Caister B (UK) – Located in the Southern North Sea and beginning production in 1993, the Caister B contains a GIIP of 171 BCF and EUR of 113 BCF for a gas recovery factor of 66%. Gas is trapped in the Bunter Sandstones within an elongate dome formed by salt diapirism. The reservoir consists of sheetflood sands and ephemeral fluvial channels with minor sabkha and aeolian deposits. Reservoir quality is good with high N:G (0.98) and good poroperms. A drastic drop in production was related to salt deposition, high water-cuts and sand production led to the drilling of a horizontal sidetrack. A foaming and water-washing pilot failed. Production ceased in 2013 when cumulative production was 113 BCF and the field was decommissioned in 2016.
Dai Hung (Vietnam) – Onstream since 1994, the field has a STOIIP of 436 MMBO, which is mainly contained in the Lower Miocene Dua Formation sandstones and the Middle Miocene Thong-Mang Cau Formation carbonates. Oil and gas occur in organic buildups and sandstones deposited in fluvial and deltaic environments, trapped in a heavily faulted horst and tilted fault-block complex. The main producing sandstones have 25% porosity and 50 mD permeability. Light-medium and sweet oil with 28-37 °API is produced by solution-gas drive and weak aquifer support, supplemented by water injection one year after the field was put onstream. Matrix acidization and infill drilling improved recovery. Ultimate recovery factor is estimated at 19.8%.
Hochleiten (Austria) – Located in the Vienna Basin, this field came onstream in 1974 and had a STOIIP and EUR of 53 MMBO and 25 MMBO, respectively. Oil and gas are contained in the Middle Miocene lower Sarmatian and Badenian nearshore sandstone deposits, trapped in tilted fault-blocks. There are five fault compartments. Lateral facies changes and shale interbeds resulted in poor connectivity and resulted in large pressure changes. The heavy oil required water injection, however, this combined with well stimulation using cyclic gas injection were unsuccessful owing to the heavy oil and complex heterogeneous reservoir. Cumulative production reached 19 MMBO by end-2018.
San Francisco (Colombia) – Onstream since 1985, the field has a STOIIP of 675 MMBO, which is contained in the Albian-Aptian Caballos Formation. The estuarine channel sandstone reservoir has an average porosity of 17% and permeability of 950 mD. Medium oil (25 °API) is trapped in a faulted anticline by dip closure and lateral facies change. Production was by solution-gas drive aided by waterflood. Reservoir stimulation, artificial lift, and conformance improvement help enhance recovery. An ultimate recovery factor of 31% is expected.
Semberah (Indonesia) – Onstream since 1991, the field has an EUR of 65 MMBO and 1189 BCF, held in numerous isolated sandbodies in an inversion anticline. The sandstones were deposited in distributary channels in fluvial-dominated delta settings with porosity of 5-28% and permeability up to 1200 mD. The light oil (40 °API) is produced by strong aquifer and gas expansion drive. In-situ gas lift and deliquification was applied in oil and gas producers, respectively. Step-out drilling in low-permeability gas pools led to additional reserves.
Tambaredjo (Suriname) – Onstream since 1982, the field has a STOIIP of 525 MMBO. An >500 ft oil column is trapped at 850 ft TVD by updip pinch-out and onlap of the Paleocene Lower Saramacca sandstones on a regional homocline. Heavy oil (16 °API) has been produced from fluvial-channel, tidal-channel, mouth-bar, and shoreface sands. Reservoir permeabilities range from 0.5-40 D with porosities of 33-40%. A tight (10 ac) grid of producers was adopted for development, with all wells completed as open holes and equipped with pumps. The field suffered from rapid water breakthroughs, which was mitigated with higher-capacity pumps. Cyclic steam injection, horizontal drilling, and cold heavy oil production with sand have been tested but have proved either too expensive or not technically feasible. An ultimate recovery factor of 32.5% is expected.