Layer | Fill | Outline |
---|
Map layers
Theme | Visible | Selectable | Appearance | Zoom Range (now: 0) |
---|
Fill | Stroke |
---|---|
Collaborating Authors
Oil & Gas
Abstract 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.
- Asia > Middle East (0.28)
- North America > United States (0.18)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Limestone (0.52)
- Geology > Mineral > Carbonate Mineral > Calcite (0.49)
ABSTRACT Some coreflood literature points to the initial wettability state undergoing change during waterflooding, usually towards water-wetness. The current study aimed to directly probe the adsorbed/deposited oil components on model silicate substrates prior to and after flooding. Bare glass and kaolinite-coated glass in the initial brine were drained with crude oil and aged, after which the oil was displaced with the flooding brine. For a matrix of initial and flood brines (comprising sodium and calcium) of varying salinity and/or pH, the oil remaining on the substrates was analyzed by high-resolution scanning electron microscopy, contact angle and spectroscopy. On glass, the oil layer contacting it in the initial (aged) state retracts and detaches during flooding, to typically leave individual oil nanodroplets separated by clean substrate. Brines less able to overcome the oil-glass adhesion displayed a higher coverage of more irregularly shaped, semiretracted drop-lets and a higher frequency of larger microscopic residues. On kaolinite-coated glass, the added porosity and roughness increased the presence of these adhering, stranded residues. On bare glass, the residual deposit after high salinity flooding is generally least at intermediate flood pH 6, while residues decrease with decreasing pH of low salinity floods. However, on kaolinite-coated substrates, residual deposit is greatest after flooding at intermediate pH 6, and also increases on reduction of flood salinity
- North America > United States (0.28)
- Oceania > Australia (0.28)
Abstract The two main parameters required to assess an enhanced oil recovery (EOR) technique in terms of its efficiency are interfacial tension and surface (wettability) alteration. The impact of these parameters on recovering what is left in the reservoir is crucial. With the current interest in brine injection as a potential-EOR method, the role of IFT and wettability alteration needs better understanding. In this study, a theoretical model is developed to evaluate the impact of both parameters. The results of this study indicate that salinity injection affects more surface wettability rather than interfacial tension. Conventional techniques of contact angle measurements on reservoir rocks at downhole conditions are very complicated. They are highly sensitive and require good core preservation and preparation. We propose a protocol to measure contact angle dependence on brine salinity, which includes a single contact measurement in rock/brine/oil system using fresh water and a set of less complicated measurements in brine/oil and rock/brine/air systems. The results of our predictive protocol for contact angle measurements are in very good agreement with conventional experimental measurements using glass/brine/dodecane system. The fact that simple contact angle measurements on the surface in air are required to calculate contact angles at different salinities makes the utilization of this protocol very attractive and less sensitive to surface preparation and its complexity.
- Asia > Middle East (0.47)
- Europe > Austria (0.28)
A Novel Approach to Handle Continuous Wettability Alteration during Immiscible CO2 Flooding Process
Al-Mutairi, Saad M. (King Fahd University of Petroleum and Minerals) | Abu-Khamsin, Sidqi A. (King Fahd University of Petroleum and Minerals) | Hossain, M. Enamul (King Fahd University of Petroleum and Minerals)
Abstract Wettability has been recognized as one of the main parameters that control the remaining oil-in-place. Knowledge of wettability alteration during displacement is essential to understand the displacement mechanisms and to recover oil efficiently. Continuous alteration of wettability and other related properties need to be addressed properly for an effective approach to enhanced oil recovery (EOR). Review of the literature reveals that much laboratory work, including core and micro-model flooding, was conducted to investigate wettability alteration during CO2 flooding process. However, limited research on numerical and/or analytical modeling of such wettability alteration has been reported. Moreover, to the best of our knowledge, published numerical and/or analytical models are time-independent solutions. Ignoring this time dimension creates a significant knowledge gap between such solutions and reality. To mitigate this shortcoming, a novel approach was developed to handle wettability alteration on continuous basis during immiscible CO2 flooding process. A mathematical model was developed to incorporate continuous time function for immiscible CO2 flooding process. During the development of the model equation, Cory relative permeability model was utilized. In this model, a new, modified Corey relative permeability model was incorporated to calculate the phase relative permeability as a function of wettability. A numerical, 1-dimensional, two-phase immiscible simulation scheme was built utilizing MATLAB program to solve the model equations. The results showed that inclusion of continuous wettability alteration model is believed to predict oil displacement and sweep efficiency more realistically. #
- North America > United States > Texas (0.47)
- North America > United States > Oklahoma (0.29)
Abstract The productivity and economics of horizontal wells are governed by the ability of the transverse fractures to communicate efficiently with the wellbore, which is strongly controlled by the conductivity of the proppant bed and the effectiveness of the fluid additives. These impact the relative permeability, the capillary pressure and the effective conductivity in the proppant bed. If the wellbore is high in the fracture, gravity segregation will cause liquid removal from the lower portion of the fracture to be very difficult. In low conductivity proppant beds, capillary pressure will tend to retain high water saturations, thus lower the effective conductivity even for the portions of the fracture above the wellbore. Laboratory and field studies are presented comparing various sizes and types of proppants and the influence of surfactants used in oil bearing formations including commonly used demulsifiers and a multi-phase complex nano fluid system. Ammot cell and centrifuge tests were used to evaluate imbibition of oil and water. Columns packed with proppant and formation cuttings are used to compare the effectiveness of various additives in allowing the displacement of water and establishing oil flow. Results are correlated with interfacial tension, contact angle, capillary pressures and surface energies of actual formation materials, oils and treating fluids from the Niobrara, Bakken, Granite Wash and Eagleford formations. Simulations are presented that show the impact of capillary pressure and oil viscosity on the displacement of fluids. Field results from various fields including the Niobrara, Bakken, and Marcellus formations are presented. The normalized field data shows that wells with higher conductivity proppants and properly selected surfactant packages result in longer effective frac lengths and greater normalized oil and gas production. Correlations are made between the observed relative perms in the lab vs. the observed field results.
- North America > United States > West Virginia (1.00)
- North America > United States > Texas (1.00)
- Geology > Rock Type > Sedimentary Rock (0.99)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (0.68)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > West Virginia > Appalachian Basin > Utica Shale Formation (0.99)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > United States > Tennessee > Appalachian Basin (0.99)
- (23 more...)
Wettability in CO2/Brine/Quartz Systems: An Experimental Study at Reservoir Conditions
Saraji, Soheil (Department of Chemical and Petroleum Engineering, University of Wyoming) | Goual, Lamia (Department of Chemical and Petroleum Engineering, University of Wyoming) | Piri, Mohammad (Department of Chemical and Petroleum Engineering, University of Wyoming)
Abstract A new experimental setup is developed that is capable of performing accurate IFT and contact angle measurements under extreme conditions, i.e., high pressure (up to 15,000 psi), high temperature (up to 200°C), and with highly corrosive fluids. The apparatus is equipped with an advanced and accurate temperature control system and a pulse-free Quizix pump to provide precise and stable experimental pressures and temperatures. Pre-equilibration of phases is achieved before each test, outside the measurement cell, to avoid non-equilibrium effects. Using an advanced drop shape analysis technique (ADSA-NA) and an automated polynomial fit, advancing and reseeding contact angles were measured with a protruded needle. The results cover a range of temperatures and pressures including subcritical and supercritical CO2 phases allowing characterization of wettability under both conditions. This preliminary study shows that wettability of quartz surface alters towards less water-wet condition when CO2 phase changes from subcritical to supercritical conditions. In addition, changes in wettability of quartz may not be monotonous function of temperature.
- Research Report > New Finding (0.64)
- Research Report > Experimental Study (0.40)
Abstract Wettability is a key property, which controls multiphase fluid flow in oil recovery processes. It is well known that the asphaltene deposition on rock surface changes the wettability of the rock. Although many experiments in the literature have been conducted to understand the physics underlying wettability alteration in crude oil/brine/rock (COBR) system because of asphaltene deposition; a sophisticated mathematical model describing this phenomenon is absent. In this paper, based on available experimental data in the literature and known physical mechanisms of asphaltene deposition on the rock in the COBR system, a model for wettability alteration due to asphaltene instability in crude oil is presented. Contact angle is introduced as a function of asphaltene stability index (ASI), which is determined thermodynamically based on the difference between the fugacity of asphaltene and the heaviest component in the oil. The shape of this function depends on pH, salinity and cation valency of brine, and asphaltene content of crude oil. We implemented our proposed model along with asphaltene precipitation, flocculation, and deposition models into an in-house compositional simulator, UTCOMP, developed at The University of Texas at Austin. Permeability and porosity reduction due to asphaltene deposition are also considered. Furthermore, relative permeabilities and capillary pressure are modified because of contact angle alteration during simulation. Although the amount of asphaltene deposition in the reservoir may not be comparable to the wellbore, a significant change in wettability occurs after the deposition of first layer of asphaltene on the rock surface. The result of our simulation shows that wettability alteration affects oil recovery, specifically when the brine produces unstable water film on the rock surface. In this case, rock wettability can change from 30° (water-wet) to 150° (oil-wet) and yield change in recovery depending on absolute permeability reduction magnitude and change in trapped oil saturation as well as end-point relative permeability.
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Treatment (0.36)
Abstract Low-permeability reservoirs are highly sensitive to water saturation. When filtrate or clear brine is lost into these formations, capillary forces pull the fluid into pore spaces and prevent full displacement upon production. This paper illustrates how effective flowback chemistry reduces water saturation and enhances productivity. The authors initiated a study to evaluate chemistries that can be added to reservoir drill-in fluids, completion brines, and workover fluids to reduce capillary forces, recover invaded brine from the formation, and promote optimal productivity of the well. This paper introduces a unique flowback chemistry that not only provides excellent surface tension reduction and good thermal stability, but fulfills a challenge not met before; i.e., it is completely soluble and compatible with all common types of completion brines. Furthermore, this chemistry is not absorptive to solids in drilling fluids or a porous formation matrix, therefore low surface tension and low capillary pressure are maintained with mud filtrate or brine that is lost to the formation. Simple, low-cost, and innovative methodologies are presented to illustrate capillary pressure reduction and brine recovery in a simulated formation. Due to the nature of surface activity, flowback treatments containing surfactants invariably generate strong and long-lived foam. If not controlled, foam can cause difficulties or even catastrophic outcomes for well service jobs including fluid transportation, well circulation, and brine reclamation. The flowback chemistry presented in this paper includes a new and very effective defoamer (or antifoamer,) which renders the flowback treatment non-foaming. Successful lab tests and field application are presented.
- North America > United States (0.49)
- Asia (0.46)
Abstract Efficient displacement and effective removal of oil-based mud from the wellbore prior to cementing is critical to developing an excellent bond between casing and formation. Synthetic-based muds (SBM) can leave a thin-layer of oil on the casing and the formation when displacing to cement. It’s one of the least compatible fluids with cement slurries. This oil-layer can prevent the cement slurry from forming a strong bond with the formation and the casing. The lack of good bond could lead to poor zonal isolation and leave the casing and wellbore with decreased structural integrity. Removing this oily layer is generally accomplished by running viscosified weighted spacer containing cleaning agents ahead of cement slurry. Traditional surfactants have limited performance inverting and cleaning oil-water emulsions, besides being extremely detrimental for the development of the mechanical properties of the cement. Microemulsions (Picture 4) are an oil-external, thermodynamically stable microemulsion that can be added in water or a viscous spacer as a single additive. The additive is a microemulsion dispersion of solvents and surfactants designed to enhance compatibility with the drilling fluid, demulsify, clean and water-wet the casing and borehole surfaces for better cement adhesion. Unlike traditional surfactants and solvents utilized to improve mud removal, the proprietary microemulsion additive, provides micellular dispersions that remain uniformly dispersed in water or viscous spacers, providing greater mud removal efficiency. Laboratory data demonstrates the effectiveness of the microemulsion in removing oil or synthetic-based mud while aggressively removing the oily layer and water-wetting from the casing and the formation.
Experimental Study of Wettability Alteration of Limestone Rock from Oil-Wet to Water-Wet using Various Surfactants
Golabi, Elyas (1Department of Petroleum Engineering, Omidiyeh Branch, Islamic Azad University, Omidiyeh, Iran.) | Azad, Fakhry Seyedeyn (2Department of Chemical Engineering, University of Isfahan, Isfahan, Iran) | Ayatollahi, Sayed Shahabuddin (3EOR Research Center, School of Chemical and Petroleum Engineering, Shiraz University, Shiraz, Iran.) | Hosseini, Sayed Nooroldin (1Department of Petroleum Engineering, Omidiyeh Branch, Islamic Azad University, Omidiyeh, Iran.) | Akhlaghi, Naser (1Department of Petroleum Engineering, Omidiyeh Branch, Islamic Azad University, Omidiyeh, Iran.)
Abstract The water flooding in the carbonate fracture reservoir is low efficiency because of higher permeability in fractures than in matrix, and water will not imbibe spontaneously into the matrix due to a negative capillary pressure. Spontaneous imbibition of water into carbonate fracture reservoir is a very important issue in secondary oil recovery method. However, almost more than 80% of the entire known carbonate reservoir can be categorized as oil wet. It is therefore important to find methods to alter the wettability from oil-wet to water-wet conditions that are effective in order to improve the recovery from carbonate fracture reservoir. So far, two methods have been developed wettability alterations: 1) addition of certain chemical surface active agent to the injection water, and 2) thermally wettability alteration by steam injection. In this study, an oil sample with 20 API was used to investigate the effect of the understudied surfactants on wettability alteration in the oil-water-limestone system. Understudied surfactants were SDBS (sodium dodecylbenzene sulfonate), C12TAB (dodecyl trimethyl ammonium bromide), C16TAB (hexadecyl trimethyl ammonium bromide) and Triton X-100 that were utilized at 0.5, 1.5 and 2.5 wt% concentrations. The experiments were performed several times (0, 1, 6, 12, 24, 48, 72, 96 h) after injection of oil drop under limestone rock sample at reservoir temperature of 80°C. The obtained results showed that the increasing each of the surfactant could cause wettability alteration of the rock from oil-wet towards water-wet situation by passing of time. This alteration was very sharp at the beginning, but it was increases slightly at the time. It was observed that Triton X-100 was more efficient than C16TAB, C12TAB and SDBS to alter the wettability of the rock.
- North America > United States (1.00)
- Asia > Middle East > Iran (0.29)