Drilling of horizontal wells with multi-stage hydraulic fracturing (MFHW) is one of the most common solutions in the development of low-permeable oil and gas reservoirs. At the same time, the estimation of the well and reservoir parameters by well test analysis is complicated due to long time response to the radial flow regime. It is possible to eliminate uncertainty dealt with the absence of radial flow response by using data from the early radial regime that occurs at early times of pressure buildup. However, its appearance is only possible if the distance between the parallel fractures is much larger than the fracture half-lengths, which is not usual in practice. At the same time, MFHW demonstrate a complex buildup behavior due to fracture interference. By analytical and numerical simulations it is shown that the early time buildup behavior depends on duration of well production before shut-in. This behavior is similar to the buildup of a vertical well near the sealed boundary. For short production times, a radial-like regime may appear at early buildup times caused by elliptical flow around the fractures. The consistency of this regime and the relation of the pressure derivative plateau level to the parameters of the elliptical flow are justified. An empirical formula of sufficient accuracy has been obtained for reservoir transmissibility (flow capacity). This formula is applicable for the most common range of parameter values of the MFHW. These results open up new opportunities for reliable assessment of the well and reservoir parameters from well tests in MFHW in low-permeability reservoirs, including new wells or wells restarted after a long inactive period.

In oil and gas reservoirs with significant hydrocarbon columns the dependency of the initial hydrocarbon composition on depth – the compositional gradient – is an important factor in assessing the initial amounts of components in place, the position of the gas-oil contact, and variations of fluid properties throughout the reservoir volume. Known models of the compositional gradient are based on thermodynamic relations assuming a quasi-equilibrium state of a multi-component hydrodynamically connected hydrocarbon system in the gravity field, taking into account the influence of the natural geothermal gradient. The corresponding algorithms allow for calculation of changes in pressure and hydrocarbon fluid composition with depth, including determination of the gas-oil contact (GOC) position. Above and below the GOC, the fluid state is considered single-phase. Many oil-gas-condensate reservoirs typically have a small initial fraction of the liquid hydrocarbon phase (LHC) – scattered oil – within the gas-saturated part of the reservoir. To account for this phenomenon, a special modification of the thermodynamic model has been proposed, and an algorithm for calculating the compositional gradient in a gas condensate reservoir with the presence of LHC has been implemented. Simulation cases modelling the characteristic compositions and conditions of three real oil-gas-condensate fields are considered. The results of the calculations using the proposed algorithm show peculiarities of variations of the LHC content and its impact on the distribution of gas condensate mixture composition with depth. The presence of LHC leads to an increase in the level and possible change in the type of the fluid contact. The character of the LHC fraction dependency on depth can be different and is governed by the dissolution of light components in the saturated liquid phase. The composition of the LHC in the gas condensate part of the reservoir changes with depth differently than in the oil zone, where the liquid phase is undersaturated with light hydrocarbons. The results of the study are significant for assessing initial amounts of hydrocarbon components and potential efficiency of their recovery in gas condensate and oil-gas-condensate reservoirs with large hydrocarbon columns.

Results are discussed for evaluation of effectiveness of the cyclic geomechanical treatment (CGT) on a Tournaisian carbonate reservoir. Analysis of laboratory experiments performed according to a special program to assess permeability changes for Tournaisian samples under cyclic changes in pore pressure is presented. The main conclusion is the positive selectivity of the CGT: an increase in permeability is observed for samples saturated with hydrocarbons (kerosene) with connate water, and maximal effect is related to the tightest samples. For water-saturated samples, the permeability decreases after the CGT. Thus, the CGT improves the drainage conditions for tight oil-saturated intervals. It is also confirmed that the CGT reduces the fracturing pressure in carbonate reservoirs. Using flow simulations on detailed sector models taking into account the results of laboratory experiments, a possible increase in well productivity index after CGT with different amplitudes of pressure variation was estimated. Results of a pilot CGT study on a well operating a Tournaisian carbonate reservoir are presented, including the interpretation of production logging and well testing. The increase in the well productivity index is estimated at 44-49 % for liquid and at 21-26 % for oil, with a more uniform inflow profile after the treatment. The results of the field experiment confirm the conclusions about the mechanisms and features of the CGT obtained from laboratory studies and flow simulations.