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.
Sand production in oil and gas wells is a complex problem that requires a multidisciplinary analysis to arrive at an optimal solution of the problem and thus increases the productivity of oil fields with problems of production of sand. Many operators choose as first alternative, the exclusion of sand, avoiding doing a risk management, which ultimately provides lower index of productivity and in many cases convert the wells with sand problems in unproductive wells. Therefore always be a better option the sand management and take as a last option the sand exclusion, obviously framed within a technical and economic evaluation of alternatives. In most cases when we refer to a chemical treatment for sand control, it tends to confuse with chemical consolidation treatments, however a different option, is the application of chemical treatments to modify the zeta potential of the formation fines that has been very successful. Modifying The zeta potential to optimum range, provides a strengthened attraction between the particles to optimally align proppant type, sand particles, fines, etc., allowing the formation of conglomerates of proppant, sand, fines, etc., improving conductivity and control of fines migration. This study focused on the evaluation in the laboratory of chemical treatment (compatibility, zeta potential and rock-fluid testing, etc.), mineralogical and granulometric analysis of sand and fines produced by wells with sanding problems, selection of wells and treatment zones, quantification of costs associated with sanding problems, technical and economic evaluation of the application of treatments in candidate wells, etc. This paper presents the results of the laboratory evaluation of chemical treatment (satisfactory results in compatibility and modification of the zeta potential, permeability returns of over 80%, etc.) and implementation in the well Bonanza 39, located in the Basin of the Middle Magdalena Valley in Colombia, where dropped dramatically the frequency of interventions by sanding problems. Before chemical treatment, the well had a monthly intervention and after nine months of the treatment, has not required intervention, allowing increase productivity of the well. Finally, the main findings, conclusions and recommendations obtained in this study are shown.
Formation damage could potentially impede production and injection operations. Hence, characterization and discretization processes of formation damage should be connected to quantification and disaggregation techniques, relying on characterization fundamentals that consider chemical and physical changes in the fluid and rock system through the field productive life. This document presents a review of different disaggregation, quantification and discretization methods for the formation damage estimation in oil and gas fields. This review is mainly divided into three main sections, namely: i) Formation damage diagnosis, ii) Formation damage quantification, and iii) Formationdamage disaggregation. This document will aid in the alignment of the academic and industrial sectors to incentivize the prevention and inhibition of formation damage, as well as the optimal design of remediation mechanisms.
A special engineering methodology was developed to understand the complexity of formation damage mechanism currently affecting the well productivity of the oil fields being operated by SOP (Superintendencia de Operaciones Putumayo) Ecopetrol. The initial stage of this study involved the characterization and analysis of reservoir fluids samples taken along the time during different exploitation stages. The analyzed data was processed through specialized software to identify formation damage associated with both organic and mineral scales. Simultaneously a second stage was developed to determine and quantify the influence of production parameters on both fines migration and water production. The data obtained during the previous stages were properly combined to generate a comprehensive formation damage model. Nodal system analysis, material balance, reservoir fluids characterization, and mineral/organic scale models and correlations were finally combined to identify and quantify the main formation damage mechanisms taking place in SOP′s fields. Once the main formation damage mechanisms were identified and quantified then an extensive lab job was performed. This lab study determined the Best In Class (BIC) fluids required to dissolve and mitigate the formation damage. The combination of formation damage model with lab data allowed designing an optimized treatment schedule by each well producing in SOP fields. Finally, an economical study was involved in the study in order to help in well prioritization to start the stimulation and inhibition campaign for SOP field. A 3D simulation of certain formation damage mechanism was included as the final stage in this study. It was very important, especially when optimizing the stimulation-inhibition designs in those wells in which local grid refinement is required to better understanding of certain critical formation damage parameters. The final list of well prioritization was optimized and stimulation-inhibition campaign for SOP fields was finally outlined to be started during the second semester of 2011.
This work aims to develop a fracturing nanofluid with a dual purpose: i) to increase heavy crude oil mobility and ii) to reduce formation damage caused by the remaining fluid. Three commercial nanoparticles were evaluated: two fumed silica of different sizes and one type of alumina. They were acidified and basified, obtaining nine nanoparticles (NPs) by the surface modification, characterized by TEM, DLS, Z Potential and Total Acidity. The effect of adding nanoparticles at different concentrations onto the linear gel and heavy crude oil was determined by their rheological behavior. Also, there was assessed the alteration of the rock wettability by contact angle for all NPs and concentrations. Based on these results, the nanoparticle with better performance was the neutral fumed silica of 7 nm at 1000 mg/L. These were used to make a fracturing nanofluid from a commercial fracturing fluid (FF). Both of them were evaluated through their rheological behavior overtime at high pressure following the API RP39 test and quantitative measurements of the rock sample wettability changes. Displacement tests also were performed on proppant and rock samples at reservoir conditions: pressure and temperature. Finally, there was evaluated the rheological behavior of the crude oil recovered in the displacement test. It was possible to conclude that the inclusion of nanoparticles allowed obtaining a reduction of 10 and 20% in the two breakers used in the commercial fracture fluid formulation. An alteration of the rock wettability was achieved, where the rock sample became up to 50% more wettable to water. Moreover, there was a diminution of 53% in the damage caused by the remaining fracturing fluid to the oil effective permeability in the proppant medium. In the rock sample, a decrease of 31% of this kind of damage was observed. Increases of 28 and 18 % in the crude oil recovery were noticed in the proppant and the rock sample, respectively. Finally, there was a reduction of 40% in the crude oil viscosity, showing the effectiveness of adding nanoparticles to fracturing fluids for increasing oil mobility and reducing the formation damage.
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