NO163376B - PROCEDURE FOR AA REDUCEING THE WATER SUPPLY IN OIL PRODUCTION BURNS. - Google Patents

Abstract

1. Method of reducing the inflow of water in petroleum producing wells of an oil deposit by injecting an aqueous solution of alginates into the water-bearing layers of the deposit, characterized in that an aqueous solution of alginates having an alginate concentration of from 0.1 to 8 g/l is injected into the water-bearing as well as into the oil-bearing layers of the deposit.

Description

The invention relates to a method for reducing the water inflow in oil production wells where an aqueous solution of alginates is injected into the water-bearing layer of the formation. It is particularly suitable for formations with a higher content of divalent cations in the formation water.

With the increasing age of petroleum fields, the amount of water in the produced fluids increases, usually continuously, and eventually reaches such high values that, for economic reasons, transport has to be stopped. The flow of water to the production wells is conditioned by the expansion of the aquifer adjacent to the oil field, or by secondary methods, by water injection into the injection wells.

Depending on the design of the formations, with regard to the water inflow and the methods to be used for its reduction, three cases can be distinguished.

Case 1:

In many formations, only the upper part of the formation is oil-bearing, the lower, on the other hand, is water-bearing, so the formation is underlain by groundwater. Also in the case of homogeneous permeable formations, due to its relatively higher mobility compared to oil, the water usually needs to advance fastest in the lower layer of the formation. After the water breakthrough, a water cone forms around the transport probe with increased oil/water contact, thereby causing a faster increase in dilution.

Case 2:

With greater permeability inhomogeneity of the formations, the water tends to penetrate the mostly strongly highly viscous oil. After water breakthrough in the transport probes, only water soon flows in these layers, while the oil moves in the less permeable layers at small pressure drops only at a reduced speed. Here, too, there is a very rapid increase in the dilution of the probe.

Case 3:

Finally, in most cases the water does not flow from all sides to the transport probes, but after water breakthrough primarily in a small azimuth area, which increases during the transport time.

In a homogeneous layer, the simultaneous flow and oil can be approximately described by the concept of the mobility ratio. The mobility is the quotient of permeability k and viscosity n of the relevant phase, the mobility ratio M is often expressed as the quotient of the water and oil mobilities, i.e.:

with k eff w = effective permeability to water at residual oil content,

H w = water viscosity,

k eff o = effective permeability for oil wood

adhesive water content,

no = viscosity of the oil

Part of the previously known methods refer to the blocking of bottom water (above-mentioned first case). For example, the lower water-bearing part of the formation can be cemented or sealed off with packs in the risers. Advantageous are methods by which clogging of the pore space of the water-bearing layers is achieved up to a few meters into the formation. For this purpose, liquids are injected into the bottom water-bearing part of the formation which after some time form a gel such as water glass solutions, which upon addition of an electrolyte such as hydrochloric acid or ammonium chloride, solidifies into a rigid gel after a certain incubation time. The disadvantage of this method consists in the penetration of the primarily thin-flowing solutions into the oil-bearing layer, these are also sealed and their access is blocked. In practice, such sealing can no longer be done the other way around.

Increased efforts were therefore made to develop methods that inhibit the inflow of water more strongly than the inflow of oil, which according to the above-mentioned equation (1) means that the effective permeability for water, k eff w, is reduced more strongly than the effective permeability for oil, k eff o In US patent 3,308,885, an injection of water-soluble, partially hydrolyzed high molecular weight polyacrylamides is recommended for this application.

German Offenlegungsschrift 23 58 350 describes the use of a mixture of a hydrocarbon solvent, colloidal silicon dioxide, a higher molecular polymer, such as partially hydrolyzed polyacrylamide, a surfactant and water.

According to US patent 3,032,499, the water-bearing layers are selectively blocked by injection of a hydrocarbon solution of an acid addition addition of an N-alkylalkylene polyamine.

Finally, according to US patent 3,721,295, the use of water-in-oil emulsions with finely divided water-soluble vinyl addition polymers is recommended.

Despite intense efforts in the area of water blocking, in practice none of the mentioned methods have proven to be of unlimited use, partly because the occurring water blocking effects were quantitatively too insignificant, partly also because the proposed methods are difficult to implement in practice, resp. were also too expensive. The task was therefore to provide a method which, in all three of the above-mentioned cases of water inflow, is applicable, easy to implement and not too expensive.

This task is solved according to the present invention by means of a method of the nature mentioned at the outset, the characteristic features of which appear in claim<*> 1. Further features of the invention appear in the other non-independent claims.

Preferably, an alginate solution with a concentration of 0.5-5 g/l is injected.

According to an embodiment according to the invention, an alginate solution is injected into the formation which, as a means of delaying gel formation, contains chemicals which form gels with polyvalent cations. As such agents for delaying the gel formation, complex phosphate, especially sodium hexametaphosphate or sodium tripolyphosphate, can be used, especially in a concentration of 0.1-10 g/l and preferably 0.5-2 g/l.

The treatment with alginate solution is preferably carried out in several stages, with salt water containing at least 2 g/l polyvalent ions being injected alternately with the alginate solution. Thus, alginate solutions and polyvalent cation-containing salt solutions can be injected separately from each other using a buffer of water or salt water with only monovalent cations. According to a further embodiment, a solution of sodium algalnate, salt water with only monovalent cations and salt water containing at least 2 g/l multivalent ions is injected into the formation alternately.

Alginates are alkali salts of alginic acid extracted from algae, a linear copolymer of D-mannuronic acid and L-guluronic acid with molecular weights approx. between 30,000 and 150,000 g/mol.

At concentrations up to 8 g/l and especially below 5 g/l, the aqueous solutions of sodium alginates are still relatively low-viscosity and can also be easily injected into formations with low permeability. When forming a network with polyvalent cations, alginates form gels. This ratio can be exploited in formations whose water, in addition to alkali salts, also has a certain content of alkaline earth ions such as calcium or magnesium ions. In Central Europe, the largest part of the petroleum fields originate from the Mesozolcum (Valendis, Wealden, Dogger, Lias), as the formation water has a content of alkaline earth ions of over 5 g/l, often even significantly higher. This content is sufficient to cross-link the alginate solutions injected in low-viscosity form into the formation in contact with this water, thereby causing an obstruction to the flow of water. In contact with crude oil, however, no cross-linking takes place.

For delay of. the gel formation, chemicals can be added to the alginate solutions that have a gel-forming effect on the multivalent ions. In practice, for cost reasons, for example, complex phosphates such as sodium hexametaphosphate or sodium tripolyphosphate will be used. Other gelation agents such as nitrilotriacetic acid or its salts, ethylenediaminetetraacetic acid and its salts, as well as essentially the entire range of gelation agents known to those skilled in the art, would also be suitable in this application.

It is already known to carry out bottom water shut-offs selectively, i.e. separately from the oil-bearing layers.

According to DE-AS 10 25 806, salts of alginic acid and/or high-polymer polyacrylates are injected with water-soluble urea-formaldehyde condensate for complete sealing and fixing of formation areas.

According to US patent 3,208,524, to avoid the loss of drilling fluid when drying a borehole, a gel is injected into the cleft and highly permeable borehole parts, the gel can be made from polysaccharides or also from alginates. As gel-forming components, borate is preferably used there. The gel is produced above ground. Injected gels ensure a complete sealing of the treated area of the formations. The oil transport is not affected by the procedure according to this publication.

In US patent 2 211 688, the use of alginate in a drilling flushing formulation is also disclosed, as the alginate increases the flushing's filter cake formation and improves the flushing's overall tolerance. The method also serves to secure unstable formations and to reliably seal gas- or water-bearing horizons by completely blocking the access channels. Packets or other suitable technical measures are used here to inject treatment liquid alone into the horizons to be sealed.

One can thus, according to the state of the art, for example for the above-mentioned case 1, use alginate solutions of very high concentration, up to 20 g/l and higher, which admittedly have higher viscosities (up to 100 mPa.s and higher), but also form practical water-permeable and permanent gels. For wetting, especially with relatively soft formation water, calcium chloride solution can be pumped in advance and/or also alternately with alginate solution. To achieve greater penetration depths, you can inject buffers of non-wetting water between the alginate solution and the wetting water.

In almost all crude oil formations, in addition to crude oil, suspended water is also present, mostly between 10 and 20% of the pore volume. The alginate then also reacts with the cross-linked ions of the attached water. A gel coating forms on the stone surface, whereby the effective permeability to oil can be reduced. When injecting an alginate solution, in addition to the water-bearing layers, at the same time also in the oil-bearing layers, a certain reduction in the effective oil permeability must be taken at the price, which is, however, surprisingly small, as is also shown with the help of the following laboratory experiments.

Only part of the alginate solution comes into contact with the adhering water and gel forms. The main amount of the alginate solution is not transported back in gel form. The retarding effect of the phosphates is therefore advantageous. According to the invention, because of this outflow ratio, it succeeds significantly more strongly in reducing the permeability in the diluted areas and in injecting the alginate solution deeper into these areas than in the oil-bearing areas. Thereby, the flow of oil increases considerably due to the increased pressure gradient. It can therefore be assumed that the oil content of the wet oil during radial flow to the transport probes is more favorable than what corresponds to the change in the mobility ratio.

In practice, to achieve this effect, one will try to select the concentration of the alginate so that the viscosity of the solution is clearly above this for water and clearly below this for crude oil. For a successful application, it is essential that the gels produced in the oil-bearing area are not too thick. Therefore, alginate concentrations < 5 g/l are particularly advantageous for the treatment.

In the meantime, it may be beneficial to the alginate to mix an alkali salt, whereby at a given concentration in advance the viscosity of the solution is lowered. Table I shows the viscosities of the sodium alginate "PROTANAL" LF (50 eps) manufactured by the company Protan & Fagertun A.S., Drammen/Norway, as a function of the concentration for fresh water and 2% potassium chloride solution as mixing water at 2 temperatures and the cutting trap 10 s_<1>. In the following experiments, the effect of the alginate treatment on the effective oil and water permeabilities and thus on the mobility ratio was examined. Linear packings of sand or torn core material was filled with Dogger water as suspension water and then floated with oil of different viscosities. After achieving the non-reducible water content, the effective oil permeability k^ eff o was measured. The oil was then floated with Dogger water and the effective water permeability k^ eff w was measured. Dogger water has a total salt content of 176 g/l and a Ca resp. Mg content of 4.5 g/l resp. 0.9 g/l. After determining the effective permeabilities, the packings were floated at typical formation temperatures with sodium alginate solutions of various concentrations, partly with sodium hexametaphosphate, and then again determined the effective water and oil permeability kg eff w and kg eff o.

The characteristic data are compiled in table II. The permeability is indicated in jjm<2> (Darcy). Trial 1 served as a prototype for complete shut-off of the bottom water. During the treatment, the effective water permeability was practically reduced to 0. For the further tests under different conditions, the mobility ratios Mj before and Mg after the alginate treatment as well as the corresponding effective water and oil permeabilities are indicated. It surprisingly turned out that with the alginate treatment, the effective water permeability is reduced significantly more than the effective oil permeability, meaning that a selective water barrier has taken place. For example, in trial no. 4, the effective water permeability is reduced by the treatment by around a factor of 10.4, but the effective oil permeability is only around a factor of 1.8. Correspondingly, the mobility ratio in this experiment before and after the treatment with the alginate solution is improved by around a factor of 5.78. In practice, the amount of alginate solution will be selected so that a radius of approx. 0.5-5 m, and preferably from approx. 1-3 m, around the bore is gripped by the treatment liquid. The alginate must be protected against bacterial decomposition by means of a suitable bactericide.

Claims (8)

1. Method for reducing the water inflow in oil production wells where an aqueous solution of alginates is injected into the water-bearing layer of the formation, characterized in that the aqueous solution of alginates with an alginate concentration of 0.1-8 g/l, which possibly contains agents for delay or acceleration of the alginate's gel formation, is also injected into the oil-bearing layer of the formation, as the formation's treatment can possibly take place in several stages with alternating injection of salt water. 2. Method according to claim 1, characterized in that an alginate solution with a concentration of 0.5-5 g/l is injected. 3. Method according to claim 1 or 2, characterized in that an alginate solution is injected into the formation and which, as a means of delaying the gel formation, contains agents that form gels with multivalent cations. 4. Method according to claim 3, characterized in that an alginate solution is injected into the formation and which, as a means of delaying gel formation, contains a complex phosphate, in particular sodium hexametaphosphate or sodium tripolyphosphate. 5. Method according to claim 4, characterized in that an alginate solution containing the complex phosphates in a concentration of 0.1-10 g/l and preferably 0.5-2 g/l is injected. 6. Method according to one of the preceding claims, characterized in that the treatment of the formation with alginate solutions takes place in several steps, alternating with the alginate solution, salt water containing at least 2 g/l multivalent ions is injected. 7. Method according to claim 6, characterized in that the alginate solutions and the multivalent cation-containing salt solutions are injected separately from each other by means of a buffer and water or salt water with only monovalent cations. 8. Method according to claim 6, characterized in that a solution of sodium alginate, salt water with monovalent cations and salt water containing at least 2 g/l multivalent ions is injected alternately into the formation.