High B.T.U. Gas Where will we get the natural resources to make high 6.t.u. gas when we need it? Where are they located?
And how long will they last?
Natural gas now supplies about 30% of the R.t.u. requirem e n t ~in the United States. Based on the present proved reserves and predicted future consumption rates, there is probably somewhat over 20 years’ supply. The price is almost certain to go up. To get the funds and permission for building transmission lines-with only a 20-year supply of natural gas-other resources must be considered. The adequacy of other natural resources to make high B.t.u. gas is not only dependent on their size but also on their distance from existing population centers and existing transmission lines. To make gas out of coal by gasification followed by catalytic methanation would require somewhere between 6.5 and 13 million tons of coal for each 1% of present consumption of natural gas. I n 70 to 80 years when coal is needed it will be available, probably where it is needed and at a reasonable price. T o meet present requirements of natural gas entirely by converting oil shale to high B.t.u. gas with conventional processes would require an annual production of about 2.5 billion barrels of shale oil. The richer deposits of oil shale alone would provide enough raw material for a high B.t.u. gas industry for almost 200 years at the current rate of consumption of natural gas. However, despite the abundance of oil shale, the richer deposits of oil shale could probably satisfy only about one fourth of current requirements for natural gas VOL. 52, NO. 7
JULY 1960
575
because of lack of water. In addition, the rich deposits are so far from population centers and existing pipelines that new pipeline construction is necessary. The shales of the eastern U. S. that assay poorly by the Fisher assay method give almost as good results on direct hydrogenation as shale in the Colorado area. Thus the whole eastern shale reserves (probably over a trillion barrels) become a potential source of high B.t.u. gas. Over 300 billion barrels of tar sands are estimated to exist in the Athabasca deposit alone and presumably could be used for high B.t.u. gas. Again, the raw material is far from population centers and pipelines. For the immediate future, synthetic gas from fuel oil and petroleum sources will most probably augment the present pipeline systems. The amount of gas that is burned off each day in the oil refineries on the eastern seaboard north of Richmond is equivalent to 400 million cubic feet of natural gas a day. The oil refiner could burn heavy pitch and release
this refinery gas to go into a gas pipeline system. The H fuel process, pioneered by Dent in England, adds hydrogen to pentane and hexane to produce 1000-B.t.u. gas. Pentane and hexane are in sxrplus supply in this country as well as in Europe. It appears possible to produce a high B.t.u. gas from fuel oil by gasifying 60 to 70y0 of the oil, producing 30 to 40% of heavy tar and coke, and using the heavy tar and coke to produce hydrogen which, in turn, is fed back to the fuel oil, thus giving a thermal efficiency of 80 to 8S%. Because of the relative availability of petroleum products they will be used for the next 5 to 10 years to supplement natural gas. When base load plants are required, either shale or coal will come into the picture. Plant locations will depend on technologic developments under way today, but whether it comes from shale in the East or West or from coal deposits, there is a supply good for hundreds of years for all the natural gas that will be needed in reasonable amounts.
What is the possible effect of wellhead price levels on future supply? Are we likely to find that the wellhead price, held low b y Government edict, results in too ’few reserves available to dedicate future pipeline construction? One of the things producers have suddenly realized is that they have been selling a t the wellhead a raw material at a price, let’s say, of 12 cents per million cubic feet that competes with oil, which they sell a t $3.00 a barrel. That takes away markets. Saying that gas should cost 50 cents per million cubic feet a t the wellhead to compete with $3.00a-barrel oil is a gross oversimplification because gas, once found, is somewhat cheaper to produce. It does not have the lifting cost, it does not have the development cost associated with it because of wider gas well spacing than that of oil wells. Yet, the disparity between 12 cents per million cubic feet and $3.00 a barrel, and a pure B.t.u. ratio of 6 to 1-which is SO-cent gas us. $3.00-a-barrel oil-is the kind of problem with which the industry itself and the Federal Power Commission are wrestling. What the answer is may not be known for several years. The economics of high B.t.u. oil gas have been most clearly demonstrated in production equipment savings. At a time when water gas sets cost $70 a therm of daily capacity, a heavy oil gas set cost $34 per therm; but water gas sets already in use could be converted to high B.t.u. oil gas for very low costs per therm of increased capacity. Conversion of a water gas plant to use No. 2 oil cost $2.84 per therm of capacity increasefrom 50,000 a day up to 91,000. Eliminating all bottlenecks in the plant and using No. 2 oil the thermal capacity is increased to 235,200 against the original 50,000 therms a t a cost of $6.55 per therm. High B.t.u. plants reduce the holder costs of gas. In one plant in 1952 water gas holder cost was 8.6 cents per therm. O n conversion to heavy oil, it was 6.6 cents per therm. I n 1954 with natural gas in the plant the cost was 6.5 cents per therm. Going from a low B.t.u. of 528 to 1000 B.t.u. gives an increase of roughly 80% in thermal capacity of a distribution system. To get this increase today would cost $20 to $25 per
customer. However, it is possible to produce a high B.t.u. oil gas diluted with air down to 528 B.t.u. and obtain a gain in plant efficiency but do nothing about the distribution system. An increase of the thermal output of the Cambridge, Mass., system of about eight times, since putting in natural gas and considerable sums of money on the distribution system, has resulted in a decrease of investment from $1200 per therm of output down to only $400. Natural gas today in New England, including standby costs and peak shaving, costs 6.6 cents; with the new increase, rates will go up to almost 7 cents a therm. With such factors as today’s cost of oil in New England, credit prices, light oil credit, and labor rates, it would be about 5.4 cents a therm in New Bedford, 5.8 cents in Cambridge, and 6.5 cents in Worcester. The difference in cost is in the lay-down price of raw material. The two major problems of the natural gas industry are the cost of transporting gas in a pipeline and the extremely difficult legal regulatory system that gas has to follow. Even the highest prices paid for gas today a t the wellhead still are less than 20% of the total cost a t the burner tip. The production cost on gas today runs anywhere from about 7 to 8% to a maximum of about 20%. The big cost is in transporation, transmission, and distribution, and these are the things on which the industry is going to have to spend a great deal more money on research than it has in the past. Pipelines are u p to 36 inches in diameter now and going u p to 42- or 48-inch pipelines handling over a billion feet a day each can be envisioned.
The editors wish to thank Dr. Glenn C. Williams, Symposium Chairman, for his assistance in preparing this discussion for publication.
Participants in the Panel Discussion HALL M. HENRY
P. C. KEITH
HARRY PERRY
New England Gas and Electric Associates Service Corp., Cambridge, Mass.
Hydrocarbon Research, Inc., New York, N. Y.
U. S. Bureau of Mines, Washington,
JAMES JENSEN A. D. Little, Inc., Cambridge, Mass.
576
INDUSTRIAL
AND ENGINEERING
CHEMISTRY
D. C.
JOHN F. LYNCH
GLENN C. WILLIAMS
Texas Eastern Transmission Co., Houston, Tex.
Massachusetts Institute of Technology, Cambridge, Mass.
