Fracture Assessment

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TITLE

Methods for Determining Frack Performance

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Abstract

This thesis investigates the role of tracers in determining and monitoring the fracture profile

and penetration depth of a stimulation/hydraulic fracturing job. It also looks at the other

roles the tracers play in the oil and gas industry, like determining inter-well connectivity,

single well residual oil saturation and monitoring of EOR injections like SWAG and

WAG. Different types of tracers: radioactive and chemical (water, oil and gas based) have

been discussed in detail with reference to their properties, efficacy, detection techniques

and potential hazards. Other techniques that are used to understand fracture penetration and

propagation like tilt meter, microseismic, production logging and well testing have also

been reviewed.

Then it discusses how the information from tracers can be related to understanding the

fracturing process, and looks at certain alternatives to the conventional radioactive and

chemical tracers on both technical and environmental grounds. It concludes with what

further research and development is being carried out and how it would affect the industry

and the consumers.


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Table of Contents

Abstract .................................................................................................................................. iii

Acknowledgements .............................................................. Error! Bookmark not defined.

List of Figures ........................................................................................................................ vi

List of Tables ........................................................................................................................ vii

Chapter 1 Introduction ...................................................................................................... 1

1.1 Background .............................................................................................................. 1

1.2 Problem Statement ................................................................................................... 2

1.3 Research Objectives ................................................................................................. 2

1.4 Outline of the Thesis ................................................................................................ 3

1.5

Hydraulically Induced Fractures .............................................................................. 3

Chapter 2 Literature Review ............................................................................................. 5

2.1 Introduction .............................................................................................................. 5

2.2 Overcoming Wellbore Damage ............................................................................... 7

2.3 Making Deep-Penetrating Reservoir Fractures ........................................................ 7

2.4 Helping Secondary Recovery Operation ................................................................. 7

2.5 Disposing of Oilfield Brines .................................................................................... 8

2.6 How is a Fracture Made? ......................................................................................... 8

2.7

Formation Damage Mechanisms ............................................................................. 9

2.8 Description of fractures ......................................................................................... 10

2.9

Initiation and Extension of Fractures ..................................................................... 11

2.10 Fracture Orientation ........................................................................................... 11

2.11 Fracture Height and Length................................................................................ 12

2.12 Fracture Width.................................................................................................... 12

2.13 Fracturing Fluid .................................................................................................. 13

2.14

Fracture Conductivity ......................................................................................... 13

2.15 Hydraulic Fracturing Models ............................................................................. 14

2.16 Hydraulic Fracturing in Naturally Fractured Reservoirs .................................... 18

Chapter 3 Fracture diagnostic techniques ....................................................................... 21

3.1 Basic Concepts and Introduction about the techniques ......................................... 21

3.2

The description of common technologies for monitoring fracking penetration .... 24


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Group 1 - Direct far field .............................................................................................. 24

Group 2 - Direct near-wellbore .................................................................................... 27

Group 3Indirect ........................................................................................................ 30

Chapter 4 Chapter 4: Tracers for determining fracking penetration ............................... 31

4.1 Tracers in the Oil industry ..................................................................................... 31

4.1.1 Inter-well Connectivity ................................................................................... 31

4.1.2 SWAG or WAG injection EOR monitoring ................................................... 32

4.1.3 Single Well Residual oil saturation determination ......................................... 33

4.1.4 Cement job integrity ....................................................................................... 35

4.1.5 Multiple zone completion/ Sub-sea well performance analysis ..................... 35

4.1.6

Tracers for fracture profiling .......................................................................... 36

4.2

Types of Tracers .................................................................................................... 40

4.2.1 Radioactive Tracers ........................................................................................ 41

4.2.2 Chemical Tracers ............................................................................................ 41

4.3 Activation/Release of Tracers: ............................................................................... 43

4.4 Detection of Tracers ............................................................................................... 44

4.5 Advantages and Disadvantages of tracers.............................................................. 45

Chapter 5 Alternative Tracers and Conclusions .............................................................. 46

5.1

Alternative Tracers ................................................................................................ 46

5.2 Naturally occurring radioactive tracers :................................................................ 46

5.2.1

Bio Tracers and Nano Rust ............................................................................. 46

5.2.2 Conclusions .................................................................................................... 47

References ............................................................................................................................ 49


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List of Figures

Fig. 2.1 Creation of Propped Hydraulic Fracture [55] ......... Error! Bookmark not defined.

Fig. 2.2 Damage in Hydraulically Fractured Reservoir [14] Error! Bookmark not defined.

Fig. 2.3 Initiation of Vertical Fracture, the Least Principle Stress is Horizontal [37] .......... 11

Fig. 2.4 Fracture orientation a) Vertical Fracture, b) Horizontal Fracture, and c) Angular

Fracture [39] ......................................................................................................... 12

Fig. 2.5 Fracture Geometry of the KGD Model [41]............................................................ 15

Fig. 2.6 Fracture Geometry of the PKN Model [49] ............................................................ 16

Fig. 2.7 Interaction between the Hydraulic Fracture and Natural Fracturesn [69] ............... 20

Fig.2.1 Creation of Propped Hydraulic Fracture [55] ............................................................ 9

Fig.2.2 Damage in Hydraulically Fractured Reservoir [14] ................................................. 10

Fig.2.3 Initiation of vertical fracture, when stress is horizontal [37] ................................... 11

Fig.2.4Fracture orientation a) Vertical Fracture, b) Horizontal Fracture, and c) Angular

Fracture [39] ......................................................................................................................... 12

Fig.2.5 Fracture Geometry of the KGD Model[41].............................................................. 15

Fig.2.6 Fracture Geometry of the PKN Model[49] .............................................................. 16

Fig.2.7 Interaction between the Hydraulic Fracture and Natural Fractures [69] .................. 20


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List of Tables

Table 1 Capabilities of Fracture Diagnostics [70], [72] ....................................................... 23

Table 2Description of borehole images ................................................................................ 29

Table 3The advantages/constraints of some Gas tracers [88] .............................................. 42


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Chapter 1 Introduction

1.1 Background

Hydraulic fracturing is an efficient way to improve the flow capacity of reservoirs to

increase the productivity of the well. The first attempt to fracture a formation to improve

the production was not hydraulic in naturepeople actually broke the formation apart by

using high explosives and providing flow channels from the matrix to the wellbore as early

as 1890 [1]. Then, during the 1930s, Dow Chemical Company realized that the rock matrix

could be deformed if large enough downhole fluid pressure was exerted, and the effect of

acid stimulation would become better in the deformed formations [2].

The first hydraulic fracturing without acidization was applied on a gas well in the Hugoton

field, Kansas, in 1947 to compare the results of this technique with the acidization method

[3]. However, the outcome in Hugoton was not significant, and people thought that

fracturing would not replace acidizinguntil the mid-1960s, when propped hydraulic

fracturing became the first stimulation choice in the Hugoton field.

Nowadays, about 70% of the gas wells and 50% of the oil wells which have been drilled in

North America after the 1950s are hydraulically fractured [1], and many fields produce

commercially only because of the hydraulic fracturing stimulation.

Hydraulic fracturing is suitable for a wide range of geological formations from tight gas

fields, weakly consolidated offshore sediments, soft formations such as coal beds, and

naturally fractured reservoirs[4]. A hydraulic fracturing treatment is divided into two steps

as described below [5][3][1].

The first step is to perforate the casing and create finger-like holes. After the perforation, a

viscous fracturing fluid, which is called pad, is pumped into the well, and a fracture will

propagate into the surrounding rock from the perforated interval when the downhole

pressure goes beyond the breakdown pressure of the formation.

The second step is to inject slurry of fluid with proppants.These proppants are solid

material usually made from silica or ceramic and play the role of keeping the fractures open


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for fluid flow. Such fluid will extend the fracture and carry the proppant deep into the

fracture. Subsequently, the fluid will flow back out of the well and leave the proppant to

support the fracture and create a high-permeability path connecting the matrix and the

wellbore.

1.2 Problem Statement

Hydraulic stimulation is an important technology for extracting hydrocarbons from both

conventional and unconventional reservoirs. For ultralow-permeability shale reservoirs,

now being regularly exploited, hydraulic treatment is absolutely essential to obtain

economic levels of production [6],[7].

A better understanding of fault mechanics and in-situ stress changes during hydraulic

fracturing will increase our ability to better predict the likelihood and characteristic of the

stress field underground allowing for better optimizing hydraulic treatment design.

Using tracers, it is possible to monitor and track the fracture profile and the depth of

penetration. Lacing the fracturing fluid with a tracer can provide valuable information

about the fact that whether the fracking job has contaminated the shallow aquifers or not.

Hence it is important to understand the different types of tracers, how they work, how they

can be detected and what environmental impact they have.

1.3 Research Objectives

Hydraulic fracturing has a key role in improving the productivity of any well. The main

role of determining hydraulic fracturing penetration is to achieve better production of the

reservoir. It helps the producer to optimize field development and well economics.

It is the objective of this thesis to investigate the limitations, advantages and disadvantages

of tracers for determining fracking penetration and to look at some alternative suitable and

more environmentally acceptable tracers.

Previous studies in the literature on fault stability focus on the geological sequestration of

CO2, reservoir depletion and so on. A comprehensive analysis of how hydraulic stimulation

influences the fault stability has not been fully investigated to date. A prediction of how


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pre-existing faults and fractures respond to hydraulic stimulation can help optimize field

operations and improve recovery[9]. For this, understanding the role and function of tracers

in a hydraulic fracturing job is critical. The main purpose of the study is to investigate the

available tracers and to look at more advanced and environmentally acceptable tracers.

1.4 Outline of the Thesis

This thesis is presented in a series of manuscripts. This introductory chapter provides

background information. Some basic knowledge involved in this study is provided in

Chapter 2. Chapter 3 presents the fracture diagnostic techniques; existing methods for

determining fracking penetration. Chapter 4 investigates characteristics of tracers to

determine fracking penetration, and other uses of tracers in the oil industry. Chapter 5

summarizes the use of tracers in determining the successful monitoring of a hydraulicfracture job, and discusses the alternative tracers that could be used for fracture

monitoring..

1.5 Hydraulically Induced Fractures

The highly conductive propped path created by hydraulic fracturing is narrow, but it can be

really long. Economides[10] points out that the typical widths of a hydraulic fracture are

around 0.25 in or less, while the length may reach up to 3,000 ft from tip to tip. The

treatment would take place from tens of minutes to a few hours depending on fracture size.

The direction of hydraulically induced fractures is usually normal to the smallest principal

stresses as the fractures tend to open in the direction of the least resistance; thus, most of

the induced fractures are in the vertical plane, since the smallest principal stress is in the

horizontal plane for most reservoirs[11]. If the formation is isotropic and homogeneous, the

in-situ stress is the controlling factor on fracture propagation[5]. For most cases, the

geometry of the hydraulically induced fracture is determined by the rocks mechanical

properties, in-situ stresses, the rheological properties of the fracturing fluid, and local

heterogeneities such as preexisting natural fractures[11].

In addition, for making the natural gas to flow from formations to the wellbore very easily

the fracking method is used by injecting the mixture of water, sand and chemicals. In most

scenarios the hydraulic fracturing and horizontal drilling are used together to get a


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reasonable cost in natural gas production. It is not commercially viable to extract natural

gas from shale formations without combining these two procedures

The use of hydraulic fracturing has four advantages:

(1)

overcoming wellbore damage,

(2) creating deep-penetrating fissures in the reservoir for increasing well productivity;

(3) to improve the effectiveness of secondary recovery operations;

(4) to create the smooth path for injection and removal of brine [12].

Guo et al.[13]investigated the conductivity effect and fracture penetration on productivity

of wells with several vertical fractures. Guo and Ghalambor[14] and Zheng-dong et

al.[15]predicted the variables in dimensionless groups for the explanation of the production

behavior in the fractured well which is assumed as an infinite conductivity fracture.

The calculation of the effective wellbore radius which is equal to the half of the fracture

length is demonstrated by Prats et al.[16]. And Abousleiman et al.[17]modeled the first

mathematical model which is suitable inthis kind of applications for using well test data

analysis when wells cross the large fractures. Adachi et al [4]investigated several methods

to predict the production rate in hydraulically fractured horizontal wells.

Rajagopal S et al [18] has estimated the productivity of fractured horizontal wells in low

permeability reservoirs

Finally, Zheng-dong Le idefined a new way for predicting the performance of fractured

horizontal wells which is based on non-steady flow of fracturing pad during production.It

has been done by applying potential function principles, superposition principle and

mathematical method for solving, and coupling seepage flow in the formation and pipe

flow in the well bore [15].

The purpose of this study is to investigate the limitations, advantages and disadvantages of

tracers for determining fracking penetration. Furthermore, we try to investigate more

efficient and environment friendly tracers.


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Chapter 2 Literature Review

2.1 Introduction

Tracers are quite commonly used to monitor and evaluate the fracture profile and its depth

of penetration in a formation rock. To understand how tracers work in stimulation /

fracturing job, it is important to understand how rocks fracture. Stimulation fracturing or

fracking is an artificial fracturing where fluids are injected at high pressures to fracture the

rock. Natural fractures also occur in rocks due to geological events like tectonic

movements, faulting and folding.

Once a fault has been formed its further motion is controlled by friction. Friction is a

contact property rather than a bulk property[19]. Friction experiments were first carried out

by Leonardo da Vinci. Leonardos discoveries remained hidden and then were rediscovered

200 years later by Amontons. Da Vinci found that frictional sliding will occur on a plane

when the ratio of shear to normal stress reaches a material property of the material, , the

coefficient of friction[20].

A comprehensive summary of numerous laboratory experiments on friction on a wide

variety of rock types indicates that at intermediate pressure and high pressure (~100

MPa), surface roughness, rock type, normal stress, etc. have little or no effect on friction.

The coefficient of friction is found to be within a relatively small range: 0.61.0.

For example, Morrow, Shi, &Byerlee[21] found that samples of a fault gouge with clays

from the San Andreas fault have coefficients of friction ranging from 0.15 to 0.55. Fault

gouges with a wide range of constituent minerals relevant to natural faults are found to

have a strong influence on frictional stability; the friction of natural faults is strongly

dependent on the composition of gouge[22].

The recent development of unconventional tight gas reservoirs has inspired researchers to

investigate the mechanical properties of gas shale reservoir rocks[23], [24]. Samples tested

differ in their mineralogical composition, the degree of diagenesis, the total organic content

and the degree of maturity of organic material.


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It is suggested by laboratory data that Youngs modulus correlates well with the amount of

viscoplastic creep and that frictional strength, coefficient of friction and amount of

viscoplastic creep vary strongly with clay content. Based on rate and state, friction

experiments in the laboratory using shale samples with a large range of clay content

indicate that clay content determines the deformation mechanism of pre-existing fractures

and faults[9]. When shales comprise of about less than 30% clay, slip on faults is expected

to propagate unstably, thus conventional microseismic events are generated.

For shales containing more than 30% clay, fault slip is expected to propagate slowly, which

does not generate high frequency seismic waves. Depending upon the in-situ stress regime,

faults underground may or may not be tectonically active. Generally when active faults are

in critical stress state, even a slight stress perturbations may trigger such faults to slip[25],

[26].

Fluid injection to subsurface reservoirs, such as hydraulic stimulation and geological

sequestration of CO2, raises pore pressure and causes in-situ stress field changes, which

would tend to influence the stability of underground faults. Researchers have done a lot of

work on fault stability for CO2sequestration[27], [28], [29].

According to the theory of poroelasticity, depleting a hydrocarbon reservoir alters the state

of in-situ stresses, which can sufficiently reactivate and induce the slip of nearby faults[30],[31], [32], [33], [34]. Horizontal wells with multiple fractures are commonly used in

unconventional gas reservoirs, such as the ultralow-permeability shales. It is absolutely

essential to perform hydraulic stimulation in order to achieve commercial gas production

rates[6], [7].

During this kind of stimulation, the local earth stresses are changed, which affects the

stability of underground faults. For hydraulic treatment, there are two common effects

causing stress change during hydraulic fracturing[35], thus, affecting the stability of faults.The first one is the increase of minimum stress because of the poroelastic effect. During

hydraulic treatment, fracturing fluid leaks into formations. Pore pressure increases around

the hydraulic fractures due to leakage, resulting in dilation of the formation.


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The minimum stress thus increases in this stimulated region. When injection is stopped and

the excess pore pressure spreads out into the formation, these poroelastic effects disappear.

The second effect is the stress increase due to the opening of the fracture. If the induced

fracture is held by proppant, this effect remains. This could mean that the original fracture

changes the in-situ stress, and a subsequent vertical fracture will propagate perpendicular to

the initial vertical fracture.

When a fracture is reoriented, fracture width is expected to be reduced and the dependence

of the degree of reduction in the fracture width from the degree of orientation[36]. A

narrow effective fracture width tends to increase fracture pressure, and consequently greater

fracture-propagation pressure.

2.2 Overcoming Wellbore Damage

Damage to the wellbore is usually one of the main reason to reduce effectiveness of

formations that destructs flow channels of oil and gas from formations into the wellbore.

The main character of the fracturing is to make an effective permeability in reservoirs by

creating channels with short radius. Sometimes depth of channels reach 10-20 ft which

increase the production rate 10 to 50 times over pre-treatment rates. The reason of a

significant progress in production rate is clear by the fractures breaking through a damaged

zone in the immediate surroundings of the well.

2.3 Making Deep-Penetrating Reservoir Fractures

Using advanced fracture systems like as deep-penetrating and high-flow-capacity in most

part of the reservoir increase the production of gas. Additionally, it causes a large drainage

area for reservoir formations to feed gas by utilizing the energy of the reservoir to the

maximum.

2.4 Helping Secondary Recovery Operation

Fracturing plays two important roles in the secondary recovery oil:

It helps to injection well to accept more fluid by enhancing the capacity of well

It also increases the efficiency of water-flooding project by creating efficient

capacity flow channels into the production well.


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2.5 Disposing of Oilfield Brines

The huge amount of high salinity water produced by certain oil wells causes a significant

reduction in oil production. On the other hand it has been acclaimed in the industry that by

using low-pressure, high-fluid-injection wells, fractures can reduce salinity of water. Thispractice is based on improved experience of the Atomic Energy Commission with the

disposal of radioactive materials by using fractured wells.

2.6 How is a Fracture Made?

The following steps are involved:

1. The initial fracture is created using the pumping pad (the fracturing

fluid) with the required dimensions. Polymer solutions and water-based

chemical are the most common type of fracturing fluids. The most

suitable fracturing fluids display non Newtonian behavior and have

reduced loss rates. The process requires a fair amount of pre-pad, and

usually half the of the Pad volume pumps leaks off to the formation.

Typically, only less than 30% is required to complete the fracking.

2. For both applications gravel pack sand and proppant are used as they

are similar in size. Once the fracture is large enough to accommodate the

proppant mix and the fracture length is at the desired length, a low

concentration of proppant mix can be used.

3. The fracturing fluid is injected to the perforations and halted when

the proppant slurry exceeds the fracture tip.

4. During the leak-off process, the viscosity of the fracturing fluid is

decreased by the addition of a chemical breaker, and this assists in the

production of the degraded pad, followed by natural gas production, as

shown in Fig 2.1 [55].


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Fig.2.1 Creation of Propped Hydraulic Fracture [55]

2.7 Formation Damage Mechanisms

For creating effective fractures, the fracturing fluid is injected to perforated zone with high

injection rate. The huge portion of this fluid enters the formations around the fractured zone

which possibly damages the formations, creates filter cake and chocking effect near the

wellbore. Fig. 2.2 describes details of this effect.


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Fig.2.2 Damage in Hydraulically Fractured Reservoir [14]

2.8 Description of fractures

Underground fractures can be distinguished as follows:

Natural fractures which created by tectonic forces

Manmade fractures caused by hydraulic fracturing at the wellbore

The effectiveness of fracturing during fracture treatment depends on fracture length,

fracture height and fracture flow capacity. [37]. It is extremely difficult to determine the

exact shape of fractures in deep reservoirs

However, by simulating reservoir conditions, all other properties of hydraulic fracturing are

studied based on laboratory tests[12].


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2.9 Initiation and Extension of Fractures

Hydraulic pressure is caused by fluid column in the well which starts from surface pumping

units. Initiation and extension of fractures is created based on the least principle stress in a

formation which has been described in Fig.2.3.Once the fracture is created, it makes flowpath to fractures and hydraulic pressure applies to the fracture face.When the fracture tip is

high enough to overcome both the rock tensile strength and the least principle stress, the

growth of fractures will continue till the end of this pressure. [37].

Fig.2.3 Initiation of vertical fracture, when stress is horizontal [37]

2.10 Fracture Orientation

Based on least principle stress in the formation the fracture settles in the perpendicular

surface to this principle. On other hand one of the main thing for determining fracture

orientation is formation heterogeneity. Additionally fractures can also lie in the parallel

plane to faults which are characterized by normal faulting [38].


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2.11 Fracture Height and Length

The fracture area is calculated by multiplying the fracture height and length.If the fracture

area is obvious the fracture length mostly depends on fracture height. In the hydraulically

fractured zone the fracture height is determined by using temperature log and SpectralGamma Log Analysis which is run from the perforated zone during fracture treatment,

before and after the completion. When the treatment is continuing the fracture area is

extended by using viscous fracturing fluid and extremely high injection rate (See Fig. 2.4)

[39]. When the fracture encounters barriers, the position of these barriers around the

fractured zone extremely prevent the fracture height.

Fig.2.4Fracture orientation a) Vertical Fracture, b) Horizontal Fracture, and c) Angular Fracture [39]

2.12 Fracture Width

One of the most useful and critical features of the hydraulic fracturing is fracture width

which is calculated by using two different models. These models are described as

following:

(1) Two dimensional

(2) Three dimensional.

Khristianovic, Geertsma and de Klerk developed new model (KGD). When the fracture

height is bigger than its length and also free slippage occurs, the rectangular figure is


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considered at the wellbore and based on this statement it is considered that the shape of

fracture is not depend on fracture position. [40], [41]. (SeeFig.2.4 a).

2.13 Fracturing Fluid

Fracturing fluids (fracturing pad) has a major effect on creating fracture in reservoir and

which relates the final result of fracturing. Van Poollen had concluded from laboratory tests

that fracturing fluid should carry several features for the effectiveness of fractures. These

features have been described as following steps [42]:

Sufficient capacity for carrying proppant material

Very little leak-off rate

Minimum friction to reduce losses during pumping the fracturing fluid.

There are several basic chemical additives used in fracturing fluid. The following order

describes these chemicals with their purpose.

Acids (Helps dissolve minerals)

Sodium Chloride (To break the gel polymer chains)

Polyacrylamide (To reduce the friction between fracturing fluid and pipe)

Ethylene Glycol (To prevent scale deposition)

Guar Gum (To thicken the water suspending sand) Citric Acid (To prevent precipitation of metal oxides)

2.14 Fracture Conductivity

When fractures are created, they accumulate oil and gas from reservoir rock and make path

for production fluid to move easily into the wellbore. In most cases the effectiveness of the

process is influenced by two critical stages:

(1) During collecting production fluid from the reservoir matrix

(2) Making a path for the fluid into the wellbore.

Overall the limitation in one of these steps is enough to reduce the productivity of the well.

The length and height of the fracture effects the productivity of the first step while the

permeability of the crack effects in the second step.


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2.15 Hydraulic Fracturing Models

Hydraulic fracturing is a very complicated process. Taleghani identified three procedures

that need to be brought together to model the process of hydraulic fracturing: first,

mechanical deformation of the formation caused by the pressure inside the fracture; second,fluid flow within the fracture networks; third, fracture propagation[11].

The very first comprehensive modeling study on hydraulic fracturing was done by Hubbert

and Willis[43].They offered results of laboratory experiments and concluded that

hydraulically induced fractures should always propagate in the direction perpendicular to

the least principal stress. Carter presented a formula for the area of a fracture that considers

the injection rate as well as the width of the fracture constant[44].

() [ ] }Equation 2.1

Where:

A is the area of the fracture face, Qiis constant injection rate, Wis constant fracture width, tis

total pumping time, and C is a constant describing the flow resistance of the fluid leakoff

from fracture into the formation.Khristianovic and Zheltov[40] first investigated the width

of hydraulically induced fractures with the assumption that the direction of plane strain

state is vertical, which means the width of the fracture does not change along the vertical

direction.

The drawback of their model is that they neglected the leakoff of fluid and the pressure

disparity inside the fracture when solving it. Then, Geertsma and de Klerk [41] improved

the model by including the fluid leakoff. The geometry of the fracture is illustrated

inFig.2.5.


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Fig.2.5 Fracture Geometry of the KGD Model[41]

Most importantly, they first suggested that the faces of the fracture close smoothly at the

edges, which implied that: where w is the width of the fracture and fLis thefracture length. They also presented a formula to calculate the fracture width at the

wellbore, where the width of the fracture is the maximum:

Equation 2.2

Where:

wwis the width at the borewell, in;

= fluid viscosity, cp;

q = rate of fluid injection, bbl/min

L = fracture length,ft;

G = shear modulus of formation,psi

H = fracture height


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Daneshy[45] extended the KGD model for the case of power-law fluids, and then Spence

and Sharp[46] included fracture toughness into the model. Another comprehensive study to

determine fracture width was done by Perkins and Kern[47]. They used the classic

Sneddon[48] elasticity plane-strain crack solution to establish the PK model. Nordgren[49]

modified the PK model to the PKN model, which included the fluid leak off from fractures

into the matrix. A schematic illustration of the PKN fracture model is shown inFig.2.6.

Fig.2.6 Fracture Geometry of the PKN Model[49]

Unlike the KGD model, which assumes the width of the fracture does not change along the

vertical direction, the PKN model made an assumption that the plane strain does not change

with the length, which means that the fracture width varies in the vertical direction and the

pressure at any point is dominated by the height of the section.

This model also assumes that an isotropic, homogeneous, elastic material surrounds the

fracture; the vertical height of the fracture is constant; the width of the fracture is the

maximum at the wellbore; and the cross-section of the fracture at the wellbore is elliptical

with semi axes h and wmax. The width of the fracture is given by


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{ ( ) || || Equation 2.3

Where:

w = fracture width, the unit of the fracture;

= bulk Poissons ratio of formation;

G = bulk shear modulus of formation;

h = fracture height;

z = Cartesian coordinate in z direction;

S = normal compressive stress on fracture plane before fracturing

p = pressure in fracture net of S

The difference between the PKN and KGD models is that they have different focuses. The

PKN model primarily studies the effect of fluid flow and pressure gradients within the

fracture, and the condition of the fracture tip is not significant. On the other hand, the

condition of the fracture tip is very important in the KGD model. Both of the models

provide a valuable insight in understanding the parameters and conditions which affect the

propagation of hydraulically induced fractures.

However, for both the PKN and KGD models, the fracture propagation is 2D: the fracture

height was assumed equal to the pay zone that has constant height. Since the 1970s, several

attempts and studies have been done to model 3D fracture propagation (e.g. Clifton and

Abou-Sayed, 1981[50]; Settari and Cleary, 1984[51]). Clifton and Abou-Sayed[50]

formulated elasticity equations by using a method which is similar to the finite-element

method. The difference between this method and the finite-element method is the treatment

of the physical problem which was formulated by integral equations instead of differential

equations.


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However, the computation is very costly and extremely time consuming. In addition, the

model needs to be improved to deal with the advancing crack and non-Newtonian fluids.

Thiercelin et al.[52]extended their work by analyzing the effect of interfaces in the

formation, allowing the simulation of out-of-plane growth in the vertical direction, and

using the boundary integral method for the displacement field. The drawback of this model

is that it could not incorporate non-planar fractures.

Even though the hydraulic fracturing models are becoming comprehensive and efficient,

they are not sufficient to deal with unconventional gas reservoirs, such as shale gas and

tight gas, which exhibit significant heterogeneity. Another important factor that needs to be

considered is the preexisting natural fractures. Therefore, studies, which incorporate the

characteristics of unconventional gas reservoirs, have been conducted by several

researchers. The next section reviews the literature for hydraulic fracturing in naturally

fractured formations.

2.16 Hydraulic Fracturing in Naturally Fractured Reservoirs

Unconventional gas reservoirs, such as shale gas and tight gas reservoirs possess

tremendous reserves all over the world. However, they are very difficult to produce

commercially due to their extremely tight formation and it increases the importance of

natural fractures to unconventional gas reservoirs[59]. Some of natural fractures are closedor sealed with minerals; all the cores recovered from the Barnett shale contain cemented

natural fractures[60].

But they cannot be neglected since they can act as weak paths for fracture growth.

Hydraulic fracturing is necessary to naturally fractured formations to make commercial

production possible because it may connect and open the natural fractures. However, the

presence of preexisting natural fractures is not always favorable. For example, in naturally

fractured reservoirs, the leakoff rate is commonly high during the process of hydraulicfracturing: some reports indicate that fluid leakoff could be as high as five times larger than

the fluid leakoff in unfractured reservoirs[11].

Field observations indicate that leakoff in naturally fractured reservoirs primarily depends

on net treatment pressure and fracture fluid parameters[61], [62]. A typical approach to


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control high leakoff rate in fractured reservoirs has been to pump large volume of pad, but

the washout process has not been very successful[11]. Many experiments have been done to

evaluate the effect of interaction between hydraulic fractures and natural fractures.

Since this dissertation mainly focuses on the numerical models, experimental studies arenot specifically listed for each study. In one of the first studies in this area, Lamont and

Jessen[63] investigated the effect of rock heterogeneity, especially preexisting natural

fractures, through triaxial laboratory experiments for six different types of rocks.

They concluded that if the aperture of a natural fracture is small, crossing will dominate,

while the possibility of dilation increases if the aperture is large. They also concluded that

both the strength of preexisting fractures and different stress regimes play important roles

in affecting fracture geometry. Besides the experimental research, a lot of studies have beendone on modeling hydraulic fracturing in naturally fractured formations. Lam and Cleary

[64] modeled the effects of bedding planes or frictional interfaces on hydraulic fracture

growth. They approached the solution by using the displacement discontinuity method with

the assumption of a plane-strain condition and the assumption of constant fluid pressure

inside the fracture. The method has been adopted as a boundary-element method. Zhang et

al.[65]improved the model by incorporating fluid flow into it. Jeffrey et al.[66]used the

same method to develop a 2D method to model the slippage along the natural fractures by

using the Mohr-Coulomb failure criterion.

They concluded that higher treatment pressures are needed to accommodate the interaction

between the hydraulic fracture and natural fractures. De Park and Beugelsdijk[67] and

Akulich and Zvyagin[68] also completed similar research. Taleghani[11] and Taleghani

and Olson [69] used an extended finite element method (XFEM) to simulate the fracture

propagation and the coupling process in their 2D model. The criterion for interaction

between the hydraulic fracture and the natural fractures was the critical energy release rate

ratio. The effect of natural fractures on the propagation of a hydraulically induced fracture

is demonstrated byFig.2.7.


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Fig.2.7 Interaction between the Hydraulic Fracture and Natural Fractures [69]

is the approach angle, 1& 3denote maximum and minimum horizontal principal

stresses.


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Chapter 3 Fracture diagnostic techniques

3.1 Basic Concepts and Introduction about the techniques

One of the main keys to economic success in the oil and gas industry is to get more

advanced hydraulic fracturing treatment of oil and gas fields. Nowadays there has been

several technological advancement in the field of fracture diagnostics. To determining

fracking penetration is very sensitive and difficult with as it is a process which happens

thousands of feet below the surface. Because of the complexity of the earth the fracturing

process is not so clear. It is impossible to change the geological complexity of the Earth

that is why the diagnostic characteristics of the fracture determining methods need to be

improved continuously.

The fracture diagnostic techniques should cover several important questions in the

evaluation process of hydraulically fractured zone which have been described as following

order: [70],

Do fractures cover the pay zone?

What is the optimum treatment size? What is the optimum proppant?

What is the fracture azimuth & dip?

What direction the horizontal well should be drilled?

What is the optimum well placement?[70]

During measuring the hydraulic fracturing process, it is very important to carrying out an

advanced treatment for protecting the groundwater and preventing any environmental risk.

While certain monitoring parameters are observed, others are derived from observed

parameters. These certain parameters should be continuously monitored.


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These would contain: Psurface injection pressure (psi)

Vsslurry rate (bpm)

Cproppant concentration (ppa)

Vffluid rate (bpm)

Vpsand or proppant rate (lb/min) [71]

All fracture diagnostic techniques cannot cover the important issues of hydraulic fractured

zones. They have their own capabilities that have been shown in the Table 1.


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Table 1 Capabilities of Fracture Diagnostics.Adopted from [70],[72]

Group Techniques Length Height Width Azimuth Dip Volume Conductivity Assymetry

Direct, Far

Field

Surface tilt fracture mapping

DH Offset Tilt mapping

Microseismic fracture mapping

Direct

Near

Wellbore

Radioactive tracers

Temperature logging

HIT

Production logging

Borehole image logging

Downhole video

Caliper logging

Indirect

Net pressure fracture analysis

Well testing

Production analysis

- Determine

- May determine

- Cannotdetermine


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3.2 The description of common technologies for monitoring fracking

penetration

Group 1 - Direct far field

This group includes mainly two types of fracture diagnostic techniques: tiltmeter fracture

(surface tilt fracture mapping, downhole offset tilt mapping, treatment well tiltmeters) and

microseismic fracture mapping. These techniques are carried out from the surface or from

an offset wellbore. A main limitation of these techniques is that they are not able to get

information about fracture conductivity and width.

Surface tilt fracture mapping

Surface tiltmeter fracture mapping is one of the unique fracture diagnostic technique in oil

and gas industry.It is utilized on more than 2,000 fracture per year and it has been operated

to the depth of nearly 6000 ft.

Surfacetiltmeteris carried out with very simple principles(See Fig. 3.1)the tilt

measurement is done at many points inthe hydraulically fractured zone.It requires

extremely sensitive measurements and is arranged in narrow holes at radial distance starts

nearly from a hundred feet to approximately one mile around the fractured zone.The

surface tiltmeters is too far fromt he fractured zone that is why they are not able to define

fracture height and length.

The arrays of surface tiltmeter measure the fractured zone by creating the map above this

zone. Afterwards by solving the geophysical reverse ,it is possible to get information about

the fractured zone. The fracture orientation can be obtained by using extremely accurate

carpenter levels [70]. The tools for tiltmeter operations are cylindrical metal (diameter =

2in. length = 36 in.) [73].

The main limitations of surface tiltmeter are:

The limitation of depth is nearly 6,000 ft

The Dependence of mapping resolution from the depth (the digression of

fracture azimuth is 1in each 1000 ft)

The lack of information about fracture length and height

The requirement of large surface area [74]


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DH (downhole) Offset Tilt mapping

Comparing the DH offset tilt mapping with surface tilt mapping, they are both based on

same tiltmeter fracture mapping principles (See Fig. 3.1). The main difference between

these two tilt mapping is that DH offset tilt mapping is located at the depth of hydraulicallyfractured zone by wireline [70]. This technique presents the clear diagram of the field

deformation which is close to the hydraulic fracture. Downhole tiltmeters can be located

very close to hydraulically fractured zone. As a result, it can define fracture length, width

and height depending on time [75].

In most scenarios downhole and surface tilt mapping are used separately or in combination

to cover each other and to get more advanced information about fracture induced zone.

The main limitations of this technique are:

The disability to detail the information about fracture growthBig picture.

There is no information about proppant dispensation.

The uncertainty of the fracture mapping ( 35 ft for fracture length and 25 ft for

fracture height). [76].

Fig. 3.1 Tiltmeter fracture mapping [76]


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The lack of information about the location of proppant.

The difficult and uncertain application in treatment wells.

The requirement for intensive analysis [74]

Group 2 - Direct near-wellbore

In this chapter we are only looking at basic methods of direct near-wellbore techniques.

Radioactive tracers will be discussed detailed in the next chapter. Direct near-wellbore

fracture diagnostic techniques basically are run inside the treatment wellbore by taking into

consideration the physical properties such as conductivity or temperature near wellbore

region. In this aspect the main limitation of these techniques is that they do not provide

exact information about the fracture which is further than 1-2 feet from wellbore. [75].

Temperature logging

Temperature logging is one of the more suitable techniques which have been used for many

years for determining the fracture height at the wellbore. Mainly this technique is based on

the field and laboratory measurements of thermal conductivity. The simple procedure is

carried by measuring the cooling because of fluid injection during incentive treatment by

looking at the comparison of temperature profile of pre-fracture and after 1 to 24 hours of

treatment. [70].

DTS (Distributed Temperature Sensing) is the latest technology for real time fracture

determining diagnostics. The process is based on simple heat transferring rules (See Fig.

3.3).In this technique fibre-optic cable is positioned in the wellbore across the perforated

zone.

The temperature logging fracture diagnostic technique is limited in shallow depth of

investigation and can it can only determine the height of the fractured zone near wellbore.


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Fig. 3.3The basic thermal processes are observed during fracture treatment [77].

Production logging

When the layers of reservoir are separated by non-producing intervals, the production

logging is run if all intervals are perforated (See Fig. 3.4). The first time when

Schlumberger brothers ran their first electric line, they introduced the production logging

technique to the industry. [72].

Fig. 3.4 The production logging tool and principle [78]

Fluid entry zones to wellbore are identified by noise log to determine the sound of this

fluid. The production logging diagnostic technique can be used only in an open hole. This


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Fig. 3.5TheCaliper logging tool [81]

Group 3Indirect

Indirect methods for fracture diagnosis make use of established techniques like well testing

and production analysis to get some information about the fracture. They can be easily run

using wireline tools and then the acquired data can be processed and interpreted.

Well testing and production logging both monitor the pressure and flow rate as a function

of time and use the information obtain to characterise the fracture.

There are three fracture diagnostics (net pressure fracture analysis, well testing and

production analysis) included to the third Group of fracture diagnostic methods. Recently

indirect methods have been one of the widely used techniques because the information for

these operations is ready to process and they can estimate the fracture conductivity, heightand length by taking into account the assumption on indirect measurement such as pressure

and flow rate during production [70].

The disadvantage of these techniques is that they do not produce exact information about

fracture dimensions and it needs to be calibrated with direct observations.


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Chapter 4 Tracers for determining fracking penetration

4.1 Tracers in the Oil industry

As their name indicates tracers are substances which leave a trace or a signal behind and

can be tracked using different methods. These tracers could be radioactive isotopes,

chemical substances or even biological molecules or proteins. Their detection method

depends on the type of tracer used and could either be an in-situ diagnosis or a surface

analysis of the produced/ back- flow fluid. These tracers can be water based, gas based or

oil based although the first two are the ones most commonly used for several applications,

like

Inter well connectivity

SWAG or WAG EOR monitoring

Single well residual oil saturation determination

Cementing job integrity analysis

Multiple zone completion/ sub-sea wells performance analysis

Fracture profiling

4.1.1 Inter-well Connectivity

In a heterogeneous reservoir, for the purpose of reservoir monitoring, it is very important to

know the connectivity of the reservoir between wells. For example, when designing a water

injection/ chemical injection scheme targeted at sweeping the oil by using water/chemicals

from the injector to the producer, it is absolutely essential to know whether the wells are in

hydraulic communication or not. By introducing water soluble chemical/radioactive tracers

in the injection well, and by sampling the produced fluid at the producer well, the

connectivity between the wells can be easily tested. If the tracer shows up in the production

well(s) fluid, then it means that the injector-producer pair is in communication. Also, if we

have a 5-spot or 9-spot injection pattern, then by comparing the concentration of the tracer

in the produced fluids, it can be guessed that which wells receive more of the injection fluid

and are better swept. This can also give a qualitative estimate of the inter-well directional

permeability.


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The presence of a thief zone/high permeability channel can also be detected if the tracer

shows up really early in the produced fluid at the monitoring wells [82].

Fig. 4.1: Inter well connectivity determination using tracers [89]

4.1.2 SWAG or WAG injection EOR monitoring

SWAG (Simultaneous Water and Gas) injection or WAG (Water Alternating Gas) injection

are EOR (Enhanced Oil Recovery) techniques that are used for tertiary recovery of

bypassed oil. The SWAG injection has been successfully used in Siri Field, Denmark and

in the Mumbai High Field, India [83]. While WAG injection has been used in North Sea

fields to recover attic oil [84]. Both these techniques involve injection of water and gas into

the reservoir either simultaneously, or alternately. The effectiveness of these projects can be

monitored by using tracers in both the injected water and the injected gas using suitable

tracers for each phase. They are usually Tritium for the water, and Sulphur hexafluoride

(SF6) for the gas. The produced fluid at the monitor well(s) has to be analysed for any trace

of these tracers once the EOR injection has been started. In case of a higher


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SF6concentration recorded at the monitor well, it means that gas is breaking through in

the reservoir. If there is a higher concentration of Tritium, it means that there is a high

permeability thief zone wherewater is bypassing the oil [84].

4.1.3 Single Well Residual oil saturation determination

The Single Well Tracer Test (SWTT) was developed in 1968 by Exxon to determine the

residual oil saturation in well using tracers. The information of residual oil saturation (Sor)

is really important for the financial success of any petroleum project. Typical methods for

determining Sorare wireline logs and core plugs. The limitation of both of these methods is

that the sample size is very small and average values are not representative of the entire

reservoir.

The Single Well Tracer Test is an in-situ method for determining the residual oil saturation.

It uses ester-based (usually ethyl acetate) [85] tracers that are injected into a well that is at

residual oil saturation after a waterflood. The ester based tracers flood is followed by a

tracer free water bank and then the well is shut in for a few days to allow partial hydrolysis

of the ester. The hydrolysis of ester produces ethanol, which is a secondary ester. While,

ester distributes itself in both the oil and the water; the ethanol has an almost exclusive

preference for water. Therefore, when the well is opened for production/flowback ethanol

has a higher velocity than the ethyl acetate which is partitioned in both faces. By

monitoring the arrival time of both ethanol and ethyl acetate, estimates can be made of the

residual oil saturation. The greater the difference in arrival time, the greater is the residual

oil saturation. By using chromatography, the concentrations of the tracers can be quantified.


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Fig. 4.2 : Schematic of the SWTT procedure [90]

Fig.4.3: Analysis of tracers using chromatography and simulation [90]


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4.1.4 Cement job integrity

A cement job is considered to be successful if it isolates undesired zones. If it fails, then

there will not be proper sealing between the casing and the borehole, and fluids can leakthrough the casing to the surface. Radioactive tracers are used to check the effectiveness of

a cement job. A radioactive tracer is added to the cementing mud before it is pumped

downhole. After the cement job is completed, a logging tool is lowered to record the

radioactivity. The top part of the cemented interval can be identified as the point where the

radioactivity deceases to the level of the background radioactivity of the formation rocks.

Fig.4.4:Determination of the top of cement section [86]

4.1.5 Multiple zone completion/ Sub-sea well performance analysis

The productivity index of the well determines the performance of a well. When the

productivity index of the well goes down, it is due to problems in the reservoir, in the

completion or the surface conditions or a combination of all these . For a well completed in

a single layer, it is quite difficult to pin point the source of decrease in productivity, so for a

well completed in a commingled manner in multiple layers is much more difficult to

analyse which zones are facing problems. A production log could be run for such a


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scenario. Alternatively, tracers present a solution to this problem. By injecting a unique

tracer in each of these layers, the reservoir fluid would be laced by a unique tracer which

can be identified at the surface. With the commingled completion, the oil/water produced

from all the layers will get mixed up. However by knowing which tracer was injected into

which layer and by determining its concentration in the production stream, the contribution

of each layer to the total flow can be calculated. Hence, the productivity of each layer in a

commingled system can be calculated [86].

In case of sub-sea completions, the production from the different sub-sea wells is tied

through a manifold into a common production line and then separated at a platform/FPSO.

In this case also, it would be difficult to analyse the productivity of individual wells. For

sub- sea wells, production logging would also be technically and economically unfeasible

in most scenarios [86]. Hence, by injecting unique tracers to the different wells connected

to a common production line their productivity indices can be determined.

Fig.4.5 : Schematic of sub-sea wells tied to a FPSO [91]

4.1.6 Tracers for fracture profiling

When hydraulic fractures are created, whether in a conventional or unconventional

reservoir, it is important to know the location and depth of these fractures. This can be

achieved by using tracers, both radioactive and chemical.

In case of radioactive tracers, the proppants, that are used to keep the fractures open, are

coated with a radioactive material. Typically these tracers are gamma ray emitters. A

gamma ray base line log is run before the fracking job, and another log is run after the


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fracking. A comparison of these two logs will show an increase in the radioactivity

corresponding to the placement of the tracer coated proppants. Hence, a fracture profile can

be created. The radioactivity increases (an increase in the Gamma ray log), due to the tool

detecting the presence of the radioactive isotopes which are embedded or coated on the

proppant. Since the log is always measured versus the depth, an increase in gamma ray

would mean that at that particular depth, proppant containing fractures are present.

The increase in gamma ray is proportional to the concentration of the isotope (in the

proppant). A longer/deeper fracture would have more proppants in place to keep the

fractures open (assuming successful proppant placement). Hence a deeper penentrating

fracture would show a bigger spike in the gamma ray compared to a shallow fracture.


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Fig.4.6 : Comparison of the gamma ray log, pre and post fracking[92]

The above figure shows significant radioactivity in the zone between X450 and X530,

indicating that this zone has been successfully fractured. X490 has the deepest fracture

because of the maximum increase in gamma ray response.

Chemical tracers can also be used to understand fracture profiles.

Appropriate fracking fluid and proppant placement is the key for the success of any

fracking job. Fracking fluids have three main roles. First, to create fractures; second to

place proppants into these fractures and third to flowback to the surface. The productivity

of any well, after proppant introduction, depends on how efficiently the fracking fluids

have flown back to the surface. Chemical Tracers can be used to assess and monitor the

flow back of these fracking fluids.

The fracking fluid is tagged with these tracers when it is being pumped into the formation

to create fractures. In case of different zones, unique chemical tracers can be injected into

the different zones. This can also be used to test vertical communication between different

zones, apart from flow back efficiency. Then during the clean- up of the well, the flowback

fluid is sampled and analysed for the presence of these tracers. The detection techniques

have been discussed in detail in section 4.4 of this chapter.

Using mass balance technique, the flow back for each fracking fluid stage is calculated.

Hence, the flow back efficiency for each stage/ zone can be calculated and also for the

overall well. The mass balance technique is a basic scientific concept of mass conservation

used in many sciences and engineering applications. When a particular chemical tracer is

used in a particular quantity (mass), we are interested in keeping track of its mass right

from injection to flow back to understand its distribution in various stages of fracking.

Suppose an initial mass X of the chemical tracer was used and injected along with the

fracking fluid. Then by monitoring the concentration (using the techniques described in

section 4.4) of tracer in the flow back fluid at different fracking stages , the flow back


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Fig 4.7: Chemical Tracer response of Fry 18-4 well [87]

Fig 4.8 :Flowback efficiency of Fry 18-4 well [87]

By monitoring the concentration of these tracers over time and using mass balance

technique , clean up efficiency, obstacles to flow and contribution of different zones can be

understood [87].

4.2 Types of Tracers

The two main types of tracers that are used in the industry are the radioactive tracers and

the chemical tracers. These can be subdivided into water based, oil based or gas based

tracers. Recent developments and environmental concerns have led to bio-tracers as well

but these are not so widely used as the chemical and radioactive tracers.

Radioactive tracers can be detected in situ using logging tools while the chemical tracers

are detected by sampling the produced fluid at the surface and analyzing it by using

different analytical chemistry techniques.


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4.2.1 Radioactive Tracers

The easiest way to detect these tracers are by tagging proppants, gravel pack, cement slurry,

injection fluid (depending on the objective) with a radioactive isotope.

Some of the most commonly used radioactive tracers are Antimony-124, Bromine-82,Iodine-125, Iodine-131, Iridium-192, Argon-41, Xenon-133 and Scandium-46. These are

gamma ray emitters, which are easily identified and measured, compared to alpha and beta

ray emitters [86].

The gamma ray signal of each of these isotopes is unique which can easily identify them.

This requires a logging tool which records the radioactivity of these tracers and hence the

location and depth of these can be accurately mapped.

These isotopes have different half-lives and therefore depending on the requirement of the

job, a suitable tracer can be picked. Iridium, Scandium and Antimony have half-life of a

few days, while for projects that require long term monitoring, Cobalt and Cesium can be

used which have a half-life of a few years[86].

4.2.2 Chemical Tracers

In recent years, the oil industry has started using chemical tracers in place of radioactive

tracers for a lot of applications. One advantage is that these tracers do not have the same

rigorous accountability and environmental regulations that disposal of radioactive tracers

require. Another advantage is that they do not have to be monitored in situ unlike the

radioactive tracers, so it is more economical as logging is not required. Analysis of

produced fluid is required for the monitoring of the tracer.

These chemical tracers can be water based, oil based or gas based depending on the

application. Some of the commonly used water based chemical tracers are [87]

Ammonium Thiocyanate

Fluoro-boric Acid

Potassium Cobalto- cyanide


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Sodium Chloride (natural tracer)

Ammonium Nitrate

Ammonium Bromide

Potassium Iodide

Alcohols & Esters

Poly fluorinated aromatic carboxylic acids

Sodium Chloride, Fluoro-boric acid and Barium and Strontium are the most commonly

used water based tracers used for monitoring fracking penetration [ 93][94]. They have

been successfully used and monitored in the Marcellus Shale Gas Field [93]. Among thegas based tracers ,perfluoro carbons have been used along with fracking fluids for fracking

penetration estimates in the Greene County site in Pennsylvania [95].

And some Gas tracers which have been described in Table 3

Table 3. The advantages/constraints of some Gas tracers [88]

Gas Tracers Constraints

Sulphur Hexafluoride (SF6) Can be measured in GC using ECD.

Halo-fluoro compounds (freons) Earlier in use, now coming under increasing

regulatory pressure.

Argon Low cost tracer, can be used in reservoirs where

natural concentration of argon is low enough.

Carbon mono-oxide (CO) Can be tagged with carbon-14 to have more

sensitivity.


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Nitrous oxide (N2O) Can be measured chromatographically using ECD.

Perfluoro Methane (CF4)and

Perfluoro Ethane (C2F6)

Their current limit of detection is about 0.1ppm, No

ultra-sensitive method developed to analyze them

Cyclic Perfluoro compounds

Sampling and analytical procedure are specific.

Having relatively large molecules with substantial

partition into oil phase, hence significant lag of tracer

relative to the gas front.

4.3 Activation/Release of Tracers:

Some applications may require the tracer to be active in the reservoir from the moment that

it is injected (for example: inter well connectivity test, or a single well tracer test), while

some applications may require the tracer to be activated by a particular fluid or event.

Depending on the application, a suitable technique can be employed to activate or protect

the tracer.

For example, in case of a radioactive tracer used with the proppant for fracturing, the tracer

should not be washed away during the flowback period. ProTechnics Zerowash commercial

radioactive tracer has the isotope embedded within a proppant made of ceramic material

which is resistant to flow back periods. The proppant and the embedded tracer are injected

with the fracking fluid. After the fracking job is over and the flow back fluids have been

produced at the surface, the tracer will still be present in the formation with the proppant.

When a gamma ray log is recorded, the tracer can be detected and the fracture profile

understood.

When Chemical tracers are used for fracking applications, they usually need to be activated

by some event like the presence of formation water or oil. They are injected into the

formation along with the fracking fluid.

In case of chemical tracers that need to be activated by some event, like water

breakthrough, the tracer can be encapsulated in a plastic polymer like material. The

polymer resists erosion to high flow rates and remains in passive position, till it is triggered


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by even 1 % water cut . The water disintegrated the polymer, and releases the tracer which

can then be monitored[83]. Likewise, polymers can be designed to be disintegrated by oil

break through. For example, in a flow back scenario, the tracer will be immune to the flow

back fluid, but will only be activated once oil starts to flow. Often, oil activated and water

activated tracers are used together [87].

Norways RESMAN and UKs Tracerco company are leaders in these oil and water

actuated tracers and claim that these tracers can be detected at levels of parts per trillion

[87].

4.4 Detection of Tracers

Tracers can be detected in situor at the surface. The radioactive tracers (usually gamma ray

emitters) are detected by lowering a gamma ray logging tool in the formation. The increase

in the radioactivity due to the tracer isotopes accounts for their detection. The chemical

tracers are detected by the analysis of the produced fluid at the surface. By using mass

balance technique, the flow back efficiency of each flow back stage can be calculated.

The main principle behind the detection of the chemical tracers is based on gas and liquid

chromatographic separation. The laboratory techniques that are used to identify the tracers

are [87]:

Gas ChromatographyMass Spectroscopy (GCMS)

Gas Chromatography with different detectors like ECD (Electron Capture Detector),

FID (Flame Ionization Detector), ELCD (Electrolytic Conductivity Detector) ,

PFPD (Pulsed Flame Photometric Detector)

High Performance Liquid Chromatography (HPLC) with different detectors like UV

(Ultra-violet), Fluorescence, Electrochemical

Automatic Thermal Detector (ATD)


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The water tracers are monitored using HPLC or after separation of the volatile

components using GC-MS, while the gas tracers are detected using GC and ATD

techniques.

4.5 Advantages and Disadvantages of tracers

The tracers are very useful in analyzing stimulation or a hydraulic fracturing job. Their

main advantage lies in accurate determination of the proppant placement compared to other

techniques. This is because

Tracers can be accurately detected even at very low concentrations

They can be analysed both in situand at surface. This gives flexibility to the

fracking schedule

There are a lot of different types of tracers that can be used to monitor different

zones uniquely

Their release / actuation can be controlled and altered to suit the requirement of the

job

There are also some drawbacks related to the use of tracers. The main ones are listed below.

Radioactive and chemical tracers both present the health hazard when handling on

site

They could find their way into the aquifer and contaminate the drinking water table

Disposal of the produced fluid presents an environmental problem because of the

presence of these chemical and radioactive tracers Some of the radioactive tracers have a short half-life. So in case of a stuck-up or

other technical constraints, their detection might be difficult and the job may have

to be repeated


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Chapter 5 Alternative Tracers and Conclusions

5.1 Alternative Tracers

Tracers present a very powerful tool to the oil and gas industry in reducing uncertainty in a

lot of critical areas like reservoir description, residual oil determination, stimulation job

monitoring and of course fracking in Shale gas. The high stakes and economic risks of any

petroleum project make reducing uncertainty an absolute must. Tracers are one of the key

uncertainty reducers.

The need for the industry is to address these concerns by coming up with suitablealternatives to these tracers that fit the environmentally friendly description. In recent

years, there have been some developments in this direction and below are presented two of

alternative tracer techniques.

5.2 Naturally occurring radioactive tracers:

There are several isotopes of oxygen, hydrogen, strontium, boron and radium that exist in

formation water found in the subsurface rocks. When fresh or saline water used for

preparing the fracking fluids, mixes with the formation water containing these isotopes,

they are diluted, or their concentration changes. Hence, their radioactivity signal

diminishes. Monitoring the change of this signal can give an estimate of the fracture profile

. Thermal ionization mass spectrometry can be used to analyze the radioactivity of the

produced/flowback water.

The combined application of geochemistry, stable isotopes (18

O,2H), strontium isotopes

(87

Sr/86

Sr), boron isotopes (11

B), and radium isotopes (228

Ra/226

Ra) provides a unique

methodology for tracing and monitoring shale gas and fracking fluids in the environment[86] [88].

5.2.1 Bio Tracers and Nano Rust

But perhaps the best alternative would be a bio-tracer which is most environmentally

friendly. BaseTrace company claims to have developed a synthetic DNA based tracer that


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can be used in fracking fluids. It is neither radioactive nor requires a huge amount

(measured by industrial drums) of chemicals to be injected into the rocks.

The amount of BaseTrace tracer needed per frack site is equivalent to a teaspoon, diluted

in several million gallons of water used to frack the gas well. The tracer is detectable in

water at the level of a few parts per quadrillion by means of polymerase chain reaction

analysis, a method of magnifying strands of DNA.

This tracer has no effect on people or animals. It is being subjected to stability tests at

reservoir temperature, pressure and salinity conditions to confirm its use in real field

operations.

Recently Andrew Barron from the Rice University in Texas has come up with an iron-oxide

based tracer that he calls nano rust. This tracer can be injected along with the fracking

fluid. Its detection is based on the principle of magnetism and samples collected from

ground water sources can confirm if they have been contaminated by the fracking

operations [96].

5.2.2 Conclusions and Recommendation

It is quite obvious that tracers are a very important tool in the oil industry to reduce

uncertainty about a lot of critical technical parameters which have a huge impact on the

economic success of any project. The connectivity of a Reservoir, communication between

different producing zones, contribution of different zones, presence of high permeability

channels ; all these questions can and have been successfully answered by using tracers.

In case of hydraulic fracturing also, tracers play a vital role in understanding the fracture

penetration depth and its profile. They have been successfully deployed to evaluate the

efficiency and increased productivity of wells due to fracking. Used along with the other

diagnostic techniques for fracture detection, tracers can help in accurate profiling of a

fracture.

The issue with using tracers is that they might have hazardous impact on humans and the

environment. It could penetrate the underground aquifers that are in vicinity of the


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formation or at the surface, the radioactive tracer laced fracking fluid is disposed in

wastewater ponds, and radiation could find its way into water used for human consumption.

This leads or requires the industry to look at alternative tracers for fracking jobs that are

environmentally friendly. Most of these tracers have a different half-life depending onwhich stage of fracking they are used for. Even with a very short half-life of a few days,

they will still leave behind a concentration which is significantly hazardous.

With increased and stricter environmental regulations and monitoring on the Oil and Gas

industry, the need is to judiciously use the available and alternative tracers based on a

techno-economic-environmental screening criteria. The decision to use tracers may not be

up to the drillers or the fracking companies anymore. Only tracers that are considered and

proven to be environmentally non-hazardous would pass the test.

The Bio-tracers seem to be the best alternative to the radioactive and chemical tracers that

are currently in use. They are used in very small concentrations and are environmental

friendly. Their detection is also done using conventional analytical techniques in very small

traces. After a few field trials, it would be clear that these bio-tracers can replace the

conventional chemical and radioactive tracers. This would be a major step and would lead

the industry to further research in these bio tracers.

It is recommended that as future work, the stability and efficiency of these bio tracers is

studied under different conditions that are found in reservoirs worldwide. For example

variations in salinity, temperature, pressure, presence of certain ions, clays etc. are the

distinguishing characteristics of reservoirs. If these tracers continue to be functional in

these different conditions then it would be a major step for the industry, the environmental

bodies and the government because fracking is one of the biggest tools for acquiring energy

independence for most countries in the foreseeable future.


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