Effective geological storage of CO2 can be accomplished through a number of trapping mechanisms. Physical trapping is achieved through either CO2 being trapped under a structural closure or CO2 made immobile in the pore space, as residual saturation, by capillary action. Geochemical trapping, which might be regarded as a more secure mode of storage, is achieved through dissolution of CO2 in formation water and precipitation of carbonates. The dissolution rate depends on surface contact and is generally enhanced by greater CO2 plume movement. During site selection, a potential injection well location is commonly evaluated with respect to the proximity to potential leakage features. This paper investigates requirements for separation distance between CO2 injection location and potential leakage features in highly permeable steeply dipping brine reservoir settings. Reservoir models are simulated with a compositional code and sensitivity analyses performed with variations in reservoir permeability, hysteresis effects, and formation dip. Trapping mechanisms, over a timescale of several centuries, are illustrated as key indicators for containment and storage performance. Study results suggest that the amount of CO2 trapped by dissolution and residual saturation is enhanced by a dynamically flowing plume. The simulation results demonstrate that the separation distance requirement typically envisaged in a worst-case reservoir geometry setting is commonly overly conservative, representing opportunity for further optimisation. Numerical simulation is useful in addressing the complex reality of flow dynamics such as hysteresis in footprint prediction. Understanding CO2 plume migration scenarios relative to potential leakage risks, under various key reservoir key properties, is essential in storage containment and capacity assessments for storage site selection and development.

For a tight reservoir, assessment of zonal production contribution is often possible only after the reservoir has been hydraulically fractured. Spinner survey is commonly the tool of choice for diagnosing relative production contribution across perforated interval in a cased-hole and by extension, minimum productive fracture height at the wellbore. However, its limited radial resolution renders such tool unreliable in evaluating flow characteristic within fracture body and across fracture planes. The acquired data is generally insufficient for resolving relative contribution of various productive horizons intersected by the fracture. As the measurements are focused on flow characteristics inside the wellbore, fracture height diagnosis is limited by the extent of perforation interval. Alternatively, radioactive tracing and microseismic survey allow one to see through the casing wall albeit at the expense of heightened cost and operational complexity. Thermal logging, being a cheaper alternative, is time-sensitive and not deployable immediately following proppant placement due to restricted wellbore access. Most importantly, hydraulic and propped fracture heights diagnosed by these methods may not necessarily coincide with effective fracture height that contributes directly to well productivity. Integrating acoustic logging to conventional production logging measurements may, in addition to increasing resolution for low flow measurement, significantly extend the investigation radius beyond casing wall. Different acoustic characteristics potentially exhibited by flow of different fluid phases may also validate conventional log-derived reservoir fluid types. The paper describes the application of acoustic logging in diagnosing zonal production contribution, fracture height, and reservoir fluid type across hydraulically fractured tight gas condensate and oil reservoirs. In four naturally flowing wells, zonal production contribution derived from acoustic wave analysis and conventional production log data were both in good agreement. The analysis of depth-specific acoustic wave amplitude provided useful insight in the diagnosis of zonal production contribution and by extension, productive fracture height. In one well, acoustic-derived fracture height could be closely corroborated with that of radioactive tracer data. In addition, one may also observe distinct shape of maximum amplitude of first sound wave arrival in a gas well compared to that in an oil well.

Carbon dioxide (CO2) geological storage is considered in many large "greenfield" developments. The requirements for long-term injection operations have put a premium on obtaining the right information early, constraining engineering solutions and costs before major investment decisions are reached. Information such as long-term field pressure evolution and local fracture gradient alteration may have major impacts on development cost forecast. Reservoir heterogeneity and compartmentalization may result in continuous reservoir pressure escalation as injected CO2 amount increases. Maintaining rate is essential to avoid venting. However, this requires proportionate injection pressure increases—an option bounded by formation integrity, seal capacity, and well interference limits. When operating conditions approach these limits, one may avoid compromising rate by, albeit costly, drilling more injection wells over time. We investigate the impact of mean reservoir parameter and boundary condition assumptions on project economics. The potential impact of injection temperature on formation integrity and in-field power needs is also explored. Well injection rate is estimated analytically using a Darcy law's approximation. Taking high seal entry pressures as a given, the study defines allowable injection pressure in terms of fracture gradient. Upward fracture gradient adjustment is modeled for escalating reservoir pressure, allowing mitigation of injection rate reduction. We later analyze the variation of fracture gradient with injection temperature to account for thermal fracture limitation. Ultimately, the study presents pre-tax break-even CO2 unit technical costs in dollar per tonne injected, providing comparison of relative economic performance among the investigated scenarios. The results demonstrate the importance of reservoir quality in suppressing cost-intensive injection well and CO2 heating requirements. The range of costs indicates the value of early appraisal information before making development decisions. The application of geologically-constrained engineering analysis in economic modeling is useful in providing insight on value of information as well as supporting decisions for CO2 storage site development.