It is estimated that more than 60% of the world’s oil and 40% of the world’s gas reserves are held in carbonate reservoirs. The Middle East, for example, is dominated by carbonate fields, with around 70% of oil and 90% of gas reserves held within these reservoirs.
Carbonates can exhibit highly varying properties (e.g., porosity, permeability, flow mechanisms) within small sections of the reservoir, making them difficult to characterize. A focused approach is needed to better understand the heterogeneous nature of the rock containing the fluids and the flow properties within the porous and often fractured formations. This involves detailed understanding of the fluids saturation, pore-size distribution, permeability, rock texture, reservoir rock type, and natural fracture systems at different scales.
Fracture corridors often exist that range from tens to hundreds of meters in width and height and have areal extents in the order of kilometers, representing primary pathways for hydrocarbon migration. Such fracture corridors can have a permeability of a thousand times greater or more than the surrounding rock matrix and have a considerable impact on oil, gas, and water production, including issues related to the drilling process.
Exploration and evaluation programs for carbonates are similar to those for sandstone reservoirs. However, new tools, techniques, and interpretation methodologies are required to address the specific challenges above to drill and produce these reservoirs optimally. These involve borehole measurements in combination with high resolution 3D surface seismic surveys.
Geologists and engineers must understand porosity distribution, fluid saturation, and the extent to which pores are linked to allow flow. These investigations begin in the borehole.
Fractures in carbonates can range from microscopic fissures to kilometer long swarms. To estimate the true production potential of the reservoir, one must also investigate at a larger reservoir scale.
With an understanding of the carbonate rock formation along the wellbore and at the larger reservoir scale, specific intervals of the reservoir can be opened and stimulated independently ensuring optimal reservoir contact and delivering full well potential.