Surface Casing Cementing Program–U.S Land and Gulf of Mexico
(TECHNICAL EDUCATIONAL PURPOSES ONLY) Add Your Comments
The following document contains examples of typical U.S. Land and U.S. Gulf of Mexico (GOM) Surface Casing Cementing programs; the designs are not field-approved or location-specific engineering programs. This document is intended solely for educational, training, and reference purposes. It provides illustrative examples of cementing-program structure, slurry design, volume calculations, operational steps, and quality-control requirements based on typical U.S. land and Gulf of Mexico surface-casing operations.
For deployment in real drilling operations, this document must be fully adapted, engineered, verified, and approved according to:
A real drilling well case design and subsurface pressure profile
Formation properties and temperature profile
Regional geology and shallow-hazard risks
Local, state, federal, and offshore regulatory requirements
Environmental constraints (water protection, discharge rules, chemical handling)
Operator-specific standards, contractor capabilities, and cement-company laboratory test results
Failure to perform full engineering validation may result in well-control issues, inadequate zonal isolation, regulatory non-compliance, or environmental impact.
1. SURFACE CASING CEMENTING PROGRAM
This technical information document explains the structure and content of a typical operator-grade Cementing Program for the Surface Casing of:
A representative USA Onshore Land Well, and
A representative USA Gulf of Mexico (Offshore) Well.
The objective is to provide:
A guide for consideration by operator engineering teams
A technically sound training example for engineers new to well construction
Reference calculations, slurry-design logic, and procedural outlines
A foundation to build real-world cementing programs using actual well data
2. DESIGN BASIS AND ASSUMPTIONS
The following reference cases represent two common instructional scenarios.
2.1 USA Land Well (Training Example)
Hole Size: 12.25 in
Surface Casing: 9 5/8 in OD
Shoe Depth: 800 ft
Cement Top: To Surface
BHCT/BHST: Insert real values during field adaptation
Note that BHCT/BHST for shallow surface strings may be low (typically 60–120 °F), but must be confirmed through actual temperature modeling.]
2.2 USA Gulf of Mexico Well (Training Example)
Hole Size: 17.5 in
Surface Casing: 13 3/8 in OD
Shoe Depth: 1,500 ft
Cement Top: To Surface
Shallow Water Flow Risk: Possible, depending on the block where the well is drilled
BHCT/BHST: To be determined per well location
GOM surface-casing BHCTs typically range 80–150 °F but must be validated with a thermal model.
3. VOLUME CALCULATIONS
All examples below are should be recalculated using actual casing dimensions, hole-caliper data, estimated hole ID, and cement yield obtained from laboratory testing.g.
3.1 Land Example
Annular Volume: 250.55 ft³
Gallons: 1,874.3 gal
Estimated Sacks (@ 1.25 ft³/sack yield): ~200 sacks
For 10% Excess: ~220 sacks
Typical surface casing excess for U.S. land ranges 25–50% unless caliper logs justify lower values. Adjust field designs accordingly.
3.2 GOM Example
Annular Volume: 1,041.96 ft³
Gallons: 7,794 gal
Estimated Sacks (@ 1.25 ft³/sack yield): ~834 sacks
For 10% Excess: ~917 sacks
GOM shallow sections often require 50–100% excess due to unconsolidated formations and washouts.
3.3 Educational Notes
Real-world cement yield varies with slurry recipe and must be validated by API RP 10B-2 laboratory testing.
Caliper logs should be used when available to quantify hole washouts.
Displacement volumes must reflect the actual casing ID and float-equipment configuration.
Note: Always verify displacement volume against float-collar auto-fill features or differential-fill tool if used.
4. TYPICAL SLURRY DESIGN PRINCIPLES
The following slurry-recipe examples should not be used without laboratory validation for actual well temperature, pressure, potential contamination, and required pump time.
4.1 Land Well: Single-System Slurry (Example Only)
Class G Cement
Target Density: 15.6 lb/gal (baseline neat)
Expected Additives (training values):
Fluid-loss control: 0.5–2.0 lb/sk
Retarder (temperature-based): 0.25–1.5 lb/sk
Dispersant: 0.1–0.5 lb/sk
Optional extenders for low fracture gradients
Design Objectives (Reference only):
Zero free water
Fluid loss < 50 mL (API)
Thickening time: 60–120 minutes minimum
24-hour compressive strength ≥ 500–1,000 psi
For shallow surface strings, fluid-loss control and free-water elimination are critical due to regulatory requirements for freshwater-zone protection.
4.2 Gulf of Mexico: Two-Stage or Unified System (Example Only)
Lead Slurry (if used):
Lightened density for ECD control
Class G + retarder + fluid-loss additive
Optional latex or foamed cement for shallow flow zones
Lightweight lead slurries in the GOM commonly range 11.5–14.0 ppg, depending on fracture gradient, shallow-water-flow (SWF) risk, and ECD limits.
Foamed cement is used only when specifically engineered and tested for the actual BHCT/BHST; it requires nitrogen equipment and strict QA/QC.
Tail Slurry:
Higher-density Class G/H
Silica flour is required for high-temperature stability
Tight fluid-loss control for zonal isolation
Silica flour is required only when BHST exceeds ~230–250 °F. Many GOM surface strings do not require silica because temperatures are typically lower. Field validation is mandatory.
Tail slurry density typically ranges 14.5–16.0 ppg depending on the fracture gradient and zonal-isolation objectives.
Design Objectives:
Manage shallow hazards (SWF, gas influx)
Maintain pumpability during long offshore placement times
Achieve the required compressive strength per the operational schedule
Ensure zero free-water, particularly for the protection of shallow aquifers and regulatory compliance (BSEE/API).
5. CASING HARDWARE AND CENTRALIZATION
A typical operator standard includes:
5.1 Float Equipment
Float Shoe and Float Collar
Auto-fill optional (per operator policy)
Tested per manufacturer standards prior to running
Many operators disable auto-fill for SWF-risk wells due to potential for uncontrolled flow during running.
5.2 Centralizers
Place two (2) centralizers per joint on the first one or two joints above the float shoe to ensure proper stand-off and uniform cement placement in the critical shoe track.
Place one (1) centralizer on the joint immediately above the float collar to maintain full stand-off across the float-collar region, where the casing is typically more eccentric.
Above the float collar:
Space centralizers every 30–60 ft (every 1–2 joints) depending on hole quality, caliper logs, deviation, and known washout intervals.
Bow-spring centralizers are recommended for irregular wellbores or large annular clearances due to their superior restoring force.
Centralization modeling is recommended for offshore wells or wells with high-risk formations, targeting an eccentricity of ≤0.3–0.4 in the shoe track and primary isolation zone.
Most GOM operators target ≥70%–80% stand-off in the surface interval based on API RP 10D-2 modeling outputs.
5.3 Wiper Plugs
Run a bottom plug for contamination control
Run a top plug to isolate displacement fluid from cement
Bump pressure recorded and validated
Verify plug compatibility with float equipment (e.g., latch-in vs. non-latch).
6. TYPICAL FIELD CEMENTING EXECUTION PROCEDURE
6.1 Pre-Job
Review cement lab test results
– Verify slurry densities, rheology, fluid loss, thickening time, free fluid, and compressive strength curve.
– Confirm compatibility with spacers, mud, and formation fluids.
– Confirm lab testing per API RP 10B-2 and 10B-3 where applicable.Review cement job simulation (design outputs)
– Hydraulics, ECD profile, placement efficiency, spacer train, contamination limits.
– Confirm centralization requirements and the installed centralizer tally.Circulate and condition the hole before running casing
– Perform bottom-up circulation to ensure clean returns.
– Remove gelled mud, cuttings, and solids to improve cement bonding.
– Condition mud to achieve stable rheology before running casing.Verify mixing-water quality
– Check pH, hardness, chlorides, temperature, and contaminants.Calibrate cement-unit equipment
– Density meters (in/out), flowmeters, pump strokes/bbl.
– Confirm additive injection calibration (liquid/solid).Pre-job safety meeting (JSA)
– Review hazards, pressure paths, emergency shutdown, communication plans, rig-up checks, and responsibilities.
6.2 Running Casing
Run and land casing to the planned depth
– Maintain controlled running speed to prevent surge/swab.
– Observe drag, torque, and weight changes continuously.Fill casing regularly while running in the hole
– Fill every 2–5 stands, depending on casing size and hole deviation.
– Maintain ≥90% full at all times to avoid collapse or well influx.
– Record actual fill volumes to detect obstructions or losses.Flow check and circulate through casing once casing is at depth
– Verify unobstructed circulation through the float shoe and float collar.
– Ensure no backflow through float equipment.Record pickup and slack-off weights
– Compare against modeled drag to identify ledges, tight spots, or pack-off intervals.Verify centralizer placement
– Confirm centralizers are installed per the approved program:
• Two (2) centralizers in the first joint(s) above the float shoe
• One (1) centralizer in the joint directly above the float collar
• Then one (1) centralizer every 20–30 ft or every second joint, depending on deviation and stand-off requirement.
– Document centralizer tally.
– Gaps must not exceed modeled limits to maintain the required stand-off per API RP 10D.
6.3 Pumping
Launch the bottom plug
Pump pre-flush/spacer train
– Mix and pump pre-flush, chemical wash, and weighted spacer as per design.
– Monitor returns and ensure proper interface separation from mud.
– Maintain spacer contact time per lab test results.Pump lead cement slurry (if applicable)
– Maintain rate, density, and monitor pump pressures.Pump tail (main) cement slurry
– Maintain programmed placement rate to control ECD.
– Monitor cement-unit densities and returns.Launch the top plug
– Verify correct plug release and monitor pressure signature.Displace with the currently in-use drilling fluid
– Displace to bump volume.
– Maintain stable flow and monitor for losses or restricted flow.Verify full and consistent returns throughout the pumping process
– Watch for lost circulation, gains, or gas cutting.Bump the top plug and record the final displacement pressure
– Identify a clean bump (pressure rise and plateau).
– Record bump pressure, displacement volume, and time.Hold pressure (if required by program)
– Hold for a designated duration to ensure plug-seat integrity.
– Verify no backflow after pressure release.Wait on Cement (WOC)
– Follow the lab compressive-strength curve for the minimum WOC time.
– Do not disturb casing until strength requirements are met.
6.4 After Cementing
Document all cement job parameters
– Actual pumped volumes, densities, pressures, rates, cement-unit charts, return behavior, and any irregularities.Flow check and confirm no backflow
– Ensure float equipment is holding.Tag cement top (if required)
– Tag with appropriate weight and depth control to verify TOC inside casing.
– Avoid excessive weight that could damage cement.Pressure test casing after WOC
– Pressure test per operator/regulatory requirements once cement reaches the required strength.Clean out the casing to the float collar
Run post-cement logs if required
– CBL/VDL, ultrasonic, or radial cement-evaluation logs, depending on well classification and regulatory rules.
– Surface casing logs may be required for conductor-to-surface-casing integrity confirmation in certain GOM well categories.
7. QUALITY ASSURANCE / QUALITY CONTROL (QA/QC)
7.1 Laboratory Requirements
The cementing contractor must supply a full laboratory qualification package in accordance with API RP 10B-2, API Spec 10A, API RP 10B-5/6, and NORSOK D-010 for offshore North Sea operations.
The package shall include:
Cement Slurry Testing
• API RP 10B-2 test results for all slurry systems
• Thickening time curve (TT) at bottomhole circulating temperature (BHCT)
• Compressive strength development curve (UCA and/or crush tests) at bottomhole static temperature (BHST)
• Free water and fluid loss measurements
• Rheology at various temperatures (API and Fann dial readings)
• Static gel strength development (SGS profile)
• Slurry stability/sedimentation test (API 10B-6)
• Density verification (lab vs. program design)
Compatibility and Contamination
• Cement–spacer and cement–mud compatibility tests (API 10B-6)
• Contamination tolerance tests simulating downhole blend ratios
• Mix water analysis (pH, chlorides, hardness, temperature)
Final Cement Design Deliverables
• Exact mix water volume and water ratio
• Final slurry yield (ft³/sk)
• Expected set time at well conditions
• Additive concentrations and batch numbers
• QA/QC certificates for dry/cement additives and blend validity
7.2 Field Requirements
Field QA/QC must comply with API 65-2, company operating standards, and cementing contractor procedures. The following measurements must be recorded, validated, and included in the final job report:
Cement Unit Operations
• Continuous recording of:
– Slurry density (in/out)
– Pump rate (spm and bpm)
– Total pumped cement volumes
– Displacement volume and rate
– Pump pressure (real-time chart)
• Density checks using a pressurized mud balance every 15-30 minutes
• Spacer density and volume verification
• Calibration check of cement unit density systems before the job
Casing & Circulation QA/QC
• Confirmation of full casing circulation before launching the bottom plug
• Verification of float equipment integrity (no backflow)
• Casing tally accuracy and centralizer tally validation
Plug and Bump Pressure Verification
• Validate bottom plug release (pressure drop or signature)
• Validate top plug bump (sharp pressure increase then stabilization)
• Compare actual bump pressure vs. predicted bump pressure
• Document plug landing displacement volumes
Returns Monitoring
• Monitor returns for:
– Full/partial or lost returns
– Gas cut mud or contamination
– Cement returns to surface (when applicable)
• Document return quality trend during spacer, lead, and tail slurries
Contingency QA/QC
• Document activation of:
– LCM pills
– Reduced pumping rates due to pressure constraints
– Excess cement volumes or extended displacement
• Record any deviation from the approved cementing program and its justification
7.3 Post-Job Quality Verification (Recommended Add-On)
• Completion of full cement job report by contractor and operator
• Inspect and retain cement unit job charts (pump pressure, density, rate)
• Verify actual vs. planned slurry volumes and returns
• Conduct CBL/VDL, USIT, or radial cement logs as per program requirements
• Pressure test casing after WOC per API 5C3 requirements
• Perform job debrief meeting with operator, contractor, and drilling crew
7.4 Document Control & Record Retention
• Retain all QA/QC job records for a minimum of 5 years or per regulatory requirement
• Include lab reports, calibration certificates, job execution charts, log evaluations, and all deviations from the program
8. CONTINGENCY GUIDELINES (TRAINING PURPOSES)
The following guidelines are provided purely for training and educational purposes and do not replace operator-specific contingency policies or regulatory requirements. The Drilling Supervisor and Company Representative must approve all actions.
8.1 Losses During Cementing
• Notify Drilling Supervisor immediately
• Reduce pump rate to lower ECD and minimize risk of losses
• Switch to low-density or lower ECD cement blends (lightweight, foam, or extended systems)
• Implement LCM strategy as per the operator's Drilling Fluid and Cementing Manual
– Pre-flush with high-vis spacer
– Pump fiber-based or granular LCM
– Pump loss-circulation cement (rapid-set or thixotropic)
• Monitor for total vs. partial losses
• Consider pumping a staged cement job
• If losses occur before displacement:
– Slow down displacement
– Add annular pressure relief via managed pressure (if equipment available)
• If severe losses threaten well control:
– Stop the job
– Check for influx
– Switch to well-control mode per operator procedures
8.2 No Returns at Surface
• Verify return path and choke line/separator system (confirm no surface restrictions)
• Check for plugged flowlines or solids buildup
• Confirm float equipment integrity and no backflow
• Monitor casing pressure for signs of trapped cement
• Slow down pumping or stop to evaluate well condition
• If returns do not re-establish:
– Be prepared to top-up cement from the surface after displacement
– Monitor annular pressure for any indication of shallow influx
• Post-job evaluation:
– Run CBL/VDL or ultrasonic log early
– Consider squeeze cementing to restore isolation
8.3 Float Equipment Failure
• Identify failure through backflow or inability to bump plug
• Install surface backpressure as needed
• Consider pumping additional cement through drillpipe or workstring
• Plan for a remedial squeeze job after WOC
• Run cement evaluation logs to verify cement placement and integrity
8.4 Plug Does Not Bump or Premature Bump
• Verify displacement volumes vs. planned
• Check for incorrect top plug release or plug signature mismatch
• Check for channeling or premature plug rupture
• If a premature bump occurs:
– Do not exceed the maximum allowable casing pressure
– Attempt a low-pressure soft bump before stopping the job
• If the plug does not bump:
– Stop displacement
– Hold pressure to see if plug seats gradually
– Prepare for wiper plug verification or inside-squeeze operations
8.5 Shallow Water / Shallow Flow Zones (GOM & Onshore Shallow Hazard)
• Use lightweight, foamed, or latex-modified cement systems for low density and better isolation depending on local well conditions
• Optimize centralization to maintain eccentricity < 0.4
• Limit pump rate to maintain ECD below fracture gradient
• Use extended or compressible slurries to minimize surge effects
• Implement pre-job pore pressure/fracture gradient review
• Use pressure-while-cementing monitoring (PWC) if available
• Increase lead slurry volume to ensure full coverage across shallow-flow zones
8.6 Annular Overpressure / High ECD Risk
• Reduce displacement rate
• Use lightweight or compressible spacers
• Circulate well to reduce gels before starting the cement job
• Monitor real-time ECD or equivalent drilling hydraulics to prevent fracturing the formation
8.7 Cement Falls Back After Pumping
• Check float equipment for leaks
• Install annular backpressure if possible
• Prepare for top-up cementing job
• Evaluate cement integrity with early CBL/VDL or ultrasonic logs
8.8 Equipment Malfunction (Cement Unit, Pumps, Mixers)
• Switch to backup pump or cement unit immediately
• Stop the job if density or rate becomes unstable
• Record the exact time and condition of failure
• If needed, execute emergency pumping from rig pumps
• Evaluate if the partial pump caused contamination or channeling
8.9 Gas Migration Risk During WOC
• Monitor casing pressure for at least 12–24 hours after cement placement, depending on well depth and gas risk
8.10 Well Control Contingencies
If any signs of kick or influx are observed during cementing:
• Stop pumping immediately
• Shut in the well per the operator's well control plan
• Follow API RP 59 / IADC Well Control guidelines
• Ensure personnel are aware of well control status and emergency procedures; evacuate only if directed by company procedures
9. ENVIRONMENTAL & REGULATORY CONSIDERATIONS
For real-world operations, environmental and regulatory requirements must be fully incorporated into the cementing program. These requirements vary depending on region (onshore/offshore), state regulations, and federal oversight. At a minimum, the following considerations must be addressed:
9.1 Water Protection & Zonal Isolation Regulations
Identify and comply with state-specific groundwater protection depth (e.g., Texas RRC USDW requirements).
Ensure cement selection and TOC comply with regulatory standards for casing and cement to protect USDWs.
Confirm compliance with:
• EPA Underground Injection Control (UIC) requirements
• API RP 65-2: Isolating Potential Flow Zones During Well Construction
• Any special aquifer protection mandates
9.2 Federal Offshore Requirements (BOEM/BSEE)
Follow BSEE requirements for:
• Cement mechanical properties (compressive strength, thickening time, free water, fluid loss)
• Real-time monitoring of volume, rate, and pressure
• Required cement evaluation logs after setting surface, intermediate, or production casing
• Shallow hazard mitigation (shallow water flow, gas hydrates)
• Submit cementing program and post-job reports per BOEM Subpart B
9.3 Chemical Handling, Storage & MSDS Compliance
• All chemicals must have Safety Data Sheets (SDS/MSDS) on site
• Storage must follow OSHA HazCom 1910.1200
• Secondary containment for additives that pose spill risk
• Document additives used in chemical inventory and usage logs for regulatory audits
9.4 Zero-Discharge / Limited-Discharge Zones
Offshore zero-discharge areas require:
• Closed-loop systems
• No release of returns or contaminated water overboard
Onshore sensitive zones (wetlands, conservation areas) may require:
• Containment berms
• Lined pits or tanks for cement returns
• No on-site burial of cement cuttings or washouts; dispose according to state environmental regulations
9.5 Marine & Wildlife Protection (Offshore)
Follow mitigation measures for:
• Marine mammal exclusion zones
• Seafloor habitat protections
• Noise control during cement pumping, if required
• Coordinate with ROV operations to avoid disturbing corals, pipelines, or protected habitats
9.6 Spill Prevention & Emergency Preparedness
Implement SPCC (Spill Prevention, Control, and Countermeasure) plans.
Cementing units must have:
• Drip trays
• Spill kits
• Dedicated chemical transfer hoses in good condition
• Immediate reporting procedures for any chemical discharge
9.7 Waste Management & Returns Handling
Establish a plan for:
• Disposal of excess mixed cement
• Cement slurry returns
• Washout material from lines/pits
Onshore: comply with state waste disposal rules (e.g., Texas TCEQ waste classification).
Offshore: comply with MARPOL Annex V and BSEE waste handling.
9.8 Air Emissions & Noise Mitigation
• Cementing unit engines must meet emissions standards (EPA Tier requirements)
• If required, use low-noise pumps or acoustic shielding in populated or protected areas
9.9 Documentation & Reporting Requirements
Provide regulatory bodies with cementing program details, including:
• Cement slurry formulas
• Centralizer program
• Actual job parameters
• Volumes, densities, pressures, returns
Maintain ready access to records for audits and incident investigations.
File cement evaluation results where required by state/federal authorities
10. DOCUMENTS & DELIVERABLES REQUIRED FROM THE CEMENTING COMPANY
The cementing service provider must deliver the following documentation before, during, and after the job. These documents must meet API, ISO, and NORSOK standards where applicable.
10.1 Pre-Job Laboratory & Engineering Deliverables
Full Slurry Design Laboratory Packet (API 10B-2 / 10B-3)
Includes complete laboratory qualification of each slurry system:
• Thickening time (TT) at BHCT
• Compressive strength development (UCA)
• Static gel strength (SGS) measurements
• Fluid loss, free water, and rheology
• Slurry stability (sedimentation) test
• Contamination tolerance (10–20% drilling fluid)
• Expansion or shrinkage additives testing (if applicable)
Detailed Slurry Recipe & Material Specifications
• Exact additive concentrations (ppt, %BWOC, %BWOW)
• Batch mixing water volume and required water quality specs
• Final slurry yield, total sack count, and total required water
• Cement type/API class and blend details (silica, pozzolan, fly ash, etc.)
Cementing Job Design Report / Engineering Model
• Expected ECD profile during pumping and displacement
• Friction pressure drop, pump rate envelopes, and hydraulic modeling
• Spacer design (density, rheology, compatibility test results)
• Temperature modeling (thermal profile, BHCT, BHST)
• Volumetric calculations (open hole volume, excess %, TOC estimate)
• Centralization model results (if provided by vendor)
Pre-Job Safety, Risk, and Contingency Documentation
• HAZID/HAZOP input for cementing operations
• Job safety analysis (JSA)
• Contingency slurry systems and criteria for activation
• Losses / no-returns / shallow hazards response plan
10.2 Operational Documentation (During the Job)
Pumping Schedule & Real-Time Execution Sheet
• Pump rates and density schedule
• Spacer and slurry volumes
• Plug release and bump parameters
• Expected displacement volumes
• Monitoring points for pressure and returns
Rig-Site QA/QC Documentation
• Calibration certificates for:
– Density meters
– Pressure sensors
– Temperature gauges
• Mix-water temperature and salinity measurements
• Real-time density and pressure monitoring logs
Material Transfer & Verification Records
• Bulk cement transfer logs
• Additive load-outs and batch tickets
• Water usage logs
• Verification of dry bulk silo pressures
• Pre-mixing batch sheets (if batch mixer used)
10.3 Post-Job Documentation (After the Job)
Complete Job Ticket (Daily Service Report)
• Actual volumes pumped
• Actual pressures and rates
• Density chart
• Pump strokes and displacement volumes
• Plug bump pressure and final signature
Pressure Chart & Density Log (Time-Stamped)
• Continuous real-time recording trace of pump pressure, density, and flow rate
• Comparison of planned vs. actual values
Post-Job Evaluation & Engineering Summary
• Final TOC estimate based on volumes and returns
• Deviations from the plan and their impact
• Recommendations for future jobs
• Summary of any operational issues (losses, no returns, plug issues)
• Evaluation of spacer performance and slurry placement efficiency
Post-Job Cement Evaluation Interpretation (if logs run)
• Preliminary CBL/VDL/USIT interpretation
• Bond index and isolation evaluation
• Identification of weak zones or potential micro-annulus
Waste and Environmental Compliance Records
• Cement returns disposal documentation
• Chemical usage logs (per environmental regulations)
• Spill prevention and handling reports
• Offshore zero-discharge compliance verification (if applicable)
10.4 Optional But Strongly Recommended Deliverables
• Digital Cementing Job Simulation Files
– Landmark, CemPro, CemCADE, or similar modeling files
– Input sheets for hydraulic and temperature modeling
• Lessons Learned Report (Operator + Cementing Vendor)
– Root cause analysis of deviations
– Recommendations for the next well
– Updates to operator procedure (if needed)
11. FINAL EDUCATIONAL NOTES & RECOMMENDATIONS
These points help bridge theoretical knowledge to real operational engineering. They reinforce that example programs are for training only, not field deployment.
• Never use example programs for real wells without a full engineering review.
• Each actual cement job requires recalculation of volumes, temperature schedules, pumpability windows, and updated formation pore/frac gradients. Lab tests must reflect current mud properties, expected contaminants, and bottomhole circulating temperatures (BHCT/BHST).
• Always request two contingency slurry systems tested at 10–20% mud contamination – This includes high-yield, lightweight options, accelerated systems, and alternatives for partial returns or losses. Contamination tests should cover both rheology and compressive strength degradation.
• Model centralization using true wellbore geometry and verify centralizer quantities with torque & drag – Avoid generic spacing rules. Run simulations for stand-off, doglegs, casing drag, and available clearance. Validate bow-spring vs. rigid centralizer selection against DLS, casing OD, and caliper logs.
• Perform shallow-hazard evaluation offshore (SWF, shallow gas, weak formations) – Integrate geohazard maps, seismic data, pore pressure modeling, and offset well failures to design fit-for-purpose pump rates and ECD limits.
• Verify float equipment and plug systems, pressure ratings, compatibility, rotation, and drillability – Ensure equipment is API-certified, rated above expected bump pressure, and compatible with the selected slurry (latex, foamed, retarded, or high-density systems).
• Confirm ECD windows using real-time mud rheology, temperature profiles, and displacement rates – Always match operational pump rates with the formation fracture gradient and pore pressure window, especially in depleted zones, SWF intervals, or weak surface formations.
• Ensure the cementing vendor provides API 10B-2 (and 10B-3 offshore) lab data, not only computer simulations – Lab testing must include rheology, thickening time, fluid loss, free water, compression strength curves, static gel strength (SGS), and contamination tolerance.
• Prepare a field-ready job card summarizing volumes, densities, mixing instructions, and bump pressures: This card must include a step-by-step pumping sequence, displacement volumes, plug identification, spacer details, contingency plans, and key pressure limits.
• Involve drilling, mud, cementing, and geology teams early – Proper integration ensures alignment on ECD management, mud conditioning requirements, circulating times, expected losses, and environmental constraints (e.g., discharge rules, waste handling).
• Document and review lessons learned after every cement job to update operator standards – Capture details such as pumpability issues, unexpected pressures, returns anomalies, job execution deviations, and post-job log results (CBL/VDL/USIT). Update best practices and operational checklists accordingly.
• Balance pre-job hole conditioning with the rig's actual capabilities – Long circulation periods, wiper trips, or bottoms-up volumes must be compatible with rig hydraulics, formation stability, and operator cost constraints.
• Always validate displacement fluid properties (density, viscosity, compatibility) – Improper displacement design is a major cause of micro-annulus and channeling failures.
• Verify cement placement using evaluation tools, not assumptions – Consider CBL, VDL, ultrasonic logs, and pressure testing to confirm zonal isolation, especially across regulatory protection depths.
• Maintain strict QA/QC on mix water, additives, batch mixing, and density control – Even slight variations in water salinity, temperature, or additive concentration can significantly affect thickening time and compressive strength.
• Perform a pre-job simulation of surge/swab sensitivity during casing running – Poor tripping practices can induce losses that compromise cement placement before the job even begins.
12. APPLICABLE STANDARDS AND RECOMMENDED PRACTICES
The following standards, recommended practices, and regulations shall be used as technical references for planning, designing, and executing casing and cementing operations. All cementation programs must conform to the most current editions of these documents as applicable to the operational area (U.S. Land, Gulf of Mexico, or other jurisdictions).
12.1 API Standards (American Petroleum Institute)
Casing & Well Integrity
• API STD 65 - Part 1 - Cementing Shallow Water Flow Zones
• API STD 65 - Part 2 - Isolating Potential Flow Zones During Well Construction
• API TR 5C3 - Casing and Tubing Properties / Pressure Ratings
• API RP 5C1 - Recommended Practice for Casing and Tubing Operations
• API RP 96 - Deepwater Well Design and Construction (for GOM operations)
Cement Testing & Slurry Qualification
• API SPEC 10A - Specification for Cements and Materials for Well Cementing
• API RP 10B-2 - Recommended Practice for Testing Well Cement
• API RP 10B-4 - Preparation and Testing of Cement Job Mix Water
• API RP 10B-5 - Determination of Shrinkage and Expansion Properties
• API RP 10B-6 - Fluid Compatibility and Contamination Testing
• API SPEC 10B-1 - Equipment for Slurry Testing
• API RP 10TR1 - Cement Sheath Integrity Evaluation
Operational Safety and HSE
• API RP 76 - Contractor Safety Management
• API RP 1173 - Pipeline Safety Management System (general safety framework often adopted by operators)
• API RP 54 - Occupational Safety for Oil and Gas Well Drilling and Servicing Operations
12.2 NORSOK Standards (Norwegian Petroleum Industry)
• NORSOK D-010 - Well Integrity Standard – Barrier requirements, cement placement quality, verification methods, TOC requirements, centralization, and annular isolation criteria.
• NORSOK D-006 - Well Design (supporting casing design and cementation considerations)
12.3 ISO Standards (International Standards Organization)
• ISO 10426-1 - Testing of Well Cements (API 10B series equivalent)
• ISO 10426-2 - Testing of Cement Slurry and Well Cement
• ISO 13679 - Procedures for Testing Casing and Tubing Connections
12.4 Other Industry and Engineering References
• SPE Drilling & Completions Manuals
• Halliburton Red Book - Cementing Tables
• Schlumberger Cementing Handbook
• Weatherford and Baker Hughes Cementing Engineering Manuals
• Deepwater and Land Operator Engineering Standards (per operator)
• Local / Federal Regulatory Requirements (BOEM, BSEE, RRC Texas, etc.)
12.5 Compliance Statement
All cementing programs shall be reviewed and verified to comply with:
• Applicable API standards and test procedures
• NORSOK D-010 barrier philosophy
• Local regulatory requirements (BOEM/BSEE, state agencies)
• Cementing company QA/QC manuals
• Operator's internal well construction and integrity standards
Where discrepancies occur, the more conservative or most stringent requirement shall apply.