SPE 166505

Defining Three Regions of Hydraulic Fracture Connectivity, in Unconventional Reservoirs, Help Designing Completions with Improved Long-Term Productivity Roberto Suarez-Rivera, Schlumberger, Larry Behrmann, Schlumberger Consultant, Sid Green, Schlumberger and the University of Utah, Jeff Burghardt, Sergey Stanchits, Eric Edelman and Aniket Surdi,

Schlumberger

Copyright 2013, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Annual Technical Conference and Exhibition held in New Orleans, Louisiana, USA, 30 September–2 October 2013. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessar ily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohi bited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.

Abstract Using large-scale hydraulic fracturing experiments on tight shale outcrops we identified three dominant regions controlling

stage production: (1) the connector between the wellbore and the fracture system, (2) the near-wellbore fracture and (3) the

far-wellbore fracture network. The particular nature of these regions may change depending on the play, the reservoir fabric,

its relation to the in-situ stress, and the distribution of rock properties. However, these regions are always well differentiated.

Understanding the role of each of these components, to hydrocarbon production, is fundamental to identify the dominant

sources of loss of fracture conductivity and accelerated production decline. The conditions promoting the loss of fracture

conductivity, fracture face permeability and surface area in contact with the reservoir vary significantly along the length of

the hydraulic fracture. By separating the induced fractured area into three characteristic regions of reservoir contact, we

isolate the dominant drivers of loss of production per region, and obtain the best compromise for sustained stage productivity.

We used large-scale hydraulic fracturing experiments to develop and validate the concept. These were integrated with

scaled-down measurements of fracture conductivity, proppant embedment and the effect of rock-fluid sensitivity. We find

that the critical conditions for productivity for the wellbore-connector depends on mechanical stability considerations and are

independent of reservoir quality. The critical conditions for productivity from the near-wellbore fracture are solids retention

in the proppant pack, and reduction of fracture face permeability due to proppant embedment. The critical conditions for

productivity from the far-wellbore fracture are loss of surface area and retention of fracture conductivity. Results provide a

framework for improving fracture design for improved long-term productivity. This is achieved by understanding the

conflicting requirements between three regions of flow within the fracture and selecting the optimal compromise between

these.

Introduction

Achieving economic production from nano-Darcy permeability, organic-rich mudstone reservoirs requires creating large

surface area, by hydraulic fracturing, in contact with high reservoir quality rock. More importantly, it depends on preserving

the created surface area and fracture conductivity during long-term production. This paper is about understanding the surface

area (fracture geometry) that is created in heterogeneous rocks with complex fabric, the potential for preserving this after

fracturing, and about maintaining adequate fracture conductivity during long-term production.

Fracture complexity, including branching, and step-overs, increases the surface area per unit reservoir volume. This is a

desirable goal, since hydrocarbon production depends, among other things, on rock permeability and the created surface area

[1]. Unfortunately, however, fracture complexity also results in poor proppant delivery and placement [2]. Proppant laden

fluids that may move readily through simple fracture systems, have to overcome the tortuosity and narrowing at fracture

connectors and shear-dominated step-overs of complex fracture systems, which are often unfavorably oriented in relation to

the in-situ stress[3]. This results in poor proppant coverage, unpropped fracture regions, significant changes in fracture

width, isolated fracture branches, and an overall reduction of surface area and fracture conductivity that impacts well

productivity over time.

Fracture complexity results primarily from complex rock fabric and heterogeneous distributions of rock properties [4]. The

former is defined by the presence of planes of weakness, their density, mechanical strength, and orientation. Examples of

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these are bedding, depositional bounding units, unconformities, mineralized- and organic-filled fractures, slickensides, and

others. These define preferential directions of weakness in the rock and control the propagation, containment, branching, and

the final geometry of hydraulic fractures, in ways that are not possible for massive rocks with weak texture. In addition to the

presence of planes of weakness, rock heterogeneity cause local changes in the magnitude and orientation of the in-situ stress,

in relation to the far field values [5]. In tight shale reservoirs, rock heterogeneity results primarily from geochemical

interactions between mineral and organic matter, the varying chemistry of the depositional environment, the presence and

distribution of micro-organisms (primary producers of organic matter and biogenic minerals, and primary consumers of

organic matter), and the large surface area of the system, which drive these changes over time. The local distributions of

stress directions and magnitudes, in relation to the regional stress, are another feature of heterogeneous unconventional

reservoirs, which are not observed in homogeneous reservoirs. Stress magnitude, stress difference, and stress orientation

define fracture geometry in homogeneous reservoirs, and the fracture geometry is simple. Rock fabric, rock heterogeneity,

the orientation of rock fabric in relation to the local stress orientation, and the strength of the planes of weakness in relation to

the magnitude of the local stress, define the fracture network in high texture, heterogeneous reservoirs [4]. Thus the rock

cannot be ignored, but unfortunately it is seldom considered.

Figure 1. Fracture geometry as a function of the presence and orientation of planes of weakness and the stress difference and orientation of the in-situ stress. Low stress contrast maximizes the effect of the planes of weakness, but does not result in geometrical complexity.

Figure 1 shows an example of fracture propagation on rocks with identical bulk properties but with planes of weakness (top)

and without planes of weakness (bottom), and subjected to identical stress regimes of high stress contrast (left) and no stress

contrast (right). The images are abstracted from a large collection of hydraulic fracture experiments on large-scale blocks,

from outcrops of tight shales and fine grained tight sands. The differences between the two sets are obvious and remarkable.

The planes of weakness momentarily arrest fracture propagation. Then proceed along the interface and/or across the

interface. The length of the fracture propagation along the interface (the stepover) is smaller the higher the stress contrast and

the stronger the interface. The resulting fracture is more complex when the rock fabric and the stress contrast (magnitude and

orientation) compete for control of the fracture. The fracture is simplest when only the stress (no fabric) or the fabric (no

stress contrast) defines the fracture geometry.

Figure 1 also provides insight in relation to the preservation of fracture area and fracture conductivity. It allows us to

anticipate a broad distribution of fracture widths, and a corresponding change in fracture conductivity. For the high texture

rock with high stress contrast, this is lower the farther away from the wellbore, and possibly lowest at the stepovers. Fracture

conductivity is only uniform for homogeneous rocks without interfaces. It is also clear that the created surface area, often

referred to as the stimulated reservoir volume (SRV), is not a good indicator of the producible surface area after fracturing

and depressurization. The potential for closing stepovers and isolating fracture branches is larger, the higher the fracture

complexity.

Fracture crossing or arrest criteria through weak interfaces have been proposed by multiple authors [6-19] and their models

include various degrees of complexity. These typically represent the presence of a weak interface that may open or locally

shear as the hydraulic fracture approaches and contacts the interface. Depending on local conditions of stress and interface

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strength, the magnitude of the slippage, and the hydraulic conductivity of the interface, the fracture crosses the interface,

continues propagating along the interface, is arrested at the interface, or crosses the interface after slippage, developing a

step-over.

Figure 2. Possible interactions of a propagating fracture with a weak interface contained within a homogeneous rock. Modified from Thiercelin and Makkhyu [14]

Important properties controlling the interaction between the fracture and the weak interface in these models are: the shear

strength of the interface, the local in-situ stress (contrast and orientation), the orientation of the interface in relation to the in-

situ stress, the width of the propagating hydraulic fracture, and the hydraulic conductivity of the interface [18]. The fracture

width is defined by the rock anisotropic elastic properties, the fluid viscosity, the fluid rate, and the fracturing fluid pressure

[20]. In general, we anticipate that the hydraulic fracture will cross the weak interface for conditions of high interface shear

strength, low shear stresses at the interface (low local stress difference), high fracture widths (high rates, high viscosity and

low rock stiffness) and low hydraulic conductivity of the interface. Conversely, we anticipate fracture arrest or propagation

along the interface for conditions of low interface shear strength, high shear stress at the interface (high stress contrast), low

fracture width (low rates, low viscosity and high rock stiffness), and high hydraulic conductivity of the interface.

Although the current models are two-dimensional, the fracture interaction with these interfaces should be considered in three

dimensions. Thus, as the fracture propagates it may be temporarily arrested at some interfaces (e.g. horizontal bedding or

mineralized vertical fractures) while propagating in directions of lower resistance. Subsequently, it may enter these

interfaces, and propagate along these for some distance, while simultaneously propagating at higher rates along other

favorable directions. Eventually, the fracture may cross some weak interfaces and be arrested by others, developing

stepovers and parallel fracture branches. Laboratory measurements of acoustic emission during fracture propagation provide

a record of a discontinuous nature of fracture propagation suggesting multiple steps of arrest and propagation [21].

In addition, changes in fluid velocity, fluid viscosity, and fracture width during fracture propagation with distance from the

wellbore, change the interaction between the propagating fracture(s) and the existing weak interfaces. During slick water

fracturing near the wellbore, the hydraulic fracture propagates under high velocity, higher fracture pressure and develops

higher fracture widths. This is so, when the conditions of perforating and fracture initiation are ideal. That is, there are no

detrimental wellbore effects, no near-wellbore tortuosity, the near-wellbore friction pressure is low, and the fracture is single

and planar. According to the previous discussion, this will promote conditions of low interaction with the planes of weakness

and may satisfy a fracture crossing criterion. The further the fracture propagates, particularly if unbounded, the lower the

fluid velocity driving the fracture, the higher the pressure losses, and the lower the fracture width. Under this condition, the

same rock fabric will interact more strongly with the propagating fracture and promote the development of fracture

complexity, which in turn will compound the effect of the rock on fracture propagation and complexity. As the proppant

laden fluid enters the created fracture, the proppant transport and placement will be strongly affected by the transport

mechanism (saltation versus turbulence assisted transport) and the increasing complexity of the fracture geometry. As a

result, the resulting fracture area with adequate proppant support and fracture conductivity is limited and typically

considerably smaller than the total created surface area.

Figure 3 shows a conceptual representation of the interaction of the propagating fracture with weak interfaces and weak

bedding, as a function of distance from the wellbore. Branching and stepovers also develop along the vertical direction (not

shown), providing resistance to flow and to upward fracture growth. Three regions of fracturing with unique properties

emerge from this concept: the wellbore/fracture connector, the near-wellbore fracture and the far-wellbore fracture. The

wellbore connector (possibly 10 to 30 ft) is the region of highest hydraulic convergence and appears to be a choking point for

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production. This is particularly so if it is not propped appropriately. The near-wellbore fracture is of limited extent (200 to

400 ft), represents most of the propped surface area and possibly most of the produced hydrocarbons [22]. Unfortunately,

proppant transport in the far-wellbore fracture region is minimal, the created far-field surface area is easily lost and does not

contribute to production. This loss of surface area at the far-wellbore region may not be avoidable by operational changes at

the wellbore.

Figure 3. Interaction of the propagating fracture with the rock interfaces, as a function of distance from the wellbore. Three regions with unique properties emerge from this concept: the wellbore/fracture connector, the near-wellbore fracture and the far-wellbore fracture

Results from a recent RPSEA-sponsored study on sustaining fracture area and fracture conductivity [22] provided insight on

the multiple causes of loss of fracture area and fracture conductivity, and a strong validation of the above conceptual picture.

A large-scale hydraulic fracturing experiment was conducted using a 2.5 ft x 2.5ft x 3ft outcrop sample from the Niobrara

shale formation. This block exhibited strong fabric, similar to that observed on cores from depth on the same formation,

including the presence of mineralized sub-vertical fractures, slickensides, subtle but important changes in texture and

composition, and bed boundaries with varying degrees of strength. Hydraulic fracturing was followed by proppant injection

and fracture conductivity measurements, as a function of stress [23]. Post-test evaluation of this experiment showed evidence

of the strong differentiation in fracture propagation and geometry as a function of distance from the wellbore. In this paper,

we consolidate these results with observations from previous large block experiments, to present an analysis of the variability

in fracture properties, surface area and fracture conductivity, along the three characteristic fracture regions and the wellbore.

Understanding the role of each of these regions to hydrocarbon production helps identify the often competing causes of

production decline over time.

Laboratory Testing and Results

Laboratory experiments of hydraulic fracture propagation in heterogeneous media are challenging to conduct and analyze,

because of internal boundary effects during fracture initiation and external boundary effects as the fracture approaches the

end of the specimen. Fracture initiation effects are minimized by preparing adequate fluid slots along the desired section of

the wellbore; outer boundary effects are minimized by extending the sample size. Thus, large-block samples provide the best

opportunity for evaluating hydraulic fracturing propagation and the interaction of fractures with planes of weakness in the

rock. In our studies, we use a polyaxial stress frame (Figure 4) with independent stress control along three perpendicular

directions, and with a maximum capacity of 8,000 psi.

SPE 166505 5

Figure 4. Large-scale polyaxial testing system (left) and large shale outcrop block (right). The system allows conducting hydraulic fracturing experiments on heterogeneous tight shales under representative conditions of stress.

Flatjacks are used for transmitting the load and for continuously monitoring the block deformation during fracturing. These

measurements allow us to detect fracture initiation and fracture breakdown, and allow us to monitor whether the fracture is

predominantly planar or non-planar. The blocks are also instrumented with an array of acoustic transducers (typically 20 to

36 and occasionally 76). These transducers are used to conduct active transmission measurements, which provide a

continuously updated velocity model of the block (every 2 seconds). This allows us to account for changes in acoustic

velocity resulting from loading and fracturing. We concurrently use the transducers in passive mode, to detect and localize

acoustic emission events and use these to map the evolution of the fracture geometry. Our broader goals are to observe the

relationship between the rock fabric, fracture containment and fracture complexity, to validate interface crossing criteria

models, investigate proppant transport and proppant distribution, and better define fracture characteristics along the near-

wellbore and far-wellbore regions.

In this paper we describe post-test analysis of fracture propagation on an outcrop block of the organic-rich Niobrara

formation, representative of the Niobrara reservoir in the DJ basin. The sample configuration simulated a vertical wellbore

completion, with the wellbore oriented perpendicular to bedding. After fracturing the block we first measured the unpropped

fracture conductivity, while changing the closure stress, and then we re-fractured the block with proppant laden slickwater

and measured the propped fracture conductivity in a similar fashion. A planar fracture with reasonable width and simple

fracture geometry was intended using 1000cp glycerol at a constant injection rate of 1000 mL/min. The sample was

subjected to representative effective in-situ stress and with a significant stress contrast in the plane perpendicular to the plane

of the fracture (1=4,500 psi, 2=3,000 psi, 3=1,000 psi). Borehole fluid injection at 1000 mL/min and continued at a

constant rate until borehole breakdown was observed, at a pressure of 4,202 psi. This value exceeded the minimum and

intermediate in-situ effective stress. Details of the testing and analysis of the time-pressure data, including the fracture

conductivity measurements are provided elsewhere [22, 23].

Figure 5 shows the open face of the fracture. The wellbore, including the steel casing and cement, was cored out, for

mechanical characterization. (Unfortunately, during this process some of the proppant was washed away limiting the global

characterization of the proppant placement). The figure shows the region of the wellbore where slots were cut for fracture

initiation. The exposed surface area exhibits three distinct regions of fracturing, occurring at the wellbore-connector region,

the near-wellbore fracture region, and the far-wellbore fracture region. The wellbore connector region is the small region

immediately adjacent to the wellbore that includes the fracture initiation slots, and defines the region of high flow

convergence connecting the wellbore to the created fracture. The near-wellbore fracture region lies between the

wellbore/connector region and the far-wellbore fracture region. It is characterized by a reasonably planar and smooth

fracture and high proppant concentration. The far-wellbore fracture region is associated with extensive branching, mixed-

mode fracture propagation and associated high surface area and fracture complexity. Figure 6 shows details of one of the

surfaces, and provides important information on the origin and evolution of the three regions of fracturing. Figure 7 shows

the gradual development of step-overs and fracture complexity as the fracture moves away from the wellbore.

Figure 5. East and West half sections of the block, exposing the created fracture surfaces. The near-wellbore region, including the casing, was drilled out. A representative drawing of the openhole section of the wellbore with the sandblasted slots is displayed towards the center of the block image.

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Figure 6. Left image: En-echelon fractures are developed gradually from the middle of the block and towards the top north section of the block. Two regions with step overs are highlighted. Right images: The red line shows the orientation of a natural, mineralized, fracture. The lower image shows the complex fracture pattern that result.

Figure 7. En-echelon fracture stacking observed on the upper portion of the East face of the block. The thickness of the step-overs was in all cases less than 1.0mm.

In Figure 6 we highlight two regions in the fracture face with red and blue rectangles. The red rectangle shows the evolution

of fracture complexity from the slotted section in the wellbore (not shown) to the far-wellbore region of the block (near its

top edge). Here, the propagating fracture developed complexity primarily by interaction with a calcite-filled, weak-interface.

The orientation of this is indicated by the red dotted line in the upper right side of the figure. A transition from few en-

echelon factures, to the left of the interface, and higher density of fractures, to the right of the interface, is apparent in the

figure. The blue rectangle shows a far-wellbore region of the block, near its side edge, and shows the development of step-

overs and multiple fracture branches as the fracture approached the boundary of the block.

A detailed view of a thick step-over, seen in the mid-section of the blue bounded area, is shown in the lower right side of the

image. We observe that fracture branches are created at weak interfaces by simultaneously crossing the planes of weakness

and propagating along them for a short distance, creating step-overs, and parallel fracture structures. This process resulted in

considerable surface area per unit rock volume, but the fractures were devoid of proppant to sustain fracture conductivity

after fracturing, and after lowering the wellbore pressure.

Figure 7 shows the transitional region between the wellbore/connector (right side) and the far-wellbore fracture regions (left

side), which is defined by a gradual development of fracture branching and complexity. The figure shows the presence of

fracture branching with three one millimeter thick, stacked fractures. By peeling off these layers, we observed that each

contained proppant in their first half inch length and no proppant afterwards. Only the dominant fracture contained proppant

SPE 166505 7

along its entire surface.

Fracture Regions Controlling Stage Production

The fracture regions observed in the previous section are not exclusive to a single test and are a common feature of most of

the large block testing we conducted. It is their pervasiveness that provides the motivation for this work. Heterogeneous tight

shale systems exhibit strong rock fabric and a large number and types of planes of weakness, including weak bedding. The

propagating fracture(s) interact with these weak interfaces. Depending on the fracture width at the location of interaction

(which changes with distance from the wellbore as a function of the fluid velocity, fluid viscosity, fracture pressure and the

heterogeneous distribution of rock properties), the fracture may propagate through the interface or create stepovers and

develop complexity. For example, the near-wellbore fracture develops under higher velocity, higher fracture pressure and

higher fracture width than at the far-wellbore fracture. This promotes more complexity in the far-wellbore region than at the

near-wellbore region.

This observation allows us to define three regions of fracture propagation associated to changes in the fracturing fluid

velocity and viscosity from high, intermediate to low, and the resulting interaction of the propagating fracture with weak

interfaces, which are pervasive in tight shales. It also allows us to conceptualize the potential interaction of the growing

fracture with weak interfaces within these three regions and to anticipate a fracture geometry that may transition from planar

and simple to tortuous and multi branched. This transition in fracture geometry may be more pervasive along the vertical

direction, because of the highly bedded nature of organic-rich mudstone reservoirs, and less pervasiveness along the lateral

direction, depending of the number, the spacing and orientation of planes of weakness in the rock (e.g. mineralized fractures,

non-mineralized healed fractures, faults, and others). A fourth region of interest is the region where the wellbore is landed.

This is not a region of fracturing per se, but should be considered in the concept, because the rock properties where the

wellbore is placed have a strong influence on fracture initiation and on the long term connectivity between the wellbore and

the created fracture.

Figure 8 shows the fourregions of the facture system. The wellbore region (with casing and cement) was cored, to visualize

the fracture geometry in this region. The location of the slotted sections is shown with a blue rectangle. The

wellbore/fracture connector is the region immediately outside the slotted region. In this test, it exhibits a simple and planar

geometry, and has lower proppant concentration (which was partially washed out during wellbore coring). The near-

wellbore region follows the wellbore/fracture connector region, and is characterized primarily by the presence of high

proppant concentration, and a surface area with moderate fracture complexity. The far-wellbore region follows the near-

wellbore fracture region and is characterized by the increased fracture complexity, increased surface area and substantially

decreased proppant concentration. In the field, the particular extent of each of these regions may change depending on the

reservoir fabric and its orientation, the in-situ stress magnitude and contrast, the distribution of rock properties, and the

completion and fracturing design (number and orientation of the perforations, fluid viscosity, pumping rates, fluid volumes,

etc.). However, these three regions will develop and will be well differentiated. We believe that understanding the role of

each of these regions in controlling hydrocarbon production is fundamental, to understand the long term production and

improve the design of hydraulic fracturing.

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Figure 8. Large-scale, hydraulic fracturing experiment. The left figure shows the four regions of the facture system: (1) the wellbore, (2) the wellbore/fracture connector, (3) the near-wellbore fracture, and (4) the far-wellbore fracture network. In this example, the wellbore region (with casing and cement) was cored, to visualize the fracture geometry in this region. The slotted section is shown with a blue rectangle.

The Wellbore

The role of the wellbore landing region to hydraulic fracturing is the long-term stability of the wellbore and the long-term

stability of the perforations (or sand-blasted slots). The wellbore geometry its orientation, and the type of completion (e.g.,

cased, openhole, perforated, sand blasted) define the stress concentrations that affect fracture initiation and breakdown, and

affect the geometry of the wellbore/fracture region connecting the wellbore to the created surface area. For example, the

presence of weak interfaces along the wellbore may facilitate fracture breakdown and improve the connectivity to the near-

wellbore fracture system. However, this will depend on the wellbore orientation in relation to these planes of weakness and

the orientation of the stress. Critical concerns for landing and for selecting the wellbore azimuth are mechanical stability,

creep, in-situ stress magnitude and orientation, rock elastic anisotropy, pore pressure, and adequate rock competence for

maintaining connectivity with the wellbore/fracture connector over time.

As an example, Figure 9 shows the potential consequences of creep on the hoop stress distribution along the wellbore, and on

fracture breakdown pressures, which are related to the rock type and properties along the perforated interval. The figure

shows the hoop stress concentrations at the top (left) and bottom (right) of a horizontal wellbore, completed either openhole

(red line) or cased and cemented (blue and green lines). The green line represents the case of an eccentric casing (resting at

the bottom side of the wellbore) but with full cement coverage. The red line represents the same case but with partial cement

coverage and a bypassed channel at the top of the wellbore. In all cases, the hoop stress is initially tensile (time zero or

instantaneous elastic response). Afterwards it increases to a maximum compressive stress value and then decreases to a

minimum value at larger time (not shown). This means that fracturing immediately after perforating facilitates breakdown.

This also means that delaying the fracturing by 1 to 4 days after perforating is detrimental and increases the breakdown

pressure (the actual time will depend on the rock creep properties). Time between perforating and fracturing may be an

important reason why the toe stage is more difficult to breakdown. At longer times, creep relaxation lowers the hoop stress

concentration and consequently reduces the breakdown pressure. For openhole conditions, the top and bottom perforations

behave identically. For cased and cemented perforations the bottom perforations maintain a higher hoop stress concentration

and the upper perforation may exhibit a faster reduction than the openhole case (when cement channeling is present). These

differences suggest that the initiation of fractures around the wellbore is far from symmetrical and may result in undesirable

complexity.

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Figure 9. Effect of creep deformation (i.e., time dependence) on the stress concentrations around the wellbore. The hoop stress and fracture initiation pressure decrease considerably as a function of time.

Figure 10. Effect of creep deformation (i.e., time dependence) on perforation closure. The perforations from cased and cemented wellbores exhibit considerable more closure than the corresponding perforations in openhole wellbores. The length and width of the perforations are shows in the horizontal and vertical axes correspondingly (Modified from [Deenadayalu, 2012]).

For the same conditions shown above, Figure 10 shows the effect of creep on the closure of the perforations, as a function of

time. Cased and openhole wellbores are considered. The perforations from cased and cemented wellbores exhibit

considerable more closure than the corresponding perforations in openhole wellbores. This is because the wellbore is

prevented from deforming by the casing and the cement sheath. The perforation is the only region that can accommodate the

time dependent deformation. Combining the above effects, it is possible to understand problems of breakdown pressures as

affected by a combination of rock properties (creep) and operation conditions (time).

Various authors [24, 25] have described the effects of anisotropic elastic rock properties on the development of near wellbore

stress concentrations and the consequence of this to fracture initiation, breakdown and near-wellbore fracture width. These

solutions acknowledge the anisotropic behavior of tight shales but often ignore non-elastic, time-dependent behavior (creep)

and changes in rock properties associated to rock fluid interactions. These should be considered.

Stress concentrations along the wellbore, with and without creep, suggest that oriented perforations (top and bottom),

focusing the energy in shorter stage intervals, and concentrating hydraulic power from various perforations into the same

plane [26] are beneficial to fracture initiation. The goal of the perforation effort should be to facilitate fracture breakdown,

promote the initiation of fractures in the direction of the far-field stress, avoid fracture reorientation, and avoiding the

generation of multiple fractures.

The Wellbore/Fracture Connector Region

The wellbore/fracture connector region (the connector) defines the connection between the wellbore and the near-wellbore

fracture system. This is a region of limited extent (possibly 10 to 30 ft, in the field) but of unordinary importance to well

production. This is a region where the wellbore stress concentrations, the regional in-situ stress, the perforations (or any

other geometry used for fracture initiation), the choice of fluid properties, fluid rates, the pumping schedule and other design

properties, strongly influence fracture initiation and development. The desirable result is to create a connector with

maximum fracture conductivity between the wellbore and the near-wellbore fracture system, minimizing any potential

restrictions of flow, and maintaining it open during long-term production. This means, obtaining a wide conduit with single

and simple planar geometry, maximum fracture width, high fracture conductivity, minimal fracture tortuosity, limited

changes in direction during propagation, and limited generation of fracture branches with reduced widths, among others.

Some of these conditions are defined by the rock properties at the wellbore landing location, the perforation configuration,

and the procedures leading to breakdown, including pumping rate, wellbore storage and fluid velocity during fracture

initiation and breakdown. For example, when fracture initiation is done from multiple perforations with different

orientations, with gradual flow rate buildup and low viscosity fluids, on rocks with high textural complexity, the result is

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typically multiple fractures and narrow fracture widths. We have a large collection of laboratory experiments on large

blocks outcrop samples, representative of tight shale plays in North America, that support this statement. In laboratory

samples, hydraulic fracturing over standard perforated intervals, with 60 deg phasing, result in multiple fracture planes,

transverse and longitudinal depending on gun orientation. The longitudinal fracture(s) are truncated within about one to two

wellbore diameters. Transverse fractures may emanate from the longitudinal fracture(s), but usually start from perforation(s)

and at 90 deg. from the longitudinal fracture(s). Tests using multiple perforations focused to a single planar orientation and

with top and bottom phasing, result in transverse fracture(s) orientations with moderate to minimal tortuosity. In the

laboratory, when we want to eliminate the tortuosity in the connector region, we create deep slots that extend outside the

wellbore stress concentration. The hydraulic fracture emerges from this as a single and simple plane in the direction

perpendicular to the minimum horizontal stress (this is the case for the test results shown in this paper).

The connector being a region of high fluid velocity may also be a region of limited proppant deposition. This may be

particularly so for single and simple fractures where the flow rate is maximum and the proppant precipitation may be low

during the duration of the treatment. If so, this will promote early closure of the connector, and significant restriction to

hydrocarbon production. Rock properties with low surface hardness, high clay content, low modulus, high creep, and high

rock-fluid interaction are problematic for developing a long lasting connector with sustained fracture conductivity. Based on

a large number of laboratory experiments and analysis of field data during fracture breakdown, we believe that the large

variability in stage production and the current inefficiency of the stimulation process is controlled primarily by the closure of

the connector. This may be the weakest link of the hydraulic fracturing pathway.

The Near-wellbore Fracture Region

The near-wellbore fracture region is the dominant region of hydrocarbon production. It is also the region with highest

proppant concentration and limited surface area. The near-wellbore fracture region is primarily susceptible to solids trapping

and salt precipitation during long term production. It is also susceptible to solids production by high drawdown, proppant

embedment, rock extrusion by proppant embedment, mobilization of fines, and loss of fracture conductivity resulting from all

these factors. It is susceptible to imbibition and loss of fracture-face permeability. Imbibition produces a water block at the

fracture face that moves away into the far-field reservoir as a function of time. This strongly reduces the fracture face

permeability immediately after fracturing, and recovers subsequently. Rock-proppant embedment, results in local plastic

deformation that may lead to dramatic reduction in fracture-face permeability at the rock/proppant interface. Figure 11

shows results of embedment and rock extrusion during fracture conductivity experiments on Haynesville shale. The main

figures (top left and bottom right) show the extent of the plastic zone (blue and green) and the extrusion of material around

the proppant, as the proppant embeds. The insert in the figure (top right), provides a visual representation of the fracture face

area with reduced fracture-face permeability due to embedment and rock plastic flow (shown in dark gray). The area with

preserved rock permeability is shown in blue, and is a small fraction of the original surface area. Conceptually, the higher the

proppant concentration per unit area the larger the damage of the reduction of the fracture-face permeability, once

embedment occurs. This may be reduced larger size mesh (i.e., the greater distance between the grains and the smaller the

embedment, the smaller the loss of fracture face permeability). Fortunately, however, the distribution of proppant in real

fractures is non-uniform, and the problem is less extensive. Promoting non-uniform proppant distribution by using pillar

proppant placement is recommended. Exposure to water base fluids, time and temperature affect the stability of sand based

proppants. This exposure promotes grain crushing, with an associated degradation in fracture width and increase of fine

materials.

Closer to the wellbore, but within this region, the near-wellbore region is a potential filter for retention and trapping of fines,

fragments, precipitants, and all other plugging constituents that are mobilized from the farther regions of the fracture. Thus,

the gradual loss of fracture conductivity in this region is possibly inevitable, and this effect may be the major source of

fracture conductivity reduction over a short period of time and corresponding loss in productivity. Pillar proppant placement

will facilitate movement of the fines and prevent rapid loss of fracture conductivity in this region.

SPE 166505 11

Figure 11. Microscope images of proppant embedment, plastic flow at the rock/proppant interface and associated extrusion of the surface around the proppant. The bulged region may be dispersed and mobilized by the flow. The surface of the rock in contact with the proppant is a plasticized surface of highly reduced permeability.

The Far-wellbore Fracture Region

Fracture containment is a dominant concern in the near-wellbore and the far-wellbore fracture regions, and this is perhaps

more important for the latter. Proppant transport to the far-wellbore fracture region, and attaining sufficient proppant

concentration to maintain fractures in this region open, are of highest concern. Loss of surface area is possibly the dominant

problem in this area. At low proppant concentrations, low fracture widths, and high proppant/rock stress concentrations,

rock/proppant interactions are critical to define weather proppant embedment or proppant crushing controls the potential for

fracture closure. In addition rock-fluid interactions soften the rock and promote embedment; proppant-fluid interaction

weakens sand, when used as proppant, and promotes proppant crushing. In either case the potential for loss of surface area is

high.

Figure 12 shows a conceptual representation of the far-wellbore fractures (left). It also shows an example from mineralized

fractures in sandstone outcrop. This fracture network increases in fracture complexity as it moves away from the source

(center). The figure also shows an outcrop example of closely spaced fractures; and propagation of secondary fractures in

sub-parallel directions (right). The far-wellbore fracture region is the fracture region that is primarily filled with fluid and

primarily devoid of proppant. Laboratory experiments have shown that fracturing with water at low rates results in highest

fracture branching and complexity, narrow widths, closely spaced fractures, and predominant fracture propagation along

planes of weakness. Laboratory experiments of fracture conductivity on split cylindrical samples with un-propped surfaces

indicate a high tendency of loss in conductivity with stress. In general, a 2000 psi closure stress is sufficient to eliminate

fracture conductivity in un-propped samples from all reservoir facies of the Haynesville, Barnett, and Marcellus shales [22].

Being a region with the highest surface area, the far-wellbore fracture region is also a region of salt dissolution, high salt

concentration in the fracturing fluid, and potential precipitation in the proppant pack at the near-wellbore fracture region

during flowback. It is also a region of high water imbibition, which results in water blocking and fracture-face permeability

impairment. Fundamentally, however, it is a region with minimal proppant concentration and high loss of surface area

immediately after fracturing.

Cavity and zone of plastification

Extruded material to accommodate the volume of proppant

Embedment observed after fracture conductivity testing

12 SPE 166505

Figure 12. Typical morphology of far-wellbore fractures: (1) Conceptual model. (2) Mineralized fractures in sandstone away from the source. (3) Closely spaced fracturing in laminated sandstone. Fracture propagates in multiple sub-parallel directions and minimal width.

Summary and Recommendations

In this work we identified three dominant regions controlling stage production: (1) the connector between the wellbore and

the fracture system, (2) the near-wellbore fracture and (3) the far-wellbore fracture network. The particular nature of these

regions may change depending on the play, the reservoir fabric, its relation to the in-situ stress, the wellbore completion

configuration, and the distribution of rock properties. However, these regions are always well differentiated. The

implication of this work is that conditions promoting loss of fracture conductivity, loss of fracture face permeability and loss

of surface area in contact with the reservoir vary significantly along the length of the hydraulic fracture. By conceptualizing

the hydraulic fractured area into three characteristic regions of reservoir contact, we isolate the dominant drivers of loss of

production per region, and obtain an optimal compromise for sustained stage productivity. These conditions can be better

understood as follows:

Productivity for the wellbore-connector depends on long-term mechanical stability considerations and is

independent of reservoir quality. The goal is to create a simple, single, wide fracture connector with adequate

proppant support, to prevent fracture closure over time and to prevent proppant plugging over time. This requires

competent rock with high surface hardness, low time dependence (low creep), and low softening associated to

rock/fluid interactions.

Productivity from the near-wellbore fracture depends on the propped area of contact with high reservoir quality rock

and the long-term retention of fracture conductivity and fracture-face permeability. This requires height growth

containment, to maximize surface area in contact with the reservoir, fracture width control (flow rate, viscosity, and

fracture pressure), to extend the region of moderate fracture complexity, non-homogeneous proppant distribution, to

minimize retention of solids from the far field, and limited loss of fracture-face permeability.

Productivity from the far-wellbore fracture depends on proppant placement and retention of fracture conductivity

during flow back and early production.

The wellbore is not a region of fracturing, but its placement and completion configuration plays a strong role in the

development of the above regions. In particular, it has a controlling effect on the evolution and geometry of the

fracture connector.

Results provide a framework for improving fracture design for improved long-term productivity. This is achieved

by understanding the conflicting requirements between three regions of flow within the fracture and selecting the

optimal compromise between these. Figure 13 shows a summary of this concept.

Far-

wel

lbo

re r

egio

n

Wellbore

12

3

SPE 166505 13

Figure 13. Summary of defining features, desired rock properties, operational considerations and goals for the three regions of hydraulic fracturing.

Acknowledgements

The authors wish to thank Schlumberger for supporting this effort and for permission to publish. We also wish to

acknowledge the technical contribution of the participants of the RPSEA-funded consortium: Encana, Penn General, and

Shell; and other scientists from Schlumberger, including Redd Smith and Nick Whitney.

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Wellbore/Fracture Connector

Region

Near-Wellbore Fracture

Region

Far-Wellbore Fracture

Region

Defining Features

Connects the wellbore to the

fractured system. This is is a region of

limited extent (possibly 10 to 30 ft, in

the field) but of unordinary

importance to well production. It is a

region of high flow convergence and

possibly low proppant concentration.

Dominant region of

hydrocarbon production. It is

the region with highest

proppant concentration, high

initial fracture conductivity and

limited surface area. It is

susceptible to solids trapping

and salt precipitation during

long term production

Region of higher fracture

complexity and limited

proppant placement.

Most (all?) of the fracture

area created in this region

is lost during wellbore

depresurization and early

production

Desired Rock Properties

Mechanically competent rock with

high surface hardness, low clay

content, intermediate modulus, low

creep, and low rock-fluid interaction

High reservoir quality rock

with moderate surface

hardness, moderate clay

content, intermediate

modulus, moderate creep, and

low rock-fluid interaction.

High surface hardness,

high unpropped fracture

conductivity, reservoir

quality rock with moderate

clay content, intermediate

modulus, moderate creep,

and low rock-fluid

interaction.

Operational Considerations

Promote a single and simple planar

geometry with high fracture width,

high fracture conductivity, minimal

fracture tortuosity, and limited

tortuosity during propagation. Ensure

high proppant concentration in this

region at the end of the job. Prevent

proppant plugging by solids during

long term production.

Minimize proppant pack

trapping of fines, fragments,

precipitantsmobilized from the

farther regions of the fracture.

Consider pilar proppant

placement. Minimize the loss

of fracture face permeability

by proppant embedment and

by imbibition of the fracturing

fluid.

Improve proppant

placement, reduce fracture

complexity, minimize salt

dissolution, and reduce

unpropped fracture area.

14 SPE 166505

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