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Chapter1Introduction

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The development of petroleum geology

The modern petroleum geologist

Some maintain that there is no such thing as etroleum geology,? there is only the science of geology applied in the search for petroleum; in which case this text ought to be entitled eology as applied to Petroleum?in the style of Illing (1942)! Alternatively, a contemporary title such as etroleum Systems Geology? emphasizes the highly integrative nature of petroleum exploration and exploitation! However, as a title, etroleum Geology? conveys a o-frills, meat-and-potatoes? approach to a branch of geology that is first and foremost a commercial enterprise concerned with the exploration and economic development of petroleum!

The role of the etroleum geologist? is also becoming increasingly complex and although the majority of professional geoscientists typically have a specialist skill, perhaps as a sedimentologist or stratigrapher for example, the professional geologist must also increasingly integrate traditional skills with the new, in an increasingly complex world. A etroleum geologist? must have a solid understanding of historical geology and stratigraphy, structural geology, sedimentary geology, mineralogy and petrology, geophysics and an understanding of subsurface fluids, petroleum geochemistry, statistics, various aspects of engineering, a solid appreciation of economics and an understanding of local, national, and international politics. However, first and foremost one must be a geologist!

The historical development of geological concepts related to petroleum

Before 1901 In the days before 1901, etroleum geologists? as such did not exist. Oil exploration theory was very rudimentary. In fact, most of the significant il-finds? were discovered using the presence of natural seeps of petroleum at the Earth's surface (example: Baku or the Appalachians) or detected by various ome-spun? methods! Legend has it that one fabled il finder? would drill wherever his hat came off whilst riding his horse; the popular attitude that oil seemed to have no known prerequisites seemed prevalent in the nineteenth century!

In 1842, William Logan, who later became the first Director of the Geological Survey of Canada, noted the presence of seepages of oil from anticline structures in Paleozoic rocks of the Gasp? Quebec. During a subsequent survey of the um beds? of Enniskillen, Ontario, soil samples were sent to Thomas Hunt for analysis. Hunt subsequently reported that the soil did indeed contained petroleum. Recognizing the association, he proposed his anticlinal theory in a publication in 1861. In that publication Hunt stated (p. 249):

hese wells occur along the line of a low broad anticlinal axis which runs nearly east and west through the western peninsular of Canada and brings to the surface in Enniskillen the shales and limestones of the Hamilton Group, which are there covered with a few feet of clay. The oil doubtless rises from the Corniferous Limestone, which as we have seen contains petroleum; this being lighter than the water which permeates at the same time the porous strata, rises to the higher portion of the formation, which is the crest of the anticlinal axis where the petroleum of a considerable area accumulates and slowly finds its way to the surface through vertical fissures in the overlying Hamilton shale, giving rise to the springs of the region?. Hunt (1861).

That same year E.B. Andrews published a paper describing the anticlines of southeast Ohio and Cow Creek in Virginia (Figure 1). In that publication Andrews states in broken rocks, as found along the central line of a great uplift, we meet with the largest quantity of oil? (p. 88), also adding at the anticlinal line are gas and oil springs? (p. 92) Andrews (1861).

Figure 1. Anticlinal section on Cow Creek, Virginia. Oil and gas springs occur at the crest (A)

(redrawn from Andrews, 1861).

A1

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Both Hunt and Andrews made significant steps towards defining a concept of how petroleum is retained in rock and in defining a eological trap,? however their work appeared to go largely unnoticed! The exploration for oil remained primarily influenced by the thinking of the time, which relied upon the presence of natural seeps in clastic sedimentary rocks around creeks and streams. Because the writings of Hunt and Andrews had not been opularized? or embodied into a formal theory, there was no systematic search for oil or the development of a ?play? and consequently many dry holes were drilled. To further complicate thinking, many early finds actually occurred within unrecognized stratigraphic traps and not anticlines! The ability of the early explorationist to unravel the complexities of the subsurface was very rudimentary, with geological data typically derived by outcrop. Because early workers had no drill core, drill cuttings, or wireline logs to guide them, correlations between wells also did not exist. With no formal theory to guide them, some felt that the best way to drill a ry hole? was to employ a geologist!

After Spindletop The 1901 Spindletop discovery in Texas and the discovery of oil beneath large anticlinal structures in Kansas, Oklahoma and California, helped formalize the nticlinal theory? of Hunt and Andrews. The apparent demonstrable link between economic accumulations of oil and anticlinal structures captivated the thinking of explorationists throughout North America.

In 1917, the Bolivar Coastal field in Venezuela was discovered also using the association of surface seeps, but in contrast to Spindletop the petroleum was retained in a homoclinal trap, not an anticline. Unfortunately, this discovery had little impact, especially within North America where the reliance upon surface seeps and the application of the nticlinal theory? completely dominated the thinking of the day. So entrenched was the apparent demonstrable link between economic accumulations of oil and anticlinal structures, explorationists feared they were running out of prospective plays. As was documented later (Hedberg, 1971), explorationists were not running out of plays, just running out of ideas! It was time for a geological revolution in thinking; a change that led to the discovery of the great East Texas Pool in which oil and gas were discovered within a stratigraphic trap and without the presence of seeps of any kind!

The East Texas Pool and beyond No longer could the explorationist simply look for seeps and folded structures, convention after convention was set aside as explorationists dared to think out of the box. What followed was the development of petroleum geology, as we know it today, with the development and application of exploration methodologies, the formulation of trap classifications, and the systematic analysis of reservoirs. It became apparent that geologists had a significant part to play in the exploration of petroleum through their understanding of the subsurface, subsurface fluids, and the application of new exploration technologies.

In short, petroleum geology as we know it was born!

The development of an industry

Some industry tatistics?

It is generally believed that there are more than 6,500 drilling rigs of varying size and depth rating currently available or in use. More than 3.7 million wells have been drilled globally within the last 100 years and on average, approximately 12 ? 107 meters of hole is drilled per year. However, the success rate (i.e., commercial viability) for ildcat? or new wells is approximately 10%. There are approximately 18,000 producing oil fields in the USA, more than 3,000 in the former CIS, 1,000 in Canada, more than 1,000 throughout Europe (including the North Sea), more than 2,000 in Australia and Asia, but less than 150 in the Middle East. The largest single oil field in the world, the Ghwahar, occurs in the Middle East, and a ypical? oil well in the Middle East produces more than 103 m3 of oil per day. This is in stark contrast to the verage? North American well that produces approximately 3 m3 per day. Approximately 70% of all North American wells yield less than 1.6 m3 (10 barrels) per day!

The member countries of OPEC (Organization of Oil Exporting Countries) currently produce more than 75% of the world oil, with Saudi Arabia, Iran, Iraq, and Kuwait producing over 50% of the world total. The countries of the Middle East (e.g., Saudi Arabia, Kuwait, Iran, Iraq, and Kuwait) hold approximately 64% of all known recoverable oil reserves (Figure 2), which is estimated to be 673.9 billion barrels. In contrast, South America has 9% (89.5 billion barrels), North America 8% (85.1 billion barrels), Africa 7% (75 billion barrels), Eastern Europe (incl. Russia and Ukraine) 6% (64.7 billion barrels), Asia and Australasia 4% (43 billion barrels), and Western Europe about 2% of the current known recoverable oil reserves. The current distribution of natural gas is quite different; the United States,



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Global distribution of conventional oil

Middle East

64%

Africa

7%

Western

Europe

2%South America

9%North America

8%

Eastern Europe

6%

Asia &

Australasia

4%

Global distribution of natural gas

S America

4%

N America6%

Western Europe

4%

Africa

7%

Middle East

34%

Eastern

Europe

38%

Asia &

Australasia

7%

Canada, Algeria, Saudi Arabia, and Iran, plus countries of Eastern Europe hold 75% of all known gas reserves, of which Iran and Eastern Europe hold 40% of the total (IEA, 2004).

Figure 2. The known (2004) global distribution of oil (left) and natural gas (right) per geographic region

(Data source: IEA, 2004: http://www.iea.org/Textbase/stats/index.asp).

The historical context of the petroleum industry

Early beginningsReferences to petroleum (i.e., pitch) exist within the Bible, in the works of Confucius (c. 600 BC), and Herodotus (c. 450 BC). Tar and pitch were obtained from natural seeps, such as those within the Middle East, and used as an illuminant, to waterproof boats and water containers, and very effectively used in warfare. By about 600 BC hand dug pits in China were created for the extraction of oil and, due to a steady development in technology, Chinese drilling tools had reached the unprecedented depth of 1,000 m by 1132 AD. By 1800 AD, the Yenangyaung oil field had more than 500 wells producing about 35,350 cubic meters (216,000 bbl) of oil per year. In contrast, the first European oil well was spudded at Pechelbronn (France) in 1745, and wells were successfully completed as oil producers in North America at Oil Springs (Ontario, Canada) and at Oil Creek (Pennsylvania, U. S.A). in 1859 (Brantley, 1971; Beaudrow et al., 2001).

The birth of a market Prior to the middle of the nineteenth century there was little need for oil due to the availability and use of other abundant materials, such as wood, coal and charcoal for heat and refined whale oil as an illuminant. Industrial production was fueled by coal. Coal was extensively used to raise steam to drive both industrial machinery and locomotives. Coal was plentiful, cheap, and reliable and coal was king! Throughout Europe and North America, the preferred domestic illuminant was kerosene, which was refined from whale oil. Whale oil was very easy to refine. However, during the nineteenth century a rapid increase in population and the continued urbanization of both Europe and North America led to an unprecedented increase in the demand for kerosene, which increased the demand for whale oil, which was in short supply. This in turn drove up the price of kerosene, prompting a search for a new and cheaper source of kerosene.

In 1854, Dr. A. Gesner, who was both a geologist and chemist, developed a process that could generate kerosene from coal; the word kerosene is derived from keros, the Greek word for wax. Because coal was very abundant and a cheap resource, coal rapidly replaced whale oil as the raw material for kerosene. As the popularity of kerosene increased, the search for a cheaper raw material continued. It was soon discovered that crude oil was a better raw material for kerosene, because it was both cheaper and easier to refine, although sources of crude oil were, at that time, limited. Therefore, new sources of crude oil were sought in North America, Europe, Russia, and Asia. This was the beginning for the il industry.?

Development and expansion In 1858, James Miller Williams began drilling at Oil Springs, Ontario, Canada. Initially drilling for water, he struck oil at a depth of 14 feet; the well was subsequently completed in August 1859 (Beaudrow et al., 2001). The first intentionally drilled oil exploration well was drilled by ncle Billy? Smith and his sons, at Oil Creek in Pennsylvania, United States, in 1859, led by olonel? Drake. Drake well was completed also in August 1859 at a depth of 69 feet (Brantley, 1971). Both wells were drilled using percussive cable drilling rigs, which was a rather slow and a potentially dangerous process because the rigs lacked the safety features common on modern drilling systems. However, within a year of the discovery of oil at Oil Creek, oil mania had struck and dozens of rigs were drilling wells in Pennsylvania.



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Imperial Russia was not far behind. Capitalizing on the vast natural oil pits at Baku, Russia was able to produce by 1870 27,500 cubic meters (168,000 bbl) of oil per year. Expansion of the industry was rapid in both Russia and the USA, and by 1871, 687,300 cubic meters (42,000,000 bbl) of oil per year (91% world production) was coming from the oil fields of Pennsylvania. Due to limited domestic demand and fierce competition from the Standard Oil Co., the Canadian industry languished and eventually perished. This was not the case in Russia. The Swedish Nobel Brothers rapidly developed the Russian oil industry with capital investment, technology, and the adoption of modern refining techniques, and by 1890 the annual production at Baku was more than 3,900,000 cubic meters (240,000,000 bbl) of oil per year, equaling the production of the United States (Brantley, 1971; Yergin, 1993).

Many significant events took place at the dawn of the twentieth century; perhaps the most significant of which was the invention of the internal combustion engine and the development of the automobile. Oil companies, such as Standard Oil, became ertically integrated,? through the control of exploration, exploitation, production, and distribution. With the creation of companies like Royal Dutch Shell, the oil industry also became an international enterprise.

The emergence of the ultinationals?The First World War was a true milestone for petroleum, especially concerning the economic and strategic importance of oil and gasoline. The First World War was the first mechanized war fought on a global scale. The rapid development of the car, the truck, armaments (e.g., the tank), and the airplane, all of which relied heavily on petroleum and derivatives, increased demand for oil and drove the economic fortunes of the oil industry. Those four years very rapidly transformed the oil industry and the way in which governments viewed oil, with governments realizing that in addition to its commercial importance, oil also had a strategic importance (Yergin, 1993).

Following the First World War and the break-up of the Standard Oil Company, the global exploration, production, and distribution of petroleum was dominated by seven large international corporations: British Petroleum, Royal Dutch Shell, Esso (Exxon), Gulf, Texaco, Mobil, and Socal (Chevron). These companies acquired true ultinational? status during the 1920s and 1930s through their various overseas operations. Exploration within North America continued, but was often overshadowed by the exploration and development of the oil fields of North Africa, the Middle East, Asia, and South America. With the creation of Corporate Centers and the establishment of Regional Centers of Operation within each foreign country, a complex network of corporate dependency was born that is still with us today! The formation of Aramco (Arabian-American Oil Co.) from Socal, Texaco, Mobil, and Exxon in the 1930s is significant because it gave both multinational corporations and the countries of the west a long-standing interest in the affairs of the Middle East, an interest that is still in evidence today.

The post-war period from the 1950s through to the mid 1980s was an era notable for several new developments. Exploration of many high-risk areas, such as the Alaskan Shelf, the North Sea, the East Coast of Canada, and the Gulf of Mexico for example all occurred during that time. Explorationists drilled deeper wells, drilled offshore in ever-increasing water depths, drilled highly geopressured formations, drilled deviated wells, employed enhanced recovery techniques, and drilled many high-risk wells that would have previously deemed unthinkable (e.g., Arctic). Wells were drilled often with very long periods of development between discovery and irst oil.? The reason was, in part, due to the establishment and activities of OPEC.

OPECOPEC (Organization of Petroleum Exporting Countries) was founded in 1960 at Baghdad and initially comprised of Iraq, Iran, Kuwait, Saudi Arabia, and Venezuela. However, OPEC was subsequently expanded to include Algeria, Dubai, Ecuador, Gabon, Indonesia, Libya, Nigeria, Qatar, and the United Arab Emirates. The criteria for membership was, and remains, that the exportation of crude oil is the main source of revenue for a potential member state, thereby excluding the U.S.A., Russia, the Ukraine, and Mexico!

OPEC primary objective was the appropriation of ational? assets and to control the price of crude oil to the advantage of member countries, whose predominant revenue was derived from the exportation of oil! Probably the most significant achievement of OPEC was, and remains, the control of individual members via production quotas and price stabilization. Cash-strapped member states have often threatened in the past to increase their individual output, thereby seeking to increase their own revenues. But the threat and ability of Saudi Arabia to flood the market with oil with the subsequent depression of the price of oil has held most member countries to line. Production quotas and the maintenance of the price of oil were two of OPEC successes during the 1970s. Several wars in the Middle East, and an increase in demand for oil in the west, helped increase the price of oil. Of course that spurred the exploration of igh riskigh cost? areas, like the North Sea, and the rapid development of many oil fields that are beyond OPEC immediate influence. This was to perhaps lessen the influence of OPEC, but not destroy it since the constant demand for oil within developed countries means a continued dependency on OPEC derived oil!



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Into the future

Some geologists are of the opinion that there will be little in the way of new ig? finds, suggesting that plays will probably become more elusive, smaller, more challenging, and more expensive with a higher element of risk! There will most certainly be an increase in the application of enhanced recovery techniques, especially in known or marginal fields by a variety of methods. Reservoir engineering and reservoir geology will become increasingly important as companies attempt to maximize their production. Dilling techniques, such as horizontal drilling, will come into greater use, especially since this form of exploitation/development increases the profitability of marginal pools. Already the industry has shown signs of diversification! Many companies are now involved in activities other than the exploration of conventional crude oil. The active exploration for natural gas began in the 1950s and 1960s, but in recent years has steadily gained a renewed level of importance, which now includes shale gas, coal bed methane, and enhanced coal bed methane development and the exploration of biogenenic gas pools. Other ancillary activities include energy diversification beyond petroleum, such as the research and pilot testing of CO2 sequestration into the earth and oceans.

The recent discoveries of gas hydrates off the western and northern coasts of North America and the development of deep gas plays off the Continental Shelf of Brazil and North America challenge us to constantly think outside the box. Perhaps more typically, we will re-evaluate old oil and gas fields using enhanced data management systems (Video 1), and new technology such as virtual reality (Video 2) to find passed-over oil or gas. Of all the activities related to the exploration and exploitation of natural gas, perhaps enhanced coal-bed methane will be the most sustainable activity in the near future! An examination of the global distribution of natural gas and the global distribution of coal reveal a telling story (Figure 3). The countries of Eastern Europe and the Middle East both account for more than 70% of all currently known reserves of natural gas. Eastern Europe has both a distribution system and a market close to hand (Western Europe) and the Middle East has only recently begun to export liquefied natural gas, predominantly to Asia. However, the greatest demand for natural gas occurs perhaps not in Europe or Japan but within North America, which has only 6% of the world share in natural gas but 26% of the world known coal reserves. This is reflected in coal-bed methane research and development, which is at a more advanced state within North America than anywhere else in the world (IEA, 2004).

There are many uncertainties and unknowns for the future. What will be the role of OPEC in the future? Will revenues diminish in the face of the Kyoto Accord? Will the demand by western countries and the rapid industrialization of China keep prices high? What will be the role of non-OPEC oil-producing countries and their state-owned companies? Will those companies spearhead new initiatives or be reduced to ineffectual industrial liabilities? How will rising prices affect the economies of the west? Will Governments be able to maintain the high level of taxation of gasoline and gas? Will the west experience yet

Global distribution of coalNorth

America

26%

Eastern

Europe

23%

South

America

1%

Western

Europe

12%

Middle East

0.2%

Africa

7%

Asia &

Australasia

31%

Global distribution of natural gas

S America

4%

N America

6%

Western

Europe

4%

Africa

7%

Middle East34%

Eastern Europe

38%

Asia &

Australasia7%

Figure 3. The global distribution of coal and natural gas by geographical region (Data source: IEA, 2004; http://www.iea.org/Textbase/stats/index.asp).

Video 1. Data management systems. From he Making of Oil,? (? 1997 Schlumberger, Ltd. used with permission).

Video 2. A virtual reality view of the subsurface. From he Making of Oil,? (? 1997 Schlumberger, Ltd. used with permission).



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another oil-induced recession, or will the high price of oil spur the development of energy alternatives. These are important questions especially with government deficits rising. How will the major multi-national companies operate in the next century? Will it be amalgamation, diversification, increased development, or extinction as new technologies are developed and evolve? Do recent or past trends give some indication? One thing is certain, the 21st Century will not be a repeat of the 20th Century.

The economics and business of oil

Economics

Profit/loss The economic viability of any oil or gas company can be simply expressed by the following equation (Rose and Thompson, 1992):

Profit (or loss) = Revenue ? Costs (1)

However, the reality of modern business practice renders this simple equation inadequate. For example, the existence of multiple levels of taxation and varying types of taxation, complex tax provisions (i.e., write-offs), and modern accounting methods complicate the financial side of the business. Oil companies are also significant employers of skilled personnel and for all employers there are variable overheads and maintenance costs to meet, which typically rise with time. Furthermore, modern petroleum ventures typically involve the long-term investment of capital many years before the generation of revenue, and probably longer before the generation of profit (Figure 4).

Profits are not received like lottery-ticket windfalls, in a lump sum, or even in predictable installments! The price of oil is determined by arket forces? andis highly variable. However, the moment in time when ventures start to generate a profit depends upon many factors. Generally, onshore oil or gas wells begin to generate profit within a year; offshore the duration can vary from 3 to 4 years or more. Unlike onshore production, offshore exploration wells are typically not used for production. Production is controlled via substantial purpose-built production platforms, which delays 'first oil' and increases the capital investment. As the two curves in Figure 4 convey, all successful ventures require capital at the onset (hence, negative cash-flow) but should, in time, be cash generating (positive cash-flow).

Net revenue interest

In reality, producers pay 100% of the costs, but receive a reduced proportion (e.g., 70 to 85%) of the revenue from production, which is known as the net revenue interest (NRI).

Profit/loss = [(NRI x reserves x wellhead price) - wellhead taxes - operating costs - govt. taxes - investment]

Within this equation there is uncertainty concerning all of the factors except the NRI. Such uncertainties include or could relate to:

Reserves: e.g., revised subsurface interpretations, premature atering-out?

Wellhead price: e.g., the price of oil is highly variable (e.g., crash of 1986)

Wellhead taxes: e.g., politics and royalties driven by the perception of profit

Operating costs: e.g., cost of infrastructure and recovery costs

Government taxes: e.g., a change in fiscal policy due to change in government

Investment: e.g., loan repayment terms

Force Majauer e.g., war or natural disaster

Figure 4. Example cash-flow streams for two hypothetical wells:

onshore (-----) and offshore (-----). NCF = net cash flow. Note the

time difference at which profits are received.



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It is the collective responsibility of all professionals to estimate accurately the magnitude of reserves, production rates, and costs, and to reduce the level of uncertainty (i.e., risk). Estimates and uncertainty levels must be conveyed to upper management accurately and with a degree of consistency because capital budgeting and the exploration of an oil/gas prospect is a long-term commitment. This is especially true in the case of large offshore prospects, in which case the time between discovery and the production of irst-oil? (i.e., revenue generating) can be considerable. For example, the Hibernia oil field off the East Coast of Canada was initially discovered in 1979? 980 but the development of the field required the commitment of many large corporations throughout a period of 15 years and the investment of hundreds of millions of dollars. The decision to continue with any play is constantly monitored (Figure 5) and always subject to numerous levels of scrutiny. New prospects are typically supported by established production. It should also be apparent that producing wells should not only support their own costs and overheads of the operating oil company but also provide revenue to support ongoing capital- intensive exploration programs. Each oil or gas production unit goes through a ife cycle? (Jahn et al., 1998) and skillful managers will seek to overlap the life cycle of each production unit, using the revenue of existing mature fields to support new prospects.

The life cycle of an oil or gas field

Introduction As discussed in the previous section, exploration geologists have been searching for oil for more than a century. Unlike the early part of the 20th Century, when the time between discovery and irst oil? may have been short, the development of some oil and gas fields have lead times of 10? 0 years or more. Furthermore, the period during which the revenue of a producing unit attains a maximal lateau? (Figure 6) varies considerably. For example, the oil and gas fields of the North Sea, which have been producing for some 25 to 30 years, may go into decline in the near future. There are some fields, such as those within the Williston Basin and those in Texas, that would have been in serious decline were it not for the recent injection of capital and the utilization of new tertiary recovery methods. Like many natural phenomenon, oil and gas fields have a ife cycle.? If prospective, they are initiated, production grows (youth), eventually reaches a plateau (matures), subsequently declines (old age), and they are subsequently decommissioned (Figure 6).

The exploration phase Exploration remains a high-risk venture, despite the development of excellent tools, such as 3-D Seismic and a growing wealth of information. Why? Simply because plays are becoming increasingly subtle, expensive, or smaller. If we include unknowns such as a volatile stock market, politics, complex tax and environmental regulations, the decision to develop a play remains solidly a business decision. The play must have the potential for commercial success. Ideas have to be worked, from initial inception through to prospect evaluation, supported by fieldwork (if possible) and various subsurface reconnaissance

Figure 5. A hypothetical sequence of posible activities and business decisions during the evolution of an exploration play (after Jahn et al., 1998; with permission from Elsevier).

Figure 6. A graphical representation of the roduction Phase?within the Life Cycle and Business Model for a hypothetical oil orgas field (after Jahn et al., 1998; with permission from Elsevier).



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(geophysical) techniques. The acquisition of seismic is costly, especially offshore where projects and rising costs can easily spiral out of control. The culmination of the exploration phase is the commitment, by management, to the drilling of the very first well, which in an unproven area is known as the ildcat well.?

Appraisal phase Once the initial well has been drilled, logged and tested, a decision must be made. If the well is non-productive or water wet the question must be asked, should both the well and play be abandoned? Or, is a second well justified in the light of new geological information if the seismic data has been re-interpreted. If potential is still perceived, is the risk so great that partners must be found?

Alternatively, if hydrocarbons are encountered, the process of evaluation may intensify because the potential of the discovery must be quickly determined. If hydrocarbons are encountered and the prospects look good, management must decide to:

Immediately proceed with (early) development and hasten the onset of irst oil?and early revenue,

or

conduct an appraisal program and delay revenue generation.

Early development The early development and irst oil? generates income within a short period of time; however, the production and distribution facilities (i.e., infrastructure) may, in time, be inadequate if at some later date the eventual field becomes much larger than initially thought. This situation limits the production and can affect the ultimate profitability of the field.

Appraisal program In contrast, the appraisal program may delay the onset of irst oil,?but may be technologically superior and lengthen the life span of the field. Appraisal is more concerned with reducing uncertainties,rather than finding more oil or gas! However, even during production, appraisal is on-going and the viability of the field is constantly monitored (Video 3). For example, many low production wells (less than 1.5 m3 per day) in North America are sub-economic when the price of oil goes below $12 per barrel. Also, woe is the company that hastens a project that requires oil at $27 per barrel, then once irst oil? comes on stream the price drops to $15 barrel!

Also during the appraisal the economic viability of the field must be evaluated! There must be a market, either in place or in development, to justify production. The need for infrastructure to facilitate the development of the field must be planned, which if not already in place must be factored into the overall cost of development. For example, it is unlikely that the gas fields of the North Sea or the Canadian Scotian Shelf would have been developed for a small local market of 1 to 2 million people. The proximity of the United Kingdom and Europe easily justified the development of the North Sea, and similarly the presence of the U.S. eastern seaboard creates a huge potential market for the Scotian Shelf gas fields!

Development planning Depending upon the outcome of the ppraisal phase? and associated easibility studies,? if the field is economically viable a development plan will be formulated. The principle goal at this stage is to determine the optimum (i.e., most cost-effective) means of exploiting the field. This includes the subsurface optimization for effective drainage and the necessary surface facilities required for distribution. The culmination of this activity may be the creation of a Field Development Plan and Budget. Once the Field Development Plan and Budget are in place the facilities have to be designed, constructed, installed, and commissioned.

Production phase The commercial production of irst oil? through the wellhead marks the beginning of the production phase. Economically, this is an important point in the life-cycle of the field, since revenue is now being generated that can be used to pay back investors, or fund other new projects. Every business plan seeks to minimize the time between discovery and irst oil.?

Video 3. Appraisal. From he Making of Oil,? (?1997 Schlumberger, Ltd. used with permission).



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Production is largely controlled by reservoir characteristics, the means of recovery, and infrastructure. All this is embodied in a Production Profile, which outlines the facilities required, the number of wells required for effective drainage, and their phasing during production. Maintenance of the field is also a significant part of the production profile. There are three components to the production phase.

Build-up Recently drilled producing wells are brought on stream.

Plateau Older wells begin to decline while new wells are brought on stream. Production is at a constant rate.

Decline This is the final component of production, during which revenue from all producing wells gradually declines.

Decommissioning phase Once the net cash flow of a field turns permanently negative, the field no longer remains economically viable and must be decommissioned. This point in the life cycle occurs when the gross income from the field no longer covers operating costs plus royalties and taxes. There are many examples in Texas and the Williston Basin, however, where fields or wells that had produced during the 1950s and 1960s and subsequently decommissioned, regained life through the application of horizontal drilling, the use of surfactants and more recently, the application of CO2 injection techniques. This example illustrates one of the possible management decisions that must occur at this point. Should the well or field be abandoned (hence decommissioned) or can enhanced recovery techniques prolong profitability. This decision will, again, be driven by economics; the capital costs of enhanced recovery versus the price of oil! For offshore fields (e.g., Norwegian Arctic) the costs may be too great, whereas onshore (e.g., Texas) the costs are significantly less.

Decommissioning costs will also vary depending upon local and national (or international when offshore) legislation and environmental concerns. It is unacceptable to simply abandon a field and facilities, typically wells have to be illed? and sealed and all surface facilities removed. This final phase incurs costs with no revenue from the field. The field has become a financial liability.

References

Andrews, E. B., 1861, Rock oil, its geological relations and distribution: Am. J. Sci., ser. 2, v. 32, p. 85-93.

Atkinson, N., 2004, The International Crude Oil Market Handbook: Energy Intelligence Research (online): http://www.energyintel.com/Research.asp.

Beaudrow, A., J. Piitz, and T. Auranen, 2001, Black gold: Canada oil heritage, Canada Digital Collections, Industry Canada: http://collections.ic.gc.ca/blackgold.

Brantly, J. E., 1971, History of oil well drilling, Gulf Publishing Co., Houston, Texas, 1525 p.

Hedberg, H. D., 1971, Petroleum and progress in geology, 24th William Smith Lecture: J. Geol. Soc. London v. 127, p. 3-16.

Hunt, T. S., 1861, Notes on the history of petroleum or rock oil: Canadian Naturalist, v. 6, p. 241-255.

Illing, V. C., 1942, Geology applied to petroleum: Proc. Geol. Assoc., v. 53, p. 156-187.

International Energy Agency (IEA), 2004, Oil information: IEA Statistics, International Energy Agency, London, 734 p., IEA statistics online: http://www.iea.org/dbtw-wpd/Textbase/stats/oilresult.asp.

Jahn, F., M. Cook, and M. Graham, 1998, Hydrocarbon exploration and production: Elsevier, Amsterdam, 384 p.

Rose, P. R., and R. S. Thompson, 1992, Part 2. Economics and risk assessment in Development Geology Reference Manual (M. Morton-Thompson and A. M. Woods, eds.): AAPG Methods in Exploration 10, AAPG, p. 23-56.

Schlumberger, 1997, he Making of Oil, Plankton to Production:? Schlumberger Limited, Sugarland, Texas.

Yergin, D., 1993, The Prize: The Epic Quest for Oil, Money, and Power: Touchstone Books, 880 p.


Chapter 2Petroleum: Composition and Characterization

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Composition

Elemental composition

The word petroleum is derived by combining the Latin words petra and oleum, which mean rock and oil respectively. Petroleum, like the source material kerogen, is predominantly comprised of organic compounds containing principally the elements hydrogen and carbon. Table 1 shows the approximate elemental composition for natural gas, oil, asphalt, different kerogen types, and two coals. Note that the relative proportion of carbon and hydrogen is greater for gas and oil as compared to kerogen, and that the relative proportion of oxygen decreases as the hydrogen content increases! The most fundamental characteristic of kerogen is hydrogen content! A high hydrogen-bearing kerogen (e.g., 10 wt. %) has a greater potential to generate oil and gas than kerogen with a low-hydrogen content (e.g., 4 wt. % hydrogen). Also because hydrogen is the lightest element, oils with higher hydrogen content have a lower specific gravity. The significance of specific gravity as a means of characterizing crude oil is discussed later.

Molecular composition

Hydrocarbon and non-hydrocarbon Petroleum contains a wide variety of molecular structures and compounds; the smallest molecule is methane (molecular weight = 16) and the largest are the asphaltene compounds (m.w. 1,000 +). Between these two extremes are hundreds of molecular structures and compounds that are grouped depending upon structural form, chemical affinity, chemical and physical properties, and means of isolation (Figure 7). For example the alkane group, comprised of open-chained molecules with single bonds between each carbon atom, form a homologous series that can be readily separated from oil using liquid chromatography. The unifying feature for all hydrocarbon groups is the presence of an atomic skeleton comprised of carbon plus hydrogen. However, if the molecular structure contains elements other than carbon and hydrogen (e.g., oxygen) then that compound is a non-hydrocarbon because it contains a heteroatom.Such structures are informally known as NSO if they contain the elements nitrogen, sulfur and

Figure 7. Fractions within crude oil (from Tissot and Welte, 1984;reprinted with kind permission of Springer Science and Business Media).

Table 1. Approximate elemental composition (in wt. %) of selected organic matter (after Hunt, 1979, 1996).

Element Gas Oil Asphalt Kerogen (immature) Coal

Type I Type II Type II Lignite Bituminous

Carbon 76.0 84.5 84.0 76.0 72.6 72.7 68.0 83.0 Hydrogen 24.0 13.0 10.0 9.4 7.9 6.0 5.0 5.0 Oxygen 0.0 0.5 2.0 8.8 12.4 19.0 22.0 8.0 Sulfur 0.0 1.5 3.0 3.8 4.9 0.0 2.0 2.0 Nitrogen 0.0 0.5 1.0 2.0 2.1 2.3 2.5 1.0 (Trace elements) 0.0 0.0 0.1 0.5 0.0 0.1 0.0 h i g h l y v a r i a b l e



11

oxygen (NSO) within their molecular structure. The presence of NSO-bearing molecular structures within a crude oil can be very significant because NSO-structures can determine the character and reactivity of a crude oil. Typically NSO-bearing compounds are associated with heavy crude oils and oils of high specific gravity and low API gravity (e.g., 10 to 15 API? . Some NSO-bearing structures, such as the resins and asphaltenes, have a very high molecular weight (e.g., m.w. = 600+) and can account for 10 to 40% of all compounds within some heavy, degraded crude oils.

Some crude oils, such as the Boscan crude from Venezuela, contain metal elements (Figure 8) such as vanadium (V), nickel (Ni) and iron (Fe). Metal elements are typically incorporated as metal chelate complexes, which are molecular structures that contain a trace element surrounded by a closed ring or a hydrocarbon framework (e.g., porphyrin). Because many trace elements have an undesirable catalytic potential in fuels and during late stage refining process; they are removed during the refining or upgrading process.

Generally, as the relative proportion of resins and asphaltenes (i.e., NSO-bearing compounds) increase within a crude oil, so the proportion of trace elements increases. Metal and trace element content is invariably the highest in naturally degraded oils (e.g., Venezeula Boscan crude and the heavy oils of Alberta and Saskatchewan, Canada). However, the presence of certain trace elements (e.g., vanadium) can enhance the economic worth of a given crude, if the trace element(s) can be economically recovered!

Saturated hydrocarbons

Alkanes (paraffins)

Hydrocarbons that have a carbon skeleton in which carbon is bound to other atoms of carbon or hydrogen by single bonds are saturated compounds and commonly known as alkanes, saturated hydrocarbons, or paraffins. If the carbon skeleton is arranged linearly then the structure is a normal alkane (nalkane). If there are branches subtending from the main structure, then the structure is an isomer and known as a branched alkane or iso-alkane. All alkanes have the empirical formula CnH2 n+2. The first four members of the alkane group (methane, ethane, propane, and butane) are gases, whereas compounds above C16H34 are solid at STP (Standard Temperature and Pressure

1). Alkanes are insoluble in water but soluble in organic solvents such as chloroform and benzene. There are various ways of reporting alkanes. Alkanes can be referred to by their name or by reference to the number of carbon atoms within the structure, for example: the compound C4H10 which is normalButane, can be reported as nButane, as C4H10, or simply as C4. Generally, for compounds of small molecular size we typically use the name (e.g., methane), whereas the larger compounds (e.g., hexadecane) are often referred to using their carbon number (e.g., C16). There are also a number of ways of graphically showing the spatial arrangement of the carbon and hydrogen atoms within a given alkane. To go to an example click on the following link (alkane).

Isomers

Isomers are alkanes that have the same empirical formula as their normal alkane counterparts, but have molecular branches. As molecular size increases, so does the number of possible molecular variants, each differing in the spatial arrangement of their branches. For example, Butane (C4) has only one isomer, Pentane (C5) has three, Heptane (C7) has nine and C30 has an unbelievable 4,000,000,000 + isomers! The terminology for naming isomers has changed throughout the last few years and an example is given that follows the (new) UPAC convention (isomer).

1

STP = 760 mm Hg or 101 kPa, 60oF or 15.6oC

Figure 8. A cross-plot of Ni vs. V contained within numerous crude oils (from Tissot and Welte, 1984; reprinted with kind permission of Springer Science and Business Media).



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Cyclic alkanes (naphthenes)

Naphthenic hydrocarbons represent one of most common constituents of conventional crude oil. Naphthenic hydrocarbons are saturated ring-based structures and have 2 hydrogen atoms less than straight chain nalkanes equivalents (e.g., cyclopentane, Figure 9) and have an empirical formula of CnH2n. Naphthenic compounds consists of rings of either 6 or 5 bonded carbon atoms and typically the number of rings within a structure increases with an increase in carbon number as illustrated in Figure 9.

The naphthenes shown in Figure 9, appear as flat two-dimensional structures; in reality such structures are not flat. The spatial arrangement (i.e., stereochemistry) of ring-based structures is extensively used by petroleum geochemists to identify and recognize il families,? conduct oil to source correlations, derive the maturity of oils, and determine the origin and depositional environment of reservoired oils. The hydrocarbons that are used in this way are collectively known as biomarkers or geochemical fossils and the form of analysis is generally known as biomarker analysis (Peters and Moldowan, 1993; Peters

et al., 2004).

Unsaturated hydrocarbons

AlkenesAlthough alkenes can be generated during laboratory pyrolysis experiments, straight chain unsaturated hydrocarbons are rare in nature partly because they are very reactive. They will not be discussed further.

Aromatics Carbon is capable of forming compounds by bonding to other carbon atoms. Aromatic hydrocarbons are molecular structures consisting of six-member rings of carbon, bearing alternate double and single bonds. The double bonds are very stable, and the basic structure of this compound class is the benzene ring, which has a general formula CnHn. Since the exact location of the double bonds within an aromatic structure are unknown for a given instant in time, a circle within the six-member ring is often used to represent the presence of double bonds (Figure 10). Aromatic hydrocarbons are liquid at STP and often occur as relatively minor constituents within light oils, but generally increase in abundance with decreasing PI. Aromatic compounds of increasing structural complexity are typically and informally grouped according to the number of aromatic rings within a given structure consisting of mono-aromatics (single ring), di-aromatics (two), tri-aromatics (three) up to, and including, polycyclic-aromatic. The structure in Figure 11 is the di-aromatic compound C19 Alkyltetrahydro-phenanthrene.

Figure 9. Example Napthenic compounds.

Figure 10. Three 2-dimensional alternative methods of portraying benzene.

Figure 11. A di-aromatic (alkyltetrahydro-phenanthrene).



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Physical states of petroleum

Introduction

Petroleum is a complex mixture of various compounds; in the previous section we examined the chemical nature of those compounds according to molecular group. In this section, the various constituents of petroleum will be examined according to their physical state; i.e., either gaseous, liquid, or ?plastic?states at STP.

Gas

Natural gas at the wellhead may include both hydrocarbon and non-hydrocarbon gases; such as nitrogen, carbon dioxide, and hydrogen sulfide. Hydrocarbon gases are gases that do not condense at 20oC and at atmospheric pressure (Patm), such as methane (C1), ethane (C2), propane (C3) through to n-butane (nC4), see Table 2.

Dry gas is a natural gas, comprised predominantly of methane (i.e., methane = 96% +), or where the C2:C1 ratio is greater than 10-6:1. If the proportion of ethane exceeds 4 to 5% of the natural gas total, then the natural gas is called wet gas. At the earth surface, where pressures and temperatures are significantly lower than those encountered in the reservoir, low molecular weight gases (i.e., C5 to C7) may condense, forming a liquid known as condensate. Condensates typically have API gravities that range between 45? to 62? and vary in color from clear to yellow or whitish-blue!

These gases should not be confused with other gas liquids such as Liquefied Natural Gas (LNG), which is methane liquefied at -160? C and Patm, andLiquefied Petroleum Gases (LPG) which is liquefied propane or butane. LNG and LPG are refinery and industrial products, whereas condensate and wet gas are complex mixtures of natural gas in the natural state.

olid gases? can also occur when a gas (e.g., methane) is both water wet and frozen. Gas hydrates (Figure 12) form via clathration when gas molecules such as methane, ethane, or iso-butane become entrapped within the lattice-like structure of ice. Approximately 1.0 m3 of gas hydrate may hold 50 to 170 m3 of natural gas, making gas hydrates very prospective!

Liquid and lastic?states

LiquidThis of course includes crude oils. Crude oil has been defined (SPE/WPC/AAPG/SPEE, 2006, p. 46) as thatportion of petroleum that exists in the liquid phase in natural underground reservoirs and remains liquid at atmospheric conditions of pressure and temperature,? noting also that crude oil may include small amounts of non-hydrocarbon. There is a wide variety of crude oils, that exhibit a range of specific gravities, sulfur content, pour point, cloud point, and molecular composition; we will examine these characteristics in a following section.

Figure 12. Samples of gas hydrate readily burn with a yellow-orange flame (image courtesy of NOAA): http://www.oceanexplorer.noaa.gov.

Table 2. Significant data of low molecular weight hydrocarbons (after Hunt, 1979, 1996; Tissot and Welte, 1984; and others).

Name Formula Mol. wt. Boiling point Solubility ( Patm) (g 10? g water)

Methane CH4 16.04 -162 24.4

Ethane C2H6 30.07 -89 60.4

Propane C3H8 44.09 -42 62.4

Isobutane C4H10 58.12 -12 48.9

n-Butane C4H10 58.12 -1 61.4

Isopentane C5H12 72.15 30 47.8



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Plastic statePetroleum in the plastic to solid state includes a variety of high molecular weight substances generally known as bitumen, asphalt, and resin. Bitumen is a broad class of natural substances that exhibit a great deal of compositional variation and as a consequence vary in their ardness? and degree of volatility. Bitumen is composed principally of hydrocarbons, but also contains a variable amount of non-hydrocarbon (i.e., NSO) compounds. Bitumen can also be a solid, plastic, or semi-liquid at STP. Bitumen is often considered as a compositional intermediate between crude oil and kerogen and is typically associated with kerogen and petroleum generation. Pyrobitumen is a specific type of bitumen and has many examples, such as Albertite, Wurtzilite, and Impsonite. Pyrobitumens are often hard, solid, and possess a molecular structure that is polycyclic and highly graphitic (Figure 13), that is they have a discernible molecular order that is detectable by X-ray diffraction and create an optical texture in crossed polarized reflected white light microscopy.

Resins represent a residuum that is insoluble in liquid propane but soluble in n-pentane, whereas asphaltenes are natural substances defined on the basis of solubility and represent a class of compounds that are soluble in carbon disulfide but insoluble in chilled n-pentane. Asphaltenes have a very high molecular weight and are agglomerations of molecules containing condensed aromatic and naphthenic rings linked by alkanes (paraffins). The recipitation? of asphaltenes during the production of heavy or degraded oil is a common problem.

Finally, do not confuse bitumen, asphaltenes, or resins with refinery by-products such as asphalt, which includes either straight-run residues or the oxidation products of crude oil residuum. Asphalt typically contains heavy oils, resins, asphaltenes, and other high-molecular-weight waxes.

The classification of crude oil

The need to classify

During processing, petroleum may yield a range of distillate hydrocarbon groups, which may include: gasoline and naphtha, containing 4 to 10 carbon atoms; kerosene and illuminating oils, with 11 to 13 carbon atoms; diesel and light gas oils, containing 14 to 18 carbon atoms; heavy gas oils, home heating oils, with 19 to 25 carbon atoms; lubricating oils, containing 26 to 40 carbon atoms; and residual heavy fuel oils, with 40 or more carbon atoms (Hunt, 1996).

The composition and character of crude oil can and does vary from sedimentary basin to basin, within a sedimentary basin, or from pool to pool. Crude oil properties, such as color, viscosity, smell etc., vary due to differences in composition, reservoir depth, the maturity and nature of the source material, and subsequent post emplacement changes. Therefore, the type and range of distillation products that can be derived from crude oil will vary from crude to crude. Hence the economic worth of crude oil is in part determined by the type and range of products derived during distillation and refining. Furthermore, because crude oil is an internationally traded resource we require various means of comparing and distinguishing between various crude oils. There are a number of properties that are used to classify and distinguish differing crude oils, and these depend to some extent upon the purpose of classification (i.e., geological, scientific, commercial, etc.).

There are 161 different internationally traded crude oils (Atkinson, 2004) traded through the International Petroleum Exchange or the New York Mercantile Exchange. Because differing crude oils can vary in composition, buyers and sellers have found it easier to refer to a limited number of reference, or benchmark, crude oils, against which other crude oils are compared for the determination of value. There are two benchmark crude oils in the United States, the West Texas Intermediate (38? to 40? API and 0.3% sulfur) and the West Texas Sour (33? API and 1.6% sulfur). The North Sea benchmark crude oil is the Brent crude (38? API and 0.3% sulfur), whereas the Asian and Middle East benchmark crude oil is the Dubai crude oil (31? API and 2.0% sulfur). Another benchmark used by OPEC, known as the PEC basket,? is an average of seven crude oils that includes Algeria Saharan Blend, Indonesia Minas,Nigeria Bonny Light, Saudi Arabia Arab Light, Dubai Fateh, Venezuela Tia Juana Light, and Mexico Isthmus(a non-OPEC crude oil). OPEC uses the price of this basket to monitor world oil market conditions.

Figure 13. Pyrobitumen as seen in reflected light under crossed polarized light (image courtesy of L. Stasiuk).



15

PI gravity The density of a crude oil forms the basis for a common means of distinguishing between various crude oils. Crude oil is typically lighter than water and therefore the density of crude oil can be simply determined by a hygrometer! However, density varies with temperature and in the United States, the density of oil is defined by the American Petroleum Institute (API), 2007, in terms of gravity units (PI), according to the following formula:

The determination of density under standardized conditions is critical since PI gravity determinations are only comparable if they are conducted at 60 degrees Fahrenheit, or 15.5 degrees Celsius. Water has an PI of 10, whereas the PI of crude oil varies from 5 to 55PI. Light oils have PI gravities between 35 to 45, medium oils range in PI from 25 to 35, and heavy oils have an PI gravity below 25. As stated earlier, because hydrogen is the lightest element, oils with high hydrogen content have a lower specific gravity, for example:

Penn. crude (hydrogen = 14.2%) s.g. = 0.862 (33? API)

Coalinga crude (hydrogen = 11.7%) s.g. = 0.951 (17? API)

Also note that PI gravity units are inversely proportional to specific gravity. Light oils (e.g., 40? to 50? API) that have relatively high hydrogen content have a specific gravity of 0.83 and generally a low viscosity. In contrast, heavy oils, containing relatively less hydrogen, have PI gravities less than 15? a specific gravity approaching 1.0, and a generally high viscosity.

Sulfur content (sweet and sour) When sulfur-bearing fossil fuels are burned, oxides of sulfur are formed (e.g., SO2) and sulfur dioxide in particular is a pollutant and known to form acid rain. If a crude oil contains sulfur, it must therefore be removed at the refinery. Crude oils are consequently classified as weet? or our? based on their sulfur content. Sweet crude oils, such as the West Texas Intermediate and Brent crude, have a sulfur content less than 1.0 wt %. In contrast sour crude oils, such as the West Texas Sour and Dubai crude, have a sulfur content of more than 1.0 wt %. Most of the sulfur in crude oil exists as heteroatoms.

Pour point All normal crude oils contain alkanes (molecular composition) that are commonly referred to as paraffins. High-molecular-weight, straight-chain paraffins with between 20 to 30 carbon atoms are generally known as axes,? that is, they are solid at STP but remain in liquid form at the elevated temperatures and pressures found within a reservoir. When present, paraffin waxes can solidify when a waxy crude oil is brought to the surface due to a decrease in temperature and pressure. The waxes are characterized by a clearly defined crystal structure (Figure 14) and have the tendency to be hard and brittle. Because waxes can create production problems due to their tendency to solidify at STP, the wax content of an oil is often determined. The pour point and cloud point of a crude oil are rule-of- thumb guides as to the wax (paraffin) content of oil and the tendency of those waxes to solidify.

The lowest temperature at which a crude oil will pour before it forms a olid? is referred to as the pour point. Most crude oils exhibit pour points between +52? C to -60? C (+125? F to -75? F). Pour point is determined by heating a sample of crude oil within a tube at a temperature of 46? C (115? F) to dissolve the wax. The tube is then cooled in a water bath that is approximately 11? C (20? F) below the estimated pour point (ASTM D5853-95). The temperature at which the oil will not flow is the pour point. Cloud point is the temperature at which the oil first appears cloudy as the wax begins to form. Cloud points are approximately 2? C (4? F) higher than the pour point. The methodology for determining cloud point is set by ASTM D2500 (http://www.astm.org).

Figure 14. Atomic Force Microscope image of a paraffin wax crystal (C36H74), measuring 14 microns along the base (image by R. Williamson; SPM Group Bristol image courtesy of DoITPoMS Cambridge).



16

Units of measurement

Crude oil There are two universally accepted volumetric units of measurement for crude oil. The unit of measurement generally used within the United States (often called an nglish Unit? is the barrel (bbl). One barrel holds 42 U.S. gallons or 34.97 Imperial gallons. Countries using the metric system use the cubic meter (m3). One cubic meter of oil is equal to 6.29 bbl. Alternatively, metric tons are often used when crude oil is shipped from place to place. However, the volume of a metric ton varies with PI gravity and temperature.

Gas The preferred unit of measurement for natural gas in the United States is a cubic foot (cf). However, gas volumes vary with temperature and pressure, therefore the unit of measurement is referenced to standard conditions (15? C and 101.325 kPa, or 60? F and 14.65 psi). The referenced unit is known as standard cubic feet (scf). Because gas volumes in reservoirs can be large, units are abbreviated thus: Mcf (thousand cf), MMcf (million cf), Bcf (billion cf) and Tcf (trillion cf). Under the metric system, the volume of gas is given in cubic meters (m3). One cubic meter is 35.315 scf.

Geochemical characterization

Broad composition

This is a straightforward scheme (Figures 15 and 16) based upon the proportion of paraffinic (normal and isoalkanes),naphthenic (cycloalkanes), aromatic, and NSO compounds present within an oil normalized to 100%, once opped? at 200? C to remove low molecular weight compounds. Although geologists do not commonly use this scheme, it is included here because it will help illustrate crude oil composition in the context of properties discussed above. Non-degraded or medium- to light-gravity crude oils can be referred to as either paraffin-based oil or napthenic-based oil, but more typically, non-degraded crude oils are classified as:

paraffinic oils, containing mostly normal and isoalkanes, and less than 1% sulfur

paraffinic-naphthenic oils, containing both linear- and cyclo-alkanes, and less than 1% sulfur

aromatic-intermediate oil, containing less than 50% saturated hydrocarbons, and usually more than 1% sulfur

However, crude oils altered in situ within the reservoir may exhibit a modified molecular composition. For example, the continued maturation (cooking) of crude oil within the reservoir (Figure 15) may result in a decrease in high-molecular weight compounds and a relative increase in low weight molecular compounds. In contrast, the in-situ

Figure 15. Ternary diagram showing the composition of six crude oils from 541 oil fields (from Tissot and Welte, 1984; reprinted with kind permission of Springer Science and Business Media).

Figure 16. A Ternary diagram showing the main trends of alteration and thermal maturation of crude oils (from Tissot and Welte, 1984; reprinted with kind permission of Springer Science and Business Media).



17

alteration of crude oil within the reservoir by oxidation or biodegradation (e.g., microbial degradation) is typically associated by a shift away from the paraffin pole, due to the relative loss in alkane content and a relative increase in poly-cyclic aromatic and NSO-bearing compounds (Figure 16).

A comparison of two oils A comparison of two oils will attempt to relate the significance of composition. Please refer to the two gas chromatograms in Figure 17. Chromatogram (A) represents the alkane fraction of a high-wax Indonesian crude oil whereas chromatogram (B) is a sample of Brent crude oil. Each chromatogram uns? left to right, with lower molecular weight compounds on the left and higher weight molecular compounds on the right. Each peak, or spike, represents an individual compound (for example C30); the height of each peak is indicative of the relative abundance of that compound within the crude oil. Even though the analyses were conducted under slightly different conditions, they are aligned so that two eference peaks? (indicated by the red arrows) lie above or below each other for comparison. You should notice that oil (A) has a much higher proportion of nalkanes in the C27 to C33 range compared to oil (B) whose nalkane distribution is skewed towards the lighter end (which is marked by *).

Here is the paradox; both oils are paraffin rich andhave a similar API gravity (~API 34? to 38? . However, the Indonesian crude has relatively low abundance of low molecular and a high proportion of C26 to C35 paraffins. Therefore, this oil is a igh wax?oil or a axy? oil. In contrast, the Brent crude oil has a relatively greater proportion of lower-molecular weight paraffins and naphthenes of 15-carbon atoms or less. Thus, the relatively high hydrogen content of the Indonesian crude is derived from the relatively higher wax content, whereas the Brent crude is associated with low-molecular weight paraffin and naphthene compounds. Although the two crude oils have similar API gravities, their pour point and cloud points are dissimilar. The Indonesian crude is almost solid at STP (standard temperature and pressure), with a pour point of +50? C (+120? F), because of the high wax content, whereas the Brent crude remains a liquid with a pour point of -3? C (+27? F). Furthermore, despite having similar gravities (API or S.G.), the variety and range of distillate fractions derived through refining will be markedly different. This simple comparison should indicate that the labeling of any crude oil by a single, simplistic characteristic such as API gravity can be misleading!

References

American Petroleum Institute, 2007: http://api-ec.api.org/Standards.

American Standards and Testing Materials (ATSM): http://www.astm.org/.

Atkinson, N., 2004, The International Crude Oil Market Handbook: Energy Intelligence Research (on-line): http://www.energyintel.com/Research.asp.

Hunt, J. M., 1979, Petroleum geochemistry and geology: Freeman and Co., San Francisco, 642 p.

Hunt, J. M., 1996, Petroleum geochemistry and geology 2nd Ed.: Freeman and Co., New York, 743 p.

SPE/WPC/AAPG/SPEE, 2006, Petroleum reserves and resources: classification, definitions and guidelines, DRAFT, September 2006, 60 p.

Peters, K. E., and J. M. Moldowan, 1993, The Biomarker Guide, Interpreting molecular fossils in petroleum and ancient sediments: Prentice Hall, 363 p.

Peters, K. E., C. W. Clifford, and J. M. Moldowan, 2004, The biomarker guide, 2nd ed., v. 1 and v. 2: Cambridge University Press, 1155 p.

Tissot, B., and D.H. Welte, 1984, Petroleum formation and occurrence: 2nd rev. ed.: Springer-Verlag, Berlin, 699 p.

Figure 17. A gas chromatogram (a.k.a. ?fingerprint?) of the alkane fraction of a high wax Indonesian crude (A) matched against a marine-sourced Brent crude oil (B). Note that the occurrence of reference compounds in each chromatogram is indicated (red arrows); also note that the Indonesian crude oil has a greater proportion of peaks around the C27 to C30range, whereas the Brent crude (A) oil has a significantly greater number of peaks at the C9 to C12 range (indicated *).


Chapter 3Petroleum: From Organism to Trap

18

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Sedimentary organic matter

Definitions and terms

The previous section ended with an examination of the molecular composition of petroleum, accompanied by definitions for various molecular components of petroleum. Therefore, before we examine the origin and generation of petroleum it is fitting that we begin by defining many of the terms that will be used throughout this section.

Source rock A petroleum source rock is generally recognized as a fine-grained sedimentary rock that has naturally generated and released enough hydrocarbons to form a commercial accumulation of oil and/or gas (Tissot and Welte, 1984).Implicit in this definition is that a source rock meets the following geochemical requirements (Peters and Cassa, 1994):

the source rock contains sufficient quantity of organic matter

the organic matter is of sufficient quality to generate oil and/or gas, and

the source rock attained a level of thermal maturity capable of generating and expelling hydrocarbons

The term potential source rock describes an organic-rich, fine-grained sedimentary rock that is not sufficiently mature to generate petroleum (i.e., oil), but under the right conditions could generate petroleum.

Kerogen Although not specifically mentioned in the definition of a source rock given above, the existence of kerogen is an implicit key characteristic of all source rocks. Kerogen is generally defined as sedimentary organic matter that is insoluble in common organic solvents and aqueous alkaline solvents (Tissot and Welt, 1984). On this basis, kerogen is rendered distinct from humic (organic) matter within soil because humin is soluble in aqueous alkaline solvents. Kerogen is distinguished from petroleum because common organic solvents are used to extract bitumen and oil from rock! The organic matter that is kerogen is commonly a mixture of different types of organic matter, the composition of which is largely dependent upon the composition of the original biologic precursor.

Macerals The term maceral was originally coined to describe the microscopic constituents of coal, that are recognizable under a microscope (Stopes, 1935), but has since been broadened to include all recognizable organic matter in sedimentary rocks (Figure 18). Generally, macerals represent the organic remnants of plant or animal matter and readily distinguishable by differences in morphology, various optical properties, and technological property (Bend, 1992; Taylor et al., 1998). Although macerals can be broadly distinguished by differences in chemistry and/or technological property, maceral identification and name designation is best achieved using a reflected light microscope (Figure 18).

Figure 18. Examples of macerals. (a and b) The macerals Alginite (A) and Fluorinite (F) are both autofluorescent under u.v. light. In these images Alginite (A) appears yellow to yellow-green, whereas the Fluorinite (F) appears a dull red-brown. (c) Under reflected white light, the med-grey maceral Telinite (T) has retained much of the original texture of the original plant material. Telinite (T) is in-filled by a darker-grey maceral known as Collinite (C). Images (a) and (b) are in reflected autofluorescent light and (c) in reflected white light.

Figure 18. Examples of macerals. (a and b) The macerals Alginite (A) and Fluorinite (F) are both autofluorescent under u.v. light. In these images Alginite (A) appears yellow to yellow-green, whereas the Fluorinite (F) appears a dull red-brown. (c) Under reflected white light, the med-grey maceral Telinite (T) has retained much of the original texture of the original plant material. Telinite (T) is in-filled by a darker-grey maceral known as Collinite (C). Images (a) and (b) are in reflected autofluorescent light and (c) in reflected white light.



19

The production and accumulation of organic matter

The carbon cycle The creation of a fossil fuel begins with the creation and accumulation of organic matter at the earth surface. Organic matter is defined as ?material comprised solely of organic molecules in monomeric or polymeric form, that are derived directly or indirectly from the organic part of organisms... deposited or preserved in sediments? (Tissot and Welte, 1984 p. 3). The production of organic matter starts with photosynthesis, with sunlight of course being the primary source of energy. The primary producers, such as photosynthetic bacteria and blue-green bacteria, are known as phototrophs because they use light (energy) to produce glucose.

h.v (energy)

6CO2 + 12H2O C6H12O6 + 6O2 + 6H2O

(674 kcal)

An equation for photosynthesis. Please note that oxygen is a by-product.

Phototrophic organisms are found on land or in the euphotic zone of the water column. Organisms that utilize carbon dioxide as their sole source of carbon are autotrophs, whereas those that derive their carbon from existing organic structures are known as heterotrophs; this is the basis of the food pyramid.

Welte (1972) estimated that the total amount of organic carbon produced within the biosphere is 6.4 x 1015 t. In contrast the global preservation of organic carbon within sediments is less than 0.1% of all organic carbon production. Therefore, the bulk of all organic carbon produced is either bound within inorganic sediments or recycled within the biosphere as carbon dioxide. Some carbon dioxide does escape from the major cycle (Figure 19) into isolated environments, but of all the organic carbon produced, approximately 0.1 to 0.01% becomes fossil fuel, which is indicated as a eakage? in Figure 19.

ProductionThere are two main factors that govern the creation and accumulation of organic matter in sediments (Demaison and Moore, 1980). They are the production of organic matter and organic matter preservation. Both are of equal importance, because both influence the amount of organic matter that occurs within a given potential source rock. However, without production, preservation becomes moot!

Biological activity within an aquatic environment (e.g., marine) is mainly controlled by sunlight, temperature, and the availability of nutrients, such as nitrates and phosphates. Therefore, the greatest level of biological production is concentrated in the upper 60 to 80 m of the water column, which is known as the euphotic zone.

The productivity of organic carbon (C org.) within coastal water, which averages approximately 100g C org ma-1, is about twice that of the open ocean (Tissot and Welte, 1984; Hunt, 1996). Continental margins that experience the phenomenon of up-welling (e.g., western South America) are especially productive, generating 300 g C org ma-1.However, most of the primary organic matter is either lost to the food chain or lost during sedimentation. The preservation of organic matter, therefore, plays a key role in the creation of a source rock.

Figure 19. A simplified organic carbon cycle (after Welte, 1972; Tissot and Welte, 1984; Hunt, 1996; and others).



20

Preservation Approximately 80% of all primary organic matter presently produced in the ocean is consumed (Menzel, 1974). The most effective consumers are zooplankton and aerobic microorganisms. It therefore follows, that the duration of time a given particle of organic matter spends suspended within oxygen-rich water has a direct impact upon the successful accumulation of organic matter within sediment. The preservation potential of organic matter can be enhanced by the adsorption of organic matter onto the surface of mineral particles, which effectively increases the mass of the organic matter, enabling it to sink faster.

However, the most effective means of attaining preservation is to decrease the amount of oxygen within the water column, or at the water/sediment interface. Depositional settings generally considered favorable for the production and preservation of organic matter are those in which bottom waters contain very little dissolved oxygen (Demaison and Moore, 1980). Such depositional environments are considered by Tyson and Pearson (1991) to include dysoxic (2.0 to 0.2 ml oxygen per liter water), suboxic (0.2 to 0.0 ml oxygen per liter water), and anoxic (0.0 ml oxygen per liter water). Within an oxygen-rich environment (>2.0 ml oxygen per liter water), aerobic bacteria utilize oxygen to degrade organic matter and generate the by-products carbon dioxide and water. In contrast, within an anoxic environment, anaerobic bacteria must acquire oxygen via a sulfate reduction process, which is a relatively slower process. Therefore, aerobic bacteria are much more efficient at consuming organic matter than their anaerobic counterparts, although it is important to note that the removal of organic matter does not cease under anoxic conditions, but occurs at a significantly slower rate; a rate that favors the preservation, rather than removal, of organic matter (Figure 20).

There are a number of reasons why anoxia may occur within the water column or sediment. The most common cause of anoxia is a respiratory demand for oxygen that is greater than the available amount of dissolved oxygen. In an open marine environment oxygen is constantly replenished; however, situations can arise that restrict the vertical exchange of water and promote the creation of anoxia (Figure 21). For example, within Lake Tanganyika, East Africa, the presence of a thermocline prevents the vertical mixing of water and the promotion of anoxic conditions at depth. Therefore, sediment deposited under anoxic conditions is associated with relatively higher organic matter content. The presence of sill at the entrance of the Black Sea (i.e., Bosporous, Figure 21) restricts the exchange of water, promoting the development of a halocline and anoxic conditions at depth (Demaison and Moore, 1980).

Figure 21. Two contemporary basins that are considered to be examples of an anoxic depositional setting. The water in Lake Tanganyika is stratified because of a permanent thermocline, whereas limited water exchange over a shallow sill has promoted the development of a permanent halocline in the Black Sea. The existence of a thermocline or halocline promotes anoxia within the water column (after Demaison and Moore, 1980).

Figure 20. The preservation potential of organic matter as related to the presence of oxic or anoxic bottom-water conditions. In the presence of free iron, the sulfate reduction process will promote the formation of pyrite, whereas in the absence of iron, hydrogen sulfide is produced (after Demaison and

Figure 20. The preservation potential of organic matter as related to the presence of oxic or anoxic bottom-water conditions. In the presence of free iron, the sulfate reduction process will promote the formation of pyrite, whereas in the absence of iron, hydrogen sulfide is produced (after Demaison and Moore, 1980).



21

The sedimentary environment and organic matter

Sediment permeability The mineralogy of the host sediment can also influence the preservation potential of organic matter (Figure 22). Clay-sized particles can adsorb organic matter (onto their surfaces) and are more readily coated with organic matter than coarse-grained siliciclastics. Also, clay particles are often transported further and deposited in low-energy environments. In contrast, sands are deposited in higher-energy environments; environments that are often associated with the presence of oxygenated water, higher sedimentation rates, and an abundance of aerobic micro-and macro-biota. The presence of any, or all, of these characteristics will conspire against the deposition and preservation of organic matter.

Sediment particle size is also important because the relative decrease in permeability associated with clay-sized particles restricts the exchange of oxygen-depleted water by oxygen-rich water (Figure 22). Whereas, the higher porosity and permeability of recently deposited sands enables oxygen rich waters to permeate the upper few meters of sediment, thereby promoting the removal of organic matter by scavenging metazoan (Figure 22). The existence of fine laminae within a fine-grained sedimentary rock is generally attributed to the presence anoxia within the depositional environment and the absence of bioturbation (Raiswell and Berner, 1985).

Carbonate rocks Carbonate rocks are interesting in that they can be both source and reservoir. Although bioherm and reef carbonates often make good reservoir rocks, they generally have diminished potential as source rocks because of the high rate of scavenging within those environments. The most favorable depositional environment for the creation of a carbonate source rock include environments that favor:

the formation of a halocline (water stratification) and anoxic conditions at depth

the growth of algal-rich sediments

Argillaceous rocks Rocks predominantly comprised of clay minerals (i.e., claystone, mudstone, and shale) are argillaceous. However, as discussed above, not all argillaceous rocks have source potential; generally, clay deposited under anoxic conditions possess the greatest potential (Figure 23). Argillaceous rocks that have the highest organic carbon content and the greatest generating potential may:

be very finely laminated due to the absence of bioturbation

contain pyrite (or some other sulfide)

be micro-fractured (possibly due to over pressuring)

have a high trace element/metal content (e.g., Mg2+, U4+, etc.)

contain the remnants of micro- and macro-biota (as either kerogen or skeletal remains)

be black to dark brown or dark gray, although Paleozoic source rocks typically deviate from this generalization.

Figure 22. Preservation potential due to lithology. A comparison between an argillite (top) and and? (bottom). Oxygenated water can penetrate the more open pore network of the sand promoting the removal of organic matter (from Tissot and Welte, 1984; reprinted with kind permission of Springer Science and Business Media).

Figure 23. An example of shale (cut perpendicular tobedding) in reflected white light. A itrinite particle? isindicated by V, a wisp of kerogen indicated by K, and atrail of generated hydrocarbons emanating from thekerogen is indicated by H. Width of image 250 microns.



22

The chemical composition of organic matter

The biological precursor The distribution of organic matter is not capricious. Living species form natural associations that reflect the habitat of a given environment. For example, the type of species that typify a fresh-water, terrestrially bound lake is markedly different from those that are found in a coastal-marine setting. Therefore, the type of organic matter within a potential source rock will vary according to depositional setting and the type of species that occur within that environment. The natural association of species within given environment gives rise to the concept of organic facies (Rogers, 1980; Jones, 1984). But before we examine the significance of organic facies, we need to examine the composition of organic matter.

Organic matter consists of various groups of molecular constituents: i.e., proteins, carbohydrates, lipids, and (in higher plants) lignin. However, significant differences in the relative proportion of each molecular group1 exist for various types of organic matter. For example, note the variation in protein content between terrestrial plants, such as Spruce wood and Scots pine, and marine zooplankton (Table 3). Similarly, the terrestrially derived examples contain lignin, which is absent in the other three examples.

Therefore, the chemical composition of organic matter within a source rock is determined by the type and variation of living precursor within a given depositional environment; which in turn are dependent upon a number of environmental factors. Living organisms within the marine realm are affected by light, temperature, the availability of nutrients and oxygen, and the presence of land barriers; whereas terrestrial habitats are influenced by climate, the type and availability of nutrients, and the availability oxygen (Tissot and Welte, 1984).

The factor of geological time is also relevant, due to the evolutionary development of species. Source rocks of the Lower Paleozoic (e.g., Cambrian and Ordovician), are typically devoid of organic matter derived from higher plants, since the diversification of vascular plants did not occur until the Devonian (Thomas and Spicer, 1986).

For example, the kukersites of Upper Ordovician age (Figure 24) within Estonia and North America (Hutton, 1987; Fowler and Douglas, 1984; Douglas et al., 1991) are dominated by the blue-green alga Gloeocapsomorpha prisca (Zalessky, 1917). Because these source rocks are of Upper Ordovician age, they do not contain terrestrially derived material such as spores, or the macerals cutinite and resinite, or macerals from the vitrinite group.

1 Proteins are highly ordered polymers made from individual amino acids and account for most of the N2 within an

organism. They can be broken down, either by enzymes or by hydrolyzation. Carbohydrates have a generalized formula of Cn(H2O)n and are essentially the hydrated forms of carbon (e.g., cellulose,

chitin, and mono-, and poly-saccharide). Higher plants contain high amounts of cellulose whereas algae and marine organisms are devoid of cellulose.

Lipids are water insoluble and include waxes, plant or animal oil and fats, oil-soluble pigments, terpenoids, and steroids. With respect to the formation of hydrocarbons, lipids are the most important group.

Lignin (and tannin) are complex 3-D aromatic molecules that give plants structural rigidity.

Figure 24. Kukersite of U. Ordovician age from the Williston Basin, Saskatchewan, Canada, containing G. prisca (G).

Table 3. The composition of living matter (examples) (data from Hunt, 1996).

Organic matter type Molecular group1

Proteins Carbohydrates Lipids Lignin

(wt. % ) (wt. % ) (wt. % ) (wt. % )

Spruce wood 1 66 4 29 Scots-pine needles 8 47 28 17 Phytoplankton 23 66 11 0 Diatoms 29 63 8 0 Zooplankton 60 22 18 0

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