In oil and gas field development, the choice of well type directly affects drilling technology and well control strategies. From vertical wells to directional wells, and then to special well types such as horizontal wells and multi-bottom wells, the differences in wellbore trajectory, formation contact methods, and engineering complexity place differentiated demands on well control equipment configuration, pressure management, and In oil and gas field development, the choice of well type directly affects drilling technology and well control strategies. From vertical wells to directional wells, and then to special well types such as horizontal wells and multi-bottom wells, the differences in wellbore trajectory, formation contact methods, and engineering complexity place differentiated demands on well control equipment configuration, pressure management, and operational procedures. The following analysis, based on the technical characteristics of different well types, examines the core points of well control management.
Vertical Wells
Vertical wells are characterized by a vertical wellbore trajectory, resulting in short construction cycles and low costs, making them the mainstream well type for conventional oil and gas reservoir development. Their well control management revolves around standardized processes: Standardized Equipment Configuration: Well control devices are selected based on the maximum wellhead pressure. For example, development wells with wellhead pressure below 21 MPa use Class III 21 MPa-level blowout preventer (BOP) kits; exploration wells with pressure between 21-35 MPa require Class II 35 MPa-level equipment; and high-pressure wells (>35 MPa) or deep wells (>4500 meters) require Class I 70 MPa-level equipment. Precise Pressure Control: Drilling fluid density design must cover formation pressure, with an additional safety margin of 0.07-0.15 g/cm³. For example, in an oilfield encountering an abnormally high-pressure layer, real-time monitoring of the equivalent circulating density (ECD) is used. If fluctuations exceed 0.03 g/cm³, drilling is immediately stopped and circulation resumed to avoid well kick risk.
Standardized Operating Procedures: A strict ‘on-duty system’ is implemented, with dedicated personnel monitoring drilling fluid level changes in the wellbore 24 hours a day. An equal volume of drilling fluid is added after every five drill pipes are pulled. One drilling team reduced the stuck-out accident rate by 60% by optimizing the grouting process.
Directional Wells
Directional wells include cluster wells, multi-bottom wells, and horizontal wells. Their large inclination angles and long horizontal sections significantly increase well control difficulty: Wellbore Cleaning and Cuttings Management: Cuttings beds easily form in horizontal well sections, increasing the risk of pumping pressure fluctuations. A horizontal well project successfully controlled the cuttings bed thickness to within 5 cm by combining high-viscosity cutting fluid (viscosity ≥40s) with low-speed drill string rotation (30-50 rpm), thus preventing lost circulation or well kick.
Differentiated pressure system control: Horizontal wells may traverse multiple pressure systems, requiring segmented design of drilling fluid density. For example, in a deep horizontal well encountering a high-pressure water layer, adjusting the drilling fluid density to 1.25 g/cm³ while controlling the tripping speed (≤0.5 m/s) successfully prevented upper leakage and lower blowout accidents.
Special tool configuration requirements: Horizontal wells require high-temperature resistant and wear-resistant well control tools. For example, using a float valve connector combined with a backpressure valve prevents fluid backflow into the drill string; installing a check valve above the drill bit ensures rapid wellhead closure in the dry well state.
Horizontal Wells
Horizontal wells meet technical standards with an inclination angle ≥86° and a horizontal section ≥60 meters. Well control management for horizontal wells faces the following challenges:
Casing Depth and Cementing Quality:The casing should be as close to the horizontal section as possible to enhance wellhead support. One horizontal well project extended the casing depth to 50 meters above the horizontal section and cemented the entire well section, increasing the wellhead pressure-bearing capacity to 70 MPa.
Early Overflow Identification and Handling:Overflow signals in horizontal wells are highly concealed, requiring multi-parameter monitoring to improve early warning capabilities. For example, one platform detected an overflow 30 minutes in advance by analyzing standpipe pressure, mud density, and outlet flow rate data in real time during drilling, providing valuable time for well shut-in and control.
Shear Gate Usage Standards:Due to the complex wellbore trajectory in horizontal wells, the use of shear gates requires greater caution. Well control regulations stipulate that shear gates should only be used in cases of blowout that endanger personnel safety, and operation requires approval from the drilling team leader, supervisor, and higher-level department.
Multi-bottom Wells and Special Well Types
Multi-bottom wells (single wellhead with multiple bottoms) and extended reach wells require customized well control management solutions tailored to project objectives:
Wellhead pressure balancing in multi-bottom wells: Multi-bottom wells require independent pressure control at each bottom through choke manifolds. For example, in one multi-bottom well project, a dual-pressure manifold was installed during the completion phase to conduct pressure tests on both bottoms separately, ensuring packer sealing effectiveness.
Friction management in extended reach wells: Extended reach wells (horizontal displacement ≥ 3000 meters) are prone to drill string buckling or wellhead lift due to high friction. One project controlled wellhead lift to within 10cm by optimizing drilling fluid lubrication (reducing the coefficient of friction to below 0.1) and the wellhead blowout preventer fixing method (using four-corner tension rope reinforcement).
From standardized management of vertical wells to refined control of horizontal wells, the requirements for well control for different well types essentially represent a dynamic definition of the ‘safety boundary.’ With the increasing number of deep wells, ultra-deep wells, and wells with special structures, well control technology is evolving from ‘passive response’ to ‘proactive prevention.’ For example, intelligent well control systems, by integrating pressure monitoring, automatic grouting, and remote decision-making functions, can adjust drilling fluid density and wellhead pressure in real time, reducing well control risks to the lowest level in the industry.
