Winter internship at ONGC well stimulation

WINTER INTERNSHIP REPORT 2018-19
SUBMITTED TO – WELL STIMULATION SERVICES, ONGC
SUBMITTED BY – SPT16 GROUP, PDPU

“Winter Internship 2018-19, Well Stimulation Services – ONGC”
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Table of Contents
1. Acknowledgement ...................................................................................................................................... 4
2. Introduction ................................................................................................................................................ 5
3. About Well Stimulation Services – ONGC.................................................................................................... 7
4. Chemistry Lab Section:................................................................................................................................ 9
4.1 Acidization ........................................................................................................................................... 9
4.2 Hydraulic Fracturing:.......................................................................................................................... 10
4.3 Hot oil Circulation: ............................................................................................................................. 10
4.4 Gravel Packing:................................................................................................................................... 10
4.5 Coiled Tubing Unit: ............................................................................................................................ 11
4.6 Liquid Nitrogen Pumping: .................................................................................................................. 11
4.7 Test Performed for Selection of Propants:......................................................................................... 12
4.7.1 Propant Sieving Test: ................................................................................................................. 12
4.7.2 Proppant density Test:............................................................................................................... 12
4.7.3 Crushing Test: ............................................................................................................................ 12
4.7.4 Solubility Test:............................................................................................................................ 13
4.7.5 Sphericity & Roundness test: ..................................................................................................... 13
4.7.6 Turbidity Test:............................................................................................................................ 14
4.7.7 Process for Making Fracturing Fluid:.......................................................................................... 14
5. Coiled Tubing Unit..................................................................................................................................... 15
5.1 COMPONENTS OF CTU....................................................................................................................... 15
5.1.1 Coil Tubing: ................................................................................................................................ 15
5.1.2 Tubing Reel: ............................................................................................................................... 15
5.1.3 Injector:...................................................................................................................................... 15
5.1.4 Stuffing Box:............................................................................................................................... 16
5.1.5 Blow Out Preventer (BOP): ........................................................................................................ 16
5.1.6 Control Console, the power pack & crane: ................................................................................ 16
5.2 General Process ................................................................................................................................. 17
5.3 Application of CTU ............................................................................................................................. 18
5.3.1 Circulation:................................................................................................................................. 18
5.3.2 Nitrogen Pumping:..................................................................................................................... 18
5.3.3 Coil Tubing Drilling:.................................................................................................................... 19
5.3.4 Production: ................................................................................................................................ 19
5.3.5 Sand Washing with Foam:.......................................................................................................... 19
5.3.6 Sand washing with nitrified water:............................................................................................. 20
6. Matrix Acidization ..................................................................................................................................... 21

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6.1 Common involved Acids:.................................................................................................................... 21
6.2 Additives used:................................................................................................................................... 21
6.3 Identification of candidate well ......................................................................................................... 22
6.4 Performing Acidization:...................................................................................................................... 22
6.4.1 Pre Flush: ................................................................................................................................... 23
6.4.2 Main Flush:................................................................................................................................. 23
6.4.3 Post Flush:.................................................................................................................................. 23
6.5 Visited (Mehsana field-Shobhasan): .................................................................................................. 24
7. Nitrogen Activation ................................................................................................................................... 25
7.1 Nitrogen Properties: .......................................................................................................................... 25
7.2 Nitrogen Advantages: ........................................................................................................................ 25
7.3 Equipment Involved:.......................................................................................................................... 25
7.4 Procedure: ......................................................................................................................................... 25
7.5 Precautions:....................................................................................................................................... 26
8. Hot Oil Circulation (HOC): ......................................................................................................................... 27
8.1 Why HOC?.......................................................................................................................................... 27
 What is HOC?..................................................................................................................................... 28
8.3 Solvent job additives:......................................................................................................................... 29
8.4 Equipments/Units Involved................................................................................................................ 29
8.5 Operation........................................................................................................................................... 29
9. Hydraulic Fracturing.................................................................................................................................. 31
9.1 Objective of hydraulic fracturing ....................................................................................................... 31
9.2 Fracture creation and its physics ....................................................................................................... 32
9.3 Equipment Used: ............................................................................................................................... 32
9.4 Process of HF ..................................................................................................................................... 33
9.4.1 Acid stage................................................................................................................................... 33
9.4.2 Minifrac Test.............................................................................................................................. 33
9.4.3 Pad stage.................................................................................................................................... 34
9.4.4 Main flush .................................................................................................................................. 34
9.4.5 Post flush, Flow back and cleaning with N2................................................................................ 34
9.5 Data acquisition and Integrated fracture model................................................................................ 34
10. Conclusion.............................................................................................................................................. 35

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Group Members
Sr. No. Name
1 Yogendra Pawar
2 Umaretiya Samip
3 Mohit B Patel
4 Chirag Vanecha
5 Gajipara Riten
6 Mungalpara Mayur
7 Ronak Pandya
8 Lijo P Lalu
9 Jigar Patel
10 Bhagyesh Kansara
11 Nehal Patel
12 Anjan Chhatrala
13 Ravinav Lal
14 Kajavadra Vishrut
15 Anvesh Rao
16 Manna Butani
17 Mukund Sharma
18 Naitik Jain

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1. Acknowledgement
The internship opportunity we had with Oil and Natural Gas Corporation Ltd. (ONGC), Well Stimulation
Services (WSS), Ahmedabad asset was a great chance for learning and professional development.
Therefore, we consider ourselves as very lucky individuals as we were provided with an opportunity
to be a part of it.
It is our radiant sentiment to place on record our best regards, deepest sense of gratitude to Mr. S.K.
Singh, Mr. Asish Thaplyal, Rajesh Sir, S.K. Srivastava Sir, Mr. N.B. Rathod, Mr. M.M. Mecwan,
Mr. Pradyuman Singh Bisht, Mr. Bhanu Prakash, Ms Sneha and Mr Nilesh Chikania for their careful and
precious guidance which were extremely valuable for our study, both theoretically and practically. We
would specially like to thank Mr. B.M. Parmar, Mr. Kaushal Agrawal for allowing us to do our project
work at WSS. We would like to take the opportunity and thank the management and staffs of ONGC
for their valuable support provided by them in the respective fields that helped us in completing the
project.
At last, we are extremely thankful to Dr. Anirbid Sircar, Director, School of Petroleum Technology,
Pandit Deendayal Petroleum University (PDPU) to provide us this extensive opportunity at ONGC WSS.
We are also grateful to Mr. Vineet Bagaria, Training and Placement officer, PDPU to help consistently
before joining the internship.
We consider this opportunity as a big milestone in our career development. We will strive to use the
gained skills and knowledge in best possible way. We will continue to work on their improvement, in
order to attain desired career objectives. Hope to continue cooperation with all of you in the future.

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2. Introduction
ONGC is the largest crude oil and natural gas Company in India, contributing around 70 per cent to Indian
domestic production. Crude oil is the raw material used by downstream companies like IOC, BPCL, and
HPCL to produce petroleum products like Petrol, Diesel, Kerosene, Naphtha, and Cooking Gas-LPG.
This largest natural gas company ranks 11th among global energy majors (Platts). It is the only public
sector Indian company to feature in Fortune’s ‘Most Admired Energy Companies’ list. ONGC ranks 18th
in ‘Oil and Gas operations’ and 183rd overall in Forbes Global 2000. Acclaimed for its Corporate
Governance practices, Transparency International has ranked ONGC 26th among the biggest publicly
traded global giants. It is most valued and largest E&P Company in the world, and one of the highest
profit-making and dividend-paying enterprise.
ONGC has a unique distinction of being a company with in-house service capabilities in all areas of
Exploration and Production of oil & gas and related oil-field services. Winner of the Best Employer
award, this public sector enterprise has a dedicated team of over 33,500 professionals who toil round
the clock in challenging locations.
Fig: ONGC Group of Companies

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ONGC is the only fully–integrated oil and gas company in India, operating along the entire hydrocarbon
value chain. It has single-handedly scripted India's hydrocarbon saga. Some key pointers:
a) ONGC has discovered 6 out of the 7 oil and gas producing basins in India:
b) This largest energy company in India has established 8.70 billion tonnes of in-place
hydrocarbon reserves. It has to its credit more than 570 discoveries of oil and gas with
Ultimate Reserves of 3.02 Billion Metric tonnes (BMT) of Oil Plus Oil Equivalent Gas (O+OEG)
from domestic acreages.
c) It has cumulatively produced 998 Million Metric Tonnes (MMT) of crude and 645 Billion Cubic
Meters (BCM) of Natural Gas.
d) ONGC has won 115 out of a total 254 Blocks (more than 50%) in the 8 rounds of bidding, under
the New Exploration Licensing Policy (NELP) of the Indian Government.
e) ONGC's wholly-owned subsidiary ONGC Videsh Ltd. (OVL) is the biggest Indian multinational,
with 41 Oil & Gas projects in 20 countries.
f) ONGC produces over 1.26 million barrels of oil equivalent per day, contributing around 70%
of India's domestic production. Of this, over 75% of crude oil produced is Light & Sweet.
g) The Company holds the largest share of hydrocarbon acreages in India (61% in PEL Areas &
81% in ML Areas).
h) ONGC possesses about one tenth of the total Indian refining capacity.
i) This E&P Company has a well-integrated Hydrocarbon Value Chain structure with interests in
LNG and product transportation business as well.
j) A unique organization in world to have all operative offshore and onshore installations (403)
accredited with globally recognized certifications.
k) This public sector enterprise operates with 14 seismic crews, manages 262 onshore
production installations, 268 offshore installations, 69 drilling (plus 37 hired) and 54 work-
over rigs (plus 25 hired), owns and operates more than 25,500 kilometers of pipeline in India,
including 4,500 kilometers of sub-sea pipelines.
l) All crudes are sweet and most (76%) are light, with sulphur percentage ranging from 0.02-
0.10, API gravity range 26°-46° and hence attract a premium in the market.
m) Strong intellectual property base, information, knowledge, skills and experience.
n) Maximum number of Exploration Licenses, including competitive NELP rounds. ONGC has
bagged 121 of the 254 Blocks awarded in the 9rounds of NELP.
o) ONGC owns and operates more than 25,500 kilometers of pipelines in India, including sub-
sea pipelines. No other company in India operates even 50 per cent of this route length.

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3. About Well Stimulation Services – ONGC
WSS provides specialised stimulation services focusing on a safety, efficiency and high-quality
standards to optimise well production. WSS have its own fleet of specialised equipment’s, trained
professionals for performing the jobs.
The role of Stimulation techniques is well acknowledged for augmenting and sustaining hydrocarbon
production from varied nature of reservoirs. However, it requires a detailed technical understanding
and analysis of the problem(s) for planning an effective treatment for wells which in turn require
trained specialists of various disciplines.
 To fulfill the stimulation needs of the Western Onshore fields of ONGC, Central Stimulation
Team (CST) was established in 1975 at Mayur Bhavan, Ahmedabad, which was later renamed
as Well Stimulation Services (WSS) Ahmedabad in 1982.
 To cater the increasing stimulation needs of different onshore Assets and Basins, the following
WSS onshore work centres were subsequently established.
 Sivasagar, Assam Asset (1983)
 Narsapur, Rajahmundry Asset(1985)
 Karaikal, Cauvery Asset(1990)
 Gandhar, Ankleshwar Asset(1995)
 CBM, Bokaro (2003)
 Jorhat, Assam & Arakan Basin (2005)
 Another WSS work centre is being established at Tripura Asset shortly which would initially
have the facilities for carrying out Acid jobs & Nitrogen / Coil Tubing Jobs.
 The services provided by WSS can broadly be categorized as follows:
 Stimulation Services
1) Acidization and Solvent / surfactant treatment
2) Hydraulic fracturing
 Allied Production Services
1) Coiled Tubing Services
2) Sand Control Services
3) Nitrogen Services
4) Hot Oil Services
5) Casing Tubing Cleaning
6) Microbial EOR
At present, ONGC owns a fleet of sophisticated more than 110 WSS units of different make and type
which are distributed across the WSS onshore work centres. These units are
 Coil Tubing Unit
 Nitrogen Pumper
 Nitrogen Bulk Carrier (Cryogenic vessel)
 Hot Oiler
 Sand Blender
 Sand Dumper
 Multi Purpose Pumping Unit (MPPU)

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 Frac Pumper
 Acid Pumper
 Acid Tanker
 Chemical additive system pumper
 Data acquisition van/system
These units are deployed on day to day basis to execute various jobs and to extend necessary
assistance in field operations as per the requirement of Assets / Basins. Since these equipment are
extensively used for stimulation and other allied operations, they need frequent check-up and
maintenance.
 A periodical schedule of inspection and maintenance as recommended in manufacturer’s
manual is necessary to keep the equipment in working order.
 Role of WSS in oil field operations normally starts from the production testing phase, however
their services are also utilized during drilling phase where there have been occasions of drill
pipe stuck up, Acidization jobs are carried out to release the stuck up. Further, in case of any
well activity during drilling, coiled tubing services are also utilized for well subduing
operations.
WSS
Hydraulic
Fracturing
1) Frac Pumping
Unit
2) Sand Dumper
(Propant Carrier)
3) Fluid Blending
Unit
4) Chemical
Additive System
5) Fracture Tanks
6) Frac Van
Matrix
Acidization
1) Acid Pumping
Unit
Hot Oil
Circulation
1) Hot oil
Circulation Unit
Coil Tubing Unit
1) Coil Tubing
Unit
Nitrogen Service
1) Nitrogen
Pumping Unit
Sand Control
Service
( Gravel Pack )
1) Frac Pumping
Unit
2) Sand Dumper
3) Solvent
Blending Unit
4) MPPU
Fig: Services
Provided by
WSS and their
required units

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4. Chemistry Lab Section:
In chemistry lab section, mainly focused on the definition of stimulation and what techniques are
useful for stimulating the well.
Stimulation: When flow of fluid is not coming from well due to some reason although reservoir has
a potential of crude oil then some techniques are applied for getting that flow that called as a
stimulation.
There are several techniques are available for stimulating the well. All techniques are used based on
the problems of well to deny fluid flow.
4.1 Acidization
Deals with skin factor of formation. Here by pumping acid into the well bore some materials (skin)
can be dissolved and attain development in the skin. Always negative skin is preferable.
Depending on the reservoir skin factor should be vary. Like in sandstone reservoir zero skin is
preferable because purpose in sandstone reservoir is to clean the pores only. Whereas in carbonate
reservoir negative skin is preferable.
There are mainly two types of acidization methods:
(A) Matrix Acidization: Purpose is to clean pores. Acid selection can be done based on the Mineralogy
of formation. This can be performed up to 3-4 feet near well bore otherwise it will react with reservoir
formation also which we don’t want.
(B) Acid Fracturing: In this, acid is pumping at high pressure than the formation breakdown pressure.
So that fracture happen in the reservoir and permeability can be developed.
Fig: Difference b/w Matrix & Fracturing Acidization

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4.2 Hydraulic Fracturing:
Here, Fracturing fluid is pumping at pressure more than formation breakdown pressure. After creating
fracture main thing is that should open. For that material used with fracturing fluid known as
“Propants”.
Selection of propants done based on its size and pressure of formation.
Prior to hydraulic fracturing job one reverse circulation of fluid (Water + KCL) is require for cleaning
well bore. After that HF process happen from tubing and return via annulus.
Fig: Proppant placed in open fractures
4.3 Hot oil Circulation:
This techniques come in play when reservoir contain heavy crude oil. Wax is deposited inside the
tubing and at bottom hole. For melting and removing that wax we pumped hot oil. Due to this wax
deposition many problems occur like, SRP stuck, Stopping flow etc.
Here hot oil temperature is maintain at 85 degree Celsius & pressure should be maintain below
formation break down pressure and if SRP installed then below maximum pressure of stuffing box.
4.4 Gravel Packing:
This techniques is performed when the reservoir producing more amount of sand. For preventing that
sand formation we create artificial skin opposite to sand producing zone with gravel size particles and
stop the sand flow. This techniques applied after drilling of during production.

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Fig: Artificial Screen against Sand formation in Open & Cased hole
4.5 Coiled Tubing Unit:
This techniques are generally used in ED (Effluent Disposal) well for activation purpose. In addition
to that CTU is also used for Bottom-hole cleaning, HOC, Acid Pumping, Nitrogen Pumping, Sand
washing with foam, well subdue etc.
4.6 Liquid Nitrogen Pumping:
Mainly for activation of well. Liquid nitrogen is stored in the Cryovessel at(−196℃). During job it is
converted into gas by boiler and pumped in well from tubing. Because of inert gas and compressibility
nitrogen is used for well activation.
Fig: Liquid Nitrogen Unit

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4.7 Test Performed for Selection of Propants:
4.7.1 Propant Sieving Test:
 In this test, First homogeneous distribution of propants are required and after that sieving can
be performed.
 In sieving process, assembly which contain selected weight of propants have to put on sieve
shaker and operate till 10 min.
 After that, from weight of empty sieve and sieve with propants can be calculated.
Fig: Sieving Mesh with Shaker
4.7.2 Proppant density Test:
 From sieving test data, density of proppants can be calculate in
𝑔𝑚
𝑚𝑙
.
4.7.3 Crushing Test:
 In this test, Pressure is applied by hydraulic press depending upon types of propants (LSP,
HSP, ISP, UHSP).
 Weight required for crushing test can be calculate by bellowing formula:
 𝑊𝑒𝑖𝑔ℎ𝑡 𝑜𝑓 𝑃𝑟𝑜𝑝𝑎𝑛𝑡𝑠 = 𝐵𝑢𝑙𝑘 𝑑𝑒𝑛𝑠𝑖𝑡𝑦 ∗ 55.63
 During this process increment in pressure should be 2000
𝑃𝑠𝑖
𝑚𝑖𝑛
.

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Fig: Proppant Crushing Machine
4.7.4 Solubility Test:
Solubility test is related to acid (HCL) if more silica content is present. Process should be,
 Take 100 ml Mud acid
 2 gm. proppants
 Pour proppants into acid
 66℃ Heating in water bath (30 min.)
 Remove acid
 Wash proppants
 Measure weight (Solubility)
4.7.5 Sphericity & Roundness test:
From sphericity and roundness chart, after observing proppants into the microscope selection can be
done of perfect shape and size of it.
Fig: Proppant Sphericity Chart

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4.7.6 Turbidity Test:
 Measured in NTU (Naphalo Turbidity Unit)
 Take 25 ml Proppants +100 ml water. Vigorously mixed both and take upper portion of
solution in container and put on Turbidity meter.
Fig: Portable Turbidity Meter
4.7.7 Process for Making Fracturing Fluid:

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5. Coiled Tubing Unit
A cost- and time-effective solution for well intervention operations employs coiled tubing. Instead of
removing the tubing from the well, which is how work-over rigs fix the problem, coiled tubing is
inserted into the tubing against the pressure of the well and during production.
In the oil and gas industries, coiled tubing refers to a very long metal pipe, normally 1 to 3.25 in (25 to
83 mm) in diameter which is supplied spooled on a large reel. It is used for interventions in oil and gas
wells and sometimes as production tubing in depleted gas wells. Coiled tubing is often used to carry
out operations similar to wire-lining. The main benefits over wireline are the ability to pump chemicals
through the coil and the ability to push it into the hole rather than relying on gravity. Pumping can be
fairly self-contained, almost a closed system, since the tube is continuous instead of jointed pipe. For
offshore operations, the ’footprint' for a coiled tubing Operation is generally larger than a wireline
Spread, which can limit the number of installations where coiled tubing can be performed and make
the Operation costlier. A coiled tubing operation is normally performed through the drilling derrick on
the oil platform, which is used to support the surface equipment, although on platforms with no
drilling facilities a self-supporting tower can be used instead. For coiled tubing operations on sub-sea
wells a Mobile Offshore Drilling Unit (MODU) e. g. semi-submersible, Drillship etc. has to be utilized to
support all the surface equipment and personnel, whereas wireline can be carried out from a smaller
and cheaper intervention vessel. Onshore, they can be run using smaller service rigs, and for light
operations a mobile self-contained coiled tubing rig can be used.
The tool string at the bottom of the coil is often called the bottom hole assembly (BHA). It can range
from something as simple as a jetting nozzle, for jobs involving pumping chemicals or cement through
the coil, to a larger string of logging tools, depending on the operations.
Coil tubing has also been used as a cheaper version of work-over operations. It is used to perform
open hole drilling and milling operations. it can also be used to fracture the reservoir, a process where
fluid is pressurised to thousands of psi on a specific point in a well to break the rock apart and allow
the flow of product.
5.1 COMPONENTS OF CTU
5.1.1 Coil Tubing:
Generally large coils of low alloy carbon sheet steel are used as coil tubes. ASTM A606 Type 4 & ASTM
A607 are most commonly used as CTs. These are thermo-mechanically rolled.
5.1.2 Tubing Reel:
The tubing reel is located on the unit itself. It is supported in axle and is driven by a hydraulic chain
drive. The inner end of the coil tube has a high pressure inlet safety valve before it is connected to the
reel.
5.1.3 Injector:
The injector is the heart of CTU which is installed directly on the well head or drill string, and is the
means by which the tubing is lowered, maneuvered and hoisted in the well. A load cell is located at
the bottom of the injector head. This hydraulic device is connected to the operator’s control panel to

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monitor tubing weight PD – 14 Technology & Application of Acidization, Sand Control and Coiled
Tubing.
5.1.4 Stuffing Box:
The stuffing box is the primary sealing mechanism for isolating well bore fluids while under static or
dynamic operating conditions. Hydraulic pressure acting on a piston actuates it. The piston compresses
a polyurethane element, which makes a seal around the CT. This element, called a stripper rubber,
allows the CT into and out of a live well, providing complete pressure control. Generally stuffing box is
mounted above the BOP and below the injector head.
5.1.5 Blow Out Preventer (BOP):
A blowout preventer (BOP) contains wellbore pressure. Its main function is to prevent well fluids from
escaping into the atmosphere. A CT BOP is designed specifically for CT operations. BOP is a critical part
of CTU and PD – 14 Technology & Application of Acidization, Sand Control and Coiled Tubing.
5.1.6 Control Console, the power pack & crane:
The coiled tubing control cabin is situated to provide a clear view of both the well head & injector and
the tubing reel.
Fig: coil Tubing Unit

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5.2 General Process
1. In this process, first the connections are made, some of the pipes are cut due to corrosion. 2. The
flange is attached to the Christmas tree for pipe fitting so that the chemicals can be pumped with the
help of the pump.
3. Here the controller has a joystick from where he operates and controls the pipe reel and the
pumping unit is operated through the controller on the top of the truck.
4. Now the injector head is held on top of the BOP which is above the X-mas tree and the pipe reel is
rotated up to some extent depending UP on the depth to Which pipe is to be lowered. The pipe used
has a diameter of 1.5 inch.
5. NOW the water is mixed with the gel powder to make the gelatic agent.
6. The pressure at which the gelatic agent or solution is pumped into the well is about 4000 kPa.
7. The gel solution is used because it is a bit sticky due to Which elements or mud is removed easily.
As the gel is viscous it is pumped through a centrifugal pump.
8. The waste water and the chemicals are removed through the return line.
9. If the well is not cleaned properly by the gel solution, then water may to clean it completely.
Fig: general configuration of CTU and
Coil Tubing which has 3000 to 5000m
length
[Source: Wellsense Energy]

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5.3 Application of CTU
5.3.1 Circulation:
The most typical use for coiled tubing is circulation or Deliquification. A hydrostatic head (a column
of fluid in the well here) may be inhibiting flow of formation fluids because of its weight (the well is
said to have been killed). The safest (though not the cheapest) solution would be to attempt to
circulate out the fluid, using a gas, frequently nitrogen (Often called a 'Nitrogen Kick‘). By running
coiled tubing into the bottom of the hole and pumping in the gas, the kill fluid can be forced out to
production. Circulating can also be used to clean out light debris, which may have accumulated in the
hole. Coiled tubing umbilicals can convey hydraulic submersible pumps and jet pumps into wells.
These pumps allow for inexpensive and non invasive well cleanouts on low-pressure CBM (coal bed
methane) gas wells. These umbilicals can also be run into deviated wells and horizontal laterals.
5.3.2 Nitrogen Pumping:
Pumping through coiled tubing can also be used for dispersing fluids to a specific location in the well
such as for cementing perforations or performing chemical washes of downhole components such as
sandscreens. In the former case, coiled tubing is particularly advantageous compared to simply
pumping the cement from surface as allowing it to flow through the entire completion could
potentially damage important components, such as the downhole safety valve. Coiled tubing
umbilical technologies enable the deployment of complex pumps which require multiple fluid strings
on coiled tubing. In many cases, the use of coiled tubing to deploy a complex pump can greatly reduce
the cost of deployment by eliminating the number of units on site during the deploy. Nitrogen is an
inert gas and, therefore, cannot react with hydrocarbons to form a combustible mixture. In addition,
nitrogen is Only slightly soluble in water and other liquids that allow it to remain in bubble form when
commingled with wash liquids. Nitrogen is a nontoxic, colorless, and odorless gas that is typically
brought to location in liquid form in cryogenic bottles at temperatures below -320°F.
The liquid nitrogen is pumped through a triple-stage cryogenic pump at a specified rate into an
expansion chamber that allows the nitrogen to absorb heat from the environment and vaporize into
a dry gas. The gas is then displaced out of the expansion chamber and into the treatment piping at
the required surface pressure to perform the prescribed job.
Although cryogenic nitrogen does not contain oxygen, several other nitrogen sources such as pulse
swing adsorption or membrane units can contain significant percentages of oxygen. This oxygen
content can exceed 3% and represents a potential corrosion problem in some applications such as
CT drilling.
In completed wellbores that are critically under-pressured or liquid-sensitive, nitrogen pumped at
high rates can be used to transport solids up the annulus and out of the wellbore. The solids removal
mechanism within the wellbore is directly dependent upon the annular velocity of the nitrogen
returns. If the nitrogen pump rate is interrupted during the cleanout program, all solids being
transported up the annulus will immediately fall back. Of equal concern are the tremendous erosional
effects on the production tube, CT, and surface flow tee or flow cross that will occur at the rates
needed to maintain solids transport up the annulus. Because of the difficulty to safely execute this
type of cleanout program, solids removal programs using nitrogen should be considered as a “last
resort” option.

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5.3.3 Coil Tubing Drilling:
A relatively modern drilling technique involves using coiled tubing instead of conventional drill pipe.
This has the advantage of requiring less effort to trip in and out of the well (the coil can simply be run
in and pulled out while drill pipe must be assembled and dismantled joint by joint while tripping in and
out).
An additional advantage is that the coiled tubing enters the hole via a stripper, mounted on the
injector, which provides a hydraulic seal around the coil. This offers well control capabilities beyond
those normally possible with drill pipe, and gives the ability to drill underbalanced. Instead of rotating
the drill bit by using a rotary table or top drive at the surface, it is turned by a downhole MUD MOTOR,
powered by the motion of drilling fluid pumped from surface. Drilling which is powered by a mud
motor instead of a rotating pipe is generally called slide drilling.
Typically, the mud motor will be one component of a Coiled Tubing Drilling bottom hole assembly. The
BHA also provides directional survey, gamma, pressure, temperature, and in some cases, petrophysical
logs as drilling progresses. The latest generation of advanced Coiled tubing drilling BHAs offer the
ability to steer the bit, enabling the well’s trajectory to be corrected in response to the measurements
taken by the sensors.
5.3.4 Production:
Coiled tubing is often used as a production string in shallow gas wells that produce some water. The
narrow internal diameter results in a much higher velocity than would occur inside conventional tubing
or inside the casing. This higher velocity assists in lifting liquids to surface, liquids which might
otherwise accumulate in the well bore and eventually "kill" the well. The coiled tubing may be run
inside the casing instead or inside conventional tubing. When coiled tubing is run inside of
conventional tubing it is often referred to as a "velocity string" and the space between the outside of
the coiled tubing and the inside of the conventional tubing is referred to as the "micro annulus". In
some cases gas is produced up into the micro annulus. Coiled tubing umbilical can convey hydraulic
submersible pumps, electric submersible pumps and jet pumps into wells for both permanent
deliquification schemes and service applications.
5.3.5 Sand Washing with Foam:
Now if one uses aerated fluid, it must not be able to suspend the sand. Foam may be recognized as
low pressure gradient fluid with sand carrying capacity. Foam is gas in water emulsion comprising of
65% to 95% gas. Ideally the gas is nitrogen. The foam at surface is generated by pumping liquid
consisting mainly about 99% water and 1%surfactant and gas. The atomizer acts as a foam generator.
Rheological properties and foam quality are affected by pressure and temperature. Choke will
maintain back pressure to maintain foam quality.
A bottom hole treating pressure has to be assumed. Once the sand has been washed to desired depth,
circulation must be maintained until the returns are clean. Bottom should be tagged several times to
make sure that sands are removed.

20 | P a g e
5.3.6 Sand washing with nitrified water:
Sand in the wellbore is critical problem that it blocks the production or injection. The sand may be
formation sand, fracturing sand, or sand from injection fluids depending on the formation completed
and type of well. The most common method is to circulate water while removing sands from the
wellbore. One aberration from other uses is that one needs to pump water through coiled tubing.
Water pressure overcomes reservoir pressure due to deeper depth with lower bottom hole pressures
making it impossible to circulate to the surface. This is the main problem associated with circulating
water. There are several methods to overcome this problem. One of the method is circulate lost
circulation material but it results into irreparable damage.
The best reliable method is to lighten the fluid column with gas to degree that the hydrostatic weight
of aerated fluid weigh less than the reservoir pressure. The fluid pump and nitrogen pump are
connected through a “Y” Connection into coiled tubing unit reel. After tubing and all surface
equipments have been tested, tubing is lowered into hole while circulating water and nitrogen.
Caution is that the wash should not be too fast.

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6. Matrix Acidization
Matrix acidizing refers to one of two stimulation processes in which acid is injected into the well
penetrating the rock pores at pressures below fracture pressure. Acidizing is used to either stimulate
a well to improve flow or to remove damage and to improve injectivity of oil, water or ED well also to
improve skin factor. It is also performed before HF job.
In case of the Matrix Acidization, BHP (Bottom hole pressure) is maintained below fracture pressure
so that fracture won’t take place. While in case of the Acidization fracturing, BHP is maintained above
the fracture pressure so that formation gets fractured. MA (Matrix Acidization) removes all those
deposited elements, iron deposition, pore blockage materials hence indirectly reduces the pore
blockage and increase permeability.
6.1 Common involved Acids:
Mud Acid is the acid used for stimulation job which is the combination of 12% HCl (Hydro-chloric acid)
and 2% HF (Hydro-Fluoric acid). ABF (Ammonium Bi-fluoride) is added in HCl which will form HF in the
formation itself. Concentration of HCl and HF vary from formation to formation and decided based on
the mineralogy. 10% HCl+ 1 or 2% HF is commonly used. Maximum allowed concentration is 12% HCl+
3% HF.
Acidization can be carried out only near to the wellbore around 3 feet. The reason behind this is the
reactivity of the acid. As the Mud acid is pumped, it gives instantaneous reaction. Due to fast reactivity,
acid can’t go more deep into the well. After matrix acidization, skin factor becomes 0 and negative in
case of carbonate formation due to Warmholes and channels creation.
HBF4 (Hydro Fluoro-boric acid) is another inorganic acid used for acidization. It is weak acid also called
water-injection acid and used for RHF- Retarded Hydro-Fluoric acid system after the Swelling test is
carried out. It will hydrolyse slowly and form in-situ HF simultaneously.
Organic acids such as Acetic acid, Formic acid are used for deep wells where temperature is high.
Because HF and HCl react fast with Iron at high temperature and corrode tubings.
6.2 Additives used:
ACI: Anti-Corrosion Inhibitors are added to protect tubings and casings from corrosion.
Anti-Sludging agent: Crude oil containing asphaltenes, resins and paraffin hydrocarbons in molecular
weight, these substances may react chemically with acids, even from crude oil, thereby forming a
precipitate blockage formation, acidification effects. Some hydrocarbons, (predominantly those
containing high levels of asphalt) tend to form acid sludge in the presence of live or spent HCl or HCl/HF
acid mixtures. Anti-sludge agents are surfactants that eliminate this problem. DDBSA-
Dodecylbenzenesulphonic Acid is used commonly.
Mutual solvents are routinely used in a range of applications, such as removing heavy hydrocarbon
deposits, controlling the wettability of contact surfaces before, during or after a treatment, and
preventing or breaking emulsions. A commonly used mutual solvent is ethyleneglycolmonobutyl ether,
generally known as EGMBE which reduces surface tension and makes flow easier.

22 | P a g e
Clay stabilizers: NH4Cl is used to prevent clay swelling. KCl can’t be used as it will form precipitate KF.
And K+ and NH4
+ ions are having same molecular sizes.
IPA: Methyl alcohol and isopropyl alcohol have been used for many years to aid in cleaning up water-
blocked gas wells. On occasion, 10 to 20% alcohol is used in acid to stimulate moderately low-
permeability (5 to 50 md) gas sands to speed the clean-up of spent acid.
Precipitate reducers: Fe(OH)3 precipitate is dangerous. So, one must reduce its formation because
permeability reduces as the pores are clogged by precipitates.
Acetic acid binds to Fe ion and doesn’t allow it to form precipitates. Citric acid is pumped with EDTA
(Ethylenediaminetetraacitic acid) as EDTA controls iron. Generally, EDTA is used in place of citric acid
in Calcium rich formation because Ca ion forms Calcium citrate. Fe2+ is less reactive than Fe3+ ion and
it will start forming precipitates after pH 6. As Acid job continues, pH increases due to dissolved matrix
which is the suitable medium for precipitation. So, Post flush is always carried out quickly before
allowing pH rise of the medium. pH reaches 4 to 5 max. during the operation. Erythorbic acid as
Reducing agent is used to convert Fe3+ to Fe2+ ion.
6.3 Identification of candidate well
This parts take care of the fact that does the well really require the acidization treatment or not.
Wells may perform poorly or less well than expected because of three different factors:
(1) an inefficient mechanical system (wrong size tubing in a flowing well or inefficient artificial lift
equipment for pumping or gas lift wells),
(2) low reservoir permeability, or
(3) wellbore restriction because of formation damage or incomplete perforating.
A good matrix acidizing candidate is any well producing from a formation with permeability greater
than 10 md and the permeability of which in the near-wellbore or near-perforation region has been
reduced by solid plugging.
Generally, the production department-the authorized person of GGS or GCS reports the loss/reduction
of production from a well, then the reason for the reduction is analysed, generally the field experience
and behaviour of offset is used for prediction.
It is also performed before Hydraulic Fracturing job. HF creates pathway by providing fractures of 40-
50 m length but it can’t remove debris created which may reduce permeability. Hence, Acid job is
performed before HF to clear the matrix near the wellbore and will provide great injectivity. Fracturing
fluid can be pumped at low pressure after acidization. HF job (pumping 250 m3 approximately) is
lengthier than acidization.
6.4 Performing Acidization:
Units involved: 1) APU- Acid Pumping Unit with Acid and Water tanks (Capacity 3 m3 each)
2) Acid Tanker

23 | P a g e
Based on the mineralogy and formation, mud acid concentration is designed for the well by Matrix
Acidization Tester (to find an acid giving more solubility) at laboratory level. Acidization job is
performed in three stages:
6.4.1 Pre Flush:
HCl in the tank with the concentration nearly 30-35% is diluted with water to make it 7.5-10-12% and
pumped into the well. Pre flush volume is pumped based on the perforation volume. Additives are
used in 1-2% concentration. Pre flush is done to clear the space for main flush.
6.4.2 Main Flush:
The main difference between pre flush and main flush is addition of ABF. HCl with ABF is pumped into
the wellbore which will form in-situ HF in the reservoir.When DPM (Deep Penetration Acid) is done,
then Boric acid is pumped to dissolve debris at deeper parts.Reverse circulation with water through
annulus to tubing is done for back flow of acid.
6.4.3 Post Flush:
To clean the tubing and annulus; water is circulated which will clean and remove the traces of acid to
protect tubings and casings from corrosion. Injectivity test is performed before and after the acid job.
Annulus valve is closed and water is injected. Based on the number of strokes per minute calculated,
the pumped volume per minute is calculated which gives injectivity. Instead of water, silicon oil is used
as driving fluid when reservoir temperature is more than 100◦ C.
Acid job can be performed during workover operations or after drilling, through CTU (Coil Tubing Unit),
in self-flowing wells. Acid is pumped through tubing to annulus and back flow is taken through annulus
to tubing. In case of CTU when packer is there or job has to performed in less time with less volume,
Acid is pumped through coil tubing to temporary annulus (between coil tubing and production tubing
shown in figure below) and back flow through temporary annulus to coil tubing. The Coil tubing is
cleaned with water after the job performed to prevent it from corrosion.
Fig: Fluid flow during Acid Job

24 | P a g e
6.5 Visited (Mehsana field-Shobhasan):
Well depth-1814 m
Perforation interval: 1814-1817 m
Tubing- 1818 m
Acid of tanks in APU is pumped with triplex pump provided with NRV (non-return valve). Mud acid
goes through triplex pumps, gets pressurized and then combine flow travels through pipe, treating
iron and tubing. It goes to the formation, return flow is dumped in waster pit.
Injectivity test: Injectivity before acid job- 120 m3
Injectivity improved after acid job- 200 m3
The acid job was performed when well was under workover operations and it was supposed to go
through HF job. Acid job was done here prior performing HF job.

25 | P a g e
7. Nitrogen Activation
The nitrogen gas is circulated into the production conduit to displace liquids and reduce the
hydrostatic pressure created by the fluid column hence, nitrogen lifting is a common technique used
to initiate production, generally a coiled tube is utilized but it can be directly injected via the annulus.
Nitrogen is selected for the purpose because nitrogen possesses certain properties which are given
below.
7.1 Nitrogen Properties:
Nitrogen is selected for the purpose because nitrogen possesses certain properties which are given
below:
a) Steady chemical properties
b) Density 1.25 kg/m3
c) High compacting factor
d) Low critical temperature
e) Low surface tension
f) Bad thermal conductivity
These are the nitrogen properties which makes it to be used for the activation.
7.2 Nitrogen Advantages:
a) Enriched source
b) Low cost
c) High security
d) Better boost pressure
e) Non corrosive
f) Available water sensitive reservoir
This technology is used in case back pressure to formation have to be reduced, formed by killing fluid
or drilling mud presented in a well after drilling or workover operations. Those jobs are done for
stimulation of kick-off in oil and gas wells.
7.3 Equipment Involved:
a) Cryo Vessel ( N2 storage) (with pumps if not a pumping unit and a heat exchanger)
b) Coiled Tubing Unit (If Packer is there)
7.4 Procedure:
a) Cryo vessel is prepared and is filled with nitrogen (Liquid state Low T at about -196oC at 1 atm
pressure)
b) The units are then mobilised to the site.
c) The connections are made with the pump outlet to the annulus of the well.
d) First the connection is tested by pressurising the line.
e) Now the annulus valve is opened and pumping begins.
f) Liquid nitrogen is sucked from the tank (at 18-20 psi) by a Boost pump (Centrifugal pump)
then it is supplied (at 60 psi) to a triplex pump where it is pressurised more (generally 1500-

26 | P a g e
1600 psi) to reduce the temperature then the nitrogen flows to the heat exchanger (With hot
water) and the temperature increases and this high-pressure gas is pumped in the annulus.
g) The tubing valve is open for the well fluids to come out if present.
h) The nitrogen pressurises the bottom hole as the pressure builds up the nitrogen expands to
698 times the original volume and lifts the present well fluids
i) The outlet of the fluids is controlled and the fluids coming out are examined.
j) After completion of the job connections are opened and the units are demobilised back to
the base.
The well site that was visited by us had a workover rig where the production was not yet started
because of the absence of natural energy of the reservoir that can produce the well fluids. So,
activation job was required to begin production where the well will need subsequent nitrogen lift
operations.
In this job N2 is pumped via annulus to clear out brine or mud collum and reduces the hydrostatic head
acting at bottom hole so the reservoir fluid can flow naturally at the surface or at some height inside
the well (If it is not self-flow).
7.5 Precautions:
However some precautions are need to be taken in this job which is listed below:
a) Stay away from liquid nitrogen, Check for leakages.
b) Monitor temperature of N2 gas while pumping in well, If liquid nitrogen is not heated properly
then it can solidifies the brine or mud inside tubing which will eventually choke the line and
pressure will shoot up and line can blast.
c) Due to low temperature in well, the metal will contract and there is possibility that the
production casing can lose the grip from hanger and fall into the sump.
Fig: Cryo-vessel on field

27 | P a g e
8. Hot Oil Circulation (HOC):
Perhaps the most common formation damage problem reported in the mature oil-producing regions
of the world is organic deposits forming both in and around the wellbore. These organic deposits fall
into two broad categories:
a) Paraffins
b) Ashphaltenes
These deposits can occur in tubing, or in the pores of the reservoir rock. Both effectively choke the
flow of hydrocarbons.
8.1 Why HOC?
In the Oil producing wells, wax or Asphaltenes gets deposited on the tubing or casing and choke
production tubing. Hence indirectly reduces the production rate. The main reason behind this wax or
Ashphaltene deposition is the reduction in temperature of the fluid flowing through the tubing.
This temperature reduction is due to geothermal gradient or reduction in size of cross sectional area
from which fluid passes. There is lots of technique to remove this deposition like:
a) Mechanical technique: scrapping
b) Solvent treatment: injection of xylene, tolueneor lighter hydrocarbon etc…
Fig: Ashphaltene Deposition in the casing
Fig: Hot Oil Circulation Unit

28 | P a g e
c) Dispersants: like sulphates or sulfonates
d) Heat application: By increasing temperature and make them soluble inliquid
Here in case of the mechanical technique like for scrapping the work over rig is required hence this
technique becomes complex and costly because trip in and trip out operations are costly and complex
if artificial lift applied on the rig. So it is not applicable in all case
In case of solvent and dispersant treatment these chemicals solvents like naptha, xylene and toluene
and dispersants like sulphate and sulfonate mix with the produced fluid and may hamper it properties.
So, these chemicals may damage the properties of produced fluid and also effect the separation
process. Hence these techniques are limited by refining companies or consumer. So, these techniques
are not even applicable for each and every case.
But the heat application doesn’t require any trip in and trip out as well as it also doesn’t affect the
properties of the produced fluid and doesn’t hamper the separation process. So, this technique is most
applicable and preferable to remove wax deposition in each and every case. The HOC (Hot Oil
Circulation) is the one type of the heat application to remove waxdeposition.
 What is HOC?
Circulation of Hot Oil from the wellbore to remove wax deposition. Wax deposition reduces production
rate so this technique is generally applicable to maintain optimum production rate by removing this
wellbore mechanical damage.
In simple case Hot Oil is circulated from tubing to the annulus but in case of the packer applied at the
bottom between tubing and casing this simple circulation cannot be obtained hence by adding CTU
artificial annulus can be created and circulation can be obtained.
While if SRP type artificial lift is present then due to the NRV at the bottom of sucker rods simple
circulation cannot be obtained hence reverse circulation is required. In reverse circulation, Hot Oil is
injected from annulus and return to surface from tubing.
Temperature of Hot Oil is maintained about 85°C or more than that because at this temperature wax
are soluble in Oil.
Weather also effect to the solubility of wax and temperature transmission via Oil. Hence in winter PPD
(Pour Point Depression) has to be added with Oil. It maintains low deposition temperature so even at

29 | P a g e
the low temperature transmission wax will remain soluble in Oil. Amount of fluid or slug that is injected
in the wellbore is selected based upon the annulus and tubing sizes.
8.3 Solvent job additives:
a) Solvent: For Ashphaltenes: Naphtha, Xylene, Toluene etc.
b) For Wax: lighter HC solution like Propane, Butane, Diesel etc.
c) Surfactant
d) Corrosion inhibitor: ACI EGMB or HMB PPD
e) Emulsifier Acid: Acetic acid, Citric acid etc.
f) Generally, Xylene, Diesel and EGMB are always used combined with each other in different
proportions.
8.4 Equipments/Units Involved
a) Crude Oil heater and Pumping unit
b) Coiled tube Unit
c) Crude oil Tanker
d) Water Tanker (For post job CT maintenance)
8.5 Operation
a) The units are mobilised to the well to be stimulated.
b) After the units reach the well site, the well is made ready for the operation. The THP (Tubing
Head
c) Pressure) and the Annulus pressure reading are taken.
d) The Valves on the BOP are operated, The Tubing head valve and mainline valves are closed.
And the CT unit is prepared for the operation, the CT and injector assembly is first attached
to the well control stack then the hole assembly is secured to the BOP Top.
e) Next operation is to make the CT empty of the previously filled water, so the main flowline is
opened and the oil is pumped in the CT to displace the previously present water as the water
is displaced the water flows from the main flowline when all of the water is emptied out, now
the unit is ready for Hot oil Circulation.
Fig 3. Ashphaltene Resin Micelle Formation

30 | P a g e
f) The oil pumping pressure is maintained as to provide sufficient backpressure for the well and
formation fluids and temperature is maintained as to solubilise the deposited organic solids
(> 85 C) now Tubing valve is opened and lowering of CT along with circulation begins the CT
unit is lowered till the desired depth (perforation depth) and then after some time of
circulation it is brought back up and the well is again shut off and pumping is stopped.
g) Now the job is complete but the CT is to be emptied for the present oil and is to be again
filled with water so that to prevent and deposition, So again the water is pumped in the CT
displacing the oil present, the most important point is that water should not go in the well
and hence the BOP valves are controlled in the desired way.
h) Units are demobilized and well is checked for improved performance.

31 | P a g e
9. Hydraulic Fracturing
Hydraulic fracturing is not a new technology in the oil and gas industry. It has been deployed in the oil
and gas industry since 1947. The first intentional hydraulic fracturing process for stimulation was
performed at Hugoton gas field in western Kansas, in 1947 as shown in the figure 1. The Klepper well
no.1 was completed with four gas-producing intervals. The fluid used for this job was war-surplus
napalm, which is an extremely hazardous material. The amount of fluid pumped in each formation was
3000 gals. Although, post-treatment tests showed that acidizing is a better technique than hydraulic
fracturing to enhance the production from limestone formations. Since that first treatment in 1947,
hydraulic fracturing has become a standard treatment for stimulating the productivity of oil and gas
wells. Many fields produce only because of hydraulic fracturing process. Applications of first
generation of fracturing were primarily small treatments to bypass near-wellbore drilling fluid damage
to formations with permeability in the milli Darcy range.
Nowadays, hydraulic fracturing has become very common technique especially in North America to
extract natural gas from unconventional reservoirs such as coal beds, tight sands and shale formations.
A large amount of shale gas production in North America has become possible due hydraulic fracturing
Treatment. The cost of the fracturing operation ranges from less than $20000 for small skin bypass
fracs to over $1 million for massive hydraulic fracturing treatments. (Michael J. Economides T. M.,
2007).
9.1 Objective of hydraulic fracturing
Main aim of HF is to increase the productivity or injectivity of well by creating multiple fractures inside
the reservoir. In addition, it will gives the best result in low permeability or in damaged reservoir.
There are many different objectives of HF depending upon certain situations like (Gidley, J.L., Holditch,
S.A., Nierode, D.E. et al. 1989),
a) Increase the flow rate of oil and gas from low permeability reservoirs
b) Increase the flow rate of oil and gas from wells that have been damaged
c) Connect the natural fractures in a formation to the wellbore
d) Decrease the pressure drop around the wellbore
e) Increase the area of drainage or the amount of formation in contact with the wellbore
Fig: Hydraulic Fracturing at Hugoton gas field in western Kansas (Klepper Well no. 1)

32 | P a g e
f) Connect the full vertical extent of the formation to the wellbore
9.2 Fracture creation and its physics
The size and orientation of fracture, and the magnitude of the pressure needed to create it, are
dictated by the formation’s in-situ stress field. The magnitudes and orientations of these three
principal stresses are determined by the tectonic regime in the region, by depth, pore pressure, and
rock properties, which determines how stresses is transmitted and distributed among formations.
In situ stresses control the orientation and propagation direction of hydraulic fractures. Hydraulic
fractures are tensile fractures and they open in the direction of least resistance and propagating
perpendicular to the least principle stress.
During fracturing, at the surface a sudden drop in pressure indicates fracture initiation, as the fluid
flows into the fractured formation. To find the fracture closure pressure, engineers allow the pressure
to subside until it indicates that fracture has closed again.
Engineers find the fracture reopening pressure by pressurizing the zone until a levelling of pressure
indicates the fracture has reopened. The closure and reopening pressures are controlled by the
minimum principal compressive stress. After performing fracture initiation, engineers pressurize the
zone for the planned stimulation treatment. During this treatment, the zone is pressurized to the
fracture propagation pressure, which is higher than fracture closure pressure. The difference is the
net pressure, which represents the sum of the frictional pressure drop and fracture-tip resistance to
propagation.
9.3 Equipment Used:
1-Blender: Used to mix
3-Frac Pumper
1-Trailer manifold
3-Proppant dumper
4-storage tank
1-Data Monitoring Van
Fig: Pressure response during Hydraulic Fracturing

33 | P a g e
9.4 Process of HF
The placement of hydraulic fracturing treatments underground is sequenced to meet the particular needs
of the formation. Each oil and gas zone is different and requires a hydraulic fracturing design tailored to
the particular conditions of the formation. Therefore, while the process remains essentially the same, the
sequence may change depending upon unique local conditions. It is important to note that not all of the
additives are used in every hydraulically fractured well; the exact “blend” and proportions of additives will
vary based on the site-specific depth, thickness and other characteristics of the target formation.
9.4.1 Acid stage
consisting of several thousand gallons of water mixed with a hydrochloric acid or mud acid. This serves to
clear cement debris in the wellbore and provide an open conduit for other frac fluids by dissolving
carbonate minerals and opening fractures near the wellbore.
9.4.2 Minifrac Test
refer to pre-frac operations conducted in the well on the same day as the main stimulation operation.
These pumping operations are carried on up to full-scale pump rates with cross-linked fluid without
proppant. The purpose is to determine or confirm certain information that had to be assumed for the
design of the treatment and if necessary, we can modify the slurry parameter and pumping rate. The
information that can be obtained from a minifrac are:
 Closure pressure and time
 Near wellbore pressure losses
 Fluid leak-off
 Rate of pressure loss due to leak-off to the formation using cross-linked fluid
Fig: Hydraulic Fracturing Site Layout

34 | P a g e
9.4.3 Pad stage
consisting of approximately cross-linked fluid without proppant material. The pad stage fills the solution,
opens the fracture in the formation and helps to facilitate the flow and placement of proppant material.
9.4.4 Main flush
which may consist of several sub stages of water combined with proppant material (generally -20 & +40
mesh size). This stage may collectively use several hundred thousand gallons of water. Proppant material
may vary from a finer particle size to a coarser particle size throughout this sequence.
9.4.5 Post flush, Flow back and cleaning with N2
consisting of clean the tubing with reverse wash. Then, after 4 to 5 hours the frac fluid is being braked to
the viscosity of 10 cp with breaker and flow back the fluid and do N2 job for cleaning perforation and
fracture.
9.5 Data acquisition and Integrated fracture model
With data acquired from minifrac and main frac, we are going for history matching model in a
FRACKPRO simulator. We can obtain the fracture dimensions, length and geometry based on that.
Fig: FRAC-PRO simulator

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10.Conclusion
The period of training at WSS, ONGC helped us to understand various stimulation jobs that are carried
out to increase the production of depleted oil and gas reservoirs. This training helped us to
accumulate the knowledge of importance of stimulation services in the petroleum industry. The
proper knowledge of stimulation jobs helps to increase the production in a cost effective way. The
stimulation jobs require proper data of the well which is provided by the asset under which the well
lies which helps the stimulation experts decide which kind of stimulation technique must be applied
to increase the production of the well. The engineers after deciding the stimulation technique
calibrate the data on the softwares to decide the materials required for the job which are then tested
by the chemical laboratory and finalised for the job. The day prior to the job all the equipments are
checked and made available on the day of the job. Then the fleet is mobilized to the jib site and then
the job is carried out with main aim to increase production. This project helped us gain an industrial
approach to the stimulation services and provided with a holistic development of the practical
knowledge over the theoretical concepts.

Winter internship at ONGC well stimulation

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