Viscoelastic surfactants (VES) are essential components in self-diverting acid systems. Their low thermal stability limits their application at elevated temperatures. The industry introduced new VES chemistries with modified hydrophilic functional groups, which enhances their thermal stability. These new chemistries are still challenged by the lack of compatibility with corrosion inhibitors (CI). This work aims to study the nature and the mechanism of the interaction between the VES and the corrosion inhibitors, which affects both the rheological and corrosion inhibition characteristics of the self-diverting acid system.
This study is based on rheology and corrosion inhibition tests, where combinations of VES and corrosion inhibitors are tested and complemented with chemical and microscopic analysis. Negatively charged thiourea and positively charged quaternary ammonium corrosion inhibitors were selected to study their impact on both cationic and zwitterionic VES systems. Each mixture of the corrosion inhibitor and the VES was blended in a 15 and 20 wt% HCl acid mixture, then assessed for its viscosity at different shear rates, CI concentrations, and temperatures up to 280°F in live and spent acid conditions. Each acid solution was assessed using Fourier-Transform-Infra-Red (FTIR) before and after each rheology and corrosion test to track the changes of the mixture functional groups. Each mixture was examined under a polarizing microscope to assess its colloidal nature. The corrosion inhibition effectiveness of selected acid mixtures was evaluated. N-80 steel coupons were immersed statically in the acid mixture for 6 hours at 150°F and 1,000 psi. The corrosion rate was evaluated by using metal coupon weight loss analysis followed by optical microscope examination for the metal surface.
The interaction between the CI and the VES surface charges and molecular geometries dictates both the rheological and the inhibitive properties of the acid mixtures. The use of a small molecular structure anionic CI with a cationic VES, results in a fine monodispersed CI particles in the VES-acid system. The opposite charges between the CI and the VES results in electrostatic attraction forces. Both the fine dispersion and the electrostatic attraction enhances the rheological performance of the mixture and packs the corrosion-inhibiting layer. The addition of a bulk and similarly charged CI with the VES results in a coarse polydispersed CI particles with repulsive nature with the VES. These properties increase the shear-induced structures and lower the packing of the inhibition layer deposited on the metal coupons, which decrease the rheological performance of the acid mixture and increase its corrosion rate. The FTIR analysis shows that there is no chemical reaction between the CIs and the VESs tested.
This work investigates the interactions between the corrosion inhibitors and the viscoelastic surfactants. It explains the impact of the surface charge of both corrosion inhibitors and VES on their rheological and corrosion inhibition characteristics. It adds a selection criterion for compatible VES and corrosion inhibitors.
Several polymer technologies are commonly used as fluid loss control additives. Working mechanisms were studied by Plank et al. (
The scope of this paper is to investigate the impact of several types of fluid loss polymers on cement slurry stability. Then, an effort is made to correlate the working mechanism of the fluid loss additive with cement slurry rheological behavior and its ability to prevent segregation or settling.
On top of conventional tests on fluid loss and flow rheology, refined evaluations of the rheological behavior are performed in oscillatory rheometry at very-low strain. This technique allows some insight into the microscopic interactions at stake in cement slurries. In particular a "yield stress model" is applied to formulated oil well cement slurries at 90°C providing additional insight on the impact of adsorbing or non-adsorbing polymers.
From this study it can be confirmed that adsorbing polymers have a strong impact on rheological properties with a surprisingly lower yield stress combined with improved slurry stability. On the other hand non adsorbing polymers of either linear or μgel form have a very limited impact on slurry yield stress and a variable impact on slurry stability through either viscosification of the interstitial fluid for linear polymers or enhanced settling hindrance from μgels.
Hydraulic fracturing has always been associated with significant volumes of fracturing fluid invading the formation matrix, which leads to water blockage and a reduction in relative permeability to gas or oil. In Shale and tight formations, this has become more challenging since capillary forces have profound impact on water retention and hence, water recovery and subsequent oil productivity. Surfactants and microemulsions have been extensively reported as flowback additives to lower surface and interfacial tension to maximize water recovery.
Most of the previous studies focused on a few testing methods to validate a surfactant or a microemulsion formulation for flowback use. In this work, a new environmentally friendly water-based surfactant formulation (Surf-I) was evaluated for flowback and its performance was compared against several industry standards of microemulsions and non-ionic alcohol ethoxylated surfactant. Surface tension (ST), interfacial tension (IFT), contact angle (CA), and coreflood tests were conducted in a wide range of typical field conditions of water salinity, temperature, crude oil type, and surfactant concentration. Core flow testing on 0.1-0.3 md Kentucky sandstone was conducted simulating oil reservoirs following constant-pressure flow schemes of 50-500 psi. Water recovery and oil productivity were determined for each pressure stage.
The new formulation showed a surface tension of 26 mN/m with CMC corresponding to a load of 0.1-0.3 gpt, depending on the water salinity. Interfacial tension measurements varied from 0.17 mN/m to 10 mN/m, depending on the crude oil type and temperature. Contact angle measurements indicated the surfactant ability to water-wet controlled substrates. The coreflood results confirmed the benefit of using surfactants for flowback versus non-surfactant cases, especially at low- to mid-pressure flow and. At 50 psi pressure difference, no oil was observed in the no-surfactant case. At 100, 250, and 500 psi the oil productivity with surfactant was 53, 22, and 20% higher than the base case. The results also showed that a formulation with ultra-low IFT (5E-2 mN/m), can initially recover substantial water volume but did not show a superior performance over the new formulation. The data obtained in this study can be used to identify the optimum criteria of a flowback additive in terms of surface tension, IFT, and wettability requirement to enhance water recovery and maximize oil productivity.
Surfactants have been used in the oil industry for decades as multi-functions additive in stimulation fluids. In hydraulic fracturing, surfactants and microemulsions have been extensively reported numerously as flowback additives to lower surface and interfacial tension to aid water recovery. Fracturing fluids invade the matrix during the fracturing, and if not recovered, leads to water blockage and a reduction to relative permeability to gas or oil. This problem is more challenging in low- permeability formations since capillary forces have more profound impact on water retention, and hence water recovery and subsequent oil productivity.
In this work, surface tension, interfacial tension, foam stability, sand-packed columns, and coreflood experiments were performed on a selected environmentally friendly water-based surfactant formulation. The performance of the surfactant of interest was compared to two commercial microemulsion and one non-ionic alcohol ethoxylated.
The results confirmed the benefit of using surfactants for flowback compared to non-surfactant case. Surface tension (ST) alone cannot be used as a selecting criterion for flow back. The alcohol exthoxylated, while reducing the ST to same level as the two microemulsions, showed very poor performance in packed column and coreflood tests. Although interfacial tension (IFT) seems to be more reasonable criteria, adsorption and emulsion tendency are other challenges that can hinder the performance of good surfactants with low IFT. Based on the data, a surfactant that lowers the IFT with the selected oil to below 1 mN/m is more likely to outperform other surfactants with higher IFT.
In naturally fractured carbonate reservoirs, Gas Oil Gravity Drainage processes (GOGD) are successfully implemented but oil recovery is limited by a slow kinetics. However a gas EOR process represents a promising alternative to boost this oil production rate. Nevertheless the design of this process should address several technical challenges: the typically unfavorable wettability of the matrix (intermediate to strongly oil-wet), the densely connected fracture network and the high contrast of fracture-to-matrix permeability.
We propose here the injection of a advanced EOR foam with reduced interfacial tension. The foam flow in the fracture creates an important viscous drive leading to a pressure gradient, which increases the oil recovery dynamics compared to GOGD. Besides, the reduced interfacial tension (IFT) between crude oil and aqueous phase allows the aqueous phase to enter the matrix despite the unfavorable wettability.
In this paper, we demonstrate that a balance exist between IFT and foam strength performances to optimize the process. Three foam formulations are optimized with very different profiles in terms of IFT and foam performances. For their design, priority is given either to ultra-low IFT values (10-3mN/m) or to a strong foam with larger IFT (0.35mN/m) or to a balance between the two first formulations (0.03mN/m). Foams are evidenced as intrinsically less stable in ultra-low IFT conditions: apparent viscosity (in porous media) in contact with oil is respectively enhanced by a factor 40 when IFT rises from 10−3 to 10−1mN/m. Based on sandpack and coreflood experiments, we recommend an IFT in the order of 10−1 mN/mas a balance between the viscous drive in fracture and an efficient aqueous phase imbibition in the oil-wet matrix. Simulation work supports this experimental conclusion: the common target of IFT in the order of 10−3 mN/m determined by capillary desaturation curves in SP flooding can be adjusted to a higher IFT value, which can be deduced from the wettability of the reservoir.
To ensure an accelerated oil recovery in naturally fractured carbonate reservoirs, we recommend the design of a low-IFT foam formulation with revised IFT performances compared to a classical Surfactant-Polymer process targeting residual oil. Indeed, the final process is likely more efficient if the target of IFT is defined by wettability requirements rather than residual oil desaturation. This article gives the target formulation parameters which arise from the mechanisms at play (viscous drive and imbibition in oil-wet matrix), and are realistically achieved with industrial surfactants.
Al-Murayri, Mohammed Taha (Kuwait Oil Company) | Hassan, Abrahim Abdelgadir (Kuwait Oil Company) | Al-Ajmi, Naser Ammash (Kuwait Oil Company) | Wartenberg, Nicolas (Solvay) | Delbos, Aline (IFPEN) | Suzanne, Guillaume (Beicip-Franlab)
There are ongoing efforts to assess the techno-ecnomic viability of surfactant polymer (SP) flooding to increase oil recovery by improving microscopic and macroscopic sweep efficiency. This paper sheds light on a methodology to design an appropriate SP formulation for potential deployment in the Ratqa Lower Fars (RQLF) heavy oil reservoir in Kuwait.
Besides achieving low residual oil saturation due to SP flooding under typical RQLF reservoir conditions, this study focuses on mitigating surfactant retention. Several injection strategies were investigated using alkali, adsorption inhibitors and a variety of water treatment techniques. For each scenario, a specific SP formulation was designed and evaluated through static adsorption tests using crushed reservoir rock. The two most promising options were then evaluated through coreflood experiments. The best option was selected based on in-depth chemical propagation, oil desaturation and surfactant adsorption. Finally, lab-optimization work was performed through additional corefloods to reduce chemical consumption while maintaining favorable oil recovery.
Softened seawater obtained through reverse osmosis was considered as the most appropriate water source to implement the desired SP process. Previous work revealed that the use of unsoftened seawater results in high levels of surfactant adsorption on reservoir rock. Salt addition allows applying an efficient salinity gradient post SP injection. Sodium chloride was used instead of alkali which did not exhibit any benefit in this case. A particular effort was made to reduce the amount of added salt and the corresponding formulation cost. Several injection sequences were investigated to compare polymer and SP flooding. The final coreflood experiment based on SP injection (0.6 PV of surfactant at 4 g/l), followed by a salinity gradient, and involving a polymer drive recovered 80% of the original oil in place. The promising performance of this injection sequence will be further evaluated using the results from a one-spot EOR pilot.
This EOR study on the RQLF shallow heavy oil reservoir in Kuwait provides important insights to select an appropriate surfactant-polymer injection strategy to increase oil recovery while maintaining reduced adsorption levels, thereby improving SP techno-economic viability.
While the global oil demand is set to increase, reducing CO2 emissions is one of the great challenges to be tackled in the coming decades. CO2-EOR has a lot of potential within a CCUS strategy, but the low gas viscosity induces limited sweep efficiency, resulting in poor storage capacity, especially in heterogeneous carbonates formations. CO2-Foams are used to alleviate such drawbacks but special care must be taken with carbonates due to water/surfactants-rock interactions.
A new cationic surfactant formulation is designed through a high throughput screening procedure accounting for solubility at high temperature (80°C), high salinity (160g/L TDS) and high hardness (R+=0.3), increased foam half-life time (at 120bar), reduced adsorption on carbonate powder and finally Ottawa sandpack flood tests (non-reactive transport). Core flooding experiments are performed on Indiana Limestone cores at 130bar and 40°C, prior targeting higher temperature. Dense supercritical CO2 is co-injected along with the surfactant formulation at the core inlet to ensure foam generation inside the rock and apparent CO2 viscosity is measured to assess the foam performance of each formulation.
In this work several surfactant families are tested, among which: (1) anionic surfactants formulation optimized for their performances in sandstones, (2) switchable cationic surfactant (tertiary amine ethoxylate), (3) cationic surfactant, and (4) optimized cationic surfactant formulation. Solubility of the optimized formulation is found to be excellent in all considered brine (up to high salinity and hardness) and at high temperature; low static is obtained on the carbonate minerals (99% calcite) and bulk foam half-life time with supercritical CO2 (40°C/120bar) exceeds 24h. As a first demonstration step, foaming performance of each surfactant formulation is assessed through coreflood tests using intermediate salinity level water. The foam shear-thinning rheological behavior is obtained for velocities representative of near wellbore to in-depth reservoir conditions (from 5ft/day up to 50ft/day). Apparent viscosities are found to be very good, about dozens of centipoises for the lowest velocities. A technical challenges with carbonates lies in fluid/rock reactivity. The increase of divalent ions concentration in brine generally impairs both solubility and foaming ability of surfactant formulations. Here the use of the selected cationic surfactants less sensitive to divalent cations and allows both low adsorption on carbonate rocks and good foaming performance.
A highly promising foaming cationic formulation, compliant with dense CO2 and carbonates, has been designed and thoroughly tested. Results obtained bring new opportunities for the CO2-foam process applied to carbonate formations within an EOR+/CCUS strategy.
The sustained lower oil price for the last three years has shifted tight oil industry interest from an intensive drilling and completion based approach to more cost effective methods aimed at maximizing rates and ultimate recovery from existing wells. In that framework, application of conventional EOR methods to unconventional tight oil well has gained momentum in the recent period, with theoretical and experimental evaluation of approaches ranking from water and CO2 flooding to huff’n puff with chemicals. For that purpose, usual EOR experiments used for conventional rock cannot always be applied due to the extremely low volumes and permeability of tight reservoir rocks. This can lead to inaccurate results or extremely long experimental times. Here, we present a novel method for rapidly evaluating oil production by EOR methods in micro-Darcy permeability reservoir rock, and apply it to evaluate various chemical EOR approaches for unconventional tight oil wells.
Our method relies on a fast screening and a continuous NMR monitoring of fluid saturations during imbibition experiments at reservoir temperature in miniaturized plugs. This permits to evaluate oil and water saturations in the rock samples as a function of time without having to interrupt the experiment for carrying out measurements. We validate this method by evaluating recovery from 10 μD sandstones and carbonates during imbibition of LowIFT formulations with various chemical additives. Despite the extremely low permeability, oil production from plugs using various chemicals can be evaluated and compared in less than 72 hours.
Our new protocol shall be of interest to all laboratories trying to adapt EOR techniques to unconventional reservoirs, by permitting a real-time accurate and quantitative evaluation of various EOR options. In addition, the data we generated using various chemical EOR techniques support the interest of using low-IFT inspired chemical EOR methods to improve the ultimate recovery from tight reservoirs.
Friction reducers (FRs) represent an essential component in any slickwater-fracturing fluid. Although the majority of previous research on these fluids has focused on evaluating the friction-reduction performance of chemical components, only a few studies have addressed the potential damage these chemicals can cause to the formation. Because of the polymeric nature of these chemicals—typically polyacrylamide (PAM)—an FR can either filter out onto the surface of the formation or penetrate deeply to plug the pores. In addition, breaking these polymers at temperatures lower than 200°F remains a problem. The present study introduces a new FR that replaces the linear gel with an enhanced proppant-carrying capacity and reduced potential for formation damage.
Friction-reduction performance, proppant settling, breakability, and coreflood experiments using tight sandstone cores at 150°F were conducted to investigate a new FR (FR1). The performance of the new FR was compared with two different FRs: a salt-tolerant polymer that is a copolymer of acrylamide and acrylamido-methylpropane sulfonate (FR2), and a guar-based polymer (FR3). Different breakers were used to examine the breakability of the three FRs, including ammonium persulfate (APS), sodium persulfate (SPS), hydrogen peroxide (HP), and sodium bromate (SB).
The friction reduction of the new chemical was higher than 70% in fresh water or 2 wt% potassium chloride (KCl) in the presence of calcium chloride (CaCl2) or choline chloride. The presence of 1 lbm/1,000 gal of different types of breakers did not affect the frictionreduction performance. The friction reduction of 1 gal/1,000 gal of the new FR1 was also higher than that of the guar-based FR3 at a load of 4 gal/1,000 gal at the same conditions. The results show that the new FR is breakable with any of the tested breakers. Among the four tested breakers, APS is the most-efficient breaker. Static and dynamic proppant-settling tests further indicated a superior performance of FR1 for proppant suspension compared with a PAM FR (FR2). Coreflood experiments showed that FR1 did not cause any residual damage to the core permeability when APS was used as a breaker, compared with 10% and 9% damage when FR2 and FR3 were tested, respectively. Coreflood tests also showed that FR1 is breakable using SB with only 2.5% damage, whereas FR2 and FR3 resulted in 47% and 41% damage, respectively. The results also show that higher salinity does not affect the breakability of the new FR.
The proposed FR shows higher friction-reduction performance and better proppant-carrying capacity with no formation damage, compared with the conventional counterparts. Hence, FR1 is a viable choice for application in fracturing formations with proppants.
This paper presents laboratory studies to apply a new approach based on combined foam EOR processes to a naturally fractured carbonate reservoir (NFR) located in Oman. Applications of EOR techniques in fractured reservoirs, despite their attractive potential, have always been challenged by the inability to efficiently control EOR fluid mobility in fractures, which results in inefficient flooding of the reservoir matrix and poor economics of the process. This work discusses the maturation of efficient foam EOR processes for NFRs. The foam is aimed at blocking aqueous solution flow in fractures on the one hand while allowing low interfacial tension (IFT) solution to enter the matrix on the other hand.
We use an extensive experimental workflow to develop such solution in the challenging salinity conditions of the considered reservoir. Using robotics, we first combine low-IFT and foam boosting surfactants to come up with the most adapted chemical cocktail in terms of solubility, IFT with crude oil and foaming properties in hard brine. The selected formulation is then quantitatively characterized for IFT with crude oil, phase behavior with live oil, foam stability in reservoir pressure and temperature conditions, and foaming properties in model porous media. Dedicated coreflood experiments mimicking flow in fractured reservoirs are finally used to quantitatively evaluate the process using the designed formulation. This includes evaluation of foam-induced pressure drop, effluent fluid composition and oil recovery in artificially fractured cores.
The designed combined foam EOR formulation is perfectly soluble in hard brine and yields an IFT with crude oil well below 10-2 mN/m at 65°C. It is able to generate and stabilize foam both in absence and in presence of crude oil. Process evaluation in artificially fractured core shows good control by foam of aqueous solution mobility in fracture, and efficient imbibition of aqueous solution from fracture to matrix. Interestingly, a filtration effect is observed whereby only aqueous solution enters the matrix from the fracture, while foam only exists in fracture. This, combined with the sensitivity of foam to presence of oil, enables an efficient production of oil from the matrix through the fracture, as measured during recovery experiments.
This paper presents the first steps toward a potential pilot application of a new process aimed at making chemical EOR in fractured carbonate technically and economically feasible. The approach presented here allows the design of a performing process in challenging conditions of water salinity and hardness.