SANDAKAN BASIN' PROSPECTS RISE FOLLOWING MODERN REAPPRAISAL

Terry Walker
WMC Petroleum (Malaysia) Sdn. Bhd.
Kuala Lumpur

Borneo is fringed by six large Neogene deltaic basins, all but one producing substantial hydrocarbons. The Sandakan basin off Northeast Borneo is the exception, but the latest exploration results suggest that it will not remain so (Fig. 1a).

The Sandakan basin lies in the southwestern Sulu Sea straddling the Philippines/Malaysia maritime border (Fig. lb). The 40,000 sq km basin contains as much as 8,000 m of Neogene deltaic sediments.

Water depths range to more than 2,000 m, with most of the prospective basin area shallower than 150 m. A small portion of the basin outcrops in the southwestern onshore area.

COMPLEX HISTORY

The local tectonic history is very complex. The area was deformed in the Lower Miocene by north-south crustal shortening related to opening of the South China Sea. A northeast trending volcanic arc from subduction of the Sulawesi Sea is expressed in onshore outcrop-and as buried volcanoes on offshore seismic.

When South China Sea spreading ceased in the early Middle Miocene the southeastern Sulu Sea commenced back-arc rifting, also with a northeast trend, and eventually oceanic crust of the Sulu Sea was produced. The rift basins extended southwest onshore into the interior of Sabah.

A major shift in sedimentary provenance occurred in the late Middle Miocene. With cessation of Sulu Sea spreading (due to collision of exotic microcontinents related to the Australian and Philippines blocks) and uplift of the Borneo interior, the previously volcanic/volcaniclastic island arc geology and associated rift basins were replaced by the classic late Middle Miocene to Recent, quartz-rich, regressive deltaic association, common to all productive basins fringing northern Borneo.

In the Sandakan basin, the Kinabatangan River system eroded the clastic, quartz-rich hinterland (Fig. 1b). The Kinabatangan River drainage area is at least the same size as the Baram River drainage area, which fed the well known Baram Delta.

In the Upper Miocene, further compression began to close the newly opened Sulu Sea, a process that continues today. In the offshore Sandakan basin this compression resulted in the formation of several northeast trending arches, which reactivated the deltaic growth faults, creating large faulted anticlines.

In distal areas, reefs grew on preexisting highs, to be later buried by prodelta shales.

EXPLORATION HISTORY

Early workers reported oil and gas seeps from the onshore area in the late 19th Century. Shell and Esso conducted surface mapping in the 1950s and 1960, and French and Japanese groups drilled nine wells in the offshore Malaysian sector between 1970 and 1975. Seven wells have been drilled in the Philippines sector, most in the 1970s.

Between 1973 and a modern acquisition round in 1990, no seismic data were acquired in the Malaysian sector. The pre-1973 seismic on which nearly all wells were targeted is low fold, unmigrated, and of poor quality by modern standards. Fig. 2 compares 1990 and 1966 data from the same location.

There has been an exploration gap in the Malaysian sector of nearly 20 years that coincided with a period of major technological and theoretical (plate tectonics, sequence stratigraphy) advancements in the oil industry. The area was thus ripe for reevaluation.

EXPLORATION RESULTS

Sixteen wells have been drilled in the Sandakan basin, targeting both structural and stratigraphic plays. These wells have been classed as valid or invalid structural or stratigraphic tests based on modern seismic data and incorporating modern concepts.

Manalunan-1, an invalid stratigraphic test, targeted vaguely defined unclosed topsets of the regressive delta system. Modern delta models would require that these topset sands be closed structurally, as it would be unlikely that intraformational seals would be strongly developed.

Magpie West-1 and Clotilde-1, both invalid structural tests, targeted apparent anticlines on the vintage low fold seismic, which with modem data are clearly seen to be volcanic complexes.

Gem Reef-1, an invalid structural test, targeted the crests of a vertically persistent "anticline," which are shown to be seismic multiples of shallow reefs on modern data.

Nymphe South-1, an invalid structural test and one of three wells on the Nymphe structure, is mapped outside of closure at all levels with modern data.

Sebahat-1, Sentry Bank-1, 389-1, and 409-1 are all invalid structural tests lying either on unclosed structural noses or below closure on valid structures. In all cases poor seismic was the major contributor to well failure.

Pad-1 was an invalid stratigraphic test, lying too far downdip from good pinchout plays.

Of the six valid tests, all structural, Nymphe-1 flowed 14-15 MMcfd with condensate from two zones; Nymphe North-1 flowed 4 MMcfd and 500 b/d of light oil/condensate from one zone; Benrinnes-1 had numerous shows but could not be tested due to severe overpressuring at TD; Sentry Bank Reef-I intersected waterwet high porosity reefal carbonates that lacked a good migration conduit; and 333-1 and Dockan-1 are listed in this category only through lack of contrary information.

In summary, of the six valid tests, two discoveries and one probable discovery resulted.

Most wells were drilled with severely overbalanced muds, which undoubtedly suppressed shows. Recent petrographic and log analyses indicate that there are numerous potential zones of bypassed pay, as conductive minerals and shale laminae in the sands caused low resistivity/low contrast wire line log responses.

Modern seismic data display numerous direct hydrocarbon indicators (DHIs) that were not visible on vintage data. Near Benrinnes-1 in particular, at least three "flat spots" associated with hydrocarbons may be seen adjacent to the well.

STRATIGRAPHY

Pre-Middle Miocene stratigraphy (Fig. 3) is dominated by the widespread Eocene-Oligocene turbiditic Crocker formation, which served as a quartz-rich source for all of the Neogene deltas in northern Borneo.

Locally, the Oligocene was dominated by the shaley Kulapis formation and the sandy Labang formation, the depositional Boundaries of which are followed by the later northeasterly rift basin trends. The Labang formation and the rift-filling Tanjong formation also provided quartz-rich sediments to the later Neogene deltas of the Sandakan basin.

With the crustal shortening in the Lower Miocene, the Crocker, Labang, and Kulapis formations were all severely deformed and present no prospective targets for hydrocarbon exploration. The deformation and later rift formation created unstable tectonic conditions' which led to the deposition of widespread melange of the Garinono and Ayer formations, characterized by huge exotic blocks in a mud matrix.

South of the Middle Miocene Tanjong formation rift valleys in the Kinabatangan River drainage area, the remnants of island arc volcanism were being deposited as the volcaniclastic Tungku formation in the Dent Peninsula area.

In the post-Middle Miocene, the tectonic upheavals and volcanic/volcaniclastic stratigraphy were replaced by thick regressive quartz-dominated deltaic deposition, sourced by the uplifted Crocker, Labang, and Tanjong formations of interior Sabah and fed by the ancestral Kinabatangan River, which is the largest river in Sabah.

Deltaic deposition began with the aggrading shale-rich Sebahat formation. In distal areas reefs grew on topographic highs, which included subsiding volcanoes of the now-inactive arc system. This was followed by deposition of the sandy, southeast prograding Ganduman formation, which has probably not been tested on a valid structure and yet has prolific oil and gas producing equivalents in all of the other Borneo deltaic basins.

After major Pliocene erosion the aggrading shaley Togopi formation was deposited.

RESERVOIR-SOURCE-SEAL

Reservoirs have been encountered in the Tanjong, Sebahat, Ganduman, and Togopi formations and are typically fluvial, delta-plain, and nearshore sands, though basin-floor fan sands and some reefal reservoirs have been encountered. Porosities are usually 20-25%, permeabilities 10-300 md.

Source rocks are typical of those seen elsewhere in Borneo (and the other major Tertiary delta systems worldwide), being dispersed, dominantly terrestrial (Type II, III kerogens), and their distribution correlating to depositional environment. Geothermal gradients of 3.3-3.8 C./100 m suggest an oil window ceiling of 2,500-3,000 m.

The Borneo delta systems have provided much of the evidence that dispersed terrestrial source rocks can generate oil.

One reason the previous explorers relinquished much of the Sandakan basin in the mid-1970s may have been a perception that terrestrial source rocks generate only gas.

Seals are transgressive intraformational shales in the delta-top sediments and neritic shales in the slope front and basin floor areas, typical of productive Borneo deltaic basins.

STRUCTURE, TRAPS

Structural styles are diverse. The hydrocarbon-bearing structures, the Nymphe complex and the Benrinnes structure both lie at the intersection of a northeast fold trend and pre-existing north-south deltaic growth faults.

The prolific Baram Delta oil fields all lie at the intersection of deltaic growth faults and later fold trends. Several similar structures with closures up to 70 sq km and fault independent relief of at least 350 m remain to be drilled in the Sandakan basin, some on trend with the Benrinnes and Nymphe structures (Fig. 4a).

Positive linear flower structures (Fig. 4b) with large relief form another structural style. None of these features have been drilled in the Sandakan basin, although some are as large as 40 sq km in area and have reliefs of as much as 450 m.

Basement highs with pinnacle reef caps have been drilled but occurred at shallow depths, isolated from potential source rocks. Further features of this kind remain and lie deeper in the section, adjacent to mature source rocks.

Potential also remains in the hydrocarbon-bearing, structurally complicated Benrinnes and Nymphe structures, which were drilled in the early 1970s. Benrinnes is bisected by a reversed growth fault with strike-slip features. Benrinnes-1 tested the western block, and the eastern block remains untested.

The Nymphe structure is compartmentalized by numerous sealing faults, like many of the Baram Delta fields. Localized DHIs point to numerous accumulations within the complex.

Fig. 5 lists the numerous similarities between the Sandakan basin and the prolific Baram Delta of Northwest Borneo. Structural styles, source and reservoir types, temperature profiles, hydrocarbon types, and other factors are common to both areas.

The Baram Delta is estimated to contain recoverable reserves of at least 4 billion bbl of oil and 12 tcf of gas. The Sandakan basin is conservatively estimated to contain 1 billion bbl and 3 tcf of recoverable hydrocarbons.

CONCLUSION

The Sandakan basin was neglected for 15-20 years between the mid-1970s and 1990. In this time the oil industry underwent a revolution in all areas, from quantum leaps in seismic acquisition, processing, and interpretation technology to the great conceptual developments of plate tectonics and sequence stratigraphy (Fig. 6).

Also during this time strong evidence emerged that oil could be generated from terrestrial source rocks.

Recent basin studies indicate that there is at least 8,000 m of quartz-rich deltaic sediment, with great potential for previously overlooked low resistivity/low contrast pay zones. Previous lithostratigraphic correlations were incorrect, and modem bio/chronostratigraphic correlations indicate thick stratigraphic intervals that are virtually untested.

Coupled with recent developments in drilling technology, flexibility in field development, and booming Asian markets for gas and oil, these studies suggest that the Sandakan basin is poised to become Borneo's sixth hydrocarbon-productive Neogene deltaic basin.