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Trapped Pressure in the SIDPP Trapped pump pressure can significantly impact the accuracy of shut-in pressure readings during kick handling. Here’s a breakdown of the key points related to trapped pressure: Cause of Trapped Pressure: Trapped pressure typically occurs when the driller does not shut down the pumps before closing the Blowout Preventer (BOP). This results in pressure being trapped in the system, leading to abnormally high shut-in pressures. Impact on SIDPP and SICP: The trapped pressure causes both the Shut-In Drilling Pipe Pressure (SIDPP) and Shut-In Casing Pressure (SICP) to read higher than expected. The increase in pressure is equal to the trapped pressure, skewing the kick data. Detecting Trapped Pressure: Bleed-Off Method: You can check for trapped pressure by slowly bleeding off less than 1 barrel of fluid through the manual choke. This should reveal a permanent drop in the SIDPP, indicating the presence of trapped pressure. Equal SIDPP and SICP: If the supervisor traps pump pressure after circulating out the influx, the SIDPP and SICP will be equal. Both pressures will be higher than the original SIDPP, which is caused by the trapped pressure. The trapped pressure should be bled off before proceeding with further operations. Post-Kill Scenario: After successfully killing the well, if the supervisor traps pressure, the shut-in pressures (SIDPP and SICP) will match the trapped pressure. This is normal and doesn’t indicate a second influx of gas or fluid. However, you must confirm the well is dead before opening the BOP, and the trapped pressure should be carefully bled off. Other Sources of Trapped Pressure: Bumping the Bit Float: When determining the SIDPP, bumping the bit float can also cause trapped pressure. Unexpected Injection: Any unexpected injection into the well during operations could result in trapped pressure. In conclusion, trapped pump pressure can give misleading shut-in pressure readings, leading to possible misinterpretations during well control operations. Therefore, it’s essential to detect and bleed off any trapped pressure to ensure accurate data and proper well control. For more information on trapped pressure, or any other well control issues, consult my Well Control Manual at: https://learn-well-control.com/product/well-control-manual-by-edwin-ritchie/ Read More

Gas Migration in Cement: Challenges and Solutions In Canada, it is estimated that approximately 57% of shallow to moderate-depth wells experience leaks after primary cementing, which highlights a significant challenge in ensuring effective zonal isolation. Key Technologies for Achieving Zonal Isolation During Cementing Stable Wellbore Conditions Achieving a stable wellbore, free from fluid losses or gains, is crucial before running casing. A consistent wellbore environment reduces the risk of gas migration during cementing. Adequate Annular Circulating Flow Clearances Ensuring adequate circulating flow clearances, particularly when selecting the bit size in relation to the intended casing size, is vital. For situations involving liner overlap, expandable casing may help avoid cement channeling in tight annular spaces. Proper Spacer Design The design of spacers, including their weight and volume, is essential for ensuring effective displacement of drilling fluids and preventing contamination of the cement slurry. Casing Centralization Correct casing centralization ensures even cement placement. It’s important to use neither too few nor too many centralizers, as either extreme can affect the quality of the cement job. Effective Drilling Fluid Conditioning Well-conditioned drilling fluids are critical for efficient mud removal and cement displacement. The proper conditioning ensures a clean wellbore and effective bonding between cement and the formation. Tripping Best Practices Following best practices when tripping both drill pipe and casing minimizes the risk of disturbing the wellbore and creating channels for gas migration. Optimal Drilling Techniques Employing sound drilling techniques throughout the well construction process contributes to minimizing wellbore instability and subsequent cementing challenges. Continuous Well Monitoring Continuous monitoring from start to finish ensures that any anomalies or changes in pressure or flow are quickly addressed, minimizing the risk of cementing failures. Proper Waiting on Cement (WOC) Time Adequate WOC time is necessary for cement to cure properly. Rig operations during this period should be managed to ensure cement integrity and prevent early disturbances that could cause gas migration. Hydrostatic Pressure Management Maintaining sufficient hydrostatic pressure during the cement curing period, coupled with cement mixes designed to resist gas migration, is essential to prevent the formation of channels that could lead to leaks.Static Gel Strengths in a Cement Slurry. The development of static gel strengths in cement during its curing process presents a significant challenge globally. As the cement hardens after displacement, gel strengths begin to form as part of the hardening process. Once the gel strength reaches its “critical gel strength,” the gel structures start to support the cement above, much like how a bowl of Jello can maintain its shape without collapsing. As the cement continues to cure, the gel structures, along with fluid loss into the formation, begin to degrade the hydrostatic barrier against the wellbore. Eventually, this may leave only the hydrostatic pressure from the makeup water. If the hydrostatic pressure of the makeup water is insufficient to resist formation fluid pressure, gas migration may occur through the water phase of the unset cement, potentially creating permanent “worm holes” within the cement sheath. This can lead to flow or Read More

What are the Proofs of Function for a Surface Stack? Here are the Proofs of Function of a Surface Stack: Regulated Control Fluid Pressure: The regulated control fluid pressure will decrease and then return to its previously set pressure. Accumulator Pressure: The accumulator pressure will drop and subsequently return to its normal pressure, although it may not reach normal levels until the pressure drops to the point where the charge pumps are activated. Flow Meter Reading: If the panel is equipped with a flow meter, the volume of fluid used to perform the function should be consistent with the preventer in use. (All subsea rig floor panels must have a resettable flow meter that tracks the total volume used to operate a subsea function.) Function Lights: The light for the active function will illuminate, while the light for the opposite function will go out. Although this is not a proof of function, it does confirm that the three-position valve on the closing unit has been moved. What are the Proofs of Function for a Subsea Stack? Primary Positive Indication: The manifold or annular pressure (depending on the specific function) drops and then returns to its normal regulated pressure. This is the primary indication that the function has occurred. Secondary Positive Indications: The accumulator pressure drops and eventually returns to normal, though it may take longer to stabilize. The volume of fluid used is consistent with the equipment being operated. The light on the driller’s remote panel, while not a definitive proof of function, can serve as supplementary evidence when considered alongside the primary and secondary positive indicators. For further reading on this or any other well control subject, consult my Well Control Manual at: https://learn-well-control.com/product/well-control-manual-by-edwin-ritchie/ Read More

Pressure and Function Testing of Blind and Blind/Shear Rams Blind ram BOPs and blind shear ram BOPs should not be tested with pipe in the stack. Instead, their suitability for use with the planned string must be verified with the manufacturer. Any non-shearable tools should be identified and clearly posted. For an accumulator test, simulate the operation of the blind or blind shear rams by closing and opening an alternate pipe ram. API Spec 16A 7.5.8.7.4 Shear-Blind Ram Test Procedure Each preventer equipped with shear-blind rams must undergo a shear test before going into service. As a minimum, the test shall involve shearing drill pipe according to the following specifications: 3-1/2”, 13.3 lb/ft, Grade E pipe for 7-1/16” BOPs, 5”, 19.5 lb/ft, Grade E pipe for 11-inch BOPs, and 5”, 19.5 lb/ft, Grade G pipe for 13-5/8” and larger BOPs. The test must be conducted without applying tension to the pipe and with no wellbore pressure present. Shearing and sealing must be accomplished in a single operation. The piston closing pressure should not exceed the manufacturer’s rated working pressure for the operating system. Verification confirms the performance and reliability of the equipment through a testing process that is both repeatable and reproducible. Many jurisdictions have additional requirements for shear rams used deep water, HTHP, and chemical (hydrocarbons, drilling fluid, acids, H2S, etc) environments. NORSOK D-001 Standard: Section 5.10.3.1 Blow Out Preventer (BOP). The shear ram shall be capable of shearing the pipe “body of the highest grade drill pipe in use, as well as closing off the wellbore.” Procedure for Shearing Pipe in the Stack Space Out the Drill String: Ensure that no non-shearable components are positioned across from the shear rams. Identify these components ahead of time and post their locations in the dog house. Non-shearable components include tool joints, tool joint upsets, and BHA tools. Centralize the Pipe: Close the hang-off ram below the shear rams to centralize the pipe. Hang Off and Reduce Tension: For subsea operations, reduce tension on the compensators. Bleed Off Trapped Wellbore Pressure: Release any trapped pressure around the shear rams. Open Accumulator Bypass Valve: Open the accumulator bypass valve to direct full accumulator working pressure to the manifold. Operate the Shear Rams: Engage the shear rams to attempt shearing the pipe. Verify Shearing Success: Confirm that the string has been successfully sheared. Monitor Well Integrity: Continue to monitor the well to ensure it remains securely closed. Note: Always check the rating of the ram blocks used for hang-off. Variable bore ram blocks generally have lower hang-off capacity than fixed ram blocks. For more information on this or other well control subjects, visit my Well Control Manual at: https://learn-well-control.com/product/well-control-manual-by-edwin-ritchie/ Read More

Using the U-Tubing Effect for Calculating Top of Cement Once DisplacedThe Top of Cement (TOC) is a critical parameter for well integrity, and its accurate estimation is essential for confirming that the cement has reached the desired position in the wellbore. Most regulatory bodies require operators to report the TOC, and various methods exist to calculate this. One of the more complex yet effective approaches is using the U-tubing effect to calculate the TOC after the cement has been displaced.Typically, the volumetric method is employed for estimating the TOC. This method involves taking into account factors such as annular washout, casing pressure and temperature variations, and fluid loss assumptions based on area-specific excess factors. However, there is an additional consideration—the U-tubing effect—that influences the cement displacement process and plays a role in accurately determining the TOC.Understanding the U-Tubing EffectWhen a liquid cement slurry, often denser than the drilling fluid, is pumped down the casing, it creates a pressure differential in the system. This pressure difference between the casing and the annulus—known as the U-tubing effect—can cause significant changes in the wellbore dynamics. As the slurry is displaced, it creates an imbalance, and if this differential exceeds the system’s friction losses, the cement begins to fall faster than the pump output, causing the well to “go on vacuum.”During this phase, a gap is formed between the cement and the wellhead, and the slurry accelerates until it reaches an equilibrium point. As the pressure differential gradually reduces, the slurry decelerates, and the gap starts to disappear. This effect can cause significant challenges in monitoring, as it generates false signals that could be misinterpreted by the crew.Challenges in Monitoring During the U-Tubing EffectWhen the cement is “on vacuum,” the pump pressure becomes meaningless. The crew may find themselves unable to control the well pressures effectively, which can lead to confusion. During this phase, the returns often exceed the pump output, which might be misinterpreted as a kick. Similarly, during the deceleration period, when returns are lower than the pump output, this can appear as losses. These fluctuations in pressure and flow can make it challenging to distinguish between normal cement placement behavior and potential well control issues.Using Pump Pressure to Estimate Top of CementOnce the cement slurry begins to ascend in the annulus and displacement fluid is pumped down the casing, another U-tube pressure differential is established. This time, however, the pump pressure increases as the slurry’s density causes a difference in hydrostatic pressure between the annulus and the casing. While the pump pressure is influenced by multiple factors—such as pump rate, fluid viscosities, and slurry density—an increase in pressure just before bumping the plug, combined with the pump strokes, can provide valuable information regarding the True Vertical Depth (TVD) of the cement.By closely monitoring the pressure changes at this stage, operators can get a better indication of the slurry’s placement, allowing for more accurate determination of the TOC. This can be especially useful in cases where other methods of measurement, such as Read More