Gazovaya promyshlennost’ Спецвыпуск № 2 2022

To date, the depletion of conventional reservoirs leads to more attention to difficult low-permeable ones. Mining of rocks with ultra-low reservoir properties always involves a range of issues associated with non-pay low or zero flow rates in wells, low efficiency of the reservoir pressure maintenance system, selecting the best new drilling locations, etc. Resolving these challenges requires a detailed picture of the formation geology and the principles and conditions of its formation. Remodeling the ancient sedimentary environments allows reflecting the reservoir spread patterns and identifying the areas with the best reservoir properties. This study aimed to determine which areas of low-permeable formations were prospective for development. The study subjects were the deposits of the Yu2-1 and Yu2-2 formation groups within the upper subsuite of the Tyumen suite, Middle Jurassic. With frequent interbedding of claystones, sandstones, and aleurolites with coal intercalations, these deposits have complex geology, wide facies variation, low reservoir properties, and significant secondary alterations, which further impair the reservoir properties. In this study, the core examination results allowed us to identify the sedimentary environment and facies of the reservoir rocks. We also retrieved the areal sedimentary environments from the seismic data, found the most prospective facies groups to bring into development, and proposed some options for effective flow initiation and enhancement.

Medvezhye oil, gas, and condensate field was discovered in 1967 and brought into development 50 years ago as one of the first West-Siberian gas giants. The field has been used to field-test new unconventional approaches to development (including rational development) and exploitation of Cenomanian gas pools and then successfully implement them at other gas giants: Urengoyskoye, Yamburgskoye, Zapolyarnoye, and more. Over 2 billion m3 of gas has been produced from Medvezhye during its development. For years, it had only one Cenomanian gas pool discovered, which is now close to depletion. The new life of the Medvezhye field is expected to yield from the exploration and development of the Neocomian gas-condensate pools discovered in 2005 and the Senonian gas pool (2012); prospecting, exploration, and development of hydrocarbon pools in the deep levels (Neocomian and Jurassic Achimov rocks); studying and developing the gas-hydrate pools in the Above-Cenomanian gas-bearing mega play. The field is to be significantly extended to the South. Medvezhye has been and still is a test side for advanced technical solutions. The exploration of the field involves such innovations as high-density seismic surveys using the 3D common depth point seismic reflection method with controlled sweep, detailed gas-chemical well studies, using wells with horizontal sideholes and multistage hydraulic fracturing, and more.

The article characterizes the pressure-and-temperature conditions of prospective West Siberian fields. It shows that developing process management methods for hydrate prevention in wells must be started now in order to enable long-term development of the oil and gas fields in the West Siberia and the Arctic shelf. The article also describes the dependence of temperature on the vertical wellbore pressure, considering the specific features of heat and mass transfer in low-temperature field wells. All the factors affecting the pressure-and-temperature regimes are reflected in temperature and pressure measurements at three points at a minimum. The dependences derived from these data are proposed to use for diagnosing production decline causes and for hydrate prevention actions. An algorithm is proposed for determining process modes for hydrate-free well development at low-temperature fields. The existence of two critical hydrate formation intervals is shown for the first time. The first interval is adjacent to the wellhead, which indicates insufficient heat insulation. In the second one, adjacent to the bottom hole, hydrates are formed due to the Joule-Thompson effect, indicating excessive drawdown or reduced tubing inlet.

At the gas condensate fields that are being put into operation there is a tendency of increasing the distance between the surface field facilities. As a result, the length of the gas gathering system pipelines is increasing. For the forecasting and analysis of the extended pipelines operation modes, the hydrodynamic simulation tools are widely used. The article considers the application of this method for solving the technological problems associated with the operation of an extended hilly terrain pipeline transporting gas with a low condensate content. By the example of one of the operating facilities, it is shown that the operation of the pipelines in the low gas flow conditions at the initial stage of the operation is complicated by the accumulation of the liquid phase, the occurrence of significant hydrostatic pressure losses, and liquid bursts. The volume of the liquid accumulated in the pipeline, its impact on the pressure drop and the multiphase flow regime were determined using steady-state hydrodynamic simulation. The technological risks associated with liquid removal during the increase in gas flow rate in the process of reaching the design mode of operation were analyzed. On the basis of the non-stationary hydrodynamic simulation various scenarios of the further pipeline operation were investigated and solutions to ensure its safe operation were proposed. Practical implementation of the solutions confirmed their effectiveness in the process of increasing the gas flow rate in the pipeline. The results of the simulation performed are in good correlation with the actual data on the pressure drop in the pipeline and the fluid outflow from it, which confirms the applicability of the simulation tools used to solve technological problems arising during the operation of the multiphase fluid extended pipelines.

The purpose of this work is to mathematically simulate the conditions of hydrate formation during the gas wells operation, allowing to search for minimum and maximum permissible (ultimate) values of the draw-down per reservoir, under which there is no risk of hydrate formation in the bottomhole zone, wellbore and wellhead equipment. A system of equations is suggested for which such ultimate values serve as a solution. The software module is created and the results of its application for geological and production conditions of Cenomanian and Valanginian deposits of Western Siberia fields are presented. A comparative analysis of existing methods for assessing the risks of hydrate formation has been carried out. The approach proposed by G.V. Ponomarev, based on the selection of equation coefficients according to the results of accurate experimental studies, turned out to be the simplest and most effective of them. Created algorithms of estimation of ultimate draw-down and flow rates of wells can be considered as modification of this method. In comparison with the hydrodynamic simulation software, the developed software module allows evaluating the ultimate values of the drawn-down and flow rates using substantially less amount of input data that enables its effective application for operational management of the gas well operation processes. The main results of the research presented in the article are the creation of a mathematical model and algorithm for calculating the ultimate draw-down and flow rates, the information about which can be used to select and justify the technological modes of gas wells, reducing the risks of hydrate formation in their bottomhole zone and wellhead equipment.

Field development in shallow waters of the Kara Sea in the Arctic continental shelf of the Russian Federation is associated with addressing a set of technical, technological, and environmental tasks and implies using sophisticated and unique production equipment, machinery, and construction technologies. The high requirements for the reliability of offshore petroleum field development facilities and the minimized timelines for the offshore construction and assembly point to the need for using advanced technologies in soil stabilization. These technologies allow for a quality ground preparation, which ensures the operational reliability of an offshore oil or gas field structure. The article analyzes the approaches to selecting an offshore oil or gas field structure, considering the ice conditions, sea depth, and geotechnical and permafrost conditions in the waters of the Gulf of Ob and Taz Estuary. Various types of these structures are considered for offshore gas and gas-condensate field development in the region. The article also shows the prospects of ground preparation for offshore oil and gas field structures via chemical soil stabilization. The soil strength characteristics achieved in 1 year with cementing agents only can be reached in 1–2 months by the joint application of mineral conditioners and cementing agents for chemical stabilization of soils with low bearing capacity. Using the technology in field development planning in the Gulf of Ob and Taz Estuary has a significant potential to reduce the construction timeline, optimize the work schedule, reduce the capital expenditure for the development, and thus improve the cost-effectiveness of the offshore projects in the region.