Tina Puntervold

Chemical Mechanism of Low Salinity Water Flooding in Sandstone Reservoirs

Both laboratory and single well field tests have documented that enhanced oil recovery can be obtained from sandstone reservoirs by performing a tertiary low saline waterflood. Due to the complexity of the crude oil-brinerock interactions, the mechanism behind the low saline EOR process has been debated in the literature for the last decade. Both physical and chemical mechanisms have been proposed, but it appears that none of the suggested processes has so far been generally accepted as the main contributor to the observed low salinity EOR effect. Based on published data and new experimental results on core flooding, effects of pH and salinity on adsorption of acidic and basic organic components onto different clay minerals, clay properties like ion exchange capacity and selectivity, and oil properties, a new chemical mechanism is suggested, which agrees with documented experimental facts. At reservoir conditions, the pH of formation water is about 4 due to dissolved acidic gases like CO2 and H2S. At this pH, the clay minerals, which act as cation exchange material, are adsorbed by acidic and protonated basic components from the crude oil, and cations, especially divalent cations, from the formation water, like Ca. Injection of a low saline fluid, which promotes desorption of Ca, will create a local increase in pH close to the brine-clay interface because Ca is substituted by H from the water. A fast reaction between OH and the adsorbed acidic and protonated basic material will cause desorption of organic material from the clay. The water wetness of the rock is improved, and increased oil recovery is observed. To observe low salinity EOR effects in sandstones, a balanced initial adsorption of organic components and Ca onto the clay is needed. Both the adsorption capacity and the pH-window for adsorption/desorption of organic material is somewhat different for various types of clay minerals. A detailed knowledge of the chemical mechanism behind the low saline EOR process together with information on formation brine composition, oil properties and type of clay material present, will make it possible to evaluate the potential for increase in oil recovery by a low salinity waterflood. Introduction A great number of laboratory tests by Morrow and co-workers (Tang and Morrow, 1999a; Tang and Morrow, 1999b; Zhang and Morrow, 2006; Zhang et al., 2007b) and also by researchers at BP (Lager et al., 2007; Webb et al., 2005a; Webb et al., 2005b) have confirmed that enhanced oil recovery can be obtained when performing a tertiary low salinity waterflood, with salinity in the range of 1000-2000 ppm. Based on 14 tests from different sandstone reservoirs, Lager et al. (Lager et al., 2007) have reported that the average increase in recovery was about 14%. The laboratory observations have even been confirmed by single well tests performed in an Alaskan reservoir (Lager et al., 2008b). As increasing amounts of laboratory experiment results have been published in the last decade, various suggestions of the mechanism behind the low salinity process have appeared. Unfortunately, none of the suggested mechanisms have so far been generally accepted as the “true” mechanism. The reason is that many parameters linked to the rock, to the reservoir fluids (oil and brine), and to the injection fluid are involved. In order to give the reader a good background to understand the proposed mechanism in this paper, a list of the accepted experimental conditions is given, followed by a short recap of the previously suggested mechanisms. Conditions for low salinity effects The listed conditions for low salinity effects are mostly related to the systematic experimental work by Tang and Morrow (Tang and Morrow, 1999a), but some points has also been taken from the work by BP (Lager et al., 2007; Lager et al., 2008a).

“Smart Water” as Wettability Modifier in Carbonate and Sandstone

Waterflooding has for a long time been regarded as a secondary oil recovery method. In the recent years, extensive research on crude oil, brine, rock (COBR) systems has documented that the composition of the injected water can change wetting properties of the reservoir during a waterflood in a favorable way to improve oil recovery. Thus, injection of Smart Water with a correct composition and salinity can act as a tertiary recovery method. Economically, it is, however, important to perform a water flood at an optimum condition in a secondary process. Examples of Smart Water injection in carbonates and sandstones are: Injection of seawater into high temperature chalk reservoirs Low Salinity floods in sandstone reservoirs The chemical mechanism behind the wettability alteration promoted by the injected water has been a topic for discussion both in carbonates and especially in sandstones. In this paper, the suggested mechanisms for the wettability modification in the two types of reservoir rocks are shortly reviewed with a special focus on possible chemical similarities. The different chemical bonding mechanisms of polar components from the crude oil onto the positively charged carbonate and the negatively charged quartz/clay indicates a different chemical mechanism for wettability modification by Smart Water in the two cases.

Optimizing the Low Salinity Water for EOR Effects in Sandstone Reservoirs - Composition vs Salinity

Particularly, even though a low salinity brine often is a successful EOR fluid, this paper shows that the importance of specific salinity comes along with the brine composition. Water with salinities below 5000 ppm are generally accepted as LS EOR fluids, but in this work “smart water” EOR effects at higher salinities than 5000 ppm have been observed. Improved oil recovery was observed in tertiary mode using a 40000 ppm NaCl brine and 25000 ppm NaCl brine, the results are in line with the suggested chemical mechanism for wettability alteration due to a local pH increase triggered by calcium desorption. The speed of oil production and ultimate recovery is influenced by the concentration of Ca2 in the FW and salinity (presence of NaCl) of the smart water brine.

Co-injection of Seawater and Produced Water to Improve Oil Recovery from Fractured North Sea Chalk Oil Reservoirs

Carbonate oil reservoirs are often fractured with moderate water-wet conditions,which prevent spontaneous imbibition of water into the matrix blocks.Enhanced oil recovery by water flooding is therefore seldom successful,and the average oil recovery from carbonates is usually much less than 30%.Hence,the improved oil recovery potential is very high in these types of reservoirs.At T100 ℃,the oil recovery by using PW:SSW mixtures in ratios ranging from 2:1 to 1:8 was significantly higher than by using pure PW in a spontaneous imbibition process.In a viscous flood,SSW appeared to be much more efficient than PW to displace the oil,and high oil recovery values were reached.

Impact of Anhydrite on the Low Salinity EOR Effect in Sandstone Material with High Clay Content

At low oil price, using expensive chemicals in EOR methods is not economically feasible. Injecting water of a tailored composition, i. e. Smart Water, is thus a better option. It has previously been shown that injecting a brine of low salinity (LS), very often results in an increased oil production. In laboratory experiments it has been found that an “in situ” induced pH increase is a key parameter to experiencing a LS EOR effect in sandstones. In a field situation, e.g. Endicott, this pH increase is rarely observed, due to pH buffering by fluids, minerals and sour gases. When a LS injection brine is introduced into a core containing crude oil and high salinity (HS) formation water, desorption of cations from the mineral surface, and a subsequent adsorption of protons, H , leaves OH-, which increases pH. At high OH- concentrations, the acidic and basic polar organic molecules attached to the mineral surface transform into species of lower affinity to the mineral surface, and are released, leading to increased oil recovery. However, the different minerals present in sandstone can influence the induced pH increase. A pH screening test has been developed to investigate the minerals’ influence on pH. Clays are the main wetting materials in sandstone rocks, and they are also known to be cation exchangers, which can influence pH in the system. Feldspars have also been shown to influence pH in both a positive and a negative way, the latter responsible for the poor LS effect in the Snorre field on the NCS. A mineral often present in reservoir rock, but usually ignored, is anhydrite, CaSO4. In this paper the LS EOR potential in reservoir sandstone containing anhydrite and significant clay content was tested. Because of the amount of clays, this reservoir should be a good candidate for LS injection. The LS EOR potential was investigated using the pH screening test, oil recovery tests and chemical analyses. The main results from this study showed that reservoir core material containing anhydrite experienced poor LS EOR effects. When LS brine is injected into a reservoir containing anhydrite, some of the anhydrite dissolves and prevents parts of the cation desorption from the clay surface, thereby lowering the pH increase needed to observe increased oil recovery. Based on this study, other minerals than clays, such as anhydrite, can have a serious influence on the reservoir LS EOR potential, and should not be overlooked.

Improved Oil Recovery from North Sea Chalk Fields by Injection of Optimized Seawater

Originally, chalk reservoirs were waterflooded for pressure support; maintaining the pressure above the bubble point of the oil, and also preventing the compaction of the rock caused by the pressure depletion. Seawater waterflooding into a chalk reservoir in the North Sea proved to be a success not only by maintaining pressure and reducing compaction, but additionally the oil recovery rate soon increased. Intensive research during the last decade has proven that seawater at high temperatures acts as a “Smart Water” being able to improve the water wetness of carbonates. The reason for that are the chemical interactions happening in the reservoir between the oil, rock and injection water, disturbing the established chemical equilibrium and leaving the rock surface a little more water-wet. The increased water wetness generates positive capillary forces, and the microscopic sweep efficiency is increased. Recent research has shown that seawater can even be modified to improve the oil recovery in a spontaneous imbibition process by 10% compared to the recovery using ordinary seawater. The seawater composition has to be tailored for every specific reservoir system, and especially important parameters to consider, when deciding on the composition of the injected seawater, are the mineralogy of the reservoir rock, and the temperature of the reservoir. For high temperature chalk fields > 100 °C, like Ekofisk (130 °C), seawater depleted in NaCl should be used as the “Smart Water” EOR fluid. For lower temperature reservoirs, <100 °C, like Valhall (90 °C), either seawater spiked with sulfate or seawater depleted in NaCl and spiked with sulfate should be used as the “Smart Water” EOR fluid. In this study, the objective was to optimize the seawater-based “Smart Water” composition for injection into chalk/carbonate. The optimal amount of NaCl present in seawater was investigated at 90 °C. The experimental results showed that more than 90% of the NaCl needed to be removed from seawater in order to increase the oil recovery significantly, compared to the recovery using ordinary seawater. By doing so, the oil recovery increased by approximately 8% OOIP.

The Impact of Common Reservoir Minerals and Temperature on the Low Salinity EOR-effect in Sandstone

The mechanism of the low salinity EOR process in Sandstone reservoirs has been debated in the literature for more than a decade. We recently proposed a chemical wettability alteration mechanism for the process, well founded in experimental observations. Even though this main chemical understanding is quite well described, there are parameters/factors that could disturb the main process. Combinations of certain minerals, temperature, and salinity/composition of formation water could have impact on the low salinity EOR process. Plagioclase, a polysilicate mineral, is often present in sandstone reservoir rocks, and could have a significant effect on the initial pH of the formation water, which will influence the initial wetting conditions. In this experimental work it is shown that Plagioclase in reservoir rock and outcrop material responded differently on the low salinity effect. It is also verified that enhanced dissolution of anhydrite, CaSO4, in the low saline fluid suppressed the increase in pH, which is an important parameter for observing tertiary low salinity effects. A combination of high reservoir temperature, Tres>100 oC and very high salinity of the formation water, >200 000 ppm, resulted in too water wet conditions for observing tertiary low salinity EOR effects, even though the clay content was high, ≈20 wt%. The experimental results are in line and discussed in relation to the previously published chemical mechanism for the low salinity EOR process.

Wetting Properties of Chalk – Impact of Water Soluble Acidic Material in Crude Oil

Carboxylic material present in the crude oil, quantified as acid number (AN), is believed to be the most important wetting parameter for carbonates. The water wetness decreases as the AN increases. At high temperature, seawater is able to displace some of the adsorbed carboxylic materials, and seawater therefore acts as a wettability modifier causing increased oil recovery both by spontaneous imbibition and by forced displacement. It has been documented that interactions between ions present in seawater, Ca2 , Mg2 and SO42-, and the chalk surface are responsible for the wettability modification. The properties of the carboxylic material may have influence on the initial wetting conditions and also on the wettability alteration process. In this paper we have extracted water soluble acids from a crude oil with high AN. The original oil (AN=1.8 mgKOH/g) and the treated oil depleted in water soluble acids (AN=1.5 mgKOH/g) were used to study wetting properties and oil recovery by spontaneous imbibition with chalk as the porous medium. The water wetness appeared to be lower for the original oil compared to the treated oil. In a spontaneous imbibition process with wettability modification at 110 °C, seawater imbibed faster into the cores saturated with the treated oil containing no water soluble acids.

EOR from Carbonates by Using Smart Water

Seawater acts as an EOR-fluid, “Smart Water”, in chalk by improving the water wetness at high temperatures, T>90 °C. It has been verified that Ca2 , Mg2 , and SO42- are the active ions in the chemical mechanism for wettability alteration. In this paper, we have identified the chemical reactions involved and compared the reactivity of outcrop chalk and reservoir limestone cores. In general, and as expected, the active ions showed the same chemical reactions towards the chalk and limestone surface, but the reactivity of the limestone surface was significantly lower than that of the pure biogenic chalk surface. It is, however, expected that seawater can act as a “Smart Water” also for limestone at the right conditions.