ABSTRACT
Conventional methods used in determining initial gas-in-place and reserves for a dry gas reservoir entails the use of P/z vs cumulative production data. In a normally pressured gas reservoir, the only important production mechanism is the compressibility of the gas. Many reservoir engineering calculations take advantage of this fact to simplify analysis. However, in deep geopressured gas reservoirs, the compressibility of the gas is much smaller and does not totally dominate production performance. Using simplified approaches may lead to serious errors in these cases. In geopressured systems, the compressibility of the rock and water may be just as large as the gas. Excluding these sources of energy from performance calculations would result in very pessimistic predictions of production versus pressure. Some investigators have postulated that water will be released from shales as the reservoir compacts during depletion. This would result in an internal water drive similar to aquifer influx. Because the reservoir rock is usually highly compressible and under-compacted, the decrease in pore volume during depletion may be very non-linear. Along with the rock compressibility, the absolute permeability may also decrease with declining pressure.
Several material balance models have been proposed to calculate the initial gas-in-place for abnormally-pressured gas reservoir. The present study is concerned with analyzing the different material balance models used to estimate IGIP for abnormally pressured reservoirs, review the bases and assumptions on which these models have been developed, as well as discuss the strength and weakness of every model. In addition, the study comprises comparative analysis of calculations of the IGIP by these material balance models for some reservoir case studies in the Gulf Coast. A sensitivity analysis is also done on some of the input parameters in these material balance models to determine their effect on estimating the original gas-in-place. Moreover, the present investigation reveals that most of the material balance models analyzed in this study are sensitive to the value of the initial reservoir pressure and the early data. Unfortunately, this is the time when reliable estimate for the IGIP is vital for economic decision regarding the development of such gas reservoirs. However, accurate estimation of the IGIP plays an important role in the evaluation, analysis, prediction of future performance, and making economic decision regarding the development of gas reservoirs.
CHAPTER 1 – Introduction
Gas reservoirs with abnormally-high pressures have been encountered all over the world. For these reservoirs, a straight line plot of P/z versus Gp for the early production data and extrapolation to zero reservoir pressure projects incorrect initial gas-in-place (IGIP). The P/z plot is based on the assumption that gas compressibility is the “sole” reservoir driving mechanism. In overpressured gas reservoirs however, grain expansion, formation water expansion and water influx from shale or small associated aquifer, in addition to gas expansion contribute significantly to gas production. In normally pressured reservoirs, the pore volume change with pressure is considered minimal, and thus the pore volume (formation) compressibility retains a very small constant value. However, in an overpressured gas reservoir, the natural compaction is incomplete, as a large portion of the overburden remains supported by high internal pore pressure. As this pressure is released, through fluid production, the pore space may reduce significantly. Thus, under overpressured conditions, cf is relatively large and may have significant variation with pressure. This becomes important to the material-balance equation, as the pore compressibility is a significant energy term in overpressured reservoirs. In normally pressured gas reservoirs, the energy of the formation is usually negligible compared to the energy of the gas.
Overpressures are subsurface fluid pressures that are greater than the pressures expected under normal hydrostatic conditions. Overpressured reservoirs are abundant in sedimentary basins throughout the world. In the United States, abnormally-pressured gas reservoirs are concentrated in the Gulf Coast, Anardako Basin, Delaware Basin and Rocky Mountain Area. In the Middle East, overpressured gas reservoirs are found in Iraq, Iran and Saudi Arabia. These reservoirs commonly produce light oils and gases and require special evaluation techniques. Prior knowledge of the possibility of encountering overpressures at particular subsurface depths is important when exploring for oil and gas. This is because the presence of higher-than-normal pressure increases the complexity and cost of drilling, well-completions and production operations. Additionally, the effect of overpressures on reservoir behavior must be recognized when predicting performance.
Initial reservoir pressure gradients are normally 0.465 psi/ft of depth, which is the hydrostatic gradient of typical brine. In many producing areas, particularly along the Gulf Coast, reservoirs exist with pressure gradients far in excess of this normal. Gradients of almost 1.0 psi/ft of depth have been observed. Any gradient in excess of 0.465 is abnormal, but the effects of abnormal pressure on reservoir engineering calculations are often ignored unless a gradient of 0.65 psi/ft or more exists. A significant amount of gas exists in abnormally-pressured reservoirs. In the offshore Gulf Coast alone, over 300 gas reservoirs have been discovered with initial gradients in excess of 0.65 psi/ft at depths greater than 10,000 ft [Bernard (1985)].
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