A Practical Approach for Modeling Low Salinity Waterflooding in Carbonate Reservoirs

Geochemical controls on wettability alteration at pore-scale during low salinity water flooding in sandstone using X-ray micro computed tomography

Alaska North Slope (ANS) contains vast resources of heavy oil which have not been developed efficiently using conventional waterflooding. Recently, low salinity waterflooding (LSWF) has been considered to enhance oil recovery by reducing residual oil saturation in the Schrader Bluff heavy oil reservoir. In this study, lab experiments have been conducted to investigate the performance of LSWF in heavy oil reservoirs on ANS. Fresh-state core plugs cut from preserved core samples with original oil saturations have been flooded sequentially with high salinity produced water, low salinity water, and softened low salinity water. The cumulative oil production and pressure drop across the core plugs have been recorded by the AFS-300 coreflooding system. The oil recovery factors and residual oil saturation after each flooding have been determined based on material balance. In addition, restored-state core plugs saturated with heavy oil have been employed to conduct unsteady-state displacement experiments to measure the oil-water relative permeabilities using high salinity produced water and low salinity water, respectively. It has been found that the core plugs are very unconsolidated, with porosity and absolute permeability in the range of 33 – 36% and 155 – 330 mD respectively. Produced crude oil sample having a viscosity of 63 cP at ambient conditions was used in the experiments. The total dissolved solids (TDS) of the high salinity produced water and the low salinity water are 28,000 mg/L and 2,940 mg/L, respectively. After softening, the TDS of softened low salinity water has little change, but the concentration of Ca2+ has been reduced significantly. The residual oil saturations are reduced gradually by applying LSWF and softened LSWF successively after high salinity water flooding. On the average, LSWF can improve heavy oil recovery by 6.3% of original oil in place (OOIP) over high salinity water flooding, while the softened LSWF further enhances the oil recovery by 1.3% OOIP. The pressure drops observed in the LSWF and softened LSWF demonstrates more fluctuations than that in the high salinity water flooding, which indicates potential particle migration in LSWF. Furthermore, it was found that regardless of the salinity the calculated water relative permeabilities are much lower than the typical values in conventional rock-fluid systems, implying more complex interactions between the reservoir rock, heavy oil, and injected water. This study provides fundamental lab data for evaluating the technical and economic benefits of LSWF in heavy oil reservoirs on ANS.

Low salinity waterflooding (LSWF), versus high salinity waterflooding (HSWF) has been the focus of significant research at various centres around the world, yet there is still considerable debate over the exact mechanism that provides incremental oil recovery. The use of the LSWF technique is not widespread in the United Kingdom continental shelf (UKCS). However, it has been announced that the Clair Ridge development will deploy low salinity waterflooding (LSWF) in secondary mode from the start of field life, and a number of companies are currently assessing the applicability of the technique through high level screening and core flooding. Forecasting the potential oil recovery under LSWF is heavily influenced by the simulation technique that is used. Presently the most widely discussed approach is the use of a weighting table with relative permeabilities representing the high and low salinity cases. As the grid block falls below threshold salinity, the simulator utilises the weighting table to assign an interpolated value of salinity. This value of salinity is utilised to represent a change in wettability. While this approach approximates the net effect of LSWF, it does not capture the oil/rock/brine interaction. This study examines the modelling approach to LSWF utilising an in-house generic Forties Palaeocene model in CMG's STARS simulator. The conventional approach of modelling LSWF using high and low salinity relative permeabilities is compared to the latest Multi-component Ion Exchange (MIE) methods by numerical simulation to assess the impact on incremental oil recovery. A sensitivity analysis is then carried out on the effects of specific parameters on incremental oil recovery, utilising published data from fields in the Forties Palaeocene fan system. A discussion is provided. The impact on secondary recovery was accessed with respect to wettability alteration; injection salinity (LSWF versus HSWF); oil viscosity and aquifer influx. The application of LSWF in secondary mode to the Forties Palaeocene Sandstones was found to be favourable for the case of mixed-wet reservoirs.

In the last decade, high salinity waterflooding has been emerged as a prospective EOR method for chalk reservoirs. Most recently, Saudi Aramco reported significant increase in oil recovery by low salinity waterflooding in Saudi Arabian carbonate reservoirs. Understanding of the mechanisms leading to an increase in oil recovery in both smart waterflooding processes (low and high salinity waterflooding) is still not clear. In this paper, we investigate experimentally the recovery mechanisms for both methods. To understand high salinity waterflooding process, we studied crude oil/seawater ions interaction at different temperatures, pressures and sulfate ion concentrations. For low salinity waterflooding, flooding experiments were carried out initially with the seawater, and afterwards the contribution to oil recovery was evaluated by sequential injection of various diluted versions of the seawater. Our results show that sulfate ions may help decrease the crude oil viscosity when high salinity brine is contacted with oil under high temperature and pressure. We have also observed formation of an emulsion phase between high salinity brine and oil with the increase in sulfate ion concentration at high temperature and pressure. We propose that the decrease in viscosity and formation of an emulsion phase could be the possible reasons for the observed increase in oil recovery with sulfate ions at high temperature in chalk reservoirs, besides the mechanism of the rock wettability alteration, which has been reported in most previous studies. No low salinity effect was observed for the reservoir carbonate core plug at the room temperature. On the contrary, a significant increase in oil recovery was observed under low salinity flooding of the reservoir carbonate core plugs at 90 °C. NMR measurements indicated that low salinity brines did not significantly change the surface relaxation of the carbonate rocks. Migration of fines, dissolution and destruction of rock particles are possible mechanisms of oil recovery increment with low salinity brines from carbonate core plugs at 90 °C. At the present stage, the mechanisms behind increment in oil recovery under various conditions appear to be different.

We investigated pore-scale oil displacement and rock wettability in tertiary low salinity waterflooding (LSW) in a heterogeneous carbonate sample using high-resolution three-dimensional imaging. This enabled the underlying mechanisms of the low salinity effect (LSE) to be observed and quantified in terms of changes in wettability and pore-scale fluid configuration, while also measuring the overall effect on recovery. The results were compared to the behavior under high salinity waterflooding (HSW). To achieve the wetting state found in oil reservoirs, an Estaillades limestone core sample was aged at 11 MPa and 80°C for three weeks. The moderately oil-wet sample was then injected with high salinity brine (HSB) at a range of increasing flow rates, namely at 1, 2, 4, 11, 22 and 42 µL/min with 10 pore volumes injected at each rate. Subsequently, low salinity brine (LSB) was injected following the same procedure. X-ray micro-computed tomography (micro-CT) was used to visualize the fluid configuration in the pore space. A total of eight micro-CT images, with a resolution of 2.3 µm/voxel, were acquired after both low salinity and high salinity floods. These high-resolution images were used to monitor fluid configuration in the pore space and obtain fluid saturations and occupancy maps. Wettability was characterized by measurements of in situ contact angles and curvatures. The results show that the pore-scale mechanisms of improved recovery in LSW are consistent with the development of water micro-droplets within the oil and the expansion of thin water films between the oil and rock surface. Before waterflooding and during HSW, the measured contact angles were constant and above 110o, while the mean curvature and the capillary pressure values remained negative, suggesting that the HSB did not change the wettability state of the rock. However, with LSW the capillary pressure increased towards positive values as the wettability shifted towards a mixed-wet state. The fluid occupancy analysis reveals a salinity-induced change in fluid configuration in the pore space. HSB invaded mainly the larger pores and throats, but with LSW brine invaded small-size pores and throats. Overall, our analysis shows that a change from a weakly oil-wet towards a mixed-wet state was observed mainly after LSW, leading to an incremental increase in oil recovery. This work established a combined coreflooding and imaging methodology to investigate pore-scale mechanisms and wettability alteration for tertiary LSW in carbonates. It improves our understanding of LSW as an enhanced oil recovery (EOR) method for potential field-scale applications. The data provides a valuable benchmark for pore-scale modelling as well as an insight into how even modest wettability changes can lead to additional oil recovery.

HypothesisThe wettability change from oil-wet towards more water-wet conditions by injecting diluted brine can improve oil recovery from reservoir rocks, known as low salinity waterflooding. We investigated the underlying pore-scale mechanisms of this process to determine if improved recovery was associated with a change in local contact angle, and if additional displacement was facilitated by the formation of micro-dispersions of water in oil and water film swelling. ExperimentsX-ray imaging and high-pressure and temperature flow apparatus were used to investigate and compare high and low salinity waterflooding in a carbonate rock sample. The sample was placed in contact with crude oil to obtain an initial wetting state found in hydrocarbon reservoirs. High salinity brine was then injected at increasing flow rates followed by low salinity brine injection using the same procedure. FindingsDevelopment of water micro-droplets within the oil phase and detachment of oil layers from the rock surface were observed after low salinity waterflooding. During high salinity waterflooding, contact angles showed insignificant changes from the initial value of 115°, while the mean curvature and local capillary pressure values remained negative, consistent with oil-wet conditions. However, with low salinity, the decrease in contact angle to 102° and the shift in the mean curvature and capillary pressure to positive values indicate a wettability change. Overall, our analysis captured the in situ mechanisms and processes associated with the low salinity effect and ultimate increase in oil recovery.

Capillary pressure and relative permeability estimation for low salinity waterflooding processes using pore network models

SummaryAlthough the advantages of Low Salinity Waterflooding (LSW) have been widely reported, studies of LSW in the past two decades have mainly focused on the underlying mechanisms through core flooding experiments. For more successful and broader applications of LSW in the field scale, it is required to have a comprehensive understanding of the LSW performance with complex geological features on a large scale that has never been addressed in the past. This paper presents insights on field scale modeling and prediction of LSW to address the current challenges with: (1) an equation-of-state compositional simulator fully coupled to multiple ion exchanges, geochemical reactions, and wettability alteration; (2) incorporation of critical geological properties important in LSW; (3) effective closed-loop reservoir management for design and prediction of the LSW process; (4) LSW evaluation in a full field scale.A mechanistic LSW model and a closed-loop modeling approach are introduced in this paper that can efficiently capture the critical effects of geology on the LSW process by integrating the use of geological software, a reservoir simulator and a robust optimizer. First, eighty geostatiscal realizations with different facies and lithology properties and distributions are generated to evaluate the effect of reservoir geology, in particular the critical effects of clay, on LSW. A wide range of recovery factors from 19% to 40% indicate that the effectiveness of LSW strongly depends on geological factors such as facies properties, clay distribution and clay proportion. In consistency with the laboratory and field-scale observations, wettability alteration has been identified as the dominant effect that contributes approximately 58% to 73% to the incremental oil recovery from these realizations. Detailed analyses of the key factors were addressed to allow the design of optimal injection strategies to maximize the oil recovery by LSW. LSW is then evaluated in a closed-loop reservoir management for a sandstone reservoir in both secondary and tertiary modes. It is found that secondary and tertiary LSW give about 6% and 4.1% incremental OOIP over high salinity waterflooding, respectively. The simulation results also indicate that the sooner the LSW process is started, the better the benefit is.

A new generation improved oil recovery methods comes from combining techniques to make the overall process of oil recovery more efficient. One of the most promising methods is combined Low Salinity Surfactant (LSS) flooding. Low salinity brine injection has proven by numerous laboratory core flood experiments to give a moderate increase in oil recovery. Current research shows that this method may be further enhanced by introduction of surfactants optimized for lowsal environment by reducing the interfacial tension. Researchers have suggested different mechanisms in the literature such as pH variation, fines migration, multi-component ionic exchange, interfacial tension reduction and wettability alteration for improved oil recovery during lowsal injection. In this study, surfactant solubility in lowsal brine was examined by bottle test experiments. A series of core displacement experiments was conducted on nine crude oil aged Berea core plugs that were designed to determine the impact of brine composition, wettability alteration, Low Salinity Water (LSW) and LSS flooding on Enhancing Oil Recovery (EOR). Laboratory core flooding experiments were conducted on the samples in a heating cabinet at 60 °C using five different brine compositions with different concentrations of NaCl, CaCl2 and MgCl2. The samples were first reached to initial water saturation, Swi, by injecting connate water (high salinity water). LSW injection followed by LSS flooding performed on the samples to obtain the irreducible oil saturation. The results showed a significant potential of oil recovery with maximum additional recovery of 7% Original Oil in Place (OOIP) by injection of LS water (10% LS brine and 90% distilled water) into water-wet cores compared to high salinity waterflooding. It is also concluded that oil recovery increases as wettability changes from water-wet to neutral-wet regardless of the salinity compositions. A reduction in residual oil saturation, Sor, by 1.1–4.8% occurred for various brine compositions after LSS flooding in tertiary recovery mode. The absence of clay swelling and fine migration has been confirmed by the stable differential pressure recorded for both LSW and LSS flooding. Aging the samples at high temperature prevented the problem of fines production. Combined LSS flooding resulted in an additional oil recovery of 9.2% OOIP when applied after LSW flooding. Surfactants improved the oil recovery by reducing the oil-water interfacial tension. In addition, lowsal environment decreased the surfactant retention, thus led to successful LSS flooding. The results showed that combined LSS flooding may be one of the most promising methods in EOR. This hybrid improved oil recovery method is economically more attractive and feasible compared to separate low salinity waterflooding or surfactant flooding.

Over the past two decades, low salinity waterflooding has emerged as a successful tertiary recovery method. Several mechanisms have been suggested to contribute to the effect of the low salinity waterflooding. Fines migration in clay containing sandstones is amongst the main reasons attributed to the success of this technique. The effect resulting from the migration of fines helps homogenize the flow pattern of the waterfront, thus achieving better displacement efficiency. Little or no attention has been given to the effect of water blockage on multilayered reservoirs. The present work aims to study the effect of low salinity waterflooding on multilayered clay-rich sandstone reservoirs. Parallel coreflood experiments were used to investigate the effect of low salinity waterflooding on multilayered reservoirs. Clay-rich Bandera sandstone cores were used for the experiment. Cores from two different blocks were used to obtain a contrast in the absolute permeability. All cores were saturated with the same high salinity formation water and then displaced with oil to reach initial water saturation. The cores were then aged at the reservoir temperature for 21 days. Three parallel coreflood experiments were used to compare the high salinity waterflooding to the low salinity waterflooding in both secondary and tertiary modes. Core effluent and CT scan were used to evaluate the recovery from all experiments. The high salinity waterflooding shows heterogeneous water invasion, and more oil was recovered from the higher permeability core. Alternatively, the low salinity waterflooding in secondary mode showed a more homogeneous recovery regime, as the water blockage kept the waterfront advancement even between cores. Finally, the application of low salinity waterflooding in tertiary mode slightly improved the recovery from both cores equally. This work is the first to emphasize the benefits of low salinity waterflooding in multilayered clay-rich sandstones. The conclusions from this work suggest a diversion effect to occur allowing for higher displacement efficiencies in multilayered clay-rich reservoirs.

After nearly thirty years of research and development, it is now widely agreed that Low Salinity Waterflooding (LSW) provides better oil recovery than High Salinity Waterflooding (HSW). Past studies also showed that there are significant advantages in combining LSW with other conventional EOR methods such as chemical flooding (polymer flooding and surfactant flooding) or miscible gas flooding to benefit from their synergies and to achieve higher oil recovery factor and project profit. This paper presents a study of Hybrid Low Salinity Chemical Flooding as a novel EOR approach with: (1) development of hybrid EOR concept from past decades; (2) implementation of an efficient modeling approach utilizing artificial intelligent technology for mechanistic modeling of these complex EOR processes; (3) systematic validation with laboratory data; and (4) uncertainty evaluation of LSW process at field scale. The phase behavior of an oil-water-microemulsion system was modeled without the need of modeling type III microemulsion explicitly. The approach has been successfully applied to model both conventional Alkaline-Surfactant-Polymer (ASP) flooding and emerging EOR processes (LSW, Alkaline-CoSolvent-Polymer, and Low-Tension-Gas Flooding). The new development allows the mechanistic modeling of the benefits of combining LSW and chemical EOR. One of the main challenges for mechanistic modeling of these hybrid recovery processes is that several factors, e.g. polymer, surfactant, and salinity, can change the relative permeability simultaneously. To overcome this problem, Multilayer Neural Network (ML-NN) technique was applied to perform N-dimensional interpolation of relative permeability. The model was validated with coreflooding data and the effectiveness of hybrid processes were compared with conventional recovery methods. The proposed model showed good agreements with different coreflooding experiments including HSW, LSW, and Low Salinity Surfactant flooding (LSS). This model efficiently captures the complex geochemistry, wettability alteration, microemulsion phase behavior, and the synergies occurring in these hybrid processes. Results indicated that LSS is an economically attractive hybrid EOR process since it increases the ultimate recovery factor compared to the conventional approaches and reduces surfactant retention. Bayesian workflow using ML-NN algorithm is efficient to capture the uncertainties in history matching and production forecasting of LSW.

SummaryCombining low-salinity-water (LSW) and polymer flooding was proposed to unlock the tremendous heavy-oil resources on the Alaska North Slope (ANS). The synergy of LSW and polymer flooding was demonstrated through coreflooding experiments at various conditions. The results indicate that the high-salinity polymer (HSP) (salinity = 27,500 ppm) requires nearly two-thirds more polymer than the low-salinity polymer (LSP) (salinity = 2,500 ppm) to achieve the target viscosity at the condition of this study. Additional oil was recovered from LSW flooding after extensive high-salinity-water (HSW) flooding [3 to 9% of original oil in place (OOIP)]. LSW flooding performed in secondary mode achieved higher recovery than that in tertiary mode. Also, the occurrence of water breakthrough can be delayed in the LSW flooding compared with the HSW flooding. Strikingly, after extensive LSW flooding and HSP flooding, incremental oil recovery (approximately 8% of OOIP) was still achieved by LSP flooding with the same viscosity as the HSP. The pH increase of the effluent during LSW/LSP flooding was significantly greater than that during HSW/HSP flooding, indicating the presence of the low-salinity effect (LSE). The residual-oil-saturation (Sor) reduction induced by the LSE in the area unswept during the LSW flooding (mainly smaller pores) would contribute to the increased oil recovery. LSP flooding performed directly after waterflooding recovered more incremental oil (approximately 10% of OOIP) compared with HSP flooding performed in the same scheme. Apart from the improved sweep efficiency by polymer, the low-salinity-induced Sor reduction also would contribute to the increased oil recovery by the LSP. A nearly 2-year pilot test in the Milne Point Field on the ANS has shown impressive success of the proposed hybrid enhanced-oil-recovery (EOR) process: water-cut reduction (70 to less than 15%), increasing oil rate, and no polymer breakthrough so far. This work has demonstrated the remarkable economical and technical benefits of combining LSW and polymer flooding in enhancing heavy-oil recovery.

Many experimental works have investigated smart water and low salinity water flooding and observed significant incremental oil recovery following changes in the injected brine composition. The commonway approach to model such EOR mechanisms is by shifting the input relative permeability curves, particularly including a reduction of the residual oil saturation. Cores that originally display oil-wetness may retain much oil at the outlet of the flooded core due to capillary pressure being zero at a high oil saturation. This end effect is difficult to overcome in high permeable cores at typical lab rates. Injecting a brine that changes the wetting state to less oil-wet conditions (represented by zero capillary pressure at a lower oil saturation) will lead to a release of oil previously trapped at the outlet. Although this is chemically induced incremental oil, it represents a reduction of remaining oil saturation, not necessarily of residual oil saturation. This paper illustrates the mentioned issues of interpreting the difference in remaining and residual oil saturation during chemical EOR and hence the evaluation of potential smart water effects. We present a mathematical model representing core flooding accounting for wettability changes due to changes in the injected composition. For purpose of illustration, this is performed in terms of adsorption of a wettability alteration component coupled to shifting of relative permeability and capillary pressure curves. The model is parameterized in accordance with experimental data by matching brine-dependent saturation functions to experiments where wettability alteration takes place dynamically due to changing one chemical component. It is seen that several effects can give an apparent smart water effect without having any real reduction of the residual oil saturation, including 1) changes in the mobility ratio, where the oil already flowing is pushed more efficiently, and 2) the magnitude of capillary end effects can be reduced due to increased water-wetness or due to reduction in water relative permeability giving a greater viscous drag on the oil.

A multi-scale experimental study of crude oil-brine-rock interactions and wettability alteration during low-salinity waterflooding

Recent field applications and laboratory studies have recognized that low-salinity waterflooding as a potentially effective technique to achieve sufficient recovery in sandstone reservoirs. It was found that the impact of clay content, rock permeability, and rock quality are still questionable on the performance of low-salinity waterflooding. A set of comprehensive coreflood tests have been conducted to estimate displacement efficiency and investigate the effect of clay content and rock quality using Bandera, Parker, Grey Berea, and Buff Berea sandstone cores. The coreflood experiments have been conducted on 20 and 6 in. length and 1.5 in. diameter outcrop cores at 185°F and 500 psi. Oil recovery, pressure drop, and pH were observed and analyzed after each coreflooding experiment. The mineralogy of the samples was assessed by X-ray powder diffraction, scanning electron microscopy, and X-ray fluorescence. The oil recovery from conventional waterflooding ranged from 24.6 to 44.7% OOIP. The oil recovery decreased when the reservoir permeability decreased. The Bandera, Parker, Grey Berea, and Buff Berea sandstone cores showed additional oil recovery ranging from 4 to 17% OOIP through injection of low-salinity brine (5000 ppm NaCl) as a secondary recovery mode. As the permeability increased from 6 to 167 md, an additional oil recovery up to 32.9% of OOIP was observed by low-salinity waterflooding. None of the three sandstone rock types (Buff Berea, Grey Berea, and Parker) showed a response in the tertiary recovery mode. A significant incremental oil recovery of 6.9% OOIP was recovered in the tertiary mode for the Bandera sandstone rock. No direct relation was found between the total clay contents and oil recovery. In addition to the clay content, the sandstone rock quality and minerals distribution appears to play a key role in the effectiveness of low-salinity waterflooding. The rock quality has a significant effect in the performance of low-salinity waterflooding. The incremental oil recovery increased from 4 to 17% when the average pore-throat radius (R35) of the core increased from 1.3 to 8.7 microns. Introduction Waterflooding is the most common type of supplementary recovery in which water is injected into the reservoir and displaces oil towards the producing zone. In the conventional waterflooding, the used injection water may be taken from the nearest available source. These sources include produced water, rivers, lakes, seawater, and aquifers. Historically, the physical mechanism behind this improvement in oil recovery was attributed to the pressure maintenance and displacement of oil by injected water. Based on the conventional view, the injection brine composition and salinity were believed to have no effect on the efficiency of oil recovery by waterflooding (Schumacher 1978). Hughes and Pfister (1947) pointed out that brines would keep the clay content of producing sands in a permanently flocculated condition, and therefore, brines were recommended for use in the secondary recovery mode by waterflooding. Over the last decade several laboratory studies and field tests have shown that low-salinity waterflooding (LSW) and smart waterflooding improved oil recovery compared to high-salinity waterflooding (HSW) for sandstone and carbonate reservoirs. LSW flooding involves injecting brine with a lower salt content or ionic strength. Previous laboratory and field tests indicated that the injected brine was in the range of 500–5,000 parts per million (ppm) of total dissolved solids (TDS) (Yildiz and Morrow 1996; Nasralla and Nasr-El-Din 2011). Yildiz and Morrow (1996) showed that changes in injection-brine composition can improve recovery, thereby introducing the idea that the composition of brine could be varied to optimize waterflood recovery. Tang and Morrow (1997) noticed that LSW has a good potential to improve oil recovery. Tang and Morrow (1999) concluded that the presence of clays, initial water saturation, and crude oil were all necessary for LSW to increase oil recovery.