Reserves estimation of geopressured oil and gas

The term “geopressure,” introduced in the late 1950s by Charles Stuart of Shell Oil Co., refers to reservoir fluid pressure that significantly exceeds hydrostatic pressure (which is 0.4 to 0.5 psi/ft of depth), possibly approaching overburden pressure (approximately 1.0 psi/ft). Geopressured accumulations have been observed in many areas of the world.

Geologic setting

In regressive tertiary basins (the geologic setting for most geopressured accumulations), such pressures in sand/shale sequences generally are attributed to undercompaction of thick sequences of marine shales. Reservoirs in this depositional sequence tend to be geologically complex and exhibit producing mechanisms that are not well understood. Both of these factors cause considerable uncertainty in reserves estimates at all stages of development/production and reservoir maturity. Geologic complexity contributes to uncertainty in estimates of oil-/gas-in-place (O/GIP) that are based on volumetric mapping. Poorly understood producing mechanisms contribute to uncertainty in estimates of reserves that are based on pressure/production performance. Each aspect is discussed below.

Geopressured reservoirs frequently are associated with substantial faulting and complex stratigraphy, which can make correlation, structural interpretation, and volumetric mapping subject to considerable uncertainty.

The resistivity of interstitial water in geopressured sections may approach that of fresh water, which may suppress the SP log. Under these conditions, it might be difficult to estimate net pay unless a gamma ray log also has been run. In addition, the relatively fresh waters frequently encountered in geopressured sections complicate interpretation of resistivity logs, especially in shaly sands. Cases have been reported in which reserves were booked on the basis of high resistivity observed in porous sands that later investigation proved bore fresh water.

Drive mechanism(s)

If gas production is attributed to gas expansion only, a plot of p/z vs. Gp should be a straight line. Because geologists considered them to be closed accumulations, during the early years of exploitation it was assumed that geopressured gas reservoirs would produce by pressure depletion and exhibit linear plots of p/z vs. G_p. Although this was observed to be true in many cases, it is not universally true. The p/z vs. G_p plots for many geopressured reservoirs initially appear to be linear, but curve downward as reservoir pressure approaches hydrostatic pressure. Extrapolation of the initial part of such a plot might yield an estimate of GIP that is approximately twice that estimated using volumetric methods. The anomalously low initial slope of the p/z vs. G_p plot has been attributed to several phenomena, including:

• PV compression
• expansion of interstitial water
• partial waterdrive

The downward curvature of the p/z vs. G_p plot has been attributed to other factors, including:

• depletion of a limited protoshale water aquifer
• rock collapse

The American Geological Inst. (AGI) defines shale as an “indurated (hardened)...sedimentary rock formed by the consolidation...of clay.” Because geopressures in tertiary basins generally are attributed to undercompaction, the term protoshale is adopted here to make that distinction.

Producing mechanisms in a geopressured gas reservoir might include:

• gas expansion
• compressibility of the reservoir pore volume (PV)
• expansion of the interstitial water
• water influx because of water expansion from a contiguous aquifer
• water influx because of dewatering of interbedded protoshale

and/or

• evolution of natural gas dissolved in interstitial and aquifer water

Any or all of these mechanisms may be active at various stages in the life of a geopressured gas reservoir. Pressure/production data typically are insufficiently diagnostic to distinguish one mechanism from another, so that there may be considerable uncertainty in analysis of historical data and estimation of reserves.

There is disagreement regarding the relative importance of these mechanisms, especially compressibility of reservoir PV and water influx from interbedded protoshale. Because it is difficult to analyze geopressure mechanisms separately for a specific reservoir, many engineers use Eq. 1 to make an aggregate adjustment to the p/z vs. G_p plot:

.............................(1)

Eq. 1 differs from Eq. 2 by inclusion of a p/z adjustment factor, which is the left-side square-bracketed term. Eq. 1 sometimes is simplified by adjusting the apparent gas in place (AGIP)—that estimated by extrapolation of the initial part of the p/z vs. G_p plot—by multiplying the AGIP by the gas-compressibility/effective-compressibility ratio.

.............................(2)

Both methods assume that PV compressibility remains constant over the life of the reservoir being evaluated, which is contrary to the findings of numerous investigators. In addition, neither accounts for possible water encroachment.

Regardless of the method used to adjust the p/z vs. G_p plot, always check a reserves estimate so derived against analogies and/or a volumetric estimate for the same well.

Analytical methods

Analytical methods outlined in the literature typically require more information than usually is available. As an alternative, a method was proposed that parallels that of Havlena and Odeh.

.............................(3)

Under this method, Eq. 3 can be written for a gas reservoir as

.....................(4)

Define

.............................(5)

and

.............................(6)

Substituting Eqs. 5 and 6 into Eq. 4 leads to

.............................(7)

Divide by the gas-expansion and rock/fluid-compression term in brackets:

.............................(8)

If the water-influx term and the rock/fluid expansion/compression terms are estimated correctly, a plot of the left-side term vs. the fractional part of the second right-side term of Eq. 8 will be a straight line. The y intercept should be equal to G_Fi. The slope of the line should equal C, the water-influx constant. Note that c_p is a function of pressure and is c_p(p) integrated over a change in net overburden pressure that corresponds to the value p_i-p.

The water-influx term probably will be the most difficult term to evaluate because water influx in a given reservoir could be attributable to expansion from a contiguous aquifer and/or to dewatering of interbedded protoshale. Favorable conditions for protoshale water influx include considerable interbedding of protoshale with:

• The gas-bearing sand
• A small contiguous aquifer
• A high initial fluid-pressure gradient

Opposite conditions would favor aquifer influx. Depending on the size and shape of the contiguous aquifer, We might be calculable using a limited linear aquifer model or a limited cylindrical aquifer model. If protoshale dewatering is suspected, a limited linear aquifer model might be more appropriate.

Geopressured gas reservoirs might exhibit retrograde behavior, a phenomenon discussed in the Condensate section of this chapter. Oil reservoirs are encountered less frequently than gas reservoirs in the geopressured section and rarely are discussed in the literature. Comments similar to those for geopressured gas reservoirs are appropriate regarding drive mechanism in geopressured oil reservoirs. Depending on circumstances, an approach analogous to that presented in Eqs. 4 through 8 might be appropriate for geopressured oil reservoirs.

PV compressibility

On the basis of numerous studies of the influence of reservoir pressure on PV compressibility, it seems apparent that PV compressibility of porous rocks depends on the stress conditions in the reservoir, decreases as stress increases, decreases as rocks become more consolidated, and might increase as temperature increases.

There appears to be no correlation between compressibility and rock properties that is generally valid across a broad spectrum of lithologies and pressures. Hall’s correlation between compressibility and porosity—still widely cited—covers only a narrow range of stress conditions and apparently reflects only data from well-consolidated rocks.

Reportedly, some geopressured sands have compressibilities approaching those usually associated with consolidated rock; however, these data apparently were measured on rock samples taken from geopressured aquifers, rather than from hydrocarbon reservoirs. In the high temperatures usually associated with geopressured environments, sandstones undergo rapid diagenesis that can cause a geologically young rock to become tightly cemented. This is more likely to occur in aquifers (where the interstitial water is mobile) than in hydrocarbon reservoirs (where the interstitial water is immobile). Expect these tightly cemented sandstones to be less compressible than relatively uncemented sands; accordingly, measure compressibility on samples taken from the hydrocarbon-bearing zone, not from the aquifer. Take great care when using compressibility data from rocks that appear similar to the zone of interest or that have comparable porosity and permeability.

In the absence of laboratory data, the following correlation can be used to estimate PV compressibility:

.............................(9)

where A, B, C, D, K₁, K₂, and K₃ depend on rock properties, as shown in Table 1.

• 

  Table 1

During pressure reduction of reservoir fluids, the resultant stresses on reservoir rocks differ from those on core samples during hydrostatic testing in the laboratory. In the subsurface, when production reduces reservoir fluid pressure, the weight of the overburden compacts the reservoir rock, which uniaxially reduces the bulk volume of the rock and, consequently, reduces PV. This process can be replicated in the laboratory, but such tests require special equipment that is not used by most commercial laboratories. Most laboratory compressibility data are measured using hydrostatic stress, which can be related to reservoir stress by

.............................(10)

Nomenclature

A	=	constant
B	=	constant
Bg	=	formation volume factor, gas, Rcf/scf
Bgi	=	initial formation volume factor, gas, Rcf/scf or RB/scf
Bt	=	formation volume factor, total, RB/STB
Bti		initial total formation volume factor, RB/STB
Bw	=	formation volume factor, water, RB/STB
cp	=	compressibility, pore volume, vol/vol/psi
cw	=	compressibility, water, vol/vol/psi
C	=	constant
D	=	curve-fit coefficient
Ec	=	water, vol/vol/psi
Eg	=	expansion of the initial gas cap, if one is present, RB/scf
Eo	=	expansion of a unit volume of oil and dissolved (solution) gas initially in place, RB/STB
FpR	=	volume of cumulative oil, gas, and water production, RB
GFi	=	free gas initially in place, scf or m3
Gp	=	cumulative gas production, scf
K1	=	constant
K2	=	constant
K3	=	constant
m	=	ratio of initial gas cap volume to initial oil column volume, dimensionless
Ni	=	oil initially in place, STB or m3
Np	=	cumulative oil production, STB
p	=	pressure, static reservoir, general, psia
pi	=	initial reservoir pressure, psia
pn	=	laboratory net (hydrostatic) pressure (confining pressure minus pore pressure), psia
pob	=	overburden pressure, psia
Rp	=	cumulative (producing) gas/oil ratio, scf/STB
Sw	=	water saturation, fraction
Wp	=	cumulative water production, STB
z	=	gas compressibility factor, general, dimensionless
zi	=	gas compressibility factor at initial conditions, dimensionless
Δp	=	pressure, incremental, psi

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See also

PEH:Estimation_of_Primary_Reserves_of_Crude_Oil,_Natural_Gas,_and_Condensate