MX2013013368A

MX2013013368A - Method for injecting low salinity water.

Info

Publication number: MX2013013368A
Application number: MX2013013368A
Authority: MX
Inventors: James Andrew Brodie; Gary Russell Jerauld
Original assignee: Bp Exploration Operating
Priority date: 2011-05-18
Filing date: 2012-05-17
Publication date: 2014-07-30
Also published as: AU2012258217B2; CA2835507A1; MX341908B; WO2012156495A2; NO2710223T3; BR112013029667A2; WO2012156495A3; EP2710223B1; DK2710223T3; US20140290942A1; CN103890315A; EA027017B1; EA201301273A1; EP2710223A2; AU2012258217A1; CA2835507C; CN103890315B

Abstract

Methods, apparatuses and computer readable instructions for determining the effectiveness of, and for performing, a low salinity waterflood. An ion diffusion distance value is determined based on the rate of diffusion of ions within the rock of a reservoir and the residency time of floodwater within the reservoir. The thickness of the layers of the reservoir are compared to this ion diffusion value to determine the effectiveness of performing a low salinity waterflood and also to enable the effective control of a waterflood and to assist in the determination of locations of wells.

Description

METHOD FOR INJECTING LOW SALINITY WATER FIELD OF THE INVENTION The present invention relates to systems and methods to determine the effectiveness of, and to perform, a flood with low salinity water in a reservoir containing hydrocarbons. In particular, the present invention relates to systems and methods for use when the reservoir comprises relatively permeable layers interspersed with relatively impermeable layers and in which the relatively impermeable layers have a relatively high concentration of ions compared to that of the relatively permeable layers when the water of salinity is present in its interior.

'State of the Art A reservoir with hydrocarbon content usually takes the form of a plurality of sandstone layers interspersed with layers of shale. The sandstone layers have sufficient porosity and permeability to store and transmit fluids (eg oil and water). Usually oil is contained in pores of rock formation. On the contrary, the shale layers are relatively impervious to these fluids.

It is known that only a portion of the total crude oil Present in a deposit can be recovered during a primary recovery process, resulting in this primary process the recovery of oil under the natural energy of the deposit. Therefore, secondary recovery techniques are often used to extract additional oil from the field. An example of a secondary recovery technique is to directly replace the oil with an evacuation fluid (also referred to as an injection fluid), usually water or gas.

Enhanced oil recovery (EOR) techniques can also be used. The purpose of such EOR techniques is not only to restore or maintain reservoir pressure (as is done by typical secondary recovery techniques), but also to improve oil evacuation from the reservoir, thereby maximizing oil recovery. from the deposit and minimizing the oil saturation of the deposit (the volume of oil present in the deposit).

"Flooding with water" is one of the most successful secondary recovery methods and is used most extensively. Water is injected, under pressure, into layers of reservoir rock through injection wells. The injected water has the function of maintaining the reservoir pressure, and sweeps the displaced oil ahead of it is through the rock to production wells from which the oil recovers. Water that is used in flooding with water is generally saline water from a natural source (such as sea water) or water can be produced (ie, water that is separated from crude oil in a production facility).

In addition to flooding with water using saline water, it is possible to use lower salinity injection water (for example, brackish water such as estuarine water, or fresh water such as river water, or lake water). The use of a flood with low salinity water can increase the amount of oil that is recovered compared to that which is recovered using high salinity water because the low salinity water is able to dislodge the oil better from the deposit .

Preferably, the water used in a flood with low salinity water usually has a total dissolved solids (TDS) content in the range of 500 to 12,000 ppm. It is also preferred that the ratio of the total multivalent cation content of the low salinity injection water to the multivalent cation content of the formation water that is present in the sandstone layers of the reservoir is less than 1. The use of a flood with low salinity water is particularly beneficial when the oil that is present in the sandstone layers of the deposit (usually oil that is adhering to the surface of the sandstone rock) is a medium or light oil that has a density according to the American Petroleum Institute · (API) of at least 15 °, preferably at least 20 °, and for example an API density in the range of 20 ° to 60 °.

During a flood with salinity water, the low salinity injection water is injected into, and flows through, the reservoir's sandstone layers. On the contrary, little water flows through the relatively impermeable shale layers. Therefore, oil is produced from the high permeability sandstone layers while unidentifiable amounts of oil are produced from the permeability shale layers. In fact, the shale is often so impermeable that the interspersed layers of the shale remained unsaturated with oil during the migration of oil from a source rock to the sandstone layers of the deposit. Instead, the shale layers are saturated with congenital water that is usually of high salinity.

It has now been found that, for deposits that have interspersed layers of sandstone and schist, the The progressive oil recovery effect achieved by using flooding with saline water can be reduced. This is due to the diffusion of the ions from the higher salinity congenital water present in the pore space of the shale layers in the low salinity water that is flowing through the adjacent sandstone layer of the deposit. This reduction in recovery is of particular interest when large volumes of high salinity congenital water reside in shale layers that are interspersed with the sandstone layers of the deposit and when the interspersed layers of sandstone are relatively thin.

The dominant mass transfer mechanism from the congenital water of the shale layers to the low salinity water that is flowing through the adjacent sandstone layers of a reservoir is the molecular diffusion, whereby the salt ions diffuse from the congenital water in the shale layer to water from ba to salinity in the sandstone layer. Usually, the molecular diffusion of the salt ions from the shale layer takes place in a direction substantially orthogonal to the direction of flow of the low salinity water through the adjacent sandstone layer (i.e., in the direction of the gradient). concent ations).

The diffusion of salt ions from the higher salinity congenital water present in the pore space of the shale layers can reduce the effectiveness of a flood with salinity water by increasing the salinity of the water that is flowing through the layers of sandstone. Therefore, one object of the invention is to improve the effectiveness of a flood with low salinity water.

DESCRIPTION OF THE INVENTION In accordance with at least one embodiment of the invention, methods, devices, systems and software are provided to support or implement functionality to provide a flood with effective water from a reservoir. This is achieved by a combination of features that are listed in each independent claim. Accordingly, the dependent claims provide for more detailed implementations of the present invention.

According to a first aspect of the invention, a method implemented by computer is provided to determine the effectiveness of flooding with water of low salinity in a reservoir containing hcarbons, characterized in that the reservoir comprises relatively permeable layers interspersed with nail relatively impermeable layers and is drilled by an injection well and a production well, including flooding with low salinity water injecting low salinity water into the hcarbon-containing reservoir from the injection well through which to pass through the relatively permeable layers of the reservoir from the injection well to the production well, and characterized in that the relatively impermeable layers have a relatively high concentration of ions compared to that of the relatively permeable layers when the water of salinity is present in its interior, the method comprising: obtaining a diffusion distance value of the ions' from: a diffusion coefficient indicative of a diffusion rate of the ions through the relatively permeable layers when the water of low salinity is present inside; and a residence time value indicative of the time required for the salinity water to pass from the injection well to the production well through the reservoir; compare the thickness of the relatively permeable layers with the diffusion distance value of the ions obtained; and using a comparison result to generate an output indicative of the effectiveness of flooding with low water salinity.

The realization of a flood with water of low salinity requires, among other things, a significant amount of water of low salinity, which in general is not available in abundance. This means that it is important to be able to determine a measure of how effective the flooding will be with low salinity water. A determination of this type can be made by performing a detailed reservoir simulation; however, realizing this requires a large amount of computing resources, usually many hours of processing using a large computer or supercomputer. Obtaining the diffusion distance value of the ions and comparing this with the thickness of the layers in the reservoir, an output indicative of the effectiveness of flooding with water of low salinity can be generated using significantly reduced calculation resources. The output can ensure that only floods with effective low salinity water are carried out, and therefore that the limited supply of low salinity water is used with maximum effect.

According to a second aspect of the invention, a computer-implemented method of flood control with low salinity water is provided for a reservoir with hydrocarbon content, characterized in that the reservoir comprises relatively permeable layers interspersed with relatively impermeable layers and is perforated by an injection well and a production well, including flooding with low salinity water injecting water of low salinity into the reservoir with hydrocarbon content from the injection well through which it passes through the relatively permeable layers of the reservoir from the injection well to the production well, and characterized in that the relatively impermeable layers have a relatively high concentration of ions in comparison with that of relatively permeable layers when low salinity water is present inside, the method comprising: obtaining an objective velocity based on: a diffusion coefficient indicative of an ion diffusion rate through the relatively permeable layers whose the water of low salinity is present in its interior; a distance between wells between the injection well and the production well; and a value indicative of a thickness of the relatively permeable layers; and transmitting the obtained target velocity to a control unit of an injection well.

As described above, it is It is important to ensure that a flood with salinity water will be effective. Although the effectiveness of a flood with low salinity water increases with the speed of the water, in general it is not possible or desirable to maximize this speed. Consequently, for a flood with efficient water to be carried out, it is necessary to find a balance between the speed of the floodwater and the amount of hydrocarbons recovered in the flood with water. This balance can be achieved by determining an objective velocity and using this target velocity to control the injection into the reservoir and thereby controlling the speed of the flood with water.

According to a third aspect of the invention, there is provided a computer-implemented method of determining the locations of at least one production well and at least one injection well for a hydrocarbon-containing reservoir, characterized in that the reservoir comprises relatively permeable layers interspersed with relatively impermeable layers and has to be drilled by the at least one injection well and at least one production well, characterized in that the injection well is arranged to provide a flood with water of low salinity which involves injecting low salinity water into the hydrocarbon-containing reservoir from the injection well through which it passes through the relatively permeable layers of the reservoir from the injection well to the production well, and characterized in that the relatively impermeable layers have a relatively high concentration of ions compared to that of the relatively permeable layers when the water of low salinity is present therein, the method comprising: calculating a value of distance between wells on the base of: a diffusion coefficient indicative of a diffusion rate of the ions through the relatively permeable layers when the water of low salinity is present in its interior; a value indicative of a thickness of the relatively permeable layers; and a speed at which low salinity water passes through the reservoir; and using the distance value between wells to determine the locations of the at least one injection well and the at least one production well in such a way that the distance between wells between said at least one injection well and at least a production well is less than said distance value between wells.

Drilling a well in an oilfield requires significant time and resources, therefore it is desirable to ensure that the maximum distance is present between wells. However, there are disadvantages to having such a large distance, one of which is that, in the case of a flood with low salinity water, the effectiveness will be reduced with the increase in distance between wells. In order to achieve a balance, this aspect of the invention calculates a distance value between wells, based on the parameters that will affect a flood with water from. low salinity, and use this value to determine the positioning of the wells.

According to additional aspects of the invention, systems and apparatuses are provided for performing the methods described above and computer readable supports that store computer-readable instructions therein for execution in a computer system for implementing the methods that have been described in the foregoing. Further features and advantages of the invention will become apparent from the following description of preferred embodiments of the invention, given by way of example only, which is made with reference to the appended figures.

BRIEF DESCRIPTION OF THE FIGURES Next, systems and methods embodiments of the present invention will be described, only by way of example, with reference to the attached figures in which: Figure 1 shows a schematic diagram of an oil recovery system and a reservoir with respect to which embodiments of the invention are applicable; Figure 2 shows a schematic diagram of a processing system in which embodiments of the invention can work; Figure 3 shows a graphic representation showing the diffusion of the ions; Figure 4 shows a computer implemented method of determining the effectiveness of flooding with low salinity water according to an embodiment of the invention; Fig. 5 shows a computer implemented method of controlling a flood with low salinity water according to an embodiment of the invention; Figure 6 shows a computer implemented method of determining the locations of the production and injection wells according to an embodiment of the invention; Y Figure 7 shows a graphical representation showing results obtained by an embodiment of the invention compared to results obtained by a detailed reservoir simulation.

Detailed Description of Illustrative Embodiments of the Invention Figure 1 is a schematic block diagram showing a simplified representation of a 100 crude oil recovery system. A multi-layer reservoir is present within the system. In this example, the reservoir comprises a series of permeable and impermeable layers interspersed. The permeable layers (in this sandstone example) contain oil in the pore spaces inside the rock, and have reference 102, 104 and 106. The impermeable layers (in this example shale) generally do not contain oil, and have by reference 108, 110, 112 and 114. Above the above impermeable layer 108 there is shown a generalized surface layer 116 which may comprise multiple layers that do not contain oil, and (if the reservoir is offshore) a layer of water of the marl The composition of these layers is not relevant for this example.

The permeable and impermeable layers constitute the deposit. Drilling the reservoir is an injection well, comprising a control station 118 and a well bore 120; and a production well, comprising a control station 122 and a well bore 124. The Injection and production wells are separated by a distance L as shown. (There are usually many more wells than the two shown in the present case, however, in the present exemplary embodiment two are shown for simplicity).

Each of the permeable layers (102, 104 and 106) in the reservoir has an associated thickness (wl, w2 and w3 respectively). As can be seen from the figure, each layer has a different thickness. Furthermore, it can be seen that the layer 102 has a variable thickness, being of thickness wl at the end of the injection well, and of a narrower thickness wl 'at the end of the production well. This change in thickness will be referred to later.

When in use for a flood with low salinity water, the injection well injects low salinity water as an injection fluid under pressure in the reservoir. The salinity water flows along each of the permeable layers 102, 104 and 106 as shown by the arrows. The low salinity water forces the oil in the reservoir ahead of it causing the oil to be forced from the reservoir into the well hole of the production well (shown again by the arrows). From here, reservoir pressure, optionally aided by pumps located in The well hole in the production well elevates the oil and water received from the reservoir to the surface where it can be stored, refined and used.

During a flood with low salinity water, the low salinity injection water can be passed continuously into the injection well and into the sandstone layers of a reservoir. However, it is preferred that the low salinity injection water is passed in one or more portions (referred to hereinafter as "liquid fractions (slug)") of a controlled volume, which it is usually expressed in terms of "pore volume" or PV. The term "pore volume" is used herein to indicate the volume of the pore space in the sandstone rock layers between an injection well and a production well and can be easily determined by methods known to the skilled artisan. matter. Such methods may include measuring the time necessary for a tracer to pass through the sandstone layers from the injection well to the production well. The swept volume is the volume swept by the injection water averaged across all the flow paths between the injection well and the production well.

Although it is possible to continue to inject the low salinity injection water into the reservoir, usually the pore volume of the low salinity injection water liquid fraction is minimized because there may be a limited injection capacity for the injection. water of injection of low salinity due to the need to eliminate the saline water produced (which is eliminated by injection in the deposit). Therefore, the volume of the low salinity injection water liquid fraction is preferably less than 1, and can be, for example, less than 0.5 PV. Therefore, the low salinity injection water liquid fraction can have a pore volume in the range of 0.2-0.9 PV, and more preferably it can be in the range of 0.3-0.45. PV.

After the injection of a low salinity injection water liquid fraction, a drive water (or post-fade) of higher multivalent content of cations and / or higher TDS (i.e. high salinity), may injected into the field. For example, the actuation water may have total dissolved solids (TDS) of at least 30,000 ppm, for example, 30,000 to 50,000 ppm and a multivalent content of cations of at least 350 ppm. Conversely, the water in the low salinity liquid fraction usually has a content of TDS in the range of 500 to 12,000 ppm. A fraction of salinity liquid of this type can have a multivalent content of cations of less than 40 ppm.

The volume of water fraction of low salinity injection water can be small, but the liquid fraction is still capable of substantially releasing all the oil that can be dislodged from the surface of the pores of the sandstone under the conditions of the deposit. In general, the volume of water fraction of low salinity injection water is at least 0.2 PV, because a fraction of liquid of a lower volume tends to dissipate in the sandstone and may not result in appreciable progressive oil production. It has also been found that, when the volume of the low salinity injection water is at least 0.3 PV (and preferably at least 0.4 PV), the liquid fraction tends to maintain its integrity within the a sandstone rock (that is, it does not disperse inside the rock) and therefore continues sweeping the evicted oil into a production well. Therefore, progressive oil recovery for a deposit comprising layers of sandstone approaches a maximum value with a liquid fraction of at least 0.3-0.4 PV. There is little recovery of Additional progressive oil with higher volume liquid fractions.

When the low salinity water injection liquid fraction has a volume of less than 1 PV (ie, the salinity fraction of the liquid will not fill the reservoir, and you will need that injection drive fluid, usually high water). salinity, injected after it), the drive water will ensure that the fraction of fractional pore volume of water of low salinity (and therefore the released oil) is swept through the reservoir to the production well. In addition, injection of the actuator water may be required to maintain reservoir pressure. Usually, the actuation water has a larger volume than the fraction of water liquid of low salinity injection.

Although the fraction of low-salinity water liquid that is injected into the reservoir-containing sandstone layers is only a fraction of the pore volume, the liquid fraction in general remains intact within the formation and continues sweeping the evicted oil into a production well. Without wishing to be limited by any theory, it is believed that, although there is dispersive (diffusive) mixing between the water of highest salinity drive and ba water to salinity in the tail (back) of the liquid fraction, there is little dispersive mixing (diffusive) between the low salinity water and the formation water in the front of the fraction of liquid. The reason why there is little diffusive mixing between the water of ba at salinity and the formation water at the front of the liquid fraction is that there is an ion exchange reaction taking place between the monovalent cations in the liquid fraction of water of low salinity and the muitivalent cations (predominantly, divalent cations) that are joining the residual oil to the surface of the rock. This means that the liquid fraction reaches a steady state that arises from the fact that the velocities of the ion concentrations are lower at the input edge than at the output portions (due to the ion exchange adsorption at the edge). of entry), and therefore the fraction of liquid sharpens with the spread. In mathematical terms, this arises because the diffusion equation for the mixing of low salinity water with the formation water that is present in the sandstone layers (which has diffusion terms for the concentrations of the individual ions in the water of low salinity and the individual ions in the formation water that depend on distance and time) is balanced by the addition of an extra mathematical term that takes into account the ion exchange between low salinity water and rock (sorption). For these reasons, the liquid fraction of low salinity water remains intact (does not mix substantially with the formation water) as the liquid fraction is forced through the sandstone layers by the salinity water more high subsequently injected.

During a flood with water of salinity, the degree of diffusion of the ions from the water of high salinity trapped in the impermeable layers to the water of low salinity, and therefore the impact of the resulting increase in the salinity of the injected water Low salinity on progressive oil recovery depends on one or more of the following parameters: 1. the flow of water from ba to salinity through the permeable (sandstone) layers of the oil field (generally expressed as a surface velocity, v); 2. the distance between wells, L, between the injection well used to inject the low salinity water into the oil field and the production well that is used to produce oil from the oil field; 3. salt diffusion coefficients in waterproof (shale) layers; 4. the gradient of concentrations between the dissolved salts that are present in the congenital water of a shale layer and the dissolved salts that are present in the water of salinity that is flowing through the adjacent sandstone layer; 5. the thickness of the interspersed shale layers of the oil field; 6. the thickness of the layers of sandstone interspersed with the oil field; 7. the fraction of the total sandstone deposit made of layers of sandstone intercalated and hydraulically connected thin inside a reservoir.

The flow (v) and the distance between wells (L) define the residence time ', t, of the water of ba to salinity in the layer or layers of sandstone of the deposit and therefore the time available for the salt ions They spread from a shale layer to low salinity water that is flowing through an adjacent sandstone layer of the deposit. Therefore, the residence time, t, can be defined as L / v in which L is the distance between wells between the injection and production wells and v is the surface velocity of the water of ba to salinity in the layers of the reservoir sandstone. If the residence time of the water of ba at salinity in the sandstone layer of the oil field is low, there may be little diffusion of salts from the shale layer in the water of low salinity and therefore a non-significant increase in the content of total dissolved solids (TDS) of low salinity water and / or its concentration of multivalent cations. Conversely, if the residence time of the low salinity water in the reservoir is high, there may be significant salt diffusion in the low salinity water and a significant increase in the TDS content of the low salinity water and / or its concentration of multivalent cations.

As discussed above, the flow rate of the low salinity water through the sandstone layers of the reservoir can be expressed as a surface velocity, v, which is defined as the volumetric flow rate of the low salinity water through the sandstone layers of the deposit (which can be determined from the volumetric injection rate) divided by the cross-sectional area of the sandstone layers. As an approximation, the surface velocity corresponds to the frontal advance rate of the water of low salinity in the reservoir.

The superficial velocity of the water of low salinity in the sandstone layers of a deposit is usually in the range of 0.05 to 5 feet / day (0.015 to 1.5 meters / day) and more often in the range of 1 to 4 feet per day (0.3 to 1.2 meters / day ). However, as discussed below, the surface velocity may be limited by the permeability of the sandstone rock or the reservoir injection capacity.

Sandstone layers interspersed in a reservoir can be isolated from each other in such a way that there is a single flow path for low salinity water through each layer of sandstone from the injection well to the production well. Alternatively, the sandstone layers of a reservoir may be hydraulically interconnected due to fractures or defects in the shale layers or to the shale layers not being contiguous with the sand layers throughout the entire distance between wells. the injection well and the production well. In this situation, the salinity injection water finds many flow paths through the hydraulically connected sandstone layers of the reservoir and it is the average surface velocity of the low salinity water through the sandstone layers that is determined .

Usually, each of the reservoir's sandstone layers has a permeability of at least 1 millidarcy, and more often at least 500 millidarcy. In In general, the permeability of each of the sandstone layers of the deposit is in the range of 1 to 1000 millidarcy. The permeability of the interspersed sandstone layers of the deposit can be determined, for example, from measurements made on control samples taken from the reservoir using conventional techniques. - The superficial velocity for water of low salinity can vary with the variation of permeability of the sandstone rock.

The surface velocity of the low salinity water through the sandstone layers of the reservoir may also depend on the reservoir's injection capacity. The reservoir's injection capacity refers to the rate and pressure at which injection fluids can be injected into a reservoir from an injection well without hydraulically fracturing the reservoir. Therefore, the pressure in the injection well should be above the reservoir pressure but below the pressure at which fractures in the reservoir rock begin to be induced. The fracture induction pressure will be reservoir specific and can be easily determined using techniques well known to those skilled in the art. Depending on the reservoir pressure and the fracture induction pressure, the water injection pressure of Salinity can be found in the range of 6,500 to 150,000 kPa Absolute, and more specifically, 10,000 to 100,000 KPa Absolute (100 to 1000 absolute bar). Therefore, the surface velocity for the water of salinity can be increased by increasing the injection pressure and therefore the rate at which the low salinity water is injected into the reservoir.

In the example system shown in Figure 1 there is only one injection well and one production well; however, in other embodiments there may be more than one injection well and more than one production well in the reservoir. Wells can be found on land or can be found offshore.

On land, there may be many different spatial arrangements between injection wells and reservoir production wells. For example, injection wells can be found around a production well. As an alternative, the injection wells can be found in two or more rows between each one of which there are production wells. However, regardless of the spatial arrangements of the wells, it is generally the case that the distance between wells L between any injection well and its associated well or production wells is less than 3000 feet. Usually, the distance between wells is in the range of 1000 to 2000 feet. Decreasing the distance between wells L between an injection well and its associated production wells reduces the residence time of low salinity water in the reservoir's sandstone layers.

Offshore, there are usually fewer production wells and injection wells that result in a larger well spacing L of, say, 3000 feet, thereby reducing an operator's ability to control residence time t of water of low salinity in the sandstone layers of the deposit. Therefore, it may be necessary to select a reservoir for a flood of low salinity water dependent on one or more of the other parameters that have been listed above.

Embodiments of the invention provide computer systems, and computer-implemented methods that can be used to assist in performing a flood with low salinity water such as described above with reference to Figure 1. To do this, Embodiments of the invention may include a computer system that performs flooding software components with salinity water (LSW) that enable the system to: determine the effectiveness of flooding with water of low salinity in the reservoir; control a flood with low salinity water inside the reservoir; determine an estimate for the recovery of hydrocarbons for a flood with salinity water carried out in the deposit; Y determine locations of the production and injection wells according to an embodiment of the invention.

The computer system can be found in a planning and control center (which can be found at a substantial distance from the site, including in a different country). Alternatively, the computer system may be part of the reservoir control systems, such as the control stations 118 and 122 as shown in Figure 1. The software components of the LSW may comprise one or more applications such as they are known in the art, and / or may comprise one or more supplementary modules for the existing software.

A schematic block diagram showing such a computer system will be described below with reference to Figure 2. The computer system 200 comprises a processing unit 202 having a processor, or CPU, 204 which is connected to a memory. volatile (i.e., RAM) 206 and a non-volatile memory (such as a hard disk) 208. The software components of LSW 209, which carry instructions for implementing embodiments of the invention, can be stored in the non-volatile memory 208. In addition, the CPU 204 is connected to one. user interface 210 and a network interface 212. The network interface 212 can be a wired or wireless interface and is connected to a network, represented by the cloud 214. Therefore, the processing unit 202 can be connected with sensors , databases and other sources and receivers of data through the network 214.

In use, and in accordance with conventional procedures, the processor 204 retrieves and executes the LSW 209 software components stored in the non-volatile memory 208. During the execution of the software components of the LSW 209 (i.e., when the computer system is performing the actions described above) the processor may store data temporarily in the volatile memory 206. The processor 204 may also receive data (as described in more detail hereinafter), through the user interface 210 and the network interface 212, as required to implement embodiments of the invention. For example, the data can be entered by a user through the user interface 210 and / or received from for example a remote sensor in a production well through network 214 and / or can be retrieved from a remote database through network 214.

These data may be generated and / or stored in a number of ways known to the skilled person. For example, diffusion coefficients (described hereafter) can be determined in a laboratory from one. witness sample in relation to the reservoir (using well-known procedures). Once determined, this data can be actively sent to the processing unit 202, or stored in a database to be retrieved as required by the processing unit 202. The alternatives will be readily apparent to the expert.

Having processed the data, the processor 204 can provide an output through either the user interface 210 or the network interface 212. If required, the output can be transmitted through the network to remote stations, such as the control station for an injection well. Such procedures will be readily apparent to the skilled person and will therefore not be described in detail.

Examples of computer-implemented methods by which the computer system described above can function to implement Embodiments of the invention will be described hereinafter; however, in order to place these methods in context, the inventors of the present invention will now describe some background information in relation to the diffusion of the ions in the water of ba to salinity that is flowing through a reservoir.

Ions (eg, salt ions) can diffuse from a shale layer to an adjacent sandstone layer relatively slowly, compared to a residence time t typical for water of low salinity in the sandstone layers of the deposit. Accordingly, the concentration gradient, and hence the direction of diffusion in the layers, can be considered to be substantially perpendicular to the schist-sandstone boundary, and, in that sense, the diffusion can be considered to be one-dimensional.

In addition, the shale layers can be considered to be of sufficient size, and to have a sufficiently high concentration of ions that they can be modeled as an unlimited source of ions. In other words, the fraction of low salinity water liquid represents only a small fraction of the volume of congenital water in the shale layers. One consequence of this is that the concentration of ions at the border can be considered between the schist and the sandstone is constant.

Finally, the sandstone layer can be considered a semi-infinite medium; that is, the portion of the layer in question is bounded on one side by the shale, but extends to infinity from here. This is an approximation, because the sandstone layer will be limited on the other side (most likely, by another layer of shale), however, this is valid for the given examples.

An analytical expression for the one-dimensional diffusion of ions from a source of constant composition in a semi-infinite porous medium of permeability (for example from shale to sandstone) is given by the following one-dimensional solution to the Fick's law: (Equation 1) where z is the distance (depth) within the sandstone measured from the boundary surface of the sandstone and shale, C0 is the concentration of the ion at z = 0 (ie the concentration in the shale layer) , Da is the apparent diffusivity of the ions within the sandstone, t is the time and C (z) is the concentration of the ion in diffusion in the porous medium at a depth of z.

Figure 3 shows a graphical representation of C (z) / C0 versus distance (z). Five lines are shown, each curve being constructed using different values of 2VDat. It can be seen from figure 3, that the concentration decreases with depth. In addition, the longer the residence time (proportional to L / v), the greater the diffusion.

As can be seen, to minimize the degree of diffusion, it is desirable to have a short residence time t. As a consequence, it is desirable to use a small well distance L and a superficial and high velocity. However, this may be difficult to achieve for both economic and technical reasons. For example, in offshore locations, the cost of drilling additional wells to achieve distances between smaller desired wells can be prohibitively expensive. To overcome these problems, it is desirable to be able to identify the conditions under which a flood of low salinity water will be effective, and to determine the effectiveness of any flooding with salinity water that could be performed under such conditions.

Referring to equation 1, it can be seen that at a value of z = 2Vüat, the concentration ratio (C / CO) has a value of approximately 0.16. Therefore, the distance d = 2 ^ Dat can be considered as the "penetration distance" (d), which represents the time-dependent distance within which 87% of the diffusing ions are present. Since the residence time 't adopts the value of L / v in which L and v are the distance between wells and the superficial velocity of the flood with water respectively, the depth of penetration d can be written again as: (Equation 2) To calculate a measure of the effectiveness of a flood with low salinity water, the penetration depth can be used to calculate a "boundary layer" thickness x. This boundary layer represents the portion of each layer of sandstone that is strongly affected by the diffusion of the ions to the sandstone layer from the surrounding shale layer. Within the boundary layer, it is assumed that there is no progressive recovery of oil (ie, there is no recovery of any additional oil from the boundary layer when compared to a flood with water). of high salinity). Conversely, outside the boundary layer, it is assumed that ion diffusion has no effect on flooding with low salinity water.

It will be evident that the boundary layer increases in thickness as the distance from the injection well increases. The thickness will effectively be zero in the injection well (because there has been no opportunity for the ions to diffuse into the low salinity water). On the contrary, the thickness of the boundary layer will be at a maximum in the production well. This average thickness of the boundary layer (x) can be calculated from the depth of penetration (d) as obtained from equation 2 as: (Equation 3) In equation 3, the empirical constant A can be made to vary to fit the equation, Da and L can be known and relatively constant. The velocity v can be a measure of the surface velocity through the reservoir; however, this is not a requirement, and any appropriate speed measurement can be used. Normally, there will be a boundary layer on the top and on the under a layer of sandstone sandwiched between the layers of shale.

Usually, A will have a value of 0.5 (assuming that the limit layer grows uniformly from the injection well to the production well), however, other values can be used. For example, if it is discovered that a particular reservoir is strongly affected by the diffusion of the ions, or that the concentration of the ions in the shale layers is atypically high, A can be increased to have a value of for example 1 or 2 The skilled person can empirically find appropriate values of A, for example by comparing the differences in the simulation results with the results obtained using embodiments of the invention.

The surface velocity v can be made to vary by changing the injection pressure, and consequently it can be made that the value of v to be used in this equation varies with dependence on other factors. For example, the maximum surface velocity that can be used across the reservoir can be limited by, for example, the maximum injection pressure that can be used without hydraulically fracturing the reservoir, or the maximum surface velocity that can be economically possible. In some embodiments of the invention, the surface velocity v used in equation 3 can be a fraction / predetermined percentage of the maximum (such as 80% of the maximum). Various methods of obtaining v. they will be apparent to the expert, and anyone can be used within the scope of the invention.

To give an example, if L is 2000 feet, v is 1 foot / day and Da is 1.33? 10-9 m / s (an appropriate value for NaCl in sandstone), then if A = 0.5, the average boundary layer thickness is approximately 0.5 m (1.5 feet).

The effectiveness of a flood with low salinity water can be calculated using a diffusion degradation factor (F) for the reservoir. In general, the diffusion degradation factor can be considered to be a measure of the ratio of the amount of additional oil that is recovered when diffusion is taken into account with respect to the amount of additional oil that is recovered when the diffusion of the ions is ignored. In the present case, the "additional" oil is the amount of oil recovered by the flood with water, of low salinity compared to the flood with water of high salinity.

One method of calculating this diffusion degradation factor is to compare the total thickness of the non-limiting layers in the reservoir with the total thickness of the global sandstone layers. Mathematically this can be represented as : (Equation 4) where, wn is the thickness of a layer (each layer indexed by n) and x is the average boundary layer thickness that has been calculated above (the coefficient 2 appears because there are two boundary layers per layer of sandstone) ).

Equation 4 is simplified in: (Equation 5) where H is the arithmetic mean of the thicknesses of the sandstone layers: (Equation 6) This equation assumes that, within the boundary layers there is no recovery of any additional oil that results from a flood with water of low salinity, while on the outside of the boundary layers, the recovery of additional oil is not affected by the diffusion of salts. Equations 4 and 5 imply a negative contribution to the recovery of additional oil from ba to salinity in the presence of diffusion when wn < 2x This can lead to underestimating the diffusion degradation factor F. Therefore, equation 4 can, for example, be modified so that it only applies when wn = 2x.

A computer-implemented method of determining the effectiveness of flooding with low salinity water according to an embodiment of the invention will be described below with reference to Figure 4. The steps described hereinafter can be performed by the processor 204 executing the software components of LS 209 as described above with reference to figure 2. It will be assumed hereinafter that any initialization step required to initialize the computer system 200, and to recover the components of the LSW software has been performed before the start of the method as described from step 402 hereafter.

In step 402 the data indicative of values for the distance between wells (L), the diffusion coefficient (Da), 4 O the surface velocity (v), and the thicknesses (wn) of the sandstone layers in the deposit are received by the processing.

With reference to Figure 1, each layer has a thickness wn in which n is an index for the layer (in Figure 1, there are three layers, hence n = 1, 2 or 3). In addition, as shown in Figure 1, the layers may have variable thicknesses. Accordingly, the thickness data for a layer having a variable thickness can be calculated from, for example, an average thickness of the layer, or from a minimum thickness of the layer (other possibilities can be devised by the skilled person).

The above data can be received through interfaces 210 or 212 as shown in Figure 2.

Data can be provided from a number of sources, including a reservoir model, witness samples, database query etc. The possible sources of such data will be readily apparent to the expert.

In step 404 the processor 204 calculates a diffusion distance value of the ions (x) from Da, L, v and A. The diffusion distance value of the ions can, as in the present embodiment, be the thickness of average boundary layer. Therefore this calculation can be done using equation 3 that has been shown above, and that repeat in the present case (Equation 3) In step 406, the processor 204 calculates the arithmetic mean of the thickness (which is represented as H) of the sandstone layers using equation 6, reproduced in the present case: (Equation 6) In step 408 the processor 204 calculates a diffusion degradation factor (F) from H and x using equation 5, which is reproduced in the present case: (Equation 5) The diffusion degradation factor F can be used in a number of ways. First, as shown in step 410, the diffusion degradation factor F can be used in generating an estimate for the recovery of oil from the reservoir. This can be done by the processor 204, or the diffusion degradation factor F can be provided to a reservoir modeling system to be used in the generation of oil recovery estimates. An example of this use can be to multiply an estimate of the progressive oil recovery from the flood with low salinity water that is provided by the model by the diffusion degradation factor F, however, for the expert methods will be evident alternative A second use of the diffusion degradation factor is described in steps 412 to 418. In step 412 the diffusion degradation factor F is compared to a threshold. The threshold may have a predetermined value, which may be, for example, in the range of 0.5 to 0.9. Preferably the threshold has a value in the range of 0.6 to 0.8. On the basis of the comparison, a determination can be made as to whether a flood with low salinity water should be made.

Therefore, in step 414, it is determined whether F is more large than the threshold value. If F is larger, then it is considered that this indicates that the flood should be carried out with water of low salinity. Alternatively, if F is less than the threshold, flooding with low salinity water is not performed.

In the method that has been described above, the diffusion distance value of the ions (x) can be calculated in step 404 from Da and t. If this is the case, the processor may, at step 402, receive a value of t instead of the values of L and v. Similarly, while the processor 204 is described as calculating the average (middle) layer thickness (H) for the reservoir, from the single layer thickness, it will be readily apparent that this value can be provided directly to the processor.

The above method can be applied to some examples of deposits, where, L = 2000 feet, v = 1 feet / day, Da = 1.33 x 10-9 m2 / s, and A = 0.5. From these, x can be calculated as 0.48 m. Using Equation 5, the diffusion degradation factor F can be calculated for a variety of different reservoirs having different layer thicknesses. The results obtained for a variety of reservoir descriptions were compared with detailed simulations that were carried out with a finite difference simulator that models the effect of a flooding with water of ba salinity and diffusion of salts on the recovery of oil. The results are shown in Figure 7. In this example, the best match between the method described in the present case and the reservoir simulation results was obtained using the default value of A = 0.5.

In addition to determining the diffusion degradation factor F, the limit layer thickness x can be used to calculate a target surface velocity or threshold for flooding with low salinity water. This can be useful because, as mentioned above, the surface velocity of the flood with water can be made to vary by varying the injection pressure, therefore, providing a speed threshold. objective, or minimum, the effectiveness of flooding with low salinity water can be assured.

First, combining equations 3 and 5, which are reproduced in the present case: (Equation 3) (Equation 5) A relationship can be established between the surface velocity v and the degradation factor F, specifically: (Equation 7) Equation 7 can be rearranged to produce equation 3: (Equation 8) It is desirable to ensure that the velocity is high enough to maintain the diffusion degradation factor F at, around, or above a desired target or limit. Therefore, taking Fobjective as the target value for the diffusion degradation factor F, the target velocity can be obtained as: (Equation 8a) The target velocity can then be used in the control of the injection well to ensure that the surface velocity of the flood with water is maintained at, around, or above the target. Various methods of doing this will be apparent to the skilled person, for example, the surface velocity can be maintained within a predetermined range around or above the objective target velocity as an alternative the surface velocity can be controlled to always be above the target velocity Vobjective with other factors (if required) determining a maximum speed.

As mentioned above, the diffusion degradation factor F represents the proportion of additional oil that is recovered by the flooding with water of ba to salinity, taking the diffusion into account in the case in which the diffusion is ignored. of the ions. In that sense, this represents a measure of the potential success of the flood with water. Consequently, the target value for the diffusion degradation factor Fobjective can be used to represent a minimum acceptable or ideal value that it should be achieved in order for the flooding with water to be successful (either in practice, in terms of, for example, the amount of water available or economically available). As a consequence, maintaining the speed of the flood with water so that it is above, or at, the target velocity will ensure that the effectiveness of the flood with water is equally above or on the target.

A computer-implemented method of controlling a flood with salinity water according to an embodiment of the invention will now be described with reference to Fig. 5. As described above with reference to Fig. 4 , the steps in the following may be performed by the processor 204 while executing the software components of the LSW 209.

In step 502 the processor receives data indicative of the distance between wells (L), the diffusion coefficient (Da), the average layer thickness (H), the constant (A), and the target diffusion degradation factor ( Fobjective). As described above, the average layer thickness (H) can be received directly, or calculated from the individual layer thicknesses (wn).

In step 504 processor 204 calculates a target surface velocity (vobjective) from Da, L, H and Objective .. This can be done using Equation 8.

The target surface velocity can then be used to control the injection pressure in the injection well to thereby control the surface velocity of the flood with water inside the reservoir. Accordingly, in step 506, the processor 204 can transmit an indication of the target surface velocity to the injection well using the interface 212.

Subsequently in step 508, the injection well control systems' control the injection well to maintain the surface velocity of the flood at an appropriate speed in view of the target surface velocity. This can be done in any number of ways, which will be obvious to the expert, and can be done by maintaining the average surface velocity of the injection fluid at the target surface velocity, or by ensuring that the surface velocity of the flood remains above the target surface velocity.

Finally, a computer implemented method of determining the locations of the production and injection wells according to an embodiment of the invention will be described with reference to Figure 6.

As described above with reference to equations 8 and 8a, a target surface velocity can be obtained. Equation 8 can be rearranged in such a way that a lh between target wells can be obtained. Specifically, equation 8 can be reordered as: (Equation 9) which provides the objective lh as (Equation 9a) This objective lh Lobj etivo can be calculated from an average value for the superficial velocity (v) as discussed above.

Therefore, with reference to Figure 6, in step 602 the processor 204 receives data indicative of the diffusion coefficient (Da), the surface velocity (v), the average layer thickness (H), the constant (A) , and the target diffusion degradation factor (Fobjective). The middle layer thickness (H) can be received directly, or calculated from the individual layer thicknesses (wn).

From these values, using Equation 9, the processor 204 obtains a length between objective wells (Lobjective). This length, being a target, can represent a maximum value for the length between wells, or it can represent the center point for a desired interval of lengths between wells (for example, Lobjective ± 10%).

In step 706 the processor 204 can emit the target wellbore length (Lobjective). In a manner similar to that described above, the Lobjective value can be issued using interfaces 210 and 212. Alternatively the value L can be used directly by the processor 204.

Finally, in step 706, the length between objective wells (Lobjective) is used in the location of the wells that perforate the reservoir. The wells may be such that the length between wells is less than the target length, or is within a predetermined factor of the length. The exact mechanism for locating the wells to be used will depend on a number of other factors, however, the length between target wells can be considered as one. guide to ensure that a flood with low salinity water will be a possibility when the wells are in production (for the reasons stated above). This stage can be carried out by the processor 204; however, this can also be done by a separate processing system that is responsible for the determination of well locations.

In the above embodiments of the invention, the calculations are described as being performed in the processing unit 202, however, this is not a requirement. Also, although the processing unit has been described as a single independent unit, this may not be the case, and for example the functionality of the processing unit may be incorporated in any other entity, or distributed through a number of entities. The software components of LSW are described as stored in memory 208, however, the software components of LSW can alternatively be received through network interface 212 (from eg a remote database) . The outputs may be provided to other diverse entities, such as the well control apparatus. The mechanisms by which this can be realized will be well known to the skilled person.

Additional Details and Modifications Although the above embodiments have been described in relation to the diffusion degradation factor F, which defines the recovery ratio of oil with and without diffusion, it will be apparent that a "factor of loss of "alternative" diffusion (G) that defines the "lost" oil ratio with respect to the total oil recovery.As a result, G can be defined as G = 1 - F = 2x / H. It will be evident that G and F have a very simple relationship, therefore, the expert would have no difficulty in the use of either in embodiments of the invention.

Although a method of determining and using a boundary layer thickness has been described above, other possibilities are devised without departing from the scope of the invention.

For example, the layers can be classified either as "marginal facies" or "axial facies". This can be done using the boundary layer thickness. For example, "marginal facies" may indicate interspersed layers of sandstone and schist in which the sandstone layers are strongly affected by the diffusion of salt ions and, in view of the above, can be defined as layers that have a thickness comparable to, or thinner than, twice the thickness of boundary layer x (which means that the entire sandstone layer is defined as the boundary layer). On the contrary, the "axial facies" are interspersed sandstone layers in which the sandstone layers are thicker than four times this thickness of boundary layer x. The threshold used to classify these layers (above 4x) can adopt other values, such as 5x or 6x. Having classified the layers, a diffusion degradation factor can then be determined on the basis of the thickness of the aggregate (axial) thickness layers with respect to the total thickness of all the layers.

It will be evident that equation 5 will tend to underestimate the diffusion degradation factor in cases where there are many layers less than twice the thickness of the boundary layer (because it is assumed that there are two full boundary layers for each layer). , regardless of whether the layer is too thin to contain two such layers - and for layers less than twice the thickness of the boundary layer, it will be assumed that the boundary layers do indeed overlap).

Consequently, the method can be adapted to take this into account. One method by which this can be done is to define an effective non-boundary thickness (in) for each layer that takes this overlay into account, ie: (Equation 9) from in, the diffusion degradation factor F can be calculated using a modified version of the equation 4 as follows: (Equation 10) In Equation 10, the diffusion degradation factor F is therefore the sum of the effective thicknesses divided by the sum of the layer thicknesses.

In the previous examples, the "apparent diffusion coefficient" has been used to define the diffusion rate of the ions through the sandstone. However, the expert will recognize that there are a number of different types of diffusion coefficient that could be used. For example: a bulk diffusion coefficient refers to the diffusion of ions in a bulk liquid; a pore diffusion coefficient takes into account the tortuosity of the pores in the sandstone that limit diffusion; finally, the apparent diffusion coefficient takes into account both tortuosity and ion sorption. For a non-sorbent ion, the pore diffusion coefficient is the same as the apparent diffusion coefficient, however, this is not the case for a sorbent ion. The skilled person will therefore understand that any suitable diffusion coefficient can be used in embodiments of the invention without departing from the scope of The claims. ' Also, the methods described above refer to salt ions that are non-sorptive in sandstone. However, it will be apparent to the skilled person that the invention can be adapted to ions that are sorbent in sandstone (with appropriate adaptation of the diffusion coefficient).

The salt shale divivities can be determined experimentally with a sufficient degree of accuracy to determine the effect of salt diffusion on the progressive oil recovery that can be achieved by flooding with water of low salinity. Because the rate of salt diffusion is proportional to the concentration gradient between the high salinity congenital water that is contained in the pore space of the shale layer and the low salinity water that is flowing through the pore space of an adjacent sandstone layer, it is important to determine the salinity of the congenital water that is present in the shale layers together with the concentrations of the individual ionic (salt) species in this congenital water, in particular, the concentration of the various multivalent cations together with the total concentration of multivalent cations in this congenital water.

Consequently, samples of the congenital water that is present in the pore space of the sandstone layers and in the pore space of the interspersed shale layers can be obtained by taking a core sample from the reservoir through the different layers of the Deposit. Then, from them, the TDS and the multivalent cation content of the water that is contained within the different layers of the control can be determined.

The low salinity water that is injected into the sandstone layers of the oil field can have a total dissolved solids (TDS) content in the range of 200 to 12,000 ppm, preferably, 500 to 10,000 ppm. When the formation rock contains swellable clays, in particular smectite clays, a relatively high TDS is required for the low salinity water in order to stabilize the clays, thereby avoiding the risk of formation damage. Therefore, when the formation rock contains a quantity of swellable clays sufficient to result in formation damage, the water of salinity which is injected into the oil-containing formation preferably has a TDS content in the range of 8,000 to 12,000 ppm. When the formation comprises amounts of swellable clays that do not result in formation damage, the TDS content of the low salinity water is it is usually in the range of 200 to 8,000 ppm, preferably 500 to 8,000 ppm, and for example it can be from 1,000 to 5,000 ppm. In this context, it is observed that an overall increase in salinity of low salinity water can be tolerated provided the salinity of the low salinity water remains within the desired range for flooding with low salinity water.

The concentration gradient between the congenital water that is present in the shale layer and the low salinity injection water that is flowing through an adjacent sandstone layer is particularly significant when the congenital water from the shale layer has a TDS of at least 100,000 ppm, especially, at least 200,000 ppm, for example, is in the range of 150,000 to 400,000 ppm, in particular, 150,000 to 250,000 ppm.

The progressive oil recovery that is achieved for a flood with low salinity water depends on the ratio of the total multivalent cation content in the low salinity injection water that is injected into the sandstone layers of the reservoir with respect to the cation content total multivalent in the congenital water that is present in the pore space of the sandstone layers of the reservoir (hereinafter referred to as "multivalent cation ratio"). It has previously been found that this reason of multivalent cations should be less than 1, for example, less than 0.9. In general, the lower the ratio of multivalent cations the greater the amount of oil that is recovered from the deposit. Therefore, the ratio of multivalent cations is preferably less than 0.8, more preferably, less than 0.6, even more preferably, less than 0.5, and especially less than 0.4 or less than 0.25. The ratio of multivalent cations may be at least 0.001, preferably, at least 0.01, most preferably, at least 0.05, in particular at least 0.1. Preferred ranges for the ratio of multivalent cations are from 0.01 to 0.9, from 0.05 to 0.8, but especially from 0.05 to 0.6 or from 0.1 to 0.5. The ratio of the total divalent cation content of said low salinity injection water to the total divalent cation content of the formation water which is present in the sand layers of the reservoir (hereinafter "cation ratio") divalent ") should also be less than 1. Preferred values and ranges for the multivalent cation ratio can be applied mutatis mutandis to the divalent cation ratio.

Usually, the calcium content. of the low salinity injection water is in the range of 1 to 100 ppm, preferably 5 to 50 ppm. Usually, the Magnesium content of the low salinity injection water is in the range of 5 to 100, preferably 5 to 30 ppm. The barium content of the low salinity injection water can be in the range of 0.1 to 20, such as 1 to 10 ppm. Usually, the total content of multivalent cations in the low salinity injection water is from 1 to 200 ppm, preferably from 3 to 100, especially from 5 to 50 ppm with the proviso that the ratio of multivalent cations is less than 1.

Therefore, the diffusion of multivalent cations from the congenital water that is contained in the pore space of a shale layer in the low salinity water that is flowing through an adjacent sandstone layer of the reservoir is of interest if this gives as a result an increase in the "multivalent cation ratio" or the "divalent cation ratio" to more than 1.

Usually, the multivalent cation content of the congenital water that is contained in the pore space of the shale layer is in the range of 7,500 to 50,000 ppm, in particular 10,000 to 30,000 ppm, with higher concentrations of multivalent cations being associated with congenital waters of higher salinity.

The apparent diffusivities of non-sorbent ions in sandstone rock can be determined using the following methodology. In sandstone, the effective diffusiyity is: characterized in that DO is the crude diffusivity in aqueous solution, F is the porosity of the sandstone, m is Archie's "cementing factor", and F is the formation resistance factor. For a typical sandstone rock, the carburizing factor, m, is within the range of 1.7 to 2.7. If it is considered that DO is 3.1 x 10-9 m2 / s (this is the value for the harmonic average of crude diffusivity of Na + and Cl- ions at a temperature of 132.8 ° F), then for a rock of sandstone having a porosity of 0.3, the effective diffusivity, De, is within the range of 1 x 10-10 to 4"x 10-10 m2 / s for the indicated range of m. Apparent, Da = D0 * (|) m-1, for a non-sorbent ion (such as Na + or C1-) is within the range of 4 x 10-10 to 1.33 x 10-9 m2 / s for the indicated range of m.

The following relationships between the chemical characteristics of the congenital water that is contained in the pore space of the shale layers and the chemical characteristics of the low salinity injected water can have an impact on the recovery of progressive oil that is get a flood with low salinity water: (a) the difference in TDS between the low salinity water that is injected into the sandstone layers of the reservoir and the congenital water from a layer of interspersed shale; (b) the difference between the concentration of multivalent cations in the low salinity water that is injected into the sandstone layers of the reservoir and the concentration of multivalent cations in the congenital water of a layer of interspersed shale.

Therefore, as discussed above, the congenital water of the shale layer has both a higher TDS and a higher multivalent content of cations than the low salinity water that is injected into the sandstone layers. of the deposit. Embodiments of the invention that have been described above allow the diffusion of non-sorbent ions, however, these methods can be combined with methods to allow the effects of TDS on the shale layers.

The thickness of the interspersed shale layers can be of importance as determined by the total amount of salt ions available for diffusion from a layer of shale interspersed in the low salinity water that is flowing through a layer of sandstone. adjacent. In deposits that have layers of shale interspersed When relatively thin, the amount of salt ions available for diffusion in interspersed sandstone layers may be low. Therefore, it is thought that the thickness of the shale layers can be taken into account in the previous calculations, as thin shale layers can no longer be approximated as an unlimited supply of ions.

It is to be understood that any feature that is described in connection with any one embodiment may be used separately, or in combination with other described features, and may also be used in combination with one or more features of any other of the embodiments, or any combination thereof. any other of the embodiments. In addition, equivalents and modifications that have not been described above may also be employed without departing from the scope of the invention, which is defined in the appended claims. The features of the claims may be combined in combinations different from those specified in the claims.

Claims

NOVELTY OF THE INVENTION Having described the present invention, it is considered as a novelty and, therefore, the content of the following is claimed as property "CLAIMS

1. - A method implemented by computer to determine the effectiveness of flooding with salinity water in a reservoir containing hydrocarbons, characterized in that the reservoir includes relatively permeable layers interspersed with relatively impermeable layers and is drilled by a well of injection and a production well, including flooding with low salinity water, injecting low salinity water into the hydrocarbon-containing reservoir from the injection well, through which it passes through the relatively permeable layers of the deposit from the well. injection into the production well, and characterized in that the relatively impermeable layers have a relatively high concentration of ions compared to that of relatively permeable layers when the water of salinity is present therein, the method comprising: obtain a diffusion distance value of the ions from: a diffusion coefficient indicative of a rate of diffusion of the ions through the relatively permeable layers when the water of low salinity is present in its interior; and a residence time value indicative of the time required for low salinity water to pass from the injection well to the production well through the reservoir; compare the thickness of the relatively permeable layers with the diffusion distance value of the ions obtained; Y use a comparison result to generate an output indicative of the effectiveness of flooding with low salinity water.

2. - The method according to claim 1, comprising: determining an average thickness of the relatively permeable layers; Y calculate a ratio of the diffusion distance value of the ions with respect to the average thickness, by which to compare the thickness of the relatively permeable layers with the diffusion distance value of the ions obtained.

3. - The method according to claim 2, characterized in that an output value is emitted based on the calculated ratio, by which to generate the output indicative of the effectiveness of flooding with water of low salinity.

4. - The method according to claim 3, characterized in that the output value is calculated from ¾ || wherein x is the diffusion distance value of the ions and H is said average thickness.

5. - The method according to any of the preceding claims, characterized in that the residence time value is calculated from a distance between wells between the injection well and the production well, and a speed at which the water of the Salinity passes through the deposit.

6. The method according to claim 5, characterized in that the diffusion distance value of the ions is determined from 2AV (DaLv-l) characterized by Da being the apparent diffusion coefficient for the ions in the relatively permeable layers , L is the distance between wells between the injection well and the production well, v is the velocity of the water of low salinity through the reservoir, and A is a constant.

7. - The method according to claim 6, characterized in that the predetermined constant A has a value in the range of 0.125-2 and preferably has a value of 0.5.

8. - The method according to any of »claims 5 to 7, characterized in that the velocity of the water of low salinity through the deposit is indicative of the superficial velocity of the water of low salinity through the relatively permeable layers.

9. - The method according to any of the preceding claims, characterized in that the residence time value for water of low salinity in the reservoir is measured using a tracer injected into the reservoir through the injection well.

10. - The method according to any of the preceding claims, which comprises using the output indicative of the effectiveness of flooding with water of low salinity to calculate an estimate for the recovery of hydrocarbons from the deposit.

11. The method according to any of the preceding claims, characterized in that the relatively permeable layers comprise layers of sandstone, and the relatively impermeable layers comprise layers of shale.

12. - A method implemented by computer control of a flood with low salinity water for a reservoir containing hydrocarbons, characterized in that the reservoir comprises relatively permeable layers interspersed with relatively impermeable layers and is drilled by an injection well and a production well, Understanding flooding with low salinity water injecting water from ba to salinity in the reservoir with hydrocarbon content from the injection well through which pass through the relatively permeable layers of the reservoir from the injection well to the production well, and characterized in that the relatively impermeable layers have a relatively high concentration of ions compared to that of the relatively permeable layers when the low salinity water is present therein, the method comprising: obtain an objective velocity based on: a diffusion coefficient indicative of a diffusion rate of the ions through the relatively permeable layers when the water of low salinity is present in its interior; a distance between wells between the injection well and the production well; and a value indicative of a thickness of the relatively permeable layers; Y transmit the obtained target velocity to a control unit of an injection well.

13. The method according to claim 12, comprising controlling a rate at which the water of salinity passes through the relatively permeable layers on the basis of the target velocity.

14. - The method according to claim 13, comprising control the flow of fluid through the injection well controlling the speed at which the water of ba salinity passes through the layers relatively permeable.

15. - The method according to any of the claims 12 to 14, characterized in that the target speed is ,? > -LA2 determines from / 2 (i -L> characterized by that Da is the apparent diffusion coefficient for the ions in the relatively permeable layers, L is the distance between wells between the injection well and the production well, H is a value indicative of an average thickness of the relatively permeable layers, A is a constant and Fobj etivo is a predetermined target diffusion degradation factor.

16. - The method according to claim 15, characterized in that the constant A has a value in the range of 0.125 to 2 and preferably has a value of 0.5.

17. - The method according to any of claims 12 to 16, characterized in that the predetermined target diffusion degradation factor Fob etivo is a measure of an objective effectiveness of flooding with low salinity water.

18. - The method according to claim 17, characterized in that the diffusion degradation factor obivo default Objective has a value between 0.6 and 0.9.

19. - The method according to any of claims 12 to 18, which comprises maintaining an average speed at which the water of low salinity passes through the relatively permeable layers so that it is at or above the target velocity by means of which control the speed at which low salinity water passes through the relatively permeable layers.

20. - The method according to any of claims 12 to 18, which comprises maintaining a minimum speed at which the water of low salinity passes through the relatively permeable layers so that it is above the target velocity by which to control the speed to which the low salinity water passes through the relatively permeable layers.

21. The method according to any of claims 12 to 20, characterized in that the relatively permeable layers comprise layers of sandstone, and the relatively impermeable layers comprise layers of shale.

22. - A computer-implemented method for determining the locations of at least one production well and at least one injection well for a hydrocarbon-containing reservoir, characterized in that the reservoir comprises relatively few layers permeable interleaved with relatively impermeable layers and has to be drilled by the at least one injection well and at least one production well, characterized in that the injection well is arranged to provide a flood with low salinity water comprising injecting water of low salinity in the reservoir with hydrocarbon content from the injection well through which it passes through the relatively permeable layers of the reservoir from the injection well to the production well, and characterized in that the relatively impermeable layers have a relatively high concentration of ions compared to that of relatively permeable layers when the low salinity water is present therein, the method comprising: calculate a value of 'distance between wells on the basis of: a diffusion coefficient indicative of a diffusion rate of the ions through the relatively permeable layers when the water of low salinity is present in its interior; a value indicative of a thickness of the relatively permeable layers; and a speed at which low salinity water passes through the reservoir; Y use the distance value between wells to determine the locations of the at least one injection well and the at least one production well in such a way that the distance between wells between said at least one injection well and at least one production well is less than said distance value between wells.

23. - The method according to claim 22, characterized in that the distance value between wells is determined from characterized by that Da is the apparent diffusion coefficient for the ions in the relatively permeable layers, H is a value indicative of an average thickness of the relatively permeable layers, A is a constant, v is a water velocity of low salinity through the reservoir, and is a predetermined target diffusion degradation factor.

24. - The method according to claim 23, characterized in that the constant A has a value in the range of 0.2 to 2 and preferably has a value of 1.

25. - The method according to claim 23 or claim. 24, characterized in that the predetermined target diffusion degradation factor Fobjective is a measure of an objective effectiveness of the flood with low salinity water.

26. - The method according to claim 25, characterized in that the predetermined target diffusion degradation factor Fobjective has a value between 0.6 and 0.9.

27. The method according to any of claims 22 to 26, characterized in that the relatively permeable layers comprise layers of sandstone, and the relatively impermeable layers comprise layers of shale.

28. - A computer reading support that stores computer-readable instructions thereon for execution in a computer system to implement a method for determining the effectiveness of flooding with salinity water in a reservoir containing hydrocarbons, characterized by that the reservoir comprises relatively permeable layers interspersed with relatively impermeable layers and is perforated by an injection well and a production well, flooding with low salinity water injecting low salinity water into the hydrocarbon-containing reservoir from the injection well through which to pass through the relatively permeable layers of the reservoir from the injection well to the production well, and characterized in that the relatively impermeable layers have a relatively high concentration of ions compared to that of the relatively permeable c When low salinity water is present inside, the method includes: obtain a diffusion distance value of the ions from: a diffusion coefficient indicative of a diffusion rate of the ions through the relatively permeable layers when the water of low salinity is present therein; and a residence time value indicative of the time required for low salinity water to pass from the injection well to the production well through the reservoir; compare the thickness of the relatively permeable layers with the diffusion distance value of the ions obtained; Y use a comparison result to generate an output indicative of the effectiveness of flooding with low salinity water.

29. A computer reading support that stores computer-readable instructions thereon for execution in a computer system to implement a computer-implemented method for controlling a flood with low salinity water for a hydrocarbon-containing reservoir, characterized by that the reservoir comprises relatively permeable layers interspersed with relatively impermeable layers and is perforated by an injection well and a production well, comprising flooding with water of low salinity injecting water of ba to salinity in the reservoir containing hydrocarbons from the injection well through which pass through the relatively permeable layers of the reservoir from the injection well to the production well, and characterized by the relatively impermeable layers they have a relatively high concentration of ions compared to that of relatively permeable layers when the low salinity water is present therein, the method comprising: obtain an objective velocity on the basis of: a diffusion coefficient indicative of a diffusion rate of the ions through the relatively permeable layers when the water of low salinity is present in its interior; a distance between wells between the injection well and the production well; and a value indicative of a thickness of the relatively permeable layers; Y transmit the obtained target velocity to a control unit of an injection well.

30. - 'A computer reading support that stores computer-readable instructions in it for execution in a computer system to implement a computer-implemented method of determining- locations of at least one production well and therefore less an injection well for a reservoir containing hydrocarbons, characterized in that the reservoir comprises relatively permeable layers interspersed with relatively impermeable layers and has to be drilled by the at least one injection well and at least one well of production, characterized in that the injection well is arranged to provide a flood with low salinity water which comprises injecting water of ba to salinity in the reservoir with hydrocarbon content from the injection well through which to pass through the layers relatively permeable from the reservoir, from the injection well to the production well, and characterized in that the relatively impermeable layers have a relatively high concentration of ions compared to that of the relatively permeable layers when the water of low salinity is present in its interior , understanding 'the method: calculate a distance value between wells based on: a coefficient of. indicative diffusion of a diffusion rate of the ions through the relatively permeable layers when the water of low salinity is present in its interior; a value indicative of a thickness of the relatively permeable layers; and a speed at which low salinity water passes through the reservoir; Y use the distance value between wells to determine the locations of the at least one injection well and the at least one production well in such a way that the distance between wells between said at least one injection well and at least one production well. is less than said 'distance value between wells.