**2. Technical approach**

The Advanced Reactive Transport Simulator (ARTS) at the University of Utah was used to perform simulation studies (Figure 2). ARTS is a modular reservoir simulator that has been under development over a number of years [2-4]. The main idea of ARTS is to decouple the discretization methods from the physical models. The discretization methods in ARTS include the conventional finite difference, control-volume finite element and a generalized control volume method. These discretization methods could be coupled with a variety of physical models. The simplest physical model would be simulation of a single-phase gas with immov‐ able water phase. Two-phase and three-phase black oil models are used to simulate primary production followed by water and polymer flooding. Thermal processes such as steam flooding, in-situ combustion, steam-assisted gravity drainage, etc. are represented in K-value based thermal-compositional models. In these models, the vapor-liquid equilibrium is calculated using the ratio between the vapor and the liquid phase composition of each component (K-value). ARTS also includes a geochemical module to simulate processes associated with carbon dioxide sequestration and reactions involving carbon dioxide, brine and rocks.

**1. Introduction**

barrels in 2011 [1] (Figure 1).

808 Effective and Sustainable Hydraulic Fracturing

The growth in producing hydrocarbons from unconventional reservoirs (shales) has been phenomenal. The production of liquids from the Eagle Ford play grew to about 52 million

**Figure 1.** The phenomenal growth in production of liquids from shales with Eagle Ford. In just over a three-year peri‐

The growth in production is driven by improvements in hydraulic fracturing technology. Multistage fracturing using long horizontal wells is the common practice. Millions of gallons of water are pumped into the formation to create these fractures. Industry data reveals that only about a third of the injected water is typically recovered. The fate of injected water is of fundamental interest. Use of large quantities of water in fracturing has brought into question the sustainability of this type of completion and development practice. Furthermore, low water recovery has prompted environmental concerns about whether the injected water leaves the target formation with a potential of infiltrating and contaminating aquifers. The purpose of this paper was to examine the capability of the formation to imbibe the injected water based

The Advanced Reactive Transport Simulator (ARTS) at the University of Utah was used to perform simulation studies (Figure 2). ARTS is a modular reservoir simulator that has been under development over a number of years [2-4]. The main idea of ARTS is to decouple the discretization methods from the physical models. The discretization methods in ARTS include the conventional finite difference, control-volume finite element and a generalized control volume method. These discretization methods could be coupled with a variety of physical models. The simplest physical model would be simulation of a single-phase gas with immov‐ able water phase. Two-phase and three-phase black oil models are used to simulate primary

od, insignificant production has been transformed to over 52 million barrels of liquids in 2011.

on different capillary pressure relationships.

**2. Technical approach**

The use of a control volume finite element model as one of the discretization schemes allows multiphase simulation of complex reservoir geometries including a discrete fracture network representation of natural and hydraulic fractures.

**Figure 2.** The framework used in simulating water injection and production in fractured systems. The discretization methods (DM) are decoupled from the physical models (PM).

We represented and simulated two different discrete fracture domains in this work – both with non-orthogonal features (Figure 3). It is common practice to represent and simulate hydraulic fractures as orthogonal features. However, it is evident that the fractures created are not perfectly perpendicular to the horizontal well. The microseimic cloud that is observed in a number of cases with multiple horizontal fractures (for example, [5]), shows fractures that are more complex than regularly spaced orthogonal features. It is true that there is no one to one correlation between the microseismic signatures and the shape and morphology of hydraulic fractures. However, there are a number of indications that point to the hydraulic fractures being more complex than simple orthogonal features.

There has been much discussion about wettability of shales. In this paper, we examined the differences in water recovery due to variations in wettability of the rock. The three sets of oil-

> Water Wet Mixed Wet Oil Wet

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0 0.2 0.4 0.6 0.8 1

**Water Saturation**

Over most of the saturation range for the oil and mixed wet situations, the capillary pressures are negative, indicating a preference for oil as the wetting fluid. Other domain-specific

water capillary pressures used in the study are shown in Figure 4.


**Figure 4.** The three sets of capillary pressures used in this study.

Initial Reservoir Pressure 2000 psia Fracture Permeability 1000 mD Porosity 20% Matrix Permeability 0.5 mD Water Injected 30000 barrels

Domain Size 260 feet X 260 feet X 100 feet

parameters are shown in Table 1.

**Table 1.** Properties of the domain and simulations




0

100

**Capillary Pressure (psia)**

200

300

400

500

600

**Figure 3.** Figure showing two fractured systems simulated in this study.

The hydraulic fractures created interact with existing natural fractures. The role of natural fractures in production of fluids from shales is still an open question. The production behavior of both the gas and liquid reservoirs does not indicate a highly fractured system. On the other hand, when fracturing water is injected in a well, it is common to see interference in an adjacent well. This may be in the form of pressure interference or explicit breakthrough of water injected in the adjacent well. Pressure interference in and of itself does not indicate fluid transport to the well.

Capillary pressures for these shale reservoirs are not well characterized. The wettability of the reservoir rocks is also not well known. Al-Bazali et al. [6], measured sealing capacities of shale caprocks. This data provides some guidance for the capillary pressure values and relationships to use for these systems. The general capillary pressure relationship is given by:

$$P\_c = \frac{2\sigma\cos\theta}{r}$$

In this equation, Pc is the capillary pressure, σ is the interfacial tension between the immiscible fluids of interest, θ is the contact angle and r is the average pore radius. Al-Bazali et al.[6], were considering shales that were less than 10 nD in permeability. For the three shales studied, they measured entry pressures ranging from 470 psia to 750 psia. They calculated pore throat radii of about 30 nM for entry pressures of crude oil. For pore throats of less than 10 nM (Sondergeld et al. [7]), very large capillary pressures (two to three times those measured by Al-Bazali et al [7]) are possible.

There has been much discussion about wettability of shales. In this paper, we examined the differences in water recovery due to variations in wettability of the rock. The three sets of oilwater capillary pressures used in the study are shown in Figure 4.

**Figure 4.** The three sets of capillary pressures used in this study.

more complex than regularly spaced orthogonal features. It is true that there is no one to one correlation between the microseismic signatures and the shape and morphology of hydraulic fractures. However, there are a number of indications that point to the hydraulic fractures

The hydraulic fractures created interact with existing natural fractures. The role of natural fractures in production of fluids from shales is still an open question. The production behavior of both the gas and liquid reservoirs does not indicate a highly fractured system. On the other hand, when fracturing water is injected in a well, it is common to see interference in an adjacent well. This may be in the form of pressure interference or explicit breakthrough of water injected in the adjacent well. Pressure interference in and of itself does not indicate fluid transport to

Capillary pressures for these shale reservoirs are not well characterized. The wettability of the reservoir rocks is also not well known. Al-Bazali et al. [6], measured sealing capacities of shale caprocks. This data provides some guidance for the capillary pressure values and relationships

In this equation, Pc is the capillary pressure, σ is the interfacial tension between the immiscible fluids of interest, θ is the contact angle and r is the average pore radius. Al-Bazali et al.[6], were considering shales that were less than 10 nD in permeability. For the three shales studied, they measured entry pressures ranging from 470 psia to 750 psia. They calculated pore throat radii of about 30 nM for entry pressures of crude oil. For pore throats of less than 10 nM (Sondergeld et al. [7]), very large capillary pressures (two to three times those measured by Al-Bazali et al

to use for these systems. The general capillary pressure relationship is given by:

being more complex than simple orthogonal features.

**Figure 3.** Figure showing two fractured systems simulated in this study.

Large cross-cutting feature

810 Effective and Sustainable Hydraulic Fracturing

the well.

*Pc* <sup>=</sup> <sup>2</sup>*σ*cos*<sup>θ</sup> r*

[7]) are possible.

Over most of the saturation range for the oil and mixed wet situations, the capillary pressures are negative, indicating a preference for oil as the wetting fluid. Other domain-specific parameters are shown in Table 1.


**Table 1.** Properties of the domain and simulations

Water recovery after one month (30 days) for each of the simulations was compiled. For the base case capillary pressures, the water recoveries for the three wetting scenarios and for the two domains (one with the cross-cutting fracture, and one without) are shown in Table 2.

At smaller pore radii, the capillary pressures are expected to be larger. One set of simulations were performed where the shape of the base case capillary pressures were maintained, but the capillary pressures were increased ten times for each of the saturation values. The resulting

The Fate of Injected Water in Shale Formations

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813

**Water Wet Mixed Wet Oil Wet**

20.1% 27.15% 41.9%

23.3% 30.2% 45.5%

**Table 4.** Water recoveries for the three wetting scenarios and for the two domains studied in this paper. Recoveries are for the case where the capillary pressures were ten times the base case capillary pressures used. The shapes of the capillary pressure curves were the same as the ones used in Figure 4. The initial reservoir pressure was 5000 psia and

As the capillary pressure increases, more water is retained. For mixed wet and oil wet scenarios, water saturation in the matrix area is lower (Figure 5). Similar relative difference between recoveries is maintained when recoveries are compared for domains with and without the large cross-cutting features. The system without the large cross-cutting fracture in this case returns on the average about 3% more water than when the large fracture exists. Water

saturations for the domain without the large fracture are shown in Figure 6.

Large cross-cutting feature

**Figure 5.** Figure showing water saturations in the matrix through one hydraulic fracture and interacting natural frac‐ tures. Left panel is for the water wet case, the middle panel is for the mixed wet case and the right panel is the oil wet case. As the wettability goes from water wet to oil wet the infiltration decreases increasing injected water recovery. In

this particular example, the large cross-cutting feature does not take a significant amount of water off site.

recoveries are tabulated in Table 4.

Water recovery ratio(With cross-cutting fracture)

the matrix permeability was 0.1 mD.

Water recovery ratio (Without the cross-cutting

fracture)


**Table 2.** Water recoveries for the three wetting scenarios and for the two domains studied in this paper. Recoveries are for the base case where the initial reservoir pressure was 2000 psia and the matrix permeability was 0.5 mD.

The water recoveries observed in the table above are consistent with water recoveries of about 20-40% listed in field observations. Water recoveries increase as we go from water wet to mixed wet to oil wet clearly indicating the tendency of the matrix to imbibe and hold water as the formation becomes more water wet. There is a 15% increase in water recovery as we go from water wet to the oil wet case. The presence of the long cross-cutting feature does not make a significant impact in recovery. The recovery does decrease as injected water is transported to longer distances – but the difference in recovery is only 1-2%.

In a number of shale reservoirs, the permeabilities are lower and the initial pressures are higher. To investigate the effects of these parameters on recovery, simulations were performed with 5000 psia initial pressure and 0.1 mD matrix permeability. Results of these simulations are tabulated in Table 3.


**Table 3.** Water recoveries for the three wetting scenarios and for the two domains studied in this paper. Recoveries are for the base case where the initial reservoir pressure was 5000 psia and the matrix permeability was 0.1 mD.

Higher initial pressure results in higher water recoveries, particularly in the water wet cases. The differences between recoveries with and without the large cross-cutting feature are now between 4-5%. The differences between the different wettability cases however are reduced to only about 8% (compared to about 15%) as the largest difference the water wet and the oil wet scenarios.

At smaller pore radii, the capillary pressures are expected to be larger. One set of simulations were performed where the shape of the base case capillary pressures were maintained, but the capillary pressures were increased ten times for each of the saturation values. The resulting recoveries are tabulated in Table 4.

Water recovery after one month (30 days) for each of the simulations was compiled. For the base case capillary pressures, the water recoveries for the three wetting scenarios and for the two domains (one with the cross-cutting fracture, and one without) are shown in Table 2.

Water recovery ratio(With cross-cutting fracture)

812 Effective and Sustainable Hydraulic Fracturing

tabulated in Table 3.

Water recovery ratio(With cross-cutting fracture)

Water recovery ratio (Without the cross-cutting

fracture)

scenarios.

Water recovery ratio (Without the cross-cutting

fracture)

**Water Wet Mixed Wet Oil Wet**

21.53% 29.35% 36.28%

22.97% 31.24% 38.39%

**Table 2.** Water recoveries for the three wetting scenarios and for the two domains studied in this paper. Recoveries are for the base case where the initial reservoir pressure was 2000 psia and the matrix permeability was 0.5 mD.

The water recoveries observed in the table above are consistent with water recoveries of about 20-40% listed in field observations. Water recoveries increase as we go from water wet to mixed wet to oil wet clearly indicating the tendency of the matrix to imbibe and hold water as the formation becomes more water wet. There is a 15% increase in water recovery as we go from water wet to the oil wet case. The presence of the long cross-cutting feature does not make a significant impact in recovery. The recovery does decrease as injected water is transported to

In a number of shale reservoirs, the permeabilities are lower and the initial pressures are higher. To investigate the effects of these parameters on recovery, simulations were performed with 5000 psia initial pressure and 0.1 mD matrix permeability. Results of these simulations are

**Water Wet Mixed Wet Oil Wet**

37.42% 40.17% 44.19%

41.02% 44.61% 49.83%

**Table 3.** Water recoveries for the three wetting scenarios and for the two domains studied in this paper. Recoveries are for the base case where the initial reservoir pressure was 5000 psia and the matrix permeability was 0.1 mD.

Higher initial pressure results in higher water recoveries, particularly in the water wet cases. The differences between recoveries with and without the large cross-cutting feature are now between 4-5%. The differences between the different wettability cases however are reduced to only about 8% (compared to about 15%) as the largest difference the water wet and the oil wet

longer distances – but the difference in recovery is only 1-2%.


**Table 4.** Water recoveries for the three wetting scenarios and for the two domains studied in this paper. Recoveries are for the case where the capillary pressures were ten times the base case capillary pressures used. The shapes of the capillary pressure curves were the same as the ones used in Figure 4. The initial reservoir pressure was 5000 psia and the matrix permeability was 0.1 mD.

As the capillary pressure increases, more water is retained. For mixed wet and oil wet scenarios, water saturation in the matrix area is lower (Figure 5). Similar relative difference between recoveries is maintained when recoveries are compared for domains with and without the large cross-cutting features. The system without the large cross-cutting fracture in this case returns on the average about 3% more water than when the large fracture exists. Water saturations for the domain without the large fracture are shown in Figure 6.

**Figure 5.** Figure showing water saturations in the matrix through one hydraulic fracture and interacting natural frac‐ tures. Left panel is for the water wet case, the middle panel is for the mixed wet case and the right panel is the oil wet case. As the wettability goes from water wet to oil wet the infiltration decreases increasing injected water recovery. In this particular example, the large cross-cutting feature does not take a significant amount of water off site.

### **3. Conclusions**

Recovery of water injected for hydraulic fracturing in shales is only about 30%. There is a question of the fate of injected water. In this paper we studied water retention in shales for different shale wettability conditions. Two different domains where a hydraulic fracture intersected with a small existing network of natural fractures were used in the simulations. A specially developed framework that can handle representation of complex fracture networks was used for simulations. Capillary pressures in rocks containing very small pores tend to be high – of the order of 1000 psia. Three sets of capillary pressures – water wet, mixed wet and oil wet were examined. Simulations showed that a recovery of 20-30% is expected for typical water wet conditions, while a recovery of about 37%-48% is expected for oil wet scenarios. The recovery for mixed wet conditions fell between these two extremes. The recovery is reduced when a large cross-cutting fracture is introduced – but not significantly. That is because water will be recovered if the fractures are interconnected. Results discussed in this paper helped quantify the role of wettability in the recovery of water used for hydraulic fracturing. In this paper we assumed that the initial water saturation was low and that the water was immovable. If that is not the case, water saturation in the matrix and in the natural fractures, as well as the water-oil or water-gas relative permeability functions play significant roles in determining the water balance.

**Author details**

**References**

Hongtao Jia, John McLennan and Milind Deo

University of Utah, 2003.

Department of Chemical Engineering, University of Utah, Salt Lake City, UT, USA

[1] Data from the Texas Railroad Commission- http://wwwrrc.state.tx.us/

Reservoirs, Ph.D. dissertation, University of Utah, 2007.

Technical Conference and Exhibition, Dallas, Texas, Oct , 9-12.

Calgary, Canada, November 2011., 15-17.

in Calgary, October (2010). , 19-21.

[2] Yang, Y. K. (2003). Finite-Element Multiphase Flow Simulator, Ph.D. dissertation,

The Fate of Injected Water in Shale Formations

http://dx.doi.org/10.5772/56443

815

[3] Fu, Y. (2007). Multiphase Control Volume Finite Element Simulation of Fractured

[4] Gu, Z. (2010). A Geochemical Compositional Simulator for Modeling C O2 Sequestra‐ tion in Geological Formations, Ph.D. dissertation, University of Utah, 2010.

[5] Stegent, N. A, Ferguson, K, & Spencer, J. (2011). Comparison of Frac Valves vs. Plug and Perf Completions in the Oil Segment of the Eagle Ford Shale: A Case Study, CSUG/ SPE 148642, Paper presented at the Canadian Unconventional Resources Conference,

[6] Al-bazali, T. M, Zhang, J, Chenevert, M. E, & Sharma, M. M. (2005). Measurement of the Sealing Capacity of Shale Caprocks, SPE 96100, Paper presented at the Annual

[7] Curtis, M. E, Ambrose, R. J, Sondergeld, C. H, & Rai, C. S. Structural Characterization of Gas Shales on the Micro- and Nano-scales, CSUG/SPE 137693, Paper presented at the Canadian Unconventional Resources and International Petroleum Conference held

**Figure 6.** Figure showing water retained in the matrix through one hydraulic fracture and interacting natural frac‐ tures. Domain without the large cross-cutting feature is used. Left panel is for the water wet case, the middle panel is for the mixed wet case and the right panel is the oil wet case. Water saturation scale is also shown. As the wettability goes from water wet to oil wet the infiltration decreases increasing injected water recovery.

## **Author details**

**3. Conclusions**

814 Effective and Sustainable Hydraulic Fracturing

water balance.

Recovery of water injected for hydraulic fracturing in shales is only about 30%. There is a question of the fate of injected water. In this paper we studied water retention in shales for different shale wettability conditions. Two different domains where a hydraulic fracture intersected with a small existing network of natural fractures were used in the simulations. A specially developed framework that can handle representation of complex fracture networks was used for simulations. Capillary pressures in rocks containing very small pores tend to be high – of the order of 1000 psia. Three sets of capillary pressures – water wet, mixed wet and oil wet were examined. Simulations showed that a recovery of 20-30% is expected for typical water wet conditions, while a recovery of about 37%-48% is expected for oil wet scenarios. The recovery for mixed wet conditions fell between these two extremes. The recovery is reduced when a large cross-cutting fracture is introduced – but not significantly. That is because water will be recovered if the fractures are interconnected. Results discussed in this paper helped quantify the role of wettability in the recovery of water used for hydraulic fracturing. In this paper we assumed that the initial water saturation was low and that the water was immovable. If that is not the case, water saturation in the matrix and in the natural fractures, as well as the water-oil or water-gas relative permeability functions play significant roles in determining the

**Figure 6.** Figure showing water retained in the matrix through one hydraulic fracture and interacting natural frac‐ tures. Domain without the large cross-cutting feature is used. Left panel is for the water wet case, the middle panel is for the mixed wet case and the right panel is the oil wet case. Water saturation scale is also shown. As the wettability

goes from water wet to oil wet the infiltration decreases increasing injected water recovery.

Hongtao Jia, John McLennan and Milind Deo

Department of Chemical Engineering, University of Utah, Salt Lake City, UT, USA

#### **References**


**Section 13**

**Numerical Modeling 2**

**Numerical Modeling 2**

**Chapter 41**

**Three-Dimensional Numerical Model of Hydraulic**

Conventional methods for simulation of hydraulic fracturing are based on assumptions of continuous, isotropic and homogeneous media. These assumptions are not valid for most rock mass formations, particularly shale gas reservoirs, as these typically consist of a large volume of naturally fractured rock in which propagation of a hydraulic fracture (HF) involves both fracturing of intact rock and opening or slip of pre-existing discontinuities (joints). The preexisting joints can significantly affect the HF trajectory, the pressure required to propagate the fracture and also the leak-off from the fracture into the surrounding formation. None of these

*HF Simulator* is a new three-dimensional numerical code that can simulate propagation of hydraulic fracture in naturally fractured reservoirs, accounting for the interaction between the hydraulic fracture and pre-existing joints. In *HF Simulator*, fracture propagation occurs as a combination of intact-rock failure in tension, and slip and opening of joints. The code uses a lattice representation of brittle rock consisting of point masses (nodes) connected by springs. The pre-existing joints are derived from a user-specified discrete fracture network (DFN).

*HF Simulator* can model fluid injection or production from one or multiple boreholes each with one or multiple clusters. Non-steady, hydro-mechanically coupled fluid flow and pressure

An outline of the code hydro-mechanical formulation is presented and examples are provided

and reproduction in any medium, provided the original work is properly cited.

© 2013 Damjanac et al.; licensee InTech. This is an open access article distributed under the terms of the Creative Commons Attribution License (http://creativecommons.org/licenses/by/3.0), which permits unrestricted use, distribution, and reproduction in any medium, provided the original work is properly cited.

© 2013 The Author(s). Licensee InTech. This chapter is distributed under the terms of the Creative Commons Attribution License (http://creativecommons.org/licenses/by/3.0), which permits unrestricted use, distribution,

within the network of joint segments and the rock matrix are considered.

**Keywords:** Numerical model, naturally fractured, rock mass

**Fracturing in Fractured Rock Masses**

B. Damjanac, C. Detournay, P.A. Cundall and Varun

Additional information is available at the end of the chapter

effects can be simulated using conventional methods.

to illustrate the code capabilities.

http://dx.doi.org/10.5772/56313

**Abstract**
