Well kill
A well kill is a procedure in oil and gas drilling operations used to stop the flow of reservoir fluids into the wellbore or prevent the well from having the ability to flow, typically by circulating out influxes and pumping higher-density drilling fluid to restore hydrostatic balance over formation pressure.[1] This process is essential for maintaining primary well control and responding to kicks, where formation pressure exceeds the hydrostatic pressure of the drilling fluid, potentially leading to blowouts if not addressed.[2] Well kills are performed during drilling, completion, or workover activities, and in emergency scenarios involving producing wells or blowouts, ensuring personnel safety, equipment integrity, and environmental protection.[2] The standard well kill procedure involves shutting in the well using blowout preventers (BOPs), recording shut-in drill pipe and casing pressures, and then circulating kill fluid at a controlled rate while adjusting the choke manifold to maintain bottom-hole pressure and achieve zero surface pressure.[3] Key preparatory steps include calculating the required kill mud density—typically using the formula incorporating original mud density, true vertical depth, and shut-in drill pipe pressure—to ensure the hydrostatic head exceeds formation pressure without fracturing the wellbore.[2] Immediate actions upon detecting a kick, such as stopping the pumps and closing the BOPs, are critical to minimize influx volume and facilitate safe circulation.[2] Common methods for well killing include the Driller's Method, which circulates the influx out using the original mud density while holding constant drill pipe pressure, followed by a second circulation with weighted kill mud; the Wait and Weight Method, which weights up the mud in the pits beforehand and circulates the kill mud in a single operation while maintaining constant bottom-hole pressure; and the Concurrent Method, which simultaneously circulates and weights up the fluid for efficiency in certain scenarios.[4][2] Non-circulation techniques, such as bullheading (pumping kill fluid directly into the formation) or lubricate-and-bleed (alternating small volumes of kill mud with pressure bleeding to displace gas), are employed when full circulation is not feasible, such as in plugged pipes or high-pressure surface conditions.[2] These methods adhere to industry standards like API RP 59, emphasizing pressure monitoring, fluid density adjustments, and contingency planning to mitigate risks.[2]Fundamentals
Definition and Purpose
A well kill is the process of regaining control over a flowing oil or gas well by introducing a kill fluid, typically a weighted drilling mud of increased density, into the wellbore to restore hydrostatic balance and overbalance the formation pressure, thereby ceasing the influx of reservoir fluids such as oil, gas, or water.[1][3] This procedure involves pumping the kill fluid to counteract the underbalanced condition that allows formation fluids to enter the wellbore, effectively stopping uncontrolled flow without causing further complications.[2] The primary purpose of a well kill is to re-establish primary well control during a kick—an influx of formation fluids—ensuring the safety of personnel, equipment, and the environment across various operational phases, including drilling, completion, and production.[2] It facilitates safe preparation for subsequent activities such as workovers or well abandonment by confining well fluids and preventing escalation of the incident.[2] In essence, well kills maintain bottom-hole pressure equilibrium to mitigate hazards, with brief reliance on concepts like hydrostatic overbalance to achieve this without detailed pressure mechanics.[2] Failure to perform a well kill promptly can lead to severe risks, including escalation to blowouts, where uncontrolled releases cause fires, explosions, or surface broaching; formation damage from high-pressure influxes; and equipment failure due to excessive pressures.[2] Such incidents also pose threats of environmental damage through spills of hydrocarbons and potential loss of life from associated hazards like struck-by incidents or vehicle crashes in chaotic conditions.[5] Under API Recommended Practice 59, well kills are required as part of well control operations for any detected kick, which represents an influx exceeding safe hydrostatic limits, to prevent blowouts and ensure operational integrity.[2]Historical Overview
The development of well kill techniques began with early challenges in controlling uncontrolled well flows during the nascent oil industry. The 1901 Spindletop blowout in Texas marked one of the first major documented well control incidents, where the well gushed uncontrollably for nine days, releasing an estimated 900,000 barrels of oil (approximately 100,000 barrels per day) before it could be capped.[6] This event highlighted the absence of effective pressure management tools, prompting initial experiments with mud-based methods in the 1910s and 1920s. Drilling fluids, commonly referred to as mud, were first introduced around 1913 specifically for subsurface pressure control to prevent reservoir influxes during rotary drilling.[7] By the 1920s, the addition of weighting agents like barite to these fluids enabled better hydrostatic balance, laying the groundwork for rudimentary kill operations.[8] Mid-20th-century advancements formalized these practices amid growing offshore exploration in the Gulf of Mexico. The introduction of blowout preventers (BOPs) in 1922 by James S. Abercrombie and Harry S. Cameron provided a mechanical means to seal the wellbore, reducing the reliance on ad hoc mud applications during blowouts.[9] Following World War II, incidents in the Gulf of Mexico during the 1940s expansion of offshore drilling underscored the need for specialized kill muds, leading to the widespread adoption of mud engineers by the mid-1940s to optimize fluid properties for pressure equalization and well stabilization.[10] This era saw the evolution of kill mud formulations with precise density control to overbalance formation pressures safely. In the 1960s, the American Petroleum Institute (API) issued Bulletin D13 in 1966, establishing early standardized guidelines for BOP installation and well control procedures, including kill mud usage, which influenced industry practices globally.[11] The 1979 Ixtoc I blowout in Mexico's Bay of Campeche exemplified the limitations of early well control techniques, prolonging the spill for nearly 10 months until relief wells succeeded.[12] The modern era accelerated innovations following the 2010 Deepwater Horizon disaster in the Gulf of Mexico, which killed 11 workers and released over 4 million barrels of oil, prompting enhanced regulatory scrutiny and advanced modeling of fluid circulation and pressure responses.[13] This event also solidified relief well protocols as a primary contingency, with two relief wells drilled to intersect and cement the Macondo well. In the 2020s, focus has shifted to automation and real-time monitoring systems, such as managed pressure drilling technologies that detect influxes and automate shut-in responses, improving kill efficiency and reducing human error in complex environments.[14]Principles
Pressure Dynamics
In well control operations, hydrostatic pressure represents the static downward force exerted by the column of drilling fluid within the wellbore, which acts to counterbalance subsurface formation pressures. This pressure is calculated using the formula P_{\text{hydro}} = \rho \cdot g \cdot h, where \rho is the fluid density, g is the acceleration due to gravity (approximately 9.81 m/s²), and h is the true vertical depth of the wellbore.[15] Maintaining adequate hydrostatic pressure is essential to prevent uncontrolled fluid influx from the formation, as it provides the primary barrier against reservoir fluids entering the well.[4] Formation pressure, also known as pore pressure, is the pressure of fluids within the pores of the reservoir rock, which can drive an influx into the wellbore if not properly overbalanced. This pressure typically arises from geological processes and can vary, with abnormal values often ranging from 0.8 to 1 psi/ft in overpressured zones.[16] The goal of well control is to achieve overbalance, where the hydrostatic pressure from the kill fluid exceeds the formation pressure gradient, thereby stabilizing the well and halting any influx.[17] Failure to maintain this overbalance results in a kick, defined as an unintended entry of formation fluids due to borehole pressure falling below pore pressure.[17] Shut-in pressures serve as critical indicators of underbalance during well control assessments. Shut-in drill pipe pressure (SIDPP) measures the difference between the true formation pressure and the hydrostatic pressure in the drill string, providing a direct gauge of the influx magnitude; it is given by formation pressure minus drill string hydrostatic pressure.[18] Shut-in casing pressure (SICP), observed on the annular side, reflects the combined effects of formation pressure, hydrostatic contributions, and any gas migration, often exceeding SIDPP due to these factors.[19] These pressures stabilize after closing the blowout preventer, allowing operators to quantify the imbalance before initiating corrective measures.[20] Pressure conditions in a well transition between dynamic and static states, particularly during operational activities like tripping. In static conditions, pressures equilibrate with no fluid movement, relying solely on hydrostatic balance to contain formation fluids. Dynamic conditions arise during pipe movement, where surge pressures—increased bottomhole pressure from running pipe downward—can exceed formation fracture gradients, risking losses, while swab pressures—reduced bottomhole pressure from pulling pipe upward—can drop below pore pressure, inducing influxes.[21] These swab and surge effects during tripping highlight the need to manage transient pressure fluctuations to prevent well control events, as high tripping speeds amplify pressure variations.[22]Fluid Mechanics
Kill fluids, essential for restoring hydrostatic balance during well control operations, exhibit specific rheological properties that ensure effective pressure management and operational stability. Density, typically expressed in pounds per gallon (ppg) or specific gravity (sg), is the primary property governing hydrostatic control, as it directly determines the fluid column's ability to counteract formation pressures and prevent further influx.[23] Plastic viscosity, representing the resistance to flow under shear, and apparent viscosity, which accounts for non-Newtonian behavior, are critical for minimizing pressure surges during circulation and facilitating controlled influx displacement.[24] Gel strength measures the fluid's thixotropic nature, allowing it to suspend cuttings and weighting agents when static, while yield point quantifies the stress required to initiate flow, aiding in hole cleaning by promoting solids transport without excessive torque.[25] These properties collectively enable kill fluids to maintain well integrity, with optimal values—such as yield points around 10-20 lb/100 ft²—balancing suspension and pumpability.[26] Influx fluids introduced during kicks complicate well control due to their distinct physical characteristics, influencing detection and migration dynamics. Gas solubility in the drilling fluid, particularly high in oil-based muds, can delay surface detection by dissolving into the liquid phase, reducing pit volume gains and masking early kick indicators.[27] Oil viscosity from hydrocarbon influxes increases the overall fluid resistance, potentially exacerbating migration rates under differential pressures, while water cut—the proportion of water in the influx—alters emulsion stability and can lead to faster gas breakout in water-based systems, aiding but complicating real-time monitoring.[28] These factors necessitate rapid assessment of influx composition to adjust kill strategies, as high-solubility gases may require extended circulation to fully remove dissolved components.[29] In the annular space during well killing, flow regimes significantly affect pressure profiles and fluid performance. Laminar flow predominates at lower velocities, providing predictable friction but limited hole cleaning, whereas turbulent flow, induced by higher pump rates, enhances solids removal through increased shear but elevates friction losses.[30] These losses, arising from viscous drag along the wellbore walls, contribute to the equivalent circulating density (ECD), which exceeds static density and must be managed to avoid formation fracturing.[31] Transitioning between regimes requires rheological tuning to optimize ECD without compromising control.[30] A key challenge in kill muds is barite sag, where weighting particles settle, causing localized density variations that undermine hydrostatic balance and risk well control incidents. This phenomenon is exacerbated in deviated wells and high-temperature environments, leading to potential stuck pipe or influx recurrence.[32] Mitigation involves incorporating polymers, such as xanthan gum or carboxymethyl cellulose, which enhance suspension through increased yield point and viscoelasticity, stabilizing the fluid without significantly raising viscosity.[33] Studies demonstrate that polymer-treated muds can reduce sag factors to below 0.53, ensuring uniform density distribution during static and dynamic conditions.[34]Calculations
Kill Mud Weight Determination
Kill mud weight (KMW) determination is a critical initial step in well control operations following a kick, aimed at calculating the drilling fluid density required to restore overbalance and balance formation pressure at the bottomhole. This calculation uses the shut-in drill pipe pressure (SIDPP), which reflects the underbalance condition, along with the original mud weight (OMW) and true vertical depth (TVD). The standard formula for KMW in pounds per gallon (ppg) is given by: \text{KMW} = \text{OMW} + \frac{\text{SIDPP}}{0.052 \times \text{TVD}} where SIDPP is in pounds per square inch (psi), TVD is in feet, and the factor 0.052 converts the pressure gradient to equivalent mud weight in ppg.[35][36] Once the base KMW is computed, adjustments are applied to account for operational uncertainties, including the addition of a safety margin typically ranging from 0.2 to 0.5 ppg to ensure sufficient overbalance against potential pressure fluctuations. Additionally, the final KMW must respect maximum density limits to prevent formation fracturing and mud losses, often kept below 18 ppg depending on the fracture gradient at the casing shoe. Rounding up the calculated value to the nearest 0.1 or 0.2 ppg is a common practice to incorporate this margin and facilitate mixing.[37][18][38] For illustration, consider a scenario with an OMW of 10 ppg, SIDPP of 500 psi, and TVD of 10,000 ft. Substituting into the formula yields: \text{KMW} = 10 + \frac{500}{0.052 \times 10,000} = 10 + \frac{500}{520} \approx 10 + 0.96 = 10.96 \text{ ppg} This value would then be rounded up, say to 11.2 ppg, incorporating a safety margin.[36] In gas kicks, where influx migration can complicate pressure readings, SICP may be used for conservative KMW estimates if SIDPP is unavailable or unreliable due to gas migration effects.[19]Circulation Parameters
Circulation parameters are essential computations in well kill operations, determining the volumes, rates, and durations needed to circulate kill fluids through the wellbore while maintaining well integrity. These parameters rely on the predetermined kill mud weight as an input to ensure the fluid density supports pressure balance during circulation. Key calculations include volumes for the drill string and annulus, pump outputs, and flow rates optimized to prevent exceeding equivalent circulating density (ECD) limits that could fracture the formation. The total pump strokes required for a complete circulation of kill fluid are given by the formula: \text{Total strokes} = \frac{\text{Annular volume} + \text{Drill string volume}}{\text{Pump output factor}} where volumes are in barrels (bbl) and the pump output factor is in bbl/stroke, typically accounting for pump efficiency. This ensures the kill fluid displaces the original mud and influx throughout the system. The pump rate, expressed in barrels per minute (bpm), is selected conservatively—often as the slow circulating rate (SCR)—to limit ECD below the formation's fracture gradient, thereby avoiding lost circulation while achieving effective influx removal.[39][40] Kill volume is calculated to provide sufficient fluid for full circulation, commonly as 1.5 times the sum of the drill pipe volume and 80% of the casing capacity, incorporating a safety margin for surface lines and potential losses. The circulating time is then estimated as: \text{Circulating time} = \frac{\text{Kill volume}}{\text{Pump rate}} This provides the duration in minutes or hours for the kill operation, aiding in planning rig time and resource allocation. In high-pressure high-temperature (HPHT) wells, safety factors are added to the kill volume and time estimates to account for fluid and gas compressibility effects, which can alter effective volumes under elevated conditions. To ensure adequate hole cleaning during kill circulation, annular velocity is computed using: \text{Annular velocity} = \frac{\text{Pump rate} \times 24.5}{D_h^2 - D_p^2} where pump rate is in gallons per minute (gpm), D_h is the hole diameter in inches, and D_p is the pipe outer diameter in inches, yielding velocity in feet per minute (ft/min). This parameter helps verify that cuttings and influx are transported effectively without excessive ECD buildup. Pressure monitoring during these circulations confirms the operation stays within safe limits, as detailed in pressure dynamics principles.[39]Primary Methods
Forward Circulation
Forward circulation is a primary technique in well control operations used to regain hydrostatic balance in a well experiencing an influx or kick by pumping kill mud downward through the drill string and upward through the annulus to displace the lighter influx fluids.[41] This method requires the blowout preventer (BOP) to remain closed to contain wellbore pressures during the process, ensuring safe circulation while monitoring for any pressure anomalies.[42] The procedure begins with shutting in the well to stabilize pressures and assess the influx volume. Kill mud weight (KMW) is then calculated based on shut-in pressures to provide sufficient hydrostatic head to overbalance the formation.[41] Kill mud is pumped down the drill pipe at a controlled rate, typically 20-40 strokes per minute (spm) depending on bit nozzle sizes and frictional losses, while the choke is adjusted to maintain constant bottomhole pressure.[43] The influx is circulated out through the annulus returns, with pressures monitored to ensure stability until the well is fully killed and hydrostatic control is restored.[42] Variants of forward circulation include the Driller's method, which first circulates the original mud to remove the influx before introducing kill mud, and the Wait-and-Weight method, which pumps kill mud immediately upon starting circulation; detailed procedures for these are covered in specific applications.[41] This technique leverages existing rig mud pumps for efficient operation and is particularly effective for low-volume kicks where full displacement is feasible without excessive volumes.[42] However, it carries risks such as potential washouts or hole enlargement in weak formations due to elevated annular velocities and pressures during circulation.[44]Reverse Circulation
Reverse circulation is a well kill method in which kill weight mud is pumped down the annulus and returns to the surface through the drill string, entering the wellbore at an open bit, circulating valve, or similar tool at the bottomhole assembly.[45] This approach is particularly suitable for high-pressure scenarios where conventional forward circulation might impose excessive bottomhole stress, risking formation fracture.[46] The procedure begins by aligning the rig's pumps and manifolds to direct flow into the annulus while monitoring shut-in pressures; circulation is initiated at a controlled rate, displacing influx fluids upward through the drill string to the surface via the standpipe or kelly hose, until the well is fully killed with kill mud.[45] Key advantages include reduced equivalent circulating density (ECD) due to lower fluid velocities in the larger annular space compared to forward circulation's annular returns, which minimizes bottomhole pressure surges in sensitive formations. It also enables faster influx removal, lower peak casing pressures, and reduced cumulative pit volume gains, making it efficient for deep wells or gas kicks.[46] However, disadvantages encompass the necessity for an open bottomhole configuration without packers or closed nozzles, which may not be feasible in all completions, and potential erosion of the drill string interior from high-velocity returns carrying abrasive influx particles.[45] During monitoring, casing pressure typically rises initially from annular friction losses as circulation starts, then stabilizes or declines as the influx is displaced and kill mud reaches the bottomhole, providing a clear indicator of progress.[47] This method uniquely aids gas migration control by confining the lighter gas influx within the drill string, preventing its expansion in the annulus and reducing risks to surface equipment and casing integrity.[45] Circulation rates are constrained by annular friction pressures to avoid exceeding formation fracture gradients, often requiring adjustments based on well geometry and fluid properties.[45] Reverse circulation is commonly applied in snubbing operations, where tubing or drill pipe is forcibly inserted into a pressurized well, allowing simultaneous influx displacement while maintaining well control through constant bottomhole pressure.[48]Bullheading
Bullheading is a non-circulating well kill technique that involves pumping kill-weight mud (KMW) directly down the tubing or drill string to displace the influx back into the formation, achieving overbalance without requiring returns to the surface.[49] The procedure begins by connecting high-pressure pumps to the tubing head after shutting in the well using the blowout preventer (BOP), ensuring all connections are secure and pressure-tested. KMW, calculated to provide sufficient hydrostatic overbalance as detailed in kill mud weight determination, is then pumped at the maximum allowable rate—typically limited by equipment and formation fracture gradient—until either returns are observed at the surface or stable overbalance is confirmed by stabilized pressures, with no annulus returns necessary during the process.[50] Monitoring of tubing and casing pressures is critical throughout to ensure the operation stays within maximum allowable annulus surface pressure (MAASP) limits.[51] This method finds primary applications in live well interventions and workover operations, particularly when the annulus is plugged or circulation paths are obstructed, preventing conventional methods.[49] The required volume of KMW is generally the tubing capacity plus an allowance for formation absorption to ensure complete displacement of the influx and establishment of overbalance.[52] It is especially effective for high-rate gas wells, where rapid pumping outpaces gas migration to maintain control.[51] Key risks include formation fracturing if the pumping rate exceeds the fracture gradient, potentially leading to losses or underground blowouts, necessitating careful rate selection based on pre-calculated limits.[53] A distinctive pressure signature during successful bullheading is a linear increase in tubing pressure, reflecting the progressive buildup of hydrostatic head from the pumped KMW without significant influx migration.[54] Following the Deepwater Horizon incident, bullheading principles were applied in top kill attempts on subsea wellhead stacks, pumping mud through choke and kill lines to counteract severe inflows, as described in subsequent static kill operations.[55][56]Specialized Techniques
Lubricate and Bleed
The lubricate and bleed technique is a secondary well control method employed to manage gas influxes when full circulation is not feasible, such as during stripping or when pipe is stuck across the blowout preventer (BOP). It involves iteratively injecting small volumes of kill-weight mud into the annulus to displace lighter influx fluids downward, followed by controlled bleeding of the influx at the surface to restore pressure equilibrium. This process leverages the density difference between the kill mud and the influx, allowing the heavier mud to sink and gradually replace the gas without establishing conventional circulation.[57][58] The procedure begins with shutting in the well and recording shut-in pressures. Small slugs of kill mud, typically 5-10 barrels, are then pumped slowly into the annulus, increasing surface pressure as the mud compresses the gas bubble per Boyle's Law (P₁V₁ = P₂V₂). After allowing time for the mud to swap positions with the gas—usually monitored via pressure stabilization—the operator bleeds off an equal volume of influx fluids at the choke manifold until the surface pressure returns to the hydrostatic equivalent of the injected mud volume, often 50 psi increments. This cycle is repeated, with each iteration reducing the gas volume until the influx is fully displaced or surface pressure falls below the maximum allowable surface casing pressure (MAASCP). If mud appears during bleeding, the process stops to avoid further influx.[59][57] Key advantages include minimizing pressure fluctuations that could damage snubbed pipes or equipment during live well interventions, making it suitable for underbalanced drilling operations or wireline logging where maintaining well integrity is critical without full kill. Unlike passive methods, it actively removes gas, reducing annulus pressure buildup and preventing sustained casing pressure issues. The technique is particularly effective for handling gas caps or migrating influxes, as it allows controlled surface disposal of hydrocarbons while preserving pressure balance as detailed in pressure dynamics principles.[57][48][60] Monitoring focuses on maintaining bottomhole pressure 50-100 psi above formation pore pressure to avoid further influx or fracturing, achieved by tracking surface pressure rises (indicating remaining gas volume) and ensuring bleed volumes match lubricated slugs. Flow checks and pit volume totals confirm no additional influx, with operations halting if pressures exceed MAASCP or if the volumetric method proves more appropriate for passive gas migration.[59][57]Volumetric Method
The volumetric method is a secondary well control technique designed to manage migrating gas influxes in situations where conventional circulation is impractical, such as pump failures, stuck pipe, or off-bottom conditions, by maintaining constant bottomhole pressure through passive surface interventions. This approach allows the gas to migrate to the surface under controlled conditions without inducing further influx or formation damage.[2] The procedure begins with shutting in the well, stopping the pump, and closing the blowout preventer while recording initial shut-in pressures and pit volumes. Operators monitor casing pressure and pit volume gains as the gas migrates upward and expands; a controlled pressure increase (typically 50-200 psi safety factor plus a pressure increment, e.g., 100 psi) is permitted to account for migration. To restore pressure to the target level, a calculated mud increment is bled from the annulus through the choke manifold into a measured volume device, equivalent to the volume displaced by the expanding gas. This bleeding step is repeated cyclically—waiting for the next pressure rise before bleeding again—until the gas reaches the surface, indicated by a sudden pressure drop and flow changes at the choke. Pit volumes are monitored for gains due to gas expansion. Once the influx is cleared, the well is shut in, and a primary kill method, such as the driller's method, is initiated to restore full control.[2][61] Key advantages include the absence of active pumping, which minimizes stress on weak formations and reduces the risk of lost circulation, while enabling safe handling of gas migration in constrained scenarios. The method relies on surface monitoring to adjust for gas expansion, with the migrated gas volume at surface approximated by the formula V_{\text{surface}} = V_{\text{initial}} \times \frac{\Delta P}{P_{\text{surface}}}, where V_{\text{initial}} is the initial influx volume, \Delta P is the pressure differential from the influx depth to surface, and P_{\text{surface}} is atmospheric pressure; this derives from Boyle's law for ideal gas behavior under isothermal conditions.[2][18] Limitations of the volumetric method include its relatively slow pace for large-volume kicks, as the cyclic bleeding process can take hours, potentially allowing prolonged pressure exposure; it is best suited for minor influxes in shallow gas zones or when pumping equipment is unavailable. Precise measurements of pit volumes and pressures are essential, as inaccuracies can lead to over- or under-bleeding and compromise bottomhole pressure control.[2][62] This technique is standardized in API Recommended Practice 59 for offshore well control operations, particularly for subsea blowout preventer systems where choke line dynamics must be considered, and it proves particularly effective for minor gas influxes by preventing escalation without circulation.[2][62]Applications in Drilling
Driller's Method
The Driller's Method is a two-circulation forward well-kill technique employed during drilling operations to regain control after detecting a kick, where the influx is first circulated out using the original mud weight (OMW) while maintaining constant bottom-hole pressure, followed by a second circulation with kill mud weight (KMW) to restore hydrostatic balance. This method relies on data from the initial shut-in, such as shut-in drill pipe pressure (SIDPP), to determine KMW without delaying circulation for mud preparation. It is particularly suited for scenarios requiring immediate action to prevent further influx migration. The procedure follows these key steps:- Upon kick detection, shut in the well using the blowout preventer (BOP), record stabilized SIDPP, shut-in casing pressure (SICP), and pit gain, then establish circulation at the predetermined kill rate using OMW while holding drill pipe pressure constant at initial circulating pressure (ICP = SIDPP + slow circulating rate pressure, SCRP) to maintain bottom-hole pressure.[2][45]
- Circulate the influx out of the wellbore, monitoring and adjusting the choke to keep drill pipe pressure constant as the lighter influx (e.g., gas or formation fluid) is displaced to the surface; once the influx is removed (confirmed by stable pressures and no further pit gain), cease circulation briefly to mix and prepare KMW based on SIDPP data from the first circulation.[2][45]
- Resume circulation with the newly prepared KMW at the kill rate, holding drill pipe pressure constant at ICP until the kill mud reaches the bit, then transitioning to maintain final drill pipe pressure constant at FCP until the kill mud returns to the surface, verifying control with zero pressures before resuming operations.[2][45]