Flow capacity is the product of permeability and reservoir interval thickness: KH = Perm * THICK. The result is measured in mD-feet or mD-meters. When summed across a reservoir and normalized between 0 and 100%, it is called the cumulative flow capacity or KH% curve. Flow capacity translates directly into estimated productivity and ultimately into cash flow.

The KH% curve is plotted versus depth on a scale of 0 to 100%, accumulated from the base of a reservoir to the top. Thus the curve will gradually shift to the right as KH% increasers upward.

There will be portions of the curve that are nearly vertical and other portions with a slope toward higher KH%. Vertical intervals show zones that failed cutoffs or with insignificant flow capacity. Intervals showing slope on the KH% curve are the best candidates for completion, stimulation, or horizontal well placement. Intervals with a vertical KH% curve are not good candidates for further expenditures, regardless of their other apparent "good" qualities..

The KH% curve will have the same shape as a spinner flowmeter survey on a production log. Since spinner surveys are not possible in wells that cannot flow continuously to surface (eg. pumping oil wells or uncompleted wells), the KH% curve may be the only indicator of production potential in such wells. It is also very much less expensive than a spinner survey or a poorly planned completion.

Completing a well for production is a balancing act between completion costs and production optimization.  A high quality petrophysical analysis that includes a permeability calculation is a first step. The cumulative flow capacity (KH%) curve, derived from that permeability, can help you make decisions about where to complete the well, or where to place a horizontal well.

To save money, we try to minimize the perforation interval, consistent with obtaining the maximum oil or gas production rate, with minimum water or gas cap production. This usually means perforating from the top of net pay to some deeper depth within the net pay, omitting any intervals where the pay flag is not turned on.

If there is a water contact in the reservoir, the lower depth of the perfs should be as far above the contact as reasonably possible. Aquifer influx will push oil up to the perfs over time. If there is a gas cap, it is normally preserved until the oil is produced, so the perfs are placed somewhat below the gas cap to allow for gas cap expansion. When the oil is depleted, the gas cap can be explored.

In gas-expansion-drive reservoirs, there is no significant moveable water to worry about and the entire interval can be perforated without fear of water production. Variations in reservoir quality may make some portions look wetter than others; these are just finer grained rocks and are still worthy of being completed in many cases.

When vertical fractures exist, the perf interval must be as far from both water and gas contacts as possible, and drawdown pressure kept as low as reasonable, to reduce the risk of gas or water inflow through the perfs.

The optimum position for a horizontal well is often determined from a petrophysical analysis of the vertical pilot hole. The same rules apply as for locating perforations. In both cases, you want to complete the interval that will produce the most hydrocarbons with the least complications. Stay above the water, stay below the gas when trying for an oil well, stay out of bounding shales or coal. In shale gas plays, the liquids-rich interval may be the most desirable location, and this may be above a leaner gas-only interval. A resistivity-at-bit and a gamma ray log on the drill string will assist in steering the wellbore.

The initial location should be near the middle of the best flow capacity in the desired reservoir, assuming that a hydraulic fracture will be designed to penetrate both upward and downward to cover the interval. In very thick reservoirs, there may be potential to drill and frac more than one interval from the same drill pad or platform.

Optimizing perforation interval or horizontal well placement can be aided by creating a cumulative flow capacity or productivity curve, based on the permeability derived from the petrophysical analysis of the prospective pay zone:
      0: KHcuml = 0.0
      1: KHi = Perm * INCR
      2: KHtotal = SUM (KHi * PayFlag)
      3: KHcuml = KHi + KHcuml
      4: KH% = 100 - 100 * KHcuml / KHtotal

  Perm = permeability of each incremental layer (mD)
  INCR = log data sample rate (feet or meters)
  KHi = flow capacity for each data sample increment (mD-ft or mD-m)
  KHtotal = total flow capacity for pay interval (mD-ft or mD-m)
  PayFlag = 0 if not Pay, = 1 if Pay
  KHcuml = cumulative flow capacity (mD-ft or mD-m)
  KH% = percent flow capacity (0% at base of pay, 100% at top of pay)

The KH% curve is presented with 0% at the left and 100% on the right. This will match the shape of a spinner survey from a flowmeter, with zero production capacity at base of pay and 100% at top of pay.

Intervals with the steepest slope on the KH% curve are the most productive and should be perforated if not too close to water or gas. Where the KH% curve is near vertical, no perfs are required.

Place horizontal well at or slightly below midpoint of the steepest slope of the KH% curve. This may vary depending on frac design and rock mechanical properties.

Permeability does not have to be well-calibrated to use this technique since the KH% curve is normalized between 0 and 100%.

Use the KH% curve to estimate increased productivity of bypassed or unperforated intervals. See example below.

CAUTION: The KH% curve is only a guide. It may not always indicate bypassed pay. The proof is in the production test.


: The objective is to consider whether the perforated interval is optimized to obtain the best production characteristics consistent with the cost of a workover, using the KH% curve as a qualitative guide.

Grid lines are 1 meter spacing. Tracks 1, 2, 3 show GR, SP, PayFlag, resistivity, PE, neutron, and density porosity. Calculated and core porosity in Track 4 with saturations in Track 5, calculated and core permeability in Track 6. Note excellent match to core data (coloured dots). Higher SW in lower zone is due to finer grained sand, not transition to water. KH% in Track 7 starts at base of PayFlag and runs up to top of PayFlag. Arrow shows base of perforations. KH% curve shows 40% of possible flow capacity has not been perforated. Since this is a gas expansion drive reservoir, the perforations should be extended 2.2 meters to capture at least 30% more flow capacity.

The objective is to consider where to place a horizontal well that will optimize production and minimize stimulation costs, using the KH% curve as a qualitative guide.

On the example shown at the right, the KH% curve is the second track from the right (shaded pink), next to the lithology track. To the left of the KH% track are permeability, saturation, porosity, and apparent porosity distribution (including clay bound water, kerogen effect, free gas, and water.

There are two long intervals on this log where the KH% curve has a significant slope (Layers A and C), separated from each other by a long interval with virtually no KH contribution (Layer B). Another zone (Layer D) with virtually no KH contribution lies above Layer C.

In round numbers, Layer C has about 45% of the total well flow capacity and the lower zone, Layer A, has about 40%.

An optimum location for a horizontal well would probably be near the middle of Layer A or near the middle of Layer C, assuming a hydraulic stimulation could be designed and executed that would extend 25 meters (+/-) above and below the horizontal well. In this example, either location offers about the same chance for economic success.

Placing a horizontal well to access both Layers A and C is much more difficult. The frac job would have to extend 75 meters (+/-) above and below the well to access the good reservoir, while penetrating 30 to 40 meters of rock that would not contribute much extra production. It may be more attractive to run two horizontal legs from the same pad to access both layers independently.



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