Gajendra Singh(ONGC Training Report)

Industrial Tranning Report-2011 Report-2011

Su m m m e r T r a i n i n g P r o j e c t o n

P r o d u c t i o n o f O i l A n d N a t u r a l G a s TRAINING PERIOD

:-

07-05-2011 TO 06-07-2011

SUBMITTED TO: Mrs. Madhu Agarwal Chemical Engineering MNIT, JAIPUR

SUBMITTED BY: Gajendra Singh 2008UCH125

Malaviya National Institute of Technology, Jaipur

Departement of Chemical Engineering, MNIT Jaipur

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ACKNOWLEDGEMENT

I wish to acknowledge the encouragement received from Mr. S.K. JANA

(HOD,

Chemical

engineering

department,

MNIT,

JAIPUR) & Mr. Rohit Goyal (Training incharge) for initiating my

interest in training. I earnestly acknowledge my profound sense of gratitude to Mr. Poddar. His mastery & work helped me in covering out this work

smoothly. I am also grateful of all the workers of various departments who have helped me to improve my thinking as well as the practical knowledge. Finally, I wish to add that I am indebted to god & My parents for everything good that has happened to me.

Gajendra Singh


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PREFACE

Practical training is a way to implement theoretical knowledge to practical use to become a successful engineer. It is necessary to have a sound practical knowledge because it is only way by which one can acquire proficiency & skill to work successfully different industries. It is proven fact that bookish knowledge is not sufficient because things are not as ideal in practical field as they should be. This report is an attempt made to study the overall production system & related action of Oil And Gas, Mehsana a unit a ONGC. It is engaged in production of highest oil and gas in over Gujarat. As compare with Ahmedabad asset and Ankleshwar Asset by production.

Gajendra Singh


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CONTENTS

CHAPTER-1

Introduction to the mehsana field:

1.1 Brief discription about the mehsana asset:.................. asset:............................... .........................1 ............1 1.2 Special features of o f mehsana asset...................... asset.................................. .............................. .......................3 .....3 1.3 Brief about balol heavy oil field................... field............................. .......................... ............................. ..............3 .3 1.4 A brief about on going schemes schemes in mehsana asset.......................... asset..............................4 ....4 CHAPTER-2

Santhal GCS (Gas Collection Station)

2.1 Introduction............... Introduction........................... ........................ ........................ ......................... ........................... ..........................5 ............5 2.2 GCS facilities................ facilities............................ ........................ ......................... ......................... ......................... .......................5 ..........5 2.3 Gas Compression Plant (GCP)-Santhal................. (GCP)-Santhal............................. ......................... .................9 ....9 2.4 GCP Facilities................. Facilities............................. ......................... ........................ ....................... .......................... ....................10 ......10 2.5 Central Farm Tank (CTF)-Santhal................. (CTF)-Santhal............................. ......................... ........................13 ...........13 2.6 Effluent Treatment Plant (ETP)Ii(Santhal).............. (ETP)Ii(Santhal).......................... ........................ ...............18 ...18 2.7 ETP Facilities................ Facilities............................ ........................ ......................... ......................... ......................... ....................19 .......19 2.8 Artificial Lift (Mehsana)..................... (Mehsana)................................. ......................... .......................... ......................22 .........22 2.9 Heater Treater................. Treater............................. ......................... ........................ ....................... .......................... ....................26 ......26 CHAPTER-3 Enhanced Oil Recovery (EOR)

3.1 Introduction………………………………………….……………...30 3.2 Eor-The Future Of India……………………………………………30 3.3 What Is Eor (Enhanced Oil Recovery)………………….…………30 Departement of Chemical Engineering, MNIT Jaipur

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3.4 Selection Of EOR Techniques……………………………...……….31 3.5 Major Constraints To Eor Development……………………………31 3.6 Eor Techniques…………………………………………………...…32

CHAPTER-4 In-Situ combustion process 4.1 Concept:.................... Concept:................................ ........................... ........................... ......................... ........................ ....................... ..............35 ..35

4.2 Introduction............... Introduction........................... ........................... ............................ ......................... ........................ ........................ .............35 .35 4.3 In-Situ combustion processes........................ processes..................................... ......................... ........................ ...............36 ...36 4.3.1 Dry combustion...................... combustion..................................... ........................... ......................... ........................36 ...........36 4.3.2 Wet combustion.................... combustion................................. .......................... ......................... ........................ ..............40 ..40 4.3.3 Reverse combustion................. combustion................................ ........................... ......................... ......................40 .........40 CHAPTER-5 Kinetics and combustion tube studies

5.1 Introduction.............. Introduction........................... ......................... ........................ ........................ ........................ ......................... ..................42 .....42 5.2 Chemical reactions associated with in-situ in -situ combustion......................... combustion.........................42 42 5.2.1 Low temperature oxidation..................... oxidation................................. ......................... ........................ ...........43 43 5.2.2 The pyrolysis reactions..................... reactions................................. ........................ ........................ ..................44 ......44 5.2.3 High Temperature Oxidation.................... Oxidation................................. ....................... .....................46 ...........46 5.3 Reaction Kinetics ..................... ................................. ........................ ........................ ........................ ........................... ...............47 47 5.4 Factors Affecting Oxidation Reactions................... Reactions................................. .......................... ...................49 .......49


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LIST OF TABLES Table-1.1 Production Of Oil In Mehsana.......................... Mehsana....................................... ........................ ...............2 ....2 Table-1.2 Comparison of Mehsana ONGC Production With Ankleswar And Ahmedabad...................... Ahmedabad................................... ........................ ....................... .............3 .3 Table-1.3 Location Of In-Situ Combustion Wells In Mehsana ONGC..........3

Table:2.1- GasAnalysis.........................................................................7

LIST OF FIGURES Figure:2.1-GCS ( Gas Collection Station).................. Station).............................. ........................ ........................ ..................8 ......8 Figure:2.2-Process FlowDiagram of GCP-Santhal..................... GCP-Santhal................................. ........................ ............12 12 Figure:2.3-CTF (Central Tank Farm).................. Farm).............................. ........................ ........................ .......................16 ...........16 Figure:2.4- Flow Diagram of GGS....................... GGS................................... ........................ ........................ ......................17 ..........17 Figure:2.5-ETP (Effluent Treatment Plant).................. Plant).............................. ........................ ........................ ..............20 ..20 Figure:2.6-Gas Lift……………........................... .......................... ...................................... ....................25 ........25 Figure:2.7- Parts of Conventional pmping unit ….............................................25 Figure:2.8-Casing and Tubing…........................................................................26 Figure:2.8-Parts Figure:2.8-Parts of Conventional pmping unit…………………………............ unit…………………………................……..26 ....……..26

Figure:2.9-Horizantal heater-treater ...................... .................................. ......................... ........................ ...................29 ........29 Figure 4.1- In-Situ Combustion Schematic Temperature Profile.......................37 Profile.......................37 Figure 4.2 - Schematic of Temperature Profile for Dry Combustion (After Moore et al., 1996).................... 1996)................................ .......................... .......................... .................34 .....34


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1.1 BRIEF DISCRIPTION ABOUT THE MEHSANA ASSET: Oil & Natural Gas Corporation Ltd. is one of the leading public sector enterprises in the country with substantial contribution to the energy demand in particular and industrial and economic growth in general. Born as a modest corporation house in 1956 as commission, commission, ONGC has growth today into a fullfledged integrated upstream petroleum company with in-house service capabilities and infrastructure in the entire range of oil and gas exploration exploration and production activities. It is one of the ten Public Sector enterprises (Navaratna’s) of India and has achieved excellence over the years and in on the path of future growth.

For practical implementation of the programs , ONGC has created a number of work units called projects (now asset) and execute in various operational programs spread throughout the length and breath of the country. MEHSANA project is one of such asset of the onshore area. Mehsana project is covering an area of about 6000 sq kms. From the north part cambay basin between latitude 23.23’ and 23.45’ and longitude 71.45’ and 72.45’ east. Ti is situated at a distance of 72 kms of Ahmedabad city in the North West direction. th

Mehsana project was started as an independent project on 7 November, 1967 when it was bifurcated from Ahmedabad project for administrative and operational convenience the project’s establishment was shifted to Mehsana and Ahmedabad project for closer administrative and operational control when the exploratory drilling in this part was vigorously taken up. At present Mehsana project comprises of Mehsana district and parts of Banaskanta, Patan and Ahmedabad districts. EXPLORATION efforts around Mehsana date back to the year 1964. Through the very first well drilled on Mehsana horst did not give encouraging results, subsequent well Mehsana-2 in allora structure gave a lead for further exploration. Mehsana project is well known for heavy oil belt, characterized by high viscosity crude. Due to viscous nature of crude resulting in the adverse mobility ration and low API gravity, the primary oil recovery factor is in the range of 6.5 to 15.8%. The techniques of IN-SITU IN-SITU COMBUSTION COMBUSTION “AN ENHANCED OIL RECOVERYPROCESS” for this heavy oil field was successfully implemented Departement of Chemical Engineering, MNIT Jaipur

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at Mehsana project on pilot basis in 1990. The success of process at the pilot project further led to the commercialization scheme that are currently under various stage of implementation at the Mehsana project. Under commercialization scheme a major project name BALOL MAIN IN-SITU COMBUSTION PLANT has been implemented to exploit the heavy crude oil of Balol oil field. THE BALOL MAIN ICP has been commissioned on 15-011999.The major oil field under the MEHSANA MEHSANA ASSET ASSET and north kadi, Sobhasan, Balol, Santhal, Jotana, Nandasan, Lanwa, Becharaji, Linch and other small fields. The asset is assigned the performance targets. 7 Deep Drilling Rigs and 16 Works Over Rigs are working in the projects, in additions to 35 production installations. The present production target is 3.25 MMT of crude oil per annum. The production wise distributions of fields are as follows (as on 31-012002) SERIAL NO.

MAJOR OIL FIELDS IN MEHSANA 1 North kadi 2 Shobhasan 3 Santhal 4 Santhal(EOR) 5 Jotana 6 Balol 7 Lanwa 8 Bechraji 9 Nandasan 10 Linch 11 Other 12 TOTAL PRODUCTION TABLE-1.1 Production Of Oil In Mehsana


TPD

1705 1129 1128 575 493 597 121 336 249 261 203 6127

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1.2 SPECIAL FEATURES OF MEHSANA ASSET (a) Largest onshore production with least manpower PLACE MANPOWER PRODUCTION Mehsana 3200 6200 tones per day Ankleswar 3700 6000 tones per day Ahmedabad 3400 4000 tones per day TABLE-1.2 Comparison of Mehsana ONGC Production With Ankleswar And Ahmedabad

(b) Highly viscous oil Only Asset to have IN-SITU combustion project employed in ONGC at such a large scalz Sr n o 1 2 3 4

Project Name

Operator

Balol Lanwa Balol Santhal

ONGC ONGC ONGC ONGC

5

Bechraii ONGC

Date initiat -ed 1990 1992 1996 1996

Combusti Oil o on type gravity, API Wet 15.6 Wet 13.5 Dry 15.6 Dry 17

No of injecto -rs 1 1 -

No. of producers 4 4 -

1996

Dry

-

-

15.6

TABLE-1.3 Location Of In-Situ Combustion Wells In Mehsana ONGC

(c) Sandstone structure.

1.3 BRIEF ABOUT BALOL HEAVY OIL FIELD Balol oil field is the center part of this heavy oil belt with Santhal field on the southern and Lanwa on the northern side. There are two different pay sections in this field namely Balol pay and Kalol pay. The Kalol pay is the main oil bearing horizon extended through out the field. Main features of fields are as follow:


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(a) Main pay sand is medium to coarse grained, clean well settled and unconsolidated to semi consolidated in nature. It has an average porosity of 28% and permeability of 5000 to 15000 md and has an edge water drive. (b) Initial oil is place is about 29.67 MMT, the Balol phase-I covers IOIP of 2.27 MMT and Balol main covers area having h aving 15.12 MMT of the affected sand. o (c) Reservoir temperature is about 70 C and has an oil saturated ranging o from 75-90 C. (d) The crude oil produced from the field has asphaletene base has an average viscosity of 150 cp at reservoir condition in southern part. The viscosity increases gradually as one move from southern par. It has o specific gravity of 0.96 (API-16) and pour point 9 C.

1.4 A BRIEF ABOUT ON GOING SCHEMES IN MEHSANA ASSET (a) E.O.R      

Balol Santhal Bechraji Lanwa Extended Pilot CSS Lanwa North kadi INSITU-Combustion Pilot

(b) I.O.R    

North kadi Jotana Santhal Sobhasan

(c) WATER INJECTION Jotana Sobhasan  


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2.1 INTRODUCTION Receiving Status:

Total Wells Connected-30 Total Working Wells- 16 2

Receiving pressure-4kg/cm Objectives: 

To collect natural gas from wells



To collect associated gas from GGS



To send gas to GCP.



To send compressed gas (CG) to GGS for artificial lifting lifting

Functions :

Its main function is gas collection and distribution. GCS receives associated gas from GGS and natural gas directly from the wells. They both are mixed in scrubber, treated and they are transferred to GCP for further compression. Now the compressed gas is again received back by GCS and then the compressed gas is sent to various destinations.

2.2 GCS FACILITIES 1. MANIFOLDS 

Gas grid manifold (to provide high pressure compressed gas through 4’’ & 6’’ pipeline to north and south Santhal gas system)

2. BEAN HOUSING 

to control the the flow of gas from the reservoir

3. SCRUBBER

Purpose 

It is a purifier that removes impurities from gas. Scrubber systems are a diverse group of air pollution control devices that can be used to remove


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particulates and/or gases from industrial exhaust streams. Traditionally, the term “scrubber” has referred t o pollution control devices that use liquid to “scrub” unwanted pollutants from a gas stream. Recently, the term is also used to describe systems that inject a dry reagent or slurry into a dirty exhaust stream to “scrub out” acid gases. Scrubbers are one o f the primary devices that control gaseous emissions, especially acid gases. Process 

It involves the addition of an alkaline material (usually hydrated lime and soda ash) into the gas stream to react with the acid gases. gases . The acid gases react with the alkaline sorbents to form solid salts which are removed in the particulate control devices. These systems can achieve acid gas (SO2 and HCl) removal efficiencies.

4. SEPARATOR 

2

Functions at 4kg/cm



In this only natural gas is separated to remove any condensed liquids if present. The gas firstly goes to separator then to scrubber.

5. STORAGE TANK 

3

3 storage tanks of 45m are present but they are not under usage.

6. VALVES 

Shut down valve-used in case of leakage or in any other emergency



Control valves- when pressure in the pipelines increases beyond the limit then these valves get open itself to prevent danger.

7. FLARE 

Used for burning off unwanted gas or flammable gas released by pressure relief valves during unplanned over-pressuring of plant equipment.


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Gas Analysis COMPOUND

MOL%

Methane(CH4)

87.150

Nitrogen(N2)

0.160

Carbon di oxide(CO2)

1.36

Ethane(C2H6)

5.22

Propane(C3H8)

2.5

Water(H2O)

0

Hydrogen bi sulfate(H2S)

0

Carbon monoxide(CO)

0

Oxygen(O2)

0

I-butane

1.35

N-butane

0.82

I-pentane

0.36

N-pentane

0.39

Hexane

0.68

Heptane

0

Octane

0

Nonane

0

Table:2.1- GasAnalysis


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Figure:2.1-GCS ( Gas Collection Station)

2.3 GAS COMPRESSION PLANT (GCP)-SANTHAL 3

Total Capacity : 5 lacks m /day Total Compresors : 10

6 in old plant and 4 in new plant 3

Capacity (old) =3 lacks m /day 3

Capacity (new) = 2 lacks m /day Reverse-Osmosis Plant (R-O): two Departement of Chemical Engineering, MNIT Jaipur

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Discharge Pressure : 40 kg/cm

2

Process Description : 2

In this plant, gas from GCS (gas collecting system) at 4kg/cm pressure comes through pipelines to GCP. Firstly it goes to common inlet separator, where the primary separation is done, usually the content of oil in gas is st negligible but if it’s there it gets separated. Now the gas goes to 1 stage suction separator, there further separation is done. Till now the pressure is 2 4kg/cm , now this gas goes for first stage compression goes into compressor. 2 After compression the gas we get is of 12-14 kg/cm and because of 0 compression temperature rises to 125 C so to low down the temperature to 0 40-45 C, compressed gas is sent to inter gas cooler. 2

nd

Now the cooled gas of 12-14 kg/cm pressure goes to 2 stage suction nd separator where further separation occurs. Then it goes to 2 stage gas compressor there compression is done and in the output we get gas of 40 2 0 kg/cm pressure but temperature has again again gone up to to 145 C because of compression so it again goes to cooler which is also known as after cooler . Now as cooling has occur so condensation will be done so again whatever amount of oil will be there will be drained out from discharge separator. 2

Then finally gas from the discharge separator at 40 kg/cm pressure is sent back to GCS.

2.4 GCP Facilities 1. Gas Compression System 

Purpose



To compress gas at high pressure



Process



It has two stage gas compression systems. First stage compressors takes gas from first suction separator and other stage takes gas from second suction separator as shown in the flow diagram.



RPM= 990



Capacity-2100m /hr

3


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

Model- 14 X 8 X 5 2 RDH-2



Make-Ingersoll sand



Type- double-acting reciprocating horizontal



Number of stages- Two

2. Raw Water Water Treatment System (R-O Plant) 

Purpose:



To remove true deposit solids from water



Process



Firstly the raw water from the storage tank flows into pipelines and come into desired location. To this raw water we add sodium hypo chloride which destroys the bacteria present in water. Then the water is treated with sodium bi sulfate to reduce the chlorine content which would have increased because of sodium hypo chloride addition. Then this treated water with sodium hexa meta phosphate so that scaling can be minimized which will occur in tubing having membranes. Then this water goes to multi grade filter where various types of gravel, sand are filtered. Then the filtered water is treated with 98% H 2SO4 so that pH of water is maintained. Then again this water goes to cartridge filter, so that if any filtration is left can be completed. Now this filtered water is pumped into tubing system having membranes with the help of high pressure pump. Then there high- quality demineralised water is produced which is then sent to storage tanks.

3. Air Compression System : 

Make- Ingersoll Rand



Model- 8 X 5 E&1-NL2



Discharge Pressure- 110 PSI



Capacity- 200 CFM(each)


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4. Cooling System :  

 

Purpose: There are two types of gas coolers inter gas coolers and after gas coolers. It’s a type of heat exchanger. Running water through it helps in cooling of gas and they are sent finally to discharge separator. Inter gas cooler takes the gas of first stage compression and gas cooler takes second stage compression. Process:

It’s a type of heat exchanger, it contains baffles and one shell and two tubes pass exchanger system. Cooled treated water enters from one side and gas enters from the other side. There occurs a counter current flow. This results in exchange of heat between two liquids and hence the fluid is cooled

5. Gas Detection and Monitoring System 

Used to detect the leakage of gas in the plant

6. Fire Fighting System  6 fire fighting pump 

4 diesel pump and 2 motor driven pump.

7. Electrical System 

Two 11 KV sub-station



8 step down transformers


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Figure:2.2-Process FlowDiagram of GCP-Santhal


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2.5 CENTRAL FARM TANK (CTF)-SANTHAL Objectives : 

Collection of oil from Palawasna, santhal, lanwa, South Kadi ,Limbodra



Treatment of crude oil



Chemical analysis



Pumping oil to desalter Nawagam plant



Pumping effluent to ETP (effluent treatment plant)

Receiving System 

Crude oil received at CTF Santhal through.



8’’ diameter line from Palawasna and Lanwa field at 1000m /day.



12’’ and 8’’ lines from Kalol field at 170m /day.



12’’ lines from south Lanwa and Palawasna field at 43m /day.

3

3

3

Collection 3  6000 m /day Functions

Crude oil is received from various GGS. The oil which is having higher water cut is sent to heater treater while oil having low water is directly dispatched to desalter. Tests Performed 

Test for specific gravityA hydrometer is an instrument used to measure the specific gravity (or relative density) of liquids; that is, the ratio of the density of the liquid to the density of water. A hydrometer is usually made of glass and consists of a cylindrical stem and a bulb weighted with mercury or lead shot to make it float upright. The liquid to be tested is poured into a tall jar, and the hydrometer is gently lowered into the liquid until it floats freely. The point at which the surface of the liquid touches the stem of the hydrometer is noted. Hydrometers usually contain a paper scale inside the stem, so that the specific gravity can be read directly. 




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

Test for water content (DEAN STARK METHOD)

This method is used for determining water-in-oil. The method involves the direct codistillation of the oil sample. As the oil is heated, any water present vaporizes. The water vapors are then condensed and collected in a graduated collection tube, such that the volume of water produced by distillation can be measured as a function of the total volume of oil used. Dispatch System 

Dispatch is done through 12’’diameter line, 51Km long pipeline to 3 desalter Nawagam through to pumps at 130 m /hr rate.



6 effluent dispatch pump each of 50 m /hr capacity.



Oil dispatch pump



(A-700) BPCL 3 in number each of 120 m /hr capacity.



(C-558)BPCL 4 in number each of 135 m /hr.

3

3

3

1. Mass Flow Meter 

Coriolis meter

2. Storage Tanks 3



10 tanks of capacity 2000 m out of which 2 are used for effluent storage and rest for storage of oil.



8 tanks of capacity 10000 m for storage of oil.

3

3. Scrapper System 

There are two scrappers receiving platforms from 12’’ pipeline for S.Kadi and 8’’ pipeline for Sanand - Jhalore field also there is one scrapper launching platforms for 12’’ pipeline desalter plant NGM.

4. Heater Treater 

In all 8 heater treater are there in this plant.



4 of which are of capacity 300m /day.



4 jumbo heater treater are also there, one of which is of capacity 3 3 800m /day and second one is of 1000m /day.

3


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

5 heater treater feed pump are available which are centrifugal and there 3 capacity is 45 m /hr.



It has three chambers namely



Heating chamber



Middle chamber



Electrical Chamber

Heating Chamber : The fire tube which extends up to this section is in submerged condition in emulsion oil. The heating of oil emulsion decreases the viscosity of oil and water and reduces the resistance of water movement. The heat further reduces the surface tension of individual droplets by which when they collide form bigger droplets. This progressive action results in separation of oil and free water. Middle Chamber : The fluids from heating enter into this chamber through fixed water .It doesn’t allow gas to pass into electrical chamber. The gas which enters heating chamber leaves from top through mist extractor. The oil in this chamber is controlled by oil level controller. Electrical Chamber : In this section constant level of water is maintained so that oil is washed and free water droplets of water are eliminated before fluid proceeds towards electrode plates (electric grid). These plates are connected with high voltage supply of 10000 to 25000 volts. When fluid passes through these electrodes the droplets polarizes and attracts each other. This attraction causes the droplets to combine; they become large enough to settle into oil and water layers by the action of gravity 5. Fire Fighting System 

3

2

4 Motor driven pump of 410 m /hr capacity work at 10kg/cm pressure.



3

2

2 diesel engine driven pump of 410 m /hr capacity work at 10 kg/cm pressure. 

Jockey pumps are 2 in number which are motor driven and there capacity 3 is 80 m /hr. 

Various potable fire extinguisher are present such as dry carbon, carbon dioxide.


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Figure:2.3-CTF (Central Tank Farm)


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Figure:2.4- Flow Diagram of GGS


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2.6 EFFLUENT TREATMENT PLANT (ETP)-II (SANTHAL) Receiving Status : Effluent from  GGS- I (Santhal), 

GGS-II (Santhal),



CTF-( Santhal) and to CTF effluent of GGS- IV also comes. 3

3

Production - 1000 m /day and 50 m /day (max.) of oil. Objectives 

The main objective of this plant is to collect effluent from various GGS and CTF and treat that water.



Finally the treated water is sent to water injection plant for final treatment. Process Description

Firstly effluent from various GGS (as mentioned above) a bove) comes into header of ETP and from those headers it goes to hold up tank .Then it goes to equalization tank where effluent is allowed to stand for some time. Thus because of this settling time water settles down and oil at the top. Then on weekly basis oil from the top is sent to sludge separating tank as the content of oil in it is very less. But water goes to receiving pump through centrifugal pump. Then from receiving sump it goes to flash mixer where alum and polyelectrolyte are added in 200 ppm and 10 ppm concentrations respectively. Alum acts as coagulant & polyelectrolyte is added to separate further. Then from there water goes to clariflocculator which has agitator inside the vessel. After agitation sludge settles down and after some time it is sent to sludge sump and then it is pumped to sludge lagoons there sludge from sludge separating tank also comes and from there it is sent for bioremediation. Now water which comes out of clariflocculator goes to clarified water tank and from there it is pumped into sand filters where the final filtration is done and then this water goes to conditioning tanks where again some settling time is given so that even if some amount of impurities is there can settle down and finally the treated water goes to storing tank and from there it is pumped into Cental Water Injection Plant (CWIP) through pipelines.


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2.7 ETP FACILITIES 1. Flash Mixer   

Alum and poly electrolyte are added Alum as coagulant Poly electrolyte for separating oil from water

2. Clariflocculator 3  Capacity-250 m  Purpose- it helps in separation of water from oil. It consists of huge 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 through V-notch provided at the sides(its periphery). Sludge settles down in a feet bottom and sludge is pumped through pump to lagoon. Whereas water is transferred to storage tank-2 (SR-2) and from there water is sent to filter for further purifications 3. Pressure Filter 

 



3

Capacity- 2.5 m Number- 2 Nos., but one filter is used at a time other is used as a standby. The filter consists of membrane made of sand and gravel (sizes ranges from 9mm- 600mm).Water is circulated here and all particles are filtered by them. Back Wash Water arrangement is also made in order to clean the filter when its cleaning is required. This is done daily as two pressure filters are available, one is used at a time and other is used as stand by.

4. Pumping System     

5 centrifugal pump 3 Capacity- 40 m /hr Head- 45 m Speed- 1450 RPM Efficiency- 48%


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Figure:2.5-ETP (Effluent Treatment Plant)


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2.8 ARTIFICIAL LIFT (MEHSANA) In many wells the natural energy associated with oil will not produce a sufficient pressure differential between the reservoir and the well bore to cause the well to flow into the production facilities at the surface .In other wells, natural energy will not drive oil to the surface in sufficient volume. The reservoirs natural energy must then be supplemented by some form of ARTIFICIAL LIFT. Types of Artificial Lift Systems There are four basic ways of producing p roducing an oil well by artificial lift. There are. (1) Gas Lift. (2) Sucker Rod Pumping. (3) Screw pump Choosing an Artificial Lift System

The choice of an artificial lift system in a given well depends upon a number of factors. Primary among them, as far as gas lift is concerned is the availability of gas. Then gas lift is usually an ideal selection of artificial lift. The Process of Gas Lift

Gas Lift is the form of artificial lift that most closely resembles the natural flow process. It can be considered an extension of the natural flow process. In a natural flow well, as the fluid travels upward towards the surface, the fluid column pressure is reduced and gas comes out of solution. The free gas being lighter then the oil it displaces, reduce the weight of the fluid column above the formation. This reduction in the fluid column weight produces the pressure differential between the well bore and the reservoir that causes the well to flow. When a well makes water and the amount of free gas in the column is reduced the same pressure differential between the well bore and reservoir can be maintained by supplementing the formation gas with injected gas. Types of Gas Lift

There are two basic types of gas lift systems used in the oil o il industry. These are: (1) Continuous flow (2) Intermittent flow


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Continuous Flow Gas Lift:

In the continuous flow gas Lift process, relatively high pressure gas is injected down hole into the fluid column. This injected gas joins the formation gas to lift the fluid to the surface by one or more of the following processes. 1. Reduction of the fluid density and the column weight so that the pressure differential between the reservoir and the well bore will be increased. 2. Expansion of the injection gas so that it pushes ahead of it which further reduces the column weight thereby increasing the differential between the reservoir and the well bore. 3. Displacement of liquid slugs by large bubbles of o f gas acting as pistons. Intermittent Flow Gas Lift: If a well has a low reservoir pressure or every low producing rater it can be produced by a form of gas lift called intermittent flow. As its name implies this system produces intermittently or irregularly and is designed to produce at the actual rate at which fluid enters the well bore from the formation. In the intermittent flow system, fluid is allowed to accumulate and build up in the tubing at the bottom of the well. Periodically, a large bubble bu bble of high pressure gas is injected into the tubing very quickly underneath the column of liquid and liquid column is pushed rapidly up the tubing to the surface. The action is similar to firing a bullet from a rifle by the expansion of gas behind the rifle slug. The frequently of gas injection in intermittent lift is determined by the amount of time required for a liquid slug to enter the tubing. The length the gas injection period will depend upon the time required push one slug of liquid to the surface. Advantages of Gas Lift

1) Initial cost of down hole equipment is usually low. 2) Gas lift installations can be designed to lift from one to many thousand of barrels. 3) The producing rate can be controlled at the surface. s urface. 4) Sand in the produced fluid does not affect gas lift equipment is most installation. 5) Gas lift is suitable for deviated well. 6) Long service lift compared to other forms of artificial lift. Departement of Chemical Engineering, MNIT Jaipur

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7) Operating costs are relatively low. 8) Gas lift is ideally suited to supplement formation gas for the purpose of artificially lifting wells where moderate amount of gas are present in the produced fluid. 9) The major items of equipment (the gas compressor) in a gas lift system are installed on the surface where it can be easily inspected, repaired and maintained. Limitations 1. Gas must be available. Natural gas is quite cheap as compared to air, exhaust gases and nitrogen. 2. Wide well spacing may limit the use of a centrally located source of high percentage. 3. Corrosive gas lift can increase the cost of gas lift operations if it is necessary to treat or dry the gas g as before use.


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Figure:2.6-Gas Lift

Sucker Rod Pumping

80-90% of all artificial lift wells are being produced on sucker rod pumping; the most common is the beam pumping system. Sucker Rod Pumping System is time tested technological marvel which has retained its typical features for over a century. When oil well ceases to flow with own pressure, this Artificial Lift system is installed for pumping out well fluid. In the well bore reciprocating pump called Subsurface pump is lowered which is operated by surface system called SRP surface unit or Pumping unit. Prototype of one such unit is in action here. General considerations:

Oil will pumping methods can be divided into two main groups:


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Rod System: Those in which the motion of the subsurface pumping equipment, originates at the surface and is transmitted to the pump by means of a rod string. Rod-less System: Those in which the pumping motion of the subsurface pump is produce by means other than sucker rods. Of these two groups, the first is represented by the beam pumping system and the second is represented by hydraulic and centrifugal pumping systems. The beam pumping system consists essentially of five parts (1) The subsurface sucker rod driven pump. (2) The sucker rod string which transmits the surface pumping motion and power to the subsurface pump. (3) The surface pumping equipment which charges relating motion of the prime motion of the prime mover into oscillating linear pumping motion. (4) The power transmission unit or speed reducer (5) The prime mover which furnishes the necessary power to the th e system.

Figure:2.7-Parts of Conventional pmping unit


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Figure:2.8-Casing or Tubing

2.9 HEATER TREATER Basic Process

There are two heater treaters connected in series.One heater treater has a 2 2 pressure of 2.7kgf/cm while other one has 1.6 kgf/cm . 1. Initial Gas Separation

Produced fluid enters the vessel above the fire-tube in the inlet degassing section. Free gas is liberated from the flow stream and is equalised across the entire degassing and heating area of the treater. The inlet degassing section is separated from the heating section by a hood typebaffle. The fluid travels downward from the degassing area and enters the heating section under the fire-tubes. Any free water associated with the crude oil is released in this area.


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2. Free Water Removal

The water level in the heating section is maintained by a float operated control which operates a water discharge valve. 3. Heating Section

The oil and entrained water flow around the fire-tube, where the desired operating temperature is obtained. The increase in temperature of the oil will release some additional gas. Temperature of oil is 80 degree Celsius in heating chamber.The heat reduces the surface tension of individual droplets by which they coalesce to form bigger droplets.Theprogressinve action results in separation of oil and free water to a grater extent and water settles down in a heating h eating chamber.The oil water interface in this section is controlled by an interface level controller which operates the control valves for draining free water.The heat released gas then joins the free gas from the inlet section and is discharged from the treater through a gas back pressure valve. The fluid level is maintained in this section by a fixed height weir. The oil and entrained water must spill over this weir to the differential oil control chamber. 4. Differential Oil Control Section

This section is located between the heating and coalescing sections of the treater. The heated fluids enter the chamber over the fixed weir baffle of the heating section. This area contains the oil level control which is activated by the rising level of the incoming fluid. The control operates the clean oil discharge valve. The fluid then travels downward to near the bottom of the differential oil control chamber where the openings to the coalescing section distributor is located. 5. Coalescing Section or electrical section Mechanism of separation

A water molecule consists of a central oxygen atom that has a partial negative character (δ -) and two (2) hydrogen atoms each having a partial positive character (δ+) .When a water droplet enters an electrical field, a dipole is created. A dipole exists when the ionic charges that that are inherent in in a droplet are separated so that the positive ions move to one end of the droplet while the negative ions move move to the other end. When these dipoles are are created the ends of droplets that are positive are attracted to the ends of droplets that are negative. This electrical attraction results in collisions between droplets.


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These collisions continue until the droplets coalesce large enough to settle into the water phase of the vessel. vess el. Process

The oil and entrained water enter the coalescing section from the differential oil control chamber through distributors. The distributor is of open bottom design and water sealed to force the oil and entrained water upward through the metered orifices; and at the same time allows any free water and solids to fall out and join with the water in this section of the treater. The water level is maintained by an interface control which operates a water discharge valve. The oil and entrained water flow upward, and are uniformly distributed to utilise the full crosssectional coalescing area. As the oil and entrained water come into contact with the electrical field in the grid area, final coalescing of the water takes place. The water falls back into the water phase and the clean oil continues to rise to the top of the vessel, where it is collected and is discharged through the clean oil outlet valve.


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Figure:2.9-Horizantal heater-treater


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3.1 INTRODUCTION Today when volatile oil prices keeps the nation’s import bill ever rising. ONGC has taken up the challenge to produce every drop of the produced oil. ONGC has employed the state of art art of EOR techniques through IN-SITU combustion in the western state of Gujarat (Mehsana). These effort have catapulted India to the select band of countries pioneering the art of heavy oil extraction that include USA, CANADA,RUSSIA,ROMANIA & VENEZUELA.

3.2 EOR-THE FUTURE OF INDIA The future scenario scenario of India will not only depend on discovery of new fields, but also an enhancement of economics recovery & improvement in recoveries rank equivalent to discoveries. The large potential potential of EOR processes in Mehsana offers enormous scope for for increasing economics oil recovery, it is anticipated that oil fields in other parts of country will in future resort to EOR. The EOR processes could substantially increases could substantially increases domestic production during the next decade.

EOR will be a thrust area and definitely play a key role in India’s march to it’s goal of attaining self-reliance.

3.3 WHAT IS EOR (ENHANCED OIL RECOVERY) The variety of methods and techniques, which permits the recovery of higher percentage of original oil in place than, would have been possible using only primary recovery method. The EOR terms replaces the old and confusing terminology of secondary and tertiary recovery.


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3.4 SELECTION OF EOR TECHNIQUES The following factors normally influence the selection of an EOR method:      

Reservoir size, geometry & homogeneity. ho mogeneity. Types of reservoir drive. Residual oil saturation after primary recovery. Viscosity and gravity of oil at reservoir condition. Reservoir pay thickness. Depth of oil reservoir.

3.5 MAJOR CONSTRAINTS TO EOR DEVELOPMENT Some of the limitations for for full scale scale development of EOR projects are given below: (a) Unproved and risky nature of certain techniques like surfactant and miscible flooding. (b) Large initial capital requirement. (c) Lack of a reliable long term price of oil to workout economics. (d) Limited available supply of certain injection material e.g. CO 2, sulphonates & polymers. (e) Long lead time is required to carry out the essential laboratory tests to design and conduct pilotless test before expanding successful pilots into field scale implementation. A complete pilot tests scheme should be prepared with: (a) Well location and completions. (b) Injection rate (year wise) from surrounding production wells. (c) Parameters to be monitored in producing wells/observation wells with value of these parameters as per scheme and on specified sp ecified time after of the pilot. (d) For economics, year wise incremental production (base value is without EOR) should be brought out. (e) The scheme should be fully engineered before being implemented.


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3.6 EOR TECHNIQUES EOR processes are subdivided into following major categories: (a) THERMAL PROCESSES: 

Steam Stimulated



Steam flooding (including hot water injection)



IN-SITU Combustion

(b) CHEMICAL PROCESSES: 

Surfactant injection



Polymer flooding



Caustic flooding

(c) MISCIBLE DISPLACEMENT PROCESSES: 

Miscible hydrocarbon displacement



CO2 injection



Inert gas injection

(d) MICROBIAL-ENHANCED MICROBIAL-ENHANCED RECOVERY

3.6.1 STEAM STIMULATION:

It is also known as cycle steam injection, steam soak or huff and puff. This is basically a stimulation stimulation process rather than than an EOR techniques. In this process steam is injected at pre-determined rate into producing well for a specified producing well for a specified period of time (normally 2-3 weeks). Following this the well is shut in for a few days (to allow sufficient heat dissipation). Thereafter the well is put on production. Heat from the injection steam increases the reservoir temperature resulting in the decreases in viscosity of oil hence an increase in mobility of oil. This result in corresponding improvement in producing rates. Other positive benefits of this processes that may contribute to production increase include.


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   

Thermal expansion of fluid Compression of solution gas Reduced residual oil saturation Well bore clean up effect

This techniques had gained wide acceptance of quick payouts.

3.6.2 STEAM FLOODING:

Steam flooding is process process similar to water flooding. A suitable suitable well pattern i.e (five spot, seven spot, etc) is chosen. Steam is injected as heat carries into a number of injection wells, while oil is produced from the production wells The primary advantages of steam flooding are:  



Steam has relatively high heat carrying capacity. Large amount of heat is transferred into formation as heat of condensation. Steam condensation volume is small.

Ideally steam forms a saturation zone around the injection well. The temperature of this zone is nearly equal to that of injection steam. As the steams moves away from the bore wells its temperature drops as it continuous to expand in response to pressure drop. At some distance from the well steam condense and from a hot water bank. In the hot water zone physical changes in the characteristics of oil o il and reservoir rock took place, thus resulting in the higher oil recovery. These changes are: 

Thermal expansion of the oil.



Reduction in the viscosity.



Reduction in residual oil saturation.



Change in relative permeability. p ermeability.


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An advantage of steam injection over other enhanced oil recovery methods is that it can be applied to wide variety of reservoirs. However the limiting factors are: 

Depth (should less than 1500 mts.)



Reservoir thickness (should be greater than 4 mts.)

The depth limitation is imposed by the critical pressure and corresponding temperature of the steam. The reservoir thickness determines d etermines the rate of the heat loss to base and cap rock. Higher grade of casing or pre stressing, use of thermal cement (API class G cement +30% to 40% silica flour) for cementation, use of vacuum insulated tubing’s and thermal packers are required for wells selected for steam injection.


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4.1 Concept: In-situ combustion is a thermal method of enanced oil recovery. The thermal methods are based on the principal of improving oil mobility by reduction of the viscosity of the oil by its heating with in the reservior. The heating of the oil, associated with the continuous injection of air and water, provides greater sweep efficiency, improved displacement efficiency by way of crude expansion, steam distillation and solvent extraction. 4.2 INTRODUCTION In-situ combustion (ISC) is basically a gas injection oil recovery process. Unlike a conventional gas injection process, in an ISC process, heat is used as an adjuvant to improve the recovery. The heat is generated within the reservoir (in-situ) by burning a portion of the oil. Hence, the name in-situ combustion. The burning is sustained by injecting air or an oxygen rich gas into the formation. Often times this process is also called a fireflood to connote the movement of a burning front within the reservoir. The oil is driven toward the producer by a vigorous gas drive (combustion gases) and water drive (water of combustion and re-condensed formation water). The original incentive for the development of the ISC process was the tremendous volume of difficult to recover viscous oil left in the reservoir after primary production. The process, however, is not restricted to heavy oil reservoir and at the present time in the U.S. more light than heavy oil is being produced using this process. In other countries, however, this process is not utilized to recover light oil. It's use is generally restricted to heavy oil reservoirs not amenable to steam.

It is the process of generation of heat inside the reservoir by burning a part of the reservoir oil. For generation of heat we apply two types of ignition process. 

One is the spontaneous ignition, where the air is simply injected in a centrally located well. This is called invert five spot patterns where the wells are drilled in a geometric fashion having an equal distance of 320 mts. Such thermal recovery is only suitable where, o the API gravity is less than 15 and viscosity is very high. As we injected air in reservoir an oxidation process starts which is by


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nature an exothermic reaction. This heating effect changes the oil flow characteristics. Its mobility and sweep efficiency is increases and it tries to move towards the production wells. 

In artificial ignition, the ignition accessories are lowered along with a burner and thermocouple wire into the sand face or the perforation face. Through wire line some pyropheric chemicals near the wall bore is lowered. As soon as fire is initiated the thermocouple detects the temperature and convey to the ignition trailer where monitoring is being done. Initially air is injected through annulus and nature gas through the tubing. A combustible mixture is generated near the sand face by charging the air/gas ratio through the ignition trailer. The pyropheric compound catches fire in presence of air inside the burner, which is the lowest part of the burner. After the trailer is disconnected air injection through compressor plant is continued to propogate thee heat away from the ignition well and close the production well. Initially the rate of injection is minimum, this rate increases at regular intervals and injection rate approaches the peak rate in about 3-4 months.

4.3 IN-SITU COMBUSTION PROCESSES Based on the direction of the combustion front propagation in relation to the air flow, the process can be classified as forward combustion and reverse combustion. In the forward process, the combustion front advances in the general direction of air flow; whereas in reverse combustion, the combustion front moves in a direction opposite to that of the air flow. Only forward combustion is currently being practices in the field. The forward combustion is further categorized into 'dry forward combustion' and 'wet forward combustion.' In the dry process, only air or oxygen enriched air is injected into the reservoir to sustain combustion. In the wet process, air and water are co-injected into the formation through the injection well. 4.3.1 DRY COMBUSTION

In this process, air (or enriched air) is first injected into an injection well, for a short time (few days) and then, the oil in the formation is ignited. Ignition is usually induced using down-hole gas burners, electric heaters or through injection of a pyrophoric agent (such as linseed oil) or a hot fluid such as the Departement of Chemical Engineering, MNIT Jaipur

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steam. In some cases, auto ignition of the in-situ crude occurs. For auto ignition to occur, the reservoir temperature must be greater than 180°F and the oil sufficiently reactive. Once ignited, the combustion front is sustained by a continuous flow of air. The combustion or fire front can be thought though t of as a smoldering glow passing through the reservoir rather than a raging underground fire. As the burning front moves away from the injection well, several well characterized zones are developed in the reservoir between the injector and producer. These zones are the result of heat and mass transport and the chemical reactions that occur in a forward insitu combustion process. The locations of the various zones in relation to each other and the injector are shown in Figure 3.1. The upper portion of this figure shows the temperature distribution and the fluid saturation from injection well to producer. The locations of the various zones are depicted in the lower portion of the figure.

FIGURE 4.1- In-Situ Combustion Schematic Temperature Profile.

Figure 3.1 is an idealized representation of a forward combustion process and developed based on liner combustion tube experiments. In the field there are transitions between all the zones. The concept depicted in Figure 3.1 is easier to visualize and provide much insight on combustion process. Starting from the injection well, the zones represented in Figure 3.1 3 .1 are: Departement of Chemical Engineering, MNIT Jaipur

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1. The burned zone. 2. The combustion zone 3. The cracking and vaporization zone. 4. The condensation (steam plateau) zone. 5. The water bank 6. The oil zone. 7. The native zone. These zones move in the direction of air flow and are characterized as follows: The zone adjacent to the injection well is the burned zone. As the name suggests, it is the area where the combustion had already taken place. Unl ess the combustion is complete, which is usually not the case in the field, the burned zone may contain some residual unburned organic solid, generally referred to as coke. Analysis of cores taken from the burned portion in the field indicate as much as 2% coke and saturated with air. The color of the burned zone is typically off-white with streaks of grays, browns and reds. Since this zone is subjected to the highest temperature for a prolonged period, they usually exhibit mineral alteration. Because of the continuous influx of ambient air, the temperature in the burned zone increases from formation temperature near the injector to near combustion temperature in the vicinity of combustion zone.

FIGURE 4.2 - Schematic of Temperature Profile for Dry Combustion (After Moore et al., 1996)


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Immediately ahead of the burned zone is the combustion zone. The combustion zone is where reaction between oxygen and fuel takes place generating heat. The combustion zone is a very narrow region (usually no more than a few inches thick) (see Figure 3.2) where high temperature oxidation (burning) takes place to produce primarily water and combustion gases (carbon dioxide CO2, and carbon monoxide CO). The fuel is predominantly coke, which is formed in the thermal cracking zone just ahead of the combustion zone. 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. The temperature reached in this zone depends essentially on the nature n ature and quantity of fuel consumed per unit volume of the rock. Just downstream of the combustion zone lies the cracking/vaporization zone. In this zone the high temperature generated by the combustion process causes the lighter components of the crude to vaporize and the heavier components to pyrolyze (thermal cracking). The vaporized light ends are transported downstream by combustion gases and are condensed and mixed with native crude. The pyrolysis of the heavier end results in the production of Co2, hydrocarbon and organic gases and solid organic residues. This residue, nominally defined as coke, is deposited on the rock and is the main fuel source for the combustion process. Adjacent to the cracking zone is the condensation zone. Since the pressure gradient within this zone is usually low, the temperature within the zone is essentially flat (30&550°F) and depends upon the partial pressure of the water in the vapor phase. Hence, the condensation zone is often referred to as the steam plateau. Some of the hydrocarbon vapor entering this zone condenses and dissolves in the crude. Depending on the temperature, the oil may also undergo 'vis-breaking' in this zone, thus reducing its viscosity. Vis-breaking is a mild form of thermal cracking. This region contains steam, oil, water, and flue gases, as these fluids move toward the producing well. Field tests indicate that the steam plateau extends from 10-30 ft. ahead of the burning front. At the leading edge of the steam plateau where the temperature is lower than the condensation temperature of steam, a hot water bank is formed. This bank is characterized by a water saturation higher than original saturation. An oil bank proceeds the water bank. This zone contains all the oil that has been displaced from upstream zones. Beyond the oil bank lies the undisturbed zone which is yet to be affected by the combustion process, except for a possible increase in gas saturation due to flow of combustion c ombustion gases (CO,, CO, and N2). The overall fluid transport mechanism in a combustion process is a highly complex sequence of gas drive (combustion gases), water drive (re-condensed formation water and water of combustion), steam drive, miscible gas and solvent drive. Although the bank concept approach described above provides Departement of Chemical Engineering, MNIT Jaipur

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much insight on the combustion process, it is not a true representation of the field behavior. In the field, various zones are not readily identified and there are considerable overlaps between zones. Further, the relative locations of the various zones and the sequence in which they occur may also be different from that described previously. This difference arises mainly because of the heterogeneous nature of the reservoir. Reservoir heterogeneity causes the fluid and heat fluxes to be different at various points of the combustion region. The fluid distribution within each of these zone is influenced by the temperature profile as well as the relative permeability characterization of the formation. The chemical properties of the oil that is left behind by the steam bank

determine the amount of coke that will be laid down, which in turn determines the amount of air that must be injected to consume this coke. 4.3.2 Wet Combustion In the dry forward combustion process, much of the heat generated during burning is stored in the burned sand behind the burning front and is not used for oil displacement. The heat capacity of dry air is low and, consequently, the injected air cannot transfer heat from the sand matrix as fast as it is generated. Water, on the other hand, can absorb and transport heat many times more efficiently than can air. If water is injected together with air, much of heat stored in the burned sand can be recovered and transported forward. Injection of water simultaneously or intermittently with air is commonly known as wet, partially quenched combustion. The ratio of the injected water rate to the air rate influences the rate of burning front advance and the oil displacement behavior. The injected water absorbs heat from the burned zone, vaporizes into steam, passes through the combustion front, and releases the heat as it condenses in the cooler sections of the reservoir. Thus, the growth of the steam and water banks ahead of the burning front are accelerated, a ccelerated, resulting in faster heat movement and oil displacement. The size of these banks and the rate of oil recovery are dependent upon the amount of water injected.

4.3.3 Reverse Combustion In heavy oil, reservoir forward combustion is often plagued with injectivity problems because the oil has to flow from the heated, stimulated region to cooler portions of the reservoir. Viscous oil becomes less mobile and tends to create barriers to flow. This phenomena is especially prevalent in very viscous oils and tar sands. A process called reverse combustion has been proposed and Departement of Chemical Engineering, MNIT Jaipur

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found technically feasible in laboratory tests. The combustion zone is initiated in the production well and moves toward the injector; counter current to fluid flow. The injected air has to travel through the reservoir to contact the combustion zone. The basic concept in reverse combustion is that the major portion of the heat remains between the production well and the oil when it is mobilized. Therefore, once the oil begins to move, very little cooling occurs to immobilize the oil. The operating principles of reverse combustion are not as well understood as those for the forward mode. Although the combustion process is essentially the same, its movement is not controlled by the rate of fuel burn-off but by the flow of heat. As explained in the section on dry in-situ combustion, the three things required for burning are oxygen, fuel, and elevated temperature. During reverse burning, oxygen is present from the injection well to the combustion zone. The fuel is present throughout the formation. The factor which determines where the burning occurs is the high temperature which occurs at the producing well during ignition. As the heat generated during the burning elevates the reservoir temperature in the direction of the injector, the fire moves in that direction. The combustion front cannot move toward the producer as long as all the oxygen is being consumed at the fire front. Thus, the combustion process is seeking the oxygen sources but can move only as fast as the heat can generate the elevated temperatures. The portion of the oil burned by forward and reverse combustion is different. Forward combustion burns only the coke like residue, whereas the fuel burned in reverse combustion is more of an intermediate molecular weight hydrocarbon. This is because all of the mobile oil has to move through the combustion zone. Therefore, reverse combustion consumes a greater percent of the oil in place than forward combustion. However, the movement of oil through the high temperature zone results in considerably more cracking of the oil, improving its gravity. The upgrading process of reverse combustion is very desirable for tar-like hydrocarbon deposits. Although reverse combustion has been demonstrated in the laboratory, it has not proven itself in the field (Trantham and Marx, 1966). The primary cause of failure has been the tendency of spontaneous ignition near the injection well. However, projects in the tar sands are being considered which attempt to use reverse combustion along fractures to preheat the formation, As the bum zone nears the injection well, the air rate is increased, and a normal forward fireflood is commenced.


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5.1 INTRODUCTION Unlike steam injection process, where the oil composition and rock mineralogy has minimal impact on oil recovery, these parameters play a major role on the outcome of an in-situ combustion (ISC) process. This is because, the ISC depends for its existence on the occurrence of chemical reactions between the crude oil and the injected air within the reservoir. The extant and nature of these chemical reactions as well as the heating effects they induce depends on the features of the oil-matrix system. The reservoir rock minerals and the clay contents of the reservoir are known to influence the fuel formation reactions and their subsequent combustion. Hence a qualitative and quantitative understanding of in-situ combustion chemical reactions and their influence on the process is critical to the design of the process and interpretation of the field performance. 5.2 Chemical Reactions Associated with In-Situ Combustion 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). (a) The LTO reactions are heterogeneous (gas, liquid) and generally results in production of partially oxygenated compounds and little or no carbon oxides. (b) ) 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). (c) 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.


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5.2.1 Low Temperature Oxidation During in-situ combustion the hydrocarbons initially present in the oil undergo two types of reaction with the oxygen (injected air) depending upon the prevailing temperature. Those reactions which occur at temperatures below 400°F are defined as the low temperature oxidation (LTO) and the other being the high temperature oxidation (HTO). Unlike the HTO, which produces CO,, CO, and water (H,O) as its primary reaction products, LTO yields water and partially oxygenated hydrocarbons such as carboxylic acids, aldehydes, ketones, alcohols, and hydroperoxides (Burger et al., 1972). Thus LTO can be thought of as oxygen addition reactions. LTO occurs o ccurs even at low reservoir temperature and is caused by the dissolution of oxygen in the crude oil. The degree of dissolution depends upon the diffusion rate of oxygen molecules in the crude (Burger et al., 1972) at reservoir temperature. Light oils are more susceptible to LTO than heavy oils. Low air fluxes in the oxidation zone resulting from reservoir heterogeneities and oxygen channeling promote LTO reactions. Poor combustion characteristics of the crude also tend to promote LTO due to low oxygen consumption. In heavy oil reservoirs, LTO tends to be more pronounced when oxygen, rather than air, is injected into the reservoir. To rectify this situation some investigators recommend adding steam to the oxidizing gas stream (Scarborough and Cady, 1982). The rationale behind this suggestion is that the addition of steam to the oxidizing gas stream will lower the oxygen partial pressure at the burning front and modify the kinetic reaction that creates the heat needed to promote and sustain combustion. "LTO are generally believed to occur at temperatures of less than 600°F, but this temperature range is very oil dependent. It is very difficult to assign a temperature range to LTO region because the carbon oxide reactions (C-C bond cleavage) are begin to occur at temperatures between 270°F and 320°F. LTO reactions are evidenced by a rapid increase in the oxygen uptake rate as well as the generation of carbon oxides, but their characteristics feature is that there is a decline in the oxygen reaction rate at temperatures in the range of 45&54OoF. This gives rise to the negative the negative temperature temperature gradient gradient region, (Figure 4.1) which is a temperature interval over which the oxygen uptake rate decreases as the temperature increases."


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FIGURE 5.1 - Schematic of Dry Combustion Temperature Profile Showing the General Effect of Temperature on Oxygen Uptake Rate for Heavy Oils and the Negative Temperature Gradient Region (After Mehta and Moore)

5.2.2 The Pyrolysis Reactions As the reservoir temperature raises, the oil undergo a chemical change called pyrolysis. Pyrolysis reactions (intermediate temperature oxidation reactions (ITO)) are often referred to as the fuel deposition reactions in the ISC literatures, because these reactions are responsible for the deposition of "coke" (a heavy carbon rich low volatility hydrocarbon fraction) for subsequent combustion. Oil pyrolysis reactions are mainly homogeneous (gas-gas) and endothermic, (heat absorbing) and involve three kinds of reactions: dehydrogenation, cracking and condensation. In the dehydrogenation reactions the hydrogen atoms are stripped from the hydrocarbon molecules, while leaving the carbon atoms untouched. In the cracking reactions, the carbon - carbon bond of the heavier hydrocarbon molecules are broken, resulting in the formation of lower carbon number (smaller) hydrocarbon molecules. In the case of condensation reactions, the number of carbon atoms in the molecules increases leading to the formation of heavier carbon rich hydrocarbons. The oil type and the chemical structure of its constituent hydrocarbons determine the rate and extent of the different pyrolysis reactions.


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The paraffins (straight chain hydrocarbons) do not undergo condensation reactions. At 7001250°F they undergo dehydrogenation and/or thermal cracking reactions depending upon the length of the hydrocarbon chain. In general short chain hydrocarbons (methane through butane) undergo dehydrogenation and the larger molecules undergo cracking. Cracking reactions are usually initiated by the cleavage of the carbon-carbon bond, followed by the hydrogen abstraction (dehydrogenation) reaction. The dehydrogenation molecules than recombine to form heavier molecules, eventually leading to the formation of "coke". Thus the larger straight chain molecules after prolonged heating or when subjected to sufficiently high temperature often produce "coke" and considerable amounts of volatile hydrocarbon fractions. The aromatic compounds (benzene and other ring compounds) undergo condensation reaction rather than degradation reactions (cracking) at 1200-3000°F. In the condensation reaction the weak C-H bonds of the ringed molecules are broken and replaced by a more stable C-C bonds and leads to the formation of a less hydrogenated polyaromatic molecule. When subjected to further heating these condensation products losses more of the hydrogen and recombines to form heavier carbon rich polymolecules, eventually leading to the formation of large graphite like macromolecules. Laboratory pyrolysis studies on heavy (14-16OAPI) California crudes (AbuKharnsin et al., 1988) indicate that the pyrolysis of crude oil in porous media goes through three overlapping stages: distillation, visbreaking, and coking. During distillation, the oil loses most of its light gravity and part of its medium gravity fractions. At higher temperatures (40&540°F), mild cracking of the oil (visbreaking) occurs in which the hydrocarbon lose small side groups and hydrogen atoms to form less branched compounds, that are more stable and less viscous. At still higher temperatures, (above 550°F) the oil remaining in the porous medium cracks into a volatile fraction and a non volatile carbon rich hydrogen poor residue often referred to as "coke". Coke is defined as the toluene insoluble fraction of an oil and generally contains 80-90% carbon and 3-9% hydrogen. Both vis-breaking and cracking reactions produce hydrogen gas and some light hydrocarbons in the gas phase. It is further observed that distillation of crude oil at low temperatures plays an important role in shaping the nature and extent of the cracking and coke formation reactions. High operating pressures generally lead to the formation of more fuel that is leaner in hydrogen. h ydrogen.

Researchers have for over 20 years studied various aspects of insitu combustion and they describe the bitumen pyrolysis reaction as: Departement of Chemical Engineering, MNIT Jaipur

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Bitumen -Maltenes Maltenes - Asphaltenes Asphaltenes -. Coke Asphaltenes + Gas Maltenes are crude oil fractions which are pentane and toluene soluble and may be further separated into saturates, aromatics, and resins using liquid chromatography. The asphaltenes are toluene soluble but pentane insoluble fraction of the bitumen. Coke is defined as the fraction insoluble in toluene. Thermal cracking of asphaltene to coke has a long induction period (initiation time). This induction period decreases as the cracking temperature increases. 5.2.3 High Temperature Oxidation The reaction between the oxygen in the injected air and the coke at temperatures above 650°F are often referred to as the high temperature oxidation (HTO) or combustion reactions in the ISC literatures. Carbon dioxide (CO,), carbon monoxide (CO), and water (H,O) are the principle products of these reactions. HTO are heterogeneous (gas-solid and gas-liquid) reactions and are characterized by consumption of all of the oxygen in the gas phase. The stoichiometry of the HTO reaction (chemical equation) is given by:

……………………(4.1) where n = atomic ratio of hydrogen to carbon m = molor (mole percent) ratio of produced CO, to CO m = zero in the case of complete combustion to C02 and H20 The heat generated from these reactions provides the thermal energy to sustain and propagate the combustion front. Studies indicate though, HTO is predominantly a heterogeneous flow reaction and the burning process involve a number of transport phenomena. Combustion (oxidation) is a surface controlled reaction and can be broken into the following steps (Scarborough and Cady, 1982): 1. Diffusion of oxygen from the bulk gas stream to the fuel surface. 2. Absorption of the oxygen at the surface. 3. Chemical reaction with the fuel. 4. Desorption of the combustion products. 5. Diffusion of the products away from the surface and into bulk gas stream.


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If any of these steps is inherently slower than the remaining steps, the overall combustion process will be controlled by that step, In general chemical reactions (step 3) proceed at a much faster rate than the diffusional processes, Therefore, the overall combustion rate likely to be diffusion controlled.

5.3 Reaction Kinetics Reaction kinetics can be defined as the study of the rate and extent of chemical transformation of reactants to product. Though, simplistic this definition is accurate for this study. The study of reaction kinetics for the in-situ combustion process is undertaken for the following reasons: 1. To characterize the reactivity of the oil. 2. To determine the conditions required to achieve ignition and or to determine if self ignition will take place in the reservoir upon air injection. 3. To gain insight into the nature of fuel formed and its impact on combustion. 4. To establish parameter values for the kinetic (reaction rate) models used in the numerical simulation of ISC processes. Combustion of crude oil in porous media is not a simple reaction but follows several consecutive and competing reactions occurring through different temperature ranges (Fassihi et al., 1984). Since crude oils are made up of hundreds of compounds, an explicitly correct kinetic representation of crude oil oxidation reaction would require an inordinately large number of kinetic expression. However, this is not feasible because these compounds undergo reactions that cannot easily be described. This complexity is linked to chemical structure of the individual hydrocarbon. Many of them contain several coexisting C-H bonds which can react successively or simultaneously and often produce intramolecular reactions. Detailed models for hydrocarbon oxidation reactions are available only for the simplest hydrocarbon molecules and are made up of several reaction steps (equations). Detailed hydrocarbon oxidation model even if exist, cannot currently be included in multidimensional in-situ combustion simulators, because the computer size, speed, and cost requirements of such a treatment would be too great. Detailed oxidation models have been developed and validated for only the simplest fuel molecule and are not available for most practical fuels. However, very simple models that approximate the oxidation reaction kinetics study of crude oils in porous media have appeared in literature. The simplest overall reaction representing the oxidation of a typical hydrocarbon fuel is


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...................... .................................( ...........(4.2) 4.2) where the stoichiometry coefficients (ni) are determined by the choice of fuel. This global reaction is a convenient way of approximating the effects of many elementary reactions which actually occur in the reservoir during the combustion process. Its rate must therefore represent an appropriate average of all the individual reaction rates involved. Most researchers describe the ISC oxidation reaction rates in terms of a simple reaction rate model that assume functional dependency on carbon (fuel) concentration, and oxygen partial pressure. This widely accepted model is given by:

………………………………….(4.3) where R, = combustion rate of crude oil, C, = instantaneous concentration of fuel, k = rate constant, Po, = partial pressure of oxygen, a = order of reaction with respect to oxygen partial pressure, b = order of reaction with respect to fuel concentration. High temperature carbon and crude oil oxidation studies by Bousaid (Bousaid and Ramey, 1968) and others (Dabbous and Fulton, 1974) indicates first order reaction dependency on fuel concentration and 0.5-1.0 order dependency with respect to oxygen partial pressure; i.e., 'a' = 1 .O 1 .O and 'b' = 0.5 to 1.0. The reaction rate constant 'k' in Equation (4.3) is often a function of temperature and expressed by

………………………………………(4.4)

where A = pre-exponential factor E = activation energy R = universal gas constant = 1.987 cal mole-' K-I o T = absolute temperature in K


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5.4 Factors Affecting Oxidation Reactions Two of the most important factors in the in-situ combustion process are fuel formation and combustion. The physical and chemical processes that govern the ability of a crude to deposit fuel and its subsequent combustion (oxidation) strongly influences the economics of a combustion project. Too little fuel deposition may prevent the formation of a sustained, stable combustion front. Likewise, too large a fuel deposition will result in uneconomically high oxidizing gas requirement. The rate of propagation of the combustion front and the air requirement depend on the extent of the exothermic oxidation reactions, which are controlled by the kinetics of these processes. A substantial investigative effort has been made over the years in the laboratory to study the many factors that affect the crude oil oxidation reactions in the reservoir. These investigations indicate that the nature and composition of the reservoir rock and the characteristics of the oil influence the thermo-oxidative characteristics of the reservoir crudes. The clay and metallic content of the rock, as well its surface area has a profound influence on fuel deposition rate and its oxidation. Metals and metallic additives also known to affect the nature and the amount of fuel formed. Metals are used as catalysts in the petroleum refining and chemical process industries to accelerate the hydrocarbon oxidation and cracking reactions. In studies undertaken to investigate the effect of metal contamination on hydrocarbon cracking reactions, it was found that various metals promote coke formation and the catalytic effect of these metals was found to be ordered as follows: Cu < V < Cr = Zn < Ni, with nickel about four to five times as active ac tive as vanadium (De 10s Rios, 1988). Studies on the effect of reservoir minerals on in-situ combustion indicate metals promote low temperature oxidation and increase fuel deposition (Burger and Sahuquet, 1972; Fassihi, 1981; Drici and Vossoughi, 1985). These researchers also noted that the catalytic activity of a metal is highly dependent on the specific composition of the crude. The benefits of metallic additives in promoting and sustaining combustion in a light oil reservoir is documented by Racz (1985). The ability to initiate and propagate the combustion front in this Hungarian reservoir was attributed to the catalytic properties of the metallic additive which increased fuel concentration.


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Gajendra Singh(ONGC Training Report)

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