What is the process for directional drilling in complex wells?

At-a-Glance

Directional drilling in complex wells is a disciplined workflow: plan a collision-safe 3D trajectory, engineer BHAs and hydraulics to achieve target build/turn rates within DLS and ECD limits, then execute with real-time geosteering, survey QC, and vibration/torque–drag management to land and hold in zone efficiently and safely.

I. Objective Definition and Key KPIs

• I.1 Objective: Drill a collision-safe, high-quality wellbore (low tortuosity, cementable, run-completable) that meets subsurface targets while controlling ECD, vibration, and hole cleaning across all complex geometries (S-curve, 3D builds/turns, ERD, multilaterals).
• I.2 Primary KPIs:
  • Throughput/Time: Feet/day; days/section; on-bottom hours ratio = 85%.
  • Quality: DLS = limit; tortuosity (micro-DLS) = 0.5–0.8 deg/100 ft; survey SF = 1.5; lateral in-zone footage = 90%.
  • Reliability: NPT = 5%; BHA runs/section 1–2; vibration indices in green band = 80% of drilled footage.
  • Hydraulics/Hole Cleaning: ECD margin = 0.2–0.5 ppg; AV = 150–200 ft/min high-angle; cuttings bed free.
  • Cost/OPEX: $/ft; bit/BHA cost/ft; fuel/ton-CO2e per ft (emissions intensity).
  • HSE/Well Integrity: Zero HSE events; barrier compliance 100%; no influx/loss-related SIR > 0.

II. Critical Parameters and Target Ranges

(Assumptions “estimated”: oil-based or inhibitive WBM; 12¼ in and 8½ in sections; 5 in DP; ERD ratio up to ~3.0.)

III. Step-by-Step Procedure / Workflow / Checklist

III.1 Plan and Model

• III.1.1 Define targets: Top/lower structural picks, landing depth and inclination, lateral window; uncertainty ellipsoids from geoscience.
• III.1.2 Anti-collision and slot layout: Build a 3D survey database; run separation scans for all offsets; codify minimum SF rules.
• III.1.3 Trajectory design:
  • Set KOP, planned build (BUR) and turn rates within DLS and tubular limits.
  • Prefer minimum curvature profile for smoothness.
  • Place tangent holds at casing seats; verify cementing feasibility.
• III.1.4 Engineering models:
  • Torque & drag, hydraulics/ECD, swab/surge, vibration, whirling risk.
  • Hole cleaning at planned inclinations; define AV, RPM, sweep program.
  • Temperature/pressure for elastomers and LWD/RSS ratings.
• III.1.5 BHA & bit selection:
  • Curve: RSS for smoothness or motor+near-bit stabilizers for high BUR.
  • Hold/lateral: point-the-bit RSS or push-the-bit RSS for azimuthal control.
  • Bit: PDC with cutter layout for formation mix; optimize DOC limiters; consider anti-whirl features.
• III.1.6 Survey strategy: MWD with continuous inclination/azimuth; periodic gyro if magnetic interference; apply multi-station corrections.
• III.1.7 Execution envelope: Define operating windows for WOB, RPM, flow, ROP, DLS, ECD, vibration thresholds, slide/rotate ratios.

III.2 Pre-Spud Readiness

• III.2.1 Tool QA/QC: RSS/MWD/motor service records; battery life; elastomer/temp limits; jar settings; drift checks.
• III.2.2 Rig capability: Top drive torque limit, standpipe pressure limit, mixing capacity, solids control, mud cooling (if needed), high-flow pumps.
• III.2.3 Crew procedures: Slide sheets; toolface control; survey QC; anti-collision holds; sweep and backreaming SOP; DPR reporting.

III.3 Execute by Section

• III.3.1 Surface/Hole Opener:
  • Verticality: maintain I = 2° to ease future casing runs.
  • Aggressive hole cleaning; minimize time with BHA stationary.
• III.3.2 Curve/Build Section:
  • Set initial high-side toolface and verify BUR/turn rate vs plan in first 200–300 ft.
  • Motor: compute slide % to meet planned BUR: \( S(\%) = \dfrac{\text{BUR}_{\text{target}}}{\text{BUR}_{\text{motor,100\%}}} \times 100 \).
  • RSS: adjust steering ratio and bias; keep DLS within limits; target smooth minimum curvature.
  • Survey QC every stand; apply azimuth walk corrections; anti-collision scan before each slide.
• III.3.3 Tangent/Hold:
  • Switch to hold BHA; minimize micro-doglegs by stabilizer placement and RSS neutral bias.
  • Maintain AV and rotation for hole cleaning; ream only on indicator rise (T&D/ECD).
• III.3.4 Lateral/3D Turn:
  • Geosteer on real-time LWD; manage stratigraphic dips with gentle DLS (= plan).
  • High-angle cleaning: = 120–180 rpm continuous rotation; periodic high-vis sweeps; flow bumps on connections.
  • Manage vibration: adjust DOC, WOB, RPM; enable surface auto-driller with MSE limit.
• III.3.5 Connections/Trips:
  • Pumps-off flow checks; minimize stationary time in high angle; rotate-while-slacking to break beds.
  • Trip sheets; monitor pick-up/slack-off deltas vs model; wiper trips on variance > 20%.
• III.3.6 Casing & cement readiness:
  • Final ream/condition to bottom; circulate clean to shakers; confirm ECD window for cement.
  • Run casing with centralization based on DLS/tortuosity; monitor set-down and drag vs model.

III.4 Post-Run Optimization

• Bit dull and dysfunction analysis: cutter damage vs vibration logs; update bit/BHA.
• Model update: Calibrate T&D/hydraulics with measured torque, SPP, ECD, and survey tortuosity.
• Lessons learned: Revise slide sheets, steering parameters, and SOPs for next section/well.

IV. Risk & Mitigation (HSE, Reliability, Redundancy)

• IV.1 Collision risk: Continuous anti-collision scanning; enforce SF thresholds; gyro when near magnetic interference; hold if SF breach predicted.
• IV.2 Wellbore stability: Real-time cavings/cavings morphology; adjust MW/chemistry; limit DLS through reactive shales; manage tripping speed to avoid swab/surge.
• IV.3 Losses/frac-out: Maintain ECD margin; staged pumps; LCM pills on early indicators; avoid high-pressure spikes from aggressive RPM/Q changes.
• IV.4 Stuck pipe: Hole cleaning discipline; rotate and circulate prior to trips; contingency jars placed; back-ream protocol and limits.
• IV.5 Vibration & tool failure: Vibe monitoring; DOC limiter bits; adjust WOB/RPM/flow; auto-driller with MSE control; backup BHA on location.
• IV.6 H2S/HP conditions: Sensors, PPE and breathing air readiness; elastomer/material compatibility; derate limits.
• IV.7 Barriers & well control: Dual barrier policy; verify floats; flow checks; shut-in drills; MPD if narrow window.

V. Optimization Levers (Analytics, Maintenance, Debottlenecking)

• V.1 Real-time analytics: Surface-downhole data fusion to optimize WOB/RPM/flow, steering bias, and connection practices; predictive alerts for ECD, T&D, and vibration excursions.
• V.2 MSE-guided drilling: Drive to minimum MSE without entering dysfunction; combine with lithology from LWD to avoid cutter overload.
• V.3 BHA tuning: Stabilizer spacing and gauge pad mods to reduce micro-doglegs; RSS bias optimization; motor bend adjustments between runs.
• V.4 Hydraulics: Nozzle re-size to reach target HSI/bit ?P; manage standpipe pressure headroom; consider mud coolers in hot holes.
• V.5 Hole cleaning: Adaptive sweep program based on cuttings loading and T&D trends; flow ramping and rotation on connections; wipers only on indicators.
• V.6 Emissions: Optimize pump RPM and auto-driller setpoints; minimize reaming and flat time to reduce diesel consumption per foot.

VI. Verification & Monitoring Plan

• VI.1 Surveys & Collision:
  • Surveys every stand (or 30 m); multi-station correction applied daily.
  • Anti-collision scan before each slide and when within 200 ft of any offset; document SF.
• VI.2 Hydraulics/ECD:
  • Record SPP vs Q every connection; ECD via PWD if available; maintain = 0.2–0.5 ppg margin to FG.
  • Mud checks every tour; track PV/YP, gels; LGS via retort daily.
• VI.3 T&D and Hole Cleaning:
  • Trend pickup/slack-off/rotating weights; variance > 15% triggers condition/ream plan.
  • Shaker cuttings size/shape logs; adjust sweeps/AV accordingly.
• VI.4 Vibration/ROP:
  • Downhole shock/vibe channels; maintain green-band = 80% of footage.
  • ROP vs MSE trending; adjust setpoints to maintain optimum.
• VI.5 Post-section reviews:
  • Bit dulls; BHA dynamics; survey tortuosity metrics; model calibration; KPI scoreboard.

Key Formulas for Directional Drilling Control

• Dogleg Severity (Minimum Curvature):

  Given inclinations \(I_1, I_2\) and azimuths \(A_1, A_2\) at two surveys separated by \(\Delta MD\):

  \( \sigma = \arccos\!\big(\cos I_1 \cos I_2 + \sin I_1 \sin I_2 \cos(A_2 - A_1)\big) \)

  \( \text{DLS}\left[\tfrac{\deg}{100\,\text{ft}}\right] = \sigma \times \frac{180}{\pi} \times \frac{100}{\Delta MD\,[\text{ft}]} \)

  Ratio factor: \( RF = \begin{cases} 1, & \sigma=0 \\ \dfrac{2}{\sigma} \tan\left(\dfrac{\sigma}{2}\right), & \sigma \neq 0 \end{cases} \)

• Build/Turn Rates:

  \( \text{BUR} \approx \dfrac{\Delta I}{\Delta MD}, \quad \text{TR} \approx \dfrac{\Delta A}{\Delta MD} \quad \left[\tfrac{\deg}{100\,\text{ft}}\right] \)

• Slide Fraction for Motor Steering:

  \( S(\%) = \dfrac{\text{BUR}_{\text{target}}}{\text{BUR}_{\text{motor,100\%}}} \times 100 \)

• Collision Separation Factor:

  \( SF = \dfrac{\text{Separation Distance}}{\sqrt{\sigma_{\text{well}}^{2} + \sigma_{\text{neighbor}}^{2}}} \quad (\text{keep } SF \ge 1.5) \)

• Annular Velocity (field units):

  \( AV\,[\tfrac{\text{ft}}{\text{min}}] = 24.5 \times \dfrac{Q\,[\text{gpm}]}{D_{h}^{2} - D_{p}^{2}} \quad (D_h, D_p \text{ in in}) \)

• Effective Circulating Density:

  \( \text{ECD}\,[\text{ppg}] = \text{MW}\,[\text{ppg}] + \dfrac{\Delta P_{\text{ann}}\,[\text{psi}]}{0.052 \times TVD\,[\text{ft}]} \)

• Hydraulic Horsepower at Bit / Impact:

  \( \text{HSI} = 11.8 \times \dfrac{Q\,[\text{gpm}]}{\sqrt{A_{n}\,[\text{in}^2]}} \), \quad \( \text{BHHP} = \dfrac{\Delta P_{\text{bit}}\,[\text{psi}] \times Q\,[\text{gpm}]}{1714} \)

• Mechanical Specific Energy (field form):

  \( \text{MSE}\,[\text{psi}] \approx \dfrac{\text{WOB}}{A} + \dfrac{120 \times T\,[\text{ft·lbf}] \times N\,[\text{rpm}]}{\pi \times D\,[\text{in}] \times A\,[\text{in}^2] \times \text{ROP}\,[\tfrac{\text{ft}}{\text{hr}}]} \)

  where \(A = \dfrac{\pi D^{2}}{4}\). Maintain consistent units.

• Cuttings Slip Velocity (laminar/Stokes, estimated):

  \( V_{s} \approx \dfrac{(\rho_{s}-\rho_{m}) \, g \, d^{2}}{18 \mu} \) (use for trend only; correct for inclination and turbulence with empirical factors)

Practical Tips Specific to Complex Wells

• Toolface control: For motor slides, pre-bias toolface by expected walk; keep slide lengths short (e.g., 10–30 ft) to reduce tortuosity.
• RSS preference: Use RSS in curves and laterals where smoothness and in-zone percentage outweigh maximum BUR needs.
• Tortuosity management: Stabilizer-to-bit distance optimization and continuous rotation reduce micro-doglegs; avoid unnecessary micro-slides.
• Thermal limits: Track downhole temperature for elastomer and electronics; derate flow/standpipe as needed; add mud cooling if required.
• Connection practices: Flow bumps before pumps off; rotate at low RPM during flow-down to limit bed settling in high angles.
• MPD integration: For narrow windows, use MPD to stabilize ECD during connections and maintain bottomhole pressure within ±0.1–0.2 ppg.