Summary The selection of a freewater knockout depends on the desired performance. The design criterion developed here is based on the perception performance. The design criterion developed here is based on the perception that most FWKO's are installed to remove the bulk of the water from -a high-watercut flow stream so that the oil can be dehydrated economically to salable specifications and to discharge water requiring minimal treatment before disposal. Only the gravity separation process is considered; the contribution of coalescing devices is excluded. Vertical FWKO's are discussed briefly, but the bulk of this paper is devoted to horizontal FWKO'S, which constitute a majority of vessels. Hydraulic similarity of horizontal FWKO's and API separators is demonstrated, and a design criterion for FWKO's is developed with the basis used in the design development for API separators. This analysis discloses that commonly used criteria overrate the ideal flow capacity of FWKO's by a factor of 4/ . It shows that maximum FWKO capacity occurs when the oil/water interface is maintained at a level of 0.769 diameters in the case of ideal vessels and somewhat higher for nonideal vessels, rather than 0.50 as commonly believed. Published FWKO residence-time distributions (RTD's) indicate nonideal flow. Consequently, a design allowance for short-circuiting and turbulence effects was incorporated into the FWKO design. The effect of vessel proportions on cost per unit capacity is analyzed and an equation is developed for determining optimum proportions. Introduction FWKO's (also known as pressurized skimmers) are commonly used on high-watercut flow streams for bulk separation of hydrocarbon phases from water. Liberated gas may be removed either with the oil or separately. An FWKO should incorporate means of dissipating the momentum of the incoming flow and confining the gas phase to the top of the vessel. These requirements are essential for providing a tranquil environment for gravity separation of oil and water. Many FWKO's incorporate coalescing media, which enhances separation; however, only gravity separation is ad- dressed in this paper. FWKO designs include both horizontal and vertical orientation, the latter being a small percentage of units in service. Stokes' law best describes the gravity-separation velocity for droplet sizes of concern in oil/water mixtures. This law, expressed in oilfield terms, is vt = 178.74(w - o)do2/uw..................(1) Values of, ranging from 0.015 to 0.020 cm are commonly used in sizing FWKO'S. Vertical FWKO'S. Because it is demonstrated here that vertical FWKO's are not a competitive alternative, these units are given minimal coverage. A vertical FWKO should be constructed so that the flow stream enters near the top and passes through a gas/liquid separating chamber. Inside the open vessel, separation of the degassed liquid mixture begins, with the oil- continuous phase rising to the top and the water-continuous phase settling to the bottom . Removal of water from the vessel is regulated by a dump valve that normally is controlled by an interface float. The oil/gas outlet is usually restricted only by superimposed backpressure. As with all vessels, outlets should be equipped with vortex breakers. Entrained oil droplets must rise countercurrent to the water-displacement velocity, which, assuming plug flow, would equal the flow rate divided by the vessel cross-sectional area. Equating this velocity to the rising velocity of an oil droplet as expressed in Eq. 1 yields the commonly used design-capacity equation: qVC = 2.1603 X 10-6(w - o)do2di2/uw,..........(2) which demonstrates that diameter is the only vessel parameter contributing to capacity. This equation, as modified later to compensate for nonideal flow, is appropriate for sizing.
5%5 19349S ummary. The expanding usage of variable-speed drives (VSD'S) indicates that their effects, on electrical submersible pump (ESP) performance and longevity merit investigation. This paper demonstrates that speed variation makes ESP, equipment selection more complex and critical if maximum pump life is to be achieved. Thrust wear can dramatically affect pump longevity. A common conception is that the rates identifying acceptable thrust limits for any pump s,peed would be the at%nity-law projections' of the detining rates at 60 cycleslsec [60 Hz]. This would result in a diverging thrust range as speed increases. This paper (1) shows the fallacy of this co"cepq (z) demonstrates mathematically and graphically that as speed increases, the tbmst range converges; (3) expresses the need for verification of the calculated data with actual measurements; and (4) discusses potential pump dinnage caused by internal recirculation cavitation at high pumping speeds and the increased exposure to vibration damage resulting from speed variation.The benefits of speed variation.are summarized. A specific ESP was selected as a typical pump for illustration. Data were normalized by dividing all characteristics by those occurring at the "peak efficiency point. The pump performance data thus obtained are used to illustrate techniques 'for designing a pump to be driven at variable or nonstandard speeds. An operating window is presented that is bounded by tie thrust range limits and by the head-vs.-rate curves that correspond to the ,maximum and minimum driving frequencies tO be considered. This is used in the discussion of VSD applications relative to wells of improving productivity and well testing. Also, the pumplmotor mismatch inherent in wide-speed-range applications and resultant low motor efficiency are demonstrated.CoPyright 7987Societyof Petrola"m Enoi"ea,s casing, surface flowline pressure, and completion inter-SPE Production Engineering, February [987 1s
This paper presents an improved method of predicting gas capacities of horizontal separators that properly accounts for the effects of the L/d ratio and the depth of the gas/oil interface. A theoretical basis for calculating oil capacities also is presented. Equations are developed for calculating optimum proportions with either gas or oil capacity governs equipment selection.
Summary Steamfloods conducted in thin reservoirs generally provide marginal profits because of relatively high field provide marginal profits because of relatively high field development costs per barrel of oil in place (OIP) and excessive heat losses from the productive zone. New techniques are being used to solve these problems, such as use of induced horizontal fractures to circumvent the detriments attributable to thin zones and to solve the problems of steam distribution and confinement inherent problems of steam distribution and confinement inherent in any steamflood. This paper documents the successful application of steamflooding in the multiple thin-sand reservoirs of the Loco Unit, Stephens County, OK. These reservoirs occur at depths from 50 to 1,200 ft [15 to 366 m] and range in thickness to 40 ft [12 m]. Porosities of the productive zones vary from 20 to more than 30%, and permeabilities range from 100 to more than 4,000 md. Oil gravities of the various zones range from 16 to 24API [0.96 to 0.91 g/cm3]. Table 1 presents average reservoir properties of the three most important zones in the area of principal interest. Reservoirs that occur at depths above approximately 700 ft [213 m] have little or no natural reservoir energy and generally contain viscous oils, ranging up to 10,000 cp [10 Pa.s]. Consequently, there was no primary production from these reservoirs, and potential for waterflooding was marginal. Steamflooding has been the only recovery process applied successfully to these zones, except for one isolated instance. Reservoirs at depths greater than 700 ft [213 m] normally contain lower-viscosity oils. Six of these zones were produced by solution gas drive and were later waterflooded successfully. After 23 years of water-flooding, two of these six zones have been tested and have proved to support commercial steamflooding operations. Introduction The Loco field is situated on a northwest-southeast trending anticline that underlies a major portion of Township T3S-R5W, Stephens County, OK, at approximately the location indicated in Fig. 1. The field was discovered in 1913, and sporadic development occurred from that time until the 2,300-acre [931-ha] unit was formed in 1961 for the pursuit of secondary recovery operations. From 1961 through 1964, the field was developed on 10-acre [4.05-ha] spacing, and water-flooding of the six deepest zones was initiated, using 20-acre [8.09-ha], five-spot patterns. Geology and Reservoir Description. Twenty-four identified zones have been proved to have, or are suspected of having, significant oil saturation in at least some areas of the unit. The most significant of these are illustrated in the log section of Well 511 presented in Fig. 2. The various oil sands have been named alphabetically ascending (As, Bs, Cs, etc.) and descending (Ad, Bd, Cd, etc.) from the Loco lime (LL), which occurs at a depth of 800 to 900 ft [244 to 274 m]. Three zones (X, Y, and Z) of minor areal extent are located between the LL and the A-shallow (As) sand. The LL and the five deep sands are of Hoxbar-Pennsylvanian age. A fault trending northeast-southwest displaced this interval approximately 100 ft [30 m]. The original OIP in the six deep zones is estimated to be 73.4 × 10(6) bbl [11.7 × 10(6) m3]. These zones have had primary recoveries of approximately 3 % of the original OIP, and waterflooding, which was initiated in 1961, will ultimately recover an additional 11 %. The shallow sands, which lie above the LL, are of Pontotoc-Permian age and are not affected by the Pontotoc-Permian age and are not affected by the faulting. Minimal natural reservoir energy has precluded significant primary recovery, and the adverse mobility ratios inherent to the native oil viscosities make waterflooding generally impractical. A notable exception to this rule was a 20-acre [8.09-ha] waterflood of the As and Cs zones, which was conducted in the southeast quarter of Sec. 9 from 1956 to 1963; this was a marginally profitable operation. No response was observed in a profitable operation. No response was observed in a 10-acre [4.05-ha] X-zone waterflood, which was operated during this time interval in the southwest quarter of Sec. 9. From 1969 through 1972, pilot waterfloods were conducted in the As, Bs, Ds, and Js sands, none of which were successful. JPT P. 1707
Power consumption of an electric submersible pump (ESP) installation may be categorized into three components: the energy required to perform useful work, which is equivalent to the net hydraulic load divided by the product of pump and motor efficiencies; the energy absorbed by tubing friction, which is equal to the dissipated hydraulic energy divided by the efficiency product; and power-cable electrical losses. An improved design technique is presented that brings the first two categories into economic perspective. The interrelated effects of tubing friction, power-cable resistance, and motor voltage on ESP power consumption are demonstrated, as is the degree of desirability for using a motor of the highest available voltage. An equation, useful in making economic evaluations of alternatives, is developed for calculating power consumption for combinations of tubing size, power-cable size, and motor voltage. Variations of power consumption are illustrated graphically for various combinations of these three parameters. Also illustrated is the effect of the nature of a specific net hydraulic load-Le., the product of rate, net lift, and specific gravity. Practical examples using the design techniques developed here are presented and comparisons made to designs based on common practice.
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