• 专利附录
  • 专利说明
  • 权利要求
  • 类似技术
  • 同族专利
  • 引用文献
  • 法律状态
  • 优先权
    • 专利摘要:
    APPARATUS AND METHOD FOR TESTING MULTIPLE SAMPLES.The invention relates to an apparatus for the simultaneous injection of fluids in a plurality of samples of porous media supports, comprising: a plurality of supports for the samples of porous media, each support comprising a glove and first and second deliveries, the first plate having an inlet for fluid injection and a second plate having an outlet for a fluid produced, and samples of porous media being arranged, in use, on each of the supports, so that the first plate and the second plate of each support contact a first end and a second end of the sample of porous medium, respectively, the entrance of each first plate being in fluid communication with an injection line for injection of fluid in the sample of porous medium arranged in the support, the exit of each second plate being in fluid communication with a dedicated effluent line for the removal of fluid produced from the sample of porous medium disposed in the support, ana media on-line and / or off-line for analysis of the fluids injected into each of the porous media samples, online and / or off-line media for the analysis of fluids removed from each of the porous media samples. A method of substantially injecting a fluid into samples of porous media is also provided.
    公开号:BR112013002938A2
    申请号:R112013002938-2
    申请日:2011-07-29
    公开日:2020-08-25
    发明作者:Ian Ralph Collins；John William Couves；Bogdan Costin Gagea；Arnaud Lager；Kevin J Webb
    申请人:Bp Exploration Operating Company Limited；
    IPC主号:
    专利说明:

    E ". APPARATUS AND METHOD FOR TESTING MULTIPLE SAMPLES, This invention refers to a method and an apparatus - for performing water flood tests and improved oil recovery techniques on multiple samples of porous media.
    It has long been known that only a portion of the total crude oil present in a reservoir can be recovered during a primary recovery process, this primary process resulting in the oil being recovered under the natural energy of the reservoir. The reservoir typically takes the form of an underground rock formation bearing oil having sufficient porosity and permeability to store. and transmit fluids, and what the oil is associated with, for example, being kept in pores or between grains in the rock formation. The so-called secondary recovery techniques are used to force the additional oil out of the reservoir, the simplest method being by one; direct replacement by another medium in the form of a displacement fluid (also referred to as an injection fluid), usually water or gas. Improved oil recovery techniques (EOR) can also be used. The purpose of these EOR techniques is not only to restore or maintain the reservoir pressure, but also to improve the oil displacement in the reservoir, thereby minimizing the saturation of residual oil in the reservoir, that is, the volume of oil present in the reservoir. When the initial reservoir pressure is close to the crude oil bubble point, secondary or improved oil recovery techniques may be used earlier in the life of a field, for example, a primary recovery may not
    -. to occur. . A “flood with water” is one of the most extensively and most successful methods of secondary recovery.
    Water is injected, under pressure, into reservoir rock formations through injection wells.
    The injected water acts to help maintain the reservoir pressure, and sweeps the oil displaced ahead of it through the rock towards the production wells from which the oil is recovered.
    The water used for flooding with water is usually saline water from a natural source, such as sea water, or it can be produced water (ie water that is separated from crude oil at the production facility). However, it is known that the use of a low salinity injection water (for example, brackish water, such as estuarine water or fresh water, such as river or lake water) during a flood with water can increase the amount of recovered oil compared to using a higher salinity water (eg sea water, produced water or aquifer water). It is also known that reducing the multivalent cation content of a lower salinity injection water can have an impact on oil recovery.
    However, lower salinity waters, such as fresh water, are often not available in a well location, for example, in offshore oil fields, and have to be done by reducing the total dissolved salt concentration (TDS ) and / or the concentration of multivalent cations in a source water using desalination techniques, such as reverse osmosis or direct osmosis.
    Source waters that are known to be treated in this way include water
    1 from the sea, brackish water, produced water and aquifer water. “Low” salinity water for use as in-injection water typically has a total dissolved solids (TDS) content in the range of 200 to 15,000 ppmv, preferably 500 to 12,000 ppmv. When the formation rock contains expandable clays, in particular smectite clays, a high element TDS for low salinity water is required in order to stabilize the clays, thereby avoiding the risk of damage to the formation. Thus, when the formation rock contains a sufficient amount of expandable clays "to result in damage to the formation, the low salinity water preferably has a total dissolved solids (TDS) content in the range of 8,000 to 15,000 ppmv, particularly
    8,000 to 12,000 — ppm. When the formation comprises quantities of expandable clays that do not result in damage to the formation, the TDS of the source water is typically in the range of 200 to 8,000 ppmv, preferably 500 to
    8,000 ppmv, for example, 1,000 to 5,000 ppmv. As discussed above, low salinity water also has a low concentration of multivalent cations, typically 40 ppmv or less, preferably less than 35 ppmv, more preferably less than 30 ppmv, for example, less than 25 ppmv. However, it is preferred that the low salinity water contains at least some multivalent cations. Thus, a multivalent cation content of low salinity water in the range of 5 to 40 ppmv, preferably 10 to 40 ppmv, is acceptable.
    The water present in the pore space of a rock, referred to from this point on as the “formation water”,
    x ". may vary in composition. When a displacement fluid. is injected without performing a primary recovery or VU immediately after the primary recovery, the formation water will typically comprise conate water, and when the displacement fluid is injected after a flooding with prior water, the formation water will typically comprise a mixture of conate water and previously injected water, such as sea water or produced water.
    The factors that control the interactions between crude oil, the rock formation, the injection fluid or displacement and the formation water and its effect on the wetting capacity and oil recovery involve complex and sometimes competing mechanisms . Currently, a core test flood test in the laboratory (where a rock sample is removed from a reservoir and then placed under the conditions of a laboratory test reservoir) or single well chemical tracker tests (where a fluid labeled with appropriate chemical trackers are injected into a formation through an injection well and produced back from the same well) are applied in order to determine the formation's residual oil saturation, following a technique of recovery of improved oil, such as flooding with low salinity water, and based on the results, a decision can be made as to whether an improved oil recovery technique, such as flooding with water using low salinity water, is worthwhile. These tests are time consuming and results are often not available during the planning stage of an oil field development,
    1 meaning equipment required for treatment. injection water may not have been included in the installation .-. of production.
    Also, the time consuming nature of these tests means that the composition of the injection water is often not optimal for the reservoir, that is, it has not been optimized for the characteristics of the reservoir rock, the formation water and the crude oil.
    US2007 / 0009384 refers to an apparatus for testing high yield of potential catalysts, which is suitable for testing a large number of catalysts using a plurality of analysis methods, preferably in parallel or in quick succession.
    This apparatus has a reactor element which includes at least one gas inlet unit, a plurality of reaction chambers and at least one restriction unit.
    The restriction unit has a plurality of channels, which are arranged in such a way that at least one reaction chamber is in direct contact with at least one channel of the restriction unit.
    The advantage of this device is that it allows for a quick screening of potential catalysts. conventional core flooding experiments are carried out using a single sample of reservoir rock contained in a core tube.
    It would be advantageous to design a high output core flooding apparatus that would be able to simultaneously flood a plurality of core flood samples under different conditions.
    However, the high production apparatus described above would be unsuitable for this purpose, due to the need for liquid inlets and outlets.
    O. Determination of residual oil saturation of. core samples taken from a formation carrying -— oil following improved oil recovery techniques, such as flooding with water in a secondary or tertiary mode is time consuming due to the length of time it takes to take a core sample to the reservoir conditions, before a core flood (for example, a flood with water). This means that a traditional core flood test probe takes more than six weeks to perform a single core flood experiment. As an understanding of the factors that result in improved oil recovery increases, there is a need to run a plurality of core flooding experiments simultaneously, to develop an understanding of the mechanisms behind improved oil recovery and to optimize injection fluids (eg, injection water for flooding with water) or the improved oil recovery techniques that must be performed in the field.
    Summary of the Invention In one possibility, an apparatus is provided for injecting fluids into a plurality of porous media samples, comprising: a plurality of supports for the porous media samples, each support comprising a glove and first and second plates, the first dish having an inlet for fluid injection and a second dish having an outlet for a fluid produced, and samples of porous media being arranged, in use, on each of the supports, so that the first dish and the second dish in
    -. each holder contacts a first end and one. second end of the sample of porous medium, J- respectively, the entrance of each first plate being in fluid communication with an injection line for injection of fluid in the sample of porous medium arranged in the support, the exit of each second plate being in communication of fluid with a dedicated effluent line for the removal of fluid produced from the sample of porous medium disposed in the support, an analyzer for analysis of fluids injected and / or removed from each of the samples of porous media.
    In some possibilities, the device comprises a control system coupled to receive measurement data from the analyzer and configured to control fluid injection based on the measurement data. In some possibilities, control of fluid injection based on measurement data comprises control of fluid injection on one of the plurality of porous media samples based on measurement data associated with another of said plurality of porous media samples . In some possibilities, the control system is configured to control the apparatus for the execution of simultaneous concurrent injections, which start alternately (for example, with a delay of start between injections), these examples of the invention have the advantage of experimental data from the first experiments in a trial can be used for procedural information / control, before all experiments have been completed. In addition, resources such as fluid pumps, reservoirs and analyzers can be
    - *. shared between experiments. For example, if all. samples are set to start at the same time, VV may need to provide a complete set of all the relevant apparatus for each experiment, because they will be at the same stage on a given date. In addition, the inventors in the present case recognized that configuring the device to start experiments in an alternating manner allows for failure detection and thus increases production by allowing problems to be detected early, thereby reducing the number of days lost with failed experiments.
    In some possibilities, the apparatus comprises an operable fluid supply to control the fluid supply for injection in the porous media samples, wherein the control system is configured to control the fluid supply for at least one of said plurality of samples of porous media. a porous medium based on the measurement data.
    In some possibilities, the measurement data is based on the amount of oil in the fluid removed from the sample of porous medium disposed on the support. In some possibilities, the controller is configured to stop the injection of fluid in one of said plurality of samples in case the amount of oil in the fluid removed from one of said samples is less than a selected threshold level. These and other examples of the invention have the advantage that, where many experiments are conducted, the tests can be stopped promptly, when they are completed, to allow the support to be used for another test, thus increasing production
    . the device. . In some possibilities, the selected go limit level is one of: a selected concentration; a percentage selected by volume, and a percentage selected per mass of fluid.
    In one possibility, a core flood test method for injecting injection fluid into a plurality of porous media samples is provided, the method comprising: arranging a plurality of porous media samples in respective pressure vessels. a corresponding plurality of them, in which the porous media samples comprise oil and water in an initial water saturation, Swi, the aging of the porous media samples so that the samples are in a mixed wetting capacity state; the injection of an injection fluid into each of the porous media samples, the removal of displaced fluid from the porous media samples, the analysis of displaced fluids from each of the porous media samples.
    In some possibilities, the analysis comprises determining the amount of oil in a fluid displaced from one of the plurality of porous media samples, the method comprising controlling fluid injection based on said determination.
    In some possibilities, fluid injection control comprises stopping fluid injection in the event that the amount of oil in fluid displaced from one of the plurality of samples is less than a selected threshold level. In some possibilities, the method comprises, in response to said determination, the removal
    = “. of one of the plurality of porous media samples from. pressure vessel and the replacement of said sample Jo from the plurality of samples with another sample comprising oil and water in an initial water saturation, i 5º Svwi.
    In some possibilities, the method comprises injecting fluid into said plurality of samples for a selected period of time, in which at least two of said samples are injected with fluid having different properties; the end of the injection after the selected period of time has elapsed; based on said analysis, the selection of properties of a plurality of injection fluids; and injecting said plurality of injection fluids into a second plurality of samples. In some examples, a device control system referred to above is configured to control the device to perform this function. These and other examples of the invention have the advantage that, based on an initial test of a set of fluids, the test protocol can be adjusted without human intervention to identify characteristics and effects of interest.
    In some examples, the method comprises, prior to arranging the plurality of porous media samples in the corresponding plurality of vessels, saturating the plurality of porous media samples with water; E The water displacement of the samples to obtain a selected level of water saturation, Swi, of the samples; wherein said arrangement of a plurality of porous media samples in respective pressure vessels of a corresponding plurality of pressure vessels comprises the
    - * transferring the plurality of samples at one level. selected "of water saturation for said VU corresponding plurality of pressure vessels. In some possibilities, the displacement of water to obtain a selected level of water saturation, Swi, comprises one of: injection of a non-wetting phase in said samples, or the centrifugation of said samples under a non-wetting fluid.In some possibilities, the simultaneous injection comprises the provision of a delay between the beginning of at least some of the injections.
    A water saturation / wetting, as used here, generally includes wetting / saturation with any aqueous fluid, such as brine. Similarly, references to water should be taken to include brines, formation water, or any other aqueous solution comprising water. Here is described a method and apparatus that can be employed as part of a high yield research program to quickly screening and classifying a plurality of potential water flooding methods or improved oil recovery for an oil-carrying reservoir, thereby allowing water injection to flood with water or fluid injection for the improved oil recovery method is optimized based on various parameters, such as chemical and physical characteristics of the reservoir rock, the chemical characteristics of the formation water associated with the reservoir rock, the chemical and physical characteristics of the oil, the chemical or physical characteristics of the
    - * - injection to be used in flooding with water Or the - chemical or physical characteristics of the J- injection fluid which is to be used in the improved oil recovery method.
    Also exposed is a process of aging core samples in parallel, thereby accelerating data acquisition.
    The present invention also provides a method and an apparatus that allow the determination of the relative permeabilities of a plurality of core samples for oil and water in parallel, thereby accelerating the acquisition of these data. An apparatus is described here for simultaneously injecting fluids in a plurality of porous media samples, comprising: a plurality of supports for the porous media samples, each support comprising a glove and first and second plates, the first plate having an inlet for fluid injection and the second plate having a outlet for a produced fluid, and samples of porous media being disposed, in use, on each of the supports, so that the first plate and the second plate of each support contact a first end and a second end of the porous medium sample respectively, the entrance of each first plate being in fluid communication with an injection line for the injection of fluid in the sample of porous medium arranged on the support, the outlet of each second plate being in fluid communication with a dedicated effluent line for the removal
    = ". of fluid produced from the sample of porous media. arranged on the support, & - online and / or offline analytical media for the analysis of the fluids injected into each of the porous media samples, online media and / or offline to analyze the fluids removed from each of the porous media samples.
    As will be understood by the reader versed in the context of the present exposition, the duration of the described test flood experiments is typically in the order of days or tens of days, so that precise simultaneity is not required.
    Therefore, as used here, the term simultaneous is generally used to mean that tests are carried out concurrently or in parallel, for example, that “simultaneous” tests are in progress at the same time, although they can start and end at different times.
    There is also a method for simultaneously injecting an injection fluid into a plurality of porous media samples, the method comprising: injecting an injection fluid into each of the porous media samples, removing any displaced fluid from the pore media. porous media, analyzing the fluids injected into each of the porous media samples, and analyzing any fluids removed from each of the porous media samples.
    Also described here is a computer-implemented method for determining one or more modes of
    "=. operation of an apparatus arranged to simultaneously. inject one or more injection fluids into a plurality of VD porous media samples, the method comprising the steps of: receiving measurement data associated with one or more characteristics of one or more injection fluids and / or one or more characteristics of the porous media and / or one or more characteristics of one or more fluids that are present in a pore space of the porous media, before the injection of one or more injection fluids; said measurement data in a software component implemented in a computer; execution of the software component in order to generate data indicative of one or more injection effects of one or more injection fluids in the plurality of samples; and determination, based on the data generated, of one or more said modes of operation of the apparatus.
    A determination of the effects of injection fluid (s) in a plurality of porous media samples is described here by generating data indicative of the effects, such as fluid release profiles, based on the measurement data taken before, during and / or after fluid injection.
    Also described here is a computer-implemented method for determining one or more modes of operation of an apparatus arranged to simultaneously inject one or more injection fluids into a plurality of porous media samples, the method comprising the steps of: receiving data indicative of one or more effects a. injection of one or more injection fluids in the plurality - of samples; DV input of said data into a software component implemented on a computer configured to compare one or more said effects with a required effect;
    the execution of the software component in order to generate experimental design data associated with obtaining the required effect, the experimental design data being indicative of a change to:
    one or more characteristics of one or more injection fluids; and / or one or more characteristics of the porous media; and / or one or more characteristics of one or more fluids that are present in a pore space of the porous media, before the injection of one or more injection fluids; and determining, based on experimental design data, one or more of the above modes of operation of the device,
    Also described here are methods for the provision of appropriate algorithms of the experimental design component, to distinguish future experiments having optimized characteristics, based on a comparison of known effects of performing an injection and a desired or preferred effect, such as a volume improved oil in increment recovered by fluid injection,
    Brief Description of Drawings
    Figure 1 is a schematic diagram of a high production apparatus according to the present invention;
    Figures 2a and 2b show schematic diagrams of
    . examples of a fluid flow line arrangement used in the apparatus of figure 1; |. figure 3 shows a control system for determining one or more modes of operation for a controller arranged to control the apparatus of figure 1; figure 4 shows the steps performed in a method for determining one or more modes of operation for the device in figure 1 using an analytical software component; figure 5 shows the steps performed in a method for determining one or more modes of operation for the apparatus in figure 1 using an experimental design software component; figure 6 shows the steps performed in a method for determining one or more modes of operation for the apparatus in figure 1 using a predictive model. Detailed Description of the Invention Apparatus Figure 1 shows a high production apparatus for simultaneously carrying out flooding experiments on multiple samples 1 of porous media. Figure 1 shows three samples 1, each contained in a dedicated pressure containment support 2. However, the number of samples and supports 2 is not critical. Typically, each experiment is performed in duplicate, preferably in triplicate, in order to test reproducibility. For example, by providing 18 samples 1, six sets of experiments can be performed in triplicate.
    Typically, supports 2 comprise first and
    . according to plates 3, 4, at the first and second ends. of the same. Figure 1 shows the supports 2 arranged vertically TS with inlets 5 and 6 exits of the supports located in the first (upper) and second (lower) plates 3, 4, respectively. However, it may be preferred that inlets 5 and outlets 6 are located on the second (bottom) and first (top) plates 3, 4, respectively, so that fluids are injected into the porous samples against gravity. Alternatively, the supports 2 can be arranged horizontally, in which case the location of the inlets 5 and outlets 6 is immaterial. Preferably, inlets 5 and outlets 6 are located centrally on the plates. Each effluent line 8 is connected to a respective fluid outlet 6 from each support 2. The effluent lines 8 are preferably in fluid communication with the effluent collection vessels 9 for the storage of fluids produced from samples 1 of porous media. Typically, a dedicated pressure regulator 10a, for example, in the form of a valve, is provided in each of the effluent lines 8 for regulating the pressure in the sample 1 of porous medium, for example, a back pressure regulator.
    A supply line 12 is also connected between a fluid source, for example, a reservoir 14 containing a fluid, and the inlet 5 of each of the supports 2, so that a fluid can flow through the supply line 12 from from source 14 to support 2 through inlet 5, through sample 1 and out of support 2 through outlet 6 and effluent line 8 to
    “. the effluent collection vessel 9. Suitably, the apparatus is. provided with a means for controlling the rate at which a fluid = flows through the supply line from the source and into the support.
    One or more online analytical instruments 7 can be provided for the analysis of an effluent fluid flowing from each sample 1. Suitable analytical techniques and instruments for use with the apparatus of the present invention are discussed in more detail below. It is noted that a sample of effluent fluid flowing from each sample 1 can be directed to the analytical instrument (s) 7. Alternatively, the analytical instrument (s) 7 can ( e) comprise at least one probe, a sensor or detector that is located in the effluent line 8, thereby allowing a direct analysis of the fluids flowing through the effluent line 8. If necessary, a port can be provided in the effluent line 8, so that the probe, the sensor or the detector can be located in the effluent stream (For example, a pH probe or an ion selective probe) or a window can be provided in the effluent line 8 with the probe, the sensor or detector located adjacent to the window for interrogating fluids flowing through effluent line 8 (for example, for spectroscopic analytical techniques). For example, in the case of an infrared (IR) analysis, the effluent stream can be irradiated with an IR radiation produced by an IR source and an IR detector can be used for the detection of infrared radiation that is transmitted through the flow (that is, not absorbed by the effluent flow). In this case, the ç analytical instrument can be a Fourier Transform IR (FT) analytical instrument that generates a transmittance or absorbance spectrum showing the wavelengths at which the effluent fluid absorbs IR radiation. Therefore, windows that are transparent to the radiation of going (for example, a sapphire or quartz window) are provided in the effluent line for the IR source and the IR detector. The use of probes or detectors allows the number of analytical instruments to be minimized, for example, a single analytical IR instrument can be used to generate IR spectra from data acquired using detectors located in two or more of the effluent lines 8.
    Similarly, one or more on-line analytical instruments 11 can also be provided for an analysis of fluids flowing through the feed lines 12. It is noted that a fluid sample being fed into each sample 1 can be directed to the (s) analytical instrument (s). Alternatively, the analytical instrument (s) 11 may comprise at least one probe, a sensor or detector that is located in the supply lines 12, thereby allowing a direct analysis of the fluids flowing through the supply lines 12 using the techniques described above with respect to effluent lines 8. Multi-way valves 10b are provided on supply lines 12 and effluent lines 8, and these valves 10b can be opened and closed, as appropriate, to allow fluid samples to be passed to analytical instruments 11 and 7,
    -—- respectively, through sampling lines 12g and 8a, Ss respectively. Fluid sampling can occur VD periodically, so that samples from flow lines 2 and effluent lines 8 are passed, in turn, to analytical instruments 11 and 17, respectively. Hydraulic pumps 10c can also be provided to supply fluids from the source 14 to the supply lines 12. The apparatus in figure 1 is provided by the bypass lines 13 that connect between the supply lines 12 and the effluent lines 8. Each of the supports 2 (containing samples 1 of porous media) can be closed using the multi-way valves 10b located in the feed lines 12 and in the effluent lines 8, thus allowing the washing of the feed lines 12 and the lines of effluent 8 through bypass line 13 (when switching between fluids). If desired, multipath valves 10b can be replaced with dedicated valves for sampling lines 12g and 8a and dedicated valves for closing supports 2 and directing fluids to bypass lines 13. Closing supports 2 also allows that each support 2 is removed from the apparatus for analysis of its associated sample of porous medium, for example, by NMR spectroscopy. Thus, the brackets 2 can be designed to be readily removable from the high production apparatus, for example, by means of pressure connection fittings or quick coupling connections or compression type connections (not shown).
    Optionally, other valves are provided in the lines
    - effluent 8, so that when fluids are being washed through the injection lines and effluent 12, 8 VÚU through the bypass lines 13, the fluids pass to a waste collection vessel (not shown) .
    In order to avoid complexity, for each set of supports (used for carrying out experiments in duplicate or triplicate), it is preferred to feed the same fluids for each of the samples 1 contained in the supports and for switching between the supply of different fluids of substantially simultaneous.
    Analytical instruments 7, 11, back pressure regulators 10a, flow control valves 10b and pumps 10c are connected to a control system 200 and an appliance controller 223, as further described below with respect to figure 3.
    Preferably, the supports 2 are cylindrical, so that the supports 2 are suitable for maintaining cylindrical samples 1 of porous media. Preferably, the inlets 5 and outlets 6 of the first and second end plates 3, 4 are arranged substantially centrally, thereby ensuring a uniform injection of fluid into samples 1 of porous media.
    Pressure retaining supports 2 can be formed, for example; from stainless steel, from a plastic material, such as Teflon "or polymers from polyether ether ketone (PEEK), or from carbon fiber. When it is intended to periodically analyze porous media samples using NMR spectroscopy, the supports sample 2 must be formed from a non-metallic material, for example, a plastic material
    Ge or carbon fiber. & Typically, each of samples 1 of porous media. it is provided with a rubber sleeve (not shown) that is open at each end.
    O-rings (not shown) can be provided at each end of the rubber sleeve for the formation of a fluid-tight seal with the pressure retaining support 2, so that a fluid-tight annular space is formed between the surface outer of the rubber sleeve and the inner surface of the pressure containment support 2. Typically, each support 2 is provided with an inlet and outlet (not shown) for a pressurized fluid, so that the pressurized fluid can be passed to the annular space and thereby exert an overload pressure on sample 1 of porous medium.
    Typically, the overload pressure is in the range 350 to 5000 psi (2.4 to 34.5 MPa), for example, around 400 psi (2.76 MPa). The number of samples 1 of porous and permeable media that can be tested simultaneously (in parallel) using the high production apparatus of the present invention is dependent on the number of supports 2, Typically, the apparatus may comprise from 6 to 100, preferably from 12 to 75, for example, from 12 to 32 supports.
    Porous media samples 1 must be permeable to the fluids that are injected into samples 1. Typically, porous media samples 1 can be plugs taken from one or more core samples removed from a formation carrying hydrocarbon from a reservoir under investigation or from a rocky outcrop having similar physical and chemical characteristics
    -. to the rock forming the reservoir under investigation. & Typically, core samples can be taken from a VU sandstone formation or from a carbonate formation (or from a rocky outcrop of sandstone or carbonate).
    When a plurality of core plugs are to be compared, using the high production apparatus and the method of the present invention, it is preferred that core plugs are drilled in close proximity to a core sample and are therefore expected to have similar rock properties (chemical and physical characteristics). These plugs are referred to as “brother plugs”. However, the apparatus and method of the present invention can also be used to compare core plugs from core samples taken from locations other than a reservoir, to determine whether differences in rock characteristics across the reservoir impact on techniques of water flooding or improved oil recovery (EOR).
    Alternatively or additionally, samples of porous media may comprise sandpacks (tubes filled with compacted sand to measure permeability and other properties), preferably formed from the produced sand; conditioning of ion exchange resin particles (cationic or anionic exchange resins) that are designed to mimic an ion exchange between injection fluids (in particular injection water) and the rock surface on the reservoir scale; packaging of resin particles
    . hydrophilic or hydrophobic (which are designed to mimic the hydrophilic or hydrophobic surface of the forming VU rock); synthetic rock (for example, silica); zeolites; or ceramic materials. Clays (for example, a kaolinite, smectite, pyrophyllite, illite, chlorite or glauconite type clay) can be mixed with sand before forming a sandpack. Clays can also be deposited on sandpacks or on samples of synthetic rock. For example, cemented quartz can be bonded with calcite and clays then can be deposited on the surface of the synthetic rock.
    The size of samples 1 of porous media depends on the oil detection limit. If the oil detection limit is too low, then sample size 1 may be too small. Currently, the detection limit for oil in water is 0.1 ml of oil in 10 ml of water. If it is desired to detect a 1% increase in oil recovery, this will require the sample to have a minimum accessible oil pore volume of 10 ml. However, for quick screening purposes, a minimum detection limit of a 5% increase in oil recovery (incremental oil recovery) may be acceptable. Typically, samples 1 of porous media are cylindrical in shape, preferably having a diameter in the range of 1 to 3 inches (2.54 to 7.62 cm), more preferably 1 to 2 inches (2.54 to 5.08 cm), for example, from 1 to 1.5 inches (2.54 to 3.81 cm) and a length of 1 to 6 inches (2.54 to 15.24 cm). For each set of experiments, samples 1 of porous media are of substantially identical size.
    ". Samples 1 of porous media are preferably. Loaded on each of the plurality of supports 2 of the high production apparatus VV. However, it is possible that one or more of the supports 2 is offline, for example, for maintenance. discussed above, the supports 2 can be arranged horizontally or vertically in the apparatus, so that fluids flow through the samples in a horizontal direction or a vertical direction. It is preferred that aqueous fluids (for example, formation water, flow) in a vertical direction from a lower end to an upper end of each sample 1. In the case of oil injection, it is preferred that the oil flow in the vertical direction be from a lower end to an upper end of each sample (in which case: oil can be injected into each sample 1 through the outlet of support 2).
    Typically, the fluids contained in the pore space of the porous media (for example, water and oil from the formation) for each of the parallel sets of experiments are the same, but the injection fluid can vary. However, it is also noted that the injection fluid used for each experiment can be the same is that one or more of the samples 1 of porous media, the oil or water of the formation can be varied.
    Although shown as disk-shaped members in the drawings, this is purely schematic. As will be appreciated by the reader versed in the context of the present exhibition, the dishes do not need to have a particular shape, and certainly do not need to be in the shape of a plate. One function of the plates is to wrap a ç test sample in a pressure vessel for testing and, optionally, D to allow fluids to enter and leave the vessel, and, VD still optionally, apply pressure to the sample. In particularly advantageous examples, one or both dishes can be provided with plungers. The two dishes need not be similar to each other.
    Figure 2a shows a detailed example of the flow lines and collectors that can be used by the apparatus of figure 1. In the example of figure 2a, two sets of three supports 2 are shown; however, the apparatus may have additional sets of supports, for example, from four to ten additional sets of three supports. For simplicity, sample 1, plates 3, 4, inlet 5 and outlet 6 for each support are not shown.
    In order to avoid any contamination of fluids, it is preferred that there is a dedicated reservoir l4a, l4b, l4c for each fluid. If dedicated reservoirs are not provided, it will be necessary to thoroughly clean the reservoir before switching fluids.
    A main oil supply line 12a is connected from an oil source l4a to a main manifold 15. Dedicated oil supply lines: 12d (one per support 2) lead via bypass manifolds 16 to manifolds input 17 for each of the supports
    2. Similarly, a main formation water supply line 12b for formation water is connected from a formation water source l14b to main collector 15, and dedicated formation water supply lines 2e ( one per support 2) lead through the bypass collectors 16 to the input collectors 17 for
    -— each of the supports 2. if In the example of figure 2a, a plurality of VU injection fluid sources 14c (of which two are shown) can be provided, in fluid communication with an injection fluid collector 18, the which allows fluid communication between one of the injection fluid sources l4c and the main manifold 15 through a main injection fluid supply line l12c. For example, when a plurality of porous samples 1 must be flooded in tertiary mode, synthetic seawater or low salinity water can be stored in the first fluid source l14c and the injection fluid (for example, the injection water ) that is under investigation can be stored in the second fluid source 14c. The dedicated injection fluid supply lines 12f (one per support 2) lead through the bypass collectors 16 to the inlet manifolds 17 for each of the supports 2, Typically, the inlet manifolds 17 are arranged on the first plate 3 of each support 2.
    Hydraulic pumps (not shown) can be provided on the flow lines. Valves (not shown) can also be provided on the flow lines and / or bypass manifolds 16 and inlet manifolds 17, as appropriate, to allow fluid switching.
    Inlet manifolds 17 operate to allow different fluids to be fed in a predetermined sequence (which can be controlled by the experimental design software component of the high production apparatus) to the inlet 5 of the first plate 3 of the support 2. The lines bypass 13 are provided so that the lines of
    The main feeds 12a, 12b, l12c and the dedicated% feed lines 12d, 12e, 12f can be flushed when connected directly to the effluent line 8, when the feeds are to be switched between different fluids.
    The valves on the main supply lines 12a ac can be opened or closed to allow selected fluids to flow into the main manifold 15, the appropriate dedicated supply lines 12d to £, to the inlet manifolds 17 and samples 1. Suitably, a control system (discussed below) of the high production device ensures that there is the correct sequence for opening and closing the valves. For non-permanent regime flooding experiments, the control system ensures that single fluids are injected in the correct sequence into the inlet manifolds 17. For permanent regime flooding experiments (for example, permanent regime relative permeability experiments), a mixture oil and water can be injected into samples 1. The control system ensures that the mixture of oil and water is injected simultaneously into samples 1 in the desired ratio (by controlling the correct sequence for opening and closing the valves and through adjustment of oil and water flow rates).
    Other arrangements for supplying fluids to each of the supports 2 can be seen. An example of an alternative arrangement is shown in figure 2b, where the valves (not shown) on the supply lines 12a, 12b and l2c can be opened or closed to allow selected fluids to flow to the main collector 15 and
    & for a single dedicated power line 12 for each% support 2. The unique dedicated power lines 12 are CÚ each provided with a by-pass line 13 that allows washing of the main collector 15 and the power line dedicated 12, thus avoiding contamination of samples 1.
    Regardless of the arrangements for supplying fluids for each of the supports 2, samples 1 of porous media are typically heated to the desired experimental temperature, for example, the temperature of the reservoir under study. The heating of samples 1 to the desired temperature can be achieved by arranging each support 2 (containing a sample 1 of porous medium) in a dedicated oven. Alternatively, each of the supports 2 can be provided with a dedicated heating jacket. These arrangements allow the temperature of samples 1 to be individually adjusted. If it is desired to heat the injection fluid to the desired experimental temperature, before being injected into samples 1 of porous media, the feed line 12 (or the dedicated feed line 12d, 12e, 12f) is preferably also heated (for example the final portion of the feed line 12 may be located in the oven, or the final portion of the feed line 12 may be provided with a heating jacket). If desired, some or all of the supports can be arranged in a single oven. For example, a set of supports 2 (and their porous samples) that should be used to perform the experiments in duplicate or triplicate can be heated to the desired experimental temperature by arranging the set of supports 2 in one
    "and single oven. A When samples 1 of porous media are samples of CV core, simultaneous core flooding experiments can be performed with samples 1 placed under full reservoir conditions, that is, the reservoir pressure and temperature from which testimony samples were taken, however, if desired, core flooding experiments can be performed at the reservoir temperature, but at a more suitable laboratory pressure. Typical reservoir temperatures are in the range of 20 to 150 ºC, for example, from 40 to 90 º C. The appropriate laboratory core pressures are in the range of 4 to 50 bar absolute (0.4 to 5 MPa), preferably 10 to 20 bar absolute (1 to 2 MPa) , for example, at around 15 bar absolute (1.5 MPa). However, the cores must be kept at a pressure high enough to prevent gas build-up (a dissolved gas forming a separate gaseous phase in the core), in particularly when using active crude oils.
    When mechanical studies are being carried out using sandpacks, synthetic rocks, packaging of resin, zeolites or ceramic materials, samples of porous media can be maintained at a temperature in the range of 20 to 90 ºC, and at an appropriate laboratory pressure (for example, at laboratory pressure as described above for core flooding experiments).
    Analysis of Porous Media and Fluid Samples Preferably, the high production apparatus is
    ". provided with a means for analyzing fluid samples & which are injected into porous samples to determine VU of one or more chemical or physical characteristics of fluids. These fluids include cleaning solvents, formation water, oil, and injection systems that are under investigation (that is, the injection waters used in simultaneous water flooding experiments or the injection fluids used in simultaneous improved oil recovery experiments). The chemical and physical characteristics of these fluids can be determined offline and on-line. When an off-line analysis is performed, fluid samples are taken for subsequent analysis. Preferably, the apparatus is also provided with a medium for analyzing samples of fluids produced from porous media (typically, oil and brine) to determine one or more chemical or physical properties of the fluids produced.
    The apparatus can also be provided with a means for analyzing samples 1 of porous media (for example, core samples) for chemical and physical characteristics.
    One or more analytical systems or instruments can be used to determine the composition of fluids injected into samples of porous media and fluids produced from samples 1 of porous media to obtain data on the chemical and / or physical characteristics of fluids injected and the fluids produced. Although manual or semi-automated systems of chemical analysis are possible, preferably an automated system, as described below with respect to q figure 3, is used to control and analyze the data. acquired using the analytical CU system (s) or instrument (s). the analytical system (s) or instrument (s) typically comprise a sensor, probe or detector and hardware for detecting signals produced by the sensor, probe or detector. For spectroscopic techniques, the analytical system (s) or instrument (s) typically also comprise a source of electromagnetic radiation (for example, ultraviolet, visible or infrared radiation).
    Preferably, the sampling points are provided immediately upstream and immediately downstream of the supports 2. Online and offline analytical techniques can be employed. For online analytical techniques, a sensor, probe or detector of an analytical instrument 7, 11 can be located directly in the pipeline of the high-throughput apparatus at each of the sampling points, for example, just before entries 5 or after exits 6 of supports 2. As discussed above, the sensor, probe or detector can be located in the fluid flow or adjacent to a window in the pipeline, so that the sensor, probe or detector can acquire analytical data with respect to fluids flowing through the pipeline. Alternatively, it may be possible to automate the high-throughput apparatus so that at least a portion of the fluid flow to each of the supports 2 or at least a portion of the produced fluids or effluent removed from each of the supports 2 is sequentially diverted for an analytical instrument
    ". 7, 11,, so that the analytical instrument 7. Sequentially analyzes the fluids being fed to each of the porous media samples and / or the analytical instrument 7 sequentially analyzes the fluids produced or the effluent being removed from each of the porous media samples, for example, a selector valve can selectively pass effluent fluids from one of the effluent lines 8 to the analytical instrument 7 through the sampling lines 8a. Similarly, a selector valve can selectively pass injection fluids from one of the supply lines 12 to the analytical instrument 11 through the sampling lines l12g. Several different on-line analytical instruments can be used for the analysis of different fluid characteristics. , the high-output device can be automated, so that fluid samples are removed at regular intervals through s of sampling ports for offline analysis.
    Analytical techniques for use with the high production apparatus of the present invention include chromatographic techniques and spectroscopic techniques. Suitable chromatographic techniques include gas chromatography (GC), high pressure liquid chromatography (HPLC), or ion chromatography used for the detection of anions or cations. Suitable spectroscopy techniques include mass spectroscopy (MS), such as atomic emission spectroscopy, atomic absorption spectroscopy, Fourier transform mass spectroscopy (FT-MS), ion and cyclotron resonance mass spectroscopy. transform (FT-ICR-MS) and gas chromatography - mass spectroscopy (GC-MS); Infrared (IR) spectroscopy; near infrared spectroscopy (NIR); Raman spectroscopy; ultraviolet (UV) spectroscopy and ultraviolet-visible (UV-VIS) spectroscopy including the use of fluorescent markers or chromophores that interact with the chemical component that is to be detected for the production of a signal in the region of
    UV or visible electromagnetic spectrum, for example,
    ionophores are available, which react with specific cations or anions, thus allowing the detection of these cations or anions using fluorescence or a color change; nuclear magnetic resonance (NMR) spectroscopy, and electron rotating resonance (ESR) spectroscopy. Other techniques include ion selective probes that can be used to determine the total dissolved solids content of a sampled water or water flowing through a flow line (for example, formation, injection water, or water produced from cores) or for the detection of specific ions in the sampled water or in the water flow, inductively coupled plasma (ICP) for the detection of metal ions; pH probes, sensors that detect electrical properties, such as impedance, resistance, dielectric constant or similar,
    and nephelometry to determine the oil content of produced fluids.
    Nephelometry techniques involve measuring the turbidity of a liquid sample by analyzing the dispersion of light in the liquid sample.
    Many of these techniques can be used online, such as the chromatographic techniques listed above, and the e techniques. spectroscopic below, GC, HPLC, ion chromatography,. IR, NIR, Raman, UV, UV-VIS and nephelometry. However, mass spectroscopic GU techniques will require sampling fluids, typically oil, for offline analysis, while an NMR analysis of porous media samples 1 will require that supports 2 be periodically removed from the high production apparatus and placed on an NMR spectrometer. Test Variables The high production device is capable of investigating one or more of the following variables: Different types of porous media; Formation of water formation; Oil composition; Injection fluid type and composition (eg injection water composition); Temperature (for example, tank temperature); Pressure (differential pressure through the porous samples and absolute pressure in the pore space of the porous samples); Compositions of fluids produced over time (for example, composition of produced water or composition of produced oil); Amount of oil produced over time and / or total amount of oil produced.
    In the case of a reservoir condition, core floods that employ an “active” oil, gas and oil ratios and / or gas composition.
    Porous media samples 1 can be plugs of
    * - core taken from samples of a formation carrying & hydrocarbon from a reservoir including CÚ plugs corestone of sandstone and carbonate; rock outcrop plugs; sandpacks including sandpacks formed from produced sand; packaging of resin, artificial rocks, ceramic materials or zeolite materials.
    As discussed in greater detail below, for flood experiments or improved oil recovery experiments, porous media samples are typically injected with water from the formation and then oil and then preferably aged.
    The formation water that is injected into the porous media samples is typically conate water (the water that was originally in place in the reservoir). However, when the reservoir has been flooded with water, the formation water may have the composition of the water that is present in the reservoir under investigation (a mixture of conated water and water previously injected).
    The oil that is injected into samples 1 of porous media can be a storage tank oil (STO) taken from a reservoir of interest or an “active” oil (a gas recombined STO, typically a synthetic gas that is representative of the gas that is separated from the oil in a production facility). Synthetic oils can also be used. For example, an organic solvent containing one or more components typically found in crude oil, such as aromatic compounds, aliphatic compounds, acids, bases or asphaltenes. The use of synthetic oils allows the study of the mechanisms by which different components of a crude oil are attached to the surface of the
    *. rock and also the mechanisms by which these “crude oil components are displaced from the surface of the rock (or from the surface of an analogous material, such as an ion exchange resin) to be studied. For example, interactions between crude oil components and additives that are contained in an injection fluid can be investigated. Typically, the basic organic solvent for synthetic oil is selected from a Cs to Cx alkane, for example, pentane, hexane, heptane, octane, nonane, decane, undecane, dodecane and mixtures thereof. Alternatively, an aliphatic base oil can be used, as long as this base oil does not contain aromatic hydrocarbons. An example of a suitable aliphatic base oil is depolarized kerosene.
    Injection fluids that can be tested include variable total dissolved solids (TDS) base brines (salinity). For example, brines having a TDS in the range of 100 to 200,000 ppm can be tested. Other potential injection fluids that can be tested include steam and gases. The gases can be, in particular, miscible gases, such as CO; z, hydrocarbon gases (such as methane, ethane or propanes) or mixtures thereof. Alternatively, the gases can be Nx, or air.
    In the case of a CO injection; miscible, the temperature and pressure of the CO, must be chosen so that the CO; be in a supercritical state. CO; Supercritical injected will be miscible with the oil that is present in the solid medium, thus reducing the oil viscosity and removing more oil from the sample 1. Due to the fact that the CO is miscible with the oil, it may be necessary to reduce the
    . pressure of the effluent, to remove CO, gaseous, before determining the amount of oil produced. Measurement VU data indicative, for example, of absolute pressure and differential, volumetric fluid recovery and recovered fluid composition are taken. Such COz floods typically involve relatively small volumes of fluid, and some samples of fluid produced may have a volume of less than 0.2 in. Miscible applications can occur over a wide range of temperatures and pressures, but a typical temperature is approximately 120 ºC (400 K) and a typical pressure is approximately 300 bar (30 MPa). An example of a technique used in CO flooding experiments involves bringing the fluids produced to the temperature and pressure of the reservoir. The fluids produced then undergo a “flash” transformation (at reduced pressure) through a regulating valve for atmospheric pressure and temperature. The fractional samples are then collected for composition analysis by the analytical component 211 of the control system 200. The mass of each fraction is measured and then using a specific weight of the original active crude oil and a pore volume factor formation, the fractional volume of oil in the reservoir conditions can be determined.
    Suitable additives for the injection fluid, in particular for the injection water, include cations, anions, polymers, surfactants, alkalis, acids, microbes, colloids, clay particles, nanoparticles, microgel particles, polymer particles, and mixtures of the same.
    Additives can be tested over a wide range of
    F concentration for determining optimal concentrations, “for example, concentrations in the range of 5 to 20,000 ppm. VU Two or more additives can be included in the injection fluid node to test for synergies between additives.
    Damage to the formation of core plugs that can arise from the passage of an injection fluid through the core plugs can be measured by monitoring any changes in differential pressure through the core plugs. Typically, an increase in differential pressure is indicative of formation damage with the amount of formation damage being related to the relationship between the initial differential pressure through the core plug and the final differential pressure through the core plug (for the same fluid viscosity ).
    It may also be necessary to monitor the viscosity of the fluid being injected into the core to correct for changes in differential pressure arising from different viscosities of the various injected fluids.
    Method A method for simultaneously injecting an injection fluid into a plurality of porous media samples is also exposed here, in which the porous media samples are saturated with oil to an irreducible water saturation, S., The method comprising: aging porous media samples that are saturated with Sw oil, so that the samples are in a state of mixed wetting capacity; the injection of an injection fluid into each of the porous media samples, the removal of any displaced fluid from the
    T- porous media, the analysis of the fluids injected into each of the CU porous media samples, and the analysis of any fluids removed from each of the porous media samples.
    Also exposed here is a method in which samples 1 of porous media are substantially similar, for example, in their mineral components, specific weight, porosity and physical dimensions, and, in fact, may be identical. , the formation water and the oil that are used to take each of the porous samples 1 for irreducible water saturation are substantially similar or the same .. Alternatively or additionally, the injection fluid that is used in each one of the simultaneous experiments can be substantially similar or the same, and one or more of the other variables can be changed / controlled, for example, the composition of the oil, the composition of the water in the formation or the type of porous media.
    Simultaneous experiments can be performed in a secondary mode by injecting different test injection fluids into samples 1 of the porous media. Alternatively, a baseline injection fluid, for example, synthetic brine, is injected into each of samples 1 to take samples 1 for a first saturation of residual oil S.1. Different test injection fluids are then injected into samples 1 of porous media in the tertiary mode. If no incremental oil is produced in the tertiary mode, samples 1 will remain at the first residual oil saturation. If
    FT. incremental or additional oil is produced from Sample 1, samples | will be in a second lower CG saturation of residual oil, Sor. Preferably, the method of the present invention includes determining the first and second saturation of residual oil (as described below). Preferably, each simultaneous experiment is performed in duplicate or triplicate by injecting a different test injection fluid into two or three of the porous media samples 1, respectively.
    Control System Software Generally, the automated system comprises the control system 200 which includes various programmable software components or tools; with reference to figure 3, an analytical component 211 and an experimental design component 213 are provided, and other software components in the form of a data acquisition component 215, a predictive model 217 and an optimization component 219 can be provided, as further described below. The control system 200 comprises a conventional operating system 221 and storage components, such as a system bus connecting a central processing unit (CPU) 205, a hard disk 203, a random access memory (RAM) 201, data adapters. 1/0 and network 207 facilitating the connection with user input / output devices and interconnection with other devices, such as analytical instruments and / or the 223 device controller, as described below, optionally on an Nl network. RAM 201 contains operating system software 221 which controls known level operation in a known manner
    * - under the 200 processing system. Still, when. control and / or analysis of fluid injection in CÚ 1 samples under the control of device controller 223, operating system 221 loads software components 211, 213, 215, 217 and 219 into RAM 201. Each software component 211 , 213, 215, 217, 219 is configurable with measurement data and / or predetermined data which can be stored in a DBl, DB2 database or other storage component that is operationally coupled or connected to the processing system 200.
    As discussed below, porous samples (in particular core plug samples) are preferably cleaned before being saturated with oil in an irreducible water saturation. The porous samples are then aged using an aging protocol. One or more sets of flood experiments are then performed by injecting an injection fluid into samples 1. Measurements of fluid characteristics and porous media required for further analysis by the 200 control system can be made: before, during and / or after each of these cleaning, saturation, aging and flooding stages, and at each stage, a user or operator of the instrument and control system 200 is optionally able to check the measurement data and manually instruct the instrument and / or control system 200 to proceed to the next stage, as desired.
    With reference to figure 4, the steps involved in the analysis of measurement data received by the control system 200 from the analytical instruments 7, 11
    FT. and / or other data acquisition hardware are shown. The * measurement data can comprise specific CV measured values as measured directly by analytical instruments 7, 11 properly positioned. In step S401, the measurement data is received by the control system 200, preferably by the data acquisition component 215. The data acquisition component 215 can be configured to process the raw measurement data received to obtain value relationships of characteristics, or values derived from several characteristic measurements separately, according to known techniques. Therefore, the gross measured characteristics can be, if necessary or preferred, manipulated by the data acquisition component 215, or, alternatively, by the analytical component 211, in order to generate measurement data that are suitable for the introduction, in step S402 , in one or more calculation algorithms in particular of the analytical component 211. This manipulation may comprise simply a conversion of measurement unit or the creation of a required relationship of measured values.
    In step S403, analytical component 211 is executed according to predetermined rules, for example, in the form of various algorithms (which are preferably stored in and accessible from the storage component DBl, as needed, and automatically executed according to parameters of the received data). The analytical component 211 is configured to analyze the compositions of the various fluids and materials involved in the experiments, for example, data indicative of the chemical characteristics of the injection fluid to be
    “. used for each of the simultaneous experiments, and also x can be configured to analyze VC experimental results received by the data acquisition component 215 of the control system 200. More specifically, the analytical component 211 is programmed according to rules, such as protocols for cleaning samples of porous media (discussed below), aging protocols (discussed below) and analytical protocols for the analysis of injection fluids and produced fluids, so that the output data, such as fluid release profiles and fluid composition parameters, as will be described with reference to step S404. In step S404, analytical component 211 generates analytical data as an output, which is indicative of the effects of fluid injection based on the measurement data.
    The analytical data may comprise a fluid release profile produced based on each sample 1 (or a single release profile produced by combining output data from similar samples); these fluid release profiles show changes in the composition and / or the amount of oil produced (recovered) and / or in the composition of water produced over time.
    Analytical component 211 can determine, for example, when no additional oil is being recovered from the samples; and when the composition of the injection fluid produced (e.g., water produced) flowing out of the samples is substantially the same as the composition of the injection fluid.
    The amount of incremental oil recovered from a sample based on a specific set of experimental parameters can also be determined by the analytical component 211.
    The analytical component 211 can determine when the porous samples are clean by detecting when cleaning solvents being recovered from the samples are of substantially the same composition as the solvents injected into the samples, in particular, by detecting when the oil components are no longer present in the solvent being recovered from the samples. In addition, the analytical component can determine when the porous samples are saturated with brine to a saturation of 100% water, S, = 1, when the samples are in irreducible brine saturation, Sw, & when the samples are saturated with oil in Si eE € the initial oil saturation, Sa For example, when injecting brine as an injection fluid, samples | are determined to be in Swi, when the presence of brine, preferably above a predetermined limit quantity, is detected by the analytical instruments 7 in the effluent lines 8. The analytical component 211 can also determine when the aging of the porous samples is completed (discussed below), for example, by analyzing NMR data that is obtained periodically for each of the porous samples. An interpretation of the measurement data can be made by the analytical component 211 based on a mapping between certain values or ranges of parameters stored in a query table that is accessible by the analytical component 211.
    Once the analytical component 211 has been executed and the analytical data has been generated, software executed by the CPU 205 of the system 200 determines, in the step
    Te S405, based on analytical data, one or more device controller & operation modes 223. The analytical GU component 211 can be configured to determine the mode (s) of operation when generating and interpreting data. analytical data, or a separate software component (not shown) can be provided.
    As discussed above, analytical data can comprise a fluid release profile showing changes in the amount of oil produced over time (typically, the cumulative amount of oil produced over time), and this can be used by the analytical component 211 for determining a future operating mode for device controller 223, based on an interpretation of the profile by analytical component 211. Analytical component 211 can access a lookup table to determine whether an operating mode should be applied to the controller of device 223 based on these data.
    For example, if an analysis of the oil recovery profile shows a sharp increase in the volume of oil recovered (for example, if there is a noticeable increase in the gradient of cumulative oil recovery over a time profile, or if the volume of oil produced is above a limit value), analytical component 211 can determine from the look-up table that the injection of the injection fluid currently in use should continue, and a mode of operation comprising an instruction to continue to inject the injection is sent to device controller 223. Alternatively, if an analysis of the recovery profile
    ”Of oil indicate that there is no oil recovery Or oil & recovery of negligible amount after a VU predetermined volume of injection fluid (such as 30 PV (pore volumes, defined here as the volume of the sample pore space Porous media 1)) be injected, the look-up table may indicate that the fluid injection should stop, as it is not producing a sufficient volume of oil in increment, and the analytical component 211 will determine and apply a suitable mode of operation, instructing device controller 223 to stop the current injection.
    Analytical component 211 can also recognize any inflection point present in the oil recovery profile, which indicates a point in time at which the recovered incremental oil begins to decline (for example, cumulative oil recovery in relation to the oil recovery profile). time begins to form a plateau, in which case Analytical component 211 can determine a mode of operation from the lookup table to continue injection for a predetermined length of time, or to inject a predetermined volume of injection fluid, such as 20 PV, after that time and then stop the fluid injection.
    The operating mode is applied in step S406 by sending the operating mode to device controller 223, where the instruction is executed by the control software associated with controller 223. The control software allows, for example, remote actuation of the valves 10a, 10b and 10c pumps.
    The control software is therefore configured with appropriate rules, just as an appropriate pump l10c can be operated simultaneously with or in
    =. an appropriate period of time from the opening of
    2 suitable valves 10a, 10b.
    CU The data acquisition component 215 can generate, in an additional or alternative way, operating modes, for example, in order to instruct the high production device to divert samples from the fluid inlet and / or outlet of each of the supports 2, in turn, for analytical instruments 7, 11 for the determination of certain chemical and / or physical parameters.
    When the analytical instrument comprises a plurality of sensors, detectors or probes that are located in the plurality of effluent lines 8 or adjacent to the plurality of effluent lines 8, the analytical component 211 or the data acquisition component 215 can generate modes of operation to instruct the analytical instrument to record data being acquired by sensors, detectors or probes to determine certain chemical and / or physical parameters.
    The analytical component or The data acquisition component 215 can instruct the analytical instruments 7, 11 to acquire this data continuously or intermittently. It is noted that two or more different sensors, detectors or probes for two or more analytical instruments can be located in an effluent line 8 for the acquisition of data associated with different chemical and / or physical characteristics of the effluent fluids.
    It is also noted that the analytical component or the data acquisition component 215 can instruct the high production apparatus to acquire samples of fluids that are flowing, for example, through the sampling flow lines 8a, 129.
    z This fluid sampling can take place on a port, for example, on sampling line (s) 8a, 12 and can be manual or automated CU.
    Accordingly, the analytical component 211 or the data acquisition component 215 can extract an instruction for the device operator to take a sample or generate an operating mode for instructing an automated sampling device to sample the fluids.
    With reference to figure 5, the experimental design component 213 is configured for identification and design, based on the results of the analytical component 211 algorithms and / or the measurement data received (step S501, which corresponds to step S401 or to S404 of figure 4) by the control system 200, other experiments having optimized characteristics that result in or improve a required effect, such as an improvement in oil recovery in increment.
    Thus, side limit 23 can correlate different levels of oil recovery in increments for different experiments performed using the high production apparatus for varying experimental parameters, such as the healthy chemical composition of the injection fluid, oil, water formation or porous media or physical parameters of the injection fluid, oil, formation water or porous media.
    The experimental design component 213 can then identify the improved potential and, preferably, the optimal compositions for injection fluids.
    Therefore, the received data is entered in step S502 in the experimental design component 213, and, in step $ 503, the experimental design component 213 is
    TZ executed according to predetermined rules, for example, in the form of varied algorithms (which VUs are preferably stored in and accessible from the DB2 storage component, as needed, and automatically executed according to the parameters of the received data) , for the generation (step S504) of experimental design data.
    The experimental design component 213 can be configured to classify the results of completed experiments with respect to oil recovery in increment and to compare these with a required effect of a future experiment, such as a desired volume of oil recovered.
    The experimental design component 213 is also configured to correlate the fluid release profile (s) generated by the analytical component 211 for a measurement of the oil in increment recovered from each sample 1. The experimental design component 213 also can determine correlations between different chemical and / or physical characteristics of injection fluids, produced fluids, formation waters, oil or porous media from complete experiments, and known oil recovery results in increment, thereby allowing that appropriate algorithms of the experimental design component share other experiments that optimize injection fluids for porous media samples.
    In particular, the experimental design component 213 may include statistical experimental design software that is configured to plot additional experiments based on initial output data
    && from a primary screening.
    o Preferably, the experimental VU 213 design component uses a statistical correlation approach to identify factors that influence experimental results. A multiple regression analysis can be performed, and a respective weight assignment for each parameter that can contribute to the recovery of oil in increment can be established. Certain parameters of those that affect an oil recovery in increment will contribute to the calculated value more than others, and this can be captured through a weighting scale from 0 to 1, for which parameters that have a weighting more high are more significant than those with a lower weight allocation. A multiple regression analysis minimizes the effects of errors in the measurement data that arise from the experiments, and hence, optimal parameter values or an optimal range of values can be calculated for use in future experiments. A bespoke experimental design software package can be employed, or statistical packages such as JMPO (supplied by SAS Inc) or STATISTICA (supplied by StatSoft Ltd) can be used. For example, the results of an initial screening (ie, a primary set of flood experiments) can be used to determine whether or not there is any incremental oil recovery when a certain additive is added to a particular injection fluid. ; determine whether or not any oil is recovered in any way, or whether an amount of oil beyond a predetermined threshold value is recovered. Based on technical factors and
    Economical TZ, it is preferable to use as little additive as possible in the injection fluid, although the amount of additive CU used can impact on the amount of oil in increment recovered. The initial screening can be carried out with a relatively high concentration of additive and, based on the results generated by the analytical component 211, the experimental design component 213 can design other experiments for the optimization of the additive concentration, typically by reducing the additive concentration . The initial concentration of the additive can be 25,000 ppm, and, based on the volume of oil in increment recovered by the initial screening, a determination is made by the experimental design component 213 to perform a second screening with an injection fluid having an reduced additive concentration of 10,000 ppm, and an instruction to this effect is sent to device controller 223 accordingly. If the incremental oil recovered during the second screening does not decrease beyond an acceptable predetermined amount, the additive concentration may be reduced again. The reduction can continue until the recovered incremental oil is negligible, and an optimal value for the additive concentration can be further investigated.
    Each of the analytical and experimental design software components 211, 213 is additionally capable of determining (step S505, which corresponds to step S405) instructions comprising a mode of operation based on the output of data in this way. The operation mode is applied in step S $ 506 (which corresponds to step S406) by sending
    & operating mode for device controller 223, cs where the instruction is executed by the CU control software associated with controller 223. Device controller 223 executes operating mode for controlling the physical device according to the design data generated (for example, for closing a valve 10a, 10b, injection of a fluid through a specific inlet 5,
    operation of a 10c pump, etc.). The experimental design component 213 can take an input from or run in conjunction with a predictive water flood model 217, similar to that described in international patent application number PCT / GB2010 / 001038. The predictive model 217 is configured to generate predictive data, for example, a theoretical prediction of the amount of oil in increment recovered when using a particular set of measurement data representative of the physical and / or chemical characteristics of the injection water, the oil, porous medium, etc., before any physical experimentation took place.
    Alternatively, a predetermined limit value of a required amount of oil displaced on a slope, compared to the predetermined volume of oil, is introduced (step S602) in the predictive model implemented in computer 217, together with the received measurement data (step S601) from the measurement of one or more characteristics of the rock formation, crude oil and water of the formation, and when executing the predictive model 217 (step S603), predictive data indicative of one or more predicted characteristics of the injection fluid are generated (step S604). For example, the predictive data generated may be related to a “total dissolved or dissolved solids content (TDS) and / or a multivalent CÚ cation content of the displacement fluid required for displacement of at least a predetermined oil limit value. displacement in increment that was introduced in the predictive model 217. Thus, the characteristics of the injection fluid that is required for displacement of a required amount of oil in increment can be predicted.
    The predictive model 217 can be used in step S605 to verify that the experiments carried out by: apparatus conform to an initial prediction and, if so, the predictive model can be used to help optimize the calculations of the experimental design component 213 Alternatively or additionally, the correlations resulting from the execution of lateral limit 23 can be used by an optimization component 219 in step S606 to optimize the algorithms and constraints of the predictive model 217. For example, if the initial experiments are not According to the initial prediction, any potential errors can be identified and investigated, before additional experiments are performed, and, once any problems are identified, the experiments can be repeated. However, if the same set of results is obtained by repeating the experiments, then it will be necessary to update the predictive model 217 to take into account additional unexpected results. As more and more measurement data is accumulated by the control system 200, the optimization component will be able to z iteratively adjust the programming rules of the predictive model 217 to optimize the accuracy of the
    Really.
    The predictive model 217 can comprise a statistical software package, such as those provided by SASG JMPO.
    The relevant data is compiled, for example, in a Microsoftê Office Excel spreadsheet, which is opened using the SASO JMPO package.
    A series of scatter type charts of specific characteristic data in relation to a value for the benefit gained (For example, the percentage of oil in increment) is produced using the function “Analyze, Adjust Y by X”, for example, a graph of dispersion type of oil percentage incremented by API oil, or percentage oil incremented by calcium concentration of the injection water.
    Scatter type plots are then used to construct a high-level image of which characteristics are most relevant (that is, produce the best correlations). A software tool which applies a principle component analysis to the data can be used to determine which characteristics to introduce in an “Fit Model” function. Alternatively, a choice of characteristics can be made manually.
    The oil percentage data in increments are then added to the “Y variables” and other chosen characteristics are added for the “construction of model effects”. The model results are then exported to a program, such as Microsofto Office Excel , and a test fit can be applied to the existing data in order to verify the
    Model T.
    "7 The control system 200 preferably provides a graphical user interface (GUI) VU to allow users to add an entry considering or suppressing the automated design by the experimental design component 213. The experimental design component 213 is capable of analyzing the data extracted from the analytical component 211 for significant statistical correlations according to a set of predetermined rules, and then, at the output of this algorithm, it is displayed visually, for example, graphically, to alert the user to the correlations found. configured to receive the data generated by the experimental design component 213, specifically, data indicative of various experiments generated in step S503, as described above; however, the user can suppress this manually using a knowledge-based assessment to determine the next experiments to be performed. For example, the user may be aware factors which are not programmed in the algorithms constituting the experimental design component 213. The measurement data received by the control system 200 are based on chemical and / or physical characteristics measured from the formation water, oil, test injection, sample of porous medium, and the fluid produced from sample 1 of porous medium for each of the “simultaneous experiments. The measurement data can comprise specific measured chemical or physical values, as measured directly by one or more of the
    analytical instruments 7, 11 properly positioned, ss or value ratios of physical or chemical characteristics, or may comprise values derived from several measurements of chemical or physical characteristics separately, according to known techniques. The data from previous high production experiments can be stored in the storage components DBl, DB2, so that, for each round of high production (simultaneous flooding experiments), the experimental results can be compared by the experimental design component 213 with the results obtained from previous high production rounds.
    Data obtained from an offline analysis of chemical or physical characteristics of fluids or porous media can also be stored in the DBl, DB2 storage components of the control system 200.
    The experimental design component 213 can be configured to sort or classify different injection fluids, for example, injection water in order of priority, based on the results of high throughput experiments. These results can alert the user that additional experiments must be carried out using the high production apparatus, in order to optimize an injection fluid for a particular reservoir (reservoir rock in particular, formation water and oil). Alternatively, the software can alert the user to an injection water suitable for a reservoir that provides a good level of oil recovery in increment taking into account factors such as available volume of the base injection water, and cost of additives,
    compared to oil recovery in increment. O. It may also be possible to automate the injection of 'test fluids' for each sample 1 of porous medium. Thus, the injection of a test fluid, for example, an aqueous fluid, can continue until the detectors downstream of the supports 2 signal that no additional eyes are being produced. A flood with an aqueous fluid can be carried out in a secondary mode, with different injection waters being classified by the control system 200 based on the amount of oil produced from samples 1 of porous media. Alternatively, the flood can be in a tertiary mode, where each sample 1 is initially flooded with synthetic or naturally occurring water with high salinity, and the amount of oil produced determined. Core samples 1 are then flooded with different types of injection water to test the production of any oil in increments. If incremental oil production is detected downstream of a support 2, the automated system will continue to inject the injection water until no additional incremental oil is produced.
    The composition of the injection fluid can be kept substantially constant with respect to time during testing. Alternatively, after a sample 1 of porous medium has been reduced to saturation of residual oil with a particular injection water, the composition of the injection water can be changed to determine whether an additional increment oil can be recovered from the sample 1 of porous medium. For example, the concentration of an additive for injection water can be increased, after
    sample 1 has reached a residual oil saturation for J to see if the increase in the concentration of the additive results in] an oil recovery in additional increment.
    Additional Data Additional data relating to the chemical and / or physical characteristics of the porous media, the formation water, the oil and the injection fluid can be determined offline.
    For example, when samples 1 of porous media are core plug samples, the core is typically subjected to chemical analysis to determine chemical characteristics, such as: the total rock clay content of the reservoir rock, Oo what can be determined by X-ray diffraction (XRD), electron scanning microscopy (SEM) or infrared scintillation point count; the mineral content of the rock clay fraction, in particular smectite clays (such as montmorillonite), pyrophyllite type, kaolinite type, illite type, chlorite type and glauconite type, which can be determined by diffraction with X-rays (XRD), electron scanning microscopy (SEM). Physical characteristics, such as porosity and permeability, can also be determined.
    By introducing these chemical and physical characteristics into the control system software components 200, the correlations between these characteristics and the results of the water flood tests can be determined.
    Other preferred or more specific chemical characteristics, which can be measured for the provision of analytical data for introduction into the components of
    . control system software 200 include: an XRD Ss analysis of total rock formation, including all] types of minerals in the reservoir rock (including clays and transition metal compounds, such as oxides and carbonates, for example, iron oxide, siderite and plagioclase feldspars); the zeta potential of the rock.
    The oil that is to be tested using the high production method and the apparatus of the present invention can also be analyzed for chemical and physical characteristics.
    The chemical characteristics of the oil include the total acid number (TAN) value; the base number of the oil; The content of asphaltene and resin components in the oil; the total nitrogen content of the oil (ppm by weight) and the basic nitrogen content of the oil; the total sulfur content of the oil (ppm by weight); the total oxygen content of the oil in ppm by weight; a SARA analysis of total oil (SARA means saturated, aromatics, resins and asphaltenes and is a full assessment of how much of each type of oil component is present in a sample 1); and the mass spectral composition, as obtained, for example, by electrospray Fourier transform ion resonance mass spectroscopy. The physical characteristics of the oil include the specific weight (relative density) of the American Petroleum Institute (API) of the oil and the viscosity of the oil at the temperature and pressure of the reservoir, the viscosity of the oil under standard conditions (for example, the measurement of viscosity can be done at 20 ºC, 25 ºC and 30 ºC). Additional oil parameters that can be taken into account, as required in order to configure the oil component
    * experimental design 213, which correlates to the Ss results of the water flooding apparatus include: oil pour point temperature (ºC); oil mist point temperature (ºC) specific weight of oil at 15 ºC (g / ml) or some other standard temperature; boiling point distribution of oil (% by weight); oil boiling point distribution (ºC); surface oil tension (mN / m); oil / salt interfacial tension (mN / m); and interfacial tension of oil / fresh water (mN / m).
    Similarly, the chemical characteristics of the formation water and any injection water can be tested using the high production method and apparatus of the present invention and the data entered in the experimental design component 213. These chemical characteristics include the total dissolved solids (TDS) content, the total multivalent cation concentration, the concentration of individual cations occurring naturally in the formation and injection waters (such as sodium, potassium, magnesium, calcium, barium and iron), the concentration of individual anions that are naturally occurring in the formation and injection waters (such as sulfate, phosphate, nitrate, nitrite) and the pH of the water. The chemical characteristics of the injection water can also include the concentration of additives, such as anions (for example, anions used for microbial increment oil recovery, MEOR), cations (for example, cations used for crosslinking polymers) , surfactants and polymers.
    Cleaning and Aging Procedure for Porous Media Samples
    & Samples 1 of porous media, for example, core plugs, are preferably cleaned prior to carrying out simultaneous flooding experiments using the high production apparatus of the present invention.
    For example, when samples 1 are core plugs or sandpacks formed from produced sand, they may initially contain many substances in their pores, for example, formation water, drilling mud, crude oil.
    If deemed necessary, the plurality of samples 1 of porous media (each arranged on one of the supports 2) is cleaned by washing the samples 1 with solvents (typically toluene followed by methanol) until all the oil has been washed from the samples 1. When the cores contain reactive clays, such as smectite clays, the cores are preferably cleaned with kerosene and isopropanol, as opposed to the most common solvents, toluene and methanol, so as not to artificially change the absolute permeability of the cores by mobilizing the clays.
    The cleaning process is improved if the solvents are switched a plurality of times,
    When cleaning samples 1 with solvents, before performing high-throughput experiments, an online solvent analysis can be used to detect differences between the solvent immediately upstream and downstream of supports 2 (for example, for the detection of signals in the effluent arising from chemical impurities (for example, oil components) that were eluted from samples 1 of porous media). When there are no differences between the chemical characteristics of the injected solvent and the effluent solvent, samples 1 of porous media are
    considered clean. As discussed above, it may be necessary to switch between the cleaning solvents to obtain efficient cleaning of the samples 1. The cleaning of the samples 1 can be automated by the use of software associated with the device controller 223, which controls the switching between solvents , for example, software that opens and closes valves leading to different solvent storage vessels (for example, 08 reservoirs 14), thereby controlling the flow of solvents through samples 1 of porous media. Preferably, this software finishes cleaning an individual sample 1 of porous medium, when an operating mode received from analytical component 211 indicates that there are no chemical impurities in the solvent that is eluted from sample 1.
    Once the l1 samples have been cleaned (if necessary), then they are saturated with a brine of known composition, whose brine can be intended for the simulation of conate water or formation water (for example, a mixture of conate water and a previously injected water, such as sea water or produced water) that is present in the reservoir under investigation. Conated water means the water originally present in the reservoir, before the migration of oil from a source rock to the reservoir rock.
    Thus, the composition of the synthetic brine may vary, depending on the reservoir under investigation. When samples 1 are fully saturated with brine, they are said to be at 100% water saturation (S, = 1). Typically, samples 1 of porous media can be brought to 100% water saturation
    Á by forcing the brine through samples 1 under vacuum ss (for example, using a suction filter set). This suction filter assembly can be separated for the high production apparatus, in which case the supports 2 are removed from the apparatus, so that samples of porous media can be placed in the suction filter assembly. Alternatively, the supports 2 can be retained in the high production apparatus, in which case a valve located on each effluent line 8 can be opened to connect the supports 2 and their samples 1 associated with a vacuum line, and a forming brine synthetic can be fed to the inlets 5 of the supports 2. It is also noted that the brine can simply be injected through samples 1 (with the supports 2 retained in the high production apparatus) for a period of time sufficient to guarantee a saturation of 100% water.
    The next step involves primary drainage of cores for an irreducible brine saturation, Swir (also referred to as initial water saturation). This drainage can be accomplished by injecting or directing a non-wetting phase or an oil through the samples | porous media, which are initially 100% saturated with brine.
    The sample restoration step 1 for irreducible or initial (healthy) water saturation can be achieved using a confined porous plate technique. Typically, samples 1 of the porous media are each arranged in porous plates that have a permeability of at least one to two orders of magnitude lower than that of samples 1. It is important that there is good contact between the porous plate and sample 1, typically this can only be ensured by inserting filter paper (which may comprise a wicking medium, such as fiberglass) between the porous plate and sample 1.
    This also helps to ensure that the porous medium is in contact with the surface moistened with water. Each sample 1 is typically arranged substantially vertically on the porous plate, with the longitudinal geometric axis through the cylindrical sample aligned with the vertical geometric axis. Once sample 1 is installed on the porous plate, a non-wetting phase, such as air, nitrogen or a mineral oil, or an oil, such as an organic oil, crude oil or a distillation fraction thereof, such as as kerosene (from this point, an “oil phase”), it is injected into sample 1 at constant pressure to move a portion of the brine (or the formation water) from the sample and through the porous plate, from that thus providing a desired ratio of aqueous phase to non-wetting phase or oil phase. Due to the fact that the non-wetting phase or oil phase is injected at constant pressure and the large difference in permeability between the samples and the porous plates and the plate being completely moistened with water, the injected non-wetting phase or oil is unable to flow out of samples of porous media. When samples 1 are saturated with the non-wetting phase or the oil phase in irreducible water saturation, water is no longer being produced from samples 1, and the cores are defined as being in S.i. If the oil phase is crude oil, samples 1
    "now they will be saturated with crude oil in Si If a non-wetting phase s is used or the oil phase is another oil in addition to crude oil, the non-wetting phase or the oil phase from the samples | will be shifted, using crude oil by injecting crude oil into the samples | at a constant pressure, leaving only water and crude oil occupying the pore space of samples 1. Samples 1 are now saturated with crude oil in Sá and are in a saturation of initial oil (Si).
    if Susi is acquired by injecting and directing kerosene through samples of porous media (which are initially saturated 100% with brine), the kerosene will typically be displaced by a toluene buffer, before displacing the toluene with oil. The toluene buffer is used to prevent the deposition of asphaltenes from the crude oil, which may otherwise flow if the crude oil contacts the kerosene.
    If Sua is acquired by injecting a gas (for example, an inert gas, such as nitrogen), through samples of porous media (which are initially 100% saturated with brine or water from the formation), the gas then, initially, it will be displaced with crude oil (under a back pressure) to obtain the initial oil saturation (Sa). However, an oil (other than crude oil) can be used for displacing the gas (eg kerosene), and this oil is subsequently displaced with crude oil.
    Swi is typically acquired using a non-wetting phase or an oil phase (other than crude oil), where the crude oil is viscous, and therefore does not readily displace the formation water from the pore space porous media samples.
    When core plugs are being used, crude oil is typically taken from the reservoir from which core samples 1 were obtained.
    The crude oil can be an “inactive” oil or an “active” oil that has been recombined with gas. When crude oil is an “active” oil, the gas remains in solution, due to the high pressure maintained on the device and on the cores.
    If desired, sample routing | for an initial or irreducible water saturation it can be performed using a separate porous plate apparatus. Samples 1 in the initial water saturation S, .i are then loaded onto supports 2. However, it is also envisaged that the high production apparatus can initially be configured so that samples 1 of porous media are arranged on supports 2 having plates end porous plates, instead of end plates 3, 4. After cleaning samples 1 and placing the samples in Sw, the porous plates are then replaced with plates 3, 4 for high production flood tests.
    It is also possible to take samples 1 of porous media to S. using centrifugal techniques. Thus, a plurality of samples 1 of the porous media that are 100% saturated with water (S, = 1) is placed in a plurality of centrifuge tubes. After centrifugation, samples 1 of porous media will be in S ', and the tubes will contain oil and water. Alternatively, S.a. can be obtained by centrifuging the samples 1 under a non-wetting gas zone, in which case it is necessary, then, to move the non-wetting phase with crude oil (optionally through an intermediate oil). This technique is suitable for core samples 1 and for small sandpacks (where the sandpacks are contained in a glove having ribs at each end to allow the oil to displace a portion of the water from the sandpack pore space). Samples 1 of porous media in the initial oil saturation (S.) are then loaded onto supports 2 of the high production apparatus.
    The initial oil phase saturation level (S.a) can be selected to replicate conditions likely to be found in a reservoir, for example, by changing the pressure of the oil that is injected into the samples | for the porous plate technique or for changing the spin speed of the centrifuge. For example, oil can be added to samples 1 in the amount required to provide an initial oil saturation level from 0.4 to 0.9, for example, from 0.5 to 0.7.
    In the laboratory, it may be possible to control conditions using the software components of control system 200 described above, so that the sum of the initial oil saturation level (Si) and the initial water saturation (S.) equals the unit , that is, Sa + Sa = 1. This means that the pores of the porous media are completely filled and contain only oil and water. In general, however, Sai + Sm is more likely to be slightly smaller than the unit, as other phases, such as air, may be present in small amounts in
    % pores.
    However, for the purposes of the high production experiments, the sum of S. and Sw is assumed to be equal to the unit.
    A nominal overload pressure of 350 to 5000 psi (2.41 to 34.47 MPa), for example, around 400 psi (2.76 MPa), is then applied to samples 1 of porous media that are at S '.. Thus, each sample 1 of porous medium that is loaded on each support 2 is provided with a rubber glove that is opened at each end.
    O-rings at the first and second ends of the sample form a fluid-tight seal with support 2. A fluid is injected under pressure into the annular space formed between the rubber sleeve and the inner wall of support 2, so that a pressure of an overload of around 400 psi (2.76 MPa) is applied to the rubber glove and, hence, to the side wall of the porous medium sample.
    This is the containment pressure of samples 1 of porous media.
    The fluid that is injected into the annular space can be water, a hydraulic oil or a gas, typically an inert gas, such as nitrogen.
    Aging of Porous Media Samples The plurality of porous media samples 1 (for example, core plug samples) in an initial water saturation (S.) and an initial oil saturation (Si) is then aged (left to balance) at the desired experimental temperature, for example, the reservoir temperature and the desired experimental pressure.
    The aging process is applied for a period of time sufficient for the restoration of samples 1 to the wetting capacity conditions typically found in the reservoir.
    During the process of
    : aging, the oil is optionally replaced periodically with “fresh” oil, for example, 1 to 2 pore volumes of oil can be renewed weekly during the aging process.
    During this aging process, a proportion of the water that is initially in contact with the pore surface of the porous media (for example, the rock surface) is replaced by oil over time, which provides a more realistic representation of the capacity from moistening the porous media (for example, the rock) to subsequent steps in the experiment.
    For example, it will be appreciated that when samples 1 are 100% saturated with the aqueous phase (i.e., before any oil is added), the aqueous phase will occupy the entire pore volume of the samples. Considering a single pore, when the oil is initially present in sample 1 in Sw, The oil will generally have displaced the aqueous phase of the apparent region of the pore, so that the water remains in contact with the pore surfaces. During aging, oil and water will redistribute themselves in the pore, for example, so that a portion of the pore surface is contacted by the oil. Therefore, after aging, the pore will be in a state of mixed wetting capacity.
    The wetting capacity controls the distribution of fluid in a reservoir and therefore has a fundamental influence on the flow behavior, residual oil saturation and relative permeability. Therefore, the wetting capacity also has a fundamental influence on the performance of the reservoir.
    % The inventors in the present case have recognized that it is more desirable that the distribution of wetting capacity in each sample 1 of porous medium is representative of a reservoir. They further recognized that The aging process must be allowed to run its course, before the samples | be used in any subsequent flooding experiments. If aging has not been completed or is not substantially completed, then any predictions based on the results of these subsequent experiments may be prone to a higher degree of error, since the samples will not closely replicate the reservoir conditions.
    A complete or sufficient aging of the samples 1 can take an extended period of time, for example, sometimes on the order of several weeks or even months, in particular from three to six weeks.
    The valve element of porous media samples 1 can be monitored using NMR spectroscopy, as described in the UK copending patent application GB 1007694.1, in which case the supports 2 for samples 1 must be formed from a plastic material. Thus, the supports 2 containing the samples 1 of porous media are periodically closed and removed from the high production apparatus for offline NMR analysis.
    Thus, in the case of flood experiments, the fluids that are contained in the pore space of the porous media samples prior to the injection of the injection fluid are oil and water from the formation.
    Determination of Pore Volumes for Oil and Water Preferably, as part of the protocol of
    In preparation, additional tests can be carried out on each of the samples 1 of porous media to determine the pore volume accessible for water of each sample 1 in S, = 1 and the pore volume accessible for oil in Sw.
    This allows the recovery of oil in increments (in pore volumes) to be determined with respect to the injected volume of water (and converted into pore oil volumes). Thus, the volume of oil produced (ml) can be divided by the volume of oil pore and the volume of water injected (ml) is also divided by the volume of water pore.
    This allows oil production in increments for simultaneous flooding experiments to be directly compared.
    The pore volume accessible for water in S, = 1 can be obtained by injecting a brine comprising a tracker, typically iodine or lithium.
    The effluent removed from each sample 1 is then analyzed for iodine or lithium concentration, for example, using an inductively coupled plasma detector (ICP) or a densimeter, and the concentration profile (C / Coº) for the volume of injected brine is used to provide an estimate of the accessible pore volume of sample 1 for water (where C is the concentration of a tracker in the effluent and OQ is the concentration of tracker in the injection brine). A second measurement can be obtained by measuring the decline in the concentration of tracker in the effluent, when the injection fluid is switched to a brine that does not contain a tracker.
    Thus, the pore volume is the volume of brine injected when C / Coº is 0.5. The total pore volume can be approximated as the sum of the pore volume of water and the pore volume of oil.
    Therefore, the pore volume of
    7 oil = 1 - pore volume of water.
    s Alternatively, the accessible pore volume for oil in Si can be determined directly for each of the porous media samples 1 by injecting oil containing a tracker (typically an iododecane or an iododecane) into the cores. The effluent is analyzed for the concentration of the crawler and the concentration profile (C / Co) for the volume of oil injected is used to provide an estimate of the accessible pore volume for the oil in Si, in a similar way to the determination of the pore volume accessible to water (where C "º is the crawler concentration in the injected oil). A second measurement can be obtained by measuring the decline in the crawler concentration of the effluent, when the injection fluid is switched to oil not containing a tracker Simultaneous Flooding Experiments Simultaneous flooding experiments can be performed in tertiary mode for each of the samples 1 by injecting each sample 1 of an injection fluid, for example, brine of known composition (for example, a synthetic seawater or synthetic low-salinity water) at constant flow, until no oil is being produced from the core. saturation of residual oil, Sorn- The effluent produced from each core can be sampled for an offline analysis, or it can be analyzed using one or more of the online analytical instruments 7,
    11. The volume of oil produced is also determined. These are control floods for comparison with a subsequent core flood with various
    7 test injection, for example, various IS injection waters (tertiary flooding). At this point, the brine can be switched to a brine of similar composition that has been doped with a dopant, such as iodine or lithium. For example, a portion of the chloride ions in the original brine can be replaced with iodine ions or a portion of the sodium ions in the original brine can be replaced with lithium ions. The pore volume accessible to water from sample 1 of porous medium following this flood with initial water (secondary recovery) is then determined, as described above. Due to the fact that the brine has a composition similar to that of the brine used during a secondary recovery, no incremental oil recovery will be observed during this test. The saturation of residual oil after this control flood, Sori, can be determined from the pore volume of water following this initial water flood (that is, Som = (1 -— pore volume of water following- secondary recovery)). The amount of oil produced in this initial water flood in conjunction with the initial oil saturation value (S.i) can also be used to determine a value for Sor. Thus, Som = (Sounds - volume of oil pore produced during a secondary recovery).
    Test injection fluids having different compositions for the initial brine are then injected into samples 1 for a period of time sufficient to determine whether any incremental oil recovery is observed. If the oil is produced from one or more
    7 of samples 1, an injection of the FZ test injection fluid will continue until oil production ceases. The amount of oil in increment produced then is determined. At this stage, the accessible pore volume of the core for water can also be determined. At this stage, the accessible pore volume of the core for water can also be determined, as described above, by using a brine of a composition similar to that of the test aqueous injection fluid.
    If there was no incremental oil recovery with the test injection fluid, S.rº will be the same as Sor1- If there is an incremental oil recovery, a Serum value will be determined from the pore volume of water after tertiary recovery with the test injection fluid or from the amount of oil in increment produced during a tertiary recovery. Thus, Som = (1 - pore volume of water following a tertiary recovery) or Sora = (Sa - total pore volume of oil produced during a secondary and tertiary recovery) or Sora = (Sor1 - pore volume of oil produced during a tertiary recovery).
    The additional or incremental amount of oil that is obtained when different injection waters are injected into different samples 1 of porous media in a tertiary recovery mode is an amount in terms of, for example, a percentage, a fraction or a volume, of oil that will be displaced or recovered, compared to a predetermined volume of oil for a displacement (or recovery) volume of “base” oil, for
    % example, a flood with base water using a base injection water, such as a synthetic high salinity fluid. This base value is the amount of oil recovered in the effluent from the cores under standardized physical conditions, such as injection pressure, volume of base injection fluid used, and injection rate. Typically, the additional or incremental amount of oil is expressed as a percentage or a fraction of the predetermined base value.
    Alternatively, samples 1 can be tested in a secondary mode, by omitting the water flooding stage of the samples with the synthetic brine for Son. Instead, samples are directly flooded with the test injection fluid, for example, the test injection water. This will allow for coarse sorting of test injection fluids when determining whether an oil is produced from the cores or not.
    Typically, the injection fluid used for each of the simultaneous core flooding experiments (for example, an injection water) is injected into each core at a flow rate ranging from 1 to 40 ml / hour, preferably from 4 to 10 ml / hour, for example, 3 to 5 ml / hour, preferably around 4 ml / hour, in order to correspond to typical rates of frontal advance of the reservoir. Rates of frontal reservoir advance are dependent on the rate at which the injection fluid is injected into the injection well and the area in which the fluid is injected (a radius from the injection well and the reservoir interval through which the fluid is injected). A typical forward feed rate is around 1 foot (30.48 x cm) per day. All recovery varies with the 7 injection rate. Therefore, for comparative purposes, the injection rates for the plurality of experiments must be the same.
    Typically, after simultaneous water flood experiments have been completed, sample 1 of porous media, for example, core samples 1 are discarded or reused by returning to the cleaning protocol. As will be understood by the reader versed in the context of the present exposition, the duration of the described test flood experiments is typically in the order of days or tens of days, so that precise simultaneity is not required. Therefore, as used here, the term simultaneous is generally used to mean that tests are carried out concurrently or in parallel, for example, that “simultaneous” tests are in progress at the same time, although they may start and end at different times.
    Determination of Relative Permeabilities of Porous Media Samples for Oil and Water In addition to determining the oil recovery in increments for different EOR techniques, the apparatus of the present invention allows the simultaneous measurement of data required to determine the relative permeability of a plurality of samples 1 of porous media for oil and water. These measurements can be performed as part of simultaneous flooding experiments.
    Thus, the high production apparatus can also be used to obtain relative permeability data for samples 1 of porous media, in particular for
    * core plugs, these data being indicative of the Z] relative ease with which oil and water can move through the reservoir-forming rock, after considering viscosity, absolute permeability and pressure gradient in the reservoir.
    At the beginning of each core flood experiment, in S.i, the relative water permeability is zero (the water is immobile), while the relative oil permeability is at its maximum. At the end of each test flood experiment, in Sor, the relative oil permeability is zero (no more oil can be mobilized) and the relative water permeability is at its maximum.
    Methods for determining the relative permeability of a core to oil and water are well known to a person skilled in the art. These methods include permanent and non-permanent techniques. These methods require the measurement of the oil saturation profile (also referred to as the oil recovery profile over time) for the core and also the following “static” parameters: the fluid viscosities of the oil and the formation water , the porosity of the core rock and its total pore volume (absolute), the absolute permeability of the core rock to 100% oil or 100% water flowing through the core, the injection pressure, the differential pressure across the core , the core temperature, and the flow through the core. Measurements of these “static parameters” are therefore made.
    An online oil measurement equipment
    * conventional, for example, F gamma attenuation (GASM) monitoring equipment for determining core oil saturation is impractical for the high production apparatus due to the need for a plurality of gamma ray sources and the size of the GASM equipment.
    Instead, the oil saturation profile can be determined by monitoring the amount of oil being produced from the core over time. This amount of oil is converted into pore oil volumes, thereby providing core oil saturation (Soi - oil production in pore volumes) over time.
    In addition, for all core flooding experiments, differential pressure measurements are made over time. These measurements can be entered into the analytical component 211 to allow a determination of the relative permeability curves (where the analytical component 211 includes the additional "static" properties described previously that are required for the determination of the relative permeability curves).
    Therefore, one or more pressure sensors can be arranged with respect to each core sample 1 for measuring the absolute pressure of a fluid introduced into and extracted from each core, these or additional sensors being additionally arranged for the measurement of a differential pressure across the length of each core. Temperature sensors can also be provided for measurement and monitoring of core and flow line temperatures. Pumps arranged for the injection of fluid into the injection flow lines 12 can be controlled so that the flow of injected fluid and an injection fluid pressure are known.
    Typically, the permeability of core samples 1 (Ky ass) & The absolute pore volume of samples 1 are determined after core samples 1 have been cleaned.
    权利要求:
    Claims (15)
    [1]
    z CLAIMS 7 1. Apparatus for simultaneously injecting fluids into a plurality of porous media samples, characterized by the fact that it comprises: a plurality of supports for the porous media samples, each support comprising a glove and first and second plates, the first plate having an inlet for fluid injection and a second plate having an outlet for a fluid produced, and samples of porous media being arranged, in use, on each of the supports, so that the first plate and the second plate of each support contact a first end and a second end of the porous medium sample, respectively, the entrance of each first plate being in fluid communication with an injection line for injection of fluid in the porous medium sample disposed in the support, the exit of each second plate being in fluid communication with a dedicated effluent line for the removal of fluid produced from the sample of porous medium disposed in the suppor te, an analyzer for analysis of fluids injected and / or removed from each of the samples of porous media.
    [2]
    2. Apparatus, according to claim 1, characterized by the fact that it also comprises a coupled control system to receive measurement data from the analyzer and configured to control fluid injection based on the measurement data.
    [3]
    3, Apparatus according to claim 2, characterized by the fact that it comprises an operable fluid supply for controlling the fluid supply for
    7 injection into samples of porous media, wherein The control system is configured to control the fluid supply for at least one of said plurality of samples of a porous medium based on the measurement data.
    s
    [4]
    4. Apparatus according to claim 2 or 3, characterized in that the measurement data are based on the amount of oil in the fluid removed from the sample of porous medium disposed on the support.
    [5]
    5. Apparatus according to claim 4, characterized in that the controller is configured to stop the injection of fluid in one of said plurality of samples in case the amount of oil in the fluid removed from one of said samples is less than than a selected threshold level.
    [6]
    6. Apparatus, according to claim 5, characterized by the fact that the selected threshold level is one of: a selected concentration; a selected percentage by volume; and a percentage selected by mass of fluid.
    [7]
    7. Flood core test method for the injection of injection fluid into a plurality of porous media samples, the method characterized by the fact that it comprises: the arrangement of a plurality of porous media samples in respective pressure vessels of a corresponding plurality of them, in which the porous media samples comprise oil and water in an initial water saturation, due to the aging of the porous media samples so that the samples are in a state of mixed wetting capacity; : the injection of an injection fluid into each of the porous media samples, the removal of displaced fluid from the porous media samples, the analysis of displaced fluids from each of the porous media samples.
    [8]
    8. Method according to claim 7.7 characterized by the fact that the analysis comprises the determination of the amount of oil in a fluid displaced from one of the plurality of porous media samples. The method comprising the control of fluid injection based on in that determination.
    [9]
    9. Method according to claim 8, characterized in that the fluid injection control comprises the fluid injection stop in the event that the amount of oil in fluid displaced from one of the plurality of samples is less than than a selected threshold level.
    [10]
    Method according to claim 8 or 9, characterized in that it comprises, in response to said determination, the removal of one of the plurality of porous media samples from the pressure vessel and the replacement of said sample of the plurality of samples with another sample comprising oil and water in an initial water saturation, Sw.
    [11]
    Method according to any one of claims 7, 8, 9 or 10, characterized in that it comprises the injection of fluid in said plurality of samples for a selected period of time, in which at least
    at least two of the said samples are injected with fluid: having different properties; the end of the injection after the selected period of time has elapsed; based on said analysis, the selection of properties of a plurality of injection fluids; and injecting said plurality of injection fluids into a second plurality of samples.
    [12]
    Method according to any one of claims 7, 8, 9, 10 or 11, characterized in that it comprises, before the arrangement of the plurality of porous media samples in the corresponding plurality of vessels, the saturation of the plurality of samples of porous media porous media with water; and the displacement of water from the samples to obtain a selected level of water saturation, Su, of the samples; wherein said arrangement of a plurality of porous media samples in respective pressure vessels of a corresponding plurality of pressure vessels comprises transferring the plurality of samples at a selected level of water saturation to said corresponding plurality of pressure vessels ,
    [13]
    13. Method, according to claim 12, characterized by the fact that the displacement of water to obtain a selected level of water saturation, Swi, comprises one of: injection of a non-wetting phase in said samples; or centrifuging said samples under a non-wetting fluid.
    [14]
    14. Method according to any of claims 1, 2, 3, 4, 5, 6, 7.8, 9, 10, 11, 12 or 13, characterized by
    the fact that the simultaneous injection comprises the provision of a delay between the beginning of at least some of the injections.
    [15]
    15. Method implemented on a computer, characterized by the fact that it comprises the method of any of claims 7, 8, 9, 10, 11, 12, 13 or 14.
    类似技术:
    公开号 | 公开日 | 专利标题
    AU2016200753B2|2017-04-06|Apparatus and method for testing multiple samples
    US10167719B2|2019-01-01|Methods and systems for evaluation of rock permeability, porosity, and fluid composition
    US7581435B2|2009-09-01|Method and apparatus for acquiring physical properties of fluid samples at high temperatures and pressures
    US9416656B2|2016-08-16|Assessing reservoir connectivity in hydrocarbon reservoirs
    CA2789718A1|2013-03-16|Method and system for measurement of reservoir fluid properties
    US10570731B2|2020-02-25|Solvent extraction and analysis of formation fluids from formation solids at a well site
    Wan et al.2018|Pore-scale analysis of gas huff-n-puff enhanced oil recovery and waterflooding process
    Chen et al.2018|Applicability of simple asphaltene thermodynamics for asphaltene gradients in oilfield reservoirs: The Flory-Huggins-Zuo Equation of State with the Yen-Mullins model
    Ghanizadeh et al.2018|Controls on liquid hydrocarbon permeability of tight oil and liquid-rich gas reservoirs: Examples from Bakken and Montney formations |
    CN105683332B|2019-01-08|Density determination method and system
    Griffiths et al.2015|The Advantages of the Application of Automated Work Flows to Coreflood Testing: Introducing the Next Generation of BP's Advanced EOR Testing Capability
    Smith et al.2008|Sampling and Characterization of Rocks and Fluids for Heavy-Oil Reservoir Management
    AU2010363053B2|2015-05-14|Reconstructing dead oil
    US20210123344A1|2021-04-29|Core sampling and analysis using a sealed pressurized vessel
    Courel et al.2014|Identifying and Assessing Productivity in CO2 Bearing Gas Zones Using Wireline Logging and Testing Data
    Ozowe2021|Evaluation of lean and rich gas injection for improved oil recovery in hydraulically fractured reservoirs
    Partouche et al.2020|A Technology Update in Wireline Formation Testing
    Mohammad2012|PVT study of selected UAE reservoir fluids
    同族专利:
    公开号 | 公开日
    US9804062B2|2017-10-31|
    MX338084B|2016-04-01|
    CA2806460A1|2012-02-09|
    EA026873B1|2017-05-31|
    AU2011287419A1|2013-02-07|
    EP2601377A1|2013-06-12|
    AU2016200753B2|2017-04-06|
    CN107101922A|2017-08-29|
    EA201600496A1|2017-03-31|
    US20130125630A1|2013-05-23|
    MX2013001453A|2013-05-14|
    WO2012017197A1|2012-02-09|
    US20160109334A1|2016-04-21|
    CA2806460C|2018-06-12|
    US9261435B2|2016-02-16|
    EA034211B1|2020-01-17|
    EA201300212A1|2013-09-30|
    EA026873B9|2017-08-31|
    CN103270240B|2017-02-15|
    AU2011287419B2|2015-12-03|
    CN103270240A|2013-08-28|
    MX349608B|2017-08-03|
    AU2016200753A1|2016-02-25|
    引用文献:
    公开号 | 申请日 | 公开日 | 申请人 | 专利标题
    US3362473A|1965-06-28|1968-01-09|Mobil Oil Corp|Waterflood achieving high microscopic sweep efficiency|
    US3428127A|1966-12-28|1969-02-18|Union Oil Co|Method for increasing the recovery of oil from water-sensitive formations|
    US4586376A|1984-09-25|1986-05-06|Union Oil Company Of California|Determining the effect of fluid flow through permeable media|
    US4597442A|1985-02-26|1986-07-01|Shell Oil Company|Reservoir preflushing process for increasing the rate of surfactant transport in displacing oil with injected steam and steam-foaming surfactant|
    DE3608038C1|1986-03-11|1987-07-09|Klaus Burk|Mixing device|
    US5060727A|1990-01-02|1991-10-29|Alberta Oil Sands Technology And Research Authority|Method for improving enhanced recovery of oil using surfactant-stabilized foams|
    US5042580A|1990-07-11|1991-08-27|Mobil Oil Corporation|Oil recovery process for use in fractured reservoirs|
    US5161407A|1990-10-16|1992-11-10|Iowa State University Research Foundation, Inc.|Means and method of soil water desorption|
    US5133207A|1991-02-14|1992-07-28|Houston Industries Incorporated|Apparatus and method for simultaneously testing the permeability of multiple core specimens|
    US5493226A|1994-04-08|1996-02-20|Mobile Oil Corporation|Method and apparatus for measuring properties of core samples including heating and pressurizing the core sample and measuring the dynamic and static capillary pressure of water in the core sample|
    US5767399A|1996-03-25|1998-06-16|Dresser Industries, Inc.|Method of assaying compressive strength of rock|
    CN2319443Y|1998-01-15|1999-05-19|中国科学院沈阳应用生态研究所|Substance procedure analogue analytic device in soil etc. solid medium|
    RU2178515C1|2000-08-01|2002-01-20|Общество с ограниченной ответственностью "ЮганскНИПИнефть"|Method of determination of residual oil saturation|
    US6467544B1|2000-11-14|2002-10-22|Schlumberger Technology Corporation|Sample chamber with dead volume flushing|
    FR2836228B1|2002-02-21|2005-08-19|Inst Francais Du Petrole|METHOD AND DEVICE FOR EVALUATING PHYSICAL PARAMETERS OF AN UNDERGROUND DEPOSIT USING ROCK DEBRIS TAKEN FROM IT|
    US7997355B2|2004-07-22|2011-08-16|Pdti Holdings, Llc|Apparatus for injecting impactors into a fluid stream using a screw extruder|
    DE10336086A1|2003-08-06|2005-03-03|Hte Ag The High Throughput Experimentation Company|Device for carrying out catalytic tests|
    US20060175061A1|2005-08-30|2006-08-10|Crichlow Henry B|Method for Recovering Hydrocarbons from Subterranean Formations|
    CN2874021Y|2006-03-17|2007-02-28|大庆油田有限责任公司|Long pipe sand filling model for physical analogue test|
    US20070284107A1|2006-06-02|2007-12-13|Crichlow Henry B|Heavy Oil Recovery and Apparatus|
    US7805982B2|2007-03-06|2010-10-05|Saudi Arabian Oil Company|Portable core flood apparatus for conducting on-site permeability measurements|
    CN101458218B|2008-12-28|2011-02-02|大连理工大学|Carbon dioxide oil-displacing nmr imaging detection device|
    US8316933B2|2009-08-28|2012-11-27|Geo Fossil Fuels Llc|Microbial enhanced oil recovery methods|
    WO2011063023A2|2009-11-17|2011-05-26|Board Of Regents, The University Of Texas System|Determination of oil saturation in reservoir rock using paramagnetic nanoparticles and magnetic field|
    US9643127B2|2010-01-15|2017-05-09|Board Of Regents Of The University Of Texas System|Simultaneous removal of oil and gases from liquid sources using a hollow fiber membrane|
    US20120292022A1|2010-11-22|2012-11-22|E. I. Du Pont De Nemours And Company|Composition for improving oil recovery including n-lauroyl amino acid-based compounds and microbes|
    US9010441B2|2011-09-12|2015-04-21|Chevron U.S.A. Inc.|Systems and methods for reservoir production management|EP2261459A1|2009-06-03|2010-12-15|BP Exploration Operating Company Limited|Method and system for configuring crude oil displacement system|
    EP2801845B1|2009-12-16|2017-02-01|Bp Exploration Operating Company Limited|Method for measuring wettability|
    US20130298644A1|2012-05-14|2013-11-14|Chevron U.S.A. Inc.|Apparatus and Method For Measuring Viscosity of a Fluid|
    GB2506851B|2012-09-28|2014-11-12|Schlumberger Holdings|NMR sample containment|
    US9580640B1|2013-08-05|2017-02-28|Mark Patton|Process for using subterranean produced fluids for hydraulic fracturing with cross-linked gels while providing elimination or reduction of formation clay stabilizer chemicals|
    BR112016001685A2|2013-09-03|2017-08-01|Halliburton Energy Services Inc|methods and systems for evaluating rock permeability, porosity and fluid composition|
    US10161242B2|2014-03-28|2018-12-25|Halliburton Energy Services, Inc.|Column flow testing|
    US9903826B2|2014-09-17|2018-02-27|Saudi Arabian Oil Company|Multi-objective core-flood test system for oil recovery evaluation|
    US9678002B2|2014-10-29|2017-06-13|Chevron U.S.A. Inc.|Method and system for NIR spectroscopy of mixtures to evaluate composition of components of the mixtures|
    US9575047B2|2014-11-12|2017-02-21|Halliburton Energy Services, Inc.|Method of clay stabilization analysis|
    GB2545824B|2014-11-13|2021-01-20|Multi Chem Group Llc|Surfactant selection methods for wetting alteration in subterranean formations|
    US20160161629A1|2014-12-05|2016-06-09|Schlumberger Technology Corporation|Monitoring Carbon Dioxide Flooding Using Nuclear Magnetic ResonanceMeasurements|
    DE102015000263A1|2015-01-16|2016-07-21|Xylem Ip Management S.À.R.L.|Method for determining the UV transmittance of water|
    CN104612674B|2015-01-29|2017-06-06|中国石油大学|Simulation fractured-cavernous carbonate reservoir is handled up experimental provision and method|
    WO2017015014A1|2015-07-17|2017-01-26|Saudi Arabian Oil Company|Smart water flooding processes for increasing hydrocarbon recovery|
    US10429372B2|2015-07-17|2019-10-01|Saudi Arabian Oil Company|Smart water flooding processes for increasing hydrocarbon recovery|
    CN105221122B|2015-10-29|2018-08-17|中国石油大学|Simulate the visual experimental apparatus and method of fractured-cavernous carbonate reservoir gas injection|
    US10723937B2|2016-01-19|2020-07-28|Saudi Arabian Oil Company|Oil recovery process using an oil recovery composition of aqueous salt solution and dilute polymer for carbonate reservoirs|
    US10781362B2|2016-01-19|2020-09-22|Saudi Arabian Oil Company|Oil recovery process using an oil recovery composition of aqueous salt solution and dilute polymer for carbonate reservoirs|
    US10961831B2|2016-01-19|2021-03-30|Saudi Arabian Oil Company|Polymer flooding processes for viscous oil recovery in carbonate reservoirs|
    US10287486B2|2016-01-19|2019-05-14|Saudi Arabian Oil Company|Oil recovery process using an oil recovery composition of aqueous salt solution and dilute polymer for carbonate reservoirs|
    US10550312B2|2016-01-19|2020-02-04|Saudi Arabian Oil Company|Oil recovery process using an oil recovery composition of aqueous salt solution and dilute polymer for carbonate reservoirs|
    US10287485B2|2016-01-19|2019-05-14|Saudi Arabian Oil Company|Oil recovery process using an oil recovery composition of aqueous salt solution and dilute polymer for carbonate reservoirs|
    GB201604962D0|2016-03-23|2016-05-04|Bp Exploration Operating|Method to detect incremental oil production arising from a low salinity waterflood|
    CN107725016B|2016-08-11|2020-10-09|中国石油天然气股份有限公司|One-unit driving experimental device|
    CN107725015B|2016-08-11|2020-04-10|中国石油天然气股份有限公司|Binary drives experimental apparatus|
    US10443363B2|2016-10-31|2019-10-15|Exxonmobil Upstream Research Company|Method and system for core flood testing for reservoir souring studies|
    US10324077B2|2017-03-09|2019-06-18|Saudi Arabian Oil Company|Systems and methods for real-time spectrophotometric quantification of crude oil|
    CN108414416A|2018-01-29|2018-08-17|中国矿业大学|A kind of more sample infiltration coefficients test and comparison means and method|
    EP3561480A1|2018-04-25|2019-10-30|Total SA|Method for determining a relation between an initial saturation and a residual saturation in a first fluid in a porous sample and related assembly|
    US20210053048A1|2018-05-01|2021-02-25|Precision Planting Llc|Analytical cartridge for soil testing and related methods|
    EP3794337A2|2018-05-14|2021-03-24|Saudi Arabian Oil Company|System for performing microwave measurements of samples under confining pressure|
    US10845354B2|2018-05-21|2020-11-24|Newpark Drilling Fluids Llc|System for simulating in situ downhole drilling conditions and testing of core samples|
    CN109025958B|2018-06-25|2022-02-11|山东石大油田技术服务股份有限公司|Method, device and terminal for measuring produced liquid in oil field physical simulation oil displacement experiment process|
    RU2694869C1|2018-11-09|2019-07-17|Общество с ограниченной ответственностью "Корэтест сервис"|Laboratory study of core properties|
    WO2020154468A1|2019-01-25|2020-07-30|Ge Inspection Technologies, Lp|Flow network model analysis|
    RU193038U1|2019-04-29|2019-10-11|Акционерное Общество Триада-Холдинг|Device for determining the penetration of an injectable solution into a porous medium|
    CN110082272B|2019-04-30|2021-05-18|中国地质大学（北京）|Device and method for evaluating spontaneous imbibition of rock core under stratum condition|
    CN110174430A|2019-06-03|2019-08-27|西南石油大学|The measuring device and method of rock core imbibition simulated experiment under a kind of high-temperature and high-pressure conditions|
    CN110618106A|2019-08-12|2019-12-27|中国地质调查局西安地质调查中心|Chlorite mineral species identification method based on near-infrared reflectance spectrum|
    CN110905466A|2019-11-20|2020-03-24|浙江工业大学|Method for increasing yield and improving recovery ratio of biological nano-emulsion|
    US20210333188A1|2020-04-27|2021-10-28|Saudi Arabian Oil Company|Methods of determining cation exchange sites occuped by crude oil and the wettability of cation exchange sites in rock core samples in a preserved state|
    CN112322461B|2020-10-29|2021-10-01|河北地质大学|Experimental device for indoor simulation microorganism carbonate rock|
    法律状态:
    2020-09-01| B06U| Preliminary requirement: requests with searches performed by other patent offices: procedure suspended [chapter 6.21 patent gazette]|
    2020-12-15| B11B| Dismissal acc. art. 36, par 1 of ipl - no reply within 90 days to fullfil the necessary requirements|
    2021-11-23| B350| Update of information on the portal [chapter 15.35 patent gazette]|
    优先权:
    申请号 | 申请日 | 专利标题
    EP10251410.6|2010-08-06|
    EP10251410|2010-08-06|
    PCT/GB2011/001153|WO2012017197A1|2010-08-06|2011-07-29|Apparatus and method for testing multiple samples|
    [返回顶部]