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
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.
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.
Low permeability reservoirs contain a large volume of the world's oil resource. Often these fields are characterised by low waterflood injectivity, poor sweep and low productivity. A substantial number of these fields are initially, or during production become, fractured. Improved oil recovery and EOR for these fields is an attractive goal, although many conventional EOR applications present major challenges.
We present results on how wettability alteration, together with physical and chemical modifications of the waterflood, can improve oil recovery. From high precision adsorption experiments, together with wettability measurements on model systems, we present conclusions on the inter-relationship of adsorption behaviour and wettability of reservoirs.
Laboratory measurements are presented confirming how:
1. Wettability can be modified through changes in salinity, hardness and temperature.
2. In waterflooding there is a direct, measurable relationship between wettability (contact angle) and adsorption at the solid / liquid and liquid / liquid interfaces. These inter-relationships can be expressed in basic thermodynamic concepts.
3. Adsorption at solid / liquid interfaces can be directly related to the existence and nature of thin aqueous films in water wet and mixed wet reservoirs. Dynamic effects resulting from brines of different chemical and physical properties can be highly important in terms of displacement efficiency during waterflooding.
We demonstrate the significance of these results for waterflooding and EOR in lower permeability fields. Approaches such as wettability alteration, low salinity (including brine compositional modification) waterflooding, and variation of injection brine temperature all show potential. This is in contrast to more traditional chemical and immiscible gas injection, which are often technically difficult in these fields. We further conclude that these approaches can be beneficially applied fields with substantial fracturing and faulting.
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.
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.
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).
Welch, John Charles (Baker Hughes Inc.) | Newman, Caleb Ray (U. of Houston) | Gerrard, David Peter (Baker Hughes Inc.) | Mazyar, Oleg A. (Baker Hughes Inc.) | Mathur, Vipul (Baker Hughes Inc.) | Thieu, Vu (Baker Hughes Inc.)
The oil and gas industry is continuously looking for robust material and tool designs that provide greater operational flexibility in aggressive environments. Coating systems, engineered at the nanometer scale, exhibit enhancements that can address these needs.
Our study of nano-engineered coatings started with simple polymer-polymer self-assembled systems, to which was added nano-sized clay or one of several carbon-based nano materials. We evaluated application of different cross linker treatments. To evaluate the variables involved in preparation of the coating systems we quantified thickness and contact angle, and we performed micrographic and scanning electron microscope analysis of standard coated substrates. When applied to copper coupons we determined a 91% reduction of corrosion after four hours, 60% after 24 hours, and 13% after ninety hours in a hydrogen sulfide gas blend. Nano-engineered coatings applied to common oilfield elastomeric materials produce a 40x delay in swelling and decrease in transmission of carbon dioxide gas by 73%. All of the above are lab results, and the comparisons were made to baseline commercially available rubber compounds without nano-enhancement.
Our results demonstrated that nanotechnology can be very effectively used to significantly modify properties of commonly used oilfield materials. Reduced corrosion can extend the life of downhole electronics and motors. The oil swelling rate can be drastically reduced to give operators a greater flexibility in setting the packers and reducing intervention. These findings can be used to design new packers, sealing elements and other elastomeric components used in downhole environment. This paper will present our recent lab results along with a postulated mechanism on how nanotechnologies can impact material performance in downhole applications.
Thin films, typically less than 1µm thick, are created by alternately exposing a substrate to positively-charged and negatively-charged molecules or particles, as shown in Fig. 1. In this case, steps 1-4 are continuously repeated until the desired number of ?bilayers? (or cationic-anionic pairs) is achieved. However, an additional cation or anion can be introduced in the setup, leading to formation of ?quadlayers? (or cationic-anionic-cationic-anionic layers). Each individual layer may be 1-100+ nm thick depending on chemical properties, molecular weight, charge density, temperature, deposition time, counterion, and pH of species being deposited. The ability to control coating thickness down to the nanometer level, to easily insert variable thin layers without altering the process, to economically use raw materials (due to their thin nature), to self-heal and process under ambient conditions are some of the key advantages of this deposition technique. These films often have properties that are better than comparable thick films (greater than 1µm).
2.1 Layer-by-Layer Coating System
The coatings of interest contained a combination(s) of polymers like branched polyethyleneimine (B-PEI) and poly(acrylic acid) (PAA) along with nanomaterials - carbon-based and/or clay to produce 'nano brick wall' films that are fully dense and transparent. Glutaraldehyde (GA) or exposure to UV light was also used in polymer-based bilayer system to crosslink. Peroxide-based crosslinking systems were also briefly investigated.
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.