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MODIFICATIONS IN GAS AND CONDENSATE PROCESSING FACILITIES AT HAZIRA

PRE-FEASIBILITY REPORT

OIL & NATURAL GAS CORPORATION LTD.

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Executive Summary

Background

In the Tapti Daman bock of Mumbai Offshore Basin several marginal gas fields are

discovered. The Gas initial in place of ONGC fields in nomination blocks in Tapti Daman

Block, as on 01.04.2014, are 152.6 BCM (66.72 BCM in Proved Category, 36.54 BCM in

Probable Category and 49.33 BCM in Possible Category). The C-Series and B-12 fields

are being developed in different phases. Following development projects are being

implemented:

i. C- 24 Cluster Development project (on production)

ii. C-26 Cluster Development project (under implementation)

iii. Land Acquisition in Kelwa-Mahim, Palghar for setting up new onshore terminal for

processing gas from Daman Development Project (in progress)

iv. Takeover of Tapti JV Facilities for early monetization of additional gas from C-

Series and Daman Development Project (under approval)

The status of different projects is as under.

* The production is less than the planned production because of sub surface

surprises in C-39 and C-22 fields. Out of 7 wells drilled in C-39 field, five wells are

devoid of hydrocarbon and in C-22 field the production ceased due to pre mature

depletion of the reservoir.

Integration of Tapti facilities takeover with early monetization of gas under C-

series and Daman Development Project

The Daman Development project includes gas from additional development of C-24 and

development of B-12 fields. A development scheme has been prepared by IRS which

envisages a peak gas rate of 8.38 MMSCMD in firm case with upside up to 10 MMSCMD

from additional development of C-24 and development of B-12 fields.

Including the production from existing C-Series fields (C-24 Cluster) and fields likely to

be developed in C-26 Cluster project, the overall production from C-Series – Daman

Development project may reach to about 13-14 MMSCMD.

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The present process capacity available at NQ for handling C-Series gas is about 3.2

MMSCMD. Additional process capacity of about 3.6 MMSCMD are being created at

MOPU (Sagar Pragati converted) to be deployed bridge connected at C-24. Thus,

additional process capacity of about 7 MMSCMD need to be created for C-Series and

Daman Development Project.

In case the processing facilities at TPP/ TCPP and pipelines from TCPP / TPP to SBHT

line are transferred to ONGC by the Govt., it may be possible that gas produced from C-

26 cluster project will be evacuated using TCPP facilities in 2015-16 themselves even in

case of delay / non availability of MOPU. Further gas production from C- Series and

Daman Development C-24 (additional) and B-12 fields may commence by 2016-17.

The reservoir simulation studies have been carried out by IRS.. The well design, casing

policy, mud policy, well completion and sand control measures have been made. The

Geo mechanical and Geo technical studies have also been carried out to identify the

platform locations and well trajectory. The flow assurance studies have been carried out

by IOGPT for identification of tubing sizes and optimized pipeline design. The adequacy

check of existing facilities at offshore and at Hazira has also been carried out.

Upside Potential

In addition to the fields considered in the present FR the upside potential exists in the

fields in the nearby area which are under exploration and delineation. The expected

production potential from these fields is as below:

B-12-17 : 1.5-2.0 MMSCMD

CA &SD : 1.0 MMSCMD

B-9-1&3 : 1.0 MMSCMD

NELP-MB-OSN2005/1 : 4-5 MMSCMD

C-37, NMT &C-23 : 0.5-0.6 MMSCMD

These fields are expected to be developed in next phase around the year 2020 based on

the detailed Reservoir Characterization.

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Need For The Project/Demand And Supply Analysis

The hydrocarbons sector plays vital role in the economic growth of the country. Efficient,

reliable and competitively priced energy supplies are prerequisites for accelerating

economic growth. For any developing country, the strategy for energy development is an

integral part of the overall economic strategy. The per capita consumption of primary

energy and hydrocarbons reveals that India is amongst the lowest in consumption of

hydrocarbon in terms of kilograms of oil equivalent. It is a known fact that there exists a

fair degree of correlation between the growth in petroleum products and the growth in the

overall economic activities. Currently, the supply from the domestic market caters to only

30% of the total demand for crude oil in the country and the majority of the demand is

largely met through the imports. Hence the hydrocarbon sector is most crucial for

determining the energy security for the country. The gap between supply and availability

of crude oil, petroleum products as well as gas from indigenous sources is likely to

increase over the years. The growing demand and supply gap require, increased

emphasis to the monetization of fields.

Oil Demand

According to the BP Statistical Review, Dated Brent averaged $111.26 per barrel in 2011,

an increase of around 40% from the 2010 level. Global oil consumption grew by a below-

average 0.6 million barrels per day (b/d), or 0.7%, to reach 88 million b/d in 2011. OECD

consumption declined by 1.2% (600,000 b/d), the fifth decrease in the past six years.

Despite strong oil prices, oil consumption growth was below average in producing regions

of the Middle East and Africa due to regional unrest. China again recorded the largest

increment to global consumption growth (+505,000 b/d, +5.5%) although the growth rate

was below the 10-year average.

Annual global oil production increased by 1.1 million bbl/d or 1.3% in 2011. Virtually all

of the net growth was in OPEC, with large increases in Saudi Arabia (+1.2 million b/d),

the UAE, Kuwait and Iraq more than offsetting a loss of Libyan supply (-1.2 million

b/d).The US (+285,000 b/d) had the largest increase among non-OPEC producers for

the third consecutive year. Global refinery crude runs increased by a below-average

375,000 b/d, or 0.5%. Non-OECD countries accounted for all the net increase, rising by

685,000 b/d. While OECD throughput declined by 310,000 b/d, US throughput increased

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(+110,000 b/d) and the US became a net exporter of refined products for the first time on

record.

Global oil trade in 2011 grew by 2%, or 1.1 million b/d. At 54.6 million b/d, trade accounted

for 62% of global consumption, up from 58% a decade ago. China accounted for roughly

two-thirds of the growth in trade last year, with net imports (6 million b/d) rising by 13%.

US net imports were 29% below their 2005 peak. Middle East countries accounted for

81% of the growth in exports last year. While crude oil accounted for 70% of global trade

in 2011, refined products accounted for two-thirds of the growth in global trade last year

As reported by BP Statistical Review 2012, at 5.7 billion barrels of oil equivalent (bboe),

India's proven balance recoverable oil reserves are a meagre 0.3 percent of world's total

reserves. More than 50 percent of India's proven oil reserves are located in the western

offshore, Mumbai High, and in the onshore northeast of the country. Substantial

undeveloped reserves are also located in the offshore Bay of Bengal Krishna Godavari

basin and in onshore Rajasthan

With Reserves to Production (R/P) ratio of 18 years, India's existing domestic production

of about 858,000 barrels of oil per day (bopd) is only about 25 percent of its current

consumption of 3,473,000 bopd, creating a wide gap to be met through imports. As a

result, the volume of crude oil imports has been increasing steadily in India nearing about

75 percent of its total crude requirement in 2011

Domestic oil production is currently dominated by the state-owned exploration companies

ONGC and OIL, which together accounted for ~74 percent of India's crude oil production

in 2010-11. Crude oil production has increased by 12.5 percent to 37.68 mmt in 2010-11

from 33.50 mmt in 2009-10 due to contribution of over 6 mmt from Barmer, Rajasthan

and KG Basin.

There are a number of factors driving the volatility making it difficult to identify any one

dominant driver at a given point in time. However, the relative influence of oil market

fundamentals on the one hand and speculative financial flows into and out of futures

markets on the other, continue to vie for prominence among those seeking to explain

short-term price shifts. Inventory levels, upstream spare capacity and the balance

between refining configuration and crude slate all influence absolute and relative prices.

Limited price elasticity can also magnify the price impact of relatively small changes in

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supply and demand. There is a clear need for broader and deeper data capture on market

fundamentals if light is to be shed on currently opaque non-OECD stock levels and

demand.

However it is also clear that after the recent roller-coaster ride in prices that many other,

less tangible factors, including expectations for the shape of the market in the future, also

play a key short-term role in influencing prices. These range from concerns about peak

oil and the adequacy of upstream and downstream investment, all the way to exchange

rate fluctuations, equity market shifts, perceptions on global economic recovery and

short-term money flows into and out of commodity futures markets.

Given the demand-supply gap for hydrocarbons in the country and the price outlook,

there is a positive consideration for this project in the Indian context. In view of the global

trends in the Oil and Gas markets and the domestic requirement for crude oil and gas

supplies viz a viz current performance in E&P in India, any additional production possible

by ONGC would go a long way in reducing India’s dependence on imported hydrocarbon

resources and resultant impact on India’s forex position.

Global Gas Demand and Supply

According to the BP statistical Review 2012, World natural gas consumption grew by

2.2% in 2011. Consumption growth was below average in all regions except North

America, where low prices drove robust growth. Outside North America, the largest

volumetric gains in consumption were in China (+21.5%), Saudi Arabia (+13.2%) and

Japan (+11.6%) in 2011. These increases were partly offset by the huge decline in EU

gas consumption (-9.9%), driven by a weak economy, high gas prices, warm weather

and continued growth in renewable power generation.

The total global natural gas production grew by 3.1% in 2011. The US (+7.7%) recorded

the largest volumetric increase despite lower gas prices, and remained the world’s largest

producer in 2011. Output also grew rapidly in Qatar (+25.8%), Russia (+3.1%) and

Turkmenistan (+40.6%), more than offsetting declines in Libya (-75.6%) and the UK (-

20.8%). As was the case for consumption, the EU recorded the largest decline in gas

production on record (-11.4%), due to a combination of mature fields, maintenance, and

weak regional consumption.

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Given the general weakness of gas consumption growth, global natural gas trade

increased by a relatively modest 4% in 2011. LNG shipments grew by 10.1%, with Qatar

accounting for 87.7% of the increase in 2011. Among LNG importers, the largest

volumetric growth was in Japan and the UK. LNG now accounts for 32.3% of global gas

trade. Pipeline shipments grew by just 1.3%, with declines in imports by Germany, the

UK, the US and Italy offsetting increases in China (from Turkmenistan), Ukraine (from

Russia), and Turkey (from Russia and Iran).

As per the IEA Energy Outlook, Shale gas production is expected to increase from 5.0

trillion cubic feet per year in 2010 (23 percent of total U.S. dry gas production) to 13.6

trillion cubic feet per year in 2035 (49 percent of total U.S. dry gas production). As with

tight oil, when looking forward to 2035, there are unresolved uncertainties surrounding

the technological advances that have made shale gas production a reality. The potential

impact of those uncertainties results in a range of outcomes for U.S. shale gas production

from 9.7 to 20.5 trillion cubic feet per year when looking forward to 2035.

Indian Gas Demand and Supply

As per the Report by Industry Group for Petroleum and Natural Gas Regulatory Board “

Vision 2030 Natural Gas infrastructure in India” the share of natural gas in the energy

mix of India is expected to increase to 20% in 2025 as compared to 11% in 2011. It is

envisaged that the share of natural gas in the primary energy mix would reach 20% till

2030 if not more.

In recent years the demand for natural gas in India has increased significantly due to its

higher availability, development of transmission and distribution infrastructure, the

savings from the usage of natural gas in place of alternate fuels, the environment friendly

characteristics of natural gas as a fuel and the overall favorable economics of supplying

gas at reasonable prices to end consumers. Power and Fertilizer sector remain the two

biggest contributors to natural gas demand in India and continue to account for more

than 55% of gas consumption. India can be divided into six major regional natural gas

markets namely Northern, Western, Central, Southern, Eastern and North-Eastern

market, out of which the Western and Northern markets currently have the highest

consumption due to better pipeline connectivity. However, with the increasing coverage

and reach of natural gas infrastructure in India, this regional imbalance is expected to get

corrected. In future, the natural gas demand is all set to grow significantly at a CAGR of

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6.8% from 242.6 MMSCMD in 2012-13 to 746 MMSCMD in 2029-30. The contribution to

the overall demand from the CGD sector is set to increase from 6% to 11% during the

projected period.

Natural gas in India is mainly consumed by Power, Fertilizer, City Gas Distribution,

Refineries, Sponge Iron and Petrochemicals sector (Figure given below) showing the

increase in natural gas off take by various consumers, as estimated in the year FY15.

The share of CGD and others is expected to grow at a faster rate; this is because of

increasing share of r-LNG in the natural gas supplies and CGD and others segments

have higher potential to take the relatively high priced r-LNG.

Trend in Industry-wise off-take of domestic natural gas (mmscmd)

Source: MoPNG

Due to falling production of mature fields such as Bombay High, Bassein and South Tapti

, Mid Tapti, problems with securing supplies from KG-D6 field and increase in prices of

alternate fuels, in India, demand has continuously exceeded production. This is leading

to higher emphasis on imports including r-LNG and transnational pipelines. With a host

of r-LNG terminals being commissioned by the end of XIIth five year plans, r-LNG is

expected to take a significant share in meeting gas demand in the country

Domestic Gas supply and Imports (MMSCMD)

61.6

118.3

39.9

50.4

11.4

21.4

43.5

51.6

FY11 FY15EPower Fertilizer

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Source: MoPNG

To reduce this gap, production from discovered gas fields is being contemplated. On this

backdrop, the present proposal for the additional development of C- 24 field and

development of B-12 fields is being contemplated. Also all production from this scheme

over the project period is treated as additional new production. India is net importer of

oil/energy deficient country. Hence, production of gas/condensate from C-24 and B-12

fields will reduce the dependence on imports to the extent of such production. Hence no

problem is envisaged in the marketing of condensate and gas produced from the

proposed project. Further, for early monetization of the gas in place in the proposed

fields, the project is needed to be developed.

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Modifications in Hazira Plant

IOGPT carried out adequacy study of existing facilities at Hazira Plant for processing

of additional gas and condensate, to be received from Daman Development Project

through TCPP/TPP in addition to gas and condensate being / to be received at Hazira

Plant from Bassein and other fields via SBHT Lines .The study indicates that the

additional gas and condensate from B-12 & C-24 can be processed with some

modifications in some of the existing facilities. However, since the condensate is

envisaged to be heavy, some modifications in existing units are required.

Creation of a New Atmospheric Steam Distillation column with

accessories for processing the bottom product of existing of Naphtha

(1st) column.

Creation of an additional new Atmospheric steam based distillation

column with accessories for processing entire NGL generated from the CFU, to address

various issues of increased maintenance activities in existing KRU and various

operational issues arising out of it.

Additional facilities required at the inlet of CFU: (Horizontal Surge drum, Activated

Carbon filter etc.)

Storage & evacuation facilities (Heavy cut insulated storage tanks , HSD storage tank,

Kerosene evacuation Rail Gantry , Kerosene loading pumps , Diesel evacuation loading

bays, HSD Loading pumps, Conversion of existing HSD Loading Bay for RCO/Heavy

cut, Heavy cut loading pumps, Pipelines to transfer HSD to IOC/HPCL/BPCL etc.

Execution in Conventional LSTK method (Option-1)

i) An Engineering design and PMC consultant will need to be appointed for preparation

of BEDP and Technical bid package, assist ONGC in technical evaluation of bids and

PMC purposes. The PMC consultant will also carry out review of detailed engineering

drawings/documents of LSTK contractor and construction supervision services.

ii) If the project is executed by a single LSTK contract, the design & detailed

engineering, procurement, construction and commissioning activities shall be carried

out by LSTK contractor.

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Execution through OBE method (Option-2)

This mode of execution would have single point responsibility. Shorter overall project

execution time by avoiding the EPC contract tendering. Lower cost (LSTK Margin,

contingencies, engineering fees etc.) and Contractor fees and profit known to owner.

Owner bears realistic price as governed by market conditions, no hidden costs.

Greater flexibility, transparency in costs and fees. As per experience of EIL, the overall

cost of execution of project on OBE basis is generally less than the conventional

method of execution on LSTK basis.

As per budgetary quotation of M/s EIL, cost estimation on OBE mode of

implementation works out to be 374 Crores (with accuracy of ±20%) and schedule of

implementation shall be 27 months for Mechanical Completion from the date of NOA.

The schedule includes validation of adequacy study done by ONGC.

As per EIL, implementation on conventional LSTK mode, the cost works out to

be 418 Crores (with accuracy of ±20%) and schedule of implementation shall be

35 months for Mechanical Completion from the date of NOA. The schedule

includes validation of adequacy study done by ONGC.

By awarding the job through OBE mode of implementation, there would be

saving of Rs. 44 crores as well as time of completion would be 8 months lesser.

It is proposed for execution of work at Hazira on OBE mode through M/s EIL in view

of the following reasons.

Project Schedule for Modification in Hazira Plant:

Approval of FR : Aug.2014

Award of Work to EIL on OBE basis : Nov .2014

Completion of Work : 31.01.2017

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Cost Estimation

Facilities:

The facilities required for field development have been finalized in various MDT meetings.

Based upon the scope of work finalized by the MDT, Engineering Services has estimated

the cost as per the latest approved methodology for cost estimates and discussed below:

Phasing of Expenditure

Phasing of capital expenditure considered for well platforms and pipeline and top side

modifications is as under.

Year Phasing of Expenditure

Facilities

2014- 15 5 %

2015-16 75%

2016-17 20%

Modification in Hazira Facilities:

Based on IOGPT Adequacy check report, detailed in house deliberations & discussions

and discussions & deliberations in various MDT meetings, the requirement for

modifications at Hazira Plant was worked out. As Hazira Engineering Services does not

have dedicated costing group and Costing cell at Offshore Engineering Services does

not have the cost data for onshore equipment involved, the list of requirement along with

relevant portion of IOGPT Adequacy Study Report was forwarded to EIL for budgetary

quote.

EIL worked on the CAPEX estimation with both methods viz. OBE and LSTK method.

Accordingly, EIL provided their budgetary quote with CAPEX estimation based on both

the methods. The summary of budgetary quote by EIL is as follows:

The cost estimation on Open Book Estimates (OBE) mode of implementation works

out to be 374 Crores (with accuracy of ±20%) and schedule of implementation shall

be 27 months for Mechanical Completion from the data of NOA. The schedule

includes validation of adequacy study done by ONGC.

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For implementation on conventional LSTK mode, the cost works out to be 418

Crores (with accuracy of ± 20%) and schedule of implementation shall be 35 months

for Mechanical Completion from the data of NOA. The schedule includes validation

of adequacy study done by ONGC.

It is apparent that by awarding the job through OBE mode of implementation, there

is saving in monetary terms (44 crores) and also on time (8 months).

Phasing of Expenditure

The phasing of expenditure considered for Hazira plant modifications is as under.

Year Phasing of

Expenditure Rs. Cr.

2014-15 20

2015-16 150

2016-17 204

Viability Analysis

The economic feasibility of the project has been assessed as per the existing guidelines

issued vide Circular No. DF/ND/PAS/390/2013 dated 24th Jan 2013.

The major assumptions are as under:

(i) The base oil price of 53.66 US$/bbl (2013-14) has been considered for condensate

revenue and gas price of 6.30 US$/MMBTU upto 2019-20 with escalation of 1

US$/MMBTU thereafter once in a block of every 5 years has been considered as

per present guidelines.

(ii) 97.5% of the total production for condensate and 97% of the gas has been taken

for estimation of revenue calculations.

(iii) The Gas has been considered after internal consumption. The average calorific

value has been considered as 9157 Kcal/m3 for C-24 and 8833 Kcal/m3 for B-12

(iv) Capital cost has been escalated @ 6% p.a. only for phase-II and Operating cost

has been escalated @ 8% p.a.

(v) The hurdle rate considered is 14%

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(vi) All calculations have been carried out in post-tax scenario. The corporate Tax has

been considered as 33.99%.

(vii) The Royalty on gas has been considered as 9.09%. Education Cess and OIDB

Cess has been considered as 3% and Rs. 4500/MT respectively. NCCD has been

taken as Rs.50 / MT. Well Head deduction have been taken as Rs.947/ MT

(viii) The depreciation on facilities is considered @ 15% on WDV and additional 20%

on the fresh / new investments for the first year only and 100% for well cost.

(ix) The Exchange rate has been considered as 1 USD= Rs.59.71 (average of June

2014)

(x) Abandonment cost for new facilities and wells to be added has been considered as

per the rates for 2013-14.

(xi) The abandonment cost of Tapti facilities has been assumed to be Nil/ on account

of JV.

Sensitivity analysis

Sl. No

Parameter

NPV @14% IRR

(RS. Cr.) (%)

1 Base Case 7226.84 60.39%

2 Capex + 10% 6844.61 54.74%

3 Capex + 20% 6462.39 49.93%

4 Opex + 10% 7070.59 59.77%

5 Opex + 20 % 6914.34 59.14%

6 Production ( – ) 10% 6060.79 53.95%

7 Production ( – ) 20 % 4894.73 47.31%

8 Both Capex & Opex + 10%, PDN (–) 10 %

5525.57 48.16%

9 Both Capex & Opex + 20%, PDN (– ) 20 %

3830.82 37.30%

10 Price of Gas @ USD 5.25 5683.98 51.47%

11 Price of condensate @ 41/BBL 6585.22 56.80%

12 Price of Condensate @ 48/BBL 6939.99 58.79%

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Adequacy check of Hazira Facilities and Modifications required

Background The capacity of major units of Hazira Gas Process Complex (HGPC) such as Condensate

Fractionation Units, Gas Sweetening Units, Gas Dehydration Units, Dew point

Depression Units, LPG Unit and Kerosene Recovery Unit have been tabulated below:-

Major Unit Installed Capacity Normal Operating Capacity

Gas Sweetening Unit 52.5 MMSCMD 46.9 MMSCMD with One train stand by

Sulphur Recovery Unit (SRU) 1.06 MMSCMD 0.88 MMSCMD with one train stand by

Condensate Fractioning Unit (CFU)

12600 M3/day (inclusive of sweet & sour condensate)

10800 M3/day (inclusive of sweet & sour condensate) with one train stand by

Gas Dehydration Unit (GDU) 47.3 MMSCMD 41.7 MMSCMD with One train stand by

Dew Point Depression (DPD) 51.0 MMSCMD 45.5 MMSCMD with One train stand by

Liquefied Petroleum Gas (LPG) Plants

5.27 MMSCMD, 960 m3/day of sweet condensate

Single Unit. No stand by

Kerosene Recovery Unit 3972 MT/day Single Unit. No stand by

IOGPT has carried out adequacy check of existing facilities for processing of additional

gas and condensate likely to be received from Daman Development Project through

offshore TCPP/TPP facilities. This additional gas & condensate processing would be

in addition to the existing gas and condensate being received at HGPC from Bassein

and other fields via SBHT Lines.The study indicates that additional peak production of

8.38 MMSCMD gas & 9316 BPD condensate from B-12 & C-24 can be processed with

some modifications in the existing facilities.

Adequacy of Major Units The adequacy of HGPC units has been carried out on HYSYS Process Simulator using

the average composition of the combined streams from offshore. The salient outcome of

the study for various units is discussed below.

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Condensate Fractionation Unit (CFU)

All heat exchangers duties, temperature and pressures parameters are within the design

limits. The required operating temperatures of stripper re-boilers will be around 145ºC

which is 20ºC above the existing operating temperatures. With reference to the design

heat duty of the stripper re-boiler, the available MP steam which is at a temperature of

200°C is sufficient for meeting heating requirement.

For LPG re-boilers, the operating temperatures will be about 180ºC which is about 25ºC

above the existing operating temperature. With reference to the design heat duty of the

LPG re-boiler, the available HP steam which is at a temperature of 260°C is sufficient for

meeting heating requirement.

The simulated flooding factor for the stripping columns and LPG columns were less than

40% and thus the columns are adequate.

While processing the entire DPD condensate in CFU trains, it is observed that the

operating temperatures of Stripper re-boilers will be around 135ºC which is 10ºC above

the existing operating temperatures. With reference to the design heat duty of the stripper

re boiler, the available MP steam which is at a temperature of 200°C is sufficient for

meeting heating requirement.

For LPG re-boilers, the operating temperatures will be about 175ºC which is about 10ºC

above the existing operating temperatures. With reference to the design heat duty of the

LPG re-boiler, the available HP steam which is at a temperature of 260°C is sufficient for

meeting heating requirement.

Thus, the adequacy check revealed that all the heat exchangers, pumps & columns of

CFU are adequate.

Receipt of black colour condensate at HGPC from new fields has disturbed the

operations of various downstream units such as CFU & Kerosene Recover Unit leading

to inferior product quality. To address this issue, it is proposed to install two horizontal

surge vessels for water knock out followed by activated carbon & cartridge filter systems

at the inlet of CFUs. This facility shall have 6722 m3/day condensate handling capacity.

It will ensure processing of clean condensate feed in CFUs and also for improving quality

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of downstream products. The proposed schematic filtration system at CFU inlet is shown

below.

Gas Sweetening Units ( GSU) All vessels, pumps, heat exchangers duties, temperature and pressures parameters are

within the design limits. The simulated flooding factor for the Absorber column and

Regenerator column was less than 34% and therefore columns are adequate. Hence, no

inadequacy is envisaged in GSUs.

8.2.3 Gas Dehydration Units (GDU) All vessels, pumps, heat exchangers duties, temperature and pressures parameters are

within the design limits. The simulated flooding factor for the Absorber column and

Regenerator column was less than 40% and therefore columns are adequate. Hence, no

inadequacy is envisaged in GDUs.

Dew Point Depression Unit (DPD) All vessels, pumps, heat exchangers duties, temperature and pressures parameters are

within the design limits. Hence, no inadequacy is envisaged in DPDs.

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Liquefied Petroleum Gas (LPG) All vessels, pumps, heat exchangers duties, temperature and pressures parameters are

within the design limits. Hence, no inadequacy is envisaged in LPG plant.

Kerosene Recovery Unit (KRU) For assessing the adequacy of existing KRU on long term sustainable basis, following

aspects / constraints for KRU operations as conveyed by HGPC were considered:

KRU is responsible for production of most of the value added products viz. Naphtha,

Kerosene, ATF, HSD. In future also, with Daman inputs, it will be responsible for

producing all above products in enhanced quantities and additionally Heavy cut

product. The dispatch / marketing of value added products depend on maintaining

strict quality norms. In view of change in product basket, KRU operations will be even

more critical in terms of VAP production, storage and evacuation.

The present KRU at HGPC is more than 16 years old and it is the only unit available

for processing NGL generated from CFUs, thus making it a bottle-neck in reference

to HGPC processing facilities.

As mentioned above, KRU being a single unit without standby, a lot of operational

constraints are faced during long planned and unplanned shutdowns. Any partial / full

shutdown leads to loss of Naphtha / SKO or ATF & HSD production. It also leads to

storage of off-spec products or NGL into Naphtha tanks creating ullage problems. In

extreme case, it may also lead to ullage problem for sour condensate in slug catchers

further leading to stoppage of offshore supplies & consequent offshore shutdown.

It is worth mentioning here that there is statutory requirement of carrying out shutdown

/ turnaround activities (TA) every four years for around 15 days, for carrying out

various health checks and related maintenance. Apart from this, it has been observed

that due to plant aging the occurrences of forced / break down maintenance activities

are increasing. In past, apart from statutory TA activities, KRU partial shutdown for

various maintenance and repair works was needed to be taken for more than 60 days

since 2007, leading to production of off-spec products and their subsequent

reprocessing.

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The capacity of reprocessing off-spec products being small it takes long periods to

reprocess off-spec products.

In future, it is planned to transport Naphtha from HGPC to OPAL, Dahej through

pipeline. The pipeline is already under construction. In this arrangement, OPAL is

likely to be dependent on HGPC for continuous and uninterrupted Naphtha supply. In

such scenario, uninterrupted operation of KRU is likely to become even more

important for maintaining continuous supply.

Adequacy study revealed that existing Naphtha column and its associated facilities can

process the additional feed. However, diesel quality cannot be achieved by processing

Naphtha column bottom liquid in the existing Kero column. To address product quality

issue, operational, maintenance and evacuation constraints for KRU operations as

conveyed by HGPC, following two processing options have been worked out by

IOGPT.

Option-1: Processing of entire NGL generated from CFU in existing Naphtha column

of KRU and then routing of the bottom liquid of Naphtha column to a new Atmospheric

Steam Distillation Column

Option-2: Processing of entire NGL generated from CFUs in a new Atmospheric

Steam Distillation Column as proposed by HGPC

Option-1 envisages processing of around 920 m3/day of Naphtha column bottom

liquid in a New Atmospheric Steam Distillation Column. Facilities broadly considered

20

are surge drum, feed preheating section, furnace, atmospheric distillation column

(steam stripping based) along with associated facilities, diesel side stripper, product

coolers, pumps, chemical injection system etc. The schematic diagram for this option

is given below.

Option 2 envisages processing of entire NGL (around 4287 m3/d) from CFUs in a

new Atmospheric Steam Distillation Column. This option broadly consists of surge

21

drum, feed preheating section, furnace, atmospheric distillation column (steam

stripping based) along with associated facilities, kerosene & diesel side strippers,

product coolers, pumps, chemical injection system etc. The schematic diagram for this

option is given below.

Broad process details are established from the process simulator. From the process

simulator, salient parameters such as density, viscosity, boiling ranges, cetane index

details are established as per Euro-IV/Bharat-IV standards. However, other parameters

related to quality of products are to be established by a detailed laboratory analysis during

Engineering / Design stage.

Based on due consideration of above important factors about KRU operation and IOGPT

adequacy Report, after detailed deliberations & discussions in house, it is proposed to

carry out following modifications in Kerosene Recovery Unit for processing Daman

inputs.

Creation of a New Atmospheric Steam Distillation column with accessories for

processing the bottom product of existing of Naphtha (1st) column.

22

Creation of an additional new Atmospheric steam based distillation column with

accessories for processing entire NGL generated from the CFU, to address various

issues of increased maintenance activities in existing KRU and various operational

issues arising out of it.

Storage and Evacuation For storage & evacuation requirement, as proposed by HGPC, following are considered.

Any ullage problem (non-availability of storage space for value added product) leads to

stoppage of upstream processing / production activity (including offshore) which is not

desirable. At times, many factors leading to non-evacuation and subsequent ullage

problem are external and hence are not controllable to a large extent. To mitigate such

situations, HGPC has multiple modes of evacuation like rail, road, pipeline etc. for various

major value added products. In past, it has been proved to be very handy for maintaining

smooth operations of HGPC, when some modes were not available due to various

marketing / external issues. Under such scenarios, HGPC was able to run smoothly, only

because of availability of alternate mode(s) of evacuation.

Considering existing infrastructure availability for storage & evacuation of products, no

additional facilities have been considered for LPG & Naphtha.

In a feedback from HGPC Marketing Group, it was informed that SKO local demand is

going down since last few years and likely to reduce further. In view of this, it may be

necessary to evacuate SKO to distant places in the country, requiring POL rail gantry.

Therefore provision of one rail gantry has been considered for evacuation of Kerosene

product.

HGPC has also proposed diesel evacuation option by pipeline transportation to nearby

OMC (IOC /BPCL /HPCL) which has been considered in addition to the existing road

transportation. As HSD is going to be a major product, it is proposed to have road gantry

for its evacuation along with pipeline transportation to nearby OMC (IOC/BPCL/HPCL).

Because of substantial increase in HSD production, additional HSD storage tank is

considered.

23

Since, no Heavy cut product storage and evacuation facilities are available at HGPC,

three new insulated storage tanks each of 300 m3 capacity have been considered. As

proposed by HGPC, necessary modifications for converting two existing HSD loading

bays for heavy cut product evacuation by road transportation have been considered.

Based on IOGPT adequacy check findings, MDT / in house deliberations & discussion

with HGPC Marketing Group, the requirement considered for storage and evacuation are

as follows:

Storage & Evacuation Facilities

Product Anticipated Production m3/d

Existing Storage Capacity m3

Storage Days

Existing Evacuation Options

Remarks

LPG 2666 2500 m3 x 9 nos ~ 7 Rail/ Road /Pipeline

No additional facilities required

Naphtha 3800 16500 m3 x 8 nos ~ 30 Ship / Rail/Pipeline

No additional facilities required

Kerosene 460

5000 m3 x 4 nos ~ 35

Road As proposed by HGPC, new rail gantry is considered

Diesel 430 500 m3 x 2no tanks 5000 m3 x1no tank

~11 Road As proposed by HGPC, following additional facilities are considered:

1. 8” pipeline to OMCs (3 Nos. X 5 Km) 2. Three road loading bays

Heavy cut 33 nil nil

Road

1. New tanks 3 nos each of 300 m3 capacity considered.

2. As proposed by HGPC, conversion of existing two HSD loading bays into heavy cut bays .

24

Details of facilities required at Hazira Gas Process Complex A broad list of additional facilities required to process the new feed gas and condensate

is listed below

A broad list of additional facilities required with respect to Condensate Fractionation

Unit is listed below.

Equipment List Additional facilities required at the inlet of CFU

1 Two Horizontal Surge drum for water knockout ( 50% x 2 Nos) 1.5m x 6.5 m

2 Activated carbon filter system with downstream cartridge filter system (2 operating + 2 standby)

1.5 m x 5.5 m

A broad list of additional facilities required with respect to KRU is listed below

Additional facilities for handling bottom product of existing Naphtha Column in New

Kero Column

Equipment Detail Design level

Vessels

Feed Surge Drum 1 2.13 x 4 m

Atmospheric distillation column reflux drum 1 2.13 x 3.2 m

Flare Knockout drum 1 5.450 x 1.820 m

Fuel gas Knock out drum 1 3.0 x 0.50 m

Closed Blow down drum 1 3.5 m x 1.6 m

Columns

Atmospheric Distillation Column with internals (with 610 mm tray spacing)

1 1.7 m x 21 m (25 trays)

Diesel Side stripper with internals (structured packing) 1 0.61 m x 1.5 m

Exchangers & Furnace

Feed-Hot HSD Exchanger 1 0.7 x 1.2 Mkcal/hr

Feed –Hot HSD Pump Around exchanger 0.4 x 1.2 Mkcal/hr

Atmospheric Distillation Column top Condenser (Air cooler) 1 1 no X 3.8 x 1.2 Mkcal/hr

SKO/ATF Product cooler 1 0.53 x 1.2 Mkcal/hr

HSD Product cooler 1 1.2 x 1.2 Mkcal/hr

Heavy cut / RCO Product cooler 1 0.2 x 1.2 Mkcal/hr

Furnace ( Packaged item) 1 3.6 x 1.2 Mkcal/hr

25

Pumps

Feed pumps (Design Pressure:16 kg/cm2 a)

2 38.5 X 1.2 m3/hr

Atm Column reflux cum transfer pumps (Design Pressure = 14 kg/cm2 a)

2 44 X 1.2 m3/hr

HSD Pump Around pumps (Design Pressure= 8 kg/cm2 a)

2 20 X 1.2 m3/hr

HSD Product transfer pumps (Design Pressure = 8 kg/cm2 a)

2 18 X 1.2 m3/hr

Heavy cut Product transfer pumps (Design Pressure= 19.2 kg/cm2 a)

2 1.5 X 1.2 m3/hr

Corrosion inhibitor injection pumps (Design Pressure= 9 kg/cm2 a)

2 40 X 1.2 LPH

Ammonia injection pumps (Design Pressure= 9 kg/cm2 a)

2 40 X 1.2 m3/hr

CBD liquid transfer pump (Design Pressure= 6 kg/cm2 a)

1 6 X 1.2 m3/hr

Unit Flare KOD pumps (Design Pressure= 6 kg/cm2 a)

2 12 X 1.2 m3/hr

Miscellaneous

Corrosion inhibitor tank 1 6 m3

Ammonia solution tank 6 m3

Equipment List for processing entire NGL from CFU in new Atmospheric Column

Equipment Detail No Design level

Vessels

Feed Surge Drum 1 2.4 x 7.3 m

Atmospheric distillation column reflux drum 1 2.75 x 8.9 m

Flare Knockout drum 1 6.25 x 2.44 m

Fuel gas Knock out drum 1 3.0 x 1.0 m

Closed Blow down drum 1 3.5 x 2.0 m

Columns

Atmospheric Distillation Column with internals (with 610 mm tray spacing)

1 4.0 x 36.0 m (50 trays)

Kerosene Side stripper with internals (structured packing) 1 0.65 x 2.0 m

Diesel Side stripper with internals (structured packing) 1 0.65 x 2.0 m

Exchangers & Furnace

26

Feed –Hot SKO Pump Around exchanger 1 1.2 X 1.2 Mkcal/hr

Feed –Hot HSD Pump around Exchanger 1 1.4 X 1.2 Mkcal/hr

Atmospheric Distillation Column top Condenser (Air cooler)

2 2 nos x 9.5 X 1.2 Mkcal/hr

Naphtha Product cooler 1 0.7 X 1.2 Mkcal/hr

SKO/ATF Product cooler 1 0.9 X 1.2 Mkcal/hr

HSD Product cooler 1 1.4 X 1.2 Mkcal/hr

Heavy cut / RCO Product cooler 1 0.2 X 1.2 Mkcal/hr

Furnace ( Packaged item) 1 10 X 1.2 Mkcal/hr

Pumps

Feed pumps (Design Pressure= 16 kg/cm2 a)

2 144 X 1.2 m3/hr

Atm Column reflux cum transfer pumps (Design Pressure= 14 kg/cm2 a)

2 244 X 1.2 m3/hr

SKO Pump Around pumps (Design Pressure= 8 kg/cm2 a)

2 50 X 1.2 m3/hr

SKO Product transfer pumps (Design Pressure= 8 kg/cm2 a)

2 19 X 1.2 m3/hr

HSD Pump Around pumps (Design Pressure= 8 kg/cm2 a)

2 50 X 1.2 m3/hr

HSD Product transfer pumps (Design Pressure= 8 kg/cm2 a)

2 18 X 1.2 m3/hr

Heavy cut Product transfer pumps (Design Pressure= 19.2 kg/cm2 a)

2 1.5 X 1.2 m3/hr

Corrosion inhibitor injection pumps (Design Pressure= 9 kg/cm2 a)

2 112 X 1.2 LPH

Ammonia injection pumps (Design Pressure= 9 kg/cm2 a)

2 140 X 1.2 LPH

CBD liquid transfer pump (Design Pressure= 6 kg/cm2 a)

1 25 X 1.2 m3/hr

Unit Flare KOD pumps (Design Pressure= 6 kg/cm2 a)

2 50 X 1.2 m3/hr

Miscellaneous

Corrosion inhibitor tank 1 25 m3

Ammonia solution tank 1 25 m3

27

A broad list of additional facilities required for Storage & Evacuation is as below:

Equipment List for Storage and Evacuation

Equipment Detail No Design level

Storage Tanks

Heavy cut insulated storage tanks 3 300 m3 (each)

HSD storage tank 1 5000 m3

Miscellaneous

SKO Rail Loading Gantry Kerosene Evacuation Rail Gantry

One no.

Kerosene loading pumps 4 2 + 2 each 200 m3/hr

HSD Road Loading Gantry Diesel evacuation loading bays

Three nos

HSD Loading pumps 4 2 +2 each 50 m3/hr

Heavy Cut / RCO Loading Bay Conversion of existing HSD Loading Bay for RCO/Heavy cut

2 nos

Heavy cut loading pumps 4 2 +2 each 20 m3/hr

HSD Pipeline Transfer Pipelines to transfer HSD to IOC/HPCL/BPCL ,

8” X ( 3 nos x 5 KM )

During simulation studies, while processing the additional feed gas of B-12 and C-Series,

it was observed that condensate generation is negligible from gas and thus not

contributing to LPG production. Since the feed condensate is heavy, it is capable of

yielding Naphtha, Kerosene, Diesel and Heavy cut (RCO) products.

Project Schedule For Modification in Hazira Plant :

Approval of FR : Aug.2014

Award of Work to EIL on OBE basis : Nov .2014

Completion of Work : 31.01.2017

28

Environment & Safety Management

Background

The proposed project is a Development project aimed at judicial use of our national

resources to ensure Energy Security of the Nation, while achieving Environmental

Security & Sustainability.

The key to environment protection lies in designing of system and process facilities. The

environmental impact of the proposed Integrated Process Plant is not being developed

expertise in gas processing but safety aspects of human being as well as nature are also

being care with equal importance. The project is being made with lot of investment for

ecological protection. Liquid & gaseous effluents from the processing units will be treated

& closely monitored to make them suitable for disposal as per the guidelines/statutory

norms set by Pollution Control Board.

Base Line Environmental Status

The gas from C-24 and B-12 fields is sweet. Results of analysis of the water and

sediment samples are as under:

• Water column

Hydrocarbons - 0- 2.52 µ g/liter

Cadmium - Not Detected

Chromium - 0 – 110 µ g/liter

Copper - 10 – 120 µ g/liter

Lead - Not Detected

• Sediments: (Air Dry Basis)

Hydrocarbons - 31 – 124 µ g/g

Cadmium - 0.0 – 0.02 µ g/g

Chromium - 24.5 – 83.9 µ g/g

Copper - 24.4 – 77.7 µ g/g

Lead - 4.6 – 8.3 µ g/g

29

Sources of Pollution

Production operations involve the following discharges:

Effluents

(a) Liquid Emissions

The waste collection and treatment system receives, segregates, and transfers all plant process and liquid waste streams for plant water management and ensures conformance to the statutory government guidelines prevailing in the state.

(b) Gaseous Emissions

The air pollutants are suspended particulate matter (SPM), Sulphur Dioxide (SO2),

Nitrogen Oxides (Nox), Hydrogen Sulphide (H2S), Carbon Monoxide (CO) &

Hydrocarbons (HC) emitted from diesel generators at rigs and from turbine generators,

diesel generators flue gas/gas flares at process platforms. Flare header is provided to

transport the flare gas to the flare system of existing process platforms. All designs will

be made to insure zero/technical gas flaring. All kinds of gas vents will be taken into

process system for their utilization / evacuations including those from existing process /

equipments.

(c) Solid Wastes

For sanitary wastes, adequate treatment and disposal systems will be used to minimize

any impact on environment.

Environmental Impact

Air Environment

Concentration of HC, CO & H2S is below limit of detection and that of SPM, Nox & SO2

is much below the permissible limits. Hence gaseous emissions have no impact on air

environment

Disaster management plan

To minimize the consequence of disasters due to the situations mentioned above,

Disaster Management Plans (DMP) have been prepared.

30

Drills and exercise

Regular drills are carried out to ensure that persons are familiar with their emergency

duties and can respond effectively.

Safety and environment management system

Policies and objectives

Safety & Environment Policies & Objectives have been formally adopted and brought to

the notice of all concerned.

Organization and responsibilities

Health Safety & Environment Management (HSE) Section of Hazira Plant is active for

implementation of company’s policies & objectives by operating groups.

Standards and procedures

The standards prescribed under the Environment Protection Act and its sub-ordinate

legislations and the stipulations of MOEF, issued in connection with environmental

clearance are followed in design and operation of offshore facilities.

Environment audit

In house and third party environmental audit is carried out.

Management review

Compliance with statutory requirements and company’s performance targets are

reviewed every month by the concerned Key Executives and Board of Directors.

Environmental clearance

Formalities for obtaining Environmental Clearance from MOEF will be obtained.

31

Engineering Consultant

Preparation of Tender and the project execution would be done by EIL on Open Book

Estimate (OBE) basis. Modifications/ Facilities work at Hazira is related to Down Stream

process such as fractionation, columns, etc and need very different experience criteria.

M/s EIL will be the nodal agency responsible for design/ engineering, Project

Management, ordering for materials and works, certification and handling contracts.

Execution of Work/ facilities related to modification work at Hazira Plant is proposed to

be done through M/s EIL on OBE mode of execution.

32

Risk Analysis and Mitigation Plan

Risk Factor Risk Perception Risk Analysis Proposed Risk

Mitigation

Execution Risks

Bidding

Process

As the award for

project contracts is

likely to be through

an elaborate bidding

process, delay in

process may affect

the schedule.

In the present case

the schedule of

completion of

facilities is very

challenging. Any

slippage in award of

contract from the

anticipated time may

result in large time

over run. Because if

platforms or

pipelines are not

installed by April

2016 as envisaged

then due to monsoon

it may to shift by one

season due to which

drilling of wells and

start of production

may get delayed.

To meet the schedule

of award the bid

package preparation

has started and it is

planned that NIT

would be issued

pending sanction.

However, award of

work would be done

after sanction.

Operation Risk

33

Transfer of

TCPP

complex

facilities to

ONGC

Any delay in transfer

of TCPP complex

facilities may affect

the production

schedule as well as

idling of newly

installed platforms

As the production of

well fluid from C-24

and B-12 fields is

planned to be taken

up to TCPP complex

for processing

compression and

transportation to

Hazira. Therefore

any delay in transfer

of TCPP complex

facilities may affect

the production

schedule as well as

idling of newly

installed platforms

The DGH has already

been informed and the

high level meetings of

JV partners are

proposed.

Change in

hand of

operatorship

The operating &

maintenance

philosophy of BG is

different from

ONGC’s.

Understanding of

equipments set up

by ONGC crew may

take little time.

There is no standby

philosophy for major

rotary equipments

like Process gas

compressors. This

may result in

bottleneck.

Frequent interaction of

ONGC crew with JV’s

team before JV

relinquishes the

operation would take

place.

Possibility of

continuing existing

maintenance contract

of critical equipments

with OEM may be

looked into.

34

Investment

approval

Delay in approval Investment approval

for this project by

ONGC Board is

required before

award of different

project contracts.

The approval

process to be

expedited to ensure

overall completion of

the Project by April

2016 as envisaged.

Any delay in

approval may have

adverse impact on

schedule of the

project which would

impact the project

cost and along with

delay in start of

revenue would

impact the NPV

adversely.

The approval process

is being expedited and

project is planned be

put to ONGC Board in

the in Aug. 2014 for

approval. After

approval of project in

this meeting the

timelines are expected

to be met.

Technology &

Specification

risk

ONGC is

understood to have

a robust process for

award of LSTK

Contracts and the

As indicated most of

the project

components being

standard in nature, no

significant

35

selected entity is

likely to have

technical

competence to

complete the project

as per technical

specification.

Most of the project

components being

standard in nature,

no significant

technological risks

are perceived for

this project.

technological risks are

perceived for this

project.

36

Capital Cost Estimates

Facilities

Cost Estimation

The facilities required for field development have been finalized in various MDT meetings.

Based upon the scope of work finalized by the MDT, Engineering Services has estimated

the cost as per the latest approved methodology for cost estimates and discussed below:

Modification in Hazira Facilities:

Based on IOGPT adequacy check report, detailed deliberations & discussions in house

the requirement for modifications at Hazira Plant has been worked out. As Hazira

Engineering Services does not have dedicated costing group and Costing cell at Offshore

Engineering Services does not have the cost data for onshore equipment involved, the

list of requirement along with relevant portion of IOGPT Adequacy Study Report was

forwarded to EIL for budgetary quote.

EIL has worked on the CAPEX estimation with both methods viz. OBE and LSTK method.

Accordingly, EIL provided their budgetary quote with CAPEX estimation based on both

the methods. The summary of budgetary quote by EIL is as follows:

The cost estimation on Open Book Estimates (OBE) mode of implementation works

out to be 374 Crores (with accuracy of ±20%) and schedule of implementation shall

be 27 months for Mechanical Completion from the date of NOA. The schedule

includes validation of adequacy study done by ONGC.

For implementation on conventional LSTK mode, the cost works out to be 418 Crores

(with accuracy of ±20%) and schedule of implementation shall be 35 months for

Mechanical Completion from the date of NOA. The schedule includes validation of

adequacy study done by ONGC.

From above summary, it is seen that by awarding the job through OBE mode of

implementation, there is saving in monetary terms (44 crores) and also on time (8

months).

37

Phasing of Expenditure

The phasing of expenditure considered for Hazira plant modifications is as under.

Year Phasing of Expenditure

Rs. Cr.

2014-15 20

2015-16 150

2016-17 204

38

Operating Cost Estimates

Estimation of Operating cost

Operating cost has been calculated as per the latest guidelines (PAS circular dated

24.01.2013) by segregating the total expenditure into fixed and variable components

considering the actual operating expenses for the year 2013-14 as a base. The variable

expenditure has been then multiplied by the physical activities.

The estimated maintenance cost of Tapti facilities before commencement of production

has been estimated to be Rs 65 Cr (Cost of Certification of Top Side and Jacket, TG

overhaul, TG Health checkup, certification of TCCP spur pipelines in SBHT pipeline

Certification cost, Surveillance certification cost and contractual services. The annual

repair and maintenance cost for TCPP/TPP facilities has been taken as Rs. 12.3 crore

per annum with standard escalation based on average expenditure of BPB process

complex.

The following components have been considered as Fixed Cost:

1. Staff expenditure

2. Pollution Control (MSV cost)

3. Insurance

4. Repair & Maintenance

The following components have been considered as Variable Cost:

1) Consumption of Stores & Spares

2) Transport expenses

3) Other Contractual Payments

4) Other Production expenditure

5) Transportation and Freight (TOG)

6) Gas Processing cost at Hazira Plant

39

Viability Analysis

The economic feasibility of the project has been assessed as per the existing guidelines

issued vide Circular No. DF/ND/PAS/390/2013 dated 24th Jan 2013.

The major assumptions are as under:

1. The base condensate price of 53.66 US$/bbl (2013-14) and gas price of 6.30

US$/MMBTU upto 2019-20 with escalation of 1 US$/MMBTU thereafter once in a

block of every 5 years has been considered as per present guidelines.

2. 97.5% of the total production for condensate and 97% of the gas has been taken for

estimation of revenue calculations.

3. The Gas has been considered after internal consumption. The average calorific value

has been considered as 9157 Kcal/m3 for C-24 and 8833 Kcal/m3 for B-12 .

4. Capital cost has been escalated @ 6% p.a. (only for Phase II)and Operating cost has

been escalated @ 8% p.a.

5. The hurdle rate considered is 14%

6. All calculations have been carried out in post-tax scenario. The corporate Tax has

been considered as 33.99%

7. The Royalty on gas has been considered as 9.09%. Education Cess and OIDB Cess

has been considered as 3% and Rs. 4500/MT respectively. NCCD has been taken as

Rs. 50 / MT. Well Head deduction have been taken as Rs. 947/ MT

8. The depreciation on facilities is considered @ 15% on WDV and additional 20% on

the fresh / new investments for the first year only and 100% for well cost.

9. The Exchange rate has been considered as 1 USD= Rs.59.71 (average of June 2014)

10. Abandonment cost for new facilities and wells to be added has been considered as

per the rates for 2013-14.

11. The abandonment cost of Tapti facilities has been assumed to be Nil/ on account of

JV

12. The Acquisition cost of Tapti facilities has been assumed at Zero Cost to ONGC

40

Over all completion of Project in different stages is planned as below:

Approval from PAC/Board : Aug. 2014

Hand over / Transfer of Tapti Facilities : Jan. 2016

Installation of Platforms, pipeline and modifications : April 2016

Modifications at Hazira Plant : Jan. 2017

Drilling and completion of Wells : March 2019

Start of Production from first well : April 2016