A METHOD OF ABANDONING A ZONE OR A WELL WITH SCALE

Abstract

The method includes a step of introducing into the reservoir, via a well, a mixture comprising a scale inhibitor, a first scale precursor and a second scale precursor. The first and second scale precursors can react together to form scale. The first scale precursor may be an ammonium salt. The method can further comprise a step of stopping the introduction into the reservoir of the mixture and shutting in the well for 2-24 hours, and a step of introducing into the reservoir a further mixture comprising a scale inhibitor, a first and second scale precursor which can react together to form scale. The steps of stopping and resuming the introduction of mixtures may be repeated at least once. The components of the mixtures may be provided as concentrated solutions and diluted in a stream of water prior to being introduced into the reservoir. The method provides an effective way of generating a barrier to fluid flow in a reservoir. The method may be a method of abandoning an entire well in a reservoir.

Claims

1. A method of abandoning a zone in a reservoir, the method comprising the steps of: (i) introducing into the reservoir, via a well, a mixture comprising a scale inhibitor, a first scale precursor and a second scale precursor, wherein the first and second scale precursors react together to form scale; (ii) stopping the introduction into the reservoir of the mixture and shutting in the well for 2-24 hours; and (iii) introducing into the reservoir, via a well, a further mixture comprising a scale inhibitor, a first scale precursor and a second scale precursor, wherein the first and second scale precursors of the further mixture react together to form scale.

2. A method as claimed in claim 1, wherein the scale inhibitor, the first scale precursor and the second scale precursor of the mixture are the same as the scale inhibitor, the first scale precursor and the second scale precursor of the further mixture, respectively.

3. A method as claimed in claim 1, wherein the first scale precursor of the mixture is a soluble inorganic salt of one of a Group 1 metal and ammonium.

4. A method as claimed in claim 3, wherein the salt is selected from the group consisting of: a sodium, potassium or an ammonium sulphate.

5. A method as claimed in claim 3, wherein the salt comprises an ammonium cation.

6. A method as claimed in claim 5, wherein the salt is ammonium sulphate.

7. A method as claimed in claim 1, wherein the steps (ii) and (iii) are repeated at least once.

8. A method as claimed in claim 1, wherein the step (ii) of stopping the introduction into the reservoir of the mixture lasts for from 4 to 12 hours before step (iii).

9. A method of abandoning a zone in a reservoir, the method comprising the step of introducing to the reservoir, via a well, a mixture comprising a scale inhibitor, a first scale precursor and a second scale precursor, wherein the first and second scale precursors react together to form scale; wherein the first scale precursor comprises ammonium sulphate.

10. A method as claimed in claim 1, which is a method of abandoning a well in the reservoir.

11. A method as claimed in claim 1, wherein a stream of water is spiked with the scale inhibitor, the first precursor and the second precursor of the mixture and the stream of water and mixture are introduced into the well together.

12. A method as claimed in claim 11, wherein the water is at least one of sea water, produced water and oilfield brine.

13. A method as claimed in claim 12, wherein the water comprises sea water.

14. A method as claimed in claim 11, wherein the scale inhibitor of the mixture is spiked into the stream of water before the first and second scale precursors of the mixture.

15. A method as claimed in claim 14, wherein the first scale precursor of the mixture is spiked into the stream of water before the second scale precursor of the mixture.

16. A method as claimed in claim 1 wherein the second scale precursor of the mixture is a soluble inorganic salt of a Group 2 metal.

17. A method as claimed in claim 16, wherein the salt is selected from the group consisting of a calcium halide or nitrate.

18. A method as claimed in claim 17, wherein the salt calcium chloride.

19. A method as claimed in claim 1, wherein the scale inhibitor is selected from the group consisting of: a carboxylic acid, a carboxylate, an acrylic acid, an acrylate, a phosphonate, a phosphonic acid, a sulfonate, a sulfonic acid, a maleic acid, a maleate, an aspartic acid, an aspartate, a polysaccharide and a polyvinyl, or a derivative, polymer, copolymer thereof, or combinations thereof.

20. A method as claimed in claim 1, wherein the method further includes a pre-treatment step of flushing the well, prior to step (i).

21. A method as claimed in claim 1, wherein the well comprises tubing, and the method further includes a step of displacing the mixture from the tubing, subsequent to step (i) and prior to step (ii).

22. A method as claimed in claim 1, wherein the method further includes the step of at least partially filling the well with cement.

23. A method as claimed in claim 1, wherein the well has perforations therein, and the method further includes the step of at least partially blocking the perforations with a yet further mixture.

24. A method as claimed in claim 23, wherein the further mixture comprises one or more of silicone, a vinyl silicone, a vinyl terminated silicone, polydimethylsiloxane, vinyl polydimethylsiloxane, a fumed silica, a silica flour and a siloxane.

Description

[0096] Embodiments of the present invention will now be described by way of example only and with reference to the accompanying figures, in which:

[0097] FIG. 1 is a cross-section of a hydrocarbon reservoir;

[0098] FIG. 2 is a graph of scale inhibitor concentration in a reservoir;

[0099] FIG. 3 is a schematic diagram of the method of treating a well in a reservoir

[0100] FIG. 4 is a schematic of a typical core flood apparatus;

[0101] FIG. 5 is a plot of differential pressure versus pore volume for a first coreflood experiment; and

[0102] FIG. 6 is a plot of differential pressure versus pore volume for a second coreflood experiment.

[0103] FIG. 7 is a plot of effective differential pressure versus pore volume for a third coreflood experiment.

[0104] FIG. 8 is a plot of differential pressure versus pore volume for a specific part of the third coreflood experiment.

[0105] FIG. 1 shows a well 10 in a hydrocarbon reservoir 12. The hydrocarbon reservoir 12 has outer boundaries 14. Calcium chloride, sodium sulphate and a scale inhibitor are injected into the reservoir 12 to form scale 16.

[0106] A silicone 18 may be added into the well 10 to block the perforations in the well 10 and the well may be plugged with cement 20.

[0107] During the step of injecting the material into the reservoir to form calcium sulphate, the material initially passes into the most permeable sections of the reservoir. Calcium sulphate scale forms and the remaining material is diverted into other zones. At the same time the scale inhibitor adsorbs onto the surfaces of the rock (not shown) of the reservoir, increasing the tendency of the remaining material to form calcium sulphate scale due to a reduced amount of scale inhibitor in the material.

[0108] The quantity of calcium sulphate scale required to form a block in the reservoir can be considerable. To treat a 100 metre interval with a porosity of 25% such that scale forms a skin that is 50 cms thick from the well bore, requires 19.6 m.sup.3 of scale to be deposited. It is not necessary to fill the whole pore space but rather to block the pore throats to mitigate fluid movement and/or reduce the effective permeability of the reservoir.

[0109] All fluid flow in a reservoir goes through the pores and pore throats of the reservoir rock. The pore throats are small gaps joined up by pores in the rock, through which the fluid passes. The fluid flow path is often tortuous. The ease with which fluid passes through a rock and therefore the pores and pore throats is known as its permeability.

[0110] The flow of fluid can be prevented by blocking the pore throats or by increasing the viscosity of the fluid passing through the pore throats. Because the pore throats are relatively narrow, a comparatively small amount of material in a pore throat can result in a significant amount of damage to the reservoir and therefore reduction in the overall permeability or ability of fluid to flow through the reservoir. If sufficient damage to the reservoir can be induced in the formation of the well, fluid in the reservoir is typically isolated and therefore cannot reach the well.

[0111] FIG. 2 is a graph of scale inhibitor concentration in a reservoir. The x-axis is time and the y-axis is inhibitor concentration.

[0112] The line on the graph of FIG. 2 presents a scaling boundary, that is when scale is produced 40 and when no scale is produced 42. Any point on the line represents a time at which precipitation of scale occurs at a given concentration of scale inhibitor at a given temperature.

[0113] By adjusting the scale inhibitor concentration, the time at which scale is formed and so the point in the well that scale precipitates, can be controlled. It is important that scale does not form in the well bore but only in the formation of the reservoir.

[0114] The method of abandoning the well 10 in the hydrocarbon reservoir 12, as shown in FIG. 3 includes mixing calcium chloride, sodium sulphate and a scale inhibitor to form a material; and injecting the material into the reservoir to form calcium sulphate.

[0115] FIG. 3 shows a source of water 30, typically filtered injection quality seawater in offshore locations. This is pumped into the well 10 to be treated via a manifold 32.

[0116] In one embodiment, a scale inhibitor 4 is dosed or spiked into the stream of water at a concentration of from 0.5 to 2.0 percent. The fluids pass through an inline mixer 3 and then dosed/spiked with a saturated solution of a sulphate brine 6, in this embodiment a sodium sulphate brine containing 139 g/ltr sodium sulphate, such that a concentration of from 0.5 to 1.0 Molar solution of sulphate ions is created in the water. The fluids are then passed through a second inline mixer 3 and then dosed/spiked with saturated calcium chloride containing 745 g/ltr calcium chloride 5 brine such that a concentration of from 0.8 to 1.2 Molar calcium ions is created in the water. The whole mixture of brines scale inhibitor and seawater is then injected into the well at a pump rate set such that the time taken from point of mixing to entry into the reservoir is less than the time taken for the waters to scale.

[0117] In an alternative embodiment, a scale inhibitor 4 is dosed/spiked into the stream of water at a concentration of 0.1-2.0%. The fluids pass through an inline mixer 3 and are then dosed/spiked with a saturated solution a sulphate brine 6, in this embodiment an ammonium sulphate brine containing 239 g/ltr ammonium sulphate such that a concentration of from 0.5 to 1.0 Molar solution of sulphate ions is created in the water. The fluids are then passed through a second inline mixer 3 and then dosed/spiked with saturated calcium chloride containing 299 g/ltr calcium chloride brine 5 such that a concentration of from 0.8 to 1.2 Molar calcium ions is created in the water. The whole mixture of brines scale inhibitor and seawater is then injected into the well at a pump rate set such that the time taken from point of mixing to entry into the reservoir is less than the time taken for the waters to scale.

[0118] Introduction of the scale inhibitor into the water before the scale precursor solutions is preferred as this can mitigate scale formation due to interactions between the precursor sulphate ions with ion already present in seawater. Pumps 2 may be referred to as dosing pumps.

[0119] The scale inhibitor may be added to the sulphate brine, but is typically added separately as described above.

[0120] The rate and therefore the location of scale formation within the reservoir can be controlled by making adjustments to the scale inhibitor concentration, the molar concentrations of either calcium or sulphate ions or the overall pump rate.

[0121] The method may also include injecting into the reservoir a dilute solution of an acid such as hydrochloric acid, formic acid, acetic acid and/or citric acid. The dilute solution of acid is at a concentration of from 0.25 to 5%.

[0122] The dilute solution of an acid is injected into the reservoir prior, sometimes just prior, to scale inhibitor treated scaling waters. The subsequent scale inhibitor treated scaling waters mix with the dilute solution of an acid and on contact therewith this lowers the pH of the scale inhibitor treated scaling waters thereby rendering the scale inhibitor inactive and accelerating the scaling process.

[0123] In an alternative embodiment, one of the brines, ideally the second calcium containing brine 5 maybe pumped via coiled tubing with remaining fluids injected at the well head into the production tubing 8 such that mixing of fluids and the commencement of scale formation occurs across the perforated interval 9 and scale is formed within the reservoir. Assuming a porosity of 25%, this equates to a volume of approximately 400 litres of each brine per metre of reservoir interval. Both brines are filtered and scale inhibitor is added to both at a concentration sufficient to prevent scale formation. This concentration is determined by a series of experiments and may vary depending on the conditions of the well.

[0124] Further alternatively, the dilute solution of acid can be pumped into the reservoir formation before the brines 6 and 5 and before the scale inhibitor 4. When the brines 6 and 5 contact the dilute solution of acid the pH of the brines 6 and 5 is reduced, thereby rendering the scale inhibitor ineffective. Yet further alternatively the dilute solution of acid can be pumped into the well after the brines 6 and 5 or some of the dilute solution of acid can be pumped into the well before and some after the brines 6 and 5. Fluid is pumped into the reservoir until a back pressure builds up indicating that the permeability of the reservoir is significantly reduced or the back pressure does not exceed the fracture pressure of the reservoir

[0125] Experiments were used to determine the time it took for the formation scale using different sulphate salts as the first scale precursor and with the addition of different scale inhibitors.

[0126] Initially, the experiments were carried out using sodium sulphate and calcium chloride as the scale precursors, with either Bellasol S50, a polyphosphinocarboxylate polymer scale inhibitor, or Briquest 543-45AS, a diethylenetriaminepenta acetic acid based phosphonate scale inhibitor. It was then discovered that using ammonium sulphate instead of the sodium scale may be advantageous for offshore applications and, consequently, further experiments were performed using ammonium sulphate and calcium chloride as scale precursors, with Dequest 2066A as the scale inhibitor.

[0127] Experiments using sodium sulphate:

[0128] The experiments were repeated at various Bellasol S50 and Briquest 543-45AS inhibitor concentrations and at a pH of 7 and 4 respectively. A plastic cup was placed onto of a white sheet of paper with a black cross drawn on it, allowing the formation of calcium sulphate to be evaluated by the disappearance of the cross. 10 ml of the CaCl.sub.2 solution and 10 ml of Na.sub.2SO.sub.4/inhibitor solution were measured and placed into the plastic cup. As soon as the brines were mixed together a timer was started.

[0129] Photos were taken every 30 minutes until the cross was no longer visible. It was however possible to observe a clear development in the formation of scale. In a pre-scaled cup the cross was completely visible. During the progression of scale formation, there was a reduction in visibility of the cross due to low levels of scale formation. A completely hidden cross indicated that the inhibitor had become completely ineffective and scale had fully formed. After 24 hours, the solution was filtered and the precipitate was weighed to determine the mass of calcium sulphate that had formed.

[0130] Tables 1a and 1b below show inhibition times, that is how long the formation of scale is inhibited using various concentrations of Bellasol S50 and Briquest 543-45AS.

[0131] M in tables 1a and 1c means Molar

TABLE-US-00001 TABLE 1a Blank Low level Calcium Full sulphate Scale Mass of Inhibitor Volume Volume Formation Formation precipitate Concentration Na.sub.2SO.sub.4 CaCl.sub.2 Time Time after 24 (ppm) (ml) (ml) (mins) (mins) hours (g) 0 10 10 0 55.0 Bellasol S50 Low level Mass of Calcium precipitate sulphate after 24 Inhibitor Conc. Conc. Formation Full Scale hours (g Concentration Na.sub.2SO.sub.4 CaCl.sub.2 Time Formation per litre (ppm) (M) (M) (mins) Time (hrs) fluid) 5,000 1.0 1.0 30 24 42.5 25,000 1.0 1.0 90 24 40.5 50,000 1.0 1.0 120 24 41.0 75,000 1.0 1.0 180 24 41.5 100,000 1.0 1.0 240 24 44.5 Briquest 543-45AS Low level Mass of Calcium Full precipitate sulphate Scale after 24 Inhibitor Conc. Conc. Formation Formation hours (g Concentration Na.sub.2SO.sub.4 CaCL.sub.2 Time Time per litre (ppm) (M) (M) (mins) (mins) fluid) 5,000 1.000 1.000 30 28.5 10,000 0.739 1.06 40 50 25,000 1.000 1.000 90 16.0 50,000 1.000 1.000 720 12.5 100,000 1.000 1.000 2880 11

TABLE-US-00002 TABLE 1b Blank Low level Calcium Full sulphate Scale Mass of Inhibitor Volume Volume Formation Formation precipitate Concentration Na.sub.2SO.sub.4 CaCl.sub.2 Time Time after 24 (ppm) (ml) (ml) (mins) (mins) hours (g) 0 10 10 0 1.1 Bellasol S50 Low level Calcium Full Scale Mass of Inhibitor Volume Volume sulphate Formation precipitate Concentration Na.sub.2SO.sub.4 CaCL.sub.2 Formation Time after 24 (ppm) (ml) (ml) Time (mins) (hrs) hours (g) 5,000 10 10 30 24 0.85 25,000 10 10 90 24 0.81 50,000 10 10 120 24 0.82 75,000 10 10 180 24 0.83 100,000 10 10 240 24 0.89 Briquest 543-45AS Low level Calcium sulphate Full Scale Mass of Inhibitor Volume Volume Formation Formation precipitate Concentration Na.sub.2SO.sub.4 CaCL.sub.2 Time Time after 24 (ppm) (ml) (ml) (mins) (mins) hours (g) 5,000 10 10 30 0.57 25,000 10 10 90 0.32 50,000 10 10 720 0.25 100,000 10 10 2880 0.22

TABLE-US-00003 TABLE 1c CaCl2 Na2SO4 Inhibitor Hazying Scaling Weight (M) (M) (%) (mins) (mins) (g/100 ml) 1.06 0.739 0 0 0 6.19 1.06 0.739 0.75 12 15 0.5

[0132] A concentration range of inhibitor from 5000 ppm (0.5%) to 100,000 ppm (10%) was used throughout.

[0133] 100 ml of each inhibitor concentration was prepared. Appropriate volumes of inhibitor were measured into a volumetric flask and made up to 100 ml with Na.sub.2SO.sub.4. Inhibitors were only added to the Na.sub.2SO.sub.4 solution due to both being insoluble in CaCl.sub.2. The pH of each of inhibitor stock solutions was altered accordingly, see Table 2 below.

TABLE-US-00004 TABLE 2 Inhibitor (ppm) Buffer solution pH Required Bellasol S50 NaOH 7 Briquest 543-45AS NaOH 4 Dequest 2066A NaOH 4

[0134] Tables 1a and 1b show that when no inhibitor is applied to the Na.sub.2SO.sub.4 brine, and the brine is then mixed with CaCl.sub.2, the solution becomes fully scaled instantly. When either inhibitor is added to the Na.sub.2SO.sub.4 brine, the formation of calcium sulphate is initially postponed. When the Bellasol S50 is added, scale production is in two stages. Stage one involves the inhibitor retarding the growth, but not being able to completely block the development of, the crystals. This is illustrated by the formation of low levels of calcium sulphate. As time progresses stage two involves the inhibitor becoming less effective and becoming consumed in the growth of the crystal lattice. This is represented by a change from the large crystals into smaller, more stable crystals of calcium sulphate.

[0135] It was noted that, in the examples where calcium chloride and sodium sulphate were equimolar, the Briquest 543-45AS inhibitor never allowed the final crystal structure of calcium sulphate to be achieved and only allowed low levels of calcium sulphate to be formed. This indicates that the inhibitor could have been irreversibly adsorbed at the active growth sites of the calcium sulphate scale crystals, resulting in complete blockage, halting the production of the smaller more stable crystals of calcium sulphate. Use of a reduced concentration of sodium sulphate and a slightly increased concentration of calcium chloride resulted in a large gain in scale precipitation, to levels above those seen for Bellasol S50.

[0136] Tables 1a and 1b show that both inhibitors postponed the formation of calcium sulphate for different lengths of time dependant on their concentration. A general trend was that as the concentration was increased, the time taken for the calcium sulphate scale to form also increased. The Bellasol S50 inhibitor prevented the growth of calcium sulphate from 30 minutes to 240 minutes whilst the Briquest 543-45AS inhibitor could inhibit the growth from 30 minutes to 48 hours, although full scaling was never achieved.

[0137] The mass of calcium sulphate scale produced after 24 hours using both inhibitors is shown in tables 1a and 1b. When compared to the blank sample it was highlighted that the Bellasol S50 inhibitor produced a comparable mass of precipitate. This is compared to the equimolar brine and Briquest 543-45AS inhibitor tests, which produced a considerably lower mass (around 75% less) compared to the blank sample. However, using a lower ratio of sodium sulphate to calcium sulphate greatly increased the scale produced for Briquest 543-45AS. Even so the quantity of scale produced in the inhibited system even after 24 hours was between 5 and 7 g/ltr compared to the blank where a quantity in excess of 60 g/ltr of scale was formed.

[0138] It was shown that the formation of calcium sulphate scale, from solutions of calcium chloride and sodium sulphate, can be controlled between 30 minutes and 48 hours using different scale inhibitors and adjusting the concentration of the inhibitors and the pH.

[0139] A number of laboratory tests have been conducted to investigate the method of abandoning including the stopping step. A widely accepted technique to determine the effect on permeability of injecting fluids into an oil bearing reservoir is to conduct core flood experiments. A piece of reservoir core or sandstone of similar permeability to the reservoir is cut to provide a corea cylinder typically one inch in diameter and between three to six inches long. This core is mounted in a coreflood holder such that fluid can be pumped through the core. Typically fluid is pumped through the core at a steady flow rate, typically using a syringe pump. The pressure differential across the core is measured and this is directly proportional to the permeability of the core. If the pressure differential decreases, permeability is enhanced and the core is stimulated.

[0140] Conversely if the pressure differential increases, permeability is diminished and the core is damaged.

[0141] Fluid that has passed through the core was collected and analysed. FIG. 4 shows a schematic of a typical core flood apparatus.

[0142] The core flood apparatus (50) shown in FIG. 4 has two pumps, pump A (52) and pump B (54). Pump A (52) pumps a calcium brine solution; pump B (54) pumps an inhibitor in sulphate solution (/Sl). The apparatus (50) has a bleed line and valve (56), pressure relief valve (58), pressure transducer (60), display readout (62) and computer (64). A core sample (not shown) is held in the core holder (66) that has twin port plates for face and line cleaning (68). One of the twin port plates for face and line cleaning (68) has a clean/back flush line (70) attached. The outlet line (72) is attached to a flow regulating valve (74) and then a UV analyser (76) and fraction collector (78).

[0143] The following procedure was adopted. The following solutions were prepared: a solution containing 21,000 mg/ltr of calcium by dissolving calcium chloride powder in water to produce a calcium brine; and a solution containing 35,500 mg/ltr of sulphate by dissolving sodium sulphate powder in water to produce a sulphate brine. A quantity of Briquest 543-45AS, a commercially available salt of diethylenetriaminepentamethylene phosphonic acid (DTPMP), a scale inhibitor, was added to the sulphate brine to achieve a concentration of 5,000 mg/ltr of Briquest 543-45AS.

[0144] A core of Berea sandstone was cut and placed into the core holder apparatus. The available pore volume of the core was estimated to be 14 ml. A volume of the sulphate brine containing 5000 mg/ltr of scale inhibitor, equivalent to one pore volume, was introduced into the core and the scale inhibitor adsorbed on the surface. This was followed by three pore volumes of prepared calcium brine mixed with scale inhibitor containing sulphate brine. Pumping was stopped and the mixture was left in the core for a period of five hours, during which time the protection afforded by the inhibitor would have been lost and any scale formed would have precipitated within the core. During this time a pressure differential across the core was determine at 10 psi.

[0145] After five hours flow was recommenced. No change in differential pressure was initially observed and this was as expected since only 0.7 g scale, equivalent to 3% of the pore volume, was estimated to have precipitated. However, once pumping recommenced the differential pressure across the core increased rapidly such that after five pore volumes the pressure exceeded 100 psi.

[0146] FIG. 5 is a plot of differential pressure versus pore volume (PV) for the coreflood. During the initial treatment a differential pressure of about 13 psi was needed to achieve a flow rate of 300 ml/hour or 21 pore volumes (PV's) and there was little evidence of any damage to the core. However, after the core was shut in for five hours and flow restarted, differential pressure build up started to occur almost immediately and within 2 PV's from restarting the differential pressure exceeded 100 psi, activating the pressure relief valve in the equipment. This equates to a reduction in permeability of over eighty percent.

[0147] This was surprising and unexpected and so the test was repeated with a different core. The results are shown in FIG. 6. The results were very similar to the previous core flood experiment with differential pressure exceeding 100 psi. The rapid reduction in permeability was surprising and it was much more rapid and complete than was expected considering only five pore volumes of fluid had been injected, and by calculation only fifteen percent of the total pore volume is occupied by scale.

TABLE-US-00005 TABLE 3a Low level Dequest Conc. Calcium Salt used 2066A Na.sub.2SO.sub.4 sulphate Mass of as first Inhibitor or Conc. Formation precipitate scale Conc. (NH.sub.4).sub.2SO.sub.4 CaCl.sub.2 Time after 24 precursor (ppm) (M) (M) (mins) hours (g) Sodium 10,000 0.739 1.06 40 50 Ammonium 10,000 0.739 1.06 >180 Ammonium 5,000 0.739 1.06 33 60 Ammonium 2,500 0.739 1.06 15

TABLE-US-00006 TABLE 3b Low level Dequest Calcium Type 2066A sulphate Mass of of Inhibitor Conc. Conc. Formation precipitate water Conc. (NH.sub.4).sub.2SO.sub.4 CaCl.sub.2 Time after 24 used (ppm) (M) (M) (mins) hours (g) Fresh 2,500 2.22 2.69 30 20-30 Sea 2,500 2.22 2.69 15 Sea 3,000 2.22 2.69 30 20-30

[0148] Experiments involving ammonium sulphate:

[0149] Further experiments were carried out using ammonium sulphate instead of sodium sulphate as the first scale precursor with an aim to replicate the scaling time observed when using the sodium salt. As before, calcium chloride was used the second scale precursor. Dequest 2066A, a commercially available salt of diethylenetriaminepentamethylene phosphonic acid (DTPMP), was used as the scale inhibitor. The scale inhibitor was modified to have pH of 4 as shown in Table 2.

[0150] As before, the apparatus used comprised a plastic cup placed onto a white sheet of paper with a black cross drawn on it, allowing the formation of calcium sulphate to be evaluated by the disappearance of the cross. 50 ml of the calcium chloride solution and 50 ml of the solution comprising ammonium sulphate and the Dequest 2066A scale inhibitor were measured and placed into the plastic cup. The scale formation process was observed over a period of 24 hours.

[0151] Table 3a shows how the concentration of Dequest 2066A affects the resulting mass of the precipitate formed after 24 hours. It was found that scale formation was more easily inhibited when using ammonium sulphate compared to sodium sulphate. Specifically, the amount of the scale inhibitor required to inhibit the reaction of ammonium sulphate with calcium chloride, and the resulting scale formation, is half of the amount of the scale inhibitor required when using sodium sulphate.

[0152] An advantage of using ammonium sulphate is that it is more soluble compared with sodium sulphate, meaning that higher concentrations of sulphate can be made available. Concentrated brines can be brought to an offshore site and diluted back with seawater before being injected down a well, reducing the total volume of fluids required to be shipped offshore.

[0153] In order to test this approach, the experiment was repeated again, using more concentrated solutions of the scale precursors. The new formulation comprised a 29.3% w/v ammonium sulphate solution and 29.9% w/v calcium chloride solution. Dequest 2066A scale inhibitor was provided as a separate solution rather than being included in the sulphate solution.

[0154] The concentrates were spiked into water in the following order: scale inhibitor, ammonium sulphate, calcium chloride. In offshore applications, the introduction of the scale inhibitor before the scale precursors is important, as it prevents scaling due to interactions between sulphate ions in the scale precursor solution and the ions already present in seawater. In the first trial the concentrates were spiked into fresh water to monitor the scale formation time without the ion interferences of seawater. In the second trial fresh water was substituted with seawater.

[0155] During each trial the relative composition of the final mixture was 1 part concentrate to 2 parts water per solution, meaning 1 part concentrate to 6 parts total volume of the mixture. As a consequence, the concentrations of the scale precursors reduced by a sixth, and that of the scale inhibitor decreased by half, compared with the previous experiments.

[0156] Table 3b shows the resulting mass of the precipitate formed after 24 hours, for both trials, that is using fresh water and seawater, the latter with different concentrations of the Dequest 2066A scale inhibitor.

[0157] It was found that the new formulation using more concentrated scale precursor solutions leads to a substantially the same scale formation time as the initial formulation using the less concentrated solutions, while requiring lower concentrations of the scale inhibitor.

[0158] Finally, a core flood experiment was performed to investigate the new formulation in the method of abandoning a zone or a well including the stopping step. The experiment was carried out using the apparatus as in the previous core flood experiments shown in

[0159] FIG. 4. To simplify the pumping procedure the concentrate solutions were pre-blended such that the volume pumped through pump A (52) comprised 66.0% v/v filtered seawater, 33.4% v/v ammonium sulphate solution and 0.6% v/v pH-modified Dequest 2066A scale inhibitor solution, and the volume pumped through pump B (54) comprised 66.6% v/v filtered seawater and 33.4% v/v calcium chloride solution. The fluids were pumped at equal rates through a core sample.

[0160] The pressure differential across the core measured during the experiment is shown in FIGS. 7 and 8. In both figures the pressure is shown as a function of the pore volume of the fluids pumped through the core. One pore volume is defined as the volume of fluid required to fill the pores in the core. For the core used in the experiment one volume corresponded to 18 ml of fluid.

[0161] The first two sections in FIG. 7 represent pre-flush stages, therefore it was expected that no increase in pressure would be observed. In the first stage of the main treatment (Main T 1), that is the introduction of the mixture of the scale inhibitor and scale precursors, a slight increase in pressure was observed but not enough to block the core. The pumping was then stopped, the core was shut in to allow the solution to form nucleation sites, and the pumping was restarted. After pumping approximately 4 pore volumes of the mixture, no significant increase in pressure was observed. Consequently, the stopping and restarting steps were repeated until such increase was noted. As shown in FIG. 7, during the fifth repetition of the main treatment (Main T 5) the pressure rose steeply reaching a maximum indicative of the complete blockage of the core.

[0162] As the flow rate was gradually reduced over the final two sections of the main treatment (Main T 4 and Main T 5), the y-axis in FIG. 7 shows the equivalent differential pressure instead of the actual differential pressure. As such, the equivalent pressure of 1000 psi corresponds to the actual differential pressure of 120 psi, which was the maximum allowable pressure before the pressure relief valve (58) of the equipment opened.

[0163] FIG. 8 shows the actual differential pressure change as a function of the injected pore volume for the final section (Main T 5) only. The initial value of the pore volume is set to 0 PV in order to clearly show at what stage during the final section the core began to block significantly. The steep rise in pressure begins approximately at 1.5 PV as measured from the beginning of the final section.

[0164] While in this experiment the scale formation sufficient to fully block the core required five repetitions of the main treatment, this would not be necessary under other conditions (including higher temperature, different pump rates, longer residence times, and/or larger/different volume of rock).

[0165] It follows from the above experiments that the new formulation with ammonium sulphate used as one of the scale precursors provides an effective method of abandoning a zone or a well in a reservoir, with comparable scale formation time and reduced amount of scale inhibitor required, even compared with the initial formulation using sodium sulphate. Therefore, the new formulation provides an advantage over the initial formulation for offshore applications as taking concentrated solutions of the scale precursors to site, diluting them back with seawater, adding a scale inhibitor to the diluted brines and mixing in line or just before pumping the fluids into the reservoir is a more practical approach than supplying the mixtures ready to go to the site, owing to the large volumes of fluid required in the latter case. A barrier to flow can therefore be introduced by the simple means of mixing fluids on site and pumping them directly into the reservoir.

[0166] An example treatment composition for offshore applications may include 66.3% v/v filtered injection quality seawater, 16.7% v/v ammonium sulphate solution, 16.7% v/v calcium chloride solution and 0.3% v/v pH-modified scale inhibitor solution (shown in bold in Table 3b). The exact dose rates during application of the method of abandoning a zone or a well in a reservoir may vary depending on a range of factors such as, for example, the tubing volume or maximum pump rate. These variables will dictate the length of time it takes for the fluid to reach the reservoir, and therefore how long a delay is required to onset of scaling.

[0167] Modifications and improvements can be incorporated herein without departing from the scope of the invention.