GB2598969A

GB2598969A - Sealing method

Info

Publication number: GB2598969A
Application number: GB2014978.7A
Authority: GB
Inventors: Joseph Collins Patrick; Scullion Callum; Vanessa Goodwin Barbara
Original assignee: Aubin Ltd
Current assignee: Aubin Ltd
Priority date: 2020-09-22
Filing date: 2020-09-22
Publication date: 2022-03-23
Also published as: GB202014978D0

Abstract

A method of forming a seal in an annular space in a well positioned radially inward of at least one casing. The annular space may be a B-annulus 11. The method comprises deploying a flowable chemical mixture having a first viscosity and comprising a polymer component into the annulus. The viscosity of the chemical mixture is increased to a second viscosity, optionally, at least in part, by increased heat in the well. The chemical mixture having the second viscosity has a maximum Shore OO hardness of 90. The method may further comprise delivering a liquid component into the annular space to increase the hydrostatic head on the chemical mixture. The liquid component normally has a lower density than the chemical mixture.

Description

Sealing method This invention relates to a method of forming a seal in an annular space in a well, especially to at least mitigate sustained casing pressure.

Figure 1 is a schematic of an oil well. Oil flows from a subterranean reservoir 1 through an opening 2 in a steel pipe or casing 3, into a cavity 4 and passes into production tubing 5 set within the casing 3 where it is recovered to the surface exiting via a well head 7 as is conventional. Fluids or gases produced may be at temperatures of between 60 C and 200 C and pressures of more than 5,000 psi and occasionally exceeding 20,000 psi.

During the construction of hydrocarbon producing wells it is necessary to strengthen the well to prevent its collapse by successively installing casing strings 3, 8, 9 shown in Fig. 1 in successively smaller diameters.

In the process of construction a series of annular spaces are created 10,11,12. These spaces are sealed from contact with the produced hydrocarbons through the installation of barriers such as mechanical barriers e.g. a packer 13, or more commonly in the outer shallower annular spaces the cement sheath 14 that is used to secure the casing in place also acts as the barrier. To aid identification these annular spaces are designated A,B,C etc with the deepest annulus being the A annulus the next the B annulus etc. Annuli are commonly filled, or part-filled with fluid.

In normal operation the annular spaces do not suffer pressure build-up except during the start-up of production when expansion due to heat can result in pressure building in the annulus. This is relieved though a valve on the well head.

During production of the well over time the cement sheath 14 may be subjected to periods of stress causing cracks to form in the cement. Joins in the casing string may also be incomplete. This results in the development of a path from the reservoir or other pressured zone through to the annulus. This occurrence is most common but is not restricted to the B annulus 11. When this happens pressure in the annulus is created that must be relieved at the wellhead via a pressure relief valve 15, once relieved however the pressure will build up and may need to be bled off. This pressure then starts to build up again with more inflow of fluids or gases into the well. Each time the annulus is bled off the pressure builds up again. However this build up becomes successively quicker as the annulus fills with more liquid and often less dense fluid resulting in the volume of compressible gas reducing meaning that pressure builds more rapidly with each successive bleed off. This situation where pressure is built up over a sustained period is described as sustained casing pressure.

A direct consequence of this sustained annulus pressure build up is that the pressure is contained by only one barrier, namely the well head. In general, it is accepted engineering practice forming part of regulatory guidelines to rely on a minimum of two barriers to control pressure release. Currently there are ways in which operators deal with this issue.

Some operators have a policy whereby they will only operate a well if there are two barriers and may choose to discontinue production from the well with attendant economic consequences.

Alternatively provided the pressure is not excessive and is stable the operator of the well may choose not to bleed off the annulus since to do so will make the situation worse. As a consequence, a decision is made not to bleed off pressure and so the annulus remains under pressure despite there being only one barrier present. Such a decision to operate where only one barrier is employed is a serious one requiring careful engineering consideration and prior approval from regulatory authorities.

It is in this context that the present disclosure has been conceived.

In accordance with an aspect of the present disclosure, there is provided a method of forming a seal in an annular space in a well defined radially inward of at least one casing of the well, the method comprising: - deploying a chemical mixture comprising a polymer component into a well annulus, the chemical mixture being in a flowable state and having a first viscosity, - causing the viscosity of the chemical mixture to increase to a second viscosity; wherein the chemical mixture with the second viscosity is an extrudable compliant material.

Thus, the increased viscosity of the chemical mixture can mitigate a flowpath or leak in the annulus. It usually has a maximum Shore 00 hardness of 90. In contrast, cement is on a different, higher, scale of hardness, usually with values of above 70 on the much higher Shore D scale. It is not compliant and so can result in such flow paths opening up. Optionally the Shore 00 hardness of the chemical mixture with the second viscosity may be less than 80 on the Shore 00 hardness scale. It may be more than 5 on the Shore 00 hardness scale.

Thus the method is usually a method for mitigating sustained casing pressure. The seal may be a partial seal although is preferably an entire seal.

The chemical mixture may form a compliant solid which is usually a relatively soft, extrudable rubber-like solid (usually with a maximum Shore 00 hardness of 90) that can move into or extrude into cracks in cement, casing joins and/or other leak paths.

To determine the Shore hardness of a material, the method outlined in ASTM D2240 may be followed.

The chemical mixture may be directed to the base of the annular space although for certain embodiments it may be spaced away from the base of the annular space.

Following the increase in viscosity to the second viscosity, a ringing gel may be formed. It will be understood that a ringing gel is typically one which holds its shape under modest movement. Viewed another way, it will be understood that a ringing gel may be defined as a gel having a composition within an isotropic, one-phase region of its ternary phase diagram.

The method may further comprise delivering a further liquid component into the annular space, above the chemical mixture. Thus, the mass of the further liquid component can be used to create more hydrostatic head (hereinafter "head fluid"), optionally in combination with the mass of the chemical mixture and optionally other fluids, to mitigate or counterbalance a pressure in a reservoir, that would otherwise leak into the annular space.

In particular, the mass of the head fluid can also assist, by compression, in causing the mixture with the second viscosity/compliant solid to extrude into at least one of any leak paths in the annulus.

The head fluid may have a density less than a density of the chemical mixture the volume of further liquid such that it forms above the chemical mixture.

The head fluid may be a brine Optionally, the head fluid may be delivered into the annular space after the chemical mixture has set. Thus, the penetration of the head fluid through the chemical mixture will be impeded by the increased viscosity of the chemical mixture following initiation of the reaction of the second chemical component with the first polymer component.

For certain embodiments however, surprisingly, the head fluid and the chemical mixture comprising the polymer component can be deployed into the well together and then separate in the annulus. In this way, the liquid component, which is often a brine with a low viscosity, can assist in maintaining the chemical mixture which is increasing in viscosity, in a flowable state through potentially narrow diameter tubes or passages. The chemical mixture and further liquid then settle into different layers in the annulus. The chemical mixture and head fluid may be added to the well in a volume ratio determined by the depth of plug, required hydrostatic head to pressure balance the chemical mixture and density of further liquid. As such, the ratio depends on various factors, but may be 1:5 to 5:1, preferably 1:2 to 1:1-. When added together, optionally more of the head fluid can be added after the combination of the head fluid and the chemical mixture.

The chemical mixture may have a density greater than water. The chemical mixture may have a density greater than 1000 kilograms per cubic metre, or more than 1300 kilograms per cubic metre.

Especially when added together, the head fluid preferably has density of less than the chemical mixture. For example, less than 1300 kilograms per cubic metre.

Any pre-existing annulus fluids may have a density of 800-1200 kilograms per cubic metre, albeit this depends on their nature. Sometimes they will be a mixture of different components that have separated, such as an oil and a brine. Usually they are less dense than the chemical mixture, and less dense than the head fluid. Thus they will therefore be displaced by the chemical mixture and the head fluid. They may remain at the top of the annulus. In certain circumstances they may provide the required hydrostatic head. In certain circumstances, they may be removed, in part at least, from the annulus.

In certain situations, particularly where the base of the annulus is difficult to access, a displacement fluid, such as a brine, with a density greater than any pre-existing annulus fluid contents is pumped first, displacing any annulus contents. The chemical mixture is then pumped with a density less than the displacement fluid such that the chemical mixture is above the displacement fluid but below the annulus contents. Concurrently in part at least, or after pumping the chemical mixture, the head fluid usually with a density less than the density of the chemical mixture is pumped such that it forms a column on top of the chemical mixture creating a downward force on the chemical mixture. The downward force is usually greater than or equal to the pressure from the reservoir and this can be achieved by increasing the amount of the head fluid above the chemical mixture until a sufficient downward force is achieved.

The head fluid does not usually have gel strength. The viscosity of the head fluid may be less than 1000 centipoise optionally less than 100 cenfipoise.

The polymer component may be substantially insoluble and/or immiscible in water. Thus, the polymer component can move through any water in the annular space substantially without dissolving.

The head fluid may be delivered to sit above the chemical mixture when a viscosity of the chemical mixture has changed from the first viscosity to a third viscosity between the first viscosity and the second viscosity. In other words, at a time when the head fluid is delivered to the annular space, the viscosity of the chemical mixture may be between the first viscosity and the second viscosity.

At least one of the chemical mixture, head fluid and displacement fluid, may be delivered into the annular space by insertion through an opening defined at an upper end of the annular space. The opening may be part of a pressure release valve for allowing excess pressure in the annular space to escape the annular space. Thus, no new openings need be provided in the annular space for such embodiments.

The method may further comprise inserting a tube through the opening defined at the upper end of the annular space, the tube being inserted towards the annular space. The chemical mixture may be delivered through the tube. The head fluid may be delivered through the tube and optionally likewise the displacement fluid. In another example, the chemical mixture may be delivered directly into the annular space through the opening, without a tube extending into the annular space. The head fluid may be delivered directly into the annular space through the opening, without a tube extending into the annular space. And optionally likewise the displacement fluid.

Typically, the seal is formed in an annular space in a well. The annular space is defined radially inward of at last one casing string of the well.

This may especially be a B-or outer annulus, such as C-or D-. This is particularly applicable to the B-annulus. For example, an annulus between the 9 5/8" casing string and the 13 and 3/8" casing string.

The top of annulus where the fluid is applied may be, for example, from 500-2000m below the surface of the well. Or between 900-1400m.

The well is typically a well allowing access to a reservoir of hydrocarbons, for example oil and/or gas. It is usually a hydrocarbon production well.

The chemical mixture comprising a polymer is usually activated to increase the viscosity.

This may be, at least in part, caused by increased temperature as the chemical mixture is deployed downhole. Before being activated, the chemical mixture has a first viscosity at ambient temperature and pressure (20 °C, 1 atm) The first viscosity is usually less than 1000 centipoise (1,000 millipascal seconds), typically less than 500 centipoise (500 millipascal seconds) or less than 100 centipoise (100 millipascal seconds).

The second viscosity may be greater than 5,000 centipoise (5,000 millipascal seconds), optionally greater than 10,000 centipoise (10,000 millipascal seconds). The second viscosity may be greater than 100,000 centipoise (100,000 millipascal seconds) and so essentially solid.

The second viscosity is usually determined when the chemical mixture has stopped increasing in viscosity, usually when set. Whilst this may occur quicker, this may be assessed at 48 hours after being pumped down/added to the annulus. Or, whilst still optionally occurring quicker, this may be determined 1 week after being introduced into the annulus.

The second viscosity is determined at temperatures in the annular space of the well, which vary from well to well and indeed within a well. For example, this may be at seabed temperatures in cold, subsea wells (i.e. 3-5 °C or above) at seabed depths or higher at further depths. For further depths, a typical B annulus at 1000 m may have a temperature of 50C or above.

The change in viscosity between the first and second viscosities is usually more than 1,000 centipoise (1,000 millipascal seconds), typically more than 10,000 centipoise (10,000 millipascal seconds).

Viscosity may be assessed using the method described in API RP 13B-1 and API RP 39.

Optionally, a second chemical component is added to the chemical mixture for activation and to cause the chemical mixture to have the second viscosity greater than the first viscosity on reaction of the second chemical component with the first polymer component.

The method further comprises reacting the second chemical component with the first polymer component to cause the chemical mixture to have the second viscosity.

The chemical mixture may be activated less than 24 hours before the chemical mixture is added to the annulus, or less than 12 hours or less than 6 hours.

The chemical mixture may be delivered to sit on a layer of cement at the annular space that is at the base of the annulus.

The method may be for forming a seal, at least in part, in an existing well. The method may be for forming a seal after well completion. The method may be a remedial method. Thus, the method may be additional, beyond the method originally undertaken to install the well.

A variety of chemicals can be used to make a mixture with an increased viscosity, and the preferred compliant solid.

For example, a buffered solution may be used and the rate of gel formation controlled by the amount of different components in the buffer that is used as well as typically the concentration of gellant and typically the temperature of the system.

The chemical mixture normally has a carrier fluid such as water and/or oil.

The polymer component may be a hydropropyl based polymer, a silicone-based polymer or other type of polymer.

The hydropropyl based polymer may have an average molecular weight of above 1,000,000 Da and optionally below 4,000,000 Da. Molar substitution (i.e. how much hydroxypropyl substitution) is usually below 3, optionally below 1.

Optionally, the silicone-based polymer may be a silicone oil.

The second chemical component may be an acid and/or a cross-linking agent. Thus, the viscosity of the chemical mixture of the first polymer component and the second chemical component can be increased by use of the cross-linking agent.

The cross-linking agent may comprise a silyl hydride. The cross-linking agent may comprise at least one of an oligomer and a polymer, each containing repeat silyl hydride groups.

The cross-linking agent may have the following formula: R4 where R1, R2, R3, R5, R6, R7 may each independently be optionally substituted methyl or phenyl groups. R4 may also be optionally substituted methyl. Alternatively, R4 may be an optionally substituted phenyl. The crosslinking agent may have a second repeating silyl hydride monomer producing a copolymer with an R8 group may be optionally substituted methyl or optionally substituted phenyl.

The H atom attached to the Si atom may be replaced independently by an optionally substituted methyl or optionally substituted phenyl.

The value n is from 1, typically at least 3 and may be less than 500. Typically, where the cross-linking agent comprises a homopolymer, n may be from 10 to 170. Where the cross-linking agent comprises a copolymer, n may be from 3 to 50.

The cross-linking agent may comprise a trimethylsiloxyl-terminated hydride material.

The well may be a subsea well.

The chemical mixture is typically not cement.

Embodiments of the invention are further described hereinafter, by way of example only, with reference to the accompanying drawings, in which: Fig. 1 shows an example of a well for use with an aspect of the present invention; and, Fig. 2 shows an example of a well having a seal applied thereto in accordance with an aspect of the present invention.

A polymer fluid is made up at the surface as necessary and introduced into the B-annulus 11. The mixture 16 undergoes a slow reaction to gradually increase its viscosity. At first, it is of a viscosity such as 10-12 centipoise allowing it to flow into the annulus and settle at the cement base of the annulus. Over time, such as 1 hour, it gradually sets, forming a compliant gasket-like material.

A separate fluid may be added together with the mixture 16, or afterwards, but in any case settles on top of the compliant material due to its reduced relative density. In this example, a brine 17 is used which creates a hydrostatic head greater than the pressure created by any leak path through the cement base.

This excess hydrostatic pressure also pushes down on the compliant material to force it into any leak path. It therefore at least partially seals the leaks and inhibits or stops uncontrolled pressure build-up in the annulus.

Optionally, a displacement fluid 18 may be added before the above fluids. This is of a relatively high density, and displaces any pre-existing well fluids, and therefore sinks to the bottom of the annulus. The polymer mixture 16 and hydrostatic head fluid 17 may then be added as described above, as shown in Figure 2, and these sit on top of the displacement fluid 18 as they are of a lower density. An advantage of such embodiments is that if it is difficult to deploy the polymer fluid into the bottom of the annulus, then the displacement fluid can allow it to be placed further up. It may also or alternatively assist in positioning the compliant material further up the well to mitigate leaks from elsewhere, such as casing joints.

The displacement fluid may on certain occasions mitigate the leaks. However, it may itself slowly dissipate into the formation, and then in due course the compliant material comes into contact with the cement and remedies or mitigates the leaks as described.

A variety of chemicals and chemical mixtures may be used to form the compliant material. Examples are set out below.

>50 deg example for deeper annuli

Material (w/w%) Description

Polydimethylsiloxane, 50 47.09 Component 1 cSt (Carrier) cSt vinyl terminated 12.38 polydimethylsiloxane (Polymer) 1 % Karstedt in 1000 vinyl 0.02 (Catalyst) Hydrophobic fumed silica 0.3 (suspending aid) Silica Flour (weighting 40.21 additive)

Material (w/w%) Description

1 3- 100 Component 2 divinyltetramethyldisiloxane (modifier)

Material (w/w%) Description

methylhydrosiloxane- 100 Component 3 dimethylsiloxane copolymer, cSt (crosslinker) Component Mix 1 (w/w%) Cure time 85 °C Component 1 96.8 <90 minutes Component 2 0.2 Component 3 3 Lower temperature example for shallow (seabed) annuli:

Material (w/w%) Description

Polydimethylsiloxane, 50 51.25 Component 4 cSt (Carrier) cSt vinyl terminated 8.25 polydimethylsiloxane (Polymer) 1 I% Karstedt in 1000 vinyl 0.02 (Catalyst) Hydrophobic fumed silica 0.31 (suspending aid) Silica Flour (weighting 40.17 additive) Component Mix 1 (whar%) Cure time 0 °C Component 4 96.98 < 12 hours Component 2 0.02 Component 3 3.00

Tables la -lf

In one embodiment shown in the above tables, a polydimethylsiloxane such as DMS T15 from Gelest is blended with between five to fifteen percent of a vinyl terminated polydimethylsiloxane of 100cst viscosity. To this mixture a quantity of 1,3 divinyl tetra methyl disiloxane described as the modifier, is added to control the rate of subsequent reaction the quantity being determined by the speed of the reaction increasing the modifier slows the crosslinking reaction.

At the same time a quantity of Karstedt catalyst an organoplatinum compound derived from divinyl-containing disiloxane is added to the mixture the quantity of this reactant is typically in the order of 0.02 percent by weight. The mixture is then mixed for an additional ten minutes. A quantity of a hydrophobic silicon oxide/amorphous fumed silica such as Rheosil is added and silica flour are added to increase the density of the fluid.

Just prior to application, a quantity between five to one percent of trimethylsiloxy terminated hydride material or, alternatively methylhydrosiloxane-dimethylsiloxane copolymer, is added as a crosslinking agent and the fluid is introduced into the annulus of the well either injected at the surface whereupon it sinks through the annulus contents to the bottom of the annulus or alternatively the fluid is injected through a conduit such that it is placed directly at the bottom of the well.

When this mixture reaches the annulus after enough time a reaction occurs wherein the crosslinker undergoes an addition curing reaction with the vinyl functional polymer forming an ethylene bridge crosslinking reaction. This reaction causes the fluid to transform into a rubbery compliant solid material with no loss of volume at the annulus forming over any leak path at the annulus.

In an alternative embodiment, material that uses water or brine as a base fluid can be used, as detailed in table 2 hereinafter. Water is buffered to between pH 8 and pH 12 by adding a mixture of citric acid and sodium carbonate. To this mixture the following are added as powders in the following concentrations sodium carbonate at between 0.1 to 0.5 percent by weight of the total mass, hydroxyethyl cellulose such as HEC 5000 in a concentration of between 0.2 and 0.6 percent by weight of the total mass and between 3.0 and 5.0 percent of a hydroxypropyl guar such as Polyflos 61 from Lamberti Spa. An example formulation is detailed in table 2 hereinafter, with values shown as weight ratios.

Component Weight ratio in SCP system Supplied as 55% potassium formate solution (density = 1.36-1.37 g/cc) 95 "Component 1" Base fluid Citric Acid 0.15 to 0.20 "Component 2" Added to Base fluid (Powder) Sodium carbonate 0.05 Polyflos 61 4.25 "Component 3" Gel/ant (Powder) (hydroxypropyl guar -HPG) Sodium carbonate 0.40 HEC 5000 0.35 (hydroxyethylcellulose)

Table 2

By varying the quantity of buffer and the quantity of gellant a strong compliant "ringing" gel can be formed at a variety of temperatures. The rate of gel formation of the gel is dependent on the amount of citric acid / sodium carbonate buffer that is used, the concentration of gellant and the temperature of the system. For example, between 0.1 to 1.0 sodium carbonate may be used. Some examples of various different formulations and the time taken to form a ringing gel are detailed in table 3 hereinafter. Proportions shown in table 3 are given as weight ratios. It is readily apparent that provided one knows the temperature of the system component ratios can be varied to control the setting time of the gel.

Component 1 and 3 delivery weight ratio: 95:5 #W5954 Citric Acid Component "2" 0.15 0.18 0.20 Time to form 5 °C >7<22 hours >6<16 hours 2:30 hours ringing gel at temperature °C 5 hours 3 hours 1:30 hours °C 1:45 hour 1:20 hour 40 mins Component 1 and 3 delivery weight ratio: 94.5:4.5 95.17:4.83 Time to form 5 °C 36 hours 24 hours 7-8 hours ringing gel at temperature ° >7 hours 7 hours 5 hours °C 2:15 hours 1:45 hour 45 mins Table 3: Time to Gel -Citric acid concentration and temperature effects A further benefit of this gel is that it can be removed subsequently by lowering the system pH through the addition of acid.

Whilst water or other liquids can be used to create a hydrostatic pressure, brine is preferred and could be calcium chloride, calcium bromide, sodium chloride, potassium chloride, sodium bromide or a formate brine such as potassium or sodium formate. The hydrostatic head acts to push the compliant gel or viscous paste into the leak path sealing it and creating an acceptable pressure barrier.

The fluids both sealant 16 and brine 17 and displacement fluid 18 can be introduced either by pumping them directly through the well head annulus valve 15 and allowing fluid to sink to the bottom of the well or alternatively introducing a hollow tube through the valve 15 passing it down the well to a point just above the B annulus (for example at a distance of between 500 -2000 metres measured or 300 -1500 true vertical depth). Such equipment can be supplied by Expro group Ltd of Aberdeen.

Thus embodiments of the invention can provide a secondary pressure barrier in addition to the wellhead or the likes.

Claims

CLAIMS1. A method of forming a seal in an annular space in a well defined radially inward of at least one casing of the well, the method comprising: -deploying a chemical mixture comprising a polymer component into a well annulus, the chemical mixture being in a flowable state and having a first viscosity, -causing the viscosity of the chemical mixture to increase to a second viscosity; wherein the chemical mixture with the second viscosity has a maximum Shore 00 hardness of 90.
2. A method as claimed in claim 1, wherein the viscosity is increased, at least in part, by increased heat in the well.
A method as claimed in either preceding claim, wherein the chemical mixture with the second viscosity forms a compliant solid.
4. A method as claimed in any preceding claim, wherein the first viscosity is less than 1000 centipoise (1000 millipascal second) and the second viscosity is greater than 5000 cenfipoise (5000 millipascal second).
5. A method as claimed in any preceding claim, wherein the annular space is a B-annulus.
6. A method as claimed in any preceding claim, further comprising, delivering a liquid component into the annular space to increase the hydrostatic head on the chemical mixture, the liquid component normally having a lower density than the chemical mixture.
A method as claimed in claim 6, wherein the liquid component comprises a brine.
8. The method as claimed in any of claims 6 to 7, wherein a mass of the liquid component is sufficient to create a hydrostatic head in the annular space sufficient to move a portion of the chemical mixture at least partly into any adjacent flowpaths between the annulus and an outside of the annulus.
9. A method as claimed in any one of claims 6 to 8, wherein the chemical mixture and at least a portion of the liquid component are introduced into the well together.
10. A method as claimed in any preceding claim, comprising delivering a displacement fluid into the annular space, with a higher density than the chemical mixture.
11. A method as claimed in any preceding claim, wherein the chemical mixture is activated to change to the second viscosity by manipulation of its pH.
12. A method as claimed in claim 11, wherein the chemical mixture comprises a buffered solution.
13. A method as claimed in claim 11 or 12, wherein the polymer component comprises a hydropropyl-based polymer.
14. A method as claimed in any preceding claim, wherein a second chemical component is added to the chemical mixture to cause the mixture comprising the polymer component and the second chemical component to increase to the second viscosity.
15. A method as claimed in claim 14, wherein the mixture is formed by mixing the polymer component and the second chemical component before the polymer component and the second chemical component are delivered to the annular space.
16. A method as claimed in any one of claims 14 to 15, wherein the polymer component is mixed with the second chemical component less than twelve hours before the mixture is delivered to the annular space.
17. A method as claimed in any one of claims 14 to 16, wherein the second chemical component comprises a cross-linking agent.
18. A method as claimed in claim 17, wherein the cross-linking agent comprises a silyl hydride.
19. A method as claimed in any preceding claim, wherein at least the chemical mixture is delivered into the annular space by insertion through an opening defined at an upper end of the annular space, the opening being in a wellhead, normally controlled by a valve.
20. A method as claimed in claim 19, further comprising inserting a tube through the opening, wherein the chemical mixture is delivered through the tube.
21. A method as claimed in any preceding claim, wherein the chemical mixture is delivered to the base of the annular space.