DrillBuddy

01/19/2025

01/15/2025

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.

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 fluids, 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 pressure transmission through the set cement.

The critical gel strength, referred to as Zero Gel Time, typically begins around 100 pounds per 100 square feet and ends at approximately 500 pounds per 100 square feet. The time between these two gel strength levels is known as the transition time.

Mechanical Barriers

In certain situations, utilizing mechanical barriers such as packers or plugs can provide an added layer of protection against gas migration, ensuring long-term well integrity.

By addressing these factors, the industry can mitigate the risks associated with gas migration in cement and improve the overall success of cementing operations.

For further information on this or other well control subjects, consult my Well Control Manual at: https://learn-well-control.com/product/well-control-manual-by-edwin-ritchie/

01/15/2025

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/

01/13/2025

Kick Warning Signs: What Drillers Need to Watch For

Kick warning signs are crucial indicators that help a driller recognize when the well is at risk of going underbalanced, which could lead to a kick (influx of formation fluids into the well). These warning signs fall into three categories, as defined by the API:

- Offset Well Information
- Physical Response Indicators
- Chemical and Technical Indicators

When a warning sign is detected, the driller should immediately perform a flow check to assess the situation and prevent further escalation.

1. Offset Well Information

Offset wells refer to wells drilled in the same area before, providing valuable data on the formation and pressures. Information from offset wells can give advance warning of potential kick risks. Key data includes:

Formation pressure gradients: Information on pressure zones and their depths can indicate areas that may be capable of flowing.
Fracture gradients: Data on the fracture pressure of the formations can warn of potential loss zones.

Permeability: Permeability data shows how easily fluids can enter the wellbore, indicating potential kick risks if the formation is highly permeable.

This information is only useful if it is shared between reservoir engineers, well planners, and the rig team, ensuring everyone is aware of potential risks.

2. Well Physical Indicators

Physical indicators are warning signs that can be observed directly during the drilling process. These indicators are often picked up through close monitoring of drilling parameters, mud monitoring systems, and flow line data. Physical warning signs include:

Drilling break: A sudden change in the rate of pe*******on can signal that you're drilling into an under-compacted shale or a high-pressure zone.

Lost circulation: If mud returns are lost to the formation, it indicates that hydrostatic pressure is being reduced, putting the well at risk of going underbalanced.

Pump pressure/speed variations: If the pump pressure or speed fluctuates, it could suggest that a kick has occurred or that the well is drilling sloughing formations.

Temperature gradient increase: Higher temperatures can indicate you are drilling into high-pressure or gas-bearing formations, or under-compacted shale.

Reduction in mud density: A decrease in mud density might suggest an influx of less dense formation fluids, increasing the risk of a kick.

Gas levels increase: Rising levels of gas after connections (connection gas) can indicate increasing formation pressures. Similarly, trip gas after circulating can signal that hydrostatic pressure is decreasing.

Tight hole/sloughing: When the hole becomes tight or sloughing, it can suggest that you're encountering high-pressure formations.

Changes in cuttings: Significant changes in the size, shape, or quantity of the drill cuttings can indicate that you're drilling into high-pressure formations.

3. Chemical and Technical Indicators

Chemical and technical indicators are usually monitored by specialized personnel such as mud engineers and mud loggers. These indicators help detect any subtle changes that might indicate a kick. They include:

Chloride changes: Variations in chloride levels in the mud can point to a potential water kick.

Oil shows and staining: If oil is observed on the cuttings or shaker screens, this can indicate an influx of formation fluids.

Gas shows: Increased gas readings on the gas chromatograph are a common sign of formation fluids entering the wellbore.

Formation fluid in mud: An influx of formation fluid into the mud can cause a decrease in mud density, possibly affecting its viscosity and gel strength.

Shale density reduction: A decrease in shale density observed on logging while drilling (LWD) tools may signal under-compacted shale, which could be under pressure.

Resistivity changes: Changes in resistivity on LWD logs can indicate changes in formation fluid properties.

Decrease in the “d” exponent: This occurs when drilling through consistent shale beds and can indicate under-compacted shale, increasing the likelihood of a kick.

Conclusion

Recognizing kick warning signs early is crucial to preventing well control issues. By staying alert to offset well information, physical changes in the well, and chemical/technical indicators, drillers can act swiftly to perform necessary checks and maintain control over the well. Regular training, close monitoring of drilling parameters, and communication between all team members help ensure that warning signs are detected and addressed promptly.

For more information, see my Well Control Manual at: https://learn-well-control.com/product/well-control-manual-by-edwin-ritchie/

01/12/2025

Trip Tank: Essential for Accurate Measurement During Well Operations

A trip tank plays a crucial role in ensuring accurate measurement of fluid returns during trips or periods of non-circulation. Without it, the driller might struggle to detect small differences between the anticipated and the actual returns, especially in a large active system. For instance, in a typical 700-barrel tank, a mere one-inch gain could equal approximately 7.5 barrels of fluid.

In the past, drillers had to count the number of pump strokes required to fill the hole at regular intervals. This method, however, was prone to inaccuracies due to potential errors in estimating pump efficiency. Today, the trip tank, equipped with a 3” to 4” centrifugal circulating pump, is the standard method for measuring hole fill during trips and non-circulation periods, significantly reducing the likelihood of serious incidents.

How the Trip Tank Works

To measure and monitor fluid returns, the driller diverts them into a smaller, auxiliary tank known as a trip tank. For example, in a typical 40-barrel trip tank, each inch on the gauge might represent just 0.4 barrels of fluid. This smaller volume allows for more precise monitoring compared to larger, active systems.

Trip tanks are often standalone units, equipped with an internal gauge marked off in one-barrel intervals or even smaller increments. The volume of a trip tank can vary, typically ranging from 10 barrels to 100 barrels, depending on the size of the rig. Smaller workover and completion rigs may use trip tanks as small as 5 barrels. It’s important that the trip tank has a larger capacity than the pill (slug) tank. On smaller rigs, the trip tank may even be a separate compartment built into the mud tank.

Stripping Tanks: For Even Finer Measurements

In some cases, rigs are also equipped with a stripping tank, a smaller tank used for extremely fine measurements, down to as little as 0.02 barrels per inch. However, due to their limited capacity,stripping tanks are generally not suitable for use as trip tanks.

Measurement Methods and Monitoring

Trip tanks can be equipped with various measurement systems, such as mechanical floats attached to pulleys, or more advanced options like electronic sensors, sonar, or infrared sensors. These tanks are not considered part of the active system during drilling operations and are bypassed when the well is being circulated.

Despite this, trip and stripping tanks can still be monitored while circulating mud into the well through the fill-up line. Mud returns are then sent back via a return line, usually off the flow line. Any changes in the mud volume in the hole are immediately reflected in the trip tank’s fluid level, ensuring real-time monitoring.

Keeping the Mud in Motion

To maintain consistency, some trip tanks are equipped with paddle agitators or jets that stir the mud when it’s not being circulated. This keeps the mud evenly mixed and helps avoid inconsistencies that could lead to inaccurate measurements.

In summary, the trip tank is an indispensable tool in modern drilling operations, providing accurate, real-time fluid measurement that helps prevent well control issues and ensures a safer, more efficient drilling process.

For more information on using trip and strip tanks, visit my Well Control Manual at: https://learn-well-control.com/product/well-control-manual-by-edwin-ritchie/

01/12/2025

LOT Requirements

Requirements to Complete a LOT (Leak-Off Test) or FIT (Formation Integrity Test)

Hole Conditions:

The new casing shoe must be drilled out, and an additional 5 to 30 feet of formation must be penetrated.
A sample from the new formation should be circulated up to verify the formation has been drilled.
Circulate the hole with mud until the shakers are free of cement and cuttings.

Mud Properties:

The mud must be clean, consistent, have low gel strengths, and have a known mud weight.
If there is uncertainty about the mud weight consistency, the test should not be conducted until you are certain the mud properties are the same throughout the active system.
Accurate calculation of hydrostatic pressure is crucial for the test’s validity.
Excessive gel strengths may negatively impact the results of the

LOT/FIT.
Line Up:

LOT/FIT tests require a high-pressure, low-volume pump, typically a cement pump.

The pump should be lined up to pump both down the drill pipe and into the annulus.

A Blowout Preventer (BOP) must be closed to seal the annulus, and BOP side outlets opened to pressurize the choke line against a closed choke.

Valves should be positioned to allow the recording of both drill pipe and casing pressure.

Testing through a mud motor or non-return valve should be avoided if possible.

Instrumentation:

The driller must be able to record cumulative pump strokes or volume pumped, drill pipe pressure, and casing pressure.

Accurate pressure measurement requires recently calibrated pressure gauges and large-scale charts mounted on a manifold.
In some cases, downhole pressure gauges may be used for better results, especially when using high mud weights or compressive base fluids.

Pump Rates:

The pump rates should be slow, typically ½ barrel per minute (bbl/min) or less, to ensure accurate readings and minimize risks during the test.

These requirements ensure a successful and accurate LOT or FIT, providing essential data for well integrity and pressure management during drilling.

For more information on LOTs and other Well Control subjects, read my Well Control Manual at: https://learn-well-control.com/product/well-control-manual-by-edwin-ritchie/

01/12/2025

Dynamic MAASP and Kill Speed: Understanding Pressure Losses During Well Control
When calculating the Maximum Allowable Annular Surface Pressure (MAASP), we typically do so under static conditions. However, once the pumps are started during a well kill operation, we immediately face annular pressure losses. These losses, which occur as fluids move through the wellbore, add to the pressure and increase the risk of fracturing or breaking down exposed formations. To minimize this risk, it’s important to manage these dynamic pressures by controlling the kill rate (pump rate), which helps to reduce the additional pressure applied during the kill process.

The Role of Dynamic Pressure Losses
In deep, slim-hole wells, annular pressure losses (APL) can become significant, even at slow kill rates. If not properly managed, this pressure could cause the shoe (the bottom part of the casing) to break down. If you know the annular pressure loss at the shoe, you can adjust the casing pressure accordingly to offset this loss. However, this action reduces the MAASP by the same amount, leading to what is known as the Dynamic MAASP.

Calculating the dynamic MAASP can be complex, especially when determining annular pressure loss accurately. As a result, dynamic MAASP is not commonly used in surface stack operations where APL is harder to measure.

Subsea Wells and Choke Line Friction
Subsea wells are a different story. In these wells, there can be significant dynamic pressure losses through the choke line. Much like annular pressure loss, these losses contribute to the overall pressure in the wellbore. The good news is that choke line friction is easy to measure, which makes it possible to account for it when adjusting casing pressure.

To avoid exceeding MAASP, it’s common practice to reduce the casing pressure by the amount of choke line friction as the pumps are brought online during a kill operation. This adjustment effectively reduces the dynamic MAASP by the same amount as the choke line friction.

Calculating Dynamic MAASP
The equation for calculating the Dynamic MAASP is simple:

Dynamic MAASP (psi) = Initial MAASP (psi) – Choke Line Friction (psi)

Example Calculation:
Let’s look at an example of a subsea well.

Initial MAASP = 1638 psi
Choke Line Friction at 40 SPM = 160 psi
To calculate the Dynamic MAASP when bringing the pumps to 40 strokes per minute (SPM) at the start of the kill:

Dynamic MAASP = Initial MAASP (1638 psi) – Choke Line Friction (160 psi)
Dynamic MAASP = 1638 psi – 160 psi = 1478 psi

So, after adjusting for choke line friction, the new dynamic MAASP pressure would be 1478 psi.

Conclusion
Managing dynamic pressures during a well kill operation is critical to preventing damage to the wellbore and formations. By understanding how to adjust the MAASP for annular pressure losses and choke line friction, operators can maintain control of the well while minimizing the risks associated with pressure increases.

01/10/2025

When do uou use TVD vs MD on a Kill Sheet?

Use True Vertical Depth (TVD) when calculating:

-Hydrostatic pressure
-Fracture pressure
-Formation pressure

Use Measured Depth (MD) when calculating:

-Mud volumes
-Pump pressure losses
-Drill string length
-Hydraulic delay

TVD is essential for pressure-related calculations, while MD is used for volume and equipment-related calculations. Always ensure you're using the correct depth type for each calculation.

01/10/2025

Trapped Gas in Horizontal Wells: What You Need to Know

In horizontal wells, gas can sometimes become trapped in pockets within the wellbore. Due to buoyancy, gas tends to rise and gather on the high side of the hole when circulation slows or stops. This gas can remain in these pockets, such as washouts, when circulation resumes at a slow rate.

In wells that are deviated at more than 90 degrees, gas might even migrate toward the bottom (toe) of the well. Unfortunately, these gas pockets can be difficult to remove when circulating at low rates, and they may only become dislodged later during drilling when pump rates resume to normal.

To avoid these problems, it’s often recommended to use the Driller’s Method for well control in high-angle or extended-reach wells. This method involves starting the first circulation at a kill rate close to the normal drilling rate. This helps dislodge the trapped gas into the vertical section, preventing it from becoming an issue later on. By circulating at a higher rate initially, you can ensure that all the gas is safely evacuated.

For more detailed information on trapped gas in horizontal wells,see my Well Control Manual V2.6 at:

01/09/2025

What is Kick Intensity?

Kick intensity in drilling refers to the degree of underbalance in the wellbore, which occurs when the pressure exerted by the drilling fluid is lower than the pressure exerted by the formation fluids. The greater the difference between the pressure in the wellbore (due to the mud weight) and the formation pressure, the more intense the kick. The intensity of the kick impacts the speed and volume of the influx of formation fluids into the wellbore, which can be critical for the well’s safety.

In practical terms, kick intensity is related to how much the formation pressure exceeds the pressure exerted by the drilling fluid, and this imbalance is directly tied to the risk of a blowout. The pressure difference is typically measured in terms of pounds per gallon (ppg) or kilograms per cubic meter (kg/m³) for mud weight, or in pounds per square inch (psi) or kilopascals (kPa) for pressure measurements.

For more information on Kick Intensity as it relates to well control visit:

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