The key factors in tortuosity models are the amplitude and the period of the variation. The amplitude represents the maximum angle change observed during the planned survey, while the period indicates the length of the cycle of that variation. Tortuosity is categorized into three levels: mild, moderate, and severe. 'Mild Tortuosity' is less than 5° per 100 feet. It has minimal effect on drilling operational difficulties. 'Moderate Tortuosity' ranges from 5° to 15° per 100 feet, which results in some drilling and completion difficulties. 'Severe Tortuosity' exceeds 15° per 100 feet and could cause significant drilling, completion, and production challenges.

Causes of wellbore tortuosity:

Wellbore tortuosity can stem from several key factors, which fall into three main categories: geological formations, drilling operations, and well design.

Geological Factors:

1.     Natural faults and fractures: Geological structures have natural faults and fractures within formations. Encountering these anomalies can lead to unexpected drilling behaviors, and the drill bit can veer off course, resulting in abrupt changes to the well profile.

2.   Formation dips: Layers within a formation commonly have natural dips that can impact the drilling bit and assembly. Even with the directional driller's best efforts to stick to the planned trajectory, these dips can force the bit in a different direction and cause a crooked wellbore.

3.   Heterogeneous rock formations: Sedimentary rocks typically have layered structures. The properties of these layers, such as hardness and density, can vary significantly. As the bottom hole assembly navigates through heterogeneous rock formations, these variations can frequently cause unintended shifts in the well path.

4.    Unstable rock: Unstable rock formations can collapse or crumble, causing wellbore deformation and tortuosity. They may also have larger borehole diameters, making the drilling assembly unstable and causing it to waver from the intended well path, leading to deviations and tortuosity.

5.   Salt formation: Salt's low yield strength leads to plastic deformation under drilling loads and can alter drilling dynamics, resulting in tortuosity. The drilling fluid can dissolve the salt, altering wellbore geometry and adversely affecting drilling assembly stabilization, which can lead to increased tortuosity in the wellbore.

Drilling-Related Factors:

1.     Drill string dynamics and BHA: Improperly positioned stabilizers can lead to an unstable Bottom Hole Assembly (BHA), which may cause the drill bit to behave erratically and compromise well direction control. Additionally, excessive lateral or axial vibrations in the drill string can lead to erosion and enlargement of the wellbore, further destabilizing the drill string and the bit and ultimately increasing the well’s tortuosity.

2.    Drilling parameters: Weight of Bit (WOB) and Revolutions Per Minute (RPM) are the mechanical energy inputs crucial for drilling through rocks. The specific combinations of these parameters can lead to different behaviors in the drilling assembly, influenced by the formation's characteristics and the Bottom Hole Assembly (BHA) design. These variations can also affect vibrations within the drill string, impacting the wellbore tortuosity.

3.    Drill bit type and design: The type of drilling bit you choose significantly affects the tortuosity of the wellbore. Generally, fixed cutter bits provide more stability and produce less vibration than roller cone bits. Additionally, smaller bits have more stability than their larger counterparts, and more aggressive bit profiles can increase vibrations. Furthermore, factors like the cutter type, orientation, and quantity all contribute to the drilling dynamics and vibration levels, which ultimately influence the tortuosity of the wellbore.

4.   Hole cleaning and ECD: Inadequate hole cleaning can lead to cuttings buildup within the wellbore, potentially causing blockages and causing the bit to deviate from its intended path. Additionally, high Equivalent Circulation Density (ECD) may result in hole erosion, compromising the stability of the drilling assembly and the bit. This could ultimately lead to a tortuous wellbore.

5.    Drilling technique and methodology: Rotary Steerable Systems (RSS), steerable mud motors (SM), and conventional rotary Bottom Hole Assemblies (BHA) each create different levels of tortuosity. While RSS generally creates less tortuosity than steerable mud motors, its mechanism involves adjusting the steering force or pressure at specific frequencies. This adjustment enables the system to push a pad or flex a shaft to achieve a particular directional target. These frequent corrections contribute to the overall tortuosity of the drilling path.

Other Factors:

 1.     Inadequate well planning: When planning a well, it's essential to evaluate geological and petrophysical data thoroughly. When selecting the kickoff point, build rate, casing seat, hole size, and drill bit, it’s important to carefully consider each factor and its potential impact on the well's tortuosity.

2.     Aggressive well trajectory: Steeper angles, more frequent changes in azimuth, and sharp doglegs can increase the likelihood of tortuosity being introduced into the wellbore.

3.     Human error: Utilizing incorrect drilling parameters may lead to excessive vibrations, which could cause the drill bit to deviate from its intended path.

4.     Equipment malfunction: A malfunction in the downhole drilling equipment may compromise control and jeopardize the wellbore quality.

5. Downhole troubles: Key seat formation, hole enlargement, differential stuck pipe issues, and fishing operations might necessitate more aggressive strategies, often at the expense of effectively managing wellbore tortuosity

Effects of wellbore tortuosity:

The impact of wellbore tortuosity can be substantial, affecting multiple stages of drilling, completion, and production processes. It introduces extra friction between the tubular and the borehole, leading to challenges with casing and completions, hindering effective cementation, compromising logging quality, and even causing casing wear issues.

Drilling Performance Impacts: Wellbore tortuosity raises friction levels, which in turn consumes energy that could otherwise be directed to the bit for drilling. This results in slower drilling rates, leading to longer drilling times and extended hole exposure. Consequently, this can increase the complexity of drilling due to downhole troubles.

Drill string and BHA issues: Wellbore tortuosity impacts the stability of the bottom hole assembly (BHA), leading to increased vibrations and stresses in the drill string. This not only hampers drilling performance but can also result in cyclical stresses that may cause drill string failures, which could necessitate a fishing job.

Casing and cementing challenges: Casing is stiffer compared to the drill string. Therefore, while the drill string might navigate through winding sections, the casing could struggle to do the same. Increased tortuosity raises friction levels, which can lead to the casing getting stuck during installation. Additionally, an irregular wellbore shape—characterized by necking and crooked sections—can hinder the cement from achieving a uniform coverage, ultimately impacting zonal isolation negatively.

Formation evaluation challenges: The goal of drilling a well is to assess the reservoir's potential through Logging While Drilling (LWD) or Wireline logging and formulate the best strategies for extracting formation fluids. The wireline tools are lighter than the drill string, making it difficult for them to navigate highly tortuous sections. Often, longer tools prove too rigid to maneuver through these crooked passages, necessitating multiple trips with shorter tools. High tortuosity results in slower logging speeds in difficult sections. It also poses a higher risk of cable damage, leading to signal loss, poor data quality, and transmission issues. When data quality suffers, it diminishes the accuracy of reservoir modeling, affecting production forecasts and completion design. LWD faces similar challenges; tortuous paths make it difficult to maintain stable tool orientation, hindering image quality and further complicating data transmission.

Completion and production impacts: Wellbore tortuosity poses significant challenges when running production tubing and accessories. The sharp bends and curves induce localized stresses within the string, heightening the risk of failure. This complexity makes it tough to maintain the optimal orientation for perforations and negatively influences perforation density. Furthermore, it elevates the chances of the perforation tunnel collapse, which can ultimately lead to a decrease in well productivity. Additionally, tortuosity complicates the initiation of fractures at targeted locations and the placement of stimulation fluid, reducing its overall effectiveness. 

Reducing wellbore tortuosity impact:

During the planning phase, it's essential to anticipate any additional friction between the tubular and the borehole and calculate more accurate contact-side forces. The practice involves applying tortuosity to the planned survey using the Torque and drag model. This is typically achieved using a mathematical function—usually a sinusoidal or random variation of the inclination and azimuth over a specified length. Addressing wellbore tortuosity is crucial for ensuring that drilling, completion, and production operations are efficient, safe, and cost-effective. Therefore, it’s important to incorporate best practices for minimizing wellbore tortuosity and alleviating its effects during planning.

Some of the mitigation strategies that can help reduce wellbore tortuosity are as follows:

Ø  Conduct thorough geological and petrophysical analysis.

Ø  Geomechanical modeling and stratigraphic analysis to have complete information on subsurface geology and possible challenges.

Ø  Integrated well planning and designing to incorporate geological and petrophysical information with completion and production objectives.

Ø  Identify heterogeneous layer sections to have more caution drilling parameter optimization

Ø  Collaboration between Drilling, Completion, and Production Teams

Ø  Conduct regular ‘Risk Assessments and Mitigation Planning’ for every phase.

Ø  Advanced, well-planning, and design software.

Ø  Drill string and bottom-hole assembly (BHA) design optimization

Ø  Use advanced drill string dynamics modeling and select appropriate drilling tools and stabilizers

Ø  Deploy advanced drilling technologies (e.g., rotary steerable systems)

Ø  Implement effective wellbore placement and geosteering strategies

Ø  Use advanced bit design simulations

Ø  Optimize bit selection for formation type

Ø  Optimize drilling parameters and closely monitor them to adjust accordingly

Ø  Real-time drilling optimization and monitoring using MWD/LWD tools.

Ø  Monitor and adjust drilling operations in real-time using vibration analysis and signatures.

Ø  Improve hole cleaning and ECD management

Ø  Utilize advanced logging tool design

Ø  Completion of design optimization

Ø  Regular Completion of Performance Reviews and Risk Assessments

Directional Drilling Equipment & Services

Ref: Borehole Tortuosity Effect on Maximum Horizontal Drilling Length Based on Advanced Buckling Modeling S.Menand, DrillScan US Inc. - AADE-13-FTCE-21