Oil and Gas Operations: Equipment and Standards by Segment

The oil and gas industry runs on three segments, and each one runs on different equipment, different failure modes and different governing codes.

Upstream produces hydrocarbons. Midstream moves and stores them. Downstream converts them into products. A reliability engineer at a compressor station and one at a refinery are solving unrelated problems under separate standards.

Those standards are not optional. API inspection codes are cited as recognized and generally accepted good engineering practice under OSHA Process Safety Management, which means they are enforced through audit rather than by direct regulation.

This guide maps each segment to the equipment it depends on, the codes that govern it, and the inspection intervals those codes set.

Significance of the Oil and Gas Industry

The oil and gas industry is central to global energy systems, supplying fuels, feedstocks, and raw materials that support transportation, power generation, manufacturing, and petrochemicals. Its operational scale spans offshore platforms, remote gas fields, cross-border pipelines, and high-capacity refineries.

Beyond energy supply, oil and gas operations represent some of the most capital-intensive industrial activities in the world. Countries and corporations depend on reliable exploration, production, and processing to maintain economic growth, stabilize energy prices, and ensure national energy security.

Why capital intensity shapes everything downstream of it

A refinery, an LNG train or a long-haul pipeline is a multi-billion-dollar asset with a design life measured in decades. Capital on that scale is only justified by sustained utilization, which makes availability the governing commercial metric rather than throughput alone.

That is why mechanical integrity programmes, inspection intervals and turnaround planning sit at board level in this industry and not in facilities management. Operational efficiency, asset reliability, and project execution directly influence profitability and long-term competitiveness in this sector.

Sectors of the Oil and Gas Sector

The oil and gas sector is divided into three major segments: upstream, midstream, and downstream. Each part connects with the next, forming an integrated chain that spans from resource discovery to end-user consumption.

What changes between them is not only the activity. It is the equipment, the regulatory regime and the dominant risk.

Upstream: Exploration and Production (E&P)

The upstream sector focuses on finding and producing crude oil and natural gas. It is the most geographically dispersed segment, with assets frequently located beyond grid and road infrastructure.

That dispersion is the defining operational constraint. An upstream facility must generate its own power, maintain its own equipment and operate with limited on-site personnel, which makes reliability engineering and remote monitoring disproportionately valuable.

Activities here include exploration, drilling and production.

Exploration

Oil companies search for potential reserves in gas fields, offshore basins, and shale plays. Geologists and geophysicists use seismic imaging to identify subsurface formations that may hold hydrocarbons.

Seismic imaging sends acoustic energy into the ground and interprets the reflections to build a subsurface model. It identifies structures capable of trapping hydrocarbons; it does not confirm that hydrocarbons are present or recoverable.

Exploration is a geoscience discipline performed by specialist contractors and the operator's own subsurface teams. Reserve estimates arising from it are reported under JORC or NI 43-101 equivalents for oil and gas, and require a qualified person to sign them.

Drilling

Once exploration confirms a viable prospect, operators deploy a drilling rig to reach the formation. Technologies such as hydraulic fracturing create fractures in low-permeability rock, which is what made shale reserves economically viable.

Drilling is performed by drilling contractors under the operator's direction, supported by a specialist service sector covering mud, cementing, directional services, wireline and completions.

Where the power comes from

Every rig and every drilling pad needs power before it needs anything else. Remote sites run on diesel generation, on gas-fired generation using produced gas, or increasingly on grid connection where one is reachable.

That generation is a separate procurement from the drilling contract, and it is frequently the item that determines whether a site can operate on schedule.

Production

Wells bring hydrocarbons to the surface, where production equipment separates oil, gas and water and controls flow and pressure.

The separator is the central piece of equipment. It uses gravity and residence time to split the well stream into phases, and its sizing determines how much liquid carryover reaches downstream equipment.

Safety instrumented systems prevent overpressure, loss of containment and blowouts. IEC 61511 governs functional safety for the process industries and defines safety integrity levels, or SIL, which express the required risk reduction for each protective function. API RP 14C covers safety system analysis for offshore production facilities.

The reliability problem specific to production

Rotating equipment at a production facility runs continuously, often unattended, in a dusty or corrosive environment, far from a workshop. Compressors, pumps and prime movers accumulate hours faster than they accumulate attention.

Condition monitoring earns more here than almost anywhere else in the value chain, because the alternative is a site visit after failure rather than before it.

Midstream: Transportation and Storage

Once produced, hydrocarbons move through the midstream network. Midstream operators manage the logistics of transporting crude oil and natural gas to refineries and distribution centres, work that depends heavily on the E&P supply chain that keeps oil and gas operations moving.

Midstream is the most heavily regulated segment for containment, because the consequence of a failure is release into the environment rather than loss inside a plant boundary.

Gas processing sits at the start of it, removing water, acid gases and natural gas liquids so the gas meets pipeline specification. A compressor station that receives off-spec gas accumulates damage it was not designed for.

Pipelines

Pipelines move large volumes across long distances, with pumping stations driving liquid lines and compressor stations driving gas lines. They are the lowest-cost transport mode per barrel-mile and the least flexible.

ASME B31.4 governs pipeline transportation systems for liquids and slurries. ASME B31.8 governs gas transmission and distribution piping systems. In the United States, 49 CFR Part 195 covers hazardous liquid pipelines and 49 CFR Part 192 covers natural gas pipelines.

API RP 1130, Computational Pipeline Monitoring for Liquids, governs the software-based leak detection systems that run continuously alongside physical inspection.

The station nobody discusses

A compressor station is a power plant with a compressor attached. Gas turbine or reciprocating engine drivers, electrical distribution, controls and auxiliaries all have to work for the station to pass gas.

Station availability is therefore a rotating equipment and power problem rather than a pipeline problem, and it is where most midstream unplanned downtime originates.

Storage Facilities

Operators store crude oil and refined products to balance supply against demand, buffer production variability and meet commercial obligations.

API 650 is the construction standard for welded atmospheric storage tanks. API 653 governs their inspection, repair, alteration and reconstruction in service, applying to atmospheric or low-pressure tanks operating under 2.5 psi.

API 653 sets a maximum external inspection interval of five years, with internal inspection normally starting from a ten-year baseline and capped at twenty or thirty years depending on release-prevention features such as double bottoms, liners and leak detection.

Internal inspection requires the tank to be emptied and cleaned, and assesses the bottom, shell interior, welds and coatings using ultrasonic thickness testing and magnetic flux leakage floor scanning. A settlement survey is required at ten years or after major repair.

What happens when a tank fails inspection

It comes out of service. Tank capacity is rarely redundant, so an unplanned internal inspection finding removes storage from the system and constrains throughput upstream and downstream of it.

Planning internal inspections against the commercial calendar rather than against the deadline is the difference between a managed outage and a forced one.

Shipping and Trucking

Tankers and trucks move hydrocarbons where pipelines cannot reach, which includes almost all intercontinental movement and most final-mile distribution.

Marine transport carries the large majority of internationally traded crude, because no pipeline crosses an ocean. LNG carriers perform the equivalent function for natural gas, which must be liquefied at roughly minus 162 degrees Celsius to be shipped economically.

Rail and road handle volumes too small or too intermittent for fixed infrastructure, and they are the flexible layer that absorbs disruption when a pipeline or terminal is unavailable.

Efficient midstream infrastructure minimizes bottlenecks and keeps production flowing from remote fields to domestic and global markets.

Downstream: Refining and Distribution

• The downstream segment converts raw hydrocarbons into usable products. Refineries process crude oil into fuels, chemicals and feedstocks through a sequence of separation, conversion and treatment steps.
• Downstream is the most process-safety-intensive segment, operating at high temperature and pressure with large inventories of flammable material inside a confined site boundary.
• Major downstream activities include refining, marketing and petrochemical manufacturing.

Refining

Refineries break crude into jet fuel, heating oil, diesel, gasoline and petrochemical feedstocks through atmospheric distillation, followed by conversion and treating units.

Atmospheric distillation separates crude by boiling point and is the first unit every barrel passes through. Fluid catalytic cracking converts heavy fractions into lighter, higher-value products. Hydrotreating removes Sulphur and nitrogen to meet fuel specifications and protect downstream catalysts.

Each unit depends on heat exchangers, fired heaters, pumps, compressors and a utilities system supplying steam, power, cooling water and instrument air.

Utilities are the single point of failure

• A refinery's utilities system serves every unit on the site. A steam or power interruption does not slow one unit; it trips the complex.
• That is why many refineries run cogeneration, producing both power and process steam on site, and why utilities reliability carries a weight out of proportion to its capital cost.

Marketing

• Refined products reach end users through terminals, distributors and retail networks, with product specification, blending and logistics managed to seasonal and regional requirements.
• The commercial function sits with the operator's downstream organization. The operational layer beneath it is terminal infrastructure: storage tanks under API 653, loading racks, metering and vapor recovery.

Petrochemical Manufacturing

Refinery by-products and natural gas liquids serve as feedstock for plastics, textiles, synthetic rubber and industrial chemicals, produced through steam cracking and downstream polymerization.

A steam cracker is among the most energy-intensive units in the entire value chain, operating furnaces above 800 degrees Celsius with run lengths limited by coke formation on the tubes. See our guide to petrochemical plant operations for the process and reliability detail.

Petrochemical plants operate under the same mechanical integrity regime as refineries, governed by ASME B31.3 for process piping design and API 510, 570 and 653 for in-service inspection of vessels, piping and tanks.

Key Operations Across the Oil and Gas Industry

Each sector involves distinct but interconnected operations. What follows maps the core functions to the equipment and standards that govern them.

Exploration and Development

Seismic surveys identify subsurface formations capable of holding hydrocarbons, interpreted by geoscience specialists against regional geology.

Test wells confirm whether the formation contains recoverable hydrocarbons, and appraisal wells define the extent and characteristics of a discovery before development commitment.

Production facilities are then designed and built to bring the resource online, which is where engineering, procurement and construction management begins and where the power, utilities and rotating equipment scope is set.

Facility design decisions made at this stage determine operating cost for the asset's entire life, including whether the site generates its own power and at what redundancy level.

Drilling Operations

• A drilling rig penetrates to the target formation, with the well construction sequence including casing, cementing and completion.
• Hydraulic fracturing enhances recovery from low-permeability formations by creating fractures held open with proppant, which is what made shale production commercially viable.
• Drilling parameters are monitored continuously to manage well control, optimize rate of penetration and detect problems before they become incidents.
• Drilling is performed by drilling contractors and a specialist oilfield service sector.

Oil and Gas Production

• Production equipment separates crude oil and natural gas from produced water and solids, with separator sizing determining how cleanly the phases split.
• Flow control and pressure maintenance equipment holds the well and gathering system within its operating envelope, with artificial lift applied where reservoir pressure is insufficient.
• Safety instrumented systems prevent leaks, overpressure and blowouts. IEC 61511 governs functional safety for the process industries and defines safety integrity levels, which set the required risk reduction for each protective function.

What determines production availability

Rotating equipment, almost always. Compressors, pumps and prime movers accumulate the operating hours and the failures, and on a remote site the response time to a failure is measured in days rather than hours.

Transportation and Storage

Pipelines, rail and marine transport move hydrocarbons between production, processing and consumption, with pumping and compressor stations providing the motive force.

Storage buffers the system against production variability, demand seasonality and transport interruption, with tank farms governed by API 650 for construction and API 653 for in-service inspection.

In-line inspection tools, known as smart pigs, travel inside the pipeline measuring wall thickness, corrosion and deformation, detecting internal conditions no external survey can see.

API RP 1130 governs computational pipeline monitoring for liquids, the continuous leak detection layer that runs alongside physical inspection under 49 CFR Part 195.

Refining and Processing

Refineries heat, separate and treat hydrocarbons through distillation, conversion and treating units to produce finished fuels and feedstocks.

Mechanical integrity is governed by three API in-service inspection codes, each with its own default intervals.

API 570 sorts piping into classes by the consequence of a leak. Class 1, handling flammable or toxic fluids, requires external inspection at intervals not exceeding five years. Class 2 and Class 3 systems allow a maximum of ten years.

API 570 is the in-service counterpart to ASME B31.3, which is the design and construction code for process piping. Pipeline systems constructed to ASME B31.4 and B31.8 fall outside API 570 scope entirely, which is a distinction operators regularly get wrong.

Risk-based inspection and interval extension

API RP 580 provides the risk-based inspection methodology that can modify intervals across all three codes, replacing fixed calendar intervals with intervals derived from probability and consequence of failure.

An authorized inspector must approve any extension based on documented RBI analysis. Extension is not a decision the operator makes alone, and an undocumented extension is a finding at the next audit.

Turnarounds

A turnaround is a planned total shutdown of a unit or complex for inspection, repair and replacement work that cannot be done online. It is where most inspection findings are addressed and most major rotating equipment work is executed.

Turnaround scope grows between planning and execution, and the discipline that controls cost is scope freeze rather than execution speed.

Distribution and Marketing

• Refined products move from refinery to terminal to end user through pipeline, rail, marine and road, with product specification maintained through blending and additive injection.
• Jet fuel supplies aviation, diesel and gasoline supply transport, and heating oil supplies residential and commercial heating with pronounced seasonal demand.
• Terminal infrastructure is the operational layer: storage under API 653, loading racks, custody transfer metering and vapour recovery systems.
• Custody transfer metering is the point at which ownership and liability change, and its accuracy is contractually and commercially significant rather than merely technical.

Challenges in the Oil and Gas Industry

The oil and gas industry faces four persistent operational challenges, and the regulatory one is enforced through a route many operators underestimate.

API inspection codes are not regulations in themselves. They are cited by OSHA Process Safety Management under 29 CFR 1910.119 and by EPA Risk Management Program rules as recognized and generally accepted good engineering practice.

That means non-compliance is enforced indirectly through PSM audits rather than through direct citation of the API code. A gap in a mechanical integrity programme becomes a PSM finding.

API revises its inspection codes on roughly a five-to-seven-year cycle, with addenda issued in between, so a programme written against a superseded edition drifts out of compliance without anything changing on site.

Insurance and the audit trail

Insurers assess mechanical integrity programmes, inspection records and turnaround discipline when pricing industrial risk. A documented programme with recorded findings and closed actions is underwriting evidence; an undocumented one is a question at renewal.

Outside the United States

OSHA PSM, EPA RMP and the 49 CFR parts are US federal regulation. API and ASME standards are used internationally, and other jurisdictions apply their own process safety regimes, including the Seveso Directive in the European Union and COMAH in the United Kingdom.

Volatile Prices

Crude and product prices move with global supply, demand, inventory levels and geopolitical events, and the swings are large enough to change project economics between sanction and completion.

Operators manage exposure through hedging, portfolio diversification and cost discipline, but the operational consequence is that capital programmes are deferred and restarted on price signals rather than on asset condition.

That creates a specific risk. Deferred maintenance and extended inspection intervals accumulate during low-price periods, and the backlog surfaces as reliability loss later.

Environmental Concerns

Emissions regulation has moved from aspiration to enforceable standard, with methane the dominant focus.

In the United States, 40 CFR Part 60 Subpart OOOOb sets methane standards for crude oil and natural gas facilities constructed, modified or reconstructed after 6 December 2022, with Subpart OOOOc covering existing sources through state plans.

The compliance obligation includes leak detection and repair, associated gas handling and pneumatic controller replacement, and it carries specific detection performance thresholds that determine which monitoring technologies qualify.

Technological Demands

Digital technology in oil and gas rests on a data layer that most operators have to build before any application works.

SCADA, supervisory control and data acquisition, collects and presents field data and issues control commands. A historian stores time-series process data at defined resolution and retention. A computerized maintenance management system, or CMMS, holds the asset register, work orders and maintenance history.

Analytics applications read from all three. The prerequisite is a segmented operational technology network, because connecting field systems to business systems without a security boundary converts an operational problem into a safety one.

ISA/IEC 62443 governs industrial automation and control system security through zones and conduits. For the full implementation sequence and the cybersecurity prerequisites, see our guide to digital oilfield technologies.

Electrification of field operations

Replacing diesel prime movers with grid power, gas-fired generation or renewables with storage reduces fuel cost, maintenance burden and emissions simultaneously. It is the technology on this list with the most direct operating cost effect and it is frequently categorized as a sustainability measure rather than a cost one.

Geopolitical Tensions

• Production, transit and refining capacity are concentrated in regions subject to political instability, and disruption to any of them transmits through global markets within days.
• Operators respond by diversifying supply sources, holding strategic inventory and building redundancy into logistics, each of which carries a working capital cost.
• The operational consequence is that supply chain resilience is a design parameter rather than a procurement preference, particularly for long-lead equipment with limited qualified sources.

The Future of the Oil and Gas Industry

Oil and gas will remain central to the global energy system for decades, while the operating model around it changes substantially.

Demand for crude and natural gas continues to grow in developing economies, aviation has no scaled alternative to jet fuel, and petrochemical feedstock demand is tied to materials consumption rather than to energy policy.

What is changing is how production is run. Operators are investing in methane leak reduction, carbon capture, field electrification and renewable integration at site level, driven by a combination of regulation, cost and investor expectation.

Midstream operators are upgrading infrastructure to reduce fugitive emissions, which under OOOOb and OOOOc is a compliance obligation rather than a voluntary programme. Refiners are investing in lower-carbon fuels and in utilities efficiency, where the emissions reduction and the cost reduction point the same way.

The practical position for an operator is that integrity, emissions and energy efficiency have converged into one programme rather than three.

At the Bottom Line

The oil and gas value chain runs on three segments with different equipment, different codes and different dominant risks.

Upstream is defined by remoteness, which makes site power and rotating equipment reliability the binding constraints. Midstream is defined by containment, governed by ASME B31.4 and B31.8, 49 CFR Parts 192 and 195, API RP 1130 and API 653. Downstream is defined by process safety, governed by ASME B31.3 and the API 510, 570 and 653 in-service inspection codes under an OSHA PSM mechanical integrity programme.

Knowing which segment you operate in tells you which codes apply, which intervals govern your inspection schedule and where your availability risk actually sits.

How Prismecs Can Help You with Oil and Gas Operations?

Prismecs supplies, installs, commissions, operates and maintains power generation, electrical systems and rotating equipment for oil and gas facilities, and provides the supply chain behind them.

Delivered project scope includes eight TM2500 dual-fuel units totaling 260 MW at Birr, Switzerland, online in six months with a new 220 kV interconnection; four TM2500 units totaling 110 MW at Duqm, Oman, kept grid-ready with resident O&M crews, CMMS and parts support; an LM2500XPRESS plant at Miaoli, Taiwan delivered in ten months; and an LM6000 fleet decommissioned in Norway, transported and recommissioned at a new site.

That record is site power and rotating equipment delivery, which is the layer every segment in this article depends on: generation for remote upstream facilities, drivers and electrical systems at compressor and pumping stations, and utilities and rotating equipment at refineries and petrochemical plants.

Capability spans power generation asset services, O&M services for the operating phase, I&C services for electrical systems, instrumentation, controls and SCADA support, EPCM services for project delivery, distributed energy solutions for site power and microgrids, owner's engineering for independent review, supply chain solutions for procurement, and technology and consulting for assessment. Sector context is on the oil and gas page.

One scope boundary worth stating. Prismecs does not perform drilling, well construction, reservoir management or exploration. Those are the domain of drilling contractors, the oilfield service sector and the operator's own subsurface teams. The work here is power, electrical systems, rotating equipment and the supply chain that supports them.

Apply this article's criteria to any proposal, including ours. Ask which segment and which codes the provider actually works under. Ask for their scope boundary in writing. Ask what they do when an inspection finding lands mid-contract. Ask who holds the records at handover.

To discuss site power, rotating equipment support or an operations and maintenance scope, send your facility type and location, connected and peak electrical load, prime mover inventory, and the outcome you need to sales@prismecs.com or call +1 (888) 774-7632.

Frequently Asked Questions

What are upstream, midstream and downstream?

Upstream covers exploration and production of crude oil and natural gas. Midstream covers transportation and storage through pipelines, tankers, trucks and tank farms. Downstream covers refining and distribution, converting hydrocarbons into fuels, chemicals and feedstocks. Each segment runs on different equipment under different governing codes, with different dominant risks: well control upstream, loss of containment midstream, and process safety downstream.

What is the API 653 tank inspection interval?

API 653 sets a maximum external inspection interval of five years, with internal inspection normally starting from a ten-year baseline and capped at twenty or thirty years depending on release-prevention features such as double bottoms, liners and leak detection systems. Internal inspection requires the tank emptied and cleaned, assessing bottom, shell interior, welds and coatings using ultrasonic thickness testing and magnetic flux leakage floor scanning.

What are the API 570 piping inspection intervals?

API 570 sorts piping into classes by the consequence of a leak. Class 1, handling flammable or toxic fluids, requires external inspection at intervals not exceeding five years. Class 2 and Class 3 systems allow a maximum of ten years. Thickness measurement intervals follow the same class logic and are shortened where measured corrosion rates require it.

What is the difference between API 570 and ASME B31.3?

ASME B31.3 is the design and construction code for process piping. API 570 is its in-service counterpart, governing inspection, rating, repair and alteration of piping already in operation. The two apply at different points in the asset life. Pipeline systems constructed to ASME B31.4 or B31.8 fall outside API 570 scope entirely and are governed by their own in-service regimes.

Are API inspection codes legally required?

Not directly, and they are enforced in practice. OSHA Process Safety Management under 29 CFR 1910.119 and EPA Risk Management Program rules cite API inspection standards as recognised and generally accepted good engineering practice, which means non-compliance is enforced indirectly through PSM audits. A gap in a mechanical integrity programme becomes a PSM finding rather than an API citation.

How often are API inspection codes revised?

API revises its inspection codes on roughly a five-to-seven-year cycle, with addenda issued between full editions. A mechanical integrity programme written against a superseded edition drifts out of compliance without anything changing on site, which makes edition tracking a programme requirement rather than an administrative task.

Can inspection intervals be extended?

Yes, through risk-based inspection. API RP 580 provides the methodology that modifies intervals across API 510, 570 and 653, replacing fixed calendar intervals with intervals derived from probability and consequence of failure. An authorized inspector must approve any extension based on documented RBI analysis. An undocumented extension is a finding at the next audit.

Which codes govern pipelines?

ASME B31.4 governs pipeline transportation systems for liquids and slurries, and ASME B31.8 governs gas transmission and distribution piping. In the United States, 49 CFR Part 195 covers hazardous liquid pipelines and 49 CFR Part 192 covers natural gas pipelines. API RP 1130, Computational Pipeline Monitoring for Liquids, governs software-based leak detection running alongside physical in-line inspection.

What is a compressor station and why does it matter?

A compressor station provides the motive force that moves gas through a transmission pipeline, using gas turbine or reciprocating engine drivers with their own electrical distribution, controls and auxiliaries. It is effectively a power plant with a compressor attached, which makes station availability a rotating equipment and power problem. Most midstream unplanned downtime originates there rather than in the pipe itself.

What determines availability at a production facility?

Rotating equipment, in most cases. Compressors, pumps and prime movers accumulate the operating hours and the failures, and on a remote site the response time to a failure is measured in days rather than hours. Condition monitoring earns more at remote production facilities than almost anywhere in the value chain, because the alternative is a site visit after failure rather than before it.

Why are refinery utilities a single point of failure?

Because the utilities system supplies steam, power, cooling water and instrument air to every unit on the site. A steam or power interruption does not slow one unit; it trips the complex. Many refineries run cogeneration producing both power and process steam on site for that reason, and utilities reliability carries a weight out of proportion to its capital cost.

What is a turnaround and what controls its cost?

A planned total shutdown of a unit or complex for inspection, repair and replacement work that cannot be performed online. It is where most inspection findings are addressed and most major rotating equipment work is executed. Turnaround scope grows between planning and execution, and the discipline that controls cost is scope freeze rather than execution speed.

What functional safety standard applies to production facilities?

IEC 61511 governs functional safety for the process industries and defines safety integrity levels, which express the required risk reduction for each protective function. API RP 14C covers safety system analysis and design for offshore production facilities. Together they govern the safety instrumented systems that prevent overpressure, loss of containment and blowouts.

What methane regulation applies to oil and gas facilities?

In the United States, 40 CFR Part 60 Subpart OOOOb sets methane standards for crude oil and natural gas facilities constructed, modified or reconstructed after 6 December 2022, with Subpart OOOOc covering existing sources through state implementation plans. Obligations include leak detection and repair, associated gas handling and pneumatic controller replacement, with specific detection performance thresholds determining which monitoring technologies qualify.