A choke is a special valve used in well control situation and its primary purpose is to generate back pressure in a well, effectively increasing bottomhole pressure to manage formation flow during the removal of an influx. Chokes come in two types: positive or non-positive sealing, with adjustable features necessary for well control applications, as opposed to fixed chokes used in production or testing. These components are offered in various sizes and pressure ranges, and adjustable chokes can be either manually operated or hydraulically controlled from a remote console.

There are two main categories of chokes: manual chokes and hydraulic chokes.

Manual Chokes:

Operated by hand using a handwheel, manual chokes are not the primary choice for well control operations. The manual adjustment process is less effective for controlling pressure in the wellbore during circulation.

Manual Chokes

Hydraulic Chokes:

Hydraulic chokes provide easy adjustment and enable precise remote regulation of choke pressure. A notable feature of most hydraulic remote chokes is their placement in the choke manifold, while control occurs remotely from a panel displaying casing and drill string pressures.

Hydraulic Choke

In scenarios with multiple chokes, the manifold design should facilitate the isolation and repair of one choke while another remains active. Additionally, it is crucial to have spare parts for the chokes readily available at the rig site.

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.

<p>The post What is a choke in well control? first appeared on Drilling Formulas and Drilling Calculations.</p>

The Valve Removal Plug (VR Plug) is a specialized one-way check valve designed for threaded installation through an outlet valve on a casing head, casing spool, or tubing spool into a female thread in the outlet. This configuration effectively isolates the valve from pressure, enabling the convenient removal of the outlet valve for repair or replacement. After the necessary maintenance, the valve can be reinstalled, and the VR Plug can then be removed. It is important to note that VR Plugs are intended for short-term use and should not be considered a permanent substitute for wellhead valves. The image below is a VR plug.

Most newly installed wellheads are equipped with machined threads in the outlets to facilitate the installation of a VR Plug. However, it’s worth noting that many older wellheads may not be configured to accommodate the use of a VR Plug.

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.

<p>The post What is Valve Removal Plug (VR plug) for Wellhead? first appeared on Drilling Formulas and Drilling Calculations.</p>

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

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.

<p>The post What is a trip tank and its roles for drilling operation? first appeared on Drilling Formulas and Drilling Calculations.</p>

A drill pipe float valve, also recognized as a non-return valve, is a specialized valve installed in the bottom hole assembly (BHA) and its primary function is to serve as a check valve, permitting the downward flow of drilling mud through the drill string but preventing any unwanted fluid from flowing back up into the drill string.

Key advantages of float valves

• Provide immediate shut-off against high or low back pressure and prevent fluid flow through the drill string.
• Prevent cuttings from entering the drill string, thus reducing the likelihood of pulling a wet string.

Disadvantages of float valves

• Require filling up pipe while tripping in hole
• Unable to perform reverse circulation

Types of Drill Pipe Float Valves:

• Plunger Type: The most prevalent type, featuring a plunger that seals against a seat to prevent reverse flow.

• Flapper Type: Utilizes a flapper resting on a seat to obstruct reverse flow.

Ported or Non-Ported Float Valve

A ported float valve features a small hole in its center, offering two significant advantages. Firstly, it enables the monitoring of drill pipe pressure post-well shut-in. Secondly, it helps minimize the risk of downhole fracture during well pack-off, as excess pressure can be released through the ported float. However, a drawback is that some influx may enter the drill string.

In contrast, a non-ported float valve completely seals the interior of the drill string, preventing communication unless the float is disturbed. The primary advantage is the prevention of influx into the string. Nevertheless, it comes with two drawbacks: 1) the need to pump the float to observe shut-in drill pipe pressure, and 2) the absence of a method to release downhole pressure in the event of wellbore pack-off. This limitation arises because, when surface pressure is reduced to zero and the float valve is closed, pressure becomes trapped between the pack-off and the string without a means of release.

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.

<p>The post Understanding Drill Pipe Float Valve: Functionality, Types, and Benefits first appeared on Drilling Formulas and Drilling Calculations.</p>

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.

1. Change in Rate of Penetration:
   • An alteration in drilling speed is a prominent indicator of potential formation pressure changes.
   • Increase or decrease in drilling rate may suggest drilling into higher-pressure zones.
   • Abrupt changes, known as drilling breaks or reverse breaks, can signal transitions into abnormal pressure areas.
2. Cuttings Changes: Shape, Size, Amount, Type:
   • The characteristics of rock cuttings provide valuable insights into formation conditions.
   • Size, shape, and amount alterations may signify changes in pressure differentials, bit conditions, or formation types.
3. Torque/Drag Increase:
   • Gradual increases in rotary torque and drag may indicate larger amounts of cuttings entering the wellbore.
   • These changes can result from the bit encountering softer formations or increased formation pressure.
4. Sloughing Shale/Hole Fill:
   • As formation pressure surpasses mud column pressure, shale may slough off the wellbore walls.
   • Sloughing shale can lead to complications such as tight holes and equipment becoming stuck.
5. Gas Content Increase:
   • Elevated gas content in drilling fluid is a reliable indicator of abnormally pressured zones.
   • Differentiate between drill gas, connection gas, and background gas to interpret pressure changes accurately.
6. Variations from “d” Exponent:
   • The “d” exponent method offers a simple means to detect abnormal pressures.
   • Changes in the slope of the “d” exponent line on a plot can indicate pressured zones, aiding in mud weight predictions.
7. MWD and LWD:
   • Measurement while drilling and logging while drilling tools provide real-time information on drilling conditions.
   • Parameters such as resistivity, torque, and pressure can help identify changes in drilling conditions and influx detection.
8. Shale Density Decrease:
   • Deviations from the predicted increase in shale density can suggest higher pore pressure zones.
   • Challenges in measuring shale density should be considered when interpreting results.
9. Flowline Temperature Increase:
   • An abnormal increase in flowline temperature can indicate a transition zone or higher pressure.
   • Temperature curves offer additional insights, considering factors like circulation rate and mud properties.
10. Change in Chloride Content:
    • Alterations in chloride ion content within drilling fluids serve as a valid pressure indicator.
    • Monitoring chloride content changes requires meticulous control of mud checks for accurate interpretation.

Rig personnel must be vigilant in recognizing these indicators, as prompt communication and appropriate responses are essential to managing the challenges posed by formation pressure changes during drilling operations.

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.

<p>The post Indicators of Formation Pressure Changes During Drilling Operations first appeared on Drilling Formulas and Drilling Calculations.</p>

For well control equipment or pressure containment for oil and gas, ensuring reliable sealing solutions is paramount to maintaining operational integrity and safety standards. Among the array of sealing mechanisms employed, API ring gaskets stand out for their versatility and effectiveness in various applications, including wellheads, risers, and Xmas trees.

These ring gaskets, designated by different API types such as ‘R’, ‘RX’, ‘BX’, ‘AX’, ‘VX’, and ‘CX’, each offer unique sealing characteristics tailored to specific operational requirements. Understanding the intricacies of these API ring gaskets is essential for ensuring optimal performance and mitigating potential risks associated with leaks and equipment failures.

In this comprehensive exploration, we delve into the different types of API ring gaskets, their design principles, sealing mechanisms, and practical applications in well control equipment. From the traditional ‘R’ type gasket to the advanced ‘CX’ pressure-energized gasket, we examine their features, benefits, and challenges, providing insights to aid industry professionals in selecting the most suitable sealing solution for their specific operational needs.

API Type ‘R’ Ring Joint Gasket

The ‘R’ type ring joint gasket doesn’t rely on internal pressure for its sealing. It seals through small bands of contact between the grooves and the gasket’s OD and ID. The gasket can be octagonal or oval in cross-section. Due to its design, ‘R’ type gaskets don’t allow face-to-face contact between hubs or flanges, so external loads are managed through the sealing surfaces. However, vibration and external loads may deform the small bands of contact, potentially leading to leaks unless the flange bolting is regularly tightened.

API Type ‘RX’ Pressure-Energized Ring Joint Gasket

The ‘RX’ type gasket, developed by Cameron Iron Works and adopted by API, is pressure-energized. Sealing occurs along small contact bands between the grooves and the gasket’s OD, with the gasket slightly larger in diameter than the grooves, compressed slightly during joint tightening. ‘RX’ gaskets are designed to withstand external loads without deforming the sealing surfaces. It’s recommended to use a new gasket for each joint assembly.

API Type ‘BX’ Pressure-Energized Ring Joint Gasket

Similar to ‘RX’, ‘BX’ gaskets rely on pressure energization and sealing along small contact bands. However, achieving face-to-face contact between hubs or flanges can be challenging due to tolerance variations. Without proper contact, vibration and external loads may cause deformation and eventual leakage. ‘BX’ gaskets often feature axial holes to ensure pressure balance.

API Face-to-Face Type ‘RX’ Pressure-Energized Ring Joint Gasket

This ‘RX’ variant aims for face-to-face contact between hubs, with sealing occurring along small contact bands. However, the gasket may lack support on its ID, potentially leading to deformation during tightening and subsequent leaks. This type is not widely accepted in the industry.

‘CIW’ Type ‘RX’ Pressure-Energized Ring Joint Groove

Modified by CIW, these grooves aim to prevent gasket buckling and consequent leaks. While similar to standard ‘RX’ gaskets, these grooves offer improved support, reducing the likelihood of gasket deformation and leaks.

Type ‘AX’ and ‘VX’ Pressure-Energized Ring Joint Gasket

Developed by Cameron Iron Works and Vetco respectively, ‘AX’ and ‘VX’ gaskets seal along small contact bands, with the gasket slightly larger than the grooves. They feature smooth IDs and grooved ODs, allowing for minimal axial pressure loading. They’re designed to maintain face-to-face contact between hubs with minimal clamping force, with external loads transmitted through the hub faces.

‘CIW’ Type ‘CX’ Pressure-Energized Ring Joint Gasket

Similar to ‘AX’ and ‘VX’, ‘CX’ gaskets seal along small contact bands and are slightly larger than the grooves, with recessed designs for protection against keyseating. They allow for face-to-face contact between hubs with minimal clamping force and are suitable for use throughout the BOP and riser system.

Application of Type ‘AX’, ‘VX’, and ‘CX’ Pressure-Energized Ring Joint Gaskets

These gaskets facilitate face-to-face contact between hubs with minimal clamping force and are suitable for various applications, including at the base of the wellhead, side outlets on the BOP stack, and throughout the BOP and riser system.

Key Takeaways:

• Pressure-energized gaskets generally offer better performance than non-energized ones.
• Face-to-face contact, when achieved, distributes loads better and reduces gasket damage.
• Each type has its own strengths and weaknesses, requiring careful selection based on application.

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.

<p>The post Different Types of API Ring Gaskets Used in Well Control Equipment, Wellhead, Riser, and Xmas Tree first appeared on Drilling Formulas and Drilling Calculations.</p>

Well control situations can get tricky during completion or workover operations. Sometimes, the standard methods involving circulation just won’t work. This can happen due to:

• Lack of pumps or malfunctioning pumps on site
• A plugged workstring
• Kicks encountered while pulling out the drill string or when the tubing is far above the perforations
• No drill string in the well at all

These situations require special well control techniques. The most crucial step, as always, is to shut in the well using the blowout prevention equipment (BOP) immediately upon encountering a kick. Once the well is shut in, solutions often involve practical measures:

• Bringing in a new pump or fixing the existing one (pumps)
• Perforating or bullheading down the casing (plugged workstring)
• Stripping back to bottom or bullheading if the tubing is stuck (kicks with tubing off bottom)
• Running a bridge plug or wireline-set retainer, bullheading, or using snub tubing if there’s no pipe in the well

However, if logistics prevent these solutions and a gas kick is present, Volumetric Control comes into play.

Volumetric Control: Managing Pressure as Gas Migrates

Volumetric Control allows for managing bottomhole and surface wellbore pressures while the gas kick migrates up the wellbore. This is particularly useful since most workover and completion casings are designed to withstand the pressure of a migrating gas kick without expansion, assuming a Minimum Allowable Surface Pressure (MASP) is maintained.

As the gas bubble moves upwards, it increases both bottomhole and surface pressures. Eventually, the perforated interval will start taking fluid, preventing the surface pressure from ever reaching the bottomhole pressure. However, there are situations where Volumetric Control becomes essential to avoid further complications:

• Open hole completions or sidetracked wells
• Old perforations or a higher perforated interval that could take fluid and cause crossflow or an underground blowout
• Formations sensitive to large volumes of fluid that could be severely damaged
• Formation fluids trapped in a sealed wellbore (above a bridge plug or tubing plug)

The Science Behind Volumetric Control: Boyle’s Law

The success of Volumetric Control hinges on understanding gas behavior and Boyle’s Law (P₁V₁ = P₂V₂). This principle states that at constant temperature, the pressure and volume of a gas are inversely proportional. In simpler terms, as the volume of a gas increases, its pressure decreases.

Volumetric Control involves carefully bleeding off small amounts of fluid at a time. This keeps the bottomhole pressure slightly above the reservoir pressure, allowing the gas kick to migrate upwards without causing a pressure surge that could compromise the well’s integrity. Importantly, Volumetric Control should only be used when the surface pressure is rising and threatens the well’s integrity.

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.

<p>The post Volumetric Well Control – When will we need to use it? first appeared on Drilling Formulas and Drilling Calculations.</p>

By understanding and applying these three key principles – Boyle’s Law, hydrostatic pressure, and the volume-height relationship – the Volumetric Well Control Method can be effectively employed to manage gas kicks and maintain well control. The details are shown below.

1. Boyle’s Law:

This law states that for a gas at constant temperature, pressure and volume are inversely proportional. Simply put, compressing a gas increases its pressure, while allowing it to expand lowers the pressure.

Expressed mathematically:

Boyle’s Law: P₁V₁ = P₂V₂

where:

• P₁ = Pressure of gas at condition 1
• V₁ = Volume of gas at condition 1
• P₂ = Pressure of gas at gas at condition 2
• V₂ = Volume of gas at condition 2

Although this equation simplifies the real gas law equation, PV=ZnRT, by neglecting temperature effects and gas compressibility, this equation provides a good foundation for understanding volumetric control

In well control, as a gas influx migrates up the wellbore without expanding, its pressure remains constant. Conversely, if it expands as it rises, the pressure decreases.

Preventing gas expansion during migration can be catastrophic. Since the gas enters with formation pressure, it would exert the same pressure at the surface, essentially bringing high pressure from below to the wellhead. This could rupture casing or cause a blowout.

Volumetric control addresses this by allowing gas expansion. We measure this expansion by monitoring the amount of drilling mud bled off through a choke line.

2. Hydrostatic Pressure:

The pressure exerted by a static fluid column equals the fluid’s hydrostatic pressure plus any pressure applied at the top.

Pressure at Mud Column Bottom = Hydrostatic Pressure + Surface Pressure

Similarly, the pressure exerted by a migrating gas bubble acts on the mud column below, increasing the pressure at the bottom (bottomhole pressure).

We can express this as:

Bottomhole Pressure = Hydrostatic Pressure (below bubble) + Gas Bubble Pressure

As the bubble moves up one foot, there’s one additional foot of mud below it, increasing the hydrostatic pressure at the bottom. If the bubble pressure stays constant while moving, the bottomhole pressure will also increase by the hydrostatic pressure of this “new” mud.

By bleeding mud from the annulus to create space for gas expansion, we reduce the mud volume and consequently, the hydrostatic pressure. This bleeding needs to be done while maintaining constant casing pressure. As per the equation above, this reduces bottomhole pressure.

In volumetric control, we can influence bottomhole pressure in two ways:

• Do nothing: The gas bubble rises, and both bottomhole and surface pressures increase.
• Bleed mud: Assuming surface pressure stays constant, bottomhole pressure decreases by the amount of hydrostatic pressure lost due to mud removal.

Careful control of mud bleed is crucial. If surface pressure drops or hydrostatic pressure is lowered too much, an underbalanced situation can occur, allowing more gas influx. The goal is to bleed off just enough mud to maintain constant surface pressure until the lost wellbore pressure equals the pressure increase allowed before bleeding. To achieve this, we equate the desired hydrostatic pressure loss with the volume of mud bled off. The casing pressure can then be allowed to increase by this lost pressure to maintain bottomhole pressure. This is why the amount of bled mud is measured and equated to a reduction in hydrostatic pressure.

3. Volume and Height:

These factors are essential for calculating the reduction in hydrostatic pressure each time mud is bled from the annulus. We need to know the pressure drop resulting from each bled mud volume.

The formula for calculating annulus capacity factors

Annulus Capacity Factor (ACF) = (OD² -ID² ) ÷ 1029.4

Where:

ACF = Annulus Capacity Factor (bbl/ft)

OD = Outside Diameter of Annular Space(in)

ID = Inside Diameter of Annular Space (in)

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.

<p>The post Three Key Principles for the Volumetric Well Control Method first appeared on Drilling Formulas and Drilling Calculations.</p>

The Volumetric Control Method is a well control technique employed to manage bottomhole pressure (BHP) while enabling preparations for well circulation or bullheading kill fluid into the wellbore. It is not intended to completely kill the well, but rather to provide a controlled environment until definitive well control measures can be implemented.

The Principle of Controlled Expansion

The core principle of Volumetric Control lies in facilitating the controlled expansion of a gas influx as it migrates up the wellbore. This is achieved by maintaining constant casing pressure while strategically bleeding off mud at the surface. The casing pressure is only held constant during mud bleed-off; otherwise, it is allowed to rise naturally. Each barrel of mud removed from the annulus induces the following effects:

1. Accommodation of Expanding Gas Bubble: The removed volume allows the gas bubble to expand by one barrel within the wellbore.
2. Reduction in Hydrostatic Pressure: The hydrostatic pressure exerted by the mud column in the annulus decreases.
3. Calculated BHP Reduction: The bottomhole pressure experiences a calculated decrease corresponding to the reduction in hydrostatic pressure.

Management of Bottomhole Pressure Using Volumetric Control Method

Volumetric Control operates through a series of steps that create a cyclical pattern of rising and falling BHP. The process follows these steps:

1. Waiting for Gas Bubble Rise: The well is shut-in, allowing the gas bubble to migrate upwards. During this phase, both casing pressure (CP) and BHP increase.
2. Bleed of Mud while Maintaining Constant Casing Pressure : To prevent further casing pressure rise, mud is bled off from the annulus while maintaining a constant casing pressure (CP). This action reduces BHP.
3. Well Shut-In and Pressure Rise: The well is shut-in again, and the cycle restarts. The gas bubble continues to rise to a planned value, leading to a further increase in casing pressure (CP) and BHP.
4. New Casing Pressure Bleed: Once casing pressure (CP) reaches a new, higher level, mud is bled off again to maintain this pressure. This process lowers BHP once more.

By repeating this cycle, BHP is maintained within a controlled range (almost constant). The lower limit ensures sufficient pressure to prevent another influx, while the upper limit safeguards against a formation fracture. The cycle continues until either the casing pressure stabilizes (indicating cessation of gas migration) or the entire gas influx reaches the surface (in scenarios where the gas is distributed throughout the wellbore).

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.

<p>The post Volumetric Control Method Principle in Well Control Operations first appeared on Drilling Formulas and Drilling Calculations.</p>

This technical guide provides a detailed procedure for performing the Volumetric Well Control Method.

Step 1 – Perform Essential Calculations

Prior to executing the Volumetric Control procedure, three key calculations are necessary:

1. Safety Factor (SF)
2. Pressure Increment (PI)
3. Mud Increment (MI)

Safety Factor (SF): This is the additional bottomhole pressure permitted to occur naturally as gas migrates up the annulus with the well shut in. It ensures the bottomhole pressure remains sufficiently above the formation pressure to prevent underbalance. A typical Safety Factor ranges from 50 to 200 psi. The appropriate value depends on factors such as depth, angle, hole size, and well fluid. Migration time for the gas bubble to increase the casing pressure by this amount can vary from minutes to several hours.

Pressure Increment (PI): This is the working pressure range for the Volumetric Control Method. It represents both the surface pressure increase tolerated per step and the reduction in hydrostatic pressure during each step. The Pressure Increment is generally set equal to the Safety Factor (rounded to the nearest 10 psi). For example, with a Safety Factor of 100 psi, the recommended PI would also be 100 psi.

Mud Increment (MI): This is the volume of mud that must be bled from the annulus to decrease the annular hydrostatic pressure by the Pressure Increment. The Mud Increment is calculated using the formula:

Mud Increment (MI) = (PI×ACF) ÷ (MW×0.052)

where:

• PI = Pressure Increment (psi)
• ACF = Annulus Capacity Factor (bbl/ft)
• MW = Mud Weight (ppg)

For instance, with a PI of 100 psi, an ACF of 0.0802 bbl/ft, and a MW of 12.0 ppg, the Mud Increment (MI) is approximately 12.85 bbl.

Step 2 – Allow Casing Pressure to Increase

With calculations complete, allow the gas bubble to migrate up the annulus, increasing the shut-in casing pressure by the Safety Factor (SF) plus the Pressure Increment (PI). Initially, no mud is bled from the annulus, so the hydrostatic pressure remains unchanged. The bottomhole pressure increases by the combined Safety Factor (SF) and Pressure Increment (PI), resulting in a controlled overbalance to a desired casing pressure.

While allowing casing pressure:

$\text{Bottomhole Pressure ↑}=\text{Hydrostatic Pressure (constant) }+\; Surface\text{Pressure ↑}\text{(Initial Casing Pressure + Safety Factor + Pressure Increment )}$

Step 3 – Maintain Casing Pressure Constant While Bleeding Mud

To prevent further pressure increase, bleed the first Mud Increment (MI) from the annulus while keeping the casing pressure constant. This ensures that the reduction in bottomhole pressure results solely from the hydrostatic pressure decrease. Multiple small choke adjustments may be required to maintain constant surface pressure. During this process, the bottomhole pressure decreases by the Pressure Increment.

While bleeding mud:

$\text{Bottomhole Pressure}\downarrow =\text{Hydrostatic Pressure}\downarrow +\text{Surface Pressure}\text{ (constant)}$

As mud is bled, the gas bubble expands to occupy the vacated volume, decreasing the bubble’s pressure according to Boyle’s Law. Note that improper control of surface pressure may allow additional influx from the formation, exacerbating well control issues.

Step 4 – Wait for Casing Pressure to Increase

After bleeding the Mud Increment (MI), wait for the gas bubble to migrate upward, causing the surface pressures to increase by the Pressure Increment (PI). This restores the overbalance to the Safety Factor plus Pressure Increment (PI).

Step 5 – Repeat Mud Bleeding to Maintain Constant Casing Pressure

Once the maximum overbalance is reached, hold the casing pressure constant by bleeding another Mud Increment. This decreases the bottomhole pressure by the Pressure Increment (PI) and allows further gas expansion.

Step 6 – Alternate Between Pressure Holding and Gas Bubble Migration

Continue alternating between maintaining constant casing pressure and allowing it to rise as the gas bubble migrates, repeating steps 4 and 5. Each cycle involves bleeding mud to reduce bottomhole pressure and waiting for the casing pressure to rise as the gas migrates. By the time the gas reaches the surface, it has expanded significantly, reducing its pressure substantially.

Figure 1  demonstrates casing pressure and overbalance while performing volumetric well control. If you want to see how the example of the volumetric well control, please check this article. Volumetric Well Control Example Calculations 

Figure 1 – Example Casing Pressure and Overbalance

Critical Notes:

• Maintaining constant casing pressure during mud bleed steps is essential to ensure the sole influence of hydrostatic pressure change on BHP.
• Gas expansion follows Boyle’s Law during bleeding, reducing its pressure. Allowing casing pressure to drop defeats the purpose and might worsen the well control situation.

The Volumetric Well Control Method allows controlled wellbore pressure management during gas influx migration. By following the outlined steps and maintaining constant casing pressure during mud bleeding, bottom hole pressure will be maintained almost constant until conventional well control procedures can be implemented or gas is safely controlled migration to surface.

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.

<p>The post Volumetric Well Control Method: A Step-by-Step Guideline first appeared on Drilling Formulas and Drilling Calculations.</p>

What is Bullheading?

Bullheading well control is a well control technique used in specific scenarios during drilling operations to pump an influx back into the formation. This method involves displacing the casing with a sufficient quantity of kill fluid to push well fluids back into the reservoir. Successful bullheading requires unobstructed annulus flow and the ability to inject into the formation without surpassing pressure limitations such as the Maximum Allowable Annular Surface Pressure (MAASP). Formation breakdown may be acceptable in certain cases if it is preferable to other potential outcomes.  Bullheading may result in fracturing the exposed formation if injection pressures exceed the fracture gradient.

Situations for Bullheading

Bullheading may be considered in the following circumstances:

• Gas Volume at Surface: When conventional displacement methods would result in an excessive gas volume at surface conditions, possibly exceeding the capacity of the mud-gas separator.
• High H2S Content: When the influx contains unacceptable levels of H2S.
• Large Influxes: When a significant influx is encountered.
• No Pipe in Hole: When an influx occurs with no pipe in the hole.
• High Surface Pressures: When conventional methods could lead to excessive surface pressures, potentially exceeding the Maximum Allowable Surface Pressure (MASP) and risking casing failure near the wellhead.
• Pipe Off Bottom: When a kick is taken with the pipe off bottom and stripping back is not feasible.
• Pressure Reduction: To reduce surface pressures before further well control operations.

Note: The decision to bullhead must be made promptly after shut-in. Delays can allow gas migration upwards, reducing the likelihood of successful re-injection into the formation. Pumping may lead to formation fractures at weak points such as the shoe.

Key Factors in Bullheading

Bullheading should be considered only when standard well control techniques are unsuitable. Accurate information on formation injectivity or fracture characteristics is often unavailable. The feasibility of bullheading is determined by several factors:

• Type of Influx and Formation Permeability: Gas migration may require downward fluid velocity to exceed migration rates for effective displacement. Viscosifiers in the kill fluid may help limit migration.
• Openhole Characteristics: Low reservoir permeability may necessitate exceeding fracture pressure.
• Influx Position: The location of the influx in the hole.
• Well Control Equipment and Casing Pressure Ratings: Equipment and casing pressure limits must be known and not exceeded, accounting for wear and deterioration.
• Consequences of Formation Fracture: Evaluate the impact of fracturing open hole sections.
• Drill Pipe and Casing Pressure Limits: Ensure limits are not exceeded. Applying pressure to the outside of the innermost casing may help stay within burst limits.
• Filter Cake Quality: The integrity of the filter cake at the permeable formation.
• Drilling Fluid Displacement: Consider the effects of displacing large volumes of drilling fluids into potentially productive formations.

Bullheading Procedure

Bullheading procedures should be tailored to the specific conditions at the rig site. For instance, bullheading an H2S-containing influx may be necessary even if it causes a downhole fracture. Conversely, fracturing may be unacceptable with shallow casing, where broaching risks outweigh surface high-pressure risks.

Steps for Bullheading:

1. Calculate Fracture Pressures: With the well shut-in, calculate expected surface pressures that would cause formation fracture during bullheading.
2. Prepare Pressure Chart: Create a chart using strokes versus pumping pressure, especially if using heavier mud to reduce surface pressure.
3. Eliminate Surface Gas: If gas is present at the surface, use Lubricate and Bleed procedures before starting bullheading.
4. Pump Kill Fluid: Gradually bring the pumps up to speed to overcome well pressure and pump the kill fluid down the annulus. Monitor pump pressure throughout.
   • Caution: Avoid exceeding maximum surface pressures unless formation breakdown is tolerable.
5. Pump Rate: Pump fast enough to surpass gas migration rates.
6. Monitor Pressure: As fluids are forced back into the formation, the added hydrostatic pressure should decrease the pumping pressure. Record all pressure values.
7. Stop Pump and Monitor: Stop the pump (unless over-displacement is approved), shut-in the well, and monitor the situation.
   • Note: If pressure is observed, gas may have migrated up-hole faster than the fluid was pumped down, or the fluid density may be insufficient to kill the well.

In summary, bullheading is a high-risk but potentially effective well control technique for managing influxes during drilling by pumping kick fluids back into the formation. Its feasibility depends heavily on specific well conditions and risks like inducing fractures. Bullheading requires comprehensive planning, contingencies, and care in execution by experienced personnel. When justified for the situation, it can enhance safety and reduce costs, but should only be attempted after thorough analysis deems it the best available option given the elevated risks compared to conventional methods.

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.

<p>The post Bullheading Well Control Method in Drilling Operations – All Things You Need to Understand about It first appeared on Drilling Formulas and Drilling Calculations.</p>

Stripping well control becomes more complex when encountering an influx, simply called influx penetration.. This article explores how influx penetration, the drill string entering the influx zone, affects well control procedures.

As the drill string enters the influx, the height of the influx increases. This larger influx volume translates to a decrease in hydrostatic pressure within the wellbore. To maintain well control and prevent additional influx due to underbalance condition, the casing pressure at the surface needs to compensate for this pressure reduction. Figure 1 demonstrates influx height change when BHA penetrates into influx. This penetration will elongate the influx casing reduction in hydrostatic pressure.

Figure 1: Influx Penetration

The impact of influx penetration is particularly significant for gas kicks. Due to the lower density of gas compared to wellbore fluids, a gas influx causes a much larger decrease in hydrostatic pressure, requiring a more substantial increase in casing pressure.

The well control method employed during stripping also plays a role. When using the volume accounting method, casing pressure automatically adjusts as the drill string penetrates the influx. This eliminates the need for precise calculations regarding penetration timing.

However, the constant surface pressure method requires manual adjustments. Here, the operator must calculate the necessary increase in casing pressure based on the influx volume using the equation:

ΔCP = ΔH × (PGM – PGI)

In this formula,

ΔCP represents the required casing pressure increase (psi).

ΔH is the change of the height of the influx zone (ft).

PGM is the Pressure gradient of drilling mud (psi/ft).

PGI is the Pressure gradient of influx (psi/ft).

** This calculation is suitable for non-migrate influx such as oil or water kick.

Influx Penetration Calculation Example

The information given shows in the figure 2.

Figure 2 – Information given for influx penetration

Solution

Hole capacity = 8.5²÷1029.4 = 0.0702 bbl/ft

Capacity between hole and BHA = (8.5² – 6.5²) ÷ 1029.4 = 0.02914 bbl/ft

Capacity between hole and DP= (8.5² – 5²) ÷ 1029.4 = 0.0459 bbl/ft

Initial length of influx = 30 bbl ÷ 0.0702 bbl/ft = 427 ft

Volume of influx between hole and BHA = 90 ft × 0.02914 bbl/ft = 2.62 bbl

Therefore, volume of influx between hole and drill pipe is equal to initial volume (30 bbl) minus volume of influx between hole and BHA(2.62 bbl).

Volume of influx between hole and drill pipe = 30 – 2.62 = 27.38 bbl.

Height of influx between hole and drill pipe = 27.38 bbl ÷ 0.0459 bbl/ft = 597 ft

Total influx height once the BHA penetrates into the influx = 90 + 597 = 687 ft

Mud Gradient (PGM) = 9 × 0.052 = 0.468 psi/ft

ΔH = 687 – 427 = 260 ft

ΔCP = 260× (0.468 – 0.3) psi

ΔCP = 44 psi (round up figure)

New casing pressure  = 150 + 44 = 194 psi

Figure 3 – Casing pressure once the influx is penetrated.

For non-migrating influxes, such as oil or saltwater kicks, estimating the penetration time is relatively straightforward. We simply calculate the length of pipe needed to reach the influx depth and subtract it from the initial distance between the drill string and the bottom of the wellbore.

In practice, a safety factor can be added to the calculated casing pressure increase. This ensures the well remains overbalanced even after encountering the influx, providing an additional layer of security. However, it’s crucial to ensure this safety factor doesn’t exceed the maximum pressure the well can withstand.

The situation becomes more complex with migrating gas kicks. Relying solely on surface pressure or the volume of fluid bled off (volume accounting) is insufficient for maintaining well control. In such cases, Volumetric Control techniques become essential. This method involves simultaneously measuring the volume of fluid bled off and monitoring the volume of drill pipe stripped into the well. The next section will delve deeper into combining Volumetric Control with stripping operations.

By understanding the impact of influx penetration on well control procedures, operators can ensure safe and efficient stripping operations even when encountering unexpected situation.

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.

<p>The post Understanding Influx Penetration and Its Calculation during Stripping Well Control first appeared on Drilling Formulas and Drilling Calculations.</p>

In order to shear a string and shut the well in, two essential components used in Blow Out Preventer (BOP) are Shearing Blind Rams (SBR) and Interlocking Shear Rams (ISR), both of which play a vital role in containing well pressures, controlling blowouts, and shearing drill pipes when needed.

This article examines the key differences between these technologies and highlights the advantages of ISR over SBR.

Shearing Blind Rams (SBR)

Shearing Blind Rams (SBR) are the standard rams used in most BOPs. These rams are designed primarily for shearing operations, although they also function as blind rams, sealing the well after cutting the drill pipe.

Example: Shear Blind Rams (SBR) – Cameron Type U

Key Features of SBR

1. Single-Piece Design: SBRs consist of a single-piece structure where the blades are integral to the ram body. This creates a robust shearing tool, but one that may be limited when dealing with larger or multiple pipes.
2. Blade Geometry: The upper SBR is designed with a V-shaped cutting edge, while the lower SBR features a straight cutting edge. This combination ensures that the pipe is sheared effectively, but it also requires the lower portion of the severed pipe (fish) to fold over.
3. Sealing Capability: After shearing, the upper SBR houses a large blade packer that seals on the front surface of the lower SBR blade. This packer is designed to maintain a seal under normal operating conditions, preventing fluid or gas escape from the well.
4. Lower Fish Folding: One drawback of SBRs is that the lower fish must be folded over after the pipe is cut, which requires additional force. This folding mechanism is necessary to create a proper seal between the upper and lower blades.
5. Prolonged Packer Life: The large front packer in the upper shear ram is designed to seal against the front face of the lower shear ram. This prolongs the life of the packer and improves the overall durability of the ram assembly. However, the sealing mechanism may not be as reliable as that of ISR rams, especially in oversized wellbore cavities.

Interlocking Shear Rams (ISR)

The Interlocking Shear Rams (ISR) are an advanced shearing technology, offering an enhanced capacity over the standard Shearing Blind Rams (SBR). Their unique design enables them to handle more complex and challenging well conditions.

Example: Interlock Shear Rams (ISR) – Cameron Type U

Key Features of ISR

1. Improved Shearing Capacity: ISR rams can handle larger shear loads compared to traditional SBRs. This makes them ideal for situations where a higher shearing force is required, such as when drilling with larger or multiple strings of pipe.
2. V-Shaped Geometry: One of the most distinctive features of ISR rams is their V-shaped design. This shape maximizes shearing efficiency, allowing ISR rams to cut through drill pipes as large as 6-5/8 inches in outer diameter (O.D.).
3. Wider Cutting Range: The width of ISR rams allows them to shear through multiple strings at once. This ability is crucial when working in environments where multiple pipes or strings are being run into the wellbore simultaneously, offering a significant improvement over standard SBRs that may struggle with such complexity.
4. No Fish Folding Requirement: Unlike SBRs, ISR rams do not need to fold over the lower “fish” (the severed portion of the drill pipe). This reduces the force required to complete the shear, enhancing operational efficiency.
5. Pumpability After Shear: After the ISR rams shear the drill pipe, the severed portion remains open. This allows kill mud to be pumped down through the cut pipe, aiding in well control by equalizing wellbore pressure and potentially stopping a blowout.
6. Interlocking Mechanism: The interlocking mechanism incorporated into the ISR rams ensures that they can be used in oversized cavities without the risk of a leak, even at low wellbore pressures. This feature is essential in maintaining well integrity and preventing pressure leaks during critical operations.

Comparison Between ISR and SBR

The ISR and SBR both serve the same basic function—shearing drill pipe during well control operations—but the differences in design and functionality set them apart in terms of performance and versatility.

• Shearing Capability: ISR rams can handle larger pipes and multiple strings, making them more suitable for complex or high-risk operations. SBRs, on the other hand, are better suited to standard shearing tasks.
• Force Requirements: ISR rams require less force to shear because they do not need to fold the lower fish. This can save valuable time and reduce wear on the BOP equipment.
• Post-Shear Pumping: After shearing, ISR rams leave the fish open, allowing kill mud to be pumped through the severed pipe. In contrast, SBRs seal the well after shearing, which may limit options for pressure control.
• Leak Prevention: The interlocking mechanism in ISR rams ensures a more secure fit in oversized cavities, reducing the risk of leaks at low pressures. SBRs, while effective, may not offer the same level of sealing security in oversized cavities.

Conclusion

The Interlocking Shear Rams (ISR) provide an improved alternative to the standard Shearing Blind Rams (SBR) for well control operations, especially when dealing with larger or more complex drill pipe scenarios. Their advanced shearing capacity, reduced force requirements, and ability to maintain well control through open-ended fish make ISR rams a superior choice in many situations. However, SBRs still play an important role in standard well control operations and continue to be widely used due to their reliability and cost-effectiveness. For drilling operations requiring enhanced shearing capabilities and increased efficiency, ISR rams offer a compelling solution, ensuring both safety and operational success.

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.

U RaM-Type BOP. (n.d.-b). https://www.slb.com/products-and-services/innovating-in-oil-and-gas/well-construction/rigs-and-equipment/pressure-control-equipment/ram-type-bops/u-ram-type-bop

<p>The post Understanding Shearing Blind Rams (SBR) and Interlocking Shear Rams (ISR) in Well Control Operations first appeared on Drilling Formulas and Drilling Calculations.</p>

References

<p>The post Barriers in Well Control: A Comprehensive Overview first appeared on Drilling Formulas and Drilling Calculations.</p>

Well control responsibilities on a rig involve a coordinated effort by multiple personnel, each tasked with critical roles during well control operations. These responsibilities are vital in managing potential risks and ensuring that the well is controlled and stabilized effectively.

Company Representative

Company Representative plays a crucial role as the overall supervisor, ensuring that all steps are conducted safely and effectively. They closely monitor the rig teams ensuring that each member follows the well control procedures accurately. Their leadership ensures that every action is aligned with operational and safety standards.

Before initiating any well control operations, the Company Representative is responsible for verifying the accuracy of critical data, such as well pressures and volumes. By confirming this information, they help avoid potential risks that could jeopardize the safety of the operation.

A key aspect of their role is serving as the communication link between the rig and the company’s headquarters. In the event of a well kill or emergency, the Company Representative ensures that updates are exchanged efficiently, coordinating responses between on-site personnel and management to ensure timely, well-informed decisions.

Toolpusher

The Toolpusher plays a key role in ensuring the crew is organized and fully prepared for any well-kill operations. This involves constant communication with the company representatives throughout the operation. The Toolpusher may also be responsible for operating the choke, either personally or through a designated individual.

Driller

The Driller bears the responsibility of continuously monitoring the well, identifying any kick indicators that signal an issue, and promptly shutting in the well when necessary. Following a shut-in, the Driller contacts the Person-in-Charge and, on floating rigs, the Subsea Engineer is called to the drill floor. The Driller closely monitors pressures, volumes, and time, designating a crew member to record these parameters during the kill operation, while also operating the mud pump.

Assistant Driller / Derrickhand

Assistant Drillers and Derrickhands are tasked with lining up the mud gas separator and vacuum degasser, as well as preparing the mixing pumps and bulk barite system for weighting up the mud. They stand by for specific instructions from the Toolpusher and Mud Engineer, and during pumping operations, they constantly monitor mud weight and pit volumes, reporting their findings to the Driller.

Floormen

Floormen follow the instructions given by the Driller, ensuring the operation runs smoothly.

Mud Engineer

The Mud Engineer coordinates the building and maintenance of the mud system, checks the preparations made by the Assistant Driller or Derrickhand, and monitors the mud properties and return flow for any signs of abnormalities. Additionally, the Mud Engineer confirms the calibration of the mud balance and checks all mud and chemical volumes on board.

Barge Supervisor / Captain

The Barge Supervisor or Captain ensures that the bulk system is charged and ready for immediate use. They stand by in the control room or bridge, prepared to respond to emergencies and notify the standby vessel, if available, to move into evacuation position. They also ensure the readiness of the evacuation equipment.

Crane Operator

The Crane Operator is responsible for ensuring doors and hatches are closed, assisting in mud mixing operations, and supervising Roustabouts. They report to the mud pits or sack room to assist the Assistant Driller and Derrickhand.

Subsea Engineer

The Subsea Engineer reports to the drill floor to check the functions and operating pressures of the Blowout Preventer (BOP) control panel and remains present at the panel in case of equipment issues.

Mud Logging Engineers

Mud Logging Engineers are stationed at the mud logging unit, where they continuously monitor the circulating and drilling systems. They review all data and report any abnormalities to the company representatives, Driller, and Toolpusher.

Cementer

The Cementer ensures that the cement unit is tested and ready for operation and that slurry formulations and additives are prepared in case a cement plug is needed. If required, the Cementer operates the cement unit under the direction of the Senior Toolpusher.

Electrician / Mechanic

Electricians and Mechanics remain on standby, ready to respond to any instructions during well control operations.

Control Room Operator

The Control Room Operator ensures the rig’s stability and continuously monitors safety systems, including gas alarms, throughout the operation.

Radio Operator

The Radio Operator logs all communications, including calls, telexes, and faxes, while keeping communication lines open for the DSM/WSM, Offshore Installation Manager (OIM), and any other personnel authorized by the OIM. They also assist with all communication matters as directed by the OIM and DSM/WSM.

Each role within the rig is essential to maintaining safety and ensuring the well control operation proceeds efficiently, with clear responsibilities and communication protocols in place for every individual involved.

Conclusion

In summary, well control on a rig is a team effort that requires every crew member to understand and execute their specific responsibilities. From the Toolpusher’s overall organization of the crew to the Driller’s monitoring of the well, and the Mud Engineer’s management of the drilling fluids, each role is essential in ensuring the safe and effective management of the well. Proper coordination, preparation, and communication are key to preventing and controlling well incidents, maintaining safety, and avoiding catastrophic blowouts.

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.

<p>The post Well Control Responsibilities on a Rig first appeared on Drilling Formulas and Drilling Calculations.</p>

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.

Purpose and Benefits of Slow Circulating Rates

When performing well control operations, the primary goal is to maintain constant bottom hole pressure to avoid losses or taking unintentional influx, which occurs when formation fluids enter the wellbore uncontrollably. Well kills are typically executed at SCRs, which are lower than regular drilling rates, due to the following advantages:

1. Negligible Friction Pressure in the Annulus: At reduced pump rates, the friction pressure within the annular space (the area between the drill pipe and the casing) is minimized. This is beneficial because it allows for more accurate control over bottom hole pressure, reducing the chance of unplanned pressure surges that could compromise well integrity.
2. Better Choke Control: Lower flow rates make it easier for the choke operator to manage choke pressures precisely. During well control operations, the choke, a device used to control fluid flow and pressure, plays a pivotal role. The choke operator can more easily maintain stable pressure readings, allowing for safer well control.
3. Reduced Wear and Erosion of Equipment: Operating at SCRs limits the erosion and wear of the choke manifold and its components. High flow rates lead to more significant frictional forces, which can quickly degrade equipment. Slower rates extend the lifespan of essential well control components, thereby lowering maintenance costs and downtime.
4. Barite and Mud Weight Management: SCRs facilitate the control of barite (a weighting agent used in drilling fluids) and mud weight (MW). Managing these parameters effectively is crucial to maintaining appropriate mud properties, which, in turn, helps control wellbore pressure during a well kill operation.
5. Reduced Pressure on the Wellbore: The overall pressure exerted on the wellbore is lower with SCRs, reducing the risk of formation fractures or breakdowns. This is particularly beneficial when dealing with formations that have low fracture gradients, as excessive pressures could otherwise damage the well structure.

Measuring Slow Circulating Rates

SCR pressures are measured and recorded under various conditions to ensure accurate bottom hole pressure calculations. Regular recording of SCR values is essential for adjusting well control parameters in real-time and ensuring optimal performance during circulation. SCR readings are typically recorded when:

• Mud Weight (MW) or Mud Properties Change: Changes in mud composition affect circulation pressures, so measuring SCR helps recalibrate bottom hole pressure accurately.
• Bit Nozzle or Bottom Hole Assembly (BHA) Changes: Modifications to the drilling assembly alter flow dynamics, requiring new SCR measurements to gauge the resulting pressure effects.
• After Each Trip: Drilling trips, where equipment is raised or lowered in the wellbore, can affect pressure, and measuring SCR after each trip helps maintain consistent pressure control.
• Every 500-1000 Feet of Depth: As drilling progresses and the well depth increases, recording SCR pressures every 500 feet helps maintain safe and accurate well control as pressure profiles change with depth.
• After Equipment Changes or Repairs: Pump or surface equipment repairs can impact circulation performance, making updated SCR measurements critical for stable well control operations.

Friction Pressures in Subsea Operations

In subsea drilling, friction pressures in choke and kill lines are essential considerations. These lines form part of the fluid circulation path and can impose additional pressure on the wellbore, especially in deepwater environments where water depth and narrower inner diameters contribute to greater frictional resistance. The friction pressure in these lines must be routinely measured, recorded, and accounted for to prevent underestimating the wellbore pressure, which could lead to operational hazards.

Subsea well control is particularly complex due to the high pressures at depth and the reduced diameter of subsea lines, which increases friction as fluids are pumped through. This friction pressure, if unaccounted for, can reduce the precision of pressure control, increasing the risk of uncontrolled flow. Therefore, friction pressure measurements in choke and kill lines help ensure that the pressures applied to the wellbore remain within safe operational limits.

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.

<p>The post Slow Circulating Rates (SCRs) in Well Control Operations first appeared on Drilling Formulas and Drilling Calculations.</p>

Tripping operations in drilling are critical phases where the drill string is either pulled out of the well (tripping out) or run back into the well (tripping in). These operations require good planning and execution to maintain well control and prevent issues such as kicks or swabbing. This article outlines essential tripping considerations for effective tripping, focusing on trip tanks, slugs, pumping out, tripping-in techniques, and breaking circulation.

The Role of Trip Tanks

A trip tank is a specialized vessel used to monitor the volume of drilling fluid during tripping operations. Typically holding between 20 to 50 barrels, its design allows for precise detection of fluid volume changes, which is vital for maintaining well control. The trip tank continuously circulates fluid to keep the well filled, compensating for the volume occupied by the drill string. Accurate monitoring through the trip tank helps detect potential issues such as swabbing or influxes of formation fluids.

During tripping out, it is crucial to ensure that every stand of drill string removed is replaced with an equivalent volume of drilling fluid. For instance, if ten stands are pulled out, there should be a corresponding decrease of approximately eight barrels in the trip tank. Any discrepancy may indicate that formation fluids have entered the wellbore, necessitating immediate corrective actions.

Slugs: Enhancing Efficiency

Slugs are large volumes of drilling fluid pumped into the well to facilitate pulling the pipe dry whenever feasible. The slug’s volume and weight should remain consistent across trips to ensure reliable measurements1. Monitoring the pressure-volume-temperature (PVT) data during slugging operations allows for accurate assessment of returns while the slug is pumped and falls. This practice not only enhances operational efficiency but also minimizes risks associated with unexpected pressure changes.

Pumping Out Techniques

In certain hole conditions, it may be necessary to pump the drill pipe out of the hole to a predetermined depth, such as the casing shoe or liner top. This technique helps minimize swab pressures that could lead to well control issues. Developing a rig-specific procedure for this operation ensures consistency and accuracy in monitoring and fingerprinting12. By adhering to these protocols, crews can effectively manage pressure dynamics during tripping operations.

Tripping-In: Managing Running Speeds

When tripping in, careful attention must be paid to running speeds to prevent excessive surges that can induce high surge pressures. Surge pressures can occur when initiating circulation or during pipe movement. To mitigate these risks, operators should aim for controlled descent rates and be vigilant about monitoring pressure fluctuations throughout the process.

Breaking Circulation: Challenges and Solutions

Breaking circulation can lead to very high surge pressures, especially if mud conditions are poor or gel strengths are elevated. In such scenarios, staging within the hole can be beneficial when breaking circulation. This technique involves temporarily halting operations at predetermined depths to allow for pressure stabilization before resuming full circulation4. It is essential to monitor mud properties closely during this phase to ensure optimal performance and prevent complications.

Conclusion

Effective management of tripping operations is paramount in drilling activities. Utilizing trip tanks accurately monitors fluid levels and prevents potential well control issues during tripping out and in. Additionally, employing slugs enhances operational efficiency while minimizing risks associated with pressure fluctuations. By developing specific procedures for pumping out and carefully managing running speeds during tripping-in operations, crews can significantly improve safety and performance outcomes.

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.

<p>The post Tripping Considerations in Drilling Operations first appeared on Drilling Formulas and Drilling Calculations.</p>