Ongc to Develop of Parbatpur Area in Jharia Coal Field in Jharkhand for Commercial Production of Cbm

7/30/2019 Ongc to Develop of Parbatpur Area in Jharia Coal Field in Jharkhand for Commercial Production of Cbm

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1. Introduction

Oil & Natural Gas Corporation Ltd. "ONGC" or "corporation" proposes to develop b sq. km. ofParbatpur area in Jharia coal field in Jharkhand for commercial production of Coal Bed Methane(CBM).

Coal Bed Methane is essentially methane gas trapped in coal reserves due to the pressure ofoverlying rock formations and organic debris. To release the gas, the pressure has to be reduced.This is done by dewatering the coal beds. Initially, the CBM wells - produce only water.Subsequently, water production declines and the gas production rises.

Coal Bed Methane is being commercially exploited and used around the world for the last oneand a half decades. The leading country in its commercial exploitation is USA having estimatedCBM reserves of 750 trillion cu. ff. The present CBM production is over 1200 billion cu. ff. peryear. Australia and China are also producing CBM in commercial quantities. India is estimated tohave CBM reserves of 30 trillion cu. ft.

ONGC has been working in Jharia coal field since 1992 for CBM exploration. The firstbreakthrough came in 1997 when ONGC was successful in flowing CBM from one of the R&D

wells. The Jharia block was awarded to ONGC-CIL consortium on a nomination basis by theGovernment in 2002. The CBM reserves in the area are estimated at 8 BCM (0.28 trillion cu. ff.).

The company proposes to drill 14 wells from 6 pads for the commercial production of CBM.Based on a recovery factor of 49.1%, it is assumed that the wells would produce 3.93 BCM of gasduring the lifetime of the project. The company proposes to use Horizontal Multilateral In-seamDrilling technology, which is known to improve the recovery of the gas manifolds.

The project cost is estimated at Rs. 528 crores to be funded completely by internal accruals. Thefinancial analysis establishes that the project is commercially viable with an IRR of 12.35%. TheIRR is likely to go up with the improvement in recovery factor and benefits derived out of carboncredits. As methane is a Greenhouse Gas, the production of the gas for commercial consumptionwill make the project eligible for carbon credits.

The total CBM gas produced by ONGC would be sold to Steel Authority of India (SAIL) for use intheir Bokaro plant. The project cost includes the cost of setting up pipeline network andcompressor for transportation of CBM gas to the premises of SAIL.

The Coal Bed Methane extraction project by ONGC is the first of its kind in the country. Thesuccess of the project may inspire more projects for commercial exploitation of CBM in thecountry.

2. COAL BED METHANE - AN INTRODUCTION

Coal is the most abundant nonrenewable energy source in the world, Coal beds are a major

source of an odorless, colorless natural gas called methane. Methane build-up in coal mines hascaused many mine explosions, killing thousands of miners worldwide. However, recenttechnology developed in the US has allowed the gas to be tapped and sold in commercialquantities. Coal. is a carbon-rich material that has been formed by the chemical and thermalalteration of organic debris. During this process called coalification, a series of by-products aregenerated, including water and methane.

The amount of methane produced during coaliflcation generally exceeds the capacity of coal tohold the gas. On an average, about 140 m3 of methane is generated per ton of coal. The excess


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gas migrates into the surrounding rock strata and into the traditional sand reservoirs that mayoverlie 1he, more deeply buried coals. The amount of methane in a coal bed depends on the age,moisture content, quality and depth of the coal deposit. In general, the higher the energy value ofthe coal and the deeper the coal bed beneath the surface, resulting in more pressure fromoverlying rock formations, the more methane the deposit holds. Coal stores six to seven timesmore gas than the equivalent rock volume of a conventional gas reservoir.

The knowledge of methane occurring with coal beds is as old as the mining itself. However, beinghighly explosive, it is treated more as a hazard than a resource. High capacity fans are used todilute the gas during mining and the mixture is released into the atmosphere. Thus, the resourceis not only lost, being a greenhouse gas, it contributes to the global warming. Coal mining isreported to be contributing about 9% of the total methane emissions.

2.1 Estimation of Coal Bed Methane

The estimation of availability of CBM is a complex, time-consuming, and capital-intensiveprocess. For example, the number of drill holes needed for exploring CBM is 10 items more thanthat needed for natural gas. The time and cost involved in pumping out the associated water fromCBM drill holes are also high. The quantum of gas is dependent on many parameters and some

of them are highly variable.

The estimation of CBM reserves is based upon gas content (mainly methane) of the coal seam,which is generated and stored in adsorbed state during coalification process, The reserves, apartfrom gas content, also depend upon the thickness and aerial extent of the coal formation (i.e. coalvolume) and its density. Like conventional reservoirs, in place CBM reserves can be estimated byvolumetric method, but with a different formula, which is as follows.

Gas in Place (GIP) = A'h'p'Gc

Where A = aerial extent of coal formation

H = average thickness of coal formation

Gc = average Gas content, and

p = Density of coal

2.2 Extraction of Coal Bed Methane

Methane locked in coal beds is usually not as expensive to develop as natural gas found in othergeologic formations b6cause modified water well drilling rigs can be used in place of specializedoil and gas drilling rigs. Wells are cased with pipe and cemented. Cased wells tend to deter,though not always prevent, gas from seeping into nearby rock beds and underground waterformations called aquifers. Fractures that run through coal beds are usually filled with water. The

deeper the coal bed, the less water is present, but the more saline (or salty) it becomes. Waterpressure holds methane in the coal bed.

To release the gas, its partial pressure is reduced by removing water from the coal beds. Oncethe pressure is lowered, the gas and water move through the coal bed and up the wells. At first,coalbed methane wells produce mostly water, but over time, the am-punt of water declines andgas production rises as the bed is dewatered. Water removal may continue for several years. Thewater is usually discharged on the surface or injected into aquifers. Drill rigs are brought to wellsites by trucks, and access roads must be constructed. Electric or gas "powered motors are used


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to power the pumps and compressor stations. Pipelines are also built to gather the gas from eachwell and transport it to customers in distant markets.

Coal Bed Methane can be extracted from coal beds in several ways,

Conventional Drilling

A well is drilled as shown in the picture. Fluid is forced down through the well to fracture the coal,which releases methane gas.

As the well is vertically drilled in the coal seam, lesser area is exposed to and therefore, therecovery of methane gas is lower.

Horizontal Drilling

In case of horizontal drilling, the motor behind the drill is twisted to drill horizontally into a coalseam, which is fractured to produce methane. The advantage is that the well is drilled within theseam and therefore the recovery of methane is many times better compared to conventionaldrilling.

When drilling is done in such a manner that there is one main lateral (well) and a number of sublaterals (like main vein and side veins on a leaf), then it is called multilateral horizontal drilling.Due to this type of drilling, much larger surface area of the coal is exposed, which results intorapid de-pressurization by faster de- watering and hence rapid and high gas production,

2.3 Advantages of Coal Bed Methane

The extraction of Coal Bed Methane offers many advantages.

a) Cheaper Fuel

The cost comparison among different types of fuels viz. coal, tar, furnace oil and coal gas beingused in the nearby industries indicates that the CBM can be marketed at a cheaper price thanfurnace oil and gas. If compared only on the basis of calorific value, CBM may be higher in costthan coal. However, if the cost of disposal and handling of huge solid waste generated in case ofcoal based industries and other environmental aspects are considered, CBM will be a cheaperoption.

b) Reduction in Green House Effect

The gas produced during the mining is released into the atmosphere after diluting it, which leadsto green house effect. It is estimated that methane so released contributes to about 9% of globalwarming. In case of CBM extraction, the gas is captured for commercial use before the mining ofthe coal begins, therefore, the emission of gas during mining is reduced.

c) Improving the mine safety by degassing the mines

The extraction of CBM prior to mining will improve the mine safety as methane gas has caused anumber of accidents in mines in past.

Apart from above, the government will be benefiting by promoting extraction of CBM as it willopen a new revenue stream in the form of Royalty Payments, Production Linked Payments, taxes


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etc. The development of a new energy resource can -help speeding up economic activitiesleading to better economic growth of the country, particularly as our domestic energy options arelimited.

2.4 Coal Bed Methane Potential - Worldwide Interest

Coal Bed Methane (CBM), a source of clean energy, is being commercially exploited and usedaround the World for the last one and a half decades. The leading country in its commercialexploitation is U.S.A., having total proved coal reserves of 246 billion tonnes (1998) and anestimated CBM reserve of 750 Trillion cu-.ft. CBM development was started in U.S.A. in early 80swhen production of CBM was 10 billion cu: ft. (1984) and by 1990 the production had reached alevel of 194 billion cu.ft.

Subsequent to the enactment of CBM legislation by some states, the CBM development gotfurther accelerated and by 1997 its production had reached a level of 1130 billion cu. ff. Thepresent CBM production is over 1200 billion cu.ft. per year. Drilling is concentrated in two areas,

Alabama's Black warrior, where the coal seams-'are particularly gas-rich; and New Mexico's SanJuan basin, which is fled into the natural gas grid.

Australia is likely to be the next producer of commercial quantities of methane. The pilot projectsin Queensland and New South Wales are already well advanced. The drawback in such a hugebut sparsely populated territory is finding a market for the gas. China, the world's largest coalproducer, is sitting on more than 700 TCF of coal bed methane. The country already has a fairlywidespread system of methane drainage and capture, to keep its gassy mines safe enough towork in. But though 60% of drained methane is utilized, most of it is too dilute to be used inanything other than local power plants or factory sites. Interest around the world is quickening,and world coal bed methane output is on the fast track.

India is among the top ten countries in coal resources, having an estimated coal reserve of 160million metric tons, with an estimated methane resource of 850 BCM (30 TCF). The Indian coal ismainly confined to the Permian Gondwana basins and the terfiaries. Tertiary coals arewidespread in Assam, Meghalaya, Arunachal Pradesh, Tamil Nadu, Rajasthan and Gujarat.

Tertiary coals are generally found to be lignitic to sub-bituminous in rank and are generallyconsidered to be unsuitable for coalbed methane target,

However, tertiary coals in petroliferous basins of Cambay, Upper Assam and Assam Arakan maybe prospective due to reported higher gas content, which is probably stored in the coal aftergeneration from deeper-lying hydrocarbon source beds or may be of biogenic origin. Methaneemission studies from working mines of India reported most of the degree three gassy mines (>10 cubic m/ton), are confined in the four Damodar Valley coal fields, viz. Raniganj, Jharia, Bokaroand North Karanpura in 3ihar and West Bengal. In these areas, the thickest bituminous coals areextensively developed in the Barakar measures and in Raniganj measures of Lower and UpperPermian age, respectively, The Barakar coal seams are superior to Raniganj coal seams ascoalbed methane targets.

3. HARNESSING THE CBM POTENTIAL - INDIAN SCENARIO

Coal Bed Methane is environment friendly clean fuel with properties similar to Natural Gas. Thecommercial production of CBM is proven technology an& CBM is now considered as a majorsource of gas supplementing the production of hydrocarbon gas from petroleum sources. USA isthe leader in CBM production in the world. The total CBM production of USA (135 MMSCMD) isalmost twice the total Natural Gas production of India. The successful commercial recovery ofCBM in USA has been followed up by several major coal producing countries including Australia,Canada, People Republic of China and India.


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India is endowed with rich deposits of coal and lignite in different sedimentary basins of varyingdimensions. The bulk of the coal resources of around 250 billion tonnes is contained in olderbasins. Large lignite deposits also occur in younger basins of Gujarat, Rajasthan (Western India)and Tamilnadu Southern India). These coal and lignite deposits contain varying amount of CBMdepending upon the rank of coal, depth of burial and geo- tectonic settings of the basins.

The CBM resources as per Directorate General of Hydrocarbon (DGH), Ministry of Petroleum &Natural Gas (MOP&NG) are tabulated here under:

S.No. State Coalfield/Block Area of delineatedblock (Sq. KM)

Prognosticated CBM Resourceas per DGH

In trillioncubic feet

In billion cubicmeter

1. West Bengal a. North Ranigang 232 1.030 29.17

b. EasgternRaniganj

500 1.850 52.38

c. Birbhum 250 1.000 28.82

Sub Total 982 3.88 10.87

2. Jharkhand a. Jharia 69.20 2.407 68.16

b. East & WestBokaro

93.37 1.590 45.02

c. North Karanpura 340.54 2.181 61.75

Sub Total 503.11 6.178 174.93

3. MadhyaPradesh

a. Sohagpur 495 3.030 85.79

b. Sohagpur 500

c. Satpura 500 1.000 28.32

Sub Total 1495 4.030 114.11

4. Gujarat a. Cambay Basin 2400-3218 11 to 19.4 317 to 549.39

Grand Total 2980.11 25.088 710.39-948.73

3798.11 33.488

3.1 The CBM Policy

In 1997, GoI recognized CBM as natural gas and formulated a CBM Policy for the commercialexploitation of CBM. The CBM Policy provided attractive fiscal and contract term, which wereformulated following a process of consultation and were based on prevailing international fiscalregimes. The main features of the CBM Policy are as under:

a. Blocks would be awarded through open international competitive bidding.b. Contractors would be required to pay license/lease fee and charges including surface

rentals, land acquisition charges etc. as per P&NG rules or as required under any otherprovisions.

c. The contractor shall pay fixed ad valorem royalty and biddable Production LevelPayments (PLP) on a sliding scale based on the monthly average of dagy production withincreased RLP being payable on incremental production with base rate of 1096. Thus,while no PLP would be payable on an average natural gas production of upto 1 Million


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Standard Cubic Metre Per Day (MMSCMD), thereafter PLP would be biddable on everyincremental production of 0.5 MMSCMD.

d. Contractor and sub-contractors will be exempted from payment of customs duty onimport of goods and materials required for exploration and exploitation of CBM.

e. Contractor will be required to pay a commercial discovery bonus of US $ 0.3 million or itsequivalent amount in Indian Rupees on the declaration of commercial discovery.

f. The contractor would be required to pay corporate income tax as per the Income Tax Act.g. Seven year tax holiday from the date of commencement of commercial production.

h. Contractor will be provided flscdl stability during the entire period of contracts.

i. The contract will be subject to the laws of India.j. Arbitration shall be governed as per the Indian Arbitration and Conciliation Act, 1996.

k. A model contract will be prepared and made available to the companies.

l. The contract duration will be divided into four phases as follows:

Phase - I : 3 years and will be for exploration

Phase - II : 5 years pilot assessment for commercially

Phase -III : 5 years development phase.

Phase - IV : 25 years production phase

m) The companies will have a walk-out option at the end of Phase-I and Phase-II.

After the approval of CBM policy and signing of the MOU between Ministry of Petroleum &Natural Gas and Ministry of Coal, steps were taken to implement the CBM policy with a view tooffering CBM blocks for exploration and production.

3.2 Government Initiatives

DGH carved out several potential CBM blocks after giving due consideration for future coalmining programme by closely interacting with the Ministry of Coal and coal mining agencies. InMay 2001, Government of India has awarded 16 CBM blocks for exploration and production ofCoal Bed Methane in different coal fields of India through competitive bidding process. During thelast three years, more than 50 Boreholes, 15 Test Wells and 3 Pilot Wells have been drilled in theawarded blocks. The commercial production of CBM from few of these awarded blocks may startby 2006-07. These blocks may yield a peak production of about 23 MMSCMD of CBM in thecountry.

Total CBM resources in the 16 awarded blocks are estimated to be 820 BCM and the expectedtotal production from these blocks is estimated around 23 MMSCMD.

3.3 Industry Analysis - Natural Gas

Natural Gas currently accounts for 9% of the commercial energy consumption in the country. Thetotal proven reserves of natural gas in India at the end of 2003-04 was about 923 billion cubicmetres (BCM) in comparison to 854 BCM at the end of 2002-03. Most domestic natural gasreserves are concentrated in the offshore gas fields at Mumbai High. Offshore gas reserves arealso located.'-in Gujarat, Andhra Pradesh (Krishna-Godavari basin), Tamil Nadu (Cauvery basin)and Rajasthan. Onshore reserves are located in Gujarat ind the north-eastern states of Assam,Nagaland, Arunachal Pradesh and Tripura.


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The total gas production in India was about 31,962 MCM in 2003-04 compared with 3,851 MCMin 1981- 82. At this production level, India's reserves are likely to last for around 26-27 years; thatis significantly longer than the 22-23 years estimated for oil reserves. The entire natural gasproduction is consumed internally.

However, increasing demand mainly from the power sector and fertilizer sector made imports

necessary. LNG imports to India began from 2004. It imported 1.8 mtpa (if LNG in 2004.Currently, the total LNG re- gasification capacity of India is 7.5 mtpa. Proposed plans to increasethis capacity to 25 mtpa are in the initial stages. The existing 5 mtpa Dahej terminal of Petronet inGujarat has a long- term LNG supply contract with Qatar's Rasgas.

Shell, on the other hand, is buying Spot LNG cargo to feed its 2.5 mtpa terminal of Hazira,Gujarat. Currently, India is in negofiations with Iran (Iran-Pakistan-India) for gas imports throughpipelines. It is also exploring the possibility to source gas from Turkmenistan by extending theplanned Turkmenistan-Afghanistan-Pakistan) pipeline to its borders.

As per the current projections, the gap between demand and supply is expected to increase inthe years to come with the sustained growth in economy and in spite of greater emphasis ondevelopment of natural gas.

Natural gas: Demand supply forecast

(mmscmd) 2003-04 E

2004-05 E

2005-06P

2006-07P

2007-08P

2008-09P

2009-10 PBase case

2009-10 POptimistic

Demand 93.64 99.54 119.80 135.64 143.52 155.86 184.55 193.93

Supply 84.66 93.74 104.16 110.43 120.16 135.22 169.23 169.23

Surplus/(deficit)-8.98 -5.80 -15.64 -25.21 -23.36 -20.63 -15.32 -24.70

In the context of widening demand-supply gap in natural gas, CBM, a new source of energy in thecountry, is expected to contribute significantly to the domestic supply. It is estimated that theblocks awarded by GoI would be producing CBM commercially by 2007 yielding 23 MMSCMD ofgas production and bridge the gap partially as shown in the following graph.

3.4 Pricing of Natural Gas

In India, the price of natural gas has been regulated for a very long time and has remained at lowlevels, competing favorably with almost all fuels in all the consuming sectors of power; fertilizerand petrochemicals. The prices of domestic natural gas were fixed as' per the recommendationsof the Shankar Committee and have remained frozen at Rs 2,850 per tcm (around $1.6 perMMBTU) for over 4 years. The delivered price of this translates to around $2.7 per million Britishthermal units (MMBTU). The joint venture (JV) gas (from fields like Panna Mukta and Tapti) wasalso sold at the same levels and the difference between the producer price and the APM(administered price mechanism) price was borne by Oil and Natural Gas Corporation (ONGC).

Although the price of APM gas was at IRS 2,850 per tcm, the delivered price of domestic gas soldby private players such as Niko and GSPC was at the much higher level of $4 per MMBTU. TheR-WG delivered price of $4.5 per MMBTU is serving as a cap in most cases. The methods ofprice fixation have also been different. The APM gas and gas from Panna Mukta and Tapti (PMT)are indexed to a basket of fuel oils. On the other hand, GSPC sells gas indexed to a fixed price,while the gas sold by Niko is linked to crude oil prices. Hence, customers of natural gas havebeen paying varied prices.


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Under CBM policy, Govt. of India has recognized CBM as natural gas and has accorded theproducer "Freedom to market gas in domestic market at market determined prices". Since CBMin India does not fall under the purview of APM, the CBM pricing vis-a-vis natural gas in othercountries may be used as benchmark,

USA is the biggest market for CBM where CBM is approx. 9% of the total gas production. The

CBM produced from San Juan Basin, the most prolific producer accounting for almost 86% oftotal US production, is directly fed into the natural gas pipeline grid for transportation. Theoperator company can do the feeding of CBM into the national gas grid if certain specifications interms of composition of CBM are maintained. The pricing of CBM is on prorata basis for itsCalorific value subject to the specifications being maintained.

The average calorific value of CBM produced from Jharia coal field is 7800 Kcal per cu. m. Anelementary comparative study between various fuels being used in the nearby industries andCBM gas has indicated a minimum rate of Rs. 4086 per' 1000 SCM or US$ 3 per MMBTU. AsCBM would be compressed and delivered at customer premises, the pricing can be based on theprice of CNG as fixed by the government in case of Panna Mukti Tapti tussle.

The Panna Mukta Tapti field, which supplies around 10.8 MMSCMD of gas was selling at $3.11

per MMBTU, while the customer price was pegged at APM levels. The production-sharingcontract (PSC) allowed for a revision in prices from April 2005. After long deliberations among allthe parties involved, the government mandated that around 4.8 MMSCMD of gas would bedirectly sold by the PMT consortium (i.e., ONGC, RIL and BG India), while the remaining 5.5-6.0MMSCMD would be available for sale via GAIL to the existing customers along the HBJ networkfor the current year. These quantities have been reserved for power and fertilizer sector players,who showed reluctance to accept the increase in prices.

Meanwhile, the government increased the producer price of gas to $3.86 per MMBTU at the levelof LNG prices. This move was again contested and, subsequently, the users agreed to pay theincremental 75 cents per MMBTU. The matter, however, has still not been resolved, with NTPCrefusing to offtake gas, resulting in reduced production at the fields. The RIL-NTPC deal may alsobe considered where a price US$ 2.97 per MMBTU was agreed but lately, RIL has sought a

change in terms and conditions of the contract.

Since, there isn't much clarity on the price determination of CBM, the price fixed by the'Government i.e. US$ 3.86 per MMBTU has been assumed as the minimum price, ONGC wouldbe able to command in the market.

3.5 Distribution of CBM

The development of pipeline infrastructure has been quite limited in the last few years, the onlyexception being the Dahej-Vijaipur Pipeline (DVPL), which commenced operations in April 2004.

At present, the country has a total pipeline infrastructure of around 7,500 km, supplying around70 MMSCMD of gas (excluding internal consumption). Gas Authority of India Ltd. GAIL/ currentlyowns and operates around 80% of the onshore pipeline network with ONGC following at 13.5%.

Company-wise pipeline ownership

(km) OnshoreOffshoreTotal

GAIL 5.340 0 5.340

ONGC929 67.1 1.600

OIL 213 0 213

GSPC 360 0 360


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Others2 0 2

Total 6,844 671 7.515

The development of pipeline network is key focus area in the years to come. ONGC would besetting up a pipeline for supply of CBM to its prospective customers. As the company already hasstrengths in Pipeline construction and operations, setting up of pipeline infrastructure formarketing CBM gas may not pose any problems for ONGC.

4. THE CBM PROJECT - AN ONGC INITIATIVE

4.1 The Project

Oil and Natural Gas Corporation (ONGC) proposes to develop b square km. central part ofParbatpur area in Jharia Block through 14 horizontal in-seam multi-lateral wells, to be drilled from6 pads, for commercial production of Coal Bed Methane (CBM). Once drilled and put onproduction, these 14 wells are to produce CBM at a peak rate of 0.784 MMSCMD for a period of3 years and then decline @ 5% per annum. Cumulative gas production during 20 years shall be3.93 BCM, recovery factor being 49.1 %.

The above 14 wells include 2 wells to be completed in Lower Barakar coal seams having very lowpermeability values. However, once encouraging results are obtained from these two wells due toapplication of horizontal in-seam multilateral technology, 6 more wells; 5 in Lower Barakar coalseams and 1 in Middle Barakar coal seams shall be drilled in the same area, improving therecovery factor substantially.

The Site

Jharia CBM Block is located within Jharia coalfield, about 25 km. east of Bokaro Steel city. Totalarea of Jharia block is 84.5 sq. km. Out of it area of Parbatpur area is approx. 18 sq. km. and thearea under present early pilot scheme is 6 sq. km. in central Parbatpur. The Jharia Coalfieldwhich is located about 300 km. north- west of Kolkata, lies mainly in the Districts of Dhanbad and

Bokaro with a small north-western portion of it falling in Giridih District in the State of Jharkhand.The Jharia QM Block (84.55 sq.km.) falls mainly within Bokaro District with a small eastern partfalling in Dharibad District. The Parbatpur area, under present discussion forms the south-easternpart of Jharia coalfield and is located towards south of river Damodar in Bokaro district.

This U/G Block (as per mining industries) covering an area of 18 sq. km. (Approximately) forms apart of Survey of India Toposheet No. 73 I/06 (RF 1:50,000). The area is located between

Latitude - (N) 23o39'30' - 23o42'06'

Longitude - (E) , 86o19'15" - 86o23'28"

It is bounded on the north by Damodar river, on the south by boundary fault, leading to directjuxtaposition of Archaean Metamorphics with Lower Gondwana sediments, on the west by Aluara(Aluara U/G block as per mining industry) area on the east and partly by Amlabad area and partlyby Mahal area (Mahal U/G block as per mining industry). The area can be approached fromDhanbad, which is about 27 kms. north-east of it, via - Bhowrah by road. The area can also beapproached by road via Chas located on NH 32. Talgaria railway Station on Bhojudih-Mohudaloop line in Adra-Gomoh section of South Eastern Railway falls within the said Parbatpur area.Shewababudih railway station on this loop line is also located nearby this area.

The site was selected for the exploration of CBM on the basis of following.


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a. The 6 sq. km. area around Parbatpur village has a high Borehole density.

b. Depiction of geological model of this area with much higher confidence level is possibledue to good Borehole control.

c. As most of the Boreholes have been drilled upto shallow depths (600m - 800m) by themining industries for fulfilling their mining objectives, confidence level of construction ofgeological model for the Barakar Succession below that depth is much less and it is

largely conceptual.d. The identified 6 sq. km. area of central part of Parbatpur ar6a covers the entire Parbatpur

dome. Thus all the regionally correlatable good coal seams are expected to occur atshallower levels.

e. Direct production testing data are available from 3 vertical Exploration wells of ONGC,which lead to identify this area as one of the most potential locales in terms of CBMprospectivity and production.

f. Play of the regional and local normal faults can be envisaged with much higherconfidence level due to availability of high density of Boreholes of mining industries atleast up to 600m - 800m. Thus the uncertainties involved in prediction of geological setup due to pressure of faults are much less in this area up to 600m - 800m. However,geological uncertainties still remain for the lower portion of the Barakar succession.

g. Presence of several normal faults in the central part of Parbatpur area is assumed to

have given rise to better permeability development and in turn better producibility.h. Several interactions were made with different CBM operators, engaged in developing

CBM fields in USA and Australia. They also are of the opinion that the central Parbatpurarea holds such level of CBM prospectivity which can be considered for introducing adevelopment scheme applying horizontal inseam drilling technique or similar technology.

Background & Exploration History:

ONGC, in pursuit of its CBM exploration activities has been working in-Jharia coalfield area since1992. In 1997, ONGC made significant breakthrough by flowing out CBM from its first R&D well(JH# 1 ) in Parbatpur area (18 sq km) of Jharia Coalfield, first time in India. Taking the lead fromthis success, ONGC drilled three more R&D wells in Parbatpur area. These wells are underdifferent stages of production testing and have so far yielded encouraging results, leading tofurther steps for exploration activities in this area. Nine Pilot wells were planned and released inthis area. Apart from Parbatpur Sector, activities have also been undertaken in the adjoiningareas of Parbatpur, where 6 Core holes/Boreholes have already been drilled by ONGC foracquiring CBM specific information to increase acreage of Exploration.

Meanwhile, ONGC and Coal India Ltd. jointly identified 21.55 sq km area in the adjoining part ofONGC's activity for joint working. Govt. of India awarded an area of 84.55 sq. km. as Jharia CBMBlock to ONGC-CIL Consortium on Nomination basis in January, 2002. As per Contract withGovt. of India, a Minimum Work Programme of drilling 8 Boreholes and 2 Exploratory wellsbesides 9 Pilot wells in Parbatpur during Exploration Phase in Jharia Block was committed toGovt. of India by ONGC-CIL Consortium. The PEL grant for the Block was received from Govt. ofJharkhand w.e.f. 28.08.2003. As per JOA with CIL Borehole drilling activities are theresponsibilities of CIL, whereas drilling and testing of the Exploratory and Pilot wells are the

responsibilities of ONGC.

The status of wells / boreholes drilled in Jharia Block as on 1.10.2005 is as follows: :-

Total Exploratory Wells drilled in Parbatpur area = 4

Total Exploratory Wells drilled outside Parbapur Area = 0 (nil)

Total boreholes drilled by ONGC outside Parbatpur area = 10


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Estimation of In-place CBM:

In-place CBM in the 6 sq. km. area have been estimated and are given below. The 8 BCM gas in-place CBM has been considered in the present Project for exploitation through initially 14horizontal in-seam, multilateral wells in 6 sq. km. of central Pearbatpur area, and subsequently, ifrequired, through additional 6 horizontal inseam multilateral wells.

Coal SeamResource (MMm3)Gas in place (MMm3)

XV 1223.22 978.58

XIV A 864.78 691.83

XIV 673.48 538.79

XIII 873.21 698.57

XII 919.22 735.38

XI 827.62 662.10

IX 377.94 302.35

V-VII 1873.97 1499.98

III-IV 2359.12 1887.30

Total 774.88 (8 BCM Approx.)

Considering a recovery factor of 49%, about 3.93 BCM of gas would be produced during thelifetime of the project.

Reservoir & Production Testing Data:

A number of injection fall-off tests have been carried out for different coal seams in 4 exploratorywells drilled so far to estimate reservoir parameters, chiefly permeability and reservoir pressure.

Also, different-objects, either individually or in commingled fashion, in these wells have been testflowed. The four Exploratory Wells viz. JH#l, JH#2, JH#3 and JH#4, which were drilled by ONGCin 1999, have been taken as key wells for estimating gas content and gas saturation

characteristics of the Barakar coal seams of this area directly and to estimate the CBM resourceof each object coal seam. Production testing and well and data of three of these wells have beenconsidered to the estimate the Gas to be produced from the different coal seams.

Gas Production data of CBM Wells, Jharia field

Well Object tested Cum Gas produced,m3 (15.10.2005)

JH # 1 I, II 0907424

JH # 2 I,II,III, IV, V, VI, VII, VIII 9211539

JH # 4 I, II, III, IV, V, VI, VII, VIII, IX 0272401

Fluid Characteristics:

Typical composition of CBM gas in Jharia Coal Field shows high methane content.

S.No.Component Percentage (%)

1 Methane 95-97 %

2 Ethane 0.23-1.02%

3 Propane 0.00%


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4 Carbon Di-Oxide2.26-4.02 %

5 Nitrogen 0.03-1.23%

4.2 The Project Implementation

The project would be implemented through Integrated Turnkey Contract including all the activitiesstarting from civil work to regular production & creation of Surface facilities. The Project shall bespread over a period of 31 months from the date of award with a provision of 12 months period ofmaintenance of each of the wells. ONGC's role is limited to obtaining statutory clearances andland acquisition required for drill sites and installations.

Technological Aspects

Based on the interactions with global operators, it is found that the extraction of CBM resourcefrom the coal beds using horizontal - multilateral drilling technology is becoming increasinglypopular due to multifold increase in productivity and long term techno economic benefits.

Different companies use different types of horizontal = drilling techniques, which are proprietary in

nature. Out of these, few technologies are mentioned below about which some preliminaryinformation have been gathered through interactions with few global CBM operators.

a. Horizontal -lnseam - Multilateral Drilling technology.

b. Z-Pinnet -Technology.c. Radial - Horizontal - Multilateral drilling technology.

d. Dimaxian - Horizontal drilling technology.

For all practical purposes and for formulation of development scheme in 6 sq. km. ParbatpurCentral Block the "Horizontal = Inseam - Multilateral - Drilling technology has been consideredand different technological inputs / requirements pertaining to this technique as are enumeratedbelow have been incorporated while planning the Development well locations and DevelopmentPlan.

Considerations for Drilling:

Drilling of vertical well (12'/,") to a desired depth as per disposition of the top most coal seam.

a. Setting of surface casing (95/s") accordingly.b. Drilling of 8'/i' hole vertically down to Kick off Point (KOP).

c. Drilling of 8'/2" deviated hole from KOP with building up of hole angle to 70 at a buildingup rate of 10 per 30m. Once this required angle is achieved, it should be held constantand a tangent section is to be drilled through all and a sump of about 50 m. is also to bedrilled below the deepest object coal seam.

d. Setting of 7" casing up to desired depth.e. Cut window (6.125") in 7" casing against the bottom most object coal seam.f. After building up of the angle from 70 to about 90 (or little more as per requirement)

drilling of horizontal drain hole along the object coal seam using under balanced drillingtechniques with 6"bit..

g. Drilling of side laterals (multilaterals) from the main lateral (Drain hole).h. Maximum length of Main lateral (Drain hole) to be drilled - 1000m.

i. Length of each side lateral - 400m.

j. Distance between two consecutive side laterals - 250m.


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k. Drilling of two oppositely heading side laterals from the same point on the main lateral(Drain hole). Accordingly drilling of b side laterals (2 x 3) from 3 points on the Main lateralhas been envisaged.

l. Average angle between the main lateral and each side lateral has been taken as 45o(Average).

m. Each well will handle completion against three coal seam objects, which are 50 - 100m

apart and are separated from each other by a non-coal parting.n. Up the dip -drilling of the Drain hole (Main lateral) portion has been considered as a

preferred method.

o. Incase of intersection of the main lateral with a normal fault, having more than 20m throw,possibility of further drilling along the fault plane to trace the same coal seam on the otherside of the fault at a deeper depth has not been thought of. Accordingly, the well locationson each object seam/ pack of seams has been so designed that well course of each ofthe main lateral along with its 6 branches on either side are restricted within one faultsector/block.

p. From each common point/site/pad possibility of drilling of maximum 3 wells have beenconsidered.

q. Considering all the above assumptions, the lateral (Drain hole) maximum cumulativemeterage of horizontal main drilling in each coal seam has been worked out to rangefrom 3400m - 1000m whereas maximum meterage of 6 horizontal side laterals has beenworked out to be about 2400m.

r. As each well will handle 3 object seams of one pack, the maximum cumulative horizontalcoverage within. these 3 target coal seams have been estimated to be in the order of10,200m.

Considerations for Completion:

a) Once drilling network (i.e. main lateral and side-laterals/branches) in each object seam iscompleted, the whip stock is retrieved fully and finally.

b) Depending on the strength of the coal seam, provision of putting slotted/pre- perforated poly

liner through the main lateral up to the desired depth and has been incorporated under thecompletion plan.

c) It has been considered that after completion of drilling of three object seams under each pack,finally removing whip stock from the well and putting the slotted liner into the drain hole portion,an Electric Submersible Pump is to be installed with 3 '/2" production tubing within the sumpportion below the bottom most object seam of the respective pack for faster de-watering andproduction testing.

The Proposed Development Plan

Considering all the technical requirements of the Horizontal - Inseam - Multilateral drillingtechnique, it has been observed that for full scale development of all the 9 object coal seams inthe central part (6 sq. km.) of Parbatpur area, about 20 horizontal wells are required ,to be drilled.These 20 wells are distributed in such a manner that the, main laterals and the side lateralscreate maximum exposure of each object coal seam to the well bores leading to maximumextraction of in-place CBM resource from the said area. Pack-wise distribution of the indicated 20Development Wells is summarized below:

a. For Upper Pack - 6 wells

b. For Middle Pack - 7-wells


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c. For Lower Pack- 7 wells

These 20 wells are to be drilled from 10 clusters /sites lpads. Out of these 10 pads, 4 pads (PodB, Pad C, Pad D & Pad F) will contain 3 wells each, 2 pads (Pad A and Pad E) will contain 2 wellseach and 4 pads (Pad G, Pad H, Pad I and Pad J) will contain 1 well each.

Suitability of the Horizontal inseam multilateral drilling technology for extracting CBM from thepoor permeability Indian Gondwana coal of Permfan, age is unknown. Moreover, permeability ofthe thick lower Barakar coal seams is found to be even poorer. In view of this, it is proposedunder the current Development plan, which is to be giving on service contract, to initially take updrilling and completion jobs of only 14 wells out 'of 20 horizontal well locations identified, to testthe applicability of the technology in the present geological setup, to practically experience itseffectiveness in coals with low to very low permeability and to observe the magnitude of increasein deliverability. Once these factors are ascertained and in the case of obtaining favorable resultsfrom these wells, drilling and completion jobs of the remaining 6 wells may be taken up in future.

Pack-wise distribution of the 14 Development Wells, proposed for initial drilling and completionactivities under the current development plan is summarized below:

a. For Upper Pack - All 6 Wells, identified

b. For Middle Pack - 6, out of 7 Wells identified.c. For Lower Pack - 2, out of 7 Wells identified.

These 14 wells will be drilled from 6 clusters/sites/pads, wherein 3 pads (Pad B, Pad C and Pad Fwill contain 3 wells each, 2 pads (Pad D and Pad E) will contain 2 wells each and 1 pad (Pad A)will contain 1 well.

Production Forecasting Aspects

In order to forecast production profile for the planned Development Wells, following factors havebeen considered and assumptions have been made

Co-mingled production testing of five Middle Barakar object coal seams in the verticalExploratory Well, JH#2 in Parbatpur area indicated a sustained production Q6000m3/day for a period of about 1 '/2 years.

Results of individual zone testing against two Lower Barakar object coal seams viz. III-IVcomposite seam & V- VII composite coal seam in the wells JH#2 8. JH#4 respectivelyindicated production @ 2000m3/day (approx).

Production testing against seam XV in the well JH# 1 in Parbatpur area revealedapproximate rate of production in the order of 1200m3/day.

Combining the above observations and considering about 10 to 15 times hike inproduction performance by the use of horizontal in-seam multilateral drilling and

completion techniques, production rate per day from the nine object coal seams, groupedunder 3 packs, have been estimated.

Preliminary assessment, based on the gas content data of the Exploratory Wells ofONGC, thickness of the coal seams and the density of the same indicated CBM in placeof the order of 8 BCM. in the 6 sq.km. central part of Parbatpur area. While estimatingCBM in-place, reduction of about 20% in the total resource of the central part has beenconceived due to some geological uncertainties viz. heat effect on coal seams by


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intrusives, omission of the seams by the normal faults, pinching of the seams, splitting ofthe seams etc.

Measurement of permeability of the object coal seams by well tests in the 3 exploratorywells in Parbatpur area shows a trend of reduction in permeability with increase in depthas given below:

Permeability of the seams-XV, XIV (A) 8, XIV which are clubbed under Upper Pack in thecurrent scheme, range from 1.0 to 3.Omd.

Permeability of the seams-XIII, XIV & XI, which are clubbed under Middle Pack in thecurrent scheme, range from 0.5 to 1.0md.

Permeability of the seams-IX, V-VII combined & 111-IV combined, which are ' clubbedunder Lower Pack in the current scheme, range from 0.25 to even lesser.

Based on the above observations, a tentative allocation of permeability against the 9 object coalseams have been made as follows for the purpose of assessing deliverability of each seam:

Seams under Upper pack - Average assumed Permeability 1.0md.

Seams under Middle pack- Average assumed Permeability 1.0md.

Seams under Lower pack - Average assumed Permeability 0.25md.

Laboratory analysis revealed six middle Barakar coal seams, under upper and middlepacks of the current development scheme, to have better type and quality than the lowerBarakar seams, of lower pack. Gas content of the six seams under upper and middlepacks range from 10 to 20cc/gm. with an average of 15cc/gm. and gas saturation rangefrom 80 to 90%. Gas content of the three seams, under lower pack range from 6 to15cc/grn with gas saturation up to 80%.

It is assumed that the lesser gas content and poorer permeability of the seams, underlower pack, may be compensated to some extent by their huge thickness, whichultimately imparts betterment in terms of their kh values and thereby aid improving theirproduction efficiencies.

Based on the above mentioned considerations, the co-mingled productivity per day from eachDevelopment Well, under current plan, are tentatively allocated as follows:

Each well, which will be completed in the three coal seams viz. Seam XV, XIVA and XIVof the Upper pack is expected to deliver CBM gas @ 71,000 m3/per day.

Each well, which will be completed in the three coal seams viz. seam XIII, XII and XI ofthe Middle pack is expected to deliver CBM gas @ 50,000 m3/per day.

Each well, which will be completed in the three coal seams viz. Seam IX, V to VII and III-IV composite seams of the Lower pack is expected to deliver CBM gas @ 29,000 M3/perday.

In accordance with the above mentioned per day per well production rate estimation, initial gasproduction rate from the proposed 14 Development wells is estimated to be in the order of7,84,000 m3/per day. From preliminary tentative production projection analysis the followingproduction pattern is anticipated.

The above mentioned per day gas production rate from 14 wells will sustain for a periodof initial 3 years.

It has been assumed that after initial 3 years production from 14 wells, there will be areduction in total production @ 5% per annum.


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In this manner cumulative gas production from 14 Development wells in 20 years lifecycle of the project has been estimated to be of the order of 3.93 BCM, which leads toestimated recovery factor of the order of 49.1 %.

Apart from the gas production projection, water production estimation has also been done asfollows based on the present experience of water production of the existing Exploratory Wells of

Parbatpur area.

Initial rate of de-watering from each Development well has been assumed to be 50M3/per day.

Accordingly cumulative volume of water production from 14 Development wells isestimated to be 700m3/day.

Surface Facilities

Considering the volume of per day gas and water production from 14 Development wells andbased on the proposed locations of the sites / pads, pipeline network within the 6 sq. km.identified area has been tentatively planned. Necessity of installing one GCS of 1 MMms/ dayhandling capacity in the central part of the said 6 sq. km. area has been felt. Accordingly, initialrequirements under surface facilities viz. installation of compatible compressors, ETP,Dehydration Unit etc. in connection with installation of the said GCS has been incorporated underthe Development Scheme and cost implication therein has been considered while working out thetechno-economics of the project.

Implementation Schedule

The execution of entire project is planned for 31 months including creation of surface facilities, butexcluding 12 months of maintenance of the wells after putting on regular production. Theschedule of project implementation shall be as follows:

Date Activity

15.01.2006 Award & Commencement of Work15.06.2007 Drilling & Completion of 5 wells. Completion of GCS

& connecting of 5 wells to GCS after theirproduction testing. Commercial production of gasfrom 5 wells @ 0.3 MM m3 per day.

15.08.2008 Drilling and completion of all 14 wells under thecontract, their connecting to GCS for regularcommercial production. Gas rate 0.784 MMm3 perday.

15.08.2009 Completion of the contract with completion ofsuccessful regular maintenance of 14th well

4.3 Status of the Project Activities

The status of project activities is as follows.

a. Tender for Integrated Turnkey Contract is floated.b. All 14 early pilot locations stand released after their firming up, staking and ground

checking.

c. Land acquisition work for different drill sites and GCS area Under progress.


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d. Environment clearance in progress.

Status of Environment and other Statutory, clearances:

a. Guidelines of JSPCB and DGMS shall be strictly adhered to.

b.All other statutory clearances from state govt, local bodies etc. will be obtained wheneverrequired for implementation of the scheme.

4.4 Marketing Arrangements

ONGC team carried out a market survey in September 2005 to evaluate CBM requirements ofprospective consumers and likely selling prices. The team visited the area around Bokaro steelcity and Dhanbad to have a first hand exposure of energy requirement /market in the vicinity ofJharia area. Interaction was held with Bokaro Chamber of Commerce and nearby majorindustries in the area, such as Bokaro Steel Plant, Sindri Cement Plant of ACC and BharatRefractoriness Ltd.

Prior to Survey, letters seeking expression of Interest were sent to major consumers from

different sections of user industries. Based on interest shown the following were called fordiscussions to understand their requirements, details of various energy sources used by them, acomparative cost to the consumers, gauge their interest and price affordability. The industriesincluded SAIL, Bokaro Steel plant, Bokaro, Damodar Valley Corporation, Kolkata, Tata power,Jamshedpur, Hindqlco Industries, Chhotamuri, Ranchi Distt., Lafarge Cements, Jamshedpur,CC&L/ WBTIDCL (for CNG in Kolkata) and Greater Calcutta Gas supply Corporation Limited

The CBM requirement in the nearby region of about 60-70 km radius including eastern parts suchas Bokaro Steel city, Chhotamuri, Ranchi and western markets like Dhanbad, Sindri, Maithon etcis estimated over 4.5 MMSCMD. The following end-uses of CBM has been suggested.

a) As Substitute of Existing Fuels in Use

Some of the companies have expressed keen interest in switching over to CBM gas. They are asfollows.

SAIL- Bokaro Steel Plant uses coke as feedstock for its blast furnaces, which could besubstituted by CBM. Considering the landed prices of imported coke, the fuel valuationfor CBM is around $5.3 to $5.5/MMBTU on energy equivalent basis. As only about 69%of the coke is effectively utilized for blast furnaces, the effective imputed valuation ofCBM works out to nearly $8/MMBTU.

DVC Maithon is having it Gas Turbine station at Maithon in idle condition due to highcosts of liquid fuel it was using earlier. The turbine at present can be operated in opencycle mode. The valuation for CBM is estimated to be $3.74 MMBTU in open cycle. Theinstallation of combined cycle system will make the valuation of CBM even moreattractive.

b) Sale as CNG in Kolkata for Mass transport

The West Bengal government is interested in introducing CNG for public transport vehicles inKolkata in a gradual manner. CC&L led consortium, authorized by West Bengal TransportationInfrastructure Development Corporation has desired the delivery of gas (about 6000 kg/day) byDecember 2005. Keeping in view the instructions of the Green Bench of the Kolkata High court,the demand would be gradually ramped up to the level of 3 lakh SCMD by March 2007. The total


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estimated demand potential is about 1.0 MMSCMD for this sector. However, there is no concretedevelopment on this front as of-now.

c) Option of generating power from gas

ONGC has also explored the avenue for generation of power from CBM to work out comparative

analysis for different options in marketing of CBM. Power industry is gradually getting deregulatedand any party is now allowed to generate power for commercial purpose. There is shortage ofpower in Jharkhand in general and it would be possible to market power in the region. PowerTrading Corporation of India has offered a rate of Rs. 2.05/kwh in case ONGC decides togenerate power from CBM. The imputed valuation for gas works out to $3.33/MMBTU forCombined Cycle Gas Turbine system.

Considering the available options for the sale of CBM, it is ,unlikely that ONGC will face anyproblems with respect to the marketing of CBM. However, the financial projections have assumedthe sale of entire production to SAIL as a scenario. This is due to the fact that SAIL has conveyedtheir readiness to purchase the entire projected production of 0.78 MMSCMD for their Bokaroplant. pipeline for delivery of the gas to the Bokaro plant of SAIL as a part of the project.

4.5 The Project Cost and Means of Finance

The total project cost has been estimated at Rs. 528 crores including the Rs. 75 crores as cost ofsetting up pipeline network-for transportation of gas to the to be totally funded by equity orinternal sources. The breakup of the project costs is given below.

S.No

Details Amount (Rs. InCrores)

1 Drilling Costs for 14 wells 215.89

2 Mobilization Costs of Drilling Rigs 10.00

3 Civil Work at Well Sites 3.33

4 Approach Road and Culvets 2.785 Civil Work at GCS 1.02

6 Logging Operations 38.54

7 Costs of Interpretation of Logs 0.48

8 Well Completion 13.26

9 Production Testing 2.21

10 Maintenance Charges 8.40

11 Surface Creation Facilities 59.76

12 Setting Up of Office 10.00

13 Contingencies @ 20% 73.84

14 Escalation in Capex 6% 13.53

TOTAL 453.06

15 Setting up of Pipeline Network for SAIL 75.00

TOTAL 528.06

The details of the individual cost heads are given in Annexure- I. The year wise breakup of capexschedule is as follows.


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Capex Schedule including contingenciesin Rs. Crores

2006-07 196.11

2007-08 300.11

2008-09 30.14

2009-10 1.70

Total 528.06

The cost of setting up of the pipeline network for transportation of gas to the SAIL's plant inBokaro is considered in the year 2007-08 as the commercial production of the gas begins in thatyear. The year wise detailed breakup of Capex schedule is given in Annexure II.

The total project cost is proposed to be met by internal accruals as ONGC has surplus cashfunds.

5. FINANCIAL FEASIBILITY AND SENSITIVITY ANALYSIS

5.1 Financial Projections

The financial projections have been made considering two scenarios.

Scenario 1: Delivery at GCS Fence

Under this scenario, the entire production is assumed to be sold at the GCS Fence at a price ofUS$ 3.86 per MMBTU or Rs. 54.95 lac per MMSCM. The price has been assumed on the basisof the price fixed by the Government in the case of Panna Mukti Tapti consortium.

A brief profitability statement under this scenario is as follows.

Year ending 31 May-07 Mar-08 Mar-09 Mar-10 Mar-11 Mar-12 Mar-13 Mar-14 Mar-15

Production Levels 0 40% 100% 100% 100% 95% 90% 86% 81%Annual Production(MMSCM)

0.00 109.76 274.40 274.40 274.40 260.68 247.65 235.26 223.50

Revenue 0.00 54.70 136.74 136.74 136.74 129.91 135.75 128.96 122.52

Royalty to StateGovt.

0.00 5.48 13.71 13.71 13.71 13.02 13.61 12.93 12.28

Production Linked

Payment to GOl 0.00 4.47 3.68 3.68 3.68 3.49 3.65 3.47 3.30

Net Revenues 0.00 53.37 133.42 133.42 133.42 126.75 132.45 125.83 119.51

Less: OperatingExpenses 2.78 15.86 16.36 15.82 22.51 23.55 25.62 26.83 28.14

PBDIT (2.78) 37.51 117.06 117.60 110.91 103.20 106.83 99.00 91.40Depreciation 39.22 68.56 53.04 43.92 37.25 31.66 26.91 22.87 19.44

Interest 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00,

PBT (42.00) (31.04) 64.01 73.68 73.66 71.54 79.92 76.12 71.95

Provision for Tax 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 24.22

PAT (42.00) (31.04) 64.01 73.68 73.66 71.54 79.92 76.12 47.73


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The detailed financial assumptions, projected Profitability Statement, projected Balance Sheetand projected Cash Flow statement is given in Annexure III, Annexure V, Annexure VI and

Annexure VII respectively.

Scenario 2: Delivery at Customer Premises

Under this scenario, the entire production is assumed to be sold to Steel Authority of India Limitedat a floor price of US$ 3.86 per MMBTU or Rs. 54.95 lac per MMSCM. However, it is expectedthat ONGC would be able to negotiate better price as it will be setting the distribution network forthe same on its own cost.

The capital expenditure in this case assumes an additional investment of Rs. 75 crores for thepurpose of setting up pipeline and compressor system for the transportation of the gas at thepremises of SAIL's steel plant at Bokaro. The operating expenses have also been suitablyadjusted to account for the fuel consumption by compressor and other expenses relating to themaintenance of the pipeline.

The brief profitability statement for this scenario is as follows.

Year ending 31 May-07 Mar-08 Mar-09 Mar-10 Mar-11 Mar-12 Mar-13 Mar-14 Mar-15

Production Levels 0% 40% 100% 100% 100% 95% 90% 86% 81%Annual Production(MMSCM)

0.00 109.76 274.40 274.40 274.40 260.68 247.65 235.26 223.50

Revenue 0.00 60.32 150.81 150.81 150.81 143.27 149.71 142.23 135.12

Royalty to StateGovt.

0.00 5.5 13.7 13.7 13.7 13.0 13.6 12.9 12.3

Production LinkedPayment to GOl 0.00 1.5 3.7 3.7 3.7 3.5 3.7 3.5 3.3

Net Revenues 0.00 53.4 133.4 133.4 133.4 126.7 132.5 125.8 119.5

Less: OperatingExpenses 2.8 20.7 25.6 25.2 32.1 32.9 35.5 36.6 37.8

PBDIT (2.8) 32.7 107.9 108.2 101.4 93.8 96.9 89.2 81.7

Depreciation 39.2 83.6 62.0 51.6 43.8 37.2 31.6 26.9 22.8

Interest 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00,

PBT (42.00) (50.8) 45.8 56.7 57.6 56.6 65.3 62.3 58.9

Provision for Tax 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 19.8

PAT (42.0) (50.8) 45.8 56.7 57.6 56.6 65.3 62.3 39.0

The detailed projected Profitability Statement, projected Balance Sheet and projected Cash Flowstatement is given in Annexure VIII, Annexure IX and Annexure X respectively.

5.2 Key Financial Indicators

The key financial indicators in both the scenarios are as follows.

Financial Indicators Delivery at GCS Fence Delivery at Custom Premises

NPV (Rs.in Crores)* 191.90 70.73

Post Tax Project IRR 19.67% 13.29%


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PBP (No. of years) 5.16 6.16

ROCE (Year ending Mar 31, 2010) 25.96% 20.50%

Break Even (Year ending Mar 31, 2010)5.43% 12.91%

Project Cost of Funds

The project is- envisaged to be funded totally by internal accruals. The hurdle rate as approvedby ONGC Board for project appraisal is 10%. Hence, the cost of capital is taken as 10% for thecalculation of Net Present Value (NPV) of the project.

5.3 Sensitivity Analysis

The sensitivity analysis for the project was carried out by considering the impact of the followingfactors on the profitability of the project.

Sensitivity Factors Assumption

Increase in Project Cost (A)+5%

Decrease in Sales Price (B)-5%Increase in Expenses (C) +5%

The following table assesses the Impact of the above sensitivity factors on the profitability of theproject.

Scenario 1: Delivery at GCS Fence

Base CaseA B C

Post Tax Project IRR19.67% 18.34%17.90%19.31%

NPV (In Rs. Crores) 191.90 173,08 154.74 183.15

PBP (in years) 5.16 5.20 5.21 5.17ROCE 25.96% 24.72%24.48%25.78%

Break Even 5.43% 5.43% 5.73% 6.06%

In this scenario, project is commercially viable under .all the scenarios considered. However, thescenarios of decline in price had the biggest impact on the financial indicators.

Scenario 2: Delivery at Customer Premises

Base CaseA B C

Post Tax Project IRR13.29% 12.18%11.68%12.78%

NPV (In Rs. Crores) 70.73 48.92 35.55 58.93PBP (in years) 6.16 7.03 7.04 6.18

ROCE 20.50% 19.52%19.30%20.26%

Break Even 12.91% 12.91%13.35%13.92%

The above analysis shows that the project is financially viable under most of the scenarios thatcould have a negative impact on the profitability of the project. However, a decline in price by 5%leads to sharpest fall in project IRR falls to 11.68%. Therefore, the pricing of the gas is critical forthe project to be viable. It is expected that ONGC would be able to negotiate for a better price, as


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it would providing the gas at the premises of the customer. Also, if the recovery factor of the gasis improved leading to improved production volumes, the viability of the project can be furtherenhanced.

6. Risk Factors & Mitigants

Risk Mitigation MechanismDevelopment Risk

Selection of EPCContractor Approvals& Clearences

Selection of EPC Contractor ought to be donebased on the ability and predetermined criteriathrough a competitive bidding process Approvalsrequired for the project are mostly environmentalclearences and ONGC shall be obtaining allapprovals prior to start of drilling operations.

Construction Risk

Machinery &Construction

Adequate insurance policies shall be taken bythe EPC contractor during supply of equipmentup to the project site, during storage of

equipment and during the construction period tocover for the asset risks.

Cost & Time Overrun The project shall be implemented through anintegrated tarnkey Contract, thus limiting theconst overrun risks. The contract would also bestipulating adequate liquidated damages payableto ONGC in the event of any failure to comply.

Funding Risk Arranging the project funding would not be anIssue, as ONGC would be investing in if from itsinternal accruals.

Operating Risk

Reserves Estimation The estimation of reserves has been carried out

by ONGc itself by drilling exploratory wells. Thefour exploratory wells drilled by ONGC in 1999,have been taken as key wells for estimating gascontent and gas saturation characteristics. Theanticipated ultimate recovery of in place reserveshas been estimated at a conservative recoveryfactor of 49%.

Operations &Maintenance

Under the O & M agreement, EPC contractorshould provide an unconditional guarantee forcertain minimum production output.

Revenue Risk

Offtake The site is located close to Bokaro Steel city and

Dhanabd where __ number of Industries arelocated. The site is also close to Kokata wherethe CBM can be sold as CNG for masstransport. As of now SAIL has shown keeninterest in sourcing entire production of CBM orthe steel plant in Bokaro.

Price The sales price of CBM is determined based onprevailing LNG price. The CBM Policy advocatesmarket determined pricing for CBM. ONGC is


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still to negotiate with SAIL on the pricing of CBM.

Competition This project is first of its kind in India, Hence, nosuch risk is envisaged. However, on assessingthe competition with substitute like coal or coke,CBM turn out to be superior and cheaper.

Other Risk

Environment The extraction of Coal Bed Methane leads togeneration of watering of coal beds andtherefore, its salline and cannot be concerned.This water is neither suited for irrigation. Thedeployment of water still needs to be addressed.Currently, the water is supposed to the drainedwithin the coal field area.

Force Majeure A comprehensive insurance cover needs to betaken by ONGC to account for losses because ofForce Majeure.

Regulatory The Government of India is actively CBMdevelopment as it will help meet the growing

demand of natural gas in the country. The CBMPolicy provides for incentives for thedevelopment of CBM. It is expected thatregulatory stance would be favorable for CBM inthe years to come.

7. KYOTO PROTOCOL & BENEFITS FROM CARBON CREDITS

The presence of certain gases, such as carbon dioxide (CO2), methane, and nitrous oxide,enables the atmosphere to act like a greenhouse, retaining part of the solar heat. The naturalgreenhouse effect is desirable as it traps part of the incoming solar energy to maintain habitabletemperatures on, the earth's surface. However, human activities, like . burning of fossil fuels,deforestation, agricultural practices, and manufacturing are increasing the concentration of GHGs

in the atmosphere and causing an enhanced greenhouse effect. resulting in higher globalaverage temperatures. Impacts are likely to include changes in precipitation patterns, increasedfrequency and intensity of storms surges and hurricanes, changes in vegetation, and a rise in sealevel. Developing countries, especially the poor ones, are more vulnerable to these changesgiven their high dependence on natural resources and their limited capacity-human, financial, andinstitutional-to adapt to extreme events. Climate changes can have severe adverse impacts onthe health and livelihood of the poor. Extreme climate conditions exacerbated by climate changecan, divert scarce development resources from poverty reduction into disaster recovery.

Amidst growing concern and increasing awareness on the need for pollution control, the conceptof carbon credit came into vogue as part of an international agreement, popularly known as theKyoto Protocol. Kyoto Protocol is a voluntary treaty signed by 141 countries, including theEuropean Union, Japan and Canada for reducing Greenhouse Gases (GHG) emission by 5.2%

below 1990 levels by '12. However, the US, which accounts for one-third of the total GHGemission, is yet to sign this treaty. Carbon credits are certificates Issued to countries that reducetheir-emission of GHG, which causes global warming. It is estimated that 60-70% of GHGemission- is through fuel combustion in industries like cement, steel, textiles and fertilizers.

The concept of carbon credit trading seeks to encourage countries to reduce their GHGemissions, as it rewards those countries which meet their targets and provides financialincentives to others to do so as quickly as possible. Surplus credits (collected by overshooting theemission reduction target) can be sold !n the global market. One credit is equivalent to one tonne


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of CO2 emission reduced. Carbon Credits (CC) are available for companies engaged indeveloping renewable energy projects that offset the use of fossil fuels.

Developed countries have to spend nearly $300-500 for every tonne reduction in CO2, against$10-$25 to be spent by developing countries. In countries like India, GHG emission is . Muchbelow the target fixed by Kyoto Protocol and so, they are excluded from reduction of GHG

emission. On the contrary, they are entitled to sell surplus credits to developed countries. It ishere that trading takes place. Foreign companies who cannot fulfil the protocol norms can buy thesurplus credit from companies in other countries through trading.

Thus, the stage is set for Certified Emission Reduction (CER) trade to flourish India is consideredas the largest beneficiary, claiming about 31% of the total world carbon trade through the CleanDevelopment Mechanism (CDM), which is expected to rake in at least $510bn over a period oftime.

The trading takes place on two stock exchanges, the Chicago Climate Exchange end theEuropean Climate Exchange. CC trading can also take place in the open market. Europeancountries and Japan are the major buyers of carbon credit.

The Kyoto Protocol provides for three mechanisms that enable developed countries withquantified emission limitation and reduction commitments to acquire greenhouse gas reductioncredits. These mechanisms are Joint Implementation (JET), Clean Development Mechanism(CDM) and International Emission Trading (IET). Under JI, a developed country with relativelyhigher costs of domestic greenhouse reduction would set up a project in another developedcountry, which has a relatively low cost.

Under CDM, a developed country can take up a greenhouse gas reduction project, activity , in adeveloping country where the cost of GHG reduction project activities is usually much lower. Thedeveloped country would be given credits for meeting its emission reduction targets, while thedeveloping, country would receive the capital and clean technology to implement the project.

Under IET mechanism, countries can trade in the international carbon credit market. Countries

with surplus credits can sell the same to countries with quantified emission/limitation andreduction commitments under the Kyoto Protocol. `Getting carbon credits -certified for Kyoto is alengthy and complex process. There are four stages of CDM approval. The first stage is at thedomestic level, where National CDM Authority (NCM) approves the project. After NCM's approval,the project is sent to the United Nations Framework Convention on Climate Changes.

After this, the executive board of UNFCCC reviews the project. The project gets evaluated onevery front and is then registered under UNFCCC only if it meets all the norms. Thereafter,certification is done for the reduction in emission and credits are issued.

Currently carbon credits are being traded at US $ 7-10 per CER (1000 kg. of CO2). In India thiscan translate to improvement in project IRR between 3-5% and thus would be significant driverfor growth in the sector once carbon credit trading becomes well established.

The project proposal should establish the following in order to qualify for consideration as CDMproject activity:

Emission Additionality; The project should lead to real, measurable and long term GHGmitigation, The additional GHG reductions are to be calculated with reference to abaseline. Baseline is the scenario, which represents the emissions by sources of GHGsthat would occur in the absence of the registered project activity.


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Financial Additionality: The procurement of Certified Emission Reduction (CERs) shouldnot be from Official Development Assistance (ODA).

Sustainable Development Indicators - It is the prerogative of the host Party to confirmwhether a clean development mechanism project activity assists It In achievingsustainable development. The CDM projects should also be oriented towards Improvingthe quality of life of the poor from the environmental standpoint.

The CDM project activity should lead to alleviation of poverty by generating additionalemployment, removal of social disparities and contribution to provision of basic amenities topeople leading to improvement in quality of life of people.

Economic well-being; The CDM project activity should bring in additional investment consistentwith the needs of the people.

Environmental well being: This should include a discussion of impact of the projectactivity on resource sustainability and resource degradation, if any, due to proposedactivity; bio-diversity friendliness; impact on human ?health; reduction of levels ofpollution in general;

Technological well being: The CDM project activity should lead to transfer of

environmentally safe and sound technologies that are comparable to best practices inorder to assist in upgradation of the technological base. The transfer of technology canbe within the country as well from other developing countries also.

The project proponent could develop a new methodology for its project activity or could use oneof the approved methodologies by the CDM Executive Board. For small-scale CDM projects, theproject proponent can use the simplified procedures. The project proposal should Indicate theformulae used for calculating GHG offsets in the project and baseline scenario. Leakage, if any,within or outside the project boundary, should be clearly described. Determination of alternativeproject, which would have come up in absence of proposed CDM project activity should also bedescribed in the project proposal.

Procedure for Registration

The National CDM Authority is a single window clearance for CDM projects in the country, Theproject proponents are required to submit one soft copy of Project Concept Note (PCN) andProject Design Document (PDD) through online form and 20 hardcopies each of PCN and PDDalong with two CDs containing all the information in each of them. The project report and CDsshould be forwarded through covering letter signed by the project sponsors. The project reportsubmitted should be properly bound. The National CDM Authority examines the documents and ifthere are any preliminary queries the same are asked from the project proponents. The projectproposals are then put up for consideration by the National CDM Authority. The project proponentand his consultants are normally given about 10-15 days notice to come to the Authority meeting ,and give a brief power point presentation regarding their CDM project proposals. Members seekclarifications during the presentation and in case the members feel that some additionalclarifications or information is required from the project proponent the same is informed to the

presenter. Once the members of Authority are satisfied, the Host Country Approval (HCA) isissued by the Member-Secretary of the National CDM Authority.

Financial Implication of Carbon Credit Benefits

I. The Role of Emissions Reduction Credits in Stimulating Project Development

When coal mine gas supplants other fuels, emissions of SOx, NOx, and particulates are typicallylowered. Coalmine gas projects may thus be eligible for emissions reduction credits - or other


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types of environmental incentives that may be in place in the particular country or region wherethe project is implemented.

Greenhouse gas emission reduction credits also may be available for projects that utilize ordestroy coalmine gas. By preventing this powerful greenhouse gas from escaping to theatmosphere, such projects can mitigate global climate change. An active greenhouse gas market

has emerged, however, and brokers have supported numerous transactions whereby parties thatmay benefit from offsetting carbon emissions have purchased the right to tradable credits thatmight exist in the future. These purchase options have already aided in developing projects thatreduce methane emissions.

Per unit of energy, combustion of natural gas results in 42 percent less carbon dioxide emissionsthan coal and 29 percent less than residual fuel oil. Significant reductions in carbon dioxideemissions could be made through fuel switching, for example, from residual fuel oil to natural gas.Each pound of non-combusted methane that escapes to the atmosphere is 21 times more potentas a greenhouse gas than carbon dioxide, Global Warming Potential (GWP) of methane (CH4) =21, GWP of CO2 = 1, Combustion of one tonne of CH4 produces 2,75 tonnes of CO2; thereforethe capture and combustion one tonne of otherwise fugitive CHQ emissions yields a GWP benefitof at least 18.25 tonnes CO2. If the captured CH4 is used as energy source (on-site or delivered

into a pipeline) the full 21 tonnes of GHG reductions can be claimed.

Since the project aims at capturing methane and using if' as energy resource, the projectwould be eligible for 21 tonnes of GHG reductions per 1 tonne of methane.

The methane captured over the lifetime of the project is estimated at 950k of 3.93 BCMor 2.80 million tonnes (1 tonne of gas is equivalent to 1333 cu - m.)

The total carbon credits the project would be eligible for is 58.8 million tonnes of GHGreductions or 58.8 million carbon credits over its lifetime.

Assuming these credits are traded at a price of USD 5 per Credit, the cash-flows theproject can be tremendously enhanced.

If Carbon credits are factored in financials of the project along with the cost incurred for availingthe carbon credit benefit under CDM, these credits can increase the IRR by around 2.5% to 3%.

Recent Developments

A coal mine/coal bed methane utilization project in northeast China entered into agreements withtwo separate buyers under the Clean Development Mechanism (CDM), according to AsianDevelopment Bank (ADB). ADB's Clean Development Mechanism Facility and Clear worldEnergy, a clean energy development company headquartered in Beijing, structured thetransactions. The seller in the transaction is Fuxin Mining Group and the buyers are ICTJ Limitedand a consortium led by Natsource. The project is expected to improve coalmine methane andcoal bed methane extraction, distribution, and utilization at mines around Fuxin, LiaoningProvince.

8. RECOMMENDATIONS

UTI Bank has examined the financial viability of the propos6d proje6t based on the DFR madeavailable along with extensive discussions with ONGC officials. UT'I Bank has assessed theviability of the project under the impact of various scenarios by carrying out sensitivity analysisunder various scenarios, which seek to present the financial results in case of changes in the keyassumptions. Based on the appraisal exercise, it may be concluded that the project is viableunder the Base Case scenario under both the scenarios


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Scenario l: Delivery at GCS Fence with a post-tax IRR of 19.67% and a NPV of Rs.191.90 crores at 10% rate of return

Scenario 2: Delivery at Customers Premises with a post-tax IRR of 13.29% and a NPV ofRs. 70.73 crores at 10% rate of return

The IRR for Scenario 2 is lower as additional investment of Rs. 75 crores is considered in setting

up the pipeline and compressor for supplying the gas at customer premises. However, the priceassumption has been kept constant at US$ 3.86 per MMBTU. Therefore to get better returnsONGC should negotiate with the customer to pay price higher than US$ 3.86 MMBTU, whichwould also cover up the expenses of transportation from GCS Fence to Customer Premises.

The sensitivity analysis also shows that the project is viable under various adverse scenarios. It isexpected that the returns from with project would further improve as the financial projections havebeen made at a conservative estimate of 49.1 % recovery of the estimated reserves of 8 BCM.The preliminary analysis done by ONGC suggests that there is good potential demand of gas inthe nearby markets and thus the prices are likely to improve in comparison to the prices assumedfor financial projections. Also, the eligibility of the project for carbon credits may further improvethe profitability of the project.

A study has also been carried out to assess the potential risks to the project and the expectedrisk mitigation mechanisms. The study indicates that the offtake risk is low due to existingdemand of Gas in the area. The cost and time over run risks are being mitigated adequately byONGC by entering into LSTK contracts with reputed CBM Service Providers and includingsuitable performance clauses to allocate these risks, to the extent possible, to the third parties.

Keeping in view the above analysis and subject to the investment risks and the impact of thevarious scenarios as discussed under the sensitivity analysis, the capital expenditure; program ofONGC for the proposed project is considered financially and commercially viable.

Annexure - I : Detailed Project Cost Break Up

1) Drilling Costs

a) Cost of Drilling main deviated section of each well of 1850 m measured depth

Item Rate Quantity Total Amount (In Rs.Lac)

Drilling (hiring of rig) 7 Rs. lac per day 60.00 days 420

Cementation - - 51

Casing Pipe 67 $/m for 9 5/8" 300 m 9

Casing Pipe 40 $/m for 7" 1850 m 34

Well Head 3 Rs. Lacs 1 3

Mud Chemicals &

other wellconsumables

25 Rs. Lacs 25

Total Cost per well 25 Rs. Lacs 542

b) Cost of Drilling in -seam sections in each of horizontal well of 1850 m measured depth

Item Rate Quantity Total Amount(in Rs. Lac)


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Drilling (hiring of rig 7 Rs. lac per day 60 days 420

Cutting Windows 60,000 US $ 3 83

MWD & Gamma Ray $ per day operational

Package 1900 charges 60 days 52

$ per day operational

SDMM Package 2800 charges 60 days 77

Rs. Lac per day

UBD Package 7.8 operational charges 60 days 468

Speciality Mud Chemicals &Other well consumables

50 Rs. lac 50

Total Cost per well 1,151

Cost of Drilling the wells of varying dpeths

Cost of Drilling 1 well of 1850 m 1,693



Total Drilling Costs (in Rs. Lacs)21,589

C) Mobilization Costs of Drilling Rigs @ Rs.250 lacs = Rs. 1000 lacs

Average Drilling Costs per well = Rs. 1613 lacs

2) Civil Work

a) Drill Sites

Type Rate Quantity TotalAmount (in Rs. Lac)

1 Well Site 38 Rs. lac 1 38

2 Well Site 52 Rs. Lac 2 104

3 Well Site 63.5 Rs. Lac 3 190.50

Total 6 332.5

b) Approach Roads and Culverts

Description RateQuantity Total Amount (in Rs. Lac)

New Road 13 Rs. Lac per km 12 156

Upgradation of Old Road9 Rs. Lac per Km 12108Culvert 0.6 24 14.40

Total 278.4

C) Cost of Civil Work at GCS = Rs. 100 lacs

Total Costs of Civil Work = Rs.710.9 lacs


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Average Costs per Drill Sites including roads = Rs. 101.8 lacs

3) Logging Operations

a) Field Operations

Type of Well Rate Quantity Total Amount (in Rs. lac)

8 1/2" Opern Deviated Section514.72 US $ per m15,900 m3764.66

7" Cased Deviated Section 12.28 US $ per m 15,900 m89.82

Total 3854.48

b) Interpretation of Logs & Report

in Us $In Rs. LacQuantity Total Amount (in Rs. Lac)

Interpretation Costs of all logs7435 3.42 14 wells 47.88

Total Costs of Logging 14 Horizontal Wells = Rs. 3902.36 lacs

Average Costs of Logging per well = Rs.278.74 lacs

4) WELL COMPLETION

a. Cost of Tubing of 18000 m = Rs. 66.5 lacsb. Cost of 14 ESPs required = Rs. 1050 lacs

c. Cost of lowering ESPs = Rs. 1050 lacs

Total costs of Well Completion = Rs. 1326.5 lacs

Average Costs of Well completion per well = Rs. 94.7 lacs

5) PRODUCTION TESTING

a) Manpower Costs

Manpower Costs per day (in Rs.) 750

Manpower Required per day 4

Manpower Cost per month (in Rs.)90000

b) Equipment Rental Cost per month (in Rs) = 100000

c) Power Consumption per month (in Rs.) = 600000

Total Costs of Production Testing = Rs. 221.2 lacs

Average costs of Production Testing per well = Rs. 15.8 lacs

6) MAINTENANCE OF WELLS


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WOR Hiring Charges per day = Rs, 100000

Total Maintenance Costs = Rs. 840 lacs

Average Maintenance Costs per well = Rs. 60 lacs

7) CREATION OF SURFACE FACILITIES

GCS Cost 2650

Flow line cost 1750

Underground Cable Cost 1000

Transformer Cost for each well 5

Area Lighting Cost for each pad 1

Initial Capital Cost of Power Electric Arrangements500

Total cost of surface facilities 5976.0

8) Expenditure for setting up of Project Office = Rs. 1000 lacs

9) Additional Capex for Delivery at the Premises of SAIL = Rs. 7500 lacs (includes the cost ofcompressor system and station at Rs, 6250 lacs and cost of setting up pipeline ne4work at Rs.12,50 lacs)

Annexure II: Cost Breakup in the different years of execution

Capex 2006-07 in Rs. Lac

Civil Work at 6 drill sites/pads including roads 611

Civil Work at GCS 100

Drilling of 5 wells 8,067

Logging of 5 wells 1,394

Surface Facilities (80%) 4780.8

Completion of 5 wells 473.7

Production Testing of 5 wells 79

Maintenance of wells 0

TOTAL (in Rs. Lac) 15,506

Capex 2007-08 in Rs. Lac

Drilling of 8 wells 12,908

Documents

Ongc to Develop of Parbatpur Area in Jharia Coal Field in Jharkhand for Commercial Production of Cbm