Wettability in reservoir engineering. Professor Ole Torsæter Wettability in reservoir engineering. Introduction Factors affecting wettability Core handling Measurement methods

Definitions When a liquid is brought into contact with a solid surface, the liquid either expand over the whole surface or form small drops on the surface. In the first case the liquid will wet the solid completely, while in the other case a contact angle  >0 will develop between the surface and the drop.

Introduction Reservoir rock material The wettability of a reservoir rock system will depend on many factors: Reservoir rock material Geological mechanisms (accumulation and migration) Composition and amount of oil and water Physical conditions; pressure and temperature Mechanisms occurring during production; i.e. change in saturations, pressure and composition. It is difficult to make a general model of wettability including all these factors. Berea Sandstone Strongly water-wet ɸ: 23% k: 400 mD

Factors affecting wettability: Rock and water Rock composition carbonates are basic Silicates are acidic Different minerals have different basic/acidic properties Water Presence of water inhibits oil wetting ability Salinity Composition pH

Factors affecting wettability: Oil properties Oil composition Resins (NSOs) Nitrogen Sulphur Oxygen Heavy depositional polar components asphaltenes, kerogen, bitumen, wax Increase of heavy components = Increase of oil wetness

Factors affecting wettability in the laboratory Temperature Initial drop of temperature (and pressure) can alter native wettability Loss of light ends – more oil wetting? Deposition of heavy ends, asphaltenes Redistribution of fluids Oxidation Oxidation of crude creates surfactants Surfactants

Core handling and flooding Accurate core measurements require representative wettability Core handling can change wettability Core flooding experiments in the lab are therefore usually performed on socalled restored cores (cleaned and then treated in crude oil for a long time to obtain desired wettability). Wettability play an important role in the production of oil and gas as it not only determines initial fluid distributions, but also is a main factor in the flow processes in the reservoir rock.

Wettability nomenclature Water wet system Oil-wet system Grain Oil Water Wettability nomenclature Water wet Oil wet Fractional wettability (heterogeneous, spotted, dalmatian?) Some portions strongly oil wet, rest strongly water wet Mixed wettability Large pores oil wet (continuous oil wetting) small pores water wet Intermediate wettability Slight but equal oil or water wetting throughout the core Neutral wettability No real preference for either oil or water No spontaneous production Small, equal spontaneous production

Measurement of Wettability No satisfactory method exists for in situ measurement of wettability, and therefore it is necessary to estimate the wettability from laboratory measurements. To obtain representative information on wetting preferences in the reservoir from laboratory experiments, the following conditions should be fulfilled: The method should not damage the surface properties of the rock The method should determine wettability from very water-wet to very oil-wet The results should not depend on parameters such as rock permeability and fluid viscosity The results should be reproducible

Measurements on Core Samples The most common methods for measuring wettability on core samples are: Displacement test with two different fluids (rel. perm.) Capillary pressure measurements (USBM-method) Measurements of nuclear magnetic relaxation (NMR) rate Imbibition measurements (Amott) Imbibition and displacement (Amott - Harvey method). The Amott- Harvey test is the most accepted and widely used test in the oil industry

The Amott-Harvey procedure includes four steps: Displaced oil Spontaneous imbibition: Oil-saturated sample is placed in an imbibition cell surrounded by water. The water is allowed to imbibe into the core sample displacing oil until equilibrium is reached. The volume of water imbibed is equal to the oil displaced ; Vo1 2. Forced imbibition: The core is moved to a core holder and water is pumped through. The volume of oil displaced may be measured; Vo2 Rock sample Core holder with rock sample Water Oil Water index:

3. Spontaneous uptake of oil: The core, now saturated with water at residual oil saturation, is placed in an Amott cell and surrounded by oil. The oil is spontaneously taken up and water is displaced. The volume of water displaced is measured; Vw1. 4. Forced displacement of water: The core is removed from the cell after equilibrium is reached, and remaining water in the core is forced out by displacement in a flooding rig. The volume of water displaced is measured; Vw2 Rubber tube Oil Core sample Displaced water Core holder with rock sample Oil Water Oil index:

Amott-Harvey wettability index VO1 = volume of oil produced during water imbibition VO2 = volume of oil produced during water flooding VW1 = volume of water produced during oil “imbibition” VW2 = volume of water produced during oil flooding rw = water index ro = oil index. Empirical test based on some theoretical reasoning. The test steps are difficult to perform at reservoir pressure and temperature. WI = 1.0 completely water wetting WI = 0.0 neutral WI = - 1.0 completely oil wetting

Measurement on Core Samples: Centrifuge- or USBM-method The centrifuge method for determining wettability is based on a correlation between the degree of wetting and the areas under the capillary pressure curves. The method is often called the USBM-method (USBM is abbreviation for United States Bureau of Mines). Photo: Georg Voss

Capillary pressure Pressure in the non-wetting phase minus the pressure in the wetting phase. For a two fluid system the saturation in a core plug rotating in a centrifuge looks like this:

Measurement on Core Samples: Centrifuge A core sample is saturated with brine. The core is then placed in a centrifuge core holder. The core holder is filled with oil and rotated at a certain speeds to obtain the primary drainage curve. The core is placed in an inverted core holder filled with brine. The brine is allowed to spontaneously imbibe into the core. Then the core is centrifuged at incremental steps. The core is placed in a core holder filled with oil and the secondary drainage curve is obtained. The areas under the two curves are determined From N.R.Morrow (JPT, Dec. 1990)

From N.R.Morrow (JPT, Dec. 1990)

Measurement on Core samples: Centrifuge The logarithm of the area ratio is defined as the USBM-wettability index; WIUSBM = log(A1/A2). The relative wetting tendencies of the liquids in a porous medium and the distribution of pore sizes determine the shape of the capillary-pressure curves. In general, water-wet systems should have a larger area in the water-displaced-by-oil curves (area A1) than the area under the oil-displaced-by-water curves (area A2). Therefore, the logarithm of the area ratio for the water-wet system is greater than zero. Conversely, the area ratio is less than unity for oil-wet systems and the logarithm of the ratio is negative. WIUSBM = ∞ completely water wetting WI = 0 neutral WIUSBM = - ∞ completely oil wetting

Final remark Todays methods for measuring the wettability of a crude oil/brine/rock system have a weak theoretical basis, are time consuming to perform and the results are questionable. In WP6 in PoreLab we will study wettability and hopefully be able to introduce a new and better measurement method for crude oil/brine/rock systems.