TREAT facility

One of the most comprehensive economic studies was done in two phases. The first phase addressed whether the location of the treating facilities should be offshore or onshore. The second phase evaluated the process design options. The outcome of the first phase recommended onshore natural gas treating facilities the second phase recommended implementation of the turboexpander process design. The process options evaluated for this project are listed below ... 

The following example illustrates some of these features. In a clean room with automated transporting and processing facilities, there are two quality classes of air. The space close to the small items under processing and the treating facilities should be exposed only to air of class A quality (very low contaminant level) and the rest of the room air is class B quality (normal standard). Figures 11.2 and 11.3 (see color insert) represent two out of a large number of parameter studies. 

Cj s and C s include propane, propylene, normal butane, isobutane, and butylene. Propylene and butylene are used to make ethers and alkylate, which are blended to produce high-octane gasoline. Most gas plants also include treating facilities to remove sulfur from these products. 

Although an increase in the sulfur content of the residue feedstock will have a minimal effect on unit yields, the sulfur content of the RFCC products and the flue gas is greater, requiring additional treating facilities. 

Enclosed buildings handling fluids that have the potential to accumulate flammable gases (e g., produced water treating facilities). 

Enclosed water treating facilities that can release entrained combustible gases or vapors, especially a concern at produced water treating operations. 

Undesirable sulfur, nitrogen, and oxygen compounds are often encountered in commercial gas production and gas treating facilities relating either to natural sources or to synthetic processes. Water also occurs as condensate in these gas streams or water is brought in contact with gas streams in various processing steps. 

In 1993, a 60-kW system was used at a wood treating facility in Missouri to treat ground-water contaminated with PCP. This unit had operating costs of 1.30 per 1000 gal of water treated (D135159). 

According to the vendor. Microbial Fence has been used to treat groundwater contaminated with polycyclic aromatic hydrocarbons (PAHs) benzene, toluene, ethylbenzene, and xylenes (BTEX) and volatile organic hydrocarbons (VOCs) at petroleum, chemical, and wood treating facilities and manufactured gas plants. Microbial Fence was used alone or in conjunction with soil venting/bioventing, aquifer aeration, pump-and-treat methods, and/or recovery of non-aqueous-phase liquids (NAPLs). 

In many areas of the unit, separation and processing vessels were operated at 3S psig (343.3 kPa). Hydrocarbons discharged from these vessels were flashed to stock tanks, and all vapors were vented to the atmosphere. Following consolidation of these conventional tank batteries, rich vapors were recovered by vapor-recovery equipment at the central treating facility. Total recovery over the life of the unit is projected to be 133,000 bbl (21 144 m3) of liquids and 262 MMcf (7.4 x I06m3) of gas. 

The Jay field was discovered in June 1970 with the St. Regis No. 1 well, located about 35 miles north of Pensacola, Fla. (Fig. I). Initial well testing confirmed that the reservoir oil contained an appreciable amount of hydrogen sulfide (Table 1). The approximate 9 mol percent hydrogen sulfide required treating facilities to make the oil and gas salable. 

Following testing of the St. Regis No. 1 well, studies were immediately undertaken for initiation of production from the field. Two alternatives were considered for sizing a treating facility (1) conduct a short-term produc-... 

Even before the optimum plant size was determined, a contractor had been selected and process design work was in progress. The contractor was selected on the basis of competitive cost plus fixed-fee bids. The contract was later converted to a turn-key type, based on the competitive-bid fixed-fee percentage and a definitive cost estimate for completion of the job. This saved about 2 months in over-all job completion time. Through duplication of equipment purchases and construction drawings, it was possible to reduce over-all completion time for three subsequent plants by as much as 8 months from the 17 months required for the first module (Fig. 2). About 29 months were required from Geld discovery to startup of the last Exxon treating facility. 

Fig. 4—Coordination of treating-facility construction and development drilling permitted full allowable production to be attained in minimum time...

The petroleum industry has taken the position that oil and gas production can and will be compatible with a high level of public health and environmental protection. The treating facilities at Jay are designed to achieve this goal, particularly regarding the emission of sulfur compounds into the atmosphere. 

Kuwait oil fields have produced over 21 billion barrels of dry, salt free crude. Due to salt water production, a number of wells had to be shut lr. for lack of treating facilities. 

In many held the water treating facility started as a simple gravity separation in a pit or tank But as it became necessary to handle ever-increasing volumes m addition to improving water quality, new ly ies of... 

Indirect cost normally ranges from 20 to 35% of material plus labor of the modular major equipment cost. In most cost analysis of complete processing units, the indirect cost is very significant. Indirect cost factors should therefore always be a part of the summary sheet s total cost analysis and never overlooked. For most refinery, chemical plant, and oil- and gas-treating facilities, a 25% indirect cost factor is a well-accepted number in the industry, worldwide. The 25% factor of the material plus labor is therefore advised and is used in this chapter. 

Safe Operation of Refinery Steam Generators and Water Treating Facilities... 

In a 1977 test run in Chevron U.S.A. s Salt Lake Refinery, hydro-treating facilities were adequate stable products were produced by coking a mixture of in situ shale oil and crude oil residua (3). 

All of the acid dilution rates are large and the resulting fresh acid costs are adequate to support efficient feed fractionation and treating facilities, frequent maintenance and close operator observation and control of upstream operations. Assuming this is done, the major remaining concern Is the operation of the alkylation unit proper, particularly the reactor section. 

Process sewers to in-plant treating facilities (with Piping). 

Within oil-field production, treating equipment is selected in a similar manner. As the amount of water produced will vary over the life span of an oil field, equipment is often added as needed to an oil-field treating facility. The design of existing facilities will allow the addition of equipment to occur with minimal disruption during periodic maintenance shutdowns (or turnarounds ) if proper consideration has been given to the potential of changing production fluids. 

Emulsions stabilized by paraffin are usually restricted to light crude oils in oil-field production. If paraffin deposition that restricts production is occurring upstream of an oil-treating facility, it may be feasible to apply a paraffin crystal modifier to the crude oil to prevent paraffin deposition and to eliminate paraffin as an emulsifying agent. A paraffin crystal modifier must enter an oil system at a temperature greater than the cloud point of the crude oil and upstream of the problem area. 

To select chemical programs for an oil-treating facility, each facility must be examined on an individual basis. The selection of a chemical or group of chemicals for emulsion breaking must be preceded by valid test procedures and a thorough understanding of the treating system and petroleum company objectives. 

Historically, the chemical selection process has been performed on a bench-top scale. Bottle tests (including ratio, elimination, and confirmation test), jar tests, and portable electric desalter tests fall into this test category. No effort will be made to describe these tests or the associated analytical procedures in detail, as they are described in Chapters 3 and 10. Furthermore, significant variation in testing procedures will exist between various chemical companies, oil producers, and refiners. Each test procedure is also tailored to each treating facility. 

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