AMIT NITHARWAL

SUMMER TRAINEE UniversityCollege of

Engineering, RTU, KOTA

University

PROJECT REPORTON SURFACE OPERATIONS

FOR OIL/GAS WELL Submitted by

AMIT NITHARWAL

Students of 6th semester of B.Tech (Petroleum Engineering)

University College of Engineering, RTU, Kota

Under GuidanceAnkit GuptaEE (Production)

Oil & Natural Gas Corporation Limited

Mehsana Asset

ACKNOWLEDGEMENT

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.

AMIT

NITHARWAL Student of B.Tech (PETROLEUM)

University College of Engineering, RTU, Kota Tra

inee Camp: - Oil & Natural Gas

Corporation Limited, Mehsana Asset

Oil and Natural Gas Corporation Limited Mehsana Asset

Certificate

This is to certify that AMIT NITHARWAL. Student of B.Tech. Petroleum Engineering 3rd year, University College of Engineering, RTU, Kota has successfully completed his summer training on “SURFACE OPERATIONS FOR OIL/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

EE(Production)

Contents:S.R Description1 About ONGC

2 About ONGC’S Mehsana Asset

3 Journey of Crude oil

4 Surface facility4.1 South santhal (GGS Cum CTF)

4.1.1 Overview4.1.2 GCP4.1.3 ETP

4.2 Sobhasan (GGS Cum CTF)4.2.1 Overview

4.2.2 GCP

5 EOR5.1 Overview5.2 Insitu combustion

6 Artificial Lift6.1 Overview6.2 PTYS

7 References

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. It has 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 Government. 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's domestic production. Of this, over 75% of crude oil produced is Light & Sweet. The Company holds the 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. Pandit Nehru 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 years of its existence ONGC has crossed many a milestone to realize the energy dreams of India. The journey of ONGC, over these years, has been a tale of conviction, courage and commitment. ONGCs’ superlative efforts have resulted in converting earlier frontier areas into new hydrocarbon provinces. From a modest beginning, ONGC has grown to be one of the largest E&P companies in 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 Natural Gas Corporation Ltd. (ONGC) is, the leader in Exploration & Production (E&P) activities in India having 72% contribution to India’s total production of crude oil and 48% of natural gas. 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 Mehsana Asset

The oil and natural gas corporation ltd. (ONGC) is India’s biggest integrated oil company having major interest in E&P activities. Mehsana Asset, about 60km. from Ahmedabad is located in northern part of Gujarat state. it is the highest oil producing onshore asset of ONGC. The asset has oil fields producing both heavy and light crude with API gravity ranging from 130-420 API. The heavy oil fields viz. SANTHAL, BALOL, LANWA and BECHRAJI having API gravity between 130-170 falls in the northern part of CAMBAY basin.

LANWA, BALOL and SANTHAL fields have contiguous structure with only geographical demarcation 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 are channel sands and the major pay sand kalol is distributed in the entire length of the heavy oil belt. The structure is a homocline diping NNW-SSE with dip ranging from 20-60. Towards the eastern side all along the length of the heavy oil belt is an infinite aquifer which provide pressure support. In the western side, the heavy oil belt abuts against the uplifted block called the Mehsana Horst where the Kalol sands thin out. Kalol sands occur at a depth of 950 to 1000m with average reservoir pressure of about 100kg/cm2.

Oil viscosity increases from south to north. In southern part of santhal field. The oil viscosity is about 50cp and in the northern part of Lanwa field it is about 1500cp at reservoir temperature of 70`C. because of the viscous nature of 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.

Sr. No.

Areas Asset production(TPD)

Area production Previous day(MT)

Area production Today(MT)

1 N. KADI 1540 1488 15002 SOBHASAN 848 881 8623 SANTHAL 1330 1355 13404 BALOL 488 462 4645 JOTANA 216 235 2396 NANDASAN 497 487 4687 LANWA 202 177 176

8 BECHARAJI 224 204 2129 LINCH 471 469 50310 LANGHNAJ 85 108 11011 MANSA 21 10 17TOTAL(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 (WWTP).

Oil is produced through three types of wells:

a) Self Drive Wells

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).

Process Description:- Oil is received in GGS- 7(k) from the wells through 4” pipelines into the following headers 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 Emulsion Header:- 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. HP header:- Well fluid flows from header & goes to emulsion separator – 2 / HP separators . From separator 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. Separators:- Five separators 7-v-01, 02, 03, 04, 05 having a designed capacity to handle 580m^3 day of well fluid are provided. Out of these separators 7-v-01 is meant for group production with all instrumentation, 7-v-02 is meant for testing of wells & 7-v-03,04,05 are meant for 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 pressure in 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 treater. 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 protect the vessel against over pressure. The valves are set at a pressure of 6.6kg/cm2 & PSV – 106 set ata a pressure 16.5 kg/cm2.

Typical oil and gas production flow diagram

South santhal (GGS cum CTF)

1) Discovery: - South santhal CTF of Mehsana Asset was discovered in 1971.The installation is integrated with a gas compressor plant (GCP) and ETP.

2) Structure: - The santhal field is the southern segment of heavy oil belt comprising Lanwa, Balol and santhal field located in north cambey basin.

3) Reservoir:-The 150m thick sandstone with in kalol formation ,middle Eocene age occurring a depth of about 150m constitute the reservoir ,the sand are medium coarse grained ,poorly consolidate with thin discontinuous shale layers.

1) avg. porosity=28%2) permeability=8-15 Darcy3) reservoir pr.=105kg/cm24) initial oil saturation=65-80%

4) Reserves: - The initial oil in place is estimated to be 54MMT of which 8.01MMT is recoverable under natural drive. The total recoverable reserves 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. The field initially produced oil@34TPD through 3 wells.

5) Oil &gas properties: crude oil gravity 170 API and reservoir viscosity is 60 cp.

WELL DETAILS:

Total no. of flowing wells: 127A) Self flowing well: 14B) SRP well: 113 Total non-flowing wells: 40

PRODUCTION DETAILS:

Total liquid production: 3300 m3/day Net oil production: 1200 m3/day Effluent generation: 2100 m3/day Total gas compression: 50,000 m3/day

PROCESSING FACILITIES:

Oil and gas separator: - 02 Heater treaters :- 10 Oil storage tanks:- 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 dispatched to: Mehsana CTF through 8” pipeline (20539.79 m3/day)

SAFETY FACILITIES:

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 Drenchers: 06

Fire extinguishers: A) DCP type: 49 nos.

B) Co2 type: 17 nos.

C) Foam type: 03 nos. Gas detectors: 01 Portable

01 On line First aid kit & breathing

Apparatus: Available

Nearest fire station: ONGC fire stationSanthal 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 from its different assigned fields. Crude is separated here in the form of 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 from GGS is sent to ETP (Effluent Treatment Plant) and then to CWIP (Central Water Injection Plant) for its further treatment and injection into the well to enhance recovery. Gas injection programmes are carried out and controlled by the specified GGS

GROUP SEPARATOR

STORAGE TANK

HEATER TREATER

TEST SPARATOR

SEPARATOR

DEMULSIFIER DOSING TANK

GAS TO GCP

DOSING PUMP

EFFLUENT WATER TO ETP

OIL TO CTF

OIL TRANSFER PUMP

OIL

VALVE MANIFOLD

EMULSION, TEST & GROUP HEADER

OPERATING SYSTEMS

VALVE MANIFOLD:

Purpose-

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

valves.

SEPARATOR:

Purpose-

Used primarily to separate a combined liquid-gas well stream into components that are relatively free of each other. The name separator usually is applied to the vessel used in the field to separate oil & gas coming directly from oil or gas well, or group of wells.

Process-

Fluid enters tangentially and due to the sudden pressure drop 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 pressure affects both the liquid and gas densities

3. In the allowable velocity

4. In actual flowing volumes

Net effect: increase in pressure leads to increased gas capacity of the separator in scf/cm

B. Temperature-

Affects gas-liquid capacities only when it affects the actual flowing volumes & densities.Net effect: increase in temperature leads to decrease in capacity.

Temperature control usually involves cooling as well stream flow temperatures are generally above the optimum separation temperature. Expansion in the

cooling system is widely used because HP 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:

Heater Treater is a horizontal vessel 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 pressure combined with static head.

COMPONENTS/PARTS OF HEATER TREATER:

Inlet degassing section Heating 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:

1. Burners2. Valves and controls and sight glasses3. Safety valve4. Fire tube

From the heater treater the separated oil is sent to storage tanks and the water is sent to ETP (Effluent treatment plant) for further treatment.

STORAGE SYSTEM:

Purpose-

• To store oil before being pumped to CTF.

• To measure the oil produced.

Process-

• Oil from the heater Treater is taken into overhead cylindrical tanks and subsequently measured.

From here the oil is sent to CTF, where oil from different GGS is collected and measured.

GCP (Gas Compression Plant)

INTRODUCTION:

The main function of GCP (K) is to compress the gas received from GCS at 3.6 kg/cm2 to 42 kg/cm2 and send it for gas injection purpose. The production is 5x105

m3/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 treatment plant.

The GCP compresses the gas and sends it back to GCS from where it is sent to receivers like RIL, Bharat Vijay Mills etc. It receives gas from GCS at 3.6 kg/cm2 and 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 kg/cm2 to 42 kg/cm2. This gas is then sent to GGS where it is used for gas injection.

PLANT DISCRIPTION:

The various components of GCP are:

Inlet separator Gas compressors Discharge separators Condensation drum Gas coolers Reverse osmosis plant (RO Plant) Degasser tank Cation and anion exchangers Cooling towers

GAS COMPRESSORS:

Gas compressors are used to compress the gas to a high pressure of 42kg/cm2 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.DISCHARGE SEPARATOR:

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 inlet separator.

CONDENSATE DRUM:

This is the storage drum 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.

GAS COOLERS:

It is 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.

FIELD SPECIFICATIONS:

Production rate = 5x105 m3/day. Total compressors = 10 (6 in old field and 4 in new) Capacity of each compressor = 2100 m3/hr Compressor type = 2RDH (2 stages, reciprocating, double acting, horizontal) Compression ratio (r) = ¼

ETP (EFFLUENT TREATMENT PLANT)

INTRODUCTION:

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 through treatment.

OPERATIONS:

MANIFOLD:

Its main function is to receive water effluent from installations like GGS, CTF in a controlled manner.

STORAGE TANK:

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 discharge from the installation.

AGITATOR:

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.

FILTER:

Its purpose is to filter the water for the impurities and contaminants present in it.

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 arrangement is also made in order to clean the filter when its cleaning is required. After this the water is sent to conditioning tank where pH 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

PROCESS DISCRIPTION:

The effluent water is received from GGS-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 mixture.

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 upwards.

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 a lagoon.

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 injection purposes.

SOBHASAN GGS cum CTF

Overview:-

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 operation.

In the heater treater the oil is separated from the water, separated oil is stored in the oil storage tank. There are 6no. of oil storage tanks, 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 before dispatch to the mehsana CTF through one no of BPCL pump capacity 45m3/hr and two no 9GR pump capacity 35 m3/hr. separated water from the heater treaters are simultaneously sent to sobhasan effluent treatment plant for further treatment of effluent before injection into disposal wells. 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 from some well site is also transported through tankers to plant and unloaded through 4 pumps, 2*35 m3/hr 9GR, 30m3/hr nemo pump and 11GR 15 m3/hr. a mass flow meter is installed at the dispatch line to measure the quantity of oil dispatched to the Mehsana CTF.

Introduction:

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 following points:

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 tankers6. 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

disposal.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

Laboratory.12.LP gas is use for Gas engines, Heater treaters and bath heaters burner

system.

Sobhasan GGS cum CTF got commissioned on 4th October 1975.

GCP commissioned on 4th April 2006.

WELL DETAILS:

Total no. of flowing wells: 72C) Self flowing well: 06D) SRP well: 15E) Gas lift wells: 50F) PCP 01 Total non-flowing wells: 20

PRODUCTION DETAILS:

Total liquid production: 2000-2100 m3/day 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 m3/day

PROCESSING FACILITIES:

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)

SAFETY FACILITIES:

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 Drenchers: 06 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

Apparatus: Available

Nearest fire station: ONGC fire stationSobhasan 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 pressure ratios1st stage 1.2-7.5kg/cm2 2nd stage 7.5-21kg/cm23rd stage 21-51kg/cm2

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 improve sweep 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 improve displacement efficiency to flooding

force generated by injectent.

The different methods of EOR are- Chemical flood

Polymer Surfactant slug Alkaline Miscellar Alkaline-surfactant-polymer (ASP)

Miscible Hydrocarbon miscible flooding Carbon dioxide injection Nitrogen injection

Thermal methods Hot fluid injection Cyclic steam stimulation Steam flooding In-situ combustion Steam -assisted gravity drainage

Others MEOR

In-situ combustion

4.1 Introduction A portion of the oil-in-place is oxidized and used as a fuel to generate heat. In the in-situ combustion process, the crude 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 crude oil 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 crude composition, 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 hydrocarbon fraction).

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) conditions.

Vaporizing zone

Ahead of the coke region is the vaporizing zone that consists of vaporized light hydrocarbons, combustion products, and steam.

Condensing zone

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 temperature.

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.

Undisturbed reservoir

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-situ combustion

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

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

Pressure will affect the economics of the process, but does not affect the technical aspects of combustion.

Temperature

Temperature will affect auto ignition otherwise not critical Reservoir thickness

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.

Permeability

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.

Oil nature

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 injectent.

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 from 4-150 ft. The process, however, proved to be most effective in 10-50 ft. sand bodies.

The formation permeability has minimal effect on the process. The process 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, Becharaji

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 Nm3/day.

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 header system.

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, the heat 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 requirements.

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 horizontal well 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)

Introduction:-

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, just like 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 increase production. 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 Plunger lift Progressing cavity pumping (PCP)

GAS LIFT: 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 pressure allows 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.

FIELD SPECIFICATIONS:

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, are also 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 system using a surface power source to 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.

FIELD SPECIFICATIONS:

SRP Specifications: 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

References:-

1) www.wikipidia.com2) www.ongcindia.com

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