer is re-cycled; i.e. preferably said method includes contacting said fluid (which suitably includes an active material as described hereinafter) with further oil, for example in a subterranean formation, in order to facilitate its recovery and/or mobility. The method may include delivering fluid removed from said lower layer into a treatment formulation receptacle which is arranged to delivery treatment formulation to a position wherein it contacts oil, for example in a subterranean formation. The method may include introducing one or more additives (e.g. additional active material as described hereinafter) into the fluid in the treatment formulation receptacle so that the fluid therein has a predetermined composition and/or so the concentration of active material in said formulation is within a predetermined range.

Said first receptacle may include an outlet for removal of solids, e.g. sand, therefrom. Thus, said method preferably includes the step of separating solid material from the fluid in the first receptacle.

When said first receptacle includes a first outlet as is preferred, said first outlet may be connected to a second receptacle and the method may include withdrawing fluid from the upper part of the first receptacle and delivering it into said second receptacle. In the method, water in the fluid is preferably separated from oil in the fluid in the second receptacle. Preferably, no chemical demulsifier (preferably no demulsifier of any description) is added to the second receptacle. Separation in said second receptacle preferably includes the step of heating the fluid in the second receptacle, suitably to a temperature of at least 40° C., preferably at least 50° C. The fluid may be heated to less than 90° C. Preferably, the fluid is heated to a temperature in the range 50° C. to 90° C. Said fluid may be heated as described (e.g. so it is within the range 50° to 90° C.) for at least 1 hour, at least 12 hours, at least 24 hours or at least 36 hours; it may be heated as aforesaid for less than 96 hours or less than 72 hours.

Said second receptacle may be arranged for delivery of fluid from an upper part thereof into further separation means which may comprise a conventional battery.

Said treatment formulation may have a surface tension (in the absence of any oil) at 25° C., preferably in the range 35 to 66 mN/m, more preferably in the range 40 to 65 mN/m.

Said IFT may be at least 6 mN/m, suitably at least 7 mN/m, preferably at least 8 mN/m, more preferably at least 9 mN/m. The IFT may be less than 18 mN/m, suitably less than 16 mN/m, preferably less than 14 mN/m, more preferably less than 12 mN/m, especially less than 10 mN/m. Preferably, the IFT is in the range 8 to 14 mN/m, especially 9 to 12 mN/m.

Said treatment formulation suitably comprises water and an active material, wherein suitably said active material affects the IFT of the treatment formulation in relation to oil and/or modifies the water so it has the IFT as described herein.

Said treatment formulation is suitably aqueous. It suitably comprises at least 80 wt %, preferably at least 90 wt %, more preferably at least 95 wt %, especially at least 98 wt % water. It may include 99.5 wt % or less of water.

Said treatment formulation suitably includes at least 0.1 wt %, preferably at least 0.3 wt %, more preferably at least 0.4 wt % of said active material. It may include less than 1 wt %, preferably less than 0.8 wt % of said active material.

Said treatment formulation suitably includes 95 to 99 wt % of water, 0.1 to 1 wt % of said active material and 0 to 3 wt % of other additives, such as biocides or corrosion inhibitors. The amount of other additives may be less than 2.5 wt %, suitably less than 2.0 wt %, preferably less than 1 wt %. Preferably, said treatment formulation includes 98 to 99.9 wt % of water, 0.1 to 1 wt % of said active material and 0 to 1 wt % of other additives.

Said treatment formulation suitably includes less than 0.01 wt %, more preferably 0 wt % of polyethylene glycol p-(1,1,3,3,-tetramethylbutyl)-phenyl ether (e.g. TRITON X-100 (Trade Mark)). Said treatment formulation suitably includes less than 0.01 wt %, more preferably 0 wt % of a polymer which includes a (CH₂CH₂O—)_n repeat unit. Said treatment formulation suitably includes less than 0.01 wt %, more preferably 0 wt % of an anionic surfactant. Said treatment formulation suitably includes less than 0.01 wt %, more preferably 0 wt % of a cationic surfactant. Said treatment formulation suitably includes less than 0.01 wt %, more preferably 0 wt % of zwitterionic surfactant. Said treatment formulation suitably includes less than 0.01 wt %, more preferably 0 wt % of a non-ionic surfactant. Said treatment formulation suitably includes less than 0.01 wt %, more preferably 0 wt % of amine group-containing materials. Said treatment formulation suitably includes less than 0.01 wt %, more preferably 0 wt % of a quaternary-ammonium group-containing material. Said treatment formulation suitably includes less than 0.01 wt %, more preferably 0 wt % of a carboxylic acid (—COOH) group containing material.

Said active material is preferably wholly soluble in treatment formulation at the concentration used in the method and at 25° C. Said active material is preferably soluble to at least 1 wt % at 25° C. in de-ionized water.

Said active material may be such that, in water, it self assembles into pseudo micelles with hydrodynamic radii in the nanometre range as opposed to macroscopic micelle as may be formed with conventional surfactants.

Said active materials is preferably non-ionic.

Said active material is preferably such that a 1 wt % aqueous solution has no detectable cloud point. This contrasts with for example surfactants which often have a cloud point in the range 0° C. to 100° C.

Said active material may have a weight average molecular weight (Mw) of less than 200,000, suitably less than 150,000, preferably less than 100,000, more preferably less than 50,000. The Mw may be at least 5,000, preferably at least 10,000. The Mw may be in the range 5,000 to 25,000, more preferably in the range 10,000 to 25,000.

Weight average molecular weight may be measured by light scattering, small angle neutron scattering x-ray scattering or sedimentation velocity. The viscosity of the specified aqueous solution of the polymeric material may be assessed by Japanese Standards Association (JSA) JIS K6726 using a Type B viscometer. Alternatively, viscosity may be measured using other standard methods. For example, any laboratory rotational viscometer may be used such as an Anton Paar MCR300.

The viscosity of a 4 wt % aqueous solution of the active material at 20° C. may be at least 2.0 cP, preferably at least 2.5 cP. The viscosity may be less than 6 cP, preferably less than 5 cP, more preferably less than 4 cP. The viscosity is preferably in the range 2 to 4 cP.

Said active material may include a repeat unit which includes a hydrophilic functional group. Said hydrophilic functional group preferably includes an—O— moiety and, more preferably, includes an—OH moiety.

Said active material may include a repeat unit which includes a relatively hydrophobic functional group. Such a group may be of formula R¹CO—, wherein R¹ represents an optionally-substituted alkyl group, for example optionally-substituted C_1-10, preferably C_1-5, alkyl group. Said R¹CO— may be an acetate moiety.

Said active material preferably includes a hydrocarbon backbone, preferably a saturated, preferably aliphatic, hydrocarbon backbone.

Said active material is preferably a random copolymer (as opposed to a block copolymer).

Said active material may include more than two different repeat units. Preferably it includes no more than two different types of repeat units.

In said active material, the mole % of repeat units which include hydrophilic functional groups divided by the mole % of repeat units which include hydrophobic functional groups may be in the range 1.5 to 19, preferably in the range 2 to 15, more preferably in the range 4 to 12.

When said separation means comprises a first receptacle which includes upper and lower layers as described, said upper, oil, layer suitably includes less than 0.3 wt %, less than 0.2 wt %, less than 0.1 wt %, less than 0.05 wt % or less than 0.01 wt % of said active material. The ratio of the wt % of active material in the lower layer divided by the wt % of active material in the upper layer may be at least 5, preferably at least 7, more preferably at least 10.

In a first embodiment, said active material is not an optionally cross-linked hydrolysed polyvinyl alcohol and/or it preferably does not include vinylalcohol repeat units and/or it does not include a polymeric material which includes—O— moieties pendant from a polymeric backbone thereof, wherein said polymeric material is optionally cross-linked. However, in a second embodiment, said active material may comprise a polymeric material. Such a polymeric material suitably comprises at least 50 mole %, preferably at least 60 mole %, more preferably at least 70 mole %, especially at least 80 mole % of vinylalcohol repeat units. It may comprise less than 99 mole %, suitably less than 95 mole %, preferably less than 91 mole % of vinylalcohol repeat units. Said polymeric material suitably comprises 60 to 99 mole %, preferably 80 to 95 mole %, more preferably 85 to 95 mole %, especially 80 to 91 mole % of vinylalcohol repeat units.

Said polymeric material preferably includes vinylacetate repeat units. It may include at least 2 mole %, preferably at least 5 mole %, more preferably at least 7 mole %, especially at least 9 mole % of vinylacetate repeat units. It may comprise 30 mole % or less, or 20 mole % or less of vinylacetate repeat units. Said polymeric material preferably comprises 9 to 20 mole % of vinylacetate repeat units.

Said polymeric material is preferably not cross-linked.

Suitably, the sum of the mole % of vinylalcohol and vinylacetate repeat units in said polymeric material is at least 80 mole %, preferably at least 90 mole %, more preferably at least 95 mole %, especially at least 99 mole %.

Said polymeric material preferably comprises 70-95 mole %, more preferably 80 to 95 mole %, especially 85 to 91 mole % hydrolysed polyvinylalcohol.

Said mixture collected in step (i), suitably includes greater than 5 wt %, preferably greater than 10 wt %, more preferably greater than 20 wt %, especially greater than 30 wt % of oil. The material collected may comprise less than 1 wt %, or even less than 0.75 wt % of said active material. The mixture may comprise greater than 30 wt %, greater than 40 wt % or greater than 50 wt % of water.

The method of the first aspect may include a step (a) prior to step (i) which comprises treating oil to define the mixture selected in step (i) of the method. Step (a) may comprise contacting oil to be treated with said treatment formulation.

Said oil is preferably a crude oil which term in the context of the present specification includes tar (heavy crude oil), obtained from tar sands, and bitumen. The oil may have an API gravity of less than 30°, suitably less than 25°, preferably less than 20°. In some cases, the API gravity may be less than 15°.

Said treatment formulation could be initially contacted with oil at or near the surface, for example to facilitate transport of the oil in a pipeline. Preferably, said treatment formulation is initially contacted with oil when the oil is underground. Preferably, said treatment formulation is introduced into a subterranean formulation. It is suitably arranged to contact oil in or associated with said formation.

Said treatment formulation may be at a temperature of at least ambient temperature immediately prior to introduction into the formation. Preferably, the temperature is above ambient temperature immediately prior to said introduction. It may be at least 5° C., preferably at least 10° C. above ambient temperature.

Said treatment formulation suitably has a viscosity at 25° C. and 100 s⁻¹ of greater than 0.98 cP, suitably greater than 1 cP, preferably greater than 1.2 cP, especially greater than 1.5 cP. Said treatment formulation preferably has a viscosity under the conditions described of not greater than 10 cP, preferably of 5 cP or less, more preferably of 2 cP or less.

Water for use in the treatment formulation may be derived from any convenient source. It may be potable water, surface water, sea water, aquifer water, deionised production water and filtered water derived from any of the aforementioned sources. Said water is preferably a brine, for example sea water or is derived from a brine such as sea water. The references to the amounts of water herein suitably refer to water inclusive of its components, e.g. naturally occurring components such as found in sea water. Water may include up to 6 wt % dissolved salts but suitably includes less than 4 wt %, 2 wt % or 1 wt % or less of dissolved salts which are naturally occurring in the water.

In an embodiment (A), the treatment formulation may be delivered underground in step (a). This may comprise contacting oil in a formation with the treatment formulation at a position upstream of a production well. The treatment formulation may be introduced into a formation via an injection well. Said injection well may be selected from a vertical well, a deviated well or a horizontal well. In some examples, treatment formulation may be introduced into a plurality, suitably three or more, injection wells, suitably substantially concurrently. Preferably, in embodiment (A), initial contact of oil in said formation by said treatment formulation causes oil to move in a first direction, wherein suitably the oil contacted was not moving in said first direction prior to said initial contact. Preferably, initial contact of oil in said formation causes the speed of movement of the oil contacted to increase. For example, the oil may be trapped and therefore substantially stationary (except for molecular motion of the oil) prior to contact. After contact, oil may be caused to move and so its speed will be increased. Suitably after contact, oil travels substantially at the speed of the treatment formulation with which it is associated. In some cases, gravity may act on the oil to move it towards the production well in which case oil may move to the production well under both gravity and the force applied by said treatment formulation. In other embodiments, substantially the only force causing oil to move towards the production well may be supplied by said treatment formulation. Preferably, the treatment formulation is arranged (e.g. by virtue of the pressure applied to it to introduce it into the formation) to carry oil towards the production well.

The method of embodiment (A) may be used after some oil has been removed from the formation by an alternative method. The method may include one step which comprises contacting oil in said formation with said treatment formulation as described and another step which involves contacting the formation with a different formulation. Subsequent to contact with the different formulation, there may be a further step which comprises contacting oil in said formation with treatment formulation as described.

In an embodiment (B), step (a) may comprise improving performance or efficiency of a wellbore pump associated with a wellbore and/or increasing the rate of production of reservoir fluid from a reservoir, wherein a wellbore pump is arranged to pump wellbore fluid within the wellbore to a surface, said method comprising the steps of:

(I) selecting a wellbore which includes an associated wellbore pump; and
(II) contacting a reservoir fluid upstream of an inlet of the wellbore pump with said treatment formulation.

In step (II), said reservoir fluid is preferably initially contacted with said treatment formulation in said wellbore.

Prior to contact with said reservoir fluid in said embodiment (B), said treatment formulation is suitably above the surface of the ground in which said wellbore is defined. It may be contained within a receptacle. In step (II), said treatment formulation is preferably caused to move from a first position, spaced from the inlet of the wellbore pump, towards a second position defined by the inlet of the wellbore pump. Said treatment formulation is preferably arranged to move along a fluid flow path which extends within the wellbore (preferably within an annulus of the wellbore) on moving towards said second position. Preferably, said fluid flow path extends between a first region of the wellbore adjacent an upper end of the wellbore and a second region of the wellbore which is suitably below the first region, preferably at or adjacent said inlet of said pump. Preferably, substantially the entirety of said fluid flow path extends within the wellbore. Said fluid flow path may extend at least 10 m, preferably at least 30 m. Preferably, in step (II), a force is incident upon the treatment formulation to cause it to move between said first and second positions. Said force could be provided, at least in part, by a pump means. Preferably, a major amount of said force is provided by gravity. In a preferred embodiment, treatment formulation is introduced into said wellbore and allowed to fall under gravity thereby to move towards the wellbore pump. In this case, suitably, no pump means may be used to speed up flow of the treatment formulation within the wellbore.

In one example of embodiment (B), in step (II), said treatment formulation may be initially contacted with reservoir fluid in the annulus of the wellbore. The treatment fluid formulation may, after initial contact, be allowed to fall under gravity and move towards the inlet of the wellbore pump. Preferably, treatment formulation is initially contacted with reservoir fluid at a position which is at least 5 m above the height of the inlet of the wellbore pump. If the wellbore includes more than one pump, the referenced pump is suitably the lowermost one. Said wellbore pump may be of any type. Preferably, said wellbore pump is selected from a progressing cavity pump (PCP) (also known as an eccentric screw pump), a beam pump (also known as a rod pump, walking beam pump and a suction rod pump) and a centrifugal pump for example an electrical submersible pump (ESP).

In an embodiment (C), said treatment formulation may initially contact the oil at or downstream of a producing face of a subterranean formation. This may be suitable for treating oil which is arranged to flow along a fluid flow path. Said fluid flow path is preferably defined by a conduit means. Said conduit means preferably includes a first conduit part (e.g. a pipeline) which is arranged downstream of a production means, preferably above ground level. Said fluid flow path (e.g. said conduit means) may extend between a first point, remote from the point of production of the oil and a second point closer to, for example at or adjacent to, the point of production of the oil. Said first point may be above ground and may be, for example, a well-head or a refinery; said second point may be closer to the producing face of a subterranean formation. It may be at or adjacent to the producing face. Said fluid flow path may be defined, in part, by a second conduit part which extends upwardly from below ground to above ground. Said second conduit part may be a riser pipe. Said second conduit part may contain oil after contact with the treatment formulation. A delivery flow path is preferably defined which is arranged to communicate with said fluid flow path wherein said treatment formulation is dosed into said oil in said fluid flow path via said delivery flow path. Said delivery flow path preferably communicates with said fluid flow path at or downstream of a producing face of the subterranean formation. The ratio of the flow rate (in weight per unit time) of treatment formulation in said delivery flow path to the flow rate (in the same units) of oil in said fluid flow path may be in the range 0.1 to 2.5, preferably in the range 0.2 to 1, more preferably in the range 0.4 to 0.8, especially in the range 0.6 to 0.7.

In an embodiment (D), step (a) may comprise a method of increasing production of hydrocarbons from a reservoir penetrated by a wellbore which includes an associated artificial lift means, the method comprising:

• • (X) inserting a conduit having an outlet into the wellbore;
  • (Y) introducing treatment formulation into the wellbore via the outlet of the conduit as the conduit is moved into the wellbore, said treatment formulation being arranged to mobilise hydrocarbons.

The conduit may be inserted into the wellbore via an associated production well. Treatment formulation may be introduced into the wellbore via the outlet of the conduit as the conduit is moved into the wellbore away from the production well. As the conduit is moved into the wellbore, the treatment formulation introduced is able to mobilise hydrocarbons, for example heavy oil, which may otherwise be substantially immovable under the conditions in the wellbore in the absence of said formulation.

The outlet of the conduit may be moved through a distance of at least 25 m, 50 m, 100 m, 200 m, 300 m, or at least 400 m during its insertion into the wellbore. Thus, the length of the conduit from the surface may have the aforementioned values. Preferably, said treatment formulation is injected from said conduit continuously as it is moved through a distance of at least 25 m, 50 m, 100 m, 200 m, 300 m, or at least 400 m along the laterally extending wellbore. Preferably, in the method, treatment formulation is flowing from the outlet of the conduit as the outlet passes the artificial lift means and passes into a laterally extending wellbore. Preferably, treatment formulation is flowing from the outlet of the conduit when the outlet is positioned at a distance of at least 10 m or at least 20 m from the artificial lift means, when measured upwardly from the artificial lift means. Preferably, treatment formulation is flowing from the outlet of the conduit when the outlet is positioned a distance of 10 m or 5 m from the top of the production well. Preferably, treatment formulation is flowing from the outlet of the conduit substantially during the entire passage of the conduit down the production well. After insertion, the outlet of the conduit and/or the entire conduit is preferably stationary. When in the aforesaid stationary position, treatment formulation is suitably introduced into the wellbore. Preferably, whilst the artificial lift means is being operated to remove hydrocarbons from the wellbore, the treatment formulation is introduced into the wellbore via the outlet of the conduit. Preferably, treatment formulation is continuously introduced into the wellbore whilst the artificial lift means is operating.

After reaching the stationary position, treatment formulation may be introduced into the wellbore over a period of at least 10 days, at least 50 days, at least 100 days, at least 1 year or at least 5 years.

According to a second aspect of the invention, there is provided a first receptacle containing fluid produced after treatment in said method of the first aspect, said receptacle including a lower layer comprising water and an active material as described and an upper layer comprising oil. Said first receptacle may have any feature of the first receptacle described herein mutatis mutandis.

According to a third aspect there is provided apparatus comprising:

a first receptacle containing fluid produced after treatment in the method of the first aspect;
a second receptacle downstream of the first receptacle and operatively connected to the first receptacle for transfer of fluid from an upper part (e.g. upper layer of fluid) in said first receptacle to said second receptacle;
a treatment formulation receptacle operatively connected to the first receptacle for transfer of fluid from a lower part (e.g. lower layer of fluid) in said first receptacle to the treatment formulation receptacle;
wherein said second receptacle includes a higher concentration of oil than in said treatment formulation receptacle or said first receptacle; and
said first receptacle contains more water than said second receptacle.

Said apparatus may include any feature of apparatus, formulations, methods and uses as described herein mutatis mutandis.

Any feature of any aspect of any invention or embodiment described herein may be combined with any feature of any aspect of any other invention or embodiment described herein mutatis mutandis.

Specific embodiments of the invention will now be described by way of example, with reference to the accompanying drawings, in which:

FIG. 1 is a schematic representation showing treatment of a subterranean formation with a treatment fluid and subsequent separation of recovered oil from used treatment fluid; and

FIG. 2 is a plot of viscosity v. temperature for an oil before and after treatment with and subsequent separation from a treatment fluid.

Referring to FIG. 2, a treatment fluid tank 2 is arranged to pump treatment fluid (which contains an additive) down an annulus of a wellbore as described in WO2008152357 to improve the performance or efficiency of a wellbore pump associated with the wellbore and/or for increasing the rate of production of reservoir fluid from the reservoir. A downhole pump at position 4 pumps fluid, which may comprise liquid hydrocarbon (oil), reservoir water, sand and/or gas back to the surface and into a production tank 6 at the surface. By selection of a suitable treatment fluid including additive, as described hereinafter, the oil can be caused to separate from water, brine and/or sand in the production tank 6, without addition of any chemical demulsifiers in the production tank 6. Separation may be achieved simply by incubating the mixture in production tank 6 at 50-90° C. for a few days. During incubation, a fluid 8 comprising sand and water containing the additive falls to the bottom of the tank and oil rich phase 10 moves to the top of the tank. The oil rich phase may include 1 to 25 wt % of water. However, it includes substantially none of the additive which was included in the treatment fluid. The oil rich phase 10 comprising wet oil may periodically (e.g. every few days) be delivered to a sales tank 12 where it is further incubated at 50° C. to 90° C., which causes further separation of dryer oil 14 from residual water, brine and/or sand 16. Again, no chemical demulsifier is needed to cause the separation in tank 12.

The fluid 8 in tank 6 (which includes substantially all of the additive from the fluid delivered into the tank 6) is recycled back to tank 2 (which is possible because fluid 8 includes only a very low level of oil and a high level of the additive), as represented by arrow 11. The concentration of additive in tank 2 may be adjusted by addition of further additive so that fluid in tank 2 is of the desired concentration (typically comprising 0.5 wt % of additive). If the water in tank 8 is not suitable for recycle as aforesaid, it may be disposed of as represented by arrow 18. Sand in fluid 8 can be withdrawn and disposed of as represented by arrow 20.

After incubation in tank 12, the dryer oil 14 may be delivered to a battery 22 where it is further treated to separate it from remaining water suitably so the water in oil at 24 has less than 0.5 wt % of water. Demulsifiers may be used at this stage. Dry oil 24 may be delivered to a refinery as represented by arrow 26. Any water 28 removed at the battery may be disposed of as represented by arrow 30.

It has been found that the separation of the oil from the treatment fluid, without using chemical demulsifiers, depends on the interfacial tension (IFT) between oil and water phases. Thus, additives for use in oil treatments may be selected according to their IFTs. Example 1 describes how IFT may be measured.

EXAMPLE 1

General Method of Determination of Interfacial Tension by Kruss Pendant Drop Method

The method is generally in accordance with Shi-Yow Lin, Li-Jen Chen, Jia-Wen Xyu and Wei-Jiunn Wangi, Langmuir 1996, 11, 4159-4166 4159. It was undertaken at 25° C. However, since oils are too viscous to pass through the needle, the oil was diluted with toluene prior to being tested at an oil:toluene ratio of 75:25.

A Kruss DSA1000 Surface Tensiometer was used to measure IFT between two liquids at ambient temperature with a J-Needle. In the method, a fluid drop, of a certain shape, is created hanging from an upturned needle while suspended in an optical cell containing another fluid and mathematical equations are used to calculate the Interfacial Tension between those two fluids. The procedure used was as follows:

(i) The angle of inclination of the prism (Tilt) was turned to 0°.
(ii) A Hamilton glass syringe was filed with no more than 0.4 ml of the fluid to be tested and it was ensured there was no air entrapped in the syringe.
(iii) The J-Needle was screwed onto the end of the syringe and the syringe was pushed into the syringe holder on the syringe unit ensuring there was a gap between the glass flange of the syringe and the uppermost clip of the syringe holder and that the end of the plunger fits into the syringe unit.
iv) The zoom function on the unit was adjusted so that the needle occupies approximately 10% of the screen.
v) The Optical Glass Cell was slid under the needle and the cell was completely filled with the fluid to be tested. The sample table was raised until the needle was just touching the bottom of the cell.
vi) The image was focused.
vii) With the dosing mode set as ‘Continuous’ a dosing rate of 20 microlitres/minute was input. The syringe unit then started to push test fluid down through the needle and a drop started to form and could be seen on the screen. The ideal shape for a drop image is the image of a drop just about to drop off the needle. However with viscous fluids it is very difficult to determine the ideal shape as the drop tends to form a spherical shape due to the weight acting down of the embedded phase. Initial investigations into this method have shown that very large drops are required to get consistent accurate results. For optimum results the drop image needs to fill as much of the window as possible hence the zoom may have to be adjusted.
viii) The drop was developed at the low dosing rate to an appropriate size and then the image was captured.
ix) The software was then used to calculate the Interfacial Tension between the two fluids.

EXAMPLE 2

General Procedure for Assessing Ease of Separation of Oils and Treatment Fluid Containing Selected Additives and Residual Water in the Oil

Formulations to be tested were mixed with selected oils, using an oil:formulation ratio of 70:30 to produce a dispersion. The dispersion was then incubated in a glass vessel at 80° C. for 16 hours. After this time, the contents were analysed using a conventional BS&W technique (ASTM Standards D4007-08) to assess if separation had taken place. A “Y” in Table 1 indicates separation has taken place, whereas a “N” indicates that separation did not taken place.

The reference to “residual water” is the level of water in the oil as assessed by BS&W measurements.

EXAMPLES 3-13

Testing Formulations

Using the procedures described in Examples 1 and 2, test formulations were assessed (the concentration of additives being 0.5 wt %) and the results are provided in Table 1. Oils 1 and 2 had viscosities at 25° C. of 37,500 cP and 71,000 cP respectively. The uncertainty in the IFT measurements was 0.1 mN/m.

	TABLE 1
	Oil 1	Oil 2
Example		IFT	Residual Water		IFT	Residual
No.	Test Formulation	mN/m	(%)	Separation	mN/m	Water (%)	Separation
3	Polyvinyl Alcohol 100% Hydrolysed	20.88	10	N	18.75	12	N
4	Polyacrylic Acid	19	25	N	19.9	17	N
5	Sodium Carbonate	21	15	N	19	21	N
6	PVOH 20,000 mol wt, 89% hydrolysed	9.32	1	Y	9.15	2	Y
7	PVOH 180,000 mol wt, 89% hydrolysed	9.66	1.5	Y	9.8	0.8	Y
8	Hydrophobicaly Modified Polyvinyl alcohol	11.99	3	Y	13.42	1.6	Y
9	Starch	12	2	Y	11	1.7	Y
10	Triton X 100 Surfactant	0.4	28	N	1.2	27	N
11	Trition X 100 Surfactant + PVOH 20,000 mol wt, 90%	3	20	N	2.8	15	N
	hydrolysed
12	Quaternary Amine Surfactant	0.1	25	N	0.3	24	N
13	Vinyl Amine Derivatized PVOH	2.26	20	N	5.56	26	N

Table 1 shows how interfacial tension affects whether separation occurs or not. A particularly interesting result is that for examples 6 and 11. Whilst the Example 6 formulation which includes the 20,000 molecular weight, 89% hydrolysed polyvinyl alcohol separates from the oil, when surfactant is added as in Example 11, the IFT of the test formulation is increased significantly and separation does not take place. Thus, presence of surfactant hinders separation of oil and water mixtures.

EXAMPLE 14

Comparison of Oil Before and after Treatment

The viscosity of a selected oil was measured at a shear rate of 10 s⁻¹ over a temperature range of 10° C. to 160° C. using an Anton Paar MCR 301 rheometer equipped with a cone and plate sensor. The selected oil had a viscosity at 20° C. of 160,000 cP. A 70:30 oil:formulation dispersion was made and the mixture separated as described in Example 2. A small aliquot of the separated oil phase was collected and viscosity re-measured as before. Results are provided in FIG. 2 from which it will be noted the viscosity profiles are almost identical, indicating that the oil has not been changed by the treatment.

The invention is not restricted to the details of the foregoing embodiment(s). The invention extends to any novel one, or any novel combination, of the features disclosed in this specification (including any accompanying claims, abstract and drawings), or to any novel one, or any novel combination, of the steps of any method or process so disclosed.

Claims

1. A method of separating a mixture of oil and water into oil-rich and water-rich phases, the method comprising the steps of:

(i) selecting a mixture which comprises oil recovered from a subterranean formation and a treatment formulation, wherein the treatment formulation was added to the oil in order to facilitate its recovery and/or mobility, wherein the treatment formulation has an Interfacial Tension (IFT), measured against a sample of the oil in the range 2 to 20 mN/m;

(ii) directing the mixture to a separation means; and

(iii) in the absence of a chemical demulsifier, heating the mixture until separation is effected at least partially under gravity.

2. A method according to claim 1, wherein the treatment formulation is able to increase the mobility of the oil and has at least one of the following characteristics, measured at 25° C., when the treatment formulation is contacted with a sample of the oil, wherein the ratio of oil:treatment formulation is 70:30:

(a) a dispersion of the oil and the treatment formulation has a viscosity, at a shear rate of 1 s−1, of less than 5000 cP;

(b) a dispersion of the oil and the treatment formulation is pseudoplastic over the shear rate range 1 s−1 to 100 s−1; and/or

(c) a dispersion of the oil and the treatment formulation has a viscosity, at a shear rate of 100 s−1, of no more than 700 cP.

3. A method according to claim 1, wherein the separation means comprises a first receptacle into which the mixture is delivered, wherein the method includes the step of heating the mixture in the first receptacle into which the mixture is delivered to a temperature of at least 40° C. for at least 1 hour.

4. A method according to claim 3, wherein during the heating, the mixture separates under gravity so that two layers of materials are defined, one being a lower layer comprising water and water-soluble materials and the other being an upper layer comprising oil, wherein the upper layer includes less than 20 wt % of water and the lower layer includes at least 70 wt % of water.

5. A method according to claim 3, wherein the first receptacle includes vent means for removing gas from the first receptacle and the first receptacle includes a first outlet for removing fluid from an upper part of the first receptacle, the method including the step of removing fluid from an upper layer of fluid in the first receptacle.

6. A method according to claim 5, wherein the method includes the step of removing fluid from the lower layer in the first receptacle, wherein the fluid removed from the lower layer is re-cycled.

7. A method according to claim 6, wherein the first receptacle includes an outlet for removal of solids.

8. A method according to claim 7, wherein the first receptacle includes a first outlet which is connected to a second receptacle and the method includes withdrawing fluid from an upper part of the first receptacle and delivering the fluid from the upper part into the second receptacle and water in the fluid is separated from oil in the fluid in the second receptacle.

9. A method according to claim 8, wherein no chemical demulsifier is added to the second receptacle and separation in the second receptacle includes the step of heating the fluid in the second receptacle to a temperature of at least 40° C.

10. A method according to claim 8, wherein the second receptacle is arranged for delivery of fluid from an upper part thereof into further separation means comprising a battery.

11. A method according to claim 1, wherein the treatment formulation has a surface tension, in the absence of oil, at 25° C., in the range 40 to 65 mN/m.

12. A method according to claim 1, wherein the IFT is in the range 8 to 14 mN/m.

13. A method according to claim 1, wherein the treatment formulation comprises water and an active material wherein the active material affects the IFT of the treatment formulation in relation to the oil and/or modifies the water so the treatment formulation has the IFT, wherein the treatment formulation includes at least 95 wt % water.

14. A method according to claim 13, wherein the active material is non-ionic and/or the active material is such that a 1 wt % aqueous solution has no detectable cloud point and/or the active material has a weight average molecular weight (Mw) of less than 200,000.

15. A method according to claim 13, wherein the active material is not an optionally cross-linked hydrolysed polyvinyl alcohol.

16. A method according to claim 13, wherein the active material comprises a polymeric material which comprises at least 50 mole % of vinylalcohol repeat units.

17. A method according to claim 16, wherein the polymeric material includes vinylacetate repeat units.

18. A method according to claim 1, which includes a step (a) prior to step (i) which comprises treating the oil to define the mixture selected in step (i) of the method and step (a) comprises contacting the oil to be treated with the treatment formulation.

19. A method according to claim 18, wherein the treatment formulation has a viscosity at 25° C. and 100 s−1 of greater than 0.98 cP.

20. (canceled)

21. Apparatus comprising:

a first receptacle containing fluid produced after treatment in the method of claim 1;

a second receptacle downstream of the first receptacle and operatively connected to the first receptacle for transfer of fluid from an upper part in the first receptacle to the second receptacle;

a treatment formulation receptacle operatively connected to the first receptacle for transfer of fluid from a lower part in the first receptacle to the treatment formulation receptacle;

wherein the second receptacle includes a higher concentration of oil than in the treatment formulation receptacle or the first receptacle; and

the first receptacle contains more water than the second receptacle.