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1
MODIFICATIONS IN GAS AND CONDENSATE PROCESSING FACILITIES AT HAZIRA
PRE-FEASIBILITY REPORT
OIL & NATURAL GAS CORPORATION LTD.
2
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.
3
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.
4
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
5
(+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
6
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.
7
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
8
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
9
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.
10
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.
11
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
12
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.
13
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%
14
(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%
15
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.
16
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
17
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.
18
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.
19
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