TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe use of stimulation treatments based on alcohol to remove liquid blockage or condensate banking in the near well zone date from sixties. Among the proposed mechanisms to explain the enhancement in gas effective permeability and also the higher degree of cleaning and liquid removal obtained in laboratory and field studies, are interfacial tension reduction and the miscibility characteristics reached between the treatment fluids and the formation fluids. This paper presents the results for compatibility and displacement tests carried out among reservoir fluids, alcohol and inhibited diesel based treatments and formation cores from main Cupiagua field. These tests are focused about the behavior of these treatments when they are applied in core flooding tests to reduce liquid saturation and also to increase the gas effective saturation in a porous media. The offered results can be interpreted as a preliminary sight about the use of these treatments on lab scale before applying them as stimulation fluids on a field project.The study consists in assess the alcohol-based and inhibited diesel treatments' efficiency through the gas effective permeability before and after of the treatment injection into a core. The objective was focused to study the use of alcohol and inhibited diesel to remove formation damage by liquid blockage and their application in condensate gas reservoirs.The alcohol-based treatments show consistent results about their effectiveness both on core tests carried on Mirador formation, Cupiagua Main Field -Colombia, and Berea sandstone. In general, the results show up an increase on the gas effective permeability, the lower the core permeability the higher the gas effective permeability enhancement reached after the treatment. The alcohol labeled 21-NE-06 and inhibited diesel treatments increase the gas effective permeability both in Berea and Mirador cores. Both Alcohol 21-NE-06 and inhibited diesel based treatments are effective for removing liquid phases that cause a liquid blockage to gas flow. The stimulation degree is higher in Mirador than in Berea cores. Some treatments did not show any stimulation degree, instead, they generate additional gas effective permeability impairment. Campus Special Petrophysical Analysis integrated by Pablo
Well logs acquired directly in field have turned out to be one of the most key engineering elements to evaluate hydrocarbon formations. Nevertheless, the lack of information, some technical troubles related to the unfolding of tools, the operational states of the well and many other reasons may sharply limit the carrying out of an optimal formation characterization methodology along the entire productive or injective lifespan of a reservoir. Nowadays, artificial neural networks (ANN) are one of the strongest tools to supply such missing information in order to generate synthetic logs.In this paper, we explain the putting into practice of an ANN methodology with the aim of provide useful input information in geomechanical modeling for the hydraulic fracturing simulator GIGAFRAC. More explicitly, the purpose of the schemes presented here is to provide transit-time curves for primary or compressional waves (DtP) and secondary or shear waves (DtS), based on full information measurements of Gamma Ray, Neutron-Porosity, Density, DtP and DtS logs; for some wells in the Cupiagua field located in Colombian Foothills, which break through some geologic formations such as Mirador, Barco, Guadalupe, and Los Cuevos.A noteworthy amount of considerations were taken into account to ensure the success of the ANN estimation phases. A strong focus is done regarding to filtration and quality control of the input information to the network, relating to the control mechanism of outliers, as well as the splitting-up of logs in zones by using a geological criteria and spreading of data information in computationally convenient vectorial and matricial arrangements. Finally, good adjustments were obtained throughout the validation phases and they all were considered as successful outcomes, together with training phase and subsequent use of the same for estimating DtP and DtS curves.
Historically, the geomechanical behavior of a hydrocarbon reservoir has been modeled based on the classical theory of poro-elasticity, which considers absolute reversibility of deformation, which is liable to a porous medium when the mechanical state of the rock is altered. The sands associated with heavy oil formations are generally characterized by low levels of cohesion and density, which is viewed in an increased sensitivity of the rock to permanent deformation and hysteresis; hence it is not suitable to model these formations as if their rheological behavior is elastic. This set the need to construct a model, which describes the permanent plastic deformation that rocks from this kind of reservoir have.The modeling of the stress-strain behavior of plastic porous media aims to evaluate the permanent deformation that the rock suffers and to study the impact of this phenomenon on the behavior of the reservoir permeability porosity and mechanical stability of the layers overlying (compaction, subsidence). Several theoretical research and experimental surveys have defined that most heavy oil reservoirs can be studied as elasto-plastic materials.The purpose of this paper is to show the couple model of constitutive equations (stress-strain model) and fluid flow equations that describe the dynamic behavior of a heavy oil reservoir during an isothermal process, which deforms elasto-plastically, and thereby, to predict several geomechanical phenomena or consequence as productivity drop due to changes in the permeability, pore collapse, cap rock integrity, subsidence, among others, that allow an approach to the behavior of these kind of reservoirs in order to improve production processes and simulation.
Hydraulic fracturing is a well stimulation operation which is done with the purpose to increase the production of oil wells, and due to its associated high costs a preliminary evaluation using computational methods is required. Carrying out a hydraulically fracture in previously fractured wells could represent several benefits if the new fracture propagates towards different direction than the first did, thus the fracture can reach and drainage new regions in the reservoir. The success of these operations depends on the behavior of the horizontal stresses, because they are the ones that determine the orientation and the geometry of the hydraulic fracture, the fluid production and injection that take place within both operations alter the stress state. This paper shows the mathematical analysis developed to model the horizontal stress reorientation and the conditioning of a coupled geomechanics-flow numerical simulator to calculate the angle of reorientation, and the results obtained using the data of two wells located in Cupiagua field, Colombia.
This paper presents a systematic simulation study of a tight-gas, vertically-fractured well aimed to describe the evolution of drainage shape and size with time. The drainage shape is described in terms of the drainage-aspect-ratio, the ratio of the length to width of the specified isopressure line. The drainage size is described in terms of the drainage-area-ratio, the ratio of the area for the specified isopressure line to the well spacing area. The shape and size of a drainage area are determined numerically for a specified isopressure line as functions of dimensionless fracture conductivity (1 FCD 1,000), fracture half-length (94 to 840 ft), permeability level, permeability anisotropy, and time. Knowledge of the evolution of drainage size and shape with time and their long-term behavior are extremely important for planning infill drilling activities, either for choosing new infill well locations or modifying well spacing/pattern. An example is given to show how to estimate drainage shape and size based on the results presented here. Introduction The efficient, rational, and fast development of Tight Gas Reservoirs (TGR) require hydraulic fracturing as an effective stimulation technique for enhancing well productivity, and the application of an infill drilling program to increase the total field production rate. Elliptical shape is known to describe a more realistic flow pattern around a fractured well. Deviation from the usually assumed radial pattern is more drastic for low permeability reservoirs with long fractures. The quantification of the drainage shape has becoming more important as the hydraulic fracturing technology advances and as the well spacing reduces to approach the length scale of the hydraulic fracture. There are only few studies regarding to the drainage shape quantification for hydraulically-fractured tight-gas wells.1–3 Krus et al.2 and England et al.3 presented the results of drainage-aspect-ratio as a function of fracture half-lengths and dimensionless fracture conductivity (FCD). They concluded that for an effective fracture half-length of 1,000 ft or less, the aspect ratio becomes 1.5 and is independent of the dimensionless fracture conductivity. Pertinent information such as well spacing/pattern, permeability level, and time scale, however, were not documented. The objectives of this study are:To investigate the time evolution of drainage shape and size of a vertically-fractured tight-gas well.To investigate the impacts offracture conductivity,fracture length,permeability level, andpermeability anisotropy on the evolution of drainage shape and size.To develop technique to estimate drainage shape and size of a vertically-fractured tight-gas well. Results generated from this study should provide a better understanding and quantification of the drainage shape and size of a vertically-fractured tight-gas well. Simulation Considerations Modeling long and high conductivity vertical fractures in a conventional reservoir simulator presents some practical issues such as instability and long computer time. This is due tothe actual fracture width is generally much smaller than the grid block size, andlarge permeability contrast between the fracture and formation.4 Several methods have been proposed to solve/relieve the above problems. These methods can be classified into:source/sink points,equivalent fracture conductivity,equivalent wellbore radius,numerical well model, andlocal grid refinement. The choice depends on the type/nature of problem at hand, e.g., single-well study, short-/long-term performance analysis, etc. Hegre4 presents an extensive discussion and application of several methods to simulate fractured wells using either conventional or specialized reservoir simulators.
scite is a Brooklyn-based organization that helps researchers better discover and understand research articles through Smart Citations–citations that display the context of the citation and describe whether the article provides supporting or contrasting evidence. scite is used by students and researchers from around the world and is funded in part by the National Science Foundation and the National Institute on Drug Abuse of the National Institutes of Health.
hi@scite.ai
10624 S. Eastern Ave., Ste. A-614
Henderson, NV 89052, USA
Copyright © 2024 scite LLC. All rights reserved.
Made with 💙 for researchers
Part of the Research Solutions Family.