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.

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.

No abstract

The Sulige is a low-permeability tight gas sandstone field whose natural gas production has gradually declined with continuous development. The primary reason was that most of the wells in the field flew below their critical rates and liquids started to accumulate in the wellbore at different levels, which resulted in the production reduction due to the wellbore pressure decrease and back pressure increase on the produced gas. An artificial lift was required to remove the liquids from those wells. With the advantages such as simple installation and operation, low cost and high liquid-carrying capacity, the plunger lift has been proven effective in the Sulige Gas Field. In this paper, firstly, a series of mathematical models were developed to investigate plunger displacement and velocity in the uplink and downside phases, fluid leakage in the uplink phase, and the characteristics of tubing pressure and casing pressure in the uplink and pressure build-up phases. Then, taking well X1 and well X2 at Su 59 area of the gas field as an example, the established mathematical models were applied to estimate its tubing and casing pressure, plunger moving displacement and speed, fluid leakage during the uplink phase, and gas production during the plunger lift. Hence, the well production cycle operated by the maximum gas rate was optimized. This study provides a theoretical basis for the optimal design of plunger lift parameters and the improvement of gas production.

This study performed in-depth analysis of onsite fatigue damage and stress distribution in pumping rods. Two aspects of fatigue damage were analyzed: macroscopic morphology and chemical properties. In terms of chemical properties, the crystalline phase composition and hardness of the product at fatigue damage were analyzed; the stress distribution was analyzed in term so of the rod-body stress and the connection-section stress. The cross-sectional characteristics of the fatigue crack expansion were summarized, and the types of fatigue fracture and the influencing factors of the pumping rod were obtained from these cross-sectional characteristics. Finally, modeling and stress analysis of the pumping rod were performed using SolidWorks and ABAQUS software. By comparing the stress cloud diagrams of different thread root shapes, the factors that cause fracture in the pumping rod and the locations of stress concentrations and dangerous cross-sections of the rod were determined. The highest principal stresses were obtained at the rod body near the upsetting flange of the pumping rod, and fatigue damage was the most likely to occur at this location. The shoulder of the unloading groove and the upsetting flange area were relatively safe because of their large cross-sectional area and less likelihood to produce stress concentrations. The results of this study can provide scientific guidance and reference for the development of pumping rods for efficient oil production and the improvement of oil and gas production efficiency.