Tight reservoir means that reservoir of low porosity and low permeability. Many tight formations are extremely complex, producing from multiple layers with different permeability that is often enhanced by natural fracturing. The complicity of these reservoirs is attributed to a) Low porosity and low permeability reservoir b) The presence of clay minerals like illite, kaolin and micas in pores, c) The heterogeneity of the reservoir in vertical and lateral directions. Evaluation of tight gas sand reservoirs represents difficult problems. Determination of petrophysical properties using only conventional logs very complicated. Using of NMR in individual bases or in combination with conventional openhole logs and SCAL data leads to better determination of petrophysical properties of heterogeneous tight gas sand reservoirs.
Nuclear magnetic resonance (NMR) logs differ from conventional neutron and density porosity logs, NMR signal amplitude provides detailed porosity free from lithology effects and radioactive sources and relaxation times give other petrophysical parameters such as permeability, capillary pressure, the distribution of pore sizes and hydrocarbon identification
This paper concentrates on determination of three petrophysical parameters of tight gas sand reservoirs: 1) Determination of detailed NMR porosity in combination with density porosity, ϕDMR 2) NMR permeability, KBGMR, it is based on the dynamic concept of gas movement and bulk gas volume in the invaded zone and 3) Capillary pressure derived from relaxation time T2 distribution and then it could be used for formation saturation measurements especially in the transition zone.