Gazovaya promyshlennost’ № 03 2022

To date, there are regulatory documents providing basic and general recommendations for field surveys to obtain reliable information on gas condensate characteristics. These recommendations set the requirements for the allowable well operating conditions during testing (reservoir drawdown, gas flow rate) and lists the factors that reduce the informative value of gas condensate well tests. These factors include a certain amount of brine water and oil in the fluid; formation of hydrates, paraffins, and other solid deposits in the wellbore, and more. Forecasting gas condensate characteristic behavior is especially relevant when designing and monitoring the development of low-permeable Achimov pools of Urengoyskoye oil, gas and condensate field (Yamalo-Nenets Autonomous Okrug) with a high content of C5 + in the formation gas. Problems arise in PVT (pressure, volume, temperature) modeling of formation gas, determining the dynamics of the potential content of C5 + components varying with pressure and well operation modes. The problematic part is the consolidation of the formation gas sample data obtained in the gas condensate well test and the condensate content with the reservoir (bottom hole) pressure measured during the gas-dynamic well test. A digital compositional model of a single well was created to resolve the problem. The model was used to reproduce the history of primary gas condensate and gas-dynamic studies, analyze the fluid composition, and link the composition to pressure. The composition identification method was tested at various reservoir properties in the hydraulic conductivity range of 10–5–10–1 μm2 · m. The deviation of the gas condensate characteristic was estimated by the bottom hole and reservoir pressures.

This paper presents petrophysical models’ classification of complexly composed low-permeable reservoirs of the Lower Permian terrigenous molasse of the Upper Pechora depression of the Pre-Ural foreland basin. This classification is based on a comprehensive generalization of petrophysical core studies, well logging and testing. It is revealed that presence of core connected porosity is not, in itself, indicative of filtration characteristics of the rock under consideration. The key factor that determines a reservoir rocks’ permeability is the presence of secondary capacity (weakened fractured zones). The reservoirs of the Upper Arti deposits are divided into four types: traditional, predominantly porous; traditional in terms of permeability and fractured (cavernous-fractured) in terms of the voids type; unconventional, rather low permeable with isolated pores; unconventional extremely low-permeable (values of absolute gas permeability are below the limit) and low-porous. Lower shale strata (members I–IV) can act as unconventional reservoirs in the molasse formation of the Upper Pechora depression and upper sandy-siltstone members (V–VII) – as combined (traditional – unconventional) reservoirs. Moreover, the lower shale strata (particularly members I–III), which are poorly studied by the core data (one determination of the organic carbon content), can so far be considered only as potential gas-bearing shales.

The study analyzes the specific features of pressure-and-temperature regimes of the Chayandinskoye oil, gas and condensate field related to low formation temperature, salinity of the residual brine water, and thus, low gas-moisture content. It is shown that hydrate formation in the well tubing is thermodynamically possible directly from vapor moisture present in the gas rather than condensed droplets, the latter being typical for gas producing wells at higher formation temperatures. Calculations are made for the formation gas moisture content and phase equilibrium in the “natural gas with water vapor – hydrate” system applied to the gas flow in wells. It is noted that almost the entire wellbore is in the hydrate-formation zone even at a reservoir drawdown of hydrate-free operation. That being said, the hydrate deposit accumulation is quite slow due to the abnormally low formation gas moisture content. They can accumulate partly on the internal tubing wall and move with the gas flow to localize in the wellhead and angle throttling valve.