Changes

''Pay'' is defined as that part of a reservoir unit from which hydrocarbons can be produced ''at economic rates given a specific production method''. This concept of pay links the physical characteristics of the reservoir (rock properties, fluid saturations, and capillary behavior) to the economic aspects of production (completion method, recovery techniques, and volumetric estimates of reserves). ''Nonpay'' is defined as the part of a reservoir unit that will not produce hydrocarbons at economic rates and includes intrareservoir barriers.

''Pay'' is defined as that part of a reservoir unit from which hydrocarbons can be produced ''at economic rates given a specific production method''. This concept of pay links the physical characteristics of the reservoir (rock properties, fluid saturations, and capillary behavior) to the economic aspects of production (completion method, recovery techniques, and volumetric estimates of reserves). ''Nonpay'' is defined as the part of a reservoir unit that will not produce hydrocarbons at economic rates and includes intrareservoir barriers.

A ''reservoir rock'' is any porous and permeable rock capable of ''potentially'' containing hydrocarbons in its pore system. This statement implies that not all reservoir rocks qualify as pay. In some reservoirs, there may be intermediate pay types or a continuum between pay and nonpay intervals. This situation may include reservoir units that have differing fluid saturations or pore geometries, or that are present at different elevations above the hydrocarbon-water contact.

A ''reservoir rock'' is any porous and permeable rock capable of ''potentially'' containing hydrocarbons in its pore system. This statement implies that not all reservoir rocks qualify as pay. In some reservoirs, there may be intermediate pay types or a continuum between pay and nonpay intervals. This situation may include reservoir units that have differing fluid saturations or pore geometries, or that are present at different elevations above the Basic open hole tools [http://www.glossary.oilfield.slb.com/en/Terms.aspx?LookIn=term%20name&filter=oil-water%20contact hydrocarbon-water contact].

The production methodologies—primary, secondary, and enhanced recovery—affect the definition of pay. For example, beds with limited lateral continuity may qualify as pay under primary production, but may not be waterfloodable at contemplated injector-producer well spacings, thus disqualifying them as pay under secondary production. Thus, there are two separate but related questions regarding pay determination: first, the delineation of [[reservoir quality]] rock, and second, the classification of that part of a reservoir quality interval as pay.

The production methodologies—primary, secondary, and enhanced recovery—affect the definition of pay. For example, beds with limited [[lateral]] continuity may qualify as pay under primary production, but may not be waterfloodable at contemplated injector-producer well spacings, thus disqualifying them as pay under secondary production. Thus, there are two separate but related questions regarding pay determination: first, the delineation of [[reservoir quality]] rock, and second, the classification of that part of a reservoir quality interval as pay.

==Pay determination techniques==

==Pay determination techniques==

* Results of sedimentological studies, preferably using conventional cores (see [[Lithofacies and environmental analysis of clastic depositional systems]])

* Results of sedimentological studies, preferably using conventional cores (see [[Lithofacies and environmental analysis of clastic depositional systems]])

* [[Core analysis]]

* [[Overview of routine core analysis|Core analysis]]

* Analysis of the capillary system of selected core samples (see [[Capillary pressure]])

* Analysis of the capillary system of selected core samples (see [[Capillary pressure]])

* Thin section petrography and electron microscopy for mineral composition and pore geometry (see [[Reservoir quality]]) and [[Thin section analysis]] and [[SEM, XRD, CL, and XF Methods]]

* Thin section petrography and electron microscopy for mineral composition and pore geometry (see [[Reservoir quality]]) and [[Thin section analysis]] and [[SEM, XRD, CL, and XF methods]]

* [[Well log]]s, including measures of the lithology, [[porosity]], and fluid saturation

* [[Basic open hole tools|Well logs]], including measures of the lithology, [[porosity]], and fluid saturation

* Production history and well test results, including spinner and temperature surveys  

* Production history and well test results, including spinner and temperature surveys  

* Ancillary data, including mud logs, drillers' logs, and [[show evaluation]]s  

* Ancillary data, including mud logs, drillers' logs, and [[show evaluation]]s  

! Procedure

! Procedure

|-

|-

| 1. Geologically characterize reservoir

| 1. Geologically characterize reservoir || [[Core description]], wireline log calibration, [[lithofacies]] determination, depositional environment analysis

| [[Core description]], wireline log calibration, lithofacies determination, depositional environment analysis

|-

|-

| 2. Determine reservoir properties

| 2. Determine reservoir properties || Core analysis (porosity, [[permeability]], fluid saturation), wireline log analysis (porosity, fluid saturation)

| Core analysis (porosity, [[permeability]], fluid saturation), wireline log analysis (porosity, fluid saturation)

|-

|-

| 3. Delineate reservoir and nonreservoir rocks and characterize pore space geometry

| 3. Delineate reservoir and nonreservoir rocks and characterize pore space geometry || [[Porosity]]/permeability crossplots, thin section petrography, pore cast electron microscopy, mercury injection capillary analysis; apply cut-off criteria (Table 2)

| [[Porosity]]/permeability crossplots, thin section petrography, pore cast electron microscopy, mercury injection capillary analysis; apply cut-off criteria (Table 2)

|-

|-

| 4. Evaluate pay and nonpay

| 4. Evaluate pay and non pay || Mercury injection capillary analysis, fluid saturation analysis; apply cut-off criteria (Table 3)

| Mercury injection capillary analysis, fluid saturation analysis; apply cut-off criteria (Table 3)

|-

|-

| 5. Confirm pay zones

| 5. Confirm pay zones || Measure well performance using spinner, temperature, flowmeter data and production results; observations noted during drilling, including shows

| Measure well performance using spinner, temperature, flowmeter data and production results; observations noted during drilling, including shows

|}

|}

The simplest, yet most useful, method for combining this information is a composite log, which displays the different classes of data in a format in which each data set is readily correlated by depth. From a detailed reservoir profile log, pay zones can be identified and correlated to uncored wells using well log curves that are calibrated to core data. Examples of this type of procedure can be found in Connolly and Reed,<ref name=pt06r19>Connolly, E. T., Reed, P. A., 1983, Full spectrum formation evaluation: Canadian Well Logging Society Journal, v. 12, p. 23–69.</ref> Harris,<ref name=pt06r48>Harris, D. G., 1975, The roles of geology in reservoir simulation studies: Journal Petroleum of Technology, May, p. 625–632.</ref> Hearn et al.,<ref name=pt06r51>Hearn, C. L., Ebanks, W. J. Jr., Tye, R. S., Ranganathan, V. 1984, Geological factors influencing reservoir performance of the Hartzog Draw field: Journal of Petroleum Technology, v. 36, Aug., p. 1335–1344., 10., 2118/12016-PA</ref> and Hietala and Connolly.<ref name=pt06r53>Hietala, R. W., Connolly, E. T., 1984, Integrated rock-log calibration in the Elmworth field, Alberta, Canada, Part II—well log analysis methods and techniques, in Masters, J. A., ed., Elmworth—Case Study of a Deep Basin Gas Field: AAPG Memoir 38, p. 215–242.</ref>

The simplest, yet most useful, method for combining this information is a composite log, which displays the different classes of data in a format in which each data set is readily correlated by depth. From a detailed reservoir profile log, pay zones can be identified and correlated to uncored wells using well log curves that are calibrated to core data. Examples of this type of procedure can be found in Connolly and Reed,<ref name=pt06r19>Connolly, E. T., and P. A. Reed, 1983, Full spectrum formation evaluation: Canadian Well Logging Society Journal, v. 12, p. 23–69.</ref> Harris,<ref name=pt06r48>Harris, D. G., 1975, [https://www.onepetro.org/journal-paper/SPE-5022-PA The roles of geology in reservoir simulation studies]: Journal Petroleum of Technology, May, p. 625–632.</ref> Hearn et al.,<ref name=pt06r51>Hearn, C. L., W. J. Ebanks, Jr., R. S. Tye, and V. Ranganathan, 1984, Geological factors influencing reservoir performance of the Hartzog Draw field: Journal of Petroleum Technology, v. 36, Aug., p. 1335–1344, 10, 2118/12016-PA.</ref> and Hietala and Connolly.<ref name=pt06r53>Hietala, R. W., and E. T. Connolly, 1984, [http://archives.datapages.com/data/specpubs/fieldst4/data/a013/a013/0001/0200/0215.htm Integrated rock-log calibration in the Elmworth field, Alberta, Canada, Part II—well log analysis methods and techniques], in J. A. Masters, ed., Elmworth—Case Study of a Deep Basin Gas Field: [http://store.aapg.org/detail.aspx?id=67 AAPG Memoir 38], p. 215–242.</ref>

An important component of effective pay determination is a systematic, sedimentologically based reservoir zonation. This procedure provides a direct method of evaluating the validity and representativeness of core measurements in relation to the actual distribution of porosity, permeability, and fluid saturations within the reservoir. Core description should be integrated with well logs for calibration and correlation to uncored wells. Discussion of calibration techniques can be found in Connolly and Reed,<ref name=pt06r19 /> Hietala and Connolly,<ref name=pt06r53 /> and Sneider and King.<ref name=pt06r128>Sneider, R. M., King, H. R., 1984, Integrated rock-log calibration in the Elmworth field, Alberta, Canada—Part I, Reservoir rock detection and characterization, in Masters, J. A., ed., Elmworth—Case Study of a Deep Basin Gas Field, AAPG Memoir 38, p. 205–214.</ref>

An important component of effective pay determination is a systematic, sedimentologically based reservoir zonation. This procedure provides a direct method of evaluating the validity and representativeness of core measurements in relation to the actual distribution of porosity, permeability, and fluid saturations within the reservoir. Core description should be integrated with well logs for calibration and correlation to uncored wells. Discussion of calibration techniques can be found in Connolly and Reed,<ref name=pt06r19 /> Hietala and Connolly,<ref name=pt06r53 /> and Sneider and King.<ref name=pt06r128>Sneider, R. M., and H. R. King, 1984, [http://archives.datapages.com/data/specpubs/fieldst4/data/a013/a013/0001/0200/0205.htm Integrated rock-log calibration in the Elmworth field, Alberta, Canada—Part I, Reservoir rock detection and characterization], in J. A. Masters, ed., Elmworth—Case Study of a Deep Basin Gas Field, [http://store.aapg.org/detail.aspx?id=67 AAPG Memoir 38], p. 205–214.</ref>

Well and production tests are often taken over too large an interval in the wellbore to be precise in distinguishing pay and nonpay, especially in heterogeneous reservoirs. Spinner and temperature surveys can be good indicators of the loci of production where the borehole penetrates the reservoir if production rates are high enough. Electric logs can delineate hydrocarbon saturated intervals, but are not an effective tool for pay determination until they are calibrated with production tests, core analyses, or results from analogous reservoirs. The effective determination of pay relies on analyses from the physical sampling of reservoir and nonreservoir rocks. The different classes of information regarding reservoir behavior and pay determination may be irreconcilable or open to misinterpretation in the absence of a thoroughly understood geological framework.

Well and production tests are often taken over too large an interval in the wellbore to be precise in distinguishing pay and nonpay, especially in heterogeneous reservoirs. Spinner and temperature surveys can be good indicators of the loci of production where the borehole penetrates the reservoir if production rates are high enough. Electric logs can delineate hydrocarbon saturated intervals, but are not an effective tool for pay determination until they are calibrated with production tests, core analyses, or results from analogous reservoirs. The effective determination of pay relies on analyses from the physical sampling of reservoir and nonreservoir rocks. The different classes of information regarding reservoir behavior and pay determination may be irreconcilable or open to misinterpretation in the absence of a thoroughly understood geological framework.

Of all the methods available for the prediction of the behavior of the rock-fluid system, capillary analysis is essential in determining pay because the displacement characteristics of hydrocarbons are dependent on pore throat geometries, fluid saturations, and the respective fluid properties of immiscible wetting and nonwetting phases,

Of all the methods available for the prediction of the behavior of the rock-fluid system, capillary analysis is essential in determining pay because the displacement characteristics of hydrocarbons are dependent on pore throat geometries, fluid saturations, and the respective fluid properties of immiscible wetting and nonwetting phases,

Methods of [[capillary pressure]] analysis (such as mercury injection) and the interpretation of capillary behavior in reservoir rocks can be found in Wardlaw and Taylor.<ref name=pt06r149>Wardlaw, N. C., 1976, Pore geometry of carbonate rocks as revealed by pore casts and capillary pressure: AAPG Bulletin, v. 60, p. 245–257.</ref> Mercury injection capillary pressure curves can be readily transformed for predicting fluid behavior during production, locating transition zones, and estimating water cut during production.

Methods of [[capillary pressure]] analysis (such as mercury injection) and the interpretation of capillary behavior in reservoir rocks can be found in Wardlaw and Taylor.<ref name=pt06r149>Wardlaw, N. C., 1976, [http://archives.datapages.com/data/bulletns/1974-76/data/pg/0060/0002/0200/0245.htm Pore geometry of carbonate rocks as revealed by pore casts and capillary pressure]: AAPG Bulletin, v. 60, p. 245–257.</ref> Mercury injection capillary pressure curves can be readily transformed for predicting fluid behavior during production, locating transition zones, and estimating water cut during production.

The initial delineation of reservoir quality rocks can be obtained by crossplotting such quantities as porosity, permeability, and fluid saturation in which these attributes are identified by lithofacies, depositional environment, or any other valid geologically based description that zones the reservoir into genetically distinct units. Hydrocarbon fluid saturation within the rock pore space is ''not'' a factor in determining reservoir rock qualify. A set of guidelines that identifies reservoir quality and nonreservoir rocks in most cases is shown in Table 2. These criteria have been derived from monitoring the production history of different rock types in varied geological settings in hundreds of wells. A relative ranking system of reservoir and nonreservoir rock types can be established using this table in cases where some, but not all, criteria are met.

The initial delineation of reservoir quality rocks can be obtained by crossplotting such quantities as porosity, permeability, and fluid saturation in which these attributes are identified by lithofacies, depositional environment, or any other valid geologically based description that zones the reservoir into genetically distinct units. Hydrocarbon fluid saturation within the rock pore space is ''not'' a factor in determining reservoir rock qualify. A set of guidelines that identifies reservoir quality and nonreservoir rocks in most cases is shown in Table 2. These criteria have been derived from monitoring the production history of different rock types in varied geological settings in hundreds of wells. A relative ranking system of reservoir and nonreservoir rock types can be established using this table in cases where some, but not all, criteria are met.

|+ {{table number|Table 2}}Reservoir and nonreservoir rock criteria based on mercury (Hg) injection capillary data

|+ {{table number|Table 2}}Reservoir and nonreservoir rock criteria based on mercury (Hg) injection capillary data

|-

|-

! Criterion

! Criterion || Reservoir || Nonreservoir

! Reservoir

! Nonreservoir

|-

|-

| Initial displacement pressure (psi)

| Initial [[displacement pressure]] (psi) || <100 || >100

|

| >100

|-

|-

| [[Capillary pressure]] (psi) (1% bulk volume Hg fluid saturation)

| [[Capillary pressure]] (psi) (1% bulk volume Hg fluid saturation) || <300 || >500

|

| >500

|-

|-

| Bulk volume Hg fluid saturation at 1000 psi

| Bulk volume Hg fluid saturation at 1000 psi || >3% || <=2%

| >3%

|

|-

|-

| Bulk volume Hg fluid saturation at 2000 psi

| Bulk volume Hg fluid saturation at 2000 psi || >>3% || <=3%

| >>3%

|

|-

|-

| Distribution of effective pore throat radii at 2000 psi capillary pressure

| Distribution of effective pore throat radii at 2000 psi capillary pressure || >50% of radii ≥ 0.05 μm || >50% of radii ≤ 0.05 μm

| >50% of radii ≥ 0.05 μm

| >50% of radii ≤ 0.05 μm

|}

|}

|+ {{table number|Table 3}}Pay cutoffs based on mercury injection capillary pressure data

|+ {{table number|Table 3}}Pay cutoffs based on mercury injection capillary pressure data

|-

|-

! Classification

! Classification || Bulk Volume(%) || Pore Volume (%)

! Bulk Volume(%)

! Pore Volume (%)

|-

|-

| Pay

| rowspan = 2 | Pay || >4 || >40

| >4

| >40

|-

|-

| ~3–4 || >30–40

| ~3–4

| >30–40

|-

|-

| Intermediate

| Intermediate || ~2–3 || >22–30

| ~2–3

| >22–30

|-

|-

| Nonpay

| rowspan = 2 | Nonpay || >1–2 || >10–22

| >1–2

| >10–22

|-

|-

|

| ≥1 || ≥10

| ≥1

| ≥10

|}

|}

==See also==

==See also==

* [[Introduction to geological methods]]

* [[Introduction to geological methods]]

* [[Subsurface maps]]

* [[Subsurface maps]]

* [[Conversion of well log data to subsurface stratigraphic and structural information]]

* [[Conversion of well log data to subsurface stratigraphic and structural information]]

* [[Correlation and regression analysis]]

* [[Correlation and regression analysis]]

* [[Reservoir quality]]

* [[Reservoir quality]]

* [[Fluid contacts]]

* [[Fluid contacts]]

==References==

==References==

[[Category:Geological methods]]

[[Category:Geological methods]]