Enhanced Understanding of Fluid Variability in Pliocene Reservoirs of the South Caspian Basin

Abstract

The South Caspian Basin (SCB) hosts more than 600 onshore and offshore oil and gas fields where hydrocarbons are mainly accumulated in Pliocene sand reservoirs. Fluid properties in two adjacent anticline fields located offshore in the eastern SCB show significant variations both laterally and with depth (API gravity from 26 to 53, Gas-Oil Ratio (GOR) from 350 to >20,000 scf/bbl). This study aims at investigating lateral and vertical connectivity in these two fields and the processes causing fluid variations to better handle the reservoir production strategy and decisions for infill drilling and near-field exploration.

Fluid lateral and vertical variations were evaluated using geochemical analyses performed on 45 surface and downhole samples from 35 wells and 8 distinct producing intervals. Results show that the Oligocene-Lower Miocene Maykop Formation initially generated hydrocarbons, which accumulated in the deeper layers and possibly in the shallower layers. Subsequently, the Middle to Upper Miocene Maykop Formation started generating hydrocarbons, which migrated to the shallower layers. There are no abrupt changes in facies throughout the Oligocene and Miocene deposits, but variations in organic matter input are reflected in the bulk and compound-specific isotopes and in the hopanes and steranes distributions. Biomarkers show a less reducing environment than described for the Maykop rocks in the western SCB, but are mixed with markers of a highly reducing environment, suggesting a mixture of different facies. Other source rocks in the SCB —Jurassic and Cretaceous carbonates, Eocene shales and Lower Pliocene mudstones— might also contribute to the hydrocarbons accumulated in the Pliocene sandstone reservoirs, possibly indicating a more complex petroleum system than previously reported for the SCB. The presence of H₂S, reported for the first time in the SCB, and in a clastic reservoir, further suggests a possible contribution from deeper carbonate source rocks.

Slight biodegradation and water washing alter hydrocarbons distributions in most samples. Co-occurrence of biodegraded and non-biodegraded fluids and of hydrocarbons showing various stages of thermal maturity in some samples indicate that several reservoirs have received multiple fluid charges. Migration of light fluid might be the dominant process affecting the fluid properties, highlighting the potential key role of the fault network on the fluid type distribution in the two investigated fields.

AAPG Datapages/Search and Discovery Article #90323 ©2018 AAPG Annual Convention and Exhibition, Salt Lake City, Utah, May 20-23, 2018