Mechanical sticking – Causes, indications, prevention, and recovery

Nonproductive time has a significant impact on the cost of a well. Based on several studies, a stuck pipe is one of the most expensive complications during drilling operations. Deploying suck pipe preventive measures is far more cost-efficient than having to use recovery methods. Recognizing potential drilling problems, understanding their causes, and preparing solutions in advance are key to success. There are primarily three types of string-stuck situations faced during drilling: differential sticking, mechanical sticking, and formation-related sticking.

Mechanical sticking occurs when the drill string gets trapped in the wellbore due to obstructions or geometric constraints primarily resulting from drilling practices. It differs from other pipe-sticking mechanisms resulting from a pressure differential or formation-related issues. As detailed below, there could be several reasons for mechanical sticking, and maintaining a close watch on wellbore conditions and taking timely action can help prevent it.

Keyseats:

Keyseats are caused by well trajectory issues. If there is a sharp change in direction in a section of the borehole, it results in a high dogleg. In these crooked sections, a narrow groove or channel may form in the wall due to the motion of the drill string while drilling or tripping. This groove, known as a keyseat, can pose operational challenges. The larger-diameter components, such as tool joints or the bottom hole assembly (BHA), can wedge into these grooves during tripping, causing the string to become stuck mechanically.

A keyseat will likely develop if the wellbore surveys in a high-angle well reveal higher doglegs. Circulation will be normal, but erratic overpulls and pipe sticking tendencies while tripping indicate a possible keyseat in the well. If these overpulls occur at a specific depth when larger-diameter components cross it, it would further consolidate the possibility of a keyseat. Keyseat sticking often allows free downward movement.

Some of the preventive measures to avoid the string getting stuck due to keyseat are as below:

Closely watch the bottom hole assembly's build, drop, and turn tendencies. Avoid severe deviations and minimize doglegs. Optimize drilling practices to minimize wellbore tortuosity.
Optimize bottom hole assembly (BHA) design to achieve stability with minimum vibrations during drilling operations. Run the keyseat wiper in the BHA and include a jar to free the string in case it gets stuck.
Ream the hole frequently and ream potential keyseat early to smoothen it before it hampers the string movement.
Minimize rathole length below casing. The rathole is the section of the wellbore located below the casing shoe, which is a larger-diameter hole than the next section. A longer rathole results in unstable BHA while starting the next hole section, which can cause higher doglegs, giving rise to the possibility of forming keaseat.
Specialized casing/liner shoe designs smooth the wellbore while running the string, helping it reach the drilled depth and minimizing the rathole length.

2. Under-gauge hole:

Drilling in abrasive formation wears down the bit and other BHA components. While the drilling continues with the under-gauge bit, it drills a smaller hole section. A new bit may jam when running in the hole entering this under-gauge section.

Measuring the gauge of the pulled-out bit and stabilizers helps forewarn the possibility of encountering an under-gauge hole while running it with a new bit and replaced BHA components.

If the new bit takes weight before touching bottom when running in or faces difficulty while rotating or pulling out, it indicates an under-gauge hole.

Running the new assembly too fast could cause it to jam in the new bit and become mechanically stuck in an under-gauge section. To avoid getting stuck and minimize surge pressures, it is a good practice to run the string in the open hole at a controlled speed.

Preventive measures are as follows:

Identify abrasive formations in advance by evaluating the stratigraphic maps and offset well data.
Use bits with robust gauge protection to minimize the bit wear.
Gauge bits and stabilizers accurately once out of the hole to anticipate any under-gauge conditions while running in the new bit and assembly.
Make slow trips and ream frequently to avoid getting mechanically stuck in an under-gauge hole.
Avoid forcing the bit while running in. Instead, ream down when any obstruction is encountered in the open hole.

3. Inadequate Hole Cleaning

According to statistics, Inadequate Hole Cleaning is a primary cause of up to 30% of mechanical stuck pipe events in vertical wells and up to 80% in high-angle wells. Poor removal of drill cuttings leads to accumulation in the annulus and the formation of cutting beds, increasing the risk of pipe sticking. Accumulation of drilled cuttings or unstable formation material (cavings) in the annulus can obstruct the drill string. This is common in directional wells, where cuttings settle on the low side. Inadequate hole cleaning occurs when the drilling fluid fails to remove cuttings from the wellbore effectively.

Common indicators of inadequate hole cleaning are as follows:

Increased pump pressure with spikes: When hole cleaning isn’t done correctly, cuttings can accumulate in the annulus. This buildup restricts the flow path, making it harder for the fluid to move. Consequently, the pump has to exert more effort, resulting in increased pressure. Spikes in pressure can occur when bigger pieces of cuttings or debris briefly block the system, resulting in sudden surges in pressure.

Reduced cuttings at the shale shaker: The shale shaker operates as a vibrating screen designed to remove and separate drilled cuttings before the mud is sent back into the well. Typically, a consistent flow of cuttings indicates that drilling is progressing well. However, if fewer cuttings are visible on the shaker screen, they may not be efficiently brought to the surface. This could indicate that they're settling in the wellbore due to inadequate fluid flow or subpar fluid characteristics, suggesting inadequate hole cleaning.

Increased torque and drag: When cuttings accumulate in the wellbore, they form a layer of debris that increases friction between the drill string and the borehole wall. This increased friction makes it more difficult to rotate the drill string, resulting in higher torque. Raising or lowering the drill string also shows higher drag. This situation indicates a physical blockage due to inadequate hole cleaning.

Decreased rate of penetration (ROP): If cuttings are not efficiently removed, the bit may regrind old cuttings instead of cutting fresh rock, reducing drilling efficiency. Accumulated cuttings can also pack around the bit, creating a cushion that hampers its ability to contact the formation, resulting in a reduced penetration rate.

Lost circulation: A buildup of cuttings in the wellbore can increase pressure across certain zones, potentially fracturing the formation and opening pathways for fluid loss. Although lost circulation has multiple causes, poor hole cleaning can contribute to it by creating these high-pressure conditions.

Pipe sticks shortly after pump shutdown: When the pumps are turned off, the drilling fluid stops circulating, and any suspended cuttings in the wellbore begin to settle. In cases of inadequate hole cleaning, many cuttings may already be present in the annulus, settling around drill string components and making movement or rotation difficult. If movement restriction is noticed shortly after pump shutdown, it indicates inadequate hole cleaning.

Preventive measures to address inadequate hole cleaning conditions are as follows:

Track the volume of cuttings returning to the surface closely and compare it to the amount expected based on the drilling rate of penetration (ROP). If there is a significant discrepancy, increase the circulation time or adjust the mud properties to enhance cleaning.
Ensuring a clean wellbore before pulling the drill string prevents complications such as pipe sticking. Circulate at an adequate rate to transport all cuttings to the surface until the shakers are clean to ensure that the annulus is clear before tripping begins.
The mud's viscosity and density determine its ability to suspend and carry cuttings. If the mud is too thin, cuttings settle; if it is too thick, it may increase pump pressure. The annular velocity must be sufficient to lift cuttings without causing erosion or excessive pressure. Based on downhole conditions, adjust the fluid properties and pump at rates adequate to maintain the required annular velocity, ensuring the effective transportation of cuttings to the surface. Use hydraulics simulation modeling with real-time data to assess the downhole conditions.
Viscous sweeps are high-viscosity pills circulated through the wellbore. Regular drilling fluid may not fully remove cuttings in challenging wells (e.g., deviated or horizontal). Pump viscous sweeps at specific intervals or when poor hole cleaning is suspected.
If the drilling hydraulics is not optimized, a high penetration rate (ROP) can often exceed the hole-cleaning capacity, leading to a buildup of cuttings in the annulus. Reducing the ROP can give more time to remove these cuttings effectively. It's important to adjust drilling parameters to ensure that the drilling rate and rate of cutting generation align with the hole-cleaning capacity.
In deviated or horizontal wells, cuttings can settle on the low side, forming beds that fluid circulation alone may not be able to clear. Wiper trips, which mechanically disturb these beds, help remove cuttings. Carry out regular wiper trips, pulling and lowering the drill string while rotating, to agitate cuttings and allow the fluid to remove them from the wellbore.

4. Junk in the hole

Sometimes, metal debris from equipment failure downhole or dropped tools from the surface can interfere with the drill string's movement. This junk can wedge between the drill bit and the wellbore wall or get caught in the BHA, restricting movement due to tight downhole clearances. Preventing junk from entering the wellbore is critical to avoiding a stuck drill string and maintaining smooth drilling operations.

Indicators of junk in the hole:

Decreased rate of penetration (ROP): Junk at the bottom can clog or damage the bit’s cutting structure, block fluid flow through the nozzles, or prevent bit cutters from fully engaging the formation, reducing the drilling rate.

Erratic torque and sudden increase in drag: A piece of debris may become caught between the bit and the formation or lodge in the stabilizers, resulting in uneven resistance. This manifests as sudden spikes or drops in rotary torque. This will also increase the force needed to pull or lower the string. A sudden increase in drag or erratic torque during string rotation suggests that the drill string is scraping against or becoming hung up on debris downhole, potentially risking a stuck pipe.

Metal shavings at the shaker: The shale shaker screens segregate cuttings from the drilling fluid before it returns to the mud system. If metal shavings are observed along with drilled cuttings, it would indicate either erosion of some steel components in the wellbore or junk in the hole, possibly from a worn-out bit, a failed tool, or a broken piece of a drill string component. These shavings can indicate that metal objects are grinding against the drill string or wellbore, potentially lodging in a way that restricts the string’s ability to move.

Pipe sticks after downhole equipment failure: If a component fails downhole, its remnants, such as broken bearings or other metal pieces, can become lodged in the annulus or BHA. The drill string may initially continue to move freely, but as the debris shifts or accumulates, it can jam the pipe, causing it to become stuck. If pipe sticking is noticed soon after a noticeable failure event, such as a sudden loss of string weight or a sudden pump pressure drop, it would indicate some equipment failure downhole.

Preventive measures:

Good housekeeping on the rig floor: Secure tools to maintain good practices and an organized rig floor. Removing unnecessary equipment from the work area and regularly clearing the floor of debris reduces the risk of loose items accidentally falling into the wellbore and jamming the drill string.

Inspect equipment before running it in: All drilling tools, drill pipe, and bottomhole assembly (BHA) components should be thoroughly checked for worn threads, cracked tool joints, or loose fittings before they go downhole to ensure that no damaged or defective parts enter the well that can break off during operation, becoming junk that might lodge in the annulus. Visual checks, pressure tests, and torque specifications confirm that everything is intact and secure, reducing the likelihood of equipment failure and the risk of the drill string getting stuck due to debris downhole.

Keep the hole covered when not in use: An open wellbore during flat times, when drilling is paused, is vulnerable to objects falling from the surface. Covering the hole is a simple yet effective barrier, ensuring no debris enters during downtime.

Remedial Measures:

If the drill string becomes stuck due to debris in the hole, mechanical manipulation is the best immediate option to free it.

Work the string up and down, gradually increasing force: Apply cyclic stress to break the junk loose or shift it enough to release the string. Start with gentle movements, gradually increasing force within the string’s tensile and torque limits. This can either dislodge the debris or grind it into smaller pieces that can be circulated out of the well. If a piece of metal is wedged between the BHA and the wellbore, this motion might dislodge it, allowing the string to move freely again.

Attempt to move into an over-gauge section to lose the junk: If there is an over-gauge part in the wellbore that’s wider than the nominal diameter, (washout, underreamed, rat hole or previous casing) close to the current location of the string, and if the string can be maneuvered into this larger section, the junk might lose its grip or fall off, freeing the pipe.

5. Cement Problems

After cementing the casing, the casing shoe is drilled out. While drilling the next hole section, chunks of hardened cement near the casing shoe could break off, jamming in the narrow clearance between the bottom hole assembly components and the wellbore. Another situation could occur when the clean-out or drilling assembly is run after spotting a cement plug; the drill string may encounter soft (green) cement, becoming trapped and stuck.

Cement chunks or green cement can create uneven resistance as the drill string rotates or is moved up and down. Hardened chunks may become lodged on the bit or BHA, causing sudden torque spikes and increased drag when jammed.

If cement fragments appear on the shale shaker screens, it indicates that hardened cement chunks are present in the wellbore. These could originate from cement in the rat hole below the casing shoe or cement in the casing shoe annulus that breaks apart because of string vibrations during drilling. Soft cement on the shaker screens would indicate that the cement is not fully set. Green cement can stick to the drill string, bit, or BHA, acting like a glue restricting movement. It might also slump into the wellbore, packing off the annulus.

These indicators collectively suggest issues related to cement. If they precede a stuck pipe event, it could indicate that the string got stuck due to cement-related issues.

Recovery Measures

If the warning signs indicate sticking due to the soft cement, pull the string upwards within the maximum limit while jarring. Since the cement is still not fully set, this should be able to pull the string out of the green cement.

If the string is stuck due to the cement chunks lodged in the narrow annulus clearance, work it up and down. This can dislodge the chunks or break them into smaller pieces that can be circulated out of the well.

Preventive Measures

Ensure sufficient cement curing time: Before drilling can be resumed, cement requires ample time to transition from a slurry to a fully hardened state. The slurry formulation and downhole factors like temperature determine the waiting-on-cement (WOC) duration. Depending on the design, sufficient time should be allowed for the cement to achieve its target compressive strength, typically 500–1000 psi, to avoid accidentally burying the drilling assembly in the soft cement.

Follow good cementing practices: Using best practices for cementing reduces the risk of cement-related pipe sticking. Some of the key points for good cementing techniques are as follows:

Use the right slurry composition.
Ensure effective mud removal.
Ensure long enough circulation to condition the hole and attain the required mud rheology.
Maintaining adequate pump rates.
Use appropriate spacer design to avoid slurry contamination.
Run centralizers to keep the casing centered to improve cement coverage.
Verify the top of cement (TOC) to avoid over-drilling into unset cement.

Minimize the rathole below the casing shoe: The rathole is the uncased section of the wellbore below the shoe, often left after drilling to set the casing. Leftover contaminated cement in the rat hole can harden into chunks or remain soft, creating a sticking hazard for the drill string. Ideally, the rat hole should be just enough for the casing shoe plus a small buffer.

Thoroughly ream after drilling ratholes or cement plugs: Thorough reaming ensures a uniform borehole, reduces friction and the risk of mechanical sticking, and clears out potential hazards. It also removes any leftover cement chunks and patches of green cement, which could jam the string if not cleared.

Caution when tripping through the shoe or past plugs: Tripping the drill string too fast or applying excessive force can shear off the cement around the casing shoe, causing it to fall into big chunks, which can lodge themselves in the bit or drill string components.

6. Collapsed Casing:

Excessive formation pressure that surpasses a casing’s collapse rating can cause the casing to buckle inward, reducing its inside diameter and potentially jamming the drill string.

There are several reasons for a drill string to encounter torque and drag while rotating and moving in the open hole. However, increased levels of torque and drag while the string is still inside the casing could indicate a narrowed section of the casing. If tools or the drill string encounter unexpected resistance or cannot pass through certain casing sections, it may suggest a reduction in the casing’s inside diameter due to collapse.

Preventive Measures:

Proper Casing Design and Selection: Select casing with a collapse rating that exceeds the maximum expected formation pressure, factoring in safety margins.

Effective Cementing Practices: Poor cementing can leave voids or channels, allowing formation pressure to act directly on the casing. Use best cementing practices with appropriate hole conditioning, slurry designs, spacer design, pump rates, and displacement to ensure complete coverage.

Use of Centralizers: Centralizers keep the casing centered in the wellbore, promoting even cement distribution around the casing. This reduces the risk of weak spots where formation pressure could cause localized collapse.

Remedial Measures:

If casing collapses and the drill string becomes stuck or unable to pass certain cased hole sections, run diagnostics and confirm that the cause is a collapsed casing before taking remedial action.

Cut and retrieve the Drill String: In extreme cases where the collapse is severe, it may be necessary to cut the stuck drill string or back off the drill string above the jammed section and retrieve it. Run a fishing assembly to engage the string left downhole and attempt to retrieve it.

Ream Through Minor Collapses: For slight reductions in casing diameter, use a smaller-diameter bit or a reaming tool to enlarge the narrowed section carefully. There is a risk of getting the reaming tool stuck. Hence, appropriate assembly and procedural steps must be carried out to carefully run the string to the collapsed section. A thorough risk assessment is essential to anticipate and mitigate all possible risks.

Damage assessment: Run logs and downhole camera to assess the damaged area and decide on appropriate action to ensure wellbore integrity.

Section mill: In case of excessive casing damage, run a section mill to cut and remove the damaged section. Depending on the well conditions and objectives, evaluate the options of running a casing patch or abandoning and side-tracking.