The changes reflect a fundamental shift in how operators manage assets. Operators now work within an environment defined by regulatory pressure, public scrutiny and the technical reality of aging infrastructure. As a result, pipeline management has become a practice that depends on accurate data, continuous monitoring and reliable decision pathways rather than isolated inspections.

This article examines how the field has evolved, the challenges operators continue to face, the technologies shaping 2026 and the practical direction that data driven programs provide. It also explains how Cenozon’s pipeline integrity solutions integrate into day-to-day operations. 

What Pipeline Management Means in 2026

Pipeline integrity management in 2026 relies on continuous visibility supported by scenario-based analysis. According to a 2024 GAO report, about 43% of significant onshore gas pipeline incidents were caused by material or equipment failure, with corrosion responsible for another 16%. This underscores why operators must combine inspection data, operational history, and environmental monitoring into a unified view, reviewing condition data, material information, operational inputs, and geospatial context together to form a consolidated understanding of system health.

Several factors pushed the field into its current form.

1. Operators Need Consistent Data, Not Isolated Reports

ILI (inline inspection) tools continue to play a central role by capturing internal pipeline conditions such as wall thickness, corrosion, and deformation. However, federal data from PHMSA show that internal corrosion caused around 12% of pipeline incidents between 2013-2017, reinforcing why ILI measurements alone are not enough without complementary operational and environmental data.

2. Aging Infrastructure Requires Closer Supervision

Many North American systems now operate beyond their original design life, shifting the focus toward trend-based interpretation. Long-term analysis indicates that external corrosion remains the leading cause of pipeline ruptures, with rates roughly double those caused by excavation or material failure. This underscores the importance of trend-based monitoring and predictive maintenance.

Operators want to understand whether a corrosion feature is stable or accelerating, whether fatigue cycles are increasing, and whether coating failures correlate with known environmental conditions.  This makes continuous tracking critical.

3. Field Work Needs to be Documented the Moment it Happens

Supervisors want accurate confirmation of repairs, valve operations, measurement changes, excavation results and patrol observations. Manual entry introduces errors. Tools like Cenozon’s FINDpro support structured digital capture in the field, which improves the fidelity of integrity programs.

4. Decision Pathways Must be Traceable

Regulators expect operators to show why decisions were made. A modern program records data inputs, risk calculations, classification of threats and the rationale behind mitigation work.

When combined, these factors form the new baseline for digital pipeline management across the industry.

Challenges Faced by Pipeline Operators in 2026

Even with better tools, operators still contend with several structural issues. 

These issues influence cost, staffing, productivity and compliance.

Fragmented Data Systems

Many operators still work with separate inspection databases, GIS platforms, maintenance logs and environmental records. Fragmentation increases the risk of missed information. A pressure cycle anomaly may not be recognized during a corrosion review if the data sits in a separate application.

Regulatory Complexity

Rules continue to expand, especially for gas gathering, liquids transmission, emergency response and methane reporting. Compliance officers need accurate documentation. Programs that depend on manual file handling often fall behind.

Skill Shortages

Experienced integrity engineers are retiring faster than companies can replace them, creating a growing knowledge gap. New engineers and technicians require structured workflows, clear data streams, and consistent tools to make informed decisions. Without these systems in place, risk assessments can be delayed or inconsistent, and field teams may struggle to prioritize maintenance effectively.

Aging Pipelines and Changing Environments

Flooding, slope movement, and extreme weather events place additional stress on older pipelines, increasing the likelihood of failures. Identifying threats early is now a requirement, not an aspiration, and it demands both high-quality data and integrated monitoring systems. Corrosion, soil movement, and environmental shifts all interact in complex ways, making it essential to combine sensor readings, historical records, and geospatial insights to accurately assess risk. Proactive maintenance and predictive analytics are central to keeping infrastructure safe and reliable.

Inconsistent Reporting from the Field

Handwritten notes, delayed uploads and unstructured photographs reduce data quality. This directly affects risk assessment for pipelines because incomplete information creates blind spots.

These challenges explain why digital integration has become a core requirement rather than an optional improvement.

The Role of Digital Transformation in Modern Pipeline Programs

A recent MDPI study shows that pipeline release frequency has steadily declined from about 1.1 per 1,000 km/year in the 1970s to 0.09 in 2022. But the same research also notes that corrosion and material fatigue still account for most leak events. In other words: even with fewer incidents overall, the nature of the risk hasn’t changed.

That’s why operators are shifting toward technology-driven programs that tighten risk management, strengthen maintenance planning, and improve the accuracy of integrity forecasts. Teams rely on AI-assisted analysis, IoT sensors, cloud platforms, and standardized data models to bring all their data together and make decisions faster and more reliably.

Below is how each of these layers contributes to a more predictive, connected integrity program.

AI Assisted Threat Identification

Artificial intelligence reviews large volumes of data far faster than manual methods. For example, operators can analyze corrosion growth by comparing multiple ILI runs over time. AI tools can detect subtle patterns, such as localized acceleration that may not appear significant at first glance. The technology does not replace engineering judgment. It highlights where deeper review is needed.

IoT Based Monitoring

Pressure sensors, flow transmitters, vibration instruments and line temperature monitors supply continuous data. This strengthens pipeline monitoring software because the system can flag outliers, confirm stable operation or identify deviations that correlate with known threats.

Unified Software Ecosystems

When GIS, ILI databases, excavation reports, environmental logs and emergency response plans sit within a single platform, decisions are faster and more defensible. This is central to oil and gas asset management in 2026. Teams no longer work from fragmented records. They operate from a verified source of truth.

Digital Twins

A digital twin is a virtual representation of a pipeline system. It updates as new data enters the platform. This allows engineers to run scenarios, such as predicting corrosion growth or evaluating pressure related fatigue. Digital twins support planning and audit readiness.

Enhanced Field Integration

FINDpro simplifies field operations by capturing photos, measurements, work notes, valve movements, excavation findings and repair details in structured form. Supervisors receive clean data in real time. This improves the accuracy of integrity workflows.

Best Practices in Data Driven Decision Making

Below are the practices adopted by operators with advanced digital programs. These practices allow teams to work with consistent data and clear rules.

Develop a Unified Data Model

All pipeline records should flow into a consistent structure. This includes ILI findings, coating surveys, cathodic protection readings, operational logs, environmental information and field reports. A unified model prevents errors created by inconsistent formats.

Build Repeatable Risk Calculations

Risk models must be transparent, traceable and updatable. Whether evaluating corrosion, geotechnical threats or third party damage, engineers should be able to view every input. Tools like Cenozon’s Pipeline Integrity Risk Manager (PIRM) provide standardized calculations that reflect industry methodology.

Use Predictive Analytics to Refine Maintenance Cycles

Predictive tools help teams move from reactive work to planned intervals. This is especially important for predictive maintenance oil and gas programs. When operators know which features are trending toward criticality, they can schedule repairs before the system enters a high risk state.

Align Field Operations with Integrity Workflows

Field crews collect the information that drives engineering decisions. Programs only function if that information is accurate. Cenozon’s FINDpro supports this with structured reporting templates and automatic uploads.

Integrate Environmental Monitoring

Cenozon’s HydroFlow helps operators track crossings, wetlands and sensitive areas. Environmental data matters because it informs mitigation. For instance, if a watercourse shows significant fluctuation, engineers can evaluate whether scour or bank movement threatens nearby pipe.

Maintain Audit Ready Documentation 

Data validity matters. Regulators expect accurate, traceable records, especially for inspections, repairs, and incident responses. Cenozon’s Pipeline Integrity Risk Manager (PIRM) centralizes inspection reports, repair logs, and operational data, ensuring documentation is complete, standardized, and easily retrievable. By keeping all information in a unified digital system, PIRM reduces the risk of missing data and supports audit-ready compliance.

Case Examples: How Cenozon Tools Work in Practice

Below are clear, scenario based examples that mirror real field conditions. These are not generalized summaries. They show how tools support specific decisions.

Scenario 1: Corrosion Feature Trending Toward Intervention

An operator compares two ILI runs. The feature shows measurable growth but does not meet immediate repair criteria. Engineering wants more context before scheduling excavation. PIRM compiles the growth rate, wall thickness, pipe grade, pressure cycles and coating history. The engineer then views the predictive curve and identifies that the feature will reach the threshold in the next operating cycle. The excavation is scheduled during planned downtime.

Scenario 2: Field Excavation Documentation

A dig crew exposes pipe for verification of metallic loss. Instead of handwritten notes, the crew uses FINDpro to capture exact measurements, photographs of the feature, coating condition and soil characteristics. The data uploads instantly. Engineering verifies the measurements the same day rather than waiting for manual file transfer.

Scenario 3: Environmental Changes at a Crossing

HydroFlow records water level variation at a river crossing. The data shows a steady rise during spring runoff followed by rapid drops. A geotechnical review identifies potential bank movement. The team schedules a targeted inspection to confirm whether support structures or bedding require work.

Scenario 4: Pressure Deviation in a Gathering Line

Sensors detect a repeating pressure fluctuation during a specific operating window. The control room flags it. PIRM correlates the fluctuation with an area that previously showed coating damage. This prompts a closer review, which results in a short targeted dig. The issue is resolved before the fluctuation turns into fatigue risk.

Scenario 5: Documentation for an Audit

During an audit, regulators request verification of repairs completed three years earlier. Instead of searching through paper files, the operator retrieves repair records, field photos, measurements and signoff from PIRM and FINDpro. The audit proceeds without delay.

Top 5 Trends in Pipeline Management for 2026

Below is a simple table summarizing the most influential trends.

Future Trends Shaping the Next Decade

While the industry has made significant progress, several trends will likely define the next decade.

Broader Automation in Inspection and Verification

Automated data checks will increase. Software platforms will compare readings across multiple sources and alert teams when inconsistencies appear. This reduces manual review time for engineers.

Wider Adoption of Cloud Based Systems

Cloud platforms support version control, role based access, remote audits and shared workspaces. They also support real time updates, which is valuable during operational events or emergency response situations.

Predictive Risk Frameworks

Risk calculations will shift from static models to continuous models. As new data enters the system, the risk score recalculates. This approach supports accurate mitigation scheduling.

Integration of Geospatial Analytics

Slope movement, stream migration, frost heave and settlement all influence pipeline conditions. Geospatial data will become a standard part of integrity programs.

Stronger Environmental Accountability

Environmental reporting will become more structured. Tools like HydroFlow already support these expectations. Over the next decade, programs will tie environmental readings directly into integrity workflows so threats can be identified more quickly.

Conclusion: The 2026 Outlook

Pipeline teams work within a complex environment. They balance regulatory demands, technical realities, aging infrastructure and stakeholder expectations. The shift toward unified data, predictive models and digital field reporting is not a trend. It is a necessary response to current operating conditions.

As 2026 continues, operators who invest in structured tools, consistent data and clear processes will maintain safer and more predictable systems. Cenozon simplifies pipeline management for operators across North America with platforms that support this direction, including PIRM, FINDpro and HydroFlow.

Looking for a smarter way to manage pipeline integrity? Integrate your data, reduce risk, and make every decision audit-ready with Cenozon. 

The post Understanding Pipeline Management in Oil and Gas [2026] appeared first on Cenozon.

This is the daily reality for oil and gas operations teams in 2026. With assets spread across remote pipeline corridors, well sites, and processing facilities, traditional field service approaches create bottlenecks that cost you time, money, and regulatory confidence. The right field service management software for oil and gas doesn’t just digitize paperwork it fundamentally changes how your teams work in low-connectivity environments while maintaining the audit trails that keep regulators satisfied.

Key Takeaways

• Offline-first capabilities are non-negotiable for oil and gas field operations where connectivity is unreliable
• GIS mapping integration reduces wrong-site visits and cuts navigation time by helping teams locate assets precisely using LSD/township coordinates
• Digital work orders and compliance documentation accelerate close-outs, reduce safety incidents, and create clean audit trails for PHMSA and state regulators

Why Feature Checklists Matter More in Oil & Gas

Not all field service management software is built for the realities of oil and gas operations. Consumer-grade tools assume constant connectivity, simple workflows, and forgiving compliance requirements. Your operations demand something different.

Pipeline integrity work happens in remote locations where cellular signals disappear for miles. A single missed inspection or incomplete JSA can trigger regulatory action. Your technicians need to capture GPS-stamped photos, complete multi-page inspection forms, and document safety protocols—all while standing next to a valve station with zero bars of signal.

1. Offline-First, Field-Ready Mobile App

Why It Matters

When your field technicians lose connectivity, work shouldn’t stop. An offline mobile field app with store-and-forward architecture allows teams to complete inspections, capture data, and document compliance activities in zero-signal environments. The app queues all entries locally, then syncs them back to your central system once connectivity returns.

Without offline capability, technicians resort to paper notes, photos on personal phones, and manual data entry back at the office. This introduces transcription errors, delays reporting, and creates gaps in your audit trail.

What good looks like:

• Full functionality without internet connection—forms, photos, videos, signatures, GPS coordinates
• Automatic conflict resolution when multiple technicians sync overlapping data
• Media compression to minimize sync time when connectivity is poor
• Visual indicators showing which data is synced versus queued locally
• Battery-efficient operation for full-day field work

How to Evaluate It

Questions to ask vendors:

• Can technicians complete entire workflows with airplane mode enabled?
• How does your app handle conflicting edits from multiple users on the same asset?
• What happens to queued data if the app crashes or the device dies?
• How large are your mobile apps, and how much storage do they require for typical use?

Red flags:

Apps requiring ‘periodic connectivity checks,’ vendors who say ‘just use mobile hotspots,’ or systems that lose queued data after forced app closure.

Cenozon in Practice

FINDpro’s offline mobile inspections and workflows enable field teams to capture inspection data, complete digital forms, and document compliance activities at remote pipeline facilities. All entries—including photos, GPS coordinates, and e-signatures—queue locally and sync to the cloud when connectivity returns, ensuring supervisors receive complete, timestamped records for office review and regulatory reporting.

2. Interactive GIS Mapping & Precise Asset Location

Why It Matters

Finding the right valve station or pump site shouldn’t require three phone calls and two wrong turns. GIS mapping for oil and gas operations provides spatial intelligence that gets technicians to the correct location faster, reduces fuel costs, and eliminates the compliance risk of working on the wrong asset.

Oil and gas assets are often identified by legal land descriptions (LSD), township-range-section coordinates, or internal ID systems that don’t appear on consumer GPS apps. Field service management software with integrated GIS layers allows technicians to search by these identifiers, visualize asset locations on satellite or topographic maps, and receive turn-by-turn directions to sites that may not have street addresses.

What good looks like:

• Search by LSD, township coordinates,, or internal asset IDs
• Layered map views showing pipeline routes, facility boundaries, and equipment locations
• Filtering by asset type, inspection status, risk rating, or custom attributes
• Shareable location links for coordinating multi-crew operations
• Offline map caching for areas with poor connectivity
• Integration with existing GIS data sources

Cenozon in Practice

FIND+ offers interactive GIS mapping for field teams with powerful filtering by asset attributes, inspection history, and risk indicators. Teams can search by LSD or internal IDs, view assets on satellite imagery, and share precise locations with colleagues. FINDpro builds on this foundation by providing visibility into all of your assets as well as your inspections.

3. Digital Work Orders & Customizable Forms

Why It Matters

Paper-based inspection forms and work orders create bottlenecks at every stage. Field technicians struggle with illegible handwriting, forgotten signatures, and missing required fields. Supervisors can’t see job status until paperwork physically returns to the office. Compliance teams waste hours reconstructing audit trails from incomplete documentation.

Digital work orders with customizable forms eliminate these issues. Conditional logic ensures technicians complete every required field based on asset type, work classification, or inspection results. Mandatory photo attachments, GPS stamps, and e-signatures create defensible records.

What good looks like:

• Customizable form templates for Standard Operating Procedures (SOPs), Method of Procedure (MOPs), Job Safety Analyses (JSAs), permits-to-work, and inspection checklists
• Conditional logic that shows/hides fields based on previous answers
• Required field validation that prevents incomplete submissions
• Multi-media attachments (photos, videos, PDFs) linked directly to workflows (aka digital forms)

4. Field-to-Office Data Sync & Real-Time Visibility

The gap between field execution and office awareness creates operational blind spots. Without field-to-office data sync, supervisors cannot prioritize or duplicate efforts by sending multiple crews to the same location, and executives lack the real-time visibility needed for accurate reporting to stakeholders.

Real-time sync (or near-real-time when connectivity allows) ensures that completed inspections, discovered anomalies, and safety incidents flow immediately to office dashboards.

Cenozon in Practice

FINDpro shares real-time digital data between field crews and office personnel. As technicians complete inspections or update asset status in FINDpro, changes sync to cloud dashboards that summarize key indicators—inspection completion rates, anomaly counts, technician productivity, and SLA compliance.

5. Integrations with Computer Maintenance Management Systems (CMMS) , Pipeline Integrity Systems and other applications

Data silos are expensive. When field service data lives in one system,, GIS records in another, and integrity assessments in a third, your team wastes hours reconciling information and misses patterns that span multiple data sources.

GIS, and Enterprise Resource Planning (ERP) integrations create a single source of truth. Field inspection results automatically update asset records in your GIS. Most importantly, field data integrates with pipeline integrity risk management systems so that inspection findings, ILI results, and maintenance history all inform your risk models and regulatory reports.

Cenozon in Practice

Cenozon’s pipeline integrity risk management (PIRM) platform integrates with Production systems, GIS data sources, ERP platforms, and field data capture tools. Organizations using FIND and FINDpro alongside PIRM gain unified workflows where field inspection data automatically feeds integrity risk models, ILI findings trigger targeted field investigations, and all information rolls up into comprehensive regulatory reports.

6. Compliance, Safety, and Traceable Records

When PHMSA or state regulators request documentation, you need to produce complete, defensible records quickly. Paper-based systems create compliance risk through lost documents, missing signatures, and unverifiable timestamps. Digital systems with weak audit trail capabilities aren’t much better if you can’t prove when, where, and by whom work was completed.

Strong field service management software treats compliance as a core capability, not an afterthought. Every inspection, form entry, and status change generates a timestamped record that identifies the user, captures GPS coordinates, and stores the original and modified values.

Cenozon in Practice

FINDpro digitizes inspections and documentation with built-in compliance features. Every field entry includes GPS stamps, user identification, and device timestamps. Cenozon’s PIRM and ILI data management modules provide enterprise-grade auditability for pipeline integrity programs.

7. Reporting & Analytics Readiness

Field service data is valuable only when you can analyze it. Basic reporting shows technician productivity, job completion rates, and mean time to repair (MTTR). Advanced analytics identify patterns—which crews consistently miss inspection deadlines, which asset types generate the most emergency calls, which geographic areas have rising anomaly trends.

The best field service management software provides immediate value through configurable dashboards while offering a clear upgrade path to predictive analytics.

Cenozon in Practice

FIND dashboards summarize key indicators for field operations—inspection completion rates by crew, anomaly trends by asset type, and geographic heat maps showing where field activity concentrates. For organizations requiring deeper analysis, Cenozon’s analytics stack (including InSight for ILI data management) demonstrates the upgrade path to advanced risk modeling, predictive integrity assessments, and data-driven optimization of inspection schedules.

Build vs. Buy & Total Cost of Ownership

Some organizations consider building custom field service tools in-house. Before committing to this path, account for the full TCO:

Upfront costs:

Software licenses, ruggedized mobile devices, infrastructure setup, data migration from existing systems.

Ongoing costs:

User training, mobile data plans, cloud hosting, software maintenance, security patches, and feature development to keep pace with evolving operational needs.

Hidden costs:

Opportunity cost of internal IT resources focused on maintaining custom tools instead of core business initiatives, compliance risk during transition periods, and productivity loss during extended deployment timelines.

Buyer’s Checklist: 12 Must-Haves for Oil & Gas FSM

Use this checklist when evaluating field service management software for your operations:

1. Full offline functionality — forms, media capture, signatures, and GPS work without connectivity
2. GIS mapping with LSD/township search, asset filtering, and shareable locations
3. Customizable digital forms — SOPs, MOPs, JSAs, permits with conditional logic and required fields
4. Automatic field-to-office sync with configurable dashboards for different roles
5. Integration capabilities — REST APIs, webhooks, and pre-built connectors for automated integrations
6. Immutable audit trails with GPS stamps, user identification, and timestamp verification
7. Role-based access controls ensuring field crews, supervisors, and executives see appropriate data
8. Mobile app performance — fast launch times, battery efficiency, and works on standard rugged devices
9. Reporting and analytics — out-of-box KPI dashboards plus export for advanced analysis
10. Vendor support for oil & gas — demonstrated experience with pipeline integrity, regulations (CSA & PHEMSA), and industry standard processes 
11. Scalability — system performance with thousands of assets and years of historical data
12. Clear pricing model — transparent licensing, no surprise charges for essential features

What Great Looks Like: A Day in the Life

It’s 6:30 AM when David pulls up to Pipeline Station 47-B, forty miles from the nearest town. He’s here to complete a quarterly integrity inspection—a multi-page checklist with photos, measurements, and documentation that must be filed.

David taps FINDpro on his tablet. The app already queued today’s assignments while he had WiFi at the office. He opens the Workflow, photographs the assessment site, and completes the digital form—all while her phone shows ‘No Service’ at the top of the screen.

During the inspection, he discovers minor corrosion on a valve flange. He captures photos with automatic GPS stamps, marks the anomaly severity using drop-down options that match her company’s integrity management process, and adds a note recommending follow-up in 90 days. The entire inspection takes 45 minutes. He signs digitally and moves to the next site.

Three hours later, David stops at a roadside cafe for lunch. When her device reconnects to WiFi, FINDpro automatically syncs all morning inspections to the cloud. Back at the office, his supervisor sees the completed work appear on his dashboard in real-time.

When the inspector from the state regulatory agency requests documentation of Station 47-B’s inspection history three months later, the compliance team produces complete records—with GPS verification, timestamps, photos, and supervisor sign-offs—in under five minutes.

Paper vs. Digital Work Orders: The Reality

Choosing the right field service management software for oil and gas operations isn’t about finding the cheapest option or the one with the most features. It’s about finding the platform that works in your operational reality—remote locations, compliance pressure, distributed teams, and the continuous need to prove work was done correctly.

The seven features outlined above represent the foundation of effective FSM for pipeline integrity, facility maintenance, and well site operations. Evaluate platforms against this framework, test them with your actual workflows in your actual field environments, and choose vendors who demonstrate expertise in oil and gas operations.

Experience the Difference: Try FIND+ Today

Ready to see how modern field service management software handles the unique challenges of oil and gas operations? Start with FIND+, Cenozon’s free web-based GIS platform for asset mapping, location search, and route planning.

When you’re ready to add offline mobile workflows, digital inspections, and comprehensive field-to-office sync, book a FINDpro demo to see the complete solution in action.

Visit: cenozon.com/solutions/find/

Contact: cenozon.com/contact

The post Field Service Management Software for Oil & Gas: 7 Crucial Features to Look Out For [Updated for 2026] appeared first on Cenozon.

In oil and gas, external corrosion is one of the most persistent threats to safe, reliable operations. It  impacts pipelines, tanks, refineries, and offshore structures, shortening asset life,  increasing maintenance costs, and creating potential safety and environmental risks. 

That’s why Cathodic Protection (CP) has become a vital component of corrosion control  programs. When combined with coatings, CP helps operators defend critical infrastructure  against everything from acidic soils to saltwater offshore environments. 

How Cathodic Protection Works in Oil & Gas Pipelines 

Cathodic protection prevents corrosion by making a steel asset (like a pipeline or tank) act  as the cathode of an electrochemical cell, effectively stopping metal loss at the steel  surface and shifting it elsewhere. 

There are two main methods used across the industry: 

1. Sacrificial Anode (Galvanic) CP 

– Uses reactive metals such as zinc, aluminum, or magnesium that corrode in place  of steel. 

– Simple, no external power required 

– Well-suited for smaller or buried assets 

– Requires periodic anode replacement 

2. Impressed Current CP (ICCP) 

– Uses an external DC power source with inert anodes like mixed metal oxide or  graphite. 

– Effective for long-distance pipelines, refineries, or offshore facilities – Provides longer service life and scalability 

– Requires regular monitoring and power supply maintenance

– Ongoing monitoring for testing for acceptable application

Benefits Of Cathodic Protection

Implementing cathodic protection in oil and gas operations delivers measurable operational and financial advantages. By proactively addressing corrosion risks, companies can achieve higher asset uptime and reduce unexpected maintenance expenditures. CP enhances the overall reliability of infrastructure, supporting continuous energy transport and storage while safeguarding against environmental hazards. The system’s adaptability allows it to complement a range of materials and structural designs, ensuring tailored protection for both legacy and new installations. Integrating advanced monitoring tools with CP empowers operators to make data-driven maintenance decisions, optimize resource allocation, and extend the leveraging predictive analytics within CP management helps identify potential weaknesses before they escalate into costly failures, improving safety and operational efficiency. From regulatory compliance to operational sustainability, cathodic protection acts as a strategic solution that maximizes ROI while reinforcing confidence in infrastructure performance. Companies that prioritize CP benefit not only from reduced repair costs but also from improved resilience, energy efficiency, and environmental stewardship across their oil and gas networks.

Applications of CP in Oil & Gas Operations 

Cathodic protection is applied across the full value chain: 

– Pipelines (buried & subsea): CP + coatings reduce external corrosion; system type  depends on environment and scale. 

– Storage Tanks: Underground tanks often rely on sacrificial anodes; above-ground  tanks lean toward ICCP. 

– Offshore Platforms & Subsea Structures: ICCP dominates in marine environments,  sometimes with galvanic backups. 

– Refineries: ICCP provides reliable protection over large areas exposed to aggressive  conditions. 

Monitoring & Maintenance in the Digital Era

Cathodic Protection systems are not “set and forget.” They require regular monitoring to ensure assets  remain within protective potential ranges (e.g., the -850-mV criterion recommended by  NACE/AMPP standards). 

Key monitoring activities include: 

– Galvanic CP: Inspect and replace anodes at intervals. 

– ICCP: Verify rectifier output, anode performance, and current distribution. – Remote Monitoring: Deliver real-time insight, especially for remote pipelines and  offshore platforms. 

This is where Cenozon’s pipeline integrity software adds value. By centralizing CP data into  a single platform, operators can: 

• Track structure-to-electrode readings against compliance standards (CSA Z662, PHMSA).
  
• Automate regulatory reporting.
  
• Spot emerging risks through trend analysis. Our ACE connectivity model further enhances this by providing a clear understanding of asset connectivity and how CP is associated with each asset, increasing the value and accuracy of trend analytics.
  
• Streamline workflows by eliminating spreadsheets and manual reporting.

Special Challenge: AC Interference and Coating Shielding

CP systems can face challenges from AC interference or issues related to coating shielding, both of which can impact the effectiveness of corrosion protection.

• AC Interference: Electrical currents from nearby AC power lines or industrial equipment can induce unwanted voltages on pipelines. This interference can cause unexpected voltage fluctuations, leading to inaccurate CP readings and potential over- or under-protection of assets.
• Coating Shielding: Imperfections or variations in pipeline coatings can shield areas from CP currents, preventing proper protection. This can result in localized corrosion, noisy or inconsistent monitoring data, and challenges in accurately assessing pipeline integrity.

Understanding and mitigating these challenges is critical for maintaining effective corrosion control and ensuring reliable trend analysis in CP systems.

Ways to Mitigate the Impact 

AC interference and coating shielding can impact CP system performance, but operators can take several steps to address these challenges. Leveraging Cenozon’s ACE connectivity model allows anomalies to be traced back to specific assets, locations, pipelines, and the network as a whole, providing a holistic view for prioritization and monitoring.

Key mitigation strategies include:

• Automated CP controllers that adjust in real time
  
• High-resolution remote monitoring for early detection of anomalies
  
• Bonding and grounding strategies to manage interference
  
• Event-based inspections to target potential problem areas
  

By combining these strategies with software-enabled monitoring, operators can correlate anomalies with network context, take corrective action quickly, and ensure CP performance remains reliable.

Why Cathodic Protection Still Matters 

Cathodic protection remains one of the most reliable defenses against external corrosion in oil and  gas. But today, the real differentiator comes from how cathodic protection is managed. 

By combining proven CP engineering with digital oversight through Cenozon’s integrity  management software, operators can: 

– Extend asset life and reduce replacement costs 

– Minimize downtime and safety risks 

– Stay ahead of regulatory compliance requirements 

– Make smarter, data-driven integrity decisions 

It’s not just corrosion control, it’s a long-term investment in pipeline reliability, safety, and  efficiency.

FAQs: Cathodic Protection in Oil & Gas 

Q1: What is the most common method of cathodic protection for pipelines? Impressed Current Cathodic Protection (ICCP) is most common for long-distance or high value pipelines due to its scalability. 

Q2: How often should CP systems be checked? 

Galvanic systems require periodic anode inspections, while ICCP requires rectifier  checks—best practice is quarterly to continuous monitoring. 

Q3: What role does software play in CP management? 

Software enables real-time monitoring, automated reporting, and trend analysis, helping  operators stay compliant and proactive. 

Further Reading: 

– OilAndGasInfo.ca: Cathodic Protection 

– Trident Energy International: CP Systems 

– AION-Pro: CP in Oil & Gas

The post Cathodic Protection in Oil & Gas: Methods, Benefits and Monitoring Abilities. appeared first on Cenozon.

1. Edge Computing – Edge computing involves processing data closer to the source, rather than sending it to a centralized server for analysis. Edge computing can enable faster response times and more efficient use of network bandwidth. As pipelines become more connected, edge computing is likely to become an increasingly important part of digital twin architectures.
2. Predictive Maintenance – Predictive maintenance involves using advanced analytics and machine learning algorithms to predict when equipment is likely to fail. This can help operators to schedule maintenance proactively, reducing downtime and increasing asset reliability. As digital twins become more sophisticated, they are likely to incorporate more advanced predictive maintenance capabilities.
3. Digital Twins for Networks – Digital twins have traditionally focused on individual assets, such as pipelines or wells. However, as the oil and gas industry becomes more interconnected, there is growing interest in creating digital twins for entire networks. These digital twins can provide a more comprehensive view of the entire system, enabling operators to optimize performance across multiple assets.
4. Digital Twins for Sustainability – As the energy industry transitions to a low-carbon future, there is growing interest in creating digital twins that incorporate sustainability metrics. For example, a digital twin could be used to optimize the placement of wind turbines or solar panels in a pipeline network, maximizing energy production while minimizing environmental impact.

Overall, the next evolution of a digital twin for pipelines is likely to involve a range of advancements that enable more sophisticated monitoring, prediction, and optimization of pipeline assets. These advancements will enable operators to achieve higher levels of performance, reliability, and efficiency, while also supporting the industry’s transition to a more sustainable future.

Benefits of Digital Twins for Networks

There are many statistics that demonstrate the economic benefits of using digital twins for networks in the oil and gas industry. Here are a few examples:

1. Reduced Downtime – According to a study by Accenture, digital twins can reduce unplanned downtime by up to 20%. This can result in significant cost savings, as downtime can cost oil and gas companies up to $1 million per day.
2. Increased Asset Utilization – Digital twins can also help oil and gas companies to increase the utilization of their assets. A study by GE Digital found that digital twins can increase asset utilization rates by up to 5%.
3. Improved Safety and Environmental Performance – Digital twins can also support improved safety and environmental performance, which can help to avoid costly accidents and regulatory fines. According to a study by McKinsey, digital twins can reduce the likelihood of safety incidents by up to 25%.
4. Cost Savings – Digital twins can also deliver significant cost savings for oil and gas companies. According to a study by the Boston Consulting Group, digital twins can deliver cost savings of up to 20% for asset-intensive industries.

Overall, the economic benefits of using digital twins for networks in the oil and gas industry are significant. By reducing downtime, increasing asset utilization rates, improving safety and environmental performance, and delivering cost savings, digital twins can help oil and gas companies to improve their bottom line and remain competitive in a challenging market.

Find out more about how Cenozon is exploring digital twin technology.

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This rule was developed in response to catastrophic failures, including the 2010 Marshall, Michigan incident, where over 843,000 gallons of crude oil leaked for 17 hours, and the 2010 San Bruno, California explosion, which killed eight people and exposed the consequences of a delayed 90+ minute shutdown. These tragedies underscored the need for faster response to ruptures and stronger regulatory controls. 

This new regulation presents both a challenge and a chance to modernize operations through effective use of technology and stronger safety practices.

The PHMSA RMV Rule

The RMV Rule applies to pipelines with diameters of 6 inches or greater and requires that new construction or full replacements include automatic shut-off valves (ASVs), remote control valves (RCVs), or approved equivalent technologies (AETs). Effective April 10, 2023, it applies to Class 3 and 4 locations and other areas PHSMA considers high risk. Key requirements include:

• 30-minute maximum closure time following rupture identification.  

• Real-time telemetry and leak detection integration.

• Annual drill performance documentation.  

• Direct notification to 911 emergency call centers.  

• Post incident analysis and 90-day summary for RMV-related events, with sign-off by a senior executive.

The rule is reshaping how operators manage compliance at scale, particularly in pipeline-heavy states like Texas. 

Texas Pipeline Landscape: Post 2023 

Texas, with approximately 125,000 miles of gathering and transmission pipelines 6 inches or greater in diameter, is uniquely affected. With a surge in new natural gas development, many of these projects will now need to incorporate RMV technology. Some of the most prominent projects include:

• Traverse Pipeline (WhiteWater Group) – A 36-inch natural gas line connecting Houston’s Katy-area pipelines to the Agua Dulce hub (announced April 2025).  

• DeLa Express Pipeline (Moss Lake Partners) – A 690-mile pipeline from west Odessa to Lake Charles, Louisiana (in development).

• Rio Bravo Pipeline Project (Enbridge) – A 137-mile pipeline supplying Rio Grande LNG, with construction starting in 2025.  

How Cenozon Supports RMV Compliance

1. RMV Readiness and Risk-Based Prioritization 

Cenozon helps operators geospatially identify RMV-affected segments using class location data, HCA/MCAs, and asset schedules. This allows for optimized valve placement and alignment with PHMSA’s risk-based guidelines. 

2. Valve Response Validation and Telemetry Logging

Through real-time telemetry integration, Cenozon enables centralized tracking of valve performance and closure-timing, which is critical for validating the 30-minute shutdown requirement and improving response management.

3. Documentation and Executive Sign-Off

PHMSA requires all failure investigations, emergency reviews, and corrective actions to be documented and signed by a senior executive. Cenozon automates this process, delivering compliant, audit-ready records – including the 90-day post failure summary – that are maintained throughout the pipeline’s lifecycle.

4. AET and Equivalency Submissions

If a pipeline segment uses alternative technologies (e.g. check valves, advanced sensors), Cenozon simplifies the preparation of performance justifications for PHMSA review, reducing delays and minimizing risk of non-compliance. 

5. Scope Clarification

The rule was initially intended for Type A gas gathering pipelines (those operating at 20% SMYS or more in Class 2-4 areas) but recent court rulings have overturned those provisions. Cenozon continues to monitor these legal developments and adjusts accordingly.

Beyond RMVs

Cenozon’s capabilities go far beyond valve compliance, including:

• Automated class location tracking with MOAP exceedance alerts.  

• Geohazard data integration with satellite overlays and risk scoring.

• Regulatory dashboards to monitor district-wide compliance.  

• Off-line capable mobile tools (like FIND+ and FINDpro) for field inspections, repairs, and form-based reporting.

Built with PHSMA in mind, Cenozon helps operators stay organized, audit-ready, and aligned with regulatory expectations. The platform also adheres to ISO/IEC 27001:2022 Information Security Management Systems standards, ensuring sensitive data remains secure. 

A Trusted Partner in Compliance and Security

Cenozon delivers more than software – we help pipeline operators meet regulatory demands with confidence. Our ISO/IEC 27001:2022 certification reflects our commitment to secure data practices, giving operators peace of mind.

Navigate Tightening Pipeline Regulations in Texas with Scalable Compliance Solutions from Cenozon

As pipeline regulations tighten, operators need scalable solutions built with compliance in mind.  This is especially true in states like Texas, where pipeline development is being closely monitored by heightened regulatory practices.

Cenozon brings together industry knowledge and next-generation technology to keep operators ahead of change. From real-time data insights to automated compliance tracking, we enable safe, more efficient, and fully compliant pipeline operations.

Request a Demo

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Cenozon’s PIRM leverages AI to move beyond static risk models, enabling dynamic, data-driven integrity management. Through machine learning, PIRM continuously refines risk assessments by correlating historical failure data, geospatial variables, operational metrics, and inspection results. This allows for precise threat identification and prioritization, especially in complex pipeline networks where traditional rule-based systems fall short. 

Large Language Model (LLM) integration allows technical teams to question unstructured datasets, accelerate reporting, and automate root cause analysis. These models also support the optimization of inspection intervals, maintenance schedules, and compliance workflows based on predicted degradation patterns.  

The latest GIS enhancements within the PIRM application redefine how pipeline operators visualize, manage, and act on spatial and operational data. These upgrades go beyond improved mapping; they deliver a more intelligent, responsive system that accelerates decision-making, enhances compliance, and integrates seamlessly with predictive analytics. With artificial intelligence-driven insight, immersive 2D/3D visualization, and granular data control, PIRM empowers operators to unify asset intelligence across complex networks. 

Explore the Feature Highlights Below:  

Core Navigation  

• High-performance map interaction: Zoom, scroll, and pan fluidly from regional to asset-level views.  

• 2D/3D Views: Instantly switch between 2D and 3D for immersive spatial context. 

• Asset Selection: Access specifications, status, and compliance, data directly from the map. 

Data Management  

• Print & Export: Generate high-resolution maps and reports (300-1200 DPI).   

• Draw and Markup Tools: Annotate and export custom overlays in GeoJSON or Shapefile formats. 

• Advanced Search: Locate pipelines, wells, and facilities with global search and filter controls.   

• Data Tables: View, filter, and bulk-edit asset data with export support.  

• Dynamic Layers: Add and update custom data layers in real-time.  

• Layer Control & Legend: Manage 50+ categories via interactive legend.  

Oil & Gas Infrastructure 

• Pipelines Management: Visualize lines with metadata including status, operator, and substance.  

• Wells & Facilities: Track UWI-tagged assets with precise location and operational data. 

Advanced Analytics  

• Risk Profile Analysis: Visual overlays highlight high-risk zones. 

• No Flow Monitoring: Flag inactive segments across user-defined time intervals.  

• Composition Analysis: Monitor fluid composition for blending and compliance insight.  

Regulatory Compliance  

• Pipeline Centerline Creation: Draw survey-grade centerlines aligned with AER standards.  

• Regulatory Export Compliance: Generate AER-compliant files for faster approvals. 

• Application Support: Automate map and spatial data outputs for new route submissions.  

• Incidents Management: Visualize and track incidents to enhance emergency readiness.  

• In-Line Inspections: Integrate inspection data for maintenance and compliance planning.  

• Environmental & Cultural Mapping: Identify wetlands, wildlife zones, Indigenous lands, and urban areas for permitting alignment.  

• Landslide Susceptibility: Model terrain risk zones for improved planning.  

Infrastructure Integration 

• Transportation Networks: Overlay roads, bridges,and rails for logistics and emergency planning.  

• Hydrographic Systems: Use multi-scale water mapping for crossings and flood risk.  

• Survey Systems: Supports Dominion Land Survey (DLS), National Topographic Map Numbering System (NTS), and Public Land Survey System (PLSS) for precise boundary compliance.  

• 3D Elevation Model: Leverage 2m-resolution terrain for slope, drainage, and elevation analysis.  

Basemap & Visualization  

• Satellite Imagery: Access high-res aerial photos for site verification and change detection.  

• Basemap Options: Toggle between terrain, street, and custom views.  

• Custom Client Layers: Integrate proprietary or LiDAR datasets for tailored analysis.    

Mapping a Safer Future, Together  

These GIS enhancements mark a change in pipeline integrity management, features in performance architecture, and operational reach. The new engine delivers instantaneous map rendering and supports unlimited users, enabling full team collaboration without performance limitations. All updates are provided as a complimentary upgrade to current PIRM users, underscoring Cenozon’s commitment to continuous innovation and client value.  

The enhanced system also enables deeper integration across asset workflows, bridging spatial, regulatory, and operational data into a unified decision-making framework. 

PIRM is the first Cenozon application to feature these enhancements, with rollout to other apps like FIND coming soon.   

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One of the key issues in pipeline integrity management is effectively adjusting corrosion

mitigation measures in response to changes in operating conditions. An international energy company was running a 38-well project in Alberta, with conditions as listed below.

• H2S: 3 with trace H2S (>0.01%)
• Chloride: 5,500 ppm
• CO2: 2.5%
• Pressure and Temperature: 500KPA, 8°C
• Production: 300 E3M3/d Gas, 8 M3/d Water
• History: No internal and external failures recorded since 1960

Cenozon’s Pipeline Integrity Risk Manager (PIRM) software was used to optimize the corrosion chemical treatment program, as PIRM allows users greater visibility into their pipeline environments.

Chemical Treatment Optimization Made Easy With PIRM

With a comprehensive understanding of existing conditions at each well, a number of changes to the chemical program were recommended based on the PIRM built-in mitigation matrix.

Saving Time and Saving Money

With PIRM, the company realized the benefits of optimizing their pipeline internal corrosion mitigation practices. Key features of the software include:

• Data access to facility (well and pipeline) operating characteristics
• Corrosion mitigation best practice (NACE recommended)
• Automated comparison between existing mitigation and best practice
• Notification enabling prompts for action.

As a result of the changes made, the existing chemical treatment schedule was shown to be in excess of requirements. The company realized an 80% savings in their chemical program over a 3-year period, totaling over $500,000.

Knowing your system from the inside out. Take Control.

PIRM implementation resulted in substantial savings at the Alberta well project, however, savings are just part of the benefit. The company also gained a much greater degree of visibility into the changing pipeline environment at each well and had the tools they needed to optimize their own chemical program and take control of their pipeline management practices.

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Incident reduction is a critical goal in oil and gas. Successfully monitoring and maintaining pipeline systems involves the consideration of numerous risk factors. Understanding these factors means informed decisions and improved outcomes in the face of aging infrastructure.

A major North American oil & gas production company set out to streamline their pipeline risk assessment and management program and decrease the manual workload. They wanted a more efficient process that allowed them to thoroughly understand their pipeline system and that assisted in the identification of risk areas.

PIRM is a Fully Supported, Real-Time, Low-Cost, Simple Solution

In 2014 the company implemented Cenozon’s Pipeline Integrity Risk Manager (PIRM) software. The first steps in the PIRM implementation were to map connectivity and input risk mitigation parameters. Their technical leads, in conjunction with industry-trained support from the Calgary based Cenozon team, configured the software such that it was optimised for conditions and risk tolerance.

An Integrity Specialist with the company says the decision to go with Cenozon was based on “PIRM’s instantaneous, dynamic approach to managing assets. When you make a change to connectivity the flow dynamics and pipeline are immediately updated, as is the risk assessment.”

PIRM gives the company a new level of control. They maintain the system on their own, enabling real-time operations data updates and keeping the annual costs low. They use the software to search and navigate the from general information, to a schematic map, to a topographical map, and to understand immediately how one asset impacts another.

Fewer Incidents, Greater Savings

The two-year average (2013-2014) incident rate related to corrosion for companies using PIRM for 5 years or more is 47% below the industry norm. While reducing the incidents is critical, another key benefit is cost reduction.

The industry average pipeline incident cost is over $150,000 with costs upward of $1,000,000 per incident not uncommon. With over 9,000 pipelines, the company projected efficiency savings per risk assessment – based on an estimates manual risk assessment cost of $150/hr at 2hrs/segment – is $2,700,000.

Don’t Take the Risk. Take Control.

With PIRM, the company greatly improved its ability to mange pipeline assets through a new level of insight into their system. The ability to minimize risk, reduce the chance of failure and realize substantial savings through more efficient operations are key to pipeline management.

Pipeline failures can be catastrophic, but they can be avoided. With an ageing pipeline infrastructure, it is more important than ever to thoroughly understand the ever-changing pipeline environment, mitigate risk, and take control.

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The Challenges of Water for Oil and Gas Operators

Bodies of water present unique challenges and responsibilities for a pipeline operator. The terrain of pipeline water crossings ranges from farmland to mountains and the watercourses vary from slow-moving creeks to fast-flowing rivers- all with varying depth of coverage requirements. In addition, flooding can increase the likelihood of pipeline failure due to increased exposure, or scour – resulting decreased depth of cover. Extreme weather patterns, such as those recently witnessed in North America, raise flood risk in some areas and drastically change depth of cover. Rivers and streams also change course over time, making water crossings a dynamic environment requiring diligent review and management. Operators are guided by their own pipeline integrity programs as well as federal and provincial regulations and standards in managing pipeline water crossings.

A lack of accurate information can lead to unnecessary inspections, or the wrong type of inspection, which can be costly and ineffective. There has been no easy way for the oil and gas industry to remotely monitor the thousands of water crossings they are responsible for – until now.

Real-time Abnormal Water Flow Event Monitoring

The game-changing technology monitors and automatically notifies operators of abnormal water flow events occurring near their pipelines and facilities – in real-time. The app assists pipeline integrity management teams to identify and manage water-related hazards, whether resulting from river erosion or abnormal stream flow conditions and flooding.

Easy-reference Online Maps with Flow Gauge and Asset Details

The HydroFlow app utilizes data in the form of major and minor water flows, tributaries and sub-drainages, which have been mapped by provincial and federal authorities. This data is combined with historical data, real-time water level and flow data from thousands of existing gauges at hydrometric stations. The app then spatially intersects pipeline data with water flow data, allowing clients to easily associate major or minor flows with pipeline mapping and therefore increase operational efficiency.

Case Study

Client Reviewed Previously Unknown Historical Water Level Trends

The client in this case study was a mid-size oil and gas company with hundreds of pipelines installed over three decades across the province of Alberta. The client engaged Cenozon to conduct a pilot project using Cenozon’s standalone, cloud-based app, HydroFlow.

The client was able quickly review HydroFlow’s of historical data, which showed nearly 100 years of water level trends at the gauges nearest to their pipeline water crossings. It was this historical perspective that, in this case, provided the client with information it otherwise wouldn’t have known existed. As we’ll see, water flow history was useful to the operator in deriving a more accurate risk profile for one pipeline water crossing in particular.

Defined Monthly or Seasonal Thresholds Based on Historical Data

Cenozon set up the HydroFlow mapping for the client’s pipelines within a day, allowing the client to immediately begin associating river and other water crossings with their pipelines based on pipeline license numbers. HydroFlow enabled the client to assign their own risk analysis priorities and set specific thresholds, derived from a combination of data:
• The client’s geo-hazard assessment data
• 3rd party datasets of seasonal or monthly water gauge levels including historical
abnormal flow conditions
• Geographic location
• Environmental and regulatory factors
• The age and depth (of cover) of the pipeline

HydroFlow Helped Client Identify Potentially Vulnerable Water Crossing

In this case, the water crossing ultimately identified by the client as being potentially vulnerable had been installed in 1990, and the operator had performed all required inspections, the last of which occurred in 2009. When the client reviewed the data on the HydroFlow app, they were able to see that there had been abnormally large flow occurrences on nine occasions over the last two decades with a one-in-a-hundred-year scale event in 2010, a year after the last inspection.

As a result of the HydroFlow-generated data, the client knew a geo-technical assessment was required for the water crossing in question and determined that, although it would take another one-in-a-hundred-year event to expose the pipeline, their parameters for optimal safety and efficiency require addressing this risk in the near future.

Notification if Threshold Exceeded

Upon review of HydroFlow’s data and its own geographical assessment relating to the vulnerable water crossing, the client was able to set their thresholds for that crossing to ensure a pro-active and preventative response before another potentially significant occurrence of abnormal water flow. If conditions for that crossing exceed the specified acceptable range, client will receive an automatic notification, enabling the operator’s integrity and safety teams to quickly assess the situation and dispatch appropriate resources when and where they are required.

Better Understanding of Risk = Cost Savings

HydroFlow was developed as part of Cenozon’s existing Geo-Hazards Module within its Pipeline Integrity Risk (PIRM) Software, and it easily integrates with third-party databases. The app provides valuable information for the assessment of risk by operators through a user friendly interface as well as delivering the confidence of knowing pipeline water crossings are being monitored on a timely basis. Real-time data streams provide operators with the information to determine when an inspection is required, what level of inspection is required, and ultimately when a costly inspection or geotechnical assessment may be unnecessary. HydroFlow makes it easier for oil and gas operators to obtain the right data and effectively achieve optimal operational efficiency, safety and compliance.

The post Hydroflow in Action: Real Cost Savings for Clients appeared first on Cenozon.

A growing oil and gas company with a significant asset portfolio in Alberta and Saskatchewan and a strong focus on financial metrics was seeking a calibration management software that could be commonly deployed over 600 sites. The internal, paper-based system the energy producer had in place was not accessible to all relevant departments and did not provide visibility and traceability of all assets at all times.

Reliability and Accuracy

Metering and calibration are essential in the oil and gas industry to ensure the precise volume of measurements at the sample points in shared wells and plants. The Alberta Energy Regulator sets out compliance and audit requirements that all producers must follow. However, scheduling, validating and distributing gas and liquid analyses is a logistically challenging and time-consuming exercise that has traditionally utilized considerable resources. Reliable metering calibration and analysis assists with legislative requirements, saves time and manpower and prevents costly inaccuracies, which is why this client chose to partner with Cenozon for its sampling and analysis process.

Instant Access to Calibration & Analysis

One of the client’s Instrumentation Engineering Technologists pointed out that “before we started using Measurement Manager a year and a half ago, we didn’t have a common calibration format. The diverse sites in the company manually collected samples and kept track using an internal system of spreadsheets and paper records. If anyone needed the information, we relied on e-mail. Now the calibration and analysis are automatic and instantly accessible by anyone in the company. And we can easily track completion by areas and fields and compare analyses against historical data.”

Saves Time and Manpower

Measurement Manager’s cloud-based software also handles scheduling and flags results with significant variances. One of the plant and battery operators of the client company has found that managing company resources is easier with Cenozon’s scheduling feature. “We’re saving manpower and company resources in a few ways. The scheduler allows us to simply go into Measurement Manager to determine how many calibrations need to happen in that time frame and what the results are. I just have to determine if its trending within our variances and if it is, then I approve it and a record is generated. In addition, we don’t ‘have to spend time pulling
analyses from various records when someone needs them.” Because the subject company didn’t have a previous common calibrating and analysis system, they have found that the software has initiated a standardization of its processes and terminology. According to one of its IE Technologists, “it’s motivated us to become more consistent with our data descriptions. The search function is sophisticated – it allows you to filter
searches based on legal description, person, pending, and many other search terms – but it’s also easy to use and very intuitive.”

Phenomenal Customer Support

Cenozon’s staff are industry experts with decades of experience in oil and gas. This particular client has been very satisfied with the level of in-house support services and training provided to their staff. “The software is easy to learn, but Laurel has been phenomenal in supporting us with any implementation questions that we had,” notes one field operator. As someone who has trained others in his site office on the software, he found it “easy to explain and the trainees picked it up really fast.”

Automatic Reporting

Management of the subject company believe there is another significant way that Measurement Manager could soon save them even more costs and that relates to its automatic reporting function for meters that qualify under the Alberta Energy Regulator’s exemption requirements. “In the past it was not worth the paperwork involved in keeping track, but now it’s another way Measurement Manager can leverage our business by saving costs.

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