COMPARATIVE ANALYSIS OF RESERVES DETERMINATION TECHNIQUES IN OVERPRESSURED GAS RESERVOIRS
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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
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)].
COMPARATIVE ANALYSIS OF RESERVES DETERMINATION TECHNIQUES IN OVERPRESSURED GAS RESERVOIRS
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