Interaction Between Natural and Hydraulic Fractures

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SPE-174384-MS

A Study of the Interaction Mechanism between Hydraulic Fractures andNatural Fractures in the KS Tight Gas Reservoir

Fuxiang Zhang, PetroChina; Kaibin Qiu, Schlumberger; Xiangtong Yang, PetroChina; Jun Hao, Schlumberger;

Xuefang Yuan, PetroChina; Jeffrey Burghardt, Schlumberger; Hongtao Liu, PetroChina; Jianyi Dong,and Fang Luo, Schlumberger

Copyright 2015, Society of Petroleum Engineers

This paper was prepared for presentation at the EUROPEC 2015 held in Madrid, Spain, 1–4 June 2015.

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 necessarily 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 prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations maynot be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.

Abstract

The KS reservoir is a naturally fractured, deep, tight gas sandstone reservoir under high tectonic stress.

Development wells for this reservoir are of depths in excess of 6,500 m TVD. Stimulation is required to

provide production rates that sufficiently compensate for the high cost of drilling and completing wells to

access this deep reservoir. Hydraulic fracture design and execution must be optimal to ensure economic

production. To effectively stimulate a more than 200-m thick sandstone reservoir yielding consistently

high performance, it is critical to understand the interaction between hydraulic fractures and natural

fractures, as the natural fractures significantly affect the growth and geometry of hydraulic fractures.

To this end, a comprehensive study was conducted involving frac pressure analysis of previously

stimulated wells, microseismic data analysis, hydraulic fracturing modeling by using a fracturing simu-

lator that honors the natural fracture system, near-wellbore 4D geomechanical simulation of mechanical

response of natural fractures during hydraulic fracturing, and large block hydraulic fracturing tests. This

study reveals that existing natural fractures results in complexity of hydraulic fracture systems both in the

near wellbore region and in the far field region. The complexity in the far field is largely controlled by

the intersection angle (defined as the angle between the natural fracture strike and the maximum horizontal

stress direction) given the large differential horizontal stress in this field.

Based on an understanding of the interaction mechanism, an optimization of the hydraulic fracturing

strategy was implemented in KS field. Improvements were made in staging, perforation, diversion, and the pumping schedule, which increased the averaged production rate more than 50% compared with previ-

ously stimulated wells.

Introduction

The high pressure, high temperature (HPHT) KS tight sandstone reservoir is located in the Kuqa foreland

thrust belt, in the Tarim basin. Recent exploration success shows that there is a large reserve of natural

gas in the KS reservoir, following previous discoveries located in the thrust belt (Wang et al. 2013). The

reservoir formation is the Cretaceous Bashijiqike fan delta sandstone, overlaid by Kumugeliemu inter-

bedded gypsum-salt rocks acting as excellent cap rock (Xie et al. 2013; Liu et al. 2013). The reservoir



sandstone is relatively clean with average clay content of 12%, tight with average porosity of 5% and

average permeability less 0.01mD in the matrix. Extensive natural fractures were developed in the

reservoir sandstone (Zeng et al., 2004; Zhang et al. 2008; Li et al. 2011) due to tectonic activity and

overpressure generation (Liu et al. 2013) which provide excellent conductivity over the matrix, and

production data analysis shows that more than 95% of production is attributed to the natural fractures for

the adjacent Dabei field (Zhang et al. 2011). Nevertheless, even with the natural fractures, the reservoir

cannot be produced economically without hydraulic fracturing given high drilling and completion cost for the development wells.

Other workers have shown that due to the existence of natural fractures, the growth of hydraulic

fractures exhibits a very complex manner resulting from interaction between the hydraulic fractures and

natural fractures (Warpinski and Teufel 1987; Fisher et al. 2002; Maxwell et al. 2002a; Maxwell et al.

2002b; Daniels et al. 2007; Calvez et al. 2007; Rich and Ammerman 2010; Mayerhofer et al. 2010).

Hydraulic fracture complexity has been directly observed from mine-back experiments and core-through

(Warpinski and Teufel 1987; Warpinski et al. 1991, Jeffrey et al. 1992; Warpinski et al. 1993; Fast et al.

1994; Jeffery et al. 1995; Branagan et al. 1996, Cipolla et al. 2008), and inferred from microseismic

monitoring (Fisher et al. 2002; Maxwell et al. 2002a; Maxwell et al. 2002b) and treating pressure analysis

(Barree 1998; Medlin and Fitch 1988; Davidson et al. 1993; Sato et al. 1999). Similar phenomenon was

inferred from the initial stimulation efforts in the KS reservoir that rebuked the traditional single planar bi-wing fracture paradigm. As an example, two wells in the reservoir, KS2-1-1 and KS2-2-8, exhibited

very distinct behavior during hydraulic fracturing (see Table 1) despite similar petrophysical properties,

mechanical properties and in-situ stresses. Large difficulties were encountered when stimulating those

high intersection angle wells and stimulations failed to place adequate volume of proppant into the

reservoir.

To be able to effectively stimulate the KS reservoir, understanding of the interaction mechanism

between hydraulic fractures and natural fractures is a must. Previously, the interaction mechanism

between hydraulic fractures and natural fractures had been extensively evaluated by methods including

mine-back/core-through, microseismic monitoring, and large block hydraulic fracture tests (Lamont and

Jessen 1963; Anderson 1981; Jeffrey et al. 1987; Renshaw and Polland 1995; Olson et al. 2012;

Suarez-Rivera et al. 2013), as well as frac pressure analysis and hydraulic fracturing modeling (Cipolla

et al. 2010, 2011). However, past investigations have been was largely conducted using standalone

approaches with limited sources of data, and an integrated effort, which is essential to gain a deep

Table 1—Comparison of stimulation response from well KS2-2-8 and KS2-1-1

Well KS2-2-8 KS2-1-1

Intersection angle (°) 5 40

Treating pressure (MPa) 85 101

Fluid volume injected (m3) 1697 1239

Proppant mass injected (ton) 108.7 64.4

Flow back rate Slow Fast

Flow back ratio Low High

Fracture complexity Low High

Microseismic events Scarce Massive

Fracture height from HFM (m) 120-190 44-50

Fracture propagation Fast Slow

Fracturing me chanism Tensil e domi nant Shear dominant

Proppant and fracture effectiveness Good Poor

Productivity High Low

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understanding of this complex matter, was largely missing. In addition, the work was done for those

reservoirs with relatively low horizontal differential stress, and the outcomes of the evaluations lack direct

applicability to the KS reservoir. This paper presents an integrated, multi-faceted field study to evaluate

the interaction mechanism between hydraulic fractures and natural fractures, and a new stimulation

strategy that was formulated based on the understanding of interaction mechanism and successfully

applied in the reservoir.

Integrated Study Workflow

Owing to the complex nature of the interaction mechanism, it is not possible to gain a complete, in-depth

understanding of the mechanism by segmented information or a standalone approach. Indeed, determining

how hydraulic fractures grow in deep, naturally fractured reservoirs may be well beyond the ability of a

single data set or standalone analysis and interpretation. In this study, we applied an integrated approach

to incorporate all information (see Fig. 1):

● Conduct frac pressure analysis to reveal controlling factors for hydraulic fracture breakdown and

propagation;

● Leverage microseismic monitoring data to add to our understanding of fracture propagation and

complexity;

● Conduct hydraulic fracturing modeling to disclose the effect of natural fractures on the hydraulic

fracture geometry and the treating net pressure through utilizing a fracturing simulation modeler

capable of predicting complex hydraulic fracture growth in naturally fractured reservoirs;

● Carry out near-wellbore 4D geomechanics simulation to link geomechanical responses of the

reservoir during hydraulic fracturing with the microseismic data;

● Carry out large block hydraulic fracturing tests to reveal the relationship between near-wellbore

complexities and the perforation configuration.

Figure 1—Integrated workflow to evaluate interaction mechanism between hydraulic fracture and natural fracture.

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The workflow is intended to emphasize the interrelationship of the various components and the need

to link the results from different interpretations and data sets. Understanding hydraulic fracture complexity

is only the first step: the critical steps that follow are formulation of a strategy to improve stimulation

effectiveness and efficiency of field application. The analysis of data acquired during the field application

could feed back into and deepen the understanding of the interaction mechanisms.

Understand the Reservoir

Understanding of the reservoir, from a petrophysical, natural fracture and geomechanical perspective

gives an indispensable context for reservoir stimulation and investigation of the interaction mechanism.

Also knowledge on the petrophysical properties, natural fractures, geomechanical properties and in-situ

stresses constructs a basis for the integrated analysis. For the practical publishing purpose of the paper,

the petrophysical analysis, natural fracture interpretation and geomechanical analysis are only briefly

described in this paper, some of the detailed workflows and results will be presented in future publications.

Petrophysical Properties

An advanced petrophysical analysis of key study wells was conducted using the full suites of log data toestablish an interpretation model. The model was applied to rest wells with only triple combo to determine

lithology, porosity and permeability of the reservoir. Fig. 2 shows the petrophysical interpretation results

for well KS2-2-8 as an example. The analysis reveals that the reservoir formation is a clean, tight

sandstone. There is no aquifer underneath, so there is no risk to connect to water zone during hydraulic

fracturing.

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Natural Fracture Properties

Interpretation of natural fractures was conducted on all study wells using borehole image data acquired

for the wells. The fracture orientations were determined by fitting flexible sinusoids to the fracture traces

on the unwrapped images. Fig. 3 shows the image interpretation results for well KS2-2-8 as an example.

As can be seen from figure, in the upper part of the reservoir, the natural fractures are primarily sealed

and closed (indicated as red tadpoles), and in the lower part of the reservoir, most natural fractures are

open (indicated as blue tadpoles). The statistical analysis of the dip and dip azimuth of the natural fractures

every 50 m is given by the rose plots in the second track from the right, and some variation of dip and

dip azimuth is observed. The rose plots for the maximum horizontal stress azimuth in every 50 m are given

in the last track which is interpreted from breakouts and drilling induced fractures from the image data,

some variation of stress azimuth along the wellbore is also observed.

Figure 2—Petrophysical evaluation for well KS2-2-8.

SPE-174384-MS 5



In-Situ Stress Field in KS

High tectonic activity during geological history (Jia 1991) resulted in imbricate faulting structures and

high differential stress in KS (see Fig. 4). In this study, major efforts were made to construct 1D

Mechanical Earth Models (1D MEMs) for more than 37 wells in the field. A MEM is a numerical

representation of the state of in-situ stresses and rock mechanical properties for a specific stratigraphic

section in a field or basin. It includes elastic properties, rock strength data, and geostresses (Plumb et al.

2000, Ali et al. 2003). Some of the work on 1D MEM construction in the KS field has been previously

published (Zhang et al. 2014). Fig. 5 displays the output window of the 1D MEM and wellbore stability

prediction for well KS2-2-8. The reliability of the 1D MEM was validated through comparing the

prediction from the 1D MEM to the observed borehole failure. The synthetic borehole failure image (Qiu

et al. 2008), located on the second track from the right, shows the predicted breakout (see yellow area fill)

and drilling induced fracture (see the dark line segments in the same track) from the 1D MEM. The square

log B and D in the same track show the depth intervals where breakout and drilling induced fractures,

respectively, were observed from the borehole microresistivity image. The borehole enlargement is also

Figure 3—Dip and dip direction of natural fractures for well KS2-2-8 (left: dip azimuth; middle: strike of natural fractures; right: dip of

natural fracture). Track 1: ELAN volume; Track 2: total porosity; Track 3: Gas saturation; Track 4: Volume of clay; Track 5: tadpoles of

natural fractures, red color indicates sealed fracture, while blue color indicates open fractures; Track 6: strike of natural fractures within

50 m; Track 7: strike of maximum horizontal stress average within 50 m.

6 SPE-174384-MS



shown in first track on the right through the caliper logs. A comparison of the predicted synthetic borehole

failure image and the observed borehole failure yielded a reasonably good match. Through this method,

the 1D MEM was validated for each study well. It was shown that the difference between the minimum

and maximum horizontal stress exceeds 30 MPa in the KS reservoir (see the track of In-Situ Stresses in

Fig. 5). Compared with previous publications on tight reservoirs, the KS reservoir has much higher

differential horizontal stress. Table 2 shows the representative averaged overburden stress, minimum and

maximum horizontal stress.

Figure 4—Geological structure of the KS field. The structure penetrated by well KS2 is the target field studied in this paper (Modified

from Yi et al. 2012).

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The most reliable method for determining in-situ stress orientations is through observing the wellbore

failure resulted from either compressive or tensile stress concentrations around the wellbore. In a vertical

well, compressive stress failures at the azimuth of the minimum horizontal stress can result in breakout

(Bell and Gough, 1979; Plumb and Hickman, 1985), while tensile stress failure at the azimuth of the

maximum horizontal stress (Aadnoy, 1988; Aadnoy and Bell, 1990) are termed as drilling induced

fractures. In this study, the stress direction for each study well was determined through identifying

breakouts and drilling induced fractures from images, and large variations among the wells are observed

(see Fig. 6) despite the background north to south tectonic thrusting. It is anticipated that such variation

resulted from the ubiquitous faults and natural fractures in the reservoir. Nevertheless, the exact reason is

still subject to further investigation.

Figure 5—1D MEM for well KS2-2-8. The in-situ stress state on Track 4 including maximum horizontal stress (SigH_1), minimum

horizontal stress (Sigh_1), overburden stress (SigV_1) and pore pressure (PPRS_1); the mechanical properties on Track 5 including

UCS (UCS_1), tensile strength (TSTR_1), friction angle (FANG_1), Poisson’s ratio, (Pr_sta_1) and Young’s modulus (E_sta_1); the

boundaries for wellbore deformation and the stable mud window on Track 5, and the synthetic borehole failure image (Qiu et al. 2008)

on Track 6.

Table 2—Average in-situ stresses in the KS reservoir

Depth Range (m)

Reservoir

Pressure (MPa)

Overburden

Stress (MPa)

Min. Horizontal

Stress (MPa)

Max. Horizontal

Stress (MPa)

For all depth ranges 116 167 135 170

8 SPE-174384-MS



Intersection Angle and Normal Stress on the Natural Fracture Plane

The intersection angle is the angle between the strike of the natural fracture and the azimuth of the

maximum horizontal stress for a given well. There is a large variation of stress direction (See Fig. 6) and

fracture strike which results in a large variation of intersection angles among the wells in the reservoir.

The intersection angle controls the normal stress on the natural fracture plane. Fig. 7 illustrates how the

effective normal stress varies with the intersection angle for natural fractures with dip angle of 60°, 70°,

80° and 90°. It was constructed through projecting the three principal stresses on to the fracture plane

(Jaeger et al. 2007) based on the in-situ stress information as listed in Table 2. Note as a simplified

solution, this analysis ignored the potential disturbance on the in-situ stresses in the near fracture region

due to existence of the natural fracture (stress rotation near natural fractures). In the KS reservoir, the

natural fracture dip spans from 60° to 90° with an average value of 75°, so the figure illustrates the general

trends of normal stress on natural fractures varying with the intersection angle. As can be seen from the

figure, when the intersection angle is lower than 10°, the normal stress is largely constant, and exhibits

an approximately linear increase trend when the intersection angle goes beyond 10°. For the 70° dip anglecase, the effective normal stress is up to 36 MPa at the intersection angle of 40°, which is 13 MPa higher

than the effective normal stress at the intersection angle of 10°. In many stimulation treatments, the net

pressure is generally lower than 10 MPa, thus a 13-MPa difference in the normal stress can make a big

difference in the reservoir stimulation behavior.

Figure 6 —Maximum horizontal stress direction in the western part of the KS reservoir. Upwards is north direction.

SPE-174384-MS 9



Frac Pressure Analysis

Analysis of fracturing treating pressures is recognized as a powerful technique for developing a compre-

hensive understanding of the fracturing process, fracture geometry and fracture conductivity ( Nolte 1979,

1986). In the KS reservoir, the near wellbore tortuosity, 3D distribution of the natural fracture network,

and fluid leakoff in the natural fractures are largely unknown so rigorous pressure analysis is very difficult

with limited mini-frac data. In this study, as a preliminary step, the frac pressure analysis focuses on

revealing the controlling factors on the breakdown pressure and fracture propagation pressure from the

pressure data of the main fracs. The breakdown pressure is an indication of how easily the reservoir

formation can be fractured; and fracture propagation pressure is an indication of how easily the hydraulic

fracture can grow into the far field and the proppant can be placed. Since there is a large variation in

treating pressure during the whole course of the treatments, with change of pumping rate and proppant

concentration in the slurry, the instantaneous shut-in pressure (ISIP) was used to represent the fracture

propagation pressure to make the results comparable among different treatment wells. After the treatments

were performed fracturing pressure analysis was conducted for 8 wells for which massive hydraulic

fracturing was conducted. Once the breakdown pressure and ISIP were obtained from these wells, an

effort was made to correlate them to mechanical properties and stresses to reveal the controlling factors

for the two parameters.

Breakdown Pressure

It was found that the breakdown pressure is well correlated to the minimum horizontal stress (see Fig. 8

(a)). In other words, a hydraulic fracture is easier to initiate at the lower minimum horizontal stress

intervals. Hence it is reasonable to perforate in the depth intervals with low minimum horizontal stress to

facilitate the initiation of hydraulic fractures and mitigate difficulties of breakdown observed in some

wells.

Figure 7—Normal stress on the fracture plane.

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Fracture Propagation Pressure

Meanwhile, it is also observed that the fracture propagation pressure (represented by ISIP) is mostly

correlated to the normal stress on the natural fracture plane (see Fig. 8 (b)). As can be seen from the figure,

as the intersection angle increases, the effective normal stress increases. High normal stress on the natural

fracture plane makes it even more difficult to slip or open, resulting in a narrower aperture and

subsequently blocking the transportation of the proppant across the fracture, which might be the root cause

for high fracture propagation pressure for the high intersection angle wells (e.g. well KS2-1-1). This

interpretation will be further validated by hydraulic fracturing modeling in a later section of this paper.

Diversion vs. ISIP

With more than 200 m of reservoir thickness, multiple stage hydraulic fracturing is required to achieve

sufficient vertical coverage of the reservoir. Due to the HPHT and depth of the reservoir, operations of

the mechanical bridge plugs are very difficult, time consuming and prone to failure. To this end, a

fluid-based fiber diversion technology, which has previously been successfully applied to shale gas, was

introduced to the KS reservoir. Fiber diversion is accomplished through using special fibers added to the

fracturing fluid to create a temporary bridge within the active fracture network which results in differential

pressure increase and causes treatment redirection to understimulated intervals (Daniels et al. 2007;

Potapenko et al. 2009; Waters et al. 2009). The objective of applying the fiber diversion in the KS

reservoir is to effectively stimulate the more than 200-m depth interval.

Fig. 9 illustrates staging diversion analysis of well KS2-2-12, in which three straight lines represent the

ISIP obtained from the treatment stages 1, 2 and 3. This well had a 3 stage proppant fracturing treatment

separated by two fiber diversions. The green line is the ISIP for stage 1, the cyan line and blue line are

the ISIP after the 1st and the 2nd fiber diversion operation, respectively. The ISIP is a good representation

of fracture propagation pressure as mentioned previously. As can be seen from the figure, the ISIP for the

stage 1 stimulation is barely above the minimum horizontal stress profile in limited depth intervals in the

upper portion of the reservoir, which means the stage 1 stimulation only opened limited depth intervals

in the reservoir. The cyan line, represent the ISIP after the first division, and is around 5 MPa higher than

the ISIP from the first stage. It can be seen that the cyan line is sufficiently higher than the minimum

horizontal stress in most depth intervals in the upper portion of the reservoir, which means the first

diversion effectively improved the vertical coverage of the hydraulic fracture. The blue line, which is

Figure 8 —Frac pressure analysis.

SPE-174384-MS 11



around 3 MPa higher than the cyan line, is higher than the minimum horizontal stress in almost all depth

intervals of the reservoir. It means after the second diversion, the hydraulic fracture has vertical coverage

of almost the whole depth interval of the reservoir. The analysis shows that the two fiber diversion

treatments were successful and effective that enabled a good vertical coverage of the pay interval, and

maximized the contact to the reservoir.

Microseismic Data Analysis

Microseisms are micro-earthquakes induced by the changes in stress and pore pressure associated with

hydraulic fracturing. Microseismicity monitoring is the primary technique to image the geometry and

growth of the hydraulic fractures (Albright and Pearson 1982; Thorne 1988; Mahrer 1993; Fisher et al.

2002; Maxwell et al. 2002).

There are three possible sources of microseismic events during hydraulic fracturing, namely opening

at the fracture tip, failure of intact rock in regions other than the fracture tip, and failure on pre-existing

natural fractures (Cipolla et al. 2010). While the microseismic deformation can contain tensile modes of

deformation, shear deformation is the dominant mode. It is generally assumed that most of the observed

microseismic events are shear failures, either of intact rock, or more likely on existing planes of weakness,

such as faults or natural fractures (Gale et al. 2001; Maxwell et al. 2008).

Microseismic monitoring data were acquired for two wells, KS2-2-8 and KS2-1-1 in the KS reservoir

(see Fig. 10). The two wells have similar petrophysical and mechanical properties as well as in-situ stress

Figure 9—ISIP vs. the minimum horizontal stress for two diversions for well KS2-2-12. The green line is the ISIP for stage 1, the cyan

line and blue line are the ISIP after the 1st and the 2nd fiber diversion operation, respectively.

12 SPE-174384-MS



profiles except the difference of the intersection angle. Well KS2-1-1 has an intersection angle of 40°,

while well KS2-2-8 has an intersection angle of 10°. From map view it can be seen that geometry of

microseismic events is largely aligned with the maximum horizontal stress for well KS2-2-8, while well

KS2-1-1 exhibits much more complex geometry. Cipolla et al. (2008) proposed that the total width vs.

total length of the microseismic cloud can be used to evaluate fracture complexity, which is comparable

with other data set. Fracture complexity index (FCI) is defined as the ratio between total width and total

length of microseismic cloud, with planar fractures having a relatively small FCI and network fractures

having a larger value. It can be seen (Fig. 11) that KS2-1-1 has the extreme value of FCI as 1, and KS2-2-8

has relatively lower FCI value of 0.25, both exhibit equivalent or even higher complexity compared to

many shale gas wells in US. In other words, the hydraulic fracture network for KS2-2-8 and KS2-1-1 are

both complex, although well KS2-1-1 has much higher complexity compared to well KS2-2-8. In addition

to the geometry, the propagation patterns of microseismic events are also very distinct between the two

wells. Fig. 12 shows the microseismic events in time and distance from wellbore cross plot, in which blue

dots shows the events from well KS2-2-8, while red dots shows those from well KS2-1-1. Several distinct

behaviors can be observed:

Figure 10—Microseismic map for KS2-1-1 and KS2-2-8. In far right of the figure, the rose plot shows the strike of the natural fracture,

and the red arrow in the ellipse shows the maximum horizontal stress direction. The dominant deformation mechanism of the natural

fractures are also shown in the far right, see text for more detail.

SPE-174384-MS 13



Figure 11—Fracture Complexity Index (FCI) for various geologic environments (Modified from Cipolla et al. 2008).

Figure 12—Microseismic event propagation for KS2-2-8 and KS2-1-1.

14 SPE-174384-MS



● Well KS2-1-1 has a lot more microseismic events than well KS2-2-8, which implies a lot more

shear slippage induced during the hydraulic fracturing of well KS2-1-1 in addition to the possible

different acquisition bias between the two wells.

● The microseismic events from well KS2-2-8 propagated much further away from the wellbore

shortly after commence of the hydraulic fracturing, while the microseismic events from well

KS2-1-1 propagated much slower, and most events were constrained within a distance range of 100 m away from the wellbore, implying the existence of the strong lateral containment to the

hydraulic fracture growth.

The distinct behavior between the two wells might be attributed to the interaction mechanism between

the hydraulic fractures and natural fractures. For well KS2-2-8, the hydraulic fracture can propagate easily

away from the wellbore with low treating pressure because the natural fractures are favorably oriented in

relation to the in-situ stress and largely aligned with the propagation direction of the hydraulic fracture.

The natural fractures are prone to be opened in tension (as illustrated in the rightmost plot in upper portion

of Fig. 10) given the low normal stress on the natural fracture plane. However, for well KS2-1-1, the

intersection angle is 40°, so the hydraulic fracture will unavoidably intersect the natural fractures (as

illustrated in the rightmost plot in lower portion of Fig. 10), and can reactivate the natural fractures in

shear, branching and/or cross the natural fractures in offset with building up of net pressure. The naturalfractures essentially create an avenue for lateral growth resulting in a shorter primary hydraulic fracture

length. More detailed investigation of the mechanism will be conducted in the following sections of

hydraulic fracture modeling and near-wellbore 4D geomechanics simulation.

Hydraulic Fracturing Modeling

To enable an optimized hydraulic fracture design, execution and interpretation, technical capability to

model the propagation of hydraulic fractures is required. Planar bi-wing hydraulic fracture models such

as well-known PKN (Perkins et al. 1961; Nordgren 1972) and KGD (Khristianovich et al. 1955; Geertsma

and Klerk 1969) have been used in the industry for decades, but these models are overly simplified and

inadequate for unconventional reservoirs, as they do not properly describe the details of hydraulic fracture

growth in these complex environments. As noted by Nolte (1987), the next meaningful advance in

hydraulic fracturing is to address the case of multiple fractures and slippage of joints. To overcome the

limitation of these conventional bi-wing fracture models, Xu et al. (2009a, 2009b, 2010) presented a

model, referred to as the Wire-mesh model, which simulates fracture network propagation during a

fracture treatment in a reservoir with given orthogonal sets of natural fractures. While the Wire-mesh

model is capable of providing an estimate of the fracture network dimensions and proppant placement in

the natural fractures, it has inherent limitations that the natural fracture network pattern (i.e. the frac strike

and spatial distribution) cannot be directly linked to the pre-existing natural fractures (Cipolla et al. 2011).

To honor a pre-existing natural fracture pattern, a more rigorous fracture simulator has been developed,

referred to as the Unconventional Fracture Model (UFM) (Weng et al. 2011). The UFM is able to conduct

the modeling on a more realistic fracture network linking directly to the pre-existing natural fractures

(Cipolla et al. 2011). A key component of the UFM is the ability to simulate the interaction of a hydraulic

fracture tip with a pre-existing natural fracture when they intersect, i.e., whether the hydraulic fracture

propagates through, or is arrested by, the natural fracture, which may open and propagate (Gu and Weng

2010; Gu et al. 2012). The branching of the hydraulic fracture at intersections with the natural fractures

gives rise to the development of a non-planar, complex fracture network.

Developing a DFN for UFM applications

Only discrete features have a direct impact on the hydraulic fractures simulated with the UFM. In this

study, we use a discrete fracture network (DFN) to represent a pre-existing natural fracture network. The

SPE-174384-MS 15



DFN was initially proposed in the 1980’s (Schwartz et al. 1983; Dershowitz 1988) to replace the idealized

dual porosity/dual permeability model (Warren and Root 1963) for reservoir simulation of fractured

reservoirs. The main difference in using a DFN in the fracture modeling rather than reservoir simulation

is a required input of the friction angle of the DFN In this study, the friction angle of 30° is assigned to

DFN which is consistent previous laboratory-determined values (Zoback 2007). The DFN was generated

by using FMI interpretation results as mentioned previously from well KS2-2-8 to give the statistical

information on the fracture spacing, size and orientation. The details of building a DFN representation are

described by Will et al. (2005) and will not be covered in this paper. Once a DFN is generated, the DFN

and 1D MEM are used as input and a hydraulic fracture network can be predicted for a given pumping

schedule. Simulations were performed using UFM to illustrate the impact of natural fractures on fracture

geometry, complexity and net pressure. While keeping the mechanical properties, in-situ stress and

pumping schedule constant, the simulation evaluated three scenarios including a no-natural fracture

scenario (scenario 1), small intersection angle scenario (scenario 2) and large intersection angle scenario

(scenario 3) (see Table 3).

Effect of Natural Fracture on the Geometry of Hydraulic Fracture System

The impact of natural fracture system on the geometry of hydraulic fracture system is shown in Fig. 13.

A long and bi-wing fracture is generated for no-natural fracture scenario (see the upper plot of Fig. 13).With existence of natural fractures with the small intersection angle, a shorter hydraulic fracture is

generated with a low level of complexity (see the middle plot of Fig. 13). This is due to the strike of

natural fractures being largely aligned with the hydraulic fracture propagation direction, so that hydraulic

fracturing would open the natural fractures rather than crossing them. There is consequently little

resistance and disturbance on the hydraulic fractures. For the large intersection angle scenario, the fracture

network becomes much more complex, wider and shorter (see lower plot of Fig. 13). For this case, the

hydraulic fractures will unavoidably intersect natural fractures. They can reactivate the natural fractures,

and/or cross the natural fractures in offset, resulting in a complex 3D hydraulic fracture network.

Table 3—Hydraulic fracture modeling scenarioNo. Scenario Description

1 No-fracture scenario Ignore the existence of natural fracture

2 Low intersection angle scenario The intersection angle is 10° (actual case for well KS2-2-8)

3 High intersection angle scenario The intersection angle is 40°

16 SPE-174384-MS



Figure 13—The modeled hydraulic fracture network for 3 scenarios. No natural fracture (upper); intersection angle of 10 (middle) and

intersection angle of 40 degree.

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Effect of Natural Fractures on Net Treating Pressure and Main Fracture Aperture

Fig. 14 shows the predicted net treating pressure and main fracture aperture for the 3 scenarios. The

no-natural fracture scenario has the lowest treating pressure while the large intersection angle scenario has

the highest treating pressure (see left side of Fig. 14). For the no-natural fracture scenario, the net treating

pressure is only 6 MPa above the minimum horizontal stress (the green curve), and the low intersection

angle scenario (the blue curve) yields 10 MPa, both are within reasonable values observed from

stimulations. However, the net pressure for large intersection angle scenario is more than 20 MPa. This

is because additional net pressure is required to either reactivate or cross the natural fractures for this

scenario, owning to the large horizontal differential stress in the KS reservoir. As shown in Fig. 7, the

natural fractures with a large intersection angle to the maximum horizontal stress will always have higher

normal stress on the fracture planes. This explains the difference of the observed treating pressures for

wells KS2-2-8 and KS2-1-1 (see Table 1). Due to high net treating pressure, the large intersection angle

scenario yields the largest aperture for the main hydraulic fracture (see right plot in Fig. 14). However,

it does not necessarily mean that the placement of proppant will be easier for this scenario. Rather,

connections and offsets with natural fractures by the hydraulic fracture have much lower aperture due to

high normal stress, and they could become obstacles for proppant transportation, resulting in difficulties

for proppant placement. This is also consistent with the observations from previous stimulation experi-ences (see Table 1).

18 SPE-174384-MS



Near-Wellbore 4D Geomechanics Simulation

Previously, microseismic monitoring has been largely applied in standalone mode and encountered

difficulties with interpretation and application to improve stimulations. In the last 10 to 15 years, the

continued growth of microseismic mapping, especially in shale-gas development, has highlighted the need

for integrating geomechanical modeling with microseismic applications (Cipolla et al. 2010). Settari et al.

2002, Warpinski et al. 2004, Warpinski 2009, Palmer et al. 2007 have all documented the potential

application of geomechanics to improve microseismic interpretation. In this study, geomechanics mod-

eling is used to enhance the interpretation of microseismic data, by using well-established geomechanics

principles to provide a physical explanation of the observed microseismic events in the KS reservoir.

As mentioned previously, natural fractures may slip due to changes in the far-field stress induced by

fluid migration and overpressure during hydraulic fracturing, and the slippage might be detected from

microseismic monitoring (Warpinski and Branagan 1988; Fisher et al. 2004). At this moment, the existing

hydraulic fracture modeling codes do not account for the impact of fluid migration and overpressure zone

on the slippage of the natural fractures so it is required to simulate this separately by near-wellbore 4D

geomechanics. 4D geomechanics simulations calculate stress disturbances resulting from stimulation

Figure 14—Net treating pressure and main fracture aperture predicted from hydraulic fracture simulation

SPE-174384-MS 19



induced fluid migration and related overpressure, and subsequent shear failure in the natural fractures. The

calculated plastic shear strain, the representation of shear failure, is used as proxy of microseismic events

( Nagel and Sanchez-Nagel 2011) so the plastic shear strain cloud from natural fractures is comparable

with the microseismic event cloud. Hence geomechanics simulation will be able to provide insight on

mechanical behavior of natural fractures during hydraulic fracturing, and create a direct link to micro-

seismic events.

It is noteworthy that the simulation is a “screening model”, meaning it takes a global perspective wheredetails of natural fracture distribution, fluid leakoff and time dependent failure propagation is not

considered due to limited data available (Palmer et al. 2013). Although the model is a screen model, it is

intended to capture the key factors such as in-situ stresses and natural fracture strike that control the

interaction between hydraulic fractures and natural fractures during stimulation. It is a cost and time

efficient approach to approximate the true answer of the problem.

In this paper, the 4D geomechanics simulation was conducted by using the 3D finite element method

(FEM) simulator VISAGE which is integrated with Petrel and the reservoir simulator ECLIPSE.

Gridding

Gridding divides the formations of the model into a mesh of finite elements to be used for numerical

simulation (Logan 2010). Typically, for 3D and 4D geomechanics simulation, gridding should be based

on the geological framework from horizons to honor the geological structure of the field. However, for

this study, since it is single well simulation, the grid is constructed by following the formation tops. To

ensure adequate resolution to include a fracture system, the horizontal resolution of the model is assigned

as 2m 2m. The vertical resolution is also assigned as 2m. The total lateral extent of the model is 200m

200m.

3D Mechanical Properties

As a simplified approach, constant elastic properties were used in the simulation. Table 4 shows the

mechanical properties used in the simulation.

Discrete Fracture Network (DFN) Modeling

The natural fractures in the model were represented by a DFN with weaker mechanical properties

compared to the matrix. A DFN was constructed for well KS2-2-8 based on the FMI interpretation results

as explained previously (see Fig. 3). During modeling, the density of fractures has been scaled down

intentionally to achieve both simulation efficiency and ability to delineate deformation of fractures during

hydraulic fracturing. The DFN was then integrated into the 3D geomechanical model. The fractures were

represented by assigning different mechanical properties for the cells passed through by natural fractures by using equivalent material concept (Qiu et al. 2014). The friction angle of fractures is assigned as 30°,

and their cohesion is assigned as 0.

Stress Initialization

The 3D FEM is used to initialize the stress tensor in the 3D model (Qiu et al. 2013). The detailed theory

of the FEM involves a good number of mathematical equations which have been well documented

elsewhere (Zienkiewicz and Taylor 2005; Logan 2010) and is not covered in this paper. In the 3D

finite-element software tool used in the project, the pre-production stress solution was calculated in two

stages. For the first step, only the gravity and pore pressure loads were applied; the second step added

Table 4—Mechanical properties used for near wellbore 4D geomechanics simulation

Young’s modulus (GPa) Poisson’s Ratio () UCS (kPa) Friction angle () Tensile strength (kPa)

50 0.25 180,000 45 13,000

20 SPE-174384-MS



depth-dependent horizontal loads on the side boundaries. It is important to emphasize that these side loads

were applied on the boundaries only; inside the grid, stress magnitudes and orientations will vary

according to the local pressures and properties. The magnitudes of the side loads are initially estimated

based on the knowledge of horizontal stresses gained from building the 1D MEM. Then the side loads are

adjusted until the resulted 3D stress field was consistent with the in-situ stress profiles from the 1D MEM

at the well location.

Overpressure Zone Modeling

The exact geometry of the overpressure zone created from hydraulic fracturing is very complex as it

depends on the matrix permeability, distribution of natural fractures and propagation and communication

of hydraulic fractures with natural fractures. Previously, an ellipsoid shape of overpressure zone was

assumed ( Nagel and Sanchez-Nagel 2011; Palmer et al. 2013) for numerical simulation to history match

the microseismic data. In this simulation, we adopted a similar approach to construct an overpressured

ellipsoid. The pore pressure value in the overpressured ellipsoid is 155 MPa for KS2-2-8 which is

minimum breakdown pressure observed (see Fig. 8), while for KS2-1-1 it is 165 MPa since a higher net

pressure is observed from that well.

4D Numerical Simulation

4D numerical simulation was conducted by incorporating the new reservoir pore pressure cube, and the

new stresses and strains in the natural fracture system caused by the overpressure zone (due to hydraulic

fracturing) are obtained.

Visualization and Interpretation

The interpretation herein focuses on the additional strain and stress induced by the hydraulic fracturing.

Fig. 15 (a) and (b) show the overpressured zone resulting from hydraulic fracturing and the predicted

plastic shear strain on the DFN for well KS2-2-8, respectively. Note the plastic shear strain less than 0.001

has been filtered out. As can be seen from Fig. 15 (b), most plastic shear strain on the DFN is largely

restrained within the overpressured zone. This is a significant observation as it means that only when

hydraulic fracturing fluid flows into the natural fractures (which both reduces the normal stress by

overpressure and reduces friction angle from lubrication), the slippage of natural fractures can be triggered

and accompanying microseismic events can be captured. The stress shadow effects by the overpressure

zone itself seem only to impact the tip area of the overpressure zone. Fig. 16 (a) shows the same predicted

plastic shear strain on DFN as in Fig. 15 (b) but in top view and with different display limits to make the

variation of the strain more visible. Since most recorded microseismic events reflect shear slippage

(Pearson 1981; Maxwell et al. 2008), the plastic shear strain (and slippage) predicted from 4D geome-

chanics simulation should be comparable with the microseismic cloud. A comparison between the

microseismic cloud and the simulation results was conducted and the results are shown in Fig. 16 (b). It

can be seen that the geometry of the fractures with obvious plastic shear strain is adequately consistentwith microseismic monitoring events. It is concluded that during hydraulic fracturing of well KS2-2-8, the

overpressured zone resulted from hydraulic fracturing is largely contained in a narrow band along the

maximum horizontal stress direction. The stimulation fluid dominantly migrates along the band so only

the natural fractures within the narrow band are reactivated and which triggers the microseismic events.

The geometry of the assumed overpressure zone used for numerical simulation largely reflects the likely

geometry of the stimulation fluid migration region.

SPE-174384-MS 21



Following the same workflow, a 4D geomechanics simulation was also conducted for well KS2-1-1.

Fig. 17 (a) shows the overpressured zone resulting from hydraulic fracturing, whose geometry is assumed

to be the same as the one used for well KS2-2-8. Fig. 17 (b) shows the predicted plastic shear strain for

the DFN for well KS2-1-1. Again plastic shear strain less than 0.001 has been filtered out. Similar to well

KS2-2-8, the plastic shear strain on the DFN is largely contained within the overpressured zone, except

that some low plastic shear strain branches expand out near the tip area of the overpressure zone. It is

evident that the magnitude of the predicted plastic shear strain is much higher and covers a much bigger

reservoir volume compared to the one from well KS2-2-8 (see Fig. 15 (b)). This supports the fact that the

KS2-1-1 well had many more observed microseismic events. The observation from well KS2-1-1reconfirms the hypothesis from well KS2-2-8, that when hydraulic fracturing fluid migrates into the

natural fractures, the natural fractures will slip and trigger microseismic events. The stress shadow effects

seem limited and only impact the tip area of the overpressure zone. Fig. 18 (a) shows the predicted plastic

shear strain in the DFN in top view, and Fig. 18 (b) gives a rough comparison of the predicted plastic shear

strain and the microseismic cloud. It can be observed that there are large differences in the geometries

which implies that the actual overpressured and stimulation fluid migrated zone for this well is very much

different from what was used in the geomechanical simulation. In other words, the overpressured zone for

well KS2-1-1 during stimulation is much shorter and wider compared to well KS2-2-8.

Figure 15—Overpressured zone and plastic shear strain on DFN for well KS2-2-8.

Figure 16—Fracture slippage predicted for well KS2-2-8 ((a) predicted shear strain in natural fracture system; (b) compared with

microseismic cloud).

22 SPE-174384-MS



With the integration of the simulation results from wells KS2-2-8 and KS2-1-1, it can be concluded:

y Most plastic strain and slippage on the DFN is related to fluid migration and related overpressure

during stimulation. Much less plastic strain will be generated due to stress shadow. The micro-

seismic cloud gives a good indication of the stimulation fluid migration volume during stimulation.

y Due to high net pressure and high intersection angle, stimulation of well KS2-1-1 develops much

higher plastic strain within a much bigger volume, which is the root cause of many more

microseismic events with much higher magnitude being observed in well KS2-1-1 versus well

KS2-2-8.

Large Block Hydraulic Fracturing TestLarge block hydraulic fracturing tests have been widely conducted in the industry to evaluate the impact

of natural fractures or fissures on the growth of hydraulic fractures (Lamont and Jessen 1963; Daneshy

1974; Olson et al. 2012), the effect of injection rate and fluid viscosity on treating pressure and fracture

geometry (Beugelsdijk et al. 2000), the containment of hydraulic fractures (Warpinski et al. 1982;

Suarez-Rivera et al. 2013) and crossing rules for hydraulic fractures (Blanton 1981 1996; Renshaw and

Polland 1995; Gu et al. 2012). All these works focus on revealing interaction mechanisms between

hydraulic fractures and natural fractures in far field. Meanwhile, high near wellbore pressure drops have

been frequently reported in fracture treatments. Romero et al. (1995) concluded the three possible

Figure 17—Overpressured zone and predicted plastic shear strain on DFN for well KS2-1-1.

Figure 18—Fracture slippage predicted for well KS2-1-1 ((a) predicted plastic shear strain in natural fracture system; (b) compared with

microseismic cloud).

SPE-174384-MS 23



mechanisms as perforation phasing misalignment, perforation pressure drop and fracture reorientation, all

contributing to near wellbore fracture complexity. To reduce near wellbore pressure drop, perforation

configuration has to be optimized. The previous work (Daneshy 1973; Behrmann and Elbel 1991; Abass

et al. 1994; Behrmann et al. 1999) shows that a small angle between perforation direction and maximum

horizontal stress is favorable for reduction of near wellbore tortuosity and breakdown pressure. However,

so far there is no study available to evaluate impact of perforation configuration (oriented vs. helical) on

the near wellbore complexity in fractured reservoirs under high tectonic stress. In this study, a test programme was formulated to explore viable perforation configurations to reduce near wellbore tortuosity

and breakdown pressure in KS reservoir.

Large Block Hydraulic Fracturing Test Setup

The tests were conducted on 3 samples obtained from the outcrop of the KS reservoir Bashijiqike

sandstone (see Table 5). The objective of tests is to investigate near-wellbore complexity in relationship

with perforation configuration with the presence of natural fractures with large intersection angle (e.g.

well KS2-1-1). The tests were designed to represent 3 different perforation configurations (see Table 6).

All three tests utilized nearly identical geometries with the exception of the perforation design. Three

parallel simulated natural fracture interfaces were created in each block. The strike of the simulated

natural fractures was 40° relative to the maximum horizontal stress direction. The dip of the interfaces was

75° (see Fig. 19). Cardinal directions referenced in the block test designs do not coincide with directions

in the KS field, but refer to laboratory coordinates used for convenience. The simulated natural fractures

constructed by cutting the block with a saw, polishing the surface to be flat, then placing the pieces back

together. The interfaces were left un-bonded over most of their surface area, with only a small amount of

adhesive at the top and bottom surfaces for handling purposes. For all three tests presented in this paper

a 1 inch diameter wellbore was drilled and a steel casing was cemented in place with an epoxy resin. Holes

were pre-drilled into the casing where simulated perforations were constructed after the casing was

cemented in place. A total of eight simulated perforations were created in each block using an abrasive

jetting tool. The perforation tunnel diameter was approximately 1/8 and the length was approximately ¾”.

As described below, the location and orientation of these eight perforations was changed for each of the

tests presented.

Table 5—Large block hydraulic fracture sample information

Block size 281 mm 229 mm 379 mm

Rock type KS outcrop

Completion configuration Vertical, cased hole and perforations (3 different configuration)

Simulated natural fracture geometry three parallel natural fractures with strike 40-degrees from direction of H , and 75° dip

Fracturing fluid 5 Pa-s silicone oil

Injection rate 4 mL/min

Vertical stress 22 MPa

Maximum horizont al stress 24 MPaMi ni mum horiz ont al stress 7 MPa

Intersection angle 40 (between the strike of natural fractures and the maximum horizontal stress)

Table 6—Perforation configuration for large block tests

Test Objective Number of perforation

MB-3 Fracture initiation with perforations oriented in direction of H

8, 4 on the each side of the casing (180° phase angle)

MB-4 Fracture initiation with perforations oriented along strike of natural fractures 8, 4 on the each side of the casing (180° phase angle)

MB-5 Fracture initiation helical perforations 8, 60° phase angle

24 SPE-174384-MS



Each block was loaded under a true-triaxial state of stress as listed in Table 5, then hydraulicallyfractured using a 5 Pa-s silicone oil pumped at 4 mL/min. The injection rate and fluid viscosity was chosen

based upon the scaling analysis of Lecampion (2012). The loading system was designed to apply a

constant stress to the block throughout the test, even as it expands and/or contracts as a result of the

hydraulic fracturing. To maintain this constant load through the test, the hydraulic actuators must add or

remove hydraulic fluid to allow the block to expand or contract during the test. The change in hydraulic

fluid volume necessary to maintain the constant load in each direction was recorded throughout the test.

The average displacement of the block in each direction is then calculated by dividing this change in

volume by the block cross-sectional area in each direction.

Because of wellbore storage effects, for a short time after the hydraulic fracture initiates, the flow rate

into the fracture is not equal to the pumping rate ( Lecampion 2012). The actual flow rate into the fracture

is calculated by as described by de Pater (de Pater 1994). An additional important implication of wellborestorage is that the fracture may initiate and begins propagating before the wellbore pressure reaches its

maximum value. However, using the measured block displacements and the calculated flow rate into the

fracture, the instant of fracture initiation can be estimated. In all of the plots of the test data the estimate

for the instant of fracture initiation is indicated with a vertical green line.

Large Block Hydraulic Fracturing Test Results

For test MB-3 the perforations were aligned with the direction of the maximum horizontal stress, with four

perforations on each side of the wellbore. Fig. 20 shows the test geometry used for test MB-3 along with

a plot of the data recorded during the test. The upper plot on the left-hand side of Fig. 20 shows the

Figure 19—Engineering drawing to illustrate the geometry of the block and simulated natural fracture interfaces.

SPE-174384-MS 25



wellbore pressure and the three applied stresses as a function of time. The horizontal dashed line in this

plot is the calculated normal stress acting across the simulated natural fractures. As this plot shows, the

maximum wellbore pressure was below this value, indicating that the fluid pressure within the simulated

natural fractures was certainly insufficient to mechanically open the interface. It is believed that the fluid

was able to flow through the natural fractures by a shear-enhanced dilation mechanism causing an increase

in the hydraulic conductivity, since the native hydraulic conductivity appears to have been quite low. The

center plot on the left-hand side of Fig. 20 shows the measured average block displacements throughoutthe test. Here and throughout, displacement is taken to be positive in compression. Just prior to fracture

initiation, a gradual expansion in the direction of h

and a nearly equal and opposite contraction in the

direction of H

is observed. The contraction in the direction of H

is somewhat larger than the expansion

in the direction of h

. This suggests that the primary cause of the block displacement is shearing along

the simulated natural fractures. This shearing appears to be caused by the increase in fluid pressure within

the simulated natural fractures, which reduced the frictional forces that previously supported the shear

stress produced by the difference between the principal stresses. The bottom plot on the left-hand side of

Fig. 20 shows the pumping rate, the calculated flow rate into the fracture, and the total volume injected

into the fracture.

After the test the block was unloaded and opened to reveal the fracture geometry. The fracture

geometry was mapped using a high-resolution laser scanner. Fig. 21 and 22 show the 3D visualization of

the fracture geometry from test MB-3. Here and throughout, new hydraulic fractures are shows in blue,

while the fluid filled portion of the simulated natural fractures are shown in red. As can be seen from the

figure, a primary hydraulic fracture was created that initiated at the perforation cluster and extended over

most of the height of the block. The lateral extent of this primary fracture was contained by the adjacent

interfaces, which were intersected by the perforations. A secondary hydraulic fracture initiated from the

edge of the fluid penetrated zone of the middle interface and propagated to the upper interface, which was

not intersected by any perforations. The initiation of a secondary hydraulic fracture from the tip of the

Figure 20—A plot of the data recorded during the test (left) and the test geometry (right) for test MB-3.

26 SPE-174384-MS



fluid penetrated zone is consistent with observations from the literature of large tensile stress concentra-

tions near the tip of sheared zones within an interface ( Chuprakov 2014). These secondary fractures are

often called wing cracks in the literature. The presence of these secondary fractures, together with other

indicators discussed blow, suggest that the displacement along the interfaces was primarily a shearing

displacement, with little or no indication of opening. This test produced the largest primary hydraulic

fracture (directly connected to the perforation cluster) of the three tests.

Figure 21—3D visualization of fracture geometry for sample MB-3 showing the activated areas of the natural fractures in brown and the

newly-created hydraulic fractures in blue.

Figure 22—3D visualization of fracture geometry for sample MB-3 (view from top). The secondary fracture is visible to initiate from the

tip of sheared zone on the interface.

SPE-174384-MS 27



Test MB-4 was conducted in exactly the same way as MB-3, except that the perforations were aligned

with the strike of the simulated natural fractures rather than with the maximum horizontal stress direction.

Fig. 23 shows an engineering drawing of the block and perforation geometry along with the data recorded

during this test. The most obvious difference observed between test MB-4 and MB-3 is that the peak

wellbore pressure is much higher. This is likely the result of the perforations being aligned in a direction

where the local near-wellbore stresses are relatively large. Similar to test MB-3, the displacements

measured for test MB-4 show an expansion in the direction of h

and a nearly equal and opposite

contraction in the direction of H

. The contraction in the direction of H

is somewhat larger than the

expansion in the direction of h

. As discussed above, this is consistent with primarily a shearing

displacement along the simulated natural fractures.

Fig. 24 and 25 show the 3D visualization of fracture geometry from tests MB-4. Like the previous test,

this test showed that the natural fractures had a large impact on the hydraulic fracture geometry, and

greatly limited the extent of the hydraulic fracture propagation. The newly-created hydraulic fractures

were contained between the lower/south interface and the center interface (see Fig. 25). The hydraulicfractures did not extend to the edge of the block. Large regions of the lower/south natural fracture and the

center natural fracture were penetrated by fracturing fluid. This test had the smallest new hydraulic

fracture surface area and the highest breakdown pressure of the three tests described here.


28 SPE-174384-MS



Whereas tests MB-3 and MB4 both used oriented perforations, test MB-5 used a traditional helical

distribution of the eight perforations. Fig. 26 shows an engineering drawing of the block and perforation

geometry along with the data recorded during this test. The peak wellbore pressure was lower for this test

than either of the two previous tests, and as with MB-3, was well below the level of the stress acting

normal to the simulated natural fractures. The block displacements followed a similar trend as the previous

two tests—expansion in the direction of h

and contraction in the direction of H — except that the total



Figure 25—3D visualization of fracture geometry for sample MB-4 (view from top).

SPE-174384-MS 29



magnitude of the displacement was much greater for this test, and the expansion in the direction of h

exceeded the contraction in the direction of H

by a small amount—the opposite of what was observe in

the three previous tests. This indicates much more opening of new hydraulic fractures—which is

consistent with the post-test observations discussed below.

Fig. 27 and 28 show the 3D visualization of fracture geometry from test MB-5. Similar to the previous

two tests, this test showed that natural fractures have a large impact on the hydraulic fracture propagation

and considerably limit the extent of the hydraulic fractures. This was the only one of the three recentlycompleted tests that had a hydraulic fracture actually reach the edge of the block. In fact, this test produced

the largest new hydraulic fracture surface area and lowest breakdown pressure of the three tests presented

here. Like one of the hydraulic fractures observed in test MB-3, the hydraulic fracture that reached the

south face of the block in this test appears to have initiated near the edge of the shear-activated region of

a natural fracture. What is unique and particularly interesting about the result of this test is that there are

clearly 3D effects in the fracture re-initiation process that are not considered in the papers from the

literature since they considered only 2D geometries. In this case the tip of the shear-activated region is

roughly circular rather than a straight line implied by the 2D models from the literature. The consequence

of this is that the fracture that re-initiates has a curvature that appears to become reduced as it propagates

away from the natural fracture into the rock matrix.


30 SPE-174384-MS



The key findings from the large block tests are:

● Hydraulic fracture growth was impeded by natural fractures. This is evident for all 3 samples.

● A large proportion of energy was dissipated due to leakoff of stimulation fluid into the natural

fracture.

● Activation of natural fractures was primarily shear, with no evidence of opening-mode displace-

ment. Two evidences of this are: the fracture propagation pressure is lower than normal stress on



Figure 28 —3D visualization of fracture geometry for sample MB-5 (view from top).

SPE-174384-MS 31



the fracture plane, and the mirror of displacement in h

and H

direction, both indicate a dominant

shear deformation.

● 3D hydraulic fracture geometry is evident for all 3 samples, which results from complex stress in

the near wellbore due to existence of natural fractures. Curved hydraulic fractures will be less open

and less supported by proppant, and could result in poor communication with the wellbore from

the far field.

● Secondary hydraulic fractures initiate from the edge of the shear-activated zone. At the edge of shear-activated zone, there is large stress concentration, which favors inducing new fractures (see

Fig. 29).

● Proppant is unlikely to reach secondary fractures because natural fractures do not open.

Based on the key findings, there are key completion guidelines for KS field, especially for those wells

with high intersection angles:

● Effective bridging agent for the natural fractures during hydraulic fractures will be beneficial to

mitigate the impact of natural fracture on the propagation of hydraulic fracturing.

● Avoid perforating right at the fracture zones to avoid near wellbore complexity.

● Based upon the tests presented here, helical perforation with 60° phase angle provides an

acceptable solution. Oriented perforations appear to offer little advantage to KS field.

Hydraulic Fracture Strategy Optimization

Since there are distinct interaction mechanisms for low intersection angle wells and high intersection

angle wells, the stimulation strategy for the two kinds of wells are different in terms of pumping schedules.

Nevertheless, the perforation strategy and diversion strategy are very similar.

Perforation

In addition to favoring high reservoir quality (high porosity, low clay volume zone) depth intervals,

special care should be taken to select low minimum horizontal stress zones and avoid those densely

fractured zones, to yield low breakdown pressure and low near wellbore complexity. Helical perforationswith 60° phase angle is applicable in the KS reservoir. Reducing total perforation length through cluster

perforation minimizes the formation of multiple fractures in the near wellbore region.

Diversion

To effectively stimulate the reservoir with more than 200-m thickness, fiber diversion technology should

be used. A primary indicator for staging for diversion selection is minimum horizontal stress. Perforation

depth intervals should be further optimized to aid diversion from stage 1 to 2 (typically from upper part

of reservoir to lower part of the reservoir since the minimum horizontal stress increases with depth in

general). Since the perforation clusters are placed in non-fractured zones, the dominant factors to control

Figure 29—Conceptual model for secondary hydraulic fracture initiate from edge of shear-activated zone.

32 SPE-174384-MS



fracture breakdown is the minimum horizontal stress. Fracture propagation pressure after diversion should

be high enough to cover the whole reservoir interval.

Pumping schedule

There is a distinct difference between the pumping schedules for the two kinds of wells. For low

intersection angle wells, since the impact of natural fractures is limited, it is recommended that:

● Smaller volume of a 100-mesh proppant slug is required. A proppant slug, combined with fiber,

provides sufficient blockage of natural fractures to limit branching of hydraulic fracture system.

Since the branching is less severe in this case, a smaller slug and less fluid volume will be required.

● Maximize the stimulation volume to ensure sufficient fracture length with adequate contact of the

reservoir. In this scenario the stimulated length will be much larger than the stimulated width.

● Increase diversion stages when required. For low intersection angle wells, the treating pressure is

low which gives chance for additional diversion.

For high intersection angle wells, with consideration of the complexity of hydraulic fracture system

and high treating pressure, it is recommended to:

● Use large volume of 100-mesh proppant slugs and fiber to temporarily block the natural fracturesto minimize their impact on the propagation of hydraulic fracturing.

● Use acid as pre-pad to create a better communication channel between the wellbore and the main

fracture, reduce near wellbore friction and breakdown pressure.

● Limit the diversion stages.

Fig. 30 shows the stimulation design (including staging, perforation) for well KS807 as an example,

in which this stimulation strategy was applied. The figure shows gamma-ray log (Track 2), ELAN volume

(Track 3), effective porosity (Track 4), water saturation (Track 5), the minimum horizontal stress (Track

6) and natural fracture density (Track 7). The last track shows the expected hydraulic fracture height

initiated from each perforation cluster, and the perforation clusters are also shown in the same track. The

perforations were designed based on the guidelines as explained above, and the staging of the stimulationis designed based on the minimum horizontal stress. Fig. 31 shows the predicted hydraulic fracture

geometry for two stages. Branching and interaction with the natural fractures are visible from the figure.

SPE-174384-MS 33



Figure 30—Hydraulic fracturing design for KS807. The last track shows expected hydraulic fracture height initiated from each

perforation cluster including both Stage 1 and Stage2, the perforation clusters are also shown in the same track. The horizontal dash

lines show the rough separation between Stage 1 and Stage 2.

34 SPE-174384-MS



The stimulation strategy was successfully applied to 7 wells in the reservoir and yielded an average

daily production rate of 790,000 m3/day, which is 50% higher than previous wells.

The Way Forward

An in-depth insight has been gained from the integrated study of the interaction mechanism between

hydraulic fractures and natural fractures in the KS reservoir. Nevertheless, given the extraordinary

complexity of the problem, a lot of additional work is yet to be done. We foresee the following additionalwork that will be beneficial to improve the understanding of the interaction mechanisms and further

optimization of the stimulation of the reservoir:

● Construct 3D geological models to honor lateral and vertical heterogeneity in the reservoir.

● Predict the 3D hydraulic fracture distribution by using geological structure restoration (Maerten

and Maerten 2006) and paleo-stress inversion (Maerten et al. 2006) given the poor seismic quality

data in the reservoir under salt. This will help to delineate fracture properties in the reservoir.

● Conduct additional large block tests to evaluate the mid-field and far field fracture complexity and

placement of proppant in the fracture network. Microseismic data acquired during the test should

be analyzed as well.

● Carry out detailed treating pressure analysis and pressure history matching on the main frac and

mini-frac at each stage of fracture evolution (i.e., growth, closing phase and after-closure period)

with downhole pressure measurements. Variation of the traditional calibration tests, such as step

rate test/flowback/step-down should be conducted for determination of near wellbore effect,

closure pressure and fracture conductivities (Economides and Nolte 2000).

● Conduct production profile logging to understand stimulation efficiency and effectiveness across

the production interval.

● Conduct additional near-wellbore 4D geomechanical studies through integrating the fracture

network and overpressure regime from UFM with consideration of stress shadow due to the

fracture opening, leakoff and time elapse effects.

Figure 31—Predicted hydraulic fracture geometry for well KS807 including both stages.

SPE-174384-MS 35



● Conduct a full field 4D geomechanics study to evaluate how depletion of the reservoir impacts

hydraulic fracture conductivity, natural fracture conductivity and well integrity during the pro-

duction of the reservoir.

Some of the work has been started and will be published separately once a milestone step is made.

ConclusionAn integrated evaluation on the interaction mechanism between hydraulic fracture and natural fractures

was conducted in the tectonically-active and naturally-fractured KS reservoir. A new stimulation strategy

was formulated based on the deep insight into the fracture complexity, fracture propagation and

interaction mechanism in the fractured reservoir.

The key findings from the integrated evaluation include:

● Due to large differential horizontal stress in KS field, the intersection angle is the key controller

of hydraulic fracture complexity. The high intersection angle wells exhibit distinct behavior from

the low intersection angles on microseismic cloud geometry, treating net pressure, fracture

complexity, fracturing mechanism, hydraulic fracture effectiveness and productivity.

● Under the large intersection angle case, the hydraulic fracture will unavoidably intersect withnatural fractures, and can reactivate the natural fractures, and/or cross the natural fractures in

offset, resulting in a complex 3D hydraulic fracture system, which is the root cause of high treating

pressure, limited lateral extent of hydraulic fracture system, difficulties in proppant placement,

and, subsequently, poor production performance.

● The breakdown pressure increases with the increase of the minimum horizontal stress, while

existing the natural fractures impede propagation of the hydraulic fractures, so the perforation

clusters should be placed on the lowest horizontal stress depth intervals while avoiding the densely

fractured zone.

● The fracture propagation pressure increases with the increase of the normal stress on the natural

fracture planes, which is root cause for high fracture propagation pressure for the high intersection

angle wells.● Fiber diversion is applicable in KS reservoir that enabled a good vertical coverage of the pay

interval, and improved the contact to the reservoir while largely reducing the operational risk.

● The microseismic monitoring indicate that KS wells exhibit equivalent or even higher complexity

compared to many shale gas wells in US, and the large intersection angle wells has the extreme

FCI value as 1.

● Hydraulic fracture modeling shows that existence of natural fractures results in the complexity of

hydraulic fracture system, and higher intersection angle will cause larger complexity and high net

treating pressure, which is consistent with the field observations.

● 4D near wellbore geomechanical simulation indicates that most plastic strain and slippage on the

DFN is related to fluid migration and overpressure during stimulation. Much less plastic strain will

be generated due to stress shadow. The microseismic cloud gives a good indication of thestimulation fluid migration region during stimulation.

● Large block tests confirmed that the existence of near wellbore natural fractures impede the

propagation of hydraulic fracture and results in the near wellbore complexity, and helical

perforation is viable in KS field.

● Due to distinct complexity of hydraulic fracture system, very different stimulation strategy should

be applied to low intersection angle wells and high intersection angle wells.

The new stimulation strategy had been successfully applied to the KS reservoir and yielded large

increase of the production rate and great financial success.

36 SPE-174384-MS



The paper shows that by understanding the interaction mechanism between hydraulic fracture and

natural fractures, optimization of fracturing treatments has been achieved to improve post-frac well

performance in naturally fractured tight gas reservoirs.

AcknowledgmentThe authors thank PetroChina and Schlumberger for permission to publish this paper. The authors also

thank Schlumberger colleagues in TerraTek for conducting large block test, Yanhua Li, Zhe Yuan Huangand others for acquiring and processing the microseismic data, Xin Wang for the petrophysical interpre-

tation work, Yongjie Huang for reservoir engineering work, and Zijun Zheng for the additional near

wellbore 4D geomechanics simulation work.

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Interaction Between Natural and Hydraulic Fractures

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