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RA and DMP for Development of Vashishta and S-1 fields, Expansion of Odalarevu onshore processing terminal and Installation of dual 14” sub-sea pipeline, East Godavari District, Andhra Pradesh

Asian Consulting Engineers Pvt. Ltd. 1

RISK ASSESSMENT AND DISASTER MANAGEMENT PLAN

1. INTRODUCTION

ONGC is currently involved with the exploration in several deep sea fields off the East Coast of India in water depths ranging from 250 meters and up to 3000 meters. ONGC plans to initiate development activity on an integrated basis to produce gas within the shortest feasible time from two recently discovered gas fields - Vashishta and S-1respectively, in the Krishna–Godavari (KG) Offshore Basin. The project location is shown in Figure 1.

The drilling activities offshore are envisaged to complete within six to seven months. Considering that both the fields (Vashishta and S-1) are put on production simultaneously, an average daily gas rate of 5.75 MMSCMD is envisaged for a period of six years. The cumulative gas production at the end of nine years is expected to be close to 15.775 BCM. These two fields are under Eastern Offshore Asset, which is headquartered at Kakinada.

The gas from Vashishta and S-1 fields shall be transported through dual 14‖ subsea pipelines to the new onshore terminal at Odalarevu. The new onshore processing terminal at Odalarevu will be located adjacent to the existing onshore processing terminals.

The existing onshore processing terminal at Odalarevu receives hydrocarbons from GS-15 field and the processing facilities under construction will receive & process hydrocarbons from G-1 as well as GS-15 fields located in the KG Basin.

ONGC presently operates its marine logistic support to its offshore operations in KG Basin from Kakinada Deep Water Port located at Kakinada and air logistics support from Visakhapatnam. Kakinada is located at about 75 km to east of Rajahmundry, which is the nearest airport, and is well connected by rail and road. Visakhapatnam also has port facility and is located about 160 km to the North–East of Kakinada and well connected by road, rail &air to all major cities like Hyderabad, New Delhi, Mumbai, Kolkata, Chennai, Bangalore etc.

This chapter includes the studies of risk assessment, disaster management plan and emergency response plan in following sections.



Figure 1: Project Location

2. PROJECT DETAILS

2.1 Onshore Terminal at Odalarevu

Onshore terminal at Odalarevu for processing of well fluids from Vashishta & S1 fields will be set-up adjacent to the existing terminal. Onshore terminal is designed to fulfill following objectives:

Supply of Dehydrated gas at 60 barG, Transfer of plant generated HC condensate (if any) to existing facilities, Produced water disposal (to existing disposal line) after treatment, Generation and supply of utilities as needed, Integration with existing compressors in order to utilize spare capacity available and

design of gas dehydration & metering conditioned total gas, Throughput from existing as well as new terminal.

The major facilities envisaged at onshore terminal are as given below: High-pressure Pig Receiver & Launcher Multipipe Slug Catcher Gas System (which includes Gas Compression, Gas Dehydration, DPD and Metering) MEG regeneration, Refrigeration system and Produced Water handling facilities



Utility Systems such as Cooling Water, Fuel Gas, Plant and Instrument Air System, Circulating hot oil system, Diesel engine and Gas turbine generator

Flare & Closed Drain System Open Drain System (Oily water sewer, Storm water sewer and Contaminated rain water

sewer) Chemical Injection System Fire Water system

a) Salient features of the processing scheme

Well fluid is received at onshore facility via two 14‖ pipelines. As indicated by flow assurance study, during initial period - from year 1 to 4, production fluid arrival pressure will be 24 barg and later from year 5 onwards, the production fluid arrival pressure will be 9 barg. Temperature of production fluid will vary from 15~30 °C. Production fluid received at onshore terminal is sent to slug catcher for first stage of separation. Multi pipe slug catcher is considered for achieving bulk separation of gas and liquid. Slug catcher will separate well fluid in to following three streams:

Hydrocarbon (HC) gas, Hydrocarbon (HC) condensate, and Rich MEG (Mono-Ethylene Glycol) aqueous phase.

HC gas separated at slug catcher is routed to Inlet Scrubber through pressure control valve. Two pressure control valves acting in split range is provided to control compressor suction pressure at around 7.0 barg in any of the operating case. Tapping for alternate fuel gas during start-up is provided from slug catcher gas outlet header. Gas engine driven reciprocating compressors are used for compressing the gas from 7.0 barg to 67.5 barg. Integration of new compressors with existing process gas compressors (MC-01A/B/C/D/E) is required (as part of this project) in order to utilize spare capacity available in existing machines. At the upstream of gas compressor suction header, a part of the gas stream is withdrawn on flow control and sent to existing facility for compression through existing compressors for spare capacity utilization.

HC Dew Point Control and Sales Gas Metering: Sales gas hydrocarbon dew point is achieved by cooling it to below zero degree centigrade temperature. This cooling of dry gas is achieved in two stages

At Gas- Gas Exchanger and At Gas Chiller

Hydrocarbon gas from the low temperature separator overhead is reheated in Gas-Gas Exchanger to get gas temperature around 40 °C. Finally, conditioned hydrocarbon gas from Gas-Gas exchanger is sent to the Gas metering skid for custody measurement. After metering, gas is sent to Onshore Terminal battery limit as sales gas at around 60barg and 25~45 °C. For monitoring of HC dew point and water dew point of sales gas, analyzer is provided upstream of Gas Metering Skid.

Gas Compression system at new onshore terminal shall be designed for 4.5 MMSCMD. New gas compressors will be gas engine driven reciprocating compressors running in parallel to the existing reciprocating compressors.

The following fuel/chemicals required will be stored at the terminal for various applications:



S. No.

Chemical Storage Tank Data

Remarks Dimensions (Dia. X Ht.- in m)

Operating Capacity (m3)

1 Fresh Glycol 3.5 X 4.5 25 2 MEG 6.6 X 9 230 Not in the MSIHC 3 Methanol 4.3 X 6 50 Coming under MSIHC 4 Corrosion Inhibitor --- --- In drums 5 Scale Inhibitor --- --- In drums 6 Diesel 3 X 3 10 Petroleum rules

Only one chemical i.e. Methanol is coming in the hazardous category as per ―manufacture, Storage and Import of Hazardous Chemical‖ Rules 1989 (MSIHC).

S. No

Material

S. No & Threshold Quantity (TQ in Kg) as

per MSIHC Rules Chemicals Hazards Potential

Remarks Schedul

e-1, Part-II

Schedule-2, Part-I

Schedule-3, Part-I

Hazards Toxic

1. Glycol --- --- --- Not in the MSIHC List

2. MEG --- --- --- Not in the MSIHC List

3.

Methanol

CAS No:67-56-1

UN No:1230

A colourless fairly volatile liquid with a faintly sweet pungent odour like that of ethyl alcohol.

No: 377 --- ---

Highly Flammable; Behavior in Fire: Containers may explode. Health Hazards: Exposure to excessive vapor causes eye irritation, head- ache, fatigue and drowsiness. High concentrations can produce central nervous system depression and optic nerve damage. 50,000 ppm will probably cause death in 1 to 2 hrs. Can be absorbed through skin. Swallowing may cause death

ERPG-1: 200 ppm ERPG-2: 1000 ppm ERPG-3: 5000 ppm IDLH: 6000 ppm

Proper care shall be taken during handling and storage of this chemical. Personnel authorized to handle the chemical shall have proper PPEs at all times.



S. No Material

S. No & Threshold Quantity (TQ in Kg) as

per MSIHC Rules Chemicals Hazards Potential

Remarks Schedul

e-1, Part-II

Schedule-2, Part-I

Schedule-3, Part-I

Hazards Toxic

or eye damage.

2.2 Vashishta and S-1 Fields

ONGC proposes to produce Vashishta and S-1 fields concurrently through in-field flow lines using daisy chain architecture. Dual subsea pipelines to the onshore terminal at Odalarevu will be installed. The current field architecture provides suitable tie-in locations at both S-1 and Vashishta locations. The location of gas field and composite production profile of Vashishta and S-1 fields are given in Table 1 and 2 respectively.

Table 1: Location of the Gas field

Location Geographic Coordinates UTM Coordinates

Longitude (East) Latitude (North) Easting Northing

Existing Vashishta VA-1A well

82o 10‘ 09.84‖ 16o 11‘ 49.96‖ 625000 1791106

Existing Vashishta VA-2 well

82o 12‘ 37.11‖ 16o 11‘ 25.30‖ 629378 1790373

VADA 82o 10‘ 10.99‖ 16o 11‘ 50.38‖ 625034 1791119

VADB 82o 12‘ 38.74‖ 16o 11‘ 25.02‖ 629426 1790365 S-1-A 82o 11‘ 49.48‖ 16o 16‘ 27.56‖ 627909 1799654 S-1-B 82o 12‘ 24.58‖ 16o 15‘ 58.69‖ 628956 1798773 Landfall Point 81o 59‘ 57.048‖ 16o 15‘ 15.462‖ 606682 1815764

Table 2: Composite Production Profile of Vashishta and S-1 Fields

Wells VA-DA (New

location) VA-DB S-1-A S-1-D Total Gas

Production/ Yr

(MMm3)

Cum Gas

(MMm3) Year

Avg. Gas rate

(MMm3/d)

Avg. Gas rate

(MMm3/d)

Avg. Gas rate

(MMm3/d)

Avg. Gas rate

(MMm3/d)

Avg. Gas rate

(MMm3/d) 1 2.75 0.80 1.2 1.0 5.75 2099 2099 2 2.75 0.80 1.2 1.0 5.75 2099 4198 3 2.75 0.80 1.2 1.0 5.75 2099 6296 4 2.75 0.80 1.2 1.0 5.75 2099 8395 5 2.75 0.80 1.2 1.0 5.75 2099 10494 6 2.32 0.76 1.2 1.0 5.3 1927 12421 7 1.85 0.58 1.2 1.0 4.6 1688 14109



Wells VA-DA (New

location) VA-DB S-1-A S-1-D Total Gas

Production/ Yr

(MMm3)

Cum Gas

(MMm3) Year

Avg. Gas rate

(MMm3/d)

Avg. Gas rate

(MMm3/d)

Avg. Gas rate

(MMm3/d)

Avg. Gas rate

(MMm3/d)

Avg. Gas rate

(MMm3/d) 8 1.47 0.45 0.9 0.7 3.6 1303 15412 9 0.63 0.36 0.0 0.0 1.0 363 15775

2.3 Subsea Pipeline and Onshore Pipeline

a) Subsea pipe line for transfer of NG product from Wells to ‗landfall point‘

Pipeline routing will follow the existing G1 pipeline system as much as possible and therefore has a minimal impact on the seabed and surrounding environment. The system has been designed so that pigging can be undertaken fromonshore; this negates the need to for offshore intervention and therefore reduces the overall operating carbon footprint of the asset.

The use of horizontal trees means that a light intervention vessel is required for any well work over rather than a drill rig. This saves on vessel mobilization and therefore assists in maintaining a minimal carbon footprint.

Daisy chain development with midline tees and crossovers located at S1 wells, VA-DB and PLETs at VA-DA. PLEM at VA-DB will allow pigging for future expansion.

The pipeline has been split into two sections for determination of wall thickness: subsea and landfall. The landfall section of pipe has higher integrity requirements and therefore higher wall thickness. Maintaining a constant bore through the pipeline (to allow for pigging) is preferable. Hence, pipe with non-standard outer diameter is selected for the Subsea pipeline (2 X 14‖ pipelines of 45 km long; including infield sub-sea architecture –subsea umbilical).

Subsea Pipeline details:

Pipeline Length (m) : ~43,000 Design Capacity : 6 MMSCMD Maximum Design Temperature (oC) :65 Minimum Design Temperature (oC) : -75 Design Pressure (barg) : 255 Operating Pressure : ~ 60 bar G

b) Onshore Pipeline details:

Pipeline Length (m) : ~4,200 Pipeline Length (Dia. ‘‘) : 14 Design Capacity : 6 MMSCMD Maximum Design Temperature (oC) : 30 Minimum Design Temperature (oC) : 15 Operating Pressure (Receiving) : ~ 9 to 24 bar G Operating Pressure (Discharge) : ~ 67.5 bar G



2.5 meters burial and 60mm concrete coating up to 27 meters water depth. This will be approximately up to two thirds of the way along the first leg of the pipeline.

2.5 meter burial and 60mm concrete coating up to 79 meters water depth. This is just after the first deviation away from the G-1 pipelines

30mm concrete coating up to 200 meters water depth. 3LPP coating and surfaced laid for the remainder of the development. 2.5 meters burial for the onshore section. [Additional precautions may be taken if

any railway or road crossings are involved.]

For the first two stages, the pipeline is protected against the likely forms of risk (on shore- surface movement of man/ vehicle; off shore- Coastal movement of crafts/fishing vessels). As the water depth increases the protection provided is mainly against mechanical risks such as fishing gear and dropped objects. Once the water depth is greater than 200metres the overall risk to the field is as low as reasonably practicable and therefore no additional protection is provided.

3. RISK ASSESSMENT

Hydrocarbon operations are generally hazardous in nature by virtue of intrinsic chemical properties of hydrocarbons or their temperature or pressure of operation or a combination of them. Fire, explosion, hazardous release or a combination of these are the hazardous associated with hydrocarbon operations. These have resulted in the development of more comprehensive, systematic and sophisticated methods of safety engineering such as identification and analysis of hazards and Risk assessment to improve upon the integrity, reliability and safety of hydrocarbon operations. The RA studies are based on Quantitative Risk assessment Analysis (QRA). The analysis based on ALOHA (Aerial locations of Hazardous Atmosphere), which is developed jointly by NOAA and the environment protection agency (EPA), US.

ALOHA is a program designed to model chemical release for emergency responders and planners. It can estimate how a toxic cloud might disperse after a chemical release & also features served fires & explosions scenarios. A sample sheet of QRA modeling analysis of S-1 and VA is given in Annexure-I.

3.1 Onshore Facilities

3.1.1 Hazards in Onshore Facilities -Nature and sensitivity of impact zones

Onshore pipeline will be laid at a depth of ~ 2.5 m. The line may pass through inhabited areas (uninhabited now but may get inhabited after some period) and also some road / railway crossings may come later. Any opening in the operating pipe line (due to any damage or any other cause) will result in gas leakage.

The gas will be received in the terminal for processing (i.e. separation from unwanted matter (condensate and other materials) and compressed to 67.5 barg and sent to metering station.

Hazards in the terminal will be mostly from HC gas leakage and also from chemical spillage (methanol or others). The leakage from process equipment (flange connections/instrument tapings or catastrophic equipment flange failures) can occur. The rate of leakage will depend upon system pressure, depth and opening size.



3.1.2 Failure Scenarios (Likely)

Considering the above key parameters, five scenarios /cases occur:

Scenario 1. a. Pipe Line opening (leakage source)~50% of inlet cross section b. Line Pressure ~ 25 bar

Scenario 2. a. Flange leakage (opening cross section~ 20 mm dia.) b. Line Pressure ~ 25 bar

Scenario 3. a. Flange leakage (opening cross section~ 20 mm dia.) b. Line Pressure ~ 60 bar

Scenario 4. a. Equipment flange failure (150 mm dia.) b. Line Pressure ~ 60 bar

Scenario 5.

a. Methanol Spillage

Scenario No

Scenario Impact Zone Remarks

1 a. Pipe Line opening ~ 50% of inlet cross

section; Line Pressure ~ 25 bar Jet fire

38 m

1st degree burn

2 Flange Leakage [Opening cross section ~ 20 mm dia.]; Line Pressure ~ 25 bar Jet Fire

< 10 m 1st degree burn

3 Flange Leakage [Opening cross section ~ 20 mm dia.]; Line Pressure ~ 60 bar Jet Fire

< 10 m 1st degree burn

4 Equipment Flange Failure (150 mm); Vessel Pressure 60 bar Jet Fire

74 m 1st degree burn

5 Methanol spillage from Tank; Toxic vapors IDLH < 10 m



Scenario – 1

Scenario – 4



3.1.3 Sensitive Receptors and Impact

Any adverse incident in the proposed terminal can have minor or major damage to permanent receptors if the same are coming within the impact zone. The terminal is not coming in ―Coastal Regulation Zone (CRZ)‖ classified as sensitive zone as per Environment Protection Act (1986). The existing ONGC terminal can be adversely affected nearest village is Odalarevu at a distance of 630 m from facility.

3.1.4 Control Measures for Major Hazards

The preventive control measures to prevent/avoid occurrence of hazardous stance are given below:

LDAR program:

Hydrocarbon industry in general and Natural gas producing and processing facility is highly hazardous in nature due to the inflammable/explosive nature and also toxic nature (if H2S is there in NG). Some of the chemicals used are also hazardous.

The proposed ONGC terminal is using pipelines, vessels, compressors, pumps, valves and other fittings in the transfer and processing of gas/fluid from ―Onshore pipeline‖ to the terminal. To reduce fugitive emissions in the plant, proper Leak Detection &Repair (LDAR) program is required in the facility.

The proposed LDAR program is as follows:

Identification of sources: Valves, pipes, joints, pump and compressors seals, flanges etc.

Monitoring of Gas/VOC is to be carried out regularly through permanent Gas monitors at strategic locations and also portable gas detector. Monitoring frequency should be once in a quarter is required.

Focus should be for prevention of fugitive emissions by having preventive maintenance of pumps, valves, pipelines etc. A preventive maintenance schedule should be prepared and it should be strictly adhered to.

When monitoring results indicate Gas/VOC above permissible limit repairing should be done immediately. The repair should be conducted in such a way that there is no fugitive emission from the particular component.

Fugitive Emission

The following guidelines for fugitive emissions should be strictly followed:

Fugitive emissions over and around vessels and other machineries transfer areas etc. should be monitored regularly.

Enclosures to chemical storage area should be provided. Vapor balancing, nitrogen blanketing, isolated tanks etc., should be provided. Special

care will be taken for odorous chemicals.

3.1.5 Fire Fighting Facility

Adequate firefighting facilities have been considered at the terminal design stage provided including

Water ring



Hydrants Fire Water Pumps: 6 nos. [3 Electric and 3 Diesel Engine Driven; Two electric driven

Jockey pumps) Fire Water Reservoir (cap. 9525 M3)

Fire extinguishers will be put up at strategic places as per requirement. Gas sensors with alarm will be installed at sensitive locations to caution about HC gas leakage.

3.1.6 Frequency of Occurrence of Accident Scenario

Frequency of occurrence of incident is important in risk analysis. Safe operating procedures, proper maintenance and safety precaution reduce the frequency of occurrence of such incident. The data sources referred for failure frequency is E&P Forum (Oil Industry International Exploration & Production Forum) frequency data base from TNO and failure frequency data from the Rajmond Report (COVO study). The frequency occurrences for various scenarios are given below, which is probability data in general of only one tank.

S.No. Scenarios Frequency of Occurrence 1. Catastrophic failure of largest

nozzle connection in HSD tank 1 x 10-6 per tank per year

Probability of Ignition Immediate Ignition 0.065 Delayed Ignition 0.065 No Ignition 0.87

2. Catastrophic failure of Tank 6.7 x 10-7 per tank per year

Safety precaution, proper maintenance of equipment and risk mitigation measures adopted in storage and handling of inflammable materials will reduce the probability of occurrence of hazardous incident.

3.1.7 Occupational Health

The construction and operational activities of proposed Onshore Terminal involves many occupation health hazards to the workers at site. The site preparation, noise generation, handling of fuel, chemicals & lubricants (if not handled properly) and process leaks and fire/explosions may affect the health and cause serious injuries to the workers and surrounding communities.

ONGC will take all health and safety measures in compliance with following rules and procedures:

Storage and handling of Hazardous Materials TAC 1998 – Fire Protection Manual (Internal Appliances, Fire Engines, Trailer

Pumps and Hydrant Systems) Chief Controller of Explosive Guidelines Indian Factories Act 1948 / State Factories Regulations Gas Cylinder Rules Indian Electricity Act / Rules

Safety Code for Transportation of Hazardous Substances



Provincial Fire Codes for Buildings Fire Protection Manual of Tariff Advisory Committee Rules 2008 and OISD 233 and 118 for fire and explosion risk assessment and fire

protection/fighting systems

Health Hazard Control is done by adopting following measures:

Prioritize the health hazards based on their risk potential. Identify specific work groups affected by each hazard. Determine the controls required to manage these identified hazards. Develop an action plan identifying work to be done.

All employees undergo a periodic medical examination. The record of the health check-up will be maintained centrally off site in confidential file by the medical section. The medical officer at base recommends appropriate treatment for the persons found to be having any health problems requiring attention.

Majority of the employees will be trained in first aid. Regular drills and lectures on first aid are carried out at the terminal. HSD Tanks shall be provided with Foam and spray system. Establishment of warning signs at the potentially danger places, fire alarm & protection system and good housekeeping practices. Occupational Health Surveillance Program is summarized below.

Cause of health hazard Risk Mitigation Measures

Noise (Generators, Cranes, Fire,

Water pump, Hot oil pumps,

condensate transfer pumps)

Hearing loss Use of PPEs in high noise area and

written operational procedures to be

followed.

Procedures to be followed as per

MSDS of all hazardous chemicals for

safe handling.

ERP/DMP to be followed. Ensure the

availability of medical treatment on

site and off site and written procedure

to be followed.

Handling of heavy equipment

and material (Manual handling

of material)

Back problem

Handling of chemicals

(Chemical stores, Chemical

dosing areas, Chemical labs)

Eye problems and

chemical ingestion,

Dermal effect of

chemicals

Process Leaks/Fire and

Explosion

Serious

Injuries/damage to

health

Occupational Health surveillance of workers shall be done on regular basis and records maintained as per the Factory Act.

3.2 Offshore Gas Field Development

3.2.1 Hazards in ―Offshore Gas Field Development‖



Taking into account the applicability of different risk aspects (in context of the offshore Gas field development only) to be undertaken in the proposed East Coast KG Basin, various hazards associated with proposed project are:

A. Natural Hazards: Extreme Storm

The following met ocean design conditions are used for the detailed design of the system:

Seasonal and whole year directional extremes of wind, waves and currents Directional significant wave height Wave and current climate for fatigue analysis Air temperature extremes and climate at landfall locations Persistence of storm and calm conditions for onsite operations Variability of the sea level Hydrological sea water parameters (temperature, salinity and density)

Bay of Bengal is known for rough weather; since the production facilities will be sub-sea, it is unlikely to be affected much with rough weather.

B. KG Basin Operation

The Vashishta and S1 development shall comprise four production wells: VA-DA and VA-DB at the Vashishta field and S1-A and S1-B at the S1 development. The Vashishta field is located in water depths of 500 to 700 meters. Two new wells are proposed to be drilled in this field. The S-1 field is located in water depths of approximately 250-600 meters. ONGC intends to drill and test two new wells as part of its field appraisal plan.

Some of the other hazards associated with hydrocarbon in offshore and onshore productions are as follows:

Blowouts Collisions Helicopter crash Presence of H2S Process leaks Process and non-process fires / explosions

Other possible hazard scenarios like chemical spills, falls, etc. has not been considered for detailed assessment as preliminary evaluation has indicated that the overall risk that may arise out of them would be low. In addition, it is understood that the causative factors and mitigation measures for such events can be adequately taken care of through existing safety management procedures and practices of ONGC.

The above risks and hazard have been evaluated based on the likelihood of occurrence and the magnitude of consequences. The significance of the risk is expressed as the product of likelihood and the consequence of the risk event, expressed as follows: Significance = Likelihood X Consequence. The Figure 2 below illustrates all possible product results for the four likelihood and consequence categories and the Table 3 assigns risk significance criteria in three regions that identify the limit of risk acceptability according to the policy and the strategic objectives of ONGC. Depending on the position of the intersection of a column with a row in the risk matrix, hazard prone activities have been classified as low, medium and high thereby qualifying for a set of risk reduction / mitigation strategies.



Figure 2: Risk Matrix and Acceptability Criterea

Table 3: Risk Categories and Significance of Criterea

3.2.2 Major Hazards

a) Oil Spill

Minor Oil Spill

During the well testing operation, there exists a possibility of hydrocarbon gases / oil getting released due to some unavoidable incidents. Once the flow of oil / gas from well is stopped, then on-site access for clean-up is possible. If flow from well cannot be stopped, a blowout situation exists.

Major Oil Spill

Significant hydrocarbon inventories will not be maintained at the rig. A major spill can, therefore, only arise as a result of an uncontrolled flow from a well i.e blowout.

Provided that ignition does not take place and the well head is not obstructed the well can be shut in at the wellhead. If ignition occurs or other damage prevents access to the wellhead then a blowout situation exists and appropriate measures must be implemented.

b) Blowout



Blowout means uncontrolled violent escape of hydrocarbon fluids (gas with associated water, gas with condensate and gas wit oil) from a well. The oil and condensate concentration is very small and gas coming out:

a. From sea bed is already stripped out of both and saturated with water. Its combustion characteristics are unlikely to be affected by oil.

Blowout followed by ignition which prevents access to the wellhead is a major hazard. Contributors to blowout are:

Primary

Failure to keep the hole full Mud weight too low Swabbing during trips Lost circulation Failure of differential fill-up equipment

Secondary

Failure to detect and control a kick as quickly as possible Mechanical failure of BOP Failure to test BOP equipment properly Damage to or failure of wellhead equipment Failure of casing Failure of formation or cement bond around casing

Blow Out Consequences and Effects

A blowout incident can take a variety of different forms, ranging from a minor leak which can be stopped within minutes, to a major release which continues out of control for days or even months. The consequences of a blowout event will to a large extent depend on how the blowout scenario evolves and the following possible scenarios are likely:

Release of high pressure inflammable and explosive gas. This may have deleterious effect on the coastal traffic.

Ignition of the flammable gas released resulting in a jet fire, pool fire or an explosion.

Ignition of released gas can possibly result in considerable harm, with historical datashowing 40 % blowout such incidences leading to more than significant damage to the drilling ship / platform (WOAD database) and resulting in associated fatalities amongst drilling crew and support personnel present on the ship / platform. Also, ignition has been recorded in about 30% of the blowout cases on an average (SINTEF offshore blowout database). However, on positive side, with improvement of offshore drilling, production and product transfer- trasporttechnology, number of offshore blowouts occurring has significantly gone down in the last decade.

Risk Ranking for Blowouts

Likelihood Ranking - B

Consequence Ranking - 5

Risk Ranking –5B (High)



If the hydrostatic head exerted by the column of drilling fluid is allowed to drop below the formation pressure then formation fluids will enter the wellbore (this is known as a kick) and a potential blowout situation has developed.

In the proposed KG Operation such occurrences are possible.Fast and efficient action by operating personnel in recognizing the above situations and taking precautionary measure can avert a blowout.

c) Collisions Involving Drill Ship (MODU)

A collision situation is considered for the risk assessment for the impacts on ―Well Unit‖ by heavy falling objectsfrom otherdrill ships or other marine vessels working nearby or passing by it.

The following possibilities have been taken into consideration:

Visiting support vessels which approach the MODU under their own power and includingsupply vessels, standby vessels accidently releasesome objects and it hits the well.

Consequences and Effects

The analysis of collision consequences is generally based on the principle of conservation ofenergy. The impact of a full-on collision may however be more severe and may lead to damage to the well and may lead to a rupture or leak in the riser resulting in a process leak or a blowout.

Risk Ranking for Vessel Collision

Likelihood Ranking - C Consequence Ranking - 3 Risk Ranking - 3C (Medium)

In the proposed KG Operation such occurrences are possible.

d) Helicopter Crashes

The journey to and from offshore rig has historically been one of the main reasons for accidental death or injury to many offshore workers. For the ONGC India drilling activities, crew transport to and from the MODU will be by helicopter, due to its speed, convenience and good operability under rough weather conditions.

Several approaches exist to analyze probability of helicopter crash risks.

A more reasonable approach involves the use of individual risk approach as a product of 3 components:

Frequency of helicopter accidents per flight; Proportion of accidents which involve fatalities; Proportion of personnel on board in fatal accidents who become fatalities.


Helicopter crashes involved with offshore oil & gas exploration and production have happened routinely in the past, especially in the North Sea offshore operations in Europe, with some resulting in fatalities or injuries to crew members. In addition to the risk posed to the



helicopter occupants, accidents involving helicopters can also cause damage to the drill ship itself by way of crashing into the ship during take-off or landing or by an accident when the helicopter is on the helideck. However, the consequence of such risk may be considered to be small compared to the other risks sources on the MODU.

Risk Ranking for Helicopter Crash

Likelihood Ranking - B Consequence Ranking - 3 Risk Ranking - 3B (Medium)

In the proposed operation the need for helicoter movement will be less and during well maintenanace only.

e) Hydrogen Sulphide (H2S)

Hydrogen sulphide gas (H2S) is extremely toxic, even very low concentrations can be lethal depending upon the duration of exposure. Without any warning, H2S may render victims unconscious and death can follow shortly afterwards. In addition, it is corrosive and can lead to failure of the drill string or other tubular components in a well.

The Occupational Safety and Health Act (OSHA regulations) set a 10 ppm ceiling for an eight hourly continuous exposure (TWA limit), a 15 ppm concentration for short term exposure limit for 15 minutes (STEL) and a peak exposure of 50 ppm for 10 minutes.


The gas rate can be very large (depending well pressure and other well conditions). However gas rate blowing out will be affected by water depth (due to hydraulic pressure as high as 68 bar). Two scenarios have been considered:

Blow Out – due to failure in Well Heavy Leakage due to damage in system downstream in the well (caused by external

object or else)

Gas will disperse (to some extent) due to wave motion and come to surface in a wide area. The area of dispersion will depend upon depth of well, current / sea roughness, weather etc. However for modeling (80% for Blow Out and 60 % for heavy leakage) part of the leakage have been considered as concentrated at one place and catch fire,

The rate of leakage will depend upon pipe line pressure, depth and opening size.

Considering these key parameters four scenarios /cases selected for the modeling and consequential impact. The selected scenarios are summarized below.

Scenario No. Scenario

Impact Zone (m) Remarks

1

Blowout for VA-DA (due to heavy impact from heavy falling objects; Remote possibility);

Jet fire

90

1st degree burn Max Flame Length: 14 meters

2

Heavy leakage from the well VA-DA(due to heavy impact from heavy falling objects or well system failure);

Jet fire

72


3 Blowoutfor S1-A (due to heavy impact 64 1st degree burn



Scenario No. Scenario

Impact Zone (m) Remarks

from heavy falling objects; Remote possibility);

Jet fire

Max Flame Length: 10 meters

4

Heavy leakage from the well S1-A (due to heavy impact from heavy falling objects or well system failure);

Jet fire

51


The scenarios considered are both for Vashishta and S-1 gas wells.

Scenario--1



Scenario—2

Scenario—3



Scenario—4

3.2.4 Receptors and Sensitive Locations

Any adverse incident in the proposed Vashishta and S-1 Gas wells can have minor or major damage to permanent receptors if the same are coming within the impact zone (At present no such receptors are there). Gas wells are also not coming within the ―Coastal Regulation Zone (CRZ)‖ which is classified as sensitive zone as per Environment Protection Act (1986).

The distance between adjoining wells are given in Table 4. Any adverse incident in one of the well will be limited 90 m (max.) and is unlikely to affect the vessel carrying out maintenance in nearest adjoining well.

Table 4: Distance of Wells in Vashishta and S-1 fields

Wells Distance (in km)

V1 V2 S-1A S-1B V1 0 4.54 9.06 8.61 V2 0 9.45 8.47

S-1A

0 1.45 S-1B 0



a) Blowout

The precautionary and control measures used for blowout prevention are discussed below:



I. Precaution against Blowout

1. The following control equipment for drilling mud system shall be installed and kept in use during drilling operations to prevent the blowout: A tank level indicator registering increase or reduction in the drilling mud volume

and shall include a visual and audio –warning device near the driller stand. A device to accurately measure the volume of mud required to keep the well

filled at all times. A gas detector or explosive meter at the primary shale shaker and connected to

audible or visual alarm near the driller stand. A device to ensure filling of well with mud when the string is being pulled out. A control device near driller stand to close the mud pump when well kicks.

2. Blowout prevention drill shall be carried out once every week near the well during drilling.

3. Suitable control valves shall be kept available near the well which can be used in case of emergency to control the well.

4. When running in or pulling out tubing, gate valve and tubing hanger shall be pre- assembled and kept readily available at the well.

II. Precaution after Blowout

On appearance of any sign indicating the blowout of well, all persons, other than those whose presence is deemed necessary for controlling blowout, shall be withdrawn from the location. While controlling of blowout is in progress, the following precautions shall be taken:

1. A competent person shall be present on the spot throughout. 2. An area within the 500 meters of the well on the down wind direction shall be

demarcated as danger zone. All electrical installations shall be de-energized. Approved safety lamps or torches shall only be used within the danger zone. No naked light or vehicular traffic shall be permitted within the danger zone.

3. A competent person shall ascertain the condition of ventilation and presence of gases with an approved instrument as far as safety of persons is concerned.

4. These shall be available at or near the place, two approved type of self-contained breathing apparatus or any other breathing apparatus of approved type for use in an emergency.

5. Adequate firefighting equipment shall be kept readily available for immediate use.

b) Vessels Collisions

A Vessel Management Plan will be formulated and implemented to reduce collision risk, both vessel–vessel and MODU–vessel and will address the following:

Mandatory 500 m safety zone around well location; Operational restrictions on visiting vessels in bad weather; Defined vessel no-go areas within safety zone; andagreed approach procedures to rig

by supply and safety vessels.

c) Helicopter Crashes

Following preventive and mitigation measures will be adopted with respect of helicopter operations:



Air worthiness of helicopter to be checked by competent authority or ONGC before helicopter is hired.

ONGC should ensure that the pilot/pilots who will be operating have got appropriatetraining on similar craft.

Effective arrangements for coordination would be developed with air traffic control room at Base port, as also in the MODU;

Helicopter operations to be restricted during night time and during bad weather conditions.

All employees who are supposed to travel on helicopters would be receiving basic training on rescue and survival techniques in the case of a helicopter crash at sea.

ONGC has ensured that all helicopter crews are HUET trained and all choppers are having AS4 safety rating for offshore operations.

d) Control Measures of H2S

The following control measures for H2S will become necessary if presence of H2S is detected at any new well.

I. H2S Detection System Presence

A four channels H2S gas detection system will be provided. Sensors will be positioned at optimum points for detection, actual locations being decided on site but likely to be:

Well Nipple Rig Floor Shaker header tank Substructure cellar

The detection system will be connected to an audio visual (siren and lights) alarm system. This system will be set to be activated at a concentration of 15 ppm H2S.

The mud logging will have a completely independent detection system which is connected to an alarm in the cabin. This system will be adjusted to sound an alarm at a concentration level of 10 ppm H2S as suggested in the Drilling and Production Safety Code for Onshore Operators issued by The Institute of Petroleum.

A stock of H2S scavenger will be kept at drilling site for emergency use.

II. Small Levels of H2S

Small levels of H2S (less than 10 ppm) will not activate the well site alarms. Such levels do not create an immediate safety hazard but could be a first indication of high levels of H2S to follow.

H2S will cause a sudden drop of mud pH. The mud man will therefore organize and supervise continuous pH checks while drilling. Checks should be as frequent as possible and always made following a formation change.

Following control measures will be taken in case of small level of detection:

H2S scavenger will be added to mud. H2S levels will be cheked at regular intervals for possible increase.



All personnel of the rig will be informed about the presence of H2S and current wind direction.

Operations will be commenced in pairs. Sub base and cellar out-of-bounds will be rendered without further checking levels in this

area.

The workers will be provided with personal H2S detectors along with self containing breathing apparatus.

III. High Levels of H2S

Higher levels of H2S (greater than 10 ppm) do not necessarily cause an immediate safety hazard. However some risk does exist and, therefore, any levels greater than 10 ppm should be treated in the same manner. Occurrence of 10 ppm or greater H2S concentration will sound an alarm in the mud logging unit.

If higher levels of H2S greater than 10 ppm are found, following steps will be taken:

Driller will shut down rotary and pumps, pick-up so that drill pipe in BOP and chain down the break.

One pre-assigned roughneck will go to doghouse and put on breathing apparatus. All other rig personnel will evacuate the rig and move in up-wind direction to designated muster point.

Driller and roughneck will return to the rig floor and commence circulating H2S scavenger slowly and reciprocating pipe.

The level of H2S will be checked in all work areas. H2S scavenger will be added to the mud and circulated. If H2S levels drop, drilling will be continued with scavenger in the mud. Approximately 30 % of hydrogen peroxide (H2O2) solution will neutralize H2S gas in the mud at 20 gallon of H2O2 per 100 barrels of mud.

The workers will be provided with personal H2S detectors along with self containing breathing apparatus.


Since the operational wells will be at sea bottom (S-1 Wells ~250-600 m or Vashishta Wells ~ 500 - 700 m), the permanent firefighting facilities may not be feasible.Marine firefighting and medical facilities may be created and stationed at nearest port so as to be available during emergency.

3.2.7 Frequency of Occurrence of Accident Scenario

Frequency of occurrence of incident is important in risk analysis. Safe operating procedures, proper maintenance and safety precaution reduce the frequency of occurrence of such incident. The data sources referred for failure frequency is E&P Forum (Oil Industry International Exploration & Production Forum) frequency data base from TNO and failure frequency data from the Rajmond Report (COVO study). The frequency occurrences for various scenarios are given below, which is probability data in general of only one tank.



S.No. Scenarios Frequency of Occurrence 1. Catastrophic failure of largest nozzle

connection in HSD tank 1 x 10-6 per tank per year

Probability of Ignition Immediate Ignition 0.065

Delayed Ignition 0.065

No Ignition 0.87 2. Catastrophic failure of Tank 6.7 x 10-7 per tank per year

Safety precaution, proper maintenance of equipment and risk mitigation measures adopted in storage and handling of inflammable materials will reduce the probability of occurrence of hazardous incident.


Occupational hazards associated with offshore drilling include illness from exposure to geographical and climatic elements. Work in offshore can involve exposure to hazardous substances, noise, vibrations, hot or cold conditions, heavy manual handling activity on the derrick floor etc. Installations especially in deep water drilling are isolated, workforce travels to work by helicopter and perform shift duties. Extended long distance travelling, psychological stress resulting from physical isolation due to remoteness of site and shift duty pattern, seasickness and exposure to extreme weather conditions is other hazards. Harsh climate, parasitic diseases and infections may result in respiratory tract diseases.



Pumps and Hydrant Systems) Chief Controller of Explosive Guidelines Static & Mobile Pressure Vessels Rules

Indian Factories Act 1948 / State Factories Regulations Gas Cylinder Rules Safety Code for Transportation of Hazardous Substances Fire Protection Manual of Tariff Advisory Committee

Petroleum and Natural Gas Rules ( Safety in Offshore operations)

Rules 2008 and OISD 233 and 118 for fire and explosion risk assessment and fire protection/fighting systems


Prioritize the health hazards based on their risk potential. Identify specific work groups affected by each hazard. Determine the controls required to manage these identified hazards. The cost of each

identified control versus benefits of its implementation may be evaluated. Develop an action plan identifying work to be done.



On board qualified doctor is available 24 hrs on the drilling rig for the immediate treatment and first aid. For serious injuries and diseases patient is evacuated by the emergency helicopter exclusively meant for emergencies to the nearest base.

The health and hygiene of the personnel working at the Drilling Rig or at sea for long period will be monitored through periodic health checks of the persons. All employees undergo a periodic medical examination. The record of the health check-up will be maintained centrally off site in confidential file by the medical section. The medical officer at base recommends appropriate treatment for the persons found to be having any health problems requiring attention.

During the proposed drilling operations, inspections of cleanliness are carried out. First aid boxes are provided at different strategic locations on the drilling rig. The medical officer on board shall regularly inspect the first boxes and ensures that their contents are in order. Majority of the employees on the drilling rig are trained in first aid. Regular drills and lectures on first aid are carried out at the rig. Occupational Health Surveillance Program is summarized below.

Cause of health hazard Risk Mitigation Measures Noise (Generators, Cranes, Fire,

Water pump, Hot oil pumps, Crude dispatch pumps)

Hearing loss Use of PPEs in high noise area and written operational

procedures to be followed.

Procedures to be followed as per MSDS of all hazardous chemicals for safe handling.

ERP/DMP to be followed.

Ensure the availability of

medical treatment on site and

off site and written procedure to

be followed.

Handling of heavy equipment and material (Manual handling

of material)

Back problem

Handling of chemicals (Chemical stores, Chemical dosing areas, Chemical labs)

Eye problems and chemical ingestion,

Dermal effect of chemicals

Fire/Leakage/Blowout Serious Injuries/damage to

health

3.3 Installation of Subsea and Onshore Pipeline

3.3.1 Hazards in Insulation of Subsea and Onshore Pipeline - Nature and sensitivity of impact zones

Subsea Pipeline:

1) Natural hazards - Landslides

The generation of landslides that could potentially affect the pipeline integrity has beenqualitatively evaluated at the outset of the project for the entire pipeline route. It was concluded that the pipelines are not threatened by landslide. The occurrence of a landslide is due to the coexistence of various conditions such as:

Thick layers of very soft sediments lying on steep slopes Slope angles able to trigger the development of soil instability Triggering mechanisms causing the landslides (e.g. seismic loads, wave loads, rapid

accumulation of soft sediments)



No such conditions have been found along the pipeline routes. In addition the proposed pipeline support system is designed after conducting on-bottom stability tests and maximum free span lengths totake care of the subsea soil erosion (if any) and regular inspection of pipeline route will caution of any likely damage.

2) Natural hazards - Extreme Storm

The following met ocean design conditions are used for the detailed design of the system

Seasonal and whole year directional extremes of wind, waves and currents Directional significant wave height Wave and current climate for fatigue analysis Air temperature extremes and climate at landfall locations Persistence of storm and calm conditions for onsite operations Variability of the sea level Hydrological sea water parameters (temperature, salinity and density)

Bay of Bengal is known for rough weather; since the production operational system and Subsea pipeline will be near the sea bottom, it is unlikely to be affected much with rough weather.

3) Heavy Impact and Damage to pipeline due to dropping of heavy objects

A situation is considered for the risk assessment for the impacts on ―Subsea Pipeline‖ by heavy falling objectsfrom otherdrill ships or other marine vessels working nearby or passing by it.

The following possibilities have been taken into consideration:

Vessels which passes through the pipeline route may accidently release some heavy objects/ anchors and it hits the Pipeline.


The analysis of consequences is generally based on the principle of conservation ofenergy. The impact of a complete contact with the object may however be more severe and may lead to damage to the pipeline such as rupture or leak from the pipeline resulting in a process leak.

Risk Ranking

Likelihood Ranking - C Consequence Ranking - 3 Risk Ranking - 3C (Medium)

KG Basin Operations:

Any heavy pipeline leakage (if occurs) at a depth of ~ 250 - 600 m and at maximum pressure (nonoperation; design) of 3242 psia (220 atm.). This will cause tremendous stirring/ agitation at sea bottom/may result in shock waves causing damage to adjoining (pipeline) installations and also to nearby installations. The high pressure gas will be directed as jet in the direction of leaky point and rise to the surface and will blow out as gas / water shower combination. It may catch fire also (less likely as it is with sea water and cool) and burn. The gas rate can be very large (depending well pressure and other pipeline /operational conditions)



Onshore Pipeline:

Onshore pipeline will be laid at a depth of ~ 2.5 m. The line may pass through inhabited areas (uninhabited now but may get inhabited after some period) and also some road / railway crossings may come later. Any opening in the operating pipe line (due to any damage or any other cause) will result in gas leakage.

Leaking gas will come out at pressure from underground and disperse to surface in a wide area. The area of dispersion will depend upon depth of pipeline and weather etc. If ignition source is found it may catch fire.


Subsea Pipeline

Subsea pipeline will be laid at sea surface at a depth varying from > 600 m to shore. The sea water will exert pressure on the line which can be as high as 60 bars. Any opening in the operating pipe line (due to any damage or any other cause) will result in gas leakage.

Leaking gas will disperse (to some extent) due to wave motion and come to surface in a wide area. The area of dispersion will depend upon depth of pipeline, current / sea roughness, weather etc. However for modeling (60 %) part of the leakage have been considered as concentrated at one place and catch fire,

The rate of leakage will depend upon pipe line pressure, depth and opening size. Considering these key parameters four scenarios /cases are envisaged.

Onshore Pipeline

Onshore pipeline will be 2.5 m buried. Additional precautions may be taken if any railway or road crossings are involved. Any leakage in the pipeline (if small) will seep through soil and come out and catch fire if any source of ignition is there. It may start domino effect if any other inflammable material is there (dry grass or else). In case of major damage and consequential fire the heat radiation zone can be large as given below.

For modeling purpose worst possible conditions (line pressure 220 atm. and 60 atm. is taken) which may occur due to major system failure.

Scenario 1. a. Pipe Line opening (Leakage source)~ 50% of inlet cross section; Vertical b. Depth ~ 500 m c. Line Pressure ~ 220 bar

Scenario 2. a. Pipe Line opening ~ 50% of inlet cross section; Vertical b. Depth ~ 500 m c. Line Pressure ~ 220 bar


Scenario 4.



a. Pipe Line opening ~ 50% of inlet cross section; Vertical b. Depth ~ 300 m c. Line Pressure ~ 60 bar



Scenario 7. a. Pipe Line opening ~ 50% of inlet cross section b. Line Pressure ~ 25 bar

Scenario No Scenario Impact Zone Remarks

1 Pipe Line opening ~ 50% of inlet cross section Line Pressure ~ 220 bar [Release Pressure—170 bar Jet fire

96 m

1st degree burn

2 Pipe Line opening ~ 50% of inlet cross section Line Pressure ~ 220 bar [Release Pressure—190 bar Jet fire

101 m

1st degree burn

3 Pipe Line opening ~ 50% of inlet cross sectionLine Pressure ~ 60 bar [Release Pressure—10 bar Jet fire

26 m

1st degree burn

4 Pipe Line opening ~ 50% of inlet cross sectionLine Pressure ~ 60 bar [Release Pressure—30 bar

Jet fire



Jet fire



Jet fire


7 Pipe Line opening ~ 50% of inlet cross section; Line Pressure ~ 25 bar Jet fire

38 m

1st degree burn



Scenario - 1

Scenario - 2



Scenario – 3

Scenario - 4



Scenario – 5

Scenario - 6



Scenario – 7

3.3.3 Sensitive Receptors and Impact

Any adverse incident in the proposed Subsea and Onshore pipeline can have minor or major damage to permanent receptors if the same are coming within the impact zone. Both subsea pipeline and Onshore pipelines are coming in ―Coastal Regulation Zone (CRZ)‖ classified as sensitive zone as per Environment Protection Act (1986).

3.3.4 Subsea Pipeline layout impacts

The fire may occur if gas comes in contact with source of ignition.Subsea pipeline do not have any installation nearby. Coastal movement of small vessels/ fishing will be affected. Any off shore equipment/structure or vessel is likely affected by the fire if happened to be within impact zone. There can be domino effect if any sensitive system (fuel transporter or any explosive/inflammable laden vessel) gets trapped in impact zone.

3.3.5 Onshore Pipeline installation Impact Zone

The impact due to accident in the pipeline will be restricted to 56 m (1st degree burn). Terminal may be affected if the incident occurs near the terminal and may initiate a domino effect. However accidents resulting due to domino effect can be more serious. Since the terminal does not have any large storage of inflammable and explosive material there cannot be any major incident. The inhabited areas are far away (> 500 m). Existing ONGC terminal can also be adversely affected. Nearest village isOdalarevu at a distance of 630 m from facility.





A Management Plan will be formulated and implemented to reduce contactriskforconsequential fall of heavy objects,vessel–vessel contactand will address the following:

Mandatory 500 m safety zone around well location; Operational restrictions on visiting vessels in bad weather; Defined vessel no-go areas within safety zone; and agreed approach procedures by

supply and safety vessels during laying of pipeline.


Marine firefighting and medical facilities may be created and stationed at nearest port so as to be available during emergency for offshore pipeline and other installations.

For onshore pipeline, fire engines with other safety devices like fire suits and breathing apparatus/first aid etc. should be stationed at onshore terminal.


The installation and operational activities of proposed pipeline and umbilical for onshore facility at onshore and offshore section involves many occupational health hazards to the workers at site. Work in offshore can involve exposure to hazardous substances, noise, vibrations, hot or cold conditions, heavy manual handling activities (both at onshore and offshore during the handling and laying of pipes) etc. Installations especially in deep water drilling are isolated, workforce travels to work by helicopter/vessels and perform shift duties. Extended long distance travelling, psychologicalstress resulting from physical isolation due to remoteness of site and shift duty pattern, seasickness and exposure to extreme weather conditions is other hazards. Harsh climate, parasitic diseases and infections may result in respiratory tract diseases.



Pumps and Hydrant Systems) Chief Controller of Explosive Guidelines Static & Mobile Pressure Vessels Rules

Indian Factories Act 1948 / State Factories Regulations Gas Cylinder Rules Indian Electricity Act / Rules

Safety Code for Transportation of Hazardous Substances Provincial Fire Codes for Buildings Fire Protection Manual of Tariff Advisory Committee Petroleum and Natural Gas Rules ( Safety in Offshore operations)

Rules 2008 and OISD 233 and 118 for fire and explosion risk assessment and fire protection/fighting systems




Prioritize the health hazards based on their risk potential. Identify specific work groups affected by each hazard. Determine the controls required to manage these identified hazards. The cost of each

identified control versus benefits of its implementation may be evaluated. Develop an action plan identifying work to be done.

On board qualified doctor is available 24 hrs on the vesselsduring laying period for the immediate treatment and first aid. For serious injuries and diseases, patient is evacuated by the emergency helicopter, exclusively meant for emergencies to the nearest base.

The health and hygiene of the personnel working at the vesselsfor long period will be monitored through periodic health checks of the persons. All employees undergo a periodic medical examination. The record of the health check-up will be maintained centrally off site in confidential file by the medical section. The medical officer at base recommends appropriate treatment for the persons found to be having any health problems requiring attention.

Majority of the employees on the vessels are trained in first aid. Regular drills and lectures on first aid are carried out at the vessels. Occupational Health Surveillance Program is summarized below.

Cause of health hazard Risk Mitigation Measures

Noise (Generators, Cranes, Fire Water pump) Hearing loss

Use of PPEs in high noise area and written operational

procedures to be followed.

Procedures to be followed as per MSDS of all hazardous chemicals

for safe handling.

ERP/DMP to be followed. Ensure

the availability of medical

treatment on site and off site and

written procedure to be followed.

Handling of heavy equipment and material (Manual handling

of material) Back problem

Handling of lubricants and oils Eye problems and

chemical ingestion, Dermal effect

Process Leaks/Fire and Explosion

Serious Injuries/damage to

health

Occupational Health surveillance of workers shall be done on regular basis and records maintained as per the Factory Act.

4. DISASTER MANAGEMENT PLAN

For meeting the emergencies caused by major accidents, planning response strategies are termed as Disaster Management Plans (DMPs). DMPs cannot be considered in isolation or act as a substitute for maintaining good safety standards in a plant. The best way to protect against major accidents occurrence is by maintaining very high levels of safety standards.

Generally, the following five phases are involved in an emergency:



Discovery and Notification: An event with an imminent threat of turning into an accident must first be discovered and the discoverer quickly notifies the same to the plant safety officer and also Duty Officer on shore.

Evaluation and Accident Control Initiation: Based on the evaluation of available information, the safety officer makes a rapid assessment of the severity of the likely accident and initiates the best course of action. If required alert the personnel at shore and Coast Guard.

Containment and Counter Measures: Action is first taken to contain and control the accident by eliminating the causes which may lead to the spread of accident. Measures are also taken to minimize the damage to personnel, property and environment.

Cleanup and Disposal: After the accident is effectively contained and controlled, the cleanup of the site of the accident and safe disposal of waste generated due to the accident are undertaken.

Documentation: All aspects of accidents, including the way it started and progressed as well as the steps taken to contain and the extent of the damage and injury, must be documented for subsequent analysis of accident for prevention in future, damage estimation, insurance recovery and compensation payment. It may be noted that some aspects of documentation, such as, photographs of the site of accident and main objects involved in the accident, survey for damage estimation, etc. may have to be carried out before the cleanup and disposal phase. However, the effort in all cases is to recommence the production as soon as possible.

4.1 Emergency Classification

Severity of accident and its likely impact area will determine the level of emergency and the disaster management plan required for appropriate handling of an emergency. Emergency levels and the action needed for each level are indicated below:

Level 1 Emergency

A local accident with a likely impact only to immediate surroundings of accident site, such as, local fires and limited release of inflammable material. The impact distance may not be more than 15 m from the site of primary accident and may require evacuation of the site area (plant/drilling rig) where accident occurred and utmost the adjacent areas (plant/drilling rig).

Level 2 Emergency

A major accident with potential threats to life and property up to 500 m distance requiring the evacuation of all personnel from the threatened area except the emergency response personnel. Larger fires, release of large quantities of inflammable materials may belong to emergency level 2.

Level 3 Emergency

An accident involving a very serious hazard and with likely impact area is extending beyond the operational area limit of ―onshore processing terminal‖, ‗Exploration Rig‘ and ―off-shore and onshore pipeline‖ such as, major fire, very large release of inflammable material and big explosion. Major fires will usually have the triggering effect resulting in the propagation of explosion. In a level 3 emergency, evacuation populations near the site area (exploratory well



periphery (if near coast)/ plant area) and alert the fishing and other vessels operating in nearby areas.

On-site Disaster Management Plan (DMP) will meet the hazards created due to all Level 1 emergencies and most of the Level 2 emergencies. In addition to on-site DMP, off-site DMP may also have to be put into operation for some Level 2 and all Level 3 emergencies.

4.2 Emergency Response Plan

In case of emergencies (fire/leakage/failure/other offshore exigencies), the Shift Field/Plant Operator shall immediately inform Shift Console Operator and the Control Room. The shift Console Operator shall inform Well Head Team Leader/ Shift-in-Charge, Shift Maintenance Engineer and Fire Station and act on the basis information received from Shift Operator. The Well Head Team Leader/Resident Engineer acts as On-Scene Coordinator till the Head Operation reach the site.

If the emergencies requires shut down the platform/plant and activate Disaster Management Plan (DMP)/Oil Spill Contingency Plan (OSCP). The Shift-in-Charge (Odalarevu) provides all necessary information regarding safe shutdown of platform/platform and ensure the availability of vessel/helicopter/fire fighting vessel/fire tender/ambulance depending on the situation. Shift in Charge follow duties as per fire order and other requirements under the direction of On Scene Coordinator. Shift Security officer inform central first aid facility and control traffic. OSC shall coordinate with the Shift Security Supervisor and Resident Medical Officer and coordinate the aid within ONGC and from outside agencies as per requirements. Resident Medical officer ensure first aid facility and inform local doctors/hospitals to remain in readiness for attending to serious burns and gas poisoning case.

The On-Scene Coordinator/Commander (OSC) shall maintain communication with Asset Manager, which shall be the Chief Emergency Officer (CEC) and coordinates with I/C of Safety, Fire and Security. The CEC coordinate with On-Scene Coordinator (OSC) and other ECR (Emergency Control Room) members and inform the CMD, Director (HR)-CCEC, Director-Concerned and Director-I/C HSE on the situation. If requires, CEC activate off-site DMP and shall request the intervention of corporate crisis management group for activation of corporate level DMP. The CEC give technical and management advice to other coordinators and take the decision on partial or total evacuation of the site. The actions to be taken during emergency are given in Figure 3.



Figure 3: Actions to be taken During Emergencies

4.2.1 On Scene Coordinator

Initial Phase: In the initial phase someone close to the scene of emergency can exercise emergency coordination. Accordingly Well head team leader/Resident Engineer will assume the role of on scene Coordinator (OSC) till On Scene Commander takes over.

Intermediate Phase: The Chief Emergency Co-ordinator (CEC) at Asset level may appoint a person, normally stationed at base to take over the task of OSC at Site Control Room (SCR).

Fire/Leakage/Failure/Other Offshore Exigencies

Shift Field Operator/Person Noticing First

Shift-In-Charge/Well Head Team Leader

Resident Engineer

Head Operations/On-Scene Coordinator

Chief Emergency Coordinator-Asset Manager

I/C Safety

Shift Maintenance Engineer

I/C Maintenance

I/C Security

Muster In charge

Shift-In-Charge (Fire)

On Escalation – Offsite DMP will be activated by CEC-AM

ECR (Offsite)

ECR (Onsite)

Medical Officer

Shift-In-Charge (Security)

Actuate Platform Shutdown, if

require



Function: The OSC will make an assessment of the situation; the type and quantity of assistance required and communicate the same to the Asset ECR. The OSC will mobilize the resources available at scene, deal with the situation and take such actions as directed by the Chief Emergency Coordinator at the Asset/ Basin/ Plant. He will transmit situation reports (SITREPS) at regular interval prefixing a numerical sequence to each message.

4.2.2 On-Site Control Room

This temporary centre shall be established at a suitable location at the affected site/ nearby rig or a vessel stationed nearby or in any building at the base by the Head operations, with the assistance and advice from the Emergency Control Room. Head operations will be the on-scene coordinator. Other Coordinators at the location will be the Fire Fighting, Safety, Security and Maintenance Coordinators who will assist the On Scene Coordinator in discharging his duties at the site of emergency.

4.2.3 Communication

As effective communication is crucial for the overall success of the operation, a communication flow-chart for such scenario is outlined herewith. In the event of a terrorist act, timely, accurate communications will be critical for the success and survival. Timely response during emergency is extremely important. Flow chart for first information regarding an emergency is given in the Figure 4 and 5.

Figure 4: Communication Flow Chart (First Information)



Figure 5: Offshore communication flow chart

CEC at the work center must communicate immediately as per the flow chart for first information in case any emergency is likely to come to the notice of media. This is to ensure that the management has an authentic update of the emergency to reply to the media.

4.2.4 Communicating With Employees

The following shall be followed for internal communications Head Corporate Communication shall on behalf of CCEC communicate with ONGC employees through intranet or any other communication channel to apprise all ONGC employees on the status of the incident. Chief ER on behalf of CCEC shall establish communication with the family members of the affected employees and contractors.

4.2.5 Communicating With Media

The following shall be followed while communicating with the media



CMD, CCEC or Head CC on their behalf shall interact with print/ electronic media. Head CC with the approval of CCEC shall brief the press/ give press release.

No other official at corporate office will interact with Media/ Press unless approved by CMD/ CCEC.

The main purpose of Crisis communication with the media will be o Positive messages with a focus on action taking place o Clarity in all messages delivered o Consistency in all messages repeated o Bias-free messages o Correct any misinformation

4.2.6 Warning System

A high pitch warning system is available at the site (Drilling Platform/Terminal) (repeated at base camp emergency center) for announcing the emergency and giving the all clear signals. SMC will declare the emergency level and operational personnel and, if necessary, public in surrounding villages will be notified about the nature of the emergency by using alarm system in the following manner:

Level 1 Emergency – Single beep every five seconds Level 2 Emergency – Double beep every five seconds Level 3 Emergency – Continuous wailing of alarm

4.2.7 Emergency Procedures

Level 1 Emergencies

Accident is small and isolated and does not require the shutdown of any project operation (installation/unit of the Drilling Operation or the onshore terminal or evacuation of production fluids). Effort shall be made to arrest its propagation. Level 1 fire may be extinguished with water, sand or fire extinguishers. Level 1 hazardous chemical release, if any, can be contained and controlled quickly without requiring shut down of any installation/unit or the evacuation of persons working in the affected area.

Level 2 Emergencies

The affected unit will be brought to a safe shut down while continuing emergency supplies of water and power. Level 2 fires will be extinguished by mobilizing water and foam extinguishers. Level 2 hazardous chemical release, if any, will require evacuation of personnel including those working in downwind direction towards upwind or cross wind direction to minimize the injurious effect of hazardous gas release.

Level 3 Emergencies

Level 3 emergencies are not applicable to exploratory drilling (except near or at the coast) operational area, onshore processing terminal and off-shore and onshore pipeline.

4.2.8 Accident Site Clean Up

While cleaning the site after explosion and fire accidents, care shall be taken against the probability of leaving any hazardous / or any other materials (which may be dangerous to terrestrial and marine life or obstacle to terrestrial and marine operation) lying buried in the



land and sea-bed. Information regarding the cleaning up of spills of hazardous materials, if used, is available in material safety data sheets.

4.2.9 Emergency Response Personnel Safety

All emergency response personnel from the ONGC and outside agencies shall enter the accident site under instruction of SIC. These persons shall invariably wear appropriate protective gear, such as, fire suits, helmets, boots, respirators and gas masks, before entering the accident site.

4.2.10 All Clear Signal and Public Statement

For Level 1 and 2 emergencies Site Main Controller will authorize an all clear signal in the form of long high pitched alarm with intermittent pauses, say, two minutes alarm followed by one minute pause repeatedly. Public statements regarding the emergency will be issued only by SMC.

EIA report for Drilling and completion of wells at Vashishta and re-entry and completion of wells at S-1 Fields , KG Offshore, Andhra Pradesh


4.3 ONGC CONTINGENCY PLAN FOR OFFSHORE BLOWOUT (DRILLING RIG)

Figure 6: Organizational Set up / Contingency Plan for DMP

SECONDARY RESPONSE ASSESSMENT OF SITUATION AT LOCATION

MEETING ON MSV OR

PROCESS PLATFORM

NOMINATE ASSET /

BASIN COORDINATOR

WORK OUT

CONTROL STRATEGY

ESTABLISH

INFRASTRUCTURE

MOBILISE RESOURCES AS

PER

CONTROL STRATEGY

EXECUTE CONTROL PLAN

CMT HEAD

MEDIA MANAGEMENT (CORPORATE

COMMUNICATIONS)

LIAISON WITH GOVT. AGENCIES

LIAISON WITH STATUTORY BODIES

INSURANCE & LEGAL

- COMMUNICATION

- FIRST-AID CENTRE -

ONSITE CAMP -

OFFSITE OFFICE

BLOWOUT CONTROL & FIRE

FIGHTING EQUIPMENT

POLLUTION CONTROL EQUIPMENT

PROFESSIONAL EXPERTS

RELIEF WELL / SNUBBING ETC.

ENGINEERING

RELIEF WELL

TEAM

SURFACE

INTERVENTION

TEAM

INCIDENT REPORTED BY LOCATION R.O

A

L

E

R

T

NEARBY RIGS

NEARBY PLATFORMS

OSVs

STANDBY MSVs

FIRE FIGHTING VESSELS

FIELD HELICOPTER

R/O HELIBASE

BASE RADIO ROOM

CONCERNED AM/BM

OTHER AMs & BMs

HEAD DRILLING SERVICES

RIG INCHARGE

AREA INCHARGE

LM OR BM

DRILLING CONTROL ROOM

OERATIONS CONTROL ROOM

HEAD WELL SERVICES

HEAD HR-ER

HEAD RCMT

HEAD FIRE SERVICES

HEAD SECURITY

HEAD HSE

HEAD OFFSHORE LOGISTICS

I/C HELIBASE

I/C VIZAG

HEAD INFOCOM

HEAD MEDICAL SERVICES

HD. CORP. COMMUNICATIONS

HEAD FINANCE

HEAD MM

EASTERN NAVAL COMMAND

COAST GUARD

ODAG

AIR FORCE

DGCA

NAVY

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