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Chapter1—Introduction

Chapter 1—Introduction The development of petroleum geology The modern petroleum geologist Some maintain that there is no such thing as 憄etroleum geology,? there is only the science of geology applied in the search for petroleum; in which case this text ought to be entitled 慓eology as applied to Petroleum? in the style of Illing (1942)! Alternatively, a contemporary title such as 慞etroleum Systems Geology? emphasizes the highly integrative nature of petroleum exploration and exploitation! However, as a title, 慞etroleum Geology? conveys a 憂o-frills, meatand-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 憄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 憄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, 憄etroleum geologists? as such did not exist. Oil exploration theory was very rudimentary. In fact, most of the significant 憃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 慼ome-spun? methods! Legend has it that one fabled 憃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 慻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):

揟 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 搮 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 搮 at the anticlinal line are gas and oil springs? (p. 92) Andrews (1861).

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A

Figure 1. Anticlinal section on Cow Creek, Virginia. Oil and gas springs occur at the crest (A) (redrawn from Andrews, 1861).

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Chapter1—Introduction

Both Hunt and Andrews made significant steps towards defining a concept of how petroleum is retained in rock and in defining a 慻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 憄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 慸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 慳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 慳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 憇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 憌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 憈ypical? oil well in the Middle East produces more than 103 m3 of oil per day. This is in stark contrast to the 慳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抯oil, with Saudi Arabia, Iran, Iraq, and Kuwait producing over 50% of the world抯 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, 2

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Chapter1—Introduction

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).

Global distribution of conventional oil

Global distribution of natural gas

Middle East 64%

Asia & Australasia 7%

Middle East 34% Asia & Australasia 4%

Africa 7%

Africa 7% Western Europe 2%

South America 9%

North America 8%

Western Europe 4%

Eastern Europe 6%

S America 4%

N America 6%

Eastern Europe 38%

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 beginnings References 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 憃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 揢 ncle Billy? Smith and his sons, at Oil Creek in Pennsylvania, United States, in 1859, led by 慍olonel? Drake. Drake抯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. 3

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Chapter1—Introduction

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 憊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 慚 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 憁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 everincreasing 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 慺irst oil.? The reason was, in part, due to the establishment and activities of OPEC.

OPEC OPEC (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抯 primary objective was the appropriation of 憂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抯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 慼igh risk杊igh cost? areas, like the North Sea, and the rapid development of many oil fields that are beyond OPEC抯 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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Chapter1—Introduction

Into the future Some geologists are of the opinion that there will be little in the way of new 慴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.

Eastern Europe 23%

Global distribution of coal

Global distribution of natural gas

North America 26% South America 1%

Asia & Australasia 31%

Middle East 0.2%

Asia & Australasia 7%

Middle East 34%

Africa 7% Western Europe 4%

Western Africa Europe 7% 12%

S America 4%

N America 6%

Eastern Europe 38%

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 ).

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 reevaluate 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抯 share in natural gas but 26% of the world抯 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 5

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

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

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Chapter1—Introduction

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 憁 arket forces? and is 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).

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.

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]

(2)

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 憌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 6

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Chapter1—Introduction

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 慺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 capitalintensive exploration programs. Each oil or gas production unit goes through a 憀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 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). 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 慺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 憄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 憀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 Figure 6. A graphical representation of the 慞roduction Phase? must have the potential for commercial success. Ideas within the Life Cycle and Business Model for a hypothetical oil or have to be worked, from initial inception through to gas field (after Jahn et al., 1998; with permission from Elsevier). prospect evaluation, supported by fieldwork (if possible) and various subsurface reconnaissance 7

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Chapter1—Introduction

(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 憌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 慺irst oil? and early revenue, or conduct an appraisal program and delay revenue generation.

Early development The early development and 慺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 慺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 慺irst oil? comes on stream the price drops to $15 barrel!

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

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 慳ppraisal phase? and associated 慺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 慺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 慺irst oil.? 8

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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 慿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抯oil heritage, Canada抯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, 揟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.

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Chapter 2—Petroleum: Composition and Characterization

Petroleum: Composition and Characterization 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. Table 1. Approximate elemental composition (in wt. %) of selected organic matter (after Hunt, 1979, 1996). Element

Carbon Hydrogen Oxygen Sulfur Nitrogen (Trace elements)

Gas

76.0 24.0 0.0 0.0 0.0 0.0

Oil

Kerogen (immature)

Asphalt

84.5 13.0 0.5 1.5 0.5 0.0

84.0 10.0 2.0 3.0 1.0 0.1

Type I

Type II

76.0 9.4 8.8 3.8 2.0 0.5

72.6 7.9 12.4 4.9 2.1 0.0

Type II 72.7 6.0 19.0 0.0 2.3 0.1

Coal Lignite 68.0 5.0 22.0 2.0 2.5 0.0

Bitumino us 83.0 5.0 8.0 2.0 1.0 highly variable

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 openchained 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 nonhydrocarbon because it contains a heteroatom. Such structures are informally known as NSO抯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).

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Chapter 2—Petroleum: Composition and Characterization

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 NSObearing 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抯 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!

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).

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 Pressure1). 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

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Chapter 2—Petroleum: Composition and Characterization

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 憃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 Figure 9. Example Napthenic compounds. biomarker analysis (Peters and Moldowan, 1993; Peters et al., 2004).

Unsaturated hydrocarbons Alkenes Although 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 癆 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.

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

Figure 11. A di-aromatic (alkyltetrahydrophenanthrene).

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Chapter 2—Petroleum: Composition and Characterization

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. 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 (癈 P atm)

Methane Ethane Propane Isobutane n-Butane Isopentane

CH4 C2H6 C3H8 C4H10 C4H10 C5H12

16.04 30.07 44.09 58.12 58.12 72.15

-162 -89 -42 -12 -1 30

Solubility (g 10? g water)

24.4 60.4 62.4 48.9 61.4 47.8

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抯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, and Liquefied 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. 慡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 latticelike 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 憄lastic?states

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

Liquid This of course includes crude oils. Crude oil has been defined (SPE/WPC/AAPG/SPEE, 2006, p. 46) as 搮 that portion 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 nonhydrocarbon. 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.

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Chapter 2—Petroleum: Composition and Characterization

Plastic state Petroleum 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 慼ardness? and degree of volatility. Bitumen is composed principally of hydrocarbons, but also contains a variable amount of nonhydrocarbon (i.e., NSO) compounds. Bitumen can also be a solid, plastic, or semiliquid 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.

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

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 憄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 慜PEC basket,? is an average of seven crude oils that includes Algeria抯 Saharan Blend, Indonesia抯 Minas, Nigeria抯Bonny Light, Saudi Arabia抯Arab Light, Dubai抯Fateh, Venezuela抯Tia Juana Light, and Mexico抯Isthmus (a non-OPEC crude oil). OPEC uses the price of this basket to monitor world oil market conditions.

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Chapter 2—Petroleum: Composition and Characterization

癆 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 (癆 PI), according to the following formula:

The determination of density under standardized conditions is critical since 癆 PI gravity determinations are only comparable if they are conducted at 60 degrees Fahrenheit, or 15.5 degrees Celsius. Water has an 癆 PI of 10, whereas the 癆PI of crude oil varies from 5 to 55 癆PI. Light oils have 癆PI gravities between 35 to 45, medium oils range in 癆 PI from 25 to 35, and heavy oils have an 癆 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 癆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 癆 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 憇weet? or 憇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 憌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-ofthumb guides as to the wax (paraffin) content of oil and the tendency of those waxes to solidify.

Figure 14. Atomic Force Microscope image of a paraffin wax crystal (C36H74), measuring 14 microns along the base (image by R.

The lowest temperature at which a crude oil will pour before it forms a 憇olid? is SPM Group Bristol image referred to as the pour point. Most crude oils exhibit pour points between +52? C Williamson; courtesy of DoITPoMS Cambridge). 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).

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Chapter 2—Petroleum: Composition and Characterization

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 慐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 癆 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 憈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. Nondegraded 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 highmolecular 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).

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Chapter 2—Petroleum: Composition and Characterization

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 憆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 憆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 *).

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 C30 range, whereas the Brent crude (A) oil has a significantly greater number of peaks at the C9 to C12 range (indicated *).

Here is the paradox; both oils are paraffin rich and have 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 慼igh wax? oil or a 憌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. 17

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Chapter 3—Petroleum: From Organism to Trap

Petroleum: From Organism to Trap 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 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 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 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 by a darker-grey maceral known as Collinite (C). Images (a) and (b) are in reflected autofluorescent light and (c) in reflected white light. a darker-grey maceral known as Collinite (C). Images (a) and (b) are in reflected autofluorescent light and (c) in reflected white light.

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Chapter 3—Petroleum: From Organism to Trap

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抯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 + 6O 2 + 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 憀eakage? in Figure 19.

Production There 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.

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

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.

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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).

Figure of organic organic matter matter as as related relatedtotothe thepresence presenceofofoxic oxicororanoxic anoxic Figure 20. 20. The preservation potential of bottom-water presence of of free free iron, iron,the thesulfate sulfatereduction reductionprocess processwill willpromote promotethethe bottom-water conditions. conditions. In the presence formation the absence absence of of iron, iron,hydrogen hydrogensulfide sulfideisisproduced produced(after (afterDemaison Demaison and formation of of pyrite, whereas in the and Moore, 1980).

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).

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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 microand 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).

Figure 22. Preservation potential due to lithology. A comparison between an argillite (top) and 憇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).

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.

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

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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. Table 3. The composition of living matter (examples) (data from Hunt, 1996). Molecular group1

Organic matter type

Spruce wood Scots-pine needles Phytoplankton Diatoms Zooplankton

Proteins

Carbohydrates

Lipids

Lignin

(wt. % )

(wt. % )

(wt. % )

(wt. % )

1 8 23 29 60

66 47 66 63 22

4 28 11 8 18

29 17 0 0 0

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 bluegreen 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

Carbohydrates Lipids Lignin (and tannin)

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

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. 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. 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. are complex 3-D aromatic molecules that give plants structural rigidity.

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Kerogen Type Introduction Because sedimentary organic matter can and will vary in amount and type from place to place for reasons previously outlined, geoscientists need a classification scheme that differentiates between various types of sedimentary organic matter, better known as kerogen. A hypothetical example was given in the previous section that contrasted the petroleum generative potential of a terrestrially derived kerogen against a marine-sourced kerogen. It was speculated, in that example, that the terrestrially derived kerogen would contain molecular remnants and modified material derived from lignin, cellulose, and other carbohydrates, and minor amounts of lipid material (i.e., relatively low hydrogen content); whereas the marine-sourced kerogen would contain molecular remnants and modified material derived from lipids, carbohydrate, and proteins (i.e., relatively higher hydrogen content). We also reviewed earlier (Chapter 2) that petroleum, like kerogen, is predominantly comprised of organic compounds containing principally the elements hydrogen, carbon, and oxygen. With respect to the generation of petroleum, the most fundamental characteristic of kerogen is hydrogen content, because under optimal conditions a hydrogen-rich kerogen will generate more oil than a hydrogen-lean kerogen. Therefore, by determining the elemental composition of kerogen it is possible to differentiate and classify kerogen, and broadly predict the type of petroleum a given kerogen will generate in the subsurface under the right conditions.

Figure 25. A cross-plot of the atomic ratios H/C versus O/C, generally known as a 憊an Krevelen diagram? showing the broad evolutionary paths for Types I, II, and III kerogen and the empirically determined three areas of thermal maturity known as diagenesis, catagenesis, and metagenesis (after van Krevelen, 1960; Tissot et al., 1974; Durand, 1980; Tissot and Welte, 1984; and others).

Atomic ratio method The van Krevelen diagram is an x-y cross-plot of the Atomic Ratio of the elements Hydrogen/Carbon (H/C) against the Atomic Ratio of Oxygen/Carbon (O/C) obtained by elemental analysis (Figure 25). For example, the bulk analysis of a hypothetical marinesourced kerogen may contains carbon (76.4 wt. %), hydrogen (8.3 wt. %), and oxygen (13.1 wt. %), which gives H/C and O/C Atomic Ratios of 1.3 and 0.13 respectively. Our hypothetical marinesourced kerogen plots as an immature Type II on the diagram. In contrast, our hypothetical terrestrial kerogen contains carbon (72.7 wt. %), hydrogen (6.0 wt. %), and oxygen (19.0 wt. %), which gives H/C and O/C Atomic Ratios of 0.9 and 0.2 respectively and plots as an immature Type III kerogen.

Hydrogen or oxygen index Probably the most common means of characterizing kerogen is via Figure 26. The Hydrogen and Oxygen Index bulk pyrolysis, which is typically obtained by RockEval pyrolysis. cross-plot, showing the evolutionary paths for Part of the appeal of this approach is convenience and the wealth of Type I, II, III, and IV kerogen (after Tissot et al., 1974; Durand, 1980; Tissot and Welte, 1984; data obtained during analysis. Data is derived by pyrolyzing the and others). kerogen under standardized conditions (Espitalie et al., 1980, etc.), which yields data that can be plotted in an analogous way to the van Krevelen-type diagram. The Hydrogen/Oxygen Index cross-plot (Figure 26) also designates kerogen into one of three main petroleum generative kerogen Types. A fourth kerogen Type also exists (Type IV) but is generally considered non-generative. Continuing to use our hypothetical example kerogen, the immature marine example may generate a Hydrogen Index of 620 mg HC/g TOC and an Oxygen Index of 75 mg CO2/ g TOC (i.e., Type II kerogen). In contrast, the terrestrial kerogen may generate a Hydrogen Index of 110 mg HC/g TOC and an Oxygen Index of 125 mg CO2/ g TOC (i.e., Type III kerogen). 23

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Type I kerogen Kerogen of this type has the highest hydrogen content of all kerogen types and is strongly oil prone. Type I kerogen is derived from organic matter rich in lipids and is generally subdivided into Alginite A, representing the accumulation of algal material, e.g., Tasmanites, Gloeocapsomorpha prisca, Botryococcus or Pila (Figure 27), or Alginite B, hydrogenrich amorphous organic matter (Figure 27c). The G. prisca-rich Ordovician kukersites of North America represent an example of Type I kerogen.

Characteristics van Krevelen diagram: a high initial H/C (e.g., 1.3+) and a low O/C (i.e., less than 0.1) Atomic Ratio. HI/OI plot: a very high Hydrogen Index (600 to 900) and very low Oxygen Index (10 to 30).

Figure 27. Examples of Type I Kerogen known as Alginite. Image (a) contains Pila (P); image (b) contains Tasmanites (T), and image (c) contains amorphous organic matter (A). All images in reflected autofluorescent light (image 27c courtesy of L. Stasiuk).

Type II kerogen This is perhaps the most commonly reported type of kerogen, which is probably a chemical averaging artifact due to the bulk analysis of complex kerogen mixtures within a given source rock. True Type II kerogens possess relatively high initial hydrogen content and a moderate amount of oxygen (Figure 28). Examples of Type II kerogen include marine organic matter, phytoplankton, zooplankton, and bacteria deposited in a reducing environment, and some terrestrially derived material also (Figure 28b, c), although marine-derived Type II kerogen is more common. Typically Type II kerogen is associated with a lower oil yield than an equivalent volume of Type I kerogen. The Jurassic Kimmeridge clay (North Sea basin) contains a prolific Type II kerogen. Type II kerogens may also be subdivided on the basis of sulfur content (Hunt, 1996).

Characteristics van Krevelen diagram: a moderately high initial H/C (1.0 to 1.3) and a moderate O/C (0.03 to 0.15) Atomic Ratio. HI/OI plot: a high Hydrogen Index (550 to 600) and moderate Oxygen Index (50 to 100).

Figure 28. Examples of Type II Kerogen. Image (a) contains the maceral Sporinite (S); images (b) and (c) contain the macerals Resinite (R) and Cutinite (C).

Type III kerogen This kerogen type releases little in the way of aliphatic material during thermal maturation and, therefore, true Type III kerogens are not usually considered oil prone. Type III kerogens are typically derived from terrestrially derived vascular plant material, i.e., vitrinitic, not liptinitic (Figure 29a, b). The Manville shale (U.S.A. and Canada) is an example of a Type III kerogen.

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Characteristics van Krevelen diagram: a low H/C Atomic Ratio (i.e., less than 1.0) and an initial O/C ratio between 0.2 to 0.3. HI/OI plot: a low initial Hydrogen Index (i.e., less than 150) and an high initial Oxygen Index (e.g., 150+).

(a)

(c)

(b)

Figure 29. Examples of Type III and Type IV kerogen. Image (a) is a Type III kerogen-bearing shale (K); image (b) is a Vitrinite-rich sediment (V); image (c) contains Fusinite (F) as an example of a Type IV kerogen (image 29c courtesy of L. Stasiuk).

Type IV and residue Some recognize a fourth type of kerogen, known as Type IV. However, the oil and gas generation potential of this kerogen is extremely low and typically considered non-generative. An example of this type of kerogen is the maceral Fusinite, which is derived by the oxidation of derived vascular plant material (Figure 29c).

Organic facies As stated earlier, the chemical composition of organic matter within a source rock is determined by the type and variation of living precursor within a depositional environment; that is dependent, in turn, 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 of oxygen (Tissot and Welte, Figure 30. A section through the Earth's crust showing possible general relationships between depositional setting, available oxygen supply, and broad 1984). Furthermore, since the early differences in organic matter type (marine/terrestrial/algal). Devonian, the diversity and number of species has increased, giving rise to natural associations of increasing differentiation and complexity due to variations in depositional setting (Figure 30) and evolution. Therefore, the chemical composition of a given kerogen is largely dependent upon depositional environment and the natural association of plant and/or animal species present within that environment (Figure 30). This in turn influences the generative potential of the kerogen (i.e., gas prone or oil prone). For example, a marine source rock may contain organic matter principally derived from marine plankton, composed of proteins, carbohydrates and lipids. In contrast, a terrestrially derived source rock may contain organic matter derived from vascular plants, mainly composed of lignin, carbohydrates, and some lipid material. It would be reasonable to anticipate (following this example), that the marine-derived kerogen would be oil prone, whereas the terrestrially derived kerogen would probably be gas prone. Lateral and vertical variations in association of organic matter are increasingly described and interpreted in terms of organic facies (Rogers, 1980; Jones and Demaison, 1982; Jones, 1984, 1987; Jacobsen, 1991). Organic facies are determined by the type of organic matter within the rock unit, which is generally considered linked to the paleodepositional environment (Figure 31) (Rogers, 1980). Jones (1984) defines an organic facies as a mapable subdivision of a designated stratigraphic unit, distinguished from the adjacent subdivisions on the basis of the character of its organic constituents, without regard to the inorganic 25

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Chapter 3—Petroleum: From Organism to Trap

aspects of the sediments. Tyson (1995) notes that this definition does not limit the definition to any given technique or methodology. This is significant since organic matter within sediment can be characterized by microscopy, by geochemical analysis, or better still by integrating the two. The organic facies concept can be used as an exploration tool by the petroleum geochemist to map source rock characteristics and also to predict the occurrence, quality, and generative potential of source material within a basin or stratigraphic sequence. For a detailed account of organic facies please refer to Tyson (1995).

Figure 31. The relationship between selected organic facies and sedimentary environment and climate, according to Jones (1987) (from Tyson, 1995; reprinted courtesy of Springer Science and Business Media). A listing of Organic facies (i.e., D, C, B, etc.) and a summary of respective characteristics is given below in Table 4.

Table 4. Organic facies and selected characteristics (after Jones, 1984, 1987; Jones and Demaison, 1982; Tyson, 1995). Organic facies A AB B BC C CD D

H/C Atomic Ratio at %Ro ~ 0.5 > 1.45 1.35 to 1.45 1.15 to 1.35 0.95 to 1.15 0.75 to 0.95 0.60 to 0.75 < 0.6

Pyrolysis yield HI OI > 850 650 to 850 400 to 650 250 to 400 125 to 250 50 to 125 < 50

10 to 30 20 to 30 30 to 80 40 to 80 50 to 150 40 to 150+ 20 to 200+

Generation potential oil

mixed mixed gas none

Dominant organic matter Algal; amorphous Amorphous; minor terrestrial Amorphous; commonly terrestrial Mixed; some oxidation Terrestrial; some oxidation Oxidized; reworked Highly oxidized; reworked

Sedimentary structure

Laminated Well bedded to laminated Poorly bedded Poorly bedded to bioturbated Massive, bioturbated

The generation of petroleum Thermal maturation Thermal maturation is the natural transformation of kerogen into petroleum in response to increased thermal stress, which is due to an increase in burial depth throughout geological time. The maturation threshold for each kerogen type differs because the transformation of kerogen into petroleum involves the thermal rupture of chemical bonds, and is dependent upon the molecular make-up of a given kerogen due to differences in (bond) dissociation energy, in which carbon-sulfur and carbon-oxygen bonds generally have lower dissociation energies than carbon-hydrogen bonds (Hunt, 1996). Following deposition and preservation, the subsequent transformation of organic matter into kerogen and the generation of petroleum involves three discrete,

Figure 32. The three stages of kerogen transformation, with the relative production of biogenic gas, oil, and thermogenic gas. Within the nine inset figures, inherited hydrocarbons are indicated in solid black, whereas generated hydrocarbons are in gray (from Tissot and Welte, 1984; reprinted with kind permission of Springer Science and Business Media).

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sequential stages of alteration (Figure 32) known as: diagenesis, catagenesis, and metagenesis (Espitalie et al., 1980; Tissot and Welte, 1984). Each stage of alteration is characterized by a different process. The diagenetic stage is predominantly biochemical, within which microbial processes predominate. Catagenesis immediately follows diagenesis and represents the principal stage of petroleum generation. When kerogen crosses the chemical boundary (a.k.a. threshold) between diagenesis and catagenesis, thereby entering the catagenesis stage, the kerogen is said to be thermally mature with respect to petroleum generation. The final stage, known as metagenesis, is typically associated with the generation of dry gas and nonhydrocarbon gases.

Diagenesis Diagenesis (Figures 32 and 33) is the immature stage and typically associated with the progressive biochemical transformation of organic matter into kerogen. Diagenesis commences within the water column and continues within the subsurface until a temperature threshold of 50 to 75? C, or a vitrinite reflectance minimum of om 0.5%, is reached2. It is within the diagenetic stage that the crucial process of preservation occurs. Some hydrocarbons may co-exist with the immature kerogen (Figure 32), however, they are either inherited hydrocarbons from biological organisms (e.g., biomarkers), or metabolic by-products (e.g., biogenic methane); shown in black within the nine inset diagrams in Figure 32. Examples of inherited hydrocarbons include the tricyclic and pentacyclic biomarkers, terpenoids, certain isoprenoids, and waxes. Typically, the generation of petroleum, via the thermal rupture of chemical bonds, is not considered a characteristic of diagenesis. However, bitumen and heavy oil generation is known to occur in carbonate-rich, sulfurbearing kerogen, such as Type IIS (Horsfield and Rullk鰐ter, 1994; Hunt, 1996) because of differences in bond dissociation energy (Hunt, 1996).

Figure 33. The thermal evolution of kerogen as depicted on a van Krevelen type diagram. Note the color-coded kerogen maturity zones diagenesis, catagenesis and metagenesis for each kerogen type. Each recognized kerogen type has an evolutionary tract, along which kerogen of similar composition but of increased level of thermal maturity plot. The attained level of thermal maturity is determined by analyzing the residual amount of elemental hydrogen, oxygen and carbon within a sample of kerogen and calculating the appropriate atomic ratios (after van Krevelen, 1960; Tissot et al., 1974; Durand, 1980; Tissot and Welte, 1984; and others).

Catagenesis The onset of petroleum generation and the thermal degradation of kerogen marks the beginning of catagenesis (Figures 32 and 33). The generation of petroleum is indicated by a significant decrease in atomic H/C (e.g., 1.25 to 0.5 in Type II) due to a net loss of hydrogen from the kerogen. This process can be effectively depicted on a van Krevelen diagram (Figure 33) with data derived from the elemental analysis or Rock Eval pyrolysis of kerogen. Despite the apparent synonymous nature of catagenesis and the 憃il window,? catagenesis is widely recognized as having both an oil generating and wet gas-generating zone, in that order depending upon the kerogen Type. The oil window is defined as that part of catagenesis in which oil generation exceeds gas generation, whereas wet-gas formation is associated with diminished oil generation. Vassoevich et al. (1969) described the petroleum generation process during catagenesis as having a principle zone of oil generation, now simply known as the oil window (Figures 33 and 34), the boundaries of which are routinely defined by using techniques such as vitrinite reflectance or RockEval pyrolysis. However, because of differences in activation energy, the 憃il window? varies for different kerogen Types. For example, it is lowest ( om 0.5% and a Tmax 430oC) for Type IIS kerogen and highest for a Type I kerogen (~ om 0.65% and a Tmax 440oC) due to differences in the presence of different elements. Throughout catagenesis, kerogen becomes increasingly aromatic and greatly depleted in paraffinic/naphthenic compounds (Figure 34, numbers 2 to 4) due to the process of oil/gas generation. This progressive increase in aromaticity creates changes within the kerogen (e.g., increase in light opacity, red-shift in autofluorescence; see Figure 34) that form the basis of many indices of maturation (e.g., Heroux et al., 1979) as used by organic petrographers and petroleum geochemists.

2

The vitrinite reflectance parameter % om indicates that the vitrinite reflectance value represents the arithmetic mean ( ) of a number of values measured using oil immersion (o) and non-polarized light (m) under standardized conditions.

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Chapter 3—Petroleum: From Organism to Trap

Metagenesis This zone represents the thermal cracking of previously generated hydrocarbons, should any remain within the source rock (Figure 33) and the additional generation of methane (C1) directly from the remaining kerogen. Metagenesis is considered to be the final stage in the generation of oil and gas, and is simply a process of organic metamorphism due to the relatively higher temperatures that typically occur deep within a basin. During metagenesis, oil is thermally cracked to produce dry gas (methane) and a carbonaceous, aromatic-rich residue (Figure 34; number 5).

Figure 34. Changes in composition and appearance in response to thermal maturation, using Type II kerogen as an example. Five infrared spectra, representing changes in a Type II kerogen during thermal maturation (shown on the left), are stacked to show the relative changes in molecular structure due to the process of thermal maturation. A series of spore 憄alynomorphs? exhibiting the sequential changes in opacity are also shown, alongside the corresponding level of thermal maturity. On the right, a van Krevelen diagram shows the approximate equivalent of thermal maturity as determined by the atomic ratios of H/C and O/C. This example is for illustrative purposes only (stacked infra-red spectra modified from Tissot and Welte, 1984, with kind permission of Springer Science and Business Media; spore micrographs modified from Combaz, 1980, courtesy of Editions Technip; van Krevelen diagram modified after van Krevelen, 1960; Tissot et al., 1974; Durand, 1980; Tissot and Welte, 1984; and others). Note within each of the stacked infrared spectra, the area and height of each peak corresponds to the abundance of a given molecular group (e.g., C=O). Note that changes in kerogen chemistry (i.e., decrease in oxygen functional groups, aliphatic C-H, and an increase in aromatic C-H) due to thermal maturation are accompanied with changes in spore opacity due to an increase in the adsorption index. The changes in molecular group and changes in spore opacity are reflected by successive differences in the atomic ratios H/C and O/C. Note specifically: #1: Recent organic matter that is thermally immature (diagenesis). Note the high C=O peak, high aliphatic peaks, and very low aromatic peaks. Correspondingly this immature kerogen has a relatively high H/C and moderately high O/C Atomic Ratio. Spores are clear to pale yellow. #2: Onset of catagenesis: entering the 憃il window? (marginally mature). Note the decrease in C=O and aliphatic compounds, loss of H and O relative to C in the Atomic Ratio, and a darkening of the spore. #3: Peak of hydrocarbon generation (mature), catagenesis. Continued decrease in C=O and aliphatic compounds with a significant increase in aromatic content, marked loss of H relative to C in the Atomic Ratio, and a further darkening of the spore to a dark orange color. #4: End of hydrocarbon generation (post mature) and start of metagenesis. C=O and aliphatic compounds are markedly reduced with an accompanying increase in aromatic content. Note also the continued loss of H relative to C in the Atomic Ratio and a further darkening of the spore to a dark brown. #5: Metagenesis. The aliphatic content is significantly reduced whereas the aromatic content has increased. The H/C and O/C Ratios are greatly diminished and the spore is black.

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Chapter 3—Petroleum: From Organism to Trap

Source rock assessment There are many techniques available to determine the thermal maturity of a potential source rock, some are standardized by scientific organizations (e.g., The Society for Organic Petrology or the International Committee for Coal Petrology), and some are not. Without doubt, the two most universally accepted techniques used by industry include RockEval pyrolysis (Tmax) and vitrinite reflectance (% o m). Vitrinite reflectance measures the amount of light reflected from the surface of a polished fragment of vitrinite (i.e., Type III kerogen), whereas RockEval pyrolysis indirectly derives the hydrogen, carbon, and oxygen content of kerogen from a crushed sample plus a host of other useful parameters (e.g., Tmax, PI, etc). Neither technique is without flaw, since both have well-known limitations. However, they permit the rapid determination of thermal maturity for a given sample and provide a suitable framework by which other techniques can be compared. For example, by reference to specific values, such as om 0.5 to 0.6% and Tmax values of 430o to 435o, the boundary for the onset of oil generation can be rapidly determined, easily defined, and universally understood.

Migration and Accumulation of Petroleum Introduction Definitions The economic accumulation of petroleum generally occurs in a relatively coarse-grained porous and permeable rock that contains little or no insoluble organic matter (i.e., kerogen). It is, therefore highly probable that petroleum compounds underwent some form of migration phenomenon from their place of origin to place of accumulation. The release of petroleum compounds from kerogen and their subsequent movement within the fabric of the source rock has been termed primary migration. Secondary migration is the movement of petroleum from the source rock, through the larger pore-throats of more permeable beds or permeability conduits, to the trap. Tertiary migration is the movement of petroleum from a previous accumulation to either the earth抯surface or a shallower trap.

Compaction Sediment compaction creates an increase in bulk density, a marked reduction in porosity, and changes in pore geometry. The rate at which compaction occurs is largely governed by the properties of the sediment, the process of mineral diagenesis, the rate of fluid expulsion, rate of deposition, and burial depth. Within shale in particular, the greatest decrease in porosity occurs at relatively shallow depth, with a rate that generally decreases with increasing depth; accompanied by a marked decrease in average pore diameter, with final values of between 1.0 to 2.5 Nm (Figure 35). Hall et al., (1986) reported porosities of 5.2% for the Cherokee Shale (Oklahoma) and 4.3% for the Bakken Formation (N. Dakota). Both are proven source rocks. The reported median pore diameters were 7.0 nm and 5.0 nm respectively. However, the laboratory derived values of Hall et al., (1986) would probably be reduced by the presence of chemi- or physi-sorbed water and the presence of structured water. Such values may then be closer to the median value of 3 nm proposed by Momper (1978). The effective diameter of petroleum molecules varies greatly and generally increases with increasing molecular weight, as shown in Figure 35 and Table 5 (Welte, 1972; Hunt, 1979, 1986; Tissot and Welte, 1984). When compared to the 慳verage? shale pore diameter, most complex molecules are either similar in size or larger. So how does the oil or gas get out of the source rock?

Figure 35. Generalized relationship between depth, temperature, pressure, and porosity (modified after Tissot and Welte, 1984, with kind permission of Springer Science and Business Media).

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Chapter 3—Petroleum: From Organism to Trap

Primary migration Table 5. Effective diameter of selected molecules

Chemical and physical constraints A number of mechanisms have been proposed for the process of primary migration, including petroleum moving as discrete molecular entities, as a continuous oil or gas phase, as individual oil droplets or gas bubbles (globules), as colloidal and micelle solutions, or as true molecular solutions! Theoretically, primary migration could involve a variety of mechanisms. In reality, petroleum generation causes migration. The mechanism of primary migration is not yet unequivocally known, but is generally considered to occur via processes involving diffusion, solution, and/or hydraulic pressure.

Molecule

Effective diameter (Nm)

Water Carbon dioxide Methane Pentane Benzene n-alkanes Cyclo-hexane Complex ring structures Asphaltene molecules

~0.32 0.33 0.38 0.46 0.47 0.48 0.54 1.00 to 3.00 5.00 to 10.00

Source: Stewart (1928), Welte (1972), Hunt (1979, 1986), Tissot and Welte (1984)

Diffusion A diffusional process is one in which molecules move from high concentration to lower concentration. Diffusion preferentially favors the smallest molecules, such as methane (Table 5) compared to other gaseous hydrocarbons (Welte, 1972; Magoon and Claypool, 1983; Krooss and Leythaeuser, 1997).

Solution Benzene and toluene are highly soluble in water3 (Price, 1973, 1976; McAuliffe, 1966). In contrast methane is relatively insoluble in fresh water at low temperature and pressure (McAuliffe, 1966), although at higher temperature and pressure a solubility increase of 300 times was reported at 6,096 m (20,000 feet) (Culberson and McKetta, 1951). Generally, the solubility of petroleum compounds decreases in the order: aromatics cycloalkanes normal alkanes, although the majority of petroleum compounds have solubilities in water that is less than 1.0 mg liter (McAuliffe, 1966) at 25 癈. Most economic accumulations of petroleum consist of compounds that are insoluble in water.

Hydrocarbon phase migration The pressure-driven, hydrocarbon-phase movement of petroleum is shown in Figure 36 (Ungerer et al., 1983). A source rock containing organic carbon (4.0 wt. %) is equal to 9.8% organic matter by volume. At depths greater than 1,500 m the organic matter would occupy a significant proportion of available pore space. A source rock containing more than 4% Corg would become 憃il wet? (with an associated high resistivity). The presence of networks of both bitumen and oil increases the oil wettability of shale, possibly facilitating oil-phase migration (Hunt, 1996). During the transformation of solid kerogen into liquid hydrocarbons, or gas, there is an increase in fluid pressure (i.e., Figure 36. Microfracture-induced hydrocarbon-phase migration during oil pore pressure) (Momper, 1978; Ungerer et generation. (A) Represents the initial stage prior to oil generation, in which the bulk of the source rock is water-wet. (B) Oil generation has occurred al., 1983). The combined effects of oil with the creation of an oil-wet pore network around the kerogen. The generation, the thermal expansion of connate generation of oil creates an increase in pore pressure that either opens water, rapid burial, and partial transfer of existing fractures or creates new ones. The oil is then expelled along oil-wet geostatic stress from rock fabric to pore fluid microfractures (modified and redrawn from Ungerer et al., 1983). are thought to generate pressure centers within the source rock; which induces micro-fracturing, along which migrating hydrocarbons are expelled (Figure 36). This pressure driven mechanism of primary migration is thought to involve many repeat cycles: pressure build-up

microfracturing

hydrocarbon expulsion

pressure release

oil generation

expansion

(repeated many times) 3

Price (1973, 1976) and McAuliffe (1966) report solubilites of 1,740 ppm (+17) and 1,780 ppm (+45) respectively for benzene, and 554 ppm (+15) and 515 ppm (+17) respectively for toluene at 25? C

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Chapter 3—Petroleum: From Organism to Trap

Secondary migration Secondary migration is defined as the movement of petroleum through more permeable and porous carrier beds and reservoir rocks. Secondary migration terminates once the hydrocarbons encounter a trap, but may be re-initiated by tectonic events; known as 憆e-migration? or 憈ertiary migration.? Secondary migration and the subsequent entrapment of petroleum is controlled by three parameters: the buoyant rise of petroleum in water-saturated porous rocks, capillary pressure, and hydrodynamic flow. The main driving force for secondary migration is considered to be density, in which hydrocarbons move in the direction of decreasing energy. Because oil and gas have lower densities than the surrounding, subsurface, aqueous pore fluid, the process of secondary migration is essentially driven by buoyancy, due to differences in density. The density differences are: -3

Oil s.g.

= 0.5 to 1.0 g cm

gas s.g.

= less than 0.01g cm

pore fluid s.g.

= 1.0 to 1.2 g cm

-3

-3

Countering the buoyant rise of petroleum is capillary pressure. Within a multi-phase system consisting of immiscible phases (e.g., water and oil), an interfacial tension will exist across the contact interface. Capillary pressure is the pressure difference across the multi-phase interface. The greater the difference in interfacial tension between two phases, the greater the capillary pressure. When a small drop of oil is added to water, the oil globule assumes a shape of least surface area (Figure 37), which is a sphere due to interfacial tension ( ). The force required to distort that sphere, and subsequently drive the oil droplet through a small pore throat, is often referred to as the driving force or more correctly the injection pressure (Berg, 1975). As a general rule, capillary pressure increases with increasing interfacial tension and/or decreasing pore throat diameter. The termination or continuation of movement is determined by an interplay between the driving force (e.g., density) and the resisitive force (i.e., capillary pressure). As shown in Figure 38, to drive an oil globule between the two grains, considerable energy must be exerted on the globule to overcome surface tension effects, increase the curvature of contact, and reduce the effective radius of the oil. When the upper and lower radii (r) within the distorted globule are equal to one another, the capillary force is overcome and the globule can rise due to buoyancy.

Figure 37. Surface tension on a droplet; the arrows show the pull of the attractive forces.

Subsurface water flow may assist, modify, or even counter the movement of hydrocarbons. The existence of high capillary pressure within narrow rock pore throats is the main cause for hydrocarbon entrapment. Video 4 shows oil and water moving through porous media. Video 4. Oil and globules of water moving through a water-wet pore network. Note that each grain is coated with water (i.e., water wet); also note that water globules, e.g., 慩? are 慸istorted? as they pass through the pore throats as shown in Figure 38 (Dong et al., 2007, used with permission).

Figure 38. The movement of an oil globule (black) through a pore throat in water-wet rock (blue). The buoyant movement of the oil globule is opposed by capillary pressure until both the curvature contact and the internal radius (r) decrease and are equal at the lower and upper ends of the globule (right) (after Berg, 1975; and others). P = internal pressure within the globule = interfacial tension r = globule radius rp = globule radius outside the pore rt = globule radius inside the pore

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Chapter 3—Petroleum: From Organism to Trap

Post emplacement processes Introduction 揟 he history of petroleum does not end when petroleum products are pooled into reservoirs? (Connan, 1984, p. 299). Changes, sometimes subtle, effect petroleum after it leaves the source rock. Beyond the changes in composition that can occur during migration (e.g., fractionalization) several post-accumulation processes have the potential to modify petroleum within the reservoir or even during migration. For the most part, the alteration is generally considered destructive or a degrading process. For example, increases in temperature within the reservoir (i.e., in-reservoir maturation) will lead to a decrease in the relative proportion of higher molecular weight compounds (i.e., C15+) and a relative increase in the low molecular fraction. A decrease in pressure within the reservoir could lead to the deasphatling of petroleum through the precipitation of higher molecular weight compounds within the reservoir. Perhaps the two most prevalent alteration processes to effect reservoired petroleum include water-washing and microbial biodegradation. Degradation by the process of water-washing and the microbially-derived process of biodegradation is a widespread phenomenon; for example, the seven largest super-giant accumulations of tar sands (degraded crude) contain as much oil as the 264 largest conventional oil fields (e.g., Athabasca tar sands, Western Canada, = 700 to 1000 ? 109 bbl), due to the degradation of a medium-gravity crude oil into a tar sand with an associate API gravity 0.60, connate water occupies small and medium sized pores and surrounds the 憁 ineral grains? Within the pores oil and water are immiscible. However, the flood water, flowing left to right, has a different water chemistry and as a consequence there is interfacial tension between the connate water and the flood water, they do not readily mix (i.e., immiscible), hence the visible interface between the flood water and connate water. Consequently, the waterflood has formed a 憁 icro-channel? (blue arrow) and has bypassed the oil in the upper and lower pores. The scale bar is approximately 500 m. (after Dong et al., 2007, reprinted with kind permission).

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Chapter 8—Production and Recovery

Water is injected via a separate injector well, or more typically via a number of wells arranged in a set pattern. Injector wells are always down dip from the producing wells. As oil is withdrawn the oil/water contact will rise. As producing wells 憌ater-out,? during production (Video 21), they would most likely be converted to an injector well (Sam Sarem, 1992; Jahn et al., 1998). Of course in plan view, the pattern of injector wells should reflect the geometry of the trap, the porosity and permeability distribution throughout the reservoir, and known changes in facies, although typically producers use set injector patterns (Figure 179). Geologically inhomogeneous reservoirs are the norm, and a poorly designed injector pattern will produce less than ideal recovery, leaving behind by-passed oil (Figure 177), which can be difficult and expensive to recover. In the example given in Figure 177, injected water appears to have effectively swept oil from two high permeability zones and successfully produced oil. However, there are two low permeability zones, associated with a significant amount of oil Video 21. The animation shows the remaining within those reservoir partitions as by-passed oil (Jahn et al., sequential transformation of producing wells into water injector wells. 1998). Any attempt to recover the by-passed oil by continued injection of water would be futile, since the injected water would preferentially travel through the more permeable zones (Figure 178). The geologist can contribute significantly in the optimization of production through the application of his/her knowledge and understanding of the reservoir rock, facies variation, type and depositional setting of the reservoir rock, trap geometry, variations in porosity and permeability and water saturation (i.e., Sw, Swirr) etc., all of Figure 179. Water injector arrangement patterns. Shown here are the 4-Spot and which have great relevance when the 5-Spot patterns. Single wells are typically associated with simpler patterns, whereas large pools demand complex patterns. determining the optimum injector pattern.

Gas injection Producing oil wells can be assisted by injection of (compressed) solution gas back into the gas cap, in order to maintain pressure. Sometimes producing companies can inject unwanted gas back into the reservoir; this depends upon local regulations. Another option allows for the injection of gas into the annulus, with the aim of lowering the density of the produced oil and aiding production (Jahn et al., 1998).

Thermal techniques Thermal techniques are used to reduce the viscosity of oil within the reservoir in an attempt to increase mobility and displacement by reservoir drive mechanisms. Sources of heat include steam flood or hot water flood. The injection of a heat source may require separate injector wells or, the producing well may be used by cycling between production and injection. In-situ combustion is an extreme example of heat injection (Breit, 1992).

Chemical techniques Chemical techniques utilize reagents that change the physical properties of the produced fluid or the displacement fluid. There are two general sub-types, polymer flooding and alkali-surfactant flooding. Polymer flooding aims at increasing the viscosity of the displacing fluid (i.e., connate water) and increasing the sweeping efficiency of that fluid. Alkali-surfactant and surfactant flooding is used to reduce the amount of residual oil left in the pore space of the reservoir by reducing interfacial tension between water and oil. This is achieved by a reduction in oil droplet size, thereby permitting the oil to pass through smaller pore throats (Breit, 1992; Jahn et al., 1998). Emulsifiers can also be used in situations where oil to water ratios are unfavorable, or to assist with the production of heavy gravity crude oils, i.e., low API? gravity (Liu, 2006; Dong et al., 2007) (Video 22).

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Video 22. Oil, connate water and alkalisurfactant flood moving through a laboratory scale reservoir. The alkaline flood reduces the interfacial tension between the flood water and oil, increasing sweep efficiency. (after Dong et al., 2007, used with kind permission).

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Chapter 8—Production and Recovery

Miscible processes Miscible fluids are utilized to produce oil that could potentially become residual oil. This is achieved by injecting a fluid that mixes with the produced fluid. Typical miscible fluids are organic-based solvents, hydrocarbon gases, CO2 and N2 (Breit, 1992; Jahn et al.,1998)

Artificial lift systems Some wells will produce throughout most of their life without the need for EOR. However, most wells will require some form of recovery method to enable or accelerate production. Many wells require some form of artificial lift as reservoir pressures drop and production declines. Artificial lift is not an EOR technique, although it can augment the specific application of EOR. Artificial lift may also extend the life of a pool or field, or become the only means through which a well can become economic. Prior to the option of running horizontal legs, production from stripper wells (i.e., production less than 1.5 m3 p.d.) was only feasible by using a pump jack (beam pump) (Figure 180), the cost of which may represent one third of the total cost of drilling and developing some wells in N. America. In the case of off-shore ventures, the cost of production can easily exceed exploration costs.

Figure 180. A pump jack in the Midale field, Sask., Canada.

When is the best time to install an artificial lift system? The obvious need is when production rates decline, or when the well is in danger of becoming sub-economic. However, probably the most intelligent time to install an artificial lift system is prior to first oil; because the cost of installation can be covered by the increased production rate throughout the life of the well, and the cost of installation can be written throughout over a longer period of time (if advantageous). Although, there may be cases when the optimal type of artificial lift changes during the life of a well or field. The types of artificial lift discussed here include: the pump jack (beam pump), the progressive cavity pump, the electric submersible pump, hydraulic reciprocating pump, hydraulic jet pump, continuous flow gas lift, and intermittent gas lift (Figure 181) (Smallwood, 1992; Jahn et al., 1998).

Figure 181. Examples of artificial lift systems. A gas lift, B hydraulic jet pump, C pump jack, D progressive cavity pump, and E electric submersible pump (after Jahn et al., 1998, reprinted with permission from Elsevier).

Gas lift Gas is injected into the producing fluid column, which decreases the hydrostatic pressure within the well bore, thereby stimulating natural flow (Figure 181a). In the continuous gas lift type, a constant stream of gas aids the production of fluid and the gas becomes dispersed within the produced fluid. However, in the intermittent gas lift variant the gas is injected as 憄ulses? generating a 憄iston-like? or pulse lift. The gas is removed from the produced fluid at the end of each 憄ulse.? Lift capability (gross / BPD) 100 to 1,000

Hydraulic efficiency 2 to 30%

Continuous gas lift

Lift capability (gross / BPD) 1 to 800

Hydraulic efficiency 2 to 10%

Intermittent gas lift

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Hydraulic jet pump A downhole hydraulic motor, driven by a hydraulic medium under pressure, achieves lift (Figure 181b). Energy for the motor is delivered via the hydraulic medium by a surface motor. There are no moving parts in the downhole hydraulic motor. Lift capability (gross / BPD) 80 to 12,000

Hydraulic efficiency 10 to 30%

Hydraulic Jet pump

Lift capability (gross / bpd) 80 to 10,000

Hydraulic efficiency 2 to 30%

Hydr. reciprocating pump

Pump jack Also known as the beam pump and affectionately as a 憂odding donkey? (Figure 181c). Lift is achieved by a downhole plunger, which is connected to the counter-balanced reciprocating beam by sucker rods. A small motor drives the beam at the surface. Differing rates of production are achieved by varying the beam speed, the dimensions of the plunger, and stroke length, all of which should match the permeability characteristics of the reservoir and viscosity of the produced fluid. Lift capability (gross / BPD) 1 to 5,000

Hydraulic efficiency 50 to 60%

Progressive cavity pump Based upon the Archimedes screw, the progressive cavity pump is a downhole motor driven by a small surface motor (Figure 181d). Variations in production rate can be achieved by changing the dimensions of the stator rotor and pump speed. Lift capability (gross / BPD) 1 to 2,000

Hydraulic efficiency 50 to 70%

Electric submersible pump This is a centrifugal type of pump driven by a downhole motor powered by electricity (Figure 181e). Typical units consist of more than one pump, arranged as a series of pumps to aid lift. Lift capability (gross / BPD) 100 to 50,000

Hydraulic efficiency 40 to 50%

Surface production facilities Introduction It is an exceptional oil-field fluid that can be produced from the reservoir ready to export. Typically the produced fluids will exist as a mixture of oil and gas, oil and water, oil plus gas and water or even condensate and hydrogen sulfide etc. Therefore, the produced fluids must be separated and the unwanted fluids or gases disposed. Separation is achieved at the surface in an oil and gas processing facility near or adjacent to the producing well and such facilities are tailored to the specifics of the producing well, pool, or field (Jennings, 1992; Jahn et al., 1998). Off-shore facilities may employ three separate fluid separators; consisting of a high pressure, medium pressure, and low pressure separators to remove gas and water. In comparison, land-based operations often use a single three phase separator (Figure 182).

Separators The single three phase separator uses differences in density to remove gas, free-water and oil from the produced fluids (Figure 182). The inlet section [1] separates most of the liquid phase from the produced mixture. The dissolved gas comes out of solution and rises within the vessel as a gas phase. Because small amounts of liquid may exist as droplets within the gas phase, a demisting section [2] or device is utilized to remove any fluid phase. Demisting can be achieved by ether a centrifuge demister or an impingement demister. The centrifuge type utilizes high velocities to separate the phases whereas the impingement device is composed of either a screen or series of condensing plates upon which the fluid phase condenses. The fluid phases are separated at the base of the tank by a weir [3], which causes the liquid phases to 慴ack-up,? separation of oil and water is achieved by differences in density. Water-free oil spills over the weir and is collected as gas- and water-free oil. 122

1

2 3

Figure 182. A generalized three phase separator (redrawn and modified after Jahn et al., 1998).

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Chapter 8—Production and Recovery

References Borah, I., 1992, Drill stem testing in Development Geology Reference Manual (M. Morton-Thompson and A. M. Woods, eds.): AAPG Methods in Exploration 10, p. 131-139. Breit, V. S., 1992, Enhanced recovery in Development Geology Reference Manual (M. Morton-Thompson and A. M. Woods, eds.): AAPG Methods in Exploration 10, p. 527-530. Dong, M., Q. Liu, and A. Li, 2007, Micromodel study of the displacement mechanisms of enhanced heavy oil recovery by alkaline flooding: SCA Annual Symposium, Calgary, Canada, September 9-13, in press. Holditch, S. A., 1992, Well completions in Development Geology Reference Manual (M. Morton-Thompson and A. M. Woods, eds.): AAPG Methods in Exploration 10, p. 457-541. Jahn, F., M. Cook, and M. Graham, 1998, Hydrocarbon Exploration and Production Developments in Petroleum Science 46: Elsevier, New York, 384 p. Jennings, J., 1992, Surface production equipment in Development Geology Reference Manual (M. Morton-Thompson and A. M. Woods, eds.): AAPG Methods in Exploration 10, p. 482-484. Liu, Q, 2006, Interfacial phenomenon in enhanced heavy oil recovery by alkaline flood, Ph.D. Thesis (unpub.): Faculty of Engineering, University of Regina, Canada, 234 p. Lancaster, D. E., 1992, Production testing in Development Geology Reference Manual (M. Morton-Thompson and A. M. Woods, eds.): AAPG Methods in Exploration 10, p. 474-476. Lynes United Services Ltd, 1981, Drill Stem Test Analysis and Interpretation: Calgary, 62 p. MMS, 2004, United States Department of the Interior Minerals Management Service, http://www.mms.gov/stats/PDFs/Milestones.pdf. Sam Sarem, A. M., 1992, Waterflooding in Development Geology Reference Manual (M. Morton-Thompson and A. M. Woods, eds.): AAPG Methods in Exploration 10, p. 523-526. Sills, S. R., 1992, Drive mechanisms and recovery in Development Geology Reference Manual (M. Morton-Thompson and A. M. Woods, eds.): AAPG Methods in Exploration 10, p. 518-522. Smallwood, D. D., 1992, Artificial lift in Development Geology Reference Manual (M. Morton-Thompson and A. M. Woods, eds.): AAPG Methods in Exploration 10, p. 485-487. Veldman, H., and G. Lagers, 1997, 50 years Offshore: Foundation for Offshore studies, Delft, 216 p.

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Chapter 9—Petrophysical Logs

Petrophysical Logs Introduction Log Petrophysical logging, wireline logging, and borehole logging are used as synonyms to describe the same thing. In the same way, the word log is used as a noun, verb, or adjective; here we will limit the term to the act of either recording depth-related information over time (verb) or to the actual recorded hard copy (or digital display) of the depth-based measurement! Logs are used to conduct subsurface correlations, to assist with structure and isopach mapping, help define physical rock characteristics (lithology, porosity, pore geometry, and permeability), and identify production zone thickness and determine the type of formation fluids. There are two basic types of wireline logging tool. Those that are designed to work in an 憃pen? uncased hole and those that are able to work within 慶ased hole.? Open hole logs are recorded in the uncased section of the well, usually at some intermediary depth or total depth (TD), prior to running casing. This is because some logging tools do not work well in cased holes. For example, microresistivity logging devices cannot work through casing, unlike acoustic (or sonic) tools. A useful basis for subdividing open hole wireline logging tools is on the basis of 憈ype? or 慹nd-use? (Alberty, 1992), which will be used here (Table 10).

Table 10. Basic open hole wireline tools by 憈ype?and 慹nd-use?(after Alberty, 1992). 慣ype?or 慹nd-use?

Wireline tool

Correlation and lithology Spontaneous potential Gamma ray Photoelectric effect Resistivity

Induction Laterlog Microresistivity

Porosity and lithology

Density Compensated Neutron Sonic Photoelectric effect

Auxiliary

Caliper Dipmeter Formation tester Core plug Borehole televiewer

The Borehole and associated environment Explanation of some symbols and terms When a borehole penetrates a formation, the character of the formation and the fluids within it are altered in the vicinity of the hole. The area immediately surrounding the borehole becomes contaminated with drilling fluid, with concomitant changes in resistivity. Such changes are constructively used to interpret the characteristics of both formation and the formation fluid(s). dh hole diameter Borehole diameters may increase or decrease for a given well section due to: (a) formation wash out, (b) sloughing, or (c) build-up of filtercake on the walls of porous formations. A caliper tool measures and records the size (diameter) of the borehole through an interval of depth. Rm drilling mud A pressure imbalance (i.e., overbalance) between the hydrostatic pressure of drilling fluid within the borehole and formation pressure will lead to the invasion of porous formational units by the drilling fluid. As invasion takes place, the solid material (e.g., gels or clay) from the drilling fluid infill the rock pore spaces and line the borehole wall with a gelatinous, sticky layer known as 慺iltercake,? the invading fluid (minus solids) is known as mud filtrate. Water saturation Water saturation (Sw) is the percentage of pore volume (within a rock) occupied by formation water. Irreducible water saturation (Sw irr) is the proportion of formational water that is adsorbed (physisorbed or chemisorbed) on mineral surfaces, or held within micro pores by capillary pressure. Conductivity Conductivity is the reciprocal of electrical resistance. Materials resist the flow of electricity differently in the reservoir, which is a function of porosity, fluid type, and rock type. For the basis of log interpretation, hydrocarbons and rock fabric act as insulators (non-conductive and highly resistive). In contrast, salt water is highly conductive.

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Invaded zone This is the immediate zone around the borehole that is invaded by mud filtrate; consisting of a flushed zone (Rxo) within which mud filtrate has flushed formation water and/or hydrocarbons from the formation, and a transition zone (Ri) in which a mixture of filtrate and formation fluids exists. Abbreviations and meaning The following diagram graphically sums, for a resistivity tool, the zones that typically exist within a porous and permeable formation. The abbreviations given in Figure 183 will be used throughout this review of petrophysical logs. dh

hole diameter

di Drj dj

radius of invaded zone

diameter of invaded zone (flushed zone)

diameter of invaded zone (invaded zone)

h mc thickness of filtercake ( mudcake) Rm resistivity of the drilling fluid Rmc resistivity of the filtercake Rmf

resistivity of the mud filtrate

Rs

resistivity of shale

Rt

resistivity of the uninvaded zone

Rw

resistivity of formation water

Rxo

resistivity of the flushed zone

Sw

water saturation (uninvaded zone)

Sxo

water saturation of the flushed zone

Figure 183. The borehole environment, notation and symbols (image ? 2005 Schlumberger, Ltd. used with permission).

Correlation and lithology logs Beyond the characterization of the reservoir and the fluids within it, there is a need to correlate between wells, define sequence boundaries, and identify common formations and marker zones. The logging devices in this category primarily serve that purpose.

Spontaneous Potential (SP) The SP log is used to identify impermeable (e.g., shale) and permeable zones (e.g., sand), and help determine Rw. This tool can only be used in the open hole containing a conductive drilling fluid (i.e., not oil-based mud). The SP log is a record of the DC voltage difference between the naturally occurring potential of a moveable electrode in the well bore and the potential of a fixed electrode located at the surface. Electric currents are generated between the conductive mud filtrate (Rmf ) and formation fluids (Rw) within permeable beds. Shale, due to its predominant clay content, acts as a cation membrane; that is it is permeable to cations (e.g., Na+) but not to anions (e.g., Cl-) due to the high negative charge on the lattice of clay minerals. The cations are able to move through the shale, that is from concentrated to dilute solutions (i.e., from salt to fresh) which creates a measurable potential within the borehole opposite the shale (by Na+). In contrast a negative potential is created within the borehole opposite a permeable formation. The presence of the Cl- anion generates a current, known as the SP current, which is measured in millivolts (mV). The overall effect is that the electrical potential is empirically related to formation permeability and the presence or absence of shale. The SP is influenced by bed thickness, bed resistivity, invasion, borehole diameter, shale content, and the ratio Rmf / Rw. The SP device has a vertical resolution of 6 to 10 ft (5.5 to 9.3 m) (Alberty, 1992).

Shale baseline and the SP curve The SP log is recorded on the left of the log, track 1. For a given borehole, the SP response is relatively constant opposite all shale units, which enables the logging engineer to set the log to read zero opposite shale, which creates the shale baseline (Figure 184). Permeable zones are indicated wherever the SP deflects from the shale baseline and permeable bed boundaries are drawn at the point of inflection. In water-bearing zones the amount of SP reduction is 125

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proportional to the amount of shale present within the formation. The SP also usually has lower amplitude within hydrocarbon bearing zones. Deflection of the curve from the shale baseline can be used to demarcate sand, sandstone, or limestone in normal conditions, i.e., the salinity of the formation water is greater than that of the filtrate (Alberty, 1992; Asquith and Krygowski, 2004). In a general way, curvature to the left suggests permeability, whereas curvature to the right indicates no permeability, i.e., the presence of shale or clay.

Gamma ray log The gamma ray curve is also placed in track 1. The scale, is given in API units, typically ranges from 100 to 150. Tracks 2 and 3 often contain porosity logs or resistivity logs. The gamma ray log is affected by borehole dimension, but because the gamma ray tool detects the presence of natural radioactivity it can be used in cased hole. The resolution of the gamma ray device is 2 ft (~0.6 m) with a radius of investigation half that value (Alberty, 1992), the gamma ray tool is typically combined with other devices (Figure 185).

Figure 185. Microresistivity and gamma ray tool (click to activate).

The gamma ray tool contains a scintillometer that detects the natural radioactivity (e.g., potassium) within a formation. Potassium (K40) is a common element within illite (but also occurs to a lesser extent within 憁ixed clays? , K-feldspar, mica, sylvite, carnallite, and glauconite. Thorium (Th232) occurs mainly in heavy minerals such as rutile, monzanite, and zircon, whereas uranium (U238) is often associated with phosphates or organic matter. Organic matter within shale may contain small amounts of highly radioactive elements, such as U and Th, the so-called 慼ot shales? within the North Sea are a known example of this phenomenon. Radioactivity can also be emitted from radioactive salts bound to the charged surfaces of clay minerals. The gamma ray tool generates a log that is commonly used for correlative purposes between wells and the log is also used to estimate the proportion of shale/clay minerals within a formation. Because shale usually contains a high proportion of radioactive elements and clean quartz-rich sandstones contain none; the gamma ray log is used to differentiate between shale and shale-free lithologies. As the shale content increases, so the gamma ray curve deflects to the right; in contrast, clean sands are indicated by a deflection to the left. However, sandstone may produce a deflection to the right if it contains feldspars, micas, glauconite, zircon, and/or uranium-rich waters. The gamma ray log is also affected by borehole dimension, but because the gamma ray tool detects the presence of natural radioactivity, it can be used in cased hole.

Figure 184. Example SP deflections from the shale baseline. The mud filtrate resistivity (Rmf ) is greater than that of the formation water (Rw) (from Asquith and Krygowski, 2004).

Volume of shale calculation The gamma ray log can be used to calculate the volume percent shale within a given formation, known as the shale volume (Asquith and Krygowski, 2004). The derivation of shale volume (Vsh) begins with the calculation of the gamma ray index (IGR) using the following formula (Schlumberger, 1974): (15)

where: IGR = gamma ray index GRlog = gamma ray reading from the log GRmin = minimum gamma ray reading (i.e., clean sand) GRmax = maximum gamma ray reading (shale) Once IGR has been calculated, there are two subsequent possible methods that can be used to derive Vshale; a linear and a nonlinear estimator (Alberty, 1992). The linear method is the most 126

Figure 186. Empirical correlations relating shale volume (Vsh) to gamma ray index (IGR) (after Larionov, 1969; Stieber, 1970; Clavier et al., 1971; Schlumberger, 1974; Western Atlas International, 1985; Bassiouni, 1994; and others).

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straightforward and can be used to derive a first order estimation of shale volume, where Vsh = IGR (Asquith and Krygowski, 2004). The nonlinear method applies an empirical correction (Figure 186), based upon clay content, formation age and geographic location, to derive Vsh (e.g., Larionov, 1969; Clavier et al., 1971). For further discussion please see Bassiouni (1994). Worked example (volume of shale): We will use the example log in Figure 187 and the procedure outlined above (Asquith, 1982; Alberty, 1992; Asquith and Krygowski, 2004). where:

GR

=

28 at 13,570'

GRmin =

15 at 13,590'

GRmax =

128 at 13,720'

log

IGR

=

(28 - 15)

(16)

(128 - 15) IGR

=

0.115

The calculated Vsh value is first located on the horizontal axis (Figure 186), ascending vertically and intercepting the appropriate curve, a 慶orrected? value of shale content (Vsh), depending upon geologic age and basin location, can be derived directly off the shale volume chart (Alberty, 1992; Asquith and Krygowski, 2004). A linear value of Vsh will be 11.5%, whereas 慶orrected? values will differ: for example: Vshale

= 5.7% (pre-Tertiary)

Vshale

= 2.8% (Tertiary)

or

Photoelectric log The Photoelectric effect (Pe) measures the ability of a formation to absorb gamma rays; an ability that varies from lithology to lithology. Because the tool requires contact with the borehole wall it is, therefore, a pad device (Alberty, 1992). The photoelectric index (Pe) records the absorption of low-energy gamma rays expressed in units of barns/electron (Doveton, 1994). The Photoelectric log is particularly useful in distinguishing between quartz sandstone, dolomite, and limestone, particularly in an alternating succession of sandstone and carbonate (Doveton, 1994). A cross-plot of Pe and potassium concentration, derived from a Natural Gamma Ray Spectrometry log (Figure 188) provides clay mineralogy information.

Figure 187. Example gamma ray log (track 1) and neutrondensity log (track 2) (after Asquith and Krygowski, 2004).

Figure 188. A crossplot of Pe (photoelectric factor) and %KNGScor (Natural Gamma Ray Spectrometry Log), showing the general plot areas associated various clay minerals (? 2005 Schlumberger, Ltd. used with permission).

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Resistivity Introduction Resistivity tools are used for correlation and commonly to: determine the water saturation (Sw) of a formation determine hydrocarbon versus water-bearing zones indicate permeable zones determine Rt. Resistivity and conductivity logging tools are connected to a source of power (i.e., generator), current is passed from the generator via tool electrodes though the borehole fluid into the formation and detected at the surface by a remote reference electrode. Because the rock fabric (i.e., minerals plus cement) is non-conductive, the ability to transmit an electric current is dependent up the formation fluid within the pores and capillaries (Video 23). Figure 189 and 190 show the resistivity profile for water-bearing and hydrocarbon-bearing formations, respectively. Note also the resistivity profiles for freshwater- or saltwater-based mud differ depending. Hydrocarbons are non-conductive (i.e., high resistivity) and saltwater is conductive. Therefore, in a water-bearing zone, where Rmf ~ Rw the resistivity response will be similar throughout each zone. In a hydrocarbonbearing zone, where Rmf > Rw, Rt should increase.

Figure 189. A resistivity profile for transitionstyle invasion within a water-bearing formation (from Asquith and Krygowski, 2004).

Video 23. A resistivity log response, from 揟 he Making of Oil? (? 1997b Schlumberger, Ltd. used with permission).

Figure 190. A resistivity profile for transitionstyle invasion within a hydrocarbon-bearing formation (from Asquith and Krygowski, 2004).

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There are three basic types of resistivity tool currently in use: induction laterlog microresitivity

Induction This tool consists of one, or more, transmitting coils that emit high frequency AC creating a magnetic field within the formation, which in turn induces currents that are detected by the receiver. This tool enables the determination of resistivity without the requirement for a direct electrical connection between tool and formation and can, therefore, work with non-conductive drilling fluids (Alberty, 1992). The received signals are proportional to the conductivity within a given zone. Focusing coils within the tool minimize erroneous signals from the invaded zone, borehole and adjacent beds, thereby allowing the derivation of the resistivity of the uninvaded zone (Rt). Also the tool allows for differing degrees of vertical resolution and depth of investigation. The induction tool is better applied where resistivities are lower, rather than higher since it is a conductivity device. Induction devices have evolved since their inception, from a single induction measurement run in combination with the older short-normal measurement, to the dual induction and more recently the newer array tools. The new array tools have more receivers and use computer algorithms to improve signal response.

Induction electric log This was a single induction device run in combination with the short-normal measurement. The induction log was a single deep induction measurement (RIL) with a short normal measurement (RSN). Because the short-normal can measure the resistivity of the invaded zone it remains in service (Asquith and Krygowski, 2004). Short-normal resistivity This tool measures the resistivity within the invaded zone (Ri). When the resistivity of the short normal log is compared to that of the induction log, for example, invasion is detected by the separation of the two curves. The presence of invasion is significant because it suggests the presence of a permeable formation. The short normal resistivity device has an electrode spacing of 16 inch (~40 cm), and has a resolution of 4 ft (1.2 m) or more. In contrast, the induction tool has a transmitter/receiver spacing of 40 inch (~100 cm) and can resolve a bed thickness of 5 ft (1.3 m). Salt-waterbased muds do not provide a suitable environment where Rmf ~ Rw.

Dual induction focused log This is the modern induction tool, capable of deep- (RILD), medium(RILD) for Ri, and shallow-reading (Rxo). The three resistivity curves on the dual induction focused log are recorded on a four-cycle log scale (e.g., 0 to 2000 ohm/meters) and correspond to tracks 2 and 3. If it is suspected that deep invasion of the formation has occurred by the mud filtrate, by using the data from all three readings in conjunction with a tornado chart (Figure 191 and covered later) a true value for Rt can be derived (Asquith and Krygowski, 2004). Induction tools may be run in air, oil, or foam filled boreholes since the induction system does not require the transmittance of electricity through the drilling fluid. Induction tools should be used in non-salt-saturated mud where Rmf > 3 Rw to obtain a more accurate value of true resistivity (Rt). Boreholes filled with a salt-saturated drilling mud (Rmf ~ Rw) require electric logs (e.g., Laterlog, or Dual Laterlog). The resolution of deep, medium, and shallow dual laterlog devices is 7 ft, 5 ft and 2.5 ft (1.8 m, 1.3 m and 0.6 m) respectively (Alberty, 1992). Bed boundaries Bed boundaries on a conductivity response occur half-way between the highest and lowest reading. For thin beds, the peak value represents the bed value. For thick beds with variable values, they are sometimes averaged. The short normal is another basic geological correlation tool and bed boundary are derived using the inflection point plus half the electrode spacing (8 inch or 20 cm)

129

Figure 191. Example Tornado chart (image ? 2005 Schlumberger, Ltd. used with permission).

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Laterlogs This logging device requires electrical contact with the borehole wall, which is achieved via the drilling fluid within the annulus (Alberty, 1992). Laterlogs are therefore suited to water-based mud (i.e., not oil invert mud), and designed to measure true formation resistivity (Rt) where Rmf ~ Rw. The laterlog tool should not be run with fresh-water mud where Rmf > 3 Rw (Asquith and Krygowski, 2004). Focusing is achieved by location of electrodes along the device and, therefore, laterlogs are associated with good vertical resolution (e.g., 60 cm) with a radius of penetration of 0.5 m; although depth of penetration can be dependent upon the state of the filtercake and depth of invasion. Invasion effects are corrected using a 憈ornado chart? (Figure 191), discussed later in the section Introduction to log interpretation.

Dual Laterlog The dual laterlog replaces the single laterlog device and consists of deep- (RLLD) and shallow-reading (RLLS) measurements. The log contains both curves in tracks 2 and 3, and gamma-ray in track 1. The microspherically focused device (MSFL) has electrodes within a pad that are forced against the borehole wall, thereby providing a very shallow reading of Rxo. When a dual laterlog-microspherically focused log combination is run, it is possible to correct for formation invasion using a tornado chart and derive Rt (Alberty, 1992; Asquith and Krygowski, 2004). The vertical resolution of deep, medium, and shallow laterlogs is 2 ft, 2 ft and 2 to 4 inches (60, 60 and 5 to 10 cm), respectively and the radius of investigation is 45, 16, and 1 to 2 inches (1153, 410, and 2.5 to 5 cm), respectively (Alberty, 1992).

Figure 192. The focusing pattern for a laterlog array device, Mode 0 measures mud resistivity. Modes 1 to 5 measure formation resistivities at different depths from the borehole. The red lines are the measure currents, and the white lines are the focusing currents (image ? 2005 Schlumberger, Ltd. used with permission).

Laterlog array This device delivers five independent, focused, higher resolution and depth matched measurements (Figure 192). The intention of this device is to better account for borehole effects, invasion and problems that arise from using laterlog and dual laterlog devices in thin beds (i.e., shoulder-bed effects).

Microresistivity Microresitivity devices are also of the pad-type (Figure 193) and therefore used specifically to estimate the resistivity of the flushed zone (i.e., Rxo), minimizing the effects of irregularities in borehole shape (Asquith, 1982; Asquith and Krygowski, 2004). When run with a deep penetrating tool, the influence of the flushed zone can be removed from readings of the deep device and a better understanding of Rt derived. This device, like most logging devices, combines resistivity and gamma ray determinations.

Microlog This pad-based device detects the presence of mudcake. By inference the presence of significant mudcake indicates that invasion has occurred and also suggests the presence of a porous formation (Asquith, 1982). However, this device does not work well in saltwater drilling fluids where Rmf ~ Rw or gypsumbased drilling fluids (Asquith and Krygowski, 2004). Microlaterlog, Proximity logs, and spherically focused logs are also derived from pad type logging devices. The typical vertical resolution of microresistivity devices is 2 to 3 inches (5 to 7.5 cm) with a radius of investigation of between 1 and 4 inches (1 to 10 cm) (Alberty, 1992). Figure 193. Pad configuration for a microresistivity tool showing current flow for: (a) microlog and (b) spherically focused log (from Asquith and Krygowski, 2004).

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Porosity and lithology logs The three types of porosity log include: Sonic logs Density logs Neutron logs

Sonic logs This is an open hole, borehole compensated, porosity log that measures the interval transit time ( t) of a compressional sound wave through the formation. The interval transit time ( t) is the reciprocal of matrix velocity and is therefore expressed in microseconds per unit distance. The acoustic 慶licks? emitted from the transmitter travel faster through formation than through the drilling fluid and are picked up by the receiver located on the same tool (Figure 194). Example values for t are (Wyllie et al., 1958): Lithology

sec/m

sec/ft

Dolomite Limestone Sandstone Anhydrite

143 156 182-168 164

43 47.6 55-51 50

Figure 194. A logging truck and sonic tool.

Because interval transit time is dependent upon rock type and rock density (i.e., mineral density and cement), and also by the fluid within the pores, it can, therefore, be related to formation porosity. Sonic logs (like all logs) are best used in conjunction with other logs (e.g., density, SP, resistivity). Sonic logs also work best in consolidated and compact formations. There are two types of sonic devices: the compensated compression wave sonic device and the full waveform sonic (FWS) device. The FWS device contains an array of receivers designed to detect shear velocities, this log is used by log analysts to determine the mechanical properties of the lithologies of interest. Sonic devices have a vertical resolution of 2 ft (~0.5 m) with a radius of investigation of 6 in. (~12 cm) (Alberty, 1992). For an excellent overview of the sonic log and the application of correction factors see Asquith and Krygowski (2004).

Formation density log The formation density tool is another 憄ad-type? device that measures the electron density of a formation. This tool consists of source (Cobalt-60 or Cesium-137) that emits medium-energy gamma rays into the formation. The gamma rays collide with electrons in the formation and lose energy and/or are scattered; redirected as a photon of reduced energy (i.e., Compton scatter), scattered energy is detected by the device. Compton scatter is a direct function of the number of electrons present within a formation (electron density) and, therefore related to bulk density (Kg/m3 or g/cc) (Alberty, 1992). This device is used to: determine formation porosities when lithology is known, determine lithology in conjunction with other logs, detect gas-bearing zones, and identify uncommon minerals in evaporite beds. Bulk density (pb) values for common reservoir minerals (with zero porosity) are: Mineral Dolomite Calcite Quartz Anhydrite

Actual density: p (Kg m3) 2870 2710 2648 2960

Detected density: pb (Kg m3) 2876 2710 2648 2977

Compensated neutron This is a neutron-emitting pad-type device. The neutrons are created from a chemical source within the sonde, which may be a mixture of americium and beryllium. This device responds to the hydrogen (H) ion concentration of a given formation as an amount of hydrogen per unit volume of formation. The emitted neutrons collide with H ion nuclei, pass into a thermal state, and undergo capture by a nucleus with the subsequent emission of gamma rays, which are in turn 131

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detected by the device. In a clean, shale-free, sandy formation filled with water or oil, the neutron device measures only liquid-filled porosity. Neutron porosity values will be lower in gas filled pores than in pores filled with either oil or water, this creates the so-called gas effect (Asquith, 1982). Neutron logs are also used to detect the presence of coal. Most neutron log curves are reported in either limestone or sandstone porosity units, whereas older logs may be reported in API units. This tool can be run in cased hole, however this device is very sensitive to hole rugosity (Alberty, 1992) and borehole size (corrected by caliper). Neutron log responses can also vary depending upon changes in lithology, mudcake thickness and formation fluid characteristics (filtrate/formation fluid).

Auxiliary devices Caliper tools This device is specifically designed to ascertain changes in borehole diameter and, to some extent, geometry. Caliper tools are extensible devices that have one, two, three, four, or six arms (Figure 195). Some caliper devices are cleverly arranged so as to ascertain two different measurements simultaneously; for example density log and caliper, where the tool ensures a good borehole wall contact for the emission of lower energy gamma rays and determines hole diameter. The extensible arms are spring-loaded, which are only extended during the retraction of the tool, and changes in hole rugosity are determined by a combination of extension and compression of the arms. Caliper logs are invaluable for assessing hole dimension, which is required for calculating cement volumes following the running of casing.

Figure 195. Four-arm caliper tool.

Formation tester/reservoir characterization instrument These devices are designed to measure the formation pressure, without having to resort to the expense of a full drill-stem test (DST). Because this is a wireline device several sequential tests can be conducted, in open hole, during a single tool run (Smolen, 1992). Formation testers permit variations in pressure among various formations to be determined. Formation testers are specifically useful in measuring reservoir pressures, information that can be used to determine the existence of reservoir compartmentalization (Video 24). An important feature of the formation tester is the ability to obtain an actual fluid sample, via a chamber that has a capacity of 40 liters in the larger tools (Smolen, 1992).

Video 24. Animation showing a repeat formation tester, from 揟 he Making of Oil? (? 1997b Schlumberger, Ltd. used with permission).

Dipmeter This pad-type device is specifically designed to determine the angle of formation dip and provide the nature and orientation of planar surfaces, such as faults and bedding planes (Goetz, 1992). Dipmeters (Figure 196) are comprised of three or more extensible arms, each bearing an identical sensor. A bedding plane or fault crossing the borehole at an angle would generate measurable anomalies at each sensor, which would register against differences in depth (Figures 197, 198). The usual measurement is microresistivity (Goetz, 1992). The true orientation of the device is achieved through the use of three orthogonally mounted magnetometers and accelerometers. Several properties can be derived from a dipmeter determination, such as the orientation of subsurface bedding, lamination thickness and regularity, layering contrast and continuity, and the presence of flaser and load structures. Most data, once processed by the engineer, is presented as either an arrow or tad-pole plot (Figure 198). The position of the 慴ody? against a vertical scale indicates dip, whereas the orientation of the tail indicates the direction of strike (Goetz, 1992).

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Figure 197. A six-arm, dipmeter log (from Goetz, 1992).

Figure 196. A four-arm dipmeter tool showing relevant orientation measurements (from Goetz, 1992).

Figure 198. Dip data on an arrow plot (left) and the corresponding structure shown as a sketch section (from Goetz, 1992).

Borehole imaging devices The televiewer The televiewer is an acoustic reflection device that uses a rotating ultrasonic transducer as the imaging unit. High frequency waves, ranging from 200 kHz to 1 MHz, are bounced off the borehole wall, detected by the device and relayed to a surface computer (Luthi, 1992). The transducer(s) can be deployed as 慺ocused? or 憉nfocused? and rotate at between 3 to 16 rotations per second. True orientation of the device (i.e., a constant reference) is obtained by use of a magnetometer. The televiewer can (a) (b) provide two basic types of log; one that is Borehole televiewer televiewer images images showing showing (a) (a) aa fracture fracture (arrow) (arrow) based upon reflected wave amplitude, and a Figure Figure 199. 199. Borehole and (b) (b) drill drill marks marks (arrow) (arrow) (from (from Luthi, Luthi, 1992). 1992). second that is based upon two-way travel time. and Images derived from a televiewer (Figure 199) 133

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are typically in gray scale; darker tones of gray representing lower reflected amplitudes (i.e., density) and higher twoway travel times (i.e., distance). The televiewer is essentially a device that provides a continuous 360o surface measurement of the borehole wall, and provides information on the presence of lithologic fractures (Figure 199a), borehole geometry, and bedding planes. However, artifacts such as drill marks (Figure 199b), and hole rugosity can effect performance. The two-way travel times provide a measure of borehole dimension, useful for wellbore volume calculations (Luthi, 1992).

Depiction of borehole images Before progressing much further, it is worth considering what the image in Figure 199 represents and the orientation of that feature in the subsurface! Does the fracture represent a planar surface or a tightly folded surface? A study of Figure 200 will help! Images derived from imaging devices (e.g., televiewer and formation microscanners) are unfurled 360o depictions of the inside of the borehole and orientated according to azimuth. Unfurled images typically contain azimuthal data (Figures 199b, 200). A planar feature (e.g., fracture, fault) therefore, would have a sigmoidal appearance; the angle of dip derived by the amplitude and orientation by noting the bearing associated with the features of interest or the maxima and minima of a Figure 200. The depiction and orientation of borehole images curved surface (Serra, 1984; Serra, 1989; Dueck and (after Serra, 1984; Serra, 1989; Dueck and Paauwe, 1994; Hurley, 2004; and others). Paauwe, 1994; Hurley, 2004).

Electrical borehole scanning ®

Formation Microscanner (FMS) and ® Fullbore Formation MicroImager (FMI) are trade names for electrical borehole imaging devices and represent a development of the dipmeter and microresistivity device previously discussed. Electrical borehole imaging devices typically have four or more extensible arms that have an array of electrodes; there are 64 electrodes on the FMS tool and 191 on the FMI tool; each electrode is 0.2-in. diameter, and individually monitored. As either tool is tracked up the borehole, the amount of current emitted from Video 25. An electrical borehole scanning device, from 揟 he Making of each electrode is recorded as a function of Oil? (? 1997b Schlumberger, Ltd. used with permission). azimuth and depth. Each array, therefore, produces a microresistivity 慽mage? of the borehole wall (Video 25). Earlier devices had two to four pads, and provided a discontinuous unfurled image (Figure 200). More recent tools, however, have more pads and even additional 慺lip-out? pads that provide a full 360o coverage, for a given nominal borehole size (Luthi, 1992). Early FMS images were gray scale in which the darker tones represented lower resistivities. However, the current trend is towards color enhanced images, with the most conductive events identified as black and the most resistive as lighter colors (Figures 202, 203). Like the acoustical televiewer device, the electrical borehole-imaging device is also subject to minor problems, such as pad 憇tand-off? (due to mudcake) and is sensitive to minor changes in tool speed (Luthi, 1992). However, that said, this electrical device has been capable of not only imaging fractures and bedding planes, but, because of the fine spacing of the electrodes it has been capable of detecting unconformities, the presence of stylolites, cross-bedding, erosional surfaces, and finely intercalated formations (Figures 201 and 202). Using such a device to recognizing specific sedimentological features, subtle plays such as the Middle Devonian channel sands have been followed and successfully exploited within the Mitsu field of Alberta, Canada (Dueck and Paauwe, 1994), a play that would have otherwise proven difficult.

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Figure example FMI log used used to to track track Figure 201. 201. An An example FMI log channel the Mitsue Mitsue Field, Field, Alberta, Alberta, channel sands sands in in the Canada courtesy of GlenofIsle Glen Exploration Canada (image (image courtesy Isle Ltd. and by authority of the of Exploration Ltd. and by Canadian authoritySociety of the Petroleum Geologists).

Figure 202. FMI images showing different sedimentological structures: top left shows a collapse breccia, top right vuggy limestone, lower left shows slumped sandstone and lower right shows a turbidite deposit (image ? 2005 Schlumberger, Ltd. used with permission).

Nuclear magnetic resonance logging Background The nuclear magnetic resonance (NMR) device is relatively new and provides a lithology-independent measure of effective porosity, total porosity, and differentiates between irreducible and moveable (i.e., 慺ree? water (Stambaugh, 2000). Formation fluids contain differing amounts of hydrogen that varies with composition (e.g., oil versus water) and physical state (i.e., gas and fluid). All hydrogen nuclei are spin, although in the natural state the spin orientation is random and the net magnetization is zero. However, when a strong external magnetic field (from the NMR device) passes through the formation, the protons are aligned or polarized. The state of polarization increases exponentially in time (Freedman, 2006). An antenna in the NMR device emits a pulsating radio frequency that induces a magnetic field causing the spin-axes to tip away from the original (i.e., polarized) alignment. When the antenna is turned off and the magnetic pulse is removed, the resonance relaxes and the signal decays (Henderson, 2004), producing a signal called the spin echo. Repeated pulses create a spin echo train which is used to interpret fluid and formation properties. The polarization time is known as Tp and the time constant used to characterize the magnetization buildup is known as T1, whereas T2 represents the transverse decay time, commonly known as relaxation time (Henderson, 2004; Freedman, 2006). For a given fluid type, T2 has been shown to be proportional to pore size, in which micropores are associated with the fastest relation times compared to free fluids and fluids within larger pores (Stambaugh, 2000; Henderson, 2004); in this way NMR logs can be used to differentiate between irreducible and free-water (Figure 203).

Figure 203. Hypothetical T2 distribution, showing partitioning of the T2 distribution into irreducible and free water using empirically determined cutoffs. For sandstone 慉? is 33 ms, whereas the cutoff for limestone is 100 ms (after Schlumberger; Halliburton; Freedman, 2006; and others).

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Application Reservoir fluids possess different polarization times (T1) and relaxation times (T2). In this way NMR logs can be used to characterize and differentiate between formation fluids (e.g., oil/water), and for a given formation fluid (i.e., water) determine the presence of clay-bound, capillary-bound, and free water. More recently, NMR logs have been used to provide estimates of pore-size distribution, grain size (clastic reservoir) and estimates of permeability (Henderson, 2004; Freedman 2006).

Sidewall coring devices A sidewall coring device allows small (e.g., 3 5 cm) solid plugs of selected lithologies to be obtained from predetermined depths, without the high cost of traditional coring. The sidewall device may be capable of obtaining more than two dozen sequential core plugs in a single tool-run. The location of each core plug is pre-selected and recorded. This device represents and excellent option for the visual confirmation of lithologies, the determination of laboratory porosity and permeability measurements, or scanning electron microscope analysis, etc., on actual rock material.

Cased hole tools There are many good reasons why it might be necessary to run logs in cased hole, for example; the need to check the integrity of cement through casing, the existence of an unstable or overpressured formation, or perhaps there were changes in formation property since the casing or liner was set. However, not all tools can be run in cased hole. Devices that can be run inside casing, include the gamma ray (and spectra log) and various neutron devices. These devices have been discussed. However, one tool that is gaining popularity is the pulsed neutron tool. As the name implies, pulses of high-energy neutrons are emitted from a source within the tool, pass through the casing and bombard the formation. When the neutrons are captured within the formation, gamma rays are emitted, which are, in turn, detected by the tool (a gamma-ray spectrometer). The prime use for this tool is the derivation of the distribution of the elements carbon and oxygen by bombardment neutrons of specific energy

Logging tool suitability Logging tools are designed to be run for only a limited range of borehole size and condition, either because of the diameter of the tool (minimum borehole size), or because of the limitations of the extensible arms (max. size). Not only that, but some tools are not suited in some invert mud systems, also some tool combinations do not work well. Table 11 is quick-check tool table (Alberty, 1992). Table 11. A tool reference table: where ? ?favorable, ? ?marginal and ? ?unfavorable (from Alberty, 1992).

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Introduction to log interpretation Example use of charts and nomograms Formation temperature (Tf ) Temperature increases with increasing depth. The resistivity of a fluid (i.e., formation waters) decreases with increasing salinity and increasing temperature and therefore, corrections must be applied. Schlumberger Gen-6 chart (Figure 204) will be used in this worked example. Please refer to Figure 204. Temperature scales are along the bottom and the top of the chart, representing measured bottom hole temperatures for mean surface temperatures in either Fahrenheit or Celsius respectively. The oblique blue lines running diagonally across the chart are geothermal gradients (assumed to be linear). Depth is on the ordinate. Example Total depth 5,175m (~15,000 ft), mean surface temperature is 16 oC (80 oF), the bottom hole temperature is 98 oC (~200 oF), and the depth of interest is 3,050 m (~10,000 ft). Locate the respective temperature scale of interest (i.e., either Fahrenheit or Celsius indicated by a short red arrow). Locate the bottom hole temperature in either Celsius of Fahrenheit (circled in red). Locate the total depth. Descend (Celsius) or ascend (Fahrenheit) along the appropriate (solid green) line to the line representing the total depth value, selecting the (diagonal) geothermal gradient that bisects that point. The indicated geothermal gradient in this example is 1.82 oC/100 m (1.0 oF/100 ft). Ascend along that gradient to 3,050 m (~10,000 ft) and ascend or descend vertically intercepting the corrected temperature (Tf) of 75 oC or 175 oF representing the formation temperature at 3,050 m (~10,000 ft) respectively.

Figure 204. Chart for estimating geothermal gradient and formation temperature (image ? 1997a Schlumberger, Ltd. used with permission).

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Temperature correction for resistivity The resistivity of a fluid (i.e., brine) measured at the earth抯 surface is different to that measured at depth, and since resistivity changes with temperature, therefore a correction must be applied to derive an accurate value for Rm at a specific depth of interest. It is assumed that when the temperature of a solution is increased the salinity stays constant. We will use the Schlumberger chart GEN-9 to correct Rm (Figure 205). Example: Resistivity of drilling fluid is 0.06 ohm-m at 139 oF. What is Rm at 179 oF? Using GEN-9 (Figure 205), locate 0.06 ohm-m at 139 oF on the vertical and horizontal axes respectively. Draw a vertical line connecting the two values (i.e., 0.06 ohm-m at 139 oF), from the horizontal axis (i.e., arrow 慳? . The intercept of 0.06 ohm-m at 139 oF is on the salinity line of 60,000 ppm (dark blue line). Descend diagonally (arrow 慴? to a new intercept of 179 oF along that line and read off the new value for Rm along the vertical axis (i.e., arrow 慶? , which is 0.048 ohm-m.

Figure 205. Resistivity/temperature correction chart, Gen-9 (after Schlumberger; image ? 1997a Schlumberger, Ltd. used with permission).

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Chapter 9—Petrophysical Logs

Invasion correction charts (tornado diagrams) Invasion correction charts are used to determine the depth of invasion (di), the Rxo/Rt ratio, and the true resistivity of the formation Rt(cor.). It is assumed that the contact between the invaded zone and uninvaded zone is sharp, and resistivity measurements have been corrected (Asquith, 1982). To use this diagram, enter the abscissa and ordinate with the required resistivity ratios; the point of intersection defines the depth of invasion di, the Rt/Rxo ratio, and Rt. Example Given data: depth 2615 m (8580 ft), borehole diameter is 203 mm (8 inch), filled with a salt mud system. Data from a Laterlog: LLLD = 35 ohm-m, LLLS = 15 ohm-m, Rxo (from MSFL) = 4 ohm-m. To derive Rt(cor.) we use a tornado diagram specific to the diameter of the borehole and drilling fluid type (e.g., salt mud system). In this example we will use the Schlumberger Chart Rint-9 (Figure 206). You may wish to compile a data table like this, either hand calculating various ratios or use the math function in a spreadsheet (suggested method).

Calculate values (RLLD/RLLS) and (RLLD/RXO), use those calculated values to determine Rt/RLLD from the tornado chart (i.e., the red solid lines, ~1.39), Rt/Rxo using the solid blue lines (~12.5), and di using the dashed blue lines (~50 in. or 1.27 m). Use Rt(cor.) and Rxo to calculate Rxo (cor.).

Figure 206. A tornado diagram for determining depth of invasion and correcting Rt and Rxo (after Schlumberger; image ? 1997a Schlumberger, Ltd. used with permission).

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M-N plots for lithology The estimation of lithology using the M-N plot necessitates obtaining data from the Neutron and Sonic logs, and calculating coordinates for the relevant M-N* cross plot (Figure 209) which contains lithology specific regions . Data points that plot away from those regions are indicative of either a mixed lithology or porosity infilling. All data points are plotted directly on the M-N* plot! The values for M and N are calculated using the following:

(17)

where:

tf = transit time for drilling fluid pb = interval bulk density (from log) Nf = neutron density for drilling fluid

t = interval transit time (value from log) pf = bulk density for drilling fluid N = interval neutron density (value from log)

Example: Given data: tf is 185 (value for salt mud), pf is 1.1 gm/cc, Nf is 1.1 (value for salt mud), t is 60, N is .16, and pb is 2.70 g/cc, depth 9210 Using the given values for N, t, and pb, calculate the values for M and N. Apply your calculated M ? N values directly on the cross plot (Figure 207). Your values should indicate a dolomite with an anhydrite infilling.

Figure 207. Chart for estimating lithology, M-N plot (image ? 1997a Schlumberger, Ltd. used with permission).

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Porosity Many would agree that the most reliable determination of porosity involve combinations of two or three different measurements. Cross plots are graphical solutions using two or three parameters to estimate formation lithology and porosity. The specific choice of cross plot depends upon the salinity of the drilling fluid (i.e., fresh/salt), the type and age of the logging device, and the terms used for apparent limestone porosity (e.g., NPHI or TPHI). The example given here uses data derived from the Combination Neutron-Density log (Figure 208). Example :

Give data: given values for CNL is 23pu (apparent limestone porosity), bulk density (Pb) is 2.42 g/cc or Mg m3. Using a fresh-water based mud system where Pf =1.0 gm/cc, refer to Figure 210 (Schlumberger CP-1c). Use the given values to determine the point of intersection, at the point intersection read the lithology (mineralogy) and porosity ( ) for that depth.

Figure 208. Chart for estimating lithology (mineralogy) and porosity (image ? 1997a Schlumberger, Ltd. used with permission).

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Water resistivity (Rw) and water saturation (Sw) There are a number of methods to derive Rw (Asquith and Krygowski, 2004), although only the Archie equation will be discussed here.

Archie method for Rw Archie demonstrated (Archie, 1942) that the resistivity of a given water-filled formation (Ro) can be related to the resistivity of the formation fluid by using a constant (F), which he termed the formation resistivity factor (ibid). Ro = F

Rw

(18)

If using the Archie method, the zone chosen should be 100% water saturated, contain no clay, free from shoulder effects, and must have a porosity log available (Peveraro, 1992). Archie showed that the formation resistivity factor (F) was related to porosity ( ): (19)

Where: a m

= porosity = tortuosity factor = cementation exponent

Because m and a are interdependent upon each other, i.e., as a increases so typically does m (Asquith and Krygowski, 2004). The Archie equation can be reduced to (Peveraro, 1992): Rw =

Rt

(20)

Water Saturation Sw Water saturation probably represents the most fundamental parameter used in log evaluation. As discussed in previous chapters, water volume greatly affects the economics of a given reservoir. Sw can be calculated from Ro (i.e., wet resistivity of the formation) and Rt (the resistivity of the uninvaded zone) (Archie, 1942; Asquith and Krygowski, 2004). (21)

where: Sw Rw Rt n

= = = =

water saturation resistivity of the formation fluid (water) true resistivity of the formation saturation exponent (normally 2.0)

The Archie equation has been modified, often because of a, m, and n. Because the tortuosity factor a, saturation exponent n, and the cementation exponent m vary with lithology, age, and degree of compaction. They have, therefore, been empirically summed by a number of workers into a series of Formation Factors (F). For example:

for carbonates F = 1/

2

for consolidated sandstones F = 0.81/

2

for sands (i.e., unconsolidated) F = 0.65/

2.15

Combining equations 18 and 21 gives the common form of the Archie equation for water saturation Sw (22)

where: Sw Rw Rt F n

= water saturation = resistivity of the formation fluid (water) = true resistivity of the formation = Formation factor = saturation exponent (normally 2.0)

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Chapter 9—Petrophysical Logs

References Alberty, M. W., 1992, Basic open hole tools in Development Geology Reference Manual (M. Morton-Thompson and A. M. Woods, eds.): AAPG Methods in Exploration 10, p. 144-149. Archie, G. E., 1942, The electrical resistivity log as an aid in determining some reservoir characteristics: Journal of Petroleum Technology, v. 5, p. 54-62. Asquith, G., 1982, Basic well log analysis for geologists: AAPG Methods in Exploration 3, 216 p. Asquith, G., and D. Krygowski, 2004, Basic well log analysis, 2nd Edition: AAPG Methods in Exploration 16, 244 p. Bassiouni, Z., 1994, Theory, measurement and interpretation of well logs: Society of Petroleum Engineers, Richardson, TX, 372 p. Clavier, C., Hoyle, W., and Meunier, D., 1971, Quantitative interpretation of thermal neutron decay logs, Part I: Fundamentals and techniques: Journal of Petroleum Technology, v. 23, June, p. 743-755. Doveton, J. H., 1994, Geologic log interpretation: SEPM Short Course no. 29, Society for Sedimentary Geology, Tulsa, Oklahoma, U.S.A., 166 p. Dueck, R. N., and E. F. W. Paauwe, 1994, The use of borehole imaging techniques in the exploration for stratigraphic traps: an example from the Middle Devonian Gilwood channels in north-central Alberta: Bulletin of Canadian Petroleum Geology, v. 42, no. 2, p. 137-154. Freedman, R., 2006, Advances in NMR Logging: Journal of Petroleum Technology, SPE 89177, p. 60-66. Goetz, J. F., 1992, Dipmeters in Development Geology Reference Manual (M. Morton-Thompson and A. M. Woods, eds.): AAPG Methods in Exploration 10, p.158-162. Henderson, S., 2004, Nuclear magnetic resonance logging in Basic well log analysis, 2nd Edition, (G. Asquith and D. Krygowski, eds.): AAPG Methods in Exploration 16, p. 103-113. Hurley, N., 2004, Borehole images in G, Basic well log analysis, 2nd Edition, (G, Asquith and D. Krygowski, eds.): AAPG Methods in Exploration 16, AAPG, p. 151-163. Larionov, V. V., 1969, Theoretical studies on the effect of conditions prevailing during borehole measurements on the configuration of curves obtained by the gamma method: (in Russian) Tr., Mosk. Inst. Neftekhim. Gazov. Prom., no. 89, p.122-132. Luthi, S. M., 1992, Borehole imaging devices in Development Geology Reference Manual (M. Morton-Thompson and A. M. Woods, eds.): AAPG Methods in Exploration 10, p. 163-166. Peveraro, R., 1992, Determination of water resistivity in Development Geology Reference Manual (M. MortonThompson and A. M. Woods, eds.): AAPG Methods in Exploration 10, p. 170-173. Schlumberger, 1974, Log interpretation manual/applications, vol II: Houston, Schlumberger Well Services, Inc. Schlumberger, 1997a, Log interpretation charts: Sugarland, Texas, Schlumberger Wireline and Testing, SMP-7006. Schlumberger, 1997b, The Making of Oil: Schlumberger Wireline and Testing, Sugarland, Texas. Schlumberger, 2005, On-line Glossary: http://www.glossary.oilfield.slb.com/ Serra, O., 1984, Fundamentals of well-log interpretation: 1: the acquisition of logging data, (Translated by Westaway, P. and H. Abbott): Developments in Petroleum Science, 15A, Elsevier Science Publishers, Amsterdam, 423 p. Serra, O., 1989, Formation Micro Scanner Imager Interpretation: Schlumberger Educational Services, Schlumberger Ltd., 117 p. Smolen, J. J., 1992, Wireline formation testers in Development Geology Reference Manual (M. Morton-Thompson and A. M. Woods, eds.): AAPG Methods in Exploration 10, p. 154-157. Stambaugh, B. J., 2000, NMR tools afford new logging choices: Oil and Gas Journal v. 98, p. 45-52. Stieber, S. J., 1970, Pulsed neutron capture log evaluation in the Louisiana gulf Coast: SPE 2961, presented at the 1970 SPE Annual Meeting, Houston, Oct. 4-7. Western Atlas International, Inc., 1985, Log interpretation charts: Houston, Texas, Western Atlas, 300 p. Wyllie, M. R., A. R. Gregory, and G. H. F. Gardner, 1958, An experimental investigation of the factors affecting elastic wave velocities in porous media: Geophysics, v. 23, p. 459-493.

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