API MPMS 20.2 2016 pdf free download

API MPMS 20.2 2016 pdf free download.Manual of Petroleum Measurement Standards Chapter 20.2 Production Allocation Measurement Using Single-phase Devices.
The lowest metering uncertainty is generally associated with custody transfer metering (e.g. sales meters). Metering upstream of the custody transfer point, near the wellhead, usually has a higher uncertainty due to the various conditions that exist in production operations. See Annex A (Figure A.1 ) for a measurement process flow diagram (MPFD). Production processes are generally the same where fluids exiting the wellhead travel to a facility where separation occurs through a separator or series of separation vessels and other facilities in an ever decreasing pressure environment. At wellhead conditions, the liquid hydrocarbons contain varying amounts of dissolved natural gas. Furthermore, at the wellhead condition, a significant amount of natural gas will be mixed with the liquid flow. And finally, in addition to the hydrocarbon constituents, produced water is normally present in varying amounts. During the production process through the various stages of separation, the liquid hydrocarbons approach atmospheric pressure conditions and contain no dissolved natural gas (i.e. they are atmospherically stable). The produced water has also been removed. At this point, hydrocarbon liquids are considered merchantable. Throughout the process, the natural gas has been gradually removed and collected in a compression arrangement such that it becomes pressurized for transport in natural gas pipelines. If necessary, the gas passes through dehydration units where excess water vapor is removed. The end result of the process is atmospherically stable hydrocarbon liquids and dehydrated natural gas for measurement through a custody transfer measurement system and eventual transport to facilities further downstream. Some of this natural gas may be consumed for fuel or burned as flare.
Within the process, stabilized and predictable flow conditions might not be fully achievable. For example, depending on pressure, process control, and the makeup or composition of hydrocarbon fluids, there will generally be some level of gas bubbles within the liquid outflow from separators. This is called gas carry-under. Likewise, it is not uncommon for the phenomenon to occur where some free liquid flows as an aerosol mist with the gas flow from the top of the separator. This is called liquid carry-over. Both conditions reduce the ability of single-phase gas and liquid meters to achieve their intended accuracy. It is important to understand and account for the inaccuracies encountered due to intermittent and low-level two-phase conditions. 4.2 Single-phase Meters Used for Production Allocation Measurement General 4.2.1 Metering the produced quantities throughout the process is very important for varying reasons. The most critical metering occurs at the end of the process, where the products are transferred (or sold) from the producers to (normally) transporters. Sometime these are called sales meters or lease automatic custody transfer unit (LACT) meters, and they are normally the basis of revenue and taxation. These systems (i.e. sales meters) are expected to meet a tighter tolerance or “lower uncertainty” than could be achievable for the flow measurement systems located upstream towards the production sources (often called allocation meters). Separator-based Metering Applications 4.2.2 A primary function of the production process is phase separation. Separators take in a mixed flow of oil, gas, and water and through a series of internal arrangements allow for a gas to flow to the top and a liquid to flow to the bottom. The efficiency of a production separator is generally a function of separator size, fluid properties, and temperature.
A two‐phase separator does not have a produced water leg. Two-phase separators present greater opportunity for fluctuation in produced water levels at the separator liquid outflow, which in turn can affect measurement accuracy. On two‐phase separators, hydrocarbon and water are also measured as a single liquid phase using meters similar to those on a three‐phase separator. A single-phase meter in oil/water mixture service can be challenged by the process fluid condition changes including density ratio, oil/water fraction, droplet size, viscosity, density, composition, and flow regime. This fact inherently increases the measurement uncertainty versus a three-phase separator where hydrocarbon and water are metered separately. Regardless of the separator type, the water content should be measured in conjunction with single-phase meter quantities to determine the net oil content of the liquid stream. On a three‐phase separator, the water content of the oil outlet might vary from a few tenths of a percent to several percent. On two‐phase separators, water content is relative to the watercut (WC) of the well stream, which could vary from 0 % to 1 00 %, especially on an instantaneous basis. The range of water content will impact the technology used to measure or sample product.