Understanding the Effect of Rock Compressibility on CO2 Storage Capacity Estimation in a Depleted Carbonate Gas Reservoir

Avoiding or reducing greenhouse gases emission in the atmosphere requires extensive application of technologies and one of them is underground CO2 sequestration. Capture and storage of CO2 in depleted hydrocarbon reservoirs can reduce greenhouse gases released into the atmosphere effectively. Hydrocarbon reservoirs are considered one of the ideal geologic storage sites as they have held hydrocarbons over millions of years. Their architecture and properties are well understood due to exploration and production activities from these reservoirs. Storage projects require a large depleted hydrocarbon reservoir with good reservoir properties and are affected by several factors including voidage created by hydrocarbon production, pressure, architecture, formation permeability, aquifer influx, subsidence and compaction, and rock compressibility to name a few. Thus, realistic estimation of the storage capacity of the reservoir is a key step in the evaluation of CO2 storage plan. A good history matched simulation model incorporating the geomechanical parameters is essential to estimate storage capacity of the reservoir. Three major depleted gas reservoirs in Central Luconia field, located in offshore Sarawak, are being evaluated for future CO2 storage. Reservoir simulation is used as a tool to estimate future CO2 storage capacity of these reservoirs. Reliability of forecast from a reservoir simulation model is dependent on the quality of history match achieved. Hence it is believed that CO2 storage capacity estimates obtained from a good history matched simulation model must be reliable. However, during history matching exercise in these reservoirs, it was observed that an acceptable history match could be achieved with a range of rock compressibility values and aquifer influxes. Generally, a constant value of rock compressibility is used in conventional simulation. For example, in order to obtain an acceptable history match, with a lower compressibility, a larger aquifer influx is needed and vice versa. Interestingly, a forecast using these history match cases yield different CO2 storage capacities. A closer evaluation shows that aquifer influx has a strong impact on future CO2 storage capacity. An acceptable quality of history match can be obtained for a range of rock compressibility values when aquifer influx is adjusted along with it. Sensitivity analysis shows that future CO2 storage capacity in depleted hydrocarbon reservoir is sensitive to rock compressibility used in the simulation model. A detailed sensitivity analysis along with multiple history match scenarios is necessary to understand the range in future storage capacity when evaluating CO2 storage plan.

Hydro-mechanical coupling in porous rocks: hidden dependences to the microstructure?

SUMMARY While hydro-mechanical coupling in rocks is generally well understood, exotic rock poroelastic responses—such as unexpected dependence to fluid diffusion time and low skeleton moduli—have been reported. Hydro-mechanical coupling, or poroelasticity, explains how fluid-saturated rocks respond to either confining or fluid pressure variations. This coupling is usually inferred from the apparent mechanical and hydraulic properties: mechanical properties determine the strain level experienced by the rock when submitted to pressures at a timescale when fluid pressure is equilibrated, which is in turn ruled by hydraulic properties. However, the coupling between properties might not always be straightforward, particularly for rocks in which two distinct families of pore types coexist: spherical pores and cracks. Comparing it with reported laboratory data sets on pressure-dependent hydraulic and elastic properties in sandstones of different porosity confirms that the well-known simple concepts of networks in parallel apply and yield opposite dependencies for the two properties on the two pore families. Because hydro-mechanical coupling implies that the two properties—that depend differently on the pore families—will be interdependent, we further apply the same concept of parallel network. It yields that, although under apparent drained conditions, typical poroelasticity experiments could underestimate the rock compressibility ${C_{\mathrm{ bp}}}$, measured as a response to fluid pressure variation, and underestimate the related skeleton (or unjacketed) bulk modulus ${K_\mathrm{ s}} = \ 1/{C_\mathrm{ s}}$.

Integrated Subsurface to Surface Modeling to Assess Reservoir Uncertainty Quantification to A Carbonate Reservoir

This study accommodates subsurface uncertainties analysis and quantifies the effects on surface production volume to propose the optimal future field development. The problem of well productivity is sometimes only viewed from the surface components themselves, where in fact the subsurface component often has a significant effect on these production figures. In order to track the relationship between surface and subsurface, a model that integrates both must be created. The methods covered integrated asset modeling, probability forecasting, uncertainty quantification, sensitivity analysis, and optimization forecast. Subsurface uncertainties examined were : reservoir closure, regional segmentation, fluid contact, and SCAL properties. As the Integrated Asset Modeling is successfully conducted and a matched model is obtained for the gas-producing carbonate reservoir, highlights of the method are the following: 1) Up to ± 75% uncertainty range of reservoir parameters yields various production forecasting scenario using BHP control with the best case obtained is 335 BSCF of gas production and 254.4 MSTB of oil production, 2) SCAL properties and pseudo-faults are the most sensitive subsurface uncertainty that gives major impact to the production scheme, 3) EOS modeling and rock compressibility modeling must be evaluated seriously as those contribute significantly to condensate production and the field’s revenue, and 4) a proposed optimum production scenario for future development of the field with 151.6 BSCF gas and 414.4 MSTB oil that yields a total NPV of 218.7 MMUSD. The approach and methods implemented has been proven to result in more accurate production forecast and reduce the project cost as the effect of uncertainty reduction.

A Novel Model for Well Production Performance Estimate in Low-Permeability and Tight Reservoirs Considering Stress Sensitivity

Stress sensitivity phenomenon is an important property in low-permeability and tight reservoirs and has a large impact on the productivity of production wells, which is defined as the effect of effective stress on the reservoir parameters such as permeability, threshold pressure gradient, and rock compressibility change accordingly. Most of the previous works are focused on the effect of effective stress on permeability and threshold pressure gradient, while rock compressibility is critical of stress sensitivity but rarely noticed. A series of rock compressibility measurement experiments have been conducted, and the quantitative relationship between effective stress and rock compressibility is accurately described in this paper. In the experiment, the defects in previous experiments were eliminated by using a new-type core holder. The results show that as the effective stress increases, the rock compressibility becomes lower. Then, a stress sensitivity model that considers the effect of effective stress on rock compressibility is established due to the experimental results. The well performance of a vertical well estimated by this model shows when considering the effect of effective stress on the rock compressibility, the production rate and recovery factor are larger than those without considering it. Moreover, the effect of porosity and confining pressure on the productivity of a vertical well is also studied and discussed in this paper. The results show that the productivity of a vertical well decreases with the increase in overburden pressure, and increases with the increase in the porosity.

Coal fracturing through liquid nitrogen treatment: a micro-computed tomography study

Low permeability of coal has been a constant obstacle to economic production from coalbed methane reservoirs, and liquid nitrogen (LN2) treatment has been investigated as one approach to address this issue. This study examined LN2 fracturing of a bituminous coal at pore-scale through 3D X-ray micro-computed tomography. For this purpose, a cylindrical sample was immersed into LN2 for 60 min. The micro-CT results clearly showed that the rapid freezing of the coal with LN2 generated fracture planes with large apertures originating from the pre-existing cleats in the rock. This treatment also connected original cleats with originally isolated pores and micro-cleats, thereby increasing pore network connectivity. Moreover, scanning electron microscopy highlighted the appearance of continuous wide conductive fractures with a maximum opening size of 9 µm. Furthermore, a nano-indentation technique was used to test the effect of LN2 on coal mechanical properties. The indentation moduli decreased by up to 14%, which was attributed to the increase in the cracked rock compressibility, showing considerable fracturing efficiency of the LN2 treatment. Through in-situ microscopic visualisation and surface investigation, this study quantified the pore structure and connectivity evolution of the rock based on the morphological alteration, and demonstrated the promising effect of LN2 freezing on fracturing of bituminous coals, thus aiding coalbed methane production. The significance of this study was investigating the mechanisms associated with and the efficiency of LN2 treatment of a coal rock in a 3D analysis inside the rock.