Restored State Core

A restored state core is a rock sample taken from a wellbore that has been cleaned of all original fluids and then resaturated with reservoir-representative liquids to bring it back to a condition that mimics the original reservoir wetting state. The cleaning step removes oil, brine, and drilling fluid contamination. The resaturation step restores the original balance of wettability between the rock mineral surfaces and the fluids. Without this restoration, measurements of relative permeability and capillary pressure on the cleaned sample would reflect the wettability of a water-wet rock, not the actual mixed-wet or oil-wet condition that governs fluid flow in most producing reservoirs.

Key Takeaways

Core samples change wettability during drilling and handling. Oil-based mud filtrate, the reduction of pressure during retrieval, and core aging all shift the surface chemistry of the rock. A restored state core attempts to undo these changes before measurements are taken.
The restoration process typically involves: cleaning the core with solvents (toluene to remove oil, methanol to remove salt and water); drying; then resaturating first with brine to the connate water saturation, then with crude oil (or a refined oil with similar chemical character) at reservoir temperature for one to six weeks. This aging period allows crude oil components (particularly asphaltenes and resins) to adsorb back onto the rock surfaces and re-establish the original wetting condition.
The time and temperature of the aging step matter. Cores aged at reservoir temperature for four weeks typically show stable, reproducible wettability measurements. Cores aged for less than 24 hours often show a more water-wet response than the true reservoir condition.
Relative permeability and capillary pressure measurements on restored state cores differ substantially from measurements on as-received cores or cleaned, water-wet cores. Relative permeability to oil at residual water saturation can be 30 to 50 percent lower on a properly restored mixed-wet core than on a cleaned water-wet one, which directly affects reserves calculations and water flooding performance predictions.
Restored state core analysis is part of special core analysis (SCAL), the set of advanced measurements that supplements routine core analysis (porosity, air permeability, grain density). Not every well program requires SCAL; it is most valuable for reservoirs with uncertain wettability, complex pore geometry, or where water flooding is planned.

Why Core Wettability Matters for Flow Measurements

Wettability is the tendency of a fluid to spread across a solid surface in the presence of another fluid. In a rock pore, wettability determines which fluid preferentially coats the mineral surfaces and which fluid sits in the center of the pore space. In a water-wet rock, water clings to the mineral surfaces and oil sits in the middle of the pore throats. In an oil-wet rock, it is the opposite: crude oil coats the mineral surfaces and water fills the centers.

This distinction governs how oil and water move through the rock during production. In a strongly water-wet reservoir, water injected to maintain pressure moves through the pore centers as a continuous front, efficiently displacing the oil. In an oil-wet reservoir, the injected water fingers rapidly through the pore centers (since oil coats the walls and water has no preference for them), leaving oil stranded on the mineral surfaces and producing a poor sweep efficiency.

The problem with measuring relative permeability and capillary pressure on a cleaned core is that cleaning strips the crude oil components that established the original wettability. The cleaned core is strongly water-wet regardless of what the original reservoir wettability was. Measurements on a water-wet cleaned core predict water flooding behavior that is far more optimistic than what actually happens in an oil-wet or mixed-wet reservoir.

Fast Facts

The industry term for the quality grade of a core measurement is "reservoir conditions." The hierarchy from lowest to highest quality is: ambient conditions (room temperature, atmospheric pressure); preserved conditions (tested at reservoir pressure and temperature without cleaning); and restored state (cleaned, then re-aged with reservoir fluids at reservoir conditions). A fourth category, native state, refers to a core that is frozen immediately at the wellsite, transported under pressure, and tested without any cleaning at all. Native state cores give the most direct measurement of the original reservoir fluid distribution but are expensive and logistically demanding.

The Restoration Procedure

Restoration starts with cleaning. Core plugs cut from the whole core are placed in a Dean-Stark apparatus or a Soxhlet extractor where boiling toluene and methanol vapors condense through the sample, removing oil and brine. The clean, dry core is then measured for porosity and air permeability to give the baseline rock properties without any fluid influence.

Resaturation begins with brine flooding. The dry plug is evacuated under vacuum, then brine (matched to the reservoir formation water salinity) is injected until the plug is fully saturated. Oil is then flooded through the brine-saturated plug until only irreducible (connate) water remains. This establishes an initial water saturation representative of the reservoir just before production.

The oil-flooded plug is then placed in a sealed aging cell at reservoir temperature, typically 60 to 120°C for most sandstone and carbonate reservoirs. The crude oil is left in contact with the rock for two to four weeks. Asphaltenes and resins from the crude oil slowly adsorb onto the mineral surfaces, shifting the wettability from strongly water-wet toward the mixed-wet or oil-wet state of the original reservoir.

Where Restored State Core Analysis Is Used

In Alberta's Cardium, Viking, Duvernay, and Montney plays, restored state SCAL is ordered when a new reservoir interval is being evaluated for water flooding or gas injection. The relative permeability curves from the SCAL program feed directly into the reservoir simulation model that predicts production response under injection. An error in the wettability assumption can cause the simulation to predict oil recovery of 35 percent of original oil in place when the true recovery might be only 22 percent, leading to incorrect reserves booking and poor capital allocation.

On the Norwegian Continental Shelf, the Petroleum Safety Authority Norway (PSA) and the Norwegian Oil and Gas Association specify restored state SCAL as part of the data package for field development plan submissions when relative permeability data is cited in reserves calculations. The Ekofisk and Valhall chalk fields have been studied with restored state methods because chalk reservoirs are particularly susceptible to wettability changes that alter oil recovery factors dramatically.

Offshore Australia, Woodside and Santos routinely commission SCAL programs on Carnarvon Basin and Browse Basin cores ahead of major gas field development decisions where the reservoir model feeds into liquefaction plant capacity sizing.

A restored state core is also called an aged core or a wettability-restored core. The procedure is sometimes called the Amott restoration method when wettability is quantified by the Amott-Harvey index after aging. Related terms include wettability (the preference of a fluid to contact a solid surface in the presence of another immiscible fluid; controls the distribution of oil and water in reservoir pores and governs relative permeability), relative permeability (the ratio of effective permeability to a specific fluid to the absolute permeability of the rock; a dimensionless function of fluid saturation that is the key input to reservoir flow modeling), special core analysis (SCAL, the set of advanced core measurements beyond routine porosity and permeability; includes relative permeability, capillary pressure, wettability, electrical properties, and acoustic properties), capillary pressure (the pressure difference across the interface between two immiscible fluids in a pore throat; governs the initial fluid distribution in the reservoir and the saturation at which each fluid becomes mobile), and native state core (a core transported and tested under preserved pressure and temperature without any cleaning, representing the highest fidelity reproduction of original reservoir fluid distribution; more expensive and logistically demanding than restored state preparation).

How an Incorrect Wettability Assumption Wrote Down 8 Million Barrels of Oil Reserves

A North Sea operator had a proven oil field in a Jurassic sandstone reservoir producing under water injection. The original reserves estimate, based on a water-flooding model calibrated to cleaned water-wet relative permeability curves, showed an oil recovery factor of 38 percent. The field had been on production for six years when production rates fell below the model prediction despite reservoir pressure being well-maintained by the injection.

A SCAL study was commissioned on new core cut from a sidetrack well. Restored state relative permeability testing, with cores aged for four weeks at reservoir temperature (94°C) with the field's crude oil, showed significantly higher residual oil saturation and a less favorable oil relative permeability curve than the original water-wet measurements. The interpreter recalibrated the reservoir simulation model with the restored state curves.

The recalibrated model matched the observed production decline closely. The revised recovery factor was 29 percent. The reserves write-down was 8 million barrels of oil equivalent. The operator's share price fell 4 percent the day the revision was announced. The SCAL program itself cost approximately USD 380,000. The cost of not doing it at the start of field development was nine years of optimistic production forecasts, overestimated reserves, and capital allocated to compression and injection capacity sized for a recovery factor that was never achievable.