Explore 56 new and updated Reservoir Evaluation Reports from across the globe. Discover a wide spread of global oil and gas analogues, including: 13 from the Middle East, 12 from North America, 10 from Europe, 9 from Asia-Pacific, 6 from Latin America, 5 from Africa, and 1 from Russia and the Caspian.
Highlights include:
The Greater Burgan Field (Kuwait) – Located offshore, this supergiant is the world’s second largest oil field with a STOIIP of 84 BBO and EUR of 51 BBO. Most of the oil is contained in a single pool in the Wara-Mauddud-Burgan reservoirs with a single 1226-ft oil column contained in a basement-uplift anticline. Production also comes from the Minagish Oolite and Marrat reservoirs. Field production peaked in 1972 at 2.4 MMBOPD but the rate was later constrained, and the field was severely damaged in the Gulf War. Production was restored by 1994 to pre-war levels. Since, recovery has been improved by using horizontal and multilateral wells. Other improved recovery techniques include infill drilling, acidization and hydraulic fracturing, water shut-off, water coning control and the use of simultaneous injection and production wells.
The Ansai Field (China) – This field has a STOIIP of 3.5 BBO and a recovery factor of 22%. Oil is stratigraphically trapped on a gently dipping homocline by lateral depositional pinch-out and diagenetic changes. It produces from lacustrine-deltaic sandstones of the Yanchang reservoir with average porosity of 12% and average permeability of only 1.3 mD and therefore hydraulic fracturing is essential to achieve commercial flow rates. The reservoir was developed using water injection, infill drilling and horizontal wells. Advanced injection, where an injector is activated prior to adjacent producers being completed, has been particularly effective along with repeat fracturing and cluster well drilling techniques.
The Korolev Field (Kazakhstan) – Discovered in 1986, the Korolev Field did not come onstream until 2001 when export capacity became available. It contains a STOIIP of 1.6 BBO and EUR of 840 MMBO. Here, an overpressured 1033 m-thick oil column is contained in a Devonian-Carboniferous skeletal-oolitic carbonate buildup. Reservoir architecture is complex with natural fracturing and karstification improving quality and vertical connectivity. Production was initially through two wells, increasing to nine when production reached ~57,000 BOPD. Productivity was improved through acid stimulation. A small-scale water injection pilot in 2016 was followed by a larger two-well pilot in 2021 to gather data and reduce uncertainties.
The Madura MDA Field (Indonesia) – Located in the Madura Strait, offshore Java, this field has a GIIP of ~400 BCF and a recovery factor of 77%. Here, dry biogenic gas is trapped in the Pliocene Globigerina Limestone in a faulted inversion anticline. The reservoir consists of friable, foraminiferal grainstones and muddy wackestone/packstones. Despite being discovered in 1984, the field did not come onstream until 2022. Production was via five radially-drilled, highly-deviated/horizontal wells, achieving a plateau of 96 MMCF/day in 2024-25.
The Erha Field (Nigeria) – Located on the outer lobe of the Niger Delta, and one of Nigeria’s first deep-water developments, the Erha Field sits in 1200 m of water and has a STOIIP of 1460 MMBO and an EUR of 492 MMBO. The reservoir consists of stacked deep-water channel complexes which drape over a shale-cored anticline and pinch out laterally. Field production began in 2006 and it produces by gas-cap expansion supported by continuous water and gas injection. Here, 4-D time-lapse seismic improved understanding of reservoir communication pathways between the channel complexes and led to a reconfigured injection strategy adding 9000 BOPD to production at the field.
The Apaika-Nenke Field (Ecuador) – New to DAKS – Located in the Oriente Basin, this small field has a EUR of 34 MMBO. Here, oil is contained in fluvio-deltaic and estuarine sandstones of the Albian-Campanian Napo Formation. The reservoir is weakly consolidated with average porosity and permeability of 23.5% and 1168 mD. The field was developed using deviated J- and S-profile wells drilled from two pads, as well as horizontal wells, and utilized pressure drawdown of wells to reduce sand production. Production from the Upper Napo M1 reservoir peaked in 2016 at ~16,455 BOPD under strong aquifer and solution-gas drives, followed by a sharp decline. Field production rates averaged 3800 BOPD by 2025.