No abstract

Density and ultrasonic speed measurements have been made, respectively, by means of a densimeter operating in a flow mode and by a sonic solution monitor using a 'sing-around' technique, for aqueous mixtures of 2-(2-methoxyethoxy)ethanol and 2-[2-methoxy(ethoxy),lethanol, at 298.15 K, across the entire composition range. The density values were readily converted to molar volumes, V, and excess molar volumes, VE. Estimates of the isentropic molar quantity, K,, equal to -(aV/ap), , and of its excess counterpart, KE, have been obtained from the density values, in combination with the ultrasonic speed values. The magnitude of VE increases with the introduction of oxyethylene groups into the molecule of amphiphile. The composition dependence of KE shows a similar increase, but one that is limited to the water-rich region. Data reduction procedures have been used to calculate several related quantities leading to graphs with enhanced visual impact. Our results have been compared with those reported earlier for methanol-water, and 2-methoxyethanol-water. Graphical analyses of the data sets are presented in an effort to find a plausible rationale for the observed trends in terms of prevailing patterns of molecular aggregation, while the various excess quantities considered are analysed using a segmented-composition model.

Hydraulic fracturing is the most common stimulation technique to make hydrocarbon production feasible and optimal worldwide. However, it has been preferentially focused on low permeability formations, and when applied to high permeability, it has been focused on sand control. This article outlines the process and results of the hydraulic fracturing campaign for productivity purposes (not for sand control) in the basin of the eastern plains of Colombia given the petrophysical characteristics of the cretaceous formations, where thinking "out of the box" and separating from the existing premises, resulted in successful implementation of this technique in high permeability wells (~ 1D), high water cuts (up to 80% BSW) and heavy oil reservoirs (9–12 API). The technical process consisted on several steps leading to the success of the campaign, which included: Formation damage study that identified candidate wells and damage mechanisms affecting them.Refining of the petrophysical model from pressure testing to establish incremental production.Adjustment of fracture models using varying anisotropy from special sonic log runs.Using state of the art technologies such as mobility enhancers and Flow back proppant additives as active ingredients of the fracturing fluid. This article presents the outcomes of more than 40 wells intervened to date with an average volumetric increment of ~ 250 BOPD per well, consistent reductions of BSW up to 60% and optimized operations which let the operator consider the hydraulic fracturing as a production optimization option for the field under analysis.

Determining hydrocarbon saturation in Colombian oilfields is particularly challenging for conventional methods since the formation water in most of the tertiary sand targets is extremely fresh, frequently in the 100 ppm to 3,000 ppm NaCl equivalent range. In these conditions, the uncertainty in resistivity and sigma-based saturation interpretation methods is huge. Recent advances in measurement technology and interpretation including the combined use of dielectric dispersion and radial magnetic resonance provide a considerable uncertainty reduction in water saturation and hydrocarbon mobility evaluation. These open-hole measurements have a very shallow depth of investigation (DOI) and provide valuable information from the flushed zone, at one to four inches within the reservoir. A new, advanced nuclear spectroscopy tool conveyed on wireline makes a direct total carbon measurement at a DOI from four to nine inches within the reservoir. When the inorganic mineral carbon is subtracted from the total carbon measurement, the resultant total organic carbon (TOC) can be used to directly compute formation hydrocarbon volume and saturation. Validation is available from the slightly shallower dielectric-derived water filled porosity. These combined measurements provide a saturation profile independent of resistivity and salinity, and allow key reservoir evaluation parameters including hydrocarbon type and oil mobility to be evaluated more accurately. In mature fields, slim carbon-oxygen logging has been the main technique historically for estimating oil saturation behind casing, given its salinity independency. In order to achieve a desirable statistical precision and accuracy, carbon-oxygen data with slim tools requires several logging passes over the zone of interest. A typical acquisition strategy consists of a sigma pass acquired at 1500 ft/h and three or more carbon-oxygen passes acquired around 120 ft/h. In addition to borehole fluid sigma and salinity, these measurements provide information on formation porosity, lithology, matrix properties and oil saturation. The advanced spectroscopy tool was run in the same wells as the slim carbon-oxygen devices. Comparison of measurements from both services indicates that the advanced spectroscopy device is capable of providing lithology, matrix properties and hydrocarbon volume and saturation from TOC with improved accuracy in a single logging run, at a logging speed five time faster that one single carbon oxygen acquisition pass from the slim logging device. The advanced spectroscopy tool also provides improved precision and the measurement of additional elements compared with previous generation tools, allowing for a more accurate computation of mineral components and matrix properties.

This study aims to develop and evaluate fracturing nanofluids from the laboratory to the field trial with the dual purpose of increasing heavy crude oil mobility and reducing formation damage caused by the remaining fracturing fluid (FF). Two fumed silica nanoparticles of different sizes, and alumina nanoparticles were modified on the surface through basic and acidic treatments. The nanoparticles were characterized by transmission electron microscopy, dynamic light scattering, zeta potential and total acidity. The rheological behavior of the linear gel and the heavy crude oil after adding different chemical nature nanoparticles were measured at two concentrations of 100 and 1000 mg/L. Also, the contact angle assessed the alteration of the rock wettability. The nanoparticle with better performance was the raw fumed silica of 7 nm at 1000 mg/L. These were employed to prepare a fracturing nanofluid from a commercial FF. Both fluids were evaluated through their rheological behavior as a function of time at high pressure following the API RP39 test, and spontaneous imbibition tests were carried out to assess the FF’s capacity to modify the wettability of the porous media. It was possible to conclude that the inclusion of 7 nm commercial silica nanoparticles allowed obtaining a reduction of 10 and 20% in the two breakers used in the commercial fracture fluid formulation without altering the rheological properties of the system. Displacement tests were also performed on proppant and rock samples at reservoir conditions of overburden and pore pressures of 3200 and 1200 psi, respectively, while the temperature was set at 77 °C and the flow rate at 0.3 cm3/min. According to the effective oil permeability, a decrease of 31% in the damage was obtained. Based on these results, the fracturing nanofluid was selected and used in the first worldwide field application in a Colombian oil field with a basic sediment and water (BSW%) of 100 and without oil production. After two weeks of the hydraulic fracture operation, crude oil was produced. Finally, one year after this work, crude oil viscosity and BSW% kept showing reductions near 75% and 33%, respectively; and having passed two years, the cumulative incremental oil production is around 120,000 barrels.