Quintero, Harvey (ChemTerra Innovation) | Abedini, Ali (Interface Fluidics Limited) | Mattucci, Mike (ChemTerra Innovation) | O’Neil, Bill (ChemTerra Innovation) | Wust, Raphael (AGAT Laboratories) | Hawkes, Robert (Trican Well Service LTD) | De Hass, Thomas (Interface Fluidics Limited) | Toor, Am (Interface Fluidics Limited)
For optimizing and enhancing hydrocarbon recovery from unconventional plays, the technological race is currently focused on development and production of state-of-the-art surfactants that reduce interfacial tension to mitigate obstructive capillary forces and thus increase the relative permeability to hydrocarbon (
A heterogeneous dual-porosity dual-permeability microfluidic chip was designed and developed with pore geometries representing shale formations. This micro-chip simulated Wolfcamp shale with two distinct regions: (i) a high-permeability fracture zone (20 µm pore size) interconnected to (ii) a low-permeability nano-network zone (100 nm size). The fluorescent microscopy technique was applied to visualize and quantify the performance of different flowback enhancers during injection and flowback processes.
This study highlights results from the nanofluidic analysis performed on Wolfcamp Formation rock specimens using a microreservoir-on-a-chip, which showed the benefits of the multi-functionalized surfactant (MFS) in terms of enhancing oil/condensate production. Test results obtained at a simulated reservoir temperature of 113°F (45°C) and a testing pressure of 2,176 psi (15 MPa) showed a significant improvement in relative permeability to hydrocarbon (
Measurements using a high-resolution spinning drop tensiometer showed a 40-fold reduction in interfacial tension when the stimulation fluid containing MFS was tested against Wolfcamp crude at 113°F (45°C). Also, MFS outperformed other premium surfactants in Amott spontaneous imbibition analysis when tested with Wolfcamp core samples.
This work used a nanofluidic model that appropriately reflected the inherent nanoconfinement of shale/tight formation to resolve the flowback process in hydraulic fracturing, and it is the first of its kind to visualize the mechanism behind this process at nanoscale. This platform also demonstrated a cost-effective alternative to coreflood testing for evaluating the effect of chemical additives on the flowback process. Conventional lab and field data were correlated with the nanofluidic analysis.
Using a single universal spacer surfactant to clean a wide variety of oil-based mud (OBM) is considered the "Holy Grail" of spacer fluid system. Specialty chemical and service companies have devoted intense research and vast resources to develop the ideal spacer surfactant, but their efforts have not led to a singlesurfactant solution due to uniquely different drilling mud properties. It is no surprise to experts in the field that surfactant selection is extremely mud specific. For instance, one surfactant may effectively clean certain types of OBM, but fail in another mud from a different location that has the same density and base fluid. As a result, service companies have numerous surfactants in their portfolios, further complicating logistics and operations. This paper presents the discovery of a high-performance universal biomicromaterial, which can significantly improve the cleaning performance of any surfactants/spacer fluids to remove most, if not, all types of drilling mud. The innovative bio-micromaterial is an eco-friendly byproduct from another industry.
Successful cleaning of the drilling mud was demonstrated by standard rotor testing with different OBM samples from across North America, and the percentage of mud removal was determined. Furthermore, the ability of the innovative micromaterial to efficiently clean the mud was verified by measuring the strength of bonding between the set cement and the metal casing that had been cleaned by the spacer fluid after drilling mud contamination. Basically, this new procedure simulates downhole fluid displacement by the intermediate spacer fluid, which is ahead of the cement slurry, displacing the mud. Stability and mixability were also studied to determine the effect of the bio-micromaterial addition to the spacer fluid. Finally, a fundamental scientific study using thermogravimetric analysis and imaging techniques was done to characterize the material and determine its thermal stability.
For the first time, newly discovered, high-performance, universal cleaning micromaterial is presented to enhance the OBM removal of any spacer fluid design. This groundbreaking research has successfully demonstrated the unconventional advanced material to be a universal cleaning, single-additive spacer admixture for a wide variety of drilling mud from various regions across North America. To our knowledge, based on extensive literature search, this is the first report about the application of this natural waste product in wellbore cleaning fluids like the spacer.
Application of horizontal wells and multi-stage fracturing has enabled oil recovery from extremely low permeability shale oil reservoirs, but the decline in production rate is more than two thirds in the first two years. We are trying to develop chemicals that can be injected into old wells to stimulate oil production before putting the well back in production. The goal of this work is to evaluate chemical blends for such a process at the laboratory scale. The chemical blend contains surfactants, a weak acid, a potential determining ion, and a solvent. Six different solvents were screened: Cyclohexane, D-Limonene, Dodecane, Kerosene, Turpentine, and Green Solvent®. Most of the chemical blends with the solvents extracted about 60% of the oil from shale chips, but the Green Solvent® extracted about 84%. Spontaneous imbibition tests were performed with outcrop Mancos shale cores. Oil was injected into these outcrop cores at a high pressure. NMR T2 distributions were measured for the cores in the original dry state, after oil injection and after imbibition. The aqueous phase from the chemical blend imbibed into the cores and pushed out a part of the oil and gas present in the cores. The surfactant in these blends can change wettability and interfacial tension. The solvent can mix with the oil and solubilize organic solid residues such as asphaltenes. The weak acid can dissolve a part of the carbonate minerals and improve permeability. The synergy can make these chemical blends strong candidates to stimulate oil recovery in shale formations.
Wang, Mingyuan (The University of Texas at Austin) | Baek, Kwang Hoon (The University of Texas at Austin) | Abeykoon, Gayan A. (The University of Texas at Austin) | Argüelles-Vivas, Francisco J. (The University of Texas at Austin) | Okuno, Ryosuke (The University of Texas at Austin)
Tight oil reservoirs typically show rapid reduction in production rate within a few years. Various methods of improved oil recovery from tight reservoirs have been studied, such as cyclic injection of gas and chemical solutions. Chemical solution injection is expected to improve oil recovery through wettability alteration and water/oil interfacial tension (IFT) reduction because most tight oil reservoirs are reportedly intermediate- to oil-wet.
This paper presents a comparative study of two wettability modifiers with different characters for enhancing water imbibition from a fracture into the surrounding matrix. One is 3-pentanone, a symmetric short ketone, and the other is 2-ethylhexanol-4PO-15EO, a non-ionic surfactant with an ultra-short hydrophobe. They were used as low-concentration additives (approximately 1 wt%) to reservoir brine (RB) in this research.
Contact-angle experiments with oil-aged calcite surfaces showed that the two chemicals are comparable as wettability modifiers. For example, the surfactant solution was able to change the contact angle of oil droplets on oil-aged calcite surfaces from 134° to 47° within a day.
Coreflooding experiments using fractured limestone cores showed that the 3-pentanone solution resulted in more rapid oil recovery by water imbibition than the surfactant solution. The incremental oil recovery factor was 30.9% for 1.6 pore-volumes injected (PVI) of the 3-pentanone solution and 8.4% for 1.2 PVI of the chase RB. For the surfactant case, it was 23.6% for 1.6 PVI of the surfactant solution and 23.7% for 7.0 PVI of the chase RB.
The difference in oil recovery response between the two chemical solutions was attributed to their different characters as wettability modifiers; that is, the surfactant solution lowers the water/oil IFT from 11 mN/m to 0.21 mN/m, but the 3-pentanone solution does not. The 3-pentanone solution can keep the original water/oil IFT, and increase the capillary force for water imbibition by wettability alteration. The importance of lowering the water/oil IFT was observed during the extended chase RB injection after the surfactant slug. The oil recovery in the surfactant case was increasing even after 7.0 PVI of the chase RB.
The goal of this work is to evaluate the applicability of a novel set of surfactants to enhance recovery from a viscous oil, high temperature, high permeability, clastic reservoir. A large number of novel short-hydrophobe based surfactants/cosolvents were designed and synthesized. As these surfactants do not require expensive aliphatic alcohols for their synthesis, they are likely to be less costly than conventional anionic surfactants. Here only phenol hydrophobe based non-ionic surfactants with varying number of propylene oxide (PO) and ethylene oxide (EO) groups are discussed. These surfactant molecules were investigated for their aqueous stability limits, interfacial tensions (IFT) with a viscous crude oil and oil recovery from sandpack or sandstone cores. Surfactant phase behavior experiments with viscous crude oil showed low IFT (not ultralow) for single surfactant systems. Only one surfactant (Phenol-7PO-15EO) formulation was chosen for coreflood in sandpack and sandstone cores. Water flood recovered about 50% original oil in place (OOIP) and reduced the oil saturation to about 48% in the high permeability sandpacks. The tertiary surfactant polymer flood with Phenol-7PO-15EO increased the cumulative recovery to 99% for sandpacks. The oil recovery was insensitive to injection brine salinity in the range studied. As the permeability decreased, the tertiary oil recovery decreased if the permeability is lower than 7 Darcy. Surfactant-polymer (SP) formulations with this surfactant can be recommended for high permeability sandstone reservoirs with viscous oils, but not for sub-Darcy sandstones.
Abdelfatah, Elsayed (Chemical and Petroleum Engineering Department, University of Calgary, 2500 University Drive NW, Calgary, Alberta T2N 1N4, Canada) | Wahid-Pedro, Farihah (Chemical and Petroleum Engineering Department, University of Calgary, 2500 University Drive NW, Calgary, Alberta T2N 1N4, Canada) | Melnic, Alexander (Chemical and Petroleum Engineering Department, University of Calgary, 2500 University Drive NW, Calgary, Alberta T2N 1N4, Canada) | Vandenberg, Celine (Chemical and Petroleum Engineering Department, University of Calgary, 2500 University Drive NW, Calgary, Alberta T2N 1N4, Canada) | Luscombe, Aidan (Chemical and Petroleum Engineering Department, University of Calgary, 2500 University Drive NW, Calgary, Alberta T2N 1N4, Canada) | Berton, Paula (Chemical and Petroleum Engineering Department, University of Calgary, 2500 University Drive NW, Calgary, Alberta T2N 1N4, Canada) | Bryant, Steven (Chemical and Petroleum Engineering Department, University of Calgary, 2500 University Drive NW, Calgary, Alberta T2N 1N4, Canada)
Waterflooding of heavy oil reservoirs is commonly used to enhance their productivity. However, preferential pathways are quickly developed in the reservoir due to the significant difference in viscosity between water and heavy oil, and hence, the oil is trapped. Here, we propose a platform for designing ultra-low IFT solutions for reducing the capillary pressure and mobilizing the heavy oil.
In this study, mixtures of organic acids and bases were formulated. Three different formulations were tested: (i) Ionic liquid (IL) formulation where bulk acid (4-dodecylbenzene sulfonic acid) and base (Tetra-
The IL and ABs formulation are acidic solutions with pH around 3. The ASBs formulation is highly basic with a pH around 12. Non of the formulations salted out below 14 wt% of NaCl. While conventional surfactant, SDBS, precipitated at salt concnetration less than 2 wt% of NaCl. The formulation solutions (1 wt%) have different optimum salinities: 2.5 wt% NaCl for ASBs, 3 wt% NaCl for IL and AB. Although IL and AB have the same composition and molar ratio of the components, their performances are completely different, indicating different intermolecular interactions in both formulations. Corefloods were conducted using sandpack saturated with Luseland heavy oil (~15000 cP) and at fixed Darcy velocity of 12 ft/day. A slug of 1 PV of each formulation was injected after waterflooding for 5 PV and followed by 5 PV post-waterflooding. In the hydrophilic sandpacks, IL and AB formulation produced an oil bank, consisting mainly of W/O emulsion, with oil recovery that is 1.7 times what was recovered by 11 PV of waterflooding solely. Majority of the oil was recovered in the 2 PV of waterflood following the IL slug. ASBs formulations produced O/W emulsions with prolonged recovery over 5 PV waterflooding after the ASB slug. The recovery factor for ASBs was 1.6 times that recovered for 11 PV of waterflooding only. In the hydrophobic sandpacks, The ASB formulation slightly increased the recovery factor compared to only waterflooding. While for IL and AB formulation, the recovery factor decreased.
This work presented a novel platform for tuning the recovery factor and the timescale of recovery of heavy oil with a variable emulsion type from O/W to W/O depending on the intermolecular interactions in the system. The results demonstrate that the designed low IFT solutions can effectively reduce the capillary force and are attractive for field application.
We present a CT coreflood study of foam flow with two representative oils: hexadecane C16 (benign to foam) and a mixture of 80 wt% C16 and 20 wt% oleic acid (OA) (very harmful to foam). The purpose is to understand the transient dynamics of foam, both generated in-situ and pre-generated, as a function of oil saturation and type. Foam dynamics with oil (generation and propagation) are quantified through sectional pressure-drop measurements. Dual-energy CT imaging monitors phase saturation distributions during the corefloods. With C16, injection with and without pre-generation of foam exhibits similar transient behavior: strong foam moves quickly from upstream to downstream and creates an oil bank. In contrast, with 20 wt% OA, pre-generation of foam gives very different results from co-injection, suggesting that harmful oils affect foam generation and propagation differently. Without pre-generation, initial strong-foam generation is very difficult even at residual oil saturation about 0.1; the generation finally starts from the outlet (a likely result of the capillary-end effect). This strong-foam state propagates backwards against flow and very slowly. The cause of backward propagation is unclear yet. However, pre-generated foam shows two stages of propagation, both from the inlet to outlet. First, weak foam displaces most of the oil, followed by a propagation of stronger foam at lower oil saturation. Implicit-texture foam models for enhanced oil recovery cannot distinguish the different results between the two types of foam injection with very harmful oils. This is because these models do not distinguish between pre-generation and co-injection of gas and surfactant solution.
Wax and paraffin precipitation is a major problem around the world, costing the petroleum industry billions of dollars yearly. As temperature drops below the Wax Appearance or Wax Precipitation Temperature (WAT/WPT) of crudes, paraffin starts to precipitate out and restrict or block the effective flow. There are different methods, such as mechanical and chemical remediation to deal with wax issues. Among the latter ones, the use of surfactants is favorably looked upon since they are small molecules with surface activity properties. This study aims to introduce novel aliphatic non-ionic surfactants with different chain length and degree of ethoxylation. In addition to chain length, the impact of branching on the hydrophobic part of the surfactants was also studied.
A waxy crude oil from Brazil was characterized through determining its carbon distribution, WAT, viscosity and density based on industry standard methods. Several surfactants with different combinations of chain length/ethoxylation number were then selected for screening. The performance of surfactants was evaluated based on data obtained from treated crude versus the control sample through different experiments. Rheology studies were conducted at 50 to -10°C and at shear rates of 5 and 300 s-1. The cold finger instrument was utilized to determine paraffin content of the untreated and treated crude. Finally, the paraffin crystal size was analyzed through microscopic studies.
The results showed that shear rate can affect the wax treatment outcome as well as the effective concentration of surfactant. Therefore, it is important to assess the rheology at high and low shear rates. Some surfactants in the present study performed great at both low and high shear rates and were able to reduce the viscosity by 80% at temperatures well below WAT of the crude oil. The microscopy results confirmed that wax crystals were reduced in size and were more dispersed after treating the crude with these surfactants. The findings from High Temperature Gas Chromatography showed that the deposition of heavy fraction part of crude (C40+) is reduced after treating the crude oil with the surfactants in the present study.
The current study addresses the wax precipitation/deposition challenges of heavy crudes and proposes mitigating them through the use of some new non-aromatic non-ionic surfactants. The chemistries and findings of this research help the oil and gas industry to save money and time by mitigating flow assurance problems.
Surfactant-Assisted Spontaneous Imbibition (SASI) and gas injection have been proven to improve production from Unconventional Liquid Reservoirs (ULR). However, the novelty of the method has resulted in a few publications to date. This study utilizes numerical modeling to upscale laboratory data of SASI for completion purposes and gas injection plus SASI for EOR. Novel gas and aqueous-phase injection strategies following primary depletion are designed based on actual completion and production data. Multiple sequencing configurations for both surfactant and gas injection are tested to propose the best combined-EOR scheme for ULR.
Parameters related to the mechanism of SASI and gas injection are retrieved from CT-generated core-scale model of laboratory experiments. SASI and gas injection experimental results were upscaled to model production response of a hydraulically fractured well with realistic fracture geometry and conductivity. The core-scale model was created to determine the diffusion coefficient, relative permeability, and capillary pressure curves by history-matching the laboratory data. The field-scale model was developed with a dual-porosity compositional model to predict production enhancement for various combined-EOR schemes in ULR.
Wettability and IFT alteration are the two primary mechanisms for SASI in enhancing production. Experimental studies revealed that surfactant solution recovered up to 30% OOIP, whereas water alone only recovered approximately 10% OOIP. Capillary pressure and relative permeability constructed from scaling group analysis and core-scale numerical models showed that surfactant addition enhances the two curves. On the other hand, gas injection EOR was found to be driven by multi-contact miscibility and diffusion. Parameters related to both methods were applied to the field-scale model for multiple completion and EOR schemes. Results demonstrate that the combination of SASI and gas injection possesses significant potential in improving production rates and estimated ultimate recoveries (EUR) in ULR. Soak times, surfactant concentration, injection pressure, duration of the cycle, and cumulative gas injection control the level of enhancement. With a large number of control variables, specific customizations can be optimized to suit criteria of different field applications.
Kar, Taniya (Reservoir Engineering Research Institute, Palo Alto, CA) | Chávez-Miyauchi, Tomás-Eduardo (Universidad La Salle México) | Firoozabadi, Abbas (Reservoir Engineering Research Institute, Palo Alto, CA) | Pal, Mayur (North Oil Company, Doha, Qatar)
Low salinity water injection when effective in increasing oil recovery is often thought to be through increase in water wetting. Recently, oil-water interfacial rheology has been suggested to be related to oil recovery from low salinity water flooding. We have also discovered that addition of a very small amount of a functional molecule in the injection brine increases oil recovery significantly. Quantitative effect of interfacial elasticity and the effect of rock on oil recovery is investigated at 100 ppm concentration in this work for the first time. A light crude oil is used in four sets of waterflooding experiments in a carbonate rock. The injection brine is modified by adding 100 ppm of a non-ionic surfactant. To understand the recovery performances, interfacial viscoelasticity, interfacial tension and contact angle measurements are performed using brines of varying salinities. In interfacial rheology the effect of equilibration of the aqueous phase with the rock is also investigated. Additionally, adsorption of the surfactant in the carbonate rock is investigated for various aqueous phases via UVvis spectrometry. Crude oil, calcite and reservoir brine show moderate oil-wetting behavior. Addition of surfactant molecules makes the system more water-wet, however, the change is not pronounced. From coreflooding experiments, addition of surfactant in high salinity brine increases recovery by over 20% which we interpret to be due increase in interface elasticity. The phase angle which is a direct measure of interface elasticity decreases by 70% in an aqueous phase at about 4 wt% salt due to the surfactant. High interface elasticity reduces oil snap off and increases oil recovery. An effective molecule dissolved in water can increase the interface elasticity significantly. In relation to low salinity water injection we have established that there is an optimum salt concentration for high oil recovery. The injection of an aqueous phase without salt gives a lower recovery than injection of say 0.1 wt% salt in the injected water.
We have introduced a new IOR process based on interface elasticity which requires a very low concentration of a non-ionic surfactant. The process is neither through wettability alteration nor through significant change in IFT. The chemical we have used is environmentally friendly and of low cost. It has very low adsorption onto the rock surface.