The Natural gas compressibility factor is an important reservoir fluid property used in reservoir engineering computations either directly or indirectly in material balance calculations, well test analysis, gas reserve estimates, gas flow in lines and in numerical reservoir simulations. Existing gas compressibility factor correlations were derived using measured data at low to moderate pressures(less than 8, 000 psia) and temperatures (less than 212oF), and an extrapolation to High Pressure High temperature (HPHT) is doubtful. The need to understand and predict gas compressibility factor at HPHT has become increasingly important as exploration and production has moved to ever deeper formations where HPHT conditions are to be encountered. This paper presents laboratory measurement of gas compressibility factors at HPHT natural gas systems and the evaluation of some selected gas compressibility factors correlations. Samples of gas mixtures were collected from the high pressure gas reservoirs from the Niger Delta region of Nigeria. Vinci PVT Cell was used to measure the gas compressibility factors for a pressures ranging from 6,000 to 14,000 psia and temperatures at 270oF and 370oF. The new laboratory data was compared to some of the gas compressibility factor correlations/ models used in the petroleum industry. Results showed that majority of the correlations studied overestimated the gas compressibility factor at HPHT. Mean relative and absolute error analysis were done based on the temperature difference; it was found that the total mean relative and absolute errors for the 370o F cases are higher than those for 270oF. Among all the correlations assessed, Hall and Yarborough equation performed better than other existing correlations with a mean absolute error of 3.545 and relative error of -2.668 at 270oF. At 370oF, Beggs and Brills correlation predicted better than other correlations studied with a mean relative error of -4.77 and absolute error of 7.187
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