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Reserves estimation of geopressured oil and gas

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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. Gp. Although this was observed to be true in many cases, it is not universally true. The p/z vs. Gp 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. Gp plot has been attributed to several phenomena, including:

  • PV compression
  • expansion of interstitial water
  • partial waterdrive

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

  • depletion of a limited protoshale water aquifer[1]
  • rock collapse[2]

The American Geological Inst. (AGI) defines shale as an “indurated (hardened)...sedimentary rock formed by the consolidation...of clay.”[3] 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


  • 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[4] and water influx from interbedded protoshale.[5][6][7] 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. Gp plot[8]:


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. Gp plot—by multiplying the AGIP by the gas-compressibility/effective-compressibility ratio.


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. Gp 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[9] that parallels that of Havlena and Odeh.[10]


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






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


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


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 GFi. The slope of the line should equal C, the water-influx constant. Note that cp is a function of pressure and is cp(p) integrated over a change in net overburden pressure that corresponds to the value pi-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,[11][12][13][14][15][16][17][18][19][20] 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[21] 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[22]; 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[23]:


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



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


  1. Duggan, J.O. 1972. The Anderson "L" -An Abnormally Pressured Gas Reservoir in South Texas. J Pet Technol 24 (2): 132-138. SPE-2938-PA.
  2. Harville, D.W. and Hawkins Jr., M.F. 1969. Rock Compressibility and Failure as Reservoir Mechanisms in Geopressured Gas Reservoirs. J Pet Technol 21 (12): 1528-1530.
  3. Gary, M., McAfee, R. Jr., and Wolf, C. eds. 1972. Glossary of Geology. Washington, DC: American Geological Inst.
  4. Bernard, W.J. 1987. Reserves estimation and performance prediction for geopressured gas reservoirs. J. Pet. Sci. Eng. 1 (1): 15-21.
  5. Wallace, W.E. 1969. Water Production from Abnormally Pressured Gas Reservoirs in South Louisiana. J Pet Technol 21 (8): 969-982.
  6. Bourgoyne Jr, A.T. 1990. Shale water as a pressure support mechanism in gas reservoirs having abnormal formation pressure. J. Pet. Sci. Eng. 3 (4): 305-319.
  7. Chierici, G.L., Ciucci, G.M., Sclocchi, G. et al. 1978. Water Drive From Interbedded Shale Compaction In Superpressured Gas Reservoirs A Model Study. J Pet Technol 30 (6): 937-946. SPE-6503-PA.
  8. Ramagost, B.P. and Farshad, F.F. 1981. P/Z Abnormally Pressured Gas Reservoirs. Presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 4–7 October. SPE-10125-MS.
  9. Cronquist, C. 2001. Estimation and Classification of Reserves of Crude Oil, Natural Gas, and Condensate. Richardson, Texas: SPE.
  10. Havlena, D. and Odeh, A.S. 1963. The Material Balance as an Equation of a Straight Line. J Pet Technol 15 (8): 896–900. SPE-559-PA.
  11. Geertsma, J. 1957. The Effect of Fluid Pressure Decline on Volumetric Changes of Porous Rocks. In Transactions of the American Institute of Mining, Metallurgical, and Petroleum Engineers, Vol. 210, 331–340. Dallas, Texas: Society of Petroleum Engineers.
  12. Fatt, I. 1958. Pore Volume Compressibilities of Sandstone Reservoir Rocks. J Pet Technol 10 (3): 64–66. SPE-970-G.
  13. van der Knaap, W. 1959. Nonlinear Behavior of Elastic Porous Media. In Transactions of the American Institute of Mining, Metallurgical, and Petroleum Engineers, 216, 179-187. Dallas, Texas: Society of Petroleum Engineers of AIME.
  14. Dobrynin, V.M. 1962. Effect of Overburden Pressure on Some Properties Of Sandstones. SPE J. 2 (4): 360-366.
  15. Chierici, G.L. and Ciucci, G.M. 1967. Water Drive Gas Reservoirs: Uncertainty in Reserves Evaluation From Past History. J Pet Technol 19 (2): 237-244.
  16. Von Goten, W.D. and Choudhary, B.K. 1969. The Effect of Pressure and Temperature on Pore Volume Compressibility. Presented at the Fall meeting of the Society of Petroleum Engineers of AIME, Denver, Colorado, 28 September-1 October.
  17. Teeuw, D. 1971. Prediction of Formation Compaction from Laboratory Compressibility Data. SPE Journal 11 (3): 263-271. SPE-2973-PA.
  18. Newman, G.H. 1973. Pore-Volume Compressibility of Consolidated, Friable, and Unconsolidated Reservoir Rocks Under Hydrostatic Loading. J Pet Technol 25 (2): 129-134. SPE-3835-PA.
  19. Jones, S.C. 1988. Two-Point Determinations of Permeability and PV vs. Net Confining Stress. SPE Form Eval 3 (1): 235-241. SPE-15380-PA.
  20. Yale, D.P., Nabor, G.W., Russell, J.A. et al. 1993. Application of Variable Formation Compressibility for Improved Reservoir Analysis. Presented at the SPE Annual Technical Conference and Exhibition, Houston, Texas, 3-6 October 1993. SPE-26647-MS.
  21. Hall, H.N. 1953. Compressibility of Reservoir Rocks. J Pet Technol 5 (1): 17-19.
  22. Bernard, W.J. 1987. Reserves estimation and performance prediction for geopressured gas reservoirs. J. Pet. Sci. Eng. 1 (1): 15-21.
  23. Yale, D.P., Nabor, G.W., Russell, J.A. et al. 1993. Application of Variable Formation Compressibility for Improved Reservoir Analysis. Presented at the SPE Annual Technical Conference and Exhibition, Houston, Texas, 3-6 October 1993. SPE-26647-MS.

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