Dynamic Core Experiment – Accredited Multi‑Phase Flow and Formation Damage Evaluation for Global Oil and Gas Markets
Our internationally accredited laboratory provides a specialist dynamic core experiment service that gives reservoir engineers, drilling‑fluid formulators, enhanced‑oil‑recovery specialists and carbon‑storage project developers worldwide the precise, in‑situ data they need to model fluid behaviour, quantify formation damage and optimise injection and production strategies. All tests are conducted under the rigorous framework of ISO/IEC 17025, and each report bearing the ILAC mark is unconditionally accepted by regulatory authorities, notified bodies and supply‑chain partners in all major economies. The dynamic core experiment flows representative reservoir or injected fluids through a preserved or restored‑state core plug under precisely controlled overburden pressure, pore pressure, temperature and flow rate, and it continuously measures the differential pressure, the permeability evolution, the filtrate loss and the return‑permeability before and after the exposure to the treatment fluid. For a drilling‑fluid engineer designing a reservoir‑drill‑in fluid for a deepwater development, a completion‑fluid specialist evaluating the clean‑up efficiency of a filter‑cake breaker, or a CO₂‑injection project manager assessing the injectivity decline caused by salt precipitation, this service delivers the legally robust, defensible petrophysical data that underpin field‑development decisions, regulatory submissions and the demonstration of technical competence to joint‑venture partners and host governments.
Product Samples We Regularly Subject to Dynamic Core Experiments
Our high‑pressure, high‑temperature core‑flooding systems accommodate core plugs up to 1.5 inches in diameter and 3 inches in length, and they can operate at overburden pressures exceeding 10 000 psi and temperatures above 200 °C. The following categories represent the most frequently evaluated materials:
- Reservoir‑rock core plugs – sandstone, carbonate, chalk, tight‑gas‑sand and shale core samples, either preserved at the native wettability or cleaned and restored to a defined saturation state
- Drilling‑fluid and reservoir‑drill‑in fluid formulations – water‑based, oil‑based and synthetic‑based muds that are circulated across the core face to deposit a filter cake and to evaluate the depth and the severity of the filtrate invasion
- Completion and workover fluids – clear brines, viscosified brines and solids‑free fluids whose dynamic filtration and formation‑damage potential are measured at the reservoir temperature
- Stimulation fluids – acidising formulations, scale‑dissolver treatments and hydraulic‑fracturing fluids that are injected into the core to assess the permeability improvement or the secondary‑precipitation damage
- Enhanced‑oil‑recovery agents – polymer, surfactant, alkaline and low‑salinity water formulations whose rheology, adsorption and incremental‑oil‑recovery performance are evaluated under the dynamic flow conditions
- Injectant gases and supercritical fluids – carbon dioxide, nitrogen, hydrocarbon gas and supercritical CO₂ that are flowed through the core to determine the relative permeability, the injectivity decline and the mineral‑reaction‑induced permeability alteration
Dynamic Formation‑Damage and Permeability‑Impairment Experiments – Return‑Permeability and Filtrate‑Invasion Evaluation According to API RP 63 and Industry Standards
- Dynamic filtration and return‑permeability testing of drilling and completion fluids according to the principles of API RP 63 (Recommended Practice for Evaluation of Polymers Used in Drilling Fluids) and the internal protocols of the major oilfield operators: the core plug is mounted in a core holder and saturated with a synthetic or a native reservoir brine, and the initial permeability to the formation fluid – oil or brine – is measured at the reservoir‑confining pressure. The test fluid is then circulated across the core face at a controlled shear rate and overbalance pressure for a defined period – typically 16 hours – while the filtrate volume and the differential pressure are continuously recorded. After the dynamic‑filtrate‑invasion phase, the production is reversed, and the return permeability is measured at several flow‑back rates. The percentage of the initial permeability that is recovered and the pressure required to initiate the back‑production are reported, providing the quantitative formation‑damage metrics that the well‑construction engineer uses to compare the reservoir‑compatibility of different fluid candidates. This dynamic core experiment is mandatory for the qualification of every reservoir‑drill‑in fluid and every completion brine proposed for a high‑value development well.
- Dynamic filter‑cake lift‑off and clean‑up simulation: after the filter cake has been deposited, a breaker fluid, an acid wash or a displacement brine is circulated across the core face, and the time, the pressure and the flow‑rate required to completely remove the cake are measured. The return‑permeability after the clean‑up is compared with the initial permeability, and the efficiency of the clean‑up treatment is reported. This dynamic core experiment determines the minimum soak‑time and the optimum breaker concentration for the reservoir section of the well.
- Depth of the filtrate invasion and the solids‑entrainment analysis: after the dynamic‑filtration test, the core is removed, sectioned and analysed for the concentration of the invaded polymer, the solids and the brine‑salinity gradient. The depth of the invasion and the mass of the retained material are correlated with the permeability impairment, providing the data that the reservoir‑simulation engineer uses to model the near‑wellbore skin and to predict the well‑production performance.
- Dynamic fluid‑loss and permeability‑impairment testing of fracturing fluids: a fracturing‑fluid gel is circulated across the core face at the shear rate and the overbalance pressure representative of the fracture‑face conditions, and the filtrate loss and the filter‑cake thickness are recorded. The return‑permeability after the gel‑breaker treatment is measured, and the regaining of the permeability is reported, supporting the selection of the least‑damaging fracturing‑fluid system for the tight‑gas or the unconventional reservoir.
- Dynamic core experiments with the live‑oil and the crude‑oil samples at the reservoir temperature: for the oil‑producing reservoirs, the core is saturated with the live crude oil, and the dynamic‑filtrate experiment is conducted with the oil as the saturating phase. The oil‑phase return‑permeability and the wettability‑alteration effect are quantified, providing the most representative assessment of the formation damage that will occur in the oil‑producing zone.
Relative Permeability, Capillary Pressure and Enhanced‑Oil‑Recovery Dynamic Core Experiments – Steady‑State and Unsteady‑State Methods According to ASTM D6524 and Industry Protocols
- Determination of the two‑phase oil‑water relative permeability by the steady‑state and the unsteady‑state methods according to the principles of ASTM D6524 (Standard Test Method for Measuring the Relative Permeability of Core Samples) and the industry‑standard procedures: the core is brought to the irreducible water saturation or the residual oil saturation, and a simultaneous injection of oil and water at a fixed fractional flow is performed. The saturation is monitored by the gravimetric method, the nuclear‑magnetic‑resonance or the in‑situ saturation‑profiling, and the relative permeability to each phase is calculated from the pressure drop and the flow rates. The relative‑permeability curves and the end‑point saturations are reported, providing the fundamental data that the reservoir‑simulation engineer uses to history‑match the production and to forecast the ultimate recovery. This dynamic core experiment is routinely performed on the core samples from the exploration and the appraisal wells to reduce the uncertainty in the field‑development planning.
- Steady‑state gas‑oil and gas‑water relative permeability for the gas‑condensate and the gas‑storage reservoirs: the core is saturated with the gas and the liquid phases at the reservoir pressure, and the relative permeability is measured at several pressure‑depletion steps, capturing the effect of the condensate‑drop‑out or the water‑vapour‑condensation on the gas mobility. The data are used to design the gas‑injection and the gas‑withdrawal strategies for the underground gas‑storage facilities and the carbon‑capture‑and‑storage projects.
- Dynamic evaluation of the polymer, the surfactant and the alkaline‑surfactant‑polymer flooding for the enhanced oil recovery: the core is flooded with a sequence of water, chemical slug and chase‑water, and the incremental oil recovery, the pressure‑drop profile and the chemical‑retention rate are measured. The dynamic core experiment quantifies the mobility‑control effectiveness, the interfacial‑tension reduction and the wettability alteration, and the data are used to design the pilot‑scale and the field‑scale enhanced‑oil‑recovery projects.
- Capillary‑pressure and the wettability‑restoration experiments by the porous‑plate and the centrifuge methods: the core is saturated with the formation brine, and the oil is injected at a series of increasing capillary pressures, or the saturated core is centrifuged, and the saturation‑versus‑pressure curve is constructed. The test determines the irreducible water saturation, the residual oil saturation and the wettability index, and the data are integrated with the relative‑permeability curves to build the complete saturation‑dependent flow model.
Dynamic Core Experiments for Carbon Capture, Utilisation and Storage – Injectivity, Mineralisation and Geochemical Interactions
- CO₂‑brine dynamic displacement and injectivity assessment for the saline‑aquifer storage sites: supercritical carbon dioxide is injected into a brine‑saturated core at the reservoir pressure and temperature, and the pressure drop, the relative permeability and the displacement efficiency are measured. The test is continued for hundreds of pore‑volumes, and the injectivity decline caused by the salt precipitation, the fines migration and the mineral dissolution is monitored. This dynamic core experiment provides the injectivity‑index data that the storage‑site operator uses to design the injection‑well completion and to predict the long‑term injectivity of the formation.
- Reactive‑flow‑through experiments for the CO₂‑water‑rock interaction: the core is flooded with the CO₂‑saturated brine, and the effluent is sampled and analysed for the cations, the anions and the pH, while the differential pressure is continuously recorded. The change in the permeability and the porosity caused by the carbonate‑cement dissolution, the clay‑swelling or the secondary‑mineral precipitation is quantified, and the geochemical model is calibrated against the experimental data.
- Dynamic core‑flooding for the hydrogen‑storage and the compressed‑air‑energy‑storage reservoirs: hydrogen or compressed air is injected into a water‑saturated core, and the cyclic‑injection‑and‑withdrawal efficiency, the residual‑gas trapping and the mineral‑reactivity are evaluated. This dynamic core experiment supports the qualification of the underground porous‑rock formations for the large‑scale, seasonal energy‑storage projects that are an essential component of the future decarbonised energy system.
- Microbial‑enhanced‑oil‑recovery and the biocide‑compatibility dynamic core experiments: the core is inoculated with the reservoir‑indigenous or the injected microorganisms, and the growth‑medium or the nutrient‑solution is flowed through the core while the permeability, the biomass accumulation and the metabolite‑induced oil‑mobilisation are monitored. The test determines the feasibility of the microbial‑enhanced‑oil‑recovery for the target reservoir and the compatibility of the biocide treatments with the formation.
Report Acceptance and Global Regulatory Compliance
All measurements performed within our dynamic core experiment programme are executed under the fully accredited scope of our ISO/IEC 17025 quality management system. Each test report that carries the ILAC mark is therefore automatically recognised by regulatory authorities, notified bodies, customs offices and supply‑chain partners in all major economies. For oil‑and‑gas operating companies, drilling‑fluid and completion‑fluid manufacturers, enhanced‑oil‑recovery chemical suppliers and carbon‑storage project developers anywhere in the world, the report constitutes legally robust, internationally accepted evidence that the dynamic‑filtrate, the formation‑damage, the relative‑permeability and the injectivity data have been determined in accordance with the applicable API, ASTM, ISO and customer‑specified methods. The documentation can be directly used to support the well‑construction permit, the field‑development plan approval, the issuance of the inspection certificates according to EN 10204 or equivalent national standards, and the resolution of commercial and technical disputes concerning the reservoir‑compatibility and the flow‑assurance performance of any well‑construction or injection fluid.
