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= Sirikit field of the Phitsanulok Basin, Thailand =

Sirikit Oil Field Summary (Geologic History)
The Sirikit oil field is an Cenozoic age unconventional oil play found in the Phitsanulok Basin of Thailand. This basin was formed through significant extensional rifting throughout the Oligocene, and concurrent basin inversion. The Sirikit field lies within a half-graben bordered to the west by a listric fault. The Sirikit area is considered to unconventional due to the nature of deposition having stemmed from fluvio-lacustrine systems. Due to extensive delta progradation and retreat during this time period, the system is defined by sequences of heterolithic clay and sand. This ultimately gave cause to both structural traps and stratigraphic traps being able to form locking in oil and gas throughout the basin. Though many formations exist within the Phitsanulok basin, the Lan Krabu and the Chum Saeng have the largest potential of oil and gas. The Lan Krabu and Chum Saeng Formations also intertwine due to delta movement depositing clay and sand intermittently. This in turn causes the Lan Krabu and the Chum Saeng to function as both the source and the seal of the reservoir. Due to a slight up-dip angle of approximately 15-25 degrees, the oil found in the Phitsanulok basin, specifically the Chum Saeng travels and comes to rest in the Lan Krabu Formation of the Sirikit area forming the greatest potential reservoir.

Who Discovered the field?
The Sirikit oil field was discovered in 1981 by Thai Shell during a partnership with Thai company PTT Exploration and Production (PTTEP). The well is now however owned entirely by PTTEP, and began production in 1982. The area was named after Thailand's Queen Sirikit.

Shell Logo.

Production

 * The oil found in the field is relatively immature and produces a light waxy sweet oil (15-20% wax).
 * 1997 - 24,000 bbl/day of oil, 300 tonnes/day liquified petroleum gas, 40 MMscf/day of sales gas.


 * 2014 - (Refer to table below)



Stratigraphy and Geomorphology
The Phitsanulok basin is located in Central Thailand is of Cenozoic age and is located within a cluster of equally aged basin systems. The Phitsanulok basin has undergone drastic and frequent geomorphic changes since the Oligocene. The area lies within an extensional setting and is highly faulted, with extension continuing from the Oligocene up until the Late Miocene where structurally the basin began to undergo inversion, depositing marine claystone atop fluvial sandstone deposits. The Sirikit field area, located in the western flank of the Phitsanulok basin, is known for being greatly faulted by north-south trending listric type normal faults. These listric faults were later altered during sequences of left lateral strike slip faults, within the Mae Ping and Uttaradit fault zones.. These strike slips fault coincidentally formed the surrounding area of antithetic and synthetic faults. The overall structure of the basin being a unconventional lacustrine basin associated with lacustrine environments such as deltas, alluvial fans, shallow marine, or similar paleoenvironments.

Chum Saeng
Defined as a sequence of Lower-Middle Miocene syn-rift lacustrine organic rich bituminous claystone with slight coal deposits. The Chum Saeng is strongly defined by listric faults cutting through it deep into basement rock. This area is also frequently overlapped by the Lan Krabu due to delta progradation. This area also forms a east to north east dipping fault of roughly 15-25 degrees and causes oil/gas flow to move towards Lan Krabu reservoirs. The Chum Saeng also forms heterolithic sediment packages with the Lan Krabu of intertwining claystone and sandstone. These heterolithic packages can be linked to the formation and trapping of sandstone by claystone during delta cycles. Type one and three kerogen are also present in the formation and are though to have been derived from freshwater algae. The total organic carbon content typically ranges from 1-2% but can be much larger between 17-40% occurring within the thin beds of the formation.

Lan Krabu
This formation is largely defined as a Lower Miocene fluvio-lacustrine system, composed majorly of sandstone and siltstone. The body of this formation being made up of lacustrine delta sand and shale deposits. These primarily formed during regressive marine cycles or during cycles of delta progradation. This formation is both sourced and sealed by the Chum Saeng formation which is composed of claystone or otherwise known as shale deposits. As you move further south in this formation, it is found that shale becomes more dominant as it begins to coalasce with Chum Saeng formation as synrift sediment increases. This formation is also greatly faulted with high angle normal faults occurring deep in the section. Three main reservoir components are present: K, L, and M. These three members are sandstone beds being stratigraphically trapped and separated by lacustrine shales. The claystone of the Chum Saeng is often found interweaved into the oil and gas bearing sandstone of the Lan Krabu which is forming the main reservoirs found within the K, L, and M members. Sandstones typically range from 21-30% porosity and have a permeability in the range of 30-2000 mD.

Trapping
This area is unconventional due to the lacustrine bituminous clay-rich environment in which the sediment was formed and deposited. Normal faults, along with basin inversion and strike-slip faults also caused many depositional changes within the basin. Due to the complexity of the tectonism and deposition of sediment this area is defined as both, structurally and stratigraphically trapped oil and gas deposits. Structural traps were formed from fault bound oil and gas becoming stuck in the anticlinal structure of the basin. Stratigraphic traps formed from highly impermeable shale due to heavy marine sequences being deposited atop porous sandstone deposits. Essentially, the shale heavy Chum Seang and the recurring sandstone of the Lan Krabu being juxtaposed atop one another creating source, seal, and reservoir can result in either hydrocarbon trap system depending upon drilling location. The wells in the area are naturally driven by a gas cap, but was found to be too weak too be sustained. Due to the weak gas cap, water injection was to be used as a secondary means of recovery.