method of comparing a secondary oil recovery process with a tertiary oil recovery process using NMR

专利摘要:
method for measuring rock wettability a method of comparing a secondary oil recovery process with a tertiary oil recovery process, the secondary oil recovery process and the tertiary oil recovery process being applied to a substantially fluid medium porous saturated containing an oil phase and an aqueous phase, the method comprising using measurements of the relaxation time in calculating a modification factor of the wettability index for the oil phase or the aqueous phase, thus comparing the recovery process of tertiary oil with the secondary oil recovery process.
公开号:BR112012014902B1
申请号:R112012014902
申请日:2010-11-19
公开日:2020-02-04
发明作者:Ralph Collins Ian；Chen Quan
申请人:Bp Explorartion Operating Company Ltd；
IPC主号:

专利说明:

METHOD OF COMPARISON OF A SECONDARY OIL RECOVERY PROCESS WITH A TERTIARY OIL RECOVERY PROCESS USING NMR SPECTROSCOPY, METHOD IMPLEMENTED IN NMR SPECTROSCOPY COMPUTER AND MRI SPECTROSCOPY SYSTEM
The present invention relates to the measurement of wettability. In particular, the present invention relates to the measurement of wettability characteristics and / or their variations in a porous medium having a fluid in it, for example, a mixed phase fluid comprising two or more phases, at least one of which is a liquid.
In the oil and gas industry, gaining an understanding of the wettability characteristics or wetting condition containing a hydrocarbon, forming a subsurface (a reservoir) can be particularly advantageous. For example, this understanding can help to optimize the development of the field, since wettability can have an effect on the calculation of the reserve and / or the dynamic behavior of a reservoir.
Wettability can be defined as the tendency of a fluid to spread over or adhere to a solid surface in the presence of other immiscible fluids.
Thus, for example, wettability can describe the relative preference of a rock to be covered by a certain phase, for example, water or oil. For example, a rock can be said to be water-wet if the rock has a much greater affinity for water than for oil. So, in the case of a porous water-wet rock containing phases of water and oil within its pores,
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2/96 substantially the entire internal pore surface would be covered with a layer of water. In this case, the water can be called the wetting phase.
Conversely, in the case of a porous oil-wet rock, substantially the entire internal surface of the pores would be covered with a layer of oil. In this case, the oil can be called the wetting phase.
Likewise, a porous rock of mixed wettability may contain some pores that are water-wet and some that are oil-wet. In addition, some regions of an individual pore can be water-wet, while others are oil-wet.
In practice, it will be appreciated that extreme water wetting or oil wetting is rare in reservoirs containing oil.
It should be appreciated, however, that for a two-phase fluid within a porous rock, the humidification phase will cover the most porous surface area and have a stronger affinity of the surface with the pore walls than with the pore phase. not humidification.
In fluid systems comprising a gas phase, for example, gas-liquid systems, it can safely be assumed that the gas is not the wetting phase.
The wettability of a porous rock will depend on the type of rock and will also be affected by any minerals present inside the pores. For example, clean sandstone or quartz can be extremely water-wet, while most rock formations of oil-containing reservoirs can typically be of mixed wettability. For a reservoir, the change in state wettability
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3/96 original wetting water for a mixed wetting state may have occurred after crude oil migrated to a reservoir trap and reduced the reservoir water saturation down to the saturation of conata water over geological time. The reservoir's wettability depends on the composition of the crude oil, the chemistry of the conata water, and the mineralogy of the rock surface, as well as the temperature, pressure and saturation history of the reservoir. The saturation distribution of the initial fluid in an oil formation is dependent on the balance between capillary forces and gravity forces on the reservoir scale and on the pore scale. The wetting state may vary according to pores and geometry of the pore throat. During the oil migration process, gravity is insufficient to overcome the large capillary pressure inside the micropores and, thus, the micropores typically remain completely of saturated conated water, thus retaining their original wet water state. While large pores are often invaded by oil, a film of water connects to the rocky surfaces of large pores usually remains. The change in wettability within the large pores depends on the stability of this water film. In extreme conditions, the water film can be stable and fully coat the surface area of the large pores thus maintaining the oily phase of having direct contact with the pore surface. Thus, over geological time, the large pores remain water-wet. Alternatively, the entire surface of the large pores can become coated by the oil phase such that the large pores are the
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4/96 oil-wet. Typically, the surfaces of the large pores are partially in contact with both the aqueous phase and the oil phase, and therefore have mixed wetting characteristics.
Traditionally, wettability has been characterized in the laboratory using also the Amott or US Bureau of Mines (USBM) indexes. However, the methods by which these indices are generally determined are invasive and time consuming. In addition, they cannot be easily transferred to the field.
It is known that nuclear magnetic resonance (NMR) techniques can be used to verify information in relation to fluids contained within a porous medium. Advantageously, using NMR techniques it offers a non-invasive means for determining in-situ fluid wettability in reservoir rocks, that is, the NMR measurement process does not interfere with the distribution of fluid within the pores of the rock. Thus, NMR techniques can be applied to monitor dynamic processes in progress including changes in wettability, such as aging and secondary or tertiary oil recovery processes.
Proton ( ¹ Ή) NMR techniques may be particularly well suited for studies of fluids containing water and hydrocarbon phases, for example, water and oil, within a porous medium.
NMR spectroscopy can be used to measure the spin-reticulated (longitudinal) relaxation time (Ti) and / or the spin-spin (transverse) relaxation time (T2) of the fluid. For example, proton NMR spectroscopy ( ¹ Ή)
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5/96 measures the relaxation time for protons within the fluid. From these measurements, it may be possible to elucidate certain information about the fluid and / or the porous medium.
For example, core samples can be taken for subsequent analysis using terrestrial NMR equipment.
Alternatively, NMR tools can be advantageously implemented at the bottom of the well. Such tools generally employ so-called low-field spectroscopy.
However, NMR measurement tools also suffer from some drawbacks. For example, they cannot be used in wells, or sections of them that are aligned with metal casing. In addition, current tools can usually only obtain information in the region close to the well, for example, typically within a radial distance of about 10 cm (4 inches) from the well. However, it is anticipated that future generations of NMR measurement tools may be able to obtain information related to other regions of the well.
Oil can be produced from a reservoir in a variety of phases, which can be classified as primary, secondary and tertiary phases.
In a primary stage in recovery of oil, The natural energy from reservoir is enough to to produce oil without any assistance. At the however, only fence in
15 percent of the original oil in place of a reservoir is recovered during primary recovery.
In some reservoirs, however, the pressure of the natural reservoir may not be sufficient to drive
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6/96 only the oil to a production well for the surface. Therefore, it may be necessary to artificially increase oil production. In this regard, it is known that the production of oil from a reservoir can be assisted by injecting immiscible fluids, such as water or gas, into the reservoir, in order to maintain the reservoir pressure, and / or to move the oil to a production well. Injecting such immiscible fluids usually produces about 20 to 40 percent of the original oil in place.
When the fluid is unchanged, typically seawater or other readily available water, this process can be classified as a secondary oil recovery process (alternatively a secondary process). In general, such a secondary oil recovery process can be referred to as a water flood or water flood.
Whenever the fluid is treated in any way to modify its properties, this process can be classified as a tertiary oil recovery process. For example, tertiary recovery processes may include flooding of low salinity water in which a source of water, such as seawater is treated to reduce its salinity before injection into the reservoir and the processes in which the fluid is being injected comprises one or more additives chosen especially, for example, chemicals and / or microbes. By appropriately modifying the injection fluid, tertiary oil recovery processes can be used to increase oil production at
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7/96 starting from and / or extending the production life of a reservoir. Typically, tertiary oil recovery processes can displace oil from a reservoir that is not displaced by secondary oil recovery processes. Tertiary recovery processes can usually be referred to as enhanced oil recovery (RMP) processes. The RMP techniques offer prospects for a total recovery of 30 to 60 percent, or more, of original oil in place.
During the life of production in a reservoir many different methods of recovery in oil can to be employees. Per example, initially, O reservoir can
be produced by a primary recovery method. However, after a while, the reservoir pressure may drop and it may become necessary to resort to secondary oil recovery processes. A secondary oil recovery period can be followed by one of the RMP processes, in order to maximize production from the reservoir. Naturally, the person skilled in the art will appreciate that other sequences are possible: for example, it may be the case that the reservoir is never produced in primary recovery because the natural pressure of the reservoir is not high enough, alternatively or additionally, a period of RMP can be applied only after primary recovery, with this RMP process being referred to as a secondary process in RMP mode. In contrast, an RMP process can be performed after the completion of a secondary oil recovery process, with this RMP process being referred to as an RMP mode tertiary process.
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It is a non-exclusive object of the present invention to provide an improved method for determining the wettability of a saturated porous fluid medium such as a reservoir rock having oil and the water phases present within its pores.
It is another non-exclusive object of the present invention to provide a method for determining changes in the wettability characteristics of a reservoir, especially before, during and / or after a secondary or tertiary oil recovery process.
According to a first aspect of the present invention there is provided a method of comparing a secondary oil recovery process with a tertiary oil recovery process, the secondary oil recovery process and the tertiary oil recovery process being applied to a substantially saturated fluid porous medium containing an oil phase and an aqueous phase, comprising the method:
(a) providing a first sample of the porous medium, the sample having a known initial volume of the oil phase within the pores thereof;
(b) measure a relaxation time for the fluid inside the first sample;
(c) submit to the first sample with the secondary oil recovery process;
(d) measure a relaxation time for the fluid remaining inside the first sample, after the secondary oil recovery process;
(e) providing a second sample of the porous medium, the second sample having within its pores a
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9/96 substantially known initial volume similar to that of the oil phase;
(f) measure a relaxation time for the fluid inside the second sample;
(g) submit to the second sample of the tertiary oil recovery process or, subsequent step (d) and without performing steps (e) and (f), subjecting the first sample to the tertiary oil recovery process;
(h) measure a relaxation time for the fluid remaining inside the second sample or first sample after the tertiary oil recovery process; and (i) use the relaxation time measurements in the calculation of a modification factor of the wettability index for the oily phase or the aqueous phase, thus comparing the tertiary oil recovery process with the secondary oil recovery process.
The method can be performed under ambient conditions, in the laboratory. Alternatively, the method can be performed under reservoir conditions or laboratory simulation.
The porous medium can be a rock, preferably a rock formation containing hydrocarbons (a reservoir rock) or a replica thereof. Typical reservoir rocks include sedimentary rocks, such as clastic sedimentary rocks and carbonates.
A or each sample of porous medium can be a buffer Taken from an sample in core. Preferably , where a plurality in tampons is used, earplugs can be
drilled in close proximity to the core sample and is therefore expected to have rock properties
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10/96 similar. Such plugs are referred to as sister plugs.
Alternatively, the or each sample may have been prepared artificially in the laboratory, for example, the or each sample may comprise a sand pack.
The aqueous phase may comprise brine, fresh water, brackish water or sea water. Preferably, the aqueous phase can be substantially similar in composition to a formation water associated with a reservoir. A suitable aqueous phase can be prepared in the laboratory. Thus, the
phase watery can understand a solution in brine, what can understand a water in formation or one water in synthetic formation. When the porous medium is a rock withdrawal from one
reservoir that is under primary recovery, the water formation can be conata water ie the original water in place in the formation. Conate water can contain a wide range of total dissolved solids (STD), for example, from about 100 ppm to 100000 ppm, say about 35000 ppm. Whenever the rock is removed from a reservoir that is under secondary recovery, the formation water may comprise a mixture of conate water and water that has been injected into the reservoir during secondary recovery, for example, sea water, water brackish, aquifer, surface water, such as rivers or lakes, or produced water. Typically, seawater can have an STD content in the region of 35000 ppm.
The oily phase may comprise live crude oil, stock tank oil (often called dead crude oil) and kerosene or other refined oils.
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The secondary oil recovery process may comprise a water flood experiment and / or an imbibition experiment. The water flood and / or the soaking experiment, can use a brine solution. Typically, the brine solution may comprise sea water, brackish water, aquifer water, surface water, produced water, conated water, training or laboratory water prepared from replicates thereof.
Tertiary oil recovery processes may include: a flood of low-salinity water; injection of a fluid containing one or more specially selected agents or additives, for example, microbes, chemicals, for example, polymers, alkalis or surfactants; or thermal methods, for example, hot water or steam injection, or in-situ combustion, or gas injection, for example, miscible / immiscible gases, such as carbon dioxide, hydrocarbon gas or nitrogen gas.
In a flood of low water salinity, an aqueous solution is injected into the porous medium, in which the aqueous solution has a selected total dissolved solids (STD) content and / or selected multivalent cations content. Typically, the selected STD content can be less than 10,000 ppm, preferably less than 8000 ppm, for example, in the range of 500 to 5000 ppm. Advantageously, the aqueous solution to be injected (the injection water) can be selected to have a lower multivalent cation content than the aqueous phase (the resident phase) that is contained in the porous medium. For example, the ratio between the content of multivalent cations in
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12/96
injection for O cation content multivalent gives phase resident is in preference of less than 0, 9, more preferably , less than 0.8, in particular, in any less
of 0.5.
When the tertiary oil recovery process comprises the injection of a fluid containing one or more specially selected agents or additives, the fluid may comprise an aqueous solution, in which the or each of the agents or additives may be present in a concentration of less from 10000 ppm, for example, in the range of 100 to 6000 ppm, preferably from 200 to 5000 ppm.
Suitable microbes can include bacilli, Clostridia, pseudomonas, hydrocarbon-degrading bacteria, and denitrifying bacteria.
Suitable chemicals can include polymers, surfactants, alkaline materials, or a combination thereof.
Preferably, relaxation time measurements can be made using NMR spectroscopy.
Preferably, the relaxation time can be a spin-spin (transverse) relaxation time (T2). Alternatively, the relaxation time can be a spin-reticulated (longitudinal) relaxation time (T1).
Preferably, the method may comprise the step of normalizing measurements by reference to measurements obtained from a porous sample, wherein the sample can be saturated with a single phase, for example, with water or oil.
Preferably, the method may comprise having reference or measurements of the calibration relaxation time for bulk samples of the aqueous phase and / or the oil phase.
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In a second aspect of the invention there is provided a method of assessing a change in the wettability of a formation containing porous and permeable hydrocarbons in the region around a well that penetrates the formation, the method comprising:
(i) locating an NMR measurement tool inside the well, at a depth corresponding to an interval of the formation containing hydrocarbons, (ii) measuring a relaxation time for the fluid located inside the formation containing hydrocarbons;
(iii) optionally, remove the NMR measurement tool from the well;
(iv) an injection of a secondary or tertiary recovery process fluid or an RMP process fluid for a period of time such that a known pore volume or fractional pore volume of the fluid is injected;
(v) optionally closing the well for a period of time;
(vi) return the well back to production and produce and, optionally, recover the injected fluids;
(vii) after the injected fluids have been produced, if necessary, the relocation of the NMR measurement tool inside the well at substantially the same depth as before, and (viii) measuring a relaxation time for the fluid located within the formation containing hydrocarbons.
(ix) optionally repeat steps number (iv) to (viii) with a recovery fluid different from that used
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14/96 in step (iv) originally.
Preferably, the method can be repeated one or more times to measure changes in the wettability characteristics of the formation, for example, before, during and / or after secondary and / or tertiary oil recovery processes.
Typically, the method of this second aspect of the present invention can be carried out in an injection well, a production well, a test well and / or a new drilled well.
Optionally, the method of this second aspect of the present invention can be combined with a single Tracer well test chemical, SWCT test which is designed to measure in-situ oil saturation (residual oil saturation) after the implemented secondary recovery, tertiary recovery, or RPM process.
When the method of this second aspect of the present invention is combined with a SWCTT, the method is modified using an aqueous fluid such as the injection fluid. The aqueous injection fluid is divided into a first (smaller) portion and a second (larger) portion. The first portion of the aqueous injection fluid is marked with a reactive chemical marker, for example, an ester such as ethyl acetate, which reacts with water during the cutting period to form a product tracer (for example, an alcohol such as ethanol) which is practically insoluble in the oil phase that is present in the formation pores. Optionally, both the first and second portions of the aqueous injection fluid are labeled with a non-reactive tracer, non-partitioning (material balance), for example,
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15/96 isopropanol. The amount of the second aqueous injection fluid portion that is used in step (iv) is typically sufficient to push the first aqueous injection fluid portion a radial distance of at least 1.524 m (5 feet), for example, between 1.524 4.572 m (5 to 15 feet) from the well. Closing the well in step (v) is essential in order to allow a (measurable) detectable amount of product marker to form. Typically, the well is closed over a period of one to ten days.
Typically, the conversion from the reactive tracer to the product tracer (e.g., conversion from ester to alcohol) is 10 to 50%. Then, the closing period, the well is produced back and the fluid produced is periodically sampled and immediately analyzed for the unreacted ester tracer content (eg ethyl acetate), the alcohol product tracer (eg , ethanol) and the optional material balance plotter (for example, isopropanol). At the start of the return to production step (vi), the unreacted ester tracer and the alcohol product tracer are superimposed at the location that is at least a radial distance of at least 1.524 m (5 feet) from the well. Partitioning of the unreacted ester tracer between the immobile residual oil phase and the mobile aqueous phase delays the production of the ester by an increase in volume directly related to the residual oil saturation. The alcohol product tracer, however, is not delayed, and flows back into the well at almost the same rate as water. Since alcohol does not spend time in the stationary oil phase, which is produced earlier than the unreacted ester tracer (for example, acetate)
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16/96 ethyl), resulting in a separation between the peak concentrations of the alcohol product tracer and unreacted ester tracers. The saturation of the residual oil is then calculated using the amount of separation between the ester tracer and the alcohol product tracer. Thus, the SWCT test results for formations with high residual oil saturations show a large separation between the alcohol product tracer and the reactive ester tracer while the test results for formations having low residual oil saturations show a small separation between the alcohol product tracer and the reactive ester tracer. The optional material balance tracer allows for the interpretation of test results in case the entire ester tracer reacts, or if some of the ester is extracted from the aqueous fluid produced by gas leaving the fluid or by gas used during operations gas lift. The change in the wettability index determined using the relaxation time measurements determined in step (viii) can be correlated with the residual oil saturation, as determined during the SWCT test.
SWCT tests are described in more detail, for example, Deans, HA, and Carlisle, CT: Single-Well Tracer Tests in Complex Pore Systems, paper SPE / DOE 14886, presented at the Fifth Symposium on RMP in Tulsa, April 20_23, 1986 ).
In a third aspect of the invention there is provided a method of evaluating a change in the wettability of a formation containing porous and permeable hydrocarbons in the region around a new well that penetrates the formation, the
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17/96 change being due, at least in part, to the entry of drilling mud into the formation, the method comprising:
(i) locate a pre-existing well penetrating the formation containing hydrocarbons or a similar formation;
(ii) locate an NMR measurement tool inside the pre-existing well, at a corresponding depth with a portion of the formation containing hydrocarbons;
(iii) measure a relaxation time for the fluid located within the region of the nearby well around the pre-existing well;
(iv) drill a new well to a new location removed from the pre-existing well, in which the new well enters the formation containing hydrocarbons;
(v) locate an NMR measurement tool inside the new well, at a corresponding depth with a portion of the formation containing hydrocarbons;
(vi) measure a relaxation time for the fluid located within the region of the nearby well around the new well; and (vii) to compare the relaxation time measurements of steps (iii) and (vi) to assess the change in fluid wettability in the region near the well around the new well, the change being due, at least in part, to the entry of drilling mud into the formation during the drilling of the new well.
The NMR well measurement tool can be a fixed network or recording tool during
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18/96 drilling.
Typically, the pre-existing well is a hydrocarbon production well that has been placed over production in such a way that hydrocarbon fluids are present in the region close to the well.
A plurality of new wells can be drilled, each using drilling muds, for example, based on oil drilling muds, having different compositions, for example, containing surfactants and / or other additives, in order to compare the effect drilling muds in the formation wettability.
Once sufficient field data has been obtained, it may be possible to select a more suitable drilling mud for each new well subsequently drilled.
In a fourth aspect of the invention there is provided a method of tracking the aging of a sample of a porous saturated fluid medium, wherein the fluid is located within the pore structure of the porous medium and the fluid comprises at least two immiscible components or phases, at least one of which is a liquid, comprising the method:
(i) taking a first measurement of a relaxation time distribution of the fluid within the porous medium;
(ii) taking a second measurement of the distribution of the time of relaxation of the fluid within the porous medium, after a time interval;
(iii) take one or more other measurements of the distribution of the fluid relaxation time within the porous medium at subsequent intervals of time until the
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19/96 distribution of relaxation time is substantially unchanged from one measurement to the next, indicating that the sample is aged completely or at least to an acceptable extent.
Preferably, the two components or phases can comprise an aqueous phase and an oil phase.
The porous medium sample can be a core sample, for example, taken from a rock such as a reservoir rock or the like. Alternatively, it can be a sand pack or similar, which has been specially prepared, typically in a laboratory.
Relaxation time measurements can be taken at regular or irregular intervals over a period of time. The number, frequency and regularity of measurements that are taken, as well as the period during which they are taken can depend on a large number of factors, including the nature of the porous medium and the composition of the fluid. For example, relaxation time measurements can be made once a day or once every few days.
Preferably, the relaxation time can be measured using an NMR spectrometer.
Preferably, the relaxation time can be a transverse relaxation time (spin-spin).
After aging, the sample of porous medium can be used in further tests or experiments.
According to another aspect of the present invention, a method of determining the wettability distribution characteristics is provided in both pore and field scales of a reservoir, that is, wettability is
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20/96 determined as functions of both the pore size and the height above a free water level in a reservoir.
In a further aspect of the invention, a computer-implemented method for determining wettability characteristics of a fluid-containing porous medium is provided, the method comprising the steps of:
receiving measurement data indicative of a time of relaxation of the fluid present in the porous medium to a defined fluid saturation;
receiving reference data indicative of one or more reference relaxation times of the fluid, and calculating a wettability index, based on differences between the received measurement data and the received reference data, said wettability index being indicative of the wettability characteristics of the porous medium in the defined fluid saturation.
The method may further comprise receiving a plurality of measurement data, each of which is indicative of a fluid relaxation time present in the porous medium:
i) at different points in time;
ii) at different locations in the porous medium, or iii) at different stages before, after and / or during at least one of a primary, secondary or tertiary fluid recovery process;
calculation of the wettability index for each of the plurality of measurement data, respectively, and calculation based on a comparison of the calculated wettability indices, a modification factor of the wettability index indicative of a change in
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21/96 wettability characteristics of the porous medium.
The method for determining the wettability characteristics defined above decouples certain factors (such as microscopic fluid saturation and distribution, pore structure, rock mineralogy, and distribution of paramagnetic impurities on the pore surface, as well as the composition of the oil crude) of a NMR relaxation time distribution, and includes both surface coverage and surface affinity factors for the wettability index and the wettability index modification factor.
This method can also evaluate the surface coverage and surface affinity contribution to wettability separately.
Advantageously, the wettability index modification factor can be used to assess the change in wettability of improved oil recovery processes by comparing the surface coverage and surface affinity of a secondary oil recovery process with that of a tertiary oil recovery process.
The method may also comprise the step of receiving parameter data indicative of parameters related to the pore size, the capillarity pressure, the saturation of the fluid in the porous medium and / or the height above the level of free water in the porous medium, in order to to calculate the wettability index as a function of the parameters.
The different locations in the porous medium mentioned above may be related to the first and second wells that are willing to penetrate the porous medium, the
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22/96 modification of the calculated wettability index is indicative of a change between the wettability characteristics of the porous medium with the first and second wells.
The fluid present in the porous medium can comprise at least two components of immiscible fluids or phases, and the wettability index can be calculated by at least one of said fluid components or phases.
The reference data can comprise one or more relaxation time measurements made on:
i) a sample of the porous medium that is saturated with a single aqueous phase;
ii) a sample of the porous medium that is saturated with a single oil phase; and / or iii) bulk samples of an aqueous phase and / or an oil phase corresponding to that of the porous medium.
A mixed wettability NMR signature after the flood water was identified in the application of the method for determining the wettability characteristics defined above. This signature is characterized by the peak relaxation time value (T2) o after a flood of water is greater than any relaxation time component (T2) of the crude bulk oil and a core buffer completely saturated with water, but less than the bulk water relaxation time. This mixed wetting NMR signature can be used to identify mixed wetting characteristics in a porous medium comprising multiple fluid components or phases.
The method may also comprise normalizing the data
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23/96 measurement based on reference data.
Measurements of relaxation time can be spin-spin measurements of relaxation time (transverse) made using NMR spectroscopy.
The porous medium can comprise a reservoir rock formation, a sample of it or a replica of it.
In accordance with the above aspect of the invention, it also provides a system for determining the wettability characteristics of a fluid-containing medium, the system comprising:
data receiving means arranged to receive measurement data indicative of a fluid relaxation time present in the porous medium to a defined fluid saturation;
means of receiving data arranged to receive reference data indicative of one or more reference fluid relaxation times, and means of computer-implemented programs arranged to calculate a wettability index, based on differences between the received measurement data and the reference data received, said wettability index being indicative of the wettability characteristics of the porous medium in the defined fluid saturation.
The system can also comprise:
data receiving means arranged to receive a plurality of measurement data, each of which is indicative of a fluid relaxation time present in the porous medium:
i) at different points in time;
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Ii) at different locations in the porous medium, or iii) at different stages before, after and / or during at least one of a primary, secondary or tertiary fluid recovery process;
means of computer implemented programs arranged to calculate the wettability index for each of the plurality of measurement data, respectively, and means of implemented computer programs arranged to calculate, based on a comparison of the calculated wettability indices, a modification factor wettability index indicating a change in the wettability characteristics of the porous medium.
In order that the invention may be more fully understood, it will now be described by way of example only and with reference to the accompanying drawings in which:
Figure 1-1 shows the relaxation time distributions T2 of core plugs No. 156 and No. 157 of 100% water saturation.
Figure 1-2 shows the initial water saturation distribution (SAI) as a function of pore size (r) at different capillary pressures, calculated using a cylindrical pore throat and spherical pore body model.
Figure 1-3 shows the initial water saturation distribution (SAI) as a function of the relaxation time at different capillary pressures, calculated using a cylindrical pore throat and spherical pore body model.
Figure 1-4 shows the distribution of water volume
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25/96 as a function of pore size (r) with 100% water saturation (SA = 1) and initial water saturation (SAI = 0.2) for No. 156 core buffer, at a pressure of 182 psi (1.25 MPa) capillarity, calculated using a
throat pore cylindrical and model in body pore spherical . THE figure 1-5 shows the distribution of volume initial of Oil as a size function of pore (r) with
initial oil saturation (SOI = 0.2) for No. 156 core buffer, at a capillary pressure of 182 psi (1.25 MPa), calculated using a cylindrical pore throat and spherical pore body model.
Figure 1-6 shows the distribution of water volume as a function of pore size (r) with 100% water saturation (SA = 1) and initial water saturation (SAI = 0.2) for core No. 157, at a capillary pressure of 182 psi (1.25 MPa), calculated using a
throat pore cylindrical and model in body pore spherical . THE figure 1-7 shows the distribution of volume initial of Oil as a size function of pore (r) with
initial oil saturation (SOI = 0.2) for No. 157 core buffer, at a capillarity pressure of 182 psi (1.25 MPa), calculated using a cylindrical pore throat and spherical pore body model.
Figure 1-8 shows the initial oil saturation as a function of pore size (r) to one of 182 psi (1.25 MPa) capillarity corresponding to an initial total oil saturation of 0.8 for n sibling buffers 156 and 157, calculated using a cylindrical pore throat and
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26/96 spherical pore body model.
Figure 1-9 shows at distributions of time in T2 relaxation for an oil in bulk and for one core buffer (No. 156) in conditions of saturation in different fluids. Figure 1-10 shows at distributions of time in T2 relaxation for an oil in bulk and for one core plug No. 157, in conditions of saturation in different fluids; Figure 1-11 shows O wettability index gives oily phase as a function of pore size (r) after saturation aging in initial oil to a pressure 182 psi capillarity (1 , 25 MPa) for the buffer in core to No. 156. Figure 1-12 shows O wettability index gives
oily phase as a function of pore size (r) after aging in the initial oil saturation at a capillarity pressure of 182 psi (1.25 MPa) for core plug No. 157.
Figure 2-1 shows the T2 relaxation time distributions of twin core plugs after flooding with three different salinity brines.
Figure 3-1 shows initial water saturation (SAI) as a function of the relaxation time T2 for ROMM core plugs at a capillary pressure of 100 psi (0.69 MPa).
Figure 3-2 shows initial water saturation (SAI) as a function of the pore-body radius (r) for ROMM core plugs at a capillary pressure of 100 psi (0.69 MPa).
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Figure 3-3 shows the distribution of water volume as a function of the pore-body radius (r) under conditions of 100% saturated water (SA = 1) and in the initial water saturation (SAI = 0.28).
Figure 3-4 shows relaxation time distributions T2 for a crude bulk oil and for core buffers under different fluid saturation conditions for a ROMM core buffer experiment.
Figure 4-1 shows an experimental installation for a first sand pack sample subjected to brine soaking next to a second sand pack sample in microbial enhanced oil recovery (ROMM);
Figure 4-2 shows T2 distributions of brine soaking experiments conducted in the first sand pack;
Figure 4-3 shows T2 distributions for ROMM experiments conducted on the second sand pack;
Figure 4-4 is a graph comparing T2 distributions for the first sand pack after soaking in brine and the second sand pack after ROMM;
Figure 4-5 is a graph showing oil recovery over time from the first sand pack and the second sand pack;
Figure 4-6 shows the T2 distributions for a pack of 100% saturated brine sand, a pack of 100% saturated inoculum sand, and a pack of saturated inoculum sand after aging for six days.
A pore of saturated fluid within a rock can be divided into two regions, namely, a region of
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28/96 surface and a region in volume. The surface region comprises a relatively thin layer, for example, with a thickness of no more than a few molecules, on the internal surface of the pore. The volume region comprises the remainder of the internal pore volume.
It has been found that, typically, the relaxation time for a molecule in the surface region is considerably less than for a molecule within the region in volume. Without wishing to be limited by any theory, this may be due to the effect on molecules within the surface region of paramagnetic centers within the pore walls. In the case of ( ¹ Ή) proton NMR spectroscopy ( ¹ Ή), which may also be due in part to the reduced speed of rotation of the hydrogen protons on the rock surface.
In porous reservoir rocks, the pores are typically smaller than about 100 pm in diameter. Therefore, the volume region may occupy a relatively small proportion of an individual pore.
The spin-spin relaxation time for a fluid in a pore can be affected by contributions from three relaxation mechanisms: (i) relaxation of the fluid in the volume region; (ii) relaxation of the fluid in the surface region, and (iii) due to the self diffusion of relaxation of the fluid in the gradient of the applied magnetic field. Generally, it can be difficult to separate the relative contributions of the three mechanisms, particularly when the fluid contains more than one phase, for example, an aqueous phase and an oil phase.
For a saturated fluid medium in the event that the
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29/96 low field NMR spectroscopy with a short echo time is used, for example, as it can typically be used in oil field NMR measurement, it can be assumed that the contribution to the spinspin relaxation time due to self diffusion can be negligible, since molecular diffusion in internal magnetic field gradients can be negligible.
Thus, for a porous medium of saturated water 100% (in SA = 1), the inverse of the spin-spin relaxation time (T ₂ ) of the aqueous phase in a pore at the fast diffusion limit can be expressed as:
t ^A vt ⁱ 2, A1 ^{κ 1} ΐ /, Ά
In equation (1), T ₂ , ai is the spin-spin relaxation time of totally saturated water rock p ₂ , A is the spin-spin relaxivity of the aqueous phase, T ₂ v, a is the spinspin relaxation time in volume of the aqueous phase, A is the surface area of the pores within the porous medium and V is the volume of pores.
The aqueous phase typically comprises conate water, formation water, or the like.
In the case of a porous rock with 100% saturated water, Equation (1) can often be approximated by neglecting the term volume relaxation. This can be done, since the water relaxation time inside the porous rock of a reservoir is much shorter than the mass water relaxation time. Therefore:
THE
Aa.
(2)
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30/96
The V / A ratio can be used to measure pore size using the following equation:
wavy and geometric, which depends on the shape of the pores and is equal to
1, 2 and for the flat pores or fractures, cylindrical pores, and spherical pores, respectively, and it is half the opening of the pore for flat pores or fractures and is the radius of the pore body for cylindrical or spherical pores.
For a body pore and a pore-throat model of a throat in a porous medium, a body-to-pore ratio (RGP) can be defined as:
RGP
R that r is the radius of a pore body that is connected to another pore body by a pore throat with a radius of
R.
RGP can be determined, for example, by comparing the pore throat size distribution determined through mercury injection experiments and pore body size distribution determined by NMR DDCI (decline due to diffusion in the inner field) or by analysis of thin sections of rock samples using electron microscopy.
The CPMG NMR (Carr-Purcell-MeiboomGill) pulse sequence is the most common method for measuring relaxation time T ₂ . The pulse sequence consists of a 90 ° pulse followed by a series of 180 ° m pulses to generate an echo after each 180 ° pulse, which makes a train of m echoes as a result (where m is an integer) . O
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31/96 time interval between adjacent pulses of 180 ° is the echo time, TE.
For a simple fluid in volume such as water, the amplitude of the echo decays as a single exponential function of the echo time as determined by
M (mTE) = M (0) exp (-mTE / T ₂ v, A) where M (mTE) is the transverse magnetization, and M (0) is the signal amplitude that corresponds to the initial transverse magnetization.
A fluid (e.g., water) having a porous medium is typically composed of a wide distribution of pore sizes. Therefore, the total NMR signal is the sum of the fluid signals within all individual pores of the porous medium. It can be expressed as a multi-exponential decay in a transverse magnetization CPMG measurement:
where A, is the signal amplitude of the nth component with the characteristic relaxation time T2, i.
An inverse Laplace transform of data following equation (6) will produce the relaxation time distribution T ₂ . In a fast diffusion limit and in a weak diffusion coupling regime, the T ₂ distribution can be linearly converted to a pore size distribution by Equation (3).
The sum of signal amplitude (Ai) of all components (n) is equal to the signal amplitude of the initial transverse magnetization as indicated in Equation (7):
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32/96 (7) i-l
The amplitude of the signal (Ai) is directly proportional to the fraction of the pore volume of the nth component with the relaxation time of T2j.
A core analysis process usually begins with cleaning the reservoir core plugs with solvent to a strongly water-wet state. During a primary drainage process (to mimic the migration of crude oil) such as a capillary drainage pressure experiment in a laboratory, a core plug initially entirely of saturated water is desaturated by air or oil using a porous plate or centrifugation techniques. For example, when using the porous plate technique with nitrogen gas displacement air or water, after a displacement pressure has been applied and the pressure has been balanced to fix the capillary pressure (Pc), the water saturation The remainder can be determined by measuring the amount of water produced from the core plug. If the applied pressure exceeds the limit pressure of a given pore, air or nitrogen gas will invade the pore and occupy the center of the pore with the remaining water coating on the pore surface as a layer. The pores will remain fully saturated with water, if the applied pressure does not exceed the limit pore pressures. According to the Young-Laplace equation for the water-air or water-nitrogen system with zero contact angle, the relationship between capillary pressure (P _c ) and a limit radius of the cylindrical pore throat (Rt), which remains fully saturated with water is given by
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33/96 where σ is the interfacial tension or surface tension that is 72 mN / m, for the air-water system.
In a reservoir containing oil, the first drainage capillary pressure curve regulates the initial water and oil saturation above the oil-water contact. During the oil migration process, the capillarity pressure is balanced by gravitational forces resulting from the difference in density between water and oil in the
balance. Per therefore, the distribution of fluid like a function gives height above water level free (H) is: Pc = (Pan - Po) gH(9) Where Praça is the pressure of capillarity, Pa and _o are the
densities of the aqueous phase and oil phase in a reservoir, respectively, g is the gravitational acceleration, and H is the height above the level of free water in the reservoir.
According to Equations (4) and (3), at the capillary limit pressure, the corresponding maximum of fully saturated water of the pore body radius (rt) and the spin-spin relaxation time T ₂ , t limit of the aqueous phase are related to the limit radius of the pore throat (Ri) by ^ ^RGP (10)
T (II) * P _íh A
During desaturation of an aqueous phase from a non-wetting phase (gas or oil), the pore bodies will remain fully saturated with water, if the applied pressure does not exceed the limit capillary pressures of the pore bodies. If the applied pressure exceeds the pressure of
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34/96 limit capillarity of a determined pore body, the non-wetting phase will invade the pore body through a connected pore throat and will occupy the center of the pore body with the remaining aqueous phase forming a coating on the surface of the pore pore wall. At the limit capillary pressure, it is assumed that the thickness of the layer of the aqueous phase that remains in the non-wetting phase (air or oil) has invaded pore bodies is equal to the radius of the limit pore throat of Rt. To calculate the saturation of initial water during the desaturation processes, the pore body and pore throat model also assumes that the volume of pore throats is negligible compared to the volume of the pore bodies.
Therefore, during a desaturation process the initial water saturation, Saí, as a function of the pore body radius (r), the capillarity pressure (P _c ) and pore shape factor (k) can be determined by :
(12a) ^{= 1} “I ~~ ----— or Exit = 1 if r <r _t .
where, as discussed above, k is equal to 1, 2 and 3 for the flat pores or fractures, cylindrical pores, and spherical pores, respectively. The physical boundary condition of Exit is 0 <Exit <1.
For a two-phase system with water and oil, the initial oil saturation (Soi), as a function of the pore body radius (r), the capillarity pressure (P _c ), and the pore shape factor (k ) can be determined by:
= fif _r >rt; S _i = 0ifr <r _t. ^(12b) ί )
Substituting equations (3) and (11) in equation (12a) gives
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35/96 the initial water saturation, I left, as a function of spin-spin relaxation time, T2, there, capillarity pressure (P _c ) and pore shape factor (k), for bodies of water pores completely saturated:
^ (η.ΑΐΛ, υ = ιTj.Ai tfTj, Ai>Ta;í> r S _A1 -] ifTj ^ Tst
For a two-phase system with water and oil, the initial oil saturation,
So, as a function of the spin-spin relaxation time, the capillarity pressure (P _c ) and pore shape factor (k) can be determined by
S _Q f = O if T _3rA] <Tit (13b)
As an example, for a spherically shaped pore model, where k = 3, equations (12a), (12b), (13a) and (13b) can be simplified as equations (14a), (14b), (15a ) and (15b), respectively:
íf r> r _t ;
or S Ai — 1 if r <r _t .
(14a)
if r> r _t ;
or Soí -0 if r <r _v (14b) ⁵ αΛΛα ₍ ) = Η ífT>T2t; orSAi “l ifT2 <T2t. (15a) ^fll l · ⁷ - ^{! Rj} - ifTj. _THE! > T _It ; or S _Oi -Q if T _2jA] <T ₂₁ ^(15b) l ^J 2. _A ]]
Thus, equations (14a) and (15a) can be used
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36/96 to determine initial water saturation as a function of pore size and, if desired, as a function of relaxation time T2, at a plurality of different capillary pressure (for example, at seven different capillary pressures) , as shown in figures 1-2 and 1-3, respectively.
Alternatively, the porous medium can be modeled as regular polygonal tubes when analyzing the initial water saturation distribution at the pore scale and its relationship to the relaxation time distribution T2 during the primary drainage process.
When applying equation (2) to regular N-sided polygonal tubes (where N is an integer, for example 3, 4, 5 or 6), we found that the relaxation time distribution T2 of a regular polygonal tube of water fully saturated is directly proportional to the apotheme (L) of the regular polygons if we ignore the relaxation in volume and the relaxation diffusion components of T2:
t _ b (16)
The porous rocks are initially of fully saturated water and strongly wetting water with a contact angle of zero. When the porous medium is modeled as regular polygonal tubes, the capillary pressure limit, Pci, is given by:
where Léo apótema of the regular polygon of n sides.
For the model that employs regular polygonal tubes,
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37/96 during a primary drainage process, a given pipe can be invaded by a non-wetting phase (for example, oil or air), if the applied pressure only exceeds the limit capillary pressure defined in equation (17). Therefore, the non-wetting phase occupies the center of the pore like a cylinder with the radius of L.
As the applied pressure increases further, more and more water is displaced by the non-wetting phase. Consequently, remaining water resides in the corners of the pore space and as a thin film coating of water on the pore walls. All smaller pores, whose limit pressures are greater than the applied pressure cannot be invaded by the non-wetting phase and remain with completely saturated water, for example:
Out = 1 for Pc <P (| (18)
In the pores of regular polygonal tubes that have been invaded by the non-wetting phase, the radius of curvature (R _c ) of the water remaining in the corners of the pore space is related to the capillary pressure (P _c ) by
R, · = - (19)
For pores invaded by the non-wetting phase of regular N-sided polygonal tubes, the volume of the thin coating of the water film on the surface of the pore walls can be ignored. Therefore, the initial water saturation, Saí, as a function of the relaxation time Τ ₂ , Αί, the capillarity pressure (P _c ) and N can be determined using the following equation:
λ π jVtanO / N) j for Ρ _ρ > Ρ «ι, or Sai = 1 for PtSPci
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38/96 (20a)
Likewise, the initial water saturation, I left, as a function of the pore size the capillary pressure can be determined using the following equation:
S ^ L, F _Ci N) =
Alaní ^ / Ã) J for Ρ _Ε > ΡΛ or S _A1 = 1 for P _c <P _d ^(20b) where, as discussed above, Léo apótema and N is the number of sides of the regular N-sided polygonal tubes.
For a two-phase system with water and oil, the initial oil saturation, Soi, as a function of the spin-spin relaxation time in 100% water saturation (T2, there), the capillarity pressure (P _c ) and N can be determined by
for P _c > P _ub or Sqj ^ O for P _c <P ₀ | (20c)
Likewise, for a two-phase system with water and oil, the initial oil saturation, Soi, as a function of pore size (L), capillary pressure (P _c ) and N can be determined by
go
N (an (^ / 7V) (20d) for P _€ > P «|, or Süí'0 tor P _ç <P _C |
Substituting equation (9) into equations (12a), (12b), (13a), (13b), (20a), (20b), (20c), and (20d) gives initial fluid saturation distributions as a function the height above the level of free water (H) in reservoirs containing hydrocarbons.
The initial saturation of total water (Exit) can be determined from the function of the initial water saturation (Exit (r, P _c )) with respect to the pore size (r), the pressure
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39/96 capillarity (P _c ), and the pore size distribution function Ai (r) by
Sk ⁽²¹⁾
It is observed that, when modeling the porous medium with regular polygonal tubes, r can be replaced by L in equation 21.
Likewise, the total initial water saturation (Saí) can be determined by the initial saturation water function (SAí (r, P _c )) with respect to the spin-spin relaxation time (T ₂ ), capillarity pressure ( P _c ), and spin-spin relaxation time distribution function (T ₂ ), Ai (T ₂ ) by
4, -2 ^ (4-4:) 4 (4) ⁽²²⁾ f = l
Similar to equation (1), for a porous medium of 100% saturated oil, the inverse of the spin-spin relaxation time (T ₂ ) of the oil phase in a pore at the fast diffusion limit can be expressed as :
k. _ „I ¹ (23) m prκττ ^J 3, OL
In equation (23), T ₂ , o is the spinspin relaxation time of fully oil-saturated rock, p ₂ , o is the spin-spin relaxivity of the oil phase, T ₂ b, o is the spin-spin relaxation time in volume of the oil phase, A is the surface area of the pores within the porous medium and V is the volume of pores.
For large pores of 100% saturated oil in a porous medium, the inverse of the spin-spin relaxation time (Tb.oí.l) of the oil phase in the large pores at the limit of
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40/96 rapid diffusion can be expressed as:
_ „Λ, ¹ (24)
7 '~ ^ ² · ^υ y ⁺ τ ^{L ΐ3} · ^ΰ _J is the surface area of the large pores within the porous medium and Vl is the volume of the large pores.
Models of initial water and oil saturation and its limit capillarity pressure (Pci), limit pore-body radius (ri) and limit throat pore radius (Ri), as well as spin-spin relaxation time (T ₂ , i) limits developed in the present invention can be used for the distribution of pore size partition in small pores with the initial water saturation of 100% and larger pores that are initially saturated with water and oil. The cutting pore radius (r _c ) for small pores will be dependent on a number of factors, including capillary pressure, interfacial tension and pore geometry. The person skilled in the art would be able to select the cutting pore radius for a formation containing hydrocarbons in particular among the small pores that are 100% saturated with water and the larger pores initially saturated with water and oil.
After primary drainage, the oil invades the large pores in the reservoir. If the invaded oil phase does not contact the surface of the pore walls, the reservoir rocks remain water-wetting and the oil phase only provides the volume relaxation contribution for the relaxation time. If the oily phase begins to contact the surface of the pore walls, the contributions from both the surface relaxation mechanism and the volume relaxation mechanism take effect, and the process
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41/96 wettability change occurs. After changing the wettability of a partially porous medium of saturated oil, the inverse of the spin-spin relaxation time (T ₂ ) of the oil phase in a large pore at the fast diffusion limit can be expressed as:
< ²⁵ >
T „^ s _a )“ va, T _1Bfl
In equation (25), T ₂ , o, l (S _q í) is the spin-spin relaxation time of the oily phase the initial oil saturation of S _o í of a large pore of partially saturated oil, S _o ile represents saturation of the initial phase of the large pore of invaded oil, p ₂ , that is the spin-spin relaxivity of the oil phase the initial saturation of the oil phase Soí, Aoíl is the surface area of the large pore contacted by the oil phase, and Vl is the large pore volume.
As a change in wettability during aging, water flooding, or RMP processes occur mainly in large pores containing oil, wettability indices for large pores can also be formulated. In the initial condition of the saturation oil (Soi), the wettability index of the oil phase for the oil phase invaded by large pores is defined as:
(26a) where S _o l, l is the initial oil saturation in the oily phase invaded from large pores.
The present invention allows NMR wettability indexes to be defined based on two factors, that is,
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42/96 the fraction of the pore surface in direct contact with the fluid, and the relative surface relaxivity, which is the ratio of surface relaxivities in different saturation states to a porous medium (for the same porous medium). This newly defined relative surface relaxivity eliminates the influence of other factors on surface relaxivity, for example, rock mineralogy, and paramagnetic impurities that are present on the pore surface, and is directly related to the affinity between the pore surface and the fluids that are present in the pore space.
Likewise, in the condition of residual oil saturation (S _or ) after water soaking, water flooding and / or an RMP process, the wettability index of the oil phase (Wi _or , L) for the large invaded oil phase during a primary drainage process is like:
Ori- j ₁
TT '25, 0 of defined pores l ___ ΐ (^ Or) Ι'ίΒ.Ο where S _O r, L is saturation of residual oil in the oily phase invaded from large pores during a primary drainage process.
In the condition of residual oil saturation (S _or ) after water soaking, water flooding and / or an RMP process, the water phase wettability index (WIa, l) for the large pore-invaded oil phase is defined as :
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43/96 (26c) ^ ϊ, Αΐ, ί. Utf.A where Sa, l is the saturation of water in saturation of residual oil in the oily phase invaded from large pores during the primary drainage process.
By analyzing the relaxation time distributions (T ₂ ) in the initial water and initial oil saturation state before and after the aging of the core, a cut-off spin-spin relaxation time (T ₂ , c) can be determined for additional partition of the oil phase pore volume invaded from large pores into small pores when the change in wettability does not occur and large pores, where change in wettability occurs. Therefore, the wettability index of the oil phase for the large pores, where the change in wettability occurs is defined as:
(26d) ^ 2.0JW
All terms in equation (26d) are used to describe the wettability index, spin-spin relaxation time (T ₂ ), and initial oil saturation in the large pores, where the wettability changes after aging of the core. T ₂ , o, m (Soi) is the oily phase spin-spin relaxation time at the initial oil saturation, T ₂ , oi, m is the oily phase spin-spin relaxation time at 100% oil saturation , and S _o í, m is initial oil saturation in the oily phase invaded from large pores when the
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44/96 change in wettability occurs after aging of the core.
Under conditions of initial oil saturation (S _o í), the wettability index for the oil phase as a function of both pore radius (r) and capillary pressure (P _c ) is defined as:
(27)
It is observed that when modeling the porous medium with regular polygonal tubes, r can be replaced by L in equation 27.
Replacing equation (12b) in equation (27) gives wettability index (WI) of the oil phase as a function of pore size (r) and capillary pressure (P _c ) for the pore-body and pore-throat model:
__ ^]
TT / f / D T _2S q L. r J ~ ~ - t --------- T ----------------- if r>rt; or WIoí = 0 if r <rt (28a)
Substituting equation (13b) in equation (27) gives the wettability index (WI) of the oil phase as a function of the spin-spin relaxation time (T2) and the capillarity pressure (P _c ) for the pore-body and pore-throat model :
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45/96
1 1 1__1 ^ 2.01 C ^r )
τ ^{2σ Μί} * Ρ, Α ^ ^ ί.Αι if Τ ₂ , αι> T _2t ; or WIoí = 0 if T ₂ , ai ^ T ₂ t (28b)
Substituting equation (20c) in equation (27) we find the wettability index (WI) of the oil phase as a function of the spin-spin relaxation time (T ₂ ) and capillarity pressure (P _c ) for the regular polygonal tube model of N sides:
1___1 wi _a (T _t , p _c ) = ^η ί °
π
TVtaufyr // V) ( ^r ) if T ₂ , wi> T _2t ; or WIoí - 0 if T ₂ , wi —T ₂ t (29a)
Substituting equation (20d) in equation (27) we find the wettability index (WI) of the oil phase as a function of pore size (L) and capillary pressure (P _c ) for the N-sided polygonal tube model:
1___1
A / tan ^ r / TV);
for P _c > Pct or WIoí = 0 for Pc ^ Pct (29b)
Substituting equation (9) into equations (27), (28a), (28b), (29a), (29b) we find the wettability indexes
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46/96 as a function of the height above the free water level (H) in reservoirs containing hydrocarbons.
It is noted that relaxivity is influenced by surface affinity and the presence of any paramagnetic materials on or near the pore surface. The person skilled in the art will be aware that values for fluid relaxivity can be obtained from the literature, although these values may not always be reliably accurate. Additionally or alternatively, the relaxation values can be determined by experiment.
Let's consider a situation in which two porous samples of saturated fluids are taken or prepared, which samples that contain a certain proportion of oil and water within their pores. The oil can be produced from one of the samples using a water flood or brine soaking process, that is, a secondary oil recovery process from the other sample using a microbial process or RMP chemical process, that is , a tertiary oil recovery process.
In the first case, (for example, flood water), the inverse of the spin-spin relaxation time (T2) of the aqueous phase can be expressed as:
—--- = - ^{+ (30)}
7 ₂ , _A (Sod) rs _A1 T _1B , _A]
In equation (30), T2, A (S _O ri) is the spin-spin relaxation time of the aqueous phase in the saturation of residual oil, Sori, after the water flood, Q2, ai is the spinspin relaxivity of the aqueous phase after the flood of water, T2b, ai is the relaxation time large quantities spin-spin by volume
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47/96 of the aqueous phase, Aai is the internal surface area of the pores that is in contact with the aqueous phase after the water flood, Sai is the water saturation level after the water flood and V is the pore volume . In a two-phase system, it should be noted that Sai = (lS _O laughs).
In the latter case (for example, after microbial RMP, hereinafter referred to as ROMM or after a chemical RPM process or after a low salinity water injection RPM process) the inverse of the spinspin relaxation time (Ta) of the aqueous phase can be expressed as:
(31) ____1 ____ 4 ^ 2 | 1
In Equation (31), T2, A (S _O r2) is the spin-spin relaxation time of the aqueous phase to a second saturation of residual oil, S _O r2, after the RPM flood, p2, A2 is the spin- spin of the aqueous phase after the RPM flood, T2b, a2 is the relaxation time spin-spin in volume of the aqueous phase, Aa2 is the area of the internal surface of the pores that is in contact with the aqueous phase after the RMP flood, Sa2 is the initial water saturation level and V is the pore volume. In a two-phase system, it should be noted that Sa2 = (lS _O r2).
Equations (30) and (31) can be normalized depending on the situation for 100% water saturation (ie, as described by equation (1) above), to provide the wettability indices according to the following equations:
(32)
A1—- ⁵ A1 iJi, Al γ ₂₃ , (Μ η_.
1___1_ ^ 2, Al ^ 2B, A
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48/96 where equation (32) provides the wettability index for the aqueous phase after water flooding or soaking:
^ Za.RMP ⁼
Pl.A ^
1___1
A ^^^) Íjj.Aí
ZZZZZ
7 '7' ⁱ 2.Ai * ϊ ».Α (33) where equation (33) provides the wettability index for the aqueous phase after a ROMM or RMP flood.
In measurements of the spin-spin relaxation time of fluids within porous media, information about the distribution of fluid within the pores and / or the structure of the pores can often be superimposed on each other. Thus, the normalization described above is carried out in order to dissociate this overlapping information.
Dividing equation (33) by equation (32), a NMR wettability index modification factor (EMIMa) can be derived for the aqueous phase that compares, for example, RMP with a water flooding process. This is shown in equation (34) below:
IMF ^A PtA ^ A]
1 __1 _^ 2A! ^ A2 η α (^ γ2) 1 1Γ _1ιΑ (& γ1) ^J A1
(34)
It should be noted that the definitions provided by equations (33) and (34) are suitable for secondary or tertiary oil recovery processes.
Likewise, the wettability indexes for the oil phase after flooding water (or soaking) with
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49/96 residual oil saturation of processes residual oil saturation of S _O r2 can equations (35) respectively:
of Sori and RMP with being defined as
T _3fljO
Ϊ
2.0] ^J ΪΒ.0
RMP-.
02 # ^Λ
1___1
T _aa (Sc> r2) _Ü
£ 2 Jl
In equation (35)
WIo is the wettability index for the oil phase after a flood of water (or soaking)
Sori denotes a primary saturation of residual oil after water flooding, T2, o (S ₀ ri) is the spinspin relaxation time of the oil phase in the first saturation of residual oil, P2oi is the spin-spin relaxivity of the oil phase in the first saturation of residual oil, T2b, o is the spin-spin relaxation time in volume of the oil phase, Aoí is the area of the internal pore surface that is in contact with the oil phase, T2, hi is the spin relaxation time -pin of the oil phase to a porous medium that is fully saturated with the oil phase (100% saturation of the oil phase), p2, o is the spin-spin relaxivity of the oil phase, Τββ, ο is the spin- spin in volume of the oil phase, and A is the surface area of the pores within the porous medium. Thus, equation (35) refers to a secondary oil recovery process.
In equation (36), WIo, rmp is the wettability index for the oil phase after a flood of improved oil recovery, S _O r2 is the second oil saturation
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50/96 residual after flood RMP, T ₂ , o (S _or2 ) is the spin-spin relaxation time of the oil phase in the second residual oil saturation, p ₂ , o ₂ is the spin-spin relaxivity of the oil phase in second saturation of residual oil, T ₂ b, o is the spin-spin relaxation time in volume of the oily phase, Aq ₂ is the surface area of the pores within the porous medium in contact with the oily phase, T ₂ , hi is the spin-spin relaxation time of the oil phase at 100% saturation of the oil phase, p ₂ , o is the spin-spin relaxivity of the oil phase, T ₂ b, o is the spin-spin relaxation time in volume of the phase oily and A is the total pore surface area within the porous medium. Thus, equation 36 refers to a tertiary recovery process.
The NMR wettability index (FMIMo) modification factor for the oil phase when comparing an RMP process with a water flooding (or soaking) process is defined as:
1 1IMF r _2O (5or2) T1B, O. ΰ ^- ] 1 Tísf) _
(37)
While the NMR wettability indexes and the wettability modification factors in equations (32) to (37) above were defined in terms of the spin-spin relaxation time (T ₂ ), it should be noted that they are also applicable to measurements of spin-reticulated relaxation time. When using Ti instead of T ₂ , p ₂ should be used instead of p ₂ in the equations.
In addition, it should be noted that NMR measurements of relaxation times generally record a distribution of the
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51/96 relaxation time. As will be described later, it is the peak values (that is, the most common relaxation time) or the average values of the appropriate distributions that are inserted in the equations listed above.
A system for determining the wettability characteristics of a fluid-containing porous medium will now be described. The system includes means for receiving data arranged to receive measurement data indicative of a time of fluid relaxation present in the porous medium to a defined fluid saturation. It should be understood that, as explained above, the fluid for which the relaxation time is measured can comprise an aqueous phase or an oil phase of fluid present in the porous medium. The fluid saturation defined can be, for example, initial oil saturation, residual oil saturation or water saturation in residual oil saturation, as defined with respect to equations (26a) to (26c), respectively.
The system further includes means of receiving data arranged to receive reference data indicative of one or more times reference fluid relaxation times, for example, the reference relaxation times in equation (26a) are the spin-relaxation time. spin of the saturated porous medium of 100% oil, and the spin-spin relaxation time in volume of the oil phase. Computer-implemented media, in the form of one or more software components, as a component for calculating the wettability index, are arranged to calculate the relevant wettability index (which, as described above, is indicative of the wettability characteristics of the medium porous). The wettability index is calculated based on the
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52/96 difference between received measurement data and received reference data, for example, according to equations (26a) to (29b) and (32) for (36) defined above. The calculated wettability index is indicative of the wettability characteristics of the porous medium at the defined fluid saturation.
The system can also receive any other relevant data, such as data indicating pore size, capillary pressure and / or residual oil saturation, needed to calculate the wettability index.
The system may also comprise means of receiving data arranged to receive a plurality of data, each of which is indicative of a time of fluid relaxation present in the porous medium. For example, relaxation times can be measured at different points in time, at different locations in the porous medium, or at different stages before, after and / or during at least one of a primary, secondary or tertiary recovery process. fluid, as will be described below with reference to several examples. In this case, the system comprises means implemented on a computer, such as the component for calculating the wettability index, arranged to calculate the wettability index for each of the plurality of measurement data, respectively. The system also includes means implemented in a computer arranged to calculate, based on a comparison of the calculated wettability indexes, the modification factor of the wettability index described above in equation (37). This last calculation can be performed by a component of calculation of the modification factor of the wettability index. The factor of
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53/96 modification of the calculated wettability index is indicative of a change in the wettability characteristics of the porous medium.
The system is preferably a processing system comprising conventional operating system and storage components, such as a random access memory (RAM) bus system, a hard disk, a central processing unit (CPU), adapters input / output devices that facilitate connection to user input / output devices and, in some modalities, interconnection with other devices on a network. RAM memory contains operating system software that controls, in a known manner, the low level operation of the processing system. The RAM memory contains the component for calculating the wettability index, the component for calculating the modification factor for the wettability index, and any other software components, during its execution. Each software component is configurable with the measurement and / or predetermined data stored in one or more databases
data or others components in storage that are operatively coupled or connected to the system in processing. This invention it will be now described per
reference to the following figures and examples.
EXAMPLES
GENERAL LABORATORY PROCEDURES
Experiments that demonstrate the principles of the present invention were carried out in the laboratory.
Experiments can be performed on samples
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54/96 prepared in the laboratory to simulate reservoir rock, for example, sand packets or core buffer samples taken from the field.
When using core buffer samples, it may be preferred to take a single core buffer and then divide it into a plurality of smaller ones called sibling buffers. This will help to ensure that the buffer samples used in a particular experiment are as similar as possible.
In general, core samples or plugs must first be prepared and aged.
For example, where the sample is a core plug, it may initially contain many substances within its pores, for example, tap water, drilling mud, crude oil. If deemed necessary, the core buffer sample is cleaned using a solvent to remove these substances.
Once the sample has been cleaned (if necessary), it is then saturated with an aqueous phase, the phase of which can be used to simulate the conate water that can be found inside a particular reservoir.
An oily phase is then added to the sample, displacing a portion of the aqueous phase to provide a desired aqueous to oil phase ratio. In the laboratory, it may be possible to control conditions such that the sum of the initial saturation level of the oil phase (Soi) and the initial saturation level of the aqueous phase (Saí) is equal to the unit, that is, Soi + Saí = 1. This it means that the pores are completely full and contain only the two phases. In general, however, Soi + Saí is more likely
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55/96 will be slightly smaller than the unit, since the other phases such as air may be present in small amounts within the pores.
The initial level of oil phase saturation (Soi) will be selected to reproduce the conditions that can be found inside a reservoir. For example, oil can be added to the sample in the amount needed to give an initial oil saturation level of 0.4 to 0.9. The initial oil saturation level can be, for example, about 0.4, 0.5, 0.6, 0.7, 0.8 or 0.9.
The sample is then allowed to age to allow the fluid, i.e. the aqueous phase and the oil phase, to redistribute themselves within the sample pores until an equilibrium distribution is achieved.
For example, it will be appreciated that when the sample is saturated with an aqueous phase (that is, before any oil is added), the aqueous phase will occupy the entire pore volume of the sample. Considering a single pore, when the oil is added to the sample, initially the oil phase will in general displace the aqueous phase from the region in volume of the pore. The aqueous phase will remain in contact with the pore surfaces. During the aging of the oil phase and the aqueous phase they will redistribute themselves within the pore, for example, such that a portion of the pore surface is contacted by the oil phase. Therefore, after aging, the pore will be in a state of mixed wettability.
Wettability controls the distribution of fluid in a reservoir and therefore has a fundamental influence on flow behavior,
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56/96 residual oil and relative permeability. Thus, wettability also has a fundamental influence on the performance of the reservoir. Therefore, it is more desirable that the wettability distribution within a test sample is representative of the reservoir.
It is therefore important that the aging process is allowed to run its course before a sample is used in all subsequent experiments. If aging is not complete or is not substantially complete, then any predictions based on the results of such subsequent experiments may be subject to a greater degree of error, since the sample will not closely reproduce the reservoir conditions.
Complete or sufficient aging of a sample can take a long time, for example, sometimes on the order of several weeks or even months.
Taking regular T2 distribution measurements, the aging process can be monitored. For example, T2 distribution measurements can be taken every day or every few days.
The T2 distribution will change when the phases are redistributed between the pores, for example, when more oil contacts the pore surfaces. When the sample has been aged sufficiently or completely, the T2 distribution will not fail to change significantly from one measurement to the next. Conveniently, the aging process can be tracked through observation and tracing the trend in the logarithmic medium of the T2 distribution, which will tend to
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57/96 based on or around a particular value for the end of the aging process.
When test samples are obtained from core samples, the reservoir's wettability can be restored by cleaning the or each core sample with a solvent, followed by the acquisition of representative initial oil and water saturation, and aging ( for example, by immersion) in crude oil for a period of time to reestablish the reservoir's wettability.
Imbibition experiments (oil displacement) can be performed on the test samples. These can be forced imbibition experiments or spontaneous imbibition experiments.
The various measurements of the relaxation time T2 can be taken using a Carr-PurcellMeiboom-Gill (CPMG) pulse sequence with an echo time of 0.2 ms, and a resonance frequency of 2 MHz. The data obtained from CPMG can be inverted for a T2 relaxation time distribution using an inverse Laplace transformation algorithm.
EXAMPLE 1
NMR WET STUDIES DURING CORE AGING AND PROCESSES OF EMBEBITION OF LOW SALINITY WATER AND HIGH SALINITY SEAWATER
Two samples of the sandstone core plug # 156 and # 157 were selected as a pair. The buffers were cleaned using a hot solvent flow.
After core cleaning the plugs were
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58/96 characterized. The diameters of the buffer samples # 156 and # 157 were 3.8 centimeters and their lengths were 7.7 centimeters and 7.6 centimeters, respectively. Core buffer samples # 156 and # 157 had a porosity of about 0.15 and a permeability of about 25 mD.
The two core buffer samples were brought to the initial water saturation (Saí) of 0.2 by nitrogen gas using the porous plate technique with capillarity pressure of 182 psi (1.25 MPa).
The two core samples were inserted into hydrostatic core supports and a 400psi (2.76 MPa) nominal overload pressure was applied. The two core plugs were saturated with kerosene in the initial water saturation condition (Saí). The crude oil samples were heated to a reservoir temperature of 68 ° C and were injected into the core samples through a 0.5 micron filter. Before the injection of the crude oil, the kerosene was displaced by a toluene plug to prevent the deposition of asphaltenes from the crude oil, which can otherwise occur if crude oil contacts kerosene. The two core buffer samples in initial water saturation (Sai) and initial oil saturation (Soi) were heated to a temperature of 68 ° C in the hydrostatic core supports and were then aged for a period of three weeks. A pore volume of 1.5 crude oil was refreshed weekly, during the aging period.
The two core plugs were subjected to investigation of T2-NMR relaxation time distributions at each stage of their saturation history:
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59/96 • 100% water saturation;
• in the initial water saturation (Saí) and initial oil saturation (Soí) before the aging of the nucleus;
• in the initial water saturation (Saí) and initial oil saturation (Soí) after the aging of the core;
• in saturation of residual oil (Ser) after imbibition (with sea water or low saline brine) • in oil saturation 100%.
In addition, the response to the T2 relaxation time of
NMR was measured in a bulk sample of crude oil and in samples of water by volume (sea water and low saline brine).
A synthetic brine composition was used as the aqueous phase within the aged buffer 15 samples. Details of the composition of the synthetic brine are given below in Table 1-1.
Component Concentration (g / l) NaHCOa 1,315 Na2SO4 0.037 Na2CO3 0.000 CaCl22H2O 1.367 MgCl26H2O 0.217 FeCl3 0.000 BaCl22H2O 009 KCl 0.200 SrCl26H2O 0.067 LiCl 0.011 NaCl 11,359
Table 1-1
After aging the core, the two plugs on the
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60/96 nuclei were placed on imbibometers. Core plug # 156 was submerged in a low-saline brine and core plug # 157 was submerged in synthetic seawater. The imbibometers were placed inside a laboratory oven and kept at a temperature of 68 ° C. The oil produced due to spontaneous imbibition was monitored.
The composition of synthetic seawater is shown below in Table 1-2.
Component Component concentration(g / l) NaHCOa 0, 19 Na2SO4 3.92 CaCl22H2O 1.47 MgCl26H2O 10, 64 KCl 0.72 NaCl 23.48
Table 1-2
Low salinity brine was obtained by diluting synthetic seawater with deionized water so that the total content of dissolved solids was 1500 ppm by weight.
The two brine soaking experiments showed that the water saturation level rose rapidly and reached a higher final value for the low salinity brine (core buffer sample # 156) than for the high salinity brine (sample buffer sample). core # 157). The possible difference in water saturation after 42 days of soaking was 4.2 saturation units (42.2% for high salinity brine and 46.4% for
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61/96 low salinity (see table 1-3)).
Table 1-3 Results of spontaneous soaking experiments for buffer samples # 156 and # 157
Number ofplug Soi Sor Oil production(OOIP fraction) 156 0.79 0.54 0.32 157 0.80 0.58 0.27
Table 1-3
Figure 1-1 shows the T2 relaxation time distributions for sibling rock core buffers at 100% water saturation (Sa = 1). The relaxation time distributions for the two 100% water saturation buffers were nearly identical, indicating that the two buffers have very similar pore size distributions.
A porous plate experiment was carried out for the two rock core plugs, # 156 and # 157, with water displacing the air, where Θ = 0, and σ = 72mN / m. The capillarity pressure applied was 182 psi (ie, Pc = 182 psi (1.25MN / m ² )), which corresponded to a capillary pore throat radius (Rt) of 0.11 pm, determined using the equation (8). The total initial water saturation measured was 0.2.
The initial water saturation distribution (Saí) as a function of the pore size for a cylindrical pore throat model and spherical pore body (equation 14a) was used to match the total initial water saturation determined of 0.2 the capillarity pressure of 182 psi (1.25MN / m ² ) with equation (21) thus providing corresponding parameters of effective water relaxivity, Q2, a, of 26.1 um / s, and a ratio
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62/96 body to the pore throat (BTR) 1.5. The corresponding parameters determined were used in equation (14a) to determine the initial water saturation distribution as a function of the pore size of six different capillary pressures, that is, 5, 10, 25, 50, 100 and 400 psi ( 34.47 KPa, 68.95 KPa, 172.37 KPa, 344.74 KPa, 689.47 KPa, 2757.90 KPa), as shown in figure 1-2.
Likewise, the initial water saturation distribution (Saí) as a function of the relaxation time (T2) for a cylindrical pore and spherical body throat model (equation 15a) was used to match the total water saturation determined initial value of 0.2 psi (1.38 KPa) at capillary pressure of 182 psi (1.25 MPa) with equation (22) thus providing corresponding parameters of effective aqueous phase relaxivity, P2, a, of 26, 1 pm / s, and BTR of 1.5. The corresponding parameters determined were used in equation (15a) to determine the initial distribution of water saturation as a function of the relaxation time (T2) at six different capillarity pressures, that is, 5, 10, 25, 50, 100 and 400 psi (34.47 KPa, 68.95 KPa, 172.37 KPa, 344.74 KPa, 689.47 KPa, 2757.90 KPa), as shown in figure 1-3.
Water volume distributions as a function of pore size (r) with 100% water saturation (Sa = 1) and initial water saturation (Saí = 0.2) were determined for core buffer # 156 a a capillarity pressure of 182 psi (1.25 MPa); these are shown in figure 1-4. The water volume distributions were calculated from the cylindrical pore and spherical body throat model (equation (14a)) with a BTR of 1.5, a
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63/96 effective water phase relaxivity, P2, a, of 26.1 pm / s, and a surface tension of 72mN / m. The water volume distribution as a function of the pore size curve in the fully saturated water condition (Sa = 1) in figure 1-4 was converted from the relaxation time distribution curve T2 of core buffer # 156 of figure 1-1. The initial water volume distribution as a function of the pore size curve in figure 1-4 was determined by multiplying the amplitudes in the fully saturated water curve in figure 1-4 by the corresponding initial water saturation value (Saí) for the curve at a capillarity pressure of 182 psi (1.25 MPa) shown in figure 1-2.
The distribution of the initial oil volume as a function of the pore size, at a capillarity pressure of 182 psi (1.25 MPa) and at the initial oil saturation of 0.2 for core buffer # 156 is shown in figure 1 -5 and was calculated from the model of the cylindrical pore throat and spherical pore body (equation (14b)) with a BTR of 1.5, effective aqueous phase relaxivity, P2, a, of 26.1 pm / s, and a surface tension of 72mN / m.
The initial water volume distribution as a function of the pore size in the condition of fully saturated water (Sa = 1) and in the initial water saturation (Saí = 0.2) for core buffer # 157 at a capillarity pressure of 182 psi (1.25 MPa) is shown in figure 1-6. These were calculated from the model of the cylindrical pore throat and spherical pore body (equation (14a)) with a BTR of 1.5, an effective water phase relaxation, P2, a, of 26.1 pm / s , and a surface tension of 72mN / m. The distribution
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64/96 water volume as a function of the pore size in the fully saturated water condition (Sa = 1) of figure 1-6 has been converted from the relaxation time distribution curve T2 of core buffer # 157 ( figure 1-1). The initial water volume distribution as a function of the pore size curve in figure 1-6 was determined by multiplying the amplitudes of the fully saturated water curve in figure 1-6 by the corresponding initial water saturation value (Saí) (from 182 psi (1.25 MPa) curve in figure 1-2).
The initial oil volume distribution as a function of pore size, at a capillary pressure of 182 psi (1.25 MPa) and at the initial oil saturation of 0.2 for core buffer # 157 is shown in Figure 1- 7 and was calculated from the cylindrical pore throat and spherical pore-body model (equation (14b)) with a BTR of 1.5, an effective water phase relaxivity, P2, a, of 26.1 pm / s, and a surface tension of 72mN / m.
The initial oil saturation as a function of the pore size, at a capillarity pressure of 182 psi (1.25 MPa) and corresponding total initial oil saturation of 0.8 for # 156 and # 157 sibling core plugs is shown in figure 1-8. This was calculated from the cylindrical pore throat and spherical pore-body model and equation (14b) with a BTR of 1.5, an effective water phase relaxivity, P2, a, of 26.1 pm / s, and a surface tension of 72mN / m.
Figure 1-9 shows relaxation time distributions (T2) of a bulk crude oil (labeled bulk crude) and for core plug # 156 in different
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65/96 saturation states, that is, 100% brine saturation (labeled SWl), 100% oil saturation (labeled Sol), in the initial oil and water saturation before aging (labeled Swi) and after aging for three weeks (labeled Envelhecidos @ Saí), and after spontaneous soaking with low salinity water (labeled as soaking).
Comparing the T2 relaxation time distributions for core plug # 156 before and after aging for the large pores showed that the T2 relaxation time distribution of the aged rock sample was shorter than for the un aged rock sample . This is because the oily phase contacts the surface of the pore walls and results in a change in wettability in the large pores. In the large pores, the aging process shifts the T2 relaxation time distribution to the left side, with a similar scale, while retaining a similar shape. Therefore, the aging process in the large pores shifts the shift in distribution from total T2 relaxation time to shorter T2 relaxation times. This can be roughly represented by a change in peak relaxation time T2 values from 41884 ps to 31910 ps. This change is used in equation (28a) to calculate the wettability index distribution of the oil phase as a function of the pore size after aging. Peak relaxation time T2 values for bulk crude oil and 100% saturated oil core buffers are also used as inputs to equation (28a). The wettability index determined as a function of the size of the
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66/96 pore is shown in Figure 1-11 for core plug # 156.
The results presented in figure 1-9 show that the T2 relaxation time distributions in the initial water and oil saturation before and after aging were almost unchanged for T2 relaxation time components less than 2521 ps, these components reflect the distribution of the T2 relaxation time of initial water and small pore oil that remains strongly wet with an oil phase wettability index of zero after aging. Applying a cut-off time of relaxation time T2 (T2c) of 2521 ps for the distribution of relaxation time T2 in initial water and oil saturation before aging, the initial water and total oil saturation in the small pores was determined as 0.214 PV ( pore volume). Before aging, the initial phase of the oil does not come into contact with the surface of the rock grain and remains as the non-wetting phase and, therefore, has characteristics of mass relaxation in the rock.
Applying a T2 relaxation time cut of 2521 ps to the T2 relaxation time distribution of bulk crude oil, the pore volume ratio of the initial oil phase in the small pores to the total initial oil phase was determined to be 0.093, the which gives the amount of initial aqueous phase completely covering the surface of a pore wall as 0.14 PV. In addition, in the small pores, there is no 0.074 PV of initial oil phase in contact with the surface of the pore wall after aging. Applying the initial oil saturation of 0.074 PV in the small pores for the distribution of the oil phase volume as a function of the pore size, a value of
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67/96 1 pm pore radius cut, r _c , was determined. This gave a limit condition reaching a contact angle (Θ) of zero, as well as an oil phase wettability index (Wloi) of zero and an aqueous phase wettability index (WIAi) of 1, for a pore radius of less than 1 pm, that is, Θ = 0, and Wloi = 0, and WIwi = 1 for r <r _c .
The peak values of relaxation time distributions T2 of the oil phase for sample # 156 of the core buffer in initial oil saturation after aging (Ιύ, ο (Soi)), in the 100% oil saturation phase ( T2, hi), as well as the peak relaxation time value (T2) for a bulk crude oil sample (T2b, o) are shown in table 1-4 below:
T ₂ b, o (ms) T ₂ , hi (ms) T2, o (Soi) (ms) 50.21 26, 619 31.91
Table 1-4
Using the initial oil saturation determined in the large pores, that is, S _o í, m = 0.912, and the peak values of relaxation time distributions T2 (shown in table 1-4) as inputs for the calculation component of the wettability index, the wettability index calculation component performs the steps according to equation (26d), and generates a value of 0.59 for the average wettability index for the oily phase in the largest pores after aging (WI _o , m = 0.59).
Figure 1-10 shows the relaxation time distributions (T2) of a bulk crude oil (labeled as bulk crude) and for core buffer # 157 in different saturation states, that is, brine saturation at 100 % (labeled SW1), 100% oil saturation (labeled
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68/96
Sun), in the initial oil and the water saturation before aging (labeled Saí) and after aging for three weeks (labeled aged), and after spontaneous imbibition with high salinity water (labeled as imbibition).
Comparing the T2 relaxation time distributions for core plug # 157 before and after aging for the large pores showed that the T2 relaxation time distribution of the aged rock sample was shorter than for the un aged rock sample. This is because the oily phase contacts the surface of the pore walls and results in a change in wettability in the large pores. In the large pores, the aging process shifts the T2 relaxation time distribution to the left side, with a similar scale, while retaining a similar shape. Therefore, the aging process in the large pores shifts the whole distribution of relaxation time T2 to shorter relaxation times T2. This can be roughly represented by a change in peak relaxation time T2 values from 50210 ps to 38254ps. This change is used in equation (28a) to calculate the wettability index distribution of the oil phase as a function of the pore size after aging. Peak relaxation time T2 values for bulk crude oil and 100% saturated oil core buffers are also used as inputs for the wettability index calculation component, which performs steps according to equation (28a) . The wettability index determined as a function of the pore size is then produced by the
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69/96 component for calculating the wettability index and is shown in figure 1-12 for core plug # 157.
The results shown in figure 1-10 show that the T2 relaxation time distributions in initial water and oil saturation before and after aging were almost unchanged for the T2 relaxation time components of less than 3309 ps; these components reflect T2 relaxation time distributions of the initial water and oil in small pores that remain strongly water-wet with an oily phase wettability index of zero after aging. Applying a relaxation time cut (T2c) of 3309ps for the distribution of relaxation time T2 for the initial water and oil saturation before aging, the total initial water and oil saturation in the small pores were determined to be 0.2524 PV (pore volume). Before aging, the initial phase of the oil did not come into contact with the surface of the rock grain and remained as the non-wetting phase and, therefore, showed mass relaxation characteristics in the rock.
Applying a 3309 ps T2 relaxation time cut to the T2 relaxation time distribution of the crude bulk oil, the pore volume ratio of the initial oil phase in the small pores to the total initial oil phase was determined to be 0, 1189, which provides the amount of initial aqueous phase completely covering the surface of a pore wall as 0.1586 PV. In addition, in small pores, there is no 0.0938 PV of initial oil phase in contact with the surface of the pore wall after aging. Applying initial oil saturation
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70/96 determined from 0.0938 PV in the small pores for the distribution of the phase oil volume as a function of the pore size, a pore radius cutoff value, r _c , of 1 pm was determined. This gave a limit condition reaching a contact angle (Θ) of zero, as well as an oil phase wettability index (Wloi) of zero and an aqueous phase wettability index (WIAi) of 1, for a pore radius less than 1 pm, that is, Θ = 0, and Wl _o í = 0, and WIaí = 1 for r <r _c .
The peak values of the relaxation times T ₂ of the oil phase for the core buffer sample # 157 in initial oil saturation after aging (T ₂ , o (S _o í)), at 100% oily phase saturation phase (T ₂ , oi) as well as the peak relaxation time value (T ₂ ) for a bulk crude oil sample (T ₂ b, o) are shown in table 1-5 below:
T ₂ b, o (ms) T ₂ , hi (ms) T ₂ , o (Soi) (ms) 50.21 29,145 38,254
Table 1-5
Using the initial oil saturation determined in the large pores, that is, Soi, m = 0, 939, and the peak values of relaxation time distributions T ₂ (shown in table 1-5) as inputs for the calculation component of the wettability index, component of calculating the wettability index performs steps, according to equation (26d), and generates a value of 0.41 for the average wettability index for the oily phase in the largest pores after aging (Wí ₍ i, m = 0.41).
Table 1-6 shows the peak values of relaxation times T ₂ of the oil phase for the buffer sample of
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71/96 core # 156 in residual oil saturation after imbibition of spontaneous low salinity brine (T ₂ , o (Sor)) and in 100% oily phase saturation (T ₂ , oi), as well as the peak value the relaxation time T2 for a bulk crude oil sample (T ₂ b, o), and the saturation value of residual oil (Sor, L) in the oily phase that invaded large pores after spontaneous soaking of low saline brine.
T2b, the (ms) T2.0 (So = 1) (ms) T2.0 (Ser) (ms) ^S or, L 50.21 29,145 50.21 0.56
Table 1-6
The NMR oily phase wettability index for core buffer sample # 156 at residual oil saturation (Sor) after soaking low spontaneous saline brine was determined by the component of calculating the wettability index using equation (26b) and the data from table 1-6, giving an oily phase wettability index of 0, indicating a strongly wet water state.
Table 1-7 shows the peak values of oil phase T2 relaxation times for core buffer sample # 157 in residual oil saturation after soaking high spontaneous salinity (T2, O (Sor)) and of phase oil saturation at 100% (T ₂ , oi) as well as the peak relaxation time value (T2) for a bulk crude oil sample (T ₂ b, o), and the saturation value of residual oil (Sor, L) in the oily phase that invaded large pores, after spontaneous imbibition of high salinity of sea water.
T2b, the (ms) T2.0 (ms) T2.0 (Ser) (ms) Sor.L 50.21 29,145 41,884 0.60
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Table 1-7
The wettability index of the NMR oil phase for core buffer sample # 157 in residual oil saturation after spontaneous seawater soaking can be calculated by the wettability index calculation component using equation (26b) and the data in the table 1-7, which gives an oily phase wettability index of 0.17, indicating a mixed wet state.
NMR studies of core pair # 156 and # 157 show that spontaneous soaking of low-saline brine results in a wetter state of water than sea water soaking, and, consequently, oil recovery has increased .
EXAMPLE 2
NMR WETWATCH STUDIES FOR FLOOD WATER WITH HIGH SALINITY PICKLE AND DIFFERENT LOW SALINITY PICKLES
In this example, water flooding experiments were performed on three sister core buffer samples using different saline brines as the injection water.
The permeability of the core buffer samples was 158mD. The samples were prepared and aged to an initial aqueous phase saturation of 17.6% (ie Saí = 0.176). The aqueous phase was synthetic-forming water. The oily phase was oil from the stock tank (OTE).
The first of the three plugs in the sibling core was subjected to a high salinity flood water. The total dissolved solids (STD) content of the high salinity water was 33,435 mg / 1.
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The second of the three brothers core plugs was subjected to a low salinity brine # 1 (secondary mode) from the flood water. The STD content of low saline brine # 1 was 3144mg / l.
The third of the three sibling core plugs was subjected to a low salinity brine # 2 (secondary mode) from the flood water. The STD content of low saline brine # 2 was 441mg / l.
Figure 2-1 shows the T2 relaxation time distributions for the following samples: (i) bulk OTE; (ii) one of the core plugs at 100% water saturation (labeled SAl) (iii) one of the core plugs after aging in initial water and initial oil saturation, (iv) the first of the three sister core plugs in the saturation of residual oil after flood water of high salinity water (labeled high salinity Ser); (v) the second of the three sibling core buffers in residual oil saturation after flooding the low salinity brine # 1 water (labeled as low salinity # 1 Sor, and (vi) the third of the three saturation sibling core buffers of residual oil after flood water of low salinity brine # 2 (labeled low salinity # 2 Ser).
In Figure 2-1, a mixed wetness state signal is identified from the T2 relaxation time distributions in residual oil saturation after three different flood water salinities with, in each case, a peak T2 relaxation time greater than those of bulk crude oil and core buffer fully saturated with water.
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Figure 2-1 clearly shows that the main components of the T2 relaxation time distribution of the sample aged with OTE at the initial water saturation (Saí) of 17.6% was shifted to the left side, compared to the time distribution T2 relaxation unit in bulk. This may be due to surface relaxation effects, when the oily phase is in contact with the pore surfaces after aging due to a change in the wetting state of the sample.
The three relaxation time distributions T2 for the three sibling core plugs after their respective flood waters show changes significantly from the distribution of the relaxation time T2 of the aged sample with a significant reduction in oil peaks and the appearance of additional peaks on the right side of the spectrum. The new additional components have longer relaxation times than the longest relaxation times for bulk OTE. These components, therefore, clearly result from the injection water and, furthermore, confirm the development of a mixed wetness state. Since significant pores of the pore surface have become covered with crude oil, the surface areas in contact with the injection water have been limited, which results in a dramatic increase in the relaxation time T2 for the injection water. The relaxation time T2 for injection water, however, is shorter than that of bulk water due to the partial contact of the injection water with the pore surface. Further analysis of T2 distributions for the main components of the injection water clearly shows a
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75/96 decreasing tendency of relaxation time with a decrease in the salinity of the injection water. This indicates a change in wettability, with a decreasing tendency for wet oil when the salinity of the injection water is reduced. The smaller tendency of wet oil is observed for water with optimized low salinity.
Using the wettability index modification factor definition described above, the change in wettability during oil recovery processes of different salinities is analyzed quantitatively. Figure 2-1 shows that all components of the OTE T2 relaxation time in bulk are less than 160 ms. Therefore, after the flood water the components of the T2 distribution longer than 160 ms must arise from the aqueous phase. Thus, the logarithmic mean values of relaxation time distributions longer than 160 ms are calculated as T2A (Sorl) = 580ms, T2A (Sor2) = 446ms, T2A (Sor3) = 393ms, for high salinity flood water, low salinity flood water and optimized low salinity flood water, respectively. The residual oil saturations determined from the core flood are Sor1 of 0.469, Sor2 of 0.321, and S or3 of 0.224, which corresponds to Sw1 of 0.531, Sw2 of 0.679 and Sw3 of 0.776 for high salinity flood water , low salinity flood water and optimized low salinity flood water, respectively. The volume relaxation time for the aqueous phase is T2b, a = 2298ms. The relaxation time values T2 determined in residual oil saturations after high salinity flood water, low salinity flood water
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76/96 (low salinity brine # 1), and after the optimized low salinity flood water (low saline brine # 2) were introduced in equation (34). In comparison with the high salinity flood water, calculated wetness index modification factors for the aqueous phase (FMIMa) calculated and produced by the component for calculating the wetting rate modification factor using equation (34) were 1.79 and 2.39 for low salinity flood water and optimized low salinity flood water, respectively.
The experimental results show that, compared to the high salinity flood water, both the oil recovery factor and wetting index of the aqueous phase have been significantly improved by the low salinity flood water and the optimized low salinity flood water.
EXAMPLE 3
NMR WET STUDY FOR A FLOOD OF THE
ROMM CORE
In this example, three similar core plugs were employed having a porosity of approximately 30% and a permeability of about 130mD. T2 NMR relaxation time distributions were obtained at 100% formation water saturation (Sa1), at 100% crude oil saturation (So1), in residual oil saturation after flooding the ROMM core under reservoir conditions , and subsequent to 47 days of diffusion of the core buffer in a reservoir of deuterium oxide (D2O) to obtain the
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77/96 distribution of the relaxation time of the oily phase only in conditions of saturation of residual oil after the ROMM process in reservoir conditions. The T2 NMR relaxation time distributions were also obtained for a bulk crude oil sample.
A pore body and throat model were used. The initial water saturation as a function of the relaxation time T2 and as a function of the pore size is shown in figures 3-1 and 3-2, respectively, for ROMM core plugs at a capillary pressure of 100 psi (0.699 MN / m ² ). The distribution of the water volume is shown in Figure 3-3 as a function of the pore-body radius at 100% water saturation (Sa = 1) and irreducible (initial) water saturation (Saí = 0.28) . The initial water saturation in small non-invaded oil pores (Saís) determined using the pore body and throat model is 0.097 which is consistent with the total water saturation of a small peak on the left side of the relaxation time distribution T2 of a core buffer completely saturated with water.
Figure 3-4 shows the relaxation time distributions T2 of crude oil in bulk (labeled as crude), the core buffer in 100% water saturation condition (labeled as Sa1) and in 100% oil condition saturated (labeled as Sol), as well as in saturation condition of the residual oil after a flood of the ROMM core in reservoir conditions (labeled as Sor + SAor) and after the diffusion of the core buffer for 47 days in a large reservoir of deuterium oxide (D2O) under saturation conditions of residual oil from MOER (Sor)
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78/96 (labeled as Ser D2O). The deuterium oxide (D2O) replaced with water (H2O) that was originally present in the core buffer allowing the distribution of the relaxation time T2 of the oil phase (Sor) to be determined; this is because deuterium oxide (D2O) cannot be detected with the low field NMR spectrometer. The T2 relaxation time distribution of the aqueous phase in the saturation of the ROMM residual oil (labeled SAor) was determined by subtracting the residual oil phase signal (Ser D2O) from the T2 relaxation time distribution after flooding the ROMM core under conditions reservoir (labeled as Sor + SAor) ·
Table 3-1 shows the peak relaxation time T2 values of the relaxation time distributions shown in Figure 3-4 for bulk crude oil and core buffer under different saturation conditions before and after ROMM, as well as the saturation of residual oil (SorL) and saturation of water (salt) in large pores invaded with oil during the primary drainage process.
T2B, O T2, a (SA = 1) T2, o (So = 1) T2A (Sor) salt T2, o (Sor) ^S orL (ms) (ms) (ms) (ms)(ms)68,335 54,974 26,619 60, 19 0.732 38,934 0.268
Table 3-1
After ROMM, the wettability index (of large pores invaded by oil during the primary drainage process) calculated and the yield by the component of the wettability index calculation is 0.13 for the oil phase (WIor, L), and 0, 67 for the aqueous phase (WIa, l) · These values were calculated by the component of calculation of the
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79/96 wettability index using equations (26b) and (26c), respectively. This result shows that the process of flooding the ROMM core under reservoir conditions results in the core buffer samples having a more water-wet and less oil-wet state.
EXAMPLE 4
EXPERIMENTS WITH SAND PACKAGES
In this example, spontaneous soaking experiments were carried out on two sand packs, # 110, 210, which were intended to simulate a porous rock formation. The sand packages were prepared initially by saturating the produced sand (obtained from an oil reservoir) in brine, and partially drying the sand to remove excess brine. The sand / brine was then mixed with oil to a known weight of oil, brine and sand. Excess oil and / or brine was removed from the surface of each sand pack. The two sand packs were then aged. The two sand packs were prepared to be as similar as possible.
After aging, one of the sand packages was destined to be subjected to soaking in brine to produce oil from it, while the other was destined to be submitted to a ROMM process.
In a spontaneous soaking experiment, the prepared and aged samples are only soaked or submerged in a body of aqueous fluid, which is extracted into the sample by the action of capillarity to displace oil. The soaked fluid is at ambient pressure.
The initial NMR measurements of the T2 distribution for
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80/96 the fluid inside each aged sand pack was carried out.
Figure 4-1 shows an experimental set, in which the two sand packs, # 110, 210 are each contained in a similar device, the two devices 1, 2 being positioned side by side.
The first set of apparatus 1 comprises a base 190 in threaded engagement with a vessel 120 and a sand package 110, the sand package 110 being located on the base 190 and inside the vessel 120. Extending upstream from the vessel 120 in a substantially vertical direction is in an elongated tube 130, whose tube 130 is in fluid communication with the internal volume of vessel 120. Tube 130 is supplied at its upper end with a tap 140 to control the
passage of fluid of the tube 130 for an opening 150 situated for beyond gives tap 140. The tube 130 and the vase 120 are both done in glass. O pipe 130 is provided on your
with markings to assess the amount or level of a fluid contained therein.
Also, extending outwardly from a side wall of vessel 120 is an inlet tube 160, which provides fluid communication with the internal volume of vessel 120. Inlet tube 160 is connected to a supply line of fluid 170, which communicates with a fluid source (not shown). Inlet tube 160 is provided with a tap 180 to control the flow of fluid from fluid supply line 170 and into vessel 120 through inlet tube 160.
The fluid source comprises a container for a
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81/96 body of fluid. The fluid supply line 170 communicates with a lower portion of the container such that, in use, the fluid is forced along the supply line 170 by the weight of the fluid in the container. In apparatus 1, the fluid comprises a simple brine solution.
The second set of the apparatus 2 comprises a base 290 in threaded engagement with a vessel 220 and the sand package 210, the sand package 210 being located on the base 290 and inside the vessel 220. Extending upwards from the vessel 220 in a substantially vertical direction is an elongated tube 230, whose tube 230 is in fluid communication with the internal volume of vessel 220. Tube 230 is supplied at its upper end with a tap 240 to control the passage of fluid from the tube 230 for an opening 250 located on the other side of the tap 240. The tube 230 and the vessel 220 are both made of glass. Tube 230 is provided on the outside with markings to assess the amount or level of a fluid contained therein.
Also, extending outwardly from a side wall of vessel 220 is an inlet tube 260, which provides fluid communication with the internal volume of vessel 220. Inlet tube 260 is connected to a fluid supply line 270, which communicates with a fluid source (not shown). Inlet tube 260 is provided with a tap 280 to control the flow of fluid from fluid supply line 270 and into vessel 220 through inlet tube 260. The fluid source comprises a container for a body of fluid. Fluid supply line 270 communicates with a
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82/96 lower portion of the container such that, in use, the fluid is forced along the supply line 270 by the weight of the fluid in the container. In apparatus 2, the fluid comprises a brine solution in which two strains of microbes are dissolved (a first strain that is capable of generating a biofilm and a second strain that is capable of modifying the wetting properties of the sand surface).
Sand packs 110 and 210 were prepared as described above. Therefore, it will be seen that sand packs 110 and 210 are aged before being included in the experimental apparatus. Thus, sand packs 110, 210 contain a known volume of aqueous phase (brine) and oily phase (crude oil).
In the oil displacement experiment performed on a device 1, taps 180 and 150 are initially opened, as a brine solution flows from the container into the vessel 120 through line 170. Once the resulting fluid level within the tube 130 reaches a predetermined height (typically near the top of the marks outside tube 130), taps 180, 150 are closed. Preferably, tap 180 is closed just before tap 150.
As the experiment progresses after taps 180, 150 are closed, the brine solution is soaked in the sand pack 110, thus displacing the crude oil. The volume of displaced crude oil is measured inside tube 130.
In the oil displacement experiment carried out on a device 2, taps 280 and 250 are initially opened, with the brine solution flowing from the container into the vessel 220 via line 270.
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Once the resulting fluid level inside the tube 230 reaches a predetermined height (typically close to the top of the marks outside the tube 230), the taps 280, 250 are closed. Preferably, tap 280 is closed just before tap 250.
As the experiment progresses after taps 280, 250 are closed, brine solution is soaked in sand pack 210, thus displacing the crude oil. The volume of displaced crude oil is measured inside the tube 230.
It will be observed that the experiment carried out in apparatus 2 was exactly the same as that described above in relation to apparatus 1, except that the brine solution provided along line 270 containing the two strains of microbes.
Differences in the volume of solution soaked (displaced oil) and in the T2 distribution profile between the two experiments can be attributed to the effects of microbes on interfacial activity, for example, wettability, between the oil and the pore walls within the sand pack.
At the end of the oil displacement experiment, measurements of the relaxation time T2 by NMR were taken from the fluid remaining inside the sand packages (in residual oil saturation).
The results for the two sand packs were then compared.
Points of reference useful for the analysis of Dice subsequent can be obtained by measurement of distributions of time relaxation T2 for samples bulk of oily phases and watery, a sample porous
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84/96 comparable which is 100% saturated with the aqueous phase and a comparable porous sample which is 100% saturated with the oil phase.
Figure 4-2 shows the T2 (ps) distributions for a number of samples, namely: (i) sand pack 110 in residual oil saturation after soaking in brine, (ii) sand pack 110 after aging, but before brine soaking, (iii) a sample of comparable sand pack 100% saturated with the aqueous phase, (iv) a sample of comparable sand pack 100% saturated with the oily phase, and (v) a sample of the phase oily in bulk.
Samples (iii), (iv) and (v) represent useful reference points for analyzing subsequent data. Often, it will also be useful for obtaining T2 relaxation time data for a bulk sample of aqueous phase.
The distribution curves are not on top of each other. In particular, it can be seen that the peak of the brine soaking curve occurs at a longer relaxation time than the peak of the curve for the sand pack after aging and before brine soaking. This is because brine soaking displaces oil from the sand pack.
Figure 4-3 is similar to Figure 4-2, but shows data from a ROMM experiment. Therefore, figure 4-3 shows the T2 distributions (ps) for the following samples:
(i) sand pack 210 in residual oil saturation after soaking in ROMM, (ii) sand pack 210 after aging, but before soaking in ROMM, (iii) a sample of comparable sand pack 100% saturated with
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85/96 aqueous phase, (iv) a sample of comparable sand pack 100% saturated with oil phase, and (v) a sample of the bulk oil phase.
Again, the distribution curves are not on top of each other. In particular, it can be seen that the peak of the ROMM soaking curve occurs at a longer relaxation time than the peak of the curve for the sand pack after aging and before soaking in brine.
In figure 4-4, distribution curves T2 in saturation of residual oil from Figures 4-2 and 4-3 are shown on the same axes. The saturation of the residual oil (Sro1) for the first sand package 110 after soaking in brine was revealed to be 12.6% and the saturation of residual oil (Sor2) for the second sand package 210 after soaking in ROMM was revealed to be 8 ,1%. As can be clearly seen, the two curves are not on top of each other. The T2 distributions for the first sand packet 110 after soaking in brine (i) and the second sand packet 210 after soaking in ROMM (ii) can therefore be compared. The curve for the ROMM soaking experiment is shifted to shorter relaxation times compared to the curve for the brine soaking experiment. In particular, the peak relaxation time for the ROMM experiment is shifted to a shorter time than that for the brine experiment. This is due to a stronger interaction between the aqueous phase and the pore wall, that is, increased wettability for the aqueous phase. Thus, the ROMM soak process may have released at least a portion of the residual oil that has not been displaced by the
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Figure 4-5 serves to demonstrate the advanced oil recovery that was obtained from sand pack 210 using the ROMM process (ii) in comparison with sand pack 110 through brine soaking (i). Figure 4-5 shows an amount called the oil recovery factor as a function of time (t, (minutes)), the oil recovery factor being a measure of the proportion (expressed as a percentage) of the oil within the oil package. sand before imbibition (an amount known since oil was added during sample preparation), which was displaced from the sand pack during imbibition. The amount of oil displaced is measured by recording the volume of oil inside tubes 130 and 230 of apparatus 1 and 2, respectively.
As can be seen, initially the rate of oil recovery from the sand packets increased relatively quickly before planing to a much slower rate after about 500 minutes. After the initial period during which the oil recovery rate is relatively fast, the oil recovery factor for the ROMM experiment (sand pack 210) is consistently higher at any given time than for the brine experiment (pack of sand 110). The reading made after another 8500 minutes recorded final oil recovery factors of 85.5% and 90.6% for brine soaking (sand pack 110) and ROMM (sand pack 210), respectively.
Table 4-1 below shows the peak values of the spin-spin relaxation time distributions under conditions
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87/96 different saturation for the brine soaking process carried out in a sand pack 110.
T2B, A2 T2B, O T2, a (Sa = 1) T2, o (So = 1) T2A (Sor1) Sa1 T2, o (Soí) Soi (ms) (ms)(ms) (ms)(ms)2297.8 68,335 113,532 54,974 113,532 0.874 59,109 0.869
Table 4-1
T2b, a2 is the peak relaxation time for a bulk aqueous phase sample. T2b, o is the peak relaxation time for a bulk oily phase sample. T2, a (Sa = 1) is the peak relaxation time for a comparable sand pack saturated with the aqueous phase. T2, o (S0 = 1) is the peak relaxation time for a comparable sand pack saturated with the oil phase. T2A (Sor1) is the relaxation time at the peak measured after the completion of the brine soaking (oil displacement) experiment conducted in a sand packet 110 on device 1. T2, o (So1) is the relaxation time of the measured peak after sand pack 110 has been aged.
S _w i is the saturation level of the final water inside the sand pack 110 at the end of the oil displacement experiment (soaking in brine) performed on a device 1. S0i is the initial saturation level of the oil in the aged sand pack 110.
Sa1 can be calculated from So1 and the oil recovery factor, since So1 is known for a given sample prepared in the laboratory and the oil recovery factor is determined by the experiment. For example, consider a sand packet prepared such that Soi + Saí = 1, where Soi = 0.7 and Saí = 0.3, where the sand pack is then subjected to an oil recovery experiment
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88/96 which returns an oil recovery factor of 80%. In this case, the saturation level of the residual oil will be 0.14, that is, 20% Soi, and the saturation level of the residual aqueous phase will be 0.86.
The values shown in Table 4-1 can be entered in the equations shown above, in order to calculate the desired wettability indexes.
For example, by entering the values for the wettability index calculation component, which performs the steps according to equation (26a), the yield of the oily phase wettability index by the wettability index calculation component (in the initial condition of oil saturation for sand pack 110, WIoi) is 0.56.
Similarly, if the component for calculating the wettability index is willing to perform the steps according to equation (32), it is calculated that the wettability index in the aqueous phase (the saturation condition of the residual oil (Sorl) after the brine soaking process, WIa) is 0.87.
Table 4-2 below shows the data equivalent to
Table 4-1, but with respect to the ROMM process performed on sand pack 210.
T2B, A2 T2B, O T2, a (Sa = 1) T2, o (So = 1) T2A (Sor2) SA2 T2.0 (Soi) Soi (ms) (ms) (ms) (ms) (ms)(ms)2249.7 68,335 113,532 54,974 73,475 0.919 59,109 0.865
Table 4-2
T2b, a2 is the peak relaxation time for a bulk aqueous phase sample. T2b, o is the peak relaxation time for a bulk oil phase sample. T2, a (Sa = 1) is the peak relaxation time for a sand pack
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89/96 comparable saturated with the aqueous phase. T2, o (So = 1) is the peak relaxation time for a comparable sand package saturated with the oil phase. T2a (Sor2) is the peak relaxation time measured after the completion of the brine soaking (oil displacement) experiment conducted in a sand pack 210 on device 2. T2, the (Soi) is the measured peak relaxation time after sand pack 210 has been aged.
Sa2 is the final water saturation level inside the sand pack at the end of the oil displacement experiment (ROMM) conducted on sand pack 210 on device 2. Soi is the initial oil saturation level on the aged sand pack 210 Sa2 can be calculated in a similar way to Sa1.
The values shown in Table 4-2 can be entered in the equations shown above, in order to calculate the desired wettability indexes.
According to equation (26a), the component of calculation of the wettability index can calculate that the wettability index in aqueous phase (in the condition of initial oil saturation for sand pack 210, WIoi) is 0.56. It is observed that this is the same value as for sand pack 110 which suggests that the two samples of the sand pack were comparably similar, as desired, before being subjected to brine soaking or ROMM soaking as the case may be.
If the component for calculating the wettability index is willing to perform steps according to equation (33), it can be calculated that the wettability index in aqueous phase under saturation of residual oil (Sor2)
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90/96 for sand pack 210 after the ROMM soaking process is WIa, rmp = 1.45. This is a considerably higher value than for sand packet 110 after soaking in brine, which suggests that the porous medium (the sand packet) becomes relatively more watery after the ROMM process, due to the effect of modifying wettability of the ROMM process.
Using these values and equation (34), it is possible for the calculation component of the wettability index modification factor to calculate the wettability index modification factor for the aqueous phase due to the ROMM process in comparison with brine soaking. as FMIMa = 1.66. This suggests that the ROMM process results in a very strong wettability modification for the water wettability state compared to the brine soaking process.
Another sand pack experiment was performed as an additional control. Thus, a sand pack was prepared using the same produced sand that was used to prepare sand packs 110, 210. The sand was 100% saturated with an inoculum (being immersed in the inoculum). The inoculum was identical in composition to the brine solution containing the two strains of microbes that were used in the ROMM soak experiment for sand pack 210. After removing the excess inoculum, the sand pack was allowed to age for six days to allow a biofilm to grow on the sand surface. This aging time corresponded to the period of time that the sand pack 210 was subjected to imbibition in ROMM (6 days). You should note that the sand pack used in this
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91/96 control experiment was not exposed to crude oil. Due to the absence of crude oil, there was no change in the surface cover in the aqueous phase in the sand pack (that is, the sand pack remained 100% saturated with inoculum).
Figure 4-6 shows the T2 relaxation time distributions for (i) 100% brine-saturated sand package in the absence of microbes (taken from figure 4-3), (ii) 100% saturated inoculum sand package before aging and (iii) 100% saturated inoculated sand after aging for 6 days. It can be seen that the relaxation time distribution T2 of the 100% saturated inoculum sand package before aging is very similar to that for the 100% saturated brine sand package. However, after 6 days of aging, the T2 relaxation time distribution of the 100% saturated inoculum sand pack had shifted to the left side significantly. It is believed that the change in the relaxation time distribution is caused by the growth of a biofilm (resulting from the microbial biofilm-generating strain). This generated biofilm (typically comprising biopolymers) adheres to the surface of the sand grain, which reduces mobility in the aqueous phase, thus reducing relaxation times T2 (the biofilm allows the aqueous phase to adhere more strongly to the sand particles). The
results also show what the measurements gives distribution of time T2 relaxation per MRI can to be used for to monitor the growth in biofilm in middle no
intrusively porous.
As discussed above, based on the value of
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92/96 T2 relaxation of the peak for sand pack 210 when 100% saturated with brine (in Sa = 1), the wetting index in aqueous phase (in saturation of residual oil after the ROMM process, WIa.rmp) was revealed to be 1.45. This wettability index, therefore, represents both an effect of the modification of the covering surface by the strain of surface-modifying microbes and an effect of modification of the surface affinity by the strain of biofilm-generating microbes.
Table 4-3 is similar to table 4-2 in that it shows the values of the relaxation time distributions T2 at peak in different saturation conditions during the soaking process in ROMM for sand pack 210. However, in Table 4-3, the peak relaxation time T2 for the 100% saturated inoculum sand pack after aging for 6 days (73.475 ms) is used for the 100% saturated aqueous phase (Sa = 1). When this data is applied to calculate the wettability index for sand pack 210, the effect of the modification of the surface affinity due to the biofilm generated can be canceled since the change in the relaxation time value T2 from the peak to sand pack 100 % saturated inoculum after aging can only arise as a result of the growth of biofilm in the sand pack. Using equation (33) and the data in table 4-3, the wettability index in the aqueous phase (in condition of residual oil saturation (Sor2) after the ROMM process for sand pack 210, WIa.rmp), calculated by the component calculation of the wettability index is 0.92. This wettability index, therefore, only takes into account the
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93/96 effect of the modification of the resulting surface coverage from the strain of microbes that modify the surface's (interfacial) wettability properties. The strain of microbes that changes the interfacial or wettability properties of the sand surface can release the oil from the sand and thus reduce the surface coverage of the oil phase and increase the surface coverage of the water phase.
T2B, A2 T2B, O T2, a (Sa = 1) T2, o (So = 1) T2A (Sor2) SA2 T2, o (Soi) Soi (ms) (ms) (ms) (ms) (ms)(ms)2249.7 68,335 73,475 54,974 73,475 0.91 59,109 0.8659
Table 4-3
It will be appreciated that the NMR techniques according to the present invention can be used to confirm or determine the relative effectiveness of oil recovery processes, in particular tertiary oil recovery processes, for the particular types of reservoir rocks . As a consequence, it may be possible to select an optimal or most appropriate oil recovery process for a supplied oil reservoir.
Although the previous examples demonstrate the application of the methods of the invention within the laboratory, it is anticipated that the methods would also be useful and applicable outside the laboratory, for example, in an oil field, where the measurement of wettability and / or its changes would be desirable.
For example, experiments could be carried out in the field where the drilling well's NMR record can be
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94/96 used to obtain wettability data in the region of a formation containing hydrocarbons around a well. NMR data for the bulk aqueous phase can be obtained in the field using an NMR record from the drilling well of an underlying aquifer that is in hydraulic communication with the hydrocarbon-containing formation. NMR data for the bulk oil phase can be obtained using a sample of crude oil that was produced from the formation containing hydrocarbons.
Can be necessary to work saturation of oil original how an basis for calculating an estimate of quantity of oil in place within training. Beyond addition, a profile of saturation may be necessary.
It is anticipated that it would also be possible to assess the extent of any changes in wettability and / or damage characteristics for a given formation that may be caused by the drilling process using NMR.
During the drilling of a well, a well will typically be filled with drilling fluid (also known as drilling mud). The drilling fluid can flow out of the well and into the region of the well near the formation, which in turn can move the oil away from the well.
Thus, it will be observed that the saturation conditions within the well region close to the formation will vary with the distance from the well as a consequence of the infiltration of the drilling fluid in the formation. For example, due to the infiltration of the drilling fluid into the formation, the rock closest to the well may no longer have the original saturation level of the formation oil.
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By measuring the wettability characteristics of the region near the well using an NMR recording tool, it may be possible to determine the extent of drilling mud infiltration by verifying how far from the well the rock has the original saturation level of the oil.
Thus, changes in wettability in the area close to the well due to the presence inside the drilling fluid formation can be compared.
Using an oil-based drilling mud with a surfactant can alter the wetting conditions of the formation. Therefore, it will be appreciated that the techniques of the present invention can be used to assess and / or compare the effects of different drilling fluids or muds on the wettability characteristics of the region near the formation well.
Similarly, comparative wettability tests could be performed after a secondary oil recovery process, for example, a water (or brine) flood process or tertiary oil recovery such as ROMM.
In addition, it should be noted that NMR registration can be performed in injection wells and / or production wells. In the case of an injection well, for example, the NMR record can be used to measure the relaxation times for the fluid in the region close to the well. Thus, it is anticipated that it may be possible to determine how much oil was left behind within the region close to the drilling well, for example, after a water flood or RMP process.
Petition 870190115383, of 11/08/2019, p. 101/126
96/96
It will be appreciated that protons ( ¹ H) NMR can be particularly well suited for studies of porous media containing fluids therein comprising aqueous phase and hydrocarbons. However, it is anticipated that other NMR modes 5 may be useful for the investigation of other mixed phase fluid systems in porous media and that the principles of that invention may be applicable when using such other NMR spectroscopy modes.

权利要求:
Claims (9)
[1]
Claims
1. Method of comparing a secondary oil recovery process with a tertiary oil recovery process using NMR spectroscopy, the secondary oil recovery process and the tertiary oil recovery process being applied to a substantially porous fluid medium saturated containing an oil phase and an aqueous phase, the method characterized by the fact that it comprises:
(a) measuring a fluid relaxation time within a first sample of the porous medium using NMR spectroscopy, the first sample having pores, and within the pores there is a known initial volume of the oil phase;
(b) submit the first sample to the secondary oil recovery process;
(c) measure a relaxation time of the fluid remaining inside the first sample, after the secondary oil recovery process using NMR spectroscopy;
(d) measuring a relaxation time of the fluid inside the second sample of the porous medium using NMR spectroscopy, the second sample also having pores, and within the pores there is a known initial volume substantially similar to that of the oil phase;
(e) submit the second sample to the tertiary oil recovery process or, subsequent to step (d) and without performing steps (e) and (f), subjecting the first sample to the tertiary oil recovery process;
(f) measure a relaxation time for the fluid
Petition 870190115383, of 11/08/2019, p. 103/126
[2]
2/9 remaining inside the second sample or first sample after the tertiary oil recovery process using NMR spectroscopy;
(g) using the relaxation time measured after the secondary oil recovery process in order to calculate a first NMR wettability index indicative of the wettability characteristics of the porous medium after the secondary oil recovery process;
(h) use the relaxation time measured after the tertiary oil recovery process in order to calculate a second NMR wettability index indicative of the porous medium's wettability characteristics after the tertiary oil recovery process; and (i) comparing the first NMR wettability index and the second NMR wettability index in order to calculate a NMR wettability index modification factor indicative of a change in the wettability characteristics of the porous medium for the oil phase or phase aqueous, thus establishing a comparison of the effects of the tertiary oil recovery process in the porous medium with those of the secondary oil recovery process.
2. Method, according to claim 1, characterized by the fact that the relaxation time measurements are made for the oil phase and / or the aqueous phase.
[3]
3. Method according to claim 1, characterized by the fact that the porous medium substantially saturated with fluid is a reservoir rock or a replica thereof, and contains an oily phase selected from: a live crude oil and an oil gross stock tank that is associated with the
Petition 870190115383, of 11/08/2019, p. 104/126
3/9 rock reservoir; and an aqueous phase selected from: a conate water and a formation water that is associated with the reservoir rock.
Method according to claim 1 characterized by the fact that the secondary oil recovery process comprises a water flood and / or brine soaking, which uses a selected saline solution from sea water, brackish water, an aquifer water, produced water, conated water, formation water and replicas / models prepared in the laboratory.
5.
Method according to the claim characterized by the fact that the brine solution contains a microbe selected from; bacillus, clostridia, pseudomonas, hydrocarbon-degrading bacteria, and denitrifying bacteria.
6. Method according to claim 4 characterized by the fact that the brine solution is a low salinity water having a total dissolved solids content in the range of 500 to 5000 ppm and a ratio of the multivalent cations content of the low salinity water for the multivalent cation content of the conate water, or the formation water, of less than 1, preferably less than 0.9.
7. Method according to claim 1, characterized by the fact that the relaxation time measurements are the spin-spin (transversal) relaxation time (T2) made using NMR spectroscopy.
8. Method, according to claim 1, characterized by the fact that the measurements are normalized
Petition 870190115383, of 11/08/2019, p. 105/126
[4]
4/9 with a processor by reference to the relaxation time measurements made using NMR spectroscopy on a sample of the porous medium that is saturated with a single phase of water, and / or on a sample of the porous medium that is saturated with a single phase of oil and / or in bulk samples of the aqueous phase and / or the oil phase.
9. Method implemented in an NMR spectroscopy computer that, when executed by a processor, determines the wettability characteristics of a porous fluid support medium, in primary, secondary or tertiary fluid recovery processes, the method characterized by the fact that understand the steps of:
receiving a plurality of measurement data from an NMR spectroscopy system, each measurement of which is indicative of a fluid relaxation time that is present in the porous medium to a defined fluid saturation made using NMR spectroscopy, with the plurality of measurement data being received from the NMR spectroscopy system occurring:
i) at different points in time;
ii) in different locations in the porous medium; and / or iii) in different phases, each of i), ii) or iii) occurring before, after and / or during the performance of primary, secondary or tertiary fluid recovery processes;
receipt of NMR spectroscopy reference data, from a database comprising computer-readable non-transitory media, indicative of one or more reference fluid relaxation times, at the defined fluid saturation, made using spectroscopy
Petition 870190115383, of 11/08/2019, p. 106/126
[5]
5/9 NMR;
calculating, with a central processing unit, a wettability index for each of the plurality of measurement data, respectively, based on differences between the received measurement data and the received reference data, each of said wettability indices calculated being indicative of the wettability characteristics of the porous medium in the defined fluid saturation;
the calculation, with a central processing unit, of a NMR wettability index modification factor, indicative of a change in the wettability characteristics of the porous medium, based on a comparison of the calculated wettability indices; and the display, of the NMR wetting index modification factors calculated in an output device;
a modification factor of the wettability index
NMR that is indicative of a change in the wettability characteristics of the porous medium based on a comparison of the calculated wettability indices; and an output device arranged to display the calculated NMR wettability index modification factor.
10. Method, according to claim 9, characterized by the fact that it still comprises the step of receiving the NMR spectroscopy system of data indicative of parameters related to the pore size, the capillarity pressure, the saturation of the medium fluid porous and / or the height above the free water level in the porous medium, in order to calculate the wettability index as
Petition 870190115383, of 11/08/2019, p. 107/126
[6]
6/9 a function of the parameters with the central processing unit.
11. Method, according to claim 9, characterized by the fact that said different locations refer to first and second well holes arranged so as to penetrate the porous medium, the calculated wettability index modification factor that is calculated being indicative of a change in the wettability characteristics of the porous medium in said different locations in the first and second wells.
12. Method, according to claim 10, characterized by the fact that said different locations refer to first and second well holes arranged so as to penetrate into the porous medium, the calculated wettability index modification factor that is calculated being indicative of a change in the wettability characteristics of the porous medium in said different locations in the first and second wells.
Method according to any one of claims 9, characterized in that the fluid present in the porous medium comprises at least two immiscible fluid components or immiscible fluid phases, and in which the wettability index is calculated for at least one of said immiscible fluid components or immiscible fluid phases.
14. Method, in wake up with claim 9, characterized by fact that the reference data in spectroscopy NMR received comprise measurements in
relaxation times made, using NMR spectroscopy, on:
Petition 870190115383, of 11/08/2019, p. 108/126
[7]
7/9
i) a sample of the porous medium that is saturated with a single aqueous phase;
ii) a sample of the porous medium that is saturated with a single oil phase; and / or iii) bulk samples of an aqueous phase and / or an oil phase corresponding to that of the porous medium.
15. Method according to claim 9 characterized by the fact that it comprises normalizing the relaxation time measurement data based on the NMR spectroscopy reference data received from the database.
16. Method according to claim 14, characterized in that the relaxation time measurements received are measurements of the spin-spin (transverse) relaxation time made using NMR spectroscopy.
17. Method according to claim 9, characterized in that the porous medium comprises a reservoir rock formation, a sample of the reservoir rock formation or a replica of the reservoir rock formation.
18. NMR spectroscopy system configured to determine the wettability characteristics of a porous fluid support medium, in primary, secondary or tertiary fluid recovery processes, the system characterized by the fact that it comprises:
means for receiving data arranged to receive from a NMR spectroscopy system a plurality of measurement data, each measurement of which is indicative of a relaxation time of said fluid present in the porous medium, to a defined fluid saturation made using
Petition 870190115383, of 11/08/2019, p. 109/126
[8]
8/9 NMR spectroscopy; with the plurality of measurement data being received from the receiving means of the NMR spectroscopy system:
i) at different points in time;
ii) in different locations in the porous medium; and / or iii) in different phases, each of i), ii) or iii) occurring before, after and / or during the performance of primary, secondary or tertiary fluid recovery processes;
means of receiving data arranged to receive, from a database comprising computer-readable non-transitory media, a plurality of NMR spectroscopy reference data that is indicative of one or more fluid reference relaxation times made using NMR spectroscopy;
computer implemented means arranged to calculate a wettability index with respect to each of the plurality of received measurement data found in i), ii) and / or iii) respectively, based on differences between the received measurement data and the data reference correspondents received from the database, said wettability index being indicative of the wettability characteristics of the porous medium at the defined fluid saturation;
computer implemented means arranged to calculate a NMR wettability index modification factor that is indicative of a change in the wettability characteristics of the porous medium based on a comparison of the calculated wettability indices; and an output device arranged to display the
Petition 870190115383, of 11/08/2019, p. 110/126
[9]
9/9 modification factor of the calculated NMR wettability index.

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同族专利:

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CA2782731A1|2011-06-23|

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EP2801845A1|2014-11-12|

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EA201200864A1|2013-02-28|

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CA2957098A1|2011-06-23|

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CN104730586A|2015-06-24|

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EP2801844A2|2014-11-12|

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EA201500768A1|2015-12-30|

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EP2513678A1|2012-10-24|

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US20120241149A1|2012-09-27|

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CN104849765A|2015-08-19|

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AU2010332558B2|2014-08-07|

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CN104849765B|2017-10-24|

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CA2782731C|2017-10-31|

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CN102834737B|2016-04-13|

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EP2801845B1|2017-02-01|

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WO2011073608A1|2011-06-23|

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CN102834737A|2012-12-19|

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CN104730587A|2015-06-24|

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EP2804021A1|2014-11-19|

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CA2957098C|2019-08-20|

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EA023601B1|2016-06-30|

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DK2801845T3|2017-05-01|

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US9575203B2|2017-02-21|

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DK2513678T3|2015-03-30|

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MX2012006956A|2012-07-30|

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EP2801844A3|2015-02-18|

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EA201500033A1|2015-08-31|

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EP2513678B1|2015-01-07|

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AU2010332558A1|2012-07-12|

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BR112012014902A2|2017-03-14|

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法律状态:
2019-01-08| B06F| Objections, documents and/or translations needed after an examination request according art. 34 industrial property law|

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2019-08-13| B06U| Preliminary requirement: requests with searches performed by other patent offices: suspension of the patent application procedure|

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2020-01-21| B09A| Decision: intention to grant|

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2020-02-04| B16A| Patent or certificate of addition of invention granted|Free format text: PRAZO DE VALIDADE: 20 (VINTE) ANOS CONTADOS A PARTIR DE 19/11/2010, OBSERVADAS AS CONDICOES LEGAIS. |

优先权:

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申请号 | 申请日 | 专利标题

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EP09252811A|EP2341372A1|2009-12-16|2009-12-16|Method for measuring rock wettability|

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GB201007694A|GB201007694D0|2010-05-06|2010-05-06|Method for measuring wettability|

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PCT/GB2010/002142|WO2011073608A1|2009-12-16|2010-11-19|Method for measuring rock wettability|

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