Tengiz Field is the world's deepest developed supergiant oil field, with an oil column of nearly 1600m. The reservoir consists of Devonian and Carboniferous platform/slope carbonates, divided into three stratigraphically-defined units. Production of over 500,000 BOPD is mainly from the upper unit. A significant portion of this production is controlled by natural fractures. A new reservoir model has been constructed to support a future growth project, including miscible gas injection, and to guide reservoir management strategies, development planning, and oil-in-place estimation.
Our new model represents a significant change from previous models in that a dual porosity, dual permeability flow formulation (fracture and matrix) is being applied. This change to dual porosity, which is necessary to effectively characterize the fracture-matrix flow, requires a significant modification of the overall reservoir modeling workflow. Matrix porosity and permeability are distributed into the fine-scale model and fracture properties are populated into the model after upscaling, because representative fracture attributes are only available at a large scale.
Fracture porosity is high in the depositional slope (about 0.4%) due to the cavernous character of portions of the fracture system. This fracture porosity represents a significant volume, and has a large impact on reserves. Fracture permeability is also a critical factor, and has a large affect on flow behavior and recovery. Although fractures are important, their intersection by wellbores is relatively rare, due mainly to under-sampling of sub-vertical fractures by vertical wells and sparse well control in the slope. Because of this under-sampling, and general ambiguity in image-log data, uncertainty associated with fracture properties is large. To address this uncertainty, significant effort has gone into collecting reservoir surveillance data. In addition, fracture properties from image logs were reconciled with well tests and other logs.