As a highly effective organic salt treatment agent, sodium formate serves multiple functions in water-based drilling fluids, including shale inhibition to prevent wellbore collapse, density adjustment, reservoir protection, and enhancing resistance to high temperatures and salinity. Its addition rate must be precisely controlled based on the specific fluid system type, well depth, formation conditions, and target density. The conventionally recommended dosage ranges from 5% to 20%, with practical application rates typically falling between 10% and 20%. Excessive addition can easily lead to salt-sensitivity damage, increased costs, and fluctuations in rheological properties, while insufficient addition prevents the agent from achieving its intended efficacy.
In conventional polymer-based drilling fluids, sodium formate is typically added within a range of 5% to 10%. Its primary purpose in this context is to enhance shale inhibition, stabilize the wellbore, and minimize hydration-induced swelling and sloughing. This dosage is suitable for vertical wells and shallow directional wells; it is compatible with other treatment agents—such as xanthan gum, phenolic resins, and emulsified asphalt—and serves to reduce fluid loss and bolster the mud's resistance to contamination while maintaining stable rheological properties. Consequently, it represents the mainstream choice in scenarios where cost-effectiveness is a priority.
In solid-free formate drilling fluids and horizontal well systems, the addition rate of sodium formate is increased to between 15% and 20%, a range widely recognized as the industry standard. An addition rate of 20% can raise the density of a clear water-based fluid to 1.11 g/cm³, thereby meeting the drilling requirements for low-pressure oil and gas reservoirs and horizontal well sections. This approach facilitates "clean drilling" by minimizing reservoir damage while ensuring that the core permeability recovery rate exceeds 85%. In complex geological formations—such as those encountered in shale gas extraction or salt-cavern gas storage projects—the addition rate may be temporarily increased to between 20% and 30% to specifically enhance wellbore stability and resistance to salt intrusion; however, a prior assessment of the risks associated with rock salt dissolution and salt sensitivity is required in such instances.
When utilized as a weighting agent, the addition rate of sodium formate correlates directly with the target fluid density: achieving a density of 1.08 g/cm³ typically requires approximately 16% sodium formate; 1.11 g/cm³ requires approximately 20%; and a density of 1.20 g/cm³ can be achieved with an addition rate of 35%. Due to limitations regarding cost and density ceilings, when the required density exceeds 1.40 g/cm³, it is recommended to incorporate inorganic weighting agents—such as barite or iron ore powder—rather than relying solely on sodium formate, which would drive up costs unnecessarily.
On-site addition must adhere to the principle of "prepare solution first, measure precisely, and add gradually." Priority should be given to preparing a 50% aqueous solution and adding it slowly; this prevents issues such as uneven dissolution and localized salt precipitation that can arise from the direct addition of dry powder. Simultaneously, viscosity, shear strength, fluid loss, and density must be monitored in real-time. For high-temperature, deep-well applications, hot-rolling recovery tests should be conducted to ensure that the dosage is optimally matched to the specific fluid system.
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