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>

An annular rubber element stands as a pivotal component within an annular blowout preventer (BOP), playing a crucial role in safeguarding oil well drilling operations by preventing the uncontrolled release of formation fluids, such as oil, gas, or water, from the wellbore.

When to Change Annular Preventer Element

Crafted from a high-performance elastomer compound, these elements are engineered to withstand the demanding conditions of the downhole environment. Subjected to high pressures, extreme temperatures, and exposure to corrosive fluids, they are strategically placed around the wellbore within the BOP body to forge a seal between the drill pipe or casing and the wellbore wall.

Upon activation of the BOP, the element undergoes compression, forming a tight seal that effectively halts the flow of fluids up the wellbore. Available in various sizes and configurations, annular rubber elements cater to diverse wellbore conditions and applications.

Here are some primary functions of annular rubber elements:

1. Primary Pressure Barrier: The element serves as the primary barrier against the upward flow of formation fluids throughout drilling, completion, and production phases.
2. Accommodation of Different Pipe Sizes: Designed to adapt to a range of pipe diameters, ensuring a secure seal irrespective of the size of the drill pipe or casing utilized.
3. Resistance to Wear and Tear: Manufactured from robust materials capable of withstanding the abrasive downhole conditions.
4. Maintenance of Flexibility: Flexibility is paramount for the element to conform to the irregularities of the wellbore wall and pipe while maintaining a tight seal.

The decision to replace an annular rubber element in an annular BOP is critical for wellbore safety and should be approached on a case-by-case basis, taking into account various factors. Here are key indicators that replacement might be necessary:

This is an example of worn out annular rubber element.

Visual Inspection:

• Visible Damage: Any cuts, tears, abrasions, nicks, or physical damage compromise the sealing ability and warrant replacement.
• Excessive Wear: Significant or uneven wear suggests the end of the element’s useful life.
• Swelling or Softening: Signs of exposure to incompatible fluids or excessive heat indicate weakening and necessitate replacement.

Performance Issues:

• Leaks: Even minor leaks around the element necessitate investigation and potential replacement.
• Increased Activation Pressure: Elevated pressure requirements could signify wear or damage, reducing sealing effectiveness and calling for replacement.

Preventative Maintenance:

• Manufacturer Recommendations: Adhering to recommended replacement intervals ensures optimal performance and safety.
• Pre-operational Inspections: Scheduled inspections before each operation enable early detection of potential issues.
• Records and History: Detailed records of element usage aid in predicting replacement needs.

Additional Factors:

• Wellbore Conditions: Harsh environments accelerate wear, necessitating more frequent replacements.
• Drilling Operations: Operations involving abrasive materials or frequent pressure cycling influence replacement decisions.

Replacing an annular rubber element is a critical safety measure. Consultation with experienced personnel, qualified inspectors, and adherence to industry regulations is imperative for informed replacement decisions. Never delay replacement if there are suspicions regarding the integrity or performance of the element.

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 Factors To Be Considered When to Change Annular Preventer Element 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>

Successful Fishing Operations are required a lot of effort from every party. Therefore, we provide the guideline which will help you get higher chance of success to fish your tool out of the hole. Fishing operations demand adherence to specific guidelines and protocols applicable across various scenarios. Challenges like downhole issues, equipment malfunctions, geological formations, and human error may necessitate fishing interventions or hinder completion. By following the guidelines outlined in this chapter, one can maximize the likelihood of a successful fishing endeavor.

The Essential Guidelines for Successful Fishing Operations

While all aspects are significant, certain principles merit special attention. Skilled and seasoned personnel play a pivotal role, capable of executing most fishing tasks, including engaging a specialist if needed, or preempting the need for fishing altogether. Preparedness is key, as fishing often arises unexpectedly. Understanding the situation thoroughly, promptly taking appropriate actions, expediting operations, and knowing when to pivot or cease efforts are critical. Post-job analysis is essential for preventing future mishaps or improving efficiency. Familiarity with common drilling or workover operations prone to fishing is invaluable for success.

Assess Situation

Thoroughly evaluate the situation. What is lodged in the hole, and where exactly? Assess the feasibility of retrieval. Scrutinize well records and historical data. Seek insights from various stakeholders such as fishing-tool supervisors, tool pushers, drilling/production supervisors, engineers, and drillers. Explore alternative strategies.

Prioritize safety and rely on proven methodologies. While multiple approaches may be viable, opting for a proven technique minimizes uncertainties. Consider the ripple effects of each step on subsequent actions. Maintain meticulous records of all interventions and outcomes.

Communicate

Effective communication is paramount throughout the fishing operation. Ensure comprehensive and timely sharing of information among all involved parties. Steps to foster effective communication include:

• Gather complete and accurate information about the situation.
• Notify fishing-tool company personnel promptly to facilitate preparation.
• Ensure mutual understanding among all stakeholders regarding procedures.
• Provide regular progress updates, including successes, challenges, problem analysis, alternative plans, and equipment requirements.

Gather Data

Certain critical factors and information must be considered and documented during a fishing operation. Thorough data recording is imperative, with no information deemed unnecessary. Key considerations include:

• Document outside and inside diameters, as well as the length of the fishing string, and create detailed drawings.
• Discuss the job comprehensively with all concerned personnel.
• Understand the limitations of the drill pipe and tools.
• Ensure accuracy of weight indicators.
• Determine the location of the fish and assess the condition of the hole and tools.
• Utilize appropriate methods, such as lubricators when running wireline.

A Systematic Approach To Solutions

Adopt a systematic approach to problem-solving using the acronym OD, ID, M, LP, and C:

• OD: Prioritize catching the fish by its outer diameter.
• ID: If the outer diameter is inaccessible, target the inner diameter.
• M: Assess if modifications are necessary to access either diameter.
• LP: Consider cutting the fish into smaller sections if required.
• C: Recognize scenarios where the risks of fishing outweigh the benefits, opting for cementing solutions or abandonment.

Pipe Tally Management

When laying down pipe during fishing operations, meticulously track the pipe count. Avoid mixing the fishing string with other pipe on location. Measure and record the lengths of all items laid down and picked up, as the difference will indicate the distance to the top of the fish

Avoid Rotating The Fishing String

Unlike drilling operations, never rotate the fishing string to speed up trips. Spinning the fishing tools like overshots, spears, or junk baskets can cause the fish to be released back into the hole.

Caution With Conductor Lines

When retrieving tools or instruments attached to conductor lines with rope-socket shear devices, avoid pulling out the rope socket. Instead, cut the line at the surface and strip over, especially in open holes with radioactive sources. Pulling the rope socket can rupture the canister and contaminate the well fluid.

The Role of A Fishing Tool Supervisor

The modern fishing tool supervisor assumes multifaceted responsibilities, extending beyond traditional roles. Effective communication, interpretation of downhole data, and collaboration with diverse teams are essential skills. Experience is invaluable in accurately assessing and addressing fishing challenges in today’s complex oil well operations.

References

The Guide to Oilwell Fishing Operations: Tools, Techniques, and Rules of Thumb (Gulf Drilling Guides) by Joe P. DeGeare, David Haughton, Mark McGurk

<p>The post The Essential Guidelines for Successful Fishing Operations first appeared on Drilling Formulas and Drilling Calculations.</p>

What is backoff operation?

The backoff operation is a procedure used in oil and gas well fishing jobs to unscrew a stuck pipe string at a specific threaded joint above the stuck point. This method is particularly popular for drill pipes and drill collars because it leaves a threaded connection at the top of the remaining pipe, making it possible to screw back into the fish with a workstring and fishing tools.

The backoff process involves applying a left-hand torque to the pipe string while firing a shot of prima cord explosive. The resulting explosion produces a concussion that partially unscrews the threads at the targeted joint.

For tubing or coupled pipes, backoff is still a common method, although their finer threads and higher thread interference make the process slightly different. In some cases, it may be more economical to back off the tubing, circulate the well, screw it back together, and continue the process until the fish is removed.

In addition to backing off stuck pipes, string shots can also be used for releasing stuck packers or fishing tools, removing corrosion, opening perforations, jumping collars or tool joints, and removing jet nozzles from drill bits.

The Method of Backoff Operation:

1. Tightening and Reciprocating: The pipe string is first tightened with right-hand torque and then moved up and down (reciprocated) while maintaining the torque. This ensures a good connection and distributes the force throughout the string.
2. Applying Left-hand Torque: Next, torque is applied in the opposite direction (left-handed) to the string. This torque is also “worked downhole” by reciprocating the pipe. The amount of left-hand torque required varies based on factors such as the depth of the stuck point, hole conditions, and pipe type. A general rule of thumb is to use three-quarters to one round per 1,000 feet of free pipe for tubing and half to three-quarters of a round for drill pipes.
3. Firing the String Shot: Ideally, the pipe at the separation point should be neither under tension nor compression. In reality, a slight tension is preferred. A small explosive device called a string shot is then detonated, creating a shockwave that loosens the threads at the desired joint.
4. Unscrewing and Removing the Pipe: With the threads partially unscrewed, the pipe can be further unscrewed using surface equipment and then removed from the well.

Important Considerations:

• Pipe Type: Backoff works well with drill pipe and drill collars due to their coarse threads and metal-to-metal seals. Tubing, with its finer threads and tension, can also be parted using backoff, but other factors need to be considered.
• String Shot Selection: The string shot’s strength and fuse type depend on the pipe size, depth, wellbore fluid, and temperature.
• Outside Backoff: This is a variation where the string shot is placed outside the pipe in the wellbore annulus. It’s suitable for hard rock formations and situations where the pipe is plugged and cannot be cleaned for an internal shot.

Additional Uses of String Shots:

There are several purposes which string shots can be used as listed below;

• Breaking free stuck packers or fishing tools
• Removing corrosion from pipes
• Opening clogged perforations in the wellbore casing
• Separating a stuck drill collar from a tool joint
• Removing nozzles from drill bits to improve circulation
• Dislodging drill pipes stuck in formation keyseats

What is Outside Backoff ?

When a drill pipe gets stuck in a wellbore, and traditional methods of retrieval are impossible due to a plugged pipe, an outside backoff technique can be a viable option. This method is most successful in near-vertical wells with hard rock formations, and not recommended for wells with softer formations like shales or unconsolidated sands.

Here’s how it works:

1. A special tool called a side-door sub (also known as an outside backoff collar or hillside sub) is lowered down the wellbore on a wireline. This sub has a side opening that allows access to the space outside the stuck pipe.
2. Another tool called a string shot, which is essentially a small explosive charge, is then lowered through the side opening of the sub and positioned near the connection point of the stuck pipe.
3. With the string shot in place, torque is applied to the drill pipe, and then the string shot is detonated. The explosion creates a shockwave that can loosen the connection and allow the drill pipe above the stuck point to be retrieved.

Important points to note for outside backoff:

• Outside backoff is a technique for near-vertical wells and is not suitable for directional drilling.
• This method is ideal for hard rock formations and should be avoided in softer formations.
• The string shot design ensures it lands near the pipe connection for optimal impact.

References

The Guide to Oilwell Fishing Operations: Tools, Techniques, and Rules of Thumb (Gulf Drilling Guides) by Joe P. DeGeare, David Haughton, Mark McGurk

<p>The post What is backoff operation for fishing job? first appeared on Drilling Formulas and Drilling Calculations.</p>

Chemical pipe cutting is a wireline operation that utilizes an electric tool and a halogen fluoride chemical reactant to perforate and weaken pipe, enabling its subsequent removal (pipe recovery). Originally introduced in the 1950s as a patented process exclusive to a single wireline company, chemical cutting has now become widely adopted across the industry. Today, most electric-wireline service providers offer this technique, making it the predominant method for cutting pipes due to its efficiency and effectiveness.

Courtesy of Versa-line – https://versa-line.com/

The process involves the following components and mechanisms:

Tool Design

The chemical cutting tool comprises a body with a series of flow jets around its lower section. It contains:

• An ignition system to initiate a propellant charge
• A reservoir for the chemical reactant (halogen fluoride or bromine trifluoride)
• Pressure-actuated slips to prevent vertical movement during operation

Operating Principle

1. The propellant charge is electrically ignited, generating high pressure and temperature.
2. The reactive chemical is forced through the jets by the propellant gases.
3. The jets impinge the chemical on the pipe wall at high velocity.
4. The halogen fluoride chemically reacts with the pipe metal, eroding and perforating it circumferentially.
5. The reaction products are harmless iron salts that dissipate in the well fluid.

Advantages

• Efficiency: Minimizes rig time compared to other methods.
• Clean Cut: No flaring, burrs, or swelling occur on the cut pipe, eliminating the need for dressing before retrieval. The image  below shows the result of cut pipe from using a chemical cutter.

Pipe was cut using a chemical cutter. courtesy of Versa-line – https://versa-line.com/

• Safe: The chemical reaction produces harmless salts that don’t damage nearby casing and dissipate quickly in well fluids.

Operational Parameters

• Requires a minimum of 100 ft of fluid above the tool for successful operation.
• Well fluid must be clean and free of lost circulation materials.
• Rated for up to 18,500 psi hydrostatic pressure and 450°F temperature.
• Compatible with most tubing, drill pipe, and casing sizes.

Chemical cutting tools revolutionized wireline pipe recovery operations, offering a safe, efficient, and cost-effective solution compared to traditional mechanical cutting methods.

References

The Guide to Oilwell Fishing Operations: Tools, Techniques, and Rules of Thumb (Gulf Drilling Guides) by Joe P. DeGeare, David Haughton, Mark McGurk

Versaline Services wireline solution – https://versa-line.com/pipe-recovery/

<p>The post What is a Chemical Cutter? and How It Works? first appeared on Drilling Formulas and Drilling Calculations.</p>

In the oil and gas industry, fishing operations refer to the procedures used to retrieve or remove stuck or failed equipment from the wellbore. These obstructions can include stuck pipe, drill collars, parted tubulars, stuck packers, parted or stuck wireline, and other lost or failed equipment. When such conditions develop, drilling, workover, and completion operations must cease until the obstruction is removed, allowing normal operations to resume.

Obstructions in the wellbore can result from various factors, such as human error, unknown hole conditions, metal fatigue in tubulars, junk in the hole, and faulty equipment. These obstructions are generally classified into two categories: fish and junk.

A fish is a part of the drill string that separates from the upper remaining portion while the drill string is in the well. This can occur due to mechanical failure or when the lower portion of the drill string becomes stuck or disconnected from the upper portion. In such cases, an operation is initiated to free and retrieve the lower portion (or fish) from the well using a specialized, strengthened string.

On the other hand, junk refers to small, non-drillable metal items that fall or are left behind in the borehole during drilling, completion, or workover operations. These non-drillable items must be retrieved before operations can continue.

It is crucial to remove fish or junk from the well as quickly as possible. The longer these obstructions remain in the borehole, the more difficult they become to retrieve. Additionally, if the fish or junk is in an open hole section of the well, it can cause problems with borehole stability.

While fishing operations are typically less expensive than the overall drilling or workover costs, they can still have a significant economic impact on the project. If a fish or junk cannot be removed promptly, it may be necessary to sidetrack (directionally drill around the obstruction) or drill another borehole, incurring additional costs.

To ensure an economical fishing operation, a careful assessment of the problem, effective communication among all parties involved (such as geologists, reservoir engineers, and others responsible for the well), and consideration of alternative options (like open-hole sidetracking or cased-hole casing exit) are essential. Experience, good judgment, and the use of probability factors based on similar situations can also aid in determining the appropriate course of action and the time to be spent fishing.

In order to do the economic justification, the numbers of day of fishing operation can be determined by the following equation.

D = (V  + Cs)÷ (R + Cd)

where
V is the replacement value of the fish
Cs is the estimated cost of the sidetrack or the cost of drilling a new well
R is the cost per day of the fishing tool and services
Cd is the cost per day of the drilling rig and other support

Advances in fishing, milling, and sidetracking technologies, along with a large database of information on fishing operations, have made decision-making easier for operating companies. However, every situation is unique, and a standard checklist applicable to all scenarios would be impossible. The ultimate goal is to return to normal drilling, completion, or workover operations with minimal lost time and money.

In summary, fishing operations play a crucial role in the oil and gas industry, enabling the removal of obstructions from the wellbore. By employing effective strategies, considering economic factors, and leveraging advanced technologies, companies can successfully overcome these challenges and resume operations efficiently.

References

The Guide to Oilwell Fishing Operations: Tools, Techniques, and Rules of Thumb (Gulf Drilling Guides) by Joe P. DeGeare, David Haughton, Mark McGurk

<p>The post The Economics Fishing Operations in Oil Well Drilling: Balancing Efficiency and Economics first appeared on Drilling Formulas and Drilling Calculations.</p>

When abandoning an oil or gas well, performing salvage operations, or facing situations with low fluid levels, heavy drilling mud, or cost constraints, operators often turn to a specialized tool called the explosive jet cutter or jet cutter in short. This shaped charge device runs on an electric wireline and is designed to sever pipes in a controlled and efficient manner.

The jet cutter’s plastic explosive features a modified parabolic face with a circular shape that conforms to the pipe it needs to cut. This unique design allows for a precise and focused detonation.

Upon detonation, the shaped charge explosive flares the cut end of the pipe. To facilitate the subsequent fishing or retrieval of the severed pipe section, it is necessary to remove this flared portion. Typically, this can be accomplished during the same operation by employing a mill guide or a hollow mill container with an insert. These tools are run on the bottom of an overshot fishing tool and, through rotation, can dress off the flared or burred end, allowing the overshot to slip over the fish (severed pipe section) easily.

This image below shows how the tubing was cut with the explosive jet cutter.

Tubing cut with the jet cutter

It is important to note that there is a slight risk of damaging adjacent strings or casings if they are in contact with the pipe at the cut point during the detonation.

Jet cutters are available for a wide range of pipe sizes, including tubing, drill pipe, and casing. For particularly challenging fishing operations involving drill pipe and drill collars, operators may opt for larger jet cutters known as severing cutters. These cutters create an even more significant flare, making it challenging to dress off the top of the severed section, especially in open holes. Severing charges are placed across tool joints rather than within the pipe’s tube itself.

Overall, jet cutters offer a reliable and cost-effective solution for cutting pipes during well abandonment, salvage operations, or when other cutting methods are impractical or uneconomical.

References

The Guide to Oilwell Fishing Operations: Tools, Techniques, and Rules of Thumb (Gulf Drilling Guides) by Joe P. DeGeare, David Haughton, Mark McGurk

<p>The post What is an Explosive Jet Cutter for Pipe Severing Operation? first appeared on Drilling Formulas and Drilling Calculations.</p>

In this article, it describes type of mechanical cutters used for fishing operation. When running fishing tools to retrieve stuck or damaged downhole equipment, the pipe or casing often needs to be cut or parted. This allows the fishing tools to latch onto and retrieve the fish. If wireline tools are available, the pipe can be parted using wireline cutting methods to minimize rig time. However, when wireline is not practical, the pipe must be cut using mechanical cutters run on the end of a workstring.

Internal Mechanical Cutters

Mechanical Internal Cutter

One common method is an internal mechanical cutter. This tool is mounted on a mandrel with an automatic slips release mechanism that allows it to be set at the desired depth. Friction blocks or drag springs provide backup for the release.

The cutter works by slowly rotating right-hand and applying weight, which feeds out knives on tapered blocks to cut into the inside of the pipe. Springs in the feed mechanism absorb shocks to prevent the knives from gouging or breaking. A bumper jar is usually run above to control the cutting weight.

The knife tips are made of brass to prevent breaking when contacting the pipe wall. Internal cutters are available for most tubing and casing sizes.

Internal Hydraulic Cutters

An alternative is an internal hydraulic cutter designed for single strings. It uses hydraulically-activated knives for a smooth, efficient cut. An indicator signals when the cut is complete by a drop in pump pressure. Stabilizer slips anchor the tool before cutting.

Hydraulic Internal Cutter

The tool is run to depth, then rotation and circulation are initiated. Increasing torque indicates cutting has started. When complete, a control dog drops into a recess, reducing pump pressure to signal the cut is done. Straight pickup then retracts the slips and knives.

For multiple strings or open holes, a pressure-activated multiple string casing cutter can be used instead of a hydraulic cutter. Pump pressure forces the knives into the pipe to make the cut.

External Cutter (Washover Cutters)

When circumstances demand cutting from the outside, the washover outside or external cutter steps in as a versatile solution. Ideal for addressing scenarios where internal obstructions impede the use of wireline tools, this cutter operates on the bottom of a washover string, executing cuts from the exterior.

Washover outside cutter

Adaptability is the hallmark of the external cutter, with configurations tailored to catch various tool joints or couplings on the fish. From spring fingers to flipper dog cages, each design caters to specific requirements, ensuring a secure grip. Flush-joint pipe necessitates a hydraulically actuated catcher, with pump pressure activating the cutter’s knives.

With careful calibration of rotation and fluid flow, the cut is initiated, culminating in the retrieval of the fish and subsequent extraction from the washpipe at the surface. Vigilance is paramount throughout the process to prevent surges in pump pressure and ensure a smooth operation from start to finish.

References

The Guide to Oilwell Fishing Operations: Tools, Techniques, and Rules of Thumb (Gulf Drilling Guides) by Joe P. DeGeare, David Haughton, Mark McGurk

<p>The post Type of Mechanical Cutters for Fishing Operations first appeared on Drilling Formulas and Drilling Calculations.</p>

Drilling through coal formations, especially in long tangent wellbores, presents a unique set of challenges for the oil and gas industry therefore we need best practices for drilling coal formations. Coal seams are notorious for their potential instability, abnormal formation pressures, and propensity for swelling and sloughing when exposed to water-based drilling fluids. These challenges can lead to various drilling problems, such as stuck pipe incidents, lost circulation events, and well control situations, ultimately compromising the safety and efficiency of drilling operations.

Coal over shale shakers

When drilling extended reach or horizontal wells with tangent sections, the complexities associated with coal formations are further amplified. The increased wellbore exposure to these challenging formations, coupled with the difficulties in maintaining adequate hole cleaning and wellbore stability in long tangent intervals, necessitates a comprehensive approach to mitigate risks and ensure successful drilling operations.

Using water-based muds for drilling coal formations introduces additional considerations, as these fluids can interact with the reactive shale and coal layers, potentially exacerbating wellbore instability issues. Consequently, careful mud design, composition, and treatment are paramount to maintain the desired mud properties and mitigate formation-related challenges.

The best practices for drilling coal formations in long tangent wells using water-based mud systems are listed below;

Mud Weight and Density Control:

Coal formations are often associated with abnormal formation pressures, either overpressured or underpressured. Maintaining the correct mud weight and density is crucial to prevent kicks (influx of formation fluids) or lost circulation events. Regular formation pressure integrity tests (FIT) and careful pore pressure/fracture gradient analysis should be performed to optimize the mud weight.

Mud Composition and Inhibition:

Coal formations are prone to swelling and sloughing when exposed to water-based muds. The mud should be properly inhibited with potassium chloride (KCl) or other shale inhibitors to minimize wellbore instability. Maintaining a slightly alkaline pH (8.5-9.5) can also help mitigate shale/coal instability.

Hydraulics and Hole Cleaning:

Maintaining effective hole cleaning is of paramount importance in long tangent sections to prevent the accumulation of formation cuttings, which can lead to potential wellbore instability issues and compromised drilling performance.

To enhance cuttings removal and mitigate associated risks, operators should consider employing high-viscosity pills or performing wiper trips, which involve circulating a viscous fluid or specialized pills to displace and lift cuttings from the wellbore effectively.

Drilling Fluids Monitoring and Treatment:

Coal formations can release methane, carbon dioxide, and other gases, which can affect the mud properties and potentially cause kick situations. Regular monitoring of gas levels, mud weight, and rheological properties is essential. Appropriate solids control equipment and treatments (e.g., degassers, defoamers) may be necessary to maintain the desired mud properties.

Wellbore Stability and Casing Design:

Coal formations are often associated with unstable wellbore conditions due to their swelling and sloughing tendencies. Proper casing design, including casing setting depths, mud weights, and potential use of expandable casing or liners, should be considered to maintain wellbore stability.

Bit Selection and Drilling Parameters:

Coal formations can be abrasive and challenging to drill, leading to increased bit wear and potential stuck pipe situations. Selecting the appropriate bit type (e.g., PDC, impreg, or roller cone) and optimizing drilling parameters (WOB, RPM, ROP) is crucial for efficient and safe drilling operations.

Real-time monitoring while drilling:

Utilizing formation evaluation tools while drilling is crucial to identify coal seams and other potential hazards, allowing for timely adjustments to mud properties and drilling parameters to mitigate risks proactively.

Continuous monitoring of key drilling parameters, such as torque and drag, is essential to detect early signs of wellbore instability. Prompt corrective actions, such as modifying mud properties, adjusting drilling parameters, or implementing contingency plans, should be taken to prevent further deterioration of wellbore conditions and potential stuck pipe incidents.

Team collaboration:

Successful drilling of coal formations in long tangent wells necessitates close collaboration among the drilling team, mud engineers, and geologists. The drilling team executes operations while working closely with mud engineers to design inhibitive muds that control coal swelling and maintain proper rheology. Geologists provide critical insights into formation characteristics, hazards, and pore pressures to guide drilling parameters and casing design. This multidisciplinary teamwork enables informed decision-making, proactive adjustments, and timely implementation of contingency plans for safe and efficient operations.

What is your experience about drilling through coal? 

Please feel free to share in the comment section below.

<p>The post Best Practices for Drilling Coal Formations in Long Tangent Wells Using Water-Based Mud 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>

A triplex pump is a type of reciprocating positive displacement pump that consists of three cylinders and three corresponding pistons or plungers. Here’s how a triplex pump works:

1. Cylinders and pistons: The pump has three cylinders arranged in a horizontal or vertical configuration, each with its own piston or plunger. The pistons are connected to a crankshaft, which converts the rotational motion of the pump’s drive into the reciprocating motion of the pistons.
2. Suction and discharge: Each cylinder has a suction valve and a discharge valve. During the suction stroke, the piston moves outward, creating a vacuum that draws fluid into the cylinder through the suction valve. During the discharge stroke, the piston moves inward, closing the suction valve and forcing the fluid out through the discharge valve.
3. Firing sequence: The three pistons are arranged at 120-degree intervals, ensuring that one piston is always beginning its suction stroke while another is discharging, and the third is in an intermediate position. This firing sequence results in a relatively smooth and continuous flow of fluid from the pump.
4. Pulsation dampeners: To further reduce pulsations and pressure fluctuations caused by the reciprocating action of the pistons, triplex pumps often incorporate pulsation dampeners or accumulators in the suction and discharge lines.

Triplex pumps are commonly used in applications that require high pressures and consistent flow rates, such as drilling rigs, hydraulic power units, chemical processing plants, and water treatment facilities. Their ability to handle a wide range of fluids, including abrasive or corrosive materials, makes them suitable for various industrial applications.

Triplex pumps are preferred for drilling rigs for several reasons:

1. Efficiency and Power Delivery: Triplex pumps, which have three plungers or pistons, deliver a more continuous flow of drilling fluid compared to duplex pumps (which have two pistons). The triplex design results in a smoother and more consistent delivery of fluid, reducing pulsation and the associated wear and tear on the entire pumping system.
2. Compact Design: Triplex pumps are generally more compact and lighter than comparable duplex pumps. This compactness is particularly advantageous in the limited space of a drilling rig, where optimizing space is crucial for both operational efficiency and safety.
3. Higher Pressure and Flow Rate: Triplex pumps are capable of delivering higher pressures and flow rates, which are essential for the demanding conditions of drilling operations. This capability allows for effective circulation of drilling mud, which is necessary for cooling the drill bit, carrying cuttings to the surface, and maintaining well pressure.
4. Durability and Reliability: The design of triplex pumps tends to offer greater durability and reliability. With three pistons, the load is distributed more evenly, reducing the wear on individual components. This leads to longer service intervals and less downtime, which is critical in drilling operations where time is money.
5. Ease of Maintenance: Triplex pumps are relatively easy to maintain. Their design allows for easier access to components for routine inspection and repairs. This ease of maintenance contributes to lower operational costs and minimizes downtime.
6. Versatility: Triplex pumps can handle a wide range of fluid types and viscosities, making them suitable for various drilling environments and conditions. This versatility is beneficial in adapting to different drilling fluid compositions and pressures encountered during drilling operations.

Overall, the combination of efficiency, power, compactness, durability, ease of maintenance, and versatility makes triplex pumps a preferred choice for drilling rigs. Their ability to deliver consistent high-pressure fluid flow under demanding conditions is essential for the success and safety of drilling operations.

<p>The post Why Do We Prefer Using a Triplex Pump For Drilling Rig? first appeared on Drilling Formulas and Drilling Calculations.</p>

Mono Trip Gas Lift (MTGL) Completion is an advanced well completion technique introduced by Baker Hughes, designed to significantly improve the efficiency and reduce cost of gas lift operations. In traditional gas lift completions, multiple trips in and out of the wellbore are required to install the lower and upper completion equipment. The MTGL completion technique simplifies this process by allowing the installation of the entire gas lift system and a packer in a single trip. Additionally, cementing operations, packer setting, and cleaning operations can all be done offline once the rig skids off to another well. This application drastically reduces well costs. The MTGL completion is particularly well-suited for small reservoir fields or brownfields where well economics are very low. With traditional completion techniques, the well cost would be so high that development of the field would not be economical.

Here are some key advantages of MTGL Completion:

1. Single Trip Installation: The primary feature of MTGL completion is that it allows for the installation of all necessary gas lift equipment, including gas lift mandrels and valves, in one run into the wellbore. This significantly reduces the time and cost associated with well completion compared to conventional methods that require multiple trips.
2. Efficiency and Cost-Effectiveness: By reducing the number of trips needed, MTGL completion minimizes the operational time, decreases the risk of operational mishaps, and lowers the overall cost of well completion.
3. Cement Through Design: Special equipment within the MTGL system is designed to be tolerant of cement, allowing for installation of the production tubing and other tools before cementing the wellbore. This minimizes risks and streamlines the process.
4. Integrated Design: MTGL systems are designed to integrate seamlessly with existing well architecture. They often include pre-installed gas lift mandrels and valves on the production tubing, ensuring that the system is ready for immediate use once installed.
5. Operational Flexibility: MTGL completion provides operational flexibility by allowing for adjustments and optimizations of the gas lift system without requiring additional trips. This can include changes in gas injection rates or the replacement of gas lift valves if necessary.
6. Enhanced Production: By streamlining the installation process and optimizing gas lift operations, MTGL completion can enhance hydrocarbon production rates, making it an attractive option for wells that require artificial lift to sustain or increase production levels. Studies have shown that MTGL completions can increase oil recovery by over 15% compared to traditional methods.
7.  Reduced Risk: Fewer trips in and out of the wellbore reduce the risk of complications such as stuck pipe, well control issues, and equipment failures, enhancing overall well integrity and safety.

The video below demonstrates how MTGL works.

<p>The post What is Mono Trip Gas Lift (MTGL) Completion? first appeared on Drilling Formulas and Drilling Calculations.</p>

A deadline anchor on an oil rig is a critical component used to secure the deadline, which is the non-moving end of the drilling line in a drilling rig system. This piece of equipment ensures the stability and proper tension of the drilling line, which loops around the drawworks (the primary hoisting machinery) and the traveling block (the movable pulley system).

Key Functions of a Deadline Anchor

1. Securing the Deadline: The deadline anchor firmly holds the dead line in place, ensuring that it remains stationary and taut during drilling operations. This stability is essential for the safe and efficient functioning of the entire drilling rig.
2. Maintaining Tension: By keeping the deadline under consistent tension, the deadline anchor helps prevent slack, which can cause operational disruptions and pose safety risks. Proper tension is crucial for the precise control of the drilling process.
3. Load Bearing: The deadline anchor is designed to handle the substantial loads exerted by the drill string (the assembly of drill pipe and tools) during drilling. It absorbs and distributes these loads to prevent excessive stress on the rig’s other components.

Deadline anchor in a drilling rig

Importance in Drilling Operations

1. Safety Assurance: The deadline anchor is critical for maintaining the structural integrity of the drilling rig. By securing the deadline, it helps prevent any unexpected movements or slack that could lead to accidents or equipment failure. In the high-risk environment of offshore drilling, where equipment malfunction can lead to catastrophic outcomes, the reliability of the dead line anchor cannot be overstated.
2. Operational Efficiency: A well-secured dead line ensures that the drilling line can operate smoothly, allowing for precise control over the drilling process. This precision is essential for hitting the exact target formations and for managing the drilling speed and pressure. Consequently, the deadline anchor contributes to the overall efficiency and productivity of drilling operations.
3. Load Management: The deadline anchor is designed to withstand substantial loads. During drilling, the drill string, which can weigh several tons, exerts considerable force on the drilling line. The deadline anchor absorbs and distributes this load, preventing undue stress on other rig components. This load management is vital for prolonging the lifespan of the rig’s equipment and for minimizing maintenance costs and downtime.

Deadline anchor in a drilling rig

Technological Enhancements

Modern deadline anchors have evolved significantly, incorporating advanced materials and technologies to improve their performance and durability:

• High-Strength Materials: Innovations in material science have led to the use of high-strength alloys and composites, enhancing the durability and load-bearing capacity of deadline anchors.
• Automated Tension Monitoring: Some deadline anchors are now equipped with automated systems that monitor and adjust the tension in real time, ensuring optimal performance and safety.
• Smart Sensors: Advanced sensors integrated into deadline anchors provide continuous data on load and tension, enabling predictive maintenance and early detection of potential issues, which can prevent critical failures.

Future Prospects

The ongoing advancements in drilling technology suggest that deadline anchors will continue to improve in terms of strength, resilience, and intelligence. Future developments might include:

• New Materials: Research into composite materials with superior strength-to-weight ratios could lead to even more robust and efficient dead line anchors.
• Artificial Intelligence: Integration of AI for predictive maintenance could enhance the reliability and lifespan of dead line anchors by anticipating and addressing issues before they arise.

<p>The post What is a Deadline Anchor in a Drilling Rig? 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>

The top drive systems (TDS) ,designed to perform several essential functions that make it crucial in the drilling operation, are essentially a powerful motor assembly suspended from the derrick or mast of an oil rig. Its primary function is to rotate the drill string, which is crucial for boring into rock formations and creating wellbores. This rotational force is the driving mechanism that enables the drill bit to penetrate the earth’s crust, paving the way for oil and gas extraction.

First and foremost, the top drive rotates the drill string during the drilling process. This rotation is critical for boring into the rock and creating a wellbore. By spinning the drill string, the top drive helps break up rock formations, enabling the drilling process to advance efficiently. This capability ensures that the wellbore is created to the desired specifications, which is fundamental for successful drilling operations.

Figure 1: Top Drive Systems Used on The Rig

In addition to rotating the drill string, the top drive allows for the circulation of drilling fluid. This fluid, often referred to as drilling mud, serves multiple purposes. It cools and lubricates the drill bit, ensuring that it does not overheat or become damaged during the drilling process. Moreover, the drilling fluid removes cuttings from the wellbore, preventing blockages and maintaining a clear path for the drill bit. The fluid also helps to maintain wellbore pressure, which is crucial for the stability of the well and the prevention of blowouts.

One of the significant advantages of top drive systems over traditional rotary table systems is their ability to improve both efficiency and safety on the rig. Top drives enable faster drilling by allowing for the use of longer drill pipe sections. While traditional rotary table systems typically handle drill pipe sections of about 30 feet, top drives can manage sections up to 90 feet long. This reduction in the number of connections required translates to less time spent tripping, which involves adding or removing drill pipe. As a result, the drilling process becomes significantly faster, reducing downtime and increasing overall productivity.

Top drive systems also enhance safety by minimizing the need for manual handling of the drill string. In traditional rotary table systems, workers must manually handle the drill pipe, which can be a hazardous task due to the heavy weight and the potential for accidents. With top drives, much of this manual labor is eliminated, reducing the risk of injuries associated with handling heavy drill pipe. The automation provided by hydraulic systems in top drives further reduces the physical demands on rig workers, enhancing overall safety on the rig.

The advantages of top drive systems extend beyond efficiency and safety improvements. These systems offer enhanced control over the drilling process, which is vital for preventing issues such as differential sticking, where the drill pipe gets stuck in the wellbore. The precise control afforded by top drives reduces the likelihood of such problems, ensuring smoother and more reliable drilling operations.

Moreover, top drives are highly versatile. They can rotate the drill string while pulling it out, a process known as backreaming. This capability is not available with traditional kelly rigs and can be crucial for clearing cuttings or preventing the drill from getting stuck. The ability to backream adds an extra layer of flexibility and problem-solving capability to the drilling process.

Top drives also contribute to the longevity and durability of drilling equipment. By using standard round drill pipes, they cause less wear on the blowout preventer (BOP) rubber element compared to the non-round kelly bar. This reduced wear translates to longer-lasting equipment and fewer maintenance requirements, further enhancing the overall efficiency and cost-effectiveness of drilling operations.

Top drive systems are available in various configurations. This diversity in design and power sources allows top drives to cater to different drilling needs, making them adaptable to a wide range of drilling environments and challenges.

In summary, top drive systems have revolutionized oil and gas drilling compared to traditional kelly rigs. Their ability to rotate the drill string, circulate drilling fluid, and improve efficiency and safety makes them an indispensable part of modern drilling operations. With increased drilling speed, reduced manual labor, enhanced safety, precise control, versatility, and reduced equipment wear, top drives offer a comprehensive solution to many of the challenges faced in the drilling process. Their adoption has significantly advanced the capabilities and efficiency of oil and gas drilling operations, making them a cornerstone of modern drilling technology.

<p>The post The Essential Role and Advantages of Top Drive Systems (TDS) first appeared on Drilling Formulas and Drilling Calculations.</p>