Gas separation: processes – Deflecting – And filtering
Reexamination Certificate
1999-07-23
2001-06-26
Spitzer, Robert H. (Department: 1724)
Gas separation: processes
Deflecting
And filtering
C095S269000, C095S287000, C055S330000, C055S337000
Reexamination Certificate
active
06251168
ABSTRACT:
FIELD AND BACKGROUND OF THE INVENTION
The present invention relates, in general, to oil and gas separation systems and, in particular, to an improved, unique, and useful method and apparatus for separating a multiple phase mixture into separate vapor and liquid phases utilizing single or multiple pairs of centrifugal force separators in conjunction with a coalescing media. The present invention is particularly well-suited for applications involving the separation of oil and gas phases contained in wellhead fluids, obtained from hydrocarbon production systems, and can be employed in any hydrocarbon production facility, including topside or subsea locations.
Many problems which are unique to hydrocarbon production systems, such as foaming, emulsions, intermittent flows, waxing, and hydrates, are encountered when separating the liquid and gas phases of wellhead fluids. Such wellhead fluids typically comprise one or more of the following: hydrocarbon liquid(s), hydrocarbon gas(es), water, sand, and/or other solids or gases (including carbon dioxide and/or hydrogen sulfide which, in small quantities, do not affect the separation process but, based on their corrosive nature, do influence the choice of construction materials for gas-oil separators). Also, wellhead fluids typically have multiple components—that is, the specific type and number of hydrocarbons encountered may vary (i.e., methane ethane, propane, etc.), such that the pressure and temperature of the wellhead fluid determines whether the particular hydrocarbon in question is a liquid or a vapor. Likewise, the distribution and quantity of the various components determines the gravity of the oil and the gas.
In comparison to a one-component, two-phase system (such as a steam-water mix), wellhead fluids present other unique separation problems because of the large number of possible combinations of particular gases, liquids, and solids contained in a specific wellhead fluid. Essentially, each particular wellhead fluid will have a unique set of fluid properties which can only be approximated by knowing the pressure, temperature, liquid gravity, and gas gravity of that fluid. Furthermore, if the wellhead fluid contains hydrocarbons and water, the resulting emulsions may impact separator performance in such a way that is not seen in one-component, two-phase systems.
Accordingly, it is common practice to separate the phases in a wellhead fluid. The
Petroleum Engineering Handbook,
Society of Petroleum Engineers, 3
rd
printing, (1992), recommends that the oil content of the gas discharged by an oil and gas separator should be in the range of 0.10 gallons per million standard cubic feet (Gal/MMscf) to 1.0 Gal/MMscf, as a commercially accepted standard of the performance under normal or average conditions for gas-liquid separators in hydrocarbon production systems.
Current gas-liquid separators for wellhead fluids can be classified in two general categories. The first class of separators rely on natural separation, also known as gravity separation. These systems require large vessels to achieve the desired separation performance. When natural separation is attempted in a relatively small vessel, the throughput, or vapor flux, of that system is significantly smaller when compared to other systems not relying on natural separation. An example of such a system is described in U.S. Pat. No. 4,982,794.
The second type of wellhead fluid separators are generally defined as centrifugal separators. These separators rely on centrifugal force to achieve the desired separation performance. In this arrangement, the separation efficiency of such a separator may be sensitive to small changes in flow, and it may require relatively larger pressure drops to create the centrifugal force. See,
Surface Production Operations, Volume
1,
Design of Oil
-
Handling Systems and Facilities,
Ken Arnold and Maurice Stewart, Gulf Publishing Company. Therefore, cyclone separators are not commonly used in hydrocarbon production systems.
A typical cyclone separator
10
is shown in
FIGS. 1A and 1B
. In this separator design, gas with entrained liquid oil droplets from the primary separator (not pictured) enters the cyclone through multiple inlets
45
created by inlet vanes
40
which are arranged tangential to the inside can
30
of the cyclone
10
. This inlet arrangement imparts a swirl on the incoming fluids causing the heavier liquid droplets to move in a radial outward direction towards the wall
30
of the cyclone while the lighter gas phase flows upward through the center of the cyclone. The liquid forms a film on the inner wall
30
of the cyclone and is removed through skimmer slots in the wall of the cyclone
10
.
Typically, when separator
10
is used in combination with a certain primary separator, the resulting gas-liquid centrifugal separator system can remove over 99% of the incoming liquids from the feed stream. Significantly, the ability of this separator system to meet the oil content in gas specification is limited by separator
10
, the secondary cyclone separator. While this separated gas is sufficiently free of liquids for use in some separation applications, the gas quality may not satisfy the oil content in gas specification mentioned above, particularly at high liquid loads (i.e., a feed stream with a liquid volume greater than 15%). An example of a gas-liquid centrifugal separator system which utilizes a secondary cyclone is illustrated by co-pending U.S. application Ser. No. 08/695,947, titled “Compact, High-Efficiency Gas/Liquid Separator Method and Apparatus.”
The performance of the secondary cyclone separator is strongly dependent upon two factors. The first factor is the size of the liquid drops entering the cyclone. Droplet carryover occurs when there is insufficient residence time inside the cyclone for the drop to move the radial distance across the cyclone where it becomes separated from the core gas stream. This problem is more acute for small droplets, since small droplets prefer to remain with the core gas stream. A second mechanism that limits the liquid carryover performance of the secondary cyclone separator is re-entrainment from the liquid film on the radial wall of the cyclone. When the feed stream contains a high liquid load, the liquid entering the secondary cyclone may form a relatively thick film on the inner wall of the cyclone. The upward flowing gas can re-entrain liquids from this film before its removal from the cyclone, which can cause a significant liquid carryover under high liquid load conditions.
While the components of the above-described gas-liquid separator system are similar to steam-water separators used in power generation applications, such as U.S. Pat. No. 4,648,890 to Kidwell or U.S. Pat. No. 3,324,634 to Brahler (both assigned at issue to the Babcock & Wilcox Company), substantial differences between the fluid properties of gas/oil wellhead fluids and water/steam mixtures make these systems markedly different. In addition to the unique problems caused by gas-liquid wellhead fluids discussed above, the fluid properties of steam-water mixtures varies significantly from that of gas-liquid wellhead fluids such that the droplet entrainment tendencies, centrifugal separation tendencies, and vapor carry under tendencies of each system are also different. Accordingly, while use of gas scrubbers (systems which separate gas-oil with low liquid loading) has been known, the development and use of a gas-oil centrifugal separator system for hydrocarbon production systems with high liquid loading was not previously envisioned or expected to be feasible by those skilled in the art.
In gas scrubbers, separation efficiency is limited by the size of droplets entering the cyclone, with the larger liquid droplets being more susceptible to separation via centrifugal force than smaller droplets. However, none of the prior art gas scrubbers described above include a means for reliably controlling or enhancing droplet size. Moreover, the setup and operation of these systems are limited by the pressure drop requirem
Birmingham Daniel P.
Rush Gregory C.
Baraona R. C.
Hudson Products Corporation
Marich Eric
Spitzer Robert H.
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