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Turbidite Systems in Hydrocarbon Exploration
I) Turbidite Deposits and HC Exploration
In the past 25 years, reservoirs related to gravity flows in deep marine environments have aroused increasing interest in oil and gas exploration. Economical hydrocarbon accumulations associated with such reservoirs, generically called turbidites, have been found in tens of sedimentary basins around the world (fig. 1).
Fig. 1- Since 1980, the contribution of turbidite depositional systems to worldwide petroleum reserves has been very significant. The period of rapid increase started in the North Sea. Later, with the advent of deep water drilling technology, several major oil and gas fields were discovered in South Atlantic margins, with the main reservoir-rocks in deep-water turbidites, in both basin floor fans or slope fans (Vail's terminology).
During the first quarter of the 20th century, hydrocarbon discoveries in turbidite sandstone reservoirs were restricted to California basins. With the advent of offshore exploration, large oil and gas fields were found in the North Sea, between 1970 and 1990. Major discoveries in the deep-water of the Gulf of Mexico have occurred from 1979 to the present day. Since 1990, offshore and particularly deep offshore exploration in West Africa (Congo, Angola, Gabon, and Nigeria) and Brazil (Campos) has discovered large hydrocarbon reserves found in turbidite sandstone reservoirs (fig. 2).
Fig. 2- Each stack of barrels represents deepwater hydrocarbon discoveries in water depths greater than 500 m and exceeding 500 MMBOE recoverable. They (34 discoveries) have roughly 33 BBOE of reserves. Those made in South America and the Gulf of Mexico are oil discoveries. In West Africa, they are either oil or gas. In Europe, Asia and Australia they are predominantly gas discoveries. To these discoveries, it is important to add those made recently, particularly in offshore Angola, which have significant reserves. The amount of reserves shown here must be used carefully, as reserve amounts are often influenced by politics. For all barrel of oil equivalents (BOE), the conversion factor employed is 6000 cu. ft. gas = 1 barrel oil or condensate.
In other words, so far, the most active deep-water exploration frontiers and associated resources (not all of discovered hydrocarbons have been proven to be economic, and therefore can not be classified as reserves) are located along post-Pangea, Atlantic-type, continental divergent margins and very often down-dip from productive Tertiary delta systems, such as the Niger, Congo, and Mississippi. The generating petroleum sub-system (potential source rocks) are typically located either in rift-type basins, or in the transgressive (backstepping) or regressive (forestepping) phase of the post-Pangea continental encroachment stratigraphic cycle. In West Africa for instance, as illustrated in fig. 3, there are several potential generating petroleum-subsystems:
A) The organic-rich lacustrine shales (and limestones) deposited in rift-type basins. They are oil-prone source rocks with type I organic matter.
B) The transgressive marine sediments associated with the maximum post-Pangea flooding surface (Cenomanian-Turonian in age). Their organic matter is type II. They can generate oil or gas and their burial is determinant.
C) Low TOC (Total Organic Carbon) Tertiary deep-water sediments. Their organic matter is type III and dispersive. These source rocks are fundamentally gas-prone, nevertheless, in favourable conditions condensate and small amounts of oil are associated.
Fig. 3- On this geological interpretation of a regional seismic line from northern offshore Angola, the vertical superposition of different sedimentary basins is evident. Using the Bally's basin classification (Bally, 1980, 1985), from bottom to top, it is easy to recognize: (i) an old Fold-belt, often considered as the basement, (ii) several Upper Jurassic-Lower Cretaceous rift-type basins and (iii) a Meso-Cenozoic Atlantic-type continental divergent margin. On the other hand, this section can be characterized by the deposition of subaerial lava flows (SDRs) above the basement and distal rift-type basins, deposited immediately after the break-up of the lithosphere; and by the presence, in the lower part of the margin, of a thick salt interval. As in all divergent margins, the Western Africa margin is composed of a backstepping or transgressive phase at the bottom and, at the top, by a forestepping or regressive phase. The limit between these two sedimentary phases is marked by a major downlap surface (i.e., MFS 91.5 Ma, in Vail's terminology (1977)). Three potential source-rock intervals have been distinguished as having generated the hydrocarbons found in the area: (A) in the large rift-type basins, similar to the one visible on the right part of the line, lacustrine potential source-rocks rich in type I organic matter, (B) in the lower part of the margin, at the top of the transgressive phase and in association with the major downlap surface (MFS 91.5 Ma), potential marine source-rocks rich in type II organic matter and (C) in the regressive phase, within the deep-water sediments of the Cenozoic depocenters, potential source-rocks intervals characterized by type III dispersible organic matter.
In the Gulf of Mexico (Fig. 4), the predominant generating petroleum system is associated with the major downlap surface of the post-Pangea continental encroachment stratigraphic cycle, i.e., with Cenomanian - Turonian sediments (La Luna equivalents):
- Their organic matter is marine and type II. The maturation of the organic matter determines the generation of oil or gas.
- Due to the presence of autochthonous and chiefly allochthonous salt, the knowledge of the burial and thermal flux make the prediction of the maturation zones of the potential source rocks challenging.
- The geometry of the salt related to the geometry of the source rocks is also quite important. For instance, the salt being an excellent heat conductor can retard, or prevent, the maturation of the organic matter when it overlies the source rocks, or increase the maturation when it underlies them.
Fig. 4- On this geological interpretation of a regional seismic line located between the Alabama offshore and the eastern part of the Gulf of Mexico, the boundary between the two major sedimentary phases of the post Pangea continental encroachment stratigraphic cycle (Duval et al., 1993), that is to say, the downlap MFS. 91.5 Ma is easily recognized by the geometrical relationships between the reflectors. On the lower part of the line, a tectonic disharmony, at the bottom of the Jurassic salt, separates the substratum, composed by subaerial lava flows (SDRs), from the Mesozoic Mediterranean -type basin (Bally, 1980). In this Mesozoic basin, which roughly corresponds to a Pannonian basin with oceanization, a carbonate interval (Smackover formation) deposited above the salt layer is considered as a potential source-rock interval (in the Alabama offshore). However, by far, the most important potential marine source-rock interval corresponds to the organic rich sediments deposited in association with the major Meso-Cenozoic downlap surface, i.e., MFS 91.5 Ma. Obviously, in the eastern part of the line (landward of the old Cenomanian-Turonian shelf break), the organic matter of the marine potential source rocks is immature. However, seaward, as the burial increases, it becomes mature. Below the MFS 91.5 Ma (underlined in red on this interpretation), the geometry of the reflectors strongly suggests a passage from platform sediments (on the right) into slope sediments (on the left). The limit between these sedimentary environments, i.e., the shelf break is often enhanced by reefal developments.
In NW Australia, the more likely potential generating petroleum subsystem, as illustrated in fig. 3, is mainly gas-prone:
- It is related either with the Kimmeridgian downlap surface or with the forestepping Tertiary sediments.
- The organic matter of Kimmeridgian shales is marine and type II. It can generate gas or oil depending on burial. The organic matter of progradational Tertiary sediments is type III disperse (gas-prone).
- Organic matter type III disperse can generate economical gas accumulations only when the thickness of the source rock is and migration paths are predominantly vertical and convergent into a large trap.
So far, in deep-water exploration, the global exploration average success rate is around 30% (fig. 5). That is a very high success rate. The highest success rate is 45% for West Africa. Undeniably, the principal success factor has been seismic DHI’s (Direct Hydrocarbon Indicators). Their identification allows explorationists to predict reservoirs and hydrocarbons almost without any knowledge of the geological and petroleum settings of a basin. Such practice has strongly favoured a reductionist (Cartesian), or fragmented, approach to deep-water exploration. Unfortunately, it has often been said that when scientists reduce an integrated whole to its fundamental constituents (cells, genes, fundamental particles, reservoirs, anomaly amplitudes, etc.) and then try to explain all phenomena with regard to these elements; it is impossible to understand the coordinating activities of system.
Fig. 5- So far, in deep-water environments, exploration success rate has been quite high, mainly in West Africa (40%). In the Gulf of Mexico, it is around 30% and in Brazil roughly 25%. The global average exploration success rate is approximately 30 %, which apparently indicates that deep-water exploration is facile. However, not all discovered hydrocarbons have been proven to be economic. In addition, it is important to notice that 200 MMBBOE discovered in West Africa may be classified as resources (may be non-economical), while in the GOM, they will be considered as reserves, i.e., economical. On the other hand, it is important to point out that the easy deep-water exploration targets, particular in Western Africa, are tested first. Indeed, in offshore Angola, for instance, the exploration of the relinquished area of the block 17, is not going to be so easy as at first, since the more evident amplitude anomalies have already been drilled. In the same token, the exploration in the next relinquished areas of blocks 31 and 32, will be much more difficult and, probably, the success rate is going to plunge abruptly. Indeed, so far, as in the old block 17, exploration was just mapping and drilling the larger and evident amplitude anomalies. In fact, some executives used to say "even a taxi drive can find oil in offshore Angola". I hope they can be able to find oil on the next relinquished areas, in which the potential prospects are not only below the inversion surface (no amplitude anomalies) but in a subsalt context as well.
In fact, in spite of the large number of announced discoveries, the consequences of the Cartesian exploration approach are already quite evident. In fact, many drilled amplitude anomalies (USA $30 to 50 M per well) are not associated with hydrocarbons but with:a) Condensed stratigraphic sections, b) Facies change, c) Fault planes, d) Volcanic glass, e) Downlap surfaces, f) Opal horizons g) Cherts, h) Pelagic limestones i) BSR (Bottom Simulated Reflectors, Fig. 6), j) Diagenic line, etc.
Fig. 6- Not all bright spots correspond to hydrocarbon presence. As illustrated on this seismic line the bottom simulating reflector (BSR) may appear as a bright spot which cross-cuts bedding-related reflectors. Indeed, the lower limit of hydrate-cemented sediment is quite often concordant with bathymetry, because the velocity contrast between the gas-hydrate-cemented sediments and underlying non-cemented sediment is large enough to generate a non-chronostratigraphic seismic reflector.
Thus, in deep water, even above the inversion point where the amplitude anomalies are normally located, a reductionist exploration is not appropriate. Amplitude anomalies are necessary but not fundamental. The identification of stratigraphic and morphological traps, the reservoir architecture prediction, the cartography of the seals, the maturation zones and migration paths, etc., are paramount.
So far, in deep water exploration, the reductionist approach has been very successful and is responsible for the new exploration cycles that characterize all offshore petroleum basins. Actually, in almost each petroleum basin, it is possible to recognize several exploration cycles associated with new technologies. For instance, in Campos basin (fig. 7), three exploration cycles can be recognized: (1) The first, between 1974 and 1983, (2) The second between 1983 and 1992, and (3) The third since 1993.
Fig. 7-This figure illustrates the cumulative reserves of 46 discoveries from turbidite reservoirs in the Campos basin. The main graphic shows individual fields and discoveries in chronological order (histogram bars, left y-axis) and cumulative ultimate recoverable reserves for the basin (right x-axis). The cumulative curve is re-scaled in time in the upper left inset. The pie chart shows the percentage of the reserves for each trap type. In this basin, the cyclicity of the exploration results is quite evident. Three peaks of discovered reserves are easily recognized. Each cycle seems to correspond to a technological improvement in petroleum exploration (see text).
The first cycle emphasizes conventional shallow water exploration. The second cycle marks the advent of new drilling technologies, which allow for testing of large deep-water turtleback structures such as Albacora, Marlin and Barracuda. The last cycle is mainly due to new geophysical technology, particular seismic DHI’s and subsalt imaging.
The tremendous progress in finding hydrocarbons realized by explorationists in deep-water exploration did not significantly contribute to widening their basic exploration philosophy. The Cartesian paradigm (reductionism or fragmentation of exploration) often dominates exploration and particularly deep-water exploration. In fact, as amplitude anomalies and large structural or morphologic traps become less common, to continue to find significant resources, a new paradigm will be necessary with concepts transcending the Cartesian vision of Geology. It is possible that a systemic or holistic vision furnish the conceptual setting of new exploration (fig 8).
Fig. 8- In deep water (>500 meters), the recoverable resources announced in Brazil, West Africa, GOM and NW Australia (fig. 1) include producing reserves, i.e. those in development, and technically recoverable resources for which development has not been sanctioned. All these resources are in Atlantic-type divergent margins. However, the resources found in Mid-Norway (Ormen Lange) 11 TCF & 34 MMBC, Egypt (Scarab-Saffron) 4.5 TCF and Philippines (Malampaya) 3.5 TCF, strongly suggest that other types of sedimentary basins can also be highly prospective. This seems particularly true for non-Atlantic type divergent margins. In addition, as illustrated above, other deep water basins as Jean d’Arc, Sakhalin, South Caspian, Taranaki, etc, and the ultra deep basins must be taken into account. In spite of all these discoveries, in terms of global petroleum consumption, it must be said that the deep-water exploration has been quite disappointing. Indeed, it cannot substantially delay the peak of oil. Let's take a simple example. Assuming that the remaining reserves of the offshore Angola (recently, ENI gave almost USA$ 1G (1 billion) to get the relinquished area of the bloc old 17) are 10 Gbl (10.000.000.000bl), they correspond just to four (4) months of the world oil consumption (85 Mbld).
In a systemic/holistic exploration approach, the passage from the objects to the relations will have important implications. The relations should be used as base of all definition. Geological features, such as a turbidite, should be defined not by what it is, in itself, but by the relations with other objects. The fragmentation or reduction of exploration should not be confused with the act of division of an area of knowledge into particular fields of specialization or with the abstraction of specific problems for study. These divisions may be perfectly legitimate, and in fact, they are essential features of exploration. Rather as the term indicates, to fragment means “to back up or to smash”. Fragmentation in exploration arises when an attempt is made to impose divisions in an arbitrary fashion without any reference for wider context, even to the point of ignoring essential connections to the rest of the basin or adjacent basins.
The ultimate recoverable resources, (at least 1 BBBOE from turbidites) for 17 sedimentary basins of different types are illustrated in fig. 9, as well as the age of their main reservoir rocks. Cenozoic divergent margins (Atlantic and non-Atlantic type) are largely dominant. However, Cenozoic perisutural and episutural basins are also quite prolific.
Fig. 9- This plate illustrates the more likely total Ultimate Reserves, for 17 basins, exceeding 1 BBOE ultimate recoverable. The basin types, mainly from the Bally's classification (1980), are listed along with their reservoir ages. The green colour represents oil, and the red gas. Outside of divergent continental margins (Atlantic or non-Atlantic type), the reserves are quite small. However, several conjectures can be advanced to explain such a feature: (i) the absence of source-rocks and (ii) the absence sealing-rocks. Indeed, when the potential reservoirs are turbiditic in nature, the potential traps are mainly non-structural, and therefore, the sealing-rocks, lateral and vertical become paramount. In fact, without a rock sealing the reservoir interval there is no closure, and therefore no trapping.
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