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Using large scale hydraulic fracturing experiments on tight shale outcrops, we identified three dominant regions controlling stage production: the connector between the wellbore and the fracture system, the near wellbore fracture and the far well fracture network.
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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
2 SPE 166505
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
SPE 166505 3
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
4 SPE 166505
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.
6 SPE 166505
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.
8 SPE 166505
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.
SPE 166505 9
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
10 SPE 166505
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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