Additives for enhanced oil recovery

Abstract

The embodiment relates to a method for enhanced oil recovery, which includes injecting a composition comprising a hyperbranched polyglycerol into an injection well in an underground oil-bearing reservoir, wherein the hyperbranched polyglycerol is a primary alcohol, which is a reaction product of a C2 to C25 carbon alcohol and a plurality of glycidols; and using the composition to displace the petroleum in the underground oil-bearing reservoir.

Description

Technical Field

[0001] Embodiments relate to additives for use in enhanced oil recovery. Background Art

[0002] During the primary production process, only a portion of the oil originally present in the underground oil-bearing reservoir is recovered, and the primary production process uses the natural energy of the reservoir (such as fluid and rock expansion, solution gas drive, gravity drainage and water intrusion) to produce oil. Various enhanced oil recovery processes can be used to increase the output of the oil reservoir, wherein the enhanced oil recovery process can be after the primary production process. The enhanced oil recovery process can be achieved by injecting materials such as water, steam, hydrocarbons and / or carbon dioxide into the underground reservoir to drive oil from the pore space, but the efficiency of this oil drive can depend on many factors, such as oil viscosity and rock properties. In addition, surfactants can be added to the enhanced oil recovery process as a foaming agent. The enhanced oil recovery process should drive oil from the pore space, but the efficiency of this oil drive depends on many factors (such as oil viscosity and rock properties). Therefore, other additives that can enhance the effectiveness of the enhanced oil recovery method and withstand the harsh conditions of the underground reservoir and the enhanced oil recovery process are sought. Hyperbranched polyglycerols, which are the reaction products of C2 to C25 carbon alcohols and glycidol, have been proposed to further improve various enhanced oil recovery processes, and may be combined with surfactants. Summary of the invention

[0003] The embodiment can be achieved by a method for enhanced oil recovery, which includes injecting a composition containing a hyperbranched polyglycerol into an injection well in an underground oil-bearing reservoir, wherein the hyperbranched polyglycerol is a primary alcohol, which is a reaction product of a C2 to C25 carbon alcohol and a plurality of glycidols; and using the composition to displace the petroleum in the underground oil-bearing reservoir. BRIEF DESCRIPTION OF THE DRAWINGS

[0004] Figure 1 is a graphic representation of the various subclasses, including dendrimers, linear-dendritic hybrids, dendrimers or dendritic graft polymers, hyperbranched polymers, multi-arm star polymers, and hypergrafted polymers. DETAILED DESCRIPTION

[0005] Various methods can be used to enhance oil recovery. The various methods include the following:

[0006] CSS - Cyclic Steam Stimulation, where steam is injected into the well for weeks to months. The well may be left to sit for days to weeks to allow the heat to soak into the formation. Then, hot oil begins to be pumped out of the well, and once production declines, the well may go through another cycle of steam injection, soaking, and production. This process may be repeated until the cost of injecting steam becomes higher than the return on oil produced from it. Recovery may be high, but the cost of injecting steam is high.

[0007] SAGD-Steam Assisted Gravity Drainage, in which at least two horizontal wells are used, one at the bottom of the formation and the other above it. Steam is injected into the upper well, and the heat reduces the viscosity of the heavy oil, allowing it to drain by gravity into the lower well and then be pumped to the surface.

[0008] VAPEX - Steam Extraction process is similar to SAGD, but instead of steam, hydrocarbons and / or other gases are injected into the upper well to dilute the heavy oil and allow the diluted heavy oil to flow into the lower well.

[0009] Chemical flooding, such as waterflooding, in which water is injected into a well to increase the reservoir pressure to its initial level and maintain it near that pressure. The water used for waterflooding can be brine or saline water recovered from the primary production process (i.e., water recovered from an underground oil-bearing formation).

[0010] The enhanced oil recovery process may include the use of a foam-forming composition, which may be used as a foam-assisted enhanced oil recovery process on its own or in combination with another recovery process.

[0011] The effectiveness of various enhanced oil recovery processes may depend at least on the fluidity ratio between the oil and the composition used in the enhanced oil recovery process. For example, the wettability of the reservoir rock and the surface tension between water and oil, particularly in the geological formation of the underground reservoir, may affect the efficiency of the oil recovery process. In addition, some conventional additives may be ineffective under the harsh conditions of the underground reservoir and / or circulating water. Therefore, additives that can enhance the effectiveness of the enhanced oil recovery method while tolerating the harsh conditions of the underground reservoir (e.g., surfactants, steam and / or circulating water) are sought.

[0012] The effectiveness of the enhanced oil recovery process can be altered by, for example, (i) adjusting the oil / liquid (or gas) mobility ratio by increasing the displacement fluid viscosity to increase oil recovery, (ii) changing the wettability of the reservoir rock to be more wetter to increase oil recovery, and (iii) reducing the surface tension between the liquid (or gas) and the oil.

[0013] Hyperbranched polyglycerol is a primary alcohol, which is the reaction product of a C2 to C25 carbon alcohol and a variety of glycidols. An exemplary schematic diagram is shown below, in which a C2 to C25 carbon alcohol is described as ROH, and an exemplary structure of a hyperbranched polyglycerol is shown.

[0014]

[0015] Hyperbranched means that the polyglycerol is highly branched and includes at least 2 branches (e.g., at least 4 branches, at least 5 branches, etc.). Hyperbranched polyglycerols have the classification of dendritic structures (tree-like structures, and are considered to be unique non-linear structures), with a subclassification of hyperbranched polymers. Dendritic polymers refer to the following types of polymers known in the art of polymer chemistry:

[0016]

[0017] The various subclasses include dendrimers, linear-dendritic hybrids, dendrimers or dendritic grafted polymers, hyperbranched polymers, multi-arm star polymers, and hypergrafted polymers, e.g. Figure 1 The embodiments are particularly directed to the hyperbranched polymer subclass under the dendrimer class. The hyperbranched polymer has a randomly branched structure in which exactly one focal unit is a primary alcohol (which is the initiator) and at least two branch points are multiple glycidols.

[0018] C2 to C25 carbon alcohol refers to that the alcohol includes 2 to 25 carbon atoms (for example, C4 to C25 includes 4 to 25 carbon atoms, C5 to C22 includes 5 to 2 carbon atoms, C5 to C20 includes 5 to 20 carbon atoms, C8 to C18 includes 8 to 18 carbon atoms and other ranges therebetween). Alcohol refers to that C2 to C25 carbon alcohol has at least one hydroxyl group, it can be a monohydric alcohol with a hydroxyl group or a polyhydric alcohol with 2 or more hydroxyls. C2 to C25 carbon alcohol can be straight-chain, branched or cyclic, and can optionally have one or more hydrogens substituted by Cl, F or CN. In exemplary embodiments, C2 to C25 carbon alcohol can be an unsubstituted hydrocarbon monohydric alcohol (including only carbon atoms, hydrogen atoms and an oxygen atom).

[0019] Multiple glycidol refers to two or more glycidol monomers, so that glycidol addition by ring-opening polymerization proceeds on C2 to C25 carbon alcohols to form a higher molecular weight polymer. Glycidol refers to a monomer having the following structure:

[0020]

[0021] Primary alcohol means that the hyperbranched polyglycerol includes at least one terminal hydroxyl group (primary alcohol group). The hyperbranched polyglycerol can be a multi-branched polymer including two terminal hydroxyl groups at the end of each branch, for example, as shown in the following exemplary structure:

[0022]

[0023] Hyperbranched polyglycerol can have different molecular weights, which are typical in hyperbranched polymers. The exemplary number average molecular weight range of each hyperbranched polyglycerol polymer is 100g / mol to 100,000g / mol (e.g., 100g / mol to 75,000g / mol, 100g / mol to 50,000g / mol, 100g / mol to 25,000g / mol, 100g / mol to 10,000g / mol, 100g / mol to 5,000g / mol, 100g / mol to 3,000g / mol, etc.). Hyperbranched polyglycerol can be used as an additive in an amount of 0.001wt% to 10.000wt%, based on the total weight of the composition placed in an underground oil-bearing reservoir for enhanced oil recovery (and the composition may include water and / or steam and / or other additives). The nominal hydroxyl functionality of the hyperbranched polyglycerol can be at least 4 (e.g., 4 to 100, 6 to 90, 8 to 80, 10 to 70, 10 to 60, 10 to 50, 10 to 40, 10 to 30, 10 to 20, etc.). In particular, since the hyperbranched polyglycerol is a hyperbranched polymer, it has a unique structure and properties, such as abundant hydroxyl functional groups.

[0024] Hyperbranched polyglycerols can be synthesized in a one-shot process (batch process) and / or using the gradual addition of glycidol (semi-batch process). The gradual addition of glycidol can be used to control polydispersity. The resulting hyperbranched polyglycerols can have a low polydispersity (e.g., less than 4 and / or greater than 1).

[0025] It is believed that hyperbranched polyglycerols may be comparable and / or more stable under high temperature and / or high salinity conditions, for example, compared to commercially available α-olefin sulfonates, while still being well suited for enhanced oil recovery. For example, hyperbranched polyglycerols may act as foam promoters (for foam-assisted enhanced oil recovery). Hyperbranched polyglycerols may act as wetting agents in oil recovery processes. Hyperbranched polyglycerols may be stable at high temperatures of at least 140° C. (e.g., see the cloud point and CMC data in Table 1). Hyperbranched polyglycerols may provide desired interfacial (surface) tensions, even at high temperatures, for example, compared to conventional surfactants, making hyperbranched polyglycerols likely to be very suitable for oil recovery (e.g., see the IFT data in Table 2). The viscosity of hyperbranched polyglycerols may be adjusted with simple solvents such as water for various types of enhanced oil recovery (e.g., see the HPG / water mixture viscosity data in Table 3). It is desirable to be able to adjust the viscosity of the additive based on the conditions of a specific enhanced oil recovery process and / or the conditions of an underground reservoir. Hyperbranched polyglycerols can be stable so that phase separation is not observed under high salinity conditions even at high temperatures of at least 80°C (e.g., see Table 4). Hyperbranched polyglycerols can sufficiently modify water contact agents to be suitable for use as wettability modifiers (e.g., see Table 5). Hyperbranched polyglycerols can be suitable for adjusting the interfacial tension between crude oil and brine to be suitable for enhanced oil recovery (e.g., see Table 6). Hyperbranched polyglycerols can substantially promote foam volume, for example, compared to traditional foam boosters, while still being stable under high temperature and / or high salinity conditions (e.g., see Table 7).

[0026] Hyperbranched polyglycerol is used as the additive in the enhanced oil recovery process. Based on the gross weight of the composition, the hyperbranched polyglycerol can be present in an amount of 0.001 wt % to 10.000 wt % (e.g. 0.001 wt % to 5.000 wt %, 0.001 wt % to 3.000 wt %, 0.001 wt % to 1.000 wt %, 0.001 wt % to 0.500 wt %, 0.001 wt % to 0.100 wt % etc.). Based on the type of the enhanced oil recovery process used, the composition can also include water and / or steam.

[0027] The hyperbranched polyglycerol according to the embodiment is believed to be useful as a multi-purpose additive for increasing the oil recovery rate from underground reservoirs. In addition, the hyperbranched polyglycerol is believed to be able to withstand the harsh temperatures of underground reservoirs. For example, the hyperbranched polyglycerol is believed to be able to withstand the salinity conditions of circulating water used to increase the oil recovery rate of underground reservoirs.

[0028] Example

[0029] With respect to the illustrative working examples, comparative examples, and information used in reporting results of the working examples and comparative examples, general properties, characteristics, parameters, etc. are provided below.

[0030] The main materials used are as follows:

[0031] Glycidol solution with more than 95% by weight of glycidol (obtained from ).

[0032] C8-OH initiator alcohol, which is a solution of greater than 98 wt% 1-octanol (obtained from ).

[0033] C12-OH initiator alcohol, which is a solution of greater than 98% by weight of 1-dodecanol (obtained from ).

[0034] C18-OH initiator alcohol, which is a solution of greater than 95% by weight of 1-octadecyl alcohol (obtained from ).

[0035] 15-S-3 is available from The Dow Chemical Company as TERGITOL TM 15-S-3 Secondary alcohol ethoxylation product obtained.

[0036] 15-S-40 is available from The Dow Chemical Company as TERGITOL TM 15-S-40 is a secondary alcohol ethoxylation product obtained.

[0037] AOS alpha-olefin sulfonate, available from AkzoNobel as Witconate TM AOS-12 is obtained as a foam booster and wetting agent.

[0038] Cation Exchange Resin A strongly acidic cation exchange resin used in industrial and residential softening and desalination applications, available from The Dow Chemical Company as DOWEX TM MARATHON TM C Resin is obtained.

[0039] Based on the anionic ring-opening polymerization of glycidol, an example of preparing HPG material is described below. The synthesis of HPG material is carried out in a 3-neck round-bottom flask (250 mL) equipped with a mechanical stirrer, a condenser and a low nitrogen flow. The initiating alcohol (0.1 mole) is added to a drying device. Toluene (~150 mL) is added and heated to reflux to remove residual water in the alcohol by azeotropic distillation. The flask is then cooled to room temperature. Sodium hydride (0.1 molar equivalent based on hydrophobic substance) is added to the stirred alcohol in the flask and reacted under nitrogen for about 1 hour. The reaction mixture is heated to 70°C and glycidol (distilled and stored under nitrogen) is added at a rate of 1-1.5 mL / hr using a syringe pump (with a dry syringe and needle). After the addition of glycidol is completed, stirring is continued at 70°C for several hours. The resulting reaction mixture is cooled to room temperature and then quenched with methanol (~150 mL) to dissolve the resulting crude HPG material. Then, a cation exchange resin is added and stirring is continued for 2 hours. The cation exchange resin is removed by filtration and the HPG material is then precipitated three times from methanol and ether. Prior to precipitation, the methanol solution of the HPG material may need to be concentrated by removing some of the methanol under reduced pressure to produce a good precipitation. The HPG material is dried in a vacuum oven to remove excess ether or methanol from the final product.

[0040] For each of HPG-1 to HPG-11, the ROH used is provided in Table 1 below.

[0041] Table 1

[0042]

[0043]

[0044] Referring to Table 1, the cloud point of each of HPG-1 to HPG-11 is determined by obtaining an initial cloud point measurement using a 1% solution of the HPG material in water. The solution is placed in a sealed glass tube and evaluated using a Mettler FP81 C Cell connected to a Mettler Toledo FP90 central processor. The sample is evaluated at the highest temperature of the instrument (140° C.), which is the lowest cloud point expected for an enhanced oil recovery process and indicates the successful synthesis of the HPG material. Thus in Table 1, it is advantageous to find that the HPG material is stable (i.e., not turbid) at temperatures above 140° C. Therefore, it is believed that the HPG material can be used under high temperature conditions in underground reservoirs.

[0045] In addition, the CMC as critical micelle concentration was determined using a Kibron Delta-8 multi-channel microtensiometer system, where the HPG material was added to an aqueous solution in an amount of 1% by weight. CMC is the additive concentration that determines the thermodynamically soluble aggregate in an aqueous solution. Above the CMC, it is considered that the solubility of the additive in an aqueous solution is exceeded. Therefore, it is shown that HPG-1 to HPG-11 are stable polymers at high temperatures and can be used in high temperature environments for oil recovery.

[0046] Referring to Table 2, the interfacial (surface) tensions of the examples of HPG-1 and HPG-3 to HPG-10 were evaluated, which exist when two phases (e.g., oil and water) are present. Interfacial tension is the force that holds the surfaces of a particular phase together and is provided in Table 2 below as a measurement based on dynes / cm. For Table 2, the interfacial tensions of 1 wt% HPG material solutions in dodecane at different temperatures were evaluated.

[0047] Table 2

[0048]

[0049] The interfacial tension (IFT) data of the HPG materials were obtained using a Tracker Tensiometer. For this test, dodecane was used as the oil droplet phase and a 1% solution of the HPG surfactant in water was used as the bulk phase. Interfacial tension measurements were performed at 110, 130, 150 and 170°C, and at least two measurements were performed at each temperature. Of critical significance, no turbidity was observed up to 170°C for any of the HPG materials. In particular, it can be seen that the HPG examples are able to maintain low surface tension between water and dodecane, even at high temperatures such as 170°C. In contrast, compared to the primary alcohols of the HPG materials, the secondary alcohol 15-S-40 became ineffective at maintaining the desired surface temperature at 130°C because the solution became turbid. This property is a very desirable quality in the enhanced oil recovery process. No measurements were obtained for sample HPG-9 at 170°C because the droplets were lost during the run. The interfacial tension (IFT) data of the HPG samples were obtained using a Tracker Tensiometer. Low surface tension refers to a surface tension of less than 20.00 dynes / cm at a temperature of 170° C. or less. Therefore, it is believed that HPG materials can be used in high temperature conditions of subterranean reservoirs (eg, as surfactants).

[0050] The examples of HPG-1 to HPG-11 were evaluated to adjust the fluid viscosity to evaluate the ability of the HPG material to be used in oil recovery. In particular, different samples were prepared using different weight percentages of HPG-1 to HPG-11 in water. Referring to Table 3 below, the viscosity measurements of the HPG-1 to HPG-11 samples were measured at 1 wt % to 70 wt % HPG in water. In Table 3, 1 wt % refers to 1 wt % HPG material in 99 wt % water, and 70 wt % refers to 70 wt % HPG material in 30 wt % water.

[0051] Table 3

[0052]

[0053] The viscosity (cp) for the data in Table 3 was measured on a Hamilton automatic liquid dispenser using the TADM (Total Aspiration and Dispense Monitoring) program at room temperature (eg, about 23° C.) The data are provided in centipoise at room temperature.

[0054] It was found that the HPG material has a relatively low viscosity at a concentration of about 10% HPG in water with a viscosity of less than 6 cp. When the HPG material is mixed with water of different concentrations, the viscosity is less than 300 cp even at a concentration of 50 wt. % HPG to 50 wt. % water. Therefore, it is believed that the HPG material can be used as an additive to water (e.g., circulating water) in different amounts in an enhanced oil recovery process for underground reservoirs.

[0055] The ability of HPG materials to withstand the severe salinity conditions of circulating water is being studied by observing phase separation. Specifically, the phase separation behavior using HPG materials was studied using salinity solutions. Referring to Table 4, commercially available AOS and experimental HPG-6, HPG-7, and HPG-9 were evaluated at 4% salinity and 12% salinity over a temperature range of 25°C to 80°C. The examples were prepared by mixing 4% NaCl and 12% NaCl by weight in distilled water, and then mixing the additives at a concentration of 1% in 4% and 12% brine, respectively, using an impeller at a speed of 300 rpm. Phase separation was observed within 30 minutes. The examples were heated using a hot plate to achieve different temperature ranges.

[0056] Table 4

[0057]

[0058] Referring to Table 4, the indication of clarity means that small particles in the sample are not observed by the naked eye and the sample is substantially clear. The indication of turbidity means that white is observed in the sample, but no obvious phase separation is observed by the naked eye. The indication of phase separation means that small particles in the liquid phase are observed by the naked eye, and is considered to be an indication of separation of the solid phase and the liquid phase in the sample.

[0059] As shown in Table 4, the HPG material is miscible with 4% and 12% salinity solutions at temperatures between 25° C. and 80° C. However, the commercially available AOS sample is immiscible with the 12% salinity solution at temperatures between 25° C. and 80° C. Therefore, in contrast to the AOS sample, the HPG material is believed to be useful in high-salinity conditions of circulating water used in enhanced oil recovery from underground reservoirs.

[0060] The water contact angle can be used to measure the wettability of a surface or material. Wetting refers to how a liquid deposited on a solid substrate spreads or the ability of a liquid to form a boundary surface with a solid state. The contact angle is the angle formed between the liquid-solid interface. The wettability change of the HPG material was evaluated based on the contact angle. Specifically, a 2000ppm HPG sample in a 10,978ppm TDS brine and a carbonate (limestone) core were used to measure the wettability change ability of the reservoir core. The core was aged in crude oil by soaking the core in a reservoir crude oil sample at 25°C for 24 hours. The brine without a drop of HPG sample was placed in the crude oil aged core to measure the contact angle. Then, a brine with a 2000ppm horizontal concentration of HPG material was placed on the crude oil aged core to measure the contact angle.

[0061] Referring to Table 5, HPG materials can change the contact angle of water droplets from >90° to significantly less than 90°. This shows that HPG materials can change the contact angle of rocks, making them hydrophilic, and then change the capillary pressure of water from negative to positive, so that water can enter the tight pores of the reservoir, expel oil from the tight pores, and enhance oil recovery.

[0062] Table 5

[0063] Contact angle (°) HPG-1 40.7 HPG-4 43.2 HPG-7 40.0 HPG-9 50.0

[0064] Interfacial (surface) tension (IFT) was measured between crude oil and brine samples (total dissolved salts of approximately 100,978 ppm) at 60°C, with and without HPG samples (see control). IFT was measured using a Kruss spinning drop apparatus at the concentrations provided below in Table 6. Specifically, approximately 5 ml of brine sample was used for the measurement by placing the brine in a spinning dropper and then inserting a small drop of oil using the typical procedure described in the Kruss spinning dropper manual.

[0065] Table 6

[0066]

[0067] Referring to Tables 5 and 6, HPG materials can provide excellent efficacy in changing the wettability of rocks from oil-wet to water-wet, and provide feasible IFT between crude oil and brine. Therefore, it is believed that HPG materials may be able to provide significant water self-imbibition in tight pores to expel oil from the reservoir, thereby improving oil recovery from the reservoir. Therefore, it is believed that HPG materials can be used as wettability-changing additives to improve oil recovery from underground reservoirs.

[0068] HPG materials were tested for foam formation. Specifically, commercially available AOS and experimental HPG-6, HPG-7, and HPG-9 were evaluated at 4% salinity in an amount of 2000 ppm using a Telis Foam Scan instrument to measure the foam volume (mL) from 0 seconds to 300 seconds. The foam volume of all examples was estimated to be 0 mL @ 0 seconds. The estimated foam volumes for 50 seconds and 300 seconds are shown in Table 7 below.

[0069] Table 7

[0070]

[0071] It is believed that both provide comparable performance in terms of foam volume control. In particular, all examples see a rapid increase in foam volume over a period of at least 0 seconds to 50 seconds. In addition, all examples achieve good performance at 300 seconds.

Claims

1. A method for an enhanced oil recovery process, the method comprising: A composition comprising a hyperbranched polyglycerol is injected into an injection well in an underground oil-bearing reservoir, wherein the hyperbranched polyglycerol is a primary alcohol having a C2 to C 25 Reaction products of carbon alcohols and various glycidols; and The composition is used to displace petroleum in the underground oil-bearing reservoir.

2. The method of claim 1, wherein the hyperbranched polyglycerol has a nominal hydroxyl functionality of at least 4.

3. The method of claim 1, wherein the hyperbranched polyglycerol is present in an amount of 0.001 wt% to 10.000 wt% based on the total weight of the composition.

4. The method according to any one of claims 1 to 3, wherein the enhanced oil recovery process is a foam-assisted enhanced oil recovery process.

5. The method according to any one of claims 1 to 3, wherein the enhanced oil recovery process is a waterflood enhanced oil recovery process.

6. The method according to any one of claims 1 to 3, wherein the enhanced oil recovery process is a steam-assisted enhanced oil recovery process.

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