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Reservoir properties are mapped to promote optimal field development. Subsurface maps dictate well placement and enable engineers to calculate reserves and monitor trends in reservoir performance. Geologists play a key role in subsurface mapping by using interpretations of depositional environments and diagenetic events to project reservoir data away from relatively few well control points (see other chapters). In this sense, subsurface mapping is in great contrast to geological mapping of the earth's surface. Whether using traditional concepts<ref name=pt06r71>Landes, K. L., 1951, Subsurface maps and sections, in Petroleum Geology: New York, John Wiley, 660 p.</ref> or “high technology” computer contouring hardware/software systems<ref name=pt06r60>Jones, T. A., Hamilton, D. E., Johnson, C. R., 1986, Contouring geologic surfaces with the computer: New York, Van Nostrand Reinhold, 320 p.</ref>, mapping interwell areas places a premium on interpretation rather than straightforward plotting of precise data. “Mapping” is here limited to projections in plan view.

Reservoir properties are mapped to promote optimal field development. Subsurface maps dictate well placement and enable engineers to calculate reserves and monitor trends in reservoir performance. Geologists play a key role in subsurface mapping by using interpretations of depositional environments and diagenetic events to project reservoir data away from relatively few well control points. In this sense, subsurface mapping is in great contrast to geological mapping of the earth's surface. Whether using traditional concepts<ref name=pt06r71>Landes, K. L., 1951, Subsurface maps and sections, in Petroleum Geology: New York, John Wiley, 660 p.</ref> or “high technology” computer contouring hardware/software systems,<ref name=pt06r60>Jones, T. A., Hamilton, D. E., Johnson, C. R., 1986, Contouring geologic surfaces with the computer: New York, Van Nostrand Reinhold, 320 p.</ref> mapping interwell areas places a premium on interpretation rather than straightforward plotting of precise data. “Mapping” is here limited to projections in plan view.

==Mapping surfaces==

==Mapping surfaces==

===Structure===

===Structure===

Structure maps show lines of equal elevation or depth for a selected marker horizon ([[:file:subsurface-maps_fig1.png|Figure 1]]) (see [[Evaluating structurally complex reservoirs]]). Mean sea level is a useful reference datum. Commonly contoured horizons are top of zone or top of net pay. Control points are provided by surveyed wells and can be supplemented by [[seismic interpretation]]s, especially offshore. In highly developed fields, typically onshore, sufficient well control might exist to allow geostatistical interpolation between control points (see Part 8).

Structure maps show lines of equal elevation or depth for a selected marker horizon ([[:file:subsurface-maps_fig1.png|Figure 1]]) (see [[Evaluating structurally complex reservoirs]]). Mean sea level is a useful reference datum. Commonly contoured horizons are top of zone or top of net pay. Control points are provided by surveyed wells and can be supplemented by [[seismic interpretation]]s, especially offshore. In highly developed fields, typically onshore, sufficient well control might exist to allow geostatistical interpolation between control points.

[[file:subsurface-maps_fig2.png|thumb|{{figure number|2}}Structure of the base of the Humber unconformity (top of the Brent Group), Dunlin field, U.K. Northern North Sea mapped with 1979 and 1989 vintage data. Contours are marked in ft subsea × 100; contour interval is 100 ft. (From <ref name=pt06r16>Braithwaite, C. I. M., Marshall, J. D., Holland, T. C., 1989, Improving recovery from the Dunlin field, U., K. Northern North Sea, in Formation Evaluation and Reservoir Geology: 64th Annual Technical Conference of the Society of Petroleum Engineers, San Antonio, TX, Oct. 8–11, SPE 19878, 18 p.</ref>.)]]

[[file:subsurface-maps_fig2.png|thumb|{{figure number|2}}Structure of the base of the Humber unconformity (top of the Brent Group), Dunlin field, U.K. Northern North Sea mapped with 1979 and 1989 vintage data. Contours are marked in ft subsea × 100; contour interval is 100 ft. (From <ref name=pt06r16>Braithwaite, C. I. M., Marshall, J. D., Holland, T. C., 1989, Improving recovery from the Dunlin field, U., K. Northern North Sea, in Formation Evaluation and Reservoir Geology: 64th Annual Technical Conference of the Society of Petroleum Engineers, San Antonio, TX, Oct. 8–11, SPE 19878, 18 p.</ref>.)]]

===Pressure===

===Pressure===

Maps of reservoir pressure are useful throughout reservoir life ([[:file:subsurface-maps_fig3.png|Figure 3]]). Pressures should be converted to a common depth datum, such as mid-reservoir, prior to contouring. (For information on obtaining pressure data, see the chapters on [[Production testing]] and [[Pressure transient testing]] in Part 9, “Wireline Formation Testing” in Part 4, and [[Drill stem testing]] in Part 3.)

Maps of reservoir pressure are useful throughout reservoir life ([[:file:subsurface-maps_fig3.png|Figure 3]]). Pressures should be converted to a common depth datum, such as mid-reservoir, prior to contouring. (For information on obtaining pressure data, see [[Production testing]] and [[Pressure transient testing]], [[Wireline formation testers]], and [[Drill stem testing]].)

==Mapping thicknesses==

==Mapping thicknesses==

[[file:subsurface-maps_fig4.png|thumb|{{figure number|4}}(a) Cross section and (b) net pay Isopach map of the Strachan gas field, western Canada. Contour Interval is 100 ft. (From <ref name=pt06r55>Hriskevich, M. E., Faber, J. M., Langton, J. R., 1980, [http://archives.datapages.com/data/specpubs/fieldst2/data/a012/a012/0001/0300/0315.htm Strachan and Ricinus West gas fields], Alberta, Canada, in Halbouty, M. T., ed., Giant Oil and Gas Fields of the Decade 1968–1978: AAPG Memoir 30, p. 315–327.</ref>.)]]

[[file:subsurface-maps_fig4.png|thumb|{{figure number|4}}(a) Cross section and (b) net pay Isopach map of the Strachan gas field, western Canada. Contour Interval is 100 ft. (From <ref name=pt06r55>Hriskevich, M. E., Faber, J. M., Langton, J. R., 1980, [http://archives.datapages.com/data/specpubs/fieldst2/data/a012/a012/0001/0300/0315.htm Strachan and Ricinus West gas fields], Alberta, Canada, in Halbouty, M. T., ed., Giant Oil and Gas Fields of the Decade 1968–1978: AAPG Memoir 30, p. 315–327.</ref>.)]]

Interpretations of depositional trends, pre- and syndepositional structural development, and reservoir storage capacity are based in large part on thickness information. An accurate meaning of thickness is critical in these and other analyses (see “Conversion of Well Log Data to Subsurface Stratigraphic and Structural Information”).

Interpretations of depositional trends, pre- and syndepositional structural development, and reservoir storage capacity are based in large part on thickness information. An accurate meaning of thickness is critical in these and other analyses (see [[Conversion of well log data to subsurface stratigraphic and structural information]]).

===Isopach===

===Isopach===

===Isochore===

===Isochore===

A contour map of equal values of true vertical thickness is an ''isochore map''<ref name=pt06r141>Tucker, P. M., 1988, Seismic contouring—a unique skill: Geophysics, v. 53, n. 6, p. 741–749., 10., 1190/1., 1442509</ref>. Note that in common practice, isochore maps are informally referred to as “isopach” maps, a term that properly should be restricted to true stratigraphic thickness.

A contour map of equal values of true vertical thickness is an ''isochore map.''<ref name=pt06r141>Tucker, P. M., 1988, Seismic contouring—a unique skill: Geophysics, v. 53, n. 6, p. 741–749, DOI: 10.1190/1.1442509.</ref> Note that in common practice, isochore maps are informally referred to as “isopach” maps, a term that properly should be restricted to true stratigraphic thickness.

===Isochron===

===Isochron===

An ''isochron map'' is a contour map of equal values of seismic travelfime between selected events<ref name=pt06r141 />). Isochron maps are the seismic analog of isochore maps and, as such, are intended to derive thickness information from seismic data. Isochroning between events above and below a pay horizon, for example, would estimate pay thickness. Renick and Gunn<ref name=pt06r109>Renick, H. Jr., Gunn, R. D., 1989, Triangle Ranch Headquarters field development using shallow core holes and high-resolution seismic data: Geophysics, v. 54, n. 11, p. 1384–1396., 10., 1190/1., 1442602</ref> present a good case history of using isochron and time-structure maps to generate “isopach” and elevation-structure maps. Their isochron-isopach approach delineated reef trends for further development drilling and used well penetrations through a shallow horizon for depth control on a deeper horizon. Phipps<ref name=pt06r99>Phipps, G. G., 1989, Exploring for dolomitized Slave Point carbonates in northeastern British Columbia: Geophysics, v. 54, n. 7, p. 806–814., 10., 1190/1., 1442709</ref> documents the pros and cons of using isochron thins and structural highs as exploration drilling criteria for dolomitized Devonian limestones.

An ''isochron map'' is a contour map of equal values of seismic traveltime between selected events.<ref name=pt06r141 /> Isochron maps are the seismic analog of isochore maps and, as such, are intended to derive thickness information from seismic data. Isochroning between events above and below a pay horizon, for example, would estimate pay thickness. Renick and Gunn<ref name=pt06r109>Renick, H. Jr., Gunn, R. D., 1989, Triangle Ranch Headquarters field development using shallow core holes and high-resolution seismic data: Geophysics, v. 54, n. 11, p. 1384–1396, DOI: 10.1190/1.1442602</ref> present a good case history of using isochron and time-structure maps to generate “isopach” and elevation-structure maps. Their isochron-isopach approach delineated reef trends for further development drilling and used well penetrations through a shallow horizon for depth control on a deeper horizon. Phipps<ref name=pt06r99>Phipps, G. G., 1989, Exploring for dolomitized Slave Point carbonates in northeastern British Columbia: Geophysics, v. 54, n. 7, p. 806–814, DOI: 10.1190/1.1442709</ref> documents the pros and cons of using isochron thins and structural highs as exploration drilling criteria for dolomitized Devonian limestones.

==Mapping to calculate reserves==

==Mapping to calculate reserves==

When few production performance data are available, typically early in the life of a reservoir, reserves can be calculated by a volumetric analysis (see “Reserves Calculations”). For an oil reservoir, the basic volumetric equation is as follows:

When few production performance data are available, typically early in the life of a reservoir, reserves can be calculated by a volumetric analysis (see [[Reserves estimation]]). For an oil reservoir, the basic volumetric equation is as follows:

:<math>N = 7758 \times A \times H \times \phi \times (1 - S_{\rm w})/\mbox{Boi}</math>

:<math>N = 7758 \times A \times H \times \phi \times (1 - S_{\rm w})/\mbox{Boi}</math>

The product ''A'' × ''H'' is the reservoir bulk volume, and the product ''A'' × ''H'' × ϕ is the reservoir pore volume. The general determination of bulk reservoir volume involves mapping reservoir area in plan view and mapping net pay in terms of true vertical thickness to provide a common presentation of dipping beds or deviated wells. An isochore map of net pay should be contoured using well control points and interpolated or extrapolated using available seismic and well test data and the geologist's interpretation of depositional and diagenetic history.

The product ''A'' × ''H'' is the reservoir bulk volume, and the product ''A'' × ''H'' × ϕ is the reservoir pore volume. The general determination of bulk reservoir volume involves mapping reservoir area in plan view and mapping net pay in terms of true vertical thickness to provide a common presentation of dipping beds or deviated wells. An isochore map of net pay should be contoured using well control points and interpolated or extrapolated using available seismic and well test data and the geologist's interpretation of depositional and diagenetic history.

“Net” pay (see [[Effective pay determination]]) implies that some formation thickness has been excluded from consideration by either (1) occurring below an oil-water contact (or above a gas-water contact), or (2) having porosity and/or [[permeability]] values below a “cutoff” limit for productivity. Not all net pay is necessarily productive at a given well spacing. Discontinuous productive horizons between wells might be described, for example, by the concept of net pay to net connected pay ratio<ref name=pt06r103>Poston, S. W., 1987, Development plan for oil and gas reservoirs, in Bradley, H. B., ed., Petroleum Engineering Handbook: Richardson, TX, Society of Petroleum Engineers, p. 36-1–36-11.</ref>.

“Net” pay (see [[Effective pay determination]]) implies that some formation thickness has been excluded from consideration by either (1) occurring below an oil-water contact (or above a gas-water contact), or (2) having porosity and/or [[permeability]] values below a “cutoff” limit for productivity. Not all net pay is necessarily productive at a given well spacing. Discontinuous productive horizons between wells might be described, for example, by the concept of net pay to net connected pay ratio.<ref name=pt06r103>Poston, S. W., 1987, Development plan for oil and gas reservoirs, in Bradley, H. B., ed., Petroleum Engineering Handbook: Richardson, TX, Society of Petroleum Engineers, p. 36-1–36-11.</ref>

[[file:subsurface-maps_fig5.png|thumb|left|{{figure number|5}}Porosity-weighted average water saturation map for Layer 2 of a Middle Eastern carbonate reservoir.]]

[[file:subsurface-maps_fig5.png|thumb|left|{{figure number|5}}Porosity-weighted average water saturation map for Layer 2 of a Middle Eastern carbonate reservoir.]]

===[[Porosity]]===

===[[Porosity]]===

The porosity (ϕ) in a reservoir zone can be determined from log and/or core data (see “Porosity”). The data in an individual well within the net pay interval can be averaged arithmetically and posted on a map for contouring. The averages should be weighted by thickness.

The porosity (ϕ) in a reservoir zone can be determined from log and/or core data (see [[Porosity]]). The data in an individual well within the net pay interval can be averaged arithmetically and posted on a map for contouring. The averages should be weighted by thickness.

===Water saturation===

===Water saturation===

===[[Permeability]]===

===[[Permeability]]===

Permeability (''k'') can also be mapped and contoured (see “Permeability” and “Core-Log Transformations and Porosity-Permeability Relationships”). As for saturation values, some care must be exercised in mapping permeability because values must be derived from indirect measurements. Typically, permeabilities are derived from wireline log porosities transformed on the basis of core permeability versus porosity cross plots. Permeabilities can be reported at ambient laboratory conditions of pressure or adjusted to reservoir conditions of confining pressure. Similarly, permeabilities can be absolute permeabilities to air (nitrogen) or liquid or effective permeabilities to oil in the presence of irreducible water. Permeability values in an individual well are thickness weighted and typically averaged harmonically, arithmetically, or geometrically, depending on flow geometry. Alternatively, flow capacity (''kH'') values derived from [[pressure transient testing]] can be divided by net pay thickness (''H'') to yield a liquid permeability value for a well.

Permeability (''k'') can also be mapped and contoured (see [[Permeability]] and [[Core-log transformations and porosity-permeability relationships]]). As for saturation values, some care must be exercised in mapping permeability because values must be derived from indirect measurements. Typically, permeabilities are derived from wireline log porosities transformed on the basis of core permeability versus porosity cross plots. Permeabilities can be reported at ambient laboratory conditions of pressure or adjusted to reservoir conditions of confining pressure. Similarly, permeabilities can be absolute permeabilities to air (nitrogen) or liquid or effective permeabilities to oil in the presence of irreducible water. Permeability values in an individual well are thickness weighted and typically averaged harmonically, arithmetically, or geometrically, depending on flow geometry. Alternatively, flow capacity (''kH'') values derived from [[pressure transient testing]] can be divided by net pay thickness (''H'') to yield a liquid permeability value for a well.

===Porosity thickness===

===Porosity thickness===

===Productivity index===

===Productivity index===

To avoid coning, sand production, pipe collapse, or other harmful effects, wells might not be produced at their maximum wide-open flow rates. Therefore, the ability of a well to produce is usually determined by a productivity index (PI<ref name=pt06r66>Kimmel, J. D., Dalati, R. N., 1987, Potential tests of oil wells, in Bradley, H. B., ed., Petroleum Engineering Handbook: Richardson, TX, Society of Petroleum Engineers, p. 32-1–32-16.</ref>. The PI is a measure of the stock tank barrels (STB) of oil produced per day per psi drawdown under steady-state or pseudosteady-state flow conditions (see “Production Testing”). Changes will show on periodic maps of PI during reservoir life indicating trends in reservoir depletion or formation damage.

To avoid coning, sand production, pipe collapse, or other harmful effects, wells might not be produced at their maximum wide-open flow rates. Therefore, the ability of a well to produce is usually determined by a productivity index (PI).<ref name=pt06r66>Kimmel, J. D., Dalati, R. N., 1987, Potential tests of oil wells, in Bradley, H. B., ed., Petroleum Engineering Handbook: Richardson, TX, Society of Petroleum Engineers, p. 32-1–32-16.</ref> The PI is a measure of the stock tank barrels (STB) of oil produced per day per psi drawdown under steady-state or pseudosteady-state flow conditions (see [[Production testing]]). Changes will show on periodic maps of PI during reservoir life indicating trends in reservoir depletion or formation damage.

===Solution gas to oil ratio===

===Solution gas to oil ratio===

Engineers forecast ultimate recoverable reserves by applying material balance equations or decline curve analysis to production history records. For example, in a depletion-type reservoir, the solution gas to oil ratio is sometimes plotted versus cumulative oil production on semilog paper<ref name=pt06r37>Garb, F. A., Smith, G. L., 1987, Estimation of oil and gas reserves, in Bradley, H. B., ed., Petroleum Engineering Handbook: Richardson, TX, Society of Petroleum Engineers, p. 4-1–40-38.</ref>. If such a curve shows a good straight-line relationship, the curve can be used to predict the trend of a cumulative gas or cumulative oil plot to estimate ultimate recovery.

Engineers forecast ultimate recoverable reserves by applying material balance equations or decline curve analysis to production history records. For example, in a depletion-type reservoir, the solution gas to oil ratio is sometimes plotted versus cumulative oil production on semilog paper.<ref name=pt06r37>Garb, F. A., Smith, G. L., 1987, Estimation of oil and gas reserves, in Bradley, H. B., ed., Petroleum Engineering Handbook: Richardson, TX, Society of Petroleum Engineers, p. 4-1–40-38.</ref> If such a curve shows a good straight-line relationship, the curve can be used to predict the trend of a cumulative gas or cumulative oil plot to estimate ultimate recovery.

The solution gas to oil ratio (GOR) is the amount of dissolved gas that will evolve from the oil as the pressure is reduced to atmospheric from some higher pressure. GOR is usually expressed in units of SCF gas/STB oil. A barrel of oil and its solution gas at reservoir conditions of temperature and pressure will usually “shrink” as the fluid is produced and brought to stock tank conditions (normally reported at [[temperature::60&deg;F]] and 14.7 psia). As GOR changes during reservoir life, GORs for individual wells can be mapped periodically to identify areas of the reservoir receiving or not receiving pressure support and serving as indicators for reservoir management action.

The solution gas to oil ratio (GOR) is the amount of dissolved gas that will evolve from the oil as the pressure is reduced to atmospheric from some higher pressure. GOR is usually expressed in units of SCF gas/STB oil. A barrel of oil and its solution gas at reservoir conditions of temperature and pressure will usually “shrink” as the fluid is produced and brought to stock tank conditions (normally reported at [[temperature::60&deg;F]] and 14.7 psia). As GOR changes during reservoir life, GORs for individual wells can be mapped periodically to identify areas of the reservoir receiving or not receiving pressure support and serving as indicators for reservoir management action.

===Cumulative production===

===Cumulative production===

Cumulative oil or gas production is a parameter useful for ultimate reserves forecasts. Cumulative production can also be mapped periodically as a performance indicator signaling areas of the reservoir that may be responding in a manner seemingly unrelated to initial potential. [[:file:subsurface-maps_fig7.png|Figure 7]] shows an example of cumulative production that was concluded to be only poorly correlated to storage capacity (Figure 6) in individual and summed zones of a carbonate reservoir<ref name=pt06r81 />. In this case, porosity did not necessarily indicate effective porosity.

Cumulative oil or gas production is a parameter useful for ultimate reserves forecasts. Cumulative production can also be mapped periodically as a performance indicator signaling areas of the reservoir that may be responding in a manner seemingly unrelated to initial potential. [[:file:subsurface-maps_fig7.png|Figure 7]] shows an example of cumulative production that was concluded to be only poorly correlated to storage capacity (Figure 6) in individual and summed zones of a carbonate reservoir.<ref name=pt06r81 /> In this case, porosity did not necessarily indicate effective porosity.

==Other maps==

==Other maps==