Flowrate

The oil and gas samples are taken from the appropriate flowlines of the same separator, whose pressure, temperature and flowrate must be carefully recorded to allow the recombination ratios to be calculated. In addition the pressure and temperature of the stock tank must be recorded to be able to later calculate the shrinkage of oil from the point at which it is sampled and the stock tank. The oil and gas samples are sent separately to the laboratory where they are recombined before PVT analysis is performed. A quality check on the sampling technique is that the bubble point of the recombined sample at the temperature of the separator from which the samples were taken should be equal to the separator pressure. 

For direct measurement from core samples, the samples are mounted in a holder and gas is flowed through the core. The pressure drop across the core and the flowrate are measured. Providing the gas viscosity (ji) and sample dimensions are known the permeability can be calculated using the Darcy equation shown below. 

For a single fluid flowing through a section of reservoir rock, Darcy showed that the superficial velocity of the fluid (u) is proportional to the pressure drop applied (the hydrodynamic pressure gradient), and inversely proportional to the viscosity of the fluid. The constant of proportionality is called the absolute permeability which is a rock property, and is dependent upon the pore size distribution. The superficial velocity is the average flowrate... 

The field unit for permeability is the Darcy (D) or millidarcy (mD). For clastic oil reservoirs, a good permeability would be greater than 0.1 D (100 mD), while a poor permeability would be less than 0.01 D (10 mD). For practical purposes, the millidarcy is commonly used (1 mD = 10" m ). For gas reservoirs 1 mD would be a reasonable permeability because the viscosity of gas is much lower than that of oil, this permeability would yield an acceptable flowrate for the same pressure gradient. Typical fluid velocities in the reservoir are less than one metre per day. 

The relationship between the flowrate (Q) towards the well and the pressure drawdown is approximately linear, and is defined by the productivity index (PI). 

The flowrate of oil into the wellbore is also influenced by the reservoir properties of permeability (k) and reservoir thickness (h), by the oil properties viscosity (p) and formation volume factor (BJ and by any change in the resistance to flow near the wellbore which is represented by the dimensionless term called skin (S). For semisteady state f/owbehaviour (when the effect of the producing well is seen at all boundaries of the reservoir) the radial inflow for oil into a vertical wellbore is represented by the equation ... 

Routine production tests are performed, approximately once per month on each producing well, by diverting the production through the test separator on surface to measure the liquid flowrate, water cut, and gas production rate. The wellhead pressure (also called the flowing tubing head pressure, FTHP) is recorded at the time of the production test, and a plot of production rate against FTHP is made. The FTHP is also recorded continuously and used to estimate the well s production rate on a daily basis by reference to the FTHP vs production rate plot for the well. 

The progressive cavity pump consists of a rotating cork-screw like sub-surface assembly which is driven by a surface mounted motor. Beam pump rods are used to connect the two. The flowrate achieved is mainly a function of the rotational speed of the subsurface assembly. There Is in principle very little that can go wrong with progressive cavity pumps. Progressive cavity pumps excel in low productivity shallow wells with viscous crude oils and can also handle significant quantities of produced solids. 

Operating conditions all gas lift valves apart from the bottom orifice valve are closed. The energy to the system is delivered by a compressor. The performance of the system is monitored by observing flowrates and the casing and tubing pressures. 

The actual flowrate of each component of the gas (in for example cubic mefres), would be determined by multiplying the volume fraction of that component by the total flowrate. 

Centrifugal demister or cyclone) devices rely on high velocities to remove liquid particles and substantial pressure drops are required in cyclone design to generate these velocities. Cyclones have a limited range over which they operate efficiently this is a disadvantage if the input stream flowrate is very variable. 

The above example reveals that layer C is not contributing to flow at all (zero increase in total production as the tool passes this layer), and that a denser fluid (water) is being produced from layer B, which is also a major contributor to the total flowrate in the well. 

Column Mobile Phase Flowrate Temperature Detector ... 

Sephadex G-X Specific volume water mL/g dry gel Permeabihty, iC Operating pressure, kPa Flowrate water, mL/(cm h)... 

The incremental pressure drop for wet mesh is not available for all operating conditions or for mesh of different styles. The data of York and Poppele for wet-mesh incremental pressure drop, APi in cm of water, are shown in Fig. 14-122 or parameters of liquid velocity L/A, defined as liquid volumetric flowrate, cmVmin per unit of mesh cross-sectional area in cm" liqiiid density Pl is in g/cm. ... 

The resulting volumetric flowrate is the sum of the combustion of the natural gas q and the process gas stream p at the operating temperature ... 

Fig ure 1-5. The typioally flat turboexpander effioienoy oharaoteristie with various flowrates is shown here. Effioienoy versus the velooity ratio v (ratio tip speed to spouting velooity) is also shown. (Source Atlas Copco.)... 

Adaptability Expander internals (rotors, impellers, inlet nozzles, ete.) ean be redesigned at moderate eost to aeeommodate ebanges in proeess eonditions, sueb as lower pressure, ebanging gas eomposition, and flowrate. 

Expander performance will shift as plant conditions—such as gas flowrate, gas inlet, and discharge pressure—gas composition, and inlet temperature change. Calculation of expander diermal efficiency from field data is not accurate because expander discharge flow normally consists of two phases, gas and liquid. Efficiency calculations should always be cross-checked with the shaft power produced before any decision on expander performance is made. 

For small flowrates, the single-casing radial compressor without intercooling is employed for delivery pressures of up to 4-6 bar. Higher pressures of up to 15 bar are attained with intercooled machines of single- and double-casing design. 

Above a minimum intake flowrate of about 50,000 m /hr and depending on the required discharge pressure, axial compressors (Figure 4-15) offer certain advantages. Their polytropic efficiencies. 

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