Relationships between seepage, tectonics and subsurface petroleum reserves

Relationships between seepage, tectonics and subsurface petroleum reserves Duncan S. Macgregor BP Exploration Operating C o m p a n y Limited, 4/5 Long Walk, Stockley Park, U x b r i d g e UB11 1BP, UK

Received 15 July 1992; revised 27 November 1992; accepted 5 December 1992

The relationship between visible petroleum seepage and commercial subsurface reserves has been investigated by a study of the distribution of documented seeps in south-east Asia. This is accompanied and integrated with a broader global study. The intensity of flowing seepage is controlled largely by present day tectonics and by the timing of petroleum migration. When such influences are reduced by isolating sets of tectonically similar basins, correlations are found between numbers of seeps and basin reserves. At a sub-basinal scale, seeps are observed to concentrate over tectonic features such as active diapirs, active faults and uplifted basin margins. It is relatively rare for seeps to directly overlie major fields, although many seeps may be linked to downdip accumulations by long tortuous paths. The best seep-accumulation relationships are observed in active compressional and diapiric settings, particularly those involving shallow reservoirs. Seeps are rare where traps are buried beneath thick undisturbed overburdens. The prime value of visible seeps in most frontier basins lies at the regional level, in the clues they give to the nature, extent and quantitative hydrocarbon potential of a basin's source system. Keywords: seepage; tectonics; hydrocarbon accumulations; migration

Introduction This paper is aimed at improving our understanding of visible seeps in the light of modern concepts of basin tectonics, dynamics and geochemistry. Invisible microseeps, such as are detected by total scanning fluorescence and other geochemical methods (Brooks et al., 1986) are not covered by this paper and will require separate study. The mapping and study of surface seepage are important tools in the search for subsurface petroleum reserves, although their importance has decreased through time as the most obvious seeping fields and provinces have been found. Seepage has, however, remained a poorly understood phenomenon. Perrodon (1983) summed up this situation in the following terms: The deeper meaning of these shows (seeps) is still fundamentally hypothetical. . . . The presence of active shows is undeniably the proof of the genesis of hydrocarbons in the basin or in a zone, but it cannot indicate whether they represent the vanguard of great battalions that have remained in the ground, or merely the last survivors of a decimated rearguard. Compared with other topics in petroleum geology, there are few recent papers on seepage. There are many broad vintage analyses of the significance of seepage in oil exploration (e.g. Cunningham-Craig, 1912; Link, 1952), most of which were written before the bulk of the world's petroleum reserves were discovered. Recent work concentrates on describing the surface and near-surface features of individual sets of seeps, e.g. in the Gulf of Mexico (Behrens, 1988;

Kennicutt and Brooks, 1990) and in the North Sea (Hovland and Somerville, 1985). Clarke and Cleverly (1991) produced a broader paper summarizing and classifying the shallow processes affecting seeps, but did not attempt a detailed study of their subsurface origins. The lack of recent studies on seepage may be linked to database problems. To enable a detailed and systematic study, the area concerned needs to have been both systematically mapped for surface seepage and densely drilled, such that sufficient knowledge exists about the distribution of petroleum at the surface and in the subsurface. For this study, the region of south-east Asia has been selected as that which comes closest to meeting these criteria. Analysis has been carried out at regional, sub-basinal and prospect scales to identify the controls and to determine the strength of the relationship between surface shows and large subsurface reserves. The hypotheses established from this regional study are then tested by reviewing published data on other basins and by a broad study of the correlation of seeps to reserves at a global scale. A series of tentative conclusions has therefore been reached by a combination of detailed work in specific regions and broader work world-wide, which I put forward in the hope of stimulating further study and contributions on this poorly understood aspect of petroleum geology.

Definitions and database As in the Link (1952) and Clark and Cleverly (1991)

0264-8172/93/060606-14 ©1993 Butterworth-Heinemann Ltd 606

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Seepage, papers, it should be noted that the terms 'seep' and 'seepage' apply only to visible features. A differentiation is also made between seeps which are flowing and thus are being replenished ('flowing seeps'), and oil-impregnated stratum which show no evidence for replenishment and therefore are not seeps in the true sense of the word ('impregnations'). It should, however, be pointed out that for many of the less spectacular onshore features it is often difficult to identify whether flow or replenishment is indeed occurring. Flow is easier to identify for offshore seeps, particularly where gas plumes or surface slicks can be identified. Mention of seeping gas always implies a flowing seep. The key database used in this study is the BP SEEPS database, described by Clarke and Cleverly (1991). The intention when compiling this database was to restrict it to flowing seeps; however, because of the incompleteness or ambiguity of many descriptions, some inactive impregnations are inevitably included. Flowing seeps are differentiated in this paper wherever possible. The SEEPS database does not cover the USA or Europe, where other published sources have been used (e.g. Link, 1952; Wilson etal., 1973; Seiley, 1992),. As pointed out by Clarke and Cleverly (1991), phase changes occur as petroleum migrates to the surface and thermogenic gas seeps are thus as relevant as oil seeps in the search for subsurface oil reserves. Indeed, it could be claimed that gas seeps have been more instrumental than oil seeps in the discovery of major oil

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reserves. For this reason rio differentiation is made between oil and gas seeps in these analyses. A similar logic has been applied to the statistics for petroleum reserves, which are quoted in oil equivalent. The quality and reliability of the SEEPS database varies regionally. Despite the considerable volume of research undertaken, it is unlikely that in any region of the world all seeps have been included. The database is thought to be most complete for regions of the world which were actively explored by western companies and geological surveys during the period 1880-1940, when the presence of seeps was a key factor in focusing exploration activity. In the region selected, south-east Asia, seeps were systematically mapped as parts of large geological surveys (e.g. Tobler, 1912; Latouch% 1918). In addition, this part of the world is unusually highly explored, thus the locations of most major fields are known. The region chosen for this study, covering the onshore hydrocarbon-bearing basins of western Indonesia, Malaysia, Brunei, Thailand, Burma and north-east India, is one of relatively uniform climatic and cultural factors. By comparison with other regions, the area is densely populated and has high water-tables. Cultural and climatic influences on the completeness of the SEEPS database are thus felt to have been minimized. Study of the distribution of seeps on a global scale, as is attempted later in this paper, must consider a number of likely non-geological influences on the database. Included in these are the effects of variations in levels of water-table between different climatic zones, geomorphological factors and omissions resulting from non-detection due to a number of

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Seepage, tectonics and petroleum reserves: D. S. Macgregor 1. Over reverse-faulted anticlines, e.g. the Naga and cultural factors. Greater stress is therefore placed in associated thrusts of the Assam region. In most this paper on the trends observed on the south-east instances seeps occur on the outcrops of reverse Asian database. faults, although in some cases seeps are developed over anticlinal crests Regional analysis: south-east Asia 2. Over diapiric anticlines, often associated with mud The region chosen for study is shown on Figure 1. All volcanoes, e.g. on the Belait anticline of Brunei, basins covered were active tectonically in the Neogene, the Muara Enim Anticlinorium of south Sumatra, therefore any influences resulting from the timing of and the Yenangyaung Anticline in Burma tectonic activity and of petroleum migration are 3. At the outcrops of highly dipping sandstone beds minimized. Most seeps considered are believed, on the on the uplifted margins of basins, e.g. on the basis of the use of words such as 'live', 'emanate' and south-eastern rim of the Belait syncline (Brunei), 'flow' in the original references (e.g. ToNer, 1912; and on the outcrops of a Late Miocene Latouche, 1918; Liechti, 1960), and/or the presence of reservoir/carrier bed on the margins of the North gas seepage, to be flowing seeps. Sumatra Basin. Figure 2 is a plot of the number of known seeps By and large, most seep-rich regions in south-east against established reserves for the main basins in the Asia have been well explored, no doubt because of the region. A good spatial relationship is seen: eight out of tantalizing evidence provided by seepage. The Belait nine basins with more than 35 documented seeps also anticline in Brunei, for instance, with about 50 seeps, contain at least one billion barrels oil equivalent, has been penetrated by more than 14 wells, from which (BBOE) proved reserves. This relationship can be a total of only 33000 bbl were recovered (Brunei Shell, explored further by differentiating the two main 1962). In all instances these regions of seepage were the tectonic trends crossing the area, i.e. the 'forearc' trend first areas to be explored for oil in the late 19th century of tectonically complex basins, extending from the and contain the earliest oil discoveries (e.g. Telaga Said collisional complexes of Assam and Burma through the in north Sumatra, Yenangyaung in Burma). However, Indonesian forearcs to New Guinea, and the 'backarc' in most instances the proportion of seeps located near trend of less deformed basins on the Sundaland and discoveries is low - - less than 10% in Burma, Brunei Eurasian continents. The 'forearc' trend shows a and Assam, increasing to around 40% in north and different statistical relationship between seeps and south Sumatra. The largest oilfields in each basin were reserves to the 'backarc' trend, and it appears that found considerably later and usually occur basinward of these highly tectonized basins are expelling a higher the seep concentrations. For example, most seeps in proportion of their hydrocarbons to the surface. the southern part of the South Sumatra Basin occur on the heavily faulted and folded western flank, but the Sub-basinal analysis: Assam, Burma, Sumatra largest fields occur on an intrabasinal high which is and Brunei largely devoid of seeps. The spatial relationship between seeps, basin geometry and the main subsurface accumulations in south-east Asia is illustrated on Figure 1. Schematic cross-sections have been compiled over each basin to show relationships in the vertical dimension (Figure 3). It is clear, even at this scale, that the coincidence between the locations of seeps and large oilfields is not good. The seeps, in general, tend to concentrate over basin margins, whereas the large oilfields are usually found close to basin centres. Fields which do seep are generally shallow, tectonically complex, and small in terms of their reserves. The only giant field in the region with nearby seepages is the Arun field of north Sumatra. Comparing with geological maps over these basins shows that seeps are largely confined to regions of shallow or outcropping bedrock. Many large fields are covered by thick recent drift deposits and this could in part explain the poor seep-accumulation relationships. However, there are still many large fields with little or no recent cover deposits which have no recorded seeps. No seeps are known for instance over the two largest fields in central Sumatra (see later), which occur in areas of shallow bedrock. In contrast with the poor observed relationship with major fields, a good relationship exists between seep concentrations and major tectonic features. Three main seep-tectonic associations are identified and are summarized below. These settings grade into each other, particularly in the cases of seeps lying over anticlines formed by a combination of reverse fault activity and mud swelling.

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Central Sumatra anomaly The Early Miocene sandstone play of the Central Sumatra Basin provides a rare example of a major petroleum system that shows no significant surface expression in the form of seepage. The only seeps known in this basin are developed on the western margin (Figures 1 and 3), well updip of the major fields, which are the largest in the whole Far East region. The reasons for this low number of recorded seeps cannot be related to cultural or geomorphological factors; the large fields are not overlain by thick alluvial cover whereas the population density and geological survey coverage is equivalent to that in the adjoining seep-rich regions of the North and South Sumatra Basins. The main differences to adjoining basins are geological and lie in the absence of significant diapirism, recent uplift or surface-penetrating reverse faults. The major traps are drapes over basement highs, which are suggested to be features much less conducive to the development of visible seepage at the surface.

Prospect scale analysis: north and south Sumatra Further detailed work has been performed on the North and South Sumatra Basins to evaluate the significance of seepage in prospect analysis and to more closely evaluate the geological origins of seeps. These two basins appear to show the greater degree of coincidence between seeps and accumulations on the sub-basinal analysis. Oil generation in the two basins is believed to have peaked in the Late Miocene

Marine and Petroleum Geology, 1993, Vol 10, December

Seepage, tectonics and petroleum reserves: D. S. Macgregor ASSAM

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Marine and Petroleum

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1993, V o l 10, D e c e m b e r

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Seepage, tectonics and petroleum reserves: D. S. Macgregor ( P E R T A M I N A / B E I C I P 1982), although large areas are affected by Plio-Pieistocene compression, which has shut off oil generation and undoubtedly led to a redistribution of earlier reservoired hydrocarbons. Seeps in these two basins show distinct tectonic associations. Almost all the seeps in the South Sumatra Basin and roughly half those in North Sumatra lie over anticlines formed by a combination of mud swelling and reverse faulting (i.e. a composite of settings 1 and 2). The remainder of seeps, lying mainly in the North Sumatra Basin, can be tied to association 3, i.e. the uplifted margin association. The intensity of seepage in the two basins is strongest on the south-western flanks within a region of compression related to the Plio-Pleistocene Barisan Uplift (Figure 1). An analysis has been performed on the approximately 500 exploration wells, 169 discoveries and 166 known seeps in the two basins. The seep distribution relative to known oilfields is shown in Figure 4. About a third of seeps can be tied to subsurface accumulations, albeit mainly small and shallow ones, whereas the success rate for wells drilled near seeps is about 60%, roughly double the success rate for all exploration wells. However, there is no tendency for the seeps to overlie the more successful fairways or the larger fields, and most of the accumulations in all reserve groupings are not overlain by documented seeps. It would therefore seem that the presence of a seep over a prospect in this basin does imply a significantly lower than average exploration risk (although it does not remove the risk completely). On the other hand, an observed absence of seeps over prospects has little effect on the success rates. The reasons may again largely be related to tectonics. Closer investigation reveals that it is generally the shallower traps, and those most strongly affected by diapirism or faulting, that seep visibly. Deeper trap types that are not connected to the surface by faulting (e.g. reefs, uninverted or mildly inverted fault blocks), which comprise many of the larger fields, rarely give rise to visible surface seeps.

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610

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Summary of seep-accumulation relationships in south-east Asia It can be concluded that in south-east Asia an indirect relationship exists between seeps and petroleum reserves. Seep-rich basins generally correlate with basins rich in subsurface reserves, but the locations of seeps rarely overlie those of major fields. Very few large fields in the region are known to seep visibly, and even for the basins showing the best relationships, the proportions of seeps associated with accumulations seems to be only about 40%. Local tectonics seem to exert a stronger control on the locations of seeps, which tend to lie in three intergradational settings: over reverse faults or associated anticlines, over diapirs, and on carrier bed outcrops on uplifted basin margins.

Comparison with studies elsewhere As mentioned in the introduction, there are relatively few recent published regional studies of seepage. It is necessary in many cases to go back as far as 40 or 50 years to find useful references on this subject. This is largely a reflection of the low importance placed on seepage in oil exploration in recent times. It is only in the last few years, in frontier offshore areas such as the deep water Gulf of Mexico, that there has been a revival in the subject. Eight regions are discussed in the following, for which at least some details are available on the relationship between seeps, subsurface accumulations and tectonics. Additional analysis has occasionally been performed by the author to aid a statistical comparison with the south-east Asian basins.

Gulf of Mexico The Gulf of Mexico is a region with a comparable well/seeps database to south-east Asia, although much information in the offshore is still restricted. Most of the early onshore discoveries were linked to flowing gas seeps, e.g. Spindletop (Landes, 1970), though as exploration progressed, larger discoveries were made which were not seep-related (e.g. the East Texas Field). Trap types can be loosely divided in the region into salt-related traps, which show moderate to good seep-accumulation relationships, and stratigraphic traps, which have few associated seeps. As exploration has moved from onshore to shallow and then into deep water, so has the search for seeps, this being reflected in published work. Many subregional studies have been published and these are summarized in the following. Link (1952) mapped out seeps over the onshore salt basin, with particular detail in the southern Louisiana salt province. His compilation has been briefly evaluated by Dunlap and Hutchinson (1961), who found 20 of the 51 seeps in southern Louisiana (40%) to overlie known piercement salt domes. This seems to be an underestimate; based on a more recent map of salt domes by Landes (1970), the true figure seems to be closer to 60%. Dunlap and Hutchinson also estimate that only 17% of these seeps directly overlie producing fields, although it is apparent from Link's map that as many as half the seeps in southern Louisiana lie within a few kiiometres of gas or oil accumulations. An onshore feature that has been given particular attention is the presence of exposed oil impregnated caprocks at Damon Mound (e.g. Sassen et al., 1991). A

1993, Vol 10, December

Seepage, tectonics and petroleum reserves: D. S. Macgregor discovery was made in sands trapped against salt close to this impregnation, which is developed over the crest of the salt dome. The impregnation represents the exposure of one of a series of stacked traps and illustrates that impregnations can, at least in some instances, be of direct exploration significance. Tinkle (1973) systematically mapped gas seeps over the Texas-Louisiana shelf using a database of high resolution shallow seismic results. As deep seismic data were not used, it was only possible for Tinkle to identify seep associations where structural features show a distinct seabed expression. For this reason and because of a concentration of seeps in the Mississippi delta area, an area of high sedimentation rate in which seabed features may be obscured, most of his seeps show no discernible structural association. However, if only seeps outside the delta area are considered, some more distinct associations and trends can be identified. For this set of 75 seeps, 30% show no apparent association, 30% are associated with faults identifiable on the seabed, and 40% overlie salt domes which show seabed expression. It is likely that many of the seeps which show no apparent association overlie structural features which do not show seabed expression, but which would be identifiable on a deep seismic database. The T e x a s - L o u i s i a n a shelf is an area which has been intensely explored and it is believed that most major fields have been found. Of all the seeps in Tinkle's database, 17% directly overlie production, whereas a cumulative 51% of seeps are within two miles of production. These figures seem broadly correlatable with the moderately good seep-accumulation relationships observed in the onshore portions of the salt dome fairway, suggesting that seeps and oilfields are typically slightly offset in this region. Seep detection in the less explored deep water areas has been performed largely using seabed coring. Although there are many occurrences of visible oil in cores, most of these data remain confidential at the time of writing. The region which seems to be richest in seeps, and on which most data exist, is the Green Canyon, a region of mixed stratigraphic and structural (salt dome) traps. Detailed studies have been published for various concentrations of seeps in the northern Green Canyon (Behrens, 1988; Brooks et al., 1986) and for the Bush Hill mud mound (Neurater and Bryant, 1990). Most of these derive from active normal faults over salt diapirs, with the exception of the Bush Hill seep, which is associated with a mud volcano-like mound. This trend is supported by a compilation of observations of surface slicks by Williams et al. (in press), most of which lie close to or over salt diapirs and walls. The faults which source the seeps extend for the studied cases at least as deep as 700 m, close to the diapir crests at 800 m. Geochemical analysis of the seeps show the oil to have a source identical to that of deep accumulations (Kennicutt et al., 1988) and to have been generated within syrtclines developed between salt diapirs. The spatial relationship between slick locations and major oilfields is poor in the Green Canyon, even for the structural traps. Williams et al. conclude that seep/slick mapping is not a prospect-specific tool in this region. In summary, seepage in the Gulf of Mexico area seems to be closely tied to recent salt diapirism. Most seeps lie over the crests of salt diapirs or domes.

Moderately good seep-accumulation relationships are observed for some traps and fairways related to salt diapirism, although there are usually offsets of a few kilometres between the main subsurface accumulations on diapir flanks and the seeps over the crests. Significant populations of seeps seem to overlie petroleum-bearing and dry salt domes. The larger stratigraphic traps in the onshore and offshore are rarely associated with seeps. The relationships observed are therefore broadly the same as m south-east Asia, with seepage being controlled more by tectonics than by the occurrence of large oilfields and with only the more tectonically complex trap types giving rise to visible seepage.

Offshore California Although many workers refer to large numbers of seeps in onshore and offshore California (e.g. Link, 1952), there is a surprising lack of documentation on these. Seeps were known to be instrumental in many of the early discoveries in onshore California (Hoots and Bear, 1954). The traps involved (e.g. Midway-Sunset) are complex shallow pinchout traps that can be tied most readily to the uplifted margin association. The only well documented seeps are the offshore slicks of the Santa Barbara Channel, particularly the natural slicks off Coal Oil Point. In the most geologically oriented of several papers on these, Fischer and Stevenson (1973) show that all these seeps lie either on anticline crests or on the surface intersects of transpressional fault planes. These seeps appear to derive by vertical leakage from underlying small accumulations in faulted anticlines. Pressure communication between the seeps and accumulations has been proved by the decrease in seep flow-rate with oil production. Structuring in this region appears to be recent, with the seeps most common over Pleistocene thins, and the seeps may indicate a breaching of the underlying accumulations by active faulting.

Zagros Within the Asmari play fairway of the Iranian Zagros, there appears to be a good relationship between the locations of flowing gas and oil seeps and the surface intersections of thrust faults bounding giant oilfields (Lees and Richardson, 1940). Flowing gas seeps, often associated with sulphur mineralization (gash-i-turush) are also common on anticlinal crests. The relationship is poorer in the Iraqi Zagros, where the only field with major associated seepage is the giant Kirkuk field and where many seeps overlie dry structures. A high proportion of the world's seep-associated giant fields occur in this province (see the Global analysis section of this paper). The Zagros is relatively lightly drilled compared with the south-east Asian basins analysed in this paper. Despite this, at least 40% of the Iranian seeps in the SEEPS database can be linked with underlying accumulations; the true figure may be 50% or more. The equivalent figure in the Iraqi Zagros may, however, be lower. For the Zagros as a whole, at least 40% of the major fields appear to seep visibly at the surface. According to Dunnington (1958), seepage in the thrust belt results from a combination of direct leakage from accumulations and from a release of remigrated petroleum (i.e. tertiary migration) from tilted traps

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Seepage, tectonics and petroleum reserves: D. S. Macgregor deep in the basin. The reasons for the improved relationship between seeps and large subsurface accumulations in the Zagros, as opposed to most south-east Asian basins, can be related to the compressional nature of the successful play fairways, particularly the thrust faulting that provides a leakage pathway to the surface directly over petroleum-bearing traps.

South Caspian The South Caspian is probably the world's most dramatically seeping basin. It is probably no coincidence that it is also one of the world's most actively subsiding basins (Table 1) and one of the stratigraphically youngest known petroleum systems. Most seeps are related to active mud volcanism and to the underlying accumulations in related diapiric folds. The hydrocarbon systems here are dynamic: seepage is thought to be occurring simultaneously with focused secondary petroleum migration. Seeps, mud diapirs and subsurface accumulation are interpreted by Goubkhin (1934) to be intimately related in a cyclical process not dissimilar to that of an igneous volcano; the diapir provides a focus for oil migration, accumulations are formed against the diapir, and seepage occurs up the flank of the diapir in bursts controlled by the build-up and release of pressure.

North Caucasus The first discoveries in the North Caucasus foreland basin in southern Russia were seepage-linked (Beeby-Thompson, 1922). Although seeps are known along the entire Caucasus thrust front, the most reliable data comes from a paper by Pererva (1984) on the west Kuban region. Seeps here concentrate on the southern flank of the foreland basin against the thrust front and are often associated with mud diapirism and inorganic geochemical anomalies. Five of the 25 seeps mapped in this region overlie small shallow fields formed on thrust anticlines; most of the seeps occur updip of these small accumulations. The largest oil accumulations in the basin are located in the basin centre to the north, associated with mud diapirism that does not penetrate to the surface, and have no recorded associated seeps. The association of seeps in this region shows similarities to those on the uplifted basin margin of South Sumatra (Muara Enim, Figure 3) and also to offshore seeps in the adjacent Black Sea Basin (Macgregor et al., in press).

Britain and the North Sea Selley (1992) documented 173 surface petroleum occurrences in onshore Britain, most of which are impregnations, or, at best, very slowly flowing seeps. Three main settings were identified: the outcrops of permeable formations overlying basements on basin margins; fault planes; and an unusual tin-granite association. In many instances, exposed oilimpregnated sands may represent breached oilfields, e.g. on the Derbyshire Dome. No example is quoted of a seep overlying a commercial oilfield, although many of the features described lie close to and probably have a related origin to nearby oilfields in the three main onshore petroleum provinces, i.e. Dorset, the Weald and Nottinghamshire. The seep and impregnation

612

distribution mapped by Selley could be said to be a moderately good indicator on a regional scale as to where the main onshore Britain oil reserves lie, though again this relationship breaks down at the sub-basin scale. Hovland and Somerville (1985) have reported two natural gas seepages in the North Sea.

East Africa There are many surface hydrocarbon indications in this region of low exploration success. It is notable that most of these appear to be impregnations rather than flowing seeps, resulting from recent uplift and destruction of Mesozoic oil accumulations. The best known example is the Bemolanga Tar Sands of Madagascar (Macgregor and Clarke, 1992).

Gulf of Suez The Gulf of Suez (Ghorab, 1960) is a mature exploration province and the good database available on this region provides a useful case study of seepage in an active rift basin. Relatively few seeps are, however, known, this perhaps being a consequence of the arid climate and low water-table. Three large onshore flowing seeps are known (the Zeit, Gemsa and Abu Durba seeps), all of which are related to surfacepenetrating graben-bounding faults. The Abu Durba seep is also associated with features similar to mud volcanoes (Beeby-Thompson, 1922). Two of these three documented onshore seeps overlie shallow accumulations, which were the first two fields found in the region. However, the reserves involved are insignificant compared with the non-seep-related discoveries made much later in the basin's exploration history. Three offshore slicks are also known, which also appear to be fault-related, but are distant from known oilfields.

Summary The spatial relationship between flowing seeps and large subsurface accumulations is shown in these published examples to be highly variable. In most instances, encompassing examples such as the southeast Asian basins, much of the Gulf of Mexico, the Caucasus and the Gulf of Suez, it is poor or moderate. In these cases only a minority of the documented seeps can be related to significant accumulations, whereas the largest known fields do not appear to seep. However, some examples have been given where the relationship between seeps and major fields is significantly improved. These include the Zagros thrust belt, the South Caspian mud diapir province, parts of the salt fairway in the Gulf of Mexico and some trap types in onshore California. In all these instances the processes controlling the formation of traps are interlinked with those controlling seepage, and clear leakage routes can be identified between the accumulations and the surface. These traps are usually also shallow. The relationship between flowing seeps and accumulations is thus seen to be dependent on the tectonics and geometry of the play. The best correlations between seeps and reserves are observed in active thrust belts and diapiric basins, with the poorest correlations observed for traps buried beneath unfaulted overburdens. Impregnations seem, for the examples quoted, to show a poorer relationship with subsurface accumulations than do flowing seeps.

Marine and Petroleum Geology, 1993, Vol 10, December

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Not in top 100 petroleum provinces C. Burma Myanmar NZ East Coast New Zealand Anambra Nigeria Sah/Tun Atlas Algeria/Tunisia Beni Bolivia Karoo South Africa Taranaki New Zealand Arakan-Tripura Myanmar./Bangladesh Northern Cuba Cuba

In top 100 petroleum provinces Kura-S. Caspian Azerbaijan Baram Malay/Brunei Papua Papua New Guinea South Trinidad Trinidad Venture Ste Barbara USA Gom Caenozoic USA North Sumatra Indonesia South Sumatra Indonesia Maracaibo Venezuela Tampico-Misalante Mexico Assam India West Java Indonesia Santa Cruz Bolivia Napo-Putumayo Peru/Colombia Magallanes Argentina/Chile Zagros Iran/Iraq Llanos Colombia North Caucasus Russia

Basin

Thrust beltJForearc Accretionary wedge Rift Thrust belt Foreland/Thrust belt Foreland Backarc Accretionary wedge Thrust belt

Foreland-diapiric Passive margin Thrust belt Thrust belt/Foreland Transfer margin Passive margin-diapiric Backarc Backarc Foreland Passive margin Thrust belt/Foreland Backarc Foreland/Thrust belt Foreland Foreland Thrust belt Foreland Foreland/Thrust belt

Basin type

196 101 83 61 54 59 50 44 41

>200 282 168 104 >100 >100 85 81 80 78 75 71 63 52 44 42 41 >40

No. of known seeps

Table 1 M a j o r seeping basins (basins w i t h m o r e than 40 d o c u m e n t e d seeps)

300 200 Erosional Erosional 200 Erosional 50 Erosional Erosional

1000 200 Erosional 200 1000 1000 100 125 200 Erosional 200 60 200 (foreland) 100 50 Erosional 100 130

Max. Neogene sedimentation rate (m/Ma)

1 0 0 0.1 0 0 1.3 0.3 0

10 3 2 3 5 64 6 2 50 22 2 3 3 4 4 250 3 4

Approx. known reserves (BBOE)

Reverse fault, mud volcano, uplifted margin Reverse fault, mud volcano ??Impregnations (not true seeps) Reverse fault Reverse fault? ??Impregnations (not true seeps) Unknown Mud volcano Reverse fault?, crushed source rocks

Diapiric, mud volcano Diapiric, mud volcano, uplifted margin Reverse fault, anticlinal crest, mud volcano Diapiric/reverse fault, anticline, mud volcano Transform fault, anticlinal crest, uplifted margin Diapiric (salt), normal fault Reverse fault, uplifted margin, diapir Reverse fault, uplifted margin, diapir Uplifted margin, mud volcano Igneous intrusion Reverse fault, anticlinal crest Uplifted margin Reverse fault? Reverse fault, mud volcano Reverse fault? Reverse fault, anticlinal crest Reverse fault, mud volcano Reverse fault, uplifted margin, mud volcano

Main seep associations

Pascoe (1912) Wilson et aL (1973)

Pascoe (1912) Kvenvolden and Pettinga (1989)

Dunnington (1958) Beeby-Thompson (1922) Pererva (1984)

Link (1952)

Goubkhin (1934) Liechti (1960) Martin and Cawley (1991) Pascoe (1912) Fischer and Stevenson (1973) Various (see this paper) Various (see this paper) Various (see this paper) Link (1952) Muir (1936) Latouche (1918) Various (see this paper)

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Figure 5 Venn diagram illustrating relationships b e t w e e n seep-rich and petroleum-rich basins world-wide. T h e r e is 52% coincidence between two lists of the 100 basins with the largest reserves and numbers of documented seeps

Global analysis: basin scale One of the hypotheses generated by the south-east Asian study is that correlations exist between the number of seeps and subsurface reserves on a basinal scale, the relationship between these two variables being dependent on basin type. This hypothesis is here tested on a global scale with the use of internal BP databases on seeps (SEEPS) and reserves. Lists have been compiled of the 100 basins containing the largest numbers of documented seeps and highest proved petroleum reserves. These correspond respectively to basins with 10 or more documented seeps, and to basins containing in excess of 1.8 B B O E proved reserves. G o o d and poor data areas are differentiated; the latter are taken to include most offshore areas and onshore areas in the CIS and China. As shown by Figure 5, the degree of correlation between the two lists of basins is moderately good. There are over 700 known sedimentary basins world-wide and if seeps and reserves were not related in any way, the expectation of coincidence would be only 15% (15 basins). However, 52 basins appear on both lists, representing a degree of coincidence over three times that which would be statistically expected. A basin rich in seeps is, on these statistics, more likely than not to contain significant petroleum reserves - - in other words, the average success rate is slightly better than one in two. A basin with a few documented seeps has a much lower chance of containing large reserves; on the figures quoted in Figure 1, the average success rate for a seep-poor basin would be 48/600 = 1 in 12.5. Variations within the group of 100 seeping basins were studied by differentiating a subset of 27 basins with over 40 known seeps (Table 1). Eighteen of these (i.e. 67%) are in the top 100 petroleum provinces. This suggests that the chance of a major petroleum province increases with increasing numbers of seeps per basin. Clearly evident on this listing are associations with reverse faults, associated thrust anticlines, and with diapirism, both of mud and salt. Almost all the highly seeping basins listed are currently undergoing active uplift or rapid subsidence, in the latter cases being characterized by high present day sedimentation rates, often as high as 1000 m/Ma. Timing of tectonic activity is thus identified as a key control on the intensity of seepage. The influence of basin type and tectonics on the 614

relationships described here has been more closely investigated by classifying all 148 basins considered into six simplistic basin types, based on their Late C r e t a c e o u s - R e c e n t plate tectonic setting. Figure 6 shows the distribution of basin types for the two data sets of reserves-rich and seep-rich basins. It can be seen that the degree of correlation between the two data sets varies considerably with anomalies heavily concentrated in a few basin types. Each of these will now be reviewed with specific examples. The term I N T R A C R A T O N I C basins is used to describe basins which lay in continental interiors in the Late Cretaceous-Tertiary period, i.e. were not involved in plate collisions or separations. These form most of the examples of major petroleum provinces that appear to show little or no surface expression in the form of seepage. Examples include the Permian, Illinois (Landes, 1970), and East Siberian Basins. In some instances, the lack of seepage may be due to climatic factors - - many arid basins are included. However, the contention that seepage rates from this type of basin are anomalously low is supported by the fact that almost all the rare examples of preservation of Palaeozoic petroleum occur in this basin type. This petroleum could only have been preserved if leakage to the surface was very slow and would therefore be incapable of supporting large numbers of visible seeps. The evaporite seals that occur in many intracratonic basins may be a major factor in constraining the rates of seepage. F O R E L A N D basins, which are probably the most productive basin type, show anomalously low seepage in relation to their large reserves. This becomes most apparent when forelands are compared with adjoining

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Marine and Petroleum Geology, 1993, Vol 10, December

Seepage, thrust belts, which are usually rich in seeps (see later). The Arabian foreland, for instance, contains few seeps compared with the Zagros thrust belt. Surface indications of petroleum in such basins are thus concentrated on the thrusted margin and on the opposite flank, where feather-edge tar sands may occur (e.g. Alberta; Wilson et al., 1973). Within this group there are marked differences according to the timing of deformation. The more recent and more deformed Andean foreland basins show larger numbers of seeps than do Alpine (Late Cretaceous-Palaeogene) examples. RIFT basins show similar variations according to timing, with Recent rifts such as Lake Albert and Lake Baikal showing larger numbers of seeps than older, now buried features. PASSIVE MARGINS can be subdivided into those affected by mud or salt diapirism, which show large numbers of seeps (e.g. Gulf of Mexico) and into undeformed examples, which show few recorded seeps (e.g. onshore Niger Delta). This is, however, a difficult class to adequately assess as many examples lie in poor data areas offshore. Nevertheless, available offshore seeps databases (e.g. Johnson, 1971; unpublished BP experience with airborne laser fluorosensor studies) do tend to support the view that offshore passive margins not affected by diapirism are generally poor in seeps. ACTIVE MARGINS (transform and arc-related basins) show anomalously large numbers of seeps relative to their reserves. South-east Asian and Californian examples are discussed in this paper. THRUST BELTS, which are taken to include strongly deformed forearcs and accretionary wedges such as the Burmese basins, are highly prone to seepage. This set of basins includes many seep-rich basins that are not major petroleum provinces. The reasons can be assumed to be geological as examples of seeping thrust belts occur in a wide variety of geographical and climatic settings, even in the most arid of regions (Zagros, Iran; Rif, Morocco). In terms of its wider geochemical significance, seepage is most easily understood in terms of the dynamic interpretation of the global petroleum system recently published by Miller (1992). Petroleum systems are interpreted to be continually or spasmodically leaking to the surface, with the volume of retained reservoired petroleum decaying exponentially with time. Miller estimates an average 'half-life' for reservoired oil of 29 Ma. This paper suggests differing relationships between seepage rates and reservoired petroleum for different tectonic settings. In terms of Miller's concepts, this must mean that the half-life of petroleum varies considerably according to the nature of the basin. Intracratonic basins are suggested on the basis of the above discussions to be releasing petroleum relatively slowly and probably therefore have very long half-lives. On the other hand, thrust belts and active margin basins are indicated to be expelling oil to the surface rapidly and must have shorter half-lives.

Global analysis: field scale A list of the 200 largest oilfields in terms of recoverable reserves in the world has been compiled and investigated for their relationship with seepage. Various papers on the exploration histories of these regions have been researched for mention of seepage

tectonics and petroleum reserves: D. S. Macgregor associated with these fields (e.g. Landes, 1970). Documentation of visible seepage was found for 30 of these fields, representing 15% of the total number of fields and 20% of the total reserves within these. Twenty-three of these 30 seep-related giants lie within the three provinces described in this paper as showing particularly good seep-accumulaion relationships, i.e. Zagros, California and South Caspian. This suggests that the good seep-accumulation relationships identified in these basins are very much the exception rather than the rule. Other examples of seeping giants lie in Kuwait (Burgan), Venezuela (Bolivar), Peru, Bahrein, Mexico (Golden Lane) and Colorado. Most of these 30 fields are shallow, with reservoir crests above 1000 m. Although the true proportion of these major fields that seep may be slightly higher than the figures quoted, it is clear that the correlation between seeps and major fields is significantly poorer than that between seeps and major petroleum provinces. The proportion of the world's present petroleum reserves in fields associated with seepage is now much lower than the 50% estimated by Link in 1952; this is due to the fact that most major fields were discovered after Link's paper. Most of these more recent discoveries were not linked to seepage. It would indeed seem that the proportion of the world's major oilfields associated with visible seepage has been decreasing through time. Beeby-Thompson reported in 1922 that all major fields discovered at that time were seep-associated; the proportion decreased to the 50% reported by Link (1952) and now seems to be around 20%. This reflects not only the gradual drilling out of seeping onshore structures and the decreased use of seepage as an exploration tool, but also the expansion of the oil industry into less tectonized basins less prone to vertical seepage. It is notable that despite the large numbers of offshore seeps now known (Wilson et al., 1973), there are very few instances of visible seepage linked with large offshore fields. In summary, this broad global study again supports most of the hypotheses resulting from the more detailed south-east Asian study. Good relationships between seeps and reserves are indicated at a basinal scale, but not generally at the field scale. An indirect relationship between seeps and accumulations seems to be implied. The remainder of this paper is given over to speculating on the nature of this relationship.

Origin and associations of visible seeps Seeps concentrate on the surface intersects of permeable fractures or other seal breaches. Such perme~ible pathways must be fed by a deep carrier bed or reservoir. As estimated seepage rates run orders of magnitude above theoretical source rock expulsion rates (Clarke and Cleverly, 1991), any viable model for feeding a visible seep must involve the focusing of petroleum generated over a wide kitchen area. Clarke and Cleverly concluded from this that most seeps must derive from underlying accumulations. From the data presented in this paper, it seems that in most basins their model can only be applied to a minority of seeps. Alternative models must therefore be sought for most of the world's seeps. By grouping seeps into a number of broad tectonic associations it is possible to derive models which are

Marine and Petroleum Geology, 1993, Vol 10, December

615

Seepage, tectonics and petroleum reserves: D. S. Macgregor Table 2 Generalized tectonic settings and p r o p o s e d origins of seeps Feature

Tectonic association

Sub-associations

Examples

Flowing seeps

Diapiric association (mud or salt diapirs)

Mud volcanoes and associated features Collapse faults over diapirs

Burma, South Caspian

Compressive association

Reverse fault planes

N/B Sumatra, Zagros

(includes transpression)

Shattered anticlinal crests Normal fault planes

Assam, Zagros, Ste. Barbara Central Sumatra Gulf of Suez

Exposed accumulations (includes many tar sands)

Madagascar, Damon Mound (Texas)

Exposed migration pathways or source rocks

Many British "seeps' e.g. Dorset

Igneous contacts

Cornwall, UK

Gulf of Mexico

Extensional association (includes transtension) Outcropping carrier beds, Belait syncline (Brunei), Uplifted margin especially along ?California onshore association unconformities Impregnations

Uplift and erosion of 'fossil' petroleum systems

Igneous association

Proposed origin

Relationships with subsurface accumulations

Strongly focused Variable, dependent on reservoir secondary migration geometry with respect to diapir (partly overpressurePoor to moderate, may driven) be linked to downdip and laterally offset traps 1. Breaching of and Moderate to good, though little relationship with field size leakage from traps 2. Tertiary migration Often good, most commercially (redistribution of significant seeps petroleum) Generally poor Ends of migration pathways on sides of basin 1. Strongly focused Good only for very shallow basin margin traps; otherwise fields secondary migration substantially offset from seeps 2. Tertiary migration Past (now inactive) migration

Good only where stacked reservoirs may have existed and some have survived Past (now inactive) May suggest the occurrence of a petroleum system in less migration uplifted regions Usually poor Contact metamorphism

The most significant seep types in terms of abundance and flow rates are italicized

applicable to most seeps in these associations (Table 2). Although it is believed that this represents the most realistic manner of grouping seeps in terms of understanding their origins, it should be emphasized that not all seeps fall readily into these groupings and the settings themselves grade into one another. This is not, as yet, an attempt at a formal classification of seeps. The two most significant seep associations in terms of numbers of flowing seeps and detectable flow seem to be those associated with active diapirism or reverse faulting. These associations are termed, for the purposes of this paper, as the diapiric and compressive associations, respectively. The diapiric association covers two distinct settings: active collapse fault planes over diapirs and intrusive features such as mud volcanoes. Both require active diapirism, either of salt or overpressured muds, and therefore occur only in basins undergoing very rapid subsidence and sedimentation. In most instances source rocks will be at their maximum maturity at the present day and thus secondary migration should be active. Rising diapirs provide an obvious structural focus for such migration, whether it be driven by buoyancy or overpressuring, and thus focused secondary migration is a viable model for the seeps of this association. The importance of this association explains why there is an apparent relationship at a global scale between seep-rich basins and high present day sedimentation rates. The relationship between surface seepage and subsurface accumulations seems to be dependent on play geometry, particularly the position of the reservoir with respect to the diapir. Where diapirism on an underlying horizon forms a closure on a younger reservoir, as in the South Caspian or in Burma, this relationship may be good. However, where successful traps and reservoirs are located downflank of the diapirs, as in Green Canyon, poorer relationships are observed. Very different models must be considered for the origins of seeps in the compressive association. The active thrust belts and inverted backarcs considered

616

here are regions currently undergoing uplift and erosion, with petroleum generation unlikely to be active at the present day (exceptions to this may be the regions immediately adjoining a still-subsiding foreland basin). Petroleum within traps filled during earlier generation phases in such settings is, however, likely to be undergoing various forms of re(tertiary)migration, including lateral remigration as traps are reshaped, and vertical leakage as faults are reactivated. Seeps are likely to derive by a combination of two mechanisms: lateral spillage using carrier beds and vertical leakage using faults. In south Sumatra therefore, the 40% or so of seeps which overlie small oil accumulations may result from the breaching and slow destruction of these accumulations, whereas other seeps may represent loss of petroleum to the surface by various combinations of lateral remigration along carrier beds and leakage to the surface on faults. The models proposed by Dunnington (1958) for the Zagros are also consistent with these ideas. Visible seeps seem to be common in extensional settings only where active normal faults extend to the surface. Various models can be proposed for the uplifted margin association, all implying long distance lateral migration from kitchens located in basin centres. These kitchens may or may not be active at the present day. Seeps may well derive from downdip accumulations, particularly where tertiary migration models need to be invoked, but lateral offsets between seeps and accumulations are likely to be high. Exceptions may occur in the case of shallow pinchout traps on the basin margin, as in parts of California. Impregnations, as a group, show a poorer relationship with subsurface accumulations than do flowing seeps, though care must be taken in every instance to ensure that the feature concerned is truly a fossil feature and is not at least periodically flowing. A dominance of impregnations over flowing seeps would seem to indicate that the petroleum system has been largely destroyed through erosion in the region, although obvious potential may then exist in nearby less eroded regions. It is also possible for stacked

Marine and Petroleum Geology, 1993, Vol 10, December

Seepage, tectonics and petro/eum reserves: D. S. Macgregor DIAPIRIC ASSOCIATION

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Figure 7 Diagrammatic illustration of the main seep associatons identified in this paper and of the subsurface origins proposed. Three main processes are believed to source flowing seeps: vertical leakage from accumulations (common only in compressive and diapiric settings); remigration (common on uplifted margins); and focused secondary migration (common in diapiric and extensional settings). Impregnations result from the uplift and exposure of petroleum systems and are usually of less commercial significance

reservoirs that one of these may be exposed as an impregnation, as is the case for the Damon Mound feature in Texas. Hence although onshore impregnations are of less value to the explorer than are flowing seeps, they should not be ignored in the development of regional geochemical models. In summary, it is proposed that flowing seeps originate in the subsurface from three main processes: (l) structurally focused secondary migration; (2) lateral spillage from accumulations during basin tilting; and (3) direct vertical leakage from accumulations breached by active faulting and diapirism. The applicability of

these models varies with basin tectonics and play geometry. Seeps derived by vertical leakage are clearly those of the greatest commercial significance, but these appear to form a highly variable proportion of the total seep population in different basin types. Only in some compressive and diapiric basins do these seeps seem to form a significant proportion of the seep population and, even then, there seems to be no definable relationship between the intensity of seepage and field size. The processes involved in models (1) and (2) imply indirect or long tortuous links between seeps and laterally offset accumulations. These models, if applied

Marine and Petroleum Geology, 1993, Vol 10, December

617

Seepage, tectonics and petroleum reserves: D. S. M a c g r e g o r

as suggested to the majority of seeps, would explain why good relationships can be observed between seeps and reserves at global and regional scales, but not at field/prospect scales. The value of seepage in future frontier exploration can similarly be expected to vary with basin types. As few thrust belts are unexplored, the value of seeps in directly locating giant fields may be confined to diapiric basins. In other basin types the value of seepage will be greatest in regional analysis, e.g. anomalously high numbers of seeps on basin margins indicating prospectivity in downdip regions. It is vital for the explorer to distinguish, as best he or she can from the information to hand in the area of interest, which seep association and likely models of origin he or she is dealing with. The value of flowing seeps to the explorer can be considerably enhanced by evaluating their tectonic and geochemical origins with the aid of subsurface geological and geophysical data and by geochemical sampling. In this manner, greater value can be extracted from the study of seeps than is implied by the Perrodon quote at the beginning of this paper.

Further work The study of petroleum seepage is, in the view of the author, one of the most inadequately researched aspects of petroleum geology. I hope that, if nothing else, this contribution will provoke others to contribute to the subject. Regional studies of seepage patterns, such as the south-east Asia study in this paper, should be made over many more regions than it has been possible for the author to include in this broad study, and will help prove or disprove the hypotheses proposed in this paper. Regions suggested are the Gulf of Mexico, Venezuela, California, the subAndean basins, Romania and the Caucasus-Black Sea region. The author has, due to the lack of publishable data available, not included the study of microseepage in this paper. The physical processes involved may well be different to those outlined here for visible seepage and a separate study is required. Lastly, it is suggested that a detailed study of seeps in a geochemically well controlled basin, including measurement of flow-rates through time, may provide invaluable clues to the physical processes involved in oil generation and migration and the rates at which these processes take place.

Conclusions The relationship between seepage and commercial reserves is more complex than has previously been assumed. This is due to the strong influence of tectonics and the variety of different processes which may give rise to a surface seep, only some of which imply an underlying accumulation. Seepage is a valid guide to the prospectivity of a basin only when adequately evaluated in terms of its present day tectonic style and activity. As guidelines to such evaluations, the following generalizations can be made, based on the broad studies made in this paper. More work is required to confirm many of these. 1.

618

Seepage patterns are strongly controlled by regional and local tectonics. Visible seeps are most common in overpressured diapir-rich basins and in

active thrust belts. Visible flowing seepage is most commonly related to active compressional faulting and diapirism. Seeps are also common on the outcrops of carrier beds on uplifted basin margins. 2. Seeps are rare in tectonically inactive basins or in regions where structures are now inactive and are draped by undisturbed overburdens. 3. Relatively few large accumulations seem to seep directly to the surface. In most areas, seeps derived by vertical leakage from the underlying accumulations form a minority of the total population of seeps. Exceptions occur in shallow play fairways controlled by recent reverse faulting and diapirism. 4. The number of seeps in a basin, when evaluated in terms of the active tectonics of that basin, provide a useful indicator of the regional quantitative hydrocarbon potential. This relationship is less reliable at sub-basinal or smaller scales. Different basin types show differing relationships between apparent seepage rates and the volume of reservoired petroleum. Intracratonic and foreland basins show relatively low numbers of seeps relative to reserves; thrust belts show anomalously large numbers of seeps. Petroleum half-life is thought to vary with basin type, with petroleum surviving for the longest periods in quiescent intracratonic basins. 5. A number of broad guidelines can be drawn on the significance of seepage in play and prospect evaluations. The presence of seeps over basins or prospects reduces exploration risk, often considerably. The absence of observed seepage over tectonically inactive basins or deep traps should not affect the risks applied. However, a similar observation over a tectonically active basin or a shallow faulted prospect would give some concern.

Acknowledgements The author is indebted to the many colleagues within BP who have contributed to the compilation of the databases on which this study is based, particularly Robin Cleverly, Jackie Bannon and Peter Sharland. Dave Moore's work was instrumental in the assessment of the Sumatra basins. Roger Sassen was of great assistance in compiling the Gulf of Mexico section and I am also grateful to William Bryant for supplying a copy of Tinkle's thesis on this area. Helpful and constructive criticism of this paper was provided by Richard Clarke, Alan Williams, Robin Cleverly, Jane Thrasher, Richard Miller and Dave Roberts. I am indebted to the management of BP Exploration for permission to publish this paper.

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