The Petroleum Refining Industry

Chapter 5

The Petroleum Refining Industry

Photo credit American Petroleum Institute and Exxon Corp.

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- Contents . .,

PageIndustry Overview . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Industry structure........,. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 85Product Mix . . . . . . . . . . . . . . . . . . . . . . . ● ... ...... . . . . . . . . . . 86Economics of Refining .. ....,. . . . . . . . . . . ● . . . . . . . . . . . 88imports and Exports ....... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 89Trends and Uncertainties.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..... 90

Energy and Technology.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 92Production Processes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 92

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Kinds of Refineries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 94Energy Use . . . . . . . . . . . .; . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 95Energy Conservation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 97Potential for Energy Saving . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 98Technologies for lncreased Energy Efficiency . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 99Proven Technologies for Energy Conservation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 99New Concepts in Refinery Energy Use . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 101

Investment Choices for the Refining industry . . . . . . . . . . . . . . . . . . . . . ......... . . . . 104Capital Expenditures in the oil lndustry . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 104Other Investment opportunities ● P. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 105

impacts of Policy Options on the Petroleum Refining Industry . . . . . . . . . . . . . . . . . . . . 107The Reference Case . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 107Projected Effects of Policy Options . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 110

TABLES

Table No.21. Definition of SIC 29-The Petroleum Refining and Related Industries . . . . . . . . . . . . 8522. Petroleum Refining Corporations Earning More Than $16 Billion in 1981 . . . . . . . . 8623. Products Manufactured in SIC 29, . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8724. Process Plant Construction Cost,1972 and 1982. . . . . . . . . . . . . . . . . . . . . . . . . . . . 8825. Comparison of 1972 and 1981 Energy Consumption in Petroleum Refining

Industry. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9826. Petroleum Refining industry Projects To Be Analyzed for lnternal Rate of Return

(lRR) Values . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10827. Projected Changes in Petroleum Refining Production Between 1985 and 2000.... 11028. Effects of Policy Options on lRR Values of Petroleum Refining Industry Projects.. . 11129. Effect of Lower interest Rates on lRR Values of Petroleum Refinery Industry

Projects . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 112

FIGURES

Figure No. Page19. Employment Trends in Petroleum Refining lndustry,1970-82 . . . . . . . . . . . . . . . . . . 8920. Topping Refinery Model Configuration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9421222324

25

26

27

Hydroskimming -Refinery Model Configuration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 94Complex Refinery Model Configuration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 96Alliance Refinery Energy Profile . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 97Comparison of Petroleum Refining Industry Energy Use and Production Output1972 and 1981 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 98Diagram of Atmospheric Fluidized-Bed Combustion Boiler/CombustorArrangements. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 103Petroleum Refining Industry Projections of Fuel Use and Energy Savings byPolicy Options 1990 and 2000 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 109Petroleum Refining Industry Energy Intensity Projection, 1970X)00. . . . . . . . . . . . . 110

Chapter 5

The Petroleum Refining Industry

INDUSTRY OVERVIEW

The petroleum refining industry uses the largestquantity of premium fuels in the industrial sec-tor, amounting to 2,7 Quads in 1981. ’ It is sec-ond only to the chemicals industry in the totalamount of energy it consumes. Classified underSIC 29, the petroleum refining industry is definedas the group of establishments engaged in refin-ing petroleum, producing paving materials, andmanufacturing lubricating oils. Its official descrip-tion is shown in table 21.

This industry faces a future that bears little re-semblance to its past. Previously, the firms thatmade transportation fuels for the United Stateshad access to large quantities of high-qualitycrude oil. Now, they must use less desirable high-suIfur crude oils as feedstocks. The petroleumproduct market is changing as well. Environmen-tal considerations require production of high-octane, unleaded gasoline, instead of gasolinewith lead added to improve fuel quality.

In addition, the costs of fuel have risen to suchlevels that overall demand for refining productsis projected to decline over the next two decades.Thus, the management of firms in SIC 29 findsitself in the unenviable position of having to makesizable capital investments in an industry whoseproduct will be in less demand.

1 American Petroleum I nstltute, Energy Et’t’/c/ency /rnpro~’emenland Recot ered ,W]tcr\al L’tlllzatlon Report to U.S. Department otEnerg}, June 10, 1982, p 2.

Table 21 .—Definit ion of SIC 29—The PetroleumRefining and Related Industries

This major group includes establishments primarily en-gaged in refining petroleum, manufacturing of paving androof ing mater ials, and compounding lubr icat ing oi ls andgreases from purchased materials. This SIC group containsthe following subcategories:

SlC Title

291 . . . . . . . . Petroleum ref ining295. , . . . Paving and roofing materials299. . . . . . . . Miscellaneous products of petroleum and oilSOURCE Office of Management and Budget, Standard Indusfrlal Classification

Manual, 1972

Finally, the refining process is becoming morecomplex as demand increases for high octane,unleaded gasoline. Crude petroleum, as foundin nature, must be processed (refined) to removeimpurities and to manufacture such usefuI ma-terials as gasoline, jet fuel (kerosene), and fueloil. In the early days of the petroleum refiningindustry, simple distillations were used to pro-duce desired gasoline and kerosene products,with up to so percent of the crude oil feedstockbeing discarded. In recent years, this industry hasmade a great deal of effort to increase the yieldof high octane products, minimize waste, and im-prove the overall quality of the product pro-duced.

Industry Structure

The U.S. petroleum refining industry now con-sists of approximately 270 refineries owned by162 companies.2 Refineries are located in 40 ofthe sO States. Refining capacity is located in areasknown as Petroleum Administration for Defense(PAD) districts. Major concentrations of refiningcapacity exist in PAD districts 2 (Great Lakes andMidwestern States), 3 (Gulf Coast), and 5 (PacificCoast). PAD district 1 (East Coast) has less refin-ing capacity, a deficiency made up for by pipelineand tanker shipments from the Gulf Coast andby imports, primarily of residual fuel oil, fromforeign Western Hemisphere refineries,3.

As of January 1, 1982, the operating refineriesin the United States had a total crude-runningcapacity* of about 17.7 million barrels per day(bpd), representing about 27 percent of the refin-ing capacity of the non-Communist world.4 Proc-essing from around 1,000 bpd to over 600,000bpd, refineries range from “fully integrated” com-

Zlbld., p. 6.J/nrernatjona/ ~etro/eum Encyclopedia, J. C. McCasli n (cd. ) (Tulsa,

Okla.: The Petroleum Publishing Co., 1981).*The size of a refinery IS normally expressed as Its “crude capaci-

ty, ” meaning the number of barrels that can be “run” each daythrough its atmospheric distillation units.

‘Amercian Petroleum Institute, Basic Petro/eum Data Book, Jan-uary 1983.

85

86 • Industrial Energy Use

plex plants, capable of producing a completerange of petroleum products, to small, simplerefineries that can produce only straight-run dis-tillates, heavy fuel oils, and sometimes asphalt.Small (less than 75,000 bpd) refineries make upabout 60 percent of the total number of refiningunits, but their combined capacity is only about24 percent of the total throughput. * In terms ofownership, the four largest companies haveabout 38 percent of the total refining capacity,and 20 companies have about 77 percent of thetotal refining capacity. 5 The top 10 firms areshown in table 22.

There is no single, accepted method of catego-rizing the structure of the U.S. petroleum refin-ing industry that captures the similarities and dif-ferences in refineries related to processing capa-bilities, access to feedstock supplies, ability tomarket, and the like. One grouping is:

1. Large, integrated, multinational companiestypically have worldwide production, refin-ing, and marketing operations in addition totheir activities in the United States. A numberof these firms are descendants of the Stand-ard Oil companies created when Rockefel-ler’s Standard Oil trust was dissolved in1911.6 These major oil producers have typ-ically had access to assured supplies of crudeoil from the Middle East and other produc-ing areas of the world. Such guaranteed sup-

*Throughput–the total amount of crude oil initially processed.‘Oil and Gas Journal, “Refining Capacity Dips on Broad Front, ”

vol. 81, No. 12, Mar. 21, 1983, p. 84.6U.S. House of Representatives, Committee on Energy and Com-

merce, U.S. Refineries: A Background Study, July 1980.

2.

3.

A

plies of crude oil are diminishing as govern-ments of the producing countries increasing-ly take over responsibility for disposing oftheir crude production. As a consequence,many of the U.S. multinational oil producersfind that their domestic activities–includingrefining—are becoming more important totheir financial health. These companies, withtheir sophisticated high-volume refineries,provide the bulk of the products manufac-tured through complex processing steps.Large- and medium-sized domestic refinersmake up a diverse group of companies.Some are fortunate in being largely self-suf-ficient in domestic production of crude oil.Others depend for their crude supply onsome combination of long-term contractsand “spot” purchases. * They have muchless total refining capacity than do the ma-jor firms, but a number of them are signifi-cant marketers in their own regions.Independent refiners form the most diversegroup of all. Most independent refiners aresmall, domestic companies. Refining is theirprincipal operation; most do not producecrude oil and do not market their productsunder their own names.

Product Mix

petroleum refinery is a complex assembly ofindividual process plants interconnected with pip-ing and tanks. Each plant has a specific function,

*Spot purchases are those made by refiners on the open marketand without benefit of a contract.

Table 22.—Petroleum Refining Corporations Earning More Than $16 Billion in 1981

RevenuesCorporation (in billions) Employees

Exxon . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $110.06 137,000Mobil Oil. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 60.33 82,000Texaco . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 57.63 66,728Standard Oil of California (Chevron) . . . . . . . . . . . . . . . . . . . . . 46.61 43,000Standard Oil (Indiana) (Amoco) . . . . . . . . . . . . . . . . . . . . . . . . . . 31.73 58,700Atlantic Richfield . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28.75 54,200Gulf Oil Corp. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21.17 53,300Shell Oil Co. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21.60 37,273Conoco . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16.29 34,500Phillips Petroleum Co. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16.29 34,500SOURCE” Standard and Poor’s Register of Corporations, Directors and Executives, vol. 1, 1983

Ch. 5— The Petroleum Refining Industry . 87

and each refinery has been built to process a cer-tain type of crude oil (or “slate” of crudes) to pro-duce the products required for a defined market.7

Markets for specific products change constant-ly, and existing refineries are modified or newrefineries are built to accommodate suchchanges. In recent years, Government regula-tions, subsidies, and other influences (to bedescribed later) have greatly affected both re-finery operations and the construction of newrefineries.

Refineries convert crude oils into a broad spec-trum of products, most of which are fuels. A sim-ple grouping of refinery fuels would include lique-fied petroleum gases, gasolines, jet fuels, dieselfuels, distillate heating oils, and residual fuel oils.Refineries processing heavy crude oils may alsoproduce asphalt and coke (see table 23). Refiner-ies vary greatly in their size, processing complex-ity, and abiIity to use crude oiIs of differing char-acteristics.

The Mellon Institute, The /ndustrla/ Sector Technology Uw,\k)de/, Ilnal report, \ol. ‘3, The f’etro/eurn Refi”n/ng /ndustry, April1982

An important aspect of the U.S. refining indus-try is its ability to produce basic petrochemicals—feedstocks for the manufacture of a wide varietyof plastics, synthetic fibers, paints and coatings,adhesives, piping, and other products of modernsociety. Basic petrochemical materials man-ufactured by the U.S. refining industry frompetroleum fractions and natural gas include suchlarge-volume commodities as ethylene, meth-anol, and benzene and other aromatics. Until re-cently, it appeared that U.S. refineries couId lookforward to increasing markets for these materi-als. Now, however, the picture seems much lessbright because the industry appears to be “over-built” for current market demands.8 Recent stud-ies have concluded that current worldwide ethy-lene capacity is adequate to meet demands atleast through 1985.9

80il and Gas journal Mar. 21, 1983, op. cit., p. 85.‘Chemical and Engineering News, “Saudi Arabia Set To Emerge

as Factor in World Marketplace for Chemicals, ” Dec. 20, 1982,p. 65.

Residual fuel oil

Aviation jet fue l

Petrochemical feedstocks

15

6

5

Table 23.—Products Manufactured in SIC 29

Percentage of totalProduct manufactured 1980 production Definition of product and uses

Gasoline 39 A refined petroleum distillate, normally boiling within the ranges of30 to 300 C, suitable as a fuel in spark-ignited internal combustion

Distillate fuel oils

engines.18 A general term meaning those intermediate hydrocarbon liquid

mixtures of lower volatility than that of kerosene, but still able to bedistilled from an atmospheric or vacuum distillation petroleumrefining unit. Used as boiler fuel in industrial applications, and ashome heating fuel.

The material remaining as unevaporated liquid from distillation orcracking processes. Used mainly as boiler fuel in powerplants,oceangoing ships, and so forth.

Specially blended grades of petroleum distillate suitable for use in jetengines, These fuels have high stability, low freezing points, andoverall high volatility.

A broad term encompassing those refinery products, having typicallylow molecular weight and high purity (ethylene, propylene, andacetylene, which are used as feedstocks in chemical production ofeverything from food additives to textile fibers.

Liquef ied petroleum gases 4 Light hydrocarbon material, gaseous at atmospheric pressure androom temperature, held in liquid state by pressure to facilitatestorage, transport, and handling. consists primarily of propane andbutane. Used in home heating.

Kerosene 2 A refined petroleum distillate, intermediate in volatility betweengasoline and heavier gas oils used as fuels in some diesel engines.Often used as home heating fuel.

Other products 11 Includes items such as petroleum coke, petroleum solvents,lubricating oils and greases, asphalt, and the like.

SOURCE American Petroleum Institute Data Book, published 1979, and National Petroleurn News, December 1980

88 . Industrial Energy Use

Economics of Refining

The economics of refining is now undergoingmajor changes. Existing refineries were built andexpanded during a period of steady increase inmarket demand, accompanied by continuous,but moderately paced developments in refinerytechnology. The large integrated companies prof-ited by the total price spread between their low-priced crude oil and the sales of refined products.Non integrated companies with access to crudeoil supplies profited by refining this crude oil anddisposing of the products in largely “unbranded”bulk markets. Others, without crude oil suppliesof their own, but able to purchase crude oil onfavorable terms, developed specialized refineriesto supply regional markets, such as an Air Forcebase or commercial airport.

During these years of expansion, refinery op-erating costs were not considered critically im-portant. Many in the industry were content tolook at the “big picture” of the total spread be-tween cheap crude costs and income from fin-ished product sales. The cost of the refining op-eration, although certainly not insignificant, wasonly one of many costs in the series of steps be-tween crude oil exploration and production andthe delivery of products to the final consumer.The industry’s profits came from high volumesof oil moved through the entire system, and re-fineries did what was necessary to keep this flowgoing.

Now the picture is changing. Some essentialfeatures of these changes can be summarized:

1.

2.

3.

As product demand has leveled off or evendecreased, the refining industry finds itselfwith more capacity than it can use. Manypredict that this decrease in demand reflectsa long-term trend.Existing refineries, faced with the recent es-calation in energy costs and the increasingneed to break even or show an operatingprofit, are being forced to look much harderat ways to decrease operating costs, such asthe more effective use of energy in refiningprocesses.“Margin a]” refineries, those that are expen-sive to operate or are poorly located with

4.

5.

respect to crude oil or markets, are beingshut down—some temporarily, others forgood. Although some employees will betransferred, most will be permanently laidoff when a refinery closes.Even if an individual company’s market pros-pects or improvements in technology sug-gested that major new refinery process plantsshould be built, construction costs have es-calated to the point that such new facilitiesi n the United States would face capital car-rying charges that would make it difficult tocompete with existing refineries having sur-plus capacity. The increase in constructioncosts in the past 10 years for the three typesof refineries are illustrated in table 24.As a final deterrent to new “grass-roots” con-struction, siting problems—including the in-evitable vigorous local environmental con-cerns—when coupled with increased costs,make it unlikely that a new refinery couldbe built in marketing areas where the capaci-ty is needed (such as the NortheasternUnited States).

From the foregoing it appears safe to concludethat construction of a major new U.S. refineryis unlikely in the foreseeable future. Instead, theemphasis will largely be on adapting existing re-fineries to the changing patterns of crude supplyand product markets (described in a subsequentsection).

Employment

Employment in SIC 29 as a whole, or in SIC2911, the petroleum refining industry itself, hasbeen remarkably stable over the past decade. Thetrend, as shown in figure 19, exhibits the slightdecrease during the 1972 and 1979 oil disrup-tions, but overall employment has been main-tained at approximately 150,000 jobs.

Table 24.—Process Plant Construction Costs,1972 and 1982 (thousands of dollars/bpd)

1972 1982

Topping refineries . . . . . . . . . . . . . . . . . . . . . . 5 4 0 1 , 6 0 0Hydroskimming refineries. . . . . . . . . . . . . . . . 9 4 0 2 , 8 0 0Complex refineries. . . . . . . . . . . . . . . . . . . . . . 1,600 4,800SOURCE Refinery Flexibility—An Inferim Report of the National Petroleum Coun-

cil, VOI 1, December 1979

Ch. 5—The Petroleum Refining Industry • 89

1970 1972 1974 1976 1978 1980 1982Year

SOURCE Annual Survey of Manufacture and Census of Manufacture.

Production Costs

The operating costs of refineries are generallyclosely held figures. These costs depend greatlyon the size and complexity of a specific refinery.They are normally expressed in terms of dollarsper barrel of crude unit throughput. Such figurescan be misleading, however, because larger,more complex refineries will incorporate processplants used for the relatively expensive process-ing required to make a few specialty or highlyrefined products. Simple topping refineries—andespecially those of medium to large size—willhave relatively low processing costs per barrel,but the value of their products will be corre-spondingly low in comparison to the muchbroader range of products from a more complexrefinery. 10

Capital Investment

For a further perspective on the economics ofthe oil industry, it is important to recognize thatabout 70 percent of capital spending in a typicalSIC 29 firm goes for exploration and productionactivities. ” Petroleum refining capital budgetsmust compete for the remaining 30 percent ofavailable funds with petrochemicals manufactur-ing, marketing, oil and gas pipelines, and otheractivities.

In considering the ability of the refining industryto raise funds for new capital expenditures, in-cluding those for energy conservation, it shouldalso be recognized that the profitability of therefining industry appears to be very questionablein the immediate future.12 Because U.S. refineriesare operating well below capacity, there is adownward pressure on refined product pricesthat will prevent many refiners from passing onto their customers all their costs, including crudecost .

As a final observation on the subject of oil refin-ing economics, it should be recalled that sincethe early 1960’s, the industry has been under var-ious types of controls intended to aid—i e., sub-sidize—small refiners. Under the original crudeimport control system of the 1960’s, small refinerswere given special allocations of “import tickets”that they could sell to large refiners who importtheir own foreign crude. In August 1971 addi-tional subsidies for small refiners were put intoeffect.13 These included price controls on domes-tic crude oil, crude entitlement biases, small re-finery set-asides for military businesses, guaran-teed small business loans, U.S. royalty crude pref-erence sales, naval petroleum reserve set-asides,mandatory crude allocations, and exemptions ofsmall refiners from the scheduled phasedown oflead-octane additives.

As one result, this subsidy program establishedextremely attractive investment opportunities forvery small, simple refineries, and many werequickly built. Very few of them could producegasoline, and many used high-quality crude inthe simple production of fuel oil instead of pro-ducing higher quality products. However, as ofJanuary 1981, all price and allocation controlswere removed from crude oil and petroleumproducts.

Imports and Exports

Prior to the removal of price and allocationcontrols in January 1981, U.S. refiners were large-ly protected from foreign competition by a systemof crude oil and product price controls.14 This

10Natlona I petroleum Cou nci 1, Refinery F/exibi/ity, prepared forthe U.S. Department of Energy, Washington, D. C., 1980, p. 18.

I I standard 01 I CO, of Cal i fornia, 1980 Annual ~eport.

120;/ and Gas ]ourna/, Mar. 21, 1983, OP. cit., P. 85.

I jNational Petroleum Cou nci [, op. cit., p. 24.14U .s. House of Representatives, Committee on Energy and Com-

merce, U.S. Refineries: A Background Study, July 1980.


program resulted in an average raw material costfor U.S. refiners that was below the price foreignrefiners had to pay for their crude. As domesticcrude oil price controls were phased out, the rawmaterial cost advantage of the U.S. refiners beganto disappear. The decontrol action eliminated theremaining advantage.

With its access to crude oil at worldwide com-petitive prices and an efficient domestic productdistribution system, a vigorous U.S. refining in-dustry should have little reason to fear foreigncompetition. All that seems to be required at thispoint is close monitoring by both Governmentand industry of the expansion of export refineriesaround the world, together with a continuingevaluation of how they might affect the U.S. refin-ing industry if no control were exercised.

Refineries in Venezuela and the Caribbeanarea, for example, now supply somewhat over1 million bpd of product to the U.S. market.15

However, residual fuel oil makes up most of theseimports. These refineries have relatively littlecapacity to make gasoline and other light prod-ucts, and it seems unlikely that they will investin the very considerable conversion programsnecessary for producing significant amounts ofgasoline, jet, and diesel fuel to be marketed incompetition with underutilized U.S. refineries.

Existing European refineries have considerableunused processing capacity, but to reach the U.S.market they must face the expensive transporta-tion of refined products in small tankers. (Thevessels of “supertanker” and larger size cannotpractically be used to transport the mixed cargoesof light products that would be required in suchmovements.) Another major disadvantage facedby European refiners is the growing predomi-nance of unleaded gasoline in the U.S. markets.Unleaded gasoline of high octane is manufac-tured only in the United States. It appears mostunlikely that European refiners could afford to in-vest in the additional catalytic reforming andother processes necessary to provide unleadedgasoline just for their share of the U.S. market.

In the long run, a more serious threat is pro-duction from very large petrochemical plants be-

15National Petroleum Council, op. cit., P. 223.

ing built in areas where the basic raw materialsare less costly (or will be made available by localgovernments at prices well below U.S. costs).Such plants are being built in Canada, Mexico,and—most significantly—the Middle East. 16 Sev-eral such plants are being built at Jubail and Yan-bu, in Saudi Arabia, by Saudi Government agen-cies and by joint ventures between these agen-cies and large foreign firms. These plants havebeen promised feedstocks and fuel at costs ofonly a fraction of world market prices. Althoughthe plants are remote from current world markets,the industry anticipates that their low manufac-turing costs will permit them to enter such mar-kets, to the detriment of current producers. Ananalysis of transportation costs and potentialmarkets indicates that finished products fromnewly constructed Middle East refineries will goprimarily to Western Europe, presenting addi-tional problems to the already depressed Euro-pean refining industry. Another possibility is thatthe Middle East governments (notably SaudiArabia) may require their crude oil purchasersto buy some refined products in order to be al-lowed access to crude oil.

Trends and Uncertainties

Refineries in the United States are experienc-ing drastic changes in the business atmospherein which they operate. Available crude oil sup-plies are deteriorating in quality, motor gasolineuse has been dropping sharply from historichighs, markets for many products are levelingout or declining, and Government-mandatedchanges (e.g., requirements for low-sulfur fuel oil,increasing use of unleaded gasoline, and the ul-timate phaseout of leaded gasolines) require in-creasingly sophisticated and costly refining oper-ations.

Refining capacity has probably peaked for theforeseeable future. Investment in refinery processplants will continue to be made, as necessary,to handle the growing amounts of heavy crudeoil and the greater relative demand for unleadedgasoline of (perhaps) steadily rising octane num-ber. The additional energy requirements of these

16Chemical and Engineering News, Op. cit.


new processes may affect the industry’s abilityto continue the recent trend toward more energy-efficient processing.

Details of these trends are discussed under thefollowing topics and in subsequent sections of thisanalysis.

Crude Supply Uncertainties.– If the volumesof foreign crude oil imported into the UnitedStates continue to decrease, the industry and theNation may become unjustifiably complacentabout the perceived dim in ishing dependence onforeign crude oil. Short-term or even longer in-terruptions in the availability of Middle Easterncrude always remain a possibility.

Crude Oil Prices.–Crude oil prices quadrupledduring the Arab oil embargo of 1973-74 and morethan doubled again during the Iranian crises of1978-80, in the early 1980’s, worldwide crudeoil prices declined as a result of production over-capacity and lowered demand. ’ 7 It is not clearwhat will happen to crude oil prices. Politicalupsets in the Middle East could result in crudeoil embargoes or physical interruptions in crudeoil availability, with consequent skyrocketing ofprices worldwide. Also, reductions in crude oilprices, if unaccompanied by significant increasesin production, couId have a shattering effect onthe economies and possibly on the internal sta-bility of several of the highly populated, oil-producing nations.

Changing Crude Mix.–Much of the older refin-ing capacity in the United States was designedto process crude oil of low sulfur content and me-dium-to-high quality. Available supplies of thesecrude oils are dwindling, both in the United Statesand elsewhere. Those OPEC countries having re-serves of both light and heavy crudes are requir-ing their customers to take quantities of bothtypes, instead of merely “lifting” predominantlythe more desirable light crudes.18

As a consequence of this changing crude oilmix, U.S. refiners are being forced to make ma-jor investments in additional processes and new

I TU ,s. Depar(rnent of Energy, Energy Information Ad m i n istratlon,

Short-Term .Ertergy Out/ook, Washington, D. C., February 1983, p. 5.18.;/ and ~a5 )ourna/, “surviving the Shakeout: Refining and Mar-

keting In the Elghtles,” Oct. 26, 1981.

facilities. These facilities involve heavy fuel oildesulfurization and coking, together with proc-esses to recover the light ends given off in thecoking operation. Modifications to permit proc-essing heavy crude oil can be quite costly andenergy-intensive. One U.S. refiner, for example,has announced a $1 billion program to modifyits Gulf Coast refinery so that it can process theArabian heavy crude oil that it will be requiredto take as part of its share of ARAMCO* produc-tion.20

Changing Product Demand.–The decliningdemand for refined products in the United Statessince 1978 seems permanent and is primarily aresponse to higher prices, the current lower levelof economic activity, and the gradual introduc-tion of more fuel-efficient small cars.21 Also, thetrend of the refinery process mix will probably

be away from motor gasolines and toward mid-dle-distillate fuels. Yet it is not at all clear howmuch the U.S. demand for refined product willdecline before it rises again (if it does). One majoruncertainty is the response of the American mo-torist to the belief (not necessarily valid) that thedays of skyrocketing motor fuel prices are over.It has been suggested that: 1) a period of levelmotor fuel prices will result in an increase in driv-ing, with a correspondingly greater demand forfuel; and 2) motorists will not accept the small,fuel-efficient automobiles predicted for the nextdecade, but will instead turn back to larger, morecomfortable and more powerful vehicles.

Residual Fuel Oil Demand.–Since residualfuel oil, as normally produced, is high in sulfur,environmental restrictions have reduced its useby utilities and industry. Its place has been takenby natural gas, distillate fuel oil, and coal. Thus,the demand for residual fuel oil is now declin-ing. Current demands are for about 1.8 millionbpd, resulting in increased needs for refinery fueloil desulfurization and coking.22 The rate at which

~~oj[ and Gas ]ourna( “Petrochem Units Benefit From integra-tion, Flexibility, ” Apr. 11, 1983, p. 100.

*Arabian American Oil Co-consortium of American and SaudiArabian oil companies, formed in the 1920’s to ftnd and process

crude oil In the Middle East.Zostanda rd Oil CO. of California, 1981 Arrnua/ Report.z I u s Depa ~rnent of Energy, Energy I nformatlon Administration,,.

Short-Term Energy Outlook, Washington, D. C., February 1983, p.24,

221 bid., p. 26.

92 • Industrial Energy u s e

the demand for residual fuel oil decreases willbe affected by natural gas usage policy and pricesand by the rate at which major users of residualfuel oil can convert to coal in environmentallyacceptable ways.

Motor Gasoline Upgrading.–Regardless o fhow the demand for motor gasoline changes, itis expected that unleaded gasoline—now over 50percent of the refinery gasoline output—will com-prise 100 percent of the market within 10 years.23

it is also possible that gasoline octane numberswill continue to inch up in response to require-ments for more efficient automobile engines, aswell as to motorists’ desires for better perform-ance. The production of high-octane, unleaded

23National Petroleum Council, op. cit., p. 52.

gasoline requires more complex and energy-intensive refinery processing. These complex fa-cilities often require significant investments, whilecontributing nothing to the crude throughput ofa refinery. In fact, the gasoline yield per barrelof crude oil may be lowered as a result,

Environmental Constraints.–Environmentalrestrictions designed to control gaseous emissionsand the release of liquid pollutants have greatlyaffected refinery investments and operating costs,as well as the ability of refiners to install new proc-ess units or modify existing facilities. Although itseems unlikely that environmental regulationsand emission controls affecting refineries will bestricter in the next few years, the present regula-tory framework can make it very difficult to mod-ify or replace existing facilities.

ENERGY AND TECHNOLOGY

Production Processes

To understand how refineries use energy andwhat the possibilities are for more efficient useof such energy, it is useful to review the principalprocesses of a modern refinery.24

Atmospheric Distillation

Incoming crude oil is first treated to remove in-organic salts and then dehydrated. Under slightpressure it is then heated to a boil in a columnwhere the various components of the crude oilare separated according to their boiling temper-atures. Distillation, sometimes called “fractiona-tion, “ is carried out continuously over a rangeof boiling temperatures, and at several points hy-drocarbon streams within specific boiling rangesare withdrawn for further processing.

Vacuum Distillation

Some crude oil components are too heat-sen-sitive or have boiling points that are too high tobe distilled at atmospheric pressure. In such casesthe so-called “topped crude” (material from the

ZAPrWeSS descriptions are adapted from Argonne National Lab-

oratory publication Energy and Materia/ Flows in Petro/eum Refin-ing, AN L/CN5V-l O, February 1981. Available from National Tech-nical Information Service, Springfield, Virginia.

bottom of the atmospheric column) must be fur-ther distilled in a column operating under avacuum. This operation lowers the boiling pointof the material and thereby allows distillation ofthe heavier fractions without excessive thermaldecomposition.

Fluid Catalytic Cracking

Through fluid catalytic cracking, crude petro-leum whose lighter fractions were removed byatmospheric or vacuum distillation is entrainedin a hot, moving catalyst and chemically con-verted to lighter materials. The catalyst is thenseparated and regenerated, while the reactionproducts are fractionated into their various com-ponents by distillation. This is one of the mostwidely used refinery conversion techniques.

Catalytic Reforming

Reforming is a catalytic process that takes Iow-octane materials and raises the octane numberto approximately 100. Although several chemicalreactions take place, the predominant reactionis the removal of hydrogen from naphthenes (hy-drogen-saturated, ring-like compounds) and theconversion of naphthenes to aromatics (benzene-ring compounds). In addition to markedly in-

1 0 1 —

Ch. 5—The Petroleum Refining Industry ● 9 3

creasing the octane number, the process pro-duces hydrogen that can be used in other refineryoperations.

Alkylation

In the alkylation process, isobutane, a Iow-molecular-weight gas is chemically added to thecarbon-to-carbon double bonds that occur in cer-tain hydrocarbons. The resulting product, nowcontaining many isobutyl side groups, has a muchhigher octane number compared to the originalstraight-chained substance, and is therefore a bet-ter motor fuel. Branched-chain hydrocarbons,such as those with isobutyl side groups, are ableto have their octane rating increased even fur-ther with lead additives, but with the increasingconsumer need for unleaded gasolines, this typeof alkylation will be less and less used.

Hydrocracking

Hydrocracking is a catalytic, high-pressureprocess that converts a wide range of hydrocar-bons to lighter, cleaner, and more valuable prod-ucts. By catalytically adding hydrogen under veryhigh pressure, the process increases the ratio ofhydrogen to carbon in the feed and produceslow-boiling material. Hydrocracking is especial-ly adapted to the processing of low-value stocksthat are not suitable for catalytic cracking or re-forming because of their high content of tracemetals, nitrogen, or sulfur, Such feedstocks areused to produce gasoline, kerosene, middle-distil-late fuels, and feedstocks for other refining andpetrochemical processes.

Hydrotreating

A number of hydrotreating processes use thecatalytic addition of hydrogen to remove sulfurcompounds from naphthas and distillates (lightand heavy gas oils). Removal of sulfur is essen-tial for protecting the catalyst in subsequent proc-esses (such as catalytic reforming) and for meetingproduct specifications on certain “mid-barrel”distillate fuels. Hydrotreating is the most widelyused treating process in today’s refineries. In ad-dition to removing sulfur, it can eliminate otherundesirable impurities (e.g., nitrogen and oxy-gen), decolonize and stabilize products, correct

Photo credit: Phillips Petroleum Co. and American Petroleum Institute

A portion of Phillips Petroleum Co.’s refinery near Borger,Tex. In the background is one of two huge catalyticcracking units at this refinery. A large part of the refineryoutput is moved by four long-distance product pipelines,radiating in all directions from the refinery and serving

markets as far away as Denver and Chicago

odor problems, and improve many other defi-ciencies. Fuel products so treated range fromnaphthas to heavy burner fuels.

Residuum Desulfurizing

With the increasing need to use the heavier,higher boiling components of crude oils (the“bottom of the barrel”), a number of processesare being offered for the desulfurization ofresiduum, the material remaining after at-mospheric and vacuum column distillation. Theseprocesses operate at pressures and temperaturesbetween low-severity hydrotreating and themuch more severe hydrocracking previously de-scribed. Depending on the market, the desulfur-ized “resid” can be used as a blending compo-nent of low-sulfur fuel oils or as a feedstock toa coke producing unit (if a low-sulfur coke wereto be made).

94 ● Industrial Energy Use —

Coking

In the past, the residual bottoms from the crudeunit have been blended with lighter oils and mar-keted as fuel oils of low-quality and often highsulfur content. These residues do, however, con-tain lighter fractions (naphthas and gas oils) thatcan be recovered if the residual oil is “coked”at high temperatures. It is becoming economicallyworthwhile to recover these remaining light endsfor further processing. Petroleum coke is usedprincipally as a fuel. Coke derived from untreatedresidues may have a high sulfur content andhence be of limited commercial value.

Kinds of Refineries

Refineries can be considered under the follow-ing three broad classifications:

Topping Refineries.—A topping refinery (fig.20) is usually small, often having less than 15,000bpd capacity (although some are much larger).It relies entirely on crude oil distillation to pro-vide various product components, primarilyliquefied petroleum gases, gasoline blendingstocks, and distillate fuels (jet and diesel fuel andheating oils). Residuum would be sold as a heavyfuel oil or, if vacuum distillation were incor-

Figure 20.—Topping Refinery Model Configuration

LPG (liquefied

Naphtha Gasoline or,

blendingRaw materials

w (crude Unit) Distillates Jet fuels d is t i l la te

1 J fuels

I

porated, would be partly made into asphalt. Sincea topping refinery, as described, has no crack-ing, hydrotreating, or reforming processes, itsrange of products is almost entirely dependenton the characteristics of the crude oil feedstock.

Hydroskimming Refineries.–Hydroskimmingrefineries (fig. 21) make extensive use of hydrogentreating processes for cleaning up naphthas anddistillate streams. Thus, a refinery of this type isless dependent on the quality of the crude oil run,but it is still limited in its ability to produce high-octane, unleaded gasoline, and its productstreams are heavily weighted toward fuel oils.Such a refinery would normally include catalyticreforming to increase its yield of high-octane fin-ished gasoline.

Complex Refineries.–Most of the refining ca-pacity (but not the number of refineries) falls intothe category of complex refineries (fig. 22) A typ-ical complex refinery uses most of the processespreviously described. By virtue of its cracking

Figure 21 .–Hydroskimming Refinery ModelConfiguration

LPG(liquefied

Light ends Light- ~ natural gas)\ * ends

processing ~ Ref ineryfuel

- Naphtha1 P Gasoline orblending gasoline

Hydrotreating

Catalyticreforming Gasoline

1

Reducedcrude Heavy

gasoil

1

Vacuumdistillation vacuum residuum

Visbreaking- (thermal

cracking)

Jet fuelsdistillatefuels

Residualfuel oil

, Asphalt

SOURCE’ California Oil Scenario (Houston, Tex : Bonner & Moore Associates,Mar 29, 1980) SOURCE California 0il Scenario Bonner and Moore Associates, Mar 29, 1980

Ch. 5— The Petroleum Refining Industry . 95

Photo credit Marathon Oil Co. and American Petroleum Institute

A portion of Marathon Oil Co. ’s refinery near Robinson,Ill. In the background is the crude distillation unit whichhas a charging capacity of 110,000 barrels of crude oil

per day

capacity, the refinery can convert high-boilingcrude oil fractions (otherwise suitable only forheavy fuels) into lower boiling fractions suitablefor gasoline and distillate fuels. By alkylation andother processes it can convert materials that aretoo light for gasoline into stocks that can beblended into gasoline. A typical complex refinerywould thus be able to run a wider range of crudeoils than would either a topping or a hydroskim-ming refinery. In addition, many—but not all—of the larger complex refineries will have distilla-tion units designed to permit running crude oilof moderately high suIfur content (e. g., from theAlaskan North Slope).

Energy Use

The petroleum refinery has not traditionallybeen looked on as a major “profit center. ” prof-its in the oil industry come instead from produc-ing crude oil and from marketing the productsor, in the large, integrated companies, from thetotal operation of getting crude oil out of theground and products into the hands of the con-sumer. Refineries themselves were (and continueto be) expensive to build and operate. Refinerssought efficiency improvements primarily to ob-tain a greater output of more uniform productsfrom existing equipment. They studied and im-proved processes and installed expensive in-strumentation and control systems to eliminateas much as possible of the uncertain “human ele-ment.” As a result, oil refining now has one ofthe highest capital costs per employee of any U.S.industry.

Although refinery managements and their tech-nical staffs had other priorities, they have takenmeasures to use energy efficiently. I n many re-fineries, periodic efforts were made to improvethe steam balance and eliminate obviously waste-ful plumes of exhaust steam. Where large vol-umes of surplus low-pressure steam were avail-able, consideration was given to investing in acondensing turbine driving a continuously oper-ating pump or blower. Many refineries at onetime supplied their electrical energy needs by“topping” turbines exhausting to the refinerysteam system, a highly efficient use of fuel energy.However, as refinery electrical loads increasedand the cost of electrical energy available fromlocal utilities continued to decrease, investmentsin additional refinery electrical generating capaci-ty appeared less attractive when viewed by thestandards applied to other investments in the oilindustry. In time, purchased electrical energycame to supply most of the refinery load.

At a few locations, a refinery and a local utilitywere able to collaborate on a large powerplantin or adjacent to the refinery. Typically, thepowerplant would obtain heavy fuel oil from therefinery. The utility, in turn, might supply steamto the refinery. However, many utilities were re-luctant to lose their expensively treated boiler


Figure 22.—Complex Refinery Model Configuration

Natural gasIiquids fuel gas

All processeIight ends

Reducedcrude

Residual fuel o i l

SOURCE: Callifornla Oil Scenario (Houston, Tex.: Bonnar & Moore Associates, Mar. 29, 1980.

feedwater in the form of steam that would not topping refineries use less energy per barrel, andbe returned (or would come back contaminated).These early attempts at cogeneration were notvery successful because to be of interest to theutility, the electrical capacity of the refinery hadto be much greater than the refinery’s demand.Also, the utility’s need for fuel and the refinery’sfor steam were normally not in thermal balance,and the overall economics of the joint venturewere usually not attractive.

A rule of thumb used by some refiners is thatit takes 1 barrel of oil-equivalent energy to proc-ess 10 barrels of crude oil. In other words, usingan average heating value for crude oil, process-ing a barrel of crude through a typical refineryresults in the use of about 580,000 Btu of energy.This is a good approximation of energy use. Small

complex refineries with a wide spectrum of fin-ished products probably use more.

In typical refining processes, feed streams arenormally heated, either to effect a physical sep-aration (crude unit fractionation) or to provideenergy for a heat-absorbing reaction (e. g., cat-alytic reforming). Although heat exchange is usedto preheat feed streams to the highest economi-cally feasible temperatures, additional heat isusually needed. Specifically, petroleum refiningprocesses use energy in the form of fuel, steam,or electrical energy for the following functions:

● To heat crude units and other process feedstreams.

• To make steam for mechanical-drive turbinesto power major compressors and some large

Ch. 5—The Petroleum Refining Industry ● 9 7

pumps; for process heating, steam-stripping,and steam-jet vacuum ejectors.

● To heat reboilers (steam-fired or fuel-fired).. To power most pumps and the fans i n air

coolers (usually with electric motors.)

Energy losses from petroleum refining opera-tions are primarily the result of the following:

●

●

●

●

Heat rejected by (lost to) air- and water-cooled heat exchangers used to cool recy-cle and product streams. (This equipment isestimated to account for up to 50 percentof refinery heat losses.)Unrecovered heat in flue gases from furnacesand steam boilers (perhaps 25 percent of re-finery energy losses).Convection and radiation losses from hotequipment and piping.Steam system losses.

Although most refineries maintain summaryrecords of energy use by their process plants and

of energy purchased from utilities or sold offsiteto other energy users, the only complete public,nonproprietary analysis of a “refinery energy pro-file” is the study of Gulf Oil Co.’s Alliance refinerycarried out by Gulf Research & Development Co.under contract to the Department of Energy’s(DOE’s) Office of Industrial Programs.25 Allianceis a typical complex refinery incorporating all theprincipal refining processes described earlier,with the exception of hydrocracking. Figure 23,reproduced from the Gulf Research repot-t, illus-trates the flow of energy into the total refinery,as well as the form and amount of energy lossesfrom the system.

Energy ConservationFor this report, the basis for reviewing the en-

ergy conservation record of the petroleum refin-

25GuIf Research & Development Co., Refinery Energy profile—Final Report, prepared for DOE, report No. ORO-5262-5, January1979,

Figure 23.—Alliance Refinery Energy Profile(M Btu/bbl of oil charge to refinery and percent)a

Energy input to plant Energy output as losses

Heater and boiler stacksFuel gasb

:372 (66°/0)

105 (19%)

174 (31 %)

Electric power Water coolers 137 (240/o)

Petroleum coke

Feed streams

Exothermic reaction

Oil charge Iossc

1

117 (21 %)

12( 2%)

14( 2°/0)

32( 6°/0)

Total 560 (lOOO/o)

Steam system 18( 3°/0)

Electrical system 5( 1%)

Radiation and convection 21 ( 4°/0)

Products and wastes 10( 2%)

Endothermic reactions 38( 7°/0)

Oil and gas losses 36( 6°/0)

Subtotal 545 (97%)Imbalance 15( 3%)

Total 560 (loo%)

aBa~ed ~n period 9126177. 1016177 at 214,636 bpd oil charge to refl~~.blnclude~ 2713 (487. ) of refining gas and 102 (180/0) of natural 9as.CEnergy value of combustible portion of stock loss

SOURCE: Deparment of Energy, Refinery Energy Profile-Final Report, prepared for DOE by Gulf Research & Development Co., Report No. ORO-5262-5, January 1979.


ing industry is the energy efficiency report madeby the American Petroleum Institute (API) toDOE’s Office of industrial Programs. Table 25presents the petroleum refining industry’s reportto DOE on energy consumption for the year1981.

As part of DOE’s energy efficiency program, thepetroleum industry adopted a voluntary goal ofimproving efficiency by 20 percent by 1980. Ameasure of industry progress toward this goal isshown in figure 24. Electricity and petroleum useremained approximately constant over the timeperiod. However, natural gas use is now less thantwo-thirds of what it was in 1972. Production de-creased by less than 1/2 percent over the sametime period.

Potential for Energy Saving

It is to be expected that refinery managementsand their technical staffs will continue to look forenergy-saving opportunities and to implementthose that appear to be economically justified.However, in evaluating progress the refining in-dustry has made in energy conservation, as wellas the potential for further savings, it is essentialto keep several considerations in mind.

First, competition for capital funds in the petro-leum industry is intense and likely to remain so.

Table 25.–Comparison of 1972 and 1981 EnergyConsumption in Petroleum Refining Industry

1972 1981Energy type consumption consumption

1. Electricity . . . . . . . . . . . . . . 200,525 250,1932. Natural gas . . . . . . . . . . . . . 1,034,006 686,2773. Propane . . . . . . . . . . . . . . . . 9,850 6,9794. LPG . . . . . . . . . . . . . . . . . . . . 28,438 24,8525. Bituminous coal . . . . . . . . . 4,850 4,8236. Anthracite coal . . . . . . . . . . 38 07. Coke . . . . . . . . . . . . . . . . . . . 0 08. Gasoline. . . . . . . . . . . . . . . . 107 1129. Distillate fuel oil . . . . . . . . . 22,183 8,425

10. Residual fuel oil . . . . . . . . . 257,606 177,02811. Petroleum coke. . . . . . . . . . 441,512 427,56912. Purchased steam . . . . . . . . 37,128 27,62913. Refinery gas . . . . . . . . . . . . 1,030,162 1,162,45314. Other liquids . . . . . . . . . . . . 6,692 2,48715. Other (specify) . . . . . . . . . .

16. Total energy consumption 3,073,098 2,778,827SOURCE: American Petroleum Institute, 1981 Report to the U.S. Department of

Energy, “Energy Efficiency Improvement and Recovered MaterialUtilization Report.”

Figure 24.–Comparison of Petroleum RefiningIndustry Energy Use and Production Output

1972 and 1981

200

-180 -

-1972 1981

Energy Production Energy Productionuse use

Coal Petroleum

Natural Electricity and Productiongas steam index

- - t [

SOURCE American Petroleum Institute and Federal Reserve Board

Thus, corporate management may see currentlyunderused refineries as less desirable for invest-ment than are the exploration and production ac-tivities that are rightly considered to be essentialfor the future well-being of the industry.

Second, many of the easy and obvious oppor-tunities for energy savings have been taken. Ad-ditional opportunities, although certainly present,will be more difficult to identify and justifyeconomically. In part, these energy savings willbe difficult to make because environmental regu-lations have affected the industry’s energy use interms of the need for energy-consuming pollu-tion abatement equipment and also in terms ofthe mandate to produce unleaded gasoline.


Technologies for IncreasedEnergy Efficiency

Numerous energy conservation opportunitieshave been identified in the petroleum refiningindustry. 26 The most productive energy-conserv-ing measures appear to be in the areas of im-proved combustion, the recovery of low-gradeheat, and the use of process modifications.

However, there are several barriers to improv-ing the efficiency of energy use in refineries. First,there are operational limits. Energy efficiencymeasures to achieve energy savings cannot oftenbe put into effect just by a plant’s operating or-ganization when it is primarily concerned withrunning the equipment, maintaining safe condi-tions, and producing the desired amounts ofspecification products. An effective energy con-servation program requires a sustained technicaleffort having the consistent support of the com-pany’s management.

Second, there are thermodynamic limits to theamount by which heat input into the processing“system” can be reduced. Many of the chemicalreactions in refining processes require heat (i. e.,they are endothermic). Other operations, suchas fractionation, require that fluid streams beheated to high temperatures. It is not possible toobtain all this heat by exchange with otherstreams. Even more fundamentally, the greatamounts of heat present in refinery lines, vessels,and tanks at low or moderate temperatures can-not be upgraded to higher temperatures by anytechniques now available. Fired furnaces mustusually provide such heat.

Finally, there are economic limits to the in-vestments that can be justified to achieve specificenergy savings. The amount of energy saved does

26 The potent\a/ for Energy Conservation in Nine Selected ln-dustrles: The Da ta Base , Vo l . 2, P e t r o l e u m f?efining, GordlanAssociates, Inc., for the Federal Energy Admlnlstration, NTIS orderNo, PB-243-613, June 1974; Energy Eficlency /rnprovement Targets,Vo/. 1, Petro/eurn and Coa/ Products, Gordian Associates, Inc., forthe Federal Energy Admlnlstratlon, contract No. FEA/D-77/244, June25, 1976

not justify the capital required. Some of theselimits will be apparent in the following discussion.

Proven Technologies forEnergy Conservation

Considering only proven technologies, themost significant opportunities for energy savingsin refineries are likely to be found in the follow-ing operations and systems.

Air and Water Cooling of Process Streams

As indicated previously in figure 23, the finalcooling of process streams in air- and water-cooled heat exchangers can represent the great-est single loss of heat in the refinery. Where feasi-ble, heated streams can first be used to heat otherprocess streams and thus minimize the amountof heat rejected to air or water. Cold streamssuitable for this exchange must be available. TheGulf Research study showed that the total energyinput requirements of the refinery could be re-duced by about 18.7 percent if all such streamscould be brought down to a temperature of 2000F by process heat exchange before being cooledfurther. Such an extreme reduction is unlikely tobe feasible, but the Gulf study showed that reduc-tions to 250° or 300° F would reduce energy re-quirements by 8.6 and 3.7 percent, respective-ly. (Recovery of low-grade heat as mechanicalenergy is discussed under “New Concepts” in

the next section.)

Process Heaters and Steam Boilers

These direct-fired units offer many opportuni-ties for energy savings. With fired heaters, someof the options are: 1 ) reducing excess air and im-proving combustion by using stack gas analyzersand combustion control instrumentation, 2) re-ducing stack gas temperatures by using air pre-heater to heat incoming combustion air, and3) installing convection sections at the heateroutlets to heat incoming feed or to generatesteam. (A constraint on the last two options is theneed to keep stack gas temperatures above thesulfur content “dew point, ” below which seriouscorrosion of carbon steels can be anticipated.)Steam boilers, although many commonly incor-porate such heat-conserving devices as air pre-

100 ● Industrial Energy Use—

heaters and “economizers,” can also often ben-efit by improved combustion controls and per-haps by boiler blowdown heat recovery.

Steam System Improvements

In most refineries, steam is generated and thendistributed at moderately high pressure (often 600psi), as well as at medium or low pressures, suchas 150 and 50 psi. The steam is used for heatingand for mechanical drives (usually turbines) atmany locations in the refinery. Ideally, the steamgenerated and distributed at these pressure levelsis used at such levels, and is reduced or “letdown” to a lower level only while doing usefulwork. At the lowest pressure level, all steam isideally used for heating (or perhaps driving a con-densing steam turbine) so that no steam is wastedby being vented to the atmosphere. Such a sys-tem represents the ideal goal of being “in bal-ance. ”

Inevitably, though, process plants are modified,and their uses of steam change. Steam systemsget out of balance, and frequently no juggling ofsteam turbine and motor drivers can preventwasteful let-downs of high-pressure steam orventing to the atmosphere of excess low-pressuresteam. When steam systems become acutely im-balance, many refineries achieve significant sav-ings by changing major drivers; installing large,low-pressure, condensing turbines; and usingother means to minimize loss in the system. Sinceit is almost never economical to generate steamfor a turbine driver if its exhaust steam will bewasted, replacement of such turbines by motorsoften represents an attractive investment.

Improved Process Heat Exchange

A refinery will contain many heat exchangersfor transferring heat from one process to another.A great number of heat exchanger arrangementsare usually possible, and the optimization of heatexchange—especially in the crude preheat train—is an important aspect of plant design. in thedesign of many U.S. refineries, low fuel prices(and hence low energy costs) resulted in a min-imum amount of heat exchange being installedoriginally. Although a major revamp of heat ex-change systems can be quite expensive, andsometimes impossible because of space limita-

tions, such an investment will often show a verygood return.

Improved Instrumentation and Controls

Most refiners have steadily improved their in-strumentation and control systems, even to theextent of using closed-loop computer controls.The economic benefits from such systems are pri-marily in improved performance of the processunits, but consistently higher outputs and closerproduct specification tolerances can also resultin significant energy savings per barrel of finishedproduct.

Improved Insulation

As with heat exchange systems, insulationstandards in many refineries were developed dur-ing the earlier era of cheap energy. Substantialheat losses from lines, vessels, and other equip-ment were anticipated. Many engineering designpractice standards called for no insulation of sur-faces at temperatures below 200° F unless a sur-face represented a hazard to operating and main-tenance personnel who could inadvertentlytouch it from grade or operating platforms. Insuch cases, the hot surface was often insulatedonly as far as a person could reach. With in-creased energy costs, insulation of surfaces atmuch lower temperatures can now be justified.This justification is especially apparent for large,bare storage tanks operating at temperatures wellabove that of their surrounding environments.

Energy Recovery From Process Streams

Many high-pressure, gaseous, and liquid proc-ess streams are “throttled” by control valves, withsignificant energy loss. In some applications, hy-draulic turbines and power recovery turbines (tur-boexpanders) can be used to extract considerableenergy from such streams.

Pump Efficiency Improvement

Since refinery motors (and most mechanical-drive steam turbines) operate at constant speed,control of output from the pumps they drive mustbe achieved by throttling through a control valve.If the characteristic curve of the pump essential-ly matches that of the piping system, this throt-

Ch. 5—The Petroleum Refining Industry ● 101

tling dissipates only moderate amounts of energyand can usually be ignored. Unfortunately, mis-matches of pump and system are all too com-mon, and often intentional. Design engineershave been encouraged to specify pump impellersof greater diameter (which often need largermotors) than the hydraulic design actually re-quires. Thus, the engineer is protected againstcharges of having “underdesigned, ” and the op-erator is assured of immediately available extracapacity in case he ever wishes to operate theplant above the original design limits. As a result,during its entire lifetime the pump wastes energyby discharging against a partially closed controlvalve, while the unnecessarily large motor driver,operating below its rated output, wastes evenmore energy because it is well below its pointof maximum efficiency. Although the principalsavings in this area can be achieved by properselection of pumps and drivers initially, simplychanging pump impellers can often achieve sig-nificant savings in an operating plant.

Fractionation Efficiency Improvements

The operating characteristics of a fractionatingcolumn are largely established in initial plant de-signs. Or-ice the column has been installed, rela-tively little modification is feasible, and specificopportunities for energy savings are limited. How-ever, many columns are operated at considerablyhigher reflux rates than necessary for proper frac-tionation. Reducing these reflux rates to the min-imum required for proper functioning of the col-umn can result in significant savings.

Refinery Loss Control

Many potential types of refinery losses includelosses from flares, relief valve leaks, tank filling,evaporation from tanks and from oil-water sep-arators, other leaks of all types, tank cleaning andvessel draining, and spillages from all forms ofloading operations.

Housekeeping Measures

Potential savings by vigilance in policing andcorrecting such energy wasters as faulty steamtraps, damaged insulation, careless steam depres-surizing and venting, and the like. The possible

energy-saving measures discussed to this pointinvolve well-understood technologies and oper-ating and maintenance practices. The challengeto refineries comes from the need to identify suchopportunities in specific plants, evaluate them todetermine what corrective measures can be jus-tified, and then proceed to take the necessaryaction.

New Concepts in Refinery Energy Use

Beyond the existing technologies discussedabove there appear to be some significant, long-term opportunities for improving in energy effi-ciency by the use of certain new—or at least un-proven–technologies. Refineries may be able touse other sources of energy, and otherwisewasted heat, to reduce the combustion of gas-eous and liquid fuels. OTA considers that fuelsubstitution (such as the use of coal in refineries)is an important goal, even though the calculatedefficiency of fuel energy use may not be improvedor may even be lowered as a result of such achange in fuel.

The majority of refinery process heaters nowburn only gaseous and liquid fuels derived frompetroleum. in some heaters, tube configurationsand the need for close control of process reac-tions permit only gas to be burned. Since it isperhaps not entirely clear why coal-burning re-finery process heaters have not been developed,it may be useful to summarize the principal de-mands made on refinery process heaters:

1.

2.

3.

In many heaters, the fluids undergo processreactions in the tubes, often at high pressureand temperature. Careful monitoring andprecise control of such reactions are essen-tial, since the process fluid will decomposeif heated above the intended temperature.Precise firing control is necessary for rapid,even instantaneous, control response nec-essary because of the need to shut down fir-ing immediately if the instrumentation or op-erators detect tube failures, dangerouslyreduced flow rates in any tubes, or a powerfailure.In addition to the required, precise controlof temperature of the process streams beingheated, measurement and control of tube

99-109 0 - 83 - 8

102 ● Industrial Energy Use

wall temperature in many furnaces is nec-essary to prevent overheating and ruptureof the tube, with the resulting prospect ofa serious fire.

Coal as a Refinery Fuel

Coal-fired furnaces are perceived by refinersas unable to meet any of the above requirementsbecause they have considerable “thermal mass”and respond relatively slowly to control changes.Also, coal firing results in molten ash depositionon tubes at some temperatures. Lower heat-re-lease rates for coal burning require larger (andhence more expensive) furnaces. Large volumesof ash must be dealt with and—as always withconventional coal burning—the stack gases mustbe cleaned of particulate and perhaps evenscrubbed to remove sulfur acid compounds. Inview of the historically small differential betweenthe costs of coal energy and those of petroleum,it is understandable that little pressure has existedfor the development of coal-fired refinery processheaters. Now, however, with increasing energycosts and potential restrictions on the use ofpetroleum-derived fuels, renewed emphasis is be-ing placed on coal as a potential refinery fuel.Some of these developments are discussed in thefollowing paragraphs.

CONVENTIONAL FIRING

Several attempts have been made to designprocess heaters in which coal would be fireddirectly. Furnace “geometry” would of coursebe different; provisions for ash collection andremoval wouId be provided; and other changeswould be made to use the electric utilities’ ex-perience with burning coal. Pulverized coal(rather than stoker firing) would be necessary topermit faster response to combustion controls.Although some progress reports have appearedin the technical press, the refining industry’s ap-parent conclusion is that no coal-fired heaterdesigns are yet available to meet the exactingdemands of process heater service.

FLUIDIZED-BED COMBUSTION

Fluidized-bed combustion is a process bywhich a fuel is burned in a bed of small particlesthat are suspended, or “fluidized, ” in a stream

of air blown upward from below the bed. Almostany type of properly dispersed fuel can be burnedin a fluidized bed, but most of the technologyof interest re!ates to the combustion of coal ina “clean” manner that eliminates the need forstack gas scrubbing devices to remove sulfur ox-ides. This result can be achieved by feedingcrushed limestone or dolomite into the fluidizedbed along with the coal. The sulfur in the coalcombines with the calcium in the crushed rockto form calcium sulfate. Sometimes identified as“spent sorbent, ” this material is removed withthe ash, and the combined solid waste is disposedof as landfill or used in some other manner.

The concept of a fluidized bed is not new.Since the 1940’s, various forms of catalytic crack-ers, using fluidized beds, have evolved. The fluidcatalytic cracking process is the result of thisdevelopment. The petroleum refining industryhas been following the development of fluidized-bed combustion with great interest. Although itwas originally thought to be just a clean methodof burning coal for refinery steam generation,fluidized-bed combustion could ultimately devel-op into a technology for providing a large partof the total heat required by a refinery. As an il-lustration, figure 25 shows, in elementary form,a conceptual comparison between steam boilersand process heaters using atmospheric, fluidized-bed combustion (AFBC) techniques. In this con-cept (diagram C), the process fluid to be heatedwould be immersed in the fluidized bed.

Since coal-burning equipment of any type re-quires large areas for coal storage and handling,as well as for ash disposal, it would not be feasi-ble to replace individual process heaters through-out a refinery with coal-burning, fluidized-bedunits. Instead, it is possible to visualize large fluid-ized-bed process heaters made up of several cells.Steam would be generated from. coils in someparts of the bed, and process heat could be gen-erated in coils in other parts of the bed. Becauseof the distances involved and the characteristicsof process fluids, it seems unlikely that manyprocess steams would be heated directly bymeans of coils in fluidized beds. Instead, heatmight be transferred to the process areas by hot-oil systems and heat exchangers, and perhapsalso by high-temperature, pressurized water sys-

Ch. 5— The Petroleum Refining Industry ● 103

Figure 25.— Diagram of Atmospheric Fluidized-Bed Combustion (AFBC) Boiler/Combustor Arrangements

A. Saturated steam boiler B. Superheated steam generator

Saturatedsteam outlet

Off gas

Economizer Feed water

Feed water i n l e t —inlet

Off gas

Fuel and

Fuel an Superheatingsorben Superheated

inlet steam outlet

idizing

Ash disposal—.. . -

Ash disposal

C. Indirect process heater

Off gas

●

Workingfluid sorbent inletinlet

Ash disposal

SOURCE U S Department of Energy 1977 Annual Report

terns. Since some process streams must be heatedto temperatures higher than a hot-oil systemcouId feasibly deliver, some process heaterswould still be required.

In view of the foregoing, it seems necessary toconclude that fluidized-bed combustion of coal,although perhaps an eventual means of reduc-ing the combustion of petroleum-derived fuelsin refineries, will not be a significant process

D. Direct process heater

Hot gasesfor process

n e e d s

I I

dt

s)Ash disposal

energy option in the immediate future. It very

likely will, however, find increasing applicationfor steam generation in refineries.

COAL GASIFICATION

It has been suggested that refineries might in-stall coal gasification units to obtain energy fromcoal. Coal gasification couId most logically pro-duce a medium-Btu industrial “syngas” com-

—

104 . Industrial Energy Use

posed primarily of hydrogen and carbon monox-ide. However, it seems unlikely that such an in-stallation would now be attractive to refiners. Thegasifiers being offered are in various stages ofdevelopment, and none can be considered reli-able. Likewise, the relatively low conversion ef-ficiency of the process, the problems of handlingcoal and ash, the need to build and operate anadjacent oxygen plant, and the complications ofconverting refining furnaces to use a fuel of muchlower Btu than now used all argue against con-sidering coal gasification a reasonable option. Ifdone at all, it seems most likely that coal gasifica-tion will be undertaken by a major utility serv-ing refineries along with its many other industrialcustomers.

Thermal Recovery of Low-Level Heat

As might be expected from the magnitude oflosses to air- and water-cooled heat exchangers,refinery management and its technical staff seethermal recovery of low-level heat as a prime op-portunity to save energy. They are also aware thatopportunities for recovering significant amountsof this wasted heat are unlikely to be found inexisting operating plants, but must await insteadthe design of new facilities where heat balancescan be developed with consideration for the truevalues of heat at all temperatures and pressurelevels.

one major refining company is designing a newlubricating-oil manufacturing plant to take advan-tage of low-level heat recovery. In this plant, theprocess streams being “run down” for final cool-ing first generate 45-lb steam and then provideheat to a pressurized, “tempered” water systemoperating at about 2850 F. The tempered wateris used for process reboilers and also as the heat

source for the aqua-ammonia absorption refrig-eration system, a key part of the plant. Finally,the process streams are cooled in the conven-tional manner. Although these streams are stillat temperatures of approximately 300° F whenfinally cooled, considerable energy that wouldotherwise be wasted is recovered.

Most of the many opportunities for using low-Ievel heat from rundown streams will appear inthe design of new facilities whose energy require-ments are not circumscribed by existing systems.

Mechanical Recovery of Low= Level Heat

Low-1evel waste heat might be used to vaporizea fluid, use the vapor to operate a mechanical-drive turbine, and then condense the vapor forrecycling to the heat source. Although the con-cept is straightforward, its practical applicationis not. Organic fluids must be used instead ofwater because of the size of the required equip-ment and the complexity of operating under avacuum. * Selection of a working fluid involvesconsiderations of toxicity, environmental accept-ability, cost, and the thermodynamic propertiesneeded for the cycle. Although the various fluoro-carbons are leading contenders, increasing re-strictions may make their use inappropriate.other typical refrigerants have been considered,and one, toluene, is used in one experimentalapplication reported in the literature. Finally, inaddition to other limitations of this method, thelow level of heat involved limits energy recoveryto perhaps 10 percent, making this form of energyconservation generally unattractive economically.

*The term ‘‘organic rankine cycle” is used to refer to this low-Ievel heat recovery technology.

INVESTMENT CHOICES FOR THE REFINING INDUSTRY

In this section OTA examines certain broader native investments discussed to those for energy-aspects of the petroleum industry, including: saving options in refineries.1 ) competition for capital investment dollarswithin the industry as it is now structured, and Capital Expenditures in the Oil Industry2) possible investment opportunities in largely In considering investment opportunities and in-nonoil operations. OTA then relates the alter- centives for energy-saving measures in refineries,


it is essential to keep in mind the magnitude ofother demands for capital in the entire industry.For example, the 0il & Gas Journal summarizesthe 1982 budget for the U.S. oil industry as:

Explorat ion and product ion . . . . . . . . . .$66,8 bi l l ion

Refining . . . . . . . . . . , . . . . . . . . . . . . . . . .6.4 bi l l ion

Other . . . . . . . . . . . . . . . . . ........22.1 billion

Total 1982 budget . . . . . . . . . . . . . . . .$95.3 bi l l ion

The Standard Oil Co. of California capital ex-penditure record (shown below) for 4 years isconsistent with the Journal’s report and is be-lieved to be representative of similar expendituresby other major U.S. oil companies.

Capital and Exploratory Expenditures (millions of dollars)

1977 1978 1979 1980Producing and exploration .,$ 891 $1,163 $1,603 $2,230M a n u f a c t u r i n g : C h e m i c a l s 6 0 2 6 57 91

Refining . 168 149 187 328M a r k e t i n g 76 92 102 272Transportation 84 50 96 134O t h e r 150 212 213 544— — . .

Total expenditures ... ... .$1,429 $1,692 $2,258 $3,599

A very significant aspect of the foregoing figuresis the magnitude of the financial resourcesneeded to discover and produce crude oil andnatural gas. These expenditures have increasedrapidly in recent years, partly because of the an-ticipated (and then actual) decontrol of oil pricesand because of the urgent need seen by the in-dustry to reduce its dependence on foreignsources of crude oil. In addition, even thoughgeophysical techniques are constantly improving,exploration operations produce many more “dryholes” than wells promising commercial produc-tion. As the potentially hydrocarbon-bearing geo-logic structures now being explored are at in-creasingly greater depths, the exploratory wellsand those drilled for production of commercialdiscoveries are becoming increasingly expensive.

Another drain on the capital resources of theindustry is the previously mentioned restructur-ing of processing systems to permit runningheavy, high-sulfur crude oil and producing theincreasing share of unleaded gasoline that mustbe provided for the motor fuels market.

Other Investment Opportunities

Corporate planners in the oil industry work inan atmosphere of great uncertainty. They know

that supplies of crude oil and natural gas willbecome increasingly scarce, but they do notknow whether a serious availability “crisis” willoccur within a decade, a generation, or at sometime in the next century. More immediately, theycannot assess political conditions in the troubledareas of the oil-producing world accuratelyenough to forecast either worldwide price trendsor the amounts of imported crude oil the Westernworld can safely count on. They can be certain,however, that their past world of steadily increas-ing crude runs and product sales has come to anend; they must now do the best they can to planfor an uncertain future. Two options–not mutual-ly exclusive–seem open to the industry:

●

●

Concentrate on employing the resources andspecial skills they now have available, includ-ing searching out long-term investment op-portunities in areas of technology that canbe developed without major shifts in cor-porate structure, personnel, or markets.Use their great financial resources and pre-sumed managerial and technical expertiseto enter any field of endeavor that promisesfinancial rewards, regardless of its relationto existing operations.

In considering options of the second type, oilindustry corporate management may find itselfconfronted with what might be termed an “iden-tity crisis.” As repeated public opinion pollsdemonstrate, the industry is now held in lowesteem by much of the U.S. public. In spite ofclear factual evidence to the contrary, a large seg-ment of the public seems to believe that the muchpublicized oil shortages and the gasoline lines ofthe recent past—and for many, perhaps, evenhigh gasoline prices–have been contrived by themajor oil companies for their own financial ben-efit. Although legislative proposals for break Upor nationalization of the industry appear to have

subsided, such proposals are very much in thebackground and would probably be reintroducedif their sponsors felt the political climate wereright.

The public can likewise be expected to recallthat much of the industry vigorously campaignedfor decontrol of oil prices, giving as a principaljustification the need for more revenue to in-crease oil and gas exploration in the United

—


States. Now that oil price decontrol has beenachieved, public opinion and editorial commentcould be most unfavorable to announcements bymajor oil companies of large investments in ac-tivities unrelated to the oil business or to takeoverattempts within the industry by companies al-ready perceived to be “big enough. ”

Given this background, corporate managementmight seek several types of investments to guidetheir companies during the uncertain transitionperiod.

Energy Investments

The most obvious area of oil industry expan-sion involves investments in other forms ofenergy. Although not all investment decisions useoil industry expertise directly, most do follow thesequence, “research -development-marketing,”to which the industry is accustomed. Exampleswould include the following:

Synfuels: Liquefaction of Coal.–Liquefactionof coal is perceived by many industry analysts tobe one of the best long-term opportunities formajor refiners. In direct liquefaction processes,liquids are obtained directly by hydrogenation ofcoal. Liquefaction processes are being developedin many of the major oil industry process labora-tories, and several processes are felt to be ap-proaching commercial development–examplesare SRC-11, Exxon Donor Solvent, and H-Oil. Un-fortunately, all these processes still appear to beplagued by mechanical problems as well as byprocess uncertainties. Moreover, recent declinesin crude oil prices, together with the great reduc-tion in Federal subsidization of demonstrationenergy projects, make it unlikely that directliquefaction plants of commercial size will be builtin the near future. Nevertheless, these processesrepresent a long-term source of liquid fuels thatcould supplement and perhaps ultimately sup-plant crude oil in the manufacture of liquid fuelsand a wide range of other products. It is to beexpected that the industry will continue to workon their development.

Indirect processes of coal liquefaction are thosein which coal is first gasified to produce a medi-um-Btu syngas. This gas can be converted to liq-uid fuels or to chemical feedstocks, as done in

the South African Government’s large “SasoI”plants. Alternatively, the syngas can be convertedto methanol and then to gasoline, using Mobil’sproprietary process. Although the indirect lique-faction technologies are considerably furtheralong in development than are the direct proc-esses, they seem to be less attractive to the oilindustry. Their conversion efficiency is significant-ly lower, and they do not produce the wide rangeof products required by oil industry markets. Oilindustry R&D appears to be concentrated on di-rect liquefaction processes, but considerable ef-fort is also being devoted to the indirect ap-proaches.

Geothermal Energy production.–Some geo-thermal energy resources (steam and hot water)can be identified by surface geologic conditions,others by exploratory drilling for oil and gas.Typically, an oil company exploiting a geother-mal resource will top the steam or hot water andthen sell it to a utility for power generation.Cooled water may be returned for injection intothe formation. In spite of many optimistic assess-ments, use of geothermal energy resources pre-sents many technological and environmentalproblems that can be expected to slow develop-ment. Nevertheless, geothermal energy resourcesin the United States are of very great magnitude.It is expected that oil industry participation intheir use will continue.

Petrochemicals.–Most U.S. manufacture ofpetrochemicals (including basic feedstocks) is notespecially profitable at present. Although it is abasic activity of the refining industry, petrochem-ical manufacture would not appear to be an at-tractive investment area until the potential prob-lems of foreign competition are resolved and theU.S. market improves.

Alternative Energy Sources.–Many oil industrylaboratories conduct intensive research programsin such fields as fuel cells, solar photovoltaics,and other forms of solar energy utilization. Mostof these activities are considered to be very longrange. It is hoped that some will result in newand economical sources of energy, but none isbelieved to be at a point where a major capitalinvestment in the technology would be consid-ered.


Oil Shale Mining and Processing.–Many of themajor oil companies are undertaking oil shaleprojects, and others have been preparing to doso. Some acquired their own oil shale propertiesmany years ago. Others operate under Federalleases. The hydrocarbon reserves in Coloradoand other oil shale deposits are of very great size,and much informed opinion in the oil industryholds that oil from shale will be developed andon the market long before synfuels from coal canbe produced. Nevertheless, billion-dollar in-vestments will be required for shale productionand retorting, and few companies appear to bewilling (or able) to proceed with such develop-ments without Federal product purchase con-tracts or loan guarantees. As with many otherenergy proposals, softening prices of crude oil aredampening the recent enthusiasm for shale oil,and several cutbacks and postponements of thesedevelopments have already been announced. Al-though ultimate use of these shale oil resources

seems certain, the firms making investments noware doing so because of the long-range poten-tial, and not in expectation of immediate profits.

Nonoil-Related Investments

Although many nonoil-related investments areinitially profitable—and others may prove so afterinitial difficulties—several have already causedunfavorable comment in the financial press.Among the best known examples of investmentsthat apparently have not been profitable areMobil’s acquisition of Marcor (including Mont-gomery Ward), Exxon’s Office Systems Co., andExxon’s acquisition of Reliance Electric. It wouldappear that such investments are appropriateonly when oil industry management is confidentthat no reasonably equivalent opportunities canbe found in its own industry–including the oftenoverlooked possibilities of investments to achievemore efficient refinery operations.

IMPACTS OF POLICY OPTIONS ON THE PETROLEUMREFINING INDUSTRY

Having examined the energy use characteristicsof the petroleum refining industry, including thespecific unit operations where energy is used andthe technological opportunities that can improvethe efficiency of energy use, the rest of this chap-ter will be devoted to an examination of the ef-fect of a series of policy options as they wouldinfluence energy use.

This analysis is based on a trio of analyticalmethodologies. In each policy option case, OTAhas projected fuel use between 1980 and 2000using the Industrial Sector Technology Use Model(ISTUM). Second, OTA has assembled a list ofeight typical projects in which a petroleumrefinery management could invest its capitalfunds. The projects are ranked according to theirinternal rate of return (1 RR) under both thereference case and the policy option. Anychanges in the ranking are then examined anddiscussed. Finally, the observations and analysesof OTA’s consultants, advisory panelists, andworkshop participants are noted.

The projects used to illustrate the IRR calcula-tions are described in table 26. Four of the proj-ects are specifically oriented toward the petro-leum refining industry. The remaining four aregeneric—i. e., they are applicable throughout theindustrial sector.

A graphical illustration of the impact of eachpolicy option on energy use in the industry ispresented in figure 26. The analysis begins witha discussion of the reference case.

The Reference Case

The reference case is predicated on the eco-nomic and legislative environment that existstoday. It includes the following several generaltrends that can be identified at present and whichshould continue over the next two decades:

● A general decline in the total amount of re-fined product produced between 1980 and2000.

. —


Table 26.—Petroleum Refining Industry Projects To Be Analyzed for Internal Rate of Return (lRR) Values

1.

2.

3.

4

—

Inventory control. —A computerized system that keepstrack of product item availability, location, age, and soforth. In addition, these systems can be used to forecastproduct demand on a seasonal basis. The overall effect isto lower inventory yet maintain the availability to shipproducts to customers with little or no delay. In typicalinstallations, working capital costs are dramaticallyreduced.Project life—5 years.Capital and installation costs–$560,000.Energy savings—O directly, but working capital could be

reduced by $1.2 million.Electric motors. -The petroleum refining industry useselectrical motors for everything from vapor recompressionto mixing, pumping, and extruding. In this analysis, OTAhas assumed that five aging electric motors will bereplaced with newer, high-efficiency ones.Project life—10 years.Capital and installation costs–$35,000.Energy savings–$16,000 per year at 4¢/kWh.Catalytic reformer air preheater #1.—A typical energyconservation project in the petroleum refining industrywherein hydrogen is removed from certain organiccompounds, thereby increasing the octane rating of theremaining aromatic material.Project life—10 years.Capital and installation costs—$2 million.Energy savings—$894,000 at 30 million Btu saved per hour.Catalytic reformer air preheater #2.—Same as above,except that major structural changes are necessary in thefurnace configuration, thereby increasing installation cost.Project life—10 years.Capital and installation costs—$3 million.

SOURCE: Office of Technology Assessment

● A shift in product mix produced by the petro-leum refining industry.

● A deterioration in the quality of crude oilfeedstock available to the petroleum refin-ing industry.

As mentioned before, these trends place SIC 29corporations in the unenviable position of hav-ing to make substantial investments to accom-modate changing feedstocks and product marketsin an industry whose overall growth will benegative.

These trends can be clearly seen in the model-ing analyses carried out under OTA direction.Table 27 presents the OTA projection for totalproduction in SIC 29. As shown, it decreases froma high of 14.2 million bpd in 1980 to 13.9 millionbpd in 2000. At the same time, the product mixis forecast to change from a preponderance of

5.

6.

7.

Energy savings—$t394,000 at 30 million Btu saved per hourof operation.

Computerized process contro/.—One of the mostubiquitous retrofit purchases being made for industrialsystems is to add measuring gauges, controlling activators,and computer processors to existing machinery. The mainaccomplishment of such a process control system is toenhance the throughput and quality of a refinery with onlymaterials and small energy inputs.Project life—7 years.Capital and installation costs–$500,000.Energy savings—$150,000 per year.Crude oil atmospheric distillation unit.—lt is assumed thattwo major crude oil distillation furnaces have been inoperation for many years. While relatively inefficient inenergy use, the two furnaces are nevertheless stillserviceable, Can their replacement be justified in energysavings alone?Project life—10 years,Capital and installation costs—$12 million.Energy savings— $3.2 million per year.Counterflow heat exchanger. —Installation of a counterflowheat exchanger to preheat air entering a furnace with theexhaust stack gases from the same kiln.Project life—10 years.Capital and installation costs–$200,000.Energy savings—$53,000 per year.

8. Refinery boiler control system. —Installation of a computercontrol system to optimize burner efficiency in a boilerfurnace.Project life—10 years.Capital and installation costs—$3.75 million.Energy savings—$820,000 per year.

gasoline to an equality between gasoline andmiddle distillates.

The decline in energy intensity will be mostrapid in the 1980-90 decade owing to projectedimprovements in operations and retrofit additionsto enhance heat recovery (see fig. 27). Computercontrols and process units, heat exchangers, re-generators, waste heat boilers, and the like areexpected to improve the efficiency of existingunits and fired heaters. I n the following 10 years(1990-2000), new, more efficient processesshould be added to refinery operations to helpreduce energy intensity. These should be proc-esses such as fluid coking with gasification, poly-merization, and so forth. It is interesting to notethat, given the projected decline in consumptionof refined petroleum products, 80 percent of theexpected improvement in energy efficiency in SIC


4.0

3.5

3.0

2.5

2.0

1.5

1.0

0.5

0.0

Figure 26.—Petroleum Refining Industry Projections of Fuel Use andEnergy Savings by Policy Options,-1990 and 2000

Fuel Use Projections

Naturalgas

1990

Oil Coal Purchasedelectricity

2000

Ref No EITC Btu Cap Ref No EITC Btu Capcase ACRS tax avail case ACRS tax avaiI

Fuel Savings Projections1.0

1990

0.3

0.2

0.1

0.0

2000

Ref No EITC Btu Cap Ref No EITC Btu Capcase ACRS tax avaiI case ACRS tax avaiI

SOURCE Office of Technology Assessment


Table 27.—Projected Changes in Petroleum Refining ProductionBetween 1985 and 2000a

1980 1985 1990 2000Gasoline . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.4 6.4 (42%) 5.7 (380/.) 4.9 (350/o)Middle distillates . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.0 4.4 (290/o) 4.7 (32%) 4.7 (34°/0)Naphtha . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.5 0.6 0.7 0.9Petrochemical feedstocksb . . . . . . . . . . . . . . . . . . . . 0.6 1.0 1.2 1.3Residual oil . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.4 1.5 1.4 1.0Others C . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.3 1.2 1.2 1.1— —

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14.2 15.1 14.9 13,9aln million barrels of oil refined per day and percent,bOther than naphtha.clnclude~=phalt paving matedals, Petroleum coke, Iubricatingoiis, ~d the ‘ike.

SOURCES: Department of Energy, Petroleum Supply Annual Report, 1901; and Office of Technology Assessment projectionusing ISTUM.

r

1970 1975 1980 1985 1990 1995 2000

YearSOURCE Office of Technology Assessment

29 will be attributable to add-on energy conser-vation units over the next two decades. Only 20percent will be attributable to new processes.

Projected Effects of Policy Options

Option 1: Removal of AcceleratedDepreciation

OTA projects very little change in petroleumrefining energy use patterns if the ACRS is re-moved, as shown in figure 26. There should bea slight increase in natural gas used (1 percent-age point or less) and a slight increase in coalused. Cogenerated electrical energy productionwould be down because the depreciation in new-ly installed equipment would not be as rapid andwould therefore be less attractive. overall energyuse is projected to increase less than 1 percentagepoint above that of the reference case.

This analysis is corroborated by an examina-tion of table 28. There are no changes in any ofthe IRR values that are greater than 1 percentagepoint, nor are there any changes in the rankingof any project.

The top three projects are obviously attractiveinvestments. They represent the type of projectscorporations readily take on when energy costsbegin to approach 1981 levels. And these proj-ects maintain their attractiveness even withoutthe added incentive of ACRS depreciation. Theseprojects will be done, assuming capital is avail-able, because energy, along with materials andlabor, is expensive, and each of the top threeprojects represents a means of reducing costswithout changing the nature of the products pro-duced.

Option 2: Energy Investment Tax Credits

OTA analysis suggests a less than l-percentchange in overall energy use as a result of a10-percent targeted energy investment tax credit(EITC). And, perhaps surprisingly, the change isprojected to be a slight increase, as shown infigure 26. This result arises from a projected in-crease in cogeneration, which comes about pri-marily from using natural gas to produce bothsteam and mechanical or electrical energy. Coaluse is also projected to increase by several per-centage points as coal-fired boilers are used toraise steam, and coal is used for process heat.

Table 28 shows the impact of an EITC on theIRR values of representative petroleum refining

Ch. 5—The Petroleum Refining Industry . 111

Table 28.—Effects of Policy Options on IRR Values ofPetroleum Refining Industry Projects

IRR with policy option

$1/MMBtu tax onReference ACRS 10-percent natural gas and

Project case removed EITC petroleum products1. Inventory control . . . . . . . . . . . . . . 87 87 87 872. Electric motors . . . . . . . . . . . . . . . 43 43 48 513. Catalytic air preheater #1 . . . . . . . 30 30 34 374. Catalytic air preheater #2 . . . . . . . 20 20 23 255. Crude unit furnace

replacement . . . . . . . . . . . . . . . . . . 17 17 21 246. Computerized process

control . . . . . . . . . . . . . . . . . . . . . . . 16 16 22 197. Counterflow heat exchanger . . . . 15 15 18 198. Boiler plant control system . . . . . 14 14 17 18SOURCE: Office of Technology Assessment.

industry projects. As shown, the impact on theproject was modest. Most IRR values increasedby 3 to 5 percentage points, and only one proj-ect, the computerized process controller, movedup in ranking, but only by 1 point. It is unlikelythat this change in ranking would affect manage-ment’s decision to take on, for example, thecrude unit funace replacement. Such factors astotal cost, age of the furnace, perceived reliabilityof the computer process controller, and the like,would have more impact on the decision.

In evaluating the potential effect of energy taxcredits, it is necessary to recognize that ap-plicability of such credits is not guaranteed. Inorder to avoid having such credits treated as justone more general investment tax credit, the In-ternal Revenue Service (IRS) can be expected toexamine proposed applications of an energy taxcredit closely. To judge from experience, IRS ex-aminations and rulings may be expected to delaythe application of such credits and to limit theiruse to a perceived energy-saving portion of aninvestment, even though the entire investmentmust be made in order to achieve the energy sav-ings.

Option 3: Tax on Premium Fuel

OTA analysis suggests that a fuel price increaseof $1/MMBtu, whether in the form of a tax ormarket-dictated increase, would have the effectof slowing the penetration of cogeneration tech-nology into SIC 29 relative to what is projected

to occur in the reference case. And because co-generation is slowed, natural gas use will be lessand purchased electricity will be greater than thatin the reference case.

However, the greatest effect would be to pro-mote fuel switching away from premium fuelsand toward coal for both coal boilers and forhydrogen production. The combined effect of theuse of more coal technologies with the decreasein cogeneration and increased purchase of elec-tricity from utilities leads to a slight increase intotal energy demand.

Table 28 presents the projected impact on IRRvalues of the petroleum refining projects. The fuelprice increase does increase IRR values by 5 to7 points, except for the inventory control option,which is a project with no premium fuel use.However, none of the projects changed its rela-tive ranking. While the list of projects may notbe all inclusive of those available to a refinery’smanagement, it does illustrate that other factorsbesides IRR would be needed to change the rank-ing of a project.

An energy tax can have undesirable effects onthe refining industry. Refining costs would in-crease, and product prices would necessarily fol-low. imported products would become morecompetitive, perhaps necessitating specific tariffs

or other measures to protect U.S. refiners andtheir industrial customers. And refiners wouldhave less ability to invest in energy-saving equip-


ment to the extent that they couldn’t pass on theirincreased costs.

Option 4: Low Cost of Capital

OTA analysis suggests that of all the legislativeoptions examined, the low cost of capital wouldcause the greatest change in energy use com-pared to the reference case. The low cost ofcapital would promote the use of cogenerationand retrofit conservation technologies, therebyproducing more self-generated electricity and areduction in waste energy. The most significantshift in fuel mix would occur in steam methanereforming, where partial oxidation of coal to pro-duce hydrogen displaces the use of natural gas.

Table 29 presents the OTA analysis of the im-pact of a decrease in interest rate on moneys bor-rowed to undertake the representative petroleumrefining projects. In this instance, the referencecase figures have been changed to reflect a situa-tion where two-thirds of the money needed tofinance the project is borrowed at a 16-percentinterest rate. One-third of the cost wouId comefrom funds already in hand in the firm. When theinterest rate is lowered to 8 percent, two of the

projects move up in ranking. Although the cata-lytic air preheater # 1 project would advance tothe second place, it was already very attractive.Even without borrowing, the IRR value was above30 percent with borrowing, it soars to 83 percent.The shift to above 100 percent will not significant-ly increase the attractiveness of an already de-sirable project,

Because of the decline in interest rates, all theprojects have become more attractive, at least asmeasured by I RR values. Other factors such astotal cost, plant downtime, and the like, however,would also affect the decision about whether toinvest in these projects. It must again be em-phasized that investments for energy savings haveno special priority over the petroleum industry’sneed to spend vast amounts of capital in essen-tial exploration and producing activities and toadapt refineries to the changes in available crudetypes and to the changing demands of the prod-ucts market. Many such investments will be con-sidered necessary by industry management andthus will take priority in discretionary capital ex-penditures.

Table 29.—Effect of Lower Interest Rates on IRR Values ofPetroleum Refinery industry Projectsa

Reference case IRR IRR with policywith 16 percent options: interest

Project interest rate rate of 8 percent

1. Inventory control . . . . . . . . . . . . . . . . . . . . . . . . . . .2. Electric motors . . . . . . . . . . . . . . . . . . . . . . . . . . . .3. Catalytic air preheater #1 . . . . . . . . . . . . . . . . . . . .4. Crude unit furnace replacement . . . . . . . . . . . . . .5. Catalytic air preheater #2. . . . . . . . . . . . . . . . . . . .6. Computerized process controller . . . . . . . . . . . . .7. Counterflow heat exchanger . . . . . . . . . . . . . . . . .8. Boiler plant control system . . . . . . . . . . . . . . . . . .

385938376703633

413

37097

1079089443859

aAll projects are assumed to be two-thirds debt financed and one-third equity financed

SOURCE: Office of Technology Assessment.

Documents

The Petroleum Refining Industry