Skule Strand

Chemical flooding of oil reservoirs 4. Effects of temperature and pressure on the middle phase solubilization parameters close to optimum flood conditions

Abstract The effect of pressure and temperature on the multi-phase behavior of a multicomponent model oil, with and without methane, and a one-component surfactant system has been studied at constant salinity (2.20 wt.% NaCl solution) close to the optimum condition for oil recovery. Solubilization parameters of oil and water in the middle phase have been determined at actual temperatures (70–110°C) and pressures (100–600 bar). Both of the systems showed a normal phase behavior in the three-phase region by changing the pressure and temperature. Increase in pressure and temperature caused the systems to move towards the II(−) state. The variation in the solubilization parameters caused by changes in pressure and temperature close to optimum flood condition is discussed. The multiphase behavior is also discussed in relation to the composition of the oil.

Wettability of chalk: impact of silica, clay content and mechanical properties

The success of improved oil recovery from natural fractured chalk fields by injection of water depends largely on the wetting conditions of the reservoir rock and also, to some extent, on the compaction due to water weakening of the formation. Samples from outcrops are often used to mimic the reservoir properties in laboratory work. The present study illustrates that care must be taken when selecting outcrop material; in particular, the content of silica will affect these important properties. Chalk samples from Aalborg, which contained significant amounts of silica and minor amounts of clay (6.3 wt% Si), were studied by SEM and the mineral properties of the silica characterized. The surface chemistry of the porous medium was different from chalk containing smaller amounts of silica and clay (1.4–2.8 wt%). In the presence of a crude oil with high acid number and initial formation water, the water-wet fraction of Aalborg chalk remained close to 1.0 after aging for four weeks at 90°C in the crude oil. The Amott–Harvey wetting index showed, however, the wetting condition to be close to neutral, and only small amounts of water and oil imbibed spontaneously at the residual saturations. The difference in wetting conditions due to different content of silica and clay is also reflected in differences in the mechanical properties. It appeared that the mechanical strength, as studied by a large number of tests, became weaker as the water wetness decreased. The effect of wettability on the water weakening of chalk is discussed in terms of chalk dissolution and the chemistry associated with thin water films. As an overall conclusion and recommendation, a careful comparison should be made of the Si-content in the reservoir rock and outcrop chalk when picking material for laboratory experiments.

Chemical flooding of oil reservoirs 5. The multiphase behavior of oil/brine/surfactant systems in relation to changes in pressure, temperature, and oil composition

Abstract Multiphase PVT-studies are conducted on surfactant-brine-oil systems relevant for oil recovery processes. An alkyl- o -xylene sulfonate is used as surfactant, NaCl-solution as brine, and various types of live oil, i.e. crude oil, fraction of crude oil, and model oil. Solubilization parameters for the microemulsion phase are determined in the temperature range of 40–180°C and the pressure range of 200–1000 bar. By increasing the pressure the trend in the phase behavior in all cases is II(+)/III/II(−). In the temperature scan the crude oil system showed a II(−)/III/II(+) phase behavior by increasing the temperature, while the model oil and the distillation cut of the crude oil without the heavy end fraction showed the opposite phase behavior, II(+)/III/II(−). The difference in the phase properties is discussed in terms of the resin-type compounds acting as cosurfactants, and the dissolution of water into the oil phase at high temperatures.

“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.

Why Such a Small Low Salinity EOR – Potential from the Snorre Formation?

Two cores from the Lunde formation in the Snorre field have been tested at reservoir temperature for enhanced oil recovery by the low saline water injection technique. In both cases, the cores were cleaned by successive flooding with toluene, methanol, an

Wettability Restoration of Limestone Cores Using Core Material From the Aqueous Zone

Abstract In the struggle to mimic the wetting state of a limestone reservoir, strongly water wet preserved cores from the aqueous zone have been used. By exposing the cores to the reservoir crude oil and formation water, the authors tried to mimic core properties from the oil leg. Wettability and oil recovery of restored cores were compared, confirming that both wettability and oil recovery depended on the fluids used in the cleaning process. When the preserved cores from the water zone was cleaned mildly and restored with formation brine and crude oil, they behaved in strongly water-wet way (reference core), while restored oil contaminated cores cleaned by organic solvents acted less water-wet. The water wetness was improved when the oil-contaminated cores were cleaned with hot seawater or hot seawater containing cationic surfactant. The oil recovery by spontaneous imbibition for the reference cores was significantly higher than the restored cores previously exposed to crude oil. In the case of forced displacement, the oil recovery from the water-wet reference core was lower than the same restored core.

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.

Produced Water Treatment with Membranes for Enhanced Oil Recovery in Carbonate and Sandstone Reservoirs

The research is focused on determining the technical performance of membranes for treating and reinjecting produced water (PW). Ionic composition of pre-treated PW containing 90,000 ppm total dissolved solids (TDS) is manipulated by membrane separation and reinjected as smart water in carbonate and sandstone reservoirs. Nanofiltration (NF) membranes coupled with reverse osmosis (RO) membranes are tested in this research. TDS of less than 5,000 ppm with negligible divalent ions is defined as Smart Water for sandstone reservoirs. High divalent ion concentrations with TDS typically above 10,000 ppm compose Smart Water for carbonate reservoirs. The performance of NF membranes at different pH of PW is evaluated at various pressures. An economic analysis is performed for different combinations of membranes with TDS of 90,000 ppm as reference. A combination of two NF membranes are used to produce Smart Water for carbonate reservoirs. The power consumption is calculated at 0.37 kWh/m3. PW reinjection in sandstones with TDS of 5,000 ppm require either the use of permeate from RO or supplying fresh water by other means for diluting permeate from NF. A power consumption of 14.8 kWh/m3 is calculated for the combination of two NF membranes and RO for Smart Water production for sandstones.

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.

Implementation of Spiegler–Kedem and Steric Hindrance Pore Models for Analyzing Nanofiltration Membrane Performance for Smart Water Production

A predictive model correlating the parameters in the mass transfer-based model Spiegler–Kedem to the pure water permeability is presented in this research, which helps to select porous polyamide membranes for enhanced oil recovery (EOR) applications. Using the experimentally obtained values of flux and rejection, the reflection coefficient σ and solute permeability Ps have been estimated as the mass transfer-based model parameters for individual ions in seawater. The reflection coefficient and solute permeability determined were correlated with the pure water permeability of a membrane, which is related to the structural parameters of a membrane. The novelty of this research is the development of a model that consolidates the various complex mechanisms in the mass transfer of ions through the membrane to an empirical correlation for a given feed concentration and membrane type. These correlations were later used to predict ion rejections of any polyamide membrane with a known pure water permeability and flux with seawater as a feed that aids in the selection of suitable nanofiltration (NF) for smart water production.