Interstitial Water

Key Takeaways

• Interstitial water saturation derived from resistivity logs using the Archie equation is the standard method for determining the hydrocarbon saturation of every well logged in a clastic reservoir — the Archie equation (Sw = [(a × Rw) / (phi^m × Rt)]^(1/n)) calculates water saturation Sw from the formation water resistivity (Rw), the rock porosity (phi), and the formation's resistivity (Rt) as measured by the resistivity log, where a, m, and n are lithology-dependent constants; in an oil-bearing zone, Rt is high (oil is a poor conductor of electricity) and Sw is low, indicating that most of the pore volume is filled with oil rather than conductive formation water; in a water-bearing zone, Rt is low and Sw is high; the interstitial (irreducible) water saturation is the minimum Sw value found at elevations well above the oil-water contact where capillary pressure is at its maximum for the hydrocarbon column height — this Swi value is used as a lower bound on the water saturation expected in the best reservoir quality, and deviations above Swi at any point in the reservoir indicate either poorer reservoir quality (tighter pore throats with more capillary-held water) or transition zone effects near the oil-water contact.
• The capillary pressure-water saturation relationship (Pc-Sw curve) from core analysis directly measures Swi and the rate at which water saturation increases approaching the oil-water contact — mercury injection capillary pressure (MICP) tests inject mercury (a non-wetting phase analogous to oil in a water-wet system) into a cleaned, dry core plug at progressively increasing pressures, measuring the volume of mercury (and therefore the pore volume accessible to non-wetting phase) at each pressure step; the lowest mercury saturation reached at the highest test pressure — which corresponds to the mercury trapped in the smallest pore throats that require very high capillary pressure to fill — represents Swi when converted from mercury-air to oil-water capillary pressure through the interfacial tension and contact angle transformation; MICP provides much more information than just Swi — the full Pc-Sw curve describes the pore throat size distribution of the rock, the capillary entry pressure (the minimum oil column height needed to displace water and begin filling the reservoir), and the transition zone thickness — all of which are essential inputs for reservoir characterization and fluid contacts prediction.
• Chlorinity or salinity of interstitial water determines the formation water resistivity (Rw) used in Archie's equation, and getting Rw wrong produces systematically incorrect water saturation calculations throughout the entire reservoir — if the interstitial water is fresher (less saline) than assumed in the Rw value used in the calculation, the actual Rt value corresponding to a given water saturation will be higher than the Archie calculation predicts, causing the log analyst to underestimate Sw (and overestimate oil saturation) in zones containing fresh formation water; in reservoirs with variable formation water salinity (which occurs in reservoirs with mixed water sources, in low-relief structures near freshwater aquifers, or in reservoirs that have experienced dilution by meteoric water flushing), using a single Rw value for the entire reservoir is a systematic error source that should be identified and corrected through formation water sampling from core extracts, drillstem tests, or produced water analysis from early production; the salinity of interstitial water can also provide geological information about the reservoir's diagenetic and hydrodynamic history.
• Interstitial water in tight gas reservoirs creates a particularly damaging completion challenge called water blockage or water imbibition damage — when a hydraulic fracture is created in a tight gas reservoir and the fracturing fluid (which is water-based in slickwater completions) contacts the tight reservoir rock, capillary forces cause the reservoir to imbibe (absorb) some of the water into the small pore throats; this imbibed water cannot easily be expelled during flowback because the capillary pressure holding it in the tight pore throats exceeds the gas pressure needed to displace it; the result is a zone of elevated water saturation (above Swi) around the fracture face that reduces the relative permeability to gas and creates a "water block" that reduces the well's early production; some researchers believe that water block may be self-healing over time as gas displaces water slowly at reservoir pressure, while others argue that a portion of the water block persists through the well's producing life; the use of gas-energized fracturing fluids (nitrogen or CO2 foams) reduces the volume of aqueous fluid that enters the formation and mitigates water block in tight gas applications.
• Interstitial water salinity in produced water streams from newly producing wells provides information about the fracture and matrix connection established by hydraulic fracturing — water recovered from a tight reservoir during flowback typically has a salinity that evolves from near-fresh (reflecting the fracturing fluid that was injected) to progressively more saline (reflecting the interstitial water being displaced from the reservoir matrix into the fractures) over a period of days to weeks after fracture stimulation; the rate and ultimate level of salinity increase provides a qualitative indication of how effectively the fractures are connected to matrix pore space where interstitial water is stored; in formations where the interstitial water has distinctive geochemical signatures (specific isotope ratios, trace element concentrations, or dissolved gas compositions), produced water geochemistry can be used as a diagnostic tool to identify which formation zones are contributing to production and whether the fractures are communicating with intended or unintended intervals.