Indian Oilfield Chemistry Conference 2018 is the first of its kind endeavor in India with the objective of bringing together Oilfield Operators, Chemicals Users/Manufactures/Suppliers and Researchers. The conference will provide an opportunity for sharing wisdom, knowledge, and information among the operators in different fields of India as well as with operators from other parts of the world. This may provide a way forward and solutions of several field problems and provide insight into “why the things are happening this way”.

1. M. No.: +91 99719 43010
Email: technical@oilfieldchemical.org
Web: www.oilfieldchemical.org
Organizer
IOFC 2018
27 – 28 Sep’18, Hotel Hyatt Ahmedabad, India
Indian
Oil Field Chemistry
Conference 2018
Souvenir

3. Welcome Message
Dear Friends,
With the growing concerns about energy security,
new chemistries are helping to optimize exploration,
drilling and production of hydrocarbons. Oilfield
chemicals form an integral part of the oil & gas
industry and find extensive usage in various stages of
oil exploration and evacuation. They play a significant
role in drilling, well completion, well stimulation,
water shut off, hydrofracturing, flow assurance, crude
oil demulsification, corrosion inhibition, effluent
treatment, injection water treatment, enhanced oil
recovery, scale management, etc. Well stimulation
segment holds a significant share of oilfield chemicals
by application. The best application of these chemicals
is seen in the production fromunconventional resource
like shale gas and tight oil where technologies such
as hydraulic fracturing and acidizing are used.The
global oilfield chemicals market is estimated to value
at ~USD 26,000 million in 2018 and projected to reach
at ~USD 33,000 billion in 2023, at anestimated CAGR
of 4.64% during 2018-2023 (as per internet source).
The demand for the former is driven by the increased
shale gas exploration & production.~Rs. 1500 crore is
a rough estimate of oil field chemicals currently used
in India and it may be more.
The ultimate dream of any oil Asset owner is to
take oil recovery to the levels of a gas reservoir, i.e.
around 80 - 85%. The various improved oil recovery
techniques are able to take the recovery levels to 40%
and in some of the cases beyond that, even to the
level of 55%. But, in many of the cases, these levels
are restricted to ~20 – 35%. Science and engineering
together can play a big role in bringing the recovery
to higher levels from the existing brown fields and
understanding of chemistry and use of chemicals will
definitely play a big role in this direction.
Indian Oilfield Chemistry Conference 2018 is the first
of its kind endeavour in India with the objective of
bringing together Oilfield Operators, Chemicals
Users/Manufactures/Suppliers and Researchers. The
conference will provide an opportunity for sharing
wisdom, knowledge, and information among the
operators in different fields of India as well as with
operators from other parts of the world. This may
provide a way forward and solutions of several field
problems and provide insight into “why the things
are happening this way”. I am hopeful that the
cooperation of all the supporters and participants will
help in achieving the objectives of the conference.
Dr. Anil Bhardwaj
Convener & Chief of Technical Committee
Ex-GGM, ONGC
Dignitaries of
Inaugural Session
Mr. Pramod Kumar Sharma
Director (Operations)
Oil India Limited
Mr. Sanjay Kumar Moitra
Director (Onshore)
ONGC
Prof. (Dr.) G. D. Yadav
Vice Chancellor
Institute of Chemical Technology
Mumbai
Prof. (Dr.) R. K. Khandal
President
(R&D and Business Development)
India Glycols
IOFC 2018 || 03

4. IOFC Technical Agenda
Day 1: 27th
September 2018
08.30 – 09.30 Registration
09.30 – 11.00 hours Session 1
Session 1: Inauguration and Opening Ceremony (09.30-11.15 hours)
09.30 - 11.15 Inauguration & Opening Ceremony
• Lamp Lighting Ceremony
• Welcome Address by Dr. Anil Bhardwaj, Convenor & Chief of Technical Committee, Ex-GGM, ONGC
• Modern Trends of Innovation in Oilfield Chemicals” Prof. (Dr.) R. K. Khandal, President(R&D and Business Development),
India Glycols
• Keynote Address by Padam Shree Prof. G. D. Yadav, Vice Chancellor, Institute of Chemical Technology, Mumbai
• Address by Guest of Honour, Mr. P. K. Sharma, Director (Operations), Oil India
• Address by Chief Guest, Mr. S. K. Moitra, Director (Onshore), ONGC
• Vote of Thanks & Opening of the Exhibition
11.15 – 11.45 Tea /Coffee Break
Hall A (11.45 – 13.00) Hall B (11.45 – 13.15)
Session 2A: Enhanced Oil Recovery Session 2B: Miscellaneous – I
11.45-12.05 “Challenges in Selection and using of
Production Chemicals with CEOR Operations during
Polymer Breakthrough Phase”
- Mr. V. Panneer Selvam, Consultant (Technical Services), Cairn
Oil & Gas, VEDANTA
12.05-12.25 “Evaluation of Associative and Sulphonated
Polymer for Chemical Enhanced Oil Recovery at High
Temperature and High Salinity Conditions”
- Dr. Mrinmoy Biswas, Chemist, Institute of Reservoir Studies
12.25-12.45 “EOR Materials : Market Growth Trends &
Changing Landscapes”
- Mr. Pravir Shah & Ms. Manasi Patil, Head-Sourcing Strategy
and Execution & Category Manger : Chemicals, Baker Hughes,
a GE company
12.45-13.00 Open Discussion & Q/A
11.45-12.05 “Chemical Management System (CMS)”
- Mr. Brian Jobson, Project Director, Nalco Champion Dai-ichi
12.05-12.25 “Impact Zone Assessment Due to Loss
of Containment of a Hazardous Utility Chemical in a
Petroleum Process Plant”
- Dr. U. K. Chakrabarty, Dy General Manager (P) /I/C Risk &
Safety Division ONGC, IPSHEM, Goa
12.25-12.45 “H2S Scavengers vs the Chemistry of
Sour Water Sweetening – Technological Advances for
Improving Desulphurization of H2S from Sour Water”
- Mr. Sheldon McKee, Director Business & Product
Development, AMGAS
12.45-13.05 “TiO2 Assisted Stable Silica Nano-fluid of
an Oilfield Polymer Polyacrylamide (PAM) for Oilfield
Application”
- Mr. Ravi Shankar Kumar, Rajiv Gandhi Institute of Petroleum
Technology
13.05-13.15 Open Discussion & Q/A
1300 – 1400 hours Lunch
Hall A (14.00 – 15.30) Hall B (14.00 – 15.30)
Session 3A: Chemistry in Well Services – I Session 3B: Microbiology in Upstream Oil & Gas Industry
14.00-14.20 “Stimulation of Oil Well in Upper Assam Basin
using Acids and Solvents – A Case Study”
- Mr. Uttam Prodhan, Sr. Research Scientist, R&D Department,
Oil India Limited
14.20-14.40 “Developing the Water Foamer for Design of
Foam Fracturing Fluids in Hydro Fracturing Operations for
Sub Hydrostatic Wells”
- Major Janeshwar Prasad, Deputy General Manager
(Chemistry), IDT, ONGC, Dehradun
14.40-15.00 “High Throughput Screening Investigating
Rheology and Temperature Effect of Different Co-
Surfactants on Zwitterionic Visco-Elastic Surfactants”
- Mr. Hans Oskarsson, Technical Service Manager, AkzoNobel
Surface Chemistry
15.00-15.20 “Dewaxing Operation in Oil Field by Coiled
Tubing Unit”
- Mr. Debanuj Khound, Superintending Engineer (OGPS)WSS
WSS, Oil India, Duliajan
15.20-15.30 Open Discussion & Q/A
14.00-14.20 “Aromatic Plant Essential Oils as Green
Biocides for Oil Field Produced Water Treatment”
- Dr. Ranjan K. Bhagobaty, Deputy Chief Research Scientist,
R&D Department, Oil India Limited
14.20-14.40 “Compatibility Studies of Natural Gas and
Its Impurities Limiting Which Impacts Integrity of Gas
Transmission Pipelines Via Physical, Chemical And Bio-
Chemical Behaviour of Debris and New Approach of
Biological Measurements in Pipe Line Industries”
- Mr. P. Kombaiah, Sr. Mgr, GAIL KG Basin, A.P
14.40-15.00 “Potential Efficacy Assessment of Generic
Biocides for Improved Microbial Treatment in Water
Injection Systems”
- Ms. Archana, Sr. Chemist, RGL Panvel, ONGC
15.00-15.20 “Microbiologically Influenced Corrosion
(MIC) in Petroleum Pipelines”
- Mr. Sahab Singh Gurjar, Manager- Asset Integrity , Cairn Oil
& Gas, Vedanta Limited
15.20-15.30 Open Discussion & Q/A
04 || IOFC 2018

5. 15.30- 16.00 Tea /Coffee Break
Hall A (16.00 – 17.30)
Session 4: Miscellaneous - II
16.00-16.20 “Novel Approach for Measurement of Corrosivity of Acidic Crude Oils”
- Mr. Biswajit Shown, General Manager, R&D Centre, Reliance Industries, Jamnagar
16.20-16.40 “LOCAT–Process for Converting Toxic Hydrogen Sulfide Gas into Elemental Sulfur for Safe Disposal of
Acid Gases: A Case Study of Hazira Plant”
- Dr. J. K. Srivastava General Manager - Head Quality & Process Control Laboratroy, Hazira Plant, ONGC
16.40-17.00 “Evaluation Identification of Hydrogen Sulphide Scavenger to Mitigate H2S Problem in Mumbai Offshore”
- Dr. (Mrs). Jharna Jana, Chief Chemist, ONGC, Panvel
17.00-17.20 “Optimized Modeling of 5-Lumped Fluid Catalytic Cracking Riser Reactor using Polymath”
- Mr. Mohammad Shadab Alam, Department of Chemical Engineering, Zakir Hussain College of Engineering & Technology,
Aligarh Muslim University
17.20-17.30 Open Discussion & Q/A
17.30-18.30 Visit to the Exhibition
18.30-21.00 Dinner
Day 2: 28th
September 2018
08.30 – 09.30 Tea/ Coffee
Hall A (09.30 – 11:15) Hall B (09.30 – 11:15)
Session 5A: Research and Trends in Drilling Fluids
Session 5B: Water Management in Upstream Oil & Gas
Industry
09.30-09.50 “THERMADRIL and BARADRIL-NX fluid
systems”
-Mr. Mayuresh Dhavle, Drilling fluids engineer, Halliburton
Offshore Inc.
09.50-10.10 “Design and Development of Various Density
Clear Completion Fluids for Drilled Shale Gas / Oil Wells
and Evaluated From 120˚C to 160˚C”
-Major Janeshwar Prasad, Deputy General Manager
(Chemistry), IDT, ONGC, Dehradun
10.10-10.30 “Newly Designed K2SO4-PHPA Inhibitive
Mud System to Drill Reactive Shale Formation”
- Mr. Amlan Buragohain, Sr. Chemist, Chemical Department,
Oil India Limited
10.30-10.50 “Evolving Rheology of Oil-based Drilling
Muds/Fluids”
Dr. Sandeep Kulkarni, Associate Professor, IIT Kharagpur
10.50- 11.10 “Role of Carbon Based Nano-Fluid in
Enhancing the Properties of Drilling Fluid’
- Mr. Rakshit Pareek, Rajiv Gandhi Institute of Petroleum
Technology
11.10- 11.15 Open Discussion & Q/A
09.30-09.50 “Thin Film Composite (TFC) Membrane in
Water Injection Operations - A Potential State-of-Art
Technology for Secondary Oil Recovery”
- Dr. P.K. Mahata, Deputy General Manager (Chemistry)
ONGC Onshore Gas Terminal, ONGC Onshore Gas Terminal,
Andhra Pradesh
09.50-10.10 “Failure Analysis of Carbon steel Sub Sea
Water Injection Pipeline”
- Mr. Bipin Kumar, Dy. General Manager (Mech.) Materials and
Corrosion Section, IEOT, ONGC
10.10- 10.30 “Effect of Concentration, Temperature
and Flow Rate on the Reduction of Permeability in the
Reservoir due to Scaling Effect”
- Prof. Tarkeshwar Kumar, Professor, Department of Petroleum
Engineering, IIT (ISM), Dhanbad
10.30- 10.50 “Development of a New Protocol for
Evaluation of Scale Inhibitor and Effective Management
of Scale Inhibition – A Case Study”
- Mr. Bijan Mahanta, Superintendent Research Scientist
R&D Department, Oil India
10.50- 11.10 “Scale Treatment in Heat Exchangers-A Case
Study’
- Mr. Alok Dwivedi, EE(P), ONGC Panvel
11.10- 11.15 Open Discussion & Q/A
11.15 – 11.45 Tea /Coffee Break
Hall A (11.45 – 13:15) Hall B (11.45 – 13:15)
Session 6A: Crude Oil Treatment Session 6B:Miscellaneous – III
11.45–12.05 “Challenges in Desalting Process”
- Mr. Srikanth Jampa, AVP, Ion Exchange (India)
12.05-12-25 “The Science Engineering and Art of Breaking
a Crude Oil Emulsion”;
- Dr. A. K. Saxena, Ex General Manager (Chemistry), ONGC
Vadodara
11.45–12.05 “Assessment of Marine Environment by
Analyzing Petroleum Hydrocarbon Content in Sediment
–A Case Study around Sediments of Western Offshore of
Mumbai High, ONGC”
- Mr. G. L. Das, DGM (Chemistry), IPSHEM, ONGC, Goa
12.05- 12-25 “Importance of Fluid Properties in the
Selection of Artificial Lift Mode”
- Mr. Saurabh Rajvanshi, Executive Engineer (Production)
ONGC, Panvel
Technical Agenda
IOFC 2018 || 05

6. Hall A (11.45 – 13:15) Hall B (11.45 – 13:15)
Session 6A: Crude Oil Treatment Session 6B:Miscellaneous – III
12-25-12.45 “Studies on Heavy Crude Oil/Emulsions
Viscosity and Correlation Development by using Bio-
Additive”
- Dr. Tarun Kumar Naiya, Assistant Professor Department of
Petroleum Engineering, IIT (ISM), Dhanbad
12.45- 13.05 “Crude Oil Treatment Strategies based on
Crude Emulsion Characteristics to Ensure Flow Assurance
– A Case Study”
- Mr. Rajarshi Panigrahi, Superintending Research Scientist
R&D, Oil India
13.05 – 13.15 Open Discussion & Q/A
12-25- 12.45 “Synergy of Polyacryloyl Hydrazide (PAHz)-
Ag NPs on Drying and Re-dispersibility of Pickering
Emulsions for Transportation and Storage Applications”
- Mr. Ramesh Narukulla, Rajiv Gandhi Institute of Petroleum
Technology
12.45- 13.05 “Experimental Studies on the Flow Behavior
of Polyethylene glycol(PEG 3000) polymer”
- Ms. Yusra Hamid, Department of Chemical Engineering,
Zakir Husain College of Engg. & Technology, Aligarh Muslim
University, Aligarh
13.05 – 13.15 Open Discussion & Q/A
1300 – 1400 hours Lunch
Hall A (14.15 – 15.45) Hall B (14.15 – 15.45)
Session 7A:Chemistry in Well Services – II
Session 7B: Problems and Solutions for Flow Assurance
of Viscous and Waxy Crude Oils
14.15- 14.35 “Water shut-off technology with the
application of sediment forming chemical TAMOLEX®
characterized with the selective action in water saturated
interlayers”
- Mr. Alexey Mokrushin, Business Development Manager,
POLYEX jsc, Russia
14.35- 14.55 “Invert Emulsion-An Improved Friction
Reducer for Hydraulic Fracturing”
- Ms. Saroj Chaudhary, Chief Chemist, IOGPT, ONGC, Panvel
14.55-15.15 “Innovative Substitute for KCl as Clay
Stabiliser”
- Ms. Sudipta Biswas, Suptdg Chemist, IOGPT, ONGC, Panvel
15.15-15.35 “Acidizing Sandstone Formations using
Alcoholic Fluoboric Acid at High Temperature in Gas
Reservoir”
- Mr. Ganesh Mhaske, Superintending Engineer (Production),
IOGPT, ONGC, Panvel
15.35- 15.45 Open Discussion & Q/A
14.15- 14.35 “Novel low temperature stable paraffin
inhibitors for improved flow assurance solutions”
- Mr. Shekhar Khandekar, Sr.Manager– R&D, SI Group
14.35-14.55 “A Novel Solvent Formulation for Flow
Assurance- A Case Study from Kathana Filed of Cambay
Asset”
- Mr. K. C. Rajput, Chemist, Cambay Asset, ONGC
14.55-15.15 “Differences in Crystallisation Dynamics
and Crystal Morphology of Microcrystalline and Macro-
Crystalline Waxes from Mineral Oils”
- Ms. Jyoti R. Seth, Assistant Professor, Department of Chemical
Engineering IIT Bombay
15.15-15.35 “Effect of Natural Extract as a Viscosity
Reducer in Crude Oil Transportation”
- Mr. Biswadeep Pal, Department of Petroleum Engineering,
IIT (ISM) Dhanbad
15.35- 15.45 Open Discussion & Q/A
15.42- 16.15 Tea /Coffee Break
Hall A (16.15- 17.30)
Session 8:
Panel Discussion and Valedictory Session : Smart & Intelligent Use of Oilfield Chemicals and Upcoming Trends
Technical Agenda
06 || IOFC 2018

8. Participating Companies
Media PartnersSpecial Acknowledgement
Gold Partners
Participating Companies
Lanyard Partner Branding Partners
08 || IOFC 2018

9. Tittle: “Challenges in Selection and using of Production
Chemicals with CEOR Operations during Polymer
Breakthrough Phase”
- Mr. V. Panneer Selvam, Consultant – Technical Services, Cairn
Oil & Gas Vedanta Ltd.
ABSTRACT
Enhanced Oil Recovery is important stage of life cycle of a field
and often it is implemented with challenges. In the chemical
EOR, challenges and surprises are expected in production
chemistry and production facilities operations. Partially
hydrolyzed poly acrylamide used widely for controlling mobility
ratio so that Operator is able to recover maximum possible oil.
With complex water chemistry and rich in positively charged
divalent ions, flooded polymer having negative charge interacts
with divalent ions of produced water. While back produced
sheared polymer interacts with divalent ions to form semi hard
to hard scales poses challenges of the reliability of production
facilities. Other important limitations to be noted CEOR phase
are in using production chemicals to control scale, emulsion
and microbial treatment under Hydrogen Sulphide and waxy
crude environment.
This paper discusses about the requirement of
preparedness and how to overcome challenges of EOR
operations and handle the back produced polymer in following
areas: a) Selection of production chemicals to be compatible
to polymer so that no degradation or loss of viscosity due to
polarity of chemicals, b) Influence of contaminants such as
OxygenandHydrogenSulphideinpolymersolutionpreparation
and flooding, c) Performance of production chemicals in the
presence of polymer, d) Solids loading in production system
post polymer breakthrough in production, e) Emulsion and
produced water treatment with back produced polymer, f)
Suitability of produced water treatment facilities with back
produced polymerized water, g) Revised scaling control with
back produced polymer with rich divalent ions present in
produced water, h) Strategizing chemical management system
to suit polymer flood and polymerized back produced water
treatment regime
This paper indicates the experience of reinjection of
polymerized water, requirement of good understanding of
testing methods and continuous revisions of them, this is
mainly most of the injection water quality test methods are
standardized for water flood cases and facilities usually
designed for non- polymeric water treatment. Often it requires
using new quality monitoring methods and techniques for
water quality management, as standard methods used for
water flood may not be valid during polymer flood. Similarly
produced water treatment facilities modifications are inevitable
unless they are designed to handle back produced polymerized
water with the consideration of higher water viscosity and solid
loading if the produced water is rich of divalent ions.
Tittle: “Evaluation of Associative and Sulphonated Polymer
for Chemical Enhanced Oil Recovery at High Temperature
and High Salinity Conditions”
- Dr. Mrinmoy Biswas, Mr. Ravisantosh Kumar Mavoori,
Mr. Ankit Hanotia, Mr. Supriyo Samanta, Mr. Adarsh Kumar
Jain, Ms. Padmaja Mattey and Mr. Swapnil Pancholi, Chemical
EOR Laboratory, Institute of Reservoir Studies, Ahmedabad
ABSTRACT
The demand for energy requires increasing production of
crude oil while maintaining acceptable cost levels. In order to
exploit hydrocarbon resource left behind after the application
of conventional technology enhanced oil recovery come into
play. As all EOR processes are reservoir specific, screening is
mandatory to evaluate best EOR technique. Chemical EOR is
very unique where success of EOR in reservoir depends on the
chemical formulation optimized.
Polymer flooding is one of many chemical EOR processes
in which brine solution of polymer (250-2000 ppm) is used in
water flood operation. The goal is to lower the mobility of
flood water by increase in viscosity and decrease in relative
permeability. Polymer does not lower the residual oil saturation,
but it increase oil recovery as a result of improved sweep. The
long polymer chains entangled to decrease water mobility
and enhance resistance factor. The mobile oil saturation must
be reasonably high to afford economic potential for polymer
injection. However, many complicating factors such as viscosity
drop due to high salinity, thermal and mechanical degradation
of polymer, gel formation, adsorption etc. affect the success of
the process. Commercial practices are also underway in several
areas around the world due to relatively simple cost effective
setup than EOR methods. Currently, polymer flood has been
conducted in large scale in China for light to medium oils and
Canada in medium to heavy oils.
Polymer flood using cheap synthetic polyacrylamide is
an effective way, in spite of elevated temperature (>80°C), low
permeability and divalent ions limiting the scope of using it
in good potential field. Delicate structural engineering of the
PHPA chain backbone for enhanced robustness can widen the
threshold in reservoir application. Thus copolymerization with
other monomers (i.e. terpolymer) or hydrophobic association
in chain segment (associative polymer) comes into existence.
The copolymerization enhances the thermal and divalent
ion tolerance, whereas the associative polymer restricts the
viscosity drop in saline environment. Represented samples of
sulphonated copolymer and associative polymer along with
conventional PHPA polymer sample are considered on the
basis of comparable apparent viscosity in normal soft brine.
Detail characterization and evaluation of property of this new
kind of polymers is performed based on thermal stability,
rheology and divalent ion tolerance at high temperature (90°C)
and high salinity (>3.5% as NaCl& 0.2% hardness) conditions
with respect to conventional polymer. The efficiency statistics
of those synthetic polymers in the harsh condition can
categorizes them; add more value in chemical EOR research,
which is still overlooked.
Tittle: “EOR Materials: Market Growth Trends and Changing
Landscapes”
- Mr. Pravir Shah and Ms. Manasi Patil, Baker Hughes, a GE
Company
ABSTRACT
With 30% average yearly decline in petroleum discoveries in
last 5 years and 70% of the world production coming from
Mature Fields older than 30 years, it is believed that Enhanced
Oil Recovery (EOR) methods will play a major role in meeting
energy security in the future. Technological Advancements in
Abstracts
IOFC 2018 || 09

10. EOR have been growing due to this in the last two decades.
Diverse case-studies on EOR Projects executed in India and the
world namely China’s Gudong(1992), La Salina in Venezuela
(2001) and Cairn’s Barmer(2014) are analyzed; detailing the
chemical formulation, dosage and consumption of materials
used in the process. The data is also used to construe the
growth and capability enhancement of the ASP chemical
manufacturers in the respective regions like Henan (China),
Lagomar (Venezuela) etc.
This paper also draws a parallel between the World and
India for EOR Projects. The country’s numerous aging oilfields
anduntappedpotentialfortertiaryrecovery,coupledwithIndian
government’s new “Energy security” Policy (2018) is providing
a conducive environment to Operators for undertaking ER, EGR
and EOR. Various Indian Oil companies have planned multi-
billion CAPEX over next 5 years to meet Indian government’s
goal to cut oil & gas imports by 10%. This paper illustrates
few of the ongoing EOR projects and the opportunity to
grow ASP supply chain in India. The paper comments on the
prevailing chemistry, application and formulation techniques
to develop capabilities of Indian manufacturers. The effort is
to list down capability requirements, capital investments and
perform a GAP analysis between Indian manufacturers and the
best-in-class. The aim of this paper is to showcase EOR related
opportunities for developing manufacturing capabilities in the
region, for India and for the world.
Tittle: “Chemical Management System”
- Mr. Brian Jobson, Project Director, Nalco Champion Dai - ichi
ABSTRACT
An integrated team model approach that provides unmathched
onsite support and access to local technical support; to regional
product line, application and field support specialist, and to a
global network of the industry’s top scientists and researchers
and their combined best practices. An early collaboration
influences both CAPEX spend and OPEX cost.
Design Phase: Project management and design teams
contribute chemical and engineering design and development.
Commission: Prior to commissioning, account
management teams begins process safety, inventory,
manpower, system monitoring and service planning.
Start up: teams work out in tandem to execute plans,
assure compliance and complete all necessary field and lab
testing to authenticate data.
Production: Account managers continue routine
rotational schedules, providing technology support, inventory
management and reporting.
Tittle:“ImpactZoneAssessmentDuetoLossofContainment
of a Hazardous Utility Chemical in a Petroleum Process
Plant”
- Dr. U. K. Chakrabarty, Institute of Petroleum Safety, Health &
Environment Management, ONGC Goa
ABSTRACT
A few years back, a petroleum process plant in the western India
suffered a huge agitation from the surrounding population due
to complaints of a pungent odour and health symptoms from a
suspected leak of known odourising chemical ‘Ethyl Mercaptan’
that the company is mixing with the LPG for household leak
detection purposes. The process plant regularly use ethyl
mercaptan (having both toxic and flammable characteristics)
stored in 200 litres drums for dosing in to the LPG storage in
Horton spheres. The plant management carried out a detailed
consequence analysis considering different release scenarios
from the drum and the dosing system and declared that the
incidents of odour problem faced by the local population is
actually symptomatic and a nuisance, but no adverse effects
on health is anticipated as the exposure concentration of
surrounding people is well below the threshold value. The
American Conference of Governmental Industrial Hygienists
(ACGIH) recommended the average concentration of airborne
methyl mercaptan which should not be more than 0.5 ppm
for every 8-hour exposure (time-weighted average) in a 40-
hour work week. Following World Bank Release Criteria, the
paper presents the “worst case release scenario” and the
“alternative case release scenarios” for both flammable and
toxic consequences endpoints using ALOHA. The worst case
scenario involves the release of the maximum inventory of
Ethyl Mercaptan in accordance with the guidelines specified.
The scenario assumes the instantaneous failure of the Ethyl
Mercaptan containment. The credible alternative scenarios
could be the release of Ethyl Mercaptan as a result of a
puncture in the containment or breakage of a 2-inch Ethyl
Mercaptan dosing pipeline. The analysis of the alternate case
scenarios could be better used for launching proper emergency
responses to mitigate the adverse effects of the chemicals on
the people. In addition, the paper attempts to establish the
fact that the perception of an odour, rather than an actual
chemical exposure, may have a role in the development of
health complaints from the members of public residing within
1 km and 2 km radii of the process plant. However, plant
management need to take adequate lessons from the incident
and redesign its Process Safety Management (PSM) including
emergency response system to mitigate the effects and quickly
bring any release situation under control through periodic
interactions and safety awareness of the public.
Tittle: “H2
S Scavengers vs the Chemistry of Sour Water
Sweetening –Technological Advances for Improving
Desulphurization of H2
S from Sour Water
- Mr. Sheldon McKee, Director – Business & Product
Development, Mike Shields, Ph.D., P.Chem. Senior Scientific
R&D Associate, AMGAS
ABSTRACT
Development of improved H2
S removal technologies from
both crude oil and process water streams has the potential
to be incorporated into many projects across the global
oil & gas industry. Entrained H2
S contained within these
fluids produces nuisance odors and poses safety handling
risks, thus making the prevention of free H2
S releases to
atmosphere very important prior to the fluids arriving at their
final destination). Low tonnage H2
S processing strategies for
treating sour fluids focus on direct treating the liquid using
a consumable wet chemical triazine formulation. Although
such chemical addition methods have proven effective at
eliminating free H2
S by converting it to a stable organo-
sulfur reaction product, drawbacks of this approach include
high chemical consumptions and/or aggressive scaling on
process internal surfaces. In higher tonnage H2
S management
projects, traditional stripper tower packages are usually the
technology of choice in order to lower the operating costs in
the project over time. Although being proven and effective, the
drawbacks associated with stripping towers include the cost of
Abstracts
10 || IOFC 2018

11. construction and/or the lack of mobility when working outside
of a plant/facility setting. Viewing these drawbacks from both
direct chemical treating and stripping towers as a challenge
from industry, our group investigated and developed a
unique, new process strategy for efficiently sweetening sour
fluids (crude oil and water) in a variety of job scopes across
a broad range of H2
S tonnages in the oil & gas industry. Our
paper highlights the AMGAS CLEAR™ technology for use in
the desulphurization of H2
S from sour water. The equipment
package associated with the technology for removing the H2
S
from the sour fluid will be described, highlighting the operation
of various components of the system. Process flow diagrams
and schematics will show how the desulfurization technology
can be combined with multiple sulfur recovery technologies
for processing the H2
S off the system, depending on the
quantity of H2
S being managed. Such technologies include
the use of consumable chemicals for low H2
S tonnage projects
but will also describe how regenerable wet redox chemicals
Case studies will be presented showing the OPEX savings vs
traditional H2
S scavenging system.
Tittle: “Tio2
Assisted Stable Silica Nano-fluid of an Oilfield
Polymer Polyacrylamide (PAM) for Oilfield Application”
- Mr. Ravi Shankar Kumar and Mr. Tushar Sharma, Enhanced
Oil Recovery Laboratory, Rajiv Gandhi Institute of Petroleum
Technology
ABSTRACT
Silica nanofluids, as advanced nanomaterials, offer significant
advantages in various applications including oilfield industry.
The high surface area to volume ratio, better dispersion
stability, and most abundancy in earth layers of silica NPs make
its nanofluid more applicable in oil and gas industry. However,
silica NPs (being solid in nature) tend to sediment with time and
as a result, nanofluid is hardly left with NPs to work. In addition,
silica NPs possess high surface energies which causes them to
aggregate and form clusters which is further responsible for
premature sedimentation making nanofluid unstable fluid.
Therefore, a stable nanofluid possessing significant dispersion
stability and reduced size of NP clusters is a prerequisite for
better performance. In this study, we report the use of TiO2
NP
(0.05 wt% and 0.1 wt%) to improve the dispersion stability of
silica nanofluid [0.5 wt% SiO2
in 1000 ppm aqueous phase of
PAM] by controlling the homo-aggregation between SiO2
-
SiO2
NPs. PAM is an oilfield polymer and used as viscosifier,
with typical oilfield concentration of 1000 ppm, to increase
the viscosity of bulk nanofluid phase. Increasing viscosity of
nanofluid phase reduces the extent of NP sedimentation. The
effect of TiO2
on stability and properties of SiO2
nanofluid was
envisaged through various techniques such as SEM, EDS, DLS,
Electrical conductivity, and rheology, and results are discussed
and reported accordingly. It was found that the slight addition
of the TiO2
NP as a co-stabilizer significantly improved the
dispersion stability of silica nanofluid by more than two weeks.
Tittle: “Stimulation of Oil Well in Upper Assam Basin using
Acids and Solvents – A Case Study”
- Mr. Uttam Prodhan, S. Purohit, Debarati Dey and M. C.
Nihalani, R&D Department, Oil India Limited
ABSTRACT
Formation damage, resulting from crystallization and
deposition of paraffin wax along with mineral scale and/or
asphaltenes leading to permeability changes or wettability
changes arising out of water loading / emulsion blockage,
within the reservoir or near wellbore is a recurrent production
problem. Among the well stimulation processes, acidization
is one of the oldest techniques still prevalent in recent times.
The success of the stimulation operations mainly depends on
the proper selection of acid types along with suitable additives
and the ability to inject a sufficient quantity of the acid-solvent
mix of interest into the desired target zone. An understanding
of the capabilities and constraints of the acids and readily
available solvents along with the information from laboratory
results and field interventions aids in the proper selection of
the acid-solvent mix for stimulating producing wells.
Crude Oil produced from some of the fields in the Upper
Assam Basin have shown considerable amount of organic
deposits in the tubing of the well and other production setups.
Repeated scrapping jobs are periodically required to clean the
tubing string. SARA analysis of the samples produced from
these fields also shows quite huge percentage of asphaltene
content. Despite having good initial FBHP and production
rate, over a period of time alarming rates of decrease in
production rate and pressure drop is observed in many of
the wells. Conventional matrix acidization in these wells may
lead to further damage in the formation due to formation
of precipitates and emulsions. Therefore, a thorough study
of the reservoir properties as well as the compatibility of
the stimulation fluid with the reservoir is required before
proceeding for the job.
The present study presents the causes of near wellbore
damage due to organic deposits, laboratory testing of the
samples, selection of candidate wells, designing of a suitable
recipe using readily available chemicals and field execution
of the designed job with the help of a case study on the
stimulation of an oil well, which was carried out using HCl and
Diesel oil mixed with other solvents as additives. The designed
recipe has been successfully implemented in few oil wells and
is planned to be executed in other wells.
Tittle: “Developing the Water Foamer for Design of Foam
Fracturing Fluids in Hydro-fracturing Operations for Sub
Hydrostatic Wells
- Major Janeshwar Prasad, IDT, ONGC
ABSTRACT
Hydraulic Fracturing is the process of fracturing or enhancing
the permeability of the formation where the production has
been declined by means of injecting the pressurised fluid
into the formation. This pressure plays a vital role here in this
process where the fluid which is pumped with a pressure which
can make a way in to the formation. The use of a proppant,
can be explained in a straightforward way as a medium which
lets the fractures or the permeability remain open after the
fracturing. Several types of Hydro fracturing fluids have been
proposed for several types of conditions of the formation.
The Present work also describes and explains the
role of hydraulic fracturing, its objectives, Mechanisms and
particularly the condition where the hydrostatic pressure of
the well is reduced. These wells are termed as “Sub Hydrostatic
wells” and Foam based Hydro Fracturing Fluid is used for these
kinds of wells.
Foam, as a Hydro Fracturing Fluid, enhance the
productivity of Hydrocarbons in a tight formation, Water cannot
be used a fracturing fluid, as it can lead to swelling problems in
Abstracts
IOFC 2018 || 11

12. the well. So, a foam based fracturing fluid has been developed.
The stability of the foam has been experimentally studied to
carry the proppant within and to place it within the induced
permeability created within the job time. Different foaming
agents and gelling agents were analysed and extensive studies
have been carried out to design the suitable hydrocarbon
fracturing fluid. Foam Fracturing Fluids provide means to
reduce water consumption by replacing most of the water used
in fracturing jobs by gases like N2 or CO2 and they also have
potential to provide the well productivity, proppant placement,
and clean-up and also prevent the reservoir damages. In this
article it is described about the development of the water
foamer for hydro fracturing in sub hydrostatic wells and tight
reservoirs. Different water foamers evaluated in Laboratory
and based on the studies, on Flow Behavior Index, Consistency
Index, Foam Quality, Viscosity, Thermal stability, Miscibility,
Ionic nature, proppant settling and carrying capacity, the
foamers which are suitable for designing the hydro fracturing
fluid in sub hydrostatic wells and conclusion is given based on
the results.
Tittle: “High Throughput Screening Investigating Rheology
and Temperature Effect of Different Co-Surfactants on
Zwitterionic Visco-Elastic Surfactants”
- 1)Hans Oskarsson, 2)Martijn Smout, 2)Boen-Ho O, 3)
Lingling Li, 4)Mohammad Areeb Siddiqui1) AkzoNobel Surface
Chemistry AB, Sweden, 2)AkzoNobel Research Development &
Innovation, Netherlands, 3)AkzoNobel Surface Chemistry LLC,
United States, 4)AkzoNobel Surface Chemistry, Dubai
ABSTRACT
Visco-elastic surfactants (VES) are widely used for different
purposes in oil and gas-well stimulation operations. This visco-
elasticity occurs when conditions are changed and the micelles
become cylindrical in structure and are behaving like polymers.
Transforming the micelle structure from spherical into these
cylindrical structures or vice versa allows for changing the
fluid flow or rheology properties. This rheology “on-off”
functionality makes the VES concept ideal for oil and gas-well
stimulation both due to the ability to direct the visco-elasticity
by diversion and triggers as electrolyte and temperature for a
viscoelastic on-set and to be able to turn off the effect to avoid
formation damage by triggers as solvents or surfactants just to
mention some of the most common methods.
Another factor affecting the formation of cylindrical
micelles is the presence of other surfactants as they form mixed
micelles. A typical formulation for the stimulation operation
may contain a number of different surface active compounds
such as corrosion inhibitors and chelants for iron control.
Also surface active wetting agents are commonly added
to alter the nature of the surface of the formation together
with non-emulsifiers and sometimes dispersants for sludge.
Mixtures of surfactants will form mixed micelles which may
have different micelle geometry (and not be the cylindrical
micelle). This will affect the visco-elastic fluid properties
profile, such as operation temperature interval, maximum
viscosity, and elastic properties important for particle
suspension just to mention some of the important properties
of the fluid. To understand mixed micelles of visco-
elastic surfactants and other surfactants used in a typical
stimulation formulation and its implication on rheology,
different combinations and tests need to be executed/
performed to find the right combinations. In order to
accelerate such experimentation a high throughput screening
technique has been developed using a robot for sample
preparation, rheology and surface chemistry measurements.
The high-throughput screening technique used to
develop optimized stimulation fluids, the experimental
strategy and rheology aspects will be outlined in this paper
along with surface chemistry aspects of these multi surfactant
formulations and applicability in the oilfield stimulation -
acidizing industry. Concept formulations will be illustrated.
Tittle: “Dewaxing Operation in Oil Field by Coiled Tubing
Unit”
- Mr. Debanuj Khound, WSS, Oil India, Duliyajan
ABSTRACT
Sustaining crude oil production from a mature field is a very
challenging task for an Oil and Gas industry. The primary
cause of wax or paraffin deposition is due to loss in solubility
in the crude oil. This loss of solubility is primarily due to
changes in temperature, pressure, or the composition of
the crude oil as a result of loss of dissolved gases. Crude oil
often contains paraffins which precipitate and adhere to the
production tubing, sucker rods, Electrical Submersible Pumps
and surface equipment as the temperature of the producing
stream decreases in the normal course of flowing owing to
geothermal gradient, gas lifting or pumping. Heavy paraffin
deposits are undesirable because they reduce the effective
size of the flow conduits and restrict the production rate from
the well. Paraffins that have the highest melting point and
molecular weight are usually the first to separate out from the
solution, with lower-molecular-weight paraffins separating as
the temperature decreases further. These deposits are mainly
constituted by n-paraffins and small amounts of branched
paraffins and aromatic compounds. Naphthenic and long
chain paraffins also have a contribution to microcrystalline
waxes and have remarkable influences on macrocrystalline
growing patterns.
In the journey of crude production from reservoir to
processing station, paraffin gets deposited over the time
in the vertical regime as well horizontal regime and causes
problem in down hole as well as surface operations. Paraffin
gets deposited during the process is so hard that it can even
plug the tubing as well as the flow line resulting in a loss
of crude oil production. To remove the wax in the vertical
regime, mechanical scraping is done at an interval suitable for
maintaining the crude oil production. There are instances where
it is not possible to remove wax even by mechanical scraping.
In that scenario, dewaxing is carried out by Coil Tubing
Operation (CTU). The dewaxing operation involves CTU,
Fluid pumping unit with heating facility and other auxiliary
units required for the operation. The fluid medium used
during the operation is Low Wax crude (LWC) produced from
the field.
There are various solvents used in dewaxing operation by
CTU. These solvents are costly and needs extra care for storage
and handling. In Oil India Limited particularly in WSS & ALP
section we are doing dewaxing operation with the involvement
of CTU, FPU Unit for the selected wells where removing of
wax by mechanical scraping operation is not possible in
vertical regime. Dewaxing by using LWC is unique in nature
for the following reasons: (i) It does not have any harmful
effect with produced crude rheology; (ii) It is compatible
with reservoir condition; (iii) It is more economical as
Abstracts
12 || IOFC 2018

13. compared with other solvents used in dewaxing operation.
Since it is a produced fluid during crude oil production, there
is no cost involvement for LWC; (iv) No extra storage and
handling is required for LWC as compared to specific solvents
for which designated storage and handling facilities are
required; (v) It does not have any adverse effect with the
flowing tubing head pressure of well during crude oil
production; (vi) No recovery process of LWC is required from
produced crude, as the LWC can be directly sent to surface
facilities for further processing.
During the process of dewaxing by CTU, LWC produced
in the field is heated to a temperature of 75-80 degree
centigrade and pumped through FPU unit to CTU. The CT is run
in hole with circulation of heated LWC to a maximum depth of
1500-1800M depending upon the crude oil behaviour of the
wells. Various types of down hole CT tools are used during
the dewaxing operation. The principal tool string comprises of
various sizes of gauge cutters and nozzles etc.
The tubing dewaxing by CTU is economical as compared
to well intervention jobs by work over operation in case of
a plugged well. Major advantage of the process is that the
produced crude can be used as LWC depending on their API
and wax content thereby saving a huge amount of money
for chemicals if used instead of LWC. The maximum depth of
tubing dewaxing operation is also well specific. The periodicity
of dewaxing operation depends upon crude rheology and
crude production profile of the wells.
Tittle: “Aromatic Plant Essential Oils as Green Biocides for
Oil Field Produced Water Treatment”
- Dr. Ranjan K. Bhagobaty, Prashant K. Dhodapkar and M. C.
Nihalani, R&D Department, Oil India Limited
ABSTRACT
Aromatic Plants have been known to possess inherent
anti-microbial properties. In the present study, essential
oils of three different locally available species of aromatic
plants, viz., Lemongrass (Cymbopogonflexuosus), Citronella
(Cymbopogonwinterianus) and Patchouli (Pogostemoncablin)
were assayed to determine their inhibitory and anticorrosion
effects on Sulphate Reducing Bacteria (SRB) prevalent in the
produced water of an oil field located in North-Eastern India.
The Minimum Inhibitory Concentration (MIC) of the essential
oils was ascertained using the microdilution susceptibility tests
and was found to range from 50 ppm to 450 ppm. Biocidal
potential of the essential oils was determined by Minimum
Bactericidal Concentration (MBC) assays and were found to be
similar to their respective inhibitory concentrations. Studies on
laboratory grown biofilms in glass and N-80 steel coupons were
carried out and effects monitored using Light and Scanning
Electron Microcopy (SEM). The results obtained indicate that
the essential oils were able to exhibit a significant anti-bacterial
and anti-corrosion effect under the test conditions. Presently,
efforts are ongoing to carry out field scale performance
optimization studies with an objective at developing them as
ecologically safe green biocides for oil field produced water
treatment in the near future.
Tittle: “Potential Efficacy Assessment of Generic Biocides
for Improved Microbial Treatment in Water Injection
Systems”
- Ms. Archana, Ms. Veena Kothe and S. K. Bhattacharya, RGL
Panvel, ONGC
ABSTRACT
Microbial growth in oilfield water systems is known to
cause severe problems including energy losses due to
increased fluid frictional resistances, formation plugging,
souring of oil and gas and microbiologically influenced
corrosion (MIC). The most common method of controlling
microbial growth in oilfield water systems has been
through the application of biocides. While a wide variety
of biocides are available for use in oilfield water systems,
no fool proof guide is available for the selection and
application of micro biocides that can realistically ensure
continuous, effective microbiological control in different
types of systems under a multitude of possible operating
conditions.
As a consequence, there is always a scope for new
and more effective chemistry, better methods of chemical
application, or new inventions. Several parameters, including
antimicrobial efficacy, compatibility with equipment and
other chemical additives and their potential impact on the
environment are all critically important considerations while
choosing a biocide.
The paper documents the studies carried out to
determine the biocidal efficacy of four different products
namely Tetrakish (hydroxymethyl) phosphonium sulfate
(THPS), Tributyl tetradecyl phosphonium chloride (TTPC), 1,5
Pentanedial (Glutaraldehyde) and 2,2, dibromo-3-nitrilo-
proprionamide (DBNPA). These were selected on the basis
of unique properties and high efficacy to control growth of
microorganisms. The Performance test of all the products was
evaluated against General Aerobic Bacteria (GAB) and Sulphate
Reducing Bacteria (SRB). The studies revealed that all the four
products are effective as biocides at a minimum of 50 ppm
dose. Application of these generic biocide products in oil fields
may provide better microbial control, more cost efficiency and
environment protection.
Tittle: “Microbiologically Influenced Corrosion (MIC) in
Petroleum Pipelines”
- Mr. Sahab Singh Gurjar, Cairn Oil & Gas, Vedanta Limited
ABSTRACT
MIC is corrosion process affected by the presence or activity (or
both) of microorganisms in biofilms on the internal surface of
petroleum pipeline transporting multiphase liquids, crude oil,
Wet Gas, white products etc. MIC typically takes place in the
presence of microbial consortia that are comprised of more
than one physiological type of microorganism. Depending on
the environment, these microbes may include metal-oxidizing
bacteria, sulfate-reducing bacteria /prokaryotes (SRB/P), acid-
producing bacteria (APB), metal-reducing bacteria (MRB), and
methanogens that interact in complex ways within the structure
of biofilms. MIC can result in pitting, crevice corrosion, under-
deposit corrosion, and de-alloying, in addition to galvanic
corrosion.
This paper discusses the corrosion mechanism,
threat assessment, field detection, field sampling,
laboratory analytical methods, analysis of field / laboratory
results, probability of MIC in pipelines based on field /
laboratory investigations, mitigation / control measures,
monitoring, biocide injection to control the MIC etc.
to enhance the awareness among the field engineers to
control /mitigate the failure which may takes place
due to MIC.
Abstracts
IOFC 2018 || 13

14. Tittle: “Novel Approach for Measurement of Corrosivity of
Acidic Crude Oils”
- Mr. Biswajit Shown, General Manager, Research &
Development Centre, Reliance Industries, Jamnagar
ABSTRACT
Processing of high acidic crude oil is one of the major
contributors for increasing gross refining margin due to its
substantial price difference with non / low acidic crude oils.
Acidity of crude oil is mainly due to presence of Naphthenic
acid and generally expressed by the parameter Total Acid
Number (TAN). A well-known refining problem during
processing of acidic crude oil is high temperature naphthenic
acid corrosion in crude distillation units. Naphthenic acid
corrosion are generally pitting in nature and its severe attack
occurs at ~200–400°C temperature & high velocity areas of
heat exchangers, heaters, distillation columns, transfer lines,
etc. Naphthenic acid corrosion cannot be correlated with only
acidity (TAN value) of crude oil. It is also dependent on the
structure, molecular weight, and boiling point of naphthenic
acids. So it is very much important to quantify naphthenic acids
in crude oil and measure its corrosivity using various modern
analytical techniques e.g. FTIR, GCMS, NMR, FTICR, etc. and
lab scale corrosion measurement. In this paper chemistry of
naphthenic acids, its impact on refinery process equipment and
measurement techniques of actual corrosivity of acidic crude
oil has been discussed which will help refiners to process more
high acidic low corrosive opportunity crude oils to increase
profitability as well as increase reliability of refinery equipment
and proper utilization of costly chemicals.
Tittle: “LOCAT–Process for Converting Toxic Hydrogen
SulfideGas into Elemental Sulfurfor Safe Disposal of Acid
Gases: A Case Study of Hazira Plant”
- Dr. J. K. Srivastava, Ritu Singh, Hazira Plant, ONGC
ABSTRACT
Hazira Plant is the one of the largest Sour Gas processing
plant in India with installed capacity of 52.5 MMSCMD. Plant
is presently processing approximately 38 MMSCM of sour
gas and 5500 m3 of sour condensate per day for supply of
sweet natural gas to HVJ line of GAIL and VAPs to the OMCs.
Gas received from offshore is sour in nature i.e. contains H2
S
(≈300 ppm) & CO2
(6-7%), and as such is unfit for pipeline
transportation to consumers, therefore it is processed in
Gas Sweetening Units to meet pipeline specifications as per
GSA (Gas Sales Agreement) i.e. H2
S below 4 ppm. During the
sweetening process, acid gas is generated which contains
about 6,000 to 10,000 ppm of H2
S and this gas being very toxic,
cannot be vented into atmosphere.
The Sulfur Recovery Unit (SRU) of Plant is designed to
treat acid gas. At SRU, acid gas is converted to elemental sulfur
by using Regenerative Desulfurization Process, LOCAT-Liquid
Oxidation Catalyst. LOCAT technology contains a liquid redox
catalyst that converts H2
S into elemental sulphur. Liquid redox
involves the absorption of H2
S into the aqueous, chelated iron
solution and its subsequent ionization, secondly the oxidation
of hydrosulfide ions to elemental sulfur and the accompanying
reduction of the ferric (Fe+++) iron to the ferrous (Fe++) state
followed by oxidation of the ferrous iron back to the ferric
state, by absorption of oxygen (from ambient air) into the
aqueous solution.
It is interesting to note that the chelating agents do not
appear in the process chemistry, and in the overall chemical
reaction, the iron effectively cancels out. One may wonder why
chelated iron is required at all, if it doesn’t take part in the
overall reaction. The iron serves two purposes in the process
chemistry. First, it serves as an electron donor and acceptor
and secondly, it serves as a catalyst in accelerating the overall
reaction. The chelating agent(s) do not take part in the process
chemistry. Their role is simply to hold the iron ions in solution.
Neither ferrous (Fe++) nor ferric (Fe+++) ions are very
soluble or very stable in aqueous solutions. Iron will ordinarily
precipitate at low concentrations as either ferric hydroxide
Fe(OH)3
or ferrous sulfide (FeS). The chelating agents are
organic compounds that wrap around the iron in a claw-like
fashion, preventing the iron ions from forming precipitates.
Chelates increase the solubility of metal ions in water and iron
has a very low solubility in H2
O, 4ppm. Chelates can increase
the solubility of iron to 4.0wt% (40,000ppm).
The process is affected by various parameters such as
Specific gravity, pH of the solution, Oxidation–reduction
potential (ORP), Thiosulphate content, Alkalinity, Iron
concentration, chelate concentration and bacterial count.
These parameters play very important role in the process
therefore they are continuously monitored and controlled.
Effect of these parameters and how they are maintained at
Hazira Plant will be discussed in detail in paper.
Tittle: “Evaluation Identification of Hydrogen Sulphide
Scavenger to Mitigate H2S Problem in Mumbai Offshore”
- Dr. (Mrs). Jharna Jana, Nilesh Shelke, Ms. Jyoti Chaugale and
S. K. Bhattacharya, ONGC, Panvel
ABSTRACT
Souring due to increased levels of Hydrogen Sulphide gas
(H2
S) in oil and gas lines and reservoirs is very commonly
observed over a period of time. Sulphide is produced by
non-biogenic and biogenic processes. During water injection,
the sulphate present in injected water is consumed by
the Sulphate Reducing Bacteria (SRB) generating H2
S gas.
Hydrogen Sulphide which is toxic and highly corrosive needs
to be minimised to the acceptable level of ppm. As a measure,
Hydrogen Sulphide Scavenger Technology is deployed for its
mitigation. Hydrogen Sulphide Scavenger Technology refers
to dosing chemical additive (scavenger) into an oil/ gas line
and is generally resorted to when Hydrogen Sulphide levels
are > 500 ppm.
This paper discusses the methodology developed for the
evaluation of Hydrogen Sulphide scavengers. Methodology
is simple, quick and highly effective to mitigate H2
S gas from
system. Hydrogen Sulphide gas from a cylinder is bubbled
through water, dosed with specific ppm of H2
S scavenger
and the hydrogen sulphide gas is measured at ppm level at
the outlet through an online monitoring system, i.e., by H2
S
analyser. The ppm of hydrogen sulphide gas at the inlet is
maintained almost at the same level as expected in the field.
Gas passed through the solution is consumed by the scavenger
and the un-consumed excess gas at the exit is recorded
allowing calculation of Hydrogen Sulphide gas consumed by
the scavenger at specific time intervals.
Mumbai offshore pipeline especially SHG-IB has
been encountering H2
S gas at 100-200 ppm and for its
mitigation hydrogen sulphide scavenger is being used. The
developed methodology for evaluating hydrogen sulphide
scavenger is being further upgraded by including mass flow
Abstracts
14 || IOFC 2018

15. controller which helps to maintain stable and constant flow
rate of incoming gas accurately throughout the evaluation.
The methodology is suitable for the identification of best
performing H2
S Scavenger with which field trial can be carried
out, before actual implementation. Two parameters were
considered for evaluating H2
S scavengers e.g., breakthrough
time and time interval for retaining minimum 50 % efficiency
of scavenger. Based on these two parameters, best performing
Hydrogen Sulphide Scavenger have been identified, where
minimum breakthrough time of hydrogen sulphide scavenger
was recorded as 12.45 minutes. Scavenging efficiency was
maintained at minimum 50 % at 17 minutes and above. The
methodology developed for identifying and evaluation of H2
S
scavenger is expected to be highly effective for mitigation H2
S
from Mumbai High field.
Tittle: “THERMADRIL and BARADRIL-NX fluid systems”
- Mr. Mayuresh Dhavle, Drilling fluids engineer, Halliburton
Offshore Inc.
ABSTRACT
Baroid customized its THERMA-DRIL™ high-performance
(HP) HT WBDF, using select high-temperature polymers
to build a system that exhibited excellent thermal stability
up to 375°F (190°C). Fluid viscosity and high-pressure/
high-temperature filtration control characteristics are very
stable. In field applications, multiple benefits were observed
with the new customized fluid. Significantly lower dilution
rates and daily treatment schedules were needed to
maintain the fluid in specification. THERMA-DRIL HP HT WBDF
exhibited relatively low viscosity and high lubricity, helping
to maintain low equivalent circulating density (ECD), improving
pump rates and ROPs, and further reducing torque and
drag. The system was also far more tolerant of CO2
influxes
without detrimental impacts on fluid properties. Numerous
operational benefits were also experienced due to the more
durable fluid. Smooth drilling operations for the 8- 3/8-inch
section; fluid showed high thermal stability while drilling
and tripping. All bottom-up circulations showed fluid was
in good condition with no sign of polymer deterioration
or barite sag even after a six-day logging run
Baroid’s BaraDrilN™ X High Temperature Reservoir
Drill-In Fluid was developed in response to the need for a
water-based fluid that can provide high temperature stability
while protecting the reservoir and meeting increasing
environmental demands. BaraDrilN® X fluid demonstrates
long-term high-temperature stability with the use
of a synthetic polymer with strongly bonded chemical
linkages and cross-linked chains. This fluid has been
specifically designed as a non-damaging reservoir
drilling fluid, avoiding the dependence on potentially
damaging components such as clays, weighting agents and
stabilizers
i) Predictable HPHT Drilling: BaraDrilN™ X will maintain
rheology, suspension and hole cleaning performance under
extended HPHT exposure. The resilience of the polymer
system means that fluid conditions and performance
can be maintained under static conditions as well as
dynamic circulation.
ii) Improved Safety: To protect operations and the
surrounding environment, BaraDrilN X provides well
control, HT stability and HPHT drilling performance using
a water-based fluid. This solution extends the disposal
options for cuttings and fluids. BaraDrilN X is designed to
perform in a divalent brine base delivering easy access to
higher fluid densities and extra kick protection.
iii) HPHT Open-Hole Completions: Up to now
open-hole completions in HPHT reservoirs has been an
uncommon technique. However, this is increasingly an
option, which is being considered for conventional HPHT
reservoirs. However, drilling fluids, both oil- and water-based,
for HPHT purposes have traditionally focused on maintaining
high temperature stability with little consideration for
the effects on reservoir permeability. BaraDrilN X has
been specifically designed as a reservoir drilling fluid ensuring
that fluid performance does not compromise reservoir
productivity
Tittle: “Design and Development of Various Density Clear
Completion Fluids for Drilled Shale Gas / Oil Wells and
Evaluated From 120˚C to 160˚C”
- Major Janeshwar Prasad, DGM(Chemistry), IDT, ONGC
ABSTRACT
The significance of drilling fluid and completion fluid in oil
industries are essential as blood in our body as these fluids
helps to transport the cuttings / debris from the well, cool and
lubricate the down hole equipment, control the subsurface
pressure and many more functions. While testing or
completing the wells, the, completion fluid is placed in the well
after hermetical test and to control the subsurface pressure is
the important function of completion fluid.
The hydrocarbons are explored from shale gas /oil wells
by hydro fracturing operation. Before hydro fracturing jobs,
wells are to be made ready and drilling fluid is to be replaced
with completion fluids as per well requirements. If drilling fluid
is kept in the wells for a longer period, then deposition of solid
material will take place at bottom and substantial amount of
time is wasted in clearing the wells. To minimize the above non-
productive time we decide to “Design of Suitable completion
fluid for drilled shale gas / oil wells.
The completion fluid designed with Sodium Chloride
of specific gravity 1.10 and 1.20, Potassium Chloride
of specific gravity 1.10 and 1.16, Calcium Chloride of
specific gravity of 1.10 and 1.40, Sodium Chloride + Sodium
Formate of specific gravity 1.30, Sodium Formate of
specific gravity 1.30, Sodium Formate + Potassium Formate
of specific gravity 1.50 and Potassium Formate of specific
gravity 1.50 along with XC-Polymer and other required
chemicals. Various sets of experiments were performed
for evaluating the designed completion fluids in terms of
rheology, pH & specific gravity from 120˚C to 160˚C and found
suitable thereon.
Based on the laboratory studies and evaluation of various
salt based completion fluids, all types (Sodium Chloride,
Potassium Chloride, Calcium Chloride, Sodium Formate
and Potassium Formate) completion fluids are stable and
recommended for filed implementation as per specific gravity
and rheology requirements. If temperature of well is more than
140 0C, then Sodium Formate and Potassium Formate based
completion fluids are recommended as per specific gravity and
rheology requirements because XC-Polymer is thermally not
stable in Sodium Chloride, Potassium Chloride and Calcium
Chloride based completion fluids but stable in Sodium Formate
and Potassium Formate based completion fluids at 160˚C and
higher temperature.
Abstracts
IOFC 2018 || 15

16. Tittle: “Newly Designed K2SO4-PHPA Inhibitive Mud
System to Drill Reactive Shale Formation”
- Mr. Amlan Buragohain, P. K. Das, S. Bora, R. Sarmah, K. K. Das
and J. Hazarika, Chemical Department, Oil India Limited
ABSTRACT
The clay content of the Kopili shale in major OIL operational
areas is mainly Ilite, Kaolinite, Rrutile, Calcite, Dolomite,
Orthoclase and Halite which are less reactive to water. However,
presence of water sensitive Smectite clay in Chabua and Moran
field could be a challenge while using water base mud system.
Recently,a non-dispersed inhibitive KCl-PHPA-Polyol mud
system has been successfully implemented during the drilling
of shale section in these two fields. The chloride ion however
can be defined as a contaminant in land operations, with the
potential to inhibit the growth of vegetation, and it can also be
considered as a potential pollutant to aquifers. Hence the main
purpose of this investigation is to develop a potassium based
shale inhibitive mud system employing an alternative source
of K+ other than KCl which is not commercially available in
India. In order to replace KCl, Potassium sulphate mud system
has attracted much more attention. Owing to its tremendous
beneficial characteristics such as: (i) Commercially available
in India, (ii) Prevent shale instability, (iii) Chloride free, (iv)
Environmentally friendly solution; Potassium Sulphate is also a
fertilizer, we have employed potassium sulphate mud system
in combination with PHPA-PAC-Polyol for drilling the Lower
Eocene-Paleocene Formations in the exploratory location DYC
(S-bend) lies in the Moran, Tiloinagar prospect. Moreover, the
Potassium Sulphate mud system, with minimal environmental
risk and disposal issue, is highly cost effective. During the
course of drilling, drill cuttings were observed to be well
encapsulated with PHPA and dry. The mud system was found
to be very stable at BHT of 175-248oF. During drilling, rheology
was found to be very stable and could be maintained within
25-39lbs/100ft2 by addition of PHPA and XC Polymer. The API
Filter Loss was found to be very low (3.0cc – 5.0cc) throughout
the drilling. At static condition, the stability of the mud system
was easily maintained by keeping the pH value within 9.0-9.5
and regular dose of biocide. The lubricity coefficient of the
mud system was found to be 0.14-0.2, which indicates the high
lubricant property of the mud system. Polyol also contributed
significantly by removing the free water in the mud. This paper
is intended to present the performance of the K2SO4-PHPA
mud system based on the results obtained from laboratory
and field investigations.
Tittle: “Evolving Rheology of Oil-based Drilling Muds/
Fluids”
- Dr. Sandeep Kulkarni, Associate Professor, IIT Kharagpur
ABSTRACT
The oil-based drilling muds (OBMs) have evolved over years.
The first use of OBM containing emulsified water was reported
in 1960. Suitable emulsifying agents were selected to achieve
stable emulsions. The improvements in the OBM system may
be broadly classified in below three classical categories.
Clay-based OBMs: In early sixties, organophilic clays
were developed by reaction of bentonite with suitable aliphatic
amine salts. The base oils for these OBMs were selected based
on the environmental guidelines. The clays would swell in oils
and could form strong gel structures that could suspend solid
particulates in the fluid.
Clay-free OBMs: The organophilic clay-free OBMs
were developed by replacing organophilic clays with certain
polymeric viscosifiers. In 2004, a first of its kind, clay-free
OBM system was presented, and provided the following
advantages: First, fluid rheology did not become too thick at
low temperatures. Second, the gel structure did not lead to
pressure spikes during flow initiation. These properties were
proved beneficial for narrow margin drilling.
Temperature stable OBMs: For both typical clay-free
and conventional clay-based IEFs, high-temperature stability
continued to remain a challenge from a cuttings transport
and barite sag standpoint. Several methods were used by
researchers in the industry to improve the stability of clay-
free IEFs. In last few years, a temperature thickening OBMs,
consisting of different combinations of colloidal particulates,
micronized barite and polymeric viscosifiers have been
developed. High-shear treatment is also being employed to
further improve the rheological stability of these OBMs.
Based on the well geometry, inclination, and temperature/
pressure conditions, the appropriate OBM system needs to be
chosen to achieve the desired performance, safety and cost
goals. Several case studies to illustrate the OBM selection
process will be presented in this work.
Tittle: “Role of Carbon Based Nano-Fluid in Enhancing the
Properties of Drilling Fluid”
- Mr. Rakshit Pareek, Rajiv Gandhi Institute of Petroleum
Technology
ABSTRACT
The quest for cost-effective drilling fluids for ever-competing
demands of petroleum industry has always remained a
striking area of research. Carbon Nanodots have created a
lot of interest in recent times due to their bio-compatibility
which provides them cheap synthesis methods. So, nanofluids
prepared using these CNDs has found applications in oil &
gas industry which is primarily due to two reasons – feasibility
of large scale production and ability to provide better drilling
fluid stability through significant reduction in viscosity.The
rheological behaviour of the CND nanofluid based drilling
fluid investigated by experimental tests and data analyses.
After generating a typical CND nanofluid based drilling
fluid, its viscosity was tested at different temperatures. The
fluid has high viscosity in low shear rate conditions, so that
it can provide an effective seal in pore openings and help in
bridging the pores. Also the method of preparation of CND
based nanofluid is such that it is stable at high pressure and
high temperature conditions. Therefore these properties of the
nanofluid will enable the drilling fluid to be suitable for HPHT
wells to a certain degree. The starting materials are a mixture
of polyols and amines for the preparation of CND. Its LSRV
after addition of nanofluid is higher than without nanofluid.
Tittle: “Thin Film Composite (TFC) Membrane in Water
Injection Operations - A Potential State-of-Art Technology
for Secondary Oil Recovery”
- Dr. P. K. Mahata, ONGC Onshore Gas Terminal, HPHT Asset
ABSTRACT
To fulfill the growing demand of primary energy requirement
and reduce hydrocarbon deficit, acquiring stake in exploration
acreages is one of the way forward besides enhancing
domestic reserve base and improving recovery factor of
Abstracts
16 || IOFC 2018

17. existing fields. Majority of the Indian reserves are depleting
day by day. Several practices are being used to increase
the productivity from the depleted reservoir. It is the time
to look into newer technology for extraction of oil from the
recoverable field through secondary recovery. Water Injection
practices are used to increase the production from depleted
reservoirs as a secondary recovery. It is still a common practice
to use available water for injection operations regardless of the
water’s quality for scale forming species, and then attempt to
correct the problems that occurs. To overcome the long-term
remedial costs and in some cases with irreversible damages
water injection operations should be designed properly from
the start. Existing practice in ONGC is to use Micro-Filter & Dual
Filter for solid particle filtration prior to injection of chemically
treated water, into the well. However, internationally several
new technology in water Injection are used for arresting
polyvalent cation and solid ingredient removal of scaling in
the reservoir.
Present work emphatically focused for incorporating
a State-of-Art Technological advancement in developing a
Thin Film Composite (TFC) membrane which are capable of
rejecting divalent anions (e.g., sulfate) while retaining a large
portion of monovalent anions (e.g., chloride) from seawater
and fresh ground water. TFC is thus a potential technology
to provide nearly poly valent free seawater and fresh ground
water for oil fields water injection operations. It is a relatively
recent membrane filtration process used most often with low
total dissolved solids water, with the purpose of softening
(polyvalent cation removal) and removal of disinfection
by-product precursors such as natural organic matter and
synthetic organic matter. Materials that are commonly used
for membrane include polyethylene terephthalate (PET).
Recent Literature revealed that Poly-Divinylbenzene-co-
Ethylvinylbenzene, poly (DVB-co-EVB) has better potential in
arresting poly valent cations than PET. On the basis of the
success of the preliminary results reported in the literature, it
is envisaged that TFC membrane constituting by poly (DVB-
co-EVB) may provide better results than PET. In addition, with
the addition of Nano particle blending to the copolymer exerts
remarkable improvement in the performance of the membrane.
Though the analytical work has made a lead, but engineering
and designing part as per requirement are yet to be framed.
Present work is the blue print of the conceptual model of the
new state-of-art membrane which may open a new horizon in
Surface operation of depleted reservoir.
Tittle: “Failure Analysis of Carbon steel Sub Sea Water
Injection Pipeline”
- Mr. Bipin Kumar*, Sangeeta Rani Prasad, S.K Srivastava, Anil
Bhardawaj and P.K Borghate, Institute of Engineering & Ocean
Technology, ONGC
ABSTRACT
The 12ӯ x 9.32 kms API 5L X 52 water injection (WI) pipeline
laid in 2002 leaked at a distance of 1.13 Nm (2.09 km) from
ONGC offshore platform in February 2012. The identified leak
was repaired and reported to be further leaked from same
place on 03.03.2012. The issue of frequent leakages has been
being encountered in water injection lines of ONGC Asset were
deliberated at length. IEOT took the initiative to carry out the
studies to investigate the causes and probable mechanism of
failure of 12ӯ WI pipeline and suggest remedial measures.
In order to identify the cause and mechanism of failure,
detailed laboratory and analytical investigations were carried
out with a view to characterize the material property as well
as to evaluate the corrosivity of operating environment.
Studies like visual inspection, non destructive testing,
corrosion product analysis, elemental compositional analysis,
metallographic investigations, inclusion content test, hardness
testing, tensile strength studies, impact test, stereo micrscopy,
scanning electron microscopic (SEM) coupled with energy
dispersive spectroscopy (EDS) studies, have been carried out
and their results have been discussed in detail. Operating
condition of the WI line, like injection water flow rate/velocity,
quality parameters of injection water, chemical treatment
program of raw sea water etc. have been critically examined
and factors like effect of chloride ions, dissolved oxygen,
microbes, metallurgical characteristics of material, pigging etc.
are discussed in detail in this report.
Pipeline material is found to be conforming to the
specification API 5L X-52 carbon steel. The analysis shows
that the most probable cause of the failure of the pipeline
was under-deposit corrosion and grooving, which started with
oxygen corrosion and microbial induced corrosion (MIC) and
was subsequently supported by very low flow velocity. The low
water velocity, especially in low lying areas and the formation
of thick deposit consisting of corrosion product, sludge or
suspended solids and biomass as a result of proliferation of
bacterial colonies were the conditions for attack to set off. The
galvanic corrosion further accelerated the metal loss process
and grooving/channeling in this case.
Tittle: “Effect of Concentration, Temperature and Flow
Rate on the Reduction of Permeability in the Reservoir due
to Scaling Effect”
- Prof. Tarkeshwar Kumar, T. K. Naiya and Sanjiv Kumar,
Department of Petroleum Engineering, IIT(ISM), Dhanbad
ABSTRACT
Scaling is a major problem where industrial water treatment
is involved. It is the deposition of solid minerals due to
precipitation of inorganic salts. Depending on the nature and
toughness it can be treated by easy means or in certain cases
it can cause ultimate failure of the system and its treatment is
difficult. In oil industry major scales involve Calcium Carbonate,
Barium Sulfate, Strontium sulfate, Halite, Iron sulfides etc.
Most occurring scale is calcium carbonate, it is pH dependent
and its remediation is relatively easy as it is easily soluble in
most of the known acids. However, acid being corrosive in
nature and creating environmental problem is now a days not
suitable and development of better alternative is required. In
this direction different class of methods are available which
includes mechanical cleaning or use of chemicals. Mechanical
method is suitable where scales are accessible, but mostly
scales are formed in areas where mechanical cleaning may
not be feasible. In those cases chemical treatment is the only
option.
Scaling problem is great headache for numerous
industries. Any industries that deal with industrial water face
the problem of scaling. Oil and gas industry, petrochemicals
industry, refineries, waste water treatment plant, RO water plant
are to be named a few. The problem become so severe that
complete blockage occurs and delicate parts of the machinery
and equipment need to be replaced. Some types of scales
are relatively easy to handle while scale like strontium sulfate
and barium sulfate are tough in nature and its removal is very
Abstracts
IOFC 2018 || 17

18. costly and yet complete remediation is never achieved. Current
work explains reduction of permeability in the reservoir due to
scaling effect. The experimental work carried out on sand pack
flooding with water containing various ratio of scale forming
salt. The experimental condition was varied and its effect
was observed on sand pack permeability reduction. Effect of
concentration, temperature and flow rate was observed and
the result was obtained in the form of relative permeability
change.
It was observed that at 75 cc/min flow rate of scaling
water in sand pack, the reduction in permeability ratio was
almost twice than that of at flow rate of 25 cc/ min at 700
minutes of flow. It indicates that while other parameter
remains fixed the flow rate has significant effect on scaling in
the absence of scale inhibitor. Similar observation is obtained
while varying the temperature and keeping other parameters
constant. This study suggests that at higher concentration and
greater flow rate the chance of permeability reduction due to
scaling increases. The significance of the study is that it shows
real scale problem that occurs into the reservoir condition.
Tittle: “Development of a New Protocol for Evaluation
of Scale Inhibitor and Effective Management of Scale
Inhibition – A Case Study”
- Mr. Bijan Mahanta, S. Sinha and M. C. Nihalani, R&D
Department, Oil India Limited
ABSTRACT
As water percentage in produced formation fluid increases due
to ageing of fields, it becomes very important to control the
adverse effects in handling produced waters. Oil India Limited
(OIL) has been facing acute scaling problem in the produced
water outlet lines of Emulsion Treater (ET), water disposal lines,
valves and pumps etc. in few of its field installations. It has
been observed that the scaling is aggravated in installations
handling water produced from different horizons like
Oligocene and Eocene. The present study discusses the unique
process developed in-house for evaluation of Scale Inhibitor
(SI) having various formulation and chemistry for effective
control of scale formation (Calcium Carbonate Scales). The
study also discusses the steps adopted for mitigation of scale
problem in some oil and gas production facilities of OIL in
crude oil production / processing installations.
Suitable SI has been identified through laboratory
developed evaluation process to mitigate the scaling problem
at various installations. The test protocol for selection of SI
is based on quantitative estimation of calcium ions which is
discussed in detail in the present study. This testing procedure
established a very firm correlation between Laboratory and
field performance of Scale Inhibitor in terms of Scale Inhibition
(in percentage) and Scale Control in the laboratory and in the
field installations respectively. The advantage of this testing
protocol is that it is based on complexo-metric titrimetric
analysis and does not require any sophisticated equipment. It
shortens the product development time for OIL and within a
reasonable timeframe; the developed SI product can be taken
for field applications. The present study also discusses about
the principle followed for advising dosing rate of SI in the field
installations.
Tittle: “Scale Treatment in Heat Exchangers-A Case Study”
- Mr. Alok Dwivedi, Sudipta Biswas, S. K. Jaruhar and Rajeev
Bansal, ONGC, Panvel
ABSTRACT
The shell and tube type heat exchanger in one of the plant in
ONGC was found to be choked. The choked deposits were very
hard and hence could not be cleaned through conventional
hydro-jetting. As the deposition in tubes was very hard, so
cleaning was planned through a combination of telescopic
drilling and chemical methods.
The first step towards selecting the suitable chemicals
for scale dissolution depends on the composition of the scale
sample. The samples are blackish brown in appearance and
were hard in nature. The compositional analysis revealed that
the scale was predominantly inorganic in nature along with
minor amount of organics. Major part of inorganic portion was
acid soluble and rich in calcium indicating calcium carbonate
scale. Keeping in mind the calcium carbonate rich scale
deposition in crude heater tubes a plan was devised to carry out
the laboratory study with a mixture of acid and organic solvent
to dissolve the inorganic portion and organics respectively.
An experimental study was carried out for the dissolution of
scale samples in different concentrations of hydrochloric acid
with and without addition of organic solvent xylene. Due to the
easy availability of naphtha as a byproduct in the plant itself,
series of experiments were performed with naphtha instead of
xylene. A combination of 15% HCl and naphtha in 2:1 ratio has
been found to be effective for scale dissolution.
Based on the experimental results, it was recommended
to circulate a mixture consisting of 15% HCl with 3% ACI &
Naphtha in 2:1 ratio (i.e. 2 part HCl with ACI and 1 part Naphtha)
at a slow rate till 70% openings of tubes is achieved. Telescopic
drilling followed by circulation of air and water were required
to remove the debris and to ensure circulation of chemicals
through the tubes prior to the chemical circulation. Residual
scale deposition can be removed by Hydro-jetting. Further, use
of suitable scale inhibitor in appropriate dosage and regular
cleaning of exchangers are also recommended to avoid such
problem in future. The implementation of the job plan has
helped cleaning of six exchangers leading to improvement in
their efficiency.
Tittle: “Challenges in Desalting Process”
- Mr. Srikanth Jampa. AVP, Ion Exchange (India)
ABSTRACT
With the changing rheological behaviour of crudes, crude
oil properties have also been observed to change from one
well to another. In addition, properties of crude oil in the well
source vary in different regions and countries, posing an overall
challenge in desalting process both in the upstream oil field
and downstream refinery process. Desalting process being one
of the vital operations in both oil field and downstream refinery
has therefore become a crucial subject of discussion in many
forums. Optimizing the desalting operation has become an
exclusive art and operation that is worth learning for different
crude oil processing.
While removing of water as basic sediment and water
(BS&W) is vital in the oil field both for handling and selling net
crude worth, it is also important to understand the individual
impurities and how they can affect the downstream refinery
process. Major elements contributing to these challenges are
the impurities in crude oil like water, sediment, filterable solids,
organic acids, hydrogen sulphide, asphaltenes etc.
A desalter is like a kidney to the refinery process and
Abstracts
18 || IOFC 2018

19. is the primary step right after crude oil extraction, both in
the oil field and refinery battery limit. Though each crude oil
refining process is unique, sharing of individual challenges and
appropriate steps taken in the desalting process will facilitate
generation of sufficient data to help define and streamline the
methods for different process challenges.
This presentation will give a holistic view of the desalting
process and give refiners a direction to plan and optimize the
desalting process at all times.
Tittle: “Silicone additives for Crude Oil Processing”
- Dr. Bilson Shukla, Elkay Chemicals
ABSTRACT
Silicone is a class of performance chemicals that have
unique physical and chemicals properties. Silicone
(polydimethylsiloxane) products give better performance
in various oil & gas applications as defoaming, antifoaming,
demulsification, release agents etc. Its effectiveness
gives desired results by using very low quantity and
hence cost reduction could be achieved in this sector. The
unique chemical properties of silicones (surfactants, fluids,
emulsions)such as low surface tension (21 dynes/cm),
high temperature stability, inert and wide pH stability, bio
compatibility and environmental friendly could be used in
various applications where performance required and this
haven’t achieved with conventional chemistries. For the
petrochemical industry, from drilling to refining to shipping –
foaming leads to losses in efficiency, mechanical issues and
fouling. Silicone foam control solutions allow foam control in
multiple places in petrochemical units to increase productivity
and save money.
Demulsifiers are a class of specialty oilfield chemicals
used to separate water in oil/oil in water emulsions. They are
used in the processing of crude oils which contains significant
amount of saline water (produce water). This saline water
should be removed from crude oil before refining, as this
saline water causes corrosion in equipments used for crude oil
refining process. Silicone demulsifiers are a relatively new type
of chemical demulsifier which are driving efficiency. There have
been several studies and tests done which show that silicone
demulsifiers are efficient reagents both in pure form and as
additives to organic systems. Silicone demulsifiers are not
intended to replace organic demulsifiers. Instead, they should
be blended together with organic demulsifiers. Typically, such
a blend contains between 2 and 5% of a silicone demulsifier.
These new organic/silicone formulations have synergies in
demulsification of various crude oils.
Silicones are also being used as excellent leveling and
release agent for refinery sulphur pastillization units. It prevents
sticking of sulphur pastilles to processing equipment and
provides an inert, homogenous, clear and shear stable solution
in water. Silicones are easy to spray due to low viscosity and
allows for a uniform shape and dust free pastillization process.
Silicone oils are having high flash points, wide temperature
range working, insoluble in crude oils, low viscosity change
with respect to temperature and highly stable at oilfield
applications.
Tittle: “The Science Engineering and Art of Breaking a
Crude Oil Emulsion”
- Dr. A. K. Saxena, Ex. General Manager (Chemistry), ONGC
ABSTRACT
There are a few developments which simultaneously occur
when an oil field starts ageing and is so called a mature or
brown oilfield. The topmost being the increase in the water
cut, others are changes in the characteristics of the produced
crude oils and/or emulsions and final being the increase in
toughness of the produce emulsions which may also be a
result of the particular EOR/IOR process to which the oilfield is
subjected. The major challenge in a matured oil field, apart from
maintaining or increasing the production levels is to demulsify
the tough produced emulsions to the desired levels which
are accepted by the crude processing refineries. The energies
used in the demulsification process are heat energy, chemical
energy, kinetic energy and potential energy. All these energies
are critical to the efficient crude oil dehydration process and
the total sum of the energies essential to break an emulsion
may depend upon the type and toughness of the emulsion.
The present paper discusses the various factors which
determine the stability of the produced crude oil emulsions
including the crude oil characteristics, produced water
characteristics and presence of emulsifying agents. With
the basic knowledge of the stabilizing factors of a crude oil
emulsion, it is easier to evolve the emulsion breaking strategies.
These strategies involve erecting required engineering facilities,
choosing a right chemical or a right combination of chemicals,
creating the right energies for emulsions breaking and effective
separation of the two streams after demulsification.
The chemical often called as Demulsifier plays a critical
role in the overall demulsification process and developing
a chemical formula for a particular emulsion requires
understanding of the characteristics and behaviour of the
particular emulsion for which the chemical(s) are being
designed. The various types of chemical formulations which
can be used for different crude oils and under various
conditions have also been discussed. The engineering surface
facilities available for the demulsification process also play
an important role and their requirement for various types
of crude oil emulsion has also been discussed. Often, these
two complement each other; however, the deficiencies of the
one can be supplemented by the efficiencies of the other.
The efficient crude oil demulsification is a right mix of the
surface facilities and the right choice of a chemical and a clear
understanding of the characteristics of the oil and emulsion
help in creating the right ones and making the process
economically and technically efficient.
Tittle: “Studies on Heavy Crude Oil/Emulsions Viscosity
and Correlation Development by using Bio- Additive”
- Dr. Tarun Kumar Naiya, Manoj Kumar Gudala, Shirsendu
Banerjee, Ajay Mandal and T Rama Mohan Rao, Department of
Petroleum Engineering, IIT (ISM), Dhanbad
ABSTRACT
Heavy crude oil exploration and production is very important
due to the abundant global reserve(Saniere et al., 2004).
Heavy and extra heavy crude oil demand is marginal, this is
due of their complex compositions, high viscosity, and also
the lack of transporting and refining technology. Heavy crude
oil is very expensive and problematic during production
and transportation when compared to light crude oil with
conventional technologies. This high viscosity and high
density crude oil is difficult to exploit, produce, transport, refine
these also lead to many problems such as high pump power
Abstracts
IOFC 2018 || 19

20. requirement, low throughput, pipeline blockage, pigging
operation cost etc. during their transportation (Kumar et al.,
2016).The conventional methods to reduce viscosity of heavy
and extra heavy crude oils are heating, blending with lighter
hydrocarbons/condensate, emulsions (oil-in-water or water-
in-oil emulsions), and viscosity reducing agents like surfactant
and polymers, partial upgrading(Martínez-Palou et al., 2011).
Heavy crude oil has more complex rheological
properties these are shear-thinning, thixotropic, yield stress
and viscoelasticity due to different proportions of saturates,
aromatics, resins and asphaltenes(Martínez-Palou et al., 2011).
Most of the models established to predict heavy crude oil
viscosity were based on influencing factors. ASTM double log
model(ASTM 341-93, 1998), Arrhenius model(Andrade, 1934),
modified Arrhenius model (Liu et al., 2017) were developed
based on temperature. Shear rate is another viscosity
influencing parameter. Power law model(de Wawle, 1925),
Bingham plastic(Bingham, 1922), Casson model(Casson and
Mill, 1959), and Herschel and Bulkley model (Herschel and
Bulkley 1926) are existing models based on shear rate. Alomair
et al., (2014) and Liu et al.,(2016) developed models which are
based on temperature and API gravity. Ronningsen (1995), Al-
Roomi et al.,(2004), Azodi and Nazar (2013), Wen et al., (2016)
developed model based on temperature, dispersed phase in
the emulsion and shear rate.
Due to the interesting capabilities of dispersed
water with bio-additive (potato starch) to reduce viscosity
of heavy crude oil, this work aims to investigate the
viscosity and other rheological behaviour of heavy crude oil
at different temperatures, concentrations of water and bio
additive, and shear rate. This work also aims to develop a
mathematical model to predict heavy crude oil viscosity with
effective parameters by using statistical software. Heavy
crude oil viscosity and Rheological behaviour at different
concentrations of water, natural additive potato starch,
temperatures, and shear rates was investigated. Maximum
viscosity reduction of 80.4% was obtained at 50ºC and a shear
rate of 1000s-1after addition of 2000ppm potato starch to
85% heavy oil+15% water. Correlation was also developed
and then modified to predict heavy crude oil viscosity with
effective parameters by using statistical software Design-
Expert. The modified (combinational effect) correlation was
good agreement with experimental results (R2=0.9421) and it
can be used to predict heavy crude oil viscosity within given
range of effective factors.
Tittle: “Crude Oil Treatment Strategies based on Crude
Emulsion Characteristics to Ensure Flow Assurance – A Case
Study”
- Ms. Ragini Sarmah, Rajarshi Panigrahi, S. Sinha and M. C.
Nihalani, R&D Department, Oil India Limited
ABSTRACT
The occurrence of water-in-oil emulsions is a very common
phenomenon observed in the E&P industry during crude oil
production. The presence of water in the emulsion is mostly not
homogeneous. The heterogeneity of emulsion makes it difficult
to determine the correct dosage of the chemicals required to
mitigate flow assurance problems in the production tubing and
oil flow lines like deposition of wax, asphaltenesetc. Moreover,
the response of different crude emulsions to treatment with
various chemical additives is different. Therefore, a suitable
treatment strategy to address any flow assurance issue
has to be identified based on laboratory studies on the
crude emulsion.
The present case study discusses two different
approaches in dealing with Flow Assurance problem in two
wells from different oil fields of Oil India Limited (OIL). The two
treatment strategies are based on difference in crude emulsion
behaviour when subjected to treatment with chemical additives
viz. Oil Soluble Demulsifier (OSD) and Liquid Flow Improver
(LFI). In one well, demulsification of the crude by OSD helped in
improving the rheological behaviour of the crude to desirable
values in terms of its pour point and viscosity without adding
any LFI. At the same time in another well, demulsification
of the crude showed little improvement in its rheological
properties. Both the crude emulsion and demulsified dry
crude were further treated with different doses of LFI. Usually,
it is observed that the demulsified crude responds better to
Flow Improver (FI)/ Pour Point Depressant (PPD) additives as
compared to crude emulsion. However, in the present case, it
is found that the crude emulsion showed better response to
LFI treatment resulting in decrease in viscosity and deposition.
The laboratory studies discussed in both the cases were carried
out to assess the effectiveness of different crude treatment
strategies on wellhead crude emulsions. The emulsion specific
treatment strategy developed in the laboratory has been
successfully implemented in one of the wells and is planned to
be extended to other wells.
Tittle: “Assessment of Marine Environment by Analyzing
Petroleum Hydrocarbon Content in Sediment –A Case
Study around Sediments of Western Offshore of Mumbai
High, ONGC”
- G. L. Das, R Sitaraman and Atul Garg, IPSHEM, ONGC, Goa
ABSTRACT
Petroleum consists of crude oils and a wide variety of
refined oil products that the elemental composition varies
over a narrow range 82%–87% carbon, 12%–15% hydrogen,
the balance being oxygen, nitrogen and sulphur. Pollution
of the sea by petroleum hydrocarbons occurs mainly
through marine operations, land based discharges,
atmospheric and natural inputs. The total input of petroleum
into the seas through human activities and sources
such as atmospheric fallout, natural seepage, etc. is
estimated at, 2.37 106 × t year-1. Out of these, about
65.2% is discharged through municipal and industrial wastes,
urban and river runoffs, oceanic dumping and atmospheric
fallout; 26.2% derived from discharge during transportation,
dry docking, tanker accidents, and de-blasting. The remaining
8.5% comes from fixed installations like coastal refineries,
offshore production facilities, and marine terminals. When
petroleum hydrocarbon is released directly to water through
spills or leaks, certain petroleum hydrocarbon fractions
will float in water and form thin surface films. Other heavier
fractions will accumulate in the sediment at the bottom of the
water, which may affect bottom-feeding fish and organisms.
The occurrence of enhanced levels of hydrocarbons especially
in sediments can be a good indication of anthropogenic
sources of pollution.
After discovery of Bombay High in 1974, ONGC has
deployed several drilling rigs and process platforms and more
than a hundred unmanned platforms in Western offshore.
ONGC deployed its own self control strategies in the initial
phase of oil field developments by following international
Abstracts
20 || IOFC 2018