I suggest the following procedure, based on my long experience with naturally fractured carbonates.

- establish matrix properties (if the irreducible water saturation is not too high, you can have movable gas in the largest pores of the matrix; also, vuggy porosity is sometimes  distributed in the matrix, and can be important even if the number is small, because of the typical low irreducible water saturation in large vugs, and the recovery can be high if the vugs are connected to the natural fracture network; the Net/Gross Ratio can be an important factor).

- establish the properties of the natural fracture network (you can use FMI log and core calibration of the FMI, plus a Discrete Fracture Network simulation built from the FMI results; all the rock is more or less fractured, so that the Net/Gross ratio for  fractures is 1; irreducible water saturation in the natural fracture network is going to be very small to insignificant; fracture porosity is usually very low say 0.5% to 1% as a reservoir-wide average , but the single "pores" are tens of meter long; storativity in the fracture system is very important and the fractures are extremely permeable, say tens to hundreds of Darcies, i.e. 10,000 to 100,000 mD and more; look out for leaching, because leaching enlarges fractures and results in considerable fracture porosity (0.7% to 1.1% and enhances greately the fracture permeability);

- consider that the gas recovery factor of matrix is going to be less than the gas recovery factor of the natural fracture network (both can be rather high, say 70% from the matrix and 80-90% from the fractures);

- total recoverable gas reserves are going to be the sum of matrix gas plus fracture gas.

I can help if you need.

Roberto

Thank you Roberto sir for your answer, you answer has shown a path to go.

My problem is slightly different, matrix porosity in my case is very low(nil to 7%). Actually the host rock is of Proterozoic, it is hard and compact almost like metamorphic rock. Would this type of rock will have storage capacity in matrix porosity? 

If you say that the matrix porosity is as high as 7%, you may have beds where matrix porosity is 7%, 6% and 5%. If those beds are sucrosic dolomite, the pore size in sucrosic dolomite usually is big enough to be effective for gas production.

I mention sucrosic dolomite because such lithotype is not rare in thick carbonate units, and the secondary dolomitization of limestone (the process that forms sucrosic dolomite) generates typically 5% - 6% porosity rock. The calcite lattice, when comes in contact (under the appropriate physical-chemical conditions) with Magnesium ions, takes them in and it is transformed into dolomite lattice which is 5% denser, and this creates the typical porosity of sucrosic dolomite.

The appropriate procedure would be to try and calibrate the log porosity against core porosity, to validate the log measures. Then, try and use available core material to measure the capillary pressure of the best matrix porosity, and see what irreducible water saturation (Swi) the 7%, 6% and 5% porosity matrix beds have.

Swi values above 65% or 70% indicate that those beds are very tight and are unlikely to horst (and produce) significant gas.

Small Swi values would point to the possibility of producing gas from matrix beds of sufficient porosity.

Never say never! Apparently tight matrix (when judged with sandstone criteria) may contain and may be able to produce gas, even if in your case the majority of the produced gas is likely to come from the natural fracture system.

Roberto