Hassan Mahani

Kinetics of Low-Salinity-Flooding Effect

Low-salinity waterflooding (LSF) is one of the least-understood enhanced-oil-recovery (EOR)/improved-oil-recovery (IOR) methods, and proper understanding of the mechanism(s) leading to oil recovery in this process is needed. However, the intrinsic complexity of the process makes fundamental understanding of the underlying mechanism(s) and the interpretation of laboratory experiments difficult. Therefore, we use a model system for sandstone rock of reduced complexity that consists of clay minerals (Na-montmorillonite) deposited on a glass substrate and covered with crude-oil droplets and in which different effects can be separated to increase our fundamental understanding. We focus particularly on the kinetics of oil detachment when exposed to lowsalinity (LS) brine. The system is equilibrated first under high-salinity (HS) brine and then exposed to brines of varying (lower) salinity while the shape of the oil droplets is continuously monitored at high resolution, allowing for a detailed analysis of the contact angle and the contact area as a function of time. It is observed that the contact angle and contact area of oil with the substrate reach a stable equilibrium at HS brine and show a clear response to the LS brine toward less-oil-wetting conditions and ultimately detachment from the clay substrate. This behavior is characterized by the motion of the three-phase (oil/water/solid) contact line that is initially pinned by clay particles at HS conditions, and pinning decreases upon exposure to LS brine. This leads to a decrease in contact area and contact angle that indicates wettability alteration toward a more-waterwet state. When the contact angle reaches a critical value at approximately 40 to 50 , oil starts to detach from the clay. During detachment, most of the oil is released, but in some cases a small amount of oil residue is left behind on the clay substrate. Our results for different salinity levels indicate that the kinetics of this wettability change correlates with a simple buoyancyover adhesion-force balance and has a time constant of hours to days (i.e., it takes longer than commonly assumed). The unexpectedly long time constant, longer than expected by diffusion alone, is compatible with an electrokinetic ion-transport model (Nernst-Planck equation) in the thin water film between oil and clay. Alternatively, one could explain the observations only by more-specific [nonDerjaguin–Landau–Verwey–Overbeek (DLVO) type] interactions between oil and clay such as cation-bridging, direct chemical bonds, or acid/base effects that tend to pin the contact line. The findings provide new insights into the (sub) pore-scale mechanism of LSF, and one can use them as the basis for upscaling to, for example, pore-network scale and higher scales (e.g., core scale) to assess the impact of the slow kinetics on the time scale of an LSF response on macroscopic scales.

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

Demonstrating the Potential of Low-Salinity Waterflood to Improve Oil Recovery in Carbonate Reservoirs by Qualitative Coreflood

Low salinity waterflood (LSF) is a promising improved oil recovery (IOR) technology. Although, it has been demonstrated that LSF is an efficient IOR method for many sandstone reservoirs, the potential of LSF in carbonate reservoirs is still not well-established as only a limited number of successful coreflood experiments are available in the literature. Therefore, the aim of this study was to examine the oil recovery improvement by LSF in carbonate reservoirs by performing coreflood experiments. This paper proposes an experimental approach to qualitatively evaluate the potential of LSF to improve oil recovery and alter the rock wettability during coreflood experiments. The corefloods were conducted on core plugs from two Middle Eastern carbonate reservoirs with a wide variation of rock properties and reservoir conditions. Seawater and several dilutions of formation brine and seawater were flooded in the tertiary mode to evaluate their impacts on oil recovery compared to formation brine injection. In addition, a geochemical study was performed using PHREEQC software to assess the potential of calcite dissolution by LSF. The experimental results confirmed that lowering the water salinity can alter the rock wettability towards more water-wet, causing improvement of oil recovery in tertiary waterflood in plugs from the two reservoirs. Furthermore, seawater is more favorable for improved oil recovery than formation brine as injection of seawater after formation brine resulted in extra oil production. This demonstrates that the brine composition plays an important role during waterflooding in carbonate reservoirs, and not only the brine salinity. It was also observed that oil recovery can be improved by injection of brines that cannot dissolve calcite based on the geochemical modeling study. This implies that calcite dissolution is not the dominant mechanism of IOR by LSF. To conclude, this paper demonstrates that low-salinity waterflood has a good potential as an IOR technology in carbonate reservoirs. In addition, the proposed experimental approach ensures the verification of LSF effect, either it is positive or negative. However, more work is required to further explore the most influential parameters affecting LSF response and explain the dominant mechanisms. Introduction Low salinity waterflood (LSF) is a relatively mature improved oil recovery technique for sandstone reservoirs. The concept of LSF, for sandstones, is to lower the ionic strength of the injected brine, which leads to an alteration of the rock wettability towards more water-wet and hence an improvement of oil recovery. Numerous laboratory studies demonstrated the effect of LSF by spontaneous imbibition tests and coreflood experiments (Bernard 1967, Jadhunandan and Morrow 1991, Yildiz and Morrow 1996, Tang and Morrow 1997, Lager et al. 2006, Ligthelm et al. 2009, Masalmeh et. al. 2013). Furthermore, published data confirmed the positive response of LSF at the field scale (Webb et al. 2004, Lager et al. 2008, Vledder et al. 2010). However, the potential of LSF for carbonate reservoirs has not been well investigated. Several spontaneous imbibition tests were performed on Stevns Klint outcrop chalk (Austad et al. 2005, Zhang and Austad 2006, Strand et al. 2006). The results demonstrated the wettability alteration towards more water-wet by seawater or modified seawater. Increasing the sulfate concentration in seawater resulted in more change of wettability towards waterwetness. Ferno et al. (2011) performed spontaneous imbibition tests on different chalk outcrops (Stevns, Rordal, and Niobrara) using brines with and without sulfate. The effect of adding sulfate to the brines on wettability alteration was observed only in plugs from Stevns Klint chalk, but not from the other 2 chalk types. Webb et al. (2005) performed

Driving Mechanism of Low Salinity Flooding in Carbonate Rocks

Several studies conducted mainly on the laboratory scale indicate that in carbonate rocks oil displacement can be influenced by the ionic composition of the brine, providing an opportunity to improve recovery by optimizing the brine mixture used in secondary or tertiary recovery. In industry this topic has been termed “low salinity flooding (LSF) in carbonates” while the underlying mechanisms are not very well understood. The increased oil recovery has been attributed to wettability alteration to a more water-wet state. However, in some studies a positive low salinity effect (LSE) has been ascribed to dissolution of rock, which occurs on the laboratory scale but due to equilibration of brine with carbonate minerals on larger length scales this is not relevant for the reservoir scale. Therefore, the objective of this paper is to gain a better understanding of the underlying mechanism(s) and investigate whether calcite dissolution is the primary mechanism of the LSE. We used a model system where the contact angle of crude oil deposited on planar surfaces coated with crushed carbonate rock particles was monitored as a function of brine composition. The approach is similar to the one published in Mahani et al. (2014) for sandstone rock, but instead of clay minerals we used carbonate materials from natural limestone and Silurian dolomite rocks. Furthermore, the effective surface charge at the oil-water and water-rock interfaces was quantified via zeta-potential measurements at several salinity and pH levels in order to establish a link between changes in the intermolecular interactions at the solid-liquid interface and the contact angle at the brine-oil-rock contact line, which is an indicator for wettability change. The impact of mineral dissolution was addressed by comparing the response to brines that were fully equilibrated (and hence dissolution suppressed) and the response to those completely under-saturated with calcium carbonate (leading to dissolution). The investigation was accompanied by geochemical modeling using PHREEQC. It was observed that by switching from formation water (FW) to seawater (SW), diluted seawater (dSW) and diluted seawater equilibrated with calcite (dSWEQ), the limestone surface became less oil-wet reflected in contact angle decrease. The recession of the 3-phase contact line observed for both SW and dSWEQ, which are not impacted by dissolution, suggests that the LSE occurs even in the absence of mineral dissolution. The trends observed for the zeta-potential data on brine composition clearly support the surface-charge-change mechanism for limestone, where at lower salinities the charges at the limestone-brine interface become more negative, causing lower adhesion or even repulsion between oil and rock. Dolomite rock shows a different behavior. First, there is a much smaller response in terms of contact angle change. Also, the zeta-potential of dolomite shows generally more positive charges at higher salinities and less decrease at lower salinities, where in comparison to limestone the electrostatic interaction remains attractive or becomes only weakly repulsive. In summary we conclude that a positive LSE in carbonate rock exists without any dissolution and it is driven by the brine composition dependency of electrostatic interactions between crude oil and rock. However, the magnitude of the LSE is impacted by the mineralogy of carbonate material.

Vorticity-Based Perpendicular-Bisector Grids for Improved Upscaling of Two-Phase Flow

This paper (SPE 113703) was accepted for presentation at the EUROPEC/EAGE Conference and Exhibition, Rome, 9–12 June 2008, and revised for publication. Original manuscript received for review 21 February 2008. Revised manuscript received for review 20 September 2009. Paper peer approved 23 December 2009. Summary Highly detailed geological models, which are primary inputs for reservoir simulators, necessitate a reduction in the number of gridblocks used in the solution of flow equations. However, preparing a coarse-scale model that can mimic the fine-scale behavior is challenging. Cartesian grids suffer from some shortcomings, such as in adaptation with geological and geometrical features and the grid-orientation effect that motivates the use of unstructured grids. Different methods have been used for this purpose, but none is robust enough. This justifies further research. In this paper, we propose a novel unstructured-grid-generation scheme that uses the vorticity of fluid flow in porous media as the determining parameter for background-grid generation. It entails simulating single-phase flow on the fine grid and obtaining the velocity field and, subsequently, the vorticity map. Vorticity is then used to generate the background grid that plays an essential role in the generation of a desired final coarse grid. At this stage, users need to determine the value of some parameters, such as maximum and minimum spacing, vorticity cutoff, and vorticity-intensity degree. The advancing-front method and Delaunay triangulation are then used to provide the triangular and Voronoi perpendicular-bisector (PEBI) grid. The developed technique, which aims to capture both flow and geologic details, produces grids with higher resolutions at critical vorticity areas, such as around layer boundaries, and with lower resolution where vorticity is negligible, such as in homogeneous regions. This technique is applied to two channelized and heterogeneous models, and the results are presented. Two-phase-flow simulations are performed on the generated coarse grids, and the results are compared with those of fine-scale grid and uniformly generated coarse grids. The results show a greater accuracy compared with uniformly gridded models.

Reservoir Flow Simulation Using Combined Vorticity-based Gridding and Multi-Scale Upscaling

A novel technique for upscaling of detailed geological reservoir descriptions is presented. The technique aims at reducing both numerical dispersion and homogenization error, generated due to incorporating a coarse computational grid and assigning effective permeability to coarse grid blocks respectively. In particular we consider implicit-pressure explicit-saturation (IMPES) scheme where homogenization error impacts the accuracy of the coarse grid solution of the pressure equation. To reduce the homogenization error, we employ the new vorticity-based gridding that generates a nonuniform coarse grid with high resolution at high vorticity zones. In addition, to control numerical dispersion, we use Dual Mesh Method (DMM), which uses different grids to solve pressure and saturation equations. The coarse grid generated from vorticity is used for computation of pressure and the reference fine grid is used for updating saturation explicitly. The most strong point of the method is that dual mesh method has been incorporated onto non-uniform grid structure. This combination removes the need to solve the full fine grid for two-phase flow modeling, resulting in a less computationally demanding and more accurate upscaling technique. To evaluate the method, we run two-phase simulation using different 2D test cases. Our results indicate that the non-uniform DMM is more accurate than the uniform DMM due to using vorticity-based grids. The speed-up achieved in the computation is significant depending on the complexity of model and degree of upscaling.

Pore-scale processes in Amott spontaneous imbibition tests

We observed the redistribution of the oil phase in the pore space of the rock in real-time in water-wet and mixed-wet (by ageing in crude oil) carbonate samples. During the imbibition of the water phase both, pore filling events with connection to the surrounding brine as well as snap-off events connected through water films only were detected. The distribution of the oil in different pore sizes as well as the different event types help to identify the wettability state of the system and understand how pore scale processes lead to the oil production at the larger scale.