Yeganeh, Mohsen (ExxonMobil Research and Engineering Co.) | Hegner, Jessica (ExxonMobil Research and Engineering Co.) | Lewandowski, Eric (ExxonMobil Research and Engineering Co.) | Mohan, Aruna (ExxonMobil Research and Engineering Co.) | Lake, Larry W. (The University of Texas at Austin) | Cherney, Dan (ExxonMobil Research and Engineering Co.) | Jusufi, Arben (ExxonMobil Research and Engineering Co.) | Jaishankar, Aditya (ExxonMobil Research and Engineering Co.)
A capillary desaturation curve (CDC) depicts the relationship between residual oil saturation, Sor, (i.e. oil left behind in a well-swept permeable medium) and capillary number. A CDC is one of the most fundamental curves of oil recovery as it reveals flow conditions required for good oil displacement in porous media. Despite the importance of this critical curve, the fundamentals describing the physics of a CDC are still incomplete.
We present a physical model to describe the capillary desaturation curve. The model balances the capillary pressure and applied viscous stresses caused by flow and takes advantage of contact angle hysteresis that occurs in porous media. It defines a critical oil ganglia length that depends inversely on capillary number and depends on porosity, permeability, and wettability. We have combined the critical oil ganglia expression and ganglia length distribution in porous media to arrive at an expression for the capillary desaturation curve. The model suggests that when a trapped oil ganglion is larger than the critical ganglia length, the applied pressure difference can mobilize the trapped oil ganglion. We describe the differences and similarities between our critical ganglia length expression and previously reported expressions. The model describing the relationship between residual oil saturation and capillary number was successfully verified with microfluidic experiments using various crude oils and displacing fluids. We have also demonstrated that the model applies to previously reported coreflood CDCs from sandstone and carbonate media. Extension of the model led to a single curve representation of variations in Sor with reduced pressure. This representation is independent of the chemistry of the displacing fluid.
A systematic approach to characterize the mixed wet configurations of various reservoir rocks (sandstone and carbonates) by evaluating their surface energy distributions has been presented in this paper. This approach was tested against the macroscopic spatial distribution of oil-wet and water-wet sites and at different temperatures for validation.
The new approach used to characterize the mixed wettability of a reservoir rock pertains to establishing a relation between the volume fraction of the mixed-wet reservoir rocks and surface energy of the mixture. This approach is based on an accurate description of the various physico-chemical interfacial forces present at the reservoir rock surface using Inverse Gas Chromatography (IGC). Mixed-wet configurations of various reservoir rocks are created by combining water-wet and oil-wet samples of the rock in different volume fractions and shaken together to establish uniform distribution. These samples are then subjected to the IGC analysis at different temperatures to deduce their surface energy distribution. The relation developed herein is tested against spatial heterogeneity by combining the oil-wet and water-wet rock samples in a layered fashion to validate the approach. The complete method to deduce the surface energy distribution of a rock surface using IGC has also been explained in detail.
A definite and conclusive relationship between the surface energy and mixed wettability of silica glass beads, calcite, and dolomite samples was established in this study. The mixed-wet configurations of the rock samples ranged from 0% oil-wet (meaning water-wet samples) to 100% oil-wet samples. The findings indicated that the Lifshitz-van der Waals component of the rock mixture did not undergo any change with change in the wetting state of the system under study. However the acid base components showed a marked decrease with increasing oil wetness before plateauing. Temperature was found to have a profound impact on the surface energy of a rock surface. Spatial heterogeneity by way of layered and segregated distribution of oil-wet and water-wet sites did not affect the eventual surface energy distribution thereby validating the new approach.
An important factor during the life of a heavy crude reservoir is the oil mobility. It depends on two factors, oil viscosity and oil relative permeability. Two characteristics of nanoparticles that make them attractive for assisting IOR and EOR processes are their size (1 to 100 nm) and ability to manipulate their behavior. Due to their nano-sized structure, nanomaterials have large tunable specific surface areas that lead to an increase in the proportion of atoms on the surface of the particle, indicating an increasing in surface energy. Nanoparticles are also able to flow through typical reservoir pore spaces with sizes at or below 1 micron without the risk to block the pore space. Nanofluids or "smart fluids" can be designed by tuning nanoparticle properties, and are prepared by adding small concentrations of nanoparticles to a liquid phase in order to enhance or improve some of the fluid properties. However the use of nanoparticles and nanofluids for oil mobility has been poorly studied. Hence, the scope of this work is to present the field evaluation of nanofluids for improving oil mobility and mitigate alteration of wettability in two Colombian heavy oil fields; Castilla and Chichimene. Asphaltenes sorption tests with two different types of nanomaterials were performed for selecting the best nanoparticle for each type of oil. An oil based nanofluid (OBN) containing these nanoparticles was evaluated as viscosity reducer under static conditions. Displacement tests through a porous media in core plugs from Castilla and Chichimene at reservoir conditions were also performed. OBN was evaluated to reduce oil viscosity varying oil temperature and water content. Maximum change in oil viscosity is achieved at 122°F and 2% of nanofluid dosage. The use of the nanofluid increased oil recovery in the core flooding tests, caused by the removal of asphaltenes from the aggregation system, reduction of oil viscosity, and the effective restoration of original core wettability. Two field trials were performed in Castilla (CNA and CNB wells), by forcing 200 bbl and 150 bbl of nanofluid respectively as main treatment within a radius of penetration of ~3 ft. Instantaneous oil rate increases of 270 bopd in CNA and 280 bopd in CNB and BSW reductions of ~11% were observed. In Chichimene also two trials were performed (CHA and CHB), by forcing 86 bbl of and 107 bbl of nanofluid as main treatment within a radius of penetration of ~3 ft. Instantaneous oil rate increases of 310 bopd in CHA and 87 bopd in CHB were achieved not BSW reduction has been observed yet. Interventions were performed few months ago and long term effects are still under evaluation. Results look promising making possible to think extending application of nanofluid in other wells in these fields.
This paper presents a dynamic wettability alteration model based on the Gibbs adsorption isotherm equation. The model is conceptually and thermodynamically developed for ideal surfactant solutions (
The developed models can be tuned with experimental data including the contact angle, relative permeability, and capillary pressure parameters then they can be used to predict the efficiency of surfactant injection processes in naturally fractured reservoirs accordingly.
The application of surfactants to improve oil recovery in conventional reservoirs via wettability alteration and enhancement of spontaneous imbibition has been extensively studied in the literature. However, little work has been performed yet to investigate the interaction of these surfactants with ultra-tight oil-rich shale reservoirs such as Wolfcamp shale. The use of horizontal drilling and massive multistage hydraulic fracturing has made primary oil recovery from these ultra-tight oil-rich shale reservoirs possible. With declining production from existing shale wells, it is essential to explore potential "beyond primary" strategies in shale oil development. This paper analyzes the potential of surfactants in altering wettability and improving the process of spontaneous imbibition in oil rich shales demonstrating nanodarcy range permeability, relevant to stimulation and "beyond primary" chemical EOR applications in shales.
Novel proprietary surfactant blends along with traditional nonionic surfactants were investigated in this study using Wolfcamp shale core samples exhibiting nanodarcy permeability. X-ray diffraction analysis was performed which indicated that Wolfcamp shale has mixed mineralogy, with quartz, calcite, and dolomite acting as the major minerals in varying proportions depending on the interval depth. Contact angle and interfacial tension measurements were performed at reservoir temperature to identify the state of native wettability and the impact of surfactants in altering wettability. Thereafter, spontaneous imbibition experiments were performed using 3D computed tomography methods to understand the improvement in the magnitude of imbibition penetration due to surfactant addition. Contact angle and spontaneous imbibition experiments showed that Wolfcamp shale is intermediate-wet and surfactants have the potential to alter the native wettability to a preferentially water-wet state and improve oil recovery due to enhanced spontaneous imbibition.
Surfactants which altered the wettability significantly, but lowered the interfacial tension only slightly showed the highest oil recoveries due to the creation of strong capillary driven forces directly responsible for effective spontaneous imbibition. The potential of surfactants in altering wettability and improving oil recovery via enhanced spontaneous imbibition in ultra-tight oil-rich shales was verified in this study. The effectiveness of traditional nonionic surfactants in altering wettability and improving oil recovery was found to be comparable to that of novel, more expensive proprietary surfactant blends, and hence, the traditional nonionic surfactants provide a cost effective option for stimulation and EOR applications in Wolfcamp shale. Overall, this paper presents the theory behind surfactant interaction with ultra-tight shales and provides experimental results to validate the viability of surfactant induced improved oil recovery in shales.
Dalmazzone, C. (IFP Energies Nouvelles) | Mouret, A. (IFP Energies Nouvelles) | Behot, J. (IFP Energies Nouvelles) | Norrant, F. (IFP Energies Nouvelles) | Gautier, S. (IFP Energies Nouvelles) | Argillier, J.-F. (IFP Energies Nouvelles) | Chabert, M. (SOLVAY)
A majority of the worldwide oil reserves is contained in carbonate reservoirs. Most of these reservoirs are naturally fractured and produce less than 10% of the oil in place during the primary recovery operations. It is noteworthy that this particularly low recovery ratio is essentially due to a low permeability associated to an intermediate or preferentially oil wettability. Consequently, the recovery of residual oil from these specific reservoirs is a great challenge. Changing the wettability from oil wet to preferentially water wet by using chemicals is one of the EOR technique that may be advantageously used to enhance the production rate. This chemical treatment consists in injecting an aqueous solution of surfactants or chemical additives to increase the water wettability and favour spontaneous imbibition into the porous matrix. We present a new test allowing a fast screening of aqueous solutions of chemicals that may be used to improve oil recovery from carbonate reservoirs. The test consists in depositing a drop of aqueous solution on a porous carbonate slice that has been treated to be preferentially oil wet before being put into dodecane. The evolution of the drop profile is then monitored as a function of time by means of a camera, which permits a simultaneous measurement of the interfacial tension between oil and water, contact angle between the water drop and the porous matrix and spontaneous imbibition. Various types of non-ionic and anionic surfactants belonging to different families have been tested and ranked to identify the best candidates among these chemicals. Finally, a Nuclear Magnetic Resonance technique was used to follow spontaneous imbibitions of selected candidates in miniplugs representative of the carbonate slices used in the screening test. NMR's results confirmed the classification issued from the fast screening test.
Disproportionate permeability reduction (DPR) may provide field solutions to address high volumes of water production and efficiency of oil recovery in non-communicating layered reservoirs. This work evaluates the lab-scale DPR effectiveness at different formation wettability conditions using an environmentally friendly, water-soluble, silicate gelant. A robust, time/temperature stable and easy-to-design water-soluble silicate gelant system is utilized to conduct DPR treatments in oil- and water-wet cores using a newly established steady-state, two-phase chemical system placement. The experimental procedure is applied to ensure the presence of moveable oil saturation at which the injected DPR fluid (gelant) gels in the treated zone and to quantitatively control the placement saturation conditions in the formation. DPR treatments are conducted using a steady-state, two-phase (oil/gelant) placement to better control the water/oil saturation at which the silicate gel sets. The performance of water-soluble, silicate-based DPR treatments are evaluated using pre- and post-treatment two-phase (brine/oil) steady-state and unsteady state permeability measurements.
Strongly water-wet Berea cores are chemically treated to alter their wettability to oil wet and measured phase effective permeability curves are used to characterize the newly established core wettability. Treatment design should include filterability/injectivity and rheological studies of the DPR fluid to evaluate gelant interaction with the formation as well as gelation time and kinetics. Single-phase DPR fluid injectivity through Berea cores is excellent. At relatively high watercuts in water-wet cores, two-phase DPR-fluid/oil injectivity is good and even better in oil-wet cores regardless the watrecut. At relatively low watercuts in water-wet cores, the injectivity is not as good as in higher watercuts and the mobility reduction keeps increasing with the co-injection of the DPR-fluid/oil.
DPR-fluid/oil placement experiments conducted at the same saturation conditions and water/oil ratio (WOR) showed that the ultimate oil residual resistance factor in oil-wet cores is significantly lower than the one in water-wet cores. This is mainly due to more favorable oil-phase continuity and distribution in oil-wet media compared to the corresponding ones in water-wet formations. In water-wet cores, encapsulation of oil by gel may cause oil-phase discontinuities and porous medium conductivity reduction. Wettability tests have shown that silicate gel is strongly water-wet. Therefore, in oil-wet DPR treatments, formed gel in porous media yields a mixed-wet formation and a lower trapped oil saturation compared to the water-wet formation.
In either wetting state, relative permeability hysteresis was insignificant during the post-DPR treatment imbibition/drainage cycles. This also reflects stable gels during post-DPR treatment floods. DPR treatments conducted at high WOR in oil-wet cores have shown a minor gel "erosion" during the post-treatment two- and single-phase (water) injection; gel "erosion" ceased during oil injection. DPR treatments conducted at high WOR caused an increase in residual resistance factor (
Wang, D. (University of North Dakota) | Dawson, M. (Statoil Gulf Services LLC) | Butler, R. (University of North Dakota) | Li, H. (Statoil Gulf Services LLC) | Zhang, J. (University of North Dakota) | Olatunji, K. (University of North Dakota)
With the recent dramatic drop in oil price, production from ultra-tight resources, like the Bakken formation, may drop substantially. Since expenditures for drilling, completion, and fracking have already been made, existing wells will continue to flow, but oil rates will decline—rapidly in many cases. In a low oil-price environment, what can be done to sustain oil production from these tight formations?
We are testing a surfactant imbibition process to recovery oil from shales. We measured surfactant imbibition rates and oil recovery values in laboratory cores from the Bakken shale. After optimizing surfactant formulations at reservoir conditions, we observed oil recovery values up to 10–20% OOIP incremental over brine imbibition. However, whether or not surfactant imbibition will be a viable recovery process depends on achieving sufficiently high oil production rates in a field setting—which requires that we identify conditions that will maximize imbibition rate, as well as total oil recovery. In this paper, we describe laboratory evaluations of oil recovery using different core plugs. These recovery studies involved
(1) surfactant formulation optimization on concentration, salinity and pH, (2) characterization of phase behavior, (3) spontaneous imbibition, and (4) forced imbibition (flooding) with gravity drainage assistance.
In preserved cores, we observed: (1) Formulations using 0.1% surfactant concentration at 4% TDS salinity showed favorable oil recoveries (up to 40% OOIP). (2) Generally, surfactant formulations at optimal concentration and salinity were stable at high temperature (115°C). (3) Injectivity/permeability enhancements up to 75 percent occurred after acidification using acetic acid or HCl. (4) Wettability alteration is the dominant mechanism for surfactant imbibition. Of course, actions that increase fracture width will aid gravity drainage and oil recovery. This information is being used to design and implement a field application of the surfactant imbibition process in an ultra-tight resource.
Recovery from oil reservoirs could be improved by lowering the injection water salinity or by modifying the water injection chemistry. This has been proposed as a way to increase rock water-wetness. However, we have observed that the presence of sulfate anions in the aqueous phase can change the crude oil-water interfacial rheology drastically, and as a result, the oil recovery factor could be increased solely by alteration of fluid-fluid interactions. The purpose of this research is to show the effect of sulfate anion concentration in seawater injection on oil production through coreflooding results at low temperature.
Interfacial rheological experiments were run with several crude oils and modified seawater to see the effect of different ions on visco-elasticity of the crude oil-brine interface using an AR-G2 rheometer with a dual-wall ring fixture. Based on previous experimental results, carefully selected coreflooding experiments were run to evaluate differential pressure and oil recovery for each selected brine. Coreflooding experiments used Indiana Limestone at 25°C without aging to minimize changes in rock wettability.
The interfacial rheological results show that the visco-elasticity of the crude oil-brine interface is higher for a low-salinity brine compared to a higher-salinity one when individual salts are used, e.g. NaCl or Na2SO4. The difference is more pronounced if ultralow salinities are compared. For the cases with salinity values similar to that of seawater, the effect of sulfate concentration in water on interfacial visco-elasticity is more noticeable. Coreflooding results show that brines with a higher visco-elasticity, corresponding to a higher sulfate concentration in the water injected, yield higher oil recovery factor that those with lower visco-elasticity, including the experiments with salinity lower than 50% of that of seawater. Brine-rock reactions were geochemically simulated to prevent injection conditions that could cause formation damage. Additionally, pH, electrical conductivity and total dissolved solid (TDS) were analyzed in the effluents. Results show that for the model rock used, brine composition does not change significantly from contact with rock surfaces. Since wettability alteration was minimized by use of low-temperature and short ageing time, recovery correlates better with changes in interfacial rheology. For results showing an apparent lack of correspondence with the interfacial rheological response, arguments based on ganglia dynamics might shed light on the observed recovery outcome.
Our findings reveal that the injection of water with sulfate can modify the fluid-fluid interactions and consequently the final oil recovery, so in some cases, low-salinity brine injection is not necessarily conducive to an increment in oil production. Findings also indicate that more characterization of the brine-crude oil interface should be carefully conducted as part of the screening of adjusted brine chemistry waterflooding.
Carbonate rocks are typically heterogeneous at many scales; hence foams have the potential to improve both oil displacement efficiency and sweep efficiency in carbonate rocks. However, foams have to overcome two adverse conditions in carbonates: oil-wettability and low permeability. This study evaluates several foam formulations that combine wettability alteration and foaming in low permeability oil-wet carbonate cores. Contact angle experiments were performed on oil-wet calcite plates to evaluate the wettability altering capabilities of the surfactant formulations. Static foam stability tests were conducted to evaluate their foaming performance in bulk. Finally, oil displacement experiments were performed using Texas Cream and Estaillades Limestone cores with crude oil. Two different injection strategies were studied in this work: alternating gas-surfactant-gas injection and co-injection of wettability alteration surfactant with gas at a constant foam quality. Cationic surfactants DTAB and BTC altered the wettability of the oil-wet calcite plate to water-wet, but were ineffective in forming foam. The addition of a non-ionic surfactant Tergitol NP helped in the foaming ability of these formulations. In-house developed Gemini cationic surfactant GC 580 was able to alter the wettability from oil-wet to water-wet and also formed strong bulk foam. Static foam tests showed increase in bulk foam stability with the addition of zwitterionic surfactants to GC 580. Oil displacement experiments in oil-wet carbonate cores revealed that tertiary oil-recovery with injection of a wettability-altering surfactant can recover a significant amount of oil (about 20–25% OOIP) over the secondary water flood and gas flood. The foam rheology in the presence of oil suggested propagation of only weak foam in oil-wet low permeability carbonate cores.