Subsurface Maps. K. W. Weissenburger. Isopach. Isochore. Conoco, Inc. Ponca City, Oklahoma, U.S.A.

Transcription

1 Subsurface Maps K. W. Weissenburger Conoco, Inc. Ponca City, Oklahoma, U.S.A. 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 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

2 Subsurface Maps MILES Figure 1. Structure map of the top of the T5 marker, Frio Formation, Brazoria County, Texas. (After Bebout et al., 1978.) pros and cons of using isochron thins and structural highs as exploration drilling criteria for dolomirized Devonian limestones. 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 the chapter on "Reserves Calculations" in Part 10). For an oil reservoir, the basic volumetric equation is as follows: N = 7758 x A x H x $ x (1 - S w )/Boi where N = original oil in place, stock tank barrels (STB) 7758 = conversion factor (acre-feet to barrels) A = area of reservoir (acres) H = height or thickness of pay zone (feet) < > = porosity (fraction of bulk volume) S w = connate water saturation (fraction of pore volume) Boi = oil formation volume factor (dimensionless, reservoir bbls/stock tank bbls) A similar basic equation applies to gas reservoirs. Net Pay The product A x H is the reservoir bulk volume, and the product A x H x ty 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

3 296 PART 6 GEOLOGICAL METHODS - V MARCH 1974 /wf [ ym "*^^ r T\I* f * *^v» rajivst \N VXV J V* \r1 K /" * ".V^ * ' / * \ \ vlnn *V"-* j< tf* * * yv*"""! * Itft»* 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 'SINK < I PATTERN I FLOOD AREA Figure 3. Map of pressure response to pattern flood, Judy Creek field, western Canada, 1974 and Contour interval is 2750 kpa. (After Jardine and Wilshart, 1987.) Water Saturation 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. The water saturation (S w ) 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 (S 0 ) 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

4 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.) Figure 5. Porosity-weighted average water saturation map for Layer 2 of a Middle Eastern carbonate reservoir. 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. 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.

5 298 PART 6 GEOLOGICAL METHODS B zone absent A A and C zones combined 10,000 feet Figure 6. Porosity thickness (4>H) maps for the B and C zones from the San Andres Formation reservoir, Jordan field, Ector and Crane Counties, Texas. Contours in PV fraction-feet. (After Major and Holtz, 1989.) Water Cut Water cut is the fraction of a liquid production stream that is water, where oil cut = 1 - water cut. Like GOR, water cut will change during the life of a reservoir, and periodic mapping can serve as a performance indicator for reservoir management. A variety of performance features can be indicated by water cut maps, including water coning, directional permeability or channeling, and formation damage. 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. 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 (Major and Holtz, 1989). In this case, porosity did not necessarily indicate effective porosity. OTHER MAPS A variety of other maps can come into play during the development of a specific reservoir. Maps of fades, facies architecture, paleoenvironment, and isolithology might be particularly important in selecting stepout well locations and planning reservoir development strategy. Other reservoir properties such as temperature can have value for specific reservoir engineering applications, particularly where potentially temperature-sensitive chemical stimulation, production, or recovery technology might be involved.

6 Subsurface Maps 299 > <250 Figure 7. Cumulative oil production map for the A, B, C, and D zones from the San Andres Formation reservoir, Jordan field, Ector and Crane counties, Texas. Contours in MSTB/year/acre. (After Major and Holtz, 1989.)