CALIBRATING Water Saturation
During coring, moveable hydrocarbons are flushed from the core and replaced by mud filtrate, leaving residual oil and irreducible water. Some of the irreducible water may be replaced by mud filtrate as well. During recovery and transport of the core, the majority of the water will drain out, leaving residual oil and irreducible water. The sum of residual oil saturation plus irreducible water saturation is usually less than 1.0, the balance being the moveable oil saturation. In older reservoirs with many years of production, there may also be some moveable water. This will also be flushed by the mud filtrate. To appreciate the meaning of the core saturations,  it is important to know the history of a reservoir relative to the when the core was cut.

In petrophysical analysis, we utilize the core water saturation as a guide to the irreducible water saturation in a reservoir above the transition zone. In a core, the difference between residual oil and water saturation is usually assumed to be the moveable oil fraction of the reservoir fluids, when the reservoir is at initial conditions. The core water saturation is usully assumed to be close to the irreducible water saturation.

In older reservoirs, no longer at initial conditions,, there may be some moveable water as well as the moveable oil. This can often be seen on the log analysis results depth plots where log analysis saturation is higher than core water saturation. The excess water saturaton is a measure of potential water production.

If corroboration of water saturation is required, air-brine capillary pressures should be taken, along with electrical properties, from at least a dozen core plugs with some variations in porosity or pore geometry. This will resolve the initial irreducible water saturation question. A reservoir simulation history match would be needed to resolve the question of moveable water saturation.

Cores taken in oil based mud give a better view of irreducible water, as these muds do not displace the water.

The main use for core analysis oil saturation is to estimate minimum possible residual oil saturation, and to assist in locating gas-oil and oil-water contacts. Gas and water zones have low residual oil, unless they were once oil zones (recently or in earlier geologic time). Oil saturation from core analysis is quite useful in tar sand and sometimes in heavy oil evaluations, where flushing is minimal.

CALIBRATING LOG ANALYSIS TO CORE SATURATION EXAMPLES
These examples demonstrate the close match between log analysis water saturation and core analysis water saturation. It works most of the time, especially with cores cut after the mid 1980's, provided they have been handled according to best practices. If it doesn't work, or doesn't seem to make sense, forget it and move on.


Bakken “Tight Oil” example showing core porosity (black dots), core oil saturation (red dots). core water saturation (blue dots), and permeability (red dots). Note excellent agreement between log analysis and core data. Separation between red dots and blue water saturation curve indicates significant moveable oil, even though water saturation is relatively high. Log analysis porosity is from the complex lithology model and lithology is from a 3-mineral PE-D-N model using quartz, dolomite and pyrite.


Sandstone example (left) and carbonate example (right) showing close match of log analysis and core analysis water saturation. Black dots are core porosity and permeability. Light blue dots are core analysis water saturation, which fall close to log analysis saturation curve (blue). Red dots on sandstone example are residual oil saturation, showing lots of moveable oil between the water curve, even though the water saturations are quite high (due to poor pore geometry).

Moveable Hydrocarbon EXAMPLE
This example shows a comparison of residual oil from core in a depleted zone (M1 interval) and in a bypassed zone (M3 interval). The Sor from core equals (1 - SW) from log analysis, so there is no moveable oil in the M1. The close match suggests that most of the saturation parameters (A, M, N, RW@FT) and porosity are reasonably well calibrated. Since the world abounds with depleted zones (most are well known to the well operators) this test should always be made to confirm SW parameters where ever core data is available.


Computed results for carbonate example. Note higher water saturation on M1 compared to M3. M3 is bypassed pay. M1 is depleted oil. Dots are core data. Note that residual oil on core in M1 matches calculated
Sor = (1 - SW). In M3, Sor on core is less than (1 - SW) from log analysis, so there is moveable oil in
 M3 interval but not in M1. Calibration to core permeability needs more work to get a decent match.
 

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