Turbidite plays' immaturity means big potential remains

WORLD TURBIDITES-1

Henry S. Pettingill
Repsol Exploracion SA
Madrid

The international exploration and production industry is increasingly focusing on deepwater plays. Turbidites are not the only reservoir type that occurs in deepwater frontiers, but they are the primary reservoir type of those plays. This has most recently been reinforced by deepwater drilling in Brazil, the Gulf of Mexico, and West Africa.

A worldwide data base assembled from published information on 925 fields and discoveries with deepwater clastic reservoirs ("turbidites" sensu lato) has been employed to investigate the large-scale exploration and production trends (Fig. 1 [121,845 bytes]). Coverage of the Former Soviet Union, China, and the Indian subcontinent has been minor, but with the large data base of fields and discoveries from the rest of the world, the broad conclusions should remain valid.

A simple but useful way of analyzing the reserves potential of a basin or play is to plot either cumulative recoverable resources or produced reserves versus time (Fig. 2 [34,414 bytes]), sometimes termed a "creaming curve." Generally, exploration maximizes value creation when this curve is at its maximum slope. Value creation in the latter part of the curve, where the slope flattens, is generally driven by changes in fiscal environments, politics (i.e. new access), technology advancements, or cost reduction. However, it is important to note that when using such curves on a basinwide scale, individual component plays can deviate from the curve. For example, the Gulf of Mexico turbidite play displays such a deviation, providing rejuvenation of an otherwise mature basin (Fig. 2C).

Using such an analysis in the most general sense, a cumulative reserves versus time curve for all worldwide turbidite discoveries exceeding 10 million bbl of oil equivalent is presented in Fig. 3 [87,339 bytes]. The cumulative curve has been re-scaled in absolute time in Fig. 4 [13,537 bytes].

It is evident from these curves that turbidites are a reservoir type that have a relatively recent rise in importance in global exploration and production, and global turbidite exploration is at an immature stage. In fact, there has been a three-fold increase in cumulative ultimate discovered turbidite reserves since 1970. In addition, three of the eight turbidite supergiants that exceed 2 billion bbl of oil equivalent have been discovered since 1980. Since most deepwater plays have turbidites as primary reservoirs, the deepwater play can be also be considered immature, with significant reserves remaining to be discovered.

This article describes the global turbidite play in terms of:

1. Basins of the world where turbidite fields have been discovered;
2. The five largest basins in terms of total discovered resources; and
3. A summary of trap type, which is a critical geological factor in turbidite fields.

The second article will summarize a population of the world's 43 largest turbidite fields and discoveries.

Setting of turbidite fields

Fig. 5 [59,767 bytes] shows the top 17 basins in terms of discovered reserves, which constitutes those that exceed 1.0 BBOE ultimate recoverable.

The top three are divergent margins and the next two "California-type" borderland basins. These top five total 47 BBOE, about 50% of the world total shown in Fig. 4. Although the divergent margins and California-type basins are dominant, it is important to note that several other basin types are represented in the top 17, such that virtually no basin type should be excluded provided the requisite petroleum system parameters are in place (e.g. source rock presence and maturation, thick net reservoir sections, formation of large traps).

The top three basins which to date have the most oil and gas proven from turbidites are discussed briefly herein, in order of their ultimate reserves. All three are in divergent settings, and two are Atlantic-type passive margins.

Greater North Sea

The Viking graben, Central graben, and Moray Firth areas of the North Sea are rift-sag basins filled primarily during the Mesozoic and Tertiary. Turbidite plays of the North Sea graben systems encompass territorial waters of the U.K., Norway, and to a small extent, Denmark. The grabens have different depositional and tectonic histories, including turbidite plays with reservoirs of Jurassic, Cretaceous, and Paleogene age. The West of Shetlands turbidite play is from a separate Atlantic-type passive margin basin, but since it shares the Kimmeridgian source rock and age-equivalent Paleocene reservoirs of the North Sea, its discoveries are included in Fig. 6 [110,383 bytes]. The geological settings of these basins and their turbidite systems have been well documented in the literature (for example, references 1 and 2). In the most general sense, the play area is characterized by a robust deepwater sand delivery system, with thick reservoir accumulation in grabens and reservoir pinchouts along the flanks in the Mesozoic and Paleocene systems, and thick, isolated basin floor channel sands in the Eocene. Seismic anomalies, including flat spots and AVO, have been the key factor that allowed identification of both structural and stratigraphic traps.

A cumulative ultimate reserves versus time curve for the North Sea graben system turbidite play is shown in Fig. 6. About 17 BBOE have been found in turbidites of the North Sea, with a possible additional 2 BBOE in the West of Shetlands. Twelve giant fields have been discovered in turbidites in the North Sea-West of Shetlands area, in Jurassic, Cretaceous, Paleocene, and Eocene reservoirs.

The numerous individual sub-plays are not differentiated herein; however a splitting based on reservoir age has been employed which differentiates the Upper Jurassic, Lower Cretaceous, Paleocene, and Eocene levels (Fig. 7 [58,978 bytes]). The Paleocene reservoirs account for about 50% of the area's recoverable hydrocarbons, and the Paleocene cumulative ultimate curve, in contrast to the other reservoir ages, continues its climb through 1995 (most recently reflecting the West of Shetlands discoveries); however, given the publishing lag, drilling activity in the Mesozoic since 1995 may lead to rejuvenation of those plays.

For the large fields, traps tend to be sizable: areas up to 100 sq km, with net pay often several tens of meters. Other factors contributing to the basin's large reserves are good porosity (average 25%) and permeability (up to 3 darcies). Stabilized flow rates of 30,000 b/d have been achieved in the West of Shetlands (Schiehallion³); in the grabens, 10,000-12,000 b/d has been achieved, but 2,000-5,000 b/d is more typical of the larger oil fields.

Oil gravity ranges from 18-50°, and the total oil/gas mix within turbidites is 70% oil on an equivalent basis. Oil recovery ranges from 26-40% in the Jurassic and Cretaceous reservoirs but from 45-57% in the Tertiary reservoirs, where a strong water drive is often present.

Employing a simple three-fold trap classification that distinguishes purely structural, purely stratigraphic, and combination structural-stratigraphic traps, turbidite reserves are classified according to trap type (inset of Fig. 6). Normalizing for fields where insufficient trap information is published, 37% of the hydrocarbons are found in purely structural traps, 26% in purely stratigraphic traps, and 37% in combination traps.

Fields with compactional trap components, common in the Tertiary, can be classified into one of the previous three categories depending on whether structural closure exists at the top reservoir horizon. These fields account for 24% of the North Sea turbidite reserves. Structural traps account for a few giant fields that were discovered early (Forties and Frigg); however, a continued climb in reserves resulted from the addition of fields trapped with stratigraphic components in all reservoir ages (e.g., Jurassic;^{4 5 6} Cretaceous: Brittania,⁶ Captain;⁷ Tertiary: Alba,^{8 9} Grane.¹⁰). In fact, since 1975, an average of more than 500 MMBOE/ year has been discovered in North Sea and West of Shetlands turbidites (Fig. 6 inset).

U. S. Gulf of Mexico

The offshore U. S. Gulf of Mexico is a prolific and "hot" area of turbidite exploration and production, primarily in deep water but also in shallow waters, including the subsalt play.

The basin is a passive margin, with turbidite reservoirs of Miocene, Pliocene, and Pleistocene age in a variety of settings, usually related to syn-depositional salt tectonics.^{11 12} This basin is an example of a relatively "new" play in turbidites revitalizing a mature basin, with approximately 12 BBOE discovered in turbidites in the offshore basin (Fig. 2 and Fig. 8 [112,374 bytes]).

In much of the deepwater portion of the turbidite play, sediment ponding in intraslope salt minibasins is key to the accumulation of stacked reservoirs and thick net pay sections, as well as creating reservoir pinchouts on the minibasin rims.^{12 13} However, significant discoveries have also been made in less confined settings in the eastern Gulf of Mexico, and leasing of the abyssal plain has initiated exploration in the unconfined setting. Seismic anomalies have been the key factor that allowed identification of the stratigraphic traps.

A notable characteristic of Gulf of Mexico turbidite fields is their relatively small trap area. Salt minibasins provide sediment ponding and trapping in much of the basin, and these minibasins are restricted in size in most of the basin. In contrast to the North Sea, few if any turbidite fields or discoveries have trap areas exceeding 25 sq km; this probably explains why few giants have been found in the basin. Trap areas for the large Mars¹³ and Auger¹⁴ fields are less than 25 sq km, yet stacked pays of up to 200 m in net can lead to large reserves (Mars exceeds 700 MMBOE).

Other factors contributing to the basin's large turbidite reserves are high porosity (average 30%), excellent permeability (up to 3 darcies), and well flow rates up to 12,000 b/d (30,000 b/d being planned¹⁵). Oil gravity ranges from 18-25°, and the total oil/gas mix within turbidites is 60% oil on an equivalent basis, with a more oil-rich ratio in the deepwater portion of the play.

The Gulf of Mexico is a good example of how stratigraphically-trapped turbidites can provide significant exploration success in a basin. Because of the competitive nature of leasing in the U.S. Gulf of Mexico, published geological description of fields is relatively scarce, especially in the deepwater play. However, useful insights can still be extracted from an anecdotal analysis of trap type because information has been published on most of the largest discoveries.^13-18

Fig. 8 has trap type indicated for the major fields for which such information has been published. The discovery of the partially stratigraphically-trapped Bullwinkle field¹⁶ in 1983 occurred when the basin's turbidite cumulative ultimate reserves curve shows an increase in slope, and in subsequent years the cumulative curve is dominated by discoveries with a stratigraphic component. In fact, since 1983, an average of about 600 MMBOE/year has been discovered in turbidites, primarily in deep water. The impact of stratigraphic trapping was demonstrated in 1989 with the discovery of giant Mars field, which according to published maps^{13 19} is a synclinal feature with a strong stratigraphic trap component.

Campos basin, Brazil

The Campos basin is an Atlantic-type passive margin basin with turbidite plays in reservoirs of both the syn-rift (Albian-Turonian) and drift (Santonian-Miocene) phases of basin development.

Readers are referred to excellent summaries of the geological setting of the Campos basin and its turbidite systems published by Petrobras.²⁰ As in the Gulf of Mexico, structure and turbidite stratigraphy of many fields are related to salt tectonics. Turbidite fields and discoveries of the Campos basin account for more than 14 BBOE of announced reserves and six giants.

The Campos basin has not yet reached a mature stage with respect to exploration (Fig. 9 [78,806 bytes]). The first discovery occurred in 1974, but the climb was modest until 1984, when the first of the six giant fields was discovered (Albacora, 624 MMBOE²¹), in a combination trap. Large discoveries have continued, as recently as 1996 (Roncador, 2.9 BBOE²²), each of which has a significant stratigraphic trap component.²² Since 1983, an average of approximately 850 MMBOE/year has been discovered in turbidites, almost entirely in deep water.

The stratigraphically-enhanced trapping has created both large trap areas and net pay sections; however, it is the potential for very large trap areas that sets the Campos basin apart from other turbidite-producing basins of the world. Marlim field has a trap area exceeding 150 sq km, while the greater Marlim complex (Marlim, Marlim Sul, and Marlim Leste) exceeds 500 sq km. Other large fields range from 100-250 sq km.

Large net pay values in both Cretaceous and Tertiary reservoirs, as high as 154 in total, contribute to the Campos giants. Other factors contributing to the large reserves are excellent porosity (average 30%) and permeability (up to 5 darcies), and flow rates often exceeding 5,000 b/d. These positive factors offset the fact that the crudes may be heavy (as low as 18°), viscous, and waxy. Oil recovery generally ranges from 19-33%.

Published information on trapping of the Campos fields indicates that more than 80% of the oil in turbidites is partially or totally stratigraphically trapped (Fig. 9 inset). The steep climb in the cumulative ultimate curve is a result of several giant fields, each having a combination fault/pinchout trap. Thus, exploration of such traps was responsible for the Campos basin becoming one of the world's most prolific turbidite basins. Seismic anomalies have been a key factor that allowed identification of the stratigraphic traps.

Summary: The future

The recent steep climb in world cumulative reserves indicates that turbidites are in an immature exploration stage globally and will thus play a significant role in the future of hydrocarbon exploration and production.

This study indicates that deepwater passive margins will probably provide significant additional turbidite reserves as well as additional giant discoveries. Furthermore, combination traps and Tertiary reservoirs will be the focus because they have the potential for large trap areas and/or net pay sections and good quality reservoirs capable of high sustained flow rates. These characteristics have been components of the recent successes in West Africa, where several large discoveries have been made in the last two years.

This analysis of turbidite discoveries indicates that stratigraphic trapping usually contributes a major portion of a basin's ultimate reserves, although this contribution does not necessarily occur early in a basin's exploration history. Therefore, if a turbidite play is judged solely on its structural prospect inventory, then the reserve potential will generally be underestimated. This is reinforced by the fact that few giant turbidite fields have purely structural traps, and most of those were discovered by 1971. Thus, basins with current turbidite production predominantly from structural traps may have a bright exploration and production future.

Since most major turbidite hydrocarbon provinces are within basins that produce from other reservoir types, these lessons could be applied to major producing basins that contain turbidites but lack significant turbidite production even when such basins are in a relatively mature stage of E&P.

Turbidites are known to produce oil and/or gas in more than 80 basins^{23 24} and also occur in other petroliferous basins where they are productive only in minor amounts.²⁴ Significant future opportunity should therefore remain in those basins in which turbidites occur and robust regional charge systems are in place but in which reserves have been found primarily in fluvial and deltaic sandstones (examples in Table 1).

Acknowledgments

The author thanks Repsol Exploracion SA for permission to publish this study. He is grateful to all the authors who have published papers for their invaluable contribution to the understanding of turbidite exploration and production.

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