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Oil and Natural Gas Corporation Limited,
PROJECT: SURFACE OPERATIONS
FOR OIL/GAS WELL
UniversityCollege of Engineering, RTU, KOTA
ON SURFACE OPERATIONS FOR
Students of 6th semester of B.Tech (Petroleum Engineering)
University College of Engineering, RTU, Kota
Oil & Natural Gas Corporation Limited
The training here at Oil & Natural Gas Corporation (ONGC),Mehsana Asset in
Production Team has been a great experience, both educative and enjoyable
at the same time. I would like to thank the entire Human Resource
Department of the Mehsana Asset for their support and co-operation
throughout the training period 18.05.2015 to 17.07.2015.
I wish to express my indebted gratitude and special thanks to Dr. D. Basu GM
(GENERAL MANAGER) of Mehsana Asset Oil & Natural Gas Corporation
Limited (ONGC) for his esteemed guidance and giving me an opportunity to
gain an insight into the working of an industry.
I would specially like to thank Dr.Bimal C.Mandavawala DGM (P) for his
support and vital encouragement throughout the training period.
I express my deepest thanks to my guide Mr. T M More (SAM-II), Mr. M.S
Jetawat (SAM-IV), Mr. C.K Das (SAM-EOR), and Mr. M.P Waghmare (Artificial
Lift) for his vital encouragement and guidance to carry out my industrial
training work at Mehsana Asset.
I would like to thank Mr. T. Hazarika (Area Manager) to make this training
highly informative and educative.
I would also like to thanks Mr.Gyanender Singh (security officer) for their
continuous support during the training.
Student of B.Tech (PETROLEUM)
University College of Engineering, RTU, Kota
Camp: - Oil & Natural Gas Corporation Limited,
Oil and Natural Gas Corporation Limited
This is to certify that AMIT NITHARWAL. Student of B.Tech. Petroleum
year, University College of Engineering, RTU, Kota has successfully
completed his summer training on “SURFACE OPERATIONS FOROIL/GAS WELL” at
Mehsana Asset, ONGC, during 18th May 2015 to 17th
July 2015. He has done his
work diligently and sincerely and I am fully content with his performance.
Mr. Ankit Gupta
1 About ONGC
2 About ONGC’S Mehsana Asset
3 Journey of Crude oil
4 Surface facility
4.1 South santhal (GGS Cum CTF)
4.2 Sobhasan (GGS Cum CTF)
5.2 Insitu combustion
6 Artificial Lift
Oil and natural gas corporation (ONGC)
ONGC is the one of the largest Asia based oil and gas exploration and
production company and produces around 72% of India’s crude oil and
48% of its natural gas.
ONGC has been ranked 357th in the fortune global 500 list of the
world’s biggest corporations for the year 2012.
It is also among the 250 global energy companies by Plats.
ONGC was founded on 14th Aug 1956. It is involved in exploring for
and exploiting hydrocarbons in 26 sedimentary basins and India and
owns and operates over 11000 km of the pipelines in the India.
ONGC Represents India's Energy Security through its Pioneering Efforts
ONGC is the only fully–integrated petroleum company in India, operating along
the entire hydrocarbon value chain. It has single-handedly scripted India's
hydrocarbon saga. Some key pointers:
ONGC has discovered 6 out of the 7 producing basins in India:
It has 7.59 billion tons of In-place hydrocarbon reserves. It has to its credit
more than 320 discoveries of oil and gas with Ultimate Reserves of 2.69 Billion
Metric tons (BMT) of Oil plus Oil Equivalent Gas (O+OEG) from domestic acreages.
Ithas cumulatively produced 851 Million Metric Tons (MMT) of crude and 532
Billion Cubic Meters (BCM) of Natural Gas, from 111 fields.
ONGC has won 121 out of a total 235 Blocks (more than 50%) in the 8 rounds
of bidding, under the New Exploration Licensing Policy (NELP) of the Indian
ONGC's wholly-owned subsidiary ONGC Videsh Ltd. (OVL) is the biggest Indian
multinational, with 30 Oil & Gas projects (9 of them producing) in 15 countries.
Produces over 1.24 million barrels of oil equivalent per day, contributing over
64% of India'sdomestic production. Of this, over 75% of crude oil produced is Light
The Company holdsthe largest share of hydrocarbon acreages in India (51% in
PEL Areas & 67% in ML Areas).
ONGC possesses about one tenth of the total Indian refining capacity.
ONGC has a well-integrated Hydrocarbon Value Chain structure with interests
in LNG and product transportation business as well.
ONGC’s growth towards its self-reliance
ONGC was set up under the visionary leadership of Pandit Jawahar Lal Nehru.
PanditNehru reposed faith in Shri Keshav Dev Malviya who laid the foundation of
ONGC in the form of Oil and Gas division, under Geological Survey of India, in
1955. A few months later, it was converted into an Oil and Natural Gas
Directorate. The Directorate was converted into Commission and christened Oil &
Natural Gas Commission on 14th August 1956. In 1994, Oil and Natural Gas
Commission was converted in to a Corporation, and in 1997 it was recognized as
one of the Navratnas by the Government of India. Subsequently, it has been
conferred with Maharatna status in the year 2010.
Over 56 yearsof its existence ONGC has crossed many a milestone to realize the
energy dreamsof India. The journey of ONGC, over these years, hasbeen a tale of
conviction, courage and commitment. ONGCs’ superlative effortshave resulted in
converting earlier frontier areasinto new hydrocarbonprovinces. From a modest
beginning, ONGC has grown to be one of the largest E&P companiesin the world
in terms of reserves and production.
ONGC as an integrated Oil & Gas Corporate has developed in-house capability in
all aspects of exploration and production business i.e., Acquisition, Processing &
Interpretation (API) of Seismic data, drilling, work-over and well stimulation
operations, engineering & construction, production, processing, refining,
transportation, marketing, applied R&D and training, etc.
Today, Oil and NaturalGas Corporation Ltd. (ONGC) is, the leader in Exploration &
Production (E&P) activities in India having 72% contribution to India’s total
production of crude oiland 48% of naturalgas. ONGC has established more than 7
Billion Tons of in-place hydrocarbon reserves in the country. In fact, six out of
seven producing basins in India have been discovered by ONGC.
Oil and natural gas corporation (ONGC
The oil and natural gas corporation ltd. (ONGC) is India’s biggestintegrated oil
company having major interest in E&P activities. Mehsana Asset, about 60km.
fromAhmedabad is located in northern part of Gujaratstate. it is the highest oil
producing onshoreassetof ONGC. The assethas oil fields producing both heavy
and light crude with API gravity ranging from130
API. Theheavy oil fields viz.
SANTHAL, BALOL, LANWA and BECHRAJI having API gravity between 130
in the northern part of CAMBAY basin.
LANWA, BALOL and SANTHAL fields have contiguous structurewith only
geographicaldemarcation stretching in North-South direction with LANWA field in
the North, SANTHAL field in the South and BALOL field in between. BECHRAJI field
is located in the west of Mehsana Horst.
The pay sands arechannel sands and the major pay sand kalol is distributed in
the entire length of the heavy oil belt. The structureis a homocline diping NNW-
SSE with dip ranging from20
. Towards theeastern side all along the length of
the heavy oil belt is an infinite aquifer which providepressuresupport. In the
western side, the heavy oil belt abuts against the uplifted block called the
Mehsana Horstwhere the Kalol sands thin out. Kalol sands occur at a depth of
950 to 1000mwith averagereservoir pressureof about100kg/cm2.
Oil viscosity increases fromsouth to north. In southern part of santhalfield. The
oil viscosity is about 50cp and in the northern part of Lanwa field it is about
1500cp atreservoir temperature of 70`C. becauseof the viscous natureof oil, the
primary recovery of the heavy oil field is very low ranging from 6%-17%. The
STOIIP of four heavy oil fields about 140MMT.
Total 11 field in Mehsana Asset.
1 N. KADI 1540 1488 1500
2 SOBHASAN 848 881 862
3 SANTHAL 1330 1355 1340
4 BALOL 488 462 464
5 JOTANA 216 235 239
6 NANDASAN 497 487 468
7 LANWA 202 177 176
8 BECHARAJI 224 204 212
9 LINCH 471 469 503
10 LANGHNAJ 85 108 110
11 MANSA 21 10 17
TOTAL(MT) 5922 5876 5891
JOURNEY OF CRUDE OIL
The Crude oil produced from various oil fields are being transported through
pipelines to a Group Gathering Station (GGS). In GGS the oil is being separated
from impurities and water by the process of three stages Separator which
contains de-emulsifier (IG- Lube, Polarchem) injection in its first stage followed by
heating process and electrostatic separation (Heater-Treater). The gas which is
produced is transported through pipelines to Gas Collecting Station (GCS). In GCS
the collected gas is subjected to Gravity Separation through various separators
like HP Separators, LP Separators, Group Separators and Test Separators.
The Processed crude oil from many GGS is being transported to a Central Tank
Farm (CTF) where again the crude oil is subjected to a separation process in a
Heater-Treater in which the separation occurs in three stages. Later on the
processed crude is transported to the desalter plant for reduction of salt and
water content of the crude oil (water content<0.2%). In desalter plant the
received oil is subjected to separation in three stages (heat exchange trains,
heater-treater, and desalter tank). The final crude oil is recovered with 0.10%
water-cut and is transported through a pipeline to a nearby refinery (The crude
from desalter plant at Nawagam is sent to Koyali refinery Vadodra, Gujarat) for
production of finished products.
The collected gas at GCS is at very low pressure of about 2-5 kg/cm2 which is
being transferred to a Gas Compression Plant (GCP) to compress the gas to a
pressure of about 40-45 kg/cm2 to use the gas for injection purpose so as to
enhance the oil recovery through GGS.
The waste water collected from all separation processes are being sent to Effluent
Treatment Plant (ETP) where the trace oil is being recovered from waste water.
The treated water is being sent to a Water Injection Plant (WIP) which is being
pumped to various wells so as to enhance the oil recovery process. The recovered
water from the Desalter plant is being sent to Waste Water Treatment Plant
Oil is produced through three types of wells:
a) Self DriveWells
b) Sucker Rod Pump (SRP) Wells
c) Artificial Lift Wells (gas injection/ water injection)
Self drive wells or Self flow wells are the wells which flow with their own
pressure. Sucker Rod Pumps work on the principle of hand pumps to produce
from the well. In artificial lift wells either gas is injected or water/polymer is
injected for the production of oil.
When the oil well ceases to flow with own pressure then Artificial Lift System is
installed for pumping out well fluid. The wells having high flux are mainly
subjected to artificial lift technique. The gas injection process may either be
continuous or intermittent (done in fixed intervals).
Oil is received in GGS- 7(k) from the wells through 4” pipelines into the following
1. Group header
2. Test header
3. Emulsion header
4. H.P header
Group Header (oil & gas):-
Well fluid from the wells to header, to bath heater, for preheating & then to
group separator .Oil water mixture after separation of gas in group separator goes
to heater -Treater for emulsion treatment .Oil from HT goes to oil storage tank &
from tank it goes it is pumped to CTF (K) with the help of oil dispatch pumps. Gas
from the group separator goes to booster compressor for compression & goes to
the gas grid of Kalol area to GGS (K) which is measured by flow recorder.
Test Header (oil & gas):-
One test header with section valve is provided to facilitate testing of individual
wells one well can be tested one at a time. The well to be tested is diverted to
test separator where liquid & gas separation take place. Gas is sent to gas grid &
liquid flow 2 TCS tanks. Metering facility is provided for oil & gas
Well fluid flows from the wells to header & goes to emulsion separator for
separating liquid & gas. Liquid goes to heater treater for emulsion separation oil
from HT goes to oil storage tank & gas from e/ sep goes to the gas grid of kalol
area of GGS which is measured by flow recorders.
Well fluid flows from header & goes to emulsion separator – 2 / HP separators .
Fromseparator liquid goes to heater treater for emulsion treatment & gas goes to
the gas grid of kalol area to GGS kalol which is measured by the flow recorders oil
from HT goes to storage tanks.
Emulsion Header/H.P. Header:-
This is a 8 “PHI & 4 “phi line system connecting the valve manifold to the
separator via bath heater. It is meant for collecting oil from wells & diverting the
same to the separators.
Five separators 7-v-01, 02, 03, 04, 05 having a designed capacity to handle
580m^3 day of well fluid are provided. Outof these separators 7-v-01 is meantfor
group production with all instrumentation, 7-v-02 is meant for testing of wells &
7-v-03,04,05 aremeantfor emulsion flow. One HP separator 7-v-06 is provided to
handle HP gas. Feed enters the separator from the valve manifold through 4” line.
The operating pressurein the separator is 6 kg/cm2. The separator are two phase
separating vessels, capable of separating liquid and gas. The vessels are designed
for a pressure rating 9kg/cm2 at a temp. Of 70*c . Flow recorders are provided to
measure produced gas . The separated oil flows out from the separator on oil
level through LV 101/102/103/104/105/106 to oil storage tanks via heater
Pressure gauges are provided on the separators to monitor the operating
pressure . All the separators are provided with pressure relief valve PSV -
101/102/103/104/105/106 to protectthe vesselagainstover pressure. The valves
are set at a pressure of 6.6kg/cm2 & PSV – 106 set ata a pressure 16.5 kg/cm2.
South santhal (GGS cum CTF)
1) Discovery: - South santhalCTF of Mehsana Assetwas discovered in
1971.Theinstallation is integrated with a gas compressor plant(GCP) and
2) Structure: - The santhalfield is the southern segment of heavy oil belt
comprising Lanwa, Balol and santhal field located in north cambey basin.
3) Reservoir:-The150mthick sandstonewith in kalol formation ,middle
Eocene age occurring a depth of about 150mconstitute the reservoir ,the
sand are medium coarsegrained ,poorly consolidatewith thin
1) avg. porosity=28%
2) permeability=8-15 Darcy
3) reservoir pr.=105kg/cm2
4) initial oil saturation=65-80%
4) Reserves:- The initial oil in place is estimated to be 54MMTof which
8.01MMTis recoverableunder natural drive. The total recoverablereserves or
oil including EOR oil are estimated to be 20.98MMT.
4) Production: - Well santhal -1 discovered oil and is on production since June
1974. Thefield initially produced oil@34TPD through 3 wells.
5) Oil &gas properties: crudeoilgravity 170
API and reservoir viscosity is 60
Total no. of flowing wells: 127
A) Self flowing well: 14
B) SRP well: 113
Total non-flowing wells: 40
Total liquid production: 3300 m3
Net oil production: 1200 m3/day
Effluent generation: 2100 m3/day
Total gas compression: 50,000 m3/day
Oil and gas separator: - 02
Heater treaters :- 10
Oil storagetanks:- 6 nos. (1300 m3 capacity)
2 are Testing tank(50m3) & 2 effluent tank(2000m3)
Flare system: 01
Oil dispatch pumps: 04 nos. (43.5 m3/day)
Oil is being dispatchedto: Mehsana CTF through 8” pipeline (20539.79m3/day)
Fire water pumps 4 nos. (capacity 162 m3/hour of
For firefighting: two pumps, 425 & 437 m3/hr of two)
fire alarm system: electrical and hand operated
fire hydrants: 16
fire monitors: 12
Fire extinguishers: A) DCP type: 49 nos.
B) Co2 type: 17 nos.
C) Foamtype: 03 nos.
Gas detectors: 01 Portable
01 On line
Firstaid kit & breathing
Nearest fire station: ONGCfire station
Santhal fire station
Fire mock drill: twice in a month
Generator set: 1 nos. (capacity 250 KVA)
Group Gathering System (GGS)
GGS (Group Gathering Station) is an installation which receives oil through
manifolds fromits different assigned fields. Crudeis separated here in the
formof oil, gas and water. Separated gas is sent to CTF (Central Tank Farm)
for further treatment, separated gas is sent to GCP ( Gas Compressor Plant)
through GCS( Gas Collecting Station) in order to receive back compressed
gas sent at 3 kg/cm2 and received at 42 kg/cm2. Water fromGGS is sentto
ETP (Effluent Treatment Plant) and then to CWIP (CentralWater Injection
Plant) for its further treatment and injection into the well to enhance
recovery. Gas injection programmes arecarried out and controlled by the
To group the wells based on their pressure.
To group the wells based on quality of oil, i.e. pure or emulsion.
To isolate any well for testing purpose.
To divert any well to the required header through operation of
Used primarily to separate a combined liquid-gas well streaminto
components that arerelatively free of each other. The name separator
usually is applied to the vesselused in the field to separateoil & gas coming
directly fromoil or gas well, or group of wells.
Fluid enters tangentially and due to the sudden pressuredrop to the set
level, the fluid gets separated into liquid and gases. Baffles are fitted inside
the separator to help in better separation of fluid. The fluid is given greater
residence time to allow better separation.
FACTORS AFFECTING SEPARATION:
A. Operating pressure-
1. Dependent on GOR
2. Change in pressureaffects both the liquid and gas densities
3. In the allowable velocity
4. In actual flowing volumes
Net effect: increase in pressureleads to increased gas capacity of the separator in
Affects gas-liquid capacities only when it affects the actual flowing volumes
& densities.Net effect: increasein temperature leads to decreasein
Temperature control usually involves cooling as well streamflow temperatures
are generally abovethe optimum separation temperature. Expansion in the
cooling systemis widely used becauseHP gas is becoming more common and
little capital outlay is required.
C. Retention Time
After separation into gas and liquid in the separators the liquid containing oil and
water and dissolved gas is sent to the ‘Heater-Treater’. The gas from the
separators is sent to GCS.
Heater Treater is a horizontalvessel employing a vertical flow pattern. Methods
of heating, chemical action, electrical coalescence, water washing of oil & settling
for demulsification are used. Movements of fluid are controlled by differential
pressurecombined with static head.
COMPONENTS/PARTS OF HEATER TREATER:
Inlet degassing section
Differential oil control chamber
Coalescing section ( Electrical chamber)
• Inlet degassing section: Oil mixed with demulsifies enters the heater
Treater through degassing section, above the fire tubes. Free gas is liberated from
the flow stream & equalized across the entire degassing & heater areas of the
Treater. The degassing section is separated from heating section by baffles. The
fluid travels downwards from the degassing area and enters the heating section
under the fire tubes through multiple orifice distribution.
• Heating section: This section consists of a fire tube (U-tube) bent at 180
degrees. The constant level is maintained by weir height. Oil enters this section
from bottom of the degassing section & passes through heater at the bottom and
washing action takes place & free water & solids fall out of oil stream. The water
level in this section is controlled by a weighted, displacement type interface
control valve. The oil and entrained water flow upwards from the distributors
around the fire tubes, where the required temperature is reached. The increase in
temperature of oil releases some additional gas. The heat released gas then joins
the free gas from the inlet section and is discharged from the Treater through a
gas pressure control valve. Burners are designed for maximum heat output with
minimum fuel consumption &maintenance requiring little adjustments. Plots are
fixed type and require no adjustments. Fuel gas supply is to be properly adjusted
and regulated which is free of liquid and solid particles.
• Differential Oil Control Chamber: The heated fluid transfers from the
heating section over the fixed weir into a differential oil control chamber, which
contains a liquid level control float. The fluid travels downwards to near the
bottom of oil control chamber where the openings of the coalescing section
distributors are located.
• Coalescing section (Electrical Chamber): Heater Treater uses a high
voltage potential on the electrodes for coalescing of water droplets in the final
phase of processing. The electrodes are suspended on the insulated hanger from
the upper portion of the vessel. The ‘Ground’ electrode is furnished with solid
steel hangers to ensure grounding with the steel of the Treater. An externally
mounted, oil immersed high voltage transformer is furnished to provide the
power to the electrodes. The transformer uses 240 volts in primary and supplied
about 16500 volts in secondary. The high voltage secondary is connected to
charged electrode through a specially designed high voltage entrance. Secondary
is also connected to voltmeter and external pilot indicating lamp. The oil and
entrained water enter the coalescing section from the differential control
chamber through multiple, full length distributors. As the oil and entrained water
come into contact with the electrical field in the grid area, final coalescing of
water takes place. The water falls back to the water area at the bottom and the
clean oil continues to rise to the top, where it enters a collector and is discharged
through the clean oil outlet control valve.
CHECKS FOR HEATER TREATER:
2. Valves and controls and sightglasses
3. Safety valve
4. Fire tube
Fromthe heater treater the separated oil is sent to storagetanks and the water is
sent to ETP (Effluent treatment plant) for further treatment.
• To store oil before being pumped to CTF.
• To measurethe oil produced.
• Oil fromthe heater Treater is taken into overhead cylindrical tanks and
Fromhere the oil is sent to CTF, where oil from differentGGS is collected and
GCP (Gas CompressionPlant)
The main function of GCP (K) is to compress the gas received from GCS at 3.6
to 42 kg/cm2
and send it for gas injection purpose. The production is 5x105
/day. It has a total of 10 compressors (6 in old plant and 4 in new plant) and a
water treatment plant with 2 reverse osmosis plants (RO plant) and a chemical
The GCP compresses the gas and sends it back to GCS from where it is sent to
receivers like RIL, BharatVijay Mills etc. Itreceives gas fromGCS at 3.6 kg/cm2
compresses it to 42 kg/cm2
in two stages. In the first stage it compresses the gas
from 3.6 kg/cm2
to 13 kg/cm2
and in the second stage it compresses it from 13
to 42 kg/cm2
. This gas is then sent to GGS where it is used for gas
The various components of GCP are:
Reverseosmosis plant (RO Plant)
Cation and anion exchangers
Gas compressors are used to compress the gas to a high pressure of
so as to increase the flowing pressure. The compression is done
in two steps, in the first step it is compressed from 3.6 kg/cm2
to 13 kg/cm2
and id the second step from 13 kg/cm2
to 42 kg/cm2
The function of the discharge separator is to separate the gas from the
condensates during the discharge stage. It has the same process as that of
This is the storagedrum for the condensates which receives the condensate
(liquid hydrocarbon) from the inlet, suction and discharge separator. The
gas is sent to flare while the liquid hydrocarbons left at the bottom of the
drum is sent to CTF (central tank farm) for further treatment through a
condensate transfer pump.
Itis a type of heat exchanger. It contains baffles and is a shell and tube type
heat exchanger (one shell and two tubes). It is used to cool the gas and is
done at two points inter gas cooler (receiving gas from first stage
compression and second stage compression) and after gas cooler. In this
HE, water enters from one side and the gas from the other side and a
counter current flow takes place and the gas gets cooled.
Production rate = 5x105
Total compressors=10 (6 in old field and 4 in new)
Capacity of each compressor =2100 m3
Compressor type= 2RDH (2 stages, reciprocating, double acting, horizontal)
Compression ratio (r) = ¼
ETP (EFFLUENT TREATMENT PLANT)
The main function of this plant is to collect effluent water coming from GGS
and CTF and treat that water so that it can be used for injection purposes. It is
expected that this plant must receive water having 2000 ppm of oil content.
But sometimes this may not happen and hence oil must be removed and again
sent back to CTF from there. Finally the treated water is sent to water injection
plant for final treatment.
Waste water treatment plant also known as WWTP, has the same function as
that of ETP. WWTP receives waste water from the desalter plant and treats it.
The oil content in waste water is up to 100 ppm which is then recovered
Its main function is to receive water effluent from installations like GGS, CTF in
a controlled manner.
It helps in storing effluent water obtained. Here oil removed is sent to lagoon
via a pump and it is collected there as sludge. Mostly the storage tanks are
open roof type. Open roof types are preferred because the total cost of
treatment is not compensated in the floating roof type tanks.
There are 2-3 tanks for storage depending upon the dischargefromthe
Its main function is to separate oil from water by addition of compounds like
alum, catalyst polymers and non polymers.
It consists of blades which agitates the water with the addition of above
chemicals. Therefore water molecules are separated from oil molecules.
Finally after this process the whole solution is transferred to clariflocculator.
CLARI FLOCCULATOR: It consists of a huge circular cylindrical tank with a
hollow cylinder inside. The solution of oil and water enters through this hollow
cylinder with oil on top. Oil separates at the top of its periphery and pumped
through to a lagoon and collected as sludge there, whereas water is sent to
filter for further purification.
Its purposeis to filter the water for the impurities and contaminants presentin
The filter consists of membrane made up of sand and gravel. Water is
circulated here and all the particles are filtered by them. Back wash water
arrangementis also made in order to clean the filter when its cleaning is
required. After this the water is sent to conditioning tank wherepH level is
maintained by the addition of chemicals like SHMP. Finally the treated water
is sent to WIP (Water Injection Plant) where it is mixed with treated raw water
and sent to GGS for water injection purposes
The effluent water is received fromGGS-I (K), GGS-II (K), GGS-VII (K) and
CTF (K) through a common header.
This effluent first goes to SR-8 which is known as ‘Hold up Tank’. This
tank not only stores the effluent water, but also helps in separation of
oil and water by gravity separation. Using a pump the effluent water is
pumped to SR-7.
SR-7 is an ‘equalization tank’. In equalization tank the oil is recovered by
overflowing (done in a10 day interval). The oil at the top is removed by
spooning action and the effluent water is sent to SR-1.
SR-1 is a ‘Receiving Sump’. The effluent water flows from SR-7 to SR-1
due to gravity. From the receiving sump the effluent is pumped to flash
In flash mixture we add alum and a catalyst polymer (poly electrolyte).
These chemicals aid in the separation of oil and water as alum pushes
the water downwards, whereas the polyelectrolyte pushes the oil
The effluent is then sent to a clariflocculator (CF). It consists of a huge
circular cylindrical tank with a hollow cylinder inside. The solution of oil
and water enters through this hollow cylinder with oil on top. Oil
separates at the top of the periphery due to a rotary motion imparted
by the motor (centrifugal force acts). The sludge removed (oil) is sent to
The effluent is now sent to SR-2 due to gravitational force acting on the
effluent water. SR-2 is a ‘Clarified Water Tank’.
From SR-2 the effluent is pumped to media filters i.e. PF-I and PF-II. The
effluent water is made free of heavier impurities present in it.
From the media filters the effluent water is sent to SR-6 which is a
‘Conditioned Water Tank’. In conditioned water tank certain chemicals
are added to the water to free it of impurities such as bacteria.
From SR-6 the water is sent to CWIP (central water injection plant), for
SOBHASAN GGS cum CTF
SOB.CTF is designed to process crude emulsion produced from Sobhasan CTF oil
field. The crude emulsion from individual wells are received at the three nos. of
inlet manifold header from where the emulsion are fed to three separator (one
separator operating at 4.5kg/cm2 and other two separator operating at
2.5kg/cm2) to separate the gas from the liquid. The associated gas separated
from the separator is supplied to consumers and to GCP for compression. The
GCP in turn compresses this low pressure gas of 1.5kg/m2 to 47-49kg/m2 for gas
lift wells. The liquid from the separator is feed to the bath heater and heater
treaters working at 1.8kg/cm2 for separation of oil from water. Two nos. of bath
heater and ten no. of heater treaters are available in the installation are under
In the heater treater the oil is separated from the water, separated oil is stored in
the oil storagetank. There are 6no. of oil storagetanks, each of capacity 400m3.
The oil is kept in these tanks for about 16hours to settle down and then the free
water is drained to paraffin from these tanks beforedispatch to the mehsana CTF
through one no of BPCL pump capacity 45m3/hr and two no 9GR pump capacity
35 m3/hr. separated water fromthe heater treaters are simultaneously sentto
sobhasan effluenttreatment plant for further treatment of effluent before
injection into disposalwells. The emulsion accumulated at paraffin pit is recycled
to the heater treater with the help of the recycle pump and (11GR) of 15 m3/hr
capacity. Oil fromsomewell site is also transported through tankers to plant and
unloaded through 4 pumps, 2*35 m3/hr 9GR, 30m3/hr nemo pump and 11GR15
m3/hr. a mass flow meter is installed at the dispatch line to measurethe quantity
of oil dispatched to the Mehsana CTF.
Sobhasan GGS(Group Gathering Station) cum CTF(Central Tank Farm) which got
commissioned in 4th
October, 1975 is the third largest production installation in
the Mehsana Asset which handles crude and gas from the Sobhasan field. The
mehsana field being a matured field now requires secondary and tertiary
techniques for production. Gas laft and Enchanced oil recovery are some of the
techniques used in Mehsana. The wells under Sobhasan GGS cum CTF are mainly
on artificial lift i.e gas lift and Sucker rod pump.
The activities performed in Sobhasan GGS cum CTF can be summed up in
1. To receive emulsion and gas from wells.
2. To receive emulsion and low pressure (LP) gas from Sobhasan GGS-I.
3. To receive LP gas from Sobhasan GGS-II.
4. To receive /feed LP gas in Gas grid.
5. To receive emulsion from well site tanks through road tankers
6. Process of emulsion and to store treated oil in storage tanks and dispatch
to Mehsana CTF.
7. Compression of LP gas (1.5 kg/cm2) to HP gas (47-49 kg/cm2) for gas lift
(GLV) wells of Sobhasan Area.
8. Separated effluent is sent to Sobhasan ETP for further treatment and
9. LP gas supply to GAIL.
10.RO water plant is used for GCP cooling system, Steaming units, Drilling rigs
and for drinking purpose.
11.Testing of effluent sample, water cut and salinity of emulsion in Chemistry
12.LP gas is use for Gas engines, Heater treaters and bath heaters burner
Sobhasan GGS cum CTF got commissioned on 4th
GCP commissioned on 4th
Total no. of flowing wells: 72
C) Self flowing well: 06
D) SRP well: 15
E) Gas lift wells: 50
F) PCP 01
Total non-flowing wells: 20
Total liquid production: 2000-2100 m3
Net oil production: 460-470 m3/day
Effluent generation: 1500-1600 m3/day
Total gas compression: 5.50 lakh m3/day
Total gas sell to GAIL: 105
Oil and gas separator: 12
Heater Treater :- 10
Bath heater:- 02
Oil storage tanks:- 6 nos. (400 m3 capacity) 2 are under maintenance
Flare system: 01
Oil dispatch pumps: 04 nos. (43.5 m3/day)
Oil is being dispatched to: Mehsana CTF through 8” pipeline (20539.79 m3/day)
Fire water pumps 4 nos. (capacity 162 m3/hour of
For firefighting: two pumps, 425 & 437 m3/hr of two)
fire alarm system: electrical and hand operated
fire hydrants: 16
fire monitors: 12
Fire extinguishers: A) DCP type: 49 nos.
(As per OISD 189 STD 2012) B) Co2 type: 17 nos.
C) Foam type: 03 nos.
Gas detectors: 01 Portable
01 On line
First aid kit & breathing
Nearest fire station: ONGC fire station
Sobhasan fire station
Fire mock drill: twice in a month
Generator set: 1 nos. (capacity 250 KVA)
GAS COMPRESSION PLANT (GCP)
The gas compressor plant is related to the gas lift wells, it supplies
compressed gas for artificial gas lift wells. it compresses natural gas
available from the gas grid at 1.2kg/cm2 to 51kg/cm2 with the help of 3
stage compressor driven by 12 cylinder gas engine.
There are 5 compressors (3 in GCP I and 2 in GCP 2) at Sobhasan CTF, which
are maintained and operated by Dresser-Rand India Pvt. ltd. The capacity of
plant is around 470,000 m3/day.
a) Compressor: The gas is compressed in following 3 stages at increasing
b) Gas Engine: The 3 stage gas compressor is driven by 12 cylinder gas
engine. water with nalcol, an additive is used as a coolant, so as to
increase its heat capacity.
c) Air compressor: one air compressor with one standby is used to feed
compressed air to engine and measuring devices. The compressor works
at 14kg/cn2 as discharge.
Oil Transportation to Refinery:
The oil from different GGS and CTF is collected into Mehsana CTF and sent to the
desalter plant at Navagam, for desalination. After desalinating the crude ,and
meeting the required specifications, the crude is sold to the customer, Indian Oil
Corporation Limited’s (IOCL)refinery at Vadodara for downstream refining
processes and marketing.
ENHANCED OIL RECOVERY (EOR)
Overview: - In order to further enhance the recovery, Enhanced Oil Recovery
techniques are used. The general principle of EOR –
To improvesweep efficiency through reduction in mobility ratio.
Reduction in interfacial tension/capillary forces between rock and targeted
fluid i.e. oil.
Both the processes lead to improvedisplacement efficiency to flooding
forcegenerated by injectent.
The different methods of EORare-
Carbon dioxide injection
Hot fluid injection
Cyclic steam stimulation
Steam -assisted gravity drainage
A portion of the oil-in-place is oxidized and used as a fuel to generate heat. In the
in-situ combustion process, thecrude oil in the reservoir is ignited and the fire is
sustained by air injection. The process is initiated by continuous injection of air
into a centrally located injection well. Ignition of the crudeoil can either occur
spontaneously after air has been injected over some length of time of it requires
heating. Chemical reaction between oxygen in the injected air and the crude oil
generates heat without combustion. Depending on the crudecomposition,
kinetics of this oxidation process may be sufficient to develop temperatures that
ignite the oil. If not, ignition can be initiated by-
Down hole electric heaters.
Preheating injection air.
Preceding air injection with oxdisable chemicals.
4.2 Combustion Process
Combustion is the sequence of exothermic chemical reactions between a fuel and
an oxidant accompanied by the production of heat water and other gases.
4.3 Chemical reaction
Air + Fuel N2 + CO2 + CO + Water + Unreacted O2
(N2 and O2) (C and H)
4.4 Chemical reaction mechanism
The chemical reactions associated with the in-situ combustion process are
numerous and occur over different temperature ranges. Generally, in order to
simplify the studies, investigators grouped these competing reactions into three
classes: (1) low temperature oxidation (LTO), (2) intermediate temperature, fuel
formation reactions, and (3) high temperature oxidation (HTO) or combustion of
the solid hydrocarbon residue (coke).
The LTO reactions are heterogeneous (gas/liquid) and
generally results in production of partially oxygenated
compounds and little or no carbon oxides.
Medium temperature fuel formation reactions involve
cracking/pyrolysis of hydrocarbons which leads to the
formation of coke (a heavy carbon rich, low volatility
The high temperature fuel combustion reactions are
heterogeneous, in which the oxygen reacts with un-
oxidized oil, fuel and the oxygenated compounds to
give carbon oxides and water.
4.5 In-situ combustion Process
There are seven zones that have been recognized during the forward combustion
process, these are -
The burned zone
It’s the region that is already burned. This zone is filled with air and may contain a
small amount of residual unburned organic materials, it is essentially composed
primarily of clean sand that is completely free of its oil or coke content. Because
of the continuous air injection, the burned zone temperature increases from the
injected air temperature at the injector to the temperature at the combustion
leading edge. Since this zone is subjected to the highest temperature for a
prolonged period, they usually exhibit mineral alteration.
Combustion front zone
Ahead of the burned out zone is combustion front region with a temperature
variation ranging from 600®F to 1200®F. It is in this region that oxygen combines
with fuel and high temperature oxidation occurs.
The coke zone
Immediately ahead of the combustion zone is the coke region. The coke region
represents the zone where carbonaceous material has been deposited as a result
of thermal cracking of the crude oil. The coke residual fractions are composed of
components with high molecular weight and boiling point temperatures. These
fractions can represent up to 20% of the crude oil. Coke is not pure carbon, but a
hydrogen deficient organic material with an atomic hydrogen to carbon (H/C)
ratio between 0.6 and 1.6, depending upon the thermal decomposition (coking)
Ahead of the coke region is the vaporizing zone that consists of vaporized light
hydrocarbons, combustion products, and steam.
Further downstream of the vaporizing region is the condensing zone, from which
oil is displaced by several driving mechanisms. The condensed light hydrocarbons
displace reservoir oil miscibly, condensed stream creates a hot water flood
mechanism, and the combustion gases provide additional oil recovery by gas
drive. Temperature in this zone are typically 50®F-200®F above initial reservoir
Oil bank zone
The displaced oil accumulates in the next zone to form an oil bank. The
temperature in the zone is essentially near the initial reservoir temperature with
minor improvement in oil viscosity.
Further ahead of the oil bank lie’s the undisturbed part of the reservoir which has
not been affected by the combustion process.
4.6 Factors affecting in-situcombustion
Nature of the formation
The rock type is not important provided that the matrix/oil system is reactive
enough to sustain combustion. Swelling clays may be a problem.
Depth should be large enough to ensure containment of the injected air. There is
no depth limit, except that this may affect the injection pressure.
Pressure will affect the economics of the process, but does not affect the
technical aspects of combustion.
Temperature will affect auto ignition otherwise not critical
Thickness should be greater than about 4m to avoid excessive heat losses to
surrounding formations. Very thick formations may present sweet efficiency
problems because of gravity override.
This has to be sufficient to allow injection of air at the designed air flux.
Conditions are favourable when kh/μ is greater than about 5md m/cp3
Porosity and oil saturation
These have to be large enough to allow economic oil recovery. The product ØSo
need to be greater than 0.08 for combustion to be economically successful.
In heavy oil projects the oil should be readily oxidisable at reservoir and rock
matrix conditions. This relationship must be determined by lab experiments. The
same lab experiments can also determine the amount of air needed to burn a
given reservoir volume. This is key to the profitability of the process.
4.7 Scope of in-situ combustion Implementation
ISC is a unique oil recovery process. It can be viewed as a combination process. It
encompasses some aspects of nearly every known oil recovery method. These
include steam distillation, steam displacement, CO2 flood, hydrocarbon miscible
flood, immiscible gas (N2) displacement, and water (hot and cold) flood. Next to
water flooding, ISC is perhaps the most widely applicable improved oil recovery
technique. The major assets of ISC include the following-
Thermally, it is the most efficient oil recovery process.
It uses air, the least expensive and the most readily available fluid as
ISC can recover oil economically from a variety of reservoir settings. The
process has proven to be economically in recovering heavy oil (10-2O°API)
from shallow reservoirs (less than 1,500 ft.), and light oil (>30°API) from
deep reservoirs (1 1,000 ft.).
It is an ideal process for producing oil from thin formation. Economically,
successful projects have been implemented in sand bodies ranging in
thickness from4-150 ft. The process, however, proved to be most effective
in 10-50 ft. sand bodies.
The formation permeability has minimal effect on the process. Theprocess
has been successfully implemented in formations whose permeability
ranges from 5 md to 10,000 md.
The process can be applied in reservoirs where waterflood and/or
steamflood are not effective.
4.8 IMPLEMENTATION OF IN-SITU COMBUSTION IN MEHSANA:
As part of Mehsana Field is Heavy Oil belt like Lanwa, Balol, Santhal,
Field characteristics are:
High Reservoir Pressure ( 123 kg/cm2)
Active water drive
High Permeability of pay zone (in Darcy’s)
The features of Balol Main EOR centre:-
Presence of 5 Low Pressure and 5 High Pressure compressors which
produces the pressure of 123 kg/cm2 and volume of around 2,00,000
The presence of Water tank A of capacity 2520 m3 effluent water and
Water tank B of same capacity for Bore well water storage.
There are booster pumps to provide water pressure to make them flow to
the cooling chambers of the compressor, cooling units and injector well
Electrical transformers to step down the input voltage of 66000 V to output
of 6600 V for the compressors and 440 V for light motors and other usage.
4.9 Limitations of In-situ Combustion Process
Though air is free, it must be compressed and delivered to the formation.
The power required for compressing air together with maintenance costs
of the compressor are high enough that overall costs for delivering air to
the reservoir can be substantial. Relative to energy intensive steam
injection operation, the costs for in-situ combustion are lower only when
the formation is less than 40 ft. in thickness. For thicker reservoirs, theheat
losses during a steam chive are low enough to enable the heat to be
delivered at a lower cost.
Operational problems associated with combustion are more troublesome
and require a higher degree of technical sophistication to solve it. In
comparison, steam injection operations are relatively problem free.
Unlike the steam injection process design of in-situ combustion processes
must be preceded essentially by laboratory investigations. This is needed
to ascertain the burning characteristics of the crude, fuel availability and air
Thus, planning and design of a combustion project is more expensive.
While considerable improvements are being made in the application of this
technology, many operators still view this technology as a high-risk
operation. The commercial success of this process in the deep, extremely
low permeability carbonate, and elastic reservoirs in the U.S. had made
operators take a second look at this process.
The success of horizontalwell combustion technology in the heavy oil fields
of Canada has also contributed to revival of operators’ interest in this
process. Currently several new combustion projects are on the drawing
board, and one operator contemplates on implementing this process in a
deep offshore light oil reservoir.
ARTIFICIAL LIFT (A/L)
Artificial lift refers to the use of artificial means to increase the flow of liquids,
such as crude oil or water, from a production well. Generally this is achieved by
the use of a mechanical device inside the well (pump or velocity string) or by
decreasing the weight of the hydrostatic column by injecting gas into the liquid
some distance down the well. Artificial lift is needed in wells when there is
insufficient pressure in the reservoir to lift the produced fluids to the surface, but
often used in naturally flowing wells (which do not technically need it) to increase
the flow rate above what would flow naturally. The produced fluid can be oil
and/or water, typically with some amount of gas included.
Why use Artificial Lift?
Any liquid-producing reservoir will have a 'reservoir pressure': some level of
energy or potential that will force fluid (liquid and/or gas) to areas of lower
energy or potential. You can think of this much like the water pressure in your
municipal water system. As soon as the pressure inside a production well is
decreased below the reservoir pressure, the reservoir will act to fill the well back
up, justlike opening a valve on your water system. Depending on the depth of the
reservoir (deeper results in higher pressure requirement) and density of the fluid
(heavier mixture results in higher requirement), the reservoir may or may not
have enough potential to push the fluid to the surface. Most oil production
reservoirs have sufficient potential to produce oil and gas - which are light -
naturally in the early phases of production. Eventually, as water - which is heavier
than oil and much heavier than gas - encroaches into production and reservoir
pressure decreases as the reservoir depletes, all wells will stop flowing naturally.
At some point, most well operators will implement an artificial lift plan to
continue and/or to increaseproduction. Most water-producing wells, by contrast,
will need artificial lift from the very beginning of production because they do not
benefit from the lighter density of oil and gas.
Hydraulic pumping systems transmit energy to the bottom of the well by means
of pressurized power fluid that flows down in the wellbore tubular to a subsurface
pump. There are two types of hydraulic subsurface pump:
a) A reciprocating piston pump, where one side is powered by the injected fluid
while the other side pumps the produced fluids to surface, and
b) A jet pump, where the injected fluid passes through a nozzle creating a venturi
effect pushing the produced fluids to surface.
These systems are very versatile and have been used in shallow depths (1000 ft)
to deeper wells (18,000 ft), low rate wells with production in the tens of barrels
per day to wells producing in excess of 10,000 barrels per day (1,600 m³/d).
Certain substances can be mixed in with the injected fluid to help deal or control
with corrosion, paraffin and emulsion problems. Hydraulic pumping systems are
also suitable for deviated wells where conventional pumps such as the rod pump
are not feasible.
These systems have also some disadvantages. They are sensitive to solids and are
the least efficient lift method. While typically the cost of deploying these systems
has been very high, new coiled tubing umbilical technologies are in some cases
greatly reducing the cost.
Most oil reservoirs are of the volumetric type where the driving mechanism is the
expansion of solution gas when reservoir pressure declines because of fluid
production. Oil reservoirs will eventually not be able to produce fluids at
economical rates unless natural driving mechanisms (e.g., aquifer and/or gas cap)
or pressure maintenance mechanisms (e.g., water flooding or gas injection) are
present to maintain reservoir energy. The only way to obtain a high production
rate of a well is to increase production pressure drawdown by reducing the
bottom-hole pressure with artificial lift methods. Approximately 50% of wells
worldwide need artificial lift systems. The commonly used artificial lift methods
include the following:
Sucker rod pumping (SRP)
Gas lift (GL)
Electrical submersible pumping (ESP)
Hydraulic piston pumping
Hydraulic jet pumping
Progressing cavity pumping (PCP)
An artificial-lift method in which gas is injected into the production tubing to
reduce the hydrostatic pressure of the fluid column. The resulting reduction in
bottom hole pressureallows the reservoir liquids to enter the wellbore at a higher
flow rate. The injection gas is typically conveyed down the tubing-casing annulus
and enters the production train through a series of gas-lift valves. The gas-lift
valve position, operating pressures and gas injection rate are determined by
specific well conditions.
As the name denotes, gas is injected in the tubing to reduce the weight of the
hydrostatic column, thus reducing the back pressure and allowing the reservoir
pressure to push the mixture of produce fluids and gas up to the surface. The gas
lift can be deployed in a wide range of well conditions (up to 30,000 bpd and
down to 15,000 ft). They handle abrasive elements and sand very well, and the
cost of work over is minimum. The gas lifted wells are equipped with side pocket
mandrel and gas lift injection valves. This arrangement allows a deeper gas
injection in the tubing. The gas lift system has some disadvantages. There has to
be a source of gas, some flow assurance problems such as hydrates can be
triggered by the gas lift.
GLV is manually controlled
Injection pressure = 30-35 kg/cm2
Number of GLV’s present = 7 (Intermittent Gas lift)
Injection is done every 12 hours (one injection is done for 5 minutes)
Progressing Cavity Pump (PCP):
Progressing Cavity Pumps, PCP, arealso widely applied in the oil industry. The PCP
consists of a stator and a rotor. The rotor is rotated using either a top side motor
or a bottomhole motor. The rotation created sequential cavities and the
produced fluids are pushed to surface. The PCP is a flexible system with a wide
range of applications in terms of rate (up to 5,000 bpd and 6,000 ft). They offer
outstanding resistance to abrasives and solids but they are restricted to setting
depths and temperatures. Some components of the produced fluids like
aromatics can also deteriorate the stator’s elastomer.
Progressive cavity pump
SUCKER ROD PUMPING(SRP):
Sucker rod pumping is also referred to as ‘‘beam pumping.’’ It provides
mechanical energy to lift oil from bottom hole to surface. It is efficient, simple,
and easy for field people to operate. It can pump a well down to very low
pressure to maximize oil production rate. It is applicable to slim holes, multiple
completions, and high-temperature and viscous oils. The system is also easy to
change to other wells with minimum cost. The major disadvantages of beam
pumping include excessive friction in crooked/ deviated holes, solid-sensitive
problems, low efficiency in gassy wells, limited depth due to rod capacity, and
bulky in offshore operations. Beam pumping trends include 50 improved pump-
off controllers, better gas separation, gas handling pumps, and optimization using
surface and bottom-hole cards.
An artificial-lift pumping systemusing a surfacepower sourceto drive a downhole
pump assembly. A beam and crank assembly creates reciprocating motion in a
sucker-rod string that connects to the downhole pump assembly.
(SRP) The rod pump is the most common artificial-lift system used in land-based
operations. The relatively simple downhole components and the ease of servicing
surface power facilities render the rod pump a reliable artificial-lift system for a
wide range of applications.
Gear type = helical
Number of gears (in gearbox) = 3
Polished rod diameter = 38 mm
Catcher depth (depth till which sucker rod is lowered) = 1350 m
Ball seat depth = 1380-1400m
Production from SRP = 4 m3/day
Bearing size = 32” 314
Make : Russian
Estimated cost = Rs. 15-18 lakh
3) Enhanced oil recovery operation manual(completed by : surface Team)
4) Brown, Kermit E. (1980). The Technology of Artificial Lift Methods,
Volumes 1, 2a and 2b. Tulsa, OK: PennWell Publishing Co