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Reserves estimation of geopressured oil and gas: Difference between revisions
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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. | 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== | == 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. | |||
The resistivity of interstitial water in geopressured sections may approach that of fresh water, which may suppress the [[ | 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 [[Spontaneous_(SP)_log|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<sub>p</sub>. Although this was observed to be true in many cases, it is not universally true. The p/z vs. G<sub>p</sub> 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<sub>p</sub> plot has been attributed to several phenomena, including: | 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<sub>p</sub>. Although this was observed to be true in many cases, it is not universally true. The p/z vs. G<sub>p</sub> 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<sub>p</sub> plot has been attributed to several phenomena, including: | ||
*PV compression | *PV compression | ||
*expansion of interstitial water | *expansion of interstitial water | ||
Line 15: | Line 18: | ||
The downward curvature of the p/z vs. G<sub>p</sub> plot has been attributed to other factors, including: | The downward curvature of the p/z vs. G<sub>p</sub> plot has been attributed to other factors, including: | ||
The American Geological Inst. (AGI) defines shale as an “indurated (hardened)...sedimentary rock formed by the consolidation...of clay.”<ref name="r3" /> Because geopressures in tertiary basins generally are attributed to undercompaction, the term protoshale is adopted here to make that distinction. | *depletion of a limited protoshale water aquifer<ref name="r1">_</ref> | ||
*rock collapse<ref name="r2">_</ref> | |||
The American Geological Inst. (AGI) defines shale as an “indurated (hardened)...sedimentary rock formed by the consolidation...of clay.”<ref name="r3">_</ref> 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: | Producing mechanisms in a geopressured gas reservoir might include: | ||
*gas expansion | *gas expansion | ||
*compressibility of the reservoir pore volume (PV) | *compressibility of the reservoir pore volume (PV) | ||
*expansion of the interstitial water | *expansion of the interstitial water | ||
*water influx because of water expansion from a contiguous aquifer | *water influx because of water expansion from a contiguous aquifer | ||
*water influx because of dewatering of interbedded protoshale | *water influx because of dewatering of interbedded protoshale | ||
and/or | |||
and/or | |||
*evolution of natural gas dissolved in interstitial and aquifer water | *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. | 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<ref name="r4" /> and water influx from interbedded protoshale.<ref name="r5" /><ref name="r6" /><ref name="r7" /> Because it is difficult to analyze geopressure mechanisms separately for a specific reservoir, many engineers use '''Eq. 1''' to make an [[Glossary:Aggregate|aggregate]] adjustment to the p/z vs. G<sub>p</sub> plot<ref name="r8" />: | There is disagreement regarding the relative importance of these mechanisms, especially compressibility of reservoir PV<ref name="r4">_</ref> and water influx from interbedded protoshale.<ref name="r5">_</ref><ref name="r6">_</ref><ref name="r7">_</ref> Because it is difficult to analyze geopressure mechanisms separately for a specific reservoir, many engineers use '''Eq. 1''' to make an [[Glossary:Aggregate|aggregate]] adjustment to the p/z vs. G<sub>p</sub> plot<ref name="r8">_</ref>: | ||
[[File:Vol5 page 1549 eq 001.png]].............................(1) | [[File:Vol5 page 1549 eq 001.png|RTENOTITLE]].............................(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<sub>p</sub> plot—by multiplying the AGIP by the gas-compressibility/effective-compressibility ratio. | '''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<sub>p</sub> plot—by multiplying the AGIP by the gas-compressibility/effective-compressibility ratio. | ||
[[File:Vol5 page 1521 eq 005.png]].............................(2) | [[File:Vol5 page 1521 eq 005.png|RTENOTITLE]].............................(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. | 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<sub>p</sub> plot, always check a reserves estimate so derived against analogies and/or a volumetric estimate for the same well. | Regardless of the method used to adjust the p/z vs. G<sub>p</sub> plot, always check a reserves estimate so derived against analogies and/or a volumetric estimate for the same well. | ||
==Analytical methods== | == Analytical methods == | ||
Analytical methods outlined in the literature typically require more information than usually is available. As an alternative, a method was proposed<ref name="r9" /> that parallels that of Havlena and Odeh.<ref name="r10" /> | |||
Analytical methods outlined in the literature typically require more information than usually is available. As an alternative, a method was proposed<ref name="r9">_</ref> that parallels that of Havlena and Odeh.<ref name="r10">_</ref> | |||
[[File:Vol5 page 1520 eq 001.png]].............................(3) | [[File:Vol5 page 1520 eq 001.png|RTENOTITLE]].............................(3) | ||
Under this method, '''Eq. 3''' can be written for a gas reservoir as | Under this method, '''Eq. 3''' can be written for a gas reservoir as | ||
[[File:Vol5 page 1549 eq 002.png]].....................(4) | [[File:Vol5 page 1549 eq 002.png|RTENOTITLE]].....................(4) | ||
Define | Define | ||
[[File:Vol5 page 1549 eq 003.png]].............................(5) | [[File:Vol5 page 1549 eq 003.png|RTENOTITLE]].............................(5) | ||
and | and | ||
[[File:Vol5 page 1549 eq 004.png]].............................(6) | [[File:Vol5 page 1549 eq 004.png|RTENOTITLE]].............................(6) | ||
Substituting '''Eqs. 5''' and '''6''' into '''Eq. 4''' leads to | Substituting '''Eqs. 5''' and '''6''' into '''Eq. 4''' leads to | ||
[[File:Vol5 page 1549 eq 005.png]].............................(7) | [[File:Vol5 page 1549 eq 005.png|RTENOTITLE]].............................(7) | ||
Divide by the gas-expansion and rock/fluid-compression term in brackets: | Divide by the gas-expansion and rock/fluid-compression term in brackets: | ||
[[File:Vol5 page 1549 eq 006.png]].............................(8) | [[File:Vol5 page 1549 eq 006.png|RTENOTITLE]].............................(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<sub>Fi</sub>. The slope of the line should equal C, the water-influx constant. Note that c<sub>p</sub> is a function of pressure and is c<sub>p</sub>(p) integrated over a change in net overburden pressure that corresponds to the value p<sub>i</sub>-p. | 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<sub>Fi</sub>. The slope of the line should equal C, the water-influx constant. Note that c<sub>p</sub> is a function of pressure and is c<sub>p</sub>(p) integrated over a change in net overburden pressure that corresponds to the value p<sub>i</sub>-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 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 | *The gas-bearing sand | ||
*A small contiguous aquifer | *A small contiguous aquifer | ||
*A high initial fluid-pressure gradient | *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. | 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. | 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== | == PV compressibility == | ||
On the basis of numerous studies of the influence of reservoir pressure on PV compressibility,<ref name="r11" /><ref name="r12" /><ref name="r13" /><ref name="r14" /><ref name="r15" /><ref name="r16" /><ref name="r17" /><ref name="r18" /><ref name="r19" /><ref name="r20" /> 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. | |||
On the basis of numerous studies of the influence of reservoir pressure on PV compressibility,<ref name="r11">_</ref><ref name="r12">_</ref><ref name="r13">_</ref><ref name="r14">_</ref><ref name="r15">_</ref><ref name="r16">_</ref><ref name="r17">_</ref><ref name="r18">_</ref><ref name="r19">_</ref><ref name="r20">_</ref> 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<ref name="r21" /> 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. | 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<ref name="r21">_</ref> 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<ref name="r22" />; 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. | Reportedly, some geopressured sands have compressibilities approaching those usually associated with consolidated rock<ref name="r22">_</ref>; 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<ref name="r23" />: | In the absence of laboratory data, the following correlation can be used to estimate PV compressibility<ref name="r23">_</ref>: | ||
[[File:Vol5 page 1550 eq 001.png]].............................(9) | [[File:Vol5 page 1550 eq 001.png|RTENOTITLE]].............................(9) | ||
where A, B, C, D, K<sub>1</sub>, K<sub>2</sub>, and K<sub>3</sub> depend on rock properties, as shown in '''Table 1'''. | where A, B, C, D, K<sub>1</sub>, K<sub>2</sub>, and K<sub>3</sub> depend on rock properties, as shown in '''Table 1'''. | ||
<gallery widths=300px heights=200px> | <gallery widths="300px" heights="200px"> | ||
File:Vol5 Page 1551 Image 0001.png|'''Table 1''' | File:Vol5 Page 1551 Image 0001.png|'''Table 1''' | ||
</gallery> | </gallery> | ||
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 | 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 | ||
[[File:Vol5 page 1551 eq 001.png]].............................(10) | [[File:Vol5 page 1551 eq 001.png|RTENOTITLE]].............................(10) | ||
== Nomenclature == | == Nomenclature == | ||
{| | {| | ||
|- | |- | ||
|''B'' | | ''A'' | ||
|= | | = | ||
|constant | | constant | ||
|- | |||
| ''B'' | |||
| = | |||
| constant | |||
|- | |- | ||
|''B''<sub>''g''</sub> | | ''B''<sub>''g''</sub> | ||
|= | | = | ||
|formation volume factor, gas, Rcf/scf | | formation volume factor, gas, Rcf/scf | ||
|- | |- | ||
|''B''<sub>''gi''</sub> | | ''B''<sub>''gi''</sub> | ||
|= | | = | ||
|initial formation volume factor, gas, Rcf/scf or RB/scf | | initial formation volume factor, gas, Rcf/scf or RB/scf | ||
|- | |- | ||
|''B''<sub>''t''</sub> | | ''B''<sub>''t''</sub> | ||
|= | | = | ||
|formation volume factor, total, RB/STB | | formation volume factor, total, RB/STB | ||
|- | |- | ||
|''B''<sub>''ti''</sub> | | ''B''<sub>''ti''</sub> | ||
| | | | ||
|initial total formation volume factor, RB/STB | | initial total formation volume factor, RB/STB | ||
|- | |- | ||
|''B''<sub>''w''</sub> | | ''B''<sub>''w''</sub> | ||
|= | | = | ||
|formation volume factor, water, RB/STB | | formation volume factor, water, RB/STB | ||
|- | |- | ||
|''c''<sub>''p''</sub> | | ''c''<sub>''p''</sub> | ||
|= | | = | ||
|compressibility, pore volume, vol/vol/psi | | compressibility, pore volume, vol/vol/psi | ||
|- | |- | ||
|''c''<sub>''w''</sub> | | ''c''<sub>''w''</sub> | ||
|= | | = | ||
|compressibility, water, vol/vol/psi | | compressibility, water, vol/vol/psi | ||
|- | |- | ||
|''C'' | | ''C'' | ||
|= | | = | ||
|constant | | constant | ||
|- | |- | ||
|''D'' | | ''D'' | ||
|= | | = | ||
|curve-fit coefficient | | curve-fit coefficient | ||
|- | |- | ||
|''E''<sub>''c''</sub> | | ''E''<sub>''c''</sub> | ||
|= | | = | ||
| water, vol/vol/psi | |||
|- | |- | ||
|''E''<sub>''g''</sub> | | ''E''<sub>''g''</sub> | ||
|= | | = | ||
|expansion of the initial gas cap, if one is present, RB/scf | | expansion of the initial gas cap, if one is present, RB/scf | ||
|- | |- | ||
|''E''<sub>''o''</sub> | | ''E''<sub>''o''</sub> | ||
|= | | = | ||
|expansion of a unit volume of oil and dissolved (solution) gas initially in place, RB/STB | | expansion of a unit volume of oil and dissolved (solution) gas initially in place, RB/STB | ||
|- | |- | ||
|''F''<sub>''pR''</sub> | | ''F''<sub>''pR''</sub> | ||
|= | | = | ||
|volume of cumulative oil, gas, and water production, RB | | volume of cumulative oil, gas, and water production, RB | ||
|- | |- | ||
|''G''<sub>''Fi''</sub> | | ''G''<sub>''Fi''</sub> | ||
|= | | = | ||
|free gas initially in place, scf or m<sup>3</sup> | | free gas initially in place, scf or m<sup>3</sup> | ||
|- | |- | ||
|''G''<sub>''p''</sub> | | ''G''<sub>''p''</sub> | ||
|= | | = | ||
|cumulative gas production, scf | | cumulative gas production, scf | ||
|- | |- | ||
|''K''<sub>1</sub> | | ''K''<sub>1</sub> | ||
|= | | = | ||
|constant | | constant | ||
|- | |- | ||
|''K''<sub>2</sub> | | ''K''<sub>2</sub> | ||
|= | | = | ||
|constant | | constant | ||
|- | |- | ||
|''K''<sub>3</sub> | | ''K''<sub>3</sub> | ||
|= | | = | ||
|constant | | constant | ||
|- | |- | ||
|''m'' | | ''m'' | ||
|= | | = | ||
|ratio of initial gas cap volume to initial oil column volume, dimensionless | | ratio of initial gas cap volume to initial oil column volume, dimensionless | ||
|- | |- | ||
|''N''<sub>''i''</sub> | | ''N''<sub>''i''</sub> | ||
|= | | = | ||
|oil initially in place, STB or m<sup>3</sup> | | oil initially in place, STB or m<sup>3</sup> | ||
|- | |- | ||
|''N''<sub>''p''</sub> | | ''N''<sub>''p''</sub> | ||
|= | | = | ||
|cumulative oil production, STB | | cumulative oil production, STB | ||
|- | |- | ||
|''p'' | | ''p'' | ||
|= | | = | ||
|pressure, static reservoir, general, psia | | pressure, static reservoir, general, psia | ||
|- | |- | ||
|''p''<sub>''i''</sub> | | ''p''<sub>''i''</sub> | ||
|= | | = | ||
|initial reservoir pressure, psia | | initial reservoir pressure, psia | ||
|- | |- | ||
|''p''<sub>''n''</sub> | | ''p''<sub>''n''</sub> | ||
|= | | = | ||
|laboratory net (hydrostatic) pressure (confining pressure minus pore pressure), psia | | laboratory net (hydrostatic) pressure (confining pressure minus pore pressure), psia | ||
|- | |- | ||
|''p''<sub>''ob''</sub> | | ''p''<sub>''ob''</sub> | ||
|= | | = | ||
|overburden pressure, psia | | overburden pressure, psia | ||
|- | |- | ||
|''R''<sub>''p''</sub> | | ''R''<sub>''p''</sub> | ||
|= | | = | ||
|cumulative (producing) gas/oil ratio, scf/STB | | cumulative (producing) gas/oil ratio, scf/STB | ||
|- | |- | ||
|''S''<sub>''w''</sub> | | ''S''<sub>''w''</sub> | ||
|= | | = | ||
|water saturation, fraction | | water saturation, fraction | ||
|- | |- | ||
|''W''<sub>''p''</sub> | | ''W''<sub>''p''</sub> | ||
|= | | = | ||
|cumulative water production, STB | | cumulative water production, STB | ||
|- | |- | ||
|''z'' | | ''z'' | ||
|= | | = | ||
|gas compressibility factor, general, dimensionless | | gas compressibility factor, general, dimensionless | ||
|- | |- | ||
|''z''<sub>''i''</sub> | | ''z''<sub>''i''</sub> | ||
|= | | = | ||
|gas compressibility factor at initial conditions, dimensionless | | gas compressibility factor at initial conditions, dimensionless | ||
|- | |- | ||
|Δ''p'' | | Δ''p'' | ||
|= | | = | ||
|pressure, incremental, psi | | pressure, incremental, psi | ||
|} | |} | ||
==References== | == References == | ||
<references | |||
<references /> | |||
== Noteworthy papers in OnePetro == | |||
Use this section to list papers in OnePetro that a reader who wants to learn more should definitely read | Use this section to list papers in OnePetro that a reader who wants to learn more should definitely read | ||
==External links== | == External links == | ||
Use this section to provide links to relevant material on websites other than PetroWiki and OnePetro | Use this section to provide links to relevant material on websites other than PetroWiki and OnePetro | ||
==See also== | == See also == | ||
[[PEH: | |||
[[PEH:Estimation_of_Primary_Reserves_of_Crude_Oil,_Natural_Gas,_and_Condensate]] | |||
[[Category:5.7.1 Estimates of resource in place]] |
Revision as of 19:12, 9 June 2015
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:
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
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[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]:
.............................(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. Gp 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. 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]
.............................(3)
Under this method, Eq. 3 can be written for a gas reservoir as
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 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]:
.............................(9)
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
.............................(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 |
References
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See also
PEH:Estimation_of_Primary_Reserves_of_Crude_Oil,_Natural_Gas,_and_Condensate