Slow Circulating Rates (SCRs) in Well Control Operations

Slow Circulating Rates (SCRs) refer to the use of slow pump rates during circulation to manage wellbore pressure, especially during situations where there is a need to control or “kill” the well. SCRs are integral in maintaining stability and safety in drilling environments, as they help manage bottom hole pressure, mitigate friction in the annulus, and provide additional control over circulation pressures. Let’s delve deeper into why SCRs are essential, how they are applied, and the importance of accounting for friction pressures, particularly in subsea operations.

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Indicators of Formation Pressure Changes During Drilling Operations

Identifying signs of formation pressure changes is crucial for drilling operations, ensuring the safety and efficiency of the process. Drilling team on the rig plays a vital role in recognizing and communicating these indicators to supervisors. The following key signs should be closely monitored, acknowledging that some may have alternative interpretations.

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What is a trip tank and its roles for drilling operation?

A trip tank serves as a compact, calibrated tank typically holding between 20 to 50 barrels, employed in drilling operations to monitor the flow of drilling fluid into and out of the wellbore whether pulling out (tripping out) or running in (tripping in) drill pipe or any tubular in the hole.

As each section of pipe is pulled out, the resulting void must be filled with drilling mud equivalent to the removed steel volume. This process, known as “pulling dry,” prevents a decrease in hydrostatic pressure, which can lead to unwanted wellbore events. The volume of mud pumped in is meticulously recorded on a trip sheet.

Trip tanks help detect potential kicks (inflow of formation fluids) by comparing the actual mud volume pumped in with the calculated displacement volume. If the actual volume is significantly lower, it suggests the well is swabbing and fluids are entering, a key indicator of a potential kick. Conversely, while running pipe in, any excess mud displaced should equal the steel displacement. The image below shows the typical trip tank diagram.

Trip tanks come in various configurations, but all prioritize accurate volume monitoring. The typical design is tall and narrow, allowing for easier detection of even slight changes in fluid level. This ensures precise measurement of fluid gain or loss within the wellbore.

The ability to continuously fill the hole and simultaneously capture returns in the trip tank is highly beneficial. This eliminates the need for constant driller attention, reducing the risk of hydrostatic pressure fluctuations. Comparing the actual trip tank volume changes with the calculated displacement volumes helps identify discrepancies and ensures the well is receiving the appropriate amount of mud. Trip tanks can also be utilized for dedicated wellbore monitoring. By diverting wellbore returns to the tank, even small fluid gains or losses can be identified, providing valuable information during flow checks and other critical operations. The image below shows the actual trip tank on the rig.

Trip Tank

Trip Tank

Rigorous maintenance of trip tanks is essential. Regular cleaning prevents solids buildup, while inspections ensure proper valve and pump functionality. Additionally, floats and instrumentation require calibration at specified intervals to maintain accuracy.

For even greater accuracy, especially during stripping operations, a separate tank with a smaller capacity (3-4 barrels) can be used. This “strip tank” allows for precise measurement of small fluid volumes before transferring them to the main trip tank for cumulative volume analysis.

Conclusion:

Trip tanks are indispensable tools in drilling operations, ensuring accurate wellbore pressure maintenance, kick detection, and overall wellbore status. By prioritizing reliability, accuracy, and meticulous maintenance, these vital pieces of equipment contribute significantly to a safe and efficient drilling process.

References 

Cormack, D. (2007). An introduction to well control calculations for drilling operations. 1st ed. Texas: Springer.

Crumpton, H. (2010). Well Control for Completions and Interventions. 1st ed. Texas: Gulf Publishing.

Grace, R. (2003). Blowout and well control handbook [recurso electrónico]. 1st ed. Paises Bajos: Gulf Professional Pub.

Grace, R. and Cudd, B. (1994). Advanced blowout & well control. 1st ed. Houston: Gulf Publishing Company.

Watson, D., Brittenham, T. and Moore, P. (2003). Advanced well control. 1st ed. Richardson, Tex.: Society of Petroleum Engineers.

What are HCR Valves?

An HCR valve, also recognized as a High Closing Ratio valve, is a specialized type of gate valve widely employed in well control systems, particularly within the blowout preventer (BOP) stack. Its purpose is to deliver a dependable and efficient method for managing wellbore pressure and averting uncontrolled fluid flow during drilling, completion, and production activities.

Distinguished by a remarkable closing ratio, which represents the ratio of fluid pressure upstream of the valve to the hydraulic pressure needed for closure, HCR valves excel in sealing against elevated wellbore pressures, even in the face of sudden pressure surges.

Typically featuring a double-acting design, HCR valves possess two hydraulic chambers that can be pressurized for both valve opening and closure. This dual-system redundancy ensures continued operability, even if one hydraulic system encounters a failure. Operating at a typical pressure of 1,500 psi, HCR valves are engineered with a rising stem design, offering enhanced control during operations. Unlike some valve designs, HCR valves do not incorporate back-seating allowance, emphasizing their commitment to reliable and secure fluid control.

Engineered to endure challenging wellbore conditions, such as high temperatures, corrosive fluids, and abrasive sand, HCR valves are crafted from robust materials like forged steel or stainless steel. Protective coatings are applied to resist corrosion, enhancing their durability.

As integral components of well control systems, HCR valves play a pivotal role in ensuring the safety of personnel and environmental protection during drilling and production operations. Their high closing ratio, redundant systems, and robust design collectively contribute to their reliability and effectiveness in managing wellbore pressure and preventing uncontrolled fluid flow.

References

Cormack, D. (2007). An introduction to well control calculations for drilling operations. 1st ed. Texas: Springer.
Crumpton, H. (2010). Well Control for Completions and Interventions. 1st ed. Texas: Gulf Publishing.
Grace, R. (2003). Blowout and well control handbook [recurso electrónico]. 1st ed. Paises Bajos: Gulf Professional Pub.

Understanding Factors Leading to Low Density Drilling Fluid and Potential Well Control Events

The density of drilling fluid plays a critical role in well control during both drilling and completion operations. This article aims to explore the various factors that can result in low-density drilling fluid, potentially leading to well control challenges.

Accidental Dilution and Fluid Addition

Maintaining the hydrostatic pressure necessary to balance or slightly exceed formation pressure requires constant monitoring and adjustment of drilling fluid density. Accidental dilution of drilling fluid with makeup water in surface pits or the addition of low-density formation fluids into the mud column can reduce fluid density, triggering a potential kick. Rigorous vigilance in monitoring mud pits is essential to ensure the required fluid density is consistently maintained.

Gas Cutting

Large volumes of gas in the returns can cause a drop in the average density and hydrostatic pressure of the drilling fluid. Notably, gas cutting often occurs in an overbalanced condition downhole. If a formation containing gas is drilled, the gas within drilled cuttings can expand as it moves up the annulus, leading to gas cutting at the surface. Detecting this is crucial, as a flowing well indicates a kick, necessitating immediate well shut-in and initiation of the proper kill procedure.

Oil or Saltwater Cutting

Invasions of oil or saltwater from drilled cuttings or swabbing can reduce the average mud column density, causing a drop in mud hydrostatic pressure. While the effect of these liquids on average density is less pronounced than gas, the impact on bottomhole pressure can be substantial. Liquids, being less compressible, result in uniform density reduction throughout the mud column.

Settling of Mud Weighting Materials

The settling of desirable solids or drilled cuttings in a mud can significantly reduce mud density, affecting hydrostatic pressure. Barite sag, more prevalent in highly deviated wells, requires a combination of sound mud design and operational practices for management.

Loss of Equivalent Circulating Density (ECD)

Shutting down pumps during drilling connection can lead to a reduction in dynamic bottomhole pressure, causing the loss of ECD. This loss can allow formation fluids to enter the wellbore, known as “connection gas.” Observation of connection gas is an indication that static mud overbalance is lost, necessitating a potential increase in mud weight.

Cementing Operations

Improper cement mixing, lost circulation, or casing float equipment failure can compromise cement density and reduce hydrostatic pressure, leading to well control issues.

Cement Slurry Transition

As cement transitions from a slurry to a solid state, there’s a temporary reduction in hydrostatic pressure due to self-supporting cement solids before the structure becomes impermeable. This can potentially lead to an influx.

Closely monitoring the well throughout all phases of drilling, completion, and cementing operations is imperative for preventing and mitigating well control events. Nurturing a proactive approach ensures the integrity and safety of the wellbore.

To prevent well control events caused by low drilling fluid density, it’s essential to:

  • Maintain strict pit discipline and monitor fluid properties regularly.
  • Use appropriate mud additives to prevent gas cutting and control fluid rheology.
  • Monitor for oil or saltwater invasions and address them promptly.
  • Implement proper mud design and operational practices to minimize barite sag.
  • Maintain pumps running during pipe connections to avoid ECD loss.
  • Exercise caution during cementing operations and closely monitor pressure changes.

References

Cormack, D. (2007). An introduction to well control calculations for drilling operations. 1st ed. Texas: Springer.
Crumpton, H. (2010). Well Control for Completions and Interventions. 1st ed. Texas: Gulf Publishing.
Grace, R. (2003). Blowout and well control handbook [recurso electrónico]. 1st ed. Paises Bajos: Gulf Professional Pub.