Topic last reviewed: June 2023
Sectors: Upstream
When transporting fluids through a flow system, including flexible or rigid piping/flowline/pipeline, energy is lost. Various factors affect the loss, including heat transfer between flow system and surrounding environment, pressure drop as a function of many parameters (such as distance, pipeline diameter, wall friction, change in altitude, fluid density, viscosity, flow regimes, insulation, change in momentum/direction, metering/restriction orifices), upstream compression, downstream compression, and so on. Energy losses must be met by higher energy inputs from the source (for example, the reservoir in upstream production) or from external equipment (such as heating, compression, pumping, insulation). Flowlines and pipelines are one part of a production, gathering, and transportation system. This Compendium topic discusses minimizing energy loss in flowlines and pipelines, which improves overall system efficiency.
From wellhead to hydrocarbon processing facilities, the system may consume between 0 to 7 per cent of total energy extracted from the reservoir. This is specific to each development’s conditions, such as production type and composition (oil/gas), depth, water separation, pumping/compression, transportation distance, temperature, and flow assurance/integrity requirements. Within the constraints of any development, there are opportunities in design and operations to minimise energy loss. The challenge is to use energy only where and when required, to minimize losses due to friction and the environment.
Design
The Energy efficient design for carbon dioxide reduction info sheet should be consulted when designing a system that includes flowlines and pipelines.
Pipelines, which include flowlines in this document, are built according to design criteria, engineering codes, and standards, to meet project needs. Typical criteria for pipeline and/or network design are:
- System deliverability (ability to transport a defined nominal flow rate) and its hydraulics (pressure drops across the pipeline)
- Requirements to satisfy system integrity management (pigging, minimum flow velocity to avoid solids settling, erosional velocity limitations, liquid management, slugging, and so on) and processing facility capabilities (liquid surge volume, etc.)
- Thermal requirements for safe operating conditions, including minimum temperature (to avoid hydrate/wax formation) and cooldown time (time, after flowline shutdown, before the fluid temperature drops down to the hydrate formation temperature for a given flowline shutdown pressure) required for hydrate management.
In addition to techno-economic aspects, physical and social constraints, and materials and chemicals compatibility, a pipeline route should be reviewed using hydraulic models for energy efficiency, optimal design, and layout of pipeline facilities. Hydraulic models can help establish the required dimension of the pipeline to minimize friction loss and optimize the location of pumps/compressor stations for managing oil and gas transmission efficiently. Any route should undergo steady-state and transient flow simulation studies during the facility design and layout. Selecting the best flow routes, and defining operating envelope using pipeline network analysis, can provide efficient management of pressure drop during transportation.
Best practices for energy efficient design are:
- Minimize energy loss by avoiding elbows.
- Optimize the pipe diameter (a larger diameter will cause less frictional losses but cost more).
- Leverage gravity feed, for example, flowing down a hill to avoid pumping.
- Insulate where needed to minimize line loss for production fluids, but also for boiler feedwater and steam lines. Note that heat loss is higher when running in batch mode or for smaller diameter pipelines.
In upstream developments, transporting full well stream fluids (fluids from the well prior to separation) from the wellhead to a processing facility leads to considerations which affect the energy needs of the system. In many developments, reservoir pressure and temperature provide energy and making the most of that energy is an opportunity to maximize efficiency. Adapting the processing facilities and designing pipeline operations to harness the higher pressure can save power in compression and pumping in the processing facility.
Typical flow assurance challenges, such as multiphase flow, slugging, solids (sand, hydrate, wax, asphaltene, scale) prevention and mitigation, and emulsion formation, may drive the thermal and hydraulic requirements of a flow system, including flowline sizing as well as potential heat and friction loss mitigation. Heated flowlines, pipe-in-pipe or insulation, or a combination, may be required in the design for normal and transient operating scenarios (such as start-up, shut down, ramp up/ramp down, depressurization, and so on). Chemicals and mechanical cleaning (pigging) may also be used to manage the challenges related to flow assurance and system integrity. In addition, field layout optimization, such as connection of multiple nearby wells in a loop or daisy chain, may be employed to meet field development requirements.
Efficient pipeline system design is critical for flow assurance risk management and can significantly reduce the energy required to transport produced oil and gas in the system. Consideration for all operating modes, across the project lifecycle, needs to be included in the design to reduce capital and operating expenditures, to manage a variety of operational conditions, and to minimize costly brownfield modifications to remediate flow assurance issues.
To avoid hydrate or wax formation in the flowlines, the temperature and pressure need to be maintained such that the fluids remain outside the hydrate or wax formation conditions. It is therefore important to have a design with good insulation of these flowlines, to avoid or minimize heating. In many cases, extra heating of the flowlines is required, and a direct electrical heating (DEH) system may be installed. One alternative to heating is hydrate or wax inhibitor injection. Use of such inhibitors may reduce energy consumption but may cause more difficult oil/water separation, contamination of the oil, and difficulty complying with the environmental discharge requirements for produced water. Where hydrate inhibition is made via continuous injection of glycols (Monoethylene Glycol (MEG), Triethylene Glycol (TEG)), thermal energy consumption for glycol regeneration through a dedicated unit should be considered in the overall system design. It is important to include all aspects when choosing the system for avoiding hydrate or wax formation.
Designers should consider the accommodation of probes and instrumentation for sensors to acquire real-time operational data inside the flowlines. For example, internal or external sensors distributed along the flowlines would reduce the data acquisition limitations that are covered by NDT (non-destructive testing), line survey, and pigging operations. Real-time operational data (such as pressure, temperature, flowrates) are necessary to understand and analyze process scenarios against the energy performance of the whole distribution system and predict which corrective maintenance is required to repair the systems. In general, the objective is to improve data acquisition and to include, within the flowline design and fabrication phase, a range of connections for instrumentation suitable to acquire process, chemistry, and internal surface data as needed.
Operations
In the upstream, most developments have a limited life. Oil and gas production rates decrease as reservoir pressure declines. Liquid rates may remain constant (constrained by processing facilities), with water increasing as oil is decreasing. Energy requirements may change with fluid compositions, the physical and thermodynamic properties of the fluids, or flow conditions (such as flow regime). During operations, the flow assurance challenges mentioned above, as well as integrity related challenges (such as corrosion), may require chemical applications and pigging campaigns. Pigging is used to remove solids deposition (for example, wax and sand) or liquid holdup (gas fields) from creating higher pressure drops, impacting production rates and operation integrity. In addition, efficiency may be improved through optimization of maintenance or pigging frequency.
As reservoir pressure and production declines, the flow system may be prone to more slugging. Slug flow can cause downstream equipment malfunction in separators and compressors, resulting in intermittent flaring. Slugging is typically managed by optimizing gas lift, changing operation procedures, periodic pigging to remove accumulated liquids, or a combination of these options. Managing liquid surges at the process facilities, and managing gas lift requirements for slugging mitigation, requires high energy consumption by pumps and compressors.
For longer distance flowlines, like offshore developments, a direct electrical heating (DEH) system may be used to manage temperature, which requires additional energy. Once operating, the flow system and operating modes of the DEH should be evaluated for opportunities to save energy. One operator in the North Sea, that installed DEH on flowlines to avoid wax and hydrate formation, has reduced heating and energy consumption by assessing actual heating needs. For one cluster of wells/flowlines, where continuous heating was used, it was found that heat was only required during production shutdown/restart. It was estimated that power consumption could be reduced by up to 1 MW, resulting in CO2 reductions of up to 5,000 tonnes per year. Such opportunities are specific to each flowline system, but this case shows that there is potential to reduce heating if the need is carefully evaluated.
Another typical situation in upstream developments is the addition of wells to a production network, to take advantage of the infrastructure (pipelines and processing facilities). A flowline/pipeline network analysis can address any bottlenecking to manage flows efficiently. Continuous injection of drag reducing agents (DRA) is effective at reducing pressure losses along a pipeline, lowering pumping energy demand. Typical DRAs are polymer additives used in liquids to increase flow rate in oil or water pipelines that are hydraulically limited by frictional pressure losses. Such chemicals are only effective under turbulent flow regime (Reynolds number of the liquid phase greater than 6,000), which is typical of upstream transportation (except for heavy viscous oils). DRAs are also effective on multiphase flow, if transportation is dominated by the liquid phase. DRAs do not affect gas transportation lines. DRAs may reduce pumping power/wellhead pressure at a given production rate, or increase production, at the same pressure conditions. Subsea application of DRAs is unproven. Some DRAs have a chemistry that could be incompatible with other flowline chemicals (such as corrosion inhibitor, and so on), and some DRA chemical compositions could be problematic for oil quality or produced water that is discharged to sea. These aspects must also be included in the evaluation.
Monitoring of flowline conditions with a pipeline management system (PMS) or real time surveillance tool, is crucial to understanding energy inefficiencies. New technologies which can provide pressure, temperature, and velocity profiles along the pipeline, to detect deposits or bore restriction which impede flows, may be used to minimize inefficiency.