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Requirements to Complete a LOT (Leak-Off Test) or FIT (Formation Integrity Test)Hole Conditions:The new casing shoe must be drilled out, and an additional 5 to 30 feet of formation must be penetrated.A sample from the new formation should be circulated up to verify the formation has been drilled.Circulate the hole with mud until the shakers are free of cement and cuttings.Mud Properties:The mud must be clean, consistent, have low gel strengths, and have a known mud weight.If there is uncertainty about the mud weight consistency, the test should not be conducted until you are certain the mud properties are the same throughout the active system.Accurate calculation of hydrostatic pressure is crucial for the test’s validity.Excessive gel strengths may negatively impact the results of the LOT/FIT.Line Up:LOT/FIT tests require a high-pressure, low-volume pump, typically a cement pump.The pump should be lined up to pump both down the drill pipe and into the annulus.A Blowout Preventer (BOP) must be closed to seal the annulus, and BOP side outlets opened to pressurize the choke line against a closed choke.Valves should be positioned to allow the recording of both drill pipe and casing pressure.Testing through a mud motor or non-return valve should be avoided if possible.Instrumentation:The driller must be able to record cumulative pump strokes or volume pumped, drill pipe pressure, and casing pressure.Accurate pressure measurement requires recently calibrated pressure gauges and large-scale charts mounted on a manifold.In some cases, downhole pressure gauges may be used for better results, especially when using high mud weights or compressive base fluids.Pump Rates:The pump rates should be slow, typically ½ barrel per minute (bbl/min) or less, to ensure accurate readings and minimize risks during the test.These requirements ensure a successful and accurate LOT or FIT, providing essential data for well integrity and pressure management during drilling.For more information on LOTs and other Well Control subjects, read my Well Control Manual at: https://learn-well-control.com/product/well-control-manual-by-edwin-ritchie/ Read More

Dynamic MAASP and Kill Speed: Understanding Pressure Losses During Well ControlWhen calculating the Maximum Allowable Annular Surface Pressure (MAASP), we typically do so under static conditions. However, once the pumps are started during a well kill operation, we immediately face annular pressure losses. These losses, which occur as fluids move through the wellbore, add to the pressure and increase the risk of fracturing or breaking down exposed formations. To minimize this risk, it’s important to manage these dynamic pressures by controlling the kill rate (pump rate), which helps to reduce the additional pressure applied during the kill process.The Role of Dynamic Pressure LossesIn deep, slim-hole wells, annular pressure losses (APL) can become significant, even at slow kill rates. If not properly managed, this pressure could cause the shoe (the bottom part of the casing) to break down. If you know the annular pressure loss at the shoe, you can adjust the casing pressure accordingly to offset this loss. However, this action reduces the MAASP by the same amount, leading to what is known as the Dynamic MAASP.Calculating the dynamic MAASP can be complex, especially when determining annular pressure loss accurately. As a result, dynamic MAASP is not commonly used in surface stack operations where APL is harder to measure.Subsea Wells and Choke Line FrictionSubsea wells are a different story. In these wells, there can be significant dynamic pressure losses through the choke line. Much like annular pressure loss, these losses contribute to the overall pressure in the wellbore. The good news is that choke line friction is easy to measure, which makes it possible to account for it when adjusting casing pressure.To avoid exceeding MAASP, it’s common practice to reduce the casing pressure by the amount of choke line friction as the pumps are brought online during a kill operation. This adjustment effectively reduces the dynamic MAASP by the same amount as the choke line friction.Calculating Dynamic MAASPThe equation for calculating the Dynamic MAASP is simple:Dynamic MAASP (psi) = Initial MAASP (psi) – Choke Line Friction (psi)Example Calculation:Let’s look at an example of a subsea well.Initial MAASP = 1638 psiChoke Line Friction at 40 SPM = 160 psiTo calculate the Dynamic MAASP when bringing the pumps to 40 strokes per minute (SPM) at the start of the kill:Dynamic MAASP = Initial MAASP (1638 psi) – Choke Line Friction (160 psi)Dynamic MAASP = 1638 psi – 160 psi = 1478 psiSo, after adjusting for choke line friction, the new dynamic MAASP pressure would be 1478 psi.ConclusionManaging dynamic pressures during a well kill operation is critical to preventing damage to the wellbore and formations. By understanding how to adjust the MAASP for annular pressure losses and choke line friction, operators can maintain control of the well while minimizing the risks associated with pressure increases.For more information on dynamic MAASP, you may refer to my Well Control Manual at: https://learn-well-control.com/product/well-control-manual-by-edwin-ritchie/ Read More

Close-In Procedures: Guidelines for Shutting the Well InA close-in procedure is a set of actions taken to safely shut in a well and stop the flow if primary well control is lost. It involves quickly implementing secondary barriers to regain control. The procedure should meet the following criteria:Familiar to the Crew – The team should be well-acquainted with the procedure.Industry-Recognized – The method should be widely accepted in the industry.Appropriate for Current Conditions – The procedure must be suitable for the specific situation.Regularly Practiced – It should be part of routine BOP (Blowout Preventer) drills.Options for Closing the Well InThere are two main methods for closing a well in:Soft Close-InHard Close-InThe steps to shut in will vary depending on the rig’s current activity, such as drilling, tripping in/out, running casing, cementing, wireline operations, or running a completion string. However, the general principle is to shut in from top to bottom. Start by closing the top preventer, and if it fails, immediately close the next preventer in the stack.Key Steps in the Close-In ProcedureShut in Early and Quickly: The goal is to minimize the influx volume as soon as possible. The sooner the well is shut in, the better the chances of preventing further complications.Crew Awareness: Every crew member must be vigilant for signs of a kick and immediately notify the driller if any warning signs appear.Flow Diversion: If the well is to remain shut in for an extended period, it is good practice to divert the flow line to the trip tank and set an alarm.Consequences of a Larger InfluxIf the influx is large, it reduces the hydrostatic pressure in the annulus, assuming the influx is lighter than the well fluid. As the hydrostatic pressure drops, the wellbore pressures above the influx increase. Higher pressures in the open wellbore raise the risk of breaking through the weakest formation, which could lead to:Lost circulationUnderground blowoutsPossible surface blowoutsAdvantages of Early Kick DetectionThe key to minimizing the risk of a kick escalating to an uncontrolled blowout is early detection and taking action as quickly as possible. Early kick detection offers the following advantages:Minimizes Kick Volume: The sooner you shut in, the less influx there will be.Minimizes Wellbore Pressures: Early shut-in reduces the pressure buildup in the wellbore.Reduces the Risk of Losses: Less influx means less chance of losing control.Prevents Damage to Preventer Rubbers: If a kick is not shut in quickly, the flowing well may damage the preventer rubbers, making it harder to secure the well.For more information on shut-in methods, refer to my Well Control Manual at:Well Control Manual V2.6 by Edwin Ritchie What is Primary Well Control? Primary well control is preventing formation fluids from entering into the wellbore by keeping the hydro- static pressure equal to, or greater than, the formation pressure Read More

Understanding Positive Kick IndicatorsA positive kick indicator is a clear sign that the well has taken in a kick, meaning there is an influx of gas or fluid into the wellbore. Recognizing these indicators quickly is critical, as it helps the driller take immediate action to secure the well and minimize the volume of the influx.Three Main Positive Kick Indicators of a Gas Kick:Unaccounted Pit Volume GainA sudden increase in the pit volume without an obvious explanation is a sign of a kick.Increased Flow with Constant Pump SpeedIf the flow rate increases while the pump speed remains unchanged, this could indicate that a kick has occurred.Flowing with Pumps OffIf the well begins to flow despite the pumps being turned off, this is a key indicator of a kick.However, for a indicator to be positive, it’s essential to rule out other potential causes, such as:Thermal expansion or “U-tubing” of the mudRig heave or other rig movementsBallooning or breathing formations (when formations expand and contract)Liquid Kick Positive IndicatorsThe three primary positive kick indicators also apply to a liquid kick, where fluid (typically mud) enters the well. In addition to these indicators, there are some secondary indicators that may suggest a liquid kick:A slight decrease in the density of the mud returning from the well (though typically not significant and may not be immediately noticed.)A small increase in the string weightChanges in the chloride content of the mud (requires a chloride test)An increase in rotary torqueContaminated mud appearing on the shaker after circulating the well (bottoms up)Interestingly, liquid kicks may not always cause an increase in casing pressure. In some cases, casing pressure may even decrease while the kick is being circulated up the wellbore.Positive Indicators During TrippingWhen tripping, certain signs may indicate a potential kick:Less mud required to fill the hole: If less mud is needed to fill the hole than expected, it could mean the well has taken an influx.More mud returning to the trip tank: If more mud than expected returns to the trip tank when running into the well, this may indicate an influx.Flowing with the pumps off: Like the earlier indicator, if the well starts to flow without pump activity, it’s a strong signal of a kick.Flowing up the drill string: If flow is observed in the drill string when no float valve is present, this is another positive indicator. However, before concluding it’s a kick, be sure to rule out potential causes such as:U-tubing due to cuttings in the annulusFlowback from ballooning formationsThermal expansion, especially in oil-based mudsFlowback from drilling with a compressible fluid, which may expand after the pumps are turned offSummary:Positive kick indicators help identify if a kick has occurred, allowing for quick action to control the well. By recognizing these signs and ruling out other causes, well operators can take the necessary steps to manage the influx and prevent well control issues.The correct action to tale in response to a positive indicator is to immediately secure the well.For more information on positive kick indicators Read More

When do you use TVD vs MD on a Kill Sheet?Use True Vertical Depth (TVD) when calculating:Hydrostatic pressureFracture pressureFormation pressure Use Measured Depth (MD) when calculating:Mud volumesPump pressure lossesDrill string lengthHydraulic delayTVD is essential for pressure-related calculations, while MD is used for volume and equipment-related calculations. Always ensure you’re using the correct depth type for each calculation.For more information about filling out Kill Sheets, refer to my Well Control Manual at: Well Control Manual Read More