WO1996037686A1

WO1996037686A1 - Treatment of subsurface hydrocarbon reservoirs

Info

Publication number: WO1996037686A1
Application number: PCT/NO1996/000127
Authority: WO
Inventors: Paul Henry Nadeau
Original assignee: Den Norske Stats Oljeselskap A.S
Priority date: 1995-05-25
Filing date: 1996-05-23
Publication date: 1996-11-28
Also published as: GB2301125B; GB2301125A; GB9510597D0; AU5914596A; CA2225637A1

Abstract

A method for treating a hydrocarbon-bearing rock formation (14). A colloidal suspension is introduced into the formation. An electrical potential gradient established by means of an anode (18) and a cathode (19) which produces osmotic forces which in turn cause stabilisation of the colloid. This increases the mechanical stability of the formation allowing the hydrocarbon material to be extracted while water production and sand production is suppressed.

Description

TREATMENT OF SUBSURFACE HYDROCARBON RESERVOIRS

The present invention relates to the treatment of subsurface hydrocarbon reservoirs, for example, hydrocarbon reservoirs in poorly consolidated measures, such as sands. The techniques are particularly (though not exclusively) applicable in the case of secondary production and/or when the hydrocarbon product to be recovered is relatively viscous, though they may will be applicable in certain primary production operations.

Ordinarily, hydrocarbon reservoirs in poorly consolidated sands are susceptible to instability and sand production problems. The onset of sand production is often not observed until the onset of water production, however. Even poorly consolidated reservoirs are often capable of sand free production during the early operational stages, that is, when the reservoir is at irreducible water saturation and the relative permeability of, for example, oil to water is close to unity. As production depletes the reservoir of hydrocarbons, the water saturation increases and water production begins, often with reservoir instability and sand production.

Currently, methods for controlling sand production include the deployment of a screen, or filter in the form of a gravel pack, to prevent the unstable material from entering the production well. These measures do not, however, control the production of watering, or other related problems including scale formation, fines migration, and corrosion. The cost of water production and its associated problems is substantial. Large amounts of water must be treated and pumped at high pressure via injection wells to maintain reservoir performance and fluid flow. Produced water must also be treated and disposed of. The precipitation of chemical scale, often in the form of barium and strontium sulphates, damages and contaminates production wells and equipment. The removal and disposal of scale, contaminated equipment, and produced water is costly and environmentally undesirable. Therefore, the benefits afforded by these conventional methods are, in many cases, less than satisfactory.

One technique which has been proposed to enhance oil recovery from porous rock measures is electro-osmosis. This is described for example in US Patent No.s 2799641, 3417823, 3724543, 3782456 and 4645004. Essentially, the electro-osmosis actually involves applying a DC potential within the production interval. While this can in theory improve oil recovery, it does not in itself address the difficulty of sand and water production and its associated problems. Electro-osmosis is apparently not used in practice.

It is therefore an object of the present invention to enhance the recovery of hydrocarbons from subsurface reservoirs where water and/or sand production are problematic.

It is a further object of the invention to minimise the problems of corrosion, contamination and scale associated with water production.

Civil engineers have long used electro-osmotic stabilisation (EOS) techniques on surface clay-rich soil materials which pose instability problems during construction operations. This is addressed for example in US Patent No. 2099328 and in Casagrande L. 1952 Electro-Osmotic Stabilisation of Soils, Boston Society of Civil Engineers Journal Vol. 39, pp 51-83. However, based on the theoretical calculations in the Casagrande article, reservoir sandstones would not be expected to respond to EOS due to their substantial hydraulic conductivities and low surface areas, relative to clay- rich soils.

According to the present invention, a method for treating a hydrocarbon bearing rock formation comprises introducing into the formation a colloidal material such as clay and stabilising the colloidal material as a gel in an aqueous phase in the formation by applying an electrical potential gradient.

It should be appreciated that the prospect of deliberately introducing clay or particulate material into a hydrocarbon reservoir would be considered by persons skilled in the art to be quite undesirable, because the clay particles introduced would be expected to clog the pores in any production interval. Surprisingly, however, when specially prepared colloidal material such as clay/water suspensions are used, this has been found not to be the case. In accordance with the invention, the applied electrical potential produces osmotic forces which cause stabilisation of the colloid. This increases the mechanical stability of the sand in the reservoir and decreases the relative permeability of the formation to water, with the result that water production can be substantially reduced or eliminated. Consequently, the relative permeability to the hydrocarbon is increased.

Preferably, the colloidal material is introduced in the form of an aqueous dispersion, for example, a clay- water suspension. Suitable clay-water suspensions are described in US Patent No. 4687521 in the name of P Nadeau, and in Nadeau P H 1987 Clay Particle Engineering: A Potential New Technology with Diverse Applications; Applied Clay Science Vol 2 pp 83-93. Preferred suspensions include aqueous suspensions of smectite, suspensions in which the weight ratio of smectite to interstratified clay exceeds 1:1, and suspensions similar in composition to Examples 11 to 21, particularly Examples 16 to 21 in US Patent No. 4687,521.

The introduction of colloids, such as the clay-water suspensions of the Nadeau article into sand reservoirs increases the electro-osmotic to hydraulic conductivity ratio (k_e/k_h) in such a way that they can respond significantly to EOS. The introduction of highly dispersed clay particles with large negatively charged surface areas and exchangeable cations, alters the reservoir water phase properties so that electro-osmotic forces may significantly influence water behaviour. It is important that the clay-water colloids be formulated such that they have acceptable injectivity properties. Furthermore, they must be chemically stable and compatible within the reservoir system.

Preferably, the clay particle content in the suspension is from 1 to 20 g/1, preferably 5 to 15 g/1, more preferably 10 to 13 g/1 for example between 11 and 12 g/1. Suspensions similar in composition to Examples 19-21 in the Nadeau article, have been tested under a variety of laboratory and sandstone core flood conditions. These suspensions have been prepared by Na⁺ saturation, with clay concentrations, of 11.1-11.8 mg/ml, pH values of 7.30-7.52, a viscosity of approximately 2 cp, and residual Cl^" of 2.2-7.1 mg/1. Results demonstrate good injectivity characteristics prior to EOS, and efficient gel formation by the application of potential gradients of 1-4 volts/cm over experimental distances of 7.5-10.5 cm.

By EOS of colloidal films along sand grain boundaries, the mechanical stability of reservoirs so treated can be substantially increased. Practical application of this effect in poorly consolidated subsurface sandstone reservoirs tends to minimise or eliminate sand production.

Preferably, a chemical agent, such as a surfactant can also be introduced in order to form oil-wet pathways through the stabilised colloids. This may facilitate the movement of oil from the reservoir into a production well.

It is known from, for example, US Patent Nos. 3724543, 3782465 and 4645004 to arrange electrodes in an oil-bearing formation and to apply a voltage thereby causing a current to flow. One of the primary objects in these cases has been to raise the temperature of the oil in the formation in order to render it more mobile. In the present invention, there is no need to raise the temperature and accordingly, less electrical power is likely to be required.

Preferably, the electrical potential is a DC potential, though a pulsed potential may be applied. It is preferably applied by means of an array of at least two electrodes extending into the appropriate rock formation. The anode may be at the location of a production well and the cathode may be a specific electrode at a distant location.

Typically, the spacing between the electrodes might be from 1 to 50 m, more conveniently from 2 to 20 m, for example, about 5 m. The necessary electrical potential to be applied would depend upon various factors, such as reservoir porosity, water saturation and oil viscosity, but would normally be between 5 and 500 volts per metre. Preferably, the applied potential would be from 50 to 400 v/m, for example, about 200 v/m

An important factor in the case of the present invention is that once gel formation has occurred it may not be necessary to continue to apply the voltage at the same level as was necessary to establish the gel because it is believed that the gel will show an inherent stability.

Preferably, therefore, after establishment of the gel, the voltage (and current) is reduced or even removed altogether. Preferably the voltage is reduced to 10% to 20% of the peak voltage.

Naturally, the present invention is applicable to the use of several electrodes (both anodes and cathodes) and in situations where there may be several production wells.

Another important and beneficial feature of reservoirs treated in accordance with the invention relates to water production control.

During the production life of most reservoirs, water saturation increases such that produced water volumes are considerable. In these circumstances, the reservoir can be considered to have excess fluid production capacity, relative its hydrocarbon saturation. The presence of stabilised colloids reduces the absolute permeability of the reservoir, but in preferential and economically desirable ways.

By its distribution along the sand grain boundaries, the stabilised colloidal gel reduces the water-producing production portion of the permeability network. Furthermore, the amount and type of the introduced colloids, as well as the current density and configuration of the electric field, can be regulated such that the relative permeability of the reservoir to hydrocarbons (which do not respond significantly to electro-osmosis with respect to the aqueous phase) is favourably maintained or increased. In this way, the treated zone around a production well behaves as a semi- permeable membrane, so that produced water volumes are commensurably reduced or eliminated. This is achieved despite the high water saturation state of the reservoir, which ordinarily would be expected to produce at a high and ever increasing 'water-cut' .

It may not be immediately apparent how the introduction of a water suspension with clay concentrations of 1% can so alter the response of sandstones to EOS. This is explained by the fact that colloidal clay materials have total surface areas up to approximately 760 m²/g. By comparison, fine sand has negligible surface area (about 0.02 m²/g) . According to P H Nadeau (Clay Particle Engineering [1987] - see above) , when the water phase content in the suspensions described herein is distributed over the total clay surface area, the average water thickness is approximately 100 nm. This distance is well within the influence of EOS for their electrolyte concentrations (as taught by Casagrande) .

When introduction of these suspensions into hydrocarbon reservoirs is considered, the desirability of maintaining a buffer between the suspension and saline formation waters is evident. This can be achieved by standard practice, for example by means of suitable reservoir preflush treatments.

Laboratory experience indicates that after introduction of the suspension to the reservoir, when saline waters do come into contact with the clay suspension the effect will be to form a distal gel barrier at the suspension/saline water interface. This will further increase resistance to the passage of saline water into the production well. Furthermore, as the hydrocarbons move towards one electrode, for example, the anode, there will be an osmotic pressure against the water in that direction.

In order to act as an effective semi-permeable membrane to control water production, the current density and osmotic pressure within the stabilised colloidal film must fractionally offset the pressure gradient which is driving fluid production. This is the difference between the reservoir pressure and the well flowing pressure, referred to as the draw down. Draw down pressure gradients towards production wells are logarithmic, such reservoir pressures are usually achieved approximately 2 to 5 m away from the well. Therefore, EOS must be particularly effective in this region.

Simple electrode configurations achieve maximum effectiveness under a fixed range of production and draw down conditions. In some cases it may simply be necessary to employ a single positive electrode, for example the screen at the production well, which may be plated with a suitable metal such as copper. This may be particularly so far sandstones, though if the reservoir is in carbonate measures, then it may be more preferable to charge the screen negatively and to use positively charged clay particles.

Radial and vertical compound electrode configurations can achieve maximum control under more variable production conditions. Multi-well configurations are most efficient to control the approximate 10^"4 cm/sec water front flood velocity in a typical reservoir, given that the electro-osmotic conductivities for dispersed clay-water colloidal gels are also of the order of 10^"4cm for nominal potential gradients of 1-4 volt/cm. In multi-well configurations, the use of cements formulated with conductive materials, such as graphite or metallic compounds, may be used to facilitate electrical contact with the reservoir. Under favourable conditions, the positive electrode may be configured at or near the well production face of the reservoir interval, with the negative electrode some distance away or the current may be simply grounded to a suitable earth.

Laboratory experiments have demonstrated that graphite, silver, steel, stainless steel, and iron can serve as electrode materials, and that aluminium, copper, and their alloys such as brass, are particular well suited with regard to stabilised gel formation efficiency, strength and uniformity. For colloidal clays with predominantly negatively charged surfaces, gel formation occurs in the vicinity of the positive electrode. However, in some cases, it may be desirable to use a mixture of negatively and positively charged clays. Then, the positively charged particles will migrate away from the positive electrode. This, together with hydrated cation movement, will tend to resist water movement forwards the positive electrode and may serve to establish a positive clay particle gel remote from the positive electrode. Furthermore, the use of positively charged colloidal clays may be particularly desirable in carbonate reservoirs.

Once the reservoir has been treated in accordance with the invention, extraction may continue in any convenient manner, while the electrical potential is maintained. Extraction techniques may include the application of hydraulic pressure through one or more injection wells, which may or may not be at the same locations as the electrodes.

The invention also extends to a method of producing hydrocarbons from a subsurface reservoir which comprises treating the reservoir as described above and extracting the hydrocarbons via a production well. In order to maintain the performance of the treated reservoir during the course of EOS and as oil depletion continues, additional colloidal material may be required in the stabilised zones. This may be facilitated in part by initially injecting the colloids beyond the reservoir zones required for EOS, so that additional material will migrate into these zones as required to maintain effective film thickness. During the course of the production of life of the well, however, it may be necessary to inject additional colloids into the reservoir to maintain adequate water production control.

Overall, the combined effects of the invention on enhanced sand stabilisation and water production control significantly reduces operational costs and increases well life. In this way, the volumes of economically recoverable hydrocarbons from the reservoir interval are substantially increased. The beneficial effects are particularly important for offshore hydrocarbon fields, given the otherwise high costs of produced water management and treatment, and these effects are achieved in a way which is not in any way harmful to the environment.

The effects invention will now be further illustrated with reference to the following experimental test results.

Test 1

A 3.8 cm diameter core of Bentheimer sandstone 7.5 cm in length was flooded with water and a suspension of smectite clay was introduced (11.2 mg solids per ml water) . The core had a porosity of 22%. A voltage of 30v was applied between the ends of the core resulting in a maximum current of 3 m A. The voltage was applied for 30 hours. This resulted in the formation of a gel and a consequent reduction in permeability of 98% at a constant flow rate of water.

Test 2

Test 1 was repeated using a 1:1 oil/water flood. Again a clay suspension was introduced but in this case the clay was four parts smectite and one part synthetic mica and the concentration was 11.1 mg solids per ml water. The maximum current was 0.8 mA. Over a period of 20 hours, the produced oil/water ratio increased by 20% at a constant overall oil/water flow rate.

Test 3

This test examined the effect of the electrodes material on gel formation. The test used a cell in the form of a rectangular container containing a clay suspension to a depth of 2.5 cm though sand was also present in EOS-4 and EOS-15. The cell was 7.5 cm long and 5 cm wide in all cases except EOS-15 in which a cell 10.5 cm long and 7.5 cm wide was used. The applied voltage was 7.5v in all cases except EOS-15 in which the applied voltage was 10.5v.

In all cases, a gel formed at the anodes which remained stable even after the applied voltage was disconnected. In EOS-4 and EOS-15, gel formation had the effect of consolidating the sand present, at the anode end of the cell.

The results are summarised in Table 1.

/NO96/00127

12

The invention may be carried into practice in various ways and some embodiments will now be described by way of example, with reference to the accompanying drawings, in which:-

Figure 1 is a schematic view of an installation suitable for carrying out the present invention;

Figure 2 and 3 are views similar to Figure 1 showing alternative arrangements;

Figures 5, 6 and 7 are schematic diagrams of three different electrode arrangements; and

Figure 8 is a plan view of one embodiment of a multi-well/multi-electrode arrangement.

Figure 1 shows an offshore platform 11 with a production borehole pipeline 12 extending down through an overburden 13 of various measures and into an oil-bearing sandstone stratum 14. The platform 11 has a DC power source 15, a pump 16 and a source of colloidal suspension

17, in this case smectite clay in water.

The borehole pipeline 12 has a pair of electrodes

18, 19 within the stratum 14 and between the electrodes 18, 19, a perforated section 20. The electrodes 18, 19 are connected to the positive and negative terminals of the power source 15 so that terminal 18 represents an anode and terminal 19, a cathode, though other arrangements would be quite possible. In many cases, it may be desirable to complete the perforated section so that the production base is adjacent the conductive material, such as conductive cement or a screen liner, which could also serve as an electrode.

In use, the colloidal suspension of clay in water is pumped from storage 17 down the pipeline 12 and into the oil-bearing stratum 14. The suspension distributes throughout the aqueous phase in the stratum 14 in the vicinity of the pipeline. After distribution, the power 13

source 15 is energised, the electrodes 18, 19 become charged, and a potential gradient is established between the electrode 18, 19 (and possibly 20) .

The potential gradient stabilises the suspension through the osmotic forces which are set up and a gel is formed. Oil is then extracted via the perforated section 20 of the pipeline 12, while sand and water production are suppressed.

Figure 2 shows an offshore platform 21 with a production borehole pipeline 22 extending down through an overburden 13 of various measures and into an oil-bearing sandstone stratum 14. The platform 21 has a DC power source 15, a pump 16 and a source 17 of colloidal suspension of clay in water.

The platform 21 also has an injection pipeline 23 extending into the oil-bearing stratum spaced from the production pipeline 22, a pump 24 and a source 25 of a suitable water phase.

The production pipeline 22 has a perforated section 26 within the oil-bearing stratus 14. The positive terminal of the power source 15 is connected to the perforated section 26, which thus constitutes the anode. The negative terminal of the power source 15 is connected to the injection pipeline 23 (though this may not be necessary) .

In use, the colloidal suspension is introduced into the stratum 14 by the pump 16 via the production pipeline 22 and distributes itself in the vicinity of the wellbore in the oil-bearing stratus 14. The power source is energised, a potential gradient is established, the colloidal suspension stabilises and a gel is formed. The oil is then extracted via the perforated section 26. In order to enhance the recovery, a suitable water phase is pumped down the injection pipeline 23. Naturally, more than one injection pipeline 23 can be employed.

Figure 3 also shows a production platform 32 having a production borehole pipeline 32 extending down through the overburden 13 into the oil a bearing stratum 14. In this case, however, there is a second platform in the form of an injection platform 35 which has a pipeline 34 extending into the oil bearing stratum 14. The production platform 31 includes pump 16 and a source of colloidal suspension 17, as in the case of the previous embodiment. The second platform 33 is used to inject water into the oil bearing stratum 14. It has a power source 35, a pump 36 and a source 37 of a suitable water phase. The power source 35 has its negative terminal connected to an electrode 38 which is located on the pipeline 34 within the stratum and which thus constitutes a cathode. The positive terminal of the power source 35 is connected via the pipeline 32 to an electrode 39 on the pipeline 32, also within the stratum 14. Thus, the electrode 39 constitutes an anode. In most instances, the water phase injected will be saline and will therefore have a high conductivity. In such cases, the saline water will effectively constitute the cathode.

In use, the colloidal suspension is introduced into the stratum 14 by the pump 16 via the pipeline 33, and distributes itself in the vicinity of the wellbore in the stratum 14. The power source 35 is then energised, the cathode 38 and cathode 39 become charged and a potential gradient is established. As in the previous embodiments, the osmotic forces resulting from the potential gradient stabilise the suspension in the vicinity of the wellbore to form a gel and oil is extracted via a perforated section 40 of the production pipeline 32.

In order to enhance oil recovery, hydraulic pressure is employed. This is achieved by pumping a suitable water phase down the pipeline 34 from the source 37 by means of the pump 36 thus encouraging oil production via the pipeline 32.

Figure 4 shows a preferred arrangement for a production wellbore in an oil-bearing stratum 14. Within a borehole 41, a casing 42 extends down and terminates at a shoe 43 in the cap rock 44 above the oil-bearing stratum 14. A liner 45 is suspended from within the casing 42 from a hanger 46. The bottom part of the liner 45 is a perforated metal screen 47 which is separated from the liner 45 by an electrically insulating joint 48, which may be of any suitable material such as porcelain or a plastics material. An electrical cable 49 from a power source (not shown) is connected to the screen 47. The screen 47 is of stainless steel plated with copper, though other conductive materials can be used. This arrangement can be employed in any of the embodiments illustrated in Figures 1 to 3. In cemented liner and cemented cashing well completions, the above method can be employed using a modified sand production control tool, employing for example an electrically insulated screen as an electrode. The well may also require some modifications, such as electrical insulation of the casing and/or perforated zone.

Various other electrode arrangements can be employed in order to establish a suitable potential gradient. Figure 5 shows a simple arrangement in which an oil reservoir is diagrammatically designated 51. A production pipeline 52 has electrodes 53 and 54 and production perforations 55. Electric current flow lines 56 are shown joining the electrodes 53, 54.

The arrangement in Figure 6 is similar to that of Figure 5 in that a production pipeline 62 extends into a reservoir 61. However, in this case, there are four electrode always at 63, 64, 65, 66 which can be variously arranged as anodes and cathodes. Again there are production perforations 67. The electrodes can be joined by various flow lines 68, depending upon the way in which the electrodes 63, 64, 65 and 66 are charged.

Figure 7 shows a multi-well arrangement. There is a reservoir 71 and a production pipeline 72, as before, which has production perforations 73. However, in this case, the pipeline itself serves as an electrode, possibly using electrically conductive cements. Two (or more) wells 74 extend into the reservoir 71 and serve as additional electrodes. The flow lines for this configuration are designated 75.

Figure 8 shows, in plan a possible multi-well arrangement. The arrangement includes a central production well 81 and, in this case, six electrode wells 82 arranged about the production 81 are in a reservoir area 83. Equi-potential lines are designated 64.

Claims

1. A method for treating a hydrocarbon-bearing rock formation which comprises introducing into the formation a colloidal material and stabilising the colloidal material as a gel in an aqueous phase in the formation by applying an electrical potential gradient.

2. A method as claimed in Claim 1 in which the colloidal material is introduced in the form of an aqueous suspension.

3. A method as claimed in Claim 2, in which the colloidal material is a suspension of clay in water.

4. A method as claimed in Claim 3, in which the clay- water suspension is a combination of smectite and interstratified clay .

5. A method as claimed in Claim 3, in which the clay water suspension comprises smectite.

6. A method as claimed in any preceding claims in which the dispersion comprises from 11 to 12g clay per litre of water.

7. A method as claimed in any preceding Claim in which the electrical potential is a DC potential.

8. A method as claimed in any preceding Claim, in which the electrical potential is a pulsed potential.

9. A method as claimed in any preceding Claim, in which the electrical potential is established by means of an array of at least two electrodes.

10. A method as claimed in any preceding Claim, in which the positive electrode is at the location of a production well.

11. A method as claimed in claim 10, in which the positive electrode is in the form of an electrically insulated screen at the base of a liner in the production well.

12. A method as claimed in any of Claims 9 to 11, in which electrodes include an anode and a cathode, spaced from the anode.

13. A method as claimed in Claim 12, in which the anode and cathode are separated by a distance of between 1 and 50 m.

14. A method of treating a subsurface hydrocarbon- containing reservoir substantially as herein specifically described with reference to and as shown in Figure 1, Figure 2 or Figure 3 of the accompanying drawings.

15. A method for producing hydrocarbons from a subsurface reservoir which comprises treating the reservoir as claimed in any preceding Claim and extracting the hydrocarbons via a production well.

16. A method as claimed in Claim 15, in which a surfactant is also introduced into the oil bearing stratum.

17. A method as claimed in Claim 16, in which the surfactant forms oil-wet pathways through the stabilised colloidal material.

18. A method as claimed in any Claims 15 to 17 in which further additions of colloidal material are made to the oil bearing stratum as the oil is extracted.