Production Characteristics Of Wells Research Articles

STUDYING WAYS TO INCREASE THE RELIABILITY OF CRM-APPROACHES IN THE ANALYSIS OF THE HISTORY OF THE WELLS OF SYSTEMS BY INVOLVING ADDITIONAL INFORMATION

Due to the large number of production and injection wells in the field, it is a difficult task to take into account the interconnection and mutual influence of all wells with each other. In this regard, it is advisable to use a proxy reservoir model, which allows to quickly calculate the main development indicators.These algorithms make it possible to predict the production characteristics of wells over the next years, as well as to optimally redistribute the volume of injected fluid between injection wells with minimal costs and high payback. The article calculated 8 cases in which the parameters of well operation control, well commissioning times, the nature of well operation and the change in production well modes on the forecast changed.

Increasing the filtration characteristics of rocks in areas of high temperatures

One of the important problems of the oil and gas industry is the decrease in the production characteristics of wells in fields that are at the final stage of development. In addition, the drop in well production below their potential and the decrease in hydrocarbon recovery factors are often due to the deterioration of the reservoir properties of rocks in the process of drilling in productive formations, well workover, as well as the imperfection of production processes and means of their implementation. The object of research is the technology of treatment of the bottomhole formation zone with non-acidic systems based on ammonium salts for the intensification of hydrocarbon production. The paper considers a number of methods that allow solving the above problems, taking into account their complexity, efficiency and duration of the positive effect of processing. The main acid methods of influencing the bottomhole formation zone and their modifications are analyzed. The authors, using the results of the research and experience gained, proposed a non-acidic system of chemical treatment of oil and gas wells based on ammonium salts. Their influence on the rocks occurs more long-term and does not lead to the destruction of reservoirs. During the research, physical, chemical, physicochemical methods and techniques developed by the authors for processing and analyzing field data, statistical methods for processing experimental studies were used. Modeling of deep processes was carried out on the installation developed and created by the authors. The mechanism of interaction of ammonium salt solutions with terrigenous and carbonate rocks is revealed. Experimental studies have confirmed and theoretically substantiated the effectiveness of the use of ammonium salts to improve the filtration characteristics of reservoirs. The effect of ammonium salt solutions on the change in the permeability of sandy and carbonate reservoirs in the Dnipro-Donetsk depression (DDD, Ukraine) has been studied. And also a mathematical model of the process of increasing the permeability of rocks during their dissolution by the studied chemical reagents was created. The mathematical model is available for its wide application in the practice of technological calculations and designing measures for the stimulation of oil and gas production.

Analysis of Production Data From Hydraulically Fractured Horizontal Wells

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 110848, "Analysis of Production Data From Hydraulically Fractured Horizontal Wells in Tight, Heterogeneous Formations," by F. Medeiros, SPE, Petrobras, and B. Kurtoglu, SPE, E. Ozkan, SPE, and H. Kazemi, SPE, Colorado School of Mines, prepared for the 2007 SPE Annual Technical Conference and Exhibition, Anaheim, California, 11–14 November. The paper has not been peer reviewed. The full-length paper discusses the analysis of production data from hydraulically fractured horizontal wells in tight, heterogeneous formations. Horizontal wells with longitudinal and transverse hydraulic fractures that might be surrounded by a region with natural fractures are considered. These well/reservoir configurations are of interest in many unconventional reservoirs, including tight gas sands and shale-oil or -gas formations. A semi-analytical model that incorporates the key features of reservoir heterogeneity and the details of hydraulic-fracture and wellbore flow was used to compute production decline. Introduction In the last decade, interest in developing unconventional oil and gas reservoirs has grown. Most of these unconventional reservoirs have very low permeability, as in the case of tight gas sands and fractured shale formations. Production economics for these reservoirs normally requires large reservoir contact per well. An efficient means of increasing reservoir contact to achieve higher well productivity is to drill horizontal wells and stimulate with hydraulic fractures. Productivity might be improved further if the horizontal well and hydraulic fractures are connected to an active natural-fracture network. This fracture network may be pre-existing in a naturally fractured reservoir (dual-porosity system) or may be generated or reactivated locally by hydraulic fracturing around the well. Production characteristics of wells in globally and locally fractured reservoirs may differ significantly, depending on the contrast between the matrix and natural-fracture properties. The full-length paper discusses the analysis of production data from hydraulically fractured horizontal wells in reservoirs with a global- or localized-natural-fracture network. It explains the characteristics of production decline associated with various transient-flow regimes, describes the procedure to generate production-decline curves, and demonstrates matching field data with the model. The general idea of this work follows from a production-decline-analysis concept. A transient productivity index (PI), J, is used in the analysis of production data for horizontal wells. Material-balance time is incorporated into the analysis to generalize the analysis procedure for all phases and modes of production. There are two important aspects of the approach presented in the full-length paper. The first aspect is the use of a semianalytical model that incorporates the important features of reservoir heterogeneity and hydraulic fractures without elaborate numerical computations. The model was built on the basis of a semianalytical simulation approach. Having a computationally efficient model is important in that the production-decline model needs to be used in an iterative manner in the analysis of the field production data. Moreover, especially in the early development stage, there are not enough data to sufficiently characterize heterogeneous, unconventional reservoirs. Therefore, more-detailed numerical modeling may not be a viable option until more data become available later in the development of the field.

Study on the flow production characteristics of deep geothermal wells

This paper describes a study on the potential flow production characteristics of three non-producing, deep (average depth 4000 m) geothermal wells in the Cerro Prieto geothermal field. The expected production characteristics of these wells were computed in order to determine whether their inability to sustain flow was due to: (1) heat loss effects in the well; (2) the influence of casing diameters; (3) transient temperature effects during the first days of well discharge, and/or (4) the effects of secondary low-enthalpy inflows. For the study, the conservation equations of mass, momentum and energy for two-phase homogeneous flow were solved for the wellbore, since homogeneous flow provides the simplest technique for analyzing two-phase flows when the flow patterns are not well established. The formation temperature distribution was computed assuming radial transient heat conduction. The numerical model was validated by comparison with analytical solutions and with measured pressure and temperature profiles of well H-17 from the Los Humeros geothermal field, Mexico. It was found that the wells should have sustained production. The early heat losses were so large that the flow needed to be induced, and flow will be sustained only after a few days of induced discharge. For well M-202, the analysis suggests that the inflow of secondary colder fluids was responsible for stopping the flow in this well.

Fully Coupled Analysis of Well Responses in Stress-Sensitive Reservoirs

Summary A fully coupled geomechanics and single-phase, fluid-flow model is developed to evaluate the combined effects of stress, fluid flow, and reservoir property changes on well responses in stresssensitive reservoirs. In particular, we pay attention to the interpretation of pressure buildup tests and to changes in the production characteristics of wells. In general, for weak hydrocarbon reservoirs that exhibit nonlinear, elastic and plastic constitutive behaviors, and stress-dependent properties such as permeability and porosity, the physical effect contributed from geomechanics may not be ignored in well test analysis. The coupled interaction between geomechanics and reservoir fluid production markedly affects the stress state and reservoir properties. Because we are using a coupled, numerical model, we evaluate the consequences of using simplified relationships (e.g., permeability as a function of pressure). Numerical analyses are performed to quantitatively assess the impact of reservoir stress sensitivity on practical well test problems. The key variables investigated in the study, that are important in evaluating stress-sensitive reservoirs, include permeability, porosity, and constitutive behaviors of reservoir rock including hysteresis and loading conditions. The development of high-stress regions around wellbores and its consequences on well performance are considered. The numerical results from the study indicate that for analyzing highly stress-sensitive reservoirs, a fully coupled geomechanics and fluid-flow modeling approach is necessary and the developed model employed in this study provides such a tool.

Effect of Rock Stress on Gas Production From Low-Permeability Reservoirs

The effect of stress on permeability has been incorporated into a mathematical model for gas flow based on a theoretical analysis of the stress state around a wellbore. Example calculations show that permeability reduction due to stress can significantly affect the permeability reduction due to stress can significantly affect the production characteristics of wells in tight gas reservoirs. production characteristics of wells in tight gas reservoirs. Introduction The decline in gas reserves has stimulated widespread interest in gas-bearing formations previously considered to be uneconomic because of extremely low permeability. Routine core analyses have indicated permeabilities in many such reservoirs on the order of 0.1 md and lower. Wells in such reservoirs have been proposed as candidates for nuclear or high-explosives stimulation to increase production rates. production rates. In investigating the flow behavior of wells in tight gas reservoirs, it has been observed that measured flow rates are sometimes much lower than predicted by transient gas flow equations based on Darcy's law. Several plausible explanations for this discrepancy have been offered. Errors may be caused by deviation from the usual simplifying assumptions such as reservoir homogeneity, open-hole completions, and single-phase flow. Non-Darcy effects due to high gas velocity near the wellbore may restrict flow. Liquid from retrograde condensation or formation of gas hydrates can reduce permeability; however, the ranges of the temperature, pressure, and gas composition necessary for this to occur are usually not encountered in low-permeability gas reservoirs. This paper discusses a mechanism that may have a significant effect on production from tight gas reservoirs - reduction of permeability due to rock stress. Lowering of pore pressure as gas is produced increases the confining stresses on the reservoir rock, causing it to compact. The compaction causes reduction of the effective pore diameters, resulting in a decreased permeability. This effect has been studied by several permeability. This effect has been studied by several authors. These studies covered both clean and shaly sandstones. Confining pressures were applied hydrostatically and with different pressure applied to the sides of the core than to the ends. Only one set of data was reported for a core of less than 0.1 md permeability. The effect of stress on this core with permeability. The effect of stress on this core with very low permeability was much greater than the effect on the others. A possible explanation for this is that very tight cores have smaller pore radii. Increasing the compressive stress applied to pores of small radius could decrease their flow capacity proportionately more than that of larger pores. proportionately more than that of larger pores. This study was conducted to confirm the conclusions of previous work, and to demonstrate experimentally that permeability reduction is proportionately greater in low-permeability than in proportionately greater in low-permeability than in high-permeability cores; to incorporate the stress effect into a mathematical model for reservoir gas flow; and to use this model to check the extent of production decrease that might be expected because of production decrease that might be expected because of permeability's sensitivity to stress. permeability's sensitivity to stress. Laboratory Measurements of Stress Effect on Permeability A schematic diagram of the experimental apparatus is shown in Fig. 1. Basically it consisted of a cell for applying pressure to cylindrical cores, a nitrogen source for permeability measurement, pressure gauges, and a flow meter. The core samples were 2 in. long and 2 in. in diameter. P. 1161