Notes 1 Sedimentary Basins 2010

PgDip/MSc Energy Programme/Subsurface Sedimentary Basins

Sedimentary Basins

Review

In this topic the student is introduced to the different types of sedimentary basins and their importance to the petroleum industry.

Content

The Habitat of Petroleum A sedimentary basin is an area of the Earths crust where sedimentary sequences are much thicker than those found in surrounding areas. Oil and gas commonly occur in sedimentary basins, whilst being absent from intervening metamorphic and igneous rocks. Most sedimentary basins cover tens of thousands of square kilometres, and may occur as part of a mountain chain, beneath a continental peneplain or under an ocean.

There are more than 600 sedimentary basins Worldwide and over a quarter of them produce petroleum. Figure 1 shows the global distribution of the major basin areas and the major oil producing regions.

Figure 1. Sedimentary Basins Around the World (From THE DYNAMIC EARTH by B.J. Skinner and S.C. Porter, copyright 2000 John Wiley and Sons. This material is used by permission of John Wiley and Sons, Inc.).

There are five essential requirements for the formation and preservation of oil and gas. For these five requirements, a sedimentary basin with a thickness of at least 2500 to 5000m of sediment is needed to ensure that the source rocks are mature to the oil generation threshold. The magic five are:

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1. a source rock: fine grained shale or limestone with a minimum of 0.5% petroleum producing organic matter;

2. heat is required to generate petroleum from the organic matter. The oil window is from 60 C to 120 C for the production of oil and up to 180 C for the production of gas;

3. a reservoir rock that is both porous and permeable and of sufficient thickness, sandstone and limestone;

4. an impermeable cap rock or seal composed of fine grained shales or evaporite;

5. a trap, structural, stratigraphic, combination or hydrodynamic, where the migration of petroleum is barred. The trap must have been emplaced before the migration. Once trapped the oil must not be buried too deep that it is destroyed or be allowed to escape by subsequent faulting.

Any thick sedimentary sequence may contain these ingredients and are thus important for petroleum exploration. As a general rule we can expect to find gas in the deepest parts of the basin, light oils in the intermediate zone and heavier oils in the basin margins. Hydrocarbon distribution within a basin is related to both the thermal maturation of the source beds and the permeable migratory paths. For example, gas requires higher temperatures for formation and will therefore be more prevalent at depth unless allowed to migrate. A mixture of oil and gas that is allowed to migrate up and across a basin will fill traps as it travels. Gas is less dense and will therefore spill from a trap after the oil. As a result deeper traps will contain gas, and shallower traps, oil. As always, however, local conditions will produce exceptions to this, the Niger Delta being an example.

Sedimentary Basin Formation Formation of a sedimentary basin of sufficient size to produce and trap hydrocarbons can occur via several mechanisms. The formation of a topographic basin itself, however, does not mean that it will fill with sediment. This will be dictated by local conditions. The shape of the basin, the position of the thickest sediments within, and the type of those sediments, will depend upon whether the deposition occurred at the same time as the basin or before, and upon the method of sediment transfer to the region. For example, a basin may be filled with sediment as it is formed, or, as it may form at a time after deposition of sediments in that region (Figure 2). This will relate to the type of trapping structures likely to occur within the basin, when they were formed in relation to kerogen maturation, and hence the probability of finding oil. The method of sediment transfer will influence sediment topography. Deltaic sediments will tend to advance in a linear fashion, for example, and the greatest thickness may not necessarily coincide with the maximum basin depth.



Figure 2. Sediment Thickness and Sediment Type in Relation to Deposition Time (after Selley, 1998).

Basins can be classified according to their mode of genesis, although, as in other areas of geology, this serves only as a guide and is not a strict scientific classification system. Additionally, the history of a particular basin is likely to be complex, and it may have changed from one type to another over time.

Basins form in four main ways and can be found both at plate margins and within continents:

crustal tension (constructive and transform margins); crustal compression (convergent and transform margins); in response to vertical crustal movements (temperature and phase

changes below the lithosphere);

due, rarely, to loading by deposited sediments (deltaic deposits over oceanic crust).

From these, the most significant basins in relation to the petroleum industry are formed by crustal thinning and rifting. Figure 3 illustrates basic examples of the three main mechanisms. Due to the complexity of basin formation the details of these mechanisms are still areas of scientific debate, and as such, well outside the scope of this text. Three different models are commonly accepted as being valid for rift drift sequences for example (Figure 4), although many more have been suggested. Of these, the McKenzie model receives particular attention within the oil industry, as it predicts heat flow, and can therefore be used to model petroleum maturation. The following sections, therefore, aim to illustrate the main types of sedimentary basins with relation to their basic genesis and occurrence, rather than act as a definitive guide.



Figure 3. Various Types of Basin Formation (after Selley, 1998).

Figure 4. Three Common Models for Rifting (after Selley, 1998).

Basins Associated with Divergent Margins Rift-drift basins are formed at diverging constructive margins and are associated with major fault systems. They account for over 80% of petroleum occurrence in basins. Grabens are bounded by two sets of faults, and half grabens, one set. Several general stages can be recognised in rift basin formation, independent from the driving mechanisms and deformation characteristics:

Stage 1: Magma is pushed up from the molten mantle into the older crust on top. This crust is weakened and uplifted leading to faulting.



Stage 2: The weakening of the crust will often result in the formation of a graben or rift valley. The uplifted area will be exposed to erosion and the resulting sediment will be transported and deposited in the low lying basin areas of the rift valley. These basins tend to be relatively small and away from the source rock formations. Traps are not normally well developed and volcanoes can be associated with the rifting. Volcanic ash deposits mixed with sediment will reduce the available pore space and permeability in potential reservoir rocks. Small fields are exploited in the Rhine graben of Germany.

Stage 3: As the spreading of the plates continues the rift will widen and develop further. Faulting and dropping of the blocks will continue until eventually the sea will inundate the basin (Gulf of Suez). Volcanic interference has disappeared and there is generally now an abundance of organic matter for the generation of potential source rocks. Wave and tide action will sort sediment derived from the eroded uplifted areas to provide potential reservoir sands. The formation of combination traps is likely as fine muds are deposited over the tops of earlier faulted, collapsed and tilted blocks (Argyll Field). The formation of evaporites is also possible.

Stage 4: Eventually the magma will force through the crust and the new oceanic crust will be formed.

Stage 5: The continental margins away from the centre of spreading are stable. They cool and subside creating wide continental shelves. Thick sequences of sediment will accumulate.

Petroleum generation, migration and accumulation will depend on localised factors: potential formation of source rocks, reservoir rocks and the creation of traps. Delta formations at the head of major rivers provide suitable habitats. Deltaic sand deposition provides the reservoir and organic rich source rocks (Niger and Mississippi Deltas). This rift drift sequence, continuing today along several active mid ocean ridges, may stop at any point. The North Sea graben is an example of a rift which failed to grow beyind the initial stages.

Sedimentary sequences also tend to follow a regular pattern, not surprisingly. When the rift is still above sea level, sediments are composed of continental clastics, often of volcanic origin. As sea level is reached, the formation of evaporites is favoured due to vertical oscillation and flowing of the sea in and out of the rift area. On final immersion, organic rich marine muds will be deposited within the still restricted trough area. Finally, as the rift opens into the wider ocean, open marine sediments such as carbonate shelves and clastic wedges from the surrounding continental shelf may be deposited.

Basins at Converging Margins Convergent margins can occur as continent-continent, continent-oceanic or oceanic-oceanic crust collisions. As one plate is subducted under the other the crust is subjected to compressional forces. The resultant form of the boundary will vary with the type of collision, but several characteristics are common. At the boundary itself a trough will form as one plate sinks below, and drags, on the other. Wedges of compressed



sediments and faulting may produce a non-volcanic island fore-arc. On the overriding plate a rise in the crust due to compression leads to island arc or mountain range formation (orogeny), often with associated volcanic activity. In turn, behind this, a drop in height will lead to a back-arc plane or trough. Sedimentary basins may form in either the fore-arc or back-arc troughs (Figure 5). Extremely high compressional forces and volcanic activity are not conducive to petroleum formation. Occurrences are more prevalent in back-arc troughs, or in broadly shelving fore-arc troughs.

Back-arc troughs or basins tend to be asymetric, with sediment thickness increasing towards the arc. Deposits largely consist of carbonates, shallow marine shales and mature tidal shelf sands with some non-marine sediments. The majority of sands are produced by weathering and extensive re-working of the crust, mainly in high energy marine environments. The resultant deposits therfore tend to be mineralogically mature, well sorted, and to have good porosity and permeability. All conditions favourable for reservoir rock formation. During the later stages, however, detritus (erosional or volcanic) tends to be deposited from the arc as it rises further. These deposits will be less mature and less well sorted than those deposited previously, and therefore less likely to produce a good reservoir.

In addition to good reservoir rock potential, back-arc basins have conditions favourable for source rock deposition. Extensive marine shelves combined with deposition of clays during periods of marine transgressions and uplifting of the arc (environment isolation) all combine to form potential source environments. Trapping structures are also varied. Anticlines and other structural traps can form near the thrusted regions, whilst further away, conditions are favourable for the formation of many different stratigraphic traps. Back-arc basins therefore have a high potential for hydrocarbon production.

Figure 5. Common Features Associated with Fore-arc and Back-arc Basins.

Fore-arc basins are much more complex in both physical structure and geological facies. Sediments can come from a wide range of environments from continental to deep marine. Sands will be eroded from the volcanic arc and tend to be immature. If the arc shelves steeply deposition will be rapid and there will not be time for mineralogical



maturation or sorting. Shallow, broad shelves, conversely, will allow some maturing and sorting before depostion, so are more favourable for reservoir rock formation (Cook Inlet, Alaska). Formation of an outer arc by thrusting of fore-arc sediments will also deposit sediments into the basin as it rises. Sands from this process, as with volcanic deposits from the main arc, tend to be immature and may be deposited rapidly. Fore-arc basins, therefore, tend to be less conducive to reservoir formation than back-arc basins.

Source rocks may however be abundant due to occurrence of deep, restricted, sea floor environments. The depth of the oil window however may be deeper than expected, as the subducting plate cools the surrounding rocks, at depth, resulting in a decreased isothermal gradient within the basin.

Traps in fore-arc basins tend to be structural due to the extensive folding and faulting present. As a result, fields may be complex, and individual pools may be small and hard to locate.

Basins at Transform Margins Transform margins are characterised major wrench faults. Movement is not normally completely transverse. Areas of compression and tension will exist which, due to the nature of the fault, may change from one to the other. This leads to the formation of rift basins that are normally small, deep, subside rapidly and have high heat flow. They are often asymmetric with alluvial and submarine conglomerates along the active fault boundary. Sedimentary sequences tend to be thick and consist of rapidly buried clastics varying from deep sea to continental deposits. Source rocks may be extremely rich due to the deep oceanic deposits. Traps tend to be within faulted anticlines.

An important petroleum habitat along a transform margin: California, where approximately 35 small basins lie on either side of the San Andreas Fault.

Basins within Continents Basins formed within normally stable continental crust, away from faults, are termed cratonic, and may be split into intracratonic (wholly on continental crust) and epicratonic (bordering oceanic crust). They are usually circular in nature and may contain horst and graben structures within but major rifting is absent. Formation mechanisms are poorly understood, but phase changes within the mantle, mentioned earlier, have received particular interest. The most popular proposes that a hot spot produces doming of the crust, leading, in turn, to erosion of the uplifted rocks, followed by cooling and collapse. Collapse will initially be rapid, leading to rifting, followed by a period of gentler sagging or subsidence. Conversely, mantle cold spots have been proposed as the source. In this scenario cooling will lead to downwelling and gentle sagging of the crust. Faulting of the basement rocks due to crustal extension during a failed rifting period has also been suggested. All studies are generally based on a particular region or collection of regions



and it seems likely therefore that a variety of mechanisms are responsible.

A cratonic basin will become important to the petroleum industry depending on when the basin was formed (the type of organic deposits and length of possible maturation time), the local environment at the time and throughout its development (land or sea), and its resultant depth (conducive to the oil) window. Intracratonic basins tend to be broad, shallow, saucer shaped basins, whereas epicratonic basins tend to take on the form of an embayment from the oceanic crust into the continental crust (Figure 6).

Their sediments may be dominated by continental clastics (termed terrigenous) or carbonates (marine or evaporitic). Changes in sea level over time can vary the sequences contained to a large degree and change the dominant sediment type. Any classifications based on sediment type therefore are only based on historical differences rather than any structural differences.

Figure 6. Intracratonic (left) and Epicratonic (right) Basins (Selley, 1998).

Relative Importance of Sedimentary Basins Several studies have attempted to classify sedimentary basins and their relative importance around the globe. One scheme developed by Klemme (1980) attempted to classify them by structure. He split basins into eight types (Figure 7). Again this is a guide rather than a strict classification system.



1.5

18.2

25

27.3

105.4

47

17.5

0.5

18.2

7.5

7.1

2.5

3.7

6

2.6

0 5 10 15 20 25 30 35 40 45 50

Type I. Intracratonic basins

Type II. Epicratonic basins

Type III. Rifts

Type IV. Continentalborderland down warp

Type V. Coastal rifts

Type VI. Fore-arc andBack-arc

Type VII. Molasse

Type VIII. Tertiary deltas

World's proven oil reserves (%) World's basin area (%)

Figure 7. Distribution of Basin Types and their Relative Reserves (figures from Klemme, 1980).

Figure 7 of course shows known reserves. Reserves located within tertiary deltas and offshore basins are likely to increase as exploration techniques become more cost effective. Note also that the Arabian Gulf has a major influence on Type IV (47%) as 38% of the Worlds known reserves are in this one area.


ReviewContentThe Habitat of PetroleumSedimentary Basin FormationBasins Associated with Divergent MarginsBasins at Converging MarginsBasins at Transform MarginsBasins within ContinentsRelative Importance of Sedimentary Basins

Notes 1 Sedimentary Basins 2010

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