GB2439076A

GB2439076A - Controlled location of the precipitation of scale in reservoirs

Info

Publication number: GB2439076A
Application number: GB0611816A
Authority: GB
Inventors: Jeremy James Tyrie
Original assignee: ABERDEEN PETROLEUM ENGINEERING
Current assignee: ABERDEEN PETROLEUM ENGINEERING
Priority date: 2006-06-15
Filing date: 2006-06-15
Publication date: 2007-12-19
Anticipated expiration: 2026-06-15
Also published as: GB2439076B; WO2007144562A1; NO20090213L; GB0611816D0; NO345678B1

Abstract

A process for enhanced hydrocarbon recovery from a reservoir by actively forming scale within the reservoir. Predetermined locations for the deposition of the scale are calculated and a mix of scale inhibitor(s) and injection fluid are introduced through injection wells 112 into the reservoir. As the scale precipitates 132 through the reservoir, fluids are diverted to preferentially sweep locations thereby recovering increased hydrocarbons at the production wells, and reduced levels of scale are produced at the production well 114.

Description

Controlled Location of the Precipitation of Scale in Reservoirs The

present invention relates to a process for enhanced S hydrocarbon recovery from a reservoir including oil, gas, aquifer, geothermal, water tables etc. More particularly the present invention relates to a method of controlling the location of the precipitation of scale in a reservoir to improve the sweep efficiency through the reservoir and to prevent scale formation at the production facilities.

Underground pools of natural hydrocarbons, known as reservoirs' , contain oil and/or gas. These hydrocarbons accumulate within the subterranean rock formations and are recovered or produced therefrom through wells, called production wells, drilled into the subterranean formation.

Recovery occurs by inducing a pressure drop at the production wells which causes the hydrocarbons to expand up the well to the surface. Production will cease when the head of pressure of the fluids in the well equals the pressure in the reservoir, i.e. there is no longer sufficient energy within the reservoir to drive out the hydrocarbons. Such recovery is often termed primary' The point when the reservoir runs out of energy can be delayed via the natural influx of water from an underlying aquifer, a source of energy, or by the direct injection of water through injection wells, or both. The water not only augments the reservoir pressure t it also displaces, or sweeps' the hydrocarbon out of tne rock pore spaces. Such supplemental techniques to obtain additional hydrocarbons are often referred to as secondary, tertiary, enhanced or post-primary recovery operations.

Water flooding is one of the most successful and extensively used secondary recovery methods. However, there are some disadvantages to this technique.

The displacing of hydrocarbons by water from a reservoir can be very different depending on the hydrocarbon, rock, reservoir and the water properties and how each property varies within the reservoir. In general the displacement is far from perfect and some parts of the reservoir are preferentially swept many times by water in contrast to others that may be less swept or not swept at all. A solution to this problem has been recognized in blocking the previously swept parts so that others can subsequently be swept. Several different attempts have been made to provide diversion of sweeping fluids through blocking of the previously swept parts. Blocking agents are typically injected into the reservoir. These agents include polymers, resins and even biomasses. While these injected agents have provided enhanced production, a major disadvantage to their use is that as the reservoir is a huge volume, any chemical process tends to be prohibitively expensive.

After part of a reservoir has been swept it will approach residual oil (or gas) . Residual oil is that oil trapped in the rock formation pores and cannot be displaced be further sweeping of water alone. Residual oil saturation may be achieved in one sweep, under certain circumstances where the mobility of the water is less than that of the oil, but generally this will take several sweeps. Thus the water n flooding technique has the disadvantage of leaving a quantity of the hydrocarbons in the reservoir. A partial solution to this problem is achieved by injecting chemicals into the reservoir which interact with the hydrocarbons to increase their relative permeability and so release them from the pores. While these injected chemicals have provided enhanced production, a major disadvantage to their use is that as the reservoir is a huge volume, any chemical process tends to be prohibitively expensive. 1 0

As described above, aquifer water can be used to enhance recovery. Aquifer water can contain many different natural chemicals due to its interaction with the rocks it has come into contact with. These interactions with the reservoir rocks can both remove and add chemicals to the water as it moves through various geological formations. Common chemical constituents found in aquifer water are; sodium, chloride, calcium, strontium, barium, magnesium, potassium, bromide, bicarbonate and some heavy metals. They can be depleted in suiphates. If aquifer water is produced by a production well it is subjected to a temperature and pressure drop in the well. These conditions cause the mineral salts, in particular calcium carbonate, to precipitate. Accordingly, a major problem which occurs with aquifer water is the formation of scale in the well or in the surface facilities which causes some malfunction of equipment or simple blocking of pipes and vessels.

Calcium carbonate can normally be controlled with the injection of a scale inhibitor at the bottom of the well before the pressure drop occurs, or in a scale inhibitor squeeze. Here the chemical is adsorbed onto the near well reservoir rock by squeezing the chemical into the reservoir and then producing the well again with hydrocarbons and a trace of scale inhibitor that depletes over a period of time. Unfortunately, production of the well has to be S shutdown while the squeeze process is performed.

Additionally, once the well is brought back into production, the desorption process of the inhibitor is often found to be quite rapid necessitating frequent shutdowns for additional treatments. This has the effect of substantially reducing the productivity of the well.

Alternatively, the calcium carbonate scale is often effectively treated with acid, simply soaking the affected parts of the facilities, wells or reservoir with acid to dissolve it. It will be appreciated that this is potentially a hazardous procedure due to strength of acid required and the application process.

In offshore locations, e.g. North Sea, seawater is an abundant cheap source of water to sweep hydrocarbon reservoirs. Common chemical constituents of seawater are; sodium, chloride, calcium, potassium, magnesium, sulphates, bicarbonates and can be lacking in barium and strontium. As both aquifer water, present in the hydrocarbon part of the reservoir as well as underlying it, and the injected seawater commonly find their own paths through the reservoir they often first come into contact with each other at or near the production well. This mixes the sulphate and bicarbonate ions of the seawater with the barium and strontium cations and other alkaline earth metal ions in the aquifer water, and, depending on the concentrations, can rapidly lead to the precipitation of scale.

Similar treatments and inhibitor methods as used for calcium carbonate are utilised for the sulphate scales although different chemicals may be required. A major disadvantage is that barium and strontium sulphate scales are harder to inhibit and to treat once they are deposited. These scales also have the added complication that they result in a low specific radio activity which requires specialist treatment and protection. 1 0

As a result there are many types of scale inhibitors available together with a variety of processes for use in reservoirs. All of these are aimed at inhibiting scale deposition in the reservoir, near the production well and in the production facilities. Most rely on precipitating the scale inhibitor in the reservoir and then allowing the absorbed inhibitor to desorb during fluids production. The inhibitors have a limited operational period and thus sufficient quantity and mix have to be injected or squeezed into the reservoir to ensure that the scale does not precipitate until it is clear of the production facilities.

At this point it is disposed of along with the produced water. To ensure precipitation does not occur large quantities of scale inhibitor are used and this makes the process expensive.

It is an object of the present invention to provide an enhanced hydrocarbon recovery process which diverts injected fluid to sweep different parts of a reservoir.

It is a further object of the present invention to provide an enhanced hydrocarbon recovery process which improves the displacement of in situ. hydrocarbons within a reservoir.

It is an object of at least one embodiment of the present invention to provide an enhanced hydrocarbon recovery process which reduces the scaling tendency of subsequently produced fluids from a reservoir.

It is an object of at least one embodiment of the present invention to provide an enhanced hydrocarbon recovery process which facilitates safe disposal of produced water from a reservoir by re-injection.

it is an object of at least one embodiment of the present invention to provide an enhanced hydrocarbon recovery process which advantageously binds unconsolidated rock formations in a reservoir.

According to the present invention there is provided an enhanced hydrocarbon recovery process for recovering hydrocarbons from a subterranean reservoir penetrated by one or more injection wells and one or more production wells spaced apart from said injection well, said process comprising the steps: (a) mixing an injection fluid with a scale inhibitor to form a first solution; (b) injecting said first solution into said reservoir through at least one of said injection wells to thereby sweep said reservoir; (c) forming scale precipitation in at least one predetermined location of the reservoir to thereby reduce reservoir permeability at said at least one location; (d) divertin the said first solution by said scaae to sweep locations of the reservoir with now relatively higher permeability; and (e) recovering hydrocarbons from said production well.

In this way, scale is deliberately created in the reservoir to block parts of the reservoir in order to divert water to different parts of the reservoir. Thus parts of the reservoir which would typically have lower relative permeability are now preferentially swept which increases the recovery of hydrocarbons from the reservoir.

Preferably, the process includes the step of initially calculating the at least one predetermined location within the reservoir where the scale needs to be deposited. This step may be performed using a reservoir simulator and standard analytical techniques.

Preferably, the process includes the step of measuring the ion concentration of the injection fluid. The injection fluid may include one or more components from a group comprising: seawater, formation water, aquifer water, produced water, potable water, solutions with scaling ions or solutions with added scaling ions. y using the produced water with scale inhibitor, any scaling ions produced by the reservoir are safely disposed of by re-injection.

Preferably also, the process includes the step of determining a volume of the first solution. This may be calculated using the reservoir simulation model. The volume requires to be sufficient for the purpose of supporting reservoir pressure and achievinq the said sweep.

Preferably, the process includes the step of determining the scaling characteristics of the injection fluid.

Advantageously the components of the injection fluid are selected to provide a sufficient mass of scaling ions to effectively reduce the rock permeability at the locations selected in the reservoir. This step may include conducting core laboratory experiments to calculate the effectiveness of the scale at reducing permeability of the rock based on the mass of scaling ions used or available.

Preferably, the process includes the step of selecting one or more scale inhibitor(s) and determining their relative concentrations to provide predetermined placement of scale precipitation in the reservoir. This step may include using the reservoir simulator model to assist in determining the correct scale inhibitor(s) and dose to inhibit the precipitation of scale until the first solution has reached the predetermined location(s) within the reservoir taking into account the injection rate and path taken by the first solution. Additionally the step may include determining the chemical interaction between the first solution and the reservoir rock to correctly model the adsorption and absorption and calculate the position and rate of scale deposition in the reservoir. Core laboratory experiments may be used to assist in this.

Advantageously the process includes the step of selecting a mix of injection fluid and scale inhibitor(s) as the first solution based on the preceding calculations and models.

Advantageously the step of initially calculating the at least one predetermined location within the reservoir where the scale needs to be deposited is performed in order to divert the first solution to other parts of the reservoir by reducing the rock permeability in selected locations. 1 0

Advantageously also, the step of initially calculating the at least one Predetermined location within the reservoir where the scale needs to be deposited is performed in order to ensure displacement of in situ hydrocarbons which may be residual.

Optionally, the process may include the step of selecting the injecting fluid so that suiphates in the injecting fluid are removed as they form the scale to thereby reduce the scaling tendency of subsequently produced fluids from the reservoir. This injection fluid may advantageously be a mix of sea water and aquifer water.

Advantageously, the step of initially calculating the at least one predetermined location within the reservoir where the scale needs to be deposited is performed in order to use the scale to bind unconsolidated rock formations.

Optionally, the process may include the step of using a second solution to sweep the reservoir prior to injecting the first solution.

Advantageously, the process may include the step of using a third or more solutions to sweep the reservoir after the first solution is injected. In this way, if aquifer water is not initially available as an injection fluid, the produced fluids can be monitored to determine when aquifer water is produced throuqh the production well(s) and the solution modified to include the aquifer water.

Advantageously also, the process may include the step of forming the scale in fractures identified in the reservoir.

In this way, the process would enhance hydrocarbon recovery in fractured reservoirs.

Advantageously also, the process may include the step of creating precipitation of the scale in thief zones of geo-thermal reservoirs. In this way the solution is diverted from these zones to sweep water to hotter rocks.

Embodiments of the present invention will now be described, by way of example only, with reference to the accompanying drawings, of which: Figure 1 is a schematic flow diagram through a section of a reservoir between an injector well and a production well

according to the prior art;

Figure 2 is a schematic flow diagram through a section of a reservoir between an injector well and a production well according to an embodiment of the present invention; and 1.1 Figure 3 is a schematic flow diagram through a section of a reservoir between an injector well and a production well according to a further embodiment of the present invention.

Reference is initially made to Figure 1 of the drawings, which illustrates a schematic cross-sectional view through a reservoir, generally indicated by reference numeral 10, between an injector well, indicated at 12, and a production well 14. It will be appreciated that the reservoir 10 is three dimensional and that any number of injector wells 12 and production wells 14 may be present.

A reservoir 10 is a geological rock formation in which exists underground pools or reservoirs' of natural hydrocarbons typically in the form of oil and/or gas. The oil/and gas is located in the rock pore spaces providing hydrocarbon bearing formations 16. Aquifers 18 can also exist in the reservoir 10 which introduce water into the formation. Thus a typical reservoir 10 will be made up of parts each varying in the properties of the rock, hydrocarbon and water present.

It is known to recover the hydrocarbons by drilling into the formation to create a production well 14. By inducing a pressure drop at the production well 14 this causes the hydrocarbons to expand up the well to the surface. This is primary recovery. In order to produce more hydrocarbons an artificial pressure drop must be induced. This is typically achieved by injecting water into the reservoir at a distance from the production well so that the water travels across the reservoir, generally referred to as a sweep, displacing the hydrocarbons towards the production well 14. One or more injection wells 12 are located in the reservoir for this purpose. Reservoir simulation modeling as is known in the art is used to determine the location of the injection wells 12 and the injection flow rate to provide a predicted hydrocarbon recovery rate at the production well 4.

Figure 1 illustrates a normal reservoir sweep known in the prior art. Here, seawater 20 is used as the injecting solution due to its abundance on offshore facilities. The seawater 20 is injected into the reservoir 10 through the injection well 12. As will have been calculated form the reservoir simulation model, sufficient pressure drop will exist across the reservoir 10 to drive the seawater 20 to the production well 14. Naturally the seawater 20 will take the path of least resistance i.e. highest permeability. In the example given, the aquifer 18 towards the base of the reservoir presents a high water cut and consequently highest permeability. Thus while the seawater will sweep the hydrocarbon bearing portion 16 and drive some hydrocarbons to the production well 14, a large quantity of water will also be produced at the well 14. This water, termed produced water 22, comprises a mix of sea water 20 and aquifer 18. The produced water 22 must be separated from the produced fluid i.e. hydrocarbons 24 and safely disposed of.

As described previously, aquifer water 18 and seawater 20 include chemical components. The following table indicates the main ion concentrations found in a scaling reservoir:

I

ION mg/i Aquifer Water Sea Water Sodium 20000 10000 Chloride 40000 20000 Calcium 1000 400 Bicarbonate -1000 -200 Barium 200 0 Strontium 200 0 Sulphate 0 3000 Potassium 200 500 Magnesium 1000 1500 Heavy metals <10 0 When the aquifer water 18 and the seawater 20 come into contact under the pressure and temperature experienced in the reservoir, the constituents combine to form scale.

While the commonest scale is calcium carbonate, which can be produced by production of the aquifer 18 alone, the combination with seawater 20 produces barium and strontium sulphate scales. These sulphate scales have a low specific radio activity which requires specialist treatment/disposal of the produced water 22.

The scales described primarily precipitate in the near well area of the production well 14 and through the production facilities. This is because the seawater 20 and the aquifer water 18 take different paths through the reservoir and typically contact each other near the production well. The scale can block both the rock pores in the reservoir and pipes and vessels in the facilities. Consequently reservoir scale is recognized as a tremendous problem to the oil and gas industry. Much work has been done to provide a group of chemicals referred to as scale inhibitors 26. These scale inhibitors 26 are designed to prevent the precipitation of scale until such time as the produced water is disposed of.

While inhibitors 26 are known to be mixed and injected with the seawater 20, the quantities required to ensure that precipitation of scale does not occur until the produced water has been disposed of, make this prohibitively expensive in many circumstances.

A more common approach, as illustrated in Figure 1, is to inject a scale inhibitor 26 directly into the production well 14. This is referred to as a squeeze. By stopping fluid production, the well is effectively shut-in for a period of time for the inhibitor to penetrate into the near weilbore region. It is calculated that as the majority of scale will form in this region, preventative treatment is only required at this location. Squeeze operation are also expensive as there is no hydrocarbon production during the operation which can take weeks. Additionally the squeeze operation may need to be repeated at regular intervals.

As is apparent from the prior art, reservoir scale is a tremendous problem for the oil and gas industry. The prior art teaches that the scale should be prevented from forming in the reservoir by the application of scale inhibitors.

In contrast, the present invention proposes the deliberate deposition of scale in the reservoir. The present invention uses an abundant waste by-product of hydrocarbon production and thus presents a inexpensive technique for enhanced hydrocarbon recovery.

Reference is now made to Figure 2 of the drawings which illustrates a schematic cross-sectional view through a reservoir, generally indicated by reference numeral 110, between an injector well, indicated at 112, and a production well 114. As with Figure 1, it will be appreciated that the reservoir 10 is three dimensional and that any number of injector wells 112 and production wells 114 may be present.

In this embodiment, the reservoir 110 is initially modeled to determine the areas of highest permeability and lowest hydrocarbon content. In the Figure this would be marked at the aquifer 118 though it will be appreciated that an array of individual pockets is more likely to be identified. The skilled man i.e. a reservoir engineer using standard IS analytical techniques or more advanced reservoir simulation techniques will be able to perform this calculation using standard inputs. Through these techniques the engineer will produce a scenario in which they have predicted the potential hydrocarbon production on the basis of blocking off areas of the reservoir having high permeability and efficiently providing a sweep of the reservoir where injected fluid is diverted to other parts of the reservoir to displace in situ hydrocarbons, residual or otherwise which would otherwise be unswept. The engineer can model the effect of creating the blocked areas following an initial sweep or, if more beneficial, in the first sweep.

With this information the next step is to determine how to cause scale to form in the predetermined locations which the engineer has identified as wishing to block in the first step. Advantageously, we have scale forming ions in the common injection fluids, these being the seawater, formation water, aquifer water, produced water, potable water or other solutions with scaling ions. For the particular reservoir the ion concentration of the seawater and produced water can be measured. In this step we must also calculate the volume of injected fluid which will be required to be sufficient to sweep the reservoir for the purpose of reservoir pressure support.

Knowing the injection fluids available and their ion concentrations, we next determine the scaling characteristics of various mixtures of components. In this calculation there should be sufficient mass of scaling ions to effectively reduce the rock permeability within the reservoir path being swept. A skilled man, in this case a chemical engineer, will be able to calculate the effectiveness of the scale at reducing the permeability of the rock based on the mass of scaling ions used or available. Core laboratory experiments will assist this using core (rock) samples taken from the reservoir. Core analysis is a known technique.

Now that we know where we wish the scale to be deposited and have the correct amount of scaling ions in the reservoir to achieve this, we now need to ensure that the scale will form in the desired locations. We know that the scale will begin to form when the seawater contacts aquifer water. Indeed scale will be present in the produced water. Thus scale will be prone to precipitation from the point of injection into the well. We know that scale inhibitors 26 can be used to prevent scale formation for given times. We therefore select scale inhibitor(s) and their concentrations to provide different times of scale precipitation. The skilled man, a chemical engineer, will be able to determine the correct scale inhibitor and dose to inhibit the precipitation of scale until the injection fluid has reached the pre-determined location(s) within the reservoir taking into account the injection rate and path taken by the injected fluid as determined in the first step. At this stage modeling of the chemical interaction, e.g. adsorption or absorption, with the reservoir rock must be taken into account. Core laboratory experiments will assist this. 1 0

Once the desired mix of injection fluids and scale inhibitor(s) have been determined, this solution can be injected into the injector well 112 so that the scale is deposited in the reservoir at the calculated location(s) . It will be appreciated that these steps may have to be repeated and relative adjustments made as the produced sea and aquifer water is measured for scaling ion content during production.

Figure 2 illustrates the effect of injecting the solution 128 to sweep a reservoir 110. The solution is created on the topside facilities by mixing seawater with the produced waters 130. In this way the produced waters are re-injected so that disposal is not required. When the solution 128 enters the reservoir 110, it will naturally seek out the easiest parts of the reservoir to flow through and these will be the parts that have been previously swept by water.

This will be through the aquifer 118 as it provides the highest permeability. Once in the aquifer 118, the scale inhibitor(s) will cease to have an effect. This is as precalculated so that the controlled precipitation of scale 132 occurs in these parts. The scale will block the rock pores and create a barrier and effectively block off a selected water path through the reservoir. The barrier 132 created causes the following solution 128 to be diverted into other flow paths, in this case through the hydrocarbon bearing zone 116. Thus other parts of the reservoir are swept and, consequently, this improves the recovery of oil from the reservoir. Additionally, the precipitation of scale within the reservoir will displace the existing fluids out of the rock formation pores, this will effectively reduce the residual oil or gas saturation and result in additional hydrocarbons being produced.

Additionally, as the scale 132 is deliberately deposited in the reservoir, less scale is then present in the solution which reaches the production well 114. This will reduce or potentially mitigate the requirement to provide squeeze operations 126 on the production well, so that hydrocarbon production 124 can be maintained during the treatment process. As can also be seen in Figure 2, by blocking the water path through the aquifer 118, the water behind the barrier 132 remains unswept and thus the water cut of the produced fluids is reduced.

Reference is now made to Figure 3 of the drawings which illustrates a further embodiment of the present invention.

In this Figure, like parts to those of Figure 2 have been given the same reference with the addition of one hundred.

In this embodiment a further aquifer production well 234 has been included. The aquifer well 234 will only produce aquifer water which can be brought to the topside and introduced to the mixing vessel 236. As previously indicated aquifer water contains an increased quantity of barium and strontium in comparison to seawater. By the controlled mixing of seawater 220 and aquifer water 218, scale in the form of barium sulphate and strontium sulphate, together with other suiphates, can beformed. The scale inhibitors 226 would ensure the scale is deposited in the desired locations and as a result we have thus removed the scaling tendency of the sweeping water before it reaches the production facilities.

The principal advantage of the present invention is that it provides an enhanced hydrocarbon recovery process which utilises a waste by-product and by the controlled precipitation of this byproduct i.e. scale, an enhanced oil recovery process is achieved.

A further advantage of the present invention is that it provides an enhanced hydrocarbon recovery process which provides a cheap method of blocking parts of a reservoir to divert injected fluid to sweep different parts of a reservoir and thereby improve the displacement of in situ hydrocarbons within the reservoir.

A yet further advantage of at least one embodiment of the present invention is that it provides an enhanced hydrocarbon recovery process which reduces the scaling tendency of subsequently produced fluids from a reservoir.

A yet further advantage of at least one embodiment of the present invention is that it provides an enhanced hydrocarbon recovery process which facilitates safe disposal of produced water from a reservoir by re-injection.

Further modifications may be made to the invention herein described without departing from the scope thereof. For example, if aquifer water is not directly available from a dedicated aquifer well then the process can still be implemented once aquifer water is produced through the production wells. Simple monitoring of the produced fluids will allow the facilities engineer to establish the volume of seawater and scale inhibitor required to give the effective control although the advantage of mitigating the scaling problem before it reaches the production wells would have been lost.

It will also be appreciated that by causing the precipitation of scale in controlled process within a reservoir, those portions chosen to be blocked could represent unconsolidated rock formations such as sands. By using the scale to bind these together we can advantageously consolidate these formations.

It will further be appreciated that the scale may be calculated to be formed in cracks or fractures found in fractured reservoirs. Fractured reservoirs often have fracture networks that connect too directly from producers to injectors. These have previously been controlled by the injection of reservoir gels to block them and divert injected water to other parts of the network or through the matrix; the precipitation of scale in these fractures would It will also be appreciated that the present invention may find application in geo- thermal reservoirs. These reservoirs often depend on sweeping cold injection fluid passed hot rocks that replenish there heat through conducting heat from deeper hot rocks. Thief zones can often be established and scale precipitation could block these to divert sweep water to hotter rocks.

Claims

CLAIMS

1. An enhanced hydrocarbon recovery process for recovering hydrocarbons from a subterranean reservoir penetrated by one or more injection wells and one or more production wells spaced apart from said injection well, said process comprising the steps: (a) mixing an injection fluid with a scale inhibitor to form a first solution; (b) injecting said first solution into said reservoir through at least one of said injection wells to thereby sweep said reservoir; (c) forming scale precipitation in at least one predetermined location of the reservoir to thereby reduce reservoir permeability at said at least one location; (d) diverting the said first solution by said scale to sweep locations of the reservoir with now relatively higher permeability; and (e) recovering hydrocarbons from said production well.

2. A process as claimed in claim wherein the process includes the step of initially calculating the at least one predetermined location within the reservoir where the scale needs to be deposited.

3. A process as claimed in claim 2 wherein the step of initially calculating the at least one predetermined location is performed using a reservoir simulator and standard analytical techniques.

4. A process as claimed in any preceding claim wherein the process includes the step of measuring the ion concentration of the injection fluid.

5. A process as claimed in any preceding claim wherein the injection fluid includes one or more components from a group comprising: seawater, formation water, aquifer water, produced water, potable water, solutions with scaling ions or solutions with added scaling ions.

6. A process as claimed in any preceding claim wherein the process includes the step of determining a volume of the first solution by a calculation using a reservoir simulation model.

7. A process as claimed in any preceding claim wherein the process includes the step of determining the scaling characteristics of the injection fluid.

8. A process as claimed in claim 7 wherein the components of the injection fluid are selected to provide a sufficient mass of scaling ions to effectively reduce the rock permeability at the locations selected in the reservoir.

9. A process as claimed in claim 8 wherein the step includes conducting core laboratory experiments to calculate the effectiveness of the scale at reducing permeability of the rock based on the mass of scaling ions used or available.

10. A process as claimed in any preceding claim wherein the process includes the step of selecting one or more scale inhibitor(s) and determining their relative concentrations to provide predetermined placements of scale precipitation in the reservoir.

11. A process as claimed in claim 10 wherein a reservoir simulator model is used to assist in determining the correct scale inhibitor(s) and dose to inhibit the precipitation of scale until the first solution has reached the predetermined location(s) within the reservoir taking into account the injection rate and path taken by the first solution.

IS 12. A process as claimed in claim 10 or claim 11 wherein the step includes determining the chemical interaction between the first solution and the reservoir rock to correctly model the adsorption and absorption and calculate the position and rate of scale deposition in the reservoir.

13. A process as claimed in any one of claims 10 to 12 wherein the process includes the step of selecting a mix of injection fluid and scale inhibitor(s) as the first solution based on the preceding calculations and models.

14. A process as claimed in any preceding claim wherein the step of initially calculating the at least one predetermined location within the reservoir where the scale needs to be deposited is performed in order to divert the first solution to other parts of the reservoir by reducing the rock permeability in selected locations.

15. A process as claimed in any preceding claim wherein the step of initially calculating the at least one predetermined location within the reservoir where the scale needs to be deposited is performed in order to ensure displacement of in situ hydrocarbons including at least some residual.

16. A process as claimed in any preceding claim wherein the process includes the step of selecting the injecting fluid so that suiphates in the injecting fluid are removed as they form the scale to thereby reduce the scaling tendency of subsequently produced fluids from the reservoir.

17. A process as claimed in claim 16 wherein the injection fluid is a mix of sea water and aquifer water.

18. A process as claimed in any preceding claim wherein the step of initially calculating the at least one predetermined location within the reservoir where the scale needs to be deposited is performed in order to use the scale to bind unconsolidated rock formations.

19. A process as claimed in any preceding claim wherein the process includes the step of using a second solution to sweep the reservoir prior to injecting the first solution.

20. A process as claimed in claim 19 wherein the process includes the step of using a third or more solutions to sweep the reservoir after the first solution is injected.

21. A process as claimed in claim 20 wherein the produced fluids are monitored to determine when aquifer water is produced through the production well(s) and the solution is modified to include the aquifer water.

22. A process as claimed in any preceding claim wherein the process includes the step of forming the scale in fractures identified in the reservoir.

23. A process as claimed in any preceding claim wherein process includes the step of creating precipitation of the scale in thief zones of geo-thermal reservoirs.