We determine net pay by applying appropriate cutoffs to reservoir properties so that unproductive or uneconomic layers are not counted. This can be done with both log and core data. Routine, or
conventional, core analysis data can be summed and averaged to
obtain mappable reservoir properties, just like log analysis
results. These mappable properties are also used to compare log
analysis results to core data. If the mappable properties do not
match over the same rock interval, some adjustments must be made to
the log analysis. Be sure to depth match the core to the logs first,
and take into account macro and micro fractures that the logs cannot
see. Laminated reservoirs may cause point by point differences but
the average values of log and core properties should be similar.
Typical cutoffs are:
1: IF (Vsh <= VSHmax)
* (PHIe >= PHImin) * (Sw <= SWmax) * (Perm >= PERMmin)
= 1
Where:
PHImin = 0.03 to 0.16 SWmax = 0.30 to 0.70
PERMmin = 0.01
to 5.0 mD
In
reservoir simulation work, the Net Reservoir is also needed. In
this case, set SWmax = 1.00. The result of equations 1 to 4 for
this case is Hres instead of Hnet.
Some
people are interested in "Net to Gross Ratio" but they have to be
specific as to whether they mean: COMMENTS: Some cutoffs may be set high enough or low enough so as not to be effective. For example, if PERMmin = 0, then no value of Perm could be less than PERMmin, so permeability could not fail to pass a layer. More than one set of cutoffs are normally run and the results compared to find the set that appears to give reasonable results when compared to production profiles in the area. Since porosity is somewhat proportional to shale volume, saturation somewhat proportional to porosity, and permeability somewhat proportional to all three, it is desirable to choose a balanced set of cutoffs. Balanced cutoffs in a hydrocarbon bearing zone usually will fail a layer with more than one cutoff. If only one cutoff fails a layer, the cutoffs may need some adjustment.
Cutoffs can be tested against production flowmeter data and can be tuned, in some cases, based on actual production rates
1: IF PHIe < PHImim THEN PAYFLAG$ = "TIGHT" 2: OR IF Sw > SWmax THEN PAYFLAG$ = "WET" 3: OR IF Perm < PERMmin THEN PAYFLAG$ = "LOWPERM" 4: OR IF Vsh > VSHmax THEN PAYFLAG$ = "SHALY" 5: OTHERWISE PAYFLAG$ = "PAYZONE" 6: IF PHIdc >= PHInc + TOLER THEN PRODFLAG$ = "GAS" 6: IF PHIdc < PHInc + TOLER THEN PRODFLAG$ = "OIL" 7: IF PHIe * Sw > PHIxSWmax THEN PRODFLAG$ = "H2O" 8: Hnet = SUM (PAYFLAG$ = "PAYZONE" * INCR) Sonic neutron crossover can also be used to test for "GAS" flag.
Where:
PHImax SWmax PERMmin VSHmin PHIxSW 0.00 1.0 0.0 0.0 1.00 0.15 0.5 5.0 0.3 0.07 0.20 0.4 10.0 0.3 0.07 0.25 0.3 15.0 0.3 0.07
2.
Low porosity set:
Close spaced DST's can also be used in open or cased hole to simulate a flowmeter profile. You can mimic this in the lab with flow tests in core plugs using reservoir fluids under simulated formation pressure and temperature. However, hardly anyone actually does either flowmeter or core flow analysis because it is expensive and often means completing or coring poor quality rock to find out how low the cutoffs can be set. The pragmatic approach is much more widely used. 1. Plot core porosity vs logarithm of core permeability. Fit a semi-log line through the data points (exclude fractured plugs). For gas use a perm cutoff of 0.1 to 1.0 md, for oil use 1.0 to 5.0 md. Find the equivalent porosity on this graph corresponding to the selected perm cutoff. This is your porosity cutoff. 2. Plot porosity vs water saturation in the oil or gas leg above the transition zone. This can be log analysis data or values from capillary pressure curves. Fit a hyperbolic line through the data. Enter with porosity cutoff and find corresponding SW. This is the SW cutoff. 3. In shaly sands, plot porosity vs shale volume. Enter graph with porosity cutoff and pick corresponding shale volume. This is Vsh cutoff. This is called a coordinated cutoff set. Reservoir engineers sometimes plot cumulative porosity or permeability or both (sort data into ascending order first). They then place the cutoff at the 5 or 10% accumulation. This is exceedingly arbitrary but was a widespread method. It was only vaguely useful if the core contained no poor quality rock or if there was no spread in the rock properties.
To find the beginning of a possible pay zone, search from the top of the computed interval for the first data set with a "pass" in its cutoff field. Then find the first deeper level with a "fail" in its cutoff field. The depths of these two points define the top (ZONETOP) and bottom (ZONEBOTTOM) of a zone. This interval thickness is tested against the acceptance criteria. The depth of the next pay zone top is then found and the interval between pay zones tested against the rejection criteria.
1:
IF PAYFLAG$ ="OIL" Repeat these steps until the bottom of the computation interval is reached. At this time each level computed will have two flags set - one to indicate whether it passed cutoffs (CUTOFF$) and whether the layer is considered part of a pay zone (PAYFLAG$), even if it failed its cutoffs. To find net pay thickness, count the number of levels with the pay flag equal to "pay" and multiply by the depth increment between the data points.
32:
Hnet = Sum ((IF PAYFLAG$ = "PAY") * THICKi)
Where: COMMENTS: 39: Hnet = Sum ((IF PAYFLAG$ = "PAY" AND IF CUTOFF$ = "PASS") * THICKi)
1.
If cutoffs are: Then net pay extends from 2054.1 to include 2063.1. 2. If SWcut is lowered to 50.0, then net pay covers 2054.1 to 2059.5 and 2061.9 to 2062.2 in two zones. 3. If HREJECT = 3 m, then these two pay zones combine to form one zone because the rejected interval is less than 3.0 m. 4. If HACCEPT = 3.0 m, then the second zone is not pay because it is not thick enough.
Rejected
intervals are included in the zone for Case 3 and contribute to
net pay thickness. |
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