Wettability Thermodynamic Relationship Between Vapour Adsorption And Wetting Biology Essay

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Wettability is defined as the tendency of one fluid to spread on or adhere to a solid surface in the presence of other immiscible fluids, in a rock/oil/ brine system, it will refer to the preference that the rock has for either oil or brine (water). When a rock is oil wet, the oil will occupy the small pores and to contact the majority of the rock surface. Similarly, in water -wet system, water will be in contact with the majority of the rock surface. However, the term wettability is describing the preference of the rock, and does not refer to the fluid that is in contact with the rock surface at the given time.

If a sandstone core is saturated with oil, this core can still be preferentially water -wet. This can be illustrated by allowing water to imbibe into the core, the water will displace the oil from the rock surface, indicating that the rock prefers to be in contact with water. Depending on the interactions between rock/oil/brine the wettability can range from strongly water - wet to strongly oil -wet. Neutral wettability can also occur, that is when rock has no strong preference to either oil or water. Beside these two types, the third type of wettability is the fractional wettability, where different areas of the core have different wetting preferences

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The wettability is important because it is a major factor controlling the location, flow and distribution of fluids in the reservoir. When the system is in equilibrium, the wetting fluid will completely fill up the smallest pores, and be in contact with the majority of the rock surface. The non - wetting fluid will occupy the centers of the larger pores, and even form bobbles that extend over several pores. It is generally assumed that for a system with a strong wetting preference, the wetting - fluids relative permeability is only a function of its own saturation.

Historically it was believed that all petroleum reservoirs were strongly water - wet, because all sedimentary rocks are strongly water - wet and sandstone reservoirs were deposited in aqueous environments which oil migrated into later. It was assumed that the connate water would prevent the oil from touching the rock surface. It was later found that some producing reservoirs actually were strongly oil - wet. Reservoir rocks can change from its original condition (assumed that the original was water -wet) by adsorption of polar compounds and/or the deposition of organic matter originally in the crude oil. Some crude oils can make a rock oil - wet by depositing a thick organic film on the mineral surfaces, other crude oils contains polar compounds that can be adsorbed to make the rock more oil - wet. Some of these compounds are water soluble so they can pass through the aqueous phase to the rock surface.

Insert a picture of different types of wettability

Fractional wettability

The realization that rock wettability can be altered by crude oil components led to the idea that heterogeneous form of wettability exist in the rock. The internal surface of reservoir rock is composed of many different minerals, with different surface chemistry and adsorption properties which may lead to variations in wettability. In fractional wettability, crude oil components may be strongly adsorbed in certain areas, so a portion of the rock is strongly oil - wet, while the rest is strongly water wet.

Mixed wettability: this is introduced for a special type of fractional wettability in which the oil - wet surfaces form continuous paths through the larger pores, the smaller pores remain water -wet contain no oil. The oil in a mixed - wettability core is located in the larger oil - wet pores causes a small but finite oil permeability to exist down to very low oil saturations. This permits the drainage of oil during a waterflood to continue until very low oil saturations are reached. The main distinction between mixed and fractional wettability is that the latter implies neither specific locations for the

oil - wet surfaces or oil wet paths.

The generation of mixed wettability is generalized in this manner: When oil initially invaded an originally water - wet reservoir, it displaced water from the larger pores, while the smaller pores remained water - filled because of the capillary forces. Mixed wettability occurs if the oil deposited a layer of oil - wet organic material only on these surfaces that were in direct with the oil but not with the brine - covered surfaces. Oil - wet deposits would not be formed in the small pores, allowing them to be water - wet. As the oil moves into the larger pores, a thin layer of interstitial water remains on the pore walls, preventing the oil from coming in contact with the rock. Under certain conditions the water film separating the crude oil from the mineral surface can rupture. The water film becomes thinner as more oil is entering the pores, a critical thickness is reached where the water film becomes unstable. The film ruptures and is displaced allowing oil to contact the rock.

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Cores from three different states of preservation are used in core analyses; native state, cleaned and restored state.

Native - state core

The best results for multiphase flow analyses are obtained from native state cores, with these cores the wettability alteration from undisturbed reservoir rock are minimized. It has not been made any distinction between cores taken with oil - or water - based wettability, as long as the original wettability is maintained. Every precaution has been taken to minimize changes from original state. It start from when the core has been flushed by the drilling fluid, a mud with surfactants or a pH that differs from the reservoir fluid most be avoided. Three different coring fluids have been recommended to get native - state cores:

Synthetic formation brine

Unoxidized crude oil

A water based mud with a minimum of additives

Once the core is brought to the surface it must be protected from wettability alteration caused by the loss of light ends, deposition and oxidation of heavy ends. Exposure to air can cause substances in crude oil to rapidly oxidize to form surfactants, altering the wettability. If the core is allowed to dry out, thick oil - wet residue from crude oil will be deposited on the rock surface.

Cleaned core

For cleaned cores, it has been attempted to remove all fluids and adsorbed organic material by flowing solvents through the cores. Cleaned cores are usually strongly water - wet and should only be used for such measurements as porosity and air permeability where the results are not affected by the wettability.

Restored core

In the third type of cores, the native wettability is restored by a three step process. Core is cleaned, saturated with brine, followed by crude oil and finally the core is aged at reservoir temperature for about 1000 hours.

Factors affecting the original reservoir wettability

The surface active agents in the crude oil which can alter the original rock wettability are believed to be polar compounds that contain oxygen, nitrogen or sulfur. These compounds contain both a polar and a hydrocarbon end. The polar end adsorbs on the rock surface, exposing the hydrocarbon side and making the surface more oil - wet. How these compounds come in contact with the rock surface are discussed earlier. The degree to which the wettability is altered by these compounds is not only determined by the composition, but also by the pressure, temperature, mineral surface and the brine chemistry including ionic composition and pH. Multivalent cations can sometime enhance the adsorption of surfactants on the mineral surface, alkaline chemicals can react with some crude to produce surfactants that alter wettability. It has been experimentally found that asphaltenes are responsible for changing some crude oil/water systems from water - wet to oil - wet.

Measurements of asphaltene adsorption in cores with and without water show that in many cases a water film will reduce but not completely inhibit asphaltene adsorption. Because the water film will coadsorb, the water film may alter the detailed adsorption mechanism.

Sandstone and Carbonate surfaces

The types of minerals are also important in determining the wettability, for example carbonate reservoirs are usually more oil - wet than sandstone ones. When the effects of brine chemistry are removed, silica tends to adsorb simple organic compounds, while the carbonates tend to adsorb simple organic acids. This is occurs because silica usually has a negatively charged, weakly acidic surface in water near neutral pH, while the carbonates have a positively charged, weakly basic surfaces. These surfaces will preferentially adsorb compounds with the opposite charge. Wettability of silica will be strongly affected by organic compounds, while carbonates will be strongly affected by the organic acids. Acidic compounds have little effect on silica, while organic compounds will have little effect on carbonates. In the experiments most of the adsorbed compounds changed the wettability only from strongly water wet to mildly water - wet. Oxygen containing acidic compounds will react gradually with carbonate, so the system will gradually become more water - wet. Compounds responsible for wettability alteration are higher - weight polar compounds and other portions of asphaltenes and resins.

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In more complex oil/brine/rock systems the mineral surfaces will not necessarily have a preference for compounds with the opposite polarity. Sometimes multivalent cations can promote the adsorption of surfactants with the same polarity as the surface. Wettability in sandstone can be altered by both acidic and basic compounds, while limestone was more sensitive to the basic compounds.

Brine chemistry

The salinity and the pH of brine are very important in determination of the wettability, because they strongly affect the surface charge on the rock surface and fluid interfaces, which can affect the adsorption of surfactants. Positively charged, cationic surfactants will be attracted to negatively charged surfaces, while negatively charged, anionic surfactants will be attracted to positively charged surfaces. The pH also affects the ionization of the surface active organic acids and bases in the crude oil. For example the hydroxide ions react with organic acids in crude oils to produce surfactants that alter wettability and adsorb at the oil/brine interface to lower IFT. In silica/oil/brine systems, multivalent metal cations in the brine can reduce the solubility of the surfactants in the crude oil and promote the adsorption at the mineral surfaces, causing the system to become more oil - wet. Multivalent metal cations that changed the wettability of such systems includes; Mg2+, Cu2+, Ni2+ and Fe3+. Experiments have showed that very small amount of can alter the wettability from water - wet to oil - wet.

There are two main reasons to why the wettability is affected by the multivalent cations. First, they can reduce the solubility of the surfactants in the crude oil and brine, helping to promote oil wetting. Second, they enhance the surfactant adsorption on the mineral surface and increase the floatability. Generally they act like a bridge between the mineral surface and the adsorbing surfactant, helping to bind the surfactant to the surface.

Clays

Adsorption of asphaltenes and resins onto clays can make them more oil - wet. Adsorption of asphaltenes and resins onto cores containing significant amount of kaolinite could make them neutrally wet. The adsorption can also reduce the expansion of swelling clays, surface area, cation exchange capacity and water sensitivity. Experiments done on dry clay, showed a maximum adsorption of 30 mg asphaltene/g clay. Addition of water will reduce the adsorption, because water and asphaltene will co adsorb.

Amines

Amines, R-NH2, have been used to study EOR caused by wettability alteration. Wettability was reversed by changing the pH from alkaline to acidic. When the pH was alkaline, the amine group was physically adsorbed on the rock surface, exposing the hydrocarbon chain to make the surface more oil - wet. Wettability was altered when pH become acidic, because the amines formed water - soluble salts that rapidly desorbed from the rock surface leaving it water - wet.

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Wettability measurement

When a drop of water placed on a surface immersed in oil, a contact angle is formed, that ranges from 0 áµ’ to 180 áµ’. The surface energies in the system are related by the Young's equation:

Where the contact angle, = interfacial energy between oil and water, = interfacial energy between oil and solid, = interfacial energy between water and solid. If the contact angle is less than 90 ᵒ the system is preferentially water - wet, and oil - wet when the contact angle is greater than 90 ᵒ. For almost all pure fluids and clean rock or polished crystal surfaces and have values such that θ is equal to 0. When crude oil components are adsorbed onto the surface, the interfacial energies are changed. This changes the contact angle and hence the wettability. The term is sometime called the adhesion tension, σA. The adhesion tension is positive when the system is water wet, negative when the system is oil - wet and near zero when the system is neutrally wet.

Methods of wettability measurement

Three quantitative methods generally are used, contact angle measurement, the Amott method (imbibition and forced displacement) and the USBM method. The contact angle measures the wettability of a specific surface, while the Amott and USBM methods measure the average wettability of a core. There are other methods to measure wettability, with different criteria to determine the wettability. This leads to differences when experiments are performed and compared.

Contact angle method

This method is the best one when pure fluids and artificial cores are used, because it is not any possibility of surfactants or other compounds altering the wettability. There are different methods to measure the contact angle, in petroleum industry the methods that are generally used are the "sessile drop method" and a modified form of this method. In both methods, the mineral crystal to be tested is placed in a test cell composed entirely of inert minerals to prevent contamination. The sessile drop method uses one single crystal, while the modified sessile method uses two mineral crystals which are placed parallel to each other.

The first step in measuring the contact angle is to clean the apparatus, because small amounts of contamination can alter the contact angle. Then the cell containing the mineral crystals are filled with brine. For the modified method, an oil drop is placed between the two crystals so that it contacts both crystals. Then the oil/crystal interface is leaved to be aged for a few days, and then the two crystals are displaced parallel to each other. This shifts the oil drop and allows brine to move over a portion of the surface previously covered with oil. A non equilibrium is observed right after the drop is moved. This angle decreases for a day or two until a constant value is obtained. The oil/mineral surface is then aged further, the water is advanced and a new value is obtained.

The question how representative these results are of the wettability. The contact angle cannot take into account the roughness, heterogeneity and complex geometry of reservoir rock. Roughness and pore geometry will influence the oil/water/solid contact line and can the apparent contact angle. On a smooth surface, the contact angle is fixed. On the edges found in reservoir, there is a wide range of possible contact angles. On the sharp edges, contact angles can change without moving the position of the contact line.

Contact angle measurements cannot take into account the heterogeneity of the reservoir rocks. Contact angles are measured on a single mineral crystal, while a core contains many different constituents. Surfactants in the crude oil can affect the wettability of the sands and clays differently, causing localized heterogeneous wettability.

The third limitation is that no information can be gained about the presence or absence of permanently attached organic coatings on reservoir rocks.

Amott method

This method combines imbibition and forced displacement to measure the average wettability of a core. Both reservoir core and fluids can be used in the test. The Amott method is based on the fact that wetting will generally imbibe spontaneously into the core, displacing the nonwetting one. The ratio of spontaneous imbibition to forced imbibition is used to reduce the influence of other factors, such as relative permeability, viscosity and the initial saturation of the rock. Cores are prepared by centrifuging under brine until residual oil saturation (ROS) is reached. Wettability measurements by these steps:

Immerse the core in oil and measure the volume of water displaced by the spontaneous imbibitions of oil after 20 hours.

Centrifuge the core in oil until the irreducible water saturation (IWS) is reached, and measure the total amount of water displaced, including the volume displaced by spontaneous imbibitions.

Immerse the core in brine, and measure the volume of oil spontaneously displaced by imibibition of water 20 hours.

Centrifuge the core in oil until ROS is reached, and measure the total amount of oil displaced.

The ratio of the water volume displaced by spontaneous oil imbibition alone, Vwsp, to the toal displaced by oil imibibition and centrifugal (forced) displacement, Vwt,

The "displacement by water ratio" is given by the ratio of the oil volume displaced by spontaneous water imbibition, Vosp, to the total oil volume displaced by imbibition and centrifugal (forced) displacement, Vot:

Amott used a time period of 20 hours for the spontaneous oil and water imbibitions in his method, but a time limit of 1 - 2 weeks or to allow the cores to imbibe until either imbibition are complete are recommended. Imbibition can take from several hours to more than 2 months to complete. If the procedure is stopped earlier, then the measured spontaneous imbibition volume will be lower than the equilibrium value for low permeability test, causing an underestimation of δo and δw. The measured values will underestimate the water - oil wetness of the rock.

A modification of the Amott wettability test are also used, this procedure are called "Amott - Harvey relative displacement index" and has an additional step in the core preparations; the core is centrifuged first under brine and then under crude oil to reduce the plug to Irreducible water saturation. The displacement ratios are then calculated by Amott method. The Amott - Harvey relative displacement index is the displacement by water ratio minus the displacement by oil ratio:

This combines the two ratios into a single wettability index that varies from +1 for complete water wetness to -1 to complete oil wetness. The main problem with the Amott wettability tests is that they are insensitive near neutral wettability. The limiting contact angle which spontaneous imibibition will not occur depends on the initial saturation of the core.

USBM wettability index

This test measures the average wettability of the core, and is relative rapid it requires a few days to test four to eight plugs. A major advantage compared to the Amott test is its sensitivity near neutral wettability. The disadvantage is that this test can only be used on

plug - size samples because samples have to be spun in a centrifuge. The USBM test compares the work necessary for one fluid to displace the other. The work required for the wetting fluid to displace the non wetting fluid from the core is less than the work required for the opposite displacement. The work required to do so, will be proportional to the area under the capillary pressure curve. Before the tests are run, plugs are prepared by centrifugation under oil at high speed to reach IWS. Wettability index are calculated from the area under the two capillary curves:

Combined Amott/USBM method

This procedure has 5 steps:

Initial oil drive, the plugs are driven to IWS

Spontaneous (free) imbibition of brine, cores are immersed in water and the total amount of water that imbibes freely is measured

Brine drive, the average saturation of the plug is determined from the amount of expelled oil at each capillary pressure. At the end of this step, the plus is left to reach ROS.

Spontaneous (free) imbibition of oil, cores is immersed in oil, and the volume of oil that imbibes spontaneously is measured.

Oil drive, capillary pressures and average saturations are used to area needed for the USBM method. The wettability index for USBM is calculated, at the end of the oil drive the plug is left at IWS.

The areas under the brine - and oil drive are used to calculate the USBM index, while the Amott index uses the volumes of free and total water and oil displacements. There are two advantages of the combined method. First, the resolution of the USBM method are improved by accounting for the saturation changes that occur at zero capillary pressure and the Amott index is also calculated.

Insert a picture of the curve obtained, with further explanation

Imbibition method

This method is one of the qualitative methods, and is most commonly used, because it gives a quick but rough idea of the wettability without requiring any complicated equipment. The original equipment used during imbibition tested the wettability at room temperature and pressure. During the imbibition test a core at IWS is first submerged in brine underneath a graduated cylinder, the rate and amount of displaced oil by brine imbibition are measured. If large volumes are rapidly imbibed, the core is strongly water. In the opposite situation, as if smaller volumes are imbibed, the core is strongly oil wet. If no water is imbibed, the core is either oil - wet or neutrally wet. Non - water - wet cores are then driven to ROS and submerged in oil. With the graduated cylinder below the core the rate and amount of water displaced by oil is measured. If oil is imbibed the core is oil - wet. The strength of wetness, are dependent of the rate and amount of oil imbibed. Cores can also imbibe both water and oil, these cores will have either fractional or mixed wettability. The problem with this method is that imbibition rate does not depend only on wettability, other factors such as permeability, viscosity, IFT, pore structure and initial saturation of the core. Dependence of other variables are reduced by comparison of the measured imbibition rate with a reference rate measured when the core is strongly water - wet. This is done by heating the core to 400 áµ’ C for 24 hours to oxidize all of the original organic material, leaving the core strongly water - wet. The core is then resaturated to its original oil saturation with refined oil having the same viscosity as the crude oil and the reference imbibition rate is recovered. Wettability changes are reported as change in terms of the "relative rate", which is given by

Where R is the relative rate of imbibition, ṁ is the initial imbibition rate just after the core has been submerged and ṁr is the initial rate imbibition rate of the cleaned, strongly water wet core. This method has the same problem as Amott method, insensitivity near neutral wettability. There are other methods of measuring wettability such as microscope examination, flotation method, glass slide method, relative permeability method etc.

There are also some other methods used to measure mixed wettability; nuclear magnetic relaxation and dye adsorption.

Effects of wettability on water flooding

Wettability affects water flood behavior, relative permeability, capillary pressure, irreducible water saturation, ROS, dispersion, simulated tertiary recovery and electrical properties. During a water flood of water wet system the relative permeability of water will increase, while the relative permeability of oil is decreasing. This will allow the water to flow more easily in comparison with crude oil, causing earlier breakthrough and less efficient recovery. A water flood in strongly oil wet system is much less efficient than one in water wet system, because more water must be used. During production, the WOR (water oil ratio) will increase gradually and eventually decrease to a very low level.

In water flooding there are there are three oil saturations of interest; breakthrough saturation, practical saturation and true residual saturation. All three are essentially equal in strongly water wet system with a moderate oil/water viscosity ratio. These saturations can however differ greatly in intermediate or oil wet systems with a large oil/water viscosity ratio. Breakthrough occurs when the water is first produced. The lower oil the saturation in the reservoir is at breakthrough the more economically attractive a water flood will be. When the WOR is so high that water flooding will no longer be economical, the system is at practical saturation. After that the practical saturation is reached in an intermediate - or oil wet system, it is still possible to produce oil at very high WOR. When no more oil can be produced, then true residual saturation will be reached. This can take injection of tens to thousands of pore volumes of water, depending on the wettability of the system.

Amount of produced oil before and after breakthrough is controlled by not only the wettability, but also by the oil/water viscosity ratio, . When the oil/water viscosity is large enough, there will be a significant period of two phase flow at any wettability. An increase in oil viscosity lowers the mobility relative to the water mobility. This change in mobility can cause an earlier breakthrough, and an increased period of production of two phase fluid before the residual oil saturation is reached. Higher oil/water viscosity ratios will give a decreased recovery at breakthrough and a longer period of two phase production in both water wet and oil wet system.

Determining wettability by calorimeter

To understand the characterization of adsorption phenomena at the solids requires experimental methods to determine the solid surface in terms of surface area, porosity and energy of adsorbing. Because most physical phenomena are accompanied by heat transfer of some sort, there is developed several methods of microcalorimetry. In additional these methods can be done under most experimental conditions, even in very heterogeneous systems such as surfactant adsorption studies.

Microcalorimetry can be used to characterize the surface of minerals or to follow the adsorption process. The method is based on the determination of the enthalpy (or internal energy) of adsorption. When the main characteristics of the surface are known, microcalorimetry can be used to follow the adsorption process. Microcalorimetric processes can be distinguished in three main types: Adsorption of gas phase (vapor adsorption), wetting by a liquid and adsorption of a solute from the liquid phase.

Vapor adsorption

The most suited method for determining adsorption isotherm of vapor onto solids is gravimetry, but it is difficult to couple it with micro calorimeter. Point by point volumetric methods are used in the case of vapors that are condensable at room temperature. They need good control of temperature gradients, particularly when the equilibrium pressure is close to saturation. A very large volume of vapor is also needed when the saturation pressure is low at room temperature. These facts lead to technical complications and also increase of the experimental errors. These problems can be avoided by using a pump to directly inject the vapor into the calorimetric cell.

Calorimetry is probably the best method evidence the heterogeneous character of adsorbents, but the concept is in itself relatively limited. The amount of distributed energy is not "universal" information, it cannot be used to predict the adsorption of another molecule. This is excepted in a few cases. For example the energetic distribution which is determined by adsorption of argon or nitrogen, cannot be used to predict adsorption of complex molecules, like surfactants or polymers. The heterogeneities which are seen in adsorption of argon or nitrogen can be at a scale which is too small to be seen by the larger molecules that are used in adsorption of solutions. For example, silica has a heterogeneous behavior in the case where nitrogen or argon is adsorbed, while in the case of adsorbing surfactants or polymers it will have a homogeneous one.

Microcalorimetry gives directly the curve of adsorption enthalpy as a function of the coverage. From the shape of the curve it is possible to conclude on the heterogeneous character of the solid surface. Most frequently encountered enthalpy curves are given in the figure below.

Figure 3. Most frequently encountered enthalpy curves; 1. Heterogenous surface, adsorption is decreasing with coverage. 2. Well defined surface where all the adsorbing sites have the same energy and interactions between adsorbed molecules are not important. Curve 3 and 4 can also correspond to homogenous surfaces, but in these cases molecule interactions are not negligible. Curve 5 can show the presence of several well defined domains.