**Enhanced Oil Recovery in Fractured Reservoirs**

Martin A. Fernø

*Department of Physics and Technology, University of Bergen Norway*

## **1. Introduction**

Introduction to Enhanced Oil Recovery (EOR) 88 Processes and Bioremediation of Oil-Contaminated Sites

Youssef, N., Simpson, DR., Duncan, KE., McInerney, MJ., Folmsbee, M., & Fincher T. (2007).

petroleum reservoir. *Appl. Environ. Microbiol*., Vol. 73, pp. (1239–1247). Zobell, C.E. (1947). Bacterial release of oil from sedimentary materials. *Oil Gas J*., Vol. 2: pp.

(Eds.), Afton, Oklahoma, pp. (149–153).

(62–65).

1982 InternationalConference on MEOR, Donaldson, E. C. and Benett Clark, J. B.

In situ biosurfactant production by *Bacillus* strains injected into a limestone

In this chapter oil recovery mechanisms in fractured reservoirs will be reviewed and discussed. Most attention will be devoted to experimental studies on fluid flow in fractured reservoirs and imaging techniques to visualize fluid flow in-situ. Special focus will be on complementary imaging in the laboratory, where important processes in fractured reservoirs are studied at different length scales over a range of 5 orders of magnitude. A solid understanding of the flow functions governing fluid flow in fractured reservoirs provides the necessary foundation for upscaling laboratory results to the field scale using numerical simulators. The fact that numerical models and reservoir simulators are based on observations from hydrocarbon producing field and laboratory tests demonstrates the need to study the same process at different length scales. It also illustrates the close link between experimental and numerical efforts and the need for interdisciplinary knowledge to constantly improve the representation of fractured reservoirs and the predications made.

## **2. Naturally fractured carbonate reservoirs**

Naturally fractured carbonate reservoirs are geological formations characterized by a heterogeneous distribution of porosity and permeability. A common scenario is low porosity and low permeability matrix blocks surrounded by a tortuous, highly permeable fracture network. In this case, the overall fluid flow in the reservoir strongly depends on the flow properties of the fracture network, with the isolated matrix blocks acting as the hydrocarbon storage. Most reservoir rocks are to some extent fractured, but the fractures have in many cases insignificant effect on fluid flow performance and may be ignored. In naturally fractured reservoirs, defined as reservoirs where the fractures have a significant impact on performance and oil recovery, fracture properties should be evaluated because they control the efficiency of oil production. Fractures are usually caused by brittle failure induced by geological features such as folding, faulting, weathering and release of lithostatic (overburden) pressure (Miller, 2007). Fractured reservoirs may be divided into categories characterized by the relationship between matrix and fracture properties such as permeability and porosity. Allen and Sun, 2003 defined four categories of fractured reservoirs based on the ratio between permeability and porosity in their comprehensive study of fractured reservoirs in the US as follows.

 Type I - little to no porosity and permeability in the matrix. The interconnected fracture network constitutes the hydrocarbon storage and controls the fluid flow to producing well.

Enhanced Oil Recovery in Fractured Reservoirs 91

capillary pressure curve, or more accurately, the positive part of the imbibition capillary pressure curve. The shape and range of the positive capillary pressure curve is dictated by

The performance of a waterflood in a given field may be tested in the laboratory in a spontaneous imbibition test. A standard imbibition test where an oil saturated rock sample is immerged in brine and the production of oil is measured as a function of time has been used to estimate production by spontaneous imbibition in fractured reservoirs. A method to upscale the laboratory imbibition curves to the production of oil from isolated reservoir matrix blocks, with various sizes and shapes, has been studied extensively. Several scaling groups to readily use laboratory results to estimate reservoir behavior are proposed. Aronofsky *et al.*, 1958 proposed an exponential form of the matrix-fracture transfer function, and formulated an important usage of scaling groups to increase computational efficiency of simulators by several orders of magnitudes. The time to complete a simulation of oil recovery from a fractured reservoir decreased dramatically when the transfer functions for fluid flow between fracture and matrix contained the rate of imbibition with scaled dimensionless time. The use of shape factors (Barrenblatt *et al.*, 1960) related to the geometric shape of the matrix block (Kazemi *et al.*, 1976; Zimmerman and Bodvarsson, 1990) was introduced to increase efficiency of numerical simulations. Experimental evidence for the validity of the shape factor was presented by Mattax and Kyte, 1962 with a dimensionless group to scale the imbibition behavior from matrix block of the same rock type with different geometries. According to Morrow and Mason, 2001, the application of

the scaling group by Mattax and Kyte are subject to the following six conditions:

The effect of viscosity was included by Ma *et al.*, 1997, who experimentally showed that the rate of spontaneous imbibition was proportional to the square root of the viscosity ratio for systems with similar geometry. They introduced a new definition of characteristic length, and used the geometric mean of viscosities to modify the dimensionless scaling group

> � � ��� � ��

� <sup>∑</sup> �� ��� � ���

where *tD* is the dimensionless time, *k* is the permeability, *Φ* is the porosity, *σ* is the interfacial tension between the wetting and non-wetting phases, *t* is imbibition time, *µgm* is the

� � (1)

(2)

�� �����

�� � �

geometric mean of the viscosities and *LC* is the characteristic length defined as:

sample shapes and boundary conditions must be identical

 the relative permeability functions must be the same capillary pressure functions must be directly proportional

proposed by Mattax and Kyte, 1962, defined as:

the wettability.

**3.1 Scaling laws and shape factor**

gravity effects may be neglected

 oil/water viscosity is duplicated initial fluid distributions are duplicated

The four types of fractured reservoir defined above honors the geological features related to hydrocarbon storage and the relationship between permeability and porosity. Furthermore, the production characteristics of fractured reservoirs differ from conventional reservoirs in many fundamental ways. Some of the most pronoun differences are listed below (Allen and Sun, 2003).

In the following section the main focus will be on the production of hydrocarbons from fractured reservoirs, more specifically production of oil from fractured carbonate reservoirs.

## **3. Recovery mechanism in fractured reservoirs**

The presence of fractures dramatically influences the flow of fluids in a reservoir because of the large contrast in transmissibility between the fracture and the matrix. High permeable fractures carry most of the flow, and therefore limit the buildup of large differential pressures across the reservoir. The limited viscous forces are negative for production during e.g. a waterflood, where most of the water flows in the fracture network only and does not displace oil from the matrix blocks, leading to poor sweep efficiency and low recoveries. In this scenario, the recovery mechanism is capillary imbibition rather than viscous displacement. Counter-current spontaneous imbibition, where water in the fracture spontaneously enters a water-wet rock and oil is displaced in the opposite direction, is a key recovery mechanism in fractured reservoirs during waterflooding. The amount of water imbibed from the fracture network depends on the capillary pressure curve, which is closely correlated to the pore structure and wettability preference of the rock surface. The amount of spontaneously imbibed water into an oil saturated rock is ultimately controlled by the Introduction to Enhanced Oil Recovery (EOR) 90 Processes and Bioremediation of Oil-Contaminated Sites

 Type II - low matrix porosity and permeability. Some of the hydrocarbons are stored in matrix. Fractures control the fluid flow, and fracture intensity and distribution dictates

 Type III - high matrix porosity and low matrix permeability. Majority of the hydrocarbons are stored in matrix. Matrix provides storage capacity, the fracture

 Type IV - high matrix porosity and permeability. The effects of the fracture network are less significant on fluid flow. In this type category reservoir fractures enhance

The four types of fractured reservoir defined above honors the geological features related to hydrocarbon storage and the relationship between permeability and porosity. Furthermore, the production characteristics of fractured reservoirs differ from conventional reservoirs in many fundamental ways. Some of the most pronoun differences are listed below (Allen and

 Due to high transmissibility of fluids in the fracture network, the pressure drop around a producing well is lower than in conventional reservoirs, and pressure drop does not play as important role in production from fractured reservoirs. Production is governed

 The GOR (gas-oil ratio) in fractured reservoirs generally remains lower than conventional reservoirs, if the field is produced optimally. The high permeability in the vertical fractures will lead the liberated gas towards the top of the reservoir in contrast to towards producing well in conventional reservoirs. This is to some degree sensitive to fracture spacing and orientation and the position of producers. Liberated gas will

form a secondary gas gap at the top of reservoir or will expand the existing cap. Fractured reservoirs generally lack transition zones. The oil-water and oil-gas contacts are sharp contrasts prior to and during production. The high fracture permeability

In the following section the main focus will be on the production of hydrocarbons from fractured reservoirs, more specifically production of oil from fractured carbonate reservoirs.

The presence of fractures dramatically influences the flow of fluids in a reservoir because of the large contrast in transmissibility between the fracture and the matrix. High permeable fractures carry most of the flow, and therefore limit the buildup of large differential pressures across the reservoir. The limited viscous forces are negative for production during e.g. a waterflood, where most of the water flows in the fracture network only and does not displace oil from the matrix blocks, leading to poor sweep efficiency and low recoveries. In this scenario, the recovery mechanism is capillary imbibition rather than viscous displacement. Counter-current spontaneous imbibition, where water in the fracture spontaneously enters a water-wet rock and oil is displaced in the opposite direction, is a key recovery mechanism in fractured reservoirs during waterflooding. The amount of water imbibed from the fracture network depends on the capillary pressure curve, which is closely correlated to the pore structure and wettability preference of the rock surface. The amount of spontaneously imbibed water into an oil saturated rock is ultimately controlled by the

network transport hydrocarbons to producing wells.

allows the rapid re-equilibration of the fluid contacts.

**3. Recovery mechanism in fractured reservoirs**

permeability instead of dictating fluid flow.

by the fracture/matrix interaction.

production.

Sun, 2003).

capillary pressure curve, or more accurately, the positive part of the imbibition capillary pressure curve. The shape and range of the positive capillary pressure curve is dictated by the wettability.

#### **3.1 Scaling laws and shape factor**

The performance of a waterflood in a given field may be tested in the laboratory in a spontaneous imbibition test. A standard imbibition test where an oil saturated rock sample is immerged in brine and the production of oil is measured as a function of time has been used to estimate production by spontaneous imbibition in fractured reservoirs. A method to upscale the laboratory imbibition curves to the production of oil from isolated reservoir matrix blocks, with various sizes and shapes, has been studied extensively. Several scaling groups to readily use laboratory results to estimate reservoir behavior are proposed. Aronofsky *et al.*, 1958 proposed an exponential form of the matrix-fracture transfer function, and formulated an important usage of scaling groups to increase computational efficiency of simulators by several orders of magnitudes. The time to complete a simulation of oil recovery from a fractured reservoir decreased dramatically when the transfer functions for fluid flow between fracture and matrix contained the rate of imbibition with scaled dimensionless time. The use of shape factors (Barrenblatt *et al.*, 1960) related to the geometric shape of the matrix block (Kazemi *et al.*, 1976; Zimmerman and Bodvarsson, 1990) was introduced to increase efficiency of numerical simulations. Experimental evidence for the validity of the shape factor was presented by Mattax and Kyte, 1962 with a dimensionless group to scale the imbibition behavior from matrix block of the same rock type with different geometries. According to Morrow and Mason, 2001, the application of the scaling group by Mattax and Kyte are subject to the following six conditions:

The effect of viscosity was included by Ma *et al.*, 1997, who experimentally showed that the rate of spontaneous imbibition was proportional to the square root of the viscosity ratio for systems with similar geometry. They introduced a new definition of characteristic length, and used the geometric mean of viscosities to modify the dimensionless scaling group proposed by Mattax and Kyte, 1962, defined as:

$$\mathbf{t}\_D = \mathbf{t}\left(\sqrt{\frac{k}{\Phi}} \frac{\sigma}{\mu\_{gm}} \frac{1}{l\_C^2}\right) \tag{1}$$

where *tD* is the dimensionless time, *k* is the permeability, *Φ* is the porosity, *σ* is the interfacial tension between the wetting and non-wetting phases, *t* is imbibition time, *µgm* is the geometric mean of the viscosities and *LC* is the characteristic length defined as:

$$L\_C = \sqrt{\frac{\nu}{\Sigma\_{l=1}^n \frac{A\_l}{\mathbf{x}\_{A\_l}}}} \tag{2}$$

Enhanced Oil Recovery in Fractured Reservoirs 93

scale. They found that the increase in imbibition time for mixed-wet samples was a result of very low water relative permeability caused by low connectivity of water at intermediate saturation demonstrating that pore-scale modeling is a useful tool to understand the physics involved with e.g. spontaneous imbibition in mixed-wet cores. The aim of pore-scale modeling is to predict properties that are difficult to measure, such as relative permeability, from more readily available data, such as drainage capillary pressure (Valvatne *et al.*, 2005). Additional areas where the use of pore-scale modeling is beneficial was demonstrated by Jackson *et al.*, 2003 investigated the effect of wettability variations on flow at the reservoir scale using a pore-scale network model in conjunction with conventional field-scale reservoir simulators. They successfully predicted experimental relative permeability and waterflood recovery data for water-wet and mixed-wet Berea sandstone, and found that the traditionally used empirical models for predicting hysteresis in the transient zone above the oil-water-contact (OWC) were insufficient if wettability varied with height. A significant increase in oil recovery using scanning curves generated by pore-scale network rather than

Designing an enhanced oil recovery project is only possible when the governing processes that control fluid flow and transport within a multi compositional oil reservoir is fully understood. Performing advanced experiments that shed light on these processes is vital for validation of numerical simulators and theoretical calculations needed to evaluate the project. An important objective for experimental reservoir physics is to contribute to numerical simulation of fluid flow within a petroleum reservoir. The governing physics that describe fluid interface interaction and flow on the pore-scale (10-3m) is used as input in numerical simulators to predict flow on the reservoir scale (103m). However, the parameters observed to be important on the pore-scale may or may not be dominant on the field scale. By experimentally investigating the same problem at increasing length scales one is well equipped to decide how to upscale from the pore-scale to the length scale of a grid block in a numerical simulation of e.g. a waterflood in an oil reservoir. Figure 1 illustrates this approach and demonstrates the importance of a strong link and interaction between numerical simulations and experiments at different length scales to fully understand the

The key issue for simulating flow in fractured rocks is to model the fracture-matrix interaction correctly under conditions such as multiphase flow. Combining visualization tools with different spatial resolutions and size capabilities may dramatically increase the overall understanding of the studied phenomena. The use of three visualization techniques is described below, and demonstrates the increased knowledge when applying

Direct visualization of fluid flow and displacement mechanisms on the pore-scale is possible by using mircromodels. Micromodels are porous structures in two dimensions that are based on a real rock and are normally made of glass. The micromodel used here was etched silicone micromodels designed and manufactured by Dept. of Energy Resources

the empirical models was also demonstrated.

**4. Complementary imaging techniques**

process.

complementary imaging.

**4.1 The micro scale**

where *V* is the bulk volume of the matrix, *Ai* is the area open to imbibition at the *i*th direction and ܺ is the distance traveled by the imbibition front from the open surface to the no-flow boundary. A limitation to this scaling group is that its validity was only tested for strongly water-wet systems.

## **3.2 The influence of wettability**

Understanding the wettability effect on the spontaneous imbibition process during waterflooding in fractured reservoirs is crucial because most of the worlds known oil reservoirs are not strongly water-wet. Clean carbonate rocks (and sandstones) are naturally water-wet, even though most reservoir rocks show some oil-wet characteristics. Enhanced oil recovery techniques successfully implemented in water-wet reservoirs may not necessarily perform as well in oil-wet reservoirs as the waterflood performance is strongly dependent on the wettability of the reservoir. In an oil-wet, fractured reservoir, water will not spontaneously displace oil from the matrix, and only the oil in the fractures will be displaced, resulting in poor recoveries and early water breakthrough. In water-wet fractured reservoirs, imbibition can lead to significant recoveries. The recovery of oil from fractured reservoirs is controlled by the interaction between brine/oil/rock interaction, which again depends on the wetting and two-phase flow, the chemical and physical properties of all of the three components, fracture geometry and pore structure of the matrix (Morrow and Mason, 2001).

The impact of matrix wettability on imbibition potential is well-known and the rate of spontaneous imbibition is highly sensitive to wettability (Zhou *et al.*, 2000). A general scaling law that included the effect of wettability was proposed by Li and Horne, 2002 to predict the oil recovery by water injection in fractured reservoirs. Morrow and Mason, 2001 cautioned against implementing the wettability effect in scaling laws directly, and pointed out the difficulty to scale the rate of imbibition even in simple systems like a cylindrical tube where the issue of static vs. dynamic angles arises. Although it is appealing to represent the wettability in terms of the cosine to the contact angle and apply this directly in the scaling law, the assignment of a single effective average contact angle is not physically correct for systems where there is a distribution of contact angles (Jackson *et al.*, 2003, Behbahani and Blunt, 2005).

The impact of wettability on oil recovery by waterflooding was demonstrated by Jadhunandan and Morrow, 1995, who found a maximum recovery at moderately water-wet conditions, with an Amott-Harvey index (Amott, 1959) of Iw-o = 0.2, in Berea sandstone core plugs. Zhou *et al.*, 1995 also reported the highest recovery by long-term spontaneous imbibition (~50 days) in moderately water-wet Berea core plugs. Additional evidence for the importance of wettability on spontaneous imbibition was provided by Johannesen *et al.*, 2006 that reported a similar trend in chalk. In this crude oil/brine/rock type system the maximum recovery was shifted to a wettability index of Iw-o = 0.4 measured by the Amott test.

To understand the physics behind the wettability impact, Behbahani and Blunt, 2005 used pore-scale modeling to explain the decrease in imbibition recovery and production rates with increasing aging times reported by Zhou *et al., 2000*. They used a topologically equivalent Berea network model and adjusted the distribution of contact angles at the pore Introduction to Enhanced Oil Recovery (EOR) 92 Processes and Bioremediation of Oil-Contaminated Sites

where *V* is the bulk volume of the matrix, *Ai* is the area open to imbibition at the *i*th

no-flow boundary. A limitation to this scaling group is that its validity was only tested for

Understanding the wettability effect on the spontaneous imbibition process during waterflooding in fractured reservoirs is crucial because most of the worlds known oil reservoirs are not strongly water-wet. Clean carbonate rocks (and sandstones) are naturally water-wet, even though most reservoir rocks show some oil-wet characteristics. Enhanced oil recovery techniques successfully implemented in water-wet reservoirs may not necessarily perform as well in oil-wet reservoirs as the waterflood performance is strongly dependent on the wettability of the reservoir. In an oil-wet, fractured reservoir, water will not spontaneously displace oil from the matrix, and only the oil in the fractures will be displaced, resulting in poor recoveries and early water breakthrough. In water-wet fractured reservoirs, imbibition can lead to significant recoveries. The recovery of oil from fractured reservoirs is controlled by the interaction between brine/oil/rock interaction, which again depends on the wetting and two-phase flow, the chemical and physical properties of all of the three components, fracture geometry and pore structure of the matrix (Morrow and

The impact of matrix wettability on imbibition potential is well-known and the rate of spontaneous imbibition is highly sensitive to wettability (Zhou *et al.*, 2000). A general scaling law that included the effect of wettability was proposed by Li and Horne, 2002 to predict the oil recovery by water injection in fractured reservoirs. Morrow and Mason, 2001 cautioned against implementing the wettability effect in scaling laws directly, and pointed out the difficulty to scale the rate of imbibition even in simple systems like a cylindrical tube where the issue of static vs. dynamic angles arises. Although it is appealing to represent the wettability in terms of the cosine to the contact angle and apply this directly in the scaling law, the assignment of a single effective average contact angle is not physically correct for systems where there is a distribution of contact angles (Jackson *et al.*, 2003, Behbahani and

The impact of wettability on oil recovery by waterflooding was demonstrated by Jadhunandan and Morrow, 1995, who found a maximum recovery at moderately water-wet conditions, with an Amott-Harvey index (Amott, 1959) of Iw-o = 0.2, in Berea sandstone core plugs. Zhou *et al.*, 1995 also reported the highest recovery by long-term spontaneous imbibition (~50 days) in moderately water-wet Berea core plugs. Additional evidence for the importance of wettability on spontaneous imbibition was provided by Johannesen *et al.*, 2006 that reported a similar trend in chalk. In this crude oil/brine/rock type system the maximum recovery was shifted to a wettability index of Iw-o = 0.4 measured by the Amott

To understand the physics behind the wettability impact, Behbahani and Blunt, 2005 used pore-scale modeling to explain the decrease in imbibition recovery and production rates with increasing aging times reported by Zhou *et al., 2000*. They used a topologically equivalent Berea network model and adjusted the distribution of contact angles at the pore

is the distance traveled by the imbibition front from the open surface to the

direction and ܺ

Mason, 2001).

Blunt, 2005).

test.

strongly water-wet systems.

**3.2 The influence of wettability**

scale. They found that the increase in imbibition time for mixed-wet samples was a result of very low water relative permeability caused by low connectivity of water at intermediate saturation demonstrating that pore-scale modeling is a useful tool to understand the physics involved with e.g. spontaneous imbibition in mixed-wet cores. The aim of pore-scale modeling is to predict properties that are difficult to measure, such as relative permeability, from more readily available data, such as drainage capillary pressure (Valvatne *et al.*, 2005).

Additional areas where the use of pore-scale modeling is beneficial was demonstrated by Jackson *et al.*, 2003 investigated the effect of wettability variations on flow at the reservoir scale using a pore-scale network model in conjunction with conventional field-scale reservoir simulators. They successfully predicted experimental relative permeability and waterflood recovery data for water-wet and mixed-wet Berea sandstone, and found that the traditionally used empirical models for predicting hysteresis in the transient zone above the oil-water-contact (OWC) were insufficient if wettability varied with height. A significant increase in oil recovery using scanning curves generated by pore-scale network rather than the empirical models was also demonstrated.

## **4. Complementary imaging techniques**

Designing an enhanced oil recovery project is only possible when the governing processes that control fluid flow and transport within a multi compositional oil reservoir is fully understood. Performing advanced experiments that shed light on these processes is vital for validation of numerical simulators and theoretical calculations needed to evaluate the project. An important objective for experimental reservoir physics is to contribute to numerical simulation of fluid flow within a petroleum reservoir. The governing physics that describe fluid interface interaction and flow on the pore-scale (10-3m) is used as input in numerical simulators to predict flow on the reservoir scale (103m). However, the parameters observed to be important on the pore-scale may or may not be dominant on the field scale. By experimentally investigating the same problem at increasing length scales one is well equipped to decide how to upscale from the pore-scale to the length scale of a grid block in a numerical simulation of e.g. a waterflood in an oil reservoir. Figure 1 illustrates this approach and demonstrates the importance of a strong link and interaction between numerical simulations and experiments at different length scales to fully understand the process.

The key issue for simulating flow in fractured rocks is to model the fracture-matrix interaction correctly under conditions such as multiphase flow. Combining visualization tools with different spatial resolutions and size capabilities may dramatically increase the overall understanding of the studied phenomena. The use of three visualization techniques is described below, and demonstrates the increased knowledge when applying complementary imaging.

#### **4.1 The micro scale**

Direct visualization of fluid flow and displacement mechanisms on the pore-scale is possible by using mircromodels. Micromodels are porous structures in two dimensions that are based on a real rock and are normally made of glass. The micromodel used here was etched silicone micromodels designed and manufactured by Dept. of Energy Resources

Enhanced Oil Recovery in Fractured Reservoirs 95

formation damage. Recent studies have reported flow behavior and production mechanisms in fractured chalk and their dependency of wettability, rate and fracture aperture and

The nuclear tracer imaging (NTI) technique was developed by Bailey *et al.*, 1981 and improved by Graue *et al.,* 1990, and utilizes the emitted radiation from radioactive isotopes, individually labeling the fluids to measure the *in situ* fluid saturation profiles during core flood tests. The large dimensions of the rock samples imaged is a strong advantage of this method, for instance enabling the simultaneous study of the impacts from viscous, capillary and gravity forces in a controlled fractured system. One of the advantages of using nuclear tracers is its inertness nature with respect to the delicate network of pores, assuming that adsorption is minimized by preflushing with non-radiation brine. The possibility to perform multiple experiments on the same rock sample allows for experimental reproduction and investigation of impacts on flow- and recovery mechanisms from a single parameter (e.g. injection rate, wettability or fracture). Also, the NTI technique has the capability of imaging the 1D *in-situ* oil production in cores up to 2 m in length, thus minimizing the disturbance from capillary end effects, and enabling large scale gravity drainage experiments with local saturation measurements. Details on fluid saturation calculations and experimental

The production of oil is challenging in fractured reservoirs due to the large transmissibility contrast between matrix and fracture, and primary recovery is often low. The recovery efficiency depends on the relationship between the fracture and matrix permeabilities, and is strongly dependent on the wettability of the matrix, which reflects the imbibition potential of the reservoir. High demands and rising oil prices has increased focus on improved oil recovery from large, low recovery oil fields. Some of the world's largest remaining oil reserves are found in oil-wet, fractured, carbonate reservoirs. The understanding of multiphase fluid flow in oil-wet fractured reservoirs has been studied, especially the influence of capillary pressure. The presence of capillary pressure is important in recovery mechanisms like spontaneous imbibition, waterflooding, and gravity drainage. Complementary imaging techniques used to study Enhanced Oil Recovery (EOR) processes in fractured oil reservoirs have provided new and improved fundamental understanding waterflood oil recovery. MRI provides high spatial resolution and fast data acquisition necessary to capture fluid displacements that occur inside fractures less than 1 mm wide, whereas NTI provides information on macro-scale saturation distribution in larger fractured

The oil recovery mechanisms involved with waterflooding fractured chalk blocks were found to be dependent on the wettability of the chalk, as the wettability had great impact on the fracture/matrix hydrocarbon exchange. The wettability was altered by dynamic aging (Fernø *et al.*, 2010) in a North Sea crude oil. After aging, the crude oil was displaced from the core at elevated temperature by injecting 5PV of decahydronaphthalene followed by 5PV decane to avoid asphaltene precipitation, to stop the aging and to establish more reproducible experimental conditions by using decane as the oleic phase throughout the

fracture configurations (Graue *et al.*, 2001;Aspenes *et al.*, 2002;Aspenes *et al.*, 2008).

**4.3 The block scale**

systems.

procedures are found in Ersland *et al.*, 2010.

**5. Complementary imaging in fractured reservoirs**

Fig. 1. Complementary imaging at different length scales.

Engineering, Stanford University. The structure of the micromodel was a 1:1 realization of the pore size and pore shapes based on a Berea sandstone thin section. The structure was etched in silicon for increased control of etching depth and accurate reproduction of finescale details that result in sharp, unrounded corners (Kovscek *et al.*, 2007). Average channel depth was 25µm and sand grain features ranged between 50-300µm. The total area of the micromodel was 50 x 50 mm2, representing approximately 600 x 600 pores (Buchgraber *et al.*, 2011). The absolute permeability was 950mD and the porosity was 0.47, resulting in a pore volume (PV) of 0.013ml. For further detail on fabrication process the reader is referred to Hornbrook *et al.*, 1991.

## **4.2 The core scale**

Magnetic Resonance Imaging is a versatile visualization tool frequently used in hospitals and medical applications. The applications of MRI for characterizing core samples and flow properties of porous materials are also known and a considerable amount of literature has been published on the topic. MRI provides a visualization tool to study the movements of fluids inside a fracture network, and provides high spatial resolution and fast data acquisition. Previous work have discussed MRI imaging for core characterization purposes (Baldwin and Spinler, 1998; Baldwin and King, 1999), the monitoring of imbibition and displacement processes (Baldwin, 1999) and the application of MRI to the study of formation damage. Recent studies have reported flow behavior and production mechanisms in fractured chalk and their dependency of wettability, rate and fracture aperture and fracture configurations (Graue *et al.*, 2001;Aspenes *et al.*, 2002;Aspenes *et al.*, 2008).

## **4.3 The block scale**

Introduction to Enhanced Oil Recovery (EOR) 94 Processes and Bioremediation of Oil-Contaminated Sites

Engineering, Stanford University. The structure of the micromodel was a 1:1 realization of the pore size and pore shapes based on a Berea sandstone thin section. The structure was etched in silicon for increased control of etching depth and accurate reproduction of finescale details that result in sharp, unrounded corners (Kovscek *et al.*, 2007). Average channel depth was 25µm and sand grain features ranged between 50-300µm. The total area of the micromodel was 50 x 50 mm2, representing approximately 600 x 600 pores (Buchgraber *et al.*, 2011). The absolute permeability was 950mD and the porosity was 0.47, resulting in a pore volume (PV) of 0.013ml. For further detail on fabrication process the reader is referred to

Magnetic Resonance Imaging is a versatile visualization tool frequently used in hospitals and medical applications. The applications of MRI for characterizing core samples and flow properties of porous materials are also known and a considerable amount of literature has been published on the topic. MRI provides a visualization tool to study the movements of fluids inside a fracture network, and provides high spatial resolution and fast data acquisition. Previous work have discussed MRI imaging for core characterization purposes (Baldwin and Spinler, 1998; Baldwin and King, 1999), the monitoring of imbibition and displacement processes (Baldwin, 1999) and the application of MRI to the study of

Fig. 1. Complementary imaging at different length scales.

Hornbrook *et al.*, 1991.

**4.2 The core scale**

The nuclear tracer imaging (NTI) technique was developed by Bailey *et al.*, 1981 and improved by Graue *et al.,* 1990, and utilizes the emitted radiation from radioactive isotopes, individually labeling the fluids to measure the *in situ* fluid saturation profiles during core flood tests. The large dimensions of the rock samples imaged is a strong advantage of this method, for instance enabling the simultaneous study of the impacts from viscous, capillary and gravity forces in a controlled fractured system. One of the advantages of using nuclear tracers is its inertness nature with respect to the delicate network of pores, assuming that adsorption is minimized by preflushing with non-radiation brine. The possibility to perform multiple experiments on the same rock sample allows for experimental reproduction and investigation of impacts on flow- and recovery mechanisms from a single parameter (e.g. injection rate, wettability or fracture). Also, the NTI technique has the capability of imaging the 1D *in-situ* oil production in cores up to 2 m in length, thus minimizing the disturbance from capillary end effects, and enabling large scale gravity drainage experiments with local saturation measurements. Details on fluid saturation calculations and experimental procedures are found in Ersland *et al.*, 2010.

## **5. Complementary imaging in fractured reservoirs**

The production of oil is challenging in fractured reservoirs due to the large transmissibility contrast between matrix and fracture, and primary recovery is often low. The recovery efficiency depends on the relationship between the fracture and matrix permeabilities, and is strongly dependent on the wettability of the matrix, which reflects the imbibition potential of the reservoir. High demands and rising oil prices has increased focus on improved oil recovery from large, low recovery oil fields. Some of the world's largest remaining oil reserves are found in oil-wet, fractured, carbonate reservoirs. The understanding of multiphase fluid flow in oil-wet fractured reservoirs has been studied, especially the influence of capillary pressure. The presence of capillary pressure is important in recovery mechanisms like spontaneous imbibition, waterflooding, and gravity drainage. Complementary imaging techniques used to study Enhanced Oil Recovery (EOR) processes in fractured oil reservoirs have provided new and improved fundamental understanding waterflood oil recovery. MRI provides high spatial resolution and fast data acquisition necessary to capture fluid displacements that occur inside fractures less than 1 mm wide, whereas NTI provides information on macro-scale saturation distribution in larger fractured systems.

The oil recovery mechanisms involved with waterflooding fractured chalk blocks were found to be dependent on the wettability of the chalk, as the wettability had great impact on the fracture/matrix hydrocarbon exchange. The wettability was altered by dynamic aging (Fernø *et al.*, 2010) in a North Sea crude oil. After aging, the crude oil was displaced from the core at elevated temperature by injecting 5PV of decahydronaphthalene followed by 5PV decane to avoid asphaltene precipitation, to stop the aging and to establish more reproducible experimental conditions by using decane as the oleic phase throughout the

Enhanced Oil Recovery in Fractured Reservoirs 97

Water displaced oil upwards and into the outlet core plug to the producer because there was no alternative escape path for the oil phase. At strongly water-wet conditions, the water filled the fracture from the bottom to the top, displacing oil in a horizontal oil-water interface. No residual oil was observed in the fracture after the water filled the fracture and invaded the outlet core plug. At weakly oil-wet conditions, water displaced the oil from the fracture similarly to strongly water-wet conditions, with a horizontal oil-water interface moving upwards. However, unlike strongly water-wet conditions, droplets of oil remained

The locations where the droplets emerged at the fracture surface were not arbitrary, and were likely to be controlled by clusters of larger pores throats. The larger pore throats will reach zero capillary pressure before pores with narrower throats and, hence, the droplets will emerge at these locations. In the conceptual model proposed by Gautam and Mohanty (2004), the oil droplets emerged at the matrix-fracture interface in clusters of large pore throats, and, in accordance with the experimental observations made by Rangel-German and Kovscek (2006), the water transport from fracture to the matrix occurred via narrow pore throats in the vicinity of the oil producing locations. The oil droplet growth process was intermittent, i.e. a blob starts to grow, is displaced by a new blob that starts to grow at the same location and detaches from the fracture surface. Oil droplets forming on the fracture surface during displacements may be an important recovery mechanism if they bridge the fracture to create liquid bridges for oil transport and reduce the capillary retained oil in the hold-up zone during gravity drainage in oil-wet, fractured reservoirs (Fernø, 2008). Oil was also injected through stacked strongly water-wet limestone core plugs to investigate the impact from wettability and the significance of wetting affinity between injected fluid and fracture surface on the forming of oil droplets. No oil droplets were observed in the fracture during oil injections at water-wet conditions. The hydraulic pressure in the fracture was measured during both waterfloods and oilfloods at oil-wet conditions, and the pressure development demonstrates the mechanistic difference when there is a wetting affinity between the fracture surface and the injecting fluid phase. During waterfloods, the fracture hydraulic pressure demonstrated the need to overcome a threshold value before the water invaded the outlet core, whereas no pressure increase was observed during oil injection,

The impact of wettability on the larger scale was also experimentally investigated using the NTI method and the MRI during waterfloods in fractured systems with different wettabilities. The presence of fractures dramatically changed the oil recovery, flow dynamics, and displacement processes. Three wettability conditions were tested: strongly water-wet, weakly water-wet, and weakly oil-wet. In combination with volumetric production data, the *in-situ* fluid saturation data provided information about the flow pattern with the presence of fractures to better understand the recovery mechanisms (Haugen *et al.*, 2010b). Figure 3 demonstrate the difference in waterflood behavior for three wettabilities and list the main recovery mechanisms and implications in the fractured systems. Large fractured block samples (LxWxH= 16x3x9 cm3) were waterflooded to study the effect of wettability on the waterflood behavior. Warmer colors indicate higher oil

on the fracture surface after the water advanced into the outlet plug.

demonstrating the spontaneous nature of the transport of oil.

**5.2 Wettability effects in block samples**

saturations.

experiments (Graue *et al.*, 1996;Graue *et al.*, 1998,1999a;Graue *et al.*, 1999b). The wettability after aging was measured with the Amott method (Amott, 1959).

Increased oil recovery during waterflooding was reported by Viksund *et al.* (1999) in fractured chalk. They used the NTI method to observe that fractures significantly affected water movement during waterfloods at strongly water-wet conditions, whereas the fractures had less impact on the waterfront movement at moderately water-wet conditions, where the injected water crossed fractures more uniformly, apparently through capillary contacts. The MRI images of oil saturation development inside the fractures (Graue *et al.*, 2001) demonstrated transport mechanisms for the wetting phase across the fracture at several wettability conditions, and provided new and detailed information on fluid fracture crossing previously observed in block scale experiments investigated by NTI. The high spatial resolution MRI images revealed water droplets forming on the fracture surface at moderately water-wet conditions, transporting water across the fracture.

A plausible explanation to the increased recovery above the spontaneous imbibition potential in fractured reservoirs during waterflooding was an added viscous pressure drop exerted by the wetting phase bridges across isolated matrix blocks surrounded by fractures.

## **5.1 Wettability effects in core plugs**

Mechanistically similar to water droplets forming during waterfloods in water-wet chalk, oil was injected in oil-wet limestone cores to observe the forming of oil droplets on the surface (Fernø *et al.*, 2011). Stacked core plugs separated by 1 mm space were waterflooded, and the *in-situ* development in oil and water saturations was monitored with MRI. Figure 2 shows the wettability effect on the forming of oil droplets on the fracture surface during a waterflood in a stacked core system consisting of an inlet core, a 1mm space between the core plugs, and an outlet core plug. The space between the core plugs constitutes the fracture. Oil appears bright on the images, whereas a reduction in signal indicates increased water saturation. Each image represents a snapshot in time of the fracture, and time increases from left to right.

Water was injected into two stacked systems with different wettabilities. The fracture was initially oil filled, and water was injected in the core plug upstream of the fracture. Water breakthrough from the inlet plug to the fracture was observed at the bottom of the fracture. Introduction to Enhanced Oil Recovery (EOR) 96 Processes and Bioremediation of Oil-Contaminated Sites

experiments (Graue *et al.*, 1996;Graue *et al.*, 1998,1999a;Graue *et al.*, 1999b). The wettability

Increased oil recovery during waterflooding was reported by Viksund *et al.* (1999) in fractured chalk. They used the NTI method to observe that fractures significantly affected water movement during waterfloods at strongly water-wet conditions, whereas the fractures had less impact on the waterfront movement at moderately water-wet conditions, where the injected water crossed fractures more uniformly, apparently through capillary contacts. The MRI images of oil saturation development inside the fractures (Graue *et al.*, 2001) demonstrated transport mechanisms for the wetting phase across the fracture at several wettability conditions, and provided new and detailed information on fluid fracture crossing previously observed in block scale experiments investigated by NTI. The high spatial resolution MRI images revealed water droplets forming on the fracture surface at

A plausible explanation to the increased recovery above the spontaneous imbibition potential in fractured reservoirs during waterflooding was an added viscous pressure drop exerted by the wetting phase bridges across isolated matrix blocks surrounded by fractures.

Mechanistically similar to water droplets forming during waterfloods in water-wet chalk, oil was injected in oil-wet limestone cores to observe the forming of oil droplets on the surface (Fernø *et al.*, 2011). Stacked core plugs separated by 1 mm space were waterflooded, and the *in-situ* development in oil and water saturations was monitored with MRI. Figure 2 shows the wettability effect on the forming of oil droplets on the fracture surface during a waterflood in a stacked core system consisting of an inlet core, a 1mm space between the core plugs, and an outlet core plug. The space between the core plugs constitutes the fracture. Oil appears bright on the images, whereas a reduction in signal indicates increased water saturation. Each image represents a snapshot in time of the fracture, and time

Fig. 2. The effect of wettability on the fracture-matrix fluid transfer during waterfloods in

Water was injected into two stacked systems with different wettabilities. The fracture was initially oil filled, and water was injected in the core plug upstream of the fracture. Water breakthrough from the inlet plug to the fracture was observed at the bottom of the fracture.

after aging was measured with the Amott method (Amott, 1959).

moderately water-wet conditions, transporting water across the fracture.

**5.1 Wettability effects in core plugs**

increases from left to right.

stacked core systems.

Water displaced oil upwards and into the outlet core plug to the producer because there was no alternative escape path for the oil phase. At strongly water-wet conditions, the water filled the fracture from the bottom to the top, displacing oil in a horizontal oil-water interface. No residual oil was observed in the fracture after the water filled the fracture and invaded the outlet core plug. At weakly oil-wet conditions, water displaced the oil from the fracture similarly to strongly water-wet conditions, with a horizontal oil-water interface moving upwards. However, unlike strongly water-wet conditions, droplets of oil remained on the fracture surface after the water advanced into the outlet plug.

The locations where the droplets emerged at the fracture surface were not arbitrary, and were likely to be controlled by clusters of larger pores throats. The larger pore throats will reach zero capillary pressure before pores with narrower throats and, hence, the droplets will emerge at these locations. In the conceptual model proposed by Gautam and Mohanty (2004), the oil droplets emerged at the matrix-fracture interface in clusters of large pore throats, and, in accordance with the experimental observations made by Rangel-German and Kovscek (2006), the water transport from fracture to the matrix occurred via narrow pore throats in the vicinity of the oil producing locations. The oil droplet growth process was intermittent, i.e. a blob starts to grow, is displaced by a new blob that starts to grow at the same location and detaches from the fracture surface. Oil droplets forming on the fracture surface during displacements may be an important recovery mechanism if they bridge the fracture to create liquid bridges for oil transport and reduce the capillary retained oil in the hold-up zone during gravity drainage in oil-wet, fractured reservoirs (Fernø, 2008).

Oil was also injected through stacked strongly water-wet limestone core plugs to investigate the impact from wettability and the significance of wetting affinity between injected fluid and fracture surface on the forming of oil droplets. No oil droplets were observed in the fracture during oil injections at water-wet conditions. The hydraulic pressure in the fracture was measured during both waterfloods and oilfloods at oil-wet conditions, and the pressure development demonstrates the mechanistic difference when there is a wetting affinity between the fracture surface and the injecting fluid phase. During waterfloods, the fracture hydraulic pressure demonstrated the need to overcome a threshold value before the water invaded the outlet core, whereas no pressure increase was observed during oil injection, demonstrating the spontaneous nature of the transport of oil.

#### **5.2 Wettability effects in block samples**

The impact of wettability on the larger scale was also experimentally investigated using the NTI method and the MRI during waterfloods in fractured systems with different wettabilities. The presence of fractures dramatically changed the oil recovery, flow dynamics, and displacement processes. Three wettability conditions were tested: strongly water-wet, weakly water-wet, and weakly oil-wet. In combination with volumetric production data, the *in-situ* fluid saturation data provided information about the flow pattern with the presence of fractures to better understand the recovery mechanisms (Haugen *et al.*, 2010b). Figure 3 demonstrate the difference in waterflood behavior for three wettabilities and list the main recovery mechanisms and implications in the fractured systems. Large fractured block samples (LxWxH= 16x3x9 cm3) were waterflooded to study the effect of wettability on the waterflood behavior. Warmer colors indicate higher oil saturations.

Enhanced Oil Recovery in Fractured Reservoirs 99

At weakly water-wet conditions oil was recovered by capillary imbibition of water from the fractures to the matrix blocks. The interconnected fracture network limited the viscous forces in the system as the injector and producer was in direct contact, see Figure 3. The mechanism for oil recovery was purely capillary imbibition of water from the fracture. The strength of the capillary pressure to transport water from the fracture network to the matrix was reduced compared with strongly water-wet condition. The weaker capillary forces led to a reduction in matrix-fracture transfer rate and increased the likelihood of *instantly filled fracture* regime (Rangel-German and Kovscek, 2002), with counter-current imbibition of water. The presence of fractures dramatically reduced the oil recovery. Waterflood oil recovery without fractures was RF=63%OOIP compared with RF=22%OOIP with the presence of fractures. This demonstrates the potential to increase oil recovery in fractured

The fracture system for the weakly oil-wet block was similar to the strongly water-wet block (see Figure 3). Waterfloods were performed both before and after fractures were present, injecting water with the same rate (2 cc/hr) in both cases. The waterflood oil recovery at fractured state was RF=15%OOIP, compared with RF=65%OOIP without the presence of fractures. In addition to a strong reduction in recovery, the fractures changed the time of water breakthrough to the producer. Water breakthrough without fractured was observed after 0.47PV injected, in contrast to only 0.10PV injected with fractures. The oil-wet wettability preference of the matrix suppressed oil recovery by capillary imbibition of water from the fracture network. Recovery was dictated by the ability to generate a differential pressure across the system. Displacement of oil from matrix only took place in the unfractured inlet block, once water entered the fracture network it rapidly filled the fractures, first the lower horizontal fracture, then the remaining fracture network before it reached the

Oil production from fractured oil reservoirs poses great challenges to the oil industry, particularly because fractures may exhibit permeabilities that are several orders of magnitude higher than the permeability of the rock matrix. Low viscosity fluids used for enhanced oil recovery, such as gases or supercritical fluids may channel into the highpermeable fractures, potentially leading to early breakthrough into the production well and low sweep efficiency. Carbonate reservoirs usually exhibit low porosity and may be extensively fractured. The oil-wet nature of the matrix reduces capillary imbibition of water. Carbonate reservoirs contributes substantially to US oil reserves (Manrique *et al.*, 2007), and the low primary recovery and the large number of carbonate reservoirs in the US and

Foam has the potential to increase oil recovery by improving areal sweep, better vertical sweep (less gravity override), less viscous fingering, and diversion of gas away from higherpermeable or previously swept layers (Bernard and Holm, 1964, Holm, 1968, Hanssen *et al.*, 1994, Schramm, 1994; Rossen, 1995). Diversion of gas into lower-permeable layers using

outlet. No transport of water from fracture to matrix was observed.

**6. Enhanced oil recovery in fractured reservoirs**

around the world makes them good targets for EOR efforts.

**5.2.2 Weakly water-wet**

**5.2.3 Weakly oil-wet**

reservoirs by increasing the viscous forces.

Fig. 3. The effect of wettability on the fracture-matrix fluid transfer during waterfloods in fractured block systems. Water is injected at the boundary on the left, and the direction of flow is from left to right. Fractures are indicated in black where not directly observed.

#### **5.2.1 Strongly water-wet**

In strongly water-wet systems containing several disconnected matrix blocks the fractures were barriers to flow. The displacement process was governed by capillary forces, corroborated by the visualized displacement pattern with a block-by-block displacement attributed to discontinuity in the capillary pressure curve at the matrix-fracture interface. The positive capillary pressure in the matrix block during oil displacement trapped the water phase in the matrix block until the capillary pressure at both sides of the matrixfracture interface were equal. This occurred at the end of spontaneous imbibition, when Pc=0 in the matrix block. Water in the fracture network may imbibe into the adjacent downstream matrix block. Consequently, the fluid flow dynamics were strongly influenced by the presence of fractures at strongly water-wet conditions, but residual oil saturation and recovery were similar to the waterflood without fractures present. Waterflood recovery without fractures was RF=45%OOIP compared with RF=42%OOIP with fractures. The displacement pattern was in most cases determined by the location of the water in the fractures, and due to gravity segregation the lower blocks closer to the inlet imbibed water first. The combination of high capillary imbibition and the applied water injection rate led to the *filling regime* (Rangel-German and Kovscek, 2002) and co-current imbibition.

#### **5.2.2 Weakly water-wet**

Introduction to Enhanced Oil Recovery (EOR) 98 Processes and Bioremediation of Oil-Contaminated Sites

Fig. 3. The effect of wettability on the fracture-matrix fluid transfer during waterfloods in fractured block systems. Water is injected at the boundary on the left, and the direction of flow is from left to right. Fractures are indicated in black where not directly observed.

In strongly water-wet systems containing several disconnected matrix blocks the fractures were barriers to flow. The displacement process was governed by capillary forces, corroborated by the visualized displacement pattern with a block-by-block displacement attributed to discontinuity in the capillary pressure curve at the matrix-fracture interface. The positive capillary pressure in the matrix block during oil displacement trapped the water phase in the matrix block until the capillary pressure at both sides of the matrixfracture interface were equal. This occurred at the end of spontaneous imbibition, when Pc=0 in the matrix block. Water in the fracture network may imbibe into the adjacent downstream matrix block. Consequently, the fluid flow dynamics were strongly influenced by the presence of fractures at strongly water-wet conditions, but residual oil saturation and recovery were similar to the waterflood without fractures present. Waterflood recovery without fractures was RF=45%OOIP compared with RF=42%OOIP with fractures. The displacement pattern was in most cases determined by the location of the water in the fractures, and due to gravity segregation the lower blocks closer to the inlet imbibed water first. The combination of high capillary imbibition and the applied water injection rate led to

the *filling regime* (Rangel-German and Kovscek, 2002) and co-current imbibition.

**5.2.1 Strongly water-wet**

At weakly water-wet conditions oil was recovered by capillary imbibition of water from the fractures to the matrix blocks. The interconnected fracture network limited the viscous forces in the system as the injector and producer was in direct contact, see Figure 3. The mechanism for oil recovery was purely capillary imbibition of water from the fracture. The strength of the capillary pressure to transport water from the fracture network to the matrix was reduced compared with strongly water-wet condition. The weaker capillary forces led to a reduction in matrix-fracture transfer rate and increased the likelihood of *instantly filled fracture* regime (Rangel-German and Kovscek, 2002), with counter-current imbibition of water. The presence of fractures dramatically reduced the oil recovery. Waterflood oil recovery without fractures was RF=63%OOIP compared with RF=22%OOIP with the presence of fractures. This demonstrates the potential to increase oil recovery in fractured reservoirs by increasing the viscous forces.

#### **5.2.3 Weakly oil-wet**

The fracture system for the weakly oil-wet block was similar to the strongly water-wet block (see Figure 3). Waterfloods were performed both before and after fractures were present, injecting water with the same rate (2 cc/hr) in both cases. The waterflood oil recovery at fractured state was RF=15%OOIP, compared with RF=65%OOIP without the presence of fractures. In addition to a strong reduction in recovery, the fractures changed the time of water breakthrough to the producer. Water breakthrough without fractured was observed after 0.47PV injected, in contrast to only 0.10PV injected with fractures. The oil-wet wettability preference of the matrix suppressed oil recovery by capillary imbibition of water from the fracture network. Recovery was dictated by the ability to generate a differential pressure across the system. Displacement of oil from matrix only took place in the unfractured inlet block, once water entered the fracture network it rapidly filled the fractures, first the lower horizontal fracture, then the remaining fracture network before it reached the outlet. No transport of water from fracture to matrix was observed.

## **6. Enhanced oil recovery in fractured reservoirs**

Oil production from fractured oil reservoirs poses great challenges to the oil industry, particularly because fractures may exhibit permeabilities that are several orders of magnitude higher than the permeability of the rock matrix. Low viscosity fluids used for enhanced oil recovery, such as gases or supercritical fluids may channel into the highpermeable fractures, potentially leading to early breakthrough into the production well and low sweep efficiency. Carbonate reservoirs usually exhibit low porosity and may be extensively fractured. The oil-wet nature of the matrix reduces capillary imbibition of water. Carbonate reservoirs contributes substantially to US oil reserves (Manrique *et al.*, 2007), and the low primary recovery and the large number of carbonate reservoirs in the US and around the world makes them good targets for EOR efforts.

Foam has the potential to increase oil recovery by improving areal sweep, better vertical sweep (less gravity override), less viscous fingering, and diversion of gas away from higherpermeable or previously swept layers (Bernard and Holm, 1964, Holm, 1968, Hanssen *et al.*, 1994, Schramm, 1994; Rossen, 1995). Diversion of gas into lower-permeable layers using

Enhanced Oil Recovery in Fractured Reservoirs 101

injection, the gas only displaced surfactant in the fracture and was not able to penetrate the matrix to displace water. During pregenerated foam injection into the fracture; the foam was able to penetrate the matrix to displace water. The gas pressure in the fracture fluctuated highly as a result of the forming and breaking of gas bubbles in the fracture. The pressure fluctuations controlled the local gas rates in the fracture, as the gas phase switched between stationary to high flow rates continuously. The fluctuating pressure and flow contributed to the amount of gas invaded into the matrix. Surfactant in the matrix resided in the smallest

Fig. 4. The effect of foam on the transport of gas from the fracture to the matrix. Left column:

pure gas injection with gas flow was only in fracture. Right column: foam injection displacing water in the fracture and the matrix. In each image, sand grains are white, the aqueous surfactant solution is blue, gas is red, and the interface between the gas and the

pores and in corners.

surfactant is black.

foams have previously been reported (e.g. Casteel and Djabbarah, 1988, Llave *et al.*, 1990, Zerhboub *et al.*, 1994, Nguyen *et al.*, 2003 *et al.*). This may be important for fractured systems, where a very large permeability contrast exists and cross-flow between the zones occur (Bertin *et al.*, 1999).

The application of foam to enhance oil recovery was studied at different length scales in fractured systems with complementary imaging techniques. Experiments were performed on the micro scale, core plug scale, and the block scale to study the use of foam in a fractured system to improve oil recovery. At the *micro scale* the mechanism for gas and liquid transport from the fracture to the matrix was investigated. Liquid snap off at the pore throat was observed as a mechanism for foam generation within the matrix, whereas large pressure fluctuations along the fracture lead to foam invasion from the fracture to the matrix. At the *core scale* the added oil recovery during foam injection compared to gas injection was demonstrated in a fracture core plug with the presence of oil in the matrix. The increased pressure drop across the fracture contributed to fluid transport from the fracture to the matrix and displacement of oil. The wettability of the core plug was weakly oil-wet reflecting the reservoir wetting preference in several large carbonate oil fields. The same process was studied in at the *block scale*, where three forces (gravity, viscous, and capillary) were active simultaneously. The injection of pregenerated foam greatly increased recovery by increasing the differential pressure across the system. Foam injection was compared to waterfloods, surfactant injection, pure gas injection and co-injection of surfactant and gas (Haugen *et al.*, 2010a). Experimental results at each length scale are described in detail in the sections below.

## **6.1 EOR at the micro scale**

Foam injection in fractured reservoirs was studied at the micro scale using etched silicon micromodels manufactured at the Department of Earth Sciences, Stanford University (Hornbrook *et al.*, 1991; Buchgraber *et al.*, 2011). Experiments were designed to study the transport of gaseous phase from the fracture into the matrix during foam flow at a pore level. The micromodel represents an actual Berea sandstone pore space with respect to pore size distributions. The model was shaped as a square, with injection ports in each corner. Injection ports were paired and connected with a conduit that constituted a fracture. All injections were performed horizontally, without the influence of gravity. A NIKON microscope, in combination with a cam recorder, was used to visualize and store images of the displacement processes in the fracture and in the matrix during injections. The injected gas phase was N2, and the foam was pregenerated outside the micromodel by co-injecting gas and a standard 1wt% active AOS surfactant solution in a Berea sandstone core plug. Foam generation in silicon micromodels was previously reported by Kovscek *et al.*, 2007.

Figure 4 shows the displacement process during a pure gas injection (left column) and foam injection (right column) in a fractured reservoir. The fracture was located at the top of the image and in direct contact with a porous structure. Both fracture and matrix were initially fully saturated with surfactant solution. In each image sand grains are white, the aqueous surfactant solution is blue, gas is red, and the interface between the gas and the surfactant is black. A slight backpressure was applied to reduce gas compressibility effects. Total injection rate was 4 cc/hr during both the pure gas injection and during the foam injection. The gas fraction during foam injection was 0.95. The results show that during pure gas Introduction to Enhanced Oil Recovery (EOR) 100 Processes and Bioremediation of Oil-Contaminated Sites

foams have previously been reported (e.g. Casteel and Djabbarah, 1988, Llave *et al.*, 1990, Zerhboub *et al.*, 1994, Nguyen *et al.*, 2003 *et al.*). This may be important for fractured systems, where a very large permeability contrast exists and cross-flow between the zones occur

The application of foam to enhance oil recovery was studied at different length scales in fractured systems with complementary imaging techniques. Experiments were performed on the micro scale, core plug scale, and the block scale to study the use of foam in a fractured system to improve oil recovery. At the *micro scale* the mechanism for gas and liquid transport from the fracture to the matrix was investigated. Liquid snap off at the pore throat was observed as a mechanism for foam generation within the matrix, whereas large pressure fluctuations along the fracture lead to foam invasion from the fracture to the matrix. At the *core scale* the added oil recovery during foam injection compared to gas injection was demonstrated in a fracture core plug with the presence of oil in the matrix. The increased pressure drop across the fracture contributed to fluid transport from the fracture to the matrix and displacement of oil. The wettability of the core plug was weakly oil-wet reflecting the reservoir wetting preference in several large carbonate oil fields. The same process was studied in at the *block scale*, where three forces (gravity, viscous, and capillary) were active simultaneously. The injection of pregenerated foam greatly increased recovery by increasing the differential pressure across the system. Foam injection was compared to waterfloods, surfactant injection, pure gas injection and co-injection of surfactant and gas (Haugen *et al.*, 2010a). Experimental results at each length scale are described in detail in the

Foam injection in fractured reservoirs was studied at the micro scale using etched silicon micromodels manufactured at the Department of Earth Sciences, Stanford University (Hornbrook *et al.*, 1991; Buchgraber *et al.*, 2011). Experiments were designed to study the transport of gaseous phase from the fracture into the matrix during foam flow at a pore level. The micromodel represents an actual Berea sandstone pore space with respect to pore size distributions. The model was shaped as a square, with injection ports in each corner. Injection ports were paired and connected with a conduit that constituted a fracture. All injections were performed horizontally, without the influence of gravity. A NIKON microscope, in combination with a cam recorder, was used to visualize and store images of the displacement processes in the fracture and in the matrix during injections. The injected gas phase was N2, and the foam was pregenerated outside the micromodel by co-injecting gas and a standard 1wt% active AOS surfactant solution in a Berea sandstone core plug. Foam generation in silicon micromodels was previously reported by Kovscek *et al.*, 2007.

Figure 4 shows the displacement process during a pure gas injection (left column) and foam injection (right column) in a fractured reservoir. The fracture was located at the top of the image and in direct contact with a porous structure. Both fracture and matrix were initially fully saturated with surfactant solution. In each image sand grains are white, the aqueous surfactant solution is blue, gas is red, and the interface between the gas and the surfactant is black. A slight backpressure was applied to reduce gas compressibility effects. Total injection rate was 4 cc/hr during both the pure gas injection and during the foam injection. The gas fraction during foam injection was 0.95. The results show that during pure gas

(Bertin *et al.*, 1999).

sections below.

**6.1 EOR at the micro scale**

injection, the gas only displaced surfactant in the fracture and was not able to penetrate the matrix to displace water. During pregenerated foam injection into the fracture; the foam was able to penetrate the matrix to displace water. The gas pressure in the fracture fluctuated highly as a result of the forming and breaking of gas bubbles in the fracture. The pressure fluctuations controlled the local gas rates in the fracture, as the gas phase switched between stationary to high flow rates continuously. The fluctuating pressure and flow contributed to the amount of gas invaded into the matrix. Surfactant in the matrix resided in the smallest pores and in corners.

Fig. 4. The effect of foam on the transport of gas from the fracture to the matrix. Left column: pure gas injection with gas flow was only in fracture. Right column: foam injection displacing water in the fracture and the matrix. In each image, sand grains are white, the aqueous surfactant solution is blue, gas is red, and the interface between the gas and the surfactant is black.

Enhanced Oil Recovery in Fractured Reservoirs 103

was maintained for 170hrs (total 272PV, 247.5PV N2 gas and 24.5PV surfactant solution). A sharp initial increase and slowly rising differential pressure, reaching maximum at 25kPa, was observed. Foam was not observed at the effluent, but rater single menisci dividing alternate bubbles of liquid and gas. Final recovery after the foam injection demonstrate the potential of this technique, but the high number of pore volumes injected to reach ultimate

Foam injection as an EOR technique in fractured, oil-wet carbonate rocks was further investigated in a block sample. Oil recovery during waterflood, pure gasflood, and surfactant injection were compared with co-injection of gas and surfactant in a pregenerated foam injection. Three injections were performed: 1) a waterflood with 10 cc/hr injection rate, 2) a surfactant flood with 10 cc/hr injection rate, and 3) a pre-generated foam injection with an injection rate of 130 ml/hr (N2 gas fraction was 0.92). Figure 6 shows the experimental setup used with a Bentheim sandstone core plug as a foam generator. The

recovery must be improved for the technique to be successfully applied in the field.

Fig. 6. Experiment setup used during pregenerated foam injection in a fractured block

Figure 7 shows the oil recovery for each injection and the development in differential pressure. Waterflood produced RF=10%OOIP with a clean water-cut (i.e. no two-phase production). The subsequent surfactant injection produced an additional RF=2.5%OOIP during 9PV injected. The pre-generated foam injection produced additional oil, amounting to RF=75.7%OOIP, with a fast initial recovery followed by a slowly reducing oil production. Differential pressure across the block was fluctuating, with an overall increasing trend. Foam was not observed in the effluent, but rather as single menisci dividing alternate slugs

During pre-generated foam injection the differential pressure increased in all tests, and the oil production increased significantly. Foam was not observed at the outlet suggesting that foam collapsed or changed its configuration when advancing through the fracture(s). The destabilization of foam inhibited further foam front movement (Bernard and Jacobs, 1965). The mechanism(s) behind foam collapse cannot be distinguished from this work alone, but

**6.3 EOR at the block scale**

sample (Haugen *et al.*, 2010a).

plausible mechanisms include:

of liquid and gas.

fracture network in the block sample can also be seen.

## **6.2 EOR at the core plug scale**

Foam experiments in a fractured limestone core plug (length: 7.07 cm, diameter: 4.8cm) was performed to study the use of foam as an EOR technique in fractured reservoirs. The performance of foam was compared to pure gas injection. The wettability of the matrix was weakly oil-wet. The vertical fracture (top to bottom) in the horizontally positioned cylindrical core plugs constituted a rectangular slit. The fracture aperture was not measured, but was calculated from the empirical relationship between aperture and the measured permeability. Because the core plug was cut using a circular saw with a diamond coated blade, the fracture surface was assumed to be smoother than naturally-fractured reservoirs. The two half-cylindrical core plugs were inserted into a core holder and the confinement pressure was increased until a desired fracture aperture or system permeability was established.

Figure 5 shows the oil recovery and differential pressure buildup during the gas and foam injections. The core geometry is seen in the lower right corner, with the fracture plane indicated. Two injections were performed: 1) gasflood with N2 gas with 30 ml/hr injection rate, and 2) injection of pre- generated foam at 33ml/hr (N2 gas fraction at 0.91).

Fig. 5. The effect of foam as an EOR technique in fractured, oil-wet carbonate core plug.

Gasflood oil recovery was RF=4%OOIP, attributed to the oil in the fracture volume of the core. No pressure build up was recorded as the pressure remained at 0.15kPa during the injection (42hrs, 49PV). Significant increase in oil recovery was observed during the pregenerated foam injection, with RF=77%OOIP additional recovery. Oil recovery ceased after 30hrs injection (total 48PV, 43.7PV N2 gas and 4.3PV surfactant solution), but the injection was maintained for 170hrs (total 272PV, 247.5PV N2 gas and 24.5PV surfactant solution). A sharp initial increase and slowly rising differential pressure, reaching maximum at 25kPa, was observed. Foam was not observed at the effluent, but rater single menisci dividing alternate bubbles of liquid and gas. Final recovery after the foam injection demonstrate the potential of this technique, but the high number of pore volumes injected to reach ultimate recovery must be improved for the technique to be successfully applied in the field.

#### **6.3 EOR at the block scale**

Introduction to Enhanced Oil Recovery (EOR) 102 Processes and Bioremediation of Oil-Contaminated Sites

Foam experiments in a fractured limestone core plug (length: 7.07 cm, diameter: 4.8cm) was performed to study the use of foam as an EOR technique in fractured reservoirs. The performance of foam was compared to pure gas injection. The wettability of the matrix was weakly oil-wet. The vertical fracture (top to bottom) in the horizontally positioned cylindrical core plugs constituted a rectangular slit. The fracture aperture was not measured, but was calculated from the empirical relationship between aperture and the measured permeability. Because the core plug was cut using a circular saw with a diamond coated blade, the fracture surface was assumed to be smoother than naturally-fractured reservoirs. The two half-cylindrical core plugs were inserted into a core holder and the confinement pressure was increased until a desired fracture aperture or system permeability was

Figure 5 shows the oil recovery and differential pressure buildup during the gas and foam injections. The core geometry is seen in the lower right corner, with the fracture plane indicated. Two injections were performed: 1) gasflood with N2 gas with 30 ml/hr injection

rate, and 2) injection of pre- generated foam at 33ml/hr (N2 gas fraction at 0.91).

Fig. 5. The effect of foam as an EOR technique in fractured, oil-wet carbonate core plug.

Gasflood oil recovery was RF=4%OOIP, attributed to the oil in the fracture volume of the core. No pressure build up was recorded as the pressure remained at 0.15kPa during the injection (42hrs, 49PV). Significant increase in oil recovery was observed during the pregenerated foam injection, with RF=77%OOIP additional recovery. Oil recovery ceased after 30hrs injection (total 48PV, 43.7PV N2 gas and 4.3PV surfactant solution), but the injection

**6.2 EOR at the core plug scale**

established.

Foam injection as an EOR technique in fractured, oil-wet carbonate rocks was further investigated in a block sample. Oil recovery during waterflood, pure gasflood, and surfactant injection were compared with co-injection of gas and surfactant in a pregenerated foam injection. Three injections were performed: 1) a waterflood with 10 cc/hr injection rate, 2) a surfactant flood with 10 cc/hr injection rate, and 3) a pre-generated foam injection with an injection rate of 130 ml/hr (N2 gas fraction was 0.92). Figure 6 shows the experimental setup used with a Bentheim sandstone core plug as a foam generator. The fracture network in the block sample can also be seen.

Fig. 6. Experiment setup used during pregenerated foam injection in a fractured block sample (Haugen *et al.*, 2010a).

Figure 7 shows the oil recovery for each injection and the development in differential pressure. Waterflood produced RF=10%OOIP with a clean water-cut (i.e. no two-phase production). The subsequent surfactant injection produced an additional RF=2.5%OOIP during 9PV injected. The pre-generated foam injection produced additional oil, amounting to RF=75.7%OOIP, with a fast initial recovery followed by a slowly reducing oil production. Differential pressure across the block was fluctuating, with an overall increasing trend. Foam was not observed in the effluent, but rather as single menisci dividing alternate slugs of liquid and gas.

During pre-generated foam injection the differential pressure increased in all tests, and the oil production increased significantly. Foam was not observed at the outlet suggesting that foam collapsed or changed its configuration when advancing through the fracture(s). The destabilization of foam inhibited further foam front movement (Bernard and Jacobs, 1965). The mechanism(s) behind foam collapse cannot be distinguished from this work alone, but plausible mechanisms include:

Enhanced Oil Recovery in Fractured Reservoirs 105

the well (Shi and Rossen, 1998). For fractured reservoirs, the pressure drop generated by the low-mobility foam, extending from the displacement front back to the injection well, is an important mechanism to improve the sweep efficiency. The injection of pre-generated foam reported at the core and block scale was successful with respect to oil production, which significantly increased recovery in all samples. The process was inefficient in terms of the number of pore volumes required to recover the oil. Economically viable production rates and reduction of surfactant cost could be achieved by taking the necessary steps to reduce foam collapse, which could be caused by any of the mechanisms previously outlined. The increase of the foam tolerance to oil (Hanssen and Dalland, 1990;Dalland and Hanssen, 1993;Dalland and Vassenden, 1998;Hanssen and Dalland, 2000) is a proven method to make

Foam injection as an EOR technique at field scale should be considered to reduce gravity override and injectivity issues. Foam injection was successfully implemented on the Norwegian Continental Shelf in the Snorre field as a Foam-Assisted-Water-Alternating-Gas (FAWAG). This project revealed that important parameters for the success of foam injectivity were surfactant adsorption, critical surfactant concentration, foam drying effect, foam oil tolerance, and foam strength (Blaker *et al.*, 2002). Foam efficiency could also be improved with smaller well-spacing (Awan *et al.*, 2008). A surfactant preflush that alters the wettability of the fracture surface (removes oil) may benefit foam stability in the fracture. In vertical fractures, care should be taken to limit gravity segregated fluid flow during coinjection of aqueous and gaseous phases. During gas injection projects, foam should be injected as early as possible after gas breakthrough (Surguchev *et al.*, 1996). Foam injection in combination with other EOR efforts may also improve economics, for instance foam in

Complementary imaging techniques used to study EOR techniques such as waterflooding, gas injection, and foam injections in fractured oil reservoirs provide new and improved fundamental understanding of the oil recovery process. The use of complementary imaging techniques allows studying EOR processes in porous media from the micro scale (10-5-10-3m) to block scale (10-1-100) covering 5 orders of magnitude. The combination of two imaging techniques such as Magnetic Resonance Imaging (MRI) and Nuclear Tracer Imaging (NTI) enables a complementary investigation on materials and processes, where large scale

MRI provides high spatial resolution and fast data acquisition necessary to capture the processes that occur inside fractures less than 1 mm wide, whereas NTI provides information on macro-scale saturation distribution in larger fractured systems. The oil recovery mechanisms involved with waterflooding fractured carbonate blocks were found to be dependent on the wettability of the matrix, as the wettability had great impact on the fracture/matrix hydrocarbon exchange. The MRI images of oil saturation development inside the fractures revealed transport mechanisms for the wetting phase across fractures at several wettability conditions, and provided new and detailed information on fluid fracture crossing previously observed in block scale experiments investigated by NTI. The forming of oil droplets of the fracture surface at oil-wet conditions mechanistically corroborated the results previously observed when waterflooding chalk at water-wet conditions. Pore scale

(~meters) phenomena are controlled by small scale (micrometer) heterogeneities.

combination with ASP flooding or polymer gels (Wang *et al.*, 2006).

foam injections more efficient.

**7. Conclusion**

Fig. 7. The effect of foam as an EOR technique in fractured, oil-wet carbonate block sample.

## **6.4 EOR by foam injection in fractured reservoirs**

Enhanced oil recovery by foam injection during gravity drainage was studied numerically by reducing the gas mobility (Farajzadeh *et al.*, 2010). Water and oil were produced at the bottom of the fracture at the instance they were displaced from the matrix, resulting in the fracture always being gas-filled. With decreased fracture permeability, the mobility of all fluids was reduced, increasing the viscous forces in the system. Similar results were found by Haugen *et al.*, 2008 and Fernø *et al.*, 2008 where decreasing fracture transmissibility increased oil recovery during waterfloods. In the case of foam flow in fractured media, the apparent foam viscosity is more important for oil recovery than the reduction in fracture transmissibility because increased foam viscosity leads to increased differential pressure and the increased oil recovery.

The application of foam as an EOR technique in fractured reservoirs will also lead to improved sweep efficiency. This is essential in highly heterogeneous reservoirs, where the majority of fluid flow is concentrated in the high permeable zones. Continuous foam injection at fixed injection rate may improve sweep efficiency by raising the injection-well pressure (Shan and Rossen, 2004), but the pressure increase may be undesirable in conventional, un-fractured reservoirs, where a rise in injection-well pressure could damage Introduction to Enhanced Oil Recovery (EOR) 104 Processes and Bioremediation of Oil-Contaminated Sites

Fig. 7. The effect of foam as an EOR technique in fractured, oil-wet carbonate block sample.

Enhanced oil recovery by foam injection during gravity drainage was studied numerically by reducing the gas mobility (Farajzadeh *et al.*, 2010). Water and oil were produced at the bottom of the fracture at the instance they were displaced from the matrix, resulting in the fracture always being gas-filled. With decreased fracture permeability, the mobility of all fluids was reduced, increasing the viscous forces in the system. Similar results were found by Haugen *et al.*, 2008 and Fernø *et al.*, 2008 where decreasing fracture transmissibility increased oil recovery during waterfloods. In the case of foam flow in fractured media, the apparent foam viscosity is more important for oil recovery than the reduction in fracture transmissibility because increased foam viscosity leads to increased differential pressure and

The application of foam as an EOR technique in fractured reservoirs will also lead to improved sweep efficiency. This is essential in highly heterogeneous reservoirs, where the majority of fluid flow is concentrated in the high permeable zones. Continuous foam injection at fixed injection rate may improve sweep efficiency by raising the injection-well pressure (Shan and Rossen, 2004), but the pressure increase may be undesirable in conventional, un-fractured reservoirs, where a rise in injection-well pressure could damage

**6.4 EOR by foam injection in fractured reservoirs**

the increased oil recovery.

Oil intolerance

 Fracture wettability Divalent ions in the brine

Gravity segregation in the fracture

the well (Shi and Rossen, 1998). For fractured reservoirs, the pressure drop generated by the low-mobility foam, extending from the displacement front back to the injection well, is an important mechanism to improve the sweep efficiency. The injection of pre-generated foam reported at the core and block scale was successful with respect to oil production, which significantly increased recovery in all samples. The process was inefficient in terms of the number of pore volumes required to recover the oil. Economically viable production rates and reduction of surfactant cost could be achieved by taking the necessary steps to reduce foam collapse, which could be caused by any of the mechanisms previously outlined. The increase of the foam tolerance to oil (Hanssen and Dalland, 1990;Dalland and Hanssen, 1993;Dalland and Vassenden, 1998;Hanssen and Dalland, 2000) is a proven method to make foam injections more efficient.

Foam injection as an EOR technique at field scale should be considered to reduce gravity override and injectivity issues. Foam injection was successfully implemented on the Norwegian Continental Shelf in the Snorre field as a Foam-Assisted-Water-Alternating-Gas (FAWAG). This project revealed that important parameters for the success of foam injectivity were surfactant adsorption, critical surfactant concentration, foam drying effect, foam oil tolerance, and foam strength (Blaker *et al.*, 2002). Foam efficiency could also be improved with smaller well-spacing (Awan *et al.*, 2008). A surfactant preflush that alters the wettability of the fracture surface (removes oil) may benefit foam stability in the fracture. In vertical fractures, care should be taken to limit gravity segregated fluid flow during coinjection of aqueous and gaseous phases. During gas injection projects, foam should be injected as early as possible after gas breakthrough (Surguchev *et al.*, 1996). Foam injection in combination with other EOR efforts may also improve economics, for instance foam in combination with ASP flooding or polymer gels (Wang *et al.*, 2006).

## **7. Conclusion**

Complementary imaging techniques used to study EOR techniques such as waterflooding, gas injection, and foam injections in fractured oil reservoirs provide new and improved fundamental understanding of the oil recovery process. The use of complementary imaging techniques allows studying EOR processes in porous media from the micro scale (10-5-10-3m) to block scale (10-1-100) covering 5 orders of magnitude. The combination of two imaging techniques such as Magnetic Resonance Imaging (MRI) and Nuclear Tracer Imaging (NTI) enables a complementary investigation on materials and processes, where large scale (~meters) phenomena are controlled by small scale (micrometer) heterogeneities.

MRI provides high spatial resolution and fast data acquisition necessary to capture the processes that occur inside fractures less than 1 mm wide, whereas NTI provides information on macro-scale saturation distribution in larger fractured systems. The oil recovery mechanisms involved with waterflooding fractured carbonate blocks were found to be dependent on the wettability of the matrix, as the wettability had great impact on the fracture/matrix hydrocarbon exchange. The MRI images of oil saturation development inside the fractures revealed transport mechanisms for the wetting phase across fractures at several wettability conditions, and provided new and detailed information on fluid fracture crossing previously observed in block scale experiments investigated by NTI. The forming of oil droplets of the fracture surface at oil-wet conditions mechanistically corroborated the results previously observed when waterflooding chalk at water-wet conditions. Pore scale

Enhanced Oil Recovery in Fractured Reservoirs 107

Bailey, N.A., Rowland, P.R. and Robinson, D.P. "Nuclear Measurements of Fluid Saturation

Baldwin, B.A. and Spinler, E.A. "A direct method for simultaneously determining positive

Baldwin, B.A. and King, R. "Why Would an Oil Company use MRI", Spatially Resolved

Barrenblatt, G.I., Zheltov, I.P. and Kochina, I.N. "Basic concepts in the theory of the seepage

Behbahani, H. and Blunt, M.J. "Analysis of Imbibition in Mixed-Wet Rocks Using Pore-Scale

Bernard, G.B. and Jacobs, W.L. "Effect of Foam on Trapped Gas Saturation and on

Bernard, G.G. and Holm, L.W. "Effect of Foam on Permeability of Porous Media to Gas",

Bertin, H.J., Apaydin, O.G., Castanier, L.M. and Kovscek, A.R. "Foam Flow in Heterogeneous Porous Media: Effect of Crossflow", *SPEJ* 4(2):pp.75-82, 1999 Blaker, T., Aarra, M.G., Skauge, A., Rasmussen, L., Celius, H.K., Martinsen, H.A. and

Casteel, J.F. and Djabbarah, N.F. "Sweep Improvement in CO2 Flooding by Use of Foaming

Dalland, M. and Hanssen, J.E. "Foam barriers against gas coning: Gas blocking with

Dalland, M. and Vassenden, F. "Cost-effective foams for gas influx control: Role of polymer additive", 19th IEA Workshop & Symposium on IOR, Carmel, CA, 1998 Ersland, G., Fernø, M.A., Graue, A., Baldwin, B.A. and Stevens, J. "Complementary imaging

Farajzadeh, R., Wassing, L.B.M. and Boerrigter, P.M. "Foam Assisted Gas Oil Gravity

Fernø, M.A. "A Study of Capillary Pressure and Capillary Continuity in Fractured Rocks" PhD, Dept. of Physics and Technology, Univeristy of Bergen, Bergen, 2008 Fernø, M.A., Haugen, Å., Howard, J.J. and Graue, A. "The significance of wettability and

Project", *SPE Reservoir Evaluation & Engineering* 5(4):pp.317-323, 2002 Buchgraber, M., Clemens, T., Castanier, L.M. and Kovscek, A. "A Microvisual Study of the

Agents", *SPE Reservoir Engineering* 3(4):pp.1186-1192, 1988

and Exhibition, Florence, Italy, 09/19/2010, 2010

Vassenden, F. "Foam for Gas Mobility Control in the Snorre Field: The FAWAG

Displacement of Viscous Oil by Polymer Solutions", *SPE Reservoir Evaluation &*

hydrocarbon foams", 7th European Symposium on Improved Oil Recovery

of oil recovery mechanisms in fractured reservoirs", *Chemical Engineering Journal*

Drainage in Naturally-Fractured Reservoirs", SPE Annual Technical Conference

fracture properties on oil recovery efficiency in fractured carbonates", International Symposium of the Society of Core Analysts, Abu Dhabi, October 29-November 2,

Bournemouth, UK, September 21-23, 1981

Modeling", *SPE J.* 10(4):pp.466-473, 2005

Permeability of Porous Media to Water", *SPEJ* 41965

VCH, New York, 1999

4(3):pp.267 - 274, 1964

*Engineering* 14(3)2011

Moscow, Russia, 1993

158(1):pp.32-38, 2010

2008

1303, 1960

*Science and Engineering* 20(3-4):pp.161-165, 1998

in EOR Flood Experiments", European Symposium on Enhanced Oil Recovery,

and negative capillary pressure curves in reservoir rock", *Journal of Petroleum*

Magnetic Resonance (Methods, materials, Medicine, Biology, Rheology, Geology, Ecology, Hard Wave), P. Blumler, B. Blumich, R. Botto and E. Fukushima, Wiley-

of homogeneous liquids in fissured rocks (strada)", *J. Appl. Math. Mech.* 24:pp.1286-

modeling should be considered as a tool to calculate more accurately the capillary pressure and relative permeability curves in the fracture in the presence of growing liquid droplets. This would increase the confidence in the applied multiphase functions and strengthen the overall physical understanding of flow in fractured rocks. The derived multiphase functions should be implemented in the numerical model, and the errors by not accounting for this should be understood and quantified.

The effect of capillary pressures at various wettabilities was experimentally studied at different length scales, which was used as the basis for numerical simulations of multiphase flow in fractured reservoirs. This review demonstrates the influence of capillary pressure as a vital input parameter in simulations to describe fluid flow in the reservoirs and as the dominant multiphase function for important recovery mechanisms in fractured reservoirs; such as spontaneous imbibition and gravity drainage.

Injection of pre-generated foam greatly enhanced oil recovery, with recoveries up to 80%OOIP. Increased apparent foam viscosity increased oil recovery in similar fractured systems. Enhanced oil recovery by pre-generated foam injection in fractured, oil-wet limestone was observed only after high pore volumes throughput. Oil recovery efficiency may increase by reducing the rate of foam collapse in the fractures by:

## **8. Acknowledgement**

The Royal Norwegian Research Council, BP, Statoil and ConocoPhillips for financial support.

## **9. References**

Introduction to Enhanced Oil Recovery (EOR) 106 Processes and Bioremediation of Oil-Contaminated Sites

modeling should be considered as a tool to calculate more accurately the capillary pressure and relative permeability curves in the fracture in the presence of growing liquid droplets. This would increase the confidence in the applied multiphase functions and strengthen the overall physical understanding of flow in fractured rocks. The derived multiphase functions should be implemented in the numerical model, and the errors by not accounting for this

The effect of capillary pressures at various wettabilities was experimentally studied at different length scales, which was used as the basis for numerical simulations of multiphase flow in fractured reservoirs. This review demonstrates the influence of capillary pressure as a vital input parameter in simulations to describe fluid flow in the reservoirs and as the dominant multiphase function for important recovery mechanisms in fractured reservoirs;

Injection of pre-generated foam greatly enhanced oil recovery, with recoveries up to 80%OOIP. Increased apparent foam viscosity increased oil recovery in similar fractured systems. Enhanced oil recovery by pre-generated foam injection in fractured, oil-wet limestone was observed only after high pore volumes throughput. Oil recovery efficiency

The Royal Norwegian Research Council, BP, Statoil and ConocoPhillips for financial

Allen, J. and Sun, S.Q. "Controls on Recovery Factor in Fractured Reservoirs: Lessons

Amott, E. "Observations Relating to the Wettability of Porous Rock", *Trans. AIME*

Aronofsky, J.S., Masse, L. and Natanson, S.G. "A model for the mechanism of oil recovery

Aspenes, E., Graue, A., Baldwin, B.A., Moradi, A., Stevens, J. and Tobola, D.P. "Fluid Flow

Aspenes, E., Ersland, G., Graue, A., Stevens, J. and Baldwin, B.A. "Wetting Phase Bridges

Mixed-Wet Fractured Chalk", *Transport in Porous Media* 74(1):pp.35-47, 2008 Awan, A.R., Teigland, R. and Kleppe, J. "A Survey of North Sea Enhanced-Oil-Recovery

Learned from 100 Fractured Fields", SPE ATCE, Denver, CO, USA, October 4-7,

from the porous matrix due to water invasion in fractured reservoirs", *Trans. AIME*

in Fractures Visualized by MRI During Waterfloods at Various Wettability Conditions - Emphasis on Fracture Width and Flow Rate", SPE ATCE, San Antonio,

Establish Capillary Continuity Across Open Fractures and Increase Oil Recovery in

Projects Initiated During the Years 1975 to 2005", *SPE Reservoir Evaluation &*

should be understood and quantified.

Improving the foam oil tolerance.

216:pp.156-162, 1959

213:pp.17-19, 1958

TX, USA, Sept. 29-Oct.3, 2002

*Engineering* 11(3):pp.497-512, 2008

**8. Acknowledgement**

support.

**9. References**

2003

such as spontaneous imbibition and gravity drainage.

Optimizing the injection of foam (e.g. FAWAG).

may increase by reducing the rate of foam collapse in the fractures by:

Changing the wettability of the fracture surface to water-wet.

Enhanced Oil Recovery in Fractured Reservoirs 109

Hornbrook, J.W., Castanier, L.M. and Pettit, P.A. "Observation of Foam/Oil Interactions in a

Jackson, M.D., Valvatne, P.H. and Blunt, M.J. "Prediction of wettability variation and its

Jadhunandan, P.P. and Morrow, N.R. "Effect of Wettability on Waterflood Recovery for Crude-Oil/Brine/Rock Systems", *SPE Reservoir Eng.* 10(1):pp.40-46, 1995 Johannesen, E., Steinsbø, M., Howard, J.J. and Graue, A. "Wettability characterization by

Kazemi, H., Merril Jr., J.S., Poterfield, K.L. and Zeman, P.R. "Numerical simulation of wateroil flow in naturally fractured reservoirs", *SPE J.* 16:pp.317-326, 1976 Kovscek, A.R., Tang, G.Q. and Radke, C.J. "Verification of Roof snap off as a foam-

Li, K. and Horne, R.N. "A General Scaling Method for Spontaneous Imbibition", SPE ATCE,

Llave, F.M., Chung, F.T.-H., Louvier, R.W. and Hudgins, D.A. "Foams as Mobility Control

Ma, S., Morrow, N.R. and Zhang, X. "Generalized scaling of spontaneous imbibition data for

Manrique, E.J., Muci, V.E. and Gurfinkel, M.E. "EOR Field Experiences in Carbonate

Mattax, C.C. and Kyte, J.R. "Imbibition Oil Recovery from Fractured, Water-Drive

Miller, M. "Naturally Fractured Reservoir Engineering", Reservoir Engineering Course

Morrow, N.R. and Mason, G. "Recovery of oil by spontaneous imbibition", *Current Opinion*

Nguyen, Q.P., Currie, P.K. and Zitha, P.L.J. "Effect of Capillary Cross-Flow on Foam-

Rangel-German, E.R. and Kovscek, A.R. "Experimental and analytical study of

Rossen, W.R. and Kumar, A.T.A. "Effect of Fracture Relative Permeabilities on Performance

Rossen, W.R. "Foams in Enhanced Oil Recovery", Foams : theory, measurements, and

*Physicochemical and Engineering Aspects* 302(1-3):pp.251-260, 2007

Exhibition, Dallas, Texas, 01/01/1991, 1991

*Science and Engineering* 39(3-4):pp.231-246, 2003

Analysts, Trondheim, Norway, September 12-16 2006

San Antonio, TX, USA, September 29-October 2, 2002

Symposium, Tulsa, Oklahoma, 04/22/1990, 1990

Handouts, HOT Engineering, Vienna, Austria, 2007

Conference, The Hague, Netherlands, 05/13/2003, 2003

Exhibition of Mexico, Veracruz, Mexico, 10/10/1994, 1994

*in Colloid & Interface Science* 6(4):pp.321-337, 2001

*Science and Engineering* 36(1-2):pp.45-60, 2002

Reservoir", *SPE J.* 2(2):pp.177-184, 1962

4):pp.165-178, 1997

667-686, 2007

1995

New, High-Resolution Micromodel", SPE Annual Technical Conference and

impact on flow using pore- to reservoir-scale simulations", *Journal of Petroleum*

NMR T2 measurements in chalk", International Symposium of the Society of Core

generation mechanism in porous media at steady state", *Colloids and Surfaces A:*

Agents for Oil Recovery by Gas Displacement", SPE/DOE Enhanced Oil Recovery

strongly water-wet systems", *Journal of Petroleum Science and Engineering* 18(3-

Reservoirs in the United States", *SPE Reservoir Evaluation & Engineering* 10(6):pp.pp.

Induced Diversion in Layered Formations", SPE European Formation Damage

multidimensional imbibition in fractured porous media", *Journal of Petroleum*

of Naturally Fractured Reservoirs", International Petroleum Conference and

applications, R. K. Prud'homme and S. A. Khan, Marcel Dekker, Inc., New York,

Introduction to Enhanced Oil Recovery (EOR) 108 Processes and Bioremediation of Oil-Contaminated Sites

Fernø, M.A., Torsvik, M., Haugland, S. and Graue, A. "Dynamic Laboratory Wettability

Fernø, M.A., Haugen, Å. and Graue, A. "Wettability effects on the matrix–fracture fluid

Graue, A., Kolltveit, K., Lien, J.R. and Skauge, A. "Imaging Fluid Saturation Development in Long-Core Flood Displacements", *SPE Form. Eval.* 5(4):pp.406-412, 1990 Graue, A., Tonheim, E. and Baldwin, B.A. "Control and alteration of wettability in low-

Graue, A., Viksund, B.G. and Baldwin, B.A. "Reproduce Wettability Alteration of Low-

Graue, A., Viksund, B.G. and Baldwin, B.A. "Reproducible Wettability Alteration of Low-

Graue, A., Viksund, B.G., Eilertsen, T. and Moe, R. "Systematic wettability alteration by

Graue, A., Aspenes, E., Moe, R.W., Baldwin, B.A., Moradi, A., Stevens, J. and Tobola, D.

Hanssen, J.E. and Dalland, M. "Foams for Effective Gas Blockage in the Presence of Crude

Hanssen, J.E., Holt, T. and Surguchev, L.M. "Foam Processes: An Assessment of Their

Hanssen, J.E. and Dalland, M. "Increased Oil Tolerance of Polymer-Enhanced Foams: Deep

Haugen, A., Ferno, M.A., Graue, A. and Bertin, H.J. "Experimental Study of Foam Flow in

Haugen, Å., Fernø, M.A. and Graue, A. "Numerical simulation and sensitivity analysis of in-

Recovery Symposium, Tulsa, Oklahoma, 04/03/2000, 2000

Presence of Foam", 8(4):pp.359 - 369, 1968

Recovery Symposium, Tulsa, Oklahoma, USA, 01/01/2010, 2010a

transfer in fractured carbonate rocks", *Journal of Petroleum Science and Engineering*

permeability chalk", 3rd International Symposium on Evaluation of Reservoir Wettability and Its Effect on Oil Recovery University of Wyoming, Laramie, WY,

Permeable Outcrop Chalk", SPE/DOE Improved Oil Recovery Symposium, Tulsa,

Permeable Outcrop Chalk", *SPE Reservoir Evaluation & Engineering* 2(2):pp.134-140,

aging sandstone and carbonate rock in crude oil", *Journal of Petroleum Science and*

"MRI Tomography of Saturation Development in Fractures During Waterfloods at Various Wettability Conditions", SPE ATCE, New Orleans, LA, USA, September

Oil", SPE/DOE Enhanced Oil Recovery Symposium, Tulsa, Oklahoma, 04/22/1990,

Potential in North Sea Reservoirs Based on a Critical Evaluation of Current Field Experience", SPE/DOE Improved Oil Recovery Symposium, Tulsa, Oklahoma,

Chemistry or Just "Simple" Displacement Effects?", SPE/DOE Improved Oil

Fractured Oil-Wet Limestone for Enhanced Oil Recovery", SPE Improved Oil

situ fluid flow in MRI laboratory waterfloods of fractured carbonate rocks at different wettabilities", SPE ATCE, Denver, CO, USA, September 21-24, 2008 Haugen, Å., Fernø, M.A., Bull, Ø. and Graue, A. "Wettability Impacts on Oil Displacement in Large Fractured Carbonate Blocks", *Energy & Fuels* 24(5):pp.3020-3027, 2010b Holm, L.W. "The Mechanism of Gas and Liquid Flow Through Porous Media in the

Alteration", *Energy & Fuels* 24(7):pp.3950-3958, 2010

77(1):pp.146-153, 2011

Oklahoma, 04/19/1998, 1998

*Engineering* 24(2-4):pp.85-97, 1999b

1996

1999a

1990

30-October 3, 2001

04/17/1994, 1994

**Section 2**

**Environmental Management**

**Through Bioremediation**