You must log in to edit PetroWiki. Help with editing

Content of PetroWiki is intended for personal use only and to supplement, not replace, engineering judgment. SPE disclaims any and all liability for your use of such content. More information


Reserves estimation of tight gas reservoirs: Difference between revisions

PetroWiki
Jump to navigation Jump to search
No edit summary
m (Protected "Reserves estimation of tight gas reservoirs" ([Edit=Allow only administrators] (indefinite) [Move=Allow only administrators] (indefinite)))
 
(3 intermediate revisions by 2 users not shown)
Line 1: Line 1:
As defined by the U.S. Federal Energy Regulatory Commission (U.S. FERC), low-permeability (“tight”) gas reservoirs have an average in-situ permeability of 0.1 md or less. Others have placed the upper limit at 1 md. Estimates of ultimate recovery from these resources vary widely and depend chiefly on assumptions of wellhead gas price.  
As defined by the U.S. Federal Energy Regulatory Commission (U.S. FERC), low-permeability (“tight”) gas reservoirs have an average in-situ permeability of 0.1 md or less. Others have placed the upper limit at 1 md. Estimates of ultimate recovery from these resources vary widely and depend chiefly on assumptions of wellhead gas price.
 
== Consideration of reserves estimation ==


==Consideration of reserves estimation==
Methods for estimating gas reserves in moderate- to high-permeability reservoirs are unreliable in very-low-permeability reservoirs. The unreliability can be attributed to the geologic setting in which these reservoirs occur and the completion methods required to make them commercial. In general, their geologic setting is characterized by:
Methods for estimating gas reserves in moderate- to high-permeability reservoirs are unreliable in very-low-permeability reservoirs. The unreliability can be attributed to the geologic setting in which these reservoirs occur and the completion methods required to make them commercial. In general, their geologic setting is characterized by:
*A high degree of permeability heterogeneity
*A high degree of permeability heterogeneity
*Lateral discontinuities in apparently blanket sands
*Lateral discontinuities in apparently blanket sands
*Stratigraphic, rather than structural, traps
*Stratigraphic, rather than structural, traps
*Complex mineralogy, frequently with high-grain-density minerals randomly dispersed throughout the section as well as water-sensitive clays.  
*Complex mineralogy, frequently with high-grain-density minerals randomly dispersed throughout the section as well as water-sensitive clays.


These attributes make it very difficult to determine [[Porosity determination|porosity]] and interstitial water saturation by conventional log and core analysis.<ref name="r1" /><ref name="r2" /><ref name="r3" /><ref name="r4" /><ref name="r5" /> [[Petrophysical properties of gas reservoirs|Petrophysical properties]] measured at ambient conditions (e.g., k and S<sub>w</sub>) differ substantially from those at reservoir conditions, and corrections for formation compressibility are subject to considerable uncertainty. For example, permeabilities can be as much as two orders of magnitude greater at ambient conditions than at reservoir conditions. These problems and poor lateral continuity lead to substantial uncertainties in volumetric estimates of gas-in-place (GIP). In many cases, it is impossible to distinguish between commercial and noncommercial intervals from log analysis alone. Drillstem tests rarely provide useful information because formations often are damaged during drilling.  
These attributes make it very difficult to determine [[Porosity_determination|porosity]] and interstitial water saturation by conventional log and core analysis.<ref name="r1">Brown, C.A., Erbe, C.B., and Crafton, J.W. 1981. A Comprehensive Reservoir Model of the Low Permeability Lewis Sands in the Hay Reservoir Area, Sweetwater County, Wyoming. Presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 4–7 October. SPE-10193-MS. http://dx.doi.org/10.2118/10193-PA.</ref><ref name="r2">Kukal, G.C., Biddison, C.L., Hill, R.E. et al. 1983. Critical Problems Hindering Accurate Log Interpretation of Tight Gas Sand Reservoirs. Presented at the SPE/DOE Low Permeability Gas Reservoirs Symposium, Denver, Colorado, 14-16 March 1983. SPE-11620-MS. http://dx.doi.org/10.2118/11620-MS.</ref><ref name="r3">Spencer, C.W. 1985. Geologic Aspects of Tight Gas Reservoirs in the Rocky Mountain Region. J Pet Technol 37 (7): 1308–1314. SPE-11647-PA. http://dx.doi.org/10.2118/11647-PA.</ref><ref name="r4">Witherbee, L.J., Godfrey, R.D., and Dimelow, T.E. 1983. Predicting Turbidite-Contourite Reservoir Intervals in Tight Gas Sands: A Case Study From the Mancos B Sandstone. Presented at the SPE/DOE Low Permeability Gas Reservoirs Symposium, Denver, Colorado, 14-16 March 1983. SPE-11609-MS. http://dx.doi.org/10.2118/11609-MS.</ref><ref name="r5">Lewis, D.J. and Perrin, J.D. 1992. Wilcox Formation Evaluation: Improved Procedures for Tights Gas-Sand Evaluation. J Pet Technol 44 (6): 724-730. SPE-20570-PA. http://dx.doi.org/10.2118/20570-PA.</ref> [[Petrophysical_properties_of_gas_reservoirs|Petrophysical properties]] measured at ambient conditions (e.g., k and S<sub>w</sub>) differ substantially from those at reservoir conditions, and corrections for formation compressibility are subject to considerable uncertainty. For example, permeabilities can be as much as two orders of magnitude greater at ambient conditions than at reservoir conditions. These problems and poor lateral continuity lead to substantial uncertainties in volumetric estimates of gas-in-place (GIP). In many cases, it is impossible to distinguish between commercial and noncommercial intervals from log analysis alone. Drillstem tests rarely provide useful information because formations often are damaged during drilling.


Massive [[hydraulic fracturing]] usually is required to obtain commercial flow rates. Despite more than 35 years of experience with fracturing technology, however, the industry remains unable to design a treatment and predict the results with high confidence when relying solely on analytical methods.<ref name="r6" /><ref name="r7" /> Typically, operators rely on analytical models coupled with analogy.  
Massive [[Hydraulic_fracturing|hydraulic fracturing]] usually is required to obtain commercial flow rates. Despite more than 35 years of experience with fracturing technology, however, the industry remains unable to design a treatment and predict the results with high confidence when relying solely on analytical methods.<ref name="r6">Kazemi, H. 1982. Low-Permeability Gas Sands. J Pet Technol 34 (10): 2229-2232. SPE-11330-PA. http://dx.doi.org/10.2118/11330-PA.</ref><ref name="r7">Veatch, R.W.J. 1983. Overview of Current Hydraulic Fracturing Design and Treatment Technology—Part 1. J Pet Technol 35 (4): 677-687. SPE-10039-PA. http://dx.doi.org/10.2118/10039-PA.</ref> Typically, operators rely on analytical models coupled with analogy.


Along the US Gulf Coast, tight-gas accumulations frequently occur in geopressured sections.<ref name="r8" /><ref name="r9" /> In this environment, understanding the influence of reservoir stress on rock properties is important for differentiating between productive and nonproductive formations.  
Along the US Gulf Coast, tight-gas accumulations frequently occur in geopressured sections.<ref name="r8">Robinson, B.M., Holditch, S.A., and Lee, W.J. 1986. A Case Study of the Wilcox (Lobo) Trend in Webb and Zapata Counties, TX. J Pet Technol 38 (12): 1355-1364. SPE-11600-PA. http://dx.doi.org/10.2118/11600-PA.</ref><ref name="r9">Lewis, D.J. and Perrin, J.D. 1992. Wilcox Formation Evaluation: Improved Procedures for Tights Gas-Sand Evaluation. J Pet Technol 44 (6): 724-730. SPE-20570-PA. http://dx.doi.org/10.2118/20570-PA.</ref> In this environment, understanding the influence of reservoir stress on rock properties is important for differentiating between productive and nonproductive formations.


Over the life of a well completed in low-permeability gas reservoirs, the gas production rate typically exhibits a hyperbolic decline,<ref name="r10" /><ref name="r11" /> with apparent b values generally >1. In addition to decline curve analysis, empirical log-log rate/time models might provide useful short-term information for such wells—before the onset of significant pressure depletion. The following equations, developed in the 1980s for more than 2,500 then-new wells in the U.S. Rocky Mountains, have been used to estimate flow rates ('''Eqs. 1''' and '''2''') and near-term reserves ('''Eqs. 3''' and '''4''') for damaged fracture flow<ref name="r12" />:
Over the life of a well completed in low-permeability gas reservoirs, the gas production rate typically exhibits a hyperbolic decline,<ref name="r10">Stewart, P.R. 1970. Low-Permeability Gas Well Performance At Constant Pressure. J Pet Technol 22 (9): 1149-1156. http://dx.doi.org/10.2118/2604-PA.</ref><ref name="r11">Brown, C.A., Erbe, C.B., and Crafton, J.W. 1981. A Comprehensive Reservoir Model of the Low Permeability Lewis Sands in the Hay Reservoir Area, Sweetwater County, Wyoming. Presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 4–7 October. SPE-10193-MS. http://dx.doi.org/10.2118/10193-PA.</ref> with apparent b values generally >1. In addition to decline curve analysis, empirical log-log rate/time models might provide useful short-term information for such wells—before the onset of significant pressure depletion. The following equations, developed in the 1980s for more than 2,500 then-new wells in the U.S. Rocky Mountains, have been used to estimate flow rates ('''Eqs. 1''' and '''2''') and near-term reserves ('''Eqs. 3''' and '''4''') for damaged fracture flow<ref name="r12">Hale, B.W. 1986. Analysis of Tight Gas Well Production Histories in the Rocky Mountains. SPE Prod Eng 1 (4): 310-322. SPE-11639-PA. http://dx.doi.org/10.2118/11639-PA.</ref>:


[[File:Vol5 page 1544 eq 001.png]]('''Eq. 1''')
[[File:Vol5 page 1544 eq 001.png|RTENOTITLE]]('''Eq. 1''')


[[File:Vol5 page 1544 eq 002.png]]('''Eq. 2''')
[[File:Vol5 page 1544 eq 002.png|RTENOTITLE]]('''Eq. 2''')


[[File:Vol5 page 1544 eq 003.png]]('''Eq. 3''')
[[File:Vol5 page 1544 eq 003.png|RTENOTITLE]]('''Eq. 3''')


and
and


[[File:Vol5 page 1544 eq 004.png]]('''Eq. 4''')
[[File:Vol5 page 1544 eq 004.png|RTENOTITLE]]('''Eq. 4''')


where K<sub>A</sub> and K<sub>B</sub> are coefficients calculated during fitting these equations.  
where K<sub>A</sub> and K<sub>B</sub> are coefficients calculated during fitting these equations.


For an undamaged, fractured well, initial values of n should equal approximately –0.5. Because of damage, however, initial n values as small as –0.15 had been observed in the wells studied; the average was –0.34. With the onset of depletion, n decreases to –1.0 or more.<ref name="r13" /><ref name="r14" />
For an undamaged, fractured well, initial values of n should equal approximately –0.5. Because of damage, however, initial n values as small as –0.15 had been observed in the wells studied; the average was –0.34. With the onset of depletion, n decreases to –1.0 or more.<ref name="r13">Hale, B.W. 1981. A Type Curve Approach to Reserves for the Big Piney Gas Field. Presented at the SPE/DOE Low Permeability Gas Reservoirs Symposium, Denver, Colorado, 27-29 May 1981. SPE-9840-MS. http://dx.doi.org/10.2118/9840-MS.</ref><ref name="r14">Harlan, L.E. 1966. A Method for Determining Recovery Factors in Low Permeability Gas Reservoirs. Presented at the 41st Annual Meeting of the Society of Petroleum Engineers of AIME, Dallas, Texas, 2-5 October. http://dx.doi.org/10.2118/1555-MS.</ref>


Eqs. 1 and 3 can be used to account for the effects of a damaged fracture by using the field-observed value of n for each such well. Depending on circumstances, however, Eqs. 2 and 4 might provide a better fit to the observed data.
Eqs. 1 and 3 can be used to account for the effects of a damaged fracture by using the field-observed value of n for each such well. Depending on circumstances, however, Eqs. 2 and 4 might provide a better fit to the observed data.


Reserves estimates (RE) of gas from some of these reservoirs vs. k<sub>g</sub>h is shown in '''Fig. 1'''<ref name="r15" />. Well spacing ranges from approximately 160 to 320 acres. For k<sub>h</sub> of less than approximately 50 md-ft, there is a decrease in RE, albeit erratically so.  
Reserves estimates (RE) of gas from some of these reservoirs vs. k<sub>g</sub>h is shown in '''Fig. 1'''<ref name="r15">Cronquist, C. 2001. Estimation and Classification of Reserves of Crude Oil, Natural Gas, and Condensate. Richardson, Texas: SPE.</ref>. Well spacing ranges from approximately 160 to 320 acres. For k<sub>h</sub> of less than approximately 50 md-ft, there is a decrease in RE, albeit erratically so.


<gallery widths="300px" heights="200px">
<gallery>
File:vol5 Page 1544 Image 0001.png|'''Fig. 1 – Observed gas RE as related to ''kh''. (After Cronquist.<ref name="r15" />)'''
File:vol5 Page 1544 Image 0001.png|'''Fig. 1 – Observed gas RE as related to ''kh''. (After Cronquist.<ref name="r15" />)'''
</gallery>
</gallery>


Because of the high degree of permeability heterogeneity, drainage areas of individual wells vary widely. In the Green River basin (US), for example, effective drainage areas reportedly have ranged from approximately 100 to 640 acres.<ref name="r16" /> Depending on economics, such situations can offer opportunities for significant increase in reserves by infill drilling.
Because of the high degree of permeability heterogeneity, drainage areas of individual wells vary widely. In the Green River basin (US), for example, effective drainage areas reportedly have ranged from approximately 100 to 640 acres.<ref name="r16">Cipolla, C.L. and Kyte, D.G. 1992. Infill Drilling in the Moxa Arch: A Case History of the Frontier Formation. Presented at the SPE Annual Technical Conference and Exhibition, Washington, D.C., 4-7 October 1992. SPE-24909-MS. http://dx.doi.org/10.2118/24909-MS.</ref> Depending on economics, such situations can offer opportunities for significant increase in reserves by infill drilling.


== Nomenclature ==
== Nomenclature ==


{|
{|
|''G''<sub>''p''</sub>
|=
|cumulative gas production, scf
|-
|-
|''K''<sub>''A''</sub>  
| ''G''<sub>''p''</sub>
|=  
| =
|coefficient  
| cumulative gas production, scf
|-
| ''K''<sub>''A''</sub>
| =
| coefficient
|-
|-
|''K''<sub>''B''</sub>  
| ''K''<sub>''B''</sub>
|=  
| =
|coefficient  
| coefficient
|-
|-
|''n''  
| ''n''
|=  
| =
|variable  
| variable
|-
|-
|''q''<sub>''g''</sub>  
| ''q''<sub>''g''</sub>
|=  
| =
|gas production rate, scf/month  
| gas production rate, scf/month
|-
|-
|''t''  
| ''t''
|=  
| =
|time, months or years  
| time, months or years
|}
|}


==References==
== References ==
<references>
 
<ref name="r1">Brown, C.A., Erbe, C.B., and  Crafton, J.W. 1981. A Comprehensive Reservoir Model of the Low Permeability Lewis Sands in the Hay Reservoir Area, Sweetwater County, Wyoming. Presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 4–7 October. SPE-10193-MS. http://dx.doi.org/10.2118/10193-PA. </ref>
<references />
<ref name="r2">Kukal, G.C., Biddison, C.L., Hill, R.E. et al. 1983. Critical Problems Hindering Accurate Log Interpretation of Tight Gas Sand Reservoirs. Presented at the SPE/DOE Low Permeability Gas Reservoirs Symposium, Denver, Colorado, 14-16 March 1983. SPE-11620-MS. http://dx.doi.org/10.2118/11620-MS. </ref>
 
<ref name="r3">Spencer, C.W. 1985. Geologic Aspects of Tight Gas Reservoirs in the Rocky Mountain Region. ''J Pet Technol'' '''37''' (7): 1308–1314. SPE-11647-PA. http://dx.doi.org/10.2118/11647-PA. </ref>
== Noteworthy papers in OnePetro ==
<ref name="r4">Witherbee, L.J., Godfrey, R.D., and  Dimelow, T.E. 1983. Predicting Turbidite-Contourite Reservoir Intervals in Tight Gas Sands: A Case Study From the Mancos B Sandstone. Presented at the SPE/DOE Low Permeability Gas Reservoirs Symposium, Denver, Colorado, 14-16 March 1983. SPE-11609-MS. http://dx.doi.org/10.2118/11609-MS.  </ref>
<ref name="r5">Lewis, D.J. and Perrin, J.D. 1992. Wilcox Formation Evaluation: Improved Procedures for Tights Gas-Sand Evaluation. ''J Pet Technol'' '''44''' (6): 724-730. SPE-20570-PA. http://dx.doi.org/10.2118/20570-PA. </ref>
<ref name="r6">Kazemi, H. 1982. Low-Permeability Gas Sands. ''J Pet Technol'' '''34''' (10): 2229-2232. SPE-11330-PA. http://dx.doi.org/10.2118/11330-PA. </ref>
<ref name="r7">Veatch, R.W.J. 1983. Overview of Current Hydraulic Fracturing Design and Treatment Technology—Part 1. ''J Pet Technol'' '''35''' (4): 677-687. SPE-10039-PA. http://dx.doi.org/10.2118/10039-PA. </ref>
<ref name="r8">Robinson, B.M., Holditch, S.A., and  Lee, W.J. 1986. A Case Study of the Wilcox (Lobo) Trend in Webb and Zapata Counties, TX. ''J Pet Technol'' '''38''' (12): 1355-1364. SPE-11600-PA. http://dx.doi.org/10.2118/11600-PA. </ref>
<ref name="r9">Lewis, D.J. and Perrin, J.D. 1992. Wilcox Formation Evaluation: Improved Procedures for Tights Gas-Sand Evaluation. ''J Pet Technol'' '''44''' (6): 724-730. SPE-20570-PA. http://dx.doi.org/10.2118/20570-PA. </ref>
<ref name="r10">Stewart, P.R. 1970. Low-Permeability Gas Well Performance At Constant Pressure. ''J Pet Technol'' '''22''' (9): 1149-1156. http://dx.doi.org/10.2118/2604-PA. </ref>
<ref name="r11">Brown, C.A., Erbe, C.B., and  Crafton, J.W. 1981. A Comprehensive Reservoir Model of the Low Permeability Lewis Sands in the Hay Reservoir Area, Sweetwater County, Wyoming. Presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 4–7 October. SPE-10193-MS. http://dx.doi.org/10.2118/10193-PA. </ref>
<ref name="r12">Hale, B.W. 1986. Analysis of Tight Gas Well Production Histories in the Rocky Mountains. ''SPE Prod Eng'' '''1''' (4): 310-322. SPE-11639-PA. http://dx.doi.org/10.2118/11639-PA. </ref>
<ref name="r13">Hale, B.W. 1981. A Type Curve Approach to Reserves for the Big Piney Gas Field. Presented at the SPE/DOE Low Permeability Gas Reservoirs Symposium, Denver, Colorado, 27-29 May 1981. SPE-9840-MS. http://dx.doi.org/10.2118/9840-MS. </ref>
<ref name="r14">Harlan, L.E. 1966. A Method for Determining Recovery Factors in Low Permeability Gas Reservoirs. Presented at the 41st Annual Meeting of the Society of Petroleum Engineers of AIME, Dallas, Texas, 2-5 October. http://dx.doi.org/10.2118/1555-MS. </ref>
<ref name="r15">Cronquist, C. 2001. ''Estimation and Classification of Reserves of Crude Oil, Natural Gas, and Condensate''. Richardson, Texas: SPE. </ref>
<ref name="r16">Cipolla, C.L. and Kyte, D.G. 1992. Infill Drilling in the Moxa Arch: A Case History of the Frontier Formation. Presented at the SPE Annual Technical Conference and Exhibition, Washington, D.C., 4-7 October 1992. SPE-24909-MS. http://dx.doi.org/10.2118/24909-MS. </ref>
</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:Estimation of Primary Reserves of Crude Oil, Natural Gas, and Condensate]]
 
[[PEH:Estimation_of_Primary_Reserves_of_Crude_Oil,_Natural_Gas,_and_Condensate]]
 
==Category==


[[Category:3.4.1 Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene]]
[[Category:3.4.1 Inhibition and remediation of hydrates, scale, paraffin or wax, and asphaltene]] [[Category:YR]]

Latest revision as of 11:17, 11 June 2019

As defined by the U.S. Federal Energy Regulatory Commission (U.S. FERC), low-permeability (“tight”) gas reservoirs have an average in-situ permeability of 0.1 md or less. Others have placed the upper limit at 1 md. Estimates of ultimate recovery from these resources vary widely and depend chiefly on assumptions of wellhead gas price.

Consideration of reserves estimation

Methods for estimating gas reserves in moderate- to high-permeability reservoirs are unreliable in very-low-permeability reservoirs. The unreliability can be attributed to the geologic setting in which these reservoirs occur and the completion methods required to make them commercial. In general, their geologic setting is characterized by:

  • A high degree of permeability heterogeneity
  • Lateral discontinuities in apparently blanket sands
  • Stratigraphic, rather than structural, traps
  • Complex mineralogy, frequently with high-grain-density minerals randomly dispersed throughout the section as well as water-sensitive clays.

These attributes make it very difficult to determine porosity and interstitial water saturation by conventional log and core analysis.[1][2][3][4][5] Petrophysical properties measured at ambient conditions (e.g., k and Sw) differ substantially from those at reservoir conditions, and corrections for formation compressibility are subject to considerable uncertainty. For example, permeabilities can be as much as two orders of magnitude greater at ambient conditions than at reservoir conditions. These problems and poor lateral continuity lead to substantial uncertainties in volumetric estimates of gas-in-place (GIP). In many cases, it is impossible to distinguish between commercial and noncommercial intervals from log analysis alone. Drillstem tests rarely provide useful information because formations often are damaged during drilling.

Massive hydraulic fracturing usually is required to obtain commercial flow rates. Despite more than 35 years of experience with fracturing technology, however, the industry remains unable to design a treatment and predict the results with high confidence when relying solely on analytical methods.[6][7] Typically, operators rely on analytical models coupled with analogy.

Along the US Gulf Coast, tight-gas accumulations frequently occur in geopressured sections.[8][9] In this environment, understanding the influence of reservoir stress on rock properties is important for differentiating between productive and nonproductive formations.

Over the life of a well completed in low-permeability gas reservoirs, the gas production rate typically exhibits a hyperbolic decline,[10][11] with apparent b values generally >1. In addition to decline curve analysis, empirical log-log rate/time models might provide useful short-term information for such wells—before the onset of significant pressure depletion. The following equations, developed in the 1980s for more than 2,500 then-new wells in the U.S. Rocky Mountains, have been used to estimate flow rates (Eqs. 1 and 2) and near-term reserves (Eqs. 3 and 4) for damaged fracture flow[12]:

RTENOTITLE(Eq. 1)

RTENOTITLE(Eq. 2)

RTENOTITLE(Eq. 3)

and

RTENOTITLE(Eq. 4)

where KA and KB are coefficients calculated during fitting these equations.

For an undamaged, fractured well, initial values of n should equal approximately –0.5. Because of damage, however, initial n values as small as –0.15 had been observed in the wells studied; the average was –0.34. With the onset of depletion, n decreases to –1.0 or more.[13][14]

Eqs. 1 and 3 can be used to account for the effects of a damaged fracture by using the field-observed value of n for each such well. Depending on circumstances, however, Eqs. 2 and 4 might provide a better fit to the observed data.

Reserves estimates (RE) of gas from some of these reservoirs vs. kgh is shown in Fig. 1[15]. Well spacing ranges from approximately 160 to 320 acres. For kh of less than approximately 50 md-ft, there is a decrease in RE, albeit erratically so.

Because of the high degree of permeability heterogeneity, drainage areas of individual wells vary widely. In the Green River basin (US), for example, effective drainage areas reportedly have ranged from approximately 100 to 640 acres.[16] Depending on economics, such situations can offer opportunities for significant increase in reserves by infill drilling.

Nomenclature

Gp = cumulative gas production, scf
KA = coefficient
KB = coefficient
n = variable
qg = gas production rate, scf/month
t = time, months or years

References

  1. Brown, C.A., Erbe, C.B., and Crafton, J.W. 1981. A Comprehensive Reservoir Model of the Low Permeability Lewis Sands in the Hay Reservoir Area, Sweetwater County, Wyoming. Presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 4–7 October. SPE-10193-MS. http://dx.doi.org/10.2118/10193-PA.
  2. Kukal, G.C., Biddison, C.L., Hill, R.E. et al. 1983. Critical Problems Hindering Accurate Log Interpretation of Tight Gas Sand Reservoirs. Presented at the SPE/DOE Low Permeability Gas Reservoirs Symposium, Denver, Colorado, 14-16 March 1983. SPE-11620-MS. http://dx.doi.org/10.2118/11620-MS.
  3. Spencer, C.W. 1985. Geologic Aspects of Tight Gas Reservoirs in the Rocky Mountain Region. J Pet Technol 37 (7): 1308–1314. SPE-11647-PA. http://dx.doi.org/10.2118/11647-PA.
  4. Witherbee, L.J., Godfrey, R.D., and Dimelow, T.E. 1983. Predicting Turbidite-Contourite Reservoir Intervals in Tight Gas Sands: A Case Study From the Mancos B Sandstone. Presented at the SPE/DOE Low Permeability Gas Reservoirs Symposium, Denver, Colorado, 14-16 March 1983. SPE-11609-MS. http://dx.doi.org/10.2118/11609-MS.
  5. Lewis, D.J. and Perrin, J.D. 1992. Wilcox Formation Evaluation: Improved Procedures for Tights Gas-Sand Evaluation. J Pet Technol 44 (6): 724-730. SPE-20570-PA. http://dx.doi.org/10.2118/20570-PA.
  6. Kazemi, H. 1982. Low-Permeability Gas Sands. J Pet Technol 34 (10): 2229-2232. SPE-11330-PA. http://dx.doi.org/10.2118/11330-PA.
  7. Veatch, R.W.J. 1983. Overview of Current Hydraulic Fracturing Design and Treatment Technology—Part 1. J Pet Technol 35 (4): 677-687. SPE-10039-PA. http://dx.doi.org/10.2118/10039-PA.
  8. Robinson, B.M., Holditch, S.A., and Lee, W.J. 1986. A Case Study of the Wilcox (Lobo) Trend in Webb and Zapata Counties, TX. J Pet Technol 38 (12): 1355-1364. SPE-11600-PA. http://dx.doi.org/10.2118/11600-PA.
  9. Lewis, D.J. and Perrin, J.D. 1992. Wilcox Formation Evaluation: Improved Procedures for Tights Gas-Sand Evaluation. J Pet Technol 44 (6): 724-730. SPE-20570-PA. http://dx.doi.org/10.2118/20570-PA.
  10. Stewart, P.R. 1970. Low-Permeability Gas Well Performance At Constant Pressure. J Pet Technol 22 (9): 1149-1156. http://dx.doi.org/10.2118/2604-PA.
  11. Brown, C.A., Erbe, C.B., and Crafton, J.W. 1981. A Comprehensive Reservoir Model of the Low Permeability Lewis Sands in the Hay Reservoir Area, Sweetwater County, Wyoming. Presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 4–7 October. SPE-10193-MS. http://dx.doi.org/10.2118/10193-PA.
  12. Hale, B.W. 1986. Analysis of Tight Gas Well Production Histories in the Rocky Mountains. SPE Prod Eng 1 (4): 310-322. SPE-11639-PA. http://dx.doi.org/10.2118/11639-PA.
  13. Hale, B.W. 1981. A Type Curve Approach to Reserves for the Big Piney Gas Field. Presented at the SPE/DOE Low Permeability Gas Reservoirs Symposium, Denver, Colorado, 27-29 May 1981. SPE-9840-MS. http://dx.doi.org/10.2118/9840-MS.
  14. Harlan, L.E. 1966. A Method for Determining Recovery Factors in Low Permeability Gas Reservoirs. Presented at the 41st Annual Meeting of the Society of Petroleum Engineers of AIME, Dallas, Texas, 2-5 October. http://dx.doi.org/10.2118/1555-MS.
  15. 15.0 15.1 Cronquist, C. 2001. Estimation and Classification of Reserves of Crude Oil, Natural Gas, and Condensate. Richardson, Texas: SPE.
  16. Cipolla, C.L. and Kyte, D.G. 1992. Infill Drilling in the Moxa Arch: A Case History of the Frontier Formation. Presented at the SPE Annual Technical Conference and Exhibition, Washington, D.C., 4-7 October 1992. SPE-24909-MS. http://dx.doi.org/10.2118/24909-MS.

Noteworthy papers in OnePetro

Use this section to list papers in OnePetro that a reader who wants to learn more should definitely read

External links

Use this section to provide links to relevant material on websites other than PetroWiki and OnePetro

See also

PEH:Estimation_of_Primary_Reserves_of_Crude_Oil,_Natural_Gas,_and_Condensate

Category