Well killing operation remains an important technological stage before well workover or servicing, during which filtrate penetrates the bottomhole area of the formation. The impact of process fluids and their filtrate on rock has a significant influence on permeability and porosity of carbonate reservoirs, which decrease due to fines migration. There are few known scientific studies of the interaction of killing fluid filtrate with carbonate rock and fines migration. In our experiments, an aqueous phase was used which is the basis for well killing in pure form, for the preparation of blocking agents and is used in reservoir pressure maintenance system. Core samples taken from the pay of the reservoir were used to simulate the well killing process with generation of reservoir thermobaric conditions. Killing fluid filtrate was kept for seven days, which characterizes the average workover time at flowing wells in the fields of the Perm Territory. Using micro-X-ray tomography and scanning electron microscope, images were obtained before and after the experiment, which allowed confirming a decrease in total number of voids due to fines migration and, as a consequence, a decreasing permeability of samples. Measurement of pH and fines concentration in the aqueous phase was performed before and after the experiment and pointed to mineral reactions occurring as a result of rock dissolution. The results of experiments made it possible to record a decrease in permeability of carbonate samples by an average of 50 % due to clogging of void space and migration of fines (clayey and non-clayey).
Transient well tests are a tool for monitoring oil recovery processes. Research technologies implemented in pumping wells provide for a preliminary conversion of measured parameters to bottomhole pressure, which leads to errors in determining the filtration parameters. An adaptive interpretation of the results of well tests performed in pumping wells is proposed. Based on the original method of mathematical processing of a large volume of field data for the geological and geophysical conditions of developed pays in oil field, multidimensional models of well flow rates were constructed including the filtration parameters determined during the interpretation of tests. It is proposed to consider the maximum convergence of the flow rate calculated using a multidimensional model and the value obtained during well testing as a sign of reliability of the filtration parameter. It is proposed to use the analysis of the developed multidimensional models to assess the filtration conditions and determine the individual characteristics of oil flow to wells within the pays. For the Bashkirian-Serpukhovian and the Tournaisian-Famennian carbonate deposits, the influence of bottomhole pressure on the well flow rates has been established, which confirms the well-known assumption about possible deformations of carbonate reservoirs in the bottomhole areas and is a sign of physicality of the developed multidimensional models. The advantage of the proposed approach is a possibility of using it to adapt the results of any research technology and interpretation method.
Hydraulic fracturing is an effective way to stimulate oil production, which is currently widely used in various conditions, including complex carbonate reservoirs. In the conditions of the considered field, hydraulic fracturing leads to a significant differentiation of technological efficiency indicators, which makes it expedient to study in detail the crack formation patterns. For all affected wells, the assessment of the resulting fractures spatial orientation was performed using the developed indirect technique, the reliability of which was confirmed by geophysical methods. In the course of the analysis, it was found that in all cases the fracture is oriented in the direction of the development system element area, which is characterized by the maximum reservoir pressure. At the same time, reservoir pressure values for all wells were determined at one point in time (at the beginning of hydraulic fracturing) using machine learning methods. The reliability of the used machine learning methods is confirmed by high convergence with the actual (historical) reservoir pressures obtained during hydrodynamic studies of wells. The obtained conclusion about the influence of the formation pressure on the patterns of fracturing should be taken into account when planning hydraulic fracturing in the considered conditions.
Determining formation pressure in the well extraction zones is a key task in monitoring the development of hydrocarbon fields. Direct measurements of formation pressure require prolonged well shutdowns, resulting in underproduction and the possibility of technical problems with the subsequent start-up of wells. The impossibility of simultaneous shutdown of all wells of the pool makes it difficult to assess the real energy state of the deposit. This article presents research aimed at developing an indirect method for determining the formation pressure without shutting down the wells for investigation, which enables to determine its value at any time. As a mathematical basis, two artificial intelligence methods are used – multidimensional regression analysis and a neural network. The technique based on the construction of multiple regression equations shows sufficient performance, but high sensitivity to the input data. This technique enables to study the process of formation pressure establishment during different periods of deposit development. Its application is expedient in case of regular actual determinations of indicators used as input data. The technique based on the artificial neural network enables to reliably determine formation pressure even with a minimal set of input data and is implemented as a specially designed software product. The relevant task of continuing the research is to evaluate promising prognostic features of artificial intelligence methods for assessing the energy state of deposits in hydrocarbon extraction zones.
The article studies the formation features of the bottomhole zones in productive formations during operation of production wells in the north of the Perm Territory. Their distinctive feature is the high gas saturation of formation oil. The most widely used parameter in Russian and world practice – the skin factor was used as a criterion characterizing the state of the bottomhole zone. Analysis of scientific publications has shown that one of the main problems of applying the skin factor to assess the state of bottomhole zones is the ambiguity of interpretations of its physical meaning and the impossibility of identifying the prevailing factors that form its value. The paper proposes an approach to identifying such factors in the conditions of the fields under consideration, based on multivariate correlation-regression analysis. Choice of this tool is due to the complexity of the processes occurring in the “formation – bottomhole zone – well” system. When describing complex multifactorial processes, the chosen method demonstrates a high degree of reliability. For a large number of wells in the region, significant material was collected and summarized, including the results of determining the skin factor (1102 values) during hydrodynamic investigations, as well as data on the values of various geological and technological indicators, which can probably be statistically related to the value of the skin factor. A series of multidimensional mathematical models has been built; the skin factor was used as a predicted parameter, and data on the values of geological and technological indicators were used as independent indicators. Analysis of the constructed models is a key stage of this study. Set of parameters included in the multidimensional models, sequence of their inclusion and contribution to the total value of the achieved determination coefficient as the main indicator for the performance of the constructed models were studied. It has been established that the main factor influencing the state of the bottomhole zone is oil degassing. Significant differences in the formation features of the skin factor in the terrigenous and carbonate sediments at the fields under consideration have been determined.
Significant share of the developed oil assets related to carbonate complex-built objects has formidably increased in Russia, including the Perm Region. Reliable knowledge of the parameters for the cavern-pore type of the reservoir allows clarifying the existing geological and hydrodynamic models (GHM), selecting a rational development system, regulating the development processes and providing optimal geological and technical measures for this formation. In the construction and adaptation of GHM for oil fields, especially those related to complex-built carbonate reservoirs, knowledge of both horizontal and vertical permeability (anisotropy parameter) is important. When creating GHM of carbonate objects in Perm Region deposits, vertical permeability is often taken to be zero, although this is far from being the case. Determining the vertical permeability (anisotropy parameter), its dynamics when changing the formation and bottomhole pressures and using it in GHM is an urgent task that will improve the quality and reliability of using digital models to calculate and predict the oil production process. Article describes the methodology for determining permeability anisotropy according to the interpretation of hydrodynamic investigations of wells. Proposed methodology for determining the anisotropy parameter processed the results of more than 200 studies conducted on production and injection wells of the Famennian deposit at the Gagarinskoye field. For each lithological-facies zone, dependence of the permeability anisotropy index on the bottomhole pressure is constructed. To predict and evaluate the effectiveness of the applied geological and technical measures and technological development indicators, author modified the geological and hydrodynamic model taking into account the obtained dependencies on the change in the anisotropy parameter. Using a modified hydrodynamic model, it was possible to significantly improve the adaptation of both production and injection wells. Thus, the quality and reliability of the digital model of the Famennian deposit at the Gagarinskoye field for calculating and predicting the oil production process has improved.
