risk assessment for development wells, ggs,...

Risk Assessment for Development

Wells, GGS, Pipeline and

GPP in the Block AAP-ON-94/1,

Tinsukia District, Assam

Final Report

Dirok Field Development Phase-I & II

Prepared for:

Hindustan Oil Exploration Company Limited

Prepared by:

SENES Consultants India Pvt. Ltd.

Accreditation No. – NABET/EIA/1013/43

October, 2015

RA for Dirok Development Field

SENES 2 HOEC

Risk Assessment

1.1 QUANTITATIVE RISK ASSESSMENT

This section on Quantitative Risk Assessment (QRA) aims to provide a systematic analysis of the major

risks that may arise as a result of HOEC’s Gas Production Program comprising of drilling of 3 development

wells, installation of 1 Gas Gathering Station (GGS), Gas Processing Plant (GPP), laying of gas pipelines for

evacuation of natural gas from GGS to GPP

The QRA process outlines rational evaluations of the identified risks based on their significance and

provides the outline for appropriate preventive and risk mitigation measures. Results of the QRA provides

valuable inputs into the overall project planning and the decision making process for effectively

addressing the identified risks. This will ensure that the project risks stay below As Low As Reasonably

Practicable (ALARP) levels at all times during project implementation. In addition, the QRA will also help

in assessing risks arising from potential emergency situations like a blow out, jet fires and develop a

structured Emergency Response Plan (ERP) to restrict damage to personnel, infrastructure and the

environment.

The risk study for the onshore production activities has considered all aspects of operation of the drilling

rig and other associated activities during the production phase. Pipeline rupture and leaks constitute the

major potential hazards that may be associated with the proposed onshore production activities in AAP-

ON-94/1 block.

The following section describes objectives, methodology of the risk assessment study and then presents

the assessment for each of the potential risk separately. This includes identification of major hazards,

hazard screening and ranking, frequency and consequence analysis for major hazards. The hazards have

subsequently been quantitatively evaluated through a criteria based risk evaluation matrix. Risk

mitigation measures to reduce significant risks to acceptable levels have also been recommended as a

part of the risk assessment study.

1.1.1 Objective of the QRA Study

The overall objective of this QRA with respect to the proposed project involves

identification and evaluation of major risks, prioritizing risks identified based on their

hazard consequences and formulating suitable risk reduction/mitigation measures in line

with the ALARP principle. Hence in order to ensure effective management of any

emergency situations (with potential individual and societal risks) that may arise during

the development drilling activities, following specific objectives need to be achieved.


SENES 3 HOEC

Identify potential risk scenarios that may arise from the proposed development activities

particularly during transportation of natural gas and development drilling.

Analyze the possible likelihood and frequency of such risk scenarios by reviewing

historical accident related data for the onshore oil and gas industries.

Predict the consequences of such potential risk scenario’s and if consequences are high,

establish the same by through application of quantitative simulations.

Recommend feasible preventive and risk mitigation measures as well as provide inputs for

drawing up of Disaster Management Plan (DMP)/Emergency Response Plan (ERP) for the

project.

1.1.2 Risk Assessment Methodology

An overview of the methodology employed is provided here to briefly introduce the study

approach.

A site reconnaissance visit was conducted to identify all hazards, both generic and site specific.

Reviews of literature and accident databases were also undertaken. These formed the basis for

identifying all hazardous scenarios for the QRA Study. The frequencies, or the likelihood, of the

various possible outcomes resulting from natural gas release scenario were derived from historical

accident databases and, where necessary, these were modified to take into account local factors.

For all identified hazards assessed the consequences of each release were modeled using ALOHA

consequence modeling software.

Hazard Identification

Hazards associated with the proposed project have been identified based on site reconnaissance

visit, understanding of existing operations and detailed review of known incident records

worldwide and experience gained from operations at similar facilities.

In addition, based on the discussion with HOEC representative it is understood that natural gas

will be handled both at the well site and pipeline transportation. As the gas disperses, it mixes with

the surrounding air and warms up. The vapour cloud will only ignite if it encounters an ignition

source while concentrated within its flammability range.

Hazard Effects

In the event of an accidental natural gas release (in gaseous phase) from piping or equipment or

during blow outs, the characteristics of the possible hazardous effects are described below.


SENES 4 HOEC

Jet Fire

Jet fires result from ignited releases of pressurized flammable gas or superheated/pressurized

liquid. The momentum of the release carries the materials forward in a long plume entraining air

to give a flammable mixture. Jet fires only occur where the natural gas is being handled under

pressure or when handled in gas phase and the release are unobstructed. This is considered to be

the most credible risk scenario for the proposed project given the pipeline will be operated at a

design pressure of ~50 kg/cm2.

Flash Fire

Following natural gas release under high pressures, a cloud of methane may be formed, initially

located around the release point. If this cloud is not ignited immediately, it will move with the

wind and be diluted as a result of air entrainment. The dispersing vapour cloud may subsequently

come in contact with an ignition source and burn rapidly with a sudden flash. If the source of

material which created the cloud is still present, then the fire will flash back to the source giving a

jet fire. Direct contact with the burning vapours may cause fatalities but the short duration of the

flash fire generally means that thermal radiation effects are not significant outside the cloud and

thus no fatalities are expected outside of the flash fire envelope.

Fireball

Immediate ignition of releases caused by a rupture in a gas piping may give rise to a fireball upon

ignition. Fireballs have very high thermal radiation, similar to jet fires although the duration of the

event is short.

Vapour Cloud Explosion

A flash fire is the most likely outcome upon ignition of a dispersing vapour cloud from a natural

gas release. If the gas is ignited in areas where there is significant degree of confinement and

congestion an explosion may result. However if the ignition happens in open (unconfined) areas

as in this case, pure methane is not known to generate damaging overpressures (explode).

To summarize a gas phase release can result in a flash fire, fireball or jet fire. A liquid phase release

is generally associated with flash fire, vapour cloud explosion, pool fire or jet fire.

Scenarios for QRA study

Scenarios for the QRA study were identified based on the hazard identified in the aforesaid section

based on the site visit undertaken and review of incident records. Loss of containment events have

been identified for each section of the pipeline, corresponding to the relevant process conditions,

as listed in Table 6.1.


SENES 5 HOEC

TABLE 0-1: SCENARIOS FOR QRA STUDY

Sl.

No Plant Section

Initiating

Event Risk Scenario

Potential Outcome

Scenario

1 Pipeline Rupture 8” & 12” pipeline

rupture Jet fire, flash fire

Frequency Analysis

1.1.3 Pipeline Failure Frequency Analysis

An effort has also been made to understand the primary failure frequencies of gas pipeline which

is the result of the number of incidents within a period divided by the corresponding total system

exposure. Based on the European Gas Pipeline Incident Data Group (EGIG) database the evolution

of the primary failure frequencies over the entire period and for the last five years has been

provided in Table 6.2 below.

TABLE 0-2: PRIMARY GAS PIPELINE FAILURE FREQUENCY

Period No. of Incidents Total System

Exposure (km.yr)

Primary failure

frequency

(1000 km.yr)

1970-2007 1173 3.15.106 0.372

1970-2010 1249 3.55.106 0.351

1971-2010 1222 3.52.106 0.347

1981-2010 860 3.01.106 0.286

1991-2010 460 2.25.106 0.204

2001-2010 207 1.24.106 0.167

2006-2010 106 0.654.106 0.162

Source: 8h EGIG Report

As referred in the above table the overall failure frequency (0.35) of the entire period (1970-2010)

is slightly lower than the failure frequency of 0.37 reported in the 7th EGIG report (1970-2007).

The failure frequency of the last 5 years was found to be half the primary failure frequency over

the entire period showing the improved performance over the recent years.

Incident Causes

Natural gas pipeline failure incidents can be attributed to the following major causes viz. external

interference, construction defects, corrosion (internal & external), ground movement and hot tap.

The distribution of incidents with cause has been presented in the Figure 6.1 below.


SENES 6 HOEC

FIGURE 0-1: NATURAL GAS PIPELINE FAILURE – DISTRIBUTION OF INCIDENT & CAUSES

Source: 8th EGIG Report

The interpretation of the aforesaid figure indicated external interference as the major cause of

pipeline failure contributing to about 48.4% of the total failure incidents followed by construction

defects (16.7%) and corrosion related problems (16.1%). Ground movement resulting from

seismic disturbance, landslides, flood etc contributed to only 7.4% of pipeline failure incident

causes.

The pipeline failure frequency viz. leaks or rupture from natural gas transportation pipeline with

respect to the proposed project has been established based on the interpretation of the database of

European Gas Pipeline Incident Data Group (EGIG) representing almost 2 million kilometer year

of pipeline operations. The failure rate reported by EGIG for on-shore gas pipeline with design

pressure greater than 15 bar is 4.76 x 10-4 km/year. Full Bore Rupture (FBR) represents 13% of

the cases (6.188 x 10-5 failure /km/yr) and 87% of the cases represents Leaks (4.14 x 10-4 failure

/km/yr).

The frequency of pipeline failure computed for the proposed project based on EGIG failure

frequency is presented in the Table 6.3 below.

TABLE 0-3: NATURAL GAS PIPELINE FAILURE FREQUENCY

Sl. No Pipeline Failure Case

EGIG Failure

Frequency

(per km.year)

Total

Pipeline

Length (km)

Project Pipeline

Failure Frequency

(per year)

1 Gas Pipeline Rupture 6.188 x 10-5 25 1.54 x 10-3

2 Gas Pipeline Leak 4.14 x 10-4 25 1.03 x 10-2


SENES 7 HOEC

Pipeline Failure – Ignition Probability

In the period 1970-2010, only 4.4% of the gas releases recorded as incidents in the EGIG database

ignited. Ignition depends on the existence of random ignition sources. The EGIG database gives

the opportunity to evaluate the link between ignition and leak size.

The ignition probability of pipeline failure (rupture & leaks) with respect to the proposed project

is derived based on the following equations as provided in the IGEM/TD/2 standard

P ign = 0.0555 + 0.0137pd2; for 0≤pd2≤57

(Ignition Probability for pipeline ruptures)

P ign = 0.81; for pd2>57

P ign = 0.0555 + 0.0137(0.5pd2);

for 0≤0.5pd2≤57

(Ignition Probability for pipeline leaks)

P ign = 0.81; for 0.5pd2>57

Where:

P ign = Probability of ignition

p = Pipeline operating pressure (bar)

d = Pipeline diameter (m)

The ignition probability of natural gas release from 8” & 12” pipeline leak or rupture is calculated

based on the above equations utilizing the following input parameters as discussed below.


SENES 8 HOEC

Based on the aforesaid calculation the probability of jet fire occurring from accidental gas release

from pipeline leak or rupture and subsequent ignition has been presented in Table 6.4 below:

TABLE 0-4: NATURAL GAS CONNECTIVITY - PROBABILITY OF JET FIRE

Sl.

No Pipeline Failure Case

Project Pipeline Failure

Frequency (per year)

Ignition

Probability

Jet fire

Probability

1 8” Gas Pipeline Rupture 6.683 x 10-4 0.08 5.34 x 10-5

2 8” Gas Pipeline Leak 4.471 x 10-3 0.06 2.68 x 10-4

3 12” Gas Pipeline Rupture 6.683 x 10-4 0.11 7.35 x 10-5

4 12” Gas Pipeline Leak 4.471 x 10-3 0.08 3.57 x 10-4

1.1.4 Process Leak – Frequency Analysis

The frequency of process leaks can be estimated directly from analysis of historical data obtained

from E & P Forum hydrocarbon leak database (E&P forum 1992), World Offshore Accident

Pipeline Inlet Pressure (bar) = p= 50 kg/cm2 or 49 bar

Pipeline diameter = d = 12 inches or 0.304 m

Pipeline diameter = d = 8 inches or 0.203 m

For 8” pipeline rupture pd2 = (49) X (0.203)2 = 2.019

For 8” pipeline leak 0.5 pd2 = 0.5 X (49) X (0. 203)2 = 1.009

For 12” pipeline rupture pd2 = (49) X (0. 304)2 = 4.528

For 12” pipeline leak 0.5 pd2 = 0.5 X (49) X (0. 304)2 = 2.264

Since 0≤pd2≤57 and 0≤0.5pd2≤57, the following equation has been utilized for deriving

the ignition probability for pipeline failure.

P ign for 8’ pipeline rupture = 0.0555 + 0.0137pd2 = 0.0555 + 0.0137 (2.019) = 0.083

P ign for 8” pipeline leak = 0.0555 + 0.0137(0.5pd2) = 0.0555 + 0.0137 (1.009) = 0.069

P ign for 12’ pipeline rupture = 0.0555 + 0.0137pd2 = 0.0555 + 0.0137 (4.528) = 0.117

P ign for 12” pipeline leak = 0.0555 + 0.0137(0.5pd2) = 0.0555 + 0.0137 (2.264) = 0.086


SENES 9 HOEC

Database (WOAD) and OREDA. Although onshore data is available for process leaks, the

information is not considered representative of the actual scenario. Under such circumstances

historical data available on hydrocarbon leaks in the OGP authenticated offshore accident

databases have been considered for purpose of process leak frequency analysis. Failure frequencies

of process equipment as in this case where leaks have been considered from valves and flanges of

the GCS facility has been presented in Table 6.5 below.

TABLE 0-5: LEAK FREQUENCIES FROM PROCESS EQUIPMENT

Equipment Type Frequency

(per equipment item year)

Flanges 8.8 X 10-5

Valves 2.3 X 10-4

Source: HSE Hydrocarbon Release Database

1.1.5 Blow Out – Frequency Analysis

Blow out frequency estimates is obtained from a combination of incident experience and associated

exposure in a given area over a given period. For the purpose of calculation of blow out frequency analysis

in context of the present study involving development operations, blow out frequencies per well drilled

have been considered. As comparable data for onshore operations was not available database for offshore

operations of North Sea Standard1 has been referred which has recorded a blowout frequency of 1.8 X 10-

5 per well per year.

Based on the given frequency and information provided by HOEC for the proposed project the blow out

frequency is calculated as follows:

No of development wells to be drilled = 3 (A)

Blow out frequency for development well drilling = 1.8 X 10-5 per well drilled (B)

Frequency of blow out occurrence for the proposed project = (A X B) = 3 X 1.8 X 10-5

= 5.4 X 10-5 per well drilled

Thus, the blow out frequency for the proposed project is calculated at 5.4 X 10-5 per well drilled i.e. the

likelihood of its occurrence is “Not Likely”

Blow Out – Ignition Probability

Review of SINTEF database indicates that a rounded ignition probability of 0.3 has been widely used for

the purpose of quantitative risk analysis arising from blow outs. As per this database generally ignition

occurred within first 5 minutes in approximately 40% of the blowouts leading to either pool and/or jet

1 http://www.ogp.org.uk/pubs/434-02.pdf

http://www.ogp.org.uk/pubs/434-02.pdf


SENES 10 HOEC

fire. Blow out leading to flammable gas release has a greater probability of ignition compared to liquid

releases2

An alternative to the blowout ignition probabilities given by the UKOOA look-up correlations can be

obtained from Scandpowers’s interpretation of the blowout data provided by SINTEF 2. The most

significant category is that for deep blowouts which indicates an early ignition probability of 0.09. For the

purpose of the QRA study this can be taken as occurring immediately on release and calculation provided

below:

No of development wells to be drilled = 3 (A)

Blow out frequency for development drilling = 1.8 X 10-5 per well drilled (B)

Blow out ignition probability = 0.09 (C)

Probability of Blow out ignition for the proposed project = (A X B X C) = 3 X 1.8 X 10-5 X 0.09

= 4.8 X 10-6

Hence based on the aforesaid calculation the probability of ignition of blow out releases of hydrocarbons

for the proposed project will be 4.8X10-6 and has been considered to be as negligible.

1.1.6 Consequence Analysis

Pipeline generally contains large inventories of oil or gas under high pressure; although accidental

releases from them are remote they have the potential of catastrophic or major consequences if

related risks are not adequately analyzed or controlled. The consequences of possible pipeline

failure is generally predicted based on the hypothetical failure scenario considered and defining

parameters such as meteorological conditions (stability class), leak hole & rupture size and

orientation, pipeline pressure & temperature, physicochemical properties of chemicals released

etc.

As discussed earlier, jet fire have been identified as the possible consequences resulting from

release and is dependent on the ignition time. Taking into account the gas gathering and processing

facilities and pipeline the hypothetical risk scenarios as provided in Table 6.1 have been

considered for failure consequence modeling with respect to proposed project. In addition to the

above the following design specifications as presented in Table 6.6 have been considered for

consequence modeling

TABLE 0-6: PIPELINE DESIGN SPECIFICATIONS

Sl.

No. Parameters Values

1 Pipeline diameter (inch) 8 inch and 12 inch

2 Pipeline length (km) 16km & 9km

2 Fire and Explosion – Fire Risk Analysis by Daejun Change, Division of Ocean System and Engineering


SENES 11 HOEC

Sl.

No. Parameters Values

4 Design pressure (bar)* 49

5 Design temperature (in °C) 50

In the present study, we have estimated the consequence of each reference scenarios (as mentioned

in Table 6.1) in terms of fatality only. For each effect type (i.e. radiation, overpressure and toxic

release), a set of threshold values were considered having 1, 5, 10, 20 and 50% fatality (Table

6.7). These threshold values were derived from Probit functions using the following equations:

Thermal Radiation [1]: Pr = -14.9 + 2.56 x In (Q4/3 x t) ........................................ Eq.

Overpressure [2]: Pr = 1.47 + 1.37 ln (p) ..................................................... Eq.

Toxic release [3]: Pr = a +b x In (Cn x t) ....................................................... Eq.

where,

Pr = Probit

Q = heat radiation (W/m2)

t = exposure time (s)

p = peak overpressure (psig)

a, b, n = constants describing the toxicity of a substance

C = concentration (mg/m3)

t = exposure time (minutes)

TABLE 0-7: THRESHOLD VALUES FOR EACH EFFECT LEVEL

Fatality (%) Radiation (kW/m2) Overpressure (psi)

50 26.50 13.10

20 20.78 7.15

10 18.25 5.20

5 16.42 3.95

1 13.42 2.40

[N. B. The values were derived using the above mentioned Probit equations]

Based on these threshold values, effect distances were calculated to delineate different threat-zones

for each reference scenario. The analysis made use of the ALOHA model, one of the most

commonly used effect models to generate the consequence effects showing the estimated distances

for each scenario considered to a specified hazard end-point. These zones are displayed on a single

Threat Zone plot displayed as red, orange and yellow with red representing the worst hazard. The

threat zone displayed by ALOHA represent thermal radiation levels and also indicates the effects


SENES 12 HOEC

on people who are exposed to those thermal radiation levels but are able to seek shelter within one

minute.

Predominant local meteorological conditions and composition of the natural gas as provided

during discussions with HOEC personnel was also considered for this study. Nearly about 88-90%

of the natural gas is constituted by methane with ethane representing the remaining 2%.

Case I: Release of natural gas from valves/flanges of GGS – hole size (1”dia)

The jet fire threat zone plot for release and ignition of flammable natural gas from GGS facility

valves/flanges leak of size - diameter 1 inch is represented in Figure 6.2 below.

FIGURE 0-2: THREAT ZONE PLOT FOR JET FIRE – 1” DIA LEAK

THREAT ZONE:

Threat Modeled: Thermal radiation from jet fire

Orange: 11 meters --- (10.0 kW/ (sq m) = potentially lethal within 60 sec

Yellow: 16 meters --- (5.0 kW/ (sq m) = 2nd degree burns within 60 sec


SENES 13 HOEC

Taking into consideration established probit values that are linked to fatality caused by thermal

radiation from fire, no endpoint distances have been computed below thermal radiation of 13.42

kW/sq.m.

Case II: Ignition of natural gas from complete rupture of 8” pipeline

The complete rupture of 8” pipeline will result in the release of natural gas (in gaseous phase) the

ignition of which is likely to result in jet fire. The threat zone plot of jet fire resulting from pipeline

rupture is derived using ALOHA and represented in Figure 6.3.

FIGURE 0-3: THREAT ZONE PLOT FOR JET FIRE - 8” PIPELINE RUPTURE

THREAT ZONE

Threat Modeled: Thermal radiation from jet fire resulting from full bore rupture

Red : 19 meters --- (26.50 kW/ (sq m) = 50% fatality

Orange: 25 meters --- (18.25 kW/ (sq m) = 10% fatality

Yellow: 30 meters --- (13.42 kW/ (sq m) = 1% fatality


SENES 14 HOEC

The worst hazard for release and ignition of natural gas from complete rupture of 8” dia pipeline

will be experienced to a maximum radial distance of 19m from the source with 50% fatality.


SENES 15 HOEC

Case III: Ignition of natural gas from complete rupture of 12” pipeline

The complete rupture of 12” pipeline will result in the release of natural gas (in gaseous phase) the

ignition of which is likely to result in jet fire. The threat zone plot of jet fire resulting from pipeline

rupture is derived using ALOHA and represented in Figure 6.4.

FIGURE 0-4: THREAT ZONE PLOT FOR JET FIRE - 12” PIPELINE RUPTURE

THREAT ZONE

Threat Modeled: Thermal radiation from jet fire resulting from full bore rupture

Red : 29 meters --- (26.50 kW/ (sq m) = 50% fatality

Orange: 38 meters --- (16.42 kW/ (sq m) = 10% fatality

Yellow: 46 meters --- (13.42 kW/ (sq m) = 1% fatality

The worst hazard for release and ignition of natural gas from complete rupture of 12” dia pipeline

will be experienced to a maximum radial distance of 29m from the source with 50% fatality.


SENES 16 HOEC

For various hypothetical scenarios considered with respect to proposed production project, the

threat zones calculated using ALOHA for defined thermal radiation intensities have been presented

in the Table 6.8 below.

TABLE 0-8: THREAT ZONE DISTANCE FOR HYPOTHETICAL RISK SCENARIOS

Case

No Pipeline Failure Case

Hole Size

(inch)

Distance to

26.50 kW/m2

(m) – 50%

fatality

Distance to

16.42 kW/m2

(m) – 10%

fatality

Distance to

13.42 kW/m2

(m) – 1%

fatality

I Valves/flanges leak 1.00 <10 <10 <10

II 8” pipeline rupture 8.00 19 25 30

III 12” pipeline rupture 12.00 29 38 46

Modeling Risk of Overpressure from Vapour Cloud Explosion

A flash fire is the most likely outcome upon ignition of a dispersing vapour cloud from a natural

gas release. If ignited in open (unconfined) areas, pure methane is not known to generate damaging

overpressures (explode). However, if the gas is ignited in areas where there is significant degree

of confinement and congestion an explosion may result.

Although an unconfined explosion is considered to be unlikely for the proposed project an effort

has been made to establish the overpressure (blast force zone) that may result from delayed ignition

of vapour cloud generated from any such accidental release from ruptures. For overpressure risk

modeling using ALOHA a delayed ignition time of 15 minutes was considered of the vapour cloud

mass. However the threat modeled revealed that Level of Concern (LOC) was never exceeded that

may possibly lead to loss of life within the blast radius. This is in agreement with the earlier

assessment that no damaging overpressure is likely to be generated from unconfined ignition of

natural gas vapour cloud. The results have been provided in Figure 6.5 below

FIGURE 0-5: VCE MODELING RESULTS FOR OVERPRESSURE

Blowout Consequence Analysis

Blow out from a hydrocarbon well may lead to the following possible risk consequences:

Pool fires and smoke plumes resulting from ignited oil blow outs


SENES 17 HOEC

Jet fires resulting from ignited gas blow outs

Oil slicks resulting from un-ignited oil pools.

However for the proposed project involving development drilling of gas wells for natural gas releases

leading to jet fire, modeling has been based considering methane which has been identified as the

principal constituent of natural gas.

Ignition of Flammable Gas Release leading to Jet Fire

Jet fires are burning jet of gas or sprays of atomized liquids resulting from gas and condensate release

from high pressure equipment and blow outs. Jet fires may also result in the release of high pressure liquid

containing dissolved gas due to gas flashing off and turning the liquid into a spray of small droplets. In

context of the present study, formation of jet fires can be attributed by the high pressure release and

ignition of natural gas if encountered during development of block hydrocarbon reserves.

Natural gas as recovered from underground deposits primarily contains methane (CH4) as a flammable

component, but it also contains heavier gaseous hydrocarbons such as ethane (C2H6), propane (C3H8) and

butane (C4H10). Other gases such as CO2, nitrogen and hydrogen sulfide (H2S) are also often present.

Methane is typically 70-90 percent, ethane 5-15 percent, propane and butane, up to 5 percent. Thus,

considering higher percentage of methane in natural gas, the thermo-chemical properties of the same has

been utilized in the jet fire blow out consequence modeling. The following risk scenario (Table 6.9) has

been considered for nature gas release consequence modeling:

TABLE 0-9: NATURAL GAS RELEASE MODELING SCENARIOS

Scenario Release Rate (kg/s) Release Type

Worst Case 10 Large

For the worst case scenario (10 kg/s release of natural gas) an effort was made to establish the

overpressure (blast force zone) that may result from delayed ignition of vapour cloud generated from any

such accidental release. For overpressure risk modeling using ALOHA a delayed ignition time of 5 minutes

was considered of the vapour cloud mass. However the threat modeled revealed that Level of Concern

(LOC) was never exceeded that may possibly lead to damage to property or life within the blast radius.

The results have been provided in Figure 6.6 below

FIGURE 0-6: WORST CASE – OVERPRESSURE RISK MODELING RESULTS FOR BLOWOUT


SENES 18 HOEC

Pre Control Measure of Gas Release

1. Rig Safety Engineer, Rig Manager & Drilling Supervisor to create the awareness about the gas

leakage procedure to the crew 2. All the employees to wear appropriate Personal Protective equipments 3. Avoid creating any source of ignition surrounding the rig site 4. Restricted Hot work & Kitchen activities

5. Restricted Vehicle Movements 6. Minimize the Crew moment 7. Medic & HSE Engineer should be Maintain SCPA ready condition 8. Medic should be organize necessary emergency facilities at First Aid Room as well as Ambulance

van

9. Fire Team to be Maintain the Fire Engine, Fire Extinguishers & Water to be control the fire during

the emergency. 10. Before testing inspect the Gas Detectors readily working condition

11. Inspect the Wind sock & it’s Properly fixed necessary place 12. Inspect the HSD Storage area any leakage in surrounding area & reduce the stock 13. Flammable material (LPG, HSD...etc) & Chemicals should not be stored

14. Inspect the rig site & Stop all hot work and shutdown all other sources of ignition 15. Incase any Emergency Raise the Alarm 16. Inform Drilling Supervisor of incident

17. Request assistance from emergency services 18. Shut down and isolate electrical supply & Flow lines to affected area if safe to do so 19. Evacuate any personnel at risk to the Muster Point or to a safe distance upwind from the incident

area and wait until advised otherwise

20. Confirm all personnel are accounted for via Muster Point head count 21. As time permits, maintain log of events for collection at end of incident

1.1.7 Individual Risk

Individual risk is the probability at which an individual may be expected to sustain a given level

of harm from the realization of specified hazards. In simple terms it is a measure to assess the

overall risk of the area concerned thus to protect each individual against hazards involving

hazardous chemicals, irrespective of the size of the accident that may occur. Graphically it

represents as iso-risk contour which connects all of the geographical locations around a hazardous

activity with the same probability of fatality.

In order to generate different level of iso-risk curves for the area concerned, it is required to

estimate the respective contribution of each reference scenario. Accordingly, individual risk of

each scenario was estimated by combining the frequency of the initiating event, the conditional

probability of that scenario sequence and the Probit value of the effect footprints. In particular

following expression was used to estimate the Individual Risk (IR) at a given geographical location

for each reference scenario:

IR(x, y, i) = fi. PFi ………………………………………………………………………………………………… (Eq. iv)


SENES 19 HOEC

where:

- fi is the frequency of the accident scenario i (year-1); calculated as multiplicative factor of the

frequency of the initiating event and the probability that the sequence of events leading to the

accident scenario i will occur: fi = fincident i . Psequence i

- PFi is the probability of fatality that the accident scenario i will result at location (i.e. Probit).

The individual risk so obtained is then compared with the Tolerance Criteria of Individual Risk as

provided in the Figure 6.7 below.

FIGURE 0-7: TOLERANCE CRITERIA FOR INDIVIDUAL RISKS

Hence for the proposed project the individual risk has been considered only for pipeline rupture as

no predicted fatality has been established for the consequence modeling undertaken for natural gas

release ignition from blow outs and/or valves/flanges of the GGS facility. Based on the above

equation the individual risk as calculated including the tolerance criteria has been presented in the

Table 6.10 below.


SENES 20 HOEC

TABLE 0-10: INDIVIDUAL RISK – PIPELINE RUPTURE

Accident Scenario

Frequency Fatality Probability Individual Risk

Individual Risk

Criterion

A. 8 inch Pipeline Rupture

5.34 x 10-5 0.50 2 x 10-5 ALARP

5.34 x 10-5 0.10 5 x 10-6 Tolerable

5.34 x 10-5 0.01 5 x 10-7 Tolerable

B. 12 inch Pipeline Rupture

7.35 x 10-5 0.50 3 x 10-5 ALARP

7.35 x 10-5 0.10 7 x 10-6 Tolerable

7.35 x 10-5 0.01 7 x 10-7 Tolerable

The individual risk resulting from proposed project particularly from pipeline operations in most

cases is assessed to be within tolerable limits. The maximum off-site risk is computed to be 2 x

10-5 and 3 x 10-5 which falls in the ALARP region of the individual risk criterion. Hence in order

to control the potential risk/hazards the following additional mitigation measures need to be

adopted as specified in the section below.

1.1.8 Risk Mitigation Measures

Pipeline Safety Devices & Features

The natural gas distribution network to be equipped with an emergency shutdown system

to close down all gas delivery system and to de-energize the electrical facilities located in

the vicinity of gas headers in case of leaks.

Over pressure shut off valves shall be provided upstream and downstream of controlling

regulators along with alarm provision in case of failure of the regulator.

Any equipment or section of the pipeline containing flammable gas in the form of trapped

volume shall be protected against excessive pressure developed due to rise in surrounding

temperature by installing Thermal Relief Valves (TRVs).

Pressure safety valves or other devices of sufficient capacity and sensitivity will be

installed to ensure that the normal operating pressure of the system is not exceeded by more

than 10%.

Vent line shall be designed and installed to exhaust the gas from relief valves to atmosphere

in accordance with OISD-STD-106.


SENES 21 HOEC

The pipeline should be monitored and controlled from SCADA system to ensure effective

and reliable control, management and supervision of the pipeline. All remote SV stations,

IPS, dispatch & receiving stations will have suitable field signals’ connectivity with

SCADA.

Pipeline Corrosion Control

The natural gas pipeline network will be protected from external corrosion by a

combination of anticorrosion coatings and cathodic protection. The cathodic protection

(CP) system will be designed in accordance with NACE-RP-0169.

Temporary cathodic protection will be provided during construction phase by sacrificial

anodes.

Corrosion coupons & corrosion sensing probes will be provided as required for monitoring

internal and external corrosion.

Safety devices in line with NACE-RP-01-77 shall be installed for preventing the damage

to the CP system of pipeline due to lightning or fault currents when the pipeline is installed

near electric transmission tower footings, ground cables etc

Pipeline system will be installed so that the below grade or submerged portions are not in

electrical contact with any casing, foreign piping systems or other metallic structures. This

shall not preclude the use of electrical bonds where necessary.

All pipeline stations, all roads and railway crossing locations, caution signs will be

displayed indicating hazardous area, name of the operating company emergency telephone

contact nos. etc.

Pipeline Operation & Maintenance

A detailed operation and maintenance procedure for control system and safety interlocks

will be developed comprising of pipeline system description, normal operations & shut

down procedure, temporary operations, emergency shutdown details and emergency

operations.

Operating instructions, emergency shutdown (ESD), Trip set pressures need to be

displayed in the control room and near all important operating equipments.

A detailed periodic preventive maintenance procedure and schedule to be developed for

entire mainline system considering the recommendations given by the original equipment

manufacturer. In this regard the work permits system as specified in OISD-STD-105 will

be adhered.


SENES 22 HOEC

Pipelines will be inspected with Geometry pig for dent/ ovality and other geometrical

deformities at the time of construction.

Pipeline valve location access will be properly maintained. Road and highways crossings

will be inspected once in 3 months. Water course crossings shall be inspected twice in a

year i.e. prior and after monsoon or flash flood for sufficiency of cover, accumulation of

debris, or for any other condition affecting the safety and security of the pipeline crossings.

Inspection of pipes, valves and fittings will be carried out as per OISD-STD-130.

Periodic inspection and maintenance will be carried out for control and protective

equipment including pressure limiting devices, regulators, controllers, relief valves and

other safety devices in accordance with OEM and OISD standards (Pumps: OISD-STD-

119, Compressors: OISD-STD-120, Pressure Limiting Devices: OISD-STD-132)

Periodic monitoring will be undertaken for Cathodic Protection System and internal

corrosion.

Route markers need to be installed and frequent patrolling will be carried out along the

pipeline route. Special precautions in this regards will be taken near community settlements

and infrastructure (schools, health centers etc) identified within the potential threat zone

leading to ≥ 1% fatality.

Villagers / public along the right of way will be a made aware of the possible consequence

of pipeline leaks and this shall be included as a part of regular audit procedure.

Blow Out Preventive Measures

Mitigation measures for prevention of blow out incidents as outlined below is formulated

based on review of specific provisions of Oil Mines Regulation Act 1984

The following control equipment for the drilling mud system shall be installed and kept in

use during drilling operations:

A pit level indicator registering increase or reduction in the drilling mud volume and shall

include a visual and audio warning device near the driller’s stand.

A device to accurately measure the volume of mud required to keep the well filled at all

times;

A gas detector or explosimeter at the primary shale shaker and connected to audible or

visual alarm near the driller’s stand;

A device to ensure filling of well with mud when the string is being pulled out;

A control device near the driller’s stand to stop the mud pump when the well kicks,


SENES 23 HOEC

If the control equipment indicates that formation fluids are entering the well, immediate

steps shall be taken to control the well.

The manager of every mine in which blowout preventor (BOP) assembly is installed, shall

submit to the Regional Inspector standing orders specifying the action to be taken when a

well kicks and the duties of each person employed on the rig and such order persons as

may be necessary for blowout drills and actual emergencies.

Blowout prevention drill shall be conducted for this purpose once in seven days.

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

emergency to control the well.

1.1.9 Emergency Management

Objective

The primary objective of the Emergency Response Plan (ERP) is to provide a safe, timely, effective and

coordinated response by the onsite Emergency Response Team (ERT), along with the other local and

government agencies/departments to prevent or minimize any major emergencies that may arise from

possible failures of proposed development drilling project.

The main objectives of this plan are:

Minimize the risk for human life, environment and common property resources, by means

of an effective and efficient intervention;

Protection of the environment;

Protection of public safety;

Initiate the early and efficient response throughout the utilization of all available resources.

Purpose

The purpose of the ERP is to effectively manage and control the emergencies occurring during project

operations. This ERP ensures,

emergency response group is effective & adequate;

clear roles and responsibilities of key personnel & support groups;

availability and adequacy of emergency infrastructure & resources; and

efficient emergency communication


SENES 24 HOEC

1.1.10 Emergency Response - Organizational Structure

HOEC will constitute emergency response teams to respond to Environmental issues, fire, accidents and

technical emergencies. These teams will be made up from operations personnel, who can be called upon

24 hours a day, supported by senior management field personnel as and when required. The emergency

response teams will receive specific training for their roles and exercised on a regular basis.

The emergency response set-up is categorized into

Emergency Response Group (ERG) members

Emergency Management Team (EMT) members

The Emergency Response Group (ERG) is the field-based team, which activates the emergency response

immediately on realizing the emergency. The ERG is organized as:

Emergency Response Group (ERG) leader

Forward Controller (FC)

Incident Controller (IC)

Emergency Response Team (ERT) members

Rig HSE Engineer

Event logger (to be appointed by Rig Manager as per requirement)

The Drilling Supervisor shall be the Emergency Response Group (ERG) leader located at drilling Rig site.

The Drilling Rig Manager shall presume the role of ‘Forward Controller’ (FC). The Tool Pusher shall

presume the role of ‘Incident Controller’ (IC) and shall be at the scene of the incident along with his team

members, to control the emergency. The Forward Controller shall be located at the Rig control room. He

shall direct and advise the Incident Controller (IC) on the course of action to be taken in consultation with

Drilling Supervisor. The Incident Controller will be present at the scene of emergency and will be the

person in the field responsible to control the emergency. He will report the situation to the Forward

Controller and to the Drilling Supervisor (ERG leader). The Drilling Supervisor and the Forward Controller

(FC) shall constantly update the Drilling Superintendent who in turn updates the other members of the

Emergency Management Team (EMT) at Chennai Head Quarters.

The Emergency Management Team (EMT) shall comprise of the following members:

Managing Director (Emergency Response Manager)

Drilling Manager (EMT Leader)

Drilling Superintendent

Logistics In-charge

Project Office In-Charge Assam


SENES 25 HOEC

HSE Manager

Drilling Administrator

Once the emergency message is received from the Rig, the Drilling Superintendent shall inform to Drilling

Manager who in turn after discussion with the Emergency Response Manager Managing Director and the

team at Chennai (if necessary) will activate the Emergency Management Teams (EMT) to the Emergency

Control Room.

The organizational chart for emergency response is presented in Figure 6.8 below.

FIGURE 0-8: EMERGENCY RESPONSE ORGANIZATIONAL CHART

1.1.11 Emergency Classification

Due consideration is given to the severity of potential emergency situation that may arise as a result of

pipeline failure accident events as discussed in the Quantitative Risk Analysis (QRA) study. Not all

emergency situations call for mobilization of same resources or emergency actions and therefore, the


SENES 26 HOEC

emergencies are classified into three levels depending on their severity and potential impact, so that

appropriate emergency response procedures can be effectively implemented by the ERG and EMT. The

emergency levels/tiers defined with respect to this project based on their severity have been discussed in

the subsequent sections with 'decision tree' for emergency classification being depicted in Figure 6.9

FIGURE 0-9: EMERGENCY CLASSIFICATION “DECISION TREE”

Level 1 - Emergency

An event can be dealt with by personnel and resources available at site; the event does not have any

effect outside the site, external agencies are unlikely to be involved.


SENES 27 HOEC

There is unlikely to be danger to life, to the environment, or to Company asset or reputation.

The Site Emergency Response Plan and Procedure are activated; the Company base offices at Digboi

and Chennai are notified.

Level 2 - Emergency

It is an event which may be dealt locally but requires involvement of wider Company resources and

external support. The initial event may be “on-site”, have some effect outside the site or be “off-site”, and

external services will be involved in handling the emergency.

There is likely to be danger to life, to the environment, or to Company asset or reputation.

The Site Emergency Response Plan and Procedure are activated; the Emergency Response Plan of HOEC

is activated.

Level 3 - Emergency

It is a major where likely to be danger to life, to the environment, or to Company asset or reputation is

involved.

The Site Emergency Response Plan and Procedure are activated; the Emergency Response Plan of HOEC

will be activated.

1.1.12 Emergency Response Procedure

The emergency response plan covers the following risk scenarios viz.

Fire from ignition of gas leaks from pipeline, GGS etc

Injury

Structural Failure

Well Blow Out during drilling

Hydrocarbon Leaks During Well Testing

Bomb Threat

Extreme Weather

However for the purpose of the present study response procedures has been limited to risk assessed in

aforesaid sections viz. blow outs and fire from pipeline failure. Details of the response procedures to be

adopted to manage the aforesaid risks have been provided below.


SENES 28 HOEC

Fire from Pipeline Failure


SENES 29 HOEC


SENES 30 HOEC

Well Control Emergency

risk assessment for development wells, ggs,...

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