Crude oil vapor pressure

The first paper. Challenges Associated With the Design of Oil-Gas Separation Systems for North Sea Platforms" by Penick and Thrasher, discusses and reviews the different design aspects, requirements, and constraints associated with oil and gas separation facilities in the North Sea. Specifications of crude-oil vapor pressure and gas dewpoint are reviewed from a pipeline standpoint, and potential solutions and design approaches to meet the separation objectives are presented. 

Crude oil vapor pressure is the specification which most influences the design of oil-gas separation systems. For offshore tanker loading, the oil may be limited to a vapor pressure In the range of 8 to U pounds KVP (Reid Vapor Pressure). RVP refers to a standard method of vapor pressure testing utilizing a specific test cylinder assembly. and determined at a temperature of 100°F. RVP is (not Identical with TVP (true vapor pressure), which is the actual vapor pressure exerted by a liquid in equilibrium with a vapor at any given temperature. 

Crude oil vapor pressure limitations for pipeline delivery may be comparable to those for tanker loading. However, a pipeline can be specifically designed as a high vapor pressure system to handle gas liquids components mixed with the crude oil, and it is quite possible that North Sea oil pipeline systems will be developed in this manner. It is not expected to be feasible to recover NGL components separate from oil and gas on the offshore platforms and construct separate NGL pipeline systems. It also may not be possible in every field to design a separation system which meets both gas specifications and low crude oil vapor pressure specifications unless an intermediate product is also made. This will be more fully discussed later In this paper. A high vapor pressure crude system will have an NGL separation and fractionation plant at the onshore pipeline terminal. The vapor pressure limitation for onshore crude deliveries will be fixed by TVP limitations at pump station suction conditions. 

It is undesirable in the North Sea to have more than two product streams—crude oil, and gas--leaving the production platform. All of the components contained in the producing well stream must leave the platform, or be consumed as fuel. Depending on the well stream composition, it is possible a combination of low crude oil vapor pressure and gas hydrocarbon dewpoint specifications, with limitations in separation selectivity, may result In a third product stream of intermediate (NGL) compo-nents which cannot be put into either the oil or gas streams. As previously discussed, a separate NGL pipeline system or offshore storage and loading of NGL will be uneconomic in the North Sea, and this factor will tend to encourage development of North Sea oil pipeline systems on a high vapor pressure crude basis. 

If the third product problem arises, the most desirable solution Is adjustment of crude oil vapor pressure and/or gas dewpoints to eliminate the problem. This requires an integrated North Sea development system--oil transportation, gas transportation, and producing platform development. Transportation systems which permit this solution also will probably result in conservation of potentially valuable NGL component hydrocarbon raw materials which otherwise might not be economically recoverable. The next solution, If the volume of the third stream is small enough, is to utilize it for fuel on the... 

One way to utilize a stabilizer Is illustrated In Figure 5, which is simply the Figure 4 process with the liquids from K and 4 diverted to a stabilizer. The stabilizer could be either refluxed or cold-feed, as a further variation. This process reduces the recycle load significantly in the two lower compression stages, as compared to the previous processes. This process also provides an additional control for the crude oil vapor pressure which can be independently varied, since the fractionator split can be controlled and the fractionator bottom product is blended with the crude stream. It may be desirable to blend this stream into separator 1... 

The main objective in processing crude oil from the production well is to separate it into three phases—gas, oil, and water. Keeping this in mind, all processing is indeed simple. All successful operations are based on making the crude oil vapor pressure acceptable for pipeline transmission and removing sufficient water for the pipeline transmission. Conditioning the vapor pressure or degassing with crude water removal (dehydration) is commonly called crude oil stabilization. 

The crude oil vapor pressure will be the same as the pressure of the final flash calculation. Assuming this is a stock-tank at 14.7 psia (101.4 kPa) and 100 °F (37.8 °C), then the vapor pressure is 14.7 psia (101.4 kPa). If a sales product vapor pressure less than 14.7 psia (101.4 kPa) is necessary and multistage separators are used, the crude may require heating above 100 °F (37.8 °C) prior to entering the low-pressure separator. 

The atmospheric reduced crude is the feedstock for the vacuum distillation unit. To prevent thermal decomposition (cracking) of the higher boiling point hydrocarbons in the crude oil, the pressure in the vacuum distillation fractionation column is reduced to about one-twentieth of an atmosphere absolute (one atmosphere pressure is 14.7 psia or 760 mm Fig). This effectively reduces the boiling points of the hydrocarbons several hundred degrees Fahrenheit. The components boiling below about 1050°F (565°C) are vaporized and removed as vacuum gas... 

The first step is to use a separate cooling and separation system on the vapor streams from each stage and the recompression gases, as in Figure 4. This reduces recycle loads, because the recompressed vapors are not subjected to the absorber effect of the crude oil streams at each stage. It still is not possible to control the temperature D, but the temperature 1 can be controlled, as well as the pressure D and 1, and the crude oil product is a combination of the liquid streams from separations D and 1. If the inlet wells , re am is hot, which Is frequently expected with the high well flow rates sometimes obtained in the North Sea, this system may be much more selective because different temperature levels can be maintained in 1-4 as compared to A-D. It usually is poesible to establish a pressure level for D and 1 which will allow control of the oil vapor pressure. Recycle loads nwy still be a problem with this process, but not as much as in the previous one. 

The Reid vapor pressure is generally barely different from the true vapor pressure at 37.8°C if the light gas content —methane, ethane, propane, and butane— of the sample is small, which is usually the case with petroleum products. The differences are greater for those products containing large quantities of dissolved gases such as the crude oils shown in Table 4.13. 

Reid vapor pressure, bar Vapor pressure crude oil, bar Vapor pressure gasoline, bar R crude oil R stabilized gasoline... 

Vapor Pressure and Flash Point of Crude Oils... 

The measurement of the vapor pressure and flash point of crude oils enables the light hydrocarbon content to be estimated. 

The vapor pressure of a crude oil at the wellhead can reach 20 bar. If it were necessary to store and transport it under these conditions, heavy walled equipment would be required. For that, the pressure is reduced (< 1 bar) by separating the high vapor pressure components using a series of pressure reductions (from one to four flash stages) in equipment called separators , which are in fact simple vessels that allow the separation of the two liquid and vapor phases formed downstream of the pressure reduction point. The different components distribute themselves in the two phases in accordance with equilibrium relationships. 

Safety standards govern the manipulation and storage of crude oil and petroleum products with regard to their flash points which are directly linked to vapor pressure. 

One generally observes that crude oils having a vapor pressure greater than 0.2 bar at 37.8°C (100°F), have a flash point less than 20°C. 

Reid vapor pressures and flash points of selected crude oils. 

Cohimn pressure at the reflux drum is established so as to condense totally the overhead vapor or some fraction thereof. Flash-zone pressure is approximately 69 kPa (10 psia) higher. Crude-oil feed temper-... 

Atmospheric Distillation - The desalted crude oil is then heated in a heat exchanger and furnace to about 750°F and fed to a vertical, distillation column at atmospheric pressure where most of the feed is vaporized and separated into its... 

Propane is a nontoxic, colorless, odorless hydrocarbon chat occurs naturally in natural gas streams and crude oil. At normal atmospheric pressure and temperature, it is a gas under moderate pressure propane becomes liquid. The ratio ofhquid to gas is 270—one unit of liquid expands to 270 units of vapor. 

In situ injection of steam has been a common practice in the oil fields of southern California for several decades. The addition of heat reduces the viscosity of the crude oil, allowing it to migrate more easily. The increased temperature also beneficially increases the vapor pressure of the oil, which allows volatile compounds to be more easily recovered. For most VOCs, vapor pressure doubles for every 20°C increase in soil temperature. The use of injected heat, steam, hot water, or air exemplifies the effective transfer of technology from other fields. 

The feedstock crude oil is heated to between 65 and 177°C (150 to 350°F) to rednce viscosity and surface tension for easier mixing and separation of the water. The temperature is limited by the vapor pressure of the petroleum constituents. In both methods, other chemicals may be added. Ammonia is often... 

The source of these compounds is varied. The butanes are found naturally in crude oils and natural gas. They, plus the olefins, are products of various refinery processes and of olefins plants. They are separated by fractionation, except for butadiene and isobutylene, which are sometimes recovered by extractive distillation. They all vaporize at room temperature, so they are handled in closed, pressurized systems.. 

The atmospheric bottom, also known as reduced oil, is then sent to the vacuum unit where it is further separated into vacuum gas oil and vacuum residues. Vacuum distillation improves the separation of gas oil distillates from the reduced oil at temperatures less than those at which thermal cracking would normally take place. The basic idea on which vacuum distillation operates is that, at low pressure, the boiling points of any material are reduced, allowing various hydrocarbon components in the reduced crude oil to vaporize or boil at a lower temperature. Vacuum distillation of the heavier product avoids thermal cracking and hence product loss and equipment fouling. 

BLEVE (Boiling Liquid Expanding Vapor Explosion) See Boilover the same phenomenon may occur in a pressurized container, resulting in an explosion or bursting of the tank or vessel in which a fire is occurring. The term is almost exclusively used to describe a disastrous effect from a crude oil fire. 

With the introduction of dist.illa.tion and fractionation under high vacuum in the presence of steam, it was possible to effect a relatively efficient separation of oil from the asphalts. However, in the case of the more highly paraffinic crudes, a complete separation between oil and asphaltic materials could not be made, because the high viscosity oil fractions which have very low vapor pressures are thermally decomposed at the relatively high temperatures required in the distillation. 

The feed stock, usually topped or reduced crude oil, is heated in pipe coils (Figure 1) from about 900° to 950° F. The oil is then fed to one of two or more vertical, insulated coke drums. The coke drums are connected by valves so that they can be switched onstream for filling, then switched off-stream for coke removal. The temperature in the drum will ordinarily be 775° to 850° F. and the pressure 4 to 60 pounds per square inch gage. Hot, coke-still vapors from the coke drum pass to a fractionator where gas and gasoline, intermediate gas oil, and heavy gas oil are separated. More or less of the heavy gas oil is recycled. The ratio of recycled heavy gas oil to fresh feed is usually less than 1 but may go up to about 1.6 (5,15,28, 40). 

HifcTbe temperature of the incoming crude is somewhat jigheT than anticipated. This has been favorable in that beating to meet the required Reid vapor pressure is not necessary, thus saving on the operational cost. Since the, water cut of the crude is still very low, the water treal-j mew facility is used infrequently however, when it is used, the oil-in-water content measured in the water overboard ranges only from S to 10 ppm. 

The sour oil from each three-phase separator is metered and commingled, and flows to a stabilizer where the hydrogen sulfide and light hydrocarbons are removed. The crude product to storage is controlled at 10-psi Reid vapor pressure and less than 50-ppm hydrogen sulfide. 

Crude oil specifications may be either for offshore tanker loading or for delivery to an oil pipeline at the platform. Crude oil specifications are usually defined relatively simply, through limitations cn vapor pressure and on BS W (basic sediment and water) content. BSMf la normally limited to a nominal percentage, such as 0.5X, and meeting this specification is outside the scope of this paper. The oil-gas separation system in Dost cases does not significantly affect whether or not the oil will meet the BSAW specification, since for those oils where this is a problem special emulsion treating is required independent cf the oil-gas separation system. 

Often it is known or suspected that future platform operating requirements nay change, which requires separation system flexibility. For example, the initial plan may be to inject gas into the producing field, but a gas pipeline outlet for the gas may be expected several years later. At that time the gas would not have to be delivered at as high a pressure, but more extensive gas conditionlng would be required to meet hydrocarbon dewpoint requirements It may be possible to utilize surplus gas conpression horsepower for gas conditioning purposes at that time As another example, it may be planned to initially load low vapor pressure crude oil into tankers at the offshore platform, but later after pipeline completion to deliver high vapor pressure crude oil to the pipeline. 

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