mehsana field report

Industrial Tranning Report-2011

Departement of Chemical Engineering, MNIT Jaipur

CHAPTER-1

INTRODUCTION TO THE MEHSANA FIELD

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, ONGC has growth today into a full-

fledged integrated upstream petroleum company with in-house service

capabilities and infrastructure in the entire range of oil and gas 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.

Mehsana project was started as an independent project on 7th 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 COMBUSTION “AN ENHANCED OIL

RECOVERYPROCESS” for this heavy oil field was successfully implemented



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 15-01-

1999.The major oil field under the MEHSANA 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 31-01-

2002)

SERIAL NO. MAJOR OIL FIELDS IN

MEHSANA

TPD

1 North kadi 1705

2 Shobhasan 1129

3 Santhal 1128

4 Santhal(EOR) 575

5 Jotana 493

6 Balol 597

7 Lanwa 121

8 Bechraji 336

9 Nandasan 249

10 Linch 261

11 Other 203

12 TOTAL PRODUCTION 6127

TABLE-1.1 Production Of Oil In Mehsana



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

Project

Name

Operator Date

initiat

-ed

Combusti

on type

Oil

gravity,o

API

No of

injecto

-rs

No. of

produc-

ers

1 Balol ONGC 1990 Wet 15.6 1 4

2 Lanwa ONGC 1992 Wet 13.5 1 4

3 Balol ONGC 1996 Dry 15.6 - -

4 Santhal ONGC 1996 Dry 17 - -

5 Bechraii ONGC 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:



(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 15.12 MMT of the affected

sand.

(c) Reservoir temperature is about 70oC and has an oil saturated ranging

from 75-90oC.

(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

specific gravity of 0.96 (API-16) and pour point 9oC.

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



Chapter No.-2

Santhal GCS (Gas Collection Station) 2.1 INTRODUCTION

Receiving Status:

Total Wells Connected-30

Total Working Wells- 16

Receiving pressure-4kg/cm2

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

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 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



particulates and/or gases from industrial exhaust streams. Traditionally, the

term “scrubber” has referred to 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 of 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. 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

Functions at 4kg/cm2

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 storage tanks of 45m3 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.



Gas Analysis

Table:2.1- GasAnalysis

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



Figure:2.1-GCS ( Gas Collection Station)

2.3 GAS COMPRESSION PLANT (GCP)-SANTHAL

Total Capacity : 5 lacks m3/day

Total Compresors : 10

6 in old plant and 4 in new plant

Capacity (old) =3 lacks m3 /day

Capacity (new) = 2 lacks m3 /day

Reverse-Osmosis Plant (R-O): two



Discharge Pressure : 40 kg/cm 2

Process Description :

In this plant, gas from GCS (gas collecting system) at 4kg/cm2 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

negligible but if it’s there it gets separated. Now the gas goes to 1st stage

suction separator, there further separation is done. Till now the pressure is

4kg/cm2, now this gas goes for first stage compression goes into compressor.

After compression the gas we get is of 12-14 kg/cm2 and because of

compression temperature rises to 1250 C so to low down the temperature to

40-450C, compressed gas is sent to inter gas cooler.

Now the cooled gas of 12-14 kg/cm2 pressure goes to 2nd stage suction

separator where further separation occurs. Then it goes to 2nd stage gas

compressor there compression is done and in the output we get gas of 40

kg/cm2 pressure but temperature has again gone up to 1450C 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.

Then finally gas from the discharge separator at 40 kg/cm2 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-2100m3/hr



Model- 14 X 8 X 5 2 RDH-2

Make-Ingersoll sand

Type- double-acting reciprocating horizontal

Number of stages- Two

2. Raw 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% H2SO4 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)



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



Figure:2.2-Process FlowDiagram of GCP-Santhal



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 1000m3/day.

12’’ and 8’’ lines from Kalol field at 170m3/day.

12’’ lines from south Lanwa and Palawasna field at 43m3/day.

Collection 6000 m3/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 gravity-

A 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.



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

desalter Nawagam through to pumps at 130 m3/hr rate.

6 effluent dispatch pump each of 50 m3/hr capacity.

Oil dispatch pump

(A-700) BPCL 3 in number each of 120 m3/hr capacity.

(C-558)BPCL 4 in number each of 135 m3/hr.

1. Mass Flow Meter

Coriolis meter

2. Storage Tanks

10 tanks of capacity 2000 m3 out of which 2 are used for effluent storage

and rest for storage of oil.

8 tanks of capacity 10000 m3 for storage of oil.

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 300m3/day.

4 jumbo heater treater are also there, one of which is of capacity

800m3/day and second one is of 1000m3/day.



5 heater treater feed pump are available which are centrifugal and there

capacity is 45 m3/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

4 Motor driven pump of 410 m3/hr capacity work at 10kg/cm2 pressure.

2 diesel engine driven pump of 410 m3/hr capacity work at 10 kg/cm2

pressure.

Jockey pumps are 2 in number which are motor driven and there capacity

is 80 m3/hr.

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

dioxide.



Figure:2.3-CTF (Central Tank Farm)



Figure:2.4- Flow Diagram of GGS



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.

Production - 1000 m3/day and 50 m3/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) 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.



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

Capacity-250 m3

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

Capacity- 2.5 m3

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

Capacity- 40 m3/hr

Head- 45 m

Speed- 1450 RPM

Efficiency- 48%



Figure:2.5-ETP (Effluent Treatment Plant)



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 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 industry. These

are:

(1) Continuous flow

(2) Intermittent flow



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 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 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.

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.



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 before use.



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:



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 system.

Figure:2.7-Parts of Conventional pmping unit



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

pressure of 2.7kgf/cm2 while other one has 1.6 kgf/cm2.

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.



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 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 are inherent in a droplet

are separated so that the positive ions move to one end of the droplet while

the negative ions move to the other end. When these dipoles 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.



These collisions continue until the droplets coalesce large enough to settle

into the water phase of the vessel.

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.



Figure:2.9-Horizantal heater-treater



CHAPTER-3

ENHANCED OIL RECOVERY (EOR)

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 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 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 of EOR processes in Mehsana offers enormous scope 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.



3.4 SELECTION OF EOR TECHNIQUES

The following factors normally influence the selection of an EOR method:

Reservoir size, geometry & homogeneity.

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 full 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. CO2, 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 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.



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 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 process rather 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.



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 similar to water flooding. A 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 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.



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 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.



CHAPTER-4

IN-SITU COMBUSTION PROCESS

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,

the API gravity is less than 15o and viscosity is very high. As we

injected air in reservoir an oxidation process starts which is by



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



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 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 in-

situ 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 are:



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. Unless 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)



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 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 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



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, 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



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.



CHAPTER-5 KINETICS AND COMBUSTION TUBE STUDIES

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.



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 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 temperature gradient region, (Figure 4.1) which

is a temperature interval over which the oxygen uptake rate decreases as the

temperature increases."



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.



The paraffins (straight chain hydrocarbons) do not undergo condensation

reactions. At 700-

1250°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 (Abu-

Kharnsin 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.

Researchers have for over 20 years studied various aspects of insitu combustion

and they describe the bitumen pyrolysis reaction as:



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.



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



.................................(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 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

T = absolute temperature in oK



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 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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