Wellhead

Abstract: Clayey silt reservoirs bearing natural gas hydrates (NGH) are considered to be the hydrate-bearing reservoirs that boast the highest reserves but tend to be the most difficult to exploit. They are proved to be exploitable by the first NGH production test conducted in the South China Sea in 2017. Based on the understanding of the first production test, the China Geological Survey determined the optimal target NGH reservoirs for production test and conducted a detailed assessment, numerical and experimental simulation, and onshore testing of the reservoirs. After that, it conducted the second offshore NGH production test in 1225 m deep Shenhu Area, South China Sea (also referred to as the second production test) from October 2019 to April 2020. During the second production test, a series of technical challenges of drilling horizontal wells in shallow soft strata in deep sea were met, including wellhead stability, directional drilling of a horizontal well, reservoir stimulation and sand control, and accurate depressurization. As a result, 30 days of continuous gas production was achieved, with a cumulative gas production of 86.14 ×104 m3. Thus, the average daily gas production is 2.87 ×104 m3, which is 5.57 times as much as that obtained in the first production test. Therefore, both the cumulative gas production and the daily gas production were highly improved compared to the first production test. As indicated by the monitoring results of the second production test, there was no anomaly in methane content in the seafloor, seawater, and atmosphere throughout the whole production test. This successful production test further indicates that safe and effective NGH exploitation is feasible in clayey silt NGH reservoirs. The industrialization of hydrates consists of five stages in general, namely theoretical research and simulation experiments, exploratory production test, experimental production test, productive production test, and commercial production. The second production test serves as an important step from the exploratory production test to experimental production test.

Abstract: A method and apparatus is disclosed for heating of formations using fired heaters. Each fired heater may consist of two concentric tubulars emplaced in the formation, connected via a wellhead to a burner at the surface. Combustion gases from the burner go down to the bottom of the inner tubular and return to the surface in the annular space between the two tubulars. The two tubulars may be insulated in an overburden zone where heating is not desired. A plurality of fired heaters can be connected together such that the combustion gases from a first fired heater well are piped through insulated interconnect piping to become the air inlet for a second fired heater well, which also has a burner at its wellhead. This can be repeated for other heater wells, until the oxygen content of the combustion gas is reduced near zero. The combustion gas from the last fired heater well may be routed through a heat exchanger in which the fresh inlet air for the first heater well is preheated. A substantially uniform temperature is maintained in each heater well by using a high mass flow into the heater well.

Abstract: Wellbore fluid temperature is governed by the rate of heat loss from the wellbore to the surrounding formation, which in turn is a function of depth and production/injection time The authors present an approach to estimate wellbore fluid temperature during steady-state two-phase flow The method incorporates a new solution of the thermal diffusivity equation and the effect of both conductive and convective heat transport for the wellbore/formation system For the multiphase flow in the wellbore, the Hasan-Kabir model has been adapted, although other mechanistic models may be used A field example is used to illustrate the fluid temperature calculation procedure and shows the importance of accounting for convection in the tubing/casing annulus A sensitivity study shows that significant differences exist between the predicted wellhead temperature and the formation surface temperature and that the fluid temperature gradient is nonlinear This study further shows that increased free gas lowers the wellhead temperature as a result of the Joule-Thompson effect In such cases, the expression for fluid temperature developed earlier for single-phase flow should not be applied when multiphase flow is encountered An appropriate expression is presented in this work for wellbores producing multiphase fluids

Abstract: This paper discusses results of field tests conducted to verify minimum flow rate (critical rate) required to keep low-pressure gas wells unloaded and compares results to previous work. This paper also covers liquid yield effects, liquid sources, verification that wellhead conditions control onset of load-up, and effects of temperature, gas/liquid gravities, wellbore diameter, and packer/tubing setting depth.