Low matrix permeability and significant damage mechanisms are the main signatures of tight gas reservoirs. During drilling and fracturing of tight formations, the wellbore liquid invades the tight formation, increases liquid saturation around wellbore and eventually reduces permeability at near wellbore. The liquid invasion damage is mainly controlled by capillary pressure and relative permeability curves.
Water blocking and phase trapping damage is one of the main concerns in use of water based drilling fluid in tight gas reservoirs, since due to high critical water saturation, relative permeability effects and strong capillary pressure, tight formations are sensitive to water invasion damage. Therefore, use of oil based mud may be preferred in drilling or fracturing of tight formation. However invasion of oil filtrate into tight formations may result in introduction of an immiscible liquid hydrocarbon drilling or completion fluid around wellbore, causing entrapment of an additional third phase in the porous media that would exacerbate formation damage effects.
This study focuses on phase trapping damage caused by liquid invasion using water-based drilling fluid in comparison with use of oil-based drilling fluid in water sensitive tight gas sand reservoirs. Reservoir simulation approach is used to study the effect of relative permeability curves on phase trap damage, and results of laboratory experiments core flooding tests in a West Australian tight gas reservoir are shown in which the effect of water injection and oil injection on the damage of core permeability are studied. The results highlights benefits of using oil-based fluids in drilling and fracturing of tight gas reservoirs in term of reducing skin factor and improving well productivity.
Tight gas reservoirs normally have production problems due to very low matrix permeability and different damage mechanisms during well drilling, completion, stimulation and production (Dusseault, 1993). The low permeability gas reservoirs can be subject to different damage mechanisms such as mechanical damage to formation rock, plugging of natural fractures by invasion of mud solid particles, permeability reduction around wellbore as a result of filtrate invasion, clay swelling, liquid phase trapping, etc (Holditch, 1979).
In general, for tight sand gas reservoirs, average pore throat radius might be very small and therefore it may create tremendous amounts of capillary forces. Capillary forces cause the spontaneous imbibition of a wetting liquid (in this case water) in the porous medium in the absence of external forces such as a hydraulic gradient (Bennion and Brent, 2005). This causes significantly high critical water saturation (Bennion et al., 2006). Two forces drive capillary flow (Adamson and Gast, 1997). The first is the reduction in the surface free energy by the wetting of the hydrophilic surface (wettability). In hydraulic fracturing, water in the fracturing fluid wets the surface of the pores in the rock, resulting in a decrease in the surface free energy of the pores. The other force that drives capillary flow is the capillary pressure.
Tight gas reservoirs might be different in term of initial water saturation (Swi) compared with critical water saturation (Swc), depending on the geological time of gas migration to the reservoir. Initial water saturation might be normal, or in some cases sub-normal (Swi less than Swc) due to water phase vaporization into the gas phase (Bennion and Thomas, 1996). The initial water saturation might also be more than Swc if the hydrocarbon trap is created during or after the gas migration time. A sub-normal initial water saturation in tight gas reservoirs can provide higher relative permeability for the gas phase (effective permeability close to absolute permeability), and therefore relatively higher well productivity (Bennion and Brent, 2005).
Quinlan, Timothy Michael (Schlumberger) | Sibbit, Alan Matthew (Services Techniques Schlumberger) | Rose, David Alan (Schlumberger) | Brahmakulam, Jacob V. (Schlumberger) | Zhou, Tong (Schlumberger) | Fitzgerald, John Barry (Steve Kimminau Consulting) | Kimminau, Stephen John
Carbon Dioxide (CO2) sequestration and enhanced recovery projects require the evaluation of rocks containing mixtures of CO2, water, and gaseous or liquid hydrocarbons. Pulsed neutron logs of various designs and measurement types have been used since the 1960s to evaluate formations containing gaseous hydrocarbons, but they were not originally designed or characterized specifically for quantitative CO2evaluation. Computer modeling, test pit data, and field examples are presented in this work to highlight the issues of CO2 evaluation and to compare these with gaseous hydrocarbons.
Pulsed neutron tools emit 14 MeV neutrons from an accelerator source, but a wide variety of timing sequences, detector types, source-detector spacings, and signal processing techniques are employed by the industry to extract formation description parameters from the recorded counts. For the non-specialist petroleum engineer this variety can confuse and distract from effective use of the measurements. We organize all categories of pulsed neutron logs into simple types based upon the measurement physics to provide an effective guide to field use of these logs.
Examples of commercial and experimental tools in clastic and carbonate environments are presented. The examples show how CO2 can be quantified and demonstrate critical design requirements for successful pulsed neutron logging campaigns. We outline the lessons learned and make recommendations for the design of logging programs and interpretation of the acquired data in stand-alone or in time-lapse modes.
Bulk-phase CO2 injection into saline aquifers can provide substantive reduction in CO2 emissions if the risk arising from aquifer pressurization is addressed adequately through mechanisms such as brine production out of the system (Anchliya 2009). While this approach addresses the risks associated with aquifer pressurization it does not address the problem of ensuring CO2 trapping as an immobile phase and its accumulation at the top of the aquifer. The performance of bulk-CO2-injection schemes highly depends on the seal-integrity assessment and presence of thief zones. The accumulated pocket of free CO2 can readily leak through a breach in the aquifer seal. Ideally, the aquifer should be monitored as long as the free CO2 is present, but if the CO2 is not immobilized, it is expected to remain underneath the seal rock for more than 1,000 years. Therefore, long-term monitoring of the seal integrity and avoiding leakage will be very costly.
To minimize the free CO2 below the caprock, we propose an engineered system to reduce aquifer pressurization and accelerate CO2 dissolution and trapping. We achieve these objectives through effective placement of brine injection and production wells to facilitate the lateral movement (hence, residual and solubility trapping) of CO2 in the aquifer and impede its upward movement. The simulation results for example engineered well configurations in this paper suggest that substantial improvements in immobilizing CO2 can be achieved through increasing enhanced solubility and residual trapping that result from better CO2-injection sweep efficiency. This approach has the potential to greatly reduce the risk of CO2 leakage both during and after injection. The controlled injection of CO2 with this technique reduces the uncertainty about the long-term fate of the injected CO2, prevents CO2 from migrating toward potential outlets or sensitive areas, and increases the volume of CO2 that can be stored in a closed aquifer volume during the CO2-injection period. Field-scale compositional simulation cases are discussed, and sensitivity studies are used to provide guidelines for well spacing and flow rates depending on aquifer properties and the volume of CO2 to be stored. Although it requires additional drilled wells, the active engineered configuration proposed for CO2 injection significantly reduces the reservoir volume required to effectively sequester a given volume of CO2, and the increase in the cost caused by additional wells is recovered by dramatic reduction in monitoring cost.
Tsar, Mitchel (Curtin University) | Bahrami, Hassan (Curtin University) | Rezaee, Reza (Curtin University) | Murickan, Geeno (Curtin University) | Mehmood, Sultan (Curtin University) | Ghasemi, Mohsen (Curtin University) | Ameri, Abolfazl | Mehdizadeh, Mahna
Tight gas reservoirs are mainly characterized by low matrix permeability and significant damage. During drilling and fracturing of tight formations, wellbore liquid invades into tight formation and increases water saturation around wellbore and eventually reduces permeability near wellbore or adjacent to fracture wings. The damage to permeability caused by invasion of liquid into tight formation is controlled by capillary pressure and relative permeability curves.
The phase trap damage is one of the main concerns in use of water based drilling or fracturing fluid, since due to high critical water saturation, strong capillary pressure, and sensitivity of tight sand to water. Therefore, use of oil based mud may be preferred in drilling or fracturing of tight formation. However invasion of oil filtrate into tight formation may result in a three-phase relative permeability curves in invaded zone in presence of reservoir gas and initial water, which may differently affect damage and productivity of tight gas reservoirs.
This study evaluates phase trap damage in water-based in comparison with oil-based drilled or fractured tight gas reservoir. Reservoir simulation is used to study the effect of relative permeability curves on phase trap damage and well productivity, based on reservoir and core data from a West Australian tight gas reservoir. The results highlights benefits of using oil-based fluids in drilling and fracturing of tight gas reservoirs in term of improving well productivity.
Collett, Timothy S. (US Geological Survey) | Boswell, Ray (US Department of Energy) | Lee, Myung W. (US Geological Survey) | Anderson, Brian J. (West Virginia University) | Rose, Kelly (US Department of Energy) | Lewis, Kristen A. (US Geological Survey)
The results of short-duration formation tests in northern Alaska and Canada have further documented the energy-resource potential of gas hydrates and have justified the need for long-term gas-hydrate-production testing. Additional data acquisition and long-term production testing could improve the understanding of the response of naturally occurring gas hydrate to depressurization-induced or thermal-, chemical-, or mechanical-stimulated dissociation of gas hydrate into producible gas. The Eileen gashydrate accumulation located in the Greater Prudhoe Bay area in northern Alaska has become a focal point for gas-hydrate geologic and production studies. BP Exploration (Alaska) Incorporated and ConocoPhillips have each established research partnerships with the US Department of Energy to assess the production potential of gas hydrates in northern Alaska. A critical goal of these efforts is to identify the most suitable site for production testing. A total of seven potential locations in the Prudhoe Bay, Kuparuk River, and Milne Point production units were identified and assessed relative to their suitability as a long-term gas-hydrate-production test sites. The test-site-assessment criteria included the analysis of the geologic risk associated with encountering reservoirs for gas-hydrate testing. The site-selection process also dealt with the assessment of the operational/logistical risk associated with each of the potential test sites. From this review, a site in the Prudhoe Bay production unit was determined to be the best location for extended gas-hydrate-production testing. The work presented in this report identifies the key features of the potential test site in the Greater Prudhoe Bay area and provides new information on the nature of gas-hydrate occurrence and the potential impact of production testing on existing infrastructure at the most favorable sites. These data were obtained from well-log analysis, geological correlation and mapping, and numerical simulation.