Coalbed Methane Could Cut India's Energy Deficit

Jonathan Kelafant
Advanced Resources International Inc.
Arlington, Va.

Mark Stern
MathTech International Inc. Arlington, Va.

Foreign interest in upcoming Indian coalbed methane (CBM) concession rounds will depend on prospect quality, fiscal regime attractiveness, and perceptions interested parties will have concerning the government's willingness to promote development.

The more liberal tax and royalty provisions for foreign producers announced by the Ministry of Petroleum & Natural Gas indicate that India is interested in attracting international CBM investments.

The country's rapidly expanding economy is creating a tremendous surge in demand for natural gas. However, India's conventional gas resources are limited and unlikely to meet the growing demand. Faced with this shortfall, India must turn to either importing natural gas, either through pipelines or LNG, or attempt to exploit its unconventional gas resources such as CBM, gas hydrates, and gas shales.

Importing gas is a known option, but will require substantial capital investment, necessitate a relatively high gas price, and be subject to concerns over energy security.

Recently, the Indian government advanced initiatives to spur the development of its unconventional gas resources, especially CBM and gas hydrates. These initiatives will hopefully have an impact similar to U.S. initiatives of the late 1970s and early 1980s that stimulated the current unconventional gas production of nearly 4 tcf, accounting for over 20% of U.S. natural gas production.

This article examines the potential for developing the country's large CBM resource base, estimated between 30 tcf (250 billion cu m) and 144 tcf (4 trillion cu m) of gas. It also provides an overview of the current contractual and regulatory framework governing CBM development.

India is currently the world's third largest coal producer, producing 308 million tons in 1996, and ranks fifth in proven coal reserves with nearly 70 billion tons. The bulk of India's coal reserves are located in the eastern portion of the country in the states of West Bengal, Bihar, Orissa, and Madhya Pradesh (Fig. 1 [123,441 bytes]).

Coal fields in this region are principally Permian in age (Gondwanan) and are distributed along major river Valleys from which the coal fields are named.

The three major coal fields are:

1. The Damodar Valley
2. The Son-Mahanadi Valley
3. The Pranhita-Godavari Valley.

The Damodar Valley coal fields are the most heavily mined and will be among the first coal fields available for CBM exploration.

In addition to the eastern Gondwanan coal fields, India hosts a wide range of other age coal fields including Jurassic, Cretaceous, Eocene, Oligocene, Miocene, Pliocene, and Pleistocene-age fields. Most of these fields contain lower-rank lignitic to sub-bituminous coal seams.

The Cambay basin of Gujarat, which contains thick, sub-bituminous coal seams, has received most of the attention for CBM exploration and has been the site of several production test wells.

Damodar Valley geology

Through Gondwana times, the continents of Africa, Antarctica, Australia, India, and South America were joined together as a supercontinent known as Gondwanaland. During this time, coal deposition was widespread, forming the large Gondwana coal reserves of India, South Africa, and Australia.

In general, the Gondwana coal seams are mineral-rich, vitrinite-poor, and highly variable in maceral composition. About 110 million years ago during the Cretaceous, the Gondwanaland supercontinent began to break up and India began drifting north towards Asia.

The Damodar Valley represents a rift structure developed within the eastern India shield province. The east-west length of the Damodar Valley approaches 270 miles (450 km) with a north-south width of 36 miles (60 km) (Fig. 2 [80,513 bytes]).

Rifting occurred as a result of high heat flow underneath the shield which caused lithospheric thinning and faulting. As this zone of weakness subsided, depositional environments favorable to coal formation (fluvial, swamp) were created.

During Gondwana times, coal seams were most likely formed throughout the entire Damodar Valley. Subsequent uplift and erosion of the Gondwana sediments, however, has left only the isolated coal fields now present in the Damodar Valley.

The Damodar Valley coal fields are preserved as graben and half-graben structures. The principal fault in the Damodar Valley is the southern boundary fault, a major normal fault that runs the length of the Damodar Valley and marks the southern edge of the major coal fields where Gondwana sediments are juxtaposed with the Precambrian gneissic terrain. Displacements along this fault are on the order of 1 to 1.5 miles (2-3 km).

Within the Damodar Valley coal fields, intrabasinal faulting and igneous activity have complicated the structure of the basins. According to the Coal Mine Planning & Design Institute, the combination of "faults and igneous intrusions have imparted a complex structural character to the basins which has a direct bearing on the resource potential and exploitation of the coal deposits." While this statement expresses the concerns of the coal mining industry, it applies equally to CBM exploration.

Stratigraphy

The Gondwana sediments of India can be divided into lower Gondwana (Permian to lower Triassic) and upper Gondwana units (upper Triassic to lower Cretaceous) based on color, lithology, and floral and faunal assemblage. The two principal coal-bearing formations are the Karharbari/Barakar and Raniganj formations.

The Barakar formation is the chief coal-bearing horizon on the Indian subcontinent. Although it is well developed in different coal fields around the country, it is best developed both in number of coal seams as well as in coal quality in the Jharia and Raniganj coal fields.

On the basis of recent drilling carried out by the Geological Survey of India, it has been observed that the maximum thickness of this formation is about 2,400 ft (730 m) and 3,600 ft (1,100 m) in the Raniganj and Jharia coal fields, respectively. In most of the other fields, it ranges from 2,000 ft (600 m) to 2,500 ft (750 m) in thickness.

The Barakar formation contains up to 50 coal seams greater than 1.5 ft thick in the Jharia coal field and has at least four or five completable zones in all of the basins. Total coal thickness of the Barakar formation exceeds 200 ft in most areas.

The Raniganj formation is named after the town Raniganj in the coal mining district of Burdwan in West Bengal. It has its maximum thickness and economic importance in the Raniganj coal field.

However, the importance of this coal-bearing horizon diminishes moving westward. Even in the Jharia coal field, the next field to the west, the Barakar seams are more important than the Raniganj seams. Further to the west, in the Bokaro, Karanpura, and the Central Indian coal fields, no coal seams of economic importance are developed within the formation.

The Raniganj formation contains 10 productive coal seams, each 3-35 ft (1-11 m) thick, designated seams R-I through R-X. Coal thicknesses up to 60 ft (18 m) have been measured where several seams coalesce.

The Raniganj seams tend to be more laterally persistent and to have a more consistent thickness than the Barakar coals. However, splitting and coalescing of seams is common and there is a tendency for thickness to decrease from east to west. Rank also increases from east to west.

Previous work

Past estimates of the Damodar Valley's CBM resource base vary considerably, from 10 tcf to more than 114 tcf.1 Based on detailed work, Advanced Resources Inc. estimates the CBM resource base at about 40 tcf for the five major Damodar Valley basins, with 20-25% (8-10 tcf) of this resource estimated as recoverable.

India's Oil & Natural Gas Commission (ONGC) has recently drilled several CBM exploration wells in the Damodar Valley. The JHA-A well, located in the Parbatur block in the Jharia coal field, was production-tested for 2.5 months, averaging about 40 Mcfd from the XIV coal seam.

Within the Jharia coal field, there are several Barakar coal seams with economic potential that could add substantial production. Two additional wells were drilled by ONGC in the Parbatur block along with one in the Raniganj basin. Unfortunately, the status of these wells is unknown.

Other CBM activity in the Damodar Valley includes coring by Great Eastern Energy Co. in the Raniganj coal field, and Reliance Gas Private Ltd. plans to develop a block in the eastern Raniganj basin.

Cambay basin geology

The Cambay basin is a large, intracratonic rift basin which extends in a roughly north-south alignment from the Gulf of Cambay to northernmost Gujarat, covering an area of about 13,000 sq km (Fig. 3 [167,878 bytes]). The basin margin is defined by discontinuous step-faults, bounded to the west by the Saurashtra uplift, and to the east by the Aravalli ranges (Fig. 4 [138,122 bytes]). The Cambay basin is subdivided into four major tectonic blocks based on distinct basement fault trends:

1. Mehsana-Ahmedabad
2. Cambay-Tarapur
3. Jambusar-Broach
4. Narmada.

The basin originated towards the close of the Mesozoic Era as a failed rift, as tensional faults developed in the northwestern part of the Indian Craton. Arrested rifting was accompanied by Deccan volcanic activity. These flood basalts form the basement upon which Tertiary sediments were deposited.

The coal seams of the Ahmedabad-Mehsana block are extensively developed within early-to-middle Eocene oil-bearing formations of the Kadi and Kalol formations. Middle-Eocene coal seams are largely confined to the vicinity of Ahmedabad and Kalol, while early-Eocene coal deposits are best developed in the area around Mehsana, Sobhasan, and north Kalol.

Based on the extensive amount of drilling that has been conducted in the area, there are two persistent coal horizons in the lower part of the middle-Eocene Kalol formation. These two horizons are designated in descending order as the Kalol-IX and the Kalol-X. The strata overlying the Kalol-IX horizon do not contain any coalbeds except in the immediate vicinity of Kalol.

Separated by a 30-60 m thick parting and underlying the Kalol formation is the early Eocene Kadi formation. The Kadi formation contains well-developed coal seams under an extensive area, bounded by Kalol in the south and Sobhasan and Mehsana in the north.

The Kadi formation is divided into two members, the Mehsana and Mandhali. The Mehasana member is characterized by several thick coal seams, 20-50 m thick, called the Sobhasan seams, and a few thin seams interbedded with sand and shale.

The thickness of the Mehsana member gradually thins eastward towards the basin margin with the thickness of the coal seams also decreasing. The Mandhali member also contains coal ranging in thickness from a few meters up to 10 m. These coals are not laterally persistent.

The coal deposits have been deposited in an upper-deltaic environment within the total Cambay basin sedimentation cycle of fluvial, deltaic plain, interdelta marsh, backshore lagoon, tidal flat, and gulf environments.

Cambay basin coal seams are lignite to sub-bituminous in rank (Ro = 0.35%), are high in moisture content (20-30%), and relatively low in ash and sulfur content (5-10% and <1.0%, respectively). petrographically, the coals are closely related to the low rank tertiary coal seams of indonesia and the gippsland basin, australia.

CBM activity

Starting in 1993, Essar Oil Co. conducted the first CBM drilling program in India, near the city of Mehsana in northern Gujarat. The project was funded through the Program for Acceleration of Commercial Energy Research (Pacer), a program sponsored by the U.S. Agency for International Development.

Under the program, three wells were drilled. Two of the wells, LBM No. 1 and LBM No. 2, are about 10 km apart. Both wells were completed and stimulated. The third well, LBM No. 3, was drilled as an offset to LBM No. 1 as part of a planned five-well pilot project.

Based on data from these three CBM wells and several dozen well logs from the surrounding area, it can be shown that the three main coal seams are consistently thick and laterally persistent throughout the Mehsana CBM project area.

The Sobhasan I seam ranges between 25 m and 35 m in thickness. Below the Sobhasan I seam, the Sobhasan II seam averages 20 m in thickness, although in the eastern part of the basin the Sobhasan II merges with the Sobhasan III seam to form a 30-35 m thick seam. The Sobhasan III seam is generally 15-20 m thick when not combined with the Sobhasan II.

Gas content values are in the range of 200 cu ft/ton (6 cu m/per ton), surprisingly high given the low rank of the coal. Sorption times for the coal samples are fast, less than a few hours. Isotherms run on the coal samples indicate that the coals are fully gas saturated. Injection/fallout tests show permeability ranging from less than 1 md up to 3 md. In all tests, the coal seams were slightly overpressured.

While the area has attracted much attention from both Indian and foreign companies, CBM development is likely several years away as ONGC has conventional oil and gas operations throughout the region, complicating ownership issues.

In its preliminary evaluation of Cambay basin CBM resources, the Gujarat government has estimated 11 tcf of in-place resource for coal seams between 2,000 ft and 5,000 ft deep, over an area of about 2,000 sq miles.

Government initiatives

India's Ministry of Petroleum & Natural Gas (MPNG) has been designated as the governmental authority for the exploitation of coal bed methane resources in India, a responsibility previously held by the Ministry of Coal.

The Directorate General of Hydrocarbons (DGH) is the regulatory body now responsible for preparing the terms and conditions of contracts for CBM exploration and production licensing, developing the block data packages, and maintaining oversight during the exploration and development life cycle.

Momentum for promoting CBM was initiated by DGH in early 1997, but intervening technical issues and governmental changes have delayed the opening of the anticipated bid round for the blocks to be offered. Final approval of proposed changes to the fiscal regime requires legislative enactment, and the Ministry still must approve the model contract.

It is anticipated that these various issues may be resolved within the next 2-3 months, at which time the government of India is likely to invite bids. The proposed target is to achieve award of contracts within 9 months from the date bids are received.

The Directorate General of Hydrocarbons hosted an executive workshop on CBM in April 1997, as part of the Indo-U.S. Bilateral Energy Consultations. Major U.S. and Indian operating companies presented views on the technical, fiscal, and contractual issues that distinguished viable CBM operations from conventional oil and gas operations, and identified the comparable CBM success factors in other countries.

Participating companies included ARCO, Phillips Petroleum Co., Texaco Inc., Essar Oil Ltd., Reliance Gas Private Ltd., ONGC, the Gas Authority of India Ltd., and others. The companies, and independent experts, also were given an opportunity by the ministry to review and comment on the terms and conditions of a draft model contract. This model contract is now awaiting final government approval.

Investment factors

The life cycle for CBM differs from conventional oil and natural gas, with considerably longer gestation periods needed to determine the commercial viability of the investment before moving into full development.

Recognizing those risk factors and the competitive investment opportunities elsewhere, India has announced that it intends to offer more-liberal terms for CBM investment using concessional agreements rather than production sharing contracts (PSCs). However, proposed terms and conditions are subject to final government approval prior to opening of the bid round.

The CBM program is contractually envisioned as a four-phase effort with the following nominal time domains:

Phase I: Exploration, 3 years

Phase IIA: Pilot assessment, 3 years

Phase IIB: Market survey and confirmation, 2 years; 2 year extension for frontier areas

Phase III: Development, 5 years

Phase IV: Production, 25 years.

Relinquishment would begin at the end of Phase IIB, with additional areas being ceded subsequently. At the end of Phase III, all nonproducing areas would be relinquished. Exit options have been provided at the end of Phase I and Phase IIB.

The round of licensing will be open to both foreign and domestic companies, with no government participation and no obligation of foreign companies to take on domestic partners. However, Indian and foreign companies have held discussions regarding potential joint ventures.

CBM producers would have the opportunity to sell gas to the domestic market at prevailing market prices. The proposed fiscal regime, still to be approved, offers the CBM projects infrastructure status, which allows a 5-year tax holiday from the date production commences, and a 30% concession on income tax payable in the following 5 years.

The government is considering whether to extend this period for an additional 2 years. This concession effectively reduces the 48% tax rate on foreign operating companies to 33.6% during that period. No customs duties would apply.

The companies will be subject to a base rate 10% ad valorem royalty, payable to the respective state government. An additional production-linked payment would be payable to the central government on a sliding scale based on the production level.

This payments schedule has been kept as a biddable item. A nominal commercial bonus of $300,000 would be paid on declaration of commercial assessment. The above assumes the passage of a New Petroleum Tax Code that has been put before the former government, but as of yet, not enacted.

Upcoming bid round

The Ministry of Petroleum & Natural Gas announced in first-half 1997 its intention to offer 10 blocks for CBM exploration in six coal fields in the Damodar Valley belt and in Central India. The areas under offer will include the shallow-depth coal beds of the lower Gondwana formations.

DGH has tentatively completed preparation of data packages for each of the 10 blocks proposed for the first round of CBM licensing (Table 1 [48,762 bytes]). Release of the packages is awaiting opening of the bid round.

The producible areas within these blocks have been limited as a result of negotiations with the Ministry of Coal. The latter has expressed concern over resource and safety issues related to the practice of conducting CBM drilling in areas of active or planned coal mining, as is carried out in some CBM operations in the U.S. The number of blocks on offer may be reduced by the time the bid round is opened.

India has a large unsatisfied demand for natural gas, which is likely to grow with the projected expansion of the economy. Natural gas demand in India is presently estimated at 3 bcfd, with actual production at only two-thirds of this level. Demand for natural gas in the year 2009-2010 is forecast at just over 9 bcfd, which will necessitate an increasing import requirement, either in the form of pipeline gas or LNG. New domestic sources such as CBM may alleviate some of the rising costs of energy imports.

At present, natural gas is commanding prices of up to $3.00/MMBTU in the State of Gujarat (western India). Enron Oil & Gas Co. Ltd. is already selling natural gas to the government at a price of about $2.40/MMBTU. The government hopes that allowing CBM producers to conduct future gas sales at market prices will provide an incentive to invest in CMB development.

Reference

1. Cooper, J.L., and Kumar, P., "CBM of the Damodar Valley Coalfields-Bihar and West Bengal, India," Intergas, May 15-19, 1995.

The Authors