NO830761L - PROCEDURE FOR THE EXTRACTION OF OIL FROM AN UNDERGROUND RESERVE - Google Patents

Abstract

1. A process for recovering oil from a subterranean deposit of medium or high salinity by forcing into an injection bore a 0.1 to 30% solution or dispersion in formation water or floodwater of a carboxy-methylated oxyethylate surfactant of the formula R-(OCH2 CH2 )n -OCH2 -COOM where R is a linear or branched aliphatic radical of 6 to 20 carbon atoms or a monoalkylaromatic or dialkylaromatic radical of 3 to 16 carbon atoms in the alkyl group(s), M is an alkali metal or alkaline earth metal or ammonium ion and which has a degree of carboxymethylation is from 10% to 90%, the surfactant being chosen so that the phase inversion temperature of the system of crude oil/formation water or floodwater/surfactant/optional additive(s) is the temperature of the deposit or up to 10 degrees C above that temperature, characterised in that n is from 1 to 3.

Description

Method for extracting oil from an underground reservoir

When extracting oil from oil-bearing formations, it is usually only possible to extract a fraction of the originally present oil by primary extraction methods. Below this, the oil comes up to the surface as a result of the natural pressure in the reservoir. In secondary oil extraction, water is forced into the formation through one or more injection wells to drive the oil to one or more production wells and in this way up to the surface. This so-called waterflooding as a secondary measure is relatively cheap and is used correspondingly frequently, but in many cases only leads to a slight increase in the amount of oil extracted from the reservoir.

An effective displacement of the oil is only successful with help

of tertiary precautions which are more expensive, but nationally economically imperative due to the current oil shortage. Tertiary extraction is understood to mean methods where either the viscosity of the oil is reduced and/or the viscosity of the water used in the waterflooding is increased and/or the interfacial tension between water and oil is reduced.

Most of these processes can be characterized either

as solution or mixture flocculation, thermal oil recovery processes, surfactant or polymer flocculation or as a combination of several of these methods.

Thermal extraction processes involve the injection of steam or hot water or take place as an underground combustion. Dissolution or mixing processes consist of injecting a solvent for the petroleum into the reservoir, where "petroleum" means a gas and/or a liquid. Surfactant flooding processes (depending on the surfactant concentration, possibly the type of surfactant and additions, a distinction is made between surfactant-supported water flooding, ordinary surfactant flooding (Lowtension flooding), micellar flooding and emulsion flooding) are primarily based on a strong reduction of the interfacial tension between oil and flooding water. In some cases, especially in the presence of higher surfactant concentrations, however, VO dispersions occur with clearly increased viscosity in relation to oil, so that the surfactant flocculation here also aims at a reduction of the mobility ratio, whereby the effectiveness of the oil displacement is increased. Pure polymer flocculation is mainly due to the last described effect of the more favorable mobility ratio between oil and subsequent water.

The present invention relates to a method for extracting oil by surfactant flocculation. As oil-mobilizing surfactants, organic sulphonates such as alkyl, alkylaryl or petroleum sulphonates have so far been described above all. However, these have a very low tolerance limit to the salinity of the reservoir. Already salt concentrations of 1,000 ppm are considered problematic, and in this connection the sensitivity of these surfactants is particularly pronounced towards alkaline earth ions. Here, the upper critical limit concentration is assumed to be approx. 500 ppm (US-PS 4,110,228). In the presence of higher salt concentrations, when these surfactants are used, precipitation products are formed which can lead to clogging of the formation.

Since, however, many reservoir waters have significantly higher salinities, in northern Germany e.g. up to 250,000 ppm, people have been looking for ways to utilize the otherwise good oil-mobilizing properties of the organic sulphonates also for reservoir systems with higher salinity. When mixed with cosurfactants (interactive surfactants) such as alcohols or non-ionic surfactants, organic sulphonates also prove to be less electrolyte-sensitive. Admittedly, then, for the most part, the oil mobilizing effect was also worse.

In contrast to this substance group, alkyl resp. alkylaryl polyglycol ether sulfates or carboxymethylated alkyl resp. alkylaryloxyethylates a good compatibility even with extremely high salinities (e.g. 250,000 ppm) of the reservoir water. Since the oil-mobilizing effect of these surfactants is good (H.J. Neumann, DGMK BERICHTE, Bericht 164 (1978), D. Balzer and

K. Kosswig, Tenside Detergents 16_, 256 (1979)) and their manufacture is simple and cheap, these substance classes are very suitable for use in oil displacement in reservoir systems with medium or high salinity (10,000 - 250,000 ppm total salt content).

However, in numerous investigations regarding the mobilization of residual oil in model formations with carboxymethylated oxetylates as surfactants, it has been observed that the transport of the oil bank through the formation is accompanied by a strong increase in pressure. Thus, even with relatively highly permeable artificial formations, pressure gradients of up to 40 bar/m were observed, which when transferred to a field leads to pressures well above the petrostatic pressure and thus precludes the use of these surfactants in tertiary oil extraction. Also in literature (C. Marx,

H. Murtada, M. Burkowsky, Erdoel Erdgas Zeitschrift 93, 303

(1977)) reference is made to pressure gradients of a similar order of magnitude. The authors explain the high pressure differences with the formation of emulsion zones, which should, however, be limited to the area of the flow front. However, in the experiments carried out by the inventors of the present invention, no local limitation of the pressure gradient could be noticed. As crude oil emulsions stabilized with carboxymethylated oxyethylates are structurally viscous, the high pressure differences cannot otherwise be reduced at will, even by reducing the flow rate. For this reason, in the case of surfactant flocculation with carboxymethylated oxyethylates in oil fields, uncontrollably high pressure gradients will have to be expected.

There, therefore, was the task for the good oil-mobilizing carboxymethylated oxetylates to find a method for carrying out the surfactant flocculation which does not lead to high pressure gradients. A reduction of the pressure gradient is possible by striving for a greatly delayed surfactant breakthrough when adapting the amount of surfactant to the reservoir. Admittedly, this method presupposes homogeneous formations, which can certainly be achieved with artificial sand fillings, but hardly in actual reservoirs. A solution to the task in this way is therefore unlikely to be possible.

However, the task has surprisingly been solved by abandoning a working hypothesis that is also substantiated in the literature, and which states that an effective residual oil recovery is only possible when the conditions for the occurrence of a VO emulsion exist as far as possible during the entire flow process (U. Lepper , Erdoel Erdgas Zeitschrift 9£, 426 (1976)). According to B. Balzer and K. Kosswig, Tenside Detergents 1_6, 256 (1979), this means that the phase inversion temperature (PIT) of the system consisting of original crude oil and original formation water or flow water, when no formation water is flowed, as well as surfactant and any additions, must be clearly below the reservoir temperature, more specifically up to 15°C below this. In flow experiments carried out under these conditions on model formations, very efficient oil recovery was usually observed, while the crude oil could predominantly be flowed out in an emulsion-free state. However, high pressure gradients very often occur with this method of operation.

It has now been found that the pressure gradient while achieving a good oil recovery can be greatly lowered by a method as stated in the patent claims. This was extremely surprising, insofar as the temperature range in question is the state range for an OV emulsion.

If one chooses such a surfactant that the phase inversion temperature is 11°C and more above the reservoir temperature and one is thus in the condition range for the OV emulsion, the mobilization of the residual oil is less effective and the oil is predominantly transported as an emulsion.

The phase inversion temperature itself is determined by measuring the electrical conductivity. For this purpose, an emulsion is prepared of the crude oil and formation water from the relevant reservoir or the flood water (phase ratio 1:1 or 1:2) and the surfactant (2% calculated on the water phase) as well as any additives and measures its electrical conductivity as a function of temperature. At the phase inversion temperature (PIT), an OV emulsion turns into a VO emulsion and vice versa, as the electrical conductivity is then reduced resp. increases by leaps and bounds.

Actually, it is about a temperature range of a few degrees Celsius. The temperature at which the electrical conductivity has the mean value between the upper level (OV) and the lower level

(VO), is considered PIT.

The present invention relates to the use of carboxymethylated oxetylates as oil-mobilizing surfactants. These compounds can be prepared according to DE patent 24 18 444 by reacting oxetylates with the formula

R-(O-CH 0 -CH 2 ) OH

Z 2. n

with a salt of chloroacetic acid in the presence of alkali hydroxide or alkaline earth hydroxide, but other preparation methods are also suitable. R means here a saturated or unsaturated alkyl radical with a straight or branched chain and 6-20, preferably 8-16, C atoms or an alkylaryl radical with 3-16 C atoms in the alkyl radical. n can not only assume values of 3-30, as stated in Norwegian patent application 82 2935, the degree of oxetylation can - as has surprisingly been found on the basis of numerous experiments - also lie between 1 and 3. The cation can be sodium, potassium, lithium , ammonium, calcium or magnesium. As alcohols and phenols whose oxetylates form the basis of the carboxymethylates, there can e.g. are used: hexyl alcohol, octyl alcohol, nonyl alcohol, decyl alcohol, undecyl, lauryl, tridecyl, myristyl, palmityl and stearyl alcohol, but also unsaturated alcohols such as e.g. oleyl alcohol. The alkyl chain can therefore have a normal or branched chain. Commercially available mixtures of these alcohols are particularly suitable. Alkylphenols can be used, for example: propylphenol, butylphenol, hexylphenol, octylphenol, nonylphenol, decylphenol, undecylphenol, dodecylphenol, tridecylphenol, tetradecylphenol, hexadecylphenol, dibutylphenol, dihexylphenol, etc. The alkyl chain can have a normal or branched chain. In particular, commercially available mixtures of such alkylphenols can be used.

The oxyethylation can be carried out in the presence of catalytic amounts of alkali hydroxide with from 1 to <3 moles of ethylene oxide.

The resulting mixtures have approximately a Poisson distribution.

In accordance with their preparation, the carboxymethylated oxetylates still contain considerable amounts of NO

converted oxethylate. By the formula R-(OCH„-CH_)-OCH„-COOM is meant

2.2. no 2

therefore always a mixture with different amounts of unreacted oxethylate. According to this, it is possible to define a degree of carboxymethylation. It has been found that mixtures with a degree of carboxymethylation of between 10 and 90%, preferably between 30 and 90%, are capable of effectively displacing the oil. Mixtures with carboxymethylation degrees of 50-90% are particularly effective. The percentages are always percentages by weight.

The described mixtures of anionic and nonionic surfactants, which are designated as carboxymethylated oxyethylates, are soluble in the usual reservoir waters or can at least be easily dispersed in them, as no precipitation is observed.

According to the invention, one proceeds in the following way: By knowing the reservoir temperature or possibly a temperature range is carried out where an indicative measurement of the PIT of the crude oil, the formation water or the flow water and possibly the gas in the reservoir as well as a carboxymethylated oxyethylate that seems suitable. This measurement may have to be repeated with additional surfactants in this class and possibly additives.

On the basis of the measurement results, an adaptation of the carboxymethylated oxyethylate takes place, whose oil-mobilizing effect for the reservoir system in question can be verified through one or more preliminary tests in a sand fill as a model formation

or in original or model drill cores.

The sodium salts of the carboxymethylated oxetylates, which are produced by reacting oxetylates with chloroacetic acid in the presence of caustic soda, provide a number of reference points for the "molecular architecture" for setting a desired phase inversion temperature in a particular system:

The salts of the carboxymethylated oxyethylates are composed of three variable building blocks: The hydrophobic radical R, the oxyethylate chain and the carboxymethyl group, the proportion of which in the produced product mixture can be changed within wide limits by regulating the reaction of the starting oxyethylate with chloroacetic acid. As starting materials for the hydrophobic radical R, linear and branched (fatty) alcohols are mentioned, further alkylphenols with arbitrary alkyl radicals. The influence of the alkyl radical resp. the alkylaryl radical at the phase inversion temperature has already been explained (D. Balzer and K. Kosswig, loe. eit.). The law applies that an increase in the hydrophobicity of the surfactant reduces the phase inversion temperature, while an increase in the hydrophilicity increases the temperature. In the drawing, the dependence of the phase inversion temperature on the degree of oxetylation n in a particular system is shown. Crude oil F, formation water F and alfol-1218-oxyethylates of different degrees of ethylene oxide and carboxymethylated to approx. 70%. The surfactant concentration was 2%,

and the phase ratio between oil and water was 1:2. The influence of the degree of carboxymethylation on the phase inversion temperature has already been explained (D. Balzer and K. Kosswig, loe.

one.). The drawing and the aforementioned investigations show the possibility of variation as the class of carboxymethylated oxetylates,

which ultimately constitute mixtures of ionic and nonionic surfactants, provide with respect to reservoir conditions.

Furthermore, possibly the volume of the surfactant solution

to be injected, its concentration and any additives, as well as the nature and amount of the polymer solution that regulates mobility, are optimized using model flow tests. On the basis of the results from these preliminary tests, the surfactant solution is introduced into the reservoir by means of injection pumps. Below this, the surfactant solution can either be introduced continuously or used in the form of a plug, i.e. a narrowly limited volume of 0.05 - 4.0 PV (pore volume of the reservoir). The size of the plug depends above all on the concentration of the surfactant solution and economic considerations.

Appropriately, this is carried out before the tension flow

a waterflooding, whereby the extracting formation water or another flowwater is used as flowfluid. The size of this water plug is 0.01 - 4 PV, preferably 0.05 - 1.0 PV. After the surfactant plug, a polymer plug is appropriately injected into the reservoir both for reasons of mobility control and to protect the surfactant solution against intruding formation water or flow water. For this purpose, a polymer or a mixture of polymers is dissolved in the formation water in such a concentration that the viscosity is 4-6 times as high as the viscosity of the oil. In the case of reservoirs with medium and higher salinity (1 - 28 %), biopolymers such as polysaccharides or cellulose derivatives which, in the presence of pre-

high salt concentrations still have a sufficient viscosity and do not show any precipitation.

Table 1

The dependence of the phase inversion temperature on the length of the alkyl radical in the sodium salts of carboxymethylated fatty alcohol oxyethylates with 4.4 EO and at a degree of conversion of 65%; crude oil A (see D. Balzer and K. Kosswig, loe. eit.), formation water A

(see D. Balzer and K. Kosswig, loe. eit.), phase ratio 1:1, 2% surfactant

For reasons of a more favorable viscosity adjustment of the surfactant solution to the oil in the reservoir or to reduce the surfactant or possibly polymer holding time, it may be appropriate to add alcohols or also glycols to the surfactant or the polymer plug as cosurfactants. Suitable cosurfactants are here e.g. i-propanol, i-butanol, n-butanol, t-amyl alcohol, 2-ethylhexanol, butyldiglycol and butyltriglycol.

In the case of formation water that is relatively poor in alkaline earth ions, it may prove appropriate to add soluble alkaline earth salts to the surfactant solution as well as to the water used for flooding before or after the surfactant solution. When adapting the surfactant to the reservoir, i.e. when measuring the PIT, these additions must be taken into account.

Conveniently, a normal water flow as propulsion joins the injection of the polymer solution. This water flooding is carried out as long as it is still economical to extract oil.

The following examples shall illustrate the method according to the invention:

Example 1

For the production of an artificial formation, quartz sand with rounded edges was filled in a thermostatizable high-pressure tube with a length of 70 cm and a diameter of 5 cm, the tube being equipped with a temperature measuring device and pressure gauges. The pipe could be closed at both ends by threaded plugs with capillary inlet and pressure-retaining valve outlet. The sand fill was then saturated with formation water F using a high-pressure dosing pump and set to the desired temperature using a thermostat. Using a pressure transmitter, the permeability of the sand layer was determined. A saturation with crude oil was then carried out, while at the same time the binding water content was determined. The waterflooding was then started with a flow rate of approx. 2.5 m/d. After inflow of approx. 1.5 PV of formation water (1 PV = approx. 750 ml), achieving a degree of dilution of 98-100%, the surfactant was injected as a plug. Then 3.0 PV of formation water followed as progress. The surfactant flooding and the subsequent afterflooding with formation water took place at a flow rate of approx. 1 m/d. The formation temperature was 68°C and the pressure in the formation was 60 bar. The porosity of the artificial formation was approx. 45%, the permeability approx. 1,000 mD and the binding water content approx. 25%.

The formation water F contained per liters approx. 23.5 g NaCl, 0.75 g KCl, 1.1 g CaCl 2 , 5 g MgCl 2 , 4 g Na 2 So 4 and 0.2 g NaHCO 3 .

An alkane-based oil with an API grade of 37 was used as crude oil. The content of alkanes, naphthenes and aromatics was respectively approx. 61, 18 and 21%.

1.5 PV of a 2% dispersion of carboxymethylated c14_fatty alcohol oxyacetylate with 2.4

moles of ethylene oxide per moles in the formation water. The degree of carboxymethylation was approx. 70%, and the PIT of the relevant crude oil emulsion was 73.5°C. During the waterflooding, an oil discharge was achieved

recovery of 69%, which after a further 1.4 PV after the onset of tenside flotation could be increased by 19% to 88% total oil recovery. Below this, the dilution went back to approx. 60%. During the transport of the oil bank produced by the surfactant, an average pressure gradient of 1.6 bar/m was measured.

Example 2 (comparison example)

This comparative example was carried out using practically identical conditions, substances and process steps as in example 1, but at a test temperature of 80°C (PIT was 73.5°C as in example 1). With waterflooding, an oil recovery of 72% was achieved, which after a further 1.3 PV after the start of surfactant flooding could be increased to 94% total oil recovery. However, an average pressure gradient of 18 bar/m was measured below.

Such a pressure gradient, when transferred to the field, would lead to pressure far above the petrostatic pressure and thus preclude the use of the surfactants in tertiary petroleum extraction.

Example 3

As a model formation was used in this example

a horizontally stored cylindrical core of Bentheimer sandstone with a diameter of approx. 8 cm and a length of approx. 50 cm. The core was embedded in epoxy resin and its ends were closed using metal flanges sealed with O-rings. A water bath controlled by a thermostat was used for tempering.

After wetting the formation with formation water B, determination of the pore volume (1PV = approx. 620 ml) and the permeability (approx.

1300 mD) the core was saturated with crude oil B. Otherwise, the procedure was the same as in the previous examples, although the flow rates were only half as high and no polymer was flowed as a mobility buffer after the surfactant plug.

The formation water B contained per liters approx. 63.6 g NaCl, 0.4 g KCl, 15.1 g CaCl 2 , 3.1 g MgCl 2 , 0.4 g SrCl 2 and 0.4 g BaCl 2 .

An alkane-based oil was also used as crude oil

an API grade of 40. The content of alkanes, naphthenes and aromatics was 75, 12 and 13% respectively.

As a surfactant solution, 2 PV of a 1% dispersion of carboxymethylated oxetylates of a fatty alcohol mixture with 12-18 carbon atoms per molecule and 2.7 mol of ethylene oxide per mol, the dispersion also containing 0.2% isobutanol. The degree of carboxymethylation of the surfactant was approx. 75%. The phase inversion temperature (48°C) of the relevant crude oil emulsion lies within the range according to the invention in relation to the temperature of the model formation which was 43°C. By water-flooding was. there resulted in an oil recovery of 50%, which could be increased to 80% by surfactant flooding and subsequent water propulsion after 2.0 PV. An average pressure gradient of 0.3 bar/m was measured there.

Example 4 (comparison example)

This comparative example was carried out using practically identical conditions, substances and process steps as in example 3, but with 2.5 PV 1% solution of carboxymethylated oxytylate of a fatty alcohol mixture with 12-18 carbon atoms per molecule and 2.5 mol of ethylene oxide per mol as surfactant, as 0.2% isobutanol was also added. The phase inversion temperature of the crude oil emulsion was 42°C and was here lower than the temperature in the model formation (43°C). With water flooding, an oil recovery of 53% was achieved, which could be increased to 90% with the help of surfactant flooding.

During the transport of the oil bank, a pressure gradient of 7 bar/m developed. Such a pressure gradient can hardly be controlled in reservoir engineering in field tests at normal depths.

Example 5

This experiment was carried out using practically identical conditions, substances and process steps as in Example 1, however using carboxymethylated oxyethylate of a fatty alcohol mixture with 12-18 carbon atoms per molecule and 1.5 mol of ethylene oxide per mol (PIT 46°C) and a reservoir temperature of 41°C. With waterflooding, an oil recovery of 74% was achieved, which could be increased to 99% under the action of the surfactant. In this example according to the invention, a manageable pressure gradient of 1.2 bar/m was produced during the tension flow.

Claims (9)

1. Method for extracting oil from an underground reservoir of medium or high salinity by injecting a 0.1 - 30% solution or dispersion in formation water or flow water of carboxymethylated oxetylates with the formula into an injection well where R means an aliphatic radical with a linear or branched chain and 6-20 carbon atoms or an alkyl or dialkylaromatic radical with 3-16 carbon atoms in the alkyl group, M means an alkali or alkaline earth metal ion or ammonium and the degree of carboxymethylation is 10-90% , the surfactant being thus selected by the phase inversion temperature of the system crude oil/formation water or flow water/surfactant/any additions is at the reservoir temperature or up to 10°C above this, characterized by atn being between 1 and 3. 2. Method as stated in claim 1, characterized in that additives are added to the crude oil/formation or flow water/surfactant system. 3. Method as specified in claim 1 or 2, characterized in that the phase inversion temperature of the system crude oil/formation or flow water/surfactant/additives is 1-10°C above the temperature in the reservoir. 4. Method as specified in one of claims 1-3, characterized in that mono-, di- and/or trihydric alcohols are added to alcohols of the surfactant solution or dispersion as additives. 5. Method as stated in one of the preceding claims, characterized in that soluble alkaline earth salts are used as an addition to the formation water. 6. Method as specified in one of claims 1-3, characterized in that formation water or flow water in an amount of 0.01-4 PV is pressed into the reservoir before injecting the surfactant solution. 7. Method as stated in one of the preceding claims, characterized in that formation or flow water in an amount of 0.01-4 PV is pressed into the reservoir after the injection of the surfactant solution. 8. Method as stated in claim 7, characterized in that the formation or flow water contains a viscosity-increasing polymer. 9. Method as stated in claim 1, characterized in that the surfactant has a degree of carboxyl methylation of between 30 and 90%.