17-05-2014, 11:15 AM
TIGHT GASES and KEY CHALLENGES IN INTERPRETATION OF DATA FROM TIGHT GAS RESERVIOR
TIGHT GASES and KEY.pptx (Size: 1.5 MB / Downloads: 12)
What is tight gas?
Locked in extraordinarily impermeable, hard rock, making the underground formation extremely "tight.”
Generally trapped in sandstone or limestone formations that are typically impermeable or nonporous, also known as tight sand.
Tight reservoirs contain no natural fractures, but cannot be produced economically without hydraulic fracturing.
Comparison with conventional gas
Requires more effort to pull it from the ground because of the extremely tight formation in which it is located.
While conventional gas formations tend to be found in the younger Tertiary basins, tight gas formations are much older. Over time, the rock formations have been compacted and have undergone cementation and recrystallisation, which all reduce the level of permeability in the rock.
Natural gas deposits have permeability of 0.01 to 0.5 darcy , but formations trapping tight gases have permeability of fractions of that.
Tight or low-permeability reservoirs as occurring only within basin-centered, or deep basin settings
Objective
In many tight gas provinces, the uncertainty in formation evaluation is such that wells are routinely drilled, cased, perforated, and completed with a seeming inability to discriminate economic from noneconomic reservoirs and wells.
As a result, many zones are tested that either produce no gas, or are noneconomic. We have to develop a methodology of formation evaluation that would allow noneconomic and sub economic wells to be identified prior to expensive and unnecessary completions.
Electrical parameter (m and n)
In tight gas, there is a strong relationship between relative permeability and water saturation and therefore water-saturation cutoffs are often used to infer producible pay intervals.
Decreases in either m or n tend to lower the perceived water saturation, increasing computations of pay, gas volumes, and relative permeability
m can vary with porosity(fig)
Water saturation from core and formation water resistivity
Finding true reservoir water salinity in tight gas sands is particularly difficult, because of the small amount of water associated with small pore volumes in typical core plugs.
Problems encountered when dealing with small pore volumes of water from core plugs.
The samples with the smallest extracted water volumes show the highest salinity
Error in water volume- 0.1 c.c, because of minor water losses in the laboratory are likely to increase perceived salinity values, which in turn will lead to reductions in perceptions of water saturation
Conclusion
Traditional approaches must be calibrated over core.
Care must be taken in the collection and calibration of data and/or analogs for the reservoir in question.
Numerous issues surround laboratory methods and attempts to reproduce in-situ conditions.
Due to generally low porosities, porosity estimates from wireline logs are sensitive to small changes in grain density
Large stress-dependence of permeability; therefore measurements need to be taken at reservoir stress conditions.
Basin history, both pre- and post-hydrocarbon charge, is critical and must be incorporated in to any interpretation.