Liquid Interfaces

Liquid interface in relation to surface:

There is no fundamental physical difference between the two terms. The presence of an interface in a two-phase system tends to increase the free energy of the system, thus the system will tend to reduce
spontaneously the interface whenever possible. If the composition of the interface is modified, e.g., by the adsorption or deposition of surface active molecules, the interfacial contribution to the free energy is also changed in order to reduce the interfacial energy. Interface is normally applied to systems involving two condensed phases while Surface is applied to the region between a condensed phase (liquid or solid) and a gas phase or vacuum.

Interfacial Phenomena

When phases exist together, the boundary between two of them is termed an interface. The properties of the molecules forming the interface are often sufficiently from those in the bulk of each phase that they are referred to as forming an interfacial phase. Several types of interface can exist, depending on whether the two adjacent phases are in the solid, liquid or gaseous state. For convenience, we shall divide these various combinations into two groups, namely liquid interfaces and solid interfaces.

Liquid Interfaces

Surface and Interfacial Tension Surface: The term surface is customarily used when referring to either a gas-solid or a gas-liquid interface. “Every surface is an interface.” Surface tension- a force pulling the molecules of the interface together resulting in a contracted surface.- Force per unit area applied parallel to the surface.Unit in dynes/cm or N/m

Interfacial tension  Is the force per unit length existing at the interface between two immiscible liquid phases and like surface tension, has the units of dyne/cm.

Surface Free energy – increase in energy of the liquid and the surface of the liquid increase.-work must be done to increase liquid surface.γ – surface tension or surface free energy per unit surface. Surface Free energy W=γ ∆A where W is work done or surface free energy increase express in ergs(dyne cm); γ is surface tension in dynes/cm and ∆ A is increase in are in cm sq. What in the work required to increase area of a liquid droplet by 10 cm sq if the surface tension is 49 dynes/cm? W = 49 dynes/cm x 10 cm sq = 490 ergs

Work of adhesion(Wa), which is the energy required to break the attraction between the unlike molecules.(water to oil).

Work of cohesion(Wc), required to separate the molecules of the spreading liquid so that it can flow over the sublayer.(oil to oil and water to water). Spreading of oil to water occurs if the work of adhesion is greater than the work of cohesion.

Spreading coefficient(S) – difference between Wa and Wc.Positive S – if oil spreads over a water surface.

When a drop of oil is added on the surface of water, three things may happen:

1. The drop may spread as a thin film on the surface of water.(positve S)

2. It may form a liquid lens if the oil cannot spread on the surface of water.(negative S)

3. The drop may spread as a monolayer film with areas that are identified as lenses.

Wettability and its effect in reservoir:

Wettability is the ability of a liquid to maintain contact with a solid surface, and it is controlled by the balance between the intermolecular interactions of adhesive type (liquid to surface) and cohesive type (liquid to liquid) in reservoir rock. Is the ability of a solid surface to reduce the surface tension of a liquid in contact with it such that it spreads over the surface and wets it. Wettability is the tendency of a reservoir rock surface to preferentially contact a particular fluid in a multiphase or two-phase fluid system.

Wettability describes the attempt of a solid to form a common interface with a liquid which comes into contact with it. One measure of the wettability by a particular liquid is the contact angle. A wettability profile of a solid, the so-called wetting envelope, can be created by determining the surface free energy and its polar part and its disperse part. The degree of wetting (wettability) is determined by a force balance between adhesive and cohesive forces. Wetting deals with the three phases of materials: gas, liquid, and solid.

Contact angle

The contact angle (θ) : Is the angle at which the liquid–vapor interface meets the solid-liquid interface. The contact angle is determined by the balance between adhesive and cohesive forces. As the tendency of a drop to spread out over a flat, solid surface increases, the contact angle decreases. Thus, the contact angle provides an inverse measure of wettability.

A contact angle less than 90° (low contact angle) usually indicates that wetting of the surface is very favorable, and the fluid will spread over a large area of the surface. Contact angles greater than 90° (high contact angle) generally means that wetting of the surface is unfavorable, so the fluid will minimize contact with the surface and form a compact liquid droplet.

Fig. 2	Contact angle	Degree of wetting	Interaction strength
			Solid–liquid	Liquid–liquid
S	θ = 0	Perfect wetting	Strong	Weak
C	0 < θ < 90°	High wettability	Strong	Strong
			Weak	Weak
B	90° ≤ θ < 180°	Low wettability	Weak	Strong
A	θ = 180°	Perfectly non-wetting	Weak	Strong

IMPLICATIONS OF WETTABILITY

v  Primary oil recovery is affected by the wettability of the system.

v  A water-wet system will exhibit greater primary oil recovery.

v  Oil recovery under waterflooding is affected by the wettability of the system.

v  A water-wet system will exhibit greater oil recovery under waterflooding.

WETTABILITY AFFECTS:

·         Capillary Pressure

·         Irreducible water saturation

·         Residual oil and water saturations

·         Relative permeability

·         Electrical properties

The conventional means of measuring the reservoir rock wetting state is by contact angle measurement of an oil droplet on the rock. Water-wet if the contact angle is less than 90; oil-wet if the contact angle is larger than 90; intermediate wet if the contact angle is ~90. The reservoir wetting state may further be divided into strongly-water-wet, weakly-water-wet, strongly-oil-wet and weakly-oil-wet.

One of the most obvious limitations of wettability characterization using contact angle measurement is the absence of a standard reference. Consequently, except at the end point wetting states, the classification of wetting state from contact angle measurement is arbitrary and subjective. Another important limitation of the contact angle method is that the required length of equilibration time cannot be reproduced in the lab. This may lead to problems such as erroneous classification of wetting state and sometimes to reproducibility issues.

WETTABILITY CLASSIFICATION

v  Strongly oil- or water-wetting

v  Neutral wettability – no preferential wettability to either water or oil in the pores

v  Fractional wettability – reservoir that has local areas that are strongly oil-wet, whereas most of the reservoir is strongly water-wet.  - Occurs where reservoir rock have variable mineral composition and surface chemistry

v  Mixed wettability – smaller pores area water-wet are filled with water, whereas larger pores are oil-wet and filled with oil.  - Residual oil saturation is low.   - Occurs where oil with polar organic compounds invades a water-wet rock saturated with brine

Effects of wettability

v  Effect of Wettability  on capillary pressure:

Is the difference in pressure across the interface between two phases. It is that pressure differential between two immiscible fluid phases occupying the same pores caused by interfacial tension between the two phases that must be overcome to initiate flow. The determination of representative capillary pressure data and wettability index of a reservoir rock is needed for the prediction of the fluids distribution in the reservoir: the initial water saturation and the volume of reserves. This study shows how wettability alteration of an initially water-wet reservoir rock to oil-wet affects the properties that govern multiphase flow in porous media, that is, capillary pressure.

v  Effect of Wettability on oil recovery

Using different surfactants to deliberately improve oil recovery; however, the literature is sparse on wettability alteration that results from contact with the components of corrosion inhibitors or paints; the focus of this study.

Gas flood

Gas flood recovery efficiency also depends on reservoir wettability as well as the spreading coefficient. The best gas flood oil recovery was observed for oil-wet reservoirs particularly for tertiary recovery process i.e. at waterflood oil saturation. For gasfloods in secondary recovery processes, the mixed-wet and water-wet systems resulted in higher recoveries.

Water flood

It has long been known that wettability is a primary determinant of waterflood recovery efficiency. Strongly oil-wet reservoirs give the least waterflood oil recovery and the best recovery appears to be the mixed-wet reservoir, particularly where surface film drainage mechanism is also observed. While most researchers are in agreement on the least waterflood oil recovery for oil-wet reservoirs, there is a lack of consensus as to the wetting condition for maximum oil recovery.

v  Effect of Wettability on OOIP and Reserve Estimations

Estimations of reserves, especially by the volumetric method, are usually undertaken assuming water-wet conditions. Wettability can have a dramatic effect on the estimation of OOIP from initial volumetric to more detailed production performance predictions. Petrophysical data is of primary importance to the estimation of volumetric OOIP. Using common parameters for a water-wet reservoir in an oil-wet reservoir could lead to an over-estimation of oil-in-place.

v  Effect of Wettability on Reservoir Parameters

The wettability of the rock/fluid system is important because it is a major factor controlling the location, flow, and distribution of fluids in a reservoir. Wettability, in petrophysical interpretations affect water saturation calculation and in reservoir condition and core analysis experiments, affects capillary pressure, relative permeability, residual oil saturation, water-flood behavior, and simulated recovery processes.

v  Effects of wettability on relative permeability

Wettability affects relative permeability because it is a major factor in the control of the location, flow, and distribution of fluids in a porous medium. Typically, as the system becomes more oil-wet, the water relative permeability increases and the oil relative permeability decreases. The more oil-wet the rock, the higher the water saturation positioned in the center of the pores competing with the oil in the most permeable pathways, reducing the relative permeability to oil, and increasing the relative permeability to water. Therefore, wettability alteration to more oil-wet due to near well-bore asphaltene deposition can hinder oil production.

Skin effect

Skin effect is a side effect that affected (or rather, damaged) formation rocks near the wellbore as a result of drilling activities performed on the wellbore. Skin is the formation damage caused by drilling & completions. When a well is drilled, drilling muds must be circulating to the surface. This is done because drilling muds can cool the bit, remove cuttings, control formation pressure, etc. The drilling muds cause contaminations in the permeable area around the wellbore, thus reducing the permeability in that area. The reduction in permeability near the wellbore can be quantified by a dimensionless term called “skin”.

v  If the value of skin is positive, the formation is damaged.

v  If the value of skin is negative, the formation is stimulated.

v  If the value of skin is 0, there is nothing happens to the formation.

Rock as a base ability to move fluid (liquid or gas) through it that varies from rock to rock. When a well is drilled, drilling muds are used to circulate the hole to clean out the cuttings (rock chips) and also to put applied pressure on the reservoir to prevent a blowout (the uncontrolled release of oil or gas up the hole). This drilling mud induces a ‘damage’ in the near well bore area caused by partial clogging of the pores that oil and gas flow through. That damage is called ‘skin damage’.

Skin or skin effect in reservoir engineering is reduced permeability around the near well bore area due to the drilling process. This is usually caused by the invasion of the mud filtrate into the pores of the reservoir rock. It reduces the production potential of the well if not bypassed. Good drilling practise can reduce the invasion zone and there are several wellbore clean up chemicals that can reduce the skin effect. Skin effect is the phenomena of additional resistivity arising in bottom-hole formation zone and in face area to fluid influx into the well. Skin-effect results from production-induced impact on the bottom-hole formation zone when completing the well. Due to that, gas-dynamic features of the bottom-hole zone differ from the other part of the pay zone.

Skin-effect provides quantitative characteristic of the difference between equivalent permeability of the bottom-hole zone of the well from the other part of the drainage area. It reflects the quality of completion job dependent on the following factors: degree of reservoir contamination with drilling mud and flushing sludge; nature and quality of reservoir connection with the wellbore; type and efficiency of fluid influx into the well (enhanced oil recovery), etc.

The numerical value is defined by gas-dynamic methods of well survey as an outcome of processing the bottom-hole build-up and stabilization curves. Positive skin-effect values (above zero) indicate poor quality of completion. Negative skin-effect values (below zero) normally are associated with production-induced generation of caverns, fissures and channels in the bottom-hole zone.

Imbibition and drainage strategies

Drainage is a fluid flow process in which the saturation of the nonwetting phase increases.

Mobility of nonwetting fluid phase increases as nonwetting phase saturation increases e.g., waterflood of an oil reservoir that is oil wet  Gas injection in an oil or water wet reservoir. Pressure maintenance or gas cycling by gas injection in a retrograde condensate reservoir. A water-wet reservoir that accumulation of oil or gas in a trap does so by drainage.

 Primary and waterflood oil recovery is affected by the wettability of the system. A water-wet system will exhibit greater primary oil recovery.

Imbibition is a fluid flow process in which the saturation of the wetting phase increases and the nonwetting phase saturation decreases. (e.g., waterflood of an oil reservoir that is water-wet).

Mobility of wetting phase increases as wetting phase saturation increases. Mobility is the fraction of total flow capacity for a particular phase.

If a water-wet rock saturated with oil is placed in water, it will imbibe water into the smallest pores, displacing oil. If an oil-wet rock saturated with water is placed in oil, it will imbibe oil into the smallest pores, displacing water.

Oil-wet reservoir, imbibition

v  Oil will occupy the smallest pores

v  Oil will wet the circumference of most larger pores

v  In pores having high water saturation, water rests on a water film

Imbibition - If an oil-wet rock saturated with water is placed in oil, it will imbibe oil into the smallest pores, displacing water e.g., Oil-wet reservoir – accumulation of oil in trap

Water-wet reservoir, imbibition

v  Water will occupy the smallest pores

v  Water will wet the circumference of most larger pores

v  In pores having high oil saturation, oil rests on a water film

Imbibition - If a water-wet rock saturated with oil is placed in water, it will imbibe water into the smallest pores, displacing oil

Reservoir energy its type and its uses

Reservoir energy is the energy of the reservoir bed and of the embedded fluid (oil, water, gas) which are stressed under the effect of rock pressure and reservoir pressure.

The more gases are dissolved in oil, the higher is the reservoir energy resource. When gas or fluid is recovered from the reservoir, the reservoir energy resource is spent on fluids movement and on overcoming the forces counteracting this movement (internal friction forces of fluids and gases and their friction on the rock, as well as capillary forces).

Oil and gas movement in the reservoir is usually defined by various types of reservoir energy simultaneously (compressed formation and fluids tension and energy defined by oil gravity are always shown). Depending on geological features and the conditions of field development that or another type of energy shall prevail. According to the type of energy defining movement of gas and fluids to producing fields, different modes of operation are set for oil and gas deposits.

Main types of reservoir energy:

v  produced water discharge,

v  free gas and gas emitted when the pressure of the gas dissolved in oil is lowered,

v   compressed formation and fluids tension,

v  discharge energy defined by oil gravity.

Uses of reservoir energy

Reservoir energy resource spent during field development may be restored due to natural influx of water from surface sources into the pay zone (in outcrop locations), from aquifer (especially when external reservoir boundary is practically unlimited and has good hydro-dynamic connections with oil-saturated reservoirs) or by way of artificial injection of water, gas or other agent displacing reservoir fluid. Reservoir energy balance (ration of energy spent on production and external energy flowing into the reservoir) is one of the crucial parameters of oil field development. It is characterized by the difference between current and initial reservoir pressure, as well as by current and accumulated compensation of recovered fluid by injected working agent.

Reference

F. F. Craig, The Reservoir Engineering Aspects of Waterflooding, vol. 3 of SPE Monograph, Richardson, Tex, USA, 1971.

N. R. Morrow and J. C. Melrose, “Application of capillary pressure measurements to the determination of connate water saturation,” in Interfacial Phenomena in Petroleum Recovery, N. R. Morrow, Ed., pp. 257–287, Marcel Dekker, New York, NY, USA, 1991. View at Google Scholar

A. W. Adamson, Physical Chemistry of Surfaces, John Wiley & Sons, 6th edition, 1990.

W. G. Anderson, “Wettability literature survey-part 1: rock/oil/brine interactions and the effects of core handling on wettability,” Journal of Petroleum Technology, vol. 38, no. 11, pp. 1125–1144, 1986. View at Publisher · View at Google Scholar · View at Scopus

N. R. Morrow, “Wettability and its effect on oil recovery,” Journal of Petroleum Technology, vol. 42, no. 12, pp. 1476–1484, 1990. View at Publisher · View at Google Scholar · View at Scopus

A. Graue, E. Aspenes, T. Bognø, R. W. Moe, and J. Ramsdal, “Alteration of wettability and wettability heterogeneity,” Journal of Petroleum Science and Engineering, vol. 33, no. 1–3, pp. 3–17, 2002. View at Publisher · View at Google Scholar · View at Scopus

M. N. Derahman and M. K. Zahoor, “Prediction and estimation of capillary pressure for wettability and wettability variations within reservoir,” in Proceedings of the 13th Abu Dhabi International Petroleum Exhibition and Conference (ADIPEC '08), pp. 591–609, November 2008. View at Scopus

L. W. Lake, Enhanced Oil Recovery, Prentice-Hall, Englewood Cliffs NJ, USA, 1989.

S. K. Masalmeh, X. D. Jing, W. van Vark, H. van der Weerd, S. Christiansen, and J. van Dorp, “Impact of SCAL on carbonate reservoirs: how capillary forces can affect field performance predictions,” in Proceedings of the International Symposium of the Society of Core Analysts (SCA '03), SCA 2003-36, Pau, France, October 2003.

D. W. Ruth and Z. A. Chen, “Measurement and interpretation of centrifuge capillary pressure curves—the SCA survey data,” The Log Analyst, vol. 36, no. 5, pp. 21–33, 1995. View at Google Scholar · View at Scopus

G. R. Jerauld and S. J. Salter, “The effect of pore-structure on hysteresis in relative permeability and capillary pressure: pore-level modeling,” Transport in Porous Media, vol. 5, no. 2, pp. 103–151, 1990. View at Publisher · View at Google Scholar · View at Scopus

M. Honarpur, L. Koederitz, and A. H. Harvey, Relative Permeability of Petroleum Reservoirs, CRC Press, 1986.