Oil, petroleum, hydrocarbon ... .words that have become popular in our ,Petroleum is used in manufacturing a wide variety of materials. ....Find out which countries produce the most oil and where to pursue oil and gas jobs worldwide. Petroleum career information and oil job postings.... Oil explorationdeveloped in many parts of the world with the Russian Empire, particularly the .. .... Not allexploration wells drilled result in the discovery of oil and gas. The success rate ..A monthly magazine offering industry news, statistics and technical editorial to the oil and gas drilling, exploration and production industry,You will find definitions of terms highlighted in bold in the glossary towards the end of this unit (use the 'Jump to' facility on the navigation bar above).
Oil and gas seeps have been known since earliest recorded history. Sticky black asphalt was used by the Babylonians as a roofing material, the ancient Egyptians used it to preserve their dead, and Noah supposedly caulked his Ark with it. In Azerbaijan gas seeps have burned for centuries, and therefore it is perhaps surprising that the world's first major underground oilfield was discovered in Pennsylvania, USA only as recently as 1859. That discovery launched an era in which the world became increasingly reliant on cheap energy provided by oil and gas, a reliance assured by the inventi
on of the internal combustion engine in the late 19th century. Only now, as the issues of long-term sustainability and climate change become more apparent, are we beginning to think about unshackling ourselves from that dependency.
This unit begins by examining the geological characteristics of petroleum and the key ingredients necessary to form oil and gas accumulations. Then there is a brief description of industrial operations during the life cycle of an oilfield, starting with subsurface analysis and exploration drilling. The unit also highlights the role of safety and environmental management as an integral part of the petroleum business and concludes with a short review of global resources and non-conventional petroleum.
When you have completed this unit, you should be able to explain in your own words, and use correctly, all the bold terms printed in the text. You should also be able, among other things, to do the following:
• Interpret graphs and evaluate tables of data relating to different aspects of petroleum.
• Given basic geological information for a petroleum play, recognise the main ‘ingredients’ (petroleum charge, reservoirs, seals and traps) that contribute to its potential.• Understand the roles played by different means of exploration in contributing to defining a petroleum play, and its evaluation.
• Describe the various options for petroleum production in different settings.
• Discuss the various hazards to operators and the environment that are presented by exploiting petroleum reserves.
• Understand the criteria used in assessing petroleum reserves globally and in the UK.
• Discuss the conditions under which unconventional petroleum resources form, and the requirements for their future exploitation.
1 The chemistry of petroleum – what is petroleum?
Petroleum is the term for a complex mixture of hydrocarbons and lesser quantities of other organic molecules containing sulphur (S), oxygen (O), nitrogen (N) and some metals. Hydrocarbons are compounds that contain only hydrogen (H) and carbon (C) atoms and the number of carbon atoms in a compound determines its physical properties. For example, simple compounds such as methane (CH4), ethane (C2H6), propane (C3H8) and butane (C4H10) all have boiling temperatures below 0 °C and are therefore gases under ambient (surface temperature and pressure) conditions. Larger, more complex hydrocarbon compounds ranging from pentane (C5H12) to hexadecane (C16H34) are liquids under ambient conditions, whilst even larger compounds with a high molecular weight form waxy solids.
The molecular arrangement of hydrocarbon compounds is highly variable. The most commonly occurring forms are chemically stable, so-called saturated compounds known collectively as paraffins and cycloparaffins. A second group, in which the bonding arrangement is more complex and potentially less chemically stable, comprises unsaturated compounds called aromatics and alkenes. Aromatic compounds such as toluene (C6H5CH3) rarely amount to more than 15% of petroleum but they may impart a pleasant odour, hence their name.
Petroleum occurs naturally in several forms: natural gas – mainly gaseous hydrocarbons but also containing variable amounts of carbon dioxide; a liquid, called crude oil, that typically contains a very wide range of hydrocarbon compounds; and solid bitumen. Bitumen contains the heaviest (in the sense of high molecular weight) and most complex hydrocarbon compounds found in petroleum, and they are relatively enriched in oxygen, sulphur and nitrogen. The composition of typical petroleum samples are shown in Table 1. Note that oxygen is a significant impurity in bitumen, but is commonly found only in trace amounts in crude oil and natural gas. In contrast, nitrogen is negligible in bitumen and crude oil, but may constitute up to 15% in natural gas.
Table 1: Composition of typical petroleum samples.
Element
Natural gas/weight%
Crude oil/weight%
Bitumen/weight%
carbon
65.0–80.0
85.0
80.2
hydrogen
20.0–25.0
12.0
7.5
oxygen
trace
>2.0
7.6
nitrogen
1.0–15.0
>1.5
1.7
sulphur
>0.2
>3.0
3.0
2 Key ingredients for petroleum accumulation
2.1 Petroleum charge
There are several ‘ingredients’ or geological conditions that are prerequisites for every subsurface accumulation of petroleum. They are petroleum charge , reservoirs, seals and traps. We will look at each of these in turn in the following sections.
Petroleum charge is an abstract concept concerning the likelihood that petroleum can form, migrate and accumulate in a body of sedimentary rocks. It depends on interactions that involve a number of factors, i.e. it concerns a dynamic system in a sedimentary basin.
An effective petroleum charge system requires:
•
A source rock rich in organic debris that could potentially generate liquid and/ or gaseous hydrocarbons – petroleum;
•
Changes in temperature and pressure through time that induce the organic debris to undergo chemical reactions that produce petroleum fluids: the source rock must mature;
•
A pathway along which petroleum fluids can migrate. As hydrocarbons are less dense than water they migrate upwards, and sometimes sideways toward the Earth's surface, through water-saturated permeable rocks;
•
An impermeable rock or seal, somewhere along the migration pathway, beneath which the hydrocarbons can become trapped.
If all these factors combine, then hydrocarbons start to fill up or charge the pore spaces in a reservoir rock. To understand petroleum charge geoscientists need to consider the nature of source rocks, maturation and its timing, and migration, and we will look at each of these in turn.
2.1.1 Source rocks
Source rocks are sediments that contain sufficient organic matter to generate petroleum when they are buried and heated. Under normal conditions very little dead plant and animal tissue is preserved in sediments. Higher concentrations tend to occur only in environments where there is unusually high productivity of organic matter, such as in coastal upwellings, shallow seas, mires and lakes. Even then, the organic matter reaching the sediment–water interface must be protected from scavengers or aerobic bacteria. If not, these microorganisms use enzymes to digest and oxidise most of the organic matter completely to produce carbon dioxide and water. Under these circumstances there is clearly no potential for the sediments to preserve sufficient hydrocarbons to constitute a source rock.
The preservation of organic matter under reducing conditions is a common factor underlying the formation of both petroleum source rocks and coal. However, most petroleum source rocks form under water, unlike coals that are almost entirely products of organic accumulations at the land surface, albeit in very wet conditions. Note that coal does generate methane and coal deposits have given rise to natural gas resources, for instance those beneath the southern North Sea. So coal can be a petroleum source rock, but usually for gas fields. Petroleum source rocks can form on the beds of freshwater lakes and brackish lagoons, but the most important ones are marine.
There have been prolonged but isolated periods in the geological past when ocean water did not circulate as it does now. Under these conditions oxygen did not reach the sea floor, leading to widespread anoxia there. Decomposition by anaerobic bacteria involves chemical processes of reduction that produce methane and hydrogen, along with hydrogen sulphide, carbon dioxide and water, but leave a residue of organic compounds that are enriched in carbon and have high molecular weight. If enough organic matter has been buried, this leads to a concentration of hydrocarbons within the source rock. Since anoxia is characterised by stagnant water – currents would bring in oxygen – source rocks are products of very low energy deposition.
What kind of sediments are likely to form under such quiet conditions?
Answer
They will contain very fine grains, mainly clay minerals, and will form mudstones (an example is shown in Figure 3a).
End of answer
Anoxic conditions can also occur on a smaller scale where water circulation is restricted. For example, the present-day Oslo Fjord, Norway has an anoxic bottom layer because a shallow lip of rock prevents water from the Skagerrak from circulating around the fjord. The bottom waters of the Black Sea are also strongly reducing because it is essentially a stagnant saline lake.
Another setting that encourages preservation of organic matter is provided by shallow, often land-locked seas in tropical or subtropical latitudes. Evaporation produces a highly saline surface water layer that is denser than the underlying water column and so it sinks to form a salty layer immediately above the sea floor. Organic material derived from plants and animals that thrive in the normally saline water column sinks onto the salty sea bed. Here it remains undisturbed as only rather specialised bacteria survive in this environment. The Dead Sea is a modern example of such a system.
2.1.2 Kerogen
Organic material in buried sediments is called kerogen, a word derived from the Greek for ‘wax producer’. The concentration of kerogen in a potential source rock is usually expressed in terms of the percentage, by weight, of organic carbon in the rock. Rocks with more than 0.5% organic carbon may be effective source rocks, but prolific source rocks have more than 5% and occasionally much higher concentrations of kerogen. The world's first commercial petroleum products to be created on a large scale – in 1850 – were from black ‘oil shales’ that outcrop in the Scottish Midland Valley. These shales, or mudstones, contain more than 15% of kerogen, and when heated in sealed vessels by James ‘Paraffin’ Young they yielded the light liquid hydrocarbons from which he got his nickname.
Conventionally, kerogen is subdivided into four main types on the basis of its chemical composition, which reflects its original source material. Each type has characteristic ratios of carbon, hydrogen, and oxygen and they each generate contrasting petroleum products when they mature. Table 2 highlights the major differences between the four kerogen types in terms of their chemical properties and biological origins. Type I kerogen is comparatively rare as it is derived mainly from algal sources in lake and/or lagoonal environments: the Scottish Midland Valley ‘oil shales’ used by ‘Paraffin’ Young contain kerogen of this kind. Type II kerogen, the most abundant, is typically derived from plant debris, phytoplankton and bacteria in marine sediments; it is the common source of crude oil but also yields some natural gas. Type III kerogen comes mainly from remains of land plants found in coals and it principally generates natural gas. Type IV kerogen includes oxidised plant remains and fragmentary charcoal derived from forest fires; it has virtually no petroleum potential being devoid of hydrogen.
Table 2: Characteristics of the main types of kerogen.
Kerogen type
H:C ratio
O:C ratio
Origin of organic material
Petroleum products
Type I
1.7–0.3
0.1–0.02
Algae in lacustrine and/or lagoonal environments
Light, high-quality oil and some natural gas
Type II
1.4–0.3
0.2–0.02
Mixture of plant debris and marine microorganisms
Main source of crude oil and some natural gas
Type III
1.0–0.3
0.4–0.02
Land plants in coaly sediments
Mainly natural gas with very little oil
Type IV
0.45–0.3
0.3–0.02
Oxidised and charred wood
No petroleum potential
Box 1 summarises some of the characteristics of the Kimmeridge Clay (150 Ma), which is a mudstone sequence of Upper Jurassic age that is widespread in northern Europe. This world-class source rock is the primary reason why there is a North Sea oil industry.
Box 1: Kerogen in the Kimmeridge Clay formation.
The Kimmeridge Clay Formation is the most important source rock for North Sea oil deposits. It has an average organic carbon content of 5%, rising to 20–30% in the richest ‘oil shales’ that outcrop along the coasts of Yorkshire and Dorset in England (Figure 3a). It has an H:C ratio varying from 0.9 to 1.2.
Bacterially degraded marine algae and degraded humic matter and woody debris of land origin make up about 75% of the total carbon content. Other marine algae, land-plant spores and oxidised land-plant fragments form the remainder. The relative proportion of these constituents varies widely according to the depositional setting of the mudstones. The most organic-rich intervals developed in deeper basins where the highly anoxic bottom waters and high sedimentation rates favoured organic preservation.
Using the information in Table 2, can you suggest what kerogen type characterises the Kimmeridge Clay?
Answer
The abundance of marine algae and land-plant debris, coupled with the mid-range H:C ratio, suggests that most of the organic carbon in the Kimmeridge Clay is Type II kerogen.
End of answer
2.1 Petroleum charge (continued)
2.1.3 Maturation
The process of biological, physical and chemical alteration of kerogen into petroleum is known as maturation. Source rocks that experience the right conditions for these processes and can generate petroleum are termed mature. Maturation begins within an organic-rich sedimentary layer while it is being deposited. Here a series of low-temperature reactions that involve anaerobic bacteria reduce the oxygen, nitrogen and sulphur in the kerogen, leading to an increased concentration of hydrocarbon compounds. This stage continues until the source rock reaches about 50 °C. Thereafter the effect of elevated temperatures becomes much more pronounced as the reaction rates and solubility of some of the organic compounds increase.
Since temperature increases with depth in the Earth, heating is naturally achieved by burial of the source rock. The actual temperature reached at a given depth depends on the rate of increase of temperature with depth, the geothermal gradient. Figure 1 shows the relative proportions of crude oil and gas formed from Type II kerogen buried in an area with a geothermal gradient of about 35 °C km−1. Significant amounts of petroleum only begin to form at temperatures over 50 °C and the largest quantity of petroleum is formed as the kerogen is heated to temperatures between 60 and 150 °C. At still higher temperatures oil becomes thermally unstable and breaks down or ‘cracks’ to natural gas. Even after maturation, some of the kerogen still remains unaltered as a carbon-rich residue.
Figure 1: The relationship between depth of burial, temperature and the relative amount of crude oil and natural gas formed from Type II kerogen in an area with a geothermal gradient of about 35 °C km−1.
Look at Figure 1 and estimate the subsurface temperature and depth at which peak oil generation is achieved.
Answer
Peak oil generation in a typical Type II kerogen occurs at about 100 °C. In this example, where the geothermal gradient is 35 °C km−1, this corresponds to a depth of about 2850 m.
End of answer
The most important factors in maturation studies are the amount and type of kerogen, the temperature and time. Maturation rates generally increase exponentially with respect to temperature (up to a point) and linearly with respect to time. Thus crude oil can form in old basins with low geothermal gradients (‘cold’) as well as in young basins where the geothermal gradient is high (‘hot’). However, it cannot form in young, cold basins except in trace amounts. It is usually destroyed in old, hot basins, assuming that subsidence has been continuous, because temperature eventually rises to a point where all kerogen and any crude oil formed earlier has been converted into gas.
To illustrate this point it is useful to examine the burial histories of source rocks in three different sedimentary basins (Figure 2). The source rocks in the Paris Basin, the North Sea Viking Graben and the Los Angeles Basin are different in terms of age and composition, and each has been subjected to differing burial histories. The point at which petroleum generation starts is known as the threshold, and this was reached after 40 million years in the Paris Basin (i.e. about 140 million years ago) when Early Jurassic (175 Ma) source rocks were buried to a depth of 1400 m. In contrast, it took some 80 million years before the Kimmeridgian (150 Ma) source rocks in the Viking Graben started to generate petroleum during early Tertiary times.
Figure 2: Reconstruction of burial histories of rocks from three basins; the Paris Basin in northern France, the Viking Graben in the northern North Sea and the Los Angeles Basin in the USA.
Activity 1
Examine Figure 2 and determine the threshold depth for petroleum generation in the Los Angeles Basin. Then, assuming that this depth equates to a temperature of 120° C, and ignoring surface temperature effects, calculate the geothermal gradient.
Answer
The threshold depth is about 2.5 km. At this depth the temperature is said to be 120 °C, so the geothermal gradient is 120 °C/2.5 km=48 °C km−1.
End of answer
2.1.4 Migration
Migration refers to the movement of fluid petroleum through rocks. This process begins with primary migration, i.e. the expulsion of petroleum from the source rock. The driving force for this process is the pressure difference caused by the loading effect of overlying rocks. Overburden loading preferentially compacts mudstones, making it difficult for fluids within them to escape. As a result, pressure builds up in them until it is sufficient to drive the water and petroleum into adjacent rocks that are at a lower pressure because they are more permeable (see Figure 3). In the context of water resources, these rocks would be termed aquifers (Smith, 2005, Chapter 3), and at depth they would inevitably be saturated with water, but in petroleum parlance they are reservoir rocks, which we will discuss in more detail in Section 2.2. Figure 3b shows a potential reservoir rock exposed on land.
Figure 3: (a) A potential Jurassic source rock exposed in Dorset, the Kimmeridge Clay, whose black colour is due to high kerogen content. (b) A potential Jurassic reservoir rock exposed in Dorset, the Bridport Sand. (c) Migration of petroleum out of a source rock and upwards through a reservoir to a trap.
Once expelled from the source rock, buoyancy takes petroleum (both liquid and gas) from depth up towards the surface of the Earth because it is less dense than pore water and ‘floats’ on top of it in the reservoir rock. This is known as secondary migration, and its effectiveness depends on the permeability of the reservoir rocks and the density and viscosity of the petroleum fluids flowing through them. As Figure 3c shows, oil and gas continue to migrate upwards until they are trapped beneath an impermeable rock layer. At that point they segregate according to their density; gas is lighter so it will pool immediately beneath the permeability barrier, whereas oil is heavier and will accumulate beneath the gas. Rocks beneath will be saturated with pore water. Secondary migration serves to concentrate petroleum and by the time it reaches the trap it can occupy more than 90% of the pore volume in the reservoir.
Timing of the petroleum charge relative to the formation of a trap is critical, simply because a trap has to pre-date petroleum migration in order for an accumulation to develop: migration before suitable traps have formed would ultimately result in all petroleum escaping at the Earth's surface. Figure 3c reinforces this point by showing that the horizontal impermeable layer both truncated and sealed the dipping reservoir rocks, creating a trapping configuration, before migration occurred; otherwise the petroleum could not have been trapped.
As discussed above, petroleum generation may occur only a few million years after the source rock was deposited or tens of millions of years later, depending on the rate of burial and the geothermal gradient. An understanding of basin evolution is vital in this context, not only to determine when potential traps were formed, but to assess the degree to which they were subsequently filled, and the chances of petroleum having escaped (see Section 2.4 on traps later in this unit).
2.2 Reservoir rocks
The properties of a petroleum reservoir rock are very similar to those of an aquifer since both petroleum and water can be contained within and move between its pore spaces and fractures. Sedimentary rocks that are well cemented have only small voids between grains and hence low porosity.
Which sedimentary rock type is most likely to be a potential reservoir rock?
Answer
The most porous reservoir rocks are generally well-sorted, poorly cemented sandstones (see Figure 3b), and these make up some of the most important petroleum reservoirs around the world.
End of answer
Migrating waters can increase porosity and permeability by dissolving the cement that holds the grains together and widening small fractures that run through the rock. This effect is often enhanced if the waters are slightly acidic. Many limestones are well cemented and therefore have low porosity, but the calcium carbonate (CaCO3) that makes up the grains and cement is soluble in weakly acidic water. Consequently limestones can form good reservoirs, and in fact limestones hold 40% of the world's resources of petroleum.
The essential properties that describe a reservoir rock are porosity (the void space expressed as a percentage) and permeability (a measure of the degree to which fluid passes through it, measured in millidarcies, mD). Another property that is commonly used is the ratio of porous and permeable (net) intervals to the overall reservoir (gross) thickness. This is referred to as net to gross and it is important because it recognises that most sandstone and limestone reservoirs are not entirely homogeneous, but contain intervals or strata that less readily allow fluid flow.
To put these properties in context, Table 3 provides reservoir data for 20 oil and gas fields in the North Sea. Note the very wide range of net to gross and permeability values, despite the fact that most of the reservoirs are of the same (sandstone) type. Porosities are typically in the range 15–30%, but the more telling parameter is permeability because that largely determines petroleum flow rates. Permeability cut-offs of 1 mD for gas and 10 mD for light oil are often used as a rule-of-thumb for productive reservoirs; less permeable rocks are not usually capable of sustaining commercial flow rates. Notice also that one of the two Cretaceous Chalk reservoirs in the Ekofisk field exhibits chalk's characteristic properties of high porosity and low permeability – the latter results from very small channels that connect the pores between the tiny calcareous plankton shells that form chalky sediments. The other chalk reservoir in Ekofisk has higher permeability because it has been fractured tectonically.
Table 3: Properties of reservoirs within North Sea oil and gas fields. Note: A formation is a distinctive sequence of sedimentary rocks in a particular field.
Field
Age/Formation
Reservoir
Net to gross/%
Porosity/%
Permeability/mD
Fluid
Alwyn North
Jurassic/Brent
sandstone
87
17
500–800
oil
Alwyn North
Jurassic/Statfjord
sandstone
65
14
330
oil
Auk
Permian/Zechstein
fractured dolomite
100
13
53
oil
Auk
Permian/Rotliegend
sandstone
85
19
5
oil
Brae South
Jurassic/Brae
sandstone
75
12
130
oil
Britannia
Cretaceous/Britannia
sandstone
30
15
60
gas in liquid form under high pressures
Buchan
Devonian/Old Red
fractured sandstone
82
9
38
oil
Cleeton
Permian/Rotliegend
sandstone
95
18
95
gas
Cyrus
Palaeocene/Andrew
sandstone
90
20
200
oil
Ekofisk
Cretaceous/Chalk
limestone(fractured Chalk)
64
32
>150
oil
Ekofisk
Cretaceous/Chalk
limestone (Chalk)
62
30
2
oil and gas
Forties
Palaeocene/Forties
sandstone
65
27
30–4000
oil
Fulmar
Jurassic/Fulmar
sandstone
94
23
500
oil
Frigg
Eocene/Frigg
sandstone
95
29
1500
Gas
Heather
Jurassic/Brent
sandstone
54
10
20
Oil
Leman
Permian/Rotliegend
sandstone
100
13
0.5–15
gas
Piper
Jurassic/Piper
sandstone
80
24
4000
oil
Ravenspurn South
Permian/Rotliegend
sandstone
39–77
13
55
gas
South Morecambe
Triassic/Ormskirk
sandstone
79
14
150
gas
Scapa
Cretaceous/Valhall
sandstone
—
18
111
oil
Staffa
Jurassic/Brent
sandstone
76
10
10–100
oil
West Sole
Permian/Rotliegend
sandstone
75
12
—
gas
Activity 2
Using the information in Table 3, calculate the average porosity of the five Permian sandstone reservoirs and the three Palaeocene-Eocene sandstone reservoirs. Compare the results and suggest reasons for the marked difference.
Answer
The average porosity of the Permian sandstone reservoirs is (19+18+13+13+12)/5 = 15%, whereas the Palaeocene-Eocene reservoirs average (20+27+29)/3 = 25%. The simplest explanation for this difference is that younger reservoirs tend to have higher porosities because they usually occur at shallower depths and are less compacted than their older counterparts.
End of answer
2.3 Seals
Above permeable reservoir rocks there must be an impermeable layer (known as a seal or cap rock) to stop migrating petroleum from rising further towards the surface of the Earth. Seals are fine-grained or crystalline, low-permeability rocks such as mudstone, anhydrite and salt. Rock salt is by far the most effective seal, because it is crystalline and therefore impermeable. Seals are also enhanced if they are ductile (ductile deformation prevents the formation of open fractures and joints), substantially thick and laterally continuous; little surprise then that the largest oil fields in the Middle East are sealed by evaporites (Argles, 2005) with these characteristics.
However, seals are rarely, if ever, perfect. Hydrocarbons can migrate through almost all rock types, but at different rates that depend upon any fracturing and microscale fluid flow, and whether liquids adhere to or are repelled by the surfaces of mineral grains. Many oil and gas fields have active surface seeps of petroleum overlying them that provide a direct indication as to their location. In marine settings seeps may be detected as bubbles of gas rising from the sea bed, or as an oily sheen on the water. On land, plant communities are stunted, surface layers of rock and soil may be altered, tarry residues may encrust the surface, and sometimes there may be active oil seeps. The first oil fields to be developed in the 19th century were located beneath such obvious features. It is thought that ignition (by lightning strikes) of petroleum escaping above the huge oilfields of Iran gave rise to the fire-worshipping Zoroastrian religion. Even odder, the Ancient Greek Oracle at Delphi is thought to have made her prognostications while hallucinating under the influence of escaping natural petroleum gas.
2.4 Traps
Petroleum that accumulated as a thin layer at the top of an extensive horizontal reservoir would be uneconomic to extract. That is because many wells, each with only a small rate of production and lifetime, would be needed to extract the petroleum. To be worth working, a sealed petroleum-bearing ‘container’ or trap must be shaped naturally to retain and focus petroleum, rather as the curved upper surface of a balloon traps buoyant hot air. The lower surface of a trap is defined either by a petroleum–water contact or sometimes by another seal.
There are many different styles of trap (see Figure 4) but the most common are structural traps in the form of anticlines produced by tectonic processes, by differential compaction of soft rocks above hard, irregular surfaces and by evaporitic salt masses that rise gravitationally. The low density of salt, combined with its ductility, enables it to rise to form domes and intrusive masses. Because they produce distinctive geological and geophysical features, structural traps are the easiest to find.
Figure 4: Types of traps. Types A to E are explained in the text. A–C are structural traps, D is a stratigraphic trap and E is a combination trap.
About 80% of the world's petroleum reserves are held in structural traps like those shown in Figure 4. They include simple anticlines (A), faulted structures that juxtapose reservoirs against seals (B), and traps created at the flank of a salt dome or in the compaction anticline above it (C). Most fields in the North Sea occur in structural traps.
Stratigraphic traps result from lateral changes in rock type and typically consist of discontinuous sandstone bodies encased in mudstone (D). Sometimes referred to as ‘subtle traps’, they currently contain about 13% of the world's petroleum reserves, but much of the remaining undiscovered petroleum will probably be found in these settings because the more obvious structural traps have long since been exploited.
In practice, traps often form through a sequence of different processes over the course of tens of millions of years. For example, in E the reservoir was first deposited, then folded, uplifted and eroded, before being overlain by a much younger impermeable mudstone. The resulting configuration is appropriately called a combination trap. Provided it was intact before the reservoir received a petroleum charge, it forms a valid trap regardless of how long it took to form.
As petroleum accumulation continues it is possible for traps to fill beyond their natural spill-point, when petroleum can escape sideways to re-migrate to other traps (Figure 4, upper C) or to the Earth's surface where it emerges as oil or gas seeps.
Suggest another type of trap on Figure 4 that might experience such leakage.
Answer
The lowest trap associated with the fault might leak along fractures produced by the faulting, to help charge higher traps.
End of answer
2.5: Combining the ingredients
Having examined the essential ingredients for a petroleum accumulation, this section discusses how knowledge about them is combined to create a petroleum play. This is a particularly useful concept, since it consolidates what is known (or not known) about the petroleum potential of a particular level within a basin and forms the basic strategy for oil and gas exploration. A play is defined as a perception or model of how a petroleum charge system, reservoir, seal and trap may combine to produce petroleum accumulations at a specific stratigraphic level. By examining whether each of the play ingredients is both present and effective, it is possible to define parts of a basin where petroleum accumulations can reasonably be expected to exist. This process can be conducted systematically in a given area to generate a play fairway map that depicts where the ingredients coexist, even though the precise details of trap location and size may not be known. As more data become available the play becomes better defined, but even when the play is proven by a discovery it does not imply that every trap within the same fairway will contain a petroleum accumulation. It is in the nature of exploration that more often than not geoscientists are wrong with their predictions, but this approach at least helps to reduce their uncertainty.
To illustrate the petroleum play approach an example is provided from the Upper Jurassic of the North Sea (Table 4).
Table 4: Upper Jurassic petroleum plays of the North Sea.
There are two play types: the Kimmeridgian–Volgian deep marine play and the slightly older Oxfordian–Volgian shallow marine play. Whilst the depositional settings for the two reservoir types are quite different, both plays share the same petroleum charge, seal and trap ingredients. Importantly, notice that the onset of petroleum generation comfortably post-dates trap formation. For simplicity the two plays can be combined and their distribution plotted to create an Upper Jurassic play fairway map (Figure 5). This illustrates the close correspondence between the limit of mature Upper Jurassic Kimmeridge Clay source rocks and the fairway, such that the migration pathways between the two are short (less than 15 km) and highly permeable. More than 60 Upper Jurassic fields have been discovered to date beneath the North Sea. They have combined oil reserves of about 2.5×109 toe (tonnes of oil equivalent) and account for 23% of total North Sea production (Evans et al., 2003).
Figure 5: The Upper Jurassic play fairway in the North Sea. Beyond the mapped fairway limits one or more of the key ingredients of the play, for instance suitable traps, seals or reservoir rocks, are missing and therefore it is unlikely that Upper Jurassic petroleum discoveries will be made there. The golfing analogy of staying within the fairway in order to be successful seems particularly appropriate in the context of exploration.
3 Exploring for oil and gas
3.1 Detection, exploration and evaluation
It would be prohibitively expensive to explore for oil and gas on a random basis, and most of the effort would be wasted. When geological knowledge was far more limited than it is today, most of the discoveries were beneath quite obvious signs of petroleum seepage at the surface. Eventually, such easy targets ran out, although some are still being discovered. The key ingredients for petroleum accumulation which we have discussed in this unit were gleaned from the knowledge gained by drilling such targets and examining the geology around them. As more has been learned, increasingly sophisticated methods have been developed that increase the odds of making a discovery in less obvious situations. This section covers some of those methods and describes how an exploration well is drilled and evaluated.
3.1.1 Surface detection methods
Field mapping is a well established technique that has contributed to the discovery of billions of barrels of petroleum. In the pioneering era of onshore exploration the search for anticlinal structures at shallow, drillable depths usually began with the recognition of an overlying part of such a structure at the surface. These days, with ready access to various forms of subsurface data, field mapping is more commonly used to assess the structural style of a basin and to provide analogues for concealed reservoirs or source rocks. Far from being an outdated technique, modern fieldwork is becoming increasingly sophisticated as digital data collection is underpinned by Global Positioning Systems (GPS), satellite imagery and digital terrain models. In Norway's Lofoten Islands a detailed analysis of onshore fault and other structural patterns is being extrapolated offshore in order to calibrate three-dimensional (3-D) seismic data in unexplored portions of the Norwegian continental shelf.
3.1.2 Remote sensing methods
Remote sensing involves gathering information of many kinds at a distance from the object of investigation: it gives a regional picture and helps sort the likely areas to follow up from those much larger areas that are less favourable. Satellite, gravity and magnetic methods (see below) are commonly used during the early phase of exploration when a sedimentary basin, or at least a substantial part of it, is not known in sufficient detail to deploy more expensive methods. Their interpretation is simple and can be done relatively cheaply in the office. Satellite images take the form of spectral data over a wide range of wavelengths, from the visible through infrared to microwave (radar). They can sometimes detect unknown petroleum seepages. On land, the presence of a seep is often associated with a change in vegetation or soil colour, especially if the seep is of crude oil, whilst in the offshore setting rising gas bubbles may draw deep water to the surface, giving a cool thermal image. Alternatively, satellites can provide photographic imagery with an extraordinarily good resolution, sufficient to map rock exposures, analyse topography, and to locate roads, habitations and so on.
Gravity surveys are often used to analyse sedimentary basins at the regional scale. Because sedimentary rocks usually have a lower density than crystalline rocks, thick sequences of relatively low-density sediments effectively reduce the Earth's gravitational force and they are characterised by regional gravity lows. Gravity data may be collected on land, at sea or by air and they are particularly useful in areas of difficult terrain, such as jungles and deserts, where access is difficult. Regional airborne magnetic surveys can also be used to define the shape and gross structure of a basin and they are often acquired in tandem with gravity surveys. Magnetic rocks cause perturbations in the Earth's magnetic field, whereas non-magnetic rocks have little effect. Sediments are typically poorly magnetic because they do not contain large amounts of iron-rich minerals, whereas igneous rocks such as volcanic lavas often do. So sedimentary basins characteristically have a low, uniform magnetic signature that contrasts markedly with the highly variable magnetic anomalies associated with metamorphic basement rocks and near-surface volcanic intrusions. Where faults juxtapose rocks with different magnetic properties at depth, the faults show up as distinctive linear features.
3.1 Detection, exploration and evaluation (continued)
3.1.3 Seismic data and interpretation
Seismic surveying is by far the most widely used and important method of gaining an impression of the subsurface. Seismic surveys can be acquired at sea as well as on land. The marine method is the most common in petroleum exploration and is shown schematically in Figure 6, although the same principles apply to any seismic reflection survey.
Figure 6: Marine seismic acquisition – pulses of sound energy penetrate the subsurface and are reflected back towards the hydrophones from rock interfaces.
Compressed air guns towed behind a boat discharge a high-pressure pulse of air just beneath the water surface. The place of detonation is called the shot point and each shot point is given a unique number so that it can be located on the processed seismic survey. The sound waves (effectively the same as seismic P-waves produced by earthquakes) pass through the water column and into the underlying rock layers. Some waves travel down until they reach a layer with distinctively different seismic properties, from which they may be reflected in roughly the same way that light reflects off a mirror. For this reason such layers are called seismic reflectors.
The reflected waves rebound and travel back to the surface receivers (or hydrophones), reaching them at a different time from any waves that have travelled there directly. Their exact time of travel will depend on the speed that sound travels through the rock: its seismic velocity. Other waves may pass through the first layer and travel deeper to a second or third prominent reflector. If these are eventually reflected back to the hydrophones they will arrive later than waves reflected from upper horizons.
The hydrophones therefore detect ‘bundles’ of seismic waves arriving at different times because they have travelled by different routes through the rock sequence. Computer processing allows the amalgamation of recordings from all the shot points, filtering out unwanted signals of various sorts. The final result is a two-dimensional (2-D) seismic section. By using closely spaced survey lines or hydrophones arranged in a grid it is possible to produce 3-D seismic datasets. These are usually interpreted on a PC workstation and colours are normally used to enhance the image and aid interpretation. The data can be viewed in any orientation in order to create a 3-D visualisation of selected horizons (Figure 7).
Figure 7: A 3-D view of the Palaeocene reservoir in the Nelson Field, North Sea. The image is derived from a ‘cube’ of closely spaced 3-D seismic data, onto which the paths of the production wells are superimposed. Bright colours in this perspective view relate to depths to a particular reflecting boundary. Reds and greens are structurally highest, where petroleum may be trapped.
Seismic data of all forms (2-D or 3-D) are displayed with the horizontal axis indicating geographic orientation and distance, whereas the vertical axis is calibrated in time. The time, measured in seconds, records how long it took the seismic wave to travel from shot to reflector and then back to the hydrophone, so it is described as two-way travel time (TWT). Further processing and the incorporation of seismic velocity data allows TWT to be converted into depth. Depth-converted seismic data is the mainstay of exploration since it provides a meaningful basis for all subsequent interpretation.
What would happen to seismic waves if there was a strongly reflective layer, such as an igneous sill or salt body, in the shallow subsurface?
Answer
It would tend to reflect most of the seismic waves back towards the surface and reduce the quality of seismic imaging beneath it.
End of answer
Interpreting seismic sections is something of a ‘black art’, requiring both experience and a certain amount of interpretative flair. At the outset, interpretation involves tracing continuous reflectors on 2-D sections in order to build up a plausible structural representation of the subsurface. In the context of an initial exploration programme to find possible traps this is often sufficient.
Look at the 2-D seismic section in Figure 8. Even though it was produced to explore for coal seams it contains lots of information that might help the petroleum explorationist. What kinds of trap shown in Figure 4 might be present in that section?
Figure 8: An example of a seismic section. The (vertical) arrival time axis in milliseconds (ms) is roughly equivalent to increasing depth. Towards the top of the section a pair of dark lines indicate major coal seams. They are displaced by a fault near the centre of the traverse (marked by the dashed red line). Many other features show up, including greater complexity in the deeper part of the section, and towards the left of the section deep, more steeply dipping reflectors are truncated by the simpler ones at shallower depths: this is an unconformity (solid blue line).
Answer
The unconformity might have associated combination traps (E on Figure 4). There is a large anticline at lower left (see C on Figure 4), and reservoir rocks might be in contact with seals along the fault (C on Figure 4) that extends vertically downwards in the centre of the seismic section.
End of answer
Good quality 3-D seismic data provides sufficiently fine resolution for exhaustive processing and analysis to help in managing and developing known oilfields (Box 2).
Box 2: Applications of 3-D seismic data
Modern 3-D seismic data can be used for many purposes other than simply defining trap geometry. Sometimes it is possible to identify the presence of petroleum directly, particularly dispersed gas which tends to dissipate seismic waves and produce an ill-defined ‘shadow zone’ above a leaking trap. The changes in acoustic properties across a gas–water or gas–oil contact may also be detected as a horizontal reflector that conforms to the geometry of the trap.
More commonly, however, seismic data are used to map rock characteristics at a variety of scales. Starting with the recognition of distinctive reflector geometries and seismic sequences, and then by applying a range of seismic techniques, depositional environments can be mapped over a very wide area. As drilling progresses and data on rock properties (such as seismic velocity and density) become available, increasingly sophisticated reservoir descriptions can be developed. These commonly include an assessment of lithology, the amount of petroleum that is present, fluid type and porosity.
Interpretation of 3-D seismic data is an enormously varied and rapidly developing area of petroleum exploration that is beyond the scope of this unit.
Seismic technology has been transformed since the 1980s. Today, 3-D seismic, rather than single 2-D sections, are routinely used for exploration purposes in offshore environments because the data can now be acquired quickly and cheaply. New processing techniques and improved computerised visualisation tools add clarity to the data, helping to provide an unparalleled impression of the subsurface. The emphasis in exploration is to reduce the risk of drilling a dry hole and wasting a great deal of investment. This can only be achieved by integrating all the appropriate types of data, and with thoughtful analysis.
3.1.4 Exploration drilling
When seismic data highlight a suitable prospect, the next step is to drill into the reservoir in order to establish whether or not petroleum is trapped, and, if it is, to establish how large the accumulation might be. There are several types of drilling rig, ranging from relatively small ones as deployed on land (Figure 9a) that can be dismantled and transported by truck or helicopter, to large offshore units (Figures 9b–d) that are capable of working in a range of water depths and sea conditions. An offshore jack-up rig is a barge with lattice steel legs that can be raised and lowered (Figure 9b). It is towed into position by tugs and its legs are lowered to the seabed before the barge is raised 10–30 m out of the water to create a stable drilling platform. They usually operate in water depths up to 200 m.
Drilling in greater water depths requires a floating unit and the semi-submersible rig is the most common and versatile type (Figure 9c). The working platform is supported on vertical columns that are attached to submerged pontoons. Once in position, the rig is anchored to the seabed and the pontoons are flooded with water to submerge them beneath wave level. The lower the pontoons are beneath the water, the less likely they are to be affected by wave action. This makes them stable in rough seas. Some semi-submersible rigs have computer-controlled positioning propellers, rather than anchors, to keep them in position and they can be used in water depths down to 1000 m or more.
Figure 9: Mobile drilling units can operate on land (a) or in a variety of water depths. Jack-up rigs at rear and front right in (b) are used in water up to 200 m deep, whilst semi-submersible rigs foreground in (b) and (c) and drill ships (d) can operate in much deeper water.
Drill ships resemble conventional ships and they can move easily around the world (Figure 9d). They too have dynamic positioning that allows them to stay on location with remarkable accuracy in all but the most severe storms. Since they are not ballasted they can be unstable in high seas but their advantage is that they can drill in water depths in excess of 2000 m.
What type of rig would be used to drill in the Amazonian rainforest and what preparation would be required before drilling commenced?
Answer
Components of a land rig could be taken into the rainforest by river boats or helicopters and assembled on site. Before that process began it would be essential to survey the drilling site, determine the best access route, clear the site sensitively and safeguard local water supplies from any risk of contamination. In ecologically sensitive areas the cost of site preparation and restoration may exceed the drilling costs.
End of answer
Drilling for oil and gas is a sophisticated and very expensive process. Wells often penetrate over 3000 m into sedimentary rock; the deepest exceed 6500 m. At such depths the fluid pressures in the rock formations are so high that a dense drilling mud is continuously pumped into the borehole to counter-balance the pressure. This significantly reduces the possibility of an uncontrolled surge of petroleum to the surface, a situation that is graphically described as a ‘blowout’. The enduring image of rig workers celebrating beneath a gushing fountain of crude oil in the pioneer days of exploration distorts reality, since blowouts and the release of associated toxic gases such as hydrogen sulphide (H2S) are very dangerous. Every modern well is fitted with hydraulic rams that instantly isolate the borehole if excess pressures cause the well to flow. The other useful functions of drilling mud are to lubricate and cool the drill bit, to circulate rock fragments (cuttings) back to the surface and, in some cases, to power a turbine that rotates the drill bit.
3.1.5 Well evaluation
To some extent, well evaluation is similar to evaluation of coalfields. Traditionally an exploration well is evaluated at discrete stages by withdrawing the drill bit, lowering instruments (colloquially known as ‘tools’) down the hole on a steel cable and then hauling them slowly back to surface. This process is known in the petroleum industry as wireline logging. As the tools are withdrawn they record the properties of the rocks that surround the well and the fluids in them. Nowadays this approach is supplemented by measurements that are made while drilling is in progress, which has the advantages of providing near instantaneous data and incurs none of the expense of halting the drilling process.
The rock properties that are of interest include those used for identifying lithologies and small-scale structural or sedimentological features. Other tools help estimate porosity, permeability, pressure and fluid content. None provide a completely definitive description of the borehole wall, but in combination the data acquired by wireline logging provide sufficient information to determine whether further evaluation is justified.
The most useful geological data are derived from pieces of rock recovered from specific depth intervals. They range in size from small fragments of rock (drill cuttings) produced as the drill bit cuts into rock, to thumb-size and larger (5–15 cm diameter) cores of solid rock that are retrieved with special tools. These provide the basis for a detailed description of the reservoir, although cores may also be taken in mudstones to gain biostratigraphic and/or geochemical information.
Some exploration wells, particularly those that encounter significant volumes of petroleum, justify an extensive evaluation programme that is designed to recover fluid samples from selected intervals down the well. The fluids (oil, gas and water) are captured in situ at reservoir temperature and pressure, and then brought to the surface in a small sealed chamber for analysis. Less commonly, the fluids may be sampled by allowing them to flow to the surface. Such well testing may continue for several days. During that time it is possible to draw some preliminary conclusions about the nature of the reservoir, flow rates and the commercial potential of the petroleum accumulation.
Activity 3
Exploration is an expensive activity that can quickly lead to ‘gambler's ruin’ – betting more money than you win – unless there is a proper understanding of risk and potential reward. At the outset it is vital to decide where not to explore. List some of the fundamental geological, technical and commercial factors that you might use to reject certain parts of the world from exploration.
Answer
Source rocks only develop in sedimentary basins within continental crust, so areas formed by oceanic crust or crystalline rocks should be avoided. Remote regions (e.g. Antarctica) and inaccessible sedimentary basins (e.g. those beneath thick piles of lava or mountainous terrain) will inevitably be very expensive to explore. Some countries may be rejected for political or humanitarian reasons. It is salutary to remember that more than half of the world's countries produce no oil.
End of answer
4 Petroleum production
4.1 Appraising the discovery
Once quantities of oil or gas have been discovered by exploration drilling, the next step is to carry out an appraisal programme to determine whether the accumulation is worth developing into a producing field. To justify the move into production, the field must contain enough petroleum to repay the huge cost of development, finance day-to-day operations and still make a profit. This page and the three following outline the steps required to translate the excitement of an offshore discovery into a commercial product at the refinery, a process that may take several years because it involves a huge amount of data collection and additional drilling.
During the appraisal stage, the size of an oilfield discovery must be established as accurately as possible and the most cost-effective way to produce petroleum from the reservoir(s) sought. Geologists and engineers focus on the reservoir in particular, by attempting to provide an improved definition of the trap geometry and considering whether or not the reservoir is segmented by barriers to lateral flow, such as faults or impermeable layers that will require wells to be drilled into each segment. This work is normally underpinned by a more detailed 3-D seismic survey (Figure 7) acquired on a closely spaced grid (with less than 50 m between shot points) to provide maximum resolution. Such surveys give much more detail about the trap configuration, the depth to reservoir units and, to a certain extent, the nature of the reservoir rocks themselves.
Further drilling will improve the knowledge of how reservoir fluids (oil, gas and water) and boundaries between them are distributed. Rock properties are used to calibrate the seismic data, thereby allowing specific reservoir rock types to be mapped in areas beyond existing wells. The resulting reservoir model provides the basis for calculating the volume of petroleum trapped in the reservoir, and differing production scenarios can be assessed to determine the likely reserves that are recoverable during the life of the field.
Running in tandem with the technical work there is also a complex web of commercial, regulatory and sometimes political issues to be resolved. For example:
•
How much will it cost to build, install, operate, maintain and, eventually abandon, the production facilities?
•
Is the production facility to be located in an environmentally sensitive area or a shipping lane?
•
How will the petroleum be transported from the well to its point of use?
•
Are new tax laws envisaged that will impact profitability?
•
Might the field be confiscated if the political regime changes?
The decision to commit to developing a new field will only be made when the bulk of these issues are satisfactorily resolved. The go ahead then relies on approvals being granted by the owner(s) of the asset, governing bodies and financial underwriters. It quickly becomes evident that large-scale appraisal projects are hugely complex undertakings that require careful data integration and a multidisciplinary approach.
4.2 Development options
The approach to field development is as varied as petroleum accumulations themselves, so what follows is a brief summary. Most major petroleum field development projects in the 1990s and early 21st century were located offshore, and often presented the challenge of very deep water (over 1500 m) and elevated reservoir temperatures and pressures. One reason for long-term optimism about the future of the petroleum industry lies in its growing ability to access remote and difficult resources safely. The pace of technological innovation is rapid, and that emphasises why the perception of global petroleum resources and reserves will always change; what is inaccessible today may not be tomorrow.
Various deep-water development systems are illustrated in the animated sequence below. The sequence is best viewed in a new window (click on the link below).
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Now try this short quiz. Again, this is best viewed in a new window.
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4.3 Production techniques
In order to develop offshore fields economically, numerous directional wells radiate out from a single platform or from several sub-sea wellheads to drain a large area of the reservoir. This allows each well to produce as much petroleum as possible at economic rates. Wells which deviate at more than 65° from the vertical and reach out horizontally more than twice their vertical depth are known as extended reach wells (Figure 10). Where reservoirs are thin or suffer from low permeability it may be appropriate to drill production wells at more than 80° from the vertical and these are called horizontal wells. The flow rate from a horizontal well may be more than five times that from a vertical well, thereby justifying the higher cost of drilling a well with a complex geometry. In order that wells that deviate from the ‘standard’ vertical drilling can be guided precisely through layered reservoirs, real-time information about the location and inclination of the drill bit is transmitted back to surface. This allows the driller to ‘steer’ the bit assembly to intersect particularly productive zones.
All fluid petroleum is confined underground at high pressure, which provides a natural ‘drive’ for production, rather like artesian water supplies (Smith, 2005).
Figure 10: (a) Wells at a variety of angles extract petroleum from all parts of a large, saturated reservoir, (b) Superimposition of the plan of the wells shown in (a) over central London gives a graphic expression of the area that can be exploited from a single production platform by deviated drilling into a reservoir.
During the early stages of production, getting these fluids to the surface safely means allowing a controlled release of fluids under pressure. To prolong extraction later in the life of an oil or gas field, it usually becomes necessary to maintain the pressure underground by injecting pressurised water or gas, or both, into the reservoir.
When production begins, during primary recovery, pressurised fluids within the reservoir rise up the borehole and reach the surface. As the pressure is released, any gas dissolved in the oil comes out of solution, to rise and escape along with the oil. As production continues, the pressure of the petroleum remaining in the reservoir begins to fall. This fall in pressure and the loss of dissolved gas increases the viscosity of the oil, so that it will not flow so readily. Typically only 5–30% of the petroleum in the reservoir is brought to the surface during the primary recovery stage.
As the natural drive of the petroleum dwindles, secondary recovery techniques are needed for continued production. These techniques maintain reservoir pressure by injecting gas into the gas cap that often lies above the oil, thus forcing the oil downwards (Figure 11a), or by flooding water into the aquifer below the oil to force it upwards (Figure 11b). In some reservoirs both gas and water may be injected at the same time or alternately, increasing the recovery of petroleum to 25–65% of the volume contained in the reservoir. The gas required for injection may be derived from the production stream (the fluids that emerge from the well, which comprises gas, oil and water) itself, or from an adjacent field. Similarly, the water for injection may be water from a producing well or sea water.
Figure 11: Oil and gas production techniques. When the natural pressure within the reservoir has dissipated, the drive can be maintained by injecting (a) gas into the gas cap at the top of the reservoir, or (b) water into the aquifer beneath the oil. In some reservoirs both techniques are used at the same time.
In order to improve recovery still further, chemical or biological additives may be added to the injected water, or steam may be pumped into the reservoir, in order to reduce the viscosity of the crude oil (tertiary recovery). Secondary and tertiary recovery methods can result in over 70% of the initial oil being recovered, but the processes are expensive and for many smaller fields the amount of extra oil recovered may not be worth the investment.
The percentage of petroleum that can actually be recovered from a reservoir is a function of both fluid and reservoir properties, as well as the method of extraction. Viscous, waxy oils are more difficult to extract than light, mobile oils, and low-permeability, segmented reservoirs yield less petroleum than good quality, homogeneous ones, even using secondary recovery. Much oil can be left behind if the displacing fluids follow a few discrete pathways rather than flushing out the oil uniformly from the bulk rock. Even with modern techniques the percentage of recovered petroleum varies enormously: in North Sea oil fields it varies from around 10% up to 70% for the best reservoirs, with the average typically in the range of 30–40%. For gas fields, percentage recovery is generally much higher, with figures in the 70–80% range, because gas is many orders of magnitude less viscous than oil.
Imagine that you are the Managing Director of Spoof Oil, a small, entrepreneurial company that owns a 100 million barrel oil field with a primary recovery of 25%. Studies indicate that an alternating water and gas injection scheme would cost $80 million to install, but would increase recovery to 45%. Would you make the investment if forecasts of future oil prices are likely to remain above $30 per barrel?
Answer
Yes. Spoof Oil can access a further (0.45–0.25)×100 = 20 million barrels by installing the secondary recovery scheme for $80 million, a cost of $4 per barrel. Allowing for operating costs and taxes there are still very significant profits to be made while oil price remains high.
End of answer
During the course of field production the amount of new dynamic data that becomes available rises exponentially and it allows an improved description and visualisation of the reservoir. Constant interaction between reservoir engineers and geoscientists is required to ensure that modelled outcomes are matched by production performance. Specific initiatives such as novel drilling strategies, time-lapse (4-D) seismic surveys and well-stimulation programmes may be used to maximise recovery and manage the long-term decline. It should be clear that the incentive to produce an additional 5% of reserves from a large field is very significant, particularly in an environment of rising petroleum prices.
4.4 Getting petroleum ashore
Most offshore oil and all offshore gas are transported to shore by pipelines; the safest, most cost-effective and environmentally friendly solution to transporting large volumes of petroleum without interruption. Pipelines may be buried if the seabed conditions are suitable or they may rest on the seabed and be covered with rock and gravel to provide protection.
Where seabed topography makes pipelines vulnerable or where they cannot be justified on economic grounds, tankers transport oil from production platforms or storage systems. Storage systems may be within massive fixed platforms or in floating ‘spar’ type offshore terminals. More commonly, storage is provided within tankers themselves and these are known as floating, production, storage and offloading (FPSO) vessels (see Section 4.2). FPSOs may remain on location at a single field for many years, offloading stabilised crude to a shuttle tanker at regular intervals. Alternatively the FPSO can move between one or more fields and the shore terminal, and be redeployed as each field is abandoned.
5 Safety and the environment
5.1 Safety issues
Safety and the environment have increasingly become matters of prime concern to the petroleum industry. Losses of life, particularly offshore, and large oil spillages increasingly raise outcries and make headline news. As with the mining industry, governments in many countries have legislated to ensure that companies conform to acceptable norms of conduct. This page deals with operational safety whereas more general environmental issues follow on the next page.
Following the fire on the North Sea Piper Alpha platform in 1988, which killed 167 people, the industry implemented safety improvements, most notably the Offshore Installations (Safety Case) Regulations 1992, which changed the approach to management of safety worldwide. The regulations require the operator or owner of every fixed and mobile installation operating in UK waters to submit a safety case to the Health and Safety Executive (HSE).
Safety cases are required at the design stage for fixed installations and cover all subsequent operations and decommissioning. The safety case gives full details of the arrangements for managing health and safety and controlling major accident hazards on the installation. It must demonstrate, for example, that safety management systems are in place, that risks are identified and reduced as reasonably practicable, and that there are provisions for safe evacuation and rescue.
In the UK, current safety legislation sets out the objectives that must be achieved, but allows flexibility in the choice of methods or equipment that may be used by companies to meet their statutory obligations. The HSE employs a team of inspectors who are responsible for enforcing the regulations; their work includes regular inspection visits to offshore installations and investigation of incidents. They have the authority to shut down an installation and prosecute if necessary.
Figure 12 shows the safety performance of the UK offshore petroleum industry between 1996/97 and 2003/04. The trend in the number of reported injuries resulting in more than 3 days sick leave (called ‘over-3-day injuries’) shows an encouraging decrease, but the trend in ‘combined fatal and major injuries’ is considered far from acceptable. In 2003/04 there were 3 fatalities and 48 major injuries among 18,793 workers, the main causes of which were handling, lifting and carrying. Whilst safety legislation and management commitment is clearly vital, the challenge of improving safety performance is largely met by workers feeling responsible for their own safety as well as that of their colleagues. In this sense employee commitment to safety is an attitude of mind rather than a taught discipline, although it can be enhanced by training and incentive schemes.
Figure 12: Frequency of all significant injuries (including fatalities) among workers in the British offshore petroleum industry. Note: The statistics are expressed by convention per 100 000, whereas no more than 20 000 people work in the industry.
5.2 Environmental management
Management of the environmental impact of projects is not only a legislative requirement, but also good business. It is cost effective, provides a competitive advantage, responds to the public demand for scrutiny, and allows operations to continue in an area. Environmental management, like safety, is now an integral part of all phases of the petroleum business, from early exploration activity through to decommissioning a petroleum field.
Base-line studies and environment impact assessments are commonly used schemes for describing the potential impact of a project on the local environment. A base-line study describes the initial natural state of the flora, fauna and land/seabed conditions prior to any activity. Such a benchmark allows future changes to be identified and provides a reference point if restoration or improvement is required. Such studies are often conducted by independent scientific specialists in order to provide rigour and objectivity.
Environmental impact assessments (EIAs) are detailed ecological studies that are linked to the planned activities of a particular phase of work. They build on the findings of the base-line study and aim to develop or use specified techniques and procedures to minimise the impacts on the environment. These measures may range from using ‘soft-start’ airguns at the start of a seismic survey in order to alert nearby marine mammals, which can be disoriented by repeated loud noises, to avoiding drilling in fish spawning grounds and reducing the use of oil-based drilling muds. Effective EIAs involve widespread co-operation and consultation amongst the industry and stakeholders in order to achieve the best possible outcomes. As an example, the Atlantic Frontier Environmental Network (AFEN) focuses on the Atlantic waters to the west of Orkney and Shetland, and involves a consortium of oil companies, government bodies and conservation organisations.
5.2.1 Environmental risks
The most significant environmental risks from petroleum production come from oil spills. Despite precautions, accidents do occur. Perhaps the best documented case history is provided by the Exxon Valdez, which ran aground in 1989 in Prince William Sound off Alaska. Some 37,000 tonnes of oil were spilled (roughly equivalent to 125 Olympic-sized swimming pools), to affect more than 2000 km of coastline. Whilst this spill was not the highest ever in terms of volume, it is widely considered the worst in terms of damage to the environment, because of the rugged shoreline and abundance of wildlife. The clean-up (remediation) process cost more than 2 billion dollars and took several years. Today there is only very localised evidence of the spill.
Two much larger spills, from the Braer (85,000 tonnes) and Sea Empress (72,000 tonnes), caused far less environmental damage and had only short-lived effects. The Braer, which foundered in 1993 on the Shetland Isles, was carrying a relatively light and easily biodegradable crude oil which was quickly dispersed into the water column by storm force winds and high seas. Similarly, the Sea Empress was transporting a light crude oil when she grounded approaching the oil refinery at Milford Haven, South Wales in 1996. Although more than 100 km of outstanding coastline were initially polluted, the combination of efficient clean-up operations and rapid natural dispersion restored their visually aesthetic appeal within six months. The point is that whilst oil spills are never good news, their long-term effect is rarely enduring.
Despite the increasing number of large tankers carrying crude oil around the world, the number of large spills shows a significant decrease over the last several decades (Figure 13). This is encouraging but it does not provide grounds for complacency and maritime safety systems continue to be improved. Nevertheless, many analysts contend that more oil is ‘spilt’ each year by the deliberate flushing of tanks at sea than is lost by accident.
Figure 13: Annual number of large oil spills (over 700 tonnes) worldwide. (The horizontal bold red lines represent the 10-year averages.)
Aside from oil spills, there are several other significant environmental concerns for the petroleum industry. Gas venting and flaring has traditionally been used to dispose of excess gas in fields where no containment or transport facilities existed. This practice releases large amounts of methane and carbon dioxide into the atmosphere, both of which are greenhouse gases. The World Bank estimates that the annual volume of natural gas being vented and flared is about 100 billion cubic metres, enough fuel to provide the combined annual gas consumption of Germany and France. There is now an increasing effort to make commercial use of excess gas, as in the Clair field west of Shetland. That field was inaugurated in 2005, some 27 years after it was first discovered. With an estimated 5 billion barrels of oil in place it was considered one of the largest undeveloped resources on the UK continental shelf. The oil is being exported to the Sullom Voe Terminal in Shetland via a 105 km pipeline and the gas will be transferred to the Magnus field and re-injected there to enhance oil recovery.
5.2.2 Dealing with environmental issues
One of the most promising schemes for dealing with greenhouse gases is known as gas sequestration. This involves injecting carbon dioxide into a depleted underground reservoir and monitoring the integrity of the trapped gas with time-lapse seismic data. Successful trials in Norway indicate that this technique has the capacity to make significant reductions to the carbon dioxide emissions throughout northern Europe. Interestingly, at pressures of a few atmospheres and temperatures below 30–40 °C, carbon dioxide forms a stable liquid that is denser than water (Figure 14). At temperatures lower than 10 °C it can combine with water to form an ice-like substance known as a gas hydrate (see also Section 7.2). Provided the temperature in a depleted petroleum reservoir is below that where pressured carbon dioxide is only stable as a gas, storage can be indefinite. Methane can also be stored in similar settings, or in underground salt caverns, and recovered according to demand. The key issues now appear to be cost and legislation, rather than feasibility.
Figure 14: Results from experiments conducted at the Monterey Bay Aquarium Research Institute, California to test the feasibility of sequestering carbon dioxide in deep ocean basins. (a) A typical ocean water column temperature profile (solid red line) for Monterey Bay, California overlain on a diagram showing physical states in which carbon dioxide occurs at different pressures and temperatures. (b) Liquid carbon dioxide being poured onto the sea bed at a depth of around 900 m.
The safe disposal of waste products such as drill cuttings and oily water is subject to increasingly tight regulations and innovative solutions have emerged. For offshore installations this may involve transporting all waste to the shore for proper treatment and recycling; for example, drill cuttings are commonly recycled as cat litter, fertiliser or used in the construction of footpaths. Alternatively they are cleaned on site and re-injected underground. On a far larger scale there remains the challenge of decommissioning the 6500 offshore installations worldwide as they come to the end of their productive life. Most will be completely removed from their current location and brought to shore for reuse or recycling. The remainder will be examined on an individual basis to establish what is technically feasible and safe to remove. The debacle of the Brent Spar (Box 3) illustrates the need to resolve the technical, commercial and environmental debate before embarking on a prescribed course of action.
Box 3: The Brent Spar incident
In 1995 the giant oil company, Royal Dutch/Shell, needed to decide how to decommission a disused North Sea oil storage platform called the Brent Spar. Nearly 150 m long, this enormous structure had been in service for 20 years and had the capacity to store 50 000 t of crude oil. Shell considered various disposal options and two made it through to final consideration: deep-sea disposal and on-shore dismantling. These are summarised in Table 5.
Table 5: Two possible disposal options.
Deep-sea disposal
On-shore dismantling
Tow the Brent Spar to the North Atlantic.
Tow the Brent Spar into a deep harbour.
Use explosives to sink the platform in deep water.
Decontaminate the structure.
Allow the structure to settle on the sea bed.
Dismantle and reuse the materials.
Recognise that there will be local pollution for 12–14 months.
Dispose contaminants safely onshore.
Technically the easiest option.
Technically complex and with a greater hazard to the workforce.
Cost estimate about £10 million.
Cost estimate about £40 million.
Shell decided on the deep-sea disposal option and gained the necessary permissions from the Government and regional authorities. Greenpeace, the environmental group, argued that Shell were underestimating the amount of contaminants that remained in Brent Spar and saw no reason to pollute the ocean when an alternative existed. They further argued that Brent Spar would set a precedent for deep-sea disposal in the future. Greenpeace orchestrated a successful campaign that influenced public opinion against Shell's preferred option and it extended to a boycott of Shell petrol stations in parts of Europe.
Faced with growing opposition, Shell decided to review its options and towed the Brent Spar to Norway. Some 2 years later they dismantled it and recycled parts as a foundation for a new ferry terminal. The Brent Spar episode will be remembered as a bruising conflict in which both protagonists were accused of manipulating technical and emotional opinions to their own advantage. For example, Greenpeace have since admitted that their counter-arguments over the amount of contaminants remaining in Brent Spar were flawed. It is clear that the issue of how North Sea structures will be abandoned in the future demands full co-operation between all the stakeholders and a firm hand from the legislators.
The combination of legislation and good practice has led to a significant reduction in the environmental impact of the petroleum industry over the last decade. Quite properly, this shows no sign of slackening. However, the lasting damage done to the environment by petroleum is not primarily caused by ongoing operations or oil spills, but through society's deliberate use of petroleum products as fuels.
6 Oil and gas reserves
6.1 Estimating reserves
Exploration companies need to understand how much petroleum remains to be found in a given area or play before they commit significant expenditure to new ventures. More generally, reserves and their depletion in different parts of the world have profound political implications for ensuring future energy supplies: petroleum resources lie at the centre of global political affairs.
Estimating the amount of petroleum in a field can be achieved in a variety of ways and with differing levels of accuracy, according to the amount of data that is available. The reserves estimate for a virgin basin – one that has yet to be drilled – may be based simply on the supposed richness of the source rock or comparisons with analogous basins that contain petroleum. Conversely, in an established play that is peppered with wells and seismic data, it should be possible to define the undrilled prospects and determine how likely they are to contain given reserves.
In recent years a virgin basin to the north of the Falkland Islands in the southern Atlantic has begun to be evaluated, and several exploration wells have been drilled. Media reports (and some oil companies) claim that more than 5 billion barrels of oil will be discovered here in due course. How would you assess the validity of their claim?
Answer
Any estimation of reserves that is based on sparse data must be treated with caution. It would be more correct to quote the range of likely outcomes (e.g. 0 to over 5 billion barrels) at this early stage, rather than one possible outcome. Billion-barrel oil provinces normally have prolific source rocks, large structural traps and excellent reservoir rocks, so the diligent geoscientist should seek such evidence.
End of answer
It is also possible that the reports are designed to generate enthusiasm and encourage potential investors, particularly because the initial drilling campaign off the Falkland Islands was allegedly disappointing.
One particularly useful approach to reserves estimation is based on the observation that the largest discoveries are normally made early in the life of a play, because they are in the biggest structures that get identified and drilled first: they are the least risky and income from them allows costs to be recovered quickly. Then, as the number of exploration wells increases, so the average volume of reserves proven by each discovery diminishes. This typical pattern is illustrated in Figure 15 where, at point A, the first major discovery defines the play and reserves estimates increase rapidly. Over time, when point B is reached, only smaller fields within the play remain undiscovered and the rate of reserves additions declines. If only one play exists in this basin, then the total reserves discovered over time will approach the estimate at point B*. This trend, described by the curve A–B–B*, is referred to as a creaming curve by analogy with skimming the cream off the top of the milk.
However, if a second play is discovered (Figure 15, point C), reserves estimates increase rapidly again, and the cumulative reserves for the basin as a whole will approach point D* in time. Discovery of a third play, at point E, will increase the reserve estimate still further. The discrete creaming curves describe the evolution of plays over time and give a measure of their contribution to the basin as a whole.
Figure 15: Hypothetical creaming curves for new plays discovered within a basin. See text for discussion of the figure.
Activity 4
Examine Figure 16, showing the creaming curves for the Norwegian sector of the North Sea.
Figure 16: Creaming curves for the Norwegian sector of the North Sea. For use with Activity 4.
1.
Which is the most productive play and how much resource has it yielded?
2.
How many targets were drilled in the Upper Jurassic play before the largest discovery was made?
3.
Do you think it is likely that the Palaeocene play will yield a single discovery in excess of its current reserves?
Answer
(1) The Lower and Middle Jurassic play is the most productive, having yielded 2016 million toe. (2) About 50 wells were drilled before the Upper Jurassic play was discovered and a further 100 before the largest discovery was made. (3) The Palaeocene play has been targeted about 150 times and still no major discovery has been made. It seems unlikely that this play will have much impact.
End of answer
It is clear therefore that assessments of reserves rely upon the current state of knowledge within a basin or play. Many basins that appear to be thoroughly explored continue to provide surprises as new play tests are conducted, and thus it is useful to remember the explorer's adage:
‘We usually find oil in new places with old ideas. Sometimes, also, we find oil in an old place with a new idea, but we seldom find oil in an old place with an old idea. Several times in the past we thought we were running out of oil whereas we were only running out of ideas.’
(Parke A. Dickey)
6.2 Reserves categories and reporting
There are inherent difficulties in estimating petroleum reserves accurately, not only within a given area or play (as described above), but also within a single field. Reserves never equate solely with physical measurements such as the petroleum-saturated pore volume in a trap, but instead are influenced by a combination of technological, commercial, and sometimes political, factors, as are all other physical resources.
Petroleum reserves are an estimate of future cumulative production from known fields, and they are typically defined in terms of a probability distribution into ‘proved’, ‘probable’ and ‘possible’ categories. A probability cut-off of 90% is often used to define proved reserves, meaning that there is a better than 90% chance that they will be produced over the lifetime of the field. Although there is no single technical definition of proved reserves, a commonly used description is as follows:
The estimated quantities of petroleum which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under current economic and operating conditions.
Probable reserves are often considered to have a better than 50% chance of being technically and economically producible, whilst possible reserves are those which are estimated to have a significant, but less than 50% chance of being technically and economically producible.
In general, a proportion of a field's probable and possible reserves tends to get converted into proved reserves over time, as experience from its operating history reduces the uncertainty around what remains in the reservoir. This is an aspect of the phenomenon referred to as ‘reserves growth’. As Box 4 illustrates, petroleum companies have to be very careful in assigning their reserves to the proper category since most value is attached to those that are proven.
Box 4: Reserves reporting
During the course of a turbulent 18 months of financial reporting between 2003 and 2005, Royal Dutch/Shell Group announced its fifth reduction of proven reserves. The ‘write-downs’ amounted to 8 × 108 toe, or 30% of the company's total reserves originally reported for 31 December 2002. Regulatory authorities fined Shell about $150 million for committing stock market abuse and breaching the reporting rules. Shell has also agreed to commit a further $5 million to developing and implementing an internal compliance programme.
The importance of proper reserves reporting is to allow investors and the public at large to put a value on the assets of oil companies and to make comparisons between them. However, this only works if all companies report reserves to the same standards. Financial accounting rules, and thereby reserves reporting, vary from country to country.
The United States Securities and Exchange Commission (SEC) define the accounting standards that must be adhered to by companies listed on the New York Stock Exchange. Their definition of ‘proved reserves’ was first published in 1978. This has created numerous problems for companies because technology has not stood still in the meantime. As an example, advances in 3-D seismic, direct hydrocarbon detection and refined reservoir models, all allow far greater precision in establishing in-place and recoverable reserves than was possible a quarter of a century ago.
The SEC engineers themselves state that ‘it is difficult, if not impossible, to write reserve definitions that easily cover all possible situations’. Nevertheless, the thrust of the SEC definition remains that companies may disclose only proved reserves that have been demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions.
6.3 The global picture
The global occurrence of petroleum is very patchy and there are sound geological reasons for this. The most significant is the distribution of continental and oceanic crust, because source rocks, the prerequisite for any petroleum system, are confined to continental crust, including continental shelves. Elsewhere, and mainly concealed beneath the world's great oceans, vast areas of oceanic crust have no source rocks and therefore no petroleum potential. Similarly, igneous and most metamorphic rocks cannot source and rarely host petroleum, so areas where they predominate, such as Scandinavia and the Canadian Shield, are poor in petroleum resources.
In contrast, petroleum-rich countries generally have one of the following two features:
1.
Particularly prolific petroleum basins within their borders. The top five countries in terms of their share of proved world oil reserves (as at end 2004) are: Saudi Arabia 22.1%, Iran 11.1%, Iraq 9.7%, Kuwait 8.3% and the United Arab Emirates 8.2%.
2.
Large continental or continental shelf areas, which are statistically more likely to contain sedimentary basins with the key ingredients for petroleum. For example, the five largest countries in the world (by area) contain the following share of total proven world oil reserves (as at end 2004): Russian Federation 6.1%, Canada 1.4%, China 1.4%, United States 2.5% and Brazil 0.9%.
There are specific features of the geology of the Middle East that make it so richly endowed with petroleum. The region contains several world-class source rocks ranging in age from Palaeozoic to Tertiary, with very thick reservoirs and seals above them, in enormous, low-relief anticlines. In addition, most of its reserves were easily discovered because of the simplicity and sheer size of the traps.
6.3.1 World oil statistics
According to BP's Statistical Review of World Energy, which is generally taken as a reliable source, world proved crude oil reserves at end 2004 were estimated at 1188.6 billion barrels or 161.6 billion toe (1 barrel is equivalent to 0.136 toe). Figure 17 and Table 6 show the breakdown of this total by region. Note that Europe and Eurasia, Africa, and South and Central America each have about 10% of world reserves, but they are overwhelmed by the Middle East which has 61.7%.
Figure 17: Proved world oil reserves by region at the end of 2004 in billions of tonnes of oil equivalent (109 toe).
Table 6: Proved oil reserves (at the end of 2004, in billions of toe).
Region
Reserves/109 toe
Share/%
R/P ratio/years
Middle East
99.8
61.7
82
Europe and Eurasia
18.9
11.7
22
Africa
15.3
9.4
33
South and Central America
13.8
8.5
41
North America
8.3
5.1
12
South Asia and Pacific
5.6
3.5
14
Global total
161.6
100.0
40
One useful measure of assessing reserves is the reserves-to-production (R/P) ratio. If the reserves remaining at the end of any year are divided by the production in that year, the R/P ratio is the length of time that those remaining reserves would last if production were to continue at that level. The world oil R/P ratio rose sharply during the 1980s because significant new discoveries in the Middle East outpaced the steady growth in world production. Since reaching a peak of 43.7 years in 1989 it has hovered around the 40-year mark. Whilst this figure conceals some strong regional differences (see Table 6), it supports the notion that reserves are sufficient to bridge the gap between current demand and a transfer to alternative energy sources in the future.
World oil consumption continued to rise inexorably, and reached 80 million barrels per day during 2004. Growth was a global phenomenon, with consumption in all regions rising above the 10-year average on the back of a strong world economy. In particular, Chinese oil consumption rose by just under 16%. The Middle East accounted for 41% of world crude oil exports in 2004 (about 21% of Middle East production is consumed there). The USA accounted for about 26% of global imports, and 19% of US imports were from the Middle East (Canada, South and Central America accounted for 27%). European imports accounted for 22% of global oil trading (26% of Europe's oil imports came from the Middle East, and 50% from the former Soviet Union and North Africa). The other major industrialised part of the world, SE Asia, received 78% of its imports from the Middle East. It is quite clear why the Middle East is an area of such great political concern, and that it will remain so for a long time.
Box 5: Petroleum and units of measurement
The petroleum industry has a somewhat lax attitude towards standardisation of units. Whereas scientists have adopted the SI system universally, relics of the past prevail amongst oil-industry production engineers and statisticians. As you will know, crude oil is still sold by the barrel; a unit of volume that was defined by US coopers in the 19th century as 42 US gallons. Unfortunately, the US gallon differs from the Imperial gallon formerly used in the UK (1 barrel = 35 Imperial gallons). In SI units a barrel has a volume of about 0.16 m3. Since the density of oil varies from 0.79 to 0.97 t m−3, with an average around 0.84 t m−3, expressing oil in terms of mass is rather vague. We use the average density in converting reserves quoted in barrels into tonnes of oil equivalent (toe).
Natural gas might seem an easier material as regards units, and the unit used most commonly is the cubic metre (usually in multiples of a trillion or 1012 m3), although in the US cubic feet are still commonly used. The problem arises when the energy content of natural gas, and those of other energy resources, are needed for comparison with that of oil. It is common practice to convert volumes into toe, and many global statistics use the toe. Again there is imprecision, as different oils have different energy contents (in joules, J) and so too do different ‘varieties’ of other fossil fuels, including natural gas. It would be convenient to compare every kind of energy source in terms of the fundamental unit of energy, the joule. You will appreciate that is not possible in the case of fossil fuels, so we stick with toe for oil, and m3 for natural gas, but retain barrels of crude oil in places, because we hear of the changing price of oil in terms of barrels on such a regular basis.
6.3.2 World gas statistics
At the end of 2004, world proved gas reserves were estimated at 179.53 trillion cubic metres (179.53 × 1012 m3). Figure 18 and Table 7 show the distribution of this total by region and it is notable that the Middle East, and Europe and Eurasia are far more equitable in terms of gas reserves than for oil. Together they account for 76.3% of the world reserves.
Table 7: Proved gas reserves by region (at the end of 2004).
Region
Reserves/1012 m3
Share/%
R/P ratio/years
Middle East
72.83
40.6
>100
Europe and Eurasia
64.02
35.7
61
South Asia and Pacific
14.21
7.9
44
Africa
14.06
7.8
97
North America
7.32
4.1
10
South and Central America
7.10
4.0
55
Global total
179.53
100.0
67
Figure 18: Proved gas reserves by region at end 2004. Volumes in trillion cubic metres (1012 m3).
The world gas R/P ratio has risen over the last 20 years despite a 75% increase in gas production. This is because the 1990s was a particularly successful decade for gas discoveries in Russia and the Middle East and these cumulative reserves have outpaced production. With the exception of North America, all regions are well endowed with natural gas and have R/P ratios sufficient for several decades.
World gas consumption rose by 3.3% in 2004 to reach 2.69 × 1012 m3. Growth was robust outside North America where consumption stagnated in the face of high prices and industrial restructuring. That said, North America still accounted for 29% of world gas consumption, outstripped only by Europe and Eurasia (41%).
The largest exporters of gas by pipeline were the Russian Federation and Norway, mainly to countries such as Germany, Italy, France and Turkey that have a particularly strong dependency on imported gas. The North American market was sustained by the net import of 93 billion m3 of gas from Canada to the USA. The principal movement of liquified natural gas (LNG) was in the South Asia and Pacific region where Japan and South Korea imported 60% of total world LNG, principally from Indonesia, Malaysia and the Middle East.
6.4 The UK context
For the sake of comparison, it is interesting to note that at the end of 2004 the UK had proved reserves of 4.5 billion barrels of oil (611 million toe) and 590 billion m3 of gas. This implied a R/P ratio of only about 6 years and a UK contribution of less than 0.5% to the world share of proven oil reserves, and about the same percentage for UK gas. These rather stark statistics conceal the fact there are probably still very significant reserves to be exploited. Remaining oil reserves at the end of 2004 were estimated to be between 23–31 billion barrels (3.2 to 4.2 billion toe), which is about the same volume that has been produced to date (Figure 19). Some of these reserves are proved because they are associated with producing fields, whilst the remainder fall within the probable and possible reserve categories as they are ascribed to undeveloped discoveries and exploration potential.
Figure 19: Oil reserves estimated to be beneath the UK continental shelf in 2004, compared with production up to 2004. Note that the proven reserves are included within the producing/being developed category, some of which are probable reserves because of remaining uncertainties. Undeveloped discoveries are mainly probable reserves, while the exploration potential covers possible reserves.
The exploitation of remaining reserves presents a major challenge to all stakeholders (operators, government, contractors, trade unions). Fields are smaller and more complex, unit costs are high and infrastructure may not be accessible – all these factors will determine the economics of development and dictate the lifespan of the British North Sea petroleum fields.
Whereas the UK passed its peak production in 2000 it is expected to remain self-sufficient in oil until 2009–10. UK gas production currently meets over 90% of demand and is forecast to fulfil 60% of demand in 2010. Thereafter, the North Sea will still sustain meaningful production for several more decades.
What difference would a decade of consistently high oil prices make to the North Sea fields?
Answer
It would allow the relatively small discoveries that have been made in recent years to be developed and would sustain the production from existing fields through increased drilling and improved recovery factors. These measures should prolong the economic life of the North Sea fields and reduce the UK's need for importing oil and gas.
End of answer
You should bear in mind, however, that the price of oil is mainly determined by the rate at which oil is produced from the vast oilfields of the Middle East, where costs are much lower than for North Sea fields. Much of the variability in oil price depends on political decisions in Middle Eastern oil-producing countries, and the extent to which political (and other) pressures from major oil importers affect those decisions.
7 Non-conventional sources of petroleum
7.1 Oil sands
Non-conventional sources of petroleum, such as oil sands, heavy oil and gas hydrates, greatly exceed the world's entire endowment of conventional petroleum. Yet, because of technological, commercial and environmental constraints to production, non-conventional petroleum currently accounts for only about 5% of global consumption. This huge imbalance will slowly change as the inevitability of declining conventional petroleum reserves and increasing prices hits home. This page deals with oil sands; the next will deal with gas hydrates.
If a near-surface rock has good reservoir properties, large volumes of oil can flow into it from mature source rocks buried deep below. Exposure of crude oil to air and bacteria close to the surface degrades it to thick, viscous bitumen. Over time, tens of metres of rock from the surface downward can become completely impregnated with bitumen, forming a deposit known as oil sand.
Oil sand is composed of bitumen, sand, clays and water. Bitumen, in its raw state, is black and thicker than treacle. It requires treatment to make it fluid enough to transport by pipeline and to be usable by conventional refineries. The process involves large-scale surface strip-mining of enormous volumes of oil sand (see Figure 20a below). The sands are then heated to between 35–80 °C to separate and chemically change the bitumen to lighter hydrocarbons using water-based extraction methods. The upgraded product consists of light and heavy oils that are blended to produce a light crude oil with a low sulphur and nitrogen content.
The world's largest producer of crude oil from oil sand, Syncrude, is based in the Athabaska area of northern Alberta in Canada. Their product is called Syncrude Sweet Blend, and in 2004 it accounted for about 10% of Canada's total crude oil production. With billions of barrels recoverable using current technology, the Athabasca deposit constitutes a resource for decades to come. Importantly, the drive to reduce operating costs to their current level of around US$10 per barrel has also been accompanied by significant reductions in sulphur emissions, water abstraction and power usage during the upgrading process.
Figure 20: Large-scale extraction of oil sand in northern Canada. (a) Satellite image of the Syncrude operation at Fort McMurray, Alberta. Active and near-future operations are at lower left and top centre. The image is about 15 km across. (b) To operate continuously, oil-sand mines need the world's largest excavators. This is the Krupps Bagger 288, a bucket wheel reclaimer, which is the largest land vehicle ever built. It is on its way to a lignite mine in Germany: similar machines operate in the Canadian oil-sand mines.
When oil sands occur at depths that are too great for surface mining, in situ extraction involves injecting steam and/or hot carbon dioxide to lower the viscosity of the oil and enable it to be pumped to the surface.
Petroleum accumulations that will not flow to the surface under natural reservoir pressure are referred to as heavy oils. They are characterised by high viscosity that increases with their density, low hydrogen/carbon ratios, low gas/oil ratios and significant sulphur, asphalt and heavy-metal contents. Heavy oils can form for a variety of reasons, such as kerogen composition, level of maturity, depth of burial and exposure to water, air or bacteria. The economics of heavy oil production typically suffer from high extraction costs and a discounted value because of their inferior quality. As a result, the vast remaining global resource of heavy oils is still very much underexploited.
7.2 Gas hydrates
The temperature and pressure of the deep oceans are controlled, respectively, by deep, cold currents that move from polar latitudes along the sea floor and by the mass of the overlying water column. Consequently, at depths exceeding 300–500 m the sea floor is at a temperature of around 1–2 °C and a pressure that is several hundred times greater than atmospheric pressure. Under these physical conditions, gases such as methane (CH4) and carbon dioxide (CO2) can combine with water to form solid, ice-like crystalline compounds known as gas hydrates (see Section 5.2.2, Figure 14). Clearly, economically interesting gas hydrates are those which contain proportionally far more hydrocarbon gases in their structure than CO2. Depending on the geothermal gradient, the base of the hydrate stability zone may extend to depths of more than 1000 m beneath the ocean floor.
Hydrocarbon gas hydrates can form in deep ocean water but they are not found as a carpet on the sea floor. This is because such hydrates have a lower density than that of seawater (850 kg m−3 compared with 1025 kg m−3). As soon as they form, they float upwards and turn back into methane and water in the lower pressures and warmer temperatures of the upper layers of the ocean.
However, within the sediments just beneath the sea floor, crystals of hydrocarbon gas hydrate form and move upwards buoyantly. Frequently the rising crystals form a ‘log-jam’ within the pore space of the sediment and once this occurs, more gas hydrate crystals become trapped in the pore spaces beneath. Eventually, all available pore spaces in the sediment become completely filled by gas hydrate crystals that readily absorb methane into their lattice. Fully saturated gas hydrates can hold up to 200 times their own volume of methane, creating a zone that is denser than seawater and thus gravitationally stable.
The gas required for formation of gas hydrates comes from two principal sources: biogenic and thermogenic. Biogenic gases are those produced in situ by bacterial breakdown of organic matter contained within the sea-floor sediment. The dominant biogenic gas is CH4 (>99%) with traces of CO2 and H2S. Such gases typically form in oceanic areas that have relatively high rates of sedimentation and plenty of organic matter, such as the coastal margins of North America and the North Pacific Ocean. In contrast, thermogenic gases are those produced by the maturation of kerogen at much greater depths and elevated temperatures, as described in Section 2. Thermogenic gas hydrates contain significant amounts of ethane, propane and butane, and they occur in petroleum-rich provinces, such as the Gulf of Mexico and Caspian Sea, where leakage to the surface is common.
Gas hydrates do not form only in the oceans, but also in deep lake sediments and onshore permafrost zones across Arctic Canada and Russia. Current estimates suggest that gas hydrates globally may contain 1–5 × 1015 m3 of methane, a figure that dwarfs the remaining proven reserves of conventional gas. But there are some issues of both concern and potential, summarised by Figure 21.
Figure 21: Illustration of the major issues concerning gas hydrates in sea-floor sediments. (Left) Earthquakes trigger gas-hydrate instability that in turn triggers massive slumping of sea-floor sediments and tsunamis. Installing large structures on the sea bed might result in rapid release of gas and instability of their foundations. Any release of methane promotes global warming. (Right) The huge potential for developing gas hydrates as resources – they are readily discovered by their distinct ‘signatures’ on seismic sections.
On the positive side, the potential of methane hydrates as a major strategic energy reserve is obvious and much research is being conducted to develop appropriate extraction techniques. This extends to considering whether methane production could be combined with CO2 disposal, thus addressing the twin challenges of this century – reducing the emissions of greenhouse gases and providing a low-carbon fuel to replace oil and coal.
On the negative side, it is now recognised that gas hydrates are a potential geohazard. Dissociation of hydrates at the base of the gas hydrate stability zone (Figure 21) can cause increased pore-fluid pressures in under-consolidated sediments, forming a zone of weakness and a site of potential sea-floor failure. Slope failure can threaten underwater installations and, in extreme cases, generate tsunamis. It has even been suggested that during periods of climatic warming such as we are experiencing at present, onshore hydrates become destabilised, liberate methane to the atmosphere and thus accelerate global warming.
8 Unit summary
The main points covered in this unit are summarised below.
1.
Hydrocarbons are compounds composed mainly of carbon and hydrogen. In addition to hydrocarbons, petroleum contains significant quantities of oxygen, nitrogen, sulphur, nickel and vanadium, plus minor quantities of a host of other elements. Petroleum may be liquid (crude oil), gaseous (natural gas) or solid (bitumen).
2.
The necessary ingredients for any accumulation of petroleum – petroleum charge – are source, maturation, migration pathway and trap. As knowledge about these factors develops during the exploration and development of a petroleum-rich basin they help define petroleum plays, which are realistic strategies for directing further development.
3.
An effective source rock contains sufficient organic matter, in the form of kerogen, to produce fluid hydrocarbons when heated (matured) to temperatures above the generation threshold of about 50°C.
4.
Fluid petroleum migrates for two reasons. During burial and compaction, fine-grained, clay-rich sediments lose pore space between their grains. Water and petroleum thus expelled from source rocks start primary migration. Petroleum moves buoyantly in response to the pressure gradient within permeable strata as secondary migration begins.
5.
For petroleum to become concentrated in an economic oil or gas field, suitable rocks must be charged with petroleum fluids. These reservoir rocks must not only be porous enough to contain substantial amounts of petroleum but must also be permeable enough so that fluids can flow in to accumulate, and out during extraction. Almost all reservoir rocks are sandstones or limestones.
6.
Permeable reservoirs must be capped by impermeable seals, usually mudstones, or evaporates in one of several kinds of trap.
7.
Structural traps are formed by the deformation of sedimentary rocks and include anticlinal domes and fault traps. Other examples of structural traps include those associated with salt masses that have moved upwards because of their low density, sometimes to ‘intrude’ other sediments. Stratigraphic traps occur where there is a barrier caused by lateral permeability variation in sedimentary rocks.
8.
The main method of determining whether an area has potential traps for petroleum is seismic exploration. Seismic sections provide images of the subsurface. Once detected, a potential trap can be mapped in detail using 3-D seismic data to define its shape and the thickness of petroleum-bearing parts of the reservoir. Porosity and permeability of the reservoir rock determined by direct measurements of exploration-well samples then allow the volume of oil and gas that can be recovered to be estimated.
9.
The most significant local environmental risks from petroleum production come from accidental spillages during transportation.
10.
Primary recovery methods produce at best only 30% of the oil present. Secondary recovery techniques that pump pressurised water and gas into the reservoir can boost the amount to ∼65%, and more still can be recovered by injecting steam or chemical and biological additives into the reservoir to reduce viscosity. The feasible recovery has an important bearing on the estimates of a field's reserves.
11.
In 2004, global petroleum reserves were 162 billion toe of oil (1189 billion barrels) and 180 trillion cubic metres of gas.
12.
Petroleum reserves in the British North Sea are minute (0.5%) compared with those of the Middle East, which controlled 62% of the world proved reserves of crude oil in 2004.
13.
Large amounts of oil and natural gas are locked into oil sands and gas hydrates, but, apart from the Canadian oil sands, they do not yet constitute a globally significant economic resource.
Glossary
base-line study (environmental)
An assessment of the original, natural state of the environment before development takes place.
bitumen
Solid form of naturally occurring petroleum that consists of high molecular weight hydrocarbons. Sometimes known as tar, although that can also be produced from coal during the coking process.
cap rock
An impermeable rock layer that seals petroleum in rocks beneath it, to form a trap.
combination traps (petroleum)
Traps with both structural and stratigraphic components.
creaming curve
A plot showing the varying rate of increase in petroleum reserves as exploration of an oilfield or play progresses.
crude oil
Liquid petroleum that occurs naturally in reservoirs within sedimentary rocks.
decommissioning
Disposal of an installation after its useful lifetime has expired.
environmental impact assessment (EIA)
Ecological study aimed at assessing the likely effects of developing physical resources on the pre-existing environment, as defined in a base-line study, and means of mitigating the effects.
gas hydrates
Crystalline hydrocarbons that form by the combination of methane and/or carbon dioxide with water under the low-temperature and high-pressure conditions of the deep ocean floor.
gas sequestration
Disposal into long-term storage of the carbon dioxide produced by the use of fossil fuels, either by using petroleum reservoirs or other secure sites from which the gas cannot escape.
gas venting and flaring
The deliberate release and burning of natural gas that comes up wells along with oil, because collecting the gas for sale is not economic.
geothermal gradient
The rate at which temperature increases with depth in the Earth.
gravity surveys
Measurements of variations in the Earth’s gravitational field, which can show areas underlain by rocks of different densities.
heavy oil
Oil with high viscosity and density that occurs in oil sand deposits.
kerogen
A general term for organic material in petroleum source rocks; the name is derived from the Greek for ‘wax producer’.
magnetic surveys
Measurements of the Earth’s magnetic field, which can show variations due to the occurrence of rocks with different levels of magnetization, mainly due to oxides containing iron and titanium.
maturation
The process – involving chemical reactions, time and burial temperature – that transforms natural kerogen into crude oil and natural gas.
natural gas
Gaseous form of petroleum that consists mainly of methane, with other low molecular weight hydrocarbon gases.
net to gross
The ratio or percentage of porous and permeable rock thickness to that of the overall reservoir rock.
oil sand
A sedimentary sandstone whose pores are saturated with heavy oil or bitumen that is too viscous to flow easily – sometimes known as a tar sand because of the tarry consistency of the oil.
permeability
A measure of the degree to which fluid passes through a porous rock.
petroleum
A complex mixture of hydrocarbons and lesser quantities of other organic molecules containing sulphur (S), oxygen (O), nitrogen (N) and some metals. Petroleum is derived from the chemical alteration of kerogen in source rocks.
petroleum charge
A concept concerning the formation, migration and accumulation of petroleum in a body of sedimentary rocks. It involves consideration of source rocks, maturation, geological history and migration paths in a sedimentary basin.
petroleum play
A model that can be used to direct petroleum exploration. Plays consolidate what is known about petroleum charge, reservoirs, seals and traps, together with geological structure, and enable the chances of petroleum accumulations to be assessed at specific stratigraphic levels within a sedimentary basin.
play fairway map
Depiction of areas where geological conditions imply a high likelihood of petroleum occurrences, as deduced from a petroleum play.
porosity
The void space in a rock, commonly expressed as a percentage.
possible reserves (petroleum)
A category of reserves for which there is a significant (>0 but <50%) probability that they are technically and economically recoverable. A definition used widely in the petroleum industry.
