To determine the breakthrough time of the combustion front in the in situ combustion process for heavy oil recovery processes, no records have been reported in previous literature to date. In this work, the developed model was inspired by a new intelligent method called the “least‐squares support vector machine” (LSSVM) to specify the combustion front velocity in heavy oil recovery process. The proposed approach is applied to the experimental data from Iranian oil fields and reported data from the literature has been incorporated to develop and test this model. The estimated outcomes from the LSSVM approach are compared to the aforementioned actual in situ combustion data. By comparing the results obtained from suggested method with the relevant experimental ones it is clear that the LSSVM approach predicts the combustion front velocity with reasonable degree of precision. It worth mentioning that the LSSVM contains no conceptual errors, such as over‐fitting, which is an issue for artificial neural networks. The results of this study could couple with the industrial reservoir simulation software for heavy oil reservoirs to select the proper production method or achieve related goals.
Summary The goal of this work is to screen and evaluate laboratory mixtures of existing commercial, environmentally friendly sodium silicate chemicals that can be used for water management in naturally fractured carbonate (NFC) reservoirs. A thorough evaluation of a chemical for conformance-control purposes requires the investigation of the chemical properties before, during, and after gelation. These properties are the gelant's viscosity, pH, filterability, and injectivity; the gelation time and kinetics of the gelation process; strength of the formed gel against applied external forces; gel stability; gel shrinkage; and post-gelation-time behavior. This investigation has been conducted for different combinations (gelant systems) of sodium silicate with two types of polymers (a xanthan biopolymer and a low-molecular-weight synthetic polymer) and a crosslinker. Measurements on the gelant systems’ viscosity showed that the base sodium silicate system has a low, water-like, viscosity with a Newtonian behavior. This provides significant benefits for matrix treatment, but higher gelant viscosities may be required when sodium silicate gelants are used for conformance control of highly conductive fluid pathways to minimize potential placement difficulties caused by the lack of wellbore control with the possibility of the injected gelant reaching nondepleted formation regions, especially in cases of static gelation. This can be partially addressed by enhancing the gelant's viscosity through the addition of polymers without sacrificing, or even increasing in some cases, the resulting gel strength while at the same time lowering the gelant matrix injectivity. Gelant systems containing biopolymer resulted in a more shear-thinning behavior than other gelant systems, and the measured viscosity/shear-rate data could be well-matched with the Carreau-Yassuda model. Traditional tube testing and dynamic oscillatory tests were performed to measure the gelation time and monitor the gelation process and viscoelastic behavior of the formed gel at various temperatures. Gelation time, a critical factor in the placement of the injected-chemical system, can be tailored to field conditions by adjusting the gelant systems’ contents and concentrations. The strength of the formed gels of various gelant systems were compared on the basis of the results from maximum-compressional-pressure (MCP) tests. Strength tests showed promising gel behavior mainly for two of the selected gelant systems, one of which is the base system (sodium silicate without polymer additives) and the other is a silicate/biopolymer system. Silicate/synthetic-polymer systems, with or without crosslinker, yield significantly weaker gels. More-detailed investigations are needed, mostly on the interpretation of the tests, to be able to upscale the laboratory results to field applications. In addition to bulk measurements, coreflood tests were also conducted in artificially fractured carbonate cores to investigate gel-isolation effectiveness and formed-gel stability and shrinkage at static gelation conditions. Although some shrinkage was observed over time in practically all core laboratory experiments, the resulting core average permeabilities in post-gelation floods were significantly lower than the original fracture rock sample permeability. This was observed especially in the base sodium silicate and the silicate/biopolymer systems that were engaged to isolate the artificial core sample “fracture.” Systems containing synthetic polymers resulted in more shrinkage.
A primary difference between conventional oil and unconventional heavy oil reservoirs is the added economic value to recovery from heavy oil reserves due to the sweep efficiency. To determine the added value, one needs to obtain the recovery factor of in situ combustion; however, this requires special experimental and laboratory combustion study and field tests. In the absence of experimental studies during the early period of field exploration, techniques that correlate such a parameter are of interest for engineers. In this work, a new method called “least‐squares support vector machine” was developed to monitor the recovery factor of the in situ combustion employment through heavy oil reservoirs. The proposed approach is applied to the experimental data from extensive works reported in the literature and the model has been implemented, developed, and tested. The predicted results from the least‐squares support vector machine model were compared to the addressed real in situ combustion data. A comparison between the generated outcomes of our model and the alternatives proves that the least‐squares support vector machine model estimates the efficiency of the in situ combustion with high degree of accuracy. The least‐squares support vector machine does not contain any conceptual errors such as over‐fitting, which can be an issue for artificial neural networks. The outcomes of this research could be coupled with commercial production software for heavy oil reservoirs to enhance production optimization and facilitate design.
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 ЉerosionЉ during the post-treatment two-and single-phase (water) inje...
Linear coreflood experiments are performed at 60 °C to test the effectiveness of a low molecular weight associative polymer as a displacing agent, and its ability to enhance oil recovery on chemically treated oil-wet Berea cores. Polymer injection tests revealed high mobility reductions (resistance factor (RF)) and reduced remaining oil saturations. Results obtained suggest that the incremental oil production is due to the high mobility reduction, as reported previously for water-wet porous media. The reduced remaining oil saturation is a function of the injected associative polymer treatment volume. Polymer mobility reduction is highly affected by the injected polymer velocity; this reduction is observed to be more significant at the lower velocity spectrum. Therefore, the established incremental oil production, even at reduced polymer injection rates (lower capillary numbers), could be explained by the increased mobility reduction. A correlation for the velocity-dependent mobility reduction is developed. Results are in agreement with previously reported ones in water-wet media and related to the enhanced oil recovery (EOR) nature of the injected associative polymer as opposed to the traditional mobility control of other polymer types. During injection, a column of oil-polymer emulsion is formed gradually in the separator causing operational difficulties and introducing produced fluid measurement (and core fluid saturations) uncertainties. Produced oil/water emulsion polymer volume content is used to correct overestimated oil production attributed to measurement uncertainties. Real-time resistivity measurements could also be a valuable tool for both fluids saturation monitoring and improved core fluids saturation evaluation in flooded porous media.
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