WO1989008768A1

WO1989008768A1 - Method for enhanced recovery of hydrocarbone

Info

Publication number: WO1989008768A1
Application number: PCT/NO1988/000020
Authority: WO
Inventors: Bjørn Arild ARDØ
Original assignee: Institutt For Kontinentalsokkelundersøkelser Og Pe
Priority date: 1988-03-10
Filing date: 1988-03-10
Publication date: 1989-09-21

Abstract

For mobility control in EOR there is injected into a hydrocarbon reservoir a polymer that is soluble in injection water and insoluble with gel formation in the injection water at the formation temperature and/or soluble in the injection water at the formation temperature, but insoluble with gel formation in the formation water at the same temperature due to a different salinity or ionic strength.

Description

Method for Enhanced Recovery of Hydrocarbons

The invention relates to a method for enhanced recovery of hydrocarbons (such as oil, gas, condensate) in a subterranean formation.

During the life of an oil field it will be necessary to pump a medium into the reservoir in order to enhance the oil yield. In such a process - called EOR (= Enhanced Oil Recovery - one of the more usual media employed is water, which under certain conditions provides a good result. A drawback with wat as an injection medium is that the viscosity is so low that "fingering" of the injection water occurs with accompanied short circuit of water transport between the injection and production wells. In order to improve said situation polymers are added to the injection water such that the viscosity of the injection water becomes as high as, or greater than, the average viscosity of the displaced liguid. This improves the effect of water flooding in a reservoir, problems arise however, in case the reservoir has cracks or layers of high permeability. Further, there are problems with the short distance between the injection and production wells allowed, du to the increased pressure drop, as well as degradation of the polymers during the injection and during the long residence time in the reservoir. For those who work with water injection in oil bearing formations, these are known problems.

Said problems may be entirely or partly solved by employing a polymer that is characterized by being soluble in the injection water at temperatures different from reservoir temperatures but insoluble therein while at reservoir temperature, or that the polymer is soluble in the injection water at reservoir temperature, not however in the formation water at the temperature of the formation due to different salt content of the two fluids.

Fundamentally, there are two different physio/chemical mechanisms that can be utilized in order to obtain the desired effect:

utilization of a thermal gradient which is generated in the reservoir due to injection of water with a temperature different from the reservoir into the formation - the utilization of an ionic strength gradient which arises in the reservoir due to injection of water of different ionic strength than of the formation water in the formation.

The mechanisms may be utilized together, or separately.

1. Thermal gradient

This mechanism is based on a change in the temperature of the injection liquid when in the formation. The polymer solution will gel at a temperature primarily dependent on the polymer concentration and on the salt level of the injection water. In such a way, that the thermal gradient formed in the reservoir is utilized so as to generate a gel zone with an increased pressure drop. Through said mechanism the heat capacity of the formation is utilized in order to control the liquid front of the injection water. The heat capacity is not overly dependent on the permeability of the formation, and the movement of the liquid front will accordingly be more ideal and more controllable. Cracks and other highly permeable inhomogenities in the formation will loose the effect they have at present to disturb the desired effect of water injection. The improvement is due to gel plug formations in any highly permeable cracks and/or zones due to heat diffusion into or out of said areas from the surroundings. Mixing of water with different tempe¬ rature in said areas are also important for gel plug formation. -

The proviso for a desired function is that injected water can be forced through the gel such as to change the temperature of the formation in the gel area. The gel will then go into solution and be reprecipitated further ahead. This is contrary to known art where highly permeable zones are filled with a polymer solution along the flow directions in the formation before the polymer is brought to form a permanent gel which forces any following injection liquid to run through the less permeable zones of the formation such that hydrocarbons may be recovered therefrom. The new technology provides a gel zone which, in principle, is formed across the flow direction of the formation. The gel here forms a zone of increased pressure drop and is in dynamic balance between self association in the front and dissolution at the rear of the gel zone. This means that the polymer must provide a gel of such an open structure so as to allow liquid in the gel which does not dissolve the same, to be exchanged with displacing liquid that is capable of dissolving the gel. The movement of the liquid front through the formation is then determined by the resistance against displacement of water in the gel and not by the accidental variations in the permeability found in the formation.

For the man skilled in the art of polymer precipitations/- gels this will mean that the gel shall have a defined porosity and resistance against water permeation such that a desired effect is obtained. This is a characteristic property of the polymer(ε) to be used for mobility control according to said principle. The gel structure itself is mainly dependent on the way the polymer is put together, the molecular weight of the polymer and the concentration of the polymer in solution in the usual known way. A further advantage of said concept is that the gel zone is "self centering" which means that when a compensation for absorption losses to the formation and for the increase of gel volume as the distance from the injection well increases is added, then the concentration of polymer in the gel zone may be kept constant on account of the polymer being retarded in relation to the gel front whereas supplies of polymer can be provided from solution entering at the rear. Said effect also allows a higher polymer concentration in the gel zone than in the injection liquid itself, which is favorable from considerations of pumping as well as resistance to flow in the formation. In addition, a lower consumption of polymer may be attained than by a common polymer solution for mobility control where the polymer is not a gel former under reservoir conditions. 2. Chemical gradient

The second mechanism is based on the fact that the polymer dissolves in the injection liquid at the conditions ruling in the reservoir, gels however in the reservoir liquid at the same conditions. In case said effect is based on a general salt effect due to a different ionic strength in the reservoir liquid, this provides rather simple and controllable conditions, whereas if the effect is due to specific ions in the reservoir liquid that gels or precipitate the polymer, this may easily lead to ion exchange effects that can provide complex and unpredictable conditions. Thus, the gel formation should primarily take place through the increase or decrease of the ionic strength when the polymer solution is blended with the formation water at the front of the injected water. The behaviour of a chemically controlled gelling is otherwise quite similar to the mechanism for temperature controlled gelling as long as temperature gradient is replaced by ionic strength gradient and high/low temperature by high/low ionic strength.

Because said gels are formed from otherwise soluble polymer chains, the systems will be relatively insensitive to degradation of the polymer chains because the gelling (or the maximum viscosity) is controlled by smaller polymer chains associating with each other. This will function as long as the polymer chains do not become so short as to become soluble under all conditions in the reservoir. This is an important advantage, because polymer degradation otherwise will be a difficult problem due to the viscosity reduction often occurring during injection of liquids with dissolved polymers in reservoir rock.

It must be expected that both the thermal and the chemical effect mechanism to a greater or smaller extent will be active at the same time during true reservoir conditions; there is nothing, however, to hinder only one or both to be active during given set of conditions.

Accordingly, the invention provides a method for enhanced recovery of hydrocarbons in a subterranean formation, with water flooding in a hydrocarbon reservoir by a polymer which is soluble in injection water and insoluble with gel formation in the injection water at the temperature of the formation and/or soluble in the injection water at the temperature of the formation, but insoluble with gel formation in the formation water at the same temperature due to different salinity or ionic strength.

Exemples of polymers

Without being intended as a limitation of which types of polymers may be used, there are several known chemical structures being capable of giving a polymer the desired properties. Said polymers may be constructed in the known ways including condensation, addition and/or graft polymerisation as well as substitution of polymer chains with functional groups. The following structures, not being meant as limiting, may provide the polymers with the desired properties in the case where the reservoir is at a higher temperature than the injected water.

Ethers:

R -O-CH3, -0-C₂H₅ -(0-CH-CH-)_nOH (R=H,CH₃, C₂H₅ etc.)

Amides: O R₁-N-C-R₃ (R₂=CH,C₂H5 etc.) e.g. Methylated 66-nylon

R₂ 0

R-L-N-C-R-L (R =CH₃ , C₂H₅ etc.) e.g. Methylated 6-nylon

( (n=3 to 5) e.g. polyvinylpyrrolidone

0=C copolymers

The possibilities for variation are rather wide, in particular if the possibilities of copolymerisation and grafting are taken into full consideration. For the case where the reservoir is at a lower temperature than the injected waters, most polymers with "normal" tempera¬ ture/solubility relationships can be used as mobility control agents.

Commercial products

A substantial amount of the possible polymer types are marketed, some of those being mentioned here as examples of what is available, and not as a limitation of what is technically interesting.

1. Polyethers:

PLURONIC, DOWFAX, GENAPOL-PF, HARTOPOL, MARLOW, MONOLAN, PLURIOL, PLURIOL-RPE, PLURONIC-R

2. Polyvinylmethylethers:

LUTANOL M40, GANTREZ M

3. Celluloseethers (methyl-, hydroxyethylmethyl-, hydroxy- propylmethylcellulose and hydroxybutylmethylcellulose) :

CELACOL, CUMINAL, MARPOLOSE, METHOCEL, METOLOSE, MODOCOLL, TYLOSE M, WALSRODER MC

Hydroxyethylcelluloset

CELLOSIZE, NATROSOL, TYLOSE H

Hydroxypropylcellulose: LUCEL

In the following, examples are presented which describe the invention for the case of high temperature or saline reservoir with the low temperature or saline injection water system. Example I

In a glass column with water jacket for temperature control a reservoir model consisting of glass beads packed by means of a vibrator was made. The glass beads had a mean diameter of 0.2 mm, said column then being saturated with a 5% solution of NaCl. Said "formation liquid" then was displaced by a fresh water solution comprising 0.5% hydroxypropyl- cellulose (KLUCEL H) at 36°C. The displacement took place without the column being obstructed by precipitated polymer although a 5% NaCl solution that is layered underneath a 0.5% hydroxypropylcellulose solution forms a gel membrane at 36°C. The experiment shows that a polymer solution that gels in contact with the reservoir liquid may displace same without the reservoir being blocked.

Example II

In the reservoir model from Example I the column was washed and again saturated with a 5% NaCl solution. Said "formation liquid" then was displaced with a polymer solution containing 0.375% methylhydroxybutylcellulose solution (METHOCEL HB) . At 50°C said polymer solution forms a gel when in contact with a 5% NaCl solution. The displacement experiment shows that polymer solutions that gel in contact with the reservoir liquid may displace the same without blocking the reservoir by polymer precipitations.

Example III

By synthesis, 10 g of a commercial polymer (METHOCEL HB) having the desired starting properties was reacted with 2.5% Remazol brilliantblau R special, and purified by repeated heat coagulation. Dying of said polymer was made in order that the results of the following examples could easier be observed.

In a glass column having water jacket for temperature control a reservoir model was prepared wherein a highly permeable zone short-circuited inlet and outlet. This was carried out by sandwiching a plastic strand between a filter paper and the column wall. The two ducts formed along the plastic strand provided the model with a hydrodynamic "hole" through which the main part of the liquid that was forced through the system passed. In order to know when different liquids were passing the outlet of the column, the conductivity of the effluent water was measured conductometrically and the result plotted by means of a recorder.

By displacing a 5% NaCl solution with the dye-modified polymer it was observed that when the column temperature was less than the gel point (25°C) for 5% NaCl solution in contact with 0.375% dyed polymer solution, the displacing liquid ran mainly through the highly permeable ducts. After about 0.3 pore volumes had been displaced, there were small changes in the observed picture until the experiment was interrupted. It was easy to see that polymer flooding under such conditions had little total effect on the efficiency of the displacement in said system.

After washing and flooding with fresh 5% NaCl solution, the flooding experiment was repeated, now, however, under gelling conditions (37°C). It turned out that a gel plug rapidly formed in the highly permeable zones, which was then blocked forcing a plug flow in the column. Said condition was stable so no breakthrough was observed neither of water (conductivity measurement) nor of polymer (colour) before the entire pore volume was exchanged. It could also be visually controlled that the gel blocking the two highly permeable ducts dissolved when the front of the displacing liquid had passed, thus demonstrating the total permeability of the system was not permanently reduced.

Example IV

In order to test the method in natural sandstone a cylindrical core plug of Berea sandstone was cut. The plug was cut in such a way that the relatively small heterogenities possessed by said sandstone were parallel with the flow direction. Said plug was fixed by epoxy glue in a glass column having a water jacket for temperature control. A commercially available polymer (METHOCEL HB) having desired properties was then dissolved in 0.75% NaCl solution to a concentration of 0.375%. The salt (0.75% NaCl) is included in order to inhibit mobilisation of clay particles in the sandstone - this would otherwise reduce the permeability during the experiment thus creating unreliable results.

After saturating the column with 5% NaCl solution and the temperature adjusted to 35°C, which is below the gelling point of the polymer solution in contact with the "formation water", a displacement of the formation water with 0.375% polymer solution was performed. The progress was followed conducto¬ metrically and the result plotted with a recorder.

Hereafter, the experiment was repeated, this time, however, under gelling conditions wherein 0.375% polymer in 0.75% NaCl solution gels against the "formation water" with 5% NaCl at 50°C. The progress also this time was followed conductometrically and the result plotted with recorder.

In spite of Berea being a rather homogenous sandstone, the diagram for the displacement under gelling conditions showed a somewhat more favorable course than under non-gelling conditions.

The experiment shows that it is entirely feasible to displace a reservoir liquid with a gelling polymer solution in a natural reservoir rock without the permeability of the sandstone being destroyed due to permanent gel precipitations.

Claims

PATENT CLAIM

A method for enhanced recovery of hydrocarbons in a subterranean formation, characterized therein that for the control of water flooding in a hydrocarbon reservoir a water based' solution of a polymer is injected which is soluble in injection water and insoluble with gel formation in the injection water at the temperature of the formation and/or soluble in the injection water at the temperature of the formation, but insoluble with gel formation in the formation water at the same temperature due to different salinity or ionic strength of the latter.