Berawala, Dhruvit Satishchandra (Department of Energy and Petroleum Technology, University of Stavanger, Norway and The National IOR Centre of Norway) | Østebø Andersen, Pål (Department of Energy Resources, University of Stavanger, Norway and The National IOR Centre of Norway)
Only 3-10 % of gas from tight shale is recovered economically through natural depletion, demonstrating a significant potential for enhanced shale gas recovery (ESGR). Experimental studies have demonstrated that shale kerogen/organic matter has higher affinity for CO2 than methane, CH4, which opens possibilities for carbon storage and new production strategies.
This paper presents a new multicomponent adsorption isotherm which is coupled with a flow model for evaluation of injection-production scenarios. The isotherm is based on the assumption that different gas species compete for adsorbing on a limited specific surface area. Rather than assuming a capacity of a fixed number of sites or moles this finite surface area is filled with species taking different amount of space per mole. The final form is a generalized multicomponent Langmuir isotherm. Experimental adsorption data for CO2 and CH4 on Marcellus shale are matched with the proposed isotherm using relevant fitting parameters. The isotherm is first applied in static examples to calculate gas in place reserves, recovery factors and enhanced gas recovery potential based on contributions from free gas and adsorbed gas components. The isotherm is further coupled with a dynamic flow model with application to CO2-CH4 substitution for CO2-ESGR. We study the feasibility and effectiveness of CO2 injection in tight shale formations in an injection-production setting representative of lab and field implementation and compare with regular pressure depletion.
The production scenario we consider is a 1D shale core or matrix system intitally saturated with free and adsorbed CH4 gas with only left side (well) boundary open. During primary depletion, gas is produced from the shale to the well by advection and desorption. This process tends to give low recovery and is entirely dependent on the well pressure. Stopping production and then injecting CO2 into the shale leads to increase in pressure where CO2 gets preferentially adsorbed over CH4. The injected CO2 displaces, but also mixes with the in situ CH4. Restarting production from the well then allows CH4 gas to be produced in the gas mixture. Diffusion allows the CO2 to travel further into the matrix while keeping CH4 accessible to the well. Surface substitution further reduces the CO2 content and increases the CH4 content in the gas mixture that is produced to the well. A result of the isotherm and its application of Marcellus experimental data is that adsorption of CO2 with resulting desorption of CH4 will lead to a reduction in total pressure if the CO2 content in the gas composition is increased. That is in itself an important drive mechanism since the pressure gradient driving fluid flow is maintained (pressure buildup is avoided). This is a result of CO2 being found to take ~24 times less space per mol than CH4.
Andersen, Pål Østebø (Dept of Energy Resources, University of Stavanger and The National IOR Centre of Norway, University of Stavanger) | Berawala, Dhruvit Satishchandra (Dept of Energy and Petroleum Technology, University of Stavanger and The National IOR Centre of Norway, University of Stavanger)
Chemically reactive flow is of significant importance for EOR due to possible wettability alteration (low salinity and smart water brines), scaling and chemically enhanced compaction, which all can affect hydrocarbon transportation. In particular, chalks (Ekofisk, Valhall) are highly sensitive to the composition of the injected brine (typically modified seawater) as demonstrated on lab and field scale. We present numerical and analytical solutions to interpret the link between geochemical alterations and creep compaction in chalk cores.
A 1D core scale model is proposed for interpreting geochemical compaction during reactive brine injection into chalk cores loaded uniaxially in creep state (compaction under constant applied effective stresses). An analytical solution is derived to describe the steady state ion and dissolution rate distributions. An analytical model for creep compaction is proposed based on the applied affective stress and the rocks ability to carry that stress as function of porosity. The two models are coupled as follows: The compaction rate is assumed enhanced by the dissolution rate. Further, the solid volume changes by mineral dissolution and precipitation, also affecting the compaction rate. Brine-dependent and non-uniform compaction is therefore built into the model via the dissolution rate distribution.
The model is validated against data from ~ 25 core samples where simple Mg-Ca-Na-Cl brines were injected at Ekofisk reservoir conditions (130 °C), in particular experimentally measured effluent concentrations, distributions in mineralogy after flooding and creep compaction behavior. The model captures the effect of varying key parameters such as brine composition, injection rate and initial porosity and can predict ionic and mineralogical profiles along the core, axial and radial deformation profiles locally and with time. This model is a highly useful tool for interpreting experimental data, predicting in-situ mineralogical distributions where measurements have not been made, and for predicting compaction behavior at changes in brine composition, injection rate or effective stress.
The model is intended for giving a prediction of qualitative and quantitative trends during flooding-compaction tests in chalks. The model and its methodology are translatable to other systems but is validated for lab measurements on chalk samples. Current modeling approaches do not consider the complex interplay between brine and rock compositions, reaction and compaction. This work aims to contribute to the current understanding of this topic.
The purpose of this paper is to investigate the main controlling factors of shale gas production in the context where well-induced fractures, extending from the well perforations, improve reservoir conductivity and performance. A mathematical 1D+1D model is presented which involves a high-permeable fracture extending from a well perforation, through symmetrically surrounding shale matrix with low permeability. Gas in the matrix occurs in the form of adsorbed material attached to kerogen (modeled by a Langmuir isotherm) and as free gas in the nano-pores. The pressure gradient towards the fracture and well perforation causes the free gas to flow. With pressure depletion, gas desorbs out of the kerogen into the pore space and then flows to the fracture. When the pressure has stabilized, desorption and production stop.
The production of shale gas and mass distributions indicate the efficiency of species transfer between fracture and matrix. It is shown that the behavior can be scaled and described according to the magnitude of two characteristic dimensionless numbers: the ratio of diffusion time scales in shale and fracture
The model allows intuitive interpretation of the complex shale gas production system. Furthermore, the current model creates a base which can easily incorporate non-linear flow mechanisms and geo-mechanical effects that are not readily found in standard commercial software, and further be extended to field scale application.