Aqueous Surfactant Systems For Oil Recovery

ASP flooding achieves high incremental oil recovery factors over water flooding by reducing the interfacial tension (IFT) to ultralow values and by ensuring good mobility control, provided by the polymer. Traditionally, this has been achieved by tuning the ASP flood so that it is at optimum salinity conditions, i.e. Winsor type III micro-emulsion phase. Systematic studies of the performance of ASP at different (non-optimum) salinities are scarce, while operating at lower salinities condition can offer several advantages. These include: (1) lower surfactant retention and (2) increased polymer viscosifying power, enabling a reduction in required chemical volumes, as well as (3) a lower risk of achieving over-optimum salinity conditions in the field. This paper presents a series of core-flood experiments using light crude oil with a low Total Acid Number (TAN) and two different sandstone rock types (Bentheimer and Berea). Injection salinities ranged from under-optimum to optimum conditions (i.e. giving type II- to type III micro-emulsion systems), supported by phase behaviour and spinning drop IFT measurements. The formulation used was a model, non-optimized one with one internal olefin sulfonate (IOS) surfactant component. The injected ASP solution showed no phase separation but it was not clear. Results for this IOS surfactant system, without the addition of extra components such as a co-surfactant for improved aqueous solubility, show that ASP core flood tests performed at different salinities, both at optimum salinity and up to 1.5% NaCl under-optimum, recovered similar amounts of oil remaining in the core after water flooding, regardless of a factor three difference in IFT within the range of 10−3 and 10−2 mN/m. The residual oil saturation after chemical flooding (Sorc) was similar amongst the different experiments, ranging from 16% up to 19% Pore Volume (PV) for our specific model formulation. Moreover, oil and chemical breakthrough times are in the same range for all experiments: around 0.5 PV and 1 PV, respectively. Although total oil recovery was not affected by flooding at under-optimum conditions, lower surfactant retention and a higher oil recovery before chemical breakthrough (i.e. as clean oil) were found. In the absence of a surfactant (AP flood), poor recovery of residual oil after water flooding, regardless of a factor three difference in IFT within the range of 10−3 and 10−2 mN/m. The residual oil saturation after chemical flooding (Sorc) was similar amongst the different experiments, from 16% up to 19% Pore Volume (PV) for our specific model formulation. Moreover, oil and chemical breakthrough times are in the same range for all experiments: around 0.5 PV and 1 PV, respectively. Although total oil recovery was not affected by flooding at under-optimum conditions, lower surfactant retention and a higher oil recovery before chemical breakthrough (i.e. as clean oil) were found. In the absence of a surfactant (AP flood), poor recovery of residual oil after water flood was achieved (Sorc 32% PV). These findings suggest that injection at under-optimum conditions may be, for an IOS surfactant system, an improved, alternative to injecting at optimum conditions. Further work is recommended to quantify its advantages, including with more aqueous soluble optimized surfactant systems.

This paper examines the effects of alkaline additives on dilute surfactant systems for improved oil recovery. The study was limited to the determination of the effects of alkaline additives on interfacial tension (IFT), surfactant adsorption or retention in Berea cores, and improvement in oil recovery. The alkaline chemicals studied were sodium silicates, sodium phosphates, sodium carbonate, and sodium hydroxide. In addition, optimal salinities and surfactant average equivalent molecular weight for the recovery of two midcontinent crude oils were determined through a combination of IFT determinations and oil displacement tests. The laboratory results show that the alkaline chemicals have two major effects. First, IFT is reduced further by the high pH surfactant/alkali solution combinations, and second, certain alkaline species significantly reduce surfactant retention. This leads to recoveries of residual oil from 40 to 70% with surfactant solutions containing only 0.25 wt% surfactant.

Foam-Assisted Surfactant Flooding (FASF) is a novel enhanced oil recovery (EOR) method combining the reduction of oil-water (o/w) interfacial tension (IFT) to ultra-low values and foaming of a gas drive for mobility control. We present a detailed laboratory study on the FASF process at reservoir conditions. The stability of two specially selected surfactants in the vicinity of original injection water, i.e. sea water, at 90°C was assessed. The phase behaviour of the crude oil-surfactant-brine systems and the ability of the two selected surfactants to generate stable foam in bulk were studied in presence and in absence of crude oil. The phase behaviour and bulk tests resulted in the formulations of the surfactant slug and drive solutions. The slug solution aims for oil mobilisation by lowering of the o/w IFT and the drive formulation is required for gas foaming for mobility control. CT scanned core-flood experiments were conducted in Bentheimer sandstone cores initially brought to residual oil by water flooding. Oil mobilisation was obtained by injecting a surfactant slug at either under-optimum (o/w IFT of 10-2 mN/m) or optimum (o/w IFT of 10-3 mN/m) salinity conditions. At both salinities the injected surfactant slug yielded the formation of an unstable oil bank due to dominant gravitational forces. Optimum salinity surfactant slug was notably more effective at reducing residual oil to waterflood (81% reduction) compared to the under-optimum salinity slug (30% reduction). After oil mobilisation, drive foam was either generated in-situ by co-injection with nitrogen gas or was pre-generated ex-situ and then injected to displace mobilised oil. It was found that, at optimum salinity, FASF yielded an ultimate recovery factor of 40±5% of the oil in place (OIP) after water flooding whereas under-optimum salinity FASF showed a recovery of 35±7% of OIP after water flooding. Experiments have shown that the presence of crude oil is detrimental to in-situ foam generation and stability. Pre-generated drive foam increased its ultimate oil recovery by 13% of the OIP after water flooding compared to in-situ foam generation at optimum salinity.

Low salinity water (LSW) flooding alters rock surface wettability toward more water wetness, and consequently, oil recovery will be increased from a carbonate oil reservoir. Surfactant flooding and polymer flooding enhance oil recovery by oil–water interfacial tension (IFT) reduction and water–oil mobility ratio change, respectively. In this study, a combination of LSW and two non-ionic natural surfactants for enhanced oil recovery was evaluated. Four types of salts (CaCl2, MgCl2, Na2SO4, and MgSO4) at different concentrations in distilled water were used to find optimal LSW based on contact angle (CA) reduction. Two non-ionic natural surfactants (a new natural surfactant from Gemini surfactants (GS) family and Tribulus terrestris surfactant) were applied to obtain their optimum concentration based on IFT reduction. The minimum IFT was achieved in 2000 ppm of GS (4.06 mN/m) and 3000 ppm of TTS (6.21 mN/m). Experimental results showed that the presence of GS in low salinity surfactant solution (1000 ppm of MgSO4 and 2000 ppm GS) is capable to reduce IFT (to 1.02 mN/m) and CA (to 31.25°). Therefore, GS showed good results in IFT improvement and wettability alteration. Finally, the optimal LSS was combined with different concentrations of PHPA polymer and injected into cores. Core flooding results demonstrated 69.7% oil recovery for LSW injection, 82.2% for low salinity GS injection (an increase of 12.5%) and 87.9% for low salinity GS-polymer injection (an increase of 5.7%).

Experimental investigation of synergistic effect of non-ionic surfactant and smart water injection methods for enhanced oil recovery from carbonate reservoirs

Campbell, Thomas C. and Krumrine, Paul H., Members SPE-AIME, PQ Corp., Research and Development Center PQ Corp., Research and Development Center Copyright 1979, American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc. Abstract This paper describes the results obtained from laboratory tests performed to compare the relative efficiency of sodium orthosilicate versus sodium hydroxide on residual oil recovery. These tests provide supplementary data for an alkaline waterflooding field test. The optimum concentrations of alkali and sodium chloride, used for oil displacement studies, were determined by measuring interfacial tension values of the crude oil in contact with alkaline solutions, which were prepared from soft saline water or from synthetic reservoir brine. Data, obtained from oil displacement studies in Berea sandstone cores, have shown that dilute sodium orthosilicate solutions can recovery significantly higher amounts of residual oil than dilute sodium hydroxide solutions. The crude oil sample used in these studies was taken from the Lower Main Zone of the Huntington Beach Field in California. The differences in recovery efficiency between sodium orthosilicate and sodium hydroxide may be partially explained on the basis of increased hardness ion tolerance, greater surface activity at the oil/water interface, more favorable coalescence behavior, changes in rock wettability and decreases in surfactant adsorption. Introduction A field trial of alkaline waterflooding as an enhanced oil recovery system is in progress in the Huntington Beach Field in California. The Huntington Beach Field trial is being performed by Aminoil-USA, Inc. and is supported in part by grants from the Department of Energy. The laboratory studies summarized in this paper were undertaken to provide additional data to Aminoil on the relative recovery efficiencies of different alkaline chemicals, sodium orthosilicate versus sodium hydroxide, for crude oil from the reservoir. A considerable number of laboratory oil displacement studies have been made by R.M. Weinbrandt of Aminoil-USA using preserved core material from the Lower Main Zone of the Huntington Beach Field, produced crude oil and produced reservoir brine. These produced crude oil and produced reservoir brine. These tests have been run at reservoir temperature in plastic core bodies, and have been designed to attempt plastic core bodies, and have been designed to attempt to optimize the concentrations and slug sizes to be used in the field trial. The tests were run only with various concentrations of sodium orthosilicate, since only a limited amount of reservoir core material was available. Based on these results, the preflush of 0.75% sodium chloride will be injected for 0.35–0.40 pore volumes. Depending upon the behavior of the reservoir, 0.40–0.50 pore volume of 0.15% sodium orthosilicate in 0.75% sodium chloride will be injected as the alkaline slug. A postflush of 0.25–0.30 pore volumes of 0.75% sodium chloride solution is planned, to be followed by injection of produced brine until the test is completed. The produced brine until the test is completed. The injection of sodium orthosilicate solution should commence in August or September of 1979. In order to substantiate for Aminoil that sodium orthosilicate would be more effective than sodium hydroxide, the experiments described in this paper were performed with Berea cores using crude oil supplied by Aminoil. EXPERIMENTAL PROCEDURES The oil recovery experiments were performed using Berea sandstone cores. The Berea cores were 5.1 cm in diameter by 61 cm long cylindrical cores with an air permeability of 150–250 md. These were fitted with steel end-caps and encapsulated in epoxy resin reinforced with fiberglass cloth. In a typical experimental run with the Berea cores, the core was evacuated to a pressure of about 0.3 kPa, then filled with simulated brine from a weighed cylinder co determine the pore volume. The brine was displaced by crude oil at reservoir temperature until no more brine was produced. The crude oil was next displaced by flooding with brine until no more oil was produced. The alkaline flooding procedure was started at this point. procedure was started at this point.

Matrix-fracture interaction due to capillary forces (spontaneous imbibition) is a commonly encountered process in fractured subsurface reservoirs during oil, gas, and geothermal fluid recoveries and contaminant transport. It occurs in counter-current manner if the interaction between matrix and fracture takes place from the same side. In this study, the effects of the matrix shape factor, wettability, and interfacial tension on the rate of imbibition and development of residual non-wetting phase saturation were studied experimentally. To achieve this, experiments were conducted on Berea sandstone samples. Cylindrical samples with different shape factors were obtained by cutting the plugs _, 1 and 2 inch in diameter and 2, 4, and 6 inches in length. All sides were coated with epoxy except one end. Static imbibition experiments were conducted on vertically and laterally situated samples where the imbibition took place upward and lateral directions, respectively. Water-air, brine-kerosene, brine-mineral oil and surfactant solution-mineral oil pairs were used as fluids. The rate of imbibition was evaluated for different matrix size, shapefactor, wetting/non-wetting phase types and IFT. Conditions at which the shape factor controls the residual oil development were identified. Introduction Capillary imbibition can be an effective recovery mechanism if matrix is water wet and enough amount of water exists in fractures of naturally fractured reservoirs. Mechanism is counter-current, i.e., displacement of non-wetting phase by wetting phase takes place from the same side of the matrix, if the boundary conditions physically restricting the contact of wetting phase with matrix from the other sides exist. Despite the recognition of the process for quite a long time [1–5], yet many issues are unanswered in regards to the dynamics of the spontaneous counter-current interaction between matrix and fracture. Some of these issues include the effect of the matrix shape factor, wettability, and IFT (when surfactants are used as the wetting phase) on the rate of imbibition (progress of the front) and the development of residual oil saturation in both swept and unswept zones. Previous studies mostly dealt with counter-current imbibition in uncoated matrices (all surfaces open to flow). Ma et al. [6] conducted counter-current imbibition experiments both with all surfaces open and partially coated cores. They used coated cores ranging between 4 and 6 cm in length and a fixed 11/2 inch in diameter and were able to apply scaling equations first proposed by Mattax and Kyte [5]. Babadagli [2] used various configurations of matrix shape. He investigated co- and counter-current flow for surfactant and polymer solutions, and concluded that the modified form of Mattax and Kyte's scaling group is applicable for high-IFT cases. Bourbiaux and Kalaydjian [4] conducted counter-current imbibition experiments and estimated the relative permeabilities using numerical simulations. They observed that the relative permeabilities to the phases are smaller when compared to the ones for co-current flow. They stated that, although experimental and numerical results are consistent with the proposed theory, further investigation on counter-current interaction is needed. Schembre et al. [7] performed CT scanning experiments using Berea sandstone and diatomite.

Numerical approach for enhanced oil recovery with surfactant flooding

The paper presents the results of a pilot project implementing WAG injection at the oilfield with carbonate reservoir, characterized by low efficiency of traditional waterflooding. The objective of the pilot project was to evaluate the efficiency of this enhanced oil recovery method for conditions of the specific oil field. For the initial introduction of WAG, an area of the reservoir with minimal potential risks has been identified. During the test injections of water and gas, production parameters were monitored, including the oil production rates of the reacting wells and the water and gas injection rates of injection wells, the change in the density and composition of the produced fluids. With first positive results, the pilot area of the reservoir was expanded. In accordance with the responses of the producing wells to the injection of displacing agents, the injection rates were adjusted, and the production intensified, with the aim of maximizing the effect of WAG. The results obtained in practice were reproduced in the simulation model sector in order to obtain a project curve characterizing an increase in oil recovery due to water-alternating gas injection. Practical results obtained during pilot testing of the technology show that the injection of gas and water alternately can reduce the water cut of the reacting wells and increase overall oil production, providing more efficient displacement compared to traditional waterflooding. The use of WAG after the waterflooding provides an increase in oil recovery and a decrease in residual oil saturation. The water cut of the produced liquid decreased from 98% to 80%, an increase in oil production rate of 100 tons/day was obtained. The increase in the oil recovery factor is estimated at approximately 7.5% at gas injection of 1.5 hydrocarbon pore volumes. Based on the received results, the displacement characteristic was constructed. Methods for monitoring the effectiveness of WAG have been determined, and studies are planned to be carried out when designing a full-scale WAG project at the field. This project is the first pilot project in Russia implementing WAG injection in a field with a carbonate reservoir. During the pilot project, the technical feasibility of implementing this EOR method was confirmed, as well as its efficiency in terms of increasing the oil recovery factor for the conditions of the carbonate reservoir of Eastern Siberia, characterized by high water cut and low values of oil displacement coefficients during waterflooding.

Previous work has shown that commercially-refined lignosulfonates can considerably enhance the tertiary oil recovery efficacy of petroleum sulfonate surfactants. The present study examines the effects of using lignosulfonates in their unrefined form. i.e. as spent sulfite liquors which emanate as effluent from many Canadian pulp and paper mills. These liquors contain several inorganic and organic components in addition to lignosuljonotes, notably sugars. Interfacial tension, phase behaviour, and tertiary oil recovery data are presented for a wide range of surfactant mixtures containing spent sulfite liquors and petroleum sulfonates. It is shown that within certain concentration ranges significant increases in oil recovery can be achieved by adding spent sulfite liquors to petroleum sulfonate surfactants. Introduction It has been widely recognized that secondary or tertiary surfactant flooding of petroleum reservoirs is an effective means of recovering a fraction of the remaining oil, provided an ultralow interfacial tension (= 10−3 mN/m) between the oil and the surfactant solution can be attained. Several types of petroleum sulfonate surfactants have been investigated in the literature for the attainment of such low interfacial tensions. However, the high cost of petroleum sulfonate is one of the major drawbacks in surfactant flooding processes. The present authors have therefore been investigating the possibilities of using lignosulfonates (which are about four times cheaper than petroleum sulfonates) in enhanced oil recovery operations. Lignosulfonates were chosen as an alternate surfactant source because they are derived from wood, which is a renewable resource and abundantly available in Canada. Lignosulfonates are one of the major constituents of spent sulfite liquors which are discarded as effluents from pulp and paper plants. About 10% of the total spent sulfite liquors are currently being processed to recover useful products like lignosulfonates, which have a variety of uses such as dispersants, binders, emulsion stabilizers and industrial cleaners. Lignosulfonates in Enhanced Oil Recovery Lignosulfonate solutions are sub-colloidal, high molecular weight, polyelectrolyres which do not show any tendency to form micelles and do not reduce interfacial tension appreciably when used alone(1–2). Kalfoglou(3) patented a tertiary recovery process in which he proposed the use of lignosulfonates as sacrificial agents to reduce the adsorption loses of expensive petroleum sulfonate surfactants on the reservoir rock. However, in a recent study, Novosad(8) claimed that the beneficial effects of lignosulfonates do not result from their activity as sacrificial agents. In several studies performed ill our laboratory, increased interfacial activity was observed between oil and petroleum sulfonate solutions upon the addition of lignosulfonates(4–6). The lowering of interfacial tension produced by adding lignosulfonate was qualitatively similar to that observed when adding NaCI, provided the solution was below its optimal salinity level. However, the quantity of lignosulfonate required 10 produce a given lowering was much smaller(6). In a related study Son et al. (7) observed faster oil drop coalescence rates with these mixed surfactants than when using petroleum sulfonates alone.

Numerical simulation of steam-chemical oil recovery processes require high temperature multiphase rock-fluid properties such as relative permeabilities and capillary numbers. These parameters are needed to predict and evaluate oil recovery performance and efficiency. Experiments in both Berea sandstone and sandpacks have been conducted to measure relative permeabilities of high and low tension oil-water mixtures at elevated temperatures. A new mathematical model consisting of sets of empirical correlations based on experimental data have been developed for relating endpoint relative permeabilities to both residual and mobile oil-water saturations and capillary numbers to residual oil-water saturations. The tests were run over a wide range of temperature, 72° to 400°F, and overburden pressure range of 500 to 1000 psia. It is our belief that this model is new for the range of temperature and pressure of steam oil recovery processes with chemical additives. Predictive results made with empirical correlations are in good agreement with experimental results.

Effect of crude oil ageing on low salinity and low salinity surfactant flooding

Spontaneous imbibition is a mechanism that can significantly contribute to the production rate and final oil recovery in fractured and stratified reservoirs. This mechanism is affected by rock and fluid properties and it has been reported by several authors to be strongly dependent on interfacial tension (IFT) and contact angle. Both magnitudes are influenced by system temperature. In this work a laboratory study is performed on the influence of IFT and temperature on production rate and oil recovery for a given rock-fluid system. All sequences were performed on rock and fluid samples from Argentine basins. Rock samples were of medium permeability (56.1 to 83.1 mD) and porosity ranging from 18.7 % to 22.9 %. The fluids used were formation water and medium viscosity oil (45 cp at standard conditions). The samples were carried to irreducible water saturation before performing the imbibition tests resembling the assumed reservoir condition. Initial tests were designed including representative water, oil and rock samples at several temperature levels. Another sequence of tests were performed with the addition of variable amounts of water dispersed surfactant. A noticeable influence of experimental conditions was found on the final results. As part of the tests, the same final temperature was reached through single and several steps observing the differences in overall performance.

In the literature, both huff-n-puff gas injection and chemical injection to modify relative permeabilities have been proposed to mitigate condensate blocking near the wellbore; and huff-n-puff gas injection has been proposed to improve liquid oil production in shale gas condensate reservoirs. This paper focuses on the potential of chemical relative permeability modification (RPM) to enhance hydrocarbon recovery in fractured shale gas condensate reservoirs using the simulation approach; and the potentials to improve hydrocarbon recovery by these two approaches are compared. The relative permeability model is studied and the dependence of gas/oil relative permeability curves on capillary number and interfacial tension is discussed. Chemical treatments to mitigate condensate and water blocking have been successfully implemented in the laboratory with sandstone and carbonate. Accordingly, a brief screening of RPM chemicals is conducted and the mechanism of potential surfactant molecules that may work in shale gas condensate reservoirs are investigated. In this study, a shale gas condensate reservoir model is set up and the reservoir is assumed to be treated with a hypothetic surfactant that improves both the relative oil and gas permeability within the near-wellbore area. The simulation results are juxtaposed with those of huff-n-puff gas injection production. It is assumed that the surfactant alters the end-point gas/oil relative permeability, residual oil saturation, gas connate saturation, etc. and is durable during the production years. In the surfactant treatment cases, an increase of oil recovery by 1%-3% is observed compared with the primary depletion. However, the optimized huff-n-puff process can achieve up to 8% more oil recovery than primary depletion. In terms of gas recovery, the surfactant treatment process increases gas recovery by 1-2%, while the optimized huff-puff gas injection leads to over 20% gas recovery reduction because of less total production time. To sum up, the huff-n-puff gas injection process achieve more liquid recovery but less gas recovery than the surfactant treatment process. Analysis of simulation data about the changes in drawdown pressure and liquid saturation are proposed. A simple economic analysis is conducted as well. It is concluded that the huff-n-puff process is preferred to the RPM process when the oil price is relatively high due to higher drawdown pressure and the oil saturation reduction near the wellbore by evaporation. The potential of RPM application in unconventional reservoirs has not been well investigated in the previous literature. This paper is to discuss this potential and to compare the advantages and disadvantages of the surfactant RPM process with those of huff-n-puff gas injection in shale gas condensate.

99/02437 Recent development of enhanced oil recovery in China