Ingebret Fjelde

Chemical flooding of oil reservoirs Part 9. Dynamic adsorption of surfactant onto sandstone cores from injection water with and without polymer present

Abstract The effect of polymer on the adsorption of surfactant at the solid/liquid interface related to low tension polymer water flood (LTPWF) of sandstone oil reservoirs was studied by means of dynamic laboratory experiments. An alkylpropoxyethoxy sulfate was used as surfactant, xanthan and a copolymer of acrylamide and sodium 2-acrylamido-2-methylpropane sulfonate (An 125) were used as polymers, crude oil and n-heptane were the soils, and synthetic seawater was used for brine. All experiments were conducted at 50°C and 1 atm. Long-term adsorption experiments were performed by circulating the chemical solution through clay-containing reservoir cores for several weeks, and short-term experiments were conducted by injecting chemical slugs of constant concentration, but different size, through model sandstone cores. Various adsorption regimes of the surfactant were detected at different contact times between the reservoir core material and the circulated chemical solution, and it was observed that xanthan behaves as a sacrificial adsorbate towards the surfactant by decreasing the surfactant adsorption. In the slug experiments, using model cores, xanthan appeared to decrease the surfactant adsorption when using small surfactant slug sizes, but no measurable effect of xanthan or AN 125 on surfactant adsorption was observed for large sizes. A dynamic reversible adsorption model appeared to predict the propagation of the surfactant slug through the porous medium, but the adsorption level was not fitted.

Physicochemical principles of low tension polymer flood

Abstract Co-injection of low-concentration surfactant and a biopolymer, followed by a polymer buffer for mobility control, leads to reduced chemical consumption and high oil recovery. The method has been termed Low Tension Polymer Flood, LTPF, by BP. The present paper gives a critical discussion of the physicochemical phenomena behind LTPF. Surfactant-polymer interaction in solution and chromatographic separation of surfactant and polymer during the flooding process are believed to be important factors in performing a LTPF. The criteria with regard to chemicals and porous media are discussed in order to obtain LTPF performance. Flooding mechanisms are suggested based on an oil-in-water, II(−), and a multiphase, III, flood behavior. It is suggested to use a polymer gradient when implementing LTPF at constant salinity in the multiphase state to minimize the loss of surfactant. The HPLC method to study surfactant-polymer complex formation, applying the gel filtration technique, is presented.

Adsorption VI. Nonequilibrium adsorption of ethoxylated sulfonate onto reservoir cores in the presence of xanthan

Abstract Coinjection of xanthan (a polymer) with ethoxylated sulfonate (a surfactant) leads to reduced consumption of the latter. The sacrificial adsorbate effect of xanthan toward ethoxylated sulfonates has been studied under a nonequilibrium adsorption process using two oil-containing reservoir cores. The chemical solutions were circulated through the cores for several weeks at 50°C using an oil-in-water microemulsion. The core without polymer present showed a fast and a slow, diffusion-controlled adsorption process of the surfactant. In the presence of polymer no slow adsorption regime was observed. The final equilibrium adsorption of the surfactant was 0.77 mg/g and 0.15 mg/g for the core without and with polymer present, respectively. The sacrificial adsorbate effect of polymers towardssurfactants is discussed in relation to possible complex formation between the two chemicals. The retention process of the polymer is also discussed.

Improved Spontaneous Imbibition of Water in Reservoir Chalks

Alteration of wettability to more water-wet and thereby improvement of spontaneous imbibition of water during sea water injection, has been studied using reservoir core plugs from two fractured chalk fields. Core plugs were prepared by removing easily accessible sulphate. The wettability conditions were characterized using the sulphate wettability test. Spontaneous imbibition of water was studied using brines with different ratios between formation water and sea water. The wettability and spontaneous imbibition for reservoir core plugs and outcrop core plugs were compared.

Modelling of wettability alteration processes in carbonate oil reservoirs

Previous studies have shown that seawater may alter the wettability in the direction of more water-wet conditions in carbonate reservoirs. The reason for this is that ions from the salt (sulphat, magnesium, calsium, etc) can create a wettability alteration toward more water-wet conditions as salt is absorbed on the rock. In order to initiate a more systematic study of this phenomenon a 1-D mathematical model relevant for spontaneous imbibition is formulated. The model represents a core plug on laboratory scale where a general wettability alteration (WA) agent is included. Relative permeability and capillary pressure curves are obtained via interpolation between two sets of curves corresponding to oil-wet and water-wet conditions. This interpolation depends on the adsorption isotherm in such a way that when no adsorption of the WA agent has taken place, oil-wet conditions prevail. However, as the adsorption of this agent takes place, gradually there is a shift towards more water-wet conditions. Hence, the basic mechanism that adsorption of the WA agent is responsible for the wettability alteration, is naturally captured by the model. Conservation of mass of oil, water, and the WA agent, combined with Darcys law, yield a 2x2 system of coupled parabolic convection-diffusion equations, one equation for the water phase and another for the concentration of the WA agent. The model describes the interactions between gravity and capillarity when initial oil-wet core experiences a wettability alteration towards more water-wet conditions due to the spreading of the WA agent by molecular diffusion. Basic properties of the model are studied by considering a discrete version. Numerical computations are performed to explore the role of molecular diffusion of the WA agent into the core plug, the balance between gravity and capillary forces, and dynamic wettability alteration versus permanent wetting states. In particular, a new and characteristic oil-bank is observed. This is due to incorporation of dynamic wettability alteration and cannot be seen for case with permanent wetting characteristics. More precisely, the phenomenon is caused by a cross-diffusion term appearing in capillary diffusion term.

A Chromatographic Analysis of Commercial Products of Ethoxylated Sulfonates

Abstract Commercial products of ethoxylated sulfonate surfactants are of current interest due to their tolerance towards hard water like sea-water. An analytical KPLC-method has been worked out which can detect and quantify the distribution of the various ethoxylated sulfonate isomers, R-(EO)x-SO3- (x = 2 -15), at sea-water salinities. The different isomers of unconverted alcohols, R-(EO)x-OH, and other possible impurities, R-(EO)x-R, in the comercial product are also separated. The metod has been worked out using a commercial product of the type C9-Ph-(EO)6-SO3Na and C8-Ph-(EO)3-SO3Na of two different suppliers. The chromatographic separation is based on a mixed-mode reversed-phase/ion-exchange column, and the analysis can be implemented as a quality-test of the commercial product.

Adsorption V. Nonequilibrium competitive adsorption of polydisperse ethoxylated sulfonates onto clay-containing cores and kaolinite

Abstract Nonequilibrium adsorption of a commercial polydisperse ethoxylated sulfonate, C 9 -Ph-(EO) x SO 3 Na ( x = 3–10), onto precleaned and oil-containing reservoir cores has been studied at surfactant concentrations well above the CMC. An analytical HPLC method based on reverved-phase/ion-exchange has been worked out, which can be used to quantify and determine the relative cation affinity of the various EO-sulfonates. Chromatographic effects, which were related to increased adsorption of the low EO-number isomers, were observed for the precleaned core. No preferential adsorption of the different isomers was observed for the oil-containing core. Static equilibrium adsorption onto kaolinite at a surfactant concentration close to the onset of the adsorption plateau showed increased adsorption of the low EO-number isomers, while at very low surfactant concentration the larger EO-number isomers showed preferential adsorption. All experiments were carried out at 70°C using synthetic seawater as the brine.

Analysis of the Wettability Alteration Process During Seawater Imbibition Into Preferentially Oil-Wet Chalk Cores

Improved oil recovery from fractured oil-wet carbonate reservoirs is a great challenge. The water-flooding efficiency will be low because of higher permeability in fractures than in matrix, and negative capillary pressure retains oil inside the matrix blocks. Studies of oil-wet chalk have shown that sulphate ions in the seawater may alter the wettability towards increased water-wetness. One-dimensional spontaneous imbibition tests of seawater into preferentially oil-wet chalk cores are performed. To get a better understanding, a numerical model has been developed which includes effects of wettability alteration. The experiments are carried out on cylindrical, sealed core plugs with only top open or with both ends open. Only countercurrent imbibition takes place for cores with top end open. For cores with both ends open, both countercurrent and cocurrent imbibition take place, and oil recovery rate is obviously accelerated. Taking formation water as the base case, higher oil recovery is observed with seawater imbibition. To simulate the wettability alteration process caused by seawater, a model is developed which includes molecular diffusion, adsorption of wettability alteration (WA) agent, gravity and capillary pressure. The WA agent diffuses into the formation water initially present in the core, adsorb onto the rock surface and induce wettability alteration. Consequently, the capillary pressure curve is shifted to higher values. In particular, the capillary pressure at the initial water saturation changes from negative to positive values and seawater is imbibed into the core. The shapes of relative permeability curves also depend on the wettability. The simulation results can fairly well match the experimental data. With the experimental and modeling work we explore the interplay between capillarity and gravity, and especially the importance to consider wettability alteration process is again confirmed. Introduction Spontaneous imbibition is a process where a wetting phase displaces the non-wetting phase in a porous media by capillary action. It is important for fractured reservoirs to produce oil from the rock matrix. Many carbonate reservoirs are naturally fractured but often preferentially oil-wet (Roehl and Choquette, 1985; Chillingar and Yen, 1983). Water can enter the oil-wet matrix block to displace oil only if it overcomes the entry pressure or capillary barrier. The goal can be achieved by several mechanisms, altering the wetting state of the rock surface, lowering interfacial tension, or making use of viscous or gravitational forces. With the first approach the capillary pressure can be changed from negative to positive value which then leads to spontaneous imbibition. Many literatures have reported the wettability alteration towards water-wetness caused by surfactants (Spinler and Baldwin, 2000; Seethepalli et al., 2004; Standnes and Austad, 2000b). Usually the surfactant will also reduce the interfacial tension quite a lot, but at the same time it decreases the capillary pressure, and then spontaneous imbibition process will be negatively influenced. On the other side, the commercial feasibility of surfactant should be further studied. Strand et al. (2003) studied the spontaneous imbibition of aqueous surfactant solutions into oil-wet carbonate cores. They observed that sulphate in the imbibing fluid had a positive effect to improve spontaneous imbibition behavior. Recent laboratory studies indicated that seawater could improve oil recovery from moderately water-wet chalk reservoir such as the Ekofisk field (Austad et al., 2005; Hognesen ans Standnes, 2006; Zhang and Austad, 2005; Zhang and Austad, 2006). It was observed that high temperature and the presence of sulphate ions in the injected seawater were the key factors for wettability modifications towards more water-wet conditions. The water-wetness of the chalk material increased with increasing temperature and concentration of sulphate in the seawater. Rezaei and Hamouda (2006) concluded that presence of sulphate ions during adsorption process reduced the surface density of fatty acids. This was due to high affinity of sulphate ions for the calcite surface, which was evidenced by their

HPLC analysis of salt tolerant mixtures of ethoxylated and non-ethoxylated sulfonates applicable in enhanced oil recovery

Abstract Commercial surfactant mixtures of ethoxylated sulfonates and alkyl aryl sulfonates are of great interest due to their tolerance toward hard water and high salinities. The surfactant mixtures are possible candidates to be applied in chemical flooding of off-shore oil reservoirs using sea water as the injection fluid. In order to study possible chromatographic separation of the chemicals in the oil reservoir, an analytical HPLC method has been worked out to quantify each of the two surfactant groups at sea-water salinities. The method is based on a mixed-mode, reversed-phase/ion-exchange column of the C4 type. The method also detects unconverted alcohols, R-(EO)χ-OH, and possible impurities, R-(EO)χ-R, of the ethoxylated sulfonate, C9-Ph-(EO)χ,-SO−3. Furthermore, individual oligomers of the χ(EO)-sulfonates (χ=2–12) are separated. Alkyl oligomers of dodecyl benzene sulfonate, DBS− are also detected from the same analysis.

Effect of Initial Sulfate in Reservoir Chalks on the Spontaneous Imbibition of Sea Water

Sea water (SW) with sulphate as one of the active ions, has been reported to alter the wettability of outcrop chalk to more water-wet. Reservoir chalk samples contain higher sulphate concentration than found to affect the wettability of outcrop chalk. The main objectives for the study were to determine the effect of the initial sulphate in reservoir chalk on the spontaneous imbibition of SW and how representative wettability conditions can be established. Reservoir chalk with and without initial sulphate were prepared using synthetic formation water without sulphate and with sulphate concentration as in real formation water. The spontaneous imbibition of SW was faster and higher for the reservoir rock with initial sulphate than for the rock without initial sulphate. This means that the initial sulphate made the reservoir chalk more water-wet. Reservoir chalk should be prepared with the same initial sulphate concentration as in the reservoir area where the samples are taken. This is required to obtain correct potential estimates for water flooding and enhanced oil recovery methods. The amount of sulphate in the original reservoir chalk and in the chalk after restoration should be determined by analysis of effluent samples during cleaning and restoration of core plugs.