Shubham, Agrawal (Texas A&M University at Qatar) | Martavaltzi, Christina (Texas A&M University at Qatar) | Dakik, Ahmad Rafic (Texas A&M University at Qatar) | Gupta, Anuj (Texas A&M University at Qatar)
It is well known that the majority of carbonate reservoirs are neutral to oil-wet. This leads to much lower oil recovery during waterflooding since there is no spontaneous imbibition of water in heterogeneous reservoir displacement. It has been verified by a number of researchers that Adjustment of ion concentration in brine solutions, or adding surfactant solutions can enhance the oil recovery by altering the wettability. In the published literature, contact angle studies usually refer to measurement on calcite crystals and there are no results for the contact angle of carbonate porous media representative of reservoir rocks. Moreover, there are few studies on the effect of non-ionic surfactants, compared to those for ionic surfactants. Understanding the effect of various ions and their concentration in the injection brine on the wettability of the Limestone outcrop core samples is the first step for tailoring of the optimum injection brine. This will be followed by a study of the effect of surfactant on the wettability of calcite crystal samples. The evaluation of the results may provide guidelines for the design of injection brines for efficient enhanced oil recovery from carbonate reservoirs.
In this work, a procedure is established for the measurement of the contact angle on limestone outcrop core samples. Results showed that, at atmospheric conditions, low salinity CaCl2 solution induced the most significant improvement on the wettability of the outcrop sample. Moreover, among all the non-ionic surfactants studied, only the presence of the two first members of the 15S analogous series might lead to a slight decrease of the contact angle.
Carbon dioxide (CO2) flooding is a conventional process in which the CO2 is injected into the oil reservoir to increase the quantity of extracting oil. This process also controls the amount of released CO2 as a greenhouse gas in the atmosphere which is known as CO2 sequestration process. However, the mobility of the CO2 inside the hydrocarbon reservoir is higher than the crude oil and always viscous fingering and gravity override problems occur during a CO2 injection. The most common method to overcome these problems is to trap the gas bubbles in the liquid phase in form of aqueous foam prior to CO2 injection. Although, the aqueous foams are not thermodynamically stable, the special care should be considered to ensure about bulk foam preparation and stability. Selection of a proper foaming agent from a large number of available surfactants is the main step in the bulk foam preparation. To meet this purpose, many chemical and crude oil based surfactants have been reported but most of them are not sustainable and have disposal problems. The objective of this experimental study is to employ Lingosulfonate and Alkyl Polyglucosides (APGs) as two sustainable foaming agents for the bulk foam stability investigations and foam flooding performance in porous media. In the initial part, the bulk foam stability results showed that APGs provided more stable foams in compare with Lingosulfonate in all surfactant concentrations. In the second part, the results indicated that the bulk foam stability measurements provide a good indication of foam mobility in porous media. The foaming agent’s concentration which provided the maximum foam stability also gave the highest value of mobility reduction in porous media.
Abou Sayed, Nada (Petroleum Institute) | Shrestha, Reena (The Petroleum Institute) | Sarma, Hemanta Kumar (The Petroleum Institute) | Al Kindy, Nabeela (The Petroleum Institute) | Haroun, Muhammad (University of Southern California) | Abdul Kareem, Basma Ali (The Petroleum Institute) | Ansari, Arsalan Arshad (The Petroleum Institute)
EOR technologies such as CO2 flooding and chemical floods have been on the forefront of oil and gas R&D for the past 4 decades. While most of them are demonstrating very promising results in both lab scale and field pilots, the thrive for exploring additional EOR technologies while achieving full field application has yet to be achieved. Among the emerging EOR technologies is the surfactant EOR along with the application of electrically enhanced oil recovery (EEOR) which is gaining increased popularity due to a number of reservoir-related advantages such as reduction in fluid viscosity, water-cut and increased reservoir permeability.
Experiments were conducted on 1.5?? carbonate reservoir cores extracted from Abu Dhabi producing oil fields, which were saturated with medium crude oil in a specially designed EK core flood setup. Electrokinetics (DC voltage of 2V/cm) was applied on these oil saturated cores along with waterflooding simultaneously until the ultimate recovery was reached. In the second stage, the recovery was further enhanced by injecting non-ionic surfactant (APG) along with sequential application of EK. This was compared with simultaneous application of EK-assisted surfactant flooding. A smart Surfactant-EOR process was done in this study that allowed shifting from sequential to simultaneous Surfactant-EOR alongside EEOR
The experimental results at ambient conditions show that the application of waterflooding on the carbonate cores yields recovery of approximately 46-72% and an additional 8-14% incremental recovery resulted upon application of EK, which could be promising for water swept reservoirs. However, there was an additional 6-11% recovery enhanced by the application of EK-assisted surfactant flooding. In addition, EK was shown to enhance the carbonate reservoir's permeability by approximately 11-29%. Furthermore, this process can be engineered to be a greener approach as the water requirement can be reduced upto 20% in the presence of electrokinetics which is also economically feasible.
In a layered, 2D heterogeneous sandpack with a 19:1 permeability contrast that was preferentially oil-wet, the recovery by waterflood was only 49.1% of original oil in place (OOIP) because of injected water flowing through the high-permeability zone, leaving the low-permeability zone unswept. To enhance oil recovery, an anionic surfactant blend (NI) was injected that altered the wettability and lowered the interfacial tension (IFT). Once IFT was reduced to ultralow values, the adverse effect of capillarity retaining oil was eliminated. Gravity-driven vertical countercurrent flow then exchanged fluids between high- and low-permeability zones during a 42-day system shut-in. Cumulative recovery after a subsequent foam flood was 94.6% OOIP, even though foam strength was weak. Recovery with chemical flood (incremental recovered oil/waterflood remaining oil) was 89.4%. An alternative method is to apply foam mobility control as a robust viscous-force-dominant process with no initial surfactant injection and shut-in. The light crude oil studied in this paper was extremely detrimental to foam generation. However, the addition of lauryl betaine to NI (NIB) at a weight ratio of 1:2 (NI:lauryl betaine) made the new blend a good foaming agent with and without the presence of the crude oil. NIB by itself as an IFT-reducing and foaming agent is shown to be effective in various secondary and tertiary alkaline/surfactant/foam (ASF) processes in water-wet 1D homogeneous sandpacks and in an oil-wet heterogeneous layered system with a 34:1 permeability ratio.
This article reports a laboratory study of a novel alkaline/surfactant/foam (ASF) process. The goal of the study was to investigate whether foaming a specially designed alkaline/surfactant (AS) formulation could meet the two key requirements for a good enhanced oil recovery (EOR) [i.e., lowering the interfacial tension (IFT) considerably and ensuring a good mobility control]. The study included phase-behavior tests, foam-column tests, and computed-tomography (CT)-scan-aided corefloods. It was found that the IFT of the designed AS and a selected crude oil drops by four orders of magnitude at the optimum salinity. The AS proved to be a good foaming agent in the column tests and corefloods in the absence of oil. The mobility reduction caused by the AS foam was hardly sensitive to salinity and increased with decreasing foam quality. CT-scanned corefloods demonstrated that AS foam, after a small AS preflush, recovered almost all the oil left after waterflooding. The oil-recovery mechanism by ASF combines the formation of an oil bank and the transport of emulsified oil by flowing lamellae. Further optimization of the ASF is needed to ensure that the oil is produced exclusively by the oil bank.
For ultratight shale reservoirs, wettability strongly affects fluid flow behavior. However, wettability can be modified by numerous complex interactions and the ambient environment, such as pH, temperature, or surfactant access. This paper is a third-phase study of the use of surfactant imbibition to increase oil recovery from Bakken shale. The surfactant formulations that we used in this paper are the initial results that are based on our previous study, in which a group of surfactant formulations was examined--balancing the temperature, pH, salinity, and divalent-cation content of aqueous fluids to increase oil production from shale with ultralow porosity and permeability in the Middle Member of the Bakken formation in the Williston basin of North Dakota. In our previous study, through the use of spontaneous imbibition, brines and surfactant solutions with different water compositions were examined. With oil from the Bakken formation, significant differences in recoveries were observed, depending on compositions and conditions. Cases were observed in which brine and surfactant (0.05 to 0.2 wt% concentration) imbibition yielded recovery values of 1.55 to 76% original oil in place (OOIP) at high salinity (150 to 300 g/L; 15 to 30 wt%) and temperatures ranging from 23 to 120°C. To advance this work, this paper determines the wettability of different parts of the Bakken formation. One goal of this research is to identify whether the wettability can be altered by means of surfactant formulations. The ultimate objective of this research is to determine the potential of surfactant formulations to imbibe into and displace oil from shale and to examine the viability of a field application. In this paper, through the use of modified Amott-Harvey tests, the wettability was determined for cores and slices from three wells at different portions of the Bakken formation. The tests were performed under reservoir conditions (90 to 120°C, 150- to 300-g/L formation-water salinity), with the use of Bakken crude oil. Both cleaned cores (cleaned by toluene/methanol) and untreated cores (sealed, native state) were investigated. Bakken shale cores were generally oil-wet or intermediate-wet (before introduction of the surfactant formulation). The four surfactant formulations that we tested consistently altered the wetting state of Bakken cores toward water-wet. These surfactants consistently imbibed to displace significantly more oil than brine alone. Four of the surfactant imbibition tests provided enhanced-oil-recovery [(EOR) vs. brine water imbibition alone] values of 6.8 to 10.2% OOIP, incremental over brine imbibition. Ten surfactant imbibition tests provided EOR values of 15.6 to 25.4% OOIP. Thus, imbibition of surfactant formulations appears to have a substantial potential to improve oil recovery from the Bakken formation. Positive results were generally observed with all four surfactants: amphoteric dimethyl amine oxide, nonionic ethoxylated alcohol, anionic internal olefin sulfonate, and anionic linear a-olefin sulfonate. From our work to date, no definitive correlation is evident in surfactant effectiveness vs. temperature, core porosity, core source (i.e., Upper Shale or the Middle Member), or core preservation (sealed) or cleaning before use.
Xing, Dazun (University of Pittsburgh) | Wei, Bing (University of Pittsburgh) | McLendon, William J. (University of Pittsburgh) | Enick, Robert M. (University of Pittsburgh) | McNulty, Samuel (University of Pittsburgh) | Trickett, Kieran (University of Bristol) | Mohamed, Azmi (University of Bristol) | Cummings, Stephen (University of Bristol) | Eastoe, Julian (University of Bristol) | Rogers, Sarah (ISIS Facility Science and Technology Facilities Council) | Crandall, Dustin (URS Washington Division) | Tennant, Bryan (URS Washington Division) | McLendon, Thomas (US Department of Energy National Energy Technology Laboratory) | Romanov, Vyacheslav (US Department of Energy National Energy Technology Laboratory) | Soong, Yee (US Department of Energy National Energy Technology Laboratory)
Several commercially available, nonionic surfactants were identified that are capable of dissolving in carbon dioxide (CO2) in dilute concentration at typical minimum- miscibility-pressure (MMP) conditions and, upon mixing with brine in a high-pressure windowed cell, stabilizing CO2-in-brine foams. These slightly CO2-soluble, water-soluble surfactants include branched alkylphenol ethoxylates, branched alkyl ethoxylates, a fatty-acid-based surfactant, and a predominantly linear ethoxylated alcohol. Many of the surfactants were between 0.02 to 0.06 wt% soluble in CO2 at 1,500 psia and 25°C, and most demonstrated some capacity to stabilize foam. The most- stable foams observed in a high-pressure windowed cell were attained with branched alkylphenol ethoxylates, several of which were studied in high-pressure small-angle-neutron-scattering (HP SANS) tests, transient mobility tests using Berea sandstone cores, and high-pressure computed-tomography (CT)-imaging tests using polystyrene cores. HP SANS analysis of foams residing in a small windowed cell demonstrated that the nonylphenol ethoxylate SURFONIC® N-150 [15 ethylene oxide (EO) groups] generated emulsions with a greater concentration of droplets and a broader distribution of droplet sizes than the shorter-chain analogs with 9-12 ethoxylates. The in-situ formation of weak foams was verified during transient mobility tests by measuring the pressure drop across a Berea sandstone core as a CO2/surfactant solution was injected into a Berea sandstone core initially saturated with brine; the pressure-drop values when surfactant was dissolved in the CO2 were at least twice those attained when pure CO2 was injected into the same brine-saturated core. The greatest mobility reduction was achieved when surfactant was added both to the brine initially in the core and to the injected CO2. CT imaging of CO2 invading a polystyrene core initially saturated with 5 wt% KI brine indicated that despite the oil-wet nature of this medium, a sharp foam front propagated through the core, and CO2 fingers that formed in the absence of a surfactant were completely suppressed by foams formed because of the addition of nonylphenol ethoxylate surfactant to the CO2 or the brine.
Carboxybetaine viscoelastic surfactants have been applied in acid diversion and fracturing treatments in which high temperatures and low pH are usually involved. These surfactants are subjected to hydrolysis under such conditions because of the existence of a peptide group (-CO-NH-) in their molecules, leading to changes in the rheological properties of the acid. The objective of this paper is to study the impact of hydrolysis at high temperatures on the apparent viscosity of carboxybetaine viscoelastic surfactant-based acids, and propose the mechanism of viscosity changes by molecular dynamics (MD) simulations.
Surfactant-acid solutions with different compositions (surfactant concentration varied from 4 to 8 wt%) were incubated at 190°F for 1 to 6 hours. Solutions were then partially spent by CaCO3 until the sample pH was 4.5, and the apparent viscosity was measured using a high-temperature/high-pressure (HT/HP) viscometer. To understand the mechanism for viscosity changes on the molecular level, MD simulations were carried out on spent surfactant-acid aqueous systems using the Materials Studio 5.0 Package.
It was found that short-time hydrolysis at high temperatures (for example, 1 to 2 hours at 190°F) led to a significant increase in surfactant-acid viscosity. However, after incubation for 3 hours, phase separation occurred and the acid lost its viscosity. Simulation results showed that viscosity changes of amido-carboxybetaine surfactant acid by hydrolysis at high temperatures may be caused by different micellar structures formed by carboxybetaine and fatty acid soap, its hydrolysis product. The optimum molar ratio of amido-carboxybetaine and fatty acid soap to form worm-like micelles was found to be nearly 3:1 from our simulations.
Our results indicate that hydrolysis at high temperatures has a great impact on surfactant-acid rheological properties. Short time viscosity build-up and effective gel breakdown can be achieved if surfactant-acid treatments are carefully designed; otherwise, unexpected viscosity reduction and phase separation may occur, which will affect the outcome of acid treatments.
The Microemulsion phase behavior model based on oleic-aqueous-surfactant pseudo-phase equilibrium, commonly used in chemical flooding simulators, is coupled to Gas-Oil-Water phase equilibrium in our new four-fluid-phase, fully implicit In-House Research Reservoir Simulator (IHRRS). The method consists in splitting the equilibrium in two stages, where all the components other than surfactant are equilibrated first (e.g. using a black-oil, K-value or equation of state model), and the resulting Gas, Oil and Water phases are then lumped into pseudo-phases to be equilibrated using the Microemulsion model. This subdivision in stages is conceptual, and at each converged time-step the four phases (Gas, Oil, Water and Microemulsion, when simultaneously present) will be in equilibrium with each other.
The fluid properties (such as densities, viscosities and interfacial tensions) and rock-fluid properties (such as relative permeabilities), required in the transport equations, are evaluated with models from well-known industrial or academic simulators. Surfactant flooding being usually implemented as a tertiary recovery mechanism, on fields for which complete models that we do not wish to modify already exist, particular care is devoted to ensuring continuity of the physics at the onset of surfactant injection.
Our code is validated against a reference academic chemical flooding simulator, on 1D corefloods where the original hydrocarbons in place form a dead-Oil phase, possibly with free dry-Gas. Some numerical aspects of our implementation such as numerical dispersion versus time-step size and nonlinear convergence performance are also discussed. As an application example of our code where it is necessary to account for four phases in equilibrium, we consider a scenario where the chemical flood is preceded by a vaporizing Gas drive.
Surfactant flooding, whose key principle is to improve pore-level sweep efficiency by reducing the interfacial tension between injected Water and reservoir Oil (Lake, 1989), recently received renewed attention due to the perspective of long-lasting high oil prices. Meaningful simulation of surfactant flooding is challenging, in particular because when the surfactant concentration in the Water phase goes above a Critical Micelle Concentration (CMC), Water and Oil become mutually soluble in a proportion mainly determined by water salinity CS. Three different phase environments should be considered (Nelson & Pope, 1978; Lake, 1989). Near the so-called optimal salinity CSOP the surfactant is similarly hydrophilic and lipophilic, and a middle phase called Microemulsion forms, containing the surfactant in excess of the CMC as well as dispersed oil and water (Winsor III environment). This is the best performing regime because interfacial tensions between Water and Microemulsion and between Microemulsion and Oil are then extremely low. At low salinity the surfactant is typically hydrophilic, hence only Oil and a Microemulsion phase containing dispersed oil coexist (Winsor II- environment); on the contrary at high salinity the surfactant is typically lipophilic, hence only Water and a Microemulsion phase containing dispersed water coexist (Winsor II+ environment).
The optimization of chemical floods for a low-permeability, high-salinity, high-temperature carbonate formation presents several unique design challenges, which may be overlooked in short coreflood experiments. Low permeability formations require the optimization of polymer molecular weight distribution such that both mobility reduction and injectivity are maximized. Mitigation of emulsion issues - possibly related to high surfactant adsorption - requires the optimization of surfactant concentration and slug size. The effects of high core-scale heterogeneity must be understood and mitigated, for example, by increasing core length. These subjects are explored in the context of an ongoing flood design project. Additionally, an attempt is made to shed light on the discrepancy between available carbonate capillary desaturation curves for carbonates and the near-complete recovery reported in surfactant-polymer corefloods.