Jeroen Snippe

Observational evidence confirms modelling of the long-term integrity of CO2-reservoir caprocks

Storage of anthropogenic CO2 in geological formations relies on a caprock as the primary seal preventing buoyant super-critical CO2 escaping. Although natural CO2 reservoirs demonstrate that CO2 may be stored safely for millions of years, uncertainty remains in predicting how caprocks will react with CO2-bearing brines. This uncertainty poses a significant challenge to the risk assessment of geological carbon storage. Here we describe mineral reaction fronts in a CO2 reservoir-caprock system exposed to CO2 over a timescale comparable with that needed for geological carbon storage. The propagation of the reaction front is retarded by redox-sensitive mineral dissolution reactions and carbonate precipitation, which reduces its penetration into the caprock to ∼7 cm in ∼105 years. This distance is an order-of-magnitude smaller than previous predictions. The results attest to the significance of transport-limited reactions to the long-term integrity of sealing behaviour in caprocks exposed to CO2.

Microscale solute transport and precipitation in complex rock during drying

Formation drying and salt precipitation due to gas injection or production can have serious consequences for upstream operations in terms of injectivity and productivity. Recently, evidence has been found that the complexity of the pore space and microscopic capillary-driven solute transport plays a key role in the relationship between permeability and porosity. In this study, we investigate drying and salt precipitation due to supercritical CO2 injection in single-porosity and multiporosity systems under near well-bore conditions. We image fluid saturation states and salt deposition by means of microcomputerized tomography scanning during desaturation. We observe capillary-driven transport of brine and the respective solutes on the pore scale. Solute transport between porosity classes determines the distribution of the deposits in the pore space and the permeability porosity relationships—K(φ)—for flow-through drying.

Production-Induced Stress Change in and Above a Reservoir Pierced by Two Salt Domes: A Geomechanical Model and Its Applications

Production decreases the pore fluid pressure and increases the effective stress acting on the load-bearing grain-framework that makes up the reservoir. As a result, the reservoir deforms and compacts, and because it is connected to the rocks around it, there will be deformations and displacements in these rocks too. Well known effects are surface subsidence, wells damaged by shear, and timeshifts in 4D-seismic. Less well known is how the changes in the stress field itself should be taken into account in operations, e.g. to design infill wells and to plan production stimulation by hydraulic fracturing or waterflooding of the reservoir. We present a geomechanical model for the initial stress field and production-induced stress changes in and around a steeplydipping hydrocarbon reservoir penetrated by two large salt-domes. The model integrates 3D seismic and geological understanding, geomechanical data from wells and analogues, and depletion patterns from fluid-flow (dynamic) simulation. Our model results confirm published models of principal stress orientation in rocks pierced by salt domes. The depleted-model results show stress changes up to several MPa in magnitude compared to the pre-production stress state, but only limited changes in the stress orientations. The model highlights the influence of structural dip and time-dependent salt-sediment interaction on stress changes. We then describe the application of the model in wellbore stress analysis for infill wells and in a water-injection scheme that has (we think) been severely impacted by injection-induced fractures propagating into the reservoir towards the producer wells. We explain how the latter application uses a 3D flow simulation model coupled to a dynamic fracture propagation model. The geomechanical model provides key input: stress magnitude and orientation. Results are validated against more conventional analysis of real-time pressure data. In both applications, the integration of geomechanics in 3D static and dynamic models improved insight in the rock response to drilling and waterflooding, thus helping to optimise production. Introduction The Pierce field is characterized by two salt diapirs that are penetrating the reservoir formation, leading to two connected accumulations (North Pierce and South Pierce, see Figure 1). Seismic control is relatively poor due to the steep dips and shadow zones from the salt diapirs, and only major geological features such as large faults are well localized (at least mid to down dip). The field consists of two main reservoir units: Forties consolidated sandstone (described here) and the Chalk (undeveloped, and not treated in this paper). Geologically, the Forties consist of turbiditic sand-shale sequences, with considerable intra-reservoir structural complexity. Some data of the field are given in Table 1. It should be noted that due to the steep dips and a stepped/tilted contact, the total hydrocarbon column height is nearly 1600 m, while the average stratigraphic thickness is only approximately 100 m. It increases to approximately 230 meters in the saddle between the diapirs and in the main channel axis to the west of both diapirs. The pinching-out of the Forties towards the salt suggests that the salt diapir had pushed up two hills at the sea floor at the time of the Forties sediment deposition. Since 1999 the field has been developed under depletion drive with gas re-injection (one gas injector per accumulation). Since the aquifer strength was unknown at the time of the Field Development Plan, the producers were positioned roughly in the middle of the oil column. Then from the production and pressure data it became clear that the aquifer is weak. Therefore, in 2004, water injection was introduced in South Pierce with the dual objective to give additional pressure support and better sweep downdip of

Coupled Geochemical-Reservoir Model to Understand the Interaction Between Low Salinity Brines and Carbonate Rock

Low salinity waterflood (LSF) is a promising technology for improving oil recovery. Several laboratory studies have demonstrated the potential of LSF to alter the rock wettability and improve oil recovery in carbonate reservoirs. Some studies have considered calcite dissolution as a mechanism behind the wettability alteration by LSF in carbonates. Moreover, the interaction between rock and injected brine can lead to change in the injected brine composition and pH. Therefore, it is important to better understand the interaction between injected brine and carbonate rock to de-risk the LSF technology for field applications. A numerical model was developed by coupling a reservoir simulator (Shell in-house Simulator, MoReS) with a geochemical model (PHREEQC) to study the interaction between the injected brine and carbonate rock. Calcite is assumed to be the rock mineral to represent most of carbonate reservoirs. Two reservoir rock models are presented: one for coreflood scale and another for field scale. To mimic reservoir condition, the rock is saturated with formation brine (180 g/l) and several brines with different salinity and composition are injected. The model is calibrated to the published experimental data in the literature. Both Local Equilibrium and Kinetic approaches are used to model the interaction between injected brines and rock. Furthermore, the impact on calcite dissolution is examined against various parameters such as brine composition and pH, and temperature. The model results indicate that interaction between calcite and brine can reach equilibrium quickly. As a result, LSF may dissolve calcite from part or the whole core during flooding experiments depending on the kinetics of the interaction. However at field scale, the calcite dissolution occurs only in the area near the injector. This suggests that if calcite dissolution is one of the LSF mechanisms, this mechanism will not contribute to improving oil recovery at field scale. Although calcite dissolution can occur only near the injector, it can still change the composition and pH of the injected brine, which may have an impact on the oil recovery. The increase in salinity due to calcite dissolution in not significant in absence of CO 2 , but the brine pH may reach 8-9.