METHOD OF OIL RECOVERY FROM AN UNDERGROUND PETROLEUM RESERVOIR

专利摘要:
method of recovering oil from an underground oil reservoir. The present invention relates to a method of recovering oil from an underground petroleum reservoir using an injection fluid comprising a viscosifying polymer in a low salinity water. the reservoir is penetrated by one or more injection wells and one or more production wells. the method comprises injecting the injection fluid into at least one of the injection wells in an extent of the heavy sludge in the range of 0.4 to 1.5 pore volume (pv).
公开号:BR112014019875B1
申请号:R112014019875-6
申请日:2013-02-08
公开日:2021-06-22
发明作者:Gary Russell Jerauld；Hourshad Mohammadi
申请人:Bp Exploration Operating Company Limited；
IPC主号:

专利说明:

[0001] The present invention relates to the recovery of oil from underground reservoirs. More particularly, it relates to oil recovery using injection fluids, especially enhanced recovery using injection fluids comprising polymers.
[0002] It has long been known that only a portion of the oil can be recovered from an underground petroleum formation as a result of the natural energy of the reservoir. So-called secondary recovery techniques are used to remove more oil from the reservoir, the simplest method of which is by direct replacement by another medium, usually water or gas.
[0003] "Water Injection" is one of the most successful and widely used secondary recovery methods. Water is typically injected under pressure into rock formations in the reservoir via injection wells. The injected water acts to help maintain reservoir pressure and sweeps the displaced oil ahead of it through the rock towards the production wells from which the oil is recovered. The water used for water injection can be high salinity water, eg sea water, estuarine water, saline aquifer water or produced water (water separated from oil and gas in a production facility) . By "high salinity" water is meant that the water has a total dissolved solids content (TDS) greater than 20,000 ppmv, eg greater than 30,000 ppmv.
[0004] Intensified oil recovery (EOR) techniques can also be used. The purpose of such EOR techniques is not only to restore or maintain pressure in the reservoir, but also to improve the displacement of oil in the reservoir, thereby further reducing the saturation of the reservoir's residual oil, that is, the volume of oil remaining in the reservoir. .
[0005] The injection of an aqueous solution of a polymer (also known as polymer injection) has been used as an EOR technique for 60 years. Its application has been predominantly onshore in reservoirs, where oil has a relatively high viscosity.
[0006] In general, polymer injection consists of adding a water-soluble polymer to an injection water (aqueous-based fluid), thus providing an injection fluid, having an increased viscosity and reduced mobility in the reservoir in comparison to the aqueous base fluid. Polymer injection increases hydrocarbon recovery, eg oil, over secondary recovery (eg water injection) primarily by improving volumetric and microscopic sweeping efficiency. This can be especially beneficial, since in many reservoirs injection water is more mobile than oil, so it tends to pass through reservoir regions with less permeability leaving behind significant volumes of oil. The difference between the mobility of the aqueous polymer solution and that of the oil in the reservoir is less than the difference between the mobility of the aqueous base fluid and the oil in the reservoir. This reduction in aqueous injection fluid mobility relative to oil mobility can lead to enhanced oil recovery.
[0007] Typically, reservoirs having petroleum viscosities of 3 centipoises (cP) (3 mPa.s) or more can be considered suitable for polymer injection, ie EOR using an aqueous solution or dispersion of a polymer.
[0008] It is also known that the use of a low salinity injection water during water injection can increase the amount of oil recovered compared to the use of a high salinity water. Low salinity water can be, for example, lake water, river water, low salinity aquifer water or desalinated water.
[0009] It is also known that the reduction of the multivalent cation content in an injection water of low salinity can have an impact on oil recovery.
[00010] Thus, International Patent Application No. WO2008/029124 teaches that the recovery of oil from a reservoir comprising an oil sandstone rock formation is intensified (compared to the injection of a high salinity water) when the injection water it has a total dissolved solids content (TDS) in the range of 200 to 12,000 ppmv and the ratio of the multivalent cation content of the injection water to that of the connate water contained in the sandstone rock is less than 1.
[00011] The present invention relates to the aspects of using a polymer in a low salinity injection water, that is, a combination of low salinity water injection and polymer injection.
[00012] According to the present invention, there is provided a method that includes the recovery of oil in an underground petroleum reservoir using an injection fluid, comprising a viscosifying polymer in a low salinity water, the reservoir being penetrated by one or more injection wells and one or more production wells, the method comprising injecting the injection fluid into at least one of the injection wells.
[00013] Other features and advantages of the invention will become apparent from the following description of preferred embodiments of the invention, provided by way of example only, which is made with reference to the accompanying drawings. BRIEF DESCRIPTION OF THE DRAWINGS
[00014] Figure 1 shows the rheological behavior of an aqueous fluid comprising 2000 ppm of a partially hydrolyzed polyacrylamide, HP AM 3330S, at a temperature of 25°C, as a function of the salinity (above) and the concentration of the divalent cation (below ); SPE 124798 data (Lee, S., Kim, DH, Huh, C and Pope, GA (2009) Development of a Comprehensive Rheological Property Database for EOR Polymers, work of SPE 124798 presented at the SPE Annual Technical Conference and Exhibition held in New Orleans, Louisiana, USA, October 4-7).
[00015] Figure 2 shows polymer viscosity versus salinity over a wide range of salinity; SPE data 141497 (Vermolen, ECM, van Haasterecht, MJT, Masalmeh, SK, Faber, MJ, Boersma, DM, and Gruenenfelder, M. (2011) Pushing the Envelope for Polymer Flooding Towards High-temperature and High-salinity Reservoirs with Polyacrylamide Based Terpolymers, work of SPE 141497 presented at SPE's Middle East Oil and Gas Conference and Sample held in Manama, Bahrain, 25-28 September).
[00016] Figure 3 shows the relative permeability curves for high and low salinity brines.
[00017] Figure 4 shows a comparison of the fractional flow of water for a high salinity water injection, a low salinity water injection, a polymer injection and a combination of a low salinity and polymer injection.
[00018] Figure 5 shows a comparison of oil recovery for different EOR techniques; oil recovery using a combination of low salinity and polymer injection is the sum of the individual processes.
[00019] Figure 6 shows a comparison of oil saturation maps for low salinity water injection and a combination of low salinity and polymer injection for 0.5 (above) and 1.0 (below) pore volumes ( PV) of the injected fluid.
[00020] Figure 7 shows the permeability (millidarces [md]) in a heterogeneous model of a 1/8 of a 9-point well pattern of injection and production wells. The model is in the shape of a Parrot to model the asymmetry of the pattern.
[00021] Figure 8 shows a comparison of incremental oil recovery between heterogeneous (dashed lines) and homogeneous (solid lines) modeled cases for oils with viscosities of 5 and 50 cP (5 and 50 mPa.s).
[00022] Figure 9 shows an oil saturation map for a low salinity water injection, with and without polymer, in two layers of reservoir rock.
[00023] Figure 10 shows a comparison of secondary versus tertiary oil recovery responses for techniques other than EOR (for a 5 cP oil).
[00024] Figure 11 shows a comparison of the synergistic behavior of a combination of low salinity water injection and polymer injection under secondary and tertiary recovery conditions for an oil of 5 cP and 50 cP (5 and 50 mPa.s ).
[00025] Figure 12 shows the effect of heavy sludge extension from a low salinity water injection with and without polymer on oil recovery.
[00026] Figure 13 shows the permeability of a standard 5-point well reservoir model with one injection well and 4 producer wells.
[00027] Figure 14 shows incremental oil recovery for a high salinity water injection, low salinity water injection, with and without polymer, and a polymer injection (with a high salinity base brine) for a model of five-point well pattern reservoir (above). This model is limited to injectivity (below).
[00028] Figure 15 shows incremental oil recovery for a high salinity water injection, low salinity water injection, with and without polymer, and a polymer injection (with a high salinity base brine) for a model five-point well pattern reservoir; this model is not limited to injectivity.
[00029] Figure 16 shows incremental oil recovery for a high salinity water injection, low salinity water injection, with and without polymer, and a polymer injection (with a high salinity base brine) for a model of five-point well pattern reservoir with infill drilling (above). This model is limited to injectivity (below).
[00030] Figure 17 shows incremental oil recovery for a high salinity water injection, low salinity water injection, with and without polymer, and a polymer injection (with a high salinity base brine) for a model five-point well pattern reservoir with infill drilling; this model is not limited to injectivity.
[00031] According to the present invention, there is provided a method of oil recovery in an underground petroleum reservoir using an injection fluid, comprising a viscosifying polymer in a low salinity water, the reservoir being penetrated by one or more wells injection wells and one or more production wells, the method comprising injecting the injection fluid into at least one of the injection wells in a length of heavy slurry in the range of 0.4 to 1.5 pore volume (PV).
[00032] The Low Salinity Water The low salinity water has a total dissolved solids content (TDS) of 15,000 ppmv or less, preferably less than 12,000 ppmv, more preferably less than 10,000 ppmv, more preferably less than 8,000 ppmv ppmv, in particular, less than 5,000 ppmv. The low salinity water has a total dissolved solids content (TDS) of at least 100 ppmv, preferably at least 200 ppmv, more preferably at least 500 ppmv, more preferably at least 1000 ppmv. Preferably, the ratio of the multivalent cation content of the low salinity water to the multivalent cation content of the connate water of the reservoir is less than 1, more preferably less than 0.9, for example less than 0.8.
[00033] The term “contact water” refers to the original water that was confined in the pore space of the reservoir formation rock (prior to any injection of water into the reservoir during the recovery of oil from the reservoir).
[00034] The invention can be applied to intensified oil recovery from a reservoir, in which the tap water has a wide range of TDS levels, typically from 500 to 200,000 ppmv, preferably from 2,000 to 50,000 ppmv, in particular of 10,000 to 50,000 ppmv, especially from 20,000 to 45,000 ppmv. As discussed above, connate water is the original water associated with petroleum in the reservoir formation rock and is in equilibrium with the petroleum and reservoir formation rock, especially with respect to its multivalent cation content, in particular its content. of divalent cation (eg calcium or magnesium cation). The calcium cation content of the tap water is generally at least 50 ppm, such as 50 to 2000 ppmv and especially 100 to 500 ppmv. The magnesium cation content of the conate water is generally at least 10 ppm, such as 10 to 2000 ppmv and especially 20 to 200 ppmv. The total content of divalent cation of the conate water is generally at least 100 ppm, such as 100 to 5,000 ppmv, preferably 150 to 3,000 ppmv, especially 200 to 1,000 ppmv. In general, tap water contains low levels of trivalent cations, generally less than 100 ppmv.
[00035] When the method of the present invention has to be used during the recovery of secondary or tertiary oil from the reservoir, a sample of the connate water can be obtained by taking a core rock from the reservoir, either before the production of oil from the reservoir or during the primary recovery, and determining the multivalent cation content of the water contained in the core. Alternatively, the multivalent cation content of the water that is separated from the oil produced can be determined where water has broken down, but the reservoir has remained in primary recovery.
[00036] It is preferable that the low salinity water which is employed as the base fluid of the injection fluid has a multivalent cation content of less than 200 ppmv, more preferably less than 100 ppmv, in particular 40 ppmv or less, for example , less than 25 ppmv.
[00037] Suitable low salinity waters include desalinated water, fresh water such as river water or lake water, low salinity estuarine water resulting from mixing fresh water and sea water in estuaries, aquifer water from low salinity and low salinity produced water (water separated from oil and gas in a production unit). If desired, the water mixtures can be used as the source of low salinity water for the injection fluid, for example an aquifer water or desalinated water mixed at low TDS with a high salinity water such as produced water or sea water. The oil reservoir
[00038] The oil reservoir typically takes the form of an underground oil rock formation having sufficient porosity and permeability to store and transmit fluids, and with which oil is associated, for example, being kept in the pores or between the grains of the rock formation . The reservoir typically includes tap water.
[00039] Rock formation can include sandstone rock with which oil is associated, either by inclusion in pores or between grains or otherwise.
[00040] The rock formation, for example sandstone rock, of the reservoir may comprise minerals in an amount of up to 50% by weight, more preferably from 1 to 30% and especially from 2.5 to 20% by weight. The mineral may be a clay, in particular clay of the smectite type (such as montmorillonite), the pyrophyllite type, the kaolinite type, the illite type, the glauconite type and the chlorite type. Preferably, the clay does not expand under crude oil recovery conditions from the reservoir. Examples of other minerals that may be present in a sandstone rock include transition metal compounds such as oxides and carbonates, eg iron oxide, siderite and plagioclase feldspars. The amount of minerals in the sandstone rock can be determined by X-ray diffraction using the upper soil rock of the reservoir.
[00041] When the rock formation, for example, the oil reservoir sandstone rock contains expanding clays, in particular smectite clays, a relatively high TDS for low salinity water may be necessary to stabilize the clays, thus reducing the risk of formation damage. Thus, when the rock formation contains an amount of swelling clays sufficient to result in formation damage (for example, an amount of swelling clays greater than 10% by weight), the low salinity water preferably has a content total dissolved solids (TDS) in the range of 8,000 to 15,000 ppmv. When the rock formation comprises amounts of swelling clays that do not result in significant formation damage (for example, an amount of swelling clays less than 10% by weight), the TDS of the low salinity water is typically in the range of 100 to 8,000 ppmv, preferably 200 to 5,000 ppmv, for example 200 to 3,000 ppmv.
[00042] The oil contained in the reservoir may be a crude oil having an American Petroleum Institute (API) gravity of at least 15°, preferably at least 16°, for example, an API gravity in the range of 16 to 30th.
[00043] The oil contained in the reservoir can generally have a viscosity under reservoir conditions in the range of 3 to 200 centipoises (cP)(3 to 200 mPa.s), for example, in the range of 5 to 175 cP and in particularly in the range of 10 to 150 cP (10 to 150 mPa.s). However, in certain aspects, the present invention is particularly concerned with higher viscosity oils. This is discussed later in relation to secondary oil recovery. In such cases, the viscosity of the oil will be in the range from 40 to 200 cP (40 to 200 mPa.s), preferably from 45 to 175 cP (45 to 175 mPa.s), in particular from 47 to 150 cP (47 at 150 mPa.s).
[00044] Typically, the oil that is associated with the reservoir rock has gas dissolved in it. The viscosification polymer and the injection fluid
[00045] Typically, the polymer(s) to be used as the viscosification polymer may be more useful (useful) in an Intensified Oil Recovery (EOR) operation. The polymer(s) can be homo or heteropolymer(s) (for example, copolymer, terpolymer and others). The polymer(s) will, in general, be ionic, eg anionic(s). The polymer, or one or more of the polymers, can be an acrylamide polymer. The polymer(s) may be partially hydrolyzed. The degree of hydrolysis (T) can be from 0.15 to 0.40 and is typically from 0.25 to 0.35. The polymer(s) may be a partially hydrolyzed polyacrylamide (HP AM), for example, with a degree of hydrolysis from 0.15 to 0.40 or from 0.25 to 0.35. A suitable polymer can be selected from the FLOPAAM™ series supplied by SNF SAS. Members of the FLOPAAM™ series, which can be supplied as a powder or as an emulsion, include FLOPAAM 3630, FLOPAAM™ 3530, FLOPAAM™ 3430, FLOPAAM™ 3330, FLOPAAM™ 2530, FLOPAAM™ 2430, and FLOPAAM™ 2330.
[00046] The injection fluid is preferably a solution of the viscosifying polymer in low salinity water. However, the injection fluid can also be a dispersion of the viscosifying polymer in low salinity water, and such dispersions are also included in the present invention.
[00047] Advantageously, the polymer is, or the polymers are, substantially uniformly distributed within the injection fluid.
[00048] The injection fluid is typically aqueous and therefore is generally an aqueous solution of the viscosifying polymer or an aqueous dispersion of the viscosifying polymer.
[00049] Optionally, the polymer can be supplied as a powder. Preferably the polymer powder is at least 80% by active weight, preferably at least 90%, said in excess of 95% by active weight. Preferably, the powder is used to prepare a dispersion or stock solution of the polymer in water having a polymer concentration of at least 5% by weight, preferably at least 10% by weight, for example from 5 to 20% by weight. Weight. Typically, the powder will take approximately two hours to hydrate during preparation of the dispersion or stock solution. Alternatively, polymer powder can be added directly to low salinity water to form the viscosified low salinity injection fluid.
[00050] Preferably, the dispersion or stock solution can comprise up to 20,000 ppm of polymer by weight. For example, the dispersion or mother liquor can comprise around 10,000 ppm polymer by weight. Preferably, the dispersion or stock solution is metered into the low salinity water so that the resulting injection fluid can comprise up to 2000 ppm of polymer by weight. The injection fluid typically comprises at least 500 ppm of polymer by weight. For example, the injection fluid can comprise about 1500 ppm, 1250 ppm, 1000 ppm or 700 ppm polymer by weight.
[00051] The polymer can be supplied in the form of a concentrated dispersion, eg a colloidal dispersion (instead of being supplied in the form of a powder which is later used to form a concentrated dispersion). Thus, a concentrated dispersion of the polymer in a fluid, eg water, can be added to low salinity water.
[00052] Alternatively, the polymer can be provided in the form of an emulsion comprising a dispersed aqueous phase, in which the polymer is dissolved or dispersed in a continuous petroleum phase, for example an emulsion in which droplets of the aqueous phase are dispersed in the oil stage. Preferably the aqueous phase is a highly concentrated polymer solution. Preferably, the petroleum phase is a mineral oil. Preferably, the emulsion comprises from 28-32% (w/w) polymer, for example 30% (w/w) polymer.
[00053] Surfactants can be present in the solution, emulsion or other dispersion of the polymer. For example, surfactants can be used to break a polymer emulsion if the polymer is used in the form of an emulsion.
[00054] Preferably the emulsion, dispersion or mother liquor is metered into the low salinity water to provide an injection fluid with the desired polymer concentration and the desired viscosity under reservoir conditions. The emulsion, dispersion or mother liquor can be metered or injected into the low salinity injection water through a dedicated water injection rotary joint or through a port on an injection manifold.
[00055] The viscosity of the injection fluid can be controlled and/or changed by introducing one or more different polymers into the injection fluid, for example, replacing a first polymer with a second or introducing a second polymer into the stream comprising a first polymer . Thus, the viscosity of the injection fluid can be controlled and/or changed by selecting the molecular weight and/or chemical composition of the polymer(s). The injection fluid viscosity can also be controlled and/or changed by changing the polymer concentration in the injection fluid.
[00056] It has been found that the viscosity of a polymer solution can depend on the ratio of the comonomers in the polymer. For example, HP AM polymers are typically copolymers of acrylic acid and acrylamide. The viscosity of a polymer dispersion or solution increases with an increasing mol% of acrylic acid-derived structural units in the polymer. However, higher acrylic acid contents result in polymer adsorption to the reservoir rock, thus reducing the polymer concentration at the site. A balance therefore needs to be struck. Typically, the polymer contains 15 to 40% by mol of acrylic acid residues, for example 25 to 35% by mol of acrylic acid residues.
[00057] The viscosity of a polymer solution depends on the salinity of the water employed as the base fluid for the polymer solution or dispersion. Viscosity increases with decreasing salinity. Therefore, an advantage of using low salinity water in the injection fluid of the present invention is that lower polymer concentrations can be used to obtain the same viscosity compared to using high salinity base fluids.
[00058] Typically, the method of the present invention can be applied in reservoirs, with a temperature of up to 140°C. Higher temperatures may be outside the operating range for existing hydrolyzed polyacrylamide polymers. Since polyacrylamide polymers widely used in chemical EOR processes tend to hydrolyze at elevated temperatures and the hydrolyzed polymer tends to precipitate if the multivalent cation concentration (eg calcium concentration) is above 200 ppmv, the method of the present The invention is useful at reservoir temperatures at or above 100°C, as well as below 100°C, for example, at reservoir temperatures from 100°C to 140°C. The method of the present invention may also allow the use of polyacrylamide polymers, with a higher initial degree of hydrolysis. By "high degree of hydrolysis" is meant a polyacrylamide polymer in which the degree of hydrolysis (T) of the acrylamide units is at least 0.33.
[00059] The method of the present invention can be practiced in oil-containing reservoirs with a viscosity lower or higher than that which is usual for reservoirs considered suitable for a polymer injection, for example, 3 to 200 cP (3 to 200 mPa.s) .
[00060] The viscosity of polymer solutions decreases with increasing shear speed. The plot of the relative viscosity of the polymer solution versus the shear rate initially follows a Newtonian plateau, in other words, there is a relatively constant viscosity, with increasing shear rate, up to a certain point. Beyond this point, viscosity starts to drop with increasing shear rate. If the polymer does not degrade, the viscosity will follow the same curve if the shear rate is reduced. If the shear rate is so high that the polymer chains break, then the viscosity will no longer follow the same curve with decreasing shear rate, but will follow a different Newtonian plateau at a lower viscosity. Therefore, the viscosity at the lower shear rate will be lower as if there had been no degradation.
[00061] The viscosity curves shift upwards with increasing polymer concentration. Preferably, the shear velocities under reservoir conditions will be at the Newtonian plateau. Preferably, downhole shear velocity will lead to no or minimal shear degradation. Preferably, the treatment is designed so that downhole conditions approach the Newtonian region of the polymer solution viscosity versus shear rate curve.
[00062] It is known in the art that the viscosity of an emulsion, dispersion or polymer solution depends on some factors, for example, one or more of shear rate and temperature, and concentration of multivalent cation (especially calcium). The temperature and shear rate at the bottom of a reservoir typically cannot be controlled. However, the viscosity of the injected polymer injection under reservoir conditions will also depend on: (a) the type of polymer (chemical structure), (b) the molecular weight of the polymer and therefore the extent of any polymer shear degradation , in other words from the cleavage of the polymer chains; and (c) the concentration of polymer in the injection fluid.
[00063] Preferably, the concentration of polymer in the injection fluid is selected to provide a desired viscosity and/or mobility under reservoir conditions, for example, under reservoir temperature and pressure and estimated shear velocity within the reservoir .
[00064] Preferably, the ratio of the mobility of the petroleum to the mobility at the site of the injection fluid is close to or of 1:1. Typically this ratio might be 0.11:1-1.5, it is said 0.5-1:1-1.5. Preferably, the mobility of the injection fluid under reservoir conditions is not greater than that of petroleum.
[00065] Preferably, laboratory experiments are used to predict the viscosity of the injection fluid in the reservoir. For example, such predictions can be based on one or more types of polymer, polymer molecular weight, polymer concentration, reservoir temperature, injection brine composition, and the shear rate within the reservoir. This is because the viscosity of the injection fluid in the injection line downstream of the metering point will differ from the viscosity within the reservoir (eg at a radial distance greater than 10 meters from the injection well bore).
[00066] Economic factors can also be considered when selecting the optimal viscosity of the injection fluid, in particular the desire to minimize the amount of polymer needed, since the polymer can be relatively costly and the need to maximize the net present value (NPV) of the project. In this sense, it may be preferable to carry out a reservoir simulation and, optionally, an economic study, when estimating the ideal viscosity of the injection fluid. Therefore, the method can achieve an ideal or close to ideal balance between incremental oil cost and recovery.
[00067] The viscosity of the injection fluid will typically be in the range of 3 to 200 cP (3 to 200 mPa.s). The initial viscosity will typically be chosen to match the viscosity of the fluid in the reservoir.
[00068] The viscosity of the polymer solution is a function of the polymer composition and its molecular weight, polymer concentration, brine composition, temperature and shear rate. With all other factors fixed for the reservoir, it is the polymer selected and the concentration at which it is deployed and the salinity of the aqueous base fluid that determine the reduction in the mobility ratio of the water injection and the enhanced oil recovery. It is also the selected polymer and its concentration and selected brine composition that limit the injection rate into the reservoir and determine whether the reservoir's porosity can be maintained. In this document, the mobility ratio is understood as the mobility ratio of injection water (displacement fluid) to the mobility of oil (displaced fluid).
[00069] The polymer may be a partially hydrolyzed polyacrylamide (HP AM) such as FLOPAAM™ 3630S. This polymer is capable of imparting a high viscosity to an aqueous fluid (the viscosity depending on the polymer concentration). Preferably, the polymer solution is pseudoplastic. Thus, polyacrylamide polymers hydrolyze at high temperatures and are prone to precipitation above a certain concentration of divalent cation. If divalent cation concentrations, such as calcium and magnesium cation concentrations, are kept below about 500 ppm, preferably below 200 ppm the use of polyacrylamide polymers is feasible at reservoir temperatures of up to 140 °C. The heavy mud extension
[00070] If an injection fluid consists of low salinity water without viscosifying polymer, it has been found that incremental oil recovery is achieved until the amount of fluid injected is about 0.3 pore volumes (PV) . Above this volume of low salinity water pores, incremental oil recovery decreases drastically with little additional oil recovery benefit being observed.
[00071] It is believed that a heavy injection fluid slurry consisting of low salinity water, without viscosifying polymer with less than 0.3 PV tends to dissipate into the reservoir by mixing with the connate water and/or any water previously that is present in the pore space of the reservoir rock and/or with an aqueous drive fluid injected later. On the other hand, if a heavy injection fluid slurry consisting of low salinity water without the viscosifying polymer of at least 0.3 PV is injected into the reservoir, it is believed that the heavy slurry remains intact in the reservoir, so an injection fluid front to move through the reservoir until the injection fluid ruptures the production well.
[00072] In contrast to the situation, where the injection fluid is a low salinity water, without viscosifying polymer, it has been found in the present invention that it remains beneficial in terms of incremental oil recovery above 0.3 PV. In the case of low viscosity oil, for example, oil with a viscosity of 3 to 40 cP (3 to 40 mPa.s), for example, around 5 cP (5 mPa.s), the incremental oil recovery decreases the about 1.0 to 1.2 PV of fluid injected. In the case of high viscosity oil, for example, oil with a viscosity of 40 to 200 cP (40 to 200 mPa.s), or from 45 to 175 cP (45 to 175 mPa.s), or from 47 to 150 cP ( 47 to 150 mPa.s), for example, around 50 cP (50 mPa.s), the incremental oil recovery decreases to about 0.7 to 0.8 PV of fluid injected.
[00073] According to the present invention, the heavy slurry extent of the injection fluid (comprising a viscosifying polymer in a low salinity water) can be in the range of 0.4 PV to 2.0 PV. However, it is preferable in the range of 0.5 to 1.5 PV. In the case of high viscosity oil, for example, oil with a viscosity of 40 to 200 cP (40 to 200 mPa.s), or 45 to 175 cP (45 to 175 mPa.s), or 47 to 150 cP (47 to 150 mPa.s), for example around 50 cP (50 mPa.s), the heavy slurry extent of the injection fluid can be in particular in the range of 0.5 to 0.9 PV, for example, from 0.6 to 0.8 PV. In the case of low viscosity oil, for example, oil with a viscosity of 3 to 40 cP (3 to 40 mPa.s), for example, around 5 cP (5 mPa.s), the heavy slurry extension of the injection fluid may in particular be in the range of 0.7 to 1.5 PV, for example 0.8 to 1.2 PV.
[00074] Economic factors can also be considered when selecting the optimal extent of heavy injection fluid slurry, in particular the desire to minimize the amount of polymer and low salinity water required, since the polymer and production of low salinity water can be relatively costly. In this sense, it may be preferable to carry out a reservoir simulation and, optionally, an economic study, when estimating the ideal viscosity of the injection fluid. Therefore, the method can achieve an ideal or close to ideal balance between cost and incremental oil recovery when using a viscosifying polymer in a low salinity water.
[00075] The term “pore volume” (“PV”) is used here to mean the volume swept between an injection well and a production well. The pore volume between an injection well and a production well can be readily determined by methods known to the person skilled in the art. Such methods include modeling studies. However, pore volume can also be determined by passing a water having a tracker through the reservoir from the injection well to the production well. The swept volume is the volume swept by the injection fluid calculated over all flow paths between the injection well and the production well. This can be determined with reference to the first temporal moment of distribution of the tracker in produced water, as would be well known to a person skilled in the art.
[00076] The surface velocity of the injection fluid in the reservoir is typically in the range of 0.015 to 10 feet/day (0.0045 to 3 meters/day) and is most often in the range of 1 to 4 meters per day (0, 3 to 1.2 meters/day) at a radial distance greater than 20 feet from the injection well. The spacing between wells between the injection well and the production well can typically be 1000 to 8000 feet (304.8 to 2438.4 meters). Therefore, it can take months or years for the oil bank to release and for the injection fluid to rupture the production well. Thus, there is a delay between the start of injection fluid injection into the reservoir and the recovery of incremental oil in the production well.
[00077] After injection of the injection fluid, a drive fluid can be injected into the reservoir. The drive fluid can be water with more salinity than the low salinity water that is used in the injection fluid, and for example it can be sea water, a high salinity produced water, or a high salinity aquifer water. Typically, the high salinity drive fluid has a TDS of at least 20,000 ppm, for example at least 30,000 ppm. The high salinity water employed as the driving fluid is typically heavy water, with a multivalent cation content of at least 100 ppmv, preferably at least 500 ppmv, in particular at least 1000 ppmv, for example at least , 1500 ppmv. However, the drive fluid can also be a low salinity water as defined for the injection fluid. The person skilled in the art will understand that for offshore reservoirs, the supply of a low salinity water may be limited, as it is preferred to use a high salinity water as the drive fluid.
[00078] The drive fluid sweeps the injection fluid (and therefore the released oil bank) through the reservoir to the production well. In addition to sweeping the injection fluid through the reservoir, injection of the driving fluid may be necessary to maintain pressure in the reservoir. Typically, the drive fluid is injected into the reservoir at a pore volume greater than the injection fluid, eg a pore volume of at least 1, preferably at least 2, eg in the range of 2 to 10.
[00079] Typically, the viscosity of the injection fluid under reservoir conditions is in the range of 3 to 200 centipoises (3 to 200 mPa.s). On the other hand, the viscosity of the drive fluid under reservoir conditions is typically in the range of 0.3 to 1 centipoise (0.3 to 1 mPa.s).
[00080] A spacer fluid can be injected into the reservoir before and/or after the injection of the injection fluid comprising the viscosifying polymer into the low salinity water. The spacer fluid can be a low salinity water base fluid or a high salinity light water. Typically, the spacer fluid is injected in an amount of at least 0.05 PV, for example, at least 0.1 PV. The use of a spacer fluid with a low concentration of multivalent cations reduces the risk of polymer in front or on the heavy slurry of the viscosifying polymer in the low salinity aqueous base fluid encountering the multivalent cations that could otherwise precipitate the polymer .
[00081] In the method of the invention, the injection fluid is preferably injected under pressure, for example, at a pressure of 10,000 to 100,000 kPa (100 to 1000 bar) in at least one injection well that is spaced apart from a well of production and passes directly into the oil rock of the injection well reservoir. Passing the injection fluid displaces the oil from the reservoir rock and forces the displaced oil forward from the reservoir and towards the production well from which the oil is recovered. recovery mode
[00082] The method of the invention can be used at the start of oil production from the reservoir (omitting the primary recovery), in the secondary recovery mode (after the primary recovery of oil under the natural pressure of the reservoir) or in the tertiary recovery mode (eg after a water injection with a high salinity water or a low salinity water).
[00083] The person skilled in the art will understand that in the secondary recovery mode, a fluid is injected into the reservoir of an injection well to maintain pressure in the reservoir and to sweep the oil towards a production well. An advantage of injecting the injection fluid of the present invention into the reservoir during secondary recovery is that the injection fluid has been formulated to release additional oil from the pore surface of the reservoir rock and/or to be more effective in sweeping the released oil by the reservoir. In this sense, there may be a long period of recovery of anhydrous oil from the production well, thus prolonging the disruption of water. Furthermore, even after water breakdown, there will be enhanced oil recovery compared to using low salinity water without viscosifying polymer as injection water. In addition, there may be less water production (a higher water to oil ratio) for a given volume of fluid produced compared to using low salinity water without viscosifying polymer as injection water. These advantages also apply if the method of the present invention is used at the start of oil production from a reservoir.
[00084] According to the present invention, it was surprisingly found that an improved synergistic behavior in secondary recovery between water injection and low salinity polymer injection was observed in relation to more viscous oil. In this regard, it is preferable to apply the method of the present invention to secondary recovery, where the oil has a viscosity of 40 to 200 cP (40 to 200 mPa.s), or 45 to 175 cP (45 to 175 mPa.s) , in particular from 47 to 150 cP (47 to 150 mPa.s).
[00085] The person skilled in the art will understand that in the tertiary recovery mode, the injection of the original fluid is stopped and a different fluid is injected into the reservoir for an enhanced oil recovery. Thus, the fluid that is injected into the reservoir during tertiary recovery is the injection fluid of the present invention (comprising a viscosifying polymer in a low salinity water), and the fluid that was previously injected into the reservoir during secondary recovery can be a low salinity water (which does not contain any polymer) or a high salinity water such as sea water or a high salinity produced water.
[00086] There can be one injection well and one production well, but preferably there can be more than one injection well and more than one production well. There can be many different spatial relationships between injection wells and production wells. Injection wells can be located close to the production well. Alternatively, the injection wells can be in two or more rows between which the production wells are located. These settings are called “standard injection”, and the person skilled in the art will know how to operate the injection wells to obtain maximum oil recovery during water injection treatment (secondary or tertiary recovery). When injection fluid is injected into the reservoir through an injection well with two or more associated production wells, the pore volume of the injection fluid will be the volume swept between the injection well and the two or more production wells . The person skilled in the art will understand that depending on the spatial arrangement of the injection well and its associated production wells, the injection fluid may rupture each of the production wells at different times.
[00087] The invention can be operated onshore or offshore. Greater control over polymer use and more efficient polymer use, which is envisioned by the invention, could allow more offshore locations to use polymer injection technology in EOR operations. Computer Implemented Method and System
[00088] In order to determine the optimal configurations of various components of an oil recovery system, the system is simulated using one or more models, as described in international publication no. WO2010/139932 (the contents of which are hereby incorporated by reference). Each of the models can be dedicated to a specific part of the recovery system.
[00089] A reservoir model, which, as is known in the art, is a three-dimensional conceptual construction of a reservoir that is built from incomplete data with much of the space between wells, estimated from data obtained from nearby or seismic data can be employed. The reservoir model uses a predetermined set of rules together with the relevant input data to generate the necessary output data. In conjunction with this, a reservoir simulation, ie a computer model that predicts fluid flow through porous media (and is therefore based on the reservoir model) can be employed.
[00090] A predictive model, as further described below, can predict the amount of incremental oil displaced from the reservoir rock. Using the reservoir model, the reservoir simulation can use information such as the volume and shape of the reservoir (including the arrangement of overlying rock formations and the locations of any faults or fractures in the rock formations), the porosity of the petroleum rock formations, the permeability of the oil rock formation(s) in different directions (including the permeabilities related to oil and water), the initial oil saturation of the oil rock formation(s), the location of the well(s) ( s) of production and injection well(s), the predicted sweep (the volume of the reservoir swept by an injection fluid that is injected into the injection well(s)), in combination with the results of the predictive model , to provide an indication of how much of the projected displaced oil can be recovered from the production well(s). The models are preferably run by a processing system, for example a control system on a platform, which may comprise the operating system and conventional storage components.
[00091] The additional or incremental amount of oil that is predicted by the predictive model is an amount, in terms of, for example, a percentage, fraction or volume, of oil that will be displaced or recovered compared to a predetermined volume of oil, which is inserted into the predictive model. The predetermined volume of oil may comprise a "base" oil volume displacement (or recovery), which is calculated by running a simulation of a "base water injection" using the reservoir model. This base value reflects the oil that could be recovered or displaced (both calculations are possible by the reservoir model) based on the physical parameters of the injection fluid (such as injection pressure, injection fluid volume and injection rate) and the physical parameters of the particular reservoir(s) (such as reservoir pressure, porosity and permeability of the formation rock). Typically, the additional or incremental amount of oil is expressed as a percentage or fraction of the predetermined base amount. Alternatively, the additional or incremental volume of oil can be calculated using the predictive model based on a predetermined volume of oil that represents the original volume of oil calculated or estimated to be in place in the reservoir prior to any oil displacement or recovery (prior to primary recovery) or immediately prior to the proposed injection of injection fluid (eg, after primary recovery or after secondary recovery with a different injection fluid).
[00092] By using the results of the predictive model and running the reservoir model to simulate the recovery of displaced oil in the production wells, the reservoir model predicts a residual oil saturation that will be achieved by injecting water into the reservoir using the injection fluid comprising a polymer viscosifying the low salinity water and compares this residual oil saturation with a reservoir oil saturation that would have been achieved using an injection fluid comprising the low salinity water alone or an injection fluid comprising a viscosifying polymer in a higher salinity water, thereby providing a prediction of incremental oil recovery.
[00093] The model is able to predict the incremental oil recovery for each of these EOR techniques (compared to a standard high salinity water injection, eg a seawater injection). However, injection fluid comprising a viscosifying polymer in a low salinity water is likely to cause incremental oil recovery on low salinity water injection or polymer injection using a viscosifying polymer in a low water salinity.
[00094] The measurement data received by the system receiving means is based on the measured chemical characteristics of the oil reservoir environment and the injection fluid, as further explained below. The measurement data may comprise specific measured chemical values as measured directly by suitably positioned measurement equipment or chemical characteristic value ratios or may comprise values derived from several separate chemical characteristic measurements in accordance with known techniques.
[00095] In order for the predictive model to generate data indicative of a predicted amount of incremental displaced oil that will be achieved by configuring the crude oil displacement system in order to inject the injection fluid (comprising a viscosification polymer in a water of low salinity) having the chemical characteristics measured in the reservoir, the measurement data associated with certain chemical characteristics of the injection fluid, the rock formation, the formation water and crude oil must be entered in the model. These chemical characteristics include: the clay content of the whole rock of the reservoir rock, which can be determined by X-Ray Diffraction (XRD), Scanning Electron Microscopy (SEM) or infrared flash point strapping; the mineral content of the clay fraction of the rock, in particular clays of the smectite type (such as montmorillonite), the pyrophyllite type, the kaolinite type, the illite type and the glauconite type, which can be determined by X-ray diffraction ( XRD) or scanning electron microscopy (SEM); the gravity of oil (relative density) from the American Petroleum Institute (API); the total acid number (TAN value, a measure of acidity) of the oil; the content of asphaltene and petroleum resin components; the viscosity of oil in pressure and temperature in the reservoir; the viscosity of the stock tank crude oil (the oil that has been separated at the production facility) under standard conditions (eg viscosity measurement can be taken at 20°C, 25°C and 30°C); the total dissolved solids content (TDS) of the formation water, the concentration of multivalent cations of the formation water; the concentration of multivalent cations of the proposed injection fluid; o TDS content (indicating salinity) of the proposed injection fluid; the viscosity of the proposed injection fluid comprising a viscosifying polymer in an aqueous base fluid, which can be calculated by the model as a function of polymer concentration, polymer molecular weight, polymer type (chemical structure), shear rate under conditions reservoir and salinity of the aqueous base fluid; transport parameters such as polymer adsorption on reservoir rock, in particular on clay minerals, permeability reduction, cation exchange between Na and Ca sites of clays and injection fluid and pore volume inaccessible.
[00096] Other preferred or more specific chemical characteristics that can be measured to provide the measurement data entered into the model are: a full XRD analysis of the rock from the rock formation, including all mineral types in the reservoir rock (including clays and composites of transition metal such as oxides and carbonates, for example iron oxide, siderite and plagioclase feldspars); the zeta potential of the rock; the base number of oil; a total petroleum SARA analysis (SARA stands for saturated, aromatics, resins and asphaltenes and is a complete assessment of how much of each type of petroleum component is present in a sample); the concentration of magnesium, calcium, barium and/or iron in the formation water; the pH of the formation water; the concentration of magnesium, calcium, barium and/or iron in the injection fluid; and the pH of the injection fluid.
[00097] Additional parameters can be considered where necessary in order to configure the predictive model. Some additional parameters that can be considered are: oil pour point temperature (°C); oil turbidity point temperature (°C); oil density at 15°C (g/ml) or some other standard temperature; oil boiling point distribution (p%); distribution of the boiling point of oil (°C); total nitrogen content of petroleum (weight in ppm); basic nitrogen content of petroleum (weight in ppm); oil surface tension (mN/m); oil/salt water interfacial tension (mN/m); and oil/fresh water interfacial tension (mN/m).
[00098] The predictive model can be populated with data obtained using existing core injection data and single well chemical marker test (SWCT) data which is used to validate the model. The following system software determines the correlations between chemical characteristics and displaced oil and uses these correlations to predict the displacement of oil from the pore space of the formation rock of a modeled reservoir and, if run in conjunction with the reservoir model. , incremental oil recovery for the modeled reservoir.
[00099] Based on the predicted data, which preferably indicates a value for the incremental oil displacement as a percentage of the oil volume indicated by the data entered in the predictive model, the system can determine an ideal or suggested mode of operation and typically considers data additional when doing so. This additional data may include data regarding the required volume of injection fluid that can be provided and injected into the reservoir through the fluid injection well and any technical limitations or resource requirements that may affect the injection fluid provision, such as such as the requirement to use desalination equipment to produce the required volume of injection fluid or cost of polymer. In general, an injection fluid comprising a viscosifying polymer at a low salinity is continuously passed into the formation or preferably a heavy slurry of controlled pore volume (PV) injection fluid is passed into the formation.
[000100] The application of the computer-implemented method and system is advantageous where a limited supply of naturally occurring injection fluid having an ideal or required salinity and/or ideal or required multivalent cation content is present and/or any desalination equipment produce a limited supply of injection fluid having an ideal or required salinity and/or an ideal or required multivalent cation content or the cost of the polymer means that there is a limited supply of the injection fluid comprising a viscosifying polymer in a low water available salinity. The application of the computer-implemented method and system is also advantageous where the volume of ideal injection fluid that can be injected into one or more reservoirs or wells is limited due to the need to dispose of the water produced by injecting the water produced into the ) reservoir(s) or well(s).
[000101] The operating point may comprise an instruction to inject the injection fluid into one or a plurality of selected wells. In one example, where a limited volume of a viscosifying polymer and/or a limited volume of low salinity water for use as an injection fluid is available ("low salinity water" is as defined above), the predicted data generated by the model may indicate that a particular well is predicted to yield an incremental oil recovery of 8% based on the original on-site oil in the reservoir, while values of 12% and 4% are predicted for other wells in the reservoir. The system software can be configured to order or rank the wells in order of priority based on these production results, and the predictive model or other system software (such as the reservoir model) used in determining the operational mode can account for such factors. the initial oil saturation of each reservoir (initial oil on site), an available volume of injection fluid, and the volume of heavy sludge required to move the incremental oil to production in each well.
[000102] The system software can also be configured to provide a modified classification of production wells that takes into account the incremental oil displacement that would be achieved using the injection fluid comprising a viscosifying polymer in a low salinity water, and the displacement of the incremental oil that would be achieved using the produced water, a mixture of low salinity water and produced water or the viscosification polymer in the produced water as the injection fluid, considering the available volume of the injection fluid comprising a viscosification polymer in a low salinity water and the volume, for example, of produced water to be reinjected.
[000103] A further example of an application of the computer-implemented method and system will now be described. It is known that the chemical properties or characteristics of rock formations, oil and formation water can vary spatially within a single reservoir (both in a vertical direction and in a transverse direction). Thus, where the reservoir comprises two or more overlying petroleum rock formations (hereinafter referred to as overlying sections of a reservoir), these overlying sections may have different chemical characteristics (due to differences in the chemical characteristics of the rock formations or differences in the chemical characteristics of the crude oil or formation water contained within the pores of rock formations). Overlying sections of the reservoir may have different initial oil saturations (also referred to as initial oil on site). Likewise, the chemical properties or characteristics of rock formation, oil and formation water can vary across a layer of a reservoir such that different chemical properties or characteristics can be measured at different locations. Initial oil saturation can also vary across a reservoir layer. Considering a reservoir having a plurality of injection wells at different positions in the reservoir, the computer-implemented method can determine an operational mode comprising an indication in which wells the injection fluid (the injection fluid comprising a viscosifying polymer in a water) of low salinity), having measured chemical characteristics on the basis of which the measurement data were entered into the predictive model, should be injected in order to maximize the incremental oil displaced and therefore potentially recovered. Thus, the predictive model can include measurements of the chemical characteristics of reservoir rock, oil and formation water at different overlying layers of a reservoir as well as including measurements of such chemical characteristics at different locations within a layer of the reservoir.
[000104] For example, in the case of tertiary recovery with an injection fluid comprising a viscosifying polymer in a low salinity water, there may be weakly swept regions of the reservoir. By using the predictive model in conjunction with geographic data obtained using the reservoir model, the system can determine how areas of the reservoir operational mode(s) should be focused for additional water injections. The operational mode can comprise a selection of wells that are likely to focus on these poorly swept regions when injected with the injection fluid comprising the viscosifying polymer in a low salinity water. Additionally, on the basis of reservoir permeability data, the regions of a reservoir that are most likely to be bypassed if injected with a non-viscosified injection fluid and likely to result in an additional oil displacement if injected with the injection fluid comprising the polymer viscosification in a low salinity water can be determined. Based on this determination, a selection of injection wells for additional injection, injection well locations for new oil fields or fill well locations for existing reservoirs can be determined by the system software.
[000105] The computer-implemented method and system are particularly advantageous where, for example, a viscosifying polymer in a low salinity water for use as the injection fluid is in limited supply and the predictive model can be employed as written. above in order to order or classify the wells to be injected in priority order. The predictive modeling or other system software used in determining the operational mode can use the predetermined rules to consider factors such as the available volume of injection fluid and the volume of heavy sludge required to displace this incremental oil to each section of the reservoir in which the chemical characteristics and/or permeabilities of the measured oil and/or formation water vary.
[000106] Chemical characteristics may vary across a reservoir section. Consequently, the predictive model can be used to classify injection wells that are arranged at different locations in the reservoir and that penetrate the reservoir section. The predictive model can therefore determine an operating mode where viscosified low salinity water is used as the injection fluid for one or more, but not all, injection wells that penetrate the reservoir section.
[000107] The reservoir model or a reservoir simulation can be used in combination with the predictive model described alone to provide additional valuable information. This information can also be used to predict when and where optimal oil recovery will occur. Based on such predicted data, optimal locations for injection wells and/or production wells can be predicted, allowing the configuration of a reservoir or even an oil field to be planned to allow optimal efficiency in oil recovery. Predicted data can also be used to predict the optimal locations of injection filler wells for injection with the injection fluid comprising the viscosifying polymer in a low salinity water. Modeling Studies of Low Salinity Water Injection and Polymer Injection Simulations Combined Model Description
[000108] In a first study, LandMark's commercially available "VIP" reservoir simulator was used to model the combination of low salinity water injection and polymer injection processes. The key features of the low salinity model, as described by Jerauld et al. (Jerauld, GR, Lin, CY, Webb, KJ and Seccombe, JC (2008) Modeling Low-Salinity Waterflooding, SPE Reservoir Evaluation and Engineering, paper SPE 102239, December, 1000-1012), are: 1. Salt is modelled as an additional single agglomerate component in the aqueous phase, which can be injected and traced. The viscosity and density of the aqueous phase are dependent on salinity; 2. the relative permeability and capillary pressure are made a function of salinity. This dependence disappears in high and low salinities; permeability curves for high and low salinity are inserted into the model; the shapes for the permeability curves are interpolated between these high and low salinities; the dependence on salinity is made irreversible so that the lowest salinity achieved defines the relative permeability; 3. portions of the tap water are made inaccessible to demonstrate the impact of the creation of tap water banks on the process; 4. hysteresis between inhibition and permeability relative to secondary water drainage is included to accurately model oil bank development; 5. a dispersion model within the aqueous phase is included to allow more rigorous study of the impact of dispersion.
[000109] The polymer model for the rheology, chemistry and polymer transport in the VIP reservoir simulator is the same as previous versions of the UTCHEM model (The University of Texas Chemical Compositional Simulator, Camilleri et al. - Camilleri, D., Engelsen , S., Lake, LW, Lin, EC, Ohno, T., Pope, G. and Sepehrnoori, (1987) Description of an Improved Compositional Micellar/Polymer Simulator, SPE, Reservoir Engineering, Nov. pp 427432; D., Fil, A., Pope, GA, Rouse, BA and Sepehrnoori, K., (1987) Improvements in Physical-Property Models Used in Micellar/Polymer Flooding, SPE, Reservoir Engineering, Nov. pp 433-440). The key features of the polymer model are: 1. the viscosity of the polymer solution is a function of polymer concentration, shear rate and salinity; the effects of temperature on polymer viscosity are not directly modeled; 2. all transport parameters such as polymer adsorption, permeability reduction, cation exchange and inaccessible pore volume are considered; 3. other effects such as polymer degradation in mixing and surface installations and in injection wells and lines are considered external to the model. Simulations Study of one-dimensional simulation (ID)
[000110] ID simulation runs were conducted to study the effect of the combination of low salinity water injection and polymer injection processes on displacement efficiency. Without wishing to be bound by any theory, it is believed that low salinity water and polymer both affect the oil ID shift for different reasons. An injection of low salinity water changes the shape of the relative permeability curve due to wettability changes towards the rock more wetted with water as shown in figure 3. The relative permeability of low salinity is estimated from the relative permeability of high salinity by the desquamation of the endpoint. An additional 15% oil recovery is applied to construct the permeability curve relative to low salinity based on some typical results from the X-Ray Diffraction (XRD) prediction tool. Incremental recovery over a standard high salinity water injection is calculated as: Sor(high) - Sor(low) 1 - Swi - Sor(high) where Sor is the residual oil saturation and Swi is the connate water saturation.
[000111] The addition of polymer to an aqueous fluid changes the mobility ratio due to increased water viscosity and a permeability reduction factor. Both low salinity water injections and polymer injections improve fractional flow towards the most favorable case compared to a high salinity water injection (Lake, LW (1989) Enhanced Oil Recovery, (314353) London: Prentice- Hall). The combination of these two methods further improves the fractional flow behavior resulting in better displacement efficiency as shown in figure 4.
[000112] There are 25 grid blocks in the ID model between the injector and the producer to ensure there is a realistic level of dispersivity (modeled here with numerical dispersion). The chloride anion (Cl-) and calcium cation (Ca2+) concentrations in the high salinity saline solution are selected to be about the same levels as in seawater, 20,632.5 and 1000 ppm, respectively. The composition of low salinity saline solution is one-tenth of the high salinity concentration, thus having a Cl- concentration of 2063.2 ppm and a Ca2+ concentration of 100 ppm. Salinity thresholds are based on the calcium concentration when saline solutions are used together with the polymer in the simulation model; in this case 10316 ppm of Cl- and 500 ppm of Ca2+ for saline solution with high salinity and 4126 ppm of Cl- and 200 ppm of Ca2+ for saline solution with low salinity. Based on the polymer rheological data, the polymer concentration requirement for an oil with 10 cP (10 mPa.s) viscosity is three times higher for the high salinity saline solution compared to a low salinity saline solution. These polymer concentrations that are selected for both high and low salinity saline solutions create a polymer viscosity of about 3.5 cP (3.5 mPa.s) which is sufficient for a stable displacement of oil by the injection fluid . As discussed below, the benefit of including the polymer in the injection fluid comes from the improvement in fractional flow behavior as opposed to macroscopic sweeping efficiency. Therefore, a stable displacement of oil even in the one-dimensional case is required.
[000113] In one example, a 1.0 PV heavy slurry of a low salinity saline solution and/or polymer in a low salinity saline solution is injected followed by a high salinity saline solution. The comparison of incremental oil recoveries for all these cases is shown in figure 5. The final oil recovery (at 2.0 PV) for a combined low salinity water injection and polymer injection is almost the same as the sum of these individual processes. Figure 6 shows the comparison of polymer concentration profile and oil saturation for a low salinity water injection with and without polymer at 0.5 PV and 1.0 PV of injected fluid. The polymer added to the low salinity saline solution helps improve the injection displacement efficiency and displaces more oil compared to low salinity water injection alone. Heterogeneous versus Homogeneous Cases
[000114] A 9-point 1/8 heterogeneous model (ie, a model having a 1-injector and 8-producer arrangement in which a path is modeled) was chosen to investigate the synergistic behavior of a low salinity water injection. and polymer injection. This model consists of 44 layers of reservoir rock with a stochastic permeability distribution in a range from 10 to 4,000 milidarcies (md), as shown in Figure 7. There is an injector and a producer in this model. First, the comparison between homogeneous and heterogeneous cases was investigated. The homogeneous case was constructed by the harmonic mean of the permeability laterally and then the arithmetic mean vertically for both horizontal and vertical permeability. The injection design for multiple cases was the same as the case ID. The results obtained for the oils of 5 and 50 cP (5 to 50 mPa.s) are shown in figure 8. In general, the addition of polymer to the saline solution of low salinity for the oil of 50 cP (50 mPa.s) shows greater incremental oil recovery than for 5 cP oil (5 mPa.s). Incremental oil recovery between homogeneous and heterogeneous cases is very close, especially in oil with high viscosity. In oil with low viscosity (5 cP - 5 mPa.s), oil recovery is somewhat greater in the homogeneous case than in the heterogeneous case. To study the polymer contribution to the low salinity EOR on the sweep efficiency, the oil saturation map in layer 20 (~600 md) and layer 40 (~1.800 md) is plotted in figure 9 at 0.25 and 0.5 PV for 5 cP oil (5 mPa.s). It can be seen that the oil saturation front in the combined process tends to reduce in the high permeability layer and accelerate very slightly in the low permeability layer. This does not represent a very significant change in sweeping efficiency, which explains why most of the benefit of adding polymer is believed to be due to ID shift efficiency. Secondary versus Tertiary Response
[000115] To investigate how the use of a low salinity polymer injection in secondary and tertiary recovery modes, in purchase with each other, a series of simulations was run for various EOR techniques and two different oil viscosity cases using the same heterogeneous 1/8 pattern of a 9-point well pattern. In the tertiary injection design, 1.0 PV of low salinity water was first injected, followed by 1.0 PV of low salinity water injection or a polymer injection (with a high salinity base saline solution), or the combination of a low salinity water and polymer injection. The same permeability curves relative to low salinity were used for both secondary and tertiary cases. Figure 10 compares the response of secondary and tertiary recovery cases for oil of 5 cP (5 mPa.s) viscosity. For these model results, secondary recovery cases are more effective than tertiary recovery cases in terms of timing and oil recovery. It was found that for secondary recovery cases, petroleum responses break by 0.3 PV, compared to 0.5 PV for tertiary recovery cases. Figure 11 compares the synergistic behavior of a combination of low salinity water injection and polymer injection under secondary and tertiary conditions for oils with viscosity of 5 cP and 50 cP (5 and 50 mPa.s). In all cases, the final oil recovery from combined processes is greater than the sum of individual processes. Secondary recovery in high viscosity oil (50 cP - 50 mPa.s) gives a higher final oil recovery than for less viscous oil (5 cP - 5 mPa.s). In the later stages of secondary injection, oil recovery from the combined processes (low salinity polymer injection) falls below the sum of low salinity water injection and polymer injection. Although the total oil recovery of tertiary recovery cases is less than that of secondary cases, the combined processes in tertiary injection give greater oil recovery than the sum of individual cases at all times. The synergistic behavior of combined processes in tertiary recovery mode appears to be more effective than in secondary recovery mode. Sensitivity study of the extent of heavy mud
[000116] The effect of heavy sludge injected fluid extension on recovery was investigated for a low salinity water injection and a combined low salinity water injection and polymer injection. The same heterogeneous 1/8 pattern of a 9-point pattern was used for this evaluation. In this model, a heavy slurry extension of 0.3 PV was sufficient to achieve incremental oil recovery for a low salinity injection. No additional benefit in incremental oil recovery was seen above 0.3 PV of heavy sludge span for a low salinity water injection. However, the addition of polymer to low salinity injection is effective in achieving incremental oil recovery up to a heavy sludge extension of 0.7 PV. Figure 12 shows the comparison of 0.3, 0.5, 0.7 and 1.0 PV of heavy sludge lengths for a combination of low salinity water injection and polymer injection. A 0.3 PV heavy slurry extension for a combination of a low salinity water injection and polymer injection gives more than twice the incremental oil recovery compared to a low salinity injection alone for 50 cP oil (50 mPa.s) viscosity. As the extent of heavy sludge increases, incremental oil recovery increases, but the recovery rate starts to decline, especially above 0.5 PV. No significant increase in incremental oil recovery is observed above 0.7 PV. Chemical Cost Comparison
[000117] The cost per barrel of oil recovered (compared to a standard water injection) for a polymer injection with a high and low salinity aqueous base fluid was calculated. Table 1 lists the cost per barrel of oil recovered (compared to standard water injection) for an oil of 5 and 50 cP (5 and 50 mPa.s) viscosity. Based on the simulation results, the polymer cost for a polymer injection employing a high salinity aqueous base fluid is about $6 to $6 per barrel of oil recovered (compared to standard water injection). Whereas the cost of polymer per barrel of oil produced (as opposed to incremental oil) reduces to about $1 per barrel of oil. An approximately 5-fold reduction in chemical cost is predicted when the polymer is added to low salinity water. TABLE 1.

3-D Modeling Case Studies
[000118] To provide an independent evaluation, a reservoir simulator such as the commercially available reservoir simulator software program "STARS" (Steam, Thermal, and Advanced Processes Reservoir Simulator by Computer Modeling Group Ltd) can be configured to model these EOR processes for another exemplary case. The STARS simulator does not include salinity dependent polymer concentrations, but for the continuous injection of low or high salinity water you can properly model low salinity water injection, polymer injection and a combination of these methods. In the STARS simulator, due to the flexibility in choosing the interpolation parameter and the fact that arbitrary tabular data for the relative permeabilities and capillary pressures can be employed, a wide variety of phenomena can be handled; including the ability to interpolate basic relative permeability and capillary pressure data as a function of salinity. A function of non-linear blend viscosity was used to model polymer viscosity as a function of concentration. The dependence of polymer viscosity on water salinity cannot be considered in the STARS simulator. The simulator provides a velocity-dependent combined shear and thickening model based on the addition of the effects of the shear and thickening power entitlements. This relationship is linked by two plateaus; a plateau ensures a Newtonian fluid viscosity for lower velocities and a plateau ensures an upper viscosity limit for higher velocities. The STARS reservoir simulator represents polymer adsorption through a Langmuir isotherm correlation and also models permeability reduction.
[000119] In one example, three-dimensional (3D) simulations of a standard type model were performed for an average oil viscosity of 50 cP (50 mPa.s). This model is heterogeneous with the injectivity constraint representing a standard 5-point well model with one injector and 4 producers. Figure 13 shows the permeability of this reservoir model. A variety of options were simulated to study the performance of different EOR techniques including low salinity water injection, polymer injection and a combination of these two techniques. Low salinity water was injected for about 10 years before implementing any EOR technique. All cases were compared with high salinity water injection (provides standard oil recovery). The final oil recovery for the high salinity injection was 19.4% as shown in figure 14. Polymer injections with high and low salinity aqueous base fluids gave 5.6 and 10% incremental oil recoveries over the injection of high salinity water, respectively. In contrast, low salinity water injection alone had a final incremental oil recovery of 5.9% over standard high salinity water injection. In this case, with the injectivity limitations, the incremental oil recovery from the combination of low salinity water injection and polymer injection was not as high as the sum of each method alone. These cases were performed with no injector pressure limitation to assess the synergistic behavior of these processes with no injectivity limitation. Figure 15 shows that oil recovery for polymer injection with a high salinity aqueous base fluid increased by 5.6 to 6.0% and oil recovery for polymer injection with low salinity aqueous base fluid increased from 10.0 to 10.8%). Removal of the injectivity limitation improved the overall synergistic behavior of a low salinity water injection and polymer injection.
[000120] Another set of runs was simulated to investigate the effect of infill drilling for different scenarios. New producers were placed at the midpoint between the injectors and the original producers, all the original producers were turned into injectors and four more injectors were added between the original corner injectors. The first sets of runs were under injection pressure limits. As shown in figure 16, oil recovery from standard high salinity water injection was improved up to 29% OOIP (oil in original location) in the case of filling. As a result of smaller well spacing, oil recovery across all EOR options has increased. A low salinity injection gave an incremental oil recovery of 9.4% over the standard high salinity injection while a polymer injection (using a high salinity aqueous base fluid) gave an incremental recovery of about 9.1% over the standard high salinity injection. The combination of a low salinity injection and polymer injection increased incremental oil recovery up to 18.4%. Infill drilling helps to improve the synergistic behavior of the combined processes even under situations of limited injectivity. Polymer cases were run with no pressure constraints on the injectors to investigate the effect of no injectivity constraint combined with fill perforation (Figure 17). Incremental oil recovery in the case of polymer with low and high salinity saline solutions as base fluids increased to 23.9 and 11.8%, respectively. Removal of the injectivity limitation combined with infill piercing helps to improve the synergistic behavior of these combined processes beyond their individual contributions. Therefore, the effect of placing infill wells on incremental oil recovery with a polymer injection employing a low salinity water as the aqueous base fluid can be modeled. Modeling study conclusions: One third or less polymer is required for polymer injections that employ a low salinity water as the base fluid compared to using a low salinity water as the base fluid. This fact makes the combination of low salinity water and polymer injection very attractive; adding polymer to a low salinity water injection improves incremental oil recovery timing and enhances recovery efficiency; the incremental oil recovery between the homogeneous and heterogeneous modeled cases is in close agreement, especially for more viscous oils; it is believed that most of the benefit of the polymer comes from the improvement in fractional flow behavior as opposed to macroscopic sweeping efficiency; at high oil viscosities, a combination of a low salinity water injection and a polymer injection gives incremental oil recovery about equal to or better than the sum of each injection technique, if used separately; both secondary and tertiary recovery modes are effective for viscosified low salinity water injection, but secondary recovery mode gives better oil recovery timing; the synergistic behavior of the low salinity water injection and polymer injection processes combined is more effective in tertiary recovery modes than in secondary recovery mode; comparison of the chemical cost of the cases studied shows that a 5-fold reduction in chemical cost per barrel of oil recovered can be expected for a combined polymer and low salinity injection; injectivity limitations in field application may limit the synergy between these combined processes; modeling studies can be employed to determine the placement of infill wells to gain the optimal benefit from the synergy between the combined processes.
[000121] The above embodiments are to be understood as illustrative examples of the invention. Additional embodiments of the invention are envisaged. It should be understood that any feature described in relation to any one modality may be used alone or in combination with the other features described and may also be used in combination with one or more features of any other modality or any combination of any other modality. Furthermore, equivalents and modifications not described above may also be employed without departing from the scope of the invention, which is defined in the appended claims.

权利要求:
Claims (32)
[0001]
1. Method of recovering oil from an underground petroleum reservoir using an injection fluid comprising a viscosifying polymer in a low salinity water, the method characterized by comprising: determining the viscosity of the injection fluid within the reservoir based on at least one of a composition of the viscosifying polymer, a molecular weight of the viscosifying polymer, a concentration of the viscosifying polymer, a low salinity water composition, a reservoir temperature, or a shear rate of the injection fluid within the reservoir, wherein the reservoir is penetrated by one or more injection wells and one or more production wells, and wherein the reservoir comprises petroleum having a viscosity of 40 to 200 cP (40 to 200 mPa.s), preparing the fluid of injection, wherein the injection fluid comprises the viscosifying polymer in the low salinity water, wherein the low salinity water has a content of to such dissolved solids (TDS) of 15,000 ppmv or less, wherein the ratio of the multivalent cation content of the low salinity water to the multivalent cation content of the connate water of the reservoir is less than 1; wherein the viscosity of the injection fluid determined within the reservoir is compared to the viscosity of oil under reservoir conditions such that a ratio of an injection fluid mobility to an oil mobility in the reservoir is less than 1; initiate injection of the injection fluid into at least one of the injection wells, where the injection fluid is injected into an extent of the heavy slurry in the range of 0.5 to 0.9 pore volume (PV); and sweeping oil in the reservoir towards at least one of the one or more production wells based on the initiation of injection of the injection fluid into at least one of the injection wells.
[0002]
2. Method according to claim 1, characterized in that the injection fluid is injected into an extent of the heavy sludge from 0.6 to 0.9 PV.
[0003]
3. Method according to claim 1 or 2, characterized in that the injection fluid is injected during the secondary recovery, after the primary recovery of oil under a natural pressure from the underground oil reservoir.
[0004]
4. Method according to any one of claims 1 to 3, characterized in that the low salinity water has a TDS content of less than 12,000 ppmv.
[0005]
5. Method according to claim 4, characterized in that the low salinity water has a TDS content of less than 10,000 ppmv.
[0006]
6. Method according to claim 5, characterized in that the low salinity water has a TDS content of less than 8,000 ppmv.
[0007]
7. Method according to claim 6, characterized in that the low salinity water has a TDS content of less than 5,000 ppmv.
[0008]
8. Method according to any one of claims 1 to 7, characterized in that the low salinity water has a total dissolved solids content (TDS) of at least 100 ppmv.
[0009]
9. Method according to claim 8, characterized in that the low salinity water has a total dissolved solids content (TDS) of at least 200 ppmv.
[0010]
10. Method according to claim 9, characterized in that the low salinity water has a total dissolved solids content (TDS) of at least 500 ppmv.
[0011]
11. Method according to claim 10, characterized in that the low salinity water has a total dissolved solids content (TDS) of at least 1,000 ppmv.
[0012]
12. Method according to any one of claims 1 to 11, characterized in that the ratio of the multivalent cation content of the low salinity water to the multivalent cation content of the connate water of the reservoir is less than 0.9 .
[0013]
13. Method according to claim 12, characterized in that said ratio is less than 0.8.
[0014]
14. Method according to any one of claims 1 to 13, characterized in that the low salinity water that is used as the base fluid of the injection fluid has a multivalent cation content less than 200 ppmv.
[0015]
15. Method according to claim 14, characterized in that the low salinity water that is used as the base fluid of the injection fluid has a multivalent cation content of less than 100 ppmv.
[0016]
16. Method according to claim 15, characterized in that the low salinity water that is used as the base fluid of the injection fluid has a multivalent cation content of less than 40 ppmv.
[0017]
17. Method according to claim 16, characterized in that the low salinity water that is used as the base fluid of the injection fluid has a multivalent cation content of less than 25 ppmv.
[0018]
18. Method according to any one of claims 1 to 17, characterized in that the viscosification polymer is an acrylamide polymer.
[0019]
19. Method according to any one of claims 1 to 17, characterized in that the injection fluid is a solution of the viscosifying polymer in low salinity water.
[0020]
20. Method according to any one of claims 1 to 17, characterized in that the injection fluid is a dispersion of the viscosifying polymer in low salinity water.
[0021]
21. Method according to any one of claims 1 to 20, characterized in that the injection fluid comprises at least 500 ppm of polymer by weight.
[0022]
22. Method according to any one of claims 1 to 21, characterized in that, under conditions of temperature and pressure in the reservoir, the mobility of oil is greater than the mobility of the injection fluid.
[0023]
23. Method according to any one of claims 1 to 22, characterized in that the extent of the heavy slurry of the injection fluid is in the range of 0.7 to 0.9 PV.
[0024]
24. Method according to any one of claims 1 to 23, characterized in that after the injection of the injection fluid, a drive fluid can be injected into the reservoir.
[0025]
25. Method according to any one of claims 1 to 24, characterized in that after injection of the injection fluid, a drive fluid can be injected into the reservoir, which drive fluid sweeps the injection fluid through the reservoir to the production well.
[0026]
26. Method according to claim 24 or 25, characterized in that the drive fluid is injected into the reservoir in a larger pore volume than the injection fluid.
[0027]
27. Method according to claim 26, characterized in that the drive fluid is injected into the reservoir at a pore volume of at least 1.
[0028]
28. Method according to claim 27, characterized in that the drive fluid is injected into the reservoir at a pore volume of at least 2.
[0029]
29. Method according to claim 28, characterized in that the drive fluid is injected into the reservoir in a pore volume in the range of 2 to 10.
[0030]
30. Method according to any one of claims 1 to 29, characterized in that a spacer fluid is injected into the reservoir before and/or after the injection of the injection fluid.
[0031]
31. Method according to any one of claims 1 to 30, characterized in that the injection fluid is injected under pressure into at least one injection well that is spaced from a production well, and passes directly into the oil rock from the reservoir of the injection well.
[0032]
32. Method according to claim 31, characterized in that the injection fluid is injected at a pressure of 10,000 to 100,000 kPa (100 to 1,000 bar).

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同族专利:

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公开号 | 公开日

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MX2014009581A|2014-09-12|

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CN104334678A|2015-02-04|

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EA201400880A1|2015-01-30|

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AU2013217930B2|2016-02-11|

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MX360817B|2018-11-15|

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AU2013217930A2|2014-09-25|

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US10041339B2|2018-08-07|

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US20140345862A1|2014-11-27|

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CA2863352C|2019-09-17|

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EA026799B1|2017-05-31|

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AR089956A1|2014-10-01|

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CA2863352A1|2013-08-15|

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AU2013217930A1|2014-09-04|

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CO7111311A2|2014-11-10|

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MA35919B1|2014-12-01|

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EP2812409B1|2018-11-28|

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DK2812409T3|2019-03-25|

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EP2812409A1|2014-12-17|

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WO2013117741A1|2013-08-15|

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法律状态:
2018-03-27| B06F| Objections, documents and/or translations needed after an examination request according [chapter 6.6 patent gazette]|

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2019-08-27| B06U| Preliminary requirement: requests with searches performed by other patent offices: procedure suspended [chapter 6.21 patent gazette]|

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2021-01-05| B06A| Notification to applicant to reply to the report for non-patentability or inadequacy of the application [chapter 6.1 patent gazette]|

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2021-05-04| B09A| Decision: intention to grant [chapter 9.1 patent gazette]|

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2021-06-22| B16A| Patent or certificate of addition of invention granted|Free format text: PRAZO DE VALIDADE: 20 (VINTE) ANOS CONTADOS A PARTIR DE 08/02/2013, OBSERVADAS AS CONDICOES LEGAIS. |

优先权:

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申请号 | 申请日 | 专利标题

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US201261596789P| true| 2012-02-09|2012-02-09|

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US61/596.789|2012-02-09|

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PCT/EP2013/052614|WO2013117741A1|2012-02-09|2013-02-08|Enhanced oil recovery process using low salinity water|

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