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.
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 floodingis 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
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.
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.
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.
Golabi, Elyas (Islamic Azad University-Omidieh) | Seyedeyn Azad, Fakhri (University of Calgary) | Ayatollahi, Shahab (Shiraz University) | Hosseini, Nooradin (Petroleum University Of Omidieh) | Akhlaghi, Naser (IAU Science & Research Branch)
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 80oC.
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.
About half the world's discovered oil reserves are in carbonate reservoir forms and many of them are naturally fractured (Roehl and Choquette, 1985). The Total oil recovery does not exceed generally 30%. Such reservoirs are often characterized by high-permeability fractures and a low permeability matrix medium. Most of the injected water will pass through the fracture network and displaces only the oil residing in the fracture (Cuiec, 1984; Treiber et al., 1972). Spontaneous imbibition of water from the fractures into the matrix takes place if the reservoir is water-wet. However, up to 65% of carbonate rocks are oil-wet and 12% are intermediate-wet (Chillingar and Yen, 1983). Most of the oil reservoirs are found in carbonate rocks, many of which contain fractures with high hydraulic conductivity surrounding low-permeability matrix blocks that are mixed-wet to oil-wet (Allan and Sun, 2003; Roehl and Choquette, 1965; Salehi, et al., 2008).
Shojaikaveh, Narjes (TU Delft) | Berentsen, Cas (Delft U. of Technology) | Rudolph-Floter, Susanne Eva Johanne (Delft U. of Technology) | Wolf, Karl Heinz (Delft U. of Technology) | Rossen, William Richard
The injection of carbon dioxide (CO2) into depleted gas reservoirs and aquifers offer options for CO2-storage. Co2 sequestration is largely controlled by the interactions between CO2, reservoir fluid(s) in place and rock. In particular, the wettability of the rock matrix is a key factor for the fluid distribution and fluid displacement.
In this study, the wetting behavior of CO2-Bentheimer sandstone-water systems was investigated by means of visual contact-angle measurements. The experiments were conducted in a modified pendant drop cell (PDC) that allows captive-bubble contact-angle measurements at elevated temperatures and pressures. Contact angle measures were peformed with water that was fully (pre)-saturated with CO2. Multiple experiments were performed at constant temperature of 318K and pressures varying between 0.1-12 MPA which represent typical in-situ reservoir conditions. The experimental data shows that the contact angle and the size of the bubble converge to equilibrium in time. During this convergence period, the contact angle and the bubble size generally show a slight change as function of time. This can be contributed to the mass transfer and reduction in density of the CO2 during re-equilibration of the system. The experimental data shows a larger dependency of the contact angle on bubble size than on pressure. However, for bubbles with similar size, contact angle shows a slight increase as a function of pressure. However, for bubbles with similar size, contact angle shows a slight increase as function of pressure. All data shows that Bentheimer-water-CO2 systems remain water-wet even at high pressure.
Significant reduction in well productivity of gas-condensate reservoirs occurs owing to reduced gas mobility arising from the presence of condensate/water liquid phases around the wellbore.
As wettability modifiers, fluorinated chemicals are capable of delivering a good level of oil and water repellency to the rock surface, making it intermediate gas-wet and alleviating such liquid blockage.
The main objective of this experimental work has been to propose an effective chemical treatment process for carbonate rocks, which have received much less attention in comparison to sandstone rocks. Screening tests, including contact angle measurements and compatibility tests with brine, were performed using mainly anionic and nonionic fluorosurfactants. On positively charged carbonate surfaces the anionic chemicals were sufficiently effective to repel the liquid phase, whilst the nonionic chemicals showed an excellent stability in brine media. A new approach of combining anionic and nonionic chemical agents is proposed, to benefit from these two positive features of an integrated chemical solution.
A number of low and high permeability carbonate cores have been successfully treated using chemicals selected through screening tests. Optimization of solvent composition and filtration of the solution before injecting chemicals into the core proved very effective in reducing/eliminating the risk of possible permeability damage due to deposition of large chemical aggregates on the rock surface. The chemical solution optimized in this study can be applied as an efficient wettability modifier for mitigating the negative impact of condensate/water banking in carbonate gas-condensate reservoirs.
Proper acid placement/diversion is required to make matrix acid treatments successful. Viscoelastic surfactants (VES) are used as diverting agents in carbonate matrix acidizing. However, these surfactants can adversely affect wettability around the wellbore.
Spreading droplets may not reflect wettability, if they result from low oil-acid IFT's. Therefore, a procedure was proposed for contact angle measurements when surfactant solutions, such as spent acid with VES and EGMBE, reduce interfacial tensions (IFT's) and cause oil droplets to spread (Adejare et al. 2012).
The effect of two amphoteric amine-oxide VES', designated as "A" and "B", and an EGMBE preflush and postflush on the wettability of Austin cream chalk was studied using the proposed procedure.In addition, the two-phase titration experiment was used to measure VES adsorption.
A treating schedule sequence typical of carbonate matrix acidizing was used. Rocks were centrifuged in fluids representing the preflush, main acid stage, diverting stage, and postflush.The difference in contact angles before and after centrifuging shows the effect of surfactants in the spent acid on wettability.Contact angles were measured in spent acid with HCl only to prevent VES and EGMBE from reducing IFT's.
VES "A" and "B" adsorb on the rock surface at 25 and 80°C.Experiments with acid treatments with 4 vol% VES "A" and "B" diversion stages and a 10 vol% EGMBE preflush and postflush made initially oil-wet rocks water-wet at 25°C, 80°C, and 110°C. Acid treatments with a 4 vol% VES "A" diversion stage only made rocks water-wet at 25°C and 80°C. For the parameters investigated, our results suggest that diversion with VES "A" only, andan EGMBE flush following diversion with VES "A" and "B",can alter wettability to water-wet and increasethe relative permeability to oil.
Matrix acidizing is used to improve production from oil and gas wells and to improve injection into injection wells. An acid or solvent is injected into the reservoir below the fracturing pressure to create channels that bypass the damage in carbonates. Carbonate reservoirs are stimulated using primarily hydrochloric acid (HCl).
VES is a chemical diverting agent used in carbonate matrix acidizing. Diversion is needed because of permeability contrasts and lithological differences in the reservoir (Taylor et al. 2004). Without proper placement, more acid would be required to achieve the same amount of stimulation (Economides and Nolte 2000). In addition, improper placement will result in inefficient damage removal, with the most damaged zones getting the least amount of stimulation. At the end of the treatment, hydrocarbons or mutual solvents break down the structure of the VES gel to spherical micelles and reduce the viscosity(Nasr-El-Din et al. 2008). This allows the production of hydrocarbons. Mutual solvents are also used to make rocks water-wet.
Lab and field studies suggest that VES is retained in the reservoir.The use of VES-based acids in carbonate matrix acidizing has caused damage in low permeability oil formations (Nasr-El-Din et al. 2006). A mutual solvent flush removed only 22% of VES from 20 in. carbonate cores, after coreflood stimulation using a VES-based acid (Yu et al. 2010). Seawater did not break a VES gel in a lab test (Crews and Huang 2007). Similarly, a Gulf of Mexico API 29 gravity crude oil did not break down the viscosity of a VES gel (Huang and Crews 2008). In both experiments, VES gels were broken with internal breakers. Unbroken VES gels probably have a very high viscosity at low shear rates, and thorough mixing that is unlikely to occur in porous media is required for reservoir fluids to break the gel (Huang and Crews 2008).
Manipulating the injected brine composition can favorably alter the reservoir wetting state; this hypothesis has been validated in sandstone reservoirs by several scientists. A total of 214 coreflooding experiments were conducted to evaluate low salinity waterflooding (LSWF) secondary recovery and 188 experiments were conducted to evaluate tertiary recovery, for sandstone reservoirs. Although the incremental recovery potential in carbonate reservoirs is greater than in sandstones, only a few imbibition and coreflooding experiments have been conducted. The simulator and recovery mechanisms presented by Aladasani et al. (2012) are used and their suitability and validity to low salinity waterflooding in carbonate reservoirs has been confirmed. This has been achieved by comparing simulated LSWF secondary and tertiary recoveries with published coreflooding experiments. Furthermore, the prediction profiler in JMP was used to examine incremental recovery for the following variables: (a) acid number and interfacial tension (IFT) sensitivities, and (b) 2nd stage injected brine and 3rd stage injected brine anion contents. In weak water-wet conditions, the incremental recovery is driven by low capillary pressures, and the underlining recovery mechanism is the increase in oil relative permeability. Therefore, wettability modification is ideal when achieved by shifting the wetting state from oil-wet or water-wet to a maintained intermediate wetting condition irrespective of the injected brine salinity dilution. If the wettability is shifted to a strong water-wet system, then it would be more favorable to use brine with anions to shift the wettability back to an intermediate wetting state. IFT has a bigger impact on LSWF in carbonate reservoirs; however, contact angle is more significant to the final oil recovery. Future work should consider studying the impact of cationic and anionic ions on coreflooding recovery separately and using cores with different initial wetting states, preferably strong oil-wet cores.