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South Banskandi-GCS Facility and PLP Cachar Feasibility Report Confidential

ONGC, Cachar Forward Base, Silchar i

FEASIBILITY REPORT

South Banskandi-GCS Facility and PLP Cachar

Oil and Natural Gas Corporation Limited

March 2013

By

Team CFB

ONGC, Cachar Forward Base

Srikona, Silchar-788026, Assam

South Banskandi-GCS Facility and PLP Cachar Feasibility Report

ONGC, Cachar Forward Base, Silchar ii

Preface

Considering the opportunity that existed for ONGC to monetize surplus gas available in small quantities across a large geographical spread in the state of Assam and also the fact that some key private players were expressing eagerness to use this gas for the industrial growth of the state which is expected to gain momentum in the coming years, a Multi Disciplinary Team (MDT), comprising of officers from Assam Asset, Assam & Assam Arakan Basin, E&D Directorate, IRS, IOGPT and Corporate Marketing, was constituted by Director (Exploration) to look into the techno-economics of marginal fields of Assam vide order ref. no. ONGC/MKTG/70(4)/2009-10, dated 05.02.2010. The findings of the MDT Report have been approved by Competent Authority.

The committee members were:

1. Shri S N Das, DGM (P)-AM (Surface), Jorhat 2. Shri K K Roy, DGM ®-IRS, Ahmedabad 3. Shri N Asija, DGM (P)-Co-Opt Member, IOGPT, Panvel 4. Shri Sanjoy Goswami, CG-IRS, Ahmedabad 5. Shri Pradeep Kumar, M ®-E&D Directorate, Dehradun 6. Shri Anil K Gupta, SE (P)-IOGPT, Panvel 7. Shri M S Hiwale, CE (P)-Marketing Group, Delhi 8. Shri M P Kekre, SE (P)-Co-Opt Member, Silchar

The salient features of the scope of work of the committee were as under:

1. Explore the possibilities of bringing on production the untapped established gas resources

2. Generate optimized production profile with an inbuilt realistic input arrival plan 3. Adequacy checks for the available infrastructural facilities and project future

additional requirements/upgrading if necessary, for the processing and evacuation of the additional gas

4. Techno-economics of the project, preferably separate for each of the three sectors

5. Firm up commitment CT point-wise on gas production

This Feasibility Report is prepared based upon the findings of the above mentioned MDT. Addition of write-up beyond MDT report like 2D-3D studies and Model Review etc.


ONGC, Cachar Forward Base, Silchar iii

Table of Contents

Preface ii

1 Executive Summary 4

2 Introduction 6

3 Field Overview 12

4 Objective and Advantages of the Project 16

5 Design Basis and Input Parameters 17

6 Process Description 19

7 List of Equipment and Civil Work 29

8 Summary of Financial Analysis 33

9 Conclusion 40

List of Annexures

Annexure 1 (a-e) CAPEX Details 41-51

Annexure 2 (a-c) OPEX Details 52-54

Annexure 3 (a-b) Gas Profiles 55-56

Annexure 4 (a-c) Gas Pricing and Revenue Generation 57-59

Annexure 5 Hurdle Rate & Product Prices for Investment Proposals (DF/ND/PAS/390/2013 dated 24.01.2013)

60-66

Annexure 6 Abandonment Liability for Onshore Wells (DLI/CA/18(2)/2011-12 dated 03.04.2012)

67-68

Annexure 7 Viability Analysis 69

Annexure 8 (a-n) Sensitivity Analysis 70-83

Annexure 9 (a-d) Break Even Analysis 84-87

Annexure 10 Project Completion Schedule 88

Add List of Figures/ Plates


ONGC, Cachar Forward Base, Silchar 4

1. Executive Summary

Name of the Project South Banskandi-GCS Facility and PLP Cachar

Proposing Authority GM – Head Forward Base, CFB, Silchar

Sponsoring Authority Director (Onshore)

Executing Authority Cachar Forward Base, Silchar with Onshore Engineering Services (OES), New Delhi for LSTK project

Project Consultant a) OES, New Delhi b) IRS, Ahmedabad c) IOGPT, Mumbai

Nature of Project Integrated development and monetization of Banskandi Block-1 and Bhubandar Fields of Cachar Forward Base, A&AA Basin

Need of the Project Exploitation and Monetization of Natural Gas

Location of the Project Banskandi Block-1 and Bhubandar Fields of Cachar Forward Base, A&AA Basin, Silchar

Gas Production Envisaged 735 MMSCM in 15 years (….does not include production of well BUAE….annexure 3A and 3B)

Project Component a) Drilling of two additional gas producer wells in Bhubandar and two additional gas producer wells in Banskandi and re-activation of the wells BK-1 & BU-2

b) Land Acquisition and laying of about 35 Kms underground seamless pipeline with Cathodic protection for the entire length from Bhubandar Field to the new GCS at BK-1 well-site, including interconnecting pipelines of the 4 additional wells

c) One river crossing for the river Rukni by Horizontal Directional Drilling (HDD) with Intermediate Valve stations at both ends of river Rukni

d) Construction of GCS at BK-1 well-site

Product Evacuation Produced gas will be available to consumer from delivery point, viz. the New GCS at BK-1 well-site

Project Cost ` 16183.27 lakh (For Sanction ` 16380.52 lakh)



Completion Schedule October 2015

Cachar Forward Base has two potential wells viz., BK-1 in Banskandi field and BU-2 in Bhubandar field which are due for production since 1989 and 1995 respectively. In the present proposal those two wells located South of the Barak river are considered to be connected to a new GCS to be erected at BK-1 well-site of Banskandi field. With the execution of the project, the peak production from the GCS is expected to be 180,000 SCMD from 7 wells (including the exploratory well BUAE which is planned to be connected to the GCS on successful completion), although sales revenue calculations are based on average gas sales of 139,000 SCMD from 6 wells (excluding BUAE, as PAS guidelines suggest that production as well as the well cost of exploratory wells should not be considered for techno-economic feasibility analysis) for 15 years and sales price of 5.25 US$ / MMBTU with escalation @ 1 US$ / MMBTU once in a block of 5 years from 2020-21 and considering an exchange rate of 1 US$ = ` 53.77, with the assumption that the GCS will be commissioned by October 2015 with the development wells in place.

The basic process design, gas profile & decisive financial parameters are calculated as per the guidance of the MDT report approved by Director (Exploration) and endorsed by Director (Onshore) and Director (Offshore). The scope of work has been jointly worked out by Cachar Forward Base, Silchar and Onshore Engineering Services, Delhi, based on the MDT Report with modifications. The cost estimates of the entire project for deriving the CAPEX is provided by OES, Delhi.

The proposed project (Sanction Cost) of ` 16380.52 lakh (including cost of 4 new development wells) has an NPV at 14% = ` 1446.96 lakh and IRR = 17.08%. The proposal / FR meets the hurdle rate of 14% and hence is techno-commercially viable. However, since the realization of the project is dependent on the successful completion of the 2 new development wells in Bhubandar Field as suggested by IRS, Ahmedabad, hence, the process of releasing of development locations in Bhubandar Field and drilling of the same needs to be expedited.

The FR is submitted for further review and approval of Competent Authority.

(MUKUL CHANDRA DAS)



DATE: GM- HEAD FORWARD BASE



2. Introduction

2.1 Background

Cachar Forward Base, A&AA Basin, Silchar, had made two (02) gas discoveries in the form of wells BK-1 and BU-2 in the years 1989 and 1995 respectively. However, due to various reasons, like logistic problems, lack of surface facilities or lack of consumer demand, the wells could not be brought into commercial production till date. Nevertheless, in response to the current market demand, efforts have been initiated for monetization of these reserves. A brief historical perspective of the previous marketing efforts for the said gas fields is provided in the following sections.

2.1.1 In Banskandi field, 11 nos. of exploratory wells were drilled. Out of these only 3

exploratory wells were found gas bearing. They are BK-1 (Feb 1989), BK-2 (Mar 1990) and BK-6A (May 1993). BK-2 and BK-6A are at the north bank of the river Barak but BK-1 is at the south bank.

2.1.2 The wells BK-2 and BK-6A are connected to Banskandi EPS, which was commissioned in Feb 1997.

2.1.3 BK-1 being at the opposite side of the river could not be connected to the existing Banskandi EPS and kept sealed. The well had a reportedly sand cut problem during its initial testing. This well was planned for exploitation separately to cater gas to Silchar city and one feasibility report was submitted in June 1998. But the commitment to city supply depending on a single well was not much encouraged.

2.1.4 The development well BKDB (i.e. BK-11) was taken on drilling at the south of the river Barak in January 1996 and had to be prematurely abandoned due to blowout at very shallow depth-315 m during drilling as the well encountered unanticipated shallow gas sand.



2.1.5 Bhubandar is another field adjacent to the Banskandi field in the south of the river Barak. Total 4 nos. of exploratory wells are drilled in this field. Out of this only BU-2 was found gas bearing in October 1995. A proposal for making an EPS at BU-2 well site and to supply gas in the locality was tested feasible in Oct 2001 by IOGPT but this proposal was also strategically not much recommended.

2.1.6 Another holistic approach to join BU-2 and BK-1 with the existing system of Banskandi EPS was also studied during Oct 2001 by IOGPT. An additional EPS at the well site of BU-2 was proposed in the scheme. But the proposal was not feasible at the gas price of ` 1700 per 1000 SCM.

2.1.7 The same scheme was again reviewed by IOGPT at increased gas price of ` 1920 per 1000 SCM. The project was simplified by eliminating EPS in Bhubandar. The scheme was again found to be non-feasible. However, with the introduction of APM prices of gas, the project became viable with increased gas price of ` 4125 per 1000 SCM (base year 2008-09) escalating @ 4% per annum.

2.1.8 However, due to non-finalization of the GSA with the existing customer for this additional gas, the EC in its 367th meeting held on 28th & 30th April 2010, decided to cancel the project and advised that fresh tender may be taken up only after the conclusion of GSA and establishing commercial viability of the project.

2.2 Recent Developments

2.2.1 A Multi-Disciplinary Team (MDT) was constituted by Competent Authority to look into the techno-economics of the marginal fields of Assam including the consideration for Bhubandar and Banskandi gas profile. The MDT suggested that instead of connecting the wells BU-2 and BK-1 to BK-EPS, a new GCS facility may be considered at BK-1 and the well BU-2 should be connected to this GCS. To ensure the project viability and also the availability of gas for a long period, the MDT also suggested that one additional well may be drilled in Bhubandar and another additional well along with the released exploratory location BKAC (Banskandi PML) be drilled in Banskandi. The gas production profile had been generated based on a total of 5 wells including the drilled wells BK-1 and BU-2.



The MDT report has been approved by Competent Authority (annexed approval of competent authority).

2.2.2 In Oct 2005, BK-1 was successfully reactivated for performance study (with 3 mm, 4 mm, 5 mm bean) and there was no indication of sand cut problem. The well has reportedly sand cut problem during its initial testing with 6 mm bean which was not tried this time.

2.2.3 The other potential well, BU-2, was successfully reactivated for reservoir studies held from August 11-13th, 2009. SBHP recorded was 187.60 Kg/cm2 at measured depth of 1700 M and the same extrapolated to mid of sand face works out to be 188.21 Kg/cm2. The temperature recorded at measured depth of 1700 M was 69.01oC and when extrapolated to sand face, the same works out to be 70.31oC. The Absolute Open Flow Potential (AOFP) is around 0.18 MMSCMD with the value of n = 0.77.



Proposed Route for laying of pipeline from BU-2 to BK-1



2.3 Scope of work for the present project

2.3.1 Laying of 35 Km underground seamless pipeline from BU-2 to BK-1, including interconnecting pipelines of the 4 additional wells.

(…inter connection lines of other wells in Banskandi and Bhubandhar field from BU-2 and BK-1 is not shown in the map)

2.3.2 One river crossing for the river Rukni by Horizontal Directional Drilling (HDD). River crossing length is about 150 m.

2.3.3 Intermediate Valve stations at both ends of river Rukni.

2.3.4 Cathodic protection for entire 35 Km pipeline to prevent external corrosion.

2.3.5 Construction of GCS at BK-1 well-site which will broadly include a manifold, bath-heater, inlet separation, produced water handling and disposal and relief and blow down system.

Feasibility report is made based on the MDT report approved by Competent

Authority.

Total CAPEX (Sanction Cost) of the project is ` 16380.52 lakh (including cost of 4 new wells). (Annexures: 1) and OPEX is ` 21174.57 lakh. (Annexures: 2)

For a period of 15 years, the cash flow analysis has been done based on the revenue generation by the sale of gas and NPV @ 14 % & IRR works out to ` 1446.96 lakh and 17.08% respectively after tax. (Annexure:7)

Various sensitivity analyses have also been done forecasting different scenarios with multiple variants as per PAS guidelines in vogue and summarized in Annexures: 8



3. Field Overview

3.1 Banskandi Field

3.1.1 Total 14 wells have been drilled in Banskandi Field so far, out of which 11 wells are Exploratory and 3 wells are of Development category. However, three exploratory wells i.e. BK-1, BK-2 and BK-6A are proved to be gas bearing. However, two wells of development category i.e. BK-11 and BK-14 could not be completed due to blowout and stuck up complication respectively. (…status of another drilled development well BK-12…)

3.1.2 Well BK-1 is gas bearing in Upper Bhuban Lower Pay horizon and BK-2 is found gas bearing in Upper Bhuban Upper Pay horizon. Though Well BK-6A is gas bearing in both Upper Bhuban Upper Pay and Upper Bhuban Lower Pay, it is completed in Upper Bhuban Lower pay. The Upper Bhuban Lower Pay of BK-1 block, located south of Barak River and BK-6 Block, located on the north of Barak River is having separate gas-water contact.

3.1.3 The Banskandi field is spread on both sides of Barak River. The new GCS is proposed to be commissioned at BK-1 location on southern bank of the Barak River. The development well BK-11, located in the 1100 m SW of BK-1 was also drilled within the pool limit of Upper Bhuban Lower Pay of BK-1 block. This well has to be prematurely abandoned due to blowout at very shallow depth-315 m during drilling as the well encountered unanticipated shallow gas sand. Its objective was not fulfilled. Subsequently, a substitute location of BK-11 i.e. BKDB-A is released and planned to be drilled in BE 2014-15. Another exploratory cum development location i.e. BKAC, located about 1350 m NNE of BK-1 (within the Upper Bhuban Lower Pay pool limit of BK-1 Block) is also available for drilling.

3.1.4 The in-place volume of Upper Bhuban Lower pay for Block of BK-1 is 1054.1 MMm3 out of which 727.4 MMm3 is placed in PD category (corresponding



ultimate reserves 315.0 MMm3 in PUD category) and 326.6 MMm3 is in PS category.

3.1.5 The well BK-1 is in subdued condition due to lack of surface facilities. In the initial testing sand cut problem was reported using 6mm bean and was recommended for work-over job. The well was reactivated in October 2005 for reservoir studies. Three Bean Studies were carried out through 3, 4 & 5 mm to establish the AOFP and well deliverability. The results of bean studies are given below-

Bean mm

DOM m

THP Kg/cm2

BHP Kg/cm2

p Kg/cm2

Qg

m3/day Qcond

m3/day Qw

m3/day

S/I 1760 158.78 181.75 - - - - 3 1760 155.34 178.31 3.44 12062 - Nil 4 1760 148.45 174.29 7.46 17755 - Nil 5 1760 147.01 165.39 16.36 30773 - Nil

From the flow studies the AOFP and Well Deliverability was established by using PAN system software and also Ryder-Scott software. The estimated parameters are:

Parameters PAN system software

(pseudo pressure method) Ryder-Scott

software

AOFP, m3/day 89, 299 88,965

Well Deliverability, m3/day 13,395 13,345

AOFP ~89,000 m3/day

Well Deliverability ~13,350 m3/day (15% of AOFP)

3.1.6 In the present exercise, worked out by MDT (Gas Sale availability from untapped resources of ONGC in Assam-April 2010) the gas production profile of the block had been generated considering three wells, viz. the existing well BK-1, one released exploratory cum development location BKAC and a notional substitute location of BK-11 presumed to be drilled for the same target sand as BK-11. Based on the testing data of BK-1, initial gas production rate for each well has



been assigned as 20,000 SCMD and the profile was found to sustain for 24 years (terminal field gas rate: 33400 SCMD) with a cumulative production of 451 MMm3 (62% of PD GIIP i.e. 727.4 MMm3).

3.2 Bhubandar Field

3.2.1 Total 4 nos. of exploratory wells have been drilled in Bhubandar field so far. The well BU-2 was found gas bearing on testing in October 1995. The well is completed in Sand-I of the Upper Bhuban Formation. After the initial testing, the AOFP and well deliverability were computed as 270,000 SCMD and 54,000 SCMD respectively. However, the well was re-activated in August 2009 for detailed reservoir studies. During gradient study, the SBHP recorded was 187.60 Kg/cm2 at measured depth of 1700 m and the same extrapolated to mid of sand face works out to be 188.21 Kg/cm2 and the SBHP gradients are around 0.13 Kg/cm2/10m. During flow after flow test, the gas rate was 109,700 m3/d through 8 mm bean (correspond FBHP-130.81 Kg/cm2) & 75,800 m3/d through 6 mm bean (corresponding FBHP-155.76 Kg/cm2). The AOFP calculated after this reservoir study was 180,000 SCMD. The well could not be put on production till now because of its isolated location at the south bank of the river Barak. The well is located at around 30 KM south from Silchar city.

3.2.2 In the MDT report, in-place volume and cumulative field production from Sand-I of Upper Bhuban Formation was considered to the tune of 448.0 MMm3 & 358 MMm3 (80% of GIIP). Subsequent to that the Geological model for Bhubandar field has been revised as an outcome of integrated 2D-3D study of Bhubandar - Teidukhan area and reinterpretation of petro-physical data of BU-2. The changed GIIP and Ultimate Reserve of Sand-I (as on 01.04.2011) are 1381.1 MMm3 (942.1 MMm3 in Northern block & placed in PD category + 439.0 MMm3 in the southern block & placed in possible category) and 565.3 MMm3 (PDPB category) respectively. Additionally, 280.6 MMm3 of gas in-place (PS category) are also calculated for Sand-2 of Upper Bhuban Formation (for both Northern and Southern Block).

3.2.3 In the present exercise, the gas production profile had been generated by IRS for this block considering two wells, i.e. the existing well BU-2 and an additional location notionally placed towards WSW of BU-2 at the structurally



higher part. The gas rate per well is assigned as 60,000 SCMD. The profile is found to sustain for 11 years (although from the 7th year onwards the FTHP is maintained at the cut-off value of 15 Kg/cm2). The cumulative field production at the end of profile period is envisaged as 358 MMm3 (80% of PD GIIP of 01.04.2011).

3.3 Combination of BK-1 reserve and BU-2 reserve

3.3.1 In the proposed plan, South Banskandi and Bhubandar located around 23 KM apart will be exploited through 6 wells connected to the proposed GCS located near well No. BK-1. The GCS is planned to handle about 0.18 MMm3/d gas and is projected to be commissioned by October 2015 at a projected cost of ` 3226.90 lakh.

3.3.2 As directed by IRS, total four additional development wells (2 wells in Banskandi field and 2 wells in Bhubandar field) are proposed to be drilled to ensure project viability and also to ensure availability of gas for a long period. However, only two development locations in Banskandi Field are being released till date.

3.3.3 Another exploratory well, viz., BUAE is also planned to be drilled in Bhubandar Field. The well will be connected to the GCS if it is found to be commercially exploitable. However, in the present exercise, the well cost as well as production profile of the well has not been considered in the capital cost estimates and revenue generation figures as the well is exploratory in nature.

3.3.4 The interconnecting pipelines of 3.5” dia. size for the six wells having a cumulative length of 35 KM needs to be laid before the projected RFP at a projected cost of ` 792.95 lakh. This does not include the cost of the land for pipeline laying. Another 1.5 KM pipeline of 2” dia. for effluent disposal is also required to be laid at a cost of ` 30 lakh.

3.3.5 The peak production from four wells in Bhubandar Field and three wells in Banskandi Field is 120,000 SCMD and 60,000 SCMD respectively. The gas profiles are based on AOFP estimates made through the initial testing data, and the yielded recovery is 80% and 62% respectively. However, Banskandi having a low



potential reservoir has an extended production profile of 24 years, though for economic analysis the profile period is limited to a maximum of 15 years.



4. Objective and Advantages of the Project

4.1 Objective of the Project

To monetize the untapped established gas resources of Cachar Forward Base, Assam Arakan Fold Belt area.

4.2 Advantages of the Project

4.2.1 In the present scheme, 150,000 SCMD gas will be offered on fall-back basis to the consumer for a period of 15 years, i.e. up to 2029-30.

4.2.2 On average ` 4960.46 lakh sales revenue will be earned per year on a sustained basis.

4.2.3 Utilization of the gas for power generation purposes will help to alleviate the power crisis of this region to some extent.

4.2.4 There will also be the focus to develop the south side of the river Barak in Banskandi as well as in Bhubandar.

4.2.5 Augmentation of gas production will always help in building the corporate image of ONGC in Cachar district and in Assam as well.



5. Design Basis and Input Parameters

The basic design basis and input parameters are taken as per the guidance of the MDT report approved by Competent Authority. The scope of work has been jointly worked out by Cachar Forward Base, Silchar and Onshore Engineering Services, Delhi.

Following are the basis and input parameters:

5.1 Reservoir study report of well BU-2 (August 2009) and BK-1 (October 2005).

5.2 Re-estimated production profile for Gas Fields of Cachar Forward Base provided by IRS, Ahmedabad calculated on the basis of 3D-Seismic Data Acquisition.

5.3 The proposed GCS at BK-1 well-site will receive well fluid from BU-2 (+ 2 well) and BK-1 (+ 2 wells).

5.4 GCS shall be designed to handle 180,000 SCMD gas and 20 M3/day liquid (water 18 M3/day and condensate 2 M3/day).

5.5 Inlet battery limit conditions are:

5.5.1 Gas Pressure 135 Kg/cm2 5.5.2 Gas Molecular Weight 16.5 5.5.3 Gas Temperature 26oC 5.5.4 Liquid 20 M3/day

5.6 Outlet battery limit conditions are:

5.6.1 Gas to consumer 20 Kg/cm2 at 20oC 5.6.2 Effluent To Surface Disposal after ETP 5.6.3 Condensate To tanker by gravity

5.7 Following systems will be part of the GCS facility



5.7.1 Separate Inlet Manifold for 3 Banskandi wells and 3 Bhubandar Wells 5.7.2 Bath Heater 2 nos. 5.7.3 Inlet Separation – 180,000 SCMD, Operating Pressure – 20 Kg/cm2 5.7.4 Instrument gas scrubber 5.7.5 Degasser Vessel 5.7.6 Gas measurement for flare and supply to customer 5.7.7 Flare system with KOD, water seal and ignition system 5.7.8 Storage Tanks 2 nos. 5.7.9 ETP, OWS Pit and CBD

5.8 The U/G pipeline to be laid from various wells of Bhubandar field to the GCS is designed for handling a maximum flow rate of 120,000 SCMD of gas at a pressure range of 135-150 Kg/cm2.

5.9 As the pipeline has to cross the river Rukni on its route, the same has to be done through HDD and intermediate valve stations have to be provided at both ends of the river.



6. Process Description

6.1 General Process Description of the GCS Well fluid from Bhubandar and Banskandi wells shall be collected in two separate Inlet Manifolds at the GCS. Each header shall be routed to Indirect Water Bath Heaters to heat-up the well fluid up to 35oC or more so as to avoid any hydrate formation likely to occur during pressure drop. The heated well fluid shall be routed to gas separators. The liquid outlet from gas Separators shall also be connected to Degasser through PRV or Choke Valve. The separated gas from both Separators will flow to the Metering Skid (for metering through Ultrasonic Flow Meter) for onward supply to consumers and to fuel gas conditioning skid. The gas manifold shall be provided with Pressure Control Valve to divert excess gas to flare during process upset or during sudden reduction of gas consumption by the consumers. Also, Blow Down arrangement for release of gas to flare during shut-down, shall be provided. The liquid, consisting of condensate and water from Separators will flow to Degasser and then get stabilized in Condensate Stabilizer before draining to Storage Tank. Gas from Degasser shall be routed to Flare through KOD. The stabilized liquid will flow to main Liquid Storage Tanks where the condensate and water will be separated out. The condensate, after metering (through Coriolis type meter) will be loaded in tankers using Condensate Loading Pumps. The separated effluent/water from Liquid Storage Tanks will be pumped through effluent header of Condensate Tank Outlet Manifold using Effluent Transfer Pumps to Effluent Storage Tanks. The Effluent Transfer Pumps shall also be used for routing raw effluent/water separated out in Liquid Storage Tanks and Effluent Storage Tanks to Modular ETP, via Raw Effluent Manifold. The effluent from Effluent Storage Tanks will be sent to evaporation pit. The condensate separated in Effluent Storage Tanks shall be pumped to Condensate Inlet Manifold using Condensate Transfer Pumps.



Loading Arms will be used to load condensate and effluent water, respectively, to the tankers. The condensate tanker loading facility shall be provided with batch-controller & associated instrumentation. All vessels shall be provided with Safety Relief Valves which are set at 10% above the maximum operating pressure. During over pressurization, the excess gas will be released to the Flare Header through these valves. The bypass line of the Safety Relief Valves shall have lock and key provision and will be used for manual depressurization of the individual vessels as and when required. All vessels shall be provided with Pressure Control Valves in flare line to release the excess gas to flare. The elevated Flare Gas Header shall be routed to Flare KOD. The flare gas will be metered using Ultrasonic Flow Meter before flowing to Flare Stack through water seal where it will be burnt-out at a safe height. The height of the Flare Stack should be 30 meter as minimum. The water level will be maintained using the water from Flare Seal Water Tank. Flame Front Generator shall be provided to keep the pilot burner ignited so as to prevent release of hydrocarbons to the atmosphere without burning. Liquid separated from Flare KOD will be pumped to Condensate Tank Inlet Manifold using KOD pumps. For fire suppression, Fire Water Tanks, Diesel Engine/ Electric Motor-driven Fire Water Pumps, Deluge Valves and Fire Water Sprinkler System shall be provided.

6.2 System/Equipment-Wise Description

6.2.1 Multi Bean Variable Choke System in Well Site

In the present scheme no EPS is considered at Bhubandar. As the well BU-2 is of high pressure (FTHP = 150 Kg/cm2) in nature the line is also designed for a normal operating pressure of 150 Kg/cm2. There is always a possibility of hydrate formation and hence flow restrictions at the well site itself due to high pressure scenario. Hence multi bean systems are proposed in the well site for gradual decrease in pressure. Variable choke will help for better operation.



6.2.2 River Crossing and Maintenance of the Line

There is one river crossing on the Pipeline route and there should be one stand by line in the river crossing such that periodic maintenance of the section of the line under the river can be done without any flow interruption to the consumer. The whole line will be properly coated and cathodic protected.

6.2.3 High Pressure Inlet Gas Manifold

Total 6 wells are planned to be connected to the GCS. The 3 wells in Banskandi Field are namely BK-1, the development well BKDB-A and the exploratory-cum-development well BKAC. Similarly, the 3 wells in Bhubandar Field are BU-2 and the two envisaged development wells to be drilled in the 1st and 13th year of the project. Well fluid received from the Bhubandar Field shall be combined at BU-2 and the 3 ½“ x 23 km pipeline shall carry entire Bhubandar well fluid to Bhubandar Train at the GCS. On other hand, Banskandi well fluid inlet manifold at the GCS shall collect well fluid from BKDB-A, BKAC and BK-1 to further process Banskandi well fluid in a separate train. The two separate trains shall process gas and condensate from Bhubandar and Banskandi fields respectively with each train consisting of one IDBH, one Separator and one custody transfer meter at the outlet for gas to consumer. Bhubandar - Individual well flow lines from BU-NEW1 (4 km) and BU-NEW2 (3.5 km) shall be routed to BU-2 local well location to a common header and then 3 ½“ x 23 km pipeline shall carry entire BU well fluid to BU train at BK GCS inlet manifold to be constructed in present scope.

Banskandi - BK-1, BKAC (2.5 km) and BKDB- A (2 km) shall be connected to new manifold at the GCS. The production manifold shall also have provision (isolation valves with blind flanges) for future hook-up of one additional well flow line. These wells have FTHP in the range of 135-150 KSC.



6.2.4 Indirect Water Bath Heaters

In the present scenario, to avoid hydrate formation, the manifold facility shall be provided one Bath Heater in each Banskandi and Bhubandar Headers to heat the natural gas before reducing the pressure by self-regulating PRV / Choke. The line consisting of Bath Heater and self-regulating PRV / Choke shall be provided with line size 6”. This will be done before the gas is directed for further processing or testing. Indirect Water Bath Heaters shall be provided for heating of well fluid from Banskandi and Bhubandar header to prevent hydrate formation, if any. The Bath Heaters will heat the well fluid from 14oC to 35oC. Fuel gas from Fuel Gas Manifold (downstream of Fuel Gas Conditioning Skid) will be used for heating water to achieve the desired gas temperature as stated above. The Bath Heaters shall be provided with following instrumentation items on well fluid line - local PI and TI at inlet and outlet, PT at inlet and TT at inlet and outlet. Differential pressure switch low (PDSL) shall be provided across Bath Heaters to actuate Inlet Shut Down Valves in case of tube rupture/ leakage. Temperature Switch High (TSH) shall be provided on well fluid outlet line to cut-off fuel gas to Bath Heater, in case of over-temperature. Pressure Safety Valves (PSVs) at Well Fluid Outlet Line shall protect line for over-pressurization due to trapped well fluid within the Bath Heater. Service Water Line with isolation valve shall be provided for filling/ topping-up bath heater. The signals from instruments shall be hooked-up to HMI (PC based PLC System) in control room. The signal from TTs at Bath Heater inlet and outlet shall also be hooked-up to Telemetry Interface Cabinet (TIC). The Bath Heaters shall be provided with instrumentation & equipment data sheets. Heated well fluid from HP and Test Bath Heaters will flow to HP and Test Separators, respectively. Well fluid from MP header will flow directly to MP Production Separator.



6.2.5 Inlet Separation System

Two 2-Phase Vertical Separators shall be provided in each train. Pre-heated well fluid from the individual Bath Heaters for Bhubandar and Banskandi inlet manifolds shall be routed to their respective 2-Phase Group Inlet Separators where the liquids will be separated from the gas stream. The separated dry gas, estimated at around 180,000 SCMD, will go to the customer after metering. These lines will be 6” size and will have Control Valves. The remaining gas will be sent to flare through a 6” line. The separated liquid, estimated at around 20 M3/day, will go to Degasser Vessel through control valve. Separator shall have level and pressure sensing control instruments.

6.2.6 Liquid Handling and Disposal System

The liquid separated in the two Group Inlet Separators will be sent to the Flash Drums or the Degasser, where the dissolved gases and vapour will be flashed from the produced water and condensate. The separated vapour will be sent to the flare system. The separated liquid will be sent to 2 nos. overhead liquid storage tanks of 45 M3 capacities each. Water will be routed to Effluent Treatment Plant (ETP) while condensate accumulated over a period of time will be evacuated by tankers.

6.2.7 Gas Metering System

The gas from Banskandi and Bhubandar Fields will be supplied to the customer through two separate gas metering systems. Two gas Custody Transfer Meters (Orifice Meters with Flow Computers) will be used to measure the flow rate of the gas from the two fields. An ultrasonic flare meter will used to measure the flared quantity of gas.

6.2.8 Process Control and Monitoring System

The process control and monitoring system will be PC-PLC based. Separate PLCs will be provided for control functions and ESD functions. F&G PLC will also perform Fire and Gas logic. Process control and monitoring will be carried out from the control PLC. All plant safety shutdown and interlocks will be carried out



by PLC based system to execute the interlock requirement. All pre-alarms for Level (including inter-face), Pressure & Temperature will be provided with indications at control panel & the same shall be finalized during approval of P&IDs.

6.2.9 Safety Relief and Flare System

All the pressure vessels will be provided with a pair of Safety Relief Valves fitted with lockable Full Close/ Full Open Block Valves. The Safety Relief Valve will be set at 10% above the maximum operating pressure of the vessels. During over pressurization, the excess gas will be released to the flare header through these valves. The lockable bypass line of the safety relief valves will be used for manual depressurization of the individual vessels as and when required. A flare system will be provided for safe disposal of flammable toxic or corrosive gas/ vapours discharged by pressure relief system of various units. The flare system shall consist of - Flare Header, Flare KOD, Flare Seal Water Tank, Flame Front Generator, Flame Pilot Burner, Flare Stack, Flare Tip, etc. along with associated piping and instrumentation system. The flare system will be designed with a flow capacity of 180,000 SCMD. The safety valve discharge from process vessels / tanks shall be connected to flare header. In case, pressure exceeds set pressure in process vessel(s), the escaped gas will flow to flare header. The liquid contained in flare gas will get separated in Flare KOD which will be operated at 0.5 kg/cm2g. The liquid will be pumped from Flare KOD to Condensate Storage Tanks by Flare KOD pumps. The gas will flow to flare stack for burning before discharge to atmosphere. All discharges to flare header shall be kept sloping towards the Flare KOD. Necessary care shall be taken so that bottom of the KOD is sufficiently higher than Finished Ground Level (FGL). Total gas flared from Flare KOD will be measured by the ultrasonic flow meter. Liquid separated from flare KOD (90% water) shall be drained to Evaporation Pit manually. Gas from Fuel Gas Header will be used as fuel in the pilot burner. The quantity of gas flared shall be metered using Ultrasonic Single Path Flow Meter (with pressure and temperature compensation) with integral smart transmitter,



electronic type local flow indicator with flow rate meter, totalizer, recorder, etc., in control room. The height of Flare Stack shall be kept at minimum height of 30 meters. Flare Stack shall be provided with davit(s) for lowering flare tip and thermo-couple devise (along with associated instruments, cables etc.) for maintenance. Aviation light shall also be provided on the Flare Stack. The Flare Stack shall not contain any manual valve, at least not for flow meter isolation. The Flare Stack and davit structure will be painted by high temperature resistant paint. Flare system design shall be as per latest API RP 521. The Contractor shall also comply with other latest applicable statutory / central/ state govt. guidelines such as OMR-1984/ CPCB/ OISD-106, 118 etc. on safety/ environmental standards. In case of any conflict, the more stringent requirement shall be followed. All discharges into flare header shall be designed to eliminate any liquid pockets. Any branch connection / tapping in the flare header shall be taken from twelve o’clock (top) position to avoid collection of liquid.

6.2.10 Electrical Power Supply System

Power supply will be taken from nearby Assam State Electricity Board (ASEB) grid line. An 11 KV/0.415 KV step-down transformer will be installed within the GCS for this purpose. Normal and peak load requirement will be met from ASEB power supply. For emergency purposes like grid failure or load-shedding, 1 no. Diesel Generator of 63 KVA capacity will be installed.

6.2.11 Fire Fighting System

For fire suppression, 2 nos. RCC fire water tanks of capacities 500 M3 each, 1 no. diesel engine driven pump and 2 nos. electrical fire-water pump having capacities of 60 M3/hr at 10.5 Kg/cm2 each, deluge valves, 2 nos. jockey pumps of capacities 10.5 M3/hr at 10.5 Kg/cm2 each and fire water sprinkler system will be provided. Fire fighting system will also consist of portable fire extinguishers, hose reels, etc.



6.2.12 Diesel Storage and Transfer System

A diesel storage tank of 15 M3 capacity will be provided to supply diesel to diesel engine driven fire water pumps and DG-Set. The diesel transfer system will also include diesel tanker unloading facility and 2 nos. diesel transfer pumps of capacities 1 M3/hr at 3-4 Kg/cm2 each. The same pumps will be used for unloading diesel from tanker as well as transfer of diesel to the diesel engine driven fire water pumps and DG-Set from the storage tanks.

6.2.13 Service Water System

Raw water from 1 no. bore well will be pumped with the help of 1 no. bore well pump of capacity 20 M3/hr into an RCC raw water storage tank of capacity 80 M3. From there the water will be pumped by a transfer pump to the softening plant of capacity 10 M3/hr from where the treated water will be transferred to RCC treated water storage tank of capacity 80 M3. The treated water will then be transferred to 2 nos. O/H HDPE storage tanks (one for residential accommodation and one for office building) of capacities 2 M3 each by transfer pumps. From raw water storage tank outlet manifold, the raw water will also be supplied to Fire Water Tanks.

6.2.14 Closed Blow Down System

Condensate is highly volatile & flammable and hence, a blow down vessel shall be provided below grade for receiving process drains through closed drain header from manifolds, bath heater, separators, stabilizers, gas scrubber, flare KOD, condensate storage tanks, test storage tank, etc. during maintenance, shutdown, etc. All the level instrument drains and pump casing drains shall also be connected to blow down vessel. The accumulated liquid will be pumped to condensate tank inlet manifold using top mounted submersible pumps.

6.2.15 ETP System

Water separated in the GCS shall have some residual hydrocarbon which shall have to be separated to acceptable level before disposal to river. The suggested scheme for effluent treatment is suggested by IOGPT. The scheme shall be



further developed by LSTK to ensure outlet parameter conforming to CPCB for river disposal.

6.2.16 Open Drain System

The Open Drain System shall consist of - Open Drain Header, OWS Pit and OWS pit pumps. An open drain header shall be routed throughout the plant for receiving drain water from GCI storage tank, gas scrubbers, vessels, lines, pumps etc. An OWS pit shall be provided below grade for receiving the open drain water. The accumulated water will be pumped to ETP using OWS pit pumps.

6.2.17 Storm Water Drain System

Suitable storm water drain system shall be designed by the Contractor based upon contour survey, etc. Direction of storm water discharge shall be as per natural drainage of the plot area. This storm water drain system shall be provided for the entire plant.

6.2.18 Potable Water System

An RO plant of capacity 200 litres/day has been considered for potable water system.

6.2.19 Buildings, Roads and Sheds

The buildings (within the plant area) will include office/administrative building, electrical sub-station building, security cabin and Control Room building and Emergency Diesel Generator building.

6.2.20 Land Development As the proposed land is fairly flat, minimal earth-cutting/filling and site grading will be required over the process, operational functional areas and the areas earmarked for residential/site accommodation facilities. Construction of boundary wall will be done all along the boundary of the plant layout area. Sheds will be provided for Firewater Pump house, DG set and metering skid.



7. List of Equipment and Civil Work

7.1 List of Process and Mechanical Equipment:

Sl. No.

Equipment Name Capacity/Size Quantity

1 Bath Heater Gas: 180,000 SCMD Liquid: 20 M3/day

02

2 2-Phase Vertical Separator Gas: 180,000 SCMD Liquid: 20 M3/day

02

3 Degasser Gas: 200 SCMD Liquid: 20 M3/day

01

4 Flare KOD Gas: 180,000 SCMD Liquid: 20 M3/day

01

5 Flare Stack Gas: 180,000 SCMD 01 6 OWS Pit Pumps 1 M3/hr; 2-3 Kg/cm2 1+1 7 Instrument Air Receiver 30 M3/hr; 8 Kg/cm2 01 8 Jockey Pumps 10 M3/hr

10.5 Kg/cm2 1+1

9 Fire Fighting Pumps 2 Electric driven 1 Diesel driven

60 M3/hr 8 Kg/cm2

2+1

10 Flare KOD Pumps 1 M3/hr; 2-3 Kg/cm2 1+1 11 Fire water storage tank 500 M3 01 12 CBD Vessel 20 M3/day 01 13 CBD Pumps 1 M3/hr; 2-3 Kg/cm2 1+1 14 Produced water tank 45 M3 01 15 DG-Set 63 KVA 01 16 O/H Condensate Storage Tanks 45 M3 02 17 Diesel Storage Tank 5 M3 01 18 Diesel Transfer Pumps 1 M3/hr; 3-4 Kg/cm2 02 19 OWS pit 01 20 Air Compressor 1+1 21 Bore Well Pump 20 M3/hr 01 22 Chain Pulley Block 5 Ton

2 Ton 1 Ton

01 01 01

23 Softening Plant 10 M3/hr 01



7.2 List of Electrical Equipment:

Sl. No.

Item Description Unit Qty. in Nos.

1 11 KV Outdoor 4-pole structure, DO switch, Lightening Arrestor, etc.

L.S. 1

2 Distribution Transformer 11 KV/0.415 KV, 100 KVA

No. 1

3 NGR for transformer Nos. 1 4 PMCC 250 A MCCB Incomer No. 3 Star Delta Starter for 37 KW Motor No. 2 7.5 KW DOL Starter No. 15 125 A MCCB No. 2 63 A MCCB No. 8 5 High Mast Light No. 2 6 Area Lighting 10000 M2 2 7 LT Power & Control Cables including cable trays L.S. 1 8 110 V DC battery charger, BB & DCDB for 30

minutes back-up No. 1

9 110 V-5 KVA UPS, BB & ACDB for instrumentation 60 minutes back-up

No. 1

10 Switch Gear room 5 M x 7 M internal electrification including fittings and fixtures

L.S. 1

11 Lighting Transformer 25 KVA, 415 V/230 V Ph-Ph No. 2 12 Lighting Distribution board/MLDB No. 1 13 Auxiliary Switch Board No. 1 14 Earthing & Lightening Protection L.S. 1 15 CP system for pipeline No. 1



7.3 List of Civil Work:

Sl. No.

Item Proposed Civil Work

1 Site Grading Land filling of 40 M x 30 M x 0.5 M 2 Storm Water Drainage To be developed within the battery limit 3 Roads/Footpaths Total road length of approx. 700 M 4 DG-Set Shed of size 8 M x 8 M x 5 M to be provided along

with arrangement for chain pulley 5 Diesel Storage Tank +

Pumps Shed of size 5 M x 5 M x 5 M to be provided along with provision for truck entry and civil work for pumps, etc.

6 CBD Vessel + Pump RCC Pit of size 8 M x 5 M x 3 M and civil work for pump, pit to be covered with AC sheet roofing

7 Manifold (5 Wells) Civil work for manifold area of 10 M x 10 M 8 Separator (2 nos.) 25 M x 20 M RCC paving area and elevated

platforms for proposed separator 9 Bath Heater (2 nos.) 15 M x 10 M RCC paving area and necessary

elevated foundations for bath heater 10 Fire Water Pumps Shed of size 10 M x 10 M x 5 M to be provided

along with arrangement for chain pulley, foundation to be provided for pumps

11 Fire Water Tanks Civil work for 2 x 500 M3 RCC tanks, the periphery of the tanks at FGL will be paved with RCC (1 M width)

12 Office Building 3 rooms of sizes 12 ft x 12 ft, 12 ft x 10 ft and 12 ft x 6 ft

13 Living Quarters For 10 personnel 14 Watch Towers Civil work for 2 nos. watch towers 15 Security Cabin Civil work for Security Cabin of size 3 M x 3 M 16 Main Gate Civil work for Main Gate of size 7.5 M x 1.25 M 17 Emergency Gate Civil work for Emergency Gate of size 7.5 M x

1.25 M 18 Parking Shed of size 10 M x 4 M x 3 M to be provided 19 OWS Pit (100 M3) RCC pit of size 10 M x 5 M x 2 M



20 OWS Pump Civil work for pump foundation and canopy of size 3 M x 3 M x 3 M

21 Bore Well + Pump Drilling of 1 bore-well, civil work for room of size 3 M x 3 M x 3M with provision for pulling in/out of submersible pump and pipes

22 Raw Water Tank Civil work for 80 M3 RCC tank, 1 M periphery of the tank will be RCC paved

23 Water Softening System 24 Treated Water Tank Civil work for 80 M3 RCC tank, 1 M periphery of

the tank will be RCC paved 25 O/H Water Tanks (HDPE) One for office building and one for living quarters 26 RO System Capacity of 200 litres/day 27 Flare Stack Civil and structural work for RCC paving of 30 M x

30 M, foundation for flare stack and erecting of flare stack of height 30 M

28 Flare KOD + Pumps Civil work for flare KOD and pump foundations 29 Boundary Wall Boundary wall of 730 M to be provided 30 Pipe/Cable/Inst. Support Civil work for various pipe/cable/inst. supports 31 Green Belt Development of green belt for unused area of

total area 225 M x 140 M 32 O/H Condensate Storage

Tanks Support structure for the tanks along with dyke walls

33 Degasser Civil work for foundation of degasser 34 ETP Design and construction of ETP (20 M3/day liquid

handling capacity) of size 780 M2



8. Summary of Financial Analysis

8.1 Capital Cost of the Project 8.1.1 The creation of following facilities are being envisaged in the FR;

a) Gas Collection Station b) Effluent Treatment Plant c) Pipeline-2” Dia. 1.5 KM d) Pipeline 3.5” Dia. 35 KM e) Right of Use of land for laying of pipelines for 36.5 KM

8.1.2 The cost estimates (evaluation purpose) as per Onshore Engineering Services,

New Delhi have been adopted for the following: a) South Banskandi GCS (including ETP) : ` 3226.90 lakh b) Pipeline-2” Dia. 1.5 KM : ` 30.00 lakh c) Pipeline 3.5” Dia. for 35 KM : ` 792.95 lakh

8.1.3 In addition, land cost for laying of pipeline as informed by Revenue Authority for

six villages amounting to ` 130.45 lakh has been included in the cost estimates, which were informed in the year 2007-08 for six villages and not for seven villages as required for laying of pipeline from BU#2 to BK#1. The cost of 7th

village has been worked out on pro-rata basis. The arrived figure for seven villages has been escalated by 6% p.a. considering 2007-08 as base year. The details of Capital Expenditure workings are placed at Annexure-1.

8.1.4 The production profiles of following wells are being considered in the FR: a) BK-1 (Exploratory Well already drilled in 1989 and Capped) b) BU-2 (Exploratory Well already drilled in 1995 and Capped) c) BKDB-A (Development Well to be drilled in 2014-15) d) BKAC (Exploratory cum Development Well to be drilled in 2014-15) e) BU-NEW1 (Development Well to be drilled in 2015-16) in Bhubandar f) BU-NEW2 (Development Well to be drilled in 2026-27) in Bhubandar, in

the 13th year of the project life cycle

Another Well BUAE (Exploratory Well to be drilled in 2013-14) has not been considered in the FR being exploratory in nature, i.e., the well cost as well as



production profile of the well has not been considered in the capital cost estimates and revenue generation figures respectively.

8.1.5 Exploration cost, which has already been incurred, is considered sunk cost, thus costs of these two wells, viz., BK-1 and BU-2 have not been included in the capital cost component of FR. However, the profiles of the two wells have been considered for revenue calculations.

8.1.6 The per meter costs of two recently drilled wells in Cachar Forward Base, Silchar, i.e., PTAA & BCAA works out to ` 1.36 lakh & ` 1.39 Lakh respectively, thus per meter cost of ` 1.40 Lakh has been considered for working out the Well Cost estimates as per their respective depths. The same is tabulated below:

Well Name Depth In Meter Well Cost (` in Lakh) BKDB-A 2000 2800 BKAC 2450 3430 BU-NEW1 2000 2800 BU-NEW2 (13th Year) 2000 2800

Total 11830

8.1.7 The Abandonment Cost of wells as per Circular No. DLI/CA/18(2)/2011-12 dated 03.04.2012 (381/2012) issued by Corporate Accounts Section, New Delhi for 4 wells has been considered in the FR. An amount of ` 24,79,995/- per well net of salvage value totalling to ` 99.20 Lakh for 4 wells as per circular applicable for Silchar has been adopted. A copy of the circular is placed at Annexure-3.

8.2 Operating Cost Estimates 8.2.1 The following parameters and assumptions have been considered for working

out the operating cost estimates and have been tabulated as under:

Heads Methodology ` in Lakh Nature Mandays Cost, Officers

Salary has been considered for 4 officers @ ` 20 lakh/Year on incremental basis

80.00 Fixed



Mandays Cost, Staff

Salary has been considered for 8 staff personnel @ ` 12.00 lakh/Year on incremental basis

96.00 Fixed

HSE Cost HSE Cost has been considered as 0.1% of total 6 wells cost (4 to be drilled Wells + 2 Already Drilled Exploratory Wells) and 1% of Facilities Cost excluding land cost

53.57 Fixed

Insurance 0.11% of total capital expenditure excluding land cost

18.83 Fixed

Repair & Maintenance

1% of total capital expenditure excluding land cost

171.17 Fixed

Consumption of Stores & Spares

Consumable Expenses has been considered as 0.1% of total 6 wells cost (4 to be drilled Wells + 2 Already Drilled Exploratory Wells) and 1% of Facilities Cost excluding land cost

53.57 Fixed

Other Contractual Payments

Other Contractual Payments has been considered as 0.1% of total 6 wells cost (4 to be drilled Wells + 2 Already Drilled Exploratory Wells) and 1% of Facilities Cost excluding land cost

53.57 Fixed

Transport Expenses

The cost per unit / MMSCM for FY 2011-12 worked out to ` 120419, which was escalated @ 8% to arrive at present value for Base Year 2012-13 and then multiplied with the year wise projected production

Variable

Light, Power, Fuel & Water Charges

The cost per unit / MMSCM for FY 2011-12 worked out to ` 29100, which was escalated @ 8% to arrive at present value for Base Year 2012-13 and then multiplied with the year wise projected production

Variable



8.2.2 The actual cost of BK-1 is ` 576.93 lakh, which has been escalated @ 6% p.a. for 24 years for arriving at the present value of the well cost for working out the operating expenditure for the said well. The rig release date of the well was 02.03.1989, thus 1988-89 has been considered as base year and thereon escalated for 24 years to arrive at the present value for 2012-13 year, which works to ` 2336 lakh.

8.2.3 Similarly, the actual cost of well BU-2 has been worked out based on cost per meter of BU-1 Well and thereon escalated @ 6% p.a. for 17 years for arriving at the present value of the well cost for working out the operating expenditure for the said well. The rig release date of the well was 28.09.1995, thus 1995-96 has been considered as base year and thereon escalated for 17 years to arrive at the present value for 2012-13 year, which works to ` 1702 lakh.

8.2.4 The production in Cachar Forward Base, Silchar is very low (almost negligible) compared to other ONGC work centers, thus per unit cost of production is very high. It is pertinent to mention that considering per unit cost for working out the operating cost estimates is not rational as the current cost of CFB is being added to the new project operating expenditures.

8.2.5 The well, i.e., BU-NEW2, development well is planned to be drilled in 2026-27 in Bhubandar, in the 13th year of the project life cycle; the operating expenditure for the same has also been considered from the 13th year of the project life cycle.

8.2.6 In the current feasibility report, both fixed and variable nature of operating cost estimates have been escalated @ 8% p.a. as per prevailing project appraisal guidelines totalling to ` 21174.57 Lakh for 15 years project cycle. The base year adopted for escalation of operating cost estimates is 2012-13. The details of Operating Expenditure workings are placed at Annexures-2.

8.3 Gas Price & Exchange Rate 8.3.1 An APM Gas Price of USD 5.25/MMBTU w.e.f. 2015-16 as per prevailing project

appraisal guidelines has been adopted, which has been escalated @ 1



US$/MMBTU once in a block of 5 years from 2020-21 (Copy of workings placed at Annexure-4).

8.3.2 The rate so arrived has been adjusted for calorific value considering NCV of 8300 Kcal/SCM. Royalty @ 10% (10/110=9.09%) has been deducted to arrive at the net gas price.

8.4 Viability Analysis

The broad assumptions / parameters considered for working out viability analysis are as follows:

8.4.1 The viability analysis has been carried out on completion cost basis considering

an escalation of 6% p.a. in capital cost estimates as per existing Guidelines, which works out to ` 21555.72 lakh. Further, Operating cost has also been escalated @ 8% p.a. as per prevailing guidelines (Annexure-5).

8.4.2 The viability analysis has been carried out considering an Exchange Rate of 1 US$ = ` 53.77 (Average RBI Reference Rate for the Month of Feb’ 2013), i.e., previous one month average as per prevailing project appraisal guidelines. A copy of Circular No. Pricing/ND/367/12-13 dated 01.03.2013 is placed at Annexure-4 (a).

8.4.3 Depreciation @ 35% & 80% for facilities and pipelines respectively has been considered for the 1st year in the year of capitalization, i.e., 2015-16 and thereafter @ 15% & 60% respectively.

8.4.4 The discounting rate considered for working out NPV is 14% as per guidelines in vogue and base year considered is 2012-13.

8.4.5 All calculations have been carried out in post-tax scenario considering tax rate of 32.45% (effective presently for AY 2013-14).



The results of the financial analysis considering the above parameters are as follows:

IRR (%) NPV @ 14 %

(` in lakh) 17.08 1446.96

Although, the proposal / FR is meeting the hurdle rate of 14%, the sensitivity analysis (Annexures-8) has also been carried out under different scenarios as per prevailing project appraisal guidelines in vogue and is as under:

Sl.

No. Parameter IRR

(%) NPV@ 14% (` in lakh)

Base Case 17.08 1446.96 1 Capex + 10% 14.92 456.84 2 Capex + 20% 12.99 (-) 533.28 3 Opex + 10% 16.33 1076.92 4 Opex + 20% 15.56 706.88 5 PDN. ( – ) 10% 14.15 68.91 6 PDN. ( – ) 20% 10.88 (-) 1309.14 7 Both Capex and Opex + 10%, PDN (–)

10% 11.21 (-) 1294.58

8 Both Capex and Opex + 20%, PDN (–) 20%

4.80 (-) 4042.77

9 Gas Price + 10% 19.86 2872.32 10 Gas Price ( - ) 10% 14.05 21.61 11 Exchange Rate + 5% 18.50 2159.64 12 Exchange Rate ( - ) 5% 15.60 734.29 13 Exchange Rate + 10% 19.86 2872.32 14 Exchange Rate ( - ) 10% 14.05 21.61



The proposal can sustain the following level of escalation (increase) / reduction under the following broad heads and is tabulated below:-

Broad Heads Sustain Level in % (Break Even Points)

Capex Escalation 14.6 %

Opex Escalation 39.1 %

Shortfall in Production 10.5 %

Price Reduction 10.1 %

The detailed working of break-even analysis is placed at Annexure-9.



9. Conclusion

The marketing efforts already initiated for the sale of gas from the fields under consideration has attracted several prospective customers. Hence, the project may be considered with the following salient points:

9.1 Drilling of two wells in Bhubandar Field and two wells in Banskandi Block-1

9.2 Acquisition of Right of Use (RoU) and Laying of 35 Kms underground seamless pipeline with Cathodic protection for the entire length from BU-2 to BK-1, including interconnecting pipelines of 4 additional wells

9.3 One river crossing for the river Rukni by Horizontal Directional Drilling (HDD) with Intermediate Valve stations at both ends of river Rukni

9.4 Construction of GCS at BK-1 well-site

9.5 The project with a total Sanction CAPEX of ` 16380.52 & completion CAPEX of ` 21555.72 lakh (including cost of 4 development wells) meet the hurdle rate of 14%

9.6 The project is techno-commercially viable

The worked out techno - economics suggests an NPV of ` 1446.96 lakh (@ 14% discount rate) and IRR of 17.08%.

CAPEX Details Annexure-1 (a)


CAPEX Details Annexure-1 (b)


Phase-Wise / Year-Wise CAPEX (` in Lakh)

Year GCS+ETP Pipeline Land for Pipeline

Total Facility Cost

Esc. Fac. Cost

4 Addl. Wells

Esc. Well Cost

Total CAPEX Total Escalated CAPEX

3226.90 822.95 303.42 4353.27 6.00% 11830.00 6.00% 2012-13 0.00 0.00 0.00 0.00 0.00 2013-14 968.07 246.88 303.42 1518.37 1609.48 0.00 0.00 1518.37 1609.48 2014-15 1129.42 288.03 1417.45 1592.64 6230.00 7000.03 7647.45 8592.67 2015-16 1129.42 288.03

1417.45 1688.20 2800.00 3334.84 4217.45 5023.05

2016-17 0.00 0.00 0.00 0.00 0.00 2017-18 0.00 0.00 0.00 0.00 0.00 2018-19

0.00 0.00 0.00

2019-20 0.00 0.00 0.00 2020-21 0.00 0.00 0.00 2021-22

0.00 0.00 0.00

2022-23 0.00 0.00 0.00 2023-24 0.00 0.00 0.00 2024-25

0.00 0.00 0.00

2025-26 0.00 0.00 0.00 2026-27 2800.00 6330.53 2800.00 6330.53

Total 3226.90 822.95 303.42 4353.27 4890.32 11830.00 16665.40 16183.27 21555.72

CAPEX Details Annexure-1 (c)


Well Cost Estimates

WBS Element of Well Well Name

Year of Drilling

Cost of Well (in ̀ )

Depth (in M)

Cost (in ` / Meter)

Cost (in ` Lakh /

Meter) SI.10E.PLBLK.KMGNJ#PTAA PTAA 2011-12 191,880,963.76 1411 135989.34 1.36

SI.11E.PLBLK.CHR#BCAA BCAA 2012-13 277,703,896.31 2000 138851.95 1.39

Cost Per Meter

1.40

(` in Lakh)

Well Name Depth Unit Well Cost Category BU-NEW1 2000 Meters 2800 Development Well BKAC 2450 Meters 3430 Exploratory Cum Development Well BKDB-A 2000 Meters 2800 Development Well BU-NEW2 (13th Year) 2000 Meters 2800 Development Well Total well cost 11830

Abandonment Cost for onshore wells : ` 2,479,995.00 per well Abandonment Cost for 4 dev. wells : ` 99.20 lakh

CAPEX Details Annexure-1 (d)


Project Cost for Evaluation Purpose Sl.

No. Project Facility Cost (` in Lakh) Remarks

1 Gas Collection Station 2480.07 Estimates As Per OES, Delhi 2 Effluent Treatment Plant 746.83 Estimates As Per OES, Delhi 3 Pipeline-2" Dia 1.5 KM 30.00 Estimates As Per OES, Delhi 4 Pipeline-3.5" Dia 35 KM 792.95 Estimates As Per OES, Delhi 5 Land for Pipeline 303.42 Estimates As Per Revenue Authority

for 6 Villages Total 4353.27

Project Cost for Sanction Purpose Sl.

No. Project Facility Cost (` in Lakh) Remarks

1 Gas Collection Station 2597.53 Estimates As Per OES, Delhi 2 Effluent Treatment Plant 785.43 Estimates As Per OES, Delhi 3 Pipeline-2" Dia 1.5 KM 30.00 Estimates As Per OES, Delhi 4 Pipeline-3.5" Dia 35 KM 834.14 Estimates As Per OES, Delhi 5 Land for Pipeline 303.42 Estimates As Per Revenue Authority

for 6 Villages Total 4550.52

CAPEX Details Annexure-1 (e)


Depreciation Chart (Rs.in Lakh)

Year GCS + ETP Esc. CAPEX CAPEX for DEP. Pipeline Esc. CAPEX CAPEX for DEP. Total 15% 60%

3226.90 6.00% DEP 20% 822.95 6.00% DEP 20% Dep. 2012-13 0.00 0.00 0.00 0.00 0.00 0.00 0.00 2013-14 968.07 1026.15 1026.15 246.88 261.70 261.70 0.00 2014-15 1129.42 1269.01 2295.16 288.03 323.63 585.33 0.00 2015-16 1129.42 1345.15 3640.32 1274.11 288.03 343.05 928.38 742.70 2016.81 2016-17 0.00 0.00 2366.21 354.93 0.00 0.00 185.68 111.41 466.34 2017-18 0.00 0.00 2011.27 301.69 0.00 0.00 74.27 44.56 346.25 2018-19 1709.58 256.44 29.71 17.82 274.26 2019-20 1453.15 217.97 11.88 7.13 225.10 2020-21 1235.17 185.28 4.75 2.85 188.13 2021-22 1049.90 157.48 1.90 1.14 158.63 2022-23 892.41 133.86 0.76 0.46 134.32 2023-24 758.55 113.78 0.30 0.18 113.97 2024-25 644.77 96.72 0.12 0.07 96.79 2025-26 548.05 82.21 0.05 0.03 82.24 2026-27 465.85 69.88 0.02 0.01 69.89 2027-28 395.97 59.40 0.01 0.00 59.40 2028-29 336.57 50.49 0.00 0.00 50.49 2029-30 286.09 42.91 0.00 0.00 42.91

Total 3226.90 3640.32 3397.14 822.95 928.38 928.38 4325.52

OPEX Details Annexure-2 (a)


Operating Cost for South Banskandi-GCS Sl. No.

Description Unit Unit rate (in ̀ )

Qty. / Year

Cost per year (in `)

OPEX for 13th Year (in ̀ )

Nature

1 Mandays cost, Officers

Per Year

2000000 4 80.00 80.00 Fixed

2 Mandays cost, Staff

Per Year

1200000 8 96.00 96.00 Fixed

3 HSE Cost Per Year

53.57 56.37 Fixed

4 Insurance Per Year

18.83 21.91 Fixed

5 Repair & Maintenance

Per Year

171.17 199.17 Fixed

6 Consumption of Stores & Spares

Per Year

53.57 56.37 Fixed

7 Other Contractual Payments

Per Year

53.57 56.37 Fixed

8 Transport Expenses

120418.68 Variable

9 Light, Power, Fuel & Water Charges

29100.41 Variable

OPEX Details Annexure-2 (b)


Cost of Exploratory Wells BK-1 & BU-2 considered for estimation of OPEX

BK-1 (Banskandi)

Actual Cost ` 576.93 Lakh Drilling Depth 3010 Meter

Rig E-1400-XI Rig Release Date 02.03.1989 Cost Per Meter ` 19167

Escalated @ 6% p.a. to arrive at the present value of the well cost for 24 years

Present Value of Actual Well Cost for 2012-13 = ` 2336 Lakh

BU-2 (Bhubandar)

Pro-rata Cost ` 632 Lakh (Based on Cost per meter of BU-1) Drilling Depth 2004 Meter Rig E-1400-XI Rig Release Date 28.09.1995

Cost Per Meter ` 31532

Escalated @ 6% p.a. to arrive at the present value of the well cost for 17 years

Present Value of Actual Well Cost for the year 2012-13 = ` 1702 Lakh

BU-1 (Bhubandar)

Actual Cost ` 1161.96 Lakh Drilling Depth 3685 Meter Rig

E-1400-XI

Rig Release Date 27.04.1995 Cost Per Meter ` 31532

OPEX Details Annexure-2 (c)


OPEX Escalation Chart (` in Lakh)

Year Fixed OPEX –

up to 12th Year

Fixed OPEX -

13th Year Onwards

Variable OPEX - Transport Expenses

Variable OPEX - Light, Power, Fuel

& Water Charges

Total OPEX

2012-13 526.70 566.18 526.70 2013-14 568.84 611.48 568.84 2014-15 614.34 660.39 614.34 2015-16 663.49 713.22 41.74 10.09 715.32 2016-17 716.57 770.28 90.41 21.85 828.83 2017-18 773.90 831.91 97.65 23.60 895.14 2018-19 835.81 898.46 105.46 25.49 966.75 2019-20 902.67 970.33 113.65 27.46 1043.78 2020-21 974.89 1047.96 122.10 29.51 1126.49 2021-22 1052.88 1131.80 131.08 31.68 1215.64 2022-23 1137.11 1222.34 140.76 34.01 1311.88 2023-24 1228.08 1320.13 151.16 36.53 1415.77 2024-25 1326.32 1425.74 162.36 39.23 1527.91 2025-26 1432.43 1539.80 174.40 42.15 1648.97 2026-27 1547.02 1662.98 187.36 45.28 1779.66 2027-28 1670.78 1796.02 216.36 52.29 2064.66 2028-29 1804.45 1939.70 232.56 56.20 2228.47 2029-30 526.70 566.18 250.00 60.42 2405.29

Gas Profiles Annexure-3 (a)


Banskandi Wells: GIIP : 727.4 MMm3; AOFP: 86000m3/d; THP Cut Off : 15 Kg/cm2

YEAR Well-1, Qg (SCMD)

Well-2, Qg (SCMD)

Well-3, Qg (SCMD)

Total Qg (SCMD)

Total Qg (MMSCM/Year)

2015-16 20000 20000 20000 60000 10.92 2016-17 20000 20000 20000 60000 21.90 2017-18 20000 20000 20000 60000 21.90 2018-19 20000 20000 20000 60000 21.90 2019-20 20000 20000 19694 59694 21.79 2020-21 20000 20000 18966 58966 21.52 2021-22 20000 20000 18142 58142 21.22 2022-23 20000 20000 17346 57346 20.93 2023-24 20000 20000 16575 56575 20.65 2024-25 20000 20000 15822 55822 20.38 2025-26 20000 20000 15090 55090 20.11 2026-27 20000 20000 14378 54378 19.85 2027-28 20000 20000 13684 53684 19.59 2028-29 20000 20000 13004 53004 19.35 2029-30 20000 20000 12340 52340 19.10

Bhubandar Wells: GIIP : 1088.1 MMm3; AOFP: 180000m3/d; THP Cut Off : 15 Kg/cm2

YEAR Well-1, Qg (SCMD)

Well-2, Qg (SCMD)

Well-2, Qg (SCMD)

Total Qg (SCMD)

Total Qg (MMSCM/Year)

2015-16 40000 40000 80000 14.56 2016-17 40000 40000 80000 29.20 2017-18 40000 40000 80000 29.20 2018-19 40000 40000 80000 29.20 2019-20 40000 40000 80000 29.20 2020-21 40000 40000 80000 29.20 2021-22 40000 40000 80000 29.20 2022-23 40000 40000 80000 29.20 2023-24 40000 40000 80000 29.20 2024-25 40000 40000 80000 29.20 2025-26 40000 40000 80000 29.20 2026-27 40000 40000 80000 29.20 2027-28 30000 30000 30000 90000 32.85 2028-29 30000 30000 30000 90000 32.85 2029-30 30000 30000 30000 90000 32.85

Gas Profiles Annexure-3 (b)


Combined Gas Production Profile of Banskandi and Bhubandar Wells:

Year Bhubandar Block Banskandi (Block of BK#1) Total GIIP 1088.1 MMm3 GIIP 727 MMm3 GIIP 1815.1 MMm3 Qg SBHP Year

wise Gp Cum. Gp Qg SBHP Year

wise Gp Cum. Gp Qg Year

wise Gp Cum.

Gp Mm3/d (kg/cm2) MMm3 MMm3 Mm3/d (kg/cm2) MMm3 MMm3 Mm3/d MMm3 MMm3

0 202 0 190 0 2015-16 80 193 14.56 15 60 184 10.92 11 140 25 25 2016-17 80 184 29.20 44 60 178 21.90 33 140 51 77 2017-18 80 176 29.20 73 60 172 21.90 55 140 51 128 2018-19 80 168 29.20 102 60 167 21.90 77 140 51 179 2019-20 80 160 29.20 131 60 161 21.79 98 140 51 230 2020-21 80 152 29.20 161 59 155 21.52 120 139 51 280 2021-22 80 144 29.20 190 58 150 21.22 141 138 50 331 2022-23 80 136 29.20 219 57 144 20.93 162 137 50 381 2023-24 80 129 29.20 248 57 139 20.65 183 137 50 431 2024-25 80 121 29.20 277 56 133 20.38 203 136 50 480 2025-26 80 113 29.20 307 55 128 20.11 223 135 49 530 2026-27 80 106 29.20 336 54 122 19.85 243 134 49 579 2027-28 90 98 32.85 369 54 117 19.59 263 144 52 631 2028-29 90 90 32.85 401 53 112 19.35 282 143 52 683 2029-30 90 83 32.85 434 52 106 19.10 301 142 52 735

Gas Pricing & Revenue Generation Annexure-4 (a)


Gas Pricing & Revenue Generation Annexure-4 (b)


Gas Pricing Calculations

From 2015-16 to 2019-20

GAS PRICE $ 5.25 /MMBTU = ` 11202.08 / MCM FOR 10,000 KCAL EXCHANGE RATE US$ 1 = ` 53.77 CONVERSION FACTOR

39.68254

GAS PRICE 9297.73 8300 KCAL ROYALTY 9.09% NET GAS PRICE 8452.48 `/MCM

From 2020-21 to 2024-25

GAS PRICE $ 6.25 /MMBTU = ` 13335.81 / MCM FOR 10,000 KCAL EXCHANGE RATE

US$ 1 = ` 53.77 EXCHANGE RATE

CONVERSION FACTOR 39.68254 GAS PRICE 11068.73 8300 KCAL ROYALTY 9.09%

NET GAS PRICE 10062.48 `/MCM

From 2025-26 to 2029-30

GAS PRICE $ 7.25 /MMBTU = ` 15469.54 / MCM FOR 10,000 KCAL EXCHANGE RATE US$ 1 = ` 53.77 EXCHANGE RATE CONVERSION FACTOR 39.68254 GAS PRICE 12839.72 8300 KCAL

ROYALTY 9.09% NET GAS PRICE 11672.47 `/MCM

Gas Pricing & Revenue Generation Annexure-4 (c)


Gas Revenue Estimations

Net Gas Price Profile Gas Revenue Year `/MCM MMSCM/Year ` In Lakh

2015-16 8452.48 25.48 2153.69 2016-17 8452.48 51.10 4319.22 2017-18 8452.48 51.10 4319.22 2018-19 8452.48 51.10 4319.22 2019-20 8452.48 50.99 4309.79 2020-21 10062.48 50.72 5103.93 2021-22 10062.48 50.42 5073.68 2022-23 10062.48 50.13 5044.46 2023-24 10062.48 49.85 5016.12 2024-25 10062.48 49.58 4988.48 2025-26 11672.47 49.31 5755.43 2026-27 11672.47 49.05 5725.11 2027-28 11672.47 52.44 6121.57 2028-29 11672.47 52.20 6092.63 2029-30 11672.47 51.95 6064.33

DF/ND/PAS/390/2013 dated 24.01.2013 (Hurdle Rate & Product Prices) Annexure-5


DLI/CA/18(2)/2011-12 dated 03.04.2012 (Abandonment Liability) Annexure-6


DLI/CA/18(2)/2011-12 dated 03.04.2012 (Abandonment Liability) Annexure-6


Maps to be included with proper cross-reference: 1) Mapped Geological Structures of Cachar area 2) Map showing PEL/ ML Blocks etc. 3) Well Location Map: Banskandi 4) Well Location Map: Bhubandar 5) Planned pipeline network from well to GCS/ Consumers

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