1

UNDERGROUND COAL GASIFICATION ITS APPLICATION FOR PRODUCTION

OF DIFFICULT TO RECOVER FUELS

Presenting author: Alexey Zorya, JSC Gazprom Promgaz

Co-authors: Alexander Karasevich, Efim Kreynin (Gazprom promgaz)

Background

Modern trends of the national fuel and energy balance development are defined by inevitable de-

crease of the natural gas share and by the counterbalancing possibility of the coal use increase. Gas substi-

tution with coal seems feasible first of all in such top-energy-intensity industry as the electric power genera-

tion.

Recent conversion of heat and power stations (HPS) from coal to gas as was effected even in the

coal-rich regions proved environmentally-effective, but strategically erroneous. Nationwide it brought to a

standstill numerous projects of clean coal technology development, including new-generation above ground

coal gasification, gasification-based combined cycle turbines, underground coal gasification in situ, etc. In

addition effective use of the Russian coals is hampered by a number of other problems.

Popular belief of coal use general unacceptability in the environmental terms is nothing but precipi-

tate. Subject to a reasonable degree approximation we may speak about clean coal technologies, which

once developed and applied can promote use of coal as competitive and safe energy source. [1]. Leaders in

such technology development are Japan, Germany, France and the USA.

New trends of the Russian fuel and energy balance (FEB) shaping include first of all coal share in-

crease and become the more indispensable with coal share reaching 54% in the European energy consump-

tion, and 25% in the world consumption of primary energy (oil, gas, coal, nuclear, hydropower). In 2000-

2005 coal share in the Russian FEB accounted for 12-14 %.

Table 1 presents data on fuel consumption by the CHP sector in the G-8 countries. [2].

In the G-8 countries CHP share exceeds 60 %. The lowest CHP presence of 9,5 % and 25,9 % cor-

respondingly is in France, where over 77 % of the electric power are produced by nuclear power stations,

and in Canada, where hydropower sector accounts for 60,4 % of the electricity production.

In majority of the states, with exception of Japan and Italy, CHP is fueled by coal, with gas account-

ing for some 15-20 % of the electricity production, excluding only Great Britain where it provides for 55 % of

electricity production. In Japan individual primary energy carriers account for approximately equal shares of

electric power production. In Italy CHP is mainly fuelled by fuel oil and natural gas.

Table 1 – Primary energy mix of G-8 CHP in 2000.

Fuel mix, % Country CHP share, %

Coal Fuel oil Natural gas Total

Canada 25,9 72,7 10,1 17,2 100

France 9,5 64,6 20,1 15,3 100

Germany 62,5 82,5 1,7 15,9 100

Italy 77,7 13,3 44,4 42,3 100

Japan 59,6 35,4 27,7 36,9 100

2

Great Britain 69,2 42,1 2,2 55,8 100

USA 67,7 73,4 4,4 22,1 100

Subtotal (for the 7 coun-

tries above) 60,2 63,9 9,7 26,4 100

Russia 66,3 28,8 7,2 64 100

Total 60,9 59,9 9,4 30,7 100

Data on gas share in total Russian electric power production is presented in Table 2 [3]. You can see

that gas share has fallen to 14,6%, lower than 17,6% of the hydropower and 15,7% of nuclear electricity pro-

duction.

It should be understood that raising gas share in the electric power production FEB and moral and

physical deterioration of the equipment at the technologically obsolete coal electric power stations means

and necessitates creation of a new industry underlaid by clean and efficient coal and waste utilization tech-

niques, and not blunt coal generation extension.

It may be ascertained that as of now coal has ceased to play important role in the electric power pro-

duction.

Table 2 – Decrease of coal specific share in the Russian electricity production

Electricity production, billion kW-h Production by power station types, % Indices

2005 г. 2006 г. 2007 г. 2005 г. 2006 г. 2007 г.

Total in Russia 952 991,4 1014,9 100 100 100

including:

CHP 619 615,6 668,3 65,0 65,7 65,8

fuelled by:

natural gas - - - 44,9 45,5 46,8

coal - - - 16,0 15,8 14,6

Hydropower stations 174,9 175,2 179 18,5 17,7 17,6

Nuclear power stations 149,5 156,4 159,8 15,7 15,8 15,7

Other generation 8,6 8,2 7,8 0,9 0,8 0,8

Data source: estimation by the Central Scientific and Research Institute of Economics and Scientific and

Technical Information based on official and industry statistics.

At that, energy experts and politicians raise the ripe issue of gas systematic substitution with coal [4].

This necessary step will inevitably require revision of the developed energy strategy and urgently considering

the coal production opportunities, which are not at all exhausted and allow for further extension. In this re-

spect we cannot overlook the rational fuel use practices of developed nations.

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One cannot overlook negative impact of existing imbalance of energy prices. Translated into tons of

standard fuel (7000 kcal/kg) gas to oil price ratio is 1:1. Such situation stimulates neither CHP conversion to

gas nor introduction of new coal-fired power generating facilities.

By estimation of the Institute of Natural Monopolies’ Problems, coal can become economically feasi-

ble only when gas/coal price ratio equals at least 2:1. Besides, one cannot ignore that construction of a coal-

fired CHP involves lesser money and time resources than nuclear or hydropower stations.

Coal price is seriously influenced by transportation costs. Existing railway tariffs allow to compensate

for only half of the coal transportation costs. If the railway transportation tariffs are raised 2-fold, coal price for

final consumers will increase by 1,2-1,5 times. In this case the required gas/coal ratio of 2:1 becomes unat-

tainable.

Today we witness increase of gas prices, and at the same time the coal prices continue abreast of

the gas prices, thus contradicting the market development logic.

Figure 1 presents averages of the last decade prices of coal, natural gas and furnace fuel oil in Rus-

sia and the USA. [3].

A)

0

500

1000

1500

2000

2500

1998 1999 2000 2001 2002 2003 2004 2005 2006 2007

years

co

nsu

mp

tio

n c

ost,

RU

R/t

ce

Coal Natural gas Furnace fuel oil

Data source: estimation of the Institute of Natural Monopolies’ Problems based on the official statistics

4

B)

0

50

100

150

200

250

300

350

400

450

500

1998 1999 2000 2001 2002 2003 2004 2005 2006

years

co

ns

um

pti

on

co

st,

US

D/t

ce

Coal Natural gas Furnace fuel oil

Data source: Energy Information Administration (August 2007)

Figure 1 presents CHP fuel consumption costs in Russia and the USA and includes two diagrammes, of

which diagramme A illustrates average annual fuel consumption costs by CHP in Russia, and diagramme B

shows average annual fuel consumption costs by CHP in the USA.

In Russia the coal and gas prices invariably increase from year to year keeping on a level with each

other, while fuel oil prices exceed them by over two-times (diagramme 1 A). In the USA the fuel oil and natu-

ral gas prices grew abreast with coal having practically constant price, which in 2006 was by 7-8 times lower

than of hydrocarbon fuels.

Effective state regulation of fuel and energy price formation is required in this situation, it should in-

clude such mechanisms as flexible tax incentives, administrative and economic stimuli, etc.

Environmental impact

Wide use of natural gas in the electric power generation is defined not solely by economic (price)

factors. Environmental impact by standard coal-fired CHP is of own considerable importance.

Deliverables (Table 3) of a vast research of emissions resultant from burning of different organic fu-

els point to the solid fuel as the “most environmentally harmful” [5].

Provided application of common-use fuel burning methods, the natural gas is the cleanest energy

carrier. The research proves that substitution of gas with coal in CHP without any changes in burning tech-

nologies will bring about increased emissions not only of gaseous matter but of toxic microelements as well.

Table 3 – Specific emissions of exhaust gases’ major elements caused by burning organic fuels, kg/tce

Pollutant matter Lignite Bituminous

coal Fuel oil Natural gas Peat

СО2 3200-3300 2600-2700 2200-2250

1)

1900-2100 2)

1600-1700 —

СО 14-55 14-55 3,0-3,5 3-7,5 14-55

5

NOх 4,0-6,0 2,5-7,5 1,8-5,0 1,3-4,5 До 30

SOx 5,0-25,0 1,5-8,0 15,0-40,0 1,4-4,4 1,4-4,4

Solid particles 70-100 60-80 — 0,1 До 80

1) reduced fuel oil,

2) light fuel oil

One should not, however, hurry to conclude that solid and liquid fuels need be substituted with gase-

ous ones. Considering that natural gas and oil reserves are by an order less plentiful than those of coal, the

natural gas should be applied mainly in such spheres where the most effective use can be ensured.

The solid fuel share should be growing in the national fuel and energy balance, provided environ-

mentally safe production and application [6]. Internationally such progressive coal treatment methods as in-

tegrated coal gasification, circulating fluidized dust-coal bed, water-coal slurries, etc. have been implemented

in the heat and power sector, in Russia, however, they are still to make their appearance.

Presently cleanliness of coal technologies can be admitted on certain terms and with certain allow-

ances only. Still it will be erroneous to believe coal absolutely unacceptable in the environmental terms. Even

now we can name a good number of coal treatment and utilization techniques compatible with the environ-

mental safety standards. These technologies are underlaid by lower consumption of energy and resources,

waste and products recycling, waste quantity decrease and making waste more environmentally safe. De-

velopment of these technologies will promote application of coal as competitive and safe energy source.

Only such coal technologies as allow for reduction of atmospheric pollutant emissions and carbon

dioxide alongside with improved energy and technology efficiency can be considered clean and compatible

with environmental safety requirements.

Essential thing is reinventing role played by coal in the Russian energy sector.

The formerly upheld strategy of excessively relying on oil and gas in the fuel sector lacked true wis-

dom and hampered to the extent of making backward R&D efforts in production of coal and modern coal fu-

els and coal effective use for electric power generation as comply with the requirements of protecting envi-

ronment from harmful pollutants (fine dust, noxious gases like SOx, NOx and carbon oxides).

Experts expect the FEB share of coal to commence growing even at the beginning of the XXI cen-

tury. These expectations are based on depletion and decreasing accessibility of oil and gas reserves, on the

one hand, and on the other hand – on the absence of decisions ensuring complete safety of the nuclear

power stations and allowing for improved disposal of nuclear waste or for a safer immobilization of the spent

nuclear fuel.

However traditional methods of coal production and utilization, and coal-burning technologies in par-

ticular, breed ecological disaster.

In the next decade demand-based electricity production is expected to increase by 20-30% in the

developed countries. It inevitably involves huge noxious emissions and consequent environmental catastro-

phes.

How urgently the Russian fuel sector requires new state-of-the art clean coal technologies is clear

form the above.

The underground coal gasification (UCG) is a clean coal technology

The non-conventional environmentally safe technologies of coalbed tapping and coal burning include

first of all the underground coal gasification (UCG). Under the UCG method coal in situ is transformed into

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gaseous combustible energy, it is achieved by supplying (via system of injection wells) an oxidizer to the red-

hot coal surface and discharging produced gas (via other well systems).

Provided air injection the UCG gas combustion value can reach 4,6-5,4 MJ/m3. In case of applying

the oxygen enriched blast (oxygen concentration 65%), the gas combustion value attains to 6,7 MJ/m3. With

injection of pure technical oxygen (98 %) the gas combustion value amount to 10-11 MJ/m3.

Figure 2 presents elementary scheme of an underground gas generator module with shiftable reac-

tion channel, where the air blasts and gas flows move lengthwise. [6].

The gas generator is presented in the (inclined or horizontal) coal seam plane. The air injection well

is cased all the lengthwise. The gas production well is cased only up to the entry into the coal layer. Bottoms

of both these wells are connected into single hydraulic system by any available method. The combustion

face is located in the air injection well and the injection point moves upwards the injection channel. Thus the

oxygenizing agent flow is controlled and directed to the reacting coal face. Active heterogeneous reaction in

a channel with predominantly coal walls provides for a high subsurface temperature and minimum heat run-

way to the surrounding rock.

Figure 2 – Elementary scheme of the new technology underground gas generator module: 1 – air injection well cased within the coal seam; 2 – gas production well without casing within the coal seam;

3 – coal seam; 4 – reaction channel; 5 – cavings and skim; 6 – initial gasification channel; 7 – injection point shift lengthwise of the well

The underground gas generator consist of numerous modules presented in figure 2 and making sin-

gle hydraulic system. The gas generator provides for a stable maximum efficiency UCG process in the reac-

tion channel without afterburning the produced gas with free flows of oxidants.

The new technology methods and design solutions considerably surpass such techniques as were

current in 1970s, the time of UCG license acquisition by a USA company. New constructions of the air injec-

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tion and gas production wells together with the controllable coal seam gas drainage system ensure the fol-

lowing advantages:

−−−− Stable output of gas with maximum combustion value of 4,6-5,4 MJ/m3 (in case of air injection) or

10-11 MJ/m3 (in case of oxygen injection);

−−−− Raising the coal seam gas drainage level to 90-95 %, bringing gas losses by the underground

gas generator down to 5 %;

−−−− Raising the gasification efficiency to 75-80 %;

−−−− Minimizing ecological impact on the underground hydrosphere;

−−−− Utilization of abandoned coal mines’ resources with application of injection and suction UCG

technology;

−−−− Development of deep coal seams with the rock pressure control;

−−−− Reduction of required wells and consequently decrease of drilling costs share in the gas produc-

tion cost by 30 - 10 %;

−−−− Production of gaseous energy carrier with production costs by 1,5-2 times lower than equivalent

fuel produced at the neighbouring coal mines;

−−−− Production of synthetic hydrocarbons on the basis of the UCG gas.

Optimum output for an UCG enterprise is no less than 400-500 ths. tce/year. Investments required

for such an enterprise construction amount to 2500-2600 RUR/tce. [6].

Unlike traditional coal production the UCG does not involve environmental damage associated with

coal production, storage, transport and combustion. Exhausts of coal combustion in the UCG contain no

solid particles (ash, unburnt coal) and considerably less pollutants (NОх, SО2 и СО) (please, refer to Table

3).

An energy complex UCG – combined heat and power (CHP) production becomes a very feasible op-

tion, when the UCG is implemented with air injection, provided that the CHP plant is a steam-and-gas turbine

combined cycle one. In such case electricity generation efficiency can reach 50-55%, while application of

traditional steam turbine does not allow for efficiency higher than 30%.

These energy complexes UCG-CHP can be organized at big and small (lens) coal fields. Traditional

operation of the latter is considered unfeasible.

Practical implementation of energy complexes UCG-CHP will thus promote development of clean

coal technologies for the fuel industry. Besides, these integrated energy enterprises provide example of

natural gas and fuel oil substitution with coal and coal products. Wide-scale organization of the UCG-CHP

enterprises, especially in the regions with deficit energy supply, will result in considerably increasing coal

share in the national FEB.

Heat and energy characteristics as well as technical and economic parameters of the said com-

plexes witness opportunities presented by the UCG as gaseous source for electricity generation with applica-

tion of different technologies (steam turbine, gas turbine, steam-and-gas combines cycle turbine).

Russian regions with scare energy supply (the Primorie and Khabarovsk Territories, Sakhalin, Bury-

atia, Podmoskovie Basin, East Donbass, etc.) possess 7 billion tons of balance coal resources as can be

developed with the UCG application. Tapping of these bituminous and lignite coals may become fundamen-

tal for development of the regional gas and electricity industries.

The UCG gas and synthetic hydrocarbons

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Oxygen injection allows for the better implementation of the UGC-related energy and chemical opportunities

[6]. Figure 3 presents options of the UCG gas treatment and utilization. The process flows in the under-

ground gas generator involve steam and oxygen injection. Syn-gas (СО+Н2) is obtained on purification from

(wash down of) Н2S andСО2.

Figure 3 – The UCG gas treatment and utilization options

An option deserving special attention is production of methane (substitute natural gas) on the UCG

basis. The content of raw gas produced in the underground gas generator with steam and oxygen injection

and pressure of about 3,0 MPa is analogous to that of gas obtained in the aboveground gas generator with

the Lurgi process.

Organization of a UCG enterprise producing substitute natural gas (93 % СН4) seems a viable option

as the aboveground technology block development involves gasification in the aboveground gas generators.

Produced gas can be transported to meet energy or technology needs.

Organic synthesis of liquid carbons (methanol, gasoline, diesel fuel) as is shown in figure 3 bases on

reaction СО+2Н2→(–СН2–)+Н2О+q3. Then selection of adequate catalysts and operation parameters be-

comes distinctive and essential.

Thermal UGC methods for production of difficultly recoverable fuels

The difficultly recoverable fuels include gas hydrates, heavy oils and bitumen, coalbed methane. Ex-

isting technologies, however, lack production and energy efficiency. Thus new technologies are much re-

quired. We believe the industrial UCG technology include methods underlaid by thermal action on the above

enumerated difficultly extractable fuels.

Natural gas hydrates are the biggest reserve for developing the gas industry resource base. Global

reserves of gas hydrates are estimated to reach 2·1014

- 2·1016

m3. Of these reserves 98 % are located in the

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difficult to access ocean areas, and only 2 % (300 – 400 trillion m3) – in the continent coastline area. Devel-

opment of gas hydrated commercial production technologies would prolong the gas era for several centuries.

The last few years have witnessed serious interest to gas hydrate issues in Japan, Canada, the USA,

India and other countries. These issues are also of focal importance for Gazprom, intent on maintaining Rus-

sian headship in this area.

Gas hydrates become extractable only provided necessary treatment of the deposit thermobaric con-

ditions (raising deposit temperature or lowering deposit pressure). Lowering of pressure from 7,2 MPa to 0 at

a naked hole was applied at the Messoyakhskoye gas hydrate field. Modern methods of gas hydrates ex-

traction in Russia and abroad include injection of a heat carrier (steam, hot water) in the well.

Gazprom promgaz has patented new thermal technology of gas hydrates extraction (Russia Federa-

tion patent of 2006 №2271442 “Gas Hydrates Extraction Method”), envisaging partial combustion of the hy-

drocarbons in situ and use of yielded products for productive formation heat-up (Figure 4). Energy efficiency

of the method is evidently higher than of other technologies.

Figure 4– Principle diagramme of a drilling module for thermal production of gas hydrates : 1 – inclined hori-

zontal wells with fan termination; 2 – vertical well; 3 – gas hydrate deposit.

The developed thermal technology of gas hydrates production is underlaid by several methods of un-

derground coal gasification as consist of drilling through the gas hydrate formation of inclined vertical wells

with fan termination within the formation depth. Fan horizontal terminations cross the vertical well and, thus

united, form a hydraulically bound module.

Catching flame has hydrates provide for air injection in the module, exuding hot products heat up the

formation, which moved out of balance begins yielding gas products. Enhanced heat-up is achieved by com-

bining in different ways aerodynamics of air injection and gas flows in inclined vertical and vertical wells.

1 2

3

Air

Pro

ducts

Pro

ducts

Air

10

Gas hydrate deposits, though difficult to recover, may ensure considerable increase of gas resources

and positively influence gas strategy in the perspective up to 2030. In the near future the suggested thermal

technology should be tested in pilot production.

Heavy oils and bitumen. Traditionally heavy oil deposits are treated by injecting water steam, hot wa-

ter and other heat carriers in the seam. Another well known method is fireflooding (in-situ combustion).

Thermal methods of oil production are based on the processes of heat and mass transference in po-

rous mediums and on heat-driven chemical conversions [7].

The above mentioned heat effect methods have certain drawbacks and are energy intensive, while re-

sultant oil yield of the formation does not exceed 15-20 %. Below you will find engineering solutions making

part of new formation fire treatment method, applied principally to heavy oils [6]. Major steps of this method

are borrowed from underground coal gasification technology.

The method essentially includes making of a drilling channel in the oil layer, having the oil within this

channel inflamed and the channel itself consequently fire-treated lengthwise of the combusted surface. The

air can be injected in this channel in the straight-current (without on-surface extraction of products) or

counter-current mode, in the latter case the air is injected via one end of the channel while products of com-

bustion and oil thermal cracking are discharged via the opposite end of the channel.

Figure 5 presents principle diagramme of the new technology module.

Figure 5. Principle diagramme of the module of new thermal hydrocarbons extraction method:

1 — hydrocarbon layer; 2 — inclined horizontal well;

3 — horizontal drilling channel; 4 — vertical well.

The oil layer (1) is drilled with inclined horizontal well (2), which working part (3) finds itself in the pro-

ductive formation. A special vertical well (4) is drilled to the termination of well 2. The wells 2 and 4 are con-

nected, usually by applying a well-known hydro-fracturing technique. When the hydro-fractured slit is washed

through, and provided closed well, the oil layer in well 4 is set on fire. Then air injection is transferred onto

well 2, and they begin to gradually open well 4 in the atmosphere. The in-situ combustion source continues

at that its movement via drilling channel 3 towards the injected air flow.

This thermally treated collector has a developed and burned surface and makes a good drain in the oil

formation. To ensure a more intensive heat-up of the formation, both wells 2 and 4 may be used for injection

air combustion products

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purposes, so that low pressure and high consumption of the injected air are due to the big size of the filtra-

tion surface.

The injection stage is followed by oil products extraction. Duration of both the stages (thermal treat-

ment and oil production) vary depending in the thermal and physical parameters of the oil formation.

The module presented in Figure 5 allows for different modifications to ensure further-reaching treat-

ment of oil formation.

A mathematical model has been developed for quantitative assessment of results achievable by im-

plementing new method of viscous oil production. Implemented via drilling channels, the thermal treatment

of hydrocarbon formation includes two specific stages:

• Thermal treatment of the drilling channel as improves its draining capacity;

• Use of prepared parallel collectors for intensive injection of the heat carrier in the formation and hydrocarbons production.

So, the considered technology of oil formation fire-treatment has a sound engineering foundation bor-

rowed of the underground coal gasification. The technology is controllable and safe in contrast to fireflooding

earlier applied in viscous oil production.

Viscosity of heavy oil is considerably lowered by partial burning of hydrocarbons and heating the oil

formation up with combustion products, which provides for higher oil production at minimum energy and fi-

nance costs. The new technology of viscous oil production is ready for pilot commercial implementation.

Coal (carbonaceous) seams are another source of methane. Occluded methane (carbonaceous

seams with methane capacity of 45-50 m3/t), though potentially dangerous as cause of explosions in coal

mines, is a valuable hydrocarbon raw. The tasks to be handled here are identification of efficient coalbed

softening methods and breaking of sorbtion chemical bonds between coal and methane.

Existing methane production technologies are based on hydro-fracturing via vertical wells or on drilling

lengthy horizontal wells in the coal seam.

These technologies were first widely applied in the USA, and later in China, India, Australia, etc. In

2005-2006 the USA annually produced 45-50 billion m3 of coalbed methane.

In Russia (in the Kuzbass, Vorkuta, East Donbass fields) utilization of methane is scarce, though its

proved reserves reach some 13 trillion m3. About 2 billion m

3 of coalmine methane are emitted in the atmos-

phere essentially via mine ventilation shafts and damage the environment with greenhouse pollutants.

New technologies of intensified coalbed methane production are developed and patented in Russia

[1]. These technologies are essentially based on pneumatic hydro-fracturing of coal seams (water-air treat-

ment). Percussion (alternating) treatment of hydro-fracturing slit provides for inter-well cavitation and allows

propane-free fixture of the slit.

Another approach includes combusting of the coal seam in the hydro-fracturing slit or in the horizontal

drilling channel and blasting of hot combustion products (СО2, N2 и Н2О) through the coal formation. This

method is associated, on the one hand, with surging (by several degrees) of the formation gas permeability

factor, and with coalmine methane desorbtion by (substitution with) carbon dioxide and nitrogen.

Necessary is focused implementation of intensive coalbed methane production methods underlaid by

application of effective technical solutions dispensing with drilling numerous operation wells and ensuring

coal formation softening via limited quantity of productive wells.

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Conclusion

Reserves of hydrocarbons presently difficult to recover are colossal. (Even staged) inclusion of these

reserves in the fuel and energy cycle allows to lengthen duration of the hydrocarbon epoch.

We are faced with necessity to deploy new non-conventional methods of these difficultly extractable

fuels production. Known now are technical solutions, part of which have been this of that way implemented in

the natural conditions, another part, supported by thermal physical and design ideas, remaining at the con-

ceptual stage.

These technical solutions now require for investments (somewhat risky in terms of effective repay-

ment), while practical effect of their application can be expected only in 10-15 years. Only provided this

readiness of taking care of tomorrow now, may new hydrocarbon sources be made truly available by the

moment of traditional sources depletion.

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4. Russian President’s Administration Decides to Launch Development of New Strategy of Fuel Sup-

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