Search Results (5)

The separate-layer gas injection technology is a key means to improve the effect of refined gas injection development. Currently, the measurement and adjustment of separate injection wells primarily rely on manual experience and automatic measurement via instrument traversal, resulting in a long duration, low efficiency, and low qualification rate for injection allocation across multi-layer intervals. Given the different CO₂-containing natural gas injection rates across different intervals, this paper establishes a coupled flow model of a separate-layer gas injection wellbore–gas distributor–formation based on the energy and mass conservation equations for wellbore pipe flow, and develops a solution method for determining gas nozzle sizes across multi-layer intervals. Based on the maximum allowable gas nozzle size, an optimization method for multi-layer collaborative allocation of separate injection wells is established, with minimum wellhead injection pressure and layered injection allocation as the optimization objectives, and the opening of gas distributors for each layer as the optimization variable. Taking Well XXX as an example, the optimization process of allocation schemes under different gas allocation requirements is simulated. The research shows that the model and method proposed in this paper have high calculation accuracy, and the formulated allocation schemes have strong adaptability and minor injection allocation errors, providing a scientific decision-making method for formulating refined allocation schemes for separate-layer gas injection wells, with significant theoretical and practical value for promoting the refined development of oilfields. Full article

To meet the usage requirements of the wellhead mandrel-type tube hanger of 175 MPa ultra-high pressure, four specially shaped metal sealing structures are selected as the research objects in this paper. The mechanical properties of different metal sealing structures are calculated, respectively, by using finite element software and binary regression analysis software. It was found that the mechanical properties and contact pressure fluctuations of X-shaped and straight U-shaped metal seals were relatively large, and the sealing width was relatively small among the four types of special-shaped metal seals. The mechanical properties and sealing performance of ball-drum-type metal seals and elliptical U-shaped seals were relatively stable, and the contact width was relatively large. For the single U-shaped sealing structure, the optimization rates of the maximum contact pressure and the minimum equivalent stress reached 11.63% and 10.63%, respectively. For the double U-shaped structure, the optimization rates of its maximum contact pressure and minimum equivalent stress both exceed 12%. The tests showed that the metal sealing structure met the pneumatic sealing requirement of 175 MPa. These results provide theoretical guidance for the research and design of a new type of ultra-high-pressure mandrel oil and casing hanger with a long service life and high reliability. Full article

This paper considers the problem of estimating the quantitative parameters of a two-phase fluid flow in a well based on the dynamic physical flow model. This is a challenging problem in the oil and gas industry, where the knowledge of multiphase production rates plays an important role during reservoir characterization, production optimization and reservoir management. As the direct measurement of these rates is not easily available, they can be inferred from conventional sensors (e.g., pressure gauges) in combination with a dynamic multiphase flow model. The methodology proposed in this work uses inverse modeling concepts to estimate flow rates that are not measured directly. The mismatch between the available data and model prediction is numerically minimized, leading to the optimal set of dynamic flow variables characterizing the flow. Two different scenarios are considered: firstly, when the well has only a flow meter located at the wellhead (minimum amount of available information), and when the well has distributed pressure sensors in addition to the topside flow meter (maximum amount of information). The feasibility of the proposed concept is assessed via several simulation-based case studies. Full article

In order to clarify the gas-phase carrying capacity after the atomization of water from the bottom of deep coalbed wells, considering characteristics of atomization-assisted production and the dynamic equilibrium principle of gas–liquid two-phase flow in the wellbore, the gas-phase liquid-carrying drop model was established, and the solution method of the upstream and downstream driving force of liquid drop flow was studied. We also verified the theoretical model through physical simulation. Then, the law for the influence of droplet size, wellbore inclination, wellbore diameter, and wellhead back pressure of the critical liquid-carrying velocity in the gas phase is analyzed using the model. The results show the following: ① the larger the diameter of atomized droplets, the greater the gravity force applied to it, the worse the ability to be carried by the gas phase, a onefold increase in droplet diameter corresponds to the increase in the minimum critical velocity of the gas phase by 1.45 times; ② with the increase in wellbore inclination, the liquid-carrying capacity of the gas phase decreases, and the minimum critical liquid-carrying velocity of equal diameter droplets increases by 0.01438 m/s or 1.27 times for the increase in wellbore inclination by 10°; ③ with the increase in wellbore diameter, both the driving force of a droplet of equal diameter and the flow resistance through the gas phase in the wellbore decrease within the range of a driving pressure difference of 0.2 Mpa; the decrease in liquid-carrying velocity caused by the decrease in received flow resistance can reach the maximum value of 0.0473 m/s; ④ with the increase in wellhead back pressure, the driving force of equal-diameter droplets decreases, the resistance against passing through the high-concentration gas phase increases, and the gas-phase-carrying droplets start the game; ⑤ the atomization-assisted production has the function of drainage gas recovery, and the adoption of atomization-assisted production technology can increase the production time of a coalbed gas flowing well, enabling the wells to have a good transition time interval for the conversion of flowing wells to pumping ones, which provides a precise production dynamic basis for the efficient design and implements the overall strategy of drainage gas recovery by deep-well pumping. In short, this technology has the high-efficiency liquid-carrying function of “water atomization to help liquid-phase flow and increase gas production”, as well as obvious technical advantages, which can provide a new idea for the development of deep coalbed methane wells and other types of gas wells with water. Full article

Geothermal energy is typically produced by a collection of wells which drain a reservoir. Engineers’ experience and reservoir monitoring data are employed to properly determine the wells in operation and their production rate. However, identifying the optimal well configuration which contributes the most to the geothermal power produced at the system outlet is very complex since the extracted fluid’s energy is attenuated when traveling through the production wells and the surface network toward the delivery point. Undoubtedly, a reliable optimizer focusing on a unified system would greatly improve its management regarding both energy production and sustainability. In this work, a mathematical model is proposed, which fully describes flow in the joined production system, by coupling the reservoir, wellbore and ground pipeline network flow dynamics. The reservoir IPR (inflow performance relationship) curves are combined with the pipeline network’s hydraulic/thermal behavior, to estimate the geothermal fluid’s pressure, flow and temperature at the delivery point. Every design detail, such as the well geometry, subsurface heat loss and pressure/heat loss along the ground pipeline network, is accounted for. Subsequently, an optimizer identifies the choking that needs to be imposed at each wellhead, so that the geothermal fluids produced account for the minimum mass rate for a given heat load, thus contributing to the sustainability of the geothermal system. The model can be calibrated using history matching to further improve the estimation accuracy. Optimal conditions can be recalculated every time a change takes place in the subsurface system, the surface network or the production constraints. Full article