WO2007091032A1

WO2007091032A1 - Scale mitigation method

Info

Publication number: WO2007091032A1
Application number: PCT/GB2007/000389
Authority: WO
Inventors: Eric James Mackay
Original assignee: Heriot-Watt University
Priority date: 2006-02-09
Filing date: 2007-02-06
Publication date: 2007-08-16
Also published as: GB0602619D0

Abstract

A method for controlling the precipitation of sulphate salts from a solution by introducing a source of metal ions into the solution, the metal ions being capable of forming a salt with the sulphate ions and then controlling the reaction conditions in the solution to control the. point at which the sulphate salt precipitate is formed. The method can be applied to the recovery of hydrocarbons from a hydrocarbon reservoir; in which case, calcium ions are added to an injector fluid such as naturally occurring, sulphate containing, brine. The method of the present invention removes the need for complex and expensive injector fluid treatment designed to minimise unwanted sulphate precipitation. In addition, the location of the sulphate precipitation in the hydrocarbon reservoir can be controlled to improve hydrocarbon output.

Description

Scale Mitigation Method

FIELD OP THE INVENTION

The present invention relates to a scale mitigation method which controls the precipitation of sulphate salts that form scale and in particular a method which reduces the effect of scaling within production wells and surface facilities. Control of sulphate salt precipitation also assists in increasing hydrocarbon production.

BACKGROUND TO THE INVENTION

Sulphate scale formation is caused by the precipitation of a sulphate salt from an aqueous solution of metal ions such as barium, strontium and calcium when a source of sulphate ions is added to the aqueous solution of metal ions. The mixing of sea water with hydrocarbon reservoir brine can cause the formation of such salts as discussed by Hardy, J A, and Simm, I, ["Low Sulfate Seawater Mitigates Barite Scale", Oil and Gas Journal, December 2, 1996] .

It costs the oil industry 100s of millions of US$ annually to manage scale formation. The various known techniques for this are discussed by Graham, G.M. and Collins, I. R. ["Assessing Scale Risks and Uncertainties for Subsea and Marginal Developments" paper SPE 87460, presented at the SPE 6th International Symposium on Oilfield Scale, Aberdeen, Scotland, 26-27 May 2004] , McElhiney, J. E. ["Deepwater Project Economics Demand Sulfate Removal to Ensure Scale-Free Operation", Offshore (May 2003)], and Mackay, E.J., Jordan, M.M. , Feasey, N., Shah, D., Kumar, P. and Ali, S. ["Integrated Risk Analysis for Scale Management in Deepwater Developments" paper SPE 87459, presented at the SPE 6th International Symposium on Oilfield Scale, Aberdeen, Scotland, 26-27 May 2004] .

Additionally, injection of sulphate rich seawater, or particularly a mix of seawater and produced water for re- injection (PWRI), may lead to reservoir souring. Production of the resulting H2S may lead to corrosion and health and safety problems in the production infrastructure .

Brine is routinely injected into reservoirs with the purpose of sweeping hydrocarbons towards the production wells and to maintain reservoir pressure during production. In offshore environments seawater is often used and seawater from open seas generally contains sulphate concentrations of around 2800 mg/1.

While some of the mixing may take place deep within the reservoir, where scale deposition has no negative impact, a significant proportion of the brine mixing takes place in and around production wells, where scale build-up can reduce hydrocarbon flow, damage downhole equipment (such as subsea safety valves) and cause a health hazard due to the incorporation of radioactive radium in the crystal lattice.

Sulphate scales may be removed by chemical or mechanical means once formed, as discussed by Vu, V.K. , Hurtevent, C. and Davis, R.A. ["Eliminating the Need for Scale Inhibition Treatments for Elf Exploration Angola's Girassol Field" paper SPE 60220 presented at the SPE 3rd International Symposium on Oilfield Scale, Aberdeen, Scotland, 30-31 January 2001] . However, this tends to be difficult because of the inherent hardness of the scales, particularly in the case of barium sulphate.

As an alternative, their formation may be inhibited by the application of chemicals. On a practical level, this is the most commonly used control method.

However, in reservoirs where access to the production wells for treatment is difficult, generally because the wells are drilled in relatively deep water, alternative solutions are required to protect the wells, particularly as they may be valued in the range US$5-100 million.

One approach is to source compatible 'non-scale inducing' water from a neighbouring shallow aquifer, but a suitable source is only occasionally available.

Alternatively, the sulphate content of the injection water may be reduced by a technique called nano- filtration, as discussed by Davis, R., Lomax, I. and Plummer, M. ["Membranes Solve North Sea Waterflood Sulfate Problems" Oil and Gas Journal, 59-64, 25 November 1996] . However, the installation of the sulphate reduction plant required for this process can cost between US$20-100 million, depending on the volumes of water to be treated and the configuration of the production facility. This can be inherently unworkable in a commercial context .

SUMMARY OF THE INVENTION

In accordance with a first aspect of the invention there is provided a method for controlling the precipitation of sulphate salts from a solution, the method comprising the steps of: introducing a source of metal ions into the solution, the metal ions being capable of forming a salt with the sulphate ions; and controlling the reaction conditions in the solution to control the point at which the sulphate salt precipitate . is formed.

Preferably, the metal ions are calcium ions.

Preferably, the method further comprises determining the concentration of sulphate ions in the solution before the introduction of the metal ions.

Preferably, the step of controlling the reaction . conditions comprises, maintaining the solution below a first temperature at which the ions remain in solution ^■ within a first location and having an increase in temperature occur to a second temperature at which precipitation will occur at a second location.

Preferably, the first and second locations are separated by a distance.

Preferably, the distance is determined by the difference between the first and second temperatures .

Preferably, the second location is in a hydrocarbon reservoir .

Preferably, the solution is an aqueous solution that is injected from an injector into the hydrocarbon reservoir. The increase in temperature from the first temperature to the second temperature occurs when the solution is injected into the hydrocarbon reservoir.

Preferably, the first location is bounded by the end of the injector in operative contact with the hydrocarbon formation. .

Preferably, the increase in temperature is provided by the rock formation in the hydrocarbon reservoir.

Preferably, the step of introducing a source of metal ions comprises adding a quantity of the metal ion source prior to injection of the aqueous solution by the injector.

Preferably, the solution is brine.

Preferably, the first temperature is the ambient temperature of the injector.

Preferably, the first temperature is less than or equal to 30⁰C.

Preferably, the concentration of calcium ions is less than or equal to 4000mg/l.

In one aspect, the present invention provides a method whereby scaling is controlled through the deliberate injection of calcium ions, giving precipitation of sulphates in a controlled manner.

In accordance with a second aspect of the invention there is provided a method for controlling the direction of flow of fluid injected into a hydrocarbon reservoir, the method comprising the steps of: causing the formation of a metal sulphate precipitate at a predetermined position in the hydrocarbon reservoir by loading a sulphate containing injection fluid with a source of metal ions prior to injection; creating a barrier to fluid flow through the formation of a mass of said precipitate; injecting additional fluid whose path through the reservoir will be altered by the presence of the precipitate barrier.

The altered direction of flow may be more favourable to the removal of hydrocarbons at a producer well.

Preferably, the metal ions are calcium ions .

Preferably, the step of causing the formation of a metal sulphate precipitate in a predetermined position in the hydrocarbon reservoir comprises, maintaining the solution below a first temperature at which the ions remain in solution within a first location and having an increase in temperature occur to a second temperature at which precipitation will occur at a second location.

Preferably, the first and second locations are separated by a distance.

Preferably, the distance is determined by the difference between the first and second temperatures.

Preferably, the first location is bounded by the end of the injector in operative contact with the hydrocarbon formation.

Preferably, the solution is brine.

Preferably, the first temperature is the ambient temperature of the injector.

Preferably, the first temperature is less than or equal to 30⁰C.

Therefore, the present invention provides a method for enhanced oil recovery from hydrocarbon reservoirs through the deliberate manipulation of and use of the content of injection brines.

This aspect of the present invention is exercised through the. deliberate loading of injection brines, preferably at ambient temperatures and in any case at temperatures less than those which cause sulphate to precipitate, with calcium, causing sulphate precipitation within a reservoir, or part thereof, when the temperature of the injection brine rises to that of the reservoir, or part thereof, thereby stripping sulphate from the formation/injection brine mix in situ.

Removal of the sulphate ions through the deliberate formation of calcium sulphate will prevent those sulphate ions from forming a precipitate elsewhere in the hydrocarbon reservoir, such as in the proximity of a producer or injector well.

Removal of the sulphate ions will also prevent sulphate reducing bacteria (SRB) present in the reservoir from generating H₂S.

As a consequence, this reduces permeability in watered out zones of the well, diverting subsequently injected water to oil zones, improving recovery.

The present invention is thus of particular relevance to the field of upstream petroleum engineering.

The present invention is a method whereby scale precipitation within a material is controlled by the deliberate introduction of calcium into that material at a predetermined location.

Deliberately creating conditions for scale deposition in one part of a material, being where the precipitation of scale will be beneficial, to protect other parts of that material, where scale formation may be detrimental, enables the protection of that material from scale formation at an undesirable location, because as a material has only a limited capacity to form scale, and when that capacity is used completely or even partially at a predetermined location, where it will be beneficial, it has no or little remaining capacity to form scale at a detrimental location. Where a reduced quantity of scale is formed at the detrimental location (s), the present invention greatly reduces the extent to which other remediation techniques are required and the cost of their use.

The present invention may be carried out by injecting calcium into the location within the material where scale formation would be beneficial, preferably in the form of a calcium carrying liquid. The amount of calcium which should be used as part of the present invention should be determined experimentally, and is further discussed below.

BRIEF DESCRIPTION OF THE DRAWINGS

The present invention will now be described by way of example only with reference to the accompanying drawings in which:

Fig.l is a graph of precipitation versus Calcium ion concentration plotted at 5 different temperatures;

Fig.2 illustrates an injector/producer well system of a hydrocarbon reservoir and the dispersal of injector fluids;

Fig.3 illustrates the injector/producer well pair and the change in temperature that occurs when injector fluids are dispersed in the hydrocarbon reservoir; and

Fig. 4 illustrates an embodiment of the method of the present invention in which Calcium ions are added to a solution of injector fluid prior to injection into a hydrocarbon reservoir.

DETAILED DESCRIPTION OF THE INVENTION

The present invention may be implemented where precipitation of sulphate salts through the addition of metal ions to a solution containing . sulphate ions is controllable by for example, changing the temperature of the fluid.

The present invention has particular applications in the oil and gas industry where, as discussed above, the presence of substantially insoluble sulphate salts can cause significant additional costs in the recovery of oil and gas. In the following example, a source of calcium ions is added to an injector fluid (typically sulphate containing brine) . The brine is loaded with the calcium prior to injection. Loading of calcium into the brine can be carried out by using any one or a combination of methods, including adding calcium salts to the brine.

The injection should preferably take place at ambient temperatures and in any case, at levels less than those which generally instigate precipitation of Calcium Sulphate, to ensure the injected material remains in solution until heated.

The material should then be heated. The purpose of the heating is to stimulate a reaction between the calcium and the sulphate within the material, to form calcium sulphate. The mixture is heated to over saturate the material at the desired location and thus cause scale precipitation. The amount of calcium which is preferable to use as part of the present invention depends on the degree of scale precipitation required, and may be determined experimentally. If sufficient calcium is used, then substantially all the sulphate present within the material will be consumed in the scaling reaction, and all the propensity of the material to form scale will have been exhausted, with all the scale being present at the desired location and unable to form at any other location.

In the case of hydrocarbon reservoirs, the brine is heated within the reservoir by the natural thermal processes present within the reservoir. This heating causes the reservoir/brine mixture to become oversaturated with respect to calcium sulphate, and scale thus precipitates. If there is sufficient calcium present in the brine, then all the sulphate present within the reservoir will be consumed in the scaling reaction.

In this case, the brine should preferably have a calcium concentration of up to 4000 mg/1, at ambient conditions. This means that it will be undersaturated at ambient conditions. When injected- into the reservoir, due to_. the rise in temperature (according to typical reservoir conditions of over 70 degrees centigrade) , the injection brine will become oversaturated and calcium sulphate will precipitate. The loading of brine or seawater with calcium can be engineered by using any one of or a combination of known methods, including adding calcium salts, or by using filtration equipment, where high salinity water that is normally disposed of during hydrocarbon reservoir oil recovery can be readily and usefully employed.

Figure 1 is a graph 1 of precipitation 3 versus Calcium ion concentration 5 plotted at five different temperatures, namely.30⁰C, 90⁰C, 100⁰C, 110⁰C and 120⁰C. It illustrates the degree of calcium sulphate precipitation from seawater at various concentrations of calcium and at various temperatures . Seawater containing up to 4000mg/l calcium at ambient temperatures (30⁰C) will lead to no precipitation.

Precipitating calcium sulphate in the reservoir leads to stripping of the sulphate ions present within the reservoir during displacement through the reservoir, so that the potential for sulphate precipitation, including barium sulphate precipitation, and damage to a production well is minimised.

The correct calcium concentration for the injection brine stream may be determined experimentally, including by analysis of each individual reservoir's formation, the injection brine composition and the particular reservoir temperature at the desired location.

Furthermore, precipitation of scale in the hotter zones of the reservoir away from the cooled injection wells may result in reduced, permeability. Reducing flow in these 'watered out' zones of the reservoir increases displacement through the hydrocarbon bearing zones, diverting subsequently injected water to oil zones, enhancing oil recovery and improving production efficiency. Loading of brine with calcium can be carried out by using any one of or a combination of methods, including adding calcium salts, or by using filtration equipment, where high salinity water that is normally disposed of during hydrocarbon reservoir oil recovery can be readily and usefully employed.

When injected into the reservoir, due to the rise in temperature (according to typical reservoir conditions of over 70⁰C), calcium sulphate will precipitate.

Figures 2 to 4 illustrate various features of a method of the present invention. In figures 2 to 4 an injector well 7 is shown and a fluid path 13 between the injector well 7 along with a producer well 9. The direction of fluid flow is indicated by arrow 15 where fluid is shown entering the injector well and exiting the producer well.

Figure 2 shows three fluid zones 17, 19 and 21. The fluid zones show the extent to which injector fluid is mixed with reservoir fluids . It can be seen that in fluid zone one 17, the injector fluid is substantially un-mixed with the reservoir fluids more mixing occurs in zone two 19 and at or near the producer well the fluid consists almost entirely of reservoir fluids. This is consistent with the general object of injecting fluids to push reservoir fluids containing hydrocarbons out through the producer well.

Figure 3 shows an injector well 7 and an illustration of the change in fluid temperature along the fluid pathway. In the first zone 23 the cool injector fluid has not mixed sufficiently with the reservoir fluid or been in contact with the reservoir formation over a sufficient distance for the temperature of the fluid to increase significantly. In zone two 25 the temperature of the injection fluid has increased primarily through the duration of it contact with the reservoir formation. . In zone three 27 the temperature is at equilibrium with the general reservoir formation temperature. It can be seen therefore that the further an injector fluid travels through the fluid pathway the temperature of the injector fluid will tend towards the overall temperature of the reservoir .

Figure 4 illustrates the use of a method of the present invention in which calcium ions 30 and sulphate ions 32 are injected in solution 29 through an injector well 7. In zone one of figure 4 the injected fluid containing the calcium and sulphate ions 30 and 32 is at a temperature at or near the fluid injection temperature of approximately 30 degrees centigrade. At these temperatures the calcium 30 and sulphate ions 32 exists in solution as is shown with reference to figure 1. As the injector fluid travels along the fluid pathway the temperature of the fluid increases and precipitation occurs as is shown by the bonding of calcium 30 and sulphate 32 in zone two 33 of figure 4.

The temperature increase causes the solid precipitate to come out of solution and uses up all of the sulphate ions that were present in the original injection fluid which may be normal sea water. It can be seen that in zone three 35 little or no sulphate remains in solution and a small amount of calcium ions, that is those which were in excess of the concentration of sulphate ions, remain in solution. As can be seen from the above embodiment of the present invention, the addition of calcium ions to a sulphate containing brine removes the potential creation of damaging sulphate precipitates at or near .the producer well because these precipitates are created within a predefined fluid pathway by the inclusion of a source of calcium ions in the injector fluid. .

This embodiment of the present invention is particularly suitable for use with a deepwater hydrocarbon reservoir preferably located in over 400 metres water depth, and potentially offshore, such as those currently present in Angola, Brazil or in the Gulf of Mexico, for example, where seawater injection has been identified as the primary source of fluid for sweep, and where the formation waters contain barium concentrations in excess of 150 mg/1.

Furthermore, this embodiment of the present invention can be implemented using a small filtration plant that would use seawater as a feed, and produce a brine stream with a very high calcium concentration, or by taking calcium rich water produced from the reservoir in question, or from a neighbouring reservoir,- or from an aquifer. In any case, this brine stream would then be blended with- ^: ordinary seawater in a ratio that would give an injection water with the desired calcium concentration of up to 4000 mg/1.

In the case of hydrocarbon reservoirs, the present invention has benefits over existing nano-filtration technology. Current nano-filtration technology allows for sulphate reduction down to a minimum of 20 mg/1. This technique has the potential for removing sulphate altogether.

Also, the plant required for loading the injection brine with calcium is potentially much smaller than the plant required for nano-filtration, significantly reducing installation and running costs .

Furthermore, in the case of hydrocarbon reservoirs, the present invention gives improved water sweep due to permeability reduction in watered out zones, allowing for increased oil production at a lower cost

Improvements and modifications may be incorporated herein without deviating from the scope of the invention.

Claims

1. A method for controlling the precipitation of sulphate salts from a solution, the method comprising the steps of: introducing a source of metal ions into the solution, the metal ions being capable of forming a salt with the sulphate ions ; and controlling the reaction conditions in the solution to control the point at which the sulphate salt precipitate is formed.

2. A method as claimed in claim 1 wherein, the metal ions are calcium ions .

3. A method as claimed in claim 1 or claim 2 wherein, the method further comprises determining the concentration of sulphate ions in the solution before the introduction of the metal ions.

4. A method as claimed in any preceding claim wherein, the step of controlling the reaction conditions comprises, maintaining the solution below a first temperature at which the ions remain in solution within a first location and having an increase in temperature

, occur to a second temperature at which precipitation will occur at a second location.

5. A method as claimed in claim 4 wherein, the first and second locations are separated by a distance.

6. A method as claimed in claim 4 or claim 5 wherein, the second location is in a hydrocarbon reservoir.

7. A method as claimed in any preceding claim wherein, the solution is an aqueous solution that is injected from an injector into the hydrocarbon reservoir.

8. A method as claimed in claim 4 and claim 6 wherein, the first location is bounded by the end of the injector in operative contact with the hydrocarbon formation.

9. A method as claimed in claims 4, 6 and 7 wherein, the increase in temperature is provided by a rock formation in the hydrocarbon reservoir.

10. A method as claimed in any preceding claim wherein, the step of introducing a source of metal ions comprises adding a quantity of the metal ion source prior to injection of the aqueous solution by the injector.

11. A method as claimed in any preceding claim wherein, the solution is brine.

12. A method as claimed in claim 4 wherein, the first temperature is the ambient temperature of the injector.

13. A method as claimed in claim 4 or claim 12 wherein, the first temperature is less than or equal to 30⁰C.

14. A method as claimed in claim 2 wherein the calcium ions are at a concentration of less than or equal to 4000mg/l.

15. A method for controlling the direction of flow of fluid injected into a hydrocarbon reservoir, the method comprising the steps of: causing the formation of a metal sulphate precipitate at a predetermined position in the hydrocarbon reservoir by loading a sulphate containing injection fluid with a source of metal ions prior to injection; creating a barrier to fluid flow through the formation of a mass of said precipitate; injecting additional fluid whose path through the reservoir will be altered by the presence of the precipitate barrier.

16. A method as claimed in claim 15 wherein, the metal ions are calcium ions .

17. A method as claimed in claim 15 or 16 wherein, the step of causing the formation of a metal sulphate precipitate in a predetermined position in the hydrocarbon reservoir comprises, maintaining the solution below a first temperature at which the ions remain in solution within a first location and having an increase in temperature occur to a second temperature at which precipitation will occur at a second location.

18. A method as claimed in claim 17 wherein, the first and second locations are separated by a distance.

19. A method as claimed in any of claims 15 to 18 wherein, the solution is an aqueous solution that is injected from an injector into the hydrocarbon reservoir.

20. A method as claimed in claim 17 wherein, the first location is bounded by the end of the injector in operative contact with the hydrocarbon formation.

21. A method as claimed in claim 17 wherein, the increase in temperature is provided by a rock formation in the hydrocarbon reservoir.

22. A method as claimed in any of claims 15 to 21 wherein, the solution is brine.

23. A method as claimed in claim 17 wherein, the first temperature is the ambient temperature of the injector.

24. A method as claimed in claims 17 or 23 wherein, the first temperature is less than or equal to 30⁰C.

25. A method as claimed in claim 16 wherein, the concentration of calcium ions is less than or equal to 4000mg/l.