Detecting and mitigating near-wellbore fines migration is important in order to avoid formation damage in many gas wells. This has bearing not only on gas production but also carbon capture through the geological storage of Carbon dioxide (CO2), in pressurised, deep saline aquifers. Fines migration may occur because of weakened electrostatic forces caused by an introduced fluid which also makes fines more prone to movement by viscous drag, or where the drag forces are sufficient to physically break or lift clay crystals from their original location and transport them through the pore network.
Potential near-wellbore fines migration is typically assessed via coreflood tests. In an ideal scenario, such tests will be conducted using reservoir core material, with reservoir gas at rates and pressures comparable to the reservoir. However, due to practicality and cost constraints, tests are often conducted using available outcrop core and scaled down reservoir conditions. Laboratory tests reduce higher field pressures down to lab scale. In certain scenarios, simulating the total gas flux in a given near-wellbore system is achieved by increasing gas flow rates. Although, in some investigations, the need to utilise field realistic pressures in the lab is also becoming more of a requirement. This paper aims to address differences in lab protocols by examining both field realistic and scaled down conditions to aid best practice for formation damage identification and remediation. The potential utility, and challenges associated with a variety of hydrocarbon gas analogues in scenarios where increased gas density is required is also discussed.
The fines migration potential of a clay rich (Blaxter) sandstone was demonstrated using salinity and flux related fines migration methods, demonstrating that under certain conditions, selected cores are susceptible to fines migration. Test results with CO2 at low and medium pressure conditions demonstrated that pressure and flow rate variation in the laboratory had no notable effect on the fines migration of Blaxter sandstone samples, under the conditions examined. Additional tests conducted at higher pressures of 7250 psig did not yield fines migration although a 10% permeability loss was observed. While this was the case for Blaxter sandstone, caution is advised when testing with field substrate under these conditions, as reservoir rocks may be more susceptible to damage. Field cores typically display a well-developed crystal structure and surface area/volume ratios more normally associated with kaolinite booklets and platelets of clays, which may expose them to higher drag forces. Therefore, the minimal permeability reduction effects observed at high pressure may potentially be multiplied in field cores.
Additional core flood tests were conducted to evaluate the use of hydrocarbon gas analogues (such dodecane) as a substitute for dense gases in core flood testing. This allows lower pressures than that would be required for compressed gases. Results showed that dodecane can be used as a gas analogue under appropriate conditions. A note of caution in the use of dodecane is that results from the high-pressure tests showed that, under the conditions examined, dodecane induced a 24% permeability reduction in the core.
The work presented in this paper aims to improve the use of coreflood tests as a tool for identifying formation damage, particularly in gas wells. This work provides useful guides and shows that while testing at atypical pressures is not prevalent, it can be performed and may be required for more robust formation damage identification programs in specific scenarios.
