Versatile systems for continuous in-line blending of butane and petroleum

• US 9,207,686 B2
• Filed: 04/20/2012
• Issued: 12/08/2015
• Est. Priority Date: 02/09/2001
• Status: Expired due to Fees

• Current Assignee: Sunoco Partners Marketing & Terminals L.P. (Energy Transfer Operating, L.P.)
• Original Assignee: Sunoco Partners Marketing & Terminals L.P. (Energy Transfer Operating, L.P.)
• Inventors: Mattingly, Larry D., Vanderbur, Steven M.
• Primary Examiner(s): Maust, Timothy L
• Assistant Examiner(s): Kelly, Timothy P
• Application Number:
  US13/451,715
• Publication Number:
  US 20120203038A1
• Time in Patent Office: 1,327 Days
• Field of Search: 141/9, 141/83, 141/104, 141/105, 137/486, 137/625.41
• US Class Current: 1/1
• CPC Class Codes: C10G 2400/02 Gasoline
• CPC Class Codes: C10G 2400/28 Propane and butane
• CPC Class Codes: C10L 1/06 for spark ignition
• CPC Class Codes: C10L 1/16 Hydrocarbons
• CPC Class Codes: C10L 1/1608 Well defined compounds, e.g. hexane, benzene
• CPC Class Codes: C10L 10/00 Use of additives to fuels or fires for particular purposes additives for liquid carbonaceous fuels characterised by their chemical nature C10L1/10; using binders for briquetting solid fuels C10L5/10; using additives to improve the combustion of solid fuels C10L9/10
• CPC Class Codes: C10L 2200/0423 Gasoline
• CPC Class Codes: C10L 2270/023 for gasoline engines
• CPC Class Codes: C10L 2290/141 of additive or catalyst
• CPC Class Codes: C10L 2290/24 Mixing, stirring of fuel components
• CPC Class Codes: C10L 2290/58 Control or regulation of the fuel preparation of upgrading process
• CPC Class Codes: C10L 2290/60 Measuring or analysing fractions, components or impurities or process conditions during preparation or upgrading of a fuel
• CPC Class Codes: G05B 19/406 characterised by monitoring or safety G05B19/19 takes precedence
• CPC Class Codes: G05B 19/4166 Controlling feed or in-feed G05B19/4163 takes precedence
• CPC Class Codes: G05B 2219/37371 Flow
• CPC Class Codes: G05B 2219/41303 Flow rate valve controls speed
• CPC Class Codes: G05D 11/131 by measuring the values related to the quantity of the individual components G05D11/139 takes precedence
• CPC Class Codes: G05D 11/132 by controlling the flow of the individual components G05D11/133 takes precedence
• CPC Class Codes: G05D 11/133 with discontinuous action
• CPC Class Codes: G05D 11/139 by measuring a value related to the quantity of the individual components and sensing at least one property of the mixture
• CPC Class Codes: Y10T 137/7759 : Responsive to change in rate of fluid flow
• CPC Class Codes: Y10T 137/86823 : Rotary valve

Abstract

A system and method are provided for in-line processes of blending butane into gasoline streams, and for blending butane into a gasoline stream at any point along a petroleum pipeline. The invention additionally provides a method for measuring the vapor pressure and vapor to liquid ratio of the gasoline, both upstream and downstream of the blending operation, as well as the sulfur content of the butane entering the blending operation. The blending operation can be controlled to ensure that the blended gasoline meets EPA requirements for vapor pressure and sulfur content of gasoline. The invention further provides a method for accessing and monitoring the operation off-site.

Claims

1. A method for in-line blending of gasoline and a volatility modifying agent comprising:

a) providing a continuously flowing gasoline stream that comprises;

i) a plurality of batches of different gasoline types;

ii) a gasoline flow rate that varies over time; and

iii) a plurality of gasoline vapor pressures;

b) providing an allowable vapor pressure;

c) providing a stream of said agent that comprises an agent vapor pressure;

d) periodically determining said gasoline vapor pressure;

e) periodically determining said gasoline flow rate;

f) calculating a blend ratio based upon said agent vapor pressure, said gasoline vapor pressure, and said allowable vapor pressure; and

g) blending said agent stream and said gasoline stream at a blending unit at said blend ratio to provide a blended gasoline stream having a blended vapor pressure less than or equal to said allowable vapor pressure.

2. The method of claim 1 further comprising calculating a blend rate based upon said flow rate.

3. The method of claim 1, further comprising:

a) providing a first information processing unit (IPU) on which said calculating is performed;

b) providing a second IPU which generates pulses of flow rate data;

c) transmitting said flow rate data to said first IPU; and

d) calculating a blend rate on said first IPU based upon said flow rate data from said second IPU.

4. The method of claim 1 wherein said gasoline stream comprises a consolidation of gasoline batches from multiple sources at disparate locations.

5. The method of claim 1 further comprising:

a) storing, in one or more informational databases, seasonal data that prescribes (i) said allowable vapor pressure on two or more prescribed dates or ranges of dates, or (ii) whether agent blending is allowed on two or more prescribed dates or ranges of dates; and

b) calculating said blend ratio based upon current date information and said seasonal data.

6. The method of claim 1 further comprising:

a) recording a start time when a recorded batch begins to flow past said blending unit;

b) recording an end time when said recorded batch finishes flowing past said agent blending unit;

c) recording a quantity of agent blended with said gasoline stream between said start time and said end time; and

d) associating said quantity of agent with said recorded batch in an informational database.

7. A system for in-line blending of gasoline and a volatility modifying agent comprising:

a) a continuously flowing gasoline stream that comprises;

i) a plurality of batches of different types of gasoline;

ii) a gasoline flow rate that varies over time; and

iii) a plurality of gasoline vapor pressures;

b) an agent stream that comprises an allowable agent vapor pressure;

c) a blending unit for blending said gasoline stream and said agent stream at an actual blend ratio and an actual blend rate to yield a blended gasoline stream;

d) an upstream vapor pressure sensor in sensory communication with said gasoline stream upstream of said blending unit; and

e) one or more information processing units (IPUs) in informational communication with said upstream vapor pressure sensors, logically programmed to calculate a calculated blend ratio and calculated blend rate based upon vapor pressure and volumetric flow rate of said gasoline stream, and for communicating said calculated blend ratio and calculated blend rate to said blending unit;

f) wherein said blending unit periodically accesses said calculated blend ratio and calculated blend rate from said one or more IPUs, and adjusts the actual blend ratio and actual blend rate to coincide with said calculated blend ratio and calculated blend rate.

8. The system of claim 7 further comprising a downstream vapor pressure sensor in sensory communication with said gasoline stream downstream of said blending unit.

9. The system of claim 7 further comprising one or more informational databases in informational communication with said downstream vapor pressure sensor, wherein said one or more informational databases periodically access and store vapor pressure measurements from said downstream vapor pressure sensor.

10. The system of claim 7 wherein said one or more IPUs are further logically programmed to calculate said calculated blend ratio based upon the date.

11. The system of claim 7 wherein said blending unit comprises:

a) an on/off valve between said gasoline stream and said agent stream; and

b) a modulating valve that modulates rate of flow of said agent stream toward said on/off valve.

12. The system of claim 7 further comprising:

a) one or more informational databases on which is stored seasonal data that prescribes (i) allowable vapor pressures on two or more prescribed dates or ranges of dates, or (ii) whether agent blending is allowed on two or more prescribed dates or ranges of dates; and

b) one or more information processing units (IPUs) in informational communication with said upstream vapor pressure sensors and said informational databases, logically programmed to retrieve the date and to calculate a calculated blend ratio and calculated blend rate based upon the stored seasonal data and vapor pressure and volumetric flow rate of said gasoline stream, and for communicating said calculated blend ratio and calculated blend rate to said blending unit;

c) wherein said blending unit periodically accesses said calculated blend ratio from said IPU, and adjusts the actual blend ratio to coincide with said calculated blend ratio.

13. The system of claim 7 further comprising an agent sampling unit for periodically or continuously withdrawing agent from said agent stream, wherein:

a) said agent sampling unit is under the command of one or more information processing units (IPUs), wherein said one or more IPUs command said agent sampling unit to withdraw into a reservoir at least one sample of agent from said agent stream at least every 500,000 gallons of agent; and

b) said reservoir is manually withdrawn periodically from said agent sampling unit, and any agent contained in said reservoir is tested for sulfur content.

14. The system of claim 13 wherein said agent sampling unit and said agent vapor pressure sensor are located on a platform in proximity to said petroleum pipeline.

15. The system of claim 7 wherein said blending unit comprises:

a) an on/off valve between said gasoline stream and said agent stream; and

b) a modulating valve that modulates rate of flow of said agent stream toward said on/off valve.

16. A method for in-line blending of petroleum and a volatility modifying agent comprising:

a) providing a petroleum stream that comprises a petroleum vapor pressure and a flow rate;

b) providing an agent stream that comprises an agent vapor pressure;

c) providing an allowable vapor pressure;

d) calculating a blend ratio based upon a blended petroleum vapor pressure, said agent vapor pressure, said flow rate and said allowable vapor pressure;

e) blending said agent stream and said petroleum stream at said blend ratio to provide a blended petroleum stream wherein the blended vapor pressure is less than or equal to said allowable petroleum vapor pressure; and

f) measuring vapor pressure of the blended petroleum stream.

17. The method of claim 16, further comprising:

a) withdrawing agent from said agent stream; and

b) measuring sulfur content of said agent withdrawn from said agent stream.