Oil/gas production flowline and pipeline line sizing
Hydraulic calculations should be carried out from wells, pipelines, and risers to the surface facilities in line sizing. The control factors in the calculation are fluids (oil, gas, or condensate fluids), flowline size, flow pattern, and application region. Unlike single-phase pipelines, multiphase pipelines are sized taking into account the limitations imposed by production rates, erosion, slugging, and ramp-up speed. Artificial lift is also considered during line sizing to improve the operational range of the system. Design conditions are as follows:
- Flow rate and pressure drop allowable established: Determine pipe size for a fixed length.
- Flow rate and length known: Determine pressure drop and line size.
Usually either of these conditions requires a trial-and-error approach based on assumed pipe sizes to meet the stated conditions. Some design problems may require determination of maximum flow for a given line size and length, but this is a reverse of the conditions above. During the FEED stage of a project, the capability of a given line size to deliver the production rate throughout the life of the field is determined by steady-state simulation from the reservoir to the surface facilities throughout the field life. Sensitivities to the important variables such as GOR, water cut, viscosity, and separator pressure should be examined.
The technical criteria for line sizing of pipelines are stated in next section; however, the optimum economic line size is seldom realized in the engineering design. Unknown factors such as future flow rate allowances, actual pressure drops through certain process equipment, etc., can easily overcompensate for what the design predicted when selecting the optimum. In sizing a pipeline, one is always faced with a compromise between two factors. For a given flow rate of a given fluid, piping cost increases with diameter. But pressure loss decreases, which reduces potential pumping or compression costs. There is an economic balance between material costs and pumping costs in downstream flowlines. The optimum pipe size is found by calculating the smallest capitalization/operating cost or using the entire pressure drop available; or increasing velocity to highest allowable.
The line sizing of the pipeline is governed by the following technical criteria:
- Allowable pressure drop;
- Maximum velocity (allowable erosional velocity) and minimum velocity;
- System deliverability;
- Slug consideration if applicable. Hydraulics 393 Other criteria considered in the selection of the optimum line size
- Standard versus custom line sizes: Generally, standard pipe is less expensive and more readily available. For long pipelines or multiple pipelines for the same size, custom line sizes may be cost effective.
- Ability of installation: Particularly in deep water, the technical installation feasibility of larger line sizes may constrain the maximum pipe size.
- Future production: Consideration should be given to future production that may utilize the lines.
- Number of flowlines and risers: If construction or flow assurance constraints require more than two production flowlines per manifold, optional alternatives including subsea metering processing and bundles should be explored.
- Low-temperature limits: Subsea equipment including trees, jumpers, manifolds, and flowlines have minimum temperature specifications. For systems with Joule-Thompson cooling in low ambient temperature environments, operating philosophies and possibly metallurgical sections should be adjusted.
- High-temperature limits: Flexible pipe has a maximum temperature limit that depends on the materials of construction, water cut, water composition, and water pH. For systems with flexible pipe, the flow rate may be limited, requiring a smaller pipe.
- Roughness: Flexible pipe is rougher than steel pipe and, therefore, requires a larger diameter for the same maximum rate. To smooth flexible pipe, an internal coating may be applied.
Maximum Operating Velocities
Liquid velocity is usually limited because of erosion effects at fittings. Erosion damage can occur in flowlines with multiphase flow because of the continuous impingement of high-velocity liquid droplets. The damage is almost always confined to the place where the flow direction is changed, such as elbows, tees, manifolds, valves, and risers. The erosional velocity is defined as the bulk fluid velocity that will result in the removal of corrosion product scales, corrosion inhibitors, or other protective scales present on the intersurface of a pipeline.
The velocity of pipeline fluids should be constrained as follows:
- The fluid velocity in single-phase liquid lines varies from 0.9 to 4.5 m/s (3 to 15 ft/s).
- Gas/liquid two-phase lines do not exceed the erosional velocity as determined from following equation, which is recommended in API RP 14E.
Minimum Operating Velocities
The following items may effectively impose minimum velocity constraints:
- Slugging: Slugging severity typically increases with decreasing flow rate. The minimum allowable velocity constraint should be imposed to control the slugging in multiphase flow for assuring the production deliverability of the system.
- Liquid handling: In gas/condensate systems, the ramp-up rates may be limited by the liquid handling facilities and constrained by the maximum line size.
- Pressure drop: For viscous oils, a minimum flow rate is necessary to maintain fluid temperature such that the viscosities are acceptable. Below this minimum, production may eventually shut itself in.
- Liquid loading: A minimum velocity is required to lift the liquids and prevent wells and risers from loading up with liquid and shutting in. The minimum stable rate is determined by transient simulation at successively lower flow rates. The minimum rate for the system is also a function of GLR.
- Sand bedding: The minimum velocity is required to avoid sand bedding.
During FEED analysis, the production system should be modeled starting at the reservoir using inflow performance relationships. OLGA 2000 may be used to evaluate the hydraulic stability of the entire system including the wells, flowlines, and risers subject to artificial lift to get minimum stable rates as a function of the operating requirements and artificial lift. In the hydraulic and thermal analyses of subsea flowline systems, the wellhead pressure and temperature are generally used as the inlet pressure and temperature of the system. The wellhead pressure and temperature are functions of reservoir pressure, temperature, productivity index, and production rate and can be obtained from steady and transient hydraulic and thermal analyses of the well bore. The hydraulic and thermal models may be simulated using the commercial software PIPESIM or OLGA 2000. The hydraulic and thermal processes of a wellbore are simulated for the following purposes:
- Determining steady-state wellhead pressure and temperature for flowline hydraulics and thermal analyses.
- Determining the minimum production rates that will prevent hydrate formation in the wellbore.
- Determining the minimum production rate for preventing wax deposition in the wellbore and tree. The wellhead temperature is required to be higher than the critical wax deposition temperature in the steadystate flowing condition.
- Determining cooldown time and warm-up time from transient wellbore analysis to prevent hydrate formation in the wellbore.
The transient analyses determine how hydrates can be controlled during startup and shut-in processes. Vacuum insulated tubing (VIT) is one method to help a wellbore out of the hydrate region. Use of 3000 to 4000 ft of VIT results in warm-up of the wellbore to temperatures above the hydrate temperature in typically 2 hr or less. These warm-up rates are rapid enough to ensure that little or no hydrates form in the wellbore. This makes it possible to eliminate the downhole injection of methanol above the subsurface safety valve during warm-up. Instead, methanol is injected upstream of the choke to prevent any hydrates that may be formed during warm-up from plugging the choke. One drawback of VIT is that it cools more quickly than bare tubing since the insulation prevents the tubing from gaining heat from the earth, which also warms up during production.
As a result of this quick cooling, it is necessary to quickly treat the wellbore with methanol in the event that a production shut-in occurs during the warm-up period. For a higher reservoir temperature, VIT may not be used in the wellbore, and the cooldown speed of a wellbore is very slow after a process interruption from steady-state production conditions.
Artificial lift can be used to increase production rates or reduce line sizes. Line sizing may include the affects of gas lift. For systems employing gas lift, models should extend from the reservoir to the surface facilities incorporating the gas lift gas in addition to the produced fluids. The composition of the gas-lift gas is provided by the topside process but should meet the dew-point control requirement. The preferred location (downhole, flowline inlet, or riser base) is determined based on effectiveness and cost.
The effect of gas lift on the severe slugging boundary may be simulated with OLGA 2000 for the situations, when it is required. Normally, it is set at the riser base. The simulation may decide the minimum flow rate without severe slugging as a function of gas-lift rates and water cuts. When the gaslift injection point does not include a restriction or valve to choke the gas flows, OLGA 2000 transient simulations may model the transient flow in the gas-lift line by including the gas-lift line as a separate branch to determine maximum variation in mass rate and pressure and still maintain system stability.
Maximum production rates throughout the field life are determined as a function of gas-lift rate. In FEED designs, the gas-lift rate and pressure requirements should be recommended, including a measurement and control strategy for the gas-lift system.
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