Decrease In Reservoir Pressure Research Articles

An investigation of the effect of drawdown pressure on sand production in an Iranian oilfield using a hybrid numerical modeling approach

AbstractReservoir pressure reduction due to continuous production from oil and gas wells affects the sand production rate. An increase in drawdown pressure and/or a decrease in reservoir pressure increases the sand production rate. Since the problem of sand production is one of the main issues in the Asmari sandstone formation located in one of the oilfields in the southwest of Iran, therefore, in this research, the variations in the sand production rate due to the changes in the reservoir and drawdown pressures were investigated. So, for the first time, a hybrid numerical model of finite difference method (FDM)—discrete element method (DEM)—finite element method (FEM)—computational fluid dynamics (CFD) was developed. This numerical model investigated the increase in the sand production rate due to variations in reservoir pressure with a constant bottom-hole flowing pressure. Then, by performing an extensive sensitivity analysis on different values of reservoir pressure and drawdown pressure, the changes in the sanding rate, the critical drawdown pressure, and the safe drawdown line were determined. The results showed that, if the production flow rate of the well is constant, increasing the drawdown pressure can change the sand production rate only to a certain extent, and more than that, will be produced at a constant rate. Also, adjusting the drawdown pressure within a safe range does not necessarily keep the sand production rate constant at a permissible value for a long time, while by keeping the bottom hole flowing pressure constant within an acceptable range, the sand production rate can be controlled for a longer period.

Multi-stage hydraulic fracturing simulation methodology at the wells of the gas condensate field X

The purpose of this work is to select the optimal method for multi-stage hydraulic fracturing simulation at the wells of a large gas condensate field X in conditions of low-permeability reservoirs and potential risk of condensate loss in the near bottomhole zone with a decrease in reservoir pressure. At the moment, there are many ways to simulate hydraulic fracturing, each of which is characterized by its advantages and disadvantages. For specific simulation conditions, it is necessary to choose the most optimal method of hydraulic fracturing simulation, which allows you to correctly simulate all the effects that are expected during development. Within the framework of the current work, the most common numerical methods of hydraulic fracturing simulation were described in abstract, their advantages and disadvantages for specific conditions of field X were reflected. Special attention was paid to the comparison of hydraulic fracturing simulation techniques using virtual perforations and local grid refinement, since these techniques are the most common ways to set hydraulic fracturing in existing hydrodynamic simulators. Scenario calculations were carried out, which made it possible to determine the limits of applicability of various methods, compare the correctness of reproducing downhole effects, quantify the deviation of the calculation results of different methods from the reference calculation. In addition, in the course of the work, various features of the application of the hydraulic fracturing simulation through local grid refinement were described, which were revealed experimentally. As a result, for multi-stage hydraulic fracturing simulation was used a method in which the cells with hydraulic fracturing are logarithmically chopped relative to the original grid. This method allows to simulate the actual rate of decline in well productivity in conditions of low reservoir permeability, and also allows to simulate in the hydrodynamic model the effect of condensate precipitation in the near bottomhole zone and the subsequent decrease in gas productivity.

Application of the results of three-dimensional hydro-geomechanical modeling to determine the azimuths of hydraulic fractures

The article is devoted to the problem of determining the spatial orientation of the hydraulic fracture for hydrodynamic modeling. As a rule, the choice of the fracture strike azimuth is based on data obtained from the interpretation results of cross-dipole acoustic logging recorded for monitoring the fracturing operation. Due to changes in reservoir pressure, the expected and actual directions of the created fracture may differ, which must be taken into account when adapting and predicting the field development indices on the hydrodynamic model. The purpose of the paper is to calculate the influence of reservoir pressure on the fracture azimuth and, accordingly, on the field development indicators by constructing a combined hydro-geomechanical model that can later be used to select the optimal strategy for producing reserves. The reservoirs stressed state change, caused by the increase or decrease in reservoir pressure, is considered by the case of an oil reservoir located in the Orenburg region. Constructed geomechanical model of the selected sector includes the cubes of reservoir stresses at the initial date, the mechanical properties of the rock and faults in the productive formation. The dependence of the values of the angle on the formation pressure is constructed and the prediction calculations are carried out on the hydrodynamic model. The validity of the direction calculation is assessed by comparison with actual microimager data. As a result of work for the selected sector of the field, a hydro-geomechanical model is constructed, which makes it possible to obtain a forecast for the development of the hydraulic fracturing during the reservoir development.

EXPERIENCE OF USING ACID TREATMENTS IN THE OIL FIELD SUWAYDIYA (SYRIA)

Link for citation: Mohammad Almohammad Alnayef, Zain Alabidin Dalfi Abd Ali Khalaf, Gnidan E.V. Experience of using acid treatments in the oil field Suwaydiya (Syria). Bulletin of the Tomsk Polytechnic University. Geo Аssets Engineering, 2023, vol. 334, no. 7, рр. 50-58. In Rus. Relevance of the research is caused by the need to increase oil recovery from wells developed in the fields of Syria, in the carbonate reservoirs of the Massif and Shiranish formation, for which there is a natural drop in production rates due to decrease in reservoir pressure, water cut, opening of reservoirs with low reservoir properties and increase in the share of hard-to-recover reserves. The main aim of the study is to analyze the results of acid treatments to improve oil recovery in the field of Suwaydia, Syria. The object of study is the carbonate complexes in the Upper Cretaceous deposits of the Massif formation and the Shiranish formation, Syria. Methods: review of domestic and foreign experience in treating the bottomhole formation zone using acid compositions and analysis of production, technological, lithological, geological, geophysical, and field data of wells treated with acids. Results. The paper introduces the advantages of the acid treatments method, such as improving the reservoir permeability and decreasing the skin factor by increasing the pore space and fracture channels, as well as removing the filter cake and various inorganic sediments that prevent oil flow. The undesirable effects of acid treatments: corrosion, secondary sedimentation, water cut, are indicated. The geological and physical conditions of the well and reservoir for choosing a treatment technology are considered. They are: reservoir temperature, filtration, and reservoir properties of rocks, granulometric (fractional) and mineralogical composition of rocks, chemical composition of reservoir fluids. The main directions of measures for solving geological and technological complications that arise during acid treatments using inhibitors, new multicomponent compositions of acid agents, special additives, and multi-stage treatments are noted. The paper introduces the technology and results of the application of acid treatments: hydrochloric acid treatment and foam hydrochloric acid treatment of the bottomhole zone of wells located in the north-east of the Syrian Arab Republic, which belong to the two oil field – Suwaydia and Zarba – of the Al-Hasakah Oil Fields Administration. It was noted that the use of a simple hydrochloric acid treatment of several wells did not lead to the predicted increase in oil recovery, and the use of an acid mixture (HCL at a concentration of 15 %, HF at a concentration of 3 %) in well no. 462 of the Suwaydia oil field showed an increase in productivity of 1,5 times. Recommendations are given for improving acid treatments at the Suwaydia, Syria fields to intensify oil production.

Pore-scale characterization of residual gas remobilization in CO2 geological storage

A decrease in reservoir pressure can lead to remobilization of residually trapped CO2. In this study, the pore-scale processes related to trapped CO2 remobilization under pressure depletion were investigated with the use of high-resolution 3D X-ray microtomography. The distribution of CO2 in the pore space of Bentheimer sandstone was measured after waterflooding at a fluid pressure of 10 MPa, and then at pressures of 8, 6 and 5 MPa. At each stage CO2 was produced, implying that swelling of the gas phase and exsolution allowed the gas to reconnect and flow. After production, the gas reached a new position of equilibrium where it may be trapped again. At the end of the experiment, we imaged the sample again after 30 hours. Firstly, the results showed that an increase in saturation beyond the residual value was required to remobilize the gas, which is consistent with earlier field-scale results. Additionally, Ostwald ripening and continuing exsolution lead to a significant change in fluid saturation: transport of dissolved gas in the aqueous phase to equilibriate capillary pressure led to reconnection of the gas and its flow upwards under gravity. The implications for CO2 storage are discussed: an increase in saturation beyond the residual value is required to mobilize the gas, but Ostwald ripening can allow local reconnection of hitherto trapped gas, thus enhancing migration and may reduce the amount of CO2 that can be capillary trapped in storage operations.

Liquid Loading of Horizontal Gas Wells in Changbei Gas Field

The Changbei gas field, which initially exhibited high gas-production performance, is dominated by large-displacement horizontal wells. With the decrease in reservoir pressure, the liquid loading in the gas well is currently severe, and production has been rapidly decreasing. Thus, recognizing the gas-well liquid loading to maintain stable gas-well production is necessary. A method was established to identify the water source of the liquid loading in the Changbei gas field. First, formation water and condensate water were identified based on the mineralization of the recovered water and the mass concentration of Cl− and K+ + Na+, and then the condensate content of the water produced in the gas well was qualitatively evaluated. The water–gas ratio curve for the gas well was plotted to determine whether the produced water was edge-bottom water, pore water, or condensate. Then a method was established to distinguish the start time of liquid loading in the gas well using a curve depicting a decrease in production; the method was also used to estimate the depth of the gas well where liquid loading occurs, according to the bottomhole pressure. First, based on the available production data, the Arps decline model was applied to fit the production curve for the entire production phase; the resulting curve was compared with the actual production curve of the gas well, and the two curves diverged when fluid accumulation began in the gas well. Finally, the liquid-loading depth of the gas well was estimated based on the bottomhole pressure. This method can be used to determine the fluid accumulation and calculate the liquid-loading depth of gas wells with unconnected oil jackets. The analysis revealed that in the Changbei gas field, condensate was the type of water primarily produced in 35 gas wells, accounting for 62.5% of the total number of gas wells. Edge-bottom water was the type of water primarily produced in 16 gas wells, accounting for 28.6% of the total number of gas wells. In the remainder of the gas wells, pore water was the water primarily produced; the calculations of accumulation time and accumulation volume of typical gas wells in the block revealed that some gas wells started to accumulate liquid after 45–50 months, and the amount of accumulation could reach several tens of meters, while others were in good production condition. The method established in this paper could enhance our understanding of liquid loading in gas wells in the Changbei gas field and lay a foundation for the development of gas-well deliquification techniques.

Experimental and Numerical Assessment of the Influence of Bottomhole Pressure Drawdown on Terrigenous Reservoir Permeability and Well Productivity

During oil and gas fields development, a decrease in reservoir and bottomhole pressure has often a detrimental effect on reservoir properties, especially permeability. This study presents the results of laboratory tests conducted to determine the response of terrigenous reservoir core-sample permeability to changes in the effective stresses and a decrease in the reservoir pressure. The considered samples were exposed for a long time to a constant high effective stress for a more reliable assessment of the viscoplastic deformations. According to these experiments, the decrease of the core samples permeability may reach 21% with a decrease in pressure by 9.5 MPa from the initial reservoir conditions. Numerical simulations have been also conducted. These have been based on the finite element modeling of the near-wellbore zone of the terrigenous reservoir using poroelasticity relations. The simulation results show a limited decrease in reservoir permeability in the near-wellbore zone (by 17%, which can lead to a decrease in the well productivity by 13%).

About rationale for the selection of the cooling capacity of the turbodetander unit in the process of gas preparation

In gas condensate fields, low-temperature separation process is mainly used for primary processing of gas. Cooling of well products in gas preparation systems is achieved by throttling them. As the reservoir pressure decrease, the amount of energy obtained decreases. This worsens the conditions for the preparation of gases. Therefore, raises a need to use additional energy sources. Analysis of the operating modes of gas treatment plants has shown that the energy obtained during the expansion of gas can be used rationally. Calculations have shown that the gas temperature at the outlet of turbodetander units during adiabatic expansion provides the required dew point for water and hydrocarbons. Keywords: gas; condensate; turbodetander; gas expansion; polytrophic; adiabatic; cold productivity; dew point.

Development of technological solutions for reliable killing of wells by temporarily blocking a productive formation under ALRP conditions (on the example of the Cenomanian gas deposits)

Modern field operation conditions are characterized by a decline in gas production due to the depletion of its reserves, a decrease in reservoir pressure, an increase in water cut, as well as due to the depreciation of the operating well stock. These problems are especially specific at the late stage of development of the Cenomanian deposits of Western Siberia fields, where the anomaly factor below 0.2 prevails, while gas-bearing formations are represented mainly by complex reservoirs with high-permeability areas. When killing such wells, the classical reduction of overbalance by reducing the density of the process fluid does not provide the necessary efficiency, which requires the search for new technical and technological solutions. In order to prevent the destruction of the reservoir and preserve its reservoir properties during repair work in wells with abnormally low reservoir pressure, AO “SevKavNIPIgaz” developed compositions of special process fluids. A quantitative description of the process of blocking the bottomhole formation zone is proposed by means of mathematical modeling of injection of a gel-forming solution into a productive horizon. The well killing technology includes three main stages of work: leveling the injectivity profile of the productive strata using three-phase foam, pumping the blocking composition and its displacement with the creation of a calculated repression. Solutions obtained on the basis of a mathematical model allow optimizing technological parameters to minimize negative consequences in the well killing process.

The influence of technogenic geodynamic processes during oil and gas field development on the reliability of wells (generalization)

An overview of the influence of geodynamic processes occurring as a result of a decrease in reservoir pressure in the fields under development on the state of wells, the tightness of their casing strings and column spaces is given. The sequence of measures necessary to take into account these processes in the design of the development of oil and gas fields and the construction of wells is shown.

Velocity String Drainage Technology for Horizontal Gas Wells in Changbei

The Changbei gas field is dominated by wells with large horizontal displacement, which have exhibited high gas production performance at an early stage of development. With the decrease in reservoir pressure, the liquid loading in the gas well is relatively high and gas production rapidly decreases. Therefore, suitable drainage measures are required to maintain stable gas production. Based on the characteristics of the unconnected oil jacket of gas wells in Changbei, a velocity string was used for drainage. A critical liquid-carrying model was established to determine the location of liquid loading in horizontal gas wells in Changbei. First, the coefficients of the liquid-carrying model were determined through theoretical analysis of the characteristics of the gas well formation. Then, the depth setting of the velocity string was analyzed. The critical liquid-carrying model was employed to calculate the liquid-carrying flow rate of each section; the calculated flow rates were compared with the actual flow rates to determine whether fluid accumulation occurred in each section of the gas well. Thereafter, with the help of the oil and casing position, the suitable setting position of the velocity string was determined. The formation fluid was driven from the tubing into the casing owing to the increase in the overflow area, based on the principle of reducer fluid mechanics. The fluid velocity in the larger overflow cross-section decreased, thereby reducing the drainage capacity of the gas well and resulting in liquid loading. Finally, a timing analysis was performed. After the formation pressure decreased, the well production and flow rate changes were analyzed by placing two velocity strings of different sizes at different wellhead pressures in the gas well with fluid accumulation. The results indicated that although the velocity string was set at a position suitable for fluid drainage, fluid accumulation still occurred after a production period, thus necessitating replacement deliquification.

Investigation of the influences of asphaltene deposition on oilfield development using reservoir simulation

This paper investigates the deposition of asphaltenes in the porous medium of the studied field in Russia and predicts production profiles based on uncertainty evaluation. This problem can be solved by dynamic modeling, during which production profiles are estimated in two scenarios: with and without the activation of the asphaltene option. Calculations are carried out for two development scenarios: field operation under natural depletion and water injection into the aquifer as a reservoir pressure maintenance system. A full-scale compositional reservoir simulation model of the Russian oilfield was created. Within a dynamic simulation, the asphaltene option was activated and the asphaltene behavior in oil and porous medium was tuned according to our own special laboratory experiments. The model was also matched to production historical data, and a pattern model was prepared using the full-scale simulation model. Technological and the asphaltene option parameters were used in sensitivity and an uncertainty evaluation. Furthermore, probable production profiles within a forecast period were estimated. The sensitivity analysis of the pattern model to input parameters of the asphaltene option allowed determining the following heavy-hitters on the objective function: the molar weight of dissolved asphaltenes as a function of pressure, the asphaltene dissociation rate, the asphaltene adsorption coefficient and the critical velocity of oil movement in the reservoir. Under the natural depletion scenario, our simulations show a significant decrease in reservoir pressure and the formation of drawdown cones leading to asphaltene deposition in the bottom-hole area of production wells, decreasing their productivity. Water injection generally allows us to significantly reduce the volume of asphaltene phase transitions and has a positive effect on cumulative oil production. Injecting water into aquifer can keep the formation pressure long above the pressure for asphaltene precipitation, preventing the asphaltene deposition resulted from interaction of oil and water, so this way has higher oil production.

A new empirical model for predicting flue gas miscibility for light oils

It is typical to observe a decline in production rate and a decrease in reservoir pressure after oil reservoirs have been allowed to produce for a long time. Miscible flooding is a tertiary recovery method for enhancing the reservoirs’ sweep efficiency. During miscible injection, gasses such as carbon dioxide, natural gas, and nitrogen are employed to increase production levels. Carbon dioxide is commonly used as a miscible gas, but less abundant and more expensive than nitrogen. Flue gas, a mixture of carbon dioxide and nitrogen gas, is often used to replace pure carbon dioxide. For this study, flue gasses with the compositions, 15% of carbon dioxide, 85% of nitrogen gas and 30% of carbon dioxide,70% of nitrogen gas, are used as the injection gas to develop an empirical correlation for minimum miscibility pressure (MMP) for candidate light oil reservoirs that have been previously waterflooded. In data analysis and data analytics, the dataset was separated into two groups at random: the training set, which consists of 80% of the entire dataset, and the testing set, which made up 20% of the total dataset. The independent variables employed for model development include temperature, oil sample oil gravity, molecular percentage of carbon dioxide in the injection gas, the molecular weight of hexane plus in the oil, and the molecular percentage of intermediates. The findings reveal that the newly built model is more accurate and delivers better predictions than the existing correlations. For the testing dataset, the new model predicts flue gas MMP with an average absolute percentage error of 5.5519% and a correlation coefficient of 0.92.

Transient analysis of horizontal wells with multiple fractures in sour gas reservoirs

Due to the decrease of reservoir pressure, the elemental sulfur deposits in sour gas reservoirs, leading to the reduction in the reservoir porosity and permeability. It can also impact the transient pressure and rate behavior of gas wells, which is always reflected in pressure and flow rate type curves. However, few studies focus on transient analysis of multi-fractured horizontal wells affected by sulfur deposition. Therefore, the objective of this work is to develop a comprehensive model to analyze the transient pressure and flow rate of multi-fractured horizontal wells in sour gas reservoirs. Pseudo-time function and pseudo-pressure function are derived and the point source method is applied in this model. Then the proposed model is validated against analytical solutions and real production data. Furthermore, sensitivity analysis for pressure and rate type curves was conducted. Results show that the pressure type curves can be divided into six stages. The reservoir with higher H2S concentration will result in more sulfur deposition, which requires larger pressure difference to maintain a constant rate in the late time. Fracture properties impact flow rate in the early production time, and increasing fracture conductivity and fracture number is helpful to reduce the generation of sulfur deposition. For a smaller reservoir, larger pressure difference is essential to stabilize constant production rate, which means more sulfur deposition will be produced in the reservoir. During the development of sour gas reservoir, it is important to control flow rate to reduce pressure depletion for decrease amount of sulfur deposition. This paper reveals the impacts of sulfur deposition on type curves and provides a comprehensive transient analysis for multi-fractured horizontal wells in the development of sour gas reservoirs.

Selection & Optimization of Artificial Lift Using Delphi, TOPSIS, and SAW Methods for Natural Flow Oil Wells at HAS Field

ABSTRACTThe HAS field started producing oil and gas in 2004 until 2018, production wells in HAS experienced a decrease in oil production from 45,000 bopd to 6,190 bopd and an increase in water production from 0 bwpd to 20,463 bwpd. The decline in production occurs due to increased water production. The decrease in production was caused by a decrease in reservoir pressure, causing a larger water cut. Therefore, it is necessary to optimize production wells by considering the things mentioned above.The artificial lift selection method used is the Delphi method which has 21 screening parameters combined with the Topsis method; helps facilitate Decision-Making from various complex alternatives, by conducting comprehensive comparisons between each alternative and using the Simple Additive Weighting (SAW) method; known as the weighted addition method. The selection of the Artificial Lift in the HAS Field was carried out based on the reservoir parameters, production, well construction, and the economic factors of the artificial lift used. The artificial lift method that will be used in the HAS Field is the Electrical Submersible Pump (ESP). Based on the results of the selection of an artificial lift with a combined method of Delphi, Topsis, and SAW,Efforts to increase production with an electric submersible pump (ESP) are carried out by optimizing the number of stages and setting the frequency to a value of 45 Hz. Further optimization is carried out by gradually changing the pump frequency up to a maximum of 60 Hz, without changing the pump type. From the results of the economic analysis in the HAS Field, it was found that the most economical scenario was to use an ESP pump with the highest NPV@10 % value than the other scenarios, namely 434.85 MUS$.Keywords :Artificial Lift Conversion; Delphi; Topsis; SAW; Optimization

Effect of water on methane diffusion in coal under temperature and pressure: A LF-NMR experimental study on successive depressurization desorption

Coalbed methane production is a process of desorption, diffusion, and seepage with the successive decrease of reservoir pressure. However, desorption at atmospheric pressure has been mainly used to investigate the gas diffusion of water-bearing coal. The influence of confining pressure and gas pressure on methane diffusion is not considered in this case. So, the question is, how does the variation of the methane diffusion coefficient of water-bearing coal during desorption? How is it different from dry coal? What is the difference between the methane diffusion behavior of anthracite and bituminous coal? To address these problems, we select low-volatile anthracite in the south of Qinshui Basin and high-volatile bituminous coal in the south of Junggar Basin. The methane diffusion of water-bearing and dry coal during the successive depressurization desorption is compared by low field nuclear magnetic resonance. The influence mechanism of water on methane diffusion is explored from the pore structure, wettability, and external stress. The results show that the methane diffusion coefficient of water-bearing anthracite and bituminous coal increases with the decrease of gas pressure. The methane diffusion of water-bearing coal is affected by the combination of the increase of methane desorption volume (positive effect) and the increase of effective stress (negative effect). When the gas pressure decreases from 6 MPa to 2 MPa, the negative effect is dominant, and the effective diffusion coefficient of methane in coal is poor; When the gas pressure is less than 2 MPa, the positive effect is dominant and the effective diffusion coefficient increases significantly. The homogeneity of methane effective diffusion path of water-bearing anthracite is enhanced, resulting in higher methane desorption rate and effective diffusion coefficient than dry coal. The methane effective diffusion pore size of water-bearing bituminous coal decreases, resulting in the effective diffusion coefficient of methane less than that of dry coal. These results are of great significance to reveal the methane diffusion behavior of coalbed methane in the actual production.

HYDRODYNAMIC STUDIES OF WELL 32 OF THE SOUTHERN SECTION IN THE CHINAREVSKOYE FIELD OF THE WEST KAZAKHSTAN REGION

The paper analyzes the factors influencing the development of high-quality and cost-effective oil and gas reserves in the region (assessment, design). In order to operate wells, directions for calculating the size of reserves have been found. The scientific and technical trends of their (wells) development are considered. A comprehensive analysis of complex surveys was carried out at well No32 of the Chinarevskoye oil and gas condensate field, located in the southern section of the region. Hydrodynamic studies were carried out by interpreting the pressure recovery curve (PRC) to determine reservoir pressure, reservoir properties and the state of the bottomhole zone. These studies confirmed the low porosity properties of the reservoir: permeability - 0.004 mkm2 , conductivity - 0.056 mkm2 *m, hydraulic conductivity - 0.055 mkm2 *m/MPa*s. The skin factor varied in the range from - 0.92 to 18.4, which indicates a deterioration in the state of the bottomhole formation zone. Reservoir pressure dynamics (reduced to WOC) according to hydrodynamic studies showed that in the deposit, as the reservoir is withdrawn, there is a decrease in reservoir pressure. As of October 2019, according to the pressure build-up data, the formation pressure in well 32 (at the VNK level) is 38 MPa. Well 32 during the analyzed period (5 months) worked in three modes (from July to September 2019 with a washer with a diameter of 6 mm, from the end of September with a washer with a diameter of 8 mm, in October - 10 mm). At the same time, with an increase in the washer diameter to 8 and 10 mm, the downhole working pressure sharply decreased from 25 to 11 MPa and the static bottomhole pressure from 37.5 to 29.7 MPa. During the analyzed period, the well worked with a bottomhole pressure below the saturation pressure of oil with gas. The average gas-oil ratio was 757 m3/m3.

Carotid Reservoir Pressure Decrease After Prolonged Head Down Tilt Bed Rest in Young Healthy Subjects Is Associated With Reduction in Left Ventricular Ejection Time and Diastolic Length.

BackgroundThe arterial pressure waveform reflects the interaction between the heart and the arterial system and carries potentially relevant information about circulatory status. According to the commonly accepted ‘wave transmission model’, the net BP waveform results from the super-position of discrete forward and backward pressure waves, with the forward wave in systole determined mainly by the left ventricular (LV) ejection function and the backward by the wave reflection from the periphery, the timing and amplitude of which depend on arterial stiffness, the wave propagation speed and the extent of downstream admittance mismatching. However, this approach obscures the ‘Windkessel function’ of the elastic arteries. Recently, a ‘reservoir-excess pressure’ model has been proposed, which interprets the arterial BP waveform as a composite of a volume-related ‘reservoir’ pressure and a wave-related ‘excess’ pressure.MethodsIn this study we applied the reservoir-excess pressure approach to the analysis of carotid arterial pressure waveforms (applanation tonometry) in 10 young healthy volunteers before and after a 5-week head down tilt bed rest which induced a significant reduction in stroke volume (SV), end-diastolic LV volume and LV longitudinal function without significant changes in central blood pressure, cardiac output, total peripheral resistance and aortic stiffness. Forward and backward pressure components were also determined by wave separation analysis.ResultsCompared to the baseline state, bed rest induced a significant reduction in LV ejection time (LVET), diastolic time (DT), backward pressure amplitude (bP) and pressure reservoir integral (INTPR). INTPR correlated directly with LVET, DT, time to the peak of backward wave (bT) and stroke volume, while excess pressure integral (INTXSP) correlated directly with central pressure. Furthermore, Δ.INTPR correlated directly with Δ.LVET, and Δ.DT, and in multivariate analysis INTPR was independently related to LVET and DT and INTXSP to central systolic BP.ConclusionThis is an hypothesis generating paper which adds support to the idea that the reservoir-wave hypothesis applied to non-invasively obtained carotid pressure waveforms is of potential clinical usefulness.

Estimation of the Influence of Oil Flows on the Formation Losses of Condensate During the Development of Multi-Layer Deposits

During the development of multilayer oil and gas condensate fields, the production of condensate is influenced by the associated oil. Analysis of field data showed that the cause of oil flows is the outstripping decrease in reservoir pressure in the gas condensate section in comparison with oil zones. Thus, incoming heavy oil fractions into a gas condensate reservoir have a negative impact on reservoir losses of hydrocarbons, including the final condensate recovery factor. Many years of experience in the development of such fields showed that the bulk of the presence of associated oil in well production is explained by the following reasons: the relationship between the reservoirs through lithological windows, the residual oil saturation of the reservoirs, and the presence of lenticular layers. Determination of the quantitative content of oil in the reservoir mixture was determined by infrared spectrometry using a Perkin-Elmer Fourier transform spectrometer, which makes it possible to assess changes in the component composition of gas condensate systems. In the course of the research, selected samples of the gas and liquid phases were analyzed directly from the production facilities of the development. The analysis of IR spectrometry showed that in most of the samples of gas condensates, the effect of displacement is recorded, which is characteristic of fluids with the manifestation of oil impurities.The purpose of these studies is to study the influence of the produced oil on the dynamics of hydrocarbon production and the final condensate recovery factor.

Об одном факторе, снижающем продуктивность скважин на поздней стадии разработки месторождений

The paper presents a study of the influence of the displacement factor of perforation channels in the bottomhole zones of wells relative to the perforations in the casing pipes at a late stage of oil and gas field development, characterized by a decrease in reservoir pressure. It is shown that in most cases this displacement leads to deterioration or complete disappearance of the hydrodynamic connection of the bottomhole zone with the wellbore. It was found that the processes of creep of rocks, increasing the magnitude of the displacement of the seam top, enhance the effectof this factor. It is shown that in order to reduce the negative effects of displacement of perforation channels, it is advisable to use slotted perforation of wells or the technology of forming vertically close pairs of perforationchannels during the secondary opening of productive formations. The results of the study can be used for a reasonable choice of technologies for influencing the bottomhole zones of wells at a late stage of oil and gas field development.