Classifications

• • E—FIXED CONSTRUCTIONS
  • E21—EARTH OR ROCK DRILLING; MINING
  • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
  • E21B49/00—Testing the nature of borehole walls; Formation testing; Methods or apparatus for obtaining samples of soil or well fluids, specially adapted to earth drilling or wells
• • E—FIXED CONSTRUCTIONS
  • E21—EARTH OR ROCK DRILLING; MINING
  • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
  • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
  • E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
  • E21B43/20—Displacing by water

Definitions

• This invention relates to systems and methods for determining the effectiveness of, and for performing, a low salinity waterflood on a hydrocarbon-bearing reservoir.
• this invention relates to systems and methods to be used when the reservoir comprises relatively permeable layers interbedded with relatively impermeable layers and where 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.
• a hydrocarbon-bearing reservoir typically takes the form of a plurality of sandstone layers interbedded with shale layers.
• the sandstone layers have sufficient porosity and permeability to store and transmit fluids (for example oil and water). Typically the oil is held in pores of the rock formation.
• the shale layers are relatively impermeable to these fluids.
• Secondary recovery techniques are therefore often used to force additional oil out of the reservoir.
• a secondary recovery technique is to directly replace the oil with a displacement fluid (also referred to as an injection fluid), usually water or gas.
• EOR Enhanced oil recovery
• EOR techniques is not only to restore or maintain reservoir pressure (as is done by typical secondary recovery techniques), but also to improve the displacement of the oil from the reservoir, thereby maximizing the recovery of oil from the reservoir and minimizing the residual oil saturation of the reservoir (the volume of oil present in the reservoir).
• Waterflooding is one of the most successful and extensively used secondary recovery methods. Water is injected, under pressure, into reservoir rock layers via injection wells. The injected water acts to help maintain reservoir pressure, and sweeps the displaced oil ahead of it through the rock towards production wells from which the oil is recovered.
• the water used in waterflooding is generally saline water from a natural source (such as seawater) or may be produced water (i.e. water that is separated from the crude oil at a production facility).
• low salinity waterflooding can increase the amount of oil recovered compared to that recovered using high salinity water since the low salinity water is better able to displace the oil from the reservoir .
• the water used in a low salinity waterflood typically 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.
• a low salinity waterflood is particularly beneficial when oil that is present in the sandstone layers of the reservoir (typically oil that is adhering to the surface of the sandstone rock) is a medium or light crude having an American Petroleum Institute (API) gravity of at least 15°, preferably at least 20°, and for example an API gravity in the range of20° to 60°.
• API American Petroleum Institute
• the low salinity injection water is injected into and flows through the sandstone layers of the reservoir.
• little water flows through the relatively impermeable shale layers.
• shale is often so impermeable that the interbedded shale layers of the reservoir remained unsaturated with oil during migration of oil from a source rock into the sandstone layers of the reservoir. Instead, the shale layers are saturated with connate water that is typically of high salinity.
• the dominant mass transfer mechanism from the connate water of the shale layers to low salinity water that is flowing through the adjacent sandstone layers of a reservoir is molecular diffusion, whereby salt ions diffuse from the connate water in the shale layer to the low salinity water in the sandstone layer.
• the molecular diffusion of salt ions from the shale layer occurs 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 concentration gradient).
• the diffusion of the salt ions from higher salinity connate water present in the pore space of the shale layers can reduce the effectiveness of a low salinity waterflood by increasing the salinity of the water flowing through the sandstone layers. It is therefore an object of the invention to improve the effectiveness of low salinity waterflooding.
• a computer- implemented method for determining the effectiveness of performing a low salinity waterflood on a hydrocarbon-bearing reservoir wherein the reservoir comprises relatively permeable layers interbedded with relatively impermeable layers and is penetrated by an injection well and a production well, the low salinity waterflood comprising injecting low salinity water into the hydrocarbon-bearing reservoir from the injection well whereby to pass through the relatively permeable layers of the reservoir from the injection well to the production well, and wherein 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: deriving an ion diffusion distance value from: a diffusion coefficient indicative of a rate of diffusion of ions through the relatively permeable layers when the low salinity water is present therein; and a residence time value indicative of the time required for the low salinity water to pass from the injection well to
• Performing a low salinity waterflood requires, amongst other things, a significant quantity of low salinity water, which is generally not available in abundance. This means that it is important to be able to determine a measure of how effective the low salinity waterflood will be. Such a determination may be made by performing a fine scale reservoir simulation; however this requires a large amount of computing resources to perform, typically many hours of processing using a mainframe or 'supercomputer'. By deriving the ion diffusion distance value and comparing this to the thickness of the layers in the reservoir, an output indicative of the effectiveness of performing a low salinity waterflood can be generated using significantly reduced computing resources. The output can ensure that only effective low salinity waterfloods are performed, and therefore that the limited supply of low salinity water is used to maximum effect.
• a computer- implemented method of controlling a low salinity waterflood for a hydrocarbon-bearing reservoir wherein the reservoir comprises relatively permeable layers interbedded with relatively impermeable layers and is penetrated by an injection well and a production well, the low salinity waterflood comprising injecting low salinity water into the hydrocarbon- bearing reservoir from the injection well whereby to pass through the relatively permeable layers of the reservoir from the injection well to the production well, and wherein 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: deriving a target velocity based on: a diffusion coefficient indicative of a rate of diffusion of ions through the relatively permeable layers when the low salinity water is present therein; an interwell distance between the injection well and the production well; and a value indicative of a thickness of the relatively permeable layers; and transmitting
• a computer- implemented method of determining locations of at least one production well and at least one injection well for a hydrocarbon-bearing reservoir wherein the reservoir comprises relatively permeable layers interbedded with relatively impermeable layers and is to be penetrated by the at least one injection well and at least one production well, wherein the injection well is arranged to provide a low salinity waterflood comprising injecting low salinity water into the hydrocarbon-bearing reservoir from the injection well whereby to pass through the relatively permeable layers of the reservoir from the injection well to the production well, and wherein 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: calculating an interwell distance value based on: a diffusion coefficient indicative of a rate of diffusion of ions through the relatively permeable layers when the low salinity water is present therein; a value indicative of a thickness of the relatively per
• this aspect of the invention calculates an interwell distance value, based on the parameters which will affect a low salinity waterflood, and uses this value to determine the positioning of the wells.
• Figure 1 shows a schematic diagram of an oil recovery system and a reservoir in respect of which embodiments of the invention are applicable;
• Figure 2 shows schematic diagram of a processing system in which embodiments of the invention may operate
• Figure 3 shows a plot showing the diffusion of ions
• Figure 4 shows a computer implemented method of determining the effectiveness of performing a low salinity waterflood according to an embodiment of the invention
• Figure 5 shows a computer implemented method of controlling a low salinity waterflood according to an embodiment of the invention
• Figure 6 shows a computer implemented method of determining locations of the production injection wells according to an embodiment of the invention.
• Figure 7 shows a plot showing results obtained by an embodiment of the invention compared to results obtained by fine-scale reservoir simulation.
• FIG. 1 is a schematic block diagram showing a simplified representation of a crude oil recovery system 100.
• the reservoir comprises a series of interbedded permeable and impermeable layers.
• the permeable layers in this example sandstone
• the impermeable layers in this example shale
• Above the top impermeable layer 108 is shown a generalized surface layer 116 which may comprise multiple, non-oil bearing layers, and (if the reservoir is offshore) a layer of seawater. The composition of these layers is not relevant to this example.
• the permeable and impermeable layers make up the reservoir. Penetrating 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. (Typically there are many more wells than the two shown here; however two are shown in this exemplary embodiment for simplicity).
• each of the permeable layers (102, 104 and 106) in the reservoir has an associated thickness (wi, w 2 and w 3 respectively). As can be seen from the figure, each layer has a different thickness. In addition, it can be seen that layer 102 has a varying thickness, being of thickness w ⁇ at the injection well end, and of a narrower thickness w at the production well end. This change in thickness will be referred to later.
• the injection well When in use for a low salinity waterflood, the injection well injects low salinity water as an injection fluid under pressure into the reservoir.
• the low 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 bore of the production well (again shown by the arrows).
• the pressure of the reservoir optionally aided by pumps located in the well bore of the production well, lifts the oil and water received from the reservoir up to the surface where it can be stored, refined and used.
• the low salinity injection water may be passed continuously into the injection well and into the sandstone layers of a reservoir.
• the low salinity injection water is passed in one or more portions (hereinafter referred to as "slugs") of a controlled volume, which is normally expressed in terms of the "pore volume” or PV.
• pore volume is used herein to mean the volume of the pore space in the sandstone rock layers between an injection well and a production well and may be readily determined by methods known to the person skilled in the art. Such methods may include measuring the time taken 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 over all flow paths between the injection well and production well.
• the volume of the slug of low salinity injection water is preferably less than 1, and may for example be less than 0.5 PV. Therefore, the slug of low salinity injection water may have a pore volume in the range of 0.2-0.9PV, and more preferably may be in the range of 0.3-0.45PV.
• a drive (or post-flush) water of higher multivalent cation content and/or higher TDS may be injected into the reservoir.
• the drive water may have a total dissolved solids (TDS) of at least 30,000 ppm, for example, 30,000 to 50,000 ppm and a multivalent cation content of at least 350 ppm.
• TDS total dissolved solids
• the water in the low salinity slug typically has a TDS content in the range of 500 to 12,000 ppm.
• Such a low salinity slug may have a multivalent cation content of less than 40ppm.
• the volume of the slug of low salinity injection water may be small yet the slug is still capable of releasing substantially all of the oil that can be displaced from the surface of the pores of the sandstone rock under the reservoir conditions.
• the volume of the slug of low salinity injection water is at least 0.2 PV, as a slug of lower volume tends to dissipate in the sandstone rock and may not result in appreciable incremental oil production.
• the slug tends to maintain its integrity within a sandstone rock (that is, it does not disperse within the rock) and therefore continues to sweep displaced oil towards a production well.
• the incremental oil recovery for a reservoir that comprises sandstone layers approaches a maximum value with a slug of at least 0.3-0.4PV. There is little additional incremental oil recovery with higher volume slugs.
• the drive water will ensure that the fractional pore volume slug of low salinity water (and hence the released oil) is swept through the reservoir to the production well.
• the injection of the drive water may be required to maintain the pressure in the reservoir.
• the drive water has a greater volume than the slug of low salinity injection water.
• the slug of low salinity water that is injected into the oil-bearing sandstone layers of the reservoir is only a fraction of the pore volume, the slug generally remains intact within the formation and continues to sweep displaced oil towards a production well.
• dispersive diffusive
• the reason why there is little diffusive mixing between the low salinity water and the formation water at the front of the slug is that there is an ion exchange reaction occurring between the monovalent cations in the low salinity water slug and the multivalent cations (predominantly divalent cations) that are binding the residual oil to the rock surface.
• the flow rate (v) and the interwell distance (L) define the 'residence time', t, of the low-salinity water in the sandstone layer(s) of the reservoir and therefore the time available for salt ions to diffuse from a shale layer into the low salinity water that is flowing through an adjacent sandstone layer of the reservoir.
• the residence time, t may be defined as Llv wherein L is the interwell distance between the injection and production wells and v is the superficial velocity of the low salinity water in the sandstone layers of the reservoir.
• the residence time of the low salinity water in the sandstone layer of the oil reservoir is low, there may be little salt diffusion from the shale layer into the low salinity water and hence an insignificant increase in the total dissolved solids (TDS) content of the low salinity water and/or its multivalent cation concentration.
• TDS total dissolved solids
• the flow rate of the low salinity water through the sandstone layers of the reservoir may be expressed as a superficial velocity, v, which is defined as the volumetric flow rate of the low salinity water through the sandstone layers of the reservoir (which can be determined from the volumetric injection rate) divided by the cross-sectional area of the sandstone layers.
• v the superficial velocity corresponds to the frontal advance rate of the low salinity water in the reservoir.
• the superficial velocity of the low salinity water in the sandstone layers of a reservoir is typically in the range of 0.05 to 5 feet/day (0.015 to 1.5 meters/day) and more often is in the range of 1 to 4 feet per day (0.3 to 1.2 meters/day). However, as discussed below, the superficial velocity may be limited by the permeability of the sandstone rock or the injectivity of the reservoir.
• the interbedded sandstone layers of a reservoir may be isolated from one another such that there is a single flow path for the low salinity water through each sandstone layer from the injection well to the production well.
• the sandstone layers of a reservoir may be hydraulically interconnected owing to fractures or faults in the shale layers or to the shale layers not being contiguous with the sand layers along the entire interwell distance between the injection well and the production well.
• the low salinity injection water finds many flow paths through the hydraulically connected sandstone layers of the reservoir and it is the average superficial velocity of the low salinity water through the sandstone layers that is determined.
• each of the sandstone layers of the reservoir has a permeability of at least 1 millidarcy, and more often at least 500 millidarcies.
• the permeability of each of the sandstone layers of the reservoir is in the range of 1 to 1000 millidarcies.
• the permeability of the interbedded sandstone layers of the reservoir may be determined, for example, from measurements made on core samples taken from the reservoir using standard techniques.
• the superficial velocity for the low salinity water may vary with varying permeability of the sandstone rock.
• the superficial velocity of the low salinity water through the sandstone layers of the reservoir may also be dependent upon the injectivity of the reservoir.
• the injectivity of the reservoir 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.
• the pressure in the injection well should be above the reservoir pressure but below the pressure at which fractures start to be induced in the reservoir rock.
• the fracture induction pressure will be reservoir specific and can be readily determined using techniques well known to the person skilled in the art.
• the injection pressure of the low salinity water may be in the range of 6,500 to 150,000 kPa absolute, and more specifically, 10,000 to 100,000 kPa absolute (100 to 1000 bar absolute).
• the superficial velocity for the low salinity water may be increased by increasing the injection pressure and hence the rate at which the low salinity water is injected into the reservoir.
• FIG. 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.
• the wells may be located on land or may be located offshore.
• injection wells may be located around a production well.
• the injection wells may be in two or more rows between each of which are located production wells.
• the interwell distance L between any injection well and its associated production well(s) is less than 3000 feet.
• the interwell distance is in the range of 1000 to 2000 feet. Decreasing the interwell distance I between an injection well and its associated production wells reduces the residence time of the low salinity water in the sandstone layers of the reservoir.
• Embodiments of the invention provide computer systems, and computer
• embodiments of the invention may include a computer system running low salinity waterflooding (LSW) software components which enable the system to:
• LSW low salinity waterflooding
• the computer system may be located in a planning and control centre (which may be located a substantial distance from the reservoir, including in a different country).
• the computer system may be part of the control systems of the reservoir, such as control stations 118 and 122 as shown in Figure 1.
• the LSW software components may comprise one or more applications as are known in the art, and/or may comprise one or more add-on modules for existing software.
• the computer system 200 comprises a processing unit 202 having a processor, or CPU, 204 which is connected to a volatile memory (i.e. RAM) 206 and a non-volatile memory (such as a hard drive) 208.
• the LSW software components 209 carrying instructions for implementing embodiments of the invention, may be stored on the non-volatile memory 208.
• CPU 204 is connected to a user interface 210 and a network interface 212.
• the network interface 212 may be a wired or wireless interface and is connected to a network, represented by cloud 214.
• the processing unit 202 may be connected with sensors, databases and other sources and receivers of data through the network 214.
• the processor 204 retrieves and executes the LSW software components 209 stored in the non-volatile memory 208.
• the processor may store data temporarily in the volatile memory 206.
• the processor 204 may also receive data (as described in more detail below), through user interface 210 and network interface 212, as required to implement embodiments of the invention.
• data may be entered by a user through the user interface 210 and/or received from e.g. a remote sensor in a production well through the network 214 and/or may be retrieved from a remote database through the network 214.
• diffusion coefficients may be determined in a laboratory from a core sample relating to the reservoir (using well known processes). Once determined, this data may be actively sent to the processing unit 202, or stored in a database to be retrieved as required by the processing unit 202. Alternatives will be readily apparent to the skilled person.
• the processor 204 may provide an output via either of the user interface 210 or the network interface 212. If required, the output may be transmitted over the network to remote stations, such as the control station for an injection well. Such processes will be readily apparent to the skilled person and will therefore not be described in detail.
• Ions for example salt ions
• concentration gradient and therefore the direction of the diffusion in the layers can be considered to be substantially perpendicular to the shale-sandstone boundary, and, as such, the diffusion can be considered to be one dimensional.
• the shale layers can be considered to be of sufficient size, and to have a sufficiently high concentration of ions that they can be modelled as an unlimited source of ions.
• the slug of low salinity water represents only a small fraction of the volume of the connate water in the shale layers. A consequence of this is that the concentration of ions at the boundary between the shale and sandstone can be considered to be constant.
• the sandstone layer can be considered a semi infinite medium; that is; the portion of the layer concerned is bounded on one side by the shale, but extends to infinity from there. This is an approximation, since the sandstone layer will be bounded on the other side (most likely by another shale layer), however it is valid for the examples given.
• Equation 1 Equation 1 where z is distance (depth) within the sandstone measured from the boundary surface of the sandstone and the shale, Co is the concentration of the ion at z - 0 (i.e. the concentration in the shale layer), D a is the apparent diffusivity of ions within the sandstone, t is time and C(z) is the concentration of the diffusing ion in the porous medium at a depth of z.
• Figure 3 shows a plot of C(z)/C 0 against distance (z). Five lines are shown, each curve being constructed using different values of 2 ⁇ D a t . It can be seen from Figure 3, the concentration decreases with depth. In addition, the longer the residency time (proportional to Llv), the greater the diffusion.
• the penetration depth can be used to calculate a "boundary layer" thickness x.
• This boundary layer represents the portion of each sandstone layer which is strongly affected by the diffusion of ions into the sandstone layer from the surrounding shale layer.
• the boundary layer it is assumed that there is no incremental recovery of the oil (that is, there is no additional recovery of oil from the boundary layer when compared to a high salinity waterflood).
• the diffusion of the ions is assumed to have no effect on the low salinity waterflood.
• the empirical constant A can be varied to tune the equation
• D a and L may be known and relatively constant.
• the velocity v may be a measure of the superficial velocity through the reservoir; however this is not a requirement, and any appropriate velocity measure may be used. Normally, there will be a boundary layer at the top and bottom of a sandstone layer interbedded between the shale layers.
• A will have a value of 0.5 (assuming the boundary layer grows uniformly from the injection to the production well), however other values may be used. For example, if it is found that a particular reservoir is strongly affected by diffusion of ions, or that the concentration of ions in the shale layers is unusually high, A may be increased to have a value of e.g. 1 or 2. Appropriate values of A may be found empirically by the skilled person, for example by comparing difference simulation results to the results obtained using embodiments of the invention.
• the superficial velocity v may be varied by changing the injection pressure, and consequently the value of v to be used in this equation may be varied in dependence on other factors.
• the maximum superficial velocity which may be used through the reservoir may be limited by, for example, the maximum injection pressure which may be used without hydraulically fracturing the reservoir, or the maximum superficial velocity which may be economically possible.
• the superficial velocity v used in equation 3 may be a predetermined fraction/percentage of the maximum (such as 80% of maximum).
• Various method of deriving v will be apparent to the skilled person, and any may be used within the scope of the invention.
• the effectiveness of a low salinity waterflood may be calculated using a diffusion degrade factor (F) for the reservoir.
• the diffusion degrade factor may be generally considered to be a measure of the ratio of the quantity of additional oil recovered when diffusion is taken into account to the quantity of additional oil recovered when diffusion of ions is ignored.
• the "additional” oil here being the amount of oil recovered by the low salinity waterflood compared to the preceding high salinity waterflood.
• Equation 4 simplifies to:
• Equation 4 may, for example, be modified so that it only applies when w crab ⁇ 2x.
• step 402 data indicative of values for the interwell distance ( ), diffusion coefficient (D a ), superficial velocity (v), and the thicknesses (wong) of the sandstone layers in the reservoir is received by the processor.
• layers may have variable thicknesses. Consequently, the thickness data for a layer having a variable thickness may be calculated from, for example, an average thickness of the layer, or from a minimum thickness of the layer (other possibilities may be envisaged by the skilled person).
• the above data may be received through interfaces 210 or 212 as shown in Figure 2.
• the data may be provided from a number of sources, including a reservoir model, core samples, database lookup etc.
• sources including a reservoir model, core samples, database lookup etc.
• the possible sources of such data will be readily apparent to the skilled person.
• step 404 the processor 204 calculates an ion diffusion distance value (x) from D, L, v and A.
• the ion diffusion distance value may, as in this embodiment, be the average boundary layer thickness. Therefore this calculation may be done using equation 3 shown above, and repeated here:
• step 406 the processor 204 calculates the arithmetic mean of the thickness (represented as H) of the sandstone layers using Equation 6, reproduced here:
• step 408 the processor 204 calculates a diffusion degrade factor (F) from Hand x using Equation 5, reproduced here:
• the diffusion degrade factor F may be used in a number of ways. Firstly, as shown in step 410, the diffusion degrade factor F may be used in the generation of an estimate for the recovery of oil from the reservoir. This may be performed by the processor 204, or the diffusion degrade factor F may be provided to a reservoir modelling system to be used in generating estimates of the recovery of oil. One example of this use may be to multiply an estimate of the incremental oil recovery from the low salinity waterflood provided by the model by the diffusion degrade factor F, however alternative methods will be apparent to the skilled person.
• a second use of the diffusion degrade factor is described in steps 412 to 418.
• the diffusion degrade 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.
• the threshold has a value in the range of 0.6 to 0.8. Based on the comparison, a determination as to whether a low salinity waterflood should be performed can be made.
• step 414 it is determined if F is greater than the threshold value. If F is greater, then this is taken to indicate that the low salinity waterflood should be performed. Alternatively, if F is less than the threshold, the low salinity waterflood is not performed.
• the ion diffusion distance value (x) may be calculated in step 404 from D a and t. If this is the case, the processor may, in step 402, receive a value of t instead of the values of L and v. Equally, while the processor 204 is described as calculating the average (mean) layer thickness (H) for the reservoir, from the individual layer thickness, it will be readily apparent that this value may be directly provided to the processor.
• the boundary layer thickness x can be used to calculate a target or threshold superficial velocity for the low salinity waterflood. This may be of use since, as mentioned above, the superficial velocity of the waterflood may be varied by varying e.g. the injection pressure, therefore providing a target, or a minimum velocity threshold, the effectiveness of the low salinity waterflood can be assured.
• a relationship between the superficial velocity v and the degrade factor F can be established, specifically:
• Equation 7 can be rearranged to produce Equation 8:
• the target velocity v ta rget may then be used in the control of the injection well to ensure that the superficial velocity of the waterflood is kept at, around, or above the target.
• the superficial velocity may be kept within a predetermined range around or above the target velocity v t arget > alternatively the superficial velocity may be controlled to always be above the target velocity v tar get with other factors (if required) determining a maximum velocity.
• the diffusion degrade factor F represents the proportion of additional oil recovered by the low salinity waterflooding with diffusion taken into account against the case where diffusion of ions is ignored. As such, it represents a measure of the potential success of the waterflooding. Consequently, the target value for the diffusion degrade factor ta rget may be used to represent a minimum acceptable or ideal value which should be achieved for the waterflooding to be successful (whether practically, in terms of e.g. the amount of low salinity water available, or economically). As a consequence, maintaining the velocity of the waterflood to be above or at the target velocity will ensure that the effectiveness of the waterflood is equally above or at the target.
• step 502 the processor receives data indicative of the interwell distance (L), diffusion coefficient (D a ), the mean layer thickness (H), the constant (A), and the target diffusion degrade factor ( target)- As described above, the mean layer thickness (H) may be received directly, or calculated from the individual layer thicknesses (w hypo).
• step 504 the processor 204 calculates a target superficial velocity (v ta rget) from D a ,
• the target superficial velocity may then be used to control the injection pressure in the injection well to thereby control the superficial velocity of the waterflood within the reservoir. Consequently, in step 506, the processor 204 may transmit an indication of the target superficial velocity to the injection well using interface 212.
• control systems in the injection well control the injection well to maintain the superficial velocity of the flood at an appropriate speed in view of the target superficial velocity. This may be done in any number of ways, which will be obvious to the skilled person, and may be done by maintaining the average superficial velocity of the injection fluid at the target superficial velocity, or by ensuring that the superficial velocity of the flood is kept above the target superficial velocity.
• Equation 8 may be rearranged so that a target interwell length can be derived.
• equation 8 can be rearranged as: H 2 (l - F) 2 v
• This target length Z ta rget may be calculated from a average value for the superficial velocity (v) as discussed above.
• step 602 the processor 204 receives data indicative of the diffusion coefficient (D a ), the superficial velocity (v), the mean layer thickness (H), the constant (A), and the target diffusion degrade factor (Etarget)-
• the mean layer thickness (H) may be received directly, or calculated from the individual layer thicknesses (w hypo).
• the processor 204 derives a target interwell length (Ztarget)- This length, being a target, may represent a maximum value for the interwell length, or may represent the centre point for a desired range of interwell lengths (for example, Ztarget ⁇ 10%).
• step 706 the processor 204 may output the target interwell length (Jtarget)-
• the value Ztarget may be output using the interfaces 210 and 212.
• the value Z may be used directly by the processor 204.
• the target interwell length (Z targ et) is used in locating the wells penetrating the reservoir.
• the wells may be located such that the interwell length is less than the target length, or is within a predetermined factor of the length.
• the exact mechanism to locate the wells which is to be used will depend on a number of other factors, however the target interwell length can be considered as a guide to ensure that low salinity waterflooding will be a possibility when the wells are in production (for the reasons stated above).
• This step may be performed by processor 204; however it equally may be performed by a separate processing system which is tasked with determining well locations.
• the calculations are described as being performed in the processing unit 202, however this is not a requirement. Equally, while the processing unit has been described as a single, stand-alone, unit, this may not be the case, and for example the functionality of the processing unit may be incorporated into any other entity, or be distributed across a number of entities.
• the LSW software components are described as being stored in the memory 208, however the LSW software components may alternatively be received via the network interface 212 (from e.g. a remote database).
• the outputs may be provided to various other entities, such as the well control apparatus. The mechanisms by which this may be done will be well known to the skilled person.
• G diffusion loss factor
• the layers may be categorized as either “marginal facies” or “axial facies”. This may be done using the boundary layer thickness.
• "marginal facies” may denote interbedded sandstone and shale layers where the sandstone layers are strongly affected by diffusion of salt ions, and in view of the above, may be defined as layers having a thickness comparable to, or thinner than, twice the boundary layer thickness x (meaning that the entire sandstone layer is defined as being boundary layer).
• the "axial facies” are interbedded sandstone layers where the sandstone layers are thicker than four times this boundary layer thickness x.
• the threshold used to categorize these layers (4x above) may take other values, such as 5x or 6x. Having classified the layers, a diffusion degrade factor may then be determined based on the aggregate thickness of the thick (axial) layers to the total thickness of all the layers.
• Equation 5 will tend to underestimate the diffusion degrade factor in cases where there are many layers of a thickness less than twice the boundary layer thickness (since two full boundary layers are assumed to exist for each layer, irrespective of whether the layer is too thin to be able to contain two such layers - and for layers of a thickness less than twice the boundary layer thickness, the boundary layers will effectively be assumed to overlap).
• the method may be adapted to take this into account.
• One method by which this may be done is to define an effective non-boundary thickness (e n ) for each layer which takes into account this overlap, i.e.:
• Equation 10 the diffusion degrade factor F can be calculated using a modified version of Equation 4 as follows: , V « (Equation 10)
• the diffusion degrade factor F is therefore the sum of the effective thicknesses divided by the sum of the layer thicknesses.
• the "apparent diffusion coefficient" has been used to define the rate of diffusion of the ions through the sandstone.
• a bulk diffusion coefficient relates to the diffusion of ions in a bulk liquid
• a pore diffusion coefficient takes into account the tortuosity of the pores in the sandstone which constrain the diffusion
• the apparent diffusion coefficient takes into account both tortuosity and sorbtion of ions.
• the pore diffusion coefficient is the same as the apparent diffusion coefficient, however this is not the case for a sorbing ion.
• any appropriate diffusion coefficient may be used in embodiments of the invention without departing from the scope of the claims.
• the salt diffusivities in shale can be determined experimentally with a sufficient degree of accuracy to determine the effect of salt diffusion on the incremental oil recovery that can be achieved with a low salinity waterflood. Since the rate of salt diffusion is proportional to the concentration gradient between the high salinity connate water 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 connate water that is present in the shale layers together with the
• concentrations of the individual ionic (salt) species in this connate water in particular, the concentration of the various multivalent cations together with the total concentration of multivalent cations in this connate water.
• samples of the connate water that is present in the pore space of the sandstone layers and in the pore space of the interbedded shale layers may be obtained by taking a core sample from the reservoir through the different reservoir layers. From these the TDS and multivalent cation content of the water contained within the different layers of the core may then be determined.
• the low salinity water that is injected into the sandstone layers of the oil reservoir may have a total dissolved solids (TDS) content in the range of 200 to 12,000 ppm, preferably, 500 to 10,000 ppm.
• TDS total dissolved solids
• the formation rock contains swelling clays, in particular, smectite clays
• a relatively high TDS for the low salinity water is required in order to stabilize the clays, thereby avoiding the risk of formation damage.
• the low salinity water that is injected into the oil-bearing formation preferably has a TDS content in the range of 8,000 to 12,000 ppm.
• the TDS content of the low salinity water is typically in the range of 200 to 8,000 ppm, preferably 500 to 8,000 ppm, and for example may be 1,000 to 5,000 ppm. In this context, it is observed that an overall increase in the salinity of the low salinity water may be tolerated provided that the salinity of the low salinity water remains within the desired range for the low salinity waterflood.
• the concentration gradient between the connate 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 connate water of 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 incremental oil recovery that is achieved for a low salinity waterflood is dependent upon the ratio of the total multivalent cation content in the low salinity injection water that is injected into the sandstone layers of the reservoir to the total multivalent cation content in the connate water that is present in the pore space of the sandstone layers of the reservoir (hereinafter "multivalent cation ratio"). It has previously been found that this multivalent cation ratio should be less than 1, for example, less than 0.9. Generally, the lower the multivalent cation ratio the greater the amount of oil that is recovered from the reservoir.
• the multivalent cation ratio is preferably less than 0.8, more preferably, less than 0.6, yet more preferably, less than 0.5, and especially less than 0.4 or less than 0.25.
• the multivalent cation ratio 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 multivalent cation ratio are 0.01 to 0.9, 0.05 to 0.8, but especially 0.05 to 0.6 or 0.1 to 0.5.
• the ratio of the total divalent cation content of the said low salinity injection water to the total divalent cation content of the formation water that is present in the sand layers of the reservoir (hereinafter "divalent cation ratio") should also less than 1.
• the preferred values and ranges for the multivalent cation ratio may be applied mutatis mutandis to the divalent cation ratio.
• the calcium content of the low salinity injection water is in the range of 1 to 100 ppm, preferably 5 to 50 ppm.
• 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 may be in the range of 0.1 to 20, such as 1 to 10 ppm.
• the total content of multivalent cation in the low salinity injection water is 1 to
• the multivalent cation ratio is less than 1.
• the multivalent cation content of the connate 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
• the apparent diffusivities of non-sorbing ions in sandstone rock may be determined using the following methodology.
• the effective diffusivity is: e F( - m 0 ⁇ wherein D 0 is the bulk diffusivity in aqueous solution, ⁇ is the porosity of the sandstone rock, m is the Archie 'cementation factor', and F is the formation resistance factor.
• the cementation factor, m lies within the range of 1.7 to 2.7.
• the effective diffusivity, D e lies within the range of 1 x 10 "10 to 4 x 10 "10 m 2 /s for the stated range of m.
• the apparent diffusivity, D a D 0 . ⁇ " 1"1 , for a non- sorbing ion (such as Na + or CI " ) lies within the range of 4 x 10 "10 to 1.33 x 10 "9 m 2 /s for the stated range of m.
• the connate water of the shale layer has both a higher TDS and a higher multivalent cation content than the low salinity water that is injected into the sandstone layers of the reservoir.
• the above described embodiments of the invention allow for the diffusion of the non-sorbant ions, however these methods may be combined with methods to allow for the effects of TDS in the shale layers.
• the thickness of the interbedded shale layers may be of significance as this determines the total amount of salt ions available for diffusion from an interbedded shale layer into the low salinity water that is flowing through an adjacent sandstone layer.
• the amount of salt ions available for diffusion into the interbedded sandstone layers may be low. Therefore, it is envisaged that the thickness of the shale layers may be taken into account in the calculations above, insofar as thin shale layers can no longer be approximated as an unlimited supply of ions.

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