《石油地质学 Petroleum Geology》课程教学资源（阅读文献）Subsurface Maps.pdf_大学文库

Subsurface Maps K w. Weissenburger Conoco, Ine Ponca City, Oklahoma, U.S.A INTRODUCTION fields, unconformities are the location of sealing shales and/or source rocks above reservoir pay. Subcrop maps, Reservoir properties are mapped to promote optimal field traces of productive zones, barriers, or marker horizons development. Subsurface maps dictate well placement and mapped on the unconformity surface are invaluable for nable engineers to calculate reserves and monitor trends in Placement and for reservoir d reservoir performance. Geologists play a key role in subsurface mapping by using interpretations of depositional Pressure environments and diagenetic events to project reservoir data away from relatively few well control points(see other Maps of reservoir pressure are useful throughout reservoir chapters in Part 6). In this sense, subsurface mapping is in life(Figure 3). Pressures should be converted to a common reat contrast to geological mapping of the earth's surface. depth datum, such as mid-reservoir, prior to contouring.(For Whether using traditional concepts(Landes, 1951)or"high information on obtaining pressure data, see the chapters on technology"computer contouring hardware/software "Production Testing" and"Pressure Transient Testing"in systems (ones et al, 1986), mapping interwell areas places a Part 9, " Wireline Formation Testing "in Part 4, and"Drill premium on interpretation rather than straightforward Stem Testing"in Part 3. plotting of precise data. "Mapping"is here limited to ons MAPPING THICKNESSES MAPPING SURFACES Interpretations of depositional trends, pre- and yndepositional structural development, and reservoir A number of surfaces are typically mapped during storage capacity are based in large part on thickness reservoir development to show closure and other limits to information. An accurate meaning of thickness is critical in production. Maps of top of pay and bottom of pay these and other analyses (see the chapter on"Conversion of can also be"subtracted"to determine pay thickness Well Log Data to Subsurface Stratigraphic and Structural Information"in Part 6). Structure Structure maps show lines of equal elevation or depth for a selected marker horizon( Figure 1)(see the chapter on A contour map of equal values of true stratigraphic Evaluating Structurally Complex Reservoirs"in Part 6). thickness is an isopach map(Figure 4), Except for vertical wells Mean sea level is a useful reference datum. commonly in horizontal beds, corrections for wellbore deviation and contoured horizons are top of zone or top of net pay. Control formation dip are needed to make isopach maps oints are provided by surveyed wells and can be supplemented by seismic interpretations, especially offshore. Isochore In highly developed fields, typically onshore, sufficient well control might exist to allow geostatistical interpolation A contour map of equal values of true vertical thickness is between control points(see Part 8 n isochore map(Tucker 1988). Note that in common practice, isochore maps are informally referred to as "isopach"maps, a Fault planes term that properly should be restricted to true stratigraphic thickness Faults are special surfaces whose traces will show structure contour maps(Figures 1 and 2). Faults form Isochron bounding surfaces for some reservoirs, and sufficient well ontrol might exist to contour map the fault surface itself An isochron map is a contour map of equal values of seismic Projections of subsurface data into the plane of the fault are traveltime between selected events(Tucker,1988).Isochron appropriately described as cross sections. (For details of are intended to derive thickness information from seismic of fault pl e the ch data. Isochroning between events above and below a pay Conversion of Well Log Data to Subsurface Stratigraphic and horizon, for example, would estimate pay thickness. Renick Structural Information"in Part 6) and Gunn(1989)present a good case history of using isochron and time-structure maps to generate"isopach"and Unconformities and Subcrop levation-structure maps. Their isochron-isopach approach delineated reef trends for further development drilling and Surfaces of unconformity can be especially useful marker used well penetrations through a shallow horizon for depth horizons for structure contour mapping (Figure 2). In many control on a deeper horizon. Phipps(1989)documents the

Subsurface Maps INTRODUCTION 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 Part 6). In this sense, subsurface mapping is in great contrast to geological mapping of the earth's surface. Whether using traditional concepts (Landes, 1951) or "high technology" computer contouring hardware/software systems (Jones et al., 1986), 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 A number of surfaces are typically mapped during reservoir development to show closure and other limits to reservoir production. Maps of top of pay and bottom of pay can also be "subtracted" to determine pay thickness. Structure Structure maps show lines of equal elevation or depth for a selected marker horizon (Figure 1) (see the chapter on "Evaluating Structurally Complex Reservoirs" in Part 6). 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 interpretations, especially offshore. In highly developed fields, typically onshore, sufficient well control might exist to allow geostatistical interpolation between control points (see Part 8). Fault Planes Faults are special surfaces whose traces will show on structure contour maps (Figures 1 and 2). Faults form bounding surfaces for some reservoirs, and sufficient well control might exist to contour map the fault surface itself. Projections of subsurface data into the plane of the fault are also useful "maps" for reservoir development, but are more appropriately described as cross sections. (For details of construction of fault plane maps, see the chapter on "Conversion of Well Log Data to Subsurface Stratigraphic and Structural Information" in Part 6.) Unconformities and Subcrops Surfaces of unconformity can be especially useful marker horizons for structure contour mapping (Figure 2). In many K. W. Weissenburger Conoco, Inc. Ponca City, Oklahoma, U.S.A. fields, unconformities are the location of sealing shales and/or source rocks above reservoir pay. Subcrop maps, traces of productive zones, barriers, or marker horizons mapped on the unconformity surface are invaluable for planning well placement and for reservoir development. Pressure Maps of reservoir pressure are useful throughout reservoir life (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.) MAPPING THICKNESSES 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 the chapter on "Conversion of Well Log Data to Subsurface Stratigraphic and Structural Information" in Part 6). Isopach A contour map of equal values of true stratigraphic thickness is an isopach map (Figure 4). Except for vertical wells in horizontal beds, corrections for wellbore deviation and formation dip are needed to make isopach maps. Isochore A contour map of equal values of true vertical thickness is an isochore map (Tucker, 1988). 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 An isochron map is a contour map of equal values of seismic travelfime between selected events (Tucker, 1988). 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 (1989) 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 (1989) documents the

296 PART6-GEOLOGICAL METHODS 21232 ● BOTTOM CTOR SIRE SURE v OUR INTERVAL field western Canada, 1974 and 1975. Contour Interval is 2750 kPa.(After Jardine and wishart, 1987. Water Saturation The water saturation(Sw)within the net pay interval is typically estimated from well logs. Water saturations can also be derived from capillary pressure testing of cores to determine the relationship of water saturation versus heigl above the oil-water contact(see the chapter on"Capillary Pressure"in Part 5). Like porosity, the water saturation data in an individual well within the net pay interval can be averaged arithmetically and posted on a map for contouring (Figure 5). The averages should be weighted by porosity Figure 2. structure of the base of the humber unconformity( top of the Brent Group), Dunlin fleld, U. K. Northern North Sea Oil Saturation mapped with 1979 and 1989 vintage data. Contours are marked in ft subsea x 100; contour Interval is 100 ft( From Braithwaite In an oil-water system, the water saturation and oil eal,198) saturation(S)sum to 1. Therefore, once S,, has been determined, oil saturation can be calculated and mapped as S=1-S should be contoured using well control points and interpolated or extrapolated using available seismic and wel test data and the geologists interpretation of depositional and MAPPING FOR RESERVOIR MANAGEMENT diagenetic history (see the chapter on"Effective Pay Deter- A variety of maps are used to predict or monitor reservoir mination"in Part 6)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 Permeability )having porosity and /or permeability values below a cutoff limit for productivity. Not all net pay is necessarily Permeability ()can also be mapped and contoured(see productive at a given well spacing. Discontinuous productive Transformations and Porosity-Permeability Relationships"in horizons between wells might be described, for example, by Part 5). As for saturation values, some care must be exercised concept of net pay to net connected pay ratio(Poston, n mapping permeability because values must be derived from indirect measurements. Typically, permeabilities are Porosity The porosity (o)in a reservoir zone can be determined Permeabilities can be reported at ambient laboratory from log and/or core data(see the chapter on"Porosity"in conditions of pressure or adjusted to reservoir conditions of Part 5). The data in an individual well within the net pay confining pressure. Similarly, permeabilities can be absolute interval can be averaged arithmetically and posted on a map permeabilities to air(nitrogen )or liquid or effective for contouring. The averages should be weighted by permeabilities to oil in the presence of irreducible water thickness Permeability values in an individual well are thickness

296 PART 6—GEOLOGICAL METHODS Figure 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 x 100; contour interval is 100 ft. (From Bralthwaite et al., 1989.) 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 the chapter on "Effective Pay Determination" in Part 6) 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 (Poston, 1987). Porosity The porosity ((ji) in a reservoir zone can be determined from log and /or core data (see the chapter on "Porosity" in Part 5). 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. - V MARCH 1974 / w f [• ym •"*^^ r T\I* f • * *^v» rAjivSt \N VX V J V* •\r1 K •/" * " .V^ * ' / * \ \ vlnn *V"-*j<tf* * * yV*"""! * It ft»* J^?"- " i* r*'~^t \R&jEfiB3$y / • \?jS • • y 7 ••" • y ^y 5km • BOTTOM WATER INJECTOR . PERIPHERAL ' WATER INJECTOR PATTERN WATER INJECTOR CONTOUR INTERVAL 2750 kPa • PRESSURE 'SIN< K I PATTERN I FLOOD AREA Figure 3. Map of pressure response to pattern flood, Judy Creek field, western Canada, 1974 and 1975. Contour interval is 2750 kPa. (After Jardine and Wilshart, 1987.) Water Saturation The water saturation (Sw) within the net pay interval is typically estimated from well logs. Water saturations can also be derived from capillary pressure testing of cores to determine the relationship of water saturation versus height above the oil-water contact (see the chapter on "Capillary Pressure" in Part 5). Like porosity, the water saturation data in an individual well within the net pay interval can be averaged arithmetically and posted on a map for contouring (Figure 5). The averages should be weighted by porosity. Oil Saturation In an oil-water system, the water saturation and oil saturation (S0) sum to 1. Therefore, once S w has been determined, oil saturation can be calculated and mapped as S„ = l-S„ , MAPPING FOR RESERVOIR MANAGEMENT A variety of maps are used to predict or monitor reservoir performance. Permeability Permeability (k) can also be mapped and contoured (see the chapters on "Permeability" and "Core-Log Transformations and Porosity-Permeability Relationships" in Part 5). 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

a) LEDUC NET PAY ISOPACH MAP (b) CONTOUR INTERVAL.0 1 PORE VOLUME Figure 4.(a)Cross section and (b) net pay isopach map of the Strachan gas field, western Canada. Contour Interval Is 100 ft. Figure 5. Porosity-weighted average water saturation map for (From Hriskevlch et al., 1980. weighted and typically averaged harmonically, arithmetically, or geometrically, depending geometry. Alternatively, Solution Gas to Oil Ratio flow capacity (kH) values derived from pressure transient Engineers forecast ultimate recoverable e reserves by testing can be divided by net pay thickness (H) to yield a applying material balance equations or decline curve analysis quid permeability value for a well to production history records. For example, in type reservoir, the solution gas to oil ratio is sometimes Porosity Thickness plotted versus cumulative oil production on semilog paper Reservoir storage capacity or porosity thickness(H) is the (Garb and Smith, 1987).If such product of porosity and net pay (Figure 6) straight-line relationship, the curve can be used to predict the trend of a cumulative gas or cumulative oil plot to estimate Productivity Index ultimate recovery The solution gas to oil ratio(GOR) is the amount of To avoid coning, sand production, pipe collapse, or other dissolved gas that will evolve from the oil as the pressure is harmful effects, wells might not be produced at the reduced to atmospheric from some higher pressure. GOR maximum wide-open flow rates. Therefore, the ability of a usually expressed in units of SCf gas /STB oil. a barrel of oil well to produce is usually determined by a productivity index and its solution gas at reservoir conditions of temperature and PI(Kimmel and Dalati, 1987). The Pl is a measure of the pressure will usually"shrink"as the fluid is produced and stock tank barrels(STB)of oil produced per day per psi brought to stock tank conditions (normally reported at 60F conditions(see the chapter on"Production Testing"in Part 9). for individual wells can be mapped periodically to identify Changes will show on periodic maps of PI during reservoir areas of the reservoir receiving or not receiving pressure life indicating trends in reservoir depletion or formation support and serving as indicators for reservoir managemen

Subsurface Maps 297 Figure 4. (a) Cross section and (b) net pay Isopach map of the Strachan gas field, western Canada. Contour Interval is 100 ft. (From Hriskevlch et al., 1980.) 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 Reservoir storage capacity or porosity thickness (§H) is the product of porosity and net pay (Figure 6). 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) (Kimmel and Dalati, 1987). 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 the chapter on "Production Testing" in Part 9). Changes will show on periodic maps of PI during reservoir life indicating trends in reservoir depletion or formation damage. Figure 5. Porosity-weighted average water saturation map for Layer 2 of a Middle Eastern carbonate reservoir. 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 depletiontype reservoir, the solution gas to oil ratio is sometimes plotted versus cumulative oil production on semilog paper (Garb and Smith, 1987). 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 60 T 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